EPA-R2-73-188

April 1973                Environmental Protection Technology Series
Characterization
of Glaus Plant Emissions
                                Office of Research and Monitoring
                                U.S. Environmental Protection Agency
                                Washington, D.C. 20460

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                                        EPA-R2-73-188

     Characterization

                 of

Glaus  Plant  Emissions
                  by

              W. D. Beers

         Processes Research, Inc.
            2912 Vernon Place
          Cincinnati, Ohio 45219
     Contract No. 68-02-0242, Task No.  2
         Program Element No. 1A2013
    EPA Project Officer:  G. S. Haselberger

         Control Systems Laboratory
    National Environmental Research Center
 Research Triangle Park, North Carolina 27711
              Prepared for

      OFFICE OF RESEARCH AND MONITORING
     U. S.  ENVIRONMENTAL PROTECTION AGENCY
          WASHINGTON, B.C. 20460

               April 1973

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This report has been reviewed by the Environmental Protection Agency



and approved for publication.  Approval does not signify that the



contents necessarily reflect the views and policies of the Agency,



nor does mention of trade names or commercial products constitute



endorsement or recommendation for use.
                                    11

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                 PROCESSES  RESEARCH, Iisrc.
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                            ACKNOWLEDGMENT


     The author wishes to acknowledge the  assistance of Messrs.  R.  I.  Tarver

and G.  N.  Thomas in the development of this  report, the helpful  guidance  and

critique by  Messrs. G. S. Haselberger and  M. R. Jester, and the  contributions

to the  report by firms whose information appears in the Appendix.   In  addition,

the author wishes to acknowledge the many  sources of information used  and

referred to  in the Bibliography.


                                                     W. D. Beers
                                  iii

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                 PROCESSES  RESEARCH, INC.
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                          CHARACTERIZATION OF
                         CLAUS PLANT EMISSIONS
                                 INDEX
Section

    I

   II

  III
                 Title
Introduction
   IV
Summary

Claus Sulfur Plant  Technology

A.  Claus Process Variations
B.  Feed Gas Concentration
C.  Product Sulfur  Capacity
D.  Claus Sulfur Recovery
E.  Claus Tail Cas
F.  Information from Claus Plant Operating and
      Design Firms

Claus Sulfur Plants in  the United States
Page

  1

  2
                                                                          4
                                                                          7
                                                                          8
                                                                          9
                                                                          9

                                                                         10
    V

   VI
A.  Claus Sulfur  Production
B.  Claus Plant Emissions
C.  Companies Operating Claus Plants
D.  Claus Plant Design Firms

Claus Sulfur Plants  in Canada

Reduction of Claus Plant Emissions

A.  Flue Gas Desulfurization Processes
B.  Beavon Sulfur Removal Process
C.  Cleanair Sulfur  Process
D.  Institut Francais du Petrole Process
 11
 11
 13
 14

 15

 16

 17
 17
 19
 19
Appendix

    A
    B
    C
    D
    E
Map of United States  Claus Plants
Claus Process Flow Diagrams
Claus Sulfur Plant Data
Claus Sulfur Plants in Canada
Amoco Production Company  Information
                                   iv

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Appendix                        Title

    F          Elcor Chemical  Corporation Information
    G          Shell Oil Company Information
    H          Stauffer Chemical Company Information
    I          Ford, Bacon & Davis Information
    J          The Ralph M. Parsons Company Information
    K          J. F. Pritchard & Co. Information
    L          Chiyoda Chemical Engineering & Construction Co., Ltd.
                 Information
    M          Institut Francais du Petrole Information
    N          Wellman-Power Gas Information
    0          Bibliography

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                   PROCESSES  RESEARCH, INC.
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                       SECTION I - INTRODUCTION


     Glaus plants produce sulfur from hydrogen sulfide and  sulfur dioxide by gas

phase reactions.  Numerous Claus sulfur plants are operated in  the United States

in connection with  natural gas and petroleum refining.

     Because of  the apparent potential for atmospheric pollution from unconverted

hydrogen sulfide and  sulfur dioxide in Claus plant tail gas,  a  survey was under-

taken to collect information concerning Claus sulfur plant  emissions and control.

     The present report is based on review of literature, supplemented with data

from companies operating and/or designing Claus plants.

     In view of  the rapid pace at which changes are taking  place  in Claus plant

technology and applications,  the plant inventories and bibliography presented  in

this report should  be dated.  The inventory of Claus plants in  Canada was com-

pleted in December  1971.  The inventory of Claus plants in  the  United States,  and

the bibliography were completed in June 1972, based on current  publications.

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                          SECTION II - SUMMARY


     Glaus sulfur  plants  convert hydrogen sulflde and sulfur dioxide to  sulfur

by gas phase reactions  near atmospheric pressure, using catalysts in the final"

stages.  A number  of  Claus process variations are used to accommodate various

concentrations of  acid  gas feed.

     There are 169 Claus  sulfur plants in the United States having rated daily

capacities totaling over  15,800 long tons.  Most of these plants are based  on

acid gas from natural gas or petroleum refining.

     Claus plants  are found in 31 states.  The number in each state is shown on

the map of the United States in Appendix A.

     The tail gas  from  a  Claus plant contains hydrogen sulfide (l^S) and sulfur

dioxide (S02>, but the  tail gas is usually burned, converting the H2S to sulfur

oxides.  The annual emissions from Claus sulfur plants in the United States are

estimated to total 875,000 short tons of SC-2 equivalent.  The estimated  Claus

plant emission for each state is shown on the map in Appendix A.

     These estimates  assume that the Claus sulfur production averages 60 percent

of the rated plant capacity and that the Claus sulfur recovery averages  90  per-

cent.  Additional  catalytic stages could increase the Claus sulfur recovery to

about 97 percent,  eliminating 70 percent of the Claus plant emissions.

     The Beavon Sulfur  Removal Process and the Cleanair Sulfur Process are  claimed

to increase sulfur recovery to more than 99.9 percent, eliminating about 99 percent

of Claus plant sulfur emissions.  The investment and operating costs for Claus-

Beavon plants or Claus-Cleanair plants are about twice those for Claus plants

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alone.   Hence, the production costs for Claus-Beavon sulfur or Claus-Cleanair  sul-

fur are about twice those for Glaus sulfur.

     The Institut Francais du Petrole  (IFF) Process is claimed to increase the

sulfur  recovery to more than 99  percent, eliminating about 90 percent of Glaus

plant emissions.  The investment and operating costs for an IFF addition is about

half of those for the Glaus sulfur plant alone.  Accordingly, the production costs

for Claus-IFP sulfur are about 50 percent higher than those for Glaus sulfur.

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               SECTION  III - GLAUS SULFUR PLANT TECHNOLOGY


     Glaus plants produce elemental sulfur from the t^S in acid  gas obtained

principally from natural gas and petroleum refining.  They are named after an

English chemist, C.  F.  Glaus, who, about 1885, initiated development of the gas

phase process used in such plants.

     The number of Glaus sulfur plants in each state and annual  sulfur emissions

are shown on the map of the United States in Appendix A.  The basis of the Glaus

plant emissions shown is explained later in this report.

     A.  GLAUS PROCESS  VARIATIONS

         Flow diagrams  presented in Appendix B are typical of the  four principal

variations used in Glaus sulfur plants in the United States,  as  follows:

         Direct oxidation
         Split flow
         Straight through
         Sulfur recycle

These are gas phase processes as distinguished from liquid phase processes such

as the Deal-Sulfolane (Shell Oil Company), Giammarco-Vetrocoke,  Ferrox, Lacy-

Keller, Perox, Stretford, Thylox, and Townsend processes for  producing elemental

sulfur from l^S.

         A Glaus sulfur plant usually operates near atmospheric  pressure with

only enough extra pressure to overcome the pressure drop through the plant.

         1.  Direct Oxidation.  In the original Claus process, called "direct

oxidation," H2S was partially oxidized with air over a bauxite or  iron ore

catalyst in a single reactor, as follows:

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             3H2S + 1.502  	>   3S +  3H20 + 159,000 calories

Excessive temperatures experienced with this highly exothermic reaction resulted

in poor yields.   This soon led  to  partial recycle of the tail gas to control the

temperatures for acceptable yields.

             This process is used  in modern plants having dilute acid gas feed.

The sulfur recovery is increased by adding catalytic stages.

         2.  Split Flow.   About 1937, I. G. Farbenindustrie A. G. initiated two

improvements in the Claus process, one  or the other of which appears in many

Glaus plants in the United States. In  the first of these, called "split flow,"

one third of the H2S is burned  completely to sulfur dioxide  (S02) in a waste

heat boiler, as follows:

             H2S + 1.502   	>  S02 +  H20 + 131,000 calories

The S02 is then reacted with the other  two thirds of the H2S over bauxite at

about 385C, as follows:

             2H2S + S02   	> 3S + 2H20 + 28,000 calories.

Thus, only about one fifth of the heat is evolved in the catalytic reactor.  Satis-

factory temperatures are  attained  in much smaller reactors, and much of the heat

of combustion is recovered as useful steam.

         3.  Straight Through.  The second I. G. Farben improvement, called

"straight through," is the noncatalytic partial oxidation of the H2S to sulfur

with air at temperatures  up to  1000C in a waste heat boiler.  About 60 percent

conversion to sulfur is achieved,  and the flue gas is cooled and passed to the

catalytic reactor for the remaining conversion.  In this variation of the Claus

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Process, much of the  reaction heat is recovered as useful steam, and some sulfur

may be condensed from the  flue  gas to improve the conversion in the catalytic

reactor.

         4.   Sulfur Recycle.  The acid gas streams feeding Claus plants sometimes

contain so little H2S that reaction  temperatures cannot be maintained without

supplemental heat.   This gives  rise  to additional Claus plant variations, includ-

ing addition of hydrocarbons to acid gas ahead of the burner and/or indirect

preheating of the acid gas and/or air ahead of the burner or catalytic reactor.

             One Claus plant variation, particularly useful for dilute acid gas

having low sulfur oxide content, is  called "sulfur recycle."  In this, some

product sulfur is burned with air to produce SC>2 and heat.

             The acid gases fed to Claus plants in the United States usually con-

tain little or no sulfur oxides, because they are from the "sweetening" units of

natural gas plants and petroleum refineries.  These sweetening units usually

capture the H2S and the carbon  dioxide, but seldom remove sulfur oxides from the

natural gas or refinery gas.

             On the other  hand, the  acid gas fed to a Claus plant from a smelter

contains sulfur oxides as  well  as l^S.  The "direct oxidation" process probably

would be ideal for such a  feed  gas.

         5.   Conversion Incomplete.  The Claus Process reactions are reversible,

and complete conversion to sulfur is prevented by the sulfur vapor and water

vapor produced.  Attempts  to improve conversion by operating the catalytic re-

actors at temperatures below the sulfur dewpoint have not succeeded.  The liquid

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sulfur apparently blocks  the catalyst.  Instead, improved conversion is achieved

by condensing sulfur  from the  gas stream between Claus stages.  With a dilute acid

gas stream feeding a  Claus plant, less sulfur need be condensed between the Claus

stages to keep the sulfur dewpoints below the catalyst surface temperatures.

Nevertheless, improved conversion for such a dilute feed will still result from

condensing sulfur between Claus  stages.  In a modern Claus plant, more than half

of the sulfur is condensed ahead of the final catalytic stage.

             Removal  of water  vapor to improve conversion to sulfur has also been

tried by condensing water from the gas stream between catalytic stages.  Because

of plugging and highly corrosive conditions, these attempts have all been unsuc-

cessful.

         6.  Reheat Variations.  The reheating of the gas stream after condensing

sulfur presents several Claus  plant variations, as follows:

             a_.  External-fired  heat exchange.

             b_.  Internal gas-to-gas heat exchange.

             c_.  Injection of  hot gas from hydrogen sulfide burner.

             d_.  Injection of  hot gas from a hydrocarbon burner.

             e_.  Injection of  hot gas from upstream.

             While the choice  of reheating methods is important in adapting the

Claus Process to particular plant circumstances, these variations appear to have

little effect on the  sulfur recovery efficiency of Claus plants.

     B.  FEED GAS CONCENTRATION

         1.  Process  Choice.   The optimum process arrangement for a Claus plant

depends largely on the hydrogen  sulfide concentration in the acid gas feed.  For

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high HoS concentrations,  such as 90 mole percent, the "straight  through" process

is preferred.   For intermediate concentrations, such as 50 mole  percent H2S, the

"split flow" process  is  suitable.  Low l^S concentrations, such  as  15 mole per-

cent, favor the "direct  oxidation" process, or sometimes the "sulfur recycle"

process.

         2.  Claus Plant Costs.  The greater gas volumes involved with more

dilute acid gas increase the Claus plant investment and sulfur production costs

somewhat.  For typical Claus plants, each to produce 100 long tons  of sulfur

daily, the investment and sulfur production costs for various acid  gas concentra-

tions are approximately  as follows:
Mole Percent H2S
In Acid Gas Feed
15
50
90
PRODUCT SULFUR CAPACITY
Claus Plant
Investment
$1,400,000
$1,000,000
$ 900,000

Sulfur Production
Cost Per Long Ton
$14
$11
$ 9

         Product sulfur capacity has a more pronounced effect on Claus  plant

investment and sulfur production costs.  For typical Claus plants fed with

50 mole percent H2S feed gas,  the  investment and sulfur production costs  for

various capacities are approximately as follows:

         Product Sulfur
         Daily Capacity                Claus Plant         Sulfur Production
          (Long Tons)                  Investment          Cost Per Long Ton

                10                     $  300,000                $26
               100                     $1,000,000                $11
              1000                     $4,300,000                $ 8

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     D.  GLAUS SULFUR RECOVERY

         The percent conversion to sulfur is affected by the number of  catalytic

stages in Claus plants.   For Glaus plants fed with 90 mole percent H2S, the

sulfur recovery variation relative to the number of catalytic stages is approxi-

mately as follows:

             Number of Catalytic  Stages              Percent Sulfur Recovery

                          1                                    85
                          2                                    94
                          3                                    97

         The percentage  of sulfur recovery also varies with the concentration of

the acid gas fed to the  Claus plant.  For Claus plants having two catalytic stages,

the sulfur recoveries for various acid gas concentrations are approximately as

follows:

         Mole Percent H2S                      Percent Sulfur Recovery
         In Acid Gas Feed                      Two Catalytic Stages

                15                                        90
                50                                        93
                90                                        94

     E.  CLAUS TAIL GAS

         The unrecovered sulfur appears in the Claus plant tail gas principally

as H2S, elemental sulfur, and S02 with lesser amounts of other sulfur compounds.

Some of the early Claus  plants vented the tail gas directly to the atmosphere.

Others scrubbed the tail gas in towers packed with limestone wetted with water.

Incineration of the tail gas is the method most often used in United States

Claus plants treating the tail gas.  Incineration converts the unrecovered sulfur

almost entirely to  sulfur oxides.

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         For  a Claus plant recovering 100  long tons of sulfur daily,  the  incin-

erator stack  gas sulfur dioxide equivalents, for various numbers of catalytic

converters, and various acid gas feed concentrations, are approximately as

follows:

           Number of            Mole Percent H2S         Stack Gas S02
         Catalytic Stages        In Acid Gas Feed        Short Tons Daily
1
2
2
2
3
INFORMATION
90
15
50
90
90
FROM CLAUS PLANT OPERATING AND
39
25
17
14
7
DESIGN FIRMS
         In response to questionnaire letters,  information regarding Claus sulfur

plants was submitted by the following operating firms and design firms:

                     Amoco Production Company
                     Elcor Chemical Corporation
                     Shell Oil Company
                     Stauffer Chemical Company
                     Ford, Bacon & Davis
                     The Ralph M. Parsons  Company
                     J. F. Pritchard & Co.

Information submitted by these firms is presented in Appendices E, F, G,  H, I,

J, and K,  respectively.
                                  10

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          SECTION IV - GLAUS  SULFUR PLANTS:IN THE UNITED STATES


     The rated sulfur capacities  are  published for many United States Claus plants.

These are listed in Appendix  C.   In addition to the operating company names and

locations, the Claus plant ages and sources of acid gas feeds are listed for most

of the plants.  For the 169 plants listed, the rated daily sulfur capacities total

more than 15,800 long tons.

     A.  CLAUS SULFUR PRODUCTION

         The annual sulfur production is  published for twenty-three Claus plants

based on natural gas, having  rated daily  sulfur capacities totaling 2,068 long

tons.  The annual sulfur production from  these recently totaled 456,000 long

tons.  If this proportion is  typical  for  all United States Claus plants, bearing

in mind that some are standby and others  not yet in operation, the annual sulfur

production from United States Claus plants totals approximately 3,500,000 long

tons.

     B.  CLAUS PLANT EMISSIONS

         The acid gas feed composition, number of catalytic stages, and tail gas

treatment, if any, are seldom published for United States plants.  However, it

seems probable that the typical Claus plant in the United States has two cataly-

tic stages and the tail gas is burned.

         Assuming that the sulfur recovery averages 90 percent, bearing in mind

that many plants appear to have excess sulfur capacity, improving their perform-

ance, the annual emissions from United States Claus plants are equivalent to

approximately 875,000 short tons  of S02.
                                   11

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         On this basis,  Che emissions from Glaus plants in various areas of the

United States are approximately as follows (a plus sign,  + ,  denotes some plant
capacity not reported):
         Area

     Alabama
     Alaska
     Arkansas
     Los Angeles
     Other California
     Colorado
     Delaware
     Florida
     Hawaii
     Illinois
     Indiana
     Kansas
     Louisiana
     Michigan
     Minnesota
     Mississippi
     Missouri
     Montana
     New Jersey
     New Mexico
     New York
     North Dakota
     Ohio
     Oklahoma
     Pennsylvania
     £1 Paso, Texas
     Midland, Texas
     Lubbock, Texas
     Amarillo, Texas
     San Antonio, Texas
     Corpus Christi, Texas
     Houston, Texas
     Beaumont, Texas
     Dallas, Texas
     Utah
     Virginia
     Washington
  Number of
Glaus Plants

      2
      1
      4
     14
      6
      1
      2
      4
      1
      4
      3
      2
      6
      3
      2
      5
      1
      3
      8
      7
      1
      2
      3
      2
      6
      2
     20
      5
      3
      7
      1
      5
      5
     10
      2
      1
      1
Combined Daily
Sulfur Capacity
  (Long Tons)

      386
        9
      185
    1,794+
      902
       18
      775
      664
      +
      569
      414
       44
      570
       89
      170
    1,327+
       80
      233
      647+
      147
       50
      243
       95
       23
      452
    1,009
      592
       93
       76
      276
       85
      696+
      358
    1,685
       22
       50
       20
   Computed
Annual Emission
S02 Equivalent
 (Short Tons)

    21,400
       500
    10,200
    99,300+
    49,900
     1,000
    42,900
    36,700
       +
    31,500
    22,900
     2,400
    31,500
     4,900
     9,400
    73,500+
     4,400
    12,900
    35,800+
     8,100
     2,800
    13,500
     5,300
     1,300
    25,000
    55,800
    32,800
     5,200
     4,200
    15,300
     4,700
    38,500+
    19,800
    93,300
     1,200
     2,800
     1,100
                                   12

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         Area

     West Virginia
     Wisconsin
     Wyoming	
     Total United  States
     Total Texas
     Total California
  Number of
Claus Plants

       1
       1
      12
      58
      20
Combined Daily
Sulfur Capacity
  (Long Tons)

       27
       15
      919
   15,809+
    4,870+
    2,696+
   Computed
Annual Emission
S02 Equivalent
 (Short Tons)

     1,500
       800
    50.900
   875,000+
   269,600+
   149,200+
         The number  of Claus plants and annual Claus plant emission for  each  state

are shown on the map of  the United States in Appendix A.

     C.  COMPANIES OPERATING CLAUS PLANTS

         The leading operators of Claus sulfur plants in the United States  include

the following companies:

         Allied Chemical Corporation
         Amarillo Oil Company
         American Oil Company  (Standard Oil Company, Indiana)
         Amoco Production Company  (Standard Oil Company, Indiana)
         Ashland Oil, Inc.
         Atlantic Richfield Company
         BP Oil Corporation  (Standard Oil Company, Ohio)
         Chevron Oil Company  (Standard Oil Company of California)
         Cities Service  Oil Company
         Continental Oil Company
         Getty Oil Company
         Gulf Oil Corporation
         Humble Oil  & Refining Company
         Marathon Oil Company
         Mobil Oil Corporation
         Monsanto Company
         Olin Corporation
         J. L. Parker Company
         Phillips Petroleum Company
         Shell Oil Company
         Signal Oil  & Gas Company
         Stauffer Chemical Company
         Sun Oil Company
         Texaco, Inc.
         Union Oil Company of California
         Warren Petroleum Corporation
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     D.   GLAUS PLANT DESIGN FIRMS

         A number of firms are experienced  designers of Glaus sulfur plants  in

the United States, including the following:

         Black Sivalls & Bryson, Inc.
         Delta Engineering Corporation
         Dresser Engineering Corporation
         Fluor Corporation
         Ford, Bacon & Davis, Inc.
         Howe-Baker Engineers, Inc.
         Hudson Engineering Corporation
         The Ortloff Corporation
         The Ralph M. Parsons Company
         J. F. Pritchard & Company
         Pona Engineers, Inc.
         Steams-Roger Corporation
         Weatherby Engineering Corporation
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               SECTION V - CLAUS  SULFUR PLANTS IN CANADA


     Information regarding Claus sulfur plants located  in Canada is presented  in

Appendix D.  The daily sulfur capacities of the 66 Canadian plants listed total

more than 25,400 long tons.  This  is about 60 percent more than the combined daily

sulfur capacity of 169 Claus plants located in the United States.

     About 93 percent of the Canadian Claus sulfur capacity is based on Alberta

natural gas, and are located upwind of the population centers in the northern

United States,
                                  15

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             SECTION VI - REDUCTION OF GLAUS PLANT EMISSIONS


     Beyond the addition of Claus catalytic stages, the following methods have

been proposed to reduce sulfur emissions from Claus plants in the United States:

     Alberta Sulfur Research, Ltd. Sulphoxide Process
     Rhodia, Inc. Cataban Process
     Union Carbide Process
     Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process
     Wellman-Lord Sulfur Dioxide Recovery Process
     Monsanto NOSOX Process
     Takahax Process
     Beavon Sulfur Removal Process
     Cleanair Sulfur Process
     Institut Francais du Petrole Process

     The Alberta Sulfur Process, Ltd. Sulphoxide Process is claimed to reduce

Claus tail gas sulfur contents to less than 1000 ppm.  This process uses an

organic sulphoxide as a liquid catalyst medium in which to react the H2S and S02

to form elemental sulfur.  The COS and CS2 are converted to C02 and sulfur.  The

process has been operated in  the laboratory.  Application to a full-scale plant

remains to be done.

     The Rhodia, Inc. Cataban Process, which has been developed through the pilot

plant stage, uses an aqueous  solution of a chelated iron salt as a liquid phase

catalyst, oxidizing hydrogen  sulfide to elemental sulfur.  Texas Gulf Sulfur and

another company are reported  to be investigating the use of this process for re-

ducing Claus plant sulfur emissions.

     The Union Carbide Process is reported as using a new catalyst in an absorp-

tive operation.  It  is claimed that this process can reduce Claus tail gas sulfur

contents to about 50 ppm0  Union Carbide Corporation is expected to announce soon

further information about  this process.
                                   16

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     A.   FLUE GAS  DESULFURIZATION PROCESSES

         Numerous  processes being developed for removal of sulfur dioxide from

power plant stack  gas  appear applicable to incinerated Claus tail gas.   As the

S02 concentrations are several  times higher in incinerated Claus tail gas than

in power plant stack gas,  the treatment of the incinerated Claus tail gas appears

somewhat easier.

         1.  Two such  processes now being vigorously advocated in the United

States are the Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process and  the

Wellman-Lord Sulfur Dioxide Recovery Process.

             Information regarding the Chiyoda process was submitted by Chiyoda

Chemical Engineering & Construction Co., Ltd., in connection with their adver-

tisement in Hydrocarbon Processing.  This information is presented in Appendix L.

             Information regarding the Wellman-Lord process was obtained by

Environmental Protection Agency personnel on visits to plants in Japan where  this

process is in operation.  This  information is presented in Appendix N.

         2.  Monsanto  Enviro-Chem Systems, Inc., is reported to be developing its

NOSOX Process to remove sulfur  dioxide from incinerated Claus tail gas.

         3.  Ford, Bacon & Davis has recently been licensed to use the Takahax

Process of Tokyo Gas Company.   This process is reported to use an alkaline solu-

tion to scrub the  Claus tail gas and to produce elemental sulfur.

     B.  BEAVON SULFUR REMOVAL  PROCESS

         The Beavon Sulfur Removal Process is reported to have been proven in a

pilot plant by cooperation of The Ralph M. Parsons Company and Union Oil Company

of California. Union  Oil is said to be planning to use this process at their
                                   17

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Los Angeles refinery (Wilmington, California), where Union Oil already has  a

Claus sulfur plant.

         The process is named  for David K-. Beavon, Director of Process Operations

for The Ralph M. Parsons Company.

         A flow diagram for  this process is presented in Appendix J,  together

with information submitted by  The Ralph M. Parsons Company.  The process is

claimed to reduce the tail gas sulfur content to 40 to 80 ppm equivalent S02,

depending on the sulfur content of  the Claus tail gas before treatment.

         In the Beavon Process, the Claus plant tail gas is mixed with hot  com-

bustion gas produced by burning fuel gas with air.  The resulting reducing  mixture

is passed through a  catalytic  reactor resembling that of a Claus plant.  On the

cobalt-molybdate catalyst, all of the sulfur is hydrogenated to H2S.   Water is

then condensed from  the gas.   The cooled gas stream is passed to a Stretford

section in which the l^S is  removed from the gas and converted to elemental sul-

fur.  The Stretford  process  is widely used outside of the United States and one

Stretford unit was recently  installed at Long Beach, California, to sweeten natural

gas.

         The Beavon  Sulfur Removal  Process addition to an existing Claus plant

costs about as much  as the Claus plant itself.  With the doubled fixed costs and

added utilities costs, the production cost for Claus-Beavon sulfur is approximately

twice that for Claus sulfur.   Hence, the inventor is promoting this process, not

as an economical method for  producing sulfur, but strictly as a pollution abate-

ment alternative.
                                  18

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                  PROCESSES  RESEARCH, INC.
                  INDUSTRIAL PLANNING AND RESEARCH
     C.  CLEANAIR SULFUR PROCESS

         The Cleanair  Sulfur Process of J. F. Pritchard & Co.,  was developed with

Texas Gulf Sulfur Company at the Okotoks, Alberta, Canada Claus sulfur plant.

This process is being  used  in a revision of the sulfur plant in the Gulf Oil

Corporation refinery at Philadelphia, Pennsylvania.  This process is claimed to

reduce the tail gas sulfur  content to less than 250 ppm by volume of equivalent

S02 without incineration or dilution.  This would indicate an overall Claus-

Cleanair sulfur recovery of approximately 99.9 percent.

         Information regarding the Cleanair Sulfur Process submitted by J.  F.

Pritchard & Co., is presented in Appendix K.  This process includes a Stretford

section, as does the Beavon Sulfur Removal Process already described.  The  Long

Beach, California, Stretford unit previously mentioned was built by J. F.

Pritchard & Co.

         For a Claus-Cleanair sulfur plant, the investment and operating costs

are about twice those  for a Claus plant having the same sulfur production capacity,

     D.  INSTITUT FRANCAIS  DU FETROLE PROCESS

         The Institut  Francals du Petrole (IFP) Process has been in operation  in

a Japanese refinery for several months, recovering sulfur from Claus tail gas.

Four more IFP units, three  in Japan and one in Canada, are reported to be starting

operation.  Information regarding this process submitted by Institut Francais  du

Petrole is presented in Appendix M.

         The IFP process is claimed to reduce the incinerator stack gas sulfur

content to about 1500  ppm S02 for an overall Claus-IFP sulfur recovery of about
                                  19

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                 PROCESSES  RESEARCH, INC.
                 INDUSTRIAL PLANNING AND RESEARCH
99 percent.  The residual  sulfur emission occurs principally because the carbonyl

sulfide (COS) and carbon disulfide (CS2> in the Claus tail gas are not converted

by the IFF process.  The investment and operating costs for an IFF unit are about

half of those for the Claus  sulfur plant alone.  Hence, the addition of the IFF

unit results in Claus-IFP  sulfur production costs about 50 percent higher than

those for Claus sulfur.
                                 20

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    PROCESSES RESEARCH, INC.
    INDUSTRIAL PLANNING AND RESEARCH
APPENDIX A - MAP OF UNITED STATES CLAUS PLANTS
                 21

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AMHUAL  CLAUS  SULFUR PLANT
                                                                         BY  STAT£S>
N>

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  PROCESSES  RESEARCH, INC.
  INDUSTRIAL PLANNING AND RESEARCH
APPENDIX B - GLAUS PROCESS FLOW DIAGRAMS
               23

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 109
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      EPA
PROCESSES  RESEARCH, IMC.   F.I, HO
Lo< Jlion
    INDUSTRIAL PLANNING
       AND  RESEARCH
                               CINCINNATI
                                               NEW YORK
Checked by

Computed by
                                                               SULFUR. PIT
                                                                 LIQUID
                                            CLAUS

-------
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     6FA.
PROCESSES RESEARCH, INC.   f,ie No
Location

Subject
     UN tree*
    INDUSTRIAL PLANNING
      AND  RfSEARCH
CINCINNATI
                                            NEW YORK
                                                      Chededby

                                                      C°mH'"e<' by
_Shcel No

	Date .

   Dale i
            SPL;T FLOW CLAUS
                                  25

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  109
Job
       UNITSD STATES
location
PROCESSES  RESEARCH,INC.

    INDUSTRIAL PLANNING
       AND  RESEARCH
                                  CINCINNATI
File No


Checked by
                                                                                    No
                                   QB
NEW YORK    t"":P«'^ hv.
Acio
                                           CLAUS
                                         26

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PR 109
Job.
       SPA
Location


Subject .
       UHITSD
PROCESSES  RESEARCH, INC.

    INDUSTRIAL PLANNING
       AND  RESEARCH
                                  CINCINNATI
                                                   NEW YORK
                                                               f i le No
                                                               Cheded by
                                                               Computed hy  [JJ
.ShcH No


	Datf .


