EPA-650/2-74-009a
January 1974
Environmental Protection Technology Series
iii
'' "
'Xv.*.v.v.v.v.v.v.v.v.v.'
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EPA-650/2-74 -009o
EVALUATION
OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION
PROCESSES
GASIFICATION; SECTION 1: KOPPERS-TOTZEK PROCESS
by
E.M. Magee, C.E. Jahnig,
and H . Shaw
Esso Research and Engineering Company
P.O. Box 8, Linden,
New Jersey 07036
Contract No. 68-02-0629
ROAPNo. 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
January 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
A. TABLE OF CONVERSION UNITS 2
B. INTRODUCTION . 3
C. PROCESS DESCRIPTION AND EFFLUENTS 5
1. Genera 1 5
2. Effluents To Air - Main Gasification Stream „.«,. 5
2.1 Coal Preparation. 5
2.2 Gasifier 10
2.3 Gas Cleaning 10
2.4 Acid Gas Removal 11
3. Effluents To Air - Auxiliary Facilities 12
3 .1 Oxygen Plant 12
3.2 Sulfur Plant 12
3.3 Utilities 12
3.4 Miscellaneous 15
4. Liquids and Solids Effluents 15
4 .1 Coa 1 Preparat ion 15
4.2 Gasifier J . 17
4.3 Gas Cleaning 17
4.4 Gas Compression and Acid Gas Removal 19
4.5 Auxiliary Facilities 20
D. THERMAL EFFICIENCY 23
E. TRACE ELEMENTS 25
F . POSSIBLE PROCESS CHANGES 27
1. Process Alternates Considered 27
2. Engineering Modifications 29
3. Potential Process Improvements 32
G. PROCESS DETAILS 34
H. RESEARCH AND DEVELOPMENT NEEDS 42
I. QUALIFICATIONS 45
J. REFERENCES 47
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SUMMARY
The Koppers-Totzek Coal Gasification Process has been reviewed
from the standpoint of the potential effluents to 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 alternates have been proposed
and new technology needs have been pointed out.
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A. 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/calorie, kg
Kilograms/hour
Kilograms/square centimeter
Metric tons
Metric tons/day
Multiply By
0.25198
0.55552
0.028317
0.30480
0.0037854
2.5400
0.45359
1.8001
0.45359
0.070307
0.90719
0.90719
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B. 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 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 1973j(20). Phases II and III were concerned with the col-
lection of published information on fossil fuel conversion/treatment pro-
cesses and the description of selected processes. These selected processes
were evaluated for their ability to produce clean fuels and for their pos-
sibilities 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
offsite facilities are not within the scope of this study.
The first detailed study was made using the Koppers-Totzek
gasifier because of the large amount of commercial experience and the
resulting information. This study is to serve as a model for future
studies of other conversion/treatment processes.
Considerable assistance was received in making this study
and we wish to acknowledge the help and information furnished by EPA
and the Koppers Company as well as that furnished by many specialists
in the Engineering divisions of Esso Research and Engineering Company.
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C. PROCESS DESCRIPTION AND EFFLUENTS
1. General
The Koppers-Totzek gasifier as part of a complete gasification
process is the first one examined in this pollution study. This process
can be used to make synthesis gas, reducing gas, or fuel gas, and was
studied first for several reasons: (1) more complete information is
available than on some other processes, this specific design does not
include proprietary clean-up processes, and there are a number of
commercial plants in operation; (2) it is a simple and relatively clean
process in that it does not produce tar, oil, or phenols, (Minor amounts
of cyanide, ammonia, etc., are produced.); (3) the process developer
was cooperative in supplying requested information.
The gasifier operates at about 2700°F and atmospheric pressure
with oxygen, a small amount of steam, and a dilute suspension of powdered
coal to produce synthesis gas. The product gas is high in CO and hydrogen,
with negligible methane. The process is described generally in the
Koppers brochures. Additional information has been obtained from the
literature (1,2,3,A) and by discussions with the Koppers Company. The
processing steps together with effluents and a discussion of pollution
aspects follows. (In this report Figure 1 is referred to as the design
as supplied by the Koppers Company and Figure 2 is the design as revised
to incorporate environmental controls).
2 . Effluents To Air - Ma in Gasification Stream
Figure 2 is a block flow diagram of the process and auxiliary
facilities. This design, based on the design supplied by the Koppers
Company, feeds 6,750 T/D of bituminous coal containing 16.5% moisture,
17.3% ash, and 0.63% sulfur with a HHV of 8830 Btu/lb. The product gas,
after acid gas removal, is 290 MM cfd with a HHV of 303 Btu/cf and 300 ppm
sulfur. This sulfur content meets requirements but could be reduced
by the use of more equipment. Most commercial applications are for
making ammonia or methanol, but the gas can also be used as a clean
fuel for firing ceramics, glass manufacture, etc., or for steam
generation and combined cycle power plants or for upgrading to high
Btu SNG; in other words the gas can be used whenever synthesis gas,
fuel gas or reducing gas can be used. The process can also be used
to gasify coal fines, char, hydrocarbons, or tar.
2 .1 Coal Preparation
All effluents to the air are shown on Figure 2 and Table 1. The
first unit to be considered is the coal storage pile and handling facilities
This particular design does not require beneficiation of coals of
30% ash content or lower. For 30 days storage, the coal piles are about
200 feet wide, 20 feet high and 1,000 feet long. There are two of these,
with loading, unloading, and conveying equipment. These will generally
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FIGURE 1
KOPPERS-TOTZEK COAL GASIFICATION PROCESS
DESIGN BASIS AS ORIGINALLY FURNISHED BY KOPPERS CO.
Dryer Vent Gas
from _Cyclones
Hlgh pressure
Steam for Credit
Coal
469,665
Oxygen
332,700
Gas to Sulfur Plant
16,275 Including
3,386 H2S
166 COS
Gas to Coal Dryer
17.6 MMCFD
Cooling Tower Make-Up
235,612
Product Gas
. 392.6 MMCFD
HHV 303 Btu/cf
48,657 Ash
4,866 Water
Ash and Coal Fines
to Disposal by
Purchaser
62,802 Water
62,802 Ash
Water Blowdown to
Purchaser's Effluent
Treating Facilities
104,992
NOTE:
All numbers are flow rates in Ib./hr. except as indicated.
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FIGURE 2
KOPPERS-TOTZEK COAL GASIFICATION PROCESS
DESIGN REVISED TO INCORPORATE ENVIRONMENTAL CONTROLS AND TO INCLUDE ALL AUXILIARY FACILITIES
t 1
13
CftSIFICATION PROCESS
23 4 5 6789
t 1 ft ttttr
. ^^^^^^^^^^^^
COAL IN ^__ COAL ^ COAL ^ ^ACT1?T1?D
*^ STORAGE 3P PREP. -** GASIFIER
f | 1ft llt!L
10 11 12
. COOLIN
M A ' /* TOWEI
J— L
DUST
REMOVAL
' t
23 u 25 26 27 28 29 30 31 32
38 39 40 41 42 43 44 45 46 47 48 49 50 51
4 f A 4 4 A 4 4A4 A
AUXILIARY FACILITIES III ill 1 1 T 1 1
1 \ \ \ 1 1 1 1 1
0- SULFUR UTILITIES
PLANT
PLANT
Iff
MAKE-UP
WATER
TREAT. |
14
G 15 16 17
-"~ t i
1 1
f f
33 34
52 53
M
WASTE
WATER
TREAT.
