EPA450/3-75-029
October 1974
DEVELOPMENT OF INFORMATION
FOR STANDARDS
OF PERFORMANCE
FOR THE
FOSSIL FUEL
CONVERSION INDUSTRY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air unil Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA450/3-75-029
DEVELOPMENT OF INFORMATION
FOR STANDARDS OF PERFORMANCE
FOR THE FOSSIL FUEL CONVERSION
INDUSTRY
by
B . Kim, J. M. Genco,
J. Oxley, and P . Choi
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Contract No. 68-02-0611
Task 7
EPA Project Officer: William Herring
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
October 1974
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NOTICE
This document includes technical information and recommendations submitted
by the Contractor to the United States Environmental Protection Agency (EPA)
regarding the subject industry. The report, including the recommendations,
will be undergoing extensive review by EPA, Federal and State agencies,
public ihterest organizations , and other interested groups and persons . The
report and in particular the Contractor's recommended standards of perfor-
mance are subject to change in any and all respects. Mention of company
or product names is not to be considered as an endorsement by the Environ-
mental Protection Agency.
The regulations to be published by EPA under Section 111 of the Clean Air
Act of 1970 will be based to a large extent on the report and the comments
received on it. However, EPA will also consider additional pertinent
technical and economic information which is developed in the course of
review of this report by the public and within EPA. Upon completion
of the review process , and prior to final promulgation of regulations, an
EPA report will be issued setting forth EPA's conclusions concerning the
subject.industry and standards of performance for new stationary sources
applicable to such industry. Judgments necessary to promulgation of
regulations under Section 111 of the Act, of course, remain the responsi-
bility of EPA. Subject to these limitations, EPA is making this report
available in order to encourage the widest possible participation of interested
persons in the decision-making process at the earliest possible time.
This report shall have standing in any EPA proceeding or court proceeding
only to the extent that it represents the views of the Contractor who studied
the subject industry and prepared the information and recommendations.
It cannot be cited, referenced, or represented in any respect in any such
proceedings as a statement of EPA's views regarding the subject industry.
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are avail-
able free of charge to Federal employees, current contractors and grantees,
and nonprofit organizations - as supplies permit - from the Air Pollution
Technical Information Center, Environmental Protection Agency, Research
Triangle Park, North Carolina 27711; or, for a fee, from the National
Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia 22161.
Publication No. EPA-450/3-75-029
11
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TABLE OF CONTENTS
Page
INTRODUCTION 1
SUMMARY ป_ ^ 2
Coal Preparation 2
Fuel Gas Purification 2
Sulfur Recovery 4
Treatment of Glaus-Plant Tail Gas 4
Other Sources of Sulfurous Emissions . 5
COAL GASIFICATION TECHNOLOGY 6
Classification of Gasification Processes 6
Present Status of Gasification Technology 7
Selection of Coal Gasification Processes 7
Categorization of Gasification Process as Air Pollutant
Emission Source . 8
DESCRIPTION OF SELECTED COAL GASIFICATION PROCESSES AND
EMISSIONS OF SULFUROUS GASES 8
Lurgi Process (High-Btu SNG) 9
Synthane Process 17
Hygas Process (High-Btu SNG) 26
C02-Acceptor Process (High-Btu SNG) 44
Lurgi Process (Low-Btu Gas) 57
Koppers-Totzek Process (Low-Btu Gas) 62
SULFUROUS EMISSION CONTROL PROCESSES 73
ACID GAS REMOVAL PROCESSES 75
Physical Solvent Processes 75
Amine Processes 84
iii
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TABLE OF CONTENTS (Continued)
Alkaline Salt Solution Processes. ' ... ' 88
Utilities Requirements. . . 92
SULFUR RECOVERY PROCESSES. .............. i. . 98
Claus Process ................. 98
Stretford Process . . . . 103
Giammarco-Vetrocoke Processes . . ... . . . . . . 105
Utilities Requirements 106
TREATMENT OF CLAUS PLANT TAIL GAS . .-'. ... . . . .. 108
Beavon Process. ..... 108
Cleanair Process. . . . . . . . . . . . . . . . . ... .. . . HI
IFP-1 Process ...................... . . HI
SCOT Process 112
Sulfreen Process H4
Wellman-Lord Process H4
Utilities Requirements. 114
CONCLUSIONS. H8
Coal Preparation. . ......... 118
Fuel Gas Purification . . . . . . . . . . . '... ........ 118
Sulfur Recovery 122
Treatment of Claus Plant Tail Gas .............. 124
Other Sources of Sulfurous Emissions. . 124
Supplementary Information . . . ... .. . .. 126
REFERENCES .... . 127
iv
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TABLE OF CONTENTS (Continued)
Page
APPENDIX A
INDUSTRY STRUCTURE ............... A-l
APPENDIX B
INDUSTRY EXPERTS AND POTENTIAL ATTENDANTS FOR -
INDUSTRYWIDE MEETING ... . . . B-l
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LIST OF TABLES
Table 1. Design Basis for Lurgi Process for the .
Manufactur of High-Btu SNG by El Paso
Natural Gas 12
Table 2. Sulfur Balance Around Rectisol Unit for
Desulfurization of High-Btu Gas Stream in
Lurgi Process ........... 14
Table 3. Sulfur Balance Around High-Pressure Stretford
Unit for Desulfurization of Low-Btu Gas
Stream in Lurgi Process 15
Table 4. Sulfur Balance Around Low-Pressure Stretford
Units for Sulfur Recovery in Lurgi Process 16
Table 5. Emissions of Sulfur Compounds for Alternative
Control Levels in Lurgi Process . 18
Table 6. Design Basis for Synthane Process for the
Manufacture of High-Btu SNG ..... 21
Table 7. Sulfur Balance Around Hot Potassium Carbonate Unit
for Desulfurization of Fuel Gas in Synthane Process . . 23
Table 8. Sulfur Balance Around Catalyst Guard for Desulfur-
ization of Fuel Gas in Synthane Process . 24
Table 9. Sulfur Balance Around Stretford Unit in
Synthane Process . 25
Table 10. Emissions of Sulfur Compounds for Alternative Control
Levels in Synthane Process 27
Table 11. Design Basis for HYGAS Process for the
Manufacture of High-Btu SNG 30
Table 12. Sulfur Balance Around Rectisol Unit for Desulfurization
of Fuel Gas in HYGAS Process 31
Table 13. Sulfur Balance Around Rectisol Unit for Desulfuriza-
tion of Fuel Gas in HYGAS Process . 32
Table 14. Sulfur Balance Around IGT-Meissner Unit for Desul-
furization of Low-Btu Gas in HYGAS Process 34
vi
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LIST OF TABLES (Continued)
Page
Table 15. Sulfur Balance Around IGT-Meissner Unit for Desulfur-
ization of Low-Btu Gas in HYGAS Process ........ 35
Table 16. Sulfur Balance Around Glaus Unit for Sulfur
Recovery in HYGAS Process ......*........ 37
Table 17. Sulfur Balance Around Glaus Unit for Sulfur
Recovery in HYGAS Process ............... 38
Table 18. Sulfur Balance Around Glaus Unit Plus Wellman-
Lord Tail Gas Treatment in HYGAS Process ... . . .'' 39
Table 19. Sulfur Balance Around Glaus Unit Plus Wellman-
Lord Tail Gas Treatment in HYGAS Process ........ 4ฐ
Table 20. Emissions of Sulfur Compounds for Alternative
Control Levels in HYGAS Process ........ .... 42
Table 21. Emissions of Sulfur Compounds for Alternative
Control Levels in HYGAS Process ............ 43
Table 22. Design Basis for CC^-Acceptor Process for the
Manufacture of High-Btu SNG .............. 47
Table 23. Sulfur Balance Around Hot Potassium Carbonate
Unit in C02- Acceptor Process ...... ..... ... 48
Table 24. Sulfur Balance Around Ash Treatment Unit
in CO.-Acceptor Process. . . . ........ ..... 49
Table 25. Sulfur Balance Around Catalyst Guard in
CO -Acceptor Process ..... .......... ... $ฎ
Table 26. Sulfur Balance Around Glaus Unit in C02~
Acceptor Process .................... 52
Table 27. Sulfur Balance Around Claus Unit Plus Beavon Tail
Gas Treatment in CC^- Acceptor Process ...... .... 53
Table 28. Sulfur Balance Around Coal Preparation Unit in
CC^-Acceptor Process .................. 54
Table 29. Emissions of Sulfur Compounds for Alternative
Control Levels in C02~Acceptor Process ......... 56
Table 30. Design Basis for Lurgi Process for the Manufacture
of Low-Btu Gas by Steam-Air Gasification of Coal .... 60
vii
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LIST OF TABLES (Continued)
Page
Table 31. Sulfur Balance Around High Pressure Stretford
Unit for Desulfurization of Low-Btu Gas in
Lurgi Process ..................... 61
Table 32. Emissions of Sulfur Compounds for Alternative
Control Levels in Lurgi Process for Low-Btu
Gas Manufacture ..... . ........ ..... . 63
Table 33. Design Basis for Koppers-Totzek Process for the
Manufacture of Low-Btu Gas by Steam-Oxygen Gasification
of Coal ..... ................... 66
Table 34. Sulfur Balance Around MDEA Unit for Desulfuriza-
tion of Fuel Gas .................... 68
Table 35. Sulfur Balance Around Claus Unit in Koppers-
Totzek Process ..................... 69
Table 36. Sulfur Balance Around Claus Unit Plus Beavon Unit
in Koppers-Totzek Process ............... 70
Table 37. Emissions of Sulfur Compounds for Alternative Control
Levels in Koppers-Totzek Process for Low-Btu Gas
Manufacture ...................... 72
Table 38. Physical Solvent Processes for Gas Purification .... 76
Table 39. Sulfur Balance Around Selexol Unit for Acid Gas
Removel in High-Btu SNG Manufacture .......... 78
Table 40. Sulfur Balance Around Selexol Unit for
Desulfurization of Low-Btu Gas ....... ...... 79
Table 41. Sulfur Balance Around Rectisol Unit for
Desulfurization of Low-Btu Gas ... .......... 81
Table 42. Material Balance Around Purisol Process in Selective
Removal of H2S From Natural Gas .... ..... ... 82
Table 43. Amine Processes for Gas Purification .......... 85
Table 44. Typical Operating Data for Shell ADIP and Sulfinol
Processes for Purification of Synthesis Gases ..... 87
Table 45. Alkaline Salt Solution Processes for Acid Gas
Removal ........................ 89
viii
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LIST OF TABLES (Continued)
Page
Table 46. Typical Operating Data for Alkazid Process for
Purification of Ammonia Synthesis Gas
94
Table 47. Typical Operating Data for COS Hydrolysis Process
for Purification of Carbon Monoxide from Coke ^5
Table 48. Utilities Requirement for Acid-Gas Removal Processes . . 96
Table 49. Utilities Requirement for MDEA Process for
Desulfurization of Low-Btu Gas 97
Table 50. Sulfur Recovery Processes 99
Table 51. Utilities Requirement for Sulfur
Recovery Processes 107
Table 52. Glaus Plant Tail Gas Treatment Processes 109
Table 53. Sulfur Balance Around a Glaus Unit and Around a
Glaus Unit Plus a Beavon Unit 110
Table 54. Sulfur Balance Around a Glaus Unit and Around a
Glaus Unit Plus an IFP-1 Unit 113
Table 55. Sulfur Balance Around a Glaus Unit and Around a Glaus
Unit Plus a Sulfreen Unit 115
Table 56. Sulfur Balance Around a Glaus Unit and Around a Glaus
Unit Plus a Wellman-Lord Unit 116
Table 57. Utilities Requirement for Glaus Plant Tail Gas
Treatment Processes 117
Table 58. Sulfur Content of C02 Streams From Rectisol Process
for Gas Purification in SNG Manufacture From
Coal Gasification 120
Table 59. Sulfur Content of Tail Gas From Claus Process 123
Table 60. Sulfur Content of Off Gases From Claus Plant
Tail Gas Treatment Processes 125
Table A-l. Lurgi Gasification Units A-2
Table A-2. Koppers-Totzek Gasification Units A-4
Table A-3. Winkler Gasification Units A-7
IX
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LIST OF TABLES (Continued)
Table A-4. Survey of Estimates of Future Supply of Pipeline
Quality(High-Btu) Gas Produced from Coal in the
United States A-10
Table A-5. Estimate of Future Supply of Low-Energy
(Low-Btu) Gas Produced from Coal in the
United States A-10
Table B-l. List of Industry Experts B-2
LIST OF FIGURES
Figure 1. Flowsheet of Lurgi Process for SNG Manufacture .... 10
Figure 2. Flowsheet of Synthane Process for SNG Manufacture ... 19
Figure 3. Flowsheet of Hygas Process for SNG Manufacture .... 28
Figure 4. Flowsheet of C(L-Acceptor Process for SNG Manufacture . 45
Figure 5. Flowsheet of Lurgi Process for Low-Btu gas
Manufacture 58
Figure 6. Flowsheet of Koppers-Totzek Process for
Low-Btu Gas Manufacture 64
x
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DEVELOPMENT OF INFORMATION FOR STANDARDS
OF PERFORMANCE FOR THE FOSSIL
FUEL CONVERSION INDUSTRY
(Contract No. 68-02-0611, Task 7)
by
B. C. Kim, J. M. Genco, J. H. Oxley, and P. Choi
INTRODUCTION
This study was performed by Battelle's Columbus Laboratories
(BCL) for the Environmental Protection Agency under Contract No. 68-02-0611,
Task 7. The objective of this task was to develop background information
which will assist the EPA in preparing a standards support document
preliminary to setting New Source Performance Standards for the coal
gasification industry.
The scope of the present task covered desulfurization of fuel
gas produced by coal gasification and control of sulfurous emissions to
atmosphere from process sequence in coal gasification. Emissions of sulfur
dioxide from on-site utility boilers, burning fuels other than the gaseous
fuel produced by an auxiliary coal gasification unit, were excluded from
this task, since they were considered to be covered by the existing
regulations pertaining to utility boiler operations.
Coal gasification processes considered in this task included
four processes for the manufacture of a sustitute natural gas (SNG),
including the Lurgi, Synthane, Hygas, and C02-Acceptor processes; and two
processes for the manufacture of a low-Btu utility gas, including the
Lurgi and Koppers-Totzek processes. Control technology was considered
under three categories: (1) gas purification for the removal of acid gases
such as H-S and C09, and other sulfur compounds, (2) sulfur recovery, and
(3) treatment of tail gas from the Glaus sulfur-recovery process.
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SUMMARY
Sulfurous emissions and applicable control methods in the
manufacture of high-Btu SNG and low-Btu fuel gas by coal gasification
are summarized below by sources of emissions.
Coal Preparation
9 9
For a plant producing 62.5 x 10 kcal/day (248 x 10 Btu/day)
equivalent of SNG from a low-sulfur coal (0.59 percent sulfur) by the
ft i
(XL-Acceptor process, the coal preparation stage emits 61 x 10 nnrVday*
(2200 x 10 scf/day) of an off-gas containing 300 ppm of SO-. The
equivalent sulfur emissions are estimated at 25.0 MT** (22.6 tons)
or 0.23 kg S/10 kcal (0.13 Ib S/10 Btu) of SNG produced. Available process
design schemes allow discharging the S07 from coal preparation directly to
atmosphere without control.
Fuel Gas Purification
For SNG manufacture, the fuel gas usually following tine shift
reaction is purified to remove sulfur compounds and C0_ prior to
methanation. Sulfur compounds and C0_ can be removed separately or
together. Processes generally considered capable of separate removal
of sulfur compounds and C09 include the Rectisol, the Selexol, the
Purisol, and the Alkazid processes. Separate removal of acid gases produces
two effluent streams, one containing the bulk of the sulfur compounds
originally present in the gas feed and the other containing C0ซ and traces
of sulfur compounds. The sulfur-rich stream is sent to a subsequent
sulfur-recovery process for desulfurization and, therefore, is not usually
considered an emission source at the gas purification stage. The C09 stream
from the Rectisol process contains 50 to 80 ppm of total sulfur compounds
(mostly as COS) for low-sulfur coals (0.51 to 0.91 percent sulfur) and
310 ppm of total sulfur compounds for a high-sulfur coal (3.93 percent sulfur)
o
* nm stands for cubic meters at 15.6 C, 1 atm.
** MT stands for metric ton.
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The flow rate of the CO- stream is in the range of about 6.0 to 10.9 x 10
o 66
nm /day (200 x 10 to 400 x 10 scf/day). Equivalent sulfur emissions in
the CO, stream are about 0.5 to 1.3 MT S/day (0.5 to 1.4 tons S/day) or
6 6
0.009 to 0.02 kg S/10 kcal (0.005 to 0.01 Ib S/10 Btu) for low-sulfur
coals and 2.8 MT S/day (3.1 tons S/day) or 0.045 kg S/106 kcal (0.025 Ib
S/10 Btu) for the high-sulfur coal. Available process design schemes
are based on venting the CO- stream directly to atmosphere. When, C0_ is
removed together with sulfur compounds, a single off-gas stream containing the
bulk of both constituents is generated from the purification stage. Processes
generally considered applicable for simultaneous removal of acid gases
include the hot potassium carbonate, the Sulfinol, and the Fluor Solvent
processes. Available process design schemes require treating the acid gas
effluent for desulfurization.
In the manufacture of a low-Btu utility gas, sour fuel gas
produced by coal gasification is desulfurized for the purpose of reducing
SO- emissions from combustion of the fuel gas in a utility boiler.
Commercially-proven processes applicable for desulfurization include the
Stretford process and an amine-absorption process using methyldiethanolamine
(MDEA). Both processes are intended for selective removal of H-S while
9
leaving behind bulk of C09 in the fuel gas. For plants producing 32.8 x 10
9
kcal/day (130 x 10 Btu/day) equivalent of low-Btu gas from coals containing
0.69 to 1.08 percent sulfur, the sour fuel gas can be desulfurized to a
total residual sulfur level in the range of 140 to 250 ppm. Equivalent
sulfur emissions from combustion of the fuel gas in a utility boiler are
24 to 70 ppm SO- in boiler stack or 0.22 to 0.27 kg SO-/10 kcal (0.12 to
6
0.15 Ib SO-/10 Btu) of fuel gas product.* The latter emission values are
substantially below the existing Federal standards for SO- emissions
6 6
established at 2.16 kg SO-/10 kcal (1.2 Ib SO-/10 Btu) for coal-burning
equipment. To comply with the existing standards, the allowable total
sulfur levels in fuel gas are estimated at 1400 ppm for a fuel gas with a
3
heating value of 1740 kcal/nm (195 Btu/scf) (produced by the Lurgi steam-air
* The indicated ranges of the three sets of figures were derived from
different sources of data and consequently do not necessarily agree.
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gasification process) and at 2100 ppm for a fuel gas with a heating value
3
of 2167 kcal/nm (294 Btu/scf) (produced by the Koppers-Totzek steam-oxygen
gasification process).
Sulfur Recovery
Acid gases generated from fuel-gas purification will be sent
to either the Glaus process or the Stretford process for desulfurization
and sulfur recovery. The Glaus process produces a tail gas containing
sulfur as SCL in the range of 1 to 2 percent after incineration. Equivalent
sulfur emissions range from 4.3 to 45 MT/day (5 to 50 tons S/day) or 0.1 to
0.7 kg S/10 kcal (0.07 to 0.4 Ib S/10 Btu) equivalent of SNG or low-Btu
gas produced. The concentration of SO- in the tail gas is high enough to
allow further treatment of the tail gas prior to discharge to atmosphere.
The Stretford process produces effluents containing sulfur as S0_ in the
range of 150 to 420 ppm after incineration in the manufacture of SNG from
coals containing 0.69 to 1.6 percent sulfur. Equivalent sulfur emissions
are estimated in the range of 0.3 to 1.3 MT S/day (0.3 to 1.4 tons S/day)
or 0.004 to 0.022 kg S/106 kcal (0.0022 to 0.012 Ib S/106 Btu) equivalent
of SNG produced. Available process design schemes are based on discharging
the Stretford effluents directly to atmosphere without further treatment.
Treatment of Glaus-Plant Tail Gas
Commercially-proven control methods for desulfurization of
Glaus-plant tail gas include the Beavon, the Cleanair, the IFP-1, the
Sulfreen, and the Wellman-Lord processes.
The Beavon, the Cleanair, and the Wellman-Lord processes are
considered capable of reducing sulfur content of Glaus-plant tail gas to
250 ppm S0_ in the effluent discharged to atmosphere. Equivalent sulfur
emissions in the treated effluents are estimated at 0.7 to 0.9 MT S/day
(0.8 to 1.0 tons S/day) or 0.012 to 0.015 kg S/106 kcal (0.007 to 0.008 Ib
S/10 Btu) in the manufacture of SNG from a high-sulfur coal (3.93 percent
sulfur) and 0.2 to 0.6 MT S/day (0.2 to 0.7 tons S/day) or 0.003 to 0.010 kg
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S/10 kcal (0.002 to 0.006 Ib S/10 Btu) in the manufacture of SNG from
low-sulfur coals (0.51 to 0.59 percent sulfur). Sulfur emissions from
the Beavon process employed in the manufacture of a low-Btu gas from a
1.08 percent sulfur coal are estimated at 0.09 MT S/day (0.1 ton S/day)
or 0.003 kg S/10 kcal (0.002 Ib S/10 Btu) equivalent of gas produced.
The IFP-1 and the Sulfreen processes are considered less efficient
than the other three processes and are capable of reducing sulfur content of
Glaus-plant tail gas to about 2000 to 4000 ppm in the effluent discharged
to atmosphere. Equivalent sulfur emissions in the treated effluents are
estimated at 7 to 13 MT S/day (8 to 14 tons S/day) or 0.1 to 0.2 kg S/10
kcal (0.06 to 0.11 Ib S/10 Btu) in the manufacture of SNG from a high-sulfur
coal (3.93 percent sulfur).
Other Sources of Sulfurous Emissions
Additional sources of sulfurous emissions include off-gases
from sour wastewater treatment and from regeneration of catalyst guard,
the latter employed ahead of methanation in SNG manufacture.
Off-gases from wastewater treatment are generated at relatively
o 66
small quantities in the range of 28 to 4500 nm /hr (0.001 x 10 to 0.16 x 10
9 9
scf/hr) for SNG plants with a 63 x 10 kcal/day (250 x 10 Btu/day) capacity
V'"? 36 9
and 740 nm /hr (0.026 x 10 scf/hr) for a low-Btu gas plant with a 32.8 x 10
9
kcal/day (130 x 10 Btu/day) capacity. The off-gases, however, contain
2 to 4 percent H_S and cannot be discharged to atmosphere directly without
treatment. Available process design schemes specify sending the off-gases
to a sulfur recovery process for desulfurization together with acid gases
removed from fuel-gas purification.
Use of a catalyst guard is specified for the Synthane, the CO^-
Acceptor, and the Hygas processes for SNG manufacture. Sulfur emissions
as SO- from regeneration of catalyst guard are estimated to be low in the
neighborhood of 0.5 to 1.1 MT S/day (0.5 to 1.2 tons S/day) or 0.008 to 0.021
kg S/10 kcal (0.004 to 0.011 Ib S/10 Btu). Available process design
schemes allow discharging the off-gas from catalyst regeneration directly
to atmosphere without treatment.
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COAL GASIFICATION TECHNOLOGY
Gasification of coal is intended to produce gaseous products for
consumption as fuels and for industrial uses such as chemical synthesis and
a reducing gas in iron and steel production. The technology has been
practiced in a commercial scale primarily in Europe for many years to manu-
facture town gas, fuel gas, and synthesis gas.
Gasification is accomplished by reacting coal with air, with oxygen,
with steam and air, or with steam and oxygen to produce a gaseous product,
which consists of hydrogen, carbon monoxide, carbon dioxide, hydrocarbons
(mainly methane), water, nitrogen (with air-supported combustion), and sulfur
compounds (mainly hydrogen sulfice, carbon disulfide, and carbonyl sulfide).
