EPA-450/3-75-081
August 1974
           CHARACTERIZATION
        OF SULFUR RECOVERY
    IN OIL AND  NATURAL  GAS
                    PRODUCTION
     U.S. ENVIRONMENTAL PROTECTION AGENCY
        Offiro of Air and Waste Manure mm!
      Office of Air Quality Planning and Standards
     Research Triangle Park, North Carolina 27711

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                             EPA-450/3-75-081
    CHARACTERIZATION
  OF SULFUR RECOVERY
IN  OIL  AND  NATURAL GAS

        PRODUCTION
                 by

            Keshava S. Murthy

               Battelle
          Columbus Laboratories
            505 King Avenue
           Columbus, Ohio 43201

          Contract No. 68-02-0611
               Task 6
      EPA Project Officer: William Herring
              Prepared for

     ENVIRONMENTAL PROTECTION AGENCY
       Office of Air and Waste Management
    Office of Air Quality Planning and Standards
    Research Triangle Park, North Carolina 27711

              August 1974

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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers.  Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the
Air Pollution  Technical Information Center, Environmental Protection
Agency,  Research Triangle Park, North Carolina 27711; or, for a fee,
from the National Technical Information Service, 5285 Port Royal Road,
Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by
Battelle Columbus Laboratories,  Columbus, Ohio 43201, in fulfillment
of Contract No. 68-02-0611, Task 6. The contents of this report are
reproduced herein as received from Battelle Columbus Laboratories.
The opinions,  findings, and conclusions expressed are those of the
author and not necessarily those of the Environmental Protection Agency.
Mention of company or product names is not to be considered as an endorsement
by the Environmental Protection Agency.
                    Publication No. EPA-450/3-75-081
                                   il

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                                NOTICE
          The attached document is a DRAFT CONTRACTOR'S REPORT.  It
includes technical information and recommendations submitted by the
Contractor to the United States Environmental Protection Agency ("EPA")
regarding the subject industry.  It is being distributed for review and
comment only.  The report is not an official EPA publication and it has
not been reviewed by the Agency.

          The report, including the recommendations, will be undergoing
extensive review by EPA, Federal and State agencies, public interest
organizations, and other interested groups and persons during the coming
weeks.  The report and in particular the contractor's recommended standards
of performance are subject to change in any and all respects.

          The regulations to be published by EPA under Section 111 of the
Clean Air Act of 1970 will be based to a large extent on the report and the
comments received on it.  However, EPA will also consider additional
pertinent technical and economic information which is developed in the
course of review of this report by the public and within EPA.  Upon completion
of the review process, and prior to final promulgation of regulations, an
EPA report will be issued setting forth EPA's conclusions concerning the
subject industry and standards of performance for new stationary sources
applicable to such industry.  Judgments necessary to promulgation of
regulations under Section 111 of the Act, of course, remain the responsi-
bility of EPA.  Subject to these limitations, EPA ia making this draft
contractor's report available in order to encourage the widest possible
participation of interested persons in the decision making process at the
earliest possible time.

          The report shall have standing in any EPA proceeding or court
proceeding only to the extent that it represents the views of the Contractor
who studied the subject industry and prepared the information and recommendation.
It cannot be cited, referenced, or represented in any respect in any such
proceedings as a statement of EPA's views regarding the subject industry.
                                 ill

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                               ABSTRACT

          The U. S. oil and natural gas production and processing systems
are described.  The sources of sulfur emissions in these systems as well as
the current methods of control of such emissions are traced.  Fourteen major
and four minor processes for sweetening (removing H^S) sour gas, two processes
(Glaus and Stretford) for production of sulfur and six processes for tail
gas cleanup are described.  Some factors that may help choose a process for
a particular application are also indicated.  The location of 84 Glaus
sulfur production plants used in natural gas facilities, their design
capacity, and production data are tabulated.  The contribution of SCL
emissions from the natural gas processing industry to the national S0_
emission is compared and described.  Control options available for different
levels of hypothetical allowable sulfur emissions from the natural gas industry
are described.  This report was prepared for the Office of Air Quality
Planning and Standards of the U. S. Environmental Protection Agency,
Contract No. 68-02-0611, and submitted on July 29, 1974.
                                    IV

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                              TABLE  OF  CONTENTS
 LIST  OF  TABLES	viii

 LIST  OF  FIGURES	i  ix

 ACKNOWLEDGEMENTS	    x

 CONCLUSIONS	xi

 RECOMMENDATIONS	  .;  . '	 xiii

 INTRODUCTION	    1

      Objective	    2
      Methodology	    3

  I.   OIL AND NATURAL GAS  PRODUCTION AND PROCESSING SYSTEMS	    5

           Types  of Processing Facilities	    6
                Size Range of Gas  Processing Facilities	    7
           Detailed Description of Small, Intermediate  and
             Large Size Facilities	    9
                Description of Small and Intermediate Processing
                  Facilities	    9
                Description of Large Natural Gas  Processing
                  Facilities	13
                Sources of Sulfur  Emissions. .  . •	15

 II.   COMPOSITION OF NATURAL GAS AND REFINERY FUEL GASES  .......   18

           Composition of  Refinery Fuel Gas	18
           Comparison of Refinery  and Natural Gases	23

III.   MAJOR DESULFURIZATION PROCESSES IN OIL AND  GAS PROCESSING. .  .   24

           Gas Sweetening  Processes	   24
                Amine Processes	24
                Carbonate  Processes. .......  	   27
           Liquid Sweetening Processes 	  .  	   29
                Environmental Effects of Liquid Sweetening 	   29

 IV.   DESCRIPTION OF LESSER KNOWN  SULFUR (H2S)  REMOVAL  PROCESSES .  .   30

           Minor Desulfurization (H2S Removal Processes)  	   31
                Purisol Process	   34
                Iron Sponge (Oxide) Process	   34
                Fluor-Solvent Process	i  •	34
                Giammarco-Vetrocoke Sulfur Process 	   34

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                           TABLE OF CONTENTS (Continued)
            Level of Sulfur Compounds in Treated Natural Gas
              Attainable by Various Processes.	   35

   V.  COMPARATIVE DESCRIPTION OF SULFUR REMOVAL AND PRODUCTION
         PROCESSES IN NATURAL GAS AND REFINERY GASES .  . .	   38

            Factors in the Selection of H~S Removal Processes. ...   39
                 Solubility of Organic Components of the Fuel
                   Gas in Absorption Solvent 	 .....   39
                 Presence of Sulfur Species Other Than H-S in
                   Untreated Gas	   40
                 Required Degree of Removal of Sulfur Compounds.  .  .   40
                 Other Factors in Process Selection	   41
            Methods of Sulfur Production in Natural and
              Refinery Gas Applications	   41
                 Direct Vapor Phase Oxidation Principle	   41
                 Glaus Sulfur Plant Capacity VS Production Rate.  .  .   43
                 Sulfur Recovery by Liquid-Phase Absorption-
                   Oxidation. Principle	   45
            Tailgas Conditioning Processes 	   51

  VI.  ASSESSMENT OF SULFUR RECOVERY IN NATURAL GAS PROCESSING ...   53

            Listing of Sour Gas Processes in Texas	   58

 VII.  OVERALL ASSESSMENT AND RECOMMENDED CONTROL OPTIONS	   59

            Effect of Claus Plant Efficiency on S0_ Emissions. ...   59
            Control Options and Performance Standards.  ........   61
                 (A) Reinjection of Acid Gas to Well Formations.  .  .   62
                 (B) Use of Iron Oxide Process	; 66
                 (C) Use of the Molecular Sieve Process	,67
                 (D) Package Claus Plant	; 67
                 (E) Tail Gas Clean Up With Claus Plant	   67

VIII.  OPERATIONAL DATA FOR SELECTED PROCESS 	   69

           Data for Claus Plants	   71

  IX.  REFERENCES	   72
                                      VI

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                          TABLE OF CONTENTS (Continued)
                                   APPENDIX A

DETAILED DESCRIPTION OF MAJOR H S REMOVAL PROCESS IN OIL AND
  GAS PROCESSING	. .	.	A-l

                                   APPENDIX B

DETAILED DESCRIPTION OF MINOR (LESSER KNOWN) H2S REMOVAL PROCESSES. B-l

                                   APPENDIX C

DESCRIPTION OF SULFUR PRODUCTION PROCESSES.	C-l

                                   APPENDIX D

DESCRIPTION OF TAIL GAS CLEANUP PROCESSES	 D-l

                                   APPENDIX E

DETAILS OF PLANT AND FIELD VISITS AND SAMPLE OF QUESTIONNAIRE
  SENT OUT FOR SOLICITING INFORMATION	E-l

                                   APPENDIX F

LIST OF INDUSTRY AND OTHER PERSONNEL CONTACTED BY TELEPHONE AND
  VISITS.	F-l

                                   APPENDIX G

CONVERSION FACTORS	G-l

                                   APPENDIX H

HANDLING OF WASTE GAS WITH HIGH H S CONTENT	H-l


                                   APPENDIX I

LIST OF GLAUS PLANTS IN NATURAL GAS PROCESSING.	1-1

                                  APPENDIX J

TECHNICAL REPORT DATA SHEET	 	j_l
                                    vii

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                            LIST OF TABLES
TABLE 1.  CLASSIFICATION OF U.S. GAS PROCESSING FACILITIES
            BY STATE AND SIZE (JANUARY, 1973)	    8

TABLE 2.  COMPOSITION OF VARIOUS NATURAL GASES 	   19

TABLE 3.  COMPOSITION OF NATURAL GASES (1972-73 Data)	   20

TABLE 4.  SULFUR COMPOUNDS IN UNTREATED NATURAL GAS	   21

TABLE 5.  ANALYSES OF CATALYTIC CRACKER GAS	   22

TABLE 6.  SUMMARY OF MAJOR GAS AND LIQUID SWEETENING
            PROCESSES	   25

TABLE 7.  COMPARISON OF CIRCULATION RATES AND REBOILER STEAM
            RATES FOR VARIOUS TREATING PROCESSES 	   28

TABLE 8.  LISTING OF LESSER KNOWN GAS DESULFURIZATION
            PROCESSES	   32

TABLE 9.  APPROXIMATE LEVEL OF SULFUR COMPOUNDS IN TREATED
            NATURAL GAS WITH VARIOUS PROCESSES 	   36

TABLE 10. RECOMMENDED MAXIMUM CONCENTRATION OF SULFUR COM- .  .   .
            POUNDS IN NATURAL GAS SUPPLIED TO GAS TRANSMISSION  .
            SYSTEMS FROM NEW PROCESS PLANTS(a) 	   37

TABLE 11. SUMMARY OF CLAUS PLANT FIELD TESTS  	   46

TABLE 12. TYPICAL COMPOSITION OF STRETFORD PURGE SOLUTION. ...   49

TABLE 13. CLAUS PLANT TAIL-GAS TREATMENT PROCESSES 	   52

TABLE 14. NATURAL GAS AND LIQUID PROCESSING PLANTS REPORTING
            SULFUR RECOVERY	   54

TABLE 15. SALIENT DATA ON SULFUR RECOVERY IN NATURAL GAS
            PROCESSING	   56

TABLE 16. COMPARISON OF S02 EMISSIONS FROM ALL SOURCES  	   57

TABLE 17. ANALYSIS OF REPORTED DATA  (1973) ON NATURAL GAS
            PROCESSING PLANTS REPORTING SULFUR PRODUCTION. ...   60
TABLE 18. CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION
                         	•	   63
LEVEL "C",
TABLE 190  CONTROL OPTION-AT HYPOTHETICAL ALLOWABLE EMISSION
             LEVEL "B"	   64

                                   viii

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                       LIST OF TABLES (Continued)
TABLE 20.   CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION
             LEVEL "C"	65

TABLE 21.   OPERATIONAL DATA FOR TAIL GAS CLEANING PROCESSES. ...  70
                                LIST  OF  FIGURES
 FIGURE  1.   SCHEMATIC  OF  A  SMALL  (OR INTERMEDIATE)  GAS
            PROCESSING FACILITY	     10

 FIGURE  2.   TYPICAL  LARGE NATURAL GAS  PROCESSING  FACILITY   ...     14

 FIGURE  3.   DETAILED SCHEMATIC OF TYPICAL  SULFUR  RECOVERY
            (CLAUS)  PLANT	,     16

 FIGURE  4.   TREATMENT  OF  STRETFORD PROCESS PURGE  SOLUTION.  ...     50
                                    IX

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                            ACKNOWLEDGMENTS

          This report has benefitted from discussions with various oil
and gas industry personnel.  Mr.  Charles B. Sedman,  Task Officer,  U.  S.
EPA, has provided many useful suggestions for the study.   The critical review
of this report by Dr. Joseph M.  Genco,  Mr. G.  R. Smithson, Jr.,  and
Dr. James E. Flinn of Battelle Columbus Laboratories is  very much  appre-
ciated.
          Permission to reproduce process descriptions presented in
Appendixes A through D was kindly and quickly  granted by Mr. Frank L.
Evans, Editor, Hydrocarbon Processing,  Gulf Publishing Company,  Houston,
Texas, to whom sincere thanks are due.

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                              CONCLUSIONS

1.  The U.S. oil and natural gas industry operated 795 gas processing
    plants of various capacities with a total processed gas volume of
                                                           (a)
    1.6 billion scumd (56 billion scfd) as of January, 1973   .
2.  About two percent of the processed gas volume was handled in small
    plants with production less than 0.3 million scumd (10 MM scfd).
    However, the small plants numbered 206 (or 26 number percent).
3.  About 83 percent of the total processed gas volume was handled in
    plants larger than 1.13 scumd (40 MM scfd) in production volume.
                                                              (D*
4.  Reported gas volume associated with sulfur production data
    indicate that only about two percent of all natural gas processed
    was sour (i.e., contaminated with H.S    and other sulfur bearing
    compounds like COS, CS-, and RSH).  However, if plants that  do
    process sour gas but do not report sulfur production due to  flaring
    of the acid gas    are included, estimated sour gas volume may be
    about five percent of total gas production.
5.  The most widely used processes for removal of H.S and other  sulfur
    compounds from sour natural gas are the MEA, Sulfinol, DGA,
    Selexol and Benfield.  Most widely used process for production of
    sulfur from acid gases is the Glaus process*
6.  During 1973, there were 84 Glaus plants (detailed in Table 11) in
    natural gas processing with design capacities ranging from 1 to
    1250 MT/D of sulfur output.  The total design capacity was 6249
    MT/D while the reported actual production was 2443 MT/D as detailed
    in Table 15.  The number of plants with different capacities were
    as follows:  2 plants with up to 2 MT/D; 14 plants with 2 to 10
    MT/D; 34 plants with 41 to 600 MT/D; and one plant with 1250 MT/D.
    Estimated range of efficiencies of the plants is 90 to 97 percent.
(a)  Conversion factors are provided in Appendix G,
 *   References are listed on Page 71.
(b)  See footnote on Page 1 for explanation.
                                  XI

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 7.  If the maximum allowable emission limit (MAL) of sulfur per
     sulfur recovery unit (SRU) is limited at 1.0 MT/D, the 84 plants
     would emit 61,320 MT/Y of sulfur dioxide.  This quantity of SCL
     represents 0.18 percent of the national SO- emissions based on
     1972 data.  To achieve the 1.0 MT/D sulfur emission limit, at
     least 34 Glaus units or SRUs will be required to have conversion
     efficiencies in the range of 97.56 to 99.7 percent as described
     in Table 19.
 8.  If the MAL is raised to 2.0 MT/D of sulfur, the total SO  emis-
     sion will be 122,640 MT/Y which represents about 0.36 percent of the
     national S02 emission of 33 million MT/Y for 1972.  Thus, required
     efficiency of SRUs will be in the range of 95 to 99.6 percent
     for at least 34 units as detailed in Table 20.
 9.  Achieving the required  SRU efficiencies to meet the MAL of
     2.0 MT/D of sulfur is believed to require  a significantly lower
     expenditure of electrical energy (which,  therefore, is related to
     the national goal of energy resource conservation where possible)
     than the achievement of MAL of one MT/D of sulfur.  Capital and
     other operating costs of achieving the former may also be signifi-
     cantly lower.  The tradeoffs in environmental burdens to be
     considered as a consequence of decreased SO-  emissions from SRU
     are as follows:
        (a)  Increased SO- emission at power generating plants from
             increased electrical energy requirements
        (b)  Increased fine  particle emissions  at  power plants that
             escape the most advanced particulate  collectors like
             high efficiency electrostatic precipitators
        (c)  Any increase in water pollution and solid waste burden
             caused by SRU tail gas units
10.  Tail gas cleaning systems are available to increase sulfur recovery  of
     Glaus plants to 99.7 percent or higher.  Some experimental data are
     reported which support  the view that new Glaus plants can be designed
     and operated to obtain  99.3 percent efficiency.
                                   xn

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                            RECOMMENDATIONS

          On the basis of this study, it is recommended that:

1.  Consideration should be given to estimating any energy savings
    that may be realized by adopting a hypothetical allowable sulfur
    emission of 2.0 MT/D or 3.0 MT/D (see Tables 19 and 20) as compared
    to 1.0 MT/D or any other allowable sulfur emission level.
2.  Due consideration should be given to setting emission levels that
    would help to continue the existence and growth of energy supply
    from the small gas processing plants.
3.  Specific control equipment or control option should not be specified
    so that the optimum combination of options suitable for each processing
    facility can be chosen for each control category and allowable
    emission limit.
4.  The cost of various options for the different control categories be
    studied to help in understanding the control cost-benefit relationship.
5.  Evaluation should be made of the possibility of realizing improved
    Glaus plant efficiency of 98 percent and higher by exploring this
    aspect in depth and by considering the possibility of providing the
    needed lead time for the industry to evaluate this very desirable
    alternative.
                                  xill

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                  CHARACTERIZATION OF SULFUR RECOVERY
                   IN OIL AND NATURAL GAS PRODUCTION
                   (Contract No. 68-02-0611, Task 6)
                           Keshava S . Murthy
                             INTRODUCTION

          Production of petroleum (crude oil) is almost always associated
with production of substantial quantities of natural gas.  Production
wells are classified as gas wells when the ratio of gas to oil produced is
high.  When the oil-to-gas ratio is high, however, the production facility
is considered an oil well.  An arbitrary definition of a gas well is that
                                        (a\
it can product up to 31.8 kltr (200 bbl)v ' of oil per 28,000 cu m
(10  cu ft) of gas.  A higher oil-to-gas ratio in the production well could
place it in the oil well category.  These classifications are aribitrary
and are merely a convenience.
          The natural gas processing plant with the lowest gas production
reported'1) for 1973 had an output of 8400 cu m/day (0.3 x 10  cu ft per
day) in Texas (Ranchland Plant, Midland County); the highest plant through-
put was 52.7 x 10  cu m/day (1971 x 10° cu ft/day) also in Texas.
                                                                         (b)
          About five percent of the U. S. natural gas production is sour.
Consequently, treating to remove the acid gas'**) constituents is required.
 (a)  Metric System is used in this report and conversion factors are provided
     in Appendix G.
 (b)  Sour gas in industry jargon implies gas contaminated with sulfur in
     excess of pipeline specifications mainly in the form of hydrogen sulfide
     (H2S) and carbon dioxide (C02), both of which are also called the "acid
     gas" constituents of natural gas.  Many gas streams, however, particu-
     larly those in a refinery and manufactured gases may contain mer-
     captalns (RSH), carbon disulfide  (CS£) and/or carbonyl sulfide (COS).
     The latter three are often products of refinery processing and usually
     only appear in small concentrations in natural gas streams.

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The treatment process is usually designed for the product natural gas to
conform to the general pipeline specification o.f one quarter grain or one
grain of HgS per 100 standard cubic feet of gas.  The "quarter grain gas"
is equivalent to 4 parts per million by volume (ppmv) of E^S.*
          Pipeline gas specifications are known to range from 6 to 23 mg/s
cu m (0.25 to 1.0 grain/100 scf).  Pipeline companies' specifications for
other sulfur compounds in natural gas are not common.  However, the total
sulfur content of the gas is specified usually at 120 to 480 mg/s cu in (5
to 20 grains per 100 scf).
          Processes used for sweetening the sour gas are generally either
amine treatment processes or modifications thereof.  These are discussed in
this report.  Other processes used are the hot carbonate process, the
fluor solvent process, etc.  Depending upon the ratio of C0£ and H2S in the
feed gas, the acid gas from these processes may be rich in E^S.  The methods
of removal of the E^S and CO, from the natural gas and subsequent handling
or disposal of the HoS in an environmentally sound manner form the subject
of this report.

                               Objective

          The overall objective of this study (Task 6 under Contract No.
68-02-0611) is to assist the Office of Air Quality Planning and Standards,
Environmental Protection Agency in developing standards of performance for
sulfur removal and recovery associated with the production of oil and
natural gas.  The study is concerned with the identification of:  (1) sources
of sulfur emissions, (2) current methods of sulfur recovery, (3) potential
improved methods of sulfur recovery, and (4) efficiencies of sulfur recovery,
for gas processing facilities of small, intermediate, and large sizes.
From this information, recommendations for performance standards for the
three facility sizes are to be developed.  Specific subtasks to be completed
to achieve the overall objective are as follows.
* For a gas of 0.65 specific gravity the 4 ppm of H^S is equivalent to
  approximately 7 parts per million by weight (ppmwj.  In the metric system
  a quarter grain gas contains approximately 6 mg of H2S per standard
  cu m of gas.

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          (1)   Describe the oil and  gas  processing and production
               systems using typical example facilities.   Provide
               quantity and composition  of sulfur -constituents in the
               systems described.
          (2)   Describe lesser known or  novel sulfur removal processes
               used in oil and gas   fields with reasons for their choice.
               Provide quantity and  composition of sulfur constituents
               in the systems or processes described.
          (3)   Provide comparative description of natural gas and re-
               finery gas compositions and define similarities and
               differences in processing methods.
          (4)   Compare methods of  sulfur production from acid gases and
               tail gas conditioning processes.
          (5)   Provide statistical summary of sulfur recovery plants
               used in production and processing of oil and natural gas.
          (6)   Relate sulfur emissions from natural gas processing
               systems to overall national sulfur emissions.
          (7)   Provide operational details of selected oil and gas
               sweetening processes.
          (8)   Provide an overall assessment of the problems with suitable
               conclusions and recommendations.
                                Methodology
          Understanding the industry as thoroughly as possible can be
considered a prerequisite to the characterization of the problems and
methods of sulfur recovery in oil and gas processing areas.  Therefore
considerable effort was expended in the direction of familiarization
with the processing techniques by (a) field visits to processing units,
(b) discussions with process engineers and plant superintendent of
several production companies, (c) study of latest publications on

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the gas processing techniques, (d) contact with academicia, and (e) contact
with manufacturers of equipment for sulfur removal and recovery.  To obtain
insight into the Control philosophy of the state control agencies, discus-
sions were held with the state agencies in Texas, Louisiana, and Oklahoma
via telephone and visits as appropriate.
          The visits and discussions described above and listed in Appendix
E were useful.  The data and surveys reported in the Oil and Gas Journal
were a good starting point for approaching the industry base and classifying
the industry into size groups.  The Oil and Gas Journal Survey data for the
states of Louisiana and Texas were verified for completeness and accuracy
by direct contact with gas process engineers of several energy companies.
          The steps used in conducting this study to achieve the goals of
identifying control options can be summarized as follows:
          (1)  Survey open literature
          (2)  Visit processing facilities, meet industry personnel,
                                                            \
               and identify additional sources of useful and critical
               data
          (3)  Visit and/or discuss with state air-pollution control
               agencies their experience in the control of sulfurous
               emissions and related problems from oil and natural gas
               processing
          (A)  Analyze the problem in light of the above discussions,
               plant visits, and open literature survey
          (5)  Apply the results of analyses to preparation of draft
               final report
          (6)  Obtain review of the draft document from EPA
          (7)  Prepare final report.

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         I.  OIL AND NATURAL-GAS PRODUCTION AND PROCESSING SYSTEMS

          Petroleum is a complex mixture of low- and high-volatile organic
compounds.  Most of the less-volatile compounds (pentane and higher carbon
compounds) can be considered to comprise the oil portion while the more-
volatile compounds such as methane, ethane, and some propane are predomi-
nantly in the natural-gas portion of petroleum.  Butanes which have boiling
points ranging from -11.7 to -0.56 C (11 to 31 F)  occur in both the gas and
oil fractions in substantial amounts.
          Because the oil and gas occur together in the reservoir, field
facilities for oil and gas processing usually handle both oil and gas.
Usually the field processing of the oil is limited to its physical separa-
tion from the gas; the separated oil is not generally subject to further
processing in the field but is delivered to refineries for processing into
various products.  Therefore, this report is concerned primarily with the
processing of natural gas only.
          Depending on the well output, producing and natural-gas processing
facilities can be classified into small, intermediate, and large sizes.  An
arbitrary size classification is presented below:

                                       Gas Production
              Size Range     Million scf/day    Million cu m/day
             Small            0.5 to 9            Up to 0.3
             Intermediate     9.1 to 40           0.3 to 1.13
             Large            40.1 to 1971*       1.13 to 51.0

          Natural gas dissolved in the crude oil underground acts as a buoy-
ant medium for conveying the oil to the surface in the "Dissolved-Gas-Drive"
method of production.  Usually the oil production ranges from six to several
hundred kiloliters per MMscum (10 to several hundred barrels per million
cubic foot) of gas produced.
* Largest reported facility.

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          Most oil and gas wells produce at the highest rates during  the
initial period of production.  Since the production rate usually decreases
with the age of the well, a  large processing facility would normally  have
then become intermediate-sized, then small-sized, and finally shut down.
However, there are numerous  small gas and oil wells that are operated on
a part-time basis by ranch hands.

                       Types of Processing Facilities

          The facility type  is a function of production capacity and  the
constituents present in the  oil and gas.  For example, if the gas volume is
in the intermediate range and the gas has significant amounts of propanes
and butanes (NGL components), the facility would be more complex than a
simple gas-treating facility.  Similarly, if the gas is sweet (free of H2S
as >90 percent of all gas wells are) and does not contain recoverable amounts
of heavier hydrocarbons, the facility will be very simple in that the gas
after water removal is sold  directly to pipeline companies.
          An example of a complex facility is the Bryans Mill Gas Processing
Plant at Bryans Mill, Texas, operated by Shell Oil Company.  This plant
produces about 1.42 million  a cu m/day  (50 MM scf/day) of gas associated
with about 1590 kltr (100,000 bbl) of oil per day.  The Glaus unit pro-
duces 203 MT/day of sulfur (200 LT/day).  The gas from this plant is  recom-
                          2
pressed to about 253 Kg/cm   (3600 psi)  of pressure and reinjected to  maintain
sufficient reservoir pressure.  One of the purposes of the facility is to
produce sulfur which has a ready market in this area.   This facility  is not
typical in that almost all of the gas produced is recompressed and reinjected
into the reservoir.  The facility operates as a secondary oil-recovery opera-
tion and uses refrigerated absorption to produce 188 kiloliters (47,000 gal-
lons) of liquid propane and  235 kl (62,000 gallons) of combined gasoline/LP
gas per day.
          Other facilities produce gas  for sales, LPG (propane and butanes),
natural-gas liquids, and crude oil.

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Size Range of Gas Processing Facilities

          The Oil and Gas Journal Annual Survey for 1973 indicated that
during 1972, a total of 795 gas processing facilities in the U.S. produced
1.606 billion cu m (56.7 billion cubic feet) per day of natural gas,  and
295610 kltr  (78.1 million gallons) per day of natural gas liquids.  The
sulfur production per day was ~ 2480 MT/D (2445 long tons/day).
          The 795 gas-processing facilities were fed by about 120,000 indi-
vidual gas/oil wells, each facility processing on the average the output
from about 10 wells..  The size of the 795 facilities ranged'from 8400 cu m
(0.3 million eft) to 52.7 million cu m (1971 million eft) per day.  Table 1
provides detailed size classification of the processing plants by state for
the 24 states in which gas-processing facilities are reported to exist.  Al-
though the survey reports that industry response to the questionnarie by the
Oil and Gas Journal was substantially 100%, it is quite possible that some
small gas processors who flare or emit H?S as-is from their amine treatment
units may not have responded.  By and large, the data in Table 1 provide a
relatively complete picture of the industry.  A summary of the data is tabu-
lated below.