18 19 20 21
4 A i GAS TO DRYER
J ^
ACID 1
REMOVAL
PRODUCT
GAS
III
35 36 37
54 55 56
fll
COOLING
TOWER
TTT TT W Tl
57 58 59
60 61
62 63 64 65
66 67
rr
68 69
rr
70 71
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TABLE 1
STREAM IDENTIFICATION FOR REVISED KOFPERS-TOTZEK PROCESS
Stream No. Identification
1 Coal Feed
2 Dust from storage pile
3 Rain run-off from storage pile
4 Dryer vent gas
5 N2 transport gas
6 Wet slag
7 High pressure steam
8 Low pressure steam
9 Boiler blowdown
10 Wet ash from clarifier
11 Blowdown from Scrubber
cooling tower
12 Emergency release to flare
13 Air effluent from cooling tower
14 Drift loss from cooling tower
15 Air in to cooling tower
16 Cooling water, compressor driver
17 Condensate, compressor driver
18 Purge from amine scrubber
19 H2S stream to sulfur plant
20 Cooling water
21 Fuel gas to coal drier
22 Product gas
23 Wind on coal storage
24 Rain on coal storage
25 Air to burner, coal dryer
26 Fuel to coal dryer
27 N2 to purge storage drum
28 Steam to gasifier
29 Oxygen to gasifier
30 Boiler feed water
31 Spray water
32 Water make-up to cooling tower
33 Cooling water, compressor driver
34 Steam to compressor driver
35 Make-up water and chemicals
36 Cooling water
37 Steam, low pressure
38 Oxygen to gasifier
39 Nitrogen stream
40 Condensate, total
41 Sulfur
42 Tail gas
43 Steam make
44 Electric power used
45 Flue gas from boiler
46 Steam used
47 Boiler blowdown to cooling tower
48 Cooling water in power generation
49 Treated water
50 Treated water
51 Sludge from water treating
52 Treated water
53 Sludge
54 Blowdown from util.cooling tower
55 Air from util. cooling tower
56 Drift loss
57 Air to oxygen plant
58 Steam to oxygen plant
59 Cooling water to oxygen plant
60 H2S stream to Claus plant
61 Utilities to Claus plant
62 Coal to utility boiler
63 Combustion air
64 Boiler feed water
65 Cooling water
66 Fresh water
67 Chemicals
68 Water from process area
69 Water from coal storage
70 Make-up to utility cooling tower
71 Air to utility cooling tower
Flow Rate
Comment s
562,500 Ib/hr
e.g. 500,000 Ib/hr
150 MM SCFD
6 MM SCFD
53,523 Ib/hr
661,801 Ib/hr
98,527 Ib/hr
38,016 Ib/hr
125,604 Ib/hr
7, 100 MM SCFD
16,220 Ib/hr
7,100 MM SCFD
48,500 gpm
507,000 Ib/hr
3.9 MM SCFD
1110 gpm
292.6 MM SCFD
6" in 24 hrs.
220 MM Btu/hr
5.8 MM SCFD
84,735 Ib/hr
326,861 Ib/hr
798,344 Ib/hr
49,503 Ib/hr
302,485 Ib/hr
48,500 gpm
507,000 Ib/hr
1879 Ib/hr
1110 gpm
16,500 Ib/hr
326,861 Ib/hr
1,235,864 Ib/hr
576,782 Ib/hr
40 t/d
7 MM SCFD
10,564 Ib/hr
19,426 KW
320 MM SCFD
645,989 Ib/hr
30,800 Ib/hr
16,400 gpm
1,500,013 Ib/hr
75,098 Ib/hr
302,485 Ib/hr
48,000 MM SCFD
147,528 Ib/hr
1,597,388 Ib/hr
584,300 Ib/hr
79,400 gpm
3.9 MM SCFD
1360 t/d
296 MM SCFD
75,098 Ib/hr
16,400 gpm
1,575,111 Ib/hr
1,500,013 Ib/hr
48,000 MM SCFD
For inspections; see Table 7
Depends on wind conditions
Based on 6" rain in 24 hrs.
Control of dust and sulfur needed
Include with dryer vent gas
To disposal in mine
From waste heat boiler
From gasifier cooling jacket
Send to utility cooling tower
To disposal in mine
Eliminated
Use non-smoking flare
Also water vapor-potential fog
Typical loss for cooling tower
Recirc. to utility cooling tower-closed circuit
Return to boiler feed water system
Incinerate in utility boiler
23.17, H2S, 15 .27. moisture
Clean, recirculate to cooling tower
Eliminate or use only enough to meet S limit
Increases to 306.9 if none used to dry coal
Can cause dusting
To holding pond, work off over^lO days
Limit t0 give 1Q7, 02 in dryer gas
Use mostly coal, to save clean gas
Available from oxygen plant
From gasifier jacket boiler
From oxygen plant, plus 5838 Ib/hr N2
To boilers on jacket and hot gas
Tempers hot gas to boiler
From utility cooling tower blow.down
For driver condenser and after cooler
High pressure steam
Water evaporation in scrubber
From utility cooling tower
For reboiler
Plus 5838 Ib/hr N2
Plus 28,825 Ib/hr 02
Driver, heater, plus moisture in air
From claus plant
Add tail gas clean-up process
From heat of reaction
Burn coal and use flue gas
clean-up to control sulfur
and ash
Cooling tower make-up
Boiler tower make-up
Include in ash disposal
From storm run-off pond
Sediment in run-off pond
Send to scrubber cooling tower
Also water vapor, potential fog
Entrained mist of water
High pressure (plus 7856 Ib/hr low pressure)
On compression
From acid gas removal
156 KW, 5 MM Btu/hr. to incinerator
Need flue gas clean-up of sulfur and ash
Based on 207. excess air
From water treating
For power generation
Gross water required
Depends on water quality and treatment process
Rain run-off, drains, etc.
Rain run-off
Evaporation drift and blowdown
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be tamped down, but there can still be dusting and wind loss. Covered
conveyors should be used, and other precautions included in the design
to minimize dusting from stacking etc. Thorough planning is necessary
to avoid possible combustion in coal storage piles etc., and to provide
for extinguishing any fires that may start (13).
The next effluent to the atmosphere is from coal drying which
in this case uses a rotary drum drier fired with part of the product
gas, giving a sulfur level in the off gas well below that allowable
for liquid or solid fuel firing. Use of feed coal as fuel would be more
efficient than the use of product gas but would give 1.4 Ib S02/MM Btu
compared to the allowable 1.2 Ib S02/MM Btu. However, the major part
of the fuel could be coal, supplemented by some product gas to meet
sulfur emission limits. The gas effluent rate from drying is 150 MM cfd
A large volume of excess air is used to bring the drying gas temperature
down to less than 1000°F in order to avoid overheating the coal. Also,
flue gas is recycled on the drier to hold a maximum of about 10% oxygen
in the gas. The coal is not oxidized in the drying step and no tar,
sulfur, or volatiles should be evolved, since the coal temperature is
not over 200°F. It may be that a fluid bed drier would be more effective
than the preceeding because it would allow a higher gas inlet temperature
without overheating the coal. This would reduce the volume of dusty
effluent gas since less excess air is needed, and the fuel efficiency
would increase correspondingly. As an alternate, it might be possible
to dry the coal using heat in the flue gas from the utility boiler.
The drier vent gas must be cleaned up and for this purpose
an electrostatic precipitator was added to the base design. Bag
filters might be used instead, but they must be kept hot enough to avoid
water condensation. A water scrubber could be used, and may be
preferred if odors in this vent gas are objectionable. The degree of
odor control needed will depend on the type of coal and the plant
location. It may be more of a problem for example on lignite, and this
information should be obtained from plant or experimental operations.
Even so, the gas will have a high moisture content and may form a
water fog under certain atmospheric conditions. In locations where this
is not acceptable, one solution is to make sure that the vent gas is
above the critical temperature for fog formation.
Grinding and pneumatic transport with nitrogen do not generate
a gas effluent since they are designed for completely closed gas recycle.
The gas balance lines from this system (e.g. coal feed hoppers) should
be vented into the dust removal system. Great care should be taken to
avoid spills, overflow, leaks on seals, and the like. As a further
precaution to control pollution, this entire system could be housed in a
building, with positive ventilation control tied into bag filters.
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Noise control may also be needed. While the building may shield
the process area from undue noise of the grinding and handling operations,
additional precautions may be needed from the standpoint of personnel
inside the building.
In all solids handling or processing, good housekeeping is essential,
with plans for quickly containing and cleaning up spills and leaks. Inside
a building, this will be required by proper safety procedures. Outdoors in
the process and coal storage areas any dust could be picked up by the wind
unless promptly collected. Specific clean-up equipment should be provided for
this, such as trucks for vacuum pickup and spraying water on roads, and
hoses to flush dust to the storm sewer system.
2 .2 Gas ifier
No gaseous streams are released to the atmosphere from the
gasifier. Molten slag leaving the bottom of the gasifier is granulated by
dropping into a tank of water. Vapors from this tank need to be contained.
Wet slag is removed by a conveyor and is not expected to be an odor problem.
2 .3 Gas Cleaning
The raw product gas is cooled in a waste heat boiler and then
scrubbed with water. Water from the scrubber, containing approximately
half of the slag as well as dissolved H2S etc., goes to a clarifier to remove
solids and then to a cooling tower in which the air will strip out dissolved
gases. If all the dissolved H2S is stripped into the air, it will give
a concentration of 1-2 vppm. While this is below the Maximum Allowable
Concentration, it is far above the odor threshold and would be unacceptable
(see references 5 and 6). It is common to find an appreciable Biox action
in the cooling water circuit, and Koppers Company experience shows that
there is no odor problem, but this area needs'better definition, particularly
on higher sulfur coals. The problem can be avoided by using indirect
cooling by cooling water or air-fins. The calculated amount of H2S is less
than 100 Ibs/hr and it should be relatively easy to inactivate it by adding
lime slurry, or by passing the circulating water through a bed of lump
limestone. There might be sufficient alkalinity from the fraction of the
slag that is carried over to do the task.
