EPA-650/2-74-009-d
DECEMBER 1974
Environmental Protection Technology Series
I
55
\
ul
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
11
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EPA-650/2-74-009-d
EVALUATION OF POLLUTION CONTROL
IN FOSSIL FUEL CONVERSION PROCESSES
GASIFICATION; SECTION I: C02 ACCEPTOR PROCESS
by
C. £. Jahnig and E. M. Magee
Exxon Research and Engineering Company
P.O. Box 8
Linden, New Jersey 07036
Contract No. 68-02-0629
ROAP No. 21ADD-023
Program Element No. 1AB013
EPA Project Officer: William J.Rhodes
Control Systems Laboratory
National Environmental Research Center
Research T-riangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S . ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
December 1974
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U. S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation. equipment and methodology
to repair or prevent environmental 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.
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TABLE OF CONTENTS
Page
SUMMARY 1
INTRODUCTION 2
1. PROCESS DESCRIPTION AND EFFLUENTS 4
1.1 C02 Acceptor Process - General 4
1.2 Effluents to Air in Main Gasification Stream 13
1.2.1 Coal Preparation 13
1.2.1.1 Original Design 14
1.2.1.2 Revision to Decrease
Sulfur Emission 16
1.2.2 Gasifier 18
1.2.3 Gas Cleaning 19
1.2.4 Acid Gas Removal 19
1.2.5 Methanation and Compression 19
1.2.6 Regenerator 20
1.2.7 Ash Desulfurizer 20
1.3 Effluents To Air - Auxiliary Facilities 21
1.3.1 Sulfur Plant 21
1.3.2 Utilities 21
1.4 Liquids and Solids Effluents 23
1.4.1 Coal Preparation 23
1.4.2 Gasifier 24
1.4.3 Gas Clean-Up 24
1.4.4 Methanator 25
1.4.5 Gas Compression 26
1.4.6 Regenerator 26
1.4.7 Auxiliary Facilities 28
2. SULFUR BALANCE 31
3. TRACE ELEMENTS 34
4. THERMAL EFFICIENCY 37
5. POSSIBLE PROCESS CHANGES 40
5.1 Process Alternatives Considered 40
5.2 Engineering Modifications 42
5.3 Potential Process Improvements 44
5.4 Process Details 46
- iii -
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TABLE OF CONTENTS (Cont'd)
Page
6. TECHNOLOGY NEEDS 54
7. QUALIFICATIONS 57
8. BIBLIOGRAPHY 59
- iv -
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LIST OF TABLES
Table Page
Table of Conversion Units 3
1 Gasifier Heat and Material Balance
System Pressure, 150 psig 9
2 Regenerator Heat and Material Balance
System Pressure, 150 psig 10
3 Stream Identification for Figure 3 11
4 Sulfur Balance 32
5 Trace Element Concentration of Pittsburgh No. 8
Bituminous Coal at Various Stages of One
Gasification Process 35
6 Thermal Efficiency 38
7 Process Alternatives Considered 41
8 Engineering Modifications 43
9 Potential Process Improvements 45
10 Composition of Lignite Feed and Product Gas 47
11 Steam Balance 48
12 Water Requirements 49
13 Power Consumption 50
14 Lignite and Fuel Consumed 51
15 Potential Odor Emissions 52
16 Miscellaneous Inputs 53
17 Technology Needs 55
18 General Selection of Study Basis 58
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LIST OF FIGURES
Figure
1
2
3
4
5
6
7
C02 Acceptor Process with Modifications
Consol Flow Diagram for Lignite Grinding
Page
.... 5
.... 6
.... 7
.... 8
.... 15
,... 17
33
- vi -
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- 1 -
SUMMARY
The CC>2 Acceptor Coal Gasification Process 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 the thermal efficiency of the process. For the purpose of
reducing environmental impact, a number of possible process modifications
or alternatives have been proposed and new technology needs have been
pointed out.
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- 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 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
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 ESxon
Research & Engineering Company under contract EPA-68-02-0629, using all
available non-proprietary information.
The present study .under the contract involves preliminary
design work to assure the processes are free from pollution where pollution
abatement techniques are available, to determine the overall efficiency of
the processes and to point out areas where present technology and informa-
tion are not available to assure that the processes are non-polluting. 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 indicates 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 concerning technology gaps that exist for techniques
to control pollution or conserve energy. Maximum use was made of the
literature and information available from developers. Visits with some
of the developers were made, when it appeared warranted, to develop and
update published information. Not included in this study are such areas as
cost, economics, operability, etc. Coal mining and general offsite facilities
are not within the scope of this study.
Considerable assistance was received in making this study, and
we wish to acknowledge the help and information furnished by EPA and
The Conoco Coal Development Company (formerly the Consolidation Coal
Company).
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- 3 -
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
Calories, kilogram
Cubic meters/day
Meters
Cubic meters/minute
Centimeters
Kilograms
Kilograms/calorie
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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- 4 -
1. PROCESS DESCRIPTION AND EFFLUENTS
1.1 C02 Acceptor Process - General
This process makes synthetic natural gas (SNG) from lignite
by gasifying it with steam at 1500°F and 150 psig. Heat is supplied
indirectly by circulating dolomite which also takes up C0£ and sulfur.
After clean-up to remove dust and sulfur, the gas is methanated, giving
a heating value of 952 Btu/cf HHV. Since the gas fed to methanation
has a high hydrogen content, it requires no shifting or C02 removal
ahead of the methanator. It is compressed and dried to meet pipeline
requirements.
The C02 Acceptor Process has been operated in large pilot
facilities and is described in the literature (1,2,3). The basis as
supplied by the developer is shown in Figures 1 and 2, Tables 1 and
2 and Reference (3). The plant is sized to make 250 x 10^ Btu/day
(262.6 MM SCFD) of pipeline gas. Additions were made as required to
control pollution, and to arrive at a complete picture with all
effluent streams defined, according to available data, together with
utilities balances for steam, power, and water. Results of the study
are summarized in the overall flowplan on Figure 3, while all input
and effluent streams are shown in Figure 4 and Table 3.
The C02 Acceptor Process has been operated on lignite but
is not considered operable on Eastern coal because higher temperatures
are needed to get reasonable reaction rates. The higher system pressure
needed to give enough C02 partial pressure in the gasifier results in
a higher regenerator temperature which would be needed to calcine the
acceptor, and, which in turn would cause slagging of the fuel char ash
as well as severe loss of acceptor activity.
Raw lignite containing 33.67% moisture is supplied to
the plant and is dried and preheated to 500°F. Heat for this operation
increases the lignite feed requirement by 8-9%. Preheated lignite
is raised to system pressure using lock hoppers. All lift gas and
other gas used in this system is collected and returned through the
dryer and bag filters for clean-up before release to the air.
The lignite is gasified with steam in a fluid bed reactor
at 1500°F and the developer indicates that negligible tar or phenols are
formed during normal operation, based on pilot plant results. However,
there may be some during process upsets. Steam feed is preheated to
1200°F and steam conversion in the gasifier is about 70%. One-fourth
of the heat required in the gasifier is supplied by sensible heat in
the circulating dolomite returned at 1850°F, while the remainder comes
from the heat of reaction when the dolomite takes up COo.
Raw gas from the reactor is passed through a waste heat boiler
to generate steam and is then scrubbed to remove dust and ammonia. There
may also be some tar, phenols, etc., during start-up or upsets, and there-
fore provision for handling them is included. In the acid gas removal
unit, sulfur is removed to protect the methanation catalyst, and a
minor amount of C02 is taken out so that the total amount of carbon
-------
Figure 1
COAL PREPARATION
Flow Plan by Consolidation Coal Co.
To
Stack
Lignite
From
Storage
Preheater
Dry Lignite
( ) 1% Moisture
Air
Inert Gas
Inert Gas
To
Stack
Feed Bin
Lock Hoppers
To Gasifier
(zero moist.)
Lignite
Lignite
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- 6 -
Figure 2
GASIFICATION SECTION
Design Basis by Consolidation Coal Co.
Preheated Lignite
500°F
1,368,000 Ib/hr
zero moisture
Steam ———
GASIFIER
Air
Dolomite
Make-Up
Raw-Gas
To
Clean-Up
Remove NH3, l^S
and 7.6% of C02
content,
then methanate
Pipeline
Product Gas
Reject
Acceptor
93.00
4.84
0.10
1.31
0.75
250 x 109
BTU/Day
CH4
H£
CO
C02
N2
REGENERATOR
To Flue Gas
Turbine
H2S to Sulfur Plant
ASH
DESULF.
Complete heat and
material balances
supplied by
developer for this
part of process.
TT
C02 Water
-^ Carbonated
Ash
226,000 Ib/hr
1530 mols/hr
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Figure 3
C0« Acceptor Process with Modifications to Reduce Emissions
Block Flow Diagram to Show Major Streams for Complete Plant Including Auxiliary Facilities
Bnsls- 250 x 109 Btu/dav of Pipeline Gas
(Numbers are Ib/hr except where indicated.)
Flue Gas
31.3 MM SCFH
(ash from fuel 9790)
Spent Acceptor
162,810
To Sulfur Plant
0.22 MM SCFH
Raw Lignite
Feed
2,296,500
(33.671 moist.)
86,870 lignite (zero
moist.)
plus
1.00 MM SCFH gas
(341 Btu/CF)
Pipeline Gas Product
250 x 109 Btu/day
(10.9 MM SCFH)
»-
1000 pslg
952 Btu/SCF HHV.
(262.6 MM SCFD)
Air
44.5 MM
SCFH
Dolomite
makeup
254,454
Carbonated ash slurry (.101 sulfur, dry basis)
f 466,000 (501 water)
Sulfur
Plant
Acid gas to sulfur plant
0.45 KM SCFH
23.6* H.S
26.41 CO,
50.01 HoO
Water
15,800 Ib/hr
A A
'
Acld Ga«
°'67 m SCFH
°-35
SCFH
-------
Figure 4
Design Revised To Incorporate Environmental Controls And All
234 5 67 89 10 11
Mi 1 '• | Uf|
i • i i i i
nnu iii « .... i i i i
Lignite CQAL
! Feed PREP. Preheated GASIFIER Raw ""*
* Lignite* Gas * RELUVtRH
III! - " " 11
i i i i " i i
Cooled
Gas
sr.RHRRFR Scrubbed^
Gas
TT
19 20 21 22 4 —Char 24 25 26 27
GASIFICATION PROCESS Acceptor ^Acceptor 33 34 35
* a 11
[ It
HEAT
.«:««.«« F1"e RECOVERY,
GaS DUST
REMOVAL
Flue
Gas
GAS
TURBINE
TT r
43 44 45
Ash 53 54
J_*
1 l
NOTE Streams Indicated by a heavy dashed line
are emitted to the environment, all others
ASH
Streams Including Auxiliary Facilities
12 13 14 15 16 17 18
f M |
1
1 i 1
ACID GAS
REMOVAL
Low S
Low Btu
Gas
t t 1
1 1 1
METHANATOR
! I
28 29
High Btu
Gas
COMPRESS Plpellne
AND ^»
DRY Gas Product
T TT
30 31 32
36 37 38 39 40 41 42
/
AUXILIARY FACILITIES
i* T T * * 1
: 1 : : 1
SULFUR
PLANT
T
cc c< *6
55 56 57
Ml
i • i
iii
WASTE
TREATMENT
COOLING
TOWER
111 11!