  . Dale
                                                   APKJL-
                                                   #73
                                             CLAUS
                                         27

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 PROCESSES RESEARCH, INC.
 INDUSTRIAL PLANNING AND RESEARCH
APPENDIX C - GLAUS SULFUR PLANT DATA
             28

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                     PROCESSES  RESEARCH, INC.
                     INDUSTRIAL PLANNING AND RESEARCH
State/Company/City,  County

ALABAMA
  Humble Oil & Refining Co.
        Flomaton,  Escambia
  Stauffer Chemical  Co.
        LeMoyne
        Expansion
ALASKA
  Energy Co. Alaska
        Fairbanks, North  Star
ARKANSAS
  Arkla Chemical Corpo
        Magnolia,  Columbia
        Expansion
  The Bromet Co.
        Magnolia,  Columbia
  Monsanto Co.
        Eldorado,  Union
  Olin Corp.
        McKamie, Lafayette
CALIFORNIA
  Monsanto Co.
        Avon
  Union Oil Co. of California
        Santa Maria, Santa Barbara
  Allied Chemical  Corp.
        Richmond,  Contra  Costa
        Expansion
  Humble Oil & Refining Co.
        Benicia, Solano
  Shell Oil Co.
        Martinez,  Contra  Costa
  Union Oil Co. of California
        San Francisco, San Mateo
        Expansion
  Allied Chemical  Corp.
        El Segundo,  Los Angeles
        Expansion
  Atlantic Richfield Co.
        Wilmington,  Los Angeles
  Collier Carbon and Chemical Corp.
        Los Angeles, Los  Angeles
       Year
       Sulfur       Acid
       Production   Gas
       Started      So.urce
             Daily
             Sulfur
             Capacity
             Long
             Tons
       1972

Before 1962
Before 1972
       1972
Natural Gas   136

Natural Gas   127
Natural Gas  +123
Refinery
Before 1962
1962
1970
Before 1961
1944
Before 1967
1954
Before 1962
1968
1969
1966
1955
1971
1959
1964
1967
Before 1972
Natural Gas
Natural Gas
Chemical
Refinery
Natural Gas
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery

19
+11
30
25
100
132
55
100
+100
270
100
70
+75
175
+100
65
Not







Two Trains


Standby

Reported
                                     29

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                    PROCESSES  RESEARCH, INC.
                    INDUSTRIAL  PLANNING AND RESEARCH
State/Company/City, County

CALIFORNIA
  Continental Oil  Co.
        Paramount, Los Angeles
  Fletcher Oil & Refining Co.
        Wilmington, Los Angeles
  Golden Eagle Refining Co. Inc.
        Torrance,  Los Angeles
  Gulf Oil Corp.
        Santa Fe Springs, Los Angeles
        Expansion
        Expansion
  Lomita Gasoline  Co.
        Long Beach, Los Angeles
  Mobil Oil Corp.
        Torrance,  Los Angeles
        Expansion
  Powerine Oil Co.
        Santa Fe Springs, Los Angeles
  Standard Oil Company of California
        El Segundo, Los Angeles
  Stauffer Chemical Co.
        Wilmington, Los Angeles
        Expansion
        Expansion
        Expansion
        Expansion
        Expansion
  Texaco, Inc.
        Los Angeles, Los Angeles
  Union Oil Co. of California
        Willmington, Los Angeles
        Expansion
        Expansion
COLORADO
  Continental Oil  Coo
        Denver, Adams
DELAWARE
  Getty Oil Co.
        Delaware City, New  Castle
  Stauffer Chemical Co.
        Delaware City, New  Castle
        Expansion
      Year
      Sulfur
      Production
      Started
Acid
Gas
Source
Daily
Sulfur
Capacity
Long
Tons
1966
Before 1962
1959
Before 1961
Before 1962
1964
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
9
7 Standby
4 Standby
8
9
13
       1971
Before 1962

       1952
       1962
       1973
       1968
       1956

Before 1962
Before 1972
Natural Gas   Not Reported
1967
1973
1967
1972
Before 1962
Before 1962
1962
1964
1967
Before 1972
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
85
Not
20
450
100
+20
+140
+8
+132
+50
Refinery

Refinery
Refinery
Refinery
Refinery
Refinery

Refinery
Refinery
  50

  49
+100
+200
  18
 375

 260
+140
                                    30

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                   PROCESSES  RESEARCH, INC.
                   INDUSTRIAL PLANNING AND RESEARCH
State/Company/City,  County

FLORIDA
  Amerada Hess Corp.
        Jay,  Santa Rosa
  Humble Oil  & Refining  Co.
        Jay,  Santa Rosa
        Expansion
  Louisiana Land & Exploration Co.
        Jay,  Santa Rosa
  Louisiana Land & Exploration Co.
        Escambia County
HAWAII
  Dillingham  Petroleum Corp.
        Barbers Point, Honolulu
ILLINOIS
  Anilin Company of  Illinois
        Wood  River,  Madison
  Marathon Oil Co.
        Robinson, Crawford
  Mobil Oil Corp.
        Joliet, Will
  Union Oil Co. of California
        Lemont, 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
  Cities Service Oil Co.
        Lake  Charles, Calcasieu
       Year
       Sulfur
       Production
       Started
       1972

       1971
       1972

       1972

       1972


       1972


       1960

       1970

       1972
Acid
Gas
Source
Daily
Sulfur
Capacity
Long
Tons
Natural Gas   120

Natural Gas    14
Natural Gas  +360

Natural Gas    82

Natural Gas    88
Refinery


Refinery

Refinery

Refinery
 Not Reported


 150

  40

 300
Before 1961
       1964
       1971
       1952
       1964
       1972
       1972

       1971

       1972
       1968

       1968


       1972
Refinery       20
Refinery      +34
Refinery      +25
Refinery       64
Refinery      +40
Refinery      +43
Refinery     +132
Refinery

Refinery


Refinery

Refinery


Refinery
  85

  50


   6

  38


 100
                                    31

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                   PROCESSES  RESEARCH, INC.
                   INDUSTRIAL PLANNING AND RESEARCH
State/Company/City. County

LOUISIANA
  Gulf Oil Corp.
        Belle Chasse, Plaquemines
  Humble Oil & Refining Co.
        Baton Rouge
        Expansion
  Stauffer Chemical Co.
        Baton Rouge
  Shell Oil Co.
        Norco, St. Charles
  Texaco, Inc.
        Paradis,  St. Charles
MICHIGAN
  Leonard Refineries, Inc.
        Alma, Gratiot
  Marathon Oil Co.
        Detroit
        Expansion
        Expansion
  Mobil Oil Corp.
        Uoodhaven, Trenton
MINNESOTA
  Great Northern  Oil Co.
        Pine Bend
        Expansion
  North Western Refining  Co.
        St. Paul  Park, Washington
MISSISSIPPI
  Elcor Chemical  Corp.
        Canton, Madison
  Shell Oil Co.
        Jackson
  Gulf Oil Corp.
        Purvis, Lamar
  Shell Oil Co.
        Goodwater, Clarke
  Chevron Oil Co.
        Pascagoula, Jackson
MISSOURI
  American Oil Co.
        Sugar Creek, Jackson
      Year
      Sulfur       Acid
      Production   Gas
      Started      Source
       1972
Refinery
       1956
Refinery
       1962
       1955
       1963

       1968
       1965

       1972

Before 1961

       1971

       1972


       1971
Refinery
Refinery
Refinery

Refinery
             Daily
             Sulfur
             Capacity
             Long
             Tons
 40
1967
1972
1950
1965
1966
Refinery
Refinery
Refinery
Refinery
Refinery
10
+300
30
40
50
 12
Before 1961
1962
1968
Refinery
Refinery
Refinery
27
+8
+34
 60
+70

 40
Natural Gas    12 Standby

Natural Gas  1250

Refinery       30

Natural Gas    35

Refinery      Not  Reported
Refinery
 80
                                    32

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                    PROCESSES RESEARCH,  INC.
                    INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County

MONTANA
  Farmers Union Central Exchange
        Laurel, Yellowstone
  Montana Sulfur & Chemical Co.
        East Billings, Yellowstone
  Montana Sulfur & Chemical Co.
        Billings, Yellowstone
        Expansion
NEW JERSEY
  Allied Chemical Corp.
        Elizabeth, Union
  American Cyanamid Co.
        Bound Brook,  Somerset
        Expansion
  American Cyanamid Co.
        Linden, Union
  Anilin Company of New Jersey
        Perth Amboy,  Middlesex
        Expansion
  Amerada Hess Corp.
        Fort Reading, Middlesex
  Humble Oil & Refining Co.
        Linden, Union
  Freeport Sulfur Co.
        Westville, Camden
  Mobil Oil Corp.
        Faulsboro, Camden
        Expansion
NEW MEXICO
  Amoco Production Co.
        Artesia, Eddy
  Cities Service Oil  Co.
        Milnesand, Roosevelt
  Climax Chemical Co.
        Oil Center, Lea
  El Paso Natural Gas Co.
        Eunice, Lea
  Marathon Oil Co.
        Indian Basin, Eddy
  Northern Gas Products Co.
        Hobbs, Lea
Year
Sulfur
Production
Started
1969
Before 1972
1956
1964
1958
1967
1972
1972
1957
1962
Before 1967
1970
Before 1961
Before 1961
1972
1960
1967
1962
Before 1961
1967
1969
Acid
Gas
Source
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery &
Chemical
Chemical
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas

Daily
Sulfur
Capacity
Long
Tons
28
120 Standby
40
+45
30 Standby
12
Not Reported
Not Reported
35
+15
40
300 Two Trains
30
95
+90
26
20
18
30
36
13
                                    33

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                   PROCESSES  RESEARCH, INC.
                   INDUSTRIAL PLANNING AND  RESEARCH
State/Company/City, County

NEW MEXICO
  Warren Petroleum Corp.
        Taturn,  Lea
NEW YORK
  Ashland Oil,  Inc.
        Buffalo
NORTH DAKOTA
  Signal Oil &  Gas Co.
        Tioga,  Williams
        Expansion
        Expansion
  Texaco, Inc.
        Lignite, Burke
OHIO
  Ashland Oil,  Inc.
        Canton, Stark
  Republic Steel Corp.
        Cleveland, Cuyahoga
  Sun Oil Co.
        Toledo
        Expansion
OKLAHOMA
  Pioneer Natural Gas Co.
        Madill, Marshall
  J. L.  Parker  Co.
        Madill, Marshall
PENNSYLVANIA
  Atlantic Richfield Co.
        Marcus  Hook, Delaware
        Expansion
  Atlantic Richfield Co.
        Philadelphia, Philadelphia
        Expansion
  BP Oil Corp.
        Marcus  Hook, Delaware
  Gulf Oil Corp.
        Philadelphia, Philadelphia
  Sun Oil Co.
        Marcus  Hook, Delaware
  United States Steel Corp.
        Pittsburgh, Allegheny
Year
Sulfur       Acid
Production   Gas
Started      Source
             Daily
             Sulfur
             Capacity
             Long
             Tons
1961
1969
1953
1963
1967

1961
Natural Gas
Refinery
Refinery
Refinery
Refinery

Natural Gas
  50
  50
 +23 Standby
+150

  20
1970
1961
1958
1972
1967
Before 1961
Before 1961
1962
1964
1971
Before 1972
Before 1961
1955
Before 1967
Refinery
Chemical
Refinery
Refinery
Natural Gas
Natural Gas
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Chemical
50
6
12
+27
8
15 Standby
20
+32
38
+35
52
135
30
110
                                   34

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                   PROCESSES RESEARCH,  INC.
                   INDUSTRIAL PLANNING AND RESEARCH
State/Company/City. County

TEXAS
  American Smelting and Refining Co.
        El Paso,  El Paso
  Elcor Chemical  Corp.
        Van Horn,  Culbertson
  Amarillo Oil Co.
        Waha,  Pecos
  Marathon Oil Co.
        Raan,  Pecos
  Mobil Oil Corp.
        Coyanosa,  Pecos
  Texas American  Sulfur Co.
        Sand Hills, Crane
  Phillips Petroleum Co.
        Crane County
        Expansion
  Warren Petroleum Corp.
        Waddell,  Crane
        Expansion
  Warren Petroleum Corp.
        San Hills, Crane
  Northwest Production Corp.
        Big Lake,  Reagan
        Expansion
  Sid Richardson  Carbon & Gasoline Co.
        Kermit, Winkler
  Wanda Petroleum Co.
        Kermit, Winkler
  Amarillo Oil. Col.
        Goldsmith, ECtor
  Amoco Production Co.
        North Cowden, Ector
  Odessa Natural  Gasoline Co.
        Odessa, Ector
  J. L. Parker Co.
        Penwell,  Ector
  Phillips Petroleum Co.
        Goldsmith, Ector
  Elcor Chemical  Corp.
        Midland,  Midland
  Amoco Production Co.
        Midland Farms, Andrews
Year
Sulfur
Production
Started
1972
1969
1971
1967
1967
1966
Before 1961
1962
Before 1961
1968
1964
Before 1962
1962
Before 1961
1967
1967
1952
1961
Before 1962
Before 1961
1958
1956
Acid
Gas
Source
Smelter
Gypsum
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
Pilot
9 Plant
1000 Standby
2
13
29
15
100
+65
50
+45
50
3
+5
5
18
5
26
13
30
75
1 Standby
11
                                    35

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                   PROCESSES RESEARCH,
                   INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County

TEXAS
  Amoco Production Co.
        South Fullerton, Andrews
  J. L. Parker Co.
        Andrews, Andrews
  Sulpetro Corp.
        Big Spring, Howard
  Amoco Production Co.
        Sundown, Hockley
  Cities Service Oil Co.
        Welch, Dawson
  Cities Service Oil Co.
        Seminole, Gaines
  Cities Service Oil Co.
        Lehman, Cochran
  Cities Service Oil Co.
        Lehman, Cochran
  Diamond Shamrock Corp.
        Sunray, Moore

  Texas Sulfur Products Inc.
        Dumas, Moore
  Phillips Petroleum Co.
        Borger, Hutchinson
  Trans-Jeff Chemical Corp.
        Tilden, McMullen
        Expansion
  Atlantic Richfield Co.
        Fashing, Atascosa
  Elcor Chemical Corp.
        Fashing, Atascosa
  Humble Oil & Refining Co.
        Jourdanton, Atascosa
  Warren Petroleum Corp.
        Fashing, Atascosa
  Shell Oil Co.
        Person, Karnes
        Expansion
  Coastal States Gas Producing Co.
        Kenedy, Karnes
  Coastal States Petrochemical Co,
        Corpus Christ!, Nueces
Year
Sulfur
Production
Started
1968
Before 1961
1966
1951
1970
Before 1961
Before 1972
1962
1951
1966
1968
Before 1962
1962
Before 1961
1960
1967
Before 1962
1962
1965
1968
1972
Acid
Gas
Source
Natural Gas
Natural Gas
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Refinery
Daily
Sulfur
Capacity
Long
Tons
6
15
10
48
4
28
4
9
&
30
13
33
20
+80
10
55
22
45
12
+23
9
85
                                    36

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                    PROCESSES  RESEARCH, INC.
                    INDUSTRIAL PLANNING AND  RESEARCH
State/Company/City, County

TEXAS
  Phillips Petroleum Co.
        Sweeny,  Brazoria
  Atlantic Richfield Co.
        Houston, Harris
        Expansion
  Signal Oil  & Gas Co.
        Houston, Harris
        Expansion
  Shell Oil Co.
        Deer  Park, Harris
        Expansion
        Expansion
  Stauffer Chemical Co.
        Baytown, Harris
        Expansion
  Atlantic Richfield Co.
        Port  Arthur, Jefferson
        Expansion
  BP Oil Corp.
        Port  Arthur, Jefferson
  Gulf Oil Corp.
        Port  Arthur, Jefferson
        Expansion
  Mobil Oil Corp.
        Beaumont, Jefferson
  Olin Corp.
        Beaumont, Jefferson
  Amoco Production Co.
        Edgewood, Van Zandt
  Cities Service Oil Co.
        Myrtle Springs, Van Zandt
  American Petrofina
        Mount Pleasant, Titus
  Amoco Production Co.
        West  Yantis, Wood
  Elcor Chemical Corp.
        Queen City, Bowie
  Getty Oil Co.
        Cayuga,  Anderson
  Getty Oil Co.
        Winnsboro, Franklin
Year
Sulfur
Production
Started
1967
1960
1970
1963
1967
Before 1962
1966
1970
1953
1962
1961
1967
1972
Before 1961
1962
Before 1962
1959
1964
1968
1969
1963
1966
Before 1972
1969
Acid
Gas
Source
Refinery
Refinery
Refinery
Refinery
Ref inery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
25
30
Not Reported
40
10
50
+50
+300 Two T rains
70
+121
38
+35
35
75
+75
50
50 Standby
576
270
16
80
30 Dismantled
130
224
                                   37

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                    PROCESSES RESEARCH,  INC.
                    INDUSTRIAL PLANNING AND RESEARCH
State/Company/City, County

TEXAS
  Shell Oil Co.
        Bryan's Mill, Case
  Texaco,  Inc.
        Dunbar, Rains
  Warren Petroleum Corp.
        Sulphur Springs, Hopkins
UTAH
  Chevron Oil Co.
        Salt Lake City
  Union Oil Co. of California
        Lisbon, San Juan
VIRGINIA
  American Oil Co.
        Yorktown, York
WASHINGTON
  Rayonier, Inc.
        Hoquiam, Grays Harbor
WEST VIRGINIA
  PPG Industries, Inc.
        South Charleston, Kanawha
WISCONSIN
  Murphy Oil Corp.
        Superior, Douglas
WYOMING
  Amoco Production Co.
        Riverton, Fremont
  Atlantic Richfield Co.
        Riverton, Fremont
  Western Nuclear, Inc.
        Riverton, Fremont
  Amoco Production Co.
        Powell, Park
  Chem-Gas Products Co.
        Powell, Park
  Husky Oil Co.
        Ralston, Park
        Expansion
  Amoco Production Co.
        Worland, Washakie
Year
Sulfur
Production
Started
1962
1966
1965
1972
1967
1957
1962
1960
1972
1965
1963
1968
1949
1961
1964
1966
Acid
Gas
Source
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Refinery
Chemical
Chemical
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
200
70
89
12
10
50
20
27
15
70
12
5
110
14
32
+15
1958
Natural Gas    22  Standby
                                    38

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                   PROCESSES RESEARCH, INC.
                   INDUSTRIAL PLANNING AND  RESEARCH
State/Company/City, County

WYOMING
  Texas Gulf Sulfur Co.
        Worland, Washakie
  Jefferson Lake Sulfur Co.
        Handerson, Big Horn
  Atlantic Richfield Co.
        Sinclair, Carbon
  Signal Oil & Gas Co.
        Nieber Dome
  Texas-Seaboard Inc.
        Silvertip
       Year
       Sulfur       Acid
       Production   Gas
       Started      Source
       1950

Before 1959

Before 1962

Before 1962

       1957
Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas
            Daily
            Sulfur
            Capacity
            Long
            Tons
400 Standby

113 Standby

 26

 50

 50 Standby
                                    39

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   PROCESSES RESEARCH, INC.
   INDUSTRIAL PLANNING AND RESEARCH
APPENDIX D - GLAUS SULFUR PLANTS IN CANADA
                40

-------
                   PROCESSES  RESEARCH, INC.
                   INDUSTRIAL PLANNING  AND RESEARCH
Province/Company/City

ALBERTA
  Amerada Hess  Corporation
                     Calgary
  Amerada Hess  Corporation
                     Olds
                     Expansion
  Amoco Canada  Petroleum Company Ltd.
                     Blgstone
  Amoco Canada  Petroleum Company Ltd.
                     East Crossfield
  Amoco & Texas Gulf Sulfur Co.
                     West Whitecourt
                     Expansion
                     Expansion
  Aquitaine Company of Canada Ltd.
                     Rainbow Lake
                     Expansion
  Aquitaine Company of Canada Ltd.
                     Rocky Mountain House
  Atlantic Richfield Canada Ltd.
                     Gold Creek
  Canadian Delhi Oil Ltd.
                     Minnehik
                     Expansion
  Canadian Fina Oil Ltd.
                     Cochrane
  Canadian Industrial Gas & Oil Ltd.
                     Kessler
  Canadian Superior Oil Ltd.
                     Harmattan
  Canadian Superior Oil Ltd.
                     South Lone Pine Creek
  Chevron Standard Limited
                     Fox Creek
  Chevron Standard Limited
                     Nevis             Before
  Great Canadian Oil Sands Ltd.
                     McMurray
  Gulf Oil Canada Limited
                     Braeburn

Year
Sulfur
Production
Started
1970
1964
1967
1968
1968
1962
1965
1968
1968
1973
1972
1971
1967
1972
1961
1962
1966
1972
1972
1972
1967
1965


Acid
Gas
Source
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Refinery
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
400
153
+33
370
1660
700
+525
+650
75
+75
2032
106
26
+9
106
10
817
133
3065
155
350
3
                                   41

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                   PROCESSES  RESEARCH, INC.
                   INDUSTRIAL  PLANNING AND RESEARCH
Province/Company/City

ALBERTA
  Gulf Oil Canada Limited
                     Calgary
  Gulf Oil Canada Limited
                     Nevis
                     Expansion
                     Expansion
  Gulf Oil Canada Limited
                     Pincher Creek
                     Expansion
  Gulf Oil Canada Limited
                     Rimbey
                     Expansion
  Gulf Oil Canada Limited
                     Strachan
  Gulf Oil Canada Limited
                     Turner Valley
  Home Oil Co.,  Ltd.
                     Carstairs
                     Expansion
                     Expansion
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Brazeau River
                     Expansion
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Caroline
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Carstairs
                     Expansion
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Ed son
                     Expansion
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Fox Creek
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Fox Creek
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Sturgeon Lake
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Sundre
  Hudson's Bay Oil  & Gas Co. Ltd.
                     Sylvan Lake
Year
Sulfur
Production
Started
1967
1960
1966
1970
1957
1962
1961
1965
1972
1952
1960
1967
1973
1968
1969
1968
1967
1969
1965
1971
1970
1970
1970
1968
1969
Acid
Gas
Source
Refinery
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Daily
Sulfur
Capacity
Long
Tons
50
76
+50
+50
225
+450
246
+120
830
35
42
+8
+52
21
+29
16
102
+72
225
+64
1044
1030
50
18
11
                                   42

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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH








Province/Company/City
ALBERTA
Imperial Oil Ltd.

Imperial Oil Ltd.



Quirk Creek

Redwater

Year
Sulfur
Production
Started


1971

1956


Acid
Gas
Source


Natural Gas

Natural Gas
Daily
Sulfur
Capacity
Long
Tons


200

9
Jefferson Lake Petrochemicals of Canada Ltd.


Balzac
Expansion
1961
1967
Natural Gas
Natural Gas
870
4-1100
Jefferson Lake Petrochemicals of Canada Ltd.

Mobil Oil Canada,

Shell Canada Ltd.

Shell Canada Ltd.

Shell Canada Ltd.


Shell Canada Ltd.

Shell Canada Ltd.

Shell Canada Ltd.


Shell Canada Ltd.

Coleman
Ltd.
Wimborne

Burnt Timber

Innisfail

Jumping Pound
Expansion

Jumping Pound

Simonette

Waterton
Expansion

Waterton
1961

1964

1971

1960

1951
1971

1967

1971

1962
1967

1972
Natural Gas

Natural Gas

Natural Gas

Natural Gas

Natural Gas
Natural Gas

Natural Gas

Natural Gas

Natural Gas
Natural Gas

Natural Gas
377

335

120

100

90
4-240

140

90

1200
4-450

1230
Tenneco Oil & Minerals, Ltd.

Texas Gulf Sulfur

Texas Gulf Sulfur


BRITISH COLUMBIA
Nordegg River Before
Co.
Okotoks
Co.
Wild Horse Creek
Expansion

1972

1959

1966
1968

Natural Gas

Natural Gas

Natural Gas
Natural Gas

40

380

30
4-620

Gulf Oil Canada Limited

Port Moody
1972
Refinery
25
Jefferson Lake Petrochemicals of. Canada Ltd.

Shell Canada Ltd.

Taylor

North Burnaby
1957

1968
Natural Gas

Refinery
325

15
           43

-------
                  PROCESSES  RESEARCH, INC.
                  INDUSTRIAL PLANNING AND RESEARCH
Province/Company/City

MANITOBA
  Imperial  Oil Ltd.

NEW BRUNSWICK
  Irving Refining, Ltd.

NEWFOUNDLAND
  Newfoundland Refi

NOVA SCOTIA
  Imperial  Oil Ltd.

  Imperial  Oil Ltd.

QUEBEC
  Imperial  Oil Ltd.

  Laurentide Chemic


ONTARIO
  Allied Chemical Corp.
                     S
  Cornwall  Chemicals Ltd.
                     Cor
  Gulf Oil  Canada Limited

  Imperial  Oil Ltd.
  Shell Canada Ltd.

  Shell Canada Ltd.

  Sun Oil Co. Ltd.
SASKATCHEWAN
  Dome Petroleum Limited
                     Steelman
Year
Sulfur Acid
Production Gas
Started Source
Winnipeg
k •
St. John
ig Co., Ltd.
Come By Chance
Dartmouth
Halifax
Montreal
i and Sulfur Ltd.
Montreal
Expansion
>.
Sudbury
f-H
I UU •
Cornwall
t*aH
.L6U
Clarkson
Sarnia
Expansion
Oakville
Sarnia
Sarnia
1966
1962
1973
1966
1966
1965
1958
Before 1972
Before 1972
1965
1963
1964
1968
1963
1966
1970
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Smelter
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Refinery
Daily
Suflur
Capacity
Long
Tons
14
28
25
35
25
35
100
+200
275
75
40
25
+60
46
35
13
1965
Natural Gas
15
                                   44

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     PROCESSES RESEARCH, INC.
     INDUSTRIAL PLANNING AND RESEARCH
APPENDIX E - AMOCO PRODUCTION COMPANY INFORMATION
                  45

-------
                                           February 15, 1972
Dr. Paul F. Bavley
Pa tut Director
Amoco Production Company
Sox 591
Tula*, Oklahoma 74102

Subject:  Claua Sulfur Plant
          Perforaeaee

Dear Or. dawlay:

Several of tha netheda being conaidared for abatement of aulfur eolaaiona
to tha ataoaphere laelnda Claua aulfur unit*.  Tha Environmental Protection
Agono? Offim of Air Program* ha* cng«s*d Prooaaaaa Haaearch, lac., to atudy
tha affifiMT o* Claiia a«lf«r plaati la pollution abataaaat (Cootract No. 68-
02-0242).
Ua undarataad tbm yoer eaa^aaqr Ofarataa Clma oaita recovering aulfur which
would othatvia* b« emitted Ca tba ataaeetoro.  Plaaaa let ua have available
inforttatlAB) tetartint the p«rfor«ane« of thaaa unite, aa follova.  Tha Office
of Air Pvegrena iaeexeat ia in davalaflns pollution control withoda and tha
requaaend iniomatioa ia for uaa ia theaa afforte.

1.  Loeatlon. daily aulfur capacity, daya of operation annually and annual
    aulfor prodvotlon.

2.  Clauc precaaa ^aviation tned:  atraight tthroamh, avlit flow, direct
    oxidation, sulfur reayole, etc.

3.  Number of catalytic ateana and nathod of reheating prooeaa vapor.

4.  Source, quantity and oonpotition of ael
-------
Dr. Paul P. Uavley
February 15, 1972
Page 2
7.  Frequency of catalyst change and aatntenaneo.

8.  Operator attendance and trouble.

9.  Consuaption and generation of fuel, water, power and •teen.

If soae of this Information is available for on* ov oore of your Claos unit*,
please let tui know when ve nay expeet to receive it.  We thank you for your
cooperation.

                                           very truly yours,

                                           PROCESSES RESEARCH. INC.
                                           w. D. Keers
                                           Project Manager
WDB:jd

ec:  G. S. Hsaelbevger
     H. R. Jester
     P. V. Spelts

-------
                                              Amoco Production Company
                                              Amoco Building
                                              xP.O. Box 591
                                              }Tulsa,  Oklahoma 7-110?
                                              Producing Department
M. S. Kraemer
Chiol Engineer
May It, 1972

Mr. V. D. Beers
Project Manager
Processes Research Inc.
2912 Vernon Place
Cincinnati, Ohio   5^210

Dear Mr. Beers:

Subject:  Sulfur Plant Performance

Your letter of February 15, 1972 to  Dr.  Paul  F.  Hawley has  been referred
to me for a reply.  You have  indicated that you  are making  a study of
Glaus sulfur plant efficacy in pollution abatement  under contract with
the Environmental Protection  Agency.   For your study a summary of data
concerning the plants operated by Amoco  Production  Company  is attached.
However, the information will soon be  out of  date for many  of the plants
since studies are underway to modify them to  meet recently  revised state
emission regulations.

All these plants recover  sulfur from  hydrogen sulfide which has been ex-
.tracted from natural gas to reduce emission of sulfur to the atmosphere.
The acid gas feed normally contains  hydrogen  sulfide, carbon dioxide,
hydrocarbons and water.  The  plant tail  gas before  incineration is pre-
dominately nitrogen, carbon dioxide  and  water vapor with small quantities
of hydrogen sulfide .(0.5-1-5  mol$),  sulfur dioxide  (0.25-0.75 mol#), car-
bonyl sulfide (0.01-O.OU molSO, carbon disulfide (0.01-0.05 mol$), plus
fractions of a percent of hydrogen and carbon monoxide and  elemental
sulfur  (vapor and entrained).  Incineration converts the sulfur compounds
to sulfur dioxide.

These plants have low maintenance requirements and low operating costs
which combined amount to about 8 to  15$  of capital investment per year.
Catalyst life is normally about ten  years. Changes are otherwise made
only in the event of plant upsets which  result in damage to the catalyst.

Operator attendance requirements vary  depending  upon the design of the
plant and the amount of other duties assigned.  Full time operator atten-
dance is not required.

-------
Mr. W. D. Beers
May ii, 1972
Page 2
For a more detailed discussion of sulfur plants, please refer to the
attached copy of "Why Recover Sulfur from

Yours truly,
Attachment

cc - Dr. P. F. Hawley

-------
                                                                      OF 3
                       AMOCO PRODUCTION COMPANY
                        Sulfur Recovery Plants
(As of April 1972 - Plant Revisions nov being studied for compliance
 with new state 'air conservation regulations as soon as approved by EPA)
   LOCATION:  County
              State

   Dally Sulfur Capacity, LTD
        of Operation, Annually
;vnnual Sulfur Production
11971) LT

I'roceos, Glaus
[lumber of Catalytic stages
I;ohcat Method

y.cid Gas Feed
   Source
   Quantity, MMCFD
   Composition, mol jfa^S

I'lant Tail Gas
 Quantity MMCFD

Tail Gas Treatment
Catalyst Change Frequency

Utilities
   Cooling Water MMBtu/hr.
   Steam  #/hr..consumed*
      "  "   "   generated
Beaver
Creek
Fremont
Wyoming
Elk
Basin
Park
Wyoming
Empire
Abo
. Eddy
N. Mex.
 70          110           26
365 less downtime.for required maintenance.
    (Usually about  360 days/years).
                                              12,860
                        9,586
                                st. thru
                                      2
                                bypass
         split flow   st. thru
               2            2
         inline htr.  bypass
                                Natural Gas  Natural Gas  Natural Gas
                                    1.2          2.0          1.1
                                     88           60           65
                                    3.3 •
             3.7
                                None
         None
    2.68

 None
                                -  Only  in  the  event  of catalyst damage -
                                 10,700
         .10,900
-2 7,000
       Fuel  gas MMCFD
       Instrument  air  (negligible)
       Electrical  KW*
        '(Approx. 2 HP/LT/D for blower steam or electrical)
                                50

-------
                    .   AMOCO PRODUCTION COMPANY              '
      •                  Sulfur Recovery Plants
(As of April 1972 - Plant Revisions now being studied for compliance
 with new state'air conservation regulations as soon as approved by EPA)
  LOCATION:   County
             State

  Daily Sulfur Capacity,  LTD
       of Operation,  Annually
Edgewood
Van Zandt
Texas
Midland
Farms
Andrews
Texas
North
Cowden
Ector
Texas
/vnnual Sulfur Production
'1971) LT

i'roceas, Glaus
[lumber of Catalytic stages
Iieheat Method

/.cid Gas Feed
   Source
   Quantity, MMCFD
   Composition, mol /Cl^S

I'lant Tail Gas
 Quantity MMCFD

Tail Gas Treatment
Catalyst Change Frequency

Utilities
   Cooling Water MMBtu/hr.
   Steam  #/hr.,consumed*
      "  "  "   generated

   Fuel gas MMCFD
   Instrument air (negligible)
   Electrical KW*
   576             11             26
365 less downtime for required maintenance.
       (Usually about  360 days/years).

               3,018
                                  120,959
9,352
st . thru
2
bypass
exchanger

Natural Gas
10.2
86
st. thru
2
bypass

\ i
Natural Gas
0.5
52
st . thru
2
inline htr.


Natural Gas
2.1
61
                                     29.U           .93           2.8

                                Incineration . •  None        __  Ndne
                                 - Only in the event of catalyst damage -
                                   88,000
                                      500
                   0
              2,600
 7,700
      '(Approx. 2 HP./LT/D for blower s'team or electrlem
                                 51

-------
                       AMOCO PRODUCTION COMPANY
                            SMEET
                                                                       OF
                        Sulfur Recovery Plants
(AB of April 1972 - Plant Revisions now being studied for compliance
 with  new state'air conservation regulations  as soon as  approved by EPA)
  LOCATION:  County
             State

  Daily Sulfur Capacity, LTD
  Days of Operation, Annually

  /vnnual Sulfur Production
  '1971) LT

  Process, Claus
  Number of Catalytic stages
  Ileheat Method
  y.cid Gas Feed
     Source
     Quantity, MMCFD
     Composition, mol

  I'lant Tail Gas
   Quantity MMCFD
Tail Gas Treatment
Catalyst Change Frequency

Utilities
   Cooling Water MMBtu/hr.
   Steam  #/hr.,consumed*
      "  "  "   generated

   Fuel gas MMCFD
   Instrument air (negligible)
   Electrical KW*
Slaughter
Hockley
Texas
South
Fullerton
Andrews
Texas
West
Yontis
Wood
Texas
                                   80
365 lesu downtime for required maintenance.
         (Usually about 3oO days/years),
13,033
1,1*06
                                                                9.32U
split flow
2
bypass
Natural Gas
6.3
23
st. thru
2
bypass
Natural Gas
.U
te
8t. thru
2
bypass
Natural Can
1.75
Ul
   7.5
  0.5
                                  None
               None
                 3.3
               Incineration
                                 - Only in the event  of catalyst damage -
2.U

10,400

—
0
1100

—

7,900
35
      '(Appro*. 2 HP/LT/D for blower steam or electric
                                                    cal
                                  52

-------
INTEREST in the  recovery  of sulfur
from hydrogen sulfide has never been
higher. Here's why:
   • World  demand for sulfur is high
and continuing to  increase.
   • New reserves of natural gas con-
taining hydrogen sulfide have been dis-
covered.
   • A  number  of  city,  state,  and
federal  air-quality-control  laws have
been  enacted.
   • Sulfur prices are high, and should
go higher.
   So,  several  incentives,  both  eco-
nomic and  legal,  exist for  increasing
sulfur recovery  from sour  gas.  It
would be expected  lhat recent plant
construction  would show an  increase
over  that recorded previously.
   A comparison reveals some interest-
ing facts.
   By the end of 1968, there wilt have
been  constructed  132 plants of this
type  in  the  United  States, plus  29
expansions of existing plants, many of
which are really new  parallel plants.
   Of these, 78 were  built in  1961 or
before, and 83  since. At the end of
1968, as in  1961,  58% will be  in
refineries (or chemical plants) and  the
remainder  in  natural-gas   processing
plants. Table 1 shows  a  list of  all
U.S. sulfur plants.
   The largest plant before  1961  was
Texas Gulf Sulphur's Worland, Wyo.,
plant which began operating in 1950
and  shut down  in 1967. It had  400
long  tons/day  (LT/D) capacity. The
largest U.S. plant today (580 I.T/D) is
Pan American Petroleum's Edgewood,
Tex., plant completed in 1964.
   Pan American  Petroleum also op-
erates the  largest  number  of  plants.
nine,  closely  followed  by   National
Sulfur (Elcor Chemical Co.) with six.
Pan  American,  National Sulfur  and
other licensees  of  Pan  American's
patents  and  know-how  ac  -ount  for
49%  of  the  sulfur recovery capacity
built in  the  United States since 1961.
   The average per-plant  capacity of
the U.S.  operating  plants and expan-
sions constructed  has remained sub-
stantially unchanged  in  recent years
(in 1961  and before.  54  LT/D in nat-
ural gas plains  and  62  LT/D in  re-
fineries;  since 1961,  54  LT/D in  nat-
ural gas plants  and  52  LT/D in  re-
fineries).
                                                                    Fi,.  I
   Processes  for  sulfur  recovery from H,S
                 Itralfhl
                 through
      % wHur    „ ,.
      rKonrtd    13-1S+
40-93+
             75-90+
                             75-90+
H. GREKEL
J.  W. PALM
     AND
J. W. KILMER
Pan  American Petroleum Corp.
Tulsa, Okla.

