United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-90-016b
March 1993
Air
Reactor            Final
Processes in the  EIS
Synthetic Organic
Chemical
Manufacturing
Industry--
Background
Information for
Promulgated
Standards

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                           EPA-450/3-90-016b
  Reactor Processes in the
Synthetic Organic Chemical
  Manufacturing Industry -
  Background Information
for Promulgated Standards
           Emission Standards Division
        U.S. ENVIRONMENTAL PROTECTION AGENCY
           Office of Air and Radiation
        Office of Air Quality Planning and Standards
        Research Triangle Park, North Carolina 27711
             March 1993

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               U.  S.  ENVIRONMENTAL PROTECTION AGENCY

                      Background Information
             and Final Environmental Impact Statement
              for  Volatile Organic Compound Emissions
                     from Reactor Processes in
             Synthetic Organic Chemical- Manufacturing

                           Prepared by:
Bruce C. Jordan                 ~      ~	     	(Date)	
Director, Emission Standards Division
U. S. Environmental  Protection  Agency
Research Triangle Park, North Carolina   27711

1.   The promulgated standards  of performance will limit
     emissions of volatile organic  compounds  from new, modified
     and reconstructed reactor  processes.  Section ill of  the
     Clean Air Act  (.42 U.S.C. 7411),  as  amended,  directs the
     Administrator to establish standards of  performance for- any
     category of new stationary source of air pollution that
      . . . causes or contributes significantly to air pollution
     which may reasonably be anticipated to endanger public
     health or welfare."                               .

2.   Copies of this  document have been sent to the following
     Federal Departments:  Labor, Health and  Human Services
     Defense, Transportation, Agriculture, Commerce, Interior
     and Energy; the National Science Foundation;  State and
     Territorial Air Pollution  Program Administrators- EPA
     Regional Administrators; Local Air  Pollution  Control
     Officials; Office of Management and Budget; and other
     interested parties.

3.   For additional  information contact:

     Ms. Sheila Milliken
     U.  S.  Environmental Protection Agency
     Standards Development Branch (MD-13)
     Research Triangle Park,  North Carolina  27711
     Telephone:  (919)  541-2625

4.   Copies of this document may. be-obtained from:

     U.  S.  Environmental Protection Agency
     Library (MD-35)
     Research Triangle Park,  North Carolina  27711
     Telephone:  (919)  541-2777

     National Technical Information Service
     5285  Port Royal Road
     Springfield,  Virginia  22161
                               11

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This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication.  Mention of trade names or commercial
products is not intended to constitute endorsement or
recommendation for use.  Copies of this report are available
through the Library Services Office (MD-35),  U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina  27711
or from National Technical Information Services, 5285 Port Roval
Road,,Springfield, Virginia  22161.                         •
                              in

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                             CONTENTS


Disclaimer	
              • 	  .......  iii
      	    v
   1.0  Summary 	
        1.1  Summary of Changes Since Proposal!  *  ."  ."  *  *  *  1-1
             1.1.1  Applicability of the Standards."  .*  "  *  *  1-1
             1.1.2  Standardization of the Total
                    Resource Effectiveness Equation  ....  1-2
             1.1.3  Flow Indicators	*  "'  *  1-2
             1.1.4  Primary Fuel Systems. ...'.....    lls
             1.1.5  Vent Streams Fired as a Secondary Fuel"
                    or Introduced with Combustion Air  .  .  .  1-3
             1.1.6  Temperature Monitoring in Firebox  .  .  .*  1-3
             1.1.7  Carbon Bed Cool Down Temperature.  .  .  *  1-4
             1.1.8  Definition of Total Organic
                    Compounds	        1-4
        1.2  Summary of Impacts of Promulgated" Act ion .*  '.  '.  1-4
             1.2.1  Alternatives to Promulgated Action.  .  .'  1-4
             1.2.2  Environmental Impacts of Promulgated
                   -Action	    1_5
             1.2.3  Energy and Economic Impacts of
                    Promulgated Action	    !_5
             1.2.4  Other Considerations	] ." ,  [  '  1-5
                    1.2.4.1  Irreversible and Irretrievable
                             Commitment of Resources. .  .  . 1-5
                    1.2.4.2  Environmental and Energy
                             Impacts  of Delayed
                             Standards	, . . . .  .  .1-5

        Summary  of Public Comments	                  21
        2.1  Applicability of the Standards	9*1
        2.2  Definitions	2 12
        2.3  Selection  of Best  Demonstrated
             Technology 	  .....                  -> 1fl
        2.4  Format  of  Standards	      	2 19
        2.5  Modification/Reconstruction.    	"      -?~o-v
        2:..6-  Monitoring .  ..	]  [' \  ~ ]  ~ " •' ' t'H
        2.7  Performance  Testing  and Measurement	"
             Methods	                    2
        2.8  Reporting  and  Recordkeeping.*  .  '.  '.	?~lt
        2.9   General	
2.0

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                              TABLES


Number
                                                            Page
 2-1  List of Commenters on the Proposed Standards
      of Performance for Reactor Processes in the
      Synthetic Organic Chemical Manufacturing
      Industry	       2_2

 2-2  Monitoring and Reporting/Recordkeeping
      Requirements for Complying with
      98 Weight-Percent Reduction of TOG
      Emissions or a Limit of 20 ppmv	2-48

 2-3  Monitoring and Reporting/Recordkeeping
      for Affected Facilities Complying with
      Flare Specifications.	 2-49

 2-4  Monitoring and Reporting/Recordkeeping
      Requirements for Maintaining a TRE
      Index Value >l.o	       2-50

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                            1.0-  SUMMARY
      On June 29, 1990, the Environmental Protection Agency  (EPA)
 proposed standards of performance for reactor processes  in  the
 synthetic organic chemical manufacturing industry  (SOCMI)
 (55 FR 26953) under the authority of Section 111 of the  Clean Air
 Act (CAA).   Public comments were requested on the proposal  in the
 Federal Register.  Fifteen commenters, most of whom were industry
 representatives, submitted written comments during the comment
 period.  Two of these commenters submitted additional comments
 after the comment period had ended.   Comments were also received
 from a State environmental protection department.  The comments
 that were submitted,  along with responses .to these comments, are
 summarized  in this document.   The comments and subsequent
 responses serve as the basis  for the revisions made to the
 regulation  between proposal and promulgation.
 1.1  SUMMARY OF CHANGES SINCE PROPOSAL
      Several changes  and clarifications  were made in the
 regulation  as a result of the review of  public comments.   These
 changes and clarifications were made in  the following areas:
 (a)  applicability of  the standards;  (b)  standardization of the •
 total  resource effectiveness  (TRE) equation;  (c)  flow indicators;
 (d)  primary fuel systems;  (e)  vent streams  fired through a
 secondary burner or with combustion  air;  (f)  temperature
 monitoring  in firebox;  (g)  carbon bed cool  down  temperature; and
 (h)  definition of total  organic compounds  (TOO.
 1-1-1   Applicability  of  the St^nrixrrta
     In order to clarify  the  applicability  of  the standards,
 several  exemptions have been  added to  the reactors NSPS.  An
 exemption has been added  to the standards for  those reactor
 processes subject to  the distillation NSPS, those reactor
.processes producing beverage  alcohols, and  those reactor
 processes subject to  the NSPS  for polymer manufacturing.  A
                                1-1

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 definition for "relief valve" has been added to clarify that
 relief valves are not covered by the reactors NSPS.  Lastly, an
 exemption from emission control has been added for those reactor
 processes with vent stream concentrations of TOG less than
 300  ppmv as measured by Method 18 or less than 150 ppmv (or
 0.50 x 300 ppmv)  as measured by Method 25A.   For demonstrating
 applicability,  Method 25A will be allowed as an alternate
 screening method to Method 18 for those owners or operators
 seeking this exemption.
 1•1•2  Standardization of the Total Resource Effectiveness
        Equation                                   ~	
      Table 1 of the regulation for reactor processes  presents the
 coefficients associated with the THE index equation.   The TRE
 coefficients that were proposed for the reactors NSSPS differ
 slightly from those promulgated for the distillation  NSPS
 (55  PR 26947)and air oxidation NSfcS (55 PR 269...)  because  the
 derivations  were based on different cost years.   The  difference,
 however,  is  insignificant.   To reduce confusion and to ensure
 consistency  in  calculating the TRE values, the TRE coefficients
 are being standardized in the final reactors  rule.
 1.1.3   Plow  Indicators
      Because flow indicators  located in the vent pipe between the
 emission  source  and the  control  device  prior  to  being joined with
 another vent stream may  be  insufficient to meet  the intent  of the
 standard,  the flow indicator  position is, being altered.  The new
 location  would be  at  the entrance  to  any bypass  line  that could
 divert  the vent  stream to  the  atmosphere before  it reaches  the
 control device.   In addition,  the  frequency of recording the  flow
 indicator results  will be changed  to  at  least  once every
 IS minutes rather  than once per hour.  More frequent  collection
 of flow/no flow data  is  appropriate when the purpose  of the
monitoring is to detect  flow  to the atmosphere rather  than  to a
 control device.  Further, an alternate provision is being added
 for those facilities that use a car-seal  or a lock-and-key type
 configuration to maintain the bypass line closed during normal
                               1-2

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 operations.  A once per month visual  inspection will  be required.
 1.1.4  Primary Fuel
      The proposed standard required performance  testing  and
 monitoring for boilers and process heaters with  heat  input
 capacities less than 44 MW (150 million Btu/hr) .  The final
 standards do not require testing and monitoring  for boilers and
 process heaters when the reactor proces vent stream is mixed with
 the primary fuel.  When the vent stream passes through the  flame
 front it would, on average, be combusted at higher temperatures
 than if introduced with combustion air.  Also, emission  factor
 calculations (AP-42)  and submitted test results  indicate the
 expected efficiency would be greater than 99.99 percent  for
 primary fuel use.  This information indicates that a vent stream
 combusted as a primary fuel woulof achieve greater combustion
 efficiency than the 98 percent level required by the proposed
 standards.   For this  reason,  performance testing and temperature
 monitoring for "these  boilers  are being deleted.  Also, owners or
 operators who are using a control device to comply with the
 standards must maintain a schematic diagram of the affected vent
 stream,  collection system,  fuel system,  control device (s>,  and
 bypass  systems.
 1-1. S  Vent Streams Fired as  a Secondary Fuel or  Infcynrin-f P>H wifh
        Combustion Air           "                ~~ - ~ - ^^
      For those affected vent  streams  that  are fired as a
 secondary fuel  or introduced  with combustion air  prior to being
 combusted in a process  heater or boiler, an initial  performance
 test  using  Method 18  will  still be  required.   However, a
 requirement is being  added to the  standards that  these sources
 test  the  combined streams  (including  the fuel  plus  the affected-
 vent  stream)  to determine  if  total  TOG' (minus  methane  and ethane)
 is reduced  by 98  percent or to 20 ppmv.
'1.1.6  Temperature Monitoring in Pirrghmr
     To clarify placement  of  the temperature monitoring device
 for the firebox,  a change has  been made to  the  incinerator
 monitoring  provisions .  It may be difficult to  install the
                               1-3,

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 monitoring device in the firebox because of radiant, heat from the
 flame;  therefore, an alternate provision is being, added that
 allows  the temperature monitor to be placed in the ductwork
 immediately downstream of the firebox in the incinerator.
 1.1.7   Carbon Bed Cool Down Temperature
     To avoid penalizing those owners or operators who are
 operating their carbon beds at lower,  more efficient
 temperatures,  a minimum cool down temperature within 5°C of the
 temperature achieved during the performance test is being, added
 as an alternative to the proposed requirement.   The proposed
 requirement allows a cool down temperature- within 10 percent of
 the  temperature achieved during the  performance test.
 1.1.8   Definition of Total Organic Compounds
     To clarify the definition of TOG,  the current list of
 Federal Register citations identifying compounds th=it  the
 Administrator has determined contribute to the  formation of ozone
 will be listed in the preamble.   However,  'the definition of TOG
 in the  standards will retain the language  "...  those compounds
 that the Administrator has determined  do not contribute
 appreciably to the formation of  ozone  are  to be excluded."   The
 specific compounds will  not be  listed  because they may be  updated
 periodically.   By defining TOG  in this  manner,  any changes  that
 the Administrator makes  to the  list  of  compounds  would be
 automatically  incorporated into  the  definition  of TOG  in the
 standard.
 1.2  SUMMARY OF IMPACTS  OF PROMULGATED  ACTION
 1.2.1  Alternatives  to Promulgated Action
     The regulatory  alternatives  are discussed  in Chapter  6.0 of
 the proposal BID.  These  regulatory alternatives  reflect the
 different estimated  percentages  of facilities required to reduce
 emissions by 98 weight-percent or to 20 parts per million by
volume  (ppmv) under  a particular  cost-effectiveness cutoff.
These regulatory alternatives were used for  selection  of the best
demonstrated technology  (BDT), considering the estimated cost
impacts, nonair quality health impacts, environmental  impacts,
                               1-4

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 and economic impacts associated with  each alternative.   These
 alternatives have not been changed.
 1>2'2  Environmental Impacts of Promilgaf.ed Action
      The changes in the regulation will have a negligible  impact
 on the air quality impacts, water quality impacts,  and  solid
 waste impacts attributed to the standards  as originally proposed.
 These impacts are described in Chapter 7.0 of the proposal BID
. and now constitute the final Environmental Impact Statement  for
 the promulgated standards.
 1-2-3  Energy and Economic Impacts of Promilqat-.ed Action
      Section 7.5 of the proposal BID describes the  energy, impacts
 and Chapter 9.0 describes the economic impacts of the proposed
 standards.   The changes in the regulation described above will
 have a negligible effect on these impacts.
 1-2.4  Other Consideration^
      -1-2'4-1  Irreversible and irretrievable Commitment: of
 Resources .   Chapter 7.0 of the proposal BID concludes that other
 than fuels  required for the operation  of volatile organic
 compounds  (VOC's)  control  equipment, there, is  no apparent
 irreversible or irretrievable  commitment of resources associated
with the standards.  The use of the THE concept  encourages  the
use  of  recovery techniques  or  process  changes  to recover
pollutants'  as products.  The control of VOC emissions using
recovery techniques or process  changes might be  an alternative to
adding  combustion controls  for  some reactor process  facilities.
This would  result in the conservation  of both chemicals  and
fuels.  The  changes in the regulation  described above will  have
no impact on the commitment of  resources.
     1 ' 2 • 4 ' 2  Environmental and Energy Imnact-.a of Delaer! '
Standards.  Table 1-1 -in the proposal BID contains a- summary of
the estimated environmental and energy impacts associated with
promulgation of the standards.  If the standards were delayed
adverse impacts on air quality could result.  A delay in
promulgation would mean that affected facilities would be
controlled to the level specified in the appropriate State
                               1 - 5".

