EPA-450/2-76-016-a
          STANDARDS SUPPORT
                     AND
ENVIRONMENTAL IMPACT STATEMENT
                 VOLUME 1:
         PROPOSED STANDARDS
            OF PERFORMANCE
      FOR PETROLEUM REFINERY
      SULFUR RECOVERY PLANTS
              Emission Standards and Engineering Division
             U.S. ENVIRONMENTAL PROTECTION AGENCY
                Office of Air and Waste Management
              Office of Air Quality Planning and Standards
              Research Triangle Park, North Carolina 27711

                    September 1976

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This report has been reviewed by the Emission Standards and Engineering
Division, Office of Air Quality Planning and Standards, Office of Air and
Waste Management, Environmental Protection Agency, and approved for publica-
tion.  Mention of company or product names does not constitute endorsement
by EPA.  Copies are available free of charge to Federal employees, current
contractors and grantees, and non-profit organizations—as supplies permit—
from the Air Pollution Technical Information Center, Environmental Protection
Agency, Research Triangle Park, North Carolina 27711; or may foe obtained,
for a fee, from the National Technical Information Service, .5285 Port Royal
Road, Springfield, Virginia 22161.
                                    ii

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                                 Draft
                         Standards Support and
                    Environmental Impact Statement

                Petroleum Refinery Sulfur Recovery Plants

                    Type of Action:   Administrative

                               Prepared by
Director* Emission Standards and Engineering Division
Environmental Protection Agency
Research Triangle Park, PL C.  27711

                              • Approved fay
                                                                 (Pate)
Assistant Administrator
Office of Air and Waste lyi
EEviroKiinental Protection Agency
401 M Street, S.W.
Washington, D. C.  20460
                                                                 (D-ate>
Additional copies may be obtained or reviewed at:

Public Information Center (PM-215)
Environmental Protection Agency
Washington, D. C.  20460

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                          TABLE OF CONTENTS

                                                                  Page

 List of Tables 	
 List of Figures	!  .'  i  !  !  .'  ! v11i

 Chapter 1.  SUMMARY
        1.1  PROPOSED STANDARDS 	                      i  i
        1.2  ENVIRONMENTAL/ECONOMIC IMPACT. .... 	 i'l
        1..3  INFLATIONARY IMPACT	!!!,*! l!4
       i
 Chapter 2.  INTRODUCTION
        2.1  AUTHORITY FOR THE STANDARDS	               21
        2.2  SELECTION OF CATEGORIES  OF STATIONARY SOURCES.  !  *  '  2*4
        2.3  PROCEDURE FOR DEVELOPMENT OF STANDARDS OF
             PERFORMANCE	                          26
        2.4  CONSIDERATION OF COSTS	      	2  TO
       2.5  CONSIDERATION OF ENVIRONMENTAL IMPACTS ...'.''"'  2*11
       2.6  IMPACT ON EXISTING SOURCES 	                2*13
       2.7  REVISION OF STANDARDS  OF PERFORMANCE  ...            2'14
       2.8  REFERENCES	\  \  \  2J4

 Chapter  3.   SULFUR RECOVERY  PLANTS IN PETROLEUM REFINERIES
       3.1   PROCESSES AND EMISSIONS.  ...                        32
       3.2  EXISTING EMISSION  CONTROL REGULATIONS.  '.'.''''•'  s'ls
       3.3  REFERENCES	..'!.'.'  3.15

 Chapter  4.   EMISSION CONTROL TECHNOLOGY
       4.1   ALTERNATIVE  EMISSION CONTROL TECHNIQUES.  ...        41
       4.2   COMMERCIAL STATUS  OF TAIL  GAS TECHNOLOGY  .  .          4'19
       4.3   PERFORMANCE  OF EMISSION CONTROL SYSTEMS.  ...      '  4*23
       4.4   REFERENCES	[  [  4.31

 Chapter  5.   MODIFICATION AND RECONSTRUCTION
       5.1   MODIFICATION OF REFINERY SULFUR PLANTS  ...          51
       5.2   RECONSTRUCTION OF  REFINERY SULFUR PLANTS  ....!! 5.'6

Chapter 6.   EMISSION CONTROL SYSTEMS
       6.1   LOW-TEMPERATURE CLAUS REACTOR SYSTEM ....         61
       6.2  TAIL GAS SCRUBBING SYSTEM	'. '. 6\2

Chapter 7.  ENVIRONMENTAL IMPACT
       7.1  AMBIENT AIR QUALITY IMPACT	 .           72
       7.2  WATER POLLUTION IMPACT 	               y'g
       7.3  SOLID WASTE IMPACT	-....''*' 7'l7
       7.4  ENERGY IMPACT	                ' ' 7'18
       7.5  OTHER ENVIRONMENTAL IMPACTS	      '7*21
       7.6  REFERENCES	.' .' 7)24
                                IV

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                                                                 Page

Chapter 8.   ECONOMIC IMPACT
       8.1   INDUSTRY PROFILE	8.1
       8.2   COST OF ALTERNATIVE EMISSION CONTROL SYSTEMS	8.3
       8.3   ECONOMIC IMPACT	.'	8.10
       8.4   SOCIO-ECONOMIC AND INFLATIONARY IMPACT	8.34
       8.5   REFERENCES. .  . .	8.35

Chapter 9.   RATIONALE FOR THE STANDARDS
       9.1   SELECTION OF SOURCE FOR CONTROL	9.1
       9.2   SELECTION OF THE EEST SYSTEM OF EMISSION
            REDUCTION	:	9.1
       9.3   SELECTION OF POLLUTANTS FOR CONTROL . .	.9.5
       9.4   SELECTION OF FORMAT FOR THE STANDARDS	9.12
       9.5   SELECTION OF EMISSION LIMITS IN THE STANDARDS .... 9.14
       9.6   SELECTION OF MONITORING REQUIREMENTS AND
            PERFORMANCE TEST METHODS	'•.'•	9.17

APPENDIX A - EVOLUTION OF THE STANDARDS          .

APPENDIX B  - INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS .

APPENDIX C - EMISSION SOURCE TEST DATA

APPENDIX D - EMISSION MEASUREMENT AND CONTINUOUS MONITORING

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                           List of Tables
                                                              Page
 Table  1.1   Environmental  and Economic Impacts  of
            Alternative  Standards	  1.3
 Table  3.1   Typical  Composition  of Gas Streams  Entering
            and Leaving  a  Hypothetical 100  LT/D Refinery
            Claus  Plant	3.6
 Table  3.2   State  Regulations for  Sulfur  Recovery Plants  .  .  .  3.14
 Table  4.1   Listing  of Announced Tail  Gas Treating Units
            for Claus  Sulfur Plants.  	  4.20
 Table  4.2   Calculated Emissions from a Sulfur  Recovery
            Plant  with Various Emission Control  Systems
            Installed	„  .  4.24
 Table  7.1   Health and Welfare Effects of Exposure to H2S,
            COS and  CSp	7.3
 Table  7.2   Estimated  Maximum Ambient Air Pollutant
            Concentrations	  .  7.6
 Table  7.3   Water  Pollution  Impact of a Typical  100,000
            BBL/Day  Petroleum Refinery 	  7.11
 Table  7.4   Potential  Water  Pollution  Impact of Refinry
            Sulfur Plant NSPS	7.12
 Table  7.5   Energy Impact  of Alternative Emission  Control
            Systems.	..7.19
 Table  7.6   Environmental  Impact of No Standards  or
            Delayed  Standards	7.22
 Table  8.1   Domestic Refinery Sulfur  Plants	8.2
 Table  8.2   Domestic Petroleum Refineries	8.4
 Table  8.3   Sulfur Recovery  Plants  at  Domestic  Refineries.  .  .  8.5
 Table  8.4   Costs  for  Sulfur Recovery  Plants with
            Incineration 	  8.6
 Table  8.5   Costs  for  Sulfur Recovery  Plants with
            Alternative I Emission  Control  	  8.7
 Table  8.6   Costs  for  Sulfur  Recovery  Plants with
            Alternative II Emission Control  (Oxidation).  .  .  .  8.8
 Table  8.7   Costs  for  Sulfur  Recovery  Plants with
            Alternative II Emission Control  (Reduction).  .  .  .  8.9
 Table  8.8   Alternative Emission Control System Costs for
            a 100  LT/D Sulfur Plant	8.11
Table 8.9   Alternative Emission Control System Costs for
            a 10 LT/D  Sulfur  Plant	8.12
Table 8.10  Alternative Emission Control System Costs for
            a 5 LT/D Sulfur  Plant	8.13
Table 8.11   Large  Refiner Model  Financial  Profile	8.14
Table 8.12 Small  Refiner Model  Financial  Profile	8.16
Table 8.13  Case 1:  100 LT/D Sulfur Plant/100,000 BCD
            Refinery	8.17
Table 8.14  Case 2:  100 LT/D Sulfur Plant/50,000 BCD
           Refinery	8.18

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                  List  of Tables  (continued)
Table 8.15  Case 3:  50 LT/D Sulfur Plant/50,000 BCD
            Refinery	'
Table 8.16  Case 4:  50 LT/D Sulfur Plant/30,000 BCD
            Refi nery ...•••
Table 8.17  Case 5:  30 LT/D Sulfur Plant/30,000 BCD
            Refi nery ........••
Table 8.18  Case 6:  10 LT/D Sulfur Plant/30,000 BCD
            Refi nery 	
Table 8.19  Case 7:  30 LT/D Sulfur Plant/20,000 BCD
            Refinery	•
Table 8.20  Case 8:  10 LT/D Sulfur Plant/20,000 BCD
            Refinery
Table 8.21  Case 9:  5 LT/D Sulfur Plant/20,000 BCD
            Refinery
Table 8.22  Case 10:  5 LT/D Sulfur Plant/15,000 BCD
            Refinery 	
Table 8.23  Case 11:  5 LT/D Sulfur.PI ant/7500 BCD
            Refinery	
Table 8.24  Economic Impact of  Alternative Emission
            Control Systems
Table 8.25  Cost Effectiveness  vs. Size  of Sulfur Plant.  .
Table 8.26  Projected Growth of Refinery Sulfur Plants  .  .
Table 8.27  National Investment, Annualized  Costs and
            Emissions	
 Page


8.19

8.20

8.21

8.22

8.23

8.24

8.25

8.26

8.27
 8.31
 8.32

 8.31

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                           List  of Figures

                                                                   Page

Figure 3.1  Typical  Packaged  Claus  Plant (2-Stage)	34
Figure 3.2  Theoretical Claus Sulfur  Recovery  Efficiency
            vs. H2S/S02 Mole  Ratio  in Gas  Feed	      33
Figure 3.3  Stretford Process 	  3*10
Figure 4.1  Alternative Emission  Control Systems for  Refinery
            Sulfur Plants  	                    42
Figure 4.2  IFP-1 Process	4*4
Figure 4.3  Sulfreen Process	'.'.'"''  4*6
Figure 4.4  Wellman-Lord Process	4*9
Figure 4.5  IFP-2 Process	..'.'!.'  4! 11
Figure 4.6  Beavon Process. .  .	1 !.'.'.'.'.'.'  4.'14
Figure 4.7  Cleanair Process	   	4*16
Figure 4.8  SCOT Process	! ' '  '  '  4*18
Figure 4.9  Sulfur Dioxide Emissions  (IFP-1 Process).  ! .' .' .'  '.  .'  4*25
Figure 4.10 Sulfur Dioxide Emissions  (Wellman-Lord Process/
            SCOT Process)	4.27
Figure 4.11 Hydrogen Sulfide Emissions (Beavon Process) !  '. '.  '.  '. 4.*28
Figure 4.12 Reduced Sulfur Compound Emissions  (Beavon Process).  . 4'.29
                                 vn i

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                          1.  SUMMARY
1.1  PROPOSED STANDARDS
     Standards of performance for new or modified sulfur recovery
plants within petroleum refineries are being proposed under
section 111 of the Clean Air Act.  Depending on the type of emission
control system installed to comply with these standards, residual
emissions  released to  the atmosphere will consist of sulfur
dioxide  (S02) or reduced sulfur  compounds, i.e. hydrogen sulfide
 (H2S), carbonyl  sulfide  (COS)  and  carbon disulfide  (CS2),  (see
 discussion below).   The  standards,  therefore, limit either the
 concentration of S02,  or the  concentration of H2S  and  the  total
 concentration of H2S,  COS  and CS2,  in  the gases  discharged into
 the atmosphere from new or modified refinery sulfur recovery plants.
 Specifically, emissions  are limited to either 0.025 percent by volume
 of S02 on. a  dry basis and  zero percent oxygen,  or 0.0010 percent by
 volume of H2S and 0.030 percent by volume of reduced sulfur compounds
 on a  dry basis  and zero percent oxygen.
       The  standards also require continuous  monitoring of the concen-
 tration  of SOg'f H2S and reduced sulfur compounds in the gases
 discharged into.the atmosphere.  This is to ensure proper operation
 and maintenance of the emission control systems.
 1.2  ENVIRONMENTAL/ECONOMIC IMPACT
       Two alternative emission control systems were considered to
  serve as the basis for standards of performance (i.e. best system
  of emission reduction, considering costs) for refinery sulfur
  recovery plants', the  low-temperature extended Claus reaction system
                                    1.1

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  (alternative  I)  and  various  tail  gas scrubbing systems  (alternative II).
      The alternative II systems consist either of oxidation-scrubbing
  processes or  reduction-scrubbing  processes.  The oxidation-scrubbing
  processes first  convert emissions from a refinery sulfur plant to
  S02 and then  control these emissions with an S02 tail gas scrubbing
  system.  The  reduction-scrubbing processes convert emissions from
  a refinery sulfur plant to H2S and then control these emissions
 with an H2S scrubbing system.  In some cases, the reduction-scrubbing
 processes are also followed with an incinerator.   Thus,  residual
 emissions released to the atmosphere from the oxidation-scrubbing
 processes and the reduction-scrubbing processes which are followed
 by incineration consist of S02.   Residual  emissions  released to
 the atmosphere from the reduction-scrubbing  systems  which are not
 followed  by  incineration,  however, consist of H2S, COS and  CS2.
     The  potential  environmental  and  economic impacts associated
 with standards based  on  either alternative I  or alternative  II  are
 summarized in  Table 1.   There are  no  impacts  associated with
 alternative  I,  since  the level of  control specified  in most state
 implementation  plans  to meet and maintain the NMQS  for S02
 requires new refinery sulfur recovery plants to install an alternative I
 emission control system.
     There are  no adverse environmental impacts associated with the
proposed standards, which are based on alternative II.  These
standards will, however, lead to a reduction in national  S02 emissions
by some 55,000 tons per year, and a reduction in national energy consumption
by some 54 million kw-hr/yr (90,000 barrels of fuel oil)  in 1980.
                              1.2

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      The economic impact associated with the proposed standards is
 reasonable on both large and small refiners.  This impact is,
 however, greater on small  refiners than large refiners  due to  the
 "economies-of-scale."  The standards could  reduce  the profitability
 (as measured by return  on  assets)  of a  large refiner by 0.15-1.5
 percent, and that of a  small  refiner by 1.5-7.5  percent.   To maintain
 their profitability,  the large  refiner  would have  to increase
 prices on  petroleum products  by only o'.05-0.3 percent,  and the small
 refiner  by only 0.2-1.0 percent.
 1.3   INFLATIONARY  IMPACT
     The Agency's  guidelines for developing  an Inflationary Impact
Statement are increased operating costs in the fifth year of more
than $100 MM per year, or increased prices of more than 5 percent.
The increased operating costs in the fifth year associated with the
proposed standards are only $16  MM per year, and the potential
increase in prices is less  than  0.5 percent.   Consequently,  an
Inflationary Impact Statement has  not been prepared.
                                1.4

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                        2.   INTRODUCTION             ,
     Standards of performance under section 111  of the Clean Air
Act are proposed and promulgated following a detailed investigation
of air pollution control methods available to the affected industry
and the impact of their costs on the industry.  This document summarizes
the information obtained from such a study of sulfur recovery in
petroleum refineries.   Its nurpose is to explain  in detail  the
background and basis  of the  standards and  to  facilitate  analysis
of these standards  by interested persons,  including those who may
not be familiar with  the many technical  aspects  of  the  industry.
 Copies of the "Standard Support and Environmental Impact Statement -
 Petroleum Refinery Sulfur Recovery Plants" may be obtained by writing
 to the Public Information Center (PM-215), Environmental Protection
 Agency, Washington,  D.C. 20460.  (Specify "Standard Support and
 Environmental Impact Statement - Petroleum Refinery,Sulfur Recovery
 Plants.")
 2.1   AUTHORITY FOR THE STANDARDS
       Standards of  performance for new  stationary sources are
  developed  under section 111 of the Clean  Air Act (42 U.S.C. 1857c-6),
  as amended in 1970.   Section 111  requires the establishment of
  standards  of performance  for new  stationary  sources  of  air pollution
  which ".  .  -may contribute  significantly  to  air pollution  which
   causes or contributes to the endangerment of public health or
   welfare."   The Act  requires that  standards  of performance  for  such
                                 2.1

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  sources reflect ". .  .the degree of emission limitation achievable
  through the application of the best system of emission  reduction
  which (taking into account the cost of achieving  such reduction)
  the Administrator determines  has  been  adequately  demonstrated."
  The standards apply only to stationary sources, the construction
  or  modification of which  commences  after regulations are proposed
  by  publication in  the Federal  Register.
       Section  111 prescribes three steps to follow in establishing
 standards of  performance.
      1.  The  Administrator must identify those categories of
          stationary sources for which standards of performance
          will ultimately be promulgated by listing them  in  the
          Federal  Register.
      2.  The regulations applicable  to  a category  so listed must
          be  proposed by  publication  in  the  Federal  Register
          within 120 days of its listing.  This  proposal  provides
          interested persons  an  opportunity  for  comment.
      3.   Within 90  days  after proposal,  the Administrator must
          promulgate standards with any  alterations he deems
          appropriate.
     Standards of performance,  by themselves, do not guarantee
protection of  health or welfare; that is, they are not  designed
to achieve any specific air quality levels.   Rather, they are
designed to reflect best demonstrated technology (taking  into
account costs) for the  affected sources.  The overriding  purpose
                               2,2

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of the collective body of standards  is  to maintain existing  air
quality and to prevent new nollution problems  from developing.
     Previous legal challenges to standards of performance have
resulted in several court decisions1'2 of importance in developing
future standards.  In these cases, the principal issues were whether
EPA:   (1) made reasoned decisions and fully explained the basis
of  the standards,  (2) made available to interested parties the
information  on which  the  standards were based,  and  (3) adequately
considered significant  comments  from interested Parties.
      Among other things,  the  court  decisions  established:   (1) that
precaution  of  an environmental  impact  statement  is  not necessary
 for standards developed under section  111  of  the  Clean Air  Act
 because under this section EPA must consider  any  counter-productive
 environmental effects of a standard in determining what  system
 of control is "best;" (2) in considering costs it is not necessary
 to provide a cost-benefit analysis; (3) EPA is not required
 to justify standards that require different levels of control
 in different industries  unless such different  standards may be
 unfairly discriminatory;  and  (4) it is sufficient for EPA to  show
 that a  standard can  be  achieved  rather than  that it has  been
  achieved  by existing sources.
       Promulgation of standards  of  performance does  not prevent
  State or  local  agencies from adopting  more stringent emission
  limitations for the  same sources.   On  the contrary, section 116
  of the Act (42 U.S.C. 1857-D-l) makes  clear  that States  and
  other political subdivisions may enact more  restrictive  standards.
                                 2.3

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  Furthermore, in heavily polluted areas more stringent standards may
  be required under section 110 of the Act (42 U.S.C.  1857c-5)  in
  order to attain or maintain national ambient air quality standards
  prescribed under section 109 (42 U.S.C.  1857c-4).  Finally, section 116
  makes clear that a State may not adopt or enforce  less  stringent
  new source standards than those adopted by EPA under section  111.
       Although  standards  of performance are  normally  structured
  in  terms  of numerical emission  limits  where feasible, alternative
  aoproaches  are sometimes  necessary.  In some cases physical measure-
  ment  of emissions from a new source may be impractical or
  exorbitantly expensive.  For example, emissions of hydrocarbons
 from storage vessels for petroleum liquids are greatest during
 storage and tank filling.  The nature of the emissions (high
 concentrations  for short periods during filling and low concen-
 trations  for longer periods during storage)  and the configuration
 of storage tanks  make direct emission measurement highly
 impractical.  Therefore,  a more  practical  approach  to standards
 of performance  for storage  vessels has  been equipment specifications.
 2.2  SELECTION  OF CATEGORIES OF  STATIONARY SOURCES
     Section  111  directs  the Administrator to publish  and from time
 to time revise a  list of categories of sources for which standards
 of performance are to be developed.  A category is to  be selected
 11. .  .if [the Administrator] determines  it may contribute significantly
to air pollution which causes or contributes to the endangerment
of public  health or welfare."
                                2.4

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     Considerable attention has been given to the development of
a methodology for assigning priorities to various source categories.
In brief, the approach that has evolved is as follows.  Specific
areas of emphasis are identified by considering the broad
strategy of the Agency for implementing the Clean Air Act.
Often, these "areas" are actually pollutants which are primarily
emitted by stationary sources.  Source categories which emit
these pollutants are then evaluated and ranked taking into
account such factors as (1)' the level of emission control (if any)
already required by State regulations; (2) estimated levels of
control that might result from standards of performance for the
source category; (3) projections of growth and replacement of existing
facilities for the source category; and (4) the estimated incremental
amount of air pollution that could be prevented, in a preselected
future year, by standards of performance for the source category.
An estimate is then made of the time  required to develop
a standard.  In some cases, it may not be feasible to develop
a standard immediately for a source category with a high priority.
This circumstance might occur because a program of research and
development is needed to develop control techniques or because
techniques for sampling and measuring emissions may require
refinement.
     Selection of a source category for standards development leads
to  another major decision, determination of  the  types of  sources
or  facilities  to which standards will apply.  A  source category
                                 2.5

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 often  has  several  facilities  that cause air pollution.  Emissions
 from some  of these facilities may be insignificant or very expensive
 to  control.   An investigation of economics may show that, within
 the costs  that an  owner could reasonably afford, air pollution
 control is better  served by applying standards to the most severe
 pollution  problems.  For this reason (or perhaps because there
 may be no  adequately demonstrated system for controlling emissions
 from certain  facilities), standards often do not apply to all
 sources within a category.  For similar reasons, the standards
 may not apply to all air pollutants emitted by such sources.
 Consequently, although a source category may be selected to be
 covered by standards of performance, not all pollutants or
 facilities within  that source category may be covered by the
 standards.
 2.3  PROCEDURE FOR DEVELOPMENT OF STANDARDS OF PERFORMANCE
     Congress mandated that sources regulated under section 111
 of  the Clean  Air Act utilize the best system of air pollution
 control (consider!no costs) that has been adequately demonstrated
 at  the time of their design and construction.   In so doing, Congress
 sought to:
     1.  Maintain existing air quality
     2.  Prevent new air pollution  problems, and
     3.  Ensure uniform national  standards  for new facilities.
     Standards of performance, therefore, must (1)  realistically
reflect best demonstrated  control  practice;  (2)  adequately  consider
                                2.P

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the cost of such control; (3)  be applicable to existing sources
that are modified as well as new installations; and (4) meet" these
conditions for all variations  of operating conditions being
considered anywhere in the country.
     The objective of a program for developing standards of
performance is,to identify the best system of emission reduction
which "has been adequately demonstrated (considering costs}."
The legislative history of section 111 and the court decisions
referred to earlier make clear that the Administrator's judgment
of what is adequately demonstrated is not limited to systems that
are in actual routine use.  Consequently, the investigation may
include a technical assessment of control systems which have
been adequately demonstrated but for which there is limited
operational experience.  In most cases, determination of the
"degree of emission limitation achievable" is based
on results of tests of emissions from existing sources.  This
has required worldwide investigation and measurement of emissions
from control systems.  Other countries with heavily populated,
industrialized  areas have sometimes developed more effective
systems of control  than  those used in the United States.
     Since the  best demonstrated systems of emission reduction
may not be, in widespread use, the data base unon which  standards
are develoned may be somewhat limited.  Test  data on existing
well-controlled sources  is  an obvious starting point in developing
emission  limits for new  sources.  However, since the control of
                               2.7

