U.S. Environmental Protection Agency Industrial Environmental Research EPA~600/7-77-057
Office of Research and Development Laboratory /•»•»•»
Research Triangle Park. North Carolina 27711 JllHG 1977
EVALUATION OF BACKGROUND
DATA RELATING TO NEW SOURCE
PERFORMANCE STANDARDS
FOR LURGI GASIFICATION
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
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of traditional grouping was consciously planned to foster technology
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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 (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agency Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—Compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
REVEW NOTICE
This report has been reviewed by the participating Federal
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This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-77-057
June 1977
EVALUATION OF BACKGROUND DATA
RELATING TO NEW SOURCE
PERFORMANCE STANDARDS
FOR LURGI GASIFICATION
by
J.E. Sinor (Editor)
Cameron Engineers, Inc.
1315 South Clarkson Street
Denver, Colorado 80210
Contract No. 68-02-2152, Task No. 11
Program Element No. EHE623
EPA Task Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and ns"elopment
Washington, D.C. 20460
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ABSTRACT
This report contains information on expected emissions from a large coal
gasification complex based on Lurgi technology. Use of best available control
technology was assumed and two different schemes for sulfur removal were ex-
amined. The coal gasification plant was divided into 15 sections, with each
section discussed in a separate chapter. Areas were identified in which pro-
jected emissions data were deemed inadequate for evaluating environmental im-
pact. No major data gaps or inconsistencies were found, but more and better
information is needed concerning effluents resulting from the venting of
pressurization gas from the coal feed lock hoppers. This part of the plant
is a potential source for emitting significant quantities of pollutants, par-
ticularly carbon monoxide. A summary of desirable information presently
lacking in other areas is discussed also.
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CONTENTS
Page
1. INTRODUCTION 1
2. EXECUTIVE SUMMARY 3
3. COAL HANDLING & PREPARATION 19
4. GASIFICATION ' 25
5. FUEL GAS PRODUCTION 41
6. LOCK HOPPER GASES 51
7. SHIFT REACTION 67
8. GAS COOLING 75
9. ACID GAS CLEANING 87
10. METHANATION 107
11. GAS LIQUOR TREATMENT 117
12. SULFUR RECOVERY 135
13. BY-PRODUCT STORAGE 165
14. WATER & WASTEWATER TREATMENT 169
15. SOLID WASTE 197
16. STEAM AND POWER GENERATION 205
17. OXYGEN PLANT 221
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LIST OF FIGURES
Figure No. Title Page
2-1 Coal Gasification Plant Input-Output Streams 4
2-2 Block Flow Diagram with Effluent Streams 5
3-1 Flow Scheme for Coal Handling and Preparation 20
4-1 Flow Scheme for Gas Production 26
5-1 Flow Scheme for Fuel Gas Production 42
6-1 Flow Scheme for the Feed Lock Hoppers 52
6-2 Feed Lock Hopper Gas Alternatives 62
6-3 Gasifier Schematic with Exhaust Fan 63
7-1 Flow Scheme for the Shift Reaction Section 65
8-1 Flow Scheme for the Gas Cooling Section 76
9-1 Solubility of Gases in Methanol 88
9-2 Flow Scheme for the Gas Purification Section - 90
Rectisol I Process
9-3 Effect of Overhead Temperature and Pressure of Hot 94
Regenerator on Methanol Mole Fraction in Rich H«S
Gas '
9-4 Flow Scheme for the Gas Purification Section - 101
Rectisol II Process
10-1 Flow Scheme for the Methanation Section 108
10-2 Flow Scheme for the Compression and Dehydration 109
Section
11-1 By-Product Distribution 118
11-2 Flow Scheme for Gas Liquor Separation 119
11-3 Flow Scheme for Phenol Extraction - Phenosolvan 120
Process
11-4 Flow Scheme for Gas Liquor Stripping 121
12-1 Sulfur Distribution 136
12-2 Flow Scheme for Sulfur Recovery - Stretford Process 137
12-3 Sulfur Recovery Scheme I - Claus/Stretford/ 145
Inci nerati on/Scrubber
12-4 Sulfur Recovery Scheme II - Claus/Stretford/Tail 146
Gas Treatment/Incineration
12-5 Flow Scheme for Sulfur Recovery - Claus/Stretford/ 151
Beavon
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LIST OF FIGURES (Con't)
Figure No. Title Page
12-6 Sulfur Distribution at WESCO 157
12-7 Flow Scheme for Sulfur Recovery - Split Stream 160
Claus/Beavon/Stretford
14-1 River Water Pumping Plant and Raw Water Pipeline 170
14-2 Raw Water Storage and Pumping 171
14-3 Flow Scheme for the Raw Water Treatment Section 176
14-4 Flow Scheme for the Cooling Water System 180
14-5 Flow Scheme for the Ash Dewatering and Transfer 185
Section
15-1 Flow Scheme for the Ash Dewatering and Transfer 198
Section
15-2 Flow Scheme for the Mine Ash Handling Section 199
16-1 Flow Scheme for the Steam and Power Generation 206
Section
16-2 Flow Scheme for the Fuel Gas Treating Area - 217
Rectisol II Process
17-1 Flow Scheme for the Oxygen Plant 222
VI
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LIST OF TABLES
Table No. Title Page
2-1 Stream Flows for Figure 2-1 6
2-2 Air Emissions Summary 7
3-1 Stream Flows of Coal Receiving and Handling Facilities 19
3-2 Component Analysis of Coal 21
3-3 Trace Element Concentration in Coal 21
4-1 Material Balance for Gas Production 27
4-2 Moisture and Ash Free Coal Analysis 28
4-3 Trace Elements 29
4-4 Quenched Ash Stream 31
4-5 Ash Stream Component Analysis 32
4-6 Ash Quench Water 32
4-7 Trace Element Disposition 34
4-8 Trace Element Distribution - Gasifier Ash 35
4-9 Trace Elements - Tarry Gas Liquor (Water) 35
4-10 Trace Elements - Tar, Tar Oil 36
4-11 Trace Elements Percent Breakdown 36
5-1 Moisture and Ash-Free Coal Component Analysis 41
5-2 Material Balance for Fuel Gas Production 43
5-3 Trace Elements 44
5-4 Ash Stream Component Analysis 46
5-5 Ash Water Quench Stream 46
5-6 Trace Elements - Fuel Gas Producer Ash 47
5-7 Trace Elements - Tarry Gas Liquor (Stream 5.5) 47
5-8 Trace Elements - Tar, Tar Oil in Gas Stream (5.6) 48
6-1 Compositions of Coal Feed Lock Hopper Pressurizing Gas 53
6-2 Material Balances for Lock Hopper Gas Flows 55
6-3 Worst-Case Potential Emissions from Feed Lock Hoppers 58
6-4 Feed Lock Hopper Emissions with Gas Recycle 58
7-1 Material Balance for the Shift Reaction Section 69
7-2 Trace Elements Found in Gas Liquors 72
8-1 Material Balance for the Gas Cooling Section 77
VI 1
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LIST OF TABLES (Con't)
Table No. Title Page
8-2 Tar Analysis 80
8-3 Tar Oil Analysis 81
8-4 Composition of Crude Phenols 81
9-1 Material Balance for the Gas Purification Section - 91
Rectisol I Process
9-2 Commercially Available Acid Gas Removal Processes 99
9-3 Material Balance for the Gas Purification Section - 102
Rectisol II Process
10-1 Material Balance for the Methanation Section 110
11-1 Material Balance for Gas Liquor Treatment 122
11-2 Typical Contaminants Found in the Aqueous Layer at 125
the Westfield Works
11-3 Analysis of Phenols in Tar Liquor and Oil Liquor 126
at Westfield Works
11-4 Phenosolvan Plant Performance Sasol Facility 128
12-1 Material Balance for Sulfur Recovery 138
12-2 Gaseous Pollutants 140
12-3 Gaseous Sulfur and Hydrocarbon Emissions 142
12-4 Scheme I - Tail Gas Treatment Processes 147
12-5 Scheme II - Tail Gas Treatment Processes 148
12-6 Material Balance for Claus/Stretford/Beavon Sulfur 152
Recovery Process
12-7 Component Concentrations in Vent Streams from Claus/ 154
Stretford/Beavon Process
12-8 Gaseous Sulfur and Hydrocarbon Emissions 155
14-1 River Water Pumping Plant and Pipeline 172
14-2 Raw Water Storage and Pumping 173
14-3 Raw Water Treating 177
14-4 Cooling Water Systems 181
14-5 Streams Entering the Ash Transport System 188
14-6 Lime Treater Sludge Components 188
14-7 Slowdown Components 189
14-8 Contaminated Gas Liquor Components 189
vm
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LIST OF TABLES (Con't)
Table No. Title Page
14-9 Inlet Ash Transport Water, Net Composition 192
14-10 Components of Ash Transport Water 192
15-1 Mine Ash Handling 200
15-2 Component Analysis of Dry Ash 202
16-1 Material Balance for the Steam and Power Generation 207
Section
16-2 Composition of Stack Gases 211
16-3 Commercially Available Acid Gas Removal Processes 215
16-4 Material Balance for Rectisol II hLS Removal Process 218
17-1 Material Balance for the Oxygen Plant 221
IX
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1. INTRODUCTION
1.1 SCOPE OF EFFORT
This document is a first generation standards of practice manual. Due to
the interest in the subject matter, this report is being published in its pre-
sent form. The technical scope of information that will be addressed in future
standards of practice manuals will be expanded. It is the objective of future
manuals to provide all environmental requirements for a given plant type in one
report.
The report is the result of a task group effort to review the state of the
art for emission controls in first generation coal gasification plants. The
objective of this effort was to provide to the Environmental Protection Agency
a compilation of technical background information for use in assessing the need
and level of New Source Performance Standards for coal gasification plants.
Organizations involved in this task and the principal contact for each included
Cameron Engineers, Inc. (J. E. Sinor), Catalytic, Inc. (J. Cicalese), Hittman
Associates (D. B. Emerson), and Radian Corporation (W. C. Thomas). The analytical
technique used was to take published flow sheets for a particular plant and assign
the various sections to different groups who would attempt to define all internal
stream flows and effluents. Following the completion of the analysis of one par-
ticular plant design, it was anticipated that the next step would be to examine
the effect of variations in coal feed, geographical location and process techno-
logy. This report covers only the first phase work -- analysis of a specific
process and coal feed.
Major goals were the identification and characterization of all effluent
streams. Where such information was not available from published design esti-
mates, an attempt was made to provide "best guess" approximations. The time
and funding available did not allow for rigorous design calculations. The
scope of the analysis was specifically limited to the use of Lurgi gasifiers.
Since there are no operating Lurgi installations in the U.S.A., information on
detailed operating procedures is often sketchy and incomplete. Where operating
procedures could affect the generation of effluents, it was necessary either to
use engineering judgment in assuming a particular mode of operation or to con-
sider more than one alternative procedure.
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1.2 PROCESS SELECTION AND DEFINITION
The process design selected for analysis is that presented in "Second
Supplement to Application of El Paso Natural Gas Company for a Certificate
of Public Convenience and Necessity, Docket No. CP73-131, October 1, 1973".
This was judged the most complete single source of publicly available design
information for a coal gasification plant. Daily output of this plant is
288,600,000 standard cubic feet of synthetic pipeline gas with a heating
value of 954 BTU/SCF. The coal feed is a low-sulfur subbituminous coal.
The coal mining operation is not considered to be a part of the gasification
g
plant. Heating value of the input coal is assumed to be 489.5 x 10 BTU/day.
Fuel for power and steam generation within the plant is obtained by
gasifying coal in a set of air blown Lurgi gasifiers to produce a low-BTU
fuel gas. This fuel gas is desulfurized before combustion. Overall plant
balances for this design will thus be appreciably different than for a case
where coal or tar is burned directly for on-site power generation.
The basic acid gas cleanup system considered is the Lurgi-licensed
Rectisol process, as used in the El Paso design. Two different acid gas
cleanup schemes are considered. Case 1-A uses Rectisol I with sulfur recovery
via the Stretford process. Case 1-B considers the use of Rectisol II com-
bined with a Stretford and a Claus unit for sulfur recovery followed by tail
gas treatment.
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2. EXECUTIVE SUMMARY
2.1 PROCESS SUMMARY
Estimated effluents from coal gasification plants have been published in
a number of places, including environmental impact statements, FPC applications
and various EPA reports. This report is a detailed review of emissions for one
particular plant design -- the El Paso Burnham complex. Figure 2-1 is a summary
of input, product and effluent streams for the complete plant. Each effluent
stream is numbered and the same number key is used in Figure 2-2. Figure 2-2
shows the source for each stream in terms of the section of the plant involved
and the chapter in this report which describes that section.
Table 2-1 presents a summary of all major streams recognized in this
analysis. Air emissions are listed in Table 2-2. These values should be
considered by plant designers as representative of achieveable effluent levels
for steady-state operation. Practical operating considerations for a plant
of the size and complexity being studied will dictate that regulatory perfor-
mance standards must allow some leeway for plant upsets, feed variations and
general performance variations.
While the plant has been designed with extensive pollution controls, a
number of streams must still be discharged to the environment. The magnitudes
and characteristics of these streams are -discussed in the following sections.
2.2 ENVIRONMENTAL CONCERNS
2.2.1. Air Emissions
Based on currently available data, the major streams contributing to air
pollution appear to have been reasonably analyzed in previous efforts. No
major data gaps or inconsistencies were discovered in the number presented in
the El Paso FPC application, although the discussion of coal lock vent gases
was incomplete and inadequate. The major pollutants discharged to the environ-
ment from the gasifier section consist of vent gases from the coal lock hopper.
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r
AIR EMISSIONS
Jl
IOCK HOPPER POWFR PLANT TAIL-GAS POND
VEHTS EXHAUST STACKS 1HC1HERATOR EVAPORATION
ASH QUENCH
SLUICE VENT
FUGITIVE
COAL DUST
COOLING TOWER
WATER LOSSES
NITROGEN FROM
OXYGEM PLANT
BY-PRODUCT
TANK VEHTS
ADSORBER
OFF-GAS
' WATER
4>
AIR
COAL GASIFICATION PLANT BOUNDARIES
© O 0 0 0
TAR OILS
TAR
NAPHTHA
\ '
AMMONIA
10) (11
SULFUR SYNTHETIC
. , PIPELINE GAS ,
PHENOLS
COAL FINES
J
SALABLE PRODUCTS AND BY-PRODUCTS
PLANT
FLARE
ASH
COAL
REFUSE
STRETFORD
SLOWDOWN
SOLID AND
>-LIQUID
WASTES
Figure 2-1. COAL GASIFICATION PLANT INPUT-OUTPUT STREAMS
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c
p
c
1
JAL
i. 3
1
FUEL GAS '
PRODUCERS -»»
Ch. 5
'
<*
POWER & STEAM
PLANT
Ch. 16
j
/—
}'
71
ASH
DISPOSAL
Ch. 15
COAL LOCK
HOPPERS
Ch. 6
'
OXYGEN
PLANT
Ch. 17
Ch. 11
A
1 \
BY-PRODUCT
STORAGE
Ch. 13
SULFUR
Ch. 12
SHIFT
REACTION
Ch. 7
GAS
COOLING
Ch. 8
ACID GAS
REMOVAL
Ch. 9
1
/19\ VARIOUS (7z) (l7) (20) VARIOUS
v-/ SOURCES ||| SOURCES
V \\i \\i I
V
WATER
TREATMENT
Ch. 14
II , I
(14) * (23)
V-/ASH BY-PRODUCTS V7
1 \ V
PLANT
FLARE
1
9
if
i
METHANATION
Ch. 10
1
PRODUCT GAS
Note: Ch. = Chapter Number
FIGURE 2-2. BLOCK FLOW DIAGRAM WITH EFFLUENT STREAMS
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TABLE 2-1. STREAM FLOWS FOR FIGURES 2-1 AND 2-2
Stream Number
INPUTS:
1. Coal
2. Water
3. Air
PRODUCTS & BY-PRODUCTS:
4.
5.
6.
7.
8.
9.
10.
11.
Tar Oils
Naphtha
Tar
Ammonia
Sulfur
Phenols
SNG
Coal Fines
EFFLUENTS & WASTES:
12. Stretford
13. Coal Refuse
14. Ash
15. Flare
16. Sluice Vent
17. Off-Gas
18. Evaporation
19. Tank Vents
20. Incinerator
21. Nitrogen
22. Exhaust Stack
23. Cooling Loss
24. Hopper Vent
25. Fugitive Dust
Total Flow
Ibs/hr
2,706,000
3,650,000
2,593,968
24,588
20,005
88,824
21,422
15,582
11,271
513,760
211,960
Unknown
139,973
476,000
Unknown
Unknown
,803,872
80,210
12.5
78,278
,587,462
1
6,483,000
1
,483,000
2,573
121
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TAULE 2-2. AIR EMISSIONS SUMMARY
AIR EMISSIONS. LBS/IIR.
Stream
Flare
Sluice Vent
Off-Gas
Evaporation
Tank Vents
Incinerator
Nitrogen
Exhaust Stacks
Cool ing Loss
Hopper Vent
Fugitive Dust
Totals, lus/hr
Totals, Ibs/MHBTU
Total Flow
Ibs/hr
Unknown
Unknown
1,803.872
80,210
12.5
78,278
1.587,462
6,960,390
1,483,000
2,573
121
(1) (2)
II2S CO CIU NMII SO, rlOx
113 1784 3231 5782
tr.
11
50 8
325 496
tr.
14 649 188 38
127 2433 3419 5831 375 504
0.006 0.115 0.168 0.0286 0.018 0.025
(3)
Nllj. NMEII
2390
tr.
1.5 11
tr.
26
1.5 2427
0.119
C02 N2
1,598,558 128,346
49,912 29.280
1.587.462
629,453 5.041.980
1.320 262
2.279.243 6.787.338
112 333
M
80,210
4,613
271,121
1,483,000
17
I.838.9GI
90
Dust
121
121
0.00
(1) Including COS & CS?
(2) Non-methane hydrocarbons
(3) Non-methane, - ethane hydrocarbons
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The lock hoppers are pressurized with cooled raw product gas. After reaching
system pressure, coal is fed into the gasifier. When the coal lock hopper is
empty, the pressurizing gas is vented to a lock gas holding vessel which operates
near, but slightly above, atmospheric pressure. As the fresh charge of coal is
dumped into the hopper, it displaces to the atmosphere the residual gases remain-
ing in the hopper.
Estimates made in this study show that the gas vent rate is about 2,573
Ib/hr. and contains H2S, C02, CHi», CO, non-methane and non-ethane hydrocarbons,
and coal dust. A number of different gas compositions could be vented and
varying amounts of individual constituents would be discharged depending on
the source of the gas used. If the gas were not recycled at all but completely
vented, the total discharge would be on the order of 82,000 Ib/hr. Worst-case
emission, relative to coal feed rate, would be as follows:
Potential
Emissions
Components 1bs/106 BTU Coal
H2S 0.022
CO 1.0398
OK 0.310
NMH 0.083
Carbon monoxide emissions from uncontrolled venting could be a major
problem. Because of the economic value of the pressurizing gas, however, it
would undoubtedly be recycled to the maximum extent possible. Further con-
trol , if needed, could be accomplished by the use of exhaust fans and incinera-
tion.
Atmospheric discharge streams from the sulfur recovery section include
vent streams from the lean H2S absorber and oxidizer (stream #17), and stack
gas from the H2S incinerator (#20). The vent stream from the absorber and
oxidizer contains appreciable quantities of COS (67 ppmv), some H2S and traces
of CS2. Total hydrocarbons including ChU and C2H6 are 9,400 ppmv and CO
emissions are 1500 ppmv. The high levels of hydrocarbons, CO, and COS released
are a major source of concern and various control methods should be studied.
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At present, the only proven method for treatment would-be the incineration of
organic sulfur compounds and hydrocarbons. It should be noted that the emission
levels are based on study group estimates. Exact emissions from an operating
plant could vary considerably.
The incinerator stack gas (#20) consists of C02, H20, S02, and NO . The
A
estimated S02 and NO levels are 350 ppmv and 70 ppmv, respectively. These
A
gases may require desulfurization because of the relatively high S02 content.
Various venturi scrubbers/packed column systems are available for gas treating.
• The by-product storage area will also represent a pollution source for
the complex. Discharges (#19) will result from tank breathing, leaks, spills
and venting of tanks during filling. Estimated emission rates for the tank
farm are as follows:
• Crude phenol - 1.5 Ibs/hr.
• Tar Oil - 2.6
• Naphtha - 2.1
• Ammonia - 1.5
• Product gases - 3.2
• Methanol - 1.6
Control of vapor emissions could be achieved by a vent condenser which
circulates refigerated brine at 0°F or by scrubbing the vent vapors with a
low volatility solvent.
Evaporation from the waste pond (#18) and misting and evaporation losses
from the cooling towers (#23) add about 1,563,210 Ibs/hr. of water vapor plus
traces of organic compounds, and non-methane, non-ethane hydrocarbons
to the atmosphere. Although only trace amounts of these contaminants are
expected, no hard data exists on the exact quantities. Further studies are
needed to determine the amounts emitted and effects on the immediate environ-
ment.
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Discharge of the hot gasifier ash in the ash transfer sluice, produces
a small but totally undefined stream to the atmosphere. The hot ash is quenched
with contaminated process water and produces varying amounts of steam. This
steam contains ash particles and possibly traces of organic compounds which
could be formed from contacting the waste water (which has a high organics
content) with hot ash containing unreacted carbon. The nature and quantity
of these compounds is unknown, as well as the amount of steam produced. It
is not expected that this discharge would present a hazard, but more infor-
mation should be obtained to confirm that it does not.
By far the largest single discharge from the complex is the stack gases
generated by combustion in the steam and power generation section of the plant.
The total stream flow rate (#22) is approximately 6,960,390 Ibs/hr. of com-
bustion products such as S02, NOx, H20, C02, CO, hydrocarbons and air. Since
the fuel to the combustion operations is treated fuel gas, the stack gases
-contain negligible amounts of particulate matter. Use of excess air during
combustion will minimize the amount of CO and hydrocarbons in the gas. The
total effluent from the stacks meets current air pollution standards and there-
fore is discharged directly to the atmosphere.
Emissions from the coal handling and preparation area consists of fugitive
dust (stream #25) produced by the crushing, screening, conveying, stockpiling,
reclaiming, and coal fines cleaning operations. The control method proposed
by El Paso would use water sprays with a wetting agent installed at transfer
points, truck dump hoppers, etc. It is estimated that the total fugitive dust
emissions would not exceed 121 Ibs/hr. The control method chosen is an effec-
tive proven method and the emissions listed are probably the minimum achievable
level without the addition of other equipment such as exhaust fans and hoods.
Although carbon dioxide emissions are usually considered to be inert,
the large amounts emitted from a commercial gasification facility call for a
careful evaluation of local effects. Although similar in quantity to that
emitted at a large power plant, the effect of lower stack temperatures should
be studied carefully in dispersion models.
A summary of air emissions is given in Table 2-2.
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2.2.2 Water Effluents
The geographical location of the El Paso complex makes it possible to
design for zero discharge of water effluents. In other parts of the country,
where it is not possible to dispose of contaminated water by solar evaporation,
water pollution may be a major concern.
The contaminated water discharge to the evaporation pond is not considered
an effluent since none of the water is returned to the San Juan River.
However, two potential escape routes for the water from the holding pond
exist. One route would be an accidental breaching of the pond dikes. In
this case, contaminant control measures would be immediately enforced and
damage to the area minimized. The second route, which is potentially more
troublesome, involves the possibility of permeation of contaminated water
through the pond bottom. This migration could expose groundwater in the area
to all the components in the pond water, and create an extreme pollution
problem. Extraordinary care should be used in construction of the pond and
monitoring of possible waste water migration.
In some areas the coal seam being mined constitutes a part of a ground-
water aquifer. Leaching of ash and other plant wastes which have been returned
to the mine for disposal can then result in a deterioration of groundwater
quality. Although such concerns are outside the scope of this study, much
more attention should be devoted to ash leachability in areas with significant
groundwater flow.
2.2.3 Solid Waste Disposal
Coal refuse from preparation and handling, and ash from the gasifiers
are the two major solid discharge streams. The coal refuse from the preparation
section is trucked back to the mine site for disposal. This is an effective
method of control and disposal for this material. The ash from both the
oxygen and air blown gasifiers is transported to ash handling with contami-
nated process water. The ash slurry undergoes classification and dewatering.
The coarse, dewatered ash is transferred to the mine for disposal. Fine ash
- 11 -
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from the classification step and the main water stream are sent to a thickener.
The underflow containing the ash fines are sent to a fine ash settling pond.
The settled fines in the pond are periodically removed and sent to the mine
site for disposal. While the ash itself is well contained by burial, a
number of constituents in the ash could become a pollution hazard if leaching
were to occur. An uncertain amount of trace elements are concentrated in the
ash and various organics from the quench water are also present. As pointed
out in the discussion of water effluents, the possibility of water pollution
due to leaching from the solid wastes is highly dependent on local climate,
rainfall and groundwater conditions. A thorough analysis of all these factors
is required for each plant site in order to determine the best procedure for
solids disposal.
2.2.4 Occupational HealthIssues
Health statistics on occupational groups in other coal conversion operations,
such as coke ovens and coal tar processing, have shown significantly higher
lung cancer rates than groups without such occupational exposure. Several
other diseases and types of cancer may be found to have higher incidences
also. Although no comparison should be made between coke ovens, where worker
exposures are extremely high, and gasification plants where process streams
are almost totally controlled, the fact that the same types of materials will
be present indicates that occupational health concerns must be addressed
carefully and thoroughly. No data were discovered in this study to suggest a
significant health problem with the proposed plant design.
2.2.5 Trace Metals
Because of the large quantities of raw materials consumed, on the order
of 20,000 to 30,000 tons of coal per day, there is a potential for discharge
of large quantities of material which may be present only in very low con-
centrations. Neither the fate nor the effects of trace elements are clearly
understood, but many are either toxic or carcinogenic and others may act as
- 12 -
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mutagens or teratogens.
Nickel, arsenic, cadmium and lead are among the hazardous metals whose
flow rate through the plant can be as high as several pounds per hour. If
released to the environment in sufficient quantity these materials could lead
to undesirable environmental effects.
2.2.6 Polycyclic Aromatic Hydrocarbons
Many of the by-product streams will have high concentrations of poly-
cyclic aromatic hydrocarbon compounds. The concentrations will be much
higher than in comparable petroleum derived liquids. As a general class,
many of these compounds are known or suspected carcinogens. Eventual use of
the by-products by consumers, or ultimate disposal of manufactured products
should be investigated to be sure that environmental contamination by PAH's
does not occur. Within the gasification plant itself, workers must be pro-
tected from exposure, even to relatively low levels of PAH in the atmosphere.
This analysis did not reveal any obvious route for substantial quantities
of PAH to be released. One possible source could be the vent gas from the
coal lock hoppers. It is recommended that such gases be controlled and
collected locally by hoods and exhaust fans as necessary.
2.2.7 Secondary Pollution Effects
Secondary effects are defined as those which result off-site from the
use of plant products, by-products or waste streams. In order to assess the
overall environmental impact from a gasification complex, any such secondary
pollution should be identified.
The product gas will be pipeline quality; that is, it will satisfy
various standards set up by the government and the natural gas industry. It
will be distributed in the existing natural gas pipeline system for residential,
commercial and industrial usage. The composition of the final SNG product
stream is estimated to be as follows:
- 13 -
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Component Volume % Flow Rate, Ibs/hr
OU 92.92 473,512
H2 4.15 2,661
C02 1.81 25,310
N2 + Ar 1.08 12,106
CO 0.010 122
Other HC's 0.0116
No information developed in this analysis would indicate that burning
SNG will result in any new or different pollution than burning natural gas.
Certainly the use of SNG will result in much less sulfur pollution at the
point of final consumption than would the use of an equivalent amount of coal
or oil at the same point. As nearly as can be determined, all volatile trace
metals and heavy polycyclic hydrocarbons should be removed from the product
streams. However, this assumption should be verified carefully in an operating
plant to be sure that trace metals or compounds such as carbonyls do not appear
in the product by unforeseen mechanisms.
Useful by-products from the gasification plant include tars, tar oils,
naphtha, ammonia, sulfur and phenols. The tars, tar oils, naphtha and phenols
could be burned directly as fuel or used as raw materials for a large variety
of chemical products. If used directly as fuel, the sulfur and trace metal
contents may be of concern. The sulfur content of the tar is estimated to be
0.77% and of the tar oil 0.29%. In general, in order to meet sulfur emissions
limitations, a high sulfur fuel oil will be blended with a low sulfur oil until
an accpetable sulfur level results. The same technique could be applied to
combustion of the tars.
Due to the large pitch or residue content of the tar, excessive soot may
be formed in some equipment. These particulates would then be discharged
with the stack gases.
Many of the trace elements found in coal may be found in the tar. Some
of these include antimony, arsenic, boron, bromine, cadmium, fluorine, lead,
mercury and nickel. During combustion, some of these elements may be released
- 14 -
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to the atmosphere in various forms. Data are lacking with respect to both the
quantities of various elements and the actual compounds formed.
Acceptable technology for control of sulfur emissions are available in-
cluding desulfurization of the fuel, blending with low-sulfur fuels, stack
gas scrubbing, etc. Sulfur in coal tars can be controlled by any of these
methods:, so no new problems are likely to occur. Control and removal of
trace elements may be a much more difficult problem. When coal is
burned directly, most of the trace elements are recovered in either the
bottom ash or the fly ash. Extensive research has shown, however, that many
trace elements are released and their buildup in areas downwind from the
plant can be carefully analyzed. The concentration of any trace elements in
the tar, along with the lower ash content and different burning characteristics
of tar could result in an entirely different spectrum of emissions from a
tar-burning boiler. More studies are needed in this area.
Recycle of tar back to the gasifier is a direct method of control which
has been proved in operation.
Tar oils, as with tar can be burned directly or refined. An advantage
of tar oil is that it is a much lighter stock and more easily refined.
The naphtha produced in the plant appears to be much like its conventional
petroleum counterpart. Some may be used as a cutter stock to reduce the vis-
cosity of the tar before it is used in boiler furnaces. The trace element
concentrations in naphtha should be minimal, and secondary pollution from
naphtha should be basically the same as from the use of petroleum naphthas.
Ammonia and sulfur streams should be no different than those produced by
other processes.
Possible by-product uses other than fuels are listed below, along with
the current major source for each. Although the gasification by-products
will more nearly resemble coke oven products than petroleum, there are
appreciable differences even here. Gasification tar and tar oil contains
relatively high proportions of solids, water, acids and nitrogen. If the
- 15 -
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Current Dominant Source
Product Petroleum Coke Oven
Benzene X
BTX crudes X
Phenol (natural/refined) X
Cresylic acids X
Naphthalene X
Creosote X
Carbon black feedstock X
Electrode pitch X
Delayed coke X
Fluid coke X
Specialty tar coatings, pitches, enamels X
Road tars X
Distillate/residual fuel stocks X
Gasoline pool stocks X
gasification by-products are used to displace petroleum-derived products, then
the much higher content of polycyclic aromatic hydrocarbons may become a matter
of concern.
Without knowing in advance what the actual disposition of the by-products
will be, it is impossible to form even qualitative estimates of secondary
pollution impacts.
2.3 NEW TECHNOL0GY NEEDS
This study suggests that there are two major areas in which new or
improved technology is desirable in order to improve either the efficiency or
the economics of pollution control. The first area is removal of organic
(mostly COS) sulfur from the gas stream. Although sulfur as COS is only a
small percent of the total sulfur contained in the crude gas, by the time
conventional sulfur removal techniques have been applied, COS may be the
major sulfur constituent. Thus a further reduction in sulfur emitted is
possible only by attacking COS.
The second area for improvement is a better technique for control of
hydrocarbon emissions than incineration. In some cases a stream requiring
incineration can simply be added to a boiler furnace so that little additional
fuel is used. In other cases the stream may be so large that this would not
be practical.
- 16 -
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2.4 PROCESS DATA NEEDS
One of the most troublesome aspects of operating pollution control equip-
ment in coal conversion plants is likely to be the variability of the feed
coal. Coal is not a uniform substance and its chemical properties may change
markedly over short distances in the deposit. These changes can cause fluctua-
tions in the compositions of- all process streams, with resulting fluctuations
in the performance of pollution control equipment. The information upon which
this report was based consists mostly of design data from various proposed
coal gasification projects. These data are really feasibility studies based on
laboratory analysis of coal core samples and engineering estimates for the
composition of process streams. Although the accuracy of the assumptions which
went into the engineering estimates will probably not be critical with respect
to the overall operation of the coal gasification plants, it could have a very
large effect on sulfur emissions and on the efficiency and operability of
emission control devices.
Tests results in a Lurgi gasifier with American coals exhibit a wide
range of sulfur concentrations in the raw gas due to variability of the
feed. Variations in the coal produced from any one mine will depend
on whether a single or multiple seams are being mined as well as individual
deviations within a seam. A critical parameter is the amount of sulfur appear-
ing as COS, because of the difficulty of removing COS. According to testimony
presented to the National Air Pollution Control Techniques Advisory Panel,
COS concentrations may be twice as high as that predicted by Lurgi for a given
ratio of organic to pyritic sulfur in the coal.
Actual operating data, in terms of concentrations as a function of time,
rather than grab sample results, are urgently needed. Without information of
this type it is impossible to say whether certain sulfur removal systems would
be effective. Trace metal balances are needed. Although some liquid and solid
trace metal analyses have been conducted, meaningful material balances for
individual elements could not in general be closed with satisfactory accuracy.
As a result, information available to date is only qualitative at best.
- 17 -
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The composition of gases vented during ash quenching is completely un-
known.
The following types of data are the most urgently needed:
1. The time variation of effluent production under normal "steady
state" operations.
2. COS concentrations as a function of definable coal properties.
3. Closed material balances for important trace elements.
4. The influence of operating parameters and fluctuations on crude
product properties.
2.5 RESEARCH DATA NEEDS
The foregoing section discussed data which can only be obtained from a
large operating plant. However, there are many areas in which improved
knowledge of pollution parameters can be obtained by research conducted at a
smaller scale. For instances, pilot plant results for the C02 Acceptor
process have shown essentially zero generation of heavier hydrocarbons in the
raw gas. There is presently no satisfactory explanation for this phenomenon,
but if process conditions can be adjusted to reduce the output of such materials
the effect on pollution control costs could be substantial.