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implementation plan  (SIP) .  Emission levels would consequently be
higher than would be the case if the standards were in effect.
                              1-6

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                  2.0  SUMMARY OF PUBLIC COMMENTS

      A total of 17 letters  (2 conmenters submitted 2 letters)
 commenting on the proposed standards were received.  A public
 hearing on the proposed standards was not requested.  The'
 17 comment letters have been recorded and placed in the docket.
 The list of commenters,  their affiliation,  and the
 U. S.  Environmental Protection Agency (EPA)  docket number for
 each of the comments are shown in Table 2-1.  The docket
 reference is indicated in parentheses in each comment.   Unless
 otherwise noted,  all docket references are  part of Docket
 No.  A-83-29,  Category IV.   The comments have been organized into
 the  following 9  categories:
                                                               •
     •    Applicability  of the Standards
     •    Definitions
     •    Selection of Best Demonstrated Technology
     »    Format  of the  Standards
     •    Modification and Reconstruction
     •    Monitoring

     •    Performance Testing and Measurement Methods
    . •    Reporting and  Recordkeeping
     •    General
2 .1.  APPLICABILITY  OF-' THE. STANDARDS..
2.1.1  Comment
     Two commenters  (IV-D-01, IV-D-ll) requested that a specific
exemption be added  for reactor processes that do not discharge a
vent stream directly or  indirectly into the atmosphere.   One
commenter  (IV-D-01) stated that those reactors, discharging
directly into a distillation unit subject to Subpart NNN should
                               2-1

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                           COMMENTERS ON THE
               «„	REACTOR PROCESSES  J.N THE  qv
               ORGANIC CHEMICAL MANUFACTURING IND?STR?
                      Docket Number A-83-29,  IV
  Mr.  L.  A.  Mattioli
  Manager,  Pollution Control
  Allied- Signal,  Incorporated
  Post Office Box 1017
  Marcus  Hook,  Pennsylvania  19061

  Mr.  Brian  L.  Taranto
  l^nn0^en^al1Affairs  Department
  Exxon Chemxcal  Americas
  Post  Office Box 3272
  Houston, Texas   77253-3272

 Ms. *;,ary jr. Legatski
 Manager, Government  Affairs
 Synthetic Organic Chemical
                                                          Docket
                                                         reference
                                                          D-l
                                                          D-2
                                                          D-3
     r                      ,
     Connecticut Avenue, NW
Washington, B.C.  20036-1702

Mr. John Stein
                              Incorporated
                         Enslnesr in*
                                                         .D-4
 Washington,  D.C.  '20006

 Mr.  Paul  F.  Cash
 Manager,  Environmental  Control
                                                         D-5
Post Office Box  1037
Princeton, New Jersey   03543-1037

Mr. Richard L. Waters
Armstrong, Teasdale, Schlaflv,
  Davis & Dicus
One Metropolitan Square
St. Louis, Missouri  63102-2740
                                                         D-6
                               2-2
                                                     (continued)

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TABLE 2-1.  (Conti
                                       nued)
  Addressee
                     55P-
 «° KS.'SSS
 Ms  Lynne j. Omlie
 General Counsel  '
                         or
2030 Building     >
Jillard H.  Dow Center
ixdla           n
* -  Geraldine v. Cox
    M Street         Ass°ciation
*shington, D.C.  20037
                                                      Docket
                                                     reference
                                                       D-7
                                D-8
                                                     D-9
                                                     D-10
                                                    D-H
                                                    D-12
                          2-3
                                                       '^••^^
                                               (continued)

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                      TABLE 2-1.  (Continued)


 Addressee                                    '           Docket
                                                        reference
 Mr.  Albert F.  Appleton             -                      n .,,
 Commissioner                                             U--LJ
 City of New York Department of
   Environmental Protection
 2358 Municipal Building
 New  York,  New  York  10007

 Ms.  Vivian M.  Mclntire                                   n , .
 Environmental  Affairs                                    u-J.^
 Eastman Chemical Company (Kodak)
 Post Office Box 511
 Kingsport,  Tennessee  37662

 Mr.  Paul M.  King                                         D
 Corporate  Counsel,  Environment,
   Health & Safety
 PPG  Industries,  Incorporated
 One  PPG Place
 Pittsburgh,  Pennsylvania  15272

 Mr.  C.  Bruce Barbre                                      G -
 Environmental  Coordinator
 Baton Rouge  Chemical  Plant
 Exxon Chemical Americas
 Post Office  Box  241
 Baton Rouge, Louisiana   70821-0241

Mr. Richard  Sigman                                        G -
Associate Director, Air  Programs
 Chemical Manufacturers Association
 2501 M Street,  NW
Washington, D.C.  20037
                               2-4

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 be exempt from this standard.  This commenter pointed out that
 monitoring and recordkeeping requirements for such units would be
 redundant and unnecessary.
      A second commenter (IV-D-ll) remarked that the regulation is
 written as if all reactor processes create a vent stream
 requiring downstream controls.'  This commenter called for a
 specific exemption in Section 60.700(c)  to eliminate confusion
 for those reactor processes that do not emit a vent stream
 directly or indirectly into the atmosphere.
      Response
      The EPA agrees that a reactor process vent stream routed
 through a distillation unit subject to 40 CFR 60,  Subpart NNN for
 distillation operations before  it is released to the air would be
 subject to the provisions  of Subpart NNN rather than Subpart RRR
 for reactor processes.   To avoid confusion with possible overlap
 concerning applicability of these two  standards,  an additional
 exemption is being added to Section 60.700(c) (5)  which states:
      If the vent  stream from an  affected facility is  routed
      to a distillation  unit subject to Subpart  NNN and has
      no other releases  to  the air except for  a  pressure
      relief valve,  the  facility  is exempt from  all
      provisions of this subpart  except for recordkeeoinq and
      reporting in Section  60..70S(r).                *
      Recordkeeping and  reporting requirements are  being  revised
 to  eliminate redundant  reporting.   These reactor processes are
 required only to  submit'an initial  notification of this
 particular  process  design  and to  maintain a schematic  of  the
 overall  process design  for the life  of the equipment.  No other
 records  or  reports -would be  required unless process design
 changes  are  made.   Provided  the process  design change does not
 change  the  applicability status,  to: the-: reactor or  distillation
 new source-  performance  standards  (NSPS),  che owner or operator
 would only need to  submit  the process design change to the
Administrator and maintain documentation of the change for the
 life of  the  equipment.
                               2-5V

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      Recordkeeping and reporting requirements in

 Section 60.705(r) for these operations will be revised to read as
 follows:

      Each owner or operator who seeks to demonstrate
      compliance with Section 60.700(c)(5) shall submit to
      the  Administrator a process design description as part
      of the initial report.  This process design description
      shall be retained for the life of the process.  No
      other records or reports would be reouired unless
      process changes are made.

 2.1.2  Comment

      One  commenter (IV-D-01)  stated that the proposed regulation
 was unclear concerning those reactors that only vent through

 relief valves during emergencies.   This  commenter felt that

 reactors  venting through relief valves only during emergencies
 should be exempt from the regulations.
      Response

      Most reactors typically do possess  relief valves for
 purposes  of relieving pressure buildup.   It is not the intent  of

 the proposed reactors NSPS to cover pressure relief valve

 discharges.   In  the  proposed rule,  relief valve discharges  were
 specifically excluded from coverage under the definition  of "vent
 stream."   This definition has  been  retained in the final  rule.
 In  addition,  a definition for "relief valve"  has  been added to
 Section 60.701 to clarify this  term as follows:

      Relief  valve means a valve used  only to  release  an
      unplanned,  nonroutine discharge.  A  relief valve
      discharge results from an  operator error, a malfunction
      such  as  a power  failure  or equipment failure,  or other
      unexpected  cause  that requires immediate venting of  gas
      from  process  equipment in  order  to avoid  safety  hazards
      or equipment  damage.

 2.1.3  Comment

      Two commenters  (IV-D-02, IV-D-08) expressed concern  about
 the list of chemicals covered by the  reactors NSPS.   One

 commenter  (IV-D-02) stated that some  of the chemicals listed in
 the standard  for reactors  are used in processes covered by other
NSPS besides  the one for distillation operations.  The commenter

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 stressed that this overlap is confusing and that dual
 applicability of the standards needs to be avoided.
      In reviewing the list of chemicals in Section 60.707, one
 connnenter (IV-D-08)  noted an overlap with the chemicals listed in
 the air oxidation NSPS.  This commenter reviewed its processes
 for air oxidation applicability and determined that several of
 the chemicals shown on the air oxidation list were not produced
 by air oxidation processes,  but were produced via the reactor
 process route.   This commenter also found that the converse was
 true.   This  commenter pointed out that on page 3-6 of Table 3-2
 in the "Reactor Processes in Synthetic Organic Chemical
 Manufacturing Industry--Background Information for Proposed
 Standards"  (Proposal BID for Reactors)  it is stated that
 "26 chemicals are produced 'solely-  by nonreactor processes,
 specifically by air  oxidation,  distillation,  or other nonreactor
 processes."   The commenter felt  that including these  chemicals on
 the list  of  173  chemicals in Section 60.707  would confuse  the
 regulated community.   The commenter  recommended that  these
 26  chemicals  be  removed^from the  list or,  alternatively, a
 provision be  included stating that where  one  of  the chemicals
 listed  in Section 60.707  is  produced by a  process  other than a
 reactor process,  that process is  not subject  to  the standards.
     Response
     In addition to  the proposed  reactors  NSPS,  there are  two
 other final NSPS  that cover process  vents:  the air oxidation
 NSPS (40  CFR  60,  Subpart  III) and  the distillation NSPS
 (40 CFR 60, Subpart NNN).  Each NSPS  includes a separate list  of
 chemicals.  In some cases, the listed chemicals overlap between
 the three SOCMI NSPS.  This overlap  exists because various
 chemicals can potentially be manufactured via different
processes.  The  type  of process by which the chemical is produced
will determine to which of the three SOCMI NSPS a particular
process vent would be subject.  Most SOCMI product processes
would be covered by two NSPS--the distillation NSPS and either
the air oxidation NSPS or reactors NSPS.  However, in no case
                               2 - 7