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existing sources generally represents retrofit technology or was
originally designed to meet an existing State or local  reaulation,
new sources may he able to meet more stringent emission standards.
Other information, however, is also considered and judgment is
necessarily involved in develoning standards.
     A process for the development of a standard has  evolved.
In general, it follows the guidelines below.
     1.   Emissions from exi'stina well-controlled sources are
         measured.
     2.   Data on emissions from such sources  are assessed with
         consideration for such factors as:   (a) the  representative-
         ness of the source tested (feedstock, operation, size,
         age, etc.); (b)  the age and maintenance of the  control
         equipment tested (and possible degradation in  the
         efficiency of control  of similar  new equipment  even
         with good maintenance procedures); (c)  the design
         uncertainties  for the  type  of control  equipment being
         considered; and  (d)  the degree of uncertainty that new
         sources  will  be  able to achieve similar level of control.
     3.   During  development  of the standards,  information  from
         oilot and prototype  installations, guarantees by  vendors
         of control  eguinment,  contracted  (but not yet constructed)
         nrojects,  foreign technology,  and published literature are
         considered, esnecially  for  sources where "emerging"
         technology  aopears significant.
                               2.8

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4.  Where possible, standards are develoned which permit
    the use of more than one control  technique or licensed
    process.
5.  Where nossibte, standards are developed to encourage
    (or at least permit) the use of nrocess modifications or
    new processes as a method of control  rather than "add-on"
    systems of air. noilution control.
6.  Where nossible, standards are developed to nermit
    systems caoable of control ling more than one pollutant
    (for examnle, a scrubber can remove both gaseous and
    particulate matter emissions, whereas an electrostatic
    Drecipitator is specific to oarticulate matter).
7.  Where aporonriate, standards for visible emissions are
    developed in conjunction with concentration/mass emission
    standards.  The opacity standard is established at a level
    which will require nroner operation and maintenance of the
    emission control system installed to meet the concentration/
    mass standard on a day-to-day basis, but not require the
    installation of a  control system more efficient or expensive
    than that required  by the concentration/mass standard.
    In some  cases, however,  it is not possible to develon
    concentration/mass  standards, such as with fugitive
    sources  of emissions..  In these cases, only ooacity standards
    mav be  developed to  limit emissions.
                             2.9

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  2.4  CONSIDERATION OF COSTS
       Section 111  of the  Clean  Air Act  requires  that  costs be
  considered  in developing standards  of  performance.   This requires
  an  assessment of  the nossible  economic effects  of implementing
  various levels of control technology in new plants within a given
  industry.  The first step in this analysis requires  the generation
  of estimates  of installed capital costs and annual operating
  costs for various demonstrated control systems, each control
 system alternative having a different overall  control capability.
 The final  step in the analysis is to determine the economic
 impact of the various control  alternatives upon a new plant
 in the industry.   The fundamental Question to  be addressed is
 whether or not a  new plant would be constructed if a  certain
 level  of control  costs will  be  incurred.   Other aspects  that
 are  analyzed are  the effects of control costs  upon product prices
 and  product  supplies, and producer profitability.
     The economic  impact  of  a proposed  standard  upon  an  industry
 is usually addressed  both  in absolute terms and  by comparison
 With the control costs  that  would  be incurred  as a result of
 compliance with typical existing State  control  regulations.   This
 incremental approach  is taken since a new plant would be required
 to comply with State  regulations in the absence of a  Federal
 standard of performance.  This  approach requires a detailed
 analysis of the impact upon the industry resulting from the  cost
differential  that  exists between a standard of  performance  and
the typical  State  standard.
                                2.10

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     The costs for control of air pollutants are not the only
control costs considered.  Total environmental costs for control
of water pollutants as well as air pollutants are analyzed
wherever possible.
     A thorough study of the profitability and price-setting
mechanisms of the industry is essential to the analysis so that
an accurate estimate of potential adverse economic impacts can
be made.  It is also essential to know the capital requirements
placed on plants in the absence of Federal standards of performance
so that the additional capital requirements necessitated by
these  standards can be placed in the proper perspective.  Furthermore,
it is  necessary to recognize any constraints  on  capital availability
within  an industry as this factor also influences the  ability
of new plants  to  generate the capital  required  for  installation
of the additional  control  equipment needed  to meet  the standards
of performance.
      A consideration  of the  impact of these standards  on inflation
 is  of major importance.   Any action  which will  add significantly
 to inflationary pressures is considered major and requires  an inflationary
 impact statement.
 2.5  CONSIDERATION OF ENVIRONMENTAL IMPACTS
      Section 102(2)(c)  of the National Environmental Policy Act  (NEPA)
 of 1969 (PL 91-190)  requires Federal  agencies to prepare detailed
 environmental impact statements on proposals for legislation or other
 major Federal actions significantly affecting the quality of the
 human environment.  The objective of NEPA is to build into the decision-
 making process of Federal agencies a careful consideration of all
 environmental aspects of proposed actions.

-------
      As mentioned earlier, in a number of legal challenges to standards
 of performance for various industries, the Federal Courts of Appeals
 have held that environmental impact statements need not be prepared
 by the Agency for actions under section 111 of the Clean
 Air Act.  Essentially, the Federal  Courts  of Appeals  have determined
 that "...Secti'on 111  of the Clean Air Act, properly construed,  requires
 the functional  equivalent of a NEPA impact statement" in the sense  that the
 criteria "...the best system of emission reduction,"  "...require(s)
 the Administrator to  take into account counter-productive environ-
 mental  effects  of a proposed standard, as  well  as  economic costs to
 the industry..."  On  this basis,  therefore,  the Courts  "...establish(ed)
 a  narrow exemption from NEPA for  EPA  determinations under section 111."1'2
      In addition to these judicial  determinations,  the  Energy Supply
 and Environmental  Coordination Act  (ESECA) of 1974  (PL 93-319)
 specifically exempts  actions  under  the Clean Air Act from
 NEPA requirements.  According to section 7(c)(l),  "No action taken
 under the Clean  Air Act shall be deemed a major Federal action
 significantly affecting the quality of the human environment
 within  the meaning of the National Environmental Policy Act of 1969."
      The Agency has concluded, however, that the preparation of
 environmental impact statements could have  beneficial  effects on
 certain regulatory actions.  Consequently,  while not legally required
 to do so by section 102(2)(c) of NEPA, environmental impact
statements will  be prepared for various regulatory actions, including
                               2,12

-------
standards of performance developed under section  Til  of the
Clean Air Act.   This voluntary preparation of environmental
impact statements, however, in no way legally subjects  the  Agency
to NEPA requirements.
     To implement this policy, a separate section is  included
in this document which is devoted solely to an analysis of  the
potential environmental impacts associated with the alternative-
standards considered for proposal and promulgation.  Both adverse
and  beneficial imnacts in such areas as air and water pollution,
increased solid waste disposal and increased energy consumption
are  identified and  discussed.  Appendix B of this document outlines
those  sections or chapters which  examine  these potential environmental
impacts  in  detail.
2.6   IMPACT ON EXISTING  SOURCES
     •Standards of performance may affect  existing  sources in
either of two ways.  Section  111  of  the Act  defines  a  new'source
 as "any stationary  source,  the construction  or modification  of
which is commenced  after the  standards  are proposed."   Consequently,
 if an existing  source is modified after proposal  of  the standards,
 with a subsequent increase in air pollution, it  may  be subject to
 standards of performance.  Amendments to the general provisions of
 Suboart A of 40 CFR Part 60 clarifying the meaning of modification
 were promulgated on December 16, 1975 (40- FR 58416).
      Second, promulgation of  a standard of performance  requires
 States to establish standards of performance for existing  sources
 in the same industry under section lll(d) of the Act;  unless the
 standard for new sources limits emissions of a pollutant for
 which air quality  criteria have been (or will  be) issued under
 section 108 or one listed as a hazardous pollutant under section 112.
                                  2,13.

-------
 If a State does not act, EPA must establish such standards.  General
 provisions outlining procedures for control of existing sources
 under section lll(d) were promulgated in the Federal Register as
 Subpart B of 40 CFR Part 60 on November 17, 1975 (40 FR 58346). ,
 2.7  REVISION OF STANDARDS OF.PERFORMANCE
      Congress was aware that the level of air pollution control achievable
 by any industry may improve with technological advances.  Accordingly,
 section 111 of the Act provides that the Administrator may revise
 standards of performance from time to time.  Although standards proposed
 and promulgated by EPA under section 111 are designed to require
 installation of the "...best system of emission reduction...(taking
 into account the cost)..." the standards are reviewed periodically.
 Revisions are proposed and promulgated as necessary to assure
 that the standards continue to reflect the best systems of  emission
 control  as they become available.   Such revisions  are not  retroactive
 but apply to stationary sources  constructed or modified after proposal
 of the  revised  standards.
2.8  REFERENCES
1.  Portland Cement Association vs. Ruckelshaus, 486 F. 2nd  375
    (D.C. Cir. 1973).
2.  Essex Chemical Corp. vs. Ruckelshaus, 486 F. 2nd 427 (D.C. Cir.  1973).
                               2.14

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       3.  SULFUR RECOVERY PLANTS IN PETROLEUM REFINERIES
     Sulfur emissions from petroleum refining are a function  of the
sulfur content of the crude oil  being processed, the complexity
of the refinery and the refinery fuel sources.  Various refinery
processes produce process gas or "fuel" gas which can contain
significant amounts of sulfur, mainly as hydrogen sulfide. To
meet the standards of performance promulgated in March 1974
(39 FR 9308} limiting sulfur dioxide emissions from fuel gas
combustion in petroleum refineries, or to satisfy state or local
emission codes, and to reduce corrosion problems, refineries
"sweeten" or remove hydrogen sulfide from the fuel gas before
burning  it in process heaters and boilers.
     Hydrogen sulfide removal from  fuel gas consists of scrubbing
with solutions which absorb H2S.  Regeneration  of the  scrubbing
solutions  evolves  a  side  stream of  concentrated hydrogen  sulfide
with  lesser  amounts  of  carbon dioxide, water vapor and hydrocarbons,
which  is processed in an  appropriate recovery facility such  as a
 Claus  sulfur plant to produce elemental  sulfur.
      Claus sulfur plants  have  long  been  established as effective
 technology for sulfur recovery from process gases  in petroleum
 refineries.   Claus sulfur capacity  in U.S.  refineries totalled
 8000 long tons per day as of April  1973.]   Sulfur dioxide emissions
 from Claus plants based on operation at two-thirds capacity  and
 92 percent recovery are estimated at 338,000 tons in 1973.
                                 3.1

-------
      The rapid rate at which sulfur plants are being installed makes
 them attractive candidates for standard development.  Forecasted
 increases in domestic petroleum refining capacity indicate that
 a significant growth rate in refinery sulfur recovery is forthcoming.
 Over 1000 LT/D or about 13% of existing refinery sulfur plant
 capacity was scheduled for completion during 1974.2
      Refinery sulfur plants are currently located in 25 states.3  Sizes
 range from 4 to 375 long tons/day (LT/D)  with 65 LT/D being an
 average size plant.  Sulfur plants scheduled for start-up  in 1974-75
 reflect the trend toward larger facilities,  averaging 107  LT/D.4
 3.1   PROCESSES  AND EMISSIONS
      As discussed previously,  hydrogen  sulfide  gases  are released  during
 the  regeneration  of amine  or other scrubbing  solutions which  are used
 to desulfurize  refinery  process  or fuel gases.   In.addition,  some  H2S  1s
 removed from process water by  sour water strippers.   Most  refineries
 include facilities  for steam stripping H2S from sour  water streams
 as oart of the waste water treatment system.  Where sulfur recovery
 is practiced, the off-gases  from the stripper are normally routed
 to the  sulfur recovery plant.
The Claus Process
     The Claus process has been used almost exclusively in petroleum
 refineries to recover sulfur.  The basic exothermic reactions for
the Claus process are:
     (1)  H2S + 1/2 02 + H20 + S
     (2)  H2S + 3/2 02 -»- S02 + H20
     (3)  2 H2S  + S02 ^ 3S + 2H20
                               3.2

-------
     A typical two-stage Glaus plant is shown in'Fiqure 3-1.5  Hydrogen
sulfide gas enters the burner with sufficient air to convert all F^S
to sulfur.  As much as 50 to 60 nercent conversion of the hydrogen
sulfide to sulfur takes place in the initial reaction chamber by
Reaction (1).
     Reaction (2) also takes nlace, forming S0?.  After cooling,
condensing and- removing sulfur, the gases are reheated by mixing
with a portion of the cias-es bypassed around the sulfur condenser
and introduced into the first catalytic converter where the Claus
reaction  (Reaction 3) occurs.   From the first catalytic converter
the effluent  gas  is cooled,  sulfur condensed and  removed, and
the gases  reheated again.  The  process  is-repeated  in  the second
catalytic converter.   If  needed,  additional  catalytic  stages may  be
added to  remove  H?S as  sulfur.
      Some carbonyl  sulfide (COS)  and  carbon disulfide  (CS2) are formed
 in the reaction  furnace in the presence of  carbon dioxide  and
 hydrocarbons: .        •
      (4)   C02 + H2S   •*  H20 + COS
      (5)   COS + H2S  j  H20 + CS2
      (6)   CH4 + 2S2  £  CS2 + 2H2S
      Depending on the exact nature of the sour-gas feed stream and
 the operating conditions  in the upstream reaction furnace  and  catalyst
 beds, combined COS and CS2  levels as high as 5000 ppmv may exist
 in the tail  gas.6  Values of 600-1500 ppmv are more common, however.
                                3.3

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occ c/>
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-------
     The emissions of H2S, SOg , and sulfur vapor from Glaus plants
are directly dependent ®m the -efficiency  of sulfur recovery in the
Claus olant.  For example, a TO LT/0 Claus plant operating at 95 percent
sulfur recovery efficiency would eimit 5 LT/B sulfur in the flora of H2S,
SO,,, -sulfur vapor ;, COS arad £$2 formed in the reaction furnace.  Gas
  iL.
stream compositions  throughout a Claus  plant are  qiven ITU  Table 3-1  for
a hypothetical 100 LT/D plant operating at :% percent recovery efficiency.7
     Claus ®lant efficiencies in tuna are tjependent upon the-Jbllowing
      :{T)  dumber of catalytic cowersion stages,
      i(2)  Met feed stream composition.
      (3')  ©Derating temperatures and catalyst maintenance,
      i(4'3  isiaimtalniira?! the proper stoidiioraetric ratio of fi
      (5.)  'Bperatinq caparf-fey fact'or.
      for 'Clau-s roll ante fisd Witt f90 -mol-e percent H2S, the sulfur reooverv
 is approximately 85 parcent for om catalytic stage .and 95 percent for
 two or three stages.  The percentage of sulfur trecwery ails© increases
 with increasing  concentration of the acid gas fed  to ttie  Cilaus
 plant.   For plants having  two -or flw^ee  catalytic stages,,  the
 sulfur recoveries  for warious «acM  «oias  c0iiicentrati©ns  are appro'xii'mately
 90 percent  for a 15 mole ipercent iHgS  feed  stream,  93 penoerat for a
 50 mole  percent H2S stream,  and 95  percent for  90  percent H2S  concani-
 trati on .
       Contaminants in the feed -gas reduce Claus  sulfw recovery efficiency.
 Hydrocarbons in Claus feedstocks require extra aw for combustion-   Tfee
                                   3.5

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added water and inert gas associated with burning hydrocarbons  increases


the size of the sulfur plant equipment and lowers sulfur recovery since


the sulfur gas concentrations are decreased.U  Higher-molecular-weight


hydrocarbons in the feed also reduce Glaus efficiencies because of soot


formation on the catalyst.13  High feedstock concentrations of C02

                               14
adversely affect catalyst Iffe.


     Since the reactions in a Claus Plant are exothermic, sulfur


recovery is enhanced  by  removing heat, hence operation at as low a


temperature as practicable  in the reactors without condensing sulfur


vapor  on the  Claus  catalyst is necessary.  Sulfur recovery is also


dependent  upon  catalyst  performance.   One vendor has reported a  one


to two percent  loss in  recovery  efficiency over  the period of catalyst


life.15  Catalyst  life  generally varies  from  2 to 5 years  depending


on plant operation and  contaminants in the  feedstock discussed



 previously.


      Deviation above or below the 2:1 stoichiometric  ratio of


 H2S and S02 for the Claus reaction results  in a  loss  of Claus


 efficiency.  Figure 3-2 illustrates the variation of  recovery


 efficiency with H2S/S02 concentration ratio in the Claus converters.


       Operation of  a  Claus plant below capacity may impair Claus efficiency


 somewhat.  One vendor has  reported a two or three percent loss in recovery


 when  the  Claus plant was turned down to 20 percent of design capacity.


 Another vendor reports  no  loss  in  recovery efficiency when operating


 at two-thirds  of  capacity.
                                    3.7

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       95
tu
OS
       34
        0.5
1.0
                                                    2.0            3         4

                                                 H2S/S02 MOL RATIO

                                                    (TAIL GAS)


                  Figure 3-2.   Theoretical Glaus sulfur recovery efficiency vs. Mole Ratio.
                                                   5     6    7   8  9   10
                                                       3.8

-------
     Although the Impact of process variables as  discussed above
represents ih most cases a loss of only one to three nercent efficiency,
at the relatively high efficiencies typical of Claus operations (95%),
a one to three percent efficiency loss represents a 20 to 60 percent
increase in uncontrolled sulfur emissions.
The Stretford Process
                          18
     The Stretford process   shown in Figure 3-3 is a one-step
process to convert H?S  directly to elemental sulfur.  At present
the Stretford process is  the only  commercial sulfur recovery
process which has supplanted conventional  aroine treating  and
CTaus sulfur recovery in  a  refinery.  ATthough the  Stretford
is installed- in  only  one  U.S.  refinery,, it has found  application
in several  refineries as  part  of  the  tail  gas  cleanup process  for
Claus plants.
      Refinery fuel  gas  or process gas is  passed  into a  countercurrent
column  where the hydrogen suTfide in  the  gas is  absorbed in the
Stretford solution.
      A summary of the Stretford reactions is as  follows:
      (a)   Absorption of H2S
           H2S + Na2C03  -»•  NaHS + NaHC03
      (b)   Precipitation of sulfur
           2NaV03 + NaHS + NaHC03  ->  S* + Na2V205 + Na2C03 + H20
      (c)  Regeneration of sodium vanadate
           Na2V205 + ADA*  (oxidized)  -»- 2NaV03 + ADA (reduced)
                                 3.9

-------
                                                     in
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3.10

-------
     (d)   Regeneration  of ADA
          ADA (reduced) + 1/2 02 (air)   -*•  ADA (oxidized)
     (e)   Overall  reaction
          H2S + 1/2 02  -»-  S4- + H20
After recirculation through the H2S absorber,-the Stretford solution
is retained in a holding tank to allow completion of sulfur precipi-
tation.  The Stretford solution is then regenerated by air blowing
and reduced vanadium is restored by oxygen transfer from the ADA*
     Sulfur  formed in  the  solution  is floated to  the top of the oxidizer
 by air where the  froths  overflow  to a settling  tank.  Sulfur settles as
 a sludge  in  the settling  tank  and  is separated  and  recovered.
      Some adverse side reactions  occur  due to increased  liguor
 temperature and trace oxidizing gases  contained in the  fuel  gas
  (notably oxyqen, Sn2 and HCN) and result in the buildup  of sodium
  thiosulfate and related comoounds in the circulating liquor which
  must  be purged from the system.  The rate of thiosulfate formation
  depends  on  the partial pressure of the contaminant gas in the inlet
  gas stream  and the oH and temperature  of  the liguor.  Formation
  of thiosulfate is quite  low,:he!ow- about  100°F.
       Purge  stream rates  range from 1.5 to 15 gallons oer  100  moles
  of feed gas to  the Stretford absorber.

  *Anthraguinone Disulfomc Acid
                                   3.11
19

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       The major advantage of the Stretford process is the overall
  reduction in emissions, both in the desulfurized fuel gas or
  process gas and the emissions from the sulfur recovery plant.   Outlet
  sulfur loadings have been designed for less  than in ppmv H2S in the
  fuel  gas or process gas.20  COS and CS2 are  not recovered by the
  Stretford process;  however,  COS and CS2 in fuel  gases or process
  gases  are much  lower than the levels  emitted from Claus  plants.
  Essentially no  sulfur is  emitted from the oxidizer tank;  hence,
  sulfur emissions from the Stretford sulfur recovery portion  are nil.
  Emissions  are relatively  unaffected by process  variables,  although
  water  wastes and chemical  consumption  are highly  dependent upon
  operation.
      The primary disadvantage' of  the Stretford process is the lack
  of operating experience in the  U.S.  In the one U.S.  refinery anplication,
  the Stretford has yet to  demonstrate good operability, experiencing
 numerous design and operating problems.21  With time, however, the
 design and operational problems will undoubtedly be resolved so that
 the Stretford process will be competitive with the Claus process
 in refinery applications.
 Other Alternative Processes
     Other  sulfur removal  and  recovery  processes which could conceivably
replace conventional amine treating  and Claus  sulfur recovery include
the Giammarco-Vetrocoke H2S Process and the Sulfox Process.22'23  The
Giammarco-Vetrocoke H2S removal process is similar to the Stretford
process, except that arsenate replaces vanadate in the scrubbing
solution.  The Sulfox process uses an aqueous  ammonia solution to
                                    3.12

-------
absorb H2S.   Elemental  sulfur is  produced by oxidizing  the  solution
over a catalyst.
     The Giammarco-Vetrocoke process  has been applied to natural  gas
processing but has not yet been used  in refinery sulfur recovery.
The Sulfox process is designed specifically for refinery sulfur
recovery but was only recently announced.  Since neither process
has any operating experience in refinery applications,  a detailed
discussion of operation and emissions is not included.
3.2  EXISTING EMISSION CONTROL REGULATIONS FOR SULFUR RECOVERY PLANTS
     Table 3-2 summarizes current state emission control regulations
for both existing and new sulfur recovery plants.  The  most stringent
regulations for sulfur plant emissions are found in Florida, Los  Angeles
County, and Philadelphia.   Florida regulations specify maximum
allowable sulfur emissions  as 0.004 Ib S02 per Ib sulfur input, or
a  99.8 percent  sulfur recovery (equivalent to ^500 ppmv total sulfur
                       ?4
on an undiluted basis).     Los Angeles  County restricts emissions
to 500 ppmv  sulfur  calculated as S02 equivalent,25 while Philadelphia
                                                 OC
restricts refinery  sulfur plants to 500  ppmv S02-
      State codes  applicable to sulfur  recovery plants  are  generally
expressed in pounds of sulfur  input.   A majority of  states which
have  sulfur  emission regulations for sulfur  recovery plants  have
 the same  regulation, 0.01  Ibs  S/lb S input,  or  99 percent  sulfur
 recovery.
      The  format of standards in  Table  3-2 shows  some states  regulating
 S02 only, while several  have standards for "sulfur emissions."  The
                                 3.13

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 State
 Alabama
 Arkansas
 Colorado
 Connecticut
 Del aware
 Florida
 Louisiana
 New Hampshire
 New Jersey
 Ohio
 Oklahoma
 Pennsylvania
Texas
Utah
Vi rgi ni a
West Virginia
                   Tabl£ 3-2
State Regulations for Sulfur Recovery Plants

                        Regulation^
    Existing Plants             New Plants
    0.16 Ib S/lb S input        0.08 Ib S/lb S input
    	 ground level concentrations only 	
    	 ground level concentrations only 	
    0.01  Ib S/lb S input
    2000  ppmv S02
    0.004 Ib S02/Jb S input
    0.01  Ibs S/lb S input
    0.01  Ibs S/lb S input
    15,000 ppmv S02
    0.01  Ib S/lb S  input
           (a)
           (b)
   0.05  Ib S/lb S input
   0.06  Ib S/lb S input
           --0.5
0.01 Ib S/lb S input
2000 ppmv S02
0.004 Ib S0£/lb S input
0.01 Ibs S/lb S input
0.01 Ibs S/,lb S input
15,000 ppmv S02
0.01 Ib S/lb S input
0.01 Ib S/lb S input
        (a)
2200 ppmv S02d(Ref.  28)
        (c)
0.05 Ib S/lb S  input
0.06 Ib S/lb S  input
(a)  According to A=0.32 E~u*° where E = plant rating in LT/D and A =
     allowable emissions in Ib S02/lb S input.
(bj  214 Ibs S0?/hr/1000 scfm effluent flow rate.
(c)  80% control for new sources with uncontrolled sulfur emissions
     ;!250 ton/year.
(d)  at incinerator outlet, calculated for 50% excess air.
                                    3.14

-------
intent of sulfur emission codes  is  not  specified, but assumed to

be S02 regulation only,  since  emissions of  H2S  or CS2 at these

levels would incur severe odor problems.