  In  1961, only 13% of the plants in
operation  were  of  greater than  100
LT/D capacity and  at year-end 1968.
only 17%. The  overall  percentage of
plants with 25 LT/D or smaller capac-
ity was 357o in 1961 and will be 33%
at  the end of 1968.
  The capacity  of  u.s. plants  to re-
cover sulfur from  hydrogen  sulfide
increased  40%  from 1,659,000 long
tons/year  (LT/YR) at (he end  of 1961
to  2,737,000 LT/YR  at  end of 1967.
  At year-end  1968,  ihc  capacity of
3,036,000 LT/YR will be nea-.l/ double
the  1961  recovered sulfur capacity.
The  actual  production  of recovered
sulfur  in  1961  of 858,000  LT  and
1967 of 1,244,000 LT represented only
52 ami 45%, respectively,  of ;he ycar-
enJ sulfur recoverv cap.'icity.
  By contrast, the Canadian plant ca-
pacity "ill have more ihan qujJrupleJ
from  1961  to  1968.  Production in
1961  of 486,000 LT was 43% of the
1,140,000 LT/YR capacity and in 1967
         the 2,200,000 LT production was 51%
         of the year-end 4,300.000 LT/YR plant
         capacity. At (he end  of  1968. Cana-
         dian  recovered sulfur plant capacity
         will be 5,034,000 LT/YR.
           The Canadian sulfur plant size and
         balance  between natural gas and  re-
         fineries  are much  different from the
         pattern in the  United States. Table 2
         is a  list  of Canadian sulfur plants.
         In 1961, the 14 sulfur plants based on
         natural gas averaged 214 LT/D.
           The largest  plant was  the  Pctrogas
         Balzac,  Alta.,  plant  at  870  LT/D.  It
         is still the largest, having expanded  in
         1967 to 1,970 LT/D.
           In Canada,  45% of the  plants are
         over  100 LT/D and only 20%  under
         25 LT/D. There will  have  been built
         50 plants  plus 10  expansions by the
         end  of 1968.
           The average capacity  of Canadian
         plants at the  end  of  1968  will have
         increased  somewhat,  averaging  357
         LT/D for the 36 natural gas-based and
         67 LT/D  for  the   14 refinery-based
         sulfur plants.
           Tne  average  size  in  refineries  is
         influenced  greatly  by the  350  LT/D
         Great Canadian Oil Sand sulfur plant
         added in 1967.
                 (Continued on p. 93)

                 THE OIL AND GAS JOURNAL
                                                        53

-------
                                                  Fig. 2
     Sulfur-recovery  plant  investment
         10
 10           100
Product capacity, LT/D
                                             1,000

Fig. 3
Sulfur-plant operating cost
f~
10
•Q
t—
•N.
«A
S 1
O)
E
I"
0.1
V 	

v
X
•Plant operating of c
19M-W7 data

&
S.A
>^4
AA
opocJty


\
X
10 100 1,000
Piodurt (opacity, 11/0 J


   There will be in Alberta at the close
 of  1968 four  plants  of  over  1,000
 LT/D capacity.
   The fourth, at  1,480 LT/D capacity,
 started up  in February 1968,-is  now
 operated at East  Crossfield by  Pan
 American  Petroleum Corp.
   Historically, sulfur recovered  from
 H2S has  been  a by-product  whose
 economics  have been dependent  only
 on the last step of the recovery proc-
 ess. The removal of  the  H:S  from
 natural gas or refinery gas  was  justi-
 fied by the value of the sweet fuel.
   Even at  sulfur prices  as  low as
 S17/LT,  the sulfur  recovery  plant
 could  be justified economically down
•to 4 LT/D.
   At  today's Oil,  Paint  and Drug
 Reporter sulfur  price  posting of
 S42/LT  (fob  Gulf  Coast  for  bright
 sulfur), even  small  by-product sulfur
 plants can be justified.
   In contrast, high sulfur  prices have
 made  attractive  the construction of
 several large Canadian sulfur  plants
 where the residue  gas value would not
 support  the sweetening  plant costs.
 Value of  sulfur  production  may be
 90% of the total  income—enough to
 justify the entire project.
   The  need  and   desirability ot  re-
 covering sulfur  have led to  develop-
 ment of revised methods of recovering
 sulfur from more dilute  streams of
 hydrogen  sulfide.  Economic  designs
 have been  developed for recovery of
 sulfur  from acid  gas  containing' as
 little as 2 vol 7<  H,S.
   Straight-through process. If the hy-
 drogen  sulfide  concentration  of  the
 feed gas  is  high  enough  that  stable

OCTOBER 28, 1968
Fig. 4
Total sulfur-recovery cost from acid gas

I 100
t?
o
1 "
J
3
. a
•£
1
1 ««!«•/. H,l
' In add gai
• 10 ^
100 ^K

Coo liKludti operating ir
capital diorgi it 30% ol
ptr iiw. wllvr plant mly
^
»nu pliH
Inviitintnt
—-
10 1 0
Sulfur product, capacity, LT/D



                  combustion of the total stream is ob-
                  tainable, then the total stream is fed
                  to (he burner in  a  furnace or boiler
                  as shown for the straight-through
                  process in  Fig.  1. Air is fed  to the
                  burner to provide oxygen for the over-
                  all reaction: HjS + 'A O. -* S +  H2O
                     In addition, air is provided to react
                  with  hydrocarbons   in  the ac-d-gas
                  feed. Sulfur is produced  in  the flame,
                  but sulfur dioxide is also  formed, and
                  some  H,S is unrcacted.
                    The gases leaving the  furnace are
                  cooled, usually condensing sulfur from
                  the gas,  which is  then preheated and
                  fed to a  catalytic  reactor containing
                  bauxili;  catalyst where  the  Claus re-
                  action occurs.

                      2H2S + SO2 -»  3S + 2H:O
  The gas then  passes to a condenser
to  remove  liquid  sulfur.  Usually  a
second  reactor  and  condenser  (and
sometimes a third) are user!  to get
higher yields. Typical recovery levels
for the straight-through process and
other processes  are shown in Fig.  1.
  Split-flow process.  If the hydrogen
sulfide concentration  of the acid bas
is  so  low that  the  gas will not  burn
using  the  straight-through  process,
then as much as two-thirds of the gas
may be bypassed around the  furnace
as shown for the  split  flow  process
in Fig. 1.
  In  this  case,  most of the hydrogen
sulfklc fed to the  furnace  is oxidized
to sulfur dioxide and little or no sulfur
is produced in the  furnace.
  The hot  gas  from  the  furnace  is
                                                        54

-------
cooled and blended  with the bypass
gas to obtain the desired preheat tem-
perature for the  reactor, where the
hydrogen sulfide from the bypass gas
reacts with the  sulfur dioxide  from
the furnace by  the Claus reaction over
bauxite catalyst to produce  sulfur.
  The reactor and condenser train are
similar lo that  of the straight-through
process.  Preheating  of the  feed gas
may  be used to permit processing by
this method  of  feed gas containing
less than  IS  mole  % H2S.
  These two  methods can  be  used
for handling  acid gas which is too
lean  to achieve stable combustion  in
the split flow process:
   1. Sulfur recycle process
   2. Direct oxidation process
   Sulfur-recycle process. In the sulfur-
recycle  process, product sulfur is re-
cycled to the furnace and burned with
air to produce sulfur dioxide. Some of
the feed H3S may also  be burned in
the furnace to produce sulfur dioxide.
   The sulfur dioxide  formed in the
furnace is fed with acid-gas feed to
the Claus  reactors as shown  in Fig.
1. The  reactor-condenser train would
again be similar to the straight-through
process.
   Direct-oxidation process. In the di-
rect-oxidation  process,  the   acid-gas
feed is preheated, mixed with air, and
passed directly to a catalytic reactor,
as shown in Fig.  1. The oxygen reacts
with the hydrogen  sulfide to produce
sulfur dioxide and sulfur.
   Most direct oxidation plants require
two or  three reactors. Further details
concerning this process have been pub-
lished previously.1 3
   Limitations of processes.  The
straight-through  and split-flow proc-
esses are limited by process considera-
tions  to those  gases  which contain a
high enough concentration of H2S to
obtain stable combustion.
   The  sulfur-recycle process and di-
rect-oxidation process have practically
no lower limit on the hydrogen sulfide
U.S. sulfur-recovery plants from HzS
Feed
Source
Tear Chemical
started up Refinery
'or earlier Natural Cap.
.Oparatlng company
Allied Chemical




Amarillo Oil
American Cyanamid
American Oil


Anlln Co. of III.
Anlin Co. of NJ.

Arkla Chem. Corp.

Atlantic-Richfield.
Arco Chemical Co.
Div.


Cities Service


Climax Chemical
Coastal States Gas
Production Co.
Continental Oil

Diamond-Shamrock
El Paso Natural Gas
Farmer's Union Cen-
tral Exchange
Farmland Industries,
Inc.
Fletcher Oil
Freeport Sulfur
Getty Oil

Golden Eagle Re-
finery
Great Northern Oil

Gulf Oil







Hess Oil
Hess Oil & Chemical
Plant location
Elizabeth, NJ.
El Segundo, Calif.
General Chem. Div
Richmond. Calif.
Expansion
Goldsmith, Tex.
Bound Brook, N.I.
Whiting, Ind.
Expansion
YoiMown, Va.
Wood River, III.
Perth Amboy, NJ.
Expansion
Magnolia, Ark.
expansion
Philadelphia, Pa.

Port Arthur, Tex.
Riverton, Wyo.
Watson, Calif.
Myrtle Springs, Tex
Milnesand, N.M.
Seminole, Tex.
Oil Center, N.M.

Kennedy, Tex.
Denver, Colo.
Paramount, Calif.
Sunray, Tex.
Eunice, N.M.
Laurel, Mont.


Coffeyville, Kan.
Wilmington, Calif.
Westville, NJ.
Delaware City, Del
Winnsboro, Tex.

Torrance, Calif.
Pine Bend, Minn.
Expansion
Philadelphia, Pa.
Port Arthur, Tex.
Expansion
Purvis, Miss.
Santa Fe Springs,
Calif.
Expansion
Expansion
St. Croix-Virgin Is

(S-shutdown, yr)
1958 (S, 1967)
1959(5,1967)
1964
1961*
1968
1967
1967
1952
1964
1957
1960
1957
1962
1961'
1962
1964

1961
1963
1967
1968
1967
I960'
1962

1968
1968
1966
1951
I960*



1968
1961'(S, 1967)
I960'
1956
1969

1 959 (S, 1967)
1955
1963
I960'
I960*
1962
I960'

I960'
1961*
1964
1967

Gas
R
R
R
R
R
N
R-C
R
R
R
R
R
R
N
N
R

R
N
R
N
N
N
N

N
R
R
N.R
R
R


R
R
R
R
N

R
R
R
R
R
R
R

R
R
R
R

LT/D
30
175
100
100
+ 100
7
12
64
+ 40
50
150
35
-1-15
19
+ 11
38

.38
12
65
228
20
28
18

9
18
9
30
30
28


6
7
30
375
224

4
60
+ 70
135
75
+ 75
30

8
9
13
40

Operating company
Corp.
Humble Oil & Re-
fining


Husky Oil

Jefferson Lake
Sulphur
Leonard Refineries,
Inc.
Marathon Oil




Mobil Chemical




Monsanto Chemical


Montana Sulphur &
Chemical

National Sulfur






Northwest Produc-
tion Corp.

Northwestern Re-
fining
Odessa Natural
Gasoline
Olin Matheson

Pan American Petro-
leum Corp.







Plant location
Port Reading, NJ.

Baton Rouge, La.
Benicia, Calif.
Jourdanton, Tex.
Ralston, Wyo.
Expansion

Manderson, Wyo.

Alma, Mich.
Detroit, Mich.
Expansion
Expansion
Indian Basin, N.M.
Iraan, Tex.
Beaumont, Tex.
Paulsboro, NJ.
Coyanosa, Tex.
Woodhaven, Mich.
Torrance, Calif.
El Dorado, Ark.
Lion Oil Div.
Avon, Calif.

Billings, Mont.
Expansion
Midland, Tex.
Fashing, Tex.
Lehman, Tex.
Canton Miss.
Crane County, Tex.
Queen City, Tex.
Madill, Okla.

Reagan County, Tex
Expansion

St. Paul Park, Minn

Odessa, Tex.
Beaumont, Tex
McKamie, Ark.
Beaver Creek
Riverton, Wyo.
Cottonwood Creek
Worland Wyo.
Edgewood, Tex.
Elk Basin,
Powell, Wyo.
Empire Abo
Artesia, N.M.
Feed
Source
Year Chemical
started up Refinery
'or earlier Natural
(S-shutdown, yr)
1966'

1967
1968
1967
1964
1966

1958'(S, 1960)

195S
I960*
1962
1968
1967
1967
1961*
I960*
1967
1962
1967
I960*

1966'

1956
1964
1958(5.1960)
1960
1962
1965
1966
1966
1967

1961'
1962

1968

1961
1959(5)
1944

1965

1958(5,1964)
1954

1949

1960
Gas
R

R
R
N
N
N

N

R
R
R
R
N
N
R
R
N
R
R
R

R

R
R
N
N
N
N
N
N
N

N
K

R

N
N
N

N

N
N

N

N
Cap.
LT/D
40

10
270
22
32
15

113

12
27
+8
+34
36
11
50
95
29
8
85
25

132

40
+45
1
55
9
12
15
30
8

3
+5

40

12
50
100

70

22
5SO

110

22
                                                                                        THE OIL AND GAS JOURNAL
                                                            55

-------
content of.  the  gas  to be  processed
from a standpoint of operability.
  However, there are economic limits.
The lower economic limit on hydrogen
sulfide is presently  in  the  neighbor-
hood of 2 to 10 mole % depending on
the feed-gas rate and  sulfur netback
at the plant.
  Contaminants In feed gas. A typical
acid gas  from an amine-type natural-
gas-sweetening  unit  which  comprises
the feed to a  sulfur  recovery  plant
contains hydrogen  sulfide  plus carbon
dioxide with about  1  to  2 mole %
hydrocarbons.
  The HjS/COj  ratio depends pri-
marily on the ratio  of these compo-
nents in the feed gas to the sweetening
unit since both  compounds are  ab-
sorbed practically quantitatively from
the sour-gas stream.
   Hydrocarbons  in the feed  gas  to
the sulfur plant are usually detrimental
for these  reasons:
   1. In the  straight-through process,
air must  be supplied to the furnace
for combustion of the hydrocarbons
in the feed gas. The added water and
inert  gas  associated with burning the
hydrocarbons increase the  size  of-the
sulfur-plant equipment and lower the
sulfur recovery.
   2. In the split-flow process,  hydro-
carbons in the feed gas to the furnace
have a beneficial effect in helping to
maintain flame stability. However, the
hydrocarbons  in  the  gas  bypassed to
the reactor tend  to  crack over  the
bauxite catalyst, producing a carbona-
ceous product which fouls the catalyst
and contaminates the product sulfur.
The  rate  of cracking increases with
increasing  molecular  weight  of  the
hydrocarbons.
  3.  Higher-molecular-weight  hydro-
carbons in the feed to the sulfur re-
cycle  process  or the  direct-oxidation
process  also are detrimental  because
of cracking on the bauxite catalyst.
  New  gas-sweetening solvents have
been developed to obtain  higher acid-
Table 1
Feed
Source
Year Chemical
started up Rellnery
"or earlier Natural
Operating company










). I. Parker


Phillips Petroleum





Pittsburgh Plate
Glass

Powerine Oil

Rayonier
Republic Steel
Sharpies, Purvin &
Gerb
Shell Oil




Shell Chemical
Plant location
Midland Farms
Midland, Tex.
North Cowden
Odessa, Tex.
Slaughter
Sundown, Tex.
South Fullerton
Texas
West Yantis
Tyler, Tex.
Andrews, Tex.
Madill, Okla.
Penwell, Tex.
Borger, Tex.
Crane County, Tex
Expansion
Goldsmith, Tex.
Kansas City, Kan.
Sweeney, Tex.

S. Charleston
W. Virginia
Santa Fe Springs,
Calif.
Hoquiam, Wash.
Cleveland, Ohio

Powell, Wyo.
Bryan's Mill, Tex.
Martinez, Calif.
Person, Karnes
County, Tex.
Expansion
Norco. La.
(S-shutdown, yrt

1956

1952

1951

1968

1963
I960'
I960* (S)
1961'
1968
I960*
1962
I960*
1968
1967


1960

1967
1962
1961

1961
1962
1966

1962
1965
1965
Gai

N

N

N

N

N
N
N
N
R
N
N
N
R
R


Ch

R
Ch
Ch

N
N
R

N
N
R
Cap.
LT/0

11

18

48

6

80
15
IS
30
33
100
465
75
38
25


27

20
25
6

14
180
100

12
-1-23
40
FNd
Source
Year Chemical
iterted up Refinery
•or earlier Natural
Operating company

Stauffer Chemical









Sulpetro Corp.
Sun Oil

Texas-Seaboard, Inc.

Texaco Inc.




Texas Gulf Sulfur
Texas Sulfur Prod-
ucts, Inc.
Trans-Jeff. Chem.
Corp.

Union Oil

Union Oil Co. of
Calif.



Deer Park (Houston)


Sid Richardson Car-
bon & Gasoline
Signal Oil & Gas

Sinclair Oil Cor-
poration



Texas
Expansion
Winkler County,
Texas
Houston, Tex.
Expansion
Nieber Dome, Wyo
Tiqga, N.O.
Expansion
Expansion
Fashing, Tex.
Houston, Tex.
Marcus Hook, Pa.
Expansion
1961*
1966
1960*
1963
1967
1961*
1953t
1963 (S, 1967)
1967
1960*
1960*
I960*
1962
R
R
N
R
R
N
R
R
R
N
R
R
R
50
50
5
40
10
50
72
+23
+ 150
10
30
20
+32

U.S. Steel
Wanda Petroleum
Warren Petroleum

W. R. Grace
Western Nuclear,
Inc.

Plant location (S-shutdown, yr)
Sinclair, Wyo.
Baton Rouge, La.
Baytown, lex.
Expansion
Delaware City, Del.
Le Moyne, Ala.
Watson, Calif.
Expansion
Expansion
Expansion
Expansion
Big Spring, Tex.
Toledo, Ohio
Marcus Hook, Pa.
Silver Tip Field,
Wyo.
Los Angeles, Calif.
Lignite, N.D.
Dunbar, Tex.
St. Charles Parish,
La.
Worland, Wyo.

Dumas. Tex.
Tilden, Tex.
Expansion
San Juan County,
Utah

Lemont, III.
Expansion
Oleum, Calif.
Santa Maria, Calif.
Wilmington, Calif.
Expansion
Pittsburgh, Pa.
Kermit, Tex.
Fashing, Tex.
Waddell, Tex.
Expansion
Sand Hills, Tex.
Sulfur Springs, Tex
Tatum, N.M.
Puerto Rico, W.I.
Riverton, Wyo.

1961*
1950
1953
1962
1961*
1961*
1961*
1961*
1962
1964
1967
1966
1958
1955

1957 (S, 1963)
1961*
1961
1966

1966
1950 (S, 1967)

1966
1961*
1962

1967

I960*
1964
1955
1954
1952
1962
1966*
1967
1961*
1960*
1968
1964
1965
1961
1966
1968

Gill
N
R
R
R
R
R
R
R
R
R
R
R
R
R

N
R
N
N

R
N

N
N
N

N

R
R
R
R
R
R
Ch
N
N
N
N
N
N
N
R
N

Cap.
LT/D
26
30
70
121
260
127
100
+20
+ 140
+ 8
+ 132
10
12
30

50
50
20
70

50
400

.13
20
+80

10

20'
+34
70
55
49
+ 10
110
18
45
50
+ 45
50
89
4
2
5

NOTE: Refinery sulfur plants noted as shut down are assumed to be
on standby and not abandoned as
the natural gas-based
plants are when the field is shut in. tOerated
to 50
sulfur
1967.
 OCTOBER 28, 1968
                                                    56

-------
gat loadings and reduce  sweetening
costs. These may  also  increase  the
pickup of hydrocarbons in  the solvent
and result in  a higher concentration
of hydrocarbons in  the acid gas.
  Therefore, sweetening solvents
which reduce  the cost of  sweetening
need to be evaluated also in terms of
how much they may add to the sulfur
plant investment or operating costs.
  Investment costs for sulfur recovery
units have shown a definite downward
trend  as technology  has  improved. A
large part of the reduction in  invest-
ment  cost  resulted  from   using  the
patented package-plant concept which
was developed  by Pan American  Pe-
troleum Corp. in 1956.
  This  concept  resulted  in  a  cost
reduction of  about  50%   in  plant-
investment costs  at  the  time  it was
introduced.
  Table  3 compares the actual  invest-
ment cost of plants built  in  1952 with
the  present  cost for  an  equivalent
plant. Today's plant  costs (1967) are
62-87% of the actual 1952 plant costs.
   When the increase in  construction
cost  is considered,  1967  plant  costs
are  36-50% of  today's cost for the
1952 sulfur-plant design. Therefore, as
W. L.  Nelson  has also reported, im-
proved  technology  has reduced the
contract cost despite  a 75% increase
in construction costs caused by in-
flation.8
   Fig.  2  shows  typical  investment
costs  for sulfur recovery plants. These
curves represent the contract price for
a one-train, two-reactor plant as  illus-
trated by  Fig. 1  (straight-through or
split-flow). Individual plants may vary
plus or minus 20% from these typical
curves.
   If  the feed  gas on  a  dry,  hydro-
carbon-free basis contains about  20
mole % hydrogen sulfide, the  plant
cost is  about 40% higher than for a
100% H2S acid-gas  feed.
  Fig. 3 shows the operating costs for
several  sulfur-recovery plants  which
aie operated in conjunction with other
gas-processing operations.
  These costs  include operating and
maintenance  labor and materials and
catalyst, but  do not include the cost
of loading the sulfur, power for the
air blower, or fuel and other operating
costs  for  incinerator and  dispersal
stacks.
  The air-blower power will vary with
the ratio of hydrocarbon to hydrogen
sulfide in the acid gas, type  of plant,
and the design  pressure drop.
  The charge for  power will also de-
pend  on  whether electric motor  or
steam turbine drive is used and what
the plant steam  balance  is.  A  good
average power  charge  for preliminary
evaluation  would.be  S0.35/LT based
on 2 hp/daily LT sulfur.
  It has been  Pan American's  expe-
rience that even sulfur-recovery plants
having capacities of several  hundred
Canadian sulfur-recovery plants from HjS
Operating company
Amerada

Banff Oil, Ltd.
British American Oil
Co., Ltd.



Canadian Delhi
Canadian Fina Oil
Ltd
Canadian Superior
Chevron Standard

Cornwall Chemicals
Great Canadian Oil
Sands, Ltd.
Home Oil
Hudson's Bay Oil &
Gas




Imperial Oil






Plant location
Olds, Alberta
Expansion
Rainbow Lake, Alberta
Pincher Creek, Alberta
Expansion
Clarkson, Ontario
Braeburn, Alberta
Nevis, Alberta
Expansion
Rlmbey, Alberta
Expansion
Turner Valley, Alberta
Calgary, Alberta
Buck Lake, Alberta

Wildcat Hills, Alberta
Harmattan, Alberta
Nevis North, Alberta
Expansion
Ontario
McMurray, Alberta
Carstairs, Alberta
Expansion
Biazeau River,
Alberta
Caroline, Alberta
Edson, Alberta
Lone Pine Creek,
Carstairs, Alberta
Sundre, Alberta
Dartmouth. Ontario
Halifax, Nova Scotia
Montreal, Quebec
Redwater, Alberta
Sarnia, Ontario
Expansion
Winnipeg, Manitoba
Refinery
or
Year natural Capac-
start- gas Ity
ad up tource LT/0
1964
1967
1968
1957
1962
1963
1965
1960
1966
1961
1965
1952
1967
1967

1961
1966
1959
1967
1965
1967
1960
1967

1968
1968
1965
1967
1968
1966
1966
1965
1S5C
1964
1968
1966
N
N
N
N
N
R
N
N
N
N
N
N
R
N

N
N
N
N
R
R
N
N

N
N
N
N
N
R
R
R
N
R
R
R
153
+ 33
75
225
+ 450
40
3
76
+ 50
246
+ 120
35
50
26

106
817
120
+ 30
75
350
42
+ 8

21
16
225
102
18
35
25
35
9
25
+ 60
14
Operating company
Irving Refinery

Uurentide Chemical
and Sulphur, Ltd.
Mobil Oil Canada, Ltd.
Pamoil
Pan American Pe-
troleum


Petrogas Processing,
Ltd.

Saratoga-Jefferson
Lake Sulphur
Shell Canada, Ltd.






Steelman Gas Ltd.
Texas Gulf Sulphur







Westcoast-Jefferson
Lake
Plant location
St. John, New
Brunswick
Montreal, Quebec
Wimborne, Alberta
Kessler, Alberta
Bigstone, Fox Creek
Alberta
East Crossfield,
Alberta

Balzac, Alberta
Expansion


Coleman, Alberta
Innisfail, Alberta
Jumping Pound,
Alberta
Jumping Pound West,
Alberta
Oakville, Ontario
Sarnia, Ontario
N. Burnaby, B. C.
Waterton, Alberta
Expansion
Estevan, Sask.
Okotoks, Alberta
West Whitecourt,
Alberta
Expansion
Expansion
Wildhorse Creek,
Alberta
Expansion


Taylor, B.C.
Table 2
Refinery
or
Year natural Capac-
itart- gas Ity
edup source LT/0

1961*
1958
1964
1962
1968
1968

1961
1967


1961
1960

1951
1967
1963
1966
1968
1962
1967
1965
1959
1962
1965
1963

1966
1968


1957

R
R
N
N
N
N

N
N


N
N

N
N
R
R
R
N
N
N
N
N
N
N

N
N


N

28
100
335
10
320
1480

870
+ 1100


377
100

90
140
46
35
-.5
1200
+ 450
15
380
700
+ 525
+ 650

30
+ 620


325
OCTOBER IS, 1968
                                                         57

-------
   Investment  costs  for  sulfur recovery  units
                                                                    Tiblo 3
Production capacity, IT/D
Acid-gas analysis, mole % H,S (dry basis)
Actual contract cost', 1952
Contract cost escalated to 1967 construction
Cost Index (1.75 x 1952 cost)
Contract cost in 1967 tor present design
Percent of 1952 plant cost
Percent of 1967. cost for 1952 plant design
18
62
$260.000

$450,000
$160,000
62
36
52
17
$491,000

$860,000
$430,000
87
50
   'Both plants had two reactors. Contract cost does not Include land, Inventory and working
    capital, owner's overhead and engineering, boiler feed water treating, steam condensation,
    or Incinerator and stack.
Example economics of third
Number of reactors per train
Theoretical sulfur recovery, %
Long tons/day
Investment, U.S. basis
Incremental costs for third reactor, annual
Operating expense
Capital charge at 20% of incremental
investment per year
Total
Incremental sulfur production, LT/YR
Netback sulfur price at plant, $/LT, required
to pay incremental operating expense
and capital charge
reactor
2
95.0
658
$1,940,000
$ 47,000
$ 66,000
$ 113,000
2,800
40
Note: Operating expense includes power for additional blower horsepower,
nance, and insurance.
Table 4
3
96.0
665
$2,270,000
catalyst, malnte-
LT/D do not require the full-time atten-
tion of an operator.
   The amount of  the operator's  time
assigned to the sulfur  recovery plant
will often depend on the other duties
which are assigned to  him  in  other
parts of the  overall operations, and
how much automation is built into the
sulfur plant.
   Outside  of occasional tests  of the
residue gas and inspection of the con-
trols, a sulfur-recovery  plant  normally
requires little  attention.
   However,  if  the hydrogen sulfide,
hydrocarbon,  or water  content of the
acid gas varies, more operating labor
or  automatic  analysis  and automatic
control of the air rate will be required
to maintain high recovery efficiency.
   Loading operations are often done
by contract labor on a  per ton basis.
Loading costs for tank  cars will  vary
from 10 to 154/LT depending on the
amount of sulfur to be  loaded, where-
as  the costs for loading solid  sulfur
will vary  from  55 to  65^/LT  where
gondola cars are used  and the sulfur
must be crushed  to  size, costs  are
somewhat higher.
   A simplified  method of evaluating
projects is based  on the  observation
that a 12%  rate of return (after tax)
on  100% equity  investment is ob-
tained if the  annual net income before
tax is 20%  of the investment.  This
assumes constant income for 20 years,
at an income  tax  rate of 50%  and
7% investment tax credit.
  The  relationship would of course
be different for a declining production
pattern as would prevail in many nat-
ural-gas-processing  applications  or  if
the uncertainty of acid-gas feed-supply
quantity  required  a  higher  rate of
return.
  On this basis, Fig. 4 summarizes the
effect of plant size and feed-gas  com-
position on economics. An example of
the calculation method for Fig. 4 is:

Sulfur product rate, LT/ D               50
               LT/YR           17,350
Investment (70  mole % H,S In feed)
  Contract price (Fig. 2)           $270,000
  Allowance for owners' overhead
  and engineering, boiler feed-wa-
  ter facilities, and  land at 15%    $ 40,500
Total  	    $310,500
Annual capital charge at 20% of
  investment	    $ 62,100
Capital charge,  $/LT	    $ 3.60
Operating expense,  J/LT (Fig! 3)   $ 1.50
+ electric  power for  air  blower   $ 0.35

Total production cost, $/LT ....    $ 5.45
  Since investments and operating ex-
penses vary with local conditions and
specific  design  requirements, the
values in Fig. 4 should be considered
as approximate.
  In the above calculation, no charge
is  included for the  acid-gas feed  to
the sulfur recovery plant and no credit
is taken for the value of the produced
steam  since these  factors will   vary
greatly depending on the specific plant.
  The investment  and operating cost
of an  incinerator  and dispersal  stack
are not included,  because, depending
on the situation, these could be either
(a)  very  expensive, (b) not needed,  or
(c) represent a net credit,  because the
sulfur recovery plant reduced the cost
of  incinerator and stack  which air-
control  regulations  would  otherwise
have  required. These factors must  be
taken  into  account as  appropriate  in
evaluation of  a specific case.
  Third  reactor. One method  of in-
creasing  the recovery is installation  of
an  additional reactor and condenser
system in series.
  Three-reactor  plants  can be de-
signed to  achieve  recoveries  of 96-
97%.  Table 4 shows an  example  of
the effect of a third reactor on  recov-
ery and  economics  for  a  658-LT/D
plant  which processes a rich acid gas
(90 mole  % H2S).
  The  third  reactor and condenser
increases the investment 17% and the
plant  recovery 1.0%. The additional
reactor would yield a 12% return on
investment  at a sulfur netback  at the
plant  of  about S40/LT.
  In  smaller  plants the  sulfur  price
required  to justify use of a third re-
actor  is higher.
  Highly sophisticated computer pro-
grams have been  developed for opti-
mization  of  the   many   flow   sheet
options and operating  variables. For
example, the recovery of a two-reactor
plant   can  be  increased   by design
changes  which add to the  plant cost.
  It was previously reported1 that use
of gas-to-gas  exchange or an in-line
burner instead of reheat gas (injection
of hot gas from some upstream  point
in  the process) for preheating reactor
feed  gas can  increase  the recovery
about 0.5% in a two-reactor plant.
  Recovery can also be increased by
optimization oi various plant tempera-
tures. The higher  investment required
for these design changes can often  be
justified  at  present sulfur sales prices.
  Product  purity.  Sulfur recovered
from  acid  gas in  a Claus-type  recov-

       THE OIL AND GAS JOURNAL
                                                         58

-------
 cry  plant usually has a purity above
 99.9%.  To  maintain this  purity  re-
 quires caie  in  handling, particularly
 if the material  is shipped as a solid.
    Availability of material having this
 purity is advantageous to the sulfuric
 acid manufacturer since it enables him
 to reduce his plant inveitment by elim-
 inating the liquid sulfur inlet filter.
    Where storage of sulfur in the solid
 form at the  producing plant is prac-
 ticed, however, it may be necessary to
 provide  sulfur  filtration  facilities to
 assure that remelted sulfur will  meet
 customer specifications.
    Since  shipment  of solid  sulfur in
 gondola  cars is common,  contamina-
 tion during shipment is possible. It is
 therefore important for  buyer  and
 seller  to agree  on  the  manner  of
 sampling and the point at  which the
 shipment is to be sampled.
    Because of the inherent high purity
 of  recovered  sulfur,  the  analytical
 techniques  used  to detect  impurities
 require more care  and precision for
 accurate results.  Larger sample  sizes
 than used for  Frasch sulfur samples
 are  generally   advisable,   often   by
 factors as large as 20:1.
   Off-color sulfur or high organic ash
 is  generally  a sign  that hydrocarbons
 are present in the feed to the  unit in
 excess amounts. Heavy hydrocarbons
 from  the plant inlet stream or exces-
 sive carry-over  of acid-gas solvent are
 generally the source  of carbonaceous
 materials that color the sulfur.
   Inorganic   ash  in  the  as-produced
 sulfur may result from attrition of the
•catalyst or from wind-borne dust sift-
 ing into  the storage pits. Where solid
 sulfur  is stored in  open blocks,  the
 possibility of atmospheric contamina-
 tion  increases.  Care must  be  taken
 during the loading  of solid sulfur to
 avoid inclusion of soil from the load-
 ing area  in the shipment.
   Although   most  specifications  for
 arsenic, selenium and tellurium  read
 "shall be commercially free of arsenic,
 selenium and tellurium," no literature
 references are readily available to de-
 fine the absolute  limits.
   Communication with analysts whose
 experience goes  back many years  or
 whose experience includes analysis of
 sulfur recovered  from  pyrites  would
 indicate that  contents less than 0.25
 ppm of arsenic, and 2.0  ppm  of se-
 lenium or tellurium can be considered
 to be "commercially free."
   These  limits  are  given by  Texas
 Gulf Sulphur in  their sulfur  manual
 as being  maximums  for Frasch sulfur

OCTOBER 28. 1968
 as well. It is  essential  that large-size
 samples be used, and that  blank de-
 terminations be run  on all reagents.
 In the past IS years, the authors  have
 not encountered any  recovered sulfur
 which exceeded these limits.
   Plant location and customer  require-
 ments may heavily .affect storage re-
 quirements at sulfur  recovery plants.
 Normally,  3-5 days  storage  is  pro-
 vided for liquid  sulfur  and  an  area
 set  aside for several  months'  storage
 of solid sulfur.
   In past years,  when  sulfur was in
 oversupply, it  was  not  unusual for  a
 customer  to  expect  the supplier  to
 carry several months' supply in storage
 in order to be considered  an  accept-
 able source.
   In the recent short-supply situation;
 customers considered themselves  for-
 tunate if they could supply their entire
 demand without allocation.
   Plants from  which offshore ship-
 ments are  made may  require more
 solid storage than would otherwise be
 required. Cargoes  of  sulfur are  gen-
 erally in multiples  of 10,000 metric
 tons.
   Storage  of at least this amount will
 be needed either at  the plant or at the
 port unless the outputs of several small
 plants can be  dedicated  to  a  specific
 shipment.
   The latter requires  coordination of
 both production and shipping facilities
 if excess demurrage and port  storage
 charges  are to be avoided.
   Location  of  solid  storage areas
 should be chosen, keeping in mind:
   1. Location  of  recovery  facilities.
   2. Accessibility to  rail and truck-
 loading facilities.
   3. Wind  direction.
   4. Proximity to land under  cultiva-
 tion.
   More  production. The increase in
 range  of H2S  concentration  in  acid
 gas to be processed  is  due to two  fac-
 tors; increase in sulfur prices and  air-
 quality regulations.
   Recovered sulfur has come  largely
 from acid  gas  removed'from  natural
 gas  or from refinery  gases. Another
 source of sulfur with vast poicnl.J is
 stack gases. It has been estimated  that
 12,700,000 LT  of  sulfur   from   all
 sources was emitted  to the atmosphere
 in the United States in 1966.'
   Many  processes  for  removal1 of
sulfur compounds  from stack gases
 are being proposed. All  of  the proc-
esses proposed to date,  however,  are
expensive.
   Because  of  regulations  restricting
 SO2 emissions in the more populated
 areas of  the  U.S.,  it is  probably that
 economic  methods to  process  stack
 gases  to  recover  sulfur will  be  de-
 veloped.8
   According  to Archie  V. Slack  of
 TVA in,  a  paper delivered.at the  154th
 National  Meeting of  the American
 Chemical  Society, sulfur recovered
 from power-plant  stack gases  could
 become a' major raw material source
 for the fertilizer industry.
   Mr.  Slack  estimates  that by  1970
 sulfur dioxide equivalent to 8 million
 tons/year  of  sulfur will be emitted
 from power plants alone burning coal
 and fuel oil.
   However, because of the rapidly in-
 creasing world  demand,  sulfur recov-
 ered  from this source  should remain
 a small percentage of the world sulfur
 consumption.
   Increased prices have also stimulated
 increased  interest in sulfur exploration,
 particularly offshore in the Gulf Coast
 and in  West  Texas.  Results  offshore
 to  date have  not  been  outstanding.6
 In  the  Federal  Offshore-Texas Sulfur
 lease sale held in  December  1965, a
 total  of 70,560 acres  were purchased
 for  $33,740,000  for  an  average  of
 $4807 acre.
   No announcement of  a  sulfur dis-
 covery  has been made by any of  the
 leaseholders.  Elcor Chemical  Co. has
 announced7 a  new process for recov-
 ery of  1,000  long  tons/day of sulfur
 from gypsum  in Culberson  County,
 West Texas. New, unique Frasch  oper-
 ations are starting for the first lime in
 the  U.S.,  where the Frasch  method
 has been  used on a deposit not  asso-
 ciated with a salt dome.
  The Duval  Corp. has let a  contract
 to construct8  a Frasch operation in the
 same county,   which  will  recover
 2,500,000 LT/VR. Duval will complete
 expansion of  the Pecos County Frasch
 operation  to  350,000  LT/YR.  Sinclair
 has a smaller  Frasch operation in the
 same general area.

