Control of Sulfur Emissions from Oil Shale Retorts


                        by
  R.  J.  Lovell,  S. W.  Dylewski  and  C.  A.  Peterson
                 IT Enviroscience
            Knoxville, Tennessee 37923
                Contract 68-03-2568
                  Project Officer

                 Robert C. Thurnau
         Energy Pollution Control Division
    Industrial  Environmental  Research  Laboratory
              Cincinnati, Ohio  45268
    INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
         OFFICE OF RESEARCH AND DEVELOPMENT
       U. S. ENVIRONMENTAL PROTECTION AGENCY
              CINCINNATI, OHIO  45268

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                                 DISCLAIMER
     This report has been reviewed by the Industrial Environmental Research
Laboratory, U. S. Environmental Protection Agency, and approved for publica-
tion.  Approval does not signify that the contents necessarily reflect the
views and policies of the U. S. Environmental Protection Agency, nor does
mention of trade names or commerical products constitute endorsement or
recommendation for use.
                                      ii

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                                  FOREWORD
     When energy and material resources are extracted, processed, converted,
and used, the related impacts on our environment and even on our health
often require that new and increasingly more efficient pollution control
methods; be used.  The Industrial Environmental Research Laboratory -
Cincinnati (lERL-Ci) assists in developing and demonstrating new and improved
methodologies that will meet these needs.

     Synthetic fuel processes under development must be characterized prior
to commercialization so that pollution control needs can be identified
and control methods can be integrated with process designs.  Shale oil
recovery processes are expected to have unique air, water, and solid waste
pollution control requirements.  This report describes an in-depth evaluation
of the control technology systems that are applicable to the removal of
hydrogen sulfide from retort off-gases.  Further information on the environ-
mental aspects of oil shale processing and control technology can be obtained
from lERL-Ci, Oil Shale and Energy Mining Branch.
                                       David G. Stephan
                                          Director
                        Industrial Environmental Research Laboratory
                                         Cincinnati
                                      iii

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                                  ABSTRACT
     The objectives of this study were to determine the most applicable
control technology for control of sulfur emissions from oil shale processing
facilities and then to develop a design for a mobile slipstream pilot plant
that could be used to test and demonstrate that technology.

     The work conducted included an in-depth evaluation of available gas
characterization data from all major oil shale development operations in the
United States.  Data gaps and inconsistencies were identified and corrected
where possible through working with the developers and/or researchers in the
field.  From the gas characterization data, duty requirements were defined
for the sulfur removal systems.  Based on this information, Stretfbrd gas
sweeting technology was recommended, and the design of a 1000 CFM pilot
plant was completed.
                                     iv

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                                 CONTENTS
                                                                    Paqe
  I.   PROJECT SUMMARY                                                  1
      A.    Introduction                                                1
      B.    Objectives                          ,                        2
      C.    Approach                                                    2
      D.    Recommended Available H2S Control Technology                3
      E.    Design of Pilot Plant                                       5
      F.    Conclusions                                                 5
 II.   INTRODUCTION                                                     8
      A.    Oil-Shale Resource                                          8
      B.    Environmental Constraints                                   8
      C.    Purpose of Study                                            9
      D.    Approaches and Limitations                                 11
      E.    References                                                 13
III.   OIL-SHALE GAS CHARACTERIZATION                                  14
      A.    Characterization of Oil Shales                             14
      B.    Paraho Retort Gas                                          21
      C.    Occidental Vertical, Modified, In-Situ-Retort Gas          26
      D.    Geokinetics Horizontal In-Situ-Retort Gas                  32
                                                i
      E.    Union SGR-3 Retort Gas                                     37
      F.    TOSCO-II Retort Gas                                        40
      G.    References                                                 46
 IV.   REVIEW OF SULFUR REMOVAL PROCESSES                              48
      A.    Treatment Techniques                                       48
      B.    Process for Recovering Sulfur                              54
      C.    References                                                 64

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                            CONTENTS (Continued)
   V.   FACTORS INFLUENCING CHOICE OF PROCESS                           65
       A.    Product-Gas Specifications                                 65
       B.    Acid-Gas Components                                        66
       C.    Influence of Impurities                                    67
       D.    Condition of Feed Gas                                      68
       E.    Capital and Operating Costs                                68
  VI.   DUTY REQUIREMENTS FOR OIL-SHALE RETORT-GAS DESULFURIZATION      70
       SYSTEMS
       A.    Classification of Oil-Shale Retorting Processes            70
       B.    Commercial Oil-Shale Operations                            75
       C.    References                                                 79
 VII.   SCREENING OF GAS TREATING PROCESSES                             80
       A.    Direct-Conversion Processes                                80
       B.    Indirect-Conversion Processes                              84
       C.    References                                                 96
VIII.   EVALUATION OF CANDIDATE PROCESSES                               97
       A.    Basis of Evaluation                                        97
       B.    Gas Pretreatment                                           99
       C.    Direct-Recovery Processes                                 103
       D.    Indirect-Recovery Processes                               113
       E.    References                                                128
  IX.   COST COMPARISON OF CANDIDATE PROCESSES                         130
   X.   RECOMMENDED AVAILABLE H2S CONTROL TECHNOLOGY                   134
       A.    Adaptability                                              134
       B.    Operational Requirements                                  134
       C.    Sulfur Removal Effectiveness                              135
       D.    Relative Costs                                            136
       E.    Wastes Generated                                          136
       F.    Reliability                                               139
                                    vi

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                          CONTENTS (Continued)
                                                                    Page
XI.  PILOT PLANT DESIGN                                             140
     A.   Introduction                                              140
     B.   Sizing of Pilot Plant                                     141
     C.   Duty Specifications                                       142
     D.   Recommended System                                        142
     E.   Preliminary Cost Estimate                                 148
     F.   Advantages and Use of Pilot Plant                     '    154
                               APPENDICES
     A.   STRETFORD DIRECT PROCESS
     B.   THREE-STAGE SELECTIVE ABSORPTION PLUS CLAUS SULFUR RECOVERY WITH
          SCOT TAIL GAS TREATMENT
     C.   ONE-STAGE SELECTIVE ABSORPTION PLUS INDIRECT STRETFORD SULFUR
          RECOVERY
     D.   DIAMOX PROCESS PLUS CLAUS SULFUR RECOVERY WITH BSRP TAIL GAS
          TREATMENT
                                  vii

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                                   TABLES
Number
     I   Maximum Concentration of S02 to Meet Colorado and Federal   10
         PSD Requirements
     2   Properties of Green River Mahogany Ledge Oil Shale          15
     3   Ash Composition of Oil Shale                                15
     4   Composition of Organic Matter in Green River Oil Shale       15
     5   Gas Produced by Pyrolysis of Oil Shale by Modified          18
         Fischer Method
     6   Material Balance on Pyrolysis of Oil Shale by Modified       19
         Fischer Method
     7   Distribution of Elements in Products of Pyrolysis of        20
         Oil Shale
     8   Estimated Distribution of Sulfur in Oil Shale               22
     9   Design Basis for Paraho Retort                              25
    10   Estimated Composition of Green River Oil-Shale for          25
         Paraho PON Retort
    11   Gas Produced by Paraho Direct-Fired Retort                  27
    12   Range of Critical Compositions in Gas from Paraho           28
         Retort by Direct Mode
    13   Design Basis for Occidental Vertical MIS Retorts            31
    14   Gas Produced by Occidental Vertical MIS Retort              33
    15   Design Basis for Geokinetics Horizontal In-Situ Retort       35
    16   Gas Produced by Geokinetics Horizontal In-Situ Retort        35
    17   Design Basis for Union SGR-3 Retort                         39
    18   Gas Produced by Union SGR-3 Indirect-Heated Retort          41
    19   Design Basis for Tosco-II Retort                            44
    20   Net Gas Produced by Tosco-II Retort                         45
    21   Comparison of Claus Process Options                         60
    22   Comparison of Fuel Gases                                    7^
    23   Range of Gas Compositions from Direct-Fired Retorts          72
    24   Range of Gas Compositions from Indirect-Heated Retorts       73
    2!>   Selectivity Data                                            74
                                  viii

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                             TABLES (Continued)
Number                                                              Page
   26    Comparison of Gas Treatment Duty Requirements               76
   27    Commercial Oil-Shale Operations                             77
   28    Selectivity of Absorbent Processes                          82
   29    Selectivity Absorption Using MDEA with Two Stages           87
         of Adsorption
   30    Selective Absorption by Benfield Process                    89
   31    Selective Absorption Using Aqueous Ammonia                  91
   32    Selective Absorption by Diamox Process                      93
   33    Selective Absorption by Selexol Process                     95
   34    Hypothetical Direct-Fired Retort Gas                        98
   35    Comparison of Selective Absorption Processes for           114
         Treating Gas from a Direct-Fired Retort
   36    Performance of Three-Stage Selective Absorption System     118
         Using MDEA
   37    Estimated Capital and Operating Costs for Fuel-Gas         131
         Desulfurization Options
   38    Variation of Process Effectiveness with Amount of COS      137
         in Raw Gas
   39    Relative Costs of Various Gas Desulfurization Options      138
   40    Approximate Pilot-Plant Operation for Various Gases        149
   41    Pilot-Plant Components

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                                   FIGURES
Number                                        -
   1     Flow Diagram for Paraho Direct-Mode Retort                  24
   2     Flow Diagram of the Occidental Modified In-Situ Process     30
   3     Flow Diagram of Geokinetics Retort No. 17 Off-Gas           34
         Handling System
   4     Flow Diagram for Retort System in Union Oil Retort B        38
         Prototype Plant
   5     Flow Diagram for Pyrolysis and Oil Recovery Unit            42
         Tosco-II Process
   6     Gas-Sweetening Processes
    7     Typical Three-Stage Glaus Process                           55
    8     Glaus Tail-Gas Treatment Processes                          62
    9     Gas-Sweetening Processes                                    81
   10     Gas Cooler/Ammonia Absorption System                       101
   11     Stretford Process for  Fuel-Gas Sulfurization                105
   12    EIC Sulfuric Acid—Copper Sulfate Process                   111
   13     Three-Stage MDEA Selective Absorption System                116
   14    Sulfur-Burning  Claus Sulfur  Recovery System with  SCOT       120
         Tail-Gas Treatment Unit
   15    One-Stage MDEA  Selective Absorption System with            122
         Stretford Sulfur Recovery Unit
   16    Diamox Process  with  Claus Sulfur Recovery System           125
   17    BSRP Tail-Gas  Treatment Unit                               127
   18    Material Balance Flowsheet  for  Pilot Plant                 144

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                            I.  PROJfrT SUMMARY

A.   INTRODUCTION
     The future beneficial use of the nation's extensive oil-shale resources
     depends not only on the development of suitable process economics but
     also on the development of suitable environmental controls.  Even
     though the oil that would be produced is comparatively low in sulfur
     content, the potential sulfur emissions from large-scale production of
     shale oil could be enormous.  Oil shale contains up to about 2% sulfur.
     A typical shale in the Green River Formation in Colorado contains about
     0.7% sulfur.  When the shale is retorted, somewhere between 16 and 30%
     of the sulfur is liberated to the gas stream, with the majority remain-
     ing with the spent shale.  The emissions from a  64,000-m^/day
     oil-shale industry could be as high as 691-1273 tonnes  per day if
     emission controls were not applied.  If conventional flue-gas scrubbing
     systems were used to control the emissions for which the average reduc-
     tion achieved is 90%, the controlled emissions would be 69 to 127 tonnes
     day.  However, if the sulfur could be removed before the gas is burned,
     in which case the average reduction is 98%, the controlled emissions
     would be in the order of 14 - 26 tonnes/day.

     Gases produced by direct-fired retorts, either above ground or in-situ,
     are significantly different from gases normally encountered in applica-
     tion of desulfurization technology that the technology cannot just be
     transferred.  Gases from direct-fired retorts contain large amounts  of
     inert components and have a high ratio of carbon dioxide  (CO2) to
     hydrogen sulfide (H2S); they also contain large amounts of ammonia and
     unsaturated hydrocarbons, such as acetylene, ethylene, propylene,
     butylene,  and butadiene.  The gases are saturated  with water  and con-
     tain some  oxygen and trace amounts of sulfur species  other than  H2S.

     The large  amounts of CO2 in the gases and the high C02/H2S ratios make
     it impractical  to employ many of the desulfurization  technologies.
     Since  the  gases are produced in huge volumes at near-atmospheric pres-
     sures,  many other desulfurization processes  cannot be economically

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     applied.  Those processes that can be applied may be only marginal in
     performance because of  the  large amounts of C02 and the presence of
     oxygen and/or unsaturated hydrocarbons  in the gases or because the gas
     may  contain a large amount  of organic sulfur.

     Oil-shale developers  are involved in a  number of significant pilot-scale
     activities for the development of retorting process technology, and
     have indicated to the United States Environmental Protection Agency
     (EPA) their willingness to  cooperate on joint projects for  sulfur con-
     trol technology evaluation. To  capitalize on this opportunity and to
     explore the possibility that sulfur emission control will be more of a
     problem than was  orginally  thought, EPA contracted with  IT  Envirosci-
     ence, Inc.,  to  investigate  the various  commercial sulfur-removal tech-
     nologies and  to propose a pilot-plant  design based on  the most cost-
     effective process for the  removal of gaseous sulfur compounds from oil-
     shale retort  gases.

B.   OBJECTIVES
     The objectives  of this study were  to  determine  the  most applicable
     control technology for control of sulfur emissions  from oil
     shale processing facilities and then to develop a design for a mobile
     slip-stream pilot plant that could be  used to  test  and demonstrate  that
     technology.

C.   APPROACH
     The work conducted included an in-depth evaluation of available  gas
     characterization data  from all major oil-shale development operations
     in  the United States.  Data gaps and inconsistencies were identified
     and corrected where possible through working with the developers and/or
     researchers in the field.  From the gas characterization data,  duty
     requirements were defined  for the sulfur removal systems.  It was found
     that oil-shale retorting processes fall into two broad categories:
     idirect-fired-retort processes and indirect-heated-retort processes,
     each category having distinctly different duty requirements.

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The overriding factor that separates the two categories of retorting
processes and that is dominant in the application of desulfurization
technology is the C02/H2S ratio of the gas produced from the retort.
Those from direct-fired retorts have C02/H2S ratios that range from 76
to more than 165 and thus would require that the sulfur-removal process
selectively remove H2S in the presence of large amounts of C02.  Indi-
rect-heated retorts produce gases with C02/H2S ratios in the range of
4.3 to 5, which would allow a nonselective process to be usedl

During this study it was determined by the EPA that the greatest imme-
diate concern is control of sulfur emissions from direct-fired oil-
shale retorting processes and that the pilot-plant design should be
applicable to these retorting methods.  Since application of desulfuri-
zation technology to gases from direct-fired-retorting processes is
more limiting, the screening of available process technologies was
based on the duty requirements for those gases.

RECOMMENDED AVAILABLE H?S CONTROL TECHNOLOGY
The class of processes that remove H2S and CO2 from fuel gases is
generically called acid-gas removal  or gas-sweeting processes.  Removal
of acid gases and/or other gaseous impurities from gas  streams is
accomplished either by direct chemical conversion of  the acid  gas  to
another compound that can be more easily  separated from the gas, by
                                                             I
absorption into  liquid,  or by adsorption  on a solid.  The  large volumes
of gas that must be processed in a  typical oil-shale  plant will limit
the  application  of desulfurization  technology to high-capacity, liquid-
phase processes.  Since  C02  is absorbed to  some  extent  by  all  liquid-
phase processes,  the high C02/H2S ratio of  the  gas  limits  the  selection
to those processes  that  can  selectively absorb  sulfur compounds in the
presence of  large amounts of C02.

Of those processes  that  selectively remove  H2S  by  direct  conversion of
 the  H2S  to elemental sulfur,  the  Stretford process is the most effec-
 tive one.   Of those indirect processes that selectively remove H2S by
 separating the H2S  as  a  concentrated acid-gas stream, the following

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processes were selected as the most effective in their separate process
classifications:  the Selectamine and the Adip processes,  which use
MDEA as the absorbent, the Benfield, the Selexol, and the  Diamox proc-
esses.  The Benfield and Selexol processes require the gas to be at
high pressure and thus were eliminated since compression of the gas  for
the purpose of desulfurization could not be economically justified.

Except for the Diamox process, all the candidate processes are capable
of removing H2S down to about 10 ppmv.  However, organic sulfur com-
pounds , principally COS, which exist in only trace amounts in -. the gas,
are not significantly removed or are only partly removed by the various
processes.  However, the presence of those compounds may reduce the
overall effectiveness to 98%.

For desulfurization of gases from direct-fired oil-shale retorts the
Stretford direct process is the most cost-effective system.  For the
model case used to evaluate the various processes the total estimated
cost of sulfur removed by the Stretford process would be about $0.50
per barrel of oil produced, which is less than half that projected for
the best of the other processes evaluated.

The Claus process is used to recover sulfur from the acid  gas produced
by the indirect sulfur-removal processes.  The large amount of CO2 in
the gas makes the best of the indirect processes only marginally capa-
ble of producing an acid gas rich enough in H2S for processing by the
Claus process.  Thus to apply these processes multiple stages of selec-
tive absorption would be required to handle the gas produced by many of
the direct-fired retorts.  The process, however, does not  effectively
remove COS.  Only trace quantities of COS (less than 50 ppmv) have been
found in gases produced by direct-fired retorts and thus an overall
effectiveness of 98% or more is projected for the Stretford process.
If the quantity of COS in the gas should be higher than indicated by
the currently available gas characterication data the removal efficien-
cy could be less than 98%.

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     The Stretford direct process,  on the other hand,  is only minimally
     affected by the quantity of C02 in the gas and therefore is adaptable
     to the full range of gases produced by direct-fired retorts.

E.   DESIGN OF PILOT PLANT
     The pilot-plant design is based on the current state-of-the-art tech-
     nology for commercial application of the Stretford process.  The maxi-
     mum design capacity of the unit is 28.3 sm^m of feed gas and 6.6 Kg  of
     sulfur per hour.  The plant should be capable of reducing the H2S con-
     tent of the gas to 10 ppmv or less, and C02/H2S ratios as high as 200
     to 1 should be possible.

     The pilot plant is sized primarily to remove H2S from oil-shale gas
     produced by direct-fired retorts.  However, use of an ejector-venturi
     gas-scrubbing system affords wide gas turndown capability for the sys-
     tem.  The pilot plant thereby is capable of operating on a slip stream
     from any of the currently proposed direct or indirect oil-shale retort-
     ing processes in the United States.
                    it
     To properly function, the feed gas to the pilot plant must be 120°F or
     less, with most of the ammonia removed.  A gas cooling column has been
     incorporated into the pilot design for cooling and removing the ammonia
     from the feed gas.  The estimated cost of the pilot plant with all
     equipment, instruments, and controls, assembled on skid mountings as a
     complete and operable unit, is as follows:

                                   With Cooler         Without  Cooler
                                    $520,000               $338,000
                                      400,000               260,000
                                      308,000               200,000

 F.   CONCLUSIONS
     The  Stretford  direct gas  desulfurization process may  be the  only  cur-
     rently available commerical process  capable of effectively removing H2S
     from gases produced by  direct-fired retorts.   Application of the  Stret-

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ford process or of any other process to the treatment of these gases
would extend the technology of the process into areas in which no
analogous experience is available.  Many questions need to be answered
before the process can be applied with confidence to a full-scale com-
mercial shale-oil production facility.

The principal areas of concern are as follows:

1.   absorption of CO2 versus gas characteristics,
2.   capacity of the solution for absorbing sulfur versus gas charac-
     teristics,
3.   rate of by-product thiosulfate formation versus gas characteris-
     tics,
4.   disposition of COS and other organic sulfur compounds in the feed
     gas,
5.   effects of unsaturated hydrocarbons in the feed gas on process
     operation, life of the Stretford chemicals, and quality of the
     sulfur produced.

The viability of the oil-shale industry hinges on an environmentally
compatible sulfur-removal process.  Although  there are no  federal
industry  standards  for emissions  for the oil-shale industry at this
time,  the State of  Colorado has enacted legislation that limits indus-
try emissions to less than 0.3 Ib of  sulfur dioxide per barrel of oil
produced  and an equal amount per  barrel of oil refined.  To meet this
standard  at least 96% of  the sulfur in the gas expressed as  SC>2
would  have  to be removed.

The area  of air pollution compliance  that is  of  the  greatest concern to
industry  and government  is  the Prevention of  Significant Deterioration
 (PSD)  requirements  of  the Federal Clean Air Act.   This  concept was
enacted to  prevent  the addition of specified  pollutants above a  pre-
 scribed baseline value in specified air  regions.   Colorado adopted  a
more  stringent  plan, which limits the maximum level of sulfur dioxide
 in the air  to  an annual  average  of 10 pg/m3.   Thus the  maximum quantity

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of shale oil that can be produced will be limited by the effectiveness
of the sulfur emission control system used.

Unless the Stretford process can be demonstrated as an effective and
reliable process for treatment of direct-fired oil-shale gases, indus-
try may have to resort to combusting the gas first and then using less
effective flue-gas disulfurization techniques.  Because of the strin-
gent PSD requirements any increase in sulfur emissions could result in
reduction of the potential production capacity of the shale-oil indus-
try.

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                              II.  INTRODUCTION

A.   OIL-SHALE RESOURCE1
     Recently, as the price of imported oil began to rise and gasoline ex-
     ceeded $1.00/gal, interest was renewed in obtaining oil from oil shale
     as part of the solution to the energy problem.  The solutions to the
     environmental problems that were once a cost deterrent to commerciali-
     ssation have become more acceptable now that crude-oil prices are ex-
     ceeding $20.00 per barrel.

     The consumption of oil in the United States in 1978 was about 6 billion
                                                                  r
     barrels.  It has been estimated that the known oil-shale resources that
     could be tapped by use of existing technology are equivalent to
     600 billion barrels, and the total resources in the Green River Forma-
     tion in the west have been estimated at 2 trillion barrels of oil,
     which would provide oil for 100 and 333 years, respectively, based on
     the 1978 rate of consumption.  There are very sizable deposits of shale
     in the east and midwest, which are referred to as Devonian shale.
     These shales are leaner in oil than western (Eocene) shales; but, if
     they are incorporated into the resource estimate, the total amount
     climbs to about 28 trillion barrels.  With a resource of this magnitude
     available, some people would ask why we import almost half of our oil
     supply.  Part of the answer lies in the fact that the organic fraction
     of the shale is small and that, if the yield is assumed to be 24 gal/
     ton of shale, about 1 cubic mile of rock would have to be processed to
     yield the oil we consumed in 1978.  Another part of the answer is that
     sizable quantities of environmentally undesirable components could be
     released to the air and to surface waters.

B.   ENVIRONMENTAL CONSTRAINTS1
     Sulfur, one of the undesirable components, is contained in oil shale up
     to about 2%, and a typical shale in the Green River Formation may con-
     tain 0.7%.2  Partitioning studies2'3 indicate that somewhere between 16
     and 30% is liberated to the gas that is generated, with the majority of
     the sulfur remaining with the spent shale.  Under some circumstances

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    oil produced from shale might be considered to be a low-sulfur re-
    source; in this case, however, where immense volumes of rock are
    processed, the potential for sulfur emissions is sizable.  The uncon-
    trolled sulfur emissions from an 8,000 m3/day oil shale retort
    installation could be 86—.59 tonnes per day.  The resulting impact on
    the semiarid region in the west would be significant.

    The National Ambient Air Quality Standard  (NAAQS) for sulfur dioxide
    limits the annual average to 80 |jg/m3 of air.  If this were the only
    regulation that industry had to comply with, all sulfur species would
    probably be oxidized to sulfur dioxide and some form of flue gas desul-
    furization would be used for control.  However, the oil-shale industry
    must  also be concerned with regulations dealing with the amount of a
    specific material that may be emitted by a specific source.  Although
    there are no federal industry standards for  emissions for the oil-shale
    industry at this time, the State of Colorado has enacted legislation
    that  limits industry emissions to  less than  0.3 Ib of sulfur dioxide
    per barrel of  oil produced and an  equal amount per barrel for oil
    refined.  The  area  of air pollution compliance that is of the greatest
    concern  to industry and government is  the  Prevention of Significant
    Deterioration  (PSD) requirements of the Federal Clean Air Act.  This
    concept was enacted to prevent the addition  of specified pollutants
    above a prescribed  baseline value  in specified air regions.   Colorado
    adopted  a  similar plan, but made the acceptable  levels  for  PSD  more
     stringent.  Table II-l  summarizes  the  PSD  requirements  for  the  federal
    government and the  State  of  Colorado,  which  puts  limits  on  sulfur
     dioxide  to an annual  average  of  10 pg/m3.  The  future  potential of the
     oil-shale  industry  therefore  hinges on the effectiveness  of the sulfur-
     removal  process.

C.  PURPOSE OF STUDY
     Oil-shale developers are involved in a  number of significant pilot-
     scale activities for the development of process technology, and have
     indicated to the EPA their willingness to cooperate on joint projects
     for sulfur control technology evaluation.   To capitalize on this oppor-

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         Table 1.     Maximum Concentration of SO- to Meet
               Colorado and Federal PSD Requirements

a
Class I
Annual average
24-hr maximum
3-hr maximum
Class IIb
Annual average
24-hr maximum
3-hr maximum
SO 2 Maximum Concentration
Colorado

2
5
25
10
50
300
(yg/m3)
Federal

2
8
25
20
,91
512
aClass-I areas are listed as national parks and as natural wilder-
 ness and primitive areas.
 Class-II areas are the rest of the country.
                                10

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tunity and to explore the possibility that sulfur emission control will
be more of a problem than was originally thought, EPA contracted with
IT Enviroscience,  Inc., to propose a pilot-plant design based on the
most cost-effective process for the removal of gaseous sulfur com-
pounds, as well as one that is mobile.  This type of design vjould
necessitate investigation of various commercial sulfur-removal tech-
nologies and their applicability to oil-shale gases.

APPROACHES AND LIMITATIONS                                   ]
                                                             i •

Alternatives for Control of Sulfur Emissions                 ''
Two approaches can be taken to control sulfur emissions:  to ;remove
sulfur compounds from the gas before it is combusted  (a gas-sweetening
process), thereby producing a sulfur-free fuel; or to first combust the
gas and then remove the resulting S02 from the flue gases {flue-gas-
desulfurization (FGD) process].
                                                             i
The latter approach is generally less effective, because most of  the
flue-gas scrubbers can remove only 90 to 95% of  the sulfur in the  flue
gas.   The volume of gases handled by  the FGD process  is much larger
than  that handled by  the first process because the products of  combus-
tion  are more voluminous than the fuel gas burned.  Also, th^ FGD sys-
tem generally consumes more water and chemicals  and is more costly to
operate than the gas-sweetening processes.4                  ;
                                                             i
Processes  that  remove sulfur from  the fuel gas before it  is fcombusted
are generally more  effective, with most processes capable of  removing
                                                             i
98% or more  of  the H2S in  the gas.   With  these processes, however,
sulfur in  other forms,  such  as COS,  CS2,  and mercaptans,  may  be only
partly removed  or  not removed at  all.                        ;
 To meet the Colorado air quality control regulations of 0.3 Ib/bbl of
 SO2 equalivant emissions, at least 95% of the sulfur in the igas would
                                11

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have to be removed.  For these reasons this study was directed; toward
the more effective fuel-gas desulfurization techniques.

Basis of Process Selection                                    ;
During this study it was determined by the EPA that the greatest imme-
diate concern was control of sulfur emissions from direct-fired oil-
shale retorting processes and that the pilot-plant design should be
applicable to these retorting methods.  Therefore the screening of
available process technologies was based on the duty requirements for
desulfurization of direct-fired retort gases.
                                 12

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E.   REFERENCES*

1.   R. C. Thurnau, H^S/SOg Control Technology for Oil Shale  Retort Efflu-
     ents , Work Directive No.  T-7012,  EPA Contract No. 68-03-2568, June  18,
     1979.                                                       !

2.   K. E. Stannfield, I. C. Frost, W. S. McAlley, and H.  N.  Smith, Proper-
     ties of Colorado Shale, U.S.  Bureau of Mines, Report  of  Investiga-
     tions 4825 (1951).                                          :

3.   3. W. Ward, Analytical Methods for Study of Thermal Degradation  of  Oil
     Shale, U.S. Bureau of Mines,  Report of Investigations 5932 (1962).

4.   T. Nevens et al., p 133 in Predicted Costs of Environmental Controls
     for a Commercial Oil Shale Industry, Denver Research  Institute,  COO-
     5107-1 (July 1979).                                         [
    *When a reference number is used at the end of a paragraph or,on a head-
     ing, it usually refers to the entire paragraph or material under the
     heading.  When, however, an additional reference is required:for only a
     certain portion of the paragraph of captioned material, the earlier
     reference number may not apply to that particular portion.   :
                                     13

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                    III.  OIL-SHALE GAS CHARACTERIZATION          ;
                                                                  I

A.   CHARACTERIZATION OF OIL SHALES                               !

1.   Introduction
     In characterizing the gas produced by the various oil-shale retort
     processes, it is necessary to have some understanding of the nature and
                                                                  j
     composition of the organic and mineral materials that comprise oil
     shale and of how the materials become distributed among the resulting
     products.  The oil in oil shale can be neither squeezed nor drained out
     at ambient or moderately elevated temperatures.  When the oil; shale is
     heated to temperatures in excess of 200°C and up to 500°C, the material
     is destructively distilled, producing recoverable oil and gas and
     leaving a spent mineral residue.

2.   Composition of Oil Shale
     Oil shales having similar assays of oil, in gallons per ton (gpt), were
     found also to have a fairly narrow range of compositions, as can be
     seen in Table  2.   .1<2  However, even in the Mahogany ledge,; which is
     about 21 m  thick, the assay of oil varies from 37.5 to 312.3 Up tonne.
                                                                  i
     The mineral material, after being fired to an ash, has the composition
     sshown in Table  3. 1    The minerals in their natural form in oil shale
     are varied and complex, and on a point-to-point basis the pH 'can vary
     from 8.5 to 10.3

3.   Composition and Nature of Organic Matter in Oil Shale
     The organic matter in Green River oil shale has a significant amount of
     hydrogen  (see Table  4). *»4    The ratio of about 1.5 moles of hydro-
     gen per mole of carbon enabled about two-thirds of the organic matter
     to be converted to oil during retorting.  In contrast, high-volatility
     bituminous coal has a hydrogen-to-carbon mole ratio of about :0.9  to I.3

     The substantial amount of oxygen present in the organic material  indi-
     cates the likely presence of carboxyl groups.  It is also likely  that
                                                                  I
                                     14                           ;

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         Table  2.     Properties of Green River Mahogany
                          Ledge Oil Shale
Component
Carbon, organic
Hydrogen
Nitrogen
Sulfur
CO_, mineral
Ash
Mineral content of spent shale
Amount (wt % of
Stanfield3
12.4
1.8
0.4
0.6
18.9
65.7

99.8
raw shale)
1 b
Smith
12.21
: 1.76
; 0.37
: 0.70
17.92
65.26
98.22
i
a
 See ref 1; analysis based on sample that yielded  115 J,/tonne.

     ref 2; analysis based on sample that yielded  105 l-Jtonne.
            Table  3.
Ash Composition of Oil Shale
Component
SiO_
2
Fe-0,
2 3
Al_0_
2 3
C 0
a
M 0
g
so3
Na-0
2
K2°
Amount (wt % of raw shale)
27.8
|
3.0 :

8.6

15.1 !
i
6.5
1
1.2
2.0
•
1.5 i
  aOil assay, 115 Jl/tonne  (see ref 1) .
                                15

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          Table  4. •    Composition of Organic fatter  in

                       Green River Oil Shale
Component
Carbon
Hydrogen
Nitrogen
Sulfur
Oxygen
, . ... _ — .._,_ _______
Amount
Stanfielda
76.5
10.5
2.5
1.2
9.3
(wt % of raw shale)
Smith
80.5
10.3
2.4
1.0
;5.8
a.
 See ref 1;  analysis based on sample that yielded 115  £/tonne i


 See ref 2;  analysis based on sample that yielded 105  H/tonne
                               16

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     these carboxyl groups  are  saponified by  the mineral material,; whose pH
     after pyrolysis is  about 11.s   Therefore only  through pyrolysis, or
     destructive distillation,  wherein organogenic  CO2  is released, can oil
     be recovered from oil  shale.   As  further evidence  of the  change  in the
     nature of the organic  material, as implied by  the  term  "destructive
     distillation," the  oil produced from oil shale has a pour point  of
     about 29°C/ although oil will  not drain  from oil shale  at this tempera-
     ture .                                                        i

     The presence of sulfur and nitrogen in oil shale and shale  oil is dis-
     cussed below.                                                ;

4.   Recovery of Products from Pyrolysis of Oil Shale by  the Modified
     Fischer Method                                               i
     A quantity of oil shale representing 94  fcpt assay  was  obtained from  10
     locations in the Green River formation and was blended to provide a
     quantity of uniform composition.   Eight  replicate  pyrolysis runs were
                                                                  \
     made by the modified Fischer method to determine the reproducibility of
     this method of assaying the yield of oil and gas from oil shale.2
     Table  5    gives the quantity and composition of the gas produced
     during pyrolysis; the data, in material balance form,  that were  ob-
     tained are given in Table 6.                                 i

     The  recovery of materials expressed as percent of element contained in
     raw  shale  is shown in Table  7.     These data show that the\ recovery
     of nitrogen in the oil and gas streams  combined is only 53%, of which
     8.6% is in the gas stream.  They also show that the combined, recovery
     of sulfur  is only  25%, of which  16.9% is  in the gas stream,  and that if
     the  shale  oil were treated to  remove nitrogen and sulfur the NH3 con-
     tent of the gas would increase about sixfold  and  the H2S content would
     increase by  50%.

 5.   Sulfur Chemistry Relating to  Pyrolysis  Gas
     The  oil shale  in the  Green River formations contains sulfur  in  two
     major forms:   organic (with -C-S- groups present) and  pyrite, FeS2.