3.3  REFERENCES

1   Genco, Joseph M.  and Tarn,  Sanuel  S., "Characterization  of Sulfur
    from Refinery Fuel  Gas," EPA Contract 68-02-0611, Task  4, June 28,
    1974, p. 28.

2.  World Wide HPI Construction  Boxscore, Hydrocarbon Processing,
    Section 2, February 1974,  pp. 3-10.

3.  Reference 1.

4.  Reference 2.

5.  Reference 1, page C-l.

6.  Beavon, David K., and Vaell, Raoul  P.,  "The Beavon  Sulfur Removal
    Process for Purifying Claus  Plant Tail  Gas, presented  at the  37th
    Midyear Meeting,  APl'Division of Refining,  May  8-11, 1972,  p.  272.

7,  Reference 1, p. 30.

8.  Beers, W.D., "Characterization of Claus Plant Emissions,"
    EPA Contract 68-02-0242, Task No. 2, April  1973, p. 9.

9.  Letter, O.C. Roddy, Vice President, Ralph M. Parsons Co.
    to W.D. Beers, Processes Research  Inc., March 23,  1972.

10. Letter, D.F, Cole, Contract Engineer, J.F.  Pritchard & Co.
    to W.D. Beers, Processes Research  Inc., March 23,  1972.

11. Reference 8, p. 9.

12. Grekel, H. et al., "Why Recover Sulfur from H2S?"   Oil  arid  Gas
    Journal, Oct. 28, 1968, p. 95.

 13. Reference  12.

 14. Reference  10.

 15. Reference  9.

 16. Reference  9.

 17. Reference  10.

 18. Reference  1,  op. 32-35.
                                  3.15

-------
 19.  Reference 1, p. 36.   •

 20.  Brochure, "Sulfur Recovery Qualifications and Experience," J.F.
     Pritchard and Company, Kansas City, Mo., Sept. 1973, p. A-4.

 21.  Letter, L.W. Larsen, Sun Oil Company to James F. Durham, ESED,
     OAQPS, EPA, dated January 2, 1975.

 22.  Reference 1, pp. 38-40.

 23.  Conser, R.C., "Here's a New Way to Clean Process Gases,"
     01:1 and Gas Journal, April 1, 1974, pp. 67-70.

 24.  Duncan, L.J., "Analysis of Final State Implementation Plans -
     Rules and Regulations," EPA Contract 68-02-0248, July 1972,
     (APTD-1334) pp. 55-57.

25.  "Rules and Regulations," County of Los Angeles Air Pollution
     Control District, Rule 53.2.

26. Section II (B), Air Management Regulation III of the Air
    Pollution Control  Board, City of Philadelphia, adopted April 10,


27. Reference 24, p. 12.

28. Private communication, Frank J.  Spuhler, Texas Air Control  Board
    to Charles B.  Sedman", Industrial Studies Branch,  ESED, OAP,
    January 17,  1974.
                               3.16

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                 4.  EMISSION CONTROL TECHNOLOGY
4.1  ALTERNATIVE EMISSION CONTROL TECHNIQUES
     Removal of sulfur compounds from Claus plant tail gas is possible
by three general schemes:
     (1)  Extension of the Claus reaction to increase overall
          sulfur recovery;
     (2)  Conversion of sulfur gases to sulfur dioxide (S02)
          followed by S02 removal technology;
     (3)  Conversion of sulfur gases to hydrogen sulfide  (H2$)
          followed by H£S removal technology.
     Option (1) is conceptually simple and  requires only  adjustments
in the  operating temperature of the three-stage conventional  Claus.
     Ootion (2) is  attractive because the S02 removed can be recycled
to the Claus plant.  An incinerator which is standard equipment for
sulfur plants  oxidizes  all gaseous sulfur comoounds to S02 prior to
scrubbing.
     Option (3) is  attractive because H2S removal  technology is advanced
and H2S can be recycled to the Claus plant or directly oxidized to
sulfur.  Conversion of all sulfur species to H2S requires heat, a
reducing gas,  and a reducing catalyst.
     Figure 4-1 shows the various commercially available control schemes
and how each utilizes ootions (T), (2), and (3) to remove sulfur from
Claus tail  gas.  Although the literature cites many tail  gas control
systems, those described below were chosen as renresenting available
control technology for Claus sulfur plants and are presently in
commercial  operation.

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Extension of the Claus Reaction
     The conventional  Claus plant, having two or three stages, was
discussed in Chapter 3.  Such a unit has a recovery
efficiency of about 95%.  To gain further improvement in sulfur
recovery efficiency via the Claus reaction, the temperature
can be lowered to shift the equilibrium of the Claus reaction
toward formation of additional sulfur.  Two processes have been
developed for reducing emissions through extension of the Claus
reaction by operation at low temperatures.  These are the IFP-1 and
Sulfreen processes.
     IFP-1 PROCESS1'2
     The basic reaction involved in the IFP-1 process (Figure 4-2)
is the same one which takes place in the reactors of a Claus unit:
                Catalyst
     2H2S + S02    *     3S* + 2H20
Tail gas which exits  a  Claus unit at 265-285°F can be fed directly
into the  IFP  reactor  without cooling the gas.  The reactor is a
packed  column with  a  specially designed  "boot" for collecting sulfur.
Metal salts  catalyze  the  reaction which  takes place  in  a hiqh boiling
polyglycol  (PEG)  solvent  above the melting point  of  sulfur-generally
 in the  ranae of 250-260°F.  The  metal  salts  form  a  complex with H2S
 and S02 in the  feed gas,  which in turn reacts with  additional  H2S  and  S02
 to form elemental sulfur and regenerate the  catalyst complex.   Sulfur
 coalesces and settles into the boot of the reactor, from which it
 is drawn as a molten product.
                                     4.3

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     The gas leaving the reactor contains about 850 ppm H2S and 420 ppm;
S0?, assuming a 90 percent conversion.   Conversion efficiency is
maximized at the 2:1 stoichiometric H2S/S02 ratio required by the
Claus reaction.  Above or below this ratio the conversion efficiency
diminishes; hence, process controls must effectively keep the
H2S/S02 ratio in the !FP reactor feed as near 2:1 as possible.  Also,
below 2:1 H2S/S02 ratio in the gas stream, the solvent tends to
evolve absorbed H2S, which also increases ultimate sulfur emissions.
     Besides H2S and S02, about 300 ppm sulfur vapor is evolved with
the exit gas.  This is roughly the equilibrium concentration of sulfur
in the vapor phase  at 260°F.  COS and CS2 formed in the Claus plant
are not affected by the IFP-1; hence, they exit at aporoximately
the same concentrations as in the feed gas.  The reactor exhaust
containing  1500-2500 pom  sulfur and some entrained solvent  is
incinerated before  discharge to the atmosphere.
     SULFREEN  PROCESS3'4
     The Sulfreen process  (Figure 4-3) reduces  the sulfur  content
in  Claus olant tail gas by further  promoting  the  Claus  reaction
on  a catalytic surface  in a  gas/solid batch reactor.   Claus  tail
gas  is  first scrubbed with liquid  to wash  out entrained sulfur
liquid  and sulfur vapor.   The  tail  gas  is  then introduced  to a
 battery of reactors where the  Claus reactions are carried  out at lower
 temperatures (260-300°F)  than  those utilized  in the  sulfur plant.
 Lower  temoeratures  oush the  Claus  reaction toward comoletion
 due to favorable equilibrium conditions.  The catalyst is  usually
 activated carbon, though  alumina is also used.
                                  4.5

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     A regeneration gas, essentially nitrogen, periodically desorbs
the sulfur-laden catalyst beds.   Nitrogen is heated and cycles
through the catalyst bed at approximately 570°F until  all water and
C02 are driven off.
     For the desorption of sulfur, the temperature is  raised to 750°F
where sulfur vaporizes, is swept away with the nitrogen, and precipitates
in a condenser.  The carrier gas is further scrubbed in a sulfur wash
before returning to the regeneration cycle.
     The process reduces entrained sulfur, since the catalyst acts
as an absorbent for liquid sulfur.  However,  tail .gas passing through
the catalyst bed retains several hundred ppm  sulfur vapor in equilibrium
with liquid sulfur.  H2S and S02 are reduced  by 80-85 percent to
levels of  about 1800 ppmv H2S and 900 ppra  S02.  As with  the IFP-1  process,
the levels of  ^  and  S02 are highly dependent upon maintaining the
2:1 ratio  of H2S/S02 in the Glaus tail  gas.   COS and CS2 are  not  affected
by the Sulfreen process.
      A Sulfreen unit may consist of as  little as three  reactors,  two  in
absorption and one in  desorption service.   The gases from the  reactors
 in desorption  service  are  incinerated  before  discharge  to the  atmosphere.
 Conversion to S02 Followed by S02 Recovery
      Two processes have been  developed to reduce  emissions  from
 Claus sulfur plants through conversion of the sulfur  compounds
 present in the sulfur plant tail gas to S02,  followed  by recovery
 of the S02.  These are the Wellman-Lord and IFP-2 processes.   Incineration
 of the sulfur plant tail gas  effectively converts  all  the sulfur
                                 4.7

-------
  compounds present to Sf)2 and this is recovered in a conventional
  S02 scrubbing system.  In both processes  the  S02  recovered is
  recycled to the sulfur olant for eventual  conversion  to  elemental
  sulfur  by the Glaus  reaction.
      WELLMAN-LORD PROCESS5'6
      The Well man-Lord process (Figure 4-4)  uses a  wet regenerative
 system to reduce the  stack gas sulfur concentration to less than 250  ppmv.
 Sulfur constituents in Claus nlant tail  qases  are  oxid'ized  to S02 in
 the standard sulfur plant incinerator,  then  cooled and quenched to
 reduce the gas temperature and remove excess water.  The  S02 rich
 gas is then contacted countercurrently with  a  sodium sulfite (Na2S03)
 and sodium bisulfite  (NaHS03)  solution which absorbs S02  to form
 additional  bisulfite.   The  principal  reaction  between  S02 and the
 absorbent solution  is:
     S02  + Na2S03 + H20  t   2NaHS03
     The  absorber off-gas is reheated and vented to the atmosphere
 at  less than 250 pomv S02 and negligible amounts of other sulfur comoounds.
Any S03 produced by the incineration is preferentially absorbed.
     S02-rich solution is boiled in an evaoorator-crystallizer,  wherein
the bisulfite solution decomposes to S02 and H20 vaoor and sodium
sulfite is precipitated according to the reaction:
            heat
     2NaHSOs  *  Na2S03* H20 + S02+
                                A. 8

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      Strtfite crystals are separated and redissolved for reuse as lean
 solution to the absorber.
      The wet S02 gas flows to a partial condenser where most of the
 water is condensed and reused to dissolve the sulfite crystals.
 The enriched S02 stream is then recycled back to the Claus plant
 for conversion to elemental  sulfur.
      IFP-2 PROCESS7'8
      With the IFP-2 process  (Figure  4-5), Claus  plant tail gas  is
 incinerated to convert all sulfur species to S02.   The incinerated
 gas is  cooled and then fed to an ammonia scrubber,  where  S02 is
 absorbed and converted to ammonium sulfite and ammonium bisulfite
 by  the  following reactions:
      2NH4OH + S02   $  H20 +  (NH4)2S03

          NH4HH  + S02  $   NH4HS03
 Sulfates  and thiosulfates  are  also formed  in  the ammonia scrubber by
 the  foil owing side  reactions:
      2NH4OH  + S02 + 1/202 -»•  H20 + (NH4)2S04
          2NH4OH  + S03  -*-   (NH4)2S04 + H20
       2NH4OH +  S02 + S  •*  H20  +  (NH4)2S20,
                                           3
 Gas  leaving  the  absorber is reheated and vented to the atmosphere
 at less than 250 ppm S02 concentration.
     The S02 rich solution is fed to an S02 regenerator where the
sulfite and  bisulfite are thermally decomposed to S02, NH3, and H 0.
A saturated solution containing ammonium sulfate  and thiosulfate
is drawn from the bottom of the S02 regenerator and fed to a sulfate
reducer.
                               4.10

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       In  the  sulfate  reducer,  the  sulfates  and  thiosulfates  formed  in
  the  side reactions are  thermally  decomposed oer  the  following  reactions
        (NH4)2S04  -»-   NH4HS04 + NH3+
        (NH4)2S203 -j-   2NH3f + S02+  + S + H2(H
       2fJH4HS04 + S  -*•   3S02f  + 2NH3f + 2H2(H
      Gases from the S02 regenerator and sulfate  reducer are combined
 with an H2S rich stream (normally Claus plant feed gas) and fed to
 a catalytic reactor where they are contacted with a polyethylene
 glycol solvent.  The'H2S and S02 react in the solution to form
 elemental sulfur.   Sulfur is withdrawn in the molten state and
 sent to the Claus  plant sulfur pit.
      Gases from the  reactor are  cooled to condense out water and NHs
 as  NH4OH.  The NH4OH  solution  is  returned to  the  ammonia scrubber.
 Any H2S or S02 which  leaves  the  reactor -and is  not absorbed  by  the
 NH4OH solution is  recycled  to  the  incinerator and from there to
 the ammonia scrubber.
 Conversion to  H2S  Followed  by  H2S  Recovery
      Three processes  have been developed  to reduce emissions from
 Claus sulfur plants through conversion of the sulfur  compounds
 present in the sulfur plant tail gas to H2S, followed by H2S recovery.
 These are  the Beavon, Cleanair and SCOT processes.  In each of
 these processes, the sulfur plant tail gas is  mixed with a reducing
 gas such as hydrogen and passed over a reducing catalyst.  Most
 of the sulfur compounds present are converted  to H2S.  Both the
Beavon and Clean air processes  then use the Stretford orocess
                               4.12

-------
(discussed in Chapter 3} to absorb the H2S and convert it directly to
elemental sulfur.  In the SCOT process the H2S is absorbed in a
conventional H2S scrubbing system and then recycled to the Glaus
sulfur plant for eventual conversion to elemental sulfur.
                   9,10
     BEAVON PROCESS'
     The Beavon process (Figure 4-6) begins by converting sulfur
present in the tail gas (S02, COS, CS2, and elemental sulfur) back
to HoS.  This is done by hydrogenati on and hydrolysis under moderate
conditions of temperature and pressure similar to those in the
Claus plant.  Before the tail gas enters  the packed bed hydrogenati on
reactor, fuel gas is combusted substoichiometrically in an inline
burner to produce the reducing conditions necessary to convert
sulfur gases to  H2S.  The combustion  products are mixed with  the
tail  gas to  provide  a reducing atmosphere.   Extra hydrogen may  be
made  in  the  fuel-rich combustion  chamber  as  required to supplement
hydrogen already in  the tail  gas  by  the reaction:
      CO  +  H20  *  H2 +  C02
      A cobalt-molybdenum catalyst promotes  the  hydrogenation  and
hydrolysis  reactions which  reduce S02 to  very low  values  and
 (COS  + CS2)  to less  than 100 ppmv.   Elemental  sulfur is  completely
 reduced to H2S.   The reactions  are:
8H
                   8H2S
      S02 + 3H2  •>  H2S + 2H20
      COS + H20  +  C02 + H2S
      CS2 + H20  *  H2S + COS
                                  4.13

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CS2 + 2H2S
                    CH4 + 4S
     4H2 + CS2.  ^  2H2S + CH4
COS + 4H2
                   H2Q + H2S + CH
     After hydrogenation, the tail  gas is cooled and water is removed.
The H2S-rich tail gas is fed to the Stratford circuit for removal of
H2S to less than 10 opm.  final incineration before discharge to the
atmosphere is optional .
     CLEANAIR PROCESS11'12
     The CLeanair process includes the Stretford process and two
confidential processes.   Figure 4-7 is a process diagram.  An optional
part of the Cleanair package includes a modification of the Claus
plant first stage to' include a reducing and hydrolysis catalyst.
This causes the conversion of COS and CS2 to H2S according to the
following reaction:
     COS + H20  £  H2S + C02
     CS2 + 2H20  £  2H2S + C02
Carbon dioxide also is decomposed to CO to prevent the recurrence
of COS.
     Claus tail gas, with essentially all gaseous sulfur as sulfur
vapor, H2S and S02, is quenched to reduce temperature and remove
water and entrained sulfur.  The cooled gas is fed into a reactor
where H2S and S02 (in a 2:1 ratio)  react, lowering S02 to less than
250 ppmv.  Both water and sulfur (products of the Claus reaction)
are removed.
     Next, the tail gas  is sent to a Stretford unit where remaining
H2S is removed and oxidized to elemental sulfur.  Residual S02,
                             4.15

-------
 
-------
although absorbed by the Stretford solution,, decomposes the solution
and therefore increases chemical consumption and liquid purge rate.
Residual COS and CS-2 will pass through unaffected.  Purified gas
may then be sent to an incinerator to- oxidize residual sulfur to
S02 (guaranteed less than 250 ppmv) and CO to- C02 before discharge
to the atmosphere.
                                                TO: "14
     SHELL CLAUS OFF-GAS TREATING (SCOT) PROCESS  '
     Similar to the Beavon process, the SCOT process (Figure 4-8)
first converts all sulfur compounds, and free sulfur in the tail
gas to HoS.  Hydrogen, or hydrogen and carbon monoxide mixtures
are used as the reducing gases while a cobal t/mO'lybdenura-on -alumina
catalyst- promotes the  reactions:
S0
      8
                   H2S + 2H20
             8H2S
     COS and  CS2  are  reduced  in  reactions  identical with those in
the  Beavon  catalytic  reactor. Where  carbon  monoxide  is  also  present
as a reducing agent,  the following additional  reactions  may occur:
     S02 +  SCO -»• COS + 2C02
     S8 + SCO -»•   8COS
     COS +  H20 t C02 •*• H2S                                 .       .
     CO + H20 *   C02 +  H2
     CO + H2S S-   COS 4-  H2
     From the SCOT reactor,  the  tail  gas containing less than ion ppm
 (COS + CS2) and 10 ppm S02 is cooled and excess water removed.  The
 H2S  (at 20,000-40,000 oprnv)  and  some C02 are then removed by treating
                                4.17

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16
with di-isoprooanolamine solution in an .absorption column.   The H2S-
rich solution is regenerated by stripping H2S in a conventional
steam stripping column.  Regenerator off-gas, mainly H2S and some-
C02 is recycled as feed to the first stage of the Glaus unit.
The absorber off-gas, containing less than 300 ppmv H2S is
incinerated in a standard Claus incinerator.
4.2  COMMERCIAL STATUS OF TAIL GAS TECHNOLOGY
     The Wellman-Lord process has demonstrated the longest trouble-free
                                           15
operation—over two years on a Claus plant,    Wellman-Lord units on
Claus plants are in operation at three  refineries with five
additional units scheduled for start-up  in 1974 and early 1975.
The IFP-2 process  is being installed in  three Japanese refineries.'7
     Of  units  designed specifically for Claus tail gas treating, the
Beavon,  SCOT,  and  IFP-1  units have  been successfully operated  in refineries.
Four Beavon  units  have  been  running continuously  at two  refineries since
July  1973.18  Three  other Beavon  units  started  up  during 1973, with three
more  scheduled for completion in  1974.19  Two small SCOT units were
 installed in June  1973,  and  are  currently in operation  followina some
modifications.20  At least seven  more  SCOT'S were scheduled for start-up
 in 1974.21
      The IFP-1 and Sulfreen  processes  have been applied to  natural
                                                      77
 gas plants in France and Canada  for about five  years.     Also, the IFP-1
 is currently in operation on six refinery sulfur plants in  Japan
                                                 23
 and two in the U.S.  with several  more  announced.
      The Cleanair process was installed at three U.S.  refineries
                                                                          24
 in 1973; but all are still  awaiting start-up after process  modifications."
      A detailed list of present and planned Claus tail gas  control
 systems is presented in Table 4-1.
                                4.1-9

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Table 4-1.    LISTING OF ANNOUNCED TAIL GAS TREATING
    UNITS FCR CLAtfS SULFUR PLANTS'AS OF 3/1/74
Type Unit
Beavon
Beavon
Beavon
Beavon
Beavorr
Beavon
Beavon
Beavon
Cleanafr
Cleanalr
Cleanair
Cleanair
WeTlman-Lord
Well man-Lord
Company/Locatton
Union Oil Company/
Wilmington, California
Mobil Oil Company/
Torrance, California
Atlantic-Rich field/
Philadelphia, Pennsylvania
Getty Oil Company/
Delaware City^ Delaware
Kobe Steel Co ./Japan
Texaco, Inc./
Long Beach, California
Unknown/
Carribbean
Union Oil Co./
Rodeo, California
Atlantic Richfield Corp. (ARCO)/
Wilmington, California
Gulf Oil Co./
Philadelphia, Pennsylvania
Santa Fe Springs Refinery
(Gulf Oil Co.)/Santa Fe
Springs, California
Techmashimport, U.S.S.R.
Standard Oil of California/
Richmond, California
Kashima Oil Co./
l^achnmar .lanaw
Onstream
Date-
July 1973
July 19.73:
September 1973
November 1973
October T973
March 1974
April 1974
November 1974
--
—
—
--
January 1975
February 1974
No. of Number/Capacity
Units Claus Plant* LT/
2' 2/1 QQ.
2 3/100
T 1/140
1 1/300
1 1/220
•j
2
3
1 3/90
1 1/46
1 1/27
2
1 1/290
1 1/180
                         4.20

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Table 4-1. (eorjt.)  LISTING OF MN'OUICED TAIL GAS TREATING
        PUTS FOR CUIUS SULFUR PLANTS AS «F 3/1/74
Type Unit
MeTnimami-Lord
WeTI mam-lord
Meirilman-1'O.rd
Mel taam-L'O rd
Bellman-Lord
WeTlman-Lord
SCOT
Company /Loca ti on
To a ,Ne nryo/.-AH ta 9 .
Japan
T>oa learyo/Mat-syS'hima:,
Toa ilfenryo !ief«e^/fe,wasa>kii ,
Japan
Standard Oil ®f 'Calif orrona/O
Segundo, California
Standard Oil 
-------
Table 4-1. (Cont.)  LISTING OF ANNOUNCED TAIL GAS TREATING
        UNITS FOR CLAUS SULFUR PLANTS AS OF 3/1/74
Type Unit Company/Location
IFF
IFF
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
IFP
Nippon Petroleum Refining
Company (Caltex)/Negishi ,
Japan
Idemitsu Oil/Himeji, Japan
Showa Oil (Shell )/Kawasaki ,
Japan
Kyokuto Petroleum Industries
(Mobil )/Chiba, Japan
Chevron Standard Ltd.
(Chevron Research,)/Nevis,
Alta., Canada
Mitsubishi Oil Company (Getty)/
Mizushima, Japan
Mitsubishi Oil Company (Getty)/
Mizushima, Japan
Phillips Petroleum/ Borger
Texas
Ministry of Gas/Orembourg I,
U.S.S.R.
Ministry of Gas/Orembourg II,
U.S.S.R.
Ministry of Gas/Orembourg III,
U.S.S.R.
Stauffer Chemical Company/
Delaware City, Del., U.S.A.
Commonwealth Oil Refining/
Ponce, Puerto Rico, U.S.A.
Koa Oil No. 1/Marifu, Japan
Phillips/Sweeny, Texas
Koa Oil No. 2/Marifu, Japan
Unannounced/
Onstream
Date
1971
1972
1972
1972
1972
1972
1972
1973
1974
1974
1974
1973
1973
1973
1973
1974
1975
No. of Number/ Capacity o
Units Claus Plant, LT/D
1
1
T
1
1
1
1
1
1
1
1
Confidential
1
-
1
-
-
1/300
1/250
1/80
1/200
1/260
1/180
1/350
1/45
1/800
1/800
1/800
Confidential
1/60
--
1/45
--
1/400
                                . 22