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 would a particular process vent stream be regulated by more than
 one of the three SOCMI NSPS.
      The standard is clear that if a facility produces a chemical
 listed in Section 60.707 by a reactor process, then production of
 that chemical is subject to the-reactors NSPS.  As described in
 Section 60.700(b),  if an affected facility does not produce any
 of the 173 chemicals listed in Section 60.707 via one or more
 reactor processes,  then that facility is not subject to the
 reactors NSPS.  The list of 173 chemicals was developed based on
 all chemical production routes that are currently used and
 expected to  remain  competitive in the future for synthetic
 organic chemicals produced by reactor processes.   The list in
 Section 60.707 may  include chemicals currently produced by
 nonreactor processes.   However,  these chemicals were included on
 the list because available data indicated that some have in the
 past been produced  by reactor processes,  and that they may,  at
 some time in the future,  be produced by reactor processes. •
 2.1.4   Comment
     Four commenters  (IV-D-04,  IV-D-06,  IV-D-07,  IV-D-09)
 expressed concern about  the applicability of this NSPS  to  ethanol
 created by the natural breakdown  of  sugars,  a process used in  the
 production of  food  and beverage alcohols.  These  commenters  noted
 that the  intended scope  of  this rule  is virtually identical  to
 the  distillation NSPS and  that production of beverage alcohols  is
 specifically exempt from the distillation NSPS.   To remain
 consistent with  previous rulemakings, these  commenters urged that
 the  regulation of beverage  alcohol be specifically exempt  from
 the reactors NSPS.  One  commenter  (IV-D-09)  also pointed out that
 the Proposal BID  for reactors expressly excludes ethanol produced
 for human consumption from  the scope of the  reactors NSPS.  One
commenter  (IV-D-06)  added that the description of affected
facilities and the definition of "reactor processes" are broad
enough to encompass  ethanol generated directly and indirectly
from food manufacturing.
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      Response
      The EPA agrees with the*commenter that the intended scope of
 the reactors NSPS'is very similar to the distillation NSPS and
 that neither NSPS is intended to apply to ethanol created by the
 natural production of beverage alcohols.  These sources are not
 included on the priority list of sources for which standards are
 to be promulgated and,  as indicated in the notice announcing
 EPA's promulgation of the NSPS Priority List (44 PR 49222), are
 not within the scope of the SOCMI source category.  For this
 reason,  an exemption similar to the one that appears in the
 distillation NSPS will  be added to Section 60.700(c)(6)  in the
 reactors NSPS.   This provision will specifically exempt the
 production of beverage  alcohols from the reactors NSPS.
      Similarly,  it .is not the intent of the reactors NSPS to
 regulate ethanol that is generated either directly or indirectly
 during food manufacturing.   Ethanol generated during baking or
 other food manufacturing processes is produced  neither for  sale
 nor for  further  use.  Based on the definition of "product"  in
 Section  60.611,  ethanol  generated during  food manufacturing would
 not be considered a  product and,  therefore,  would  not  be  subject
 to  the reactors  NSPS.
 2.1.5  Comment
      One commenter (IV-D-05)  stated that  if  the definition  of
 "product"  in the regulation includes  raw  materials, then  those
 facilities  that  use  raw  materials  listed  under  Section 60.707 and
 that  are subject to  the  provisions  of the NSPS  for polymer
 manufacturing  (Subpart DDD),  should be exempt from the reactors
 NSPS.  This  commenter suggested an exemption which reads:   "Any
 reactor  process  that is  subject to the provisions of Subpart DDD
 is not an affected facility."
     Response
     It  is not the intent of  the reactors NSPS  to regulate
process vents that are subject to the NSPS for polymer
manufacturing under 40 CFR 60, Subpart DDD (55 PR 51010).  To
ensure that these facilities are not subject to both standards,
an exemption identical to the one that appears- in the
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 distillation NSPS will be added to Section 60.700(c)(7)  of the
 reactors  NSPS.   This exemption will exclude from regulation under
 the  reactors NSPS any reactor process that is subject'to the
 provisions  of Subpart DDD for polymer manufacturing.
 2.1.6   Comment
     One  commenter (IV-D-11)  indicated that an exemption or a
 minimum emission rate should  be added to the low flow provision
 to exclude  vent  streams that  are greater than the minimum flow
 rate of 0.011 scm/min (0.39 scfm)  but that contain relatively low
 concentrations of total organic compounds (TOG).   The commenter
 felt that this exemption is needed because it is  conceivable that
 a concentrated stream with a  low flow rate [less  tha.n
 0.011 scm/min (0.39  scfm)] could contain higher emissions
 (greater  than 20  ppm)  than a  dilute vent stream with  a large flow
 rate, making the  control cost significant.
     Response
     In reevaluating the applicability criteria of  the reactors
 NSPS, a low concentration cutoff of 300  ppmv has  been added to
 the  standard.  The low concentration exemption  was  established so
 sources would not have to bear the unnecessary  cost of
 determining the THE  index value.   The cutoff was  set  such that
 the  TRE index value  would not be less than 1.0  for  this  low
 concentration stream even if  the stream  heat content  and flow
 were worst  case.  Below this  concentration level, the  owner or
 operator  would not be required to  make an assessment  of  the TRE
 index value for a vent stream.   This  level  was  set  as  the minimum
 concentration level  below which the TRE  index value would always
 be expected to exceed a value of 1.0.  Measurement  of the
 concentration level  of a vent stream could  be made  using
 Reference Method 18.   If the  resulting concentration value is
 less than 300 ppmv TOC,  then  a TRE  calculation  is noc needed and
 combustion  is not required.   The basis for  this 300 ppmv level  is
 documented  in a memorandum entitled,  "Selection of  the Low
 Concentration Cutoff"  (Docket  No. A-83-29,  Item No. IV-B-1).
Alternatively, Reference Method 25A could be  used as a screening
method in lieu of Method 13.   However, if Method 25A is  used,  the

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measured  concentration  of  TOC must  be  less  than 150  ppmv to
qualify for  the  exemption.   See  Comment  2.7.4  for further
discussion.
     The  total cost  of  control per  unit  of  VOC removed could vary
considerably among the  different types-of reactor process vent
streams due  to variations 'in the vent  stream characteristics of
flow rate, heat  content, and concentration  of  organic  compounds.
For this  reason, the efficiency  of  controlling a particular vent
stream is taken  into consideration  in  the regulation by the TRE
calculation.  An additional  cutoff  based on minimum  emission is
not needed.
     The  standard also  contains  a mechanism for exempting any
vent stream  for  which compliance would be unreasonably costly.
This means of measuring the  cost of control  is  embodied in  the
total resource effectiveness  (TRE)  index.   Equations are included
in the regulation for determining the  TRE index of a vent stream
from an affected facility.
2.1.7  Comment
     One commenter (IV-D-15)  stated that Section 60.707  should be
amended to delete phosgene from  the list of  chemicals  affected by
Subpart RRR.  The commenter  felt  that  it has been adequately
demonstrated to  the Agency in past  industry  studies that  phosgene
is not photochemically  reactive.
     Response
     Phosgene is included on  EPA's  list of photochemically
reactive chemicals.  Phosgene is  also  included  on the  list  of
chemicals subject to the reactors NSPS in Section 60.709.
Because air emissions of phosgene could result  from reactor
processes, it will remain on  EPA's  list of chemicals subject to
the reactors NSPS.  In addition, phosgene is a highly  toxic
compound.   No additional supporting information  is available that
warrants removal of phosgene  from the reactors NSPS chemicals
list.   Phosgene will be retained on the list of  chemicals subject
to the reactors NSPS.
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2.1.8   Comment
     One  commenter  (IV-G-01)  questioned whether  a vent stream
that is mixed and used  as  a primary  fuel  in a  fuel gas system
comprised of boilers and process heaters  rather  than as a product
in subsequent chemical  processes would-be subject to the reactors
NSPS.
     Response
     For  any chemical listed  in Section 60.707 that is being
produced  as a product by reactor processes, the  resulting vent
stream  is required  to be controlled  to a  level sufficient to meet
the standard regardless of whether that resulting vent stream is
routed  for further  use  as  a primary  fuel.  However, as discussed
later in  response to Comment  2.7.7,  performance  testing and
temperature monitoring  requirements  are being  deleted from the
standards for those affected  vent streams  being  combusted as
primary fuel in boilers and process  heaters.   To distinguish
between fuel types, definitions for  primary fuel and secondary
fuel will be added  to Section 60.702 as follows:
     Primary fuel means the fuel fired through a burner or a
     number of similar  burners.  The primary fuel provides
     the  principal  heat input to the device, and the amount
     of fuel is sufficient to sustain operation  without the
     addition of other  fuels.
     Secondary fuel means  a fuel fired through a burner other
     than a primary fuel burner.  The secondary  fuel may provide
     supplementary  heat in addition  to the heat  provided by the
     primary fuel.
2.2  DEFINITIONS
2.2.1   Comment
     One  commenter  (IV-D-01)  requested a  clarification to ensure
consistency in the  definition of TOC.  This commenter pointed out
that the  definition of  TOC in Section 60.701 of  the reactors NSPS
excludes  "... those compounds that, in the future,,  the
Administrator has determined  do not contribute appreciably to the
formation of ozone  . .  . ."   This commenter speculated that EPA
is intending to exclude new hydrofluorocarbons and
hydrochlorofluorocarbons that were mentioned in  54 FR 1988,

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 published on January 18, 1989.  The commenter pointed out that
 the definition of TOC in the distillation NSPS does not include
 the compounds mentioned in 54 FR 1988.
      Response
      The EPA did intend to exclude from the definition of TOC in
 Section 60.701 specific compounds that the Administrator has
 determined do not contribute appreciably to the formation of
 ozone.   The current list of exempt compounds,  which is identified
 in separate Federal Register notices (54 FR 1988,  42 FR 35314,
 44 FR 32042,  45 FR 32424,  45 FR 48941),  is as  follows:  methane;
 ethane;  1,1,1-trichloroethane;  methylene chloride;
 trichlorofluoromethane;  dichlorodifluoromethane;
 chlorodifluoromethane;  trifluoromethane;
 trichlorotrifluoroethane;  dichlorotetrafluoroethane;
 chloropentafluoroethane;  dichlorotrifluoroethane;
 tetrafluoroethane;  dichloroethane;  and chlorodifluoroethane.  As
 the  commenter noted,  the list of specific compounds that the
 Administrator has  determined do not contribute appreciably to the
 formation of  ozone  may be  updated periodically.  If,  in the
 future,  the Administrator  adds  to the  list of  chemicals defining
 TOC,  these added chemicals  will be  identified  in future
 Federal  Register notices.   The  current definition of  TOC in the
 reactors  NSPS will  be retained  to reference but not specifically
 list  those compounds  that  the Administrator has determined do not
 contribute appreciably to  the formation of ozone.   Finally, by
 defining  TOC  in  this manner,  any changes  that  the Administrator
makes to  the  list of  compounds  would be automatically
 incorporated  into the definition of TOC in the reactors  NSPS.
2.2.2  Comment
     Six  commenters  (IV-D-02, IV-D-05,  IV-D-08, IV-D-11, IV-D-12,
IV-D-14)  objected to the definition of "product."   Two  commenters
 (IV-D-02,  IV-D-12)  felt that  the definition is confusing for
determining the applicability of the reactors NSPS.   Four
commenters (IV-D-02, IV-D-08, IV-D-12,  IV-D-14) recommended that
the definition of "product" in  the distillation NSPS be used,
with the necessary revision to reference the reactor process  list
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 of  chemicals  in Section 60.707.   These  commenters  objected to  the
 phrase  "or  is used for the production of  other chemicals  or
 compounds."   These commenters  were  concerned that  this  language
 could be interpreted to expand applicability of this NSPS to all
 facilities  that use any of the 173  listed chemicals in  their
 production  processes,  even if  they  do not manufacture any of the
 173 compounds as a product, by-product, or co-product.
     One commenter (IV-D-05) stated that  the definition of
 "product" is  unclear and it could be interpreted to include those
 cliemicals listed in Section 60.707  which  are purchased  as raw
 materials in  the production of other chemicals or  compounds.
 This commenter felt that the definition should be  identical to
 the one in  the air oxidation NSPS and recommended  the following
 definition:   "Product  means any compound  or chemical listed in
 Section 60.707 that is produced for sale  as a final product as
 that chemical or is produced for  use in a process  that  needs that
 chemical for  the production of other chemicals in  another
 facility.  By-products,  co-products,  and  intermediates  are
 considered to be products."  (The underlined phrases indicate the
 changes suggested  by the commenter.)
     Response
      The EPA agrees with the  commenters  that the  language in the
 definition of "product"  in Section  60.701 of  the proposed
 standards could be misleading  and could expand applicability of
 the reactors  NSPS  to facilities that were not intended  to be
 impacted by this regulation.   The definition  of  "product"  similar
 to the one found in the  distillation NSPS has been included in
 the reactors  NSPS.   It  states  that  a "product"  is  "any  compound
 or chemical listed in  Section  60.707  that is  produced for sale as
a final product  as  that  chemical, or for  use  in the production of
other chemicals  or compounds."  This  definition is consistent
with EPA's intent  of coverage  under the reactors NSPS.
2.2.3  Comment
     Two commenters  (IV-D-11,   IV-D-12)  requested further
clarification of the definition of  the phrase "prod\ict,
co-product,  by-product,  or  intermediate."   These commenters

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 recommended  that  wording similar to  that found in the preamble of
 the  distillation  NSPS  should be  included 'in the reactors NSPS
 preamble  to  clarify the  intent.
     Response
     As suggested by the commenters,  the following language is
 presented to clarify the intent  of the  definition of  "product."
 The  EPA considers it appropriate for the reactors NSPS to apply
 to any reactor process facility  within  a process unit producing
 any  of the listed chemicals  as a product, by-product,  co-product,
 or intermediate.  The  standards  were developed from data on
 reactor processes within process units  that produce the chemicals
 listed in Section 60.707 in  any  of the  forms listed above.   The
 cost of controlling emissions from the  production of  a listed
 chemical  as  a by-product, co-product, or intermediate is similar
"to the cost  of controlling emissions from the production of that
 chemical  as  a product.   Furthermore,  the application  of the
 standards  to facilities  producing any of the listed chemicals  was
 found to  be  reasonable.   Therefore,  EPA considers the word
 "product"  to also represent  by-products,  co-products,  and
 intermediates.
     The  standards  are also  applicable  to reactor processes that
 are used  to  recover waste or feedstock  components as  long as the
 facility  is  within  a process unit producing any of the listed
 chemicals  as a product.   The main factor in determining if  a
 listed chemical is  produced  as a product is the use of the
 chemical after the  process unit.  The EPA considers either  of  the
 following  downstream uses as indicative  of  the  production of a
 listed chemical as  a product:  (1) Production for sale as that
 listed chemical,   or (2)  use  in another process  where  that listed
 chemical  is  needed.  However, if  a listed chemical is  only  part
 of a mixed stream exiting a  process  unit and cannot be sold or
 used in another process  as the listed chemical,  then  that
 chemical is not considered to be  produced as  a  product.
 2.2.4  Comment
     Two commenters, (IV-D-05, IV-D-08)  indicated that  the
 definition of "by-product" is unclear.   One commenter  (IV-D-05)