         Size Range         Number of Plants       Total Production
           MMscfd
         0.5 to 9.0
         9.1 to 40
         40.1 to 1800
        .Total

          The data show significantly that although the plants in the small
size range amount to 26. number percent of the facilities, only 1.9 of the
total U.S. gas plant capacity is in this size range.  It is also significant
that as of January, 1973, 82.7 percent of gas production and processing was
done in the large size range plants.
Number
206
319
270
795
Percent
26%
40%
34%
100
MMscfd
1046.6
8798.4
46942
56787
Percent
1.9
15.4
82.7
100

-------
                       TABLE 1.  CLASSIFICATION OF U.S. GAS PROCESSING FACILITIES BT STATE AND  SIZE  (JANUARY,  1973)

0.5 to 9.0 MMscfd
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
North Dakota
Oklahoma
Pennsylvania
S. Dakota
Texas
Utah
W. Virginia
Wyoming
1*«%*«.1
Tocal
Number
of Gas
Plants
1
2
1
3
49
12
10
1
29
2
132
5
10
4
2
36
3
86
2
1
369
4
4
27
795
Gas Production
Per Day
MMscmnd**
0.034
0.92
0.057
2.41
24.92
10.11
22.09
14.73
136.47
22.37
553.57
3.12
2.61
0.85
0.34
88.78
2.80
95.52
0.093
0.71
590.56
3.43
7.56
24.16
1608.21
MMscfd
1.2
32.5
2.0
85
880
357
780
520
4,819
790
19,547
110
92
30
12
3,135
99
3,373
3.3
25
20,853
121
267
853
56,787
Number
of
Plants
1
1
1
1
21
6


5

20
1
7
3
2
4
1
23
2

93
1

13
206
MMscumd
0.034
0.14
0.057.
0.76
4.02
1.02


0.79

2.29
0.028
1.076
0.283
0.34
0.51
0.24
5.66
0.093

11.33
0.17

1.47
29.64
9.1 to 40 MMscfd
Total Number
Production of
MMscfd Plants
1.2
4.9
2.0
2.7
142
36


28

81
1.0
38
10
12
18
8.5
200
3.3

400
6

52
1,046.6
_ '
1

2
23
5
9*

9

37
3
3
1

10
1
35

1
167
2
2
8
319
MMscumd

0.78

2.33
11.55
1.87
3.68

5.41

18.21
1.78
1.53
0.57

3.40
0.44
30.02

0.71
160.74
1.02
0.99
4.22
249.17
40.1 to 800 MMscfd
Total Number
Production of
MMscfd Plants

27.6

82.3
408
66
130

191

640
63
54
20

120
15.5
1,060

25
5,676
36
35
149
8,798.4




5
1
1
1
15
2
75
1



22
1
28


109
1
2
6
270
MMscumd




9.35
7.22
18.41
14.73
'130.27
22.37
533.15
1.30



84.88
2.12
59.84


418.48
2.24
6.57
18.46
1329.4
Total
Production
MMscfd




330
255
650
520
4,600
790
18,826
46



2,997
75
2,113


14,777
79
232
652
46,942

'* 137. H2S.
** MMscumd - million standard cubtc meters per day.

-------
             Derailed Description of Small, Intermediate
                      and Large Size Facilities

          Distinctions between small and large facilities are not very
useful because the unit processes used in a particular facility do not
depend on the plant size but on the gas composition.  Accordingly, if the
gas is sour (523 milligrams per s cu m) and rich (or wet i.e. containing
>1.34 liters of liquids per s cu m of gas), even the smallest facility will
be forced to use a gas sweetening process and a liquid recovery unit.  On
the other hand if large quantities of sweet gases are produced, as 90% of
the gas wells do, even large plants processing more than one billion cubic
feet daily do not use sweetening units.
          However, one important difference between small and large plants
processing sour gas is in the area of sulfur recovery from acid gases.
Usually, if the volume of acid gas generated is insufficient to produce
enough sulfur (~2  MT per day) , small plants flare the acid gas instead of
recovering the sulfur.  The large plants usually practice sulfur recovery
because  of the large volume of acid gas they generate and the consequent
sulfur value contained in the acid gas.

Description of Small and Intermediate Processing Facilities

          A schematic block diagram of typical gas-processing facilities in
this size range is presented in Figure 1.  The facility represented here can
handle both sweet and sour gas.  A very small facility would only employ
processes (1), (3), (A), (6), and (8) identified in the figure.  The
description of the process steps and associated environmental burdens follow.

          Stage Separation (1).*  Gas from the wells enters the stage sepa-
rators where the oil is separated from the gas and the pressure of the gas
is reduced from about 150 atm to pipeline requirements, usually about 70 atm.
 * Number  refers  to block  number  in  Figure  1.

-------
                        Sweet and dry gas direct to sales
    Sales gas
1
1
Gas from wells Stage _
under high pressure *" separators
u.
O
•*-
'o
TJ
0)
"5
UJ
1
1
1
fl
+ 1
ol
Til
•-I
v5i
|
I
L
••»>

Amine .
treatment
unit
1
Amine
regeneral
unit

4
or



/


	 1
^ Dehy^ajion6 ^as ^
1 unit ^^metering^
\ 	 ^
— Hydrocarbon

*" Unit
(If no S recovery)
(h^S + COg) | r»rnu<»ru Tail gOS
unit
Crude oil
1 »
2
Central
unit (station)
Deemulsifying
unit
(heat or
electricity)
9
,- . ., LACT
Crude oil d f h
battery
)
(drocarbons
To flare
8
Tail gas
incinerator

Oil pipe line

                                        Water phase to formation
   LEGEND

O ATMOSPHERIC EMISSIONS
A LIQUID
FIGURE  I.  SCHEMATIC  OF A SMALL (OR INTERMEDIATE)  GAS PROCESSING FACILITY

-------
                                     11
The oil is then flashed in several stages to insure maximum oil recovery.and
the flash vapors are recompressed to pipeline pressure.                 ^-
          Products from this process step are,  (1) sour or sweet gas and
(2) crude oil.  If the gas is sweet and dry  (free of water), it is sold to
                                                  / rt \
pipe line companies via the sales metering station (8). If the gas is sour,
it is routed to step (3) which is described later.  Similarly, the crude
petroleum oil is sent to step (2) or step (9) as shown in H-gure 1.   This
process produces .no environmental burdens.

          Central Treating Unit  (2)_.  When the  crude oil  from step  (1) is an
emulsified mixture of oil and water it is pumped to a central treating
facility.  De-emulsifying treatment followed here is described in step (5).

          Amine Treatment (3).  Amine treatment removes the undesirable H^S
(and CO ) from the sour gas produced in step  (1) stage separators.  The more
common amine  treatment processes currently in use are:  the luonoethanol  amine
(MEA) process, the Shell sulfinol process, the  Diethanol  amine  (DBA) process,
and the Econamine process.  Details of these processes are discussed elsewhere
in this report.  These processes are usually carried out  at high pressures.
The process produces "quarter-grain" to one-grain gas which is  equivalent  to
about 4 to  16 ppm H_S by volume.
          There  are no environmental burdens  from this process  step.

          Amine  Regenerator  (4).  The spent  amine solution  in  step  (3)  is
continuously  regenerated in  an  amine regenerator.  Usually  the  process  in-
volves warming of  the solution  plus stripping to  desorb  the H^S and CCL.
          The process produces  H S and CO which  are  the  major  components  of
the "acid gas".  Generally the  acid gas  is  fed  to a  sulfur  recovery plant.
          The major environmental burden  from the regenerator  is H  S.   If
the acid  gas  is  not processed to recover  sulfur,  it  is  flared,  which results
in emission of sulfur dioxide to the atmosphere.

          De-emulsifying Process (5).  Treatment  of  the  oil-water emulsion
is necessary  whenever the  stage separation  process  step  (1)  generates  an
emulsified  crude oil-water mixture.  The  most common methods  of emulsion

-------
                                    12

 treating use chemicals or heat, or both.  The kind of  treating method  is  de-
 termined by the characteristics of the emulsion.  The  treatment  is  normally
 done with a "heater", or "heater-treater".  The heat is supplied by means
 of a burner which uses either gas or  fuel oil; and if  chemicals  are used,
 they are injected in  small quantities by pumps like those  used for  corrosion
 treating.  A great variety of chemicals are used  for this  purpose,  but
 no one material has proved effective  for all emulsions.
          After being heated and/or chemically treated, the  emulsion is
 allowed to enter a tank where the water can separate from  the oil.  The
 separated liquids are then drawn off-the oil going to  the  stock  tanks,
 and the water going to the disposal system.  Recently  the  use of electrical
 currents to break emulsions is gaining acceptance.
          Major environmental burden  is salt water separated in  the process.
 The water is returned to well formations; when this is not feasible, water
 treatment is employed so that the discharged water is  accepted without
 endangering the safety of the waterways.

          Dehydration (6).  Sweet gas from the amine treatment units is con-
 taminated with water vapor.  Removal  of this water vapor is usually done by
 using triethylene glycol (TEG),  an alcohol which can absorb only the water
 very effectively.
          Product from this process is dry natural gas ready for sale.  There
 are no environmental burdens from this process.

          Sulfur Recovery (7).   Acid  gas from the amine regenerator step  (A)
 is often rich in H.S and by suitable  processing,  is converted to pure ele-
mental sulfur* in this process.   The most common sulfur-recovery process em-
 ployed is the modified Claus Process which has a recovery efficiency limit
 of 90-97 percent.
          Product from this process is pure sulfur.
          The major environmental burden of this  process is a tail  gas from
 the plant which contains about 3 to 4 percent H..S in the feed.

          Tail-Gas Incineration  (8).   Unconverted H S,  sulfur vapors,  and
 other sulfur compounds from the  Claus  sulfur plant are burned to sulfur
    Sulfur purity exceeds 99.5 percent.

-------
                                     13
dioxide (SCL) In this unit.  Fuel for combustion is provided by plant
»as or by flash vapors and vapor from sour water strippers (if there are any).
          This step is the major contributor to environmental burden.  The
emission of S0« to ambient air is the major problem of Claus plants.  This
is discussed in detail in other sections of this report.

          LACT* Crude Tank Battery  (9).  This  system provides  for  the
 unattended  transfer of  the oil (or  gas)  from the lease to the  pipelines.
 The  oil storage  tanks in this system are under a positive pressure.  When
 no vapor recovery system is  installed,  a small amount of hydrocarbon vapor
 contaminated with H?S (if the oil is sour)  is  lost to ambient  air.
           Environmental burden from this unit  consists of loss of  H~S
 and  Hydrocarbons  as vapors from oil tanks.   The emissions are  not  signifi-
 cant however. Most of  the new tanks are equipped with vapor recovery
 units, thus reducing the emissions  to near zero.

 Description of Large Natural Gas Processing Facilities

           The essential differences between large processing installations
 and  the smaller  facilities are as  follows.
          (1)  The  large  facilities  can often  justify a  sulfur-recovery
               plant with recovery efficiencies  of up to  97 percent.
               This implies  that three recovery  stages will be used in
               the  Claus  plant.
          (2)  Large units are more  likely  to  have hydrocarbon recovery
               plants that produce  liquid propane, liquid butanes, and
               gasoline-blending cuts.
          A schematic of  a typical  large facility  is presented in Figure 2.
This plant  produces crude oil with  a Reid Vapor  Pressure  (RVP) of 8 psi
 (about  0.5  atm) ,  sales  gas,  propane, butanes,  natural gasoline, and elemental
sulfur.
          Figure  3  provides  a  detailed flow scheme of just the sulfur-
recovery plant shown  in Figure  2.
*.Lease Automatic Custory Transfer.

-------
!  i
i  i
            iRECOMPRESSOR
         i  !
         .  } CONDENSATE
H
            STABILIZATIOiM

           j JPLANT
                    8° RVP

                  CONDENSATEJO—5

                    STORAGE
                                                      GLYCOL

                                                   DE H YD R ATI ON

                                                       UNIT
                                          V
                                  O4
                                  o
                                  O
                                  
   j  | __ BUTANE. _____ ^
   {_=____G^S01:jNE ____
                                                                                LIQUID Ss LOADING

                                                                            BLOCK S6


                                                                            STORAGE
                         FIGURE 2o  TYPICAL LARGE NATURAL GAS  PROCESSING FACILITY

-------
                                     15
          Both Figures 2 and 3 are self-explanatory.  However, the sources
of US and SO  emissions need discussion.
                                                                         '*>
Sources of Sulfur Emissions
          The sources are:  (1) the tail gas from the Glaus plant final
sulfur separator, (2) the salt-water flash tank, and (3) the salt-water
stripper.

          Tail Gas from Glaus Plant.  The quantity of H S present in the
tail gas depends on the following factors:  (1) the H S in Glaus plant feed,
(2) the conversion efficiency of the plant which is a function of the number
of stages of sulfur reactors, (3) degree of precision in the control of the
temperature in the Glaus plant burners, and (4) the instrumentation employed
in controlling the plant-operating conditions.
                        (2)
          Rankine, et al    predict that theoretical thermodynamic recoveries
from a four-stage Glaus plant, processing a feed containing 67 percent hydrogen
sulfide, to be as follows:
               2 catalytic stage recovery  97.9 percent
               3 catalytic stage recovery  99.1 percent
               A catalytic stage recovery  99.4 percent.
          However, actual yields of sulfur in existing plants has been about
90 to 97 percent.  This leaves about 3 to 10 percent of the feed H S in the
tail gas.

          S aIt-Water Flash .Tank.  A considerable quantity of salt water (also
called sour water if dissolved H S is present) is produced from oil-water
separators.  One plant reports a salt-water production of one percent by
volume of the oil production  (one liter/100 liters of oil) and on the basis
of gas production, 4.63 kiloliters of salt water/million cu m of gas pro-
duced.  These statistics are not typical because salt-water production ranges
from 1 to as much as 99 percent of total well output.  Reported H S content of
sour waters also varies, a typical value being 0.5 gram/liter of sour water.
          Dispos.il of the sour water requires that the H_S in it be stripped.
This is accomplished in flas|) tanks and strippers.  Because the sour-water

-------











Acid
gas
from
j


0^

















N
—
X1
Air blower


3Z2(


^




regent-"'
erator













Sulfur
1





•

/
Waste heat \>»/
furnace ^X'v



plant
	 N,
\





j~-
\
\
*•»
,
Water



.!





— v,
/
/
,**
'


No. 1
r




\
\ 	 |
^





eheat burner




No. 1


i







/
\
' No. 2, No.3.X
"1
• -$

\ burner + ) ^^





J No. 1 sulfur
' reactor
-




Steam








Sulfur


\




y,

i
\



f —
\
•»>_
i
Water



i
— ^
— ;
}



s
'


")
)

reactors t
1 j ,
! s
.1
!^_



r* ^
il
\
Steam


	 t Sulfur Sulfur












I
Liquid to
OEA line










































(




Sulfur'

H2S
1^^






Heater



/ '
H2S-r-SOz
\

suirur
separator


S





+ HC

n
! |
-J
—a







i
•• Incinerator^/ \..
* . 17 \
A
1 	 Fuel Gos


^;


'
H 2S + HC


.
'^ N\

\

1
^3 n
3 -2 •ACtsr
0) w
f\i O
Salt water stripper
«H "T ~"

FIGURE 3.  DETAILED  SCHEMATIC OF SULFUR RECOVERY (GLAUS) PLANT

-------
                                     17
stripper gas contains some amounts of hydrocarbons (HC), the gases are often
fed to the Glaus tail-gas incinerator.  It is not known if this practice is
followed by all processing plants..
          It is possible to compress the gas from the stripper or operate
the sour-water stripper at about 0.5 atmospheres (-7.5 psig)  so that  the gases
can b.e fed to the Glaus plant.  However, if the hydrocarbon content of the
gas is high, removal of heavy hydrocarbons will be necessary to insure that
the purity and color of the Glaus plant sulfur is maintained.

          Emission Sources of Other Sulfur Compounds.  The natural gas
industry is predominantly concerned with ELS as an undesirable constituent
in natural gas.  However, other organic sulfur compounds that can be present
in both raw and processed natural gas are: mercaptans  (RSH), carbonyl sulfide
(COS) and carbon disulfide (CS«).  Some of the sweetening processes are
more effective in removal of these other sulfur compounds.  There is also
        (3)
evidence    that undesirable side reactions in a Glaus plant tend to form
COS and CS~.  It is estimated that as much as 2 percent of the sulfur in the
feed might be converted to organic sulfur compounds, and that this might
                                                          (A)
account for 40 percent of the S0» in the incinerated gases   .
          In summary, although COS and CS9 can be formed in a Glaus plant,
                                         *
their exact source (point location) is difficult to identify.  However,
these compounds end up in the tail gas.  Also the raw gas can contain
significant amounts of COS, and RSH as shown in Table 7.  The CS? content
of natural sour gases is very low.  By a judicious selection of the sweet-
ening process, up to 90 percent of these compounds can be taken out of the
natural gas.  However the acid gas will concentrate the organic sulfur
compounds and when fed to the Claus plant, these compounds constitute
emissions in the tail gas.  Recently, catalysts (example Cobalt-Molybdynum)
to hydrolyze COS and CS  to H,?S and C02 have been identified    .  It                  j;!;-
appears possible that improved catalysts can reduce unconverted CS0 and COS           if.*
                                                                                      m
concentrations in the tail gas and hence the SO,, emission in  the incineration         P
                                                                                       vi
of gases.                                                                             |P''
                                                                                      K
                                                                                      H

-------
                                  18

          II.  COMPOSITION OF NATURAL..GAS...AND. REFINERY _FIJKL-CASES

          The U.S. Bureau of Mines  reports    that as of December  31,  1972,
there were  1.2.1,153 producing wells  for gas and condensates  in  the  United
States.  These wells were distributed over 30 states.  Generally,  the
composition of gas from  these wells varies from well to well.  However
for processing purposes  they must be grouped.  Thus, sour and  sweet  is
one type of grouping, and, rich  (or wet) and dry gas is another  type of
grouping.  Both groupings are necessary and significant.  Sour gas contains
considerably more than 2.29 grams/100 s cu m  (1 grain of H£S per 100 scf)
and must be sweetened by amine or other processing methods  described in
Appendix A.  Rich gas is gas containing more than 1.34 litres  of liquid
components  (propane and higher-boiling compounds) per s cu  m of  gas  (10
gallons/1000 s cu ft).  Dry gas  usually contains less than  0.5 gallons of
propane plus compounds per 1000  eft and hence, recovery of  natural-gas
liquids (NGL) from dry gas is usually not economically warranted.  Natural
gas exists at high pressures (20 atm and above) which helps in amine treat-
ment.  Also, because most natural gases are free of very heavy hydrocarbons,
aromatics, and olefins, the treatment of acid gas to produce bright  yellow
sulfur in a Glaus unit is much easier.  Composition of various samples of
natural gases are presented in Tables 2 and 3.  Detailed analyses  of sulfur
compounds in natural gas are presented in Table 4.

                   Composition of Refinery Fuel Gas

          Refinery fuel gases originate in the refinery from many  cracking
and catalytic processes.  Examples  of gas producing processing are:
thermal cracking, catalytic cracking, sour water stripping, topping,
hydrotreating, etc.  Gases from  these processes usually are contaminated
with H.S.   Typical analyses of refinery fuel gases are not available because
most refineries do not record the analyses of the fuel gases except  for
their H-S content when H^S removal  is employed.   Thus,  data on the
concentrations of mercaptans and COS in refinery gases are difficult to
obtain although industry experts claim that the concentration  of these
gases in refinery fuels is generally higher than in most natural gas
streams.

-------
                        19
TABLE 2.   COMPOSITION OK VARIOUS NATURAL
                                          ,;A^<«>
....
Composition, mole %, of gas from

Component
Methane
Ethane
^r.opahe.
Butanes'
Pentanes and
heavier
•Carbon
dioxide
Hydrogen
sulfide
Nitrogen
Helium
- 'Total
To'tal sulfur, „
grains/100 ft
Classification
wet
dry
sweet
sour
Gross heating
value,-
Btu/ft
Specific
gravity
Rio
Arriba
County,
N.M.
96.91
1.33
0.19
0.05

0.02

0.82

0.68
100.00
0

X
X

1,010
0.574

Terrell
County ,
Texas
45.64
0.21




53.93
0.01
0.21
100 . 00
6.3

X

X
466
•1.0777

Stanton
County,
Kansas
67.56
6.23
3.18
1.42

0.40

0.07

21.14
100.00
0

X
X

938
0.733

San Juan
County,
N.M.
77.28
11.18
5.83
2.34

1.18

0.80

1.39
100.00
0
• X

X

1,258
0.741
Olds
Field,
Alberta,
Canada
52.34
0.41
0.14
0.16

0.41

8.22
35.79
2.53
100.00
22,525

X

X
807
0.882
Cliffside
Field,
Amarillo,
Texas
65.8
3.8
1.7
0.8

0.5



25.6
1.8
100.00


X
X

825
0.711

-------
                                  20
     TABLE 3.   COMPOSITION OF NATURAL GASES* (1972-73 Data) - Mole %


Carbon dioxide
Nitrogen
Hydrogensulfide
Methane
Ethane
Propane
Isobutane
N-butane
Iso-pentane
Gas Gas
Sample Sample
No . 1 No . 2
43.40 1.27
0.50 0.94
0.01 0.37
56.00 91.16
0.09 4.05
0 1.20
0 0.13
0 . 0.36
0 0.10
Gas
Sample
No. 5
4.4
. 8.7
10.6
59.93
7.7
4.1
1.3
2.1
0.6
Gas
Sample
No. 6
1.6
1.6
0.6
83.5
8.0
3.3
0.3
0.8
0.1
N-pentane
  and heavier                    0           0.42       0.6        0.2


Total                         100.00       100.00     100.00     100.00
  Btu/cft                     570         1060

Total sulfur gr/100 cu  ft.      10          200          NA

Specific gravity                0.975        0.622
* These data were reported by AMOCO, Shell and Exxon in response to BCL
  requests.  However, it should be noted that there are wells in the U.S,
  and Canada that contain greater than 50 percent H S by volume.

-------
                                TABLE 4.   SULFUR COMPOUNDS IN UNTREATED NATURAL GAS

Sulfurous
Components
Hydrogen suifide (H_S)
ppmv of H_S
Mercaptans (RSH) •
Sulfides (COS etc)
Residual suifide (S)
Total sulfur
C02 (mole %)
Gas Sample 1
grams*/
100 s cu m
153
1044
21
7
4
185
1.5
Gas Sample 2
grams/
100 s cu m
76
519
14
5
2
97
0.71
Gas Sample 3
grams/
100 s cu m
2
14
0.12
0.04
0.01
2.17
2.42
Gas Sample 4
grams/
100 s cu m
24,905
170,026**
627**
188
105
25,825
NA
Gas Sample 5
grams/
100 s cu m
29,213
199,437**
735**
220
121
30,289
NA
Gas Sample 6
grams/
100 s cu m
21,369
146,000**
973**
893
146
23,381
NA

*  Multiply given values by 0.43665 to obtain grains/100 scf.

** Such high concentrations are not common in natural gas streams.  These concentrations of sulfur compound
   definitely are much higher than those of refinery fuel gas.  As pointed out elsewhere, about 2 percent of
   U.S. natural gas is sour and less than 2 to 3 percent of the sour gases contain high sulfur compound
   levels presented in this table.

(Source:  Mr. Neal, Petroleum Analytical Laboratory Service,  Odessa, Texas)

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                       22
   TABLE 5.   ANALYSES OF CATALYTIC CRACKER GAS*

Mole %
Carbon dioxide
Hydrogen sulfide
Carbonyl sulfide
Hydrogen
Methane
Ethane and heavier
Water
Temperature C (F)
Pressure, atmospheres (PSIG)
1.24
6.38
•
44.86
32.17
14.35
1.00
60 (140)
5.5 (80)

* Not a typical analyses.   See text,  page 18.

 (Source:  Official Communication dated January 4, 1972
 from David C. Parnell, Chief Process Engineer, Ford,
 Bacon and Davis Texas Inc., to Richard K. Burr, U.S.
 EPA, RTF, NC 27711)

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                                  23
            Comparison of Refinery and Natural Gases

          The most imporCant differences related to the design of sulfur
recovery units from the two gases are
          (1)  Presence of heavy hydrocarbons including aromatics
               in the refinery gases which tends to form a somewhat
               black sulfur instead of the more readily marketable
               yellow sulfur in the sulfur recovery step.
          (2)  The refinery gases are usually at atmospheric pressure
               and higher than ambient temperature.  Natural gas is
               at higher pressure (>25 atm. depending on the stages
               of separation) and a lower temperature.  These factors
               contribute to the ease of processing natural gas during
               the ELS removal step.  The absence of heavy hydrocarbons
               in natural gas helps in recovering pure yellow sulfur.
          (3)  Other differences are that refinery gases contain cracked
               products (gum-forming olefins) and are more likely to
               contain sulfur compounds like carbbnyl sulfide, mereap-
               tans, etc., as discussed on page 18.
          To generalize on these differences and summarize how they affect
the design of sweetening and sulfur-recovery units is not practical because
there are far too many variables involved in the design.  However, it cannot
be too strongly emphasized that design of treatment units for refinery gases
requires more careful tailoring to individual gas compositions.  This is not
to imply that design of natural-gas treatment units is highly standardized.

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                                  24
       Til.  MAJOR DESULFURIZATION PROCESSES IN'OIL AND GAS PROCESSING

          The natural gas Industry has to sweeten (remove H»S from) both
the gas and sometimes the liquified gases such as propanes, butanes, etc.
Available sweetening p.rocesses employ physical, chemical and a combination
of separation techniques.  Thus, a confusing array of gas and liquid
sweetening processes is in use.  These are discussed below under two
headings: (1) gas sweetening processes and (2) liquid sweetening processes.

                        Gas Sweetening Processes*

          These can be grouped under five types:  (1) the Amine Processes,
(2) the New Amine Processes, (3) Carbonate Processes, (4) Physical Absorption
Methods, and (5) Solid-Bed Sweetening Processes.  Most of these processes
remove both the H S and C0? from the natural gas to produce an "acid gas"
rich in H?S and C0_.  Further processing of this acid gas is necessary to
produce sulfur.   This is discussed under sulfur production processes.
          Also, processes that combine H_S removal and direct sulfur pro-
duction are used selectively.  Examples of such processes are the Stretford
process used in the U.S. and the Giammarco-Vetricoke Process (GV) in use
primarily in Europe.
          A summary of the essential features of all these processes Is
presented in Table 6.  A brief discussion of each process type follows.
Detailed discussion and flow diagrams are presented in Appendices A, B and C.

Amine Processes (Including New Amine Processes)

          Although at least five different types of amine processes have been
developed, only three (MEA, DEA, and sulfinol) have gained wide usage in the
industry.  Of these processes, the MEA and DEA  (used chiefly in refineries),
are two of the oldest gas-sweetening processes which are still used in over
300 installations.
* There is considerable overlap in processes used for gas and liquid sweetening.