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4.3  PERFORMANCE OF EMISSION CONTROL SYSTEMS
     The Well man-Lord, IFP-2, Beavon, SCOT and Cleanair processes
all guarantee sulfur emissions less than 200-300 ppmv, for an overall
sulfur recovery including the Glaus sulfur plant of better than
99.9 percent.  The Sulfreen and IFP-1 are capable of reducing sulfur
emissions- to 1500-3000 ppm, for an overall 99.0 percent sulfur
recovery including the Claus sulfur plant.
     Table 4-2 summarizes the expected concentration and mass
emissions as discussed above both  for emission control systems on
a  100-long-ton-per-day Claus sulfur  plant.  Uncontrolled emissions
are  also included  for comparison.
Emission Source  Test Results
      Four processes—the  IFP-1, Wellman-Lord, SCOT and Beavon—were
tested to determine  emissions  of  S02, H2S and reduced sulfur compounds
 (H2S,  COS and  CS2).   The  data  gathered  by these tests are presented
in Figures  4-9 through  4-12.   The data  represented by black  circles
is data gathered by  the Agency, while the data represented by white
circles is  data gathered  by refinery personnel  or the LA APCD.
      Figure 4-9 summarizes  the results  obtained from an emission
 test on the IFP-1  process.   This  process was  not operating on a
 petroleum refinery sulfur recovery plant, but was operating  on a  large
 Claus sulfur plant installed in a carbon disulfide plant. The data,
 however, is applicable to refinery sulfur plants and the emission
 levels achieved representative of what  would be achieved by  the IFP-1
 process on a refinery sulfur plant.  As shown in Figure 4-9, emissions
 of S02 ranged from 2300 to 2600 ppm.
                                4.23

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       Figure 4-10 summarizes  the results  obtained from emission
  tests  on  a  Wellman-Lord process and a SCOT process.   Test Bl
  was  conducted  by the  Agency,  test  B2 was  conducted by refinery
  personnel and  tests B3  and C3 were conducted  by  the  LA APCD.
  The  Wellman-Lord process  is an  oxidation-scrubbing process, while
  the  SCOT  process is a reduction-scrubbing  process followed by
  incineration.  Emissions  of S02  from the Wellman-Lord  process  ranged
  from 10 to  50  ppm and emissions  from the SCOT process  averaged
  210 ppm.
      Figures 4-11 and 4-12 summarize the results obtained from
 emission tests on the Beavon process.  Test Bl was conducted
 by the Agency, test B2 was conducted by refinery personnel,
 and Tests  B3, E3 and F3 were conducted by the LA APCD.  Emissions
 of H2S were undetectable in four of these tests and ranged from
 0 to 7 ppm in the fifth.  Emissions of reduced sulfur compounds
 (calculated  as  S02)  generally ranged from 10 to 20 ppm in each
 of these tests.
 Vendor Guarantees
      Vendors of the  higher efficiency tail, gas treatment  processes
 normally guarantee emissions  of  total sulfur,  expressed as S02
 equivalent,  not to exceed  200  to  500  ppmv.   [SQ2  equivalent is equal
 to  (S02 +  H2S + COS +  2CS2 + sulfur vapor) expressed in gas
 concentrations  only.]  The J.F. Pritchard Company designed the
 Cleanair tail gas  process not to exceed 200 ppmv, 250 npmv, and 300 pnmv
total sulfur emissions for their first three installations.26>27,28
Union Oil Research designed the initial Beavon units  not to exceed
                               4.26

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 210 DDHIV total sulfur emissions.39  shell Development gave emission
 Guarantees-of 500 and 400 ppmv hydrogen sulfide for their initial
 installation of the SCOT process, though they have cited guarantees
 as low as 300 DPIW H2S (before incineration) in their literature.40^! ,42
 Davy Power Gas guaranteed 250 ppmv total sulfur as S02 on their
 first U.S. Claus nlant application of the Wellman-Lord systen.43
      Other tail gas processes which do not remove COS or CS2  usually
 guarantee efficiencies of H2S and S02 removal.   These guarantees
 cannot be directly correlated to  a total sulfur emission guarantee
 because the concentrations of COS and C$2 vary  according to Claus
 feedstock comoosition and operating conditions  in the first stage
 catalytic converter.   An  example  of vendor emission  guarantees  is
 the IFF guarantee at  one  installation of 90 percent  removal of
 H2S +  S02 in  Claus  tail gas.44
     Neither  of the vendor guarantees  soecified  whether  the concen-
 trations  quoted were  on a  dry or wet  basis  or whether they were  adjusted
 to  zero percent oxyaen.  Therefore, the  final levels of H2S and S02
could differ from the guaranteed levels when these conditions  are
taken into account.
                                4.30

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 4.4  REFERENCES
 1.  Genco, Joseph M. and Tarn, Samuel S., "Characterization of Sulfur
     from Refinery Fuel Gas," EPA Contract 68-02-0611, Task 4, June 28,
     1974, DP. 66-68.
 2.  Barthel et. al., "IFF Processes for Recovering h^S and S02 from
     Claus Unit Tail  Gas and for Cleaning S02 from Stack Gas," APCA
     Paper 73-304.
 3.  Reference 1, pp. 84-90. •
 4.  Krill, H. and Storp, K., "HoS Adsorbed from Tail Gas," Chemical
     Engineering 80<17), pp. 84-85, (July 23, 1973).
 5.  Reference 1, pp. 52-55.
 6.  Potter, Brian H., and Earl, Christopher B., "The Wellman-Lord S02
     Recovery Process," presented to the 1973 Gas Conditioning Conference.
 7.  Reference 1, pp. 68-71.
 8.  Reference 2.
 9.  Reference 1, po. 43-49.
10.  Beavon, David D. and Vaell, Raoul P., "The Beavon Sulfur Removal
     Process for Purifying Claus Plant Tail Gas," Proceedings, API
     Division of Refining', 1972, Volume 52, pp. 267-276.   .
11.  Reference 1, pp. 49-50.
12.  Landrum, L.H.,  Corn, L.H. and Fernald, W.E., "The Cleanair Sulphur
     Process," presented at  the 74th AIChE Meeting, New Orleans, March 11-15,
     1973.
13.  Reference 1 , op. 60-66.
14.  Naber, et. al., "The Shell Claus Off-Gas Treating Process,"
     presented at the 74th AIChE Meeting, New Orleans, March 11-15, 1973.
15.  Trip Report - "Visit to Wellman-Lord S02 Recovery Unit," C. Sedman,
     Industrial Studies Branch, ESED, OAP, Nov. 2, 1973.
16.  Reference  1,  p. 56.
17.  Reference  1,  p. 71.   .
                                  4.31

-------
 18.   Trip  Report  -  "Visits to Beavon Sulfur Removal Units," C. Sedman,
      Industrial Studies Branch, ESED, OAP, Nov. 5, 1973.

 19.   Reference 1, D. 45.

 20.   Trip  Report  -  "Visits to SCOT Units," C. Sedman, ESED, OAOBS, EPA,
      Nov.  2,  1973.

 21.   Reference 1, p. 63.

 22.   Reference 1, pn.  72-87.

 23.   Reference 1, pp.  72-73.

 24.   Conversation,  C.  Sedman, ESED, OAQPS, EPA, with Jim Nance,
      Los Angeles  County APCD, Dec. 11, 1974.

25.  Source Test  Report No.  74-SRY-4,  EPA Contract No. 68-02-0232,
     Task Order No.  34, Environmental  Science  and  Engineering,
     Gainesville,  Florida, June  1974.

26.   Letter, H.F.  Schaffer, GuTf Oil  Company of Pennsylvania to
      Charles B. Sedman, ESED, OAOPS,  EPA', October 16, 1973.

27.   Letter, A.A.  Muse, Jr., Atlantic Richfield Company  to
      Charles B. Sedman, ESED, OAQPS,  EPA, November 20, 1973.

28.   Letter, F.A.  Becker, Gulf Oil Company-U.S. to Charles B.  Sedman,
      ESED, OAQPS, EPA, November 27, 1973.

29.  Source Test Report No.  74-SRY-l ,  EPA Contract No. 68-02-0232,
     Task Order No.  34, Environmental  Science  and  Engineering,
     Gainesville,  Fla., March 1974.

30.  Letter, Thron Riggs, Standard Oil  Co. of  California to C.  Sedman,
     ESED, OAQPS,  EPA,'dated August 9,  1974.

31.  Source Testing Section Report No.  C-1895, Los Angeles County
     APCD, February 28, 1973.

32.  Source Test  Section Report  No. C-2104, Los Anaeles  County APCD,
     April  25, 1974.

33.  Source Test Report No.  74-SRY-2, EPA Contract No. 68-02-0232,
     Task Order No.  34, Environmental Science  and  Engineering,
     Gainesville,  Fla., March 1974.

34.  Letter,  George  L.  Tilley, Union Oil  Company of California, to
     C.  Sedman, ESED,  OAQPS,  EPA,  dated August 26, 1974.
                                4.32

-------
35.  Source Test Section Report No.  C-226,  Los Angeles County APCD,
     November 6, 1974,  December 12,  1974.
36.  Reference 30.
37.  Reference 31.         .
38.  Reference 32.
39.  Letter, D.L. Hanley,  Union Oil  Company of California to Charles
     B.  Sedman, ESED, OAQPS,  EPA, December  4, 1973.
40.  Private communication, David Hamilton, Douglas Oil Company,
     to  Charles B.  Sedman, ESED, OAQPS, EPA, October 16, 1973.
41.  Letter, R.S. Little,  Champlin Petroleum Company to Charles B.
     Sedman, ESED,  OAQPS,  EPA,  October 24,  1973.
42.  Brochure, "SCOT Process,"  Ford, Bacon  and Davis, Dallas, Tecas,
     1973.
43.  Letter, Thron  Riggs,  Standard Oil Company of California to
     Charles B. Sedman, ESED, OAQPS, EPA, December 12, 1973.
44.  Letter, W.W. Turner,  Stauffer Chemical Company to Don R. Goodwin,
     ESED,  OAQPS, EPA,  dated  June 14, 1974.
                              4.33

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               5.   MODIFICATION AND  RECONSTRUCTION
     Existing sources  which  are modified may  become  subject to
standards of performance under section  111  of the Clean  Air Act.
Any physical or operational  change to an existing facility which
results in an increase in the emission rate of any  pollutant  to
which a standard apolies may cause that facility to be considered
a modified source, subject to compliance with standards of
performance.  The full discussion of modification is included
under Subpart A - General Provisions of Part 60, 40 CFR.
5.1  MODIFICATION OF  REFINERY SULFUR BLANTS
     Under  the General Provisions of Part 60 40 CFR, physical changes
to  a facility  resulting  from routine maintenance, repair  or
reolacement will not  be  considered  modifications.   Also,  neither
an  increase in production capacity  if  this does not require  a
capital  expenditure^;  defined by §60.2(bb);  nor the  use  of
alternative raw materials,  if the facility was  originally designed
 to accommodate materials, will be considered modifications.
     The H2S gases  processed in  refinery sulfur plants  are
produced throughout a petroleum  refinery in  a number  of
different process  units. Consequently, almost  any  change within
 a petroleum refinery,such as a change  in the  type  of  crude oil
processed, construction of  new refinery process units,  expansion
 of existing process units,  or even  a change  in  the  operation
 of various process units, could  potentially  lead to a modification
 of an  existing refinery sulfur plant.
                                 5.1

-------
      Changes such as these could increase the volume of F^S gases
 generated within the refinery, leading to a need for increased
 sulfur recovery capacity.   Most refinery sulfur plants-, however,
 are overdesigned to some extent in anticipation of fluctuations
 in the volume of ^S gases generated within the refinery due  to
 seasonal  changes in refinery operation (i.e., maximum fuel
 oil  production in the winter months  comnared to maximum gasoline
 production in the summer months),  or to  changes  in  the  types  of
 crude  oil  processed.   As a result, most  refinery sulfur plants
 have excess  sulfur recovery capacity and can readily  accommodate
 changes within the refinery which  require only  moderate increases
 in sulfur  recovery capacity.
     Where the increased volume  of H2S gases  is  more  than
 that which can be  readily  accommodated by existing sulfur plants,
 additional plants  have usually been  constructed  rather  than expanding
 existing plants.   While  some expansion of existing sulfur recovery
 Plants would  be  possible through operation at higher pressure,
 this would also  probably require addition of another Claus catalyst
 stage to compensate for  the unfavorable shift in the equilibrium
 of the Claus  reaction which would accompany an increase in pressure.
 In addition,  alterations to the existing furnace and sulfur condensers
would probably also be necessary to provide increased combustion
 capacity and  increased sulfur condensation capacity.  As a result,
 the expense and problems associated with expansion of existing sulfur
 recovery plants, plus the desire on the part of many petroleum
                              5.2

-------
refineries to have excess sulfur recovery capacity and more than one
sulfur plant to compensate to some extent for the shut-down of a
sulfur recovery plant due to a malfunction, has led refineries to
construct additional sulfur recovery plants rather than expand
existing ones.
     Although as discussed in Chapter 3 the efficiency of sulfur
recovery in Claus plants and hence emissions from sulfur plants
are dependent on the composition of the H2S gases processed (lower
concentrations decrease efficiency), changes within petroleum
refinereies such as those mentioned earlier do not lead to significant
changes in the composition of the H2S gases processed by refinery
sulfur plants.  The amine treating units which remove H2S
from the  gases generated by  various refinery process units essentially
recover a gas stream containing 80-90 percent H2S regardless of  the
H2S content of the  original  process gas.
     Occasionally,  however,  in  response  to  local  or state  air
pollution control  regulations,  petroleum re fineries,:, have been
required  to  control sour water  stripper  gases  in  refinery  sulfur
plants.   These  gases usually contain only 30-40  percent H2S and
similar  concentrations  of  ammonia.   In some refineries the total
volume  of these  gases  can  be about  the same as  the total volume
of H2S  gases  produced  by the amine  treating units.  If any of  these
gases  are mixed with  those from the  amine treating units,  the
concentration of H2$  in the gases processed by the sulfur  plant
is lowered.   In addition,  since the  ammonia present in the sour
                               5.3

-------
 water stripper gases results in the formation of ammonia sulfates
 in a Glaus plant which can lead to fouling of the Glaus catalyst,
 the ammonia has to be removed by incineration of the sour water
 stripper gases.  This contributes to even greater dilution of the
 gases processed by the sulfur plant because of the fuel and air
 required for incineration.
      Consequently, if sour water stripper gases  are  mixed with  the
 H£S gases prpduced by the amine treating  units in a  refinery  to  any
 appreciable extent and fed  to an existing sulfur recovery plant,
 emissions from the sulfur plant would  increase as  a  result of both
 the higher sulfur  throughput  and the resulting decrease  in  sulfur
 recovery efficiency.   Whether or not this  would  be termed  a
 modification would depend on  the circumstances involved.   If  prior
 to  introduction of the  sour water stripper gases  into the  sulfur
 plant they were incinerated and  vented to  the  atmosphere,  S02
 emissions from the  refinery as a whole would decrease.  Under the
 general  provisions  of 40  CFR  Part 60, in this situation the sulfur
 Plant would not be  considered as a modified source even though its
 emissions would have increased.
     If, however, these sour water stripper gases had not been
 incinerated and vented to the atmosphere prior to their introduction
into the sulfur recovery plant, this might be considered a modification,
 If the sulfur recovery plant required alterations to accommodate these
gases, such as changes to the Glaus  furnace which required a capita^
                                5.4

-------
expenditure to carry out, then this would be considered a modification
and the sulfur recovery plant would be subject to compliance with
standards of performance.  If,oon the other hand, the sulfur recovery
plant required no alteration to accommodate these gases, the
decision as to whether this was a modification would hinge on the
question..."Is this a change in the method of operation?" (i.e.,
was the sulfur plant originally designed to process these gases?).
If this was concluded to be a change in the method of operation,
the sulfur recovery plant would be considered a modified source
subject to compliance with standards of performance.
     The emission control techniques discussed in Chapter 4 are
as applicable to modified refinery sulfur plants as. they are to  new
refinery sulfur plants,  since  these  control techniques  are  essentially
"add-on" control techniques which operate independently of  the
refinery sulfur plant.   In  addition,  the potential modifications
of refinery  sulfur  plants discussed  above would  not .significantly
change the characteristics  of the  tail  gas  from  the  sulfur  plant and
thus  would not prevent the  use of  any of the control techniques
discussed  in Chapter 4.   While the  Cleanair nrocess  might  require
a catalyst change  in the first stage catalyst reactor of a modified
 refinery sulfur  plant to reduce formation  of COS and CS25  and
 the IFP-1  or the Sulfreen process  might require the installation
 of additional instrumentation and process  controls to ensure main-
 tenance of the proner H2S/S02 ratio in the tail gas from the sulfur
 plant, these requirements are minor and could be readily accommodated
                                 5.5

-------
  in  a modified  refinery sulfur plant.  The Wellman-Lord, Beavon or
  SCOT processes, however, could be installed as readily on a modified
  refinery sulfur plant as on a new sulfur plant.  Each of these
  emission control techniques, therefore, can be expected to function
  as well on modified existing refinery sulfur plants as on new
  refinery sulfur plants and emissions could be reduced to the same
  levels in both situations.
 5.2  RECONSTRUCTION OF REFINERY SULFUR PLANTS
      Under the General Provisions of Part 60 40 CFR,  existing
 sources which are reconstructed may be considered as  new sources
 subject to compliance with  standards of performance,  regardless
 of whether emissions  increase  or not.   An existing  source will be
 considered reconstructed, however,  only  if most of  the separate
 components  of the source  are replaced.
     An incremental expansion  of  a  refinery  sulfur  plant,
 therefore,  is more  likely to be considered a potential modification than
 a reconstruction.   In  those cases where  the desired increase in
 sulfur  plant  capacity would be sufficient to necessitate replacement
 of most of the  separate components of an existing sulfur plant,
 it would orobably be more economical to maintain the capacity of the
 existing plant  and construct a new plant to provide the additional
 capacity as discussed above.
     Construction of an additional catalyst/sulfur condenser
stage to an existing  refinery sulfur plant to increase efficiency
would not be considered reconstruction.  If sulfur capacity  were
increased at the same  time with a resulting increase in emissions,
however, this  would  probably be considered a  modification.

                                5.6

-------
     As with modified refinery sulfur plants,  each  of the emission  control
techniques discussed in Chapter 4 are as applicable to reconstructed
sulfur plants as to new sulfur plants.  Consequently, emissions could
be reduced to the same levels through the use of these control
techniques whether the refinery sulfur plants were new or reconstructed.
                                     5.7

-------

-------
                   6.   EMISSION CONTROL SYSTEMS
     Based on the discussion presented tn the Dreceding chanters,  two
alternative emission control systems emerge as possible candidates
to serve as the basis for standards of nerformance (i.e., the best
system of emission'reduction).  These systems are the low temperature
Glaus reactor svstem and the tail gas scrubbing system.
6.1  LOW TEMPERATURE CLAUS REACTOR SYSTEM
     As,indicated  previously, most sulfur recovery nlants are two- or
three-stage  Claus  units which generally  achieve a sulfur recovery
efficiency of about 95%.  A  low  temnerature  Claus reactor system
may  be  added to  achieve an  improvement  in overall sulfur recovery.
The  low temnerature  Claus catalyst reaction  system is  much more
comnlex than a  conventional  Claus  reaction stage  and it increases
overall sulfur  recovery efficiency to about  99%.  Emissions  are
reduced bv about 80 to 85%  over those from conventional Claus  nlants.
Like the  conventional  Claus, the emissions from the  low-temperature
 svstem consist essentially  of S02. .Incineration of  the tail oases
 prior to  release to the atmosnhere effectively converts any H2S
 remaining, and any COS and CS2 formed in the Claus  reactors, to S02.
      As with the  conventional two- or three-stage Claus unit, the
 low-temnerature Claus reactor system denends on maintenance of the orooer
 H2S/S02 ratio in  the  gases  in the sulfur nlant.  Consequently, minor
 fluctuations in the gases processed by  a Claus sulfur  plant that would
 not lead to a significant  increase in emissions from  a conventional
                                    6.1

-------
  two- or three-stage unit are likely to result in an appreciable increase
  in emissions from a low-temperature Claus reactor system.   The problem
  of maintaining a 99% overall sulfur removal  efficiency,  therefore,  is
  more difficult than maintaining a 95% overall  sulfur removal
  efficiency.   Hence, emissions  from a low-temperature Claus  reactor  system
  are  likely to exhibit considerably more  fluctuation  than those  from a
  two-  or  three-staae conventional  Claus unit, although the absolute
  magnitude of  emissions would be much  lower.
  6.2   TAIL GAS SCRUBBING SYSTEM
      As discussed in Chapter 4, two different types of tail  gas
 scrubbing systems may be used to reduce emissions from Claus sulfur
 plants-reduction/scrubbing systems or oxidation/scrubbing systems.
 Either type  of system increases  overall  sulfur  recovery to about
 99.9 percent,  thereby reducing  emissions  from a conventional  two-  or three-
 stage  Claus sulfur plant  by  about  98-99 percent.
      The  Beavon,  Cleanair and SCOT processes  discussed in Chapter  4
 are  representative of the  reduction/scrubbing systems.  In these
 systems the tail  gases from  the final  sulfur condenser of a conven-
 tional Claus sulfur  plant are reduced  through the use of a reduction
 catalyst.  Essentially all the S02 and about 80-85 percent of the
COS and CS2 is converted to H£S.  In the Beavon and Cleanair  processes
the H2S is then absorbed in.a scrubbing solution and converted
directly to sulfur via the Stretford process (see Chapters  3  and  4).
                               6.2

-------
In the SCOT process the H2S is absorbed in a scrubbing solution,
then desorbed and recycled back to the Glaus sulfur plant.
     The Wellman-Lord and IFP-2 processes are representative of
the oxidation/scrubbing systems.   In  these systems the tail gases
from an  incinerator following  the  final  sulfur  condenser  of a  con-
ventional  Claus sulfur  plant  are absorbed  in  an S02  scrubbing  system.
The  S02  is then regenerated and  in the Wellman-Lord  process  recycled
 to the Claus sulfur plant.   In the IFP-2 process the S02  is  mixed
.with a small bypass gas stream from the H2S gases processed  by
 the sulfur plant and then sent to a low temperature Claus catalyst
 reactor.  The off-gases from the low temperature Claus reactor
 are then  recycled  to the Claus plant incinerator.
      Emissions  from the oxidation/scrubbing systems are  essentially
 S02.  Incineration of  the  tail gases from the  Claus sulfur plant
 prior to  entering  the  S02  scrubbing  system effectively converts
 any H2S,  COS  and CS2 to S02.  Emissions from the reduction/scrubbing
  systems,  however,  can  be  either S02  or a  mixture or H2S, COS  and
  CS2,  depending on  whether the tail  gases  from  the  scrubbing  system
  are incinerated before discharge  to the atmosphere.  Reduction of
  the tail  gases from the final sulfur condenser of a Claus sulfur
  plant effectively converts all  the S02 to H2S, but only about 80-85
  percent  of the COS arid CS2 present is converted to H2S.   The COS
  and CS2  remaining  is not absorbed in the H2S  scrubbing  system and
  is, therefore, released to the atmosphere in  the tail gases  as COS
  and CS2  along  with some H2S, unless these gases are first incinerated,
                                    6.3
                                7.1