47 48 49 50 51 52
58 59 60
fit
1 1 1
MAKE-UP
TREATMENT
\\
61 62
TTT TT
63 64 65
66 67
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Basis: 100 Ib dry lignite
fed to gasifier *
Datum: 60°F, liquid water
- 9 -
TABLE 1
CO ACCEPTOR PROCESS (4)
Gasifier Heat and Material Balance
System Pressure. 150 psig
Lbs.
Mols
Mol
°F
Enthalpy,
Btu
Ht. of
Combustion,
Btu
(2)
35.15
(11.519) (.08938)
5.572 .03128 35-00
4.392 .05780 64.66
.034 .00030 .34
1.521
Preheated Lignitev ' 100
Steam 6-5000
Acceptor (506.86)
MgO.CaO 403.83 4-4692
Inert 76.03
Heat of Reaction
MgO.CaO to MgO.CaC03
Output
Fuel Char to Regenerator
Reject Acceptor
MgO.CaC03
MgO.CaO
MgO.CaS
Inert
Acceptor to Regenerator
MgO.CaO>3
MgO.CaO
MgO.CaS
Inert
Product Gas, dry basis 7-1773
CH4
CO
C02
H2
H2S
NH3
N2
Unconverted Steam 2.3620
Heat of Reaction
Ht. of Combustion (reactants -
products ex Acceptor)
Coal sulfur to MgO.CaS
Heat Loss
(564.41)
215-23
273.02
1.653
74.51
(4.3798)
1.5329
2.8322
.0147
35.00
64.66
.34
H, wt- % 4.01 -54
C 65-37 63.41
N 1-10 -25
0 (diff.) 17.17 2.26
S .90 -97
Ash 11.45 32.57
6.08
15.19
6.91
70.91
.033
.65
.22
500 14,501
1200 188,302
1856 220,691
119.192
542,686
1,112,000
1500
16,659
4,148
203,264
79,951
75,407
155,275
4,524
3.458
542.686
1,112,000
332,170
935,105
(-155,275)
1.112.000
Lignite is fed to gasifier at 500°F and
contains zero free moisture. Raw lignite
contains 33.67% moisture, which is removed
in dryer-preheater.
Consolidation Coal Co.
December 5, 1974
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- 10 -
TABLE 2
CO ACCEPTOR PROCESS (4)
Regenerator Heat and Material Balance
System Pressure. 150 psig
Basis: 100 Ib dry lignite
fed to gasifier
Datum: 60°F, liquid water
Input . .
Fuel Char
Char Lift Gas (same composition as
outlet gas)
N
Lbs.
Mols
Mol % °F
Ht. of
Enthalpy, Combustion,
BTU BTU
35.15
.440
8.2973
.0490
20.88
78.53
.59
1500
290
290
16,659
807
14,365
332,170
1,370
Acceptor
MgO.CaCO
MgO.CaO
MgO.CaS
Inert
Makeup Stone
MgC03.CaC03
Inert
(564
215
273
1
74
( 18
16
1
.41)
.23
.02
.653
.51
.003)
.482
.521
(4
1
2
.3798)
.5329
.8322
.0147
.08938
35.00
64.66
.34
1500 203,264
60
Heat of Reaction
Sulfide Sulfur (in - out)
Heat of Combustion (reactants -
products, ex acceptor)
Output
r
Overhead
Calcined Acceptor
MgO .CaO
Inert
Gas
CO
C0
(3)
H20
Heat of Reaction
MgO.CaCO, to MgO.CaO
MgCO^.Cai
.CO., to MgO.CaO
o
Heat Loss
H, wt. %
C
N
0 (diff.)
5
Ash
(1)
.54
63.41
.25
2.26
.97
32.57
(2)
_
3.55
_
_
5.19
91.26
12.547
(506.86)
430.83
76.03
4.4692
10.6765
217
294,118 ( -294,118)
529,430 39.422
18
2.47
32.06
.056
64.07
1.29 >
56 5,535 6,352
220,691
173,400 33,070
/
116,807
10,816
2,176
529,430
39,422
(3) Gas also contains the following sulfur coin-
compounds, ppmv:
SO, 371
s 6 Consolidation Coal Co.
H?s 37 December 5, 1974"
COS 54
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- 11 -
Table 3
STREAM IDENTIFICATION FOR FIGURE 3
Strean
Identification
Flow Rate
1
*2
*3
*4
*5
6
7
8
*9
10
*11
12
*13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
*34
*35
*36
*37
38
39
*40
^41
42
43
44
45
46
47
48
49
50
51
52
53
*54
*55
«56
*57
58
*69
*60
61
62
63
64
65
66
67
Lignite feed
Rain runoff
Vent gas from dryer
Ash from dryer fuel
Reject acceptor
High pressure steam
Low pressure steam
Cooling water
Warm air
Sour water
Fine solids
Water condensate
Chemical purge
H2S/C02 to Sulfur plant
High pressure steam
Water condensate
Cooling water
Water
Rain
Air
Solid fuel to dryer
Gas fuel
Steam
Boiler feed water
Boiler feed water
Air for cooling
Cooling water
Steam for heating
Amlne or scrubber medium
Boiler feed water
Cooling water
Dryer agent
Steam from regenerator
heat recovery
Flue gas from turbine
Dust
Sulfur
Flue Gas
Steam
Cooling water
Air
Water
Additives
Air
Dolomite
Boiler feed water
Fuel gas
H2S/C02 Streams
Air
Boiler feed water
Cooling water
Air
Additives
H2S/C02
Ash slurry
Ammonia
Oil, phenols
Sludge
Water
Sludge
Miscellaneous chemicals
C02
Water
Sour Water
Water
Miscellaneous chemicals
Water
Miscellaneous chemicals
2,296,500 Ib/hr
e.g. 6 in. m 24 hr.
31.3 MM SCFH
9790 Ib/hr
162,810 Ib/hr
525,000 Ib/hr
190,000 Ib/hr
8,800 gpm
670 MM SCFH
612,000 Ib/hr
not defined yet
63,000 Ib/hr
—
220,000 SCFH
1,050,000 Ib/hr
483,000 Ib/hr
12,000 gpm
3,700 Ib/hr
e.g. 6 in. in 24 hr.
14.3 MM SCFH
86,870 Ib/hr
1.00 MM SCFH
1,653,700 Ib/hr
525,000 Ib/hr
190,000 Ib/hr
670 MM SCFH
8,800 gpm
63,000 Ib/hr
__
1,050,000 Ib/hr
12,000 gpm circl.
—
567,000 Ib/hr
57.3 MM SCFH
unknown
9,920 Ib/hr
960,000 SCFH
6,300 Ib/hr
42,900 gpm circl.
620 MM SCFH
43,000 Ib/hr
—
44.5 MM SCFH
254,454 Ib/hr
567,000 Ib/hr
65,000 SCFH
670,000 SCFH
337,000 SCFH
6,300 Ib/hr
42,900 gpm circl.
620 MM SCFH
--
450,000 SCFH
466,000 Ib/hr
11,200 Ib/hr
unknown
—
1,420,000 Ib/hr
—
--
600,000 SCFH
15,800 Ib/hr
612,000 Ib/hr
e.g. 6" in 24 hr.
—
1,420,000 Ib/hr
—
Comments
Main lignite stream from mine.
Drainage from storage and coal prep'n. area.
Hot gas from drying and preheating.
Fly ash from burning lignite fines.
Removed to maintain activity of acceptor.
From waste heat boiler on raw gas.
From waste heat boiler on raw gas.
From cooler on water scrubber
From air fin cooler after scrubber.
From scrubber; contains H2S, NH3 (10,700 Ib/hr),
tar, phenols, etc.
From clarifier on scrubber.
From steam reboller (clean water).
e.g. amine, used for acid gas removal.
H2S/C02 removed and 5.91 H2S sent to sulfur plant.
From waste heat boilers recovering heat
of reaction.
Formed by methanatlon reaction.
Cooling water on compressor.
Removed on compressor and dryer.
Rain on coal storage pile.
Combustion air on dryer-preheater
Lignite fines burned on dryer.
Gas fuel to preheater and dryer.
Reaction steam to gaslfier.
To waste heat boiler.
To waste heat boiler.
Air to air-fins on raw gas.
Cooling water on raw gas.
For reboiler or regeneration.
Scrubbing liquid on acid gas removal-
Steam generator on methanalor.
For after cooler on compressor.
Glycol, molecular sieve, or other drying agent.
Steam generated (excludes superheating).
Dust control provided - after turbine.
From dust removal - after turbine.
From Sulfur plant.
Tall gas from sulfur plant.
Generated by sulfur plant.
From cooling tower.
Used for cooling (plus 535,000 Ib/hr water evap.)
Drift loss.
e.g. chromium, chlorine, used to control
fouling and corrosion.
Combustion air to regenerator.
Make-up acceptor.
To waste heat boiler on regenerator gas.
To incinerator on Claus plant.
Streams 14 and 53.
For oxidation in Claus reaction.
To waste heat boiler on Claus plant.
Warm cooling water In
ambient air to cooling tower.
e.g.chromium, chlorine, used to control
fouling and corrosion.
Stripped off In ash desulfurlzatlon.
Carbonated ash from ash desulfunzer
In 50% slurry with water.
By-product recovered from waste water tr.
Separated from waste water treat
Separated from waste water treat.
Treated make-up water.
From make-up water treatment.
H2SO^, caustic, alum used for treating.
Stripping gas to ash desulfurlzatlon.
Used in ash desulfurlzatlon.
From scrubbing raw gas.
Rain run-off from coal storage and process
areas.
If used to treat waste water.
Make-up water to plant.
As used to treat make-up water.
* NOTE:
These streams are emitted to the environment.
All others are retained within the process.
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- 12 -
oxides is just enough to use up all of the hydrogen during methanation.
The latter gives a very high heat release corresponding to 19% of
the heating value on the gas fed to methanation. It is highly desirable
to recover this heat in the form of steam or useful preheat, as other-
wise it must be rejected to cooling water or air.
The regenerator serves two purposes in that it calcines the
acceptor to remove CC>2, and in addition reheats the acceptor to supply
sensible heat to the gasification reactor. Regenerator fuel is supplied
by feeding a separate stream of char from the gasifier, and burning
it completely in the regenerator. Thus, the dolomite is separated from
char by elutriation in the reactor before it is circulated to the
regenerator. The regenerator is operated under slightly reducing
conditions in order to avoid sulfate formation which causes fusion
and deposits. The flue gas contains 2.47 Vol. % CO, and this is burned
to generate additional heat for recovery. The hot flue gas goes through
a heat exchanger to superheat steam to 1200°F. The hot flue gas is
then used to generate additional steam in a boiler before passing to
the flue gas turbine. The turbine generates enough power to drive both
the air compressor and the product gas compressor.