The raw gas from the gasifier can be purified to remove particulate matter,
excess water vapor, and sulfur compounds to yield a clean product suitable
for use as a fuel gas. The heating value of this product typically lies
o
in the range of 890 to 4450 kcal/nm (100 to 500 Btu/scf). The fuel value
can be upgraded considerably by subsequent processing of the gasifier
product usually by water-gas shift reaction and methanation to produce a
substitute natural gas (SNG) of a pipeline quality.
Classification of Gasification Processes
Gasification processes have been classified into two broad categories,
low-Btu process and high-Btu process, depending upon the heating value of
the product. Low-Btu fuel gas is produced by the initial gasification step.
The heating value of low-Btu gas lies typically in the range of 890 to 2670
3
kcal/nm (100 to 300 Btu/scf) with air-supported operations and in the range
o
of 2670 to 4450 kcal/nm (300 to 500 Btu/scf) with oxygen-^apported opera-
tions .
High-Btu SNG is produced by further processing of the gasifier
effluent by water-gas shift reaction and methanation. Substitute natural
gas typically contains over 95 percent methane and has a heating value in
excess of 8455 kcal/nm3 (950 Btu/scf).
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Present Status of Gasification Technology
A recent survey of the gasification processes for manufacturing
gaseous fuels lists a total of 39 processes, of which 21 are for low-Btu
fuel gas and 18 are for SNG, in various stages of development and commercial
(2)
usage . Only three processes, Lurgi, Winkler, and Koppers-Totzek processes,
are practiced in commercial scale outside the United States for manufacturing
low-Btu gas. The high-Btu processes in an advanced stage of development
include: Lurgi process, Synthane process, Hygas process, and CCL-Acceptor
(3)
process . The Lurgi process is commercially proven for high-Btu SNG
except for methanation. Methanation in conjunction with the Lurgi process
is currently undergoing a full-scale evaluation at Westfield, Scotland.
As presently scheduled, the Lurgi process will be the first to be used in
commercial scale in the United States for SNG manufacture. Applications
for two SNG plants based on the Lurgi technology have been filed with the
Federal Power Commission by El Paso Natural Gas Company and by Western
Gasification Company (WESCO).*
Selection of Coal Gasification Processes
Gasification processes for the present .task were selected mainly
on the basis of (1) the availability of emission data and (2) the current
status of technology with respect to the potential for commercialization in
the United States. Using these criteria, Battelle was asked to study the
following processes:
High-Btu SNG Low-Btu Fuel Gas
(1) Lurgi (1) Lurgi
(2) Synthane (2) Koppers-Totzek
(3) Hygas
(4) C02-Acceptor
* A joint venture of Texas Eastern Transmission Corporation and Pacific
Lighting Corporation.
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The four processes listed under the SNG category had been included
(3)
in a recent Booz-Allen study as being among the most commercially viable
and providing a good coverage of all of the major elements of gasification
technology and pollution control problems anticipated. The two processes
selected for the low-Btu fuel gas are commercially practiced outside the
United .States and among the best known and most advanced processes.
Categorization of Gasification Process
as Air Pollutant Emission Source
By definition given in the Clean Air Act of 1970, Section 111,
coal gasification processes will fall into a new source category, since the
construction of the first SNG plants is not expected to commence until after
the regulations on performance standards are proposed. The source category
at this time can be further narrowed down to new construction only and
exclude process or equipment modification, since the latter cannot be de-
fined until the plants are constructed and operated.
DESCRIPTION OF SELECTED COAL GASIFICATION PROCESSES
AND EMISSIONS OF SULFUROUS GASES
A brief description is presented in this section for the selected
coal gasification processes and emissions of sulfurous gases. Emissions
are described in terms of source, type, concentration, and quantity. The
description given is keyed to simplified flowsheets. Emissions of sulfur
dioxide from on-site steam/power plants are not included, since they are
considered outside the scope of this task. Desulfurization of fuel gas is
included in the discussion for both the low-Btu gas and high-Btu gas
processes, although for the latter process desulfurization is not normally
considered either a source of sulfurous emissions or an associated emission
control process. The reason is that the desulfurization of fuel gas accom-
plished in the acid-gas removal step in the manufacture of high-Btu gas is
an integral part of the manufacturing process required to protect the methana-
-------
tion catalyst regardless of the requirement for the control of sulfurous
emissions. Treatment of sulfurous gases regenerated from the desulfurization
step is a legitimate emission control item. For the low-Btu processes, how-
ever, desulfurization of the fuel gas can be logically considered a sulfur
control method, since the fuel gas conceivably could be burned without de-
sulfurization and the resultant sulfur dioxide emissions could be controlled
by stack-gas cleaning.
Lurgi Process (High-Btu SNG)
The Lurgi process as proposed by El Paso Natural Gas Company for
the manufacture of high-Btu SNG is shown schematically in Figure 1. The
flowsheet and material-balance data, including emission data, are based
(3)
on the information developed in the recent Booz-Allen study . An important
feature of this particular plant design is the use of auxiliary air-blown
gasifiers for the manufacture of a low-Btu fuel gas which is used for on-
site power and steam generation. About 18 percent of the total coal feed
is consumed in the auxiliary gasifiers, and the remaining 82 percent in the
oxygen-steam gasification for the manufacture of high-Btu SNG. The basis
for plant design is summarized in Table 1.
Fuel Gas Desulfurization
The fuel gas produced from steam-oxygen gasification is desulfurized
by the Rectisol process. The fuel gas produced from the air-blown gasifi-
cation is desulfurized by utilizing a high-pressure Stretford process.
Referring to the flowsheet given in Figure 1, the fuel gas feed
(Stream 1) to the Rectisol process contains 0.34 percent by volume (dry-gas
basis) of H S, COS, and CS_ combined. The removal of the sulfurous compounds
in the Rectisol process is nearly complete, producing an essentially suflur-
free fuel gas for the subsequent methanation step.
The regenerated acid gases from the Rectisol unit consists of two
separate streams, one rich in H_S (Stream 4) and the other lean in H.S
(Stream 12). These two streams are processed by two separate low-pressure
-------
Coal
Coal
Preparation
^*
Steam-Oxygen
Gasification
. . ..
Gas
Washing
Shift
Reaction
0
Acid Gas
Removal
(Rectisol)
Steam and Oxygen
ฉ
Desulfurlzed Low-Btu Gas v?)
Steam-Air
Gasification
Gas
Hashing
ฉ
Sulfur
Recovery
(Stretford)
Steam and Air
CO
.
0 C02
Sulfur Atmฐ8
I
i *j\ '
^ SN
Methanation
(5) Naphtha
ฉ
1
i
Sulfur
Recovery
(Stretford)
1
1ฉ
Sulfur
ฉ
~ "1
Phenosolvan
Process
^^s 1
IV,
1
Off-Gas to
Atmosphere after
Incineration
SNG Product
FIGURE 1. FLOWSHEET OF LURGI PROCESS FOR SNG MANUFACTURE
(3)
-------
Legend for Figure 1
11
Stream Number
2
3
4
6
7
10
11
12
Description
Converted fuel gas feed to Rectisol
unit for acid gas removal
Purified fuel gas from Rectisol unit
Naphtha recovered from Rectisol unit
Regenerated acid gas (H S-rich stream
from Rectisol unit
Low-Btu gas to high-pressure Stretford
unit for desulfurization and sulfur
recovery
Waste gas from Phenosolvan unit
Tail gas from low-pressure Stretford
unit, resulting from treatment of
sulfur-rich acid gas and the waste
gas from ammonia recovery, discharged
to atmosphere after incineration
Tail gas from low-pressure Stretford
unit, resulting from treatment of
sulfur-lean acid gas, discharged to
atmosphere without incineration
Elemental sulfur recovered from
high-pressure Stretford unit
Desulfurized low-Btu gas for use at
on-site power/steam generation
Elemental sulfur recovered from
low-pressure Stretford units
Regenerated acid gas (H S-lean stream)
from Rectisol unit
-------
12
TABLE 1. DESIGN BASIS FOR LURGI PROCESS FOR THE
MANUFACTURE OF HIGH-BTU SNG BY EL PASO
NATURAL GAS<3)
Coal Feed
Type Navajo Seam
Heating value, kcal/kg 4817
Sulfur content, percent by weight 0.69
Feed rate, MT/day 25,622
Gas Production
Production rate, nm3/day(aJ 8.17 x 10
Heating value, kcal/nm3^ 8491
9
Total fuel value, kcal/day 69.3 x 10
Thermal Efficiency, percent 56.25
(a) Standard conditions are 15.6 C, 1 atm.
(b) Defined as the percentage of the total heating
value of the coal feed recovered in the high-
Btu SNG product.
-------
13
Stratford units. The H S-rich stream contains about 13 percent by volume
of sulfurous gases.
A part of the sulfur compounds leaves the Rectisol process with
naphtha (Stream 3) recovered from the Rectisol process. A sulfur balance
around the Rectisol process is given in Table 2.
The low-Btu gas produced from air-blown gasification is desulfurized
by a high-pressure Stretford unit operated at 18 atm. (250 psig). A sulfur
balance around the high-pressure Stretford unit is given in Table 3.
Sulfur Recovery
Gaseous streams containing sulfurous compounds are treated by
three Stretford units to recover elemental sulfur. One unit operated at high
pressure is used for the desulfurization of low-Btu gas as described in the
preceding section. The other two units are operated at low pressure to
treat regenerated acid gas streams (Stream 4) from the Rectisol unit and a
waste gas stream (Stream 6) generated from phenol and ammonia recovery by
the Phenosolvan process. Output from the low-pressure Stretford units con-
sist of (1) a tail gas (Stream 8) resulting from the treatment of the sulfur-
lean acid gas, which is vented directly to atmosphere, (2) a tail gas (Stream
7) resulting from treatment of the sulfur-rich acid gas and the waste gas
(Stream 6) from the Phenosolvan process, which is subsequently treated by
incineration, and (3) elemental sulfur recovered (Stream 11). Sulfur balance
around the low-pressure Stretford units is given in Table 4.
Emissions and Control of Sulfurous Gases
Emissions of sulfurous gases to the atmosphere can be considered
at several levels of control up to the fully controlled level which is
indicated in the process flowsheet. Two alternatives for the control of
sulfurous emissions can be considered as follows:
-------
TABLE 2. SULFUR BALANCE AROUND RECITISOL UNIT FOR
DESULFURIZATION OF HIGH-BTU GAS STREAM
IN LURGI PROCESS(3)
g
Basis: 69.3 x 10 kcal/day SNG Production from Navajo Seam Coal (0.69 percent sulfur)
Total Gas Flow
106 nm3/hr (dry basis)
Sulfurous Gases, volume percent
H2S
COS
cs2
Sulfur in stream
kg/hr
kg/106 kcal(b)
1 2
Fuel Gas In Fuel Gas Out
1.273 0.867
-\ trace
> 0.34 trace
-^ trace
5,850 negligible
2.0 negligible
Streams
3 4
Naphtha Out Acid Gas Out
(a) 0.0102
> 12.9
J
18 1,780
0.0062 0.61
12
Acid Gas Out
0.404
0.73
t
.
3,990
1.4
(a) Total output = 9,070 kg/hr.
(b) Based on the total HHV of SNG product,
-------
15
TABLE 3. SULFUR BALANCE AROUND HIGH-PRESSURE STRETFORD
UNIT FOR DESULFURIZATION OF LOW-BTU GAS STREAM
IN LURGI PROCESS(3)
g
Basis: 69.3 x 10 kcal/day SNG Production From Navajo Seam Coal
(0.69 percent sulfur)
Streams
10
Fuel Gas In Fuel Gas Out Elemental Sulfur Out
Total Gas Flow
10 nm3/hr (dry basis)
Sulfurous Gases, volume percent
0.399
(a) By difference.
(b) Based on total HHV of SNG product,
0.398
HS
COS
cs2
Sulfur in Stream
kg/hr
kg/106 kcal(b)
0.227
0.003
trace
1,240
0.43
trace
0.01
trace
70
0.024
l,180(a)
-------
TABLE 4. SULFUR BALANCE AROUND LOW-PRESSURE STRETFORD UNITS
FOR SULFUR RECOVERY IN LURGI PROCESS(3>
Q
Basis: 69.3 x 10 kcal/day SNG Production from Navajo
Seam Coal (0.69 percent sulfur)
Streams
4 12
Acid Gas In Acid Gas In
Total Gas Flow
106 nm3/hr 0.0102 0.404
(dry basis)
Sulfurous Gases,
volume percent
H2S H^S + COS I^S + COS
COS +CS2 =12.9 +CS2 = 0.73
cs2 , '
S02 trace trace
Sulfur in Stream
kg/hr 1,780 3,990
kg/106 kcal(b) 0.61 1.4
6
Waste Gas
from
Phenosolvan
0.0021
4.09
trace
trace
trace
118
0.041
7
Off Gas to
Atmosphere after
Incineration
0.020
trace
trace
trace
420 ppm
12
0.0042
8 11
Off Gas to Elemental
Atmosphere Sulfur
0.456
t^S + COS
+ cs2
=80 ppm
trace - --
49 5,830(a)
0.017
(a) By difference.
(b) Based on the total HHV of SNG product.
-------
17
(1) No control - Neither sulfur recovery nor tail gas
treatment will be included. Sulfurous emissions
will consist of: (a) acid gases (two streams) from
Rectisol unit, (b) waste gas from the Phenosolvan
process, and (c) sulfur compounds in the undesulfurized
low-Btu gas, which will be emitted as S09 from the
on-site steam/power plant.
(2) Sulfur recovery - The three Stretford units, one
high-pressure and two low-pressure units, will be
included, but the Stretford tail gas will not be
treated. Sources of sulfurous emissions will include:
(a) a low-sulfur and a h|gh-sulfur tail gas stream
from the Stretford units and (b) the residual sulfur
compounds in desulfurized low-Btu fuel gas.
Emissions of sulfurous gases for the two control alternatives as
described above are summarized in Table 5.
Synthane Process
The Synthane process for the manufacture of high-Btu SNG is
shown by a block diagram in Figure 2. The flowsheet and material balance
data, including sulfurous emissions, are based on the information developed
in the recent Booz-Allen study . The process has been under development
by the U.S. Bureau of Mines for the conversion of bituminous and sub-
bituminous coal and lignite into high-Btu SNG. The basis for plant design
as reported in the Booz-Allen study is given in Table 6.
Fuel-Gas Desulfurization
The fuel gas following shift conversion is purified by a hot
potassium carbonate process. The fuel-gas effluent from the potassium-
carbonate process is further purified by a catalyst guard, utilizing iron
oxide and char as sorbents for sulfur compounds, prior to methanation.
-------
TABLE 5. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL LEVELS IN LURGI PROCESS
o
Basis; 69.3 x 10 kcaI/day SNG Production from Navajo Seam Coal
(0.69 percent coal)
(3)
Control Level
No Control
Sulfur compounds, ppm
GO'S
CS
Sฐ2
Total sulfur, NT/day
Sulfur Recovery (Stretford)
Sulfur compounds, ppm
COS
CS
Sฐ2
Total sulfur, MT/day
Sources of Emissions to Atmosphere
Stream 4 Stream 12 Stream 5 Stream 6 Stream 7
Off -Gas from
Acid Gases Acid Gases Undesulfurlzed Off-Gas from Low-Pressure
from Rectisol from Rectlsol Low-Btu Gas^*) Phenosolvan Stretford^0'
1 1 . 40,090
V 129,000 h 7,300
346
43 96 30 2.8
-__ _ _' _
. 420
0.29
Stream 8
Off-Gas from
Low-Pressure
Stretford
V 80
1.2
Stream 10
Desulfurized
Low-Btu Gas
.
22
1.7
00
(a) SO. emission froa combustion of the low-Btu gas in on-site steam/power plant.
(b) After incineration.
-------
Coal
Preparation
Gasification
Gas
Washing
Shift
Reaction
ฉ
Acid Gas
Removal
(K2C03)
Steam and
Oxygen
ฉ -
Off-Gas to
Atmosphere
- ir
m
(3)
,.^-i. Catalyst
Guard
I
Air
ฎ
Sulfur
Recovery
(Stretford)
1
ฉ
Sulfur
(?)
Methanation
Vastevater
Treatment
SSG Product
FIGURE 2. FLOWSHEET OF SYNTHANE PROCESS FOR SNG MANUFACTURE
(3)
-------
Legend for Figure 2
20
Stream Number
Description
Converted fuel gas feed to hot
potassium carbonate unit for acid
gas removal
Fuel gas output from hot potassium
carbonate unit
Regenerated acid gas from hot
potassium carbonate unit to
Stretford sulfur recovery unit
Off gas from Stretford unit
discharged to atmosphere
Elemental sulfur recovered from
Stretford unit
Off gas from catalyst guard
regeneration discharged to
atmosphere
Purified fuel gas from catalyst
guard to methanation
Waste gas from wastewater treatment
to Stretford unit
-------
21
TABLE 6. DESIGN BASIS FOR SYNTHANE PROCESS FOR
THE MANUFACTURE OF HIGH-BTU
Coal Feed
Type Pittsburgh Seam
Heating value, kcal/kg 7,061
Sulfur content, percent by weight 1.6
Feed rate, MT/day 12,925
Gas Production
Production rate, nm /day'3^ 7.07 x 106
3 (a\
Heating value, kcal/nm v ' 8,250
Total fuel value, kcal/day 58.4 x 10
Thermal Efficiency, percent^ 64.0
(a) Standard conditions are 15.6 C, 1 atm.
(b) Defined as the percentage of the total heating
value of the coal feed recovered in the high-
Btu SNG product.
-------
22
The regenerated acid gases, consisting mostly of carbon dioxide
and hydrogen sulfide, are sent to a Stretford unit for sulfur recovery.
Sulfur dioxide evolved from regeneration of the catalyst guard is discharged
directly to atmosphere. Sulfur balances around the hot potassium carbonate
process and the catalyst guard are given in Tables 7 and 8, respectively.
Concentrations of sulfur compounds other than H~S in the fuel gas
input to the hot carbonate absorption stage are unavailable. Carbonyl
sulfide and CS? are hydrolyzed and converted to HซS in the absorption stage.
Consequently, the fuel gas output and the acid gas regenerated from the
absorption stage would be expected to contain little COS and CS?..
Sulfur Recovery
Acid gases regenerated from the hot carbonate process are treated
by a Stretford unit to recover sulfur. The Stretford unit also is designed
to treat sour gas generated from wastewater treatment. The treated gas
from the Stretford unit is discharged after incineration to atmosphere.
Sulfur balance around the Stretford unit is given in Table 9.
Emissions and Control of Sulfur Compounds
Two alternatives can be considered for the control of sulfurous
emissions as follows.
(1) No control - The Stretford sulfur recovery unit will
not be used. Sulfurous emissions will consist of:
(1) regenerated acid gas stream from the hot carbonate
absorption stage, (2) the off gas from catalyst guard
regeneration, and (3) sour gas generated from wastewater
treatment.
(2) Sulfur recovery - The Stretford unit will be incorporated
to treat the regenerated acid gas stream from the ab-
sorption stage and the sour gas from wastewater treatment.
Sulfurous emissions will include: (1) off gas from the
Stretford unit and (2) the off gas from catalyst guard
regeneration.
-------
TABLE 7. SULFUR BALANCE AROUND HOT POTASSIUM CARBONATE UNIT
FOR DESULFURIZATION OF FUEL GAS IN SYNTHANE PROCESS
9
Basis: 58.4 x 10 kcaI/day SNG production from
Pittsburgh Seam Coal (1.6 percent sulfur)
Streams
Fuel Gas In Fuel Gas Out Acid Gases Out
Total Gas Flow
106 nm3/hr
Sulfurous Gases, volume percent
0.854
(a) Not available.
(b) Based on the total HHV of SNG Product.
0.537
0.262
H2S
COS
cs2
Sulfur in Stream
kg/hr
kg/106kcal(b)
0.4 64 ppm
NA trace
NA trace
4,630 4.7
1.9 0.019
1.5
trace
trace
. 5,330
2.2
-------
TABLE 8. SULFUR BALANCE AROUND CATALYST GUARD FOR
DESULFURIZATION OF FUEL GAS IN SYNTHANE PROCESS
(3)
Basis: 58.4 x 10 kcal/day SNG production from
Pittsburgh Seam Coal (1.6 percent sulfur)
Total Gas Flow
106 nm3/hr
Sulfurous Gases, volume percent
H2S
COS
cs2
S02
Sulfur in Stream
kg/hr
kg/106 kcal(a)
Streams
2 7
Fuel Gas In Fuel Gas Out
0.537 0.537
64 ppm trace
trace trace
trace trace
_-
47 negligible
0.019 negligible
6
Off Gas from
Catalyst Guard
Reeeneration
NA
trace
trace
trace
NA
47
0.019
N>
(a) Based on the total HHV of SNG product.
-------
TABLE 9. SULFUR BALANCE AROUND STRETFORD UNIT IN
SYNTHANE PROCESS(3)
Q
Basis: 58.4 x 10 kcaI/day SNG production from
Pittsburgh Seam Coal (1.6 percent sulfur)
Streams
6 3
Total Gas Flow, 10 nm /hr
Sulfurous Gases, vol. percent
H2S
COS
cs2
so2
Sulfur in Stream
kg/hr
kg/106 Btu(a)
3
Acid Gases In
0.262
1.5
trace
trace
trace
5,330
2.2
8
Waste Gas From
Wastewater
Treatment
0.00416
4.5
trace
trace
trace
250
0.10
4
Off Gas to
Atmosphere After
Incineration
0.269
trace
trace
trace
150 ppm
54
0.022
5
Sulfur
Recovered
--
5,530
--
Ui
(a) Based on total HHV of SNG product.
-------
26
Emissions of sulfur compounds into the atmosphere for the two
control alternatives as described above are summarized in Table 10.
Hygas Process (High-Btu SNG)
The Hygas process is one of the advanced systems currently under
development by the Institute of Gas Technology with support from the American
Gas Association and the Office of Coal Research. A flowsheet of the process
is shown in Figure 3. An important feature of the process as displayed in
the flowsheet is the incorporation of the U-Gas process, also developed by
IGT, for the manufacture of a low-Btu gas by steam-air gasification of coal
for use as a fuel for on-site generation of power and steam. About 23 per-
cent of the total coal feed is consumed in the U-Gas process for the
production of a low-Btu gas and the remainder in the hydrogasification
process for the manufacture of a high-Btu SNG.
The process flowsheet and material-balance data, including emis-
sions of sulfur compounds, are based on the information developed in the
(3)
recent Booz-Allen study . The basis for process design utilizing two types
of coal--Montana Subbituminous and Illinois No. 6-- is given in Table 11.
Fuel Gas Desulfurization
The fuel gas (Stream 1) produced from the hydrogasification
process is desulfurized by the Rectisol process and further purified by a
catalyst guard prior to methanation. The low-Btu gas (Stream 7) produced
from the U-Gas process is desulfurized by the IGT-Meissner process, which is
a proprietary high-temperature process currently under development by IGT.
Regeneration of solvent in the Rectisol unit produces a sulfur-
rich gas (Stream 3), a sulfur-lean gas (Stream 4), and a BTX-oil liquid
(Stream 5). The sulfur-rich gas stream is diverted to a Glaus sulfur
recovery unit. The sulfur-lean gas stream is vented directly to the atmos-
phere. The BTX-oil stream goes to a storage tank. Sulfur balances around
the Rectisol unit are given in Tables 12 and 13 for the two types of coal
feed.
-------
TABLE 10. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL LEVELS IN SYNTHANE PROCESS
9
Basis: 58.4 x 10 kcaX/day SNG Production from Pittsburgh Seam Coal
(1.6 percent sulfur)
(3)
Control Level
No Control
Sulfur compounds, ppm
H S
COS
CS0
9
Sฐ2
Total sulfur, MT/day
Sulfur Recovery (Stretford)
Sulfur compounds, ppm
H S
COS
CS0
sol
Total sulfur, MT/day
Stream 3
Acid Gases
from Potassium
Carbonate Process
15,000
trace
trace
none
128
ซ_
_ _
_.
Sources of
Stream 4
Emissions to Atmosphere
Stream 6
Off-Gas from Off-Gas from
Stretford
M_
_
.
trace
trace
trace
150
1.3
Catalyst Guard
trace
trace
trace
NA
1.1
trace
trace
trace
NA
1.1
Stream 8
Off-Gas from
Wastewater Treatment
4.5
trace
trace
none
6.0
__
__
ป
(a) Based on total fuel value of SNG product.
