c,
          United States
          Environmental Protection
          Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/4-91-031/^
August 1993
          Air
&EPA    Guideline Series
          Control of Volatile Organic
          Compound Emissions from
          Reactor Processes and
          Distillation Operations Processes
          in the Synthetic Organic
          Chemical Manufacturing Industry

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"N
                                                  EPA-450/4-91-031
                            Guideline Series
                Control of Volatile Organic Compound
              Emissions from Reactor Processes and
               Distillation Operations Processes in the
        Synthetic Organic Chemical Manufacturing Industry
                                Emissions Standards Division
                            U.S. ENVIRONMENTAL PROTECTION AGENCY
                                 Office ol Air and Radiation
                             Office of Air Quality Planning and Standards
                             Research Triangle Park, North Carolina 27711
                                  August 1993
                                     U.S. Environmer' ' "Action Agency
                                     Region 5, Librar    ; 2J)
                                     77 West Jackson iL,..,avard, 12th Floor
                                     Chicago, 1L  60604-3590

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                             GUIDELINE SERIES
     The guideline series of reports is issued by the Office of Air
Quality Planning and Standards (OAQPS) to provide information to State and
local air pollution control agencies; for example, to provide guidance on
the acquisition and processing of air quality data and on the planning and
analysis requisite for the maintenance of air quality.  Mention of trade
names or commercial products is not intended to constitute endorsement or
recommendation for use.  Reports published in this series will be
available - as supplies permit - from the Library Services Office (MD-35),
U. S. Environmental Protection Agency, Research Triangle Park,
North Carolina  27711, or for a nominal fee, from the National Technical
Information Service, 5285 Port Royal Road, Springfield, Virginia  22161.

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                            TABLE OF CONTENTS

                                                                      Page


LIST OF FIGURES	    viii
LIST OF TABLES	    ix

CHAPTER

1.0  INTRODUCTION	    1-1

2.0  INDUSTRY CHARACTERISTICS AND EMISSIONS 	    2-1

     2.1  GENERAL INDUSTRY INFORMATION	    2-2

     2.2  REACTOR PROCESSES 	    2-7

          2.2.1  Scope of Reactor Processes 	    2-7
          2.2.2  Chemical Reaction Descriptions 	    2-7

                 2.2.2.1   AlkyUtion	    2-7
                 2.2.2.2   Ammonolysis	    2-10
                 2.2.2.3   Carboxylation/Hydroformylation 	    2-11
                 2.2.2.4   Cleavage 	    2-13
                 2.2.2.5   Condensation 	    2-13
                 2.2.2.6   Dehydration	    2-14
                 2.2.2.7   Dehydrogenation	    2-14
                 2.2.2.8   Dehydrohalogenation	    2-16
                 2.2.2.9   Esterification 	    2-16
                 2.2.2.10  Halogenation 	    2-17
                 2.2.2.11  Hydrodealkylation	    2-18
                 2.2.2.12  Hydrohalogenation	    2-19
                 2.2.2.13  Hydrolysis/Hydration 	    2-19
                 2.2.2.14  Hydrogenation	    2-20
                 2.2.2.15  Isomerization	    2-21
                 2.2.2.16  Neutralization 	    2-21
                 2.2.2.17  Nitration	    2-21
                 2.2.2.18  Oligomerization	    2-22
                 2.2.2.19  Oxidation	    2-23
                 2.2.2.20  Oxyacetylation 	    2-24
                 2.2.2.21  Oxyhalogenation	    2-24
                 2.2.2.22  Phosgenation	    2-25
                 2.2.2.23  Pyrolysis.  . .	    2-25
                 2.2.2.24  Sulfonation	    2-25

     2.3  DISTILLATION OPERATIONS 	 ...    2-26

          2.3.1  Types of Distillation.	    2-26
          2.3.2  Fundamental  Distillation Concepts	    2-30

     2.4  REACTOR VOLATILE ORGANIC COMPOUND EMISSIONS 	    2-35

     2.5  VOLATILE ORGANIC COMPOUND EMISSIONS FROM
          DISTILLATION UNITS	    2-43

     2.6  REFERENCES	    2-50

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                       TABLE  OF  CONTENTS  (CONTINUED)

                                                                      Page
CHAPTER
3.0  EMISSION CONTROL TECHNIQUES	   3-1

     3.1  COMBUSTION CONTROL DEVICES	   3-1

          3.1.1  Flares	   3-2

                 3.1.1.1  Flare Process Description 	   3-2
                 3.1.1.2  Factors Affecting Flare Efficiency. ...   3-5
                 3.1.1.3  EPA Flare Specifications	   3-6
                 3.1.1.4  Applicability of Flares 	   3-7

          3.1.2  Thermal Incinerators 	   3-7

                 3.1.2.1  Thermal Incinerator Process
                          Description	   3-7
                 3.1.2.2  Thermal Incinerator Efficiency	   3-11
                 3.1.2.3  Applicability of Thermal
                          Incinerators	   3-13

          3.1.3  Industrial  Boilers/Process Heaters 	   3-13

                 3.1.3.1  Industrial Boiler/Process
                          Description	   3-13
                 3.1.3.2  Process Heater Description	   3-14
                 3.1.3.3  Industrial Boilers and Process
                          Heater Control Efficiency 	   3-15
                 3.1.3.4  Applicability of Industrial Boilers
                          and Process Heaters	   3-16

          3.1.4  Catalytic Oxidizers	   3-17
                 3.1.4.1  Catalytic Oxidation Process
                          Description	   3-17
                 3.1.4.2  Catalytic Oxidizer Control
                          Efficiency	   3-20
                 3.1.4.3  Applicability of Catalytic
                          Oxidizers	   3-20

     3.2  RECOVERY DEVICES	   3-21

          3.2.1  Adsorption	   3-21

                 3.2.1.1  Adsorption Process Description	   3-21
                 3.2.1.2  Adsorption Control Efficiency 	   3-22
                 3.2.1.3  Applicability of Adsorption 	   3-24

          3.2.2  Absorption	   3-25

                 3.2.2.1  Absorption Process Description	   3-25
                 3.2.2.2  Absorption Control Efficiency 	   3-26
                 3.2.2.3  Applicability of Absorption 	   3-26
                                    IV

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                       TABLE OF  CONTENTS  (CONTINUED)
                                                                      Page

CHAPTER
          3.2.3  Condensation	   3-28
                 3.2.3.1  Condensation Process Description	   3-28
                 3.2.3.2  Condenser Control Efficiency	   3-28
                 3.2.3.3  Applicability of Condensers 	   3-30
     3.3  SUMMARY	   3-30
     3.4  REFERENCES	   3-32
4.0  ENVIRONMENTAL IMPACTS	   4-1
     4.1  AIR POLLUTION IMPACTS	   4-1
          4.1.1  Volatile Organic Compound Emission Impacts ....   4-3
          4.1.2  Secondary Air Impacts	   4-3
     4.2  WATER POLLUTION IMPACTS 	   4-5
     4.3  SOLID WASTE DISPOSAL IMPACTS	   4-6
     4.4  ENERGY IMPACTS	   4-7
     4.5  REFERENCES	   4-8
5.0  COST ANALYSIS	   5-1
     5.1  INTRODUCTION	   5-1
     5.2  COST METHODOLOGY FOR INCINERATOR SYSTEMS	   5-1
          5.2.1  Thermal Incinerator Design Considerations	   5-1
                 5.2.1.1  Combustion Air Requirements 	   5-2
                 5.2.1.2  Dilution Air Requirements 	   5-4
                 5.2.1.3  Recuperative Heat Recovery	   5-4
                 5.2.1.4  Incinerator Design Temperature	   5-5
          5.2.2  Thermal Incinerator Capital Costs	   5-6
          5.2.3  Thermal Incinerator Annualized Cost	   5-6
                 5.2.3.1  Labor Costs 	   5-8
                 5.2.3.2  Capital Charges 	   5-8
                 5.2.3.3  Utility Costs 	   5-8
                 5.2.3.4  Maintenance Costs 	   5-8
     5.3  COST METHODOLOGY FOR FLARE SYSTEMS	   5-8
          5.3.1  Flare Design Considerations	   5-10
          5.3.2  Development of Flare Capital  Costs 	   5-12
          5.3.3  Development of Flare Annual ized Costs	   5-13
                 5.3.3.1  Labor Costs 	   5-13
                 5.3.3.2  Capital Charges 	   5-13
                 5.3.3.3  Utility Costs 	   5-13
                 5.3.3.4  Maintenance Costs 	   5-13

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                      TABLE OF CONTENTS  (CONTINUED)
                                                                      Page
CHAPTER
     5.4  COMPARISON OF CONTROL SYSTEM COSTS	   5-13
     5.5  REFERENCES	   5-18
6.0  SELECTION OF REASONABLY AVAILABLE CONTROL TECHNOLOGY 	   6-1
     6.1  BACKGROUND	   6-1
     6.2  TECHNICAL BASIS FOR REASONABLY AVAILABLE CONTROL
          TECHNOLOGY	   6-2
     6.3  REASONABLY AVAILABLE CONTROL TECHNOLOGY SIZE
          CUTOFFS	   6-3
     6.4  IMPACTS OF APPLYING VARIOUS COST EFFECTIVENESS CUTOFFS.  .   6-4
     6.5  REASONABLY AVAILABLE CONTROL TECHNOLOGY SUMMARY 	   6-6
     6.6  REFERENCES	   6-9
7.0  REASONABLY AVAILABLE CONTROL TECHNOLOGY IMPLEMENTATION ....   7-1
     7.1  INTRODUCTION	   7-1
     7.2  DEFINITIONS	   7-2
     7.3  REGULATORY SUMMARY	   7-3
          7.3.1  Air Oxidation Control Techniques Guidelines. .  .  .   7-3
          7.3.2  Air Oxidation Processes New Source
                 Performance Standard 	   7-3
          7.3.3  Distillation Process New Source
                 Performance Standard 	   7-11
          7.3.4  Reactor Process New Source Performance
                 Standard	   7-11
     7.4  APPLICABILITY	   7-11
     7.5  FORMAT OF THE STANDARDS	   7-12
     7.6  PERFORMANCE TESTING 	   7-13
          7.6.1  Incinerators	   7-14
          7.6.2  Flares	   7-14
          7.6.3  Boiler or Process Heater	   7-14
          7.6.4  Recovery Devices 	   7-15
     7.7  COMPLIANCE MONITORING REQUIREMENTS	   7-15
          7.7.1  Thermal Incinerators 	   7-15
          7.7.2  Flares	   7-16
          7.7.3  Boiler or Process Heater	   7-16
          7.7.4  Recovery Devices 	   7-17
                                    vi

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                       TABLE OF CONTENTS (CONTINUED)
                                                                      Page
     7.8  REPORTING/RECORDKEEPING REQUIREMENTS.
     7.9  REFERENCES	
APPENDICES
7-17
7-18
A.  LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
    INDUSTRY CHEMICALS	   A-l
B.  EMISSION DATA PROFILES	   B-l
C.  COST CALCULATIONS	   C-l
D.  SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY
    CONTROL TECHNIQUES GUIDELINE EXAMPLE RULE 	   D-l
E.  ENVIRONMENTAL IMPACT CALCULATIONS 	   E-l
F.  RESPONSE TO PUBLIC COMMENTS RECEIVED ON THE
    DRAFT SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
    INDUSTRY REACTOR PROCESSES AND DISTILLATION
    OPERATIONS CONTROL TECHNIQUES GUIDELINE 	   F-l
                                   vii

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                              LIST OF  FIGURES
Number                                                                Page
2-1   The interwoven nature of feedstocks for the organic
      chemicals manufacturing industry	   2-4
2-2   Chemical derivatives made from the feedstock ethylene ....   2-5
2-3   Flash distillation	   2-28
2-4   A conventional fractionating column 	   2-29
2-5   General examples of reactor-related vent streams	   2-36
2-6   Process flow diagram for the manufacture of nitrobenzene. .   .   2-37
2-7   Process flow diagram for the manufacture of ethylbenzene. .   .   2-38
2-8   Process flow diagram for the manufacture of acetone 	   2-39
2-9   Potential volatile organic compound emission points for a
      nonvacuum distillation column 	   2-44
2-10  Potential volatile organic compound emission points for a
      vacuum distillation column using steam jet ejectors with
      barometric condenser	   2-45
2-11  Potential volatile organic compound emission points for a
      vacuum distillation column using steam jet ejectors 	   2-46
2-12  Potential volatile organic compound emission points for
      vacuum distillation column using a vacuum pump	   2-47
3-1   Steam assisted elevated flare system	   3-3
3-2   Discrete burner, thermal oxidizer 	   3-9
3-3   Distributed burner, thermal oxidizer	   3-10
3-4   Catalytic oxidizer	   3-19
3-5   Two stage regenerative adsorption system	  . .   .   3-23
3-6   Packed tower for gas absorption	   3-27
3-7   Condensation system 	   3-Z9
D-l   Synthetic organic chemical manufacturing industry
      reactor/distillation control techniques guideline
      logic diagram per vent	   D-3
                                   V111

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LIST OF TABLES
Number
2-1
2-2

2-3
2-4


2-5
4-1

5-1
5-2
5-3
5-4
5-5
5-6

6-1


7-1

A-l

D-l

F-l
FEEDSTOCK CHEMICALS FOR CHEMICAL PRODUCTION PROCESSES ....
ESTIMATED PRODUCTION AND CHEMICAL COVERAGE FOR VARIOUS
PRODUCTION LEVELS 	
RANKING OF CHEMICAL REACTION TYPES 	
SUMMARY OF REACTOR-RELATED VOLATILE ORGANIC COMPOUND
EMISSION FACTORS, VENT STEAM HEAT CONTENTS, AND FLOW
RATES PRIOR TO COMBUSTION 	
OVERVIEW OF THE DISTILLATION OPERATIONS EMISSIONS PROFILE . .
ENVIRONMENTAL IMPACTS FOR DISTILLATION AND REACTOR MODEL
VENT STREAMS 	
INCINERATOR GENERAL DESIGN SPECIFICATIONS
CAPITAL COST FACTORS FOR THERMAL INCINERATORS 	
ANNUAL OPERATING COST BASIS FOR THERMAL INCINERATORS 	
FLARE GENERAL DESIGN SPECIFICATIONS 	
ANNUAL OPERATING COSTS FOR FLARE SYSTEMS 	
COST RESULTS FOR MODEL SYNTHETIC ORGANIC CHEMICAL
MANUFACTURING INDUSTRY VENT STREAMS 	
SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY
REASONABLY AVAILABLE CONTROL TECHNOLOGY IMPACTS- -
HALOGENATED AND NONHALOGENATED VENT STREAMS 	
CHEMICALS AFFECTED BY SYNTHETIC ORGANIC CHEMICAL
MANUFACTURING INDUSTRY RULES AND GUIDELINE 	
LIST OF SYNTHETIC ORGANIC CHEMICAL MANUFACTURING
INDUSTRY CHEMICALS 	
COEFFICIENTS FOR TOTAL RESOURCE EFFECTIVENESS FOR
NONHALOGENATED AND HALOGENATED VENT STREAMS 	
LIST OF COMMENTERS AND AFFILIATIONS 	
Page
2-3

2-6
2-8


2-42
2-49

4-2
5-3
5-7
5-9
5-11
5-14

5-16


6-5

7-4

A-l

D-15
F-2

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                             1.0  INTRODUCTION

     The Clean Air Act  (CAA) amendments of 1990 require that State
implementation plans (SIP's) for certain ozone nonattainment areas be
revised to require the  implementation of reasonably available control
technology (RACT) for control of volatile organic compound (VOC) emissions
from sources for which  the U. S. Environmental Protection Agency (EPA) has
already published control techniques guidelines (CTG's) or for which the
EPA will publish a CTG  between the date of enactment of the amendments and
the date an area achieves attainment status.  Section 172(c)(l) requires
nonattainment area SIP's to provide for, at a minimum, "such reductions in
emissions from existing sources in the area as may be obtained through the
adoption, at a minimum, of reasonably available control technology..."  As
a starting point for ensuring that these SIP's provide for the required
emission reductions, the EPA defines RACT as:  "The lowest emission
limitation that a particular source is capable of meeting by the
application of control  technology that is reasonably available considering
technological and economic feasibility," as published in the Federal
Register (44 FR 53761 [September 17, 1979]).
     The CTG's are intended to provide State and local air pollution
authorities with an information base for proceeding with their own
analyses of RACT to meet statutory requirements.  The CTG's review current
knowledge and data concerning the technology and costs of various
emissions control techniques.  Each CTG contains a "presumptive norm" for
RACT for a specific source category, based on the EPA's evaluation of the
capabilities and problems general to that category.  Where applicable, the
EPA recommends that States adopt requirements consistent with the
presumptive norm.  However, the presumptive norm is only a recommendation.
States may choose to develop their own RACT requirements on a case-by-case

                                    1-1

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basis, considering the economic and technical circumstances of an
individual source.  It should be noted that no laws or regulations
preclude States from requiring more control than is recommended as the
presumptive norm for RACT.  A particular State, for example, may need a
more stringent level of control in order to meet the ozone standard or to
reduce emissions of a specific toxic air pollutant.
     This CTG is 1 of at least 11 CTG's that the EPA is required to
publish within 3 years of enactment of the CAA amendments.  It addresses
RACT for control of VOC emissions from two types of process vents
occurring at plants in the Synthetic Organic Chemical Manufacturing
Industry (SOCMI):  reactors (other than those involving air oxidation
processes) and distillation columns.  The SOCMI chemicals applicable under
this CTG are listed in Appendix A.  Distillation columns that are part of
a polymer manufacturing process are not subject to this CTG.
     Reactor process and distillation emissions sources, as well as other
emission sources at SOCMI plants, such as air oxidation vents, storage
vessels, equipment leaks, and wastewater, are addressed by CTG documents,
new source performance standards  (NSPS) and national emission standards
for hazardous air pollutants (NESHAP).  A CTG for air oxidation processes
was published in 1985, NSPS rules for the air oxidation and distillation
process vents were promulgated in June 1990, and an NSPS for reactor
processes was proposed in June 1990 and is nearing promulgation.
Additionally, the proposed hazardous organic NESHAP  (HON) will be applied
to a portion of the process vents within SOCMI, namely, those process
vents that emit hazardous air pollutants (HAP's).
     As noted in the preceding paragraph, there are different regulations
that can apply to the same SOCMI  facility, process unit, or process vent.
For example, a given SOCMI facility could potentially be subject to all
three NSPS (air oxidation, distillation, reactor processes), to the HON
(for process vents), and to regulations developed in accordance with this
CTG.  The required control efficiency for a combustion control device  is
the same in all these various regulations.  Thus, any process vent that  is
controlled with a combustion device to meet the requirements of the HON,
NSPS, or regulations in accordance with the air oxidation CTG would meet
recommended RACT in this CTG, and it is unnecessary  to test for
                                    1-2

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applicability for VOC regulation developed in accordance with this CTG.
Section 7.3 presents the appropriate rules and regulations to which a
SOCMI facility may be subject.
                                   1-3

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                2.0  INDUSTRY CHARACTERISTICS AND EMISSIONS

     The synthetic organic chemical manufacturing industry (SOCMI) is a
large and diverse  industry producing hundreds of major chemicals through a
variety of chemical processes.  A process is any operation or series of
operations that causes a physical or chemical change in a substance or
mixture of substances.  A process unit is the apparatus within which one
of the operations of a process is carried out.  Materials entering a
process unit are referred to as feedstocks or inputs, while materials
leaving a process unit are called products or outputs.
     The major processing steps employed in organic chemical  manufacturing
plants can be classified in two broad categories:  conversion and
separation.  Conversion processes are chemical reactions that alter the
molecular structure of the compounds involved.  Conversion processes
comprise the reactor processes segment of a SOCMI plant.
     Separation processes typically follow conversion processes and divide
chemical mixtures into distinct fractions.  Examples of separation
processes are distillation, filtration, crystallization, and extraction.
Among these, the predominant separation technique used in large-scale
organic chemical manufacturing plants is distillation.  Distillation is a
unit operation used to separate one or more inlet feed streams into two or
more outlet product streams, each having constituent concentrations
different from the concentrations found in the inlet feed stream.
     This chapter describes the use of reactor processes and distillation
operations in the SOCMI.   Section 2.1 focuses on general industry
information, while Sections 2.2 and 2.3 discuss basic concepts of reactor
processes and distillation operations, respectively.  In the final
sections of this chapter,  the characteristics of typical reactor process
and distillation operation vent stream emissions are summarized.
                                    2-1

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Section 2.4 examines reactor emission characteristics,  while Section  2.5
presents distillation emission characteristics.
2.1  GENERAL INDUSTRY INFORMATION
     Most organic chemicals are manufactured in  a multi-faceted system of
chemical processes based on about 15 feedstocks  that are processed through
one or more process levels and result in hundreds of intermediate or
finished chemicals.  These feedstocks (presented in Table 2-1)  originate
from three basic raw materials:  crude oil, natural gas, and coal.
Figure 2-1 shows the highly integrated supply system for these  feedstock
chemicals from the three basic raw materials.
     The chemical industry may be described in terms of an expanding
system of production stages.  Refineries, natural gas plants, and coal tar
distillation plants represent the first stage of the production system.
As illustrated in Figure 2-1, these industries supply the feedstock
chemicals from which most other organic chemicals are made.  The organic
chemical industry represents the remaining stages of the system.  Chemical
manufacturers use the feedstocks produced in the first stage to produce
intermediate chemicals and final products.  Manufacturing plants producing
chemicals at the end of the production system are usually smaller
operations, since only a narrow spectrum of finished chemicals  is being
produced.  The products from ethylene shown in Figure 2-2 are an example
of a system of production stages from a feedstock chemical.  The
production of feedstock chemicals is an extremely dynamic industry that
may quickly change its sources of basic raw materials depending upon
availability and costs.
     The estimated total domestic production for all synthetic organic
chemicals in 1988 was 124 x 106 megagrams (Mg) [273 x 109 pounds  (lb)].
This production total includes over 7,000 different chemicals.1  A study
conducted in the early 1980's indicated that a relatively small number of
chemicals dominate industry output, as illustrated in Table 2-2.  The
table shows the number of chemicals with production output above  various
production levels (i.e., chemicals with total national production greater
than the listed production level).  The scope of this CTG includes
approximately 719 chemicals.  The applicable chemicals are listed in
Appendix A.

                                    2-2

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               TABLE 2-1.  FEEDSTOCK CHEMICALS FOR CHEMICAL
                                 PRODUCTION  PROCESSES
Benzene
Butane
1-Butene
2-Butene
Ethane
Ethylene
Isobutane
Isopentane
Methane
Naphthalene
Pentane
Propane
Propylene
Toluene
Xylenes
                                   2-3

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Coal
I
Coal tar
Distillers











Crude Oil













I
t












\

Refineries





Naphthalene






11
Benzene
Toluene
Xylene













i
i

•*-

















ll



Natural Gas
\
Natural Gas
Plants

i
i
1
Methane

T T
Ethane
Butane






Prof







>ai




1 -Butene
2-Butene
ie






















Ethylene
Propylene
            Major Source


            Minor Source
Figure 2-1.  The  interwoven nature of feedstocks  for  the organic chemicals
             manufacturing industry.
                                      2-4

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    Ethylene Dichloride
      Other Chemicals
      Other Chemicals
Ethylene Glycol Acetate
                                   Ethylene
Ethylene Oxide

       t
Ethylene Glycol
                                Polyester Fiber
                                                         Ethanol
                         Ethylbenzene
Ethanolamines
                         Latex Paints
Figure 2-2.  Chemical derivatives made from the feedstock ethylene.
                                   2-5

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          TABLE 2-2.   ESTIMATED PRODUCTION AND CHEMICAL COVERAGE
                            FOR VARIOUS PRODUCTION LEVELS
Production level -Mg/yr
(million Ib/yr)
453,600
(1,000)
226,800
(500)
113,400
(250)
45,400
(100)
27,200
(60)
13,600
(30)
9,100
(20)
4,500
(10)
Number of
chemicals3
63
102
155
219
283
410
506
705
Percentage of national
production covered
N/A
N/A
N/A
92
94
N/A
N/A
97
aThis number signifies the number of chemicals with national  production
 greater than the production level  considered.