As a result of the favorable energy balance for the acceptor
process, no utility boiler is required to supply steam or power for
the process during normal operation. In other words, all utilities
are provided by waste heat recovery to generate steam, together with
the output of the flue gas turbine. No oxygen is needed but there will
be a sulfur plant, and waste water treatment to control phenols, ammonia,
and suspended solids. The only water effluent from the plant in normal
operation will be the water used to slurry residual ash from the lignite
feed. Some spent acceptor is rejected to maintain activity and this
will be in a dry form, low in sulfur, and probably is suitable to use
as land fill. It appears that surplus power or steam could be made
available from the process as shown, and supplied to the shops, mine,
and general off sites. A more extensive utilities study would be needed
to explore this.
Ash from the regenerator has a high sulfur content in forms
such as calcium sulfide which could cause a secondary pollution problem
due to release of hydrogen sulfide. The developer, therefore, included
treatment of the ash with carbon dioxide and water at 190°F to remove
98% of the sulfur. The resulting H2S is sent to the sulfur plant. Flow
rates for the ash desulfurizing operation are shown in Figure 2 based on
25% excess C02 over the theoretical. It may be assumed that the C02
required in the ash desulfurizer will be supplied from the regenerator
flue gas, 3% of which could supply all the CC>2 needed. The flue gas
might be used directly, or it might be processed to provide a more
concentrated stream of €02*
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- 13 -
1.2 Effluents to Air in Main Gasification Stream
Effluents to the air are shown in Figure 4 and listed in
Table 3 for the case incorporating modifications to improve environmental
aspects, and to include all auxiliary facilities and utilities. The
plant is sized to make 250 x 10^ Btu/day of synthetic natural gas
having a higher heating value of 952 Btu per cubic foot (262.6 MM SCFD).
Total consumption of lignite is 28,517 tpd of 33.677. moisture content.
The preheated lignite fed to the gasifier contains .907. sulfur, 11.457.
ash, and has a higher heating value of 11,120 Btu per pound. Further
details on the feed and products are given in Tables 1 and 2 and in
Reference 3.
1.2.1 Coal Preparation
The first effluent to the air in the process flow is from the
coal storage and preparation area. Large storage piles are needed in
view of the high lignite consumption rate, and dust problems can be
expected due to wind, handling, loading, and unloading. The equipment
should be completely enclosed as much as possible to minimize dusting
and spills. Precautions are also needed to prevent fires in the storage
pile, as lignite is especially liable to spontaneous combustion (5) .
Tamping down of the storage pile as it is being formed is one customary
precaution, but facilities and plans are also needed for extinguishing
fires if they occur. These are general observations and need careful
consideration and definition for specific projects.
The next effluent is from the coal drying system where hot
combustion gas is contacted with the lignite feed containing moisture
to accomplish drying. General requirements are that the hot gas must
be introduced at less than 1000°F so that local over-heating does not
occur and release a large amount of volatile material from the lignite.
Also, oxygen content of the gas is held down to about 117. or less by
recycling flue gas. in order to meet safety requirements.
Coal drying and preheating is a major area for consideration,
due to the large fuel consumption (8-97. of the lignite feed) and the
large volume of vent gas (1156 MM cfd) to be cleaned of dust and sulfur.
The original design used only lignite fines for fuel and has a high
sulfur emission, 1.6 Ibs of 862 per MM Btu fired vs 1.2 Ib/MM Btu allowed
for large stationary power generation. Therefore, a modified design
was made with supplemental fuel gas to reduce total sulfur emission.
These cases are discussed in sub-sections below.
For large coal fired stationary power plants, NOX content of
the flue gas must meet the emission standard of 0.7 Ib N02/MM Btu. It
has been shown that NOX can be decreased by minimizing excess air, and
by designing the combustion system to limit flame temperature. These
same considerations should be incorporated in coal fired operations used
to dry and preheat coal.
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- 14 -
1.2.1.1 Original Design
A flow plan of the overall coal preparation system supplied by
the developer is shown in Figure 1, and corresponding flow rates are shown
in Figure 5. Raw lignite containing 33.67% moisture is fed to a grinder
which is swept with hot recirculating gas to dry the lignite down to
16% moisture. Part of this is further heated to 500°F in the preheater
to provide feed to the gasifier, while the remainder is used as fuel
in the three furnaces of the coal preheat section. One of these furnaces
supplies hot gas to the grinder, another to the dryer, and the third to
the preheater. In each case, hot gas from the furnace is tempered with
recirculating flue gas or with flue gas from the regeneration vessel
so as to avoid local overheating of the lignite, which would release
volatile combustible matter.
Combustion of the lignite fuels generate ash which needs to be
separated and rejected. Slagging type furnaces are used, where an estimated
70% of the ash is removed. Hot gas leaving the furnace is tempered and
passed through cyclones to remove nearly all of the remaining ash. If
the final ash content of the hot gas is comparable to the 0.1 Ibs per
MM Btu required on stationary boilers, then overall separation of the
ash must be 99% efficient. This degree of separation has been difficult
to achieve with conventional cyclones in power plant boilers using coal
fuel.
The hot gas is contacted with lignite in the grinder and will
pick up lignite fines which also need to be recovered. To meet the
comparable dust loading for stationary boilers of 0.1 Ibs per MM Btu,
the dust remaining in the vent gas after final clean-up can be only
155 Ibs per hour. That this represents a difficult clean-up problem
is illustrated by the fact that the loss corresponds to only .01 weight
percent of the lignite charge on a dry basis. Emission of dust might
be controlled adequately by using bag filters, electrostatic precipitation
or a scrubber. Recovered solids could be returned to the gasifier or
regenerator vessel, while ash from the furnaces can be disposed of
along with the carbonated ash from the ash desulfurizer.
Sulfur content of this particular lignite is such that when
it is used as fuel, the sulfur content of the resulting flue gas will
exceed the specification set for stationary boilers. It gives 1.6 Ibs
of S02 per million Btu vs the 1.2 specification. The developer has
pointed out that the lignite is adsorbent and may remove sulfur compounds
from the flue gas. If 25% of the sulfur were adsorbed in this way then
the flue gas would meet emission standards for stationary boilers. This
would be very desirable and screening experiments should be made to
explore the possibility. Stack gas clean-up could also be used in order
to reduce the sulfur emission to a reasonable level. Processes are
offered commercially for this, such as limestone scrubbing or one of
the regenerable liquid scrubbing systems.
One further concern on emissions from the coal preparation area
is with regard to odors. Lignite is a relatively reactive material and
when dried and preheated to 500°F small amounts of vapors are evolved
including carbon dioxide and combined water.
-------
Figure 5
CONSOL FLOW DIAGRAM FOR LIGNITE GRINDING AND DRYING
Basis: 250 x 109 MM Btu/Day of Pipeline Gas
48,120 MPH
(2)
'
i
20,080 MPH
i
VENT
(1) AIR
126,740 MPH 41,390 MPH
t
[ 6,420 MPH 15,070 MPH
7 i», 1*30 Ib/hr
FURNACE
2,305,440 Ib/hr ^
•
\
|
lag rH
0
!?
in
(O
AeV.
GRINDER
' 25,560 Ib/hr
59,980 Ib/hr
< r V \
FURNACE FURNACE '
Ln
(3) V V
slag ^Slag
77,620
MPH ^ (4) ^ 37.830 MPH From
55,820 MPH (5) Regenerate]
h »-A
' f ^
DRIER 1,390,200 lb/hr_ PREHEATER 1,368,000 Ib/hr
1,820,470 1,655,000
Stream
, mol
C02
H2°
S00
(1)
(2)
(3)
(4)
(5)
.40
15.67
38.48
.0438
45.40
.77
7.16
59.91
.0379
32.11
.16
21.06
24.92
.0476
53.81
0
27.77
6.88
.0555
65.79
.12
32.76
1.28
.0449
65.79
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- 16 -
It is also possible that undesirable odors will be released,
particularly if there are any zones of local overheating. If odors are
a problem then it may be necessary to provide incineration on the
effluent gas. This would, of course increase the fuel requirement
quite significantly, so hopefully it can be avoided. If the odors are
only associated with the preheater offgas, then this stream could be
sent to the combustion zone of one of the other furnaces for incineration.
Since it is a small stream,there would be little effect on heat balances.
Emission of nitrogen oxides from the furnaces must also be
controlled. The usual techniques for decreasing NQg formation are generally
aimed at lowering the combustion or flame temperature. Since the furnaces
in this design operate with a high combustion temperature to produce
slagging, it is likely that the emission of nitrogen oxides will exceed
the standard of 0.7 Ibs N02 per MM Btu specified for stationary power
plants. One method of control would be to lower the combustion zone
temperature in the furnaces by adding inert gas available from the
regeneration system, or flue gas from the coal drying system could be
recycled to the furnace for this purpose. More ash would then be
removed by the cyclones.
There is an urgent need for effective practical methods to
remove NOX from flue gas. Although no established process is available
now for this purpose, a considerable effort is being directed at the
problem in the United States and elsewhere. Progress is encouraging,
and it is expected that suitable processes will be demonstrated and
become available in the near future.
1.2.1.2 Revision to Decrease Sulfur Emission
In the modified design, sulfur emission from the coal preparation
section is decreased primarily by using some desulfurized low Btu gas from
the gasification section as fuel to the furnaces. This gas is not methanated
but rather is drawn off after acid gas removal. The modified system is
shown in Figure 6.
To bring total sulfur emission down to the target 1.2 Ibs SC>2
per MM Btu requires replacing 25% of the lignite fuel with gas, corresponding
to 1.0 MM SCFH or about 2.6% of the total gas made by gasification. For
simplicity, flue gas from the regenerator has not been added to the coal
preparation system. Instead, flue gas from the dryer is recycled through
the furnaces to lower flame temperature and thereby reduce NOx formation.
As in the original design, cyclones are used to separate ash
from the hot gas after the furnace. The hot gas of course picks up
lignite fines in passing through the drying and grinding operation,
therefore, bag filters are provided on the vent gas streams in order to
recover all dust.
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- 17 -
Figure 6
COAL DRYING SYSTEM
ALTERNATIVE TO DECREASE SULFUR EMISSION
Vent Gas
29.8 MM SCFH
(78,420 mols/hr.)
1.47. 02
56.47. Moist.
300 ppm S02 (1.2 Ib/MM Btu)
8989 Ash
r
Bag
Filters 1— _1
CRUSH
Lignite Feed ,y nRYT ANI
2,262,346 " FINE
V* f.T%, MoiBi-ni-o GRIND
M
Air
Vent Gas
T 1,500,614 1,417,914
Nil >
Moisture
As Fuel -*^
82,700 w
Total Air
13.6 MM SCFH
(35,800 mols/hr)
M Bas
1 1 Filters
* A
Air
Low Btu
y from ea
Numbers are Ib/hr
except as indicated
To Gasifier
1,345,600
Zero Moisture
1.0 MM cfh
(0.34 MM Btu/hr)
-------
- 18 -
Separate bag filters are provided on the preheater. This
operation consumes only 127. of the total fuel for coal preparation,
and only gas fuel is fired to it. Consequently, all of the fines
recovered from the gas leaving the preheater are pure lignite and can
be used as fuel for the furnaces if desired.
