EPA-450/3-74-055
CHARACTERIZATION
OF SULFUR RECOVERY
FROM REFINERY FUEL GAS
by
J. M. Genco and S . S . Tarn
Battelle-Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Contract No. 68-02-0611
EPA Project Officer: Charles B . Sedman
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, N. C. 27711
June 1974
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available 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.
This report was furnished to the Environmental Protection Agency by
Battelle-Columbus Laboratories, in fulfillment of Contract No. 68-02-0611 .
The contents of this report are reproduced herein as received from
Batteile-Columbus Laboratories. The opinions, findings, and conclusions
expressed are those of the author and not necessarily those of the Environ-
mental Protection Agency. Mention of company or product names is not
to be considered as an endorsement by the Environmental Protection
Agency .
Publication No. EPA-450/3-74-055
11
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TABLE OF CONTENTS
SUMMARY ix
OBJECTIVE AND SCOPE 1
INTRODUCTION 3
RECOVERY OF SULFUR IN PETROLEUM REFINERIES 5
General 5
Processes for the Removal of Hydrogen Sulfide
from Refinery Process-Gas Streams. . 9
Sour-Water Stripping as a Source of Refinery Sulfur 15
CONVERSION OF RECOVERED H2S INTO ELEMENTAL SULFUR 21
Vapor-Phase Oxidation of H^S to Elemental Sulfur--
Glaus -Process Technology 21
Liquid-Phase Oxidation of H2S to Elemental Sulfur 31
TAIL-GAS-PROCESSING TECHNOLOGY FOR GLAUS SULFUR PLANTS 41
Beavon Process .......... .43
Cleanair Process 49
Wellman-Lord Tail-Gas Process 52
Shell's Glaus-Plant Off-Gas Treatment (SCOT) Process ... .60
Institute Francais du Petrole Processes (IFP) 66
Chiyoda Thoroughbred 101 Process 76
Sulfreen Process 84
ESTIMATION OF NATIONWIDE REFINERY SULFUR PLANT EMISSIONS
IN 1975 90
CONCLUSIONS 96
REFERENCES 99
APPENDIX A
FLOW DIAGRAMS FOR FUEL-GAS-DESULFURIZATION PROCESSES A-l
APPENDIX B
FLOW DIAGRAMS FOR SOUR-WATER STRIPPER B-l
APPENDIX C
FLOW DIAGRAMS FOR RECOVERY OF SULFUR FROM ACID GASES--
REFINERY GLAUS PLANTS C-l
iii
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TABLE OF CONTENTS (Continued)
Page
APPENDIX D
ALTERNATIVES TO GLAUS SULFUR PLANTS D-l
APPENDIX E
FLOW DIAGRAMS FOR TAIL-GAS-TREATMENT PROCESSES E-l
APPENDIX F
PERTINENT METHODOLOGY INFORMATION F-l
LIST OF TABLES
TABLE 1. SUMMARY OF UNIT PROCESSES IN REFINERY FUEL-GAS
DESULFURIZING 11
TABLE 2. TYPICAL SOUR CONDENSATE SOURCES 16
AST,? i APT DATA ON SOUR WATERS 18
VABI.E 4. PERFORMANCE DATA FOR SOUR-WATER STRIPPERS 20
r-.'F, •-, LISTING OF REFINERY GLAUS SULFUR PLANT CAPACITY IN
THL ,i)>uTED STATES „ 22
'{'f-BL* *., GLAUS SULFUR PLANT CAPACITY FOR RECOVERING REFINERY
28
TA.5U-! 7. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
I !':;->() THE TIC AL 100-MT/D REFINERY GLAUS PLANT 30
•••:.. ^, FACIAL LIST OF EXISTING STRETFORD PLANTS TREATING
. '. ".liikY .,A3ES FOR SULFUR REMOVAL 34
A;,-; 9. TYPICAL COMPOSITION OF STRETFORD PURGE SOLUTION 36
r\B1.;' 10, PARTIAL LISTING OF ANNOUNCED BEAVON-STRETFORD TAIL
~^' TREATING UNITS FOR REFINERY GLAUS PLANTS 45
, >•:,'> •:, APPROXIMATE SULFUR BALANCE AND WASTE STREAMS FOR
}?.M»?N TAIL-GAS PROCESS , 46
•'W , : TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
iOf-MT/D REFINERY GLAUS PLANT PLUS BEAVON TIAL-GAS PROCESS .... 47
IV
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LIST OF TABLES (Continued)
Page
TABLE 13. ESTIMATE OF UTILITIES REQUIRED FOR BEAVON TAIL-GAS
PROCESS FOR 100-MT/D GLAUS SULFUR PLANT 48
TABLE 14. PARTIAL LISTING OF ANNOUNCED CLEANAIR TAIL GAS
PROCESSING UNITS FOR REFINERY GLAUS SULFUR PLANTS 51
TABLE 15. APPROXIMATE COMPOSITION OF WELLMAN-LORD S02
PURGE STREAM 54
TABLE 16. PARTIAL LISTING OF ANNOUNCED WELLMAN-LORD TAIL-GAS
PROCESSING UNITS 56
TABLE 17. APPROXIMATE SULFUR BALANCE AND WASTE STREAMS FOR
WELLMAN-LORD TAIL-GAS PROCESS ,57
TABLE 18. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
100-MT/D REFINERY GLAUS PLANT PLUS THE WELLMAN-LORD TAIL-GAS
PROCESS 58
TABLE 19. ESTIMATE OF UTILITIES REQUIRED FOR WELLMAN-LORD
TAIL-GAS PROCESS FOR 100-MT/D SULFUR PLANT 59
TABLE 20. PARTIAL LISTING OF ANNOUNCED SCOT UNITS IN THE U.S.
AND CANADA 63
TABLE 21. APPROXIMATE SULFUR BALANCE AND ESTIMATE OF WASTE STREAMS
FOR SCOT TAIL-GAS PROCESS 64
TABLE 22. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
HYPOTHETICAL 100-MT/D REFINERY GLAUS PLANT PLUS SCOT TAIL-
GAS PROCESS 65
TABLE 23. ESTIMATE OF UTILITIES REQUIREMENTS FOR SHELL GLAUS OFF-
GAS TREATING UNIT (SCOT) APPLIED TO A 100-MT/D REFINERY
GLAUS SULFUR PLANT 67
TABLE 24. LISTING OF ANNOUNCED TGT-1500 GLAUS-SULFUR-PLANT
TAIL-GAS-PROCESSING UNITS 72
TABLE 25. APPROXIMATE SULFUR BALANCE AND ESTIMATE OF WASTE STREAMS
FOR TGT-1500 TAIL-GAS PROCESS 73
.TABLE 26. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
A 100-MT/D REFINERY GLAUS PLANT PLUS THE IFP TGT-1500
TAIL-GAS PROCESS 74
TABLE 27. ESTIMATE OF UTILITIES REQUIREMENTS FOR IFP TGT-1500
TAIL-GAS PROCESS APPLIED TO A 100-MT/D REFINERY GLAUS
SULFUR PLANT 75
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LIST OF FIGURES (Continued)
FIGURE 5. TREATMENT OF STRETFORD PROCESS PURGE SOLUTION 37
FIGURE A-l. FLOW DIAGRAM FOR H2S REMOVAL BY AMINE SOLUTION
(GIRBOTOL PROCESS) A-l
FIGURE A-2. FLOW DIAGRAM OF ADIP PROCESS (SHELL) A-2
FIGURE A-3. FLOW DIAGRAM TOR H2S REMOVAL BY K3PQ4SOLUTION
(SHELL PHOSPHATE PROCESS) .' A-3
FIGURE A-4. FLOW DIAGRAM OF ECONOAMINE PROCESS WITH DGA
SOLUTION (FLUOR) A-4
FIGURE B-l. REMOVAL OF SULFIDES AND AMMONIA FROM SOUR WATER BY
STEAM STRIPPING B-l
FIGURE B-2. CONTINUOUS STREAM STRIPPING OF SULFIDES FROM HIGHLY
AMMONIACAL FOUL WATER B-2
FIGURE B-3. SCHEMATIC BLOCK FLOW DIAGRAM SHOWING H2S AND NH3
BY STEAM STRIPPING . B-3
FIGURE C-l. TYPICAL PACKAGED GLAUS PLANT (2 STAGE) C-l
FIGURE D-l. STRETFORD PROCESS D-l
FIGURE D-2. FLOW DIAGRAM FOR H2S REMOVAL (GIAMMARCO-
VETROCOKE-H2S PROCESS) D-2
FIGURE E-l. FLOW DIAGRAM FOR THE BEAVON SULFUR-REMOVAL PROCESS . .E-l
FIGURE E-2. SIMPLIFIED FLOW DIAGRAM FOR THE CLEANAIR GLAUS
TAIL-GAS TREATMENT PROCESS E-2
FIGURE E-3. FLOW DIAGRAM FOR THE WELLMAN-LORD S02 RECOVERY
PROCESS ' E-3
FIGURE E-4. FLOW DIAGRAM FOR THE SHELL CLAUS OFF-GAS
TREATING PROCESS E-4
FIGURE E-5. FLOW DIAGRAM FOR IFP (TGT-1500)CLAUS TAIL-GAS
CLEANUP PROCESS E-5
FIGURE E~6. FLOW DIAGRAM FOR IFP (TGT-150) CLAUS TAIL-GAS
CLEANUP PROCESS E-6
FIGURE £»/. FLOW DIAGRAM FOR THE CHIYODA PROCESS E-7
FT CURL E-8. FLOW DIAGRAM FOR THE SULFREEN PROCESS E-8
VI
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LIST OF TABLES (Continued)
Page
TABLE 28. LIST OF ANNOUNCED CHIYODA THOROUGHBRED 101 TAIL-
GAS PROCESSES UNITS FOR GLAUS SULFUR PLANTS 79
TABLE 29. APPROXIMATE SULFUR BALANCE AND ESTIMATE OF WASTE STREAMS
FOR THE CHIYODA THOROUGHBRED 101 FLUE-GAS-DESULFURIZATION
PROCESS 80
TABLE 30. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
100-MT/D REFINERY GLAUS PLANT PLUS THE CHIYODA THOROUGHBRED 101
FLUE-GAS-DESULFURIZATION PROCESS 81
TABLE 31. ESTIMATE OF UTILITY REQUIREMENTS FOR CHIYODA THOROUGHBRED
101 TAIL-GAS PROCESS FOR 100-MT/D REFINERY GLAUS SULFUR PLANT. . 83
TABLE 32. PARTAIL LIST OF ANNOUNCED SULFREEN TAIL-GAS-PROCESSING
UNITS FOR GLAUS SULFUR PLANTS 87
TABLE 33. APPROXIMATE SULFUR BALANCE AND WASTE STREAMS FOR
SULFREEN TAIL-GAS PROCESS 88
TABLE 34. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
100-MT/D REFINERY GLAUS PLANT PLUS THE SULFREEN TAIL-GAS PROCESS 89
TABLE 35. ESTIMATE OF TUILITIES REQUIREMENTS FOR SULFREEN PROCESS
ADDED TO 100-MT/D REFINERY GLAUS SULFUR PLANT. 91
TABLE 36. STATE-BY-STATE LISTING OF ANNOUNCED ADDITIONALD
REFINERY CAPACITY BY 1975 93
TABLE 37. ESTIMATED ANNUAL SULFUR DIOXIDE EMISSIONS IN THE
UNITED STATES IN 1975--NO ABATEMENT 95
TABLE F-l. VISITS TO REFINERIES HAVING TAIL-GAS-TREATMENT
EQUIPMENT F-l
TABLE F-2. LIST OF SULFUR TAIL-GAS PROCESS VENDORS F-2
LIST OF FIGURES
FIGURE 1. PROCESSING PLAN FOR TYPICAL MINIMUM REFINERY 4
FIGURE 2. PROCESSING PLAN FOR TYPICAL COMPLETE OR INTEGRATED
• REFINERY 6
FIGURE 3. SCHEMATIC FLOW DIAGRAM SHOWING SOUR WATER/SOUR GAS
STREAMS (TYPICAL MINIMUM REFINERY) 8
FIGURE 4. SCHEMATIC FLOW DIAGRAM SHOWING SOUR WATER/SOUR GAS
STREAMS (TYPICAL INTEGRATED REFINERY) 10
vii
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SUMMARY
The primary objective of Task 4 of EPA Contract 68-02-0611 was
to provide an overview of available technology for treating tail gases
from refinery sulfur plants. Although general information was developed
pertaining to refinery desulfurization technology, emphasis was placed on
estimating the environmental impact (desulfurization efficiency, utilities
required, and waste streams generated) from tail-gas-treating processes.
The open technical literature was reviewed and information was
collected on sulfur recovery in petroleum refineries. Inspection trips were
taken to several refineries that currently are installing and/or operating
tail-gas-treating processes on sulfur plants. Up-to-date nonproprietary
information on commercially available tail-gas processes was then obtained
from process licensors. Heat and material balances were performed and
estimates were made for the required utilities, emissions, and waste streams
for the Beavon, Wellman-Lord, SCOT, IFP-1500, Chiyoda, and Sulfreen processes.
Insufficient information was available to permit heat- and material-balance
calculations to be performed for the Cleanair Process. Estimates were then
made for nationwide emissions of sulfur from domestic refineries and associated
sulfur-recovery plants.
Emissions of sulfur to the atmosphere at petroleum refineries
occur mainly as SO in process heaters, boilers, and flares, in the tail gas
from sulfur-recovery plants, and as trace amounts of H-S which escape during
routine processing operations. Virtually all sulfur recovery practiced at
petroleum refineries is done by vapor-phase oxidation of H.S in straight-
through Glaus plants. Domestic sulfur-recovery capacity found at refineries
amounted to about 8,000 metric tons/day (MT/D) in 1973. Plants normally are
operated at about two-thirds of capacity and sulfur-recovery efficiencies of
90 to 95 percent. Acid-gas-feed sources to refinery Claus plants originate
mainly from sour-water strippers and amine regenerators associated with hydro-
cracking units, hydrotreating units, and fuel-gas-desulfurization operations.
Fuel-gas desulfurization using amines and other reactive liquids as well as
sulfur recovery in Claus plant is well-established technology. Both
technologies are commercially available and have been practiced in the
ix
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petroleum industry for many years
Processing of tail gases from Claus plants found at refineries
would be considered emerging technology and is now only beginning to be
practiced in the U.S. Approximately 964 MT/D of parent-Claus-plant capacity
has been equipped with tail-gas processing on domestic refineries. These
plants are now mainly in start-up and are located in the Philadelphia
and Los Angeles areas. Several have been experiencing start-up difficulties.
An additional 890 MT/D of parent-sulfur-plant capacity is due to be equipped
with tail-gas processing units in the U.S. by 1975.
By the use of tail-gas processing, overall sulfur recovery can be
increased to greater than 99 percent of the total input sulfur to Claus
plants. The utilities required and waste streams generated by the operation
of tail-gas processes are not inordinate. Roughly, the utilities (hence
operating cost) are of the same order as those involved in the parent sulfur
plant. Waste streams in processes based on aqueous-phase scrubbing usually
involve either a sour-water or acid-water purge stream resulting from
condensation of water vapor contained in the tail gas. Depending upon the
process, this water is usually sent to either the sour-water stripper for
•,S removal or to the refinery wastewater-treatment system for neutralization.
JL,
TI addition, several processes, i.e., the Beavon, Cleanair, and Wellman-Lord,
],"'/c' purge streams containing metal salts that must be disposed of.
• ur>•.-.!•,fly, waste streams of this latter type are being discharged to industrial
so»er systems. Because of their small size, this does not appear to cause
,?Jor waste disposal problems.
Nationwide sulfur emissions from refinery Claus plants were
...•stiirated to be approximately 0.136 x 10 MT/year (0.272 x 10 MT of SO )
19*'. In comparison with other emission sources of sulfur, refinery
i.--,:iant emissions appear to be quite small, i.e., the sulfur contained
:lrcr\, Claus-plant tail gases is estimated to be less than 1 percent
the iy"5 unabated sulfur emission sources.
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CHARACTERIZATION OF SULFUR
FROM REFINERY FUEL GAS
(Contract No. 68-02-0611, Task 4)
by
Joseph M. Genco and Samuel S. Tarn
OBJECTIVE AND SCOPE
The objective of Task 4 under Contract 68-02-0611 was to assist:
the Emissions Standards and Engineering Division of the Environmental
Protection Agency in developing standards of performance for recovery of
sulfur from petroleum-refinery fuel gases. Specifically this involved
providing technical information in eight areas:
(1) Defining refinery fuel gas/sour gas systems
and methods of treating fuel gas to remove
sulfur
(2) Estimating the fate of sulfur compounds in
the fuel-gas system
(3) Defining options available for sulfur
recovery
(4) Estimating the extent of sulfur recovery on
current and future U.S. refineries
(5) Estimating the extent of tail-gas cleaning
practiced currently at U.S. and foreign refineries
(6) Estimating the projected growth of domestic
sulfur recovery for the period 1975 to 1985
(7) Estimating the environmental impact of tail-gas
treating processes
(8) Assessing the environmental impact of emissions
standards on sulfur recovery in the petroleum
industry and putting sulfur emission from refineries
into perspective with emissions from other major
sources.
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Although all of these areas were treated to some extent, emphasis on the
program was given to tail-gas treatment from sulfur plants as defined in
Item 7. The main thrust of the program was to provide an overview of
available technology for treating tail gases from refinery sulfur plants.
An exhaustive technical treatment of this subject was outside the scope of
the present program.
METHODOLOGY
The following methodology was used in performing the study
covered by this report.
(1) The open technical literature was reviewed to obtain
literature on fuel-gas desulfurization in petroleum
refineries. This review covered desulfurization of
refinery fuel gas and sour-water stripping, vapor-phase
and liquid-phase sulfur—recovery processes, and tail-
gas-treating technology.
(2) Trips were made to several refineries that currently
are installing and/or operating tail-gas treating
equipment. Table F-l of Appendix F lists the
refineries visited, tail-gas-treatment equipment
inspected, and contact dates. Both EPA and BCL
personnel were involved in this part of the program.
(3) To collect up-to-date information on commercially
available tail-gas-treating processes, a letter was
sent to eight companies (see Appendix F, Table F-2)
involved in providing tail-gas processes to the
petroleum industry. Each of these companies either
developed or licensed one of the leading tail gas
processes. Except for the Cataban process, all are
commercially available. The questions asked of each
of the manufacturers are given in a sample letter
included in Appendix F. Replies to this letter were
received from all developers and licensors except the
Societe Nationale Des Petroles d1 Aquitaine, developers
of the Sulfreen Process.
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(4) For all tail-gas-treating processes except the Cataban
and Cleanair processes, simplified heat and material
balances were performed by treating the process as a
"black box". Waste streams generated in the process
and approximate utilities requirements were then
estimated.
(5) Estimates were made for nationwide emissions of sulfur
from domestic petroleum refineries and associated Glaus
sulfur plants.
(6) A final report was prepared.
INTRODUCTION
Individual petroleum refineries are different. Although each
modern refinery is unique in design, each comprises basic unit processes
employing a multitude of towers, vessels, piping, valves, tubes,
exchangers, and storage tanks. Refinery operations can be classified into
four basic procedures—separation, conversion, treatment, and blending.
Crude oil is initially separated into its various components or
fractions, e.g., gas, gasoline, kerosene, middle distillates such as
diesel fuel and fuel oil, and heavy bottoms. Since these initial fractions
seldom conform to either the relative demand for each product or to the
product's qualitative requirements, the less desirable fractions are
subsequently converted to more salable products by splitting, uniting, or
rearranging the original molecular structure. Separation and conversion
products are subsequently treated for removal of undesirable components.
The refined base stocks may then be blended with each other and with various
additives to develop the most useful products.
Individual refineries differ widely, not only as to crude-oil
capacity, but also as to the degree of processing sophistication employed.
Simple refineries, often little more than "topping plants", may be confined
(1)*
to crude separation and limited treating (Figure 1). Intermediate
refineries may add catalytic or thermal cracking, catalytic reforming.