Much additional information on trace element distributions is needed,
including not only their location in various by-product and process streams
but also their form (reactivity, solubility, Teachability, etc.). Not all
forms of trace elements are toxic; it is important to know which compounds
are hazardous and which compounds are formed and/or emitted during gasification.
For instance, nickel carbonyl was detected in the product during operation of
a Lurgi gasifier at Westfield, Scotland a number of years ago. This highly
toxic material is known to be carcinogenic in the respiratory system and its
presence in any vent streams could.be-an-occupational hazard. •
- 18 -
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3. COAL HANDLING AND PREPARATION
3.1 STREAM FLOWS
Figure 3-1 is a schematic flow diagram of the coal handling and prepara-
tion facilities. These facilities produce two sizes of coal feed for the plant
(44.45 mm x 8mm and 8mm x 2mm) plus coal fines (less than 2mm) for sale.
Run-of-mine (ROM) coal will be received from the mine by trucks and dumped
into hoppers with a 36" grizzly on top. The 36" x 0 coal will be fed over a
6" grizzly and the 36" x 6" oversize crushed to minus 6". The 6" x 0 coal will
be primary screened at 1-3/4"(44.45 mm) and the oversize secondary crushed to minus
1-3/4". The primary and secondary crushers are designed to operate ten shifts
per week at 3,614 TPH.
The coal sampling and stockpiling equipment are designed to operate 10
shifts per week at 3614 TPH and the reclaiming, screening and fines cleaning
equipment are designed to operate 7 days per week, 24 hours per day at 1500 TPH.
Approximate inventory in the four stockpiles is 12 days plant feed (about
350,000 tons).
Table 3-1 lists stream flows for these facilities and Tables 3-2 and 3-3
are the components and trace element analyses of the coal. Stream compositions
for the product from coal fines cleaning and the refuse from the coal fines
cleaning plant were estimated on the basis of 95% of the ash being contained
in the refuse stream.
Table 3-1. STREAM FLOWS OF COAL RECEIVING AND HANDLING FACILITIES
(POUNDS PER HOUR, AVERAGE)
Stream
Coal
Ash
Water
Total
3.1
1,745,370
520,905
439,725
2,706,000
3.2
1,250,310
373,220
314,950
1,938,480
3.3
268,053
80,012
67,522
415,587
3.4
52,868
64,359
22,746
139,973
3.5
174,129
3,388
34,443
211,960
- 19 -
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RUN OF MINE <3 I
COAL
SIZE SAMPLE
I4O LB. PER
IOOO TON
GRADE SAMPLE
30 LB PER
IOOO TOH
BY PASS CONVEYOR
ro
O
COAL FEED (2 sizes)
44.45mm (I 3/4") i 8mm
8 mm i 2 mm
SIZED COAL TO
GAS PRODUCTION
SIZED COAL TO
FUEL GAS
PRODUCTION
REFUSE TO
MINE ASH HANDLING
CLEAN COAL FINES
TO SALES
DRAWING NOTES
Figure 3-1. FLOW SCHEME FOR COAL HANDLING AND PREPARATION
-------
Table 3-2. COMPONENT ANALYSIS OF COAL (MAP)
Weight %
Carbon 76.26
Hydrogen 5.58
Nitrogen '-32
Sulfur 1-07
Oxygen 15.74
Trace Compounds .03
100.00
Table 3-3. TRACE ELEMENT CONCENTRATION IN COAL(3)
Concentration in p.p.m. by weight
Element
Antimony
Arsen ic
Bi smuth
Boron
Bromi ne
Cadmiurn
Fluorine
GaI I i urn
Germanium
Lead
Mercury
Nickel
Selen ium
Zinc
From
0.3
. 1
.0
60.0
.4
.2
200
.5
.1
1 .4
.2
3.0
. 1
1 . 1
To
1.2
3.0
.2
150.0
18.0
.4
780
8.0
.5
4.0
.3
30.0
.2
27.0
- 21 -
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3.2 POTENTIAL EFFLUENTS
3.2.1 Major Effluents
The major effluent from these facilities is expected to be particulates
produced by the crushing, screening, conveying, stockpiling, reclaiming and
coal fines cleaning operations. Water runoff from the area also may be con-
taminated with suspended coal particles or compounds leached from the storage
pile. Some methane may be evolved from the coal while in storage, as indicated
by SASOL(4).
The El Paso FPC application does not characterize these effluents or estimate
their discharge rates. WESCO indicated that only trace amounts of particulates
(2}
are expected from the coal handling facilitiesv '. Wyoming Coal Gas Company
estimated particulate emissions of 0.05 pounds per ton of coal for the crushing,
screening and conveying operations^ . Wyoming Coal Gas Company also estimated
particulate emissions of 0.025 to 0.04 pounds per ton of coal handled for the
coal storage and reclaiming facilities. Utilizing these estimates for the El
Paso design results in an estimated 101 to 121 pounds per hour of uncontrolled
particulates emitted from the coal handling and preparation facilities.
The amount of runoff will be highly variable and depend primarily on local
climatic conditions and extent of enclosures for the coal storage area. No
estimate of methane evolved from the coal during storage is available. •
3.2.2 Trace Constituents
Trace constituents emitted from these facilities would be those contained
in the coal particulates produced by the crushing, screening and conveying
operations. Table 3-3 is a trace element analysis of the coal.
3.3 CONTROL METHODS
The planned pollution control methods for these facilities as stated in the
El Paso FPC application are: water sprays with a wetting agent will be used at
all transfer points, truck dump hoppers, crushers and screens; and dust collectors
will be installed in the screening plant. Water use for dust suppression was
- 22 -
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estimated at 20 gpm per transfer point. Total water use for the estimated
17 transfer points is 340 gpm. This water is supplied by the water stream
indicated for mine use. The physical preparation facilities are not des-
cribed in enough detail to suggest other specific controls. Some potential
methods to minimize or control pollutants include:
e enclosing screening and coal fines cleaning operations and
controlling particulates by use of wet scrubbers or baghouses.
« collecting and treating runoff from the storage piles.
« preventing spontaneous combustion in storage piles by avoiding
segregation of fines and compaction.
• covering conveyors.
» using a baghouse filter to treat air exhausted from the sampling
facilities.
e controlling the height of the stacker such that the free fall
of the coal onto the pile is minimized thus reducing the coal dust
emissions produced during the stacking operations.
3.4 PROCESS MODIFICATION
None suggested.
- 23 -
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REFERENCES
1. Wyoming Coal Gas Company, "Applicants Environmental Assessment For A Pro-
posed Gasification Project In Campbell And Converse Counties, Wyoming",
October, 1974.
2. WESCO, "Final Environmental Statement - Western Gasification Company,
Coal Gasification Project And Expansion of Navajo Mine by Utah International
Inc.", January 1976.
3. El Paso "Draft Environmental Statement - El Paso Coal Gasification Project",
July 1974.
4. Communication with EPA.
- 24 -
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4. GASIFICATION
4.1 STREAM FLOWS
The gas production section of the plant consists of 28 oxygen
blown Lurgi gasifiers operating at 435 psig. Initial plans call for the
use of 24 gasifiers for actual production with 4 gasifiers as standbys.
These units will produce 288 MMSCFD of synthetic crude gas from 23,261
tons of coal feed. The process flow for this section of the plant is
illustrated in Figure 4-1.
Streams to the gasifier consist of coal, steam and oxygen.
Initially, sized coal from coal preparation is fed into the coal bunker
atop the gasifier (see Figure 6-3). The coal is then dropped into the coal
lock which is subsequently pressurized and opened to the gasifier. The
coal then flows down through the gasifier where crude gas, tar, tar oil,
naphtha, phenols and other compounds are formed. This crude gas exits
the gasifier for cooling, separation, and further processing. The re-"
maining material, ash and some unreacted coal, are dumped out of the
bottom of the gasifier to a lock and ash quench system. The quenched
material is then transported via a sluiceway to an ash handling area.
4.1.1 Coal Feed
The crushed and sized coal is fed to the gasifiers at the rate
of 1,938,480 Ib/hr. Component flow rates are given in Table 4-1.
The component analysis for the moisture and ash free coal is
given in Table 4-2.
- 25 -
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SIZED COAL
BFW
COAL LOCK GAS
TO ASH DEWATERING
AND TRANSFER
.RECYCLE GAS
LIQUOR
CRUDE GAS TO
SHIFT CONVERSION
CRUDE GAS TO
GAS COOLING
WASH COOLER
PUMP
DRAWING NOTES
Figure 4-1. FLOW SCHEME FOR GAS PRODUCTION
-------
Table 4-1. MATERIAL BALANCE FOR GAS PRODUCTION
ro
i
tream Number 4.1 4.2 4.3 4.4 4.5
Component Ibs/hr Ibs/hr Ibs/hr Ibs/hr Ibs/hr
co2
C2H4
CO
H2
CH4
N2 + Ar 10,275
02 460,365
Total Dry Gas 470,640
Water 314,950 1,783,540 ++
Coal (MAP) 1,250,300 19,639
Ash 373,220 373,220
Naphtha
Tar Oil 11,993
Tar 65,811
Crude Phenols 173
NH.,
TOTAL 1,938,480 1,783,540 470,640 392,859
4.6
Ibs/hr
1,333,502
13,538
12,273
611,677
84,859
193,007
19,730
11,861
2,280,447
1,394,960
--
--
20,005
28,007
6,630
8,272
15,978
3,757,489
4.7
Ibs/hr
729,157
7,403
6,710
334,464
46,401
105,537
10,788
6,485
1,246,945
762,764
--
--
10,939
15,314
3,999
4,991
9,640
2,054,592
4.8
Ibs/hr
604,345
6,135
5,563
227,213
38,458
87,470
8,942
5,376
1,033,502
632,196
--
--
9,006
12,693
3,315
4,136
7,989
1,702,897
-------
Table 4-2. MOISTURE AND ASH FREE COAL ANALYSIS^
Component Wt % Lb/Hr
Carbon 76.26 953,479
Hydrogen 5.58 69,767
Nitrogen 1.32 16,504
Sulfur 1.07 13,378
Oxygen 15.74 96,797
Trace Compounds 0.03 375
TOTAL 100.0% 1,250,300
Trace elements in the coal, while averaging only .03% of the
total weight, represent a potential pollution problem. Because of this,
their distribution in the gasifier system will be estimated in Section
4.1.6. Table 4-3 gives a range of trace element flow rates into the
gasifier system based on the trace element concentrations listed in
Table 3-3.
4.1.2 Steam and Oxygen
The sources of steam for the gasifier include the normal steam
generation system as well as steam generated in the gasifier cooling
water jacket. Water feed to these systems consists of treated and
demineralized river water. It will be assumed that this is pure water
and will not contain enough trace constituents to have an effect on the
overall trace constituent balance. The combined steam rate is 1,783,540
Ib/hr at 550 psig and 750°F. Oxygen is supplied to the gasifier at 510
psia. This stream consists of 460,365 Ib/hr of oxygen with 10,275 Ib/hr
of N + Ar. The oxygen is produced by standard air separation methods.
- 28 -
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Table 4-3. TRACE ELEMENTS (POUNDS PER HOUR)
Element From J_p_
Antimony 1.5 0.375
Arsenic 3.75 0.125
Bismuth 0.25 0.0
Boron 187.5 75.0
Bromine 22.5 0.5
Cadmium 0.50 0.25
Fluorine 975.0 250.0
Gallium 10.0 0.625
Germanium .625 0.125
Lead 5.0 1.75
Mercury 0.375 0.25
Nickel 37.5 3.75
Selenium 0.25 0.125
Zinc 33.75 1.375
4.1.3 Crude Gas
Processing of the crude gas begins by passing the 650°F gas
through a direct contact wash cooler immediately after the gasifier, to
condense liquids and remove coal dust and ash. The gas is further
cooled to 370°F in a waste heat boiler which produces 100 psig steam.
During the cooling, various amounts of tar, tar oil and trace compounds
are condensed and removed. Steam condensed from the crude gas in
downstream processing is recycled back to the gasifier area for use as
the cooling agent in the direct contact cooler. During this processing,
the crude gas picks up approximately 92,000 Ib/hr of water which it
carries out of the area. Immediately following the waste heat boiler,
the gas stream is split. Approximately 45% of the gas is sent to crude
gas cooling while the remainder is sent to the water-gas shift unit for
CO conversion. The composition and flow rate of the crude gas stream as
it leaves the gas production area is given in Table 4-1.
4.1.4 Tarry Gas Liquor
Water condensed from the crude gas in the shift conversion and
gas cooling areas plus recycle water from the gas liquor separation area
- 29 -
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is sent back to the gas production area for use in the wash cooler.
This water stream, along with the tar, tar oil and crude phenols condensed
from the gases during cooling comprise the tarry gas liquor stream.
Approximately 94.3% of the tar, 44% of the tar oil and 3.3% of the crude
phenols produced in the gasifier are contained in this stream.
After leaving the gasifier area, the stream is subsequently
processed for removal of the various by-product constituents. The flow
rates of the major components of the stream (excluding trace elements)
are given in Table 4-1. A total flow rate for water, which is the
largest constituent, was not available.
Besides the major components, varying amounts of CC^, H2S and
HCN plus coal dust and ash will also be contained in these streams. No
data was available to allow an estimate of these constituents.
The composition of the tar and tar oil from the gasifier for
the El Paso case is not known. However, various operations at the
Westfield test center in Westfield, Scotland using a Lurgi gasifier
generated some data in this area. The exact composition of the tar and
tar oil will change from coal to coal and is dependent on operating
conditions. Two analyses are given in Tables 8-2 and 8-3, Chaper 8.
The expected sulfur content of the tar and tar oil for the El
Paso design are as follows:
Wt. % Sulfur Pounds per Hour Sulfur
Tar 0.515 339.1
Tar Oil 0.99 118.7
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4.1.5 Ash
Ash produced in the gasifier is discharged through the bottom
of the gasifier via a revolving grate. This 500°F ash falls into a
pressurized ash lock. The lock dumps approximately every 20 minutes
into an ash quench system where a mixture of water streams from the
plant are added. The wet ash and excess water are transferred in a
sluiceway to wet ash dewatering and handling.
During the quenching process a large amount of steam containing
ash dust and clinkers is produced. This mixture is first sent to a wet
cyclone for removal of clinkers and then to a condenser for condensing
the steam and removing fine ash particles. Along with the steam, some
amount of non-condensable gases may be formed due to organic materials in
the quench water and unreacted carbon in the ash. The quantity and
composition of this gas stream is not known, but it will be discharged
from the gasifier.
The major quenched ash components are listed in Table 4-4.
Table 4-4. QUENCHED ASH STREAM
Rate
Component (Pounds per Hour)
Water 422,950
Unreacted Coal 19,639
Ash 373,220
TOTAL 815,809
In order that individual components may be followed, a total
stream analysis is given in Table 4-5.
- 31 -
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Table 4-5. ASH STREAM COMPONENT ANALYSIS
Rate
Unreacted Coal Analysis (Pounds per Hour)
Carbon 14,976
Hydrogen 1,095
Nitrogen 259
Sulfur 210
Oxygen 3,091
Dry Ash Analysis
Si02 231,396
93,305
18,662
CaO ' 14,556
MgO 3,359
K20 2,985
Na20 5,598
Ti02 3,359
A breakdown of the quench water streams is given in Table 4-6.
Table 4-6. ASH QUENCH WATER
Rate
Source (Pounds Per Hour)
Slowdown 110,338
C-T Slowdown 135,508
Contaminated gas liquor 135,508
Process condensate 413
Utility Water 41,183
TOTAL 422,950
- 32 -
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4.1.6 Trace Elements
Trace elements in the gasification system represent only a
small percentage of the total feed. However, during the year approximately
3.3 million pounds of these elements are introduced into and come out of
the gasification plant. The distribution of these elements must be
known so the environmental impact of their disposal can be accurately
assessed and containment methods can be devised if necessary.
Unfortunately, few quantitative analyses have been made of the
fate of these elements in gasification plants. Various attempts have
been made to follow these materials through the system. A recent
effort ' at the Pittsburg Energy Research Center involved a trace
element balance around the Synthane PDU. The results indicate a general
pattern for distribution and also emphasize the problem of following
these small quantities of materials. Percent recoveries ranged from
17.2% to 1,103.7%.
Other Studies^ ^ ' have also been conducted which were only
qualitative in nature. The El Paso EIS does not address the trace
element problem. However, WESCO did attempt to quantify distribution
within their system. An existing NASA computer program was used to
evaluate volatilities, kinetics and chemical interchange of the trace
elements and 200 different oxides, sulfides, hydrides, fluorides and
carbonates formed by the trace elements. The results of this effort are
also qualitative in nature, but are shown in Table 4-7.
- 33 -
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Table 4-7. TRACE ELEMENT DISPOSITION^
1800°F 650°F 45°F -50°F
Vapor Condensed Vapor Condensed Vapor Condensed Vapor.. Condensed
Hg
Sb
Se
Te
Cd
Pb
F
Major Ash
Components
plus Be and
As (estimate
4.9 ppm)
Hg Pb (PbS) Hg
•
Sb F Te
Se (6.7%)
Te
Cd
Cd Hg(8.6%)
Se
Sb
Te(93.3%)
Hg(91.4)
Te(6.7)
The Sasol complex in South Africa is currently operating Lurgi
gasifiers to produce town gas. Operating data on trace element distri-
bution has been made available. Although the coal and operating conditions
differ, this data can be used to estimate the distribution of elements
for the El Paso complex. Comparing these estimates with results of the
studies previously mentioned, indicate that all the results fall into a
general pattern. Tables 4-8 through 4-11 are estimates of the trace
element distributions in the gasifier area.
No breakdown was given for the crude gas. While there will be
some trace elements in the gas, they will ultimately be collected in the
tarry gas liquor stream.
- 34 -
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Table 4-8. TRACE ELEMENT DISTRIBUTION - GASIFIER ASH
Element
Antimony
Arsenic
Boron
Bromine
Cadmium
Fluorine
Lead
Mercury
Nickel
Zinc
Maximum
Rate (Lb/Hr)
0.75
1.01
172.50
2.44
.26
546.0
4.68
.191
37.33
33.75
Table 4-9. TRACE ELEMENTS - TARRY GAS LIQUOR (WATER)
Element
Antimony
Arsenic
Boron
Bromine
Cadmium
Fluorine
Lead
Mercury
Nickel
Maximum
Rate (Lb/Hr)
2
12
20
428
,675
.49
,18
03
,225
,19
,1027
,1511
.153
- 35 -
-------
Table 4-10. TRACE ELEMENTS - TAR, TAR OIL
(Maximum Rates, Lbs/Hr)
Element
Antimony
Arsenic
Boron
Bromine
Cadmi urn
Fluorine
Lead
Mercury
Nickel
TAR
DISTRIBUTION
Gas
.0032
.047
.159
.0018
.00026
.044
.0123
.0017
.00064
Liquor
.053
.079
2.64
.029
.0042
.735
.204
.0287
.0106
TAR OIL
DISTRIBUTION
Gas
.0105
.0892
.0042
.0058
.0164
.00045
.0014
.0012
Liquor
.00825
.070
.0033
.00462
.0128
.00035
.00107
.0099
Element
Antimony
Arsenic
Boron
Bromine
Cadmium
Fluorine
Lead
Mercury
Nickel
Zinc
Table 4-11. TRACE ELEMENTS PERCENT BREAKDOWN
All Streams!6)
Ash% Tarry Gas Liquor%
50.0 45
27.0 66.5
92.0 6.5
10.86 89.0
52.0 45.0
56.0 43.917
93.6 2.054
50.93 40.30
99.554 0.41
100%
Tar%
3.
2.
1
,75
.25
.496
.14
.90
.08
4.33
8.12
.03
Tar Qi1%
1.25
4.25
.004
2.1
.003
.016
.65
.006
Note that bismuth, gallium, germanium and selenium are listed
as trace constituents in the coal. However, none of the reports referenced
addressed these elements and they are necessarily excluded for that
reason. The trace element values are based on the high range numbers in
Table 4-3.
- 36 -
-------
4.1.7 Lock Gas
The lock gases for both the coal lock and the ash lock are
discussed in Chapter 6.
4.2 POTENTIAL EFFLUENTS
4.2.1 Major Pollutants
The major process streams from this section are sent to downstream
processing; none are discharged to the environment at this point. There
are, however, various points within the area where the potential for
minor quantities of particulate or gaseous emissions exists. These four
points are the coal feed bin, the coal lock, the ash lock and the ash quench
system. The ash and coal lock discharges are discussed in Chapter 6.
Emissions from the coal bin will include coal dust and other
coal particulates caused by dumping the coal from the feed conveyor into
the feed bin. Dust could be a major local problem. Potential emissions from
the ash quench system will include fine ash particles, large clinkers, steam
and some non-condensable gases formed during the quenching process. Slowdown
from steam generating equipment associated with the gasifier will be dis-
charged into the plant water system.
Other possible contaminant sources are leaks around heat
exchangers, vessels and pumps. The composition and amount of effluents
emitted will vary from day to day and will be dependent upon the level
of plant maintenance. These items cannot be estimated at this time but
their possible presence should be taken into consideration.
4.2.2 Trace Constituents
No information is available on the distribution of trace
elements in the atmospheric discharge streams. The temperatures and
- 37 -
-------
pressures involved at the discharge points together with data from the
trace element studies would lead one to believe that little, if any,
trace elements would be contained in those streams.
4.3 CONTROL METHODS
4.3.1 Proven Methods
Control systems for the coal feed bin emissions were not
mentioned in the El Paso EIS. The WESCO EIS did state that dust hoods
coupled to baghouses would be used to control particulates emitted from
the coal transfer point. Estimated total particulates to the atmosphere
for this sytem are 0.97 Ib/hr.
Control of emissions for the ash quench system will involve a
two stage process. The steam, gases, ash dust and clinkers will initially
be passed through a wet cyclone for removal of the clinkers and some
dust. The remaining material will then go to a condenser where the
steam is condensed. Most of the ash dust will come out in the condensate.
The final fate of the non-condensable gases is not known, since no
information concerning their composition or volume is available.. Observations
made about the ash quench operation at the Sasol plant revealed that the
vapor gas generated during quench is mostly steam. No particulate
emission data for the system are available.
4.4 PROCESS MODIFICATIONS
There is no direct discharge to the environment from the
gasifier section which might suggest modifications to the actual process
equipment. The most effective form of emission reduction would involve
the improvement of "downstream" pollution control equipment. Controls on
the coal feed system may be warranted from the standpoint of worker health.
- 38 -
-------
REFERENCES
1. El Paso, "Draft Environmental Impact Statement," El Paso Coal
Gasification Project, July 1974.
2. WESCO, "Final Environmental Impact Statement - WESCO Coal Gasification
Project, 1975.
3. Exxon, "Evaluation of Pollution Control in Fossil Fuel Conversion
Processes, Gasification; Section I: Lurgi Process," EPA 650/2-74-009-C,
July 1974.
4. EPA, "Fate of Trace Constituents of Coal During Gasification,"
EPA 650/2-73-004, August 1974.
5. Pittsburgh Energy Research Center, "Trace Elements and Major Component
Balances Around the Synthane PDU Gasifier," EPA 600/2-76-149
June 1976.
6. EPA Communication.
- 39 -
-------
- 40 -
-------
5. FUEL GAS PRODUCTION
5.1 STREAM FLOWS
The fuel gas burned to provide steam, electric power, and air
compression for the plant is obtained from a process train consisting of
10 air blown Lurgi gasifiers. These units produce 2,800 MMBTU/HR of
fuel gas with a higher heating value of 193.9 BTU/SCF. The process
scheme for the fuel gas production area is shown in Figure 5-1.
The gasifiers operate similar to those described in Chapter 4
except for the use of air rather than oxygen.
5.1.1 Coal Feed
Sized coal from the coal blending and preparation area is fed
to the gasifier coal bunker at 415,587 pounds per hour. The breakdown
of this feed into major components is given in. Tables 5-1 and 5-2.
Table 5-1. MOISTURE AND ASH-FREE COAL COMPONENT ANALYSIS
Component Wt % Ib/hr
Carbon 76.26 204,417
Hydrogen 5.58 14,957
Nitrogen 1.32 3,538
Sulfur 1.07 2,868
Oxygen 15.74 42,193
Trace Compounds 0.03 80
TOTAL 100% 268,053
- 41 -
-------
-fs.
ro
SIZED COAL
LOCK FILLING GAS
BFW
COAL LOCK GAS
STEAM TO
GASIFIERS
TO ASH DISPOSAL
RECYCLE GAS
LIQUOR
5.6 >»-CRUDE FUEL GAS
TARRY GAS
'LIQUOR
WASH COOLER
PUMP
DRAWING NOTES
Figure 5-1. FLOW SCHEME FOR FUEL GAS PRODUCTION
-------
Table 5-2. MATERIAL BALANCE FOR FUEL GAS PRODUCTION
tream Number
Component
co2
c2H4
CO
H2
CH4
C2Hfi
N2 + Ar
°2
Total Dry Gas
Water
Coal (MAP)
Ash
Naphtha
Tar Oil
Tar
Crude Phenols
1 1 r i f\
3
TOTAL
5.1 5.2 5.3 5.4 5.5 5.6
Ihs/hr Ibs/hr Ibs/hr Ibs/hr Ibs/hr Ibs/hr
247,583
3,050
2,606
181,670
17,429
30,290
4,242
406,663 401,113
123,100
529,763 882,983
67,522 258,720 90,956 ++ 205,674
268,053 4,209
80,012 80,012
4,289
2,578 6,022
14,107 1,568
37 1,963
3,771
415,587 258,720 529,763 175,177 1,106,270
-------
Antimony
Arsenic
Bismuth
Boron
Bromine
Cadmium
Fluorine
Ga 1 1 i urn
Germanium
Lead
Mercury
Nickel
Selenium
Zinc
0.32
0.80
0.05
40.21
4.82
0.11
209.08
2.14
0.13
1.07
0.08
8.04
0.05
7.24
Table 5-3 is an estimate of flow rates for various trace
constituents in the coal feed.
Table 5-3. TRACE ELEMENTS
(Pounds per Hour)
Element From To
.08
.027
0.0
16.08
0.11
.05
53.61
0.13
0.27
0.37
0.54
0.80
0.27
0.29
5.1.1 Steam and Air
Steam to the gasifier comes from conventional steam generating
equipment plus steam produced in the gasifier cooling jacket. This
steam is fed to the gasifier at 550 psig and 750°F.
Air is dried and compressed to 360 psia before being supplied
to the gasifier at a rate of 529,763 pounds per hour.
5.1.3 Untreated Fuel Gas
The crude fuel gas is cooled and washed immediately following
its exit from the gasifier, and is then further cooled in a waste heat
boiler which produces 15 psig steam. After leaving the area, the gas is
subjected to additional cooling and then to treating for sulfur removal.
The composition of the fuel gas as it leaves the fuel gas production area
is estimated to be as shown in Table 5-2.
- 44 -
-------
5.1.4 Tarry Gas Liquor
Recycle gas liquor from the gas liquor separation plus the
tar, tar oils and phenols condensed from the gas in the wash cooler and
waste heat boiler comprise the tarry gas liquor stream. This stream is
sent to the gas liquor separation area for tar and tar oil removal.
Flow rates for the major components except water are given in Table 5-2.
Besides these major components, this stream will also contain
varying amounts of CCU, HUS, HCN, plus coal dust and ash. Not enough
data was available to estimate the amounts of these constituents. The
composition of the tar and tar oil from the fuel gas producer is not
known for the El Paso design. As with the tar products from the gasifier,
an estimate can be made using data from runs on Lurgi gasifiers at
Westfield, Scotland. These data are presented in Tables 8-3 and 8-4.
5.1.5 Ash
The ash discharge and quench system for the fuel gas producers
is the same as that for the high BTU gasifiers. Refer to Section 4.1.5
for discussion.
Flow rates and stream compositions of the ash from the fuel
gas producer are given in Table 5-2. A component breakdown for the unreacted
coal and ash is shown in Table 5-4.
- 45 -
-------
Table 5-4. ASH STREAM COMPONENT ANALYSIS
Unreacted Coal Analysis Rate Ib/Hr
Carbon 3210.0
Hydrogen 235.0
Nitrogen 55.5
Sulfur 45.0
Oxygen 662.0
Ash Analysis
Si02 49,607
A1203 20,003
Fe203 4,002
CaO 3,120
MgO 720
K20 640
Na20 1,200
Ti02 720
A breakdown of the ash water quench stream is given in Table
5-5.
Table 5-5. ASH WATER QUENCH STREAM
Source Rate Ib/hr
Blowdown 110,338
C-T Blowdown 135,508
Contaminated Gas Liquor 135,508
Process Condensate 413
Utility Water 41,183
TOTAL 422,950
- 46 -
-------
5.1.6 Trace Elements
The trace element background information contained in Chapter
4, is also applicable here. The trace element analysis for each stream
in the fuel gas section is given below.
Table 5-6. TRACE ELEMENTS - FUEL GAS PRODUCER ASH
(Pounds per Hour)
Elements
Maximum Rate
Table 5-7.
Element
Antimony
Arsenic
Boron
Bromine
Cadmium
Fluorine
Lead
Mercury
Nickel
Antimony
Arsenic
Boron
Bromine
Cadmium
Fluorine
Lead
Mercury
Nickel
Zinc
TRACE ELEMENTS -
(Maximum Rates,
Water
144
.532
2.61
4.28
.049
91.82
.022
.032
.032
.16
.216
36.99
.52
.057
117.08
1.00
.041
8.004
7.24
TARRY GAS LIQUOR (STREAM 5.5)
Pounds per Hour)
Tar
.0108
.0162
0.54
.0060
. 000891
.150
.042
.0058
.00217
Tar Oil
.0012
.0102
.00018
--
.000793
.00188
.00005
.00015
.000144
- 47 -
-------
Table 5-8. TRACE ELEMENTS - TAR, TAR OIL IN GAS STREAM (5.6)
(Maximum Rates, Pounds per Hour)
Element Tar Tar Oil
Antimony .0012 .0028
Arsenic .0018 .0238
Boron .060 .00112
Bromine .00067
Cadmium .000099 .0016
Fluorine .0167 .0044
Lead .0046 .00012
Mercury .00064 .00036
Nickel .00024 .00034
NOTE: The trace element values are based on the high range numbers,
Table 5-3.
5.1.7 Lock Gases
The lock gases for both the coal lock and the ash lock are
discussed in Chapter 6.
5.2 POTENTIAL EFFLUENTS
5.2.1 Major Pollutants
Pollution sources in this section include the coal bunker,
coal lock, ash lock and the ash quench system. All process streams and
major waste streams exit the area for further processing and separation.
None are discharged to the environment at this point. Emissions from
the coal and ash lock consist of residual pressurizing gas forced out by
the incoming coal and ash. These streams are estimated and discussed in
Chapter 6. Emissions from the coal bunker will be coal dust particles
generated by transfer of coal from the conveyor to the bin. The particle
size or concentration of dust in the air at that point is not known.
- 48 -
-------
The ash quench system generates large volumes of steam containing
fine ash particles, clinkers and non-condensable gases generated from
reactions involving organics contained in the water and unreacted coal
in the ash. The volume of steam, dust and clinker loading and non-
condensable gas composition and volume are not known.
5.2.2 Trace Constituents
No information is available on the trace constituents in these
vent streams.
5.3 CONTROL METHODS
5.3.1 Proven Methods
Control of the particulates from the coal transfer for the
WESCO case will be obtained by the use of dust collection hoods and
baghouses. No information concerning control methods was given for the
El Paso design, but it is assumed that the same type of control could
also be used here. Since baghouses are very efficient, the total particulates
emitted to the atmosphere at the exit of the baghouse is estimated to be
about 0.23 Ib/hr.
The steam-ash stream generated by the ash quench will initially
be routed to a wet cyclone for removal of the larger clinkers carried by
the stream. The remaining material will be sent to a cooling water
condenser where the steam will be condensed and returned to the ash
transfer sluiceway. It is expected that almost all of the fine ash
particles would remain in the condensate. The fate of the non-condensable
gases is not known. Recommendations for their disposal cannot be made
since information is not available on the composition or volume of this
stream.
- 49 -
-------
5.4 PROCESS MODIFICATIONS
No modifications are suggested from the standpoint of environmental
control. Hooded fans may be required at local points to avoid worker exposure
to gases and dusts.
- 50 -
-------
6. LOCK HOPPER GASES
6.1 STREAM FLOWS
In the Lurgi process, coal is fed to the gasifier in a cyclic opera-
tion using a pressurized hopper. The pressurizing gas must be vented each
time the feed lock hopper (FLH) is re-charged. Normal charging frequency
(2)
is 15 to 30 minutes. ' Ash is discharged from the bottom of the gasifier
through another lock hopper which must be vented. Ash hopper discharge
cycles are about 20 minutes.
Composition of the FLH pressurizing gas can be highly variable, depend-
ing upon the source utilized. In the El Paso design, crude gas is withdrawn
just before the final crude gas cooler and compressed directly into the FLH.
For the low BTU gasifiers, the FLH gas is withdrawn after the final fuel gas
cooler. The two FLH flow schemes are shown in Figure 6-1. ' Gas composi-
tions going to the FLH are given in Table 6-1. Flow rates are not given by
El Paso, but can be estimated as follows. Total coal feed to the high BTU
gasifiers is given as 1,938,480 Ib/hr. if it is assumed that the bulk
weight is appn
charging rate.
weight is approximately 60 Ib/ft , then 32,000 ft /hr is the volumetric
The lock hoppers probably cannot be filled completely. If 90% filling
is assumed, and 30% void volume in the coal, then the pressurant gas volume
3
will be 11,600 ft /hr at a pressure of 445 psia. With a molecular weight of
21, this results in a gas flow of approximately 20,000 Ib/hr for initial
charging of the hopper. Addition of gas during the run to replace the bulk
volume of coal-plus-gas entering the gasifier would require another 49,000
Ib/hr. The total of 69,000 Ib/hr represents 3 to 4% of the entire crude gas
make. This figure corresponds to that quoted in Ref. (2). Similarly, it
can be computed that the mass flow rate of FLH gas for the low BTU gasifiers
will be approximately 13,000 Ib/hr.