             References
  I.  H. Grekel, L. V. Kunlcel, R. McGal-
 liard, Chcra. Eng. Progress, September !?65.
 p. 70.
  2. R. Mungen, Proceeding Gas Condition-
ing  Conference.  University  of Oklahoma,
April 4-5. 1967,  Paper E.
  3. W. L. Nelson, The Oil and Gas Journal,
May 27,  1968, p. 111.
  4. Sulfur,  No. 73,  November/ December
 1967. p.  20.
  5. Sulfur,  No. 73,  November/ December
 1967. p.  24.
  6. The Oil and Gas Journal, Aug. 12,1968,
p. 123.
  7. Business Week, July 20. 1968, p. 113.
  8. Chemical Week. July 27, 1968. p.  23.
                                                          59

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     PROCESSES  RESEARCH, INC.
     INDUSTRIAL PLANNING AND RESEARCH
APPENDIX F - ELCOR CHEMICAL CORPORATION INFORMATION
                   60

-------
                                       February 16, 1972
Mr. Villiaa Haggard
Eleor Cheaical Corporation
Wllco Building
Midland. Teaas  79701

Subject:  Claus Sulfur Plant
          Performance

Dear Mr. Haggard:

Sovoral of the Methods being considered for abatement of aulfur emissions
to tho ataosphere include Claus •olftir units.  The Environmental Protec-
tlon Agency Offlea of Air Program ha* engaged Procesees teaeareh. Inc.,
to study th« afflcaey of Clans aulfur plants IB pollution abatoaant (Con-
tract Ho. 68-01-0242).

Wa undaratand that yoor eoapaay oparotaa Claua uaita rccorarlog sulfur
which would othanrise ba oaittad to tha atnoaphara.  Plaasa lat us hava
available ioforaatioo regarding tha parfontaaea of thaaa units, aa follow*.
Tha Offica of Air Pregras* iataraat ia in davaloping pollution control
nathods and tha raquastad inforaatioa is for usa in tbaaa afforts.

1.  Location, daily sulfur capacity, days of operation annually and annual
    sulfur production.

2.  Claua process variation ueedj  straight through, split flow, direct
    oxidation, aulfur recycle, etc.

3.  Huaber of catalytic atages and nethod of reheating procaaa vapor*

4.  Source, quantity and composition of acid gas food.

5.  Quantity and composition of tail gaa.

6.  Incineration or other tail gas treatcent.

7.  Frequency of catalyat change and aalnteaoace.
                                   61

-------
Mr.
February IS, 1972
     2
A.  Operator atteadance and trouble.

9.  Conauttption and geatratloa of fuel, water, power and stem.

If ae»a of thia Infomatioa !• available for ««• er nora of yoer Claua
unlta. plaaae let us know when va ajar expect to receive it.  We thank
you for your cooperation.

                                       Vary truly roura,

                                       FBOCESSE8 RESKABCH. INC.
WDB/nk

cc:  G. S. Haaelberger
     M. R. Jeeter
     P. V. Sprite
                                       \;. D. beera
                                       Project Manager
                                  62

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                                                ELCiOR
                                               CHEMICAL CORPORATION


                                  WILCO BUILDING  HIDLAND,TEXAS 79701  9IS 683-4271
                                  March 3, 1972
Mr. W. D. Beers
Process Research, Inc.
Industrial Planning and Research
2912 Vernon Place
Cincinnati, Ohio  45219

Dear Mr. Beers:

In answer to your letter of February 18, 1972, we are
pleased to supply information regarding Glaus sulfur
plant performance:

1.  We have one sulfur plant in operation, the Fashing
    Plant located in Atascosa County, Texas, which we
    designed and constructed.  It has a capacity of
    approximately 55 long tons per day but is limited
    by available feed gas to approximately 40 tons per
    day.  It operates throughout the year except for
    occasional down time for maintenance.  Sulfur pro-
    duction during 1971 was 13,500 L.T.

2.  The process used is the Split Flow.

3.  The plant has two catalytic stages and uses bypass
    reheating .

4.  The source of feed to the sulfur plant is the acid
    gas stream removed from Lone Star Gas Company's
    Fashing gas processing plant.  The composition is
    approximately 821 carbon dioxide and 18%
5.  We do not have a recent analysis of the tail gas,
    but it is essentially all nitrogen carbon dioxide
    and water vapor.

-------
Mr. W. D. Beers                              Page 2
6.  There is no additional treatment beyond the two
    catalytic reactors.

7.  Catalyst change is required every five to seven
    years.

8.  The plant is relatively trouble free.

9.  The plant is essentially self-sufficient except
    for minor amounts of fuel, water and steam supplied
    by the adjacent Lone Star Plant and the electrical
    power supplied by the local power company.

I hope this information is of some assistance in your
analysis of the Glaus process.

                         Very truly yours,

                         ELCOR CHEMICAL CORPORATION
WJII: jm

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  PROCESSES RESEARCH, INC.
  INDUSTRIAL PLANNING AND RESEARCH
APPENDIX G - SHELL OIL COMPANY INFORMATION
                65

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                                           February 18,  1972
Mr. L. P. Ha»by
Manager of Environmental Conservation
Shell Oil Company
One Shell Plaza
P. 0. Box 2463
Houston, Texas  77001

Subject:  Glaus Sulfur Plant Performance

Dear Mr. Haxby:

Several of the methods being considered for abatement of sulfur
emissions to the atmosphere include Claus sulfur units.  The
Environmental Protection Agency Office of Air Programs has en-
gaged Processes Research, Inc., to study the efficacy of Claus
sulfur plants in pollution abatement (Contract Ho. 68-02-0242).

We understand that your company operates Claus units recovering
sulfur which would otherwise be emitted to the atmosphere.
Please let us have available information regarding the perform
ance of these units, as follows.  The Office of Air Programs
Interest is In developing pollution control methods and the re-
quested information is for use in these efforts.

1.  Location, daily sulfur capacity, days of operation annually
    and annual sulfur production.

2.  Claus process variation used:  straight through, split flow,
    direct oxidation, sulfur recycle, etc.

3.  Number of catalytic stages and method of reheating process
    vapor.

4.  Source, quantity and composition of acid gas  feed.

5.  Quantity and composition of tail gas.

6.  Incineration or other tall gas treatment.

7.  Frequency of catalyst change and maintenance.
                              66

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Mr. L. P. Haxby
February 18, 1972
Page 2
8.  Operator attendance and trouble.

9.  Consumption and generation of fuel, water, power and steam.

If some of this Information is available for one or taore of your
Claua units, please let us know when we may expect to receive it.
We thank you for your cooperation.

                                            Very truly yours,

                                            PROCESSES RESEARCH,  INC.
                                            W.  D.  Beers
                                            Project Manager

WDBtmer

cc   G. S. Haselberger
     M. R. Jester
     P. W. Spaite
                              67

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                                               RECEIVED
                     SHELL  OIL  COMPA;WV  !l''°
                               °N'SH!U'UiA APR  19  JH  9:3
                                P.O. BOX
                              HOUSTON, TEXAS 77001
                                        A.-l. KINNtY. INC.
                              April 17, "~ SEARCHING.
Mr. W. D. Beers
Project Manager
Processes Research, Inc.
2912 Vernon Place
Cincinnati , Ohio  1*5219

Dear Mr. Beers:

        Please refer to your letter of February 18,  1972,  requesting  certain
operating data on commercial Glaus sulfur units for  inclusion  in  a report
you are preparing for the Environmental Protection Agency  (Contract No.  £8-
02-02U2).  On the basis of your letter and subsequent  telephone contacts with
Mr. Thomas of your company, we understand that the purpose of  the study  you
are conducting is to assess the efficacy of such type  units in emission
abatement programs.  We further understand that, for your  purposes, it is
not necessary that the location of the plants be disclosed.

        In the belief that it would prove useful in  your report to include
data on plants of various sizes, we requested our operating groups to supply
information on each; a large, medium, and relatively small sized  unit.   These
data now have been made available to us and, at this time, we  are transmitting
them to you, attached.  We hope the delay has not interfered  seriously  in
meeting your "deadlines".  As you will note, our data  are  arranged, in the
interest of uniformity, in the same context as were  the several points you
raised in your letter.

        We trust this information will suffice for your needs.  Please let
us know if we can be of further assistance.

                                     Very truly yours,
EWS:sw                               L.  P.  Haxby,  Manager
                                     Environmental Conservation Department

Attachment

cc - Mr.  Thomas, Process  Research,  Inc.

-------
                           GLAUS SULFUB  PLANT  UNITS
                                                    Plant  B
                                                             Plant  C
1.
2.

3.


I;.
6.

7.

8.
a) operator attendance
b) operating troubles
9.  utilities
       a)  fuel  gas, MCF/day
       b)  steam generated, Ibs/hr.
a) daily sulfur production,
   long tons/day
b) days of operation annually
c) annual sulfur production,
   long tons/yr.

a) process "variations"          +	

a) number of stages                 3
b) method of reheating vapor   note 1
a) acid gas feed source
b) quantity, MCF/D
c) composition, % (note 5)
     H2S
     C02
     hydrocarbons

a) tail gas quantity, MCF/D
b) tail gas composition, %
     H2S
     N2
     C02
     CO
     so2
     H20
a) tail gas treatment

a) catalyst change frequency   note 6
185
353
65 ,000
120
31,5
1*1,500
about kO
320
11,600
                                                straight through
                                            steam
                         hot by-pass
note 2
7,600
68
30
2
note 3
2,300
90
8
2
note U
1,500
71
25
U
                                     lU.OOO
              6,500
                                                          U.OOO
o.Uo
79-
17.5
2.5
0.2U
-

1.
65.
3.5
—
0.5
30.
incineration -
-
-
-
-
8,000-10,000 ppm
—
•
             ca. 18 mos.  note 6
126/hrs/wk   168 hrs/wk   78 hrs/wk
                                     note 7
                                  500
                               3U.OOO
             note 8
                192
             35,000«
                                                         note 9
                                                            250
                                                         8000-9000
 note  1  side  stream of  acid  gas  is burned in  in-line burners after condenser
 note  2  sulfinal  process  gas sweetening plant discharge
 note  3  crude oil refining process
 note  U  DEA scrubber/ethylene plant
 note  5  excludine trace amounts, if  any, of N2  and H20
 note  6  approximately once every three years
 note  7  regeneration of catalyst beds, maintenance of 2:1 ratio; of H2S to  S02,
         maintenance of  hydrocarbon recovery unit which is required;.to minimize
         carry-over of hydrocarbons to sulfur  plant
 note  8  none  reported
 note  9  low throughput  lowers efficiency, ineffective demister  mat.

 •consisting of about 26,500#/hr  of 300 psig steam and about 9,00#/hr of  50 psig steam.

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    PROCESSES RESEARCH, INC.
    INDUSTRIAL PLANNING AND RESEARCH
APPENDIX H - STAUFFER CHEMICAL COMPANY INFORMATION
                  70

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                                        ?o»r«ary 18. 1972
Mr. o. a, Boborto
Vie* Proaidoat of Bnginoorlag
Stanffor Qtottiool Corporation
J. B. Coecoo Englnoorlnt Canter
Dobb* Perry. Sow Tork  10S22

          CUo* 8vlf«r Mant Porfontaeo

     Mr. Bobortat

Several of eh* aothoda being considered for abet event of ottlfur caleaioaa
to tfao otKOopboro ioelu4* Claw owlfior onit*.  Tfco KikTiroojMatal Protoetioa
       Offieo of Air rrognHW hao «a§«t«4 Proooooo* Booooveii. !••., to
      tho offieaey of Clatto cvlfur plant* to •ollntloa aoatoMat (Cootraet
HO. 66X12-0242).

W« oa4oMtaa4 that your eo^aoy oporatao Clou onlta rooovoriai ralfwr which
woold othorwioo bo omitted to tho atMophoro.  Ploaoo lot u» h*v» avaULablo
ioforwitioa rosar^iog tho porfonuneo of thooo oalto, a> follow*.  Tho Offieo
of Air Prosroo* latoroat io is do^oloping pollatioo control oatfcoa* a«4 tho
          iftfonoitioa io for ooo ia thooo off ore*.
1.  Location . daily avlfiur capacity,  daya  of oporotioa aaaoally and aanoal
    •ttlfur protfttctloa.

2.  Claoa procoao variation osod:   otralgbt throBgh, oplit flow, dinot
    oxidation, •vlfar rooyelo,  ote.

3.  Koobor of catalytic otogoo  and nothod  of rohoatins proooo* vapor.

4.  Soorco. quantity aad eonpooition  of acid can food.

5.  Qttaatity and eoapooltion of tail  aaa.

6.  Xoclnoratioa or othor tail  (ao troat«Mt.

7.  Proqnoney of catalyst ohango and  •aiatonanco.

8.  Operator attendance and erovblo.

9.  Conaviption aad gonoration  of  f«al, vator, power and •ton*.
                                    71

-------
 Stauffer Chemical  Corporation
 Page  2
 February 18,  1972
 If some of this information is available for one or more of your Claus
 units, please let us know when we may expect to receive It.  We thank
 you for your cooperation.

                                     Very truly yours,

                                     PROCESSES RESEARCH, INC.
                                     W. D. Beers
                                     Project Manager
WDSrfj

cc:  G. S. Haselberger
     M. R. Jester
     P. W. Spaite
                                  72

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     . B. r.HT.UN
  'Nh !"NG H.NIFR
 staler  Staulffe¥-yC?.hemical Company
1 ^^*^ j  Dobbs Ferry, New York 10522 / Telephone (Area Code 914) OWens 3-1200
                       '72 APR  3  AM  |Q:
                                            March 21,  1972
                       A.I-.;. KINHLr. u-IC __ .
                       FRO. RJZStAliCH INC-
Mr. W.  D.  Beers
Project Manager
Processes  Research  Inc.
Industrial Planning and Research
2912 Vernon Place
Cincinnati, Ohio  45219

Subject:   Glaus Sulfur Plants

Reference:  Letter  from W. D. Beers to D. H.  Roberts  dated
            February 18,  1972

Gentlemen:

The following information is from various Stauffer Chemical  Company
Claus Sulfur Recovery Plants.  The data as listed is  in accordance
with the referenced letter.
1. a.  Plant       Baytown,
      Location    Texas

   b.  Daily        100
      Sulfur
      Capacity
      T/D

   c.  Day of       335
      Operation
      Annually

   d.  Annual       33,500
      Sulfur
      Pro-
      duction

2. Claus Process    Straight
   Variation       Through

3. Number of         2
   Catalytic
   Stages
               Delaware City,   Le  Moyne,   Long Beach,
                   Del.

                   400
  Ala.

 250
   Calif.

 450 (4 units)
                   335
                 134,000
                  Straight
                  Through
 335
83,750
Straight
Through
 335
150,750
 Straight
 Through
                                73

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   Mr. W. D. Beers
   Processes Research Inc.
March 21, 1972
Page Two
ta. Method of
Reheating
Process
Vapor
4. a. Acid Feed
Gas Source
b. Uuantity-
SCFM
c. Composition-
% H2S
N2
co2
CH4
H20
cs2
NH3
5. a. Tail Gas-
Quantity-
SCFM
ta. Composition-
% H2S
S02
s
co2
N2
H20
6. Gas Treat-
ment
In-line
Burners


Refinery
2800

50.3
1.0
46.1
2.5
-
-
-
6250


0.7
0.3
0.2
21.8
51.5
25.5
Incin-
eration
In-line
Burners


CS2 Plant
7680

96.3
0.2
0.2
3.2

0.2
-
20,760


0.9
0.4
0.3
1.1
64.2
33.1
Incin-
eration
In-line
Burners


CS2 Plant
4130

95.5
0.4
0.6
3.4
-
0.5
-
13,200


1.0
0.5
0.3
1.3
64.3
32.6
Incin-
eration
In-line
Burners


Refiner
4480

83.5
0.4
11.5
0.5
4.0
-
0.1
25,320


0.8
0.4
0.3
4.4
60.2
33.9
Incin-
eration
7.   Frequency of
    Catalyst Change
    Approx.  Years

-------
   Mr.  W.  D.  Beers
   Processes  Research Inc.
                      March 21, 1972
                      Page Three
8.  a.  Operator Attendance-
      Time

   b.  Trouble
 1/4         1/4       1/4       1/4

Very low    Very low  Very low   Very low
                                            191
                        130
9.  Consumption/
    Generation

   a.  Gas SCFM

   b.  Steam
   c.  Power
   I hope the above information will satisfy your requirements in
   completing your study under Contract No. 68-02-0242.
460
Consumed
within
Plant
Consumed
within
Plant
Consumed
within
Plant
Consumed
within
Plant
                                      Very truly yours,

                                      STAUFFER CHEMICAL COMPANY
                                     A   A:  ,
   LLZ:gm
   Encl.
       L. L. Zuber
       Sr. Project Engineer
                                    75

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   PROCESSES  RESEARCH, INC.
   INDUSTRIAL PLANNING AND RESEARCH
APPENDIX I - FORD, BACON & DAVIS INFORMATION
                76

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       , Bacon
Sulfur Recovery Plants
          77

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                                                                                    CZJ
                         i»fc_4ircONOENSING PASS

                           =—"• 'CONDENSING PASS
                                                                                                 ACID CAS

                                                                                                 REACTION GAS WITH
                                                                                                 SULFUR PRODUCT

                                                                                                 REACTION FEED  GAS

                                                                                                 SULFUR PRODUCT
BOILER FEED WATER
               Typical Combination Boiler-Condenser Unit (Three Reactors)


Ford, Bacon & Davis

Sulfur Recovery Plants
are a modern-day improvement of the original Claus
process for recovering sulfur from hydrogen sulfide
gas. There are more of  these type plants being
installed domestically than any other, Ford, Bacon
& Davis having completed more than 45 projects.
  Most of Ford, Bacon & Davis' plants have been
custom-designed and constructed for refinery and
chemical plant applications to process the actual
gas stream available. Except for the very smallest
units, custom-designed plants have  proven to pro-
vide a much  more satisfactory installation than a
skid-mounted or  an   off-the-shelf  design,  which
often compromise  efficiency and operation of the
plant for the sake  of compactness.
  FB&D plants are exceptionally flexible, and nor-
mally can be operated at a  rate of  as low as one-
third of design capacity. Special-design plants allow
operation at  even lower capacities.
  Ford, Bacon & Davis, as a national engineering-
contractor, offers complete  process  design,  detail
engineering, procurement, construction, and start-
up services, anywhere in the Northern Hemisphere,
and design and procurement services anywhere in
the world.
  The principal feature of  the process described
herein is a  unique, patented vessel arrangement
referred to as a boiler-condenser. This vessel, illu-
strated  above, combines  into one piece of equip-
ment several functions, such as burning the HaS
gas, cooling and condensing the sulfur, separating
the sulfur product from the  gas, and  producing
steam. This design has been proven to provide a
high-quality  unit  with maximum  recovery  levels
and easy operation at much lower costs than is pos-
                                                                       9 I CAM

                                                                             tiL
                                                                    .„»       	
                                              sible with the older-style Claus plants that require
                                              as  many as six vessels to accomplish the various
                                              functions.
                                                In very large plants where a single vessel would
                                              be too large, or where high-pressure steam genera-
                                              tion is desired, a boiler and a single, separate con-
                                              denser can  be provided as shown on Page 3.  This
                                              also provides extensive cost savings and simplicity
                                              of  operation, compared to  using several separate
                                              condensers.
                                                The reactors are also combined in a single vessel,
                                              as  shown  above, unless the  size of  the  vessel
                                              becomes impracticable,  in which case they are sep-
                                              arated as shown on Page 3. Also, because of increas-
                                              ingly-strict  pollution requirements, the use of three
                                              reactors is  now often required to  meet codes (in
                                              certain areas the  third reactor is mandatory). In
                                              many applications, the third reactor can be justified
                                              economically, because the stack  height can be re-
                                              duced due to the higher recovery levels.
                                                In addition,  we have also designed a number of
                                              plants to process  gas streams that contain  poten-
                                              tially-troublesome components such as ammonia,
                                              hydrocarbons, CSz, and COS. The  process  shown
                                              on Page 3  also includes a separate combustion
                                              chamber which  is provided  as part of the  design
                                              where required to  properly handle large concentra-
                                              tions of these components.
                                                Cost estimates  and utility requirements can be
                                              furnished from these data: Feed gas analysis (vol-
                                              ume; temperature; pressure), steam  pressures avail-
                                              able or desired, utilities available, site location and
                                              ambient conditions,  storage  requirements,  and
                                              recovery and SO* limitations (if any).
                                                         O CamrlaU 1171, Ford. Bmnm * Oant. /«<•.  • />ri»(.-J in VJS.A.
                                           78

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      Typical Separate Sorter and Condenser Unit (Two Reactors)
How the  Plants Operate

The Claus process  involves  the combustion of
approximately one-third of the HaS to SO? and the
subsequent reaction between  the remaining HsS
and  the produced SOj  to form sulfur and water
vapor, with the  subsequent recovery of the sulfur
product.
  Ford, Bacon & Davis offers the modernized Claus
process in two basic process schemes, referred to as
straight-through and split-flow. The most common
application is the straight-through process, which
is illustrated in two versions  (above and  on the
facing page), wherein  all of  the  acid gas  is fed
through the burner.  This  process is used for most
acid gas streams that contain high concentrations
of HzS,  generally in the  range  of 50 per cent or
higher, such  as  the  off-gas from a typical  amine
unit  in  a  refinery.  Our  process can provide the
highest recovery level available from the Claus-type
process. Also, we are licensed  for  various  other
processes to recover  additional sulfur from  the tail
gas  from the Claus process,  which provide even
higher recoveries.
  The  split-flow process  is required for lean acid
gas streams of less than 50 per cent HjS, such as
are found in certain gas fields where high concen-
trations of CO- are present. In the typical split-flow
unit, as much of the acid gas as possible, without
adversely affecting combustion, is fed to the burner
in the combustion chamber with air, where a large
percentage of the HzS  is combusted to SO;. The
remainder of the acid gas is mixed with the  boiler
effluent and fed directly to the reactor. The process
is designed in this way since the flame could not be
maintained if all  of the acid  gas were fed  to the
 burner, as in the design of a straight-through unit,
 due to the inerts present.
  In the straight-through process, all of the acid
gas and the combustion air are fed through a spe-
cial burner where one-third of the HiS is burned to
SOz. 'Effluent  from the second cooling pass, con-
taining sulfur vapor created from the non-catalytic
reaction between the HSS and 80s in  the first two
passes, is condensed in the first condensing  pass.
The sulfur product, which is recovered in the first
separator, is drained to storage. Gases from the first
separator  are reheated with a  hot  gas by-pass
stream from the second boiler pass to provide the
necessary reaction temperature.  This is also the
reheat method used on the second reactor  feed.
Other reheat methods can be used which provide
higher recoveries, but at relatively higher costs.
  Sulfur vapor is produced in the first reactor from
the reaction between the H»S and SOj in the pres-
ence of  a  bauxite catalyst.  The resulting  sulfur
vapor from the  catalytic reaction is condensed in
the second condensing pass, separated in the second
separator,  and drained to storage. The conversion
and recovery  cycle is  repeated in the second and
third reactors and the other condensing passes and
separators. When a third reactor is used, the reac-
tion feed gas is normally heated in  a reheat ex-
changer to reaction temperature  by using the first
reaction  effluent.
  The incinerator converts  the sulfur compounds
remaining  in  the tail  gas from the plant to 80s.
The design normally  provides for a tail  gas  stack
of sufficient height  to meet  local pollution code
limitations on 80s concentration  at grade.
  Normally, a concrete sulfur storage pit is pro-
vided to store the sulfur in a molten state for load-
ing  into trucks or rail cars. The sulfur is kept
molten with steam produced in the plant.  A steel
storage tank is sometimes used on smaller or skid-
mounted units.
                                            79

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Two 135 LTD sulfur recovery units with 300" derrick-supported stacks • Humble Oil and Refining Co., Bay way Refinery, Linden, New Jersey
    Operating  and  Maintenance Costs
    Extensive automatic controls are provided to allow
    FB&D plants to operate virtually unattended and
    to shut down the plant in the event of a hazardous
    malfunction. Only one to two manhours of super-
    vision per  twenty-four hours of  operation  are
    normally needed.
      Utilities required for the plant are nominal. The
    connected electric load is  approximately 2 horse-
    power per  ton of production, most of which is
    required for the air blower,  with a small amount
    required for the intermittent operation of the sul-
    fur pump, lighting, etc. Fuel gas is required only
    for start-up of the sulfur  plant and operation of
    the tail  gas incinerator.  Instrument air or gas of
    3 to 4 s.c.f.m. and treated boiler feed water for the
    quantity of steam produced are  the  only  other
    utilities  required.
      The unit  will produce approximately 250 pounds
of steam per hour per ton of sulfur production. The
value of the steam that is produced will normally
offset the cost of the utilities required for the unit.
If the steam cannot be used, it can be condensed
and returned to the boiler-condenser.
  The most economical plant is a single boiler-con-
denser producing all the steam in the 20 to 150
p.s.i.g. range. In the larger units, or where  high-
pressure steam is required  (wherein the  boiler is
separated  from  the condenser), as much as two-
thirds of the steam can be produced at higher pres-
sures (up  to 550 p.s.i.g.).
  Maintenance costs are normally less than 1 to
2 per cent per year of installed cost, due to the
small amount of rotating equipment, lack of cor-
rosion, etc. Catalyst is inexpensive, and normally
has a minimum life of from three to five years.
                                                  80

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                                       Two 135 LTD sulfur recovery plants • Humble 0/1 and Retini
18 LTD sulfur recovery plant with guy-supported tail gas stack • Hudson's Bay Oil and Gas Co. Ltd., Si
, California
                                                        81

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                 Sulfur recovery and amine treating units specifically designed to
                 process 5 to 50 tons of sulfur per day (Canton, Ohio). A duplicate
                 facility was also completed at Buffalo, New York • Ashland Oil Co.
Amine Treating  and  Related  Projects
Ford, Bacon & Davis also offers extensive experi-
ence in amine treating and related facilities as well
as in sulfur recovery. We are also licensed to use
various treating processes, such as Shell's Sulfinol,
and  many  gas  sweetening units of all  types  have
been completed in connection with sulfur recovery
facilities, including both  MEA and DBA. A DEA
(amine) unit will be required for refinery installa-
tions where CS2,  COS, or other contaminants are
present which would cause problems such as fouling
an MEA solution. The MEA (amine) unit is nor-
mally used in natural gas service and where certain
contaminants are not present in refining units.
  Since amine treating  or  other  gas  sweetening
units normally are required in  conjunction with,
and  are adjacent to, sulfur recovery facilities, there
is merit in considering the award of  a  single con-
tract to include these units with the sulfur plant.
  One very  important  advantage  in  combining
more  than  one unit  into a single contract is the
ability to manage the construction as a single proj-
ect, which  greatly reduces the indirect field and
home office costs when compared to two separate
projects. The majority of the turn-key facilities we
install include both amine and sulfur plants as a
single project. Thus our experience is comparable in
both areas.

        Tail Gas Recovery Processes
  Ford, Bacon & Davis is also licensed for various
processes to recover sulfur compounds from the tail
gas of sulfur  plants,  in order to increase recovery
levels, and to meet increasingly stringent air pol-
lution codes  (S02 emission). These processes can
be installed  in  conjunction with Ford,  Bacon &
Davis sulfur recovery plants when built, or for exist-
ing sulfur plants.
                                              82

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flmme treating and
Sulfur recovery
units • Farmers' Union
Central Exchange,
Laurel. Montana

                                                recovery plant and refinery
                                          gas sweetening unit (Douglas Oil
                                          Paramount, California). A similar
                                          facility was also completed at
                                                 Colorado • Continental 0/1

                                                       83

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                Expansion of reformer
                facilities • SteHy Oil
                Co., El Dorado, Kansas
                   , ,»5ilCOn &.^IVI6 has a wide range of experience in process design,
           engineering, and construction in a wide range of related facilities —
       • Petrochemical Plants • Oil Refining and Processing Plants • Natural Gas Processing /nsta/lations
     • Compressor Stations • Off site facilities • Industrial Plants • Mining and Materials-Handling Facilities
1 Power Plants • Pipe Lines • Municipal Facilities • Paper Mills • Industrial Engineering • Appraisals and Valuations
  PROCESS PUNT DIVISION: 2908 National Drive (Garland) « P.O. Box 38209 • Dallas, Texas U.S.A. 75238 • 214/278 8121
                       Also Monroe • Tulsa • Baton Rouge • New York • Calgary • Brisbane
                             Major refinery expansion • Continental Oil Co., Colon, Panama
                                                   84

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      PROCESSES  RESEARCH, INC.
      INDUSTRIAL PLANNING AND RESEARCH
APPENDIX J - THE RALPH M. PARSONS COMPANY INFORMATION
                   85

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 PR 109
 Job
        £PA - OAP
local ion


SubjecI
                PL.A+JTS
PROCESSES  RESEARCHING.

    INDUSTRIAL  PUNNING
       AND  RESEARCH
                                    CINCINNATI         NEW YORK
Che
-------
                                              February 21, 1972
Mr. 0. C. Roddey
Vice President, Precontract and
The Ralph H. Parftens Coapany
(>17 West Seventh Strict
Los Angela*, California  90017

SubJact:  Glaus Sulfur Unita and Tail Gas Tr*ats*nt

Dear Mr. Roddey:

Several of the nethoda being considered for abateoent of aulfur eniaelons
to the atmosphere include Claua sulfur unita.  The Environnental Protection
Agency Office of Air Prograea has engaged Proeeasea Research, Inc., to
study the efficacy of Clans aulfur planta in pollution abatement (Contract
tlo. 68-02-0242).

Me underatand that yoor coapany la a proadnent designer of Claua units
worldwide and has developed, with Union Oil Company of California, a
procesn for Claua tail gaa pollution abAfceaettt.  We are referring to your
Beavoo Sulfur Rwnoval Proeoas, deaeribed in the February 7, 1972. iaaue of
the Oil and Gaa Journal.  Pleaae let us have inforoatiea available regard-
Ing typical Claua sulfur unita and the Beavon procaaa, aa follows:

1.  fcr typical Clann sulfur unite, auch as thoae baaed on natural Ran
    (dully aulfur capacities of 10 tone, 100 tone, and 1000 tone, and
    gao feed concentratlone of 13 aole nercent, SO «ole percent, and 90
    nole percent 1325, and units havi»n two and three Claua catalytic
    stages are of particular interest);

    ,a.  Percentage sulfur recoveries and tall gas cexpositions for varioua
        acid gaa feed concentrations and varioua ntnbera of catalytic
        stagea.

    b_.  Variation of aulfur recovery during the uaual life of the catalyst.

    £.  Variation of aulfur recovery with acid gaa feed at lass than full
        capacity such as half of full feed rate.

    d.  Approximate inveatajent, royalty, catalyst costs, and consusjption
        and generation of fuel, water, power and stead for varioua dally
        sulfur capacities, varioua acid gaa feed concentrations and
        varioua Quakers of Claua catalytic stages.  (Do these include
        the acid gaa recovery unita* acid gaa blovora, air blowers, and
        tall gaa incineratorsT).

                                  87

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Mr. 0. C. Boddey
Page 2
February 21. 1972
    e.  Operator attendance requirement* for various dally sulfur capac-
        ities, and unbar of daye of operation Co be expected annually.

    For Beavon Sulfur Removal Process Units treat Ing Claus call gaa (daily
    sulfur capacities of 1 ton, 10 tons and 100 tons, end Claus tail gaa
    fesd concentrations of 0.) mole percent, 1 sole pareeat and 4 awl*
    percent H2S + S02 + S •»• COS + €83 are of particular Interest):

    a.  Approximate investment, royalty, catalyst costs, sad constant ion
        of fuel, water, power and st«aa for various dally sulfur capac-
        ities and various Claua tail gas feed con cent rations.  (Do these
        include the stripping of the H2S from the coadenaateT).

    b.  Operator attendance and maintenance requirements.