N/A = Not applicable.
                                    2-6

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2.2   REACTOR PROCESSES
2.2.1  Scope of Reactor Processes
      The  term "reactor  processes"  refers to means by which one or more
substances, or reactants (other than air or oxygen-enriched air), are
chemically altered such that one or more new organic chemicals are formed.
A separate CTG document has already been developed for air oxidation
processes; thus, chemicals produced by air oxidation are not included in
the scope of this study.
2.2.2  Chemical Reaction Descriptions
      Between  30 and  35  different types of  chemical  reactions are used to
produce 176 high-volume chemicals.2  Some of these chemical reactions are
involved in the manufacture of only 1 or 2 of the 176 chemicals,  while
others (such as halogenation, alky!ation, and hydrogenation) are used to
make more than a dozen chemicals.  Table 2-3 identifies most of the
chemical reaction types and the number of chemicals produced by each type.
In addition, some of the chemicals  produced by reactions listed in
Table 2-3 do not result in process  vent streams.  In this document,  a
process vent stream means a gas stream ducted to the atmosphere directly
from a reactor, or indirectly, through the process product recovery
system.
      This  section briefly describes the major SOCMI chemical reactions
involving reactor processes.  Only descriptions of the larger volume
chemicals are included in this discussion.   Each chemical reaction
description contains a discussion of the process chemistry that
characterizes the reaction and the  major products resulting from the
reaction.   In addition,  process vent stream characteristics are presented
for chemicals where industry data are available.3  The emission data
profile (EDP) for reactor processes is included in Appendix B.
Descriptions of the major large-volume chemical  reactions are presented in
alphabetical order in the remainder of this section.*
      2.2.2.1  Alkvlation.  Alkylation is the introduction of an alky!
radical into an organic compound by substitution or addition.  There are
                                    2-7

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              TABLE 2-3.   RANKING OF CHEMICAL REACTION  TYPES
Rank3
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Chemical reaction type
Pyrolysis
Alkylation
Hydrogenation
Dehydration
Carboxylation/hydroformylation
Halogenation
Hydrolysis/hydration
Dehydrogenation
Esterification
Dehydrohal ogenati on
Ammonolysis
Reforming
Oxyhal ogenati on
Condensation
Cleavage
Oxidation
Hydrodeal ky 1 at i on
Isomerization
Oxyacetylation
Oligomerization
Nitration
Hydrohalogenation
Reduction
Sulfonation
Hydrocyanation
Neutralization
Hydrodimerization
Miscellaneous
Nonreactor processes'5
Number of
chemicals
produced
7
13
13
5
6
23
8
4
12
1
7
4
1
12
2
4
2
3
1
7
3
2
1
4
2
2
1
6
26
aRanking by amount of production for each chemical  reaction type.
bChemicals produced solely by air oxidation, distillation,  or other
 nonreactor processes.
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six general types of alkylation, depending on the substitution or addition
that occurs:
      •      Substitution  for  hydrogen  bound to carbon;
      •      Substitution  for  hydrogen  attached to nitrogen;
      •      Addition  of metal  to form  a  carbon-to-metal  bond;
      •      Substitution  for  hydrogen  in a hydroxyl group of an alcohol or
            phenol;
      •      Addition  of alkyl  halide,  alkyl sulfate, or  alkyl  sulfonate to
            a  tertiary  amine  to  form a quaternary ammonium compound;  and
      •      Miscellaneous processes such as addition of  a alkyl group to
            sulfur or silicon.
      The  major chemical  products of alkylation  reactions are  ethylbenzene
and cumene.  The single  largest  category of alkylation products is
refinery alkylates used  in gasoline production.   Other chemical products
of alkylation processes  include  linear  alkylbenzene,  tetramethyl  lead,  and
tetraethyl  lead.
      In general, based on data  for production of ethylbenzene, cumene,
and linear  alkylbenzene,  reactor volatile organic compound (VOC)  emissions
from alkylation processes appear to be  small  compared to other unit
processes.  The commercial synthesis of ethylbenzene from ethylene and
benzene is  an example of the first type of alkylation reaction described
above.  The reaction can be carried out in two ways.   One production
process involves a high  pressure, liquid-phase reaction method using an
aluminum chloride catalyst, while the other operates in the vapor phase at
low pressure with various solid catalysts.  Data from one plant that
produces ethylbenzene by liquid-phase alkylation indicate that reactor VOC
emissions are relatively small.   (Although no emissions data are available
for the vapor-phase alkylation process,  the associated VOC emissions are
expected to be small  due to the high operating pressure.)  Reactor offgas
from the liquid-phase alkylator  is vented to a VOC scrubber where
unreacted benzene is removed from the gas stream and recycled to the
reactor.   According to data contained in the EDP,  the scrubber vent stream
contains inerts and a small amount of VOC's and is vented to the
atmosphere at a rate of approximately 0.5 standard cubic meter per minute

                                   2-9

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(scm/m) [17 standard cubic foot per minute (scfm)].   The estimated heat
content of the vent stream is 6.7 megajoules per standard cubic meter
(MJ/scm) [180 British thermal units per standard cubic foot (Btu/scf)].
The VOC emissions to the atmosphere from the gas scrubber are estimated to
be 2.7 kilograms per hour (kg/hr) (16 Ib/hr).
      Cumene  is  produced  by the vapor-phase catalytic  alkylation of
benzene with propylene.  The reaction takes place at 690 kilopascals (kPa)
[100 pounds per square inch absolute (psia)] in the  presence of a
phosphoric acid catalyst.  No reactor streams are vented, and thus,  no
reactor VOC emissions to the atmosphere are associated with this process
at the five cumene plants included in the EDP.  Excess benzene required
for the alkylation reaction is recovered by distillation in the cumene
product purification process and recycled to the reactor.
      Dodecylbenzenes,  also referred to  as linear alkylbenzenes  (LAB),  are
produced by alkylation of mono-olefins or chlorinated n-paraffins with
benzene.  Emissions of VOC's from both processes are small or nonexistent.
In the case of the mono-olefin production route, only high purity raw
materials can be used, thus eliminating the introduction of dissolved
volatiles.  Furthermore, the hydrogen fluoride (HF)  catalyst used in the
process is a hazardous chemical and a potential source of acidic emissions
that must be minimized.  As a result,  operators of one mono-olefin
production route for LAB indicate that process vent  streams have little or
no flow associated with them.  The alkylation reaction producing LAB from
chlorinated n-paraffins generates hydrogen chloride  (HC1) gas and some VOC
by-products.  Benzene and HC1 are removed from the process vent stream
before discharging to the atmosphere.   Data from a plant producing LAB
from chlorinated n-paraffins indicate that the processes vent stream
following the scrubber is intermittent and emits no  VOC's to the
atmosphere.
      2.2.2.2  Ammonolvsis.   Ammonolysis  is  the  process  of forming amines
by using ammonia or primary and secondary amines as  aminating agents.
Another type of ammonolytic reaction is hydroammonolysis, in which amines
are formed directly from carbonyl compounds using an ammonia-hydrogen
                                   2-10

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mixture and a hydrogenation catalyst.  Ammonolytic reactions may be
divided into four groups:
      •      Double  decomposition--NH3 is  split  into  -NH2  and  -H;  the  -NH2
            becomes  part  of the  amine while  the -H reacts with  a  radical
            such  as  Cl  that is being  substituted;
      •      Dehydration--NH3 serves as a  hydrant, and  water and amines
            result;
      •      Simple  addition--both  fragments  of  the NH3 molecule (-NH  and
            -H) become  part of the newly  formed amine; and
      •      Multiple activity--NH3 reacts with  the produced amines
            resulting in  formation of secondary and  tertiary  amines.
      The  major chemical  products  of  ammonolysis reactions are
acrylonitrile and carbamic  acid.  Reactor emissions from  acrylonitrile
production  involve  air oxidation  processes, so  they are not discussed
here.  Two  other categories of ammonolysis products are ethanolamines and
methyl amines.
      Based  on information  on ethanolamine production, ammonolytic
processes appear to  be a negligible source of reactor VOC emissions.
Ethanolamines, including mono-,  di-,   and triethanolamines, are produced by
a simple addition reaction  between ethylene oxide and aqueous  ammonia.
According to information on two process units producing ethanolamines, no
reactor VOC are emitted to  the atmosphere from  this process.    The reactor
product stream is scrubbed  to recover the excess ammonia  required for the
reaction before proceeding  to the product finishing unit.
      The  manufacture of  methylamines  involves  a vapor-phase  dehydration
reaction between methanol and ammonia.   In addition to methylamines, di-
and trimethylamines  are also formed by the reaction.  Although no process
unit data for this  process  are included  in the  EDP,  available  information
suggests that reactor VOC emissions from the process  are  small or
negligible.   Staged distillation  immediately follows  the  reactor to
separate the coproducts.   As a result, all potential  VOC  emissions to the
atmosphere are associated with distillation operations and are not reactor
related.
      2.2.2.3  Carboxy!at i on/Hydroformvlat i on.
Carboxylation/hydroformylation reactions are used to  make aldehydes  and/or
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alcohols containing one additional  carbon atom.   Carboxylation is the
combination of an organic compound with carbon monoxide.   Hydro-
formylation, often referred to as the oxo process,  is a variation of
carboxylation in which olefins are reacted with a mixture of carbon
monoxide and hydrogen in the presence of a catalyst.   Major chemical
products of carboxylation/hydroformylation reactions  are acetic acid,
n-butyraldehyde, and methanol.
     Carboxylation/hydroformylation processes typically generate
relatively large process vent streams with high heat  contents, compared to
other unit processes.  Thus, process vent streams from these reactions are
normally combusted.
     One carboxylation  process for acetic acid manufacture  reacts  liquid
methanol with gaseous carbon monoxide at 20 to 70 megaPascals (MPa)
(2,900 to 10,200 psia) in the presence of a catalyst.  At one plant that
produces acetic acid by this high pressure process,  the reactor products
are passed through two gas liquid separators.  The vent from the first
separator,  consisting primarily of carbon dioxide and carbon monoxide, is
scrubbed and sent to carbon monoxide recovery.  The  vent from the second
separator is scrubbed to recover excess reactant and  then combined with
other waste gas streams and flared.   No data are available on the VOC
content of the two vent streams.   However, the only  point where reactor
VOC's are potentially emitted to the atmosphere is the vent from the
second separator, which is ultimately discharged to  a flare.
     In the  oxo  process for  producing  n-butyraldehyde, propylene  is
reacted with synthesis gas (carbon monoxide and hydrogen) in the liquid
phase at 20 to 30 MPa (2,900 to 4,400 psia).  An aromatic liquid such as
toluene is used as the reaction solvent.  A relatively large amount of
VOC's is contained in the process vent stream for this reaction.  Industry
information suggests that this process has generally been replaced by an
unnamed, low VOC-emitting process.  No data, however, are available for
this process.  Information from one plant producing  n-butyraldehyde by the
oxo process indicates that the reactor vent stream consists of hydrogen,
carbon monoxide, and VOC and is used as fuel in an industrial boiler.
Prior to combustion, the estimated vent stream flow rate at this plant is
21 scm/min (741 scfm) and the heating value is 46 MJ/scm (1,200 Btu/scf).

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The VOC  flow  rate  prior to combustion is approximately 1,100 kg/hr
(2,425 Ib/hr).
      2.2.2.4   Cleavage.   Acid cleavage  is  the process  by which  an  organic
chemical  is split  into two or more compounds with the aid of an acid
catalyst.  This chemical  reaction is associated with production of two
major chemicals, phenol,  and  acetone.
      Production  of phenol and acetone begins  with  oxidation  of  cumene  to
cumene hydroperoxide.  The cumene hydroperoxide is usually vacuum
distilled to  remove  impurities, and is then agitated in  5 to 25 percent
sulfuric  acid until  it cleaves to phenol and acetone.  The mixture is
neutralized to remove excess  sulfuric acid, phase separated, and
distilled.  One process unit  producing phenol and acetone from cumene
hydroperoxide reports little  or no flow in the process vent stream at the
cleavage  reactor.  High purity of the cumene hydroperoxide intermediate is
the major reason for this "no flow" vent.
      2.2.2.5   Condensation.   Condensation  is  a  chemical  reaction  in  which
two or more molecules combine, usually with the formation of water or some
other low-molecular weight compound.  Each of the reactants contributes a
part of the separated compound.  Chemical products made  by condensation
include acetic anhydride, bisphenol A, and ethoxylate nonylphenol.
      Reactor  emissions  to the atmosphere from condensation processes are
expected to be small.  Available data indicate that emissions from acetic
anhydride production are  minimized by combustion of the  process vent
stream.  There are no reactor VOC emissions from bisphenol or ethoxylated
nonylphenol production.   (Bisphenol A has emissions from distillation
operations only.)
     Acetic anhydride  is  produced by the condensation  of acetic acid and
ketene.  Ketene for the reaction is made by pyrolysis of acetic acid.
After water removal, the gaseous ketene is contacted with glacial  acetic
acid liquid in absorption columns operated under reduced pressure.  The
process vent stream from the absorber contains acetic acid, acetic
anhydride, traces of ketene,  and any reaction by-product gases generated.
The VOC content of the vent stream is particularly dependent on impurities
that may be contained in the acetic acid feed, such as formic or propionic
acid,  that cause side reactions to occur.  Scrubbers are normally used to
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remove acetic acid and acetic anhydride from the vent stream.   At two
process units producing acetic anhydride,  the vent streams are burned as
supplemental fuel in pyrolysis furnaces.   No data on the vent  stream
characteristics or VOC content were provided for one of these  process
units; however, data from the other source on acetic anhydride production
identify the major components of the process vent stream after scrubbing
to be carbon monoxide, carbon dioxide, and VOC.   The typical  VOC flow rate
of the vent stream after scrubbing was estimated to 138 kg/hr  (304 Ib/hr),
based on assumptions about the purity of the reactants.
      Bisphenol A  is produced  by reacting  phenol with acetone  in  the
presence of HC1 as the catalyst.  The reaction produces numerous
by-products that must be eliminated in order to generate high  purity
bisphenol  A.  Removal  of these by-products requires distillation and
extraction procedures, and thus no reactor vents to the atmosphere are
associated with this process.
      2.2.2.6   Dehydration.   Dehydration reactions3  are  a  type of
decomposition reaction in which a new compound and water are  formed from a
single molecule.  The major chemical product of dehydration is urea.
      Commercial  production of urea  is  based  on  the  reaction of  ammonia
and carbon dioxide to form ammonium carbamate, which, in turn, is
dehydrated to urea and water.  The unreacted ammonium carbamate  in the
product stream is decomposed to ammonia and carbon dioxide gas.  A portion
of the ammonia is urea and water.   The unreacted ammonium carbamate in the
product stream is removed from the process vent stream, leaving primarily
carbon dioxide to be vented to the atmosphere.  No data are included in
the EDP for VOC emissions from urea production, but one study indicates
that VOC emissions from urea synthesis are negligible.5  Urea is the only
chemical of those that use dehydration to be included in the  EDP.
      2.2.2.7   Dehydrogenation.  Dehydrogenation is  the  process  by  which  a
new chemical is formed by the removal of hydrogen from the reactant.
Aldehydes and ketones are prepared by the dehydrogenation of  alcohols.
 This process refers to chemical dehydration and does not include physical
 dehydration in which a compound is dried by heat.  Stucco produced by
 heating gypsum to remove water is an example of physical dehydration.
                                   2-14

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Chemicals produced by dehydrogenation processes include acetone, bivinyl,
cyclohexanone, methyl ethyl ketone (MEK), and styrene.
      In  general,  dehydrogenation  processes  produce  relatively  large,
hydrogen-rich process vent streams that are either used as a fuel in
process heaters or industrial boilers, or as a hydrogen feed for other
processes.  The two process units for which data are available have high
heat content process vent streams.  These occur as a result of the
hydrogen generated in the dehydrogenation reaction.   Although these
process vent streams can be quite large, there is generally little VOC
contained in them.
     Acetone  and  MEK  are  produced by  similar  processes  involving  the
catalytic dehydrogenation of alcohols.  The emissions profile contains
four process units in the EDP that produce MEK via the dehydrogenation of
sec-butanol.  In all  cases a hydrogen-rich process vent stream is
produced.  One process unit uses  a VOC scrubber to remove MEK and
sec-butanol from the process vent stream prior to flaring.  In all four
process units, reactor VOC emissions are well  controlled or nonexistent.
One acetone production process unit has an additional reactor process vent
stream on a degasser directly following the reactor.  This degasser
reduces the pressure on the product stream to allow storage of the product
at atmospheric pressure.  The pressure reduction step causes dissolved
hydrogen and low boiling point VOC's to escape from the liquid-phase
product.   This purge stream, which is relatively small, is routed to a
water scrubber to remove some VOC's before it is released to the
atmosphere.  This is the only acetone production process unit in the EDP
that stores the acetone as an intermediate product,  and as a result, it is
the only plant with a degasser process vent stream.
     Two  process  units  in the EDP manufacture styrene  via  the
hydrogenation of ethylbenzene.  One plant produces a hydrogen-rich
(90 percent by volume) process vent stream that is normally combusted to
recover the heat content.   The other plant produces  a process vent stream
that is first condensed and then combusted in a flare system.  The vent
stream flow rate is relatively large (16 scm/min [565 scfm]); the stream
contains  23 percent VOC's  including toluene, benzene, ethylbenzene, and
                                   2-15

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styrene.  The heat content is estimated to be 11 MJ/scm (300 Btu/scf),
which would support combustion without the addition of supplemental  fuel.
      2.2.2.8  Dehydrohalogenation.   In the dehydrohalogenation process, a
hydrogen atom and a halogen atom, usually chlorine, are removed from one
or more reactants to obtain a new chemical.   This chemical  reaction is
used to produce vinyl chloride,  vinylidene chloride, and cyclohexene.
      Vinylidene  chloride  is made by  dehydrochlorinating
1,1,2-trichloroethane with lime or aqueous sodium hydroxide.  The reactor
product is separated and purified by distillation.  The process vent
stream at one vinylidene chloride process unit is incinerated and then
scrubbed with caustic before discharging to the atmosphere.  Before
incinerating, the vent stream flow rate is estimated to be 0.28 scm/min
(10 scfm) and the heat content is 22 MJ/scm (591 Btu/scf).   The VOC
emission rate of the vent stream is approximately 19 kg/hr (42 Ib/hr).   At
a second plant producing vinylidene chloride, no reactor vent streams are
used.  The process vent streams are associated with distillation
operations.
      2.2.2.9  Esterification.  Esterification  is  the  process  by which  an
ester is derived from an organic acid and an alcohol by the exchange of
the ionizable hydrogen atom of the acid and an organic radical.  The major
chemical product of esterification is dimethyl terephthalate.  Other
esterification products include ethyl acrylate and ethyl acetate.
      The  VOC  emissions  associated with esterification  processes  are
small, based on information on the production of methyl methacrylate,
ethyl acrylate,  and ethyl acetate.
      Ethyl  acrylate  is  produced  by the catalytic  reaction  of  acrylic acid
and ethanol.  The vent stream flow rate from reactor equipment producing
ethyl acrylate in one process unit is reported to be 2.1 scm/min
(74 scfm).  The heat content for this stream is estimated to be 3.8 MJ/scm
(102 Btu/scf).  The VOC emission rate of the vent stream is 2.8 kg/hr
(6.1 Ib/hr).
      Methyl methacrylate  is  produced by  esterifying acetone and  hydrogen
cyanide with methanol.  Limited information is available on reactor VOC
emissions from this process.  The EDP includes one  plant producing methyl
methacrylate; the process vent stream at this plant is combusted in an
                                   2-16

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 incinerator.  Although the incinerator is used primarily to destroy VOC's
 in offgases from another plant process, combustion of the methyl
 methacrylate process vent stream in the incinerator allows the plant to
 use less supplemental fuel by recovering the heat content of the vent
 stream.  No vent stream flow rate or heat content data are available for
 this plant; however, the VOC emission rate is estimated to be very low
 (0.05 kg/hr [0.1 lb/hr]).
      Ethyl  acetate production  involves an esterification  reaction  between
 acetic acid and ethanol.  Two process units producing ethyl acetate are
 included in the EDP.  Following condensation of the process vent stream to
 recover product, both process units discharge the vent stream to the
 atmosphere.  Vent  stream data reported by one of the process units
 indicate the VOC content of the vent stream to be low, i.e., (0.2 kg/hr
 [0.4 lb/hr]).
      2.2.2.10   Haloqenation.   Halogenation  is the process  whereby  a
 halogen (e.g., chlorine, fluorine, bromine,  iodine)  is used to introduce
 one or more halogen atoms into an organic compound.   (Reactions in which
 the halogenating agent is halogen acid, such as hydrochloric acid, are
 included in a separate unit process called hydrohalogenation.)  The
 chlorination process is the most widely used halogenation process in
 industry; fluorination is used exclusively in the manufacture of
 fluorocarbons.  The major products of halogenation reactions are ethylene
 dichloride, phosgene, and chlorinated methanes and ethanes.
      Reactor VOC emissions from  halogenation reactions vary  from  no
 emissions to 51 kg/hr (112 lb/hr).  Most chlorination reactors vent to
 scrubbers or condensers where HC1 generated in the chlorination reaction
 is removed.  Some  VOC reduction occurs along with HC1 removal by these
 devices.  Also, some vent streams are combusted prior to discharge to the
 atmosphere.  Purity of the feed materials (including chlorine) is a major
 factor affecting the amount of reactor VOC emissions vented to the
 atmosphere.
      Ethylene dichloride can be  produced by direct chlorination of
ethylene or by oxychlorination of ethylene.   Most ethylene dichloride is
currently made by  a "balanced" process that combines direct chlorination
of ethylene and oxychlorination of ethylene.  The direct chlorination
                                   2-17

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process reacts acetylene-free ethylene and chlorine in the liquid phase.
The oxyhalogenation process using oxygen for the manufacture of ethylene
dichloride is included in the reaction description for oxyhalogenation.
      Reactor  VOC emissions from  ethylene dichloride production by direct
chlorination vary according to process vent stream treatment.   Hydrogen
chloride is generated by the chlorination reaction and is typically
removed from the process vent stream by a caustic scrubber.  The vent
stream following the scrubber may be discharged to the atmosphere,
recycled to the reactor, or incinerated.  The EDP contains information on
three ethylene dichloride plants that use the direct chlorination process
as part of the "balanced" process.  The process vent stream
characteristics for the three plants indicate a range of gas flow rates  of
1.1 to 7.6 scm/min (39 to 268 scfm) and a range of heat contents of 1.5  to
46 MJ/scm (40 to 1,236 Btu/scf).  The process vent stream with the highest
heat content (i.e., 46 MJ/scm [1,236 Btu/scf]) is incinerated before
venting to the atmosphere.
      The fluorination reactions  producing dichlorodifluoromethane and
trichlorotrifluoroethane involve the replacement of a chlorine in carbon
tetrachloride with, fluorine.   At two plants surveyed,  no reactor VOC
emissions are associated with these fluorination processes.  The two
plants report no process vent stream discharges to the atmosphere.
Instead, process vent streams occur from distillation operations.
      2.2.2.11  Hydrodealkylation.   Hydrodealkylation  is  the process  by
which methyl groups, or larger alkyl groups, are removed from hydrocarbon
molecules and replaced by hydrogen atoms.  Hydrodealkylation is primarily
used in the petrochemical industry to upgrade products of low value, such
as heavy reformate fractions, naphthalenic crudes or recycle stocks from
catalytic cracking.  In particular, hydrodealkylation is used in the
production of high purity benzene and naphthalene from alkyl aromatics
such as toluene.
      The EDP  contains no  information  on  emissions  from  hydrodealkylation
processes.   In the case of benzene production, the process vent stream
containing unconverted toluene is recycled to the reactor, and no reactor
VOC emissions are vented.6
                                   2-18

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      2.2.2.12   Hvdrohalogenation.  Hydrohalogenation  is the process in
which a halogen atom is added to an organic compound using a halogen acid,
such as HC1.  The major chemical products of this reaction are methyl
chloride and ethyl chloride.
      The predominant share  of methyl  chloride  is produced by the
vapor-phase reaction of methanol and HC1.7  In three process units the
process vent stream is condensed to remove excess HC1; some VOC's are also
removed by the condensers.  Of the nine plants that manufacture methyl and
ethyl chloride included in the EDP, five have no reactor process vent
streams, one discharges the noncondensibles directly to the atmosphere,
and three route the noncondensible stream to combustion devices.  The VOC
content of a methyl chloride vent stream is 76 kg/hr (168 Ib/hr).
      2.2.2.13   Hydro!ys is/Hvdrati on.   Hydrolysis is the process  in which
water reacts with another substance to form two or more new substances.
Hydration is the process in which water reacts with a compound without
decomposition of the compound.  These processes are a major route in the
manufacture of alcohols and glycols, such as ethanol,  ethylene glycols,
and propylene glycols.   Another major product of hydrolysis is propylene
oxide.
      Propylene  oxide is produced by hydrolysis of  propylene chlorohydrin
with an alkali (usually sodium hydroxide [NaOH] or calcium hydroxide
[CA(OH)2]).  The product vent stream is condensed to remove the propylene
oxide product and the noncondensibles are discharged to the atmosphere.
Data from a process unit that produces propylene oxide indicate the flow
rate of the vent stream following the condenser to be about 2.8 scm/min
(99 scfm) and the estimated VOC emissions to the atmosphere to be
0.05 kg/hr (0.1 Ib/hr).
      Sec-butyl  alcohol is produced by  absorbing n-butenes in sulfuric
acid to form butyl hydrogen sulfate that is then hydrolyzed to sec-butyl
alcohol and dilute sulfuric acid.   The reactor product is steam stripped
from the dilute acid solution and purified by distillation.   Information
on the sec-butyl alcohol  production at one process unit does not indicate
any specific process vents.   All process vents at this process unit are
reported to be flared so that any reactor VOC emissions would be
combusted.
                                   2-19

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      In general, production of chemicals by hydrolysis/hydration
processes generate little or no reactor VOC emissions.   Based on
production information for ethylene glycol  and propylene glycol, these
hydration reactors do not have process vent streams associated with them.
Ethylene glycol and propylene glycol are produced by hydrating ethylene
oxide and propylene oxide, respectively.  The reactions for both chemicals
result in production of di- and tri-glycols as coproducts.  Following the
reactor, the glycols are separated and purified by distillation.  No
reactor VOC emissions are vented to the atmosphere from the glycol process
units in the EDP.
      2.2.2.14  Hydrogenation.  Hydrogenation  is  the process  in  which
hydrogen is added to an organic compound.   The hydrogenation process can
involve direct addition of hydrogen to the double bond of an unsaturated
molecule, replacement of oxygen in nitro-containing organic compounds to
form amines, and addition to aldehydes and ketones to produce alcohols.
The major chemical  products of hydrogenation reactions include
cyclohexane, aniline, n-butyl  alcohol, hexamethylene diamine,
1,4-butanediol, cyclohexanone, and toluene diamine.
      In general, reactor  VOC  emissions  from hydrogenation  reactions
appear to be small  in comparison with other chemical reactions.   However,
combustion devices are typically associated with the vent streams of
hydrogenation processes.  Excess hydrogen in these vent streams makes them
suitable for combustion in most cases.
      Hexamethylene diamine  is made  by hydrogenation of  adiponitrile.
Reactor VOC emissions from hexamethylene diamine production are small
according to information on three process units in the EDP.  Excess
hydrogen used in the reaction is recovered from the vent stream and
recycled to the reactor.  At two of these process units, the process vent
streams are used as fuel in a plant boiler.  The average vent stream flow
rate following hydrogen recovery at the three process units is
14.0 scm/min (494 scfm) and the average heat content is 21 MJ/scm
(564 Btu/scf).  The VOC content of the noncombusted vent stream at the
process unit that does not use combustion is approximately 3 kg/hr
(6.6 Ib/hr).  The VOC content of the combusted streams at the other two
process units is estimated to be negligible prior to combustion.
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      Cyclohexane is produced by the liquid-phase hydrogenation  of
benzene.   In this process, both cyclohexane and  hydrogen are recovered
from the process vent stream.   Information from  one cyclohexane plant
indicates  that there is usually no  flow in the vent stream following
product and hydrogen recovery.  The process vent stream after these
recovery systems is discharged to the atmosphere only during emergencies,
and the stream is vented to  the flare system for VOC destruction during
such upset conditions.
      Cyclohexane,  1,4-butanediol,  and  toluene  diamine  production  involve
the hydrogenation of phenol, 2-butyne-l,4-diol,  and 2,4-dinitrotoluene,
respectively.  The  process vent stream for these hydrogenation reactions
are ultimately combusted in  incinerators, boilers, or flares.
Precombustion vent  stream characteristic data are available for only one
of these vent streams--n-butyl alcohol.
      2.2.2.15   Isomerization.   During  isomerization, organic  compounds
are converted by heat and a  catalytic reaction that changes the
arrangement of atoms in a molecule, but not the  number of atoms.
Catalysts  include aluminum chloride, antimony chloride, platinum, and
other metals.  Temperatures  range from 750 to 900 °C (400 to 480 °F),  and
pressures  range from 7 to 50 atmospheres.8
      Isomerization  is  used  in  petroleum refining to convert
straight-chain hydrocarbons  into branched-chain  hydrocarbons.  An example
is the conversion of n-butane to isobutane.9  Emissions from this process
would be expected to be small, as with other high-temperature and
high-pressure reactor processes in the EDP.
      2.2.2.16  Neutralization.   Neutralization  is a process  used to
manufacture linear  alkylbenzene; benzenesulfonic acid,  sodium salt;
dodecylbenzene sulfonic acid, sodium salt; and oil-soluble petroleum
sulfonate, calcium  salt.  Diagrams of all  of the production processes  show
no reactor process vent streams.10
      2.2.2.17  Nitration.  Nitration is the unit process  in which  nitric
acid is used to introduce one or more nitro groups (N02) into organic
compounds.  Aromatic nitrations are usually performed with a mixture of
nitric acid and concentrated sulfuric acid.  Nitrobenzene and
dinitrotoluene are the major products of nitration reactions.
                                   2-21

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     Nitrobenzene production  involves the direct nitration of benzene
using a mixture of nitric acid and sulfuric acid.   Only a small  quantity
of by-products, primarily nitrated phenols,  are produced by the  reaction.
The reaction is normally blanketed with nitrogen gas to reduce fire and
explosion hazards.   At one process unit producing nitrobenzene,  waste acid
is removed from the reactor product stream by a separator followed by
recovery of excess benzene by distillation.   Vent streams from the reactor
and separator are combined and discharged directly to the atmosphere.
Industry information suggests that a new, but unnamed, process without
reactor process vents is now in operation.  No data, however,  are
available for this process.  The main components of the combined vent
streams are nitrogen and benzene.  The EDP nitrobenzene nitration process
has a combined vent stream flow rate estimated to be 0.38 scm/min
(13 scftn) and an approximate heat content of 16 MJ/scm (430 Btu/scf).  The
VOC emissions to the atmosphere from the vent streams are 8.6  kg/hr
(19 Ib/hr).
     Dinitrotoluene  is  produced  by  nitration of toluene  in two  stages
using different acid mixtures.  As in the case of nitrobenzene production,
the waste acid is separated and recycled.  Two process units producing
dinitrotoluene operate scrubbers on the reactor vent streams to remove
VOC.  Following scrubbing, one plant discharges the vent stream to the
atmosphere while the other incinerates the vent stream.  No data are
available on the characteristics of the incinerated vent stream.  The flow
rate of the nonincinerated vent stream following the scrubber  is estimated
to be 23 scm/min (812 scfm).  Heat content of the vent stream is
negligible.  Estimated VOC emissions to the atmosphere are 0.05 kg/hr
(0.1 Ib/hr).
     2.2.2.18  Oliqomerization.   In  the  oligomerization  process,
molecules of a single reactant are linked together to form larger
molecules consisting of 2 to about 10 of the original molecules.
Oligomerization is used to make several chemicals including alcohols,
dodecene, heptene, nonene, and octene.  Typically, it is a
high-temperature, high-pressure process.H»12  Diagrams for all  of the
chemical production processes show no reactor process vent streams.13-15
                                   2-22