- 51 -
-------
.VENT
HIGH-BTU GASIFIER
TO METHANATION
LOW-BTU GASIFIER
FUEL GAS
TO INCINERATOR
DRAWING NOTES
Figure 6-1. FLOW SCHEME FOR THE FEED LOCK HOPPERS
-------
Table 6-1. COMPOSITIONS OF COAL FEED LOCK HOPPER PRESSURIZING GAS
Volume Percent, Dry Gas
Constituent
co2
H2S + COS
C?H4
CO
H2
CH4
C2H6
N2
A El Paso
B El Paso
C WESCO -
D WESCO -
E WESCO(3)
F NGPL(4)
A
28.03
0.37
0.40
20.20
38.95
11.13
0.61
0.31
- High BTU Gasifiers
- Low BTU Gasifiers^
Fluor Corp. design
Fluor Corp. design
BCD
14.83 28.90 48.88
0.24 .32 0.42
0.26
17.46 19.55 13.96
23.27 38.81 27.84
5.07 11.09 7.95
0.37 1.01 0.72
38.50 .32 0.23
(D
1)
E
77.53
0.76
0.29
14.06
2.01
4.6
0.47
0.28
F
95.42
0.78
0.41
0.39
1.85
1.15
- 53 -
-------
The original WESCO design estimated a crude gas composition given
in Column C, Table 6-1. Presumably this would provide the lock hopper
feed. However, the FLH vent gas composition was given as Column D. No
explanation was provided for the shift in concentrations. In the WESCO
environmental impact statement^ ' the pressurizing gas was changed to
CCL (source not given)and the vent gas composition given as Column E,
Table 6-1.
In the Natural Gas Pipeline.Co. designv ' FLH pressurizing gas is
obtained from the Rectisol plant vent stream. Composition of this gas
is listed in Column F, Table 6-1.
In summary, the composition of the coal FLH pressurizing gas can be
widely variable from one plant to the next, depending upon the plant
designer's choice of a source for the gas. Molecular weight could vary
from 21 to 44. Volumetric pressurant requirements will be unaffected by
changes in composition. Weight flow rates based on Columns A and B,
Table 6-1, are given in Table 6-2.
Flowrates in Table 6-2(A) are based on the assumption that gas is
continually added to the FLH during a run in order to maintain the
pressure slightly above that in the gasifier. This procedure is speci-
fied in the WESCO design. If, instead, the mode of operation is such
that no gas is added during a run, gases from the top of the gasifier
will back flow through the entering coal stream to fill the void being
created in the FLH. Material balances given for the cooling section in
the El Paso design indicate that this type of operation is planned. The
49,000 Ib/hr gas flow required to replace the coal bulk volume would
then not appear in stream 6.1, Figure 6-1, but would pass from the
gasifier directly to the FLH. For the present analysis it is assumed
that in passing countercurrently through the incoming coal these .gases
would be cooled by heat exchange with the coal, and that tars, oil and
water would condense on the coal. The composition of gas in the FLH
- 54 -
-------
Table 6-2. MATERIAL BALANCES FOR LOCK HOPPER GAS FLOWS
A. Gas Added During Run
STREAM NUMBER
COMPONENT
co2
H2S + COS
G2H4
CO
H2
CH4
C2H6
N2 + Ar
Naphtha
Water
TOTAL
B. No Gas Added
STREAM NUMBER
COMPONENT
co2
H2S + COS
C?H4
CO
H2
CH4
C2H6
N? + Ar
Naphtha
Water
6.1
LBS/HR
40,086
412
367
18,383
2,551
5,805
593
358
176
561
69,292
During Run
6.1
LBS/HR
11,423
116
104
5,240
111
1,653
168
102
171
296
6.2
LBS/HR
38,918
400
356
17,848
2,477
5,636
576
348
171
545
67,275
6.2
LBS/HR
38,918
400
356
17,848
2,477
5,636
576
348
171
545
6.3
LBS/HR
1,168
12
11
535
74
169
17
10
5
16
2,017
6.3
LBS/HR
1,168
12
11
535
74
169
17
10
5
16
6.4
LBS/HR
3,652
44
39
2,736
263
456
64
6,039
64
25
13,382
6.4
LBS/HR
1,080
13
12
809
77
135
19
1,786
19
7
6.5
LBS/HR
3,501
42
38
2,622
251
438
62
5,788
62
24
12,828
6.5
LBS/HR
3,501
42
38
2,622
251
438
52
5,788
62
24
6.6
LBS/HR
152
2
1
114
11
19
2
252
2
1
556
6.6
LBS/HR
152
2
1
114
11
19
2
252
2
1
TOTAL
20,000 67,275
2,017 3,960 12,828
556
- 55 -
-------
at the end of the coal feeding cycle would therefore be essentially the
same as before. Flow rates for streams 6.3 and 6.2, Figure 6-1, would
be unchanged. A similar situation would prevail for the low-BTU gasi-
fier FLH streams. Material balances for this type of lock hopper
operation are given in Table 6-2(B). The amount and composition of gas
vented from the system will be the same in either case, and only the
internal flow rate for pressurizing gas will be affected.
Ash is discharged from the bottom of the gasifier in a sequence of
operations similar to that for the FLH. First the top ash lock cone
valve is closed, isolating the ash lock chamber. High pressure gases in
the ash lock at this point are mainly steam. The chamber is vented to a
close coupled direct contact condenser, where the steam is condensed
with a water spray. The bottom ash lock valve is then opened and the
ash falls out. After the ash is dumped, both cone valves are closed and
the ash lock chamber is repressurized with steam. The top ash lock
valve is opened and ash flow from the producer is re-established.
As in the case of the coal feed lock hopper, it is possible that a
different operating procedure could be used, in which the ash lock
chamber is not repressurized before reopening the valve to the gasifier
vessel. In that case gases from the gasifier would flow into the ash
lock hopper. Venting of the ash hopper on the next cycle could then
result in the emission of some of these gasifier gases.
Several variations are possible in handling the ash as it drops
from the ash lock chamber. In one design, the ash drops into circulating
"mud water" in an ash quench chamber directly below the ash lock. In
the El Paso design the ash is apparently discharged dry at about 200° C
into a sluice launder where it is completely quenched and flushed away
by a water stream. Since the gasifier bottom temperature is around
500°C, it is assumed that partial cooling is accomplished by water spray
- 56 -
-------
before dropping into the sluice launder. Steam generated in the quench-
ing will be condensed either in the direct contact condenser coupled to
the ash lock valve or in a condensing vessel above the sluice launder.
To cool the ash from 500 to 200°C, assuming a specific heat of 0.2, would
require approximately 48,000 Ibs of water per hour.
During the ash quenching, large amounts of ash dust are generated
and entrained in the steam passing to the condensers. Some noncondensable
gases may be generated also by reaction between unburned char and steam
or by thermal cracking of organic contaminants in the quenching water.
The water spray in the condenser provides a wet scrubbing action to remove
most of the ash dust from the non-condensable gas which must be vented.
Estimated flow rate is 477,000 Ib/hr of ash. Approximately 64,000 Ib/hr
of water will be flashed to steam in the two-step quench process. No
information is available for estimating the amount of noncondensable gases
formed or the amount of particulates carried by this stream.
6.2 POTENTIAL EFFLUENTS
6.2.1 Major Pollutants
If all FLH pressurizing gases are vented to the atmosphere, then
Table 6-2, and Figure 6-1 may be used to calculate the potential emissions
of major pollutants. Since volumetric requirements are constant regardless
of composition, inspection of Table 6-1 shows that the use of crude gas
for FLH pressurizing (as in the El Paso design) represents a worst case
for potential emissions of carbon monoxide and methane. Hydrogen sulfide
emissions are worst in the WESCO design (gas source not defined in flow
sheet), and non-methane hydrocarbons are maximized in the NGPL design
(using Rectisol vent gases). Worst-case emissions for each component,
assuming the El Paso design but without recycling, are summarized in
Table 6-3.
- 57 -
-------
Table 6-3. WORST-CASE POTENTIAL EMISSIONS FROM FEED LOCK HOPPERS
Component
CO
CH4
NMH
Emissions,
Lbs/Day
11,000
509,000
152,000
40,800
Emissions,
Tons/Yr
2,000
92,900
27,700
7,450
Emissions,
Lbs/106 BTU Coal
0.022
1.0398
0.310
0.083
Table 6-4. FEED LOCK HOPPER EMISSIONS WITH GAS RECYCLE
Component
CO
CH4
NMH
Emissions,
Lb/Day
336
15,300
4,460
1,180
Emissions,
Tons/Yr
61
2,790
814
215
Emissions,
Lbs/106 BTU Coal'
0.001
0.031
0.009
0.002
- 58 -
-------
Uncontrolled sulfur emissions from venting all FLH gases are approxi-
mately 2000 tons per year. This is a factor of almost 100 more than some
estimates (p. 3-14, Ref. 9). Hydrocarbon emissions would also be about ten
times larger than estimated in Ref. 9. If the FLH gas is recycled, as in
the El Paso design, and only the residual gas remaining in the FLH is vented
to the atmosphere, then total emissions would be as given in Table 6-4.
These vents have not been shown on the El Paso flow sheets. Even with re-
cycling, the sulfur emissions would be over twice the value listed in Ref.
9. Venting of FLH gases will also be a major source of carbon monoxide
emissions, which were omitted from the Table 3-4 of Ref. 9. It should be
noted that even if C^ is used as the FLH gas source, blowback from the
gasifier after the hopper is emptied could result in appreciable emissions
when the hopper is vented.
Vent gases from the lock hopper will contain some entrained coal
dust. Without actual data from an operating gasifier it is impossible to
estimate the quantity involved. Amounts are likely to be a function of
whether the lock hopper is completely emptied during the charging cycle,
rate of depressurization, size distribution of coal feed, and geometric
arrangement of vent openings.
Noncondensable gases generated in the ash quench chamber will contain
ash dust. Quantities of gas and dust in this stream are unknown.
6.2.2 Trace Constituents
Trace constituents in the FLH vent gases should be the same as in the
source stream. No additional contaminants will result from the pressurizing
process, except for entrainment of coal dust.
- 59 -
-------
6.3 CONTROL METHODS
6.3.1 Proven
Since the major control methods for FLH vent gases consist of varia-
tions in process design which have not been tried, it is perhaps mislead-
ing to talk about proven methods. The discussion in this section, however,
will concern design variations which are believed to have no known tech-
nical problems. Several choices are available both for the source of the
pressurizing gas and for the disposition of the gas when venting the lock
hopper.
Among the choices which might be considered for a gas source are
(1) raw crude gas, (2) clean crude gas, (3) product gas, (4) Rectisol
vent gas, (5) nitrogen from air plant. Any of these sources could provide
sufficient quantities of gas chemically compatible with the coal in the
lock hopper. Use of nitrogen or incinerator tail gas can probably be dis-
qualified because it would introduce nitrogen into the product gas stream.
The use of any slip stream from the product gas flow, whether raw crude,
clean crude or final product gas, will result in some emission of this gas,
even if most of it is recycled. On the other hand, if C02 from the Rectisol
vent is used, this is a stream which is vented anyway, so total emissions
may not be changed appreciably. All process equipment between the gasifier
and the slip stream point must be oversized to handle the approximately 30%
of lock gas which will pass into the gasifier with the coal feed. Therefore
there is an economic incentive to locate the bleed point as close to the
gasifier as possible. If Rectisol vent gas is us.ed, then all equipment through
the C®2 absorbtion train must be oversized. Another economic factor is
that bleeding from a high pressure stream rather than a low pressure stream
will reduce compression costs.
In disposing of the FLH vent gases, at least four alternatives are
available: (1) Recycling, (2) Venting to atmosphere, (3) Use as plant
fuel gas, (4) Incineration. Not all disposal options could be combined
with every source option. For instance, if the source is C02 vent gas,
- 60 -
-------
it would obviously be impossible to dispose by burning as fuel. Figure
6-2 illustrates the various combinations of source and disposal alternatives
with a brief summary of strengths and weaknesses. Since there would be
relatively little difference between using final product gas or clean gas
prior to methanation, only "clean gas" is listed. The ultimate choice
must be based on considerations involving the rest of the plant design.
For instance, if gas is being burned as a plant fuel, then passing a slip-
stream through the lock hopper before burning will not increase overall
plant emissions. In this case, recycle compressors are not needed. If
fuel gas (either crude or cleaned) is chosen to pressurize the lock hopper,
there will be an economic incentive to recover the majority of the gas by
either recycling or using as fuel, so that direct venting is unlikely. If
C02 is used, then direct venting may be acceptable because this gas would
be vented anyway. In the El Paso design, Figure 6-1, the low-BTU lock
hopper vent gas is injected into the low pressure Stretford unit which
processes acid gas from the Rectisol unit. This automatically provides
a clean fuel to fire the off-gas incinerator.
Although most of the FLH gas can be collected and disposed of by one
of the options discussed, there will be a residuum of gas in the hopper
when it is opened to receive a new coal charge (the hopper cannot be evacu-
ated, it can only be bled down to some pressure slightly above atmospheric).
During the coal transfer this residual gas will be displaced equal to the
volume of coal being loaded. Several plant designs have discussed the use
of exhaust hoods and vent fans on the gasifier to prevent local escape
of these gases, as e.g. Figure 6-3. This type of control does not affect
the net release to the environment unless the collected gases are then
incinerated. The amount of gas escaping in this way should be only about
3% of the pressurant requirements. Flow rates are given as streams 6.3
and 6.6 in Figure 6-1 and Table 6-2. In the WESCO design it was stated
that these gases would be collected by exhaust fans and vented from
stacks, 150 to 300 ft. high. The flow would be 99.5% air at a rate of
2,934 tons/day. Estimated HLS concentration was 5-10 ppm. If either
clean crude gas or C02 from the Rectisol vent is used, the H2S level
- 61 -
-------
Figure 6-2 FEED LOCK HOPPER GAS ALTERNATIVES
Possible
Sources
Disposal Options
Crude gas
Clean gas
C02 vent gas
A
B
C
High
1 1 C 3 J U 1 L
Compressor
W
X
Recycle
Vent
Low
Combinations
AW
AX
AY
AZ
BW
BX
BY
BZ
cw
ex
CY
CZ
Compressor —
Z Fuel gas
Remarks
El Paso design - requires oversize gas coolers only
Greatest pollution plus economic penalty for loss
of gas
Less pollution but same economic penalty as AX
No oversize required, no pollution penalty if crude
is to be used as fuel anyway
Entire process train to bleed point must be oversized
Economically unsound because recycling should be
cheaper than increasing output of entire plant
Even greater economic penalty than BX
Represents good control where product gas is used
as fuel
Increase equipment size with no benefit over CX -
does not change total vent flow
Since gas will be vented whether used for lock hopper
or not, have not increased pollution load
Not reasonable
Not practical
- 62 -
-------
ASH
ZONE
THE LURGI GASIFIER
FEED COAL
-COAL
BUNKER
TO EXHAUST FAN
SCRUBBING COOLER
COAL 5
I DISTRIBUTOR!
STEAM •!• OXYGEN
INLET
WATER JACKET
ASH OUENCH WATER
ASH
OUENCH
CHAMBER
1
ASH
Figure 6-3 GASIFIER SCHEMATIC WITH EXHAUST FAN
- 63 -
-------
should be much lower. There may be some blowback of gas from the gasi-
fier into the lock hopper during production, so that even if C02 is used
to pressurize, there may be some H~S in the vent stream. The amount of
any such blowback is impossible to estimate.
Localized control of vent gases from the ash lock quenching and ash
dumping operations can be accomplished also by hoods and exhaust fans. The
exhaust fans for both the coal lock and ash lock can be equipped with
wet cyclone scrubbers to reduce particulate concentration before being
vented from stacks. The WESCO EIS contained an estimate of particulate
emissions from the lock exhaust fans with cyclone scrubbers which amounted
to only 0.1 Ib/hr for the coal lock and 0.2 Ib/hr for the ash lock.
6.3.2 Potential
Potential methods are considered to be those requiring some process
development before they could be utilized in a plant design. Since ade-
quate control can be achieved with the best of the methods discussed, no
further development is required.
6.4 PROCESS MODIFICATIONS
Most of the control methods discussed are actually process modifi-
cations rather than end-of-pipe methods of treatment. Additional modifi-
cations which could be developed would include the feeding of the exhaust
vent streams to the intake air for air blown gasifiers, gas turbines,
or steam boilers. Since the potential emissions involved are so small
to begin with, there is little incentive to spend effort in investigating
such modifications.
It is apparent that total venting of lock hopper gases could be a
significant source of emissions if the gas is obtained from an internal
process stream. All designs utilizing such internal streams should re-
quire either recycling or routing to a pollution control unit.
- 64 -
-------
References
1. El Paso, "Second Supplement to Applicaton of El Paso Natural Gas Company
for a certificate of Public Convenience and Necessity," Docket
No. CP73-131, Federal Power Commission, October 1, 1973.
2. WESCO, "Amended Application for Certificate of Public Convenience and
Necessity," Docket No. CP73-211, Federal Power Commission, November 1973.
3. WESCO, "Final Environmental Statement - WESCO Coal Gasification Project-
1975.
4. NGPL, "Environmental Assessment of a Coal Gasification Complex in
Dunn County, North Dakota," September 1974.
5. Wyoming Coal Gas, "Applicant's Environmental Assessment for a Proposed
Coal Gasification Project, Campbell and Converse Counties, Wyoming,"
October 1974.
6. Exxon, "Evaluation of Pollution Control in Fossil Fuel Conversion
Processes, Gasification; Section I: Lurgi Process," EPA-650/2-74-009-C,
July 1974.
7. Booz-Allen, "Comparative Assessment of Coal Gasification Emission Control
Systems," EPA Contract No. 68-01-2942, October 1975.
8. Woodall-Duckham, "Trials of American Coals in a Lurgi Gasifier at
Westfield, Scotland," ERDA report FE-105, November 1974.
9. EPA, draft document, "An Investigation of the Best Systems of Emission
Reduction for Coal Gasification Plants".
- 65 -
-------
- 66 -
-------
7. SHIFT REACTION
The shift reaction section of the Lurgi high-Btu coal gasification process
is designed to adjust the H2/CO ratio of the synthesis gas to that required in
the methanation section. This is accomplished by the catalyzed reaction of
CO and H20 according to Equation 7-1.
CO + H20 ^ C02 + H2 + heat (7-1)
7.1 STREAM FLOWS
The process flow scheme and the material balance for the shift reaction
section are given in Figure 7-1 and Table 7-1, respectively. Raw gas from
the gas production section is split into two streams with approximately 55
percent being sent to the shift reaction section. This stream is cooled in a
waste heat boiler that generates 60 psig steam. The water condensed from the
raw gas is sent back to the gas production section for use as a raw gas
quench liquor.
After leaving the waste heat boiler, the raw gas undergoes the reaction
shown by equation 7-1 in two catalytic shift reactors. The hot exit gas
from each reactor is cross exchanged with the reactor inlet gas to maintain
the proper inlet temperature to each reactor. The shifted gas is then directed
to the gas cooling section for further processing.
7.2 POTENTIAL EFFLUENTS
The effluent streams from the shift reaction section include:
o Shifted gas
o Process Condensate
a Waste Heat Boiler Slowdown
o Spent Catalyst
9 Fugitive Emissions (equipment malfunctions)
- 67 -
-------
CRUDE GAS
00
I
60 PSIG
STEAM
*- SHIFTED GAS
CONDENSATE
SHIFT
REACTOR
DRAWING NOTES
1) 60 PSIG STEAM PRODUCED;
183,700 LB/HR
2) BOILER BLOWDOWN =
32.420 LB/HR
Figure 7-1. FLOW SCHEME FOR THE SHIFT REACTION SECTION
-------
Table 7-1. MATERIAL BALANCE FOR THE SHIFT REACTION SECTION
Stream Number
Stream Description
Gas Phase, Ib/hr
Component Molecular wt.
C02 44.010
CO 28.010
CHu 16.042
H2S 34.082
C2H4 28.052
C2H6 30.068
N2+Ar 35.000
H2 2.016
H20 18.016
Naphtha 78.108
Tar Oil 132.196
Tar 184.354
Phenol 94.108
NH3 ' 17.032
Total Gas, Lb/hr
Liquid Phase, Ib/hr
Component Molecular wt.
H20 18.016
Tar Oil 132.196
Tar 184.354
Phenol 94.108
Dissolved NH3 17.032
Dissolved C02 44.010
Dissolved H2S 34.082
Dissolved CO 28.010
Dissolved CH4 16.042
Total Liquid, Ib/hr
Temperature, °F
Pressure, psia
7.1
Crude Gas
From Gas
Production
729,158
334,465
105,537
7,403
6,710
10,788
6,486
46,401
762,763
10,939
15,314
3,999
4,991
9,640
2.054,594
_
-
-
-
-
-
-
-
-
_
370
450
7.2
Condensate
to Gasifier
Quench
-
-
-
-
-
-
-
-
-
-
-
-
-
-
_
251,013
*
*
*
*
8,613
123
28
5
259,782
358
446
7.3
Crude Gas
to Shift
Reactors
720,545
334,437
105,532
7,280
6,710
10,788
6,486
46,401
511,750
10,939
15,314
3,999
4,991
9,640
1,794,812
_
-
-
_
-
-
-
-
-
_
358
446
7.4
Shifted
Gas
1,096,707
95,029
105,532
7,280
6,710
10,788
6,486
63,632
357,765
10,939
15,314
3,999
4,991
9,640
1,794.812
_
-
-
_
-
-
-
-
-
_
550
400
present, but quantity unknown
- 69 -
-------
The major pollutants in each of these effluent streams are addressed in
Section 7.2.1 while the presence of trace constituents is discussed in
Section 7.2.2.
7.2.1 Major Pollutants
Shifted Gas. The shifted gas contains the same pollutants as the inlet
raw gas stream to the shift reaction section. These pollutants include:
» H2S, COS and organic sulfur compounds
Ml I
o NH3
• Tars
• Tar Oils
• Phenols
• Naphtha
The anticipated composition of the shifted gas is shown below.
Component Vo1% Component Vo1%
C02 28.3
CO -3.8
CH4 7.5
H2S + COS 0.2
CzHi, 0.3
C2H6 0.4
N2 + Ar 0.2
Process Condensate. The condensate from the waste heat boiler contains
dissolved C02, CHi», CO, H2S and H2. In addition, a portion of the heavy
hydrocarbons present in the inlet raw gas stream would probably be found in
this condensate, although these components are not shown in the material
balance given in Table 7-1.
H2
H20
Naphtha
Tar Oil
Tar
Phenol
NH3
35.8
22.5
0.1
0.1
<0.1
0.1
0.6
- 70 -
-------
Boiler Slowdown. The waste heat boiler in the shift reaction section
uses softened water for boiler feed. This inlet stream contains some dis-
solved solids, consisting mainly of Na , S0u=, Cl", COa and silicates. Only
very small amounts of Ca and Mg are present. To prevent scaling of the
boiler tubes, a portion of the boiler water is removed as blowdown. Since
the boiler operates at approximately seven cycles of concentration, this
blowdown stream contains seven times the inlet concentration of each ionic
species. Since no other pollutants are anticipated to be present in the
boiler blowdown stream, it is directed to the plant cooling system for use
as makeup water.
Fugitive Emissions. Fugitive emissions from the shift reaction section
arise from leaks around valves, flanges, connections, etc. No estimate of
the quantity of fugitive emissions can be made, although high pressures
like those found in this section tend to increase the severity of the fugitive
emission problem. Any of the materials present in the process streams found
in this section could be released as a fugitive emission.
7.2.2 Trace Constituents
The inlet gas stream to the shift reaction section may contain any of
the trace elements present in the coal feed to the gas production section.
As the gas is cooled in the shift reaction waste heat boiler, some of the
trace elements present in the gas may enter the process condensate stream.
Similarly, as the gas passes over the shift reactor catalyst, some of the
trace elements may become adsorbed/absorbed on the catalyst. Those trace
elements not entering the process condensate stream or adhering to the shift
reactor catalyst leave the shift reaction section in the gas sent to the
gas cooling section. Table 7-2 lists the trace elements found in the con-
densate streams from one commercial Lurgi coal gasification facility. A
- 71 -
-------
Table 7-2. TRACE ELEMENTS FOUND IN GAS LIQUORS
Element Concentration, ppm by wt.
Beryllium 0.03-0.06
Boron 3.3
Vanadium 0.3
Manganese 1.0-1.7
Nickel 0.3
Arsenic 1.7-2.3
Cadmium < 0.03
Antimony 0.1-0.17
Cerium < 0.1-0.17
Mercury < 0.03
Lead 0.3-0.6
Bromine 0.3
Fluorine 40
Chlorine 30
Source: Personal communication with EPA
- 72 -
-------
trace element balance for the El Paso coal feed was calculated and given
in Tables 4-9, 4-10, 4-11, 5-7 and 5-8.
In addition to the potential for trace elements being picked up by the
shift reactor catalyst, sulfur compounds and heavy hydrocarbons may also be
adsorbed/absorbed on the catalyst. At this time no information is available
as to the types or quantities of trace constituents which may be associated
with the spent catalyst.
7.3 CONTROL METHODS
7.3.1 Proven Methods
Shifted Gas. The shifted gas is further processed in other sections to
remove the tars, tar oils, phenols, ammonia and sulfur compounds present in
this stream. These processing areas provide adequate control for this
stream and are discussed in Sections 8 and 9.
Process Condensate. The process condensate stream is recycled to the
gas production section where it is combined with other condensate streams for
use as gasifier effluent quench liquor.
Boiler Slowdown. The blowdown stream from the waste heat boiler is
used as makeup water to the plant cooling system. Since the boiler is
operating at a relatively low number of cycles of concentration, the dis-
solved solids content of the blowdown stream is relatively low and does not
represent an environmental problem.
Spent Catalyst. The control methods for spent catalyst are not fully
developed at this time because of the lack of knowledge about their exact
makeup. If the catalyst does not have value sufficient to justify regenera-
tion, the most likely disposal method is as landfill. However, if the catalyst
is sufficiently toxic to warrant more elaborate treatment, some of the methods
employed for nuclear or hazardous solid waste disposal could be adopted.
- 73 -
-------
Fugitive Emissions. Fugitive air emissions are inevitable in any process
which contains fittings, valves, flanges, etc. The high pressures encountered
in the shift reaction section tend to increase the likelihood of having fugitive
emissions. While fugitive emissions cannot be completely eliminated, the
use of best available technology can help to minimize these emissions. Good
maintenance practices also help to minimize fugitive emissions.
7.3.2 Potential Methods
The control methods just discussed provide adequate control of the con-
taminants present in the effluents from the shift reaction section, although
many of the control methods are actually other processing areas of the plant.
Because of this consideration, effluent control alternatives are not discussed
in detail here, but reference is made to the process modification sections
of the appropriate other chapters of this report for detailed examination of
alternative controls.
7.4 PROCESS MODIFICATIONS
Potential process modifications to the shift reaction section are con-
strained by the requirements- of downstream processing units. It is thus difficult
to envision a process modification that would simultaneously fulfill the process
requirements and have a significant impact upon the process effluents. The
only change that would impact the effluent streams significantly would be a
change in the gas composition entering this section.
- 74 -
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8. GAS COOLING
The gas cooling section of the Lurgi coal gasification process takes shift
reactor effluent gas and crude gas from the gas production section and cools
them in separate but similar cooling trains. The system of coolers is designed
to recover a significant portion of the useful energy content of the gas streams.
8.1 STREAM FLOWS
The process flow scheme and the material balance for the gas cooling section
are given in Figure 8-1 and Table 8-1, respectively. The portion of the crude
gas from the gas production section that is not directed to the shift reaction
section is first cooled in a waste heat boiler that generates 60 psig steam.
The condensate from this waste heat boiler is recycled to the gas production
section for use as a raw gas quench liquor. The cooled crude gas then undergoes
further cooling in a waste heat boiler that produces 15 psig steam, an air
cooler and a trim (cooling water) cooler. Upstream of the trim cooler, a
portion of the cooled gas is withdrawn and sent to the ga.s production section
for use as coal lock pressurizing gas. Recompressed coal lock gas and expansion
gas from the gas purification section are introduced into the raw gas stream
after the slipstream draw-off point but prior to the trim cooler. The condensates,
or oily gas liquor, formed in the latter three coolers are combined and sent to
the by-product recovery section of the plant.
The shift reactor effluent gas is first cooled by exchange with high pressure
boiler feed water from the raw water treatment section. The shifted gas then
enters, in succession, a waste heat boiler that generates 15 psig steam, an air
cooler and a trim (cooling water) cooler. The condensates, or oily gas liquor,
formed in all of the above cooling operations are sent to the by-product recovery
section. The cooled, shifted gas is next compressed by a steam turbine-driven
compressor, combined with the cooled crude gas stream and then sent to the gas
purification section.
- 75 -
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COAL LOCK
PRESSURIZING GAS
COAL LOCK AND
EXPANSION GAS.
60 PSIQ
STM
CRUDE GAS
COND.
^J
cr>
SHIFTED
GAS
OILY GAS
LIQUOR
COOLED
GAS
CONVERTED GAS
COMPRESSOR
DRAWING NOTES
t) TOTAL COOLING WATER
HEAT DUTY . 128 X 106 BTU/HR
2) STEAM PRODUCTION
60 PSIG ' 200.640 LB/HR
15 PSIG • 276.430 LB/HR
3) TOTAL BOILER SLOWDOWN *
100.070 LB/HR
Figure 8-1. FLOW SCHEME FOR THE GAS COOLING SECTION
-------
Table 8-1. MATERIAL BALANCE FOR THE CAS COOLING SECTION
Stream Number
Stream Description
Gas Phase, Ib/hr
Component Molecular Wt ..
C02 44.010
CO . 28.010
C1U 16.042
II2S 34.082
C21U . 28.052
C2H6 30.068
N2-).-Ar . 35.000
II2 2.016
II20 18.016
Naphtha 78.108
Tar Oil 132.196
Tar ISA. 354
Phenol. 94,108
MH3 17.032
.Total Gas, Ib/hr
Liquid Phase, Ib/hr
Component Molecular Wt .
II20 18.016
Tar Oil 132.196
Tar ' 184.354
• Phenol 94. 108
Dissolved NII3 17.032
Dissolved C02 44.010
Dissolved 1I2S 34.082
Dissolved 112 2.016
Dissolved C1U 16.042
Dissolved CO 28.010
Total Liquid. Ib/hr
Temperature, °F
Pressure, psla
8 j
Shifted Gas
1,096,707
95,029
105,532
7,280
6,710
10,788
6,486
63,632
357,765
10,939
15,314
3,999
4,991
9,640
1,794,812
-
-
-
-
-
-
-
-
-
-
-
550
400
8.2
Crude Gas
604,345
277,212
87,471.
6,135
5,563
8,942
5,376
38,458
632,196
9,066
12,693
3,315
4,136
7,989
1,702,897
_
-
'
-
-
-
-
-
-
-
-
370
450
8.3
Coal Lock
Pressurizing
Gas
11,423
5,240
1,653
116
104
168
102
727
296
171
-
-
•
-
20,000
_
-
-
-
--
-
-
• -
-
-
-
180
432
8.4
Lock Gas
and Expansloi
Gas
56,494
22,430
12,602
400
934
1,512
456
3,167
545
171
-
-
-
-
98,711
-
-
-
-
-
-
-
-
-
-
-
80
432
8.5
Cooled Gas
To Gas
Purification
1,692,167
389,403
203,921
13,602
13,103
21,074
12,216
104,514
2,681
20,005
-
_
-
-
2,472,686
_
-
-
-
-
-
-
-
-
-
-
90
425
8.6
Condensate
To Gasifier
Quench
_
-
-
-
-
-
-
-
-
- -
-
-
-
-
-
324,059
-
-
-
-
8,802
97
-
5
28
332,991
344
446
8.7
Oily Gas
Liquor
_
-
-
-
-
-
-
-
-
-
'
-
-
-
-
663,470
28,007
7,314
9,127
17,629
45,154
-
'16
26
-
770,743
220
385
-------
8.2 POTENTIAL EFFLUENTS
The following sections discuss the potential effluents from the gas cool-
ing section of the Lurgi coal gasification process. The effluent streams in-
clude:
• Cooled Gas
• Recycle Process Condensate
t Oily Gas Liquor
• Coal Lock Pressurizing Gas
t Waste Heat Boiler Slowdown
• Fugitive Emissions
The major pollutants in each stream are addressed in Section 8.2.1, while the
presence of trace constituents is discussed in Section 8.2.2. For the purpose
of this study, trace constituents are assumed to be those components originally
entering the gas cooling section in trace quantities.
8.2.1 Major Pollutants
The major pollutants contained in the effluents from the gas cooling
section are necessarily restricted to the major pollutants contained in the
two major inlet gas streams to the section. These pollutants include:
• Tars
• Tar Oils
• Phenols
• Naphtha
• COS
• NH3
• C00
- 78 -
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The other major constituents of the inlet streams are considered to be desirable
compounds. The following sections discuss what is known about how these major
pollutants distribute themselves in the gas cooling section effluent streams.
Cooled Gas. The cooled gas stream leaving the gas cooling area contains
essentially all of the H2S, COS and naphtha contained in the influent streams
to that section. However, during the cooling processes the tars, tar oils,
phenols and ammonia present in the inlet streams are removed with the condensed
water. Therefore, negligible amounts of these heavier components are present in
the cooled gas stream. The anticipated composition of this stream is shown
below.
Component Vol % Component Vol %
C02 32.2 C2H6 0.6
CO 11.7 N2+Ar 0.3
CH, 10.7 H2 43.5
H2S + COS 0.3 H20 0.1
CzH^ 0.4 Naphtha 0.2
Process Condensate. The condensate from the first crude gas waste heat boiler
contains dissolved C02, CH&, CO and H2S. In addition, a portion of the heavy
hydrocarbons present in the crude gas stream would probably be found in this
condensate, although these components are not shown in the material balance
given in Table 8-1.
Oily Gas Liquor. The condensate streams produced in all of the gas cooling
operations, except for that stream generated in the first crude gas waste heat
boiler, are combined and directed to the plant by-product recovery section.
This condensate, or oily gas liquor, contains essentially all of the tars, tar
oils, phenols and ammonia originally present in the cooling section inlet gas.
Some C02, H2 and CH4 are also present in the oily gas liquor. The percent
composition of this liquid stream is shown below.
- 79 -
-------
Component
H20
C02
H2
CH,,
Wt %
86.0
5.9
< 0.1
< 0.1
Component
NH3
Tar Oil
Tar
Phenol
Wt %
2.3
3.6
1.0
1.2
Tables 8-2 through 8-4 give further details on the compounds that constitute
the tars, tar oils and phenols.