    £.  Percentage sulfur recoveries and off gas compositions for various
        Cleus tail gas feed concent rations.

    d.  Variation of sulfur recovery during the usual life of the catalyst.

    e.  IB the quality of the sulfur recovered by the Beavoa process equal
        to that of Claus sulfur?

    f.  What* if any, air pollution is presented by ontralnnent of catalyst
        overhead from the Stretford tower?   Is incineration of the off gas
        advisable?

    g.  A principal cause of poor sulfur recovery in Glaus plants is de-
    ~   viatlen froa the optimum feed ratio of air to H2S, resulting from
        inadequate instrumentation or careless operation.  This also
        results in variations froa the stoichlometrlc balance of I^S end
        SO 2 in the tail gas.  Therefore, tall gases from Cleus units having
        the greatest need for pollution abatement are likely to contain
        unbalanced and erratic quantities of U2S tod S°2-  Tha Beavon
        process appears to be insensitive to such feed fluctuations.  Do
        you concur in this observation T

    h.  Per a new Claus unit,  should the Beavon process replace the  third
        Clans stage?  Should the Beavoa process replace the Claus unit
        eltogether?

    i.  For an add gaa baring an excessive ratio of SOi  to HjS.  should
        the Beavon hydrogenatlon step be uoed to adjust the ratio for
        feeding the Claua unit?  Is this more advantageous than catching
        the excess S<>2 in the  Cleus tall gas treatment?
                                   88

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Mr. 0.  C.  Roddey
Page  3
February 21.  1972
Wo will appreciate  receiving •!! of the  above  Info rant Ion  which  yoo can
aake available Co u*.  Pleaao  let us know when we can expect  to  receive
It •


Wo thank you for your cooperation.


                                               Vary truly  yours.

                                               PROCESSES RESEARCH,  IHC.
                                               W. D. B«er»
                                               Project Manager
Wi)B:fj

cc:  C. S. Uaaalbergar
     K. R. Jaatar
     P. W. Spalte
                                   89

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      The  Ralph M. Parsons Company

               Engineers ' Constructors

6l7 IV K S T  SEVENTH S T K K K T, I. O S \ N <: K I. K S, "c A L. 1 F O R- N I A


                 March 23,  1972
                                                                  M/XII. Anni

                                                                 ''• "• ""x
                                                                 I.OS ANCKI.K5
Mr. W. U. Beers
Project Manager
Processes Research, Inc.
2912 Vemon Place
Cincinnati, Ohio  45219
               SUBJECT:  Claus Sulfur Units and Tail Gas
                         Treatment
                         Your OPA Contract No. 68-02-0242

Uear Mr. Beers:

Thank you for your letter of February 21, 1972.  We are pleased
that you have come to us for assistance in this project;  we
have made every effort to be as complete as possible in preparing
answers for your many questions.

For ease of reference we will follow your format as closely as
possible in presenting our responses.

1.  Claus Sulfur Units

    (a)  Depending upon the design of the sulfur plant and the
         nature of the impurities accompanying the feed H2S, a
         considerable range of sulfur plant recoveries is
         possible.  More or less in the middle of the range, it
         might be said that a 50 percent H2S feed gas would result
         in about 93 percent recovery from a well-designed Claus
         plant with two catalytic stages, or 95 percent with three
         catalytic stages.  Similarly, a 90 percent H2S feed gas
         would yield about 94 percent recovery from a two-stage
         Claus unit or 96 percent from a three-stage unit. An
         I12S feed gas of only 15 percent purity requires a special
         design of the Claus plant and it is preferable not to
         generalize on the recovery from such a plant because the
         ratio of H2S to impurities such as hydrocarbons is so low
         that the recovery has to be estimated on a case-by-case
         basis.  It is evident that the recovery from such a low
         purity H2S is low, and usually in the range of 80 per
         cent to 90 percent.
                               90

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                   THE  RALPH  M. PARSONS  COMPANY
Mr. W. L). Beers
Processes Research, Inc.         -2-             March 23, 1972
    (b)  It is customary to regenerate Claus plant catalyst after
         it has lost activity or become fouled.  The life of the
         catalyst may range up to twelve years, with typically
         about one regeneration annually.  After regeneration the
         catalyst should return to substantially its original
         activity, except for a permanent loss in activity for
         the hydrolysis of COS and CSo which may or may not be
         important in a particular plant.  It is reasonable that
         catalyst would be discarded if regeneration fails to
         return it to within one or two percent recovery compared
         to its new performance.  The frequency of regeneration,
         on the other hand, is very dependent upon local circumstances,
         including air pollution regulations.  In some instances,
         a catalyst regeneration would occur with a loss of less
         than 1 percent in recovery; in other instances, the
         recovery might be allowed to slip as much as 10 percent
         before the catalyst is regenerated.  Perhaps an overall
         industry average would find catalyst being regenerated
         after the yield has declined two or three percent.

    (c)  Turning down a sulfur plant to operate at less than full
         capacity usually causes a loss in percentage recovery;
         the amount of loss is highly dependent upon the design
         of the plant, and particularly depends on the method used
         for reheating the gases ahead of each Claus converter.
         With the method of reheat most often used by Parsons,  a
         sulfur plant will typically lose two or three percent in
         recovery when turned down to 20 percent of design capacity.

    (d)  Approximate Investment

         Includes royalty.  Does not include acid gas recovery units
         or acid gas blowers.  Does include air blowers, incinerators,
         and stacks.

             Gas Strength                   Investment - $MM
             and Capacity                2-stage5-stage

             90% H2S

               10 LT/D                    0.34           0.39
               100 LT/U                   0.80           0.90
               1,000 LT/U                 3.60           4.20

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                   THE  RALPH  M. PARSONS  COMPANY
Mr. W. D. Beers
Processes Research, Inc.
-3-
March 23, 1972
             Gas Strength
             and Capacity

             50% H2S

               10 LT/U
               100 LT/L)
               1,000 LT/U
        Investment - $MM
     2-stage
      0.37
      0.90
      4.10
    5-stage
     0.43
     l.OS
     4.90
                 H2S
               10 LT/U
               100 LT/U
               1,000 LT/D

         Catalyst Cost
      0.55
      1.75
     10.0
     0.65
     2.00
    11.5
         The typical cost of bauxite catalyst for a two-stage sulfur
         plant feeding 90 percent H2S is about $30 per daily long
         ton capacity.  This cost would be increased by about 30 per
         cent for a 50 percent H2S feed gas.  Adding a third Claus
         converter stage would increase the catalyst cost by 50 per
         cent.  Using synthetic alumina catalyst would increase the
         cost by about 70 percent.  Thus, the cost of catalyst for
         a three-stage sulfur plant feeding 50 percent I12S and using
         alumina catalyst would be about $100 per daily long ton
         capacity.

         Utilities Consumption

         Using a 90 percent H2S feed gas as a basis for the production
         of one long ton per day of sulfur, the process would require
         about 0.6 gallons per minute of boiler feedwater.  Electric
         power is needed only for lighting and miscellaneous purposes,
         since the air blower is driven by steam produced in the
         process at 150 psig pressure and exhausted at 50 psig.  Fuel
         gas is needed for start-up and regeneration only.  Net pro-
         duction of useable steam is 140 Ibs. per hour at 150 psig
         and 140 Ibs. per hour at 50 psig.  The incinerator is excluded
         from the above statements.  The above steam quantities may be
         used with reasonable accuracy for 50 percent H2S feed gas, and
         they are essentially independent of plant size.
                              92

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                    THE RALPH  M. PARSONS  COMPANY

Mr. W. U. Beers
Processes Research, Inc.            -4-             March 23, 1972
    (e)  Operator Attendance and On-stream Factor

         Sulfur plants up to about 100 LT/U capacity usually require
         the attendance by a man about 20 percent of the time.  This
         depends of course on the location of the plant, degree of
         instrumentation, and other factors.  Larger plants will
         tend to require somewhat more attention.

         A Parsons sulfur plant typically has an on-stream factor
         in excess of 95 percent.
2.  Beavon Sulfur Removal Process Units

    As a general comment, we have never seen a Claus tail gas contain-
    ing as little as 0.3 mol percent offl^S + S02 + S + COS + CS2);
    this includes the tail gas issuing from the IFF and Sulfreen tail
    gas processes.  Our remarks are therefore directed to tail gases
    containing either one or four mol percent equivalent H2S.

    (a)  Approximate Investment

         Includes royalty.  Our current design does not require
         condensate stripping.  Sulfur produced in molten form.
             Total Sulfur Content
                 and Capacity                 Investment  - $NIM

             1.0% S Equivalent

                  1 LT/D                           0.69
                  10 LT/U                          1.40
                  100  LT/D                         5.80 *

                  *  Multiple hydrof;enation  and  Stretford trains

             4.09o S Equivalent

                  1 LT/D                           0.61
                  10 LT/U                          1.20
                  100  LT/D                         3.50 **

                  ** Multiple Stretford  trains
                               93

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                   THE RALPH  M. PARSONS  COMPANY

Mr. W. U. Beers
Processes Research, Inc.         -5-               March 23, iy?2
         Catalyst Cost

         The cost of a catalyst fill is approximately $70 per daily
         long ton of Claus plant capacity.  The catalyst is expected
         to have a three-year life.

         Utilities Consumption

         Utilities consumption is as follows:

                         Quantity                 basis

         Fuel gas        1.25 MSCFL)   per daily ton parent sulfur plant
                                                              capacity
         50ff steam       25 #/Hr      per daily ton parent sulfur plant
         (produced)                                           capacity

         Power           85 HP        per ton sulfur in tail gas

         Soft water      2,500 gal.   per ton sulfur in tail gas

         Chemicals       $8           per ton sulfur in tail gas

         The foregoing utility figures apply to an advanced version of
         the flow scheme in which condensate is not produced as such
         and therefore stripping of the H2S from it is obviated.


    (bj  Operator Attendance

         For all but very large plants the attendance of an operator
         is required between 25 percent and 50 percent of his time.

         Maintenance requirements are expected to be modest.  Operating
         temperatures and pressure are comparatively low and no inherently
         corrosive or erosive conditions prevail.  Materials of construc-
         tion are essentially all carbon steel, with epoxy coatings in
         several areas.

    (c)  Recoveries and Tail Gas Compositions

         Tail gas containing about four percent equivalent H2S contains
         less than 80 ppm equivalent SC>2 after treatment, with COS
         constituting the major part of the combined sulfur and with
         H2$ contributing less than 1 ppm.  Treatment of a tail gas
         containing 1 percent equivalent H2S is expected to yield a
         final tail gas containing less than 40 ppm equivalent S02-
                             9 4

-------
                  THE RALPH M. PARSONS COMPANY
Mr. W. U. lieers
Processes Research,  Inc.          -6-               March 23, 1972
    (d)  Variation in Recovery

         No detectable variation of sulfur recovery is expected
         over a one-year period between catalyst regenerations.

    (ej  Sulfur Quality

         The sulfur recovered by the lieavon process is expected
         to be somewhat better than 99.8 percent pure, while Claus
         sulfur usually is at least 99.98 percent pure.  Either
         the Beavon process sulfur or the mixture of it with Claus
         sulfur meets all usual specifications for commercial
         sulfur.

    (f)  Stretford Entrainment

         Entrainment of catalyst overhead from the Stretford tower
         is avoided by proper design of the tower internals, and
         the vent gas stream is expected to meet all known air
         pollution standards.  Incineration of the off gas may be
         practised, but in our opinion it is unnecessary and
         inadvisable because of the substantial cost for fuel if
         an incinerator is operated.

    Cg)  Process Sensitivity

         Because of broad experience in the design and construction
         of many refineries and more than 160 Claus plants,
         The Ralph M. Parsons Company is well aware that the sulfur
         plant is at the very end of the train of refinery processes,
         and is subject to continual disturbance because of varia-
         tions in the up-stream units.  These variations make it
         very difficult to control a refinery sulfur plant with an
         exact stoichiometric balance of h^S to SC^.  A prime
         requisite in the development of our process was that it
         be essentially immune to upsets caused by such variations.
         This immunity is brought about by the fact that an excess
         of hydrogen is at all times available to drive the desired
         reactions to completion, and this excess of hydrogen may be
         emitted to the atmosphere without causing air pollution.
         In many months of pilot unit testing on the tail gas of
         commercial sulfur plants, in both oil refinery and natural
         gas treating installations, we have found that the process
         is indeed virtually immune to any problems resulting from
         such fluctuations.  The tail gas is always purified, and

-------
                   THE RALPH M. PARSONS COMPANY

Mr. W. U. Beers
Processes Research, Inc.          -7-              March 23, 1972
         the worst result we have observed is a very small consump-
         tion of alkali when the parent sulfur plant was extremely
         upset and insufficient hydrogen was available.  This
         insufficiency resulted only from the fact that no analytical
         instrument was available on the pilot unit to give warning;
         analytical instruments will, of course, be provided on
         commercial units.

         We concur in your observation that the Beavon process is
         insensitive to feed fluctuations.

    (h)  For a new Claus unit the Beavon process probably should
         replace the third Claus stage in all but very large units
         (probably larger than about 500 LT/D).

         Using the Beavon process to replace the Claus unit
         altogether may be desirable in small size plants with
         feed gas free of certain impurities.

    (i)  We understand your question to apply to a Claus unit being
         fed with a mixture of l-^S and S02, containing excess S02-
         If the excess of S02 is substantial, a slight modification
         in the design of the Claus unit may be used to adjust the
         ratio so that the Claus unit is more efficient and less
         sulfur remains to be taken out when the tail gas is treated.
         For economic reasons, this is preferable.  However, the
         Beavon hydrogenation step can indeed be used to overcome
         any reasonable excess of 502 in tne Claus tail gas, and the
         only argument against handling the excess SC>2 in this way
         is the relatively higher cost of making sulfur in the
         Stretford unit compared to the cost of making it in the
         Claus plant.
We trust that we have adequately responded to your needs.  Should any
clarification be required, we shall of course be pleased to hear from
you.

                                    Very truly yours,

                                    THE RALPH M. PARSONS COMPANY
                                    By
                                        0. C. Roddey
                                        Vice President
OCR:ro                        gfi

-------
     PROCESSES RESEARCH, INC.
     INDUSTRIAL PLANNING AND RESEARCH
APPENDIX K - J. F. PRITCHARD & CO. INFORMATION
                  97

-------
                                          February  22»  1972
Mr. n. P. Cole
J. F. Pritcbard asd Coapaay
4623 Koanoke Parkway
Kansas City. Kiaaourt  64112

Subject:  Claus Sulfur Units aud Tall flea Treati

!>aar Mr. Cola:

Several of the oothods being considered for abatement of sulfur anlaalen to
the atuoftphere Include Clous sulfur units.  Tha Environsttntal P rot act loo
Agency Office of Mr Profiraos has engaged Processes Research, Inc., to atudy
the efficacy of Claua aulfur plant* to pollution abatement (Contract No.
68-n2-0242>.

Wo undoratand that your covpany d*al|as Claua units and baa davalopad, with
T«xaa Gulf Sulfur Company and the Briti0;> Sorth«*aatern Gaa Board, a prooaaa
for Clnuft tail gaa pollution abataaant.  Mr. ara rafarring to the Claanalr
Process ddocribad In tbc February 7, 1972, laauee of Cbanlcal CnaioeertnK
and Tint Oil and Gas Journal.  Pleaau let us have iaforaation available r«-
gnrding typical Claua aulfur units and tite Claaunlr Procasa, aa follovat

    1.  ?or typical Claua sulfur units, ouch aa thoaa baaad on natural gaa
        (unlta having dally sulfur capacities of 10 tone. 100 tons, and
        1000 CODB, acid gaa faad concentratlooa of 15 tele percent, SO aola
        percent, and 90 «olo percent «2S' *D(1 Cvo tnd tnre« Claua catalytic
        stance are of particular interest):

        a.  Percentage evltar recoverlee and tail gaa coopoaitions, before
            incineration, for varlotu acid gaa feed concentrations and varloua
            nuabera of catalytic atagea.

        b^.  Variatieo of aulfur recovery during the uaual life of the catalyst.

        c.  Variation of eulfur recovery with acid gaa feed at leea than full
            capacity, such aa half of full feed rate.

        d^.  Approximate investaent, royalty, catalyet coata, and eonsuvption
            and generation of fuel, water, power and ateaai for varioua daily
            aulfur capacities and various acid gaa feed concentratlooa.
            (Please exclude the acid gas recovery units, but include the air
            blowers and tail gas incinerators.)
                                    98

-------
Mr. D. P. Cole
February 22, 1972
Page 2
        e_.  Operator attendance, maintenance, and catalyst replacement
            requirements for varioua dally sulfur capacities.  Number of
            days of operation to be expected annually.

        f_.  What acid gas feed pressure Is required to avoid need for
            representation to incinerate the tail gas?

    2.  Por Cleanair units treating Claua tail gas to reduce the sulfurous
        content to less than 300 ppm try volume 802 equivalent, before in-
        cineration (please include the range of Claua tail gaa feed ratea
        aad compositions produced by the Claus unite previously described:
        ve understand that Clans units designed by others or using other
        catalysts may produce different tall gases affecting the costs of
        suitable Cleaaair units):

        a.  Plow diagram.

        b_.  Approximate investment, royalty, catalyat ccets. and coneumptlon
            of fuel, water,  power and steam for varioua dally sulfur capac-
            ities and variona Claua tall gaa feed concentrations, aaauxdag
            that the feed gas Is at atmospheric pressure.

        c.  Operator attendance, maintenance, smtf catalyst replacement re-
            quirements for various dally sulfur capacities.  Number of days
            of operation to  be expected annually.

        d.  Percentage sulfur recoveries for various Claua tall gas feed
            concentrations.   Variation of sulfur recovery during the usual
            life of  the catalyst, and for various ratios of H?S to SO, in
            the Clans tall gaa feed.

        e.  What Is  the form of the recovered sulfur?  Is the recovered
            sulfurous stream recycled to the Clans unit?  What, If any.
            impurities occur in the sulfur recovered by the Cleaaair
            Process,  other than those occurring la the Clans sulfur?

        f_.   What,  if any.  air pollution is  presented by entralnmeat of
            catalyst  or solvent in the off  gas  from  the Cleaaair unit?  Is
            incineration of  the Cleanair off gaa  advisable?

   3.   For  new sulfur plants bassd on natural  gas,  combining Clans nnlts
        and  Cleanair  unite to reduce  the  sulfurous content  of the tall gaa
        to leas  than  300 ppm by volume SO2  equivalent,  before incineration
        (plants  having daily sulfur capacities  of 10 tons,  100 tons,  and
        1000 tons, end acid  gas  concentrations  of 13 mole percent,  30 mole
        percent, aad  90 mole percent  n2S, are of  particular interest):

        a.   Plow diagram.

                                   99

-------
Mr. D. P. Cel«
February 22, 1972
Page 3


        b_.  Percentage sulfur recoveries and off gas compositions, bafora
            incineration, for various acid gaa feed concentrations.

        c.  Variation of aulfur recovery during the usual Ufa of the
            catalysts.

        d.  Variation ef sulfur recovery with acid gas feed at leas than
            full capacity, such as half of full fead rate.

        £.  Approximate Investment, royalty, catalyst costs and consumption
            and generation of fuel, water, power and stes* fof various
            dally sulfur capacities and various acid ges feed concentrations.
            (Please exclude the acid gas recovery units, but include the
            air blovcrs, and, if advisable, include the off gaa Incineration.)

        f^.  Operator attendance, maintenance, and catalyst replacement re-
            quirements for various daily sulfur capacities.  Muaber of days
            of operation to be expected annually.

        &.  What acid gas feed pressure la required, including, if advisable,
            the off gaa incineration?

We will appreciate receiving all of the above infornatlon which you can nake
available to us.  Pleaae let us know when we may expect to receive It.

We thank you for your cooperation.

                                         Very truly yours,

                                         PROCESSES RESEARCH, INC.
                                         W.  D.  Ber.rs
                                         Project  Manater
UDB:fJ

cc:   C.  S.  Haselbergar
      M.  ft.  Jester
      P.  W.  Spalte
                                   100

-------
                      J. F. PRITCHARD £ CO.
                          ENGINEERS - CONSTRUCTORS

                             4625 ROANOKE I'ARKWAY

                          KANSAS CITY, MISSOURI 64112

TWX 910 771-2102                  TELEPHONE: isie) 531-9500                     CABLE. PRICO

                               June 5, 1972
  Mr.  W.  D.  Beers
  Project Manager
  Process Research Incorporated
  2912 Vernon Place
  Cincinnati, Ohio

  SUBJECT:   CLAUS  SULPHUR PLANTS & TAIL GAS TREATMENT

  Dear Mr.  Beers:

  We  are  pleased to respond to your request for information concerning  Claus
  Sulphur Plants and Pritchard's CLEANAIR Sulphur Process for treating  Claus
  tail  gas.   The information presented should assist in your study  for  the
  Environmental  Protection Agency Office of Air Programs.

  PRITCHARD EXPERIENCE

  Pritchard has  a  wealth of experience in gas treating and sulphur  recovery.
  We  have built  over 50 Amine plants, 16 Sulphur Recovery Plants ranging
  in  size from 10  LT/D to 1500 LT/D.  We currently have contracts for 3
  CLEANAIR Sulphur Plants.  In addition, we have built or are designing
  eight Stretford  Sulphur Recovery units.  The enclosed Stretford and
  CLEANAIR brochures describe these two processes and present the extent
  of  technical  information that we are at liberty to discuss without appropriate
  Secrecy Agreements.

  CAPITAL COSTS  AND UTILITY REQUIREMENTS

  Presented in the attached Tables, listed below, are order-of-magnitude
  capital costs  and utility requirements for the three cases cited  in your
  inquiry letter.   The information is presented for sulphur recovery units
  of  10,  100, 500  and 1000 LT/D.

                Table I        -  Description of Cases Studied
                Table II       -  Order-of-Magnitude Capital Costs
                Table III      -  Utility Basis              		„  .,„—,~^, .Pi,,
                Table IV       -  Order-of-Magnitude Utilities	"':j:-'-V    •'/:•':M '.  .


                                                               . i', • e   \z  B    ';nr  2:-


                                      101
                                     A
                      A Subsidiary of International Systems 8 Controls Corporation

-------
Mr. W. D. Beers
6-6-72
Page 2


PERFORMANCE OF UNITS

New Claus plants are generally designed for recoveries of 95% plus.   It is
not uncommon for Pritchard to guarantee 96% recovery when fed with Amine
off gas having an hLS concentration between 50% and 90%.   Nearly all  new
units are being designed with three Claus reactors.

When a CLEANAIR Sulphur plant is added to an existing Claus unit or built
concurrently and incorporated in a new Claus unit, the CLEANAIR plant effluent
is normally guaranteed to contain less than 250 to 300 ppm (vol.) of equivalent
sulphur dioxide on an undiluted basis.  The sulphur recovered is bright yellow,
99.9% pure, saleable sulphur.  There is no entrainment of catalyst of solvent
in the effluent gas from the CLEANAIR unit.  It is normally not required, or
recommended that CLEANAIR effluent be incinerated, as this presents  a possible
source of NOX formation.

PROCESS QUESTIONS

     (1)   Variation of Sulphur Recovery

     Sulphur recovery in Pritchard Claus plants will  normally drop 1
     to 2%, say from 96 to 94% over the period of Catalyst life.
     Catalyst life will generally vary from 2 to 5 years  depending
     on how the plant has been operated and, of course, the feedstock.
     High concentrations of heavy hydrocarbons (Cs+)  will  cause
     carburization of the catalyst and shorten the life.   High C0£
     concentrations will also affect life.

     The  CLEANAIR Sulphur plant provides extreme flexibility in
     handling varying and decreasing amounts of sulphur constituents
     in the Claus tail gas.  These plants can be designed  to operate
     on tail gases, varying threefold in sulphur constituents.   The  ^2$
     to SOo ratio in the tail gas can vary up to 8:1  without sacrifice
     in effluent quality.

     (2)   Turndown

     Claus plants can be designed (and are operating) with turndown  capability
     of 33% without sacrifice in sulphur recovery.

     The  CLEANAIR plant will  operate from 0% to 100%  of design without
     sacrifice in effluent quality or increasing operator  attention.
                                    i.nz

-------
Mr. W. D. Beers
6-6-72
Page 3


     (3)  Pressure Drop

     Acid gas feed pressures of 6 to 10 psig are adequate to avoid repressurization
     to incinerate the tail gas.  If a CLEANAIR unit is added to an existing
     Claus unit it is often necessary to add a booster blower to overcome the
     small pressure drop in the CLEANAIR unit.  This capability is built in the
     Claus blower for integrated Claus-CLEANAIR units.

MAINTENANCE AND OPERATIONS

Claus plants generally operate 365 days per year.  Their shutdown periods are
generally dictated by local boiler inspection requirements.  Some Claus units
have run as long as 5 years without shutdowns.  CLEANAIR units will operate
as long, if not longer, than Claus units without shutdown.

The estimated manpower requirements for inside battery limits units are shown
in Table IV.

Catalyst replacement will  vary from 2 to 5 years.

We thank you for the opportunity to participate in your study and request a
copy of your final report  when completed.  We hope this information meets your
needs .

                                      Very truly yours,

                                      J. F. PRITCHARD & COMPANY
                                      D. F. Cole
                                      Contract Engineer
 DFCrja
 Enclosures

 cc:   George Thomas  -  Process  Research
                                     103

-------
                             TABLE I

                      DESCRIPTION OF  CASES STUDIED


The following Table II presents order-of-magriitude total  installed capital
costs for three separate types of sulphur recovery units.   A summary of the
estimating basis is described below:

CASE A:  CLAUS UNIT
The estimates presented are based on historical  data from the more than 15
Claus plants built by Pritchard ranging in capacity from 10 LT/D to 1500
LT/D.  In general, if the HLS in the feed gas is in excess of 50%, the
investment cost will generally follow a pattern  based on recovery size in
LT/D.  These costs are based on 3 Claus reactors, H2S feed % between 50
and 90% and assume a recovery of 95%, although some units were actually
guaranteed at 96% recovery.  The costs shown include the following:

              -  Battery Limits Plant
              -  Incinerator and Stack
              -  Sulphur Pit (1 week) and Loading Pumps
              -  Paid up Royalty
              -  Initial Charge of Catalyst

CASE B:  CLEANAIR SULPHUR PLANT

The estimates are based on actual contracts or firm price estimates previously
prepared.  The costs assume the CLEANAIR unit is added to an existing Claus
unit operating at 95% recovery.  The CLEANAIR unit produces an effluent gas
containing less than 300 ppm (vol.) of equivalent SQ2 without dilution.  The
CLEANAIR costs shown include the following:

              -  Battery Limits Plant
              -  Paid up Royalty
              -  Initial Charge of Catalyst and Chemicals

CASE C:  INTEGRATED CLAUS CLEANAIR PLANT

This case represents a new installation with a Claus plant and CLEANAIR plant
built together, in which case Stage III is incorporated in the Claus plant and
overall Claus recovery is no less than 96%.  Stages I & II treat the Claus tail
gas  producing an effluent with less than 300 ppm (vol.) of equivalent SO? without
dilution.  The costs shown include:

              -  Battery Limits Plant
              -  Sulphur Pit (1 week) & Loading Pumps
              -  Paid up Royalties
              -  Initial Charge of Catalyst & Chemicals


                                     104
                                                              June 5, 1972

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                              TABLE II
TYPE OF UNIT
                   ORDER OF MAGNITUDE CAPITAL COSTS
  GLAUS UNIT
  SIZE LT/D
                                                               ORDER-OF-MAGNITUDE
                                                               INSTALLED COST
  CASE A

  Claus Unit with
  3 Stage Conversion
  10
  100
  500
1,000
                                                               $300,000
                                                             $1,000,000
                                                             $3,000,000
                                                             $4,800,000
  CASE B

  CLEANAIR SULPHUR
  Plant on Existing

  ClaUS
  10 (0.5)^
  100 (5) W
  500 (25)
1,000 (50)
                                                               $600,000
                                                             $1,400,000
                                                             $2,700j000

                                                             $3,400,000
  CASE C

  Claus-CLEANAIR
  Integrated Unit
  New Installation
  10

  100
  500
1,000
                                                               $800,000

                                                             $2,100,000
                                                             $5,200,000
                                                             $7,700,000
NOTES

(1)  Size of unit is actual  sulphur in feed  gas
(2)  Figures in parenthesis  represent  actual  sulphur  recovered  in the
     CLEANAIR unit with a Claus  unit operating at  95% recovery.
                                                                June 5, 1972
                                     105

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                             TABLE III
                            UTILITY BASIS
Boiler Feed Water
Steam
Cooling Water
Electricity
Fuel  Gas
220° F, 60 psig
50 psig
80° F, 30 psig, 15° F Rise
460 V/3 phase/ 60 h
                   <3
900 BTU/SCF G> 40 psig
                                    106

-------
                                             TABLE IV   SHEET I  ftf 'L


CASE A: CLAUS
Recovery LT/D
10
100
500
moo
C^SE B: CLEANAIR
Recovery LT/D
10 (0.5)
Ti<0 (G)
E.-UO (25)
1000 (50)
CASF. C: CLAUS-CLEANAIR
Rccovnrv LT/D
10
100
500
1000

8FW
LB/HR


3000
27,000
130,000
250,000



	


3000
27000
130,000
,250,000
ORDER OF
STEAM
LB/HR


(2,800)
(26,000)
(126,000)
(240,000)


80
800
4000
8000


(2700)
(25000)
(122,000)
(232,000)
MAGNITUDE UTI
COOLING WATER
GPM








100
900
4550
9100


100
900
4550
9100
(D
LITIES
ELECTRICITY
KW


40
350
1750
3500


50
380
1 900
3800


90
730
3650
7300
(1)   Based on Utilities Supplied  Per Table III
                                                                June r),  1972
                                 107

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                                                 TABLE TV
                                         ORDER  OF MAGNITUDE UTILITIES
                                                                     (1)
CASE A:  CLAUS
CASE__C:	C1.AUS-CLEANAIR

  !toco v_ery_lT/ D^
     1U
     100
     500
    1000
                                 FUEL GAS
                                 SCFM
 CHEMICALS
J/IW	
Recovery I.T/D

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      OVAL GUARANTEED

109

-------
... was  prouen here!



           The pilot testing and development work for the "CLEANAIR" Sulphur Process
           was carried on jointly by J. F. Prltchard and Company, and Texas Quit Sulphur Company
           operator of the plant at Okotoks,  near Calgary, Alberta, Canada (shown here).
           This significant new technology can result In cleaning up stack
           gas emissions from sulfur plants  to less than 250 ppmv equivalent SO'.

           Pritchard's new CLEANAIR Sulphur Process offers the next step In sulfur recovery
           beyond  Claus-type  systems.  The  technology Includes the very  successful
           Stratford process, plus two new processes developed and pilot tested by Prltchard and
           Texas Gulf Sulphur Company.

                                                               .



                                    110

-------
 ...THE MOST ADVANCED STEP
 in the prevention of air pollution by sulfur compounds;  99.9% sulfur
 recovery, leaving less than 250 ppmv equivalent S02 in the effluent.
 99.9%  REMOVAL GUARANTEED!
               FIGURE
       APPROXIMATE PLANT
     INVESTMENT COSTS FOR
              CLEANAIR
       Sulphur Process Plant
The above graph showing CLEANAIR plan! costs vs. Glaus plant ca-
pacity is based upon the Claus plans operating at 95% recovery of the
sulfur In Die feed, the remaining 5% going to the CLEANAIR facilities.
 Good news lo gas producers with sour
 gas environmental problems! Pritchard
 can clean up stack emissions of sulfur
 plants ... to less than 250 ppmv
 equivalent SO> exceeding the most
 stringent regulations.
 The process is applicable to new or
 existing Clans plants and is licensed on
 a world wide basis by Pritchard.

 STAGE CONCEPT
 The CLEANAIR Sulphur Process consists
 of three stages, each of which is a
 logical step toward tail gas  clean up and
 can be installed as required to meet
 varying control standards.
 Stage I of the Process can be installed
 for about 50% of the overall cost, and
 removes approximately 50% of the sulfur
 from the Claus plant tall gas.
 Stage II, involving about 40% of the
 total cost, can remove essentially the
 remaining 50% of sulfur constituents
 from the Claus plant tail gas.
     Ill provides polishing facilities,
    h reduce sulfur constituents in the
    errt to very tow levels.
      design is for less than 250 ppmv
 equivalent SO in the effluent when all
 three CLEANAIR stages are installed.

 PROCESS CONSIDERATIONS
 The CLEANAIR Sulphur Process recovers
 sulfur from Claus plant tall gas as
 elemental sulfur, making it possible to
 use existing or normally planned sulfur
 handling and storage facilities. It is
 unnecessary to recycle gas streams back
 to the Claus unit allowing the Claus unit
 to be operated as it would be without
 the CLEANAiR unit.
 Pritchard will arrange for client inspection
 visits to Okotoks and to the Pritchard
 built Stretford unit at the "THUMS"
facility, operated by Lomita Gasoline
Company in Long Beach, California. This
 unit represents an advanced
application of the Stretford Process.

 CLEAN  STACKS are Good
 Business and of Significant
 Value in Public Relations.
                                                                                   100%
 CLAUSI
PROCESS
 95%
       -90%
                                                                                  -80%
                                                                                  -70%
                                                                                  -60%
                                                                                  -50%
                                                                                  -40%
                                                                                  -30%
                                                                                  -20%
       -10%
                                      111

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                                            Figure  II
                          CLEANAIR  SULPHUR PROCESS SCHEME
Acid Qaa

Slage ill*
(Clau.)