* References are listed on pp 99 .
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distillate treating, and manufacture of such heavier products as lube oils
and asphalt. Complete or "integrated" refineries are generally large in
capacity, and encompass such operations as crude distillation; cracking;
treating; gas processing; manufacture of lube oils, asphalts; and waxes;
and gasoline-upgrading processes such as catalytic reforming, alkylation,
isomerization, sweetening, and hydrogen desulfurization (Figure 2).
Sulfur is considered an undesirable constituent of petroleum and
occurs during processing in four general types of compounds:
(a) Hydrogen sulfide and mercaptans
(b) Elemental sulfur
(c) Carbonyl sulfide (COS) and carbon disulfide (CS )
(d) Neutral sulfur compounds.
Hydrogen sulfide and mercaptans (RSH) are present in all petroleum to some
extent and especially prevalent in sour crude. They are also formed by
thermal and catalytic decomposition of sulfur compounds during distillation,
crushing, reforming, and other complex processing. Elemental sulfur per se
does not occur in petroleum. When found, it is usually formed from hydrogen
sulfide by oxidation owing to absorption of air during intermediate storage.
Under certain economic conditions, elemental sulfur is recovered as a
by-product in refinery operations. Carbonyl sulfide (COS) and carbon
disulfide (CS?) are two common forms of sulfur which are formed during
petroleum processing, particularly by thermal and catalytic cracking of
petroleum. Neutral sulfur compounds such as sulfides, disulfides, thiophenes,
henzothlophenes, dibenzothiophenes, and benzonaphtho-thiophenes are
originally present in crude oil and undergo numerous changes in the course
of processing which alter their type, molecular weight, and distribution.
RECOVERY OF SULFUR IN PETROLEUM REFINERIES
General
The amount of sulfur emitted, mainly as SO^, from refineries is
a function of the sulfur content of the crude oil being processed, the
complexity of the refinery and the refinery energy balance. Sulfur enters
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the refinery in the oil, in any purchased fuel oil or gas, and in sulfuric
acid purchased for use in various processes. A large part of the sulfur
routinely leaves the refinery in the various products, as spent sulfuric
acid shipped out for regeneration, as sulfides or sulfates in the liquid
wastes, as SO- from process heaters and boilers and in flares, in the tail
gas from the sulfur-recovery plant, and as trace amounts of H2S that
escape from the many unit operations going on in the refinery.
As shown in Figure 1, for a minimum refinery, the main sources
of sulfur feed to the sulfur recovery plant are:
A. Process Gas Sources - fuel gas
1. Atmospheric crude (topping) unit
2. Gasoline stabilization unit
3. Catalytic reformer
B. Hydrotreating Unit
C. Sour-Water Stripper.
In this hypothetical refinery, there are three sources of process gases;
the atmospheric crude unit, the gasoline-stabilization unit, and the
catalytic reformer. In each of these process gases, some H S is present
and this is scrubbed in the amine-treatment unit before the fuel gas is
used in process heaters and boilers. The acid gas or strong H S stream
leaving the amine regenerator is sent to the sulfur plant.
A secondary source of acid-gas feed to the sulfur plant would
be from the hydrotreating operations (HDS unit) used to "sweeten" the raw
kerosene and other distillates from the crude column used in the manufacture
of jet fuels and fuel oils. This stream would be treated in the HDS unit
to remove H S from excess hydrogen and light ends (CL to C-).
The third source of acid-gas feed to the sulfur plant would
arise from the sour-water stripper. Sour water arises from many sources
in the typical refinery, mainly from the atmospheric column, gasoline-
stabilization unit, hydrotreater, amine-treatment units, and the sulfur
plant. These sour waters are stripped of H S and NH_ to produce another
strong acid-gas source. This sequence of processing steps involving the
recovery of sulfur within a "minimum refinery" is shown schematically in
Figure 3,
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For the complex integrated refinery shown in Figure 2, acid gas
from four sources would be fed to the sulfur plant:
A. Process Gas Sources - fuel gas
1. Atmospheric crude unit
2. Hydrocracking unit
3. Catalytic cracking unit
4. Coker
5. Reformer
B. Hydrocracking Unit
C. Hydrotreating Unit
D. Sour-Water Stripper.
A schematic diagram (see Figure 4) showing the sour-gas and sour-water streams
for an integrated refinery is more complex but quite similar to that shown
in Figure 3. The refinery would have three amine-treatment units (one
each for the fuel-gas system, the hydrocracker, and the hydrotreater) as well
as a sour-water stripper.
The technology available for recovery of sulfur in petroleum refineries
can be divided into four categories.
(1) Fuel-gas-treatment processes
(2) Sour-water stripping
(3) Acid-gas treatment - i.e., Glaus-plant technology
and alternative methods of sulfur recovery
(4) Tail-gas-treating processes.
Pertinent technology on fuel-gas-treating processes, acid-gas treating, and
tail-gas-treating processes is summarized in Table 1.
Processes for the Removal of Hydrogen
Sulfide from Refinery Process-Gas Streams
Many regenerable methods are available for the removal of
hydrogen sulfide from refinery process-gas streams. Only the following
aiore important processes are discussed here (see Table 1):
Girbotol Process (Girdler)
Adip Process (Shell)
Phosphate Process (Shell)
Econoamine Process (Fluor).
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-------
TABLE 1. SUMMARY OF UNIT PROCESSES IN REFINERY FUEL-GAS DESULFURIZING
Process
Fuel-Gas Treatment
Mif Process (Shell)
Glrbotol Process (Girdler)
Mcnoethanolamine (MEA)
Dietbanolamine (DEA)
Triethanolamine (TEA)
EC ;noanine Process (Fluor)
Shell Phosphate Process (Shell)
Acid-Gas Treatment
Basis
Liquid Chemical Absorption
Aqueous amines,
dl-isopropanol
15-20Z aqueous solution
15-20Z aqueous solution
15-20Z aqueous solution
Alkanolamlne (DGA)
Aqueous K-PO,
Vapor-Phase Oxidation
Process
Temp,
C
30- 55
30- 55
30- 55
30- 55
30- 55
30- 55
Process
Pressure,
at*
1-70
1-70
1-70
1-70
1-70
1-70
Regeneration
(a)
(a)
(a)
(a)
(a)
(a)
Product
Forn
V
H2S
a,,s
V
V
Process
" ' ..finai; '--Verroccke - H S
iKivf rga« .~orp.)
Treat: ment
Gas-phase catalytic
oxidation 200-260
Liquid-Phase Oxidation
Solution oxidation of H,S 30- 55
absorbed as thioarsenlte
vith arsenate/arsenite air
regenerated redox couple
as oxygen carrier 30- 55
Solution oxidation of H S 30 - 55
(absorbed as bisulfide)
by two-stage redox reaction
involving vanadate and
anthraquinone disulfonic acid
as the oxygen carriers 30- 55
Liquid-Chemical Absorption
Aqueous NaS" /"aHSO
absorption 45- 55
Cat. hydrogenation to reduce
COS, SO,, and CS, to H,S
for feed to Stretford ' 30- 55
H S-rich tail gas water
cooled to continue Claus
reaction and hvdrolyze COS
and CS- to H,S; final H S
sent to Stretford 45- 55
Cat. hydrogenation to reduce
COS, SO,, and CS, to H,S
for fee3 to an afkanolamine
absorption unit 30- 55
Glaus redox reaction in
solution with or without
added catalyst 125-150
Absorption of SO, in dilute
H-SO containing Fe,(SO.)
catalyst * 45- 55
Vapor-P*-ase Oxidation
Catalytic use of activated
carbon for high efficiency
Ciaus redox reaction to
Yield s-ilfjr 125-150
1-2
1-70
1-70
1-70
1-70
(d)
, (bl
(e)
,Cb)
Air blowing
Air blowing
Air bloving
Air bloving
Thermal ro
eration
Air bloving
Air blowing
rl.S
'. *'' s:I_tioi in a rebelled stripper colurj-..
-....:,-:.: near atmosp'.-.er'.c pressure with sufficient pressure to overcome the
_- t- t."ie "laus pr^:es_T,
r-^ ,-ta* a catalytic .K\ drogenation '^reduction step} that is operated at a;
,- :,as a catalytic hv^rogenatior. step that is operated at about 315+ C
+ 'J n-^ :: rjl ized uith iir.es tone.
pressure crop In
out 315* C
-------
12
Schematic flow diagrams for all of these processes are presented in
Appendix A.
Girbotol Process. Hydrogen sulfide and carbon dioxide readily
combine with aqueous solutions of certain aliphatic amines at temperatures
usually close to ambient, and may be driven off from the fat solutions by
heating to about 100 C. The reactions with hydrogen sulfide and carbon
dioxide are essentially:
The above reaction with H S forms the basis of the well-known Girbotol
(2-4)
process (see Figure A-l) . The amines normally used are the mono-, di-,
and triethanolamines. Currently, the material most commonly used is
diethanolamine. Monoethanolamine has a higher absorptive power for hydrogen
sulfide and carbon dioxide per volume of treating solution, but has the
disadvantage that any carbonyl sulfide present in the gas combines
Irreversibly with it. The triethanolamines have poorer absorptive powers
but are more selective, removing carbon dioxide only to a relatively small
extent. The treating solution contains from 15 to 20 weight percent of the
amine .
Conventional equipment is used, generally a bubble-cap tower when
refinery gases are to be treated, together with a bubble-cap tower for
regeneration. Treatment takes place at line pressure but care must be
exercised to see that the treating temperature is 5 to 10 C above the
hydrocarbon dew-point temperature of the gas to ensure that no hydrocarbon
liquid condenses out in the plant.
The Girbotol process is perhaps the most widely used method for
the regenerative removal of hydrogen sulfide from refinery gases. However,
its use is not confined to refineries. The simple and usually troublefree
nature of the process renders it an excellent treatment tool for natural gas
and LPG in oil fields, where the plants give excellent service with a
..... ul'-nuin of attention. Utility requirements are quite low and the plants
-------
13
are quite flexible, being readily capable of yielding products containing
only very small amounts of hydrogen sulfide. However, where the hydrogen
sulfide content of the effluent gas must be reduced to less than 1 or 2 ppm
or lower, it is usually more economic to follow treatment in the Girbotol
plant with a nonregenerative soda wash rather than to incur the very high
solvent circulation rate and very complete regeneration needed if the
Girbotol plant alone has to meet requirements.
Adip Process. The Adip process (Figure A-2) is very similar to
the Girbotol process and numerous units are in operation throughout the
world. The process is based on regenerative absorption of solvent amines
in equilibrium reaction with acidic gases. KLS-containing feed is con-
tacted countercurrently with Adip (aqueous alkaline di-isopropanol amine)
solution in an absorption or extraction column. Regenerated solution is
introduced into the head of the absorption column at a normal or slightly
higher temperature and leaves at the bottom of the column. Rich solution
exchanges heat with the regenerated solution and is fed to the regenerator.
Acid gases are stripped in the regenerator column, which is equipped with
a steam reboiler. Cooled regenerated solution is recycled into the absorber.
Acid gases removed from solution in the regenerator are cooled
with air and water, thus condensing the water vapor which is refluxed into
the tower. All absorbed H S is concentrated in the acid gas stream.
Steam consumption in the process is reduced when removing H~S
from gases under pressure because higher absorption temperatures are
possible. H-S in the product can be reduced to meet stringent specifications
thus making after-treatment unnecessary. Wide flexibility is possible in
setting operating conditions. The absorber conditions are set by the
pressure of the feed stream and range from near atmospheric pressure to
about 70 atmospheres of pressure. The regenerator normally operates at
slightly above atmospheric pressure such that low-pressure (about 5
atmospheres) steam is suitable for reboiler heat.
Solvent circulation rates are dependent on the total gas feed
rate and concentration of acidic gases in the feed.
-------
14
Shell Phosphate Process. The Shell phosphate process utilizes
an aqueous solution of tri-potassium phosphate for the removal of hydrogen
sulfide from gaseous and liquid streams according to the following reaction:
KHS
A flow diagram for the phosphate process is presented in Figure A-2.
Absorption takes place at ambient temperature, usually in a bubble-cap tower.
The hydrogen sulfide is recovered from the fat solution by rebelling in a
bubble-cap tower. Regeneration is also assisted by the fact that absorption
usually takes place at a considerable pressure (10 to 70 atmospheres),
whereas the pressure in the regenerator is only slightly above atmospheric.
It can be noted in the flowsheet that the usage of steam for reboil heat
has been minimized by designing the regenerator to produce both a "very lean"
solution and a "lean" solution. The "very lean" solution is fed to the top
of the absorber to ensure that the treated stream is contacted last with
the liquor of highest power for the removal of hydrogen sulfide, while the
"lean" solution enters lower down the absorber, where it effects the removal
of the bulk of the hydrogen sulfide. This splitting of the lean-solution
flow is normally used for gas treating where a product of very low hydrogen
sulfide content is required; for treating refinery gases, the conventional
single lean-solution flow is normally adequate.
Since tri-potassium phosphate is a stable inorganic salt that
does not decompose or vaporize under treating conditions, it does not
contaminate the hydrocarbons in any way. Furthermore, solution loss is
negligible. There are no corrosion problems, and mild steel is, therefore,
a satisfactory material of construction.
An important point to note is that there is little concomitant
removal of carbon dioxide. This factor may often weigh heavily in favor
of the process and more than counterbalance the rather high steam consumption
since frequently the removal of carbon dioxide is either unnecessary or
undesirable. Furthermore, as the recovered hydrogen sulfide contains little
carbon dioxide and hydrocarbons, it is eminently suitable for the manu-
facture of elemental sulfur in a Glaus plant.
-------
15
Econoamine Process (PGA). Frequently, a gas must be dried as well
as purified of hydrogen sulflde. This is true of natural gas for domestic
distribution, where water must be removed in order to prevent condensation
in the line and the formation of solid hydrates at low temperatures. The
two operations may be combined in the glycol-amine process using a solvent
of di- or triethylene glycol plus mono- or diethanolamine together with
some water. A good example of this type of process is the Econoamine
process which uses an aqueous solution of the primary alkamolamine
(OCH-H,OC.H,NH2) having the trade name diglycolamine (see Figure A-4).
The operation of the Econoamine process is very similar to the Girbotol and
Adip processes.
Sour-Water Stripping as a Source of Refinery Sulfur
In petroleum refining, various processing operations produce
wastewater solutions, principally condensates containing sulfides. These
sulfides are generally present as hydrogen sulfide in the presence of
ammonia, mercaptans, phenolics, and possibly small amounts of water-soluble
organic acids, nitrogen bases, and cyanides. These wastewaters are
generally referred to as "foul waters" or "sour waters". The principal
sources of foul waters are condensates from accumulators, reflux drums and
knockout pots in catalytic reformers, cracking, hydrocracking, coking, and
crude distillation. Table 2 presents several typical sources of sour
( 8)
condensate.
The amount of H_S in sour condensate is related to the H_S
partial pressure in the vapor phase at the condensate source. If the source
drum contained only H S, hydrocarbon vapor, and water, equilibrium H S-H 0
conditions would be attained. However, this is rarely the case. Almost
invariably there is also a hydrocarbon liquid phase present, and the
hydrocarbon liquid forms a layer between the vapor phase and the sour
condensate. Thus, it is doubtful that true H S-H 0 equilibrium is reached
between the vapor phase H~S and the sour condensate. Also, in most cases,
ammonia is present because of one or both of the following reasons:
-------
16
TABLE 2. TYPICAL SOUR CONDENSATE SOURCES
(8)
Process
Effluent Condensate
Source
Original Steam Source
Crude oil distillation
Petroleum coking
(Thermal cracking)
Petroleum visbreaking
(Thermal cracking)
Vacuum distillation
Petroleum catalytic
cracking
Catalytic hydro-
rlesulfurization
Citalytic reforming
fetrochemical processes
^Thermal cracking of
hydrocarbons)
Distillation reflux drum
Distillation reflux drum
Distillation reflux drum
Distillation overhead
Distillation reflux drum
Product stripper reflux
drum
Product stripper reflux
drum
Quench systems and/or
distillation reflux
drum
Stripping steam, water in
crude oil
Stripping steam, coke drum
steam, heater injection
steam
Stripping steam, heater
injection steam
Stripping or diluent
steam, ejector motive
steam
Stripping steam, catalyst
stripping steam
Stripping steam
Stripping steam
Reaction diluent steam
-------
17
(a) Ammonia is usually injected into fractionator
overhead systems to neutralize the E~S and to
avoid the corrosion caused by acidic H.S in
the sour condensate.
(b) Nitrogen in the process feedstock is hydrogenated
and forms free ammonia.
Aqueous-phase concentration data for 13 different sour waters are
presented in Table 3.
Essentially, sour waters and sour condensates are aqueous
solutions of NH and H S which may contain as much as 10,000 ppm of H S.
The molar ratio of NH_ to H S varies from about 1.0 to about 2.0, with an
average of 1.5. The alkalinity ranges from 7.8 to 9.3 pH. The NH.. and H?S
+
are present in solution in equilibrium with NH, ion and SH ion. The
overall equilibrium can be depicted as follows:
NH3(g) 2
H2S(g) t
NH (£) + H2S(£) 2 NH4 + SH
Roughly speaking, the free H.S in solution would be proportional
to the partial pressure of H2S in the gas phase, in the absence of a hydro-
carbon layer. Most refineries and petrochemical plants include facilities
for stripping H_S and, in some cases, NH_ from their sour-water streams. In
those cases where sulfur recovery is practiced, the off gas from the stripper
is routed to the sulfur recovery plant. When sulfur recovery is not
practiced, the sour off-gas stream is usually incinerated. Sour-water
strippers are normally considered part of the wastewater-treatment system.
Many different types of sour-water strippers and methods of
stripping are used commercially, but most of them involve the downward flow
of sour water through a tray or packed tower while an ascending flow of
stripping steam, fuel gas, or flue gas removes the H^S and, in some cases,
the NH,. The operating conditions vary from 1 to 4.4 atmospheres and from
35 to 130 C. The sour water may or may not be acidified with mineral
acid (H SO, or HC1) prior to stripping.
-------
18
TABLE 3. API DATA ON SOUR WATERS
V
Range Avg
275-500 390
1,500
5,000
7,200
4,800
3,000-11,000 7,000
7,500-9,000 8,250
4,000
1,600-2,500 2,050
8,000
1,876
1,020
3,000
3 Phenols pH
Range Avg
100-700 135
1,000
5,000
5,000
3,600
3,500-6,000 4,750
6,100-7,000 6,550
3,000
2,000-2,300 2,150
5,000
1,480
748
2,400
Range Avg Range
7.5-8.0
100
_ -.
- -
__
700-1,000 900 8.4-8.8
800
8.5-9.0
__
102 9.0-9.5
220
--
Avg
7.75
8.00
--
--
8.30
--
8.60
8.70
8.75
8.50
9.25
8.50
8.40
Kotes: L. The H S partial pressure in source drums is estimated to be probably
0.007 to 0.3 atmosphere.
2. H S, NH , and phenol concentrations are in ppm by weight.
-------
19
H0S Is much easier to remove than is NH_. In pure water at
5
38 C, for example, Henry's Law coefficient for NH_ is 5.6 x 10 ppm/atm,
3
while that for H-S is 2.7 x 10 ppm/atm. To remove efficiently about 90
percent of the NH,, a temperature of 110 C or higher is usually employed.
For the same stripping gas rate, 90 percent of the H S could be removed at
lower temperatures.
The use of mineral acids to acidify the sour water, prior to
stripping, fixes the NH as NH.C1 or (NH.) SO,. These are salts of strong
acids and a weak base, so the free NH, formed by hydrolysis is practically
nil; hence the NH is fixed in solution. This releases the H S and 90
percent or more of the H.S can be removed at 38 C. The use of flue gas as
a stripping medium introduces C02 into the system, and this is not done
when H?S is to be recovered in a sulfur plant. Also, fuel gas, or any inert
gas, can be used to strip H?S from sour water. However, stripping H_S with
fuel gas has the disadvantage of contaminating the fuel gas with both H?S
and water. Again this is not done when H.S is to be recovered.