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Other chemical unit processes with similar high-pressure characteristics,
such as pyrolysis, emit little or no VOC's.
      2.2.2.19  Oxidation.   Oxidation  of organic  chemicals  is  the  addition
of one or more oxygen atoms into the compound.  The oxidation processes
considered here include pure oxygen oxidation and chemical oxidation.  An
example of pure oxygen oxidation is the production of ethylene oxide using
pure oxygen and ethylene.  The production of adipic acid from nitric acid
is an example of chemical oxidation.
      Ethylene oxide  can  be  produced by  oxidation  using  air or pure
oxygen.  In the pure oxygen process, ethylene, oxygen and  recycled gas are
reacted under pressures of 1 to 3 MPa (150 to 440 psia).   Two reactor
process vent  streams are reported by one process unit that produces
ethylene oxide by pure oxygen oxidation.  At this plant, the  reactor
effluent is sent through an ethylene oxide absorber.  The  offgas from this
absorber is routed to the carbon dioxide removal system.   A portion of the
vent stream from the carbon dioxide absorber system is recycled to the
reactor, while the remainder is used as fuel in industrial boilers.  The
carbon dioxide absorber liquid is regenerated, and the removed carbon
dioxide is vented to the atmosphere.  The portion of the vent stream from
the carbon dioxide absorber that is sent to a boiler has an approximate
flow rate of  176 scm/min (6,200 scfm)  and a heat content of 13 MJ/scm
(350 Btu/scf).  The estimated discharge rate to the atmosphere from the
carbon dioxide absorber liquid regenerator vent is 345 scm/min
(12,184 scfm), and the heat content is 0.15 MJ/scf (4 Btu/scf).   Prior to
combustion in the boiler, the VOC flow rate of the first vent stream is
0.59 kg/hr (1.3 Ib/hr).  For the uncontrolled vent stream, VOC emissions
to the atmosphere are estimated to be 59 kg/hr (130 Ib/hr).
      In adipic acid production, an alcohol  ketone mixture  is  oxidized
using nitric acid.  Adipic acid from the reactor is stripped of nitrogen
oxides produced by the reaction and is then refined.  Of the three process
units producing adipic acid included in the EDP, two of the process unit
discharge the stripper offgas to the atmosphere.  Vent stream flow rates
at the three process units are estimated to range from 24  to  132 scm/min
(848 to 4,662 scfm).   The heating values of all three vent streams are
negligible,  and there are no VOC emissions from any of these process units.
                                   2-23

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     2.2.2.20  Oxyacetylation.  Oxyacetylation is the process in which
oxygen and an acetyl group are added to an olefin to produce an
unsaturated acetate ester.  Oxyacetylation is used in a new commercial
process to make vinyl acetate.
     Vinyl acetate  is produced from ethylene, acetic acid, and oxygen.
Reactor VOC emissions from one vinyl  acetate production process  unit are
small.   The estimated vent stream flow rate and  heating values are
0.2 scm/min (7 scfm) and 15 MJ/scm (403 Btu/scf), respectively.   The VOC
flow rate prior to combustion is relatively low  (0.05 kg/hr [0.1  lb/hr]).
     2.2.2.21  Oxyhalogenation.   In the oxyhalogenation process, a
halogen acid is catalytically oxidized to the halogenated compound with
air or oxygen.  The main oxyhalogenation process is oxychlorination, in
which HC1 is catalytically oxidized to chlorine  with air or oxygen.
(Oxychlorination processes using air are included in the analyses for air
oxidation processes.)  The oxychlorination process is used in the
production of ethylene dichloride.
     As  described previously, most ethylene  dichloride  is  produced  by  the
"balanced process" that combines oxychlorination and direct chlorination
of ethylene.  In the oxychlorination reaction, ethylene, HC1, and oxygen or
air are combined.  Emissions from air oxychlorination reactions  used in
ethylene dichloride production are regulated by  the air oxidation
processes new source performance standards (NSPS).  Only emissions from
oxygen oxychlorination reactions are considered  here.  At one process unit
producing ethylene dichloride by oxychlorination using oxygen, the reactor
effluent is condensed, and excess ethylene is recycled to the reactor.   A
small portion of the recycle stream is vented to prevent a buildup of
impurities.  The vent stream is incinerated in order to comply with State
implementation plans (SIP's) and to reduce vinyl chloride emissions that
are regulated under national emission standards  for hazardous air
pollutants (NESHAP).  The vent stream flow rate  prior to incineration  is
approximately 8.5 scm/min (300 scfm), and the estimated heat content is
27 MJ/scm (725 Btu/scf).  The VOC flow rate in the vent stream is
estimated to be 340 kg/hr (750 lb/hr).  Following incineration,  the
estimated VOC emissions to the atmosphere are 6.8 kg/hr (15 lb/hr).
                                   2-24

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      2.2.2.22  Phosaenation.   Phosgenation  is  the  process  in which
phosgene (COC12) reacts with an amine to form an isocyanate, or with an
alcohol to form a carbonate.  Toluene diisocyanate is the major chemical
product of this chemical unit process.
      Toluene diisocyanate  is  produced  by  phosgenating  toluene  diamine.
At one process unit, the reactor vent is routed through distillation
columns for  product/by-product recovery and purification.  Thus, no
reactor VOC  emissions are vented to the atmosphere from the process.*6
      2.2.2.23  Pvrolvsis.   Pyrolysis  is a chemical reaction  in which  the
chemical change of a substance occurs by heat alone.   Pyrolysis includes
thermal rearrangements into isomers, thermal polymerizations,  and thermal
decompositions.  The major use of this process is in the production of
ethylene by  the steam pyrolysis of hydrocarbons.  Other pyrolysis products
include ketene (a captive intermediate for acetic anhydride manufacture)
and by-products of ethylene production, such as propylene, bivinyl,
ethyl benzene, and styrene.
      Ethylene and other  olefins  can be produced  from a variety of
hydrocarbon  feeds, including natural gas liquors, naphtha, and gas-oil.
Maximum ethylene production is achieved by adjusting furnace temperature
and steam-to-hydrocarbon ratios.  Pyrolysis gases from the furnace are
cooled, compressed,  and separated into the desired products.  As in
refinery operations, the economics of olefins production make  recovery of
gaseous products desirable.  Thus, process vent streams to the atmosphere
are minimized.  The ethylene process unit included in the EDP  reports no
process vent streams to the atmosphere.
     The first step  in the manufacture of acetic anhydride  is  production
of ketene.   Ketene and water are produced by pyrolysis of acetic acid.  At
two plants producing acetic anhydride, the pyrolysis  products  are cooled
and separated prior to acetic anhydride formation.   No process vent
streams are associated with the pyrolysis reaction to produce  ketene.
     2.2.2.24  Sulfonation.   Sulfonation  is the  process  by which the
sulfonic acid group (S020H), or the corresponding salt, or sulfonyl halide
is attached to a carbon atom.   "Sulfonation" can also be used to mean
treatment of any organic compound with sulfuric acid,  regardless of the
nature of products formed.

                                   2-25

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      Isopropyl  alcohol  is made  by  sulfonation of propylene to isopropyl
hydrogen sulfate and subsequent hydrolysis to isopropyl alcohol  and
sulfuric acid.
      Many  detergents are made by the sulfonation of mixed linear
alkylbenzenes.  These include benzenesulfonic acid and dodecylbenzene
sulfonic acid.  To manufacture these,  the linear alkylbenzenes  are
sulfonated with sulfur trioxide or oleums of various strengths.   One
process uses diluted sulfur trioxide vapor in a continuous operation.  The
reaction and heat removal  occurs in a thin film on a cooled reactor
surface.  The process forms almost entirely the p-sulfonic acid.17
      The EDP  contains emissions data on  one  sulfonation process unit
controlled only with a caustic scrubber.   It has extremely low  uncombusted
VOC emissions (0.05 kg/hr [0.1 lb/hr]),  even though the vent stream flow
rate is relatively large (52 scm/min [1,836 scfm]).
2.3   DISTILLATION OPERATIONS
      Distillation is the most commonly used  separation and purification
procedure in refineries and large organic chemical  manufacturing plants.
The fundamental  operating principles for a distillation column  are the
same regardless of the application.  This section briefly discusses some
of the fundamental  principles involved in distillation to provide a better
understanding of operating characteristics of distillation units and
causes of VOC emissions from these units.
2.3.1  Types of Distillation
      Distillation is an operation  separating one or more feed stream(s)
into two or more product streams,  each product stream having component
concentrations different from those in the feed stream(s).   The  separation
is achieved by the redistribution of the components between the  liquid-
and vapor-phase while the less volatile components(s)  concentrate in the
liquid-phase.  Both the vapor- and liquid-phase originate predominantly by
vaporization and condensation of the feed stream.
      Distillation systems can be divided  into subcategories according  to
the operating mode,  the operating pressure, the number of distillation
stages, the introduction of inert gases,  and the use of additional
b
 For batch distillation, the word "charge" should be used in place of
 "stream", wherever applicable.
                                   2-26

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compounds to aid separation.  A distillation unit may operate in a
continuous or a batch mode.  The operating pressures can be below
atmospheric (vacuum), atmospheric, or above atmospheric (pressure).
Distillation can be a single stage or a multistage process.  Inert gas,
especially steam, is often introduced to improve separation.  Finally,
compounds are often introduced to aid in distilling hard-to-separate
mixture constituents (azeotropic and extractive distillation).
      Single stage batch  distillation  is  not common  in large scale
chemical production but  is widely used in laboratories and pilot plants.
Separation is achieved by charging a still with material, applying heat
and continuously removing the evolved vapors.   In some instances, steam is
added or pressure is reduced to enhance separation.
      Single stage continuous distillation  is referred to  as flash
distillation (Figure 2-3).  It is generally a direct separation of a
component mixture based  on a sudden change in pressure.   Since flash
distillation is a rapid  process, steam or other components are not added
to improve separation.   A flash distillation unit is frequently the first
separation step for a stream from the reactor.   The heated products from a
reaction vessel are pumped to an expansion chamber.  The pressure drop
across the valve, the upstream temperature, and the expansion chamber
pressure govern the separation achieved.  The light ends quickly vaporize
and expand away from the heavier bottom fractions, which remain in the
liquid-phase.   The vapors rise to the top of the unit and are removed.
Bottoms are pumped to the next process step.
      Fractionating distillation  is a  multistage distillation  operation.
It is the most commonly  used type of distillation unit in large organic
chemical plants, and it  can be a batch or a continuous operation.  At
times, inert carriers (such as steam) are added to the distillation
column.  Fractionating distillation is accomplished by using trays,
packing, or other internals in a vertical column to provide multiple
intimate contact of ascending vapor and descending liquid streams.  A
simplified block flow diagram of a fractionation column is shown in
Figure 2-4.   The light end vapors evolving from the column are condensed
and collected  in an accumulator tank.  Part of the distillate is returned
to the top of  the column so it can fall countercurrent to the rising

                                   2-27

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                                                Overheads (Gas) or
                                                    Light Ends
              Pressure Control
                  Valve
      Feed
                                                    Flash Distillation
                                                       Column
                                              Bottoms (Liquid) or
                                                  Heavy Ends
Figure  2-3.   Flash distillation.
                                           2-28

-------
Feed 	 ••
V - Vapor
L = Uquid


\
—f o u ^N
Residue^ Hebo"er )


7
V2
I
V3
V4
t
V5
f
V6
f
V7
t
V8
t
V9
s


>
1
L1
I
L2
J
L3
I
L4
I
L5
I
L6
I
17
t
Ley
LO


'


— »C Reflux "V- *• Coolant
\^ Condenser J

(Accum
Tm.
TV


ulatorA
ik J

             Heating Medium
            (Bottom Products)
(Overhead Products)
Figure  2-4.  A  conventional  fractionating  column.

                                       2-29

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vapors.  For difficult separations,  additional  compounds may be added to
achieve the desired separation.  This is commonly referred to as
extractive distillation and is typically used in lubricant oil  refining.
A desorption column is very similar to a fractionating distillation column
except that it does not use a reflux condenser.
2.3.2  Fundamental Distillation Concepts
     The emissions from distillation units are dependent on the size,
operating conditions, and types of components present.  Therefore,  the
design parameters and selection of operating conditions are discussed in
this section to provide a better understanding of the emissions.
     The separation  of a mixture of materials  into one or more  individual
components by distillation is achieved by selecting a temperature and
pressure that allow the coexistence of vapor and liquid phases in the
distillation column.   Distillation is described as a mass-transfer
operation involving the transfer of a component through one phase to
another on a molecular scale.  The mass transfer is a result of a
concentration difference or gradient stimulating the diffusing substance
to travel from a high concentration zone to one of lower concentration
until equilibrium is reached.  The maximum relative concentration
difference between distillation materials in the vapor- and liquid-phases
occurs when a state of equilibrium is reached.  The equilibrium state is
reached when the concentrations of components in the vapor-phase and
liquid-phase, at a given temperature and pressure, do not change,
regardless of the length of time the phases stay in contact.
      For an  ideal  system,  the  equilibrium relationship  is determined
using the law of Dal ton and Raoult.  Dal ton's Law states that the total
pressure of a mixture of gases is equal to the sum of the partial
pressures of each gas constituent:

                                 Pt  - * PI                            (2-1)
where:
      Pt  =  Total  pressure,
      p^  *  Partial  pressure  of each  gas  constituent,  and
      n   =  Number of constituents.
                                   2-30

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Dalton's Law further states that the partial pressure of each ideal gas
constituent is proportional to the mole fraction (relative percentage) of
that gas in an ideal solution:
                                Pi ' yi Pt                           (2.2)
where:
      yi  -  Mole fraction.
Raoult's Law states the relationship for ideal solutions between the
partial pressure of a mixture constituent in the vapor phase and its
composition in the liquid-phase in contact.  When the vapor phase is at
equilibrium with the solution, the partial pressure of the evolved
component  is directly proportional to its vapor pressure (at the same
temperature) and its mole fraction in the solution:
                               Pi  • Xi  p*i                            (2.3)
where:
       Xj = Mole  fraction  in the solution.
      p*i = Vapor pressure of  the  pure  substance  at  the  same
            temperature.
These  statements may be combined to given an equilibrium vaporization
ratio  (K value).   A simplified expression for this ratio is:
                                                                     (2.4)
This equilibrium constant is used to evaluate the properties that affect
gas-liquid equilibrium conditions for individual components and mixtures.
The K value represents the distribution ratio of a component between the
vapor and liquid-phase at equilibrium.  The K value for various materials
may be calculated using thermodynamic equations of state or through
empirical methods (suitably fitting data curves to experimental data).
This constant is an extremely important tool for designing distillation
units (determining required temperatures, pressures, and column size).
     Another basic distillation concept  is  the  separation  factor or
relative volatility (ai) of system components.  This is the equilibrium
                                   2-31

-------
ratio of the mole fractions of component i  to some component  j  in  the
vapor and liquid phase:
                                                                    (2.5)

This is expressed as the ratio of the vapor pressures for an ideal
mixture:

                                                                    (2.6)

The ratio is a measure of the separability of the two components to be
separated and is very important in designing distillation equipment.  In
the case of a binary system, the two components to be separated are the
two components present in the feed.  In a multicomponent system, the
components to be separated are referred to as "heavy key" and "light key."
The "heavy key" is the most volatile component desired to be present in
significant quantities in the bottom products or the residue.  Similarly,
"light key" is the least volatile compound desired to be present in
significant quantities in the overhead products.  Generally, separation by
distillation becomes uneconomical when the relative volatility of the
light key and heavy key is less than LOS.*8
     The  operating  temperature  and  pressure  in  a distillation unit  are
interrelated.  A decision made for the value of one of these parameters
also determines the value of the other parameter.  Essentially,  the
pressure and temperature are chosen so that the dew pointc condition for
 The dew point temperature is the temperature at which the first droplet
 of liquid is formed as the vapor mixture is coiled at constant pressure,
 and the dew point pressure is that at which the first droplet of liquid
 is formed as the pressure is increased on the vapor at constant
 temperature.
 Mathematically, the dew point is defined by:

                              Z Xf  -  1.0  - Z^l                       (2.7)
                              1               K
                                   2-32

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the overhead products and the bubble point  conditions for the bottom
products can be present inside the distillation unit.  The actual decision
on these two conditions is predicated upon economic considerations and is
made after evaluating the following items:

      •     The  relative volatility, ffij,  of the components.  A lower
           pressure  in the column  increases the value of a\i and  improves
           separation.  This would result in a shorter fractionating
           column.

      •     The  effect of  pressure  on vapor volume  in the distillation
           unit.  The vapor volume increases as the pressure decreases,
           requiring a larger diameter vessel.

      •     The  effect of  pressure  on column wall thickness.  Higher
           pressures require increased wall thickness and raise  costs.

      •     Cost of achieving desired temperature and pressures.   The cost
           of changing the pressure and that of changing the temperature
           are  considered independently since these two costs are not
           proportional.

      •     The  thermal stability limit of the compounds being processed.
           Many compounds decompose, polymerize, or react when the
           temperature reaches some critical value.  In such cases it  is
           necessary to reduce the design pressure so that this  critical
           reaction  temperature is not reached at  any place in the
           distillation unit.

      Data  on the use of vacuum during distillation were compiled  for a

number of major chemicals to predict the use of vacuum for distillation.

The physical  properties of the compounds using vacuum during distillation
d
 The bubble-point temperature is the temperature at which the
 first bubble of vapor is formed on heating the liquid at
 constant pressure.  The bubble-point pressure is the pressure
 at which the first bubble of vapor is formed on lowering the
 pressure on the liquid at constant temperature.

 Mathematically, the bubble point is defined by:

                          n
                          Z yi - 1.0 - Z Ki XT                 (2.8)
                                   2-33

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were compared with those of compounds not using vacuum,  with the following
conclusions:
     •      Compounds with a melting point less than -10 °C  (14 °F) and
            with  a boiling point greater than 150 °C (302 °F) are likely
            to be distilled under vacuum.
     •      If the boiling point of a compound  is less than  50 °C (122 °F)
            then  it  is likely to be distilled at or above atmospheric
            pressure.
     •      For the  separation of compounds with boiling points between
            50 and 150 °C (122 and 302 °F), the use of vacuum depends on
            the thermal operable limit of the compound (i.e., temperature
            range in which the compound does not decompose,  polymerize, or
            react).19
     In designing a distillation system, once  the operating temperature
and pressure are established,  the type of distillation is considered.
Flash distillation is preferred for separation of components with a high
relative volatility.  Steam is the most frequently used heat source for
column distillation, since using a direct fired heater (although used  in
some instances)  could create a dangerous situation.   Steam is also used
for distilling compounds that are thermally unstable or have high boiling
points.  Azeotropic and extractive distillation are  used to separate
compounds that are difficult to separate.  For example,  benzene is
sometimes added  in a distillation process to achieve separation of an
alcohol-water mixture.
     For a  flash unit, the design of the flash vessel size  is relatively
straightforward.   In the case of a fractionating unit design,  once the
column pressure and temperature are determined, the  reflux ratio (fraction
of total overhead condensate returned to column) is  selected to ensure an
adequate liquid phase in the distillation column for vapor enrichment.
The number of trays (or weight of column packing), column diameter, and
auxiliary equipment (e.g.,  pumps,  condenser, boiler, and instruments)  are
then determined.   The final  decision on all  these items is based on
engineering judgment and economic trade offs.   More  detailed discussion on
the design of distillation units is readily available in various chemical
engineering texts.20-22
                                   2-34

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2.4   REACTOR VOLATILE ORGANIC COMPOUND  EMISSIONS
      Reactor VOC emissions  include all  VOC's  in process  vent  streams  from
reactors and product  recovery  systems.  Process product recovery equipment
includes devices  such as condensers, absorbers, and adsorbers, used to
recover product  or by-product  for  use, reuse, or sale.  Not included  in
product recovery  equipment are product purification devices involving
distillation operations.
      Reactor processes  may  be either  liquid-phase  reactions or gas  phase
reactions.   Four  potential atmospheric emissions points are shown in
Figure 2-5 and include:
      •      Direct reactor process  vents  from  liquid-phase  reactors;
      •      Vents from recovery devices  applied to  vent  streams from
            liquid phase reactors  (raw materials, products, or by-products
            may be recovered  from vent streams  for  economic or
            environmental  reasons);
      •      Process  vents  from gas-phase  reactors after  either the primary
            or secondary product recovery  device (gas-phase reactors
            always have  primary product  recovery devices);  and
      •      Exhaust  gases  from combustion  devices applied to any  of  the
            above streams.
Some chemical production processes may have no reactor process vents  to
the atmosphere, while others may have one or more vent streams.   Specific
examples of the  first three vent types described above are presented  in
Figures 2-6, 2-7, and 2-8.  Each figure represents one of the 173 reactor
process chemicals covered within the scope of this document.
      The production  of  nitrobenzene by  a  nitration process is shown in
Figure 2-6 and is an example of a  liquid reaction with an uncontrolled
vent stream  (Vent Type A).  Benzene is nitrated at 55 °C (131 °F) under
atmospheric pressure by a mixture  of concentrated nitric and  sulfuric
acids in a series; reactor vents are the largest source of VOC's in
nitrobenzene plants.  It should be noted, however,  that a new process
without vents may now be in use.
     The production  of  ethylbenzene is  an example  of  a  liquid-phase
reaction of continuous stirred-tank reactions.  The crude reaction mixture
flows to a separator, where the organic phase is decanted from the aqueous
                                   2-35

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Liquid-Phase Reactor
                          Gas
                            Vent Type A
Gas-Phase Reactor
                                       Uquid
                         Gas
      Product/By-product
       Recovery Device
Vent Type B
                                                                               Recovered
                                                                                Product
                             Liquid
                                               Gas
                                                  Vent Type C
                                                         Uquid
Process Vents Controlled by Combustion
    Process Vent Streams
       from A, B, or C
Combustion
                                                                    Gas
                                                                       Vent Type D
                                                                    C
      Figure 2-5.   General examples  of reactor-related  vent streams.

                                           2-36

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                                                        To Atmosphere
                                                        0
   Benzen
  Nitric Acii
Sulfuric Acid
          Figure  2-6.   Process  flow diagram  for the manufacture of nitrobenzene.7
                                                2-37

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Benzene


Ethylene
                To Atmosphere
                    Water
                   Scrubber
                 ©
                    voc
                   Scrubber
                   Benzene
                   Scrubber
Alkylatlon
 Reactor
                 Crude
              Ethylbenzene
 Product
Purification
(Distillation)
Ethylbenzene
    Figure  2-7.   Process  flow diagram  for  the manufacture  of ethylbenzene.

                                             2-38

-------
                                        To Atmosphere
                                       ©
                                            voc
                                          Scrubber
Isopropyl
 Alcohol

 Catalyst
Dehydrogenation
    Reactor
Condenser
                                                Acetone
                                                Product
        Figure  2-8.   Process  flow diagram for the  manufacture of  acetone.

                                                2-39

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waste acid.  Emission streams from the reactors and separator are combined
and emitted to the atmosphere without any control  devices (Vent 1).
Available data indicate that controls are not typically applied to this
process, and that where the vent stream is passed through a VOC recovery
device before it is discharged to the atmosphere (Type B).  Figure 2-7
depicts an alkylation unit process used to produce ethylbenzene.  Ethylene
and benzene are combined in the alkylation reactor to form crude
ethylbenzene.  The process vent stream from the reactor goes through three
types of scrubbers before discharging to the atmosphere.  The first
scrubber recovers the excess benzene reactant from the vent stream and
recycles it to the reactor.  The second scrubber removes any ethylbenzene
product in the vent stream and recycles it to the reactor.  Finally,
traces of acidic catalyst in the vent stream are removed by a water
scrubber before the vent stream is discharged to the atmosphere.  Vent 1
in the figure designates the only reactor vent stream for this example.
The crude ethylbenzene product stream from the reactor is purified by
distillation.  The vent stream from the product purifications operations
(Vent 2) is associated with distillation operations and, therefore, is not
considered to be a reactor-related vent stream.
      Figure  2-8  shows  a dehydrogenation  process used  to  produce acetone.
Although this is not the most widely used process to make acetone, it
provides a good example of a vapor-phase reaction and its associated vent
streams (Type C).  In this process, isopropyl alcohol is catalytically
dehydrogenated to acetone in a vapor-phase reaction to 400 to 500 °C
(750 to 930 °F).  The crude acetone then passes through a condenser or
primary VOC recovery device.  The overheads or process vent stream from
the primary condenser then goes through a VOC scrubber and is released to
the atmosphere (Vent 1).  Acetone is further refined and emissions from
the refining process (Vent 2) are again not considered to be reactor
related.  Other processes used to manufacture acetone have no reactor
process vent streams to the atmosphere.
      As  indicated  in Section  2.2,  the  characteristics of reactor vent
streams (i.e., heat content, flow rate, VOC control) vary widely among the
numerous chemicals and chemical reactions in the SOCMI.   In addition, the
numerous possible combinations of product recovery devices and  reactors

                                   2-40

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 introduce another  source of variability among various process units using
 the same reaction  type.
      Data  included in  the  reactor processes  emissions  profile  (see
 Appendix B) have been grouped by chemical reaction type.  Table 2-4
 summarizes the VOC emission characteristics of reactor processes using
 30 of the 35 chemical reactions considered here.  These data represent the
 process vent stream characteristics following the final gas treatment
 device  (i.e., condenser, absorber, or adsorber) but prior to any
 combustion device.
      There  is  a  wide variability  in the  VOC  emission characteristics
 associated with the various chemical reactions.  For example, VOC emission
 factors range from 0 kilograms per gigagrams (kg/Gg) (0 lb/106 Ib) of
 product for pyrolysis reactions to 120,000 kg/Gg (120,000 lb/106 Ib) of
 product for hydroformylation reactions.  Wide variability also exists in
 the emission characteristics associated with process units using the same
 chemical reaction.  For example, process units using chlorination
 reactions have VOC emission factors that range from 292 to 9,900 kg/Gg
 (292 lb/106 Ib to  9,900 lb/106 Ib).  The variability in process vent
 stream  flow rates  and heating values is not as pronounced as the VOC
 emission factors.  Flow rates range from 0 to 537 scm/min (0 to
 18,963  scfm) and heating values range from 0 to 58.8 MJ/scm (0 to
 1,579 Btu/scf).
      Although  process  vent  stream characteristics are  variable, there are
 some general observations evident in Table 2-4.  First, process units
 using 11 of the 30 reaction types included in Table 2-4 were reported to
 have no reactor process vents.  These reactions include:  ammination,
 ammonolysis, cleavage,  etherification,  fluorination, hydration,
 neutralization, oligomerization, phosgenation,  pyrolysis, and
 sulfurization.
     A  second general  observation  evident in Table  2-4  is that the
 process units using six of the reaction types included in there were
reported to have the largest VOC emission factors.   The reactions include:
hydroformylation, chlorination,  dehydrogenation, condensation,
oxychlorination,  and hydrochlorination.  The vent streams from process
                                   2-41

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  TABLE  2-4.    SUMMARY  OF REACTOR-RELATED VOLATILE  ORGANIC  COMPOUND EMISSION FACTORS,
                        VENT STEAM  HEAT CONTENTS, AND FLOW  RATES PRIOR  TO  COMBUSTION
Chemical
reaction type
Alkylation
Aimiination
Arrmono lysis
Carbonylation
Chlorination
Cleavage
Condensation
Dehydration
Dehydrogena t i on
Dehydroch I or i na t i on
Esterif i cat ton
Etherif i cat ion
Fluorination
Hydration
Hydrogenation
Hydrochlorination
Hydroformylation
Hydrodimerization
Hydrolysis
Neutralization
Nitration
Oligomerization
Oxidation
(Pure 02)
Oxyacety I at i on
Oxychlorination
(Pure 02)
Phosgenation
Pyro lysis
Sulfonation
Sulfurization
(Vapor Phase)
Range (or single
value) of reactor
VOC emission
factorsa-b
(kg/Gg)
5.95-78.1
Od
Od
443
292-9,900
Od
8,900
DNAe
11,400-12,600
4,790
4.38-594
Od
0*
0^
0-943
2,000-14,700
120,000
1,310
2.5
Od
9.95-1,350
Od
3,900

2.20
7,180

Od
Od
29.2
Od

Range (or single
value) of vent stream
VOC contentb-c
(g/scm)
3.07-252
Od
Od
1.06
0.209-118
Od
554
DMA*
56.5-75.0
1,097
5.34-21.8
Od
Od
Od
0-1,638
28.1-2,247
878
6.69
0.27
Od
0.03-390
Od
0-2.85

3.82
658

Od
Od
0.014
Od

Percent of
process units with
vent streams using
combustion control
33.3
Od
Od
100
44.4
Od
100
0
85.7
100
14.3
Od
Od
od
83.3
80
100
0
33.3
Od
33.3
Od
25

0
100

od
(^
0
Od

Range (or
single value)
of flow ratesb
( son/mi n)
0.24-0.48
Od
Od
537
1.13-342
Od
4.16
DMA"
16.3-147
0.283
0.06-2.12
Od
Od
Od
0.09-36.9
0.566
20.6
30.6
2.80
Od
0.37-23.3
Od
24-345

0.198
8.61

Od
Od
52.7
Od

Range (or
single value) of
vent stream
heat contentb
(MJ/scnO
0.15-6.74
Od
Od
11.0
0-45.7
Od
39.8
DMA*
10.4-11.2
22.3
3.8
Od
Od
Od
12.0-58.8
18.6-47.9
45.9
2.61
0
Od
0-16.2
Od
0-0.15

15.2
26.6

Od
Od
0
Od

Emission factors are expressed in terms of kilogram of VOC emitted per gigagram of chemical produced and represent
 emissions to the atmosphere from the final gas  treatment device (if used), but  before combustion (if used).