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 questioned whether the term by-product includes  those compounds
 that  are  unintentionally created as  a result of  a chemical
 reaction  and that are contained within a final product.   To avoid
 confusion,  the commenter recommended establishing a de minimis
 level (i.e.,  less than one percent)  to-exclude a contaminant from
 the definition of by-product.
      The  other commenter also  requested clarification for
 by-products that  are  produced  during reactor processes but are
 not pure  enough for sale and,  generally,  are disposed of  as
 waste.  This  commenter felt that it  is not  the intent of  the
 reactors  NSPS to  regulate these by-products because they  are
 neither intended  for  sale nor  used in the production of other
 chemicals.
      Response
      If a mixture is  produced  in a reactor  process  as a "product"
 and contains  a chemical  listed in Section 60.707  that is
 intentionally included in the'mixture for use of  its chemical
 characteristics,  the  process would be subject to  Subpart  RRR.  A
mixture would not be  subject if  the  listed  chemical  is included
 only  as a contaminant,  that is,  the  chemical  is not  included in
 the process for its chemical characteristics.  To further clarify
 this  distinction,  sometimes a  listed chemical can be formed
during the  reaction process as a contaminant  from side reactions
as a  consequence  of producing  other  chemicals that are not
listed.   These  contaminants would not  be  considered  to be
produced  by the reactor process  if they are not recovered  to be
sold  or used  in the production of a  final product.
      The  EPA  has  decided  that  for the  purpose of  these standards,
it is more appropriate to determine  applicability according to
whether a listed  chemical is produced  as a product,  instead of
setting a minimum concentration  level  of a listed chemical  as a
means of  defining what may  constitute  production  as  a product.
It is not feasible to set any one concentration limit for listed
chemicals below which the chemical is  always  an impxirity or
waste.  It is not  feasible  because the necessary  concentration or
purity for a  listed chemical to be considered a product can vary

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 from site  to  site.   For example,  a chemical  that  is  produced as
 90 percent pure  from one process  may only be 80 percent  pure to
 be considered a  product for another process.   Due to diversity of
 the  SOCMI, it would  not be  practicable  for EPA to establish
 different  concentration limits  for all-of the processes  covered
 by the  standards.  Therefore, the applicability of the standards
 is determined according to  whether a listed  chemical is  produced
 as a product.
 2.2.5   Comment
      One commenter  (IV-D-ll) stated that  the  definition  of  "vent
 stream" is difficult to interpret and needs  additional
 clarification.   This commenter pointed  out that the  definition of
 vent  stream also applies to any gas stream emitted from  a reactor
 that  indirectly  discharges  to the atmosphere  after being diverted
 through other process equipment.   This  commenter  noted that
 nearly all product streams  leave  a reactor process for further
 handling as a vapor  but are not considered a  vent stream at  the
 point when they  exit from the reactor process.  The  commenter
 felt that the  proposed  definition for "vent stream"  could result
 in an overlap  in regulations if the vent  stream is ultimately
 discharged from  a distillation unit that  is covered  by the recent
 distillation NSPS.
     Response
     As previously discussed in the response  to Comment  2,1.1, if
 a vent stream  is discharged exclusively to a  distillation unit
 subject to the distillation NSPS,  then that vent  stream would not
be subject to  the control provisions  in the reactors NSPS.
Typically,  a vent stream is routed  directly through  a recovery
device such as an absorber,  a condenser, or a carbon adsorber.
 In some cases, however,  the vent  stream may be diverted  first
 through other process equipment before being  routed  indirectly
through a recovery device.   For example, in a typical fixed bed,
regeneration carbon adsorption system, the process offgases pass
through a filtering and cooling system before entering the carbon
bed.   (The filtering process prevents bed contamination and the
cooling process allows the bed to be-maintained at the optimum

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operating temperature and prevents fires or polymerization of the
VOC.)  Even though this vent stream is routed through a filtering
and cooling system before reaching the recovery device, it is
still subject to the standard.
2.3  SELECTION OF BEST DEMONSTRATED TECHNOLOGY
2.3.1  Comment
     One commenter  (IV-D-01) stated that a cryogenic unit,
although not specifically considered a condenser but nonetheless
capable of achieving 98 percent or greater, reduction of
emissions, should be considered a condenser for the purposes of
an exemption from the provisions of Section 60.703(e).
     Response
     A cryogenic unit, such as the one mentioned by the
commenter, would be considered a condenser for the purposes of
the reactors NSPS and, therefore, would be subject to the.
condenser requirements under this regulation.  The owner  or
operator would be required to maintain a TRE index value  greater
than 1.0 at the outlet of the condenser.  Otherwise, if the TRE
is less than or equal to 1.0, the stream's emissions must be
reduced by 98 percent or to 20 ppmv.  Monitoring of process
parameters outlined in the regulation would be required unless
the owner or operator elected to demonstrate compliance with an
alternative process parameter allowed under Section 60.703(e).
2.3.2  Comment
     One commenter (IV-D-10) requested that although the preamble
discussion states that "any control can be used as long as it can
be demonstrated that it is at least as effective as BDT at
reducing VOC emissions," this stipulation should also be
specifically spelled out in Section 60.702 of the regulation.
     Response
     Because the standards is expressed in terms of an emission
limitation and not an equipment standard, the EPA believes that
the wording in Section 60.702(a) is clear in its intent that any
control device can be used to achieve the emission limitation.
Any VOC control device, including an incinerator, boiler, process
heater, or other combustion device, can be used to comply with

                               2-18

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  thzs requirement.  Alternatively, a flare can be used to comply
  wxth Section 60.702(b).  in addition,  any VOC recovery device
  including an absorber,  condenser, carbon adsorber, or other  '
  recovery device, can be used to comply with Section 60.702(c) to
  maintain the TRE index greater than.1.0.   it should be noted that
  the  TRE. value for a vent stream is determined at the point that
  the  stream exits the final  VOC recovery device and before it
  enters  a VOC control  device.
       If an owner or operator  elects  to use a control device  othe-
  than  an incinerator,  boiler,  process heater,  or flare- or a
  recovery device  other than  an absorber, condenser,  or'carbon
  absorber,  that facility would be  required  to provide information
  to the Administrator  describing the device and  the  process
 parameter(s) that .would indicate proper operation.   The    '
 documentation should be  submitted to the appropriate  enforcement
 offxcer.  As necessary, EPA Headquarters may be consulted to
 determine the adequacy of monitoring alternative process
 parameters.
 2.4  FORMAT OF STANDARDS
 2.4.1  Comment
      Three commenters (IV-D-08, IV-D-12, lv-D-14)  stated that the
 use of the TRE index value as  a standard is appropriate;  however
 these commenters  recommended that the TEE  aquations be
 standardized in 40 CFR Part  SO, Subpart III,  subpart NNN,  and
 Subpart  ERR.   one commenter  (IV-D-08) pointed out  that an
 important feature of the TRE index value noted in  the reactors
 NSPS preamble is  that  "it is independent of  cost changes  over
 time so  that  it is  not necessary to periodically revise the
 calculation to reflect current year dollars."  Two  commenters
 (IV-D-08,  IV-D-12)  noted that  the-only  change  to the TEE eouation
between  the distillation NSPS  and air oxidation NSPS and tTe
proposed  reactors NSPS was a revision of the  coefficients to
account for various cost  changes from a 1978 to a 1982 base year.
Both of these commenters noted  that the purpose for  changing the
                                                   develop^ the
                              2-19

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     Two commenters  (IV-D-12,  IV-D-14)  pointed out  that  for a
given process vent,  the  revised coefficients  result in TRE index
values that are about 3  percent greater.   Both commenters
recommended that the TRE equation coefficients be standardized.
Both commenters noted that by  standardizing the coefficients in
all three regulations, applicability  and  compliance
determinations for many  facilities would  be simplified without
appreciably changing the impact of the  rules.   One  commenter
(IV-D-12) argued that although the change in  the coefficients is
minimal, it creates  needless complication for a facility that
must use one set of  coefficients to determine the compliance
status of one process vent while using  another set  of
coefficients to determine the  compliance  status of  a second
process vent.  This  commenter  also pointed out that in
standardizing the TRE coefficients, considerable time  would be
saved in developing  process vent regulations  in the future that
incorporate the TRE  index format.
     Response
     The TRE equation developed for the SOCMI regulcitions  was
derived from an algebraic reduction based on  a cost algorithm.
However, the utility prices and the labor rates used in  the
derivation of the two TRE equations were  extracted  from  different
base cost years.  The TRE coefficients  in the air oxidation NSPS
and distillation NSPS were based on actual 1978 rates, whereas
the TRE coefficients in  the reactors  NSPS were based on  actual
1982 rates.  It would appear that  when  the annual rsite increases
are computed, the numerator and denominator of the  TRE equation
would increase by the same factor  so  that no  net change  is
reflected in the final TRE index value.   However, this is  not the
case.  The utility prices and  labor rates did not increase
uniformly from the 1978  base year  to  the  1982  base  year  so  that a
slight difference in the resultant TRE  index value  is noted when
comparing the calculation of the TRE  index value based on  the
1978 coefficients with the calculation  of the  TRE index value
based on 1982 coefficients.  This  difference  in the  resulting TRE
values is documented in  a memorandum  entitled  "Comparison  of

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 Total  Resource  Effectiveness  (TRE)  Index Values using 1978 and
 1982 TRE  Coefficients"  (Docket No.  A-83-29,  Item IV-B-3).
     The  EPA agrees  that  the  TRE coefficients  in the reactors
 NSPS should  be  identical  to those used in the  air oxidation and
 distillation NSPS and has made this.change to  the final  reactors
 NSPS.  This  standardization is important to reduce confusion and
 add consistency in calculating TRE  values,  especially in those
 cases  where  a facility has several  vent streams subject  to
 different SOCMI NSPS.  The resulting difference in the computed
 TRE values would be  insignificant using the adjusted TRE
 coefficients.
 2.4.2  Comment
     Two commenters  (IV-D-ll,  IV-D-15)  cited difficulties  with
 using  the TRE index.  One commenter (IV-D-ll)  felt that  the
 practical application of  the  TRE  index is  cumbersome.  The
 commenter pointed out that with the regulations',  it is difficult
 to determine  exactly where the  reactor process  and the associated
 internal optimization ends, and the recovery device begins,  for
 determining the  TRE  index.
     The commenter pointed out  that, in many cases,  the primary
 condenser on  a downstream column  is adequate to achieve and
maintain a TRE index greater  than 1.0  without additional emission
 controls because of  the properties  of  the material  involved.   The
 commenter added  that the  reactors NSPS  refers to  the  final
 recovery system and  not a primary condenser.  The  commenter
 recommended that clarification  is needed to  specify when the TRE
 index calculation should be performed.
     The other commenter  (IV-D-15)  stated that  he was  unable to
understand the rationale behind the TRE equation.   The commenter
suggested that a simplified calculation be included with a  clear,
concise explanation of how it is designed to achieve  its purpose.
     Response
     The EPA believes that application of the TRE index is
straightforward.  It also allows flexibility for the owner  or
operator to choose a method of compliance and provides an
incentive for product recovery.  The owner or operator can  elect

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 to do  one  of  the  following:  use  a VOC  combustion  device  and
 reduce TOG by 98  percent  or  to  20 ppmv;  combust  the vent  stream
 in a flare; or maintain a TRE index  greater  than 1.0 at the
 outlet of  the final  recovery device.  If the TRE index is less
 than 1.0 at the point of  measurement, the owner  or 'operator  could
 elect  either  to install an additional recovery device that
 results in a  TRE  index greater  than  1.0  or to control the vent
 stream.
     A recovery device is defined as an  individual unit of
 equipment, such as an absorber, carbon adsorber, or condenser,
 capable of and used  for the  purpose  of recovering  chemicals  for
 use, reuse, or sale.  The TRE index  should be calculated
 following  the last recovery  device but prior to  a  VOC control
 device.  A VOC control device is  a device such as  a flare or an
 incinerator.   For example, if the vent stream from a reactor
process is routed through two condensers in  series, the TRE  index
would be calculated  at the outlet of the final condenser.  If the
 calculated TRE index is 1.0  or  lower, the owner  or operator  can
 elect  to upgrade  the VOC  removal  efficiency  of existing recovery
devices, install  additional  recovery devices, or add a control
device.
 2.5  MODIFICATION/RECONSTRUCTION
2.5.1  Comment
     One commenter (IV-D-08) stated that the discusssion of
modification/reconstruction  considerations found in 55 FR 26965
and in Chapter 5.0 of the BID does not reflect the decision  by
 the United States Court of Appeals for the 7th Circuit, in
Wisconsin Electric Power  Company  v. Reilly (WEPCO), 893 F.2d 901
 (7th Cir. 1990).  The commenter stated that  it would be
appropriate to include in the final reactors NSPS preamble a
discussion of  "like-kind"  replacements and other issues raised  in
the WEPCO decision.
                               2-22

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       Reapongg




  alia 'thaf *** deClSi°n'  "" COUrt •8EMd "ith EPA- **~
  alia, that nonroutme renovations to existing plants thaTextend


  th~r life expectancy and increase the rate  L eJsioTto thT

  at.osphere are "Modifications'  for NSPS proses as defLd in









  and not  only physical  changes ^ are ^^ t              ^
examptlon found at  40  CFR S0.M(.,.  ^ Court aQ          ^
        nterpretation that for NSPS purposes,  an  increLe in

                       "lned ^ 1
                       but at the
 ,.„ , .    .  .	issue in the WEPCO case pertains

 to determining applicability to the Prevention of Significant
 J J^^ y^ ^^T^T ^Vy ?3 4" J .^VK / T^C^T^ \                                  **•* J» ^ V^G,^x O
               itffao;  program.  The PSD program cons

        past  operating history in establishing app'

        the NSPS,  which bases  applicability on the readilv
















                                                               :