Table 8-2. TAR ANALYSIS
Distillation Range
Water .
0° to 21Q°C
210° to 230°C
230° to 270°C
270° to 300°C
300° to 330°C
Residue-Pitch
Distillation loss
Tar Acids
Free Carbon
Ash
Sulfur
Specific gravity at 15.5°C
(1)
Percent
2.1
1.1
1.2
11.1
7.2
27.7
48.8
0.8
100.0
1.126
(?-)
Percent
1.8
1.2
1.6
9.8
6.3
28.6
50.0
0.7
100.0
7.1%.
2.16%
0.16%
0.77%
1.124
Source: (1) Westfield
(2) Westfield
- 80 -
-------
Table 8-3. TAR OIL ANALYSIS
Distillation Range:
Percent
5
20
40
60
80
95
Tar Acids
Pyridine Bases
Sulfur
Naphthalene
Specific Gravity at 15.5°C
0)
°C
197.5
207.0
223.0
239.0
277.5
353.5
1.005
(2)
°C
182.5
189.5
211.0
235.0
274.0
350.0
16.5%
1.3%
0.29%
7.6%
0.975
Source: (1) Westfield
(2) Westfield
Table 8-4. COMPOSITION OF THE CRUDE PHENOLS
Component Wt %
Phenol 59.9
Cresols 20.6
Xylenols 7.6
Catechols 7.3
Resorcinols 4.6
100.0
Source: Private communication with EPA.
- 81 -
-------
Coal Lock Pressurizing Gas. The temperature of the inlet gas to the trim
cooler for the crude gas stream is estimated to be approximately 180°F. At
this temperature, only negligible amounts of tars, tar oils, phenols and ammonia
remain in the gas phase. Therefore, since the coal lock pressurizing gas is
withdrawn from this stream, it too has negligible quantities of these pollutants.
However, this stream does contain H2S, COS, and other organic sulfur compounds,
since these compounds are still present in the main crude gas stream. The
percentage composition of the coal lock pressurizing gas is shown below.
Component Vol % Component Vol %
C02 27.5 C2H6 0.6
CO 19.8 N2+Ar 0.3
CH, 10.9 H2 38.2
H2S + COS 0.4 H20 1.7
C2H4 0.4 ' Naphtha 0.2
Boiler Slowdown. The waste heat boilers utilized in the gas cooling
section use softened water for boiler feed. This:inlet stream contains some
dissolved solids, consisting mainly of Na , S04, Cl~, COa and silicates. Only
very small amounts of Ca and Mg are present. To prevent scaling of the
boiler tubes, a portion of the boiler water is removed as blowdown. Since the
boiler operates at approximately seven cycles of concentration, this blowdown
stream contains seven times the inlet concentration of each ionic species.
Since no other pollutants are anticipated to be present in the boiler blowdown
stream, it is directed to the plant cooling system for use as makeup water.
Fugitive Emissions. Fugitive emissions from the gas cooling section arise
from leaks around valves, flanges, connections, etc. No estimate of the quantity
of fugitive emissions can be made, although high pressures like those found in
this section tend to increase the severity of the fugitive emissions problem.
Any of the materials present in the process streams found in this section could
be released as a fugitive emission.
- 82 -
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8.2.2 Trace Constituents
The inlet gases to the gas cooling section may contain any of the trace
elements present in the coal feed to the gasification section (see Chapter 4).
Prediction of the fate of these trace elements is complicated by a lack of
knowledge regarding the chemical form in which they exist, i.e., as oxides,
hydrides, sulfides, etc. It is anticipated that as the gases are cooled,
certain trace elements will be removed from the gas phase. Some of the more
volatile trace elements such as mercury, bromine, chlorine, fluorine, selenium
and tellurium may be retained in the gas phase. Less volatile trace elements
might have a higher likelihood of being found in the condensates produced
during the cooling operations. Exact quantification of the trace element
distribution in the effluent streams from the gas cooling section cannot be
made at this time, however. Trace elements found in the condensate streams
from one commercial Lurgi coal gasification facility were given in Table 7-2,
Chapter 7. Trace element balances for the El Paso coal feed composition were
calculated and given in Tables 4-9, 4-10, and 4-11, Chapter 4, and Tables
5-7 and 5-8, Chapter 5.
8.3 CONTROL METHODS
The gas cooling section does not discharge any effluent stream, with the
exception of fugitive emissions, directly to the environment. Instead, these
streams are directed to other processing areas for treatment or reuse. In
this section the destination of each process effluent from the gas cooling
section is identified.
8.3.1 Proven Methods
Cooled Gas. The main effluent gas stream from the gas cooling section is
sent to the gas purification section for removal of acid gases, naphtha and
v/ater. Since the rest of the major components of this stream are considered
- 83 -
-------
to be desirable gases, the gas purification section represents an adequate
control for the cooled gas stream.
Process Condensate. The condensate from the first crude gas waste heat
boiler is directed to the gas production section where it is combined with other
condensate streams for use as raw gas quench liquor.
Oily Gas Liquor. The contaminated condensates generated during the cooling
operations in this section (with the exception of the process condensate stream
discussed above) are sent directly to the by-product recovery section for removal
and recovery of tars, tar oils, phenols, ammonia and dissolved gases. These
treatment operations are discussed in detail in Section 11.
Coal Lock Pressurizing Gas- A slipstream from the crude gas cooling train
is used to pressurize the coal locks in the gas production area. Since this
stream contains sulfur compounds and naphtha, provisions must be made in the
gas production area to contain and recycle essentially all of the lock gas.
Section 6 discusses in detail the operation of the coal locks and the emissions
resulting from their use.
Boiler Slowdown . The blowdown streams from the waste heat boilers are
collected and used as makeup water to the plant cooling system. Since the
boilers are operating at a relatively low number of cycles of concentration,
the dissolved solids content of these blowdown streams is relatively low and
does not represent an environmental problem.
Fugitive Emissions. Fugitive air emissions are inevitable in any process
which contains fittings, valves, flanges, etc. The high pressures encountered
in the gas cooling section tend to increase the likelihood of having fugitive
emissions. While fugitive emissions cannot be completely eliminated, the use
of best-available technology such as mechanical seals on pumps can help to
minimize these emissions. Good maintenance practices also help to minimize
fugitive emissions.
- 84 -
-------
8.3.2 Potential Methods
The control methods just discussed provide adequate control of the contami-
nants present in the effluents from the gas cooling section, although many of the
control methods are actually other processing areas of the plant. Because of
this consideration, effluent control alternatives are not discussed in detail
here, but reference is made to the process modification sections of other
appropriate chapters of this report for detailed examination of alternative
controls.
8.4 PROCESS MODIFICATIONS
Potential process modifications to the gas cooling section are constrained
by the requirements of downstream processing units. It is thus difficult to
envision a process modification that would simultaneously fulfill the process
requirements and have a significant impact upon the process effluents. The
only change that would impact the effluent streams significantly would be a
change in the gas composition entering this section.
- 85 -
-------
- 86 -
-------
9. GAS PURIFICATION
In the gas purification section the Rectisol I process is used to remove
acid gases such as C02, H2S, COS, CS2, mercaptans, etc., from inlet gas streams by
physical absorption of these acid gases in a methanol solvent. Rectisol I,
which does not selectively absorb H2S from gases containing C02, is commercially
available and has been proven to be a reliable acid gas cleanup process.
As is the case with all acid gas cleanup processes based upon physical
absorption, the Rectisol I process operates more efficiently at high pressures
(up to 1000 psi). This effect is due to the fact that the solubility of the
acid gases in methanol increases with increasing pressure. Low temperatures
(<0°F) also increase the solubility of the acid gases in methanol.
The solubility coefficients of various gases in methanol as a function of
temperature are presented in Figure 9-1. These coefficients are a measure of
the ratio of the amount of gas found in the liquid phase to the amount of gas
found in the vapor phase at equilibrium and a gas partial pressure of 1 atm.
These coefficients generally increase with increasing partial pressure. The
influence of partial pressure, which becomes minimal at high temperatures, is
most significant when the dew point of the gas is approached. Figure 9-1
shows that the solubilities of the gases which are usually considered to be
impurities ( H2S, COS, and C02) increase with decreasing temperatures. It
should also be noted that the solubilities of gases which are normally con-
sidered to be valuable products (CO, CH,,, and H2) are not significantly affected
by temperature. This indicates that the Rectisol process is more efficiently
operated at low temperatures, a condition which also minimizes the solvent losses.
Disadvantages associated with the Rectisol process include: (a) the methanol
solvent retains heavy hydrocarbons (C3+) which must be removed; (b) since the
process operates at low temperatures (0°C), a significant refrigeration load is
required; and (c) there is a potential for high solvent losses due to the vola-
tili ty of methanol.
- 87 -
-------
10L
to
to
05
3
10
CL
(O
CL
TO2
c
OJ
•r- C
(j
M— i—
M- O
O) to
O
O **-
O
•I-J C
•,- o
3 S-
i— O
O J=
1/5 to
to
fO
cr>
_ TO1
10°
10"
o
to
l/l
s 10"
to
OJ
£ 10"
Naphtha
H2S
COS
C02
C2Hlt+C2H6
CH,
CO
Source:
-100 -90 -80 -70 -60 -50 -40 -30
Methanol Temperature (°F)
Figure 9-1. SOLUBILITY OF GASES IN METHANOL
Scholz, Walter H. Rectisol: A low-Temperature Scrubbing Process
for Gas Purification, Advan. Cryoq. Enq. 15, 406-14 (1974).
-------
9.1 STREAM FLOWS
The process flow scheme and the material balance for the Rectisol I acid
gas removal process are given in Figure 9-2 and Table 9-1, respectively.
The mixed gas from the gas cooling section is cooled by refrigeration to 32°F
before entering the prewash column. The column operates at the pressure of
the feed gas, approximately 425 psia. In the prewash column a stream of C02-
and H2S-rich methanol from the main absorber is used to remove water, naphtha
and residual heavy hydrocarbons and ammonia from the cooled product gas stream.
The prewashed gas leaving the top of the absorber is further cooled to about
-50°F before entering the main absorber.
The methanol from the prewash column enters the prewash flash tank where
most of the C02, H2, H2S, COS, organic sulfur, and lighter hydrocarbons are
flashed off. The flashed methanol is sent to the naphtha separator where water
is used to extract the methanol from the naphthas and any heavier hydrocarbons.
The naphtha is recovered as a by-product while the methanol/water mixture is
sent to the methanol/water still where the methanol and the gases in solution
are separated from the water by distillation. The water, or process conden-
sate, is sent to the plant water treatment system while the methanol vapor and
acid gases are fed to the hot regenerator.
The main absorber operates at 425 psia and -50°F. The prewashed gas
countercurrently contacts a pure methanol stream from the hot regenerator,
resulting in the removal of acid gas components including H2S, COS, C02, and
organic sulfur compounds. As mentioned earlier, a small slipstream from this
absorber is sent to the prewash column. The rich absorber effluent stream is
then sent to the flash regenerator.
In the flash regenerator column the solvent passes through a series of
pressure reduction stages. In the first stage the pressure is reduced enough
to flash off primarily the desired product gases, i.e., CO, \\z, and CH4. This
flash, or expansion gas, is recycled to the gas cooling section. In the follow-
ing stages the pressure is reduced to atmospheric or subatmospheric levels to
- 89 -
-------
LCAH H*6 -*-
COOLED
OA8
I I
REf
PRODUCT OAS EXPANSION OA8
NAPHTHA
8CPARATOR
? <0>-
C
FLASH
REOEH-
ERATOfl
Iff
UETHANOL
WATER
BTU.L
RICH H,3 OAS
6£
COOll«O
1_ WAIEB
HOT
REOEK-
ElIATOn
DRAWING NOTES
It STEAM
(100PSIG. SATI - 107 TONS/HR
(550 PSIQ. 750"F) = 113 TONS/MR
2) COOLING WATER =
422 X 106 BTU/HR
3) POWER- 9550 KW
(ABOVE UTILITIES INCLUDE
THOSE REQUIRED FOR
REFRIGERATION )
Figure 9-2. FLOW SCHEME FOR THE GAS PURIFICATION SECTION - RECTISOL I PROCESS
-------
Table 9-1. MATERIAL ISALANCE FOR THE CAS PURIFICATION SECTION - RECTISOL i PROCESS
Stream Ntnnlic r
Stream Description
fins I'liase, lb/hr
Component Molecular we.
CO? 44.010
II2S 34.082
CjlU 28.052
CO 28.010
ll: 2.0J6
CII,. 16. 04 2
C;. II r, 30.068
N2IAr 35.000
Methanol 32.042
Total Dry Cab, lb/hr
l.lqhld Phase, Ih/hr
Component Molecular we.
II20 18.016
tlnphtlia 78.108
Methanol 32.042
Total Liquid, lb/lir
Temperature, " F
Pressure, psla
9.1
Mixed fias
from
Can Cool Ing
1.692,167
13,602
13,103
389,403
104,514
203.921
21,074
12,216
~
2.450,000
2,681
20,005
~
22,686
35
426
9.2
Product
lias
110,337
-
10,135
383,101
103.515
193.766
16.743
12,107
—
829.704
•
_
-
-
-
-50
426
9.3
By-Product
Naphtha
_
-
-
-
-
-
-
-
•~
-
_
20,005
—
20.005
32
14.7
9.4
Lean II2 S
Acid C.is
1,530,329
9,417
2,390
1,720
310
3,189
3,392
.
—
1,550,747
_
-
—
-
-50
25
9.5
Rich II2S
Acid Ons
33,699
4,185
-
-
-
-
3
-
2.680
40.567
_
-
—
-
80
14. 7
9.6
Ex pun si on
C.aa
17,576
-
578
4,582
690
6.966
936
108
—
31,436
_
-
—
-
-50
103
9.7
Process
Condensate
_
-
-
-
-
-
-
-
—
-
102,681
-
—
102,681
150
14.7
9.8
Makeup
Mcthanol
_
-
-
-
-
-
-
-
—
-
_
-
2,680
2,680
80
14.7
9.9
Water to
Naphtha
Extractor
„.
-
-
-
_
-
-
-
—
-
100,000
-
-
100,000
165
14.7
-------
drive off the bulk of the C02 along with lesser amounts of H2S and COS.. These
gases are combined with the prewash flash gas to form a lean H2S gas stream
which is sent to the sulfur recovery section.
The flash-regenerated methanol stream is then pumped to the hot regenerator
where it is combined with the methanol/water still overhead product. In the
hot regenerator the sorbed acid gases are stripped from the methanol. The top
of this column is cooled using either cooling water or a refrigerant. A low
column overhead temperature is desirable here since this minimizes methanol
losses. The uncondensed gases, which are rich in H2S, are sent to the sulfur
recovery section. The regenerated methanol is cooled and returned to the main
absorber.
9.2 POTENTIAL EFFLUENTS
9.2.1 Major Pollutants
Lean H2S Flash Gas. The gas streams generated in the prewash flash and in
the main flash regenerators are comprised primarily of C02 (^98% by volume),
with smaller amounts of CO, H2, ChU, C2Hlf, C2H6, H2S, and COS. The amounts of
these compounds present depend upon the composition of the raw gas from the
gasifier and the operating parameters of the Rectisol I process such as absorber
temperature and pressure. The flash gas composition is shown below.
Component Vol % Component
C02 97.5 H2
H2S 0.8 CH,,
C2H4 0.2 C2H6
CO 0.2 N2+Ar
The presence of sulfur compounds necessitates further treatment of this
stream. The method of treatment depends upon several factors, including the
amounts and types of sulfur compounds present.
- 92 -
-------
Rich HaS Gas. The off-gases from the hot regenerator are comprised
primarily of C02, CO, H2, ChU, H2S, and COS. The concentration of H2S is
higher in this stream (M3% by volume) than in the flash gases. The concentra-
tions of the other components depend primarily upon operating parameters such
as the flash regeneration pressure. This stream may also contain substantial
amounts of methanol, depending upon the product gas (overhead) temperature and
the pressure of the hot regenerator. The effect of temperature and pressure on
the methanol concentration in the off-gas is shown in Figure 9-3. For example,
operating the hot regenerator with an overhead temperature of 1 atm and -40°F
would result in a methanol mole fraction in the off-gas of 0.001. Increasing
the overhead temperature to 100°F would result in a methanol mole fraction of
0.32. Increasing the regenerator pressure to 20 atmospheres would reduce the
methanol mole fraction in the off-gas to 0.00005 at -40°F and 0.0165 at 100°F.
A typical gas composition is shown below.
Component
C02
H2S
CO
Vol %
78.8
12.6
trace
trace
Component
H2
CH4
C2H6
N2+Ar
Methanol
Vol %
trace
trace
trace
trace
8.6
This gas stream is sent to the sulfur recovery section.
Expansion Gas. The gases released during the first stage of flash regenera-
tion are comprised of C02> CO, CH<,, C2HU, C2H6, H2, and some N2+Ar. The amount
of each component present depends upon the flash pressure and the concentration
of the component in the methanol stream fed to the flash regenerator. The
composition of this gas stream is shown below.
- 93 -
-------
1.0
en
to
GO
c
o
O
-------
Component Vol % Component Vol %
C02 31,1 H2 18.6
H2S trace CH4 33.4
C2H, 1.6 C2H6 2.4
CO 12.6 N2+Ar 0.3
Since this stream contains such high concentrations of desirable gases, it is
recombined with the cooling section product gas upstream of the acid gas
removal section.
Product Gas. The product gas exiting the Rectisol process is comprised of
CO, H2, CHu, C2Hi», C2H6 and, depending upon the required product specifications,
possibly small amounts of C02, H2S, COS and organic sulfur. The product gas
composition is shown below.
Component Vol %
C02 3.1
H2S trace
C2H, 0.5
CO 16.9
This gas stream is sent to the methanation section for conversion into sub-
stitute natural gas (SNG).
By-Product Naphtha. The by-product naphtha stream consists of C6-C3
(predominantly aromatic) hydrocarbons removed in the prewash. Some of the
expected compounds present in the by-product naphtha stream are listed below.
Component
H2
CH,
C2H6
. N2+Ar
Vol %
63.5
14.9
0.7
0.4
- 95 -
-------
Major Components (>10% each)
Paraffins and Olefins
Benzene
Toluene
Xylenes + Ethyl Benzene
Trimethyl Benzenes
Minor Components (<10% each)
Thiophenes
Styrene
Ethyl Toluene
Indane
Indene
Naphthalene
Benzofuran
Source: Private communications with EPA.
This stream, which may also contain small amounts of dissolved acid gases, ammonia,
and phenols, is sent to a by-product storage facility.
Process Condensate. The process condensate from the methanol/water still
is comprised primarily of the water in the feed gas and the water used in the
naphtha extraction operation. It may contain small amounts of phenol, cyanide,
ammonia, sulfides, and hydrocarbons such as naphthas and methanol. The process
condensate stream composition is given below.
Component
Phenol
Cyanide (as CN)
Ammonia (as N)
Sulfides (as S)
ppm (weight)
18
10.4 (includes thiocyanate)
42
trace
Source: Private communications with EPA.
This stream is sent to the wastewater treatment section.
Fugitive Emissions. Fugitive air emissions from the Rectisol I acid gas
removal process arise from leaks around pump seals, valves, flanges, etc.
High pressures like those encountered in this process enhance fugitive leaks
from equipment. The compositions of these fugitive emissions would be a
mixture of any of the various components found in the process streams.
- 96 -
-------
9.2.2 Trace Constituents
There is the possibility of trace element contamination of all the effluent
streams discussed in Section 9.2.1. Any of the trace elements found in the
coal feed to the gasifier may be present in the raw gas. However, during the
gas cooling operation many of the less volatile trace elements may be removed
from the gas stream. Trace elements which may be present in coal are shown
below.
Be
B
V
Mn
Ni
As
As
F
Cd
Sb
Ce
Hg
Pb
Br
Cl
Se
Te
The more volatile elements, including mercury, bromine, chlorine, fluorine,
selenium, and tellurium, may reach the gas purification area. The fate of these
trace elements is not known; however, they may be present to some extent in all
the effluent streams from this process.
9.3 CONTROL METHODS
9.3.1 Proven Methods
Stretford Process. The Stretford process is a proven, commercially available
process for the recovery of elemental sulfur from gas streams containing H2S. It
is capable of removing H2S to a level of 1 ppmv. This process does not remove
other acid gas components such as COS and CS2 in a regenerable manner. In order
to remove these compounds, they must first be converted to H2S by a catalytic
conversion process such as the Carpenter-Evans or Holmes-Maxted processes.
Claus Process. The Claus process is a commercially available process for
the recovery of sulfur from gas streams containing H2S. To be economically
feasible, this process requires a concentration of approximately 10 to 15% by
volume of H2S. The overall sulfur recovery efficiency of the Claus process is
- 97 -
-------
typically 95 percent, with some organic sulfur being formed and/or destroyed,
depending upon the system's operating conditions and the feed gas composition.
Wastewater Treatment. The process condensate stream can be treated to remove
dissolved organics and/or inorganics by any of several commercial processes.
Since the stream is directed to the wastewater treatment areas of the plant,
the available control methods will be discussed in Section 14.
9.3.2 Potential Control Methods
Potential methods are considered to be those requiring some process develop-
ment before they can be utilized in a plant design. Adequate control can be
achieved with the methods discussed, or with alternate methods discussed in
Section 9.4.
9.4 PROCESS MODIFICATIONS
9.4.1 Alternative Acid Gas Removal Processes
There are many commercially available acid gas removal processes which
can perform the same function as the Rectisol I process. Table 9-2 lists most
of these by type of process. Each of these processes has different advantages
and limitations which must be considered for each application.
9.4.2 Rectisol II
While the Rectisol I process can reduce the acid gas concentration of the
synthesis gas to the level dictated by the methanation operation, it may be
desirable to remove the sulfur compounds and C02 selectively to either increase
the percentage recovery of the sulfur compounds or to improve the economics of
the sulfur recovery operation. There are many processes which may be operated
selectively, including the Purisol, Selexol, and Rectisol II processes. The
latter, which is a modification of the Rectisol I process, is discussed
- 98 -
-------
TABLE 9-2. COMMERCIALLY AVAILABLE ACID GAS REMOVAL PROCESSES
Physical Solvent Processes
Rectisol
Pun'sol
Estasolvan
Fluor Solvent
Selexol
Chemical Solvent
MEA
DEA
MDEA
DIPA
DGA
Glycol - Amine
Benfield
Catacarb
Direct Conversion
Manchester
Perox
Fixed-Bed Adsorption
Haines
Molecular Sieve
Catalytic Conversion
Holmes-Maxted
Carpenter-Evans
Chemical/Physical Solvent
Ami sol
Sulfinol
- 99 -
-------
in the following paragraphs. A process flow sch.eme and a material balance for
a typical Rectisol II process are shown in Figure 9-4 and Table 9-3,
respectively.
The Rectisol II process is identical to the Rectisol I process with respect
to the prewash section. The major difference is in the main absorber. The
absorber used in the Rectisol II process is composed of three sections. In the
bottom section the prewashed gas is contacted with C02-rich methanol from the
upper sections, resulting in the removal of sulfur compounds such as H2S, COS
and C$2. The desulfurized gas then enters the second stage where it is contacted
with flash-regenerated methanol to achieve bulk C02 removal. The gas then enters
the third stage where it contacts hot regenerated methanol for final cleanup to
meet product gas specifications with respect to H2S and C02.
The third-stage methanol stream is combined with that from the second stage,
resulting in essentially a C02 saturated methanol stream. The majority of this
stream is sent to the bulk C02 flash regenerator with smaller streams feeding
the prewash column and the desulfurization section. In the bulk'C02 flash
regenerator most of the C02 is flashed off by pressure reduction. The resulting
C02-lean methanol stream is then recycled to the second stage of the main
absorber. The effluents from this process are discussed below.
Lean H2S Flash Gas. The gas streams generated in the prewash flash and in
the main flash regenerators are comprised primarily of C02 (^96% by volume),
with smaller amounts of CO, H2, ChU, C2H,4, C2H6, H2S, and COS. The amounts of
each of these compounds which are present depend upon the composition of the
raw gas from the gasifier and the operating parameters of the process such as
absorber temperature and pressure. The flash gas composition for this modifica-
tion is shown below.
Component Vol % Component Vol %
C02 96.5 CO 0.4
H2S + COS 1.3 H2 0.3
CH, 0.7
C2H, + C2H6 0.8 N2+Ar trace
- 100 -
-------
raiMAJII
flA9ll
'~D-
rn
"-"I
HCUOVkl
-*-l NAPtltMA I
T
~Q'
I OW blU
ClCAHi*1
"Ul«
t",
flASH
Q
11,9
n ASM
neocH
criATOR
p -
MAKEUP
METHAN-
9|0
DRAWING NOTES
11 STEAM (70 PSIG. SAT)
REQUIREMENT = SO TONS/HR
2) COOLING WATER = 733 X 106
BTU/lin
3) POWER = 25.000 KW
(ABOVE UTILITIES INCLUDE THOSE
REQUIRED FOR REFRIGERATION)
figure 9-4. FLOW SCHEME FOR THE GAS PURIFICATION SECTION - RECTISOL II PROCESS
-------
Table 9-3.
MATERIAL BALANCE FOR THE GAS PURIFICATION SECTION - RECTISOL II PROCESS
•Stream Number
Stream Description
Gas Phase, Ib/lir
Component Molecular wt.
C02 44.010
1I2S 34.082
C2IU, C21I6. 29.262
CO 28.0JO
H2 ' 2.016 .
C1U 16.042
N2+Ar 35.000
Hcthanol 32.042
Total Dry Oas, Ib/hr
Liquid Phase, Ib/hr
Component Molecular wt.
1I20 18.016
Naphtha 78.10.8
Methanol 32.042
Total Liquid, Ib/hr
Temperature, °F
Pressure, psla
9.1
Mixed Gas
from
Cas Cooling
1,692,167
13,602
3'' , 1.77
389,403
104,514
203,921
12,216
—
2,450,000
2,681
20,005
~
22,686
35
426
9.2
Product
Cas
_
-
20,055
384,061
104,132
196,503
12,159
~
716,910
_
-
—
_
-50
426
9.3
Bulk C02
Flash Vent
Stream
.-967,402
9,676
3,826
275
5,306
• 40
~
986,525
_
-
-
_
-50
14.7
9.4
Lean H2 S
Flash
Cas
583,839
5,932
3,391
1,321
75
1,452
320
~*
596,330
_
-
- .
_
-50
14.7
9 . 5
Rich H2S
Flash
Gas
75,064
10,523
114
1
-
4
-
6,086
91,792
_
-
-
—
80
14.7
9.6
Prewash
Flash
Cas
1,676
72
17
20
2
20
-
-
1,807
_
-
-
_
32
14.7
9.7
MeOH/H20
Still
Bottoms
_
-
-
-
-
-
-
-
_
128,460
-
-
128,460
150
14.7
'9.8
By-Product
-Naphtha
_
-
-
-
-
-
-
-
_
_
24,293
-
24,293
62
14.7
9.9
Water to
Naphtha,
Separator
_
-
-
-
-
-
-
-
_
124,106
-
-
124,106
165
14.7
9.10
Makeup
Methanol
_
-
-
-
-
-
-
—
_
_
-
6,086
6,086
80
14.7
o
ro
-------
The presence of sulfur compounds necessitates further treatment of this
stream. The method of treatment depends upon several factors, including the
amounts and types of sulfur compounds present.
Rich H2S Gas. The off-gases from the hot regenerator are comprised
primarily of C02, CO, H2, CH4, H2S, COS, and organic sulfur. The concentration
of H2S is higher in this stream (^14% by volume) than in the flash gases.
This stream may also contain substantial amounts of methanol, as discussed in
Section 9.2.1 under Rich HLS Gas for the Rectisol I process. The rich H^S gas
composition is shown below.
Component
C02
H2S + COS
Vol %
77.2
14.0
0.2
Component
CO
H2
CH.,
N2+Ar
Methanol
Bulk CQ2 Flash Gas. The gas stream from the bulk C02 flash regenerator
is comprised primarily of C02 with small amounts of H2, CO, and hydrocarbons.
There should be only trace amounts of sulfur compounds in this stream. A
typical bulk C02 flash gas composition for the Rectisol II process.is given
below.
Vol % Component Vol %
95.9 CO 0.6
trace H2 0.6
CH- 1.4
C2H6 '1.4 N2+Ar 0.1
Component
C02
H2S + COS
- 103 -
-------
Product Gas. The product gas exiting the Rectisol process is comprised of
CO, H2, ChU, C2HU, C2H6 and, depending upon the required product specifications,
possibly small amounts of C02, H2S, COS, and organic sulfur. A typical product
gas composition is shown below.
Component
C02
H2S
COS
Component
CO
H2
CH,
N,+Ar
By-Product Naphtha. The by-product naphtha stream consists of C5-C8
(primarily aromatic) hydrocarbons removed in the prewash. Some of the expected
compounds present in the by-product naphtha stream are listed below.
Major Components (>1..Q%. each)
Paraffins and Olefins'
Benzene
Toluene
Xylenes + Ethyl Benzene
Trimethyl Benzenes
Minor Components (<10% each)
Thiophenes
Styrene
Ethyl Toluene
Indane
Indene
Naphthalene
Benzofuran
Source: Private communications with EPA.
This stream, which may also contain small amounts of dissolved acid gases,
ammonia, and phenols, is sent to a by-product storage facility.
Process Condensate. The process condensate from the methanol/water still
is comprised primarily of the water in the feed gas and the water used in the
naphtha separation operation. It may contain small amounts of phenol, cyanide,
- 104 -
-------
ammonia, sulfides, and hydrocarbons such as naphtha and methanol. A typical
process condensate stream composition is given below.
Component ppm (weight)
Phenol 18
Cyanide (as CN) 10.4 (includes thiocyanate)
Ammonia (as N) 42
Sulfides (as S) trace
Source: Private communications with EPA.
This stream is sent to the wastewater treatment section.
Fugitive Emissions. Fugitive air emissions from the Rectisol II acid gas
removal process arise from leaks around pump seals, valves, flanges, etc. High
pressures like those encountered in this process enhance fugitive leaks from
equipment. The compositions of these fugitive emissions could be a mixture of
any of the various components found in the process streams.
Trace Constituents. There is the possibility of trace element contamina-
tion of all the effluent streams discussed in Section 9.4.2. Any of the
trace elements found in the coal feed to the gasifier may be present i: the
raw gas. However, during the gas cooling operation many of the less volatile
trace elements may be removed from the gas stream. Trace elements which may
be present in coal are shown below.
Be
B
V
Mn
Ni
As
As
F
Cd
Sb
Ce
Hg
Pb
Br
Cl
Se
Te
The more volatile elements, including mercury, bromine, chlorine, fluorine,
selenium, and tellurium, may reach the gas purification area. The fate of these
trace elements is not known; however, they may be present to some extent in all
of the effluent streams from this process.
- 105 -
-------
- 106 -
-------
10. METHAIiATION
In the methanation section low BTU synthesis gas is converted to methane
rich high BTU gas by the catalyzed reaction of CO, C02, and H« according to
equations 10-1 and 10-2.
CO + 3H2 »- CH4 + H20 + heat (10-1)
C02 + 4H2 - CH4 + 2H20 + heat (10-2)
Water produced in the methanation section is removed in two stages, con-
densation and absorption with glycol. The product gas formed will have a
heating value of about 980 BTU/scf and will be at a pressure suitable for
typical pipeline transport.
10.1 STREAM FLOWS
The process flow scheme for the methanation section is shown in Figures
10-1 and 10-2. The material balance for this area is given in Table 10-1.
Product gas from the gas purification section is heated by exchange with pre-
viously methanated gas and is fed to the recycle reactor. Here the gas, in
contact with pelletized nickel catalyst, undergoes the methanation reactions
shown by equations 10-1 and 10-2. The methanated gas is then cooled in a waste
heat boiler that will generate 600 psi steam. A portion of this gas is recycled
to provide an optimum feed gas temperature, and the rest is sent to a second
methanation reactor. This reactor is similar to the recycle reactor, and is
used to clean up any unreacted CO, C02 and H~.
Water from the methanation reaction is condensed and separated from the
gas stream in several stages. This water is sent to the water treatment
section and is eventually used as soft water within the plant. Cooled gas is
- 107 -
-------
CD
OO
FEED GAS
H.P BFW*
FEED
MEDIUM PRESSURE
WASTE HEAT BOILE
\ /
\/
RECYCLE
METHANATION
REACTOR
/\
/ \
,|^|
-^--I- ^-^
RECYCLE
COMPRESSOR
COND.
WET PRODUCT GAS
DRAWING NOTES
I) STEAM PRODUCTION
600 PSIG = 1,652,000 Ib./hr.
2) BOILER SLOWDOWN
16,500 Ib./hr.
Figure 10-1. FLOW SCHEME FOR THE METHANATION SECTION
-------
WET
PRODUCT GAS
WATER FROM
NG DRYING
FUEL GAS let STAGE 2nd STAGE
EXPANDER COMPRESSOR COMPRESSOR
EXPANDED
FUEL GAS
COMPRESSION
'CONDENSATE
TREATED
"FUEL GAS
DRAWING NOTES
Figure 10-2. FLOW SCHEME FOR THE COMPRESSION AND DEHYDRATION SECTION
-------
Table 10-1. MATERIAL BALANCE FOR THE METHANATION SECTION
Stream Number
Stream Description
Gas Phase, Ib/hr
Component Molecular Wt.
10.1
10.2
10.3
10.4
10.5
10:6
C02
*H2S
C2H,,
CO
H2
CHU
C2H6
N2+ Ar
H20
*C3H6
*C3H8
*Total S
*No + No2
*NH,
*HCN
*C1 •
*02
*CH3OH
TOTAL GAS, Ib/hr
44.010
34.082
28.052
28.010
2.016
16.042
30.068
35.000
18.015
42.081
44.097
32.064
46.005
17.031
27.026
35.453
31.998
32.042
Liquid Phase, Ib/hr
Component
C02
H2S
C,H,
cd*
H2
CH*
C2H6
N2 + Ar
H20
Glycol
TOTAL LIQUID, Ib/hr
Temperature, °F
Pressure, psia
Molecular Wt.