                                      17                          '<

-------
           Table  5.     Gas Produced by Pyrolysis of
              Oil Shale by Modified Fischer Method
Component

C2
C2=
C_
3
V
C4
C4=
C4
C5=
C5=
C6=
co2
CO
H2
H2S
NH,
Total
Amount
(vol %) (DG)a
17.44
5.44
2.10
2.43

2.39
1.50
0.60
1.20
1.56
1.45
0.11
24.00
5.09
29.36
3.20
2.12
100.00
of Gas Produced ,
(sin?/ tonne of raw shale)
4.7
1.5 i
0.6
i
0.6 ;
f
0.6 ;
0.4 I
i
0.2 I
0.03
0.3 ;
0.4
0.4 ;
6.5
1.4
7.9 ;
0.9
0.6 ;
27.03 ;
 See ref 2.
b
 Calculated gas production.
                                18

-------






id
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0)

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C
,Q
y
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(0
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c
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E *
M O * O
M-I CM 0) O
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^5 c *™^ 'O
Ll flJ flj
(tt «Q O
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•g 8 & s
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• f* ^* c*
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19

-------
             Table  "7.     Distribution of Elements in Products
                         of Pyrolysis of Oil Shale3

Component
Carbon, organic
Hydrogen, total
Nitrogen, total
Sulfur, total

Spent Shale
23.6
11.4
46.6
75.1
Distribution
Oil
65.9
61.9
44.8
8.0
(wt %) !
Gas
10.5 :
18.0
8.6
16.9

Water

8.7


aSee ref 2.
                                      20

-------
     The -C-S-  groups are  pyrolyzed in the presence  of hydrogen  to!yield
                                                                  s
     H2S.   Examination of  the gas phase that  is  formed in  this process  indi-
     cated that it went to completion; but since there are still sulfur-con-
     taining organic compounds in the shale oil, the existence of small
     quantities of low-boiling organic sulfur compounds in the gasjwould  not
     be surprising.                                               ;

     Pyrite can undergo hydrogenolysis to yield H2S  as shown below:

               FeS2    +     H2    	>  FeS        +       H2S:
             (pyrite)    (hydrogen)    (iron  sulfide)   (hydrogen sulfide)

     Consequently one-half of the sulfur is available for  recovery: as H2S
     and can appear in the gas.  Sulfate salts,  which are  found  in spent
     shales, are apparently formed in the combustion zone  following pyroly-
     sis.6  Table   8   shows the estimated quantity of sulfur in these two
     forms and the sulfur available for recovery (3.89 kg/tonne of raw shale).
     The sulfur recovered as H2S (1.15 kg/tonne of  raw  shale; see ;Table  6)
     is estimated to be 30% of the sulfur available for recovery. '

B.  PARAHO RETORT GAS                                             ;

1.   Introduction
     Development Engineering, Inc. (DEI), a subsidiary of Paraho Development
     Corp., have developed an above-ground retort to the point thajt they are
     ready to design a commercial-size module.  This retort can be designed
     to operate in either the direct mode, wherein combustion air ;is brought
     into direct contact with the shale in the  retort, or in the indirect
     mode, wherein only recycled reheated pyrolysis gas is brought into
     contact with  the shale.  In the  latter case the recycle gas is reheated
     by some of the pyrolysis gas being burned  in a separate unit.7  Recent-
     ly, DEI concluded that  the direct mode is  more energy efficient,  and
     they are now  emphasizing its development in preference to  the indirect
     mode.8                                                       :
                                     21

-------
             Table 8.      Estimated Distribution of
                       Sulfur in Oil Shale
Sulfur
Form
Organic
Pyrite
Unaccountable
Total
Distribution
Total Sulfur
1.5213
4.73C
.0.75d
7.00
( kg/ tonne of raw shale)
Available as HsS
1.52 j
2.37 i
3.89 i
aOil assay,  104 'i /tonne.                                     i
bBased on 0.45 kg of S/36.6 kg of C; see ref 4.                ;
c:Based on 1.41 kg. of S as pyrite/ 45 kg of S as organic;  see ref 4.

Calculation based on 7.0 kg  of total S per tonne of raw shale.
                                  22

-------
              RAW
             SHALE
                            OIL MIST
                            SEPARATORS


MIST
FORMATION
AND
PREHEATING


RETORTING
ZONE
_ — — — — _ —

COMBUSTION
ZONE
RESIDUE
COOLING
AND
GAS
PREHEATING
^ 	 2
X /
_











Y








\




c






»->



)IL







N










A










r


^N
PRODUCT 	 .,,,_
GAS i
(ELECTROSTATIC
PRECIPITATOR
:
C ^\ 1 RECYCLE GAS
V^_^7 BLOWER
f .• \ 	 .,.._ /\in BLOWER


    'GATE
    SPEED
  CONTROLLER
             RESIDUE
                                                                   OIL
Figure  1.   Flow Diagram for Paraho Direct-Mode Retort
                                24

-------
  2.
 3.
   BEI has sotted . proposal
   (DOE) Program opportunity Notice (pON)
    nd oerate    an ^ove.ground retort
                                                                   ^

                                                      ^      consti.uct .on

4.
                                                                         ^
                                                                    ^
   to .develop technology to exploit  oil shale as an energy resource.  The

   r9;;:;;:yhat  such * ret°r

   Paraho Retort Process Description
   In the direct mode of operation of the Paraho retort (see  Fig  1,
   crushed „ shale is fed to the top of the retort and spent skali

   yTherolthe "Tr-  Tbe Shale P"S" d°™""d * *"^* ""cessive-
   ly through . mist Nation and preheating 2,ne,  a  retorting .one. ,
  co^usuon 2one.  and finally,  a residue-coding,  g,s-prehe,ti,g zone.
  The „ aro onaceous  residue on the  retorted shale is turned in  the co^us-
  taon zone to provide  the principal fuel  for the process."

  The  shale-oil vapors  produced  in the retorting zone are coole
-------
             Table  9.     Design Basis for Paraho Retort3     l



  Shale-oil production                               _,ft  •».„.
                                                     ••960 nr?/day
  Oil-shale throughput                               ., „ „„„  '  I
                                                     -10,000 "tonnes/day
  Oil-shale assay
                                                     91.6-—158, £/tome
  Method of heating                                        '
                                                     Direct fired
  Gas recycle ratio                                        ,
                                                     498 sm-Vtonne
  Gas production ratio                               -   •   ->   • '
                                                     223 sm3/tonne
  Gas mole  ratio,  CO_/H_S                                 "      i

  Heat content,  HHV                                            ;
                                                     105,400 joules
  Pressure                    <./, ..&.
                                                    Atmospheric
  Temperature
 		                          60°C

  See refs 9 and  11.
         Table  10.    Estimated Composition of Green River
                  Oil-Shale for Paraho PON Retort3
     Component	

 Carbon,  organic
                                                           12.2
 Carbon,  mineral CO
                   2                                        4.9
 Hydrogen                .                                      i
                                                            1.76
 Nitrogen
                                                            0.37
 Sulfur,  organic                                               i
                                                            0.15
 Sulfur,  pyrite
                                                            0.47
 Sulfur,  sulfate                                                '
                                                            0.08
Oxygen,  except CO                                              i
                 2                                          1.37
Balance, minerals
                                                          78.7,
                                                         loo. o:
 Oil assay, 104 to 112 £/tonne(see refs 4 and 9)
                               "25

-------
               TY?;:-:G G'Ji J2 SK'JET
llV.l- Oi
                                           v. L;.. :.-'•.
        5.
Retort-Gas Characterization    •                              i        	:
                                 :                            ;          !
As the pyrolysis gas is produced, 498 sm^    of the gas per t:onne of
                                                             I    --      •
shale is recycled with sufficient air to provide the necessary heat for
pyrolysis, and 223 sm-Vtorme is forwarded for uses external to the      '
retort process.  The gas produced is discharged_at_essentially atmos^	
pheric pressure and at about  60°C (see Table 11)i  .                    i
          1                       i                            !          i
          1                       !                                      i
Although the gas from the Paraho retort has been sampled, analyzed, and
reported over the years, only the most recent data are considered as   j
adequately representative of the process because the techniques and
methods used now are considered to be better than those used'before
1977.8  Table .  11   shows the mean values of the composition of the
gas produced by the Paraho retort in the direct mode during 1977 and
1978.  In 1977, 31"gas samples were taken and analyzed and in 1978
          i                                                             :
there were 51.  The high, low, and mean values for CO2 H2S, and NH3 are .
shown, in Table   12'.. -12
        C.   OCCIDENTAL VERTICAL, MODIFIED,  IN-SITU-RETORT  GAS
                       I
                       !
        1.   Introduction
            For more than six years  Occidental Oil Shale,  Inc.  (OOSI)  (formerly     1
            Garrett Research and Development Co.)  has  been engaged in  modified,  in- j
            situ,  process technology development.   Occidental's philosophy in       i
            developing this process  for producing oil  from shale  is to maximize  the .
                       i                                                  •           !
            recovery of in-place oil while  minimizing  costs and the environmental  :
            impact.13 ,
                       I
            OOSI prepared and processed its fifth and  sixth retorts under a cooper-
                                              i          '                 !
            eitive  program with the Department of Energy (formerly the  Energy Re-
                       I                       !                           i
            search and Development Administration). The DDE/Occidental  Cooperative
                       f                       *
            Agreement is a two-phase agreement consisting  of engineering develop-
            ment of two specific retort designs for the Occidental modified in-situ
            process as the first phase and  a technical feasibility demonstration as
                                                                        i BOTTOM OF
BEGIN
LAST LINF
OF TEXT £
the second phase.13
; 	
! i;3/8" i_ iCI'26'':"ll ;
PAGE NUMBER I
EPA-287 (Cin.) :
(4-76) '
OUTSIDE
DiMLNSION
FOR TABLE?
.-AND-ILLUS-
, TRATICNS

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         Table  11.     Gas Produced by Paraho Direct-Fired Retort'
Component
CH4
C2
C2
C3*S
C.'S . .
c5-s
co2
CO
H2
H2S
NH3
N2
°2
so2
NOX
CS2, RSH, COS
Thiophene
Thio-4- (methylthio) -
3-cyc:lo-pentene-2-one
Total, DG
H O
2
•
(sm-V tonne)
' 4.8
-1.2'
1.5
=1 ,6
-1..2
1.2b
' 50..6
- '5.5
. -10,5
0,7
..i.'e
: 141.5
0,2






' 222.2


Amount !
(dry vol %)
[2.16
!0.56
0.66
;o.7i :
:0.56
0.57b
22.81
2.50
;4.74
0.30
0.70
63.80
0.09
(17 ppm)
(168 ppm)
None detected
(50 ppm)
(200 ppm)
i
100
20d

Oil assay, 100 to. 108 H /"tonne.; .see ref  12.
Total for C ' and higher hydrocarbons.
Identified sulfur compounds.
20% H,.O on wet-gas basis; see ref 9.
     j*
                                      27

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           Table T2.      Range of Critical Compositions
             in Gas from Paraho Retort by Direct Mode3

Component
co2
H2S
NH

High
27.7
0.55
1.23
Amount (dry vol %)
Low
18.0
0.19
0.50

Mean
22.8
0.30
; 0.70
"Represents 82 sample analyses  taken in 1977 and  1978; see ref 8.
                                28

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                                                                                       TP
BEGIN
LAST LiNE
OF TEXT
              Description of Process           j                                    	i
              The modified in-situ process consists of retorting a rubblized column   '
              of broken shale, formed by expansion of the oil shale into a previously
              Unined-out void volume.  In retort 5 the mined void volume is removed
              ^.frorn the^retort zone in_ the form of_a vertical _slice_along_'die_center	'_
              of the room, extending from the top of the rubble pile to be formed, to :
              the production level.  This system is known as a vertical fr|ee-face     i
              retort system (VFFR).  In retort 6 three horizontal levels are mined    !
              out similarly to room and pillar mining and then the oil shale is       \
              blasted above and below the mined-out sections to the horizontal rooms.
              This system is the horizontal free-face retort system (HFFR).13         !
              After the column of shale has been rubblized, connections are made to
              both the top and bottom and retorting is carried out (Fig. 2).
              Retorting is initiated by heating the top of the rubblized shale column
                                                                          I
              with the flame formed from compressed air and an external heat source,
              such as propane or natural gas.  After several hours the external heat
              source is removed and the compressed air flow is maintained, with the
                        f                       ;
              carbonaceous residue in the retorted shale used as fuel to sustain air
              combustion.  In this vertical retorting process the hot gases from the
              combustion zone move downward to pyrolyze the organic matter! in the
              shale below that zone, producing gases, water vapor, and shajle-oil
              mist, which condense in the trenches at the bottom of the rubblized
              column.  The crude shale oil and by-product water are collected in a
              sump and pumped to storage.  Part of the off-gas is recirculjated to
              control the oxyg;en level in the incoming air and the retorting tempera-
              ture.  The^ remainder of the off-gas passes on to the desulfurization
              train.10  ;
1
              Hasis of Retort Design and Operation                        '•
                        i                       ;                           '
              The projected bases for design and operation of Oxidental retorts 7 and
              B are given in Table   13.   "'is  The design basis for retort 6 is
              also given'.
 BOTTOM OF
 IMAGE AREA.
 OUTSIDE
           EPA-2S7 (Cin.
          .(4-75)
                                              29.
                                             l*l*l/vJLi
                                         PAGE NUf.-BER
 FOR TABLES
 •AND'ILLUS-
 TRATIONS

-------
                        -OIL RECOVERY
  RAW
  SHALE
  OIL
                               RECYCLE GAS
                               COMPRESSOR
                    FUTURE RETORT
                    CENTER SHAFT
AIR MAKE-UP-A
COMPRESSOR
                                         OIL SHALE RUBBLE

                OIL SUMP AND PUMP
figure 2.   Flow Diagram of the Occidental Modified"in-Situ"Process"

                            "V."  30 .~~~    ""   ~—	— — - -
                                              TYP'JG

-------
        Table   13.     Design Basis for Occidental Vertical MIS Retorts
           Parameter
                                       Retort 6
                        Retorts 7 and 8
Retort size (tonnes)
Oil-shale assay (fi,/tonne)
Method of retorting
Gas injected
Gas production rate (snv
Gas productions ratio (sm-V tonne)
Gas ratio, CO2/H2S  (mole/mole)
Heating value, HHV  (joules'/sm^)
Pressure  (psig)
Temperature  '(°C)
329,058
62.5
Direct in-situ
Airc
408
588"
330 to 130
i;6x!06  to  2.2xl06
Atmospheric
57 to .66 .
618,120
62.5
Direct in-situ
50% air/50% steam
1100
      f
296   !
165
4.1xl06
Atmospheric
57 to ,77
 See ref 13.
^Estimated from Oxy No. 6 and refs 14 and 15.
°Steam injected at end of run.
                                        31

-------
        4.
    "-. i
 Retort-Gas  Characterization     !                            ;.         —
 The  composition of the gas produced by retort 6 at midpoint of the run
 is given in Table 14.       The composition of the gas varied throughout
 the  run.  In the initial stage of  operation the C02/H2S molar' ratio
 averaged about 330 to  1.  After steady-state operation was established,
 the  CO2/H2S molar ratio averaged about 165 to I.13  Retorts 7 and 8
 will be operated using a 50% oil/50% steam mixture injected into the
 retort.  The use of -steam will affect the composition of the; gas pro-
 duced.   The quantity of COS in the gas is expected to increase.
           !                       i
 GEOKINETICS HORIZONTAL IN-SITU-RETORT GAS                   !
                               -•* f -, -'
        • I -.
- 'Introductic.--.-
                                                       of recovering shale: oil from
              shallow formations of oil shale.   The method consists of detonating
              implanted explosives to rubblize  the shale.  This raises the overbur-
                      ..                         t
              den,  thereby developing void spaces among the broken shale.  The bed of
              broken shale (retort) is then ignited with a fuel-air mixture injected
              at  one end,  and the retort products are expelled through a production
                                               i
              hole  at the  other end (Fig.  3).
LAST LINE
OF TEXT I
                                       The retort burn advances horizon--
  tally.   When the retort is well ignited, the fuel is shut off and only
  air is  fed to the injection hole.                           i
              Retort 18 was fired from November 16, 1979, to February 5, 1980.
                        1                       i                           ;
              Retort firings will continue in an effort to develop this technology.
              The aim of this program is the production of  320 m^ of oil ;per
              day over about a 10-year period from small shallow retorts, i
            .-.-Basis of Retort Design and Operation                        ;
                 -\ies~ign basis for geokinetics retort 18 is given in Table 15.16,17
3.   Retort Gas Characterization
               i                       !                           :
     The average composition of the gases produced by  retort 18 is given in
     Table  16.
             A T./R"
           EPA-287 (Cin.)
                                           X":'"''
                                                                           BOTTOM OF
                                                                           IMAGE ARE.-*
                                                                           OUTSIDE
                                                                           DI.V.EMSIOfJ
                                                                           FOR TABLE;.
                                                                         "yAND ILLUS
                                                                           TF; AT IONS
                                          PAGE NUf/.SER

-------
        Table  14.
Gas Produced by Occidental Vertical MIS Retort1
Component
H2
CO
co2
CH4
C2H4 ..
C2H6
C3H6
C3H8
C4
C5 +
H2S
NH
N2
°2
so2
NOX
cs2
RSH
COS
Total, DG
H20
Composition
• (sm-Vtonriek)
45.0.
-5.2-
.'188.8
8\4
0:4-
1,3
0.4
.0.6
0.-6
' 0.1
:0.7-
c
'330.5
0.5 .
6.9
0.2
c
. c
0.02
• 585.9


: C
(•vol. %) (DG)
7.65
j 0.89
I 32.26
1.44
; 0.07
\ 0.224
0.0
.0
; o
0.01
0.1
c
56.41
0.08
0.15
0.03
c
' c
: (1 — 40 pprn)
! 99.611
! 38.3d
 Gas produced by Oxy No. 6 at midpoint of run (Jan. 15, 1979); see ref 13.
 Average calculated values.                                       ,
C                                                                 '
 No data.
 vJet-gas basis.                                                   :
                                      33

-------
                                                                               4J
                                                                               (Q
                                                                               >i
                                                                               (0


                                                                               S1
                                                                               a
                                                                               a:

                                                                               10

                                                                               o

                                                                               (4-1
                                                                               U-l
                                                                               O
                                                                              -• w
                                                                               o
                                                                               -<-l
                                                                               JJ.
                                                                               0>
                                                                                o
                                                                                Ol
                                                                                en
                                                                                (0
                                                                                Q
                                                                                0)
                                                                                VI
                                                                                D
                                                                                cr>
FAGL r-.L-Vi,;.;;
                                TV-'*^1'
                                 1  > r i

-------
                            15.     Design Basis for Geokinetics
                            Horizontal In-Situ Retort
   '"t size
On *hale
""''"/a of
    Injected
                  -*-
<4^.~Z,
             V^C.
10,025
83.3— 91.6
Direct in-situ
Air
45.3
   j
c  i
181
3,35xl06
Atmospheric
54
  
-------
           Table  16.
Gas Produced by Geokinetics
                   Horizontal In-Situ Retort
Component
H2
CO
2
CH4
°2H4
C2H6
C3H6
C3H8 ^' '' ':'''^'
C4
c5+b
H2S
1!IH3
2
°2
so2
!NOX
cs2
:RSH
'COS
Total
H20
aGas produced by Geokinetics retort
C- to C,n hydrocarbons present but
o 1*J
Composition (dry yol %)
7.47
8.03 I
23.48 ;
1.61
0.085
1
0.297
0.09
0.13 !
0.15 !
0.071
0.13 ;
0.060
57.4
1.13
c :
c !
c '
c ;
(40 ppm) ;
100.13 '
15. Od .
No. 18; see ref 16.
not measured. i
CNo data.
 wet-gas basis.
                                 36

-------
                                            '•'•- FA
                                                                         fur (,
                                                                        , ;.VAC::
                                                                        'Ar;HA;
        .E.    UNION SGR-3 RETORT GAS
\-:-.\r*-   \
        i 2:
BEGIN
LAST LINE
OF TEXT if;
         3.
Introduction                     j                           !
The Union Oil Company of California (Union) have been involved  in  oil   !
shale activities for more than 50 years.	The_ development_of_their	j
retorting technology was initiated in the early 1940s, and  several     i
variations of a vertical-kiln retorting process, with upward flow  of   .
          1                       !                                       !
shale and countercurrent downward flow of gases and  liquids, have  been. [
developed.  Two variations are known as retort A and retort B.   Union
          '                                                              i
Oil now proposes to construct a 9090 tonnes/day demonstration; plant,     i
using the retort-B process, together with all the necessary auxiliary   ;
facilities.10
          i
Description of Process           |                           i
In the retort-B process  (shown in Fig.  4 . ' ) as the crushed oil shale
                                                            I     .       !
flows upward through the retort it is met by a stream of hot  (510  to   !
538°C)  recycle gas from the recycle gas heater flowing  downward.  The j
rising oil-shale bed is heated to retorting remperature  by  countercur- •
rent contact with the hot recycle gas, resulting in  the  evolution  of   j
the shale-oil vapor and product gas.  This mixture of shale-oil vapor   !
and product gas is forced downward by the recycle gas and is  cooled  by j
contact with the cold incoming shale in the lower section of  the retort ,
          i                       ;                           ;            j
cone.  The liquid level  in the lower section  is controlled  by with-
          '•                       i
drawal of the oil product.  The recycle and product  gases are removed
from the space above the liquid level.  The product  gas  is  first sent
to a venturi scrubber for cooling and removal of heavy hydrocarbons  by
oil scrubbing.  That portion of the product gas not  recycled  is then
                                 •                           i
sent to the desulfurization train.  Before the gas reaches  the  desul-
          l                       i                           |
furization train, it may be compressed and oil-scrubbed  to  recover
additional hydrocarbons.10
        -   I
Basis  of  Retort Design and Operation
The basis for design for the Union SGR-3 retort is given in;Table
 17.18'19   '
                        i
                    _1_,	
           EPA-287 (Cin.)
           (4-76)
                            !^.l?i?.:.:.. *&
                            PAGE NUMBER
  BOTTOM OF
  IMAGE AP.3-
  OUTSIDE
  DI.MBMSIOU
  FOR TABLE;:
VAND ILLUS-
  TRATIONS

-------
                                       ro
                                       rH
                                       fU

                                       0)
                                       o
                                       LI
                                       OQ

                                       JJ
                                       LI
                                       O
                                      3


                                       O
                                      1-1

                                      D
                                       V
                                       4->
                                       W
                                       >i
                                       (O
                                       Ll
                                       O
                                       1-
                                       LI
                                       0)
                                       LI
                                       fa
PiI-JG  GUIDd

-------
              Table  17.
Design Basis for Union SGR-3 Retort
Shale-oil production
Oil-shale throughput
Oil-shale assay
Method-of retorting
Method of heating

Gas production ratio
Gas production rate
Gas mole ratio, CO_/H S
                  £  2
Heat content, HHV
Pressure
Temper at ure  ( °C )
                     1440 m3/dayb '   '
                     9090 tonnes/day
                     157.4 8,/tonne
                     Indirect mode   i
                     Indirect heating; of recycled
                       retort gas    !
                     29.9 sm3/tonne  [
                     188.7 sm3/min   j
                     4.35  :          i
                     42.38xl06 joules/sin3
                     5—10 psig      ',
                     65.5	71.1°C
 See refs 18 and 19.
 Stripped shale-oil production is 1419 m-Vrday.
                                      39

-------
                      GUiL-J SHL^i
4.
             Retort Gas Characterization    '  j                            I
             The estimated composition of the gas that will be produced by the
             Union SGR-3 retort is given in Table 18.
                       i
             TOSCO-II RETORT GAS
        i.
BEGIN
LAST LINE
OF TEXT
        2. .
     Introduction
     Tosco II is a process developed by  the Oil  Shale  Corporation (Tosco).
     Initial development work began in 1955;  in  1964 a 909 tonne/day semi-
     works plant was constructed  and tested.  A  full-scale commercial plant
     is planned by the  Colony Development  Operation, a joint venture of
     several companies  who formed or own Tosco.

     Description of the Process       ;                            |           I
     The heart of the processing  sequence  is  the Tosco-II pyrolysis (retort-
     ing) unit and associated oil recovery equipment.   The flowsheet for a  ;
     single unit  (or train)  is  shown in  Fig.  5.      The raw shale from the
     final crusher is fed to a  fluidized bed, where it is preheated to about '
               1                       i                                       i
     SOO°F with flue gases  from a ball heater.   The residual hydrocarbons in
               i                       i                                       '
      the flue gases are burned  in the ball heater.10
The preheated shale is fed to a horizontal rotating retort  (pyrolysis
          i                       I                           ;
drum), together with approximately 1.5 times its weight in  hot ceramic:
balls from a ball heater in order to raise the shale to pyrolysis tem-
perature (482°C) and convert its contained organic matter to  shale-oil
          j                       i                           I
vapor.  The oil vapors are withdrawn and fed to a fractionatjor for
hydrocarbon recovery.  The mixture of balls and spent  shale is dis-
charged through a trommel, in order to separate the emerging  warm balls j
from the processed shale.10
                         \
The warm balls are purged of dust with flue gases from a  steam pre-
          i                       I
heater, and the dust is removed from the flue  gases by wet  scrubbing.
The dust-free warm balls are returned to the ball heater  via  the ball
elevator. 'In the ball heater they are reheated to about  704°C   and  	
                                                  _spent_shaie_is_cppled
      then recirculated to the
               /8"
           EPA-237 (Cin.)
           (4-7S)
                        W
BOTTOM OF
'.'.'AGE Ar.E-
OUTSICI
Q1N!ENS':G\
•'"<-. TABLE;
-AND ILLUS-
TRATIONS
                                          PAGE NUM3ER

-------
                Table .18.      Gas Produced by Union SGR-3
                          Indirect-Heated Retorta

Component
H2
CO
co2
CH4
C.H..
2 2
C H
2 4

°2H6
C H
3 6
r H
^38
C.H-
4 6
i-C..HQ
4 8
n-C H
4 8
f-C4H10
n-C_H_
5 8
i-CcH-
5 8
C5H10
C5H12
C '
6+
H2S
NH3
N2
°2
so2
NOx
cs2
RSH
COS
. Total, DG
H 0
2
Oil assay, 157£/tonne;
No delta.

(sm-V tonne)
6.95
1.44
.. 4.95
- 6.63
0.06

0.53

2.28

1.13

b

1.02

-0.09
T -
0-.'79

0.34
0.09
'T
0.12

0.06
0,28
1.84

- 1.14
b
0.03
c
. • _
b
• . •-.
-
0.-02
29.77
5.95

see ref 19.

Amount i
; (dry vol '%)
23.34
: 4.85
16.62
| 22.28
1 0.19

1.72

; 7.67

i 3.81
'
b
i
i 3.43

1 0.29

2.66
!
1.14
0.29

0.39

0.19
i 0.94
6.19

i 3.82
b
0.11
c
\
; (125 ppm)
b
j (20 ppm)
; (164 ppm]i
I ^542 ppm)
i 100.00
20d

\

No data; likely nil.
Estimated value, wet-gas basis.
                                    . 41

-------
 0]
 (0
 V
 u
 o
 Ll
 cu
 8
a
 u
 0)

 o
 u
r-J
-M
O


•o

 IS

 03
-•H
 01
 O
 Ll
CU
 10
 u
 D>
 10
in
 LI
 3
 t,

-------
              to about  149°C in a rotating drum cooler and moisturized with water
              recovered from the plant's foul-water stripper unit.10       \
              Unlike some U.S. oil-shale facilities, the Tosco-II/Colony  commercial
              plant will be designed not only to produce shale oil but also  to up-    :
              grade it on-site to produce synthetic crude oil and liquid  petroleum
              gas (LPG), with ammonia, sulfur, and coke produced as by-products.  The
              shale-oil hydrocarbon vapors from the pyrolysis drum are separated  into
              water, gas, naphtha, gas oil, and bottom oil in a fractionatpr.   The
              water is sent to a foul-water stripper, the gas and naphtha are  sent  to
              si gasoline recovery and treating unit, the gas oil is sent  to  a  hydrog-
              enation unit, and the bottoms oil is sent to the delayed coking  unit.10
         3;
         4.
ScG i N
LAST Li,\E
OF TEXT I
Basis of Retort Design and Operation
The basis for design and operation of  the Tosco-II  retort is jgiven in
Table .19.    ,20/21

          r
Retort Gas Characterization
The average composition of the gas produced by  the  Tosco-II retort is
given in Table 20.    .22
             A O '0 • •
                                              43
           EPA-2S7 (Cin.)
           (-5-76)
                                          PAGE NUMBER
                                                                          BOTTOM OF
                                                                          IVAGE ARE-
                                                                          OUTS'DE
                                                                          DIMENSSG:.
                                                                          FOR TASLEG.
                                                                          AND ILLUS-
                                                                                        TRATIONS

-------
               Table .19.   .  Design Basis for Tosco-II Retort
Shale-oil production                                 -8,872 m3/dayb
Oil-shale throughput  (6 retorts)    •                  60,000 tonnes/day
                                                                  i
Oil-shale assay                                       158 Si /tonne
Method of -retorting                                  Indirect mode;
Method of heating                                    Pyrolysis by heated balls
Gas production ratio                                 38.5 sm3/tonnec
Gas production rate  (single retort)                  26.7. f» sm3
Gas mole ratio, CO /H_S                              4.95         !
                                                                         rt
Heat content, HHV         -                           35.26xl06 joules/sin3
Pressure                                        :     Slightly positive
Temperature                                          60°C-        ,
asee refs 20 and 21.                                              !
v»                                                                 ' -
 Based on pilot study; see ref 21.  Production as low sulfur distillate is
 7,360 nrVday;   see ref 20.                                      j
°Calculated from data in ref 21.                                .  i
 Calculated valve based on C$ and higher MW hydrocarbons removed. |
                                         44

-------


Table
Component
H-
2
CO
CO-
2
CH
C-H-
2 2
C' H
24
C' K
26
C3H6
f * TT
38
C.
4
c
H2S
NH
NO
2
°o
2
so_
-2
NO
cs_
2
RSH
COS
Total
H20
. • • . •

20. . Net Gas Produced by Tosco-II
Amount
•(sm^/ tonne)
7.54

1.31
t 7.83

• 7.75
b

3.21

2.91

.2.73
-1.28

2.00

c
,1.58
d
b

b

b

b
Nil6

.- - .-
"

38.38
9.59
s r •
a
Retort ;
i :
|
(dry yol %)
20.2

3.40
20.38
'
20.2
b

8.39

7.01

. 7.14
3.35

5.22
.
c
4.12
!d
b

b

\T°
t
!b
Nile ;

(35 ppm)
(135 ppm)
100 ' ;
20b!
*See ref 21. i
 None reported.
cReported in oil recxjvered.
 Absorbed in water phase and does not appear in gas.
e
 See ref 22.
 wet-gas basis.
                                45

-------
                                                                                      i OP o;
        "G.
       REFERENCES*

          1.  V. Kalcevic  and J. Lankford, Pilot-Plant Operation of Gas-Flow Oil-     :
             Shale Retort, Report  of  Investigations 5507, U.S. Department^of Interi-,
             or. Bureau of Mines (April  1959).                                       |

        .  2.  J. W. Smith, Analytical  Method  for Study of Thermal Degradation of Oil
             Shale, Report of  Investigations 5932, U.S. Department of Interior,
             Bureau of Mines (1962).
                                              i                            h
          3.  J. W. Smith,, Geochemistry of Oil-Shale Genesis  in Colorado's, Piceance
             Creek Basin, Rocky Mountain Association of Geologists—1974 Guidebook.

          4.  J. W. Smith, Ultimate Composition of Organic Material in Green River
       j      Oil Shale, Report of  Investigations 5725, U.S.  Department of! Interior,
       |      Bureau of Mines (September  1960).

       i   5.  E. R. Bates  and T. L.  Thoem, editors. Pollution Control Guidance  for
       •      Oil Shale Development, compiled by Jacobs Environmental Division, July
       U.:_ —1979. —	 _  	7 —  "j	         -
EEG'.N
LAST L!\<
OF TEXT
          6.   J.  W.  Smith,  "High Temperature Reactions  of  Oil  Shale Minerals  and
              Their  Benefit to Oil  Shale  Processing in  Place," pp  100—112' in llth
              Oil Shale Symposium Proceedings, November, 1978.

          7.   J.  B.  Jones,  "The Paraho Oil-Shale  Project," 81st National Meeting  of
              AIChE, presented at Kansas  City, MO,  April 11—14, 1976.     ;
                                              i                            i
                        1                      i                            i
          8.   Private conversation  on Sept. 27, 1979, between  S. W. Dylewski,  IT
              Enviroscience,  Inc.,  and R. N. Heistand,  Development Engineering, Inc.

          9. '  Telephone conversation on Dec. 19,  1979,  between S.  W. Dylewski, IT
              Enviroscience,  Inc.,  and R. N. Heistand,  Development Engineering, Inc.
                        :                      l                            '
         10.   C.  Shih et al.,  Technological Overview Reports for Eight Sha'le  Oil
              Recovery Processes, EPA-600/7-79-075  (March  1979).

         11.   Development Engineering, Inc., Air  Emission  Source Construction and
              Operation Permit Application, submitted to USEPA Region VIII, July  5,
              1978.
-I
12.  K. N. Heistand and R. A. Atwood, Development Engineering, Inc., "Paraho
     Environmental Data," prepared as Part II — Air Quality, under USDOE con-
     tract EP-78-C-02-4708.AOOO  (February 1979).
               i                       i
13.  R. A. Loucks, Occidental Vertical Modified In Situ Process for the
     {Recovery of Oil from Shale  Phase I, Occidental Oil Shale, Inc., Grand
     Junction, CO, DE-FC20-78LC10036 (November 1979).
                                      I                           i
14.  Private conversation on Sept. 26, 1979, between R. Lovell, S. Dylewski,
_ _  and V. Kalcevic of IT Enviroscience, Inc., and C. Bray of Occidental
--  '  Oil Shale, 'Inc.                  i   _ •• _ ; __
                                                                                      !
            f. -3 'O"
        i    *.• O O



           EFA-2S7 (Cin.)
                i.
                                     46
                                  PAGE NUMBER
                                                                                       BOTTOM OF
                                                                                       IVAGE ARE.-
FOR TABLED
•AND ILLUS-
TRATIONS

-------

          15.
          16.
  R. E. Thomason, Occidental  Oil Shale,  Inc.,  letter request for a Pre	
  vention of Significant Deterioration Permit,  addressed to T.iL. Thoem,
  USEPA, Mar. 24, 1980.