Claw
Tall
Ga»




f

Stage
III*
1
        CLAUS
                                                              Ellluenl Containing
                                                                  Less Than
                                                                  250 ppmv
                                                                  S at SO.
             Sullur to Storage
                               Sulfur to Storage

'Stage III is Incorporated into new Glaus plant designs while it
 operates on tail gas in existing units.
                                                                            Sullur to Storage
                           SO
             Approx. 50
                               Converts essentially all
                               of the SO] to S with some
                               conversion of H;S to S.
                           40
             Approx. 50
                               Converts remaining
                               H,S to S.	
            III
10
Polishes effluent to less than
250 ppmv equivalent SO,
Reduces COS and CS,
level in tall gas.
 Development work has been carried out on a semi-
 commercial scale at the 400 LT/D Okotoks plant of
 which Texas Gulf Sulphur Company is the operator.
 Actual plant streams from an operating commercial
 Glaus plant are processed in the pilot plant facilities.
 The stream quantities  processed are  equivalent to
 a 4 to 5 LT/D Glaus unit. Pilot facilities have been
 in operation since 1968.
 The pilot plant program had two main objectives:
 • Tail gas clean-up for existing Claus units.
 • Design and clean-up of new Claus installations.
 Technology exists  to  meet the stringent  require-
 ments established  by  pollution authorities. Sulfur
 recovery could be increased by the addition of third
 and even fourth  stages  of Claus conversion—but
 there are limits. Conversion efficiency is limited by
 chemical equilibrium,  particularly  as dictated  by
 temperature and the presence of water. The amount
 of additional sulfur recovered decreases while the
 recovery cost of  the incremental sulfur skyrockets.
                         Lowering the temperature or removing water favor-
                         ably affects conversion, but results in solidification
                         of sulfur. Consequently, 98% recovery is the maxi-
                         mum  for Claus  processing—far  from  acceptable
                         by the standards being  implemented today.
                         Indeed, some standards are so rigid that  they  re-
                         quire  removal  of organic  sulfur compounds, car-
                         bonyl  sulfide (COS) and carbon disulfide (CS2), that
                         are present in Claus plant  tail gas streams in addi-
                         tion to  hydrogen sulfide and sulfur dioxide. Pre-
                         viously, removal  of COS and CSj has received little
                         emphasis since  the quantities involved  had minor.
                         effect on overall  sulfur recovery. Consequently,  the
                         state  of  the art  with  respect to removal  of  these
                         compounds has  been  less  fully developed  than  the
                         knowledge involved in the  removal of H2S and SOj.
                         Pritchard has  engineered  and  built Claus plants
                         since 1953  including units  ranging in size from 10
                         to 1,500 tons  of sulfur  per day. This experience
                         plus recent Okotoks development work  has defined
                                             112

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the troublesome areas in tail gas clean-up and has
established design parameters for. new Claus plants
to minimize these problems.
Pritchard, as a result  of the  CLEANAIR Sulphur
Process development, can offer to industry the tech-
nology required to  meet existing and anticipated
environmental  standards. By combining  an estab-
lished  process with proven sulfur chemistry and
catalyst developments,  Pritchard provides process
know-how to advance the state-of-the-art in sulfur
recovery. As a result of development work and en-
gineering/construction   expertise,  Pritchard  will
custom design plants to meet  individual client  re-
quirements.

SO: Conversion  (Stage t)
J. F. Pritchard and Company joined with Texas Gulf
Sulphur  Company  to  continue  a  development
project initiated by TGS some two years earlier. The
objective of this development work was to convert
SO] in  Claus unit tail gas to  sulfur. The result of the
joint effort is  Stage I  of the  CLEANAIR Sulphur
Process.
The pilot plant has consistently demonstrated  re-
moval of SO] down to 75 ppmv. Commercial design
is for 100 ppmv.  Some H2S is converted to sulfur
in Stage  I. All of  the entrained elemental sulfur is
recovered also.

HzS Conversion  (Stage II)
The Stretford Process
The CLEANAIR system  employs the Stretford Proc-
ess as Stage II. The Stretford Process, a develop-
ment of the North Western  Gas Board of England,
is offered by Pritchard  through license. There are
more than 50 unite in commercial operation through-
out the world. Pritchard built and successfully com-
missioned the first Stretford unit in the United States
for THUMS Long  Beach Company and the  Depart-
ment of Oil Properties  in Long Beach, California.
In addition, Pritchard is now engineering and con-
structing additional Stretford  units  for  clients  in
North America.
The Stretford Process  consists of a  gas washing
system wherein the gas is contacted countercur-
rently with an alkaline washing  solution.  Hydrogen
sulfide is removed from  the gas stream and oxidized
to solid sulfur. The sulfur is formed as a finely dis-
persed solid in the circulating solution. The reduced
solution is then oxidized by air blowing which simul-
taneously removes the sulfur by froth flotation. Oxi-
dized solution is returned to the gas washing system
to repeat the cycle.
COS/CSj Removal  (Stage III)
An Industry Breakthrough
Some of the sulfur components in a Claus unit acid
gas feed, which contains carbon dioxide and a minute
quantity of light  hydrocarbons, are  converted  to
COS and CS2  in the Claus reaction unit. As much as
25% of the sulfur present in the tail gas may be  in
the form of these organic sulfur components. Equiv-
alent SOj concentration varies from 4,000 ppmv for
a Claus unit  operating at 96% sulfur recovery  to
10,000 ppmv for a unit operating at 90% recovery.

Obviously COS and CS2  removal must  be accom-
plished to meet proposed standards that limit total
sulfur emissions to 250 ppmv. The CLEANAIR Sul-
phur   Process  incorporates   such  removal  as
Stage III.

COS and CS;  formation in Claus units has been cor-
related as a function of acid gas composition. The
correlations are  based  on  data from  operating
plants. The correlations  have been  substantiated
through pilot  plant work and are used in predicting
COS and CS2 formation in the design of Claus plants.

Stage  III of the  Process  was developed  through
18 months of pilot plant  operation. COS and CS2
contamination has consistently been  lowered  from
12,000 ppmv to 150 ppmv.  In the pilot unit, investiga-
tions have been performed on process streams from
several points in the Claus process to determine the
most economical means of accomplishing COS and
                                                 113

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                           .

                                               Aerial photo of the 1500 tons per day sulfur recovery plant, engineered
                                                        and constructed by Pritchard for Pan American Petroleum
                                                            liate of AMOCO) at East Crossfield. Alberta, 'Canada.
CSj conversion. The results of these investigations
are incorporated into the design of new Claus units
as  well as CLEANAIR units for tail gas  treatment
on existing Claus plants.
Reliability
The CLEANAIR Sulphur  Process  is carefully de-
signed to assure reliability and ease of operation.
It is expected that codes will not allow periods of
variance of emission standards. Testing  has been
carried out to determine  proper materials of con-
struction.  Critical items of equipment are  spared to
allow continuous operation.
As an example of the CLEANAIR flexibility, the Stret-
ford solution (Stage II) can be overloaded  by H2S as
much as 100% with only  minor changes  in normal
operating  procedures. This feature is especially im-
portant when it becomes necessary to burn off cat-
alyst in a  Claus unit. This also allows Stage I to be
taken out  of service while Stages II  and  III continue
to operate. This flexibility permits the plant to meet
continuous  on-stream  demands   for  clean-up
systems.
FORM CASP 5M 7112
The  CLEANAIR unit  can be  turned  down to any
rate  below design without difficulty, and can even
be idled on  line.  In  cases such as  oil refineries,
where a number of units produce acid gas, normal
shutdown of individual units causes feed rates to the
Claus unit  to vary. Ordinarily, Claus  units operate
at lower recovery efficiencies when fed at lower
than design  rates. The CLEANAIR unit, while de-
signed  for  clean-up at full Claus plant rate,  also
guarantees total  recovery over  the  full range of
Claus plant operability.

Product Sulfur  Quality
Sulfur produced  in a CLEANAIR unit is  typically
99.5% pure,  but Pritchard can guarantee the sulfur
product to  be 99.9%  pure based on total pit  pro-
duction. The  sulfur is suitable for any ultimate use.
A typical analysis is:
      Sulfur                  99.9%
      Organic Impurities      0.02% Max.
      Ash                     0.01% Max.
                                         114

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Economics
Figure I  shows CLEANAIR investment requirements.
Typical  utilities and annual operating costs are set
out in Tables II and III,  respectively, for three tail
gas clean-up cases.
     Case
       A
       B
       C
   Claus Unit
Capacity, LT/D
       50
      150
      500
Cfaus Recovery
 Efficiency, %
      95
      95
In all cases the design basis is 250 ppmv equivalent
SO] in the effluent before incineration and dilution.
Further, the Claus unit is  assumed  to be existing
and no provisions are included  in the Claus  unit to
minimize tail gas clean-up  requirements. The costs
can vary with the hydrocarbon,  carbon dioxide and
hydrogen sulfide content of the acid gas feed to the
                                       Claus unit as well as the static pressure of the tail
                                       gas.
                                         Case A
                                         $925,000
                                      INVESTMENT
                                        CaseB
                                       $1,400,000
                                         CaseC
                                       $2,200,000
                   SUMMARY
Disclosure  of technical  details  of CLEANAIR re-
quires execution of a secrecy agreement. A ques-
tionnaire is available from J. F. Pritchard & Company
to delineate  gas  conditions  and  composition for
individual   plant  applications. Order-of-magnitude
investment costs and expected operating costs can
be furnished  on a non-confidential basis.

Pritchard and TGS maintain the pilot plant at the
Okotoks, Alberta,  Canada, plant for client demon-
stration. Arrangements can be made also for client
visits to Stretford  plants.

                       TABLE II
                 UTILITIES SUMMARY
                 CoMMona
                                    CM* Cn*  C«w
                               Unit.  ABC
               50 pafg, salurateo1
     CooHngWattr 10'F. 30ptlg.
               1S°FrtM
              lb/Hr. 400 1200  4000

              0PM  475 1400  4550
     Electricity    2W/440/2160 «IW.
                9 phase, M hem    KW  200  500  1900
     Fuel On     900 BTU/scf, 40 psig  SCFH 500 1500  4500
                     TABLE III
  ANNUAL OPERATING COSTS (365 Days/Yr. BASIS)
                    Unit
                                   Annual Co*t
                              Caw*  CM*B  CM*C
                  1.40/1000 Ib.
     Cooling Water   $.02/1000 gal.
     Electricity      V007/KWH
     Fiwl CM       (.45/1000 SCF
     Chemicale      $1.75/IT ol
                  Sin TO
     Operating Ubor  v, man/shift
                  @ S7/MH
     Deer. * Finan.   15% ol flrad
                  capital inv.
                  3% of F.C.L

                  TOTAL
             $ 1.400 I 4.200  S14.000
              5.000  14,700  49.000
             12,200  35,600 116,500
              1,*00'   3,»00-  17,700'
               1.600   4,100   16.000

              15,300  15.300   15,300

             13*400 210.000  330,000

              27,100  42.000   00,000

             203.700 332.500  824.500
       * In molt cases Incineration will not be necessary.
        Coat* shown an for actual process fuel requirements
        not Including incineration
        A net credit for luel gas can be taken resulting from
        savings In  Incineration when CLEANAIR la added to
        a Claus unit. Actual fuel requirements for Incinera-
        tion are reduced by 40%.
                                          Sulfur converters and waste-gas chimney ol a typical
                                          Claus- type recovery plant
                                                     115

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Pritchard's growth  embraces world-wide  engineering,
procurement and  construction capabilities.
Pritchard has enjoyed rapid growth within the last decade.
In keeping with our fiftieth annniversary In 1970, was the achievement
of a greatly expanded sales and engineering staff and procurement
and financing connections to keep pace with world-wide construction.
Shortly thereafter, a fifty million dollar project was acquired on
a lump sum basis, involving a  giant Liquefied Natural Gas facility at
Skikda, Algeria.
The world's largest gas treating plant, a vital unit in the IGAT project,
has gone on stream  at Bid Boland, Iran.  Many other projects,
In gas treating, petrochemicals, sulfur removal and environmental
processes to clean-up pulp and paper effluent were contracted
for and constructed around the world.
Pritchard has also taken steps to bring this global capability
close to you. Sales and/or engineering offices are located in
Houston; New York; Los Angeles; Calgary; London; KCIn; Paris;
Sydney; Beirut and Tokyo. (See listing of affiliates and
addresses, on this page.)
Top management control and turn-key performance are the
Ingredients of our  success story. We welcome any Inquiry, large or
small, regarding our process technology and how It can contribute to
your expansion programs.
              THE
Pritchard
COMPANIES
              4626 ROANOKE PARKWAY • KANSAS CITY. MO 64112

                  HOUSTON • NEW YORK A  LOS ANGELCS • CALOAftY
                LONDON • KtiLN • PARIS J^QL   SYDNEY * BEIRUT • TOKYO

               Sub»id.»n*s of tnt»rn«lioo«l Svs1«m» tV Conuols CwpOfiilton
HOUSTON. T.-XIIS ffO?'f. .1. r. PnlcharO
>1 Company, tiuiln bW txuruiui1 Plaza,
4615 Soulhwoat fiiTOvnv

NEW YORK. N V iuu?it.j I  r.iichard
>\ O-'rrjKin, H-:'i>tn 351G Tinio K I id'
lluilHni'!. It I .', .si Mill! :;!»•>!<

LOS ANGELES.  lNrv»nml IViictl).
C.lliluiiiu it,>fi6;i. .). I I'nldl.inf A Citmp.niy.
f'.O »<>« '-»-tr. ."001 Bu'iiiu;sc CVnlm Or.

CALGARY I Albi'ilu. Ciin.iitt. Pnlrjhard
     lion, I miitoil. Suili- IliUO Aquilninc
Towiir. S40 Fillh Av.niuo S.W.

LONDON, WIH. SAD l.niilnmt,
I'ul, ti.ml-tili.Kli!-.  I imili'H.
I'riu hard Houi*t'., 2b7 TyltonUam Court Rd

COLOGNE, •'. Koin ,«i. W.iSl Ciormany.
KIID Piitilvud G.HI.6 H.. PoMlach 300600

PARIS, ;              ' cnlKilo
il tllr.V-K IrnluMiiiiii. 5, (rod I)
I no"u ''1111,1. -14 Avfuuo il*! Cllflton, 9^.
liil"!!  M.-i'lp.i

SYDNEY, (Clmlswood).
N S W ?007 Auslioli.i.
Pllli L.iirl l[!u-',l«, (Ausli.iliii) IMY  LTD.,
I'O tlcix 31?

BEIRUT, Liibnniin Prlichnirt-Rhoilaii
Mniclli' E;isl Liilnlfit. P.O l)o« 8100

ALGIERS. (KcnlKil AlgiM, L.i Ropubliquo
Ai.ii-iirr.lv. Prllthard-Rhodos llmiteif.
'I lil:,  U,MI MtMaliOl

TOKYO. J;i»i,-iiv U.C Worlrf Tratfn
      lion. Cf'fl  ?003
                                            116

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Clean Up Gas Streams In ONE EASY STEP
                  process
                  117

-------
THI "THUMS* PKOJtCT, LONG BIACH. CALIFORNIA
280 wellt from 4 drilling rlgtl A unique worid-engineer-
!ng-|tnt wu employed at the Four "Oil islands" where
the 4 derrick*  (shown below) mounted on tracks can
fa*  moved and positioned to iltnt-drlt! «• many  »
350 welt* Ifom eten iiland.
                                       Latest addition to the famed Long Beach "THUMS" project is this Strettord
                                       facility, engineered and constructed by J. F. Pritchard and Company,
                                       for the operator, Lomita Gasoline Company at Long Beach, California.

                                       It was the first plant built in the United States using the proven Stretford
                                       Process to clean up gas streams in addition to being the first facility anywhere
                                       in the world to apply this process to the purification of natural gas from oil
                                       wells. It incorporates exclusive new technology developed by Pritchard
                                       from extensive experience in engineering and constructing sulfur recovery plants.
                                       The oil from the surrounding Wilmington Field supplies the feed gas. The
                                       name "THUMS" is an acronym for Texaco, Humble, Union, Mobil and Shell,
                                       the oil companies, who with Standard of California, Atlantic-Richfield
                                       and Signal Oil & Gas, jointly cooperated with the City of Long  Beach and
                                       Lomita in underwriting the facility cost.
                                       Pritchard has also developed process improvements to extend the process
                                       applicability to a wide range of gases which can be purified economically,
                                       thus improving the efficiency of future plants. Plants are  normally designed to
                                       produce  a treated gas containing not more than 4 parts per million by
                                       volume (ppmv) of H>S. However, if required, as little as 0.2 ppmv can be achieved
                                       by the Stretfort Process.
                                                       118

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                                                                     THE QUEEN'S AWARD TO INDUSTRY
by the "Stretford  Process"...
Licensed to Pritchard for
world-wide application

A significant contribution  to  pollution abatement
measures is the widely proven "Stretford Process"
which  removes hydrogen  sulfide from  sulfur-
bearing gas streams including "sour" natural gas,
refinery  gas, industrial plant effluents  and coke
oven gas.
Originally developed  by  the  North Western Gas
Board of England, the process is licensed to Pritch-
ard for world-wide  application and ties in with
technology developed by Pritchard in over 50 years
of experience with gas processing, sulfur removal,
petrochemical production and Glaus plant tail gas
clean up.
The Stretford  Process has  been commercially
proven  in more than 50  plants around  the world
(about half  in the British  Isles) over a  period of
many years.
Pritchard engineers  are  confident of  perform-
ance,  and  studies or consultation services are
offered for formal presentation to  pollution control
authorities even under  strict code requirements.
Elemental sulfur removed  is normally 99.5% pure.
 This photograph  shows  sulfur cake
 being discharged from the vacuum
 filter at the THUMS facility operated
 by Lomita Gasoline Company at
 Long Beach, California.
                                                                                1968
                                                       HISTORY
 A
the  Systems Approach
is the  Sound Approach.
Generally  recognized  as  a breakthrough,
the Stretford Process of  gas purification
dates back to the early 1960's. In 1968 the
Stretford  Process  received  the Queen's
Award to Industry for technical innovation.

Based on  the use of an aqueous alkaline
solution of salts of one or several anthra-
quinone disulphonic acids (ADA), it  con-
stitutes a continuous liquid process for the
removal  of hydrogen sulfide  from  gas
streams.

The Stretford process was originally de-
veloped for the purification of coal  gas,
and proved so  successful that it is being
applied for the purification of gases as
different as coke-oven gas,  reformed pe-
troleum products, natural gas and even the
effluents  from  the manufacture of  yarn,
paper, foil and  other industrial  products.

Continued research and  experience  have
yielded many  refinements and  improve-
ments, making the Stretford Process com-
mercially   and   economically  attractive,
especially in our increasingly anti-pollution,
ecology-conscious world.

The  Stretford  Process,  originally devel-
oped to meet British Statutory restrictions
limiting H2S in coal gas, down to 1.5 ppmv,
has now been refined and improved  in so
many ways that it becomes the ultimate
choice and the  most economical overall, fn
both capital and operating costs.

Pritchard's Stretford  plants recover  sulfur
having a purity  of better than 99.5%, elimi-
nating the effluent problem  and yield  a
product in saleable form, in many  cases
amortizing part of the investment.


 SUMMING UP: Pritchard's  expertise   in
 advanced Stretford application  offers the
 most flexible  and sophisticated method
 available  for the effective, complete, one-
 step removal of H2S. And secondly, it  is
 the most  economical in  both capital and
 operating costs for most applications.
                                                119

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CLEAN GAS
   OUTLET
   FOUL GAS
       INLET
process description
       STRETFORD PROCESS FLOW DIAGRAM
                  AIR
        REACTION
                                SOLUTION    PUMPING
                               CIRCULATING    TANK
                                  PUMP
                OXIDIZER           SULFUR    SULFUR
                                SLURRY TANK  SLURRY
                                              PUMP
      A generalized process (low diagram of the Stretford
      plant is  shown above. The gas stream enters an  ab-
      sorption  column  where the HiS is  absorbed by  gas
      contact countercurrently with the Stretford solution.

      Soda Ash—When carbon dioxide is present in the gas
      stream, a mixture of sodium carbonate and sodium
      bicarbonate is formed giving a solution of stable pH
      normally In the range of 8.5 to 9.5. This provides the
      alkaline solution  for initial HiS removal from the gas
      stream with the formation of hydrosulphlde.

      Sodium Mela Vanadate—When reacted with HS",
      vanadium reduces from 5 valent to 4 valent resulting In
      the precipitation  of sulfur.

      Sodium Potassium Tartrate (Rochelle Salt)—Prevents
      deposition of vanadium in over-loaded (upset) solutions.

      Anthraqulnone Oisulphonic Acid (ADA)—the 2:7 isomer
      of ADA oxidizes 4 valent vanadium to 5 valent.

      The HtS  is absorbed  and the clean gas  stream is
      recovered for other use. Outlet H.S loading depends on
      design and can be guaranteed to be as low as 0.2 ppm
      in certain applications. It  should be  pointed out that
      more than 25 Stretford plants  are operating in  Great
      Britain and Northern Ireland, where the maximum level
      of H.S permitted  is 1.5 ppm. Most of these plants have
      demonstrated  on a continuous basis exit loadings of
      less than l  ppm.

      The Stretford  solution, after recirculation  through  the
      H.S  absorber,  is  retained for  10 minutes to allow  for
      completion of  the reaction between HS and  vanadium.
      This hold up  can be  in  the  bottom  of the  absorber
      vessel or in a separate tank. From the hold tank,  the
      solution  passes  to  the oxidlzer vessel where air is
      sparged upward through the solution.

      A SIMPLIFIED  SUMMARY  OF THE REACTIONS
      INVOLVED IN  THE  STRETFORD PLANT
      FOLLOWS:
      1. Soda  Ash  (Sodium  Carbonate)—Provides the  alka-
        line solution for initial absorption of HiS and forma-
        tion of hydrosulphlde (HS ).
           H,S+Na. CO.—>N«HS+NaHCO> (Absorber)
            2. Sodium Mela Vanadate—Reacts with HS , Is reduced
              from 5 valent to 4 valent and this precipitates sulfur
              from the hold tank.
                    HS + VH-'	> S + V**> (Hold tank)
            3. Anthraquinone  Disulphonic Acid- (ADA)—React* with
              the 4 valent vanadium, convert* It back to 5 valent
              and I* Itself reduced.
                   V'<+> + ADA	> V*> +  reduced ADA
            4. Oxygen from air convert* reduced ADA back to the
              oxidized state.
                 Reduced ADA + 0.	} ADA + HiO (Oxidlzer)
            5. Overall reaction I*—
                          2H.S + 0.	^2H*> + 2S

            A small excess of vanadium ton is helpful in preventing
            solution overloading  due  to variations in gas flow and
            H.S content, but usually is uneconomic if upsets occur
            rarely. Conversely, too little vanadium allows formation
            of thiosulphate  and concomitant  solution loss  through
            purging. Pritchard's  knowledge of operating plants in
            the  petro-chemical industry allows an optimum design
            on each individual plant. Pritchard is well qualified and
            happy to issue an economic analysis'embracing capital
            and operating costs on an individual plant basis.

            The  sulfur formed  in the Stretlord  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% sulfur
            at  the  top of  the oxidizer. This  froth overflows  to a
            settling tank where the sulfur slurry Is accumulated for
            subsequent  recovery. Underflow  from  the oxidizer is
            sent to the absorber pump tank for recirculation to the
            HiS absorber.
            The sulfur is fed to an autoclave  where heat is applied
            to  melt the sulfur.  The sulfur-water mixture  is separ-
            ated, and  liquid  sulfur  of greater than  99.5%  purity
            and commercially acceptable is obtained.  Sulfur purity
            depends largely on the amount  of impurities such as
            tars and light  oils present in the original gas stream.
            When these are absent the sulfur  purity can be as high
            as 99.9%.
            None of the constituents  used  In  the Stretford process
            has proved hazardous in years  of operation. No special
            handling precautions are necessary.
                                                120

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     A unique feature  of the Stretford plant
     at Zurich, Switzerland la the application
     of nine washing towers, accommodating
     three separate streams. Each stream has
     a capacity of 7mm SCF/D.      (photo
     courtesy N.W.Q.B.)
     Photo shows compressor and pump house
     with control panel. Stretford plant, Bris-
     tol, England,
    Stretford  Plant, Long Beach, California
    A view of the plant taken during start-
    up. This  plant purifies 65 mm SCF/D
    of oil  field  gas containing 0.15%  HtS.
    Stratford  Plant,  Bristol,  England.  Two
    parallel streams, each 8 mm SCF/D coal
    gas. Exit gas purity less than 1ppm,
E.  Stretford Plant, Belfast, Ireland. Dual ab-
    sorption  columns, oxldlzers  &  solution
    inventory tanks.
                                                       121

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       Feedstream
             Plant A

            Natural Gat
            al Wellhead

                  S5
                1490
       Flow rate— MMSCFD 	
       Inlet sulfur loadihg-ppmv	—
       Outlet sulfur loading
         (guaranteed)-ppmv				      2.5

       Capital Co«t	$800,000

       Yearly Operating Coat

       Chemicals  	-	$  1,200
       Electricity	_	  10,000
       Steam 			~	  None
       Operating Manpower 	_	  None
       Maintenance (3%  of FCI) 	  24,000
       Depreciation (15% of FCI) —	 120,000
       Total ._	-	-	$166,000
       Overall cost of operation In
         $/long ton sulfur.—	——		.....
       • 'Product quantity too low to warrant recovery for sale.
Stretford Process
Spans the world
   Stretford plants outside
 • the U. S.
 • Licensees and associates
   tor the Stretford Process
 • Pritchard built
   Stretford plants.
                                 (PARTIAL LIST)
Bath
Belfast
Bristol (3)
Cardiff
Ipswich
London (3)
Middlesbrough
Norwich (2)
Carrickfergua Oldham
Colchester   Pontypool
Ounstable
Exeter
Gloucester
Guernsey
Reading
Southampton
Tottenham
Whltchurch
                      Plant B

                      Refinery
                    Synthesis Gas

                           49
                        14,000


                           10

                     $1,100,000
                               $   16,000
                                   40,500
                                     500
                                   19,000
                                   33,000
                                  165,000

                               $  274,000


                               $    30.00
Huddersfietd
London
Manchester
Sheffield
                                                   c/
                                  f^frri
Economics
Economics of the Stretford process
have been proven. Inlet gas composition,
operating pressure and outlet gas purity
required determine both capital and
operating costs. Generalized economic
analyses can be misleading. Pritchard is
happy to provide cost estimates for
your problem gas stream.

However, shown here are two actual
cases studied with an economic analysis
for each.
Plant A involves low H>S loading while
Plant B has high H>S loading. Both plants
were designed to operate between 90
and 135 psig pressure on the inlet gas
stream. No credits are assumed
even though incineration and discharge
into a high temperature stack is
unnecessary with the Stretford system.
A high quality, saleable sulfur product
is obtained. Sulfur prices are heavily
dependent on freight and as a
consequence, economics vary with
plant location.

Stretford plants are purifying gas streams
of all  kinds, ranging from a few
thousand to more than 50 million cubic
feet per day... from coke ovens, ore
smelting, chemical plants, petroleum
refineries and natural gas sources.
Purification can be carried out at
pressures ranging from atmospheric to
more than 1,000 psig. Thus, each application
is designed to meet specific problems
and local conditions.

CONSTRUCTION MATERIALS
Usually with mild steel throughout, with
inert linings such as cold-cure epoxy
resins for oxidation vessels and slurry
tanks to avoid internal corrosion from
sulfur deposits.
Pipework is of conventional construction
throughout. Pumps are of the centrifugal
type for liquor circulation and of the
screw type for slurry handling.
The vertical washing tower or column
is the most used type of purifying vessel,
with the Stretford solution entering at top
and the gas to be purified at the bottom.
Blowers or compressors, where required,
may be of any suitable type, providing
they deliver air free from oil. No special
technical restrictions on oxidizer design
are required. Caution should be observed
to prevent the accumulation of sulfur
deposits on unprotected metal surfaces
in vessels and pipelines.
        •   v   'Tr
          ^4-
    . _^—
                                                    122

-------
 Why Stretford?

 Advantages of the Stretford Process:
   1. Well proven commercial operation
     over many years and a wide
     variety of gas streams.
   2. Provides complete clean up of HiS to
     well below 1-ppmv if required.
   3. Extremely flexible operation with
     high turndown ratio.
   4. Requires little operator attention.
     All process streams are handled as
     liquids, making for inexpensive
     automation.
   5. Good process control can be
     maintained by simple analytical
     testing with little technical
     supervision.
   6. Short start-up and shutdown period.
   7. Mild steel construction primarily.
   8. No special handling required of the
     aqueous Stretford solution or stored
     makeup chemicals.
   9. Low chemical consumption.
 10. Low maintenance.
 11. Recovers contaminants as  a saleable,
     widely-used material.
 12. Plants may be operated over a wide
     range of pressures.


 Why  Pritchard?

 In addition to the above listed advantages
 inherent in the Stretford  Process,
 Pritchard offers the following exclusive
 Improvements to the basic process:

 1. Easy, trouble-free production of
    bright molten sulfur.
 2. Increased efficiency of the oxidation
    step.
 3. Optimization of the absorber tower
    design ... all adding up to improved
    economics!
         Ctble or Call Us, About four
             ecological P«o/»m»
      Our engineer* love to talk technology.

    PHONE: (816) 531-9500

   Or,  il  you ere  overseas,  contact any of our
   offices near you, shown on back page of thi«
   folder. The meter won't be running)
          Some  Typical Stretford  Plants
                                              1
Plant Location

Amagasaki, Japan

Belfast, N. Ireland

Bergkamen, W. Germany

Carrickfergus, N. Ireland

Colchester, England

Guernsey, Channel Islands

Hamilton, Ontario

Johannesburg, S. Africa

London, England

New Delhi, India

Taiwan

Zambia

Zeebrugge, Belgium

Zurich, Switzerland

Long Beach. California

Toledo, Ohio

Herscher, Illinois

Philadelphia, Penna.


Los Angeles, California
GatFecd H,S Inlet
Type of On MMSCFD Loading
Coke Oven
Refinery/Reformed
Coke Oven
CS2 Retort
Otto Reformer
Reformed Petroleum
Coke Oven
Producer
Water Shift
Chemical Process
Coke Oven
Ammonium Nitrate Plant
Coke Oven
Coke Oven
Natural (Oilfield)
Refinery
Natural
48
45
36
0.1
6
3
28
6
65
0.1
11.8
10
14
21
55
•49
45
0.3%
16-200 ppm
0.6%
60%
30 ppm
30 ppm
0.64%
0.15%
200 ppm
100%
1.25%
1.5%
0.5%
0.5%
0.15%
1.9%
0.06%
                         (Part of a CLEANAIR plant—
                                           1 ton  sulfur per day)
FORM S*> 5M 7112
                         (Part of a CLEANAIR plant—
                                          40 tons sulfur per day)
All U.S.A. plants to date are  of Prftchard design  and construction.
The Long Beach plant went on stream May, 1971, followed  by two
plants In the Spring of 1972, and two more in early 1873.
                                                         123

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Pritchard's growth embraces world-wide  engineering,
procurement  and  construction  capabilities.
Pritchard has enjoyed rapid growth within the last decade.
In keeping with our fiftieth annniversary In 1970, was the achievement
of a greatly expanded sales and engineering staff and procurement
and financing connections to keep pace with world-wide construction.
Shortly thereafter, a fifty million dollar project was acquired on
a lump sum basis, involving a giant Liquefied Natural Gas  facility  at
Sklkda, Algeria.
The world's largest gas treating plant, a vital unit in the IGAT project,
has gone on stream  at Bid  Boland, Iran.  Many other  projects,
In gas treating, petrochemicals, sulfur removal and environmental
processes to clean-up pulp and paper effluent were contracted
for and constructed around the world.
Pritchard has also taken steps to bring this global capability
close to you. Sales and/or engineering offices are located in
Houston; New York; Los Angeles; Calgary; London; K8ln; Paris;
Sydney; Beirut and Tokyo. (See listing of affiliates and
addresses, on this page.)
Top management control and turn-key performance are the
Ingredients of our success story.  We welcome any inquiry, large or
small, regarding our process technology and how it can contribute to
your expansion programs.
              THE
Pritchard
COMPANIES
              4625 ROANOKE PARKWAY • KANSAS CITY, MO. (4112
                  HOUSTON • NEW YORK
                LONDON » KOLN . PARIS J
                 LOS ANGELES • CALGARY
                  SYDNEY . BEIRUT » TOKYO
                                                  HOUSTON, Trx.i': iVi'.'Y. .1. F. i'ntcll.lld

                                                  iht'j S.IUtlmi-Kt I l.'rw.ly

                                                  NEW YORK. N V. iwi'ii.j i  i'ii!,.h,tfd
                                                  ". Cnm|iuny, ||O»HI .'MO Timn «• l.il"'
                                                  Dl/lll'ino. II ! Uii:.l Will! ••'.«-.•!

                                                  LOS ANGELES, lNi'«(vni n.su.li)
                                                  C,iiit..mi.i <.<.>(,t;:i .1. i  I'niriKir.i x Ciiiiip.iin,
                                                  r'.ll Hn« . 'LI.' ."i,.iPr..	-t.s Cfrlliil Ol.

                                                  CALGARY '  Mlnvi.i, I'lin.uin. I'nlihanl

                                                  I,mm. ;.']» l-illll AI/,.-IIU,, s W

                                                  LONDON,  Wllv DAll l.iuilunil.
                                                  F'lit.-h.iHj-Hti.Miv, Limiloi),
                                                  TriU !i;<".1 IfiHii..-. ',".>! TMtlouhai" Cimrl H,l

                                                  COLOGNE. :i h,,in ,KI, w,-sl Gnraunj,
                                                  KHD I'liK h.n.l I", in i> II , r'usllwh 30 OB 60

                                                  PARIS. ri.Hu.-.r.nmi.i.iiiHi' CI.IIIIL,],.
                                                  il'l-'tii,!-.-.. liidii-.ilru'iifs,  (COCE.I)
                                                        ing, -M. Avruuo dii Cliniou, yi',
                                                  Itii'-it  M.-illi!.ns,>n

                                                  SYDNEY,  ((;li.ilsw,-K.i!),
                                                  NSW. PtW AuBtinlKi.
                                                  I'nlch.iiil-riDoan:. (Ausliuli.i) I'l'V. I.Tp..
                                                  i>o no* 3is
     r. l"r,Hl>Mi PnU'h.M.) lltiinl.--.
Mi.Mi. IT.isI liiiuli'il. t'O l!"«610fi


ALGIERS. (Kculiul Altj.-'i. In Roinililiq
Ai,f^rii'nno, (Jiil^hard-Rtisnfori Ifmitc-i,
.1 Kill' [!.'diari«c of Intarnational Svatama & Control! Corporation
                                            124

-------
                PROCESSES RESEARCH, INC.
                INDUSTRIAL PLANNING AND RESEARCH
APPENDIX L - CHIYODA CHEMICAL ENGINEERING & CONSTRUCTION CO.. LTD..INFORMATION
                             125

-------
                       f1 UI v A H A  
-------
        Client

Nippon Mining Co., Ltd.