-------
Incineration effectively converts  the COS,  CS2 and  HoS  present
   water pollution, solid waste generation and energy consumption also
   need to be assessed in the same manner.
        As discussed in Chanter 3, most SIP's  require new refinery
   sulfur plants to achieve an overall  sulfur  recovery of 99  percent.
   This requires a level of emission control equivalent to emission
   control alternative I.  A few SIP's, however,  require an overall
   sulfur recovery of only 96 percent.   This level  of sulfur  recovery
   can be achieved by conventional three-stage Glaus plants which,
   from the point of view of this document, are considered to represent
   uncontrolled plants.  Similarly, a few local air pollution control
   agencies require an overall sulfur recovery of 99.9 percent.   This
   is equivalent to emission control alternative  II.  Finally, a number
   of states which contain no refineries or oil and gas production facilities
   located within their borders have no air pollution regulations limiting
   emissions from refinery sulfur plants.
   7.1  Ambient Air Quality Impact
        The health and welfare effects  of S02  have  been well  documented.
   The health and welfare effects of H2S,  COS  and CS2,  however,  are
   not as  well  documented as  those of S02.  Table 7.1  summarizes
   the major health and welfare effects known  to  result from  exposure
   to var-ious levels  of these pollutants.   Of  the three (H2S,  COS,
   and CS2),  H2S appears to be the most harmful.  It can  lead  to
   death at concentrations  exceeding 1,500,000 yg/m3 while  continuous
   exposure to  concentrations  as  low as  15,000 yg/m3 leads  to
1
                                7.2

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 symptoms such as conjunctivitis, sleeplessness, and pain in the eyes.
 For occuoational exposure the American Conference of Governmental
 Industrial Hygienists (ACGIH) has set a 4-hour-per-week exposure
 limit of 15,000 ig/m3.  The effects of H2$ on domestic animals parallel
 those on humans, while appreciable damage to plants may occur at lower
 concentrations.  HgS will also cause significant damage to materials,
 especially metallic and painted surfaces.  Metals, such as silver or copper,
 will be tarnished when exposed to levels as low as 4 ifl/m3.2
      Experience with the use of CS2 in the textile and rubber manu-
 facturing industries, and to a lesser degree from toxicological  studies,
 has shown it to be highly toxic at concentrations approaching 1,000,000
 Workers exposed to lesser concentrations over a number of years  have
 experienced a variety of symptoms,  including mental  illness,  coronary
 heart  disease, high blood pressure,  and  changes in normal  reproductive
 processes  in  women  (i.e.  disruption  of the menstrual cycle  and
 pathological  changes  in  the  cellular composition  of vaginal smears).
 Some of these effects  have been  observed  with  industrial exposures
 as  low as 14,00n Pq/m3.   The ACGIH limit  for occupational exposure
 to  CS2,  however, has been established  at  67,857  vg/m3.  It  should
 be  noted that several  countries  have established lower occupational
 exposure limits, including the USSR where  it is set at 4553 yq/m3.3'4
     Comparatively  little information is available relative to the
 effects  of COS.  It appears, however, that this compound is less
 toxic than H£S or C$2-  One study usinq laboratory rabbits indicates
 the lethal dosage is about twice that of CS2.4
     To assess the environmental impact associated with standards of
Performance for refinery sulfur plants, the maximum impact on  ambient
                               7.4

-------
air quality of emissions from sulfur recovery plants was analyzed.
The dispersion model used for estimating maximum ambient air concen-
trations for averaging times ranging from one hour to one year was  the
Single Source (CRSTER) Model developed by EPA's Meteorology and
Assessment Division,  Concentration estimates were extrapolated from
the Single Source Model estimates for averaging times less than one hour.
     The meteorological input to the Single Source Model consists of one
year of hourly stability-wind-temperature data from Houston and
Chicago, two major petroleum refining cities.  The emission source
model is a 100 LT/D Claus plant with a stack height of 50 meters,
which would likely accompany a refinery capacity of about 100,000 BBL/day.
     In addition to assuming that emissions are from a single stack,
it was also .assumed that fugitive emissions do not exist, and adverse
downwash phenomena (which sometimes occur in the lee of stacks or
nearby structures) do not occur.  If fugitive emissions or downwash
problems existed, a special dispersion analysis would be required to
estimate the resultant air quality impact.  It should be noted in passing
that such problems can result in ambient concentrations several times
greater than those predicted in this analysis.
     Maximum ambient air concentrations (see Table 7.2) were estimated
to occur from about 0.6 to 1.6 kilometers from the'sulfur recovery
plant.  The 24-hour and 8-hour maxima will most likely occur on days
when there are several hours during which the wind is from a single
direction at about 3-7 meters per second and during which a neutral
or near-neutral atmospheric stability condition exists.  The one-hour
                              7.5

-------
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maxima will occur during unstable or slightly unstable atmospheric
conditions, accompanied by light wind speeds on the order of 1 to 2
meters.per second.  The downwind distance to the one-hour maxima will
range from about 0.4 to 1*6 kilometers.
     For averaging times less than one Jhour3 the peak concentrations
will most likely occur under light winds and unstable atmospheric
conditions.  The peak concentral!ows listed iia Table 7,2 for averaging
times of less than one incur will occur approximately 0,5 kilometers from
the source.
     The predicted maximum ground-level 24-hour and 1-year ambient air
concentrations of '502 from a typical 'uncontrolled IQfD LT/day sulfur
plant are 175  ifl/m3 and 15 is/m3, respectively.  These levels are
well below the correspondiing national ambient air quality standards

-------
     It appears from Table 7.2 that emission control  alternative I
(low temperature extended Glaus reaction)  reduces  the maximum  24-hour
ambient air S02 concentration by a factor of 7 and the maximum
one_year ambient air S02 concentration by a factor of 3.  Alternative II
(tail gas scrubbing), on the other hand, reduces these maximum ambient
air concentrations to essentially zero for all practical purposes,
assuming an oxidation tail gas scrubbing system is employed.  If a reduction
tail gas scrubbing system is employed, emissions of S02 are eliminated.
Use of  a reduction system, however, leads to emissions of H2S, COS and
C$2 which results in low ambient air  concentrations  of these pollutants.
     Specifically, alternative  I reduces  the maximum 24-hour ambient air
S02 concentration to 25  yg/m3  and  the maximum one-year ambient  air
SOo concentration to 5  ig/m3.   If  an  oxidation  system is employed,
alternative  II reduces  the maximum 24-hour  and  one-year ambient  air
S02  concentrations to 4 yg/m3  and  <1  yg/m3,  respectively.
      If a  reduction  system is  employed,  alternative  II  leads  to  maximum
2-10  second  ambient  air concentrations  of F^S,  COS and  CS2  of
25,  380 and  540 ;g/m3 and maximum  one-hour  ambient air  concentrations
of 1,  7 and  10 yg/m3, respectively.   Although the maximum 2-10  second
ambient air  concentrations of.H2S, COS  and  CS2  could lead to  odor problems
 or material  corrosion problems if  they  persisted  for longer periods
 (one to two hours), the ambient air quality modeling indicates  these
 concentrations are only of short duration.   As  shown in Table 7.2,
 beyond 2-10 seconds the maximum ambient air concentrations  of H2S,
 COS and CS2 decrease rapidly and fall well  below the threshold limits
 for odor or material corrosion problems.
                               7.8

-------
     Under normal  operation,  emissions  from the reduction  emission
control systems are no higher than 10 ppm H2S and  95-100 ppm for both
COS and CS2 and-, as discussed above, the resulting ambient air
concentrations of these pollutants will be low enough to ensure
that no adverse health or welfare effects arise.  Emissions of COS
and C$2, however, may increase considerably, approaching  levels as
high as 1000 ppm, if the catalysts used in the reduction  systems are
permitted to deteriorate.3  However, even at this level these
emissions are not likely to result in ambient air concentrations
sufficiently high to pose adverse health or welfare effects, based
on our present  knowledge.
     As noted earlier, most SIP's require  an overall sulfur  recovery
equivalent  to emission control  alternative  I.   Consequently, standards
based  on  alternative  I would  have little  or no  impact  on  ambient
air  quality.   Only  if standards are  based on  emission  control
alternative II  will  there  be  a  beneficial  impact  on  ambient  air
quality.   Based on  the growth projections presented  in Chapter 8,
 by 1980 some 8100 LT/day of refinery sulfur plant capacity will  be
 subject to NSPS.   Nationwide, therefore,.the beneficial impact on
 ambient air quality of standards in 1980, based on emission control
 alternative II, would be to reduce emissions by some 55,000 tons
 per year of S02-
  7.2   Water Pollution  Impact
       Petroleum refineries normally  discharge  large volumes  of
  waste water and  can  be  major point  sources  of  water pollution.
  The amount of waste  water discharged  varies  greatly from refinery

                                 7.9

-------
  to refinery, however, and depends on both the types  of orocess
  units Within the refinery and the degree  of water reuse.  The
  notential  water pollution impact  of  a typical  100,000  bbl/day
  refinery is  summarized in Table 7.3.  As  this table  shows, even
  with  the use of best practical control technology to limit water
  pollutant  discharges,  this impact can be  significant.
       Petroleum  refinery Claus sulfur plants by comparison aenerate
  an extremely small waste  water stream.  This stream results from
  condensation  of water  vaoor contained in the H2S gases as they
  flow  from the amine scrubbing units  to the Claus sulfur plant.
 Although this sour water condensate normally contains 1500-2000 ppm
 H£S and UD to 1000 ppm ammonia, the volume of water involved  is
 usually less than 0.25 liter per minute,  and this is  easily
 handled in the refinery's  waste water treatment facilities.   In
 terms  of the examole presented above, this is about 0.25 m3/day,
 or less than 0.002 percent of the  total waste water effluent  routinely
 discharged  by a  moderate size  refinery.
     The notential  water pollution impact  of the  two
 alternative emission  control systems  outlined in  Chapter 6 is
 negligible.   Table  7.4  summarizes  the characteristics and flow rates
 of the various waste water streams  discharged by  each of these
 systems.  As  this table shows, althouah the volume of waste water
discharged by some of these emission control processes is larger
than that discharged by the Claus  sulfur nlant, even in  the worst
case this is less than 50 liters per minute, which is  less  than
                             7,10

-------
                      Table 7.3
        Water Pollution Impact of a Typical
        100,000 bbl/da.y Petroleum Refinery'
Effluent Flowrate, m3/day

Pollutant Load, kg/day

   COD

   BQ%

   TQC

   TSS

   Oil

   Phenolics

   Ammoni a

   Sulfides
      13,500

Raw Water
BPCT2
1800
4500
1400
700
700
150
450
20
200
1100
350
150
70
1
100
1
Notes:

1.  Development Document for Proposed Effluent Limitations
    Guidelines and New Source Performance Standards for the
    Petroleum Refining Point Source Category, Effluent Guidelines
    Division, Office of Air and Water Programs, Environmental
    Protection Agency, December 1973, EPA/440/1-73/014.

2.  Best practical control technology.
                          7.11

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0.5 percent of the total waste water effluent routinely discharged
by a tynical 100,000 bbl/day refinery.
     The ootential water pollution impact associated with alternative  I
emission control  systems (low temperature extended  Glaus.reaction)
is negligible.  Although this alternative does not  generate additional
waste water streams continuously, intermittent waste water streams
are generated.  After about two years of operation, washing of the
catalyst is required to restore catalyst activity.   As shown in
Table 7.4, some 28,000 liters of water are required and, when discharged,
this water contains about 1 percent by weight of the organic solvent
for the Claus catalyst (polyalkyene glycol), and about 20-25 percent
by weight of the Claus catalyst itself (alkali metal salts).  This
waste water stream, however, can be easily treated  in the refinery
waste water treatment facilities to prevent any adverse water
pollution impact from arising.
     The potential water pollution impact associated with alternative  II
emission control  svstems (tail-gas scrubbing), although slightly
greater than that associated with alternative I systems, is also
negligible for all practical purposes.  Generally,  the waste water •
streams generated by the various tail-gas scrubbing processes consist
of a sour water condensate, similar to that generated by the Claus
sulfur plant, and a purge stream containing either  organic or inorganic
salts.  The amount and composition of these waste water streams
varies depending on the particular tail-gas scrubbing process used.
The sour water condensate is produced by cooling of the gases prior
                             7.13

-------
to the scrubbing tower, and the purge stream is necessary in most
cases to prevent a build-up of impurities in the scrubbing solutions.
     As shown in Table 7.4, the amount of sour water condensate
generated by these tail gas scrubbing processes is in the range of
20 to 45 liters per minute for a 100 LT/day Claus sulfur plant.
This stream is usually acidic in nature with a pH of about 2 if an
oxidation/scrubbing emission control system is employed.  If a
reduction/scrubbing system is used, this stream is usually only
slightly acidic, containing about 50 ppm H2S and a trace of ammonia.
These streams, however, can be added to the sour water condensate
stream discharged by the Claus sulfur olant for treatment in the
refinery's waste water treatment facilities.
     For a 100 LT/day Claus sulfur plant, the purge stream from
an oxidation/scrubbing emission control system» such as the  Wellman-
Lord process, is in the range of 15 liters oer minute.   This
stream consists essentially of a solution of sodium salts
in water and generally has the following composition:5

     Na2S04            5 percent by weight
     NaHS03            5 percent by weight
     Na2S03           15 percent by weight
     H20              75 percent by weight
     This  stream could be treated in the refinery waste water
treatment  system without difficulty, or it could be treated  by
                             7.14

-------
the NICE process developed by Nittetu Chemical Engineerinq Ltd.
The NICE process recovers the sodium as sodium carbonate (Na2C03)
or soda ash, which can be used to provide the necessary make-up
sodium sulfite/sodium bisulfite solution to the Wellman-Lord process.
Davy Power Gas, the developer of the Wellman-Lord process, is also
developing a treatment process for this purge stream.   Consequently,
disposal of this waste water stream will not lead to any adverse
water pollution impact.
     Unlike the Wellman-Lord process, the other oxidation/scrubbing
emission control system, the IFP-2 process, has no purge stream.  This
process Is essentially an upgraded alternative I process and consists
of a third-stage low temperature Claus reactor followed by an ammonia
scrubber.  The only waste water streams discharged are the sour water
condensate stream which  is common to all the tail-gas scrubbing processes,
and an  intermittent waste water stream resulting from washing of the
low temperature Claus catalyst every two years as mentioned earlier.
Thus, there is essentially no potential water pollution impact
associated with use of the IFP-2 process.
     The purge stream from a reduction/scrubbing emission control
system, such as the Beavon or Cleanair process, installed on a
100 LT/day Claus sulfur  plant is in the range of 5 liters
per minute.  As with the purge stream from the Wellman-Lord process,
this stream consists essentially of a solution of sodium salts
                                                     Q
in water and generally has the following composition:
                          7.15

-------
Na2C03
Na2S203
NaSCN
Misc. Sodium Salts
                           0.5 percent by weight
                           0.5 percent by weight
                           0.5 percent by weight
                           0.5 percent by weight
                          98.0 percent by weight
     This stream could also be treated in the refinery
waste water treatment system without difficulty, or treated by the
NICE process to recover the sodium as sodium carbonate.  The sodium
carbonate could be used to provide the necessary make-up solution
to the Stretford scrubbing unit of the Beavon or Cleanair processes.
The potential water pollution impact associated with the use of
the Beavon or Cleanair processes, therefore, is negligible.
     The SCOT process, which is also a reduction/scrubbing emission
control system, does not generate a purge stream.  As with the
IFP-2 process mentioned above, the only waste water stream generated
by this process is the sour water condensate stream, which can
be added to the sour water condensate stream generated by the
Claus sulfur plant for treatment in the refinery's waste water
treatment facilities.  Thus, use of the SCOT process would result
in essentially no water pollution impact.
     In conclusion, all the waste water streams generated by the
two alternative emission control systems outlined in Chapter 6
can be treated without difficulty in the refinery's waste water
treatment facilities.  Considering the small amount of waste
water discharged by these emission control systems, the potential
water pollution impact of NSPS for refinery sulfur plants will be
negligible,  whether they are based on alternative I or alternative II
emission control  systems, because of the  magnitude of dilution in the
refinery's waste  water treatment facilities.  Also, since these waste
                           7.16

-------
water streams are so small, they will  have no impact on the ability
of petroleum refineries to meet water quality effluent regulations.
7.3  Solid Waste Impact
     There is essentially no potential solid waste impact associated
with refinery sulfur plant standards based on either alternative I or
alternative II emission control systems.
     The Claus process itself requires periodic replacement of the
reaction catalysts, the frequency of replacement depending upon the
impurities present in  the  acid gas feed.  Usually the  catalyst,
made of bauxite  or alumina, is regenerated annually until a substantial
                                                       g
loss of activity occurs,  normally in  two  to  five years.    For a 100 LT/D
Claus  plant,  replacement  of the  catalyst  would  require disposal of approxi-
mately 70  tons  of spent catalyst, usually in landfills.  Alumina  (aluminum
oxide) and bauxite  (a  natural  mixture of  iron,  aluminum  and manganese
oxides/hydroxides)  are both non-toxic materials.   Neither  emission
 control  system alternative will  affect the  rate or quantity of
 catalyst replacement in the  Claus plant.
      As  for the emission  control systems  themselves,  neither  the
 alternative I systems  ("low temperature extended Claus reaction)  nor
 the oxidation tail gas scrubbing systems  (alternative II)  generate
 any .solid waste.  The reduction tail  gas  scrubbing systems,  however,
 do require periodic replacement of the reduction catalysts about
 every two years.10  These catalysts  usually have significant salvage
 value, being composed  primarily of  colbalt-molybdenum, and consequently,
 are normally returned  to a vendor for reprocessing.   Hence, even  the
 reduction tail gas scrubbing systems  generate essentially  no  solid
 waste.
                                 7.17

-------
 7.4  Energy Impact
      Although not generally recognized, petroleum refineries consume
 a significant amount of energy in processing crude oil into various
 petroleum products such as petrochemical feedstocks, gasolines,
 and fuel oils, etc.  The energy requirements of a typical  moderate
 or high conversion refinery, for example, usually represent about
 10 percent of the crude oil  throughput.11   Thus, the energy consumption
 of a nominal  100,000 bbl/day refinery is equivalent to about
 10,000  bbl/day of fuel  oil,  or some  250,000 kw-hr/tir.
      The energy requirements of refinery sulfur plants are  quite
 small in comparison.  A 100  LT/day Glaus sulfur plant, for  example,
 typically consumes  less than 1000 kw-hr/hr  of energy,12 or  less
 than  0.5 percent of the energy consumed  within  the  petroleum refinery
 itself.   Consequently,  the use  of Claus  sulfur  plants  to control
 emissions  of sulfur  dioxide  or  hydrogen  sulfide  at petroleum
 refineries does  not  significantly increase  the energy  requirements
 associated with  petroleum refining.
     The energy  impact  associated with each of the alternative
 emission control systems outlined in Chapter 6 is summarized in
 Table 7.5.  As this table shows,  the impact is negligible in all
 cases.  Alternative I,  for example, has a slight energy benefit
 (i.e. overall  energy consumption  is reduced somewhat)  due to reduced
 tail gas incineration requirements.  Alternative II, on the  other
 hand, has a slight energy nenalty or a moderate energy benefit,
 denending on whether an oxidation or reduction tail  gas scrubbing
emission control system is emoloyed and on whether tail gas reheat

                               7.18

-------
fs required to increase plume bouyancy.   A few local  air pollution
control agencies require that gases discharged into the atmosphere
must be above a certain minimum temperature to insure good plume
bouyancy and thus good plume dispersion.  Under these conditions,
Alternative II has a slight energy penalty.  Most local air pollution
control agencies, however, do not have requirements of this nature
and in most cases tail gas reheat is not necessary to obtain good
plume dispersion.  Under these conditions, Alternative II has
either a slight energy penalty or a moderate energy benefit,
depending on whether an oxidation system or a reduction system is
employed.  The moderate energy benefit associated with the reduction
tail gas scrubbing system arises because of reduced tail gas incineration
requirements.
     As mentioned earlier in this chapter, most SIP's require new
refinery sulfur plants to achieve an overall sulfur recovery of 99 percent.
This requires a level of emission control equivalent to alternative I.
Consequently, if alternative I is selected as the basis for refinery
sulfur plant NSPS, there will be no energy impact associated with the
standards.
     If NSPS are based on alternative II, there will be either
a slight energy penalty or'a moderate energy benefit associated
with the standards in all but those few  localities which already
require this type of emission control system.  This impact will
vary from  refinery to refinery depending on whether an oxidation
or a reduction tail gas scrubbing system is employed to comply with
the NSPS.  As shown in Table 7.5, use of an oxidation  tail gas
                                  7.19

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scrubbing system without tail gas reheat increases the overall
energy consumption of a Glaus sulfur plant by about 17 percent.
Use of a reduction tail gas scrubbing system without tail gas
reheat, however, reduces the overall energy consumption by about
50 percent.
     Based on the growth projections presented in chapter 8, by 1980
some 8100 LT/day of refinery sulfur plant capacity will be subject
to NSPS.  Standards based on alternative I will have essentially
no impact on national energy consumption, since most SIP's already
require the use of this type of emission control system.  Standards
based on alternative II, however, will reduce national energy
consumption by  some  54 million kw-hr/yr, or about 90,000 barrels
of fuel oil per year, assuming half of the refinery sulfur plant
capacity subject to  compliance with NSPS install oxidation tail
gas scrubbing systems without tail aas reheat and half install
reduction  tail  gas scrubbing systems without tail gas reheat.
7.5  Other Environmental Impacts
     No environmental impacts other than those discussed above
are likely to arise  from standards of performance for refinery
sulfur plants,  regardless of which alternative emission control
system is selected as the basis for standards.   Furthermore, other
than those resources initially required to construct either alternative
emission control system (most of which could probably be salvaged
in one way or another), there do not appear to be any irreversible or
irretrievable commitment of  resources associated with these standards.
As discussed above,  there is even no overall increase in the energy
requirements associated with refinery sulfur plants, since both

                               7.21

-------
                                     Table 7.6

                      Environmental Impact of No Standards or
                                 Delayed Standards
        Sulfur Plant Canacity
Nationwide S02 Emissions (M Tons/Yr)
Year Affected by Standards' No SIP*
1976
1977
1978
1979
1980
TOTAL
3150
1425
1815
850
850
8090
130
60
75
35
35
335
SIPJ Alternative IJ
25
10
15
5
5
60
25
10
15
5
5
60
Alternative II'
2
1
1
0.5
C.5
5
Note

1.  LT/day.
2.  95% control.
3.  99% control.
4.  99.9% control.
                                          7.22

-------
emission control systems result in a net reduction in energy
consumption.
     Based on the growth projections presented in Chapter 8, the adverse
environmental impact of no standards or delayed standards on nationwide
S02 emissions is summarized in Table 7.6.  If alternative I is
selected as the basis for standards, there is no adverse impact on air
quality since alternative I does not reduce emissions beyond levels
currently required by most SIP's.  If alternative II is selected
as the basis for standards, on the other hand, the adverse environmental
impact of delaying standards or not setting standards is an increase
in nationwide S02 emissions, of some 5,000 to 25:,000 tons per year,
reaching a  total of  about 55,000 tons per year by 1980.
     Since  there are essentially no adverse water pollution, solid
waste disposal  or energy consumption impacts associated with either
of the alternative emission control systems which could serve as
the basis for standards, there is no "trade-off" of potentially
adverse impacts in these areas against  the resulting adverse
impact on air quality of delaying standards or not setting  standards.
Furthermore, there does not appear to be any emerging emission
control technology on the horizon that  could achieve greater emission
reductions  or result in lower costs than that represented by
the emission control alternatives under consideration here.  Con-
sequently,  delaying  standards to allow  further technical developments
appears to  present no "trade-off" of higher SOg emissions in the
near future against  lower S02 emissions in the distant future.
                             7.23

-------
                            References

 1.  "Air Quality Criteria for Sulfur Oxides,"  U.S.  Dept. of Health,
     Education and Welfare, Public  Health  Service, January 1969.

 2.  "Preliminary Air Pollution Survey  of  Hydrogen Sulfide,"
     U.S. Dept.  of Health, Education and Welfare, Public Health
     Service, October 1969.