-------
te
Coal
Coal L.
Preparation '
Coal
~! Gasification
i
Oil
Quenching
Shift
Reaction
ฉ
Acid Cas
Removal
(Rectisol)
\
Hj Rich Cas from
Steam-Oxygen Casifler
Steam and Air
BTX-Oil
Desulfurlzed Low-Btu Gas
S02
Recycle
Catalyst
Guard
C02 to Air
Atmosphere
Sulfur
Methanatlon
1
SKG Product
Incineration
(12)
Scavenged
Gases
Tail Cas .
Treatment
(W-L)
tsi
00
Off-Cas to Atmosphere
FIGURE 3. FLOWSHEET OF HYGAS PROCESS FOR HIGH-BTU SNG MANUFACTURE
(3)
-------
Legend for Figure 3
29
Stream Number
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Description
Converted fuel gas feed to Rectisol unit for
acid-gas removal
Purified fuel gas from Rectisol unit
Regenerated H.S stream from Rectisol unit
Regenerated CO. stream from Rectisol unit vented
to atmosphere
Oils recovered from Rectisol unit
Purified fuel gas from catalyst guard
Off gas from catalyst-guard regeneration vented
to atmosphere
Low-Btu fuel gas from U-gas reactor
Desulfurized low-Btu fuel gas from IGT-Meissner
unit
Regenerated SO. from low-Btu fuel gas desulfurization
unit (IGT-Meissner)
Tail gas from Claus unit after incinerator
Combined scavenged gases from process oil
storage and wastewater treatment for ammonia
recovery
Off gas from Wellman-Lord unit for treatment of
Claus plant tail gas and scavenged gas
Elemental sulfur produced from Claus plant
50 recyclec
Claus plant
SO recycled from Wellman-Lord unit to
-------
30
TABLE 11. DESIGN BASIS FOR HYGAS PROCESS FOR
THE MANUFACTURE OF HIGH-Btu SNG<3)
Coal Feed
Type
Heating value, kcal/kg
Sulfur content, % by wt
Feed rate, MT/day
Gas Production
3 (a)
Production rate, nm /day
3 (a)
Heating value, kcal/nm
Total fuel value, kca I/day
Thermal Efficiency, percent
Montana
Subbituminous
4,904
0.51
21,476
7.36 x 106
8,597
63 x 109
60.1
Illinois No. 6
6,550
3.93
15,888
7.36 x 106
8,571
63 x 109
59.8
(a) Standard conditions are 15.6 C, 1 atm.
(b) Defined as the percentage of the total heating value of
the coal feed recovered in the high-Btu SNG product.
-------
TABLE 12. SULFUR BALANCE AROUND RECTISOL UNIT FOR DESULFURIZATION OF FUEL GAS IN HYGAS PROCESS
9
Basis: 63 x 10 kcal/day SNG production from Montana Subbituminous coal
(0.51 percent sulfur)
f\ "\
Total Gas Flow, 10 nm /hr
Sulfurous Compounds, volume percent
H2S
COS
cs2
Sulfur in Stream
kg/hr
kg/106kcal
Input Stream Output Streams
1 234
Regenerated
Fuel Gas In Fuel Gas Out H^S Out C02 Vent
1.097 0.733 0.00815 0.352
0.22 0.1 ppm. 29.86 9 ppm
25 ppm NA 0.14 39 ppm
NA NA NA NA
3,300 0.091 3,300 23
1.3 34xlO"6 1.3 0.0088
5
BTX-Oil
Out
(a)
0.44(b)
NA
NA
14.5
0.0055
(a) 102 kg moles/hr.
(b) Mole percent.
(c) Based on the total HHV of SNG product.
-------
TABLE 13. SULFUR BALANCE AROUND RECTISOL UNIT FOR DESULFURIZATION OF FUEL GAS IN HYGAS PROCESS
(3)
Basis: 63 x 10 kcal/ day SNG production from Illinois No. 6 coal (3.93 percent sulfur)
Input Stream
1
Fuel Gas in
6 3
Total Gas Plow, 10 nm /hr 1.007
Sulfurous Compounds, volume percent
t^S 1.44
COS 0.02
CS- NA
Sulfur in Stream
kg/hr 19,900
kg/106 kcal(c) 7.6
Output Streams
2 34
Regenerated
Fuel Gas Out H2S Out C02 Vent
0.674 0.0484 0.282
0.1 ppm 29.83 11 ppm
NA 0.17 300 ppm
NA NA NA
0.091 19,600 116
34x!0"6 7.5 0.045
5
BTX-Oil
Out
(a)
0.47
NA
NA
10
0.0038
(a) 67.6 kg moles/hr
(b) Mole percent
(c) Based on the total HHV of SNG product.
u>
to
-------
33
The desulfurized fuel gas from the Rectisol unit is further purified
by utilizing a catalyst guard prior to methanation. The fuel gas feed
(Stream 2) to the catalyst guard contains very little sulfur (less than 1 ppm
by volume of H S or 0.09 kg/hr (0.2 Ib/hr) of equivalent sulfur). Con-
sequently, the amount of sulfur removed by the catalyst guard also will be
small. Emission of SO from regeneration of the catalyst guard is estimated
at 0.09 kg/hr (0.2 Ib/hr) or 11 x 10"6 kg/106 kcal (19 x 10"6 lb/106 Btu)
of equivalent sulfur.
The low-Btu gas produced by the U-Gas process is desulfurized
utilizing a proprietary high-temperature process. Sulfur is regenerated
from the desulfurization process as SCL , which is sent to a Glaus sulfur
recovery unit. A sulfur balance around the desulfurization unit is given
in Tables 14 and 15 for the two types of coal used. The residual sulfur
contained in the desulfurized fuel gas as H S, COS, and CS? will be
eventually converted to and emitted as S0_ from on-site power plant.
Sulfur Recovery
A Glaus plant is utilized for sulfur recovery. Feed to the Glaus
unit consists of: (1) an H_S stream from the Rectisol unit (Stream 3), and
(2) an SO stream from the IGT-Meissner unit (Stream 10).
The tail gas (Stream 11) from the Glaus unit is combined with
scavenged waste gases (Stream 12), incinerated, and treated by the Wellman-
Lord process prior to discharge to the atmosphere.
Sulfur balance .around the Glaus unit depends on whether or not
the Wellman-Lord unit is used for tail gas treatment, since the sulfur
dioxide captured by the Wellman-Lord process is usually recycled to the
Glaus unit. In order to assess the comparative sulfur emissions with and
without tail gas treatment, sulfur balances were obtained for (1) the Glaus
unit alone without the Wellman-Lord unit, and (2) the Glaus unit and the
Wellman-Lord unit combined. Incineration was considered part of the Glaus
unit, since such practice is usually considered a minimum requirement for
Glaus plant operation.
-------
TABLE 14. SULFUR BALANCE AROUND IGT-MEISSNER UNIT FOR
DESULFURIZATION OF LOW-BTU GAS IN HYGAS PROCESS
(3)
Basis: 63 x 10 kcal/day SNG production from Montana
Subbiturainous coal (0.51 percent sulfur)
6 3
Total Gas Flow, 10 nm /day
Sulfur Compounds, percent by volume
H2S
COS
cs2
so.
Sulfur in Stream
kg/hr
kg/106kcal(a)
Input Stream
8
Fuel Gas In
NA
NA
NA
NA
Trace
1,090
0.42
9
Fuel Gas
NA
NA
NA
NA
Trace
87
0.033
Output Streams
10
Out S02 from Regeneration
0.0034
Trace
Trace
Trace
20.75
950
0.36
u>
(a) Based on total HHV of SNG product.
-------
TABLE 15.. SULFUR BALANCE AROUND IGT-MEISSNER UNIT FOR
DESULFURIZATION OF LOW-Btu GAS IN HYGAS PROCESS
9
Basis: 63 x 10 kcal/day SNG production from
Illinois No. 6 coal (3.93 percent coal)
/r o
Total Gas Flow, 10 nm /day
Sulfur Compounds, percent by volume
H2S
COS
cs2
so2
Sulfur in Stream
kg/hr
kg/106Btu
Input Stream
8
Fuel Gas In
NA
NA
NA
NA
Trace
5,760
2.2
Output Stream
9
Fuel Gas Out SO.
NA
NA
NA
NA
Trace
93
0.035
10
Regeneration
0.020
Trace
Trace
Trace
21.00
5,710
2.2
u>
Ul
(a) Based on total HHV of SNG product.
-------
36
A sulfur balance around the Glaus unit alone was obtained as
follows:
(1) Air input to the Glaus plant assumed at the
stoichiometric oxygen requirement for the
Glaus reactions
(2) A sulfur recovery efficiency assumed at 93
(4)
percent for the Glaus plant
(3) Sulfur compounds in the Glaus plant effluent
assumed at the following concentrations:
Component Mole Percent
COS 0.05
CS2 0.04
SQ 0.05
o
H S + SO Balance of total sulfur
H2S/S02 = 2/1)
(4) Incinerator operation at following conditions:
Inlet temperature: 140 C (284 F)
Outlet temperature: 649 C (1200 F)
Fuel: methane
Combustion air: 10 percent excess.
Sulfur balances around the Claus unit obtained as described are
given in Tables 16 and 17 for the two types of coal used.
Tail Gas Treatment
The Claus unit tail gas after sulfur compounds are converted to
ineration is treated by the Wellman-Lord process . The SO^
captured by the Wellman-Lord process is recycled to the Glaus plant. Sulfur-
balance data as g
Tables 18 and 19.
S09 by incineration is treated by the Wellman-Lord process . The
ured by the Wellman-Lord process is recycl
(3)
balance data as given in the Booz-Allen report are summarized in
Emissions and Control of Sulfurous Compounds
Emissions of sulfurous compounds to the atmosphere can be con-
sidered at several levels of control up to the fully controlled level as
-------
TABLE 16. SULFUR BALANCE AROUND CLAUS UNIT FOR SULFUR RECOVERY IN HYGAS PROCESS
9
Basis: 63 x 10 kcal/day SNG production from Montana
Subbituminous coal (0.51 percent sulfur)
(3)
Input Streams
ฃ. O
Total Gas Flow, 10 nm./hr
Sulfurous Compounds, mole percent
H2S
COS
cs2
so2
Sulfur in Stream
kg/hr
kg/106 kcal(a)
3
H2S from
Rectisol
0.00815
' -
29.86
0.14
NA
Trace
3,300
1.3
10
S02 from
U-Gas
0.0034
Trace
Trace
Trace
20.75
950
0.36
12
Scavenger Gas
to Incineration
0.0028
1.98
76 ppm
NA
Trace
113
0.043
Output Streams
11
Tail Gas
After Incineration
0.024
Trace
Trace
Trace
1.29
420
0.16
14
Sulfur
Recovered
-
-
-
-
3 , 940
-
OJ
(a) Based on the total HHV of SNG product.
-------
TABLE 17. SULFUR BALANCE AROUND GLAUS UNIT FOR SULFUR RECOVERY IN HYGAS PROCESS
9
Basis: 63 x 10 kcal/day SNG production from Illinois No. 6 coal
(3.93 percent sulfur)
Input Streams
/ o
Total Gas Flow, 10 nm /hr
Sul.furous Compounds, mole, percent
H2S
COS
cs2
so2
Sulfur in Stream
kg/hr
kg/106kcal(a)
3
H2S from
Rectisol
0.0484
29.83
0.17
NA
Trace
19,600
7.5
10
S02 from
U-Gas
0.020
Trace
Trace
Trace
21.00
5,710'
2.2
12
Scavenger Gas
to Incineration
0.0045
1.94
0.01
NA
Trace
119
0.045
Output Streams
11
Tail Gas
After Incineration
0.114
Trace
Trace
Trace
1.23
1,890
0.72
14
Sulfur
Recovered
.
-
-
-
-
23,500
co
oo
(a) Based on the total HHV of SNG product.
-------
TABLE 18. SULFUR BALANCE AROUND GLAUS UNIT PLUS WELLMAN-LORD
TAIL GAS TREATMENT IN HYGAS PROCESS(3)
q
Basis: 63 x 10 kcal/day SNG production from Montana
subbituminous coal (0.51 percent sulfur)
Input Streams
Total Gas Flow, 10 nm3/hr
Sulfurous Compounds, mole percent
H2S
COS
cs2
S02
Sulfur in Stream
kg/hr
kg/106 kcal(a)
3
H2S from
Rectisol
0.00815
29.86
0.14
NA
Trace
3,300
1.3
10
S02 from
U-Gas
0.0034
Trace
Trace
Trace
20.75
950
0.36
12
Scavenger Gas
to Incineration
0.0028
1.98
76 ppm
NA
Trace
113
0.043
Output Streams
13
Tail Gas from
Wellman-Lord
0.024
Trace
Trace
Trace
250 ppm
8.2
0.0031
14
Sulfur
Recovered
-
-
-
-
-
4,350
-
(a) Based on the total HHV of SNG product.
-------
TABLE 19. SULFUR BALANCE AROUND GLAUS UNIT PLUS WELLMAN-LORD
TAIL GAS TREATMENT IN HYGAS PROCESS (3)
9
Basis: 63 x 10 kcal/day SNG production from
Illinois No. 6 coal (3.93 percent sulfur)
Input Streams
Total Gas Flow, 10 nm /hr
Sulfurous Compounds, mole percent
H2S
COS
CS2
so2
Sulfur in Stream
kg /hr
kg/106 kcal(a)
3
IkS from
Rectisol
0.0484
29.83
0.13
NA
Trace
19,600
7.5
10
S02 from
U-Gas
0.020
Trace
Trace
Trace
21.00
5,710
2.2
12
Scavenger Gas
to Incineration
0.0045
1.94
0.01
NA
Trace
119
0.045
Output Streams
13
Tail Gas from
Wellman-Lord
0.114
Trace
Trace
Trace
250 ppm
39
0.015
14
Sulfur
Recovered
--
--
'
--
25,400
o
(a) Based on the total HHV of SNG product.
-------
41
displayed in the process flowsheet. Three alternatives for the control of
sulfurous emissions can be considered as follows:
(1) No control-Neither sulfur recovery nor desulfurization
of the low-Btu gas will be included. Sulfurous emis-
sions in this case will consist of: (1) acid gases from
the Rectisol unit, (2) off-gas from wastewater treatment,
and (3) sulfurous compounds in the undesulfurized low-
Btu gas converted to and emitted as S0? from an on-site
power plant.
(2) Sulfur recovery-Under this alternative, a Glaus unit
with an incinerator and desulfurization of the low-
Btu gas will be included. The sulfurous emissions
in this case will be the Glaus plant incinerator off-
gas containing sulfur as SO .
(3) Sulfur recovery plus tail gas treatment--The tail gas
from the Glaus incinerator will be treated by the
Wellman-Lord process. The sulfurous emissions under
this alternative will be the off-gas from the Wellman-
Lord process containing sulfur as S09.
Emissions of sulfurous compounds for the three control alternatives
as described are summarized in Tables 20 and 21 for the two types of coal
used.
-------
TABLE 20. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL LEVELS IN HYOAS PROCESS
Basis: 63 x 10y kcal/day SNG Production from Montana Subbitumlnous Coal
(0.51 percent sulfur)
(3)
Control Level
No Control
Sulfur compounds, ppm
COS
so2
Total sulfur, Ml/day
Sulfur Recovery (IGT-Melssner
and Claus)
Sulfur compounds, ppm
c3s
so2
Total sulfur, MT/day
Sulfur Recovery Plus Tail Gas
.'Treatment (IGT-Meissner,
Claus, and Wellman-Lord
Sulfur compounds, ppm
c3s
Sฐ2
Total sulfur, HI /day
Stream 3 Stream 4
Acid Gases CO. Vent
from Rectisol from Rectisol
298,600 9
1,400 39
trace trace
79 0.55
9
39
trace
0.55
9
39
trace
0.55
Sources of Emissions Co Atmosphere
Stream 8 Stream 9 Stream 11 Stream 12 Stream 13
Undesulfurized Desulfurized Tail Gas.. . Scavenged Tail Gas from
Low-Btu Gas (&) Low-Btu Gas^*' from Claus ^ ' Gas Wellman-Lord
trace 19,800
trace 76
NA trace
26 2.7
trace trace --
-- trace trace ~
NA 12,900
2.1 10 ~
trace . trace
trace trace
NA ~ 250
2.1 ' 0.20
-o
10
(a) SO. emission from combustion of the low-Btu gas in on-site steam/power plant.
(b) After Incineration.
-------
TABLE 21. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL LEVELS IN HYGAS PROCESS
Basis: 63 x 109 kcal/day SNG Production from Illinois No. 6 Coal
(3.93 percent sulfur)
Stream 3
Acid Gases
Control Level from Rectisol
No Control
Sulfur compounds, ppm
H S 298,300
COS 1,700
SO. trace
Total sulfur, MX/day 470
Sulfur Recovery (IGT-Melssner
and Claus)
Sulfur compounds, ppm
H2S -
COS
so2
Total sulfur, NTT/day
Sulfur Recovery Plus Tall Gas
Treatment (IGT-Meissner,
Claus, and Wellman-Lord)
Sulfur compounds, ppm
GO'S
Total sulfur, MT/day
(a) SO. emission from combustion of low-Btu gas
(b) After Incineration.
Sources of
Stream 4 Stream 8
CO 2 Vent Undesulfurized
from Rectisol Low-Btu Gae^
11 trace
300 trace
trace NA
2.8 138
11
300
trace
2.8
11
300
trace
2.8
in on-site steam/power plant.
Emissions to Atmosphere
Stream 9 Stream 11 Stream 12 Stream 13
Desulfurized Tail Gas Scavenged Tail Gas from
Low-Btu Gas (a) from Claus "") Gas Wellman-Lord.
19,400
100
trace
-- 2.9
trace trace
trace trace
NA 12,300
2.2 45
trace trace
trace trace
NA 250
2.2 0.94
-------
44
CO -Acceptor Process (High-Btu SNG)
The CO -Acceptor process is one of the advanced processes for
SNG manufacture currently under development by the Consolidation Coal
Company. A flowsheet of the process is shown in Figure 4. The flowsheet
and material-balance data, including emissions of sulfur compounds, are
(3)
based on the information developed in the recent Booz-Allen study.
The basis for process design is presented in Table 22.
Fuel Gas Desulfurization
Most of the sulfur in the coal feed is removed by a dolomite
acceptor during the gasification stage and discharged from the acceptor
regenerator as MgO.CaS in the ash. The remaining sulfur compounds in the
fuel gas stream (Stream 2) are removed by the hot potassium carbonate
process and further purified by a catalyst guard using a sponge-iron sorbent
prior to methanation.
The regenerated gas (Stream 4), containing mostly carbon dioxide,
water vapor, and about 1 percent hydrogen sulfide, from the hot potassium
carbonate absorption stage is utilized to strip out hydrogen sulfide from
the ash by the reaction of carbon dioxide and water with MgO.CaS to form
H^S and MgO ,CaCO_ . The off-gas from ash treatment now enriched with H S to
Z. J ฃ
about 9 mole percent level is sent to a Claus plant for sulfur recovery.
Sulfur balances around the hot potassium carbonate desulfurizer,
the ash treatment stage, and the sponge-iron catalyst guard are presented
in Tables 23 through 25.
Sulfur Recovery
The off-gas (Stream 6) from ash treatment and an off-gas (Stream 8)
from sour wastewater treatment are treated in a Glaus plant for sulfur
recovery. A sulfur balance around the Claus plant was obtained by using
the same method described in the preceding section for the Hygas process,
except for the sulfur recovery efficiency assumed at 83 percent. Tail gas
-------
Off-Gas to Atmosphere
Coal
Acid Gas
Removal
(K2C03)
Catalyst
Guard
Methanation
I.
Air
r~
Ash
Treatment
1
Incineration
ฉ
Sulfur
Recovery
(Claus)
ฎ
Tail-Gas
Treatment
(fieavon)
ฉ
Sul
SNG Product
Off-Gas to
Atmosphere
FIGURE 4. FLOWSHEET OF OK-ACCEPTOR PROCESS FOR HIGH-BTU SNG MANUFACTURE(3)
-------
Legend for Figure 4
46
Stream Number
1
3
4
5
6
7
8
9
10
11
Description
Off gas from coal preparation vented to atmos-
phere
Fuel gas to hot potassium carbonate unit for
acid-gas removal
\.
Purified fuel gas from hot potassium carbonate
unit
Regenerated acid gases from hot potassium carbonate
unit
Off gas from acceptor regeneration used for coal
preparation
Off gas from ash treatment
Off gas from catalyst-guard regeneration vented
to atmosphere
Off gas from wastewater treatment
Tail gas from Glaus plant, either sent to Beavon
unit for treatment or vented to atmosphere after
incineration
Elemental sulfur recovered from Glaus plant
or Glaus plant plus Beavon unit
Off gas from Beavon unit for Glaus plant tail
gas treatment vented to atmosphere ,
-------
47
TABLE 22. DESIGN BASIS FOR CO^-ACCEPTOR.PROCESS FOR THE
MANUFACTURE OF HIGH-BTU ^ '
Coal Feed
Type North Dakota Lignite
Heating value, kcal/kg 3,930
Sulfur content, percent by weight 0.59
Feed rate, MT/day 26,172
Gas Production
Production rate, nm /day^a' 7.36 x 10
3 (a)
Heating value, kcal/nm 8,475
Total fuel value 62.5 x 10ฐ
Thermal Efficiency, percent 59.2
(a) Standard conditions are 15.6.0, 1 atm.
(b) Defined as the percentage of the total heating value of the
coal feed recovered in the high-Btu SNG product.
-------
TABLE 23. SULFUR BALANCE AROUND HOT POTASSIUM CARBONATE
UNIT IN CO.-ACCEPTOR PROCESS
g
Basis: 62.5 x 10 kcal/day SNG Production from North Dakota Lignite
(0.59 percent sulfur)
6 o
Total Gas Flow, 10 nm /hr
Sulfurous Compounds, mole percent
V
COS
cs2
Sulfur in Stream
k8'hr* t*\
kg/106 kcara'
Input Stream
2
Fuel Gas In
0.785
0.05
9.3 ppm
NA
540
0.21
Output Streams
3
Fuel Gas Out
0.706
21 ppm
trace
trace
20
0.0077
4
Regenerated Aci'd Gas
0.0923
0.45
trace
trace
520
0.20
00
(a) Based on the total HHV of SNG product.
-------
TABLE 24. SULFUR BALANCE AROUND ASH TREATMENT UNIT IN CC^-ACCEPTOR PROCESS
Basis: 62.5 x 10 kcalyflay SNG Production from North Dakota Lignite
(0.59 percent sulfur)
(3)
6 3
Total Gas Flow, 10 nm /hr
Sulfurous Compounds, mole percent
V
cos
cs2
Sulfur in Stream
ks/hr (a)
kg/106 kcal
Input Streams
12 4
Ash In Regenerated Acid Gas
0.0923
0.45
trace
trace
4,630 520
1.78 0.20
Output Stream
6
H S to Glaus Unit
0.041
9.33
trace
trace
5,150
2.0
(a) Based on total HHV of SNG product.
-------
TABLE 25. SULFUR BALANCE AROUND CATALYST GUARD IN CO -ACCEPTOR PROCESS
~9
Basis: 62.5 x 10 kcal/day SNG Production from North Dakota Lignite
(0.59 percent sulfur)
,(3)
6 3
Total Gas Flow, 10 nm /hr
Sulfurous Compounds, mole percent
Y
cos
cs
Sฐ2
Sulfur in Stream
fcg'/hr, ,)
kg/106 kcal^ }
Input Stream
3
Fuel Gas In
0.706
21 ppm
trace
trace
trace
20
0.0077
Output Streams
13
Fuel Gas Out
0.706
trace
trace
trace
trace
neg
neg
7
Off-Gas to Atmosphere
NA
trace
trace
trace
NA
20
0.0077
01
o
(a) Based on total HHV of SNG product.
-------
51
incineration was assumed again as part of the Glaus plant in projecting
the sulfurous emissions from the Glaus plant alone without tail gas treat-
ment. A sulfur balance around the Glaus plant is presented in Table 26.