Fuji Kosan Co,, Ltd,
Tohoku Oil Co,, Ltd.
                          - 2 -
    Capacity

 33,500 Nm3/h

15,8,000   "

 14(000   "
Mitsubishi Rayon Co., Ltd, 90,000
   Gas to be
   Treated

Claua Tail Gaa
Boiler Flue Gas

Claus Tail Gaa
Boiler Flue Gaa
       We thank you again for your interest in our Process
and ahall be pleased to hear from you of a specific inquiry.
       With beat regards,
                             Very truly yours,
                             M. Sato
                             Executive Managing  Director
Kl/hy

Encl.
                             127

-------
The Chiyoda TI
   Flue Gas Desulfurization  Process


               CHIYODA


CHEMICAL ENGINEERING
& CONSTRUCTION CO.LTO.
                    128

-------
                 "Chiyoda  THOROUGHBRED"   Series  of
                          Environmental  Control  Technologies
   With the remarkable  industrial growth, great em-
phasis has been placed on the necessity of pollution
control.  We, at Chiyoda, fully recognizing the growing
importance  of  providing preventive measures  against
environmental  pollution,   have  been  determined   to
challenge this  difficult problem  based on  the total
systems engineering approach.   Since  the types and
conditions of pollutions are varying in nature, an overall
systems approach is essential to find the  best possible
solution.
   We  are firmly determined to concentrate  our tech-
nological efforts on the  development of various tech-
nologies for environmental control to meet the need  of
the public and  industry.  It. is for this reason that we
have given a trade name "Chiyoda THOROUGHBRED"
to  the  processes  and  equipment for  environmental
control  with  classification  numbers  coded to each
category. "THOROUGHBRED" stands for the best
race horse of a breed ever created  through centuries
of  crossbreeding improvement.  It is our sincere hope
that  the  "Chiyoda THOROUGHBRED"  series  of
environmental technologies will earn the same assessment
and reputation.
   Processes and equipment that  must  be developed
should be such that they satisfy the universal need  as
viewed  from  long range  demand  forecasts  and they
should be developed to solve various problems relating
to environmental preservation  under a wide  range  of
variable conditions.
   With the energy innovation coming before us, it is
imperative to place emphasis on the selection of systems
that will provide logical solutions to the problems.
   We  solicit your continued  kind patronage of our
comprehensive  services in the field  of  environmental
control  including plant safety  control and earthquake
damage prevention.
   We  avidly look forward to being of service to you.
                                  A. Tamaki
                                   President
                                              129

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"Chiyoda   THOROUGHBRED   101
Flue  Gas   Desulfurization   Process
1.  Flexible to Meet Various Conditions
Various processes of removing sulfur oxides from  flue
gases have been developed or are  under development
in  the  world.   However,  as each process  has  dis-
advuntages and limitations with requirements for further
improvement,  it is  of utmost importance to evaluate
and select a process most suitable and flexible to meet
each specific requirement.

"Chiyoda  THOROUGHBRED 101" not  only demon-
strates  high efficiency performance,  but  also displays
other advantageous  features.  It only produces gypsum
as  a by-product which is completely harmless and non-
toxic,  and does not. discharge any stream  that  will
cause secondary pollution.

"Chiyoda  THOROUGHBRED 101"  is  easy  to operate.
and  has a  highly reliable performance.  In  addition,
capital, operating and maintenance  costs are low.  Pro-
cessing  cost of the  by-product gypsum is only  small.
The solution  in  the absorption-oxidation section  is not
slurry,  and  thus  ensures  stable operation and  is not
detrimental  to  the  operation of the boiler and other
related  equipment.
2.  Contributions to the Petroleum Industry
"Chiyoda THOROUGHBRED 101" ensures  petroleum
refineries  an  effective  use  of  low-grade fuels  such as
asphalt for power generation and  also pipestills.
Since "Chiyoda THOROUGHBRED 101" is of simple
construction and  has  highly reliable operation,  it  is
suitable for  SO2  removal from the  tail gas of a sulfur
plant.

There  are many cases where boilers and  pipestills are
located apart in  the  premises of petroleum refineries
and petrochemical complexes, and large diameter ducts
are laid to collect flue gases to centralized stacks.  In
these cases, "Chiyoda  THOROUGHBRED  101" has an
added  advantage since the absorption-oxidation section
can be installed separately  in  one or more places to
pump  sulfuric acid to a distant place where it is con-
venient to install a crystallizer to process the by-product
gypsum.
As "Chiyoda THOROUGHBRED 101" can separate the
crystallization  section  from  the  absorption-oxidation
section for  installation at most any place desired, for
instance, within the premises adjacent to a large thermal
power plant or a large boiler, there  poses no special
problem  in  site selection.   The  process  is a  wet de-
sulfurization method with a high  sulfur  removal  rate,
which eliminates the installation of a tall chimney.
                                               130

-------
      3. Application to the Energy Industry
      Currently,  it  is  u  common practice  in Japan  that a
      thermal power station  is  jointly  built  adjacent  to a
      large  petroleum  refinery.  For  example, in the Mizu-
      shima  and  Sendai  petrochemical  complexes, thermal
      power stations were jointly  constructed  to  rationalize
      utilization of  energy.
      Since a  large  amount  of  fuels is consumed  by these
      power stations, tremendous savings are ensured,  if low
      grade fuels  such  as asphalt can be used.

      "Chiyoda THOROUGHBRED  101"  ensures thermal
      power stations the use  of low grade high  sulfur fuels
      to convert them  into electric power  without air pollu-
      tion  problem,  resulting  in  improved  national environ-
      ment ... national interests.

      A  large  quantity of the  by-product  gypsum can  be
      utilized for housing  construction  materials  and many
      other  purposes as it is  harmless  to  man  and his  sur-
      roundings.   Furthermore, as this is a wet type flue  gas
      desulfurization  process,  no  paniculate  from  stack is
      emitted even where  coal  is used with heavy fuel oils.
      and thus, no duct collector is required.
131

-------
This IOOONm]/h  (650 scf.'min) pilot plan! operated  continuously  for o\cr J!00 days desulfuriring flue gas.
                               132

-------
 Process   Description
 As  shown  in  the  process  flow  scheme,   "Chiyoda
 THOROUGHBRED  101" is comprised of three process
 steps.
 Reactions take  place in each step of the process  sequ-
 ence as  follows:
    Absorption	SO2 + H:O	> H2S03
    Oxidation  	H2S03 + JO2	» H,SO,
    Crystallization ... H2SO, + CaCO3 + H2O	>
                      CaSO4-2H:O (Solid) + CO.  (Gas)

 1.  Absorption
 After  being  removed  of dust  and  pre-cooled in the
 prescrubber,  flue gas  is  led  into  absorber  where SO2
 and SO3 contained in the flue  gas are absorbed and
 removed by  dilute  sulfuric  acid  at  50~70°C (120~
 I60°F).
 Absorption can  be  carried out in  a  column.  The ab-
 sorber  can be of any type with simple construction to
 meet the purpose.
 In H.jSOj of 2—10 wt % concentration, SO2 can only
 be  soluble  to  a  range of one-third of the  solubility to
 water,  but  the  dilute  sulfuric  acid  recycled from the
 succeeding  oxidation section  dissolves oxidation catalyst
 and  O. nearly  to the saturation point.   Thus, as oxida-
 tion reaction  can  take  place  in the absorption section
 also,  recycle  rate  of three  times  the water  is not
 required.  In  the absorption section, SO2 content in the
 exhaust gas cari be held to below  100 ppm,  depending
 upon the size of the absorber, or flow rate and  con-
 centration of dilute sulfuric acid.
 In the  pilot plant test with a six  meter (eighteen  foot)
 high packed column, combustion gas of vacuum residue
 containing SO? of 3,000 ppm  was  absorbed by 3 wt %
 sulfuric acid, and it was successful in holding  the SO,
 content in the exhaust gas to below  50 ppm.
The  treated gas  passes to the atmosphere at  about the
same temperature with  dilute sulfuric  acid.
The  dust collected in the prescrubber  can  be removed
from the process, if it affects the  gypsum quality.
 2.  Oxidation
 Sulfurous acid in the dilute sulfuric  acid is completely
 oxidized into sulfuric acid.   And a part of sulfuric acid
 (HoSO4 corresponding to  SO2 and  SO3 removed from
 the  flue gas) is  passed  into  the crystallizer to process
 gypsum  and  the remainder  is circulated into the  ab-
 sorber.
 In this  section is used a special  catalyst to accelerate
 oxidation.  The special catalyst used has been specifically
 developed  by Chiyoda  after continuing research and
 development efforts, and has  been evaluated most suit-
 able for the purpose  from the standpoint  of  catalyst
 activity,  poison  resistibility and cost.
 Type and size of the  oxidizer vary  with the oxidation
 agent,  absorption velocity, reaction velocity, etc.  It is
 recommended to  use a bubbling column of simple design
 which  can utilize air as oxidation agent.
 Air  consumption  is  about  five  times  the  theoretical
 requirement.

 3. Crystallization
 Sulfuric acid sent from  the oxidizer is neutralized with
 calcium  compounds  to  continuously  crystallize  and
 separate  gypsum.
 This process  allows choice  of  any  of a   variety  of
 calcium compounds,  such  as natural limestone, quick
 lime or  calcium  oxide, slaked lime,  calcium hydroxide
 and  carbide residue.
Gypsum  can  be  crystallized  in  varying sizes  in the
 crystallizer of special design.  Crystals thus  formed are
continuously  separated by centrifuge and water  washed
 to produce the product gypsum.
The  mother liquor and wash  water  is recycled to the
absorber,  thus, there is  no effluent  water drained out
 the whole system.
                                                     133

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                                      ABSORPTION
                                   OXIDATION
                                            VENT
                                              t
                                  REHEATER
                                 ABSORBER
                                                     FUEL
                     MAKE-UP WATER
            PRESCRUBBER
     S02 CONTAINING
             GASES
                 £3
               BLOWER
                                                                               OXIDIZER
                                                                                SULFURIC ACID TANK
PUMP
                      PUMP
                                     BLOWER
                                                           PUMP
Features  of  "Chiyoda  THOROUGHBRED  101
O Simple Process Flow and Ease of Operation
With simple process flow and plant structure, the process
promises a  wide range of operation flexibility.
C Continuously Stable Operation
Unlike  conventional wet  type flue  gas desulfurization
systems, as no slurry is used in the absorption-oxidation
section, there presents  no  problem of clogging.  In ad-
dition,  by virtue of its  process flexibility, it  ensures
reliable continuous  operation under a  wide range of
fluctuations in load.
C High-efficiency Desulfurization
Approximately 97% of desulfurization can be attained.
               In other words, SO, in the stack gas to be emitted can
               be held to lOOppm or lower.
               O Lower Construction, Operation and
                 Desulfurization Costs
               Because of its simple  process, it minimizes the number
               of unit operations.  Since there is no requirement for
               special chemicals and  utilities,  low running cost is as-
               sured, resulting in lower desulfurization costs.
               O S02 Removal for Dirty Flue Gases
               SO2 can be  removed economically even from low grade
               fuels such as combustion  gases  from vacuum  residue,
               because of stable catalyst performance.
                                                134

-------
                    CRYSTALLIZATION
                HzSO»+CaCOj+H20-'CaS04 -2H20-f C02
                                            WATER
                                                            CENTRIFUGE
                CRYSTALLIZER
LIME STONE
    \
                                                                                          GYPSUM
                                 PUMP
                                                    PUMP
 • Dust Removal
 No electrostatic   precipitator  is  required  since  the
 soot  and other particulates  in the flue gas are removed
 in the  prescrubber and absorption steps.

 • No Waste Stream
 Since  there is no bleed  of the solution, there is  no
 concern of secondary pollution problem.
 • By-Product  Gypsum
 Gypsum is a highly stable chemical  compound of sulfur.
 and  is harmless  when stocked.  There  can be found
 versatile applications in  place  of natural gypsum.  In
 Japan,  since   there  is a  lack  of natural resource  of
gypsum,  the  by-product can be used as Portland cement
retarder,  gypsum boards and so on.
In addition, dilute sulfuric acid can  be used as a pickling
solution  in steel mills, and can  be  sent to waste water
treatment facilities to  neutralize alkaline substances in
chemical  and petroleum  industries.
• Flexible  Combination of Process Steps
Since the absorption-oxidation section  can be separately
installed  from the crystallization section, dilute sulfuric
acid processed  can be  pumped through pipeline  to  a
centralized crystallization section located  in an adjacent
gypsum board plant or cement  plant.
                                                 135

-------
Investment and Utility Summary (Boiler Fine Gas Cases)
"Chiyoda THOROUGHBRED 101"
Flue Gas Desulfurization  Process
ITEM
Design Conditions
i




By-prodiicl
Plant Cost (A)
Fixed Cost (B)
Direct Cost (C)







Net Operating Cost (D)
Overhead (E)
Operation Cost (F)
By-product Credit
Cost of Desulfurization



Required Area
DESCRIPTION
Flue Gas
Power Generating Capacity
SOj Content in Flue Gas
Flue Gas Temperature
Desulfurization Rale
Service Factor of Boiler
Fuel Oil Consumption in Boiler
Sulfur Content in Fuel Oil
Gypsum (CaSO.-2H,0)

18% of (A)
Limestone Powder $5.50/T (0.25C/lb)
Electricity 0.7C/KWH
Industrial Water 2C/T (SC/lOOOgal)
Re-heat Fuel Oil S20/K1 (3.18$/barrel)
Catalyst
Labor $ 12, 000/Year/capi ta
Maintenance 2% of (A)
Sub-Total
(B) + (C)
12% of (C)
(D) + (E)
$5.50/T(0.25C/lb)
Without By-product Credit


With By-product Credit
Include 7 days Storage Area
UNIT QUANTITY
NmJ/hr (scf/nin.) 750,000 (441,400)
MW ! 250 '
p.p.m
£ (T)
2,400,000 (1,
800
1,500 1,500
140 (284) , 140
% \ More than 90
%
Kl/year (barrel/year)
%
ton/hr (bb/hr)

$/year
$/year
>>
>/
t
'/
*
f
*
$/year
'/
b

$/K) ($/bbl)
S/MWH
$/ra ($/bbi)
S/MWH
m1 (1000ft1)
90
482,000 (3,032,000)
2.7
7.8 (17,200)
4,970,000
894,600
202,400
263,200
8,000
241,000
6,000
96,000
99,400
916,000
1,810,600
109,900
1,920,500
343,200
3.98 (0.63)
0.96
3.27 (0.52)
0.79
3,600 (38.7)
More than 90
90
1,540,000 (9,
2.7
25.1
413,000)
(284)


687,000)

(55,350)
11,850,000
2, 133,000
642,400
812,000
22,400
770,000
19,000
144,000
237,000
2.646,800








4,779,800
317,600
5,097,400
1, 104,400
3.31
0.80
2.59
0.62
11,500
(0.53)

(0.41)

(123.7)
Notes : The plant cost (A) is based on the Japanese cost.
Unit cost in U. S. A. is used in column (C).
(US $1.00= ¥308)
                      136

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       PROCESSES  RESEARCH, INC.
       INDUSTRIAL PLANNING AND RESEARCH
APPENDIX M - INSTITUT FRANCAIS DU PETROLE INFORMATION
                      137

-------
                                              February 24. 1*72
 Mr.  Robert  Outriau
 Instltut  Francois  du  Petrole
 90 Park Avenue
 New  York, New York 10016

 Subject:  Claua tail  Gas Treatment

 Dear Mr. Dutriau:

 Several of  tbe methods being considered  for abatement of sulfur ami as ion
 to the atmosphere  include Claua sulfur uuits.  The Environmental Protection
 Agency Office of Air  Programs has engaged Processes Research, Inc., to
 gather information  regarding the efficacy of Claus sulfur plants in pollu-
 tion abatement (Contract Ho. 68-02-0242).

 Proa the May 1971  issue of Uydrocarbon Processing we understand that your
 company has developed a process for removing sulfur from Claus tall gases.
 Please let ua have  additional information available regarding the Inatitut
 Francais du Petrole Tail Gas Sulfur Recovery Process, as follows (tail gas
 treatment units having daily sulfur capacities of 1 ton, 10 tons.and 100
 tons, for Claua tail gas feed concentrations of 0.3 «ole percent, 1.0 mole
 percent, and 4.0 »ole percent of H2S + S02 are of particular interest):

 1.   ConfIra approxiaate investment, royalty, catalyst costs, solvent costs,
     and consumption of water, power and atean for LIT units having various
     daily sulfur capacities and various Claus tall gas feed concentrations
     *f h2S + SO2-

 2.  Operator attendance and aaintenance requirements.

 2.   Conflrn percentage sulfur recoveries for various Claus tail gas con-
     centrations of H2S + SOj.

 4.  What is the pressure drop of the gaa through the IPP unit?

5.   Is the quality of the sulfur recovered by the IFP process equal to
    that of Clausssulfur?


6.  What,  if any.  air pollution is presented by entrainaent of catalyst
    and solvent overhead froa the packed tower?  Is Incineration advisable?

7.  A principal cause of poor sulfur recovery in Claua plants is deviation
    froa the optiaua feed  ratio of air to H2S,  resulting froa inadequate


                                   138

-------
Mr. Kobert Dutriau
February 24, 1972
     2
    instrumentation or careleea operation.  This alao resulCfl  la  daviatioae
    from tUe etoicfeioMtric balance of U ,3 and 30 2  in the  tail §*».  There-
    fore tne tail gnats froa Clan* anitft having tb* gr«at*«t nead for
    pollution abat«H*iit ar« llk«ly to cotitalo oabalancad and arratlc
    quantities of Hy5 awl &°2'  x* lfc f««*ibla to uc« SIMM of  tha acid gait
    fron upatraaei of tita Claua unit to nutintaio tba ratio  of U2S  to  S02
    required by the IP? pr*e«aaT

6.  Tha COS and C$2 typical of Claua tail gaa is umlar stood not rauoved by
    tha IFF proceaa.  Do you bav« otb«r naaa* of r«»onritig  tbaa«?

9.  Tha IF1» procaa* ia uadoratooa to ba «ff«ctiva ia placa of  tba aacond and
    third Claoa atagaa.  1» tharo baai* for tbe IFF procaaa raplaciae  the
    Claua wait altogatbar?

We will appreciate rac«iviog all Che above infomatioa which you  can make
Available to u«.  Plaaaa lat ua Iwov trtien we nay expect to receive it.

We chant you for your cooperation.

                                              Very  truly yours,

                                              PROCESSES HZSBARQi, INC.
                                               a.  D.  Beere
                                               Project  Manager
WUli.fJ

ec:  U. 3.
     d. &. Jester
     P. V. Spaite
                                   139

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 r
   Mr. W. D. Beers
   Project Manager
   Processes Research, Inc.
   2912 Vernon Place
   Cincinnati, Ohio 45219
~l
               March 17, 1972

               CR 1 P08 00
                                                                                Institut
                                                                                Francais
                                                                                du
                                                                                Parole
                                                                                North
                                                                                American
                                                                                Office
         Dear Mr. Beers:
                   In reply to your letter dated February 24th 1972,  I.F.P.  is
         pleased to provide you with non confidential information on  the I.F.P.
         Glaus tail gas clean up process.  We understand that this information
         will be used for your study on pollution abatement from Glaus plants
         for E. P. A. office of Air Programs.
         contains:
                   I am sending you attached a document on our process which
                  - a process description and flow diagram
                  - reaction mechanism
                  - operating parameters
                  - typical economics for a plant tied with 30 and 140 T/D
                    Glaus plants.
                  - list of industrial references

         Besides our demonstration operation with Delta Engineering in Canada
         during the summer of 1971, I.F.P. now has 6 months of successful op-
         erating experience in the first Japanese unit.  3 more units will
         start in Japan in April 1972 and one in Canada in July 1972.

                   In addition I have attached typical economics for our I.F.P.
         plants tied with a 100, 300 and 1500 T/D Glaus plant, at different
         levels of l^S -r 502 contens in tne tail gas.

                   I will answer the questions as they are listed in your letter:

         Q 1 - See attached document.  Paid up royalty figures are of the order
               of 10-20% of erected cost.

         Q-2 - The process is very simple to operate and does not require any
               additional labor, above operators.attending the Claus plant. Main-
               tenance can be estimated at 2% of erected cost per year.
90 Park Avenue
New York, N.Y. 10016
                                Telephone (212)986.3391
                                Telex IFPNY / 620060
                                          140

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 Q 3 - See attached document

 Q 4 - Pressure drop is low and tail gas pressure is generally well above
       I.F.P. requirements.

 Q 5 - Sulfur produced by I.F.P. process is pure and can be blended with
       sulfur produced by Claus plant.  A typical analysis of I.F.P. sulfur
       is:
            ashes            100 ppm
            carbon           100 ppm
            S                99.5 minimum (wt%)

 Q 6 - The treated gas from I.F.P. plant is meant to be incinerated before
       sending it to the stack.  The purpose of this incineration is to burn
       the remaining sulfur compounds (H2S, COS, CS2> into S02.   Solvent and
       catalyst show a very low volatilaty at operating temperature.  Never-
       theless small quantities are carried over with the treated gas and completely
       burn in the incinerator without creating any pollution problem.

Q 7 - The question of H2S/S02 control is covered in the attached document. The
      basic I.F.P. design includes a bypass of small amount of acid gas in order
      to control to some extent the ratio.  This is considered as a safety
      device in case of the close loop control on the Claus plant is out of
      service.

Q 8 - COS and CS2 are inert in our process as stated in the attached document.
      Nevertheless means exist to get rid of most  of COS and CS2 in the Claus
      plant.  This is achieved by the use of specific catalyst at higher temp-
      erature in the 1st stage which destroy COS and CS2 by hydrolysis.

Q 9 - The I.F.P. process can replace the second and/or third catalytic stage.
      It does not replace the first stage, for the reason shown above (COS & CS2).

          I hope this information will be useful for your preliminary evaluation
of I.F.P. process.

          Do not hesitate if you have any question to contact me in New York.
I.F.P. is interested to get a copy of your final study.  Kindly let me know
whether this is possible.

          Looking forward to hearing from you, I remain,

                                               Yours very truly,
                                               R. Dutriau
                                               Sales Engineer
                                               North American Office
RD:cs
encls.
                                      141

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             THE IFP PROCESS FOR CLEANING UP CLAUS TAIL  CAS
 The IFP process for cleaning up
 Claus plant tail gas offers natural
 gas processors the chance to
 boost overall sulfur recoveries to
 99% levels. The IFP process is al-
 ready being used in one Canadian
 and one  Japanese plant. Actual
 performance meets design crite-
 ria. Four other plants utilizing the
 process are under construction.
 Process description and
 reaction mechanism

The basic reaction of the IFP process is
the same as that in the Claus unit itself:
2H2S
3S +  2H20
 The reaction is carried out in a catalyst-
 containing solvent. The first step of the
 reaction  mechanism is  that the  H2S
 and  S02 dissolve in the solvent, the
 extent  to which  the  gases dissolve
 naturally being a function of their par-
 ticular  pressures.  Then  the catalyst
 combines chemically with the SO2, H2S
 and sulfur to yield an active complex.
 This complex  in turn reacts with addi-
 tional feed H,S and S02 to produce
 elemental sulfur according to the reac-
 tion noted, constantly regenerating the
 active complex itself.

 During the initial phase of the reaction,
 product  sulfur dissolves in the solvent
 until  the saturation point for the given
 temperature is reached. Thereafter sul-
 fur is continuously separated from the
 reaction mixture,  and  the reaction is
 pushed to the right. Lower tempera-
 tures also favor sulfur production, but
 they must not be low enough to permit
condensation of water, or solidification
of the sulfur which would cause plug-
ging. Optimum temperature range is
230-320°F.
                                                  Advantages off the
                                                  IFP solvent/catalyst system

                                                   a) high catalyst activity
                                                  b)  good chemical and thermal stability
                                                     of both solvent and catalyst
                                                  c)  minimum volatilization losses of sol-
                                                     vent due to low vapor pressure
d) maximum gas/liquid contact, with
   no foam formation, because of good
   physical properties of solvent

e) ease of product separation due to
   low  solubility of  sulfur in solvent,
   and  large difference in density

f)  maximum product purity due to low
   solubility of solvent in sulfur

g) ready commercial availability and
   low cost of both solvent and catalyst
                                                    142

-------
 FLOW tCHIMI OF  IPP PROdtt
  tail gas from
  Clous plant
  treated  gas  to
  incinerator
     • steam condtntaia
                       liquid
                       sulfur
The IFP process is exceptionally simple
and  requires only a  few pieces  of
equipment. Glaus  tail  gas at about
260"F  is injected into the lower  part
of a packed column.  The tower  is
designed for low pressure drop.  One
or more packed beds with redistribu-
tion  are employed, depending on
capacity. Product sulfur accumulates
in a  boot  at the bottom of the tower
and  is  continuously decanted under
interface control.
The catalyst-containing solvent is cir-
culated  continuously from bottom  to
top of the tower to maximize liquid/
gas contact by counter-current flow.
Liquid temperature is  maintained  at
260-280°F. the heat of  reaction being
removed by vaporization of  conden-
sate  injected into  the solvent pump-
around loop just prior to entering the
top of the tower. Circulation  is regu-
lated to  give optimum wetted packing
surface in the tower.
Solvent degradation has not been found
to occur, but some is lost in the over-
head by evaporation even though vapor
pressure is |ow at reactor temperatures.
(These minute quantities of solvent are
completely burned in the  incinerator
and cause no pollution problems.) No
solvent  is  lost through entrainment.
Losses are made up by replacement
from a storage tank heated by a steam
coil.  The capacity of  the storage  tank
may  be as large as the total  column
and pump-around loop capacity.

Catalyst is also made up from a stor-
age tank equipped with a mixer which
holds a day's charge. Metering pumps
are used to hold catalyst  concentra-
tion constant and to compensate for
losses in solvent. The heat exchanger
shown in the circulation loop is used
for start-up to raise the solvent to reac-
tion temperature.

It is noteworthy that no buildup of water
occurs. Since the solvent itself is not
corrosive,  construction is thus entirely
of carbon  steel, and plant  investment
is  low.
                                                    143

-------
 PROCESS VARIABLES
 total MiHwr concentrcrtlon
 In Clous gas
 Conversions (S02 + H2S —» S) to be
 expected in the IFF process will depend
 on the total H2S + S02 concentration
 in the Claus tail gas:
                        Typical
H2S + S02. Vol %    conversion, %*
    0.4 - 0.8
        >0.8
80
90
 •In addition, the IFF process recovers 100% of
 free,sulfur — both vapor and entrained droplets.
HaS/SOa ratio
From an operating viewpoint, only the
ratio of H2S to S02 affects conversion
rates. The ratio should be held between
2.0 and 2.4 if conversion is to be maxi-
mum. This should  present no difficulty
in modern  gas processing  practice:
even though feeds to the Claus unit
may fluctuate widely in both flow rate
and composition, in-line gas chroma-
tographic  or UV  speclrophotometric
monitors can be used to regulate the
H2S/S02 ratio in the Claus tail gas ± 5%.
Controlling the  ratio  not  only maxi-
mizes sulfur recovery in the IFF unit,
but it also keeps sulfur recovery at the
highest  level in  the Claus plant itself.

COS and CSi content
The only other  process variable that
can affect sulfur recovery adversely is
the concentration of COS and CS2 in
the feed to the  IFP unit. Even  though
significant amounts of these com-
pounds are formed in the Claus burner,
the first Claus  catalytic  reactor can
bring levels of COS and CS2 well under
1000-1500 ppm. The level remains
essentially  unchanged in the  second
and third stages, and  is unchanged in
the IFP  unit, as  the IFP process does
not touch COS and CS2.

The first Claus reactor should  be run
hotter than usual to keep COS and CS2
at  a minimum.  Bauxite  can also be
                                                 replaced  with  a more sophisticated
                                                 catalyst. The slightly lower conversion
                                                 encountered when  running the first
                                                 reactor hotter will be more than offset
                                                 by the higher  sulfur recovery in  the
                                                 IFP unit.
                                                 Summary
                                                 Holding the H2S/S02 ratio in the range
                                                 2.0-2.4, and running  the Claus plant
                                                 to keep COS and CS2 down, can pro-
                                                 vide overall sulfur conversions of more
                                                 than 99.0% for the combined Claus-
                                                 IFP system. This is equivalent to stack
                                                 S02 emissions of  about 1500 ppm
                                                 after incineration.
                                                    144

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TYPICAL ECONOMICS  OF IFP  PROCIft
Two-stage sulfur unit, T/day
Recovery in IFP process, %
Overall recovery, % (2-stage Claus plus IFP)
HjS + SO, in tail gas, % Vol (wet basis)
Total tail gas throughput, Ib-moles/hr (wet basis)
IFP unit battery limits investment, US$ (engineering excluded)
Initial load of solvent and catalyst, US$
Chemicals consumption, US $/hr (solvent plus catalyst)
Power, KW
30
85
99
1.5
400
140,000
5100
1.00
30
140
85
99
1.5
1800
400,000
24,000
3.40
60
IFP  CLAUS TAIL  CAS  CLEANUP PLANTS  OPERATING  AND UNPER  CONSTRUCTION
                                                            Start-up      Throughput,           Sulfur
Plant owner               Location       Purpose             date         MMSCFD (design)      recovery (design)
Delta Engineering
Corporation
Nippon Petroleum
Refining Company
Idemitsu Oil Company
Lone Pine,
Alberta
Negishi,
Japan
Japan
Demonstration
Cleaning tail gas
from 3-stage
Claus plant
ditto
July '71*
Sept. '71«
April '72
0.8
26
22
80-85
85
85
Kyokutoh Oil Company      Japan
              ditto
                    April '72
                    16
                      90
Showa Oil Company
Japan
ditto
April '72
4.2
85
Confidential
Canada
ditto
July '72
22
 'Both the Lone Pine ano the Negishi plants are operating smoothly since start-up at design or
 better levels. See the article in OILWEEK 22. No. 32, 19-24 (September 27, 1971) lor full infor-
 mation on the  Lone Pine plant.

 For more information on the IFP process fnr cleaning up Claus plant tail gas,
 contact IFP's North American office at 90 Park Ave., New York, New York 10016.
 Telephone (212) 986-3391.
 Primed in U.S.A.
                                                             IFP153L712CI72
65
                                                     145

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                                                                      !  01=. '±
                                   I.F.I'. SULFUR RECOVERY PROCESS
                                     PRELIMINARY EVALUATION DATA
Performances of I.F.P. plant - 85% of H?S -r S02is converted into S
                             - 100% of free sulfur is recovered
Sulfur unit, T/day
•
Recovery Ln I.F.P. process, %
HITS 4. «;O'i<>
H2S -r S02 in tail gas, % Vol
(wet basis)
l.F.P. unit battery limits invest-
ment, US$ (engineering excluded)
F.iiLtlal load of solvent & Catalyst
US$
Chemicals consumption, US$/hr
(solvent plua catalyst)
Power, KW
.100
85

0.6

340,000

17,500

1.6

30
100
85

1

320,000

12,500

1.6

30
' 100
85

4

280,000

10,000

1.7

30
                                  146

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                                    I.F.P.  SULFUR RECOVERY PROCESS

                                      PRELIMINARY EVALUATION DATA


Performances of I.F.P. plant  -  85%  of HoS  -r S02is converted into S
                              -  100% of free sulfur is recovered
Sulfur i-.nlt, T/day                               300                    300


Recovery in I.F.P. process,  7.                     85                     85
                           Jt_
II2S •» S02 in tail gas, % Vol                       0.6
	(wet basis)
I.F.P. unit battery limits Invest-          700,000                670,0.00
nxMit , US$ (engineering excluded)
f.;iLt.l..-il load of solvent  & Catalyst           40,000                 37,000
	  	•	us$     '	'
Chemicals consumption, US$/hr                     4.3                    4.2
(solvent plus catalyst)
Pov.-er, KW                                        80                     80
                                   147

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                                   I. P.P. SULFUR RECOVERY PROCESS

                                     PRELIMINARY EVALUATION DATA


Performances of I.P.P. plant - 85% of I^S * SC^is converted into S
                             - 100% of free sulfur is recovered
Sulfur iMi.it, T/day                                1500                 1500
Recovery in I.F.P. process, %                       85                   85
H2S -r S02 in tail gas, % Vol                         0.6                 1
	(wet basis)	

I.P.P. unit battery limits invest-            3,300,000             3.000,000
menu, US$ (engineering excluded)
r.uUlal load of solvent & Catalyst              200,000               180,000
Chemicals consumption, US$/hr                       21.2               20,3
(ijulvent plus catalyst)
Power, KW                                         390                 390
                                   148

-------
 FILL OUT AND RETURN TO IFP  FOR BUDGET QUOTATION
 1. COMPANY
 2.  PLANT LOCATION.
 3. CLAUS PLANT CAPACITY_
 6. ENGINEERED BY	
_LT/D SULFUR
4. YEAR BUILT
                                         _5. YEAR STARTED UP
 7. ACID GAS THROUGHPUT
 9. ACID GAS ANALYSIS (VOL. %) H,S_
10. TYPE OF CATALYST	
11. RECOVERY: DESIGN	
     MMSCFDl      8. NUMBER OF STAGES	
    	I CO,	| H,Q	| C,.C,_
                  ACTUAL
12. PROCESS CONTROL (SPECIFY GC. UV, OTHER).
13. VARIATION OF H.S/SO, RATIO	
                                 CLOSED LOOP CONTROL (YES OR N0)_
                TO.
14. TAIL GAS THROUGHPUT.
                             MMSCFDl (5)
CAN BE COOLED . Of| is. MAXIMUM ALLOWABLE PRESSURE OROP RFTWFFN Cl AUS UNIT AND INCINFRATOR PSI
17. TAIL GAS ANALYSIS FROM 1st REACTOR
Ib-mol/hr vol %
H,S
SO,
s
S.
s,
s,
cos
cs,
N.
w,n
CO,
0,
H:
rn
c,,c,
Trvrai
FROM 2nd REACTOR
Ib-mol/hr vol %















FROM 3ni REACTOR
Ib-mol/hr vol %















18. DUTY FOR IFP PROCESS (SPECIFY ONE):
CONVERSION	% (FROM H,S + SO, IN TAIL GAS)
DECREASE IN STACK SO, FROM	PPM TO	PPM
                 INCREASE IN OVERALL RECOVERY FROM	% T0_
                    DECREASE IN STACK SO, FROM	LT/D TO
                                                                                                LT/D
19. YOUR NAME.
20. TITLE	
21. COMPANY.
22. ADDRESS.
23. CITY	
                                                     STATE
                                                                                    .ZIP.
24. TELEPHONE (AREA CODE.
                                                                       EXTENSION.
RETURN THIS COMPLETED QUESTIONNAIRE TO IFP, 90 PARK AVE., NEW YORK, N.Y. 10016 • TEL: (212) 986-3391
Printed In U.S.A.                                                                               IFP154L712C172
                                               149

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  PROCESSES RESEARCH, INC.
  INDUSTRIAL PLANNING AND RESEARCH
APPENDIX N - WELLMAN-POWER GAS INFORMATION
                150

-------
   TRIP TO JAPAN, DECEMBER 2-12, 1971
             DETAILED REPORT
                  BY
Sheldon Meyers, Control Systems Division
John DeKany, Control Systems Division
Gary Rochelle, Control Systems Division
             February 1, 1972
               151

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and manganese processes.