 3.  Peyton, Thomas 0.,  Steele, Robert V.  and  Mabey, William R.,
     "Carbon Disulfide, Carbonvl Sulfide,  Literature Review and
     Environmental Assessment,'" EPA Contract 68-01-2940, Task 23,
     July 1975.

 4.  Patty, Frank A., Industrial Hygiene and Toxicology, Vol. 2,
     2nd Ed., Interscience, New York, 1963.

 5.  Genco, J.M., and Tarn, S.S., "Characterization of Sulfur Recovery
     from Refinery Fuel Gas*11 EPA Contract 68-02-0611,  June 1974, p. 54.

 6.  Reference 5, pp. 35, 37-38.

 7.  Reference 5, p. 6n.

 8.  Reference 5, p. 36.

 9.  Letter, Cole, D.F., J.F. Pritchard and  Co. to W.D. Beers,
     Process Research, Inc. dated June  5,  1972.

10.  Reference 5, pp. 52, 57 and 64.

11.  "Impact of Motor Gasoline Lead Additive Regulations on
     Petroleum Refineries and Energy Resources  - 1974-1980 Phase 1,"
     EPA Contract 68-02-1332, Task"4, May  1974, p. V-38.

12.  Beers, W.D., "Characterization of  Claus Plant Emissions,"
     EPA Contract 68-02-0242, Task  2, Anril  1973.
                             °f C°a1  Gasification Emission Control
                                  7.24

-------
                       8.   ECONOMIC IMPACT

8.1  INDUSTRY PROFILE
     As of April 1975, there were 259 petroleuifi refineries in the United
States with a total capacity of 14.8 million barrels per calendar day
(BCD).  These refineries ranged in size from 200 BCD to 445,000 BCD,
with an average size of approximately 57,300 BCD.1  In general, new
refineries are expected to be considerably larger than the current
industry average.  Information is available on  12 refineries that have
been projected  to  be  built after January  1, 1975.  These  refineries vary
in size from 5,000 BCD to 200,000  BCD, with an average size of approximately
97,000 BCD.2
      Not  all petroleum refineries  currently  include  sulfur recovery
 plants. At the 259 domestic  refineries  referred to  above, only 81  included
 sulfur recovery plants.   There  are currently 122 sulfur  recovery plants
 within the industry, either currently installed or  due to be installed
 in 1975,  ranging  in size from 4 long tons of. sulfur per day (LTD) to 375
 LTD, with an average  size of 72 LTD.1'2'3  Sulfur recovery plants tend
 to be found  in the larger refineries.  Table  8-1 illustrates this point.
 For example, there are 175 refineries with individual capacities less
 than  50,000 BCD,  amounting to  67  percent of the total number of 259
 refineries.  These  refineries, however,  account for only 16 percent of.
 t'he  total  number  of 122  sulfur recovery  plants.  Stated  in another way,
 the  average size  of a refinery which includes a sulfur  recovery plant is
 approximately 140,000 BCD.   This  compares  to  an average size  of approximately
 27,000 BCD for those refineries  without sulfur recovery plants.
                                 8-1

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     Table 8-2 summarizes the current status of the domestic refining
industry with regard to sulfur recovery plants.  Table 8-3 provides
additional, detail with regard to the sulfur recovery plants that are
currently installed or due to be installed in 1975.
8.2  COST OF ALTERNATIVE EMISSION CONTROL SYSTEMS
     As outlined in Chapter 6, there are two alternative emission control
systems that could serve as the basis for refinery sulfur plant NSPS.
Alternative I, exemplified by the IFP-1 and the Sulfreen processes,
achieves an overall sulfur recovery of 99.0 percent measured against the
total  sulfur  in  the Claus plant feed gases.  Alternative  II, exemplified
by the Beavon, SCOT,  Wellman-Lord, Cleanair, and  IFP-2  processes,  achieves
an overall  sulfur  recovery of 99.9  percent.
     Since  more  data  was available,  both  from  vendors as  well  as owners,
the  IFP-1  and the  Wellrnan-Lord  and  the Beavon  processes were taken as
representative of  the two  alternative  emission control  systems.  Costs
would  have to be comparable  for the other systems or  they would  not be
competitive in the marketplace.   Tables  8-4,  8-5, 8-6,  and 8-7 present
the operating costs for the  basic Claus  sulfur recovery plant, a Claus
 plant with an alternative I  emission control  system (IFP-1),  a Claus
 plant with an oxidation alternative II emission control system (Wellman-
 Lord), and a Claus plant with a reduction alternative  II emission  control
 system (Beavon). The plant with the capacity of 10 long tons of sulfur
 per day is believed  to be representative of a unit required by a typical
 small refinery.  The plant with the 100 long  ton per day sulfur capacity
 is  believed  to  be typical of a unit required  by a typical  large refinery.
 A plant with  a  capacity of 5 long  tons of  sulfur per day,  while believed
 to  be toe,  snail to be  generally  utilized  in typical refineries, is  also
 shown for  comparison.       —    o o
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      Tables 8-8, a-9, and 8-10 summarize the economics of installing an
 alternative I or alternative II emission control system on a Claus
 sulfur recovery plant.  For a 100 LTD plant, use of an alternative I
 system reduces the annual return from $265,900 to $15,800, a loss of
 $250,100 per year.  Use of an alternative II system increases the annuaT
 costs to $314,600-462,800, depending on whether an oxidation or reduction
 process is employed, or a loss of $580,500-728,700 per year.   For a 10
 LTD Claus plant, use of an alternative I emission control  system increases
 the annual costs to $198,800, a loss of'$65,200 per year.   Use of an
 alternative II system increases the annual  costs  to $352,200-442,000,  or
 a  loss of $218,600-308,400 per year.  Finally,  for a 5 LTD plant,  use  of
 an alternative I system increases  the annual  costs to $205,900,  a  loss
 of $58,200 per year, and use  of an alternative  II system increases  the
 annual  costs  to  $344,800-419,900,  or a loss of  $197,100-272,200  per
 year.

 8.3 ECONOMIC  IMPACT
 Impact  by  Company Size
     Two financial profiles have beer,  developed to evaluate the economic
 impact  of the  two alternative emission control systems.  The first
 profile represents a  large, integrated oil company and the second represents
 a small oil company.  The profile of the large, integrated company is
 biased upon an analysis of the published financial statements of Exxon
 Corporation, Mobil Oil Corporation, Shell Oil Company, Phillips Petroleum
 Company, Cities Service Company, and Ashland Oil, Incorporated.  These
companies considered together should adequately represent the major
 integrated refiner sector of the domestic oil  industry.  The resulting
financial profile iis presented in Table 8-11.
                           8-10

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     The financial profile of the smaller, less complex firm is based
upon an analysis of the published financial statements of Murphy Oil
Corporation, Quaker State Oil Refining Corporation, APCQ Oil Corporation,
United Refining Company, and Edgington Oil Company,  These firms con-
sidered together should adequately represent the small refiner sector of-
the domestic oil industry.  The resulting financial profile is presented
in Table 8-12.
     The economic impact associated with standards of performance results
from the incremental cost imposed on a source to comply with these
standards above those imposed on a source to comply with existing state
or local air pollution regulations.  As discussed in Chapter 3, most
State Implementation Plans to meet the national ambient air quality
standards for SC^ require new plants to achieve an overall sulfur recovery
of 99.0 percent.  A few local air pollution control regulations require
an overall sulfur recovery of 99.9 percent.  Consequently, most state or
local regulations already require the installation of an alternative I
emission control system and standards of performance based on this
alternative will have no economic impact.
     To assess the economic impact associated with standards based on
emission control system alternative II, the effect of compliance with
standards on the financial profile of a typical refiner was evaluated.
Eleven cases covering various refinery and sulfur plant capacities were
examined, three representing a large refiner and eight representing a
small refiner.  These cases are presented in Tables 8-13 through 8-23
and are summarized in Table 8-24.
                              8-15

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     As shown by the large refiner cases of Table 8-24, standards based
on emission control system alternative II decrease the profitability (as
measured by return on assets) of a large integrated refiner by 0.37 to
1.48 percent, if unaccompanied by price increases.  To maintain an 8.10
percent return on assets, a large refiner would"have to increase prices
for petroleum products by 0.02-0.27 percent, or about 0.4-4.5 cents per
barrel.  It is highly unlikely that this impact would retard industry growth
among  the large integrated refiner sector of the  domestic petroleum refining
industry.  The reduced profitability, or the increase in product prices
necessary to maintain profitability, are for all  practical purposes negligible.
     As might be  expected, the  impact of standards on a small refiner  is
greater than that on a large  refiner due to economies of scale.  As shown
by the small refiner cases of Table  8-24,  standards  based  on  emission
control system  alternative  II decrease  the profitability of a  small
refiner by  1.28 to 7.50  percent,  if  unaccompanied by price increases.   To
maintain  a  6.27 percent  return  on assets,  the  small  refiner would  have to
 increase  prices for petroleum products  by  0.16  to 0.93 percent, or about
 1.8 to 10.6 cents per barrel.  Although it appears that the  impact of
 standards on the smallest refiner may be from three to five times as severe
 as that on the typical  large refiner, the magnitude of this impact is still
 quite small and not likely to retard industry growth among the small refiner
 sector of the domestic petroleum refining industry.  As with the large
 refiner, the price increases necessary to maintain profitability are negligible,|
 especially  in light of price increases over the  past three to five years.
                                    8-29

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      The impact analysis by refinery size is clouded by the relatively
 small size of the control  investment and annual  cost compared  with  the
 overall  refinery operation.   There is,  however,  a  more  pronounced effect
 when the incremental  differences between control units  is  considered.
 Table 8-25,  which is  derived from Tables 8-8 - 8-10, presents'the incremental
 costs of achieving alternative II utilizing  five sizes  of  control units.
 Due to economies of scale,  the cost of  controlling an incremental ton of
 S02 at the level of alternative II goes from $468-678 for  a TOO  LTD
 sulfur plant to $3,891-5,994 for a 5 LTD sulfur  plant.
 Nation-Wide
      Table 8-26 provides the number and size distribution  of Claus plant
 affected  facilities in  the period 1976-1980.  It should  be  noted that
 the growth is  greater than the projected annual increase of refinery throughput
 for three reasons.  First, approximately 30  percent  of the  current refining
 capacity  is  not controlled by  Claus  units so  the base is narrow.  Second,
 it  is  assumed  that  all  future  refinery  capacity, will  be controlled and
 third  there  will  be an  annual  replacement of  5 percent of the existing
 Claus  plants.
     Table 8-27  develops the 1976-1980  forecast to show the national
 impact of required  investment  dollars,  the annual  costs and the potential
 emission  reductions.  Standards  based on alternative  I will have no impact.
 Standards  based  on alternative  II, on the other hand will require an
 Incremental  investment  by the  domestic  petroleum refining industry of some
 $110 MM over the five-year period of 1975 to  1980.    In 1980, these standards
will increase the annual operating costs of the domestic industry by some
 $16 MM per year.  In return, the  standards will  reduce national S02  emissions
by some 57,000 tons per year.
                          8-30

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8.4  POTENTIAL SOCIO-ECONOMIC.AND INFLATIONARY IMPACT
     Since the emission control systems required to comply with standards
based on either emission control system alternatives represent such a
small proportion of the overall equipment or investment required by a
petroleum refinery, there should be no more socio-economic impact associated
with standards than associated with the addition of any new processing
unit to a refinery.
     The inflationary impact associated with standards of performance
for refinery sulfur plants is negligible.  If standards are based on
emission control system alternative I, there is no inflationary impact
at all.  If standards are based on emission control system alternative
II, the fifth-year annualized costs are about $16 MM/year, and the price
Increases necessary to maintain the current industry average return on
investment varies from $0.004 to $0.106 per barrel, depending on the
size of the refinery affected.  These are well  below the Environmental
Protection Agency's guidelines for preparation  of inflationary impact
statements.
                               8-34

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                         REFERENCES  -  CHAPTER  8
1.  Oil  and GSs Journal,  April  7,  1975,  pgs. 100-118.
2.  Hydrocarbon Processing, February,  1975,  pgs.  3-15.
3.  Characterization of Sulfur from  Refinery Fuel- Gas.  (Contract  No.
    68-02-0611, Task 4),  Battelle  Columbus Laboratories,  June  28, 1974,
    pgs. 22-27.
4.  Department of Labor, Monthly Labor Review, October  1975,  p.  96.
5.  Ford, Bacon and Davis, Sulfur Recovery Plants, 1971,  p.  80.
6.  Federal Power Commission, Typical  Electric Bills, 1974 FPCR-83.
7.  Beers, W.  D., Characterization of Claus Plant Emission,  Final
    Report from Process Research, Inc., to the United States E.P.A.
    Contract No. 68-02-0242, Task No. 2, Report No. EPA-R2-73-188
    (April 1973). p. 75.
8.  Letter, Hanley, D. L.  Union Oil Company to Sedman, C. B,  E.P.A,,
    dated  12-4-73.
g.  Comparative Assessment of  Coal  Gasification Emission Control Systems,
     (Contract  No. 68-01-2942,  Task  007),  Booz-Allen & Hamilton,  Inc.,
    October  1975, page A-3.
10.   Letter,  Andrews, J.  W.,  J.  F. P.  to Genco, J.  M., Battelle dated
     12-21-75.
11.   Letter,  Turner, W. W., Stauffer Chemical  Co.  to  Goodwin,  D.  R.
     E.P.A.,  dated 6-14-74.
12.   Letter,  Ballard, B.  F., Phillips  Petroleum Co. to  Sedman, C. B.
     E. P. A., dated 12-18-74.
13.  Trip Report:  Sedman, C. B.,  Standard Oil Company  of California,  El
     Segundo Refinery, 10-15-73.
14.  Hydrocarbon Processing, April 1973, p. 116.

                                    8-35

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15. Op. Cit, Booz-Allen & Hamilton, page A-ll,  12.
16. Moody's Industrial Manual, 1974 and 1975,
.17. Beers, W. D., op. cit., page 94.
18. Beers, W. D., op. cit., page 93.
19  Op. Cit., Booz-Allen & Hamilton, page A-5.
                                 8-36

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                  9.  RATIONALE FOR THE STANDARDS
9.1  SELECTION OF SOURCE FOR CONTROL
     Sulfur dioxide emissions from petroleum, refineries are a
function of the sulfur content of the crude oil processed and the
complexity of the refinery itself.  A major portion of the sulfur
which enters the refinery in the crude oil leaves the refinery in
the various petroleum products produced.  Most of the sulfur
not accounted for in these petroleum products is recovered
as elemental sulfur, or emitted to the atmosphere as S02-
     The major S02 emission sources in petroleum refineries are
gas and liquid fuel combustion, fluid catalytic cracking unit
catalyst regeneration and elemental sulfur recovery.  Standards
of performance limiting S02 emissions from gaseous fuel combustion
were promulgated on March 4, 1974 (39 FR 9308).  These standards
essentially require the removal of H2S from fuel gas before
it is burned, thus forcing increased elemental sulfur recovery
within petroleum refineries.
     Petroleum refinery sulfur recovery plants, however, as mentioned
above, are responsible for a sizeable portion of the total S02 emissions
emitted from petroleum refineries.  In 1975, nationwide refinery
sulfur recovery plant S02 emissions were estimated to be 0.272 x 10° MT/
yr, or about 10% of total domestic refinerv S02 emissions.  Although
refinery sulfur recovery plants are responsible for only a small
portion (about 1%) of the total unabated U.S. S02 emissions, the
expected rapid growth of these facilities emphasizes the need for their
control.  As of April 1975, there were 122 sulfur recovery plants
located in 81 domestic refineries.  Between 1976 and 1980, 107 new

-------
olants are expected to be built.  Well over half of these new
plants (about 62%) will have an average size of 100 LTD.  The total
combined capacities of these new plants will be about 6,000 LTD
so that by 1980 the number of refinery sulfur recovery plants will
double.
     A very important consideration of developing standards for
refinery sulfur recovery plants is that most refineries are located
in or near urban areas.  As the size and number of these refineries
increase and the average sulfur content of the crude oil processed
increases, control of S02 emissions becomes much more critical.
9.2  SELECTION OF THE BEST SYSTEM OF EMISSION REDUCTION
     As discussed in chanter 6, two alternative emission control
systems are considered candidates to serve as the basis for standards
of performance (i.e. best system of emission reduction, considering
costs).  These systems are the third-stage low temperature Claus
reactor system (alternative I) and various tail gas scrubbing
systems (alternative II).
     Considering only the nerformance of these systems, the
alternative II systems are clearly superior to the alternative I
systems.   (See chapters 4 and 6,0  Use of an alternative II emission
control system increases the overall sulfur recovery of a refinery
sulfur nlant from about 95 percent to 99.9 percent, comnared to
99 percent with use of an alternative I emission control system.
In terms of emission reduction, the alternative II systems reduce
emissions  by 98-99 percent, compared to an emission reduction of
only 80-85 percent achieved bv the alternative  I systems.  Also,
                                9.2

-------
the alternative II emission control systems are essentially insensitive
to fluctuations which might occur in the composition of the tail
gases from the sulfur plant.  The alternative I systems, however,
require strict maintenance of a 2:1 H2S/S02 ratio to function properly.
Thus* the alternative II systems are much less prone to upsets and
are able to limit emissions to lower levels over a wider variety
of operating conditions than the alternative I systems.
     Considering the various environmental impacts associated with
both alternatives, the alternative II emission control systems again
emerge as clearly superior to those of alternative I.  (See chapter 7.)
In terms of ambient air quality, although the alternative I emission
control systems result in a significant  reduction in  the maximum
ambient air concentrations of S02  arising from the operation of a
refinery sulfur nlant, the alternative  II systems result in a
 substantially greater reduction  of these concentrations.
More  importantly, however, most  State implementation  plans  (SIP)
already require a level of control  essentially equivalent  to the
alternative  I  emission control systems.   Consequently,  standards
based on  this  alternative would  have  little  or no impact on emissions
of S02 from  new or  modified  refinery  sulfur  plants.   Standards  based
 on the alternative  II systems,  however, will  reduce  these  emissions
 by about  90  percent and will  lead to  a  reduction in  the growth  of
 national  S02 emissions by 1980 of some  55,000 tons  per year.
      Considerinq  possible environmental impacts  in  other areas,
 there are essentially no potential adverse water pollution or solid
 waste impacts associated with either alternative emission  control
                                   9.3

-------
  system1.   With  regard  to  energy  consumption,  both alternatives
  reduce the  overall energy  consumntion  associated with a refinery
  sulfur plant.  Since  most  SIP's already require the installation
  of alternative I emission  control systems, no reduction in energy
  consumption can be associated with standards based on this alternative.
  If standards are based on  the alternative II systems, however, the
  growth in-national energy  consumption will be reduced by some 54
 million kw-hr/yr (90,000 barrels of fuel oil per year) by 1980.
      With regard to other  areas of potential environmental impacts,
 there appear to be no noise or radiation impacts, or any irreversible
 or irretrievable commitment of resources associated with either
 of these  alternative  emission control  systems.   Neither does  there  appear
 to be any incentive for not developing or  delaying  standards.
      In terms  of the  economic impacts  associated with  the  alternative
 emission  control  systems, the alternative  II  systems generally  cost
 about twice  as  much to install  and  about 2 1/2  times as  much  to
 operate as the  alternative  I  systems.   Again, however, since  most
 SIP's already require  the installation  of alternative  I  emission
 control systems, there will be no economic impact if standards are
 based on this alternative.  If standards are based on alternative II,
 the impact on a typical large integrated refinery will  reduce its
 profitability from  about  8.10 percent return on assets  to about
 7.98-8.09  percent.  To maintain an 8.10 percent return  on assets,
 the refiner would have to increase prices for petroleum products
 by only 0.03-0.12 cents per gallon,  or less than 0.5 percent.  The
magnitude  of this impact, therefore, is negligible.
                                 9.4

-------
     The impact on a typical  small refinery is larger than that on a
large refinery due to the "economies-of-scale".   In this  case the
impact of standards based on  the alternative II  emission  control
systems will  reduce the profitability of a small  refinery from about
6.27 percent return on assets to about 5.80-6.18 percent.  To
maintain a 6.27 percent return on assets,, the small refiner would
have to increase prices on petroleum products by about 0..06-0.25
cents per gallon, or 0.16-0.94 percent.  While this impact is about
twice as severe on the small  refiner as on the large refiner,
its magnitude is still quite small and not likely to retard
growth among the small refiner sector of the domestic refining
industry.  As with the large  refiner, the price increases necessary
to maintain profitability are negligible, certainly in light of price
increases over the past three to five years.
     In terms of the national impact on the domestic petroleum
refining industry, standards  based on the alternative I emission
control systems will have no impact.  Standards based on the
alternative II systems,, however, will increase the national investment
required by the domestic industry by some $115 MM over the five-year
period from 1975 to 1980; and the annual operating costs of the
industry will be increased by some $16 MM per year in 1980.
     The potential inflationary impact of these standards is
essentially negligible.  If standards are based on the alternative I
emission control systems, there is no impact, and if standards
are based on the alternative II systems, the increased fifth-year
annualized costs and increased,product prices are well below the
                                  9.5

-------
Agency's guidelines of $100 MM per'year and 5 percent for signalling
potential inflationary impact.
     It is clear, therefore, that the alternative II emission control
systems must be selected as the "best system of emission reduction,
considering costs" and that standards of performance for refinery
sulfur plants must be based on the use of these systems.
9,3  SELECTION OF POLLUTANTS  FOR CONTROL
     As discussed above, sulfur recovery olants in petroleum refineries
are major point sources of S02 emissions.  .The objective of standards
of nerformance, therefore, is to reduce these emissions from new
and modified refinery sulfur plants.  Selecting emission control
system alternative II as the basis for standards, however, complicates
the selection of pollutants for control.
     Emission control system alternative II refers to two different
processes:  oxidation-scrubbing and reduction-scrubbing.  Residual
emissions released to the atmosphere from oxidation-scrubbing
processes consist of S02-   Residual emissions released to the
atmosphere from reduction-scrubbing processes, however,  consist
of S02 if the tail  gases are incinerated before release  to the
atmosphere, or a mixture of reduced sulfur compounds  such as
hydrogen sulfide (HaS),  carbonyl  sulfide (COS) and carbon disulfide
(C$2), if the tail  gases are not incinerated (see  chapters  4 and 6).
A limit on S02 emissions alone,  therefore,  while appropriate for
the oxidation-scrubbing  processes,  and those reduction-scrubbing
processes with tail  gas  incineration, is inappropriate for  those
reduction-scrubbing  processes  without tail  gas incineration.
                                9.6

-------
     While emissions of H2S from the reduction-scrubbing processes
without tail gas incineration can vary widely depending on the
design and operation of the process, emissions of COS and CS2
will not exceed 90-100 ppm unless the reduction catalyst in the
process is permitted to deteriorate.  Consequently, the major
potential air pollution problem posed by these processes is emissions
of H2S.
     Minimizing emissions of H2S from reduction-scrubbing processes
without tail gas incineration requires design and operation: of the
scrubbing portion of the process to reduce emissions of H2S to
very low levels initially.  If standards of performance do not limit
emissions of H2S, owners or operators of these processes could
operate only the reduction portion  of these systems and by-pass
the scrubber portion.  The S02 originally present would merely be
converted to H2$ and released directly to the atmosphere.  Although
this is possible, it is unlikely because at the ambient air concen-
tration of H2S which would result  (500-2000 yg/m3, with short-
                                                o
term peaks, 2-10 second, approaching 25,000 yg/m} an extremely
severe odor problem would result (see chapter 7).  Sources would
tend to control these  HLS emissions to very low levels due to
the offensive odors which would otherwise result if they were
not controlled.
     Even  in the more  likely situation, however, where  emissions
of H2S were reduced  to the range of 200-300 ppm before  release
to the atmosphere,  ambient air concentrations of H2S ranging  from
15 to  60  yg/m3  could arise with  short-term peaks as  high as  500
to 800 yg/m3.   Since the  odor threshold for H2S  is 45 yg/m3,  an
odor  air  pollution  problem could still arise.
                            9,7