44.010
34.082
28.052
28.010
2.016
16.042
30.068
35.000
18.015
62.070
—
—
—
Feed Process
Gas Condensate
110,337
0.05
10,135
383,101
103,515
193,525
16,742
12,107
34
50
0.14
0.4
.0.6
2
0.06
<52
104
829,705
31
Wet
Product Compression
Gas Condensate
25,310
4
90
2,661
473,514
12,107
1,316
4
4
0.4
515,010
Water From Pipeline
SNG Drying SNG
25,310
4
90
2,661
473,514
12,107
66
4
4
513,760
—
-»~
—
-50
426
39
314,625
314,695
130
410
—
—
«
90
410
0.1
715
715
90
900
0.1
535
Trace
535
90
900
—
w
—
90
900
* Composition of trace components were estimated from reference (1).
- no -
-------
compressed in a two stage compressor driven by high pressure fuel gas. After
compression, the gas is cooled and the water which condenses is used as make-
up in the main cooling towers.
The final stage in the production of pipeline SNG, dehydration, is accom-
plished by contacting the cool .gas with lean glycol in a countercurrent absorber
to remove the final traces of water. Rich glycol from the bottom of the de-
hydrator is distilled to remove the absorbed water. The overhead vapor, con-
sisting of mostly water, is condensed and used as reflux. A side stream is
removed to maintain the water balance and is sent to the ash transfer system
for reuse. SNG from the dehydrator has a heating value of 980 BTU/scf and is
at a pressure of 900 psig, sufficient for pipeline transport.
10.2 POTENTIAL EFFLUENTS
The effluent streams from the methanation section include:
• Pipeline SNG
• Process Condensates
• Waste Heat Boiler Slowdown
t Spent Catalyst
• Fugitive Emissions (equipment malfunctions).
The major pollutants in each of these effluent streams are addressed in section
10.2.1 while the presence of trace constituents is discussed in Section 10.2.2.
10.2.1 Major Pollutants
Pipeline SNG. The synthetic gas feed has had all of the major pollutants
removed by the time it reaches the methanation section. All of the potential
pollutants which are present in trace amounts will be discussed in section
10.2.2.
- Ill -
-------
Process Condensates. The process condensates are made up of condensates
from methanation, compression, and dehydration. Of the three, the condensate
from the methanation step is by far the largest, having a flow of 629 gpm.
The major pollutants in this stream are CH^ and CO,,. The two other streams
having flows of about 1 gpm each, have only a small amount of CH,. However,
the condensate formed in dehydration could have some glycol as well, depending
upon the operating conditions within the glycol regenerator.
Boiler Slowdown. The waste heat boiler in the methanation section uses
softened water for boiler feed. This inlet stream contains some dissolved
solids, consisting mainly of Na , S0«~, ClI and silicates. Only very small
amounts of Ca and Mg are present. To prevent scaling of the boiler tubes,
a portion of the boiler water is removed as blowdown. Since the boiler operates
at approximately 100 cycles of concentration, this blowdown stream contains
100 times the inlet concentration of each ionic species. Since no other
pollutants are anticipated to be present in the boiler blowdown stream, it is
directed to the plant cooling system for use as makeup water.
Spent Catalyst. The pelletized nickel catalyst used in the methanation
reaction can be "poisoned" by various contaminants in the gas stream. The
expected life, however, is estimated to be from 2 to 5 year (1,2,3). When
the efficiency of a reactor is reduced sufficiently, the catalyst will have to
be shipped back to the supplier for regeneration. In this state, the catalyst
will contain potential pollutants such as sulfur, chlorine and various organic
compounds. The replacement of the catalyst could also generate a considerable
amount of metallic dust which could be a problem if worker exposure were high.
Also, during regeneration, impurities contained in the catalyst may be released
to the atmosphere at the supplier's plant. .It is difficult to determine the
- 112 -
-------
severity of this problem since the catalyst can absorb a variety of different
compounds and because the regeneration only occurs once every 2 to 5 years.
Fugitive Emissions. Fugitive emissions from the methanation section arise
from leaks around valves, flanges, connections, etc. No estimate of the quantity
of fugitive emissions can be made, although high pressures like those found in
this section tend to increase the severity of the fugitive emission problem.
Any of the materials present in the process streams found in this section could
be released as a fugitive emission.
10.2.2 Trace Constituents
The synthesis gas stream, after washing in a commercial Rectisol unit,
contains some hydrocarbons in the Co-C., range, traces of gaseous nitrogen
compounds (NO, NHL, HCN, CH-CN) and sulfur compounds (HLS, organic sulfur).
Some of these trace constituents are absorbed by the catalyst while others end
up in the product gas stream. Unsaturated hydrocarbons (ethylene, propylene)
are hydrogenated completely on the nickel catalyst and nitrogen oxides are
reduced. The conversion of cyanide, however, is incomplete. Table 10-1 shows
the estimated distribution of trace compounds within the methanation'section.
At temperatures below 300°F, reduced nickel may react with CO to form
nickel carbonyl, which is a highly toxic compound (4). Because of this, the
possibility of nickel carbonyl formation at start-up and shutdown is quite
high unless certain precautions are taken, flickel carbonyl has been found
in the product gas from the Westfield Lurgi Plant at times other than start up
and shutdown (5). Further investigation is required to determine mechanisms
of formation and control of this compound.
- 113 -
-------
10.3 CONTROL METHODS
Pipeline SNG. The major effluent from this area is the synthetic natural
gas which will be used in a variety of industrial and domestic uses. To re-
duce the formation of the highly toxic nickel carbonyl, the nickel catalyst
should not be allowed to contact CO at temperatures below 300°F. During shut-
down, vent gases, should be either recompressed for later use in the process,
or sent to the fuel burning section of the plant for use as fuel.
Process Condensates. The largest water stream leaving the methanation
section is the condensate from the methanation reaction itself. This stream
contains a total of 69 Ib/hr CH. and COp, and is sent to the water
treatment section where air is used to strip off the soluble gases in a packed
column. The clean water which results will be reused as soft water within
the plant. The condensate from the gas compression step and the water absorbed in
dehydration are sent to the main cooling tower and the ash transfer system,
respectively, for reuse.
Spent Catalyst. Catalyst dust can be controlled by dumping the catalyst
into water and using a bag filter at vent locations. In some catalyst systems,
it may be possible to regenerate catalyst without removing it from the reactor.
In that case, absorbed impurities will be released to the atmosphere. However,
the amount and frequency of these pollutants should be very small.
Fugitive Emissions. To minimize leakage, a tight system must be specified
and then maintained properly. Pump and compressor seals are potential sources
of leakage and need special attention to keep the leakage to a minimum.
- 114 -
-------
10.4 PROCESS MODIFICATIONS
Sulfur Guard. To safeguard against an upset in the Rectisol system,
resulting in excess sulfur going to the methanation catalyst, a sulfur guard
system may be required ahead of the methanation system. Typically, a tower
filled with zinc oxide is used for such an application. In this process, the
HpS concentration can be reduced to 0.1 ppmv by contacting the gas in a static
bed of ZnO to produce ZnS (6).
Charcoal Filter. At Westfield, nickel carbonyl was a problem. A charcoal
filter was used to remove it from the pipeline SNG. Depending on the operation,
a final filter may be required in the plants to be built in the USA.
- 115 -
-------
REFERENCES
Chapter 10
Moeller, F. W., Roberts, H. and Britz, B., "Methanation of Coal Gas for
SNG," Hydrocarbon Processing, April 1974, pp. 69-74 Moeller heads R/D
for Lurgi Mineralot Technik GMBH (W. Germany) Roberts and Britz are with
SASOL (South Africa) working on Fischer-Tropsch and Methanation.
Product Bulletin of "Catalysts and Chemicals International," Louisville,
Kentucky (No date).
Telecommunications with Mr. J. Richardson of Catalysts and Chemicals
International, October 7, 1976.
Technical Bulletin No. C13-035, Catalysts and Chemicals, Inc. Louisville,
Kentucky (No date).
Ricketts, T. S., "The Operation of the Westfield Lurgi Plant and the High
Pressure Grid System," Institute of Gas Engineers J. , October, 1963.
Nonbebel, G., "Gas Purification Processes," George Newnes Limited, London,
1964.
- 116 -
-------
11. GAS LIQUOR TREATMENT
The gases leaving the main Lurgi gasifier and the fuel gas gasifier are
laden with tars, tar oils and naphtha. These gases also contain phenols,
H?S, NH , chlorides,plus a large number of minor contaminants. By-product
streams generated from the treatment of these gases are produced at the rate
of about 100 tons/hour. Unless these chemicals can be treated or recovered
and subsequently utilized, a serious pollution problem can be created.
11.1 STREAM FLOWS
Figure 11-1 shows the distribution of the various by-products throughout
the plant. A sizable portion of these by-products are absorbed in or condense
out with the organic and aqueous condensates as the gases are first quenched
with water and then cooled. The heavier tars separate out first in the gasifier
waste heat boiler and are called "Tarry Gas Liquor". Further downstream, in
the gas cooling section, the tar oils with the remaining tars condense out
forming the "Oily Gas Liquor". In the acid gas removal step (Rectisol Process),
H?S and naphtha separate out. Naphtha is sent directly to the storage tank,
whereas H^S-containing acid gases are processed further to recover the sulfur.
A complete analysis of each by-product area will be presented. Gas liquor
separation, phenol extraction, and gas liquor stripping are discussed in the
following sections. Sulfur recovery will be analyzed separately in Chapter 12.
The process flow schemes for gas liquor separation, phenol extraction and gas
liquor stripping are given in Figures 11-2, 11-3, and 11-4 respectively. The
material balance for these three areas is presented in Table 11-1.
11.1.1 Gas Liquor Separation
Tarry gas liquor from the gas production section is first depressurized
in an expansion tank. The gas evolved from this tank contains mostly CO^, water
vapor and a small amount of hLS. This gas is scrubbed to remove any entrained
tar products and then sent to the sulfur recovery section for treatment. The
- 117 -
-------
TO METHANATION
VENT
DRAWING NOTES
Figure 11-1. BY-PRODUCT DISTRIBUTION
-------
COOLER
^ |\ TARRY GAS LIQUOR
COOLER
- J5AS LIQUOR
, TAR J-*-.
SEPARATOR! I
Figure 11-2. FLOW SCHEME FOR GAS LIQUOR SEPARATION
-------
FRESH SOLVENT MAKE-UP
>• I •<
CONTAMINATED
GAS
3
-N.
X
GAS LIQUOR
FILTERS
-*
EXTRACT
rii
r — — — I
\ /
\ /
/ \
L ..
GAS LIQUOR
FILTERS
^ f
1
^1
RAFF,NATE
EXTRACT
J-J
EXTRACTORS
._.-<-
• Im
cond
^
SOLVENT
RECOVERY
STRIPPER
SCRUBBING
PHENOL|
PUMP
RAFFINATE
PUMP
fcond
^-J *
SOLVENT
DISTILLATION
COLUMN
lXTURE PUMp
_^tts
DEPHENOLIZEO
CLEAN
GASLIOUOR
1
1 RAFFINATE
^PUMP
OEPHENOLIZED CONTAMINATED GAS LIQ.
CRUDE PHENOLS TO STORAGE
DRAWING NOTES
Figure 11-3. FLOW SCHEME FOR PHENOL EXTRACTION - PHENOSOLVAN PROCESS
-------
ACID GAS
REFLUX
DEACIDIFIER
DEPHENOLIZED
CLEAN GAS LIQUOR
->-
-------
ro
i
l.iivy
Sjj-i:am_ Description
Gas Phase, lh/hr
ComjipjieiH
Uater
Ta,-
Tar Oil
Recoverable Crude Phenol
Unrecoverable Phenol & Organic
Ammonia
II2S
CO.,
CO
Monohydric Phenols
Polyhydric Phenols
Other Organics
Contained Sulfur
Naphtha
Total Dry Gas, lh/hr
Liquid Phase, Ib/hr
Component
Water
far
Tar Oil
Recoverable Crude Piicnol
Unrecoverable Phenol & Organic
Ammonia
co2
CO
CII4
Monohydric Phenols
Polyhydric Phenols
Other Organics *
Contained Sulfur
Naphtha
ToUl Liquid. Ib/hr
277,150
TABLE 11-1. MATERIAL OALANCE EOR GAS LIQUOR TREATMENT
iii I »i..i:. LAii.in-.iini I'roi:!.-:.!, l.ir dub Cru.li; AciU C
165,000
79,901)
14, COO
210
130
—
300
17, i.'00
70
10
I.1UO.OOO
8,900
31 .000
11,100
1.100
21.600
300
54 ,800
--
__
1,31-1,800
••••> • i. A|*iut>iiMi i i t ft. i... j i «i i «iuj v.i u*iu ill. i u *' f i.:
-------
tar and gas liquor from the expansion tank are separated by gravity. The
heavy, viscous tars from the bottom of the separator are heated and sent to
storage. A portion of the lighter top layer containing tar oil, water and
some residual tar is sent to a second gravity separator, and the rest is
pumped back to the gasifier for quenching.
In the second separator, residual tar is withdrawn from the bottom, and
water and oil are collected separately off the top. The lighter oil layer
is withdrawn to storage, whereas the middle aqueous layer termed "Contaminated
Gas Liquor" is sent to the phenol extraction area. This stream contains a
large amount of organics and dissolved solids which cannot be separated easily.
The oily gas liquor is also flashed separately to remove acid gases.
These gases are combined with the vent gases from tar liquor flashing and are
treated similarly. Bottoms from the oily gas liquor flash are sent to a tar
oil separator. The lighter tar oil layer is withdrawn and sent to the storage
tank along with the tar oil from the tarry gas liquor. The heavier aqueous
layer, termed "Clean Gas Liquor" is sent to phenol extraction.
11.1.2 Phenol Extraction
Two parallel streams, the clean gas liquor and the contaminated gas
liquor are treated to remove various phenols and other organics in a proprietary
Lurgi process known as the Phenosolvan Process. Both streams are filtered in
gravel bed type filters to remove solids, free tar and oil, etc. No infor-
mation is available on the backwashing frequency of these filters. Filtered
liquor is passed through a series of countercurrent extractors using isopropyl
ether (IPE) as a solvent. Dephenolized clean gas liquor is sent to the ammonia
recovery section. Dephenolized contaminated gas liquor, which is very high in
dissolved solids is rejected and sent to the ash dewatering system for reuse.
The extract from both legs of the Phenosolvan process are combined and
distilled in two stages to separate the IPE from the phenol. IPE from the
top of the first distillation column is condensed and recycled to the extractor.
Additional IPE is added as required for makeup. The bottoms from the first
column are steam stripped in a second column to remove the last traces of IPE
from the crude phenol. The overhead vapors from this column are condensed and
- 123 -
-------
recycled to the first distination column. Crude phenol is pumped from the
bottom of the stripper to storage.
11.1.3 Ammonia Recovery
Dephenolized clean gas liquor from phenol extraction still contains
phenols, hLS, CCL and ammonia. The first step in the treatment of this liquor
is to selectively strip off the acid gases, H«S and CCL. This can be accomplished
because the ammonia is tied up with the phenol. The efficiency of this stripping
process is greatly dependent upon the solution pH. If the pH is around 5, almost
all the ammonia will be tied up as a salt and only acid gases will be stripped
off (3). The gases from this stripper are sent to sulfur recovery for treat-
ment.
The dilute ammonia liquor from this step is sent to a second stripping
column where the ammonia is stripped with steam at a higher temperature. The
overhead vapor, containing 25% ammonia is condensed and pumped to storage. The
effluent generated from the bottom of this column still contains small amounts
of phenols and organics, and is used as makeup in the main cooling tower.
11.2 POTENTIAL EFFLUENTS
The effluent streams from the gas liquor treatment section include:
• Gas liquor
• Expansion and acid gases
• Tar and tar oil
• Crude phenol
• Dephenolized contaminated gas liquor
• Aqueous ammonia
• Stripped ammonia solution
• Fugitive emissions (equipment malfunctions)
The major pollutants in each of these effleunt streams are addressed in section
11.2.1 while the presence of trace constituents is discussed in Section 11.2.2.
11.2.1 Major Pollutants
Gas Liquor. Gas liquors can contain virtually any contaminant encountered
within the by-product section. The major contaminants found in the aqueous
- 124 -
-------
layers of the tarry gas liquor and the oily gas liquor at the Westfield Works
are shown in Table 11-2.
TABLE 11-2. TYPICAL CONTAMINANTS FOUND IN THE
AQUEOUS LAYER AT THE WESTFIELD WORKS(5)
Tarry Gas Liquor (ppm) Oily Gas Liquor (ppm)
Sulfide as S .7
Thiosulfate as S203 9.0 15.8
Cyanide as CN 7.8 2.6
Ferrocyanide as FE (Cn)6 4.2 10.5
Chloride as Cl 4.3 11.3
Sulfate as S04 90.6 74.1
Suspended Solids 100 340
pH 9.4 8.0
Expansion and Acid Gases. All expansion gases from the tarry gas liquor
and oily gas liquor separators and the acid gases from the ammonia recovery
section contain HpS as the major contaminant. These gases also contain H^O,
CO, CH, and a large amount of COp. All expansion and acid gases are sent to
the sulfur recovery section for treatment.
Tar and Tar Oil. The major contaminants contained in the tar and tar oil
at the Westfield Works are described in detail in Table 11-3. Data from the
SASOL Plant(5) was also used to estimate the water and coal fines present in
tar and tar oil. They were estimated at 3% by weight for both the tar •
and tar oil. The SASOL information was adjusted for the El Paso coal com-
position and should be used for order of magnitude purposes only. Sulfur dis-
tribution between the tar and tar oil is shown in Table 11-1.
Estimates of the properties of tar and tar oil were given in Tables 8-2
and 8-3, Chapter 8. These tables give the physical properties, distillation
range and major components of tar and tar oil as recovered in the Westfield
plant. No information is available for the El Paso case, but it should be
similar to that given.
- 125 -
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TABLE H-3 ANALYSIS OF PHENOLS IN TAR LIQUOR
AND OIL LIQUOR
AT WESTFIELD WORKS
February, 1976
Phenols (total)
Monohydric Phenols
Phenol
0-Cresol
M-Cresol
P-Cresol
Total Xylenols
Monohydric Phenols as Percentage
of Total Phenols
CONCENTRATION, ppm
•
Tar Liquor Oil Liquor
3,570
1,843
1,260
155
170
160
100
5,100
4,560
3,100
343
422
302
393
52%
89%
Other Phenols
Catechol
3-Methyl Catechol
4-Methyl Catechol
3 : 5 Dimethyl Catechol
3 : 6 Dimethyl Catechol
Resorcinol
5-Methyl Resorcinol
4-Methyl Resorcinol
2 : 4 Dimethyl Resorcinol
555
394
385
trace
45
272
40
36
trace
190
80
110
trace
trace
176
64
—
trace
- 126 -
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Tar and tar oil contain a variety of components. These may be used as
fuels directly or after refining, reforming or cracking, etc. Similarly, crude
naphtha can be used directly as fuel or refined to produce other products such
as gasoline. In reprocessing and separating tar, tar oil and phenols into
usable components, a certain amount of spillage, leakage and vent losses may
occur. Secondary pollution generated from the utilization of these byproducts
is discussed in section 2.
Crude Phenol. There is much speculation on the distribution of various
phenols, i.e. monohydric (one-OH group) and polyhydric (more than one-OH group)
and steam volatile and nonvolatile, not to mention the specific phenols within
monohydric and polyhydric classifications. Some data from other plants is
available which gives some feel for this distribution. Table 11-3 is the data
taken from Westfield Works, Scotland and shows the distribution of phenols in
tarry liquor and oily liquor. Tar liquor contains an appreciable quantity of
phenols, which is not indicated in the El Paso document. Crude phenol contains
many of the same contaminants shown in this table and is sent to storage prior
to shipment.
Dephenolized Contaminated Gas Liquor. Table 11-4 gives data from the
SASOL plant in South Africa for the combined clean & contaminated gas liquor.
Apparently, SASOL does not distinguish between these two since all the liquor
is passed through the same extractors. The table gives some idea of the liquor
composition before and after the Phenosolvan process. The steam volatile
phenols are dramatically reduced from 4,000 ppm to 1 ppm. Unfortunately,
information is not given for all the components before and after the Phenosolvan
process. Contaminated gas liquor in the El Paso design is very high in dissolved
solids concentration and is therefore sent to the ash dewatering system.
Aqueous Ammonia. The aqueous ammonia stream, which is sent to storage,
contains 25% NH^, some C02 and a trace of hLS. This ammonia is suitable only
for fertilizer because it contains C02- For any other purpose, C0? will have
to be separated.
- 127 -
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TABLE 11-4
PHENOSOLVAN PLANT PERFORMANCE
SASOL FACILITY (5)
(For combined clean and contaminated gas liquor stream)
COMPONENT
Phenols
Sodium
Ammonia (Free)
Ammonia (Fixed)
Suspended Tar & Oil
CN
Total S
Fatty Acids as
C02
Concentration, ppm
COMPONENT
Phenols (Steam volatile)
Phenols (Bound)
Fatty Acids as Cyfy^
Ammonia as Nitrogen
Hydrogen Sulfide
CN
Fluoride
Chloride
Calcium (As Ca)
Iron (As Fe)
Orthophospate
Total Dissolved Solids
Suspended Solids
COD
PH
EFFLUENT •
Concentration, ppm
1
60-160
560
215
12
1
56 mg/1
25
18
1 mg/1
2.5
875
21
1,126
8.4
- 128 -
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Stripped Ammonia Solution. The clean water discharged from the bottom
of the ammonia stripping column contains 20 ppm of monohydric phenols, 760
ppm of polyhydric phenols and 2,700 ppm of other organics. This composition
was synthesized based on extraction efficiencies and phenols distribution as
suggested by Beychok (1). It is interesting to note however, that SASOL
reports that they can reduce the higher phenols down to 20 ppm (5). Therefore,
it is possible that the phenols and organic estimates are on the high side.
The clean water stream will also contain about 200 ppm of NH-, and the other salt
and metal contaminants which were discussed in the gas liquor section. The El Paso
design proposes to use this water for cooling tower makeup. In view of the
organic loading, it appears that the cooling water circuit may become fouled.
Fugitive Emissions. Fugitive emissions from the gas liquor treatment
section arise from leaks around valves, flanges, connections, etc. No estimate
of the quantity of fugitive emissions can be made, although high pressures tend
to increase the severity of the fugitive emission problem. Any of the materials
present in the process streams found in this section could be released as a
fugitive emission.
11.2.2 Trace Pollutants
The trace components found in coal that appear in relatively substantial
quantities in the gas liquor include fluorides, bromides, boron and arsenic.
Lesser quantities of heavy metals such as antimony, mercury, lead and cadmium
also are present (see Table 5-7 ancj 5-8). The estimated distribution of trace
metals in tar and tar oil based on data from the SASOL plant in South Africa
and adjusted for the El Paso design was given in Tables 4-9, 4-10 and 4-11.
11.3 CONTROL METHODS
Gas Liquor. Gas liquor is recycled to the gas production section where
it is used as quench liquor. Gas liquor is also recycled to the fuel gas
production section where it is used in a similar manner. These processing
areas provide adequate control for this stream and are discussed in sections
4 and 5.
- 129 -
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Expansion and Acid Gases. The expansion and acid gases generated in this
area are further processed in the sulfur recovery section to remove H2S. The
methods for controlling this and other similar streams are discussed in detail
in section 12.
By-Products. By-products such as tar, tar oil, crude phenol, aqueous
ammonia and naphtha are all pumped to storage, awaiting shipment and/or resale.
The effluents generated from the vents of each storage tank and any related
control methods are discussed in section 13.
Dephenolized Contaminated Gas Liquor. Contaminated gas liquor from the
Phenosolvan Process is very high in dissolved solids. For this reason, it is
sent to the ash dewatering system for reuse and eventual disposal. Control
methods related to this system are discussed in section 15.
Stripped Ammonia Solution. The clean water discharged from the bottom
of the ammonia stripping column is laden with phenols, organics and some
ammonia. In view of the organic loading, it appears that the cooling water
system may become fouled. Biological treatment of this stream may prove
necessary before it can be used as makeup in the cooling system. This possible
control method is discussed in detail under Process Modifications, section
11.4.
Fugitive Emissions. Fugitive air emissions are inevitable in any process
which contains fittings, valves, flanges, etc. The high pressures encountered
in certain areas of the gas liquor treatment section tend to increase the
likelihood of having fugitive emissions. While fugitive emissions cannot be
completely eliminated, the use of best available technology can help to minimize
these emissions. Good maintenance practices also help to minimize fugitive
emissions.
11.4 PROCESS MODIFICATIONS
Tar/Oil Separation. The recommended method of separation of tars and
oils from the aqueous gas liquors is by flash evaporation followed by API type
gravity separators. Under ideal conditions oil can be separated from an aqueous
stream to 50 ppm. Other methods of oil and tar separation include (7):
- 130 -
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Tar/Water
a. Fi'ltration
b. Sedimentation, filtration and flocculation
c. Centrifuge
Oil/Water
a. Air Flotation
b. Gravity separation plus air flotation
c. Filtration
d. Centrifuge
e. Filtration or centrifuge plus heat
Phenol Extraction. The El Paso design specifies the Phenosolvan Process
which is liquid exi.raction using isopropyl ether as the extracting agent.
Lurgi cl;
-------
this water composition at the SASOL plant and has been studying the operability
of a test cooling tower and heat exchanger for about one year (6). The results
of these tests are being used to study the characteristics of the El Paso
cooling water system, such as allowable cycles of concentration, foaming ten-
dency, slime build-up in tower, and heat transfer characteristics of the test
heat exchanger. Unless these tests prove otherwise, it is felt that biological
treatment is necessary before this water can be used in the cooling tower.
- 132 -
-------
REFERENCES
CHAPTER 11
1. Beychok, M. R., Coal Gasification and the Phenosolvan Process. ACS Div.
of Fuel Chemistry Symposium on Processing of Phenolic Aqueous Waste. -
September, 1974.
2. Lurgi Bulletin, Upgrading of Solid Fuels. 1972.
3. Beychok, M. W., Aqueous Hastes from Petroleum and Petrochemical Plants.
John Wiley and Sons (1967) pp. 177.
4. Serrurier, R., Prospects for Marketing Coal Gasification By-Products.
Hydrocarbon Processing, September, 1976.
5. Bertrand, R. R., Magee, E. M., (Exxon Research & Engineering Co.). Janes
T. K., Rhodes, W. S. (EPA), Trip Report: Four Commercial Gasification
Plants. November 6-18, 1974 - Unpublished.
6. Gibson, C. R., Hammons, G. A., and Cameron, D. S., Environmental Aspects
of El Paso's Burnham I Coal Gasification Complex. Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology (May, 1974, St. Louis,
Missouri), EPA 650-2/74-118, October, 1974.
7. Baum, J. S., Industrial Oily Waste Control. - Chapter 6, American Petro-
leum Institute.
- 133 -
-------
- 134 -
-------
12. SULFUR RECOVERY
Sulfur is the most important pollutant present in the coal. A large
number of processes have been developed over the years to deal with sulfur
pollution. Most of these processes were developed for the petroleum industry.
In the base case, only Rectisol followed by a Stretford process is considered.
The overall reaction for the Stretford process is as follows:
2H2S + 02 —- 2H20 + 2S
Figure 12-1 shows the typical distribution of sulfur in the production of
SNG and low BTU fuel gas. On a combined basis, 96% of the sulfur present in
the coal is recovered as by-product. About 2% of the sulfur is released to
the atmosphere, mostly as S02 and some as H^S. The rest of the sulfur appears
in by-products such as tar, tar oil, and naphtha (1).
12.1 STREAM FLOWS
Figure 12-2 is a simplified flow diagram showing various streams of the
Stretford process. Table 12-1 is the material balance for this process. The
rich FLS stream from the gas purification section along with the coal lock gas
from the fuel gasifier are treated with Stretford solution. This solution
consists of sodium carbonate, sodium meta vanadate, anthraquinone disulfonic
acid (ADA), citric acid and traces of chelated iron at a temperature of 80°F
and a pH of 8.5. In the rich HLS absorber, the H^S is oxidized by the vanadate
to form elemental sulfur. The vanadate, which is reduced by the H^S, is then
reoxidized by the ADA to the pentavalent state. The liquid containing ele-
mental sulfur passes to an oxidizer where ADA is reoxidized by air.
The elemental sulfur/air froth overflows to a holding tank/settler.
Reoxidized solution is recycled back to the absorber. Sulfur is recovered
from the sulfur froth by filtration, centrifugation, etc. The sulfur is
washed with water to remove solution. Finally, water is driven out in the
autoclave type melt storage tank where sulfur is stored for shipping. The
lean hLS gas stream along with the expansion gas stream from the tar/tar oil
separation, and the acid gas stream from the ammonia recovery section are
- 135 -
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Sulfur Balance for Manufacture
of Low BTU Fuel Gas
Sulfur W/Coal
2868 Ib/hr
Turbine Boiler Stacks
143 Ib/hr
Steam Superheater Stack
20 Ib/hr
Fuel Gas Heater Stack
4 Ib/hr
By Product Sulfur
2701 Ib/hr
NOTE: Emission Calculates as 0.1306 Lb. S02/MM BTU Fired
Sulfur Balance for Manufacture
of High BTU Gas
Sulfur W/Coal
13380 Ib/hr
Sulfur Plant Vent
108 Ib/hr
Sulfur Plant Incinerator
25 Ib/hr
By Product Sulfur
12894 Ib/hr
By Product Tar
240 Ib/hr
By Product Tar Oil
73 Ib/hr
By Product Naphtha
40. Ib/hr
Note: 1) Emission calculates as 0.00792 Ib/MM BTU of inlet coal.
2) Sulfur Plant vent is reduced sulfur with concentration
less than 100 pprav.
Figure 12-1. SULFUR DISTRIBUTION
- 136 -
-------
EXPANSION CAS
:iD GAS FROM GAS
LIQUOR STRIPPING
RICH SOLUTION FROM FUEL GAS TREATMENT
VENT
ABSORBER 8 OXIDIZER
^
<
1
<*
1
X
V
'•-
t
i
c
<
MAKEUP WATER^\
14,875 LBS/HR/ \
COOLER J \2 V ^^-^
)FF GA
'-y '
i
J—J
s
1
L
ro ATMOS.
i
^^ ^
i
INCINERATOR
FUEL GAS 8 AIR
-f
"• li
PUMPING TANK
u
OXIDIZER
SETTLER
V
PROCESS
QLOW
DOWN
-a
£-r"nr
LIQUID SULFUR
TO RAIL LOADING
LEAN SOLUTION TO FUEL GAS TREATMENT
SULFUR
STORAGE
PIT
SULFUR
TRANSFER
PUMP
DRAWING NOTES
Figure 12-2. FLOW SCHEME FOR SULFUR RECOVERY - STRETFORD PROCESS
-------
TA8LE 12-1. MATERIAL BALANCE TOR SULPUR RECOVERY
(Pounds Per Hour)
Stream Number l?.l 12.2 12.3 12.4 12.5 12.6 12.7 12.8 12.9 12.10 12.II
1
,
CO
00
1
Component
co2
H2S
COS
cs2
CO
"2
CM.
C2"4
C2H6
°2
M~
"z°
so2
N02
S
CILOII
TOTAL
59.656 8,573 1,530,329
.114 283 9,008
172
6
64 1 ,720
20 310
42 3,189
2,390
3,392
2.030 8,870
62.126 17.726 1.550.516
3,525
44'
2.641
253
440
39
60
5.824
12.826
33.698 1,598,558 42.912
4,185* 12
172
6
1,784
331
3,231
2,390
3 3,392
31.098 1.415 38,874
128.349 29,280 128.421
34.569 4.613 14,875 1,045
50
8
2,602 15,582
2,680
40,566 2,602 1,803.892 78.278 14.875 lf>8,340 15,582
* Combined IIZS, COS and CS2.
-------
sent to a parallel absorber called the lean HLS absorber. Again, the H^S is
converted to elemental sulfur as described above. Vent gases from this ab-
sorber are combined with vent gases from the oxidizer and released to the
atmosphere. Because of the presence of some hydrocarbons and other pollutants
it may be necessary to treat this stream.
Vent gases from the rich H2S absorber contain considerable H2S, COS and
other hydrocarbons. These gases are incinerated, converting hydrocarbons to
C02 and water, and the sulfur compounds to SCL.
There is no mention of a blowdown stream in the El Paso FPC document. A
fraction of the Stretford solution must be disposed of daily due to the
formation of the dissolved solids which can accumulate until they interfere
with the reaction. These solids are primarily sodium thiocyanate and sodium
thiosulfate.
After filtration, the sulfur cake is washed several times on the filter
drum to recover soluble reagents. Wash water can be used as a makeup water for the
solution. If more wash water is required than can be used for makeup, it is
concentrated and returned to the main circulation (2). The El Paso document
does not give details of the washing procedure.
12.2 POTENTIAL EFFLUENTS
Referring to Figure 12-2, primary effluents are the streams leaving the
Stretford process.
The vent stream (12.7) is a combined stream from the lean H-S absorber
and the oxidizer. Table 12-2 gives the concentration of this stream in ppmv.
There is an appreciable quantity of COS (67 ppm) as the Stretford process
does not remove COS. Also, there is some HLS and a trace of CSp. The total
hydrocarbons concentration is 9,400 ppmv, if CH, and C2Hg.are excluded, the
concentration is 2,000 ppmv, which seems quite excessive. Carbon monoxide
emissions are 1,500 ppmv. The hydrocarbons, CO and the COS are a source of
concern in this stream.
A fraction of the Stretford solution is taken out daily to keep the
dissolved solids at a low level. A typical Stretford solution purge contains
- 139 -
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TABLE 12-2. GASEOUS POLLUTANTS
Pollutant
NOX
so2
H2S
COS
cs2
Total Sulfur
CO
CH
C2H6
Total Hydrocarbons
Total Hydrocarbons
(Excluding CH,
& C2H6)
Stream (12.7)
C02 Vent.Gas
PPMv *
8.3
67
1.9
77
1,500
4,750
2,000
2,650
9,400
2,000
Rich H,S ABS.
off-gas
To Incinerator
PPMv *
610****
610
72,200
21,000
1,070
1,610 ***
23,700
1,070 ***
Stream (12.8)
Incinerator
Off Gas
PPMv *
70
350
350
Dry gas only.
Converted to volume basis as NOp from Ib./hr in El Paso Material Balance.
Does not include methanol losses from rectisol process.
**** Combined H2S, COS, and CS2-
*
**
***
- 140 -
-------
sodium salts of anthraquinone disulfonate, metavanadate, citrate, thiosulfate
and thiocyanate for which acceptable disposal must be found. The quantity
and the frequency of blowdown is not mentioned any place. Nor is there any
mention of the disposition and/or recovery of vanadium from that solution.