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                                                                                                  TABU 6  .   SUMUIV OF MAJOI GAI
ffroee.lt Conditions
Process Name
(Process Applicability)
Te»p.,
Process Mechanism C
Prassuri,
atm
Solution
Concentration,
percent Regeneration
Product
Torm
Amtna Processes
  Konoethanolamlne (HEA)


  Dlethanolamlne (DEA)
 Now Amtng  Processes
  Dlglycolani.no (DGA) or
    Flour  Econamlne (sour
    Sat
  Shell sulflnol  (gas and
    liquid sweetening)
                               Liquid chemical absorp-
                                 tion (acid-base
                                 reaction)
                               Liquid chemical absorp-
                                 tion In an aqueoul
                                 oolutlon
                               Improved liquid chemi-
                                 cal absorption with
                                 alkanolamlne

                               Liquid chemical absorp-
                                 tion plus physical
                                 solution of HjS In
                                 sulfolane
30-55       1-70       15-20% In water   In a steam strip:     H.8  gas
                                           per column

30-55       1-70       15-20% In water   By steam stripping   J^S  gas
                                                           30-55
30-50
                                                                       1-70
            1-80
                       Up to 60S In
                         water
                                                                                                    Yes
                       Highly variable   Yes
                                                                                                                             gas
                                                                  gas
   SNPA-OEA
   Soctote Rationale das
     Petroles d'Aqultnlno
     (sour gan)

   Shell ADIP (Gae and
     liquid sweetening,
     mostly In refineries)
                               Same as DEA process but     30-55
                                 the DEA concentration
                                 Is high' In this Im-
                                 proved version
                               Regenerative abtiorption     25-40
                                 In aqueous so).vont
                                 amlne (dllsopropanol
                                 amlne)
                                                                      1-70       20-30% In water   Yes                  R,S  gas
            1-80       25 to 30% In      Pressure reduc-      H..S gas
                         water             tlon plus
                                           stripping
 Carbonate Processes
   Benfleld (Benson and
     field Invention)
   Benfleld Corporation,
     Pittsburgh Pa.
   (Natural and synthesis
     gas)
   Catacarb (sour gas)
Physical Absorption
                               Activated  (promoted)
                                 hot K     process
                                Catalyzed hot K;jCO3
                                Proccea with corrosion
                                  Inhibitor
  Selexol  (Allied ChaalcQls)  Pftyotcal absorption of
     (gaa and liquid
     sweetening)
  Rectlsol
  Lurgl Mineralolcechnlk
    GMbH
     (syngas)
002 a»d HjS In di-
methyl ether of
polyethylene elycol
(DMPBO)
                                                           25-200
                                                           55-130
                                                                       7-300
                                                                       10-70
                                                                       20-80
                                                                                  20 to 35%
                                                                                  Not known
                                                                                  5 to 10% In
                                                                                    water
                                         By steam
                                           stripping
                                         Steam plus gas
                                           stripping
                                         Yes, by stage
                                           flashing and
                                           reheat
                                                                                                                             gas
                                                                                                                            gas
                                                                                                                            gas
                                Removes  CO ,  H 3,  NH  ,  HCN and other  impurities from crude gases from coal gasification, etc.
I Solid Bad Sweetening Processes
   Molecular sieve (sodlun     Physical absorption          10-40       5-100
     aluminum silicate)
 .  Union Carbide Corporation,
     Llnde Division
     (914) 345-3196
     (Gas end liquid otrecm
     with rater, BjS, 002)

 8imulfsneo bUU US° °f "8a"1C "Ui in tha a
                                                                                 Varies
                                                                                                   Heat
                                                                                                                        HjS gas
  Stretford-ADA vondate
     (sour gas)
  Sulfreen  (SNPA/Lurgt)
  The Ralph M. Person
  (Gas containing SOj)
                                          acceptable la the U.S.

                                         Yes                  Pure sulfur
                               Diooolutlon in (tquoous      58          0-100       Varies           v»s
                                 solution of sodium .
                                 carbonate, sodium                          .            .,
                                 vondate, end tinthra-
                                 qulnona dlsuli'onlc
                                 •eld (ADA)
                              Although this procesa converts H^S to sulfur. It is essentially an extension of the Claus reaction.

                             =»——~—«	=»—                                   r

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                                                                                       26
ttuobar of Units
In Operation
la the U.8.
Selectivity
for HjB In
Hj8 + COj
Rich reed
Advantages
(Also see text)
Disadvantage!
Utilities
Raqulrenentf
       AMD LIQUID SVBIIHIia IMCSS8IS
          >300 units mostly In
            refineries


          >300 unite mostly to
            refineries
          56 x 10 8 Cu, m In
            operation In
            natural gaa

          58 (NG). widely ac-
            cepted In natural
            gas, refiner? gas,
            coke oven gaa
            operation!.
          18 In Canada
          None In the U.S.
          12 In other countries
          30
          Widely accepted for
            refinery gases In
            Europe.
          Many In Europe
          20 In natural gaa
          >200 In MBa plants,
            etc.
          66 unlta total
                                 Honaelectlve
Good for
Excellent up to 50%
  COj can be re-
  tained In gaa
                                 None
Good  aelectlvlty
  achievable
                                 Possible
                                 Possible
 Rapid reaction with aold gat
   (H2S.  C02,  ate.)


 0.2  mole acid gas/mole  of
   MEA
 -Removes  901 of  all ner-
   captans with no  addi-
   tional  burdens.
 -High  solution loading
 -Excellent  ease  of
   operation
 -Skid  mounted units for
   small gas operations
   available

 Lower utility  requirements
Well danonstratad process for
  refining gases
No corrosion problems
Applicable to liquid hydro-
  carbons, synthetic gas,
  etc.
Flexible operating conditions
                           The higher the pressure the
                             better
                           Lover solubility of HC
                                                            Low cost of materials
                                                            Mora difficult  to  regen-
                                                              erate.  Higher utility
                                                              costs
 Currently DGA Is in short
   supply


 Absorbs  heavy aromatlca
   from the gaa
                              Depends on feed and/or
                                COzi  IfeB concantratlon
                                •MEA Is better for low
                                   pressure (100 pal)
                                 Must have at least 201
                                   total acid gas and
                                   must be 002
Very  low.  Lower  than
  MEA and DBA.  See
  Table next page
                                                                                                                            low
                                                                                                                          Low steasi consumption
                                                                                                                         Low steam consumption
            construction
Moderate selectivity
  for BjS la possible
Can handle both high and
  low CC? and HjS gases.
Lower capital and operating
  costs are claimed by
  developers
Can treat high pressure
  gases only
  0*0 ata)
 Not used In natural gaa Industry but Is mentioned here to emphaslce that it la a major process.
Very low compared to
  MBA
Hot XJCO3 processes
          12  In (a*
          30  In UB
Excellent for H20
  and HJS
Easy to operate and vary
  useful for LOG purification
Off gaa from regenerator
  is too lean In H»8 for
  a Claus plant.  Hence
  concentrator it needed.
Hence this proceea ts eat likely to be uaed in the U.S.
          53 unlta total
                                Completely selective
                                   to  HjS
                           No tall gaa hence no HjS
                             emissions
      Therefore It l» discussed to detail under "Tallgas Cleaning Processes",

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                                      27
           Detailed process descriptions are available in literature     and
 Appendix A.   Essentially,  the principle used is the chemical reaction of               j
                                                                                        r .'',,
 H S and CO  with amine.   In recent years the Sulfindl and other improved               !• V
                                                                                        t . ;;
 processes are tending to replace the not-so-selective MEA and DBA processes.           I  '-i'
 A comparison of some operating data for the MEA, DEA, DGA, and Sulfinol pro-           \'
 cesses are presented in Table 7.                                                       [
 Carbonate Processes

           Most of the carbonate processes were designed to remove CO- (rather
 than H S) from the gas.   The principle used is that C0? (and to a lesser ex-
 tent H S) has a high affinity for potassium carbonate (K2CO,) and hence,
 K C0_ can be used to remove C00 and H?S from a mixture of gases according to
 the following reactions.

                    K.CO.  + C00 + H00 £=£.  2KHCO-     and
                     L  J      2    2              j

                    K2C03  + H2S £=5;   KHS + KHCO^

 Since the salt formation  in both reactions is high, high temperatures are    fe'.
• • '•          •                                    '
 employed to keep the salt in solution.  Thus, the process is called hot
•  '   '      '
 carbonate process.
 '•                                              '
           The hot carbonate process has been successfully utilized for bulk
 removal of CO  and incidental removal of small concentrations of H9S.  The
              2.                                                    2.
 process will not work if  only H?S but no CO  is present.  The process has
 the advantage that both carbon disulfide (CS_) and carbonyl sulfide (COS)
 can be removed without significant solution degradation.  Carbonyl sulfide,
 for example, will hydrolyze as follows.
                        COS
 The C0«  and H S are removed as per reactions described earlier.

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                                    28
          TABLE 7.   COMPARISON OF CIRCULATION RATES AND REBOILER

                     STEAM RATES FOR VARIOUS  TREATING PROCESSES^10'

ITEM
Contactor Pressure, psla
Feed Gas Temp., °F
Feed Gas Flow (Dry), MMSCFD
Feed Gas Composition, Mol 7.
H,S
CO,
N2
Cl
C2
C3
'4
C5+
TOTAL
COS, Grs/100 SCF
RSH, Grs/100 SCF
H2S/CO2 Ratio
Sweet Gas H2S Content, Grs/100 SCF
Sweet Gas C02 Content, Hoi 1
Sweet Cas Total Sulfur, Grs/100 SCF
Solution Circulation Rate, gpm @ 110'F
SuHinol (Composition Varies)?
MEA (15 wt. 1 ME A)
DEA (25 wt. I DEA)
DGA (65 wt. 7. DCA)
Section Net Pickup, SCF Acid-Gas/Gal
Sulfinol Sol'n.
MEA Sol'n.
DEA Sol'n.
DGA Sol'n.
raboller Steam Rate. 0/HR
Sulfinol Sol'n. '
MEA Sol'n.
DEA Sol'n.
DGA Sol'n.
Reboller Steam Rate, (?/Cal. Sol'n.
SulUnol Sol'n. .
MEA Sol'n.
OEA Sol'n.
DCA Sol'n.
Cas "A"
1,000
no
100

0.65
8.73
2.37
87.90
0.35



100.00
3.0
2.1
0.0744
<. 0.25
<. 1.0
<1.0 '

1,483
2,170
1,272
1,277

4.39
3.00
5.12
5.10

69,740
143, 200
87,770
91,950

0.78
1.10
1.15
1.20
Gas "B"
1,000
110
100

20.1
2.0
1.4
71.5
2.0
1.7
1.1
0.2
100.00
7.3
1.5
10.05
<0.25
*1.0
<1.0

1,748
5,115
2,997
3,010

8.78
3.00
5.12
5.10

111,440
337.590
206,790
216,720

1.06
1.10
1.15
1.20
Gas "C"
1,000
no
100

20.10
2.00
1.40
63.01
8.43
3.71
0.82
0.53*
100.00
7.3
1.5
10.05
<0.25
<1.0
<1.0

1,790
5,115
2,997
3,010

8.57
3.00
5.12
5.10

125,960
337,590
206,790
216,720

1.17
1.10
1.15
1.20
Gas "D"
1,000
110
100

51.5
3.5
8.6
25.8
5.8
3.2
1.6

1.00.00
8.4
3.1
14.71
<0.25
<1.0
Cl.O

2,366
12.-730
7,460
7,490

16.14
3.00
5.12
5.10

156, 000
840,180
514,740
539, 280

1.10
1.10
1.15
1.20
Gas "Z"
1,000
110
100

0.10
18.00
0.70
80.94
0.17
0.05
0.04

100.00


0.0056
<0.?5
2.0**
<1.0

2,167
4,190
2,455
2.465

5.24
3.00
5.12
5.10

99,600
276.540
169,400
177,480

0.77
1.10
1.15
1.20
 * Includes 0.02 Mol. 7. arranatics.
** 2.0 mol. 7. COj for Sulfinol;  < 1.0 tnol. 7.  for all other processes.
 (Courtsey:   Campbell Petroleum Series  and Dr. R.  N.  Maddox)

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                                     29
                        Li cm Id-Swee tening Pro ce s ses

          Liquid sweetening is also widely practiced in the natural-gas
processing industry.
          Many of the gas-sweetening processes discussed previously also
serve to sweeten liquid hydrocarbons.  Examples of such processes are:
          (1)  Molecular Sieve Process
          (2)  MEA Process (plus caustic wash)
          (3)  Adip Process.
          The Molecular Sieve process is particularly suited to the simul-
taneous drying and removal of H S and CO- and is widely used.  Maddox
describes other processes used in the sweetening of gasoline fractions
(hence, not used in natural-gas processing).  These are the Merox Process,
Caustic Wash, Copper Sweetening, etc.

Environmental Effects of Liquid Sweetening

          Atmospheric emissions and other environmental burdens are not sig-
nificant because, although the volume of plant liquids treated is significant,
the total amount of sulfur removed is small.

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                                  30
             IV.   DESCRIPTION OF LESSER KNOWN SULFUR(H9S)  REMOVAL PROCESSES

          Many factors need  to  be  considered when  selecting a process  for              f-
a given sweetening application.  These  include:                                         .
          (1)  The types of  impurities  to be removed  from the gas                       {
               stream.                                                                  f
                                                  •  '  \                                 -I--.
          (2)  The relative  concentration level  of  these  impurities                     i
               and the degree of removal desired.                                       v
          (5)  The feasibility  and desirability  of sulfur recovery.                     f/
          (6)  Relative economics of the suitable processes.         .                   :•;.'
          Acid gas constituents present in most  natural gas streams  are                 rf-
                                                                                        f •
hydrogen sulfide  and carbon  dioxide.  Many gas streams, however, particularly          |.
those in a refinery or for manufactured gases, may contain mercaptans,                  '/-
                                                                                        $
carbon disulfide  and/or carbonyl sulfide.  Any of  these constituents                   f.
present in the gas stream will  lead to  irreversible reactions,  degrada-                 £:>'
tion of sweetening solution  or  non-removal of the acid gas constituent                 f
                                                                                        £
which may cause many processes  to be ineffective or economically unattractive.          !
          The level of acid  gas concentration in the  sour gas is an                     [,.
                                                                                        !'••'•
important consideration for  selecting the proper sweetening process.   Some             $
processes are applicable for removal of large quantities  of acid gas;                   }•'
however, many of  these processes, will not sweeten to  pipeline specifications.          |
Other processes have the capacity for removing acid gas constituents to  the            i"
parts per million range - although some are  applicable only to  low concen-             !,
trations of acid gas constituents in the sour gas  to  be treated.                        £
                                                                                        u
          The selectivity of a  sweetening agent  is an indication of  the                 j
degree of removal that can be obtained  for one acid gas constituent  as                 '
opposed to another.  There are  sweetening processes which display rather
marked selectivity for one acid gas constituent.  In  other cases there                 ]
is no selectivity demonstrated  and all  acid  gas  constituents  will be removed.          ;
There are processes for which operating conditions can have a marked effect            ,.

-------
                                   31
on  ihe .selectivity exhibited.  Some sweetening agents absorb relatively
large amounts of  hydrocarbons while others are much more selective for
the acid gas constituents.
          Only rarely will natural gas streams be sweetened at low pressures.
Moreover, there are processes which are unsuitable for removing acid gases
under low pressure conditions.  Other processes are adversely affected by
temperatures much above ambient.  Some processes lose their economic
advantage when large volumes of gas are to be treated.
          The major processes described earlier have gained acceptance
because among other reasons they are very flexible in their application.
However there are numerous not-so-widely used processes examples of which
are: (1) the Purisol Process licensed by Lurgi, (2) the Iron Oxide (sponge)
Process, (3) Many of the carbonate processes including the Giammarco-
Vetrocoke Process, and (4) the Fluor solvent process licensed by the Fluor
Engineers and Constructors.  All these processes, used more in Europe than
in the U.S., show high selectivity for either H S or C0~.  For example,
the iron oxide process is completely selective to H~S; thus a gas from
which only H_S needs to be removed, other conditions favoring, could be
treated by iron sponge process.  Basically therefore, the lower cost and
selectivity determine the justification for the minor processes.  It is
emphasized that to generalize on which process to employ for a general range
of input and output of H7S concentration In natural gas Is almost imoossible.
Every gas stream will have to be analyzed with reference to as many processes
as necessary to derive the factors required to make a proper process
selection.   This is a major process selection project for each gas well
or combination of wells in a field.

                 Minor Desulfurization QUS Removal) Processes

          A brief description of the four lesser known processes is provided
below and detailed flow sheets are presented in Appendix B..  The four
processes are listed in  Table  8  with possible reasons for the choice of each
process in a given processing situation.

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                           TABLE 8.  LISTING OF LESSER KNOWN GAS DESULFURIZATION PROCESSES
   Process Name
and Licensor/Seller
  Approximate Reasons for the Choice of Process
Number of Units Installed
PURISOL
Lurgi Mineral
GMBH
IRON SPONGE (OXIDE)
Sold by many in-
cluding National
Tank Company, Tulsa,
Oklahoma
(918) 663-9100
FLUOR SOLVENT
Fluor Engineers and
Constructors
- Good selectivity for H_S or C02 can be achieved
- Low temperature (ambient) operation
- Low circulation rate for a given situation
- C02 removal by pressure let down
- Excellent solvent stability
- Nontoxlc fumeless operation

- Removes efficiently trace amounts of H^S in gas
- Batch process has low investment and operating
    costs.  Infinite turndown capability
- H2S removal independent of gas pressure
- Easily installed (wood chips coated with iron
    oxide is packed in any available cylindrical
    column).
- The used iron oxide is thrown away as solid waste
    or burned
- Very low capital costs ($20,000) for a system with 10
    grains/100 scf H2S at 2 million scfd of gas.

- Low solvent loss due to low vapor pressure of poly-
    propylene carbonate
- High capacity solvent, which absorbs acid by gas by.-
    physical solution, permits solvent regeneration
    simply by pressure let down of rich solvent,
    usually without the application of heat.
- Solvent breakdown rate is virtually zero
- Carbon steel is used in construction
- The process is favored when the combined partial
    pressure of C0£ + H2S is>5 atm; and when the
    heavy hydrocarbons are low.
2 Units in Natural gas
  outside the U.S.
None in U.S. in natural
  gas
2 units in hydrogen
  manufacture in the U.S.

More than 200 batch units
  in operation.  However,
  the construction is so
  simple and costs so low
  that builders cannot
  justify maintaining
  record of installations
7 plants in natural gas
1 plants in ammonia pro-
  duction
2 plants in hydrogen pro-
  duction

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                                           TABLE 8.   (Continued)
   Process Name
and Licensor/Seller
 Approximate Reasons for the Choice of Process
Number of Units Installed
GIAMMARCO-VETROCOKE
(Power-Gas Ltd.)
Treating costs about half the costs of most other
  processes (hot carbonate, MEA).
Low capital costs
Low corrosion of G-V plants
No solution degradation
Process not applicable if H~S content is above 1-5
  volume present
Treated gas has low H?S content of 1 ppm (0.06
  gr/100 scf)
Process can operate at pressures as low as atmos-
  pheric and temperatures up to 150 C.
One plant in natural gas
  in the U.S. (West Texas)
Used mostly in Europe.
Use of the process in the
 : U.S. is not likely to
  increase because of the
  arsenic used in ab-
  sorption solution.

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                                  34
Purisol Process

          Detailed flow sheet, process description and operating conditions
are presented in Appendix B.  The process is applicable to the removal of
acid gases  (H2$  +  C02) from Syngas  (synthetic gas) and natural gas
streams using physical absorption in N-Methyl-Pyrrolidone (NMP).

Iron Sponge  (Oxide) Process

          Detailed flow sheet, process description and operating conditions
are presented in Appendix B.  This process is well suited for removal of
H?S when it  is the only undesirable component of natural gas.  The process
does not generate atmospheric pollutants because the sulfur formed in the
iron oxide bed can be disposed of in a landfill, providing that a suitable
landfill site away from water ways (both surface and underground) is
available.

Fluor-Solvent Process
          Detailed flow sheet, application and process description are
presented in Appendix B.. The process is excellent for the removal of high
concentration of acidic gases (when the combined partial pressure of
C0_  + H-S is about 5 atmospheres or higher).  The processing arrangement
can be modified to suit the degree of purification required  for  both
H-S and CCL.  Solvent regeneration is inexpensive and solvent carrying
capacity is high because of the sufficient free refrigeration obtained by
expansion of the acidic constituents.  The process does not require special
or exotic materials of construction.

Glammarco-Vetrocoke Sulfur Process

          Detailed flow diagram, application, process description and
operating conditions are presented in Appendix B. The process produces

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                                     35
sulfur as a precipitate directly by continuous scrubbing of H S with an
alkali arsenates and arsenites solution.
          The main drawback of the process for gaining acceptance in the U.S.
is the use of arsenlte compounds in the scrubbing solution.  In addition, if             .:
         •  '                                                                          '  »,'*J
both CO. and H-S are present, two separate treating units are required.  The           J ;i
process is used widely in Europe and other countries.

                    Level of Sulfur Compounds in Treated
                 Natural Gas Attainable by Various Processes

          The level of sulfur compounds attainable by the 18 processes de-
scribed earlier is summarized in Table 9.  Obviously, there are data gaps.
It should be noted that the extent of removal of H_S and other compounds de-
pends on the partial pressure of these compounds and the careful design of
                                                                                       ' if
the process to attain that level.                                                      ' • a'
          In general, the gas industry can confidently state the specific
level of H S attainable in the product natural gas.  However, since the gas
industry was not particularly required to concern itself about the concen-
tration of other sulfur compounds in product natural gas, insufficient exact
data on the levels of COS, CS-, and RSH exist.  Recommended levels of sulfur
compounds as maximum permissible concentrations in natural gas sold as in-
dustrial and residential fuel are presented in Table 10.
          Based on the fact published by the AGA*  that about 8 percent of  the
gas is sold to industry and commerce, a 64-ppm total sulfur level (4.0 gr/100
scf) would have resulted in a sulfur emission of 12 MT/D by natural gas com-
bustion during 1973.  This quantity of emission (0.009 million MT/Y as SO )            | 1
                                                                         *•             1' A
is very insignificant in comparison with national SO  emission data presented
in Table 16.  The insignificance of this quantity will be more pronounced
due to the area source nature of the emissions.
* GAS FACTS - 1971 data, American Gas Association, Arlington, Virginia.


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                                            36
                   TABLE 9.  APPROXIMATE LEVEL OF  SULFUR COMPOUNDS IN TREATED
                                    NATURAL GAS WITH VARIOUS PROCESSES
Process
Name
Level of Sulfur Compounds
In Treated Natural Gas (ppm) ^a'
H2S COS CS2 RSH Sulfur^
Source of
Information
Major absorption
  mode used in
  removal
MEA (aqueous)
                    Physical   Chemical   Chemical    Physical

                       <4         <2         <2
Industry
Expert
DEA (aqueous)
DGA
Sulfinol
SNPA-DEA
ADIP
Benfield
Catacarb
Selexol
Rectisol
Mol-sieve
GV-Sulfur
Stretford
Sulfreen
Purisol
Ironoxide
Flour Solvent
(,'/- Sulfur
<4 <5 <5 60% 10-16 w
<4 (d) (d) (d) (d)
<4 <2.0 <1 >90%^C' <10 "
Removal
<4 <2.0 <1 50%(C) <10(b)
<4 <1 <0.5 60JP <10 "

<4

0.8 1.0 Union Carbide
Bulletin F-86
<2
<0

<0.4
<0.1
<0.4
<0.4

 (a)  Blank spaces signify data not available.

.(''.')  Depends  on inlet roercaptan (RSH) levels.

 (<-)  Indicates  percent RSH removed.

 ;-.-.)  Mo  definite levels can be specified.  Mr. Dingman (see Appendix F) is of the
     .•-yi.'i.'xion  ?,hat the feed gas conditions ,'-?i.d  composition should be kno^vn to arrive
     at:  "U:V'-:1;-;  of these compounds that can be  attained.

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                              37
TABLE 10'.  RECOMMENDED MAXIMUM CONCENTRATION OF SULFUR COMPOUNDS
           IN NATURAL GAS SUPPLIED TO GAS TRANSMISSION SYSTEMS
           FROM NEW PROCESS PLANTS(a)
                                           Maximum
                                        Concentration,
           Name of Compound                  ppm


        Hydrogen eulfide (H2S)               16

        Carbpnyl sulfide (COS)               (b)

        Carbon disulfide (CS2>               (b)

        Mercaptans (RSH)                     (b)

        Total sulfur (S)                    64
        (a)  These concentration limits apply to new
             gas processing plants only.

        (b)  The allowable concentration of COS, CS-,
             mercaptans, and other sulfur compounds shall
             be such that the total sulfur content of the
             treated gas (which determines the ambient SO.
             emissions) shall not exceed 64 ppm (4 grains/
             100 scf).

        (c)  The intent of this limitation on total sulfur
             is to limit sulfur emissions to atmosphere when
             the natural gas is burned as fuel.  Therefore,
             when the same gas processing facility produces
             sour and sweet gases both feeding to a common
             transmission system, the recommended total
             sulfur limitation may need adjustment.  Such
             adjustment shall Include the permitting of a
             higher total sulfur concentration in treated
             sour gas such that its admixture with the
             sweet gas at the pipeline inlet will not
             result in a total sulfur greater than 64 ppm
             in the gas mixture.  Also, in those rare cases
             when the concentration of mercaptans in sour
             gas exceeds 400 ppm, the allowable total
             isulfur limit shall be adjusted to account for
             the fact that the best control technology
             limits mercaptan removal to 90 percent of
             inlet mercaptan level.

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                                38
        V.   COMPARATIVE DESCRIPTION OF SULFUR REMOVAL AND PRODUCTION
                  PROCESSES IN NATURAL GAS AND REFINERY GASES
          The choice of processes used in desulfurization of natural  and
refinery gases is based on the following parameters.
          (1)  Gas composition
          (2)  Gas volume
          (3)  Required degree of removal of undesirable constituents
               in the gases
          As discussed earlier, there are 14 major processes and at least
four minor processes in use for the removal of H»S in  the natural gas
processing industry.  Generally, the product from these 18 processes  is an
acid gas (a mixture of H_S 4- CO,,) which is further processed in a sulfur
plant to pure sulfur which is sold when a ready market is available.  The
tail gas from the sulfur plant may need to be further  treated by use  of
one of the many tail gas treatment processes which have been recently
developed.  Examples of tail gas treatment processes are: (1) the IFP,
(2) the Wellman-Lord S02 removal process, (3) the Clean air process,
(4) the Beavon process, and (5) the SCOT process, etc.
          A recent Battelle study^    indicates that processes for removal
of H S from refinery fuel-gases are:  (1) the Shell Adip, (2) Girdler's
Girbotol*, (3) DBA, (A) Fluor Econamine, and (5) the Shell phosphate  process.
Not included among these five fuel-gas treatment process is the Stretford
process which is a direct oxidation process for removing H2S to obtain sulfur
as the product directly.
          The four processes (Adip, MEA, DBA, and Econamine) which have com-
mon applicability to both the natural gas and the refinery gas desulfuriza-
tion needs have been described earlier in Table 8 and Appendices A and B.
An industry expert is of the opinion that the Shell phosphate process is not
* Same as MEA Process.

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                                39
in the current list of processes readily offered for licensing.  However,
this process will be s-old if specific demand exists which happens in certain
unusual situations.  The older units using this process are still working
well.
          It appears therefore that the process for I^S removal used
in the natural gas industry and in the refinery fuel gas treatment are
not significantly different.  However while the process choices available
for natural gas industry are from more than 20 processes, the refinery
gases have a limited choice, the reasons for which are explored In
this chapter.

              Factors in the Selection of I^S Removal Processes

          The parameters in the choice of processes listed earlier can be
covered under three factors which govern the selection of processes for
hydrogen sulfide removal from refinery fuels.

Solubility of Organic Components of the
Fuel Gas In Absorption'Solvent

          Natural gas has a much lower concentration of heavy hydrocarbons
(less than 1 percent of heptanes and heavier) than refinery fuel  gases.
As an example, a catalytic-cracker gas contains more than 10 percent of
heavy hydrocarbons which tend to be soluble or otherwise be held  in the
absorption solvent used in the H S removal process.  The Shell Sulfinol
process is a typical example in which the solvent  (sulfolane, di-isopropanol
amine, and water) tends to absorb heavy hydrocarbons from the feed gas,
especially the aromatics.
          By contrast, the solvent in the Shell ADIP process (di-isopropanol
amine) and the DEA process  (diethanolaraine) have a very low solubility for
almost all hydrocarbons because among other reasons, the solvents are used
as aqueous solutions (Ca 75 percent water by weight).  This Is one of the
reasons for the very wide use of ADIP and DEA In cleaning of refinery fuel

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                                      40
 gases.  Very  few  solvents have  low  solubility  for heavy Hydrocarbons while
 at  the same time  maintaining  good desulfurization ability.  The MEA, DBA,
 and ADIP processes appear to  be about  the only processes  that  are being
 widely used in refinery  fuel  gas cleaning for  this reason.

 Presence of Sulfur Species Other Than
 H,S in Untreated  Gas
__£	;	   .                                   .

          In  general, the concentration of non-H S sulfur species is higher
 in refinery-fuel-gas streams  than in natural-gas streams because the re-
 finery cracking reactions generate  these sulfur compounds*.  Consequently,
 refinery-fuel-gas streams tend to severely degenerate certain  solvents used
 in H S removal.   Such degeneration  is  generally not a serious  problem in
 natural-gas streams.  The Sulfinol  process, quite widely used  in natural-
 gas treating, is  substantially immune  to solvent degeneration^   ; the cost
 of solvent, however, is high.  The MEA solvent is subject to heavy degenera-
 tion by carbonyl  sulfide (COS), etc., and hence, is seldom used in refinery-
 gas cleaning where the concentration of COS, etc., in the gases is quite
high; DBA and ADIP are not subject  to degradation by COS and are therefore
 favored for refinery-fuel-gas cleaning.  This  is one additional factor con-
 sidered in process selection.