2-5.2  Comment-

     Two commenters (IV-D-i?   rw n i/i\
                    iJ-v D  12,  IV-D-14) requested that the types
                                              ---
                    should be clarified.  These concenters
referred to the  sxan-ples of process, eo^ipnent changes Lntioned
                              2-23

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  rate to the at.ospLe             " " 1Mr~~ in "* -^"
       The comenters believe  chat  it 'is  not  the intent of th.
                                                                -
       emission rate feSUfflS^aSSre rSnS lncrease in ^e
       the atmosphere^ -           reacfnr nroeefla_voI±« to

  (The  coMnenter- s  suggested  wording is underlined )
      Sesoonaa
                                          ««  outlined in
 ae=tefa=iit                         «°uld apply ,:o  any
2 . 6  MONITORING
2-6-l  Comment-
                             state
the

             to operate at
          commenter recc
     2-24
            ze  acxiiies tt
     efficient te.piratnres   Thi     " ^^ "= 1OW"
                einperatures.   This commenter reoommendecj a

-------
 temperature range, to be determined by EPA, instead of a
 percentage value.
      Response
      The EPA does not intend to penalize those owners or
 operators who are operating their carbon beds at lower, more
 efficient temperatures.   The commenter is correct in pointing out
 that by allowing a 10 percent variation in temperature from the
 performance test for the carbon bed following regeneration, some
 inequities may result.   To eliminate possible inequities,  a
 minimum temperature difference of 5°C will be added as an
 alternative to the 10 percent provision in
 Section 60.705(f)(3)(ii).   As discussed in the memorandum
 entitled,  "Documentation of Carbon Adsorber Cool Down
 Temperature"  (Docket No.  A-83-29,  Item IV-B-2),  the minimum value
 of  5°C  is  derived from 10  percent of 50°C,  a typical carbon bed
 cool  down  temperature.   To reflect this addition,
 Section 60.705(f)(3)(ii) will be  revised to'read as follows:
      All carbon bed regeneration  cycles during which the
      temperature of the  carbon bed after regeneration [and
      after completion of any cooling cycle(s)] was  more than
      10 percent  or 5°C greater, whichever is less stringent
      than  the  carbon  bed temperature (in degrees  Celsius)
      during the  most  recent  performance test.
      This  alternative provides more  flexibility  to  those owners
 or operators who are  operating their carbon  beds at  lower,  more
 efficient  temperatures.  As  an example,  an owner or  operator may
 be able to achieve  a carbon  bed cool  down temperature of 5QC when
 conducting the performance test.  However, using the 10 percent
 provision  to maintain compliance with the regulation, the  owner
 or operator must cool the carbon bed down to at least 5.soc.  The
 alternative added to the regulation would allow the owner  or
 operator to cool the carbon bed down  to 10°C.
 2.6.2  Comment
     Three commenters (IV-D-ll, IV-D-12, IV-D-14) expressed
concern about the requirement for flow indicators.  One commenter
 (IV-D-ll)  requested that  flexibility be included in the final
regulation to allow an affected facility to use any means

                               2-25

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 available to indicate vent stream flow.  He cited several
 monitoring techniques that were not mentioned in the regulation,
 including a computer signal that utilizes either a flow or a no
 flow indication signal to assess whether a system is venting, or
 a flow indicator on the inlet feed stream or other process
 parameters.   This commenter felt that flexibility is needed to
 allow a flow indicator to be located in a place other than the
 point closest to the inlet of the control device.
      The second commenter (IV-D-12)  stated that the requirement
 for facilities to determine the presence of vent stream flow
 before the stream is combined with other streams should be
 deleted.   This commenter pointed out that existing reactor
 process vent streams are frequently combined with other vent
 streams in a vent header prior to being routed to  a combustion
 device.   This commenter noted that in these cases,  conventional
 design provides  for flow indicators  to be placed only at a point
 close to  the control device  and downstream from all individual
 vents.  The  commenter observed that  the logic  for  this
 arrangement  is related to total flow.   This commenter recommended
 that  facilities  be allowed to comply with the  flow indication
 requirement  by using existing instrumentation  that  is  located
 close.to  the control device  and after the affected  facility vent
 stream has been  joined by other vent streams.
      The  third commenter  (IV-D-14) noted  that  the  specification
 for locating a flow indicator to check the  operation of  a  control
 device as explained in the preamble  is  inconsistent with the
provisions specified in the  standard.   This  commenter pointed out
 that  good engineering  design and the efficient operation of
 control devices  are  related  to  total  flow.  The commenter
believed that  the provisions  in  the  preamble, which state  that
 the "flow indicator  would be  required  to be installed at the
combustion device inlet", are more appropriate than the
provisions specified in Section  60.702  (a),  (b), and  (c) which
require that:

     The flow indicator shall be installed in the vent
     stream from each affected facility at a point closest

                               2-26

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                        « e
      to _ the inlet of each incinerator and before beincr
      joined with any otlfer vent stream.
      Response          ~
      The EPA considers It very important to ensure that vent
 streams are continuously vented to the flare or other control
 device.  The primary intent of the flow monitoring requirement in
 the reactors NSPS was to provide a means for indicating when vent
 streams were bypassing the flare or other control device.  In the
 June 29,  1990 proposed-rule for reactor processes,  flow
 indicators were proposed to be installed in the vent stream from
 the affected facility at "a point closest to the inlet of the
 control device and before being joined with any other vent
 stream.  The presence o£~flow was to be recorded at least once
 every hour.   The flow indicators envisioned by EPA were to
 provide an indication of flow/no flow,- and not to provide
 quantitative estimates of  flow rates.
      The  EPA has reevaluated the use of flow indicators in
 reactor process vent  streams as proposed in light of  the comments
 received.  Because  flow indicators  located on the vent  stream
 between the  emission  source  and the control  device  may  be
 insufficient to meet  the intent of  the  standard (although, this  is
 what  was  proposed), EPA has  decided to  alter the  flow indicator
 location.  The  new  flow indicator location would  be at  the
 entrance  to  any bypass  line  that could  divert  the vent  stream
 before  it  reaches the  control  device.   This  location  would
 indicate  those  periods  of times when uncontrolled, emissions are
 being diverted  to the atmosphere.   In those  instances when the
 vent  stream  is  rerouted to another  control device,  the second
 control device  must also conduct a  performance  test and meet  the
 requirements of the standard.  -The  flow indicator required in-
 each- bypass  line to the atmosphere-  can- be used  in conjunction
with any type of seal mechanism to  ensure that  flow is not
diverted.
     In some situations, there may be no bypass lines that could
divert the vent stream to the atmosphere.  In these cases, there
will be no flow indicator requirement.  In addition, engineering
                               2-27

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records  that  show an emission stream is  hardpiped to a control
device are  sufficient to  demonstrate that  the  entire flow will  be
vented to the control device.   Other piping  arrangements  can be
used, but flow indicators located in any bypass  line that could
divert a portion  of  the flow to the  atmosphere,  either directly
or indirectly,  become necessary.
     Considering  the above conclusions,  EPA  is now requiring in
Section  60.705(s)  of the  reactors regulation that engineering
records  be  retained  that  describe the piping arrangement  for
venting  the affected vent streams to a control device.  This
requirement will  further  ensure that each  reactor process vent
stream of the affected facility is being continuously vented to
the control device.   If the  piping arrangement for the reactor
process  changes,  then the facility must  revise and retain the
information.  Little or no additional burden would be expected
from this requirement since  engineering  design specifications
that describe the piping  arrangements are  already being
maintained.
     At proposal, EPA required  that  hourly recordings of  flow to
the control device be taken.  However, the Agency believes that
more frequent collection  of  flow/no  flow data  is  appropriate  when
the purpose of  the monitoring is  to  detect flow to  the  atmosphere
rather than to  a control  device.  Thus,  the  final  reactors NSPS
requires flow indicators  to  be  equipped  to indicate and record
whether or  not  flow  exists at least  once every IS minutes  (rather
than once every hour).  Because the  monitor  collects  flow/no  flow
data on a continuous  basis,  this  additional  recording would not
be an additional burden.   If an owner or operator believes that
an alternative  frequency  or placement of a flow indicator  is
equally appropriate,   then  the owner  or operator can petition  the
Administrator,  as provided by the General  Provisions, to use  an
alternative monitoring scheme.
     Other flow monitoring systems,  such as  the computer signal
technique suggested by the commenter, would also be allowed so
long as they are used in  conjunction with  the  flow indicator and
readings are  taken at least once  every IS minutes.

                               2-28

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 2.6.3  Comment
      Three commenters (IV-D-08, IV-D-ll, IV-D-12) requested that
 alternate methods be allowed for determining vent stream flow/no
 flow for an affected facility.   One commenter (IV-D-08) cited
 difficulties in meeting compliance with installation of a "flow
 indicator" on the vent stream to the control device.  This
 commenter mentioned that one of his facilities seeking compliance
 with a similar provision in the distillation NSPS found it
 necessary to ask for permission to•use an alternative method for
 ensuring that the vent stream flow reached the control device (in
 this case,  a flare).   This commenter's system had a continuous
 nitrogen purge on its vent stream to the flare header to keep it
 from plugging up with organics.   This nitrogen system was used to
 avoid an upset that could result in a possible release of
 organics to the atmosphere.   However,  the commenter pointed out
 that this continuous  nitrogen purge precluded accurate
 measurement of vent stream flow to the flare.
      The commenter also  explained that each column in his system
 has  a manual  vent valve  used for initial purging  at startup  to
 remove oxygen from the system and to prevent a flammable mixture
 in the flare  header.   According  to the commenter,  the alternative
 that  this  facility requested was  to  lock the manual  vent valves
 in the closed position during normal operations,  with periodic
 visual checking to ensure  no release to  the atmosphere.   The
 manual vent valve lock suggested  by  the  commenter would be
 secured in place  with  a  lock and  key.  The  key to the lock would
 be kept  in  the  custody of  the foreman  or chief operator.
 Alternatively,  the  commenter explained that  the valves  could be
 locked electronically  with a remote  control valve  on  a  control
 panel,  or computer-activated..  The commenter felt  that  this type
 of problem was not  an  isolated case  and  recommended adding a
provision to Section 60.703 which allows an appropriate
administrative compliance alternative method for  flow
measurement, with a direct reference to Section 60.13(1) of the
General Provisions as  the means by which a source could seek
approval.

                              2-29,

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      Response
      As discussed in the response to Comment 2.6.2, the position
 of the flow indicator has been changed to the entrance to any
 bypass line that could divert the vent stream to the atmosphere
 before it reaches the control device. -In addition to this
 change, EPA agrees with the commenters that alternate provisions
 should be allowed for indicating vent stream flow/no flow for an
 affected facility.  An alternate provision is being added to the
 reactors NSPS for those facilities that use a car-seal or a
 lock-and-key type configuration to maintain the bypass line
 closed.  This alternate provision would require all lines that
 allow emissions to bypass to the atmosphere from the control
 device to be car-sealed closed or secured with a lock-and-key
 type  configuration.   For clarification purposes,  a definition for
 car-seal is being added to Section 60.702 as follows:
      gar-seal means  a seal that is placed on a device  that
      is used to change the position of a valve (e.g..,  from
      opened to closed)  in such a way that the position of
      the valve cannot be changed without breaking the  seal.
 For'those affected facilities  that use any other alternate type
 of locking mechanism (such as  a computer-activated electronic
 locking system),  those affected facilities would be required to
 install a flow indicator in the bypass  line.
      This alternative is being added to  the  reactors NSPS  to
 ensure  that the vent  streams are  not routinely bypassed to the
 atmosphere rather than being routed  to  the control  device.   If
 the owner or operator elects to comply with  this  alternative, a
visual  inspection of  the seal  mechanism  and  valves  would be
 required  at  least  once  per month  to  report and record any  time
 the seal mechanism is broken or lock is  open, and to report  and
 record  any time the valve position has changed and  the duration
of the  release  to  the atmosphere.
     If at any time a flow indicator positioned in any bypass
line to the atmosphere  indicates gas flow, this shall constitute
a violation under Section 60.702(a), except during periods of
startup, shutdown, or malfunction.   For purposes of determining
                              -2-30

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 compliance,  malfunctions shall be events deemed to occur
 infrequently,  unforseeably,  and unavoidably.  Consequently,
 recurring instances of flow through any bypass line to the
 atmosphere shall  not constitute a malfunction under this
 standard.                       -
 2.6.4   Comment
     One  commenter (IV-D-11)  observed that the requirement to
 install temperature monitoring devices in the "firebox"  of an
 incinerator should be modified to allow for additional
 flexibility.   This commenter remarked that with many
 incinerators,  the technology does not exist to maintain  a
 reliable  temperature monitor inside the firebox.   The commenter
 noted that,  in practice, most temperature monitors are installed
 in the  exhaust gas downstream of  the firebox.   The commenter
 thought that flexibility should be. .allowed in the  final
 regulation to  allow for  the  placement of the temperature monitor
 in an appropriate location to address situations where it is not
 practical  or where the technology does  not exist to install these
 devices in the firebox.
     Response
     For purposes  of  measuring the firebox temperature in an
 incinerator, EPA  considers it  appropriate to locate the
 temperature monitor in a position before any substantial  heat
 exchange is encountered.  For  the purposes  of  this  regulation,
 the location of the  temperature monitoring  device  will be allowed
 in the  ductwork immediately downstream  of  the  firebox.  To
 reflect this clarification, the language in
 Section 60.703(a)(1)(i) will be revised to  read as  follows:
     Where an  incinerator other than  a  catalytic incinerator
     is used,  a temperature monitoring  device  shall be
     installed in  the  firebox  or  in the  ductwork immediately
     downstream of  the firebox in a position before any
     substantial heat  exchange is encountered.
2.6.5  Comment
     Two commenters  (IV-D-08,  IV-D-12) do not believe that
continuous organic monitoring devices are proven technologies
and,  therefore, believe that it is inappropriate to recommend
                               2-31-