Tail Gas Treatment
The tail gas from the Glaus plant is treated by the Beavon process
in the scheme proposed in the Booz-Allen study. In this scheme, an inciner-
ator would be used to treat the off-gas from the Beavon unit rather than
the off-gas from the Glaus plant. The Beavon process is a two-step process
involving catalytic hydrogenation followed by the Stratford process. In
the Glaus-Beavon treatment scheme, the tail gas from the Glaus plant will
be reacted first with hydrogen to convert sulfur compounds into hydrogen
sulfide. Hydrogen sulfide is removed ir. the next step by the Stretford
process. The off-gas from the Beavon process will contain residual sulfur
mostly as COS and CS present originally in the gas stream following the
catalytic hydrogenation step. The sulfur compounds will be converted to
SO by incineration prior to discharge to the atmosphere. A sulfur balance
around the Glaus plant and the Beavon unit combined is presented in Table
27. The total sulfur content of the discharge stream (Stream 11) was
assumed at 250 ppm of SO .
Coal Preparation
Feed coal is dried as part of feed preparation stage using the
off-gas from acceptor regeneration stage. During the drying operation, a
fraction of the sulfur in the feed coal is driven off as S09 and dis-
charged into the atmosphere with the drier off-gas (Stream 1). A sulfur
balance around the coal preparation stage is presented in Table 28.
-------
TABLE 26. SULFUR BALANCE AROUND GLAUS UNIT IN CO -ACCEPTOR PROCESS
9
Basis:62.5 x 10 kcal/day SNG Production from North Dakota Lignite
(0.59 percent sulfur)
Total Gas Flow, 10 run /hr
Sulfurous Compounds, mole percent
Y
cos
cs
Sฐ2
Sulfur In Stream
kg/hrfi (b)
kg/10 kcalv '
Input
6
Off -Gas from
Ash Treatment
0.0410
9.33
trace
trace
trace
5,150
2.0
Streams
8
Off-Gas from
Wastewater Treatment
2.8 x 10"5
4.09(a)
trace
trace
trace
1.6
0.00061
Output
9
Tail Gas After
Incineration
0.0750
trace
trace
trace
0.89
910
0.35
Streams
10
Sulfur
Recovered
.
4,240
(a) Assumed at the value given in Table 4 for Stream 7 in the Lurgi process.
(b) Based on the total HHV of SNG product.
-------
TABLE 27. SULFUR BALANCE AROUND GLAUS UNIT PLUS BEAVON TAIL GAS TREATMENT IN CCL-ACCEPTOR PROCESS
9
Basis: 62.5 x 10 kcal/day SNG Production from North Dakota Lignite
(0.59 percent sulfur)
(3)
6 3
Total Gas flow, 10 nm /hr
Sulfurous Compounds, mole percent
c6s
cs
Sฐ2
Sulfur in Stream
kg ,thl (b)
kg/100 kcalv
Input
6
Off-Gas from
Ash Treatment
0.0410
9.33
trace
trace
trace
5,150
2.0
Streams
8
Off-Gas from
Wastewater Treatment
2.8 x 10"5
trace
trace
trace
1.6
0.00061
Output
11
Tail Gas After
Incineration
0.0750
trace
trace
trace
250 ppm
25 .4
0.0096
Streams
10
Sulfur
Recovered
5,130
(a) Assumed at the value given in Table 4 for Stream 7 in the Lurgi process.
(b)
01
Based on total HHV of SNG product.
-------
TABLE 28. SULFUR BALANCE AROUND COAL PREPARATION UNIT IN CO^-ACCEPTOR PROCESS
q
Basis:62.5 x 10 kcal/day SNG Production from North Dakota Lignite
(0.59 percent sulfur)
Input Stream Output Stream
5 1
Off-Gas from Off-Gas from
Acceptor Regeneration Coal Preparation
Total Gas Flow, 10 nro^/hr
Sulfurous Compounds, mole percent
H S
COS
cs
Sฐ2
Sulfur in Stream
kg/hr, f .
kgVlO6 kcal*- '
1.41
trace
trace
trace
0.03
590
0.23
2.55
trace
trace
trace
0.03
1,040
0.40
Ul
(a) Based on total HHV of SNG product,
-------
55
Emissions and Control of Sulfurous Compounds
Three alternatives for sulfur emission control can be considered
as follows :
(1) No control--The first level of control can be con-
sidered without sulfur recovery. In this case
sulfurous emissions will include: (1) SO emissions
from coal preparation, (2) SO^ emissions from catalyst
guard regeneration, (3) regenerated off-gas from hot
potassium carbonate absorption, and (4) off-gas from
wastewater treatment. The ash from the acceptor
regeneration stage would most likely be disposed of
as such without desulfurization.
(2) Sulfur recovery--This alternative will include the
Glaus plant without tail gas treatment. Sulfurous
emissions will include: (1) S0? emissions from coal
preparation, (2) SCL emissions from catalyst guard
regeneration, and (3) SO- emissions in the tail gas
from the Glaus plant.
(3) Sulfur recovery plus tail gas treatment--This will
represent the fully controlled level involving the
use of a Glaus plant and a Beavon unit for tail gas
treatment. Sulfurous emissions will consist of:
(1) SO emissions from coal preparation, (2) SO
emissions from catalyst guard regeneration , and
(3) S09 emissions in the off-gas from the Beavon unit.
Emissions of S0ซ for the three control levels as described are
presented in Table 29.
-------
TABLE 29. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL
LEVELS IN CO -ACCEPTOR PROCESS^3'
Basis: 62.5 x 109 kcal/day SNG Production from North Dakota Lignite
(0.59 percent sulfur)
Control Level
Stream 1
Off-Gas from
Coal Preparation
Sources of Emissions to Atmosphere
Stream 4
Acid Gases
from Potassium
Carbonate Process
Stream 7
Off-Gas from
Catalyst Guard
Stream 8
Off-Gas from
Wastewater Treatment
Stream 9
Tall Gas
Claus <
from
Stream 11
Tall Gas.from
Beavonu;
No Control
Sulfur compounds, ppm
V
cos
so2
Total sulfur, Ml/day
Sulfur Recovery (Claus)
Sulfur compounds, ppm
c3s
so2
Total sulfur, MT/day
trace
trace
298
25.0
trace
trace
298
25.0
A, 500
trace
trace
12.5
trace
trace
NA
0.48
trace
trace
NA
0.48
40,900
trace
trace
0.038
Ul
trace
trace
8,900
21.8
..Sulfur Recovery Plus Tall Gas
Treatment (Claus plus Beavon)
Sulfur compounds, ppm
H S
COS
so2
Total sulfur, MX/day
trace
trace
298
25.0
trace
trace
NA
0.48
trace
trace
250
0.61
(a) After Incineration.
(b) Based on total HHV of SNG product.
-------
57
Lurgi Process (Low-Btu Gas)
The Lurgi coal gasification process has been used commercially
since 1936 for manufacturing low-Btu fuel gas and ammonia synthesis gas.
There are 13 commercial plants in operation today. A flowsheet of the
process for the manufacture of a low-Btu utility gas delivered at 2 atm
(15 psig) by steam-air gasification of coal is shown in Figure 5. The
flowsheet and material-balance data, including emission data, are based on
(3)
the information developed in the recent Booz-Allen study. The basis for
process design is given in Table 30 for the manufacture of a utility gas at
9 9
a plant capacity of 32.8 x 10 kcal/day (130 x 10 Btu/day).
Of the total coal feed of 9,369 MT/day (10,330 tons/day), 93.7
(5a)
percent is fed to the gasifier and 6.7 percent is fed to a boiler . The
boiler supplies 213 MT/hr (235 tons/hr) of steam to the gasifier. The ex-
pansion of the product gas from 18 atm (250 psig) to 2 atm (15 psig) supplies
the energy for driving the air compressor which delivers the gasification
air. The expansion turbine produces excess energy estimated at 51,400 kw.
The excess energy was included as a credit toward the overall thermal ef-
ficiency of the process at a rate of 10,000 Btu coal/kwh.
Fuel Gas Desulfurization and Sulfur Recovery
The fuel gas produced from steam-air gasification is desulfurized
using a high-pressure Stretford unit operated at 18 atm (250 psig). In the
Stretford unit, H S is nearly quantitatively removed and converted to
elemental sulfur which is recovered as a by-product. Carbonyl sulfide and
carbon disulfide are not removed by the Stretford unit and remain with the
fuel gas.
If the Phenosolvan process is employed for the recovery of phenol,
an off-gas from the Phenosolvan unit would be emitted, containing hydrogen
sulfide. Since the off-gas stream is comparatively small, it was assumed
that the off-gas is pressurized and fed to the Stretford unit with the fuel
gas for desulfurization. A sulfur balance around the Stretford unit is
presented in Table 31.
-------
Coal
Coal
Air
Coal
Preparation
Desulfuri-
zation and
Sulfur Recovery
(Stretford)
(3)
Sulfur
Expansion
Turbine
.Low-Btu
Gas Product
Electricity
Ln
00
FIGURE 5. FLOWSHEET OF LURGI PROCESS FOR LOW-BTU GAS MANUFACTURE
(3)
-------
59
Legend for Figure 5
Stream Number Description
1 Sour fuel gas to Stretford unit for desulfurization
2 Purified fuel gas product from Stretford unit
3 Elemental sulfur recovered from Stretford unit
4 Off gas from Phenosolvan process for by-product
recovery sent to Stretford unit
-------
60
TABLE 30. DESIGN BASIS FOR LURGI PROCESS FOR THE MANUFACTURE
OF LOW-BTU GAS BY STEAM-AIR GASIFICATION OF COAL(3ป5a)
Coal Feed
Type Navajo Seam
Heating value, kcal/kg 4,817
Sulfur content, weight percent 0.69
Feed rate, MT/day ' 9,369
Gas Production
O f \ ฃ.
Production rate, nan /day ' 18.8 x 10
Heating value, kcal/mn3^a) 1,739
Total fuel value, kcal/day 32.8 x 10
Product gas pressure, a tin, 2
Thermal Efficiency, percent 77.9
(a) Dry basis.
(b) Defined as the percentage of the total heating
value of the coal feed recovered in the low-Btu
gas product plus 51,400 kw of net power generation
from expansion of product gas.
-------
TABLE 31. SULFUR BALANCE AROUND HIGH PRESSURE STRETFORD UNIT FOR
DESULFURIZATION OF LOW-BTU GAS IN LURGI PROCESS
-. Q
Basis: 32.8 x 10 kcaI/dayJLow-Btu Gas Production from
Navajo Seam Coal (0.69 percent sulfur)
Total Gas Flow, 10 nm3/hr (dry basis)
Sulfurous Compounds, mole percent (dry basis)
HS
COS
CS2
Sulfur in Stream
kg/hr
kg/106 kcal(b>
Input
1
Fuel Gas
0.774
0.217
0.013
trace
2,400
1.8
Streams
4
Off-Gas from
Phenosolvan
0.00073
4.09
trace
trace
45
0.033
Output
2
Streams
3
Fuel Gas Sulfur Recovered
0.773
0.001
0.013
trace
146
0.11
.
2 ,300 (a)
(a) By difference.
(b) Based on the total HHV of the low-Btu gas product.
-------
62
Emissions and Control of Sulfurous Gases
Two alternatives for the control of sulfurous emissions were con-
sidered as follows:
(1) No control - Without the Stretford unit, the un-
desulfurized fuel gas and the off-gas from the
Phenosolvan process would be directly sent to a
utility boiler. The sulfurous compounds in the
gases would be converted to and emitted as SO
from the boiler stack.
(2) Desulfurization and sulfur recovery - This
alternative involves the use of a Stretford unit
for desulfurization of the fuel gas and the off-gas
from the Phenosolvan process and the recovery of a
sulfur by-product. Sulfurous emissions in this
case again would be SO from the combustion of
the desulfurized gases in a power plant boiler.
Emissions of sulfurous gases for the two control alternatives as
described above are presented in Table 32.
Koppers-Totzek Process (Low-Btu Gas)
The Koppers-Totzek process has been used commercially since 1952
for the production of synthesis gas from coal gasification. There are 20
commercial plants in operation or under construction at present. Most of
these plants are designed for the production of ammonia synthesis gas from
coal. A flowsheet for the production of a desulfurized utility gas delivered
at 2 atm (15 psig) by steam-oxygen gasification is given in Figure 6. The
flowsheet and material balance data, including emissions of sulfurous
compounds, are based on the information supplied by Koppers Company '
The basis for process design is given in Table 33 for the manufacture of
9 9
a utility gas at a plant capacity of 32.8 x 10 kcal/day (130 x 10 Btu/day).
-------
TABLE 32. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL LEVELS
IN LURGI PROCESS FOR LOW-BTU GAS MANUFACTURED)
Basis: 32.8 x 109 kcal/day Low-Btu Gas Production from Navajo Seam Coal
(0.69 percent sulfur)
Sources of Emissions to Atmosphere
Stream 1
Undesulfurized
Control Level
Fuel Gas
(a;
Stream 2
Desulfurized
Fuel Gas
-------
Coal
Coal
Air
Tail-Gas
Treatment
(Beavon)
Off-Gas to
Atmosphere
Low-Btu
Gas Product
ON
FIGURE 6. FLOWSHEET OF KOPPERS-TOTZEK PROCESS FOR LOW^BTU GAS MANUFACTURE
(3)
-------
65
Legend for Figure 6
Stream Number Description
1 Sour fuel gas to MDEA unit for desulfurlzation
2 Desulfurized fuel-gas product from MDEA unit
3 Regenerated acid gases from MDEA unit
4 Tail gas from Glaus plant, either sent to Beavon
unit for treatment or vented to'atmosphere after
incineration
5 Elemental sulfur recovered from Glaus unit
6 Off gas from Beavon unit for treatment of
Glaus plant tall gas vented to atmosphere
-------
66
TABLE 33. DESIGN BASIS FOR KOPPERS-TOTZEK PROCESS FOR THE
MANUFACTURE OF LOW-BTU GAS BY STEAM-OXYGEN
GASIFICATION OF COAlX6>7a)
Coal Feed
Type Eastern High-
Volatile Bituminous
(a\
Heating value, kcal/kgv ' 7,059
(a)
Sulfur content, weight percentv 1.08
Feed rate, MT/day^ 6,715
Gas Production
Production rate, nm /day^ '. 12.5 x 10
Heating value, kcal/nm > ' 2,620
3 9
Total fuel value, kcal/nm /day 32.8 x 10
Product gas pressure, atm 2
(c)
Thermal Efficiency, ' percent 69
(a) Based on a dried coal with 2 percent moisture.
(b) Dry basis.
(c) Defined as the percentage of the total heating
value of the coal feed recovered in the low-Btu gas
product. Of the total coal feed, 83.2 percent is
fed to gasifier and 16.8 percent is fed to boiler.
-------
67
Of the total coal feed of 6,715 MT/day (7,404 tons/day), 83.2 per-
(7a)
cent is fed to the gasifier and 16.8 percent is fed to a boiler . The
boiler supplies steam for the gasifier and power required primarily for
oxygen manufacture and for compressing the product gas to 2 atmosphere
(15 psig).
Fuel Gas Desulfurization
The fuel gas produced from steam-oxygen gasification, after
washing and cooling, is desulfurized by an amine absorption unit using
raethyldiethanolamine (MDEA) as an absorbant. The MDEA unit is designed to
desulfurize the fuel gas to about 250 ppm of total sulfur compounds as H S
and COS in the product and to provide a Glaus plant feed containing about
28 percent HซS. An additive is used to hydrolyze and convert about 75 per-
cent of COS in the feed to H.S. A sulfur balance around the MDEA unit is
given in Table 34.
Sulfur Recovery and Tail-Gas Treatment
The H S regenerated from the MDEA desulfurization unit is treated
by a Glaus plant for sulfur recovery. A sulfur-recovery efficiency for the
Glaus plant was assumed at 93 percent for an H S concentration in the feed
at 26.9 percent. A sulfur balance around the Glaus plant is given in
Table 35.
The Beavon process was considered for treating the tail gas from
the Glaus plant. A sulfur balance around the combined Glaus plant and a
Beavon unit is given in Table 36.
Emissions and Control of Sulfurous Gases
Three alternatives were considered for the control of sulfurous
emissions as follows:
-------
TABLE 34. SULFUR BALANCE AROUND MDEA UNIT FOR DESULFURIZATION OF FUEL GAS
Basis: 32.8 x 109 kcal/day Low-Btu Gas Production from Eastern High-
Volatile Bituminous Coal (1.08 percent sulfur)
Total Gas Flow, 106 nm3/nr^
(a)
Sulfurous Compounds, mole percent
V
cos
cs2
Sulfur in Stream
kg/hr
kg/106 kcalCb)
Input Stream
1
Fuel Gas
0.526
0.35
0.04
trace
2,770
2.0
Output Streams
2
Fuel Gas
0.521
150 ppm
100 ppm
trace
177
0.13
3
H S to Glaus
0.0068
26.9
1.1
trace
2,590
1.9
(a) Dry basis.
(b) Based on the total HHV of the low-Btu gas product.
oo
-------
TABLE 35. SULFUR BALANCE AROUND GLAUS UNIT IN KOFPERS-TOTZEK PROCESS
(6,7)
Basis: 32.8 x 10^ kcal/day Low-Btu Gas Production from Eastern High-Volatile
Bituminous coal (1.08 percent sulfur)
Total Gas Flow, 10 nm 3/hr
Sulfur Compounds, mole percent
CD'S
so2
Sulfur in Stream
kg/hr
kg/106 kcalOO
Input Stream
3
H2S from
MDEA
0.0068
26.9
1.1
trace
2.590
1.9
Output Streams
4
Claus Plant
Tail Gas (a>
0.0144
trace
trace
0.93
181
0.13
5
Sulfur
Recovered
2,400
(a) After incineration.
(b) Based on the total HHV of the low-Btu gas product.
-------
TABLE 36. SULFUR BALANCE AROUND CLAUS UNIT PLUS BEAVON UNIT IN KOPPERS-TOTZEK PROCESS
Basis: 32.8 x 10ฐ kcal/day Low-Btu Gas Production from Eastern High-Volatile
Bituminous Coal (1.08 percent sulfur)
(6,7)
\
6 -j
Total Gas Flow, 10 ntir/hr
Sulfur Compounds, mole percent
c3s
so2
Sulfur in Stream
kg/hr
kg/ 106 kcal(b)
Input Stream
3
H S from
T4DEA
0.0068
26.9
1.1
trace
2,590
1.9
Output Streams
6 5
Tail Gas from Sulfur, v
Ca)
Claus + Beavon Recovered
0.0116
trace
trace
250 ppm
3.9 2.590
0.0029
(a) Combined sulfur recovery from Claus plus Beavon units.
(b) Based on the total HHV of the low-Btu gas product.
-------
71
(1) No control - The fuel gas produced from the
gasifier would be directly sent to a utility
boiler. The sulfurous compounds in the fuel
gas would be converted to and emitted as SO
from the boiler stack.
(2) Desulfurization and sulfur recovery - This
alternative would involve the use of an MDEA.
absorption unit to desulfurize the fuel gas
and a Glaus plant for sulfur recovery. Sulfurous
emissions would include SO emission from com-
bustion of the desulfurized fuel gas and SO
emission from incineration of a tail gas stream
from the Glaus plant.
(3) Desulfurization, sulfur recovery, and tail-gas
treatment - This alternative would involve treating
the Glaus plant tail gas using the Beavon process.
Sulfurous emissions would include S0ซ emissions
from combustion of the desulfurized fuel gas
and SO emission from the Beavon process.
Emissions of SO. for the three alternatives as described above
are given in Table 37.
-------
TABLE 37. EMISSIONS OF SULFUR COMPOUNDS FOR ALTERNATIVE CONTROL LEVELS IN
KOPPERS-TOTZEK PROCESS FOR LOW-BTU GAS MANUFACTURE(6ป7)
9
Basis: 32.8 x 10 kcal/day Low-Btu Gas Production from Eastern
High-Volatile Bituminous Coal (1.08 percent sulfur)
Sources of Emissions to Atmosphere
Stream 1 Stream 2 Stream 4 Stream 6
Undesulfurized Desulfurized Tail Gas from Tail Gas from
Fuel Gas(a) Fuel Gas(a) Glaus Plant(b) Glaus + Beavon
No Control
H2S trace
COS trace
Sulfur compounds, ppm
H2S
COS
S02 1,000 -- --
Total sulfur, MT/day 66 -- -- -- to
jjulfur Recovery (MDEA plus Glaus)
Sulfur compounds, ppm
H2S trace trace
COS ... -- trace trace
S02 --70 9,300
Total sulfur, MT/day -- 4.2 4.3
Sulfur Recovery Plus Tail-Gas Treat-
ment (MDEA plus Glaus plus Beavon)
Sulfur compounds, ppm
HoS -- trace -- trace
COS -- trace -- trace
S02 70 -- 250
Total sulfur, MT/day -- 4.2 -- 0.094
(a) S02 emission from combustion of the low-Btu gas in a utility boiler.
(b) After incineration.
-------
73
SULFUROUS EMISSION CONTROL PROCESSES
Control of sulfurous emissions in coal gasification processes
can be considered under three broad categories:
(1) Desulfurization of gaseous products from coal
gasification
(2) Sulfur recovery
(3) Tail gas treatment.
Desulfurization requirements vary depending upon the end use of
products. In the manufacture of a high-Btu SNG, the desulfurization stage
usually follows a shift reaction and is employed to remove sulfur compounds
to an extremely low level, typically less than 1 ppm, to provide a low
sulfur stream for the methanation reaction. The bulk of carbon dioxide is
also removed in the desulfurization stage to upgrade the fuel value of the
final SNG product and also to achieve more efficient methanation. In an
SNG manufacture, therefore, desulfurization is usually considered a part of
the production process rather than an emission control process.
In the manufacture of a low-Btu gas for a utility fuel, the raw
gas from gasification is desulfurized without shift reaction to produce
the fuel gas. The requirement for the residual sulfur in the low-Btu
utility gas is considerably less stringent than for the SNG production.
For example, to meet the present Federal standards for coal-burning sources
set at 2.2 kg S/10 kcal (1.2 Ib SCv/10 Btu), a typical low-Btu gas with a
3
heating value of 1740 kcal/nm (195 Btu/scf) manufactured by the Lurgi
steam-air gasification can contain up to 1,400 ppm of total sulfur. For a
3
typical low-Btu gas with a heating value of 2620 kcal/nm (294 Btu/scf)
from the Koppers-Totzek steam-oxygen gasification, the permissible level
is about 2,100 ppm of total sulfur. For utility application, the removal
of carbon dioxide from the fuel gas is not considered necessary or even
desirable, unless there is an unusual requirement for upgrading the heating
value of the fuel.
The desulfurization stage produces a waste gas stream which
contains sulfur compounds mainly as hydrogen sulfide. The prevalent method
of disposing of the waste gas at existing coal gasification plants outside
-------
74
of the D. S. appears to be flaring and venting it to the atmosphere. For
all of the gasification processes selected in this study for potential
usage in the U. S. for the manufacture of high-Btu SNG and low-Btu utility
gases, conversion of HLS into sulfur is considered as the preferred approach
for treating the waste gas from desulfurization.
As an additional emission control requirement, treatment of a
tail gas from the Glaus sulfur recovery process is being considered for
coal gasification processes. One approach under consideration involves
the addition of a tail gas treatment process to the Glaus process to reduce
the sulfur content of the tail gas before discharge to the atmosphere. This
approach is the most common practice in the petroleum industry for treating
Glaus tail gas.
An alternative treatment method, which has been proposed for the
SNG plant by WESCO, involves piping the tail gas to an on-site coal-fired
steam/power plant for combustion and removing the SO resulting from both
the tail gas and from coal combustion in a power plant stack-gas cleaning
process.
Control processes, which have been proposed or have potential
application in coal gasification processes, have been developed and used
commercially by the petroleum industry. Typical processes which have
commercial importance in the petroleum industry are listed below.