Required Degree of Removal of Sulfur Compounds

          Pipeline companies have set the H~S  level in natural gas by the
 quarter-grain or  one-grain concept  (0.25 grains or 1.0 grain H2S per 100
 scf equivalent to 6 or 23 mg/s cu m).  However, no such strict limits for
H S content exist for refinery fuel gases because they are burned as plant
                                                                   •
 fuel on site and do not need to be piped to customers.  Further, the total
sulfur level in natural gas is usually also limited by sales agreements for
natural gas to about 10 to 20 grains/100 scf.  By contrast, the total sulfur
 level in refinery gaseous fuels can be as high as 100 grains/100 scf and
 the H S level can also range from 1 to 50 grains/100 scf.  These facts tend
* Carbonyl sulfide (COS), carbon disulflde (CS ), etc.

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                                     41
to favor the selection of desulfurizatlon processes that have low overall
cost and lower sulfur removal efficiency for refinery-fuel treating.  The
Shell ADIP process has the ability to be designed for both low- and high-
H S removal.  However, the need for more effective removal of sulfur com-
pounds like COS, CS , etc., is greater in natural-gas treatment.  Thus, the
sulfinol for example has a greater applicability to natural-gas treatment.

Other Factors in Process Selection

          The extent of carbon dioxide present in natural-gas streams is
also a factor in the selection of the gas-treating process.  Some natural-
gas streams contain very high (50 percent or more) roncentrations of CO
and low concentrations of H S which favor the use of a modified (promoted)
carbonate process.  Similarly, if the refinery fuels contain high CO. levels,
the selected cleaning process will have to deal with removal of the high C02
levels.  Outside the U.S., the GV-carbonate removal process is widely used
for this situation.
          The above factors do not cover all of the aspects involved in
the selection of a process.  Process selection is an expert area and
detailed process engineering, design, and economic analyses must precede
the selection of a process.

                   Methods of Sulfur Production in Natural
                        arid Refinery Gas Applications

          Two different principles of sulfur production from H_S are in
current use: (1) direct vapor phase oxidation-reduction and (2) liquid
phase absorption-oxidation.

Direct Vapor Phase Oxidation Principle

          The well known Glaus process employs this principle of oxidation-
reduction as follows:

                  H2S  +  3/2 02  —^> H20  +  S02  (oxidation)

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                                   42
                2H0S  4-  SO  -__^2H.O  +  3S  (Reduction)
                  /        z       /
           If the acid gas (or feed to Claus plant) contains hydrocarbon
 compounds, the following undesirable reactions also take place
                  CH.  +  S00 	^»COS  4-  H00  +  H0
                    42               22
                  CO  +  S 	5*—-COS
                  2CO
Carbonyl sulfide (COS) and carbon dlsulfide (CS.) are the undesirable
constituents contributing to tail gas sulfur.
          It also is quite likely that in the presence of hydrocarbons,
the following reaction will occur
          3CH4  +  3/2 02 - > 4H2  +  CO  +  2C  +  2H20.
This reaction can use up the air supply as well as blind the catalyst with
carbon soot.
          The Claus  plant has  found wide  acceptance  in  both the refinery and
natural gas  industries.  The choice of  the  Claus  plant  is  simply a function
of  the availability  of enough  acid gas  feed to  the unit.   Eighty- four  Claus
units  (Appendix I) are installed  in natural-gas processing with a total
                      (9)
capacity of  6250 MT/D    .  The number of  Claus units  in refinery-gas sulfur
                                                                     ^
recovery  is about 200, with a  total  production  capacity  of  8000
          Detail e.d  description of  a  Claus  plant with  three  catalytic  stapes
o f  co nv e r. y i. on  : ;: p r e. •-, eo t e d  in  A p i : \ • IK! i x  C .

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                                  43
Glaus Sulfur Plant Capacity VS Production Rate

                               (9)
          According to the data    presented in Appendix I (List of Glaus
Plants in Natural Gas Processing), as of April, 1973, there were 84
sulfur production units in natural gas processing with a total design
capacity of 6,250 MTD.  However eight of these plants with a total
capacity of 660 MTD were stand-by units.  Further, available production
data for 1972 indicate that in most cases, the actual production was
about 50 percent of design capacity.  This may be due to the reduced gas
output coupled with initial optimistic overdesign of the Claus units.
          The sulfur production data (2443 MT/D) reported in a later Section
(Table 14) is in reasonable agreement with estimated data from Appendix I*
assuming average production to be about 50 percent of plant design capacity.
          There are 31 Claus plants with design capacity greater than
or equal to 50 MT/D.  If 50 MT/D is arbitrarily chosen as the cut point
at which tail gas cleaning requirement would be deemed necessary then
a total of 35 tail gas units could be expected in natural gas processing
industry.  The rationale for chosing a  50 MT/D plant as the cut off point
is that 94% Claus plant efficiency, the tail gas unit will have at least
3 MTD of sulfur production.  This will be discussed in greater detail
in a later Section.

          Sulfur Recovery Efficiency of Claus Plants.  A considerable
amount of study on the present and potential efficiencies of Claus plants
has been conducted by the companies connected with sulfur production and
recovery in the Province of Alberta, Canada.  It is only natural that such
study has been initiated in the Alberta area which is the world's leading
sulfur production center.
                 (2)
          Rankine    et al contend that theoretical calculations and field
scale experiments together clearly demonstrate the potential of the Claus
*(6250-660)/2 * 2795 MT/D = (Total Glaus plant capacity - Capacity of standby
 units) x (Plant utilization factor of 0.5).  This "reasonable" agreement
 implies that almost all of: the Claus plants in natural gas processing are
 listed in Appendix I.

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                                   44
process to achieve efficiencies well in excess pf the present of 90-97
percent.  In their opinion more research should be directed to the
exploitation of the Glaus plant's potential for increased efficiency.
On the contrary, so far, most of the research effort has been directed
towards development of new process intended to augment Glaus plant
efficiencies.
                         (2)
          The study model    has led to the definition of several criteria
for optimum Glaus plant performance; namely
          (1)  Each sulfur condenser should operate at about
               260°F which provides a margin of about 20°F
               above the freezing point of sulfur.
          (2)  Mist elimination equipment should be utilized
               in interstage sulfur condensers as well as in
               the final condenser.
          (3)  Methods of reheat which introduce sulfur com-
               pounds into the main gas stream should be
               avoided.  This is in adherence to the principle
               that optimization implies all sulfur compounds
               are introduced as far upstream in the plant as
               possible.
          (4)  The operation of each converter should be
               adjusted so that the actual and dew point
               temperatures converge at the converter outlet.
          They conclude that these criteria have not been generally adhered
to in the design and operation of existing Glaus plants.  Finally, the
thermodynamic recoveries from a four stage Glaus plant processing a feed
containing 67 percent hydrogen sulfide were predicted as follows.
                    2 Catalytic Stage Recovery    97.9 percent
                    3 Catalytic Stage Recovery    99.1 percent
                    4 Catalytic Stage Recovery    99.A percent
          The optimum yields for the lean-feed case (H.S content of 10 to
50%) were predicted to be not significantly different.  These efficiencies
are based on the following practical factors.

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                                   45
          (1)  Furnace conversion cannot be predicted thermo-
               dynamically.  In this example a value of 60
               percent: was chosen.  This is lower than that
               which is generally observed.
          (2)  The gas off the first sulfur condenser was
               assumed to be 330°F.
          (3)  In consideration of certain side reactions,
               which must proceed in the first converter,
               an outlet temperature of 625°F was chosen.
               This temperature is well above the sulfur dew
               point.
          The above predictions were tested in June, 1972 by the Western
Research and Development Ltd. Calgary, Alberta on a Claus plant of 1600 MT/D
capacity.  Pertinent results of the field test are summarized in Table 11.
          The agreement between actual and theoretical conversion and
recovery tends to support the view that Claus plants can be operated at
high enough conversion efficiencies to obviate the need for tail gas
cleaning in most cases.
          However, conversations with the Ralph M. Parsons Company, Los
Angeles, California indicate that guaranteed efficiency of sulfur recovery
cannot be made in excess of 97% (for new Claus plants).  For old plants
with efficiencies in the range of 90-97%, increasing the efficiency by any
method will cost from 80 to 100 percent of the cost of a new Claus plant
of equal capacity.
          These discussions show the problems and potential solutions to
improve H~S conversion to sulfur in Claus plants.  The other method of
improving Claus plant efficiency is to use a tail gas unit.  The variety
of tail gas units available is described in a later section of this report.

Sulfur Recovery by Liquid-Phase Absorption-Oxidation Principle

          Three processes using this principle are described in detail in

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                              TABLE 11.   SUMMARY OF CLAUS  PLANT FIELD TESTS
                                                                           (2)

Operating Temperatures C
Conversion* Recovery*
Stage
Thermal Stage
Catalytic Stage //I
Catalytic Stage #2
Catalytic Stage #3
Catalytic Stage #4
Total
Feed
98.31
0.48
0.43
0.78
-
100.0
Actual
66.6
91.3
97.5
98.9
99.3
99.3
Theoretical Actual
-
90.9
97.3
98.8 98.6
99.3 99.1
99.3 99.1
Theoretical
-
89.1
95.9
98.6
99.1
99.1
Condenser
Outlet
190.6
176.7
165.6
137.8
123.9
-
Converter
Outlet
-
310
215.6
190.6
171.1
-
Maximum
Dew Point in
Converter
-
248.9
207.2
179.4
148.9
-

* Cumulative plant performance index in which all parameters are expressed as percentage of total plant feed.

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                                   47
Appendix C.  These are the G-V sulfur process, the Stretford ADA vandate
process, and the Takahax process.  Although all these processes are in
commercial operation as described in Appendix C, only the Stretford process
appears to be important in the U.S. and will be discussed below.

          The Stretford Process.  The reactions upon which this process is
based are essentially insensitive to pressure.  Operating temperature through-
out the unit are in the range of ambient to 49 C.  A summary of the reactions
is given below.

         (1)  Absorption of H2S
             H2S  + Na2C°3  ~* NaHS + NaHC03 '
         (2)  Precipitation of sulfur
              2NaVO   + NaHS  + NaHC03 -> S
         (3)  Regeneration of sodium vanadate
             Na2V2°5 + ADA (°xidtzed) "* 2NaV03 + ADA (reduced)  .
         (4)  Regeneration of ADA
             ADA  (reduced) + ^p  (air) - ADA (oxidized) .
         (5)  Overall reaction
             H2S +  2°2  ~*  S + H2° '
          COS and CS2 are not recovered by the Stretford process and this
reduces the overall sulfur recovery.  Otherwise the Stretford solution is
quantitative for the removal of H-S.  Some adverse side reactions occur
due to peaks in loading (increased liquor temperature) and trace oxidizing
gases contained in the fuel gas (notably oxygen, SO-, and HCN) and result

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                                   48
in the buildup of sodium thiosulfate and related compounds in the circulating
liquor which must be purged from the system.  A typical analysis for the
purge stream is shown in Table 12*.  The rate of thiosulfate formation depends
on the partial pressure of oxygen in the inlet gas stream, and the pH and
temperature of the liquor.  Formation of thiosulfate is quite low below
about 38 C.

          Disposal of Stretford Purge Solution.  Currently, the Stretford
purge stream normally is disposed of by discarding it to an industrial
sewer.  A process alternative that is being developed by Nittetu Chemical
Engineering, Ltd. (NICE) involves treatment to reclaim the sodium value as
      (12)
Na~CO.     (see Figure 4).  As shown in the diagram, waste liquid removed
from the desulfurization plant is first fed to the evaporator operated at
60 C and a vacuum of 100 mm. Hg (abs), where the salts are preconcentrated
to about 50 weight percent.  The evaporator heat source is quenched-
combustion-gas obtained directly from the quenching tank at a temperature of
about 90 C.
          The concentrated waste liquid is then sprayed into the incinerator.
Combustion of an auxiliary gas maintains the incinerator at 850 C in a
reducing atmosphere.  The reducing conditions are maintained by limiting
the oxygen feed at 70-80 percent of the theoretical amount required for
combustion.  At the designated residence time, most of the sodium salts
decompose to Na«CO- and NaHCO»; they are then blown into the quenching tank
along with the hot combustion gas.
          The quenching tank carries out two tasks: quenching of the hot
combustion gas that is blown from the incinerator, and the capture of sodium
salt contained in the gas, mainly Na^CO.,.  Quench and makeup water for the
reconstituted Na^CO, solution is fed through the gas-blowing duct between
the incinerator and the quenching tank.  The Na^CO- solution is continuously
removed from the tank and used as absorbent in the H-S absorber.
* Private communication from Charles Sedman, EPA, Durham,.N.C. to Joseph
  Genco, BCL, Columbus (December, 1973).

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                      49
      TABLE 12.  TYPICAL COMPOSITION OF
                STRETFORD PURGE SOLUTION
       Composition               Wt.  Percent
       Na2C03                       0.47

       Na-ADS(b)                    0.07
       Na-Meta  Vanadate             0.03

       Na-Citrate                   0.03

       Na2S2°3                      °'6°
       NaSCN                        0.60

       HJD                         98.20
(a)   Purge solution approximately 1.5 to 15
     gal/100 moles of feed gas to the absorber,

(b)   Na-anthraquinone disulfonate.

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  DESULFURIZATION  SECTION
                                         INCINERATION AND SODIUM  RECOVERY  SECTION
                                            Concentrated
                                            waste liquid
                               Fuel gas
                                                                                      Exhaust gas
                                                                                      (for fuel)
COG
                                                 Combustion
                                                 gas (contains
                                                                     Gas
                                                                     cooler   50 C

                                                                         kJ
                               Incinerator
                                      Quench Tank
Coke oven
gas (to be
treated)
                   Compressed
                                                                    Condensate
                   Waste liquid
                   (to be
                   incinerated)
                                   Na2C03
                                   Receiver
                                          Recovered liquid (contains NaHS)
                                                                                                   in
                                                                                                   o
          FIGURE 4.    TREATMENT OF STRETFORD  PROCESS PURGE SOLUTION
                                                                                   (12)

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                                   51
          The combustion gas, with sodium salts removed, is drawn out of
the tank at approximately 90 C.  This gas contains about 8 volume percent
(dry basis) of H_S as well as such gases as H2, CO, and CH, and has a
temperature of about 75 C when discharged from the shell side of the
evaporator.  It is cooled to about 50 C by a surface condenser and cooler
before being supplied to the H.S absorber.
          The absorber is designed to return the absorbed H S that results
from incineration under the reducing condition to the oxidizer at the
desulfurization plant.  There it is recovered from the filters as elemental
sulfur.  The Na.CO- solution, recovered from the quenching tank, and the
absorbent from the desulfurization plant are both recycled.  Indication
is that the NICE Process has been tried only at the pilot-plant level.

                          Tailgas Conditioning Processes

          The six  tail gas treatment processes in  commercial use are listed
in Table 13.  Detailed process description and flow diagrams are presented
in Appendix D.
          Since tail  gas processes are used to clean up  the Glaus  plant
effluent,  the criteria of selection of any tail  gas process are  the same
for both natural gas  and refinery fuel gas applications.   As is  the case
with any process selection problem, detailed design and  economic evaluation
of several alternate  processes for a given gas stream will be necessary to
arrive at  the process giving optimum benefits.

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                    TABLE 13.  GLAUS PLANT TAIL-GAS TREATMENT PROCESSES
  Process
Beavon


Cleanair


IFP-1


SCOT


Sulfreen


Wellman-Lord
        Developer/Licensee
      Commercial Units in Operation
          or Under Construction
Union Oil, Ralph M. Parsons


J. F. Pritchard, Texas Gulf Sulfur


Institut Francais du Petrole


Shell Development


Lurgi, SNPA*, Ralph M. Parsons


Davy Powergas
 7 in operation and  6 under construction


 1 in operation and  3 under construction


12 in operation and  5 under construction


 2 in operation and 25 under construction


 3 in operation and  4 under construction


 2 in operation and  6 under construction
tn
K>
* Societe Nationale des Petrole d'Aquitaine.

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                                   53
       VI.  ASSESSMENT OF SULFUR RECOVERY IN NATURAL GAS PROCESSING

          Natural gas and liquid processing plants reporting sulfur
recovery for 1972 are listed in Table 14  '.  Accordingly 24 states
in the U.S. processed natural gas; however, sulfur recovery from sour
gas was done in only seven of these states, namely, Arkansas, Florida,
Mississippi, New Mexico, North Dakota, Texas, and Wyoming.  The total
sulfur recovery amounted to 2443 MT/D (metric tons/day also equal
to kkg/day) and the associated gas throughput volume x/as 33
MMscumd (1162 Million scfd).  Thus the average t^S concentration in
the gas processed for sulfur recovery is computed -o be about 5.5 volume
percent or 35 grains per scf.  A salient summary by state is also
                                 i
presented in Table 15.
          The following points of significance are noted from Tables 14
and 15.
          (1)  Total sour gas (33 MMscumd) is only about two
               percent of the total daily gas production rate of
               1608 MMscumd (56787 MMscfd).
          (2)  Nearly 100% of the gas produced in 17 states in-
               cluding Louisiana, California, Kansas, Oklahoma
               is sweet.
          (3)  The total sulfur produced by the gas processing
               industry is about one million tons per year.  If
               the Claus> plants used in this production is
               assumed to be 95 percent efficient, the emissions
               from the industry would be 50,000 tons of sulfur
               per year in 1972.  Comparison of this emission with
               the total SO, emissions for the nation as a whole
                                                                   (7)
               represented by the Council on Environmental Quality
               (CEQ) is made in Table 16.  Accordingly S0_ emission
               from natural gas processing is 0.30% of the total
               national S00 emissions during 1972-1973.

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TABLE 14.    NATURAL GAS  AND LIQUID PROCESSING PLANTS
                   REPORTING SULFUR RECOVERY (1973)
                                                     (1,6)

State
Arkansas

Florida

Mississippi

New Mexico


North Dakota
Texas















Company and Plant
Arkansas Louisiana Gas Company
Hamilton Plant, Various Fields, Columbia
Exxon and other companies
Jay Field Facilities, Santa Rosa and Escambia Counties
Shell Oil Company - Goldwater Plant and Field, Clarke County
Thomasville Plant and Field, Rankin County, Jackson
Amoco, Empire Abo Plant and Field, Eddy County
Cities Services Oil Company, Bluitt Plant, Chaveroo, Roosevelt
County
Signal Oil and Gas Company, Tioga Plant, Williams County
Amoco, Edgewood Plant and Field, Van Zandt County
Midlands Farm Plant, Andrews County
North Cowden Plant, Ector County
Slaughter Plant & Field, Mockley County
South Fullerton Plant, Andrews County
West Yantis Plant. Wood County
City Services Oil Company, Lehman Plant, Cochran County
City Services' Oil Company, Myrtle Springs Plant, Van Zandt County
Robstown Plant, Nueces County
Simon X Perry's Subdivision of Fred Tract
Seminole Sulfur Plant, Seminole County
Welch Plant, Dawson County
Exxon Company, Jourdonton Plant, Atascosa County
Gulf Energy and Development Corporation, Powell Plant, Navarro
County
Odessa Natural Corporation, Foster Plant, Ector County
Sour-Gas
Production
(MMscumd)

0.9

3.7
0.17
0.40
0.68

0.85
2.12
0.86
1.00
2.6

0.82
0.51
0.37
0.76

0.59
0.79
0.05
0.62

0.30
0.54
Sulfur
Production
(MTD)

5.3

650
1.4
220
22

8
116
332
6
26
34
3
34
2
216

216
23
2
13.2

6
12.8
                                                                                         en

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                                          TABLE ]&..  (Continued)
State
Company and Plant
 Sour-Gas
Production
(MMscumd)
  Sulfur
Production
  (MTD)
Texas





Wyoming


TOTAL
Shell Oil Company, Bryan's Mill Plant, Cass County
Shell Oil Company, Person Plant, Karnes County
Warren Petroleum Company, Como Plant, Hopkins County
Warren Petroleum Company, Fashing Plant, Atascosa County
Warren Petroleum Company, Sand Hills Plant, Crane County
Warren Petroleum Company, Waddel Plant, Crane County
Amoco Production Company, Beaver Creek Plant, Fremont County
Amoco Production Company, Elk Basin Plant, Park County
Husky Oil Company, Ralston Plant, Park County

1.56
1.41
0.34
1.40
4.1
3.4
1.47
0.31
0.15
33.0
190
20
34.6
27.4
33.4
89.2
39
32
29
2,443.3
                                                                                                               I/I
                                                                                                               en

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                               56
         TABLE 13.  SALIENT DATA ON SULFUR RECOVERY
                       IN NATURAL GAS PROCESSING


State
Arkansas
Florida
Mississippi
New Mexico
N. Dakota
Texas
Wyoming
Total Sulfur
Production
(MT/D)
5.3
650
221.4
30
116
1,320.6
100
Associated (Sour)
Gas Throughput
(MMScfd)
31.9
130
20
54.3
74.8
783.0
68.2
Total                   2,443.3                  1,162.2

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                                  57
       TABLE  16.
COMPARISON OF S02 EMISSIONS FROM ALL SOURCES

S02 From Natural Gas As
Weight Percent of S0_ From
MT/Y Other Sources
Natural gas industry
CEQ Data ^ '
All industrial processes
Stationary sources using
fuel combustion
Transportation
Solid Waste Disposal
Miscellaneous
Total (except SO- from
natural gas
o.io(a)
5,1
26.3
1.0
0.1
0.1
32.6
-
2.35%
0.46%
12.0%
120.0%
120.0%
0.30%

(a)  Based on an average sulfur recovery of 95 percent  in existing Glaus
     plants and on a total sulfur production from natural gas  industry
     of about one million tons per year (MT/Y).  Texas  and Louisiana
     state laws require Glaus plants to achieve and maintain a minimum
     of 94 to 97 percent sulfur recovery depending on the size of
     the plant.

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                                   58
                   Listing of Sour Gas Processes in Texas

          Attempts were made to obtain accurate data on the extent of
unrecovered H~S emission from oil and gas processing plants in Texas.
Such information was theoretically available in the files of the Railroad
Commission of Texas*.  Accordingly, this agency was contacted and
information on H?S emissions and sulfur production for 77 plants (GP-1
forms) in Texas was obtained.  However, upon carefully checking the forms,
it was found that the information available did not differentiate between
the acid gas and H_S even though very often the acid gas contained 90 percent
C02.  As a result, the data available in GP-1 forms were suspect.  For
other states, no such data are available.
          In summary, a statewide  - plant wise emission inventory for H.S
requires a major effort.   However,  the objectives  of this  report do not
suffer due to the lack of such data because it has already been shown that
(1) small operators comprise only about 2 percent  of the total gas processing
capacity, (2) the sour gas production is  less than 5 percent of the total
gas produced in the U.S., and (3)  a sufficiently accurate  data on Glaus
plants producing sulfur for every state is available from  which an estimate
of sulfur emissions can be made.
* See listing for Mr.  James C.  Bouldin in Appendix F.   All plants processing
  gas report to the Railroad Commission of Texas on Form GP-1 entitled
  "Monthly Report for Gas Processing Plants".

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                                   59
          VII.  OVERALL ASSESSMENTAND RECOMMENDED CONTROL OPTIONS

          The US natural gas processing industry operates about 800
processing installations of three different size ranges described in
Table 17.  The combined processing capacity of these installations was
1.6 billion/scumd as of January, 1973.  Of this gas volume, 33 million
cumd was sour gas.  Thus, sour gas represents about two percent of the
total gas volume.  It is quite possible that many small gas plants
processing less than 0.3 million cumd of sour gas with low H-S (100 ppm)
concentration are not represented in this sour gas volume of 33 cumd.
But such unreported volume is not expected to be more than about a few
million/scumd) as a reasonable guess.
          As reported in  Section  II,  the  H2S  concentration in the  sour
gas ranges from 100 to 106,000 ppm (0.25 to 270/gm/scum) although
isolated fields have produced natural gas with up to 600,000 ppm of H2S.
However H?S levels in processed sour gas which led to the production
                               (1)
of sulfur in 29 reported plants    averaged 74 gm/scum.  Of these 29
plants, four were small sized, 16 were in the intermediate size
rnage and 9 in the large size range of processing facilities.  This
fact and other useful analytical conclusions are summarized in
Table 17.
          Also presented in Table 17 is the effect of HLS  recovery efficiencies
obtainable with Glaus plant and other processes on sulfur  emission levels
for the three size ranges.

             Effect of Claus Plant Efficiency on SO  Emissions

          The following conclusions can be drawn from the  data in Appendix I
and Table 17.
          (1)  Small gas plants contribute 1.6 percent of  the total
               SO- emission from all the gas plants at the three sulfur
               recovery levels of 95%, 97% and 99.5 percent.
          (2)  In absolute quantities, the reduction in S0_ emission from
               small plants realized by increasing the sulfur
               recovery efficiency from 95 percent to 99.5% will be
               85,000 MT/Y and is not significant in comparison with
               about 33 million MT/Y of S02 emission for the  nation
               as a whole.

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                   TABLE  17.  ANALYSIS OF  REPORTED  DATA^  (1973)  ON NATURAL GAS
                             PROCESSING PLANTS  REPORTING  SULFUR PRODUCTION
Classification of Natural Gas











Effect
(1) SO
i.

(2) S02


(3) S02
L*

Item
Size range MMscumd
No. of plants^1) (1972)
Volume of sour gas
Processed MMscumd
Sulfur produced MT/D (1972)
7o
Average t^S in raw gas
ppm
gm/scum
grains/lOOscf
of sulfur recovery efficiency
emission at 95%^' recovery MT/D
106MT/Y
7,
emission at 977
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                                     61
          (3)  Intermediate and larj^e plants produce about the same
               quantity of sulfur and benefits of increasing the
               sulfur recovery from these sizes are about the same.
          (4)  If the current average Glaus plant efficiency is assumed
               to be 95%, the natural gas industry at current sulfur
               production levels contributes about 0.1 million MT/Y of
               SO  to the national SO  emission of about 33 MT/Y.
               Thus, about 0.3% of the national S0_ emissions are due
               to the Glaus plants in natural gas.
          (5)  If the efficiency of all Glaus plants is raised to 97%,
               the SO  emissions would be reduced from 0.1 to 0.055
               million MT/Y, i.e., to 0.17 percent o!: the total national
               SO  emissions.  However, if the actual Glaus plant sulfur
               production reaches the full production capacity indicated
               in Appendix I, for the 84 plants, the SO  emission at
               97% Glaus plant efficiency will be 386 MT/D* which is
               about 0.43% of the national SO  emission level of 33
               million MT/Y.
          (6)  If each of the 84 Glaus plants were allowed to emit 2
               tons of sulfur per day, the total emission of SO. would
               be 0.123 million MT/Y.  This represents 0.37 percent of
               the total annual national S0? emission.
                 Control Options and Performance Standards
          The various control options available to reduce the emission of
H S and/or SO. in the natural gas industry depend on the degree of emission
reduction specified for each facility size.  The required degree of emission
reduction is derived from the allowable sulfur emission that would not sig-
nificantly contribute to the national SO- emissions.  These factors
* 386 MT/D = (2) x (6249) (100-97)/97 since one ton of sulfur (S) produces
  two tons of sulfur dioxide (SO.).

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                                     62
determine the needed performance standards Cor sulfur recovery units in
natural-gas processing.
          The control options possible for three hypothetical levels of
allowable emissions are shown in Tables 18 through 20.  In all of the hypo-
thetical, allowable levels* A, B, and C,  seven control categories result.
The various control options suggested are:
          (1)  Reinjection of acid gas
          (2)  Iron oxide process
          (3)  Molecular sieve process
          (4)  Packaged Glaus plant
          (5)  2- and 3- and 4-stage Glaus plant
          (6)  Tail-gas units with Glaus plant.
Each of these options is briefly discussed below.
(A)  Reinjection of Acid Gas or Separated Sour-
Gas to Well Formations
          Reinjection is possible and economically feasible when it assists
a production field in secondary gas/oil production and when the wells in the
field are unitized.  The decision to reinject is up to the gas processors.
                                                       (13)
There is one facility practicing reinjection in Alberta    .  Some of the
problems of handling H.S under high pressure are listed in Appendix H.  A
brief summary of the reinjection problems is listed below.
          The most serious problems to be encountered in reinjection of the
separated sour gas or of the treating plant regenerator off gases are:
          (1)  Dehydration of gas prior to handling in injection
               service.
          (2)  Hazards associated with handling high-pressure toxic
               material like H S and CO .
          (3)  Costs associated with the designing and installation
               of a safe, noncorrosive system, in unitizing the mineral
               rights of the receiving subsurface formation, and pro-
               tecting the producing wells bottomhole equipment which
               would be exposed to the high concentration of acid gases
               in the producing reservoir after reinjection.
* Defined in Tables 18, 19. and 20.