An additional effluent is the drift loss of mist from the cooling
tower. The mist will contain dissolved and suspended solids, which will
result in deposits on the ground and on nearby equipment. When this
dries out, it can cause a dust nuisance, for example if trucks use the area.
In some cases this type of drift loss has caused icing problems on equipment
and public Toads in the winter. With any cooling tower, the problem of fog
formation must be assessed, since under certain conditions the moisture con-
denses and the resulting plume can be a problem if it affects public highways.
In planning the layout of the plant facilities, these aspects should be
given careful consideration, and every effort made to avoid potential problems
by proper placement of the equipment.
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If necessary, an alternate approach is to avoid the cooling tower
by using air fin exchangers. The gas would first be scrubbed with water to
remove dust and cooled by evaporating water. Air fin exchangers would then
be used for further cooling prior to compression. Air fins reduce water con-
sumption since the heat removed from the gas is taken up as sensible heat of
the air rather than by evaporating water in the cooling tower. Water evapor,-
orated in the scrubber is recovered down stream as condehsate, amounting to
80,000 Ibs/hr (160 gpm). It can be cleaned up to supply part of the boiler
feed water makeup. Since this is a completely closed system, it avoids po-
tential pollution problems associated with the cooling tower. It would be
more practical in higher pressure operations, where the condensation tempera-
ture is higher.
2 .4 Acid Gas Remova 1
After compression, the gas is scrubbed with amine to remove
H2S. The various mono- and diethyl- amines that have a high capacity
for acid gas removal are not very selective for separating H2$ from C(>2 •
If most of the C02 is removed along with the H2S, there results a rather
dilute H2S stream for subsequent sulfur recovery and gas to the Glaus
plant would contain only about 5% H2S. This low H2S concentration would
result in poor burner efficiency and less than optimal sulfur recovery
in the Glaus plant. Actually, it is understood that Koppers Company
is planning to use MDEA (methyl diethanolamine) for selective removal
of H2S; thus, a concentration of 22% H2S passes to the Glaus plant.
The final product gas after scrubbing contains 200 vppm of H2S,
as well as an estimated 100 vppm of COS. This gas is considered a relatively
clean low Btu fuel. The sulfur level is too high, however, for methanation
etc., to make a high Btu fuel. However, if methanation is desired other
systems can be used to reduce sulfur to acceptable limits.
Carbonyl sulfide results from the gasification reactions and
causes complications in amine scrubbing. A hot carbonate scrubbing
system would be more effective but would also take out C02 • Other processes
such as the Stretford process, Institut Francais du Petrole (IFF) process,
Thylox, etc. remove H2S down to a level of a few parts per million and
at the same time produce free sulfur as a by-product. They can operate
at low pressure, for example, near atmospheric pressure, and greatly
reduce the amount of gas compression required, depending on the disposition
of the product gas.
These processes do not remove carbonyl sulfide so that this will still
leave considerable sulfur in the product gas. Work in the literature indicates
that carbonyl sulfide has been hydrolyzed over various catalysts to give a
high conversion to l^S (7). If this operation is perfected, it could be
used ahead of acid gas removal to give nearly complete removal of sulfur
compounds. Development of this step appears highly desirable and would find
application in most gasification processes.
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3 . Effluents To Air - Auxiliary Facilities
In addition to the basic process, a number of auxiliary facilities
are required which will now be discussed with regard to effluents to the
air.
3.1 Oxygen Plant
The oxygen plant provides 4,000 tons per day of oxygen. It
should pose no pollution problems since the only major effluent is a
nitrogen stream, but there is a large consumption of utilities which
affects overall thermal efficiency of the process.
3.2 Sulfur Plant
The t^S stream from acid gas removal goes to a Glaus plant.
Sulfur recovery of about 97%, can be achieved with three stages in
"straight-through" flow. The tail gas still contains about 1 ton per
day of sulfur and must be cleaned up, although this gas volume of 7 MM cfd
is small relative to the other effluents. A number of processes are
available now for tail gas clean up and several of these will be in com-
mercial use soon (e.g. Shell's SCOT process, Wellman-Lord process,
Beavon Process, etc.). In some, the tail gas is first reduced to convert
all sulfur compounds to H2S which can then be removed; in others, the
tail gas is incinerated and the S02 is then scrubbed out. Limestone
scrubbing of the incinerated tail gas may be used, with disposal of
spent limestone along with the coal ash being returned to the mine. The
amount of spent limestone is relatively small.
No specific preference is indicated for Glaus tail gas clean-up
since by the time that coal gasification finds much commercial application
in this country, there will be considerable commercial experience to
draw on. It is reasonably certain that there will be at least one
demonstrated, sat isfactory process available.
3.3 Utilities
In the utilities area, the main cooling tower has by far the
largest volume of discharge, 48,000 MM cfd of air. It is therefore critical
from the standpoint of pollution. In this particular case it is not ex-
pected to contain significant amounts of undesirable contaminants. The
cooling water circuit is clean and does not contain ash or objectionable
materials such as H2S . Normally a certain amount of leakage can be
expected on exchangers using cooling water. Since the process operates
at low pressure, this should not be a major item. Also, most of this
cooling water is from steam condensers of drivers on compressors, rather
than on oil, sour water, etc. Cooling towers will always have the problem
of mist as well as fog formation, as discussed under the area of gas
scrubbing.
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The utility power plant is a major item from the standpoint of
pollution as well as thermal efficiency of the over all process, and is
sized to make the plant self-sufficient in steam and power. It is desir-
able to burn coal as fuel, which means that sulfur and ash removal are re-
quired on the flue gas. This particular coal contains 0.63 wt. % sulfur
corresponding to 1.4 Ib S02/MM btu, whereas the allowable ,is 1.2. Therefore,
some sulfur control is required. There are many ways to do this. As
one example, a water scrubber can be used to remove ash and if some
limestone is added it should be feasible to remove,for example, 20%
of the S02, and thereby conform to regulations. The amount of limestone
to dispose of is moderate, amounting to about 40 tons per day for complete
S02 removal, compared to the ash production of 235 tons per day from
the utility boiler.
An alternate is to burn part of the product gas along with coal
to meet the allowable quantity of S02 in the flue gas discharged to the
atmosphere. It would be possible to burn only product gas in this utility
boiler to supply all the fuel required. This may not be a practical case
but does set a limit. It would result in minimum pollution from the utility
boiler, with regard to sulfur and particulates, in cases where this is
justified or necessary. The volume of flue gas from the power plant is
320 MM cfd, or about the same as the volume of clean product fuel gas.
In view of the intensive effort underway on flue gas clean-up, it is
expected that there will be techniques in wide spread use by the time that
coal gasification finds extensive application. Some of the processes for
S02 removal use liquid scrubbing which will also remove ash, or S02 might
be removed first in a dry operation, followed by scrubbing to remove ash
and perhaps other contaminants such as trace metals. On this basis it is
reasonable to assume that coal can be burned in the utility boiler. A
recent paper by Commonwealth Edison (8) indicates that a low Btu gas
produced in a manner similar to that described here may be a practical way
to use coal in power plants as an alternate to flue gas desulf urization.
Of course the specific situation will determine which method is used.
When flue gas desulfurization is used on a boiler with coal firing,
it may be desirable to add the Glaus tail gas to the boiler so that it is
incinerated and passes through the sulfur cleanup. This would avoid the need
for separate facilities for tail gas cleanup, but it does assume that the
Glaus plant would be near the boiler house. Location of the boiler might
also be dictated by the practicality of using the flue gas for coal drying.
The emissions of other gaseous pollutants from the Koppers plant
are associated with the power plant and are common to other industrial
boilers. The major pollutents will be the oxides of nitrogen (NOX) and
carbon monoxide (CO). Carbon monoxide emissions are generally less than
0.1 Ib/MM btu for gas or coal firing and are not considered to be a problem.
-------
- 14 -
Duprey (9) reported that the average emission factors for
from industrial boilers are 0.205 Ib NO* (as N02)/MM Btu for natural
gas fired boilers and 0.842 Ib NOX (as N02)?MM Btu for coal fired
boilers. These values are slightly above the national standards that
were promulgated by EPA on December 23, 1971 (10) for all new fuel-fired
steam generating units of more than 250 million Btu per hour heat input.
The standards are based on a two hour average value and are 0.20 Ibs
NOX (as N02)/MM Btu for gas firing and 0.70 Ibs NO (as N02)/MM Btu for
coal firing.