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 their use in the reactors NSPS.  These commenters cited a
 discussion of the results of a survey on hydrocarbon monitoring
 which is found in the preamble to the proposed rule for hazardous
 waste-burning in boilers, published on April 27, 1990
 (55 FR 17887).  These commenters noted-that only six incinerators
 were attempting to use these continuous monitoring devices and
 all of them were using conditioned systems rather than heated
 systems.  These commenters reported that limited data about
 continuous monitoring systems indicate that heated systems would
 detect two to four times the mass of organic compounds than would
 be detected by conditioned systems.   These commenters felt that
 heated systems have a number of operating problems which have not
 been resolved.
      One commenter (IV-D-08)  felt that continuous organic
 monitoring devices are unreliable and,  therefore,  should not be
 referenced as an allowable technology in the reactors NSPS.   The
 other commenter felt that facilities should not  be required to
 use continuous  organic monitoring devices  for demonstrating
 compliance with the  reactors  NSPS.   One  commenter (IV-D-08)
 recommended that  all references to this  technology be removed
 from the reactors NSPS until  the  devices can be proven reliable
 and accurate.   If at some time  in the  future these devices become
 proven technologies,  these commenters  suggested that  EPA  could
 issue a  notice stating that this  alternative mode of monitoring
 compliance would be  acceptable.
     Response
     The performance  of organic monitors is  not relevant to the
 reactors NSPS because  these monitors are not  required for use  on
 combustion sources.  However, organic monitors are allowed as  an
 alternative for monitoring the performance of VOC recovery
 devices.  The EPA is aware* chat these devices are currently
available and has no reason to preclude their use for certain
applications,  in each case where an organic monitor is allowed
in the reactors NSPS, an alternate monitoring device is also
specified.  For example, use of either a scrubbing liquid
temperature monitor or an organic monitor can be used to.
                              2-32

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 demonstrate the performance of an absorber,  in each case, the
 reactors NSPS allows the owner or operator to select the device
 that is most appropriate for the situation.  Although the
 reactors NSPS does not require continuous organic monitors, these
 monitors will continue to be allowed as a method for
 demonstrating compliance.
 2.7  PERFORMANCE TESTING AND MEASUREMENT METHODS
 2.7.1  Comment
      Four commenters (IV-D-08,  IV-D-ll, IV-D-14)  requested that
 guidance be provided for the performance test requirements for
 facilities that are constructed,  reconstructed,  or modified
 between the date of proposal and the date of promulgation.   All
 four commenters felt that the timing requirement  of 60  days for
 the-initial performance test was  unrealistically  tight.   They
 recommended allowing a minimum of 120 days for the initial
 performance test.                                       Three
 commenters (IV-D-08,  IV-D-12,  IV-D-14)  do not believe that
 facilities can anticipate the final  rule because  changes are
 likely  to  occur after proposal  as a  result of public comments.
 One commenter  (IV-D-14)  pointed out  that even subtle changes  can
 affect  the applicability of  the regulations  to a  facility so  that
 companies  must  review the final regulations  thoroughly before
 scheduling compliance methods and procedures.  All  three of these
 commenters explained  that it usually takes several  weeks before
 copies  of  a final regulation as printed in the Federal Register
 are available  to the  regulated  public.   One commenter (IV-D-08)
 noted that his  facility  had a difficult time  in meeting  the
 compliance dates for  the  distillation NSPS and air  oxidation
 NSPS.
     All four commenters. stated that considerable time is-needed
 to perform the  requisite  analyses and tests.  One commenter
 (IV-D-12)  stated that those affected facilities electing to
 comply with the TRE index format would have to perform stack
tests, which would take 10 to 12 weeks and, therefore,  have an
extremely difficult time in meeting the 30-day notification
deadline.  Two commenters  (IV-D-12", IV-D-14)  pointed out that
                              2-33

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 many steps are  involved when conducting  a  performance  test,
 including setup, testing, and sample  analysis.   One  commenter
 (XV-D-14) added that in many cases, a facility must  contract
 outside help to conduct its  performance  testing.  The  commenter
 elaborated that projects must  be sc9ped, contractors must be
 contacted, bids must be received and  studied, contracts must  be
 negotiated, work must be scheduled, production schedules must be
 manipulated,  analytical determination sometimes  requires off-site
 work,  and results must be related to  the applicability or
 compliance determination.  Both of these commenters agreed that
 120 days provides a more reasonable time to complete testing.
      Response
      In regard to performance tests,   the owner or operator must
 conduct performance tests and submit a written report of the
 results of such tests to EPA within 60 days after achieving the
 max:ir.Tum production rate at which the facility will be operated,
 but not later than ISO  days after initial startup of the
 facility,   in some instances, however, the initial startup of a
 facility may  occur before the date  of  promulgation.   As stated
 for monitoring requirements,  EPA has a policy of  allowing
 facilities  to conduct and report the results of'performance  tests
 within  60 days  from the date  of promulgation,  unless  maximum
 production has  not  been achieved.   In  the latter  case,  the
 facility must  conduct and  submit the results of a performance
 test no later  than  180  days after the  date  of  promulgation,   it
 is  believed that this is a reasonable  amount of time  for  the
 owner or operator of a  reactor process unit to achieve
 compliance.  All sources subject  to the NSPS must meet  these
 general  requirements.
 2.7.2  Comment,
     Four commenters  (IV-D-OS,  IV-D-ll, IV-D-12,  IV-D-14)
 expressed concern about the provision  which requires facilities
 that are built, modified, or  reconstructed  between proposal and
promulgation that have not achieved maximum operating capacity
before promulgation to conduct  their performance  test within
180 days of promulgation.  Two  commenters (IV-D-ll, :EV-D-12)
                               2-34

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 pointed out that Section 60.704(a)  clearly states that facilities
 must be run at full operating conditions and flow rates during
 performance tests.   Three commenters (IV-D-ll,  IV-D-12, IV-D-14)
 stated that if a facility does not  achieve maximum operating
 conditions  within 180 days of promulgation,  then it cannot
 conduct a performance test without  violating the provisions of
 Section 60.704(a).   These three commenters recommended that
 facilities  either be allowed  to conduct their performance test
 after the maximum operating rate has been achieved,  or that
 Section 60.704(a)  be revised  to accommodate  facilities that have
 not  yet achieved their maximum operating rate.
      One commenter (IV-D-08)  stated that the initial performance
 test required  in Section 60.702 may not be achievable within
 180  days after the  initial startup.   This commenter supported his
 statement by saying that as chemical processing  facilities become
 more complex,  contain more sophisticated equipment  and
 procedures, it may  not always"be  possible to achieve full
 production rates  and capacity  operations within  180  days.   This
 commenter further explained that  where  there are changes,  even
 small  changes,  between proposal and promulgation, facilities  may
 need to  purchase  and install new  equipment to run the performance
 tests.   For these reasons,  this commenter felt that  guidance  must
 be provided in the  final  rule  as  to  how the  performance test
 requirement should  be  handled  in  the  event that  a facility is
 unable to achieve full  capacity operation within 180  days.
     Response
     The  requirement for  the initial performance  test  to be
 conducted within 180 days  following  initial  startup will remain
unchanged.  If, however, a  facility  foresees  a problem in
achieving compliance  (i.e., if  the facility  is, unable  to achieve
maximum  capacity within ISO days), then  the  owner or  operator  of
that facility must notify the State, which has been delegated
implementation authority, or the appropriate EPA Regional Office
at the earliest possible time.
2.7.3  Comment
                              2-35

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      One commenter  (IV-D-08) expressed concern about the expected
 cost and the amount of time required by a source to run Reference
 Method 18's future validation method.  This commenter stated that
 each vent stream possesses its own set of unique characteristics
 so that each vent stream will require a separate test once the
 new validation protocol is issued.  This commenter requested some
 discussion and guidance in the final reactor processes preamble
 on possible ways to reduce this time and cost burden.
      Response
      The protocol mentioned by the commenter has been published
 as EPA Method 301:  entitled "Field Validation of Emission
 Concentrations from Stationary Sources,»  in Appendix A to 40 CFR
 Part 63.   This method is not a mandatory procedure for complying
 with the Method 18 requirements specified in the reactors NSPS.
 Rather,  it  is intended for use in validating results of emission
 testing,  particularly when there is no performance test mechod
 specified.   Because  Method 18  is specified in the reactors  NSPS,
 Method  301  is not  required by  the NSPS.   but may prove  useful in
 some situations.   To use Method 301,  the  owner or operator  would
 have to request and  receive approval  for  its use  under  the
 alternative  methods  provisions  found  in Section  60.13(1)  of the
 General Provisions.
 2.7.4  Comment
     Two  commenters  (IV-D-li, IV-D-14) felt  that  the use  of
 Reference Method 18  to determine  the  concentration of TOG would
 be extremely labor intensive, especially if  there are a number of
 compounds present.   One commenter  (IV-D-li) pointed out that
 Reference Method 18  does not specify  chemicals to be analyzed and
 that extensive  efforts could be expended quantifying trace
 components to ensure that compliance with the method is achieved.
 This commenter  recommended  that the analytical burden could be
 reduced by stating that for purposes of achieving compliance, the
analytical efforts should focus only on the compounds expected to
be present.   This commenter suggested that expected compounds
could be determined by knowledge of the process or by an initial
analytical screening.  The second commenter  (IV-D-14)  suggested
                              2-36

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 that Reference Method 25 would be a more adequate method  for  this
 determination.
     Response
     Reference Method 18 includes performance specifications,
 which are internal to the method.  These specifications offer
 guidance on the steps needed to measure approximately  90  percent
 of the total gaseous organic compounds that are present in the
 vent stream.  However, before implementing Reference Method 18,
 it is necessary to have some preknowledge of the source.  When
 designing the analytical scheme for conducting the Method 18
 performance test, it is necessary to have some prior knowledge of
 the identity and concentration of species that are present.   It
 is also necessary to be familiar with the chemical process being
 tested and to perform an initial analytical screening.  As
 discussed in Reference Method 18, presurvey sampling and  analysis
 is required to confirm the identities and approximate
 concentrations of the organic emissions.
     In response to the suggested use of Reference Method 25  as
 an appropriate method, this method is not suitable at levels  as
 low as 20 ppmv.  Because the 20 ppmv level is specified in the
 reactors NSPS for compliance with the combustion device control,
 Reference Method 25 is not considered appropriate for compliance
 testing purposes.
     As discussed in Comment 2.1.6,  a low concentration cutoff of
 300 ppmv (measured using Reference Method 18)  has been added  to
 the standards.  Reference Method 25A is allowed as an alternate
 screening method for those owners or operators seeking an
 exclusion for vent streams with low concentration levels.
Although Method 25A does not identify speciated compounds, when
 calibrated to the primary constituent in the vent stream  it can
provide a sufficiently accurate measurement of TOG for comparison
 to the low concentration applicability cutoff.   However, because
vent streams are often composed of a mixture of multiple organic
 compounds,  and some are more easily detected by Method 25A than
others,  the regulation includes certain procedures for using
Method 25A.                                    •-••••

                              2-37

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     Reference Method 25A  can only be used  if one organic
compound accounts for over 50 percent of the vent stream TOC.
This compound is referred  to as the primary constituent.  The
primary organic constituent may be determined by either process
knowledge or test data collected using-an appropriate EPA
Reference Method.  Examples of information  that could constitute
process knowledge include  calculations based on material
balances, process stoichiometry, or previous test results
provided the results are still relevant to  the current reactor
process vent stream conditions.  The primary constituent must be
used as the calibration gas for Method 25A.  The span value for
Method 25A must be set at  300 ppmv.  Note that use of Method 25A
is acceptable only if the  response from the high-level
calibration gas is at least 20 times the standard deviation of
the response from the zero calibration gas  when the instrument is
zeroed on the most sensitive scale.
     Because the compound  to which the method is calibrated may
be only half of the total  TOC, the TOC concentration measured by
Method 25A muse be less than 150 ppmv (or 0.50 x 300 ppmv) to
demonstrate cc,:>::liance with the low concentration cutoff.  This
300   w cut-off level was selected as described in the
mem   ndum entitled, ^Selection of the Low  Concentration Cutoff"
(Do   : No. A-83-29, Item  IV-B-1).  This requirement accounts for
sonu   rganics that may not be well detected when the method is
cali_,.a.ted to the primary  constituent.  Method 25A measurements
include methane and ethane.
2.7.5  Comment
     One commenter (IV-D-10)  acknowledged that Section 60.705
includes a provision that  if at a later date the owner or
operator elects to use an  alternative provision of Section 60.702
to achieve compliance, then the Administrator must be notified
90 days before implementing the change.   Upon implementing the
change,  a performance test must be performed within 180 days.
The commenter expressed confusion about when performance tests
should be conducted in this situation.  The commenter explained
that one might presume that performance tests should be conducted