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                     TABLE  18.   CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION LEVEL "A"

Gas Plant Size Sulfur Allowable
Control as Sweet Gas Production Sulfur
Category Production Rate Rate Emission
Number MMscumd hMscfd MT/D MT/D
1 Any Any £1.0 1.0
2 ^0.3 <10.5 >1 to 410 1.0
3 ^0.3 O-0.5 >10 -
4 >0.3 but >10.5 but >10 but 1.0
$1.13 £40 440
5 >0.3 but >10.5 but >40
^1.13 ^40
6 >1.13 >40 40 to 500 1.0
7 >1.13 >40 >500
Required
Sulfur
Recovery
Efficiency
0
0% at 1 MT/D
90% at 10 MT/D
94%
90% at 10 MT/D
97.5% at 40 MT/D*
97.5%*
97.56% @ 41 MT/D*
99.00% 97.5  percent  would require
  tail gas cleaning systems.   The cost of such systems range from 80 to 100 percent  of the  cost of  the  Claus plant.

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                    TABLE  19.  CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION LEVEL  "B"
            Gas  Plant  Size
 Control     as  Sweet  Gas
Category    Production Rate
 Number    MMscumd     MMscfd
                         Sulfur     Allowable
                       Production    Sulfur
                          Rate,     Emission,
                          MT/D	MT/D
                              Required
                               Sulfur
                              Recovery
                             Efficiency,
                               percent
                                                                             Control Options
    3

    4
 Any
£0.3
£0.3
>1.13
             Any
             <10.5
             <10.5
>0.3 but   >10.5 but
  £1.13      £40
              >40
   £2.0
>2 to £10
   >10
>0.3 but   >10.5 but    >10,  £40
  £1.13      £40
                                    >40
40- to 500
                                       2.0
                                       2.0
                2.0
                                       2.0
                                                                   0
                                                          0% at  2 MT/D
                                                          80% at 10 MT/D
                                                       £80%

                                                80% at 10 MT/D

                                                95% at 40 MT/D
                                                           95% at  40 MT/D
                                                           98% at  100 MT/D
                                                           99% at  200 MT/D
                                                           99.6% at 500 MT/D
Tall stack dispersion when
  ground level concentration
  of H2S/S02 is high

(1) Reinjection of acid gas
(2) Iron oxide process
(3) Molecular sieve process
(4) Packaged Claus plant

Packaged Claus plant

Packaged Claus plant

2-stage Claus plant

3-stage Claus plant
2-stage Claus plant
Claus plant + tail gas
Claus plant + tail gas cleanup
Claus plant + tail gas cleanup
                        >40
                          >500
                               £99.6%
                                                                     Claus plant + tail gas cleanup

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                 TABLE 20.  CONTROL OPTIONS AT HYPOTHETICAL ALLOWABLE EMISSION LEVEL

Control
Category
Number
1
Gas Plant Size
as Sweet Gas
Production Rate
MMscumd MMscfd
Any Any
Sulfur
Production
Rate,
MT/D
£2.0
Allowable
Sulfur
Emission,
MT/D
2.0
Required
Sulfur
Recovery
Efficiency,
percent
0

Control Options
Tall stack dispersion when
    3

    4
            <0.3
           <10.5
             , £10
  <0.3
<10.5
X).3 but >10.5 but   >10, £20
  £1.13    £40
          X).3 but >10.5 but
            £1.13    £40
                       >20
2.0      0% at 2 MT/D
         80% at 10 MT/D
                90%

1.0      90% at 10 MT/D

         95% at 20 MT/D

                95%
  ground level concentration
  of H2S/S02 is high

(1)  Reinjection of acid gas
(2)  Iron oxide process
(3)  Molecular sieve process
(4)  Package Glaus plant
                                                      2-stage Glaus plant

                                                      2-stage Glaus plant

                                                      3-stage Glaus plant
6 >1.13 >40 20-500 2
3
4
5
7 >1.13 >40 >500
95% at 20 MT/D
97% at 100 MT/D
98% at 200 MT/D
99% at 500 MT/D
2:99%
2-stage Glaus plant
4-stage Glaus plant
Glaus plant + tail gas cleanup*
Glaus plant + tail gas cleanup*
Glaus plant + tail gas cleanup
* The 98% to 99% efficiency may be attainable with the LFP-1 tail-gas cleanup process which  appears  to
  have a much lower overall energy and capital requirement.
                                                                                                               on

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                                     66
           (4)  The cost of installing adequately rated equipment in
               high-pressure service.  This cost depends on the geometry
               of the system as well as the injection pressures required
               and the volumes of gases to be handled.  These costs may
               be so high that an operator, simply because of economics
               (cost versus benefit), cannot afford to make the neces-
               sary investment in dehydration equipment, compressors,
               high-pressure lines and fittings, well conversion cost,
               etc., and may elect to prematurely abandon his production
               which is responsible for the generation of the sour gas.
           (5)  Proper consideration must be given the effect of treat-
               ing plant regenerator off gas injected on the resultant
               concentration of sour gas components in the receiving
               formation and its effect on the wellbore equipment in
               close proximity to the injection well.
           (6)  Underground reinjection of sour or acid gases as well as
               any other extraneous fluid will, in most cases, require
               complete unitization of all the mineral interests in-
               volved in the project to protect correlative rights of
               all the interests involved.  Depending upon the com-
               plexity of ownership, this unitization effort could take
               years to conclude.  This time delay and effort could add
               to the cost of the project and may also,  in itself,
               make the project uneconomical.

(B)  Use of Iron Oxide Process
          This process removes H.S from the natural-gas stream to almost
zero level.  Thus, in a small facility, a portion of the gas can be sweet-
ened and mixed with the remaining sour gas so that the total H_S in the
natural-gas mixture does not exceed pipeline or other specifications.  The
small operator may be able to reduce his H S emission to less than one MT/D
by using the iron oxide process because the process produces solid waste
but no H S emissions.  Burning the spent sponge would, of course, result
in emitting SO  equivalent to the amount of H S removed from the gas.

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                                     67
(C)  Use of the Molecular Sieve Process

          This is an alternative to the iron sponge process insofar as it
can be quite selective in removing H9S (and other sulfur compounds) but not
CO   and the comments made above apply to this process also.  However, re-
generation of the sieve, unless the non-commercial Raines arrangement is
utilized i
posed of.

(D)  Packaged Glaus Plant
utilized results in the release of the adsorbed H S which must then be dis-
          When a maximum of only about 90 percent VJ' conversion to sulfur
is required, a pack?~cd two-stage Glaus plant may provide a suitable option
at low cost.  The cost of the packaged Glaus plant in relation to cost of
the facility and other available options, if any, needs to be evaluated.

(E)  Tail-Gas Cleanup with Glaus Plant

          There are at least six commercially used tail-gas cleaning pro-
cesses with many more under various stages of development.  The six pro-
cesses, details of which are presented in Appendix C, are
          (1)  Beavon Process
          (2)  Cleanair Process
          (3)  IFP Process
          (A)  SCOT (Shell Glaus Offgas Treating) Process
          (5)  Sulfreen Process
          (6)  Wellman-Lord (W-L) S02 Recovery.
          There are advantages and disadvantages associated with the employ-
ment of any of these processes for a particular application.  All of the
processes require electrical energy; the amount of energy used usually in-
creases in proportion to the desired degree of sulfur removal for the tail
gas.  It could be useful to compare the increased emission of S02 at the
coal-fired power plant resulting from the increased use of electric power
at the natural-gas plant necessitated by the tail-gas units.  Both are point
sources and both require energy for SO  emission control.  Some aspects of

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                                     68
the operational data of these tail-gas cleaning processes are discussed in
Section VIII.
          One other control option not related to the emission of sulfur
from acid gas is the use of vapor recovery units on oil storage tanks em-
ployed in LACT systems described earlier.  The Texas Air Control Board in-
forms that all new storage tank installations do include vapor recovery
units which compress the small amount of vapor leaking from the tanks and
inject the compressed vapor to sales or plant inlet gas lines.  The injec-
tion of a small amount of H?S by this method into sales gas lines would
be permissible only if the resultant mixture does not exceed the allowable
H S level of the gas.  This practice appears to ,be a sound and reasonable
approach to the prevention of small-volume H_S emission at remotely located
IACT units.

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                                     69
               VIII.  OPERATIONAL DATA FOR SELECTED PROCESSES

          The study of the natural-gas processing systems described in the
preceding Sections of this report indicates that control options which may
be used in reducing the SO  emissions from the industry as a whole are as
follows:
          (1)  Reinjection of the sour-gas and acid gas to well
               formation
          (2)  Iron oxide process for R-S removal
          (3)  Molecular sieve process for H.S removal from sour
               gas
          (A)  Packaged Glaus plant
          (5)  2- and 3-stage Glaus plant
          (6)  A-stage Glaus plant
          (7)  Glaus plant with tail-gas unit
          (8)  Tail-gas cleaning units (TGU's)
               (a)  Beavon
               (b)  Cleanair
               (c)  IFP-1 and IFF-2
               (d)  SCOT
               (e)  Sulfreen
               (f)  W-L SO  recovery
For the six TGU's listed, detailed operational and process description data
are presented in Appendix D.  However, a convenient overall summary of the
data is also presented in Table 21.  It can be seen that the IFP-1 process
which can increase the Glaus plant sulfur recovery to about 98.5%, has the
lowest utility consumption and perhaps the lowest total capital requirement.
The waste stream from this process consists of intermittent (once every
two years) waste waters generated in catalyst washing.  The process off-gas
leaving the top of the ammonia scrubber containing traces of NH-, entrained
polyalkylene glycol solution, and occasionally fine white particulate fume
is another minor waste stream.  A study is currently in progress to determine
the least expensive method to eliminate the particulate fume    .  Both these
waste streams can be considered to constitute a minor environmental problem.

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                                                                TABU 21.  OPERATIOHAL DATA FOR TAIL GAS CLBAHIN5 PROCESSES
Proceas Bams
Beavoo
Cleanalr
nrp-i
(TCT-1300)
Operating Feature*
Redaction of tall gaa constituents to
HjS followed by sulfur recovery
with S tret ford unit
Recovers 99.9 percent of sulfur
from Clan* plant tail gaa
Designed for low coat and sulfur
recovery efficiency of about
98.5 percent
Product
From
Process
99 percent pure
Sulfur as molten
or cake. Par-
ticle size 0.3
to 23 microns
99.3 to 99.9 pure
sulfur
Bright yellow
sulfur 99.9
percent pure
Sulfur in
Exit Gaa
<100 ppa
Total S
<10 ppa
HjS
<200 ppm
by volume
~2000 ppm
of S02

Investment
For a 100 MT/D Clans
unit, $700,000 to
$1 million
$500,000 for a 10
MT/D Claus plant
$3,000,000 for a
1000 MT/D Claus
plant
$2 million for a
1400 MT/D Claus
plant with 96.5
Costs aa of April. 1973*
Utilities
Steam - 1,453 Kg/hr
Cooling water - I/sec
Electricity - 25 kwh/hr
Fuel gaa - 224 scmh
For a ton of sulfur
produced in Claus
plant per day
Steam - 22 Kg
Electricity - 4 fcwh
Cooling water - 34 1/hr
Steam: for start up
only
Electricity - 35 kwh/hr

Operating
Maintenance 2
percent of
capital
1/2 men/shift

$30/day
$347/day for
catalyst and
Secondary Waste Streams**'
Stretford purge solution
(see text, page 53) am?
sour water condensate
Purge waste water stresir
Intermittent water con-
taminated with alkali
metal salts and organic
CFP-2            High sulfur  recovery  (99 percent       Bright yellow      ~5OO ppm
  (TCT-150)        plus)  at a cost higher than            sulfur 99.9        of SO.
                   DT-t                                  	
BOOT             Increases sulfur recovery of           Pure and bright    <300 ppm
                   Claoa plant from 95 percent to         yellow sulfur      of SOj
                   99.8 percent by  reduction and
                   alfcanolamlne absorption.  Can
                   handle varying feed rat* and
                   composition
                                                                                         percent efficiency
                                                                                         and 99 percent
                                                                                         overall sulfur re-
                                                                                         covery
                                                                                       $450,000 for 200
                                                                                         MT/D Clans plant

                                                                                       $800,000 for 250
                                                                                         MT/D Claus plant at
                                                                                         93 percent
                                                                                         efficiency

                                                                                       70 to 100 percent of
                                                                                         the cost of Claus
                                                                                         plant
Cooling water - for shut
  down only
Fuel gas - 0
$70/dsy
For a 250 MT/D Claus
  plant at 94 percent
  efficiency
Boiler water - 2500 Kg/hr
LP steam - 2,910 Kg/hr
Fuel gas - 100 Kg/hr
Reducing gas - 26 Kg/hr
Electricity - 350 Kw
                                                                                                                                             solvent
Catalyst plus
  solvent, $5/
  day
Maintenance 2
  percent of
  capital
                                                                                                                                                                acid
 Hj - 507 fume pins waste
  water stream as In TCT-
  1500
Substantially none
A very small amount of de-
  grade solvent is
  generated
Sulfreen



Mailman-Lord
SO. recovery


Essentially aa extension of the
Claua process after CS2 in t;all
gas is reduced to HjS. Sulfur
yield to about 99 percent
Treats only SO? (hence tail gaa in-
cineration 1* a moat)


Liquid sulfur,
99.9 percent
pure, bright
yellow
Concentrated
SO.


~1000 ppm
of S02


<100 ppm
Of SO.


For a 1000 MT/D Claus
plant, $2 million


For a 200 MT/D Ciena
unit, $1.6 million


Electricity - 650 kwh
Boiler water - 40 1/nln
Fuel gaa - 9900 scund

Cooling water - 500**
Kg/hr
Electricity 220 Kw
HaOH - 1 MT/D
Ho liquid waste*
Catalyst life - 4 years
Solid waste is generated
as used alumina, catalyst
Purge stream containing
•etal aaJlt are eent
currently to industrial
sewer*
 * To update these ctsta to April,  1974, multiply April, 1973 costs by aa approximate CE plant cost index ratio of 1.1.
••For •aantlu.tlv* data see Referamea 
-------
                                   71
                         Data for Glaus Plants

          The most significant waste stream from a Claus           the  tail
gas which contains sulfur equivalent to 3  to 5 percent of  the  feed sulfur
concentration.   This aspect has been discussed in detail in earlier Sections
of this report.
          The second significant waste stream is the spent catalyst (usually
bauxite) generated from  the Claus catalytic reactors.  The amount  of spent
catalyst is a function of the number of catalytic conversion stages employed,
which, in turn,  is a function of the required sulfur recovery  efficiency.
Thus, to maintain an efficiency greater than 97 percent, the catalyst  may
have to be replaced every 12 to 18 months.  Current!••-, most plants replace
the catalyst between the third and fourth  years and efficiencies obtained
range from 94 to 97 percent.  One plant reports that about 20  MT of spent
catalyst is usually generated once in 3 to 4 years from a 200  MT/D Claus
plant.  The spent catalyst is not regenerated and hence constitutes a
solid waste burden.  The quantity of solid wastes generated is relatively
insignificant and toxic  or leachable substances are not expected to be
present.  For these reasons, it should be  possible to dispose  of the
spent catalyst  in a landfill.  However, it should be pointed out that
no analyses of  the spent catalyst are available to make a definite
determination of its toxicity.
                                                                                      K:
                                                                                      I :'

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                                  72
                            IX.REFERENCES

 (1)  Cantrell, Ailleen, "1973 Survey of Gas Processing Plants",  Oil
      and Gas Journal (July 9, 1973).
 (2)  Rankine, Robin. P., Kerry,  R.  K.,  et al "Potential Efficiencies
      of the Conventional Claus Sulfur Recovery Process", a paper
      presented to the Alberta Sulfur Gas Research Workshop, Edmonton,
      Alberta, Canada, November 1,  1973, by Western Research and
      Development Ltd., Calgary,  Alberta, Canada.
 (3)  Chalmers, W. W., et al "Improvements to the  Claus Process—Past,
      Present and Future" Paper No.  71-AP-8.  Presented at the 1971
      Annual Meeting of APCA,  Pacific NW International Section, Calgary,
      Alberta, Canada (Nov 21-23, 1971).
 (4)  Horner, W.  N., "Operating Parameters at Ram  River Plant Outlined",
      Gas Processing, Canada,  (March-April,  1973), Page 14.
 (5)  Reprint from the 1972 "Bureau  of Mines Mineral Year Book" - Natural
      Gas Section, U.S.  Department of Interior,  Washington,  D.C.
 (6)  Telephone Conversation with Mr. John Flynn,  Chief Gas  Processing
      Engineer, Shell Oil Company, Houston,  Texas  (Phone 713/220-5440)
      and with Mr. Carl T.  Hester, Exxon Production Company, U.S.A.,
      Houston, Texas (Phone 713/221-3563).
 (7)  "Environmental Quality"  - The  Fourth Annual  Report of  the Council
      on Environmental Quality, September,  1973.   Page 266,  Published
      by U.S.. Government Printing Office,  Washington,  D.C.   20402.
 (8)  Encyclopedia of Chemical Technology,.Edition 2,  10, Pages 390-420.
      (1965)  Kirk and Othmer Interscience Publishers,  Division of John
      Wiley,  New York,  N.Y.
 (9)  Beers,  W. D. , "Characterization of Claus Plant Emissions",  EPA
      Report  No.  EPA-RD-73-188 (NTIS PB  220-376) from  Process Research
      Inc.,  Cincinnati,  Ohio.  (April, 1973).
(10)  Maddox, R.  N., Gas and Liquid  Sweetening,  2nd Edition, John M.
      Campbell Company,  Norman, Oklahoma  (1974).

-------
                                73
(1.1)   Genco,  J.  M. ,  and Tarn,  S.  S.,  "Final Report on Characterization
      of Sulfur  From Refinery Fuel Gas" Report  to EPA,  Durham,  N.C.,
      under Contract No.  68-02-0611 (June 28,  1974).
(12)   Mitachi, K.,  Chemical Engineering, 80 (21), 78-79 (October 15,
      1973).
(13)   Baraniuk,  E.M., "Sour Gas  Compression at  the West White Court
      Plant" Journal of Canadian Petroleum Technology,  January-March,
      1968.

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             Contactor
                                    APPENDIX A

                   DETAILED DESCRIPTION OF MAJOR H2S REMOVAL
                       PROCESS  IN OIL AND  GAS  PROCESSING


                                                Stripper
    Treated  gas.
                           Reproduced  from
                           best available  copy.
                                                                                   Acid  gas
      Feed gas
 Start
eed  gas
                                                                                     Steam
                    Rich solution
         Fluor  Econamine
Application! For the removal of acidic impurities, H»S
and CO*, from. gas  streams.  The  treating  agent  used
is an  aqueous  solution  of the primary alkanolamine,
HO-CaH4-O-C2H4-NH2,  tradenamed  Diglycolamine
(DGA).


Products Natural, synthesis or refinery gas streams may
be treated to H2S levels  of less than 0.25 grains/100 scf
and to COj  levels less than normally attained with con-
ventional MEA or DEA treating.


Description: The process scheme is identical to any other
alkanolamine treating plant. In fact, several existing MEA
treating plants have been switched  to Fluor Econamine
with no equipment changes.

  Feed gas is purified in a contactor vessel where acidic
impurities are absorbed by the Fluor Econamine solution.
Treated gas  flows to  dehydration or other subsequent
processing. Rich solution is heated by interchange  with
hot lean  solution, then flows to the stripper vessel for
solution regeneration. Stripped acid gases and water vapor
pass overhead to the condenser.  Condensed water  is
rcfluxcd to the stripper while H2S and COa go  to  flare
or to  sulfur  recovery.  Stripping  heat is furnished by a
steam-heated rcboiler.  Lean solution circulates from the
stripper, through the exchangers, and is pumped  through
solution coolers to the top of the contactor.
                                                The solution is typically 65 percent by weight DGA
                                               or higher. Use of this high concentration permits reducing
                                               circulation rate by, typically, 25-40 percent compared to
                                               MEA treating. This results in substantial savings in both
                                               capital and operating costs. At the same time, experience
                                               has demonstrated that corrosion is comparable to or less
                                               than normally experienced  with conventional  amines.

                                                Degradation of the treating solution is prevented by the
                                               use of a  simple and  inexpensive high temperature re-
                                               claiming technique,  which  purifies  a slipstream  of the
                                               treating solution. No caustic or other chemical addition
                                               is involved in this operation. Solution makeup require-
                                               ments are generally  below those of conventional amine
                                               processes. This reclaiming method permits the use of the
                                               Econamine Process for gas streams containing COS  or
                                               CSa since the decomposition products formed by the reac-
                                               tion between these sulfur impurities and the DGA are also
                                               thermally  regenerated during the  normal  reclaiming
                                               operation.


                                               Commercial Installations: Econamine is in use in  19
                                               plants with an aggregate capacity of well over 1  billion
                                               standard cubic feet per day.


                                               Reference: Oil and Gas Journal, May 2, 1966, pp. 83-86.


                                               Licensor: Fluor Engineers and Contructors, Inc.
                                                                April 1973
                                                                        HYDROCARBON PnocEsstno

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     Treated
        gas
                                               A-2
         Start
                                     Flash gas

                                  *-Acld  gas
                                                                              Reclaimer i
                                                Heat
                                             exchanger
         Sulfincl
Application: Process removes acidic gas constituents such
as HZS, COj, COS, mercaptans, etc.,  from natural, re-
finery and synthesis gases, and LNG feedstocks.
Description: The process is based on  the use of an or-
ganic  solvent,  Sulfolane (tetrahydrothiophene  dioxide)
mixed with an alkanolamine,  and  water.  Simultaneous
physical and chemical  absorption under feed  gas  con-
ditions is provided by this Sulfinol solvent, and regenera-
tion is accomplished by release of the acidic constituents
at slightly above atmospheric pressure and at elevated
temperature.
  Feed gas is contacted with regenerated Sulfinol solvent
in the absorber. Feed enters near  the tower base and sol-
vent hear the top.  Treated gas from the tower leaves the
unit for further processing or use. In high operating pres-
sure units the contact  solvent  may be  flashed in a  flash
tower, where  most  of the  absorbed  hydrocarbons  are
separated  for return to the absorber or for use as plant
fuel. In other units the contacted solvent goes direct to the
regenerator, where acidic gases are stripped,  using a re-
boiler. The regenerated solvent is  cooled and recirculatcd
to the absorber. Acidic gases  are cooled,  condcnsate is
separated and  returned to the  regenerator  as  reflux, and
acidic gas is made available for processing.
Operating  conditions: The process has been  used for
natural gas  applications in which the  H:S content has
varied from 0 to 53 mole c/o  and the  CO, content has
varied from 1.1  to  28  mole  %. Satisfactory removal of
mercaptans and carbonyl sulfidc is obtained for all  nat-
urally  occurring mixtures of acid gases that  have been
found. Natural gas'pipe line specifications that arc readily
attained arc:
 H2S	below 0.25 grain/100 scf
 CO2	below 0.3 mole %
 Mercaptan content	 .below 0.2 grain/100 scf
 Total sulfur.		below 1 grain/100 scf
   With minor modifications to the normal plant design,
 the gas can be treated to LNG feedstock  requirements of
 less than 50 ppm COa.  ••
   Specifications  which allow 2 to 3% COS can be ob-
 tained where the CO3/H2S ratio is high.
   Absorption pressures are determined by the gas feed
 pressure and vary from slightly above atmospheric, to
 1,000 psi or more. The regenerator normally operates at
 near atmospheric pressure  such that low-pressure  steam
 (60 psig) is suitable for rcboilcr heat.
   The  absorber temperature varies  with the operating
 pressure, while the solvent  circulation varies with the feed
 gas rate and acid  gas content.  Circulation rates are rel-
 atively low, compared with conventional amine processes.
 Low corrosion rates are experienced.
 Economics: Typical requirements for utilities, per pound
 of acid gas removed, are:
 Electricity, kWh	<0.01
 LP steam (60 psig), Ib.	0.8-1.6
 Cooling water (or equivalent), gal	5.4*9.8
 Commercial installations: Over 100 units are in opera-
 tion or under construction; about  70 percent of these are
for natural gas treating.
 Reference: Hydrocarbon  Processing, Vol. 44, No. 4, pp.
 137-140 (1965).
Licensing Inquiries:  Shell Development  Co., Houston,
 (USA),  and Shell Internationale Research  Mij,  B.V.,
The Hague  (rest of world).
                                                                   Apr! 1973       HYDROCARBON  PROCESSING

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          Contoctor    Flash  Tank   Solution Storage
                                         .
               Regenerator  Reflux  Drum
     Sweet gas
     "X
Start
       Sour
       gas
                                      ^
                                                                                                   Acid gase
                             (           )
             <2H
         SNPA-DEA
Application: For sweetening raw gas streams containing
a total  of about 10% or more of acid gases (H2S plus
CO2) at operating pressures of about SCO psig or higher.

Product: Natural  gas streams may  be treated to meet
the conventional pipe line specification of }4 grain H2S
per  100 scf  maximum  simultaneously with CO2 of 2
volume % or less. The acid gases removed from the raw
. gas are produced at an adequate pressure and the  proper
temperature to serve as direct feed for a Glaus-type sulfur
recovery unit. No intermediate processing  steps are re-
quired between the SNPA-DEA unit and the sulfur re-
covery unit, regardless of composition  and nature of the
hydrocarbons contained  in  the raw  natural gas stream.

Description: An  aqueous solution  of diethanolamine
(DEA) is used in concentrations determined to be eco-
nomical  from  past  commercial scale experience.
   An SNPA-DEA unit is similar to a conventional DEA
unit in many respects. The notable differences are: use of
higher  DEA concentrations,  optimization  of .operating
conditions to achieve higher than conventional loading of
the rich  DEA in terms of scf  per gallon of solution, and
specific conditioning of  a slipstream of lean solution to
maintain  a  low level  of solids, corrosive products, and
hydrocarbons.  Incorporation of these  features results in
stable operation through a wide thruput range,  with  low
foaming tendencies and,  hence, high reliability and  on-
stream time.
   Sour raw gas enters the contactor  where it is  scrubbed
with lean DEA solution. The H;S (and  COa) are removed
in the rich DEA leaving the contactor. Rich DEA flows
to a flash tank from where dissolved gases, after being
further purified, are released to fuel. From the flash tank,
rich DEA is preheated and charged to the regenerator. In
the regenerator the acid gases are stripped from the DEA
solution, then cooled and routed to a sulfur recovery plant.
Heat input to the regenerator is from low pressure steam
via reboilers. Lean DEA from the regenerator is first ex-
changed  and then cooled before  returning to the  con-
tactor. Solution storage and conditioning are provided on
the lean DEA stream.

Operating conditions: Commercial units are in opera-
tion at from 600 to  1,100 psig treating raw gas streams
containing from 11 to 35% acid gases. The  ratio of
HaS:CO8 ranges from 34 to 0.65 in these units.

Investment: Process factors affecting  investment cost
include:  operating pressure, acid  gas content, HjS/COs
ratio and treated gas  purity. The onplot investment for a
battery limits units processing 220 MMscfd of natural gas
at 900 psig  to produce a treated gas meeting pipe line
specifications will be $S-$8.5 million on a Gulf Coast
basis.  The  total acid gas  removed  in  this unit is  68
MMscfd  with an H,S/CO, ratio of 4/1.

Commercial installations: The  SNPA-DEA process is
currently in use to sweeten about 3 billion scfd of raw gas,
with an added 2 MMMscfd under construction.
References: Wendt,  C. J., Jr., and Dailey, L. W., "Gas
Treating: The  SNPA  Process,"  Hydrocarbon  Process-
ing, Vol. 46, No. 10, 155-157 (1967).
Licensor: The Ralph M. Parsons Co. and affiliates.