  Telephone converstion on  Feb.  5, 'l979, between S.  W.  Dylewski, IT Envi-
  roscience. Inc., and L. Morriss, Geokinetics,  Inc.
         "177
         18.
         19.
         20.
         22.
 ~r.~Morriss, Geokinetics,"inc.,  "letter" dated  Feb.  13,   1980,  to
  S. Dylewski, IT Enviroscience,  Inc.                          i

  R. Lathrop and T. Thoem, Environmental  News, news  release by U.S.  Envi-
  ronmental Protection Agency, Region VIII, Aug.  8,  1979.
            t                       i
  J. Pownall, Union Oil Company,  Long Range Experimental ShalejOil Plant,
  PSD Permit Application, Apr. 7, 1978, and addendum Apr.  13,  1979.
            !                       i
  A. Merson, USEPA, letter dated  July 11, 1979,  to M. Legalskiy  Colony
  Development Operation.           .                            ;

— J-.- Whitcombe, The Tosco II -;ril "Shale Process ^presented  at the~79t'h~~;
  National Meeting of the American Institute of  Chemical Engineers
  March 16—20,. 1975.                                          !.

  M. Legatski, Colony Development Operation, letter  dated  Jan. 26, 1979,
  to T. Thoem, USEPA.
EEGiN
LAST LINE
OF TEXT I
 *When a reference number is used at the end of a paragraph or Ion a head-
  ing, it usually refers to the entire paragraph or material under the
  heading.  When, however, an additional reference is required for only a
  certain portion of the paragraph or captioned material, the earlier     j C.-.TTOM ,-
  reference number may not apply to that particular portion.              j i'^GE A^
                                                                          ' CUTSI-OE
            A 3 'R"
           EPA-237 (Cin.)
           (fl-76)
                                         :•:$•:•...•. 47.....'i::
                                                                           FOR TABLE
                                                                         >AN'D ILLU5
                                                                           TRATIONS
                             PAGE'NUV.BER

                                   ,n

-------
                            IV.   REVIEW!OF SULFUR REMOVAL PROCESSES
              TREATMENT TECHNIQUES     !    .....                           	
                                       !•••..                   ...  .  |
              The class of processes that remove sulfurous compounds and Carbon diox-
                                       |       .       »,i.   .    . , d.,..,,    , _  ,,  . .  [
              ide from gases is generically called acid-gas remoyal_or_gas/-sweeting __
             _.	   	    -	   |.    .  -    		-       •        |
              processes.  Removal of acid gases and/or other gaseous impurities from
              gas streams is accomplished by chemical conversion  to another compound,
                                       i       .                     •
              by absorption into a liquid, or by adsorption on a  solid.    ;
BEG!N:
LAST L!M
OF TEXT J
              In the first method the gas is passed through a fixed bed or is con-
              tacted with a liquid,  whereby the impurities are converted to another
              compound that can be morei easily removed.   Conversion is either by
              direct chemical reaction with the bed or liquid or by catalytic reac-
              tion'
i      direct chemica
                                      T
                        I
              In the second method the gas stream is contacted with a liquid, and the
                                       I..   ,   :               .             \
              gaseous impurities are either chemically or physically dissolved in the
                        '               I                    '               '
              liquid absorbent.   The absorbent is subsequently regenerated to strip
                                       i       '                            •<
              the absorbed gas and is then recycled.
              When the method of adsorption is used on a solid, the gas is passed
              through a fixed bed of granulated solid material.  The impurities are
              adsorbed and held by the solid adsorbent.  When the bed becomes satu-
              rated,  it is replaced or regenerated.                       ;
      Numerous processes for removal of sulfur compounds have been developed
                               I    '    i                           I            i
      from these methods and more  than 30 of them have achieved cpnunerical    :
                               I        '              '             i            •
      importance.  Each commercial process has specific advantages, disadvan-
                               !        '-                           ' •           i
      tages, or limitations and] was developed to satisfy specific needs.      i
                1               i        ;                           '            !
      Some processes are designed  to remove both H2S and CO2, whereas  other  ;
                i               !        :                           '            i
      processes are more selective toward H2S or C02 removal.  All liquid-    i
                I      .         |      .: ,                           i            |    '
      phase processes will remove  C02 to some degree, along with the H2S.     :
      Some processes are economical for only bulk removal of acid gas  and     ;  ;y.\GE ARE-
      will not achieve a high degree of acid-gas removal.  Other processes    ;  ^"^ . ,"c.
      will achieve a high degrep of acid-gas remoyal, to the ppm level, but_____;  FC-.-: TABLF:
                        I
            if-!L _ I.
           EPA-2S7 (Cin.)
           (4-73)
                                      48
•AND ILLUS-
TRATIONS
                                         PAG

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                                                                                     TOP Or
BEGIN
LAST LIME
OF TEXT
         a.
             are not economical for gases containing large amounts of acid gases. —
             Still other processes are effective only if the C02/H2S ratio is small,
             whereas others are more effective if the C02/H2S ratio is high.  Some
             processes cannot be.used at a low pressure, but some are equally effec-
             tive at all pressures.  Most processes'must be_carriedi_out jat_near^____
             ambient temperatures; others require cooling or chilling of the feed
             gas; some can be used at elevated temperatures, whereas others must be
             tased at elevated temperatures.
             &11 H2S removal processes can be divided into the general categories of.
             direct- and indirect-conversion processes.  In the direct-conversion
             processes the sulfur compounds are directly oxidized to elemental sul-
             fur or another compound that can be separated and recovered.]^ In_the__
             indirect conversion processes the acid-gas components are removed from
                                                                         I
             the feed gas and recovered as a separate stream, which is subsequently
             processed for recovery of the sulfur.  Sulfur is recovered from the
             concentrated acid-gas stream by the Glaus sulfur recovery process or by
             one of the direct-conversion processes.  Both these categories can be
             further broken down into either gas-phase dry-bed processes pr liquid-
             phase (wet) processes (see .Fig.  6).
             Direct-Conversion Processes
Dry Bed	Several dry-bed processes have been described for 'direct
removal of H2S from hydrocarbon gases based on the .classic Claus reac-
tion of H2S and S02 to form elemental sulfur.1  The application of
these processes is limited because of possible plugging of the beds by
condensable hydrocarbons and/or other impurities in the gas..  None of
these processes are known to have achieved commercial importance.
                                                                                   a
The Claus process, while a dry-bed process, is not in the true sense
gas-treating or sulfur-removal process and therefore is not included in ;
          !                       i                           i            j bOT lUi.s v_'~
this discussion.  The Claus process is used to recover sulfur from      j ;MAGE ARC
hydrocarbon-free acid-gas streams containing large amounts of H2S and	j ^.r^fn-
is discussed in Sect. IV-B.      i                           i       	1 FOR TABLE
                        i

                                         PAGE NUMBER
           EPA-287 (Cin.)
           (4-70.)

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                      G GUif'L L/l-iu::)
t'LO I
         b"   Liquid-Phase  Direct-Conversion Processes — Liquid-phase  direct-conver-
              sion processes  usually are best suited to  gases  containing low concen-
              trations  of H2S,  especially  in the presence  of substantial concentra-
              tions of  C02.   Very  little CO2 is absorbed by  the  solution,  and thus
              t;.hej .Processes s?.lectively remove the H2S._ The principal  disadvantage
              is the relatively low  capacity of the  solutions  for H2S,  which results
              in large  liquid circulation  rates and  requires large equipment for
              separating and  processing precipitated sulfur.   Generally plants of
              this type are not economical when the  sulfur production rate 'exceeds
               9 tonnes  per  day. Another disadvantage is  that the considerable reac-
              tion heat generated by oxidation of H2S has  to be dissipated I at low
              temperature and cannot be recovered.2  The quality of sulfur -produced
             _1S *owfr  than that of  the sulfur obtained with the indirect  processes,
              and the wastewater from purge  streams  is a major problem.
                        i                       '•                            i
              Direct-conversion liquid processes have substantial economic ladvantages;
              over direct-conversion dry-bed processes in  that they require  less
              space, eliminate  the high cost of bed  replacement, and produce higher
              quality sulfur.    Some  liquid processes are capable of producing a
              treated gas of high purity equal to that obtained with dry-be!d proc-
              esses.
         2.   Indirect-Conversion Processes
         a.
[JEGIN
LAST LINE}.
OF TEXT •••••>-
        I
         Dry Bed	The dry-bed indirect-conversion processes are  generally
         applied on a batch-loaded basis, where the bed is  removed from service
         when it is_loaded and the sorbent is replaced or regenerated.   The  dry-
         bed processes are selective for H2S and generally  achieve a high  degree
         of removal.  These processes are limited to the treatment of gas
         streams of small volume or to gas streams containing relatively low
                   i                       •                            i
         amounts of sulfur compounds.  Regeneration of the  bed is  only  partly
         achieved, and the bed eventually becomes plugged with sulfur and  must
         be replaced.  The economics generally limit application of thtese  proc-
         esses to plants recovering less than 10 tons of sulfur per day.3
            t? 3/s"
            J
          EPA-287 (Cin.)
          (4-7G)
            I
                                        51
                                         PAGE MLVBER

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                 I i . .•_•_: '. !•_- > tJi- -'. : . - !
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              The advantages of dry-bed processes are simplicity, low cost, and ease
                                                                          [
              of operation.  Essentially complete removal of H2 can be achieved, and
              some processes will selectively remove H2S without removing 'any CO2.
              The disadvantages are the large space requirements for the equipment,
              high maintenance costs for bed replacement, and problems with_sulfur	
              recovery. ;
           Liquid-Phase Process  Involving Chemical  Solvents	Chemical solvents
           involve  absorption by reversible  chemical reaction of the H2S with a
           water  solution  of the absorbent.   The  following three types of chemical
           solvents are used:               ••
3£G!N
LAST LINI
OF TEXT :
              Alkanolamines	Many types of alkanolamines are used as absorbents
              (Eig. 6   ), and numerous processes and variations of them liave been
              applied,  depending on the physical conditions of the gas to be treated,
              its composition, and its purity requirements.  Generally alkanolamine
              processes exhibit high reactivity with H2S and achieve a high degree of
              removal.   The processes are not sensitive to pressure, and operate at
              near-ambient temperatures.  Organic sulfur compounds are removed to
              some extent, but the lighter molecular weight amines may forjn nonregen-
              erative compounds when absorbing organic sulfur or cyanide compounds.
              The lighter amines, though less expensive and capable of higher absorp-
                                                                          (            J
              tion capacity, are not selective in absorbing H2S, present corrosion    '
              problems in stripper and heat-exchanger surfaces, and are plagued by    ]
              higher solvent vaporization losses than are the heavier amines.         i
              Alkanolamine processes are generally preferred for treatment! of gases
              containing moderate amounts of acid gas at near-ambient temperature and
              pressure. ;
           Alkaline  salts	Alkaline  salt processes  employ an aqueous  solution of
           a potassium or sodium  salt that  forms  a buffered solution with a pH of
           about 9 to 11.  The weak alkaline  solution chemically absorbs the acid-
           gas components.  These processes are of two types:   those carried out
           at low (ambient) temperature and pressure and those carried but at
           elevated  temperature and pressure.  The low-pressure processes have	
                     \1                 Z's2''?m                      :
                                                                                      i p.-
                                                                                       AND -iLL'
                                                                                       —r- • T '~ • '
                                                                                       i h — i i,_..
           EPA-287 (Gin.)
           (4-7C)
                                         PAGE NUMBER

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 ; 1.1."!
 £ I.1--:': Of
               TVPt.'.'G '-:
BEGIN
LAST LINE
OF TEXT ::>-
        c.
             given way to more efficient processes and are not currently used.  The
             hot processes have an advantage when the feed gas is hot (up, to 149°C )
             and under pressure (<100 psig).  Stripping is accomplished partly by  .
             flashing, and thus the energy required for regeneration is Ipwer than
             that for amine systems.  The alkaline salt solution does not degrade	_
             significantly, and only minimum purge and makeup are required.  Organic
             sulfur compounds are removed by the process, and it can be m|ade partly
             selective toward H2S removal.  The alkaline salt processes are usually
             the best ones to use when bulk removal of C02 is required,  j
                       '                       I                           :
                       i                       i
             Aqueous ammonia	Aqueous ammonia processes are generally applied when
             the gas to be treated contains ammonia.  The ammonia contained in the
             gas is absorbed simultaneously with the H2S and thus serves as the^  ac-
            ~tive agent in the absorber solution.  No chemical additives are  re-
             quired.  Ammonia can be recovered in addition to the acid-gas compo-
             nents.  Under certain operating conditions H2S can be  selectively
             removed/ Removal of up to about 97% of the H2S can be achieved; how-
             ever, organic sulfur compounds are only partly absorbed.
Liquid-Phase Processes Involving Physical Solvents	Physical-solvent
processes are based on H2S, CO2, and minor gas impurities being more
soluble in certain anhydrous organic solvents than  are  the  fuel-gas
components', i.e., hydrocarbons and hydrogen.  Since their solubilities
increase with pressure, the processes  generally  require high pressure
to be economical.  The solvent is regenerated by pressure reduction,
gas stripping, or heat applied to produce a concentrated stream of
absorbed gas.
          i
Most physical solvents have higher solubility for H2S  than  for CO2,  and
a high degree of selectivity can be obtained with some  processes.  The
solubility of hydrocarbons, however, increases with molecular weight.
Consequently hydrocarbons  above C4 are also largely removed with  the
acid gas.
              3/3"
                       !_
                                 53'::::?::::>
  ECT7O?.' 0=
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.1 FC", TAE.E:'
•;-AND ILLUS-
 | TRATiGNS
                                          PAGE
           EPA-227 (Cin.)
           (4-7G)

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-—;•<: p |
h£AD.   i
         B.
BEGIN
LAST LINE
OF TEXT i..
              The advantages of physical solvents over chemical solvents are lower —
              heat and power consumption, greater removal of organic sulfur compo-
              nents,  higher selectivity for H2S, no purge or wastewater streams, and
              little  corrosion.  The disadvantages are that a high-feed gas pressure
                        i                                                           	
              :Ls required,  heavier hydrocarbons are absorbed, the solvent loss is	
              high, and the solvent cost is high.
                        i                       •                           !
                        il                           :
              Physical-solvent processes are most economical when the feed gas is
              available at  high pressure.  These processes are usually usep for bulk
              removal of acid-gas constituents when the acid-gas impuritie's make up
              an appreciable fraction of the total gas stream, making the cost of
              removing them by heat-regenerable chemical solvents less attractive.
              When high-purity treated gas is required, additional solvent; regenera-
              tion steps beyond simple flashing are required.
              PROCESS FOR RECOVERING SULFUR
              The Claus sulfur process is the principal process used for recovery of
              sulfur from acid gases produced by the indirect-conversion processes.
                        i                                                  1
              The Claus process is discussed in some detail since it is important
              that the operation, capabilities, and limitations of the process be
              understood before fuel gas desulfurization processes are described.
              A flow diagram of a conventional Claus system is shown in Fig.  7.
              The basic Claus reaction is
                                  2H2S + S02
                                                        2H2O
              The conventional process is carried out in stages:   the  firslt  stage  is
                        '                       i                           '
              at high temperature in a thermal oxidation furnace,  where one-third  of
                        i                       ;         .                  ;
              the H2S is combusted to SO2 in the presence of air;  the  reaction in  the
                        i                       !                           !
              succeeding stages occurs at lower temperatures in the vapor phase by
                        I                       !                           i
              catalytic oxidation.  Usually two or more catalytic  stages are em-
                        !                       !                           '-.
              ployed.  Sulfur is recovered after each stage by the gas streams being
                        !•                      i                           !
              cooled and condensed.  The gas is then reheated to the operating tem-
                        !                       i                                     "—
              perature of the succeeding stage.  When the acid-gas feed is mostly	
             ri o 'Q"
        i     y3'8  •
        i—  J	_
           EPA-2S7 (Cin.)
           (1-76)
                        vj                •:•:•:•      .•:•:•:•:•:•:                     '
                                         PAGE NU.V,3=n
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LAST LINE
OF TEXT t
             H2S, sulfur conversions of up to 70%4 can be obtained by th6 thermal	.
             oxidation step alone, and overall conversions of up to 99%5 have been
             obtained by use of four catalytic stages.  The average sulfur recovery  '
             yield obtained with properly designed and operated systems usually
             ranges from 93—97%.6  The remaining 3 to 7% of the_sulfur_is present	
             in the Claus unit off-gas.       ;       •               •     >            j

             Recent developments have improved the process so that sulfur recovery
             levels of above 99% are routinely achieved by employing tail-gas treat-
             ment;5 acid-gas streams containing as little as 5% H2S have,been proc-
             essed with modified Claus systems.7                         ;

             A necessary condition for successful operation of the thermal oxidation
             furnace is that the acid-gas mixture be rich enough  (high in H2S con-
             tent) to ensure stable combustion at the required reaction temperature.
             The  gas stream entering the first-stage catalytic converter should be
             at its stoichiomatic ratio of 2 parts of H2S to 1 part of S02 and be
             free of oxygenated impurities  (S03), unburned heavy hydrocarbons, soot,
             and  excessive ammonia.  An imbalance of either H2S or S02 will  cause
             the  excess component to pass through the system unreacted.  Oxygen
                       :                       *           ,                ,
             causes sulfonation of the catalyst, which results in loss of catalyst
             activity.  Soot and carbonaceous material and ammonia, through  forma-
             tion of ammonium  sulfate, cause  the catalyst beds to become!plugged.
             Unburned hydrocarbons that condense and stick to the catalyst will also
             cause loss of catalyst activity. \
The operating temperature required for the thermal oxidation furnace is
largely governed by the impurities in the acid gas.  If the acid gas
consists of H2S, COS, CS2, and C02, a furnace temperature of 700 to
800°C is sufficient.  If the gas contains hydrocarbon compounds,
          I                       !                          '
ammonia, and other combustible impurities, temperatures of 1000 to
1200°C are required to assure complete combustion of the impurities and
elimination of soot formation.  The presence of combustible1 impurities
          i             .          i
in the acid gas increases the amount of air that must be introduced to
                    _JL_
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7 RAT IONS
           EPA-2U7 (Cin.1
           (4-76)

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BEGIN
LAST LINE
OF TEXT
                                           oi- ,"•-/::"
             the combustion chamber, and their products of combustion greatly add to
             the quantity of process gas entering the catalytic stages.   ;
                       i                       i
                       I                     '  !                     o
             Methods for Processing Acid Gases Containing 16 to 100-6 H2S  !
             If the acid gas contains 50 to 100% H2S, the total yolume of|acid gas	
             is normally fed to the combustion chamber (the classic, or the
             straight-through, process).  The amount of air fed to the reaction
             furnace is controlled to combust one third of the H2S and all the
             ammonia and hydrocarbon impurities in the feed.  If the temperature is
             maintained at the proper level (1000 to 1100°C), organic imparities are
             oxidized and the catalytic stages operate without significant problems.
             As the H2S content of the acid gas decreases, the lower the temperature
             obtained in the reaction furnace becomes.  Longer residence^time_in_the
             furnace is required to compensate for this lowered temperature,  and
             thus larger chamber volumes are needed to maintain the dyanmic  equilib-
             rium.  Below 35% H2S, the combustion required to produce the;SO2 for
             the Claus reaction is no longer possible without special modifications
             being employed.
                       t
                       I
             Below 50% H2S,  the Claus process is usually modified.  If  the H2S con-
             tent is between 16 and 50%, the  split-flow process is  often applied.
                       j                       '                            ;
             With this process only one-third of the  acid gas is  fed  to the  thermal
             oxidation furnace.  Stable combustion is obtained by the H2S; being com-
             pletely combusted to S02.  The other two-thirds  of the acid gas by-
             passes the  furnace and is mixed  with the gases  from  the  therknal oxidiz-
             er before they enter the  first catalytic converter.   However!,  impuri-
             ties  in the acid-gas stream are  detrimental  to  the downstream catalytic
             section of  the Claus plant and can affect  the  service life of the
             catalyst  and the purity  of the sulfur produced.   If  impurities are
             present in  the acid  gas,  the  complete  stream should be fed to the com-
             bustion chamber as  in  the straight-through process.   Preheating the
             combustion  air and/or  acid-gas  stream  or burning supplemental fuel or
             sulfur will enable  stable combustion to be obtained.
              3/3-
           EPA-287 (Ciri.)
                       I
57
                                          PAGE NUMBER
                                         BOTTGV, G::
                                         I'.'AGE AR1
                                         OUTSIDE
                                        j D;:,',£N3IOi.
                                        ) POJvTABLL
                                        j-AivJD ILLUS
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               TVi'ii'-iG U'Jii-'-" ^>> •--•-'
BEGIN
LAST LIN
OF TEXT r
        b.
         c.
             Methods for Processing Acid Gases Containing Less Than 16% H2S       	,
             •JLf the acid gases contain less than 16% H2S (called lean acid gases),
             the methods for obtaining stable combustion involve the following proc-
             esses:
Preheating Process	The acid gas  and/or combustion air is preheated
before it enters the thermal  oxidizer.   Preheating is accomplished by
heat exchange with  the hot  gases exiting the combustion chaniber, by
steam or by externally fired  heaters.   Only a limited amount of heat
can be obtained by  preheating. For lean acid gases it may be nessary
to use supplemental fuel in direct-fired burners.  However,Jburning the
fuel adds to the cost. x>.f. operation and to the volume of gases that must
be handled by  the downstream  components.    	j	
         ~T              ^-£.'&*!                            :
Sulfur Burning—By-Pass  Process	The Claus thermal oxidizer as such .is
eliminated.  The S02 required for  the reaction is obtained by burning
liquid sulfur  in a  separate combustion chamber;.  This has the advantage
that, stable  combustion is  obtained in the sulfur burner and' that the
gas produced is mostly SO2, depending on the purity of sulfur burned.
Off-grade sulfur  can be burned since the carbonaceous material  is
oxidized to carbon dioxide and water.  The acid-gas stream  is preheated
in a  gas-fired heater.  The hot acid gas and the S02 from the sulfur
burner are then mixed and fed to the catalytic converter.   Application
           ;                      i
of this process is limited to relatively pure acid gases since  even
 small quantities of hydrocarbon can cause carbon and tar to deposit on
 the catalyst and/or the sulfur quality  to be degraded.      ;
 Oxygen Process—Oxygen in place of air  is used in the thermal oxi-
 dizer.  This eliminates the ballasting effect of the nitrogen; thus     j
 less heat is required to maintain  equilibrium and the volume of gases   :
           t                       *                           i        •     '
 passing to the catalytic stages is reduced.   Depending on the quantity  '-.
 of combustible material in the feed,  oxygen  is mixed to the acid gas or I
 to a portion of  the  acid gas, which is then  fed to one or more burners, j
 If insufficient  heat is generated  because of lean-acid-gas Imixtures,	j
 the supplemental fuel must be_burned._	—;	_	,-J
A          I               "..-.•"-.-.•.•.•.•].-.•.•.-.•.•.•.:•                     '             1
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                                                                                        H3TTC'.' C'r
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                                                                                        OUTSIDE
FORT ABLEr
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T RAT IONS
                                          PAGE NUMBER
           EPA-237 (Cin.)
           (4-76)

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         d.    Sulfur Burning—Straight-Through Process	A portion of the acid gas is
              mixed with excess air, depending on the quantity of combustible impuri-
              ties in the acid gas, and is then fed to a special burner.  The remain-
              ing acid gas is fed into the combustion chamber.  Liquid suljfur is
              burned in a special burner to supply most of the S02 required for the  _
              Claus reaction and the heat required to stablize the combustion proc-
                                                                          i
              ess.  The quantity of sulfur burned is limited since the H2S:SO2 ratio
                        i                       .                           '            1
              of 2:1 must be maintained.  Supplemental fuel may have to be, used if
              the heat input is insufficient for thermal equilibrium to be: maintained
              in the furnace.                  •
         3.
BEGIN
LAST LINE
OF TEXT J-
     Cost Data
     Table IV-1 gives the relative capital  and operating costs of the vari-
     ous process options, based on cost  data  reported by Fischer.8  The
     sulfur-burning by-pass process  results in the  lowest capital and oper-
     ating costs of all processes available for processing lean acid gases.
     However, its application is limited to relatively hydrocarbon-free acid
     gases.  When the H2S and hydrocarbon contents  are low,  the oxygen proc-
     ess is preferable provided that the oxygen can be obtained at low cost.
     The preheating process is used  for  those applications in which  the acid
     gas contains hydrocarbon impurities and  the H2S  content is moderately
     low.                                                         '
               I
               I                       t                        .    ;
     The sulfur-burning straight-through process is the most expensive proc-
     ess.  Since the entire gas stream is introduced  to the combustion cham-
               i                                            .       i
     ber, its temperature must be raised to the furnace operating tempera-
     ture.  The higher the furnace operating  temperature, the higher the
     operating cost and the larger the equipment required.
4.   Claus Tail-Gas Treatment Processes
               i
     The tail gas from  a properly  designed and operated Claus sulfur recov-
     ery plant may contain  from  8,000  to  28,000 ppmv of sulfurous, compounds  '
     (H2S, SO2,'COS, CS2, S vapor).6   In  order to comply with the; more       j ^ ;j.-".-.--
               i                        i                           ;             ...','.!"%-- '
     stringent current  regulations, many  processes have been developed to    < '-'-'i- i c
	            :                        i                           ;         	1 Di'.'ENiiO'.
     clean up Claus tail gases.	!	|	j PQR TAL.LE".
                                       .                           ^           '•'•"AND. iLLLJ."
                                                                  !            , 1 RAT IONS
           EPA-:-:V/ (Ciri.l
           (4-76)
                                          PAGE NUMBER

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              Figure  8    shows the principal Claus tail-gas treatment processes.  	
              Three basic approaches to tail-gas cleanup are employed.  With the
              first approach all sulfurous compounds are reduced to H2S in; a high-
              temperature catalytic converter.  The gas is then cooled and the  con-   '.
              densed water removed.  After the H2S is cooled,_i^is_eitherabsorbed~3.
              and subsequently regenerated as a concentrated acid-gas  stream for
              recycle back to the Claus unit or is reacted and recovered as elemental
                                                                          I
              sulfur.  With the second approach all sulfurous compounds ark oxidized
                                                                          \
              to S02 in a thermal oxidation furnace.  The SO2 is then  either absorbed
              eind subsequently regenerated as a concentrated S02 gas stream for re-
              cycle back to the Claus unit or is reacted to form another compound,
              which is then recovered as by-product.  The third approach is to  extend
              the Claus reaction at lower temperatures.  When a catalytic system is
              operated at a lower temperature than normal (near or below the sulfur
              condensation temperature), the thermodynamic equilibrium for the  forma-
              tion of sulfur from H2S and S02 is further enhanced.  Processes based
                                                                          J
              on this approach are carried out in either the liquid phase with  a
              catalyst present or a gas phase, in which a solid catalyst bed is used.
                        i                      i                           i
                                              '                           :           :
              The choice of which tail-gas treatment process to use depends on  many
              factors, principally those given below:
              1.    the composition and volume  of the  tail  gas,             ;
              2!.    whether the system can be integrated as part  of a new  installation
                   or whether it is an add-on  to an existing Calus plant,  i
                        ;                      j
              3.    the initial investment cost and/or the  operating costs,,
              4.    the utilities required,  the sulfur product produced, and/or  the
                   wastes produced,
              5.    the performance, reliability,  and  operating range of the  system.
                |
      The Shell Claus off-gas treating (SCOT) process,  the Beavon sulfury
      recovery process (BSRP), and the Wellman-Lord (W-L)  process are the
      most widely applied processes.   If the tail gas is low in C02,  the SCOT
      process usually produces the best economics of the three.  If the gas
                                                                              1
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                        i
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          EPA-2S7 (Gin.
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              contains large amounts of C02,  the W-L or the BSRP  may be thje best

              choice.                           !
              1m excellent discussion of  the various Claus tail-gas treating proc-

              Cisses  is given in a paper presented by Goar at  the  Fifty-Seventh Annual

              Convention of the Gas Producers Association.6                I
BEGIN
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             REFERENCES*
SECTIONS '.?!

      '  ;:3T
             A. L. Kohl and F. C. Riesenfeld, Gas Purification, 3d ed., pp 421—422,
             Gulf Publishing Co., Houston, 1979.
                       1
             Ibid., p 441.
             "          I

            "Ibid.', p 382.    ~             '
       ! *•   Sulfur Recovery Catalysts for the Claus Catalytic Process.  :Pro-
             Catalyse, Technical Documentation, Rhone-Poulenc, Paris (September
             1978).    :          .             i
        5.
       ! 6.
        7.
        8.
BEGIN
LAST LINE
OF TEXT t
              A.  E.  Chute,  "Tailor Sulfur  Plants  to Unsual  Conditions," Hydrocarbon
              Processing 56(4),  119—124  (April 1977).                    !            >
                        .—                   <                           ;            !
              G..Goar,  "Current  Claus Tail Gas Clean-Up Processes," pp 152—163  in
              Proceedings of the 57th Annual Convention of  the  Gas Producers Associa-
              tion,  March 20—22,  1978, New Orleans,  LA.                  |            j

              P.  Grancher,  "Advances in Claus Technology,"  Hydrocarbon Processing    ;
              57(7), 155—160 (July 1978).    .
              '          i                      1                           i
              H.  Fischer, "Sulfur Costs Vary with Process Selection," Hydrocarbon
              Processing 58(3),  125—129  (March 1979>.
             *When a reference  number  is used at  the  end  of  a paragraph or  on  a
              heading,  it usually refers to  the entire paragraph or material under
              the heading.  When,  however, an additional  reference is  required for
              only a certain portion of the  paragraph or  captioned material, the
              earlier reference number may not apply  to that particular portion.
              3/8"
           EPA-2S7 (Cin.)
           (4-76)  . ,
I	il^ILili	
                  PAGE NUMBER
                                                                                       BOTTOM OF
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BEGIN
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                       ,4   V.   FACTORS INFLUENCING CHOICE OF PROCESS
                       i                  •     i                         .   :•
                       i    ..                   !.          •               '  ,   .
              In selecting a  gas-treating process to remove sulfur compounds many
              factors have to be considered.  The most important are the following:
              1.    the product-gas specifications,
              2.    the quantity of acid-gas components (CO2 and H2S) contained in the
                   gas,
                        i
              3.    the influence of impurities such as COS, CS2, mercaptans  (RSH),

                   NH3, and HCN,               !

              4.    the quantity of heavier hydrocarbons in the gas,
                                               i
              5.    the condition of the feed gas (temperature and pressure),
        I  ,__•_
6.   the capital and operating costs of the process.
         A.    PRODUCT-GAS SPECIFICATIONS
                        i

                        1
         1.    Sulfur Compounds
                        i
              Sulfur compounds are removed to prevent air pollution by SO2i when the
                        i                       i                            i
              gas is combusted.  They are also 'removed for safety and to prevent
                        1                       !
              corrosion and odor problems.  For^ natural-gas distributed byi pipeline
                        •                       '      •      -          •      •        3
              the total sulfur content is reduced  4.6 grams,     or less,  per 100 m
                        1                       ;    -        .  •             I
              of gas.  If the gas is used as chemical feed stock, sulfur compounds
                        i                       i
              often have' to be reduced to less .than 1 ppm to protect sensitive cata-
              lyst systems.
              Generally the cost of removing the sulfur increases as the degree  of
              removal required increases.  Achieving a high degree of removal  often
                                               i                           [
              requires sacrificing other desirable process features, such ^s H2S
              selectivity, process simplicity, 'or favorable operating economics.  The ;
                        i                       i           '.               I
              higher the degree of sulfur removal required the more limiting the
              process selection becomes.
                                              65
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                                            O!
K-2AD;
   ,' >""7 ! *
co,       ..                      j                           :
Carbon dioxide and inert gases have no harmful effect  other than that
of reducing the heating value of the gas.  Often  C02 can be jtolerated
and does not have to be removed.                            i
BEGIN
LAST LINE
OF TEXT r.
         B.
                                                                         TOP Or
                                                                         IMA&c
                                                                         "A!-FA
        j 3.    COS, CS2/ and RSH                j                           i
              Carbonyl sulfide, carbon disulfide, and mercaptans contribute to  the
              total sulfur content of the gas and generally must be removed to  the
              same degree as H2S.
                        i
         4.    Dew Point
              In a saturated gas a drop in .temperature or an increase in pressure
         _.._ 	will_cause water to be condensed in, the..lines.. ..Therefore-the .gas	  J
              should be precooled to the lowest temperature to be encountered in the  ;
              system.  Similarly, condensable hydrocarbons could condense out if the  I
              gas conditions dropped below their condensation point.
                      b-i/o       •              •
                        I
         5.    INH3       j
              If not removed, ammonia cbuld be a problem in that NO  compounds  could
              be formed when the gas is combusted.  Also, ammonia could be detri-
              mental to some desulfurization processes.                   :
ACID-GAS COMPONENTS
The most important factor in choosing a gas-treating process is the
quantity of acid-gas components, CO2 and H2S,  contained in the gas and
          I                       !                           !
the volume ratio between these two components.   If the total quantity
          !                       i                     .
of sulfur contained in the gas is small, less  than  9  tonnes/day, a dry-
          '                       '                           ]
bed or direct-oxidation process may be more  economical.  If•the quan-
          •                       i                           j
tity of sulfur is greater than 9 tonnes/day, an indirect process may be
more economical.
              Although the Claus process is preferable for recovering sulfur  from
                                               ;
              concentrated acid-gas streams produced by indirect processes, it  re-
                                                                          EOTTOM Oc
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quires an acid-gas feed containing greater  than 15% H2S for ]effective—J DIMENSION'
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        __   operation.  The higher "the concentration of H2S in the acid gas the  	
             more effective the Claus system will be.                     !