                              2-38

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 in this situation.  The commenter explained  that  although we
 might presume that performance tests should  be  conducted  within
 180 days of startup, it would eliminate any  questions  relative to
 compliance if the regulations specifically stated when the
 performance test is required.
      Response
      The requirements of Section 60.705(a) explicitly  state  that
 when an owner or operator wishes to change the method  of
 compliance to a. different provision of Section 60.702, then  that
 owner or operator must notify the Administrator within 90  days
 and conduct a performance test within 180 days of implementing
 the change.  Further,  the requirements of the General Provisions
 apply unless alternate provisions are spelled out in the
 regulation.  It  is stated in Section 60.8(a)  of the General
 Provisions that 'the performance test should be conducted not
 later than 180-days after initial startup.   Therefore,  there is
 no need to repeat this language in the reactors NSPS.
 2.7.6  Comment
      One commenter (IV-D-li)  requested clarification for the
 flare requirement in Section 60.705(b)(3).   The commenter thought
 that  instead of stating that the  requirements for the
 demonstration of  compliance  on  a  flare  should be made during the
 performance test,  it could be clarified that  the determination
 should be made "for the purposes  of  complying with
 Section 60.18."
      Response
      When using a flare to meet the  standard,  the  owner or
 operator of"the affected facility must  comply with the
 requirements of Section 60.18 of the General  Provisions.
 Reference to Section 60.13, for flares is specifically given in
 Section 60-.702'(b)  of the reactors NSPS.  For  this  reason,  it  is
 not necessary to  include a specific reference  requiring
 compliance with Section 60.18 in Section 60.705(b)(3).
 2.7.7  Comment
     Two commenters  (IV-G-01, IV-G-02) cited problems applying
performance tests and monitoring requirements  set  out in the
                               2-39

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 regulation to fuel systems that collect and mix affected reactor
 vent streams with natural gas or other fuel gas for use as a
 primary fuel source.  One of the commenters (IV-G-01) indicated
 that his plant-wide fuel system provides fuel for numerous
 (100 or more) process heaters and boilers.
      One commenter (IV-G-01)  stated that although the monitoring
 and testing requirements set out in the regulation may be
 appropriate for incinerators combusting waste vent streams, they
 are not appropriate for fuel gas systems such as this.  This
 commenter pointed out that for such a fuel system,  the required
 temperature monitoring parameter does not correlate to VOC
 removal.   This commenter explained that it would be difficult and
 costly to demonstrate that each of the boilers or process heaters
 in the system is achieving the required 98 percent  reduction
 efficiency.
      This commenter added that as  long as the  process heaters and
 boilers in the system are operating properly and ignition is
 maintained,-the 98  percent reduction efficiency required by the
 NSPS  would be greatly exceeded.  This commenter further  stated
 that  for  process and  safety reasons,  fuel  flow to the boiler  or
 process heater is-always  stopped if a flame is not  present.   This
 commenter felt that due  to the ability of  these boilers  and
 process heaters  to  achieve the 98 percent  destruction efficiency,
 these fuel systems  should be able to  monitor operating parameters
 appropriate to their particular  operations  to  ensure  that
 sufficient combustion  is  being achieved.
      One  commenter  (IV-G-Ol) stated that at least 98 percent
 destruction efficiency based on  good  combustion practices,
 including adequate residence time,  temperature, and mixing, was
 reported  for  the  example  operations.   Examples of these
 operations were  cited  by  the commenter.  The commenter requested
 that EPA allow facilities that combust reactor vent gases in
boilers and heaters to identify an appropriate operating
parameter for each combustion device to monitor as an indicator
that combustion is present.  Because normal monitoring of
combustion devices is essential to ensure proper operation, the
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 commenter stated that facilities generally have in place
 appropriate monitoring procedures to enable the identification
 and control of combustion process malfunctions such as flame
 loss.
      Response                  -
      The EPA agrees that when a vent stream is combusted as
 primary fuel, the fuel gas is passing through the flame front
 and, on average,  it is combusted at a higher temperature than if
 it were being introduced into the flame with combustion air.
 Based on emission calculations for natural gas fuel combustion,
 it has been demonstrated that boilers and process heaters with
 design capacities ranging from 10 to 100 million British thermal
 units  per hour (MM BTU/hr)  achieve greater than 99.99 percent
 combustion efficiency.   In general,  it is expected that SQCMI
 chemicals affected by this standard would be easier to combust
 than natural gas.   One  commenter submitted results of a Reference
 Method 25A performance  test conducted on a unit with design
 capacity of 70 MM BTU/hr.   The results of this test demonstrated
 that TOG was reduced by greater than 99.99 percent.   The  above
 information supports the commenter's claim that an affected vent
 stream combusted  in a boiler or process heater as  primary fuel
.would  achieve greater combustion efficiency than the  98 percent   •
 level  required by  the standards.
     It  is  also in the best interest of the owner  or  operator  to
 achieve  the  greatest combustion efficiency possible when  using
 the  vent stream as  primary  fuel.   The  process  heaters  and boilers
 in the fuel  system are operated to produce steam or heat, so that
 greater  combustion  efficiency would  minimize the amount of
 supplemental  fuel  required  and  reduce  operating  costs.
     In  addition,  for safety  reasons,  the  fuel  flow to a unit  in
 a  fuel system of the type described  by  the commenter would be
 shut down immediately if the  combustion device fails to operate.
 Fuel collecting inside a unit in the absence of combustion could
 result in a highly  flammable and dangerous situation once the
 flame is reinstated.  The EPA believes that, to avoid an
 explosion, the owner or operator would ensure that any vent

                               2-41

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 stream being used as fuel does not pass through the combustion
 device without a flame present.  In a case such as this, the vent
 stream would be diverted to another control device that would
 have to comply with NSPS requirements.
      For the above reasons, EPA has.determined that performance
 testing and temperature monitoring for those boilers and process
 heaters combusting vent streams as primary fuel is not warranted;
 furthermore, based on the performance of these types of units,  it
 is believed that they would already be achieving the levels
 required by the standards.   In view of this,  the performance
 testing and temperature monitoring requirements are not deemed
 necessary to ensure compliance with the standards.   The EPA,
 therefore,  is deleting performance testing and temperature
 monitoring requirements for those affected vent streams combusted
 as primary fuel in process  heaters and boilers.  However,.
 performance testing and monitoring is  required for  all
 incinerators,  and for boilers'and process  heaters with design
 capacity less than 150  MM Btu/hr  that  are  not  combusting their
 vent  streams as primary fuel.
      To  demonstrate  that affected vent  streams are  being routed
 to appropriate control  devices, EPA is  adding  a requirement  for
 any type of control  device used,  that  the  owner or  operator
 retain a schematic diagram of  the affected vent stream,
 collection  system, fuel  system, combustion device(s),  and any
 bypass systems.  To  demonstrate where or how the affected vent
 stream is being controlled, EPA is  adding  a requirement  for  all
 affected vent  streams being controlled in  a control device.  The
 requirement  specifies that the owner or operator retain  a
 schematic diagram of the affected vent stream,  collection system,
 fuel  system, control devices, and any bypass systems.  The EPA
 expects  ao additional burden associated with this requirement.
Retaining a  schematic diagram on  site would provide an
enforcement mechanism to ensure that the affected vent stream is
being routed to an appropriate control device.  The schematic
diagram would also indicate whether or not the vent stream is
                               2-42

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 being diverted to the atmosphere or to an additional  control
 device.                             ~"
 2.7.8  Comment
      One commenter  (IV-G-01) questioned the usefulness of flow
 indicators on the type of fuel gas system where the vent stream
 that is used as primary fuel is never vented to the atmosphere.
      Response
      As discussed previously, EPA has reevaluated the use of flow
 indicators and has decided to alter the position of the flow
 indicator so that it would provide an indication of those times
 when the vent stream is being diverted to the atmosphere.  See
 the response to Comment 2.6.2.   If no bypass lines to the
 atmosphere are present,  then flow indicators would not be
 required..  However,  if a vent stream is diverted to another
 control  device,  such as a flare,  that  device must also comply
 with the standards.
      The proposed requirement'for monitoring periods of boiler or
 process  heater operation is  not  included  in  the final  standards.
 As  explained in the  previous response,  boilers  or process heaters
 are typically operated continuously, and  due to safety reasons  a
 vent stream is  not expected  to be  introduced into  a  boiler or
 process  heater  without a  flame present.  Any bypass  of the
 combustion  device would be recorded due to the  flow  indicator
 requirements.   Therefore, a  requirement to monitor periods of
 operation of  the boiler or process heater is unnecessary.
 2.7.9  Comment
     One commenter (IV-G-02) was aware of l)  the use of process
vent streams as fuel gas in  separate burners in process heaters
and boilers, and 2) the combustion of a vent stream combined with
combustion air and routed to a heater or boiler.
     Response
     Although this commenter was aware of situations in which
process vent streams are combusted as a secondary fuel in a
separate burner or are combined with combustion air,  the
commenter did not provide any performance test data or emission
                              2-43": '

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 calculations indicating that 98 percent organics reduction
 efficiency was being met in these situations.
      The EPA is concerned about situations in which vent streams
 represent a small percentage of the total fuel input to a boiler
 or process heater and are not mixed.with the primary fuel.   When
 vent  gases are fed into the combustion system through a separate
 burner,  the potential exists for unstable burner operation and
 burner "flame-out."  When vent gases are mixed with combustion
 air prior to entering the burners,  the potential exists for the
 vent  gases to bypass the main flame zone due to poor adjustment
 of burner air registers.
      Based on discussion with combustion system operators and
 review of other information,  EPA concluded that the potential for
 significant bypass, of vent gases around the combustion zone of
 larger boilers and process heaters  is  small due to  (l)  the
 residence time,  temperature,  and turbulence associated with the
 flame zone in larger combustion systems,  (2) the use of burner
 management systems on most large combustion systems that reduce
 the potential for undetected flame-outs,  and (3)  the presence of
 operating staffs  that would detect  a problem if it  occurred.
 Therefore,  as at  proposal,  performance  testing  and  temperature
 monitoring are not required for boilers  or process  heaters  with
 capacities  of ISO  MM Btu/hr or greater.
      The  situation for smaller boilers  and process  heaters  is
 different,  however.   For  example, many  small combustion systems
 are not equipped  with flame scanner systems  that automatically
 stop  the  flow of vent  gases used as a secondary fuel  in the event
 of a burner flame-out.  Also,  the smaller  devices do  not have  the
 residence  time  or  temperature  of the larger  combustion  systems.
 Furthermore,  as stated above,  no data were provided by  the
 commenter  to  assure  such  systems would achieve  98 percent
 reduction of  organics.  As a result, the requirements for
performance testing and temperature monitoring are being retained
 for vent streams being used as  secondary fuels or combined with
 combustion air in boilers and process heaters smaller than 150 MM
Btu/hr.
                               2-44

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 2.7.10  Comment
      One commenter (IV-G-02) indicated that it would be difficult
 to determine the organics destruction efficiency of vent streams
 that represent a small fraction of the total fuel input to a
 combustion system.          •   -
      Response
      After further review,  EPA agrees that it may be difficult
 for boilers and process heaters in which vent streams are
 secondary fuels to determine the  destruction efficiency
 specifically for the  vent gases.   As a result,  a provision has
 been added to the rule clarifying that Method 18 should be used
 to demonstrate that the reduction in TOG emissions (minus methane
 and ethane)  by 98 percent or to 20 ppmv should be based on the
 combined stream (the  vent stream  plus the primary fuel and all  .-
 secondary fuels),  rather than on  the vent gases only.
 2.8  REPORTING AND RECORDKEEPING
 2.8.1  Comment
      One commenter (IV-D-08)  recommended that  an annual
 performance  test be included as an alternative  to the  extensive
 reporting requirements  set  out  in Section 60.705(b)(4).   Based on
 results  from implementing the requirements set  out  in  the air
 oxidation NSPS and distillation NSPS,  this commenter felt that
 the requirements of the reactors  NSPS  would pose  a  significant
 recordkeeping burden.   This  commenter  noted that  although
 performance  testing is  expensive,  there will be some situations
 where it  may be  less  costly  to  a  complex  plant than maintaining
 an  extensive amount of  records.
      Response
      Conducting  an annual performance  test  in lieu of the
 required  reporting,requirements- is not an appropriate alternative
 to monitoring a  process parameter.  An annual performance test
would not  indicate  compliance through the year.  The reporting
and recordkeeping  requirements provide a means of documenting
monitoring compliance on a continuous basis and allow the source
to demonstrate a continuous ability to meet the standard.'
                               2.-4S

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 2.8.2  Comment
      One commenter (IV-D-08) recommended that to eliminate
 confusion,  Section 60.705 should directly reference the
 recordkeeping time period from Section 60.7(d)  of the General
 Provisions,  which states that "the file shall be retained for at
 least 2 years following the date of such measurements,
 maintenance,  reports,  and records."
      Response
      As stated in two  previous responses (see Comments 2.7.5
 and 2.7.7),  unless alternative requirements are given in the
 regulation,  the General Provisions would apply.   Section 60.7(d)
 of  the General Provisions states that records "shall be retained
 for at least  2 years following the date of  such measurements,
 maintenance,  reports,  and records."   Therefore,  records kept for
 compliance purposes for the reactors  NSPS are required to be
 retained for  at least  2 years.   There is no need to repeat this
 language in the reactors NSPS.
 2.8.3   Comment
     One commenter (IV-D-ll)  stated that the  requirements for
 reporting and recordkeeping are  very  detailed and should be
 simplified in cases where the intent  can be satisfied by an
 alternative means.  The commenter  further explained that to  avoid
 the possibility of  numerous reports on a scattered  basis,  these
 reporting and recordkeeping requirements should be  summarized
 into a  semiannual  report to be submitted, for example,  in January
 and July of each year.
     Response
     The  compliance procedures seem complicated because  there are
 several different routes  to  comply with  the reactors NSPS.   For
 example,  the owner or operator may  elect  to comply with  the NSPS
 by installing an additional  condenser  or  by combusting emissions
 in a flare or other device.   In each case, specific monitoring,
 reporting, and recordkeeping provisions must be specified  in the
 final regulation.  These requirements are nearly identical to the
requirements in the distillation and air  oxidation NSPS.  To
remain consistent and because industry has become familiar with