No systematic survey of the factors affecting the emissions of
NOX, SOX, and CO for industrial boilers has been made to date. Estimates
of these pollutants will, therefore, be made from experience with
utility boilers (11). This assumption is fairly conservative since
it has been shown that utility boilers produce larger levels of pollutants
on the average than industrial boilers (9). The regression line for all
types of boilers fired with high Btu gas is:
Ibs NOX/MM Btu = 0.145 + 2.84 x 10"3 MW
(MW is size of the boiler in megawatts.) Similarly the regression line for
horizontally opposed coal fired boilers is:
Ibs NOX/MM Btu = 0.398 +2.61 x 10~3 MW
The nitrogen content of the coal adds the following amount of NOX to the
above, for coals of 1.1 to 1.570 nitrogen:
Ibs NOX/MM Btu = -1.56 + 1.21 (wt 7, N in fuel)
Thus for a power plant, which is rated at 110 MW (part of this is used
for steam generation in the present case), the uncontrolled NOX emissions
would be 0.457 Ibs. NOX/MM Btu for natural gas firing and 0.783 Ibs.
NOX/MM Btu for coal firing taking into account the contribution of the
fuel nitrogen in coal. Low Btu gas, such as that from the Koppers-
Totzek gasifier, would be expected to give lower NOX due to lower flame
temperature. However, some techniques of NOX control may have to be
applied to the power plant in order to meet the clean air standards.
The NOX emissions limitation can be met based on the experience of
Crawford, Manny and Bartok (12) who showed that NOx emissions can be reduced
by 25 to 60% in coal fired utility boilers by using low excess air firing
and staged burner patterns. Similarly, NOx can be reduced by as much as
80% in natural gas fired boilers using a combination of techniques which
include low excess air, staged firing, and flue p,as recirculation.
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- 15 -
3 .4 Misce 1 laneous
In general, there may be other effluents to the air from sources
such as ponds, Biox units, and API separators if used, etc. It appears that
the latter two items will not be needed in the specific design case studied.
In addition, leaks on processing equipment must be expected. For example,
packing on valves and seals on rotating equipment such as compressors and
rotary dryers are commonly found to leak, depending upon operating pressure,
design, and maintenance. Estimates must be made for specific projects to
determine the magnitude, as has been done,for example,on oil refineries in
California (25) „
4. Liquids and Solids Effluents
4 .1 Coal Preparation
Coal storage and preparation is the first major item in this category
(Figures 2 and 3). The problem is due to rain runoff. The storage pile has 9
very large volume such as 30 days holdup and the residence time is long
so that rain has a chance to react and form acids or extract organics and
soluble metals, and in any event give suspended matter in the rain runoff.
Therefore, it is necessary to collect water from this area as well as from
the process area, and send it to a separate retention pond. This pond should
have a long enough residence time for solids to settle out; also, there will
be a certain amount of biological action which will be effective in.reducing
contaminants. Limestone can be added in this circuit if needed to correct
acidity. The problem may bear some resemblance to acid mine water and should
be reviewed from that standpoint (13).
In some comparable situations, seepage .down through a process area
can be a problem in addition to the runoff. Even though storm sewers collect
the runoff in a chemical plant or refinery, leaks and oil spills can release
enough material that it actually seeps down into the ground water supply. If
the ground contains a lot of clay this will not normally be a problem - in
fact the clay can absorb large quantities of metallic ions. In sandy soil
it may be necessary to provide a barrier layer underneath the coal storage
piles. This could be concrete, plastic or possibly a clay layer. Storm
sewers from the process area should also be collected and sent to the pond.
In the present design this should be satisfactory. However, in other cases
where there can be serious spills of oil and phenols, the process area should
be drained to a separate holding pond.
Water from the retention pond will be relatively clean and
low in dissolved solids and is therefore a good make-up water for the
cooling tower circuit and for preparation of boiler feed water. Where
all of the run-off water can be used in this way, it will not constitute
an effluent from the plant.
-------
FIGURE 3
COAL PREPARATION 8
EFFLUENT WATFR
GAS IF I CAT I 0
& SO LIDS
ORAGE
DRIER
GRIND
GASIFICATION
GAS
SPILLS
STOm RUNOFF
6" RAIN IN 24 HRS
10 DAYS STORAGE
8 SETTLING POND
WET SLAG
640 T/D
9% WATER
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- 17 -
There are no specific liquid or solid effluent streams from the
drier and grinder except that the off gas passes through bag filters or
a scrubber to remove dust. An electrostatic precipitator or bag filters can
be used on the coal drier vent gas, and the dust can be returned to the feed
hoppers. Or, a scrubber may be preferred if there is an odor problem,
or if sulfur must be removed from this gas because of the fuel fired
to the dryer. Rather than to allow this scrubber water to become an
effluent from the plant, it is much preferred to return it to the slurry
scrubbing system downstream of the gasifier. In this way it can be
cleaned up without adding a separate system. Also, the residues will
be combined with the main ash discharge for return to the mine.
4.2 Gasifier
On the gasifier, the only discharge stream is wet granulated
slag which is drained to about 107. water for disposal. The material
is similar to blast furnace slag, but lower in sulfur, and it should
be suitable for fill, for road aggregate, or for addition to cinder
blocks. Since this slag stream has been melted, it should contain
a minimum amount of dust and leachable material. There can still be
a question of odor and sulfur release and these questions will have to
be answered with further data. The problems will be common to some
other gasification operations. Water used in quenching the slag is
recirculated to the scrubbing system and is not an effluent from the plant.
4.3 Gas Cleaning
The next process area is the scrubber which removes dust from
gas leaving the gasifier. A water scrubber is used, followed by disinte-
grators, which are high-powered agitators; or a venturi scrubber can
be used. The resulting spray is then knocked out in a mist eliminator
(Figure 4) .
The water slurry used for scrubbing becomes saturated with hydro-
gen sulfide and other gases, and is then cooled by circulating directly to a
cooling tower. Part or all of the dissolved gases will be stripped out by
the air in the cooling tower. If the scrubber water is saturated, calculations
indicate that it will contain 7 parts per million of H2S which is far above
the target level. At least on one plant, the Koppers Company reports
that there is no H2S odor on the cooling tower. As discussed in connection
with effluents to the air, the total hydrogen-sulfide carried in the
circulating water is less than 100 Ibs. per hour. It should be relatively
easy to control this by adding limestone as a slurry ahead of the cooling
tower in order to fix the sulfur in a non-volatile form. In fact, it
may be that the ash of the coal is alkaline enough to do this. Returning
the ash and other solids to the mine would probably not cause a secondary
pollution problem, but this point should be checked further.
-------
FIGURE
GAS CLEANU P
EFFLUENT WATER & SOLIDS
FROM
GASIFIER
WATER , COOLING
SCRUBBER r TOWER
f
\0 W
8
CW- 1 ACID GAS
RESSOR | REMOVAL
I
1 1
V" V
PRODUCT GAS
X~
oo
i
ASH SUJRRY
1500 T/D
50% WATER
11,3% CARBON
38,7% ASH
210
DRIFT LOSS
32
WATER
70
CHEMICAL
PURGE
ORIGINAL BASIS - THIS BLOWDOWN IS
ELIMINATED IN MODIFIED CASE.
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- 19 -
If the operating pressure of the gasifier were much higher,
then the solubility of l^S would be increased and the pollution problems
on the slurry cooling tower could be greater. It might then be neces-
sary to go to indirect cooling or to use air fin exchangers. This does
not appear necessary or warranted from a pollution standpoint in the
present design with low pressure gasification using low=3ulfur'western
coa 1.
The original Koppers design shows effluent water from this
scrubbing circuit. It contains ash fines and dissolved I^S, and would
be difficult to clean up as an effluent. There appears to be no basic
necessity for having a water effluent from this system, so it has been
changed to operate as a closed circuit, and the only water discharged
is that in the ash slurry returned to the mine for disposal.
In all conventional cooling towers there is a drift loss re-
presenting the water spray which is carried away by the circulating air,
as discussed under air effluents. Typically, this amount is at least 0.2%
on the circulating water, or 25,000 Ibs. per hour in the present slurry
cooling tower. This together with the 62,800 Ibs. per hour of water in
the ash constitutes the liquid water effluent from the plant. Water evaporated
in the cooling tower is about 200,000 Ibs. per hour. The resulting con-
centration or build-up of total dissolved solids compared to the makeup
water is less than a factor of three. This compares with a common guide-
line of 7 maximum and should be satisfactory.
As mentioned, it is feasible to operate the slurry scrubber system
with no net water effluent other than that contained in the wet ash slurry
being returned to the mine for disposal. It will be seen from subsequent
discussion that this is the only net water effluent from the plant; that is,
there is no effluent to rivers or the like.