The majority of installed sour-water strippers employ steam as
both a heating medium and a stripping gas. Some of these are provided with
overhead condensers to remove the stripping steam from the overhead H«S
and NH . The condensed steam is recycled or refluxed to the stripper.
(8)
Table 4 presents some available data on steam strippers and their
performance. An example of a sour-water stripper in which both H_S and NH.
are recovered (no acidification) is shown in Figure B-l. This figure shows
a stripper designed to handle sour waters and condensates from several
(9)
refinery processes (thermal cracker, fluid coker, and gas plant) in one unit.
Figure B-2 presents a typical design for stripping H-S from highly ammonical
foul waters in which NH_ is not recovered (mineral acid fixation). Both
processes employ steam as the stripping medium. A block diagram for the
recovery of NH as well as H S is shown in Figure B-3. These components
are separated, respectively, into a high-purity NH stream suitable for
sale or use within the refinery, a H?S stream suitable for conversion into
sulfuric acid or sulfur, and a clean-water stream suitable for reuse in
process plants or for direct discharge following aeration to restore oxygen
content if necessary.
-------
20
TABLE 4. PERFORMANCE DATA FOR SOUR-WATER STRIPPERS
(8)
Stripping
Medium.
scf/galW
Steam strippers
Without Acidifying 60-239
With Acidifying 30-45
Fuel-gas strippers
With SteanTc) 95
With Steam(d) 89
Fuel-gas stripper
With Acidifying (e) 56
Temperature at
Percent Removal Tower
H2S NH Bottoms, C
96-100 69-95(f) 110-132
97-100 0 110-121
88-98 77-90 113+
99 8 60
98 0 21-38
(a) Standard liters of stripping medium per liter of total tower feed
including reflux.
(b"i Excluding one unexplainably high value.
>cj Based on data from one tower. Stripping medium was 90 volume percent
n-IO volume percent flue gas.
,,!) Based on data from one tower.
'•-•) Based on data from one tower. NH.- removal assumed as 0 percent
because of acidifying.
l. Range would be 86 to 95 percent if one low value were excluded.
-------
21
CONVERSION OF RECOVERED K^S INTO ELEMENTAL SULFUR
In refinery technology, two general categories of processes are
available for recovery of elemental sulfur from lUS. Both classes of
processes involve the oxidation of H^S to elemental sulfur utilizing the
overall simplified reaction
1/2
The mechanism by which the above reaction occurs is greatly different in
the two cases and involves vapor-phase catalytic oxidation in one case
(classical Glaus-plant technology) and liquid-phase oxidation in the other.
The essence of each method is described in the following paragraphs.
Vapor-Phase Oxidation of H^S to Elemental Sulfur—
Glaus-Process Technology
The Glaus process has been proven effective in converting hydrogen
sulflde to elemental sulfur. The efficiency varies from 90 to 99 percent,
depending on the concentration of hydrogen sulfide in the sour gas and the
number of stages. A typical Glaus plant will recover about 94 percent of
the sulfur feed. Depending upon the concentration of hydrogen sulfide in
the sour gas, there are four main types of Glaus processes-' (1) straight
through, (2) split flow, (3) sulfur recycle, and (4) direct oxidation.
since the advent of economical fuel-gas-treatment and sour-water-treatment
processes from which enriched streams of hydrogen sulfide are obtained,
the straight-through Glaus process has been used almost exclusively in the
petroleum refinery industry.
Claus plants are widely used for recovering by-product sulfur
from petroleum. A plant-by-plant listing of refinery sulfur capacity is
given in Table 5 and summarized state by state in Table 6. A typical
two-stage packaged Claus plant found in refineries for the purpose of sulfur
recovery is shown in Figure C-l. The basic exothermic reactions for this
are:
-------
22
TABLE 5. LISTING OF REFINERY GLAUS SULFUR
PLANT CAPACITY IN THE UNITED STATES
(11)
State/Company/City, County
ALASKA
Energy Co. Alaska
Fairbanks, North Star
ARKANSAS
Monsanto Co.
Eldorado, Union
CALIFORNIA
Monsanto Co.
Avon
Union Oil Co. of California
Santa Maria, Santa Barbara
Allied Chemical Corp.
Richmond, Contra Costa
Expansion
Humble Oi 1 & Refining Co.
Be.iicia, Solano
Shell Oil Co.
Martinez, Contra Costa
.'c;. 0.1 'Jo. of California
r«'i Francisco, San Mateo
Expansi on
'lied Chemical Corp.
El Segundo, Los Angeles
Expansion
• . Kiutlc Richfield Co.
Wi ir.ington, Los Angeles
: Mier Carbon and Chemical Corp.
Los Angeles, Los Angeles
•" .ml ru -.tt' C, . i ?* Refining Co.
••• i . -rdngton, Los Angeles
. /.. r." i,t gle Refining Co. Inc.
loriiaice, Los Angeles
." " ) I Corp,
— tu Fe Springs, Los Angeles
.,A'>hr-h- c;-
",',l'av,B . on
Year
Sulfur
Production
Started
1972
Before 1961
Before 1967
1954
Before 1962
1968
1969
1966
1955
1971
1959
1964
1967
Before 1972
1966
Before 1962
1959
Before 1961
Before 1962
1964
Daily Sulfur
Capacity, ^a'
metric tons*
9
•
25
132
55
100
+100
270, two trains
100
70
+75
175 standby
+100
65
Not reported
9
7 standby
4 standby
8
9
13
-------
23
TABLE 5. (Continued)
Year
Sulfur
Production
State/Company/City, County Started
CALIFORNIA
Mobil Oil Corp.
Torrance, Los Angeles
Expans ion
Power in e Oil Co.
Santa Fe Springs, Los Angeles
Standard Oil Company of California
El Segundo, Los Angeles
Efauffer Chemical Co.
Wilmington, Los Angeles Before
Expansion Before
Expansion
Expansion
Expansion
Expansion Before
j'oxaco, Inc.
Los Angeles, Los Angeles Before
Union Oil Co. of California
Mi Imington, Los Angeles
/Ixpans i on
Kxp ^. i s i on
1967
1973
1957
1972
1962
1962
1962
1964
1967
1972
1962
1952
1962
1973
Daily Sulfut
Capacity, 'a'
metric tons*
85
Not reported
20
450
100
+20
+140
+8
+132
+50
50
49
+100
+200
. t: mental Oil Co.
Denver, Adams
• •-. \RE
-•» ; / Oi 1 Co.
!'v ' .;'•>.! ?\. City, New Castle
. .:. c i CheT.iical Co.
>-.- i,-v;;>:t. City, New Castle
Expcnp i on
1968
1956
Before 1962
Before 1972
18
375
260
+140
.;}/jm Pc-tro-leum Corp.
.t/t'-jtb Point, Honolulu
1972
Not reported
; « Cor.ipr.ny of Illinois
Wood River, Madison
s;,ior. Oil Co.
Robinson, Crawford
1960
1970
150
40
-------
TABLE 5.
24
(Continued)
State/Company/City, County
Mobil Oil Corp.
Jolict, Will
Union Oil Co. of California
Lemon t, Cook
Expansion
Expansion
INDIANA
American Oil Co.
Whiting, Lake
Expansion
Expansion
Expansion
Atlantic Richfield Co.
East Chicago Lake
Cities Service Oil Co.
East Chicago, Lake
KANSAS
Farmland Industries, Inc.
Coffeyville, Montgomery
Phillips Petroleum Co.
Kansas City
LOUISIANA
Citif-s Service Oil Co.
Lake Charles, Calcasieu
fulf Oil Corp.
Belle Chasse, Plaquemines
Humble Oil & Refining Co.
Bat'oa Rouge
Expansion
Year
Sulfur
Production
Started
1972
Before 1961
1964
1971
1952
1964
1972
1972
1971
1972
1968
1968
1972
1972
1967
1972
Daily Sulfur
Capacity, a'
metric tons*
300
20
+34
+25
64
+40
+43
+132
85
50
6
38
100
40
10
+300
£ f;U't for Chemical Co.
Fr, con ]\ouge
->Uc-!l Oi 1 Co.
N'i,-rco, St. Charles
Texaco, Inc.
Paradis, St. Charles
1950
1965
1966
30
40
50
ora Refineries, Inc.
/•"'I. .a, Gr.itiot
1956
12
-------
25
TABLF 5. (Continued)
State ''C i-par.y 'C: ty , County
Marathon C: 1 Co.
Detroi t
Expanse en
Ex pans ion
Mobil Oil Corp.
Woodhaven, Trenton
MINNESOf.
Great Northern Oil Co.
Pine Bend
Expansion
North Western Refining Co.
St. Paul Park, Washington
MISSISSIPPI
Gulf Oil Corp.
Purvis, Larar
Chevron Oil Co.
Pascagoula, Jackson
Year
Sulfur
Production
Started
Before 1961
1962
1968
1962
1955
1963
1968
Before 1961
1972
Daily Sulfur
Capacity,
metric tons*
27
+8
4-34
8
60
+ 70
40
30
Not reported
AiT.e :i car. Oil Co .
S'l^ar Creek, Jackson
1971
60
Fanrers 1'r.ion Central Exchange
1x3 ure I , Ye 1 1 cws tone
.' , .•, t3. L.J. S'-lfur & Cherical Co.
East Billings, Yellowstone
M .r.tan.i Suiter & Cherical Co.
Billings, Ye 11 cvs tone
F x p a n s ton
1969
Before 1972
1956
1964
28
120 standby
40
+45
A -.l.o*.! Ch, -ical Corp.
E i izabeth , Union
American Cyar.atr.id Co.
Be-ind Brock, Scnarset
Expans ion
Auilin Company of New Jersey
Perth Ar-.bcy, Middlesex
Expansion
1958
1967
1972
1957
1962
30 standby
12
Not reported
35
+ 15
-------
26
TABLE 5. (Continued)
State/Company/City, County
Year
Sulfur
Product ion
Started
Daily Sulfur-
Capacity, ^a)
metric tons*
Amerada Hess Corp.
Port Reading, Middlesex
Humble Oil & Refining Co.
Linden, Union
Freeport Sulfur Co.
Westville, Camden
Mobil Oil Corp.
Paulsboro, Camden
Expansion
NEW MEXICO
El Paso Natural Gas Co.
Eunice, Lea
1-!FW YORK
Ashland Oi1, Inc.
Buffalo
NORTH DAKOTA
Signal Oil a Gas
Tioga, Williams
Expansion
Expar si on
CHIO
*-shland Oil, Inc.
Canton, Stark
Sun Oil Co.
Toledo
Expansion
Pi. Ms'SYLVAN IA
At lam. c Richfield Co.
Ma r : -. • s Hook, Del aw are
Expansion
itlaiille Richfield Co.
Philadelphia-, Philadelphia
E\pans ion
fir .->-• 1 0,-rp.
Marcus Hook, Delaware
"u li 0; 1 r. orp.
. 'K; ,-ci.it 3 phi a, Philadelphia
jtin Oil Co.
Circus Hook, Delaware
Before 1967
1970
Before 1961
Before 1961
1972
Before 1961
1969
1953
1963
1967
1970
1958
1972
Before 1961
1962
1964
1971
Before 1972
Before 1961
1955
40
300, two trains
30
95
+90
30
50
50
+23 standby
+150
50
12
+27
20
+32
38
+35
52
135
30
-------
TABLE
Statc/Company/Ci ty , County
TEXAS
Sulpetro Corp.
Big Spring, Howard
Diamond Shamrock Corp.
Sunray, Moore
Phillips Petroleum Co.
Rorger, Hutchinson
Coastal States Petrochemical Co.
Corpus Christi, Nueces
Phillips Petroleum Co. .
Sweeny, Bra z or i a
Atlantic Richfield Co.
Houston, Harris
Expansion
Signal Oi 1 & Gas Co.
Houston, Harris
Expansi on
Shell Oil Co.
Deer Park, Harris
Expansion
Expansion
Staufier Chemical Co.
Bay town, Harris
Ex pans i on
Atldnti"': Richfield Co.
Purt Arthur, Jefferson
Expans ion
BP Oi I lor p.
Port Arthur, Jefferson
Gui f Oi 1 Corp.
Port Arthur, Jefferson
Expans i on
Mobi ! Oi 1 Corp.
Beaun.ont, .Jefferson
.V !*• . ^ i'i Pft troi i na
•V> i: L P 1 c.isant Ti t us
27
5. (Continued)
Year
Sul fur
Production
Started
1966
1951
1968
1972
1967
1960
1970
1963
1967
Before 1962
1966
1970
1953
1962
1961
1967
1972
Before 1961
1962
Before 1962
1969
Daily Sulfur
Capacity, U;
metric tons*
10
30
33
85
25
30
Not reported
40
10
50
+50
4-300, two trains
70
+121
38
+35
35
75
+75
50
Ib
• L'Ui
roi Oi 1 Co .
Salt Lake City
1972
U
Vir-rica.. Oil Co.
Vorktown, York
WISCONSIN
Murphy f». 1 Coip .
Superior, Douglas
1957
1972
50
15
Represents plant capacity in April, 1973.
-------
28
TABLE 6. GLAUS SULFUR PLANT CAPACITY FOR RECOVERING REFINERY SULFUR
Metric Tons Per Day
(a)
State
Alabama
Alaska
Arkansas
California
Colorado
Delaware
Florida
Georgia
Hawaii
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
New Jersey
New Mexico
New York
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wisconsin
Wvoming
TOTAL
Total Crude
Capacity, (b)
103 MT/D<20)
5.31
7.33
6.55
234.60
6.76
19.15
0.68
1.68
8.66
142.48
73.54
52.94
21.68
212.21
3.27
18.11
23.71
41.90
14.09
18.95
0.68
80.98
6.46
14.04
7.22
79.89
63.12
2.26
88.63
1.03
3.97
477.10
16.59
6.57
46.39
2.67
4.86
19.53
1,835.59
Sulfur
Capacity, ^c^
MT/D(11)
9
25
2,510
18
775
—
—
—
569
414
44
—
570
—
89
170
30
80
113
—
617
30
50
200
89
—
—
342
—
—
1,178
12
50
—
—
15
—
7,999
(a) Does not include standby capacity.
(b) 1 metric ton is taken to be 7.31 barrels of oil.
(c) Sulfur capacity as of April, 1973.
-------
29
H S 4- 1/2 0
-------
30
TABLE 7. TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING
HYPOTHETICAL 100-MT/D REFINERY GLAUS PLANT
(a)
Basis: Sulfur Recovery in Glaus Unit of 94 percent
Composition,
percent volume
V
so2
S vapor and mist
COS
cs2
CO
co2
HC (MW: 30)
H2
H2°
N,,
I
°2
TOTAL
Temperature, C
Pressure, atm
Gas quantity
(relative amount)
moles
F.' ow, ' scinrn
Glaus
Intake
89.9
—
—
—
—
—
4.6
0.5
—
5.0
—
—
100.0
40
1.45
1
56.78
Glaus
Before
Incineration
0.85
0.42
0.05
0.05
0.04
0.22
2.37
—
1.60
33.10
61.30
—
100.00
140
1.26
3.0
170.35
Tail Gas
After f ,
_ . . (.b)
Incineration
—
1.08
—
—
—
—
4.23
—
—
26.57
66.68
1.44
100.00
650
1.00
5.0
284.48
(a) Taken from Reference 21.
(b) Based on using 10 percent excess air in the incinerator and
CH. as fuel.
4
,[u) Flow given in standard cubic meters per minute (scmm) .
-------
31
Under the conditions prevailing in the reaction furnace (approxi-
mately 1100 C), formation of some carbonyl sulfide (COS) and carbon disulfide
(CS ) is inevitable if the acid gas contains CO and hydrocarbons:
CO + H S £ HO + COS (4)
COS + H2S 2 H20 + CS2 (5)
CH4 + 3S - H2S + CS (6)
Although the amounts of COS and CS formed are relatively small (about 400 to
500 ppm each under equilibrium conditions), especially if the hydrocarbon
content of the acid gas is low, they are significant as potential air
pollutants. Under circumstances where kinetic factors control the formation
of COS and CS , concentrations can be much higher, i.e., perhaps as high
as 4000 ppm COS plus CS , depending upon temperature. Also, some CO and H
are formed by partial oxidation of hydrocarbons contained in the Glaus feed
gas.
A special catalyst may be placed in one or all of the catalytic
converters to hydrolyze COS and CS to H S and CO by reversing Reactions
(4) and (5) at the lower converter temperatures (approximately 260 C), thus
minimizing the formation of these compounds. The modified process emphasizes
maximum conversion efficiency (about 99 percent sulfur recovery) in an effort
to minimize expenditure for tail-gas desulfurization.
Liquid-Phase Oxidation of H..S to Elemental Sulfur
In the Glaus process, sulfur in the minus-two oxidation state
(H S) is converted to the zero oxidation state (elemental sulfur). This is
done by partially burning the H S (-2 oxidation state) to yield one-third
of the original H_S stream on a molar basis in the form of S0? (+4 oxidation
state) and then catalytically reacting SO. with the remaining two-thirds
H S. Sulfur dioxide can, in this case, be viewed as the oxygen carrier. In
a number of other processes specifically designed to handle low concentrations
of sulfur compounds, as in refinery fuel gas, the oxygen carrier is either
an organic or inorganic compound chosen for its ease of transferring oxygen
to the species being oxidized (H S) and for ease of reoxidation in a
-------
32
recycling process. This is the principal characteristic of the anthraquinone
(22) (23)
and naphthaquinones used in such processes as the Stretford and Takax
methods of desulfurizing fuel gas, and two tail-gas-treating processes
t
(27)
incorporating the Stretford process; namely, the Beavon ' and Cleanair
processes. Inorganic arsenical oxygen carriers are used in the Thylox
(28)
and Giammarco-Vetrocoke methods. Iron oxide plays a similar role in
the Ferrox , Manchester , and old iron-sponge techniques
Two of the leading oxygen-carrier processes are described below;
the Stretford process, which is characteristic of an organic oxygen carrier,
and the Giatnmarco-Vetrocoke-H S (G-V) process, which is characteristic of an
inorganic oxygen carrier. Both processes have been used widely for
desulfurizing natural gas and refinery gases in Europe, but are little
known in the United States. The G-V and Stretford processes are classic
examples of multiple, coupled redox reactions in solutions. Only one known
plant uses the G-V process in the Ihited States (a natural gas plant in
Texas), while the Stretford process is being applied to treating natural,
refinery, and industrial gases.
Stretford Process. The Stretford process, shown in Figure D-l,
is a one-step process to convert low-concentration hydrogen sulfide to
f *3 O *3 / ^
elemental sulfur. The refinery fuel gas is passed into a counter-
-------
33
gas stream with the formation of hydrosulfide. In
the absence of CO., the solution pH is controlled by
use of a buffer such as sodium borate.
• Bellasol - An EDTA compound that sequesters solubilized
iron in the solution.
The II S is absorbed by the active Stretford solution, and the clean fuel gas
is used for process purposes. Outlet sulfur loadings depend on design
but are usualJy guaranteed to be less than 1 ppmv (sulfur as H S) and
usually run about 0.2 ppm in certain applications. About 2'j> Stretford
plants are operating in Great Britain and Northern Ireland where the
maximum level of II S permitted is 1.5 ppm. Most of these plants have
demonstrated on a continuous basis exit loadings of less than 1 ppm.
A partial list of Stretford units treating refinery gases is given in
Table 8.
The Stretford solution, after recirculation through the hydrogen
sulfide absorber, is retained in a holding tank for 10 minutes to allow
for completion of the sulfur precipitation. The Stretford solution is then
regenerated by air blowing and the reduced vanadium is restored to the
5-valent state through a mechanism involving oxygen transfer via the ADA.
The sulfur formed in the Stretford process is finely divided
and is floated to the top of the oxidizer by the air. The sulfur forms
a froth containing 6 to 8 percent sulfur at the top of the oxidizer.