To minimize loss of fines in the dryer, it can be operated on
a relatively coarse crushed lignite of say 1/2" size. Then the fine
grinding can be carried out after the dryer and before the preheater.
With this arrangement the very fine lignite is exposed to a smaller
volume of gas so that the problem of dust recovery is minimized.
The modification to decrease sulfur emission does not increase
the air requirement compared to the original design. Neither is the
fuel consumption increased for coal preparation, or the total amount
of raw lignite consumed. Feed to the gasifier is 2.67. higher, since
more gas must be produced in order to provide some clean gas fuel.
In applications where water is in short supply, it should
be possible to recover make-up water from the dryer vent gas by passing
it through an air fin cooler and collecting the condensate. Total
water content is about 1500 gpm and if most of this were recovered
it would be a large contribution relative to the net make-up water
requirement of 2786 gpm for the process.
In any situation where gas fuel is used for heating, it is
possible to use conventional technology to generate by-product electricity
in a turbine-generator. This applies to the modified dryer design, where
the fuel gas could be used to drive a gas turbine, and hot gas from the
turbine would go to the furnaces. The potential by-product power would
be roughly 20,000 KW. Increased fuel consumption directly chargable
to the power would correspond to about 807. efficiency on conversion to
electricity. In general, this approach merits careful consideration
in situations where substantial amounts of clean gas or liquid fuel are
used for heating.
1.2.2 Gasifier
No gas streams are released directly to the atmosphere from
the gasifier, but a stream of spent acceptor solids is removed essentially
free of char, the separation having been made within the gasifier.
This reject acceptor could result in a dust nuisance which needs to
be controlled by water sprays and careful handling. It leaves the gasifier
at 1500°F and although the method for cooling is not shown, a fluid bed
cooler would seem to be preferred to allow generating steam for use in
the gasifier. Final cooling might be by dropping into water but this
would add a problem on water clean-up- Therefore, we have used a small
amount of water that is evaporated to dryness so that the material
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- 19 -
is not wetted. Steam from final cooling can be collected and sent to
the bag filter system. Based on pilot plant experience it is expected
that the reject acceptor will be suitable for land fill without further
treatment, and additional tests on leaching, sulfur release, etc. are
needed to be sure of this.
1.2.3 Gas Cleaning
Raw gas leaves the gasifier through cyclones which remove
most of the solids. It is cooled in a waste heat boiler to make steam,
and then scrubbed with water to remove essentially all of the dust
using Venturt type scrubbers operating at the dew point and evaporating
a small amount of water. The gas is further cooled to 150°F in air-
fins so as recover condensate and conserve cooling water.
1-2-4 Acid Gas Removal
The raw gas contains 330 ppm of sulfur, mainly as H2S. Sulfur
removal is required before methanating, but it is undesirable to remove
much C02 because it is needed to consume the available hydrogen during
methanation. Various processes have been reported that remove concentrated
streams of H2S while allowing most of the C02 to pass through the absorber
system (6,7,8). A major problem in most gasification systems is obtaining
a CC>2 stream free from sulfur that can be vented. In the present case the
sulfur only has to be removed to a level sufficiently low to prevent over-
loading the zinc oxide guard boxes.
Consideration should be given to using an absorption/oxidation
process, such as Stretford, Takahax, IFF etc., on the raw gas directly.
This would remove H2S only and convert it to sulfur product without
removing
As an alternative, it may be possible to take low sulfur
ash from the ash desulfurizing system and add it to the scrubber
water so as to pick up sulfur. Sulfur-containing ash could then be
returned to the ash desulfurizing system for regeneration.
1.2.5 Methanation and Compression
Final clean-up of the gas is accomplished in a bed of zinc
oxide before methanation, to remove traces of sulfur and dust which
could foul the caualyst. There may be traces of tar fog, naphthalene,
etc. present in the gas, in which case it would be desirable to include a
guard bed of activated carbon. Methanation itself generates no effluents
to the air. After methanation the gas is compressed to 1000 psig and
dried, for example with glycol, before being sent to the pipeline.
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- 20 -
1-2.6 Regenerator
The circulating dolomite is calcined at 1850°F to remove C02•
Make up dolomite is also added and calcined. Heat is supplied by burning
the required amount of char with air in a fluid bed regenerator operating
at 150 psig. A small content of carbon monoxide is maintained in the
outlet gas in order to avoid forming oxidation compounds of calcium
which were found to cause deposits. The flue gas is removed through
cyclone separators to take out most of the dust, consisting of ash
residue from all of the lignite fed to the gasifier. This ash is removed
from the system by way of a fluid bed cooler, and sent to the ash desulfuriz-
ing unit .
Gas from the cyclones passes to heat exchangers where steam is
super-heated to 1200°F. Additional steam is then generated in a waste
heat boiler. At an appropriate point in this system additional air
can be added to burn up residual carbon monoxide (e.g. before the waste
heat boiler) . This is necessary to avoid releasing carbon monoxide to
the atmosphere, and at the same time it provides a convenient way to
recover high level heat by burning the carbon monoxide. It is known
that this reaction is reasonably fast at temperatures above 1300°F.
The reaction raises the gas temperature by about 300°F, which still leaves
it lower than the regenerator temperature of 1850°F, consequently, deposits
should not be a problem.
Flue gas then goes to an expansion turbine to recover power.
For a turbine inlet temperature of 1000°F or higher, enough power can
be generated to drive both the air compressor and the product gas
compressor. In fact, there may be excess power available. Noise
control for this area needs careful attention in a final plant design.
The flue gas contains 470 ppm of total sulfur, and can be
discharged to the atmosphere, assuming that the dust content, nitrogen
oxides, and odor are acceptable. Further information is needed on these
critical items. The NOX content may be low, in view of the relatively
low combustion temperature in the regenerator, but specific data should
be obtained on this in the pilot operations. For treating the ash to
remove sulfur, a stream of C02 is needed, which might be provided by
scrubbing part of the flue gas.
1.2.7 Ash Desulfurizer
Ash produced from the coal is processed to give 987. sulfur
removal by reacting it in a water slurry with C02 at 190°F. Off-gas
containing a calculated 27% l^S, 7% C02 and 66% H20 is sent to a sulfur
recovery plant such as a Glaus, Stretford, or other type unit. All
of the gas streams in this system are contained and should not cause
environmental problems. The carbonated ash is withdrawn as a 50% slurry
in water and is not expected to create odors, although this should be
checked out. C02 required for this operation is 1530 moles/hr, including
25% excess over theoretical and can be provided from the regenerator
flue gas.
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- 21 -
1.3 Effluents To Air - Auxiliary Facilities
In addition to the basic process, auxiliary facilities are
required which will now be discussed with regard to effluents to the
air.
1.3.1 Sulfur Plant
streams from acid gas removal and from the ash desulfurizer
go to a sulfur recovery plant. If a Glaus plant is used, sulfur recovery
of about 97% can be achieved with three stages in "straight- through"
flow. The tail gas still contains about 3 tons per day of sulfur and
might be cleaned up, although this gas volume of 20 MM cfd is small relative
to the other effluents. In fact, in this process as opposed to others, the
sulfur in the Glaus tail gas represents such a small percentage of emitted
sulfur (see Section 2) that investments or costs for sulfur removal could best
be spent cleaning the regenerator flue gas or dryer vent gas. Thus, the
Glaus tail gas could be incinerated and vented to the dryer stack and
a small additional quantity of clean product gas added as fuel to decrease
total sulfur emissions to acceptable levels. No specific preference
is indicated for sulfur recovery.
1.3.2 Utilities
Net utility requirements are low because considerable power
is recovered by passing the regeneration flue gas through an expander
turbine. Also a large amount of heat is recovered in waste heat boilers
to generate steam, and on the methanator where the heat released by
reaction amounts to about 19% of the heating value in the entering
gas. Most of this can be converted to steam by recirculating gas
from the reactor through waste heat boilers. Under development are
alternative techniques using a fluid bed or liquid slurry reactor that
should be more efficient.
A utilities balance for the process indicates that the
process is self-sufficient in steam and power, so that no utility
boiler is required for normal operation. It is likely that a more
definitive and optimized utility balance will show that it is possible
to make more steam and power than consumed by the gasification plant,
so that these could be used for shops, mining operations, offices and
general off-sites. For example, 1.65 million pounds per hour of steam
at 150 psig is used in the gasifier. This could be generated at
a higher pressure such as 600 psig and run through bleeder turbines
down to 150 psig, while generating by-product power at the rate of
about 40,000 kw.
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- 22 -
In the utilities area, the main cooling tower has by far
the largest volume of discharge. It is, therefore, critical from
the standpoint of pollution. In this particular case it is not expected
to contain significant amounts of undesirable contaminants. The cooling
water circuit is clean and should not contain ash or objectionable
materials such as phenols, oil, or H2S. Normally a certain amount of
leakage can be expected on exchangers using cooling water. Since the
process operates mainly at 150 psig pressure, this should not be a
major item. Also, most of the cooling water is from steam condensers
on drivers rather than on oil, sour water, etc.
Total cooling water requirement is modest considering the
plant size. Effluents to the air from this cooling tower amount to
457,000 Ibs/hr of water evaporated, plus 43,000 Ibs/hr of estimated drift
loss or mist. Flow of air through the tower is 15,000 MM cfd.
The drift loss or mist will contain dissolved solids which
can result in deposits on the ground and on nearby equipment, and in
some cases drift loss has caused icing problems on equipment and public
roads in the winter. With any cooling tower, the problem of fog formation
must be assessed, since under certain conditions the moisture condenses
and the resulting plume can be a problem if it affects public highways.
Reheat of the stack gas is one way to reduce fog formation, but is in-
efficient. 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.
There will also be evaporation and the possibility of odor from
ponds and water treating facilities. While most of the ammonia will be recovered
as a by-product, the waste water still will contain traces of ammonia and
probably also some phenols, hydrocarbons etc. particularly during start-up
or during upsets. These must be controlled and a biological oxidation
(biox) pond for waste water treating is needed. Depending upon
pilot plant results with regard to tar and hydrocarbons produced, it
may be necessary to provide an oil separator ahead of the biox unit,
and possibly a froth floation separator. If these are required they
should be covered to contain vapors and odors.
In addition, leaks on processing equipment can be expected.
For example, packing on valves and seals on rotating equipment such as
compressors and rocary dryers are commonly found to leak, depending
upon operating pressure, design, and maincenance. Estimates must be
made for specific projects to determine the magnitude and controls needed,
as has been done for example on oil refineries in California (9)•
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- 23 -
1.4 Liquids and Solids Effluents
1.4.1 Coal Preparation
Coal storage and preparation is the first major item in this
category. The problem is due to rain runoff. The storage pile has a
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,
sulfur, 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 (10). Rain from the dolomite storage area should also
be included.
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 such 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 che 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. Normally
all of the run-off water can be used in this way so that it will not
constitute an effluent from the plant.