Ash is separated from the scrubber slurry in a clarifier, and
is a major part of the ash in the coal feed. For convenient handling, it
is maintained as a thick sludge for transporting back to the mine. There
it will be desirable to concentrate it further and return the separated
water back to the process area for reuse. The concentrated ash sludge will
then give minimum secondary pollution (e.g., to ground water) when buried.
4 .4 . Gas Compression and Acid Gjas Removal
Gas compression is next in the process sequence. The only
effluent it generates is water condensate containing H2S and some dust.
This can be used as water make-up in the amine scrubber. Next is acid
gas removal where the H2S is removed by scrubbing. Amine scrubbing
is used and there will be a purge' stream of amine to get rid of
contaminants produced by side reactions. One way to dispose of this
is to incinerate it in the power station boiler. Some water is evaporated
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- 20 -
in the acid gas scrubber due to a small increase in gas temperature.
In many cases the product gas will then be used directly as a specialty
clean fuel gas, for example in metallurgical applications, glass manufacture,
etc. In other cases it may be desirable to dry the gas further before
use, giving additional water from condensation.
4.5 Auxiliary Facilities
Next to be considered are the liquid and solid effluents from auxiliary
facilities (Figure 5). The first of these is the Glaus plant which makes
about 40 tons per day of sulfur. Tail gas from the Glaus plant must be
desulfurized and several processes have been developed to accomplish the
task, most of which will generate additional liquid and solid effluents
These are described in the section on effluents to the air. One alternate
is limestone scrubbing, which has been tested extensively on flue gas from
power stations (14-17).While there have been problems of plugging and sludge dis-
posal, it should be possible to use the process on tail gas from a Glaus
plant Disposal of spent limestone would be a relatively minor problem
since it only amounts to about 6 tons per day of sludge in the present case.
The next item is the oxygen plant which is relatively clean.
Some water is condensed from the after-cooler on the main compressor, and
should be processed for boiler feedwater makeup.
Next is the water treating system which depends on the quality
of makeup water at the specific plant location. It may include the use
of lime to precipitate hardness and alum to cause flocculation. Sludge
from water treating must be concentrated and can be included with the ash
disposed in the mine. Boiler feedwater treating includes demineralization
using ion exchange resins. These are regenerated by backwashing with sul-
furic acid or caustic which can then be combined, neutralized, and included
in the makeup water to the ash slurry scrubbing system.
Water circulating to the cooling tower on the utility system will
normally need chemical additives to control algae and corrosion. Chromium
is considered to be the most effective corrosion inhibitor, but is highly
toxic. It can be precipitated out by raising pH although further study is
needed to define the treating needed to assure an acceptable level. Blow-
down water from steam boilers is included as makeup to the utility cooling
tower. Slowdown or purge from the latter is used as make-up water in the
ash cooling circuit.
The utility power plant has been sized based on utility balances
and requires 1360 tons per day of coal. Included are items such as water-
pumps and air fans on the cooling towers, but excluded are general offsites
such as shops, office buildings, etc. The largest effluent stream from
the boiler is 235 tons per day of ash. This may be handled along with the
ash from gasification. The exact disposal may depend upon whether a slag-
-------
- 21 -
FIGURE 5
EFFLUENT WATER AND SOLIDS FROM AUXILIARIES
FOR KOPPERS-TOTZEK PROCESS
CLAUS
PLANT
T
4000 T/D
SULFUR 40 T/D
(PLUS SPENT LIFESTONE IF USED
TO SCRUB TAIL GAS FROM INCINERATOR
EG 6 T/D),
WATER
18 GPM
WTER
SYS1B1
2644 GPM MAKEUP
POWER
PLANT
1360 T/D COAL
DRIFT LOSS FF
COOLING TOWER 295 GPM
SLUDGE & CHEMICALS
USE) FOR TREATING
SLURRY FROM
FLUE GAS SCRUBBER
ASH 235 T/D
SPENT LIMESTONE 40 T/D (8,6 T/D SULFUR)
-------
- 22 -
ging or non-slagging type of boiler is used. With a slagging boiler, most
of the ash is recovered from the bottom, and may be suitable for road ag-
gregate, etc. Also, there is less fly ash to recover and handle, for example
in a water slurry. However, the slagging boiler may not be applicable on
all types of coal, and tends to make more NOX- Further consideration on the
type of boiler to use appears warranted with regard to pollution, including
the effect on the fate of trace elements.
Depending upon the process used to clean up the boiler flue gas,
there will be additional streams to be disposed of. For example, if lime-
stone scrubbing is used for desulfurization, there will be 40 tons per day
of spent limestone, which is small compared to the amount of ash, even
assuming rather complete sulfur removal beyond target levels.
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- 23 -
D. THERMAL EFFICIENCY
Overall thermal efficiency is important in that it sets the
amount of coal raw material required to produce a given amount of clean
fuel. Moreover, part of the unused energy must be dissipated to air
or water. As a first calculation, the total product gas heating value
is divided by that for the total coal used in the plant including utilities.
This hypothetical figure is 65%. However, some of the product gas is
used for fuel in the coal dryer of the Koppers design, and subtracting
this out gives a base thermal efficiency of 61%. There are many variations
of this which can be considered, some of which are summarized in Table 2
and discussed below.
A minimum level of pollution can be achieved by burning product
gas in the utility boiler, avoiding the need for flue gas clean up. This
gives very low sulfur and particulates compared to burning coal, but of
course the thermal efficiency is also low, and it is probably not a
realistic case. For example, only enough product gas(ca. 20% of the
boiler fuel) need be burned to meet the sulfur emission limitation for
the coal considered here and then a water scrubber could be used to
remove fly ash. But as a limiting case, if the only fuel to the boiler
is product gas then the thermal efficiency would be 53%. This does
bring out strongly the need for a process to clean up the flue gas from
a boiler firing coal, particularly high sulfur coal, so that high value
product gas does not have to be burned in order to control pollution.
It is feasible to use coal as fuel in the coal dryer. If this is
done instead of using product gas, then the thermal efficiency increases
from the base 61% up to 62%. While this is not a large increase, it is
worthwhile. If only coal is fired, sulfur-emission in the vent gas would be
1.4 Ib S02/MM BTU, which is above the standard of 1.2. The standard can be
met by using gas to supply about 20% of the heat, or by partial sulfur re-
moval on the vent gas.
Gas compression is a major consumer of power and thus lowers
the thermal efficiency. Depending upon the situation, a pressure such
as 150 psig may be needed by the gas customer. In other applications
low pressure gas may be sufficient; therefore, we have projected a
case where the product gas is needed at only 15 psig. Thermal efficiency
for this low pressure case is 69% reflecting the saving in compression
power.
An amine scrubbing solution would have quite a low capacity
at this pressure, however other processes can be used that operate
efficiently at low pressure (see 2.4 above). They can reduce the H2S
level down to a few parts per million, which is much lower than
indicated for the amine scrubbing system used in the original design.
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- 24 -
TABLE 2
THERMAL EFFICIENCY
T/D
MM Btu/D
Therma1
Efficiency
6750
1360
8110
119,200
24,000
143,200
Coal To Gasifier
Coal To Boiler
Out*;
Total Gas
Less Gas To Drier
Less Drier and Boiler
Potential Improvements;
Base
Coal Fuel To Drier (vs. Product Gas)
Compression to 15 psig (vs. 150 psig)
* Thermal efficiency based on 150 psig product gas pressure,
93,000
87,000
63,700
657.
617.
537.
617.
627.
697.
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- 25 -
E. TRACE ELEMENTS
Fuels burned in the U.S. in 1970 included: 0.5 billion tons of
coal, 60 billion gallons of fuel oil, and 100 billion gallons of gasoline.
Since the potential contaminants emitted from these sources is so large,
EPA and others are making comprehensive studies on the contribution of
fuels to pollution by trace components. Available data on trace element
contents of fossil fuels have been compiled in reference 20. In addition,
surveys are being made to establish the level of contaminants in the
environment, and the sources of these. In one study the amount of particulates
in urban air was measured, and the concentration of various toxic metals
in the particles was determined for particles of different sizes, in the
range of 1.5 to 25 microns (21). Results indicate that the concentration
of some metals in fly ash is much higher than in the coal. This reference
also compares the amount of trace elements in various fuels. Several
industrial operations were examined to determine the concentration of
elements in the emissions, and this was compared to that in the raw materials.
Coal fired power plants were included, giving a basis for examining the
utility boiler of a gasification plant.