This froth overflows to a settling tank where the sludge is accumulated and
fed to a rotary vacuum filter. Underflow from the oxidizer is sent to the
absorber pump tank for recirculation to the H S absorber.
The sulfur cake is fed to an autoclave where heat is applied
to melt the sulfur. The sulfur-water mixture is separated, and marketable
liquid sulfur of greater than 99 percent purity is obtained.
The reactions upon which this process is based are essentially
insensitive to pressure. Operating temperatures throughout the unit are
in the range of ambient to 50 C. The reactions are summarized below:
-------
34
TABLE 8. PARTIAL LIST OF EXISTING STRETFORD PLANTS TREATING
REFINERY GASES FOR SULFUR REMOVAL(a)
Plant Location
Reading, U.K.
Southampton, U.K.
Antwerp, Belgium
Belfast, N. Ireland
Toledo, Ohio
(c)
Long Beach, Calif.
Type Gas
Reformed refinery gas
Reformed refinery gas
Refinery
Refinery /reformed
Refinery
Petroleum gas
Feed,
0.73
0.56
1.26
1.37
1.37
1.54
scmd
x 106
x 106
x 106
x 106
x 106
x 106
H2S Inlet
Loading, ppm
100
100
5,000
16,200
19,500
1,500
(a) Numerous Stretford units have been installed throughout the world for
treating natural gas and a variety of industrial gases. In addition,
several Stretford units have been incorporated into the Cleanair and
Beavon tail-gas-treating processes.
',,;N- 3 u n 0(1 C ompany.
;.?} THUMS project operated by the Lomita Gasoline Company.
-------
35
(1) Absorption ol H S
H2S + Na2C°3 "^ NaHS + NaI1C03 '
(2) Precipitation of sulfur
2NaVO + NaHS + NaHCO -> S \j/+ Na V 0 + Na CO + H, 0 .
(3) Regeneration of sodium vanadatc
Na V 0 + ADA (oxidized) -* 2NaVO + ADA (reduced) .
/ / 3 J
(4) Regeneration of ADA
ADA (reduced) + -^ (air) - ADA (oxidized) .
(5) Overall reaction
H2S + 2°2 ~* ^ H2° *
COS and CS are not recovered by the Stretford process and this
reduces the overall sulfur recovery. Otherwise, the Stretford solution
quantitatively removes HQS. Some adverse side reactions occur, owing to
peaks in loading (increased liquor temperature) and trace oxidizing
gases contained in the fuel gas (notably oxygen, SO , and HCN) , and these
result in the buildup of sodium thiosulfate and related compounds which
must be purged from the system. A typical analysis for the purge stream
is shown in Table 9. The rate of thiosulfate formation depends on the
partial pressure of oxygen in the inlet gas stream and on the pH and
temperature of the liquor. Formation of thiosulfate is quite low, below
about 40 C.
Currently, the Stretford purge stream normally is disposed of
by discarding it to an industrial sewer. A process alternative that is
being developed by Nittetu Chemical Engineering (NICE), Ltd., involves
/ O£ "\
treatment to reclaim the sodium value as Na?CO (see Figure 5) . As
shown in the diagram, waste liquid removed from the desulfurization plant
is first fed to the evaporator operated at 60 C and a vacuum of 100 mm
Hg (abs), where the salts are preconcentrated to about 50 weight percent.
The evaporator heat source is quenched combustion gas obtained directly
from the quenching tank at a temperature of about 90 C.
-------
36
TABLE 9. TYPICAL COMPOSITION (Weight Percent)
OF STRETFORD PURGE SOLUTION(a>
Na2C°3
Na ADS(b)
Na meta vanadate
Na citrate
Na2S203
NaSCN
H.O
0.47
0.07
0.03
0.03
0.60
0.60
98.20
(a) Purge solution approximately 0.0125 to
0.125 1/g-mole of feed gas to the
absorber.
(b) Sodium anthraquinone disulfonate.
-------
37
z
o
o
Ul
t/>
ui
oc
o
o
o
z
z
o
in
z
o
N
(L
Ul
O
ID
ro
o
H
D
o
UJ
o:
D
Q_
LU
O
O
OC
a.
a
cr
o
UJ
o:
O)
u.
o
I-
z
UJ
UJ
a:
i-
m
UJ
cc
D
O
-------
The concentrated waste liquid is then sprayed into the incinerator.
Combustion of an auxiliary gas maintains the incinerator at 850 C in a
reducing atmosphere. The reducing conditions are maintained by limiting
the oxygen feed at 70 to 80 percent of the theoretical amount required for
combustion. At the designated residence time, most of the sodium salts
decompose to Na^CO., and NaHCO.,; they are then blown into the quenching tank
along with the hot combustion gas.
The quenching tank carries out two tasks: quenching of the hot
combustion gas that is blown from the incinerator, and the capture of sodium
salt contained in the gas, mainly Na_CO~. Quench and makeup water for the
reconstituted Na CO- solution is fed through the gas-blowing duct between
the incinerator and the quenching tank. The Na^CO., solution is continuously
removed from the tank and used as absorbent in the H~S absorber.
The combustion gas, with sodium salts removed, is drawn out of
the tank at approximately 90 C. This gas contains about 8 volume percent
(dry basis) of tLS as well as such gases as H?, CO, and CH, and has a
temperature of about 75 C when discharged from the shell side of the evaporator.
It is cooled to about 50 C by a surface condenser and cooler before being
supplied to the H«S absorber.
The absorber is designed to return the absorbed H-S that results
fro'.i incineration under the reducing condition to the oxidizer at the desul-
furization plant. There it is recovered from the filters as elemental
culEur. For this reason, the Na^CO,, solution, recovered from the quenching
tank, and the absorbent from the desulfurization plant are both recovered.
As far as is known, the NICE process has been tried only at the pilot-plant
1evel.
Giammarco-Vetrocoke (BUS) Process. The Giammarco-Vetrocoke H S
i. i
removal process (see Figure D-2) is based on the absorption and reaction
of hydrogen sulfide in alkaline arsenites and arsenates. ' It is
,/ ier, and the precursor of the Stretford process, since it involves coupled
•~edox reactions in solution.
Elemental sulfur is formed from arsenic-activated sodium carbonate
solution. The chemistry of the H9S-removal process is quite complex but
can be represented by the following reactions:
-------
39
Absorption
Digestion
Acidification and Precipitation
Oxidation
4- 1 /? D ->• Nfl AcO fA^
T j./ ^, u_ -^ Ma0AbU. . ^tj
Overall Reaction
H2S + 1/2 02 -»• S + H20. (5)
Sour gas enters the base of the absorber column at pressures up
to 75 atmospheres. The absorption (1) is extremely rapid, with equilibrium
partial pressures over the solution so low that treated gases containing less
than 1 ppm are readily achieved. The absorption step is followed by the
digestion step (2) which stabilizes the sulfur in a form unaffected by CO
and oxygen. One mole of oxidized activator must be in the solution per
mole of absorbed sulfur to permit the digestion step to proceed. The thio-
arsenite (Na3AsS3> formed is slowly converted to mono-thioarsenate (Na3As03S)
and arsenite (Na3As03>, Reaction (2), which occurs in the absorber and in the
subsequent oxidizing column. The mono-thioarsanate formed (Na3As03S) in
Reaction (2) has an even lower vapor pressure of H2S. Mono-thioarsenate
(Na3As03S) , being more soluble, helps keep the sulfur in solution.
The solution leaving the base of the absorber passes to an air-
blown oxidizing column working at atmospheric pressure and around 40 C.
The vessel is open to the atmosphere at the top. Under the oxidizing
conditions, the mono-thioarsenate (Na AsO ) decomposes to arsenite (Na.AsO )
and elemental sulfur by Reaction (3). Elemental sulfur is removed overhead
from the oxidizer by froth flotation, vacuum filtered, and washed. The
oxygen-transfer reaction [Reaction (4)] reestablishes the original Vetrocoke
solution balance by oxidizing some arsenite (Na AsO ) to arsenate (Na AsO ) .
-------
40
The Giammarco-Vetrocoke H«S process has been used in the
European natural gas industry and it could be adopted to refinery gases.
Its main disadvantage is that the arsenate and arsenite solutions must
be handled. Consequently, it is being largely replaced by less toxic
solutions like the Stretford purge solution.
One of the latest in a series of processes based on multiple,
(39)
coupled, redox reactions is the Cataban process. The process is based
on an oxidation-reduction system where a complexed polyvalent ion,
preferably ferric ion, kept in aqueous solution by an organic chelating
agent, oxidizes hydrogen sulfide to sulfur, the ferric iron being reduced
to the ferrous state. Simultaneously, atmospheric or other oxygen
reoxidizes the ferrous iron complex to ferric iron. The redox reactions
involved may be represented by the following.
Oxidation by Hydrogen Sulfide to Elemental Sulfur
(1) 2Fe"H~l" + H2S = 2Fe++ + S + 2H+.
Regeneration of Ferric Ion
(2) 2H+ + 2Fe"H~ + 1/2 02 = 2Fe"H~l" + H20.
Overall Reaction for the Two Steps
(3) H2S + 1/2 02 = S + H20.
-------
41
TAIL-GAS-PROCESSING TECHNOLOGY FOR GLAUS SULFUR PLANTS
Tail-gas-processing concepts that have been tested and are being
operated or installed in conjunction with refinery Glaus plants are listed
in Table 1. These methods, with modification, probably represent today's
most practical technology for large "clean-up" units for treating tail gas.
Flow diagrams for all of these processes are presented in Appendix E. In
this section of the report, the following seven processes are described in
detail:
(1) Beavon
(2) Cleanair
(3) Wellman-Lord
(4) Shell Glaus Off-Gas Treatment (SCOT)
(5) Institut Francais du Petrole Processes
(IFP-1500 and IFP-150)
(6) Chiyoda Thoroughbred 101
(7) Sulfreen.
Tail gas from a two-stage Glaus sulfur-recovery unit can be
expected to contain some 7,000 to 12,000 ppm of sulfur compounds (see Table 7)
These compounds are H9S, SO^, CS9, COS, and S (expressed as So). Tail-gas-
L. £* £- X O
cleaning processes may be classified as continuations of the Glaus reaction
or as add-on processes of a different nature. The Beavon, Cleanair, IFF,
and Sulfreen processes are of the first type and involve continuation of the
Glaus reaction. The Wellman-Lord, SCOT, and Chiyoda processes are examples
of add-on processes that are not based on the Glaus reaction. The Wellman-
Lord S0? recovery process and the Chiyoda process handle tail gas following
its incineration in the sulfur-recovery plant, i.e., the sulfur in the form
of S0_. The Beavon and Cleanair processes are similar in that the tail gas
is handled in such a manner that the residual sulfur values occur as hydrogen
sulfide which is then converted to sulfur in a Stretford unit. The IFP arid
Sulfreen processes use different catalysts to extend the Glaus reaction--
in the first process, in an organic liquid solvent using alkali metal salts
as a catalyst, and in the second process, in the absorbed phase on the
surface of either an alumina or activated carbon catalyst.
-------
42
For each of the tail-gas processes under consideration, this
review provides the following information:
(1) Process description
(2) Commercial status as measured by the number of units
being used at refinery Glaus sulfur plants
(3) Material balances, utility requirements, and waste
streams generated in a tail gas unit applied to a
typical 100-MT-D refinery Glaus plant.
In almost all cases, the tables summarizing the number of commercial units
in operation or under construction represent partial lists. For the most
part, these data were obtained from the process vendors. However, it was
difficult to keep such lists current and omissions are sure to have occurred,
The material balances were generated for the tail gas as it progressed
through the process under consideration by making various assumptions that
were felt to be valid and commensurate with the unit operations involved.
Although the material balance calculations should be fairly representative
of gas compositions expected in the process, they are not rigorous in the
sense that each flow stream (both liquid and gas) is completely defined and
satisfies conservation of mass. Since this was the case, the utilities
requirements were not obtained from material and energy balances as one
would normally do when performing design calculations. Rather, they
vcpresent best guesses obtained from the available information and a
knowledge of the process. This often involved comparing several sources
of data (vendor estimates, open literature, and data obtained from process
usf-rs) and then selecting the one thought to be most reliable.
For the sake of consistency in performing the material balance
.. ^IcuiatLons and for making process comparisons, the following ground rules
were set.
(1) The Glaus plant being treated was 100 MT/D.
(2) The tail gas being treated had the characteristics
given in Table 7.
(3) Incineration and stack gas reheating were performed
using methane.
-------
43
(4) Incineration was done in the existing Glaus-plant
incinerator at a temperature of 650 C.
(5) Stack-gas reheating for processes based on S0«
absorption was done in a direct-fired reheater with
the exit temperature to the stack being 316 C.
Beavon Process
(25)
Process Description. The Beavon process (see Figure E-l)
begins by converting substantially all of the sulfur present in the tail
gas before incineration (i.e., S0?, COS, CS-, and elemental sulfur) back
to hydrogen sulfide. This is done by hydrogenation under very moderate
conditions of temperature and pressure, resembling those in the Glaus plant,
Before the tail gas enters the packed-bed hydrogenation reactor, fuel gas
is combusted substoichiometrically in air and steam (optional) in an inline
burner. The combustion products are mixed with the tail gas to provide a
reducing atmosphere. The burner operates fuel-rich, so it is possible to
make extra hydrogen as required to supplement the hydrogen already in the
tail gas. The hydrogenation reactions are catalyzed by a cobalt molybdate
catalyst in the packed-bed reaction. The presence of this catalyst also
promotes the reaction of water vapor with carbon monoxide to form hydrogen,
or the reaction of water vapor with COS and CS? to form H^S. The reactions
thought to occur in the decomposition are:
f* f\Q _1_ U /^ T^ f^f} i TT r»
VjUO T n_U 4- L.U« T ti^b
CS2 + H20 £ H2S + COS
CS0 + 2H S 2 CH. + 3S
224
COS + 4H0 2 H.O + H.S + CH.
222 4
-------
44
After hydrogenation, the tail gas is cooled and water is removed in a
direct-contact heat exchanger. The condensate is not corrosive, and is
suitable for cooling-tower makeup after H_S has been stripped out. A
typical hydrogenation-reaction product gas contains 20,000 to 40,000 ppm
of HLS. This stream is fed at about 1.068 atm (1 psig) into the Stretford
circuit for removal of hydrogen sulfide. (See description of the Stretford
process presented earlier.) Tail gas from the Stretford unit is discharged
to the atmosphere after incineration in the Glaus plant incinerator.
Commercial Status. The Beavon process was developed jointly by
the Union Oil Company and the Ralph M. Parsons Company. A partial list of
Beavon units that are either operating or under construction is presented
in Table 10. Eight units for which information was readily available are
listed in Table 10. Two other units are believed to have been ordered.
Material Balance and Utilities. The Beavon process appears
capable of treating Glaus-plant tail gas to the 100 to 200-ppm level prior
to incineration. Sulfur removal in the Stretford tower should be virtually
i-ati native for H^S. Only the equilibrium COS and CS~ values present in
•he j.-,jS stream following the catalytic reduction step and trace quantities
of H0S should be present and exhausted to the incinerator. Consequently,
-er^ill sulfur recovery from the Glaus plant the tail gas would exceed 99.8
^ercent, Approximate sulfur-balance calculations are summarized in Table 11
ui- a hypothetical 100-MT/D Glaus sulfur plant equipped with a Beavon unit.
Too compositions of the tail gas as it is processed through the catalytic
^.ctjon, quench tower, Stretford unit, and incinerator are given in
o>rk- ' '! » These figures formed the basis for the sulfur balance summarized
• n Tablo 11. Approximate utilities requirements for the process are given
,. (24,40)
13. ' '
Waste Streams. Two waste streams are generated by the Beavon
.•racist,. Neither is considered to be a significant secondary source of
< . .'iT'jri (see Table 11 and Figure C-l). These are the sour -water
..,J!>lcru-.ate obtained by cooling the tail gas in the direct-contact heat
-------
45
TABLE 10. PARTIAL LISTING OF ANNOUNCED BEAVON-STRETFORD
TAIL GAS TREATING UNITS FOR REFINERY GLAUS PLANTS
Company /Location
Union Oil Company/
Wilmington, Crlifornia
Mobil Oil Company/
Torrance, California
Atlantic -Richfield/
Philadelphia, Pennsylvania
Getty Oil Company/
Delaware City, Delaware
Kobe Steel Co. /Japan
On-Stream
Date
July, 1973
July, 1973
September, 1973
November, 1973
October, 1973
No. of Units
2
2
1
1
1
Number/Capacity of
Glaus Plants, MT/D
2/100
3/100
1/140
1/300
1/220
Texaco, Inc./
Long Beach, California
Unknown/
Carribbean
Union Oil Co./
Rodeo, California
March, 1974
April, 1974
November, 1974
-------
46
TABLE 11. APPROXIMATE SULFUR BALANCE AND WASTE
STREAMS FOR BEAVON TAIL-GAS PROCESS
I. Basis
A. 100 MT/D Glaus plant
B. 94 percent sulfur removal in Glaus plant
C. Assumed reduction of 85 percent, each of COS and CS~
to H2S and treating to less than 10 ppm H«S leaving
Stretford tower. No affinity of COS and CS2 for
Stretford solution.
II. Sulfur Balance
A. Glaus Plant
Input - 104.471 MT/D
Recovered - 98.203 MT/D
Tail gas - 6.268 MT/D
B. Beavon Process
Input - 6.268 MT/D
Recovered - 6.198 MT/D
Purge - 0.005 MT/D
Off-gas - 0.065 MT/D
TIT. Waste Streams
A. Sour-Water Condensate
1. pH - slightly acidic
2. I-LS and C02 dissolved to about 50 ppm each
3. Flow rate - about 0.72 I/sec for a Beavon tail-gas
unit applied to a 100-MT/day Glaus unit
4. Treatment - neutralized in wastewater-treatment system
R. Stretford Purge Solution
1. Composition - see Table 9 for approximate composition
2. Flow rate - approximately 0.0125 to 0.125 I/gram-mole
of feed to the Stretford Tower, i.e., about 0.0126 to
0.126 I/sec for a unit serving a 100-MT/day Glaus plant
3. Treatment - sent to refinery waste-treatment system or
an industrial sewer
-------
47
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TABLE 13. ESTIMATE OF UTILITIES REQUIRED FOR BEAVON TAIL-GAS
PROCESS FOR 100-MT/D CLAUS SULFUR PLANT
Item __ Value
(a\
Steam (3.40 atm, sat), kg/hr 1453V '
Cooling Water, I/sec 22.7
Electricity, kwr/hr 250
Fuel Gas, scmh 224^'
Boiler feed water, I/sec 0.25
Chemicals
Stretford Solution, I/sec 0.0131 - 0.131
Catalyst
Operating Labor, men/shift 1/3 - 1/2
Maintenance, "7- of FCI 5
(a) Steam produced in the process.
(b) Fuel gas rated at 9000 kg-cal/cu m.
Approximately 13 percent of the fuel gas is consumed
in heating the tail gas prior to the reduction reactors,
and 87 percent is used in incinerating the off-gas prior
to sending it to the atmosphere.
-------
49
exchanger prior to entry to the Stretford tower and the purge stream from
the oxidizing unit following the Stretford tower. The size and character
of these waste streams are described in Table 11. The condensate removed
would be slightly acidic due to H2S and CCL absorption (perhaps 50 ppm each)
and would be treated by neutralizing in the refinery waste-treatment system.
The Stretford purge stream (see Table 9) would be sent to either the refinery
waste-treatment system or to an industrial sewer.
Cleanair Process
Process Description. The Cleanair process includes the
Stretford process and two new processes developed by the J. F. Pritchard
Company and the Texas Gulf Sulfur Company. Similar to the Beavon process,
one of the features of the Cleanair process is the removal of organic sulfur
compounds (COS and CS,,).