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     Although emissions of COS and CS2 are normally very low,
as mentioned above,  if the reduction catalyst is permitted to
deteriorate, emissions of these compounds from reduction-scrubbing
processes without tail gas incineration can approach 1000 ppm.
Under these conditions, ambient air concentrations of COS and C.^2
ranging from 100 to  400 yg/m3 could arise, with short-term peaks
approaching 3500 to  5500 yg/m3, respectively.  While ambient air
                                                  C
concentrations of COS and CS2 at these levels probably do not
pose health problems, so little health effects data is available
on COS and CS2 that  this is questionable.  (The little data
available indicate adverse health effects occurring only at
levels greater than  15,000 yg/m3 for CS2, with no data available
for COS—see chapter 7.)  The data do indicate, however, that
these short-term peak ambient air concentrations of CS2 are at
the odor threshold level  for CS2,  so that transitory odo,rs  could
also arise if the reduction catalyst is permitted to deteriorate.
     Developing standards of performance to limit emissions of S02
from refinery sulfur recovery plants, therefore, gives rise to
a rather unusual situation.  In some cases, compliance with these
standards, while eliminating SOz emissions, would lead to emissions
of reduced sulfur compounds (i.e.  H2S, COS and CS2), which could
lead to an odor air  pollution problem.  Consequently, two alternative
courses of action emerge with regard to selecting the pollutants
for control by standards of performance for refinery sulfur recovery
plants:
                                9.8

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     1.  Limit emissions of S02 only
     2.  Limit emissions of both S02 and reduced sulfur compounds
     Limiting emissions of reduced sulfur compounds (i.e. ^S,
COS and CS2) from reduction-scrubbing emission control systems
without tail gas incineration, however, would make these pollutants
"designated pollutants," and all existing reduction-scrubbing emission
control systems without tail gas incineration installed on refinery
sulfur recovery plants "designated facilities," under section lll(d)
of the Clean Air Act.  ERA's regulations implementing section lll(d)
(40 CFR §60) would require the Agency to issue a draft guideline
document containing the necessary information for states to develop
plans for controlling these pollutants from these existing facilities
and to solicit public comments on this document.  Following considera-
tion of these comments, the Agency would make appropriate changes
to the guideline document and issue it in final form.   Those states
containing reduction-scrubbing emission control systems without
tail  gas incineration installed on refinery sulfur plants would
then be required to develop plans for controlling emissions of these
pollutants from these facilities with public hearings  to solicit
the views of interested parties.  These plans would then be submitted
to the Agency for approval  or disapproval.   If a State's plan were
disapproved, the Agency would have to develop a plan for that state.
     Currently, there are about 25 reduction-scrubbing emission
control systems without tail gas incineration now operating on
petroleum refinery sulfur recovery plants in some seven states.
Developing State plans to limit emissions of reduced sulfur compounds
                              9.9

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from these facilities, therefore, could be a significant undertaking
requiring the expenditure of considerable resources at the Federal,
State and 1 oca! 1 eve!.
     Emissions of reduced sulfur compounds, from these existing
reduction-scrubbing emission control: systems without tail gas
incineration, however, are quite low.  These systems have been
installed to comply with State or local air pollution regulations
limiting emissions of SO^ from existing refinery sulfur recovery
plants.  To ensure that the installation of these emission control
systems do not lead to local odor problems,., these.regulations
also limit emissions, of H^S, COS and CSz» either directly or
indirectly.  Where emissions of reduced sulfur compounds are
limited directly, local regulations specify the maximum concentrations
of H£S> COS and CS2 that can be present in the tail gases discharged
to the atmosphere.  In each case where this approach has been
followed, emissions of H2S are limited to 10 ppm and emissions
of total sulfur  (H2S, COS and CS2) are limited to either 300 or
500" ppm.
     Where emissions of reduced sulfur compounds are limited indirectly
by local regulations, these regulations require that the best available
emission control technology be installed.  In the process of
specifying what  the best emission control technology is, local air
pollution control agencies generally contact EPA, vendors of various
emission control systems and, other local air pollution control
agencies where various emission control systems have been installed.
                                 9.10

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In terms of -emissions .of reduced sulfur compounds from existing
reduction-scrubbing emission control systems without tail gas
incineration, this approach lias achieved the same end result
as that above, and all 25 of these systems which are now operating
have been designed and guaranteed toy the -vendors of these systems
to limit emissions to less than 10 ppm ^S and less than 300 otf
500 ppm total sulfur  (M?S, COS and CS^J
     Consequently, existing reduction-scrubbing emission control
systems without tail  gas incineration are not considered significant
sources of reduced sulfur compound emissions.  Developing State
regulations to control emissions of these pollutants from the'se
facilities, therefore, would accomplish no additional reduction i;n
reduced sulfur compound emissions.
     Probably the major reason why existing reduction-scrubbing
emission control systems without tail gas Incineration are not
sources of reduced sulfur compound emissions is that to date-,
these systems have only been installed in heavily industrialized
metropolitan areas.   In these areas, the :need for air pollution
control is generally  well recognized and the local air pollution
control agencjes have been in a position to develop and enforce
strong air pollution  regulations.
     Standards of performance for refinery sulfur plants, however,,
will require the installation of oxidation-scrubbing or reduction-
scrubbing emission control systems on new or modified refinery sulfur
recovery plants throughout the United States.  In some areas
                                 9.11

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where these systems might be installed, the need for stringent air
pollution control might not be as great as it is in these areas
where these systems have already been installed.  In these areas,
owners and operators who installed a reduction-scrubbing emission
control system without tail gas incineration would not face stringent
regulation of reduced sulfur compounds and they might permit
emissions of H2S to increase to the range of 200 to 300 ppm.  At
this point the resulting ambient air concentrations of F^S would
lead to noticeable but intermittent and transitory odors as discussed
earlier.  It is quite possible, therefore, that in complying with
standards of performance, some new refinery sulfur plants could
become sources of emissions of reduced sulfur compounds unless
the standards specifically limit emissions of these pollutants.
     Preventing new air pollution problems from arising, however,
is one of the primary goals of standards of performance.  Also,
standards of performance are to reflect the best systems of emission
reduction, taking into account the costs of installing and operating
these systems.  Considered from this perspective, since the technology
for reducing emissions of reduced sulfur compounds from reduction-
scrubbing systems without tail  gas incineration is well demonstrated,
the costs of controlling these emissions are reasonable, and not
controlling these emissions could lead to an adverse environmental
impact in some cases; reduction-scrubbing emission control  systems
without tail  gas incineration can only be included among the best
systems of emission reduction if emissions of reduced sulfur compounds
are controlled.
                               9.12

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     It is also through  standards  of performance  that  the Agency
identifies the best systems of emission reduction for  various
industrial sources of air pollution.  If the Agency were not to
limit emissions of reduced sulfur  compounds, therefore,  it  would
imply that the Agency does not consider controlling these emissions
from reduction-scrubbing processes necessary.  This view could
serve to undercut or weaken those  local air pollution  regulations
which are now effectively controlling these emissions  from  existing
sulfur recovery plants which have  installed reduction-scrubbing
emission control systems without tail gas incineration.
     A number of good reasons exist, therefore, for extending  the
standards to cover emissions of reduced sulfur compounds.   However,
a problem may arise if the burden  of the state plan submission required
by 40 CFR §60.23 outweighs its possible benefits.  To  resolve  this
problem,  it is appropriate to consider the intent of both standards
of performance and section lll(d).
      Briefly, the intent  of  standards of performance is to require
 the installation of the best systems  of emission  control at  the
 time a  source is being constructed or modified.   The intent  of
 section lll(d) is to reduce  emissions of pollutants emitted  from
 existing facilities which pose a danger to  the  public  health or
 welfare, but  which on  the basis of the information available
 cannot  be controlled under sections 108, 109 and  110 of the Act
 as  criteria pollutants, and which  cannot be controlled under
 section 112 of the Act as hazardous pollutants.
                               9.13

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     Where an emission control system installed to comply with a
standard of performance might lead to the emission of a pollutant
not originally emitted by a source, the logical course of action
is to limit emissions of this new pollutant to ensure that it
does not lead to a new air pollution problem.  In cases where the
new pollutant is a non-criteria pollutant, it must be decided
whether or not to initiate the chain of events leading to the
development of state regulations for limiting emissions of this
pollutant from existing sources already well  controlled for this
pollutant.
     The pollutants selected for control by these standards,
therefore,  are S02 and reduced sulfur compounds.   A determination
of the effort involved in developing state plans  will enable EPA
to determine whether or not to develop a guideline document or
initiate the chain of events leading to the development of state
plans for controlling emissions of reduced sulfur compounds from
existing reduction-scrubbing emission control systems without
tail  gas incineration which have been installed on refinery sulfur
plants.
 9.4   SELECTION  OF FORMAT FOR THE STANDARDS
      A  number of different,formats  could  be  selected to limit
 emissions  from  refinery  sulfur plants.  Mass standards limiting
 emissions  in  terms  of overall  sulfur recovery (i.e.  emissions
 oer  unit of sulfur  produced  or contained  in  the  feed to the
                                9.14

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plant), or concentration standards limiting the concentration
of emissions in the stack gases discharged into-the atmosphere,
could be developed.
     While mass standards may appear more meaningful in the sense
that they relate directly to the quantity of emissions discharged
into the atmosphere, enforcement of mass standards is more costly
and the results more subject to error than enforcement of concen-
tration standards.  Determining mass emissions, for example,
invariably requires developing a material balance of some form
and this requires process data concerning the operation of
the plant, whether it be input material flow rates or production
flow rates.  Gathering this data increases the. testing or monitoring
necessary and consequently increases the costs.  Manipulation
of this data increases the number of calculations necessary,
compounding the error inherent within the data and increasing
the chance for human error.
     Enforcement of concentration standards, however, requires
a minimum of data  and information, decreasing the costs and
minimizing the chances for error in determining compliance.
Concentration standards are also somewhat more consistent with
the concept of basing standards of the  "best systems of emission
 reduction," since  vendors  of  emission  control equipment normally
 guarantee  the  performance  of  their equipment in terms  of  the
 concentration  of  emissions  discharged.
     The  primary  disadvantage normally associated with concen-
 tration standards  is  that  of  possible  circumvention  by dilution
                              9.15

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  of the  gases discharged to  the  atmosphere lowering 'the concen-
  tration of  emissions,  but not reducing the total mass emitted.
  To ensure that compliance with  concentration standards is not
  achieved by dilution,  however,  section 60.12 of 40 CFR Part 60
  specifically prohibits the  use  of dilution as a means of complying
  with concentration standards.
      Consequently, considered primarily from the perspective of
  enforcement, concentration standards are selected as the format
  for standards of performance for refinery sulfur plants.   The
  lower resource requirements of concentration standards over
 mass standards far outweigh their drawbacks.
  9.5  SELECTION OF EMISSION LIMITS IN THE STANDARDS
      Specific emission limits need to be selected  to limit
 emissions of S02 from refinery sulfur plants  which employ  either
 oxidation-scrubbing emission control  systems  or  reduction-scrubbing
 emission control  systems with tail  gas  incineration.   Emission
 limits  also  need  to be selected  to  limit  emissions  of  H2S  and
 reduced  sulfur compounds (H2S, COS  and CS2) from refinery  sulfur
 plants which employ reduction-scrubbing emission control systems
 without  tail gas  incineration.
     The  data and information to support selection of these emission
 limits is summarized in chapter 4 and consists primarily of emission
 source tests by the Agency or local air pollution control  agencies.
Since the amount of emission data available is quite limited,  a
number of factors need to be considered in selecting the  specific
emission limits.
                              9.16

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     Considering first the limit for S02 emissions,  the emission
source test data from oxidation-scrubbing emission control  systems
shows emissions in the range of 10-50 ppm (tests A-j, A2, A3,
Figure 4-10).  These data, however, were collected from a unit
operating at less than half its design capacity immediately
following a major equipment turnaround.  Consequently, the data
do not reflect emission levels that could be maintained by a
unit operating at full capacity over a period of time.  According
to both vendors and owners and operators, unavoidable equipment
deterioration and chemical aging will lead to lower efficiency.
Generally, these systems operate for about a year between major
equipment turnarounds and during this time, emissions increase
by as much as  100 to  200 ppm.  Basing the emission  limit solely on the
basis of this  emission data, therefore, would significantly
shorten the  normal  run length  between major turnarounds and
increase maintenance  and  chemical  replacement costs considerably.
      The emission source  test  data available from reduction-scrubbinq
emission control  systems  with  tail  gas  incineration shows  emissions
of  about 200 ppm S02  (test  C,  Figure 4-10).  Although  this  data
is  not  EPA  data,  but  is data  from  a test bv a  local control  agency
 (EPA's  source testing at  this  facility  was  invalidated  due  to
operating  problems),  the  source testing method  emploved by  this
local  aqency is considered  comparable  to EPA's.
                               9.17

-------
      This emission level, however, is considered higher than normal
 for a typical reduction-scrubbing emission control  system with tail
 gas incineration.  According to the operators at this source, this
 particular facility is significantly under-designed and,  in fact,
 shortly after this emission test data was gathered, it was "de-
 bottle-necked" and expanded to improve its performance.
      In EPA's discussions with the vendors of this  facility, they agreed
 with the operators that it was "under-designed."  They also indicated,
 however, that emissions from typical  reduction-scrubbing  emission
 control  systems  with  tail  gas incineration are normally comparable
 to  those from oxidation-scrubbing emission control  systems,  and that
 emissions  from both systems increase  to  about the same extent between
 turnarounds due  to unavoidable equipment deterioration and  chemical
 aging.
     As  pointed  out in  chapters  4 and  7,  the  reduction-scrubbing
 emission control  systems with  tail  gas incineration  (as opposed
 to  those without tail gas  incineration)  have  a  number  of  advantages
 over oxidation-scrubbing emission  control  systems.  Operation
 of  these systems  involves  techniques with  which most refiners
 have had a great deal of experience and  thus  refiners  understand
 these systems  better, tend  to  experience fewer  problems with them
 and generally  tend to favor these  systems.  More importantly, however,
 these reduction-scrubbing emission control systems with tail gas
 incineration produce no wastewater streams that require disposal.
Both the oxidation-scrubbing systems and the reduction-scrubbing
systems without tail  gas incineration generate a wastewater stream.
                               9.18

-------
     Considering all  these factors, the emission limit for S02
emissions is set at 250 ppm.   This limit applies to both the
oxidation-scrubbing emission control systems and to the reduction-
scrubbing emission control systems with tail gas incineration.
In view of the limited emission data available and the comments
of. both the owners and operators and the control system vendors,
this appears to be a reasonable emission limit consistent with the
performance of these emission control systems.  This limit will
also ensure that these alternative II emission control systems are
installed and well operated.
     Considering the emission limit for emissions of H2S and reduced
sulfur compounds, the available emission source testing data from
reduction-scrubbing emission control systems without tail gas
incineration shows that emissions of these  pollutants  from  these
systems  are quite low.  Emissions of H2S, for example, were
frequently  not  detectable (tests  B], B2, E1 and F-J , Figure  4-11).
In  the one  test in which  emissions  of H2S were detected  (test  B2),
an  analytical method different  from  that employed  by  the Agency
was used and simultaneous testing by the Agency detected no emissions
(test  63).   Review of  both the  Agency's test method and  this  other
test method indicated  that this method which  detected  H2S  emissions
was not  as  selective  as  the  Agency's in  identifyina I'2S,  and was
 including some  of the  COS and C$2 present  as  H?S.
     The emission source  test data available  on emissions  of reduced
 sulfur compounds (H2S, COS and  CS2)  from  these  emission control
                               9.19

-------
 systems shows that emissions  of these pollutants  are in  the  range
 of 10-20 ppm (tests B-,,  82-,,  B3,  E-,  and  F-,,  Figure  4-12).  Here
 again,  however,  this data  was collected  from these  systems shortly
 after major equipment turnarounds, or when they were operating
 well  below their design  capacity  (as  low as  1/3 of  design capacity
 in one  case).
      Discussions with the  vendors of  these control  systems also
 indicated  that unavoidable equipment  deterioration  and chemical
 aging leads  to a gradual increase in  emissions with  time.  Pilot
 plant data,  for  example, indicates that  emissions increase by
 about 200  ppm  over  a vear's operation.   Thus, as discussed above
 for the  oxidation-scrubbing systems and  the  reduction-scrubbing
 systems  with tail gas  incineration, basing the emission  limits
 for reduction-scrubbing emission control  systems without tail gas
 incineration solely  on the emission data  available would significantly
 shorten  the normal run length between major  turnarounds  and increase
 the costs of maintenance and chemical replacement considerably.
     Considering these factors, the limit on emissions of H2S
 and reduced sulfur compounds from reduction  scrubbing emission control
 systems without  tail gas incineration is  set at 10 ppm and 300 ppm
 respectively.  The 10 ppm limit on H2S emissions will ensure that
 installation of these emission control systems will  not lead  to  a
local  odor air pollution problem.   The 300 ppm limit is equivalent
to the 250 ppm limit on S02 emissions in the sense that both  limits
reduce sulfur emissions—be they S02  or H2S,  COS  and CS2—to  the

                                9.20

-------
same level.  (The 250 ppm S02 limit reflects the larger volume
of gases discharged to the atmosphere.)
9.6  SELECTION OF MONITORING REQUIREMENTS AND PERFORMANCE TEST METHODS
     The objective of monitoring reouirements is to provide a quick
and easy means for enforcement oersonnel to ensure that an emission
control system; installed to comply with standards of performance
is DTOp-erly operated and maintained.  For refinery sulfur recovery
olants» the most straightforward means of ensuring proper operation
ancf maintenance is to monitor emissions released to the atmosphere.
Consequently, where oxidation-scrubbing processes or reduction-
scrubbing processes with tail gas incineration are installed to
comply- with the standards, monitoring of S02 emissions is required.
Where reduction-scrubbing processes without tail gas incineration
are installed, monitoring of H£S and reduced sulfur compound emissions
is required.
     Although monitoring requirements are included for l^S and
reduced sulfur compound emissions, the Agency has not yet developed
performance specifications for these monitors.  Consequently, owners
and operators of reduction-scrubbing emission control systems without
tail gas incineration, who are subject to these requirements, will
not have to install these monitors until these specifications have
been promulgated in the Federal Register.  The requirement for
monitoring is included in the regulations to ensure that when
these monitors become available, sources which became subject
to standards of performance before the monitors were available
will then be required to install monitors to aid enforcement personnel
in determining if the emission control  system is being properly
operated and maintained.
                              9.21

-------
     For determining compliance with the standards, Method 6 -
Determination of Sulfur Dioxide Emissions from Stationary Sources
will be used where oxidation-scrubbing processes or reduction-
scrubbing processes with tail gas incineration are installed.
Where reduction-scrubbing processes without tail gas incineration
are installed, Method 18 - Determination of Hydrogen Sulfide,
Carbonyl Sulfide and Carbon Disulfide Emissions from Stationary
Sources will be used.  These methods were the methods used to gather
the emission data contained in chapter 4 and Appendix C, which support
the standards.  Details as to why these methods were selected over
other methods for gathering this data mav be found in Appendix D.
9.7  REFERENCES
1.  Telephone conversation, F.L. Porter (EPA) with G.L. Tilley
    (Union Oil), April 28, 1976.
                                9.22

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      APPENDIX A



EVOLUTION OF STANDARDS
          A.I

-------
                      EVOLUTION  OF STANDARDS
8/73




9/73


10/5/73



10/10-10/19/73



10/17/73


11/73




10/73-2/74
 Surveyed and  reviewed  process  operations  and
 emission control  systems  for all  domestic
 Glaus  sulfur  recovery  plants.

 Sent letters  to  control enuinment vendors
 requestina  desion data for  the Wellman-Lord,
 Beavon,  Cleanair, SCOT, and Aquae!aus  orocesses,
.and  location  of  well-controlled Claus  nlants.

 Selected eioht refineries for  initial  nlant
 inspections.

 Contracted  for detailed ennineerina  studv of
 Claus  tail  gas control  systems v/ith  Battelle-
 Columbus.

 Inspected eiqht  refineries  with well-controlled
 Claus  plants, pre-surveyed  for emission testina,
 and  sent 114  letters to refineries.

 Met  with Los  Anqeles APCD for  discussion  of
 their  regulations for  sulfur recovery  plants.

 Contractor  sent  additional  letters to  vendors
 for  design  data  on the IFP-1,  IFP-2, Sulfreen,
 Cataban/and  Chivoda Thoroughbred processes
 for  tail qas  sulfur removal.

 Test methods  for determining gaseous sulfur.,
 compounds  in  Claus tail gas ("i.e., COS, ,C.S2i
 H2$, S0£, Sx) investigated  and developed.
 Presurveys  made  of three  likely test sites.
1/11/74


2/25-3/13/74
 Inspection made of IFP-1  process  on  a  Claus
 sulfur plant.

 Emission tests completed  for Mellman-Lord,
 Beavon, and SCOT control  svstems.
                                  A.2

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4/1/74



5/7/74



6/10-6/12/74

6/74




8/74- 2/75
3/75


4/29/75


5/5-5/6/75



5-7/75



8-9/75


10/75-4/76
Inspection made of second IFP-1 orocess on a
Glaus sulfur plant.  114 letters on IFP-1
process sent to operators.

Meeting with API's Committee on Environmental
Affairs to discuss emission test.results and
Dotential standards.

Emission test of IBP-1 control system completed.

Study entitled "Characterization of Sulfur
Recovery From Refinery Fuel Has" completed
by BatteH e-Columbus Labs.  Report circulated
to API for review.

Emission control costs developed, monitoring
and emission test methods finalized, and
dispersion analyses completed.  Developed first
draft of EPA Standards Support and Environmental
Impact Document (SSEID).

Revised SSEID and sent to NAPCTAC and Workina
Group members.

Met with EPA Uorkinn Group to discuss findinas
of SSEID and the recommended standard.

Met with NAPCTAC to review the recommended
standard for refinerv sulfur plants and the
basis 'for the standard outlined in the SSEID.

Delayed action to resolve potential 111(d)
aspects of standards for refinery sulfur
plants.

Responsibility for SSEID informally trans-
ferred to Standards Development Branch.

SSEID reviewed, edited and rewritten by
Standards Develonment Branch to conform
with the general outline for a SSEID.
                                 A.3

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                  APPENDIX B



INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS
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INDEX TO ENVIRONMENTAL IMPACT CONSIDERATIONS (continued)
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-------

-------
       APPENDIX C



EMISSION! SfMECE TEST DATA*
           C.I

-------
                      EMISSION SOURCE TEST DATA
 C.I   INTRODUCTION
      This appendix summarizes the emfssion test data gathered during
 the  development of standards for refinery sulfur plants.   Detailed
 information on each facility tested is  presented herein.   Each
 facility is identified by the -same coding used in Chapter 4.   Any
 reference in this appendix to commercial  products or processes
 by name does not constitute an endorsement by  the Environmental
 Protection Agency.
 C.2   SUMMARY OF TEST DATA
      Four different processes for removing sulfur from Claus
 sulfur plant exhaust gases  were tested  by EPA  to  determine the
 best  available  control  technology as  required  by  section  111
 of the Clean Air Act.   Pollutants measured included  total sulfur
 by EPA Method 18 (gas  chromatograph/flame photometric detection),,
 SOg by EPA Method 6,  H2S  by EPA Method  11,  carbon monoxide .by
 EPA Method 10,  NOX  by EPA Method 7, hydrocarbons  by  a flame
 ionization detector,  Orsat  gases by EPA Method 3, and moisture
 by EPA Method 4.
 C.3   DESCRIPTION OF FACILITIES
      Plant A -  Plant A  consists  of three  fdentfcal 150 long ton/day
 (LT/D)  Claus trains, two  of which operate with the third on stand-by.
 Emissions  from  each Claus train  is controlled by a Wellman-Lord
 scrubber.   Design basis of these Wellman-Lord scrubbers is 250 ppmv
 SOg.   Tests Al  and A2 were performed by EPA and refinery personnel,
 respectively, during the period March 11-13, 1974.   In Test Al
sulfur compounds were determined by EPA Method 18 (gas chromatograph/
flame photometric detection) for total sulfur and EPA Method 6 for S02,
                               C.2

-------
Carbon dioxide, carbon monoxide, and oxygen were determined by continuous
methods (non-dispersive infrared for C02 and CO and paramagnetic for 02)
and by the Orsat method.  Nitrogen oxides were determined by EPA Method 7,
visible emissions by EPA Method 9, moisture and flow rates by EPA
Methods 1, 2, and 4, and hydrocarbon concentrations by a flame
ionization detector.
     In Test A2 SO? and NO  were determined by a fuel cell electro-
                  £       X
chemical method, COS and CS2 by a gas chromatograph flame photometric
detector, CO and C02 by Orsat, 02 by Orsat and a paramagnetic oxygen
analyzer, and hydrocarbons By a hydrogen flame gas chromatograph.
     During Tests Al and A2 only one sulfur plant was operating
due to low refinery throughputs, caused by the OPEC oil embargo.
Sulfur feed rates during the tests averaged 113 LT/D for three runs.
     Test A3 was conducted by the Los Angeles APCD, January 10-11, 1973,
on all three Claus plants.  Hydrogen sulfide was determined by a ZnC03
impinger train,  and S02 by impingers containing a 5% NaOH solution.
Nitrogen oxides, hydrocarbons, carbon monoxide, carbon dioxide,
moisture, and flow rates were determined according to methods described
In the Source Testing Manual of the Los Angeles APCD.
     Sulfur feed to the three plants during Test A3 was 116.6, 76.9,
and 68.8 LT/D,  respectively, averaging well below design  rates.
     plant B -  Plant B  consists of two parallel 100 LT/D  Claus trains,
each of which exhausts  into a Beavon tat!  gas treating unit.  Design
basis  of each Beavon tail gas treating unit is  200 ppmv total sulfur,
with less than  10 ppmv  H2S.