No specific solid or liquid effluents are expected from the
coal or dolomite grinding, drying, and preheating sections, except
that dryer vent gas will be passed through bag filters to recover the
dust consisting of ash from burning lignite fines. It can be combined
with the ash slurry and returned to the mine. Electrostatic precipitators
or scrubbers may be used instead of bag filters.
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- 24 -
As mentioned earlier .scrubbing of the dryer vent gas may
be used to reduce sulfur emission. If so, then all water and solids
from this operation should be returned to the process, for example,
to the gasification section so that they are not allowed to
become an effluent from the plant.
1.4.2 Gasifier
The only discharge stream from the gasifier is the reject
acceptor which is replaced at the rate of 2% per day of circulation
in order to maintain activity. The acceptor is relatively coarse
compared to the char in the gasifier, and is separated from it before
being removed. Since the reject acceptor is coarse it probably will
not be a dusting problem but water sprays may be used if required to
control this.
The reject acceptor is stated to be low in sulfur, 0.084%,
which is low enough so that there should be no secondary pollution problem
upon its disposal. It would appear to be a suitable material for land
fill and should be considered for such use.
1.4.3 Gas Clean-Up
Raw gas leaves the gasifier by way of cyclone separators
which remove most of the dust. The gas is cooled as discussed in
Section 1.2.3, and a water scrubber removes residual dust and ammonia.
The scrubber water will also contain sulfur compounds, since the gas
contains 330 ppm H2S. Unreacted steam from the gasifier is condensed
in this system, constituting an effluent which must be treated and
disposed of or reused. Amounts of the various streams are shown on
Figure 3 and in Table 3.
Water from scrubbing goes first to a clarifier which removes
fine solids. It is expected that the amount of solids will be small
and can be disposed of along with the spent ash being returned
to the mine, otherwise they may have to be used in ^he process or burned
as fuel, depending on combustible content. Further information is
required on the nature of this stream. Clarifier water goes to a
sour water stripper, to separate ammonia and I^S. If ammonia can be
sold as a by-product, purification facilities can be included, using
designs that are available, to produce 130 tpd.
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- 25 -
Effluent from the sour water stripper will also contain traces
of phenols, tar, naphthalene, etc. which must be cleaned up. For this
purpose we have added a biox unit and retention pond to reduce the
contaminants to a low enough level so that the water can be recycled
as make-up water. Detailed information for designing this system should
be obtained by the developer when representative streams become available
from pilot plant operations to show whether the assumed clean-up system
is adequate. If not, it may be necessary to include such things as
oil separators and activated carbon adsorption. This stream should not
be allowed to become an effluent from the plant.
The next area is acid gas removal, where the main requirement
is to remove sulfur compounds prior to methanation. A small amount of
C02 may also be removed but this is incidental and the process depends
on leaving nearly all of the CC>2 in the gas going to methanation in
order to consume the large amount of hydrogen available. The COo content
is 6.9 Volume % and it would be acceptable to remove up to 10% of it. Acid
gas removal presents somewhat of a problem in that the usual scrubbing
systems remove much of the C02 when operated for high sulfur removal.
Some of the higher amines are more selective for removing H2S but may
not be sufficiently so.
A possible alternative is to use the carbonated ash produced
by the ash desulfurizing unit to remove sulfur compounds from the gas.
This would need to be tested experimentally but if it works it may
be possible to simply add desulfurized carbonated ash to the water
scrubbing system and remove most of the sulfur at that point. The ash
would then be returned to the ash desulfurizing system for regeneration
and sulfur removal. The total amount of sulfur in the gas is only
12 tpd, so there may be simplier ways to remove it than by using conventional
acid gas scrubbing. Caustic wash, for example, is one possible route.
The final gas clean-up needed to protect the methanation
catalyst is accomplished by passing the gas over zinc oxide at elevated
temperature, about 600°F, to remove traces of various sulfur compounds.
The zinc oxide charge is replaced when it is spent, being returned to
a manufacturer for processing.
There is a distinct possibility that small amounts of certain
elements such as fluorine, chlorine, bromine, arsenic, etc. will volatilize
in the gasifier in the presence of steam and hydrogen, as is experienced in
oil refining and other operations, in addition, nickel and iron may form
carbonyls by reaction with CO. Experimental work is needed in this area
to identify the problem so that it can be taken into account and control
measures taken if required.
1.4.4 Methane tor
Methanation increases the heating value of the gas up to
pipeline quality by reacting the carbon oxides with hydrogen present
in the gas to form methane and water. Feed gas composition is such
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- 26 -
that the reaction goes to completion with only a few percent of hydrogen
remaining. The methanation reactor may use a fixed bed of nickel
catalyst, or the spray coated catalytic tubes used by the Bureau of
Mines, or one of the other processes under development. The latter
include a fluid bed system with cooling coils in the bed, and an alternative
using a liquid slurry of catalyst.
The methanation reaction operates at about 800°F, and releases
considerable heat which must be removed to prevent excessive temperatures.
In the fixed bed system this is usually accomplished by dividing the
reactor up into a number of catalyst beds in series, with gas recirculation
through coolers on the various beds. Heat release amounts to about 197.
of the heating value of the entering gas, resulting in a considerable
loss in thermal efficiency. However, if the heat is mostly recovered
to make useful high pressure steam the debit is greatly reduced. A
further characteristic of the methanation reaction is that it produces
a considerable amount of water, 483,000 Ib/hr in this design, compared
to the 1,650,000 Ib/hr injected into the gasifier reactor. This water
is a very clean condensate - thus the methanator makes a large contribution
in the overall water balance. The met ha nation catalyst will eventually
be replaced when it has lost activity, and the spent catalyst should be
returned to the manufacturer for metals recovery or reprocessing.
1-4.5 Gas Compression
The final step is to compress the methanated gas from about
140 psig to pipeline pressure of 1,000 psig, and dry it. Compression
normally involves inter coolers and after coolers from which condensed
water will be removed - again, it is high quality condensate. The gas
then passes through a clean-up dryer, such as one using glycol, alumina,
or molecular sieves, in order to meet pipeline specifications of 7 Ibs
of water per million cubic feet. Product gas is of pipeline quality,
with a heating value of 952 Btu per cubic foot.
Gas compression requires about 33,000 brake horse power,
which can be supplied from the flue gas expander turbine. As an alternative,
the compressor could use steam drivers, but the flue gas turbine allows
large savings in steam and cooling water requirements.
1.4.6 Regenerator
The regenerator serves to calcine the acceptor for recirculation
and also supplies heat to the system. There are no liquid or solid
effluents from the regenerator, except an ash stream which is carried
overhead to cyclones and must be separated efficiently from the gas
before it goes to the flue gas turbine. Details of the system for removing
this dust and the efficiency of removal were not specified, but it is indicated
that high pressure drop cyclones will be used.
A reliable and efficient system for removing dust from the
regenerator flue gas is required.
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- 27 -
Federal regulations for large stationary boilers limit the
emission of particulates to 0.1 Ib/MM btu, corresponding to about
400 Ibs/hr of solids for the present design. This would require
a dust removal efficiency of 99.7%, which would correspond for example
to an efficient electrostatic precipitator. The allowable solids
will also be limited by erosion in the flue gas turbine which may call
for an even lower level. (18)
One manufacturer has specified a maximum dust loading of
30 ppm by weight in gas fuel for turbines, with a maximum particle
size of 10 microns. Other specifications require less than 20 ppm
of solid and a maximum particle size of 2 microns, in connection
with public utility applications. These present very difficult targets
for dust removal, particularly since it is desired to remove the dust
at 1000°F or higher. The use of several stages of cyclones has been
indicated for this service, with the final clean-up by means of high
pressure drops cyclones. In the case of cyclones offered by some
manufacturers, increased centrifugal force, and higher recovery, is obtained
by tangentially injecting an extraneous stream of clean gas at high velocity
into the cyclone. Sand bed filters have also been proposed for this service.
In general, this area of dust removal at high temperature represents a
very important technological need, where additional work could lead to a
major contribution in improving the environmental aspects of energy conversion.
While dust removal has been discussed from the standpoint of
erosion on the flue gas turbine, there are indications that corrosion
can be at least as important as erosion in setting limitations. Sulfur
is, of course,a major concern as well as alkali metals such as sodium,
calcium, etc. One specification sets a maximum of 5 ppm, calculated as
alkali metal sulfates, which are especially corrosive. Most of the
work being done in this area is with turbines in oxidizing atmospheres
containing a high percentage of oxygen. In the present design, the
turbine operates in an atmosphere containing little or no free oxygen, which
may aggravate corrosion. However, secondary air could be added ahead of
the turbine in order to increase the free oxygen content, with a corresponding
change in flow rates for the system.
The incentive for using a flue gas turbine to recover energy
from hot regenerator flue gas in the C02 Acceptor process is very great.
This is also the case for similar situations where hot dusty gas is
available at high pressure and must be depressured, as on catalytic
cracking units in oil refineries, where some commercial units are already
in use (17). Therefore the intensive effort now directed at broader
application of gas turbines is well warranted, and can be expected to
result in major contributions.
If the turbine is capable of handling high dust loadings then
it may be necessary to add dust recovery after the turbine. In this
case, electrostatic precipitation, water scrubbing, or bag filters
could be used. If water scrubbing is used it may be possible to remove
additional sulfur at the same time by adding spent ash or rejected acceptor
to the scrubbing water. Every effort should be made to incorporate
such operations in the plant design so as to minimize the extent
of pollution with only minor added cost.
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- 28 -
The coal ash separated from the regenerator off-gas amounts
to 177,400 Ib/hr with only 3.55% carbon, and can be discarded.
It is high in sulfur (5.19 wt. 7.), some of which is in the form
of compounds such as calcium sulfide which would give a secondary
pollution problem due to release of hydrogen sulfide. Therefore, the
process provides for desulfurfzing this ash by reacting it with carbon
dioxide in the presence of water at 190°F. A sulfur removal of
98% is achieved by this technique. The off-gas, containing hydrogen
sulfide, carbon dioxide, and steam is sent to the sulfur plant for
clean up.
Carbonated ash amounts to 233,000 Ibs. per hour, having picked
up considerable weight by adsorption of carbon dioxide in the ash desulfurizer,
This carbonated ash is a fine material and must be disposed of without
Leading to further pollution problems. As of now it appears that the
ash can be disposed of by making a slurry with an'equal weight of water
for return to the mine. Ash from coal preparation will be added to
this. Leachability of this material is an area that needs to be
defined•
As mentioned, the carbonated ash may be very useful for removing
sulfur compounds in other parts of the process, for example, from the
vent gas on the lignite dryer and from the raw gas prior to methanation.
If such uses are included then the size of the ash desulfurizing system
and sulfur plant would be increased accordingly.
1.4.7 Auxiliary Facilities
Next to be considered are the liquid and solid effluents
from auxiliary facilities. The acceptor process does not use an oxygen
plant as do some other gasification processes, nor does it require a
utility boiler to provide steam or power for normal operation. All
utilities are generated within the process. This of course does not
take into account start-up and the requirements of shops or off-site
facilities.