                       !                     .r                          "
             Since all liquid-phase indirect processes absorb some C02 alpng with
        ~~   the H2S, an indirect process ^elective J^owar^d H2S should_be_used ifjthe
             CO2/H2S ratio in the feed gas is greater than 1 and is essential if the
             ratio is greater than 6.  If it is necessary to remove the Cp2 along
             with the H2S, when the C02/H2S ratio is high, a process selective
             toward H2S removal should be used followed by a process thati can remove
                       i                       l
             bulk quantities of C02.  If the acid-gas stream contains less than
             about 5% H2S, it is usually more economical to process the acid-gas
                • .      .                       j                        •    '
             stream by a liquid-phase direct-oxidation process than by thfe Claus
             process.         r -

        C.   INFLUENCE OF IMPURITIES
             Host direct-recovery processes will not remove COS or CS2 and will only
             partly remove mercaptans.  The alkanolamine processes will remove       j
             organic sulfur compounds, but the  lighter alkanolamines  (MEA|) and to    j
                       '•                      '                            ;           !
             some extent DEA form nonregenerable thiosulfates, which  degrade  the     |
                       1                      *                            |           !
             solvent when COS or CS2  is present in the feed gas.  Most alkaline salt;
             processes  remove COS and CS2 by hydrolyzing them  to H2S, but mercaptans .
             are only  slightly  absorbed.  The physical-solvent processes  [effectively .
                        i
             absorb organic sulfur  compounds.
If ammonia is not removed before the acid-gas absorption step, it will
be absorbed with most processes and end up in the acid-gas stream.
Most ammonia in the gas can be removed with the condensates ±n the pre-
                                 i                           i
cooling step.  Small amounts of ammonia can be tolerated by ;the Claus
unit if the quantity of ammonia is small compared to the quantity of
1H2S in the, acid-gas stream.
          I
Hydrogen cyanide is largely co-absorbed with the other acid gases and,  . ^
if the absorbent solution does not contain oxidants, will end up with   j :;;AG=AR£-
          I                       i                                       I rii 'TS'DE
the acid-gas stream.  In the direct-recovery processes HCN is convert*^ D:"-NSIGiv
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              to stable thiocyanates,  which will build up in the solution 'and require
              that a portion of the solution be purged.
                        !         .••••!                           I     '
              If condensible hydrocarbons are absorbed, poor-quality black sulfur
              will be produced by direct-recovery processes..	Hydrocarbons in the	
         D.
         E.
5-ZG1N
LAST LINE
OF TEXT :-,
acid-gas feed to the Claus unit will increase the combustion air re-
quired and necessitate that the Claus thermal oxidizer be operated at a
higher temperature to assure complete combustion of hydrocarbons.  If
the hydrocarbons are only partly oxidized, the catalyst beds can become
plugged or a poor-quality sulfur can result.                ,
          *                       '                           i
Generally the alkaline salt and alkanolamine processes will not appre-
ciably absorb hydrocarbons.  The physical-solvent processes,; however,
will readily absorb hydrocarbons heavier than butane.
          !
CONDITION OF FEED GAS
                                 i                           !
Most processes are carried out at near-ambient temperatures 1(16 to
 54°C).   The physical-solvent processes are most effective at  lower
temperatures, and some require that the gas be chilled.  In most of the
currently applied alkaline salt processes elevated temperatures of up
          i
to 149°C can be used.
          !
          j
The physical-solvent processes arid most alkaline salt processes require
a high pressure, above 150 psig, to function efficiently.  The alkanol-
          1                       |                           !
amine and direct-recovery processes are generally independent  of pres-
          *                       •
sure and can be used equally well over a wide range of pressures.
CAPITAL AND OPERATING COSTS
The bottom line in choosing a process is the capital and operating
costs.  Generally the more sulfur contained in  the gas  the  less  the
          \                       ;                        -   ;
cost on a unit basis ($/tonne) to remove it.  If  sufficient sulfur com-
pounds are present in the gas, an indirect-recovery process 'followed by
                                 i                           I
a Claus sulfur recovery unit will provide the best economics.  The
physical-solvent processes are more economical  when the acid-gas con-
tent is high or when the gas exists at high pressure.   The  alkaline	
        I
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                                              .1.
                       J
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           (4-76)
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              salt processes have an advantage over other processes when the gas is-
              at high pressure and high temperature and contains  moderate amounts of
              acid gas.   The alkanolamine processes are most  economical whbn the gas
              is at  low  pressure and contains little CO2.  For  gases that contain
              little H2S or that have very high CO2/H2S ratios  the direct-conversion.
              processes  may be more economical than the indirect-conversion proc-
              esses.  If complete removal of H2S is required  and  the gas contains
              little H2S,  the solid-bed processes may be the  most economical ones.
                      9-1 "8"
BEGIN
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           EPA-2^7 (Cin.)
           (4-76)
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                                            i. •'. i •.;•:

       .!'.„ VI.  DUTY REQUIREMENTS  FOR OIL-SHALE  RETORT-GAS-DESULFURIZATION SYSTEMS —

        A.   CLASSIFICATION OF OIL-SHALE  RETORTING PROCESSES              j
             From  the  standpoint of removing  sulfur compounds from oil-shale retort
        \     gases all retort processes can be divided into two_broad_and_ widely	
             separated categories:   those in  which direct-fired retorts are used
             either above  or below ground (in-situ), where combustion occurs within
             'the retort; and those in which indirect-heated retorts are used and the
             shale is  retorted in  the absence of air.                    [
                        :                       '                '           •
             The application of desulfurization  technology for gases produced from
             (direct-fired  oil-shale retorting processes is distinctly different from
             that  required for natural gas, coke-oven gas, refinery gas, tor gas      ;
             produced  by coal gasification or, for that matter, for gas produced     :
             from  indirect-heated  oil-shale retorting process.  Typical compositions
             of the gases  are shown in Table   22. -1—3  The gas from direct-fired    .
             retorts contains large amounts of inert components, over 63%'N2 and 22%
             CO2,  but  the  H2S content is  less than 0.3%; it also contains large      •
             amounts of ammonia and unsaturated hydrocarbons, such as acetylene,     j
             ethylene, propylene,  butylene, and butadiene. More than 40 hydrocarbon
            • compounds have been identified in the gas; it is saturated with water   j
             and contains  some oxygen and trace amounts of sulfur species other than j
             H2S.
Table  23 ' gives the range of gas compositions from direct-fired re-
torts, and Table  24  gives the range of those produced by indirect-
heated retorts.  The overiding factor that separates the two groups of
processes and that will be dominant in selection of sulfur removal
processes is the C02/H2S ratio.  For direct-fired retorts the C02/H2S
ratio ranges from 76:1 to more than 165:1, thus requiring a!sulfur
removal process that will selectively remove H2S.  Indirect-heated
retorts produce a CO2/H2S ratio in the range of 4.3:1 to 5:1 which
would allow a nonselective process to be used.  As defined in Table  25
  H2S selectivity is the molar ratio of H2S absorbed to CO2 absorbed.
If an indirect recovery process were to be used in conjunction  with_a.	
          ,	 j...-...•.•.-.•.•.
          \T                &w'"'76'-x$:
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                                             •AK'D ILLUS-
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<^i A ^* "3 O

-------
 Table 23...  Range of Gas Compositions from Direct-Fired Retorts'
Oil assay
Gas ratio
Composition  (dry basis)  ,
  Carbon dioxide  (CO_)
  Hydrogen sulfide  (H_S)
  Carbonyl sulfide  (COS)
  Ammonia  (NH )
  Water  (HO)  (wet basis)
Gas mole ratio
  C02/H2S
  NH3/H2S
Temperature
Higher heating value  (dry gas)
62.5 to 125 5,/torine
224 to 405 smVtojnne

23 to 39 vol %
0.07 to 0.24 vol %
0 to 40 ppm      i
0.6 to 0.7 vol % i
13.5 to 15 vol % '

76:1 to 165:1°   i
2.3:1 to 2.4:ld
57 to 77°C       j
1.52xl06 to 4.13xl06'joules/sm3
 Based on Paraho PON, Occidental Oil Shale  (Gxy) retorts 7 and 8,
 and Geokinetics retort 18.                                 i
 Ratio for Geokinetics is 0.07:1.                           i
C                                                           '
 High ratio occurs at start of Oxy burn and averages about 330:1
 during the startup phase.  At steady-state conditions an average
 ratio of about 165:1 is obtained.
                                                            !
 Ratio reduces to 2.4:1 at steady state for the Oxy retort.
                                 72

-------
            Table  24.    Range of Gas Compositions from
                     Indirect-Heated Retorts
Oil assay                                    '  158  S, /tonne i
Gas ratio                                      29,9 to 38.5 sm3/tonne
Composition  (dry basis)                                     ;
  Carbon dioxide  (CO )                         16.6 to 20.4 vol %
  Hydrogen sulfide  (H2S)                       3.8 to 4.1 vol %
  Carbonyl sulfide  (COS)                       135 to 550 ppra
  Carbon disulfide  (CS_)                       0 to 20 ppm  ;
                      2                                     i
  Alkyl mercaptans "(RSH)                       35 to 165 ppm
  Sulfur dioxide  (SO )                         0 to 125 ppm !
               b                                      c     ;
  Ammonia  (NH )                                8 vol %      ;
             3                                              i
  Water  (HO)  (wet basis)                      20 to 25 vol $
Gas mole ratio
  CO2/H2S                                      4.3:1 to 5.0:1
  NH3/H2S                                      2*1
Temperature                                    60 to 71.1 °C;
Higher heating value  (dry gas)                 35.20xl06 to ^2.46 joules/sm3
'Based on Tosco-II and Union SGR-3 retorts.
 Absorbed in sour water condensed with the oil.
«                                                           '
 'Calculated value.
                                73

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                         Table   25 -  Selectivity Data
Selectivity
      (H S feed - H S treated gas) fR^> feed   H2S Claus  gas/H2S feed


      (CO  feed - CO  treated gas) /CO.,  feed ~ CO  Claus  gas/CO_ feeii
        22                22              2    ,
             CO_ feed   H  S Claus  gas   mole % H S absorbed


             H S feed   CO_ Claus  gas  ~ snole % CO, absorbed
              22                       ^
For direct-fired retorts
CO_ feed
                                            feed    11
For indirect-fired  retorts
CO2 feed


H2S feed =  T
For Claus  feed gas
                                            >0.08 to 0.25
Selectivity required
     Direct- fired retorts
                                       .76
   X  (0.08 to 0.25) =  6
                                      .165 .
                                        1
                                           X (0.08 to 0.25) = 13 to 41
     Indirect- fired retorts
•   X  (0.08 to 0.25)  = 0.4 to 1.25
                                      •74

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                Tti'{{•;(.] GUIDE SH£i:T
 V-r<.£ or
 Ti-xr   __
        i
,.».^  |
BEGIN
LAST LINE
OF TEXT E
     Claus  sulfur  recovery process,  the acid-gas feed to the Clau|s unit
     should be  as  rich in H2S  as  possible and consist of at least 8 to 25%
     H2S.   Gases from direct-fired retorts with CO2/H2S ratios in the range
     of  100:1 to 200:1 would require H2S selectivity in the range' of 8 to 50
~T_	 to  produce an_ acceptable  Claus  gas (see Table  2_5_);_ however;, gas from
     indirect-fired retorts would produce an acceptable Claus gas' only if
     all the CO2 were removed  along with the H2S.                I

                1                   •                               :
     The quantity  of H2S  and NH3  in the gas per ton of shale processed is,
     as  shown in Table   26  about equal for both direct- and indirect-
     retorting  processes.  The quantity of sulfur contained in an equal
     volume of  gas,  on the other  hand,  is as much as 60 times greater for
     indirect-fired retorts than  for direct-fired retorts.  Thus a gas
     treatment  system for a direct-fired retort would have to process up to
     SO  times more gas per ton of sulfur recovered than would a system proc-
     essing gas from indirect-heated retorts.
             9-1/3"
                I
B.   COMMERCIAL OIL-SHALE OPERATIONS
                i                      i
     The projected sizes  of several commercial oil-shale processing facili-
                i                      i                            !
     ties are given in Table  27.    All full-scale processing facilities
                i                      i                            ;
     will consist  of multiple  retort systems with several trains jof gas
     treating equipment.
                i
              '  I
     The data given in Tables   22   and   23  are based on the gas discharged
     from the retort after the oil is separated.  The actual composition and
                i                      i                            !
     condition  of  the gas as it reaches the sulfur removal train may be
                                      i                            ;
     somewhat different for a  full-scale commercial plant if additional
                                      j                            :
     product recovery and gas  treating  steps are incorporated.  For most
     direct-fired-retort  processes water scrubbing will be used to remove
                1                      i
     ammonia from  the gas and  to  cool the gas before it enters the sulfur
     removal equipment.  Some  developers propose to compress and ithen cool
                i                      '
     the gas to recover additional hydrocarbons.  Some may elect to upgrade
     the raw crude by coking and  hydrotreating and/or direct hydrjogenation.
     Residual gases from  these operations would likely be added to the feed
•-    to  the sulfur removal units.
              3/8"
                                         SIS-' 75  /xg:
 D:,V:=,\S;O-
 FOR TAE_=
'AND'iLLUS
 TRAT!G.\S
           EFA-287 (Cm.)
           (4-7G)
                                          PAGE NUMBER

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         Table   26.    Comparison of Gas Treatment Duty Requirements


Duty Range Per 45,450
Gas rate (Msm3D)
Hydrogen sulfide (tonnes)
Other sulfur compounds (tonnes)
Carbon dioxide (tonnes)
Ammonia ' ( tonnes )
Total sulfur (tonnes)
Duty Range Per Million
Direct-Fired
Retorts
Tonnes of Shale
10. 2-- 18. 4
33.6—64.5
o;Q4— 2,.o
;4, 545— 32,087
38—95.
32—62
Indirect-Heated
Retorts
Processed
1.4—1.8
78.. 2— 85.4
0.6—3.3.
443-r-r545
83—106
74—83-
Cubic Feet of Gas Treated
Shale processed (tonnes)               70—126        "         734f-947
Hydrogen sulfide  (kg)                  -30—103                 .1,636—1,773
Other sulfur compounds  (kg)             ".5—3                  12-r64
Carbon dioxide  .(kg)                   •12i727—21,818          9,250—11,363
Ammonia  (kg)                          M30--151                l,^?--1,818
Total sulfur (kg)                      29—99.-                 1-547—i; 710
                                       76

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BEGIN
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               Indirect-retort gases that have high heating values may be combined  	
               with  residual gases from other process steps and may undergo' several
               treatment steps before they reach the sulfur removal equipmept.  For "
               instance  the  shale-oil hydrocarbon vapors from the pyrolysisj drum of
             .J*®_Pr°Posed. Colonv.irosco":!:.I.._facility wi.ll be j?.ePar2ted_in_ a| fraction^
               ator  into sour water, gas,  naphtha, gas oil, and bottom oil.  The gas
               and naphtha are piped to a gas recovery and treating unit.  The other
               streams are further treated to upgrade the product.  The residual gases
               from  product  upgrading units are combined with the gas strewn from the
               fractionator  and then compressed and fed to the gas recovery! and treat-
               ing unit  along with raw naphtha recovered from various treatment units.
               Stabilized naphtha,  LPG,  butanes,  butadiene/butylenes, and ammonia are
               separated and recovered.   The remaining gas then enters the sulfur
               removal equipment.   Acid gas with residual ammonia from the sour-water
                                                                           r.
               stripper  and  from the ammonia separation unit is sent directly to the
               Claus sulfur  recovery unit.      [                            <
                      9-1/3"                                   "             :
                         i                                                  ]
               For the purpose of  this report it  is assumed that the composition of
               the gas is as  discharged from the  retort after the oil has bien sepa-
               rated,     l
            T
                    _1

                                          bOTTCV. CF
                                          IMAGE AF.l
                                          OUTSIDE
                                          DI.V-iNSiOX
                                          FOR TA3L.U.
.78
           EPA-^37 (Cin.
           (4-76)
                                          PAGE NUMBER
TRATiOX'S

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          i.
         "27'
         3.
               REFERENCES*
 M.  Gmassemi et al., TRW, Inc., Applicability of Petroleum Refinery
 Control Technologies to Coal Conversion. EPA-600/7-78-190 (October
 31978).                          !                             !

~H7 Hiraoka,'Mitsubishi"Chemical" InduYtYiesTLtd., ami E. Tana"kaTnd~H.~
 Sudo,  Mitsubishi Kakoki Kaisha, Ltd., "DIAMOX Process for the Removal
 of H2S in Coke Oven Gas," Proceedings of The Symposium on Treatment of
 Coke-Oven Gas. May 1977. McMaster Univeristy Press, Hamilton; Ontario,
 Canada.                         ;                             ;
                                 I
 W.  L.  Scheirman, "Sour Gas Treating at the World's Largest Natural Gas
 Processing Plant," p. 0-8 in Proceedings of the Gas Conditioning Con-
 ference ,  March 7—9, 1977, sponsored by Continuing Engineering Educa-
 tion,  University of Oklahoma, Norman.                        i
BUG IN
LAST LINE
OF TEXT -V
             *When a reference number is used at the end of a paragraph or on a head-
              ing, it usually refers to the entire paragraph or material under the
              heading.  When, however, an additional reference is  required ifor only a
              certain portion of the paragraph or captioned material,  the earlier     :QVTOM OF
              reference number may not apply to that particular portion.  '••
                    _ J	
           ECA-237 (Cin.)
           (4-70)
                                         PAGE NUMBER
                                                                          •'.'AGE ARE
                                                                          OUTSIDE

                                                                          -C^ TAELL.
                                                                        •.-AND ILLUS
                                                                        '  -;-.-.Tio:.s

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M::-\D.
         A   VII.  SCREENING OF GAS TREATING PROCESSES               —
          i                      !                             :.    -
          i                      i                             ;
Gases from direct-fired retorts are more limiting in the application of
sulfur-removal technology than are other gases (see Sect. VIrA).  In
the course of this study it was determined by the EPA_Jthat_the greatest
immediate concern was the control of sulfur emissions from direct-fired
                                                             i
processes and that the pilot-plant design should be applicable to these
retorting methods.  Therefore process selection was directed toward the
          i                      m                                        ;
requirements for desulfurization of gas from direct-fired retorts.      j
BEGIN
LAST LINE
OF TEXT :••£_
        I
              As is indicated in Table .23,  treating gas from direct-fired retorts
                                                                          I
              requires a process with high selectivity toward H2S.  The initial

              screening of principal commercial gas-conditioning processes! was there-

              fore based on the ability of each process to selectively remove H2S in

              the presence of large amounts of CO2.  Those processes most capable of

              selectively removing H2S were selected as candidates for morje detailed

              evaluations.  The processes referred to are shown on Fig.  9,    a

              duplicate of Fig.  6.    For the purpose of the initial screening,

              iselectivities near the midpoint of the selectivity range reported in

              the literature were used (see Table  28  ).                 :
                    _ «	
A.   DIRECT-CONVERSION PROCESSES      ;
               I                       !                           !
     In the direct-conversion processes the sulfur compounds are directly

     oxidized to elemental sulfur or are converted to another compound,

     which is then separated or recovered.
               i
               I
1.   Dry Bed   j

     Several dry-bed direct-conversion processes have been  tested but none

     are known to have been commercially applied.  These processes  are
               I                       ;                           i
     similar to the Claus process except that the S02.necessary for the

     reaction is obtained by burning sulfur in an external  burner, and the
               t                       ;
     gas to be treated is preheated to the operating temperature >of the

     catalyst beds.  To maintain high conversion efficiency the catalyst

     beds are regenerated more frequently than is required  by the Claus

     process.  One version is designed so that the catalyst is continually_.

                                Sx   8b"3:S:|:                     ;

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           EPA-287 (Cin.)
           (4-7G)
            I
                                          PAGE NUMBER

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                                                 81
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Table  28.    Selectivity of Absorbent Processes
Absorbent
MEA
DEA
MDEA
DIPA
NH_
3
Diamox
Benfield
Selexol
See ref 5.
See ref 6.
°See ref 10.
d
See ref 13.
See ref 9.
See ref 14.
Selectivity Range
0.89
1.2 to 2.27
1.2 to 7.0
3.33 to 5
1.00 to 28.9

5.7 to 9.4
2.25 to 9.8
5 to 22







Reported By
Pearce ;
Pearce
Pearce ;
Naber et al.
Kohl and Riesenfeld '

- ja
Hiraoka et al.
Parrish and Neilson '
! f
Kohl and Riesenfeld

!
i
'
i

|
                      82

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                  r^i.-iG GUIDE wrn
BEGIN
LAST LINE
OF TEXT I:*
          .__   withdrawn from the bottom of the bed and  the  regenerated catalyst  is --
               added at the top.1               j                          \   .
                         i                       I     .   •   '               !
                                                '.                          i
               The Haines process uses a bed of synthetic zeolite to adsot-b the H2S.
         rl	The. b.fd.,is. theri_.^?e.nerated._wit.h high-temperature gas that • contains^'
               sulfur dioxide.  The sulfur formed is condensed and recovered.
                         i
                         I                       !
               The application of these processes is limited due to the possibility
               that the beds will be plugged by condensible hydrocarbons and/or other
               impurities in the gas.  Since these processes have not been commercial-
               ly proven,  they are not considered further.                i
                        '                       I                          :
                        !
          2.    Liquid Phase                                               j
               Except for the EIC process the  principal liquTd^haIe~di"rie"ct^c7nvIrIion'
               processes shown on Fig.  9    selectively remove H2S by converting it
               directly to elemental sulfur.   Carbon dioxide is only slightly absorbed
               and largely'remains in the treated gas.   With the EIC process,  sulfur
               is  removed  as  ammonium sulfate  and C02  is not removed.      ;            |

                        1                       I                          l            \
               The Stretford, Giammarco-Vetracoke  (G-V),  and Takahax processes  are    *
               based  on similar  oxidation-reduction  chemistry but use  different acti-  '
               vator  chemicals.   The G-V process uses an arsenic compound/ but  because '
               of  arsenic's toxicity the process is not  applied in this  country.   The
               Takahax process,  developed in Japan, has not been widely  applied.
The Ferrox process, which  is based on the  reaction between iron oxide
and H2S, is outdated and has been  replaced by the  more  efficient Stret-
ford Process.  In the Stretford process, the  direct-conversion process
most often employed, H2S is selectively removed by direct  oxidation to
elemental sulfur but CO2 is only 'slightly  absorbed.  The process is
usually the preferred choice when  the H2S  concentration in the raw  gas
is very low or when a high degree  of selectivity is required.   Complete
removal of H2S to about 1 ppm can be obtained  in the treated gas.
Since the sulfur absorption capacity of the Stretford solution is low,
the process is not competitive with indirect sulfur removal!processes'"
3/8"     v                 ssrsi  "m         ' '                     "
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                                                                                       BOTTOM Or
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.-AND ILLUS-
| TRATIONS
          EHA-237 (Cin.)
          (4-76)
                                         PAGE NUMBER

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BEGIN.
LAST LINE
OF TEXT i
         B.
         1.
 for volumes of H2S in the feed .gas that exceed about 16% of the total
 acid-gas content of the gas.2   :                            ;
           I       •               !                            i
           !                      !                            i
 Organic sulfur compounds are not removed by the Stretford process but
 remain in the treated gas.  Stable thiosulfates form in theJoxidizer	
' "	——>— -• •  - • •   •  .*.         ....    .  ,,_...    . - -  —   .»- — --    — ^       •   —«
 equivalent to about 1% of the sulfur in the feed gas.  A portion of the
 circulating solution must be purged to control the buildup of these
 compounds.'  The quality of sulfur produced is low compared to that
 produced by the indirect-recovery processes. In spite of its: shortcom-
                                                             \
 lings the Stretford process has been widely applied, and when, the CO2/
 H2S ratio is very high, it may be the only process available! that is
                                                             1
 capable of economically purifying the gas.
           i                                                  !
           i                      l
                                 I                            i
 The EIC process is an absorption-oxidation process using copper sulfate
 as the absorbent that produces by-product ammonium sulfate from the
 hydrogen sulfide and ammonia in the treated gas.  The process reported-
 ly removes H2S and COS and ammonia but does not remove C02.3:  A high
 removal efficiency of 99% is obtained in one absorption step and the
           i                      .                            I
 system can operate at elevated temperature.  The process is in the
 development stage and has not been commercially proven.  However, since
 it appears,to match the requirements needed for desulfurization of
           i                      .                            i
 direct-fired oil-shale gases, it will be considered as a canidate for
 further evaluation.
           i
           !
 INDIRECT-CONVERSION PROCESSES
           '                      '      "          '            ;
 In the indirect conversion processes the acid-gas components! are re-
 moved from the fired gas and recovered as a separated stream; that is
 subsequently processed for recovery of sulfur.              i
 Dry Bed   ,
 The dry-bed indirect-conversion processes provide excellent selectivi-
 ty, with most of them capable of removing sulfur compounds with little
 or no C02 removal.  These processes use a fixed bed of solid, material.
 Processes that use molecular sieves or carbon adsorb the sulfur com-
 pounds, which are subsequently released^unchanged during regeneration	
                                                                                       5C7TCM 0
                                                                                       '.'. -, JE A.-.~
                    _   _____ i
                                                                         •AND ILLU5
                                                                          TRATION3
           EPA-2S7 (Gin.)
           (4-76)
                                         PAGE NUMBER

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        !  2.
BEGIN
LAST LINE
OF TEXT t
        1
               of the bed.  With the iron sponge and zinc oxide processes- H2S reacts
               with the bed to form iron or zinc sulfide.  The Katasulf process is
               based on the catalytic oxidation of H2S to SO2, followed by removal of
               S02 with an ammonium sulfite—bisulfite solution.
 Dry-bed processes, however, are  limited in  their  application and become
 economically impractical for  those cases where  large amounts of gas
 have to be treated or the total  quantity of sulfur  to be  rejmoved is
 high.  Since full-scale oil-shale facilities will be processing huge
 amounts of gas beyond the practical limit for application of dry-bed
 processes, these processes are not considered further
    1       !                       I                          ;             •
 Liquid Phase       -
,. _	 	 _	_  ;• ". ••-;"	J_	 	  	 	 .	 	 '   	
 With liquid-phase indirect-conversion processes the acid-gas  components
 are removed from the feed gas by absorption into  liquid.  T|he liquid is
 subsequently regenerated to produce a concentrated stream o'f  acid gas,
 which is'then processed by the Glaus process for  recovery of  the sul-
 fur.   The principal liquid-phase indirect-conversion processes are
 shown on Fig.  VII-1 and are classified by type.             •
           I                       J                          '             '
 Alkanolamines	The alkanolamine processes are based on the1 reaction of
 a weak base (alkanolamine)  and a weak acid  (H2S, organic aciLds, and/or
 C02)  to form a water-soluble salt:
                   RNH2 + HS
                     •*• RNH3 • HS
                   RNH2 '+ C02 + H20
                              RNH3 • HC03
 These reactions are reversible,  and the equilibrium may be shifted by
 adjustment of the solution temperature.  The absorption of CO2 involves
 the  formation of carbamates as  intermediate compounds.   With primary
 and  secondary amines the  carbamates are formed nearly instantly and the
 reaction  rate of CO2 with the amine is  nearly equal to that;of H2S with
 amine.  With  tertiary amines carbanates form at a much slower rate and
 therefore ^f^^gb^or^ed_mgre_readly_than_is_CO2.   This difference ii~
           i             "•       ~]      ~"      '   "          i      "    ""
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CF TEXT
               reaction  rates between H2S and C02 accounts for the higher selectivi-
               ties  that are obtained with tertiary amines.  Methyldiethan^lamine
               (MDEA) reportedly produces the highest selectivity of the tertiary
               amines4—6  (see Table   28 ).
              The selectivity at which H2S can be absorbed in the presence of C02
              depends on absorption kinetics rather than on equilibrium effects.   The
              actual selectivity obtained by a process is dependent on several vari-
              ables, the most readily controlled being the absorber contact time.  In
              practice high selectivity is obtained by limiting the number of contact
              stages in the absorber and the residence time per stage.  Absorption
              kinetics are also affected by a variety of other process variables,
              including competition between H2S and C02 when they are absorbed simul-
              taneously.  The degree of H2S removal decreases as the contact time is
              reduced in an attempt to increase the selectivity.  The extent of
              selectivity that can be obtained will be restricted by the parity re-
              quired of the treated gas.  To reasonably predict these effects for a
              specific gas composition and at a specified degree of desulfurization,
              the process developers have devised proprietary computer programs for
              modeling the absorption process.7'8  These models were developed and
              verified through extensive laboratory and field testing programs.
              The average selectivity of MDEA as reported by Pearce5  is 3.85.  If a
              two-stage selective absorption system were  used and a selectivity of
              3.85 per stage were obtained,  the H2S in the acid-gas stream would be
              about 12.9 vol % for a feed gas with a CO2/H2S ratio of 100:1  (see
                        ,                      .                          I
              Table   29 ).   If the ratio were 200:1,  the acid gas would contain
              about 6.9% H2S, which is marginally acceptable.  A  possible process
              option would be a system consisting of two  or more  stages of selective
              absorption, with MDEA used as  the solvent.                  !
      Alkaline Salts	The principal alkaline salt processes,  shown on
      .Fig. VII-1, are most successfully applied for bulk C02  removal but  are
      not generally considered when selective absorption of H2S  is  required.
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               Table   29.   Selective Absorption Using MDEA
                          with Two Stages of Absorption
    Feed
   ©
               Treated Gas
t
   C02 Vent
R
«-
(3)
A
t
                                                            Sulfur
R
fe
(^)
C


RED
            i	!
                                                                              t
CO2 Vent
A e ab'sorption; R = regeneration; C = Claus.; RED = reduction.
{	i	L	i
  Streeun
C02/H2S
 Ratio3
                                    (vol
Case 1
 Q) Feed 1st stage
 ^y Feed 2nd stage
 (3) Claus gas
Case 2
 (l) Feed 1st stage
 (2^ Feed 2nd stage
 @l Claus gas
Case 3
 (l) Feed 1st stage
 (£• Feed 2nd stage
 (5} Claus gas
 100
 26
 6.7

 200
 51.9
 13.5

 4
 1.04
 0.27
                                     3.7
                                    12.9

                                     0.5
                                     1.9
                                     6.9

                                    20.0
                                    49.0
                                    78.7
aBased on obtaining selectivity ratio of 3.85 per stage.
 As vol % of total CO2 and

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r , .. > {
i.!;'.'- Or
                                            CE.;.;iLn
                                            r,r iv1.-..-.'•
                                     not
                                                                                       If.'AGu
                                                        buik
            ess using DIK solvent
                                        seect   ,
                                                  y
                                                          The Alkacid proc-!
 wlutlon, the
                        can b.   „
                               "
                                                                        carbonate
                                                                     B,.,1 but, as
                                                                     iVreaTesT ~
                                                                   -
              the M
produced selectiviti
                                                              rate of HzS. has
         To apply the Benfield process.
                            the selectivity that i
        P-Posed oil-sh,le retorts would be produc'ed^aTZ;  ™"^
        sure,  the pas would have to be compressed       near-atmosphere pres-
        costs  of compressing the oas     '                  P  a  and operating
        process.  kiso/  since „      ^^  *  Justif"d by use of the jBenfield
                      "'  Si«ce H2s is less soluble in  th*>
        at higher temperatures,  the advJi™ ^ . .
                                                                   be
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           Table  30.    Selective Absorption by Benfield Process
          Compressor
 Feed
   <*
   1
t Treated Gas A Sulfur A CO- Vent
1 T
A



R


©


4 i • 4
1 	 ,


ppn


11
A*


IP


t'7* |



_i__ _ _j
A « absorption; R = regeneration; C = Claus, RED = reduction.
Stream
Case 1
^tti^
ij) Feed
Q) Clau:; gas
Case 2
(l) Feed
^^
^T) Claus gas
Case 3
• ^) Feed
(5) Clau:; gas
CO2/H2S
Ratioa
• *
;* f
100 , ~
17

200

33

4
0.7
i
H?S (vol %)

!•'
; i.o
5.7
i
! 0.5
1
2.9

20.0
60.0
*Based on selectivity ratio of 6.

 As vol % of total CO2 and H^S.
                                       89

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                  T.--
BEGIN
LAST LINE
OF TEXT 2
                Aqueous Ammonia Processes—Aqueous ammonia processes have Ibeen used  -
                since the end of the nineteenth century for removal of hydrogen sulfide
                and nitrogen compounds, primarily ammonia from coal gas.  Many ammonia-!
                based processes have been developed over the years; the principal ones
              	*.-a5e._?_.°wil_0.n.,f^9:	j. s _    Ammonia-based processes are par-
                ticularly applicable to gases containing both H2S and ammonia.  The ~"!
                ammonia contained in the gas  can;serve as the active agent for removal \
                of H2S and can be recovered as  a by-product.                ':            \
                         i                      j                                       .'