The fate of trace elements during combustion was determined in
another study for both experimental and industrial furnaces (22). Some
85-907, of the mercury in coal leaves in the flue gas, and is not retained
in the ash. Neither is it removed with the fly ash in an electrostatic pre-
cipitator. A large portion of the cadmium and lead are also vaporized
during the combustion process, but the indications are that these will be
retained with the fly ash and can be separated, for example,by an electrostatic
precipitator on the stack gas. A water scrubber could be used, although
it is not known to what extent trace elements may be soluble. This work
also shows that some elements appear in higher concentration in the high
density fractions of coal, so that coal cleaning may be effective in some
cases for control.
Mass balances were made for 34 elements on a coal fired power
station (23). More than 80% of the mercury,a major part of the arsenic,
and probably the selenium leave as a vapor in the flue gas. The electro-
static precipitator was about 98% efficient for removing fly ash and
the elements associated with it. Analytical techniques and problems are
discussed in these references.
It is apparent that further study of the emissions from coal fired
boilers associated with gasification plants will be needed with regard to
trace elements. However, the necessary studies are just getting underway to
define what is emitted, the level that will be acceptable, and control tech-
niques. Therefore it is premature to suggest detailed pollution control
procedures at this time. Such a study will be needed in the near future to
provide guidelines for coal fired boilers.
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- 26 -
Gasification can also release volatile elements from coal, al-
though it may be different than combustion since the atmosphere is reducing.
In many gasification processes the maximum temperature is much lower than
for combustion, but in the Koppers-Totzek process it is comparable. Data
have recently been obtained on the decrease in trace metals in the solids
as they pass thru the sequence of operations in the HYGAS process (24) .
Considerable amounts of many elements are lost from the ash during
devolatilization and gasification, especially mercury (see Table 3). The
loss is appreciable even in pretreating where the maximum temperature is
only 430°C. Preliminary results from the HYGAS bench scale work are
summarized below for solids leaving each processing step - the concentration
being calculated based on the original weight of coal.
TABLE 3
TRACE ELEMENT CONCENTRATION OF PITTSBURGH NO, 8 Bituminous Coal at
VARIOUS STAGES OF GASIFICATION .IN THE HYGAS PROCESS
Calculated on the Raw Coal Basis (From Ref. 24)
Max.Temp.of treat °C
After
Pretreat
430
After
Hydro-
Gasifier
650
After
Electro
Thermal
Gasifier
1000
% Overall
Loss
for Element
Element
Hg
Se
As
Te
Pb
Cd
Sb
V
Ni
Be
Cr
0.27
1.7
9.6
0.11
5.9
0.78
0.15
33
12
0.92
15
PI
0.19
1.0
7.5
0.07
4.4
0.59
0.13
36
11
1.0
17
m •
0.06
0.65
5.1
0.05
3.3
0.41
0.12
30
10
0.94
16
0.01
0.44 '
3.4
0.04
2.2
0.30
0.10
23
9.1
0.75
15
96
74
65
64
63
62
33
30
24
18
0
Although elements are lost, information is neededas to where they will appear,
and in what form (also vapor pressure, water solubility etc). Such results
will be needed for critical elements on all gasification processes used
commercially, to define what recovery or separation may be required and to
allow designing effective pollution control and disposal facilities. It is
expected that a large part of volatilized elements will be recovered in the
scrubbing operations, and whether this will result in complications or side
reactions in the presence of sulfur, phenols, and ammonia, ash, etc., will
not be known until further information is available.
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- 27 -
F. POSSIBLE PROCESS CHANGES
1. Process Alternates Considered
The gasification process was examined to indicate what facilities
should be added to control pollution, or whether simple modifications could
be made to the process to eliminate or minimize the problems. Some of the
alternates considered are summarized in Tablet , classified according to
the section of the process involved.
The general approach in this study was a stepwise attack as
follows:
1. Eliminate the problem if possible by simple modification
of the design.
2. Provide additional pollution control facilities where needed.
3. Increase thermal efficiency of the process by minor changes.
4. Point out where further work is needed to resolve pollution
questions, or where it could improve the operations signifi-
ca nt ly.
Examples of alternates in each of the above four catagories will now be given.
On item 1, it was possible to eliminate the water blowdown from the
ash slurry cooling tower, without changing the basic operation or introducing
major new problems. The only blowdown from the plant is then the water in
the wet ash slurry returned to the mine, and drift "or mist loss from the
cooling tower . The concentration of dissolved solids is still reasonable
and tolerable at the reduced blowdown rate.
With regard to item 2, addition of lime to the ash slurry cooling
water is suggested, to avoid possible loss of t^S to air in the cooling
tower. Also, the vent gas from coal drying needs to be cleaned up by
removing dust, and an electrostatic precipitator, bag filters, or a scrubber
will serve this purpose. In some cases it may be advantageous to combine
the grinding and drying in a single operation.
Item 3 relates to thermal efficiency - an example is the
suggested use of coal as fuel in the dryer to replace high value product
gas used in the original design.
On the final item A, one suggestion, is to develop catalytic hydrolysis
of COS and other sulfur compounds to H2S before acid gas scrubbing, in order
to give better sulfur removal. Also, consideration of another type process
is suggested to allow operating at low pressure, while reducing H2S to a
much lower level than is practical with amine scrubbing. A saving in gas
compression would result if the gasifier could be operated above atmospheric
pressure. This may also increase the capacity per gasifier.
Similar alternates and variations will no doubt become apparent as
reviews are made of high pressure gasification and other fuel conversion
processes.
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- 28 -
TABLE 4
PTinr.F.SS ALTERNATES CONSIDERED
Coal drier;
o
o
o
o
Electrostatic precipitator or bag filters vs water scrubber
Coal fired vs gas fuel (or use boiler flue gas) .
Fluid bed drier vs rotary drum.
Flash drying in mills for lower moisture content coals.
Gas clean-up:
o
o
Effluent water clean-up jvs eliminate blowdown.
Air fins vs cooling tower, or add limestone to scrubber
slurry to~keep free H2S out of air in cooling tower and
ash slurry returned to mine.
Acid gas removal;
o Stretford or similar process at low pressure to replace amine
scrubbing plus Glaus plant with tail gas clean-up.
o Hydrolysis of COS, etc. to H2S will allow clean-up to a few
ppm total sulfur.
Gasifier;
Utilities;
Higher pressure gasifier will save on gas compression.
Purchased power may allow shutting down utility boiler if gas
compression is not required.
Wet bottom vs dry bottom boiler with coal fuel to reduce amount
of fly ash.
If methanation is used, heat of reaction may be used to
generate high pressure steam, particularly if reactor is fluid
bed type. Steam generated will supply a large part of that
required for gas compressor.
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- 29 -
2 . Eng ineering Mod if i ca_t ions
This study was based on a specific Koppers Company design for
a particular application (e.g., the necessity for compression to a higher
pressure). As part of the present study, consideration was given to potential
changes or improvements that might be possible without involving extensive
development or pilot plant operations. Table 5 lists engineering type
modifications that may be desirable.
An important efficiency increase will result if it is acceptable
to provide the product gas at low pressure and save on compression. In
fact, for this case the entire utility boiler can be virtually eliminated
for normal operation although it may be required for start up. This
assumes that electric power requirements are purchased. As indicated,
the low pressure operation is well suited to application of the liquid
absorption/air oxidation type of process for removing H2S from the product
gas. Not only does this allow lower sulfur level in the product gas at
little added effort but, in addition, the tail gas clean-up operation on
the Glaus plant is avoided.
Coal drying is an important operation from the standpoint of
effluents, as well as thermal efficiency, and there is considerable room
for improvement in these respects. A very large volume of gas is required
to provide the sensible heat needed for drying, but it's oxygen content
must be limited to 10-11% max. due to safety considerations. This is
accomplished by recycling part of the vent gas from drying to control the
oxygen level, while treating the remainder to remove sulfur, dust, etc. as
required.
Fuel efficiency is low, about 50%, due to the excess air, even
though the gas exit temperature may be only 500°F. Drying can be carried
out in a rotary drum, by grinding in a stream of hot gas, or in a fluid
bed dryer. To optimize the drying operation in a specific application,
detailed evaluations are warranted of a number of alternates. One possibility
to consider is to use hot flue gas from the utility boiler for drying,
thereby reducing or eliminating the consumption of fuel for drying. This
fuel amounts to 300 T/D of coal in the base case, or 3.7% of the total coal.
Use of boiler flue gas for drying may also allow incorporating or combining
gas clean-up facilities for both operations, e.g. on a coal fired boiler,
dust removal would only be applied after the flue gas has been used for
coal drying.
In general, the waste heat of the process will go either to air
or to water. In a typical cooling tower only 20% to 30% of the heat is
taken out as sensible heat of the air flowing through. The other 70-80%
of the heat is removed by evaporation of water in the cooling tower.