*-
Although little good technical information is available in the
open literature and the J. F. Pritchard Company appears to be extremely
secretive about process details, an attempt was made to draw a schematic
flow diagram for the process (see Figure E-2). The Glaus tail gas is fed
to a fixed-bed reactor which contains both a reduction catalyst (thought to
be Co/Mo) and a hydrolysis catalyst (unknown). In this reactor, termed
Stage III by Pritchard, hydrolysis reduction of COS and CS? to H S takes
place. The reactions thought to be occurring are:
CS + H?0 ^3 COS + H2S
COS + H20 ^ H2S + C02 .
The Stage III fixed-bed catalyst can be incorporated directly into the
Glaus plant, usually in the first-stage reactor, while it operates on
tail gas in existing units as shown in Figure E-2.
Carbon dioxide also is decomposed to CO in the fixed-bed reactor
to prevent the reoccurrence of COS. The treated tail gas is cooled in a
quench tower prior to the Stage I reactor. Since the Glaus reaction is
thermodynamically favored at low temperature, some additional vapor-phase
sulfur is formed during this process. The cooled gas is fed into a packed
-------
50
reactor (Stage I) where S0? as well as some 1LS are absorbed and converted
to elemental sulfur via continuation of the Glaus reaction:
cat.
Although details regarding the chemical nature of the solution being used
in Stage I are proprietary, it is thought to be an aqueous medium having a
catalyst and an oxygen carrier to promote the Glaus reaction. The bottoms
from the Stage I absorber-reactor are sent to a clarifier where sulfur is
separated from the reaction solution as the underflow. A further separation
takes place in an autoclave separator from which liquid sulfur is withdrawn
as product. The aqueous phase from the autoclave separator is then recycled
to the clarifier. A slip stream from the clarifier is sent to a depurator
and oxygenated and sent back to the Stage I reactor. A purge stream is
removed from the depurator and used as process water.
After Stage I, the tail gas is sent to a Stretford unit where
tLS is removed. The purified gas is then sent to a typical Glaus incinerator
where fuel and air are added to oxidize any residual sulfur to S0_ and CO to
C0? before it is discharged through the stack.
The Cleanair process should be capable of reducing to extremely low
values the amount of sulfur being discharged in the tail gas. Values as low
as 1 ppm should be possible, depending upon the efficiency of the hydrolysis
reduction steps. Any COS and CS_ not hydrolyzed would, of course, not be
removed in either Stages I or III.
Commercial Status. The Cleanair process is licensed by the
J. F. Pritchard Company. A partial list of five Cleanair units is shown in
Table 14. The first commercial unit which treated Glaus-plant tail gas was
che unit built for Gulf Oil Company's Philadelphia, Pennsylvania refinery.
It follows a 46-MT/D Glaus plant. Because of recurrent operating problems,
the Cieanair process at Gulf in Philadelphia, as well as the two other units
in Los Angeles County, remain in start-up status. Two other units following
'Jlaus plants are under construction for Techmashimport in the U.S.S.R.
-------
51
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Material Balance and Utilities. Currently there exists a lack
of information about the Cleanair process in the open literature. Also,
the J. F. Prichard Company considers all information pertaining to the
process as proprietary. Consequently, no meaningful material balances or
estimates of utility requirements were possible.
Waste Streams. The only waste streams from the process would be
the purge stream from the Stretford unit in Stage II, and the sour water
purged from the depurator in Stage I. No quantitative information can be
presented because of a lack of material-balance data.
WeLIman-Lord Tail-Gas Process
(41-431)
Process Description. The Wellman-Lord process uses a wet
regenerative system to reduce sulfur concentration in stack gas to about
200 ppm (see Figure E-3). The sulfur constituents in the Glaus-plant tail
gas are oxidized to SCL in the incinerator, passed through a waste heat
boiler, and then quenched to reduce the gas temperature to about 38 C and
- .'"lovr excess water. The SO -rich flue gas is then contacted countercurrently
w:ih ,1 sodium sulfite (Na SO.,) and sodium bisulfite (NaHSO ) solution which
adsorbs S07 to form additional bisulfite. The absorber can be either a packed
• r tray column. Regenerated sulfite solution «;nters the top of the column
•>n3 .
The S0_-rich solution is boiled by indirect heating in an
- jp.jrator-crystallizer using an external circulation loop. The conditions
are approximately 110 C and 1.0 atm. About 9-LO kilograms of steam are used
'< t v.iporate each kilogram of S0?. The choice of single-effect or double-
OCL evaporation generally depends on the steam costs. The bisulfite
ntion decomposes to SO and HO gas and sod
f'•;•,• crystallizer according to the reaction:
decomposes to S0_ and H_O gas and sodium sulfite precipitates out
-------
53
2NaHS03 Na SO + SO,, + H20 .
The sulfite crystals are removed from the evaporator circuit and redissolved
for reuse as lean solution to the absorber.
The wet SO gas flows to a partial condenser where the water is c01
dcnsed and reused to dissolve the sulfite crystals. The enriched S0r-HO
vapor stream (85 percent/15 percent) is then recycled back to the Glaus
plant for conversion to elemental sulfur.
Apart from the two major reactions above, sodium sullate
(Na9SO^), which is nonregenerable in the normai process, is formed in tin-
absorber as a result of solution contact with oxygen or sulfur trioxide
as follows:
Na2S°3 + i/2 °2 ~* Na?S°4
2Na SO + SO + HO - Na SO. + 2NaHS00 .
^- J 3 i 2. 4 J
The sodium sulfate so formed is controlled at a level of approximately 5
percent by weight in the absorber feed stream by maintaining a continuous
pur>it. from the system. This purge stream will be discussed later.
An additional source of sodium sulfate and thiosulfate is the
auto-oxidation or so-called disproportionation reaction which takes place
in the regeneration section:
6NaHSO. - 2Na.SO. + Na.S 0 + 2S00 + 3H_0 .
3 24 22J 2 2
A small amount of sodium pyrosulfite is also formed owing to the
Hfcr.inposition of sodium bisulfite:
2NaHS03 lost because of the purge stream (see Table 15). A process modification
incorporates a centrifuge into the purge line to further concentrate purge
?.•-,!''as in the slurry. With this modification, sodium losses can be reduced
co 8 to 10 percent. In addition, any excess water removed by cooling the
gas in the quench tower would be slightly acidic due to absorption oi SO
-•nid C0_. This dilute acid would be purged and neutralized.
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54
TABLE 15. APPROXIMATE COMPOSITION OF WELLMAN-LORD
SO PURGE STREAM (a)
Component Weight Percent (")
Total Dissolved Salts 26
Na.SO. 5
2 4
NallS03 7
Na^SO 14
Na,S 0 (c)
Na2S905 (c)
Water 74
(a) No centrifuge in the system arid water added to
dissolve all solids.
(b) Data taken from letter to J. M. Genco, from
C. B. Earl, Davy Powergas, Inc., Lakeland,
Florida (December 13, 1973).
(c) Amount in solution is unknown but is thought to be
about 1 percent by weight.
-------
55
A makeup of caustic is required to replace that lost in the
purge stream. The caustic makeup solution reacts with the sodium bisulfite
in the absorber solution to form additional sodium sulfite:
NaOH + NaHS03—» Na9S°3 + H9° '
Soda ash (Na CO,,) can also be used as the makeup source of sodium.
Commercial Status. The Wellman-Lord process is licensed by
The Davy Powergas Company of Lakeland, Florida. Data on eight units known
(44)
to be in use in the United States and Japan for treating Glaus tail gas
arc summarized in Table 16. The Claus plants range in size from 80 to 290
MT/dny. Since the process treats SCL gas, it also has found application in
treating boiler flue gas and tail gas from sulfuric acid plants. In all,
there are about 20 Wellman-Lord units either under construction or in operation.
Material Balance and Utilities. Approximate sulfur-balance calcu-
lations are given in Tables 17 and 18. The basic assumptions used in
performing the material-balance calculations are:
(1) Virtually complete conversion of sulfur compounds to
SCL in the incinerator
(2) Removal of SO in the absorber to a level of about
250 ppm
(3) The off-gas from the SO absorber is reheated to 316 C
using 9000 kg-cal/cu m fuel gas
(4 ^ Approximately 5 percent of the sulfur removed from
the tail gas in the absorber is converted to nonregenerable
forms of sulfur and must be purged from the system.
•i estimate of the utilities requirements for a Wellman-Lord unit capable
of handling the tail gas from a 100 MT/D Claus sulfur plant is shown in
'i:!i>!i' 19. These data, except for the caustic make-up requirements, were
.ciktr. Lroni information supplied by the Davy Powergas Company. The
i'lstic requirements were estimated from the material-balance calculations.
-------
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TABLE 17. APPROXIMATE SULFUR BALANCE AND WASTE STREAMS
FOR WELLMAN-LORD TAIL-GAS PROCESS
Basis
A. 100 MT/D Glaus Plant
B. 94 percent sulfur removal in Glaus plant
C. Tail gas treated to 250 ppm S0~ in Wellman-Lord off gas
II. Sulfur Balance
A. Glaus Plant
Input - 104.471 MT/D
Recovered - 98.203 MT/D
Off-gas - 6.268 MT/D
B. Wellman-Lord Process
Input - 6.268 MT/D
Recovered - 4.853 MT/D
Off-gas - 0.134 MT/D
Purge - 1.281 MT/D
ill. Waste Streams
A. Sodium Sulfate/Sulfite Purge - Evaporator Unit
1. Purge stream rate - 0.221 I/sec
2. Purge composition
Component Percent by Weight
Na2SO 5
NaHSO 7
j. Treatment - discharged to industrial sewer system.
Davy Powergas is developing a proprietary process for
treating this stream. Also, the NICE process developed
for treating similar sodium waste streams should be
applicable here.
3. Acid-Water Condensate
!. Purge Stream rate - 0.322 I/sec
2. pH 2
3. Treatment - neutralized in the refinery wastewater
treatment system
-------
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59
TABLE 19. ESTIMATE OF UTILITIES REQUIRED FOR WELLMAN-LORD
TAIL-GAS PROCESS FOR 100-MT/D SULFUR PLANT(a)
Item Value
Steam (30.6 atm, sat.), kg/hr (3,028)^
Cooling Water*-0-*, I/sec 39.4
Electricity, kWr/hr 93
Fuel Gas(d^, scmh
Boiler Feed Water, I/sec 0.82
Chemicals
(100% NaOH), MT/I) 3.73
Operating Data
Labor, men/shift 1/3-1/2
Maintenance, % FCI 5
(a: Letter to J. M. Genco from C. B. Earl,
Davy Powergas, Inc. (December 13, 1973).
(b) Steam produced in process.
(c) Temperature rise of 17 C.
(d) Heating value taken to be 9000 kg-cal/cu m.
(c) Reheating done to 316 C with direct fired reheater.
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60
Waste Streams. Two waste streams are generated in the
Wellman-Lord tail-gas-cleaning process (see Table 17 and Figure E-3).
These are acid-water condensate and a purge stream. The acid water is
obtained by cooling and partially condensing water from the tail gas in the
direct-contact heat exchanger prior to the SO absorption tower. In the
Wellman-Lord design, this waste stream amounts to about 0.32 I/sec for a
(44)
100-MT/D Glaus plant and has a pH of approximately 2. It is treated in
the refinery wastewater-treatment system by neutralization with base.
The sodium sulfate/thiosulfate purge stream normally is removed as
a slurry from the steam-stripping loop in the evaporator section of the
process. It is dissolved in water to the approximate composition shown in
Table 17 and sent to either an industrial sewer or the refinery wastewater-
treatment plant if the latter is equipped to handle it. The purge following
dissolution amounts to about 0.221 I/sec. Currently, the Davy Powergas
Company is developing proprietary technology for treating this stream.
Also, the NICE process which treats similar waste streams to recover their
sodium value as Na CO,, would also appear to be applicable to the Wellman-Lord
purge (see Figure 5).
Shell's Glaus-Plant Off-Gas Treatment (SCOT) Process
Process Description. The SCOT Process ' ' consists of a
reduction section and an alkanolamine absorption section (see Figure E-4).
The sulfur compounds together with free sulfur in the Glaus tail gas are
reduced to H S with hydrogen, or hydrogen together with carbon monoxide,
ovtr a cobalt/molybdenum catalyst (Shell catalyst S-534) at a temperature of
,--b
-------
61
column. The fat (DIPA) solution is regenerated by stripping tUS in a
conventional steam stripper. The regenerator off -gas, mainly H S and some
CO , is recycled as feed to the first stage of the Glaus unit. The absorber
off-gas, which now contains about 300 ppmv H S, is incinerated in a standard
Glaus incinerator.
In the SCOT process, as in the Beavon process, COS, CS , and
elemental sulfur can be removed effectively by reducing them to H_S. S0»
and elemental sulfur are reduced by H as follows: l
S_ + 8H0 - 8H S .
o z /
With an excess of H , virtually complete conversion of elemental sulfur
and H S is obtained (i.e., residual SO contents below 10 ppmv).
When carbon monoxide is also present as a reducing agent, the
following additional reactions may occur:
S02 + 3CO - COS + 2CO
S0 + SCO -* 8COS
o
COS + HO ?- CO + H S
CO + H20 ** C02 + H2
CO + H S ** COS + H .
Under normal conditions, the concentration of carbonyl sulfide (COS)
approaches thermodynamic equilibrium (i.e., about 10 ppmv COS)
In addition to COS, carbon disulfide (CS?) may also be present
in Glaus tail gases. CS_ is converted over the Co/Mo catalyst to its
equilibrium value (i.e., about 1 ppmv CS?) as follows:
-------
62
The Co/Mo catalyst has undergone a 4000-hour life test with hydrogen or a
mixture of hydrogen/carbon monoxide as reducing agent. The results show
that the reduction catalyst has a completely stable activity with residual
SCL contents consistently below 10 ppmv.
Shell developed the SCOT process primarily for application to
refinery Glaus tail-gas treatment. Except for the Co/Mo reduction reactor
and in-line burner, no additional equipment is required. If sufficient
capacity exists, the overhead gas from the cooling (quench) tower can be
recycled to the existing amine-treatment unit in the refinery. Thus, the
process cycle can be completed without generating new waste-disposal problems.
There would, of course, be normal degenerated amine solution to be disposed of.
However, the SCOT process has still to be demonstrated on a commercial scale
for a longer period before its feasibility can be fully evaluated.
Commercial Status. The SCOT process is being licensed by the
Shell Development Company, Houston, Texas. Announced SCOT units in the
(47)
United States and Canada are listed in Table; 20. Currently, the process
is being applied to two rather small Glaus planl:s--Champlin Petroleum Company
in Wilmington, California (15 MT/D), and the Douglas Oil Company in Paramount,
JalLf^rnia (9 MT/D). Six other SCOT units have been ordered and are in
jaiicus phases of construction. The largest unit has been ordered by Shell
Canada for treating Glaus tail gas at the Watertown Natural Gas Treating
Plant, Alberta, Canada. The capacity of the Glaus plant in this case is
z,100 MT/D.
Material Balance and Utilities. Approximate sulfur-balance
Calculations are summarized in Table 21. These estimates are based on the
(21)
material balances presented in Table 22. The basic assumptions in making
the material-balance calculations are:
(1) Removal of H?S in the absorption tower to a level of
about 300 ppm
(2) The COS and CS levels following reduction of sulfur
compounds to H^S in the Co/Mo reduction reactor are
10 ppm and 1 ppm, respectively.
-------
63
TABLE 20. PARTIAL LISTING OF ANNOUNCED SCOT UNITS IN THE
U. S. AND CANADA
(Total Glaus Capacity = 2,900 MT/D)"
Company/Loc a t ion
On-Stream Data
Number/Capacity of
Glaus Plants, MT/D
Champ1in Petroleum
Company/Wilmington,
California
Douglas Oil Company/
Paramount, California
June, 1973
June, 1973
Shell Canada, Waterton December, 1974
Gas Treating Plant/
Alberta, Canada
British Petroleum
Standard Oil of Ohio/
Marcus Hook,
Pennsylvania
U. S. Steel/
Clairton,
Pennsylvania
Sun Oil Co./Duncan
Oklahoma
Marathon Oil Co./
Detroit, Michigan
Murphy Oil Co./
Meraux, Louisiana
Shell Oil/Houston,
Texas
October, 1974
Late 1974
Late 1974
Late 1974
Late 1974
1/15
1/9
1/2100
1/160
* Glaus plant units range in capacity from 9 MT/D to 2,100 MT/D.
-------
64
TABLE 21. APPROXIMATE SULFUR BALANCE AND ESTIMATE OF
WASTE STREAMS FOR SCOT TAIL-GAS PROCESS
I. Basis
A. 100-MT/D Glaus plant
B. 94 percent sulfur removal in Glaus plant
C. Tail gas treated to 300 ppm H2S, 10 ppm CS9, and
1 ppm COS in SCOT off-gas (prior to incineration)
II. Sulfur Balance
A. Glaus plant
Input - 104.471 MT/D
Recovered - 98.203 MT/D
Off-gas - 6.268 MT/D
B. SCOT process
Input - 6.268 MT/D
Recovered - 6.188 MT/D
Off-gas - 0.080 MT/D
III. Waste Streams
A. Sour-Water Condensate
1. pH - slightly acidic
2. HoS and C02 dissolved to about 50 ppm each
Purge rate - 0.442 to 0.631 I/sec
Treatment - send to sour-water stripper
Amine sludge - negligible
Spent reduction catalyst
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65
TABLE 22. TYPICAL COMPOSITION OF GAS STREAMS ENTERING
AND LEAVING HYPOTHETICAL 100-MT/D REFINERY
GLAUS PLANT PLUS SCOT TAIL-GAS PROCESS(a)
(Basis: sulfur recovery in Glaus unit of
94 percent)
Item
Glaus
Intake
Glaus
Exhaust^
Scot
1 Off-Gas
Incinerated
Scot
Off-Gas
(b)
Composition
H2
SO
S
S
2
vapor and mist
89.9
-
-
COS
cs
CO
CO
HC
H2
H2
N2
°2
2
2
(MV: 30)
0
Total
Temperature, C
Pressure, atm
-
-
4.6
0.5
-
5.0
-
—
100.0
40
1.45
0
0
0
0
0
0
2
-
1
33
61
—
100
140
1
.85
.42
.05
.05
.04
.22
.37
.60
.10
.30
.00
.26
0
-
-
10
1
-
3
-
0
7
88
-
100
40
1
.03
ppmv
ppmv
.05
.96
.00
.96
.00
<10
0
-
-
-
-
4
-
-
9
83
1
100
650
1
ppm
.02
.42
.84
.94
.78
.00
Gas Quantity
(Relative
Amount), moles
(c)
Flow ' scmm
3.0
56.78 170.35
2.2
124.91
3.5
198.74
(a) Prior to incinerator.
(b) Percent by volume unless otherwise noted.
(c) Flow given in standard cubic meters per minute.
-------
66
Overall sulfur recovery in a two-stage Glaus plant with the SCOT process
should be in excess of 99.8 percent.
Table 23 presents an estimate of the utilities required for the
SCOT process applied to a 100-MT/D Glaus plant. These data were taken from
Wall and are essentially the same as those supplied by Shell Development
(47)
Company. The reducing-gas requirements are reported as equivalent to
pure H? although, as mentioned, CO/H mixtures can be used.
Waste Streams. No major waste streams are produced in the SCOT
process (see Table 21). The most significant stream is the sour-water
condcnsate obtained by cooling the tail gas in the direct contact heat
exchanger prior to entry into the amine absorption column. This stream
would amount to 0.44 to 0.63 I/sec and would be slightly acidic. It would
be treated in a sour-water stripper for H_S removal and then sent to the
waslewater treatment system. The only other waste streams resulting from
the process are degenerated amine solution from the amine regenerator and
spent reduction catalysts. Both materials are encountered in normal refinery
practice and should not constitute secondary sources of pollution.
Institute Francais du Petrole Processes (IFF)
Process Description. IFF has developed two Glaus tail-gas-
treatment processes, namely TGT-1500 (see Figure E-5) and TGT-150 (see
(49 50)
Figure E-6). ' The former process is capable of reducing the sulfur
contru* in Glaus tail gas down to about 3000 to 4000 ppm prior to incineration,
•.n;j( vith the latter process, a reduction to 150 to 300 ppm is possible.