                If the physical parameters  of the absorption  process are controlled,    !
                aqueous  ammonia solution can  selectively remove H2S from gases contain-
                ing C02.   Selectivities  of  up to 28.9  have been reported." Hydrogen
              .  __ _._ 	1- _.	„ 	  : - I  •* " *	       	                **c 0 w^U (-^ VII CXXlU t 6 CiC wS
                rapidly with the hydroxyl ions~, wher^aTdrbon dioxide'mustTfirst" react'
               with water, forming carbonic acid, before it  can react ioniklly with  '
               ammonia.  The rate of the C02 hydration reaction is  quite low  compared '
               to the reaction rate of H2S.11
           i
 The  absorption of ammonia into water is quite rapid and is governed
 principally by the gas-film  resistance.  The rate of absorption of H2S
. into aqueous ammonia  solutions is  also  rapid although it is 'dependent
 on the ammonia concentration and 'is  probably also governed by the gas--
 film resistance.   Carbon  dioxide absorption  into  water or weak alkaline
 solutions, on  the  other hand,  is|governed by its  liquid-film  resist-
 ance, which is very much  greaterjthan that for H2S. As a result when
 gases containing H2S, ammonia, and CO*  are contacted with wJter or
 ammonia solution,  the ammonia  and H2S are absorbed much more!  rapidly
 than is C02.  This difference  can be accentuated by operating under
 conditions that reduce the gas-film resistance or  increase  the  liquid-
 film resistance.  Thus to achieve maximum selectivity,  spray!  columns  in
 combination with relatively short contact times are used." !  Table 31   |
 shows the^results  that could be  obtained  if  a selectivity of  28.9      '
 were  achieved.   However,  the  degree of H2S removal decreases1as the     !
 selectivity is  increased.   Removal of about 90% of the H2S is the maxi- '
 mum efficiency  that can be attained
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      Table   -31.'   Selective Absorption Using Aqueous Ammonia
B2°i
Feed^ A
(l) (H2S)
" i!
!!
| |
+ 1

R —


1
-fr A
(NH3)
1
1
D
1
l_ -


**



	 J *
„
1 H2
JNH
'
Waste
^ Water
-





fr Treated Gas
B Final Absorber
Batch Loaded
.
A 4 C02 Vent

r * ' r } BEP 	 fr A 	 » R — i
C^)
^k ^ 11
T ' 	 J
                D = distiilation, .
                                                 n, C » C1aus, BED - „***!«.
 2  Claus gas
     C3.aus gas
     Claus gas
-._-----.  __
BBased on selectivity ratio of 28.9.
 As vol % of total C0  and

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             sorption.  A final purification step must be added to remove the resid-
             ual H2S if it is desired to achieve a high degree of removal with a
             high degree of selective absorption.                         >
BEG'N
LAST LiNE
d.
             The selectivity_of _aqueous_ ammonia solutions_decreases_mar_kedly_ at	
             temperatures above  27°C.12  Also, the selectivity decreases as the
             ammonia concentration of the solution is increased.  However; the
             degree of H2S removal increases as excess available ammonia is in-
             creased.  The Diamox process, recently developed in Japan, was designed
             to take maximum advantage of these factors.  Hydrogen   sulfide removal
             in the range of 97  to 99%, with good selectivity still  maintained,  can
             be achieved by the  Diamox process.  Selectivities in the  order of  5.7
             to 9.4 have been obtained based on data reported_by_Hiraoka,_Tanaka,_
             andTsudo.13  If an  average selectivity of  7.6 were obtained with  the
             Diamox process (Table    32 ), an  acid gas containing 7.1% would be ob-
             tained for a feed gas with a CO2/H2S ratio  of  100:1, or 3.7% H2S would
             be obtained if the  ratio were 200:1.  The Diamox process  would be
             marginally acceptable for  gases with C02/H2S ratios of up to about
             100:1 but would not produce sufficient selectivity  for direct-fired
                       i                        j                          '
             ire tort gases with higher CO2/H2S  ratios.
             Physical-Solvent Processes - Selectivity of physical-solvent processes
             depends  on the relative solubilities of CO2 and H2S in the solvent.
             The capacity of the solution for absorbing H2S increases with increas-
             ing pressure and decreasing temperature; generally the higher the par-
             tial pressure of H2S the higher the selectivity attainable will be.
             Selectivity can also be enhanced by favorable absorber kinetics.
              The Selexol process appears to produce the highest reported selectivity .
              of the physical-solvent processes; H2S is 9 times more soluble in the   j
              Selexol solvent than C02 is.  Selectivity ratios of up to 22 have been
                        '                       '                      1*1
              obtained based on data reported by Kohl and Riesenfeld.1*   '•-
              To apply the Selexol process the retort gas would have to be compressed
1_^AO I 1-1 l\ — \                ;                       t                           ' _    .  .     I
OF TrvT t W^   and cooled before it entered the absorber.  If^an_Jave_r.a^e_sele.ct_iyity._r.;
\J t  I fc_-T I  ^^|         	       	 ,1111   i 	 " •  ~ '" "", ~~~	  -'     " "                          ».
        I	 |^''^	_J	|C.'.:92.'.'''|j;
                                                                               BOTTOM OF
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                                                                               "OR TABLE::?
                                                                               •AND ILLUS-
                                                                               TRATIONS
                                          PAGE NUMBER
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           (4-76)

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         Table  32.    Selective Absorption by Diamox Process
     Feed
A  Treated  1 Water     A
I    GaS    i          I
                                       Sulfur
1
CO2 Vent
A
T """ 9
t_T~
1
1
I,
^f
R

_-J

D
C ^ RED
(2)
T
JNH

A -fr R U
: I
1 	 : 	 1
i

                                     Waste  Water
     A « adsorption; D - distillation;  R =  regeneration; C - Claus; R = reduction.
Stream
Case 1
(l) Feed
(2) Claus ga.s
Case 2
(T) Feed
(?) Claus gas
Case 3

(l) Feed
^ Claus gas
CO2/H2S
Ratio 	 	

100
13.2

200
26.3



0.53
,H2S (vol %)

, 1.0
7.1

0.5
3.7

20.0

65.5
aBased on selectivity ratio of 7.6.
bAs vol % of total C02 and H2S.
                                       93-

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              of 13.5 were obtained as shown in Table   33    the acid-gas stream
              produced would  range between 11.9 and 6.3% H2S for a feed gas with
              CO2/H2S ratios  in the range of 100:1 to  200:1.              i

                      9-1/3"
                        I
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LAST LINE
OF TEXT
  y J/b

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           Table
..33.-  Selective Absorption by Selexol Process
                   •Treated Gas
     Compressor
                               t
                                                    Sulfur
1
C02
Vent
R
-••

©
i
C
t
k


RED

"" *
*
', 4 	
— H
' R
d
A -
              , F - flash, R - «,—»tl», C - Cl». «ED « ruction.
                                     200
                                     14.8

                                     4
                                     0.30
  Sased on selectivity ratio of 13.5.
                                                       0.5
                                                       6.3

                                                      20.0
                                                      77.1
  bAs vol % of total C02 and
                                         95

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                                             or p/••<;?
                                                                                       10!' OF
                                                                                      .;;.-' A cr
          C.

           1.
  REFERENCES*                     j                            :
                                  |
  A.  L. Kohl and F. C, Riesenfeld,  Gas Purification,  3d ed.,  pp 421 and
  422,  Gulf Publishing Co.,  Houston,  1979.

  S.  Vasan, "Holmes-Stretford Process Offers Economic H2S Removal," The
  Oil and Gas Journal 76(1). 78—80 (Jan. 2,-1978).                  	r~
          4.

          S.
BEGIN
LAST LINE
OF TEXT r-
          9..
         10.

         11.

         12.

         13.
         14.
  Letter dated Apr.  1,  1980,  from W.  Dyer,  EIC Corporation,  to R.  LovelJ  '
  IT Enviroscience.
           i
  A. L.  Kohl  and F.  C.  Riesenfeld, op.  cit.,  p 38.
           i                       ..     	                     •
  R. L.  Pearce, "Hydrogen Sulfide Removal with Miethyl Diethanolamine,"
  pp 139—144,  in Proceedings of the  57th Annual Convention  of the Gas
  Processors  Association.  March 20—22.  1978,  New Orleans.     i           i

  J. Naber, J.-Wesselingh,  and .W.  Groenendaal,  "New Shell Process  Treats
  Claus  Off-Gas," Chemical Engineering  Progress 69(12),  29—34 (December

           ;  ~"~;"              1       ;~~ ~~~"~         : 1
  C. Ouwerkerk, "Design for Selective H2S Absorption," Hydrocarbon Proc-
  essing 57(4), 89—94  (April 1978).                     	;	   |
           '                       i                            '•
  Telephone conversation Jan.  28,  1980,  between C.  A. Peterson, IT Envi-
  roscience,  and R.  L.  Pearce, Dow Chemical USA.               l

           I.                      !                            i  '
  R.  W.  Parrish and  H.  B. Neilson, Synthesis Gas  Purification  Including
  Removal of  Trace Contaminants by the Benfield Process, presented at  the
  167th  National Meeting of the American Chemical Society, Division of
  Industrial  and Engineering  Chemistry,  Los Angeles, California, March 31 ';
  to April 5, 1974.

 A.  L.  Kohl  and F.  C.  Riesenfeld, op. cit., p  148.

  Ibid., p 134.

  Ibid.. p 151.
           I
 H. Hiraoka, Mitsubishi Chemical  industries, Ltd., and E. Tan
-------
                            VIII.   EVALUATION OF CANDIDATE PROCESSES
        I A.
BEG:--:
LAST LINE,
OF TEXT P-
        I
              As  determined from the data given in Sect. VII the processes that
              produce  the  highest H2S selectivity or appear to be most applicable to
              _lreatrile™ of_ 9ase.s_.frorn .dHect-fired oil-shale ..r.e.to.rts. are _the follow::.
              ing:       ;                      :                            '
 Direct-Conversion Processes
           Stretford              |
           EIC                    [
 Indirect-Conversion Processes
           Alkanolamine processes	MDEA
           Alkanline salt processes	Benfield
           Aqueous ammonia processes	Diamox
           Physical solvent processes	Selexol
           i
 BASIS OF EVALUATION
                                  I                           :
 To furthur evaluate these processes their capabilities were jcompared,
 with a hypothetical feed gas composition used as the basis for compari-
 son.  The  gas composition chosen (Table   34)   is similar to the gas
 produced by the Paraho direct-fired retort.   Trace organic sulfur com-
 pounds, not included in Paraho's ^data,  were  added so that their effects
 could be evaluated.   The quantity of trace sulfur compounds jshown was
 extrapolated from data compiled from sources reporting on trace com-
 pounds .1   "i
The indirect sulfur  removal processes  are only marginally capable of    '
producing an acceptable Claus  gas when the C02/H2S ratio of the feed    ':
gas exceeds about 100:1 (see Tables   29   through  33  ).  The hypothe-
tical gas, with a CO2/H2S ratio of 73:1,  was  chosen so that it would be
          I                       }                            j            ;
within the capabilities of the more marginal  processes.  To treat this
gas, using an indirect removal process, an H2S selectivity ratio of at  :
          '.                       '                                        '
least 6 would be required to produce a minimally acceptable acid gas
for the Claus unit.
             f; 3/8"
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     Table   "34.
                    Hypothetical Direct-Fired Retort Gas
 Physical Properties
                               Product Gas
                               Composition
                                (wet basis)
 Amount
(wet vojl  %)
Retort off-gas temperature:
  66°C
Retort off-gas pressure:
  20 psia
            224 sm3/tonne


Gas density:  1.2 kg/in3
Gas rate:
 .•of shale
Molecular weight: 28.43
II
2
°2
N^ -3- Ar
2
CO
co2
CH4
CJH,
2 4
C-H,,
26
CH,
3 6
C,H_
3 8
C S (MW = 57.0)
C^ (MW = 71.5)
Cf + (MW = 96.2)
6
H S
2
NH,
3
H2°

3.539

0.743
51.342

1.600
17.572
1.858
0.743

0.768

0.364

0.380

0.323
0.129
0.622

0.242
i
0.566
,
19.210
lOO.OIDO3
 Includes the following trace compounds:  COS, 36 ppm; CS_!,
 7 ppm; RSH, 10 ppm; and SO_, nil.                         |-
                              98

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Uf l£ Or
"J • p\ l"
i- = .:•'  ' '-

BEGIN
LAST LINE
OF TEXT £-?
        B.
             Projected plans for full-scale commercial oil-shale plants based on  —-•
             direct-fired retort technology range from Geokinetics1 facility pro-
             ducing 2.83 million  m3 of gas per day from 16 retorts processing about
             5454 tonnes of shale per day2 to Occidental's MIS plant producing
             48   million m3  of gas per day from a series_qf_4p_retorts_prqcessing
             about 149,078 tonnes of shale per day.3                        :           ;
  The model plant selected for evaluation of a sulfur removal process has
  a  capacity  of 45,450 tonnes  of shale per day and produces 10.2- million m3
  of gas  a day based on the composition of the hypothetical gas.  A de-
  sulfurization plant  in this size range will require multiple . trains to
  process the volume of gas produced, as would be the case for most
  projected commercial oil-shale facilities.  The individual components
  required for the model-plant sulfur removal train should therefore be
  in the  size range of that required for a full-scale commercial oil-
  shale facility  and should be representative of such a facility.
           9-1/8"
            i
  GAS  PRETREATMENT
                                    1                            !
  Host sulfur removal  processes will require some form of pretreatment of
  the  gas before  it.enters the sulfur removal equipment.  For most proc-
  esses the gas must be cooled and ammonia, condensible hydrocarbons, and
  excess  water be removed.  Other processes may require compression of
  the  gas.  ^articulate matter is largely removed in the oil separation
             !                       ; '                           '
  and gas cooling steps.  Additional particulate removal is not required
             I
  before  the gas  enters desulfurization equipment.             ;
         1.
   Gas Cooling and Ammonia Removal
   The temperature of raw gases produced by direct-fired oil-shale retorts !
   range from 5/7° to 77°C.   For most sulfur removal processes the gas
             I                       !
   must be cooled before it enters the absorber.  Since the gases from
   direct-fired retorts are saturated with water, large amounts;  of water
   will be condensed out as the gas is cooled.  Calculations  indicate that
   sufficient water can be condensed to simultaneously absorb and remove
   the ammonia contained in the gas if the gas  is cooled to about  32°C.
                                    •                           I          —• -|
        I
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             The gas cooling unit for the model plant is shown in Fig. VIII-1.  The
             raw fuel gas (stream 1), which is  at 60PC,  is directly contacted with
             the cooling water in a packed tower to bring the temperature down to -  .
             32°C.  AS the gas cools, a large portion of the water vapor, 849 kg/  ^
             min, and a small amount of hydrocarbons are condensed into the__circu-—..
             lating cooling water.  Essentially all the ammonia, a stoichiometric
             amount of CO2, and a small amount of H2S are absorbed into the cooling
             water.  The cooled gas (stream 3) is sent to the desulfurization system
                                                                          1          {
             absorber.                        j                            I          '
BEGIN
LAST LIKE
OF TEXT Z.-"
         2.
A portion of the cooling water solution equilivent to the quantity of
gases and vapors absorbed is purged  (stream 2) from the system.  The
remaining cooling water solution, saturated with^COg,_is_^assed_ through
a heat exchanger to remove the heat  absorbed and then recirculated.     .
The operating conditions and the composition of the recirculating cool-
ing water are controlled so that minimum H2S is absorbed into  the cool-
ing water. :

The purge "stream will be treated  (not  shown) by being passed, through  an
oil separator, where condensed hydrocarbons are  recovered,  and then
through  a sour-water stripper and ammonia  recovery unit.   The  H2S re-
covered  in the sour-water stripper  is  returned to  the process  gas
stream.  The ammonia is stripped  and recovered as  a by-product. The
remaining water, which contains trace  amounts  of absorbed organics,
H2S,  and ammonia,  is sent to a conventional wastewater  treatment
          !
system.   >
          I
Condensible Hydrocarbons
The heavier hydrocarbons with boiling points  above 90°F will condense
 and be largely removed in  the  gas cooling unit.  However, components in
 the gas include  unsaturated hydrocarbons such as acetylene, >thylene,
propylene, butadiene,  and butylene.  These components will not condense
 as the gas  is cooled.   They can,  however,  polymerize and form tarry
 substances  that can foul the acid-gas absorber,  discolor the sulfur, or_
                                           ej^er^unjj^:y[jgQ^
  clog the cataly£t_beds of a Glaus su!
1	i            "     	I................
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 TRATiONS
                                          PAGE MJV.CER
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                             90° F
                GAS
                COOLER
                                     CW.
                                           COOLED GAS TO
                                           DESULFURIZATION
                                           SYSTEM
                                      "SOUR" WATER
                                      TO AMMONIA
                                      RECOVERY
Figure 10.  Gas  Cooler/Anunonia Absorption System
                               101

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BEGIN
LAST LINE
OF TEXT :•
        I
        I
	   tion takes place in the acid-gas absorber.  There is no  economical way
'                                                                   i
i      of removing these compounds before the gas enters the  acid-gas  ab-
|      sorber, and their effects on the desulfurization train can be deter-
1      mined only by testing of the process.                        ,

| 3.   Gas Compression                  j
j      Both the Benfield and the Selexol processes require elevated;pressure
      to operate and thus would require gas compression.  For  the model plant
      producing 10.2 million sm3d of gas (Table   34    ) a compressor rated at
!      84,500 hp would be required to boast this pressure to  150 psig.  A gas-
      turbine-driven compressor system of this capacity with intercoolers and
I      condensate separation is estimated to cost $6  to $8 million and would
      consume about $34,500 of fuel per day, or about 32% of the treated gas
      produced by the facility.        ]                            I
      If the treated gas were combusted in a gas turbine used for power
      generation, a portion of the available energy in  the compressed gas
      would be recovered as the gas expanded through the turbine.  iThus  if
      the gas is compressed, it would be advantageous to remove as|little  C02
      as possible in the desulfurization process so that more gas will be
      sivailable to expand through the turbine.  However, after compression
      the gas would have to be cooled to the operating  temperature i of the
      sulfur removal process, and so a large portion of the available energy
                                       ;                            '
      in the form of heat would be removed before the compressed gas reached
      the power generation turbine.  From an energy standpoint it would  be
      more efficient to compress the gas as it enters the power generation
      turbine rather than before sulfur removal.                   j
      Since the Benfield process can operate at up to  121°C, less heat would
      have to be removed from the compressed gas than with the Selexol or
      cither processes that operate below  32°C.  Approximately 4673.6x109
                i                       :                            '
      joules of heat per day would have to be extracted to cool the compressed
                t                       ;
      gas to  "12P.C, at a cost of about $1750/day for cooling water!  To  cool
                |                       i
      the compressed gas to 32°C approximately 10,llSxl69 joules/day must be
                i                       !                   '                  —
      extracted at a cost of $3850/day.	_^            ;   	
    I
      3/8"
_ 1
   EPA-287 (Cin.)
                              	 Sx;.;-:.: 102 : :-:'A
                                 PAGE KUV.liER
3CTIO.V. OF
".'<-'• GE ARE
7LTCICE
Ci?.'tNSiO\
FOR TABLE;'.
•A;-*D ILLUS-
TRATIONS

-------
             Compressing the gas to 150 psig would reduce its volume by a\factor of
             6 to 10, depending on the exit temperature.  Thus the number or size of
             absorbers required to handle the gas would be reduced porportionately
             for those processes in which the absorber size is gas limiting          i
             (Selexol, Benfield, and to some extent the alkanolamine processes)-_.For
             those processes in which the absorber size is liquid limiting (Stret-   j
             ford, Diamox, and to some extent MDEA) the size of the absorbers may    :
                                                                   '      !            i
             not be significantly different if the gas were compressed.  |            !
                       I                       ;                                       j
             Due to the high capital and operating costs of gas compression it is    :
             not economical to compress the gas for the purpose of sulfuri removal
             alone.  Some full-scale commercial oil-shale plants employing indirect-
             heated retorts may compress the gas before sulfur^ removal_for _the_pur- .;
             pose of recovering LPG and other condensible hydrocarbons or for other
             process reasons.  In that case the application of the Benfield or
             Selexol process may be attractive.                          i
        C.   DIRECT-RECOVERY PROCESSES        j
                       i                       I                           i
        1.   The Stretford Process  (See Appendix A)                      j
            . The Stretford process  was developed in  England jointly by the  North
             Western Gas  Board and  the Clayton Aniline  Company,  Ltd.4   The  process
                       i                       '•                           '•
             has been proven commercially over a period of many  years  in ;more than
             80 plants built around the world.5  Several modifications arid  improve-
             ments  to the basic process have  been  made  by various companies that now
                       '.                       '•                           I
             license their proprietary versions of the  Stretford process.   The
             principal licensors in this  country are Peabody Process Systems of
             Stamford, Connecticut,, the Pritchard  Corporation of Kansas City,
             Missouri, and  the Ralph M. Parsons Company of Pasadena, California.
              The chemistry of the Stretford process is relatively complex.  The
              idealized reactions illustrate the absorption, oxidation/reduction
              cycle as follows:6
LAST LINE
OF TEXT r
BOTTCV. Or
CUTSlDE
Di.VEN'SlG'
FOR TABLE.
-AND iLLli
TF-.ATiONS
                                         PAGE fvUY.L.ER
           EHA-ib? (Gin.)
           {4-76)

-------
—    Reaction 1
           Na2CO3 + H2S
NaHS + NaHC03
      Reaction 2
           4NaV03 + 2NaHS + H2O -
                i
      Reaction 3
           Na2V4O9 + 2NaOH + H2O
                i
      Reaction 4
      — — 2ADA (reduced) + O2 —
        Na2V4O9 + 2S + 4NaOH
       2 ADA
4NaVO3 + 2ADA (reduced)
       2ADA + H2O
      A flow diagram of the Stretford process for fuel gas desulftirization :Ls
      shown in Fig.   11.    The sour fuel gas (stream 1) enters the gas
      cooler, where it is cooled and a large portion of the water land most of
      the ammonia are removed (stream 2) and sent to foul water treatment.    ;
      The cooled gas (stream 3) enters the Stretford absorber at about  32°C.
                                                                  .         .   i
      The feed gas (stream 3) is countercurrently washed with an aqueous      ;
      solution containing sodium carbonate, sodium metavanadate, and anthro-
      quinone disulfonic acid (ADA).  The H2S rapidly dissolves and ionizes
      in the alkaline solution, forming a small amount of sodium hydrosulfide
                                                                              :
      (reaction 1).  Hydrosulfide loadings in the solution range from 500 to
      1000 ppm;  thus relative large amounts of solution must be circulated.
      The sodium metavanadate in the solution readily reacts with the hydro-
      sulfide to produce elemental sulfur (reaction 2).           i   •
      Sodium carbonate in the solution provides a pH buffer to prevent rapid  j
      pH changes as the acid gases are absorbed.  The alkalinity of the       i
      Stretford solution causes some of the C02 to be absorbed albng with  the
                                       i
      H2S.  The treated gas (stream 4) with essentially all the H2S removed
      exits from the  top of the absorber.  The aqueous solution enters the   ;
      delay tank, with sufficient residence timeprovidedto assure that any
   r."-V2'// (Cm.)

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TYPI;
                                        /*"* I ' * J"1"- '-" *- --* ^
                                        vz- \_;. I-' i- o i * v

-------
    remaining hydrosulfide is reacted so as to prevent hydrosulfide from	'
    entering the oxidizer and becoming oxidized to stable sodium thiosul-
    fate, an undesirable by-product.  Thiosulfate can be formed!by oxygen
    dissolved in the Stretford solution, oxygen in the feed gas;  or hydro-
    sulfide carryover to the oxidizer..  An excess..of vanadate.is maintained
    to avoid overloading the solution with hydrosulfide.  Formation of
    thiosulfate can be controlled somewhat by controlling the pH and the
                                                               i            i
    temperature of the solution.  Thiosulfate can be allowed to concentrate
    in the solution to about 20% by weight.  A small portion of;the solu-
    tion (stream 14) is then continually purged and replaced to jprevent
    further accumulation and crystallization of salts.                     ;
                                                               !            :
                                                               i      '      !
                                                               s
    The reduced solution (stream 6) is regenerated in the oxidizer tower_ by
    being sparged with an excess of air.  The reduced vanadium is reoxi-
    dized to its original state through oxygen transfer via the;ADA (reac-
    tion 3).  The reduced ADA is reoxidized by contact with air'(reac-      ;
    tion 4).  Reoxidation of the ADA can be appreciably accelerated by the
                                                               i
    presence of small amounts of iron salts kept in solution by a chelating
    agent, ethylenediamine tetracetic acid (EDTA).7            !            i

    The nitrogen and the excess oxygen from the air bubble upward through
    the solution, floating sulfur particles to the  top as a froth and
    stripping the dissolved gases.  The froth, which contains about 10%
    solids, overflows the oxidizer to a slurry tank.  A damp cake contain-
    ing 50 to 60% solids is produced by filtration  or centrifugation of the
    slurry (stream 10).  The sulfur cake can be further processed by wash-
    ing to remove the Stretford chemicals and by drying and melting to
    produce liquid or solid sulfur (stream 17).                \
    The regenerated solution (stream 5)  is relatively free  of sulfur and is
    pumped back to the absorber.   In route the solution must normally be
    cooled to maintain the desired operating temperature, which'is  usually
    accomplished in an evaporative cooling tower.   To maintain water
    balance in the system due to  the addition of sulfur and/or filter wash
   ..water and water produced by the reaction, water is evaporated with, the .
cri'A 2:17 iC.-.r. 1

-------
 treated gas or in the  cooling tower.  A solution heater  is  sometimes
 required for winter operation or to assure  sufficient  evaporation.

          i                     •!                                 .
 Carbon dioxide is partly absorbed by  the alkaline  solution, resulting
 in the formation of sodium bicarbonate  and  consequent  lowering of pH.
 The solution eventually reaches  equilibrium with  respect to jthe concen-
 tration of  C02 in the  gas stream, after which only relatively small
                                                            i
 amounts of  CO2 are absorbed.  Since  the vanadate-ADA system functions
 at a lower  pH, decarbonation of  the  solution is not required.  When the
 gas contains high concentrations of  CO2, the absorption efficiency  of
 the solution may be lowered to the extent that an appreciable increase
 in absorber height will probably be  required.  Peabody has developed a
 proprietary venturi-absorber that is insensitive  to the H2S/CO2 ratio
. T . ..  .      • •                    	  ....     	       ,
 and is capable of handling fuel gas  containing 85% C02 with!minimum
 absorption of CO2.8
         ., Ac,"
 The principal side reactions that are detrimental to the process are
 the formation of thiosulfates and thiocyanates.  If hydrosulfate is     •
 contacted with oxygen before it  is converted to sulfur, thiosulfate     :
 will form,  the amount depending  on the pH of the solution and on the    .
 operating temperature.  The rate of thiosulfate formation under favor-  :
 able conditions can be held to less than 1 wt % of the sulfur in the    '
 feed gas by controlling the pH and temperature of  the solution and by   ,
 assuring that sufficient delay time has occurred for the conversion of
 H2S to  sulfur before  the solution reaches the oxidizer tower.  However,
 gases from direct-fired retorts  contain oxygen and a large amount of    :
 COo.  Calculations show that  for those gases about 3 to 4% pf sulfur in
           -                       i                          i             '
 the gas will  go  to thiosulfate  as the  result of oxygen in the feed gas
 and the buffering action of the  CO2.   Fortunately, oil-shale gases con-
  tain  only  trace  amounts of hydrogen  cyanide  (HCN).  Hydrogen cyanide
 will  react with  elemental  sulfur to  form stable thiocyanide, which also
  accumulates  in  the solution.
                                                                          BOTTO"! C
                                                                          ;"AGE AF:
  For small'plants  producing less  than about  9 tonnes of sulfur per  day,  j ,;" l""'..-^-
 _the_wet sulfur cake is. often disposed of by approved methods in a land-
                                                                         i ,
£'.?'.
{•!-
    (Cin.)
                             PAGE iM'Mi^H

-------
   jfill.  Since the wet cake contains sufficient thiosulfate, additional  ~
   purge of the solution is not required to control thiosulfate buildup.
   For plants producing more than 9 tonnes per day it may be more economi-
   cal to recover the sulfur, in which case a small stream of solution
   must be continually purged.   	•	;.	!	
   As thiosulfate is purged from the system it carries with it !a propor-
   tionate amount of Stretford chemicals, which must be replaced
   (stream 18).  It is important therefore to permit thiosulfatje to con-
   centrate in the solution to as high a level as the process will allow
   (20  to 22%) to minimize the costs of replacement chemicals and waste
                                    1                        .   I
   disposal.
   The purge  stream containing  toxic vanadium salts with an average COD
   (chemical  oxygen demand) of  20,000 mg/liter can be difficult  to treat
   and dispose  of.  Treatment methods used  include evaporation lor spray
              ,'.-,' •                    i
   drying, biological  degradation, oxidative combustion, and  reductive
   incineration.  Peabody Holms has successfully  developed a  zero-dis-
   charge  reductive incineration process  that cracks the bleed liquor into
   a  gas stream containing H2S  and CO2, along with a liquid stream con-
   taining reduced vanadium salts that can  be returned  to the system.8
   The problem  of disposing of  wastewater containing vanadium is elimi-
   nated and  no makeup of vanadium or sodium salts is required^  However,
   makeup  water to the system must be demineralized and the feed gas to
   the Stretford  absorber must  be free of soluble minerals to prevent in-
   organic solids from building up in the system.
    The Stretford process  is insensitive  to pressure  and can operate in the
    range of atmospheric to maximum pipeline pressure.   Operating tempera-
    tures range from ambient to 49°C .  Any type of gas-liquid contacting
    device may be used as  an absorber.  Problems of plugging have been en-
    countered in packed towers, especially with gases containing high con-
    centrations of H2S (above 1%).9 .Therefore large  rings or saddles are
             ;                       •                           l
    recommended when packed towers are  used.  Venturi scrubbers have been
  ft 3/tT
£T'i,-?o7 (Cin.)
(4-7G)
                               PAG;:

-------

!
BEGIN
LAST LINE
OF TEXT Vs-.
  2.
      successfully used for gases containing larger amounts of H2S, up to
      15%. 10    |
                i
      Stretford plants are remarkably free of corrosion tendencies ; and can be
      constructed entirely of .carbon steel, witK inert linings, e.g., cold- ._
      cured epoxy resins, used for oxidizers and sulfur froth tanks.  Stain-
      less steel linings are recommended for solution and sulfur  slurry
      pumps . * *  -
                                  '                          j1            •
 The Stretford process is extremely flexible in operation and can        ;
 tolerate wide variations in both gas feed rate and H2S concentration in
 the feed gas.  Startup and shutdown are relatively simple and can be    •
 accomplished in short periods_of time.__Good process control is_ main-  .'
 tained by simple analytical testing with little technical supervision.  ;
           t                       *                           ;            I
 Since all process streams are handled as liquids,, the process is easily
 automated and requires little operator attention.5
         9-1/8"      '                                          |
           i               •                                   :
 Hydrogen sulfide removal to less than 10 ppmv can be obtained with
 normal operation of a Stretford plant.  Assuming that the gas contains
 COS in the range of 10 to 50 ppmv the overall sulfur removable  achiev-
 able by the Stretford process would be in the range of 98.0 ;to  99.3%.

           I
 The EIC Process
 The EIC process was developed by EIC Corporation of Newton, 'Massachu-
 setts,  for removal of H2S from geothermal steam.  The process has been
           t                       |                           i
 field tested  in a pilot plant processing 45,454 kg  of steam per hour
           !                       :                           i
 at The  Geysers in California.12  Although the process has not yet been
 pilot tested  on desulfurization  of  fuel  gases,  EIC  is promoting the
 process for that purpose.
           I
 Geothermal steam contains noncondensable gases  such as  carbon dioxide,
 hydrogen sulfide, ammonia,  methane,  nitrogen, hydrogen,  traces  of
           t                       »                           ••             - - —
 radon,  argon, and mercury vapor, as well as rock dust,  boron compounds,  •••:.;; AF
 and other particulates.12   In The Geysers test  desulfurization to about   '...-. '„-"-
           •i.                      I                           '          """ ' -'•••••—- -
	ll,ppm H2S  in.the exhaust  steam was achieved.
                                                      _
                                                     13
                                                                                i L :
     A
                                  Sft:...:. 109.......v
                                  PAGE NUV.BER
                                                                                PlATiCr-IS
   F.='A-237 (Gin.)

-------


HaS Removal:
^2 Removal:
                           H2S
                                  H
      CuS + 20Z
          \
             cuso4
^JJesult
     «2S + 2NHS + 20

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                                             I

                                             •O
                                             •rH

                                            .a
                                            ! O
                                            '•H
                                              U
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                                               tn
^- X -• *\ » <•  j*"' /"* *
  t f i-.v'o t_-

-------
                                     Oh '- M •'.-•
-.1
 j  ___  _ 'with
       primarily ammonium sulfate, can be recovered by removing the water in a
       vacuum crystallizer.13           '                 •
Extensive use of titanium is required in the construction of the system
because of the corrosiveness of the sulfur'ic acid—copper,sulfate solu-
tion.14  The size of the components, however, is much smaller than that
of components for competing processes as the result of irreversible
reactions occurring in the absorber and of the reactiveness land concen-
                                                            .
tration of the solution.  The smaller size of the equipment joffsets a
large part of the cost involved in the use of special materials of con-
struction.  EIC believes that the capital and operating costs of the
system, including ammonium sulfate recovery equipment, are competitive
with those of the Stretford process.12                      ;       	_.
       The process appears to be well suited to desulfurization of oil-shale
       gas since it removes both H2S and COS, as well as ammonia, and would
       not require that the feed gas be cooled.  However, there are many un-
       answered questions, and more development work needs to be done before
       the process is applied to oil-shale gas.  A potential major ;problem is
       that oil-shale gas contains various unsaturated hydrocarbons, which
       could react with the strong sulfuric acid—copper sulfate solution and
                 1                       ;                           :
       form undesirable by-products.  Of particular concern is the:large
       amount of acetylene in the gas.  :If the highly unstable compound
                 I                       •                           :
       cuprous acetylide were to form and accumulate in the system, it could
                 1                       1                           !
       become very hazardous.  Cuprous acetylide is explosive and can be
                 i                       i
       detonated by percussion or can explode when heated above 100°C.  If
                 !                       i                           !
       warmed in ;air or oxygen for several hours, it will explode when brought
       in contact with acetylene.15  The potential for formation of cuprous
                 s                       i    .. -                     i
       acetylide in the EIC copper sulfate solution has not, to our knowledge,
       been defined.
       Another potential problem  could be  entrainment  of the  solution in .the
                 i                       i                           ;            > BOTTOM
       treated. gas.   Carryover  could cause corrosion of the downstream piping '  v.j-A
                 i                       i                           i            ! .- .T-O r-.p
       and gas turbine blades.  The  process has  not  been sufficiently proved	  :,..Vr-~
.to.recommend its  use. at this  time.	The process  could become  a viable
          '                 	i	
          *                 Si?''  112'.";                      i
       3/8"
                                                                                T::AT,C\S
          (Cin.)
                                  PAGE NU.V.3ER

-------
   candidate  for  desulfurization  of  oil-shale gases  if through  testing and
   development  the  adverse  effects of corrosion  and  undesirable side
   reactions  are  proved not to  create a problem.
                                   i
             i                      1
   INDIRECT-RECOVERY PROCESSES      '.	
   Table  35    gives the approximate volume and H2S concentration of the
   acid-gas stream that the model plant would produce for each  of the
   indirect-recovery-process options. The selectivity data used for  this
   table are either the average selectivity data reported in the litera-
   ture16—18 for the process or, as in  the case for the MDEA19 and the
   Diamox20 processes, are  the actual selectivity calculated for the  proc-
   ess based on the gas composition assumed for the  model plant.  For the
   purpose of this comparison it was assumed that all H2S and a portion of
   the CO2 relative to the  average selectivity obtained by the process
   would be removed and end up in the acid-gas stream to the Claus unit.