                               C.3

-------
     Tests Bl and B2 were performed by EPA and refinery personnel,
respectively, during the period March 5-7, 1974.  In Test Bl sulfur
compounds were determined by EPA Method 18 (gas chromatograph/flame photo-
metric detection) for total sulfur and EPA Method 6 for S02.  Carbon
dioxide, carbon monoxide, and oxygen were determined by continuous
methods (a non-dispersive infrared instrument for C02 and CO, and
paramagnetic analyzer for 02) and by the Orsat method.  Nitrogen
oxides were determined by EPA Method 7, visible emissions by EPA
Method 9, moisture and flow rates by EPA Methods 1, 2, and 4,
and hydrocarbon concentrations by a flame ionization detector.
     In Test B2 mass spectrometry was used to determine CH4, COS,
S02> H£S, C$2, H2j CO/N2» 02, Ar, and C02.  Gas chromatography
was then used to obtain the CO/N2 split.
     During Tests Bl and B2 the sulfur plants were operating well
below design levels due to the OPEC oil embargo.  Sulfur feed rate
to each or both Claus tra?n(s) averaged 34.2 LT/D for three runs.
     Test B3 was conducted by the Los Angeles APCD on three separate
occasions:  July 10, August 8, and September 24, 1974.  The August 8
and September 24 tests were performed before and after overhaul  to
determine the effect of overhaul  on emissions.
     Sampling techniques included a 5% HC1 solution in an impinger
to collect ammonia, a 3% ^2^2 solution in an impinger to collect
SOgj and a ZnCOs slurry in an impinger for H2S collection.  Grab
samples were made for subsequent determinations of H2S, COS, and
CS2 by gas chromatograph with a flame photometric detector and
carbon monoxide by non-dispersive infrared absorption.
                                 C.4

-------
     Plant C - Plant C consists  of one small  16 LT/D, two-stage
Claus unit followed by a SCOT tail gas treating unit.  Design
basis of the SCOT unit is 400 ppmv total  sulfur emissions calculated
as H2S.  An incinerator oxidizes the 400 ppm H2S to S02 before
discharge to the atmosphere.
     Test C3 was conducted by the Los Angeles APCD on February 14, 1974.
Hydrogen sulfide was determined by a ZnCOs train at the outlet of the
SCOT system.  At the incinerator stack S02 was determined by an NaOH
train; combustion gases (CO, C02, and CH4) were analyzed by total
combustion analysis using a non-dispersive infrared instrument
and NOX was determined by hydrogen peroxide/sulfuric acid impinger
trains.  Water vapor, gas flow and Orsat gases were also analyzed
using  Los Angeles APCD methods.
     During Test C3 sulfur feed averaged 11:1 LT/D.
     plant D  - Test Dl was conducted June 10-12, 1974,
by EPA on a large, 395 LT/D, three-stage Claus plant followed by
an IFP-1  tail  gas process.  The Claus nlant  recovers sulfur  from
acid gases produced in a  carbon disulfide plant.  Emission design
for  the  IFP-1  unit  is 90  percent  conversion  of (H2S  +  S02) from  the
Claus  plant.   This  corresponds  to 1640 ppmv  total sulfur (wet) or
2540 ppmv total sulfur  (dry).
      In  the first test  total sulfur compounds  were determined by EPA Method  18
 (gas  chromatograph/flame  photometric detection).  S02  was determined by
 EPA  Method  6, H2S by  EPA 'Method 11,  NOX  by EPA Method  7, moisture
 by  EPA Method 4,  gas  flow by EPA  Methods 1 and 2, and  visible
 emissions by  EPA Method  9.   C02,  CO and  02 were  determined by

                             C.5

-------
continuous methods (non-dispersive infrared for C02 and CO, para-
magnetic analyzer for 02).  C0£ and 02 were also determined by a gas
chromatograph with thermal conductivity detection.
     The second test was conducted using a Meloy Analyzer, which
oxidizes all sulfur compounds to S02 and then measures S02 by a
flame photometric detector.  The third test was conducted using
a DuPont analyzer, which also oxidizes all sulfur compounds to
S02> but which then measures S02 by UV absorption.
     During these tests, sulfur feed to the Claus unit averaged
336 LT/D.
     Plant E - Plant E consists of two 96 LT/D Claus plants each with
a Beavon tail gas treating unit.  Test El was conducted December 12,
1974, by the Los Angeles APCD.   Analyses for COS, CS_, H-S, SO ,
     , total sulfur, CO, and NOX were conducted.   Details on test
methodology were not specified, though assumed the same as in previous
tests conducted by Los Angeles County (Tests A3 and B3).  No process
data were available.  The Beavon units were designed at 200 ppmv
total sulfur, 10 ppmv I^S emission levels.
     Plant F - Plant F consists of a Beavon tail  gas treating unit
which removes sulfur from four combined Claus plant tail gas streams
in a petroleum refinery.  No design or operating  data are available.
Los Angeles County conducted tests November 6, 1974, for total
sulfur, H2S, and carbon monoxide (test Fl).  Again, test methods
are assumed to be Los Angeles APCD methods  as described for
Tests A3 and B3.
                               C.6

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                                 Table 1
                               FACILITY A
                           Summary of Results
Test Number
Run Number
Date
•Stack Effluent:
  Flow rate - DNMJ/min
  Water vapor - Vol. %
  C02  - Vol. % drya
  02 - Vol. % dry9
  CO - Vol. % dry3
  C02 - Vol
  02 - Vol.
  CO - ppmv dry
 dryc
dryb
 b
  S02 - ppmv dryc
  S02 - ppmv dry
  COS - ppmv dry
  CS? - ppmv dry
                 .
  I^S - ppmv dry
  TS - ppmv dry
  NOX - ppmv dry6
  THC - ppmv dry
  Visible emissionsS
                               Al
                    1           2
                 3/11/74     3/12/74
                  197.1
                   13.0
 4.3
 0.9
95
 5.9
38
 3.2
 2.5
<0.1
46.2
17.2
 7.5
 0
135.4
 10.6
  7.2
  0.8
  0.0
  5.6
  0.2
100
 21.8
 16
  1.9
  3.4
 <0.1
 24.7
  9.0
  6.2
  n
3
3/13/74
209.7
11.2
5.35
2.95
0.0
3.8
1.5
39
7.4
10
0.9
1.1
13.1
21.0
4.6
0
Averagi

180.4
11.6
6.3
1.9
0.0
4.6
0.9
78
11.7
21
2.0
2.3
•f~ r\ i
^ w • 1
28
15.7
6.1
0
 Orsat analysis
 NDIR/Paramagnetic
CEPA-6
dGC/FPD (EPA-18)
SEPA-7
 Total hydrocarbons as methane by flame ionization
9EPA-9
Source:  Reference 1                  ^"'

-------
Test Number
Run Number
Date
Stack Effluent:
  Flow rate DNM3/MIN
  Water vapor - vol.
  C02 - vol. % drya
  02 - vol. % dr.va
  CO - vol. % drya
  S02 - ppmv dryb
  COS - ppmv dryc
  CS2 - ppmv dryc
  NOX - ppmv dryb
  HC - ppmv dryd
      TABLE 2
    FACILITY A
Summary of Results

              A2
   1            2
 3/12/74     3/13/74
   6.6
   1.3
   0.3
  10
   0.3
   1.5
  21.7
   3.0
15
25
          Averane
 6.6
 1.3
 0.3
12.5
 0.3
 1.5
23.4
 3.0
  Orsat  analysis
  fuel cell  electrochemical
 CGC/FPD (EPA-18)
  Hydrogen  flame  chroma!oaraphy
  Source:   Reference  2
                                     C.8

-------
                                 TABLE  3
                               FACILITY A
                           Summary  of Results
Test  Number
•Run Number
Date
Stack Effluent:
   Flow rate,  DNM3/M
   Water vapor -  vol.
   C02 - vol.  % wet
   CO  - vol. % dry
   SOg - ppmv  dry
   H2S - ppmv
   COS - ppmv
   C$2 - ppmv
   NOX - Ib/hr
   HC  - Ib/hr

1
1/10/73
229.37
14.0
16.0
0.36
31
<.10
15
13
0.57
0.90
A3
2
1/11/73
150.08
10.0
16.0
0.20
38
<.10
1
2
0.59
0.44

3
1/11/73
127.43
12.0
19.0
0.067
47
1.7
<1
1
0.46
0.21

Averaqe

169.05
12.0
17.0
0.41
40
0.6
6.0
5.7
0.54
0.52
 Source:   Reference  3
                                     C.9

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                                 TABLE 4
                               FACILITY B
                           Summary of Results
Test Number
Run ftaber
Date
Stack Effluent:
  Flow rate, DNM3/M
  Water vapor - vol
  C02 - vol. % drya
  02 - vol. % drya
  CO - vol. % drya
  C02 - vol. % drvb
  02 - vol. % dryb
  CO - vol. % dryb
  S02 - pwnv dryc
  S02 - ppmv drvd
  COS - ppmv dryd
  CS2 - pomv dryd
  H2S - ppmv dryd
  TS - ppmv dryd
  NOV - ppmv dry6
    *           f
  THC - ppmv dry7
Visible emissions

1
3/5/74 .
65.5
4.2
5.4
0.6
0
5.8
0.02
566
3.6
1.5
17
0.15
19
1.1
Bl
2
3/6/74
71.6
5.0
5.5
0.5
0
5.7
0.09
565
3.8
0.7
17
-
17
0

3
3/7/74
68.8
3.3
6.0
0.3
0
5.9
0.02
604
4.5
0.76
15
-
16
0

Average

68.6
4.2
5.6
0.5
0
5.8
0.04
578
4.0
1.0
16
-
17
0.4
0
 Orsat analysis
 NDIR/Paramagnetic
 cEPA-6
 dGC/FPD  (EPA-18)
 eEPA-7
 Total hydrocarbons as methane by flame tonization
 9EPA-9
 Source:   Reference  A
                                 C.10

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                                TABLE 5
                              FACILITY B
                          Summary of Results
Test Number
Run Number
Date
Stack Effluent:
  Flow rate, DNM3/M
  Water vapor - vol,
  H2 - vol. %
  CO - ppm
  CH4 - ppm
  N2 - vol. %
  02 - vol. %
  H2S - ppm dry
  Ar - vol. %
  COo -vol.  %
  COS - ppm dry
  SOg - ppm dry
  C$2 - ppm dry

1
3/5/74
5.0
479
125
87.7
0
7
1.0
63
9
0
0
B2
2
3/6/74
6.0
620
206
87.0
0
1
1.0
6.0
9
0
0

3
3/7/74
5.8
595
332
86.9
0
0
1.0
6.3
9
5
0
Averaae
  5.6
565
221
 87.2
  0
  2.7
  1.0
  6.2
  9.0
  1.7
  0
 Source:  Reference 5
                                 c.n

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                                TABLE  6
                              FACILITY B
                          Summary of Results
Test Number
Run Number
Date
Stack Effluent:
  Flow rate, DNM3/M
  Water vapor - vol,
  C02 - vol. %
  CO - ppm
  S02 - ppmv dry1
  COS - ppmv dry1
  CS2 - ppmv dry1
      - ppmv dry1
                   B3
  1
7/10/74
  2
8/8/74
  3

9/24/74
  4

9/24/74
Averane
-
0
23.0
9.7
0
-
0
16.0
0
0
346
0
6.8
0
0
335
0
7.0
0
0
341
0
13.0
2.4
0
Source:  Reference 6
Note:
T  "Assume moisture level of 5.6% based on test 62-
                                C.12

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                                 Table  7
                                FACILITY C
                            Summary  of Results
Test Number
Run Number
Date
Stack Effluent:
  Flow rate - DNM3/M
  I-LS - ppmva
  u c       b
  H9S - ppmv
  S02 - ppmva
  S02 - Ib/hr1
  SO
  NO
    x
      - Whr
            b
      - ppmv
  CO - ppmv
  02 - Vol.
  C02 - Vol .
  HC - Vol .
                                                 2/14/74
  11.33
 197
 <10
   0
   5.5
   0
  14
1500
  12.5
 Incinerator inlet
 Incinerator outlet
Source:  Reference 7
                                  C.13

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Test Number
Run Number
Date
Stack  Effluent:
       \
      Table 8
    FACILITY D
Summary of Results
                 (See below)
   1           2           3
6/10/74     6/11/74     6/12/74
Average
Flow rate - DNM°/min
Water vapor - Vol . %
C02 - Vol . % drya
02 - Vol . % drya
CO - Vol. % drya
C02 r Vol . % dry5
02 - Vol. % dryc
CO - ppmv dry
S02 - ppmv dry
S02 - ppmv dry6
S02 - ppmv dry
COS - ppmv dryf
H?S - ppmv dry
f
CSp - ppmv dry
TS (l)""""- ppmv dryf
TS (2) - ppmv dry6
TS (3) - ppmv dry9
NO - ppmv dry
421
30.9
1.3
0.28
_
1.5
0.1
3240
59
420
82
132
1190
460
2310
2390
2380
7.8
431
37.7
1.1
0.35
_
1.6
_
2450
42
430
72
77
1410
180
1920
2590
2540
1.0
414
39.0
1.1
0.31
—
1.8
0.1
3140
42
360
80
133
1950
300
2760
_
2070
4.0
422
35.9
1 .2
0.31
..
1.6
0.1
2940
48
400
78
114
1520
310
2330
2490
2330
4.3
Visible emissions1
aOrsat
bNDIR
 paramagnetic
dEPA-6
Q
 DuPont Analyzer(includes elemental  sulfur)
fGC/FPD (EPA-18)
9Meloy Analyzer
hEPA-7

 EPA-9
Source:  Reference 8
                               C.14

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                                Table 9
                               FACILITY  E
                            Summary  of Results
Test Number
 Run Number
 Date
 Stack  Effluent:
   Flow rate,  DNM /tnin
   Water vapor -  Vol. %
   COS  - ppm dry1
   CS2  - ppm dry1
   H2S  - ppm dry1
   S02  - ppm dry1
   S04  - ppm wet
   H2S04 - ppm wet
   TSa  - ppm
   TSb  - ppm
   CO - ppm wet
   N0v(as N0?) - ppm wet
     X      £•
   El
    1
12/12/74
    5
    0.5
   <1
   <0.4
    2
   <0.3
    8+
   14
   250
    I
 aTotal of separately measured constituents
 bTotal as measured by sulfur detector  (includes mercaptans)
 Source:  Reference 9
 Note:
 1.  Assume moisture level of 5.6% based on test 82-
                                  C.15

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                                 Table 10
                                FACILITY F
                            Summary of Results
 Test Number
 Run Number
 Date
 Stack Effluent:
   Flow rate -  DNM3/M
   COS -  ppm dry
   C$2 -  ppm dry
   H2S -  ppm dry
   S02 -  ppm dry
   Total  sulfur - ppm dry
   CO  - ppm  dry

Source:  Reference 10
  Fl
11/6/74
   311.49
    15.2
     0.1
     0
     0
    15.4
   670
                                C.16

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References
     1.  Source Test Report No.  74-SRY-l,  EPA Contract  No.  68-02-0232,
Task Order No. 34, Environmental  Science  and Engineering,  Gainesville,
Fla., March 1974.
     2.  Letter, Thron Rigqs, Standard Oil  Co. of California  to  C.  Sedman,
ESED, OAQPS, EPA, dated August 9, 1974.
     3.  Source Testing Section Report No.  C-1895, Los  Anqeles County APCD,
February 28, 1973.
     4.  Source Test Report No. 74-SRY-2, EPA Contract  No. 68-02-0232,
Task Order No. 34, Environmental Science and Enqineerina,  Rainesville,
Fla., March 1974.
     5.  Letter,  George L. Tilley, Union Oil Company of California, to
C.  Sedman, ESED,  OAQPS, EPA, dated Auaust 26, 1974.
     .6.  Source Testing Section Report No. C-2082, Los  Anaeles County,
APCD,  Dec. 27,  1974.
     7.   Source Test  Section  Report Mo. C-2104,  Los Angeles County, APCD,
 April  25,  1974.
     8.   Source Test  Report  No.  74-SRY-4,  EPA Contract No. 68-02-0232,
 Task Order No.  34,  Environmental  Science and Engineering  Gainesville,
 Florida, June 1974.
     9.   Source Testing  Section  Report No.  C-2234, Los Anaeles  County APCD,
 Feb. 20, 1975.
     10.   Source Testing  Section  Report No.  C-2226, Los Angeles  Countv APCD,
 Nov. 6, 1974.
                                    C.17

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                  APPENDIX  D



EMISSION MEASUREMENT AND CONTINUOUS MONITORING
                      D.I

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 D.I  EMISSION MEASUREMENT METHODS
      A review of the literature revealed that four different
 analytical methods could be used for analysis of sulfur compounds:
 colorimetry, coulometry, direct spectrophotometry, and gas
 chromotography.   Although these methods were developed in most
 cases for measurement of ambient air concentrations,  this did  not
 preclude their application to measurement of stack gas emissions.
      Colorimetr.y.   In this method a  sample is bubbled through  a
 solution which selectively absorbs the component or components
 desired.   The solution is then reacted with  specific  reagents  to
 form  a  characteristic color which is  measured spectrophotometrically.
      An example  of a  colorimetric method  is  the  methylene blue
 method  which involves the absorption  of reduced  sulfur compounds
 in  an alkaline suspension of cadmium  hydroxide to  form a  cadmium
 sulfide precipitate.   The precipitate  is  then reacted with a
 strongly  acidic  solution  of N,  N  dimethyl-P-phenylene-diamine  and
 ferric  chloride  to give methylene  blue, which is measured spectro-
 photometrically.  Automated  sampling and  analytical trains using
 sequential techniques  are  available for this procedure.   Inherent
 deficiencies for stack sampling applications however include
 variable  collection efficiency, range  limitations, and interference
 from  oxidants.
      Another colorimetric method is the use of paper tape samplers
 impregnated with either lead acetate or cadmium hydroxide.  These
 compoundsreact specifically with H2S to form a colored compound
which can be measured directly with a densitometer.  Tape samplers
                            D.2

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would not be appropriate for all reduced sulfur compounds unless
they were first reduced quantitatively to H^S.  In addition, the
range is limited, the method requires precise humidity control and
suffers from light sensitivity, fading, and variability in tape
response.
     Coulometry.  In this method a gas sample is bubbled through
a  solution  containing an oxidizing or reducing agent  (titrant).
The concentration of the titrant in  solution  is buffered by  the
 presence  of a  titrant precusor. Passage  of an electric current
 through the solution  causes the titrant  precusor  to break  down,
 releasing additional  titrant into  solution.  Consequently, as the
 titrant is consumed by  reaction with specific compounds  contained
 in the gas sample,  an electric current is passed  through the
 solution to maintain the titrant concentration.   The electric
 current required is a measure  of the reactive compounds in the
 gas sample.   Normally, the titrant  is a free halogen such as
 bromine or  iodine in solution  as an oxidizing agent, or a metal ion
 such as  silver  in solution as  a reducing.agent.
      For  determining emissions coulometric titration has  the
 advantage of  responding to a wide variety  of sulfur  compounds.  The
 response to each compound  is quite  different, however, and  this
 makes  standardization  and  reporting of  data  difficult  in  many cases.
  In addition,  the method suffers from high  maintenance  and requires
  frequent calibration to reduce drift to acceptable levels.
       Spectrophotometry.  Although infrared and mass spectrophotometric
  methods are well established  analytical techniques, most of these
                               D.3

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seven-fold that to S02> S02 cannot be analyzed by this method
if appreciable elemental sulfur is present.  The Model 464
has not yet been used as a continuous monitor in sulfur recovery
pi ants.
     Gas cJiromatography/flame photometric detection (GC/FPD) is
another method for monitoring SC^ emissions.  Systems using
this principle include the Bendix Model 8700, Tracer Model 250H.
These systems cost about the same as the DuPont 464 system discussed
above and are also semi continuous in operation.  Recently, however,
one vendor announced a complete sampling, analysis, and recording
system for $14,000 (Tracer Model 270H).  Again, automated data
reduction can be added at additional cost.  Integrators compatible
with GC analyzers can be programmed to print the concentration of each
sulfur compound.  Cost of these integrators is in the range of
$3,000-$49000.
     The GC/FPD system has several advantages.  It can separate and
detect each individual sulfur comoound.  These systems are extremely
sensitive, however, and require sample dilutions of 100:1 or more.
This presents a potential source of error and frequent calibration
is necessary to minimize such errors.
     Other continuous monitoring instruments are commercially
available.  Many of these are summarized according to their
capabilities by Nader et.al. (EPA-650/2-74-013).  To date, however,
they have not been evaluated for use on sulfur plants.
                              D.6

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                 For montiroing emissions of total sulfur and H^S, the two
            systems described previously can be used.  The Da-Font Model 454
            ultraviolet analyzer is capable of oxidizing the gas sample and
            measuring all sulfur compounds including elemental sulfur as SCh?.
            This system, however, is not able to monitor  H^S emissions.
                 The GC/FPD system: is capable of monitoring individual sulfur
            emissions (except sulfur vapor).  Total sulfur can be determined
            by adding the individually measured components tp the estimated
            sulfur vapor.  Sulfur vapor may be calculated from the partial
            pressure of sulfur at the gas stream temperature.  Since H^S
            vapor is one of the compounds determined by GC/FPD„ it can be
            reported separately.
                 Although continuous monitors are available to monitor emissions
            of reduced sulfur compounds, compliance with the monitoring
            requirements included in the standards will he delayed until
            EPA promulgates performance specifications for these monitors.
                 Since the standards specify that emissions must be determined
            at zero percent oxygen, continuous monitorinq of the oxygen concen-
            tration in the tail gases discharged to the atmosphere is required.
            A number of systems are available to monitor oxygen concentration
            and performance specifications for these systems were promulgated
            by EPA in 40 FR 46268 on October 6, 1975.
            D.3  PERFORMANCE TEST METHODS
                   EPA Method 18,  "Semicontinuous  Determination of Sulfur
            Emissions from Stationary Sources,"  has  been  prepared for use
            in  determining compliance with  new  source  performance standards at
            refinery sulfur plants.  This method  requires  use of  the  GC/FPD

                                             D.7
	UU—UNC—[J UfcM-l-Vj—I-I=CC—U-l	\^l-Itl-l-^C	I-I-UIII .     =
  Public Information Center (PM-21:5), EPA,
2O. SECURITY CLASS (TKispage)
    Unclassified
                          22rPRl'CE-
EPA Form 2220-1 (9-73)

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system discussed above and utilized during the emission testing

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