Hie ha.Ur reaction involved in the TGT-1500 process is the same one that
takes place in the reactors of a Glaus unit:
Cat
2H S + S02 «—» 3S + 2H20 .
let! I gas which exits a Glaus unit at a temperature of about 265 to 285 F can
u.<> fed Jirectly into the IFF reactor without cooling the gas. The reactor-
is essentially a packed column with a specially designed boot for collecting
liquid sulfur. Mixed alkali metal salts of an organic acid contained
-------
67
TABLE 23. ESTIMATE OF UTILITIES REQUIREMENTS FOR SHELL
GLAUS OFF-GAS TREATING UNIT (SCOT) APPLIED
TO A 100-MT/D REFINERY GLAUS SULFUR PLANT(a)
Item Value
Steam (3.40 atm, sat.), kg/hr 1,162^ '
Cooling Water (6.7 C rise), I/sec 82
Electricity, kWr/hr 140
Fuel Gas**0', scmm 1,224
Boiler Feed Water, I/sec 0.28
Chemicals^ '
Reducing gas equivalent 9.5
pure H2, kg/hr
Operating Data
Labor, men/shift 1/6-1/4
Maintenance, % FCI 2
(a) Taken from J. Wall Hydrocarbon Processing, 52(4),
114 (April, 1973).
(b) Net steam consumed in the process. Steam is
produced following the reducing reactor (2,588
kg/hr) and consumed in the amine regenerator
(3,750 kg/hr).
(c) Heating value of 9000 kg-cal/cu m.
(d) In addition, amine solution is used in the
tail-gas scrubbing tower and reducing catalyst is
used in the COS and CS0 reduction reactor.
-------
68
in a high-boiling polyglycol solvent serve to catalyze the reaction above
the melting point of sulfur--generally in the range 120 to 130 C. The metal
salts form a complex with FLS and SCL in the feed gas, which in turn reacts
with more of the two sulfur compounds to form elemental sulfur and
(52)
regenerate the catalyst complex. The sulfur coalesces and settles
into the boot of the reactor, from which it is drawn as a molten product.
In the reactor, the water of reaction is vaporized and carried out with the
cleaned tail gas. To maintain the heat balance in the reactor, condensate
is injected and vaporized together with the water of reaction. The solvent
is generally a polyalkylene glcol, although alcohols, glycols, glycol ethers,
or glycol polyethers may also be used.
One of the attractive features of the TGT-1500 process is that
there is only one piece of rotating machinery in the unit--a centrifugal
pump used to circulate the reaction solution. The only other equipment is
a heat exchanger used in start-up, storage, and mixing and injection equipment
used for catalyst and solvent makeup. The COS and CS in the Glaus tail
gas are not converted in the IFF reactor, and will pass through untransformed
to the incinerator. Recent Glaus unit catalyst developments have made it
possible to reduce the COS and CS,-, levels to 75-90 percent of their former
vd; ies. tlowever, this still remains a problem and the high sulfur content
in i:ho off-gas represents the major disadvantage of the IFP-1500 process.
To achieve better sulfur removal and treat COS and CS,-, , IFF has
developed the TGT-150 process. In this process, Glaus tail gas is
incinerated to convert COS, CS,-,, H«S, and elemental sulfur to SO,.,. The hot
fjii<- gas then js cooled prior to an ammonium sulf ite/bisu If ite scrubber.
I- ,.he. cooling process, steam can be generated.
The flue gas containing sulfur oxides is introduced into a
diiect-contact cooling section of the absorber, where it is cooled further
to i+0 to 50 C by a downflowing stream of water. This sensible-heat-removal
'1-itv ; s small in relation to the heat of condensation of the water vapor
in '^e saturated flue gas entering the absorber.
The flue gas leaving the direct contact cooling section of the
I'>S:M ;jti then enters a three-stage ammonia absorption section. Absorbent
solution is essentially a mixture of aqueous ammonium sulfite and aqueous
-------
69
ammonium bisulfite having a pH between 5 and 7. The use of ammonium
sulfite instead of ammonia as the absorbent minimizes the loss of ammonia
to the atmosphere. The absorbent solution flows down through the tower
countercurrent to the flue gas flow and the entire effluent is withdrawn
from the bottom stage. The chemistry of ammonium sulf ite/bisulf ite
absorption is identical to that presented for the sodium based system used
in the Wellman-Lord system except for the ammonium cation (NHX ) :
In the absorber ammonium sulfate is also found owing to reaction with
oxygen
An additional source of ammonium sulfate and thiosulfate is the dis-
proportionation reaction:
6(NH4)HS03 - 2(NH4)2S04 + (NH^S^ + 2S02 + 3^0 .
; vice the flue gas exiting the absorber is about 40 to 50 C, it must be
reheared prior to sending it to the stack. This usually is done by using
a gas-fired reheater. Reheat usually is provided to give the plume
ii'ioyancy and protect the stack from corrosion due to condensation of
riiisture and acid gases.
The sulfitic brine leaving the absorber is heated and decomposed
V, a two-scage process into SCL , NH~, and H-0. Although proprietary, the
• : ":, c -stage decomposer of the sulfitic brine is thought to be a sub-
, erged tube forced-circulation evaporator operated at a temperature of
.-.':. xi t 150 C and at low pressure. This type of apparatus usually consists
:^' ! heat exchanger fed by the circulation pump and a flash drum.
The concentrated solution from the flash drum is fed to the second
•-lagi, where the remaining ammonium sulfite and all of the ammonium sulfate
.-" ' ti; I osul fate are decomposed. The liquid mixture is pumped through the
i"''i-nace where the necessary heat is provided. Although there is some sulfur
-------
70
production during the decomposition of ammonium thiosulfate, the operating
temperature of the decomposer would be chosen to prevent sulfur accumulation.
Stoichiometrically, the thermal decomposition proceeds as follows:
NH.HSCL - NH_ + H.O + S00
43 32 2
Reduction of the sulfates is by reaction with recycle hydrogen sulfide
The overhead gases from both the evaporator and the sulfate
reduction furnace are then sent to an IFF catalytic reactor. This reactor
is identical to that described previously for the TGT-1500 process.
Operating temperatures are in the range from 120 to 130 C. An HLS slip
stream from the Glaus plant feed is also fed to the bottom of the catalytic
reactor along with the SO stream to maintain the SO /H S at the optimum
ratio required for efficient sulfur recovery in the reactor. Sulfur from
thfi reactor is sent to a sulfur pit by a sulfur pump. Condensates and
PEG solvent are mixed with the sulfur and must be recycled.
The vapor effluent off the IFF catalytic reactor consists
principally of NH and HO with traces of the PEG solution. Before it
returns to the scrubbing section, this vapor is first cooled to the dew
point temperature (about 100 C) . The condensate and the ammonia solution
a •?: collected in a decanter. Ammonia solution, with makeup ammonia as
NH,OH, is then recycled to the absorber.
Ammonia volatility at high scrubbing-solution pH values will
prcbably limit the SO concentration in the process gas going to the re-
hf^ter to a minimum level of 150 ppm. However, since a liquid-phase
reaction is occurring, although uneconomic, theoretically the exit SO.
concer.tration can be made to reach very low values. At 150 ppm S0? , it
is estimated that gaseous ammonia losses will be approximately 5 percent.
-------
71
of the total ammonia fed to the top of the absorber. Some ammonia will
also be destroyed during decomposition of the ammonium sulfate. This loss
is expected to be less than 5 percent of the ammonia processed through the
decomposer.
Commercial Status. The TGT-150 processes are licensed by the
Institute Francais du Petrole. The TGT-1500 process is widely used and
about 17 units have been built. Table 24 presents a partial list of TGT-1500
(53)
units. Three plants are currently in operation in the United States
on Glaus plant tail gas. No information was obtained on available TGT-150
units, although three units are reported to be ready for start-up in Japan.
Material Balance and Utilities. Sulfur-balance calculations for
the TGT-1500 process are summarized in Tables 25 and 26. These calculations
(53)
are based on information provided by IFF. The basic assumptions used
in making these estimates are:
(1) Removal of SCL and H^S in the IFF reactor amounts
to 90 percent of the input feed
(2) COS, CS», and sulfur vapor are not removed in the
reactor.
For the design shown, the overall removal efficiency of the combined Glaus-
plant and TGT-1500 process would be only 98.5 percent. As mentioned
previously, low sulfur recovery remains the major problem with the process.
An estimate of the utilities requirements for the TGT-1500 process
(53)
is shown in Table 27. Since the process involves few unit operations,
the utility requirements are quite low. Unit values for the solvent and
• :-ti-a!y~.i: were not provided by IFF since they were proprietary. However,
monetary values were provided by IFF and are reported in Table 27 in case
operating costs need to be estimated.
Since the TGT-150 was not considered to be a commercial process in
the soiise that several units were operating, material balances and utility
requirements were not estimated.
-------
72
i
TABLE 24. LISTING OF ANNOUNCED TGT-1500 CLAUS-SULFUR-
PLANT TAIL-GAS-PROCESSING UNITS
Company /Location
Nippon Petroleum
Refining Company
(Caltex)/Negishi,
Japan
Idemltsu Oil/
Himeji, Japan
Showa Oil (Shell)/
Kawasaki, Japan
Kyokuto Petroleum
On-Stream
Date
1971
1972
1972
1972
No. of Units/
Capacity,
scram
1/493
1/468
1/99
1/336
Number/Capacity
of
Claus Plants, MT/D
1/300
1/250
1/80
1/200
Industries (Mobil)/
Chiba, Japan
Chevron Standard Ltd. 1972
(Chevron Research)/
Nevis, Alta., Canada
Mitsubishi Oil Co. 1972
(Getty)/Mizushima,
Japan
Mitsubishi Oil Co. 1972
(Getty)/ Mizushima,
Japan
Phillips Petroleum/
3orger , Texas
fiioistry of Gas/
Orembourg I, USSR
Mir^stcy of Gas/
Orecnbourg II, USSR
Ministry of Gas/
Orembourg III, USSR
Stri'i;;r.ir Chemical Co./
TV i^are City, Del.,
Uj:.
Commonwealth Oil 1973
At: Dining/ Ponce,
Puerto Rico, USA
K--I 0"t No. I/ 1973
"Irrilu, Japan
Phillips/ 1973
">«/• .-:-> , Texas, USA
Koa Oil No. 21 1974
Xarify, Japan
oiumnounced/ 1975
1/448
1/392
1/510
1/105
1/84
1/260
1/180
1/350
1973
1974
1974
1974
1973
1/84
1/1344
1/1344
1/1344
Confidential
1/45
1/800
1/800
1/800
Confidential
1/60
1/45
1/400
-------
TABLE 24. LISTING OF ANNOUNCED 'IGT-liUU CLAUb-bULtUK-
PLANT TAIL-GAS-PROCESSING UNITS
Company /Location
Nippon Petroleum
Refining Company
(Caltex)/Negishi,
Japan
Iclemitsu Oil/
liimeji, Japan
Sliowa Oil (Shell)/
Kawasaki, Japan
Kyokuto Petroleum
On-S tream
Date
1971
1972
1972
1972
No. of Units/
Capacity ,
scmm
1/493
1/468
1/99
1/336
Number/Capacity of
Glaus Plants, MT/D
1/300
1/250
1/80
1/200
Industries (Mobil)/
Chiba, Japan
Chevron Standard Ltd. 1972
(Chevron Research)/
Nevis, Alta., Canada
Mitsubishi Oil Co. 1972
(Getty)/Mizushima,
Japan
Mitsubishi Oil Co. 1972
(Getty)/ Mizushima,
Japan
PhiLlips Petroleum/ 1973
Borger, Texas
Ministry of Gas/ 1974
Orembourg I, USSR
Ministry of Gas/ 1974
Orembourg II, USSR
Ministry of Gas/ 1974
Orembourg III, USSR
Stauffer Chemical Co=/ 1973
Delaware City, Del.,
USA
Commonwealth Oil 1973
Refining/Ponce,
Puerto Rico, USA
Koa Oil No. I/ 1973
Marifu, Japan
Phillips/ 1973
Sweeny, Texas, USA
Koa Oil No. 2/ 1974
Marify, Japan
1/448
1/392
1/510
1/84
1/1344
1/1344
1/1344
Confidential
1/105
1/260
1/180
1/350
1/45
1/800
1/800
1/800
Confidentia1
1/60
1/84
1/45
Unannounced/
1975
1/400
-------
73
TABLE 25. APPROXIMATE SULFUR BALANCE AND ESTIMATE OF
WASTE STREAMS FOR TGT-1500 TAIL-GAS PROCESS
I. Basis
A. 100-MT/D Glaus plant
B. 94 percent sulfur removal in Glaus plant
C. 90 percent conversion of H S and SO to S in tail gas
II. Sulfur Balance
A. Glaus plant
Input - 104.471 MT/D
Recovered - 98.203 MT/D
Off-gas - 6.268 MT/D
B. TGT-1500 process
Input - 6.268 MT/D
Recovered - 5.275 MT/D
Off-Gas - 0.993 MT/D
; tI. Process Waste Streams
A. Intermittent contaminated water. With the new catalyst
formulations, it takes about 2 years of operation before
catalyst washing is necessary. At that time, about 28,000
liters of water would be required for washing the catalyst
from a 100-MT/D Glaus plant (about 151,400 liters from a
1,000-MT/D plant). The wash water would contain about
1 percent by weight of the organic solvent (polyalkylene
glycol) and 20 to 25 percent by weight of the catalyst
(mixed alkali metal salts of an organic acid). This waste
stream would be treated in the refinery wastewater-treatment
system or sent to the sewer system.
-------
TABLE 26.
74
TYPICAL COMPOSITION OF GAS STREAMS ENTERING AND LEAVING A
100-MT/D REFINERY GLAUS PLANT PLUS THE IFF TGT-1500 TAIL-
GAS PROCESS
(a)
(Basis: Sulfur recovery in Glaus unit of 94 percent)
Composition, 7a vol.
H?S
SO
S vapor and mist
COS
cs
GO
CO,
')
HC (MW:30)
Ho
H^,0
N^
°2
Total
Ti-rpoerature , C
i'rcssure, atm
.,:, Quantity
(Relative Amount), moles
r ' - • '' Ss. mm
Glaus
Intake
89.9
--
--
--
__
--
4.6
0.5
--
5.0
--
--
100.0
40
1.45
1.00
56.78
Glaus
Exhaust
0.85
0.42
0.05
0.05
0.04
0.22
2.37
...
1.60
33.10
61.30
__
100.00
140
1.26
3.00
170.35
After
Absorption
Tower
0.085
0.042
0.050
0.050
0.075
0.219
2o376
--
1.607
330990
61.545
--
100.00
119
1
2.83
160.72
After
Incinerator
--
0.21 TL
--
__
--
--
4.483
--
__
30.502
64.299
0.504
100.00
650
1
4.03
228.98
Iktf rial-balance data taken from letter to J. M. Genco, from J. W.
Aiidrews, IFF (Dec. 21, 1973).
in standard cubic meters per minute (scmm) .
-------
75
TABLE 27. ESTIMATE OF UTILITIES REQUIREMENTS FOR
IFF TGT-1500 TAIL-GAS PROCESS APPLIED TO
A 100-MT/D REFINERY GLAUS SULFUR PLANT
Item
Value
Steam, kg/hr
Cooling Water, I/sec
Electricity, kWhr/hr
Fuel Gas, scmh
Boiler Feed Water, I/sec
Chemicals
Start-up solvent, $
Solvent and catalyst
consumption, $/year
Condensate, I/sec
Operating Data
Labor, men/shift
Maintenance, 7o FCI
Maintenance on catalyst,
liters of water
(For start-up only)
(For shutdown only)
35
0
0
18,500
(b)
10,500(b)
0,082
1/6-1/3
5
28,000
(c)
(a) Data taken from letter to Genco, J. M., from
J. W. Andrews, IFF (Dec. 21, 1973).
(b) Unit values are proprietary.
(c) Maintenance on the catalyst once every 2 years.
This is the value required for the wash water.
-------
76
Waste Streams. There are no major waste streams generated by the
TGT-1500 process. There are, however, intermittent contaminated wastewaters
(see Table 25) that arise from washing the IFF reaction catalyst. With the
new catalyst formulations, it takes about 2 years of operation before
catalyst washing is necessary. At that time, about 28,000 liters of water
would be required for washing the catalyst from an TGT-1500 process applied
to a 100-MT/D Claus plant and about 151,400 liters from a 1,000-MT/D plant.
The wash water would contain about 1 percent by weight of the organic
solvent (polyalkylene glycol) and perhaps 20 to 25 percent by weight of the
mixed alkali metal salts used as the catalyst. The waste stream would be
treated in the refinery wastewater-treatment system or sent to an industrial
sewer. While the solvent used in the TGT-1500 process is high boiling, its
vapor pressure at reaction temperatures does cause some loss in the process
off gas. The solvent is combusted to C09 and water in the incinerator,
however, and thus should not represent a pollution problem of its own.
In addition to intermittent wastewaters generated in catalyst
washing, a secondary source of pollution would arise in the case of the
TGT-150 process. This involves the process off-gas leaving the top of the
am-jonia scrubber. Besides unreacted SCL , the process gas will contain traces
of Mil,, gas, entrained PEG solution, and sometimes a fine white particulate
tu;;,e. The ammonia-SO,-, fume is thought to be the gas—phase reaction product
between NH~ and SCL . It is a fine particulate fume which is highly visible
and, because of its small size, difficult to remove from the gas. The fume
forms over the scrvibbing trays where appreciable NH~ vapor pressure exists.
A sU'dy currently is being conducted to determine the least expensive method
ol" eliminating the fume.
Chiyuda Thoroughbred 101 Process
Process Description. The Chiyoda Thoroughbred 101 process '
Is a wet flue-gas-desulfurization process which produces gypsum as an end
prod.ict. Scaling and plugging problems in the scrubber are eliminated by
scrubbing the tail gas with a dilute solution of sulfuric acid. The
particular flow scheme applicable to tail gas treatment is shown in Figure E-7,
-------
77
The incinerated off-gas from a Glaus plant is cooled to about 55 C in a
venturi saturator by means of a water spray in combination with an
intercooler for heat rejection. Next the gas enters a countercurrent
packed tower of grid-supported Tellerette packing where it is scrubbed
with dilute ILSO, to remove the S0_ . An oxidizing catalyst, ferric sullate,
24 2.
and dissolved oxygen present in the scrubbing liquor increase the solubility
of S09 in the dilute acid. The gas is then reheated by direct combustion oi
fuel and sent up the stack.
The recycle liquor from the bottom of the absorber is sent to an
oxidizer where residual sulfurous acid is completely oxidized to sulfuric
acid by air bubbles in the presence of the soluble ferric sulfate catalyst.
Air is flown upward through the liquor at about five times the theoretical
requirement. The net make of acid in the scrubber is bled from the oxidi/.er
and neutralized with limestone in a crystallizer. The sulfuric acid tank
between the oxidizer and the crystallizer has enough capacity to allow the
absorber and the oxidizer to be drained for maintenance.
Limestone pulverized to 200 mesh has an apparent 100 percent
utilization in the crystallizer. Pulverized limestone is conveyed to the
crvstallizer by an air stream. The CaSO '21LO (gypsum) crystals formed in
ff'O crystallizer are separated in a centrifuge and the dry solid is piled
L-<\ the ground for storage or sold as product, while the mother liquor is
recycled to the absorber. Catalyst makeup is added to the mother liquor tank
a-i'A a purge stream from this tank is required to remove excess water and
impurities, present in the limestone, from the system.
Clean process water is added to the system at the centrifuge in
.-'c5' i to wash the gypsum product. Because the Glaus plant tail gas contains
,•(.•>• r 33 percent water and the tail gas must be cooled, water condenses and
r-iist be removed from the system. Therefore, excess mother liquor in the
Lorni of a purge stream is pumped to the refinery wastewater treatment system
irder to maintain a water balance on the tail gas desulfurization system.