                              '      i                           !       .     '
   Based on the requirements of a minimum acceptable volume of .about 8% of
   H2S in the acid-gas feed to the Claus unit and of the need for at least
   25% H2S for effective operation,  the table indicates that a[one-stage
   selective absorption process using DEA or MDEA would not produce a suf-
   ficient level of H2S in the acid-gas stream for operation of the Claus
   sulfur recovery process.  Two stages of  selective absorption using MDEA
   as the absorbent would  be marginal, as would  one  stage of selective  ab-
   sorption  using  either the Diamox,  the Benfield, or the Selexol process.
   Three stages  of selective absorption using MDEA,  however, would produce .
   an acid gas rich enough in H2S for economic  operation of the Claus      >
             i                  .     i                           •            i
   unit.     !
    It can be'noted that  the volume  of  acid gas produced decreases  as  the
    selectivity of the process  increases.   Thus when high  selectivity  is    ;
    achieved,  the volume  of gas that must be processed by  the  succeeding
    absorption stage or by the  Claus unit is considerably  reduced,  thereby  _
    reducing the equipment size and  its installation and operating  costs.
£!'A-2G7 (Cm.)
(4-76)
                               PAGiL NV-.'.BES

-------
          Table  35.    Comparison of Selective Absorption Jrocesses for Treating
                             Gas from a Direct-Fired Retort                 ......

Ac*jri— f?as Stream to Claus Unit
A V* e= n r'V* ^ n t
DBA
MDEA
MDEA
MDEA
Diamox
Benfield
Selexol
Number
of
Stages Selectivity
• . O^
1 2.4C
2 8.2°
3 27. 4C
1 4. 7*^
1 6e
1 9f
CO2
895,129
.745,812
219,466
65,316
379,531
299,782
198,921
H2S
(sm3d)
24,649
24 ,-649
24,649
24,649
24,649
24,649
24,649
. Total
919,778
770,467
244,172
89,994
404,181
323,016
280,170
Total
; 640
535
; 170
i 62
: 280
i 224
: -156
H2S (dry
vol %)
2.7
3.2
10.1
27.4
6.1
7.6
11.0
 C°Gas rate"=45 450  tonnes/day  X  224  sm3/tonne
   1,782,900 sm^d;  H2S = 0.247 vol % = 24,649
bSee ref 16.
CSee ref 19.
dSee ref 20.
eSee ref 171
fSee ref 18.
= 10,188,000 sm3d;C02 = 17^.572 vol % =
                                             114

-------
     The Benfield and Selexol processes,  while only marginally capable of
     producing an acid gas of acceptable  concentration,  require high pres-
                                                                 I
     sure to operate.  The high cost of gas compression caused these proc-
     esses to be categorically eliminated from further considerations (see
     discussion in Sect.  VIII-B3).  	:				:	
     The indirect-process candidates therefore were narrowed to a three-
     stage alkanolamine (MEDA) process and the Diamox process.  A third
     candidate that was evaluated is a one-stage selective system coupled
     with a Stretford unit for recovery of sulfur from the acid gas.  A
     discussion of these systems follows.
1.   Three-Stage Selective Absorption Using_MDEA as the_Absprbent (See  	.
     Appendix B).                     j                           ;         /
     Two principal commercial processes are available based on the use of
     amine solutions for selective absorption of H2S in the presence of C02:
     the Selectamine process developed by Dow Chemical USA at Freeport,
     Texas, and the Adip process developed by Shell International Petroleum
     Company, The Hague, The Netherlands.  The Adip process uses'the second-
     ary amine diisopropanolaraine (DIPA) or the tertiary amine methyldietha-
     nolamine (MDEA).  The Selectamine process uses MDEA as the absorbent.
               !                 :      I
     The basic flow steps for all alkanolamine acid-gas absorptipn systems
               '                       i
     are similar.  As shown in Fig.   'tl3,   the gas to be purified
     (stream 3) enters the bottom of  the absorber and passes upward counter-
     current to the aqueous MDEA solution.  The lean solution reacts with
     and chemically absorbs the H2S and a portion of the CO2 as  it contacts
     the gas in the absorber.  The purified gas (stream 4) exits1 at the  top
     of the absorber and the rich solution containing the absorbed acid  gas
     .(stream 6) is drawn off at the bottom.  To achieve the highest practi-
               i                       t                           i
     cal selectivity, absorption kinetics are carefully controlled through
     absorber design and operation  (see discussion  in Sect. VII-B2a).  The
     selectivities achieved and the approximate volumes of gas handled by
               j                       p
     each  stage are given in Table  35.                          :          	
SOTTO.V. Oi-
•MAGE ASE.
OUTSIDE
DSf.'.nJSIO::
FOR TABLED
AND ILLUs
1 RATIONS
  EPA-237 (Gin.)
  •,-•,-76)
                                 PAGE

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                YVr l:«:o y.!.'JC C-i  -...: i
             The  sulfur removal effectiveness usually decreases as measures are
             taken to increase the selectivity.  For the process describe^ the H2S
             content of the treated gas can be reduced to about 10 ppmv and the COS
             will be reduced by about 60%.  The total sulfur reduction of the
             treated gas,  assumed to contain. 10 to 50 ppmv COS, .would be .in the —
             range of 99.2 to 99.5%.          !
0- T-:XT i?-
              The rich solution (stream 6) is heated by heat exchange with the hot
              lean solution from the bottom (stream 5) of the stripping column and
              then enters the stripping column near the top.  The lean solution par-
              tially cooled in the heat exchanger is further cooled by exchange with
              water and then fed into the top of the absorber.
              	 __ ___ 	!' 	 e .j .••)*• 	 __ 	 	
              In the stripper the absorption reactions are reversed as the  tempera-
                        i                      . (
              ture of the solution is increased.  The desorbed acid gas exiting  at
              the top of the stripping column is cooled to condense out the water
                     '-"».- •;-••                     "                           '
              vapor as the acid gas (stream 11) continues on to the next  absorption
                                               I .                          !
              stage.  The condensed water is fed back at the top of the stripper
                                               i                           !
              above the point of the rich-solution entry.  This serves to.absorb the
              amine vapors carried out by the acid-gas stream.
              The reaction between MDEA and organic sulfur compounds  is  not readily
                        i                                                              \
              reversed.  A side stream (7) of lean solution  is  sent to a reclaimer,
              where a portion of the degraded solution  is recovered by high-tempera- .
                        i                       i                                       |
              ture distillation.  The bottoms  (stream 10) accumulated from the       i
                        !                       i                                       1
              reclaimer are sent to waste disposal.                                   i
              The acid gas produced by  the  first-stage system ( 535 sm^/m ; becomes
              the feed for the next absorption stage.   Compared to the gas entering
                                               i      •                     •
              the first-stage absorber  (see Table   -36  )  the quantity of gas that
                        1                       i
              must be treated by  the  second-stage  absorber has been reduced by 92%
                                               !                           !
              and the CO2/H2S ratio reduced to 30.8.
The  second-stage absorber operates nearly identically to the first-
.stage absorber	The treated gas'(stream.12), however,~is high-purity
3/8"      tf                 :•:<•*•••••••••••••••••+:                                  1
            Q 3/s"      M
                                                                                        BOTTOM O.r
                                                                                        If.' AGE ARE
                                                                                        OUTSIDE
"- TABU:
•••:.\D ILLUS
           £PA-237 (Cin.)
           (4-73)
                                          PAGE

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               -'-' — -*'• .
              Table    36.    Performance of Three-Stage Selective Absorption
                                     System Using MDEA                   i
Stage
1
2
3
Feed Gas
Volume
(sm^m)
7,075
' 535
170
Acid-Gas Stream 1
Volume Volume Reduction H?S
r "* \ *•
(snpnu (%) (%)
535
. 170
. 62.
92.4
97.6
99.1
3.2
10.1
27.4
C02
96.8
89.9
72.6
CQ2/H2S
1 b
Ratio
30.8
8.9
2.6
% Reduction
57.6
87.7
96.4
 \folume reduction related to volume of feed gas to first-stage .absorber..
 CO2/H2S ratio of feed gas to first-stage absorber is 72.6.
c
 CX)2/H2S ratio reduction related to feed gas entering first-stage absorber.
                                           '118

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              G'J'DE 3i I[!
—   CO2, which contains  about  10 ppmv H2S  and is  often used as  a  by-product
     when a local market  exists for  it.

               '                       '                             '   '       '
     The acid gas  (170 snHm )  (stream 17) produced by the  second-stage  sys-
     tem contains about 89.9% CQ^ and 10.1% H2 and has a CO2:H2S ;ratio.of	
     .about 8.9.
     The  third-stage  absorber also produces high-purity CO2 (stream 18).
     The  acid gas  (62 sm^m  ) (stream 23),  containing about 73% CO2 and 27%
     H2S  with a CO2:H2S  ratio of about 2.6, is rich enough in H2S content to
     be processed  by  a modified Claus system for sulfur recovery.
                1                      ;
                I                      !                           i
     In the  operation of. the Claus unit (describedjLn Sect_._IV-B) the_sulfur
     burning— by-pass process is used since it is the least costly option
                i                                                  •
     and  since the acid  gas produced by the three-stage selective absorption
     process is free  of  hydrocarbon contamination (see Fig. 14).  '
             9-1/3"
     The  SCOT tail-gas treatment was chosen because it can be integrated
     with the selective  absorption system to save total installation costs-
     Since both systems  use MDEA as the absorbent, the regeneration of the
     rich solution coming from the SCOT unit can be combined with regenera-
     tion of the absorbent from the primary absorber.
      The SCOT process consists essentially of two parts:  a reduction stage
      in which all sulfur compounds and elemental sulfur in the off-gas are
      reduced to H2S and an absorption stage in which, after water is removed
      by condensation, H2S is selectively removed by MDEA absorption/regener-
      ation and is recycled to the Claus unit.  The total sulfur recovery of
                                      i                            '
      the Claus 'unit can be increased to above 99.8% of the sulfur in the
      acid-gas feed.  The SCOT unit is flexible, having a wide operating
      range, and no secondary waste streams are produced.21
      The estimated overall sulfur reduction calculated for the total desul-
                I                      !                           :             ! '  7--1-:
      furization train is about 98.8 to 99.3%, depending on the quantity of    . ~, /. ~~
      organic sulfur in the gas.	j	:	!	i r C". T--2
    D 3/8"      »*
	 J	j	
  EPA-2S37 iCin.)

                                 PAGE r:i//.s=R
    r

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r.L.'.v.r:
I AST LI WE!
             One-Stage Selective Absorption Followed by Treatment of Acid Gas by
             Stretford Process  (see Appendix C)                                      •
             As  can be seen  in  Table  35     one stage of selective absorption using.
             MDEA would produce an acid-gas stream containing approximately 3.2%
             H2S._This gas.is.too lean  to be effectively processed with a Claus
             system.  However,  sulfur can be recovered from  gases containing 3.2%
             H2S by the Stretford process.  Thus a possible  option would be to use
             one stage of selective absorption  to remove the sulfur compounds from
             the gas  followed by a Stretford unit to recover the sulfur from the     ;
             acid gas.                        j
                       I                       1                           ^            '
             Such a system (see Fig. -,   15  ) would have  several advantages.  The
             acid gas (stream 11) produced by  the^ selective  absorption step would be
             relatively  clean,  that is,  free of hydrocarbons.  Thus a  much higher
             quality  sulfur would be produced  since many problems inherent with  the
             Stretford process relative  to impurities  in the feed gas  would be
                     .-..-••                                                           !
             alleviated.   The MDEA  absorber would remove most of the organic sulfur
             compounds,  COS, CS2 and mercaptans,  but  they  would pass through the
             Stretford absorber and end up in  the C02  stream (16) discharged to  the
             atmosphere.

             The volume  of acid gas (stream 11) fed to the Stretford unit would be
                                              i
              reduced to about  535  sm^m    or  about 7.6% of the original! volume  of
              the raw gas (stream 3).   Howeverj  since  stream 11 contains  essentially
              the same amount of H2S as stream 3, the  amount of Stretford solution
              circulated; therefore except for the absorber the size of the  Stretford
                       t                       ',
              equipment required would be the same as  that for the  Stretford direct-
              absorption case.  Thus there is no cost advantage in this system over a
                       •
              Stretford direct  system.
                       I
              The estimated overall sulfur reduction calculated for the total desul-
              furization train  is in the range of 98.0 to 99.3%, depending on the
              quantity of organic sulfur in the gas.
              3 V
                                             .121
           EPA-237 iCm.)

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: AST LIME:
OF TEXT ir«-
 The Diamox Process (See Appendix D)                         [,         	->
 The Diamox process is a commercially proven process developed jointly
 by Mitsubishi Chemical Industries (MCI) and Mitsubishi Kakoko Kaisha
 (MKK), both of Japan, for desul'furizing coke-oven gas.  Five facilities
_employing the process have been built, and their performance has been	
 excellent.  MCI reports20 that the Diamox plants have achieved coke-    j
 oven gas desulfurization to levels as low as 13.7 to 18.3 gratis of H2S per
 100 sm3 (about 95 to 126 ppmv).  The Ralph M. Parsons Company of        '
 Pasadena, California, is the licensee for the process in the United
 States.   •                       s                           :  •
           i                       '
           i-                       i                           .
 The Diamox process is particularly applicable for removal of H2S from
 •gases Containing ammonia since ammonia is used as the absorbent in the
 Diamox solution..- AMP oia ^.S'sent in the raw gas is absorbed to gener-
 ate the Diamox solution, and consequently no chemicals are required for
 the process.  Once the Diamox solution is saturated with ammonia, addi-
 tional ammonia will not be absorbed but instead will pass through with
 the treated gas.  Additional ammonia scrubbers must be added if ammonia
 has to be removed from the treated gas.
           i                      i                           i
 A large part of the proprietary design of the Diamox process is em-
 bodied in the design and operation of the absorber and stripping towers
 and the temperature and solution concentrations maintained throughout
 the system.22  The process was developed to selectively absorb H2S from
 coke-oven gas with greatly improved removal effectiveness.  Up to 98%
 H2S removal has been obtained in commercial applications of the process
 compared to removals of only 90% achieved by conventional processes
 using ammonical solutions.  Selectivity ratios of up to 9.4 have been
 obtained by the process based on data reported by Hiraoka, Tanaka, and  \
 Sudo.23  Organic sulfur compounds,  however,  are not appreciably
 removed.  ]
          I
 High-quality,  99.9% pure,  bright-yellow sulfur can be recovered from
 the acid gas "produced by the Diamox process  since the concentration of  ! '"'"'y?.'".
          1                      i                            i         —s L ..'.;^,',-;:(
                                                                                       BOTTOM
            /-
            w
          (4-76!

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   ammonia, hydrocarbons, and other contaminants in the acid gas  is ex-  —
   tremely low.                     |                           ;
   A simplified flow diagram of the process is shown in Fig.  16.      The
   Diamox process operates as follows.  The. incoming raw gas  (stream .1)  is
   cooled to about .52°C by direct contact with  circulating water  in a
                                                               i
   wash tower.  Water, with a small amount of absorbed ammonia; and a
   small quantity of hydrocarbons condensed from the gas are  purged from
   the system  (stream 2) and sent to  foul-water  treatment.  Cooling to
    52°C  permits the bulk of the ammonia  to pass through with the-cooled
   gas.  The cooled gas  (stream 3) then enters the H2S absorber, where  it
   countercurrently contacts the freshly  stripped, lean ammoniacal solu-
   tion.  Nearly all the H2S and a portion of_ the CO2 are absorbed before
   the treated gas (stream 4) exits from  the top of the absorber.   The
   rich solution (stream 5) enters the acid-gas  stripper, wher^ the ab-
   sorbent  solution is heated to expel the absorbed acid gases.  The
   stripped or lean absorbent (stream 6)  is cooled and then returned to
   the H2S  absorber; the stripped acid gas  (stream 9) is sent to the Claus
   unit for recovery of  sulfur.
   A small amount of solution (stream 7)  is  purged from the recirculating
   absorbent solution to control buildup  of  impurities and then is sent to
   foul-water treatment.
  The goal of obtaining a high degree of sulfur removal conflicts with   j
  that of simultaneously obtaining high H2S selectivity; one goal must be[
  compromised to obtain the other.  To obtain a high degree of desulfuri-
           1                       !                           'j
  zation the  partial pressure of H2S in the absorbent must be low and the :
  acid-gas concentration in the regenerated lean solution musjt be at the ;
  lowest possible level.  Thus large amounts of solution must be circu-  ;
  lated through the absorber and greater amounts of utilities, consumed in
  regenerating and recirculating the solution.
           1                       i                           :
                                                                            BOTTCM O
  The system proposed for the model oil-shale gas disulfurization plant	
                                  I                           :           " i
   3__based,on a. spray .tower, absorber.with six absorption stages, (see	_.-;
f           i                      ,                                       ^ _-
{: 3/3"
                                                                            •AND ILLuc-
                                                                            •RATIONS
tr>A-?i,7 (Cin.)
                               PAGE

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                                                             I
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                                                             01

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                                                             s
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                                                              10
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                TYFiKG Gv.!;l" S- ifHT
LAST LIME
•)r TEXT j.>~
              Appendix D).20  The high C02 content results in increased Cb2 absorp- -
              tion.  Calculations indicate that the H2S content of the treated gas
              will be about 63 ppmv and that-the acid gas stripped from the rich
              Diamox solution in the acid-gas stripper contains about 6 mole % H2S.20
             JThis equates to an H2S removal of..97.9% while achieving a selectivity ..
              ratio of 4.7.  With the gas assumed to contain COS in the range of 10
              to 50 ppmv the overall sulfur removal achievable would be 96.3 to
              97.6%.  The acid gas is fed to a Claus sulfur recovery unit!for conver-
              sion of the H2S to elemental sulfur (Fig.   16  ).  The Claus unit
                                               ,                           !
              tail-gas feeds to a Beavon sulfur removal process (BSPR) for final sul-
                        1                                  •                !
              fur recovery (Fig.   17  ).  The BSPR unit was chosen due to the large
                        >                       i
              amount of CO2 in the acid gas.   '                           ',
              The Beavon sulfur removal process for treatment of Claus plant tail
              gases consists of two main steps:  catalytic hydrogenation and hydroly-
              sis of all sulfur species to H2S and conversion of the H2S to elemental
                     ;*';•**••                     t                           !
              sulfur by the Stretford process.:                           ;
              The overall sulfur recovery in the Claus and BSRP units is 99.8% per-
              cent.20  The estimated overall sulfur reduction calculated for the
              total desulfurization train is about 96.1 to 97.4%, depending on the
              quantity of organic sulfur in the gas.
              The Diamox process, while suitable for coke-oven gas containing large
                        i                       •                           !
              amounts of ammonia, carbon dioxide, and hydrogen cynide, is;only
              marginally capable of processing oil-shale gas because the ratio of C02
                        ;                       t                           '
              to H2S in the gas is very high.  The process would not be capable of
                        :                       i                           '   .
              producing an acid gas of sufficient H2S content for effective operation
              of the Claus system for most direct-fired oil-shale retort gases with-
                                               i
              out considerable sacrifice of H2S removal effectiveness.    ]
    IMAGE A-

_!,_! FOrr-TAEi.'.'
                	1	
           EPAO37 (Cin.)
           14-76)'
                                         PAGE NUMBER

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    I
     3
  !   4.
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     6.

     7.

     8.


     9.

    10.




    11.

    12.


    13.


    14.
     15.
            REFERENCES*                   •   j

            R  A  Loucks, Occidental Vertical Modified in Situ Process for the
            Recovery  of Oil  from Shale.  Phase I, Occidental Oil Shale, Inc., Grand
            Junction,  CO, prepared  for EPA under Contract No. DE-FC20-78LC10036
            (November 1979).                 j                            ,        ....

            "Telephone conversation  Feb.~8Tl98o7""between S.~~W. Dylewski, !IT Enviro-
            science,  and M.  Lekas,  Geokinetics.

            T. Nevens 'et al.,  Predicted  Costs  of Environmental Controls for a Com-
            mercial Oil Shale  Industry,  Denver Research  Institute,  COO-5107-1  (July
            1979).     |                      j
                       i                      i
            A.  L. Kohl and F.  C.  Riesenfeld, Gas Purification, 3d ed., p^476, Gulf
            Publishing Co.,  Houston,  TX, 1979.

             Sulfur Recovery Qualifications  and Experience,  Technical Documentation,
             The Pritchard Corporation (November_1978)._

             A.  L. Kohl and F.  C. Riesenfeld, op_. cit., p 477.
                       I
             Ibid., p 479.

             S. VasanY "Holmes-Stretford Process Offers Economic H2S Removal," The
             Oil  and Gas Journal 76(1), 78—80 (Jan. 2, 1978).

             A. L. Kohl and F. C. Riesenfeld, op_. cit., p 484.

             S. Vasan, *The Holmes-Stretford Process for Desulfurization of Tail-
             Gases  from Acid-Gas Systems," presented at  the Ammonia-from-Coal
             Symposium, held at TVA National Fertilizer Development Center, Muscle
             Shoals,  AL, May 9, 1979.        ,;                           i

             A. L.  Kohl and  F. C. Riesenfeld,  p£. cit., p 485.           :

             R. Dagani, "Cleaning of  Geothermal  Steam Simplified,"  Chemical and
             Engineering News  75(12),  29—30 (Dec.  3,  1979).

             Letter from W.  Dyer, EIC Corporation,  dated April 1,  1980, to R. Lovell.
              IT Enviroscience.
                       i
              G. Allen,'pacific Gas  and Electric  Co.,  and F.  Brown,  EIC Cprporation,
              Highlights of the Test Results From the Operation of a 5 HW, Pilot
              Plant Demonstration of the  EIC Process at The  Geysers, a report pro-
              vided by the EIC Corporation,  Newton,  MA.                  i
                                              i                          I
              S. Miller^ Acetylene.  Its Properties.  Manufacture  and Uses,, Vol. 1,
              Academic Press, New York, 1965.
                                                                                 !  V-.GE f-~~-
                                                                                          TA2L-

      EPA-237 (Cin.)

-------
-16.   R.  L.  Pearce,  "Hydrogen Sulfide  Removal with Methyl Diethanolamine,"
      pp  139	144 in Proceedings  of the  57th Annual  Convention of the Gas
      Producers Association,  March.  20—22,  1978, New Orleans.    }

 17.   R.  W.  Parrish and H.  B. Neilson, Synthesis Gas  PurificationiIncluding
	    Removal of Trace Contaminants, presented  at the 167 National Meeting of
-	the American Chemical Society, Division of Industrial and Engineering
      Chemistry, Los Angeles, California, March 31 to April 5, 1974.
                i                      ,                           i
                '                      *                           i
 18.   A.  L.  Kohl and F.  C.  Riesenfeld, op. cit., p 784.
                i                      t    """"~~~                    i
 19.   Telephone conversation Jan.  28,  1980,  between C. A. Peterson, IT Envi-
      roscience, and R.  L.  Pearce, Dow Chemical USA.              !
                '                      :
 20.   R.  E.  Meissner, III,  Diamox  Desulfurization Process for Treating Oil
      Shale  Retort Gases, RMP File No. 180G-1714; unpublished report provided
      by  the Ralph M. Parsons Company, Pasadena, CA (Mar. 25, 198Q).
                I                      ;                           '
                I                         "                                 .
 21._ J.  Naber, J. Wesselingh,  and W.  Groenendaal, "New Shell Process Treats
      Claus  Off-Gas," Chemical Engineering Progress 69(12). 29—34 (Dec."
      1973).    i                                   __            ;
                !                      i
 22.   T.  Shiboya et al., Process for Preparing  Purified Coke Oven Gas, United
      States Patent 3,880,617,  Apr.  29, 1975.                     1

 23.   H.  Hiraoka,  Mitsubiski Chemical  Industries, Ltd., and E. Tanaka and H.
      Sudo,  Mitsubishi Kakoi Kaisha, Ltd., "DIAMOX Process for the Removal of
      H2S in Coke Oven Gas,"  Proceedings  of  the Symposium on Treatment of
      Coke-Oven Gas, May 1977.  McMaster University Press, Hamilton, Ontario,
      Canada.
     *When a reference number  is used at  the end of a paragraph or on a head-
      ing,  it usually refers to the entire paragraph or material under the
      heading.   When, however, an  additional reference is required for only a
      certain portion of the paragraph or captioned material, the 'earlier
      reference  number may not apply to that particular portion.  '

               I
   TT
    r"
  EPA-2S7 (Gin.)
  (4-7S)
                                PAGL

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BEGIN
LAST LIN
O:T TEXT
                    TIX   COST COMPARISON OF CANDIDATE PROCESSES       [
                     I                       !                                      :
           Estimated capital and operating costs and cost-effectiveness data for
           the candidate processes described in Sect. VIII are presented *nth»_
           section   The estimates were based on a hypothetical directed oxl-._.
          "shale plant processing 45,450 tonnes of shale per day .and producing
           10.2 million s^d of  gas having  the composition shown in Table ;34
           Material balance flow sheets were  developed  for each of the  selected
           candidate processes. The major equipment components were  defined  and
           sized and the capital and operating costs estimated.          :
                      I                      I           -                 ;          ;
            The estimlted capital and operating costs and net annualised tost  of
            the various options evaluated.are_given.in_Table_ 37.  _ Thejnaterxal.
          "balance  flow sheets and a summary of the equipment requirements and    ;
            cost estimate details for each process are given in Appendices A, B, C, ^
            and D.    !                                                              !
                    9-1/3"                                                .           |
            The  estimated costs are  based  on  a  new-plant installation and  represent
             the  total investment,  including all indirect costs such as  engineering
             ,nd contractors'  fees and overheads, required  for the purchase and
             installation of all equipment and material to provide ,  facility  as
             described:  These are battery-limit costs and do not include^provisions
             for bringing utilities, services', or roads to the site;  backup facili-
             ties;  land; required research  and development; or process piping inter-
             con»ectio,is that may be  required^within the process  that generates  the
             gas fed to  the desulfurization systems.
              capital cost estimates were developed by suction of installed capital
              costs for'.the individual components of each system.  These installed
              capital costs are based on n Enviroscience experience adjusted to the
              January 1980 basis.  « addition'to the sum of the itemized capital
              costs a contingency allowance of 20% is included in overall, capital
              cost estimates.
           Er'A-257 (Cin.

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                   Table   37.    Estimated Capital  and  Operating Costs  "for
                                 Fuel-Gas  Desulfurization Options21






Item
Capital cost9
Operating cost (per year)
Chemical makevip
Steam
Power
Fuel gas
. Cooling water
Waste treatment
Operating labor
Maintenance , capital
recovery and misc.
Total operating cost
Sulfur recovery credit
(per year)
Net annualized cost
Per year
Per ton of shale
Per barrel of oil



Stretford
Direct
Process with
Purge Stream
Disposal'3
$13,322,000

$1,088,000
70,000
303,000

526,000
No cost
600,000
3,864,000

$6,451,000
$1.083,000


$5,368,000
0.29
• O.50



Stretford
Direct
Process with
Purge Stream
Recovery0
$14,840,000

$ 911,000
107,000
345,000
328,000
578,000
Neg.
720,000
4,304,000

$7,293,000
$1,116,000


$6,177,000
0.34
. 0.57
Costs
1-Stage MDEA
Selective
Absorption
with
Stretford
Sulfur
Recovery"
$17,200,00

$ 1,190,000
3,812,000
234,000

1,261,000
No cost
630,000
4,988,000

$12,115,000
$1,130,000


$10,985,000
O.60
1.01

1
3-Stage MDEA.
Selective
Absorption
. with Claus
Sulfur
Recovery3
$15,551,000

$ 24,000
.7,183,000
158,000

1,545,000
Neg.
. 480,000
4,510,000

$13,900,000 •
$1,171,000
i


$12,729,000
0.70
1.17


.
Diamox
Process
with Claus
Sulfur,
Recovery""
$32,741,000

$ 84,000
11,530,000
1,618,000

1.950,000
No cost
480,000
9,495,000

$25,157,000
$1,150 ,000


$24,007,000
1.32
2.21
"l-or 360-million-scfd plant based on Paxaho gas (see Table VZII-1) .  bstretford purge stream disposal at no cost.
                                 and gases, water, and decomposed sodium salts  recycled.   Sulfur recovered with
 S^^euZOXu PUiQi; StiecJa iJiUJ.*iei.€»uc«j. OJ*M. y&^«&^ /  «»*»,^— ,	-^.	                 -
 Stretford system. ' eSulfur recovered with Claus system with SCOT tail-gas treatment.   Sulfur recovered with Claus

 system with BSHP tail-gas treatment.  Includes process royalty fee.
                                                      131

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       The actual cost of applying any of these options at any specific  loca-
       tion could vary considerably from that given here.  The purpose of
       these estimates was to determine the relative cost differences between
       the various options.  Since the estimates for each of the options eval-
       uated were calculated on the same basest .the relative costsjof applying
       the systems should be in the order shown.                   ''••
                                                                   \            '•
                 !                       I                           '            j
       Special cautions must be used if an attempt is made to extrapolate from
       the cost-effectiveness data given since these costs will be;largely
       dependent on the composition- and volume of gases to be treated, on the
       oil yields, and on the cost factors that are pertinent to installation
                               "                                    l       ,     .
       site.                            I                           ;            i
       For desulfurization of gases from direct-fired oil-shale retorts  the    :
       Stretford process is the most cost-effective system.  For the model     ',
       case shown the cost of sulfur removal would be about $0.50 per barrel
       of oil produced, which is less than half that projected for -the better  '
       of the indirect sulfur-removal processes.  The model case is based on   '
       Paraho gas, which has the lowest C02/H2S ratio (76:1) of any gas        |
       considered for the direct-fired retorts.  For direct-fired gases  having
       higher CO2/H2S ratios the gap between the cost of applying the Stret-   •
j       ford process and the indirect desulfurization processes would be  ex-
       pected to increase, making the other options even less competitive.
                                       •                                        f
       For gases with lower CO2/H2S ratios the indirect sulfur-removal proc-   :
       esses would become more competitive.  For gases from indirect-heated
       retorts,  such as Tosco with a C02/H2S ratio of 4.1:1, the indirect
       processes could very well become more cost effective than the Stretford
       process.  !
                I
       The operating costs given are based on the assumption that there  is no
                                       1                                        i
       cost for  wastewater treatment.  The sour water stream in each case      i
                                       !                            ;            i
       would be  stripped of H2S and processed for recovery of hydrocarbon and
       •ammonia by-products.  The cost of this treatment, which is partly off-  '.  *-;:.j£ A"
       set by the  valve of the by-products recovered, was assumed £o be  equal
I                                       ;                            ••          	, U:,\U.: .biU
	-r_in..each case, and therefore is not included	The. Stretford purge	I "'.'• 7*-2Lr
1     ."i  -s .-,..                        ....   '  	                                  •»/• f ' "> 11 ! I • •
i     •;  j.-c       *•*                 •:•:•:-.     •:•:•:•:•:•:                            •      i ;-.i>.^.-i._u.
     i           V                  '••y'-y.:-. .132 :::'.::::::                      •             iPAliO?,1'^
                                  PAGE KI-V3ER

-------
                                  cr,\'rrn
                                  O:-~ PAi.:i.
   streams, containing essentially dissolved salts, were assumed to be  •— :

   sicceptable for disposal  through moisturizing of the spent shale at no

   cost.  The cost of evaporating -the purge streams to recover dissolved

   salts would be about  $557,000/yr ($0.05/bbl) for the Stretford direct   ''•

   systems and_about^$37,000/yr ($0.003/bbl) .for...the BSRP..system used.for...;
                                    :                                        {
   treatment of  the  tail gases from the Diamox process Claus unit.
   The cost of a  Stretford system incorporating a purge-stream ;reductive-

   incineration system for recovery and recycle of salts is also given in

   Table IX-1.  This  option would result in a sulfur removal cost  of about
             i.                      i
   $0.57 per barrel of oil produced,  which is about $0.07 more per barrel

   than the case  based on disposal of the purge stream at no cost.
             i
             I
           9-1/8"
EEG'N
LAST LINE
OF TEXT
         _ i!'!l _  L	
                                                                              BOTTOM C:
                                                                              IMAGE AFi:
                                                                              OUTSIDE
                                                                              DiMENSIC
                                                                              I'OR TABL-:
                                                                             j-AND ILLU2
                                                                             ! TRAT!G;-J§
EPA-2S7 (Cin.)
(4-70)
                               PAGE NUMBER

-------
BEGIN
LAST LINE
OF TEXT
                       X.  RECOMMENDED AVAILABLE H2S CONTROL TECHNOLOG-Y   I         —.';
                        i        .              i    ;                       ;	,..!
              The Stretford direct fuel-gas desulfurization process was recommended as
                        i                      .                            ,
              the most  applicable technology for removal of sulfur from direct-fired
             _oil^_shale_ retort_gases.	The basis_for__this, selection, is as ;follows.. „	
         A.
ADAPTABILITY
Gases from direct-fired retorts have a low heating value (1-52 to 4.13x10"
        ->'                       '                         ' • ''
joules/snP) because of the large amount of nitrogen,  carbon dioxide and  other
          i                       •                           i            .
inert gases in the gas.  It is not economically  feasible to upgrade  the
quality of the gas so that it will meet pipe-line quality  standards  and
          !                       i  .                •         '            !
can therefore be sold as a substitute for natural gas.  Practical uses
          i                       '                           ',            I
of the gas are limited to combustion for generating processjheat _or_
electrical power, for which purpose only the ammonia and sulfur need to .
be removed.
          I
       0.1 •'-"
The large volumes of gas that must be processed  in a typical  oil-shale
plant will limit the application of desulfurization technology  to high-
capacity, continuous-liquid-phase processes.  Since C02 is absorbed  to
some extent by all liquid-phase processes, the high C02/H2Siratio of   :
          1                       :                                       I
the gas limits the selection  to those processes  that can selectively
          i                       i                                       i
absorb sulfur compounds in the presence of large amounts of•CO2•  Of
those direct processes that selectively remove H2S by  direct  conversion
of the H2S to elemental sulfur, the Stretford process  is the  most
effective.  Of those indirect processes that selectively remove H2S  by
          !                       i                           !
separating the H2S as a concentrated acid-gas stream,  the  Selectamine
          I                       i                           I
or the Adip processes using MDEA as the absorbent, the Benfield,  the
          i                       j                           <
Selexol,  and the Diamox processes were selected  as the most effective
in their  separate process classifications.  These processes\were  than
considered as candidates for  further study.
         B.
OPERATIONAL REQUIREMENTS
          I
Oil-shale .retort  gases  are  produced at near-atmospheric pressures; thus
those processes requiring the gas to be at a high pressure (Benfield
                                                                                       BOTTOM Oc
                                                                                       FOR
                                                                                     VAND ILLUS-
                                                                                      ! TRATIC.'vlS
           EPA-?37 (Cin.)
           (4-76J
                                          PAGE NUMBER

-------
EEC IN
LAST 'Uf.E
OF TEXT r
              and Selexol) were eliminated since compression of the gas for the pur-  -
              pose of desulfurization could not be economically justified.;            j
              The Claus process is used to recover sulfur from the acid gas produced
             Jby the indirect sulfur-removal processes... The ..large amount of C02 in  _
              'the gas makes the best of the indirect process only marginally capable
              of producing an acid gas rich enough in H2S for processing by the Claus
              process.  Thus to apply these processes, multiple stages of iselective
              •absorption would be required to handle the gas produced by many  of the
              direct-fired retorts.
              The Stretford direct process, on the other hand,  is only minimally
              affected by the quantity of C02 in the gas and  therefore is  adaptable
              to the full range of gases produced by direct-fired retorts.            .
              A Stretford plant incorporating a venturi absorber  can  operate with a
                                               i                           ;
              wide-volume turndown range.  The system  capacity is limited"by the
              maximum design-basis throughput capacity of the  sulfur.  The  quantity
              of sulfur in the gas can drop  to nearly  zero without affecting the
                                               i                           ;
              sulfur removal efficiency.
              The indirect selective sulfur-removal processes  have  only limited turn-;
                        i                       •                           ii
              down capability.  The selectivity  of the process (preferencial absorp- [
                        '.                       i                           :            j
              tion of H2S over CO2) is  largely achieved  through control of  the ab-   '•
              sorption kinetics.  Therefore large  changes  in absorber gas or liquid
              throughput can  adversely  affect  the  selectivity  achieved and  conse-    •
              quently the composition of the acid  gas produced.  The Claus  process   !
                                               i                           •            i
              has a limited range of operation and can be  upset by  large variations  i
                                               !                           \            I
              in the composition of the acid-gas feed.   The wide range and  constant  :
                                               :                           !            i
              variation of the CO2/H2O  ratio of  gases from in-situ  retorts  would be
              very difficult  to handle  with an indirect  selective absorption system.
                                                                                       BOTTOM Or
                                                                                       IMAGE ARE-'
 C,   SULFUR-REMOVAL EFFECTIVENESS
	   A very high degree of H2S removal  can be  achieved by all  the  candidate	^ '*'~''.^'~~.
              processes, discussed..._ Generally the higher the amount of .sulfur, that
              --..      '                 •--•.••  '-,..•,.-...                     i
            JL
                                                                              \<-AND ILLUS-
                                                                            _j Th AT IONS
           I4-7G)
                (Cin.:
                                          PAGE .NUf.'Si-R

-------

     imust be removed the more it will cost to install and operate the desul-
     furization train.  The cost of applying these systems then becomes the
     overriding factor rather than the ultimate sulfur-removal effective-
               \
     ness.     i               .      •
KEG1N
LAST LINE
r*- —
D.
              Except for the Diamox process all the candidate processes are capable
              of removing H2S down to about 10 ppmv.  However, organic sulfur com-
              pounds , principally COS, which exists in only trace amounts iin the gas,
              are not significantly removed or are only partly removed by the various
              process.  Table  38 gives the variation in process effectiveness with
              the amount of COS in the raw gas.  Current Colorado emission standards
              limit sulfur emissions to an equivalent of 6.3 Ib of SO2/bbl of crude
              oil produced.  The estimated S02 equivalent emissions_for_each of the
              candidate process are shown in Table  38.                   ;

              RELATIVE COSTS
              The relative costs of the candidate processes studied are given in
              Table 39. i
                        I
              For desulfurization of gases from direct-fired oil-shale retorts the
              Stretford process is the most cost-effective system.  The cost ratios
              shown, based on Paraho gas, would be expected to increase for other
              direct-fired-retort gases having higher CO2/H2S ratios.     ;
     The three-stage MDEA process produces the highest degree of37 (Cm.)
                                PAGE NUMBER

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-------
                        Stretford direct       j
                                               |
                        3-stage MDEA with Claus/SCOT
                        1-stage MDEA with Stretford
                        Diamox with Claus/BSRP
                                                    7570 Jl/day
                                                 37.85.A/day
                                                    7570 a/day
                                                   246 H/day
         F.
PEGS::
LAST UNE
These estimates do not include sour water, which would be processed for
hydrocarbon and ammonia recovery prior to disposal.  The quantity of
sour water in each case would be about the same (1.13 x 10°  to 1.51 x
106 it/day).