Acid Gas Removal
Adip
Alkazid
Benfield
Catacarb
Fluor Econamine
Fluor Solvent
MEA
DEA
SNPA-DEA
Purisol
Rectisol
Sulfinol
Sulfur Recovery
Glaus
Giammarco-Vetrocoke
Stretford
Tail Gas Treatment
Beavon
Cleanair
IFP-1
SCOT
Sulfreen
Wellman-Lord
-------
75
ACID GAS REMOVAL PROCESSES
Removal of acid gases, such as H^S and C09, is usually accomplished
by absorption into a liquid phase using a suitable gas-liquid contacting
equipment. Absorption processes can be divided into three broad categories
depending upon the type of absorbent used. Physical solvent processes,
which include the Selexol, Rectisol, Purisol, and Fluor Solvent processes,
operate by the principle of physical absorption. Chemical solvent processes
are based on various amines and alkaline salt solutions, which react chemi-
cally with acid gases. Amine processes include MEA, DEA, TEA, MDEA, Adip,
Econamine, SNPA-DEA, and Sulfinol processes. Processes based on alkaline
salt solutions include the Benfield, Catacarb, and Alkazid processes. There
are direct conversion processes, such as the Stretford and Giammarco-
Vetrocoke processes, which are capable of absorption and oxidation of H S
to produce sulfur directly. The latter processes are considered as sulfur
recovery processes in this study.
Physical Solvent Processes
Physical solvent processes are recommended usually for high-pres-
sure gas treating and for purifying gases to an extremely low level of
hydrogen sulfide and other sulfur compounds required for SNG and synthesis
gas manufacture. Physical solvent processes in general have the capability
for selective absorption of hydrogen sulfide from gases containing carbon
dioxide, thereby producing an H S-rich stream suitable for a Glaus plant
feed. Physical solvent processes are capable of removing other sulfur
compounds which occur in coal gases such as COS, GS2, mercaptans, and thio-
phenes. Disadvantages of physical solvent processes are a relatively high
solubility of hydrocarbons in the physical solvents and high solvent costs
compared with chemical solvents. Commercially important physical solvent
processes are listed in Table 38.
-------
TABLE 38. PHYSICAL SOLVENT PROCESSES FOR GAS PURIFICATION^
Commercial Units in Operation
Process Developer/Licensee or Under Construction
Selexol Allied Chemical Now operating or under construction in natural gas
treatment, synthesis gas purification, and coal
gasification purification
Rectisol Lurgi, Linde AG 23 in operation plus 7 under construction
Purisol Lurgi, Linde AG 4 in operation, including 2 for hydrogen production
and 2 for natural gas sweetening
Fluor Solvent Fluor Engineers and Constructors 10 in operation, including 7 on natural gas, 1 in
ammonia production, and 2 in hydrogen production
-------
77
Selexol Process
The process was developed and is licensed by Allied Chemical
Corporation. The process is based on physical absorption using dimethylether
of polyethylene glycol, tradenamed Selexol, as the solvent. The process
will be used for gas purification in the Bi-Gas process for coal gasifi-
cation as part of the 5 tons/hr pilot plant being built at Homer City,
(9)
Pennsylvania, by the Bituminous Coal Research.
The Selexol process can be used for gas purification in coal
gasification processes for both high-Btu SNG and low-Btu utility gas manu-
facture. The Selexol process, like other physical absorption processes,
is normally designed to operate economically at high pressures. The
nominal design pressure for the unit for the Homer City Bi-Gas pilot plant
is 69 atm (1000 psig). For low-pressure gasification processes, such as the
Koppers-Totzek process, the raw gas is usually pressurized to about 21 atm
(300 psig) for the Selexol process.
For high-Btu gas applications, the Selexol process employs two
stages. The first stage removes the bulk of hydrogen sulfide preferentially
and produces a H S-rich stream suitable for a Glaus plant feed. The second
stage removes CO and the residual H S. A sulfur balance around the Selexol
process is given in Table 39 for a high-Btu gas application. The residual
sulfur content of the purified gas is less than 1 ppm of H9S and COS com-
bined. The H'S stream recovered from the first stage contains about 30 per-
cent H?S plus COS, which can be treated economically in a Glaus plant for
sulfur recovery. The C0ซ stream recovered from the second stage contains
less than 20 ppm of H2S plus COS. The C02 stream is normally vented
directly to atmosphere.
For low-Btu gas applications, the first stage alone is used for
selective removal of H S. A sulfur balance is given in Table 40. The H2S
stream recovered for Glaus plant feed contains about 20 percent H S plus
COS when the gas is treated to a residual sulfur level at around 1 ppm of
H S plus COS.
Other contaminants, such as HCN, methyl mercaptan, and thiophene,
have greater solubilities in Selexol than H-S and can be removed effectively.
-------
TABLE 39. SULFUR BALANCE AROUND SELEXOL UNlf FOR ACID GAS REMOVAL IN HIGH-BTU SNG MANUFACTURE^10^
Basis: 63 x 109 kcal/day High-Btu SNG Production
Pressure: 69 atm
Total Gas Flow, 10 mn3/hr (dry basis)
Gas Composition, mole percent (dry basis)
d.
cor
CO
c3s
Sulfur in Stream
kg/hr
kg/106 kcalCa)
Input Stream
Fuel Gas
In
1.25
46.0
8.0
15.0
30.0
0.7
0.07
13,200
5.0
Output Streams
Fuel Gas C02 Vent
Out to Atmosphere
0.866 0.348
66.3
11.5
21.6
0.5 100
H2S + COS H2S + COS
<1 ppm =20 ppm
1.2 9.5
0.00046 0.0036
H.S to
Glaus
0.0320
70
27
3
13,200
5.0
oo
(a) Based on total HHV of SNG product.
-------
TABLE 40. SULFUR BALANCE AROUND SELEXOL UNIT FOR DESULFURIZATION OF LOW-BTU GAS
Basis: 32.8 x 109 kcal/day Low-Btu Utility Gas Production
Pressure: 21 atm
(10)
Total Gas Flow, 10 nm3/hr (dry basis)
Gas Composition, mole percent (dry basis)
H
CO
CH.
N2
CO
c3s
Sulfur in Stream
kg/hr
kg/106 kcal(a)
Input Stream
Fuel Gas
In
0.954
15.0
22.0
4.0
49.0
9.0
0.7
0.07
10,000
7.3
Output Streams
Fuel Gas
Out
0.91
15.6
22.9
4.2
51.1
6.2
H S + COS
= 1 ppm
1.3
0.00095
H-S to
Glaus
0.034
NA
NA
NA
NA
80
18
2
10,000
(a) Based on the total HHV of low-Btu gas product.
-------
80
Rectisol Process
The Rectisol process was originally developed jointly by Lurgi and
German Linde. The process is licensed in the United States by American Lurgi
Corporation and by Lotepro Corporation, a subsidiary of Linde AG-Germany
The Rectisol process is a physical absorption process using
methanol as a solvent and typically operated at high pressures 21 to 137 atm
(300 to 2000 psig) and at low temperatures using refrigeration. The process
can be used for selective desulfurization or total acid-gas removal in the
manufacture of both high-Btu and low-Btu gases by coal gasification.
For high-Btu gas applications, gas purification is sometimes
accomplished in two stages: the first stage for selective desulfurization,
producing an H^S-rich stream suitable for a Claus plant feed, and the second
stage for the bulk removal of CCL. The CO stream regenerated from the
second stage is normally vented directly to the atmosphere. Typical sulfur
balances for the Rectisol process in a high-Btu gasification process are
shown in Tables 12 and 13 presented earlier in describing the Hygas process.
In low-Btu gasification processes, the first stage alone is
employed to remove H S and COS selectively. A typical sulfur balance for a
low-Btu gas application is given in Table 41.
Purisol Process >
The Purisol process was developed by Lurgi in Germany and is
licensed in the United States by American Lurgi Corporation.
The Purisol process is a physical absorption process, using N-
methylpyrrolidone (NMP) as a solvent. Absorption is usually carried out at
high pressures--typically above 55 atm (800 psig)and at ambient tempera-
(13)
ture. The solvent, NMP, is similar to Selexol with respect to the total
solubilities of H S and C02 and the selectivity between the two. Performance
of the Purisol process, therefore, is expected to be comparable to that of
the Selexol process when applied to coal gasification processes. Typical
material balance data from natural gas treatment for selective H2S removal
are shown in Table 42. For applications in coal gasification processes, the
-------
TABLE 41. SULFUR BALANCE ABOUND RECTISOL UNIT FOR DESULFURIZATION OF LOW-BTU GAS
Basis: 32.8 x 109 kcal/day Low-Btu Gas Production
Pressure: 25 to 27 atm
(12)
Total Gas Flow, 10 nuP/hr (dry basis)
Gas Composition, mole percent (dry basis)
H
CO
CH.
N
ft
c3s
Sulfur in Stream
kg/hr
kg/106 kcal(a)
Input Stream
Fuel Gas
In
0.931
16.2
21.8
4.1
48.7
8.5
0.6
0.1
8,620
6.3
Output Streams
Fuel Gas
Out
0.900
16.8
22.5
4.3
50.4
6.0
1
1
2.4
0.0018
H S to
Glaus
0.031
0.1
0.4
0.6
0.5
77.8
18.2
2.4
8,620
6.3
oo
(a) Based on total HHV of low-Btu gas product,
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82
(13)
TABLE 42. MATERIAL BALANCE AROUND PURISOL PROCESS IN SELECTIVE
REMOVAL OF H2S FROM NATURAL GAS
Pressure = 74 atm
Output Streams
Input Stream H.S to
Gas In Gas Out Glaus
Gas Composition, mole percent
CH.
4
c3
H-o
75.0
4.0
15.0
6.0
82.0
4.4
13.6 .
tL
2 x 10 *
3.0
29.3
67.7
-------
83
data given earlier for the Selexol process in Tables 39 and 40 would approxi-
mate the typical performance expected from the Purisol process.
Fluor Solvent Process
The process was developed and is licensed by Fluor Engineers and
Constructors, Inc. The process employs propylene carbonate as a solvent for
H_S and CO.. The process was originally developed for bulk removal of CO-
from high-pressure natural gas.
The Fluor solvent process, like other physical solvent processes,
is economical for treating gases at high pressures with a partial pressure
fa\
of acid gases in the feed at 6 atm (75 psi) or higher. In addition to
CO and H S removal, the process is capable of removing COS, CS , and
mercaptans.
According to the process developer, a two-step process is
recommended for treating sour gas from coal gasification, using the Fluor
solvent process followed by a diethanolamine clean-up stage. For a typical
coal gas containing 25 to 30 percent C02 and 1 percent H2S, the Fluor solvent
process employed as the first step, would remove over 90 percent of each.
This is followed by a diethanolamine clean-up step, which reduces the CO.
concentration to less than 0.5 percent and H S to about 16 ppm. The two-
step process can be used for gas purification in high-Btu coal gasification
processes. The selectivity of the solvent for H_S removal in the presence
of CO is not known to assess the capability of the process for producing
an H S-rich stream suitable for a Glaus plant feed. According to Bucking-
ham , H.S is several times as soluble as CO- in propylene carbonate.
Supporting data for selectivity are not available. The selectivity for H S
removal will determine the applicability of the process to desulfurization
of low-Btu utility gas manufactured by coal gasification.
-------
84
Amine Processes
Alkanolamine solutions have been used widely for many years for
gas purification. Removal of acidic gases, such as CO^ and H S, is accomp
lished by the reaction of the amino nitrogen with the acidic gases, as
shown below for monoethanolamine:
C02 Removal: 2RNH2 + H20 + C02 ฃ
Removal:
or
2RNH. + C00
2 2
2RNH2 + H2S
(RNH3)2S +
;ป RNHCOONH.R
# C
H2S ;
J
RNH ) S
^ 2RNH-HS
An important advantage of amine processes is a low solubility of
hydrocarbons in aqueous amine solutions employed.
A typical listing of amine processes is given in Table 43. All
amine systems, except TEA and MDEA systems, are commercially active processes,
The TEA and MDEA systems are not considered commercially competitive with
other amine processes because of comparatively low sorption capacities of
tertiary amines. Tertiary amines, such as TEA and MDEA, however, have some
selectivity toward H S removal. For this reason, the use of tertiary amine
systems will have an important advantage in coal gasification processes,
where the ratio of H S to CO is in general low. The MDEA system, for
example, is specified in the Koppers-Totzek process for the desulfurization
of a low-Btu utility gas.
Other processes based on either primary or secondary amines are
considered nonselective between H S and CO absorption and, consequently,
will produce regnerated acid gases with a low H2S concentration, which would
not be suitable as a feed to a Claus plant and must be treated by the more
costly Stretford process.
Alknolamines in general are not considered effective in removing
carbonyl sulfide. Some carbonyl sulfide is believed to be removed by
reaction with amines. Primary amines , such as MEA and DGA, react with COS
-------
TABLE 43. AMINE PROCESSES FOR GAS PURIFICATION
(8)
Processes
Absorbent
Developer/Licensee
Commercial Plants
in Operation or
Under Construction
MEA
DBA
TEA
MDEA
Adip
Econamine
SNPA-DEA
Sulfinol
(a)
Monoethanolamine (MEA)
Diethanolamine (DEA)
Triethanolamine (TEA)
Methyldiethanolamine (MDEA)
Diisopropanolamine (DIPA)
2 (2-amineothoxy)
ethanol (DGA)
Diethanolamine (DEA)
Diisopropanolamine (DIPA)
plus tetrahydrothiophene
1, 1 dioxide (Sulfolane)
Shell Development
Fluor Enginers and
Contruetors
Ralph M. Parsons
Shell Development
Several hundred units
Several hundred units
Not commerically important
Not commercially important
130 units
19 units
85 x 106 nm3/day of raw gas
More than 100 units
00
(a) SNPA stands for Societe Nationale des Petrole d'Aquitaine.
(b) Number of units in operation is not available.
-------
86
to form compounds which cannot be regenerated under normal process conditions.
Secondary amines, such as DBA and DIPA, also react with COS to form degra-
dation products. The latter, however, can be decomposed in the normal amine
(18)
regeneration stage into C0_, H?S, and amine. Tertiary amines are
believed to be inert to COS.
Gases produced from coal gasification typically contain several
hundred ppm of COS. For the manufacture of a high-Btu SNG, the desulfurization
requirement is usually specified at a total sulfur level down to a few ppm,
which cannot be met by the normal amine-type processes. An exception is the
Shell Sulfinol process, in which a physical solvent (Sulfolane) is employed
in combination with an amine (DIPA) to provide more efficient removal of
COS. The Sulfinol process is, therefore, a combined chemical-physical ab-
sorption process, incorporating the advantages of both types of sorbents.
It should be noted as a disadvantage that the addition of Sulfolane increases
absorption of hydrocarbons. A comparison of the performance of DIPA and
combined DIPA and Sulfolane is given in Table 44 reported for operation of
typical Shell ADIP and Sulfinol processes for purification of synthesis
gases. Comparable performance in terms of C02 removal and desulfurization
would be expected for application in coal gasification processes.
Use of amine processes for gas purification in coal gasification
processes will depend upon the capability of individual processes for Ee-
moving COS and selectivity toward H S removal. For high-Btu SNG appli-
cation, amine processes in general cannot effectively remove COS and con-
sequently are not expected to be in significant usage. An exception is the
Shell Sulfinol process which has the capability for removing COS and other
sulfur compounds beside H_S. The Sulfinol process, however, has a low
selectivity toward H.S removal and will be unable to produce a concentrated
H S stream suitable for a Glaus plant feed. For low-Btu utility gas manu-
facture, tertiary amines, sucn as TEA and MDEA, have the potential for com-
mercial application because of their capability.for selective H2S removal,
whereby the C02 content of the fuel gas remains substantially unchanged and
also the regenerated acid gases are enriched with H S for sulfur recovery
by the Glaus process.
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87
TABLE 44. TYPICAL OPERATING DATA FOR SHELL ADIP AND SULFT.NOL
PROCESSES FOR PURIFICATION OF SYNTHESIS GASES
Gas Composition, mole percent
ADIP Sulfinol
Gases Removed Inlet Outlet Inlet Outlet
C02 5.5 NA 5.2 25 ppm
H2S 0.5 2 ppm 0.36 0.5 ppm
COS 200 ppm 100 ppm 125 0.4 ppm
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88
Alkaline Salt Solution Processes
Processes in this group rely upon chemical absorption of acid
gases using alkaline salt solutions. Commercially important processes
listed in Table 45, include the hot potassium carbonate and the Alkazid
processes.
Hot Potassium Carbonate Process
The hot potassium carbonate process for commercial application was
originally developed by the U.S. Bureau of Mines at Bruceton, Pennsylvania,
and used for bulk removal of C00 from a synthesis gas as part of work on
(19)
liquid-fuel synthesis from coal. The process has been widely used in the
petroleum industry for removing CCL and H S from synthesis gas, hydrogen,
SNG, and natural gas. Since the original process came into being, two
improved versions of the process based on the use of catalysts to promote
the overall rate of CO. absorption and regeneration have been developed under
the name of the Benfield and the Catacarb processes.
The chemistry involved in the uncatalyzed potassium carbonate
process is shown below.
H20 + K2CO ฃ KOH + KHC03
C0_ + KOH ฃ KHC03
H S + KOH 4! KHS + H20.
The Benefield process is believed to be based on the use of di-
ethanolamine as the catalyst and involve the following reactions for CO
n (17)
removal:
C02 + R2NH # R2NCOOH
R NCOOH + KOH ฃ R NH + KHCO .
The process scheme for potassium carbonate systems is similar to
that of amine systems, involving absorption and regeneration stages. The
potassium carbonate systems, however, are operated at relatively high ab-
sorber temperatures typically in the neighborhood of 93 to 121 C (200 to
250 F), which permits considerable savings from elimination of heat exchangers
-------
TABLE 45. ALKALINE SALT SOLUTION PROCESSES FOR ACID GAS REMOVAL
(8)
Process
Developer/Licensee
Commercial Units in Operation
or Under Construction
Benfield
Catacarb
Benfield
Eickmeyer & Associates
More than 250 operating units, including 18 for
natural gas sweetening, and over 150 units for CO-
scrubbing of reformed and partial oxidation gases
73 in operation or under construction, including 34
units for ammonia production, 32 units for hydrogen
production, and the remaining units for natural gas
and SNG treatment
oo
Alkazid
I. G. Farben, Davy Powergas
Over 80 in operation
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90
and low steam and cooling water requirements. The process is considered
economical at an absorber pressure of 21 atm (300 psig) or higher, since
solution regeneration is accomplished in part by flashing of the rich solution,
An important advantage of the hot carbonate process as applied
to treating sour gas from coal gasification is the capability of the process
for removing carbonyl sulfide by hot alkaline solutions without signifi-
cant solution degradation. Carbonyl sulfide is removed by hydrolysis by
the following reaction:
COS + H20 t C02 + H2S .
Carbon disulfide and mercaptans are not removed to any great extent except
(21)
by physical absorption which is expected to be small.
A disadvantage of the potassium carbonate process is contamination
of carbonate solutions which has a depressing effect on the solution
(22)
activity. Contaminants usually found from plant operations are potas-
sium formate and sulfate. Formate results from a very slow reaction of
carbon monoxide with hydroxyl ions catalyzed by traces of oxygen. Sulfate
is produced by oxidation of hydrogen sulfide. Traces of oxygen involved in
both reactions can be introduced to coal gases from air-saturated water
employed for direct-contact cooling and scrubbing of raw gases. Use of
catalysts in the Catacarb and the Benfield processes is designed to offset
degradation of solution activity by promoting the absorption and de-
sorption of carbon dioxide.
The Catacarb process was developed by A. G. Eickmeyer and
currently licensed by Eickmeyer and Associates in the U.S. At present,
there are 73 Catacarb plants in operation or under construction world-
US)
wide o A great majority of the plants are employed for removal of C0?
in the manufacture of hydrogen and ammonia synthesis gas. According to
(23)
Eickmeyer, the Catacarb process can be designed for selective removal
of H S in treating sour gas from coal gasification. For example, a feed
gas containing 1 percent H_S and 18 to 20 percent C0? can be treated to
yield an H.S-rich gas, containing 27 percent H_S, suitable for a Glaus
plant feed. Hot potassium carbonate process in general is not considered
-------
91
selective for H.S removal. Selectivity is achieved in the Catacarb process
by changing operating conditions and solution compositions. The Catacarb
process has been employed also for treating sour natural gas for CCL and
H S removal. In a typical natural gas sweetening application at the Brega
plant in Libya, the H S removal was from 0.79 percent in the feed down to
(24)
2.3 ppm and C0? removal from 1.4 percent to 20 ppm.
The Benfield process also employs a proprietary catalyst to
promote absorption of C0ป into a hot potassium carbonate solution. The
process is used for the removal of CO^, H S, and COS from sour natural gas
and substitute natural gas. The process is claimed to have capabilities
(25)
for H.S removal to below 1 ppm and for selective removal of HซS. The
Benfield process is used in the Lurgi coal gasification plant in Westfield,
Scotland, for gas purification in the manufacture of a town gas.
Alkazid Process
The process was developed by I. G. Farben Industries in Germany
and licensed in the U.S. by Davy Powergas, Inc. Three types of absorbents
are used in the process, all of which employ a combination of the salt of a
strong inorganic base and a weak, organic, nonvolatile acid.
(1) Alkazid "M", containing sodium alanine, is used
for removing C0_ alone or simultaneous removal
of C02 and HZS
(2) Alkazid "DIK", containing the potassium salt of
diethyl glycine or dimethyl glycine, is used for
selective removal of H_S in the presence of C0_
(3) Alkazid "S", containing a mixture of phenolate,
is used for gases containing appreciable amounts
of impurities, such as HCN, ammonia, carbon
disulfide, and mercaptans.
The process is used extensively in Europe, with over 80 commercial
installations in operation today. Typical performance data for a unit
installed by Davy Powergas for selective removal of H2S from an ammonia
-------
92
synthesis gas are shown in Table 46. The synthesis gas is produced by
Winkier coal gasification.
Davy Powergas also offers a process for removing COS for use in
f2fi ^
combination with the Alkazid process for desulfurization. The process
is based on a gas-phase, catalytic hydrolysis of COS. Typical operating
data for a COS hydrolysis unit used in the manufacture of CO from coke are
shown in Table 47. There are five such units currently operating in Europe,
The performance of the COS hydrolysis process for gas streams containing
high CO. concentrations is not known.
The Alkazid process and the COS hydrolysis process can be con-
sidered commercially viable for application in coal gasification processes.
The Alkazid process can be used for fuel-gas desulfurization in the manu-
facture of a low-Btu utility gas to a residual HLS concentration in the
neighborhood of 50 ppm. Removal of COS can be also accomplished by the
hydrolysis process as required, depending upon the COS concentration in the
raw gas, to reduce the overall sulfur content of fuel gas to around 250
ppm or lower. The Alkazid process also shows a good selectivity for KLS
removal and therefore should be able to produce an H-S-rich stream suitable
for a Glaus plant feed.
For SNG manufacture from coal gasification, the Alkazid process
will require a catalyst guard to remove the residual sulfur to a level
required for methanation.
Utilities Requirements
Utilities requirements estimated for acid-gas removal processes
are given in Tables 48 and 49. The increased pollutant emissionparticulates,
sulfur oxides and nitrogen oxidesfrom a boiler which burns coal can be
estimated by using energy conversion efficiencies of 34 percent for generation
of electricity and 85 percent for generation of steam, and the emission
factors established by the EPA. Boiler stack emissions without control
equipment were estimated as follows:
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93
Emissions
Pollutant kg/kwh electricity kg/10 kcal steam
Particulate 20 A/H 9,400 A/H
Sulfur oxides 48 S/H 22,000 S/H
Nitrogen oxides 23/H 11,000/H
where A = ash content of coal, percent by weight
H = heating value of coal, kcal/kg
S = sulfur content of coal, percent by weight
-------
94
TABLE 46. TYPICAL OPERATING DATA FOR ALKAZID PROCESS
FOR PURIFICATION OF AMMONIA SYNTHESIS GAS
Gas Flow - 37,600 .rariVhr
Temperature - 40 C
Pressure - 13.6 atm
Gases
V
co2
Inlet
0.18
14.0
Gas Composition,
mole percent
Outlet
56 ppm
13.7
-------
95
TABLE 47. TYPICAL OPERATING DATA FOR COS HYDROLYSIS PROCI
FOR PURIFICATION OF CARBON MONOXIDE FROM COKE ^
Gas Flow - 20,400 nnrVhr
Temperature - 40 C
Pressure - 1.26 atm
Gas Composition,
mole percent
Gases
CO
co2
H2
CH4
N2
H2S
COS
Inlet
97
0.3
1.2
0.3
1.2
0.1315
558 ppm
Outlet
NA
NA
NA
NA
NA
NA
19 ppm
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TABLE 48. UTILITIES REQUIREMENT FOR ACID-GAS REMOVAL PROCESSES
g
Basis: 63 x 10 kcal/day SNG Production from Illinois
No. 6 Coal (3.93 percent sulfur) by the Hygas
Process)
Process
Selexol^
Rectisol(8)
Purisol<13>
Fluor Solvent^ '
Sulfinol(8)
Hot Potassium Carbonate ^
Electricity.. .
kwh/106 kcal^a)
3.0
3.2
3.6
6.3
5.2
6.7
Steam,
10ฐ kcal/10ฐ kcal(a)
0.055
0.0037
0.011
0.027
0.15
0.11
103 1/106 kcal
11
2.7
0.68
0.78
15
7.5
(a) Based on the total HHV of SNG product.