The Chiyoda process consists of three major reactions as follows:
S°2 + H2° "* H2S°3 (1)
1 catalyst
H2S03+-02 y-> H2S04 (2)
H2S04 + CaC03 + H20
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78
Reaction (1) takes place in the absorber, Reaction (2) takes place mainly
in the oxidizer, but also in the absorber, and Reaction (3) takes place
in the crystallizer.
The SO -removal efficiency that can be obtained with the Chiyoda
process is dependent upon the liquid-to-gas ratio (L/G) used in the
absorber and the height of the packing in the absorber. Because the
scrubbing liquor is dilute H SO,, very high L/G's are required to obtain
high removal efficiencies for S09> Roughly speaking, an L/G of about
54 1/cu m is required for 95 percent SO. removal at ordinary packing heights.
Furthermore, for design reasons, the packing height in the absorber is
limited to about 9 meters. For these reasons, the removal efficiency is
limited to a maximum of about 95 percent, which means that the SO content
of the tail gas could be reduced from about 10,000 ppm to about 500 ppm.
However, an S0« level of about 1,000 ppm in the treated tail gas is a
more realistic expectation.
Commercial Status. The Thoroughbred 101 process was developed
and is licensed by the Chiyoda Chemical Engineering & Construction Company,
Ltd., of Yokohama, Japan. The process has been applied to tail gas from
three refinery Claus plants and one combined industrial boiler-Glaus tail-
gas feed (see Table 28). However, since the process treats SO rather than
US, it has found fairly wide acceptance in Japan as a flue-gas-desulfurization
method on oil-fired boilers. In this regard, it has been applied to eight
plants having industrial boilers as well as one industrial incinerator. Gas
flow rates for the boiler application have ranged from 2,100 to 18,200 scram
while that for the incinerator is 434 scmm.
Material Balance and Utilities. Sulfur balance calculations are
summarized in Table 29. Table 30 gives material-balance information for
major gas streams in the process. These estimates are based in large part
c'n information provided by Chi;
making these calculations are:
information provided by Chiyoda. ' The basic assumptions used in
-------
79
TABLE 28. LIST OF ANNOUNCED CHIYODA THOROUGHBRED 101
TAIL GAS PROCESSES UNITS FOR GLAUS SULFUR
PLANTS
Company /Location
Mi f,u shim a Refinery, Nippon
'•Mning Co./Mizushima, Japan
St-ndai Refinery, Tohoku Oil
i,'o./5endai, Japan
.-'•.]\ Kosan Co., Ltd./
• .Jinan, Japan
Unit /Capacity
Startup Date (SCFM)
November, 1972 1/20,800
February, 1973 1/8,800
November, 1972 1/98,000
Number/Capaci ty
Claus Plants (LT/D)
1/200; 1/50
1/90
(a)
.;o<;)bi ued industrial boiler and Claus sulfur plant incinerated tail gas.
-------
80
TABLE 29. APPROXIMATE SULFUR BALANCE AND ESTIMATE OF WASTE STREAMS FOR
THE CHIYODA THOROUGHBRED 101 FLUE-GAS-DESULFURIZATION PROCESS
I. Basis
A. 100-M/D Glaus plant
B. 94 percent sulfur removal in Glaus plant
C. 92 percent sulfur removal in Chiyoda process
11. Sulfur Balance
A. Glaus Plant
Input - 104.471 M/D
Recovered - 98.203 M/D
Off-gas - 6.268 M/D
B. Chiyoda Process
Input - 6.268 M/D
Recovered - 5.768 M/D
Off-gas - 0.4996 M/D
TIT. rtaste Streams
A. By-Product Gypsum
(1) Rate =35.3 MT/D
(2) Composition Wt 7,
H20 10.0
CaS04'2H20 89.2
Impurities
MgO (soluble) 0.2
Fe203 0.1
Insolubles 0.5
Total 100.0
(3) Treatment Method - This must either be sold or sent to a
landfill.
i'urge Stream
(1) Flow Rate = 0.148 I/sec
(2) Composition Wt %
H20 97.0
H2S04 0.8
MgO 2.2
Fe2(304)3 Trace
100.0
(3) Treatment Method - Neutralized and sent to the refinery wastewater-
treatment system or to an industrial sewer.
-------
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(1) Essentially complete conversion of all sulfur compounds
to SO in the incinerator prior to sending the tail
gas to the Chiyoda process (fuel gas is 9,000 kg-cal/
cu m with 10 percent excess air).
(2) 92 percent removal of SO,, in the absorption column at
an L/G ratio of 44 1/cu m.
(3) The off gas from the process is reheated to 316 F in a
direct-fired reheater using 9,000 kg-cal/cu m fuel gas
and 10 percent excess air.
(4) The acid produced is neutralized with limestone having
the following composition (10 percent moisture and 90
percent solids):
Weight Percent
Composition (dry basis)
Fe203 0.20
MgO 1..86
CaO 53,.40
C02 43,. 75
Other solubles Q.,79
100 ,,00
(5) The MgO split between the purge stream and the product
is 75 percent to 25 percent, respectively.
The Chiyoda process should be capable of reducing the sulfur level
in the off gas to about the 1,000 ppm. Further sulfur reductions are
possible but would result in inordinately high liquid-to-gas recirculation
rates in the absorber. Overall sulfur recovery in the Glaus plant with
tail-gas treatment is estimated to be about 99.5 percent. An estimate of
the utilities required for a unit treating the tail gas from a 100-MT/D
Glaus plant is given in Table 31.
Waste Streams. The waste streams produced by the Chiyoda process
include a solid product gypsum with a moisture content of 5 to 20 percent
and a mother liquor purge stream (see Table 29). The purity of the product
-------
TABLE 31. ESTIMATE OF UTILITY REQUIREMENTS FOR CHIYODA
THOROUGHBRED 101 TAIL-GAS PROCESS FOR 100-
MT/D REFINERY GLAUS SULFUR PLANT
Value
Steam (32 atm, sat), kg/hr 2,470
Cooling Water (10 C rise), I/sec 64.5
Electricity, kwh/hr 425
Fuel Gas, scmro 4,256
Boiler Feed Water, I/sec 0.871
Chemicals , s
Limestone, MT/D 21.1
Operating Data
Labor-, men/shift 1/3
Maintenance, percent FCI 5
(a) Steam generated in the process.
(b) Heating value of 9,000 kg-cal/cu m.
(c) Wet basis at 10 percent water and 90 percent
solids.
-------
84
gypsum is dependent upon the level of dilute-acid-insoluble impurities in
the limestone feed. The soluble impurities washed out of the gypsum, by
adding process water at the centrifuge, end up in the purge stream. The
gypsum produced can be of sufficient quality to permit its use in wallboard.
If the gypsum could not be sold, it would have to be sent to a landfill for
final disposal.
The mother-liquor purge stream consists of dilute sulfuric acid
(about 1 weight percent), soluble impurities (mainly MgSO.) from the limestone,
+3
and a small amount of dissolved catalyst (about 2,000 ppm of Fe ). It
would normally be neutralized and sent to the refinery wastewater-treatment
system or, alternatively, to an industrial sewer.
Sulfreen Process
Process Description. The Sulfreen process ' (see Figure
E-8) was jointly developed by Lurgi Apparate-Technik, Frankfurt, West
Germany, and the Societe Nationale des Petroles d' Aquitaine (SNPA), Lacq,
France. This process reduces the sulfur content in Glaus-plant tail gas
by further promoting the Glaus reaction on a catalytic surface in a gas/
solid batch reactor:
cat.
2H2S + S02 ^ 3S + 2H 0.
The Claus-plant tail gas is first countercurreritly contacted with liquid
sulfur to wash out any sulfur particles that may have been entrained in
the sulfur plant.
The tail gas then is introduced to a battery of reactors (six
shown) where the Glaus reactions are carried out at lower temperatures
(127 to 149 C) than those utilized in the sulfur plant. The purpose of
the reduced temperature is to take advantage of the more favorable equilibrium
conditions of the Glaus reaction which is reversible. The catalyst is
usually activated carbon, although alumina is also used.
For desorption of sulfur from loaded beds, a regeneration gas
consisting essentially of nitrogen is used. The nitrogen is heated in
several steps up to 500 C in a gas-fired heater and then cycled through the
-------
85
activated carbon bed from top to bottom. The temperature is kept below
300 C until all carbon dioxide and water are displaced from the beds.
Otherwise, carbon losses would occur through gasification.
For the desorption of sulfur, the temperature is raised to 400
C. Sulfur vaporizes and is swept away with the nitrogen; most of it is
precipitated in the condenser ahead of the sulfur washing tower. The
washer itself further reduces the level of elemental sulfur down to 140
mg/cu m. At the same time, the regeneration gas is cooled in these two
units to approximately 120 C. The heat released in the condenser produces
saturated steam of 5.76 atm from boiler feedwater, and it is used for such
tasks as heating the molten sulfur product.
The process reduces entrained sulfur to a minimum as the catalyst
acts as a very effective adsorbent for liquid sulfur. A Sulfreen unit may
consist of as little as three reactors, two in adsorption and one in
desorption service. The number of reactors is determined mainly by economic
considerations and the degree of sulfur (fLS and SO,-,) removal desired. In
the process, COS and CS_ are not affected and this is a major disadvantage
of the process. Since only solid adsorbents are used, no liquids except
sulfur condense, and the process is free of major liquid disposa] problems.
'Jills :, s the main advantage of the Sulfreen process.
A one-stage Sulfreen process, similar to that shown in Figure E-8,
<• • ,H;,„!-.H- of reducing the tail-gas sulfur level by about 80 to 85 percent
tor suitnr mist, SO- and R S. A second-stage option has been considered to
f'.i'T.'ipr reduce the sulfur content. In the second stage, the tail gas is
injected with air and sent to another catalytic bed in which hydrogen sulfide
: <• oxidized directly to sulfur. Currently, the second stage is not
vommeri iail v available. It is claimed that the outlet H«S concentration
ri.^i thf • econd stage can be reduced to 10 ppm. This is highly unlikely
an<;. would require a second-stage efficiency of 99.5 percent. A more
leaJistic second-stage efficiency would be 85 to 95 percent, which would
bring the total sulfur level in the process gas going to the incinerator
ilown lo 100 to 400 ppmv equivalent HS.
-------
86
Commercial Status. The Sulfreen process Is licensed by Lurgi
Apparate-Technik, Frankfurt, West Germany, Societe Nationale des Petroles
d'Aquitaine, Lacq, France, and by the R. M. Parsons Company, Los Angeles,
California. Three commercial-scale plants are already on-stream (see
Table 32). The first, in Lacq, France, handles approximately 3.2 million
standard cubic meters per day (scmd) of gas and employs six reactors,
three of which contain activated carbon while the others contain alumina.
The second and third units in Ram River, Alberta, Canada, were started up
in the spring and fall of 1972, respectively. The Ram River units recover
sulfur as product from tail gases off four 1,000 MT/D Glaus sulfur units.
These Sulfreen units are rated at about 11.2 million scmd total. In these
(58)
two units, all reactors used only activated carbon. In addition to
these operating units, four other large-scale plants treating a total of
approximately 19.6 million scmd are under construction.
Material Balance and Utilities. Sulfur-balance calculations for
a Sulfreen unit handling the tail gas from a 100-MT/D Claus plant are
summarized in Table 33. The sulfur-balance values were based on the
material balance information presented in Table 34. Only that portion of
the process undergoing adsorption was considered in making material-
balance calculations. The basic assumptions used in arriving at the infor-
mation shown in Tables 33 and 34 are:
(1) The adsorption reactors are operated essentially
at the same temperature as the tail gas exiting the
Claus plant (140 C).
(2) The sulfur wash prior to the reactors removes 75
percent of the entrained sulfur mist entering
the washer.
(3) The gas-phase SO and H?S concentrations are reduced
by 80 percent in the reactors.
(4) COS and CS^ are not appreciably removed in the process.
(5) The off gas from the reactors is incinerated in the
Claus-plant incinerator using 9,000 kg-cal/cu m fuel
gas and 10 percent excess air.
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87
TABLE 32. PARTIAL LIST OF ANNOUNCED SULEREEN TAIL-GAS-PROCESSING
UNITS FOR GLAUS SULFUR PLANTS
Company/Location
Start-up Date
Capacity,
scmm
Number/Capacity of
Claus Plants,
MT/D
SNPA/France
Lacq Nat. Gas Plant
Aquitaine Co. (Canada)
Ltd.)/Alberta, Canada
"Ham River Gas Plant
1970
1972
11,952
1/114
2/400
(a) Four other units are thought to be under construction.
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88
TABLE 33. APPROXIMATE SULFUR BALANCE AND WASTE STREAMS FOR
SULFREEN TAIL-GAS PROCESS
I. Basis
A. 100-MT/D Glaus plant
B. 94 percent sulfur removal in Glaus plant
C. 75 percent sulfur mist ($„) removal in sulfur washing unit and
approximately 80 percent sulfur (H?S, SO ) removal in one-stage
Sulfreen unit^3'
II. Sulfur Balance
A. Glaus Plant
Input - 104.471 MT/D
Recovered - 98.203 MT/D
Off gas - 6.268 MT/D
B. Sulfreen Process
Input - 6.268 MT/D
Recovered - 4.536 MT/D
Off gas - 1.732 MT/D
,L1. Waste Streams
None
-. „,' "/_' percent removal is approximate since S0? and H S in the inlet feed are
not quite in stoichiometric ratio.
-------
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Under this set of assumptions, the overall sulfur-removal efficiency
(Glaus plant plus Sulfreen process) would be about 98.3 percent. The
sulfur concentration in the Sulfreen process off gas calculated as H S
prior to incineration would be about 5000 ppm. Utilities requirements for
the Sulfreen process are shown in Table 35. These data were scaled down
to the size required for a 100-MT/D Glaus unit from information presented
in Krill and Stopp^57^ and Wall^ .
Waste Streams. Since only solid adsorbents are used, no liquids
except sulfur condense, and the process is free of major liquid-disposal
problems. The catalyst (activated carbon or activated alumina) life
expected is about 4 years, but it would have to be disposed of or regenerated
at that time. These streams should present no major problems since both
types of waste (degenerated catalyst and sulfur-contaminated water) are
often encountered in refinery practice.
ESTIMATION OF NATIONWIDE REFINERY
SULFUR PLANT EMISSIONS IN 1975
Emissions of sulfur from petroleum refineries are a complex
function of the sulfur content of the crude oil being processed, the
complexity of the refinery, and its energy balance. Sulfur enters the
refinery in the oil, in any purchased fuel oil or gas, and as sulfuric
acid purchased for process use. A large part of this sulfur routinely
leaves the refinery in the various products, as spent sulfuric acid shipped
out for regeneration and as sulfides or sulfates in waste liquids, or is
recovered as a by-product in sulfur-recovery plants. The balance is emitted
tu the atmosphere mainly as sulfur dioxide, although some SO and H S may
also ba released. These sulfur emissions occur mainly during fuel-gas-
barn Lug operations in process heaters and boilers and to a lesser extent
as tail gas from Glaus sulfur plants. In this section of the report, nation-
wide sulfur emissions from refinery Glaus plants are estimated for the year
To estimate nationwide refinery Glaus plant emissions, several
ssumptions are required:
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91
TABLE 35. ESTIMATE OF UTILITIES REQUIREMENTS FOR
SULFREEN PROCESS ADDED TO 100-MT/D
REFINERY CLAUS SULFUR PLANT
Steam (4.76, sat), kg/hr
Cooling Water, I/sec
Electricity, kwh/hr
Fuel Gas, scrah
Boiler Feed Water, I/sec
Chemicals
Nitrogen, scmh
Catalyut, kg/hr
Operating Data
Labor, men/shift
Maintenance, percent FCJ
Alumina
Catalyst
735(a)
Nominal
124
60.9
0.189
44.9
11.0
1/3-1/2
3.3
Activated
Carbon
Catalyst
785(a)
Nominal
69
65.0
0.221
44.9
5.6
1/3-1/2
3.3
at,earn produced in process,
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92
(1) The nationwide average physical properties of petroleum
are
(a) Specific gravity = 0.876(60)
(b) Sulfur content - 0.92 percent.
(2) The average capacity factor of refinery Claus plants
is about 66 percent.
(3) Sulfur recovery from existing tail-gas units at
refineries was negligible in 1973.
(4) The average capacity factor for petroleum refineries
in 1973 was about 95.7 percent.
(5) Additional refining capacity between 1973 and 1975 will
process high-sulfur oil (i.e., about 2 percent sulfur).
(6) On the average, Claus sulfur plants in refineries are
about 92 percent efficient, i.e., an average plant
will recover on a molar basis about 92 percent of the
input H S as elemental sulfur.
(7) Tail gas processes are, on the average, about 94 percent
efficient and thus will raise the overall level of
sulfur recovery (Claus plant plus tail-gas process) to
about 99.5 percent, and this represents best available
technology.
(8) Current refinery sulfur-recovery capacity can be
obtained from the data of Beers k and amounted to
7,999 MT/D (see Tables 5 and 6) in 1973.
Domestic refining capacity in place as of April, 1973, is shown in Table 6.
Announced additional refining capacity scheduled for start-up prior to
January 1, 1975, is shown in Table 36. On the basis of these data,
domestic refining capacity will increase by about 1 percent between 1973
and 1975, i.e., from about 1.836 x 10 MT/D to 1.854 x 10 MT/D in 1975.
Likewise, the national average sulfur content of the crude oil being
processed will increase from about 0.92 to 0.93 percent over this 2-year
period. Consequently, refinery Claus-sulfur-plant capacity in 1975 can be
estimated from the 1973 value as:
1975 Claus capacity = 7,999 MT/D x 1.01 x (0.93/0.92) = 8,167 MT/D.
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93
TABLE 36. STATE-BY-STATE LISTING OF ANNOUNCED ADDITIONAL
REFINERY CAPACITY BY 1975U '
State/Company/City, County Start-up Date
Pennsylvania
AKCO
Philadelphia
Cdliloinia
Larson
i lliaoih,
tun , ford
Late 1973
Late 1973
Late 1974
(a)
Rfcfinery Capacity,
10"3 metric tons/day
2.7
6.2
Kansas
AH CO
A»'--.-r.sas City
Late 1974
2.7
Eaily 1974
2,7
May, 1974 0.8
TOTAL 18.5
.31 barr€;ls of oil per metric ton.
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94
Sulfur emitted in tail gas can be estimated from the capacity factor (2/3)
and the approximate percentage sulfur recovery in Glaus plants (92 percent),
i.e., 1975 tail-gas emissions (MT sulfur/yr = (8,167 MT/D) x (2/3) x (365
days/yr)(0.08/0.92) = 0.173 x 10 MT/yr. This value should be corrected for
sulfur recovery in tail-gas processing which will occur in 1975. The data
given in Tables 10, 14, 16, and 20 suggest that approximately 1,854 MT/D
of Glaus plant capacity will be equipped with tail-gas processing by 1975.
This translates into approximately 0.037 x 10 MT/yr of sulfur being
recovered from tail-gas processing, i.e., MT/yr « (1,854 MT/D)(2/3)(365)
(0.08/0.92)(0.94) = 0.037 x 10 MT/yr. Thus, correcting the uncontrolled
emissions number (0.173 x 10 MT/yr), one obtains the estimate for 1975
sulfur emissions from refinery Glaus plants;
1975 tail-gas emissions (MT sulfur/yr) = (0.173 - 0.037) x 106 =
0.136 x 106 MT/yr,
or in terms of SO emitted
1975 tail-gas emissions (MT S02/yr) = (0.136 x 106) x 2
= 0.272 x 106 MT/yr.
It is interesting to compare the estimate of uncontrolled emission
of SO,, from refinery sulfur plants to other sources in 1975. Table 37
litimmarizes estimated nationwide S0« emissions without abatement from several
sources. The estimates shown in Table 37 were made in 1970 by the National
research Council's Ad Hoc Panel on Control of S0? from Stationary Combustion
Sources. By far the major emitter of S0? would be fossil-fuel fired power
plants. By way of comparison with major sources, refinery Glaus sulfur-plant
emissions are rather small, i.e., about 0.3 x 10 MT/yr out of a total of
43.7 x 10 MT/yr.