This is by far the major water consumer in the entire process. Thus, for
a plant with no net water effluent the total water consumption for the
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TABLE 5
ENGINEERING MODIFICATIONS
Utility Boiler; Not needed for low pressure
operation with purchased power.
Sulfur Plant
Use liquid absorption/oxidation
on low pressure gas to avoid
Glaus and tail gas clean-up.
Coal Drier:
Use fluid bed drier to reduce volume
of vent gas.
Water Make-Up:
Use air fin cooling to reduce water
consumption and replace ash slurry
cooling tower.
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plant will be primarily set by the thermal efficiency, or rather the
thermal inefficiency. One way to reduce water consumption is to transfer
more of the waste heat to air as sensible heat using air fin exchangers.
Normally, this raises the investment and is relatively inefficient but
at least partial application may be justified for reducing water con-
sumption and potential water pollution where there is an effluent. Air
fins are more suitable for removing higher level heat such as above 150°F.
For low temperature services such as on the steam condensers of turbine
drivers,where the condensing temperature may be only 105°F9it may not be
practical to use air fins.
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3 . Potential Process Improvements
Gas compression is a very large power consumer. Improvements
can be made by reducing the amount of compression required or perhaps by
eliminating it (Table 6) . One means is operating the gasifier at higher
pressure, which will require process development. When supplying clean
specialty fuel gas, it may only be necessary to operate at 2 atmospheres
or less. This should provide enough pressure to flow through the gas
cleanup and acid gas removal sections. Some oxygen compression would be
needed. Increasing the pressure to 10 atmospheres or higher would be of
interest when making synthetic natural gas. Process development questions
are considerably more difficult but the throughput of the gasifier vessel
should be greatly increased. Based on thermodynamic calculations, such a
high pressure operation will increase the amount of contaminants such as
ammonia and cyanide in the off-gas and data on this would be needed.
In general, coal gasification forms a gas containing large
amounts of carbonyl sulfide and possibly other forms of sulfur in addition
to hydrogen sulfide. In order to get complete sulfur removal it is desirable
to convert these other forms of sulfur to hydrogen sulfide which can then be
removed by conventional processes. There is a great need for a process
to hydrolyze carbonyl sulfide, carbon disulfide, etc.,to hydrogen sulfide
at reasonable conditions. It appears that this is possible over simple
catalysts such as alumina, bauxite, and the like at perhaps 400°F to 800°F
(7 ), and development of this type of process would find application in
most of the coal gasification operations to improve and simplify the sulfur
removal system.
The Koppers-Totzek type gasification can be used to make synthetic
natural gas. There are, of course, efficiency debits due to the low
pressure at which the gas is available, as well as the large amount of
shift and methanation required. Methanation is highly exothermic, but
to the extent that this heat can be recovered and converted to useful
high pressure steam the debit is greatly decreased. In fact, the steam
generated in methanation could be enough to supply the balance of the
utilities required by the overall plant to the 150 psig. level. Since
methanation can operate at 800°F to 900°F the temperature level is
suitable. One possibility is to methanate in a fluid bed, with steam
generating tubes in the bed. The catalytic tube process being developed
by the Bureau of Mines is another way.
When required, oxygen represents a large cost item in gasification.
Where the product gas is used simply as clean fuel, it may be that air
or oxygen enriched air would be more attractive. The cost of oxygen by
air fractionation is not reduced much when going to lower purity oxygen,
but this may not be the case if another type of oxygen separation
process is used.
Where the product gas is used for power generation, a combina-
tion gas turbine and steam power plant should be attractive. The gasifier
would operate at above atmospheric pressure as determined by the require-
ments of the gas turbine.
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TABLE 6
POTENTIAL PROCESS IMPROVEMENTS
Higher pressure gasification.
Hydrolyze COS to H-S for complete sulfur removal.
Methanate to SNG (heat release is equal to utility boiler load)
Air or enriched air instead of pure oxygen for low Btu gas.
Combine with gas turbine for power generation.
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G. PROCESS DETAILS
Other details on coal analysis, utilities, etc. are covered
in Tables 7-13 for the present design supplying gas at 150 psig.
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TABLE 7
ANALYSIS OF COAL AND PRODUCT GAS
COAL COMPOSITION
Proximate;
Fixed carbon
Volatiles
Ash
Moisture
100.0
Higher Heating Value: 8830 Btu/lb.
Ultimate:
C 76.72
H 5.71
N 1.37
S 0.95
0 15.21
Cl 0.04
100.00
PRODUCT GAS COMPOSITION (dry basis)
CO 60.88
H2 32.60
C02 5.23
N2 1.16
CH^ 0.10
H2S 0.02
COS 0.01
100.00
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TABLE 8
STEAM BALANCE
High Pressure Low Pressure
Steam Steam
Consumed, Ib/hr.
Oxygen heater - 7,856
BFW pumps on gasifier 22,530
Gasifier steam - 84,735
Gas compressor 507,000
Amine reboiler - 16,500
Oxygen plant 560,000
Oxygen compression 24,000
Power generation (19,426KW) 194,260
1,307,790 109,091
Generated,lb/hr.
Gasifier jacket - 98,527
Gasifier WHB 661,801
Sulfur plant - 11,000
Utility boiler 645,989*
* Coal fired 1360 T/D @ 8830 Btu/lb, HHV.
1,307,790 109,527
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TABLE 9
WATER BALANCE
Ash Cooling Tower Ib/hr
Evaporation 218,598
Drift loss 16,220
In wet slag 4,865
In wet ash 62,802
302,485
Utility Cooling Tower
Evaporation 1,050,000
Drift loss 147,528
Blow down to Ash C.T. 302,485
1,500,013
Consumed in gasifier 11,208
Handling loss on condensate 63,890
Cooling tower makeup 1,500,013
1,575,111
Available in coal & 27, 9,585
Available from 0 plant 8,926
18,511
NET WATER REQUIRED 1,556,600 (3113 gpm)
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- 38 -
TABLE 10
POWER CONSUMPTION
KW
Coal preparation & handling 9,380
Gasifier 155
Scrubber & cooling tower 1,585
Fan on gas to compressor 500
Acid gas removal system °5
Oxygen plant
Sulfur plant 2^1
Cooling water pumps A,500
Cooling tower fans 3,000
TOTAL 19,426
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TABLE 11
FUEL CONSUMPTION
Coal to gasifiers 6,750 T/D
Coal to utility boiler 1,360 T/D
Fuel fired to coal drier 220 MM Btu/hr*
Fuel fired Glaus tail gas
incineration 5 MM Btu/hr
* Equivalent to 300 T/D coal
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TABLE 12.
MISCELLANEOUS INPUT MATERIALS
For water treating:
Cooling water additives;
Other chemicals:
Limestone:
Oil:
Catalysts,etc:
lime, caustic, sulfuric acid,
alum, chlorine.
anti-algae (chlorine), anti-corrosion
(chromate).
amine with additives if any.
if used for flue gas scrubbing, or
to control slag viscosity.
for lubricating pumps, compressors,
etc.
if add shift, methanation, driers,
or guard bed to remove sulfur.
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TABLE 13
POTENTIAL ODOR EMISSIONS
Coal preparation & drier
Ash cooling tower
Sulfur plant
Wet slag and ash to disposal
Utility boiler house
Ponds
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- 42 -
H. RESEARCH AND DEVELOPMENT NEEDS
An objective of EPA is to anticipate pollution problems and
call attention to them ahead of time so that they can be examined care-
fully, and planning or experimental work carried out where a need is
indicated. This approach is intended to:
1. Point out to process developers where pollution problems
may appear, to allow resolving questions well before de-
finite plans are underway on commercial applications.
2. Encourage or support work needed to develop techniques or
processes aimed at pollution control - especially when it
applies to problems that are common to a number of fuel
conversion processes, or where existing technology is in-
adequate .
3. Identify pollution areas that are not yet adequately de-
fined or controlled, and point out what further work is
needed.
An important part of the present study is to review various
gasification processes to identify items of the above types. Results so
far, from examination of this first gasification process, are summarized
in accompaning Table 14 grouped according to the process area.
For example, suggested items on coal drying are applicable to most
coal gasification processes, and are therefore an illustration of a type 2
objective noted above. Similarly, hydrolysis of various sulfur compounds to
H2S would find wide application.
The desirability of a test program on commerical coal gasification
plantSjto identify all trace effluents and their amounts, is an illustration
of a type 3 objective.
An example of the type 1 objectives is the suggestion to add lime
to the ash slurry scrubbing system to fix t^S so that it is not stripped
out by air in the cooling tower. This may also make it satisfactory to
dispose of the solid in a mine, without secondary pollution problems due to
odor, leaching, etc.; however, further information is needed to see whether
this is acceptable.