WELLMAM-POWER GAS LICENSEES

     We visited two operating Wellman-Lord units in Japan and discussed the
process with operating personnel and design engineers.  The processes are
summarized in the tables below.  Additional descriptive material on the units
and the process in general is in'Appendices 11.0.  The units have been in
operation since August 1971.  Performance is generally satisfactory.  Problems
are summarized in the following sections.
  Location
      Operating Wellman-Lord Units

      User               Engineers
                      Application
Kawasaki, Japan
Chiba, Japan

Paulsboro, N. J.

  Capacity Data
Toa Nenryo Kogyo
Japan Synthetic
 Rubber
Olin Matheson
Sumitomo Chem. Eng.
Mitsubishi Heavy
 Machinery Mfg.
Wellman-Power Gas
Claus plant
Oil-fired boiler

Acid plant

Kawasaki
Chiba
Paulsboro
Hypothetical 100 MW
Gas rate
SCFM
43,000
128,000
45,000
177,000
S0~ rate
C/7hr.
3300
2650
2500
5000
S02 concentration (ppm)
In Out
6500
2000
5000
2700
50
200
200
200
Purge - Degradation  of  the absorbent is similar  to  that observed at Paulsboro.
At both Japanese plants  the required makeup rate is about 0.45 moles NaOH/mole
S02 removed.  At JSR oxidation and disproportionation contribute equally to
sulfate formation.   At  Toa Nenryo disproportionation produces twice as much
sulfate as oxidation.   Overall degradation at both  units is 3 to 5% of the
sulfur removed.  Process  improvements to eliminate  disproportionation and reduce
oxidation should reduce makeup to" 0.10 moles NaOH/mole S02.

     Mother liquor purged from the evaporator is used in the prescrubber, then
treated with sulfuric acid and stripped with air to remove SO- and reduce COD.
The solution sent to sewer is essentially sodium sulfate.  Only 10 to 20% of  the
dissolved solids in  the untreated mother liquor are sulfate or thiosulfate, the
rest being sulfite and  bisulfite.  Even though degradation is only 3 to 5% of the
sulfur removed, 15 to 30% of  the sulfur is purged as sodium sulfate.  MKK is
piloting an alternate scheme  of reducing COD-by disproportionation of the waste
solution at elevated temperature.
                                      152

-------
Oxidation  -  Both plants use scrubbers with  two  stages  of  SCL  absorption  and  a
prescrubber.   Each  stage  consists  of  two  sieve  trays and  a  recirculation system.
Toa Nenryo also uses a quench  spray tower followed by  a gas cooler  before  the
prescrubber.   The stack gas at both units contains about  5% 0_.   JSR has 200 ppra
NO  into the scrubber and  160  ppm  out.  At  both units  sulfate  formation  from
oxidation  has  been  about  1 kg/100  Nm^O-.

     Both  licensees operated small pilot plants (600 SCFM).  Mitsubishi  observed
oxidation  of 0.8 -  1.3 kg Na2SO/f/100 NnrO™.  In a packed  column  Sumitomo observed
oxidation  of 3.0 kg without inhibitor, 1.3  kg with.  Both licensees found  that
the rate of oxidation was directly proportional to oxygen concentration.

     The oxidation  inhibitor developed by Sumitomo was tested  by  Welltnan-Power
Gas at Paulsboro.   It reduced  oxidation 50  to 80%.  The inhibitor has been used
continuously at Toa Nenryo, so there is no  firm evidence of its effectiveness
in that application.  Information  received  after the trip indicated that the
inhibitor  is EDTA (ethylenediarainetetracetic acid).

Disproportionation -  There are two evaporator vessels at each plant, designed
to permit  double effect of steam.  However, at half-load conditions only one
evaporator is being used, operating near atmospheric pressure.  The evaporators
are designed for a residence time  of 3'hours with respect to feed liquor.  The
amount of  disproportionation should increase rapidly with temperature and
proportionately with residence time.  Both  Japanese users are  installing vacuum
equipment  to permit operation of the evaporators at lower temperature, thereby
eliminating disproportionation.  There have been.no serious maintenance  problems
with blowers presently used to transport the SO™ product.

Ash Removal - The JSR plant was not initially equipped to remove  oil ash from
the evaporator-absorber cycle.   Ash entrained from the prescrubber accumulated
and eventually caused minor plugging in the closed cycle.  A semi-continuous
vertical centrifuge has been installed to remove particulates  from the scrubber
effluent.  It appears to have alleviated the problem.

Acid - The acid plant at JSR uses  100% excess air but is still significantly
smaller than a plant to produce acid from S.  Gas flow is about half that
required for a conventional plant.  Maximum gas temperature is 600°C.

Operations - JSR uses two operators.  Toa Nenryo is on closed loop control by
the refinery computer.

Glaus Plant Alternatives  - Toa Nenryo also considered use of the  Beavon  and
IFF processes.   Beavon is more expensive and IFF has technical problems.

Commercial Arrangements -  The JSR plant was built by funds from  MKK and the
Japan Development Bank at a cost of 800 million yen ($2.4 million).  MITI
arranged and guaranteed the low-intece,st loan.   JSR will buy the  plant after
satisfactory operation for a year.
                                       153

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  SUMITOMO  CHEMICAL  ENGINEERING COMPANY,  LTD.       11.5
THE WELLMAN-LORD SOo  RECOVERY PROCESS
             ' NOVEMBER'; 1971
SUMITOMO  CHEMICAL ENGINEERING CO,', LTD,
                 ISA

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       I.  Development and Improvement in Japan
      II. Commercial Application:—Toa Nenryo Plant
This represents a brief outline of the development and
Improvement for the WeHman-Lord S02 Recovery  process
made by our company and it's commercial  application to
toa Nenryo Plant.
                      155

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t. Development and Improvement in Japan

The environmental problems we have here in Japan are probably similar
to those of the America.  In recent years, the public opinion against
pollution-air, waters, dusts, etc. has been increasingly widespread,
centering on petro-chemical  combinat and heavy industries crov/ded  areas,
such as areas of Kawasaki, Chiba, Sakai and so on.   The emphasis given
to industrial growth in the past thinking has been  shifted to human
health, safety and well-being for environmental protection.   The enforce-
ment by laws has been gradually prepared for pollution control;
the comprehensive pollution control laws were  passed   in  the Diet
last December, transferring broad powers to local governments to regulate
pollutants emissions from worlds or factories.  The  laws:»ks enacted on
July 1st this year, giving one* year or one year and half grace period,
depending on local conditions.  With this respect to the air pollution
control, the permissible emission level of S02 from stacks has become
severe year after year and therefore industries have realized the  necessity
of the S02 recovery process to direct their efforts towards  it in  order
to meet local requirements.   As one of the approaches to the SOg abatement
process, a dry system was at first taken up. as a pilot plant, jointly
by the Government and power companies, chiefly in consideration of exit
gas diffusion.  And two processes were selected;  one is the  activated
carbon process by Tokyo Power Co. and another DAP -Mn process by Chubu
Power Co.  and another activated carbon process was  used by Kansai  Power
Co. later.

But these prospects are all  said to be not so promising from past  ex-
periences.  Some observe that a number of hitches still  remain before
the plant can be put to commercial use.

      These capacities now are:
         Tokyo Power Co.
         Chubu Power Co.
        Kansai Pov/er Co.
420,000 MM /H (on stream early next  year)
326,500   "   (           "              )
175,000   "   ( completed in  September this year
                and at present test  run continues)
                             156

-------
             SUMITOMO  CHEMICAL  ENGINEERING  COMPANY,  LTD.
We, Sumitomo Chemical  Engineering  Co.\  richly  expeirenced in the sulfuric
add plant, taking notice of this  potential  trend towards air pollution
control, introduced the SC^ recovery process from the Wellman-Power Gas
Corp. (then Wellman-Lord) jointly  with  Mitsubishi Kakoki Company two
years ago for the following reasons:

    1.  The Wellman-Lord process is  a wet  regenerative system requiring
        less plant area, less capital cost,  compaired to the dry system.
    2..  The end product from the process is  pure gaseous or liquid S02,
        which can be used as raw material  for  the sulfuric acid or elemental
        sulfur.
    3.  The Wellman-Lord process is  able to  recover at least 90% of S02
        from stack gases, in excess  of  97% of  any $03 and add mist,
                               «
        and about 902 of fly ash.
    4.  It 1s widely adaptable for use  to  power plants, chemical industries,
        oil refineries and others. *

The Wellman-Power Gas, from the very beginning of the pilot plant instal-
lation to the Olin's commercial plant through  the Baltimore demonstration
plant, has proceeded with extensive  works  to obtain the process reliabili-
ty, both technically and economically.  On the other hand, Sumitomo began
activities by installing a pilot plant  of  1,000 NM3/H_at Niihama just
after Introduction of the Wellman-Lord  process.  The objectives of the
pilot plant were:

    1.  To further investigate and corroborate the Wellmna-Lordls laboratory
        and pilot plant data, especially  in  the points of S0£ removal,
        reduction of chemical make up requirements by purge treatment and
        antloxidant.-
    2.  To refine the process design', thereby  further improving the process.
    3.  To obtain the mechanical reliability of the equipment and machinery.
                             157

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             SUMITOMO  CHEMICAL  EN6INEERIN6 COMPANY,  LTD.
 The Niihama  pilot  plant  was  operated  for the duration of about a year
 and half,  first  using  the  potassium system and then the sodium system.
 And also the plant treated gases  from the sulfuric acid tail gases to
 oil fired  boiler using the high concentrated sulfur of 5%.  Thus, the
 extensive  test programs  were conducted and the pertinent data the plant
 could give were  all  collected,  The results on basic process chemistry
 proved to  be encouraging and satisfactory.  The research and development
 tests thus carried out by  us led  to the .award of the contract by Toa
 Nenryo Company for the first Well man-Lord S02 recovery plant last July.
-II.  Commercial  Application"!!. Toa  Nenryo Plant

 Toa  Nenryo  Company,  one  of the  leading oil company 1n Japan and incorporat-
 ed with Esso  and  Mobil of the U.S.A. with each 25« shareholder, installed
 the  sulfur  recovery  plant (Claus unit) as part of the indirect desulfuriza-
 tlon plant  at Kawasaki,  Kanagawa Prefecture.  The Kawasaki area is under
 the  severest  regulation  for pollution control-because of heavy industries
 covering oil  refineries  and Iron steel densely congested and the stack '.
 height is limited as low as 50  meters or so because the Haneda air port is
 located in  the close neighborhood  of the Kawasaki area.

 In such a circumstance,  Toa Nenryo made the extensive, study of the $02
 recovery process  to  treat tail  gases from the sulfur recovery plant and
 finally selected  the Wellman-Lord  process as the most suitable and advanced
 technology  after  evaluation of  the process effectiveness.  They appreciated
 the  Sumitomo  efforts to  conduct tests by the Niihama pilot plant and finally
 gave us an  award  to  proceed with designing, engineering and construction of
 the  plant as  a general contractor  last July, based on the Well man-Lord basic
 design.  The  process is  a sodium based absorption which will recover the
 S02  for re-use 1n the sulfur'recovery plant.  The plant v/as completed early
 July this year as expected but  the plant start-up was delayed more than a
 month because Toa Nenryo decided on consideration that the Japanese market
 surrounding the oil  products was so badly depressed.
                             158

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             SUMITOMO CHEMICAL  ENGINEERING  COMPANY,  LTD.
But the plant now 1s operating successfully absorbing  $03  In excess of
the original design specifications and this is  the  first commercial
Installation of the Wellman-Lord's $02 recovery process in Japan and
further constitutes a milestone to the air pollution control.

The outlines of the Toa Nenryo plant are as follows:

      Basic design conditions

         Gas volume:         67,200 NM3/H
         S02 concentration:   7,600 PPM
         Temperature:           538°C
         Pressure:               20 mm H£0
         End product of S02: Max. 200 PPM

The process itself is principally the Well man-Lord  process except the
pretreatment of gases.  (The process flow 1s given  on  the  attached sheet
for reference.)
It 1s, first,necessary to cool down the gases  of hfgh temperature.
The gases containing rich S02 and other components  are  led into the
waste heat boiler where steam is generated  to  be available for use
and then Introduced into the spray tower by the  blower  to be cooled
down with water spray.  The cooled-down gases  are sent  to the pre-
scrubber at the absorber bottom at an appropriate temperature by way
of the Indirect gas cooler.  Following the  absorber section to the
S02 cooler through the chemical section, the main stream is as covered
by the Wellman-Lord process.  Here, we present you  some characteristics
with the Toa Nenryo plant:

         1. S02 emission at tfie absorber top.
                70~150 PPM  (Inlet S02 6.000PPM)
         2. The absorber is of sieve tray type.
         3. End product of S02 is returned  to  the sulfur recovery plant.
         4.*Antioxidant developed by Sumitomo  Chemical  Co. is used to
            inhibit the sulfate formation,  thereby  reducing chemical
            requirement.
                              159

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        5. Materials
           Rubber lining or FRP used where temperature  is  relatively
           low.  Stainless steal  used where temperature is relatively
           high or corrosion may occur.

The plant started up mid-August after a month postponement  as  aforesaid
and up to date it shutdowned twice, the  first due to  the failure  af the
gas duct from the absorber to the central  stack and the second  the sewer
system.  We experienced some mdnor mechanical problems  with it  but we
have cleared them up through a joint effort with Wellman-Power  Gas and
the client.
                              160

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PROCESSES RESEARCH, INC.
INDUSTRIAL PLANNING AND RESEARCH
     APPENDIX 0 - BIBLIOGRAPHY
             161

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                  PROCESSES  RESEARCH, INC.
                  INDUSTRIAL PLANNING AND RESEARCH
                        APPENDIX 0 - BIBLIOGRAPHY


 1.   October  1950  Industrial and Engineering Chemistry  Vol. 42 No. 10
     pages  1938-1950 "Sulfur From Sour Gases" by Frederick G. Sawyer, Rodney N.
     Hader, L. Kermit Herndon and Eugene Morningstar.

 2.   November 1950  Industrial and Engineering Chemistry  Vol. 42 No. 11
     pages  2258-2268 "Recovery of Sulfur Compounds from Atmospheric Contaminants"
     by  Morris Katz and R. J. Cole.

 3.   November 1950  Industrial and Engineering Chemistry  Vol. 42 No. 11
     pages  2277-2287 "Recovery of Sulfur From Synthesis Gas" by A. E. Sands and
     L.  D.  Schmidt.

 4.   April  1953  Chemical Engineering Progress  Vol. 49 No. 4 pages 203-215
     "Sulfur  from Hydrogen Sulfide" by B. W. Gamson and R. H. Elkins.

 5.   April  1953  The Petroleum Engineer  pages C-19 to C-24 "Sulfur Recovery
     Practices In Oil Industry" by R. A. Graff.

 6.   April  1, 1963  Chemical Engineering  Vol. 60 No. 4 pages 38 and 40 "Plant
     Recovers Sulfur From Lean Acid Gas."

 7.   March  1964  Hydrocarbon Processing & Petroleum Refiner  Vol. 43 No. 3
     pages  104-108 "New Look At Sulfur Plants, Part 1: Design" by A. R. Valdes.

 8.   April  1964  Hydrocarbon Processing & Petroleum Refiner  Vol. 43 No. 4
     pages  122-124 "New Look At Sulfur Plants, Part 2: Operations" by A. R. Valdes.

 9.   September 1965  Chemical Engineering Progress  Vol. 61 No. 9 pages 70-73
     "Package Plants For Sulfur Recovery" by Howard Grekel, L. V. Kunkel and
     R.  L.  McGalliard.

10.   April  15, 1968  Evaluation of Fluid Bed Contactor and Glaus Sulfur Recovery
     for Application to Alkalized Alumina Process  Final Report prepared for
     National Center for Air Pollution Control U. S. Public Health Service by
     A.  M.  Kinney, Inc.

11.   May 1968 Engineering and Mining Journal  Vol. 169 No. 5 pages 63-72 "Sulphur,
     Part One: The Economics of New Recovery Systems."

12.   June 1968  Engineering and Mining Journal  Vol. 169 No. 6 pages 91-100
     "Sulphur, Part Two: Pollution Control  and By-Product Sulphur Too."

13.   July 1968  Engineering and Mining Journal  Vol. 169 No. 7 pages 69-76
     "Sulphur, Part Three: Route  to Sulphur Via Volcanics and Gypsum."
                                   162

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                  PROCESSES RESEARCH, INC.
                  INDUSTRIAL PLANNING AND RESEARCH
14.   August 1968  Engineering  and Mining Journal  Vol. 169 No. 8 pages 59-66
     "Sulphur,  Part Four:  A Hidden Asset In Smelter Gases."

15.   September  1968  Hydrocarbon Processing  Vol. 47 No. 9 pages 248-252 "Today's
     Sulfur Recovery Processes" by B. Gene Goar.

16.   October 1968  Engineering and Mining Journal  Vol. 169 No. 10 pages 85-92
     "Sulphur,  Part Five:  Harvesting Sulphur From Sour Gas and Oil."

17.   October 1968  Hydrocarbon Processing  Vol. 47 No. 10 pages CR9-CR28 "HPI
     Construction Boxscore,  Hydrocarbon Processing Plants, United States."

18.   October 28, 1968  The Oil and Gas Journal  Vol. 66 No. 43 pages 88-101 "Why
     Recover Sulfur From H2S?" by Howard Grekel, J. W. Palm and J. W. Kilmer.

19.   November 1968  Chemical Engineering Progress  Vol. 64 No. 11 pages 47-53
     "The Sulfur Outlook"  by M. C. Manderson.

20.   November 1968  Chemical Engineering Progress  Vol. 64 No. 11 pages 75-81
     "New Source For Sulfur" by B. G. Mandelik and C. U. Pierson.

21.   February 1969  Hydrocarbon Processing  Vol. 48 No. 2 pages CR8-CR22 "HPI
     Construction Boxscore,  Hydrocarbon Processing Plants, United States."

22.   September  1969  Hydrocarbon Processing  Vol. 48 No. 9 pages 179-183 "Gas
     Processing In The USSR" by Joseph C. Benedyk.

23.   October 1969  Hydrocarbon Processing  Vol. 48 No. 10 pages CR13-CR25 "HPI
     Construction Boxscore,  Hydrocarbon Processing Plants, United States."

24.   November 1969  Hydrocarbon Processing  Vol. 48 No. 11 page 236 "Sulfur
     Recovery,  Direct Oxidation Process" by Pan American Petroleum Corp.(Subsidiary
     of Standard Oil Company,  Indiana).

25.   December 1969  Hydrocarbon Processing  Vol. 48 No. 12 pages 133 and 134 "Ideas
     for Gas Plant Automation" by B. A. Eckerson.

26.   February 1970  Hydrocarbon Processing  Vol. 49 No. 2 pages CR3-CR16 "HPI
     Construction Boxscore,  Hydrocarbon Processing Plants, United States."

27.   May 11, 1970  The Oil and Gas Journal  Vol. 68 No. 19 pages 63-67 "Here's
     What's Being Done To  Combat Sulfur-Oxide Air Pollution" by Charles B. Barry.

28.   August 1970  Engineering  and Mining Journal  Vol. 171 No. 8 page 136 "A
     Process That Would Permit Sulfur Oxides To Be Converted To Elemental Sulfur
     For $5 A Ton At The Smelter Instead Of The Present $47 A Ton."
                                  163

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                   PROCESSES  RESEARCH, INC.
                   INDUSTRIAL PLANNING AND RESEARCH
29.  October 1970  Hydrocarbon Processing   Vol.  49 No.  10 page 15 "Process Recovers
     99.9% Of Sulfur In Tail Gas."

30.  October 1970  Hydrocarbon Processing   Vol.  49 No.  10 pages CR5-CR18 "World-
     Wide HPI Construction Boxscore,  United States."

31.  October 5, 1970  Chemical Engineering   Vol.  77 No.  21 page 43 "Sulfur Is
     Effectively Removed From The Tail  Gas  of  Sulfur-Recovery Plants Themselves."

32.  October 5, 1970  Chemical Engineering   Vol.  77 No.  21 page 47 "New Pollutant
     Removal Processes Announced."

33.  December 14, 1970  The Oil and Gas Journal   Vol. 68 No. 50 pages 102-112
     "Evaluation of Sulfur-Plant Efficiency-A  New Stoichiometric Method" by
     L. F. Sudduth, S. K.  Farmer and  H.  Grekel.

34.  January 5, 1971  U. S. Patent 3.552.927  "Sulfur Recovery Apparatus" by
     George M.  Franklin, Lorenz V. Kunkel and  Willard A. Lewis.

35.  February 1971  Chem Tech  pages  114-116 "Desulfurize Coal?" by Henry C. Messman.

36.  February 1971  Hydrocarbon Processing   Vol.  50 No.  2 Section 2 pages 5-13
     "World-Wide HPI Construction Boxscore, United States."

37.  February 10, 1971  Chemical Week  Vol. 109  No. 6 pages 25-36 "Dark Cloud On
     Sulfur's Horizon" by John M. Winton.

38.  February 26, 1971  Preprint Japan Petroleum Institute  "Prevention of Air
     Pollution by Refinery Sulfur Plants" by David K. Beavon.

39.  April 1971  Journal of the Air Pollution  Control Association  Vol. 21 No. 4
     pages 185-194 "Control of Sulfur Oxide Emissions From Primary Copper, Lead
     and Zinc Smelters - A Critical Review" by Konrad T. Semrau.

40.  April 1971  Hydrocarbon Processing Vol.  50 No. 4  (NG/SNG Handbook)
     page 105 "Giammarco Vetrocoke  (H2S)" by The Power  Gas Corp. Ltd.
     page 112 "Modified Glaus" by BAMAG Verfahrenstecknik GmbH.
     page 113 "Molecular Sieves" by Linde Division, Union Carbide Corp.
     page 119 "Stretford"  by The Ralph  M. Parsons Company.

41.  May 1971  Hydrocarbon Processing  Vol. 50 No. 5 pages 89-91 "Treat Claus Tail
     Gas" by Yves Barthel, Yaoudi Bistri, Andre  Deschamps, Phillippe Renault,
     Jean Claude Simadoux and Robert  Dutriau.

42.  May 1971  Chemical Engineering Progress  Vol. 67 No. 5 pages 69-72 "Reducing
     S02 Emmission From Stationary Sources" by T. H. Chilton.
                                   164

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                  PROCESSES  RESEARCH, INC.
                  INDUSTRIAL  PLANNING AND RESEARCH
A3.  June 14, 1971  Chemical Engineering  Vol.  78 No. 13 pages 58-62 "Sulfur-
     Recovery Processes  Compete  For  Leading Role" by Judith Yulish.

44.  June 14, 1971  Chemical Engineering  Vol.  78 No. 13 page 151 Advertisement
     "Improved Sulfur Recovery Process  Reduces  Air Pollution" by The Ralph M.
     Parsons Company.

45.  June 14, 1971  Chemical and Engineering News  Vol. 49 No. 24 pages 31 and
     32 "Citric Acid Used In S02 Recovery."

46.  July 1971  Environmental Science & Technology  Vol. 5 No, 7 pages 626-630
     "Removal of Sulfur  Dioxide  From Stack Gases By A Modified Claus Process" by
     Robert T. Struck, Metro D.  Kulik,  and Everett Gorin.

47.  July 1971  Engineering and  Mining  Journal  Vol. 172 No. 7 pages 61-71 "S02
     Laws Force U.S. Copper Smelters Into Industrial Russian Roulette" by
     Lane White.

48.  July 5, 1971  The Oil and Gas Journal  Vol. 69 No. 27 page 106 "Dallas Firm
     Offers New Sulfur Process."

49.  July 12, 1971  The  Oil and  Gas  Journal  pages 84-124 "1971 Survey of Gas-
     Processing Plants."

50.  September 6, 1971  The Oil  and  Gas Journal pages 118-131 "Worldwide Survey
     Of Petrochemical Facilities, United States" by Ailleen Cantrell.

51.  September 20, 1971   Chemical Engineering   Vol. 78 No. 21 page 83 "Sulfur
     Removal Projects Keep A-Coming."

52.  October 1971  Hydrocarbon Processing  Vol. 50 No. 10 Section 2 pages 7-15
     "World-Wide HPI Construction Boxscore, United States."

53.  October 1971  Engineering and Mining Journal  Vol. 172 No. 10 page 32 "Pilot
     Plant to Produce Elemental  Sulfur  Comes On Stream At Asarco's El Paso Smelter."

54.  October 11, 1971 The Oil and Gas  Journal  Vol. 69 No. 41 pages 68 and 69
     "Stretford Removal  Process  For  H2S Is Licensed."

55.  November 1971  Hydrocarbon  Processing  Vol. 50 No. 11 page 9 "A New Catalyst
     Will Eliminate Sulfur In Glaus-Unit Tail Gas.,"

56.  November 1971  Hydrocarbon  Processing  Vol. 50 No. 11 page 208 "Sulfur Recovery
     (Split Flow-Sulfur  Recycle  Process)" by Amoco Production Co.

57.  November 29, 1971  Chemical Engineering  Vol. 78 No. 27 pages 17 and 18
     "Molecular Sieves Can Effectively  Control  Emissions at Sulfuric Or Nitric
     Acid Plants."
                                  165

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                  PROCESSES  RESEARCH, INC.
                  INDUSTRIAL PLANNING AND RESEARCH
58.   November 29,  1971   Chemical Engineering  Vol. 78 No. 27 pages 18 and 19
     "A Continuous Copper-Smelting Process That Is Economical And Doesn't Pollute
     The Air."

59.   November 29,  1971   Chemical Engineering  Vol. 78 No. 27 pages 43-45 "S02
     Absorbed From Tail  Gas  With Sodium Sulfite" by John C. Davis.

60.   December 1971  Environmental Science & Technology  Vol. 5 No. 12 page 1165
     "S02 Removal  Process  Tested By  Copper Producers."

61.   December 13,  1971   Chemical Engineering  Vol. 78 No. 28 pages 71-73 "Add-On
     Process Slashes Claus Tailgas Pollution" by David K. Beavon.

62.   December 13,  1971   The  Oil and  Gas Journal  Vol. 69 No. 25 page 39
     "Desulfurization Projects Mushroom In Japan."

63.   December 20,  1971   Chemical and Engineering News  Vol. 49 No. 51 page 38
     "S02 Removal."

64.   January 1972   Coal  Age   Vol. 77 No. 1 page 6 "New Contract Supports
     Gasification."

65.   January 10, 1972 The Oil and Gas Journal  Vol. 70 No. 2 pages 58 and 59
     "Sulfur-Recovery Unit Is On Stream."

66.   January/February 1972  Pollution Engineering  Vol. 4 No. 1 pages 34 and 35
     "Abating Sulfur Plant Tail Gases" by David K. Beavon.

67.   February 1972  Chemical Engineering Progress  Vol. 68 No. 2 pages 70-76
     "The Status Of SOY  Emmission Limitations" by R. L. Duprey.
                     X

68.   February 1972  Hydrocarbon Processing  Vol. 51 No. 2 Section 1 pages 17 and 18
     "Another (world's first) For IFP Sulfur Recovery."

69.   February 1972  Hydrocarbon Processing  Vol. 51 No. 2 Section 2 pages 3-10
     "World-Wide HPI Construction Boxscore, United States."

70,   February 1972  Hydrocarbon Processing  Vol. 51 No. 2 Section 2 pages 24 and 25
     "The Chiyoda Thoroughbred 101 Flue Gas Desulfurization Process."

71.   February 7, 1972 The Oil and Gas Journal  Vol. 70 No. 5 page 40 "Gulf
     Refinery Boosting Stack Cleanup."

72.   February 7, 1972 The Oil and Gas Journal  Vol. 70 No. 5 pages 65 and 66
     "Tail-Gas Desulfurization Operations Successful."
                                  166

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                   PROCESSES  RESEARCPI, INC.
                   INDUSTRIAL  PLANNING AND RESEARCH
73.   February 7,  1972   The Oil and Gas Journal  Vol. 70 No. 5 pages 66 and 67
     "New Beavon  Process  Takes Sulfur-Bearing Compounds From Tail Gas."

74.   February 7,  1972   Chemical  Engineering  Vol. 79 No. 3 page 23 "First User
     Of J. F. Pritchard & Co.'s  Process To Take Sulfur Out Of Tail-Gas."

75.   February 14, 1972  Chemical and Engineering News  Vol. 50 No. 7 page 13
     "Testing Sulfur Oxide Removal."

76.   March 1972  Hydrocarbon Processing  Vol. 51 No. 3/pages 105-108 "Watch
     These Trends In Sulfur Plant Design" by J. W. Palm.

77.   March 1972  Power  Vol. 116 No. 3 page 30 "Removal Of S02 From Flue Gases."

78.   March 6, 1972  The Oil and  Gas Journal  Vol. 69 No. 10 page 42 "The Chiyoda
     Thoroughbred 101 Flue Gas Desulfurization Process."

79.   March 6, 1972  Chemical and Engineering News  Vol. 50 No. 10 page 16 "Sulfur
     Dioxide Recovery Process."

80.   April 1972  Hydrocarbon Processing  Vol. 51 No. 4 pages 102-106 "Reduce
     Glaus Sulfur Emission" by Charles B. Barry.

81.   April 3, 1972  Chemical and Engineering News  Vol. 50 No. 14 page 16
     "Removing H2S From Effluents."

82.   April 3, 1972  Chemical Engineering  Vol. 79 No. 7 page 39 "A Quick, Simple
     Way to Remove Hydrogen Sulfide From Gases Or Liquids."

83.   April 12, 1972  Chemical Week  Vol. 110 No. 15 pages 41 and 42 "Wringing
     Sulfur From Stack  Gas."

84.   April 17, 1972  Chemical Engineering  Vol. 79 No. 8 pages 78 and 79 "Solvent/
     Catalyst Mixture Desulfurizes Glaus Tailgas" by M. Hirai, R. Odello and
     H. Shimamura.

85.   May 15, 1972  Chemical Engineering Vol. 79 No. 11 pages 66 through 68
     "Desulfurization - Part 1  ... Add-on Processes Stem I^S" by John C. Davis
     (Note correction August 7,  1972 Chemical Engineering Vol. 79 No. 17 page 5).

86.   June 1972  Hydrocarbdn Processing  Vol. 51 No: 6 page 15 "Claims Sulfur
     Removal at 99.9%  Efficiency."

87.   June 1972  Hydrocarbon Processing  Vol. 51 No. 6 Section 2 pages 3-7
     "World-Wide HPI Construction  Boxscore, United  States."

88.   June 12, 1972  Chemical Engineering  Vol. 79 No. 13 pages 52  through 56
     "Desulfurization - Part  2   ...  S02 Removal Still Prototype"  by John C. Davis.
                                   167

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BIBLIOGRAPHIC DATA '• ReP°" No- 2-
SHEET EPA-R2-73-188
4. Tide and Subciclc
Characterization of Claus Plant Emissions
7. Author(s1
W.D. Beers
9. Performing Organization Name and Address
Processes Research, Inc.
2912 Vernon Place
Cincinnati, Ohio 45219
12. Sponsoring Organization Name and Address
EPA, Office of Research and Monitoring
NERC/RTP, Control Systems Laboratory
Research Triangle Park, North Carolina 27711
3. Recipient's Accession No.
5* Report Date
April 1973
6.
8- Performing Organization Kept.
No.
10. Project/Task/Work Unit No.
Task Order 2
11. Contract/Grant No.
68-02-0242
13. Type of Report & Period
Covered
Final
14.
IS. Supplementary Notes
i6. Abstracts rj,^ repOrt discusses Claus sulfur plant emissions an
literature, supplemented with data from companies operating o
plants. It discusses process variations, investment, and opera
for 169 Claus plants in 31 states , with daily sulfur capacities to
tons , most based on natural gas or petroleum refining. Total c
plants is 60 percent more than the U.S. total. Tail gases from
usually burned, converting the H2S to sulfur oxides. Annual em
plants are estimated to be 875,000 short tons of SO2 equivalent
stages could eliminate about 70 percent of these emissions. Th
process could eliminate about 99 percent of the emissions , dou
operating costs. The IFF process could eliminate about 90 pen
investment and operating costs for the IFP addition are about h
17. Key Words and Document Analysis. 17o. Descriptors UiaUS plant aJ
Air Pollution Hydrogen Sulfide the Chiyoda a
"•Operating Costs Catalysis flue gas desu
Desulfurization are also pres
Design is included.
d control, based on
r designing Claus
tjng costs. 'It lists data
taling over 15 ,800 long
apacity of 66 Canadian
Claus plants are
issions from U.S.
. Additional catalytic
e Beavon or Cleanair
bling investment and
:ent of the emissions;
alf of those for the
[one. Information on
ind the Wellman- Power
Lfurization processes
ented. A bibliography
*Investments
Economics
Natural Gas
Petroleum Refining
Sulfur Oxides
17b. Idemifiers/Open-Ended Terms
Air Pollution Control Cleanair Process
Stationary Sources IFP Process
*Claus Plant Chiyoda Process
Tail Gases Wellman- Power Process
Beavon Process
17c. COSAT1 Field/Group 13B
18. Availability Statement 19.. Security Class (This 21. No. of Pages
Unlimited . Reft$i.AssiFiEn 167
JOTSecuriiy Class (This 22. Price
Pa*e
UNCLASSIFIED
FORM NTIS-33 (REV. 3-721
                                                                                                                           USCOMM-DC  14BS2-P72

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