(b) Includes Benfield and Catacarb processes.
VO
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97
TABLE 49. UTILITIES REQUIREMENT FOR MDEA PROCESS FOR
DESULFURIZATION OF LOW BTU
9
Basis: 32.8 x 10 kcal/day Low-Btu Utility Gas Production
from Eastern Coal (1.08 percent sulfur) by
Koppers-Totzek Process
Item Consumption
Electricity, kwh/106 kcal(a) 0.35
Steam, 106 kcal/106 kcal^a) 0.11
Cooling water, 103 1/106 kcal(a) 9.0
(a) Based on the total HHV of low-Btu gas product.
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98
SULFUR RECOVERY PROCESSES
Recovery of elemental sulfur is considered desirable in coal gasi-
fication processes for producing a salable by-product as well as for con-
trolling sulfur emissions. Commercially important processes which recover
elemental sulfur from sulfur-bearing gases include the Glaus process, the
Stretford process, and the Giammarco-Vetrocoke listed in Table 50. All
three processes are designed normally to convert hydrogen sulfide in the
feed gas to sulfur, although the Glaus process can be operated with a
mixture of hydrogen sulfide and sulfur dioxide in the feed gas as proposed
in the Hygas process.
In many coal gasification processes, the Glaus plant will be
used to treat the acid gases removed from fuel gases. A separate acid-gas
removal stage is required to provide the feed to the Glaus plant. Selective
removal of H9S is an important consideration in the acid-gas removal stage
to provide a Glaus plant with a feed containing a reasonably high H S
concentration usually above 10 to 15 percent, for efficient operation of
the Glaus plant. In contrast, The Stretford process and the Giammarco-
Vetrocoke process can be operated efficiently with a feed containing low
H S concentrations. Furthermore, the latter processes can be used to
remove H9S directly from fuel gases and convert it to sulfur, thereby
eliminating the need for a separate H_S removal stage. The Giammarco-
Vetrocoke process has an additional capability for simultaneous removal
of H9S and C09. The Stretford process is not applicable to bulk C09 removal.
tL ^ ฃ
Glaus Process
There are four principal variations used for recovering sulfur
in Glaus sulfur plants in the United States:
(a) Direct oxidation
(b) Split flow
(c) Straight through
(d) Sulfur recycle.
-------
TABLE 50. SULFUR RECOVERY PROCESSES(8' 27> 28) 29)
Process
Developer/Licensee
Commercial Units in Operation
or Under Construction
Claus
Stretford
British Gas, J. F. Pritchard,
Peabody Engineered Systems,
Ralph M. Parsons
More than 150 units in operation
in the U.S.
53 units in operation
Giammarco-Vetrocoke
Davy Powergas
30 units in operation
VO
-------
100
(27)
Beers summarizes the technology for all four variations and presents
cost estimates.
Glaus sulfur plants usually operate near atmospheric pressure
with only enough extra pressure to overcome the pressure drop through the
plant. The optimum process arrangement (variation) for a Glaus plant depends
largely on the hydrogen sulfide concentration in the acid gas feed. For
high H2S concentrations, such as 90 mole percent, the "straight through"
process is preferred. For intermediate concentrations, such as 50 mole
percent H2S, the "split flow" process is suitable. For low H S concentra-
tions, such as 15 mole percent as obtained in coal conversion processes,
the "direct oxidation" process or sometimes the "sulfur recycle" process
would be used.
Glaus Plant Variations Used With
Low H^S Feed Concentrations
z
Direct Oxidation. In the original Glaus process, called direct
oxidation, HZS is partially oxidized with air over a bauxite or iron ore
catalyst in a single reactor as follows:
3H2S +3/2 02 -. 3S + 3H20 .
This process is used in modern plants having dilute acid gas feed.
Since the H S concentration is low, an auxiliary fuel and air are fed to a
burner for partial oxidation prior to the catalytic bed. Since the Glaus
reaction is highly exothermic and the equilibrium shifts at high tempera-
ture, excessive temperatures in the catalytic beds lead to poor yields.
Partial recycle of the tail gas is often practiced to control temperatures
for acceptable yields.
Goar reports that the Pan American Petroleum Corporation has
developed a version of the direct oxidation process to handle acid gas
streams containing as little as 2 mole percent H S and relatively large
amounts of light hydrocarbons. In this process, the acid gas feed is pre-
heated and passed through one or more stages of catalytic conversion with
sulfur condensation steps after each conversion stage. Sulfur recovery of
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101
80 to 85 percent is usually obtained. Unsaturated hydrocarbons affect the
process adversely and only traces of these can be tolerated. Therefore,
the direct oxidation process may be particularly well suited for handling
acid gas streams from coal conversion processes if they contain unsaturated
hydrocarbons.
Several known plants utilizing this process have been reported
by Goar.
(1) A 4-LTPD plant which handles acid gas containing
10 mole percent H S, 90 mole percent CO-, and less
than 1 mole percent hydrocarbons. Bright yellow
sulfur is produced and the plant is skid mounted.
(2) A 15-LTPD plant - the acid gas to this plant con-
tains 9 mole percent H S, 90 mole percent CO-,
and some heavy hydrocarbons. A charcoal adsorber
unit was installed ahead of the sulfur plant.
This sulfur is used to make sulfuric acid.
(3) A 12-LTPD plant which processes acid gas con-
taining 7 mole percent H S, 71 mole percent CO ,
about 17 mole percent methane, 1 mole percent
ethane and 4 mole percent propane to heptanes
plus other hydrocarbons. Bright yellow sulfur
is produced.
Sulfur Recycle. One Glaus plant variation, particularly useful
for dilute acid gas having low sulfur oxide content is called "sulfur re-
cycle". In this scheme, some product sulfur is recycled back to the front
of the Glaus plant and burned with air to produce SO^ and heat. This
technique is limited by the fact that the ratio of H S/SO in the feed to
the first catalytic reactor should be in the ratio of approximately 2:1.
-------
102
Efficiency of Glaus Plant Operation
The operating efficiency of Glaus plants for sulfur recovery is.
influenced by feed gas composition and the number of reactors employed.
The concentrations of H S, CO , HO, and hydrocarbons in the feed have
pronounced effect on the recovery efficiency. Carbon dioxide and hydro-
carbons react with hydrogen sulfide and elemental sulfur to produce COS
and CS. which end up in the tail gas, thereby, reducing the efficiency.
(4)
According to Barry, the typical sulfur-recovery efficiencies of Glaus
plants operated with two reactors as a function of H S concentration in
feed gas are as follows.
H2S in Feed Sulfur Recovery
percent (dry basis) percent
20 92.7
30 93.1
40 93.5
50 93.9
60 94.4
70 94.7
80 95.0
90 95.3
Efficiency is reduced further at lower HLS concentrations, falling
to 80 to 90 percent at 10 percent H9S and to 70 to 85 percent at 5 percent
H2S.<3>
-------
103
Problems in Adopting Glaus Plants
to Coal Conversion Processes
The following problems are apparent in adapting Glaus plant
technology to recovery of sulfur in coal conversion processes:
(1) The most important problem appears to be that
the H S feed concentration to the Glaus plant
is low, perhaps 5 to 30 percent H S. In most
Glaus plants found in oil refineries and natural
gas recovery, H S feed composition range from a
low of 20 to 25 percent to as high as 90 percent.
Thus, the most widely used designs, i.e., the
"straight through" and split flow designs can-
not normally be used.
(2) The high CO concentration in the feed leads to
the formation of carbonyl aulfide COS, which is
difficult to convert to elemental sulfur.
(3) Since the acid gas feed composition to the Glaus
plant is low, the conversion efficiency will be
low, say 80 to 85 percent rather than 90 to 95
percent conversion obtained in plants with high
H?S feed compositions.
Stretford Process
The process removes H?S selectively from a sour gas stream and
converts it into elemental sulfur in one step, using an aqueous solution
containing sodium carbonate, a soluble vanadium salt, anthraquinone di-r
sulfonic acid (ADA), and a sequestering agent. The chemistry of the process
(31)
is represented by the following reactions:
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104
Absorption of H2S: H2S - HS* + H+
Precipitation of sulfur: HS" + 2V4"5 -* 2V4* + H+ + Sฐ
Regeneration of V+5 : 2V44 + ADA (oxidized) + 2H+ -. 2V+5 + ADA (reduced)
Regeneration of ADA: ADA (reduced) + 1/2 0 -ป ADA (oxidized) + HO .
The process was originally developed by the Northwest Gas Board
in Great Britain. Licensees in the United States include Peabody Engineered
Systems, J. F. Pritchard, and Ralph M. Parsons. An improved version of the
Stretford process is offered by Peabody Engineered Systems under the name
of the Holmes-Stretford process. As of January, 1973, a total of 53 plants
were in operation worldwide, of which 31 use the Holmes-Stretford process.
(29)
There are two plants in the United States using the Homes-Stretford process.
The Holmes-Stretford process includes two proprietary subsystems:
(1) a feed-gas pretreatment step for the removal of HCN, tars, and ashes,
using an ammonium or sodium polysulfide wash, and (2) treatment of purge
liquor from the process for the removal of byproducts, such as sodium thio-
sulfate and sodium thiocyanate. Alternative methods developed and piloted
for purge-liquor treatment include: (1) evaporation or spray drying, (2)
biological degradation, (3) oxidative combustion, and (4) reductive inciner-
ation. Reductive incineration is claimed to be a zero-discharge process,
whereby the purge liquor is treated in a furnace with reducing gases and
reduced chemicals are recycled to the process sequence.
The Holmes-Stretford process guarantees H S removal to less than
10 ppm. Mercaptans are claimed also to be removed. Carbonyl sulfide and
carbon disulfide cannot be removed. Typical operating conditions of the
(29)
Holmes-Stretford process are as follows.
3
Feed gas capacity: 0.003 to 5.4 million nm /day
(0.1 to 190 million scf/day)
Inlet H S concentration: 0.03 to 95 percent
Outlet II S concentration: 1 to 500 ppm
Pressure: 1 to 7.8 atm (0 to 100 psig)
Sulfur production: 0.5 to 76 MT/day (0.5 to 75 long tons/day)
CO partial pressure: 0.01 to 1.1 atmosphere
Inlet HCN concentration: 500 to 2,000 ppm.
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105
The Holmes-Stretford process is used at present for desulfurization
of coke-oven gas, coal gas, producer gas, natural gas, and reformed town gas
from petroleum. The process can be considered a commercially proven process
for potential application in coal gasification processes. Potential appli-
cation include direct desulfurization of a low-Btu gas and desulfurization
of an acid gas stream (H S + CO ) regenerated from acid-gas removal processes
which are nonselective for H S and consequently produce a gas stream not
suitable for a Glaus plant feed.
Giammarco-Vetrocoke Processes
The process was originally developed in Europe for removal of CCL
using an arsenic trioxide activator in potassium carbonate. The original
process has been modified to permit a simultaneous removal of H.S and C0_
or a selective removal of H S. The process for a selective removal of HLS
is based on the absorption and reaction of H9S in alkaline arsenites and
(17)
arsenates. The process chemistry is represented by the following reactions:
Absorption: KH2As03 + 3H2S - KH AsS3 +
Digestion: KH2AsS3 +
Acidification: 3KH2As03S -ป 3KH2As03 + 3S
Oxidation:
For simultaneous removal of H-S and C0~, a separate stage for CO.
removal is added to an H S -removal stage. The chemistry for CO removal
is represented by the following reactions:
Absorption: 2K3As(L + 6C02 + 3H20 - 6KHC03 + As^
K C03 + C02 + HO -* 2KHC03
Regeneration: 6KHC03 + As 03 - 2K AsO + 6C02 + 31^0
2KHC03 -. K2C03 + C02 + Hฃ0 .
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106
There are over 180 commercial installations for CO removal and
about 30 installations for H9S removal in operation today. A great majority
of these installations are located in Europe. One plant is in operation
in the United States for the removal of C0? and tUS from natural gas.
An important advantage of the Giammarco-Vetrocoke processes is the
capability for a highly selective removal of l^S or a simultaneous removal
of both CO and H S. The processes also have the combined capability of
gas purification and recovery of elemental sulfur. A major drawback of the
processes is the use of the arsenic activators, which are a potential
(2.6 )
source of hazardous material release. According to Davy Powergas, Inc.,
which is a U.S. licensee of the processes, the hazard problem will seriously
limit the application of the processes in coal gasification processes.
Utilities Requirements
Utilities requirements estimtted for sulfur recovery processes
are presented in Table 51.
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TABLE 51. UTILITIES REQUIREMENT FOR SULFUR RECOVERY PROCESSES
Process
Claus(b)(27)
Holmes-Stretford(d)(29)
Electricity. .
kwh/10 kcal
2.8
2.0
,. Steam, ., ป
10 kcal/106 kcal*-3'
(0.014)(c)
0.0013
, Fuel Gas, ,
106 kcal/108 kcal(S
0.0013
43 x 10"6
N Cooling Water: N
0 103 1/10ง kcal^a)
None
0.027
(a) Based on total HHV of product gas.
(b) Basis: 63 x 10 kcal/day SNG production from Illinois No. 6 coal (3.93 percent sulfur) o
by the Hygas process.
(c) Net steam production.
Basis: '32.8 x 10 kci
sulfur) by the Hygas process.
Q
(d) Basis: 32.8 x 10 kcal/day low-Btu gas production from Navajo Seam coal (0.69 percent
vl
-------
108
TREATMENT OF GLAUS PLANT TAIL GAS
The Glaus process is used widely in the petroleum industry for
treating sour gases generated from the purification of refinery fuel and
natural gas, to produce elemental sulfur from hydrogen sulfide. The tail gas
from the Glaus plant contains unconverted H_S and S0_ and lesser quantities
of other sulfur constituents, such as COS, CS9, and elemental sulfur vapor
and particles. The tail gas from typical Glaus plant operations contains
about 1 to 2 percent total sulfur. The normal practice in the past has
been to discharge the tail gas directly to atmosphere after passing it
through an incinerator to convert sulfur compounds into sulfur dioxide.
During the past several years, a number of treatment processes have
appeared for removing the residual sulfur compounds from the tail gas.
Tail gas treatment processes which have received commercial acceptance
are listed in Table 52.
Beavon Process
Desulfurization of tail gas from a Glaus plant is accomplished
in two stages. In the first stage, sulfur constituents in the tail gas
such as SO,,, COS, CS , and elemental sulfur are converted to H~S by hydrogenation
and hydrolysis using a packed-bed catalytic reactor. In the second
stage, H~S is removed and converted to elemental sulfur by the Stretford
process.
The Beavon process can be considered a commercially-proven
process for potential application in coal gasification processes. The
Beavon process would be installed unstream of the incinerator in a conven-
tional Glaus plant. The tail gas from the Beavon process would be
incinerated to convert residual sulfur into sulfur dioxide before
discharge to atmosphere. Typical performance data for the Beavon process
applied to the Hygas process for SNG manufacture from Illinois No. 6 coal
are given in Table 53. The Beavon process can reduce the Glaus tail gas
emissions from 1.23 percent S00 to 250 ppm S0_, which corresponds to 0.72
f f ฃ. ฃ
kg S/10 kcal (0.40 Ib S/10 Btu) of SNG produced and 0.012 kg S/106 kcal
0.0065 Ib S/106 Btu) of SNG produced, respectively.
-------
(32)
TABLE 52. GLAUS PLANT TAIL GAS TREATMENT PROCESSES^ '
Commercial Units in Operation
Process Developer/Licensee or Under Construction
Beavon Union Oil, Ralph M. Parsons 7 in operation and 6 under construction
Cleanair J. F. Pritchard, Texas Gulf Sulfur 1 in operation and 3 under construction
IFP-1 Institut Francais du Petrole 12 in operation and 5 under construction
SCOT Shell Development 2 in operation and 6 under construction
Sulfreen Lurgi, SNPA*, Ralph M. Parsons 3 in operation and 4 under construction o
Wellman-Lord Davy Powergas 2 in operation and 6 under construction
* Societe Nationale des Petrole d'Aquitaine.
-------
TABLE 53. SULFUR BALANCE AROUND A CLAUS UNIT AND AROUND A GLAUS UNIT PLUS A BEAVON UNIT
9
Basis: 63 x 10 kcal/day SNG Production from Illinois No. 6 Coal
(3.93 percent coal)
(3)
Feed to
Claus
Tail Gas
from Claus ^a'
Tail Gas from
Claus + Beavon
SulfurrM
Recovered VD'
Total Gas Flow, 10 nm /hr
Sulfur Compounds, mole percent
0.0730
0.114
(a) After incineration.
(b) From Claus plus Beavon
(c) Estimated from data given in Reference 32.
(d) Based on the total HHV of SNG product.
0.0906
(c)
H S
COS
so2
Sulfur in Stream
kg/hr
kg/106 kcal(d)
19.89
0.086
5.78
25,400
9.7
ซ...
_
1.23
1,890
0.72
_v
__
250 ppm
31
0.012
^ ,j
__
25,400
-------
Ill
Cleanalr Process
The process removes sulfur constituents in Glaus tail gas and
/g\
recovers elemental sulfur using three stages. In operation, the Glaus
tail gas is treated first by Stage III, which removes COS and CS~.
Stage III, is a fixed-bed reactor containing both a reduction catalyst
(32)
(thought to be Co/Mo) and a hydrolysis catalyst (unknown). Carbon
dioxide is also decomposed to CO in the fixed-bed reactor to prevent the
reoccurrence of COS. Stage I, which follows Stage III, is a packed-bed
scrubber in which elemental sulfur is recovered and all S0_ and some H_S
tL ฃ
are absorbed and converted to sulfur via continuation of the Glaus-type
reaction. Stage II is the Stretford process which converts the residual HLS
to sulfur.
The Cleanair process can treat Glaus tail gas to levels of not
(8)
more than 200 ppm SO,, equivalent in the effluent. Detailed .
performance data, such as material balance for sulfur constituents are
not available. The process can be considered a commercially-proven process
for potential application in coal gasification processes to treat Glaus
tail gas. The process would be installed upstream of the incinerator in a
conventional Glaus plant. The tail gas from the Cleanair process would
be incinerated to convert residual sulfur constituents into S02 before
discharge to atmosphere.
IFP-1 Process
In this process, a Glaus tail gas is fed to an absorber where
H_S and S0? are absorbed and converted to elemental sulfur by the Glaus-type
reaction. The sorbent is a high-boiling polyglycol containing mixed
(32)
alkali metal salts of an organic acid as a catalyst. The process
is capable of removing elemental sulfur, H?S, and SO among the sulfur
constituents of Glaus tail gas. Other constituents, such as COS and CS2,
are not removed.
-------
112
The IFP-1 process can be considered a commercially-proven
process for application in coal gasification processes for treating Glaus
tail gas. A major limitation of the process is that COS and CS are not
removed. Typical performance data for the IFP-1 process applied to the
Hygas process for SNG manufacture from Illinois No. 6 coal are given in
Table 54. The IFP-1 process can reduce the Glaus tail gas emissions from
1.23 percent S09 to 0.19 percent SO-, which corresponds to 0.72 kg S/10 kcal
ft 6
(0.40 Ib S/10 Btu) of SNG produced and 0.11 kg S/10 kcal SNG produced,
respectively.
SCOT Process
The process consists of a reduction section and an alkanolamine
absorption section. In the reduction section, sulfur constituents in
Glaus tail gas are reduced to R S with hydrogen or hydrogen together
with carbon monoxide over a cobalt/molybdenum catalyst (Shell catalyst
(32)
S-534) at a temperature of about 300 C. ' The H S is then removed in the
absorption section by using di-ispropanolamine (DIPA).
In the absorption stage, C0_ is coabsorbed with H9S in the
amine solution. The coabsorbed C0_ is regenerated with HJ* and the mixture
is recycled to the Glaus plant. The extent of C09 coabsorption depends on
the concentration of CO- in the Glaus tail gas. For typical refinery
applications, about 25 to 39 percent of CO. in the Glaus tail gas is
(34)
coabsorbed with 5 to 10 percent CO- in the tail gas. In coal gasi-
fication applications, the C09 concentration is expected to be much higher,
(3)
in the range of 40 to 70 percent. Consequently, a substantially greater
percentage of CO in the Glaus tail gas will be coabsorbed and recycled to
the Glaus plant which will lower the efficiency of the Claus plant
operation. For this reason, the SCOT process is not expected to find a
significant usage in coal gasification processes for the treatment of
Claus tail gas, unless the C0_ concentration in the tail gas is reduced
to an acceptable level in the neighborhood of 5 to 10 percent.
-------
TABLE 54. SULFUR BALANCE AROUND A CLAUS UNIT AND AROUND A CLAUS UNIT PLUS AN IFP-1 UNIT^3*3'3^
9
Basis: 63 x 10 kcaI/day SNG Production from Illinois No. 6 Coal
(3.93 percent coal)
Total Gas Flow, 10 run /hr
Sulfur Compounds, mole percent
V
cos
so2
Sulfur in Stream
kg/hr, , v
kg/106 kcal^c'
Feed to
Claus
0.0730
19.89
0.086
5.78
25,400
9.7
Tail Gas
from Claus ^
0.113
trace
trace
1.23
1,890
0.72
Tail Gas from
Claus + IFP-1 (&)
0.113
trace
trace
0.19
290
0.11
Sulfur
Recovered
25,100
(a) After incineration.
(b) From Claus plus IFP-1500.
(c) Based on-the total HHV of SNG product.
-------
114
Sulfreen Process
This process employs two stages for removing sulfur constituents
from Glaus tail gas. The first stage removes elemental sulfur by contacting
(32)
the feed gas with liquid sulfur. The second stage consists of a series
of catalytic reactors where the Glaus reactions are promoted at lower
temperatures 127 to 149 C (260 to 300 F) than those employed in the Glaus
plant. The Glaus reactions do not remove COS or CS which is a main disadvantage
of the Sulfreen process.
The Sulfreen process can be considered a commercially-proven
method for potential application for treating Glaus tail gas in coal
gasification processes with a limited capability for COS and CSg removal.
Typical performance data for the Sulfreen process applied to the Hygas
process for SNG manufacture from Illinois No. 6 coal are given in Table 55.
The Sulfreen process can reduce Glaus tail gas emissions from 1.23 percent
SO to 0.35 percent S09, which corresponds to 0.72 kg S/106 kcal (0.40 Ib S/106 Btu)
fi fi
SNG produced and 0.2 kg S/10 kcal (0.12 Ib S/10 Btu) SNG produced, respectively.
Wellman-Lord Process
This process removes S0_ from the off gas from a Claus plant
incinerator using an aqueous regenerative absorbent. The sulfur constituents
in the Claus plant tail gas are converted to S0_ in the incinerator. The
absorbent employed is a solution of sodium sulfite, which reacts with SO-
to produce sodium bisulfite. The S02-rich solution is decomposed by heat to
regenerate the absorbent and S0?. The regenerated S02 is recycled to the Claus plant.