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95
TABLE 37. ESTIMATED ANNUAL SULFUR DIOXIDE EMISSIONS IN
THE UNITED STATES IN 1975—NO ABATEMENT(fl)
106 Metric
Tons/Year
Power Plant Operations
(Coal and Oil) 27.3
Other Combustion of Coal 3.9
Combustion of Petroleum Products
(Excluding Power Plant Oil) 3.3
Smelting of Metallic Ores 4.2
Petroleum Refinery Operations 2.9
Miscellaneous Sources 2.1
TOTAL 43.7
(a) Data taken from "Abatement of Sulfur Oxide
Emissions from Stationary Combustion Sources",
National Research Council, COPAC-2,
Washington, B.C. (1970).
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96
CONCLUSIONS
On the basis of the foregoing analyses and review of sulfur
recovery at petroleum refineries, several conclusions can be drawn:
(1) Petroleum refineries differ widely and generalizations
about sulfur recovery and emissions are difficult to
make.
(2) Sulfur occurs in petroleum processing in the form of
four types of compounds; hydrogen sulfide and mercaptans,
elemental sulfur, carbonyl sulfide (COS), and carbon
disulphide (CS ) , and neutral sulfur compounds.
(3) Emissions of sulfur to the atmosphere at petroleum
refineries occur mainly as S0? from process heaters,
boilers, and flares, in the tail gas from sulfur-
recovery plants, and as trace amounts of H S that escape
during routine processing operations.
(4) Virtually all sulfur currently being recovered at
petroleum refineries is done by vapor-phase oxidation
of H S in straight-through Glaus plants. Domestic
sulfur recovery capacity found at refineries amounts
to about 8,000 MT/D. Plants are normally operated
at two-thirds of capacity and sulfur-recovery efficiencies
of 90 to 95 percent. Acid-gas-feed sources to refinery
Glaus plants originate mainly from sour-water strippers
and amine regenerators associated with hydrocracking units,
hydrotreating units, and fuel-gas desulfurization oper-
ations.
(5) Fuel-gas desulfurization using amines and other reactive
liquids, as well as sulfur recovery in Glaus plants, is
well-established technology. Both technologies are
commercially available and have been practiced in the
petroleum industry for many years.
(6) An alternative to Glaus-plant technology is sulfur
recovery by way of liquid-phase oxidation of H S. Good
-------
97
examples of this technique would be the Stretford
or Giammarco-Vetrocoke processes, which use multiple,
coupled redox reactions in solution to produce ele-
mental sulfur. Such processes have been used in the
European natural-gas industry and are now being
introduced into the U.S. The Stretford process is
currently being used for fuel-gas desulfurization
and also is incorporated into the Beavon and Cleanair
tail-gas-treatment processes.
(7) Processing of tail gases from Glaus plants found at
refineries (also natural-gas plants) would be considered
emerging technology and is only now beginning to be
practiced in the U.S. The leading U.S. processes are
the Beavon, SCOT, Wellman-Lord, IFP-TGT-1500 process,
and Cleanair processes. In addition, the Chiyoda
Thoroughbred 101 and Sulfreen are promising processes
that have not yet been tried on domestic refinery Glaus
plants. All but the Chiyoda process recover elemental
sulfur. Approximately 964 MT/D of parent^Claus-plant
capacity has been equipped with tail-gas processing.
These plants are now mainly in start-up difficulties.
An additional 890 MT/D of parent-sulfur-plant capacity
is due to be equipped (announced plants) in the U.S. by
1975.
By use of tail-gas processing, overall sulfur recovery
can be increased to greater than 99 percent of the
total input sulfur to the Glaus plant. The utilities
required and waste streams generated by the operation
of tail-gas processing are not inordinate. Roughly,
the utilities (hence, operating cost) are of the same
order as those involved in the parent sulfur plant.
Waste streams in the aqueous-based processes usually
involve either a sour-water or acid-water purge stream
resulting from condensation of water in the tail gas.
Depending upon the process, this water is usually sent
-------
98
to either the sour-water stripper for H~S removal or
to the refinery wastewater-treatment system for
neutralization. In addition, several processes, i.e.,
the Beavon, Cleanair, and Wellman-Lord, have purge
streams containing metal salts that must be disposed
of. Currently, they are being discharged to industrial
sewer systems. Their small size does not appear to
cause major problems. Also, the process licensors
are developing techniques for on-siite treatment.
(9) Nationwide sulfur emissions from refinery Claus
plants were estimated to be approximately 0.136 x 10
MT/yr (0.272 x 10 MT of SO ) in 1975. In comparison
with other emission sources of sulfur, refinery Glaus-
plant emissions appear to be quite small, i.e., it is
estimated that less than 1 percent: of the 1975
unabated SO sources would be attributable to refinery
Glaus-plant tail gas.
-------
99
REFERENCES
(1) Stern, A. C., Air Pollution, 2nd Edition, Vol III, Academic Press, New York,
N. Y. (1968), pp 101-103.
(2) Updegraff, N. C., and Reed, R. M., The Petroleum Engineer, 26 (10), C57-C63
(September, 1954).
(3) Blake, R. J., Oil & Gas Journal, 65 (2), 102-108 (January 9, 1967).
(4) Fitzgerald, K. J., and Richardson, J. A., Hydrocarbon Processing, 45 (7),
125-129 (July, 1966).
(5) Klein, J. P., Oil and Gas International, _10 (9), 109-112 (September, 1970).
(6) Kohl, A. L., Petroleum Processing, 6 (1), 26-31 (1951).
(7) Holder, H. L., Oil & Gas Journal, _64 (18), 83-86 (May 2, 1966).
(8) Beychok, M. R. , Aqueous Wastes From Petroleum and Petrochemical Plants,
John Wiley and Sons, New York, (1967).
C9) Anonymous, Manual on Disposal of Refinery Wastes, Vol I. Wastewater
Containing Oil, Vol III, Chemical Wastes, Vol IV. Sampling and Analysis
oi Wastewater, American Petroleum Institute, Washington, B.C. (1969).
L!; Armstrong, T. A., Oil & Gas J., .66 (25), 96-98 (June 17, 1968).
: LI> r,, W. D. , "Characterization of Glaus Plant Emissions", Final Report from
I'-.jct-jS Research, Inc., to the United States EPA, Contract No. 68-02-0242,
Task No. 2, Report No. EPA-R2-73-188 (April, 1973).
•. : ^ad.iox, R. N., and Burns, M. D., Oil & Gas J., 66 (37), 130-133
(September 9, 1968).
i ", , ;:rficel , H, Kunkel, L. V., and McGalliard, R. , Chemical Engineering Progress,
o_l {9s! , 70-73 (1965).
i i. <;re.Kt-l, H., et al, Oil & Gas J., 5j> (23), 80-81 (June 5, 1961).
/• O.-r, B. G., Hydrocarbon Processing, 47 (9), 248-252 (1968).
'•i- ,i.\el, H., and Kilmer, J. W. , Oil & J., _66 (44), 88, 93-101 (October 28, 1968)
•..wu.en-i, F. M., and Reid, L. S., Petroleum Refiner, _37. (11), 263-266 (1958).
,- "Axi-: , A. E., Trans. AIME, 241, 314-318 (1968).
... , Aiion>:.i0us, Engineering and Mining Journal, 169 (10), 85-92 (October, 1968).
^,, Anonymous, Oil & Gas J., 7_1 (32), 32-33 (August 6, 1973).
-------
100
REFERENCES
(Continued)
(21) Nader, J. E., Wesselingh, J. A., and Groenendaal, W. , "The Shell Off-Gas
Treating Process", paper presented at the 74th National Meeting of the
AIChE, New Orleans, Louisiana, March 11-15, 1973.
(22) Ellwood, P., Chem. Eng. , 7JL (15)> 128-130 (July 20, 1964).
(23) Hasbe, N., Tokyo Gas Co. Ltd, Research Report (no date given).
(24) Beavon, D. K., and Vaell, R. P., paper presented at the 37th Mid-Year
Meeting of the API's Division of Refining, New York, N. Y., May 8-11, 1972.
(25) Beavon, K. D., Chem. Eng., _78, 71-73 (December 13, 1971).
(26) Thomas, G.L., and Plum, E., paper presented at the 71st National AIChE
Meeting, Dallas, Texas, February 20-23, 1972.
(27) Goar, B. G., Hydrocarbon Processing, 47 (9), 72 (1968).
.23) Jennett, E., Oil & Gas J., 60_ (18), 72 (April 30, 1962).
(29) Swain, C. D., Jr., Hydrocarbon Processing, 49 (3), 127 (1970).
(30) Kohl, A. L., and Riesenfeld, F. C., Chem. Eng., 66 (12), 127-128
(June 15, 1959).
(31) Anonymous, Oil & Gas J., 69 (50), 39 (December 13, 1971).
•.. > Ellwood, P., Chem. Eng., _71 (15), 128-130 (July 20, 1964).
Anonymous, Oil & Gas J., 69 (41), 68-69 (October 11, 1971).
Anonymous, Hydrocarbon Processing, 50, 119 (April, 1971).
oedman, C., private communication, EPA, Durham, North Carolina
(December, 1973).
Mltachi, K. , Chemical Engineering, _80 (21), 78-79 (October 15, 1973).
Maddox, R. N., and Burns, M. D., Oil & Gas J., 66 (23), 90-95 (June 3, 1968).
lennett, E., Oil & Gas J., _60, 72-77 (April 30, 1962).
Meuly, W. C., "Cataban Process for the Removal of Hydrogen Sulfide from
•"aseous and Liquid Streams", paper presented at the 12th Annual Purdue
•• i r Quality Conference, Purdue University, West Lafayette, Indiana
(November, 7-8, 1973).
-------
101
REFERENCES
(Continued)
(40) Anonymous, "Present Technology for Sulfur Recovery—Status Report for
the Florida Department of Pollution Control", Report from Walk, Haydel
& Associates, Inc., WH&A Job No. 72-1634 (May 31, 1973).
(41) Davis, J. C., Chem. Eng. , ^78, 43-45 (November 29, 1971).
(42) Anonymous, Oil & Gas J., H) (6), 65 (February 7, 1972).
(43) Wall, J., Hydrocarbon Processing, 52 (4), 116 (April, 1973).
(44) Private communication, letter to J. M. Genco, from C. B. Earl, Davy
Powergas Inc., Lakeland, Florida (December 13, 1973).
(45) Groenendaal, W. , Nv. , M. , and VanMeurs, H. C., Petro. & Petrochem.
Int., 12 (9), 54-58 (1972).
(46) Dautzenberg, F. M. , Nader, J. E. , and Van Ginneken, A.J.J., Chemical
Engineering Progress, 67. (8), 86-91 (1971).
CM) Private Communication, letter to J. M. Genco from E. G.Foster, Shell
Development Corporation, Houston, Texas (January 22, 1974).
Wail, J., Hydrocarbon Processing, _52 (4), 115 (April, 1973).
Anonymous, Hydrocarbon Processing, 50 (5), 89-91 (May, 1971).
\-. • .. ,i!.be, G. M., Maxwell, M. A., and Rochelle, G. T. , "Control of Sulfur
Di oxide. Emission from Stack Gases -- Discussion of Promising Soluble Base
Aqu< ous Scrubbing Processes", paperpresented at the 17th Annual AIChE Meeting,
ije i aware Valley Section, Philadelphia, Pennsylvania, March 21, 1972.
Mirai, K, , Odello, R. , and Shimamura, H. , Chem. Eng., 79, 78-79
•April 17, 1972).
B.Lthe', Y. , Deschamps, A., Frankowiak, S. and Andrews, J. W. , "IFP
.'; -r.fv.,s for Recovering H2S and SC>2 from Glaus Unit Tail Gas and for
Cleaning SC>2 from Stack Gas", paper presented at the 66th Annual Meeting
.1 :-ir Pollution Control Association, Chicago, Illinois, June 24-28, 1973,
1 ;ivute communication, letter to J. M. Genco from J. W. Andrews, Institute
i'rancais du Petrole, New York, N. Y. , (December 21, 1973).
s, "Report of the Edison Electric Institute Study Program on S02
* xuval Processes in Japanese Plants", Edison Electric Institute, New York,
N. i. (1973).
tn'v/ate communication, letter to J. M. Genco from T. Kamada, Chiyoda
L. h em j c d 1 Engineering & Construction Co., Ltd., Yokohama, Japan (January 9,
1973 >.
-------
102
REFERENCES
(Continued)
(56) Idemura, H., "New Flue Gas Desulfurization Process", report by the
Chiyoda Chemical Engineering & Construction Co., Ltd., Yokohama, Japan
(June 20, 1973).
(57) Krill, N., and Storp, K., Chem. Eng., 80 (17), 84-85 (July 23, 1973).
(58) Anonymous, Oil & Gas J., 70 (26), 85-88 (June 26, 1972).
(59) Farrar, G. L., Oil & Gas J., _68 (42), 72-75 (October 19, 1970).
(60) Hobson, G. D., and Pohl, W., Modern Petroleum Technology, 4th Edition,
John Wiley & Sons, New York, N. Y. (1973), p 209.
(61) Cantrell, A., Oil & Gas J., 7J, (14)> 99-121 (April 2, 1973).
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APPENDIX F
PERTINENT METHODOLOGY INFORMATION
F-l
TABLE F-l. VISITS TO REFINERIES HAVING
TAIL-GAS-TREATMENT EQUIPMENT
Refinery/Location/Date
Tail Gas Process
Personnel Making Visit
Standard Oil of Cal.
El Segundo, Cal.
October 15, 1973
Douglas Oil Co.
Paramount, Cal.
October 16, 1973
Champlin Petrol. Co.
Wilmington, Cal.
October 18, 1973
Gulf Oil Co.
Philadelphia, Pa.
October 10, 1973
Gulf Oil Co.
Sante Fe Springs, Cal.
October 16, 1973
Atlantic Richfield Co.
Carson, Cal.
October 17, 1973
Mobile Oil Co.
Torrance, Cal.
October 18, 1973
Union Oil Co.
Wilmington, Cal.
October 19, 1973
Wellman-Lord
Shell Glaus Off-Gas
Treating (SCOT)
SCOT
Cleanair
Cleanair
Cleanair
Beavon
Beavon
C. S edman
R. Mayfield
C. Sedman
R. Mayfield
J. Genco
C. Sedman
C. Sedman
J. Durham
D. Mars land
C. Sedman
R. Mayfield
J. Genco
C. Sedman
R. Mayfield
J. Genco
C. Sedman
J. Genco
C. Sedman
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F-4
November 30, 1973
Mr. Gerald J. Smith, President
Davy Power Gas Company
P. 0. Box 2436
4715 South Florida Avenue
Lakeland, Florida 33803
Treatment of Glaus Plant Tall-Gas Streams
In Refinery Operations
Using the Wellman-Lord Process
Dear Mr. Smith:
The Environmental Protection Agency, Office of Air Programs, has engaged
Battelle-Columbus Laboratories to perform a technical review of processes
available for the recovery of sulfur from Glaus Plant tall-gas streams In
petroleum refineries (Contract 68-02-0611). This program Is being con-
ducted to provide EPA with technical Information for setting possible
sulfur-emission regulations from refinery-operated Glaus plants.
I understand that the Davy Power Gas Company is a leading process
engineering firm In the petroleum and petrochemical Industry and the
developer of the Wellman-Lord tall-gas process. It would be most helpful
to this study If you would provide the following technical Information
concerning the Wellman-Lord process:
(1) Process users - A list of the refineries, both
foreign and domestic, that are now using or plan
to use the Wellman-Lord tall-gas treating process.
Please give the location, size of the Glaus
sulfur plant being served, and the approximate
removal efficiency or pprc level being achieved
with the exhaust-gas stream from the tail-gas
unit (prior to Incineration).
(2) Process basis - A process-flow diagram and
a description of the technical basis for
Its operation.
(3) Material and energy balances - For a 100 LT/D
Clauo sulfur plant having a tail gas with the
-------
F-5
Mr. Gerald J. Smith November 30, 1973
properties shown In Table 1, can you pro-
vide approximate material- and energy-balance
information If the tall gas were to be
treated with the Wellman-Lord process?
(4) Process efficiency- In general, what Is the
lowest practical outlet-sulfur concentration
attainable with the Wellman-Lord process
(prior to Incineration), and what variables
does this depend on?
(5) Trace materials - How are Impurities such as
COS, CS2» and entrained sulfur (vapor and mist)
bandied?
(6) Process requirements - What are the approximate
utilities, i.e., fuel gas, electric power,
chemlcalc, steam, and cooling water and manpower
requirements for treating the tall gases from
100 and 1,000 MT/D Glaus plants? (Use Table 1
as a basis if need be.)
(?) Chemicals and catalysts - Are there any special
chemicals and catalysts required in the Wellman-
Lord process?
(8) Process changes - What is the effect of varying
the sulfur content of the crude, and of Increases
and decreases In crude through-put?
(9) Process waste streams - Are there any process^waste
streams generated in your tail-gas process?
(10) For a 100 MT/D Glaus sulfur plant (see Tablel),
how large are the waste streams, what is their
approximate composition, and how are they treated
and/or disposed of?
. pi>rectate greatly receiving the above Information as soon as
> For those questions and areas that may Involve proprietary
uci ,rt» please Indicate It In your reply. In this case, Battalle would
:-tsMxw to sign a secrecy agreement with your company If you so desire.
!», -ecc-iving the above Information, It Is likely that I will want to
- p-.-\\?\ to you or one of your colleagues to clarify my understanding
y
-------
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F-7
Mr. Gerald J. Smith November 30, 1973
Your kind assistance In this matter is greatly appreciated.
Sincerely yours,
Joseph H. Genco
Senior Engineer
Emissions Control and Environmental
Systems Division
JMGtclb
cc: Mr. Charles B. Sedman, Engineer
Industrial Studies Branch
Environmental Protection Agency
Durham, North Carolina 227711
Mr. James Durham, Section Chief
Industrial Studies Branch
Environmental Protection Agency
Durham, North Carolina 27711
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F-i
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1 REPORT NO. 2.
EPA-450/3-74-055
4 ~l FLE AND SUBTITLE
Characterization of Sulfur from Refinery
Fuel Gas
1 AUTHOR(S) , .
Joseph M. Genco
Samuel S. Tarn
9 f ERFORMING ORGANIZATION NAME AND ADDRESS
Battelle
Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
12 SPONSORING AGENCY NAME AND ADDRESS
Industrial Studies Branch
Office of Air Quality Planning & Standards
Research Triangle Park, N.C. 27711
3. RECIPIENT'S ACCESSION-N
5. REPORT DATE Datfi Of
June 28, 1974
6. PERFORMING ORGANIZAT
8. PERFORMING ORGANIZAT
10. PROGRAM ELEMENT NO
11. CONTRACT/GRANT NO.
68-02-0611, Task 4
13. TYPE OF REPORT AND PE
Final
14. SPONSORING AGENCY CO
15 SUPPLEMENTARY NOTES
Processes for removing and recovering sulfur from refinery fuel gas are reviewed,
Flowsheets, heat and material balances for Glaus sulfur recovery plants and
commercially available processes for sulfur removal from Glaus tail gas are
presented. Statistics on sulfur recovery systems in refineries are presented
for 1973 and projected for 1975. The environmental impact of tail gas
processes including emission reduction, liquid arid solid by-products, and
.y-cr'-gy consumption is discussed.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Jesi;l furl zation
i ; ", M c ; ,\ T £. |V1 E N T
'!" (•>->. Unlimited
b.IDENTIFIERS/OPEN ENDED TERMS
19 SECURITY CLASS (This Report)
Unclassified
20 SECURITY CLASS (This page)
Unclassified
c. COSAFI t icld/Gtou 5
21 NO OF PAGES
142
22 PRICE
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