RELIABILITY
All the candidate processes were commercially developed and\are used in
                                 1                           ;            J
various applications around_ the world._ The  Stretford process Jhas been '.
widely applied, with more than 80 commercial plants  currently  in opera-
tion.     ;

As with any process application operating problems can develop, and if
the system is misapplied or poorly designed, the problems  can  be insur-
mountable.  The principal problems reported  by Stretford users are
plugging of packed absorbers by precipitated sulfur; loss  of scrubbing
performance, when processing gases with large percentages  of CO2, be-
cause CO2 is absorbed and the solution pH is consequently  lowered; and
                                 i                           i
poor-quality sulfur as the result of hydrocarbon and other contaminants
in the sulfur.
          i
The process licensors feel confident that with proper design and
through use of proprietary Stretford chemicals these problems  can be
managed.  ;
           EPA-2S7 (Gin.)
           J4-7SJ
                                         :*:.:.:.:.:•:•*•,:•:•: •:•:•:•:•
                                         &;&, .139' -_; xj
                                         PAGE KUV.bER
                                                                          BOTTCV 0!
                                                                          ivAGE AR:
                                                                          OUTSIDE
                                                                       __J -CP. TABLL
                                                                       *>AND !LLU5
                                                                          f-vriON?

-------
                       G'-'i . •-'. S''.- • i
                                    XI.  PILOT-PLANT DESIGN
LA of LIN
Or 1GXT
         A.   INTRODUCTION
              Gases produced from direct-fired oil-shale retorting processes are
        ~ ______ sufficiently different from gases previously encountered in commercial _.
                                                                                      t
              application of gas-desulfurization systems that the technology cannot
              be simply transferred.  Application of the Stretford proces;s or any     .
              other process to the treatment of these gases would extend the technol- ,
              ogy of the process into areas in which no analogous experience is
              available.  Many questions need to be answered before the process can
              be applied with confidence to a full-scale commercial shale-oil produc-
              tion facility.              .     I
                        i                       !                          ;
              _ _ _; __ I __ r,.-> ">'•' ______ J ___ _ _ __ ___ _ • ______ -j.
              The primary function of the pilot plant would be to test the technical
              feasibility of the Stretford process for treatment of gases from oil-
              shale retorting processes, to prove the engineering assumptions and
              calculated forecasts made for the process, and to generate scaleup
                                                                         i
              design data for commercial applications of the process.
              The pilot plant should be portable and capable of  operating on a  slip
              stream from any of the currently operating or proposed  direct-fired
              oil-shale retorting facilities in the United States.  The unit should
              be flexible enough to accommodate inputs  from surface and in-situ
              retorts with flow rates ranging from 2.83 to 28.3 sm^m while retaining
              adequate design efficiencies; if possible it should have sufficient
                        :                       i                           ;
              turndown capability to also operate on gases from  indirect-heated
                        i
              retorts.  '•
                        1
              The pilot plant would be a Stretford system based  on the current  state-!
              of the-art technology for commercial applications  of the process.  The '
              unit should be the smallest size that will operate on actual shale-oil |
                                                                          permit study
   retort-gas feeds under typical plant constraints and still
   of the process dynamics.
 X T /Q ' •
 ,., O. O
j._ 	

'A-?37 (Cin.)
-7bj
                                          PAGE KUV.SLR
                                                                                       t>0 F i <-/'•- Or
                                                                                       IMAGE />Rr
                                                                                       O'jTS'nz

-------
  B.
SIZING OF PILOT PLANT         •'   i                           :
                                 i                           !
Based on the gas characterization data compiled the CO2/H2S mole ratios
are widely separated in the gases from indirect- and direct-fired
retorting processes, and it is unlikely that a fixed-size pilot plant
could handle the full range of gases from both types of retorts.  With
direct-fired retorts, either above or below ground where combustion
occurs within the retort, gas rates vary from 68.5 . to  405 sm3/tonne
of shale processed and the H2S content varies from 0.07 to 0.30 vol %
(DG).  The CO2/H2S molar ratio varies from 76 to 165 or more,
•c!—
        For indirect-heated retorts,  where heat to the retort is generated
        externally,  the gas rates vary from 27.2to 35.0 sm3/ tonne of; shale proc-
        essed and the H2S content varies from 3.8 to 4.1 vol % (DG) .^  The CO2/
        H2S molar ratio varies from 4.3 to 5.0.

             •    1        "  '          •  i                       .    :
        Thus .for a volume turndown ratio of 10 (28.3 to 2.83 smty the pilot
        plant would have to have a sulfur turndown capability of 586 to 1 if
        the H2S content of the gas ranged from 0.07 to 4.1 vol %.  If the plant
        were designed for only gases from direct-fired retorts, a sulfur turn-
        down capability of 34 to 1 would be required.  Similarly if ithe plant
        were designed for only gases from indirect-heated retorts, a| sulfur
        turndown capability of 11 to 1 would be required.  However, 'if the gas
        volume were decreased as the sulfur content was increased, then a sul-
        fur turndown capability of only 6 would be required to handle the full
        range of gases from both direct and indirect oil-shale retorts (i.e.,
        2.83 snAnof gas from an indirect-heated retort containing 4.il% H2S to
        28.3 sm3m of, gas from a direct-fired retort containing 0.07% H2S).
        In reality the Stretford system is limited in both gas throughput
                                        i                            ;            ;
        capacity and sulfur loading capacity.  Therefore to provide maximum     ;
                                        !                                        i
        turndown capability, the pilot plant should be sized to handle the      i
        maximum case for direct-fired retorts (28.3 sm3m of Paraho gas contain-
        ing 0.30 vol % H2S).  Gases containing less sulfur can be handled up to
                  i                      !
        28.3 sm3m since the system is capable of operating with reduced sulfur
      ii 3/8"
                 w
              _ 1	
                                                                                  '.'J \LL-J'
    triA-2:.17 (Cm.)

-------
s;-c i •»'••
EEGirj
IA SI L'.ME
OF TEXT i-J
loadings.  For gases containing more sulfur,  the gas  volume  can be    —
turned down to within the limits of the absorber operation while main-
taining maximum sulfur loading.
          !                      I                            '  .
          '                      j                                    —
DUTY SPECIFICATIONS
              The pilot plant should be designed primarily to remove H2S from oil-
              shale gas produced by direct-fired retorts.  The maximum capacity of
              the pilot plant should be 28.3  sm^m of feed gas.  The maximum sulfur
              capacity should be  6.6 Kg of sulfur per hour based on a loading of
              800 ppmw of hydrosulfide ion (HS ) in the solution.  The plant should
              be capable of reducing the H2S content of the gas to 10 ppmv or less,
              and CO2/H2S ratios as high as 200 to 1.
              The pilot plant should include equipment for cooling the fee|d gas  from
              60° to 32°C and for removing the ammonia before the feed gas enters the
              Stretford absorber.  The pilot-plant design should include only those
              equipment components, instruments, and controls necessary for safe
              operation of the equipment and as required to adequately test and
              demonstrate the Stretford process and to carry out the intended re-
              search program.  Most of the data required for determining the perfor-
              mance and operation of the system would be obtained by manual sampling
              and laboratory analysis of the process streams. -
         D.   RECOMMENDED SYSTEM
         1.   Basis of Design
                        i
              The bases for designing and sizing the pilot-plant components are as
              follows:  I
                                                           28.3 sm3m
                                                           Atra
                                                           60°C
     Gas characteristics
          i
       Maximum volume (dry gas)
       Pressure
          i
       Temperature
            i!H_l	
BOTTC'.' ••'•
                                                                                    "•••Aro ILL ,
          F"A-2S7 (Cin.)
          (4-76;

-------
     Critical components
       H2S
       C02
       NH3
                                 I
     Cooling water temperature
     Sour-water treatment
     Sulfur recovery
     Stretford solution sulfide loading
                                        0.3 vol %      ;
                                        22.8 vol %
                                        0.7 vol %      !
                                        Saturated      ;
                                        2i°c           ;
                                        Not included
                                        Disposal as wet cake
                                        800 ppmw       !
Description of Process
A material balance flow sheet for the Stretford pilot plant  is  shown
Fig. XI-1-  -The idealized process reactions  are as  follows:  - 	 —
                                                                on
     Reaction 1
        i-"= Na2CO3 + H2S
                        NaHS + NaHC03
Reaction 2
     -4NaV03 + 2HaHS + H2O
   .1
Reaction 3
     i
     !Na2V409 + 2NaOH + 2ADA*
     i
Reaction 4
     i
     !2ADA (reduced) + O2 -
                                      Na2V4O9  + 4NaOH + 2S
                                         4NaVO3 + 2ADA (reduced)
                                     2ADA* + H2O
      *Anthraquinone disulfonic acid.
 The sour fuel-gas feed (stream 1) enters the gas cooler,  where it is
 cooled by direct contact with circulating water solution.  The flow
 rate of feed gas is controlled to the rate set for the test and is
 continually recorded.   As the gas is cooled, a large portion of the  	;
.water.and most.of.the.ammonia are removed (stream.2)	Heat
3 8
   ICin.)
                      $$$.,l\3 ';:i;:i;::
                      F'AGC NL-'.'Cn
                                                        is .ex-	..

-------
CAS
COCKER
ABSORBER
DELAY TANK
SOLUTION
PUMP TANK
                                                       SLURRY TANK
                                               OXIDIZER  AND CHEMICAL  SLURRY
                                               TANK     MAKEUP TANK  PUMP
      SULFUR
SULFUR TRANSFER
FILTER  BOX
N, *n*r>
O.«- \. "0-

0.
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*•-•
•«•

15.10
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78J5.53
11068
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54 72
2928"
2661
48.33

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6854
_
16 17
1883
712.03



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140' f

<5>




48.67






Trace
of H-C'i
0.12
1883
581-87



649.49

90° F


15.10
2.29
2825.53
11068
1538.00
54.72
29.28
26.61
48.38

50.55
68.54

16.05
Trace
130.16



4915.89
9S6.00
90= F

<£>
15.10
2.29
2825.53
110.68
1538.00
54.72
29.28
26.61
48.38

50.55
68.54

00.54
_
130.16



4899.89




Oxygen
Nitrogen
NaHS
Water
Sulfur
Vanadate
ADA
EDTA
Iron (Soluble)
NaHCO,
Ma. CO,
Na,S,0,

Hydrocarbons





Total. Ib/hr
Total. SCFM
Total, gpm

^^



20000.00

114.90
214.90
54.00
2.00
1016.00
59.90
382250







25285.00

42.20

^^


25.57*
20006.00
I
114.90
214.90
54.00
2.00
1055.60
10.00
3824.00

Trice





25301 .00



<>>
36.70
120.90

2.80















160.40
34.50



29.40
120.90

4.80









Trace





155.10







19832. OO
—
113.90
213.10
53.50
138
1046.70
9.92
3791 SO







25063.00



^>



16S.OO
14.60
0.96
1.80
0.45
0.02
8.86
0.08
32.10







226.87



<1>


i
92,13
—
O.E5
1.02
0.2S
0,01
5.53
0:23
18.42

.





118.25
.
.
1
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8.79















8.79



X7




24.60
0.03
0.06
0.02
Trace
0.31
Trace
1.11







40.73



^5*





0.03
0.05
0.02
Trace

0.29








6.21



*•*,(«•* MWOT bttxMfl [HS] and Sulfur
         18.  Material Balance  Flowsheet  for  Pilot  Plant

                                           >v-: 144 -.-...<
                                                                   TYPING GU!D2i:

-------
              tracted by circulating the water solution through a water-cooled heat
                                              t                         '  '            I
              exchanger.                      i                           i            I
              The temperatures of the incoming sour gas,  the cooled gas,  and the
              cooling water discharge streams are continually monitored..,. The .sour .__
                                                                         !
              water (stream 2) is discharged.  Treatment  of the sour water is outside
              the scope of the pilot plant.   ',
                        '
LAC!
              The cooled gas (stream 3) then enters the ejector-venturi gas absorber
              at about 90°F.  The ejector-venturi absorber (see Appendix E) operates
              on the jet principle, in which the Stretford solution is under pressure
              to create a draft and simultaneously provide intimate contact between
              the liquid and gas as it passes through the yenturi_.  On contact with
              the alkaline Stretford solution, which is an aqueous solution contain-
              ing sodium carbonate, sodium metavanadate, and anthraquinone difulfonic
              acid (ADA) , the H2S dissolves rapidly and forms a small concentration
              of hydrosulfide ion (reaction l)j  Sodium carbonate in the Solution
              enters into the reaction and provides a buffer to prevent rapid pH
                                               i
              changes as the acid gases are absorbed.                    i
                        i                       I                          :
              The solution will absorb some CO2, resulting in formation of sodium
              bicarbonate and consequent lowering of the pH until equilibrium is
              reached with respect to the level of C02 in the gas.  The pH of the
              Stretford solution will therefore be a function of the level of CO2 in
              the gas.  !At the point when equilibrium is reached, there must be suf-
              ficient Na2CO3 remaining to convert all the H2S in the solution to
              hydrosulfide ions .
                        I  '
              For gases "with large C02/H2S ratios the pH of the solution ^ay be suf-
                                               f                          I
              ficiently lowered to affect the  absorption rate of H2S.  In that case
                        1                       »
              addition of proprietary additives to the solution may be required for
              the hydrosulfide  loadings to be  as high as 800 ppm.
                                                                                       COTTCf1 C
                                                                                       IMAGE AF,"
 The venturi discharges into a mist eliminator,  where gases are sepa-
_rated.from the liquids.- The treated.gas (stream 4),-in which essen-
                (Cin.)
           (4-76)


-------

       *
LAST LINE
OF TEXT
              tially  all the  H2S  has been removed,  will be returned to the oil-shale
              process.   The separated  liquid will flow into the delay tank.
             The  sodium metavanadate in the solution readily reacts with'the hydro-
             sulfide to produce elemental sulfur (reaction 2) and a reduced form of.
             vanadium.   Sufficient residence time is provided by the delay tank to
             assure that any remaining hydrosulfide in the solution is reacted so as
                        i
             to prevent hydrosulfide ions from entering the oxidizer and; becoming
                        i                      •                           !
             oxidized to sodium thiosulfate, an undersirable, stable, by-product.
Flow (stream 6) from the delay tank is by gravity to minimize sticking
of the sulfur when the solution is in a transitory Redox stage.  A
liquid-level controller is provided_ to control the _f low of solution
from the delay tank to the oxidizer.  The reacted solution containing
reduced vanadium and reduced ADA is regenerated in the oxidizer tower
according to reactions 3 and 4 by being sparged with an excess of air
(stream 7) supplied by a blower.  The flow of air can be adjusted so
that sulfur particles will properly rise, forming a froth at the sur-
face but allowing the Stretford solution to settle clear of sulfur.
The accumulated sulfur froth overflows (stream 10) to a slurry tank.
Trace amounts of volatile hydrocarbons that may be absorbed in the
Stretford solution will be stripped by the air rising in the oxidizer.
A hood provided over the oxidizer tank will lift and direct the dis-
          !                       '
charge gases  (stream 8) away from the operators.
                        t
              The regenerated Stretford solution  (stream 9) is essentially  free  of
                        !                       i
              sulfur and is returned to the solution pump  tank.  The solution pump
              tank is sized to hold all the required solution when  the pilot plant is
              shut down.
              The regenerated  solution (stream'4)  is  then pumped back to  the  venturi
                        '                       »                          '             f
              absorber at a preset  and controlled  rate.  The  flow  rate, pH, and tern- .  ..,_.,.
                        I                       1                          ,             j ..:..• i I
              perature of the  solution are  continually monitored and recorded.
                                                                         r>-:M--N0-!G'
                                                                         •:QS TA=L"
                                                                         '-•-••JD iLLUl
           EPA-7S7 (Cin.)
           14-76)
                                          PAGE

-------
                 rvr;i:
HEAL:.
Equipment for handling the sulfur slurry has been reduced to; the mini-  ,
mum in an attempt to keep the cost of the pilot plant to a minimum  and  •
yet provide sufficient capability to test and demonstrate the Stretford
          i                     •  i                                       i
process.  ,                       i                                       I
BEGIN
LAST LiNE
OF TEXT r
                        1  '                                                 i           >
              The sulfur produced will be disposed of as a wet  cake.  A sulfur filter .
              (see Appendix E) operated on a batch basis will filter  the sulfur from •
                        i                                         "                     J
              the slurry,  The filtrate solution  (stream 11) is returned to the solu-
              tion pump tank.  The wet sulfur cake accumulated  in  the filter will be !
              discharged to a transfer box, which is sized for  4 days of operation at
                                                                           :           i
              maximum utilization.  The amount  of Stretford  solution  lost with dis-  ;
                                                                                      i
                 :       '                       ;                                       t
              charge of the wet sulfur cake  (stream 13) should  be  sufficient to keep :
          __    the buildup of sodium thiosulfate in balance.  The cost of Stretford   .
              chemicals lost in the sulfur cake at the pilot level of operation is   !
                                                                                      i
              not a significant economic factor.  The filter system is  arranged so
                                               t                                       i
              that the filter cake can be rinsed  (stream 12) before is  is discharged.
                      9-1/8"
                        I
          3.   Turndown Capability
              The described capacity  of the pilot plant  ( 6.6 Kg of sulfur/hr) is
              based on an average solution loading of 800 ppm.   Sulfur  loadings of
              500 to 1000 ppm are commonly achieved.  The maximum  solution loading
                        i
              obtained will depend on many factors but will  largely be  a function of
              the solution pH, which  is influenced by the amount of CO2 in the gas.
              Solution loadings can be anywhere from zero up to the maximum capacity
              of the solution, which  therefore  allows infinite  turndown in the quan-
              tity of sulfur contained in the feed gas.  However,  the cost of a
                        I                       ;
              Stretford plant is largely a function of the amount  of  solution that
              must be circulated, and therefore a goal in piloting the  process is to
                        1                       i                            :
              determine .the maximum solution loading possible  that will result in
              adequate operation of the system.while obtaining a satisfactory level
              of H2S removal effectiveness.
                                                                                       BOTTOM C~
                                                                                        ' 'AGE AP>
        !     A 3/8"
        i	 J— —
The use of  the  ejector-venturi gas  scrubbing system (see Appendix E)
affords wide  gas  turndown capability for the system.   Since :the flow of .:. J.'Jv
gas..is .motivated  by. the. liquid spray, .the scrubbing system functions _.. J ' 'H T-
          i                       '                            i           •* "-, \iP* i: I ! :
          H                 X'XvX'XvX'X'X'X'                                  f '•'•l^:'>-l-U,
          V                 i£x£xi47.. x-x-':    _ 		  	i TRATIG'JS
                           PAGE NUMBER
           EPA-287 (Gin.)
           (4-7C)

-------
      largely independently of the gas flow rate.  The scrubber, which has a
      maximum gas capacity of 28.3 sm3m, can be turned down to nearly zero.
      For gases containing larger amounts of sulfur the solution loading can
      be adjusted by reducing the gas throughput.                 ;
      By changing the ejector liquid-spray nozzle the rate of liquid circula-
      tion can be reduced.  Therefore gases with less sulfur can be accom-
      modated while maintaining high solution  loadings.
                !-                      I                           :
      The operation of  the pilot plant would approximate  that described in
      Table  40  for various gas feeds.                           '•
i 4.   Equipment Description_	j_  _  		,	. .
!  "*                                    '
      The pilot plant would be  a portable  skid-mounted unit,  completely
      assembled with all  equipment,  controls, and instrumentation;required
      for a complete and  operable  unit!  Utilities and services needed to
      operate  the pilot plant must be  supplied at the  test site and be field
      connected.
                I
      The maximum demand  for services  is as  follows:
28.3 sm3m (30.5cia-diam duct)
28.3 sm3nr <30.5cm-diam duct)
30 hp (460 V, 3-phase, H2)
0.11 fcpm
1100 fcpm
4.9
           Raw retort gas feed
           Treated gas return
           Electrical power
           Process water
           Cooling water
           Sour-water disposal
       A list of the major equipment required for construction of the pilot
                                       i
       plant is given in Table 41.

  E.    PRELIMINARY COST ESTIMATE
       The total estimated cost  of the pilot plant with all equipment, instru- I  '.: '.CI A~:
                i                       I                '           ,            i Q! 'T^QC
       ments, and controls as described,  assembled on skid mountings as a com- .^,',~,"r~,
J~    ,  .                              I                                     ---...- -.-.-.
;	_plete and operable unit,, is as .follows:-

                                 "PV3E N'JVFER
   .4-76;

-------
Table . 40.    Approximate Pilot-Plant Operation for Various Gases

Gas
Tosco
Union
Paraho
Geokinetics
Oxy

Type of
Retort
Indirect
Indirect
Direct
Direct
.Direct

H2S
(vol %)
4.12
3.82
0.30
0.13
0.119

Gas Flow
2.37
2.55
32.4
31.1
31.1

Sulfur
(KB')
6.6
.6.6
6.6 .
4.3
4.0

Liquid Flow
159
159
159
102
102
Solution
Loading
(ppm wt)
800
800
800
518
476
                                149

-------
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-------
            Item-100 gas cooler module
            Item-200 absorber module    ;
                                        i
            Item 300 oxidizer module    :
            Item 400 sulfur handling module
           	 Total cost (December 1980 capital)
                         $200,000
                           74,000
                           68,000
                           58,000
                        __$400,000_
       If the gas were provided at  22°5,the gas cooler module could be
       eliminated, in which case the total cost of the system would be about
       $260,000.  The cost of the gas cooler module (Item 100) includes the
       instrumentation and controls required for proper functioning of the
       pilot unit.  These instruments ($60,000) would be required even if the
       cooler module were eliminated.   :                          !
       __	  .  : ..--•"      ... ....  ..'_.,	j	 __--.
       The probable cost range is estimated as follows:
                jLow
With Cooler
  $520,000
   400,000
       j
   308,OOO
Without Cooler
   $338,000
    260,000
    2OO,OdO
  F.
       ADVANTAGES AND USE OF PILOT PLANT                          :
       The primary purposes of a pilot plant are to prove the technical feasi-
                                       i                           '             '
       bility of the process application and to obtain data needed!for scaleup !
       of the process to production-size equipment.  If the performance of the'.
       pilot plant both at optimum and extreme conditions matched the          I
       predicted results and if there were no unreconcilable problems, then    !
       commerical application of the process could be carried out with confi-  j




BEGIN
LAST LINE
1.
2.
3.

4.
	 5.
Or itXT i-'f-
i ' :
determine the characteristics of the raw retort gas.
determine the characteristics of the treated gas.
determine the characteristics of the waste streams.

predict the characteristics of controlled emissions.
determine the process efficiency and reliability.
-... ,....'



BOTTOM OF
IV. AGE ARE
OUTSIDE
DIMENSIOK

,     _
   OJA-7iJ7'(Cin.)
   (4-70)

-------
        TYPING GUlL-if SHLEI
BEGiN
LA£T LIN
or TEXT i:£-
        I
1_   6.   evaluate transient conditions of startup, normal and emergency
                                       i                            i
           shutdown, process upsets, etc.,
   •   7    evaluate the economics of the Stretford process.        :
                ;                       I          •                  i
   	Piloting of the process can aid  in commercial  application of the proc-
      ess by providing demonstration of continuous operation  of the  system,
                i                       '
      as well as the following  data:
                i
      1.   Level of H2S  and other  sulfur  compounds  in the treated gas and
           percentage  of overall removal  of sulfur compounds  by the Stretford
           process
      2.   Disposition of COS and other organic sulfur compounds in the feed

    "™ 3^ ~ Effects of unsaturated hydrocarbons in the feed gas on process
            operation and life of the Stretford chemicals
       4.    Amount of hydrocarbons or other contaminants in the oxidizer vent
       5.    Quality of sulfur produced
       6.    Solution sulfur loading versus gas characteristics     ,
       7.   Rate of thiosulfate  formation versus gas characteristics
       8.   Absorption of C02 versus gas characteristics
       9.   Design parameters for the  absorber                     ,
            a.   HS" loading in the solution
            b.   'Thiosulfate concentration
            c.   .Na2CO3  concentration   ;
      10.   Design  parameters for  the  oxidizer
            a.   'Ratio of air to sulfur loading                   !
                 I                       i                           '
            b.   (Ratio of air to tank diameter
            c.   JHeight of oxidizer    j                           ;
             d.   ICharacteristics of sulfur froth
                 i                       i                           I
       11.    Design parameters for filter
             a.   [Filter selection
             b.   iPumping rates  and pump type                      ,
             c.
                  •Filtration rates and wash cycles required
  I.
      A ' -5 .
      y J
                                        T
                                                                POTTO'.' C'
                                                                IMAGE AF/.
                                                                OUTS! 17 =
                                                                r'!MEr';'~'C
J^	
                                             .155
                                          PAGr. NUMBER
                                                                TRATIO: Jt
    £PA-2S7 (Cin.)
    (4-76)

-------
           12.
           13.
d.   Sulfur quality         ;
e.   Washwater evaporation rate required                 :    •_-
Design parameters for gas cooler
a.   NH3 and H2S absorption versus  gas characteristics   |
b.   Characteristics of sour water  _T		
Evaluation  of corrosion problems  and materials of construction
OH TEXT
        i —
               37 iCir..) '
                                          PAGE Nbr.'.SER

-------
            9-1/5-
   ;.  , U
	j	

 EPA-:;:? !Cm.)
                                  APPENDIX A

                           STRETFORD DIRECT PROCESS
PAC-E N

-------
[SHEET
PRELIMINARY CAPITAL - DETAIL SHEET I 1 OF 6
PROJECT
r^TT'-n'n'nTT'rYDT^ TYTP'PPT PPOPKS.S
	 	 	 	 ' JOB NUMBtK
-. 	 ; 9212
PHASE jCAbt BY
SECTION NUMBER ft NAME *
FACTORS
— i —
ITEM
101
102
103
104
201
202
203
'
204
205
206
207
208
209
210
211
212
ECTOR NUMBER & NAME |
BASE; x ESC. x CAPACITY • x QUANT, x
NAME OF FACILITY
Gas Coolers
Cooler Cir. Pumps
Exchangers
Trace S Cover
For Freeze Protection
Absorbers
Fwd. Pumps
Oxidizer Tower
Air Diffusion Sys.
Sulfur Slurry Tk.
Tank Agitator
Slurry Pump
Rot. Vac. Filter Sys.
Sulfur Melter
Sulfur Fwd. Pump
Sulfur Store Tk.
Agita.tor
QUANT.
6
6
6
16
16
1
1
1
1
1
1
1
1
[MATERIAL +
CONSTRUCTION
MATERIAL
304 St.Stl
304 St.Stl
304 St.Stl
Steel
FRP
Stl. &
Epoxy
Steel
Steel &
Epoxy
Steel
FRP.
Stl.
Steel
Steel
Steel
Steel
CONDITION + COMPLEXlTYj — Mi (19 )
DESCRIPTION j
i
12'$x42' Bl to Bl.; 10 PSI
18' Packed section .
2000 ft - 3 1/2"$ ;Pall Rings
1000 GPM, 100' HD, 40 HP
5000 ft2, U Tube, 14' LG Tube
All Items
Subtotal (100 Series)
12'$x42' Bl to Bl |
18 * Packed section .
2000 ft - 3 1/2" * Pall Rings
500 GPM, 40' HD, 10 HP
30'$x24' HI w/foam
Trough & Air Ring ;
7500 SCFM, Blowers',
Elec., Air Piping, Bldg.
15000 Gal, 25 PSI
Medium Ag., 15 HP.|
100 GPM, 40 HD, 3 HP
Incls; Filter, Vac. Pump,
Filtrate Receiver '& Pump,
Conveyor, Wash Tk, & Pump,
Building
1200 Gal., 25 PSI,: JKT. &
Internal Coil, Insulate
& Baffle i
10 GPM, 1 HP
1
30,000 Gal. 1 WK
API. S.G. = 2 !
Heavy, 5 HP !


$4,028
FORM 39650 PRINTED IN U.'i-A. Rl-69
                                                                          158

-------
PRELIMINARY  CAPITAL -  DETAIL  SHEET
PROJECT
  STRETFORD DIRECT PROCESS
SECTION NUMBER t NAME
                   Case A
  213



  214

  215

  216


  217

  218

  219

  220
                                      SECTOR NUMBER & NAME
   BASE X ESC. X CAPACITY

     NAME G


Drier Sys.



Make-up Mix Tk.'

Fwd. Pump

Lean Sol. Fd. Tk.


Tower  Cool Pumps

Purge  Pump

Mix Tk.  Agitator
 Trace & Cover for Freeze
   Protection
                                     XQUANT. X  [MATERIAL   +
                                                                CONDITION + COMPLEXITY]
Y

	
QUANT.
1
1
CONSTRUCTION
MATERIAL
Steel
Steel

20
Va
Co
27
1

1


8

1

1
St.Stl.

Steel
Epoxy

FKP

FRP

Steel
200 ft  W/Heating, Air or
Vac. Sys.,  Feed & Disch.
Conveyor, Bldg.    j

2700 Gal, 8 Hr. Store

100 GPM,  100'  HD, 7 1/2 HP

36,000  Gal, 5 min. ;SG - 1.2
1000 GPM, 8Q'_ HD

100 GPM, 40' HD., 3 HP

Medium, 25 HP      ',

All Items          ;
   As Required      ;
   Subtotal  (200 Series)

   Total  (All Equipment)
                                                                                  = MS(19
                                                                                             $5943

                                                                                             $9971
   FORM 39650 PRINTED IN U.S.A. R W9
                                                159

-------
PRELIMINARY  CAPITAL  -  DETAIL  SHEET
                                                                                               f 6
PROJECT


    STRETFORD DIRECT PROCESS
                                                                    9212
   PRE-1
Case A
                                                                      2-1-80
SECTION NUMBER & NAME
                                      SECTOR NUMBER 1 NAME
FACTORS
            BASE X ESC. X CAPACITY
                XQUANT. X  [MATERIAL
                                                                 CONDITION  + COMPLEXITY]
                                                                       = MS(19
 ITEM
              KAME OF  FACILITY
                                      QUANT.
                        CONSTRUCTION

                           MATERIAL
                                                                  DESCRIPTIO'N
          Case Al - Disposal of Purge Solution



            Equipment as above (Sheets  1 and 2)



            Allowance (20%)



                                                         Total



            Royalty  (10% of capital)



            Initial chemical charge



                                    1980 Installed Capital Cost
                                                                       $ 9,971



                                                                         1,994



                                                                        11,965



                                                                         1,197



                                                                           160



                                                                       $13,322
          Case A2  - Recovery and Recycle of Purge Solution



            Equipment as above  (Sheets 1 and 2)




            Purge  stream reductive  incineration system

               (300 lb/hr salts)



                                                          Sub-total



            Allowance (20%)



                                                          Total



            Royalty (10% of capital)
                    f


            Initial chemical charge



                                     1980 Installed Capital Cost
                                                                       $ 9,971





                                                                         1,150



                                                                        11,121



                                                                         2,224



                                                                       $13,345



                                                                         1,335



                                                                           160



                                                                       $14,840
 FORM 39650 PRINTED IN U.S.A. RI-6I
                                              160

-------
                  CAPITAL  - DETAIL  SHEET
 PROJECT
   STRETFORD DIRECT PROCESS
V PHASE.