^Ranges are due to:  (1) different chemicals produced by the chemical process, and (2> different controls used at the
 process units.
CAU values represent emission stream characteristics after the final product recovery device and before combustion
 (if used).
dNo reactor vent streams are associated with chemicals manufactured by this chemical process.

"DNA = Data not available.
                                                    2-42

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units using these reactions also tend to have both high heating values and
a high percentage application of combustion devices.
2.5   VOLATILE ORGANIC  COMPOUND  EMISSIONS  FROM DISTILLATION UNITS
      The discussions on  distillation  column operating  theory  and design
show the basic factors of column operation.  Vapors separated from the
liquid phase  in a column rise out of the column to a condenser.  The gases
and vapors entering the condenser can contain VOC, water vapor, and
noncondensibles such as oxygen, nitrogen, and carbon dioxide.  The vapors
and gases originate from vaporization of liquid feeds, dissolved gases in
liquid feeds, inert carrier gases added to assist in distillation (only
for inert carrier distillation), and air leaking into the
column—especially in vacuum distillation.  Most of the gases and vapors
entering the  condenser are cooled enough to be collected as a liquid-
phase.  The noncondensibles (oxygen, nitrogen, C02, and other organics
with low boiling points), if present, are not usually cooled to the
condensation  temperature and are present as a gas stream at the end of the
condenser.  Portions of this gas stream are often recovered in devices
such as scrubbers, adsorbers, and secondary condensers.  Vacuum generating
devices  (e.g., pumps and ejectors), when used, might also affect the
amount of noncondensibles.  Some organics can be absorbed by condensed
steam in condensers located after vacuum jets.  In the case of oil-sealed
vacuum pumps, the oil losses increase the VOC content of the
noncondensibles exiting the vacuum pump.  The noncondensibles from the
last process  equipment (e.g., condensers, pumps, ejectors, scrubbers,
adsorbers, etc.) constitute the emissions from the distillation unit,
unless they are controlled by combustion devises such as incinerators,
flares, and boilers.
     The most frequently encountered  emission points from fractionation
distillation  operations are illustrated for several types of distillation
units in Figures 2-9 to 2-12.  These emission points are indicated by the
numbers in parenthesis as follows:  condenser (1), accumulator (2), hot
wells (3), steam jet ejectors (4), vacuum pump (5), and pressure relief
valve (6).  Emissions of VOC's are created by the venting of
noncondensible gases that concurrently carry out some hydrocarbons.
                                   2-43

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                                       Vent to Atmosphere
                 Distillation
                  Column
                                                               Pressure Relief
                                                                  Valve (6)
                                             Overhead Product
Figure  2-9.   Potential  VOC emission points for  a  nonvacuum distillation
               column.
                                       2-44

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                                                         Steam
                                                               Steam Jet
                                                               Ejector (4)
                                          Pressure Relief
                                            Valve (6)
                                      Accumulator
                                          (2)
                                                           Cooling
                                                            Water (CW)
                                Overhead Product
                                                                           Steam
                                                                                Steam Jet
                                                                                Ejector (4)
                                                Barometric
                                                Condenser
    Distillation
     Column
                                 (3) Hot well
                                                                           Vent
                                                                        Vent
                                                                      Wastewater
Figure 2-10.
Potential VOC emission points for a vacuum distillation
column using steam jet  ejectors with  barometric  condenser.
                                        2-45

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                                                           Steam
                                                                Steam Jet
                                                                Ejector (4)
  Vapor Phase
                      Cooling Water
                            Condenser
                               0)
                                                              Cooling Water
                                          Accumulator
                                              (2)
                             Overhead Product
                                                                                Accumulator
                                                                                    (2)
        Distillation
         Column
Figure 2-11.   Potential  volatile organic compound emission points for  a
                vacuum distillation  column using steam jet ejectors.
                                       2-46

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      Vapor Phase
                                       Condenser (1)
                                                                              Vent
                                                          Vacuum Pump (5)
                                                           Accumulator (2)
             Uquld Reflux
                                       Overhead Product
            Distillation
             Column
Figure 2-12.
Potential VOC  emission  points for vacuum  distillation column
using  a vacuum pump.
                                       2-47

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     The total volume of gases emitted from a distillation operation
depends upon air leaks into the vacuum column (reduced pressure increases
leaks and increased size increases leaks),  the volume of inert carrier gas
used, gases dissolved in the feed, efficiency and operation conditions of
the condenser and other process recovery equipment, and physical
properties of the organic constituents.  Knowledge of the quantity of air
leaks and dissolved gases in the column in conjunction with information on
organic vapor physical properties and condenser operating parameters
allows estimation of the VOC emissions that may result from a given
distillation unit operation.
     The operating  parameters for the  industry vary to  such a great
extent that it is difficult to develop precise emission factors for
distillation units.  However, an extensive data base was gathered for
organic chemical industry distillation units.  The data base contains
information on operating characteristics, emission controls, exit flows,
and VOC emission characteristics.23  This data base is presented in
Appendix B.
     The distillation emission profile contains  information on the  type
of distillation involved, the produced recovery and VOC control equipment,
the vent stream characteristics, and the other distillation units in the
plant.  The vent stream characteristics listed for each column in the
profile (determined downstream of product recovery devices, but upstream
of combustion devices) are:  (1) volumetric flow rate,  (2) heat content,
(3) VOC emission rate, (4) VOC concentration, and  (5) chlorine
concentration.  A summary of the distillation emissions profile is
presented in Table 2-5.
                                   2-48

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            TABLE  2-5.   OVERVIEW  OF  THE  DISTILLATION OPERATIONS
                                  EMISSIONS  PROFILE
Operating Characteristics of the Distillation Emission Profile
Average offgas flow rate, mroin                  1.0  (35)
 (scfm)

Flow range, m3/nrir> (scfm)                         0.001-18  (0.035-636)

Average VOC emission rate, kg/hr                  36 (79)
   (Ib/hr), precontrolled3

Average VOC emission rate, kg/hr                  5.9  (13)
   (Ib/hr), control ledb
VOC emission range, kg/hr (Ib/hr),                0-1,670 (0-3681)
  precontrolled
Calculated downstream of adsorbers, absorbers, and condensers,  but
 upstream of combustion devices.

Controlled VOC emission rates were estimated using a 98-percent
 destruction efficiency for flares, boilers, and incinerators (where it
 was indicated that control devices were being used).
                                   2-49

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2.6  REFERENCES

 1.  Synthetic Organic Chemicals, United States Production and Sales.
     U. S. International Trade Commission.  USITC Publication 2219.
     Washington, D.C.  U. S. Government Printing Office.  1989.  p. 1, 3,
     and 4 through 7.

 2.  Memorandum from Lesh, S. A., Radian Corporation, to Evans, L. B.,
     EPA/CPB.  June 22,  1984.  13 pp.  Revised list of high-volume
     reactor process chemicals.

 3.  Memorandum from Read, B. S., Radian Corporation, to Reactor
     Processes File.  May 28, 1985.  12 pp.  Summary of the emission data
     profile.

 4.  Memorandum from Fidler, K., Radian Corporation, to L. B. Evans,
     EPA/CPB.  July 6, 1983.  66 pp.  Identification of chemical
     production routes and unit processes expected to be used in the
     future to manufacture the chemicals considered in the Carrier Gas
     Project.

 5.  Urea Manufacturing  Industry—Technical Document.
     U. S. Environmental Protection Agency.  Research Triangle Park, N.C.
     Publication No. EPA-450/3-81-001.  January 1981.  p. 3-8.

 6.  Faith, W., et al.   Industrial- Chemicals 4th Edition.  New York,
     John Wiley & Sons.  1975.  pp. 129 and 130.

 7.  Chemical Products Synopsis—Methyl Chloride.  Mannsville Chemical
     Products.  Cortland, New York.  May 1984.  2 pp.

 8.  Herrick, E. C., et  al, Mitre Corporation.  Unit Process Guide to
     Organic Chemical Industries.  Ann Arbor, Ann Arbor Science
     Publishers, Inc., 1979.  pp. Ill, and 120 and 121.

 9.  Ref. 8.

10.  Ref. 3.

11.  Waddams, A. L.  Chemicals from Petroleum, 4th Edition.  Houston,
     Gulf Publishing Company.  1978.  p. 24, 145 and 146, 173 and  174,
     and 221 and 222.

12.  Industrial Process  Profiles for Environmental Use.
     U. S. Environmental Protection Agency.  Research Triangle Park, N.C.
     Publication No. EPA- 600/2-77-023f.  February 1977.  pp. 6-637
     through 6-641, and  6-667.

13.  CS-CB Olefins (Dimersol X).  Hydrocarbon Processing.  60(11):192.
     November 1981.

14.  Alpha Olefins.  Hydrocarbon Processing.  58(11):128.  November  1979.


                                   2-50

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15.  Ce-Cg Olefins  (Dimersol  Process).  Hydrocarbon  Processing.
     56(11):170.  November  1977.

16.  Organic Chemical Manufacturing, Volume  7:  Selected  Processes.
     U. S. Environmental  Protection Agency.  Research Triangle Park, N.C.
     Publication No.  EPA-450/3-80-028b.  December  1980.   Section  1-i,
     p. III-l to III-4.

17.  Ref. 8.

18.  Van Winkle, M.   Distillation.  New York, McGraw-Hill,  1967.

19.  Letter from Desai, T., Energy and Environmental Analysis (EEA) to
     Beck, D., U. S.  Environmental Protection Agency.   12 pp.
     August 11, 1980.

20.  King, C. J.  Separation  Processes, Second Edition.   New York,
     McGraw-Hill, 1980.

21.  Foust, A. S.,  et al.   Principles of Unit Operations.   New York,
     John Wiley & Sons, 1960.

22.  Treybal, R. E.   Mass Transfer Operations, Third Edition.  New York,
     McGraw-Hill, 1980.

23.  Distillation Operations  in Synthetic Organic  Chemical  Manufacturing
     Industry—Background Information for Proposed Standards.
     U. S. Environmental  Protection Agency.  Research Triangle Park, N.C.
     Publication No.  EPA-450/3-83-005a.  December  1983.
                                   2-51

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                     3.0  EMISSION CONTROL TECHNIQUES

     This chapter discusses the volatile organic compound (VOC) emission
control techniques that are applicable to distillation and reactor process
vent streams.  The control techniques discussed are grouped into two broad
categories:   (1) combustion control devices and (2) recovery devices.
Combustion control devices are designed to destroy the VOC's in the vent
stream prior  to atmospheric discharge.  Recovery devices limit VOC
emissions by  recycling material back through the process.
     The design and operating efficiencies of each emission control
technique are discussed in this chapter.  The conditions affecting the VOC
removal efficiency of each type of device are examined, along with an
evaluation of their applicability for use to reduce emissions from
distillation  vents and reactor vents.  Emphasis has been given to
combustion control devices due to their wide applicability for the control
of VOC's in Synthetic Organic Chemical Manufacturing Industry (SOCMI) vent
streams.
3.1  COMBUSTION CONTROL DEVICES
     Combustion control devices, unlike noncombustion control devices,
alter the chemical structure of the VOC.  Combustion is complete if all
VOC's are converted to carbon dioxide and water.  Incomplete combustion
results in some of the VOC being totally unaltered or being converted to
other organic compounds such as aldehydes or acids.
     The combustion control  devices discussed in the following four
subsections are flares, thermal incinerators, catalytic incinerators, and
boilers/process heaters.  Each device is discussed separately with respect
to its operation, destruction efficiency, and applicability to reactor
process and distillation vent streams.
                                    3-1

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3.1.1  Flares
     3.1.1.1  Flare Process Description.   Flaring is an open combustion
process in which the oxygen required for combustion is provided by the air
around the flame.  Good combustion in a flare is governed by flame
temperature, residence time of components in the combustion zone,
turbulent mixing of the components to complete the oxidation reaction, and
the amount of oxygen available for free radical formation.
     Flare types can be divided into two main groups:  (1) ground flares
and (2) elevated flares, which can be further classified according to the
method to enhance mixing within the flare tip (air-assisted,
steam-assisted, or nonassisted).  The discussion in this chapter focuses
on elevated flares, which are the most common type in the chemical
industry.  The basic elements of an elevated flare system are shown in
Figure 3-1.  The vent stream is sent to the flare through the collection
header (1).  The vent stream entering the header can vary widely in
volumetric flow rate, moisture content, VOC concentration, and heat value.
The knock-out drum (2) removes water or hydrocarbon droplets that could
create problems in the flare combustion zone.  Vent streams are also
typically routed through a water seal (3) before going to the flare.  This
presents possible flame flashbacks, caused when the vent stream flow rate
to the flare is too low and the flame front pulls down into the stack.1
     Purge gas (nitrogen [N2], carbon dioxide [063], or natural gas)
(4) also helps to prevent flashback in the flare stack (5) caused by low
vent stream flow.  The total volumetric flow to the flame must be
carefully controlled to prevent low flow flashback problems and to avoid a
detached flame (i.e., a space between the stack and flame with incomplete
combustion), which is caused by an excessively high flow rate.  A gas
barrier (6) or a stack seal is sometimes used just below the flare head to
impede the flow of air into the flare gas network.
     The VOC stream enters at the base of the flame, where it is heated by
already burning fuel and pilot burners (7) at the flare tip (8).  Fuel
flows into the combustion zone, where the exterior of the microscopic gas
pockets is oxidized.  The rate of reaction is limited by the mixing of the
fuel and oxygen from the air.  If the gas pocket has sufficient oxygen and
                                    3-2

-------
                                           Gas Barrier
                                              (6)
                                                Flare Stack
                                                   (5)   '
           Gas Collection Header
                 (1)
Vent Stream -
                     Knock-out
                      Drum  -"
                       (2)
V
  Drain
         Purge
          Gas
Water
 Seal-
 (3)
                                                                   Steam Nozzles
                                                                       (9)
                                                                     \
LJ
                                                    Flare Tip
                                                      (8)
                                                                                   Pilot Burners
                                                                                       (7)
^
*''
^-

t_
_ <
—1

                                               Ignition
                                               Device

                                                Air Line

                                                Gas Line
      Figure 3-1.   Steam assisted elevated  flare system.

                                                 3-3

-------
residence time in the flame zone, it can be completely burned.   A
diffusion flame receives its combustion oxygen by diffusion of air into
the flame from the surrounding atmosphere.  The high volume of flue gas
flow in a flare requires more combustion air at a faster rate than simple
gas diffusion can supply.  Thus, flare designers add high velocity steam
injection nozzles (9) to increase gas turbulence in the flame boundary
zones, thus drawing in more combustion air and improving combustion
efficiency.  This steam injection promotes smokeless flare operation by
minimizing the cracking reaction that forms carbonaceous soot.
Significant disadvantages of steam use are increased noise and cost.  The
steam requirement depends on the composition of the gas flared, the steam
velocity from the injection nozzle, and the tip diameter.  Although some
gases can be flared smokelessly without any steam, typically 0.01 to
0.6 kilograms (kg) (0.02 to 1.33 pounds [lb]) of steam per kg of flare gas
is required.
     Steam injection is usually controlled manually by an operator who
observes the flare (either directly or on a television monitor) and adds
steam as required to maintain smokeless operation.  Several flare
manufacturers offer devices such as infrared sensors, which monitor flame
characteristics and adjust the steam flow rate automatically to maintain
smokeless operation.
     Some elevated flares use forced air instead of steam to provide the
combustion air and the mixing required for smokeless operation.  These
flares consist of two coaxial flow channels.  The combustible gases flow
in the center channel and the combustion air (provided by a fan in the
bottom of the flare stack) flows in the annulus.  The principal advantage
of air-assisted flares is that they can be used where steam is not
available.  Air assist is rarely used on large flares because air flow is
difficult to control when the gas flow is intermittent.  About
67.7 kilowatts (90.8 horse power) of blower capacity is required for each
45.4 kilograms per hour (kg/hr) [100 pounds per hour (lb/hr)] of gas
flared.2
     Ground flares are usually enclosed and have multiple burner heads
that are staged to operate based on the quantity of gas released to the
flare.  The energy of the gas itself (because of the high nozzle pressure

                                    3-4

-------
drop) is usually adequate to provide the mixing necessary for smokeless
operation and air or steam assistance is not required.  A fence or other
enclosure reduces noise and light from the flare and provides some wind
protection.
     Ground flares are less numerous and have less capacity than elevated
flares.  Typically, they are used to burn gas continuously, while
steam-assisted elevated flares are used to dispose of large amounts of gas
released in emergencies.3
     3.1.1.2  Factors Affecting Flare Efficiency.4  Flare combustion
efficiency is a function of many factors:  (1) heating value of the gas,
(2) density of the gas, (3) flammability of the gas, (4) auto-ignition
temperature of the gas, and (5) mixing at the flare tip.
     The flammability limits of the gases that are flared influence
ignition stability and flame extinction.  The flammability limits are
defined as the stoichiometric composition limits (maximum and minimum) of
an oxygen-fuel mixture that will burn indefinitely at given conditions of
temperature and pressure without further ignition.  In other words, gases
must be within their flammability limits to burn.  When flammability
limits are narrow, the interior of the flame may have insufficient air for
the mixture to burn.  Fuels with wide limits of flammability (for
instance, hydrogen) are, therefore, easier to combust.
     The auto-ignition temperature of a fuel affects combustion because
gas mixtures must be at high enough temperature and at the proper mixture
strength to burn.  A gas with a low auto-ignition temperature will ignite
and burn more easily than a gas with a high auto-ignition temperature.
     The heating value of the fuel also affects the flame stability,
emissions,  and flame structure.  A lower heating value fuel produces a
cooler flame that does not favor combustion kinetics and also is more
easily extinguished.  The lower flame temperature will also reduce buoyant
forces, which reduces mixing.
     The density of the gas flared also affects the structure and
stability of the flame through the effect on buoyancy and mixing.  By
design, the velocity in many flares is very low; therefore, most of the
flame structure is developed through buoyant forces as a result of
combustion.   Lighter gases, therefore, tend to burn better.  In addition

                                    3-5

-------
to burner tip design, the density of the fuel also affects the minimum
purge gas required to prevent flashback for smokeless flaring.
     Poor mixing at the flare tip or poor flare maintenance can cause
smoking (particulate).  Fuels with high carbon to hydrogen ratios (greater
than 0.35) have a greater tendency to smoke and require better mixing if
they are to be burned smoke!essly.
     Many flare systems are currently operated in conjunction with
baseload gas recovery systems.  Such systems are used to recovery VOC's
from the flare header system for reuse.  Recovered VOC's may be used as a
feedstock in other processes or as fuel in process heaters, boilers, or
other combustion devices.  When baseload gas recovery systems are applied,
the flare is generally used to combust process upset and emergency gas
releases that the baseload system is not designed to recover.  In some
cases, the operation of a baseload gas recovery system may offer an
economic advantage over operation of a flare alone since sufficient
quantities of useable VOC's can be recovered.
     3.1.1.3  EPA Flare Specifications.  The EPA has established flare
combustion efficiency criteria in the Code of Federal Regulations
(40 CFR 60.18) that specify that 98 percent combustion efficiency can be
achieved provided that certain operating conditions are met:  (1) the
flare must be operated with no visible emissions and with a flame present;
(2) the net heating value of the flared stream must be greater than
11.2 megajoules per standard cubic meter (MJ/scm) [300 British thermal
units per standard cubic foot (Btu/scf)] for steam-assisted flares, and
7.45 MJ/scm (200 Btu/scf) for a flare without assist; and (3) steam
assisted and nonassisted flares must have an exit velocity less than
18.3 meters per second (m/sec) [60 feet per second (ft/sec)].  Steam
assisted and nonassisted flares having an exit velocity greater than
18.3 m/sec (60 ft/sec) but less than 122 m/sec (400 ft/sec) can achieve
98 percent control if the net heating value of the gas stream is greater
than 37.3 MO/scm (1,000 Btu/scf).  Air-assisted flares, as well as
steam-assisted and nonassisted flares with an exit velocity less than
122 m/sec (400 ft/sec) and a net heating value less than 37.3 MJ/scm
(1,000 Btu/scf), can determine the allowable exit velocity by using an
equation in 40 CFR 60.18.

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     3.1.1.4  Applicability of Flares.  Most of the SOCMI plants are
estimated to have a flare.5  Flares are usually designed to control either
the normal process vents or emergency upsets.  The latter involves the
release of large volumes of gases.  Often, large diameter flares designed
to handle emergency releases are used to control continuous vent streams
from various process operations.  In refineries, many process vents are
usually combined in a common gas header that supplies fuel to boilers and
process heaters.  However, excess gases, fluctuations in flow in the gas
line, and emergency releases are sometimes sent to a flare.
     Flares have been found to be useful emission control devices.  They
can be used for almost any VOC stream, and can handle fluctuations in VOC
concentration, flow rate, and inerts content.  Some streams, such as those
containing high concentrations of halogenated or sulfur-containing
compounds, are not usually flared due to corrosion of the flare tip or
formation of secondary pollutants (such as sulfur dioxide [S02]).
3.1.2  Thermal Incinerators
     3.1.2.1  Thermal Incinerator Process Description.  Any VOC heated to
a high enough temperature in the presence of enough oxygen will be
oxidized to COg and water.  This is the basic principle of operation of a
thermal incinerator.  The theoretical temperature required for thermal
oxidation depends on the structure of the chemical involved.  Some
chemicals are oxidized at temperatures much lower than others.  However, a
temperature can be identified that will result in the efficient
destruction of most VOC's.  All practical thermal incineration processes
are influenced by residence time, mixing, and temperature.  An efficient
thermal incinerator system must provide:
     •    A chamber temperature high enough to enable the oxidation
          reaction to proceed rapidly to completion;
     •    Enough turbulence to obtain good mixing between the hot
          combustion products from the burner, combustion air, and VOC;
          and
     •    Sufficient residence time at the chosen temperature for the
          oxidation reaction to reach completion.
     A thermal incinerator is usually a refractory-lined chamber
containing a burner (or set of burners) at one end.  As shown in
                                    3-7

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Figure 3-2, discrete dual fuel burners (1) and inlets for the offgas (2)
and combustion air (3) are arranged in a premixing chamber (4) to
thoroughly mix the hot products from the burners with the process vent
streams.  The mixture of hot reacting gases then passes into the main
combustion chamber (5).  This chamber is sized to allow the mixture enough
time at the elevated temperature for the oxidation reaction to reach
completion (residence times of 0.3 to 1.0 second are common).  Energy can
then be recovered from the hot flue gases in a heat recovery section (6).
Preheating combustion air or offgas is a common mode of energy recovery;
however, it is sometimes more economical to generate steam.  Insurance
regulations require that if the waste stream is preheated, the VOC
concentration must be maintained below 25 percent of the lower explosive
limit to remove explosion hazards.
     Thermal  incinerators designed specifically for VOC incineration with
natural gas as the auxiliary fuel may also use a grid-type (distributed)
gas burner,6 as shown in Figure 3-3.  The tiny gas flame jets (1) on the
grid surface (2) ignite the vapors as they pass through the grid.  The
grid acts as a baffle for mixing the gases entering the chamber (3).  This
arrangement ensures burning of all vapors at lower chamber temperature and
uses less fuel.  This system makes possible a shorter reaction chamber,
yet maintains high efficiency.
     Other parameters affecting incinerator performance are the vent
stream heating value, the water content in the stream, and the amount of
excess combustion air (i.e., the amount of air above the stoichiometric
air needed for reaction).  The vent stream heating value is a measure of
the heat available from the combustion of the VOC in the vent stream.
Combustion of the vent stream with a heating value less than 1.9 MJ/scm
(50 Btu/scf) usually requires burning auxiliary fuel to maintain the
desired combustion temperature.  Auxiliary fuel requirements can be
lessened or eliminated by the use of recuperative heat exchangers to
preheat combustion air.  Vent streams with a heating value above
1.9 MO/scm (50 Btu/scf) may support combustion but may need auxiliary fuel
for flame stability.
     Other parameters affecting incinerator performance are the vent
stream heating value, the water content in the stream, and the amount of

                                    3-8

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                                                                                     Stack
  Waste Gas
     Inlet
     (2)
 Auxiliary    —-i
Fuel Burner —J
 (Discrete)    I—
   (D
                                                                         Optional Heat
                                                                           Recovery
                                                                             (6)
             Premixing
             Chamber
                (4)
Combustion Chamber
        (5)
                   Figure 3-2.   Discrete burner,  thermal  oxidizer.

                                              3-9

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                                                                 Stack
               Burner Plate
                   (2)
Flame Jets
   0)
                    (Natural Gas)
                    Auxiliary Fuel
                                                       Optional Heat
                                                        Recovery
                                                           (4)
Figure 3-3.   Distributed burner, thermal  oxidizer.