The Wellman-Lord process can be considered one of the commercially-
proven processes for potential application in coal gasification processes
for testing Claus plant tail gas. Typical performance data on the process
applied to the Hygas process for SNG manufacture from Illinois No. 6 coal
are given in Table 56 Sulfur emissions from Claus plant tail gas can be
reduced by the Wellman-Lord process from 1.23 percent S0_ to 250 ppm, which
6 6
corresponds to 0.72 kg S/10 kcal (0.40 Ib S/10 Btu) SNG produced and 0.015 kg
S/106 kcal (0.0082 Ib S/106 Btu) SNG produced, respectively.
Utilities Requirements
Utilities requirements estimated for tail gas treatment processes
are given in Table 57.
-------
TABLE 55. SULFUR BALANCE AROUND A GLAUS UNIT AND AROUND A CLAUS UNIT PLUS A SULFREEN UNIT(3'35)
Basis: 63 x 10 kcaI/day SNG Production from Illinois No. 6 Coal
(3.93 percent coal)
f n
Total Gas Flow, 10 run /hr
Sulfur Compounds, mole percent
V
COS
so2
Sulfur in Stream
kg/hr , .
kg/106 kcalkc'
Feed to
Claus
0.0730
19.89
0.086
5.78
25,400
9.7
Tail Gas
from Claus (a)
0.114
trace
trace
1.23
1,890
0.72
Tail Gas from
Claus + Sulfreente)
0.113
trace
trace
0.35
540
0.21
Sulfur
Recovered 00
24,900
(a) After incineration.
(b) From Claus plus Sulfreen.
(c) Based on the total HHV of SNG product.
-------
TABLE 56. SULFUR BALANCE AROUND A GLAUS UNIT AND AROUND A GLAUS UNIT PLUS A WELLMAN-LORD UNIT
Q
Basis: 63 x 10 kcaI/day SNG Production from Illinois No. 6 Coal
(3.93 percent coal)
(3)
Total Gas Flow, 10 nm /hr
Sulfur Compounds, mole percent
H2S
COS
so2
Sulfur in Stream
kg/hrfi (c)
kg/10b kcarc;
Feed to
Glaus
0.0730
19.89
0.086
5.78
25,400
9.7
Tail Gas
from Claus <*>
0.114
trace
trace
1.23
1,890
0.72
Tail Gas from
Claus + W-L
0.114
trace
trace
250 ppm
39
0.015
Sulfur
Recovered 0>)
'
25,400
(a) After incineration.
(b) From Claus plus Wellman-Lord.
(c) Based on the total HHV of SNG product.
-------
. TABLE 57. UTILITIES REQUIREMENT FOR GLAUS PLANT TAIL GAS TREATMENT PROCESSES
9
Basis: 63 x 10 kcal/day SNG Production from Illinois No. 6 Coal
(3.93 percent sulfur) by the Hygas Process
Electricity.
Process kwh/106 kcal*-a'
Beavon<27>32>
Cleanair(27)
IFP-1<27>
Sulfreen<32'35)
Wellman-Lord^32^
1.1
0.11
0.056
0.23
0.27
Steam, .
10ฐ kcal/10ฐ kcal(a)
(0.0019)(b)
0.00059
None
(0.0012)(b)
(0.0049)(b)
Fuel Gas, .
10b kcal/10b kcal('a;
0.0038
None
None
0.0010
0.0045
Cooling Water.
103 1/106 kcal(a)
0.20
0.60
None
None
0.42
(a) Based on the total HHV of SNG product.
(b) Net steam production.
-------
118
CONCLUSIONS
Based on the information presented in preceding sections of
this report, conclusions are presented below on the sources and
types of sulfurous emissions and applicable control methods for process
sequence in coal gasification.
Coal Preparation
The only data available for this source are for the C0_-Acceptor
9
process for SNG manufacture. For a plant producing 62.5 x 10 kcal/day
9
(248 x 10 Btu/day) of SNG from North Dakota lignite (0.59 percent sulfur),
f O ฃ
the coal preparation stage emits about 61 x 10 nm /day (2200 x 10 scf/day)
(3)
of an off gas containing 300 ppm of S0?. The equivalent sulfur emissions
are 25.0 MT/day (22.6 tons/day) sulfur or 0.23 kg S/10 kcal(0.13 Ib sulfur/106Btu)
of SNG produced. Available process design schemes are based on venting the
off gas from coal preparation directly to the atmosphere.
Fuel Gas Purification
Manufacture of High-Btu SNG
For SNG manufacture, the fuel gas must be purified to remove
sulfur compounds and C0ซ prior to methanation. Two alternatives exist
for gas purification: (1) selective removal of HLS and other minor sulfur
compounds or (2) simultaneous removal of C02 together with sulfur compounds.
The first alternative produces two acid-gas streams, an H2S-
rich stream which usually can be sent to a Claus plant for sulfur recovery
and a second stream which is mostly CO*. The H2S stream contains the
bulk of the sulfur originally present in the fuel gas and will not be
-------
119
discharged to the atmosphere without further treatment for sulfur
removal. The C0_ stream contains a small quantity of sulfur compounds.
Available data on the sulfur content of the C0? stream from the Rectisol
process are shown in Table 58. The sulfur content of the C02 stream from
the Recitisol process is shown to vary with the sulfur content of coal feed.
Sulfur is present mostly as COS and lesser quantities of H?S and CS .
Available design concepts are based on venting the C02 stream directly to
atmosphere. Since the sulfur concentration of the C02 stream is dependent
upon the sulfur content of coal feed, emission standards can be set in terms
of the sulfur content of the coal feed.
When CO is removed together with sulfur compounds, the purification
stage produces a single off-gas stream containing the bulk of both constituents
The present design concept involves treating this stream for desulfurization
prior to discharge to atmosphere. This stream, therefore, cannot be considered
an emission source in the gas purification stage.
Manufacture of Low-Btu Utility Gas
In the manufacture of a low-Btu utility gas, fuel gas is
desulfurized for the purpose of reducing SO., emissions from combustion of
the fuel gas in a utility boiler. Commercially-proven processes being
considered for desulfurization include the Stretford process for the Lurgi
gasification process and the MDEA process for the Koppers-Totzek gasifi-
cation process. Both desulfurization processes are intended for selective
removal of H S while leaving behind the bulk of the C02 in the fuel gas.
The Stretford process is capable of a near quantitative removal
of H2S, but COS is not removed. An improved version of the Stretford
process, known as the Holmes-Stretford process, guarantees less than 10
9
ppm of H_S in the treated gas. For a Lurgi plant producing 32.8 x 10 kcal/day
9
(130 x 10 Btu/day) of a low-Btu gas from Navajo Seam coal containing a 0.69
percent sulfur, the sulfur content of the fuel gas can be reduced from 2,170
ppm H S and 130 ppm COS to 10 ppm H2S and 130 ppm COS. Corresponding emissions
of S0_ from combustion of the fuel gas in a utility boiler are estimated
f- r
at 346 ppm SO,--3.5 kg SO-/10 kcal of fuel gas output or 57.7 MT S/day
n
(1.96 Ib SO /10 Btu or 63.6 tons S/day)--without desulfurization and
-------
TABLE 58. SULFUR CONTENT OF COj STREAMS FROM RECTISOL PROCESS FOR GAS PURIFICATION IN SNG MANUFACTURE FROM COAL GASIFICATION
Process
Lurgi (El Paso Project)
Lurgi (WESCO Project)^
Hygas
Hygas
Sulfur Content
of Coal,
percent
0.69
0.91
0.51
3.93
Sulfur
H2S
8.2
NA
9
11
Compounds,
COS
68.1
60 ,
39
300
ppm
cs2
3.6
NA
NA
NA
Plant Size,
10 kcal/day
69.3
61.7
63.0
63.0
Flow Rate
of CO. Stream,
10b nmj/hr
10.92
5.97
8.46
6.76
Sulfur Emission
Metric Tons
S/day
1.23
0.48
0.55
2.78
kg S/10b
0.018
0.0079
0.0088
0.045
i-1
NJ
O
(a) Based on the total HHV of the product gas.
(b) The^CO. stream is treated by the Stfetford process. The stream data refer to the outlet of the Stretford process.
-------
121
24 ppm S02--0.22 kg SO /10 kcal of fuel gas output or 3.5 MT S/day
(0.12 lb SO /10 Btu or 3.9 tons S/day)--with desulfurization.
The MDEA process is capable of removing bulk of H.S and about 75
percent of COS. A unit designed for a Koppers-Totzek plant producing
9 9
32.8 x 10 kcal/day (130 x 10 Btu/day) of a low-Btu gas from Eastern bituminous
coal containing 1.08 percent sulfur is claimed to be capable of reducing the
sulfur content of the fuel gas from 3500 ppm H9S and 400 ppm COS to 150 ppm
H S and 100 ppm COS. Corresponding emissions of SO, from boiler stacks are
6
estimated at 1,000 ppm SO --4.0 kg S09/10 kcal of fuel gas output or 66.4
6
MT S/day (2.2 lb SO-/10 Btu or 73.2 tons S/day)--without desulfurization
6
and 70 ppm S09--0.27 kg S09/10 kcal of fuel gas output or 4.3 MT S/day
6
(0.15 lb SO /10 Btu or 4.7 tons S/day)--with desulfurization.
Sulfur content of raw gas is expected to increase in proportion
to the sulfur content of coal feed,, Residual sulfur level in desulfurized
gas will also increase with higher sulfur content of coal. The existing
Federal standards for S09 emissions for new sources of coal-burning
66
equipment are established at 2.16 kg SO./10 kcal (1.2 lb SO-/10 Btu).
To comply with the existing Federal standards, the maximum allowable total
sulfur levels in fuel gas will be 1400 ppm for the Lurgi gas (with a heating value
3
of 1740 kcal/nm (195 Btu/scf) and 2100 ppm for the Koppers-Totzek gas (with
3
a heating value of 2620 kcal/nm (294 Btu/scf). Corresponding sulfur content
of coal which can be allowed for Lurgi-Stretford and Koppers-Totzek-MDEA
combinations were estimated by assuming that (1) the Stretford effluent contains
10 ppm H_S which is independent of sulfur level in the feed gas, and (2)
the effluent from the MDEA process contains 150 ppm of H9S (independent of
feed-gas sulfur level) and 25 percent of COS in the feed gas. The maximum
sulfur contents allowed for feed coal were estimated at 6.9 percent for a
Lurgi-Stretford system and greater than 10 percent for a Koppers-Totzek-MDEA
system.
Other desulfurization processes, such as the Rectisol, Purisol,
and Selexol processes, are commercially-proven processes potentially
available for low-Btu gas application. These processes generally are
capable of reducing sulfur content of fuel gas to much lower levels than
the Stretford or the MDEA process.
-------
122
Sulfur Recovery
Acid gases removed from fuel gas in the gas purification stage
will be sent to either the Glaus process or the Stretford process depending
upon the sulfur content of the acid gases. In the gasification processes
considered in this task, the Claus process is employed for high-Btu SNG
manufacture by the Hygas and the CO -Acceptor processes and for low-Btu
gas manufacture by the Koppers-Totzek process, and the Stretford process
is employed for high-Btu SNG manufacture by the Lurgi and the Synthane
processes and for low-Btu gas manufacture by the Lurgi process.
Claus Process
Sulfur emissions from Claus plants for coal gasification
processes considered in this task are shown in Table 59, Concentration
of SO- in tail gas after incineration is shown to be in the neighborhood
of 1 to 2 percent. Total sulfur emissions range from about 4.3 to 45 MT/day
(5 to 50 tons/day) of sulfur equivalent or about 0.1 to 0.7 kg S/10 kcal
(0.07 to 0.4 Ib S/10 Btu) of the fuel value of product gas. The total sulfur
emissions are shown to increase with increasing sulfur content of coal feed.
The concentration of SO- in the range of 1 to 2 percent is too high to allow
direct discharge of the tail gas without treatment. Commercially-proven
technology is available at present for desulfurization of Claus plant tail
gas.
Stretford Process
The Stretford process employed in SNG manufacture produce off-
gases, after incineration, containing 420 ppm S09 in the Lurgi process and
150 ppm SO in the Synthane process. Corresponding total sulfur emissions
are 0.29 MT/day (0.30 ton/day) for the Lurgi process and 1.31 MT/day
(1.44 tons/day) for the Synthane process. Available process design schemes
are based on discharging the Stretford effluents to atmosphere after incineration.
-------
TABLE 59. SULFUR CONTENT OF TAIL GAS FROM CLAUS PROCESS
Process
Hygas (SNG)
Hygas (SNG)
C02-Acceptor (SNG)
Koppers-Totzek
'(low-Btu gas)
Sulfur Content
of Coal
0.51
3.93
0.59
1.08
SO- Concentration^
in Tall Gas
percent
1.29 .
1.23
0.89
0.93
Plant Size,
109 kca I/day
63.0
63.0
62.5
32.8
Flow Rate of
TailgGas,
10 nm /hr
0.0240
0.114
0.0750
0.0144
Sulfur
Metric Tons
S/day
10.1
45.4
21.8
4.3
Emission
kg S/10b
kcal
0.16
0.72
0.35
0.13
(a) After incineration.
(b) Based on the total HHV of the product gas.
-------
124
When the Stretford process is employed for desulfurization of a
low-Btu gas, no direct effluent to atmosphere is produced. The effluent
from the process is the desulfurized fuel gas as described in the preceding
section.
Treatment of Glaus Plant Tail Gas
Glaus plant tail gases in coal gasification processes typically
contain 1 to 2 percent sulfur. Commercially-proven processes are
available at present for desulfurizing Glaus plant tail gas. Typical
performance data expected from tail gas treatment processes when applied
to coal gasification processes are shown in Table 60. Tail gas treatment
processes are shown to fall into two groups in terms of desulfurization
efficiency. The Beavon and the We1Iman-Lord processes are capable of
reducing sulfur content down to 250 ppm S0_ in the effluent. The Cleanair
process, which is not shown in the table, is expected to provide comparable
performance. The IFP-1 and the Sulfreen processes are comparatively less
efficient and produce effluents containing about 0.2 to 0.4 percent S09.
Other Sources of Sulfurous Emissions
Additional sources of sulfurous emissions in coal gasification
processes include off-gases from wastewater treatment and from regeneration
of catalyst guards, the latter employed ahead of the methanation stage in SNG
manufacture.
Off gases from wastewater treatment are generated at relatively
small quantities--28 to 4500 nm /hr (0.001 x 10 to 0.16 x 10 scf/hr) but
contain 2 to 4 percent H?S. Available process design information specifies
sending these off gases to sulfur recovery processes for desulfurization.
Available design information specifies the use of a catalyst
guard fof the Synthane, the C0_-Acceptor, and the Hygas processes for SNG
manufacture. Regeneration of the catalyst guard produces an off gas
containing sulfur as S09. The SO emissions are expected to be low in
-------
TABLE 60. SULFUR CONTENT OF OFF GASES FROM CLAUS PLANT TAIL GAS TREATMENT PROCESSES
Gasification
Process
Hygas (SNG)
Hygas (SNG)
Hygas (SNG)
Hygas (SNG)
Hygas (SNG)
C02-Acceptor (SNG)
Koppers-Totzek
(low-Btu gas)
Tail Gas
Treatment
Process
Beavon
IFP-1
Sulfreen
Wellman-Lord
Wellman-Lord
Beavon
Beavon
Sulfur Content
of Coal,
percent
3.93
3.93
3.93
3.93
0.51
0.59
1.08
S02 Concentration
in Off-Gas,
ppro
250
1,900
3,500
250
250
250
250
Plant
Size,
10 kca I/day
63
63
63
63
63
62.5
32.8
Off-Gas
Flow Rate,
106 nm3/hr
0.091
0.113
0.113
0.114
0.024
0.075
0.012
Sulfur Emissions,
Metric Tons
S/day
0.74
7.0
13.0
0.94
0.20
0.61
0.09
kg S/10ฐ
kcal
0.012
0.11
0.21
0.015
0.0031
0.0098
0.0029
NJ
Ol
(a) Based on the total HHV of gas product.
-------
126
the neighborhood of 0.48 MT S/day (0.53 tons S/day) or 0.0077 kg S/10 kcal
(0.0043 Ib S/106 Btu) for the CO -Acceptor process and 1.13 MI S/day (1.25
6 i 6
tons S/day) or 0.019 kg S/10 kcal (0.011 Ib S/10 Btu) for the Synthane
process. Available process design concepts are based on direct discharge
of the off gas to atmosphere without treatment.
Supplementary Information
Supplementary information is presented in Appendices. Appendix
A contains a description of the current status of coal gasification industry,
including a list of gasification plants, and projections on growth of the
industry in the United States. Appendix B contains a list of industry
experts in the areas of coal gasification and control technology.
-------
127
REFERENCES
(1) Anonymous, "Evaluation of Coal Gasification Technology, Part II, Low-
Btu Fuel Gas", Draft Report prepared by National Research Council and
National Academy of Engineering (January 10, 1974).
(2) Chopey, N. P., "Gas-from-Coal: An Update", Chem. Engineering. 8.L (5),
70-73 (1974).
(3) Glaser, F., Hershaft, A., and Shaw, R., "Emissions from Processes
Producing Clean Fuels1*, Draft Report prepared by Booz-Allen & Hamilton
under EPA Contract No. 68-02-1358 (1974).
(4) Barry, C. B., "Reduce Glaus Sulfur Emission", Hydrocarbon Processing,
5_1 (4), 102-106 (1972).
(5) Naber, J. E., Wesselingh, J. A., and Groenendaal, W., "New Shell Process
Treats Glaus Off-Gas", Chem. Eng. Prog., 69. (12), 29-34 (1973).
(5a) Anonymous, "Clean Fuel Gas From CoaL", Report prepared by Lurgi supplied
by American Lurgi Corporation, New York, N.Y. (1974).
(6) Farnsworth, J. F., et al,. "The Production of Gas from Coal Through a
Commercially Proven Process", Koppers Company, Inc., Pittsburgh,
Pennsylvania (August, 1973 and April, 1974).
(7) Private Communication, Leonard H. F., Koppers Company, Inc., Pittsburgh,
Pennsylvania, to B. C. Kim, BCL (May, 1974).
(7a) Magee, E. M., "Evaluation of Pollution Control in Fossil Fuel Conversion
Processes, Gasification; Section 1; Koppers Totzek Process", :
EPA-650/2-74-009a (January, 1974).
(8) Anonymous, "NG/LNG/SNG Handbook", Hydrocarbon Processing, 87-132
(April, 1973).
(9) Private communication, Luley, W. E., Allied Chemical Corporation,
Morristown, New Jersey, to B. C. Kim, BCL (May, 1974).
(10) Sweny, J. W., "Synthetic Fuel Gas Purification", Paper presented before
the Division of Fuel Chemistry, ACS 165th National Meeting, Dallas,
Texas (April 8-12, 1973). (Allied Chemical Corp., Morristown, N. J.)
(11) Private communication, Bokaemper, J., Lotepro Corporation, New York,
New York, to B. C. Kim, BCL (May, 1974).
(12) Ranke, G., and Munro, A. B., "Acid Gas Separation by Rectisol in SNG
Processes", Lotepro Corporation, New York, New York (1973).
(13) Anonymous, "Purisol for Gas Treating", Report prepared by Lurgi
and supplied by American Lurgi Corporation, New York, New York (1974).
(14) Private communication, Gallagher, J. T., American Lurgi Corporation,
New York, New York, to B. C. Kim, BCL (April, 1974).
(15) Private communication, Hancock, W. D., Fluor Engineers and Constructors,
Los Angeles, California, to B. C. Kim, BCL (May, 1974).
-------
128
REFERENCES
(Continued)
(16) Buckingham, P. A., "Fluor Solvent Process Plants: How They are Working",
Hydrocarbon Processing, 4.3 (4), 113-116 (1964).
(17) Maddox, R. N. , Gas and Liquid Sweetening, Second Edition, John M.
Campbell, Norman, Oklahoma (1974).
(18) Klein, J. P., "Developments in Sulfinol and Adip Processes Increase
Uses", Oil and Gas International, 10 (9), 109-112 (1970).
(19) Kohl, A. L., and Riesenfeld, F. C., "Today's Processes for Gas Puri-
fication", Chem. Eng.. 127-178 (June 15, 1959).
(20) Goar, B. G. , "Today's Gas Treating Processes - 1", Oil and Gas Journal,
75-79 (July 12, 1971).
(21) Benson, H. E. , "Hot Carbonate Plants: How Pressure Affects Costs",
Petroleum Refiner. 40 (4), 107-108 (1961).
(22) Eickmeyer, A. G., "Catalytic Removal of CO", Chem. Eng. Prog.. 58_ (4),
89-91 (1962).
(23) Private communication, Eickmeyer, A. G. , Eickmeyer and Associates,
Prairie Village, Kansas, to B. C. Kim, BCL (May, 1974).
(24) Eickmeyer, A. G. , "Thirty-Nine Catacarb Process Plants are Now
Sweetening Sour Natural Gas". Oil and Gas Journal. 74-75 (August 9, 1971)
(25) Private communication, McCrae, D., The Benfield Corporation, Pittsburgh,
Pennsylvania, to B. C. Kim, BCL (May, 1974).
(26) Private communication, Banchik, I. N., Davy Powergas, Inc., Lakeland,
Florida, to B. C. Kim, BCL (May, 1974).
(26a) "Compilation of Air Pollutant Emission Factors", 2nd Ed., EPA
Publication No. AP-42 , EPA Office of Air & Water Programs (April, 1973).
(27) Beers, W. D., "Characterization of Glaus Plant Emissions", Final Report
from Process Research, Inc., to U.S. Environmental Protection Agency,
Contract No. 68-02-0242, Report No. EPA-R2-73-188 (April, 1973).
(28) Anonymous, "Stretford Removal Processes for H?S is Licensed", Oil and
.Trmrnal, 68-69 (October 11, 1971) .
(29) Private communication, Vasan, S., Peabody Engineered Systems, Stamford,
Connecticut, to B. C. Kim, BCL (June, 1974).
(30) Goar, B. G., "Today's Sulfur Recovery Processes". Hydrocarbon Processing.
47 (9), 248-252 (1968).
(31) Private communication, Daniels, J. D., W. C. Holmes & Company, Ltd.,
Turnbridge, Huddersfield, England, to B. C. Kim, BCL (June, 1974).
-------
129
REFERENCES
(Continued)
(32) Genco, J. M., and Tarn, S., "Characterization of Sulfur from Refinery
Fuel Gas", Draft Report to EPA, Contract No. 68-02-0611, Task 4
(March 29, 1974).
(33) Barthel, Y., et al., "Treat Glaus Tail Gas", Hydrocarbon Processing.
50 (5), 89-91 (1971).
(34) Private communication, Dodd, D. E., Shell Development Company, Houston,
Texas, to B. C. Kim, BCL (May, 1974).
(35) Krill, H., and Storp, K., "H9S Absorbed from Tail Gas", Chem. Eng.
84-85 (July 23, 1973).
(36) "Detailed Environmental Analysis Concerning a Proposed Coal Gasification
Plant for Transwestern Coal Gasification Company, Pacific Coal
Gasification Company and Western Gasification Company", Battelle's
Columbus Laboratories (February 1, 1973).
(37) Anonymous, "Lurgi Pressure Gasification Performance Record", Report by
Lurgi and supplied by American Lurgi Corporation, New York, New York
(1974).
(38) Anonymous, "Gasification Plants Using K-T Process", A Plant List
supplied by Koppers Company, Inc., Pittsburgh, Pennsylvania (1974).
(39) Banchik, I. N., "Power Gas from Coal via the Winkler Process", Report
supplied by Davy Powergas, Inc., Lakeland, Florida (1974).
(40) Kasturirangan, V. N., "Indian Government Sponsored Comparative Study
of Commercial Coal Gasification ProcessesKoppers-Totzek, Lurgi, and
Winkler", Report supplied by Koppers Company, Inc., Pittsburgh,
Pennsylvania (1968-1969).
(41) Internal planning document, Federal Power Commission.
(42) Dupree, W. G., Jr., and West, J. A., "United States Energy Through the
Year 2000", U.S. Department of the Interior, December, 1972.
(43) "Commercial Application of Coal Conversion Technology in the United
States and Prospects for Coal Exports", Review Draft from Office of
Energy Research and Development in cooperation with Bureau of Mines to
The Organization for Economic Co-Operation and Development (OECD)
Paris, France (1974).