   PRE-1
  ITEM

; & NAME
CASE
Case Al
BY

SECTOR NUMBER & NAME
            BASE X ESC. X CAPACITY
                         X QUANT. X  [MATERIAL
               NAME OF FACILITY
                                      QUANT.
                                 CONSTRUCTION
                                   MATERIAL
                               Disposal of Purge  Solution
                                                                CONDITION + COMPLEXITY]
                                                                  DESCRIPTION
                                                                               ==MS(19 )
    1.   Raw Materials:

           Vanadate
           ADA
           EDTA
           Sodium Carbonate
           Iron (Soluble)
                                                 $  174,000/yr
                                                    887,000/yr
                                                     24,000/yr
                                                      3,000/yr
                                                 	Neg/yr

                                                 $l,088,000/yr
    2.    By Products

            Sulfur
             12028 tons/yr x $90/ton = $1,083,000  (carbon)
     3.    Water Treatment or Disposal
            "Sour" Water
            "Purge" Water
            "Filter Wash"
                   132x10  gal/yr
                   9.28x10  Ibs/yr
                   5x10  gal/yr
No charge
No charge
No charge
          Utilities
                                    10.1x10  KwH/yr
Electrical Power
150 Psig Steam         28x10" Ib/yr
Process & Cooling Water  10,000 GPM
          Manpower
            14 men x 2000 hr/yr x $.15/MnHr
             1 supervisor 8760 hr x $20/MnHr
$303,000
  70,000
 526,000

$899,000
                                                  $420,000
                                                   180,000

                                                  $600,000
          Maintenance,,(5%), Capital Rec.  (20%),  Misc. (4%)  •

             29%  x capital $13,322,000                        $3,864,000/yr
   FORM 39650 PRINTED IN U.S.A. RIO
                                               161

-------
                   CAPITAL  -  DETAIL  SHEET
                                                                                                5  OF  6
 PROJECT
               n
, PHASE
PRE-1
                     Case Al
                                                                                      JOB NUMBER

                                                                                        9212
                                                                                            (UMBER
 SECTION NUMBER * NAME
                                        SECTOR NUMBER <• NAME
             BASE X ESC. X CAPACITY
                                    xQUANT, x  [MATERIAL
                                                                     CONDITION + COMPLEXITY]
                                                                                                MS(19 )
  ITEM
               NAME OF FACILITY
                                         QUANT.
                                            CONSTRUCTION
                                               MATERIAL
                                                                      DESCRIPTION
                            Disposal of Purge Solution  (Cont'd)
    7.   Net Annualized Cost
    8.   Total Installed Capital
            High, Dec. 1980
            Probable,  Dec. 1980
            Low, Dec..  1980
                                                              $5,368,000/yr   ]
                                                              $0.294/ton of shale
                                                              $0.494/bbl of oil
                                                              $17,320,000
                                                               13,322,000
                                                               10,260,000
  FORM 39650 PRINTED IN U.S.A. Rl-69
                                                  162

-------
                 CAPITAL  -  DETAIL  SHEET
                                                                               SHEET

                                                                                 G OF  6
   STRETFORD DIRECT PROCESS
   PRE-1
          Case A2
                              BY
                                                                                  JOB NUMBER

                                                                                      9212
                                                                                   EF NUMBER
SECTION NUMBER * NAME
FACTORS
 ITEM
   2.
   3.
                                     SECTOR NUMBER
           BASE X ESC. X CAPACITY
                            XQUANT. X [MATERIAL
                                                               CONDITION -f- COMPLEXITY]
                                                                                  = MS{19
             NAME  OF FACILITY
                                     QUANT.
                                    CONSTRUCTION
                                      MATERIAL	
                       Recovery and Recycle of Purge Solution
   1.   Raw Materials:

          KDA
          EDTA
By Products:
  Sulfur,  12400 TPY

Water Treatment or Disposal
  "Sour" Water      132x1.0  gal/yr
  "Filter  Wash"     5x10  gal/yr
         Utilities:
           Elec.
           Stin.,
           Water
           Gas
                11.5x10  KwH/yr
                42.9x10  Ib/yr
                11000 Gpm
                15 M Btu/hr
    5.    Manpower
           18 men x 2000 hr/yr x $15/MnHr
           1 super. 8760 hr/yr x $20/MnHr
    6.    Maint.  (5%),  Capital Rec. (20%), Misc.  (4%)

    7.    Net Annualized Cost



    8.    Total Installed Capital
           High
           Probable
           Low
                Dec.  1980
                Dec.  1980
                Dec.  1980
  FORM 39650 PRINTED M U.S.A. Rl-69
                                                                 DESCRIPTION
                                                         $887,000/yr
                                                           24,000/yf
                                                         $911,000/yr
                                                                  $l,116,000/yr  (Credit
                                                                  No charge
                                                                  No charge
$  345,000/yr
   107,000/yr
   578,000/yr
   328,000/yr
$l,358,000/yr
                                                          $540,000/yir
                                                           180,000/yr

                                                          $720,000/yr

                                                          $4,304,000/yr

                                                          $6,177,000/yr
                                                          $0.338/ton of  shale
                                                          $0.569/bbl of  oil
 $19,292,000
  14,840,000
  11,426,000
                                               163

-------
                                                 I . !  . i i li

                                                 O!"  f-At;;?
LAST LINE
OF TEXT t-
                          I                    APPENDIX B                        :



                    THREE-STAGE SELECTIVE ABSORPTION PLUS GLAUS SULFUR RECOVERY
                                     WITH SCOT  TAIL GAS TREATMENT
                        9-1/8"
        I
               3/8'
                 	J	
           EPA-287 (Cin.)
           (4-7G)
                                             PAGE NUMBER
BOTTOM OF
IMAGE ARE,:
OUTSIDE
D!f,'.Er;siot.
FOR TABLES
    ILLUS-

-------
PRELIMINARY CAPITAL - DETAIL SHEET
1
SHEET
1 OF 4
PROJECT 3 STAGE SELECTIVE ABSORPTION PLUS GLAUS SULFUR RECOVERY WITH SCOT JOB u BER
QO1 *?
TAIL GAS TREATMENT 	 	 	 , 	 • 	 „ :!„ „„ 	

i ' ^
PRE-1 • Case B
SECTION NUMBER & NAME
FACTORS
ITEM
101

102
103
104

201
202
203

204
205
206
207
208
209
210
211
212
213
214


301
302

303
304
BASE X ESC. X CAPACITY X
MAME OF. FACILITY
Gas Cooler

Cooler Pump
Exchangers
Trace & Cover
For Freeze Protection
1st. Stage Absorber
Exchanger
Pump

Interchanger .. ....
1st Stage Desorber
Condenser
Pump
Pump
Reboileir
Compressor
Amine Recovery Reboil
Sludge Pump
Sludge Accumulator
Trace & Cover
For Freeze Protection

2nd Stg. Absorber
Pump

Interchanger
Cooler
SECTOR NUMBER & NAME
QUANT. X
OUANT.
6

6
6


16
16
16

16 ..
3
3
3
3
3
3
1
1
-1



1
1

1
1
[MATERIAL •+•
CONSTRUCTION
MATERIAL
304 St.Stl.

304 St.Stl.
304 St.Stl.


Steel
Steel
D.I.

Steel
Steel
Steel
D.I.
D.I.
Steel
Std.
Steel
D.I.
Steel



Steel
D.I.

Steel
Steel
CONDITION + COMPLEXITY] (
DESCRIPTION
12'$x42' B1-B1, 10 PSI, 18'
of Packing, 2000 ft
1000 GPM, 100' HD; 40 HP
5000 ft2 U Tube, 14' Lg.
.All Items 	 ...
Subtotal (100 Series)
12'$x42' B1-B1, 10 Trays
829 ft2 	 ; '"'
150 GPM, 100' HD, 7 1/2 HP
2 :
287 ft 	 ; , .
12 '$42' B1-B1, 10 Trays
3000 ft2, Float, 14' Lg
716 GPM, 150' HD, 50 HP
639 GPM, 60' HD, 15 HP
820 ft2
6200 ACFM, 2 PSI,: 25 HP
2300 Gal., 154 ft2
1/2 HP
10 Day, 150 Gal
All Items \
As Required
Subtotal (200 Series)
9'$x36' Bl-Bl, 10 Trays
506 GPM, 150' HD/ 25 HP
2
700 ft ;
2200 ft2







$4,028

- 	














$6,205


•


FORM 396311 PRINTED IN U.S. A. KI-69
                                                                          165

-------
PRELIMINARY CAPITAL - DETAIL SHEET
MEET
2 OF 4
PROJECT 3 STAGE SELECTIVE ABSORPTION PLUS GLAUS SULFUR RECOVERY WITH SCOT : ^ goi?
'PHASE' ' CASE BY OATE , • EF NUMBER
Case B '
SECTION NUMBER & NAME
FACTORS
ITEM
305
306
307
308
309
310
311
401
402
403
404
405
406
407
408
409
410
411

500

BASE X ESC. X CAPACITY X
NAME OF FACILITY
2nd Stg. Desorber
Pump
Pump
Reboiler
Condenser
Compressor
Trace & Cover
For Freeze Protection
3rd Stg. Absorber
Pump
Interchanger
Cooler
3rd Stg. Desorber
Pump
Pump
Reboiler
Condenser
Compressor
Trace & Cover
For Freeze Protection
3 Stage Glaus Unit
Trace & Cover
As Required
SECTOR NUMBER & NAME
QUANT. X
QUANT.
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1


Sys.

[MATERIAL •+•
CONSTRUCTION
MATERIAL
Steel
D.I.
D.I.
Steel
Steel
Std.
Steel
D.I.
Steel
Steel
Steel
D.I.
D.I.
Steel
Steel
Steel





DESCRIPTION
9'$x36' Bl-Bl, 10 Trays
432 GPM, 150' HD, 40 HP
432 GPM, 150' HD, 40 HP
900 ft2 ;
2000 ft2 !
6200 ACFM, 2 PSI, 25 HP
All Items 	
As Required
Subtotal (300 Series)
6'$x30' Bl-Bl, 10 Trays
200 GPM, 100', 20 HP
187 ft2
823 ft2
6'$x30' Bl-Bl, 10 Trays
160 GPM, 150' HD, 15 HP
160 GPM, 150' HD, 15 HP
300 ft2 "
731 ft2
2123 CFM, 7 1/2 HP;
i
All Items 1
As Required
Subtotal (Series 400)
2123 scfm, 27.4 moie % H2S
35.8 TPD of Sulfur'









$957











$462
$566

foot 396SO PRINTED IM U.S.A, Rl-69
                                                                           166

-------
PRELIMINARY CAPITAL - DETAIL SHEET
PROJECT 3 STAGE SELECTIVE ABSORPTION PLUS GLAUS SULFUR RECOVERY WITH SCOT
TAIL GAS TREATMENT ' 	 — 1 	
PHASE
PRE— 1
SECTION NUMBER i NAME
FACTORS
ITEM
500
BASE
CASE BY
Case B

DATE

SHEtT
3 OF 4
9212

SECTOR NUMBER i NAME
X ESC. X CAPACITY X QUANT. X [MATERIAL + CONDITION + COMPLEXITY!
NAME OF FACILITY
SCOT tail Gas
Treatment System
Trace & Cover
As Required
Allowance (20%) -.
Royalty (Per Dow Chemical U£
Initial Chemical Charge
QUANT.
Sys.
A)
198C
CONSTRUCTION
MATERIAL
Installed C

DESCRIPTIOJN
3225 scfm, 0.035 mole % H2S
164 bb/day of sulfur
Total (All Equipment)

1

apital Cost
i

$ 358
$12,576
$ 2,515
300
160
$15,551
FORM 39650 PRINTED IN U.S.*, RIO
                                                                      167

-------
PRELIMINARY  CAPITAL -  DETAIL  SHEET
                                                                                     SHEET

                                                                                      4  OF  4
•PROJECT  3 STAGE SELECTIVE ABSORPTION  PLUS GLAUS SULFUR RECOVERY  WITH SCOT
	TATI.  GAR
 SECTION NUMBER * NAME
                CASE
                    Case B
                                     SECTOR NUMBER * NAME
                                                                                   9212
            BASE X ESC. X CAPACITY
                                 XQUANT. X  [MATERIAL
                                                                CONDITION + COMPLEXITY3
 ITEM
              NAME OF  FACILITY
                                      OUANT.
                                         CONSTRUCTION
                                           MATERIAL
                                                                  DESCRIPTION
    1.    Raw Materials:
           MDEA     13.14 tons/yr

    2.    By Products:
           Sulfur   13,016  Tons/yr

    3.    To Water Treatment or Disposal:

           "Sour" Water       133.4x10  gal/yr
           "Sludge" Water     3x10  Ib/yr
                              5.3x10  KwH/yr
                              2873x100 Ib/yr
                              1.5x10   gal/yr
4.   Utilities:
       Elec.  Power
       Stesim, Net
       Cool Water
    5.    Manpower:  •
           10 Operators
           1 Sxipervisor
    6.   Maintenance (5%), Capital Rec.  (20%),  Misc. (4%)

           20% x  Capital $15,551,000

    7.   Net Annualized Cost                  .  .
    8.   Total  Installed Capital

           High,  Dec. 1980
           Prolb., Dec. 1980
           Low, Dec.  1980
                                                              $ 24,000/yr
                                                              $l,171,000/yr (Credit
                                                              No  charge
                                                              No  charge
$  158,000/yr
 7,183,000/yr
 1,545,000/yr

$8,886,000/yr
                                                               $300,000/yr
                                                                180,000/yr

                                                               $480,000/yr
                                                               $4,510,000/yr

                                                               $12,729,000/yr
                                                               $0.069/Ton of Shale
                                                               $1.172/bbl of Oil
                                                               $20,216,000
                                                                15,551,000
                                                                11,974,000
  FORM 39690 PRINTED IN U.S.A. RI-69
                                              168

-------
EEGIN
LAST LINE
OF TEXT '
                        ,                   APPENDIX C      .                ;


            ONE-STAGE SELECTIVE  ABSORPTION PLUS INDIRECT  STRETFORD  SULFUR RECOVERY
                        !
                      9-1/8"
             {5 3/8"
             1	
_s	
                                                                     BOTTOM.1 C:-

                                                                     OL~S:C =
           EPA-.2S7 (Cin.)
           (4-70)
                                           PAGE ivi'^VBER

-------
                 CAPITAL  -  DETAIL  SHEET
                                                   SHEET


                                                     1  OF  3
   I STAGE SELECTIVE ABSORPTION PLUS  INDIRECT STRF.TFORD SULFUR ^RECOVERY
              1 ft ec             RY                               1
                                                                                      9212
                                              EF NuwSES
FACTORS
 ITEM
101




102

103

104



201



202

203

204

205

206

207

208

209

210

211

212

213

214




 301
           BASE X ESC. X CAPACITY
XQUANT. X  [MATERIAL
        Gas Coolers



        Cooler Pumps

        Exchangers
        Trace & Cover
          For Freeze  Protection

        Selective  Absorber
        Exchanger

        Pump

        Interchanger

        Strip Column

        Condenser

        Column Pump

        Reboil Pump

        Strip Col. Reboiler

        Compressor

        Amine Recv. Reboil

        Sludge Pump

        Sludge Accumulator

        Trace & Cover
           For Freeze Protection


         H»S Absorber
ACILITY



QUANT,
6
6
6
CONSTRUCTS
MATERIAL
304 St.St
304 St.St
304 St.St
                                                               CONDITION + COMPLEXITY!)
   16
                                      16
   16
   16
Steel
        Steel
D.I.
Steel
        Steel
        Steel
        D.I.
        D.I.
        Steel
        Strd.
        Steel
        D.I.
        Steel
         Steel
302
Oxidizer Tower
1
1
Steel
                                                                DESCRIPTION
12'$x42' Bl-Bl, 10 PSJ,
18' Pack Sec. 2000. ft
3 1/2" Pall Rings '

1000, GPM, 100' HD, 40 HP

500O ft2, U Tube, 114' LG


All Items         i
  Subtotal  (100 Series)

12'$x42' Bl. to.Bl ;10 Valve
Trays

57/ft2

150 GPM, 100' HD,  7  1/2 HP


287  ft2
                  I

12 • 3>x42' Bl-Bl  10  Plate

3000  ft2. Float,  14' LG

716  GPM, ISO1 HD,  50 HP

639  GPM, 50'  HD,  15 HP

722  ft2

6200 ACFM,  2 PSI ;

2300 Gal.,  154  ft

1/2  HP

10 Day,  150 gal. |

All  Items       -;
   As Required    ;
Subtotal (200 Series)

 10*x28' Bl-Bl, 13'  Pack,  Sec
 2200 ft -3 1/2" Pall Rings

 30'$x24' W/Foam Trough
 Air Ring
                                                     = MS(19
                                                     $4,028
                                                      $5,957
 FORM 13650 PRINTED IN U.S.A. Rl-69
                                             170

-------
PRELIMINARY CAPITAL . - DETAIL SHEET

SHEET
2 OF 3
PROJECT 	 	 	 ; ~~~~ ; !JOB NUMBER
I STAGE SELECTIVE ABSORPTION PLUS INDIRECT STRETFORD SULFUR RECOVERY 9212
"PHASE CASE BY DATE EF NUMBER
PRE-1 C 2-4-80
SECTION NUMBER * NAME
FACTORS
ITEM
303

304
305
306
307


308


309
310

311
312


313
314
315
316
317
318


• «" .
BASE X ESC. X CAPACITY X
NAME OF FACILITY
Air Diffusion System

Sulfur Slurry Tk.
Tank Agitator
Slurry Pump
Rot. Vac. Filter

. . - -
Sulfur Melter


Sulfur Fwd. Pump
Sulfur Store Tk.

Agitator
Drier Sys


Make-up Mix. Tk.
Fwd. Pump
Lean Sol. Fd. Tk.
Purge Pump
Mix Tic. Agitator
Trace & Cover
For Freeze Protection

•
SECTOR NUMBER 1 NAME
QUANT. X
QUANT.
1

1
1
1
1


1


1
1

1
1


1
1
1
1
1




[MATERIAL +
CONSTRUCTION
MATERIAL
Steel

Steel Epoxy
Steel
FRP
Std.

	
Steel


Steel
Steel

Steel
Steel


Steel
St.Stl.
Steel Epoxy
FRP
Steel




CONDITION + COMPLEXITY] f
DESCRIPTION
7500 SCFM, Blowers, Elec.
Air Pipe, Bldg. ;
15000 Gal. 25 psi ;
Med., 15 HP ;
100 GPM, 40' HD, 3 HP
Filter, Vac Pump, Filtrate
Receiver & Pump, Conveyor,
Wash Tk. & Pump, Bldg.
i
1200 Gal., 25 Psi,-JKT. &
Internal Coil, Insulate
& Baffle '•
10 GPM, 1 HP, T&C ;
30,000 Gal. T&C, 1 wk
API s.g. = 2
Heavy, 5 HP
200 ft w/Heating, Air or
Vac. Sys., Feed & Disch.
Conveyor , Bldg .
27,000 Gal., 8 Hr Store
100 GPM, 100' HD, 7 1/2 HP
36,000 Gal. 5 min. , s.g. =1.2
100 GPM, 40; HD., 3 HP
Medium, 25 HP
All Items
As Required i
Subtotal (300 Series)
Total (All Equipment)
— MSi'19 >









,

















$ 2,924
$12,909
FORM 39650 PRINTED M U.S-A. Rl-69
                                                                         171

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PRELIMINARY  CAPITAL -  DETAIL  SHEET
                                                    SHEET

                                                     3  OF   3
PHASE -
f
PRE-1
SECTION NUMBER * NAME
CASE
•c
BY

.
SECTOR NUMBER & NAfc
;TPOT?n ^TTT/FTTR p-pri'~nrc"DV !

DATl: 	
2-4-80 •
JOB NUMBER
9212
EF NUMBER
 FACTORS
 ITEM
            BASE X ESC. X CAPACITY
X QUANT. X  [MATERIAL
                                                                CONDITION + COMPLEXITY]
              NAME OF  FACILITY
                                      QUANT.
        CONSTRUCTION
          MATERIAL
                                                                  DESCRIPTION
          Case Bl  - Disposal of Stretford Purge Solution

            Equipment as above (sheets  1-3)

            Allowance (20%)




            Royalty (10% of capital)

            Initial Chemical Charge

                 1980 Installed Capital  Cost
                               Total
                                                      = MS(19
$12,909


  2,582


$15,491


  1,549


    160
                                                     $17,200
           Case B2 - Recovery  and Recycle of Stretford  Purge Solution

             Equipment as above (sheets 1-3)

             Stretford Purge Stream Reductive Incineration System

                                                                 Subtotal


             Allowance  (20%)

                                                                 Total


             Royalty  (10% of capital)

             Initial Chemical  Charge

                 1980 Installed Capital Cost
                                                     $12,909.

                                                       1,150
                                                     $14,059

                                                        2,812
                                                      $16,871


                                                        1,687


                                                          160
                                                      $18,718
  FOKM 3XSO PRINTED IM U.S.A. *!•«»
                                              172

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PRELIMINARY  CAPITAL  - DETAIL  SHEET
PROJECT
 I STAGE  SELECTIVE ABSORPTION PLUS INDIRECT STRETFORD SULFUR RECOVERY
 SECTION NUMBER * NAME
                     Cl
                              BY
                                     SECTOR NUMBER * NAME
    Disposal of Purge Solution
    1.    Raw Materials:
           Methyl Diethanolamine
           ADA
           EDTA
           Vanadate
           Sodium Carbonate
           Iron
         By Products
           Sulfur     12,516  ton/yr


         To Water Treatment or Disposal:
           "Sour" Water
           "Purge" Water
           "Sludge" Water
           "Filter Wash"
         Utilities:
           Electrical Power
           150 Psig  Steam
           Water
132x10  gm/yr
9.65x10  Ib/yr
3x10  Ib/yr
5x10  gal/yr
     7.8x10  KwH/yr
     1525x10  kb/yr
     24M GPM
-, — +.
ITEM
BASE X ESC. X
NAME OF
CAPACITY ^(JUANT. X [MATERIAL •*• CONDITION + CC
FACILITY
QUANT.
CONSTRUCT ON
MATERIAL
DESCRIPT
1MPLEXITY]
ION
                                                                                         ==MS(19  )
                                   $   28,000/yr
                                      954,000/yr
                                       24,000/yr
                                      181,000/yr
                                          Neg/yr
                                         3,000/yr
                                                                 §l,190,000/yr
                                    $l/130,000/yr (Credit
No charge
No charge
No charge
No charge
$  234,000/yr
 3,812,000/yr
 1,261,000/yr

$5,307,000/yr
  FORM 39CJO PRINTED IN U.S.*. RI-69
                                              173

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         fiBT.TiCTIVE ABSORPTION PLUS
            '
                                                              CONDITION  + COMPLEXITY]
         BASE X ESC. X CAPACITY
       Manpower
         15 men x 2000 hr/yr x $15/yr
         1 supervisor
$450,000/yr
 180,000/yr
$630,000/yr
  6.    Maintenance  (5%),  Capital Rec.  (20%), Misc.  (4%)

         29% x $17,200,000
$4,988,000/yr
       Net Annualized Cost
$10,985,000/yr
$0.602/ton of shale
$1.011/bbl;of oil
  8.   Total Installed Capital

         High,  Dec.  1980
         Probable,  Dec. 1980
         Low, Dec.  1980
 $22,360,000
  17,200,000
  13,244,OOJO
FOFBl 39t50 PRINTED IN U.S.*. Rl-69
                                             174

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PRELIMINARY   CAPITAL  -  DETAIL  SHEET
      TAGE SELECTIVE ABSORPTION PLUS INDIRECT STRETFORD DESULFURI2ATION
                                                          SHEET

                                                           3  OF  4
                                                                                  JOB NUMBER

                                                                                      9212
               CASE
                       C2
 SECTION NUMBER 4 NAME
                                     SECTOR NUMBER «• NAME
            BASE X ESC. X CAPACITY
      X QUANT. X  [MATERIAL   +
                                                               CONDITION + COMPLEXITY]
 ITEM
              NAME OF FACILITY
                                     OUANT.
              CONSTRUCTION
                MATERIAL
                                                                 DESCRIPTION
         Raw Materials:
           Methyl Diethanolamine
           ADA
           EDTA.
    2.    By Products
           Sulfur    12,903  TPY x $90/T


    3.    Watertreat or Disposal
           "Sour" Water
           "Sludge" Water
           "Filter Wash"
         Utilities:
           Elec:. Power
           Steam
           Water
           Gas
133.4x10  gal/yr
3x10^ Ib/yr
5x10 , gal/yr
9.2x10  KwH/yr
1540x10  Ib/yr
25M  GPM
15M Btu/hr
         Manpower
           19 men x 2000 hr/yr x $15/hr
           1 supervisor
         Maintenance (5%), Capital Rec.  (20%),  Misc. (4%)
            29% x $18,718,000
                                    $   28,000/yr
                                       954,000/yr
                                        24,000/yr

                                    $l,006,000/yr
                                    $l,160,000/yr  (Credit
No charge  '
No charge  '
No charge
$  276,000/yr
 3,850,000/yr
 1,314,000/yr
   328,000>yr
$5,768,000/yr
                                    $570,000/yr
                                     180,000/yr
                                    $750,000/yr
                                     $5,428,000/yr
  FORM 396SO PRINTED IN U.S.JL Rl-69
                                              175

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              CAPITAL  -  DETAIL  SHEET
                         SHEET

                           4 OF	4
                  C2
                                                                                  JOB NUMBER

                                                                                      9212
                                                                                   EF NUMBER
ECTION NUMBER «. NAME


           BASE X1SC. X CAPACITY
                                  I SECTOR NUMBER* NAME
                                  XQUANT. X  [MATERIAL
CONDITION + COMPLEXITY]
 	
 DESCRIPTION
7.   Net Annualized Cost
8.    Total installed Capital:
        High,  Dec. 1980
        Probable, Dec. 1980
        Low,  Dec. 1980
   $ll,792,000/yr
   $0.646/ton  oif shale
   $1.086/bbl  of oil
   $24,333,000
   $18,718,000
   $14,413,000
                                                                                          = MS(19
                                          CONSTRUCTION
                                    QUANT.  u  MATERIAL
FORM 3M50 PRINTED IN U.S.A. Rl-69

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                         G'JiL-[:
BEGIN
LAST LINE
Or TEXT
                                              APPENDIX D
                                                   I
                                      	-1-
                          JDIAMOX PROCESS PLUS  CLAUS SULFUR RECOVERY WITH

                          |              BSRP TAIL GAS TREATMENT

                          I
                        9-1/8"
                          I_
BOTTOM C
ir.'AGE A:-;.
OUTS'DE
                                                                                              ':-.\r--D !LLi
            EPA-2S7 (Gin.)
            (4-76)
                                              PAGE NUW3LR

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PRELIMINARY CAPITAL - DETAIL SHEET

SHEET
1 OF 3
PROJECT JOB NUMBER
DIAMOX PROCESS PLUS GLAUS SULFUR RECOVERY WITH -BSRP TAIL GAS TREATMENT i 9212
PHASE CASE BY DATE i EF NUMBER
Case D
SECTION NUMBER 1 NAME
FACTORS
ITEM
101


102
103
104

204





202


203

-. .
204

205
206

207

208
. .
209

210
BASE X ESC. X CAPACITY !
NAME OF FACILITY
Gas Coolers


Cooler Circ. Pumps
Exchangers
Trace & Cover
For Freeze Protection
Absorbers





Absorber Pumps

• •• - » •
Stripper Feed Pumps


Stripper Bottoms Pumps

Acid Gas Strippers
Heat Interchanger

Cooling Water Exchanger

Refrig. Exchanger

Absorber Liquor
Purge Pump
Absorber Liquor Storage
SECTOR NUMBER & NAME 1
(QUANT. )
QUANT.
6

.....
6
6


6.....





30

-•
6


4

4
4

4

4

4

1
: [MATERIAL
CONSTRUCTION
MATERIAL
304 St.Stl.


304 St.Stl.
304 St.Stl.


Steel





D.I.


D.I.

• - 	 -
D.I.

Steel
Steel

Steel

Steel

CI

Steel
CONDITION + COMPLEXITY]
DESCRIPTION
12'*x42' Bl to Bl, 10 psi
18' packed section, i
2000 ft -3 1/2"$ Pall Rings
1000 gpm, 100" Hd, 40 HP
5000 ft2, U Tube, 14' LG Tubes
All Items

12'$x72' High w/101: skirt,
6 sets spray nozzles deliver
3,000 gpm; 6 sets bulkheads
and overflow wiers for liquor
collection and visors for
gas flow. :
3000 gpm pumps to deliver
liquor to spray nozzles at
40 psig pressure
3000 gpm pumps to deliver
liquor to strippers at
30 psig pressure
4500 gpm pumps @ 30 jpsig
pressure ;
12'*x7 trays @ 24" spacing
18,000 sq.ft. multipass,
cross flow ;
18,000 sq.ft. multipass,
cross flow
2200 sq. ft., 40°F chilled
water — -
180 gpm @ 30 ft. head
!
540,000 gal., 48'4>x40'h
= MS(i9 )



-



$4,028

















'


- . -. ...



FORM 39650 PRINTED IN U.S.A. Rl-69
                                                                        178

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PBELIMfNARY CAPITAL - DETAIL SHEET
.iHEET
2 OF 3
DIAMOX PROCESS PLUS GLAUS SULFUR RECOVERY V7ITH BSRP TAIL GAS TREATMENT 9212
PHASE" " CASE BY °ATE : EF NUMBER
Case D i
SECTION NUMBER & NAME
FACTORS
ITEM
211

212

213

300
400

BASE X ESC. X CAPACITY X
NAME OF FACILITY
Absorber Feed Pump

Chilled Water Refrig.
System
Trace & Cover for
Freeze Protection " :
3 Stage Claus Unit
Trace & Cover as Required
BSPR Tail Gas
Treatment Unit
Trace s Cover as Required
• Allowance
Royalty
Initial Chemical Charge (BS
I
SECTOR NUMBER i NAME
QUANT. X
QUANT.
6

1



Sys.
Sys.
(Pe
PR Uni
198
[MATERIAL •+
CONSTRUCTION
MATERIAL
CI

Std.




,.
(20%)
: R. M. Pars
:)
) Installed
CONDITION + COMPLEXITY]
DESCRIPTION
3000 gpm pumps @ 60 psig
head
1250 Tons, 0°C
!
All Items :
As Required :
Subtotal (200 Series)
10,045 scfm, 6 mole % H-S
35.2 TPD of- Sulfur : •-•- - -
11,137 scfm, 0.031 mole % H-S
427 Ib/day
Total (Equipment)
Total i
>ns Co.)
Capital Cost
!
i
1








$19,769
$ 1,647
$ 1,021
$26,465 .
5,293
$31,758
900
83
$32,741

FORM 39CSO PRINTED IN U.S.A. RI-69
                                                                         179

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PRELIMINARY  CAPITAL  -  DETAIL  SHEET
                                                                                            OF
PROJECT                                                           •
 DIAMOX ABSORPTION PLUS CLAUS SULFUR RECOVERY WITH BSRP TAIL GAS  TREATMENT
                                                     JOB NUMBER
                                                       9212
                   Case D
                                                                                   EF NUMBER
SECTION NUMBER fNAME
                                     SECTOR NUMBER & NAME
FACTORS
            BASE X ESC. X CAPACITY
      XQUANT. X  (MATERIAL
                                                                COND1TION  + COMPLEXITY}
                         — MS(19 )
 ITEM
              NAME OF FACILITY
                                      QUANT.
              CONSTRUCTION
                MATERIAL
                                                                 DESCRIPTION
   1.    Raw Materials:   (Parsons' Info)

          Catalysts,  Chemicals, Initial Charge
          Consumption   $230/day x 365
   2.   By Products
          Sulfur   12830 TPY


   3.   Water Treatment or Disposal:
          148 x 106  gal/yr
   4.   Utilities:
          Electric  Power
          Steam, Net
          Cool HO
53.9x10" KwH/yr
4480x101' Ib/yr
1.95x10   gal/yr
   5.   Manpower:
          10 Operators
          1 Supervisor
   6.   Maintenance (5%), Capital Rec.  (20%),  Misc. (4%)

          29%  x capital $32,741,000


   7.   Net Annualized Cost
   8.   Total  Installed Capital
          High,  Dec.  1980
          Prob., Dec. 1980
          Low, Dec.  1980
                                   $82,680
                                   $84,000/yr
                                   $l,150,000/yr (Credit)
                                   No charge
$ 1,618,000/yr
$ll,530,000/yr
$ 1,950,000/yr
                                                                 $15,098,000/yr
                                   $300,000/yr
                                    180,000/yr

                                   $480,000/yr
                                    $9,945,000

                                    $24,007,000/yr
                                    $1.315/ton of shale
                                    $2.210/bbl of oil
                                    $42,563,000
                                    $32,741,000
                                    $25,211,000
 FORM 39650 PRINTED l« U.S.A. B1-C9
                                             180

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