The first of the auxiliary facilities to consider is the
sulfur plant, which produces free sulfur from gases coming from gas
clean-up and ash desulfurizing. A Glaus plant is used conventionally
for this purpose. Since the total sulfur in the tail gas is relatively
small, the tail gas can be incinerated and added to one of the large
vent streams. Instead of the Glaus plant, other processes could be
used such as: Takahax, IFF, or Stretford. Total sulfur production is
119 tpd. It can be sold or stockpiled using well established techniques
to avoid environmental problems such as dust and odors.
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- 29 -
The next area is waste water treating to remove phenols,
ammonia, etc. and suspended solids. This depends on a biox unit and
a retention pond for clean-up, as discussed more fully under the section
on gas clean-up. A highly desirable objective is to avoid having any
net water effluent from the plant and this appears possible for the
system as shown, except for water in the ash slurry returned to the mine.
The net water available from the retention pond is recycled as water
make-up and treated in the make-up water treating facilities.
In view of the large amount of ammonia recovered in the
raw gas scrubber it may be that a" large p-art "of the hydrogen sulfide
will be scrubbed out along with it; if so, little or no separate
acid gas removal may be necessary. Information is needed in this
area. One possibility that may merit further consideration, is to
separate ammonia from H^S in a sour water stripper, and recycle
some ammonia to the gas scrubbing system so as to provide the required
removal.
Treating of make-up water is the next area to be discussed, and
will depend on the quality of make-up water at the specific plant location.
It may include the use of lime to precipitate hardness and alum to
cause f locculation. Sludge from water treating must be concentrated
and can be included with the ash disposed of in the mine. Boiler feedwater
treating includes demineralization using ion exchange resins. These
are regenerated by backwashing with sulfuric acid or caustic which
can then be combined, neutralized, and included in the make-up water
to the ash slurry scrubbing system.
The final item under auxiliary facilities is the cooling
water circuit and cooling tower. Most of the cooling water is used
for clean service to condense steam on drivers generating electric
power, but a large amount is also used on inter and after coolers on
gas compression, as well as for cooling in the gas scrubbing system.
The water is recirculated through a cooling tower where it is cooled
by evaporating 457,000 Ibs per hr of water.
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 the 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. Part of the blowdown or purge from the latter can be recirculated
through make-up water treating. Final net purge from the system goes
to the ash desulfurizer circuit where it will end up in the slurry
being returned to the mine.
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- 30 -
As shown, the only net water effluent from the plant is in
the ash slurry returned to the mine. A 50% slurry should be satisfactory
for handling, corresponding to a water content of 233,000 Ibs per hr.
This is the effective blowdown from the cooling tower, and is relatively
high compared to the amount of water evaporated; therefore, it is expected
to be satisfactory as regards total dissolved solids in the cooling
tower circuit.
Total water make-up for the plant is 1,383,100 Ibs per hr.
after crediting the water formed by the methanation reaction. It is
possible that most of the moisture in the vent gas leaving the lignite drying
operation could be recovered. If so, the net water requirement is reduced
to about 700,000 Ibs per hr or 1400 gpm, which is unusually low for this
plant size.
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- 31 -
2. SULFUR BALANCE
Of the total sulfur entering in the lignite feed to the
plant, 72.4% is recovered as by-product sulfur, another 2.3% is in solid
residues and the remaining 25.3% is discharged to the air. The sulfur
balance is shown in Figure 7 and summarized in Table 4.
Some concern has been expressed that the sulfur content of
the spent acceptor rejected from the gasifier may be high enough under
some conditions to cause environmental problems. While low sulfur
content has been indicated for normal operation, there may be periods
of operation when the rejected acceptor would cause secondary pollution
problems upon disposal. Possibly the material could be stockpiled if
this occurs, and later reprocessed through the system for clean-up.
Or it might be treated in the ash desulfurizing system, although this
would increase the C02 requirements, and provision would have to be
made for it in the plant design. Pertinent information should be
obtained during pilot plant operations.
Ash containing sulfur is removed from the regenerator and
desulfurized by reacting at 190°F with CC>2 and steam. These same
gas reactants are present in the regenerator and gasifier, although
the temperature is much higher, thereby reducing the tendency to strip
out sulfur.
In pilot plant operations on the C02 acceptor processes
it will be important to confirm the operation of the sulfur recovery
system, so that sulfur in the effluent streams is adequately taken
care of.
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- 32 -
Table 4
SULFUR BALANCE
By-Product Sulfur 72.4
Reject Acceptor 1.0
Spent Ash 1.3
Regenerator Flue Gas 16.9
Dryer Vent Gas 6.2
Glaus Tail Gas 2.2
100.0
-------
Figure 7
CO ACCEPTOR PROCESS
Sulfur Balance
Sulfur
Lignite 13-700 Ib/hr
Feed
100%
COAL PREP.
Sulfur in:
13,700 Ib/hr
Dryer Vent Gas
12,850
93.8
GASIFIER
11,627
84.9
1086
REGENERATOR
9313
68.0
10221
74.6%
ACID GAS
REMOVAL
Product Gas
Reject Acceptor
1086
7.9%
Flue Gas
ASH DESULF..
Ash
9135
66.7%
SULFUR
PLANT
Tail Gas
Sulfur
Ib/hr
850
137
2315
178
300
9921
TOTAL Sulfur out Ib/hr 13,700
6.2
0.0
1.0
16.9
1.3
2.2
72.4
100.0
u>
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- 34 -
3- 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 12. 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
on the particles was determined for particles of different sizes, in the
range of 1.5 to 25 microns (13). 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
coal fired furnaces of gasification plants.
The fate of trace elements during combustion was determined in
another study for both experimental and industrial furnaces (14). Some
85-90% 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 (15). More than 80% of the mercury, a major part of the arsenic,
and probably the selenium leave as a vapor. The electrostatic 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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- 35 -
Gasification can also release volatile elements from coal,
although it may be different than combustion since the atmsophere is
reducing. In many gasification processes the maximum temperature is
much lower than for combustion, but in others 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 one gasification
process (16). Considerable amounts of many elements are lost from the ash
during devolatilization and gasification, especially mercury (see
Table 5). The loss is appreciable even in pretreating where the
maximum temperature is only 430°C. Preliminary results from this report
on bench scale work are summarized below for solids leaving each
processing step - the concentration being calculated based on thi-
original weight of coal. Although elements are lost, information
is needed as 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.
Table 5
TRACE ELEMENT CONCENTRATION OF PITTSBURGH NO. 8 BITUMINOUS COAL AT
VARIOUS STAGES OF ONE GASIFICATION PROCESS
Calculated on the Raw Coal Basis (From Ref. 16)
Max .Temp.of treat °C
After
Pretreat
430
After
Hydro-
Gasifier
650
After
Electro
Thermal
Gasifier
1000
% Overall
Loss
for Element
Element;
-ppx
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
0.
1,
7,
.19
.0
.5
0.07
4.4
0.59
0.13
36
11
1.0
17
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
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- 36 -
In operations of the C(>2 Acceptor pilot plant, it will be important
to obtain information on what happens to trace elements. Some of the volatile
ones can be carried out in the gas leaving the gasifier, and since they
cannot appear in the pipeline gas, they will have to be removed by the gas
cleaning operations. Satisfactory methods for disposal will have to be
provided, but in order to do this the first requirement is to obtain data
on what elements are carried overhead, and in what form.
Examples of volatile elements are suggested by the preceeding
table and in addition carryover can be expected on boron, zinc, fluorine,
etc. The form in which they appear may be affected by the gas - thus
CO can form carbonyls, and H2 can make arsine, HF, HC1, and 1(3803. Such
reactions have been found in gasification, as well as in other operations
at moderate temperature on coal and oil.
When these volatile materials enter the scrubber, they can
react further with NH3, l^S etc. present in the sour water. Information
is needed on this to provide a sound basis for defining pollution control
and disposal facilities.
Conditions in the regenerator will also tend to remove volatile
elements, due to the higher temperature, and large gas volume. It will
be important to measure the extent of this, and to obtain data on the
extent to which they can be removed by collection in cyclones along with
the fly ash.
Trace elements can also leave the system with the fly ash, and
in the rejected acceptor. Leachability on these materials needs to be
determined, and also on the desulfurized, carbonated ash sent to disposal.
Detailed weight balances around the entire process are needed
on all critical trace elements in order to assess the situation, and
possible need for controls. Then suitable technology for their separation
and disposal can be worked out.
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- 37 -
4. THERMAL EFFICIENCY
Thermal efficiency is important in that it sets the amount
of coal required to produce a given amount of clean fuel gas. Moreover,
part of the unrecovered energy in the coal must be dissipated to air
or water. As a first calculation the total product gas heating value
can be divided by that for the coal fed to the gasifier. This hypothetical
figure is 68.57. but it does not allow for the fuel required to dry and
preheat the lignite to 500°F; which would lower the efficiency to 62.2%,
although sulfur emission would be excessive. It is, therefore, not a
realistic number. As a most conservative (lowest efficiency) case it can
be assumed that the only fuel fired to the dryer and preheater is low
sulfur, low Btu gas taken prior to methanation. This gives a calculated
thermal efficiency of 60.2% and is a limiting case in that the vent gas
then contains very little sulfur, far below the allowable sulfur emission.
If the fuel consisted only of dried lignite fines then sulfur in the vent
gas would be 1.6 Ibs of S(>2 per million Btu fired, compared to the allowable
level of 1.2. In order to meet the allowable sulfur level, 75% of the
heat required can be supplied by lignite and the other 25% from low sulfur,
low Btu gas. This is then a realistic and practical case and gives a
thermal efficiency of 61.7%.
An alternative is to burn only lignite in the dryer and preheater,
and remove 25% of the sulfur in the vent gas. This might be done by
scrubbing with limestone, or used acceptor which could then be returned
to the gasifier-regenerator system, and finally processed in the ash
desulfurizing unit. For this case, firing only lignite fuel to the
coal preparation section, and including allowance for energy used in stack
gas clean-up, thermal efficiency is 61.9%. Results on thermal efficiency
are shown in Table 6, including numbers for the alternative dryer design
shown in Figure 6.
As mentioned earlier, by-product electric power can be made by
generating steam at 600 psig and depressuring it through a turbine generator
to supply steam required in the gasifier. If credit is taken for this
on an equivalent "fuel fired" basis (40,000 KW @ 40% efficiency), thermal
efficiency for the process increases by 2.1%. If, in addition, excess
steam available from the process is credited, thermal efficiency increases
by 5.1%.
It should be noted that this plant design and the calculated
thermal efficiency are for a specific basis as given in Table 1 and 2.
Methane content of the raw gas from the gasifier is only 6.08 Vol. %
on a dry basis, even though the hydrogen content is quite high (70.91
vol. %) as a result of the shifting effect associated with C02 removal
by the acceptor. The developer has indicated that pilot plant data show
methane contents in the gasifier product about twice that given in
Table 1. This would increase all of the thermal efficiencies given
in Table 6, but the exact amount has not been calculated.