                               2-46

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these requirements, the monitoring, reporting, and recordkeeping
provisions will not be revised.  However, Tables 2-2 through 2-4
are provided to give a general summary of the monitoring,
reporting, and recordkeeping requirements.  This general summary
should assist the owner or operator in.identifying and
locating the applicable requirements and locating these
requirements in the regulation for reactor processes.
     Semiannual reports for each affected facility are required
under Section 60.705(1) of the reactors NSPS.  The semiannual
report should include the following types of information:
     •    any exceedances of monitored parameters;
     •    any periods of time when the vent stream is diverted to
          the atmosphere from the control device;
     •    any periods of time and duration when the pilot flame
          of a flare is absent;
     •    any change made in equipment or process operations that
          increases the operating vent stream flow rate above the
          low flow exemption level;
     •    any recalculation of the THE index;
     •    any periods of time and duration when the seal
          mechanism is broken or the by-pass line valve pos- tio:
          changes; and
     •    any change made in equipment or process operatic   that
          increases the vent stream concentration above tht. low
          concentration exemption level.
An exact month for submitting the report is not specified.  The
initial report would be submitted 6 months following the startup
date of the affected facility, and subsequent reports would be
submitted in 6-month intervals following that date.
2.8.4  Comment
     Four commenters (IV-D-08, IV-D-11,  IV-D-12, IV-D-14)
requested that guidance be provided for the initial notification
requirements for facilities that are constructed, reconstructed,
or modified between the date of proposal and the date of
promulgation of the reactors NSPS.  One commenter (IV-D-12) noted
                               2-47

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        TABLE  2-2.    MONITORING AND  REPORTING/RECORDKEEPING  REQUIREMENTS
               FOR  COMPLYING WITH 98  WEIGHT-PERCENT REDUCTION  OF  TOTAL
                    ORGANIC  COMPOUND  EMISSIONS  OR  A LIMIT OF  20  ppmv
Type of control device
used for compliance
Monitoring equipment
      required3
      Parameters
   to be monitored
   Recordkeeping
   requirements
  Parameter  boundary
 exceedances to report
Thermal incinerator
Catalytic incinerator
•oiler or process
heater
Boiler or process
heater (design heat
input capacity <4A HW,
except mere vent
stream used as primary
fuel)
Temperature monitoring
device (installed in
firebox or ductwork
immediately down-
stream) equipped with
a continuous recorder
[60.703(a)(1)(i)3

Flow indicator at
entrance to bypass
line equipped with a
continuous recorder
[60.703(a)(2)(i)3B
Temperature monitoring
device (installed in
gas stream imediately
before and after
catalyst bed) equipped
with a continuous
recorder
[60.703(a)(1)(ii)3
                                               Average firebox
                                               temperature
                       Continuous records
Flow indicator
equipped with a
continuous  recorder
[60.703(a)(2)35
Flow indicator
equipped with a
continuous  recorder
[60.703(c)(1Xi)3B

Temperature monitoring
device with continuous
recorder
[60.703(0(2)3
Presence of  flow away
from incinerator, at
least once every
15 minutes

Average temperature
upstream and
downstream of the
catalyst bed
                                                                      Continuous records;
                                                                      schematic diagram
Continuous  records
Presence of flow away
from incinerator, at
least once every
15 minutes
Presence of flow away
from boiler or
process heater, at
least once every
15 minutes

Average combustion
temperature
                                                                      Continuous records;;
                                                                      schematic diagrams
Continuous records;;
schematic diagrams
Continuous records
All 3-hour periods of
operation when average
combustion temperature
is >28°C (50°F) below
the average value
measured during the most
recent performance test
[60.705(0(1)3
Periods when the vent
stream is diverted from
the combustion device
[60.705(0(2)3


All 3-hour periods of
operation when the
average temperature of
vent stream upstream of
the catalyst bed is
>28°C (50°F) below the
average value from the
most recent performance
test [60.705(0(2)]

All 3-hour periods of
operation when the
average temperature,
difference across the
catalyst bed is
80 percent of the average
temperature difference
measured during the most
recent performance test
[60.705(0(2)3

Periods when the vent
stream is diverted from
the combustion device
[60.705(0(2)3

Periods when the vent
stream is diverted from
the combustion device
[60.705(1X2)3


All 3-hour periods of
operation when average
combustion temperature
is >28°C (50°F) below
the average value from
the most recent
performance test where
the vent stream is
introduced with
combustion air or as  a
secondary fuel
£60.705(0(3)3
•Regulatory citations are  listed in brackets.

''Where the by-pass line is secured in the closed position with a car-seal  or  lock-and-key type configuration, a flow
 indicator is not required.  Visual inspection is required at least once per  month.
                                                      2-50

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        TABLE 2-3.
   MONITORING AND  REPORTING/RECORDKEEPING REQUIREMENTS
        FOR AFFECTED  FACILITIES  COMPLYING
             WITH  FLARE SPECIFICATIONS
Type of control device
used for compliance
Monitoring equipment
     required3
   Parameters
to be monitored
Recordkeeping
requi rements
 Parameter boundary
exceedances to report
Flare
                      Heat sensing device
                      [60.703(b>(1)3
                      Flow indicator*3
                      [60.703(b)(2)(i)3
                      Presence of  a flame
                      at the pilot light
                      Presence of flow
                      diverted away from
                      flare, at least once
                      every 15 minutes
                  Continuous records
                  Continuous records;
                  schematic diagrams
                 All periods when the
                 pilot flame is absent
                 [60.705(1X3)3

                 Periods when the vent
                 stream is diverted from
                 the combustion device
                 [60.705(1X2)3
aRegulatory citations are listed in brackets.

bwhere the by-pass line is secured in the closed position with a car-seal or  lock-and-key type configuration a flow
 indicator is not required.  Visual inspection is required at least once per  month.           connguration, a flow
                                                  2-51

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     TABLE  2-4.    MONITORING AND  REPORTING/RECORDKEEPING  REQUIREMENTS  FOR
           MAINTAINING A  TOTAL  RESOURCE EFFECTIVENESS INDEX  VALUE  >1.0
Final recovery device
Monitoring equipment
      required3
   Parameters
to be monitored
Recordkeeping
requi rements
      Boundary
exceedances to report3
Absorber
Condenser
Carbon adsorber
Scrubbing liquid
temperature monitor
equipped with a
continuous recorder
[60.703(d)(1)(i>]
                        Specific gravity
                        monitor equipped
                        with a continuous
                        recorder
                        £60.703(d)(1)(i)3
                        Organic monitoring
                        device equipped with
                        continuous recorder
                        r60.703(d)(1)(ii)3fa
Condenser exit
temperature
monitoring device
equipped with
continuous recorder
[60.703(d)(2)(i)]
                        Organic monitoring
                        device equipped with
                        continuous recorder
                        [60.703(d)(2)(ii)]fa
                        Integrating steam
                        flow monitoring
                        device and carbon
                        bed temperature
                        monitoring device,
                        each equipped with  a
                        continuous recorder
                        [60.703]
                                                Average exit
                                                temperature of the
                                                absorbing liquid
                        Exit specific gravity
                        (or alternative
                        parameter that
                        measures the degree
                        of absorbing liquid
                        saturation, if
                        approved by the
                        (Administrator)

                        Concentration level
                        or reading indicated
                        by the organic
                        monitoring device
                        at the outlet of the
                        absorber
                                               Average exit (product
                                               side) temperature
                    Continuous records;
                    Continuous records;
                    Continuous records
                   Continuous records
                        Concentration level
                        or reading indicated
                        by the organic
                        monitoring device at
                        at the outlet of the
                        condenser
                        Total steam mass flow
                        during carbon bed
                        regeneration cycle(s)
                   Continuous records
                   Continuous records
                  All 3-hour periods of
                  operation when average
                  temperature is >1°C
                  (20°F) above the average
                  value from the most
                  recent performance
                  test
                  C60.705(f)(1)(i)]

                  All 3-hour periods of
                  operation when average
                  liquid specific gravity
                  is >0.1 unit above or
                  below the average value
                  from the most recent
                  performance test
                  t60.705(f)(1)(ii)]

                  All 3-hour periods of
                  operation showing
                  >20 percent of the
                  amount measured by the
                  monitoring device during
                  the most recent
                  performance test
                  t60.705(f )(/>,

                  All 3-hour periods of
                  operation when average
                  temperature is >6°C
                  (11°F> above the average
                  value from the most
                  recent performance test
                  [60.705(f)(2)3

                  All 3-hour periods of
                  operation showing
                  >20 percent of the amount
                  measured by the
                  monitoring device during
                  the most recent
                  performance test
                  [60.705(f)(4)J

                  When <10 percent below
                  the value measured during
                  most recent performance
                  test t60.705(f)(3)(i)]
                                                                                                       (continued)
                                                      2-52

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                                        TABLE  2-4.     (Continued)
Final recovery device
Carbon adsorber
(continued)
Monitoring equipment
required3

Parameters :'
to be monitored
Temperature of the
carbon bed after
Recordkeeping
requi rements
Continuous records
Boundary
exceedances to report3
When >10 percent or 5°C
more than thp valna
                        Organic monitoring
                        device equipped with
                        continuous recorder
                        [60.703(dX3Xii)]fa
regeneration [and
within 15 minutes
of completing any
cooling cycle(s)]

Concentration level
or reading indicated
by the organic
monitoring device
at the outlet of
the carbon adsorber
Continuous  records
                                                                                            measured during the most
                                                                                            recent  performance test
                                                                                            [60.70520 percent of  the amount
measured by the
monitoring device during
the most recent
performance test
[60.705(f)(4>]
"Regulatory citations are listed  in brackets.

            Concentrat1on level  «** ^ monitored as  an alternative to monitoring the other parameters)  listed for
                                                      2-53

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that the requirement in 40 CFR 60.7 specifies the timetable for
facilities to submit initial notification to EPA; however, no
specific provision is given for facilities that are constructed,
modified, or reconstructed between proposal and promulgation.
All four commenters felt that .the timing requirement of 30 days
for initial notification is unrealistically tight."  They
recommended allowing a minimum of 90 days after promulgation for
the initial notification.
     IK
     Response
     The owner or operator of an affected source must submit a
notification of the anticipated date of initial startup of the
facility no more than 60 days nor less than 30 days prior to such
date  [Section 60.7(a) (2)], and a notification of the actual date
of initial startup of the affected facility within 15 days after
such date [Section 60.7(a) (3)] .-  In some instances, however, the
initial startup of the facility may occur before the date of
promulgation.  In cases such as this, EPA has a policy of
allowing these facilities to make initial notification within
30 days after promulgation.
2.8.5  Comment
     One commenter (IV-D-08) requested that the reactors NSPS
address exceedances that occur during startup or shutdown.  The
commenter also pointed out that Section 60.8(c) of the General
Provisions states that such exceedances would not be considered a
violation unless specified in the applicable standard.  The
commenter suggested that Section 60.705 of the reactors NSPS be
modified to address startup/shutdown exceedances.
     Response
     Section 60.8(c)  of the General Provisions specifies that
emissions in excess of the level of the applicable emission limit
during periods of startup and shutdown are not considered a
violation of the applicable emission limit.  This means that
emission levels during these periods are not counted as
violations if they exceed the levels specified in the standards.
Because exceedances are not addressed in the reactors NSPS, the
language of Section 60.8(c)  applies.  Because the commenter
neither provided information on controls that would be applicable

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 in  this  situation nor indicated knowledge  of  any such technology,
 no  basis exists  for modifying  the  standard to require emissions
 control  during the startup  or  shutdown period.   Because
 exceedances are  not addressed  in the  reactors NSPS,  the  language
 of  Section 60.8(c)  applies.  .Therefore, exceedances  that occur
 during startup or shutdown  should  not be reported as violations.
 2.9   GENERAL
 2.9.1  Comment
     One commenter (IV-D-15) requested that in the regulation,
 English  measurements  be included in parentheses  following the
 currently expressed metric measurements.   The commenter
 recognized that"EPA is committed to using  the metric measurement
 system;  however,  the  commenter  pointed out that many members of
 the regulated community are still  somewhat unfamiliar with it.
 The commenter cited an illustration saying that measurements such
 as 1 gigagram are  not immediately  recognizable to a  significant
 number of members  of  the regulated community.
     Response
     The EPA agrees with the commenter that,  in some  cases,
 certain English measurements may be more commonly used than their
metric equivalents.   For this reason, EPA  will include in the
 regulation English  conversions  for the less well known metric
measurements,  such as gigagram per- year and megajoules per
kilocalorie.
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                                   TECHNICAL REPORT DATA
                            IT'lease read Instructions on the reverse before completing)
 I. REPORT NO.
 EPA-450/3-90-016b
             3. RECIPIENT'S ACCESSION NO.
 i. TITLE AND SUBTITLE
 Reactor Processes in Synthetic Organic  Chemical
 Manufacturing  Industry—Background  Information for
 Promulgated  Standards
             5. REPORT DATE
              February  1993
             6. PERFORMING ORGANIZATION CODE
   iUTHOR
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