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.

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                                   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.

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                                   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
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o

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-------
          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.

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                                    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.

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                                   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.

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                                     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

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                                    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

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                                        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

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                                   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

-------
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                             48
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.

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                                    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

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                                    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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                                    52

          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

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                                    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.

-------
                         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.

-------
                                                       56
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                                    57
       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.

-------
                                    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.

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                              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.

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                               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.

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                                    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

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                             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.

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                                    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.

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                                          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

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          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

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                                   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.

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 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) .

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                        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.

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                                   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

-------
                                   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.

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                                      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.

-------
81


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-------
                                   82
          (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.

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                                   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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                                                                                89
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-------
                                   90

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

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                         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

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                         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.

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                                         99

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-------
                                      100

                                     REFERENCES
                                     (Continued)

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                                      101

                                     REFERENCES
                                     (Continued)

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      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

-------
                                       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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