Rich HpS absorber off gases are sent to an incinerator to convert hydro-
carbons to C02 plus water, and sulfur compounds to SCL. The final vent stream
composition is given in Table 12-1 and Table 12-2. All the hydrocarbons are
burned completely. Because of dilution with flue gases, sulfur concentration
is reduced from 610 to 350 ppm as SOp.
At this time, no information is available about the disposal and/or re-
covery of the Stretford solution. This can also create a secondary pollution
problem. This may become more serious if a larger blowdown is required be-
cause of the presence of HCN. When this is the case, there are two methods of
operation. In one method, a continuous supply of fresh solution is added so
as not to exceed a solids concentration of 25%. In the other method, the
concentration is allowed to build to 40% and then the complete charge is
dumped.
Table 12-3 shows a breakdown of the major sources of sulfur and hydrocarbon
emissions. The total sulfur emissions, excluding boiler flue gases, are 130
Ib/hr. This represents 0.8% of the total sulfur contained in the coal fed to
the gasifier. It can be seen that the primary source of sulfur released is
the carbon dioxide vent stream from the Stretford unit.
Total hydrocarbons, excluding methane and ethane released to the atmosphere
amount to 2,390 Ibs/hr. The sole source of hydrocarbon emissions is the C0?
vent stream from the Stretford unit. Hydrocarbons (excluding methane and
ethane) released from this stream amount to 0.12 Ib per million BTU of coal
feed.
12.3 CONTROL METHODS
Vent gases from the Stretford process, particularly from the rich H?S
absorber, contain H^S, COS and hydrocarbons. The only proven method of hydro-
carbon removal is incineration which is very expensive. Another method may
be the adsorption of hydrocarbons, so that they can be concentrated and in-
cinerated with less fuel.
- 141 -
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TABLE 12-3. GASEOUS SULFUR AND HYDROCARBON EMISSIONS
C09 Vent Incinerator Vent
Stream (12.7) (12.8) Total
Sulfur
Ib/hr 105.6 25.0 130.6
Ibs/lbs in Coal .0065 .0015 .0080
Total Hydrocarbons
Ib/hr 9,013 0 9,013
Ib/MMBTU HHV Coal .44 0 .44
Hydrocarbon excluding
CH4 and CgHg
Ib/hr 2,390 0 2,390
Ib/MMBTU HHV Coal .12 0 .12
- 142 -
-------
Off-gas from the incinerator may require flue gas desulfurization, de-
pending on SOo level. Several processes are available for desulfurization
wherein the gases are passed through a venturi scrubber followed by a packed
column. Alkaline liquids or slurries such as ammonia or lime are circulated
to react with SCL, leaving relatively sulfur-free flue gases.
12.4 PROCESS MODIFICATIONS
12.4.1 Introduction
The El Paso design used a Rectisol I unit to produce two gas streams:
(1) A Lean H2S stream containing 0.75% (H2S + COS).
(2) A Rich H2S stream containing 13.8% (H2S + COS).
Carbon dioxide is the other primary constituent of these streams. The
lean H,,S stream contains about 9,000 Ibs/hr of H2S and the rich stream only
about 4,000 Ib/hr. Both of these streams are treated by the Stretford process
An alternative to the Stretford process is the Claus process, which can
be more economical if the H?S concentration is greater than 10%. The Claus
process has been used extensively in refineries, where the FLS concentration
is typically between 60% and 80%. It cannot be used in conjunction with
Rectisol I since only about 30% of the sulfur could be treated.
However, if the Rectisol I unit were replaced by a Rectisol II process,
the acid gases would be concentrated by removing about 57% of the total C02-
The rich HLS stream would then contain 10,500 Ib/hr of HLS and the lean FLS
stream 5,560 Ib/hr of H?S. The resulting concentration of the rich H?S
stream would then be 15% H2S and that of the lean H2S stream 1.3% H2S. With
this increase in the fraction of total HLS which appears in the rich H?S
stream, it becomes attractive to treat this stream in a Claus plant. However,
the lean H2S stream still must go to a Stretford plant. Depending on several
factors, a Claus plant can remove up to 96% of the incoming H?S. Therefore, a
tail gas treatment is required for the Claus off-gases to achieve higher re-
covery.
12.4.2 Tail Gas Treatment Classification
A large number of commercial processes are available to treat Claus unit
off-gases so that up to 99.9% sulfur recovery is effected. Also, there are
- 143 -
-------
several ways that these processes can be combined to obtain the desired re-
sults. There are two basic schemes of combing these treatments as shown in
Figures 12-3 and 12-4.
The major differences between Scheme I (Fig. 12-3) and Scheme II (Fig.
12-4) is the location of the incinerator. In Scheme I, all the tail gases
from the Claus unit and the Stretford unit are incinerated first and then
treated. In Scheme II, the tail gases are treated first and then incinerated.
Of course, several variations are possible within Schemes I and II. In either
of the schemes, Stretford off-gases can be vented directly to the atmosphere
if strict hydrocarbon and CO emission standards are not imposed, since the
Stretford process can easily reduce hLS to less than 10 ppmv. If hydrocarbons
and CO concentration limits are set low, incineration of the Stretford off-
gases will be required. Also, for some processes of Scheme II, vent gases
from the incinerator may require a scrubber to meet the regulations, whereas
in others, even an incinerator may not be required. Tail gas treatment may be
enough to meet the standards.
12.4.3 Process Selection
As mentioned earlier, a large number of processes are available for tail
gas treatment. All of them were developed for the petroleum industry, since
the Claus process has been used for over fifty years in this industry. Tables
12-4 and 12-5 give a list of such processes that fall in Scheme I and II
respectively. Also given are important characteristics of some of the pro-
cesses.
One of the main advantages of Scheme I processes is that they can take
care of all species of sulfur whether organic, inorganic or sulfur vapors by
incinerating them to SO^. This means that the tail gas treatment has to re-
move S02 only, as opposed to preincineration treatment where different tech-
niques are used to remove HLS, COS, CSp and sulfur vapors. Also, hydrocarbons
are taken care of by burning, and they do not interfere with any treatment
process. However, Scheme I has some serious drawbacks. Incineration is an
expensive process in terms of fuel cost, though a part of that can be recovered
in a waste heat boiler. The volume of gases after incineration increases tre-
- 144 -
-------
RICH H2S
-P.
en
LEAN H2S
GLAUS
SULFUR
STRETFORD
SULFUR
INCINERATOR
OR jVENT
i
VENT
SCRUBBER
SULFUR RECOVERY
OR DISPOSAL
Figure 12-3. SULFUR RECOVERY SCHEME I - CLAUS/STRETFORD/INCINERATION/SCRUBBER
-------
RICH H2S
CLAUS
SULFUR
LEAN H2S
STRETFORD
SULFUR
VENT
OR | VENT
TAIL GAS
TREATMENT
INCINERATOR
OR.VENT
(SCRUBBER REQUIRED
IN SOME CASES)
Figure 12-4. SULFUR RECOVERY SCHEME II - CLAUS/STRETFORD/TAIL GAS TREATMENT/INCINERATION
-------
TABLE 12-4. SCHEME I - TAIL GAS TREATMENT PROCESSES
Process
W-L S00
Licensor
Wellman-Power Gas, Inc.
IFP I
IFP II
Institut Francais
du Petrole
Application
Desulfurization of waste gas
stream to 100 ppmv of SO
Claus tail gas or stack gas
clean up to less than 500 ppmv
-p.
I
Chiyoda Chiyoda Chemical Co.
101 Yokohama, Japan
Desulfurization to 500 ppmv
Description
All Claus gas burned to SO^.
Absorbed in sodium sulfite to
form bisulfite. S0? regenerated
and sent back to Claus plant or
other uses.
IFP I: Claus tail gas is contacted
with a solvent containing catalyst
in a packed tower. Sulfur is formed
and removed from the bottom.
IFP II: Claus tail gas after in-
cineration is scrubbed with aqueous
ammonia and clean overhead is in-
cinerated and vented. Sulfur is
recovered from the ammonium sulfites
and bisulfites.
Three stages: (a) Incinerated gases
are absorbed in dilute sulfuric acid;
(b) H2S03 is oxidized to HpSO-, with
air; \c) acid is reacted witn lime-
stone to form gypsum crystals for use.
Reference (13)
-------
TABLE 12-5. SCHEME II - TAIL GAS TREATMENT PROCESSES
Process
SCOT
Beavon
Clean Air
Sulfreen
00
I
Licensor
Shell Development
Co., Houston, Tex.
Union Oil Co. of
California
J. F. Pritchard and
Co.
SNPA/Lurgi;
R. M. Parsons Co.
Application
Increases Claus recovery to
99.8%; S emission 200-300
ppmv
Clean Claus tail gas
Recovers 99.9% of S from
Claus tail gas leaving less
than 200 ppmv S02 equivalent
Increases Claus recovery to
99%
Description
Reduction of all S to H^S over
cobalt/molybdenum, on alumina
catalyst at 300° H2S absorbed in
an alkanolamine solution and re-
cycled to Claus. Off gas burned.
Reduction as in SCOT. All gases
taken to a Stretford process.
All forms of sulfur converted to
elemental sulfur in three stages.
First removes S0?, second COS and
the third CS2 i
An extension of Claus process. H~S
and SOp reacted below the dew point
in the presence of alumina or activated
charcoal. Equilibrium conversion is
more favorable as temperature is
lowered.
-------
mendously because a large quantity of fuel and air are used to raise the tem-
perature of gases above 1200°F to completely burn hydrocarbons and convert all
sulfur to S0?. This means that the treatment equipment after the incineration
is going to be very large compared to Scheme II processes. Also, the processes
for tail gas treatment are more complex in terms of recovery of elemental
sulfur. In some cases, a large volume of solid waste containing sulfur has to
be disposed of.
In general the Scheme II processes are preferable because of the much
smaller gas volume to be handled. In some cases, the final incinerator may not be
required because of low H-S emissions. In those cases, Scheme II processes
should be more economical because of incineration fuel savings. The Beavon
and SCOT processes are examples of this type of operation. In these processes,
all sulfur components of the Claus off-gases are reduced to H?S. In the Beavon
process a Stretford absorber follows the reducing reactor and removes H^S to
10 ppm. The SCOT process, on the other hand, concentrates the sulfur-bearing
components and returns them to the Claus process. The drawback of the Beacon
process is that COS and CS« are produced in equilibrium concentration and cannot
be removed by the Stretford unit. The SCOT process requires incineration of
the off-gases because of high H^S emission (3).
For this study, Scheme II with the Beavon process has been selected for
the following reasons:
(1) The Beavon process requires a Stretford plant as the second part
of its processing; however, since a Stretford plant already
exists for treatment of the lean H?S stream, the Beavon process
will fit nicely within this setup. Gases from the Beavon unit
will add about 15% more load on the Stretford plant. That probably
will not change equipment size significantly.
(2) It will not require an incinerator since a Stretford plant will
reduce H^S to less than 10 ppmv. If strict hydrocarbon emission
standards are adopted, an incinerator may be required for the
lean acid gas vent.
- 149 -
-------
(3) It requires only one reactor to reduce sulfur compounds to H2S.
(4) There are no waste streams generated, except for a small clean
water purge which can be used as part of the Stretford water
makeup.
(5) About 50 Ib/hr of hydrogen gas is required for reduction. In its
place other reducing gases can be used. A convenient source for
the El Paso case is the product gases just before methanation
which contain mostly H2> CO, and CH^.
Fig. 12-5, shows an overall schematic flow diagram of sulfur recovery
based on the Claus/Stretford/Beavon process. Table 12-6 is a material balance
for the Claus/Streford/Beavon process. The rich H2S gas stream from the
Rectisol II unit is sent to a by-pass type Claus plant along with a stiochio-
metric quantity of air to convert 1/3 of the total sulfur to SO^. Molten
sulfur is the product of the Claus plant. Vent gases from the Claus plant
are mixed with a reducing gas to convert all sulfur to hLS in a Beavon reactor.
Gases from this reactor are absorbed in a unit containing Stretford solution.
The lean H?S gas stream is sent to a Stretford plant, along with the acid
gas stream from ammonia recovery and expansion gas from tar/tar oil recovery.
To this a small fuel flash gas stream from the treatment of fuel gas with
methanol in the Rectisol process is added. Also, added to this stream is the
coal lock gas stream from the fuel gasifier. This stream was sent to the rich H2S
absorber in the El Paso design. Since it contains hydrocarbons, it may cause some
problems in the Claus plant in terms of carbonization of the catalyst and COS
formation. For this reason it has been added to the lean H^S stream. Ele-
mental sulfur is recovered from the Stretford plant and the off-gases are
vented.
12.4.4 Potential Effluents
Referring to Figure 12-5, primary effluent streams are defined as those
leaving the Stretford process and Claus plant. The Stretford off-gas stream
is vented to the atmosphere unless provision is made for incineration. Table
- 150 -
-------
VENT
98.8OO LBS./HR.
AIR
22,600 LBS/HR.
REDUCING GAS
50 LBS/HR. (H!
S\ Kl2.li>
12.10 1 \/
\/ RICH HgS FROM f ^
RECTISOLI *
86,100 LBS./HR.
CLAUS
X\
1 ^/
\/T ^
99,700 LBS /HR.
SULFUR
REDUCTION
TO HgS
O2. l«
1 /X.
V H-S FROM ^^ / \ „„ „_,, , „_ /.,„
000 LBS./HR. /I2. IS ' \/ *^"
k. 7
\ /
\ /
X
/ ^
/ \
/ \
COAL LOCK GAS
12,800 LBS./HR.
FUEL FLASH GAS
273 LBS./HR
EXPANSION GAS
(TAR RECOVERY)
62.IOO LBS/HR.
ftCIDGAS
(NH3 RECOVERY)
17,700 LBS./HR.
OXIDATION AIR
77,300 LBS/HH
SULFUR
6,880 LBS./HR.
VENT
762,000 LBS/HR
DRAWING NOTES
Figure 12-5. FLOW SCHEME FOR SULFUR RECOVERY - CLAUS/STRETFORD/BEAVOM
-------
1AI1I.L 12-6. MATERIAL HAI.AHCE (OR CLAUS/SlRtTrORD/DEAVOH SUI.I'UK RECOVEKY PROCESS
(Pounds Per Hour)
1
01
ro
i
S I re Jin
Number
Conijioneiit
CO.,
C.
"2S
COS
cs2
C2I(4
CO
"2
CM,
c2nfi
°2
"2
n2n
CII-jOII
so.
TOIAI.
12.1 12.2 12. J
585,515 3,525 8,573
5.562 44 283
110
4
1,307 39
1.311 2.641
77 253
1.472 440
2,102 60
320 b,f;24
8.870
5-J7.8IO 12.826 17,726
12.4 12.5 12.6 12.7
238 59.656 657, 5U7
14 314 6,217
110
4
1 1.347
9 64 4,055
20 350
3 42 1.957
2 2.164
6 6 , 1 50
2,030 10,900
6.883
273 62,126 690.761 6,883
12.8 12.9 12.10 12.11 12.12 12.13
657,507 75,064
7 I0.456(2)
110 II2*2'
4 4
1.347 44
4 .055 1
350
1,957 4
2,164 70
17,960 14,370 5,261
59.330 65.480 17.310
14,945
(3)
1.035'" 8,909
77.290 1.035 762.296 85.755 22.571 8.909
12.14 12.15 12.16
75.275 75.489
508(5* 1.036
343(4) 21
4
50 2
17.310 17,310
5.451 5.600
48<6>
480* 5) 3
99.415 50 99.465
12.17
75.489
1
21
4
2
17.310
5.600
3
98.430
(I) S as II0S
t,
(2) COS and CS2 flow rales estimated usimj El Paso Burnliani 1 10/2//3 design
(3) Mc'thanol concentration uiilnowii, ()','. methiinnl assumed for materiel I balance
(4) Assumes crude estimate of 3,000 pum sulfur in funn of COS and CS.
(5) Assumes remainder of sulfur not in form of COS, CS^ or S (vapor) is H,S or SO, in ratio of 2:1
(6) Assumes 0.!>X of total sulfur leaves as vapor
-------
12-7 gives the composition of the major pollutants in ppmv. It is assumed that
the Stretford process can remove H^S to less than 10 ppmv. COS and CSp however,
cannot be removed and remain in the off-gas in the concentration of approximately
100 ppmv and 3 ppmv respectively. Hydrocarbons and CO also pass through the
Stretford absorber untouched. Total hydrocarbon emissions are quite high
(13,200 ppmv or 2,630 ppmv excluding methane and ethane) indicating that this
stream might require incineration.
The product and blowdown from the Stretford process were described in
section 12.2.1.
The Claus off-gas is sent to a Beavon tail gas treatment process for
further sulfur recovery. The off-gas from the Beavon process is considered
here as a primary pollutant.
The Beavon process reduces sulfur compounds to hLS. Most of the develop-
ment work on the process has been with tail gas from concentrated hLS type
Claus plants. Little data, concerning the concentration of the Beavon tail
gas, is available for C02 rich tail gas. As was previously mentioned, C02
adversely affects the equilibrium between COS and CS^, and hLS. For this type
of feed the licensor crudely estimates 150 ppmv COS in the outlet stream (12).
HpS will be reduced to less than 10 ppmv in the Stretford absorber. CS~ and
S02 compositions are approximately 20 ppmv each from data based on concentrated
Claus off-gas (13). With the above emissions the overall sulfur recovery would
be 98.5%.
Table 12-8 shows a breakdown of major sources of sulfur and hydrocarbon
emissions for the SNG and fuel gas production areas. The total sulfur emissions
excluding boiler flue gases is estimated to be 86 Ibs/hr. or 0.5% of the sulfur
in the coal feed to the product and fuel gas gasifiers. This is 1/3 less than
the sulfur emissions from the previous case.
Total hydrocarbons, excluding methane and ethane, released to the atmosphere
from the sulfur recovery area amounts to 1,350 Ibs/hr. However, if the C0?
vent stream is included, the non-methane and ethane hydrocarbon emissions rise
to 3,710 Ibs/hr. This is over 50% higher than the previous design case. It
appears that hydrocarbons and CO are a major problem and incineration of all
vent streams may be required.
- 153 -
-------
TABLE 12-7. COMPONENT CONCENTRATIONS IN VENT STREAMS FROM
CLAUS/STRETFORD/BEAVON PROCESS
(PPMV)1
Stretford Vent Beavon Vent
Component 12.10 12.17
S02
H2S 10 10
COS 100
CS2 3
Total Sulfur 116 220
CO 7,920
CH4 6,670
C2H4 2,630
C2H6 3,940
Total Hydrocarbons 13,240
Hydrocarbon excluding
CH4 & C2Hg 2,630
(1) Dry gas only
(2) Concentration of S02, COS and CS2 are order of magnitude only
- .154 -
-------
TABLE 12-8. GASEOUS SULFUR AND HYDROCARBON EMISSIONS
en
en
Pollutant
Total Ib/hr
Sulfur to Atmosphere
Lbs. of sulfur to
atmosphere per Ib.
sulfur in coal **
Total Ibs/hr hydrocarbons
including CH* and C?H,
Lbs. hydrocarbons to
atmosphere per million
BTU HHV of coal
Total Ibs/hr hydrocarbons
(excluding CH. and C^Hg)
Lbs hydrocarbons (excluding
CM. and CH,-) to atmosphere
pe? million BTU HHV of coal
Stream (12.10)
Lean Acid Gas Stret-
ford Vent
69
0.0042
5,470
0.27
1,350
0.066
Stream (12.17)
Claus tail Gas
Treatment Beaver.
Vent
17
0.0010
0
Total
For Sulfur Recovery
86*
0.0052
5,470
0.27
1,350
0.066
Total
Including
Rectisol
Vent
86*
.0052*
20,450
1.0
3,710
0.18
* Does not include boiler and heater sulfur emissions
** Includes sulfur in coal to fuel gas production gasifier
-------
12.4.5 Control Methods
A simplified scheme of control methods is presented in Figure 12-5. This
shows that the lean HLS gas stream is treated in a Stretford unit. The rich
HLS gas stream is treated in a Claus unit followed by a Beavon unit.
Most of the recovered sulfur, particularly in the petroleum industry,
is produced by a modification of the Claus process which was developed about
1890 and involves vapor phase oxidation of hydrogen sulfide with air over
bauxite or iron ore catalyst in a single reactor. The first significant ad-
vance in the art was made about 1937 by I.G. Farbenindustrie. Instead of
burning the HLS directly over the catalyst, one third was burned completely to
sulfur dioxide in a waste heat boiler. In most of the present day plants,
HpS is burned in a non-catalytic furnace to produce sulfur. The furnace is
followed by various combinations of condensers, reheaters and Claus catalytic
converters to recover additional sulfur.
If the acid gas contains less than about 30% (vol) C02 the "straight-
through" Claus process is generally chosen (5) (6), and the entire acid gas
is sent to the Claus furnace, where FLS is oxidized under free flame conditions
with a stoichiometric amount of air according to the following reactions:
H2S + 3/2 02 = S02 + H20
2 H2S + S02 = 3S + 2 H20
or the overall reaction is
H2S + 1/2 02 = S + H20
If the C02 concentration exceeds about 30%, the free flame combustion with
stoichiometric air becomes unstable and the "split-stream" process must be
adopted. In this case, the acid gas is divided in the ratio of 2:1. The smaller
stream is oxidized completely to S02 and then recombined with the larger stream
to produce elemental sulfur in catalytic converters. Since in our present case
HLS is only 15%, the rest being mostly C02, split stream operation is the only
possibility unless the gases are preconcentrated to about 70% HLS as is done in
the WESCO scheme (10). Figure 12-6 is reproduced from the WESCO scheme. Here,
the rich H2S gas containing 21% (vol) H2S is concentrated to 70% (vol) H2S
- 156 -
-------
en
-~j
I
(42) (0 11 <2>
(1447)
STARTUP VENT
COAL LOCK VENTS
(0.08)"
NAPHTHA SEP GAS
(301)
(137.46)
CAT. REGEN GAS*
GAS-LIO VENT.
GAS-LIQ FLASH
CRUDE PRODUCT GAS
24,820 TONS/D
8,325 BTU/LBHHV
0 912 WT% S
(202 91)
C209]
SULFUR
•BY PRODUCT
(95% RECOVERY)
(1231
(123) CI.95]
(34.0)
3, 870 TONS/D COAL FINES
,0.040eB7TU£.BoHHV
(66 0)
C0.9]
(986% RECOVERY)
(3 23)
^ SULFUR
OO^RE^OVAL)
.(0.21)
i
- ^— -
(021)
CO. 19}
^ <77>
(0 20)
224 TONS/D OIL
17,250 BTU/LB HHV
0.09 WT% S
SUPERHEATER
FIREBOX
RECTISOL
METHANATION
RECTISOL
->— SNG PRODUCT
<5,800>
PHENOLIC
WATER
TARS.OILSI9.2)
NAPHTHA (2.1)
V\J
TL
ASH
NHj PRODUCT
PHENOL PRODUCT
REUSE WATER
DRAWING NOTES
• DAILY EMISSIONS ON ANNUAL1ZED BASIS
(o) 21 VOL % H,S
(b) 0.9VOL% H2S
(c) APPROX
) ALL SULFUR SPECIES, TONS/D
] CARBONYL SULFIDE, TONS/D
> HYDROCARBONS, TONS/D
TOTAL GASIFICATION PLANT SULFUR EMISSIONS
= 0.08«l 23*0.21= 1.52 TONS/DAY
= 0.7% OF GASIFIER COAL SULFUR
TOTAL BOILER PLANT SULFUR EMISSIONS
= 3.23t0.2O = 3.43 TONS/DAY
= 10% OF BOILER COAL AND FUEL OIL SULFUR
ALL SULFUR QUANTITIES ARE EXPRESSED AS
TONS/DAY OF ELEMENTAL SULFUR. THE
"ALL SULFUR SPECIES" QUANTITIES INCLUDE
THE COS QUANTITIES.
Figure 12-6. SULFUR DISTRIBUTION AT WESCO. (10)
-------
and then taken to a straight-through Claus unit to recover 95% of the incoming
sulfur. The tail gases from the Claus unit are incinerated and scrubbed to
remove SCL to acceptable limits.
In general, the "once through" flow scheme gives the highest overall re-
covery if sulfur is condensed before entering the first catalytic converter.
This would suggest that the dilute gases should be preconcentrated. However,
the preconcentrator may not be justified, if the sulfur recovery in the Claus
unit could be increased from 90 to 95% with tail gas treatment. For this reason
the "split stream" process is chosen here. Also, with the split stream mode
of operation the formation of undesirable by-products such as COS, C$2, etc.
is minimized.
The types and amounts of hydrocarbons present in the acid gas entering
the burner have an effect on the carbon content, and hence the color of the
resulting sulfur product. Aromatics and olefins form carbon more readily than
paraffins. Also, the amount of carbonyl sulfide formed in the high temperature
region is believed to be dependent on the amounts of carbon dioxide and hydro-
carbons in the burner feed (6). Some of the reactions that may occur are:
C02 + H2S = COS + H20
CO + 1/2 S2 = COS
2 COS = C02 + CS2
COS + H2S = CS2 + H20
2 CO + S2 = C02 + CS2
C f S2 = CS2
2 COS + 302 = 2 S02 + 2 C02
2 COS + 02 = 2 C02 + S2
2 COS + S02 = 3/2 S2 + 2 C02
CS2 + SO = 3/2 S2 + C02
Equilibrium compositions have been calculated for a split stream Claus
unit using stoichiometric amounts of air (5). The primary reaction products
- 158 -
-------
are found to be S09 and H90 with virtually no elemental sulfur being formed.
-6
The partial pressures of the carbon sulfides are always less than 10~ atms.
between 300°C and 1,700°C, supporting the contention that they are produced
by the reaction between CO and elemental sulfur. This suggests that the coal lock
gas stream, which is high in CO and other hydrocarbons, may be added to the
split burner directly to convert everything to C02 and hLO. In other words,
it is possible that a split stream burner may be used as an incinerator for
this small stream.
Figure 12-7 shows a Claus unit with the split stream process. The rich
H?S gas stream is divided in a ratio of 2:1. The smaller stream is burned
with air and cooled in a waste heat boiler. Part of this gas stream is used
for reheating of gases going to the second and third converter. The rest of
it is mixed with the larger stream and sent to the first converter. The
efficiency of the Claus plant depends on:
(1) The number of converters
(2) The temperature of the converters
(3) The method of reheating
Obviously, all of these are economic decisions. In general, yield is
increased with a larger number of converters and lower reaction temperatures.
Temperature is limited by the condensation temperature of the sulfur vapors.
Liquid sulfur poisons the activity of the catalyst (7). Also, some plants pre-
fer to run the first converter at a higher temperature than the other converters
to increase the conversion of COS to elemental sulfur at the expense of HLS.
The lower temperature of the other converters compensates for this. Also,
there are four basic methods of reheat:
• Hot-gas by-pass
9 In-line burners
e Gas to gas exchangers
« Indirect heaters, fuel-gas fired
- 159 -
-------
STEAM
AIR
HOT GAS BY- PASS FOR REHEATING
WASTE
en
o
RICH
•*— \1J ( HEAT 1
, TTV BOILER J ,
^BURNER
^3
2/3
C(
1600
J«
I
^
\
\
\
/
/
/
)NVE
^
/
I
\/
X.
I \
r-i
f3755?ti #
—N x^Ss
CLAUS PLANT
SPLIT STREAM PROCESS
BEAVON CATALYTIC
REDUCER
STRETFORD
ABSORBER
DRAWING NOTES
Figure 12-7. FLOW SCHEME FOR SULFUR RECOVERY - SPLIT STREAM CLAUS/BEAVON/STRETFORD
-------
Figure 12-7 shows hot gas bypass for reheating. Vapors from each converter
are cooled below the dew point of sulfur to condense out the sulfur and then
reheated above the dew point of sulfur by mixing with hot gas from the waste
heat boiler. High purity sulfur is obtained as a by-product. The tail gas
stream is sent to the Beavon reactor.
A great deal has been written about the Claus catalysts and their activity
and poisoning (8), (9). Bauxite has been used as a catalyst for a long time.
Deactivation of catalyst due to poisoning may be caused by carbonaceous de-
posits, sulfur condensation, sulfur vapor adsorption, thermal degradation and
sulfate formation. Bauxite contains undesirable iron and silica compounds
which are poisoned very easily. An improved version of bauxite is "Porocel" of
Engelhard Minerals & Chemical Corp. which is made from high grade activated
bauxite. It contains 88 - 92% alumina. Pure activated alumina is being pro-
posed as a better catalyst. In most cases a catalyst life of 2 - 5 years can
be expected.
The Beavon process for the treatment of Claus tail gases employs three
distinct steps:
(1) hydrogenation of sulfurous compounds to hLS in a catalytic reactor.
(2) cooling of the reactor effluent gases.
(3) conversion of the H?S in the tail gas to elemental sulfur by use of
the Stretford process.
Figure 12-7 depicts the essentials of this process. The tail gas stream
from the Claus plant is heated by exchanging with the reactor outlet gas or by
mixing with the hot flue gases and then fed to the catalytic reactor. The
catalyst used is cobalt molybdate, which is both rugged and cheap. The re-
ducing gas is hydrogen, or can be supplied by partial combustion of the fuel
gas in an in-line burner which simultaneously raises the tail gas stream tem-
perature to the level required for the hydrogenation reactions. The reactor
effluent gases are then cooled with water in a direct contact condenser where
most of the water vapor is condensed, and at the same time, the tail gas is
cooled. The direct contact cooling water is in turn cooled by the cooling
tower water in a shell and tube heat exchanger. The purge water produced from
- 161 -
-------
this condenser has good quality and contains only a small amount of dissolved
H2S. With HpS removal in a small sour water stripper, it is suitable for cooling
tower makeup water. This water can also be used as a makeup water for the
Stretford solution without any further processing.
The cooled gas then enters the Stretford absorber, where H^S is removed
almost quantitatively.
12.5 OTHER PROCESS MODIFICATIONS
12.5.1 Stretford Solution Slowdown
Because of rapid buildup of solids, a substantial amount of the Stretford
solution has to be discarded. There is no mention of this blowdown in the El Paso
document. Since no satisfactory disposal methods have been worked out, this
could be a serious problem. Also, vanadium is an expensive metal, and will have
to be recovered from the blowdown. One of the ways to reduce this blowdown is
to put a hydrogen cyanide filter before the Stretford process. This will
eliminate the substantial amount of salts which are formed by the reaction of
HCN with the Stretford solution.
12.5.2 Hydrocarbon Emissions from Rectisol and Stretford Process
It has been pointed out numerous times that the vent from the Stretford
process and the vent from the Rectisol II process are both high in hydrocarbons
and CO. If strict hydrocarbon standards are applied it will be necessary to
incinerate these streams. Incineration would eliminate the hydrocarbon and CO
problem although it would generate some NO and convert all sulfur compounds to
A
S02- Incineration, however, is an extremely expensive method of control on
such large streams, even when waste heat recovery is included.
- 162 -
-------
REFERENCES
CHAPTER 12
1. Gibson, C. R., Hammons, G. A. and Cameron, D. S., Environmental Aspects
of El Paso's Burnham I Coal Gasification Complex. Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology (May, 1974, St. Louis,
Missouri), EPA 650-2/74-118, October, 1974.
2. Ellwood, P., Meta Vanadates Scrub Manufactured Gas. Chemical Engineering,
July 20, 1964.
3. Naboer, J. E., Wessenligh, J. A., and Groenedaal, W., New Shell Process
Treats Claus Off-Gas. Chemical Engineering Progress, Vol. 69, No. 12
TT973T
4. Palm, J. W., Hatch These Trends in Sulfur Plant Design. Hydrocarbon
Processing, pp. 105-108, March, 1972.
5. Meisen, A., and Bennett, H. A., Consider All C'laus Reactions - Hydrocarbon
Processing, pp. 171-174, November, 1974.
6. Opekar, P. C. and Goar, B. G., "This Computer Program Optimizes Sulfur
Plant Design and Operation. Hydrocarbon Processing, 45, No. 6, pp. 181
(1966).
7. Gamson, B. W. and Elkins, R. H., Sulfur from Hydrogen Sulfide. Chemical
Engineering Progress, Vol. 49, No. 4 (April, 1953)!
8. Pearson, M. J., Development in Claus Catalysts. Hydrocarbon Processing,
pp. 81-85, February, 1973.
9. Burns, R. A., Lippert, R. B., and Kerr, R. K., Choose Catalyst Objectively. •
Hydrocarbon Processing, November 1974.
10. Beychok, M. W., Sulfur Emission Controls for a Coal Gasification Plant.
Symposium Proceedings: Environmental Aspects of Fuel Conversion Technology,
II, (December, 1975, Hollywood, Florida), EPA 650/2-76-149.
11. Personal Communications, Davy Power Gas, Institute of Gas Technology and
Ralph M. Parson Co.
12. Personal Communication, Ralph M. Parsons Co.
13. Goar, B. G., Claus Tail Gas Cleanup Processes. Energy Processing/Canada
- 163 -
-------
- 164 -
-------
13. BY-PRODUCT STORAGE
13.1 POTENTIAL EFFLUENTS
Approximately 100 tons/hour of various by-products are produced which
must be stored and subsequently shipped to buyers. These by-products
are tar, tar oil, naphtha, crude phenols, ammonia solution, and sulfur.
Following is a breakdown of their production rates:
By-Products LBS/HR
Tar 88,800
Tar Oil 48,600
Phenols 11,260
Ammonia (as anhydrous) 21,400
Naphtha 20,000
Sulfur 15,582
Total 205,642
Tar, tar oil and naphtha are stored in API type tanks whereas ammonia
solution is stored in a pressure vessel. Phenols and sulfur are stored
in heated tanks.
Besides these by-products, other chemicals that are used in the pro-
cess are also stored. These include sodium hydroxide, methanol, iso-
propyl ether, sulfuric acid and components of Stretford solution. There
may be some other chemicals needed for auxiliary facilities, for example
boiler feed water chemicals including amines, chelants, sulfites, etc.