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- 38 -
Table 6
Thermal Efficiency
Base Design Ib/hr MM Btu/hr
In
Lignite to gasifier 1,368,000 15,212
Lignite to Coal prep. 165,470 1.546
16,758
Out
Pipeline Gas -- 10 417
Base Thermal Efficiency 10.417 = 62.27.
16,758
If use only low Btu gas as fuel
to coal prep., efficiency = 60.2%
Alternative dryer design of Figure 6
Efficiency as shown gas/coal fuel 62.4%
- plus credit for by-product power 64.5%
- and credit for by-product steam 67.5%
Efficiency if make only low Btu gas 76%
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- 39
Although this study is based on making SNG, it appears that
the process can also be used to make a low-Btu clean fuel gas (19).
An estimate of thermal efficiency for such a case was made by backing
out the methanator, giving 767. efficiency. It appears that the process
might also be able to give adequate sulfur removal at high temperature -
without having to cool to water scrubbing temperatures. If so, thermal
efficiency might be credited with sensible heat in the low-Btu gas,
provided the moisture content is low enough so that water does not have
to be removed from the gas.
In any process making SNG from syngas, the maximum theoretical
thermal efficiency is limited to 81% by the heat released in the methanation
reaction. Therefore, it is obviously much more efficient to use low-Btu
gas where applicable and wherever possible for large consumers, industrial
uses, etc.
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- 40 -
5. POSSIBLE PROCESS CHANGES
5.1 Process Alternatives 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
alternatives considered are summarized in Table 7, 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-
es nt ly.
Examples of alternatives in each of the above four categories will now be given.
On item 1 an example is the consideration of type of fuel to use
in coal drying. If lignite fines are used exclusively as suggested by
the developer then sulfur in the flue gas is undesirably high.
An alternative is to use only low Btu gas from a point just ahead of the
methanator and after sulfur has been removed, but this is a more expensive
fuel and leaves no place in the plant to use the lignite fines. It
does give minimum sulfur emission in the vent gas. A reasonable compromise
is to supply 25% of the fuel requirement as low Btu,low sulfur gas, and
the other 757. as lignite fines.
An example of additional pollution control equipment needed
is on the regenerator flue gas leaving the turbine, where dust control
facilities may be required. Only cyclones have been provided and
experience on power plants shows that fly ash recovery in cyclones is
not adequate. We have included an electrostatic precipitator for this
purpose although a scrubbing system could be used instead. In addition,
waste water treating facilities were added because of residual ammonia,
phenols, etc. that must be removed.
On item 3, thermal efficiency can be increased by burning
residual carbon monoxide in the regenerator flue gas. It could be
burned in a conventional CO boiler after the turbine, but the temperature
at this point is so low that it would be necessary to fire additional
fuel in order to maintain stable combustion. A much more efficient
alternative is to burn the carbon monoxide before the turbine to reheat
the flue gas, pass it through a boiler to generate additional steam,
and then to the turbine-
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- 41 -
Table 7
PROCESS ALTERNATIVES CONSIDERED
Coal Dryer;
• Coal fired with flue gas desulfurizing versus use low
Btu fuel gas from process.
• Recover dust by electrostatic precipitator or scrubber
versus bag filters.
Gas Clean-Up;
• Air-fin coolers to minimize cooling water required.
Acid Gas Removal;
• Stretford, IFF, or Takahax process to remove H2S
selectively versus amine or carbonate scrubbing.
Methanator;
• Ways to generate high pressure steam from heat released
in reaction.
Regenerator;
• Scrub flue gas from turbine to remove dust versus
electrostatic precipitator.
• Burn carbon monoxide before turbine versus CO boiler
after turbine.
Ash Desulfurizer;
• Supply CC>2 by scrubbing exhaust gas from turbine, versus
scrubbing sulfur plant tail gas to recycle C02«
(Enough C02 can not be made available from gasifier products.)
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- 42 -
Areas where additional work is required (item 4 above),
include: (a) the technique for selectively removing sulfur from the
raw gas without removing a large amount of carbon dioxide, (b) the
system needs further definition as regards ash disposal and potential
secondary pollution from leaching, etc., (c) further information on
potential odors is needed on the lignite dryer, ash, reject acceptor,
and water treating, (d) the fate of trace elements in the process must
be defined and may be rather different than experienced in other
gasification processes which do not use dolomite acceptor.
5.2 Engineering Modifications
In the course of the study, some additions and modifications
were made in order to have the process complete and self-sufficient,
or to improve efficiency, or help control emissions. Where these use
only known techniques that do not need experimental development,
they are referred to as engineering modifications and are shown in
Table 8-
On the coal dryer, for example, water could be recovered
from the vent gas since it contains 800,000 Ibs per hr. This is large
relative to the net requirement of 1,383,100 Ibs per hr. of water
make-up. Most of the water in the dryer vent gas could be recovered
by cooling the gas in air-fin coolers after the bag filters, e.g.
to about 150°F, which would add investment but not require cooling water,
and may be an attractive way to produce a large part of the make-up
water. Fluid bed drying may be attractive versus the pneumatic system
shown in that it should allow a closer temperature approach.
The technique of cooling the reject acceptor leaving the
gasifier was not specified, and therefore, we have added a conventional
fluid bed cooler in which steam is generated, followed by water sprays
to cool the solids further while still leaving a dry product. The
same technique is used to cool spent ash leaving the regenerator.
The C02 Acceptor Process is unusual in that it does not require
either shifting or C02 removal ahead of methanation. This allows much
greater flexibility in considering what acid gas removal process to use
for the specific application. The usual amine scrubbing or hot carbonate
systems will tend to remove more C02 than desired when removing sulfur
to a very low level, therefore, they are not particularly well-suited
for this use. However, absorption/oxidation type processes could be
much more attractive. In these H2S is selectively absorbed in a solution
where it is catalytically oxidized to free sulfur, which is removed as
a by-product. Such processes are offered by IFF, Stretford, and Takahax
etc., and would not remove CO^.
The methanator system was not described by the developer
and neither was the technique for recovering waste heat from it. We
have used this heat to generate high pressure steam and have also
included in the water balance the water produced by the methanation
reaction.
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Table 8
ENGINEERING MODIFICATIONS
Coal Preparation;
Fluid bed dryer versus pneumatic system.
Recover water from vent gas by using air-fin
coolers.
Gas ifier:
• Cool reject acceptor in fluid bed to generate steam
and minimize cooling water.
Regenerator:
• Burn carbon monoxide before flue gas turbine to
recover high level heat, rather than use conventional
CO boiler after the turbine-
Sulfur Plant;
a Use low temperature liquid absorption/oxidation
reaction to form sulfur directly from gases leaving
ash desulfurizer and acid gas removal, and avoid Claus
unit.
Utilities;
• Generate all steam at high pressure, and depressure
through bleeder turbines to generate electric power,
then use depressured steam in gasifier.
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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 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 decreases thermal
efficiency but at least partial application may be justified for reducing
water consumption 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°F,
it may not always be practical to use air fins-
5.3 Potential Process Improvements
Some of the possible changes in the process have potential
for significant improvement but would require further study and perhaps
experimental work. These are shown in Table 9-
One promising possibility is to use the acceptor to remove
sulfur from other streams in the process. It is known that it will
retain sulfur under conditions in the gasifier and regenerator, and
that it can be regenerated to remove sulfur. Thus, sulfur and dust
emissions from the dryer could be controlled by scrubbing with
a slurry of the acceptor, which would then be recirculated to the
gasifier-regenerator, and the ash desulfurizing system for regeneration.
A similar operation could be used on the raw gas from the
gasifier and would have an additional advantage if it would take out
sulfur and not much carbon dioxide. It could also be used on the flue
gas leaving the expander turbine. Although this gas is already low
in sulfur, it contains dust which could be removed by scrubbing, while
at the same time the scrubbing operation would reduce sulfur level at
little added cost.
An alternative to consider for removing sulfur from the raw
gas is to use a low temperature absorption-oxidation type reaction
to selectively remove sulfur, as is offered by Stretford, IFF, and
Takahax. These processes use a scrubbing liquid containing a catalyst
to convert hydrogen sulfide directly to elemental sulfur, which is
then separated. They give little or no removal of carbon dioxide.
Sulfur compounds other than H2S may be present but could probably be
hydrolyzed to t^S over a suitable catalyst at about 500 to 700°F as the
raw gas is being cooled.
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Table 9
POTENTIAL PROCESS IMPROVEMENTS
Coal Preparation;
Use recirculated acceptor to remove sulfur from vent
gas and supply all heat requirement by burning lignite
fines. Return acceptor to gasifier-regenerator system.
Gas Clean-Up;
• Use recirculated acceptor to remove sulfur from raw
gas without removing C02•
• Use low temperature liquid absorption/oxidation reaction
to form sulfur directly, instead of scrubbing with
amine or carbonate.
Methanator;
Other:
Fluid bed or slurry type reactor, or catalytic tube
wall of Bureau of Mines to improve heat recovery
versus fixed bed with gas recirculation through waste
heat boiler.
Use process to make low sulfur - low Btu gas for combined
cycle power generation.
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A final point for discussion is the use of the Acceptor process
to provide a low Btu low sulfur gas fuel at high temperature and under
pressure for power generation or other uses. This process offers one
way to desulfurize gas at high temperature, instead of cooling it and
scrubbing at say 200°F or less. It could, therefore, be an efficient
way to make low sulfur fuel gas from coal and alleviate the difficult
pollution control problems of burning coal directly (11). The hot gas
might be used in a combined cycle where it is first burned for use in
a gas turbine, and the hot effluent then goes to a conventional steam
boiler. Overall efficiency to electric power for such a process could
be over 45%.
In gas turbine applications at present, there are strict
limitations on the dust loading due to erosion of turbine blades. Typical
specifications are for 30 wt ppm or less of solids content in the fuel
gas burned to supply the turbine, with a maximum particle size of 10, or
in some cases 2 microns. Corrosion is also a major concern. Considerable
development work is underway in this field, therefore the situation
should be reviewed periodically, since the incentive for application
of turbines can be very large.
5.4 Process Details
Other details on the process are covered in Tables 10 through
16.
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Table 10
COMPOSITION OF LIGNITE FEED AND PRODUCT GAS
Lignite Feed
Proximate analysis: Wt. 7.
Moisture ^ 33.67
Volatile 1 58.36
Fixed Carbon J
Ash* 7.47
100.00
Ultimate analysis, Moist, free wt. 7.
C 62.87
H 4.20
N 1.04
S 0.89
0 20.14
Ash 10.86
100.00
High Heating Value* 10,945 Btu/lb
Product Gas Composition (dry) Mol. 7.
CH4 93.00
H2 4.84
CO .10
C02 1.31
N2 0.75
100.00
Calc. to be equiv. to specified properties after
preheater (Table 1), with 1.6 wt. 7. loss in preheater
and no loss in ash or heating value.
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Table 11
STEAM BALANCE
Ib./hr.