(44) Hall, E. H., Choi, P., and Kropp, E., "Assessment of the Potential of
Clean Fuels and Energy Technology", Final Report from Battelle's
Columbus Laboratories to U.S. Environmental Protection Agency,
February 28, 1974.
-------
A-l
APPENDIX A
INDUSTRY STRUCTURE
Coal gasification has been practiced for many years outside of
the U. S. for the manufacture of synthesis and fuel gases. Commercial
processes in use today include the Lurgi, Koppers-Totzek, and Winkler
processes. Coal gasification plants presently operating are listed in
Tables A-l, A-2, and A-3. A number of gasification plants have been shut
down due to economic considerations. Of a total of 16 Winkler gasification
units built between 1926 and 1960, only 3 remain in operation. It is uncertain
also whether all of the Lurgi gasification units, especially the pre-1950
units, are still in operation.
Gas Purification Practices at Existing Coal Gasification Plants
Most of the existing coal gasification units, particularly
those units which produce synthesis gases, most likely have facilities for
gas purification to remove hydrogen sulfide, carbon dioxide, or both. The
following paragraphs describe typical gas purification methods used at
several Lurgi and Koppers-Totzek plants. They are probably among the
exemplary plants as far as the present gas purification practices in the
coal gasification industry are concerned.
Lurgi Plants
At the Westfield plant in Scotland owned by the Scottish Gas
Board and operated to produce a town gas, the coal gas is desulfurized by the
(25)
Benfield process followed by oxide towers. The regenerated H-S is
treated by the Claus process for sulfur recovery. Operation of the Glaus
plant has not been economical due to a low concentration (about 5 percent)
of H2S in the feed.
-------
TABLE A-l. LURGI GASIFICATION UNITS
(37)
Owner Plant Location
A. G. Sachsische Werke,
Dresden, Germany Hirschfelde
A. G. Sachsische Werke,
Dresden, Germany B8hlen
A. G. SSchsische Werke,
Germany Bohlen
Sudetenlandische Treibstoffwerke AG,
Brtix, Czechoslovakia Most
Sudetenlandische Treibstoffwerke AG,
Brlix, Czechoslovakia Most
South African Coal, Oil and Gas
Corp., Ltd.
Sasolburg, South Africa Sasolburg
Gas and Fuel Corp.
Melbourne, Australia Morwell
Pakistan Industrial Development
Corp.
Daud Khel, Pakistan Daud Khel
Year of
Order
1936
1940
1943
1944
1949
1954
1956
1957
Feed
Lignite
Lignite
Lignite
NA
NA
Semibituminous
coal
Lignite
Intermediate between
lignite and subbitu-
minous coal
Product Use
Town gas
Town gas
Town gas
Town gas
Town gas
Fischer-Tropsch
synthesis
Town gas
Ammonia
synthesis
Raw Gas
Capacity,
10 ntn /day
0.028
0.25
0.28
0.21
0.25
3.7
0.62
0.12
-------
TABLE A-l. (Continued)
Owner
The Scottish Gas Board,
Westfield, Scotland
West Midlands Gas Board,
Coleshill, England
Honam Fertilizer Corp., Ltd.
Seoul, Korea
South African Coal, Oil and Gas
Corp. , Ltd.
Sasolburg, South Africa
Steinkohlen-Electrlzitat AG,
Essen, Germany
Plant Location
Westfield
Coleshill
Naju
Sasolburg
Luenen
Year of
Order
1960
1963
1963
1966
1969
Feed
Semicaking coal
Subbituminous
coal
Graphitic
anthracite
S emib ฑ tuminous
coal
Coal
Product Use
Town gas
Town gas
Ammonia
synthes is
Ammonia
synthesis
Fuel gas for com-
bined power cycle
Raw Gas
Capacity,
10 nm /day
0.71
1.3
0.42
1.7
8.5 x 109
kcal/day
-------
TABLE A-2. KOPPERS TOTZEK GASIFICATIONS UNITS
(38)
Owner Plant Location
Charbonnage de France,
Paris, France Mazingarbe Works (P.d.C.)
Typpi Oy,
Oulu, Finland Oulu
Nihon Suiso Kogyo Kaisha, Ltd.
Tokyo, Japan Tokyo
Empresa Nacional "Calvo Sotelo"
de Combustibles Liquidos y Nitrogen works in
Lubricantes, S.A., Puentes de Garcia
Madrid, Spain Rodriguez, Coruna
Typpi Oy,
Oulu, Finland Oulu
S.A. Union Chimique Beige,
Brussels, Belgium Zandvoorde Works
Amoniaco Portugues S.A.R.L.,
Lisbon, Portugal Estarreja Plant
Year of
Order Feed
Coal,
1949 coke oven gas,
tail gas
Coal, oil,
1950 peat
1954 Coal
1954 Lignite
Coal, oil,
1955 peat
Bunker C,
1955 plant convertible
for coal
Heavy gasoline,
1956 plant extendable
to lignite and
anthracite
Capacity
(Cg + H_) ,
Product Use 10 nm^/day
Methanol and
ammonia 0 . 08 - 0 . 16
synthesis
Ammonia
synthesis 0.15
Ammonia
synthesis 0.22
Ammonia
synthesis 0.25
Ammonia
synthesis 0.15
Ammonia
synthesis 0.19
Ammonia
synthesis 0.19
-------
TABLE A-2. (Continued)
Owner
The Government of Greece,
The Ministry of Coordination,
Athens, Greece
Empresa Nacional "Calvo Sotelo"
de Combustibles Liquidos y
Lubricantes, S.A.,
Madrid, Spain
Chemical Fertilizer Co., Ltd.
Thailand
Azot Sanayii T.A.S.,
Ankara , Turkey
Industrial Development Corp.
Zambia
The Fertilizer Corporation of
India, Ltd.
New Delhi, India
The Fertilizer Corporation of
India, Ltd.
New Delhi, India
Year of
Plant Location Order
Nitrogenous Fertilizer
Plant, Ptolemais 1959
Nitrogen works in
Puentes de Garcia
Rodriguez, Coruna 1961
Synthetic Fertilizer Plant
at Mae Moh, Lampang 1963
Kutahya Works 1966
Kafue near Lusaka 1967
Ramagundam Plant 1969
Talcher Plant 1970
Feed
Lignite,
Bunker C
Lignite
or naphtha
Lignite
Lignite
Coal
Coal
Coal
Capacity
(CO + H2) ,
Product Use 10 nm3/day
Ammonia
synthesis 0.66
Ammonia
synthesis 0. 18
Ammonia
synthesis 0.23
Ammonia
synthesis 0.82
Ammonia
synthesis 0.17
Ammonia
synthesis 2.1
Ammonia
synthesis 2 . 1
-------
TABLE A-2. (Continued)
Owner
Nitrogenous Fertilizers
Industry S.A. ,
Athens, Greece
The Fertilizer Corporation of
India, Ltd.
New Delhi, India
AE & CI Ltd.
Johannesburg, South Africa
Plant Location
Nitrogenous Fertilizers
Plant, Ptolemais
Korba Plant
Modderfontein Plant
Year of
Order Feed
1970 Lignite
1972 Coal
1972 Coal
Product Use
Ammonia
synthesis
Ammonia
synthesis
Ammonia
synthesis
Capacity
(CO + H,) ,
10ฐ nm3/day
0.25
2.1
2.3
-------
A-7
(39)
TABLE A-3. WINKLER GASIFICATION UNITSv '
Owner/Plant Location
Fabrika Azotnih Jendinjenja,
Gorazde, Yugoslavia
Azot Sanyyii TAS,
Kutahya, Turkey
Neyveli Lignite Corp.
Madras , India
Year
1953
1959
1959
Product
Synthesis gas
Synthesis gas
Synthesis gas
Raw Gas
Cgpacity,
10 nm-Vday
0.13
0.61
3.2
-------
A-8
At the Coleshill plant in England, owned by the West Midlands Gas
Board and operated to manufacture a town gas, the Alkazid process and oxide
towers are used for H2S removal/ ' The recovered H S is sent to a Glaus
plant for sulfur recovery.
At the Sasol plant in South Africa, owned by South African Coal,
Oil, and Gas Corporation, Ltd0, and operated to manufacture a Fischer-Tropsch
(14)
'2*
Disposition of the H S recovered from the Rectisol process is not known.
synthesis gas, the Rectisol process is used for the removal of HLS and C0_.
Koppers-Totzek Plants
At the Kutahya plant in Turkey, owned and operated by Azot Sanayii
T.A.S. for the manufacture of an ammonia synthesis gas, the coal gas produced
is first treated by the Sulfinol process for H^S removal and further treated
by the Retisol process for C02 removal. The H?S recovered from the Sulfinol
process is flared and vented to atmosphere. The C02 recovered from the
Rectisol process is vented directly to atmosphere,,
At the Coruna plant in Spain, owned and operated by Empresa Nacional
"Calvo Sotelo" de Combustibles Liquides y Lubricantes, S.A., for the manufacture
of an ammonia synthesis gas, the coal gas is treated for H~S and CO- removal
by a hot potassium carbonate process followed by oxide boxes. ' The HLS
regenerated is sent to a Glaus plant for sulfur recovery.
At the Modderfontein plant in South Africa, owned and operated
by AE & CI, Ltd. for the manufacture of an ammonia synthesis gas, the coal
gas produced is treated by the Recitisol process for HLS and CO removal. '
The H?S recovered from the Recitisol process will be converted to sulfur by
the Glaus process.
Contacts for Existing Coal Gasification Plants
The coal gasification plants which are operating at present
outside of the U. S. can be contacted through the U. S. licensees listed
below.
Lurgi Plants: Mr. John T. Gallagher
General Manager, Coal Gasification
American Lurgi Corporation
5 East 42nd Streed
New York, New York 10017
(212) 986-9595
-------
A-9
Koppers-Totzek Plants: Mr. Frank Cannon
Sales Manager
Koppers Company, Inc.
Koppers Building
Pittsburgh, Pennsylvania 15219
(412) 391-3300
Winkler Plants: Mr. I. N. Banchik
Manager, Commercial Development
Davy Powergas, Inc.
Post Office Box 2436
Lakeland, Florida 33803
(813) 646-7515
Prolections on the Use of Synthetic Fuels from
Coal Gasification in the United States
The use of low-energy gas from coal (or producer gas, as it is
sometimes called) was once widespread in industry; in fact, it was the first
gaseous fuel in the iron and steel industry for firing open-hearth furnaces
between 1860 and 1920, when by-product coke oven gas displaced it. In 1920,
there were reportedly over 11,000 gas producers supplying gaseous fuel for
a wide variety of industries from brick plants to bakeries. With the advent
of inexpensive natural gas and oil, however, the incentive for gasifying
coal decreased until today there are but a few bituminous coal gas producers
in this country, and these have largely been placed in standby positions.
At the present time, only one small producer in the United States is
currently known to be yielding low-Btu gas for use at a plant in Pennsyl-
vania. There has never been any substantial use of high-Btu gas derived
from coal for pipeline purposes although technology is probably available.
The future for plants producing high-Btu-gas has been estimated by
several organizations in the recent past, and the results are shown in
Table A-4. The future for low-Btu gas plants seems somewhat Less certain.
The only estimate located to date is one made by BCL for the Environmental
Protection Agency and only for application for conversion of boilers. The
figures are shown in Table A-5.
If this low-Btu gas is shown to be an adequate substitute for
industrial pruposes, and especially if town gas for residential purposes
again becomes acceptable in the Untied States, these estimates for low-
energy gas may prove to be too low.
-------
A-10
TABLE A-4. SURVEY OF ESTIMATES OF FUTURE SUPPLY OF
PIPELINE QUALITY (HIGH BTU) GAS PRODUCED
FROM COAL IN THE UNITED STATES (Trillions of kcal)
Source
Year
1980
1985
1990
1995
2000
FPC
(41)
USD I
USBM
(42)
(43)
76
180
25
280 780 200
500 -- 1400
330 760 1000 1600
TABLE A-5. ESTIMATE OF FUTURE SUPPLY OF LOW-ENERGY (LOW-BTU
GAS PRODUCED FROM COAL IN THE UNITED.STATES
(Trillions of kcal)
Source
1980
1985
Year
1990
1995
2000
EPA
(44)
120
980
-------
B-l
APPENDIX B
INDUSTRY EXPERTS AND POTENTIAL ATTENDAN
FOR INDUSTRYWIDE MEETING
Individuals who have expertise and interest in the coal gasi-
fication industry were identified during the course of this program through
direct contacts and referrals. These individuals represent the developers
and potential users of coal gasification processes and the suppliers of
control processes. A list of these individuals, including names, positions,
addresses, and telephone numbers are given in Table B-l. Individuals contacted
during this program were informed about the purpose of this program. All
expressed interest in the outcome of this_program and willingness to attend
the industrywide meeting being planned by the EPA to provide written
and oral comments on this report, and to cooperate with the EPA in writing
the New Source Performance Standards for the coal gasification industry.
-------
B-2
TABLE B-l. LIST OF INDUSTRY EXPERTS
Coal Gasification Processes
Mr. George Musat
Fossil Fuels Environmental Control
Electric Power Research Institute
3412 Hillview Avenue
Post Office Box 10412
Palo Alto, California 94304
(415) 493-4800
Mr. John B. Anderson*
Product Manager
Research and Development Sales
Combustion Engineering, Inc.
Windsor, Connecticut 06095
(203) 688-1911
Mr. John F. Farnsworth
Supervisor
Coal and Gas Technology
Engineering and Construction Division
Koppers Company, Inc.
Pittsburgh, Pennsylvania 15219
(412) 391-3300
Mr. R. S. Rutherford*
Chairman of the Board
Riley Stoker Corporation
Nine Neponset Street
Worchester, Massachusetts 01606
(617) 852-7100 .
Mr. A. M. Freudberg
Power Generation Division
The Babcock & Wilcox Company
Barberton, Ohio 44203
(216) 753-4511
Mr. I. Norman Banchik*
Manager, Commercial Development
Davy Powergas, Inc.
Post Office Box 2436
Lakeland, Florida 33803
(813) 646-7515
Mr. Howard M. Siegel
Manager
Synthetic Fuels Research Dept.
Esso Research and Engineering Corp.
Post Office Box 101
Florham Park, New Jersey 07932
(201) 474-6012
Mr. John P. Gallagher*
General Manager
Coal Gasification
American Lurgi Corporation
Five East 42nd Street
New York, New York 10017
(212) 986-9595
Mr. Joseph Agosta*
Manager
Coal Gasification Program
Commonwealth Edison Company
Post Office Box 767
Chicago, Illinois 60690
(312) 294-2914
Mr. Len Fish
Senior Vice President of Planning
American Gas Association
1515 Wilson Boulevard
Arlington, Virginia 22209
(202) 524-2000
Mr. Albert Forney*
Research Coordinator
Pittsburgh Energy Research Center
U.S. Bureau of Mines
4800 Forbes Avenue
Pittsburgh, Pennsylvania 15213
(412) 898-2400
Mr. R. A. McAllister
Process Technology Manager
Foster Wheeler Corporation
110 S. Orange Avenue
Livingston, New Jersey 07039
(201) 533-3005
-------
B-3
TABLE B-l. (Continued)
Mr. J. F. Magnuson
Sales Engineer
Mining Engineering Group
McDowell Wellman Company
113 Saint Clair Avenue, NE
Cleveland, Ohio 44114
(216) 621-9934
Mr. Thoren F. Cook
Project Director for Wesco Coal
Gasification Plant
Fluor Engineers and Constructors, Inc.
2500 South Atlantic Boulevard
Los Angeles, California 90040
'(213) 262-6111
Mr. E. M. Magee
Government Research Laboratory
Esso Research and Engineering Company
Fost Office Box 8
Linden, New Jersey 07036
(201) 474-1000
Dr. John D. Holmgren*"
Manager
Energy Systems Operation
Coal Gasification Research
Westinghouse Electric Corporation
Fost Office Box 158
Madison, Pennsylvania 15663
(412) 722-5552
Dr. A. Eugene Cover
The M. W. Kellogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
(713) 626-5600
Mr. Donald Fleming*
Manager
Pollution Control Processes
Institute of Gas Technology
3424 South State Street
Chicago, Illinois 60616
(312) 225-9600
Mr. Sidney Katell*
Chief, Process Evaluation
U.S. Bureau of Mines
Fost Office Box 880
Morgantown, West Virginia 26505
(304) 599-7431
Dr. J. D. Sudbury
Assistant Director of Research
Consolidation Coal Company
Library, Pennsylvania 15129
(412) 288-8700
Mr. Roger Detman*
Froject Manager
C. F. Braun & Company
Alhambra, California
(213) 570-1000
Mr. Ray Vener
Acting Assistant Director
Office of Coal Research
2100 M Street, N.W.
Washington, D.C. 20240
(202) 343-6681
Mr. J. T. Clancey*
Froject Manager
Consolidation Coal Company
Library, Pennsylvania 15129
(412) 288-8700
Mr. Neil Cochran*
Acting Assistant Director
Office of Coal Research
2100 M Street, N.W.
Washington, D.C. 20240
(202) 343-6681
-------
B-4
TABLE B-l. (Continued)
Mr. S. J. Thomson
Manager, Environmental Engineering
Fluor Engineers and Constructors, Inc.
2500 S. Atlantic Boulevard
Los Angeles, California 90040
(213) 262-6111
Mr. Andrew Anstadt*
Manager of Projects
Fluor Engineers and Constructors, Inc.
2500 S. Atlantic Boulevard
Los Angeles, California 90040
(213) 262-6111
Mr. J. T. Wooten
Project Director
Texas Eastern Transmission Corporation
Post Office Box 2521
Houston, Texas 77001
(713) 224-7961
Mr. R. L. Rudzik
General Manager
Pacific Lighting Service Company
720 West 8th Street
Los Angeles, California 90054
(213) 689-3586
Mr. D. Michael Mitzak
Manager, Chemical Projects Section
Koppers Company, Inc.
Koppers Building
Pittsburgh, Pennsylvania 15219
(412) 391-3300
Mr. Cecil R. Gibson
Chief Solids Gasification Engineer
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79928
(915) 543-2600
Mr. Robert M. Christiansen
Manager, Environmental Sciences Division
S teams-Roger, Inc.
Post Office Box 5888
Denver, Colorado 80217
Mr. Frank Schorra
Vice President, Process Engineering
Institute of Gas Technology
3424 South State Street
Chicago, Illinois 60616
(312) 225-9600
Dr. Bernard S. Lee
Director, Hygas Facility
Institute of Gas Technology
3424 South State Street
Chicago, Illinois 60616
(312) 225-9600
Mr. John W. Loeding
Assistant Director, Low-Btu
Gas Processes
Institute of Gas Technology
3424 South State Street
Chicago, Illinois 60616
(312) 225-9600
Mr. Fred M. Glaser
Senior Engineer
Booz-Allen Applied Research
4733 Bethesda Avenue
Bethesda, Maryland 20014
(301) 656-2200
Dr. Robert Shaw
Research Director
Booz-Allen Applied Research
4733 Bethesda Avenue
Bethesda, Maryland 20014
(301) 656-2200
-------
B-5
TABLE B-l. (Continued)
Acid Gas Removal Processes
Mr, W. E. Luley*
Director, Gas Purification Department
Allied Chemical Corporation
Post Office Box 1013-R
Morristown, New Jersey 07960
(201) 455-4353
Mr. John W. Sweney*
Manager, Process Engineering
Allied Chemical Corporation
Post Office Box 1013-R
Morristown, New Jersey 07960
(201) 455-4557
Mr. E. J. Frisch*
Group Leader
Shell Development Company
2525 Murworth Drive
Houston, Texas 77054
(713) 795-3928
Mr. R. W. Van Scoy
Senior Engineer
Shell Development Company
2525 Murworth Drive
Houston, Texas 77054
(713) 795-3962
Mr. Juergen Bokaemper*
Project Engineer
Lotepro Corporation
801 Second Avenue
hew York, New York 10017
(212) 679-1337
Kr. Howard F. Leonard*
Senior Project Engineer
Koppers Company, Inc.
Koppers Building
Pittsburgh, Pennsylvania 15219
(412) 391-3300
Mr. H. E. Benson
President
The Benfield Corporation
615 Washington Road
Pittsburgh, Pennsylvania 15228
(412) 344-8550
Mr. J. H. Field
Vice President, Engineering
The Benfield Corporation
615 Washington Road
Pittsburgh, Pennsylvania 15228
(412) 344-8550
Mr.-Don McCrae*
Manager, Process Development
The Benfield Corporation
615 Washington Road
Pittsburgh, Pennsylvania 15228
(412) 344-8550
Mr. I. Norman Banchik*
Manager, Commercial Development
Davy Powergas, Inc.
Post Office Box 2436
Lakeland, Florida 33803
(813) 646-7515
Mr. R. M. Tennyson*
Manager of Processes
Fluor Engineers and Constructors,
2500 S. Atlantic Boulevard
Los Angeles, California 90040
(213) 262-6111
Mr. P. A. Buckingham
Supervising Engineer
Fluor Engineers and Constructors,
2500 S. Atlantic Boulevard
Los Angeles, California 90040
(213) 262-6111
Inc.
Inc.
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B-6
TABLE B-l. (Continued)
Mr. A. G. Eickmeyer*
Chemical Engineering Consultant
Eickmeyer & Associates
Post Office Box 8224
Prairie Village, Kansas 66208
(913) 362-1090
Sulfur Recovery Processes
Mr. I. Norman Banchik*
Manager, Commercial Development
Davy Powergas, Inc.
Post Office Box 2436
Lakeland, Florida 33802
(813) 646-7515
Mr. Srini Vasan*
Director, Business Development
Peabody Engineered Systems
39 Maple Tree Avenue
Stamford, Connecticut 06906
(203) 327-7000
Mr. 0. C. Roddey
Vice President, Precontract and Process
The Ralph M. Parsons Company
Post Office Box 54802
Los Angeles, California 90054
Mr. D. F. Cole
Contract Engineer
J. F. Pritchard & Company
4625 Roanoke Parkway
Kansas City, Missouri 64112
(816) 531-9500
Tail Gas Treatment Processes
Mr. E. E. Dodd*
Group Leader
Shell Development Company
2525 Murworth Drive
Houston, Texas 77054
(713) 795-3920
Mr. R. A. Golding
Supervisor
Shell Development Company
2525 Murworth Drive
Houston, Texas 77054
(913) 795-3904
Mr. C. B. Earl*
Sales Manager
Davy Powergas, Inc.
Post Office Box 2436
Lakeland, Florida 33803
(813) 646-7100
Mr. A. S. Kasperik
Consultant to Technology Sales
Union Oil Company of California
Research Department
Post Office Box 76
Brea, California 92621
(714) 528-7201
Mr. 0. C. Roddey
Vice President, Precontract and Process
The Ralph M. Parsons Company
Post Office Box 54802
617 W. Seventh Street
Los Angeles, California 90054
Mr. Andrew J. Robbell
Manager, Licensing and Patents
J. F. Pritchard & Company
4625 Roanoke Parkway
Kansas City, Missouri 64112
(816) 531-9500
Mr. R. Dutria
Sales Engineer
Institut Francais de Petrole
90 Park Avenue
New York, ปew York 10016
(212) 9B6-3391
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' B-7
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/3-75-029
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE ANDSUBTITLE
Development of Information for Standards of Performance
for the Fossil Fuel Conversion Industry
5. REPORT DATE
October 1974
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
B. Kim, J. Genco, J. Oxley, P. Choi
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
BatteHe Columbus Laboratories
505 King Ave.
Columbus, Ohio 43201
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-0611, Task 7
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
Office Of Air Quality Planning & Standards
Research Triangle Park,
North Caroling 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report recapitulates information developed in EPA Report No. 9075-015
pertaining to four SNG coal gasification processes (Lurqi, Synthane, Hygas
and C02-Acceptor) and one Low-BTU fuel gasification process (Lurgi). Commercial
literature on another Low-BTU nrocess (Koppers-Totzek) is also recapitulated.
Control of sulfurous emissions is discussed, (Bibliography included.)
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Fuels
Coal Gasification
Air Pollution
Desulfurization
Fael Conversion
Sulfurous Emissions
21/D
13/H
13/B
7/A
18. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
158
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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