Emissions in this area will consist of tank breathing, leaks, spills
and venting of tanks while pumping liquids into the tanks. An estimate
of more important emissions based on API design (1) is as follows:
- 165 -
-------
Crude phenol 1.5 Ibs/hr
Tar oil 2.6
Naphtha 2.1
Ammonia 1.5
Product Gases 3.2
Methanol 1.6
13.2 CONTROL METHODS
Process leaks and spills can best be reduced by periodic maintenance
checks and adherence to operating instructions. For big spills, concrete
dikes with concrete floors around the storage tanks and pump area are
required to contain the spills. The vapor emissions from tank vents
can be controlled by one or more of the following methods:
Vent Condenser. By circulating refrigerated brine at 0°F, most of
the emissions can be reduced substantially.
Scrubbing. Vent vapors can be led to a scrubber where a suitable
solvent having low vapor pressure is used for absorbing the vapors.
Saturated solvent is either burned or steam stripped to obtain vent
vapors in liquid form after condensing the steam and separating the
phases.
Incineration of Vapors.
Absorption on Solids such as Charcoal.
- 166 -
-------
REFERENCE
CHAPTER 13
1. Anon, Petrochemical Evaporation Loss from Storage Tanks. API Bulletin
No. 2523, November, 1973.
- 167 -
-------
- 168 -
-------
14. WATER TREATMENT
14.1 RIVER WATER PUMPING PLANT, PIPELINE, AND STORAGE
14.1.1 Stream Flows
Process flow schemes for the river water pumping, pipeline and storage
sections are shown in Figures 14-1 and 14-2. A description for each stream
within these areas is presented in Tables 14-1 and 14-2. All water required
for the complex will be pumped from the San'Juan River, 40 miles from the
plant site. A bar screen at the intake will collect floating debris. The
pumping rate will be sufficient to supply the plant and non-plant water needs
of about 3.65 million Ib/hr (7,300 gpm). Because the river often carries a
high silt load, a settling basin at the pumping station is provided. The
settling basin, approximately 400 x 1000 ft will be divided into two ponds.
River water can be diverted into either one. Each basin has been sized to
provide sufficient retention time and low enough velocity to permit silt and
sand to settle from the water. A 40-mile buried, lined, steel pipeline will
transfer water from the settling basin to the storage reservoir at the plant
site. A trash screen is provided at the pump intake where the desilted water
enters the pipeline. Pumps at this station will provide the necessary pressure
to transfer the-water through the 40 miles of pipeline and overcome approxi-
mately 1000 ft. of vertical lift. Raw water from the pipeline will flow into
a 210 million gallon reservoir near the plant site. This reservoir, designated
raw water storage and pumping, will provide a 21-day storage capacity which is
expected to be adequate to maintain plant operations during water pipeline
shutdowns caused by emergencies, during periods of low flow in the San Ouan
River or when the river water is of unusually poor quality. The reservoir will
provide for additional settling of silt from the water and will also provide
water for fire fighting. This reservoir will be constructed by excavating into
a sloping terrain and constructing earthen dikes around the perimeter. The
reservoir will be lined to prevent seepage losses. The evaporation rate is
expected to average 72,500 Ib/hr (145 gpm) from May thru October and 27,500
Ib/hr (55 gpm) from November thru April.
- 169 -
-------
o
I
STILL ING BASIN, r DIVERSION DAM
SURGE PROTECTION DEVICES
MOTOR OPER GATES
MR PRESSURE
~~~i U
SURGE PROTECTION DEVICES
SLUICE GATE
MOTOR OPER GATE
1 "BAR SCREEN
STOP-LOG SLOT
36" 0 0 LINED STEEL PIPELINE
RIVER WATER
PUMP BLDG.
STANDPIPE AT
THE SUMMIT
32 8 3O 0 D LINED
STEEL PIPELINE
BACK PRESSURE
CONTROL VALVES
DISSIPATION TANKS
RAW WATER
VALVE PIT
DRAWING NOTES
THE DESIGN OF THIS SYSTEM IS EXPANDABLE
TO SUPPLY WATER FOR A NUMBER OF
PLANTS WITH TOTAL CAPACITY OF 75OMM
BTU/D SYNTHETIC PIPELINE GAS. THE
PUMPING STATION FOR BURNHAM I WILL
HAVE TWO CENTRIFUGAL PUMP TRAINS.
Figure 14-1. RIVER WATER PUMPING PLANT AND RAW WATER PIPELINE
-------
RAW WATER
FILTER BACKWASH (370 GPM)
r
,7056 GPM
r~\
AVERAGE SUMMER gate*-.
EVAPORATION 145 GPM
RAW WATER RESERVOIR
210 MM GAL.
21 DAY STORAGE
\
—
-DRAIN »-^
(FOR MAINT. ONLY)
TO FUTURE PLANTS
RAW
WATER
STRAINERS
S992 GPM RAW WATER
TO PLANT FIRE PROTECTION SYSTEM
FIRE PUMP
(ENGINE DRIVEN)
RAW WATER
PUMPS
JOCKEY FIRE FIRE PUMP
PUMP (MOTOR DRIVEN)
RAW WATER PUMP HOUSE
1289 GPM FOR NON-PLANT USE
ffi
J
nJ
DRAWING NOTES
THE RAW WATER RESERVOIR IS FOR ONE
COMPLETE PLANT WITH TOTAL CAPACITY
OF 288 MM SCFO SYNTHETIC PIPELINE GAS.
Figure 14-2. RAM WATER STORAGE AMD PUMPING
-------
Table 14-1. RIVER WATER PUMPING PLANT AND PIPELINE
Stream
IN
Quantity. Ib/hr (gpm)
Constituents
Concentration
San Juan
River Water
3,528,000
(7056)
ro
Calcium, ppm of Ca ion
Magnesium, ppm of Mg ion
Sodium, ppm of Na ion
Bicarbonate, ppm of HC03 ion
Carbonate, ppm of C03 ion
Sulfate, ppm of $04 ion
Chloride, ppm of Cl ion
Silica, ppm of Si02 ion
Suspended solids, ppm
Dissolved solids, ppm
Specific conductance micromhos @ 25°C
Carbonate hardness, ppm as CaC03
Noncarbonate hardness, ppm as CaC03
pH
66
9.1
45
144
0
168
14
11
,100
390
599
211
93
7.8
OUT
Raw Water
Same as above except
Suspended solids, ppm
3,500
-------
Table 14-2. RAW WATER STORAGE AND PUMPING
Stream
Raw water from
river water pumping
Bldg.
Filter Back-wash
Total, IN
Quantity, Ib/hr
(gpm)
3,528,000
(7056)
185,000
(370)
3,713,000
(7426)
Constituents & Concen.
See Table 14-1
NR
OUT
To raw water treatment
Non-Plant Use
Evaporation from raw
water reservoir
Total, OUT
2,996,000
(5992)
644,500
(1289)
72,500
(145)
3,713,000
(7426)
NR
NR = Not Report in El Paso Document
- 173 -
-------
In addition to the 3.5 million Ib/hr (7,000 gpm) of raw water from
the pipeline, the reservoir will also receive 185,000 Ib/hr (370 gpm) of
filter backwash from the raw water treating area. The raw water pumps
will draw water from the reservoir through strainers and deliver 3
million Ib/hr (6,000 gpm) to the raw water treating area and 0.65
million Ib/hr (1,300 gpm) to non-plant using areas.
14.1.2 Potential Effluents
14.1.2.1 Major Pollutants. It is expected that the only streams
with potential effluent problems at the river water pumping station will
be (1) trash collected on the screens at the intakes of the pumping
station at the river and the settling basin and, (2) silt and sand
accumulations in the settling basin.
The pipeline does not appear to have any potential effluent problems.
The potential effluents at the raw water storage area will be silt
accumulation in the reservoir and waste solids accumulated in the raw
water strainers at the intake of the raw water pumps.
14.2.2.2 Trace Constituents. There does not appear to be any
potential effluent problem from trace constituents.
14.1.3 Control Methods
14.1.3.1 Proven Methods. Control of (1) trash collected on the
intake screens, (2) silt and sand deposited as sediment in the raw water
settling basin and in the raw water storage reservoir, and (3) materials
collected on surfaces of strainers at pump stations, is not addressed in
the El Paso document.
14.1.3.2 Potential Methods. Trash from intake screens could be
allowed to dry and then incinerated. Silt and sand deposits from the
raw water settling basin and storage reservoir could be used as land-
fill. Materials from the pump strainers could also be used as land-
fill.
- 174 -
-------
14.1.4 Process Modifications
None suggested.
14.2 RAW WATER TREATMENT
14.2.1 Stream Flows .
The process flow scheme and the material balance for the raw water treat-
ment section are given in Figure 14-3 and Table 14-3, respectively.
14.2.1.1 Inlet Streams. This area will receive (1) some 3 million
Ib/hr (6,000 gpm) of raw desilted water from raw water storage (for
analysis see Table 14-1), (2) about 1.5 million Ib/hr (3,000 gpm) of
hydrocarbon contaminated steam condensate from various sources and (3)
about 315,000 Ib/hr (630 gpm) of process condensate from the methanation
area consisting of mostly water and containing 69 Ib/hr of dissolved gases,
C02 (0.7 mols/hr) and CH4 (2.4 mols/hr).
The raw water will be treated in a lime softening system (clarifier-
treater); alum, polymer and chlorine are also used in this treatment.
After treatment the water is stored in a clear well and then pumped
through gravity filters filled with anthracite. Filtered water goes
either through ion exchange mixed beds or through zeolite softener sets.
The process condensate from the methanation area will be stripped
of carbon dioxide and methane by blowing air through it. This stream is
then combined with the zeolite softened water.
Other streams entering the raw water treatment area are sulfuric
acid and sodium hydroxide for ion exchange regeneration, sodium chloride
for zeolite regeneration, zeolite and ion exchange resins for makeup,
activated carbon and anthracite.
- 175 -
-------
BY-PASS
POTABLE WATER TANK
.POTABLE WATER
20 GPM AVOn'O PLANT
HYPOCHLORITE
TANK
GRAVITY
FILTERS
TREATED
PLANT puMPS
SERVICE V
WATER
47I29GPM
ALUM
SOLUTION
TANKS
LIME FEED ALUM FEED POLYMER CLEARWELL
PUMPS PUMPS FEED PUMP PUMPS
AIR CONVEYOR
SODIUM HYDROXIDE SOLUTION
DEMINERALIZER ACID
STORAGE TANK
DEUINERALIZED
WATER
,,-,« ,.„..ZEOLITE SOFTENER
237OGPM . i -l
OIL FREE
CONOENSATE
ALL STEAM
CONDENSATE
RETURNS
DRAWING NOTES
Figure 14-3. FLOW SCHEME FOR THE RAW WATER TREATMENT SECTION
-------
Table 14-3. RAW WATER TREATING
Stream
IN
Raw Water
Process Condensate
All Steam Condensate
Total, Liquids IN
Lime
Sodium Hydroxide
Sodium Chloride
Polymer
Zeolite
Alum
Sulfurlc Acid
Activated Carbon
Anthracite
OUT
Softened Water
Oemineral i:ed Water
Cooling Tower Makeup
Plant Service Water
Cegasser Vent
Filter Backwash
Lime Sludge
Regeneration '.tastes
Clean Comensate
Potable Water
Total , Liquids OUT
Scent Anthracite
Spent Caroon
Solids 1n Litre Sludge
Polymer
CiCOs
A1(OH)3
Clay, Silt and Sand
Soii is in Regeneration
Wastes:
SOi
lia
c;
Ca
.ig
Carbon dioxide
No. Quantity, Ib/hr (qpm)
14.1 2,996.000
(5992)
14.2 314,500
(629)
14.3 1,520.000
(3040)
4.830,500
(9661)
220
100
100
300
MR
900
50
NR NR
NR
14.4 1,459,000
(2918)
14.5 1,112.000
(2224)
14.6 220,500
(441)
14.7 64,500
(129)
17,500
(35)
14.8 135,000
(370)
14.9 108,000
(216)
14.10 134,000
(268)
•,4.11 1,520.000
(3040)
10,000
(20)
4,330.500
(9661)
NR
14.9
300
700
320
14.10 15,300
450
490
SO
50
20
Constituent J Concen.
Known Potential
NR
HzO-315 K-
Ib/hr
C02-0.7 mols/hr
CH4-2.4 mols/hr
HjO Traces of
Hydrocarbons
NR
NR
NR
NR
NR
NR
NR
NR
Cl^.- 55 opm
Ma -33 pom
SiO? • 10 pom
SiO; • 10 ppm
NR
NR
NR
NR
NR
NR
NR
NR
NR
IIR
N R
NR
Control Methods
Ultimate Discharge
Carbon Adsorption
Carbon Adsorption
To Metnanation
To Steam i Power Generation
To Cooling Water System
To Plant
To Atmosphere
To Saw Water Storage i
Pumping
To Ash uewatering System
To Ash Sewatering System
To Steam i Power Generation
He Mane
NR > Hot Reported in El
38
To Affiospnere
To Aaospnere
Paso Document
- 177 -
-------
14.2.1.2 Outlet Streams. Water, which has been through the lime
treater-clarifier and the gravity filters, is stored in the treated water
tanks. Plant service water, potable water, and treated water for makeup
in the clean cooling tower are drawn from the treated water tanks. These
tanks also supply feed water to the demineralizers and to the zeolite
softeners. Demineralized water is sent to steam generators for lower pressure
steam generation.
Zeolite softened water is supplied to the methane generation area. The
air stripped process condensate stream from methanation is returned to that
area. After removal of trace hydrocarbon contaminants the steam condensate
stream is returned for use in high pressure steam generation. The lime
sludge underflow from the lime treater-clarifier is sent to ash dewatering
and transfer. Slowdown wastes from the regeneration of the ion exchange
and zeolite units are also sent to the ash dewatering and transfer area.
Periodically spent carbon and spent anthracite will be sent to the same area.
14.2.2 Potential Effluents
14.2.2.1 Major Pollutants. Potential pollutants are spent carbon-
containing hydrocarbons, lime sludge, blowdown from ion exchange and zeolite
regeneration and waste anthracite from the gravity filters. Carbon dioxide
and methane are discharged to the atmosphere from the degasser.
14.2.2.2 Trace Constituents. No information is available on trace
constituents in the above streams, however the only material that might be
suspected of containing hazardous trace constituents is the spent carbon
used to absorb hydrocarbons from steam condensate.
14.2.3 Control Methods.
14.2.3.1 Proven Methods. No waste streams are discharged to the environ-
ment from this area, except the degasser vent which will contain carbon dio-
xide and methane. All other waste streams are transferred to other areas
for disposal. No controls are indicated in the El Paso document.
-178 -
-------
14.2.3.2 Potential Methods. The carbon dioxide-methane-water vapor
vent from the degasser could be collected and the methane reclaimed and
returned to the product gas stream.
14.2.4 Process Modifications
The only likely modification for this area is that suggested in
14.2.3.2 above.
14.3 COOLING WATER SYSTEM
14.3.1 Stream Flows
The process flow scheme and the material balance for the cooling water
system are given in Figure 14-4 and Table 14-4, respectively. This area
serves two functions. The clean cooling towers serve oxygen compression
and storage. The main cooling towers serve all other areas in the complex.
Circulation rates are 4.1 million Ib/hr (8,200 gpm) in the clean towers and
76.4 million Ib/hr (153,000 gpm) in the main towers.
14.3.1.1 Inlet Streams. Makeup water to the clean towers will be the
boiler blowdown from the process waste heat and power generation boilers.
Makeup to the main towers will be (1) "clean" water from gas liquor stripping,
(2) treated water from raw water treating, (3) blowdown from the clean cooling
towers and treated sewage. Treating chemicals will be fed to both towers to
control foaming, corrosion, plant growth, scaling and pH.
14.3.1.2 Outlet Streams. Blowdown from the main towers will be sent
to ash dewatering and transfer. There will be entrainment and evaporation
from the towers to the atmosphere. A side stream of the circulating water
returning to the main towers is filtered. Filter backwash could be discharged
with the tower blowdown.
- 179 -
-------
8,ZOO GPM
BOILER SLOWDOWN
*>
t/\ OXYGEN
/I4 2f> COMPRESSION
\~/ AND STORAGE
D-)S'0{ qn<> T
456 GPM
00
O
CLEAN WATER
2,378 GPM
TREATED WATER^
441 GPM
TREATED SEWAGE
2O
SLOWDOWN
SULFURIC ACID
152.790 GPM
ANTI FOAM
PACKAGE
BIOLOGICAL
PACKAGE
plonl growth
control
INHIBITOR FEED
PACKAGE
•cole/corrosion
control
SULFURIC ACID
PACKAGE
ph control
AREA NAME
Got production
Got cooling
Got purification
Refrigeration
Methano synthesis
Product gat camp. 8 dehydration
Gas liquor separation
Phenol e*lroction/gos liquor stripping
Loch got storage 8 compression
Sulfur recovery
Fuel gat production
Fuel gas cooling
Fuel gas treating
Air compression
Steam S power generation
Oiygen compression S storage
TOTAL
90° F
GPM
630
I7.O6O
1.370
54.9IO
1,910
25,620
11,730
I.38O
13,000
160
5,520
— O —
4,800
4.500
S.OOO
I52.79O
DRAWING NOTES
Figure 14-4. FLOW SCHEME FOR THE COOLING WATER SYSTEM
-------
Table 11-4. COOLING WATER SYSUMS
00
Stream
!H
Clean waler from
fias Liquor Slripping
Treated Waler from
Raw Hater Treatment
Roiler Illowdnwn
Treated Sewage
Sul f uric acid
Ant i foam
Hiocide
Inhibitors
Cool ing water,
main plant
Cool ing Waler
Total, Ifl
OU1
Cool ing tower:
1 . Cnlrainment
2. Evaporation
3 . 11 1 owdown
Cool ing Water
Cool ing Hater
Total, OUT
Ho. Quantity, Ib/hr
(cjpm)
11.12 1,1(19,000
(237(1)
11.6 220,500
(111)
11.13 228,000
(456)
14.11 10,000
(20)
11.15 NR
11.16 tm
11.17 tlli
14.18 NR
14.19 76,395,000
(152,790)
14.20 4,100,000
(11200)
R2, 142,500
( 164, 2U5)
14. 21 80,000
(160)
14.22 1,403,000
(2006)
14.23 164,500
(329)
4,100,000
(11200)
76,395,000
( 1 52 ,790)
82,142,500
(I (.1,285)
Consti
Known
NR
NR
MR
NR
NR
NR
NR
NR
NR
NR
NR
MR
MR
Cons t i l.iien ts_a|id_ Concentration
Potential
1 races of aniuonia ,
phenols, naphtha
solvent
Control Methods
Traces of ammonia,
phenol solvent, naphtha
sulfur, hydrocarbons
Traces of biocide chlorine
chromates, phosphates, sul-
fates, organic anlifoam
sulfur, tar, phenol, naphl.ha
UJ tinidte J)Jschajxje
To main cooling towers
To main cooling lowers
To clean cooling lowers
lo ma i ri cooling lowers
To nnin cool ing towers
Tn clean cooling lowers
To Atmosphere
To Atmosphere
To Ar.h Dewalering SysU'm
To Oxygen Plant
To Main Plant
NR = Nol Reported in El Paso Document
-------
14.3.2 Potential Effluents
14.3.2.1 Major Pollutants. It should be noted that the blowdown
from the cooling towers will contain the treating chemicals, such as
chromates, phosphates, algacides, etc. as described in Section 14.3.3.2.
Any uncontrolled chemical treatment may constitute a serious source of
undesirable pollutants, in addition to those entering with makeup water.
The major components and their concentration in the feedwater are listed
below. These are expected to be present in the cooling tower blowdown.
Component Concentration or Range
Present in Feedwater
Phenols 760 ppm '
Organic Fatty Acids and Oils 2,700 ppm
Ammonia 200 ppm
Resulting from Additives
Inorganic Chromate Salts 300-500 ppm
Inorganic and Organic Phosphates
and Polyphosphates 2-10 ppm
Chromate and Phosphate
Combination Treatments 60 ppm
Chlorinated Phenols 300-400 ppm
14.3.2.2 Trace Constituents. There may be trace constituents
which are present in the make-up water but are as yet unidentified.
14.3.3 Control Methods
14.3.3.1 Proven Methods. No control schemes are indicated in the
El Paso document.
- 182 -
-------
14.3.3.2 Potential Methods. Some components present in the make-
up water may be discharged with the blowdown. Treatment chemicals will
also be present in the blowdown. Following are some methods which may
be used to control these components.
Biological Oxidation Using Water Cooling Towers. Cooling towers
•
have been successfully used as biological oxidation towers and have been
particularly effective in oxidizing phenols. In actual operation these
systems have achieved 98+% phenol reduction. Operating experience with
these systems has been reported as good. Fouling of process coolers by
suspended sludge has been prevented by periodic back-washing of the
coolers. However, some waste sludge is removed via windage losses. In
addition to phenols (780 ppm) the water stream from gas liquor stripping
consists of other organic fatty acids and oils, (2,700 ppm) and ammonia
(200 ppm).
Inefficient removal of these constitutents as waste sludge in
cooling towers can result in high losses to atmosphere through evaporation.
Hence, the water stream from the Gas Liquor Stripping Area should be
biotreated in a separate biological oxidation process before using it as
make-up water to main cooling towers.
Control _of Treating Chemicals In Coolijig Tower Water. The
treated water contains salts of sodium (45 ppm), calcium (19.4
ppm), and magnesium (9.1 ppm). The anions will be chlorides (14 ppm)
sulfates (168 ppm), silicates (11 ppm), carbonates, bicarbonates and
hydrates. When concentrated 3-7 times in a circulating water system,
some of the salts will exceed their solubility limits which will result
in salt deposition in the form of scale. Sulfuric acid is commonly
added in controlled quantities, to the circulating water system to prevent
scale formation. The system pH should not be reduced too far below 7.0
to prevent higher corrosion rates.
- 183 -
-------
A variety of treating chemicals, other than sulfuric acid, are used
in cooling water systems for corrosion control and for inhibiting the
growth of algae and slime. These chemicals do not react with the salts
present in the water. Thus, their concentration in the draw-off water
will simply be equal to the concentration at which they must be used in
the circulating water to perform their function. Following are order-
of-magnitude figures for the treating chemicals.
Inorganic Chromate Salts. These are used for corrosion control.
Concentration levels may be as high as 300-500 ppm.
Inorganic and Organic Phosphates and Polyphosphates. These are
used for corrosion control. Concentration levels are usually at 2-10
ppm. High concentrations of phosphate, under some conditions, can cause
the deposition of calcium phosphate scale.
Chromate and Phosphate Combination Treatments. These are used for
corrosion.control. Total concentration levels may be as much as 60 ppm
with CrO^ ranging from 10-40 ppm and P04 from 20-50 ppm.
Chlorinated Phenols. These are used for control of algae and
bacterial slime. Intermittent dosage may be as high as 300-400 ppm.
14.4 WASTEWATER TREATMENT
14.4.1 Stream Flows
There is no section in the facility dedicated solely to wastewater
treatment. The approach adopted for water disposal is to reuse those
streams which require only minimal treatment and to use the more highly
contaminated water for ash transport. The ultimate disposal of the ash
sluice water then is by evaporation (See Figure 14-5). Some will remain
in the wet ash.
- 184 -
-------
HEATER SLUDGE 216 GPM
XVV\ COOLING TOWERjiLOWDOWN
y."^ ... -- i29GPMi
329 GPM
PROCESS CONDENSATE I GPM
d_D
DRY ASH
DRY ASH FROM FROM FUEL
GAS_PROD GAS PROD.
196 T~PH\ I 42 T PH
AIR a VAPOR
DROPLET SEPARATOR
EXHAUST FAN
.UNDERFLOW^
r
ASH COLLECTION CONVEYOR
579,560 LB /HR
' WET ASH
ATM
151 GPM EVAPORATION
I 27.TOO LB /HR
TO
,E_VAPQRATIQN P_QNDS_
J
FINE ASH POND
DRAWING NOTES
Figure 14-5. FLOW SCHEME FOR THE ASH DEWATERING AND TRANSFER SECTION
-------
Ash is transported from the high- and low-Bill gasifiers using
overflow from a thickener and a combination of blowdown, condensate, and
contaminated liquids. Six liquid streams are identified as entering the
ash transport system and are listed with stream numbers, origin, and
flow rates in Table 14-5.
14.4.1.1 Lime Treater Sludge. Raw water treatment generates a
waste stream consisting of lime treater sludge. This stream has a
solids content which ranges from 5 to 10 percent, and which includes
treatment chemicals (polymer, calcium carbonate, and aluminum hydroxide)
and suspended solids present in the raw water (clay, silt and sand).
The total stream flow is 216 gpm or 108,200 Ib/hr. Components have been
estimated for this stream and are listed in Table 14-6.
14.4.1.2 Blowdown. Ion exchange demineralization and zeolite
softening are used in the water treatment process. Regeneration of
these units results in blowdown which must be disposed of. The blowdown
stream flow is 268 gpm, or 134,200 Ib/hr. The major constituents in
this waste water are sulfate, sodium, chloride, calcium, and magnesium
ions. Quantities have been estimated on the basis of the input water
quantity and quality and are shown in Table 14-7.
14.4.1.3 Cooling Tower Blowdown. There are two cooling systems
designated as "clean" and "main". The clean cooling system services
only oxygen compression and storage while the main cooling system services
the remainder of the plant. Blowdown from the clean system is combined
with makeup water to the main system. Treatment of the water in both
cooling systems includes anti-foam agents, biological controls, scale
and corrosion inhibitors, and sulfuric acid, pH control. Treatment
chemicals used for oxygen cooling towers have to be limited to only those
materials which will not initiate any kind of explosion or fire. Residues
from each of these will be contained in the main cooling system blowdown
which enters the wastewater section. Components which may be present in
the blowdown streams as a result of each of the four treatments are shown
below.
- 186 -
-------
Treatment
Anti-Foam Agents
Biological Controls
Scale and Corrosion
pH Control
Typical Components Used
Aliphatic acids and esters
Alcohols - medium to high molecular
weight, mono-and-polyhydric
Sulfonates and sulfates
Nitrogen containing compounds-amines,
amides, polyamides
Phosphates - organic phosphates
Silicones
Halogenated Compounds - high
molecular weight, highly halogenated
Inorganic compounds
Chlorine, hypochlorite, chloro-
phenols
Quaternary amines
Organotin, sulfur, or thiocyanate
Ozone
pH control inhibitors
Alkaline treatment - sulfonated
lignins and tannins, polyacrylates,
polyphosphates, polyol esters, and
phosphonates
Acid treatment - chromate and
phosphate
Chromate, zinc, and phosphate
corrosion inhibitors
Silicates and molybdates
Organic polymer - silicate
Sulfuric acid
Sodium hydroxide
- 187 -
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Table 14-5. STREAMS ENTERING THE ASH TRANSPORT SYSTEM
Stream Identification
Lime Treater Sludge
Slowdown
Cooling Tower Slowdown
Contaminated Gas Liquor
Process Condensate
Utility Water
Number
14.9
14.10
14.23
14.24
14.25
14.26
Flow Rate
gpm Ib/hr
216
268
329
329
1
100
108,200
134,200
164,700
164,700
500
50,100
Origin
Raw Water Treating
Raw Water Treating
Cooling Water System
Gas Liquor Stripping
Product Gas Compression
and Dehydration
Various Plant Utility
Sources
Table 14-6. LIME TREATER SLUDGE COMPONENTS
Component
Polymer
CaC03
A1(OH)3
Clay, Silt, and Sand
Total Solids
Total Stream Flow
Rate, Ib/hr
300
700
320
750
8,820
108,200
Concentration
0.28%
0.64%
0.30%
6.93%
8.15%
- 1!
-------
Table 14-7. SLOWDOWN COMPONENTS
Component Rate, Ib/hr Concentration
SO, 455 3,385 ppm
Na 590 4,402 ppm
Cl 78 579 ppm
Ca 47 349 ppm
Mg 22 163 ppm
Total Stream Flow 134,200
Table 14-8. CONTAMINATED GAS LIQUOR COMPONENTS^
Component
COD
NH3
Cl
H2S
CN
Phenols
Fatty Acids
TDS
SS
Ca
Fe
Total Stream Flow
Rate, Ib/hr
185
35
4
2
0.16
70(2)
60^
144
4
3
0.16
164,700
Concentration
0.11%
210 ppm
24 ppm
12 ppm
1 ppm
425 ppm
360 ppm
870 ppm
24 ppm
18 ppm
1 ppm
(pH = 8.4)
(1) Obtained from SASOL data, may be low.
(2) See Table 11-3.
- 189 -
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While the above list appears rather formidable, it must be remembered
that not all and not even most of the chemical species identified will be
present in cooling tower blowdown. As a reasonable estimate, one can assume
that an organic anti-foam agent, a biocide (probably chlorine), chromate
and phosphate corrosion inhibitors, and sulfate from sulfuric acid pH control
may be present.
Cooling tower blowdown contribution to the total ash sluicing wastewater
amounts to 329 gpm (164,700 Ib/hr).
14.4.1.4 Contaminated Gas Liquor. Contaminated gas liquor, is received
at a rate of 329 gpm or 164,700 Ib/hr. The major identifiable components of
this stream are ammonia, phenols, and fatty acids. COD, IDS, chloride,
sulfide, sulfate, and fluoride are also present along with lesser amounts of
other materials. A possible stream composition is shown in Table 11-1.
14.4.1.5 Process Condensate. This flow of 1 gpm originates in the
final gas compression and drying stage. It contains a trace of glycol drying
agent, 0.05 percent. This equals a rate of 0.25 Ib/hr of glycol.
14.4.1.6 Utility Hater. Utility water originates from various un-
specified uses within the plant. These may range from cleanup of equipment
and spills to laboratory and sanitary drains. In addition, surface drainage
holding ponds will discharge as part of the utility water flow. Prior to
being delivered to the ash handling section, utility water is treated in API
separators for removal of oil. It is assumed that the major contaminants
which will be found in the utility water are small quantities of oil and sus-
pended solids, picked up from surfaces contacted prior to entering the
collection system. Most of the oil will be removed by the API separators.
The flow to the ash transport system, at 100 gpm or 50,100 Ib/hr may contain
at intervals as much as 100 ppm of oil. Solids content also will be variable
but generally at low levels, under 200 ppm.
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14.4.1.7 Wastewater Disposal. Four paths exist for water to exit the ash
dewatering area. These are: (1) as water vapor to the atmosphere from the
lump separator feed box vent, (2) by evaporation from the main evaporation
ponds, (3) by evaporation from the fine ash pond, and (4) as water entrained in
the wet ash.
The water stream from the feed box vent results from a water spray in-
troduced into the exhaust from the feed box to contain fugitive dry ash and
droplets of slurry. Since the ash is transported wet, the possibility of dry
ash entrainment is remote, and scrubbing would primarily remove slurry droplets,
A droplet separator or demister is proposed to remove final mist from the
exhaust. No significant discharges of either solid particles or liquid drop-
lets are expected in this stream.
The primary exit of wastewater from this plant is by evaporation from the
main evaporation pond. This pond is 40 acres in area and receives 901 gpm or
451,000 Ib/hr of water from the thickener overflow. To maintain equilibrium,
evaporation must occur at a rate of 0.005 gallons per minute per square foot.
This water will contain some portion of all constituents of the entering
component streams, as well as components leached from the ash during use as
transport water. Components of the ash transport water are listed in Table 14-
9.
Two phenomena may occur during ash transport by the water. These are the
leaching of components of the ash into the transport water and the removal of
constituents present in the water by the ash. Depending upon the rates of
these processes the resulting thickener overflow stream may be of higher or
lower quality then stream 14.27.
An indication of the potential for leaching constituents from the ash
may be obtained from Table 14-10. This data was obtained from coal burning
power plants, using hydraulic ash transport systems. '
- 191 -
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"Table 14-9. INLET ASH TRANSPORT WATER, NET COMPOSITION
Components Rate
Ib/hr Percent
Total Solids (dissolved and suspended) 9,000
S04, Cl , H2S, CN
Na, Ca, Mg,' Fe
NH,
540
662
35
Organics (oils, fatty acids, phenols,
and glycol ) 135
Total Stream Flow 622,400
1 .4
0.9
0.10
56 ppm
0.02
Table 14-10. COMPONENTS OF ASH TRANSPORT WATER
Ash Transport Ash Trai sport Settled Ash
SLOWDOWN SLOWDOWN Transport Water
Consti tuent
BOD5
COD
Chromi urn
Chromium + 6
Copper
Cyanide (Total )
I ron
Nickel
Oil and Grease
Phosphate (Total)
Zinc
Total Solids
Dissolved Solids
Suspended Solids
(1) Source: Development Document for Pretreatment Standards
The Steam Electric Power Generating Industry, Hittman
Associates, Inc., Unpublished.
EXAMPLE 1
3.0
1235.0
0.37
0.030
0.16
0.005
76.0
0.24
1 .0
3.4
0.55
1532.0
388.0
1144.0
EXAMPLE 2
1 .2
290.0
0.12
0.009
0.20
0.112
6.2
0.03
1 .0
0.02
0.08
3545.0
1894.0
1651 .0
1 .0
43.1
0.02
0.011
0.2
0.012
0.33
0.03
1.0
0.02
0.02
3050.0
2980.0
70.0
- 192 -
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14.4.2 Potential Effluents
The El Paso design has no aqueous effluent return to the San Juan River.
All water which is not reused is disposed of by evaporation. The two ponds
used for this handle a total of 1,052 gpm or 526,700 Ib/hr. Thickener under-
flow carrying approximately 25% solids is settled in the fine pond from which
151 gpm or 75,600 Ib/hr of water is estimated to evaporate (periodic solids
removal will be needed). The main effluent from the thickener, the overflow,
goes to the main evaporation pond. Evaporation at a rate of 901 gpm or
475,100 Ib/hr will be required to maintain equilibrium.
14.4.2.1 Major Pollutants. In the proposed system the major pollutants
capable of producing damage are dissolved solids and organics (phenols, oils,
tars, and solvents).
It has been claimed that use of wastewater to transport ash results in
lowered organic contents. This is indicated by SASOL. Adsorption of organic
components may in fact occur but this requires substantiation. If this is
an effective treatment the organic residues may then become a potential solid
waste disposal problem.
An opposite effect, leaching components from the ash is a probable source
of additional dissolved solids loading in the streams to the evaporation ponds.
Because the mineral matter discharged from Lurgi gasifiers has not been sub-
jected to temperatures above the ash fusion point and because in addition it
has been exposed while hot to an oxidizing atmosphere, it is possible that
reactive metal oxides may be present. Upon contact with water these could
form soluble hydroxides and potentially cause additional leaching of other
metals.