Steam Generated
Net From Flue Gas Including CO Burner
Gasifier Waste Heat Boiler
Methanator
From Cooling Reject Acceptor and Ash
600 psig steam
567,000
525,000
840,000
1,932,000
165 psig steam
190,000
210,000*
63.000
463,000
Steam Consumed
Gasifier
Power Generation
Amine Scrubbing
Water Treating
175,000
175,000
* From bleeder turbine on gas recycle compressor.
1,653,700
63,000
126.000
1,842,700**
**• Total steam generated is more than required for gasification, and can
easily be run through a bleeder turbine-generator to supply power
to mine, shop facilities, offices, etc. and produce the 165 psig
steam required. Surplus steam available is then 377,000 Ib/hr at
165 psig.
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Table 12
WATER REQUIREMENTS
Water Consumed Ib/hr
By reaction in gasifier 1,053,000
In wet ash rejected 233,000
To ash desulfurizer 15,800
Evap. in cooling tower 457,000
Drift loss in cooling tower 43,000
Handling loss on condensate 68.000
TOTAL Consumed 1,869,800
Available from methanator 483,000
Available from gas Compres. 3.700
TOTAL Available 486,700
Net make-up required 1,383,100
(2766)*
If the moisture in the vent gas were recovered
(as discussed), the make-up would be about half
as much, i.e. 1400 gpm.
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- 50 -
Table 13
POWER CONSUMPTION
Consumer KW
Coal preparation 12,800
Scrubber 600
Acid gas removal 100
Gasifier and regenerator 100
Ash desulfurizer 300
Sulfur plant 400
Methanator 100
Cooling water pumps 1,500
Cooling water fans 1,000
Dolomite prep. 600
17,500*
This power is available from the process
scheme discussed (see page 20).
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Table 14
LIGNITE AND FUEL CONSUMED
Lignite to Freheater (moist, free) 1,436,400 Ib/hr
Lignite fuel to coal prep, (moist, free) 86,870 Ib/hr
Gas to coal prep, (low Btu)* 341 MM Btu/hr
Sulfur Plant tail gas incin. 22 MM Btu/hr
* Equivalent to 32,000 Ib/hr moist, free lignite
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Table 15
POTENTIAL ODOR EMISSIONS
Coal preparation dryer, and preheater
Wet ash disposal
Reject acceptor disposal
Regenerator flue gas
Sulfur plant
Ponds, waste water treating (NH3, etc.)
Trace phenols from gas clean-up.
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Table 16
MISCELLANEOUS INPUTS
For water treating: lime, caustic, alum, sulfuric acid,
chlorine
Cooling water additives: anti-algae (chlorine)
anti-corrosion (chromium salt)
Other chemicals: amines and additives
glycol for drying product gas
Catalysts, etc.: methanation catalyst
Claus plant catalyst
ZnO guard bed to remove sulfur
Oil: to lubricate pumps, compressor, etc.
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6. TECHNOLOGY 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
from examination of this gasification process, are summarized in
accompanying Table 17 grouped according to the process area.
Illustrating the first point is sulfur control on the dryer
vent gas when burning lignite. As pointed out earlier, sulfur emission
can be controlled by using some low sulfur gas made in the process, although
this increases the amount of lignite that must be gasified. An alternative
is to scrub flue gas leaving the dryer to remove sulfur. A number of
suitable processes are currently undergoing large scale testing, some of
which include regeneration of the scrubbing medium to produce by-product
sulfur, sulfuric acid, or gypsum. An advantage for flue gas cleanup is that
100% of the heating value of lignite is then available for drying, versus
about 70% when the lignite is gasified to make clean fuel gas. Scrubbing
can also remove fly ash or dust, and avoid the need for bag filters. It
is apparent that there is a great need for effective processes to clean
up stack gas from combustion operations.
Referring to item 2 above, a common problem for most coal
gasification processes is the methanation operation. Thermal efficiency
is only 81% in this case, resulting in a very high heat release,
which it is important to recover, for example, as high pressure steam.
One approach is to use a series of fixed beds having gas recirculation
through waste heat boilers. Alternatives are to use a fluid bed or
slurry type methanation reactor with steam regeneration coils in the
reactor.
Regarding item 3 above, there is a question as to the leachability
of salts and trace metals in the rejected ash and acceptor. These
are unknown areas' in which further work is needed co define the
problem. Also a suitable outlet for the reject acceptor needs to
be developed and hopefully it can be shown to be suitable for land
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- 55 -
Table 17
TECHNOLOGY NEEDS
Coal Preparation;
• Simple sulfur clean-up on vent gas to allow using coal fines
alone as fuel to dryer, with no high value gas fuel.
• Recover water from dryer vent gas when using high moisture
western coal.
Gasification;
• Operation to assure no formation of tars, phenols, etc. that
complicate clean-up.
• Use for spent acceptor; leachability, trace metals.
Gas Clean-Up;
• Ways to remove sulfur compounds without removing C02-
0 Detailed information on kinds and amounts of solids, oil, sulfur
and nitrogen compounds, and other minor components in raw gas and
effluents during normal operation as well as during upsets - their
separation, and disposal.
• Hydrolysis of sulfur compounds such as COS to H2S prior to sulfur
removal. Presence of cyanides, thiocyanates etc.
• Presence of trace compounds: HF, arsine, metal carbonyls, etc.
• High temperature clean-up of sulfur and dust.
Methanator;
• Designs to maximize recovery of heat to make high pressure steam
(e.g. optimum reactor temperature and cooling technique).
Regenerator;
• Efficient dust removal from flue gas.
• Development work, if required for flue gas turbine to maximize
energy recovery.
• Content of sulfur, trace elements, metal carbonyls, odors, in flue
gas.
Ash Desulfurlzer;
• Use and disposal of ash and spent acceptor - leachability,
trace metals.
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fill. Other areas that are not yet adequately defined have already
been discussed, for example, the exact technique for removing sulfur
from the raw gas without removing much C(>2.
Finally, the very large incentive to use gas turbines for
energy recovery should be emphasized again, and since this often involves
operating on dusty or corrosive gases, development of suitable technology
could lead to more extensive use. The need is for a process to clean
up hot gases, and particularly to remove various sulfur compounds and
small particles. If such a technique were commercially available and
practical, it could be used to advantage in the C02 Acceptor process to
clean-up the raw gas from the gasifier prior to methanation. This would
avoid the inefficient cooling, scrubbing, and reheating that is now
required.
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7. QUALIFICATIONS
As pointed out, this study does not consider cost or economics.
Also, areas such as coal mining and general off sites 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 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 C02 Acceptor study is for low sulfur western coal since
the process is not suited for use with eastern coals. Because of
variations in coal feed, moisture content, and other basis items, great
caution is needed in making comparisons between coal gasification
processes as 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 18.
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 C02 Acceptor process makes no appreciable amounts of
tar, naphtha, or phenols; however, there is a sizeable yield of ammonia
amounting to 130 tpd and it is assumed that this can be recovered and
sold.
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- 58 -
Table 18
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: e.g. mercury, arsenic, fluorine
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- 59 -
8. BIBLIOGRAPHY
1. Mosher, D. R. et al "Basic Features of the C(>2 Acceptor Gasification
Process" ACS Div. Fuel Chem., September 1971.
2. Fink, C. E., et al "C02 Acceptor Process - Status of Development"
1973 Lignite Symp. Grand Forks ND, May 9-10, 1973.
3- Clancey, J. T-, et al "Pipeline Gas from Lignite Gasification"
R&D Rept. No. 16 - Interim Report No. 4, by Consol. Coal Co.
for OCR, May 9, 1969.
4. Letter from G- P. Curran of Consolidation Coal Co. to ERE of
December 5, 1973.
5. Coalgate, J. L., Akers, D- J- and From, R. W. "Gob Pile Stabilization,
Reclamation, and Utilization", OCR RE'D Report 75, 1973-
6. Parrish, R. W. and Neilson, H. B-, "Synthesis Gas Purification
Including Removal of Trace Contaminants by the BENFIELD Process",
presented at 167th National Meeting of ACS, Div. of I&EC,
Los Angeles, March 31-April 5, 1974.
7. Valentine, J. M-, "Purification of SNG with Selexol", ibid.
8. Kniebel, M-, "Rectisol and Purisol Process for Syn-Gas Purification",
ibid.
9. Atmospheric Emissions from Petroleum Refineries, U-S- Dept. of Health,
Educ. and Welfare, Public. No. 763, I960.
10. Ohio State University,"Acid Mine Water", PB 199835, for EPA,
April 1971.
11. "Control Techniques for SOX Air Pollution", Rept. AP-52, U.S.
Dept. Health, January 1969-
12. Magee, E. M>, Hall, H. J. and Varga, G- M. Jr., "Potential Pollutants
in Fossil Fuels", EPA-R2-73-249, NTIS PB No. 225,039, June 1973-
13. Lee. R. E., et al., "Trace Metal Pollution in the Environment", Journ.
of Air Poll. Control, 23., (10), October, 1973.
14. 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.
15. Bolton, N. E., et al., "Trace Element Mass Balance Around a Coal-
Fired Steam Plant", NCS Div. Fuel Chem., J.8, (4), p. 114, August 1973.
16. Attari, A. "The Fate of Trace Constituents of Coal During Gasification",
EPA Report 650/2-73-004, Aug., 1973.
17. Franzel, H. L. "Refiner Cuts Energy Use Sharply" Oil Gas Journal
June 10, 1974, pages 58-61.
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- 60 -
18. The Environmental Impact of Coal-Based Advanced Power Operating
Systems, ?. L. Robson and A. J. Giramonti, EPA Symposium on
Environmental Aspects of Fuel Conversion Technology, St. Louis,
Mo., May 13-16, 1974.
19. Sulfur Emission Control with Limestone/Dolomite In Advanced Fossil
Fuel Processing Systems, D. L. Keairns, E. P. O'Neill, D. H. Archer,
EPA Symposium on Environmental Aspects of Fuel Conversion Technology
St. Louis, Mo., May 13-16, 1974.
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TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO
EPA-650/2-74-009-d
3 RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE Evaluation of Pollution Control in
Fossil Fuel Conversion Processes, Gasification;
Section I: CO2 Acceptor Process
S REPORT DATE
December 1974
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
8 PERFORMING ORGANIZATION REPORT NO
C.E. Jahnig and E.M. Magee
GRU.6DJ.74
9 PERFORMING ORSANIZATION 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
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
IS SUPPLEMENTARY NOTES
16. ABSTRACT
The report gives results of a review of the CO2 Acceptor Coal Gasification Process
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 the thermal
efficiency of the process. For the purpose of reducing environmental impact, a
number of possible process modifications or alternatives have been proposed and
new technology needs have been pointed out.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c COSATl Field/Croup
Air Pollution
Coal Gasification
Fossil Fuels
Effluents
Thermal Efficiency
Air Pollution Control
Stationary Sources
CO2 Acceptor Process
Clean Fuels
Research Needs
13B
13H
21D
20M
8 DISTRIBUTION STATEMENT
Unlimited
19 SECURITY CLASS (This Report/
Unclassified
21 NO OF PAGES
67
20 SECURITY CLASS (Thispage)
Unclassified
22 PRICE
EPA Form 2220-1 (9-73)
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