                            3-10

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excess combustion air  (i.e., the amount of air above the stoichiometric
air needed for reaction).  The vent stream heating value is a measure of
the heat available from the combustion of the VOC in the vent stream.
Combustion of the vent stream with a heating value less than 1.9 MJ/scm
(50 Btu/scf) usually requires burning auxiliary fuel to maintain the
desired combustion temperature.  Auxiliary fuel requirements can be
lessened or eliminated by the use of recuperative heat exchangers to
preheat combustion air.  Vent streams with a heating value above
1.9 MJ/scm (50 Btu/scf) may support combustion but may need auxiliary fuel
for flame stability.
     A thermal incinerator, handling vent streams with varying heating
values and moisture content, requires careful adjustment to maintain the
proper chamber temperatures and operating efficiency.  Since water
requires a great deal of heat to vaporize, entrained water droplets in an
offgas stream can increase auxiliary fuel requirements to provide the
additional energy needed to vaporize the water and raise it to the
combustion chamber temperature.  Combustion devices are always operated
with some quantity of excess air to ensure a sufficient supply of oxygen.
The amount of excess air used varies with the fuel and burner type but
should be kept as low as possible.  Using too much excess air wastes fuel,
because the additional air must be heated to the combustion chamber
temperature.  Large amounts of excess air also increases flue gas volume
and may increase the size and cost of the system.  Packaged, single-unit
thermal incinerators can be built to control streams with flow rates in
the range of 8.5 standard cubic meters per second (son/see) [300 standard
cubic feet per minute (scfm)] to about 1,415 scm/sec (50,000 scfm).
     Thermal oxidizers for halogenated VOC may require additional control
equipment to remove the corrosive combustion products.  The halogenated
VOC streams are usually scrubbed to prevent corrosion due to contact with
acid gases formed during the combustion of these streams.  The flue gases
are quenched to lower their temperature and are then routed through
absorption equipment such as packed towers or liquid jet scrubbers to
remove the corrosive gases.
     3.1.2.2  Thermal Incinerator Efficiency.  The VOC destruction
efficiency of a thermal oxidizer can be affected by variations in chamber
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temperature, residence time, inlet VOC concentration,  compound type,  and
flow regime (mixing).  Test results show that thermal  oxidizers can
achieve 98 percent destruction efficiency for most VOC's at combustion
chamber temperatures ranging from 700 to 1,300 °C (1,300 to 2,370 °F) and
residence times of 0.5 to 1.5 sec.7  These data indicate that significant
variations in destruction efficiency occurred for Cj to C§ alkanes and
olefins, aromatics (benzene, toluene, and xylene), oxygenated compounds
(methyl ethyl ketone and isopropanol), chlorinated organics (vinyl
chloride), and nitrogen-containing species (acrylonitrile and ethyl amines)
at chamber temperatures below 760 °C (1,400 °F).  This information, used
in conjunction with kinetics calculations, indicates the combustion
chamber parameters for achieving at least a 98-percent VOC destruction
efficiency are a combustion temperature of 870 °C (1,600 °F) and a
residence time of 0.75 sec (based upon residence in the chamber volume at
combustion temperature).  A thermal oxidizer designed to produce these
conditions in the combustion chamber should be capable of high destruction
efficiency for almost any nonhalogenated VOC.
     At temperatures over 760 °C (1,400 °F), the oxidation reaction rates
are much faster than the rate of gas diffusion mixing.  The destruction
efficiency of the VOC then becomes dependent upon the fluid mechanics
within the oxidation chamber.  The flow regime must ensure rapid, thorough
mixing of the VOC stream, combustion air, and hot combustion products from
the burner.  This enables the VOC to attain the combustion temperature in
the presence of enough oxygen for sufficient time so the oxidation
reaction can reach completion.
     Based on studies of thermal oxidizer efficiency, it has been
concluded that 98 percent VOC destruction or a 20 parts per million volume
(ppmv) compound exit concentration is achievable by all new incinerators.
The maximum achievable VOC destruction efficiency decreases with
decreasing inlet concentration because of the much slower combustion
reaction rates at lower inlet VOC concentrations.  Therefore, a VOC weight
percentage reduction based on the mass rate of VOC exiting the control
device versus the mass rate of VOC entering the device would be
appropriate for vent streams with VOC concentrations above approximately
2,000 ppmv (corresponding to 1,000 ppmv VOC in the incinerator inlet

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stream since air dilution  is typically 1:1).  For vent streams with VOC
concentrations below approximately 2,000 ppmv, it has been determined that
an  incinerator outlet concentration of 20 ppmv (by compound), or lower, is
achievable by all new thermal oxidizers.8  The 98-percent efficiency
estimate is predicated on  thermal incinerators operated at 870 °C
(1,600 °F) with 0.75 sec residence time.
     3.1.2.3  Applicability of Thermal Incinerators.  In terms of
technical feasibility, thermal incinerators are applicable as a control
device for most SOCMI vent streams.  They can be used for vent streams
with any VOC concentration and any type of VOC, and they can be designed
to  handle minor fluctuations in flows.  However, excessive fluctuations in
flow (i.e., process upsets) might not allow the use of incinerators and
would require the use of a flare.  Presence of elements such as halogens
or  sulfur might require some additional equipment, such as scrubbers for
acid gas removal.  Thermal incinerators are currently used to control VOC
emissions from a number of process operations, including reactors and
distillation operations.
3.1.3  Industrial Boilers/Process Heaters
     Industrial boilers and process heaters can be designed to control
VOC's by incorporating the reactor process or distillation vent stream
with the inlet fuel or by  feeding the stream into the boiler or heater
through a separate burner.  The major distinctions between industrial
boilers and process heaters are that the former produces steam at high
temperatures while the latter raises the temperature of process streams as
well as superheating steam, typically at temperatures lower than with an
industrial boiler.  The process descriptions for an industrial boiler and
a process heater are presented separately in the following two sections.
The process descriptions focus on those aspects that relate to the use of
these combustion devices as a VOC control method.
     3.1.3.1  Industrial Boiler/Process Description.  Surveys of
industrial boilers show that the majority of industrial boilers used in
the chemical industry are of watertube design.  Furthermore, over half of
these boilers use natural  gas as a fuel.9  In a water tube boiler, hot
combustion gases contact the outside of heat transfer tubes, which contain
hot water and steam.  These tubes are interconnected by a set of drums
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that collect and store the heated water and steam.  The water tubes are of
relatively small diameter, 5 centimeters (2.0 inches), providing rapid
heat transfer, rapid response to steam demands, and relatively high
thermal efficiency.*0  Energy transfer from the hot flue gases to water in
the furnace water tube and drum system can be above 85 percent efficient.
Additional energy can be recovered from the flue gas by preheating
combustion air in an air preheater or by preheating incoming boiler feed
water in an economizer unit.
     When firing natural gas, forced or natural draft burners are used to
thoroughly mix the incoming fuel and combustion air.  If a SOCMI vent
stream is combusted in a boiler, it can be mixed with the incoming fuel or
fed to the furnace through a separate burner.  In general, burner design
depends on the characteristics of either the fuel mix (when the SOCMI vent
stream and fuel are combined) or on the characteristics of the vent stream
alone (when a separate burner is used).  A particular burner design,
commonly known as a high intensity or vortex burner, can be effective for
vent streams with low heating values (i.e., streams where a conventional
burner may not be applicable).  Effective combustion of low heating value
streams is accomplished in a high intensity burner by passing the
combustion air through a series of spin vanes to generate a strong vortex.
     Furnace residence time and temperature profiles vary for industrial
boilers depending on the furnace and burner configuration, fuel type, heat
input, and excess air level.1*  A mathematical model has been developed
that estimates the furnace residence time and temperature profiles for a
variety of industrial boilers.12  This model predicts mean furnace
residence times of from 0.25 to 0.83 second for natural gas-fired water
tube boilers in the size range from 4.4 to 44 megawatts (MW) (15 to
150 x 106 Btu/hr).  Boilers at or above the 44 MW size have residence
times and are generally operated at temperatures that ensure a 98-percent
VOC destruction efficiency.  Furnace exit temperatures for this range of
boiler sizes are at or above 1,200 °C (2,200 °F) with peak furnace
temperatures occurring in excess of 1,540 °C  (2,810 °F).
     3.1.3.2  Process Heater Description.  A process heater is similar to
an industrial boiler in that heat liberated by the combustion of fuels is
transferred by radiation and convection to fluids contained in tubular

                                   3-14

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coils.  Process heaters are used in chemical manufacturing to drive
endothermic reactions, such as natural gas reforming and thermal cracking.
They are also used as feed preheaters and as reboilers for some
distillation operations.  The fuels used in process heaters include
natural gas, refinery offgases, and various grades of fuel oil.  Gaseous
fuels account for about 90 percent of the energy consumed by process
heaters.13
     There are many variations in the design of process heaters depending
on the application considered.  In general, the radiant section consists
of the burner(s), the firebox, and a row of tubular coils containing the
process fluid.  Most heaters also contain a convection section in which
heat is recovered from hot combustion gases by convective heat transfer to
the process fluid.
     Process heater applications in the chemical industry can be broadly
classified with respect to firebox temperature:  (1) low firebox
temperature applications, such as feed preheaters and reboilers;
(2) medium firebox temperature applications, such as stream superheaters;
and (3) high firebox temperature applications, such as pyrolysis furnaces
and steam-hydrocarbon reformers.  Firebox temperatures within the chemical
industry can range from about 400 °C (750 °F) for preheaters and reboilers
to 1,260 °C (2,300 °F) for pyrolysis furnaces.
     3.1.3.3  Industrial Boilers and Process Heater Control Efficiency.  A
boiler or process heater furnace can be compared to an incinerator where
the average furnace temperature and residence time determines the
combustion efficiency.  However, when a vent gas is injected as a fuel
into the flame zone of a boiler or process heater, the required residence
time is reduced due to the relatively high flame zone temperature.  The
following test data, which document the destruction efficiencies for
industrial boilers and process heaters, are based on injecting the wastes
identified into the flame zone of each combustion control device.
     A U.  S. EPA-sponsored test was conducted to determine the destruction
efficiency of an industrial boiler for polychlorinated biphenyls
(PCB's).14  The results of this test indicated that the PCB destruction
                                   3-15

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efficiency of an oil-fired industrial boiler firing PCB-spiked oil  was
greater than 99 percent for a temperature range of 1,361 to 1,520 °C
(2,482 to 2,770 °F) and a range of residence time of 2 to 6 sec.   This
efficiency was determined based on the PCB content measured by a  gas
chromatograph in the fuel feed and flue gas.
     As discussed in previous sections, firebox temperatures for  process
heaters show relatively wide variations depending on the application (see
Section 3.1.3.2).  Tests were conducted by the EPA to determine the
benzene destruction efficiency of five process heaters firing a benzene
offgas and natural gas mixture.15-17  jne units tested are representative
of process heaters with low temperature fireboxes (reboilers) and medium
temperature fireboxes (superheaters).  Sampling problems occurred while
testing one of these heaters, and, as a result, the data for that test may
not be reliable and are not presented.^  The reboiler and superheater
units tested showed greater than a 98-percent overall destruction
efficiency for Cj to Cs hydrocarbons.19  Additional tests conducted on a
second superheater and a hot oil heater showed that greater than
99 percent overall destruction of C} to 05 hydrocarbons occurred  for both
units.20
     3.1.3.4  Applicability of Industrial Boilers and Process Heaters.
Industrial boilers and process heaters are currently used by industry to
combust process vent streams from distillation operations, reactor
operations, and general refinery operations.  These devices are most
applicable where high vent stream heat recovery potential exists.
     Both boilers and process heaters are essential to the operation of a
plant.  As a result, only streams that are certain not to reduce  the
device's performance or reliability warrant use of a boiler or process
heater as a combustion control device.  Variations in vent stream flow
rate and/or heating value could affect the heat output or flame stability
of a boiler or process heater and should be considered when using these
combustion devices.  Performance or reliability may be affected by the
presence of corrosive products in the vent stream.  Because these
compounds could corrode boiler or process heater materials, vent streams
with a relatively high concentration of halogenated or sulfur-containing
compounds are usually not combusted in boilers or process heaters.  When
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corrosive VOC's are combusted, the flue gas temperature must be maintained
above the acid dew point to prevent acid deposition and subsequent
corrosion from occurring.
     The introduction of a vent stream into the furnace of a boiler or
heater could alter the heat transfer characteristics of the furnace.  Heat
transfer characteristics are dependent on the flow rate, heating value,
and elemental composition of the vent stream, and the size and type of
heat generating unit being used.  Often, there is no significant
alteration of the heat transfer, and the organic content of the process
vent stream can, in some cases, reduce the amount of fuel required to
produce the desired heat.  In other cases, the change in heat transfer
characteristics after introduction of a vent stream may affect the
performance of the heat-generating unit, and increase fuel requirements.
For some vent streams, there may be potential safety problems associated
with ducting reactor process or distillation vents to a boiler or process
heater.  Variation in the flow rate and organic content of the vent stream
could, in some cases, lead to explosive mixtures within a boiler furnace.
Flame fluttering within the furnace could also result from variations in
the process vent stream characteristics.  Precautionary measures should be
considered in these situations.
     When a boiler or process heater is applicable and available, they are
excellent control devices providing at least 98 percent destruction of
VOC's.  In addition, near complete recovery of the vent stream heat
content is possible.  However, both devices must operate continuously and
concurrently with the pollution source unless an alternate control
strategy is available in the event that the heat generating capacity of
either unit is not required and is shut down.
3.1.4  Catalytic Oxidizers
     3.1.4.1  Catalytic Oxidation Process Description.  Catalytic
oxidation is the fourth major combustion technique examined for VOC
emission control.  A catalyst increases the rate of chemical reaction
without becoming permanently altered itself.  Catalysts for catalytic
oxidation cause the oxidizing reaction to proceed at a lower temperature
than is required for thermal  oxidation.  These units can also operate well
at VOC concentrations below the lower explosive limit, which is a distinct

                                   3-17

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advantage for some process vent streams.  Combustion catalysts include
paladium and platinum group metals, magnesium oxide, copper oxide,
chromium, and cobalt.21  These are deposited in thin layers on inert
substrates to provide for maximum surface area between the catalyst and
the VOC stream.  The substrate may be either pelletized or cast in a rigid
honeycomb matrix.
     A schematic of a catalytic oxidation unit is shown in Figure 3-4.
The waste gas (1) is introduced into a mixing chamber (2), where it is
heated to about 316 °C (600 °F) by contact with the hot combustion
products from auxiliary burners (3).  The heated mixture is then passed
through the catalyst bed (4).  Oxygen and VOC's migrate to the catalyst
surface by gas diffusion and are adsorbed in the pores of the catalyst.
The oxidation reaction takes place at these active sites.  Reaction
products are desorbed from the active sites and transferred by diffusion
back into the waste gas.22  The combusted gas may then be passed through a
waste heat recovery device (5) before exhausting into the atmosphere.
     The operating temperatures of combustion catalysts usually range from
260 to 427 °C (500 to 800 °F).  Lower temperatures may slow down and
possibly stop the oxidation reaction.  Temperatures greater than 732 °C
(1,350 °F) may result in shortened catalyst life and possible
deterioration of the catalyst.  Any accumulation of particulate matter,
condensed VOC, or polymerized hydrocarbons on the catalyst could block the
active sites and, therefore, reduce effectiveness.  Some catalysts can
also be deactivated by compounds containing sulfur, bismuth, phosphorous,
arsenic, antimony, mercury, lead, zinc, tin, or halogens.23  if the
catalyst is exposed to any of these compounds, VOC's will pass through
unreacted or be partially oxidized to form compounds such as aldehydes,
ketones, and organic acids.  Catalysts are now being marketed that are
resistant to various poisons, specifically sulfur and halogenated
compounds.  Other designs incorporate a sacrificial bed to protect the
catalyst.  Materials accumulated on the catalyst can be removed by
physical or chemical means, thus restoring the catalyst activity to its
original (fresh) level.  Condensed organics accumulated on the catalyst
can be removed with thermal treatment.
                                   3-18

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                                                                                      To Atmosphere
                                                                                          Stack
 Auxiliary Fuel
   Burners
     (3)
Waste Gas
    (1)
          Catalyst Bed
           /  W
Auxiliary Fuel
  Burners
Mixing Chamber
      (2)
                                                                               Optional Heat
                                                                                 Recovery
                                                                                    (5)
                              Figure 3-4.   Catalytic oxidizer.

                                                3-19

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     3.1.4.2  Catalytic Oxidizer Control  Efficiency.   Catalytic oxidizer
destruction efficiency is dependent on the space velocity (i.e, the
catalyst volume required per unit volume gas processed per hour),
operating temperature, oxygen concentration, and waste gas VOC composition
and concentration.  A catalytic unit operating at about 450 °C (840 °F)
with a catalyst bed volume of 0.014 to 0.057 cubic meters (0.5 to 2 cubic
feet) per 0.47 scm/sec (1,000 scfm) of vent stream passing through the
device can achieve 95 percent VOC destruction efficiency.  However,
catalytic oxidizers have  been reported to achieve efficiencies of
99 percent or greater.24  These higher efficiencies are usually obtained
by increasing the catalyst bed volume-to-vent stream flow ratio.
     3.1.4.3  Applicability of Catalytic Oxidizers.  Catalytic oxidation
has been successfully applied to a variety of SOCMI processes.25  It is
basically a chemical process that operates at a lower temperature than
thermal oxidation, thereby reducing fuel consumption.  In addition,
catalytic oxidation produces smaller amounts of secondary air emissions
such as nitrous oxides and carbon dioxide than thermal incinerators.  High
destruction efficiencies have been achieved through catalytic oxidation,
partly because the SOCMI exhausts are generally very clean and suitable
for this technology.  The SOCMI industry has been accustomed to using a
variety of process catalysts and is skilled in understanding and
maintaining catalytic systems at maximum performance.
     Periodic replacement of catalyst is required at intervals of 2 to
5 years due to thermal aging, masking, and poisoning processes.  Thermal
aging is caused by high temperatures damaging the active metal, sintering,
or crystallizing the surface area.  This results in permanent loss of
surface area.  Masking occurs when there is a loss of active sites due to
a buildup of dust, carbons, or resins, which plug the catalyst's pores.
This process is reversible; the catalyst can be cleaned off periodically
with a caustic solution and restored.  Poisoning occurs when an active
site is taken up by contaminants and usually results in permanent loss of
catalyst.  Because of the sensitivity of catalytic oxidizers to VOC inlet
stream flow conditions, the applicability of catalytic units for control
of VOC's in the SOCMI industry is limited, particularly for halogenated
streams.
                                   3-20

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3.2  RECOVERY DEVICES
     The recovery devices discussed in this section include adsorbers,
absorbers, and condensers.  These devices are generally applied to recover
reactant, product, or by-product VOC's from a vent stream for use as a
product or to recycle a compound.  The chemical structure of the VOC
removed is usually unaltered.
3.2.1  Adsorption
     3.2.1.1  Adsorption Process Description.  Adsorption is a
mass-transfer operation involving interaction between gaseous- and
solid-phase components.  The gas phase (adsorbate) is captured on the
solid-phase (adsorbent) surface by physical or chemical adsorption
mechanisms.  Physical adsorption is a mechanism that takes place when
intermolecular (van der Vlaals) forces attract and hold the gas molecules
to the solid surface.26  Chemisorption occurs when a chemical bond forms
between the gaseous- and solid phase molecules.  A physically adsorbed
molecule can readily be removed from the adsorbent (under suitable
temperature and pressure conditions), while the removal of a chemisorbed
component is much more difficult.
     The most commonly encountered industrial adsorption systems use
activated carbon as the adsorbent.  Activated carbon is effective in
capturing certain organic vapors by the physical adsorption mechanism.  In
addition, the vapors may be released for recovery by regeneration of the
adsorption bed with steam or nitrogen.  Oxygenated adsorbents, such as
silica gels, diatomaceous earth, alumina, or synthetic zeolites, exhibit a
greater selectivity than activated carbon for capturing water vapor rather
than organic gases.  Thus, these adsorbents would be of little use for the
high moisture gas streams characteristic of some SOCMI vents.27
     The design of a carbon adsorption system depends on the chemical
characteristics of the VOC's being recovered, the physical properties of
the offgas stream (i.e., temperature, pressure, and volumetric flow rate),
and the physical  properties of the adsorbent.  The mass quantity of VOC's
that adhere to the adsorbent surface is directly proportional to the
difference in VOC concentration between the gas-phase and the solid
surface.   In addition, the quantity of VOC's adsorbed is dependent on the
adsorbent bed volume, the surface area of adsorbent available to capture
                                   3-21

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VOC's, and the rate of diffusion of VOC's through the gas film at the gas-
and solid-phase interface.  Physical adsorption is an exothermic operation
that is most efficient within a narrow range of temperature and pressure.
     A schematic diagram of a typical fixed bed, regenerative carbon
adsorption systems is given in Figure 3-5.  The process offgases are
generally filtered and cooled (1) before entering the carbon bed.  The
inlet gases to an adsorption unit are filtered to prevent bed
contamination.  The gas is cooled to maintain the bed at optimum operating
temperature and to prevent fires or polymerization of the hydrocarbons.
Vapors entering the adsorber stage of the system (2) are passed through
the porous activated carbon bed.
     Adsorption of inlet vapors  sually occurs until the outlet VOC
concentration reaches some preset level (the "breakthrough"
concentration).  The dynamics of the process may be illustrated by viewing
the carbon bed as a series of layers or mass-transfer zones (3a, b, c).
Gases entering the bed are adsorbed first in zone (a).  Because most of
the VOC is adsorbed in zone (a), very little adsorption takes place in
zones (b) and (c).   Adsorption in zone (b) increases as zone (a) reaches
equilibrium with organics and proceeds through zone (c).  When the bed is
completely saturated (breakthrough), the incoming VOC-laden offgases are
routed to an alternate bed, while the saturated carbon bed is regenerated.
     Regeneration of the carbon bed is accomplished by heating the bed or
applying vacuum to draw off the adsorbed gases.  Low pressure steam (4) is
frequently used as a heat source to strip the adsorbent of organic vapor.
After steaming, the carbon bed is cooled and dried typically by blowing
air through it with a fan; the steam-laden vapors are routed to a
condenser (5) and on to a solvent recovery system (6).  The regenerated
bed is put back into active service, while the saturated bed is purged of
organics.  The regeneration process may be repeated numerous times, but
eventually the carbon must be replaced.
     3.2.1.2  Adsorption Control Efficiency.  Many modern, well-designed
systems achieve 95 percent removal efficiency for some chemicals.28  The
VOC removal efficiency of an adsorption unit is dependent upon the
physical properties of the compounds present in the offgas, the gas stream
                                   3-22

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     VOC-Laden
     Vent Stream
         Fan
  Low
Pressure  (4)
 Steam
                           Closed
                                          Adsorber 1
                                          (Adsorbing)
                                                           Open
                                          Adsorber 2
                                         (Regenerating)
                                                         C
                                                                      (5)
Condenser
                                                  Decanter and/or
                                                   Distilling Tower
                                                                   (6)
                  Vent to
                Atmosphere
               Recovered
                 Solvent

               Water
           Figure  3-5.   Two  stage  regenerative  adsorption  system.
                                           3-23

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characteristics, the physical properties of the adsorbent,  and the
condition of the regenerated carbon bed.
     Gas temperature, pressure, and velocity are important  in determining
adsorption unit efficiency.  The adsorption rate in the bed decreases
sharply when gas temperatures are above 38 °C (100 opj.29,30  High
temperature increases the kinetic energy of the gas molecules, causing
them to overcome van der Waals forces.  Under these conditions, the VOC's
are not retained on the surface of the carbon.  Increasing  vent stream
pressure and temperature generally will improve VOC capture efficiency;
however, care must be taken to prevent solvent condensation and possible
fire.
     3.2.1.3  Applicability of Adsorption.  Although carbon adsorption is
an excellent method for recovering some valuable process chemicals, it
cannot be used as a universal control method for distillation or reactor
process vent streams.  The conditions where carbon adsorption is not
recommended are present in many SOCMI vent streams.  These  include streams
with:  (1) high VOC concentrations, (2) very high or low molecular weight
compounds, and (3) mixtures of high and low boiling point VOC's.
     The range of organic concentrations to which carbon adsorption safely
can be applied is from only a few parts per million to concentrations of
several percent.31  Adsorbing vent streams with high organic concentration
may result in excessive temperature rise in the carbon bed  due to the
accumulated heat of adsorption of the VOC loading.  However, streams with
high organic concentrations can be diluted with air or inert gases to make
a workable adsorption system.
     The molecular weight of the compounds to be adsorbed should be in the
range of 45 to 130 grams per gram-mole (gm/gm-mole) (45 to  130 pounds per
pound-mole [lb/lb-mole]) for effective adsorption.  Carbon  adsorption may
not be the most effective application for compounds with low molecular
weights (below 45 gm/gm-mole [45 lb/lb-mole]) due to their smaller
attractive forces, or for high molecular weight components  (above
130 gm/gm-mole [130 lb/lb-mole]), which attach so strongly to the carbon
bed that they are not easily removed.32
     Properly operated adsorption systems can be very effective for
homogenous offgas streams but can have problems with a multicomponent
                                   3-24

-------
 system  containing  a mixture of  light and heavy hydrocarbons.  The lighter
 organics  tend to be displaced by the heavier (higher boiling) components,
 greatly reducing system efficiency.33
 3.2.2   Absorption
     3.2.2.1  Absorption Process Description.  The mechanism of absorption
 consists  of the selective transfer of one or more components of a gas
 mixture into a solvent liquid.  The transfer consists of solute diffusion
 and dissolution into a solvent.  For any given solvent, solute, and set of
 operating conditions, there exists an equilibrium ratio of solute
 concentration in the gas mixture to solute concentration in the solvent.
 The driving force  for mass transfer at a given point in an operating
 absorption tower is related to  the difference between the actual
 concentration ratio and the equilibrium ratio.34  Absorption may only
 entail  the dissolution of the gas component into the solvent or may also
 involve chemical reaction of the solute with constituents of the
 solution.35  The absorbing liquids (solvents) used are chosen for high
 solute  (VOC) solubility and include liquids such as water, mineral oils,
 nonvolatile hydrocarbon oils, and aqueous solutions of oxidizing agents
 (e.g.,  sodium carbonate and sodium hydroxide).36
     Devices based on absorption principles include spray towers, venturi
 and wet impingement scrubbers,  packed columns, and plate columns.  Spray
 towers  require high atomization pressure to obtain droplets ranging in
 size from 500 to 100 micrometers (//m) (0.019 to 0.004 in.) in order to
 present a sufficiently large surface contact area.37  Although they can
 remove  particulate matter effectively, spray towers have the least
 effective mass transfer capability and, thus, are restricted to
 particulate removal and control of high-solubility gases such as sulfur
 dioxide and ammonia.38  Venturi scrubbers have a high degree of gas-liquid
 mixing  and high particulate removal efficiency but also require high
 pressure  and have relatively short contact times.  Therefore, their use is
 also restricted to high-solubility gases.39  As a result, VOC control by
gas absorption is generally accomplished in packed or plate columns.
     Packed columns are mostly used for handling corrosive materials,
liquids with foaming or plugging tendencies, or where excessive pressure
drops would result from use of plate columns.  They are less expensive

                                   3-25

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than plate columns for small-scale or pilot plant operations where the
column diameter is less than 0.6 m (2 ft).   Plate columns are preferred
for large-scale operations, where internal  cooling is desired or where low
liquid flow rates would inadequately wet the packing.*0
     A schematic of a packed tower is shown in Figure 3-6.   The gas to be
absorbed is introduced near the bottom of the tower (1) and allowed to
rise through the packing material (2).  Solvent flows in from the top of
the column, countercurrent to the vapors (3), absorbing the solute from
the gas-phase and carrying the dissolved solute out of the tower (4).
Cleaned gas exits at the top (5) for release to the atmosphere or for
further treatment as necessary.  The solute-rich liquid is generally sent
to a stripping unit where the absorbed VOC's are recovered.  Following the
stripping operation, the absorbing solution is either recycled back to the
absorber or sent to a water treatment facility for disposal.
     The major tower design parameters to be determined for absorbing any
substance are column diameter and height, system pressure drop, and liquid
flow rate required.  These parameters are derived by considering the waste
gas solubility, viscosity, density, and concentration, all  of which depend
on column temperature; and also the total surface area provided by the
tower packing material, and the quantity of gases to be treated.
     3.2.2.2  Absorption Control Efficiency.  The VOC removal efficiency
of an absorption device is dependent on the solvent selected, and on
proper design and operation.  For a given solvent and solute, an increase
in absorber size or a decrease in the operating temperature can increase
the VOC removal efficiency of the system.  It may be possible in some
cases to increase VOC removal efficiency by a change in the absorbent.
     Systems that use organic liquids as solvents usually include the
stripping and recycling of the solvent to the absorber.  In this case, the
VOC removal efficiency of the adsorber is dependent on the solvent's
stripping efficiency.
     3.2.2.3  Applicability of Absorption.   Absorption is an attractive
control option if a significant amount of VOC's can be recovered for
reuse.  Although absorption is applicable for many SOCMI vent streams, it
cannot be universally applied.  It is usually not considered when the VOC
concentration is below 200 to 300 ppmv.^1
                                   3-26

-------
Absorbing   m\
 Liquid In  —^—*
                                                                      (5) Cleaned Gas Out
                                                                     To Final Control Device
                                                                       or to Atmosphere

                                     Packing Support
                                                                                  (1) VOC Laden
                                                                                 —   Gas In
                                                    (4)
                                            Absorbing Uquid
                                             with VOC Out
                                    To Disposal or VOC/Sorvent Recovery
                       Figure  3-6.   Packed tower  for gas absorption.