-------
                                                     A-4
                 Absorber
             Woshing Tower
Reqenerotor
           Gas
Start-
        Rawgos
                                                                                                   Acid gos
      Applications: For the substantial  removal  (to  a few
      ppm) of H*S and the partial removal of incidental COS,
      CO» and mercaptans.

      Charge! Natural, refinery or synthesis gas or LPG  having
      any concentration of acid gases.

      Description: The process  is based on an absorption-re-
      generation cycle using a circulating aqueous solution of an
      alkanolamine which reacts with acidic gases. H2S-contain-
      ing feed is contacted counter-currently with Adip solution
      in an absorption or extraction column. Regenerated solu-
      tion is introduced into the head of the absorption column
      at a normal or slightly  higher temperature and leaves at
      the bottom of the column. Rich solution exchanges heat
      with regenerated  solution and is fed to  the regenerator.
      Acid gases are  stripped in the regenerator, which  is
      equipped with a steam  reboiler. Cooled regenerated solu-
      tion is recycled to the absorber. Acid gases removed from
      solution in die regenerator are cooled, thus condensing the
      water.

        The  low steam consumption normally associated with
      the process is further reduced when H2S  is removed from
      gases under pressure, because higher absorption tempera-
      tures are possible. Because of the relatively low  steam con-
      sumption, savings are possible in both capital and operat-
      ing costs. Initial investment is also minimized, since car-
      bon steel is used with the non-corrosive Adip solution.

        HSS  in the product can be reduced to meet stringent
      specifications (less than 10  ppm),  thus making   after-
      treatment unnecessary.
              Operating conditions: Wide flexibility is possible in set-
              ting operating conditions. The absorber pressure is set by
              the pressure of the feed stream and ranges from slightly
              above atmospheric pressure to several hundred psi. The
              regenerator  normally  operates  at  slightly  above atmo-
              spheric pressure, such that low-pressure  (above 60 psjjg)
              steam is suitable for reboiler heat.                   ' <
                The solvent circulation rates depend on  the total gas
              feed rate and the concentration of acidic gases in the feed.

              Economics:  Basis: Fetrl—925  metric  t/d, 15.6% (voL)
              H,S and 0.3% (vol.) CO2.
              Product: 100ppm vol. H2S and 0.1% vol. COa
              Plant cost: US $1 million
              Solvent circulation: 200 m'/h
              Utilities: L.P. steam (4.5 atm.)—450 t/sd
              Electricity (incl. air cooling): 3,000 kWh/sd
              Make-up water (steam condensate): 9 t/sd
              Chemicals:  Adip  (100%, incl.  mechanical losses)—70
              kg/sd
              Operating costs: Labor—J4 operator per shift
                Maintenance: 2% of capital.

              Commercial installations:  More  than  130 units are in
              operation or under construction.

              Reference:  "Developments  in Sulfinol  and Adip  Pro-
              cesses  Increase Uses," Oil and Gas International, Vol. 10,
              No. 9, September 1970, pp. 109-111.

              Licensing inquiries:  Shell Development Co., Houston,
              (USA), and Shell Internationale Research Mij  B.V.,
              The Hague  (rest of world).
                                                                            -" t973
                                         HYDROCARBON PROCESSING

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                  Purified
                  gas  out
                                                     A-5
                    JL
                                   Acid gas,
Start
       Raw gas in
   Lean
solution
  Rich
solution
                                                                     Steam
              Benfield
     Applications: Removal of CO2, H2S and COS from sour
     natural gas and raw gases produced  during manufacture
     of substitute natural gas by partial oxidation of coal  or
     oil or by naphtha reforming. Selective removal of H3S
     from  CO2  plus  H2S mixtures  provides H2S-enriched
     stream suitable for recovery of elemental sulfur.

     Feed: Sour natural gas containing CO2 or COS and H2S
     mixtures  or synthetic  gas containing  COa  (and some-
     times  HjS) produced  by partial oxidation or reforming
     processes.

     Product: Purified gas with H2S reduced to pipe line
     purity specifications and with CO2 removal to  a few ppm.

     Description:  Raw gas is contacted with potassium car-
     bonate solution containing Benfield additives  at elevated
     pressures  (100  to 2000 psig)   in an  absorber  column
     (packed or trayed) and acidic  components  (CO, and
     H2S) are absorbed. The rich solution  is  let down to about
     atmospheric pressure and stripped in  a  regenerator tower
     to drive off absorbed acid gases and the regenerated lean
     solution then recycled  to the absorber.  Process conditions
     and flowsheet vary to  meet various feed gas  composition
     and desired product gas specifications.

     Operating conditions:
       Absorption  Pressures—Usually 100 to  2,000 psig. No
       upper limit for absorber pressure.
                                  Feed  Gas Composition—Economics favored by  high
                                  partial pressure of CO2 and HZS. In usual applications,
                                  CO2 or CO2 and H2S concentrations range from 5 to
                                  50%. Feed gas may be saturated with H2O and may
                                  contain substantial content  of higher hydrocarbons.
                                  Feed Gas Temperatures—Not critical—usually ambient
                                  to 400°F. Heat in feed gas  can  be used to supply all or
                                  part of process heat requirements.
                                  Regeneration Pressure—Atmospheric.

                                Economics: Typical capital investment (large plant) per
                                Mscfd of COa + H8S removed:  $75. Typical operating
                                utility requirements per Mscfd of CO2 + H2S removed:
                                  Regeneration Heat  70,000-130,000 Btu
                                                     1-2 kwh
                                                     50,000-100,000 Btu
                                                     Solution make-up for mechanical
                                                       losses only—no degradation
                Power (pumping)
                Total Cooling Duty
                Chemical Cost
                                Commercial installations: More than  250 operating
                                units including  18  units for natural gas  sweetening and
                                over 150 units serving substitute natural  gas units  (COt
                                scrubbing of reformed and partial oxidation gases).

                                Reference: Benson, H. £., "Hot Carbonate Plants: How
                                Pressure Affects Costs," Petroleum Refiner, Vol. 40, No.
                                4, p. 107-108.

                                Licensor: The Benfield Corp., Pittsburgh, Pa.
                                                                       April  1973
                                                           HYDROCARBON  PROCESSING

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•'.»*
             Absorber
                                                    A-6
  HiaL
Pressure
  Flash
Intermediate     Low
  Pressure    Pressure
    Flash  .     Flash
Stripper
                          Recycle
 Start
                                                                                         Vent
                                                          Air Or
                                                          inert gas
          Selexol
 Application: For gas purification and removal of HjS,
 CO», COS, mercaptans, etc., from gas streams by physical
 absorption. The solvent,  dimethyl ether of polyethylene
 glycol,  trade  named Selexol,  has strong  preference for
 sulfur-based compounds, while retaining the capability to
 absorb  bulk quantities of all impurities economically. It
 is also capable of simultaneously dehydrating to pipe line
 specifications.

 Charge: Sour natural gas; raw product gas from the gasi-
 fication of  coal, oil, and light  hydrocarbons;  synthesis
 gases from steam reforming or partial oxidation: refinery
 gases.

 Product gases: To less  than 1  ppm  total sulfur;  CO,
 can be retained or removed as required: water to less than
 7 Ib./MMscf gas.

 Off gases: Provide Glaus plant  feed stream highly en-
 riched in sulfur compounds; pollution-free  vent gases.

 Description: A  Selexol plant consists of an absorber to-
 gether with means for desorbing by flashing and/or strip-
 ping.  Recycle is  sometimes included to enhance  natural
 selectivity for sulfur compounds. Temperatures can many
 times  be controlled without  external heating or cooling,
 by using hydraulic  turbines and heat  interchange. Over-
 all liiMt effects are minimized by very low heats of absorp-
 tion and a specific heat of only 0.5. No  solvent reclaimer
 is nct-dod since there  is no degradation.  This, along with
low vapor pressure means very low solvent losses. Solvent
is non-corrosive and inherently non-foaming.
             Operating conditions: Absorption of impurities is essen-
             tially proportional to their partial  pressures. Feed condi-
             tions can be  varied over a broad  range in existing
             equipment.  At the other end of the process, the solvent
             is regenerated by physical desorption, rather than chem-
             ical decomposition. Over 8 years of commercial experience
             shows long term maintenance-free service.

             Economics  (expressed as  % of  MEA  costs) :  For a
             plant treating 100 MMscfd, operating  at 1,000 psiir, re-
             ducing  CO2 from 30 to 2 mole  % rain.,  and meetine
             H2S spec, of 0.25 gi/100 scf.                      *
                                                   % of MEA
                  Grass roots plant                      70
                  Direct annual operating
                     Steam                              JQ
                     Electricity                           20
                     Cooling & process water              25

                     TOTAL                          ~4o~~
                  Indirect annual operating               75

                     TOTAL annual  operating            50

            Commercial installations: Now operating or under con-
            struction in natural gas treatment, synthesis gas purifica-
            tion, coal gasification purification, COS  removal,

            Reference: Oil and  Cos  Journal, March 20, 1967,  pp.


            Licensor: Allied Chemical  Corp.
                                                                  April 1973
                                       HYDROCARBON PROCESSING

-------
                                                 A-7
            Desulfurizotion
Regeneration
(H2S-rCOS).
Regeneration
     (C02)
        Removol
       CH3OH
                                   \l\ conversion  |"

                                         CH3OH
                                                                                                  C02
                                                                                 To meth/
                                                                                   woter
                                                                                separation
          Rectisol
Application: The process uses methanol  as  solvent in
three typical applications: (1)  Removal of CO2,  H2S,
NH3, HCN, gumformers,  higher hydrocarbons and other
impurities from crude gas produced by coal gasification
for syngas or SNG manufacture;  (2)  Removal of  H,S,
COS and  CO» from  reformed gas, in  particular  from
.gas produced by partial  oxidation of hydrocarbons, to
yield  synthesis  gas, and (3)  Integration of gas purifi-
cation with  low temperature  plants  (liquefaction  and
fractionation) for removal of moderate contents of acidic
components.

Description  (Case  2: two-stage  syngas purification):
Crude gas, saturated with water vapor, is indirectly cooled
by cold purified gas and evaporating ammonia. Icing is
prevented by the  injection of methanol.  The  gas  then
enters the  first absorber where  sulphur  compounds are
removed completely by washing with  methanol already
charged with CO,. After CO shift conversion and further
cooling, the gas is fed into the  second absorber for the
removal of CO2 down  to the  level  required. Before leav-
ing the  plant,  the purified gas  is  heat exchanged  with
the shifted gas.
  Fat solvent from the first absorber, after flashing  and
heating, is regenerated  completely in the H2S regenerator
by rebelling.  After cooling, lean solvent is supplied to
tlic second absorber top together  with stripped solvent
from  the  CO3 regenerator.  In addition,  semi-stripped
solvent is charged  to the second absorber bottom section
for bulk removal of CO2.  Fat solvent leaving tlic second
absorber is regenerated  in the CO: regenerator !>y flashing
and stripping with impure nitrogen available .from  the
oxygen unit. Solvent for dcsulfuri/ation is withdrawn from
                                                                   HjS off-gas
                                                                     57.3
                                                                     40.1
  the COg regenerator and pumped to the first absorber top.
   Co-absorbed  H2 and CO is released in the first  flash
  stages at relatively  high pressure  and either returned  to
  crude gas or used as fuel.
   Refrigeration necessary for crude  gas and solvent cool-
  ing can be supplied by NHj absorption refrigeration unit
  operating on waste heat.
   Water introduced into solvent by  crude gas is removed
  by treating a small bleed  stream in  a  methanol/water
  distillation column.
 Operating conditions: Feed: Flow—108 MMscfd (100
  MMscfd H, and CO). Pressure—685 psig.
 Desulfurlxatlom    Feed     Treated gas
   CO,, Vol. %  	 5.3        - -  *
   HtS-f COS, Vol. %  .. 0.7
   HhVol.%  	44.6
   CO, Vol. % 	48.4
   N,+Ar,Vol. % 	 1.0
 COj removal:       Feed
   CO,,Vol.%  	36.1
   HtS + COS,Vol. %  .. —
   H,,Vol. %  	62.8
   CO, Vol. %  	OJ
   N, + Ar,VoJ.  %  	0.6
 Utilities:
   Power, shaft  (without power recovery)  	 2,500 kW
   Steam, 70  psig, tat'd	5.2 t/hr.
   Waito heat (for refrigeration unit)  	50 • 10*Btu/hr.
   Cooling water, 75'F, 18* AT	2,060 m'/hr.
   Mcthnnol  	  80 kg/hr.
 Commercial installations: 23 operating  units plus 7 in
 construction, total capacity  more than 2 billion scfd.
 Reference: / & EC, Vol. 62  (1970), No. 7, 37/43.
 Licensor: Lurgi  Mincraloltechnik  GmbH.
                                                                      1.6
    5.3
  <0.1 ppm
   45.0
   48.7
    1.0
Treated gat
    0.1  (1 ppm possible)

   98.2
    0.8
    0.9

-------
                        200 mmscfd
                 Start—-1
                                              A-8
                            LJ
                       Absorbing
                                Low temperature
                                hydrocarbon
                                recovery
                                                                            Pipe line
                                         Dehydration
                             Desorbing
                                           Sweetening
        Start.
 200 mmscfd
 6% C02
 10-100 grH2S
 7 Ib r^O/mmscfd
                               T
                                                            H20
                                                        100 mmscfc
                                                        6% CO
                                                        <0.25gr
                                                        bone dry
                                                        100 mmscfd
               <0.25gr H2S
               7lbH20/mmscfd
               200 mmscfd
               3% CO
               <0.25 gr H2S
               3 lbH2C/mmscfd
               Adsorbing  Cooling
        Molecular sieve
                     Desorbing
Amine  Glvcol
Scrubber Scrubber
Application: Processes to dehydrate and to remove car-
bon dioxide and sulfur compounds from natural gas.

Charge: Impure gas streams containing water, carbon di-
oxide and sulfur compounds.

Products: Gas meeting pipe line specifications or suitable
for feeding to cryogenic processing plants and LNG plants.

Description: The processes involve two or more  fixed bed
adsorbers and other regeneration facilities. At  least one
bed is on adsorption at all times while the other bed(s)
are being regenerated.
  The natural gas passes through the service bed where
the  impure material(s) are removed to product  specifi-
cations. Dry, treated regeneration gas is heated to  400-
600° F  in a cooling adsorber and/or a heater,  then fed
counter current to normal flow through the adsorber bed
being regenerated. Impure gas from the bed being dc-
sorbed is cooled, liquid water is separated, and the stream
fed  to  the product line, used for fuel, or goes  on for
further treating.
  A typical flow arrangement for carbon dioxide removal
is similar to that shown for sweetening except that no
further treating and drying is usually needed.
  Selection of the appropriate type molecular  sieve de-
pends on impurities to be removed. Type 4A is most com-
monly used for dehydration and Type  4A-LNG for car-
                       bon  dioxide. Several  types are  used  for desulfurization
                       depending on the kinds of sulfur compounds and  their
                       concentrations to be removed. Sieve life ranges from two
                       to five years for desulfurization and carbon dioxide re-
                       moval, and from three to seven years for dehydration.

                         Molecular sieves  used for drying cryogenic plant feed
                       can  be used also for  drying out the plant during shut-
                       down and before starti-os.

                       Economics: Unit size  is dependent on  the concentration
                       of impurities in  the feed and other  factors. Generally,
                       molecular sieves  are used for sweetening when  carbon
                       dioxide can be left in the product. Their use for dehy-
                       dration depends on the required dew point and normally
                       occurs when the dew point must be  — 40° F or below.
                       Carbon dioxide removal with molecular sieves is most at-
                       tractive when the product must have a very low  CO2
                       content and the feed has 1.5% (mol) COa or less.

                       Commercial applications: More than  12 units arc used
                       for sweetening over two billion scfd natural gas. All cryo-
                       genic gas processing plants in  the USA except  two use
                       molecular sieve  dehydration.  Twenty-nine LNG  pre-
                       purificrs arc in operation and  others are in  the design or
                       construction stage.

                       Contributor: Union Carbide Corp., Linde  Div.
1!YIWOCARBON PROCESSING
Apn!  '073

-------
                                               A-9
          Purified gos
              Absorber
Start   '"Pure
                         X
                                    Lean solution
                              Rich  solution
          Giammarco  Vetrocoke—sulfur
 Application:  For the continuous removal of hydrogen
 sulfide from natural gas or synthesis gases.

 Description: The Giammarco Vetrocoke (HjS) process
 for the removal of HSS continuously scrubs sour gas with
 an alkali arscnatcs and orsenitcs solution. Sodium carbon-
 ate, being relatively inexpensive, is the alkali  usually  ap-
 plied for the removal of large quantities of sulfur. The
 successive reactions occurring are:
    + 3 H,S - Na,AsS, + 3 H,O
                       Na,AsO,
Na*AiO> + '/,€>,=
                                                 (1)

                                                 (2)

                                                 (3)

                                                 (4)
   Sour gas enters the base  of  the absorber column  at
 pressures up to and above 75 ats. g., depending on well-
 head gas conditions.  A countciflow stream of Vetrocoke
 solution scrubs the I I2S to a level of 0.5 ppm or less. The
 sweetened gas leaving the absorber is cooled to rcducC'thc
 load  on  the downstream  duhydration plant. The  con-
 dcnsntc removed takes with it most of the carryover. The
 absorption  reaction,  Equation 1,  gives rise  to sodium
 thioarscniic which has a low vapor pressure of  HjS and
 allows a high purity gas to \>c obtained by straight counter-
 current absorption.
   The thioarsenitc formed is  slowly converted to mono-
 thioarscnatc and arscnitc by a  "digestion reaction," Equa-
 tion 2, which occurs in  absorber and in the  subsequent
 oxidizing column. The monothioarsenite formed has an
 even lower vapor pressure of H2S.
   Mono-thioarsenate, being more soluble, helps keep the
 sulfur in solution.
   The solution leaving the base of the absorber passes to
 an air-blown oxidizing column  working at  atmospheric
 pressure and around 40°C. This vessel is open  to atmo-
 sphere at the top.  Under the oxidizing conditions, the
 mono-thioarsenate decomposes to arscnite and elemental
 sulfur. Elemental sulfur is removed overhead  by  froth
 flotation, vacuum filtered and washed. The oxidizing re-
 action also re-establishes the original Vetrocoke solution
 balance by oxidizing some arsenite to arscnate.
 Operating conditions:  The dual function of the oxidiz-
 ing tower limits the variation possible in the air flow to
 the oxidizer because flotation process would  be impaired
 and a constant flow of solution to the absorber is possible
 only at constant air rates. It is  not practical to control
 arsenate formation solely  by the depth of solution aeration.
 A small amount of catalyst is added to promote and con-
 trol arscnate formation. This also reduces oxidizer size.
 Commercial installations: Approximately 30.
 Economics:   Battery limits capital  cost  of a  100
 MMscfd plant (in the United Kingdom)  is approximately
 $600,000. This plant removes II-.-S from inlet concentra-
 tion of GOO ppm to outlet of J/a ppm.  Utility costs arc
 approximately 0.193 ccnts/MM Btu of treated gas,
 Reference:  Mntldox, R. N. and Burns, M.  D., "Liquid
 Absorption-Oxidation Processes,"  Oil and Gas  Journal,
 Vol. 66, No. 23, p. 90-91,%(19G8).
Contributor: Power-Gas Ltd.
                                                                 Aoril 1973
                                                                  IlYDROCAKIlON PHOCKSSINO

-------
                                                A-10
                                                                                        Purified gas
 Start
                                     Reactors
Claus unit
tail gas
i
i

' i

i

t


1 i
i


', — C
                                                                                        A/V—I
                                                             Liquid sulfur
         Sulfrean
Application: Desulfurization of residue gas.
Charge: Glaus unit tail gas.
Products: Liquid sulfur.
Description: The process is essentially an extension  of
the Claus process, except that H2S and SO2 are made to
react at temperatures below the sulfur dew point of the
reaction gas mixture:
      2H-S + SO,	>  3S + 2H,0 + 35Kcal
  Since equilibrium  conversion  Becomes  more  complete
as  temperature  is lowered,  substantially  higher  sulfur
recovery is possible than in a normal Claus plant. The
reaction  takes place  in the presence  of a  catalyst, either
alumina  or special  activated  carbon.
  Sulfur formed is  adsorbed  on the catalyst  which
eventually  becomes  saturated,  requiring  periodic  regen-
eration  by  desorption of sulfur with hot gas.
  The process  reduces  entrained sulfur  to a  minimum,
as  the  catalyst  nets  as  a very effective  adsorbent  for
liquid sulfur. COS and CS, nre not affected.
  Unit  operation is  exceedingly simple and differs only
sli"htlv  from that of a Clans unit.  Since only solid  ad-
sorbents are  used and no liquids except sulfur  condense,
the process  is  free  of liquid  waste disposal  problems.
Sulfur produced  is bright yellow and of  99.9rc  purity.
   A unit may consist of throe reactors, two in adsorption
and one in desorption service. The mimbc.r of reactors is
determined strictly by economic considerations.  Desorp-
tion of  sulfur is effected by means of hot gas in a closed
cycle  Desorption sjas,  confining liquid  sulfur  is com-
bined with Uaus pi minced  sulfur. Since produced sulfur
 is  of the same quality  no product contamination exists.
    An  alternate of  the Sulfncn process  involving two-
                        Stage treatment can provide over-all recoveries exceeding
                        99%. A two-stage  Sulueen unit consists of two catalytic
                        beds in series. In the first bed H:S and SO8 form sulfur
                        according to the Claus reaction; however, the ratio of
                        HiS/SO- is adjusted in  such a manner that essentially
                        all of the SO2 is consumed and the effluent gas contains
                        only H2S. After addition of air to the first stage effluent,
                        H2S is oxidized directly to sulfur in the second  stage.
                          With a 95%  conversion in the Claus  plant and  COS
                        and CS. content reducing the yield by 0.5%, an over-all
                        yield around  99$> (or higher with  the alternate)  can
                        be  obtained, with  either catalyst.
                        Operating conditions: As  all processes  based  on  the
                        Claus  reaction, a  control with  an  optimizer  of  the
                        H-S/SOj ratio  is  required in the  reaction gas  mixture
                        at' or near the stoichiometric proportion of 2:1  for  op-
                        timum  results. Pressure drop through the  unit is in  the
                        order of 1.4-2 psi.  Catalyst life expected: at least 4 years.
                        Investment/operating costs: Use  of alumina catalyst
                        permits carbon  steel construction and gives a lower cost
                        for the unit.  Battery limits capital cost of a unit  for  a
                         1,000 Itpd sulfur  plant will  be around $2 million.
                         Utilities consumption will  be as follows:
                           Electricity—C50 Kwh
                           Boiler feed water—10 L.S. gpm
                           Fuel cas—0.55 MMsrfd                      .
                         Commercial installations: 2 onstream: One in France
                         (1.000-t/d  sulfur  plant)  and one in Canada (4,000-t/d
                         sulfur ptonO. 3 in construction.
                         Reference* Guvot. G. and Martin. J. F.,  "The Sulfrcen
                         Process," Canadian NO PA, June II. 1971.
                         Licensor:  SNPA/I.urpi;  The R-  M. Parsons Co.. engi-
                         neering.
 HVOROCARHON PROCESSING
April  1973

-------
                                          APPENDIX  B
                       DETAILED DESCRIPTION OP MINOR  (LESSER KNOWN]
                                     H2S REMOVAL PROCESSES
                    Absorber
Stripper
Solvent  Dryer
                      Treated gas
Start
                                                 es
                                                                                          (\\  »   Steam
                                                                                          \L*  *
         Purlsol
Application: Removal of acid  gases from  syngas and
natural gas streams using physical absorption in N-Methyl-
Pyrrolidone (NMP)..Three typical applications for high
pressure gases:

  (1) Removal of high contents to low residual level,

  (2) Bulk removal of acedic components down to mod-
erate product purity using a simplified flash regenerator
system,

  (3) Selective removal of H2S.

Process description:  (Case 1,  above)  cooled  raw gas
saturated with  water  vapor enters the CO2 absorber
where it is dehydrated with rich NMP and then washed
with regenerated NMP. Entrained NMP  is removed from
treated gas by water wash.
  Rich solvent is  first  regenerated by two-stage flashing
to atmospheric  pressure. Co-absorbed H2  and CO  are
degassed at  relatively  high pressure  and  recomprcsscd
into raw gas. Residual  CO2 is removed from NMP by air
or waste nitrogen stripping. COi and stripped  gas  are
diu-lt.trgcd via water wash.
  .The  solvent drier is fed with NMP/water mixtures
fiorh dehydration  and  water wash sections  and separates
water and NMP  by distillation  with  surplus water dis-
charged from the  top  with  the off-gas and dried NMP
from tlic bottom.  This column also removes  NMP from
off-gav from  (he second flash stage.
  Operating conditions!

  Feed conditions:
    Flow
    Pressure
    Temperature
      100 MMscfd
    1,070 psig
      110°F
  Analyses:
                             Feed        Treated gas
    H,, % vol.	64.53          96.44
    CO,,  %  vol	33.15           0.10
    CO, %  vol	 1.50           2.24
    C,, % vol	0.44           0.59
    N, + Ar,9feVol	0.38           0.63

  Utilities:

    El. power, at the shaft	•	'... 2,100 kW
    (without power recovery)
    Steam, 45 psig, sat'd	1.7  t/hr.
    Cooling water, 75° F	300 m'/hr.
    Condensate	1.3  t/hr.
    NMP cxcl. leakage	3 kg/hr.

  Commercial Installations: 4 plants with a total  thruput
  of 420  MMscfd are in  operation; 2 for high pressure
  hydrogen manufacture, 2 lor natural gas treating.

  Reference: Ilochgcsand, G., "Rcctisol and Purisol,"
  Industrial  and Engineering  Chemistry, Vol. 62  (1970),
  No. 7, p. 37/43.

  Licensor: Lurgi Mincraloltechnik GmbH.
                                                                 April  1973
                             HvoRocARnoN  PROCESSING

-------
                                  B-2
        SOUR  GAS
        IN
    WATER
REGENERATION
            AIR
                      REGENERATION
                        STREAM
            SWEET
              *>
            GAS OUT
              FIGURE B-2.   TYPICAL  IRON  OXIDE PROCESS FLOW SHEET
              (Courtesy: Campbell Petroleum  Series  and Dr. R. N. Maddox)
                          IRON OXIDE  (SPONGE) PROCESS
Application;
  Removal of H2S from gases using the  solid  bed reaction of H_S with iron
  oxide (Fe~0_).  The reaction is regenerative.
                                             3, + gH90
                                             D, + 6S
                          ^  J      L          £  J
Process Description:
  A typical flow scheme using  two  towers  is  shown above.  The use of more than
  two towers is possible.  In  a  2-tower process, one of the towers wouJd be on
  stream removing H?S  from the sour gas while  the second tower would either be in
  a regenerative cycle or  having the  iron sponge bed replaced.  Both continuous
  and periodic regeneration  are  used.  A  bed  is discarded when the H»S content of
  sweet gas is unacceptable.   The  system  is most suitable for low H S concen-
  trations  and/or low  gas  rates  and will  operate satisfactorily at low pres-
  sures.  For certain  applications, capital costs about 1/4 of MES system
  costs.

-------

                                   B-3
 Operating Conditions:
   Feed  Conditions:
     Flow.  No minimum  flow
     Pressure.  Any  pressure
     Temperature.  About 80° F

 Commercial Installations;
   More  than 200 units  are  in use in the U.S.

 Reference;                                .                                            ••
   Maddox, R.  N. ,  Gas and Liquid Sweetening, John M.  Campbell Co.,  Norman,
   Oklahoma 73069  (1974).
•.••
 Manufacturers:
   (1)  National  Tank Company,  Tulsa,  Oklahoma
   (2)  Fish Engineering and Construction,  Inc.

 The process is  nonproprietory.

-------
                        Absorber
                                                 B-4
             Flash  Drums
             Treated  gos
    Start
           Feed gas  ,
                                    Recycle gos
                                  Lean solvent
                              Rich
                              solvent
                                   H
                                                                                            To
                                                                            •Expansion^  Pump
                                                                               turbine   dnve
                                         Acid gas
                 I
                                    I  ^J
                                    /—"\X5Tb pump drive
                                 Hydraulic  turbine
         Fluor  Solvent
Application: For the removal of high concentrations of
acidic impurities, CO2, and H2S, from natural or synthetic
gas streams.

Product: Plant  designs are tailored to meet the purity
levels of COa and H2S needed in each specific situation.