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- 43 -
TABLE 14
R&D NEEDS
COAL PREPARATION
o Improved drier to allow high gas inlet temperature and
maximize coal preheat without releasing volatiles,
thereby decreasing amount of vent gas to be cleaned up.
o Use warm flue gas from utility boiler to dry coal ahead
of flue gas scrubber.
o Determine leachability of trace metals from coal pile.
o Check for organic run-off in coal piles.
o Determine quantity of volatiles in dryer gas
(e.g., mercury) .
GASIFICATION
o Operate at higher pressure to save compression.
o Increase capacity per gasifier vessel, e-sg. by larger
diameter, a larger number of coal feeders, higher
pressure, and higher temperature to convert more steam.
o Determine leachibility of trace metals from slag.
GAS CLEAN UP
o Catalyst to shift COS etc. to H^S on outlet of gasifier.
o Simple venturi type water scrubber or other equipment to
give very efficient dust removal and demisting.
o Add lime or limestone to ash slurry scrubbing system to
fix H2S and keep it from being stripped out by air in
cooling tower.
o Test program on Koppers Company's operating plants to
define all trace effluents.
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- 44 -
TABLE 14 (CONT'D)
R&D NEEDS
o Selective removal of H2S (and COS,etc.) in presence of
to give less than 1 ppm total sulfur in outlet gas and
concentrated H2S to Glaus plant.
o Where product gas is used nearby as fuel, efficiency
would be improved if dust and sulfur could be removed at
moderate temperature, e.g. 300-1000"?.
o Fate of trace elements in coal; distribution to air,
water, ash, etc., and in what form.
OTHER
o High value use for by-product slag.
o High capacity methanator at 800-900°F to recover heat as
high pressure steam (e.g.,liquid phase or fluid solids to
give good heat transfer).
o Low cost oxygen - even if it is low purity.
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- 45 -
I. QUALIFICATIONS
As pointed out, this study does not consider cost or economics.
Also, areas such as coal mining and general offsites are excluded. These
will be similar and common to all gasification operations. Miscellaneous
small utility consumers such as instruments, lighting, etc., are not
included in the utility balance.
The study is based on the specific process design and coal
type supplied by the process developer, 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, the Koppers Company study happens to be on low sulfur western
coal, although high sulfur coal can be used. Because of variations in
such basis items, great caution is needed in making comparisons between
coal gasification processes since they are not on a completely comparable
basis. Some of the important factors in the study basis that must be
specified in order to make an engineering analysis of a process are
summarized in Table 15.
In some other gasification processes, appreciable amounts of
by-products are made, 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. Such variability further
increases the difficulty of making meaningful comparisons between
processes.
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- 46 -
TABLE 15
GENERAL SELECTION OF STUDY BASIS
Location: Air and water conditions, water treatment,
rainfall.
Coal: Type, preparation, drier type and fuel ash
disposal.
By-Products: Tar, phenols, naphtha, ammonia, etc.
Utilities: Pollution control on boiler
Fuel to boiler
Water quality and treatment
Cooling water additives
Cooling tower operation (fog and drift)
Application of air-fin coolers
Minor Components: Cyanides, ammonia, various sulfur
compounds, and products of interactions
Trace Components; Mercury, arsenic, fluorine, etc.
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- 47 -
J. REFERENCES
1. Koppers,H, H. "The Koppers Totzek Gasification Process", J. Inst.
of Fuel, Dec., 1957, pp. 673-680.
2. "The Gasification of Oil & High-Ash Coal by the Koppers Totzek
Process", Report 76, World Power Conf., Vienna, 1956.
3. "Town Gas Production from Coal by the Koppers Totzek Process",
Gas World, 24, 1962, pp. 315-322.
4. "Koppers Unveils Versatile Coal-To-Gas Process", Oil Gas Journal,
June 19, 1972, p. 26.
5. Sax, N. I. /'Dangerous Properties of Industrial Materials", Reinhold,
1968, 3rd Ed., (ACGIH recommendation for H2S is 10 ppm max.).
6. Sullivan, Ralph J. "Air Pollution Aspects of Odorous Compounds",
Litton Ind. Inc., Rept. of Sept. 1969 prepared for Nat. Air Pollution
Control Admin. (Clearinghouse Rept. No. PB188089).
7. Pearson, M. J./'Hydrocarbon Process, 52, (2), p. 81.
8. Agosta, J.,et al.,"Status of Low BTU Gas as a Strategy for Power
Station Emission Control",AICHE 65th Mtg.,Nov.,1972, New York City.
9. Duprey, R. C. "Compilation of Air Pollutant Emission Factors",
PHS Publication No. 999-AP42, 1968.
10. Federal Register, 36, (247), 24876, Dec. 23, 1971.
11. Bartok, W., Crawford, A. R., and Piegari, G. J., "Systematic Field
Study of NOx Emissions Control Methods for Utility Boilers", P.B. 210739,
Dec. 1971.
12. Crawford, A.R., Manny E.H., and Bartok W., "NOx Emission Control for
Coal-Fired Utility Boilers", presented at the Coal Combustion Seminar,
EPA, North Carolina, June 19-20, 1973.
13. Coalgate, J, L., Akers, D. J. and From, R. W. "Gob Pile Stabilization,
Reclamation, and Utilization",OCR RE?D Report 75,1973.
14. Final Report, Sulfur Oxide Control Technology Assessment Panel.,
APTD-1569, April 15, 1973.
15. Jones, J. J. "Limestone Sludge Disposal",Flue Gas Desulf. Symp.,
New Orleans, May 14, 1973.
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- 48 -
16. "Control Techniques for SOX Air Pollution", Kept. AP-52, U.S.
Dept. Health, Jan.,1969.
17. Gifford, D. C.,"Operation of a Wet Limestone Scrubber", Commonwealth
Edison Co., Chicago, Chem. Eng. Prog .,_69_,(6) ,p. 86, June, 1973.
18. Horlacher, W. R. et al. ,"Four S02 Removal Systems",Chem. Eng. Prog.,
j>8, (8), p. 43, Aug., 1972.
19. Slack, A. V.,"Removing S02 from Stack Gases", Environmental Science
and Tech., ^,(2), Feb. 1973.
20. Magee, E. M., Hall, H. J. and Varga, G. M. Jrk, "Potential Pollutants in
Fossil Fuels", EPA-R2-73-249, NTIS PB Noe 225,039, June 1973.
21. Lee. R. E.,et al.,"Trace Metal Pollution in the Environment", Journ.
of Air Poll. Control, 23, '(10),Oct.,1973.
22. Schultz, Hyman et al.,"The Fate of Some Trace Elements During Coal
Pre-treatment and Combustion", ACS Div. Fuel Chem. 8, (4)f
p. 108, Aug., 1973.
23. Bolton, N. E.,et al.,"Trace Element Mass Balance Around a Coal-Fired
Steam Plant", NCS Div. Fuel Chem., _18, (4), p. 114, Aug. 1973.
24. Attari, A. "The Fate of Trace Constituents of Coal During Gasification",
EPA Report 650/2-73-004, Aug.,1973.
258 Atmospheric Emissions from Petroleum Refineries, U.S. Dept. of Health,
Educ. and Welfare, Public. No. 763, 1960.
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- 49 -
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-650/2-74-009a
3. RECIPIENT'S ACCESSION1 NO.
4. TITLE AND SUBTITLE E valuation of Pollution Control in
Fossil Fuel Conversion Processes; Gasification;
Section 1: Koppers-Totzek Process
5. REPORT DATE
January 1974
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
E.M. Magee, C.E. Jahnig, and H. Shaw
8. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Esso Research and Engineering Company
P.O. Box 8
Linden, NJ 07036
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. SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a study of pollution control and thermal efficiency of
the Koppers-Totzek process for producing clean, low-Btu (303 Btu/cu ft) gas from
coal. It estimates quantities of potential pollutant streams and gives a preliminary
design that ensures clean up of these streams where appropriate pollution control
techniques are available. The report points out information gaps and research
needs, and discusses process alternatives and potential process improvements.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
bal Gasification
Fossil Fuels
Thermal Efficiency
Trace Elements
Air Pollution Control
Stationary Sources
Clean Fuels
Koppers-Totzek Process
Fuel Gas
Research Needs
Low-Btu Gas
13B
3. DISTRIBUTION STATEMEN1
19. SECURITY CLASS (This Report)
21. NO. OF PAGES
49
Unlimited
20. SECURITY CLASS (This page)
22. PRICE
EPA Form 2220-1 (9-73)
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