                                                 3-27

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3.2.3  Condensation
     3.2.3.1  Condensation Process Description.  Condensation is a process
of converting all or part of the condensable components of a vapor phase
into a liquid phase.  This is achieved by the transfer of heat from the
vapor phase to a cooling medium.  If only a part of the vapor phase is
condensed, the newly formed liquid phase and the remaining vapor phase
will be in equilibrium.  In this case, equilibrium relationships at the
operating temperatures must be considered.  The heat removed from the
vapor phase should be sufficient to lower the vapor-phase temperature to
at or below its dew point temperature (i.e, temperature at which first
drop of liquid is formed).
     Condensation devices are of two types:  surface condensers and
contact condensers.4^  Surface condensers are typically shell-and-tube
type heat exchangers.  The coolant and the vapor phases are separated by
the tube wall, and they never come in direct contact with each other.  As
the coolant passes through the tubes,the VOC vapors condense outside the
tubes and are recovered.  Surface condensers require more auxiliary
equipment for operation but can recover valuable VOC's without
contamination by the coolant, thus minimizing waste disposal problems.
Only surface condensers are considered in the discussion of control
efficiency and applicability since they are used more frequently in the
chemical industry.
     The major equipment components used in a typical surface condenser
system for VOC removal are shown in Figure 3-7.  This system includes a
dehumidifier (1), surface condenser exchanger (2), refrigeration unit (3),
and VOC storage tanks and operation pumps (4).  Most surface condensers
use a shell-and-tube type heat exchanger to remove heat from the vapor.4^
The coolant selected depends upon the saturation temperature of the VOC
stream.  Chilled water can be used down to 7 °C (45 °F), brines to -34 °C
(-30 °F), and chlorofluorocarbons below -34 °C (-30 °F).44  Temperatures
as low as -62 °C (-80 °F) may be necessary to condense some VOC streams.45
     3.2.3.2  Condenser Control Efficiency.  The VOC removal efficiency of
a condenser is dependent upon the type of vapor stream entering the
condenser, and on condenser operating parameters.  Efficiencies of
condensers usually vary from 50 to 95 percent,46 with higher efficiencies
                                   3-28

-------
                                                                      Cleaned Gas Out
                                                                   To Primary Control Flare,
                                                                        Afterburner, Etc.
VOC Laden
   Gas    •
 Dehumidlfication
      Unit
To Remove Water
      and
 Prevent Freezing .
In Main Condenser
                                   (D
VOC
Ret
IBM!
urn

Refrigeration
Unit
(3)
                                             Coolant
                                                                                     To Process
                                                                                     Or Disposal
                           Figure  3-7.   Condensation  system.

                                             3-29

-------
expected for streams with low flow rates (less than 2,000 cubic feet per
minute) and high VOC concentrations (greater than 5,000 ppmv).
     3.2.3.3  Applicability of Condensers.   A primary condenser system is
usually an integral part of most distillation operations.  Primary
condensers are needed to provide reflux in fractionating columns and to
recover distilled products.  At times additional (secondary) condensers
are used to recover more VOC's from the vent stream exiting the primary
condenser.  Condensers are sometimes present as accessories to vacuum
generating devices (e.g., barometric condensers).  Condensers are also
commonly used product recovery devices on reactor process vent streams.
     The use of a secondary condenser to control VOC emissions may not be
applicable to some vent streams.  Secondary condensers used as
supplemental product recovery devices are not well suited for vent streams
containing VOC's with low boiling points or for vent streams containing
large quantities of inerts such carbon dioxide, air, and nitrogen.  Low
boiling point VOC's and inerts contribute significantly to the heat load
that must be removed from the vent stream,  resulting in costly design
specifications and/or operating costs.  In addition, some low boiling
point VOC's cannot be condensed at normal operating temperatures.  For
example, process units producing chlorinated methanes have vent streams
with substantial amounts of methane, methyl chloride, and methylene
chloride.  These compounds are not readily condensed and, as a result, are
usually vented to the atmosphere or destroyed in a combustion device.
However, some difficult-to-condense vapors can be compressed upstream of
the condenser, thereby making them easier to recover in the condenser.
3.3  SUMMARY
     The two general classifications of VOC control techniques discussed
in the preceding sections are combustion and noncombustion control
devices.  This section summarizes the major points regarding control
device applicability and performance.
     The combustion control devices considered were flares, industrial
boilers, process heaters, thermal incinerators, and catalytic oxidizers.
With the exception of catalytic units, these devices are applicable to a
wide variety of process vent stream characteristics and can achieve at
least 98-percent destruction efficiency.  Combustion devices are generally
                                   3-30

-------
capable of adapting to moderate changes in process vent stream flow rate
and VOC concentration, while control efficiency is not greatly affected by
the type of VOC's present.  This is generally not the case with
noncombustion control devices.  In general, combustion control devices may
require additional fuel, except in some cases where boilers or process
heaters are applied and the energy content of the vent stream is
recovered.  Since boilers and process heaters are important in the
operation of a chemical plant, only process vent streams that will not
reduce boiler or process heater performance and reliability warrant use of
these systems.  Application of a scrubber prior to atmospheric discharge
may be required when process vent streams containing high concentrations
of halogenated or sulfonated compounds are combusted in an enclosed
combustion device.  The presence of high concentrations of corrosive
halogenated or sulfonated compounds may preclude the use of flares because
of possible flare tip corrosion and may preclude the use of boilers and
process heaters because of potential internal boiler corrosion.^  The
presence of a halogen acid, such as hydrogen chloride, in the atmosphere
may cause adverse health effects and equipment corrosion.
     The noncombustion control devices discussed include adsorbers,
absorbers, and condensers.  In general, although noncombustion devices are
widely applied in the industry, no one device is universally applicable to
SOCMI vent streams because of the many restrictions applying these devices
across a broad category of reactor process and distillation operation vent
streams.  For example, adsorbers may not always be applicable to vent
streams with:  (1) high VOC concentrations, (2) low molecular weight, and
(3) mixtures of low and high molecular weight compounds.  These conditions
exist in many reactor process vent streams.  Absorbers are generally not
applied to streams with VOC concentrations below 200 to 300 ppmv, while
condensers are not well suited for application to vent streams containing
low boiling point VOC's or to vent stream with large inert concentrations.
Even though these restrictions exist, many condensers and absorbers are
applied to distillation and reactor process vent streams in the SOCMI to
recover VOC's.  Control efficiencies for the noncombustion devices
considered vary from 50 to 95 percent for condensers and absorbers and up
to 95 percent for adsorbers.

                                   3-31

-------
3.4  REFERENCES

 1.  Blackburn, J. W., et al.  (IT Enviroscience, Inc.)-  Organic
     Chemical Manufacturing Series Volume 4:  Combustion Control
     Devices.  Prepared for the U. S. Environmental  Protection
     Agency.   Research Triangle Park, N.C.  Publication No. EPA-
     450/3-80-026.  December 1980.  67 pp.

 2.  Klett, M. G. and J. B. Galeski (Lockheed Missiles and Space Co.,
     Inc.).  Flare Systems Study.  Prepared for U. S. Environmental
     Protection Agency.  Huntsville, AL.  Publication No. EPA-
     600/2-76-079.  March 1976.  pp. ia, 22, 27, and 71 through 75.

 3.  D. Joseph, et al. (Energy and Environmental Research
     Corporation).  Evaluation of the Efficiency of Industrial
     Flares:  Background- Experimental Design-Facility.  Prepared for
     the U. S. Environmental Protection Agency.  Research Triangle
     Park, N.C.  Publication No. EPA-600/2-83-070.  August 1983.
     Abstract page only.

 4.  Ref. 1.

 5.  Letter from Matey, J. S., Chemical Manufacturers Association, to
     Beck, D., U. S.  Environmental Protection Agency.  14 pp.
     November 25, 1981.

 6.  North American Manufacturing Company.  North American Combustion
     Handbook, Second Edition.  Cleveland, Ohio.  1979.  p. 269.

 7.  Memorandum and attachments from Farmer, J. R.,  EPA/ESD to
     Distribution.  30 pp.  August 22, 1980.  Thermal incinerators
     and flares.

 8.  Ref. 7.

 9.  Devitt, T., et al. (PEDCo Environmental, Inc.).  Population and
     Characteristics  of Industrial Boilers in the U.S.  Prepared for
     the U. S. Environmental Protection Agency, Washington, D.C.
     Publication No.  EPA-600/7-79-178a.  August.1979.

10.  Fossil Fuel Fired Industrial Boilers - Background Information
     Document, Volume 1:  Chapters 1 - 9.  Draft EIS.
     U. S. Environmental Protection Agency.  Research Triangle  Park,
     N.C.  Publication No. EPA-450/3-82-006a.  March 1982.  p.  3-27
     and technical report data sheet.

11.  C. Castaldini, et al. (Acurex Corporation).  A Technical
     Overview of the  Concept of Disposing of Hazardous Wastes in
     Industrial Boilers.  Prepared for the  U. S. Environmental
     Protection Agency.  Cincinnati, Ohio.  EPA Contract No. 68-03-
     2567.  October 1981.  pp. 44 and 73.

12.  Ref. 11, p. 73.

                                   3-32

-------
 13.  Hunter, S. C.  and S. C. Cherry  (KVB.)  NOX Emissions from
     Petroleum  Industry Operations.  Washington, D.C.  API
     Publication No. 4311.  October  1979.  p. 83.

 14.  J. Hall, et al. (GCA Technology Division).  Evaluation of PCB
     Destruction Efficiency in  an  Industrial Boiler.  Prepared for
     the U. S.  Environmental Protection Agency.  Research Triangle
     Park, N.C.  Publication No. EPA-600/2-81-055a.  April 1981.  pp.
     4 through  10,  117 through  128,  and 161.

 15.  M. W. Hartman  and C. W. Stackhouse (TRW Environmental
     Engineering Division).  Benzene--Organic Chemical Manufacturing
     Emission Test  Report, Ethylbenzene/Styrene, Amoco Chemicals
     Company, Texas City, Texas.   Prepared for U. S. Environmental
     Protection Agency.  Research  Triangle Park, N.C.  EMB Report
     No. 79-OCM-13.  August 1979.

 16.  W. Kelly (TRW  Environmental Engineering Division).  Benzene
     Organic Chemical Manufacturing  Ethylbenzene/Styrene Test Report,
     El Paso Products Company,  Odessa, Texas.  Prepared for the
     U. S. Environmental Protection Agency.  Research Triangle Park,
     N.C.  EMB  Report No. 79-OCM-15.  April 1981.

 17.  W. Kelly (TRW  Environmental Engineering Division).  Benzene—Organic
     Chemical Manufacturing Ethylbenzene/Styrene Emission Test Report, USS
     Chemicals, Houston, Texas.  Prepared for the U. S. Environmental
     Protection Agency.  Research  Triangle Park, N.C.  EMB Report No. 80-
     OCM-19.  August 1980.

 18.  Ref. 15.
19.
20.
21.
22.
Ref. 16.
Ref. 17.
Ref. 1.
Control
     Control Techniques for Volatile Organic Emissions from Stationary
     Sources.  U. S. Environmental Protection Agency.  Research Triangle
     Park, N.C.  EPA Publication No. EPA-450/2-78-002.  May 1978.  pp. 32
     and 33, 53, 72, 76, and 83 and 84.

23.  Control of Volatile Organic Emissions.  MetPro Corp., Systems
     Division.  Harleysville, Pennsylvania.  1981.  8 pp.

24.  Letter from Connor, R. J., Manufacturers of Emission Controls
     Association, to Rosensteel, R. E., EPA.  May 4, 1992.

25.  Ref. 24, p. 6.

26.  Ref. 22,  p. 53.
                                   3-33

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27.  Stern, A. C.  Air Pollution, Volume IV, Third Edition, New York,
     Academic Press.  1977.  pp. vii through xii, 22 through 27, 336
     and 337, and 354 through 359.

28.  Barnett, K. W. (Radian Corporation).  Carbon Adsorption for
     Control of VOC Emissions:  Theory and Full Scale System
     Performance.  Prepared for the U. S. Environmental Protection
     Agency.  Research Triangle Park, N.C.  EPA Contract
     No. 68-02-4378.  June 6, 1988.  p. 3-52.

29.  Ref. 27, p. 356.

30.  Ref. 28.

31.  H. S. Basdekis, et al (IT Enviroscience, Inc.).  Organic
     Chemical Manufacturing Volume 5:  Adsorption, Condensation, and
     Absorption Devices.  Report 2.  Prepared for the U. S.
     Environmental Protection Agency.  Publication
     No. EPA-450/3-80-027.  Research Triangle Park, N.C.
     December 1980.  336 pp.

32.  Ref. 31, p. 1-4.

33.  Staff of Research and Education Association.  Modern Pollution
     Control Technology:  Volume I.  New York, Research and Education
     Association.  1978.  pp. 22-20 through 22-25.

34.  Ref. 31, p. 11-15.

35.  Perry, R.H., and Chilton, C.H. Eds.  Chemical Engineers
     Handbook.  6th Edition.  New York, McGraw-Hill.  1984.  pp. 14-1
     through 14-2.

36.  Ref. 22, p. 76.

37.  Ref. 27, p. 24.

38.  Ref. 22, p. 72.

39.  Ref. 31, p. II-l.

40.  Ref. 35, p. 14-1.

41.  Ref. 31, p. III-5.

42.  Ref. 31, Report 2, p. II-l.

43.  Ref. 22, p. 84.

44.  Ref. 31, Report 2, p. IV-1.

45.  Ref. 31, Report 2, pp.  II-3.
                                   3-34

-------
46.  Ref. 31, Report 2, p. III-5.



47.  Ref. 1.
                                    3-35

-------
                        4.0  ENVIRONMENTAL IMPACTS

     The environmental Impacts associated with applying reasonably
available control technology (RACT) to synthetic organic chemical
manufacturing Industry (SOCMI) distillation and reactor process vent
streams are analyzed  in this chapter.  As discussed further In
Chapter 6.0, the recommended RACT Is based on the combustion of certain
SOCMI reactor and distillation process vent streams to achieve a
98 weight-percent volatile organic compound (VOC) reduction.  The
requirements of RACT  can be achieved at distillation and reactor process
facilities by either  thermal incinerators or flares; therefore, the
environmental impacts analysis assumes that RACT is represented by thermal
incineration and flaring.
     The environmental impacts analysis considers effects on air quality,
water quality, solid waste, and energy consumption.  Ten model vent
streams derived from  the emissions profiles presented in Appendix B are
used to assess these  impacts.  The model vent streams represent the range
of flow rates and heating values typical of SOCMI distillation and reactor
process vent streams.  Table 4-1 presents the environmental impacts for
the 10 model vent streams.  Calculated impacts are based on the lowest
cost control technique (thermal incineration versus flares) for
nonhalogenated streams, and on a thermal incinerator/scrubber system for
halogenated streams.
4.1  AIR POLLUTION IMPACTS
     Section 4.1.1 presents the uncontrolled VOC.emissions from each model
vent stream and the expected VOC emission reductions from the application
of RACT.  Section 4.1.2 discusses additional air quality impacts that may
be observed in applying RACT to specific reactor and distillation process
vents.   Also included is discussion on possible impacts from the

                                    4-1

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 inefficient operation of the control devices used to meet RACT
 requirements.
 4.1.1  Volatile Organic Compound Emission Impacts
     The VOC emissions (megagrams per year) for the distillation and
 reactor model vent streams in Table 4-1 were estimated using an assumption
 of 8,760 working hours per year.  Controlled emissions were calculated
 using a 98 weight-percent VOC reduction efficiency.
     Uncontrolled VOC emissions from the distillation vent streams range
 from about 5 megagrams per year (Mg/yr) (5.5 tons/yr) for the Low Flow Low
 Heat (LFLH) model, to 600 Mg/yr (661 tons/yr) for the High Flow High Heat
 (HFHH) model.  Uncontrolled VOC emissions from the average distillation
 vent stream are 80 Mg/yr (88 tons/yr).  The controlled VOC emissions from
 the distillation vent streams range from 0.10 Mg/yr (0.11 ton/yr) (LFLH)
 to 12 Mg/yr (13 tons/yr) (HFHH), with 2 Mg/yr (2.2 ton/yr) representing
 the average.
     Uncontrolled VOC emissions from the reactor model vent streams range
 from 5 Mg/yr (5.5 tons/yr) (HFLH) to 800 Mg/yr (882 tons/yr) (HFHH), with
 32 Mg/yr (35 tons/yr) representing the average model vent stream.  The
 controlled VOC emissions from the reactor model streams range from
 0.11 Mg/yr (0.12 tons/yr) (HFLH) to 16 Mg/yr (17.6 tons/yr) (HFHH), with
 0.6 Mg/yr (0.66 tons/yr) representing the average.
 4.1.2  Secondary Air Impacts
     Other air quality impacts from the application of incinerator or
 flare control technologies include secondary pollutants produced from the
 combustion of vent streams containing VOC's.  Possible by-product
 emissions from VOC combustion include nitrogen oxides, sulfur dioxide,
 carbon monoxide, particulate matter.  Generally, the only
 combustion-related secondary pollutants of any potential concern are
 nitrogen oxides and carbon monoxide.  Data are not available on carbon
monoxide emissions from thermal incinerators and flares.  However, a
 reasonable estimate can be made using the AP-42 factor for natural gas
combustion.  Test data on nitrogen oxides emissions from thermal
 incinerator and flares are available as discussed below.
     Incinerator outlet concentrations of nitrogen oxides are generally
below 100 ppm,  except for cases where the vent stream contains nitrogenous

                                    4-3

-------
compounds.  Test data for a toluene diisocyanate process unit in the
reactor processes emissions profile showed a nitrogen oxide concentration
of 84 per million by volume (ppmv).1  Testing at a polymer and resin
process unit using an incinerator for VOC control  measured nitrogen oxide
ranging from 20.2 to 38.6 ppmv.2  The fuels tested were mixtures of
natural gas, waste gas, and/or atactic waste; incineration temperatures
ranged from 980 to 1,100 °C (1,800 to 2,000 °F).  In a series of seven
tests conducted at three air oxidation process units, incinerator outlet
nitrogen oxide concentrations ranged from 8 to 200 ppmv.3  The maximum
outlet nitrogen oxide concentration was measured at an acrylonitrile (air
oxidation) process unit, which has a vent stream containing nitrogenous
compounds.  The nitrogen oxide concentration measured at the other process
units, where the vent streams do not contain nitrogenous compounds, ranged
from 8 to 30 ppmv, with a median value of 21.5 ppm.
     The use of flares for combustion may also produce nitrogen oxide
secondary air pollution impacts.  Concentrations of nitrogen oxide were
measured at two flares used to control hydrocarbon emissions from refinery
and petrochemical processes.  One flare was steam-assisted and the other
air-assisted, and the heat content of the fuels ranged from 5.5 to
81 megajoule per standard cubic meter (148 to 2,175 British thermal units
per standard cubic feet).  The measured nitrogen oxide concentrations were
somewhat lower than those for incinerators, ranging from 0.4 to 8.2 ppmv.
The ranges of relative NOX emissions per unit of heat input are 7.8 to
90 gram per gigajoule (0.018 to 0.208 Ib/MMBtu) for flares.4
     Table 4-1 presents the secondary air impacts for the 10 model vent
streams.  As shown, nitrogen oxide emissions range from 0.006 Mg/yr
(0.007 tons/yr) for the LFHH distillation vent stream to 48 Mg/yr
(52.9 tons/yr) for the HFHH reactor vent stream.  The carbon monoxide
emissions range from 0.001 Mg/yr (0.0011 tons/yr) for the LFLH reactor
vent stream to 19 Mg/yr (20.9 tons/yr) for the HFHH reactor vent stream.
     In addition to nitrogen oxide and carbon monoxide emissions,
combustion of halogenated VOC emissions may result in the release of
halogenated combustion products to the environment.  Generally, streams
containing halogenated VOC would not be controlled by a flare.
Incinerators are generally more capable of tolerating the corrosive
                                    4-4

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effects of halogenated VOC and its combustion by-products.  In addition,
scrubbing is used to remove these halogenated compounds from an
incinerator's  flue gas.  Generally, incineration temperatures greater than
870 °C (1,600  °F) are required to ensure 98-percent destruction of
halogenated VOC.  For example, when incinerating chlorinated VOC's at
temperatures of 980 to 1,100 °C  (1,800 to 2,000 °F), almost all chlorine
present exists in the form of hydrogen chloride.  The hydrogen chloride
emissions generated by thermal oxidation at these temperatures can be
efficiently removed by wet scrubbing.5  As discussed further in
Chapter 5.0, the cost of the scrubber was added to the overall thermal
incinerator system cost.
4.2  WATER POLLUTION IMPACTS
     Control of VOC emissions using combustion does not typically result
in any significant increase in wastewater discharge; that is, no water
effluents are generated by the combustion device.  However, the use of an
incinerator/scrubber system for control of vent streams with halogenated
VOC does result in slightly increased water consumption.  In this type of
control system, water is used to remove the acid gas contained in the
incinerator outlet stream.  In most cases, any increase in total process
unit wastewater would be relatively small and would not affect plant waste
treatment or sewer capacity.  Table 4-1 presents the water pollution
impacts for the 10 model vent streams.  Scrubber wastewater flow ranges
from less than 0.001 million gallons per day (Mgal/d) for the LFLH reactor
vent stream to 0.05 Mgal/d for the HFHH distillation vent stream.
     The absorbed acid gas may cause the water leaving the scrubber to
have a low pH.   This acidic effluent could lower the pH of the total plant
effluent if it is released into the plant wastewater system.  The water
effluent guidelines for individual States may require that industrial
sources maintain the pH of water effluent within specified limits.  To
meet these guidelines,  the water used as a scrubbing agent would have to
be neutralized prior to discharge to the plant effluent system.  The
scrubber effluent can be neutralized by adding caustic sodium hydroxide to
the scrubbing water.   The amount of caustic needed depends on the amount
of acid gas in the waste gas.   For example, approximately 1.09 kilograms
                                    4-5

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(kg) (2.4 Ib) of caustic (as sodium hydroxide) are needed to neutralize
1 kg (2.2 Ib) of hydrogen chloride.
     The salt formed in the neutralization step must be purged from the
system for proper disposal.  The methods of disposal include direct
wastewater discharge into sewer systems, salt water bodies, brackish
streams, freshwater streams, deep well injection,  and evaporation.   Use of
the latter disposal method is not widespread, and  data show that most
plants currently incinerating halogenated streams  have State permits to
dump the brine or use on-site wells to dispose of  salty wastewater at a
relatively low cost.7  The increased water consumption and caustic costs
were included in the projected operating costs for control of halogenated
vent streams using an incinerator/scrubber system.  The costs associated
with the disposal of the salty wastewater were judged not to be
significant in comparison to the control costs and, therefore, were not
included in the projected cost impacts presented in Chapter 5.O.7
     An alternative to brine disposal is to use the brine as feed to
chlorine production.  Such a use would be site specific, where there was a
need for the chlorine in subsequent syntheses, and where quantities of
brine either alone or in combination with other brine sources were
adequate for economical production.
     The use of scrubbers to remove hydrogen chloride from the incinerator
flue gas also has the potential to result in small increases in the
quantities of organic compounds released into plant wastewater.  However,
only small amounts of organics are released into the scrubber wastewater;
the flow of wastewater from the scrubber is small  compared to total plant
wastewater, especially in installations where there are multiple chemical
processing units using a central wastewater treatment facility.
Therefore, the increase in the generation of organics in plant wastewater
is not likely to be significant.
4.3  SOLID WASTE DISPOSAL IMPACTS
     There are no significant solid wastes generated as a result of
control by thermal oxidation.  A small amount of solid waste for disposal
could result if catalytic oxidation, instead of thermal oxidation, were
used by a facility to achieve RACT requirements.  The solid waste would
consist of spent catalyst.
                                    4-6

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used by a facility to achieve RACT requirements.  The solid waste would
consist of spent catalyst.
4.4  ENERGY IMPACTS
     The use of incineration to control VOC's from reactor and
distillation process vent streams requires fuel and electricity.
Supplemental fuel is frequently required to support combustion.
Electricity is required to operate the pumps, fans, blowers and
instrumentation that may be necessary to control VOC's using an
incinerator or flare.  Fans and blowers are needed to transport vent
streams and combustion air.  Pumps are necessary to circulate absorbent
through scrubbers that treat corrosive offgases from incinerators
combusting halogenated VOC's.  Fuel and energy usage requirements for
incinerators and flares are discussed in detail as part of the overall
cost methodology in Chapter 5.0.
     Table 4-1 presents the estimated energy impacts associated with each
model vent stream from reactor and distillation units.  These energy
values include both fuel and electricity usage estimates.  As shown,
auxiliary fuel use ranges from 56 MMBtu/year for the LFHH reactor vent
streams to 34,653 MMBtu/yr for the HFHH reactor vent stream.  Electrical
demand per vent ranges from zero for two vent streams to
315,639 kilowatt-hour per year for the HFHH reactor vent stream.
Electricity generally accounts for a small fraction of the total energy
impacts, while fuel use accounts for the remainder.  Heat recovery systems
may substantially affect fuel usage requirements for incinerators.
                                    4-7

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4.5  REFERENCES

 1.  Reactor Processes in Synthetic Organic Chemical Manufacturing
     Industry-- Background Information for Proposed Standards.  Draft EIS.
     U. S. Environmental Protection Agency.  Research Triangle Park, N.C.
     Publication No. EPA-450/3-90-016a.  June 1990.

 2.  Lee, K. W., et al (Radian Corporation).  Polymers and Resins,
     Volatile Organic Compound Emissions from Incineration, Emissions Test
     Report, ARCO Chemical Company, LaPorte Plant, Deer Park, Texas.
     Volume I:  Summary of Results.  Prepared for the U. S. Environmental
     Protection Agency.  Research Triangle Park, N.C.  EMB Report
     No. 81-PMR-l.  March 1982.  pp. 12 through 15.

 3.  Air Oxidation Processes in Synthetic Organic Chemical Manufacturing
     Industry—Background Information for Proposed Standards.  Draft EIS.
     U. S. Environmental Protection Agency.  Research Triangle Park, N.C.
     Publication No. EPA-450/3-82-001a.  October 1983.  pp. ii, 7-5, C-22,
     and technical report data sheet.

 4.  McDaniel, M. (Engineering Science).  Flare Efficiency Study.
     Prepared for the U. S. Environmental Protection Agency.  Washington,
     D.C.  Publication No. EPA-600/2-83-052.  July 1983.  p. 134 and
     technical report data sheet.