Description: The Fluor Solvent Process employs an  an-
hydrous  organic compound, propylene carbonate, to re-
move COj and H2S from natural gas streams. The use of
this high capacity solvent, which absorbs acid gas by physi-
cal solution, permits solvent regeneration simply by pres-
sure letdown of  the rich solvent, usually without the  ap-
plication of heat.
  In general, this process is best suited for cases where the
combined CO2 plus H2S partial pressure in the feed  gas
is high, about 75 psi or higher. In addition, the use of  this
process is favored by low heavy hydrocarbon content.
  The processing arrangement selected for any particular
installation will depend  upon a number  of factors. These
include  the degree of purification  required for both COj
and H8S, concentration of both CO, and JIjS in the feed
gas, operating pressure, etc. Since solvent carrying capac-
ity is increased at reduced  temperatures, solvent  tempera-
tures below ambient are usually used to cut circulation
rate to a minimum. Often,  the expansion of the acidic
constituents through the plant furnishes sufficient free re-
frigeration to make this possible. At other times it has been
found advantageous to install auxiliary refrigeration facili-
ties to permit lower circulation rates with attendant reduc-
tion in equipment sizes. Split-stream schemes can be ap-
plied  to certain situations and other techniques may be
applied  to assure  the production of sales gas containing
0.25 grain H2S/100 scf. At other times simple atmospheric
flashing or vacuum flashing will be the preferred method
of solvent regeneration. Hydraulic turbines in  the rich
solvent,  and gas expansion  turbines on flash gas streams
separated at intermediate pressures, are common items in
Fluor Solvent plants. Both  these devices conserve energy
and reduce requirement for outside refrigeration.
  Extended  operation of this process over a 12-year pe-
riod has demonstrated conclusively that solvent reclaimers
are unnecessary. The solvent breakdown rate is virtually
nil. Several plants have demonstrated total  solvent losses
of 1 pound  per million standard cubic feet of feed gas,
other  plants  have demonstrated even lower losses.
  Sidestrcam .distillation or other special equipment for
water elimination is not required. By proper process de-
sign, water content of the solvent is kept at 1 percent or
below. Carbon steel is a suitable  material of construction
for all equipment  and piping in this process.

Commercial installations: The process is now in use
in a total of 10 plnnts, 7 on natural gas, 1 in  ammonia
production and 2  in hydrogen  production.

Reference:  Buckingham,  P. A.  "Fluor Solvent  Process
Plants: How They Arc Working," Hydrocarbon Process-
ing, Vol. 43, No. 4, 113-116, (1964).

Licensor: Fluor Engineers and Constructors, Inc.
              PROCESSING      April 1973

-------
                                              B-5
          Purified  gas
Absorber
Start lmpure gas »

K<

/N
T


I ^-X
L
* ,t

Steam
-r


                                                                                    kSulfur
                                                                                               Air
                             Rich  solution
                                   Heater
         Giarnmarco  Vetrocoke—sulfur
Application: For  the  continuous removal of hydrogen
sulfide from natural gas or synthesis gases.

Description: The Giammarco Vetrocoke (H*S) process
for the removal of H2S continuously scrubs sour gas with
an alkali arsenatcs and  arsenitcs solution. Sodium carbon-
ate, being relatively inexpensive, is the alkali  usually ap-
plied  for the removal of large quantities of sulfur. The
successive reactions occurring are:
3 //,$ =
                                 , + 3 H,0
(1)
              f 3 Na.AsO. = 3 Na,AsO,S + Na.AiO,     (2)

               Na,AsO*S = HaiAiO, + S             (3)

                                    >.            (4)
  'Sour gas enters  the  base  of  the absorber column  at
pressures up to and above 75 ats. g., depending on well-
head gas conditions. A  counter/low stream of Vetrocoke
solution scrubs the II2S  to a level of 0.5 ppm or less. The
sweetened gas leaving tlic absorber is cooled to reduce the
Jrod on  the  downstream  dcln drat ion plant. The  con-
dr'iisatc-removed  takes with it most of the carryover. The
absorption  reaction, Equation  1,  gives rise  to  sodium
Ihioaiscnitc which has a low vapor pressure of H2S and
allows a high purity gas to be obtained by straight counter-
current absorption.
  The  lliioarscnite  former! is slowly converted to mono-
tliionrscn.ilc and arson itc by a "t-li^rstion reaction." Equa-
tion 2, which occurs in absorbrr and in  the  subsequent
 oxidizing column. The monothioarsenite formed has an
 even lower vapor pressure of H2S.
   Mono-thioarsenate, being more soluble, helps keep the
 sulfur in solution.
   The solution leaving the base of the absorber passes to
 an air-blown oxidizing column working at atmospheric
 pressure and around 40°C. This vessel is open to atmo-
 sphere at the top.  Under the oxidizing conditions, the
 mono-thioarsenate decomposes to arsenite and elemental
 sulfur. Elemental sulfur  is removed  overhead by froth
 flotation, vacuum filtered and washed. The oxidizing re-
 action also re-establishes  the original Vetrocoke solution
 balance by oxidizing some arsenite to arsenate.
 Operating conditions: The dual function of the oxidiz-
 ing tower limits the variation possible in the air flow to
 the oxidizer because flotation  process  would be impaired
 and a constant flow of solution to the absorber is possible
 only at constant air rates. It  is not practical  to control
 arsenate formation solely by the depth of solution aeration.
 A small amount of catalyst is added to promote and  con-
 trol arsenate formation. This also reduces oxidizer size.
 Commercial installations: Approximately 30.
 Economics:  Battery limits  capital cost  of a  100
 MNfscfd plant (in the United Kingdom) is approximately
 $600,000. This plant removes  II:S from inlet concentra-
 tion of 600 ppm to outlet of /a ppm.  Utility costs arc
 approximately 0.193 ccms/MM IJtu of treated gas.
 Reference:  Madclox, R.  N. and Burns, M. D., "Liquid
 Absorption-Oxidation Processes," Oil and  Gas Journal,
 Vol. 66, No. 23, p. 90-91, (I'JGS).
Contributor: Power-Gas  Ltd.
                                                                 April 1973
                                                             IFVUftOCAUIlON PHOCKS.SINfi

-------
                                                  L-l

                                             APPENDIX C

                         DESCRIPTION  OF  SULFUR  PRODUCTION PROCESSES
Acid qas
(may contain 4

1 " ' **' Reutl
r
.Air ^
Jbf
Boiler feed
. water

ion
. i
r
| i Cond.
1
•M
Reheat
— CD
I '
(1st Stage A
converterj



t -
1

i

i




fiCond.



1


[ .



Reheat
i
| 2nd Stage]
^ converterj







1
1



;


JCond
'

k


Reheat
(


J
1
'

T(
;3rd Stage ]
converterj

|
1






Cond.
•

\








1

\

) incinerator/stack
To Beavon sulfur
removal unit
Steam


• \
Liqt
Sulfur
transfer
pumpQ
Sulfur pit II
CD-
jid sulfi

         Claus
Application:  Conversion  of hydrogen  sulfide to high
purity sulfur.

Feedstock:  Hydrogen sulfide gas streams  from gas pro-
cessing and  refinery operations.

Product: High purity elemental sulfur.

Description: The hydrogen sulfide containing acid  gas
stream, which may originate in a conventional amine unit
or similar process, is fed to a  reaction furnace where it
is 'burned with sufficient air to satisfy the stoichiometry of
the Glaus reaction.  The hot reaction gases are cooled in
the steam generating section of the reaction  furnace and
then further cooled in  the first condenser where  sulfur
produced  in  the  reaction  furnace  is removed. After re-
heating, the  gases enter the first catalytic converter  where
additional sulfur  is formed, which is condensed  in  the
second condenser. In the process  shown  three catalytic
conversion stages are used. However,  in some cases it
may be economical  to add a fourth stage,  Depending on
the hydrogen sulfide concentration in the acid gas  fed to
the unit, the number of catalytic stages and the quality of
the catalyst  used, conversion cITiricncics  of up to 98 per-
cent can be  attained.

   With proper modifications the  process  is suitable for
ihe treatment of acid  gases containing  hydrogen sulfide
over a  wide mngr of  concenirniions. In addition,  the
process c.\n be designed so that ilie presence of impurities,
                        such  as  hydrocarbons and ammonia, in  the  acid gas
                        stream has no harmful effect on  plant performance and
                        sulfur product quality. There are many units in operation
                        which process refinery gas streams containing appreciable
                        amounts of ammonia. This feature is of particular impor-
                        tance in view  of pollution control  requirements which
                        necessitate essentially complete  removal of hydrogen sul-
                        fide from  all gaseous and liquid refinery streams and
                        conversion to elemental sulfur  before disposal as waste.

                           Under the conditions prevailing in  the reaction furnace,
                        formation of some carbonyl  sulfide  (COS) and carbon
                        disulfide (CS2)  is  inevitable if the  acid gas  contains
                        COa  and hydrocarbons. Although the amounts  of  COS
                        and CSa formed are relatively small, especially if the
                        hydrocarbon content of the acid gas is low, they are signifi-
                        cant as potential air pollutants. A special catalyst may be
Elaced in one or several of the catalytic converters to
                          irgely  hydrolyze COS and  CS2 to H2S and CO2, and
                        thus  to  prevent  these compounds from  escaping to the
                        atmosphere.  The modified process emphasizes maximum
                        conversion efficiency and  the highest degree of reliability
                        at low capital  investment and  operating costs. The high
                        conversion efficiency minimizes expenditures for tail gas
                        desulfurization.

                        Operating conditions: The  process  has been  applied
                        to acid  gas streams containing from 15  to 100 percent
                        H8S in capacities from 5 to 1,500 long tons per day. The
                        smallest  units are skidmounted.

                        Contributor: Ralph M. Parsons Co.
               PROCESSING
Apn!  1973

-------
          Contactor
                02
             Skim Tank



Sweet go







Sour
aas
17** •*






s
1
rS







1









-*"i























.


















Air













-— •
















-—- --^


1


















— -—





















, 	



i


^- —


1






=»_





OTMB
•*«^














X^>
"S









Alternate
sulfur

recovery
methods


























Filtration


Filtration and
autoclave


Centrifugotion


Centrifugotion
and heating






-*


-*


— M


1
-»J





Sulfur cake


Molten sulfur


Sulfur cake



Molten sulfur





                            Oxidize r
                Surge  Tank
         Stretford
Application: For the sweetening of natural and industrial
gases by the complete removal of hydrogen sulfide and the
partial removal of organic sulfur compounds.

Product: An H2S  content of 1  ppmv can be attained in
the treated gas at operating pressures through the range of
atmospheric to pipe line pressure. Sulfur of 99% purity can
be produced molten or as a cake. Particle sizes range from
0.5 to 25 microns. It has found use in agricultural insecti-
cides, plus all normal  commercial outlets for  elemental
sulfur.

Description: The gas is washed with an aqueous  solution
containing sodium carbonate,  sodium  vanadatc,  anthra-
quinonc disulfonic acid. The solution reaches an  equilib-
rium with  respect  to the CO2 in the gas and only rela-
tively small amounts of CO2 are removed by the  process.
Thus, the process represents an economic route for sweet-
ening a sour CO5 containing gas with  much less shink-
age than  that associated with aminc based processes.
  The sour gas is countcrcurrently washed with regener-
ated liquor. The hydrogen sulfide dissolves in the  alkaline
solution and is removed to any desired  level. The hydro-
sulfidc formed reacts with the 5-valcnt state vanadium and
is oxidixcd to elemental sulfur. The liquor is regenerated
by air blowing, and the reduced vanadium  is restored to
the 5-valcnt state through a  mechanism-involving oxTgcn
transfer via the ADA. ''The sulfur  is  removed  by froth
flotation and the scum  produced can be processed several
ways  depending on the desired end product, total sulfur
production, and utilities cost. For large sulfur production
                         rates, one or more stages of centrifuging followed by heat-
                         ing are often economic.  For lower sulfur capacities, simple
                         filtration of the sulfur scum may be used.

                         Operating conditions: The reactions upon  which this
                         process is based are essentially  insensitive to pressure.
                         Thus, complete removal of  H2S is  attained equally at a
                         few inches of pressure as well  as at the  1,000-psig level.
                         Operating temperatures throughout the  unit  are  in the
                         range of  ambient to 120° F and result  in an operating
                         environment remarkabiy free of corrosion tendencies.

                         Investment: Process factors affecting investment cost in-
                         clude: operating pressure, HSS content of feed gas, and
                         disposition of sulfur product. The onplot  investment for a
                         battery limits unit processing 15 MMscfd of natural gas
                         at 30 psig, and reducing its  HSS content  from 200 grains
                         per  100 scf to ;4  grain per 100 scf will be $600,000-$7QO,-
                         000 on a West  Coast basis. CO, content of this  raw
                         natural gas is 6 vol. % and remains in treated gas product.
                         Produced sulfur is discharged as a damp cake for disposal
                         at no value.

                         Commercial Installations: 55 Stretford units are cur-
                         rently in operation,  with capacities  ranging from  100
                         Mscfd to 90 MMscfd.

                         Reference: Ellwood, P.,  "Mcta-Vanadatcs Scrub Manu-
                         factured Gas." Chemical  Engineering, Vol. 71, No.  15,
                         July 20, p. 128-130,  (1964).

                         Licensor. International Consultancy Sen-ices, British Gas
                         Corp.
 HvimOCARIJON PROCESSING
April  1973

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                                                 D-l
                                            APPENDIX  D
                          DESCRIPTION OF TAIL GAS CLEANUP  PROCESSES
                    Reactor
               Stretford
               Absorber   Oxidizer
Filter
Sulfur
Melter
  Start.
        Sulfur plant
        toil gas
Hydrogenated
cooled tail gas
to  h^S recovery
                                                                                    Liquor     .Sulfur
                                                                                    return
         Beavon
Appllcationi Purification of sulfur plant tail gas to meet
air pollution standards.

Feed: Tail gas from Glaus sulfur recovery unit.

Description: In the first portion of the process, all sulfur
compounds in the  Glaus tail gas (SO2, Sx, COS,  CSa)
are converted to H2S.  The tail gas is heated to reaction
temperature by mixing with the hot combustion products
of fuel gas and air. This combustion may be carried out
with a deficiency of air if the  tail gas  docs not contain
sufficient H2 and CO  to reduce all of the SO, and S, to
HjS. The heated gas  mixture  is then  passed through a
catalyst bed in which all sulfur compounds are converted
to H2S by hydrpgenation and hydrolysis. The hydrogen-
ated gas stream is cooled by direct contact with a slightly
alkaline buffer solution before entering  the  HSS removal
portion of the process.

  The Stretford Processes then used to remove H2S from
the hydrogenated tail  gas. This process involves absorp-
tion of the HL.S in an  oxidizing alkaline solution.  The
oxidizing agents  in  the solution convert the H2S to ele-
mental sulfur,  then are regenerated  by air oxidation,
which floats the sulfur off as a slurry.  This sulfur slurry
is then filtered, washed and melted  to  recover the Strct-
foi'd solution and produce a high-purity sulfur product.
                  Operating conditions: The pressure drop for the
                  treated gas is 2 to 3 psi; all pressures  are near atmos-
                  pheric. Operating temperatures  are 550 to  750° F for
                  the hydrogenation reactor and 70 to 120° F for the Stret-
                  ford section. Equipment is essentially all carbon steel. The
                  treated gas stream contains less than 100 ppm of'total
                  sulfur compounds and less than 10 ppm of H2S. Spent
                  oxidizer air is odorless,  since it contains only air  and
                  water vapor.
                  Economics: Based on a plant treating the tail gas from
                  a 100 It/d sulfur plant. Investment: $700,000 to $1  mil-
                  lion. Net utilities and chemical cost: $100 per day.
                  References: Beavon, D.  K. and  Vaell, R.  P.,  "The
                  Beavon  Sulfur Removal  Process  for  Purifying Glaus
                  Plant Tail Gas," 37th Mid-year  Meeting, API Division
                  of Refining,  New York, May  9, 1972.


                  Commercial installations:  Eight Bcnvon  Sulfur Re-
                  moval plants arc  currently being designed and  built  in
                  six locations in the United States and Japan.


                  licensor: Union Oil  Co. of California.
              PROCESSING       April  1973

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                                              D-2
tail gas

% sulfur recovery
from tail gas
Function
% of investment




H2S
S02
COS
CS2



. Stage IE
(optional)


i


Removes COS
and C$2


10


H2S
S02
w

1
Stage I 1 _ Staae H

•
50
Recovers elemental S
and converts all S02
S some HgS to sulfur
50
(Stretford)
1
j^s s



50
Converts H2S to S
40


Gas discharge
200 ppmv
S as S02
         Cleanair
Application: Recovers 99.9% of the sulfur from Glaus
plant tail gas,  leaving no more than 200 ppmv SOa
equivalent in the effluent.

Produ:t: Sulfur produced is typically 99.5% pure elemen-
tal  sulfur,  but  can be guaranteed  to be  99.9% pure,
based on total pit  production. The sulfur  is suitable for
any ultimate use.

Description: The  process is used to convert sulfur con-
stituents in Clans  plant  tail  gas to molten  elemental
sulfur. It is  installed  upstream  of the incinerator in a
conventional Claus plant, and  may preclude the need
for  incineration.  The process consists  of  three stages
installed stcpwisc to achieve decreasing amounts of sulfur
emitted to the atmosphere. Levels of not more than 200
ppmv SO2 equivalent in  the  effluent can be guaranteed.
The system may be installed on old Claus plants or on
new Claus  plants,  but is somewhat  more expensive on
old Claus systems.
   From a space standpoint,  the process .requires about
the same amount of plot plan as a dual-train Claus plant.
From an operating standpoint, the plant requires about  6
 hours per 24 houis of operation. Other requirements per
 daily ton of sulfur produced  in the Claus  plant arc:  8
 pounds of strani per hour,  4 Kwh per hour, 9 gpm of
 water for cooling, and 10-25 cents per day for chemicals.
  Stage one of the process removes  the  sulfur dioxide,
stage two removes the hydrogen sulfide, and stage three
removes the COS and the CSS.

Economics: With a. given  amount of gas flow,  which
would  result from a Claus plant being fed a  constant
amount of feed, the process plant cost is somewhat sensi-
tive to the amount of sulfur being handled. Therefore, a
unit for a Claus plant operating at a low efficiency is more
expensive than one operating at a high efficiency. Taking,
as an arbitrary number, a Claus plant operating at 95%
efficiency, CLEANAIR process facilities can be provided
for a 10-ton per day Claus plant for about $500,000. For
a  1,000-ton-per-day Claus plant, this would be  about $3
million.

Commercial installations:  The  first commercial  in-
stallation was made at the Gulf Oil  Corp.  refinery  at
Philadelphia.This plant is guaranteed to provide a cleanup
as low as 300 ppmv of sulfur dioxide equivalent. Several
other CLEANAIR plants arc in various stages of engi-
neering and construction.

Reference: Proceedings of the 51st Annual Convention,
Natural Gas Processors Association, April 10-12, 1972,
New Orleans, La.

Licensor: J. F. Pritchard and Co.
                                                                          1973
                            HYDHOCARMON PKOCP.S.MNG

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           To stock      Fue'
                                                 D-3
     Ammonia scrubber
->K«» S"  ~S
                                       NH3
                                     make-up
I    /O^NH3recycle

    H^S-containing gas
                                                  Catalytic
                                                   reactor
                                                                                              Solvent
           Thermal
           catalytic
           incinerator
            Fuel
            gas
  Ammoniacal
     brine       Sulfite
             evaporator
               and  S02
           regenerator
                                                     so
                                            S05
                                                        4    Sulfato
                                                              reducer
 Application:  1. Removal of H2S and SO2 from Glaus
 unit tail gas to an SOa level of 1,500-2,000 ppm (IFP-1)
 or 500 ppm or below (IFP-2). 2. Stack gas clean-up to
 take SQa down to or below 500 ppm.  (IFP-2).

 Feed:. Tail gas from 1,  2 or  3-reactor Glaus plants or
 stack gas, as appropriate.

 Product: Bright yellow sulfur, 99.9% pure, with 150 ppm
 max. ash and  150 ppm max.  organic impurities.

 Description. IFP-1 (not  illustrated):  Glaus tail gas is in-
 jected into a  packed  tower and contacted contercurrent
 with solvent containing catalyst. Sulfur is formed, collected
 and removed  from bottom of the tower. Operating  tem-
 peratures in  the tower range  from 250 to  280 ° F. No
 booster blower on  Glaus  tail gas is required due  to  low
 pressure drop  design of tower. IFP-2 (illustrated): Glaus
 tail gas after  incineration is scrubbed with  aqueous
 ammonia. Clean overhead is incinerated and vented up the
 stack.  Brine  containing sulfites,  bisulfitrs and  small
 amounts of sulfatcs from  the scrubber is evaporated;  sul-
 fairs :iro reduced, and mixed SO2/NH3 overheads arc in-
 j'Xfc'd  into the bottom of tlic contactor. An IItS slipstream
.is also fed to tlic bottom  of the contactor along with the
 SQj stream.  Solvent  containing  catalyst is  circulated
.coiinlercurrcnt to the gas  flow.  Operating temperature in
 tlic contactor ranges from  250 to 280°  F.  Sulfur is
 formed,  collected  and removed from  the  bottom  of  the
                                  tower. Ammonia is removed overhead and returned to the
                                  scrubber.

                                  Operating conditions: The solvent temperature to the
                                  packed tower ranges from 250 to 280°F. The most im-
                                  portant variable in the process is the  ratio of HjS/SO3
                                  in the feed to the packed tower. This ratio is held within
                                  a given range by  appropriate analyzer-controller equip-
                                  ment.

                                  Economics: An  IFP-1 unit  for an  over-all recovery of
                                  99% for use with a 1,400-T/d Glaus plant that recovers
                                  96.5% sulfur requires a battery limits investment of $2
                                  million. Operating costs are: utilities—$30/d;  catalyst
                                  and solvent—$347/d. Investment for  a 200-T/d IFP-1
                                  plant is of the order of $450,000. An IFP-2 plant added
                                  on to a 250-T/d Glaus @ 95% recovery requires a bat-
                                  tery limits investment of $800,000. Operating costs  are:
                                  utilities—$70/d; catalyst and solvent—$5/d.

                                  Commercial Installations: IFP-1: Seven operating, five
                                  under  construction for Glaus plants with capacities from
                                  5 to 2,400 T/d, totalling 4,000 T/d. IFP-2: One plant
                                  operating  and one under construction.

                                  Reference: Bonnifay, P. et al, "Partial and Total Sulfur
                                  Recovery,"  Chemical  Engineering  Progress,  Vol.  68,
                                  No.  8, pp. 51-52, August 1972.

                                  Lkensor:  Institnt Francois du Pctrolc.
 HYLWOCARHON PROCESSING
         April 1973

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                                                D-4
                                 Reactor
                                Cooling  Tower
              Reducing gas
                                                                                    To Clous Unit
                                                                                       incinerator
Start
      Claus Unit
      off-gas
n



n

W^

I

1
?'


Condensote to
n

^
^ Lean amine

Fat amine to
sour woter stripper | regenerator
         Shell  Glaus  off-gas  treating  (SCOT)
Application: To increase the sulfur recovery efficiency of
Claus units from the usual level of about 95% to more
than 99.8%.

Description: The process essentially consists of a reduc-
tion section and an alkanolamine absorption section.
  In the reduction section all sulfur compounds and  free
sulfur present in non-incinerated Claus off-gas are com-
pletely converted  into H2S over a cobalt/molybdenum
catalyst  at 300° C in  the presence of H2 or a mixture of
HJ and  CO. Reducing gas  can be supplied from an out-
side source, or a suitable reducing gas can be  generated
by substoichiometric combustion in the direct heater. This
heater is required in  any case for heating process gas to
the reactor inlet temperature. Reactor effluent is cooled
subsequently in a heat exchanger  and a  cooling tower.
Water vapor in the process gas is  condensed,  and con-
dcnsate  is sent to a sour water stripper.
  Cooled gas, normally containing up to 3% vol. HjS and
up to 20% vol. CO., is countercurrently washed with an
alkanolamine solution in an absorption column specially
designed to absorb almost all II:S but relatively little CO:.
Thc~ treated gas from the absorption column, which con-
tains only traces of H;S, is burned in a  standard Claus
incinerator.
  Tlic concentrated II;S is  recovered from the rich absor-
bent solution in a  conventional stripper and is recycled to
the Claus unit.

Operating conditions: Tin: process has a high flexibility
to cope  with variations in Ci.ius plant operation; changes
                                   in the Claus off-gas composition have only a small effect
                                   on over-all sulfur recovery efficiency. Feed gas rates from
                                   20 to 100 % of design can be handled easily. No secondary
                                   waste streams are produced.
                                     Units are designed for minimum pressure drop so that
                                   they can be added easily to existing Claus units.

                                   Economics: Basis: Unit for a Claus unit 250 t/sd sulfur
                                   intake and a Claus unit sulfur recovery of 94%.

                                   Utilities:                                    .   . .
                                     Boiler  feed water  	5,500 Ib/h
                                     LP steam (50 psig) 	6,400 Ib/h
                                     Electricity	 350 kW
                                     Fuel gas (LHV 19,800 Btu/lb)	  230 Ib/h
                                     Reducing gas (expressed in equivalent pure II:)...   53 Ib/h
                                     Operating data:
                                       Labor	f	1/6 operator/shift
                                       Maintenance	  2% on capital
                                   Capital investment varies between 70 and  100%  of the
                                   capital for the preceding Claus unit.

                                   Commercial Installations: Several units ranging in size
                                   from 10 to 2,100 t/sd equivalent Claus plant capacity arc
                                   in various stages of planning, design and construction.

                                   Reference: Petroleum and Petrochemical International,
                                   Vol. 12, No. 9, September 1972, pp. 54-53.

                                   Licensing inquiries:  Shell Development  Co.,  Houston
                                   (USA), Nihoii Shell  Gijutsu K.K.,  Tokyo (Japan and
                                   Far East), Shell Internationale Research Mij. D.V., The
                                   Hague (rest of world).
                                                                  April  1973
                                                                            PROCESSING

-------
                                                  D-5
                                                                                        Purified gas
 Start
Clous unit
tail gas
i
i

i

l
i

,

i
i



                                     Reactors
                                                                                        A/V—J
                                                             Liquid sulfur
        Suifresn
Application: Desulfurization of residue  gas.
Charge: Clans unit tail gas.
Products: Liquid sulfur.
Description: The process  is essentially an  extension of
the Glaus process, except that H-S and SO, are made to
react at  temperatures below the sulfur dew point of the
reaction  gas mixture:
       2  H;S + SO2	>•  3 S + 2 H2O + 35 Kcal
  Since  equilibrium conversion  Becomes more complete
as  temperature is  lowered,  substantially  higher  sulfur
recovery is  possible than in a normal Glaus plant. The
reaction  takes place in the presence of a catalyst, either
alumina or special  activated carbon.
   Sulfur formed  is  adsorbed  on  the catalyst  which
eventually becomes  saturated,  requiring periodic  regen-
eration by dcsorption of sulfur with hot gas.
   The process reduces  entrained sulfur to a  minimum,
as' the catalyst nets as a very  effective  adsorbent  for
liquid sulfur. COS and CS, arc not affected.
 '•.; Unit  operation is exceedingly simple  and differs  only
slightly  from  that of a Clans unit. Since  only solid  ad-
sorbents arc used and no liquids except sulfur condense,
the process  is free of liquid  waste  disposal  problems.
Sulfur produced is bright  yellow and of P?.9fo  purity.
   A unit may  consist of three reactors, two in adsorption
and one in dcsorption service. The number of reactors is
determined strictly by  economic considerations.  Dcsorn-
 tion of sulfur is effected by means  of hot »ns  in a closed
cvcle. Dcsorption eras,  containing  liquid sulfur  is com-
 b'incd with Clans produced sulfur.  Since produced sulfur
 is  of  the- same quality no product  contamination exists.
   An alternate  of  the  Sulfrtcn process involving  two-
                        Stage treatment can provide over-all recoveries exceeding
                        99%. A two-sta<*e Sulfreen unit consists of two catalytic
                        beds in series.  In the first  bed H:S and SO, form sulfur
                        according to  the Glaus reaction; however, the ratio of
                        H"S/SO2 is adjusted in sur.h a  manner that essentially
                        all of the SO- is consumed and the effluent gas contains
                        only H2S. After addition of air to the first stage effluent,
                        H*S b oxidized directly to sulfur in the  second  stage.
                          With a 95% conversion in the Glaus  plant and COS
                        and CS, content reducing the yield by 0.5fo, an over-all
                        yield  around  99%  (or higher with the  alternate)  can
                        be  obtained,  with  either catalyst.
                        Operating conditions: As  all  processes  based  on  the
                        Clans  reaction, a  control with  an optimizer  of  the
                        H-.S/SO. ratio is  required in the  reaction gas mixture
                        at"or near the stoichiomctric proportion  of 2:1  for  op-
                        timum  results. Pressure drop through  the unit is in  the
                        order of 1.4-2 psi. Catalyst life expected: at least 4 years.
                        Investment/operating  costs:  Use of alumina  catalyst
                        penults carbon steel construction and gives a lower cost
                        for the unit.  Battery limits capital cost  of a unit for a
                         1,000 Hpd sulfur plant will  be around $2 million.
                        Utilities consumption will be as follows:
                           Electricity—G30 Kwh
                           Boiler feed water—10 U.S. m
                           Fuel itas—0.35 MMscfd                  _    .  „
                         Commercial  Installations:  2 onstrcam: One in Fnnrc
                         (1,000-t/cl sulfur  plant)  and otu- m Canada (-l.UUU-t/d
                         sulfur plant). 3 in construction.
                         Reference: Cuyot. G. and Marlm, J. F, "The biilfrrcn
                         Process," Can.uli'an NGPA, June 11. 1971.
                         Licensor: SXPA/Lurgi;  The R.  M.  Parsons Co.. engi-
                         neering.
 11YWUOC.VRUON PkOCK ? S1 NO
April  1973

-------
        Incinerator
Waste
 Heat
Boiler
   Claus Plant
   tail gas i	,
tort	«
            D-6
Quench b» Cos
Cooling Section
   SO?                Dissolving
Absorber  Evdporotor   Tonk

 Clean
   air

'/^
t
1 A-^
u

1
                                                                                                Product S02
                                                                                                recycled to
                                                                                                Claus  Plant
          W-LS02  recovery
 Application: Desulfurization of waste gas stream.