The major components of particular concern are the alkali metals. These,
if leached, may raise the pH, and further leach other trace elements from the
ash. The entire question of ash Teachability requires definitive study.
- 193 -
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14.4.2.2 Trace Constituents. As with major pollutants, the trace constituents
of concern will be dissolved solids and organics.
Trace elements leached from the ash or having originated from contaminated
streams to the ash sluiceway will include any or all of those present in the
coal.
Traces of ammonia and sulfide will be present in the water. Cyanide may
be present in trace amounts as well.
Trace organic components other than the major organics will include 0.25
Ib/hr of glycol. Depending on the degree of adsorption of organics by the
ash the total organic contribution may be reduced to a trace level.
14.4.3 Control Methods
14.4.3.1 Proven Methods. The control of wastewater effluents provided
for this plant consists of a no discharge design. Evaporation is the only
means for water to be removed from the system. If total containment of the
contaminated water is achieved, this can be considered a proven method.
A secondary exit of water from the plant is by evaporation from the fine
ash pond. This receives underflow from the thickener. Solid content has been
estimated at 25 percent. The rate of evaporation is shown as 151 gpm. Based
on a 13 acre area, the evaporation rate if 0.0003 gallons per minute per
square foot or 0.13 pounds per hour per square foot. The same considerations
apply to the water entering this pond 75,600 Ib/hr, however, 25,200 Ib/hr
of solids are carried with that water. Periodically these solids will require
removal and ultimate disposition. Assuming that the net solids contain 10
percent moisture when removed from the fine ash pond, an average rate of
27,700 Ib/hr of material (consisting of 25,200 Ib of solid ash and 2,520 Ib
of water) must be disposed of to the wet ash conveyor.
The wet ash conveyor then receives from the ash collection system 450,800
Ib/hr of ash with 93,500 Ib/hr water, and 7,500 Ib/hr (dry) lime sludge and
from the fine ash pond 25,200 Ib/hr of ash with 2,520 Ib/hr water. Thus, a
total of 96,000 Ib/hr water contained in 483,500 Ib/hr of solids (476,000 Ib/hr of
- 194 -
-------
ash and 7,500 Ib/hr of lime sludge) is delivered by the ash conveyor to the
ash handling area.
Total containment requires no release of wastewater; however, two
potential escape routes from the impoundments exist. One such route is by
accidental breaching of the pond barriers either through overflow or by
physical damage to the dikes. Such releases would be readily observed and
could be limited in extent by appropriate emergency measures.
Of more potential danger is the possibility of permeation of con-
taminated water through the evaporation pond bottom. Leaks through the
bottom would expose groundwater in the area to all dissolved components in
the pond and under extreme conditions could potentially transport solids as
well.
Proper construction of the ponds will alleviate these two possible
sources of unintentional pollutant releases. Sizing the ponds to permit
evaporation at the required rate will be necessary. Incorporation of an
impervious liner in the main evaporation pond will be necessary to assure
leak proof conditions for the pond life. In addition, the fine ash pond
must be constructed to permit periodic solids removal. Finally, at the
termination of the operation, permanent stabilization of the residues --
precipitated and settled solids -- will be needed. Site geography and
climate will have an overpowering effect on design criteria.
14.4.3.2 Potential Methods. Water entering the evaporation ponds is
expected to have a possibly high COD. Pretreatment to reduce the organics
loading may be an effective method of preventing subsequent development of
offensive odors. As previously indicated, the unresolved effectiveness of
ash as a absorbent for organic constituents may reduce this potential problem.
14.4.4 Process Modifications
Potential process modifications are treatment of the streams entering
the ash handling system to remove organics, or the introduction of a full
treatment system with reuse of its effluent. The cost, benefits, and effective-
ness of such modifications need to be evaluated.
- 195 -
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- 196 -
-------
15. SOLID WASTES
15.1 STREAM FLOWS
15.1.1 Ash Dewatering Transfer
Figure 15-1 is a schematic flow diagram of ash dewatering and
transfer facilities. These facilities will be designed to handle all of
the ash discharged from the air blown and the oxygen blown gasifiers.
Ash will be discharged dry and hot from the individual gasifier ash
locks into a sluiceway. Water flowing in the sluice launder will quench
and transfer the ash to classification and dewatering equipment. The
coarse dewatered ash will be transferred on a belt conveyor to the mine
ash handling area for disposal in the mine.
Fine ash from the classification step and the main water stream
will be sent to a thickener. The underflow containing the ash fines
will be sent to a fine-ash pond. The El Paso document does not indicate
what disposition is to be made of the fine ash in the pond nor at what
frequency but accumulation may be some 12.5 tons/hr. It may be necessary
to remove fine ash on a fairly regular if not continuous basis from the
fine ash pond and send it to the mine along with the wet ash stream.
Major component and trace element flow rates for the dry ash to this
area were given in Tables 4-5 and 4-8, Chapter 4, and Tables 5-4 and 5-6,
Chapter 5. Total flows are given in Table 15-1.
15.1.2 Mine Ash Handling
Figure 15-2 shows the mine ash handling area and Table 15-1 defines
the inlet and outlet streams.
- 197 -
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LIME TREATER SLUDGE 216 GPM
SLOWDOWN
268GPM
COOLING TOWER SLOWDOWN
329GPM
CONTAMINATED GAS LIQUOR
329 GPM
PROCESS CONDENSATE I GPM
UTILITY WATER
100 GPM
AIR 8 VAPOR
DROPLET SEPARATOR
EXHAUST FAN
DRY ASH
DRY ASH FROM FROM FUEL
GAS PROD. GASPROD.
SLUICE LAUNDER
LUMP SEPARATOR
\ ASH CONVEYOR
ASH COLLECTION CONVEYOR
ATM
151 GPM EVAPORATION
27.700 L8./HR
FINES THICKENER
FINE ASH POND
EVAPORATION PONDS 901 GPM
79,560 LB/HR.
ET ASH
DRAWING NOTES
Figure 15-1. FLOW SCHEME FOR THE ASH DEWATERING AND TRANSFER SECTION
-------
REFUSE
ASH TRUCK
LOADING BIN
MINE ASH HANDLING
DRAWING NOTES
Figure 15-2. FLOW SCHEME FOR THE MINE ASH HANDLING SECTION
-------
Table 15-1. MINE ASH HANDLING
Stream No.
Ui
Refuse from coal 15.5
Handling & Preparation
Wet Ash from Ash 15.6
Transfer Sytem
Control Ultimate
itity, Ib/hr Constituents & Concentration Methods Discharge
Known
140,000 NR
579,500 NR
719,500
Stone
Dirt
Coal
Ash
Coal
Water
Sludge
Potential
-
- 47,600
- 96,000
- 7,500
ro
o
o
OUT
Refuse and wet ash
Water (runoff and
seepage) AD
15.7
15.8
719,500
NR
NR
Ponding
Return to mine
Evaporation
NR = Not Reported in El Paso Document.
AD = Added by Hittman Associates, Inc.
-------
Inlet Streams. Facilities in this area are designated to receive the
wet ash, 572,000 Ib/hr, from ash dewatering and transfer, and the refuse,
140,000 Ib/hr from coal fines cleaning. These materials are transported by
belt conveyors. The wet ash and refuse will discharge from the belt conveyors
either into the ash truck loading bin or be transferred by another conveyor to
the ash pile for intermediate storage. Wet ash and refuse will be received on
a continuous basis in the area.
Outlet Streams. Table 15-2 lists the component and trace element
analyses of the dry ash. The wet ash and refuse will be hauled by truck
to the mine disposal area on a 10 shift per week schedule. The reclaim
conveyor will transfer ash and refuse from the pile to the truck loading bin.
15.2 POTENTIAL EFFLUENTS
15.2.1 Major Pollutants
There may be particulate emissions produced where the hot (200°F+) ash
enters the sluice launder. If a closed transfer system is used this will be
negligible.
The major solids effluent of course is that contained in the wet ash,
whose composition and quantity is given in Table 15-2.
15.2.2 Trace Constituents
Ash Dewatering and Transfer. Trace constituents contained in the dry
ash streams entering this area are shown in Table 15-2. Most of these con-
stituents will probably leave this area in the wet ash stream.
- 201 -
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Table 15-2. COMPONENT ANALYSIS OF DRY ASH
Coal: Ib/hr wt.%
carbon 18,186 3.8
hydrogen 1,330 0.28
nitrogen 315 0.066
sulfur 255 0.053
oxygen 3,753 0.785
Ash (Dry Basis) :
Si02 281,003 58.953
A1203 113,308 23.7
Fe203 22,664 4.7
CaO 17,676 3.7
MgO 4,079 0.85
K20 3,625 0.76
Na20 6,798 1.4
Ti02 4,079 0.85
Trace Elements:
Sb 0.910 1.9X10"4,,
As 1.226 2.56x10"^
B 209.490 4.0x10-2
B'r 2.960 6.19xlO~4
Cd 0.317 6.6x10-5
F 663.080 1.38x10- '
Pb 5.680 1.2xlO-3
Hg 0.232 4.85x10-5
Ni 45.334 9.5x10-3
Zn 40.990 3.6x10-3
- 202 -
-------
Mine Ash Handling. Potential trace constituents in the ash and in water
that may separate from the wet ash include, Sb, As, B, Br, Cd, F, Pb, Hg, Ni,
and Zn.
15.3 CONTROL METHODS
15.3.1 Proven Methods
Ash Dewatering and Transfer. No control methods are indicated in the
El Paso document for solid effluent controls except for ponding of the
underflow from the fines thickener. However, as stated above, the estimated
rate of accumulation of fines is some 25,200 Ib/hr.
Mine Ash Handling. No planned pollution control methods are described
in the El Paso document. It merely states that ash will be transported by
truck to the mine disposal area.
15.3.2 Potential Methods
Ash Dewatering and Transfer. Solids collected in the fine ash pond
could probably be sent to the mine ash handling are via the wet ash conveyor.
Mine Ash Handling. Some steps that might be taken are:
• provide drainage troughs to collect water that separates from
the wet ash being trasnported on conveyors.
• put the stored wet ash in lined areas (pits depressions) and
collect runoff (from both precipitation and seepage).
• treat the wastewaters from the above two steps.
- 203 -
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15.4 PROCESS MODIFICATIONS
15.4.1 Ash Dewaterinq and Transfer
Provide for fine ash transfer from the fine ash pond to the wet ash
conveyor.
15.4.2 Mine Ash Handling
Provide for ash storage silos instead of the ash pile, which will
eliminate any runoff from the ash pile and will also prevent any carryover
of ash to the atmosphere by wind. However, the silos can be expensive and
require an economic evaluation.
- 204 -
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16. STEAM AND POWER GENERATION
The steam and power generation section is responsible for the generation
of electricity, steam and motive power for use in the other processing areas
of the plant. Included in the steam and power generation section are the
operations of fuel gas cooling, treating and combustion.
16.1 STREAM FLOWS
The process flow scheme and the material balance for the steam and power
generation section for the coal gasification plant are shown in Figures
16-1 and Table 16-1, respectively. Raw fuel gas from the fuel gas production
section is first cooled in a two-stage cooling operation (air followed by cooling
water). The condensate or oily gas liquor produced as a result of this cooling
operation is sent to the plant by-product recovery section for recovery of tars,
tar oils, phenols and ammonia. Also, a slipstream of the cooled fuel gas is
sent to the fuel gas production section for use as coal lock pressurizing gas.
The main portion of the cooled fuel gas stream is directed to the fuel gas
treating area where it is contacted countercurrently with regenerated Stretford
solution from the by-product recovery section. The Stretford solution, after
removing the bulk of the fuel gas H2S content, is recycled to the by-product
recovery section. Section 12 gives a detailed description of the operation of
the Stretford process. The resulting desulfurized fuel gas is split into two
streams, one going to the methanation section while the larger portion is
directed to the gas turbines.
The power generation facilities include fuel gas-fired gas turbines which
drive compressors and electrical generators, while the steam generation facili-
ties consist of waste heat boilers associated with the gas turbines and a fuel
gas-fired steam superheater. The combustion gases from these units are
discharged directly to the atmosphere. Demineralized water from the plant raw
water treatment section is used as boiler feed water, while the blowdown from
the boilers is used as plant cooling system makeup water.
- 205 -
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fV>
CD
TREATED FUEL GAS
EXPANDED FUEL GAS
COAL LOCK
PRESSURIZING GAS
RAW
FUEL GAS AIR COOLER
oo
OILY GAS
LIQUOR
LEAN
rRETFORD
DLUTION
BOILERS
&
TURBINES
STEAM
SUPERHEATER
STACK GAS
QAS TURBINE
j- &
BOILER STACK
GAS
RICH
—*- STRETFOHD
SOLUTION
AIR
AIR
DRAWING NOTES
1) TOTAL COOLING WATER
HEAT DUTY~76X106 BTU/HR
2) 1150 PSIG SUPERHEATED
STEAM GENERATED =
1.002.290 LB/HR
3) 550 PSIG SUPERHEATED
STEAM GENERATED=
1.652.420 LB/HR
4> 15 PSIG SUPERHEATED
STEAM GENERATED^
14.S80 LB/HR
51 TOTAL BOILER SLOWDOWN^
10.270 LB/HR
Figure 16-1. FLOW SCHEME FOR THE STEAM AND POWER GENERATION SECTION
-------
Table 16-1. MATERIAL BALANCE FOR THE STEAM AND POWER GENERATION SECTION
Stream Number
t
Stream Description
Units. lb/l>r
Component Molecular wt.
CO? ' 44.1110
CO 28.010
CH« 16.042
II2S 34.082
C2IU 28.052
Cjlls 30.068
S2 28.016
llj 2.016
II, n 18.016
Naphtha 78.108
Tat Oil 132.196
Tnr 184.354
Phenol 94.108
NH, 17.032
SO; 64.066
NO 46.008
02X 32.000
Total, Ib/hr
Temperature, *F
Pressure, psla
lfi.1
Raw Fuel
CMS
252,981
182,487
30,432
2.951
2,618
4,261
402,901
17,510
158,631
4,308
6,022
1,568
1,963
3,771
-
-
1
1,072.404
280
260
16.2
Cooled
Fuel Gas
242,583
181,670
30,291
2,942
2,606
4,242
401,113
17.425
1.674
4,289
-
-
-
-
-
-
-
888.835
90
250
16.3
Oily Gas
I.I quot
9,317
8
6
-
-
-
-
4
156,950
-
6,022
1,568
1,963
3,771
-
-
-
179,609
90
250
16.4
Caal Lock
Prcssurlzlnt
Caa
1 ,081
809
135
13
12
19
1,788
77
7
19
-
-
-
-
-
-
-
3,960
90
250
16.5
Treated
Fuel C
-------
16.2 POTENTIAL EFFLUENTS
The effluent streams from the steam and power generation section include:
• Oily Gas Liquor
• Coal Lock Pressurizing Gas
0 Treated Fuel Gas
0 Combustion Gases
0 Boiler Slowdown
a Fugitive Emissions
The following sections discuss the pollutants contained in the above effluents.
The major pollutants are addressed in Section 16.2.1, while Section 16.2.2
discusses the trace constituents. For the purpose of this study, trace
constituents are assumed to ba those components originally entering the steam
and power generation section in trace quantities.
16.2.1 Major Pollutants
Before the presence of pollutants in effluent streams from the steam and
power generation section can be addressed, the pollutants present in the inlet
streams to the area must be identified. The three inlet streams to this area
are the raw fuel gas and the two air streams. While the latter two streams are
essentially pollution free, the raw fuel gas stream contains the following
major pollutants:
0 H2S, COS and other organic sulfur compounds
0 Naphthas
- 208 -
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• Tar Oil
• Tar
• Phenols
• NH3
The other major components of the raw fuel gas stream are considered to be
desirable constituents. The following sections discuss what is known about
the fate of these major pollutants in the steam and power generation section.
Oily Gas Liquor. The condensate streams formed as the raw fuel gas is
cooled are combined and directed to the by-product recovery section. This
condensate, or oily gas liquor, contains essentially all of the tars, tar oils,
phenols and ammonia originally present in the raw fuel gas stream entering the
steam and power generation section. Some C02, CO, CH,,, and H2 are also present
in the oily gas liquor. The percent composition of this liquid stream is shown
below.
Component Wt % Component Ut %
H20 87.4 NH3 2.1
C02 5.2 Tar Oil 3.3
H2 <0.1 Tar 0.9
CH4 <0.1 Phenol 1.1
CO <0.1
Tables 8-2 through 8-4 in Chapter 8 give further details on the compounds
that constitute the tars, tar oils and phenols.
Coal Lock Pressurizing Gas. The temperature of the gas leaving the final
fuel gas cooler is estimated to be approximately 90°F. At this temperature,
only negligible amounts of tars, tar oils, phenols and ammonia remain in the
gas phase. Therefore, since the coal lock pressurizing gas is withdrawn from
- 209 -
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Component
C2H6
N2
H2
H20
Naphtha
Vol %
0.4
38.5
23.0
0.2
0.1
this stream, it too has negligible quantities of these pollutants. However,
this stream does contain H2S, COS and other organic sulfur compounds since
these compounds are still present in the fuel gas stream. The percentage
composition of the coal lock pressurizing gas is shown below.
Component Vol %
C02 14.8
CO 17.4
CH* 5.1
H2S + COS 0.2
C2H^ 0.3
Treated Fuel Gas. A portion of the treated fuel gas is directed to the
methanation section for use in a gas expander that drives the product gas
compressors. The fuel gas contains some naphtha and a very small quantity of
sulfur compounds. Essentially all of the tars, tar oils, phenols and ammonia,
and a large majority of the sulfur compounds originally present in the raw fuel
gas are removed in upstream processing operations. The composition of this
treated gas stream is shown below.
Component Vol %
C02 14.8
CO 17.4
CH4 5.1
H2S + COS <0.1
0.3
Component
C2H6
N2
H2
H20
Naphtha
Vol %
0.4
38.5
23.2
0.2
0.1
Stack Gases. The steam superheater, gas turbine and boiler stack gases
contain combustion products such as S02, N0x, H20, C02, CO, hydrocarbons and air.
Because the fuel to these combustion operations is treated fuel gas, the
resulting stack gases contain negligible amounts of particulate matter. The
use of excess air tends to minimize the amounts of CO and hydrocarbons in the
stack gas. The anticipated compositions of the stack gases are shown in Table
16-2.
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Table 16-2. COMPOSITION OF STACK GASES
Component
C02
H20
02
S02
NOX
N2
Boiler Slowdown.
Steam
Superheater
Vol %
14.0
13.3
3.0
48 ppmv
24 ppmv
69.7
The boilers in the steam
Gas Turbines
+ Boilers
Vol %
5.5
5.9
13.7
20 ppmv
46 ppmv
74.9
and power general
use demineralized water for boiler feed water. This inlet water stream is
essentially free of all dissolved solids, except for small amounts of silicates.
To prevent scaling of the boiler tubes, a portion of the boiler water is removed
as blowdown. Since the boilers are operated at approximately 100 cycles of
concentration, the blowdown stream contains 100 times the inlet water concen-
tration of dissolved solids. However, because of the high purity of the inlet
stream., the blowdown is still relatively free of dissolved solids and is sent
to the plant cooling system for use as makeup water.
Fugitive Emissions. Fugitive emissions from the steam and power generation
section arise from leaks around valves, flanges, connections, etc. No estimate
of the quantity of fugitive emissions can be made, although high pressures like
those found in this section tend to increase the severity of the fugitive emis-
sion problem. Any of the materials present in the process streams found in this
section could be released as a fugitive emission.
16.2.2 Trace Constituents
The inlet gases to the steam and power generation section may contain any
of the trace elements present in the coal feed to the gasification section
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(see Section 4). Prediction of the fate of these trace elements is complicated
by a lack of knowledge regarding the chemical form in which they exist, i.e.,
as oxides, hydrides, sulfides, etc. It is anticipated that as the gases are
cooled, certain trace elements will be removed from the gas phase. Some of
the more volatile trace elements such as mercury, bromine, chlorine, fluorine,
selenium and tellurium may be retained in the gas phase. Less volatile trace
elements might have a higher likelihood of being found in the condensates
produced during the cooling operations. Exact quantification of the trace
element distribution in the effluent streams from the gas cooling section cannot
be made at this time, however. The trace elements found in the condensate
streams from one commercial Lurgi coal gasification facility were given in
Table 7-2. Trace element balances for the gas liquor streams were calculated
for the El Paso feed coal composition and given in Tables 4-9, 4-10, 4-11, 5-7,
and 5-8
Trace elements may also be present in the combustion gases leaving the
steam and power generation section. For the same reasons mentioned in the
previous paragraph, no definitive statement can be made as to which trace
elements, if any, may be present in these effluents.
It is anticipated that the combustion gases will contain unburned hydrocar-
bons and carbon monoxide. However, since the data on the combustion character-
istics of the fuel gas are limited, no estimates are given for the quantities
of these pollutants.
16.3 CONTROL METHODS
16-3.1 Proven Methods
Oily Gas Liquor. The contaminated condensates generated during the cooling
operations in this section are sent to the by-product recovery section for
removal and recovery of tars, tar oils, phenols, ammonia and dissolved gases.
These operations are discussed in detail in Section 11.
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Coal Lock Pressurizing Gas. A slipstream from the cooled fuel gas
stream is used to pressurize the coal locks in the gas production area. Since
this stream contains sulfur compounds and naphtha, provisions must be made
in the fuel gas production area to contain and recycle essentially all of the
lock gas. Section 6 discusses in detail the operation of the coal locks
and the emissions resulting from their use.
Treated Fuel Gas. A portion of the treated fuel gas stream is sent
to the methanation section wherein the energy content of the fuel gas associated
with its high pressure is utilized to drive the product gas compressors. The
operation of these compressors is discussed in Section 10.
Combustion Gases. The gases resulting from the combustion of fuel gas
in the steam and power generation section contain only very minimal amounts
of pollutants since sulfur compounds, ammonia, and heavy hydrocarbons are
removed from the fuel gas prior to combustion. The combustion gases are
discharged directly to the atmosphere.
Boiler Slowdown. The blowdown streams from the boilers are collected
and used as makeup water to the plant cooling system. The dissolved solids
content of these blowdown streams is relatively low and does not represent
an environmental problem. No other pollutants are anticipated to be present
in the blowdown streams.
Fugitive Emissions. Fugitive air emissions are inevitable in any process
which contains fittings, valves, flanges, etc. The high pressures encountered
in the stream and power generation section tend to increase the likelihood
of having fugitive emissions. While fugitive emissions cannot be completely
eliminated, the use of best-available technology such as mechanical seals
on pumps can help to minimize these emissions. Good maintence practices also
help to minimize fugitive emissions.
16.3.2 Potential Methods
The control methods just discussed in the previous section provide
adequate control of the contaminants present in the effluents from the steam
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and power generation section. As is evident by this discussion, many
of the control methods are actually other processing areas of the plant.
Because of this consideration, effluent control alternatives are not discussed
in detail here, but reference is made to the process modification sections
of other appropriate chapters of this report for detailed examination of
alternative controls.
16.4 PROCESS MODIFICATIONS
16.4.1 Fuel Gas Cooling
Potential process modifications to the fuel gas cooling area of the
steam and power generation section are constrained by the requirements of
downstream processing units. It is thus difficult to envision a process
modification in the cooling area that would simultaneously fulfill the process
requirements and have a significant impact upon the process effluents.
16.4.2 Fuel Gas Treating
The fuel gas treating area of the steam and power generation section is
designed to remove sulfur compounds from the cooled fuel gas. There are many
commercial processes capable of removing essentially 100% of the sulfur com-
pounds from gas streams. Some of these systems are listed in Table 16-3.
In conjunction with the discussion in Section 9.4, the Rectisol II process
is addressed here as a potential process modification to the fuel gas treating
area.
The operation of the Rectisol II process is based on the different solu-
bilities of various gases in cold methanol. The solubility of C~+ hydro-
carbons, H2$, COS, organic sulfur compounds and C02 in methanol is significantly
greater than the solubility of the valuable gaseous constituents such as CO,
H2, CH^, C2H4 and C^ (see Figure 9-1). Thus, the Rectisol II process is
capable of absorbing contaminants from a gas stream while removing only minor
portions of the desirable gases.
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Table 16-3. COMMERCIALLY AVAILABLE ACID GAS REMOVAL PROCESSES
Physical Solvent Processes Direct Conversion
Rectisol Manchester
Purisol Perox
Estasolvan
Fluor Solvent Fixed-Bed Adsorption
Selexol Haines
Molecular Sieve
Chemical Solvent
MEA Catalytic Conversion
DEA Holmes-Maxted
MDEA Carpenter-Evans
DIPA
DGA
Glycol - Amine
Ben field
Catacarb
Chemical/Physical Solvent
Ami sol
Sulfinol
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As indicated in the discussion of the Rectisol II process in Section
9.4, the methanol leaving the second stage of the main absorber is rich in
CCL but very lean in HLS, COS and other organic sulfur compounds. By using
a portion of this CCL-rich methanol stream, the cooled fuel gas can be treated
for removal of sulfur compounds, without simultaneously removing CCL and the
valuable gases. It is undesirable to remove CCL since the fuel gas is used
in a gas turbine.
Stream Flows. The process flow scheme and the material balance for the
portion of the Rectisol II process associated with the fuel gas treating area
of the steam and power generation section are given in Figure 16-2 and Table
16-4 respectively. Cold methanol (-50°F) from the gas purification section
is split into two streams; one stream is sent to the prewash column while the
other stream is sent to the main absorber. In the prewash column, naphtha
and water as well as any residual ammonia and heavy hydrocarbons in the cooled
fuel gas stream are absorbed. The methanol from this column goes to the pre-
wash flash column where the least soluble gases are desorbed by reducing the
stream pressure to atmospheric. The prewash flash overhead stream will con-
tain some H2S, COS and other organic sulfur compounds and is directed to the
plant by-product recovery section where the sulfur compounds are converted
into and recovered as elemental sulfur. The flashed methanol from the prewash
flash is returned to the gas purification section for further treatment.
The overhead from the prewash column is sent to the main absorber where
it is contacted with additional cold methanol for removal of H_S, COS and
other organic sulfur compounds. Depending on the operation parameters of this
absorber, essentially all of the sulfur compounds can be removed. The de-
sulfurized fuel gas exits the top of the absorber while the CO^- and hLS-rich
methanol from the bottom of the absorber is returned to the gas purification
section for regeneration.
Process Effluents. The only true effluent from the above described
Rectisol II process is the prewash flash overhead stream. As mentioned
previously, this stream contains sulfur compounds and is directed to the
plant by-product recovery section for treatment. The anticipated composition
of this stream is shown below.
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FROM
RECTISOL 2
MAIN
~~AD"SORBER~
LEAN H2S QAS
TREATED
FUEL QAS
REF
PREWASH
PREWASH
FLASH
ABSORBER
TO NAPHTHA
SEPARATOR
IN GAS
PURIFICATION
SECTION
TO H2S FLASH
IN GAS
PURIFICATION
SECTION
DRAWING NOTES
Figure 1-6-2. FLOW SCHEME FOR THE FUEL GAS TREATING AREA - RECTISOL II PROCESS
-------
Table 16-4. MATERIAL BALANCE FOR RECTISOL II H2S REMOVAL PROCESS
Stream Number
Stream Description
Gas Phase, Ib/hr
Component Molecular wt.
C02 44.010
H2S ' 34.082
C2H4, C2H6 29.262
CO 28.010
H2 2.016
CHi, 16.042
N2 28.016
Methanol 32.042
Total Dry Gas, Ib/hr
Liquid Phase, Ib/hr
Component Molecular wt.
H20 18.016
Naphtha 78.108
Methanol 32.042
Total Liquid, Ib/hr
Temperature, °F
Pressure, psia
16-1
Cooled
Fuel
Gas
242,583
2,938
6,847
181,670
17,429
30,290
401,114
882,871
1,674
4,289
5,963
-50
265
16-2
Low-Btu
Product
Gas
306,526
7,768
181,836
17,461
30,924
400,803
945,318
-
35
265
16-3
Lean H2S
From
Flash
238
14
3
9
3
6
273
-
32
14.7
- 218 -
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Component Vol % Component Vol %
C02 81.4 H2
H2S 6.2 CH4 2.8
C2H4,C2H6 1.6 N2 3.2
CO 4.8
The methanol streams exiting the bottom of the prewash flash column and
the main absorber are returned to the gas purification section for removal
of absorbed constituents.
16.4.3 Fuel Gas Combustion
The fuel gas combustion area of the steam and power generation section
is designed to utilize both the pressure and the heating value of the fuel
gas to provide steam, electricity and motive power for the gasification plant.
The use of alternate process equipment in this area would have only minimal
impact on the environmental aspects of the combustion effluents. However,
a potentially viable process modification involves the use of fuels other
than treated fuel gas.
Since the Lurgi coal gasification process produces by-product tars and
tar oils, it may be feasible to use these heavy hydrocarbons to supply all
or a portion of the fuel requirements of the plant. Direct burning of coal
or coal fines generated in the coal pretreatment operations is also potentially
viable alternative.
The main disadvantage to the use of tars, tar oils or coal as a fuel
source is the need to treat the resulting combustion gases since all of these
fuel sources may contain significant quantities of sulfur. In addition, if
coal is used, provisions must be made for controlling the emission of
particulate matter. Before any of these alternatives are used, a careful
analysis of the economic and environmental considerations of each alternative
must be undertaken.
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- 220 -
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17. OXYGEN PLANT
17.1
STREAM FLOWS
Oxygen requirements are 470,640 Ibs/hr or approximately 5600 tons/day.
The oxygen is produced by direct separation from air in three identical trains
In each train air flows through a heat exchanger to an air compressor which
compresses the air to 85-90 psig. Moisture in the air is condensed and made
available for process use. The quantity of condensate water will be highly
variable, depending upon the relative humidity of the incoming air. The El
Paso design removes approximately 3500 Ib/hr of water. After compression,
the air enters the cryogenic box and is separated into oxygen and nitrogen
by distillation. The oxygen stream will contain approximately 98% oxygen
and 2% nitrogen and argon. This stream is compressed to 500 psig and sent to
the Lurgi gasifiers. The nitrogen stream contains approximately 429 ppm C0~,
0.2% H20, 0.9% 02 and 99% N^6'. This stream is vented directly to the
atmosphere except for perhaps 265 tons/day utilized in the gasification
plant ^ . A schematic flowsheet is given in Figure 17-1. The material
balance is given in Table 17-1.
Table 17-1. MATERIAL BALANCE FOR THE OXYGEN PLANT
Stream
Component
No
17.1
Ibs/hr
1,978,854
17.2
Ibs/hr
406,663
17.3
Ibs/hr
17.4
Ibs/hr
1,540,187
17.5
Ibs/hr
21,728
17.6
Ibs/hr
17.7
Ibs/hr
17.8
Ibs/hr
Ar
599,008 123,100 406,365 15,336 216
10,275
16,098 2,586 9.856 139 900,000 3,517 4,000,000
TOTAL 2,593,960 532,349 470,640 1,565,379 22,083 900,000 3,517 4,000,000
Compressors can be driven by steam or by gas turbine. Steam requirements
are on the order of 900,000 Ib/hr
(2)
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COOLING
WATER
AIR,
FILTER
1 ^
*
COMPRESSION
i — i
it
CONDENSATE / '
-«^ f IT •
rS
COOLING
WATER
DISTILLATION
LIQUID
PRODUCTS
HEAT EXCHANGE
AND PURIFICATION
OXYGEN
TO GAS1FIERS
COOLING
COMPRESSION
AIR TO FUEL GAS
»-
PRODUCTION
WASTE
PLANT
DRAWING NOTES
Figure 17-1. FLOW SCHEME FOR THE OXYGEN PLANT
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17.2 POTENTIAL EFFLUENTS
No chemical reactions take place in the air separation process and no
chemicals are added to the process streams. Therefore there does not appear
to be any potential for atmospheric pollution. The nitrogen vent stream
merely returns to the atmosphere the major part of the air intake stream with-
out any chemical alteration of the components.
Condensate water removed from the air stream will be supplied to the
plant water system as high quality water. Steam condensate will be returned.
Thus no environmental pollutants are expected. A cooling water requirement
of 8,000 gpm (15°F rise) must be considered when analyzing drift from
cooling towers as a pollutant.
In summary, there does not appear to be any significant pollution
potential involved with the oxygen production plant itself. Oxygen plant
design will indirectly influence overall gasification plant emissions through
the choice of power to drive the compressors. Trade-offs can be made between
steam'turbine, gas turbine and electric drivers. The choice should be made
on the basis of overall plant steam and power balances.
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TECHNICAL REPORT DATA
(Please read laurucriom on the reverse before completing
1. REPORT NO.
EPA-600/7-77-057
2.
3. RECIPIENTS ACCESSION-NO.
SUBTITLE g valuation of Background Data
Relating to New Source Performance Standards for
5. REPORT OATS
June 1977
Lurgi Gasification
6. PERFORMING ORGANIZATION CODE
7. AUTHOH(S)
J.E. Sinor (Editor)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
10. PROGRAM ELEMENT NO.
Cameron Engineers, Inc.
1315 South Clarkson Street
Denver, Colorado 80210
EHE623
11. CONTRACT/GRANT NO.
68-02-2152, Task 11
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 9/76-2/77
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES IERL-RTP task officer for this report is William J. Rhodes,
Mail Drop 61, 919/549-8411 Ext 2851.
16. ABSTRACT ,
The report contains information on expected emissions from a large coal
gasification complex based on Lurgi technology. Use of best available control tech-
nology was assumed and two different schemes for sulfur removal were examined.
The coal gasification plant was divided into 15 sections: each section is discussed in a
separate chapter. Areas were identified in which projected emissions data were
deemed inadequate for evaluation environmental impact. No major data gaps or incon-
sistencies were found, but more and better information is needed concerning effluents
resulting from the venting of pressurization gas from the coal feed lock hoppers.
This part of the plant is a potential source of significant quantities of pollutant emis-
sions, particularly carbon monoxide. Desirable information presently lacking in
other areas is summarized.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS C. COSATI Field/GfOUS
Air Pollution
Coal Gasification
Emission
Desulfurization
Carbon Monoxide
Performance
Air Pollution Control
Stationary Sources
Lurgi Process
New Source Perfor-
mance Standards
13B
13H
07A.07D
07B
3. CISTRI3UTION STATEMENT
Unlimited
19. SECURITY CLASS
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