 5.  Ref. 4.

 6.  Memorandum from Piccot, S. D., and Lesh, S. A., Radian Corporation,
     to Reactor Processes NSPS file.  June 25, 1985.  Disposal of brine
     solutions from wet scrubbers.

 7.  Memorandum from Stelling, J. H. E., Radian Corporation, to
     Distillation Operations NSPS file.  September 2, 1982.  Caustic and
     salt disposal requirements for incineration.  1 p.
                                    4-8

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                            5.0  COST ANALYSIS

5.1  INTRODUCTION
     This chapter presents the costs associated with control options for
reducing volatile organic compound (VOC) emissions from distillation
column and reactor process vents.  Control system elements, design
assumptions, and costing equations are provided for incinerator and flare
control systems.  For streams containing halogenated VOC's, the
incinerator control system cost includes a packed tower scrubber system to
remove acidic vapors from the incinerator flue gas.
     Since synthetic organic compound manufacturing industry (SOCMI)
processes encompass a wide range of emission parameters, a model stream
approach was used to present example control system costs.  Ten model
systems were selected from the distillation and reactor process emission
profiles to represent a broad spectrum of possible vent streams.  The
model vent stream characteristics are presented in Appendix B.  Because
flow rates, heating values, and VOC concentrations of the model streams
vary considerably, there is a large variation in system costs and cost
effectiveness values.
5.2  COST METHODOLOGY FOR INCINERATOR SYSTEMS
     This section presents the methodology used to develop VOC control
system costs for incinerators and scrubbers.  Incinerator costs were
developed using Chapters 2 and 3 of the EPA's Control Cost Manual (OCCM).1
Scrubber costs were based on the procedure outlined in the EPA's Handbook
on Control Technologies for Hazardous Air Pollutants,2 with equipment
costs updated from recent technical journal information.3
5.2.1  Thermal Incinerator Design Considerations
     The thermal incinerator system consists of the following equipment:
combustion chamber, instrumentation,  recuperative heat exchanger, blower,
                                    5-1

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collection fan and ductwork, quench/scrubber system (if applicable),  and
stack.  The OCCM contains further discussion of incinerator control  system
design.  Control system elements and design assumptions specific to  SOCMI
vent streams are discussed below.  General incinerator design
specifications are presented in Table 5-1.
     5.2.1.1  Combustion Air Requirements.  The amount of oxygen in  the
waste gas or that provided by the VOC's is important because it
establishes the auxiliary combustion air required, which has an impact on
both the capital and operating costs of the thermal oxidizer.  This  cost
analysis assumes that the waste gas does not contain free oxygen and that,
therefore, auxiliary combustion air must be added.  (In other words,  the
vent stream is essentially a mixture of VOC's and an inert gas such  as
nitrogen.)  After combustion, the design excess oxygen content in the
incinerator flue gas is assumed to be 3 mole percent, which is based on
commonly accepted operating practice.
     In order to calculate the amount of combustion air required to  ensure
a flue gas oxygen concentration of 3 mole percent, a complete
stoichiometric equation must be balanced for each compound present in the
waste gas stream.  In many cases, the complete chemical composition  of the
waste stream is not known.  Thus, for the purpose of costing incinerator
systems for typical vent streams encountered in the SOCMI, a design
molecule approach was used for halogenated and nonhalogenated waste  gas
streams.
     The design molecule was based on a survey of typical values for
carbon, hydrogen, oxygen, sulfur and chloride ratios for group of
219 organic compounds.4  For nonhalogenated streams, the average VOC
molecular composition of 68.3 percent carbon, 11.4 percent hydrogen, and
20.3 percent oxygen was used to calculate combustion air requirements.
These weight ratios correspond to a molecular formula of Cg.88H5.7°0.63•
For halogenated streams, component averages of 34.3 percent carbon,
4.7 percent hydrogen, and 6.1 percent chlorine were used to predict
combustion air requirements.  This corresponds to a molecular formula of
C2.86H4.7C11.71-  In D0th cases, assuming zero percent oxygen in the waste
                                    5-2

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           TABLE  5-1.   INCINERATOR GENERAL  DESIGN SPECIFICATIONS
Item
          Specification
Emission control efficiency

Minimum incinerator capacity3

Maximum incinerator capacity

Incinerator temperature
   - nonhalogenated vent streams
   - halogenated vent streams"

Chamber residence times
   - nonhalogenated vent streams
   - halogenated vent streams'5

Auxiliary fuel requirement
Scrubber system
   - type
   - packing type
   - scrubbing liquid
   - scrubber gas temperature
98 percent destruction

500 scfm

50,000 scfm
870 oc (1,600 °F)
1,100 oc (2,000 OF)
0.75 sec
1.00 sec

Natural gas required to maintain
incinerator temperature with
3 mole percent excess oxygen in
flue gas

Used when halogenated VOC is
present to remove corrosive
combustion by-products


Packed tower
2-inch rings, carbon steel
Water
100 oc (212 op)
aFor capital cost purposes.  A minimum flow rate of 50 scfm was used for
 determining operating costs.
DUsed when halogenated VOC are present due to the difficulty of achieving
 complete combustion of halogenated VOC at lower temperatures.
                                    5-3

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stream, a dilution ratio (mole of air per mole of VOC)  of approximately
18:1 is required to achieve 3 percent oxygen in the incinerator flue  gas.
     5.2.1.2  Dilution Air Requirements.   After the required combustion
air is calculated and added to the total  vent stream flow, the overall
heat value megajoules per standard cubic  meter (MJ/scm) of the stream is
recalculated.  Addition of combustion air will effectively dilute the
stream and lower the heat content of the  combined stream fed to the
incinerator.  However, if the heat content of the vent  stream is still
greater than 3,648 kilojoules per standard cubic meters (KO/scm)
[98 British thermal units per standard cubic feet (Btu/scf)] for
nonhalogenated streams or greater than 3,536 KJ/scm (95 Btu/scf) for
halogenated streams, then additional dilution air must  be added to ensure
these maximum heat content levels are not exceeded.  The imposition of a
maximum heat content level prevents the temperature in  the incinerator
from exceeding the design specifications.
     The minimum flow rate to the incinerator is 1.42 standard cubic meter
per minute (scmm) (50 scfm).  It is assumed that vent streams smaller than
1.42 scmm (50 scfm) will be mixed with air to achieve this minimum flow
rate.  The maximum incinerator flow rate  is 1,416 scmm (50,000 scfm).
Flow rates greater than this will be handled by multiple incinerators in
this cost analysis.
     5.2.1.3  Recuperative Heat Recovery.  Halogenated vent streams are
not considered candidates for heat recovery systems, and are costed
assuming zero percent heat recovery.  This conservative design assumption
is imposed because of the potential for corrosion  in the heat exchanger
and incinerator.  If the temperature of the flue gas leaving the heat
exchanger, Tf0, were to drop below the acid dew temperature, condensation
of acid gases would result.  Significant corrosion can lead to shortened
equipment life, higher maintenance costs, and potentially unsafe working
conditions.
     Nonhalogenated vent streams are considered candidates for
recuperative heat recovery.  The extent of heat recovery depends on the
heat value of the vent stream after dilution.  Four different heat
recovery scenarios are evaluated for nonhalogenated streams.  The cost
algorithm includes systems with 0, 35, 50 and 70 percent heat recovery.

                                    5-4

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The extent of heat exchange to be utilized is decided by an economic
optimization procedure with the following restrictions.  No heat recovery
is allowed for vent streams with a heat value greater than 25 percent of
the lower explosive limit  (LEL), due to the possibility of explosion or
damaging temperature excursions within the heat exchanger.  This limit
typically corresponds to a heat content of 484 KJ/scm (13 Btu/scf).
Therefore, if the heat content of the total vent stream—even after
addition of required combustion and dilution air--is still greater than
484 KJ/scm (13 Btu/scf), no heat recovery for the entire stream is
allowed.  For streams with a heat content less than 484 KJ/scm
(13 Btu/scf), the entire stream is preheated in the recuperative heat
exchanger, allowing for maximum energy recovery.  However, for streams
with a heat content greater than 484 KJ/scm (13 Btu/scf), the flammable
vent gas stream cannot be preheated, but the combustion/dilution air
stream can.  In this case, the cost optimization procedure evaluates the
option of preheating only the air stream, and combines the VOC stream with
the preheated air stream in the incinerator.
     All allowable heat recovery percentages are evaluated and the
calculated total capital and annual costs are based on the most
cost-effective configuration.  The tradeoff between the capital cost of
the equipment and the operating cost (fuel) of the system determines the
optimum level of energy recovery.
     5.2.1.4  Incinerator Design Temperature.  The destruction of VOC's is
a function of incinerator temperature and residence time in the combustion
chamber.  The design VOC destruction efficiency is 98 weight-percent,
which can be met by well-designed and well-operated thermal incinerator
systems.  Previous studies by the EPA show that 98 weight-percent
destruction efficiency can be met in a thermal incinerator operated at a
temperature,  Tf^, of 871 °C (1,600 °F) and a residence time of 0.75
second.  Thermal oxidation of halogen-containing VOC's requires higher
temperature oxidation to convert the combustion product to a form that can
be more readily removed by flue gas scrubbing.  For instance,
chloride-containing waste gases are burned at high temperature to convert
the chlorine to hydrogen chloride instead of to chlorine, since hydrogen
chloride is more easily scrubbed.  Available data indicate that a

                                    5-5

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temperature of 1,093 DC (2,000 OF) and residence time of 1 second are
necessary to achieve 98 weight-percent VOC destruction efficiency for
halogen-containing waste gas streams.  Chapter 3.0 contains additional
details on thermal incinerator performance.
5.2.2  Thermal Incinerator Capital Costs
     The costing analysis follows the methodology outlined in the OCCM.
Equipment cost correlations are based on data provided by various vendors;
each correlation is valid for incinerators in the 14.2 scmm to 1,416 scmm
(500 to 50,000 scfm) range.5  Thus, the smallest incinerator size used for
determining equipment costs was 14.2 scmm (500 scfm) and for flow rates
above 1,416 scmm (50,000 scfm) additional incinerators were costed.
     Purchased equipment costs (PEC's) for thermal incinerators are given
as a function of total volumetric throughput, Qtot> in scfm-  Four
equations were used in the costing analysis, each pertaining to a
different level of heat recovery (HR):
          PEC = 10294 Qtot0<2355        HR - 0%
          PEC = 13149 Qtot0'2609        HR = 35%
          PEC = 17056 Qtot0'2502        HR = 50%
          PEC = 13149 Qtot0'2500        HR - 70%
     The cost of ductwork (not included in PEC) was calculated based on
1/8 inch (in.) carbon steel with two elbows per 100 feet (ft), using the
equation in Reference 6.  The length of duct was assumed to be 300 feet.
Collection fan costs were developed using methods in Reference 7.  The
duct and fan costs are added to the total equipment cost and installation
factors applied to this total.
     Installation costs are estimated as a percentage of total equipment
costs.  Table 5-2 lists the values of direct and indirect installation
factors for thermal incinerators.
5.2.3  Thermal Incinerator Annualized Cost
     Annualized costs for the thermal incinerator system include direct
operating and maintenance costs, as well as annualized capital charges.
It should be pointed out that vendor contacts indicate that an incinerator
turndown ratio of 10/1 is available.8  Consequently, the minimum flow rate
                                    5-6

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        TABLE 5-2.  CAPITAL COST FACTORS FOR THERMAL INCINERATORS*


Cost item                                                   Factor


Direct Costs

   Purchased equipment costs
        Incinerator (EC)  + auxiliary equipment*)          As estimated, A
        Instrumentation0                                           0.10 A
        Sales taxes                                               0.03 A
        Freight                                       	0.05 A

             Purchased equipment cost, PEC                     B - 1.18 A

   Direct installation costs
        Foundations and  supports                                   0.08 B
        Handling and erection                                      0.14 B
        Electrical                                                 0.04 B
        Piping                                                    0.02 B
        Insulation  for ductwork*1                                   0.01 B
        Painting                                     	0.01 B

             Direct  installation cost                              0.30 B

   Site preparation                                      As required, SP
   Buildings                                          As required. Bldg.

                 Total direct costs, DC              1.30 B + SP + Bldg.

Indirect Costs  (Installation)

   Engineering                                                    0.10 B
   Construction  and field expenses                                0.05 B
   Contractor fees                                                 0.10 B
   Start-up                                                       0.02 B
   Performance test                                               0.01 B
   Contingencies                                     	0.03 B

                 Total indirect cost, 1C                          0.31 B
Total Capital Investment - DC + 1C                   1.61 B + SP + Bldg.


Reference 1.
^Ductwork and any other equipment normally not included with unit
 furnished by incinerator vendor.
clnstrumentation controls often furnished with the incinerator, and thus
 often included in the EC.
dlf ductwork dimensions have been established, cost may be estimated based
 on $10 to $12 per ft^ of surface area for field application.  Fan
 housings and stacks may also be insulated.

                                    5-7

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for determining operating costs is assumed to be 1.42 scmm (50 scfm).
Additional dilution air is added where necessary to raise the fuel-waste
gas-air mixture to 1.42 scmm (50 scfm).  The bases for determining  thermal
incinerator annualized costs are presented in Table 5-3.   Each cost
parameter is reviewed below.
     5.2.3.1  Labor Costs.  The operating labor requirements vary
depending on the components of the overall system.  Incinerator systems
not employing a scrubber require the least amount of operating labor
[548 hours per year (hr/yr) or 0.5 hours per 8-hour shift].  Systems
employing a scrubber require an additional 548 hr/yr operating labor.
Maintenance labor requirements are assumed to be identical to operating
labor requirements—that is 548 hr/yr for the incinerator and 548 hr/yr
for the scrubber.  Supervisory cost is estimated to be 15 percent of the
operating labor cost.  The maintenance labor hourly rate is assumed to be
10 percent higher than the operating labor hourly rate.
     5.2.3.2  Capital Charges.  Return on investment for the incinerator
system is not included, but the cost of the capital investment is
accounted for in evaluating total annual costs.  The capital recovery
factor (0.163) is based on a 10-percent interest rate and a 10-year life
for the equipment.  Taxes, insurance, and administrative costs are assumed
to be 4 percent of the total capital investment.  Overhead is estimated to
be 60 percent of the total labor and maintenance costs.
     5.2.3.3  Utility Costs.  The utilities considered in the annual  cost
estimates include natural gas and electricity.  The procedures for
estimating electricity and supplemental fuel requirements are described in
Chapter 3 of the OCCM.
     5.2.3.4  Maintenance Costs.  Maintenance labor costs are discussed
above.  Maintenance material costs are assumed to be equal to maintenance
labor costs.
5.3  COST METHODOLOGY FOR FLARE SYSTEMS
     This section presents the methodology used to develop VOC control
system costs for flares.  Flare design aspects and costs are based on
Chapter 7 of the OCCM.
                                    5-8

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     TABLE 5-3.  ANNUAL OPERATING COST BASIS FOR THERMAL INCINERATORS
Direct Operating Cost Factors
    Hours  of operation  (hrs/yr)
    Operating labor (manhours)
      Incinerator  (0.5 hrs/8 hr shift)
      Incinerator with scrubber (1 hr/8 hr shift)
    Maintenance  labor (manhours) per  incinerator
      Incinerator  (0.5 hr/8 hr shift)
      Incinerator with scrubber (1 hr/8 hr shift)
    Labor  rates  ($/hr)  based  on  1990  data
      Operating labor
      Maintenance labor
    Supervisory  cost
    Cost
    Maintenance  materials  cost
Labor Cost
    Utilities (1990 $)
      Electricity (S/1,000 kWh)
      Natural Gas ($/106 Btu)
Indirect Operating Cost Factors
    Equipment life  (years)
    Interest  rate  (percent)
    Capital  recovery  factor
    Taxes,  insurance, administration
      (percent of total  installed  cost)
    Overhead
       8,760
         548
       1,096
         548
       1,096
          15.64
          17.21
15% of Operating Labor
   100% of Maintenance
          59
           3.30
          10
          10
           0.163
           4
60% of Total Labor and
     Maintenance Costs
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5.3.1  Flare Design Considerations
     The flare design consists of an elevated,  steam-assisted,  smokeless
flare.  Elements of the flare system include knock-out drum,  liquid seal,
stack, gas seal, burner tip, pilot burners,  and steam jets.   For flare
system sizing, correlations were developed relating process  vent stream
flow rate and heat content value to the flare height and tip diameter.
The general design specifications used in developing these correlations
are discussed below and presented in Table 5-4.
     Flare height and tip diameter are the basic design parameters used to
determine the installed capital cost of a flare.  The tip diameter
selected is a function of the combined vent stream and supplemental fuel
flow rates, and the assumed tip velocity.  Supplemental fuel  requirements
and tip velocity values are shown in Table 5-4.  Determination of flare
height is based on worker safety requirements.   The flare height is
selected so the maximum ground level heat intensity including solar
radiation is 2,525 watts per square meter (W/m2) [800 Btu/hr per foot
squared (ft2)].  Vendor contacts indicate the smallest elevated flare
commercially available is 30 ft high and 1 in.  in diameter.   For vent
streams requiring smaller flare systems, this is the minimum flare size
used.
     After flare tip diameter (D) and flare height (H) are determined, the
natural gas required for pilots and purge, and the mass flow rate of steam
required are calculated.  Pilot gas consumption is a function of the
number of pilots and, in turn, of the tip diameter as shown in Table 5-4.
The number of pilots is selected based on the tip diameter.   The pilot gas
consumption is calculated based on an energy-efficient model of
1.98 scm/hr (70 scf/hr) per pilot burner.  The purge gas requirement is
also a function of the tip diameter and the minimum design purge gas
velocity of 0.012 meters per second (m/s) [0.04 ft/second (sec)] at the
tip, as shown in Table 5-4.  A design flare tip velocity 14.6 mps
(48 ft/sec) equal to 80 percent of the maximum smokeless velocity  is used
in the costing equations.  Steam use is that flow which maintains  a steam
to flare gas ratio of 0.4 pound (Ib) steam/lb vent gas [kilogram (kg)
steam/kg vent gas].
                                   5-10

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                         TABLE  5-4.    FLARE  GENERAL  DESIGN SPECIFICATIONS
Item
                        Specification
Emission control efficiency

General flare design
     - minimum net  heating valve
     - minimum flare tip diameter
     - minimum flare height
     - maximum gound level heat intensity*
     - flare tip velocities'1
     - emissivity
     - number of pilots6
     • pilot gas requirement
     - steam requirement
     - purge gas requirement


Supplemental fuel requirement**
98 percent destruction

Elevated, steam assisted
Smokeless flare

300 Btu/scf of gas  being combusted
2.5 cm (1.0 inch)
9.1 • (30 ft)            ,
2,525 W/*2 (800 Btu/hr ft2)
HV 5 11.2 (300): V «  18.3 m/s (60 it/a) + natural gas
                      to 11.2 NJ/Nai5 (300 Btu/scf)
11.2 (300) < HV < 37.3 (1,000):  log(V) • (HV * 1,214)/8S2
HV > 37.3 (1,000):   V  - 122 m/s (400 ft/a)
0.3
Number of Pilots              Tip Diameter

        1
        2
        3
        4

2.0 nrVhr (70  scf/hr)  of natural gas per pilot
0.4 kg steam/kg vent gas
Natural gas added to maintain a miniau* flare tip velocity of
0.01 m/s (0.04 ft/s)

Natural gas required to maintain vent stream HV of 11.2 MJ/Nm3
(300 Btu/scf for V  18.3 m/s (60 ft/s)
D t 25
25 < 0 i 61
61 < D < 152
0 > 152
(D < 10)
(10 60)
Including solar radiation of 300 Btu/hr ft2.

bHV = Heat content  value  of process vent stream, MJ/nr5 (Btu/scf).  A  flare tip velocity equal to 80 percent of the
 maxinun smokeless  velocity (18.3 m/s  [60 ft/s]) is used in the costing equations.

CD = tip diameter,  cm (inch).

drfV = flare tip velocity, m/s (ft/s).
                                                      5-11

-------
5.3.2  Development of Flare Capital Costs
     The capital cost of a flare is based on vendor supplied information
as described in the OCMM cost equations are developed from a regression
analysis of the combined data set over a range of tip diameters and flare
heights.  Flare equipment costs (Cp) are calculated based on stack height,
H (ft) and tip diameter, D (in.) according to support type as follows:
     •    Self Support Group:
               CF - [78.0 + 9.14(D) + 0.749(H)]2
     •    Guy Support Group:
               CF = [103 + 8.68(D) + 0.470(H)]2
     •    Derrick Support Group:
               CF - [76.4 + 2.72(D) + 1.64(H)]2
The flare equipment cost includes the flare tower (stack) and support,
burner tip, pilots, utility piping from base, utility metering and
control, water seal, gas seal, and galvanized caged ladders and platforms
as required.  The material of construction basis is carbon steel, except
for the upper 4 ft and burner tip, which is 310 stainless steel.
     Vent stream piping costs, Cp, are a function of pipe, or flare,
diameter, D, and length of piping.
     •    Cp ' 508 (D)l-21 (where 1" < D < 24")
     •    Cp = 556 (D)l-07 (where 30" < D < 60")
These costs include 400 ft of straight piping and are directly
proportional to the distance required.
     Knock-out drum costs CK, are a function of drum diameter, d (in.) and
drum thickness, t (in.).
     •    CK - 14.2 [(d)(t)(h + 0.812(d)]0-737
     Total flare system equipment cost is the sum of flare, piping, and
knock-out drum costs.
                             EC - CF + CK +  Cp
Purchased equipment cost, PEC, is equal to equipment cost, EC, plus
factors for ancillary equipment  (i.e., instrumentation at 0.10, sales
                                   5-12

-------
taxes at 0.03, and freight at 0.05).  Installation costs are estimated as
a percentage of total equipment costs.  The total capital investment, TCI,
is obtained by multiplying PEC by an installation factor of 1.61.
5.3.3  Development of Flare Annualized Costs
     The annualized costs include direct operating and maintenance costs,
and annualized capital charges.  The assumptions used to determine
annualized costs are presented in Table 5-5, and are given In first
quarter 1990 dollars.  Direct operating and maintenance costs include
operating and maintenance labor, replacement parts, and utilities.
     5.3.3.1  Labor Costs.  The operating labor requirements are
500 hrs/yr for typical flare systems.  Supervisory labor is estimated to
be 15 percent of the operating labor cost.  Maintenance labor is assumed
to be 10 percent higher than the operating labor cost.
     5.3.3.2  Capital Charges.  The capital recovery factor (0.1314) is
based on a 10-percent interest rate and a 15-year life for the equipment.
Taxes, insurance and administrative costs are assumed to be 5 percent of
the total capital investment.
     5.3.3.3  Utility Costs.  The utilities considered in the annual cost
estimates include natural gas and electricity.  The procedures for
estimating electricity and supplemental fuel requirements are described in
Chapter 4 of the OAQPS Cost Manual.
     5.3.3.4  Maintenance Costs.  Maintenance labor costs are discussed
above.  Maintenance material costs are assumed to be equal to maintenance
labor costs.
5.4  COMPARISON OF CONTROL SYSTEM COSTS
     This section presents and discusses the capital costs, annualized
costs, average cost effectiveness, and natural gas costs for the
application of incinerators or flares to representative SOCMI vent
streams.  These costs are determined by applying the costing methodology,
developed in the previous sections, to the 10 model vent streams described
in Appendix 8.
     For a specific combustion control system, capital and annualized
costs vary with vent stream flow rate and heat content.  Therefore, five
reactor process vent streams and five distillation vent streams are used
as examples to show how the costs of control vary for vent streams with a
                                   5-13

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           TABLE 5-5.  ANNUAL OPERATING COSTS FOR FLARE SYSTEMS
Direct Annual Costs
   Operating  Labor
   Supervision
   Maintenance  Labor
   Maintenance  Materials
   Natural  Gas  -  Pilot  Gas
               -  Auxiliary  Fuel
               -  Purge  Gas
   Steam
   Electricity
Factor/Basis
630 manhours/yr
15% of operating labor
1/2 hour per shift
equal to maintenance labor
}
}   All utilities equal to:
^consumption rate * hours/yr *
}          unit cost
}(Natural Gas - $330/106 Btu)
}(Electricity - $59.0/1,000 kWh)
}(Steam       - $5.30/1,000 Ib)
Indirect Annual Costs
   Overhead
   Capital  Recovery Factor
   General  and  Administrative,
     Taxes,  and Insurance
60% of total labor costs
0.1314 (assuming 15 year life at 10%)
(4% of total installed capital)
                                   5-14

-------
wide range of vent stream characteristics.  These example cases are
selected from the emission profiles in Appendix B and represent the range
of vent stream characteristics found.  Stream characteristics for the
10 example cases are as follows:
     Case 1 - reactor process - low flow rate, high heat content -
              (R-LFHH);
     Case 2 - reactor process - low flow rate, low heat content - (R-LFH);
     Case 3 - reactor process - high flow rate, high heat content -
              (R-HFHH);
     Case 4 - reactor process - high flow rate, low heat content -
              (R-HFLH);
     Case 5 - reactor process - medium flow rate and medium heat content -
              (R-AVG);
     Case 6 - distillation - low flow rate, high heat content - (D-LFHH);
     Case 7 - distillation - low flow rate, low heat content - (D-LFLH);
     Case 8 - distillation - high flow rate, high heat content - (D-HFHH);
     Case 9 - distillation - high flow rate, low heat content - (D-HFLH);
     Case 10 - distillation - medium flow rate and medium heat content -
               (D-AVG);
     Table 5-6 presents the results of the costing analysis for the
10 example SOCMI vent streams.  The values presented are the lower cost
control option (thermal incineration versus flaring) for nonhalogenated
streams.  For halogenated streams, the values in the table represent the
cost of a thermal incineration/scrubber system.
     Table 5-6 shows that average cost effectiveness for each control
system varies with the vent stream characteristics.  The lowest
cost-effectiveness values shown occur for those vent streams with the
highest vent stream energy flow (i.e., (flow rate) x (heat content) in
megajoules per minute); Cases 3 and 8.  The cost effectiveness for Case 3
is about $300/megagram (Mg) ($272/ton), while the cost effectiveness for
Case 8 is about $270/Mg ($245/ton).  In general, the low cost
effectiveness values for high-energy content vent streams are a result of
the large mass of VOC's available to support combustion and, subsequently,

                                   5-15

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the low supplemental fuel costs.  Also, relatively large VOC emission
reductions occur for these streams, which greatly decreases the cost per
megagram of VOC removed/destroyed.
     Table 5-6 also shows the highest cost effectiveness occurs for vent
streams with a low energy flow (Case 7).  This occurs even though this
type of stream does not have extremely high annualized costs.  For Case 4,
cost effectiveness is $13,778/Mg ($12,497/ton) with incineration.
Application of controls to this low heat content stream results in
moderately low annual costs but very low emissions reductions.  A
relatively small amount of VOC's are controlled because of the low VOC
content associated with this vent stream.
                                   5-17
-------
5.5  REFERENCES

 1.  OAQPS Control Cost Manual.  Fourth Edition.   U. S. Environmental
     Protection Agency.  Research Triangle Park, N.C.  Publication
     No. EPA-450/3-90-006.  January 1990.  pp. 1-1 through 1-7, 2-1
     through 2-32, 3-1 through 3-66, 4-1 through 4-44, 5-1 through 5-54,
     6-1 through 6-74, and 7-1 through 7-43.

 2.  Handbook:  Control Technologies for Hazardous Air Pollutants.
     U. S. Environmental Protection Agency.  Research Triangle Park, N.C.
     Publication No. EPA-625/6-86-014.  September 1986.  176 pp.

 3.  W. M. Vatavuk.  Pricing Equipment for Air Pollution Control.
     Chemical Engineering.  May 1990.  pp 126 through 130.