 Feed: Tail gas from Claus units.

 Products: Concentrated SO2 gas suitable for recycle to
 Claus units or for further processing, e.g.,  to sulfuric acid.

 Description: Tail gas from Claus sulfur units is  first
 incinerated to convert all of the sulfur compounds origi-
 nally present  (H2S, COS, CS,, etc.) to SO,. The hot gases
 are  cooled in a waste heat boiler, then  quenched  and
 fed to the SO- absorber.
   The absorber is fed a lean  solution  of sodium sulfite
 which absorbs the SO; by reacting with  it to form sodium
 bisulfite. The  clean  gases  pass  to the stack, while the
 rich bisulfite  solution is fed to an evaporator/crystallizer
 regeneration system. SO2 and water vapor pass overhead
 from the  evaporator to a  condenser. A knockout drum
 separates  condensed  water for return  to the absorbent
 dissolving tank and the product stream of concentrated,
 saturated  SO; is piped back to the Claus plant feed or to
 other processing.
   A stream of slurry is withdrawn from  the evaporator
 and the sulfite crystals are redissolvcd to produce the
 lean solution  for recycle to the absorber. The evaporator
 can  be designed  to use very low pressure exhaust steam
 •(iO-lJ psig}  as a heat supply.
   A typkul SO-: recovery system for Claus  units producing
 about 400 hpd of sulfur is designed to  treat -1-2,000 scfm
                              of tail gas with initial SO2 content in the range of 10,000
                              to 13,000 ppmv (1-1.3%, vol.). Effluents levels less than
                              100 ppmv SO2 in  the stack  gas have  been  consistently
                              achieved in commercial installations.

                              Yields: Sulfur oxide  emissions in effluent stack  gas can
                              be reduced by as much as 99%. The product stream for
                              recycle is 90-95% SO2.

                              Economics: Investment for adding a SO2 recovery system
                              onto a typical existing 200-ltpd Glaus unit is about $1.6
                              million (absorber and following).

                              Typical requirements:

                              Steam—High-pressure, produced         19,000 Ib./hr.
                                    Low-pressure consumed           14,000 Ib./hr.
                                    Net for export                     5,000 Ib./hr.
                              Connected H.P.                           300
                              Cooling water                           1,000 Ib./hr.
                              Caustic make-up (100% NaOH basis)          1 tpd

                              Commercial installations: Five in operation; eight under
                              construction or being engineered. Two of these treat Clans
                              plant tail gns: one from three 150-ltpd units at Standard
                              Oil of California's El Scgundo, Calif., refinery, and an-
                              other  used for two 200-ltpd  units at the Toa  Nenryo
                              Kogyo K.K.  refinery in Kawasaki, Japan.

                              Licensor: Wellman-Power Gas, Inc.
                                                                 April  '973
                                                        HYDROCARBON PROCESSJNO

-------
                                  E-l
                              APPENDIX E
              DETAILS OF PLANT AND FIELD VISITS AND SAMPLE
         OF QUESTIONNAIRE SENT OUT FOR SOLICITING INFORMATION
          Visits were made  to  the  companies and  the State Air Pollution
 Control  Agency  listed in Table E-l.  The persons visited and a brief
 description  of  the nature of the visit are also  presented in the table.
          In addition to these visits, numerous  (telephone) conversations
 were  held with  many  industry experts in various  areas.  These experts
 are  listed in Appendix F.   Everyone of these experts were very helpful
 in providing without hesitation the information  sought.  Such informa-
. tion  was quite  useful in making this report accurate and current.

                 Details of the Questionnaire Sent Out

          Copies of  the questionnaire presented  on pages E-3 and E-4 were
 mailed to the following:  (1) Exxon Company USA  (Production Depart-
 ment) Houston,  Texas and (2) The Texas Mid Continent Oil Gas Association;
 the  former provided  helpful oral answers while the latter organiza-
 tion  provided an excellent  compilation of written answers to every
 question.  This computation has been the source  of much useful informa-
 tion  base for this BCL report.

-------
                                  TABLE E-l.   DETAILS  OF  PLANTS  AND FIELD VISITS
        Name of Plant/
       Field Visited and
         Date of Visit
               Persons Visited With
               and Nature of  Visit
    Name of Person(s)
  Visiting from BCL/EPA
Shell Oil Company
Bryans Mill Processing Plant
Bryans Mill, Texas
March 9, 1974
Texas Air Control Board
Austin, Texas
March 10, 1974
Exxon Company USA
Production Department
New Orleans, La.
April 28, 1974
Exxon's Jay Field Gas
Processing Facilities
Pensacola, Florida
April 29, 1974
Mr. Kenneth H. Rhoads
    Chief, Gas Plant Engineering
Mr. John Flynn
    Process Engineer
Discussed methods of H2S recovery, etc., and
visited Glaus plant, and gas processing plant

Mr. Charles R. Barden
    Executive Director
Mr. Steve Spaw
    Director, Permits & Inventory Division
Mr. Samuel Crowther
    Engineer
Discussion of the extent of the S02 emissions
and control problems related to oil and gas
processing

Mr. Charles Hagemeier
    Senior Technical Advisor
Mr. Carl T. Hester
    Environmental Coordinator
Discussion of Exxon's Jay Field facilities
and reinjection as a means of control etc.

Mr. John Barry Chambers
    Senior Engineer
Plant visit and discussions
Keshava S. Murthy, BCL
Keshava S. Murthy, BCL
                                                                                                                    S3
Charles B. Sedman, EPA
Keshava S. Murthy, BCL
Charles B. Sedman, EPA
Keshava S. Murthy, BCL

-------
                                 E-3
        Information Requested by Battelle for the Preparation of
            a Document to Assist USEPA in Setting Performance
                Standards for Oil and Gas Producing and
                          Processing Facilities
NOTE;   The purpose of this information gathering is to get the opinion
        of the industry experts.  The answers need not be typed or
        formal.  These answers will not be held against anyone as legal.
        They will be kept as strictly confidential or destroyed if you
        so desire.  Therefore, feel free to provide factual and critical
        opinions and support your opinion on solid data wherever possible.
Question 1:
Question 2:
Question 3:
Question 4:
There are thousands of small gas producers/processors.
The sour gas produced by small operations is usually
treated in a conventional amine process.  The spent
amine solution is regenerated and the ?. ^generator off-
gases are flared.  Some suggest that instead of the
current practice of flaring, the off-gases (mainly
H_S and CO.) can be relnjected to the well formations.

a.  Do you agree that this is possible?
b.  If yes, can you provide details of operations
    that are currently reinjecting?
c.  If reinjection is not feasible, provide reasons
    why it is not feasible.
d.  Define problems (corrosion, etc.) If reinjection
    Is followed.

e.  In summary, please provide sufficient factual
    Information that would assist in forming definitive
    conclusions about the feasibility or otherwise
    of reinjection as a method of avoiding SO.
    pollution from flares in small plants.

If reinjection discussed above is felt to be impractical
as a method of disposal of flares, what other methods
in your opinion are available as alternatives to flaring?
Define briefly the economic and technical merits of the
method suggested by you.

What, in your opinion, should be the cut off point at
which emission regulations for gas treating plants should
be applicable (or not applicable).  Justify you opinion
with technical and economic data.

The pipeline standard for H-S is I/A grain/100 scf.  Are
you aware of any similar limitations on the concentrations
of mercaptans (RSH), carbonyl sulfide (COS), and carbon
disulfide (CS-) by pipeline companies?  If so, what are the
standards and what is the basis for these established
standards?

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                                    E-4
Question 5:  Please provide the composition of your well head gas if
             available for H^S, CO., COS, RSH, total sulfur,  and
             hydrocarbons.  (The well need not be identified  by name
             or location If you wish to preserve secrecy.)

Question 6:  List all problems (present and potential)  that small and
             large gas processors will face if SO. emission regulations
             on processing plants are enacted at levels you consider
             to be uneconomic.

Question 7:  Please provide a material balance flowsheet of the
             desulfurizatlon plant for large natural gas plants you
             currently use.  The flowsheet can be for any of  the
             following: sulfinol, DEA, SNPA-DEA, MEA, Stretford
             ADA/Vandate, Giammarco-Vetricoke, DGA or Econamine or
             hot carbonate.

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                                 F-l

                             APPENDIX F

                LIST OF INDUSTRY AND OTHER PERSONNEL
                  CONTACTED BY TELEPHONE AND VISITS
                      Mr.  Elmer Berlie
                      Vice President
                      Western Research and Development  Company
                      932, 700-6th Avenue
                      Southwest,  Calgary,  Alberta,  Canada
                      (403) 263-1253

                      Mr.  James C. Bouldin
                      Director
                      Rail Road Commission of  Texas
                      Oil  and Gas Division
                      Earnest 0.  Thompson  Building
                      Teuth and Colorado Streets
                      Austin,  Texas  78701
                      Miss Ailleen Cantrell
                      Director of Editorial Surveys
                      The Oil and Gas Journal
                      Petroleum Publishing Company
                      211 South Chayanne Street
                      Tulsa, Oklahoma  74101
                      (918) 584-4411

                      Mr. L. E. Cardwell
                      Helium Analysis Group
                      U.  S. Bureau of Mines
                      Amarillo, Texas
                      (806) 376-2658

                      Mr. Samuel Crowther, P.E.*
                      Engineer
                      Permits & Inventory Division
                      Texas Air Control Board
                      8520 Shoal Creek Blvd.
                      Austin, Texas  78758

                      Mr. Jack C. Dingman
                      Jefferson Chemicals Company
                      Box 53300
                      Houston, Texas 77052
                      (713) 529-4471

                      Mr. Vincent R. Gurzo
                      Sales Engineer
                      Linde Molecular Sieve Products
                      Union Carbide Corporation
                      1300 Lakeside Avenue
                      Cleveland, Ohio 44114
                      (216) 621-4200
* Contact established by pen-onal visit:.

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                                   F-2
                      Mr. Charles E.  Hagemeier*
                      Senior Technical Advisor
                      Exxon Company,  U.S.A.
                      Post Office Box 60626
                      New Orleans, Louisiana 70160
                      (504) 527-3440

                      Mr. J. Douglas Harlan
                      Head, Natural Gas Liquids
                      Cities Service Oil Company
                      P. 0. Box 300
                      Tulsa, Oklahoma   74102
                       (918) 586-2211

                      Mr. Carl  T. Hester*
                      Environmental Coordinator
                      Exxon Company USA
                      P.O. Box  2180
                      Houston,  Texas   77001
                      (713) 221-3563

                      Mr.  E. G.  Hill
                      Director of  Research and Development
                      National Tank Company
                      Division of  Combustion  Engineering
                      P..  0. Drawer 1710
                      Tulsa, Oklahoma   74101
                       (918) 663-9100

                      Mr.  Richard  Jackson
                      Chief of Gas Engineering
                      Cities Service Oil Company
                      Oklahoma City, Oklahoma
                       (405) 236-0601


                      Mr. Earl Jairus
                      Manager of Sfclfur Programs
                      The Ralph M. Parson Company
                      617 West 7th Street
                      Los Angeles, California  90017
                      (213) 629-2484

                      Mr.  Gordon Koelling
                      Natural Gas  Division
                      U.S. Bureau  of Mines
                      Arlington, Virginia
                       (703) 557-0239
* Contact established by personal visit.

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                                  F-3
                     Mr.  Larkin Kyle
                     Chief Engineer of Mechanical Design
                     Gas  Engineering Office
                     Cities Service Gas Company
                     Oklahoma City, Oklahoma

                     Dr.  R. N. Maddox
                     Head, School of Chemical Engineering
                     Oklahoma State University
                     Stillwater, Oklahoma
                     (405) 372-6211, Ext. 7565

                     Donald H. McCrea
                     Manager, Process Development
                     Benfield Corporation
                     615 Washington Road
                     Pittsburg, Pa.  15228
                     (412) 344-8550


                     Mr.  Jack McWilliams
                     Division Environmental Coordinator
                     Ampco Production Company
                     Houston Division
                     500  Jefferson Building
                     P.  0.  Box 3092
                     Houston,  Texas  77001
                     (713)  227-4371

                     Mr.  Kenneth  H.  Rhoads  (John Flynn)
                     Chief,  Gas Plant Engineering
                     Exploration  and Production
                     Shell  Oil Company
                     Two  Shell Plaza
                     P. 0.  Box 2099
                     Houston,  Texas   77001
                     (713)  220-5446
* Contact established by personal visit.

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                                           G-l

                                       APPENDIX G

                                   CONVERSION FACTORS
To convert from Metric to English units, use  reciprocal  of  given factors.
   To Convert (English)

=1 .-tual cubic ft/tnin (acfm)
atmospheres (atm)
barrels of oil (bbl)
barrels of oil (bbl)
cubic feet (eft)
cubic feet, (eft)
cubic meters (cum)
°F
ft
ft/sec
gal/Mcf
8Pm
grains (gr)
grains (gr)
gr/scf
grains/100 scf
in.
in. H20
Ib -moles
Ib -moles /hr
Ib-moles/min
long ton (LT  - 2240  Ib)
pounds (Ib)
pounds /sq. in. (PS I)
pounds/sq.. in. (PSI)
ton (2000 Ib) /month
tons
     To (Metric)
cu.m/hr
kilogram/Cm2
kiloliters (kltr)
U.S. gallons
cubic meters (cum)
litres (1)
cubic feet (eft)
°C
meter (m)
m/sec
I/cum
1/min
1/min/m2
milligrams (rag)
pounds (Ib)
gm/m3
mg/s cu m
cm
mm Hg
gm-moles
gm-moles/min
gm-moles/sec
metric ton (MT)
grains (gr)
atmospheres (atm.)
kilogram/Cm2 (kg/cm )
metric ton/day (MT/D)
kilograms (kg)
           Multiply by
   1.70
   1.033
   0.159
  42
   0.02832
  28.32
  35.31
subtract 32 then multiply 0.5556
   0.305
   0.305
   0.^34
   3.79
  40.8
  64.8
   0.00014
   2.29
  22.9
   2,
   1
 454
   7.
   7
   1,
     54
     ,87
    .56
    .56
    .0084
7000
   0.068
   0.0703
   0.02926
 907.2

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                            APPENDIX H
                    HANDLING OF WASTE GAS WITH
                         HIGH H2S CONTENT
                (Courtesy of Mr. Jack McWilliams,
      Mid-Continent Oil § Gas Association, Dallas, Texas)
          The corrosivity of waste gases containing hydrogen sulfide can
vary considerably due to the gas composition, temperature, pressure, moisture
or water content, velocities, etc.  The selection of the proper metallurgy,
need for protective coatings or use of inhibitors or neutralizers can best
be made when the above conditions can be accurately defined.
          Some general guidelines for handling these waste gases are listed
below.
          (1)  You will not have corrosion if moisture is not present.
               However, it is not safe to assume that because dehydra-
               tion facilities are installed that 'he gas will be kept
               dry at the operating conditions.   Uehydrators are
               notorious for having malfunctions resulting in some
               moisture or water to get into the line.  It quite
               often takes a considerable amount of time before this
               moisture is reabsorbed into dry gas.
          (2)  Hydrogen sulfide can form a liquid at moderate
               temperatures and pressures.  At approximately 1000
               psi and ambient temperature, some mixtures of H?S and
               natural gas will contain liquid rich in H^S.
          (3)  In field operations even when very high concentrations
               of H_S are present, corrosion rates are relatively low.
               The reason for this is not known; however, it is
               partly due to (1) the poisonous and corrosive nature
               of H S results in a high degree of awareness and
               effort on the part of all personnel to assure that
               corrosion mitigation and monitoring programs are
               rigidly followed; (2) sulfur or iron sulfide may form
               a very tough protective scale on the steel which
               minimizes corrosion.
          (4)  It is important that velocities be kept as low as
               possible since high velocities (particularly when any
               liquids or abrasive materials such as sand or scale
               particles are present) tend to remove any protective
               film or scale buildup and cause corrosion reactions
               to proceed at a high rate.

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                      H-2
(5)  The formation of iron sulfide can cause plugging
     of the formation you are injecting into as well as
     causing corrosion.   It should also be noted that
     iron sulfide upon exposure to air rapidly oxidizes to
     iron oxide.
(6)  Hydrogen sulfide or other corrosion can cause hydrogen
     blistering or embrittlement (stress cracking) to take
     place depending on temperatures and pressures.  To
     prevent this, metals below Rockwell "C" hardness of
     22 are used in this type service.  In wells handling
     streams containing H S, C-75 or softer tubing or casing
     are usually used.  It must be remembered that prior to
     the last few years, API Grades J, K, and N pipe had
     only a minimum yield but no maximum value.  Therefore
     manufacturers could substitute API Grade N or P grade
     pipe for J or K grade if the company so desired.  This
     could be disastrous if the higher strength steel is used
     in the well containing high H.S and a catalyst such as
     mentioned in Item 7 is used.   Instant failures in tubing
     couplings,  sucker rods have occurred under these condi-
     tions.
(7)  Any low pH material such as dissolved CCL, hydrochloric
     and other acids,  or arsenic compounds (rarely used
     acidizing inhibitors)  can act as a catalyst for stress
     corrosion and can cause rapid failure of highly stressed,
     high-strength steel.   For example, acidizing a well
     equipped with N-80  or P-105 tubing (Re above 22) that
     has been exposed  to high H S  concentrations can result in
     immediate tubular goods failures probably in the highly
     stressed couplings.
(8)  For steel tubing  and  line pipe it is generally necessary
     to use corrosion  inhibitors,  plastic coatings, or cement
     linings as  applicable  to prevent corrosion.  Most plastic
     coatings are not  effective :in very hJgh H-,8 and r.0?
     environments or high  temperatures and should be only used

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                       H-3
      after extensive testing or investigation based on
      similar operating conditions.   Cement linings are
      effective except that if the pH is below 5 to 5.5
      the cement will be dissolved by the acids formed.
      Oil or scale tends to form a protective coating on
      the cement and increase its acid tolerance to some
      degree.
 (9)   Copper and many copper alloys tend to corrode at
      extremely high rates in the presence of H-S.
(10)   High strength stainless steel tends to embrittle
      in high H_S concentrations.  Certain heat treated
      stainless steels with a low hardness are satisfactory.
      Monel and Inconel (although expensive) is an excellent
      material in a severely corrosive H^S service.
(11)   When designing any system, the conditions should be
      compared with similar systems in operation.   Also
      any potentially corrosive system installed should
      have corrosion monitors at key points.  These monitors
      such as corrosion coupons, electronic devices, etc.
      allow the corrosivity of the system to be measured.
      This will allow any changes to be made in corrosion
      mitigation programs prior to extensive damage occurring.
(12)   Attached is a reference that will be helpful  in designing
      a system.
(13)   All welds in piping used in high hydrogen sulfide system
      should be normalized (heat treated) or stress relieved
      prior to use to prevent sulfide stress cracking and
      galvanic corrosion between the weld metal and the steel.
      In mildly corrosive environments .the use of pre-heat
      and post-heat welding techniques are generally effec-
      tive.  This spreads out the heat affected zone and mini-
      mizes galvanic action.   This is discussed in  the attached
      material.

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                                      1-1

                                  APPENDIX I
                 LIST OH GLAUS PLANTS IN NATURAL GAS PROCESSING


       APPENDIX  I.  LIST OF GLAUS PLANTS IN NATURAL GAS PROCESSING
      State/Company/City, County
    Year
   Sulfur
 Production
  Started
  Sulfur      Sulfur
Production    Design
 in 1973     Capacity
 (MT/D)       (MT/D)
ALABAMA
  Humble Oil & Refining Co.
      Flomaton, Escambia
  Stauffer Chemical Co.
      LeMoyne
      Expansion

ARKANSAS
  Arkla Chemical Corp.
      Magnolia, Columbia
      Expansion
  Olin Corporation
      McKamie, Lafayette

CALIFORNIA
  Lomita Gasoline Company
      Long Beach, Los Angeles

FLORIDA
  Amerada Hess Corporation
      Jay, Santa Rosa
  Humble Oil & Refining Company
      Jay, Santa Rosa
      Expansion
  Louisiana Land & Exploration Co.
      Jay, Santa Rosa
  Louisiana Land & Exploration Co.
      Escambia County

MISSISSIPPI
  Elcor Chemical Corporation
      Canton, Madison
  Shell Oil Company (3-Stage Plant 97%)
      Jackson*
  Shell Oil Company (2-Stage Plant
    Being Upgraded)
      Goodwater, Clarke
       1972

Before 1962
Before 1972
Before 1962
       1962

       1944
       1971
       1972

       1971
       1972

       1972

       1972
       1965

       1972


       1971
    5.3
  650**
  500
    1.4
            136

            127
           +123
  19
 +11

 100
           Not reported
 120

  14
+360

  82

  88
  12 Standby

1250


  35
 (-) Blank  spaces  signify data not  available

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                                       1-2
                         APPENDIX I.  (Continued)



State/Company/City, County
NEW MEXICO
Amoco Production Company
Artesia, Eddy
Cities Service Oil Company
Milnesand, Roosevelt
Climax Chemical Company
Oil Center, Lea
Marathon Oil Company
Indian Basin, Eddy
Northern Gas Products Co.
Hobbs, Lea
Warren Petroleum Corporation
Tatum, Lea
Year
Sulfur
Production
Started


1960

1967

1962

1967

1969

1961
Sulfur
Production
in 1973
(MT/D)


24.3

8.0








Sulfur
Design
Capacity
(MT/D)


26

20

18

36

13

4
NORTH DAKOTA
  Texaco, Inc.
      Lignite, Burke

OKLAHOMA
  Pioneer Natural Gas Co.
      Madill, Marshall
  J. L. Parker Company
      Madill, Marshall

TEXAS
  Amarillo Oil Company
      Waha, Pecos
  Marathon Oil Company
      Raan, Pecos
  Mobil Oil Corp.
      Coyanosa, Pecos
  Texas American Sulfur Co.
      Sand Hills, Crane
  Phillips Petroleum Company
      Crane County
      Expansion
  Warren Petroleum Corp.
      Waddell, Crane
      Expansion
       1961



       1967

Before 1961



       1971

       1967

       1967

       1966

Before 1961
       1962

Before 1961
       1968
           20
89.0
 15 Standby



  2

 13

 29

 15

100
+65

 50
4-45

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          1-3
APPENDIX I.  (Continued)
State /Company /City, County
Warren Petroleum Corp.
San Hills , Crane
Northwest Production Corp.
Big Lake , Reagan
Expansion
Sid Richardson Carbon & Gasoline Co.
Kermit, Winkle r
Wanda Petroleum Company
Kermit, Winkler
Amarillo Oil Col.
Goldsmith, Ector
Amoco Production Co.
North Cowden, Ector
Odessa Natural Gasoline Co.
Odessa, Ector
J. L. Parker Company
Penwell, Ector
Phillips Petroleum Co.
Goldsmith, Ector
.Elcor Chemical Corp.
Midland, Midland
Amoco Production Co.
Midland Farms, Andrews
Amoco Production Co.
South Fuller ton, Andrews
J. L. Parker Co.
Andrews, Andrews
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
Year
Sulfur
Production
Started

1964

Before 1962
1962

Before 1961

1967

1967

1952

1961

Before 1962

Before 1961

1958

1956

1968

Before 1961

1951

1970

Before 1961

Before 1972

1962

1951
Sulfur Sulfur
Production Design
. in 1973 Capacity
(MT/D) (MT/D)

34 50

3
+5

5

18

5

26 26

12.8 13

30

75

1 Standby

6 11

3 6

15

34 48

2 4

23 28

2 4

9

30

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                                     1-4
                         APPENDIX I.    (Continued)
    State/Company/City, County
    Year
   Sulfur
 Production
  Started
  Sulfur
Production
 in 1973
  (MT/D)
 Sulfur
 Design
Capacity
 (MT/D)
Texas Sulfur Products Inc.
    Dumus, Moore
Trans-Jeff Chemical Corp.
    Tilden, McMullen
    Expansion
Atlantic Richfield Co.
    Fashing, Atascoaa
Elcor Chemical Corp.
    Fashing, Atascosa
Humble Oil & Refining Co.
    Jourdanton, Atascosa
Warren Petroleum Corp.
    Fashing, Atascosa
Shell Oil Co.  (2-Stage Plants
  Feed to a Common 3rd Stage)
    Person, Karnes
    Expansion
Coastal States Gas Producing Co.
    Kenedy, Karnes
Olin Corp.
    Beaumont, Jefferson
Amoco Production Co.
    Edgewood, Van Zandt
Cities Service Oil Co.
    Myrtle Springs, Van Zandt
Amoco Production Co.
    West Yantis, Wood
Getty Oil Co.
    Cayuga, Anderson
Getty Oil Co.
    Winnsboro, Franklin
Shell Oil Company (3-Stage, 97%)
    Bryan's Mill, Cass
Texaco, Inc.
    Dunbar, Rains
Warren Petroleum Corp.
    Sulphur Springs, Hopkins
       1966

Before 1962
       1962

Before 1961

       1960

       1967

Before 1962


       1962
       1965

       1968

       1959

       1964

       1968

       1963

Before 1972

       1969

       1962

       1966

       1965
   13.2

   27.4
  332

  216

   34
  190
   40
 13

 20
+80

 10

 55

 22

 45
              12
             +23
 50 Standby

576

270

 80

130

224

200

 70

 89

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                                      1-5
                           APPENDIX I.  (Continued)
      State/Company/City, County
   Year
  Sulfur
Production
 Started
  Sulfur
Production
 in 1973
  (MT/D)
 Sulfur
 Design
Capacity
  (MT/D)
UTAH
  Union Oil Co. of California
      Lisbon, San Juan
      1967
             10
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
Texas Gulf Sulfur Co.
Worland, Washakie
Jefferson Lake Sulfur Co.
1 ! . • Manderson, Big Horn
Atlantic Richfield Co.
Sinclair, Carbon
Signal Oil & Gas Co.
,. Nieber Dome
Texas-Seaboard Inc.
Silvertip
TOTAL


1965

1963

1968

1949

1961

1964
1966

1958

1950

Before 1959

Before 1962

Before 1962

1957
84 Plants


39 70

12

5

32 110

14

29 32
+15

22 Standby

400 Standby

113 Standby

26

50

50 Standby
(Incomplete) 6249

 * Field deliverability limited  production of sulfur
** These fields are unitized and the  total sulfur production in  1972 was 650 MTD
Blank spaces  indicate  data not  available

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