 4.  Organic Chemical Manufacturing Series.  Volume 4:  Combustion Control
     Devices.  U. S. Environmental Protection Agency.  Research Triangle
     Park, N.C.  Publication No. EPA-450/3-80-026.  December 1990.

 5.  Ref. 1.

 6.  Richardson Engineering Services, Inc.  The Richardson Rapid System
     Process Plant Cost Estimating Standards.  Volume 3, p. 16-0.2 and
     Volume 4, pp. 100-110.4 and 100-653.13 and 100-653.14, 1988.

 7.  Telecon.  Stone, D. K., Radian Corporation with E. Dowd, ARI
     Technology.  January 18, 1990.  Incinerator sizes and turndown.  1  p.
                                   5-18
-------
                  6.0  SELECTION OF REASONABLY AVAILABLE
                              CONTROL  TECHNOLOGY
     This chapter provides State and local regulatory authorities with
guidance on the selection of reasonably available control technology
(RACT) for volatile organic compound (VOC) emissions from synthetic
organic chemical manufacturing industry (SOCMI) reactor processes and
distillation operations.  Background on the regulatory authority and goals
for establishment of RACT is discussed in Section 6.1.  The technical
basis for RACT is discussed in Section 6.2, while the approach for
applying RACT is described in Section 6.3.  Section 6.4 presents the
impacts of RACT on example vent streams.  Finally, Section 6.5 provides an
overall summary of RACT for this source category.
6.1  BACKGROUND
     The Clean Air Act Amendments of 1990 mandate that State
implementation plans (SIP's) for ozone nonattainment areas be revised to
require the implementation of RACT to limit VOC emissions from sources for
which the EPA has already published a control techniques guideline (CTG),
or for which it will publish a CTG between the date the amendments are
enacted and the date an area achieves attainment status.
Section 172(c)(l) requires that nonattainment area SIP's provide for the
adoption of RACT for existing sources.   As a starting point for ensuring
that these SIP's provide for the required emissions reduction, the EPA has
defined RACT as "...the lowest emission limitation that a particular
source is capable of meeting by the application of control technology that
is reasonably available considering technological and economic
feasibility.  The RACT for a particular source is determined on a
case-by-case basis, considering the technological and economic
circumstances of the individual source category."1  The EPA has elaborated
in subsequent notices on how RACT requirements should be applied.2.3
                                   6-1
-------
     The CTG documents are intended to provide State and local  air
pollution authorities with an information base for proceeding with their
own analysis of RACT to meet statutory requirements.  These documents
review existing information and data concerning the technical capability
and cost of various control techniques to reduce emissions.  Each CTG
document contains a recommended "presumptive norm" for RACT for a
particular source category, based on the EPA's current evaluation of
capabilities and problems general to the source category.  Where
applicable, the EPA recommends that regulatory authorities adopt
requirements consistent with the presumptive norm level, but authorities
may choose to develop their own RACT requirements on a case-by-case basis,
considering the economic and technical circumstances of the individual
source category.
6.2  TECHNICAL BASIS FOR REASONABLY AVAILABLE CONTROL TECHNOLOGY
     The technology underlying RACT for SOCMI reactor process and
distillation operations is combustion via either thermal incineration or
flaring.  These techniques are applicable to all SOCMI reactor processes
and distillation operations and can generally achieve the highest emission
reduction among demonstrated VOC control technologies.  Thermal
incinerators can achieve at least 98 weight-percent reduction of VOC
emissions (or reduction to 20 parts per million by volume [ppmv] dry
basis, corrected to 3 percent oxygen) for any vent stream if the control
device is well operated and maintained.  Likewise, the EPA has presumed
that flares can achieve at least 98 weight-percent control of VOC
emissions if the design and operating specifications given in the Code of
Federal Regulations (40 CFR 60.18) are met.  (Chapter 3.0 contains more
detail on the performance capabilities of thermal incinerators and flares
as applied to SOCMI vent streams.)  Although the control level
representing RACT is based on the application of thermal incineration or
flaring, it does not specify these techniques as the only VOC control
methods that may be used.  Any device can be used to comply with RACT
requirements as long as the 98 weight-percent destruction or 20 ppmv dry
basis, corrected to 3 percent oxygen emission limit 1s met.
     Other VOC control technologies were considered in the RACT
evaluation, including catalytic incinerators, carbon adsorbers, condensers
                                    6-2
-------
and absorbers.  However, for several reasons, these technologies were
rejected as the basis for the recommended presumptive norm for RACT.
Catalytic incinerators are difficult to apply one costing model to,
because different catalysts are required depending on the feed stream
characteristics.  Thus, it would be difficult to evaluate the cost impacts
of RACT options based on this technology.  Carbon adsorbers cannot achieve
98 weight-percent control in all cases and may not be applicable to
certain vent streams (i.e., streams containing sulfur compounds or heavy
metals) due to problems with carbon bed fouling.  Finally, refrigerated
condensers and absorbers, while effective for certain SOCMI vent streams,
cannot achieve 98 weight-percent control in all cases because they are
highly dependent on the type and concentration of organic compounds
present in the vent stream.  As explained in Section 6.5, recovery
devices, such as adsorbers, absorbers, and condensers, can be used as
pollution prevention techniques to meet the cutoffs described in
Section 6.3.
     In summary, the control level for RACT is represented by a VOC
emission reduction of 98 weight-percent or reduction to 20 ppmv dry basis,
corrected to 3 percent oxygen.  Section 6.3 discusses how to determine
which vent streams should apply control.
6.3  REASONABLY AVAILABLE CONTROL TECHNOLOGY SIZE CUTOFFS
     Vent streams from reactor processes and distillation operations can
vary widely in flow rate, VOC concentration, heating value, and VOC
emission rate.  Therefore, the uncontrolled emissions, emission
reductions, and control costs can also vary considerably for different
vent streams.  Accordingly, it may not be reasonable from a technical or
economic standpoint to apply controls to all distillation and reactor vent
streams.
     Important vent stream parameters in determining the emission
reduction and cost impacts of control are flow rate, heating value, and
VOC emission rate.  Flow rate determines control device sizing and,
therefore,  equipment cost.  Vent stream heating value determines how much
supplemental fuel is necessary to support combustion.  The VOC emission
rate determines the amount of emissions that can potentially be reduced.
It should be noted that heating value is closely related to VOC
                                    6-3
-------
concentration.  Similarly, VOC emission rate is dependent on the flow rate
and VOC concentration.  In general, as flow rate and VOC concentration
increase, the VOC emission reduction achievable by controlling these
streams increases and they become more cost effective to control.
Alternatively, if the flow rate and VOC concentration are low, the
achievable VOC emissions reduction is low and the cost effectiveness of
control is high.
     The total resource effectiveness (TRE) Index was chosen as the
applicability approach to be adopted for this CTG.  The TRE index is a
decision tool used to determine if the annual cost of controlling a given
vent gas stream Is acceptable when considering the emission reductions
achieved.  The TRE index equation is a measure of the cost per unit of VOC
emissions reduction and is normalized so that the decision point has a
defined value of 1.0.  The variables in the TRE index equation are the
stream characteristics (i.e., flow rate, heat value, VOC emission rate and
maximum cost effectiveness).  If the result for plugging in the
characteristics of a specific vent stream is less than or equal to 1.0,
the stream could effectively be controlled further using a combustion
device (flare or incinerator).  If the result of the TRE index equation is
greater than 1.0, the stream would not be controlled further without
incurring an unreasonable cost burden.  The Radian memorandum, "Total
Resource Effectiveness Derivation," explains the TRE development and
results.4
6.4  IMPACTS OF APPLYING VARIOUS COST EFFECTIVENESS CUTOFFS
     This section describes the impacts of applying various stream
parameters and cost-effectiveness value cutoffs to SOCMI reactor process
and distillation vent streams.  Options for the recommended presumptive
norm for RACT have been identified using a TRE index less than or equal
to 1.0.  Thus, the impacts analysis assumes that any vent stream with a
calculated TRE index of less than or equal to 1.0 would be required to
reduce emissions by 98 weight-percent (or to 20 ppmv) via thermal
incineration or flaring.
     Table 6-1 summarizes the impacts of various options for the
recommended presumptive norm for RACT.  These options are based on the
different maximum cost-effectiveness values for the model streams
                                    6-4
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controlled by each option.  These impacts were calculated for a population
of model vent streams that represents a subset of SOCMI reactor process
and distillation facilities.  National impacts were calculated by scaling
up impacts that would be incurred by a typical population of facilities
for this source category.3  A discussion of the procedure for estimating
impacts incurred by the model vent stream population is contained in the
Radian memorandum, "Reasonably Available Control Technology (RACT) Impacts
for the SOCMI CTG."5
     After reviewing the impacts in Table 6-1, the EPA has selected option
number 7 as the recommended presumptive norm for RACT.  This control level
would reduce an estimated 83 percent of the available VOC emissions and
would require controls on an estimated 15 percent of the vent streams for
a typical population of facilities.  At the recommended cutoff level,
there are no technical reasons why controls could not be applied.  In
fact, many facilities with reactor process and distillation operations are
already controlling streams of this size.  The EPA recognizes that the
impacts estimation procedure includes certain average assumptions for
variables that affect emission reduction and cost.  For example,
assumptions have been made regarding the piping distance to the control
device, and availability of space within existing facilities to
accommodate new control devices.  However, it is the EPA's judgment that
even if the characteristics of any individual facility were to deviate
somewhat from the assumed characteristics, the feasibility and costs of
control would remain reasonable.
6.5  REASONABLY AVAILABLE CONTROL TECHNOLOGY SUMMARY
     The recommended presumptive norm for RACT is the reduction of VOC
emissions by 98 weight-percent or to 20 parts per million by volume (ppmv)
on a dry basis, corrected to 3 percent oxygen in any vent stream that has
both a calculated TRE index less than or equal to 1.0.  When calculating
aTo avoid "double-counting," national impacts include only those impacts
 resulting from control after the implementation of the Hazardous Organic
 National Emission Standard for Hazardous Air Pollutants (HON) has
 occurred.  The SOCMI CTG and HON process vents regulatory actions will
 affect many of the same vents at SOCMI plants.  In addition, only
 facilities in nonattainment areas are considered subject to the CTG.
                                    6-6
-------
 the TRE  index,  the  standardized TRE equation should be used with the plant
 specific characteristics, not quoted values from vendors or manufacturers.
     Several  additional considerations in applying RACT warrant mention.
 First, it  is  recommended that any vent stream for which an existing
 combustion device is employed to control VOC emissions should not be
 required to meet the 98 weight-percent destruction or 20 ppmv emission
 limit until the combustion device is replaced.  In other words, it is
 recommended that facilities not be required to upgrade or replace existing
 combustion devices.  This approach would avoid penalizing those facilities
 which have already  undertaken efforts to control VOC emissions through
 combustion, but whose control device is not designed to achieve the
 98 weight-percent/20 ppmv level of control.
     Second,  it is  important to note that the presumptive norm for RACT
 provides incentives for pollution prevention by letting each facility
 consider the  trade-offs between process modifications and add-on controls.
 Specifically, as an alternative to installing an add-on control device,
 facilities can  choose to improve product recovery equipment so that the
 calculated TRE  index falls above the cutoff value of 1.0.  In this manner,
 the facility  would be limiting VOC emissions via process changes and would
 thereby  avoid having to install an add-on combustion device.
     Another  important consideration in applying RACT is emissions of
 pollutants such as carbon monoxide and nitrogen oxides from
 combustion-based control devices.  The potential consequences of emission
 from control  devices are twofold.  First, depending on the
 VOC's-to-nitrogen oxides ratio in the ambient air, nitrogen oxides
 emissions  from  control devices may cause more ozone to be formed than
 could be eliminated through the VOC reductions.  Second, emissions from
 control  devices may be enough to trigger New Source Review.  (Table 6-1
 shows expected  national emissions of nitrogen oxides and, in parentheses,
 the maximum annual emissions of nitrogen oxides at a single facility.)
Whether the VOC emission decreases are worth the.increases in other
pollutants from the VOC control device is highly dependent on air quality
and meteorological conditions in each specific geographical area.
Therefore,  States may select a less stringent level of control as RACT
based on these  considerations.
                                    6-7
-------
     Finally, other regulatory Initiatives under Title I (Nonattainment)
and Title III (Air Toxics) provisions of the Clean Air Act Amendments of
1990 may result in the application of controls to vent streams with a TRE
index above the cutoff value of 1.0.  For example, maximum achievable
control technology (MACT) requirements for the process vents portion of
the proposed HON may impact SOCMI vents more stringently than would the
presumptive norm for RACT as described above.  Furthermore, all revised
ozone SIP's (except for "marginal" areas) must demonstrate a total net
reduction in VOC emissions in accordance with a specified percentage
reduction schedule.  This requirement could also result in more stringent
control of SOCMI reactor process and distillation vents than would be
required by the presumptive norm for RACT.
                                    6-8
-------
6.6  REFERENCES

 1.  Federal Register.  State Implementation Plans; General Preamble for
     Proposed Rulemaking on Approval of Plan Revisions for Nonattainment
     Areas - Supplement (on Control Techniques Guidelines).  44 FR 53761-
     53763.  September 17, 1979.

 2.  Federal Register.  Emissions Trading Policy Statement; General
     Principles for Creation, Banking and Use of Emission Reduction
     Credits.  51 FR 43814-43860.  December 4, 1986.

 3.  Federal Register.  Approval and Promulgation of Implementation Plan;
     Illinois.  53 FR 45103-45106.  November 8, 1988.

 4.  Memorandum from Barbour, W. J., Radian Corporation, to L. Evans,
     EPA/CPB.  July 19, 1993.  Total resource effectiveness equation
     development.

 5.  Memorandum from Quincey, K. and Pring, M., Radian Corporation, to
     L. Evans, EPA/CPB.  November 17, 1992.  Reasonably available control
     technology (RACT) impacts for the SOCMI CTG.
                                    6-9
-------
        7.0  REASONABLY AVAILABLE CONTROL TECHNOLOGY IMPLEMENTATION

7.1  INTRODUCTION
     This chapter presents information on factors State agencies should
consider when developing an enforceable rule limiting volatile organic
compound (VOC) emissions from synthetic organic chemical manufacturing
industry (SOCMI) reactor processes and distillation operations.
Information is provided on important definitions, rule applicability,
emission limit format, performance testing, monitoring, and
reporting/recordkeeping.  Where several options exist for implementing a
certain aspect of the rule, each option is discussed along with its
relative advantages and disadvantages.  In some cases, there may be other
equally valid options.  The State or other implementing agency can
exercise its prerogative to consider other options provided the options
meet the objectives prescribed in this chapter.
     For each aspect of the rule, one option is identified as the
preferred option.  This guidance is for instructional purposes only and,
as such, is not binding.  Appendix D contains an example rule that
incorporates the guidance provided in this document.  The example rule
provides an organizational framework and sample regulatory language
specifically tailored for reactor processes and distillation operations.
As with the preferred option, the example rule is for instructional
purposes and is not intended to be binding.  The State or other
implementing agency should consider all information presented in this
control techniques guideline (CTG), together with additional information
about specific sources to which the rule will apply.  The reasonable
available control technology (RACT) rule should address all the factors
listed in this chapter to ensure that the rule is enforceable and has
reasonable provisions for demonstrating compliance.

                                   7-1
-------
7.2  DEFINITIONS
     The RACT rule should accurately describe the types of sources that
would be affected and clearly define terms used to describe the SOCMI
industry or applicable control methods.   This section offers guidance  to
agencies in selecting terms that need clarification when used in a
regulatory context.  This section presents example definitions of
pertinent terms (or cites sources where  definitions may be found) the
agency may refer to when drafting RACT regulations for these source
categories.
     Two important terms that should be  defined are "reactor processes"
and "distillation operations."  An example definition of the first term
might be "unit operations in which one or more chemicals or reactants
other than air are combined or decomposed in such a way that their
molecular structures are altered and one or more new organic compounds are
formed."  An example definition of the second term might read as:  "an
operation separating one or more feed streams into two or more exit
streams, each exit stream having component concentrations different from
those in the feed streams.  The separation is achieved by the
redistribution of the components between the liquid- and vapor-phase as
they approach equilibrium within the distillation unit."  A detailed
discussion of these terms can be found in Sections 2.2 and 2.3 of this
document.
     Certain types of equipment associated with reactor processes may  need
further clarification, such as the terms "process unit" or "product."
Certain descriptors for reactor processes or distillation operations may
be helpful to define, such as "batch reactor process," "batch distillation
operation," "vent stream," or "halogenated vent stream."  A discussion of
these terms is found in Chapter 2.0 of this document.
     Other terms requiring definition are those used to describe emission
control techniques such as "recovery device," "incinerator," "flare,"
"boiler," and "process heater."  A discussion of flares and incinerators
is presented in Section 3.1.  A discussion of recovery devices is found in
Section 3.2.  A description of boilers is given in Section 3.2.3.1 and a
description of process heaters is given  in Section 3.2.3.2.
                                    7-2
-------
     Terms pertaining to equipment used in monitoring and recording
emissions which may also require further clarification are "continuous
recorder," "flow indicator," and "temperature monitoring device."  An
example definition of continuous recorder might be "a data recording
device recording an instantaneous data value at least once every
15 minutes."  An example definition of flow indicator might be "a device
which indicates whether gas flow is present in a line."  Finally, an
example definition of temperature monitoring device might be "a unit of
equipment used to monitor temperature and having an accuracy of ±1 percent
of the temperature being monitored expressed in degrees Celsius or
+0.5 degrees Celsius, whichever is greater."
7.3  REGULATORY SUMMARY
     The EPA has published one CTG, promulgated two New Source Performance
Standards (NSPS), and proposed a third NSPS for SOCMI.  These regulatory
actions are summarized in the following subsections.  Table 7-1 presents
the list of chemicals affected by the proposed and promulgated SOCMI NSPS
and air oxidation CTG.  The marks alongside the chemicals indicate which
NSPS or CTG apply to that specific chemical.
7.3.1  Air Oxidation Control Techniques Guidelines
     The air oxidation CTG published in December, 1984, was written in
response to the Clean Air Act Amendment of 1977.  The purpose of the CTG
was to provide State and local air quality management agencies with an
initial information base for proceeding with their own assessment of RACT
for specific stationary sources.  The cutoff total resource effectiveness
index (TRE) of 1.0 was based on a cutoff cost effectiveness value of
1,600 ($/megagram).  Table 7-1 lists the chemicals affected by this CTG.
7.3.2  Air Oxidation Processes New Source Performance Standard
     The NSPS for Volatile Organic Compound Emissions from the Synthetic
Organic Chemical Manufacturing Industry (SOCMI) Air Oxidation Processes
(55 PR 26912, June 29, 1990: 40 CFR 60, Subpart III) was promulgated on
June 29, 1990.  This NSPS regulates SOCMI air oxidation processes
constructed,  reconstructed, or modified after October 21, 1983, that
produce any of the affected
                                    7-3
-------
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 chemicals  listed  in Table 7-1 as a product, co-product, by-product, or
 intermediate.
 7.3.3  Distillation Process New Source Performance Standard
     The NSPS for Volatile Organic Compound Emissions from the Synthetic
 Organic Chemical Manufacturing Industry Distillation Operations
 (55 FR 26931, June 29, 1990; 40 CFR 60, Subpart NNN) was also promulgated
 on June 29,  1990.  This NSPS covers SOCHI distillation operations
 constructed, reconstructed, or modified after December 30, 1983, that
 produce any  of the affected chemicals listed in Table 7-1 as a product,
 co-product,  or intermediate.
 7.3.4  Reactor Process New Source Performance Standard
      Standards of performance for SOCMI reactor process operations were
 proposed in  the Federal Register on June 29, 1990 (55 FR 26953),! but have
 not yet been promulgated.  The proposed standards apply to reactor
 processes  operating as part of a process unit that produces any of the
 affected chemicals listed in Table 7-1 as a product, by-product,
 co-product,  or intermediate.
 7.4  APPLICABILITY
     Because most industrial plants are comprised of numerous pieces or
 groups of  equipment that may be viewed as "sources" of air pollutant
 emissions, it is helpful to define the specific source or "affected
 facility"  that will be regulated.  A possible definition for affected
 facility is  Han individual reactor or distillation column with its own
 individual recovery system (if any) or the combination of two or more
 reactors or distillation columns and the common recovery system they
 share."  Reactors or distillation units operated in a batch mode are
 excluded from this definition since this CTG focuses on reactor processes
 and distillation operations that are continuous.  Also excluded from this
definition are distillation operations that are a part of polymer
manufacturing processes.
     Other facilities to consider exempting from RACT requirements include
reactor or distillation processes in plants with very low capacities.
Most research and development facilities or laboratory-scale facilities
are not designed to produce more than 1 gigagram (2.2 x 106 pounds) of
chemicals per year.  These facilities generally operate on an intermittent
                                   7-11
-------
basis making control techniques that apply to industry-scale production
facilities inappropriate for these operations.  For these same reasons, it
may also be appropriate to exempt facilities with vent stream flow rates
or VOC concentrations below a specified level.  It would be appropriate,
however, to require initial measurements or engineering assessments and
reports of the low flow rate to verify that these facilities are entitled
to the exemption.  It may also prove valuable to require owners and
operators of both low capacity and low flow rate facilities to report if a
process or equipment change occurs that increases the production capacity
or flow rate above the specified cutoff levels.
7.5  FORMAT OF THE STANDARDS
     Several formats are available for RACT regulations covering these
source categories.  Because emissions can be measured from reactor process
and distillation operation vents and from applicable control devices, an
emission limitation (performance) standard, rather than an equipment
standard, is recommended.
     Possible emission limitation formats would include a mass emission
rate limit, a concentration limit, or a percent reduction level.  A
percent reduction format best represents performance capabilities of
control devices used to comply with the RACT regulation.  Alternate
formats (such as mass emission rate or concentration limit) could cause
greater control than is required by RACT at some sources versus others and
less control than is required by RACT at others.  For example, under a
mass emission rate or concentration format, the required control
efficiency is greater for streams with higher emission rates or higher
vent stream concentrations.  Furthermore, the required control level for
vent streams with a low mass emission rate or concentration would not
reflect the capabilities of RACT.
     A weight-percent reduction standard is feasible when applied to
incinerators, boilers, and process heaters because emission rates can be
measured readily from the control device inlet and outlet.  As discussed
in Chapter 3.0 of this document, new incinerators can achieve at least
98 weight-percent reduction in total organics  (minus methane and ethane),
provided that the total organic (minus methane and ethane) concentration
of the process vent stream is greater than approximately 2,000 parts per

                                   7-12
-------
million by volume  (ppmv).  For vent streams with organics concentrations
below  2,000 ppmv,  a 98 weight-percent reduction may be difficult to
achieve, but an  incinerator outlet concentration of 20 ppmv dry basis,
corrected to 3 percent oxygen is achievable.  Therefore, the recommended
option is an emission limitation format based on a combination
weight-percent reduction standard and a volume concentration standard.
This recommended standard would demonstrate a 98 weight-percent reduction
in total organic compounds (minus methane and ethane) or a reduction to
20 ppmv total organic compounds (minus methane and ethane) dry basis,
corrected to 3 percent oxygen, whichever is less stringent.
     Available data indicate that boilers and process heaters with design
heat input capacity greater than 150 million British thermal unit per hour
(MMBtu/hr) can achieve at least a 98 weight-percent reduction provided the
waste  stream is  introduced into the flame zone where temperatures are
highest 1,538 to 1,649 °C (2,800 to 3,000 °F).  Therefore, vent stream
combustion in a boiler or a process heater of this size makes performance
testing unnecessary.  However, to ensure sufficient destruction of the
VOC, the regulation must require that the vent stream be introduced into
the flame zone.
     Flares differ from boilers, process heaters, and incinerators because
combustion occurs  in the open atmosphere rather than in an enclosed
chamber.  For this reason, it is difficult to measure the emissions from a
flare to determine flare efficiency.  However, the EPA test data indicate
that if certain design and operating condition are met, flares can be
presumed to be in compliance with the 98 percent/20 ppmv dry basis,
corrected to 3 percent oxygen, emission limit.  These conditions are found
in Section 118 of Part 60 of Chapter 40 of the Code of Federal Regulations
(40 CFR 60).1
7.6  PERFORMANCE TESTING
     When the owner or operator of an affected facility conducts either an
initial or subsequent performance test, it is recommended that the
facility be running at full  operating conditions and flow rates.
Performance tests needed to achieve the specified RACT requirements are an
initial test for a facility demonstrating either compliance with the
98-percent/20 ppmv emission limit, or maintenance of vent stream flow

                                   7-13
-------
rates and VOC concentrations at levels that assume a IRE value greater
than 1.0.  Specific recommendations pertaining to performance and
compliance testing are provided in Appendix D of this document.
     The best available procedure recommended for determining
concentrations from reactor process and distillation vents is EPA
Method 18.  This method has the advantage of being able to detect and
measure individual organic compounds.  Details concerning the use of this
method, including sampling, analysis, preparation of samples, calibration
procedures, and reporting of results are discussed in Appendix D of this
document.  All of the reference methods mentioned in this section are
found in Appendix A of 40 CFR 60.
7.6.1  Incinerators
     For the owner or operator of a facility using an incinerator to
achieve the suggested RACT emission limit, Reference Method 18 is
recommended for determining compliance during any performance test.
Reference Method 1 or 1A is recommended for selecting the sampling site.
To determine the reduction efficiency, it is recommended that the control
device inlet sampling site be located prior to the control device inlet
and following the product recovery device.  Reference Methods 2, 2A, 2C,
or 2D are recommended for determining the volumetric flow rate,  and
Reference Method 3 is recommended for determining the air dilution
correction, based on 3 percent oxygen in the emission sample.
7.6.2  Flares
     The recommended compliance test for a flare includes measuring exit
velocity and stream heat content to verify compliance with the operating
specifications listed in 40 CFR 60.18.
7.6.3  Boiler or Process Heater
     The performance test requirements for a small boiler or process
heater (less than 150 MMBtu/hr) are identical to those for incinerators.
For a large boiler or process heater, the initial performance test could
be waived.  It is the EPA's judgment that a boiler or process heater of
this size would be able to meet the 98 percent/20 ppmv dry basis,
corrected to 3 percent oxygen emission limit provided that the vent stream
is introduced into the flame zone of the boiler or process heater.
                                   7-14
-------
 7.6.4   Recovery Devices
     A  facility may choose to comply with RACT requirements by maintaining
 its product recovery  system  in such a manner that the vent stream flow
 rate and VOC concentration are below the cutoff points.  Calculation of
 flow rate and VOC concentration must be immediately downstream of all
 product recovery equipment and prior to the introduction of any
 nonaffected stream.   It  is recommended that the volumetric flow rate be
 determined according  to  Reference Methods 2, 2A, 2c, or 2D, as
 appropriate.  Molar composition of the vent stream should be measured via
 Reference Method 18.
 7.7  COMPLIANCE MONITORING REQUIREMENTS
     Note:  The monitoring requirements need to be consistent with the
 Enhanced Monitoring Rule, once it is promulgated.  The Hazardous Organic
 National Emission Standard for Hazardous Air Pollutants (HON) can be used
 as guidance in the interim.  If a facility is covered by the HON, the HON
 monitoring requirements  would also satisfy the RACT compliance
 determination requirements,  and no additional monitoring is necessary.
 7.7.1   Thermal Incinerators
     There are two possible  monitoring methods for facilities with an
 incinerator to determine compliance with the suggested RACT emission
 limit.  They are continuous  emission monitoring and continuous combustion
 control device monitoring.   Continuous combustion control device inlet and
 outlet  monitoring is  preferred because it would give a continuous, direct
 measurement of actual emissions.  However, no continuous monitor measuring
 total organics has been  demonstrated for incinerators because each of the
 many diverse types of compounds in process vent streams would have to be
 identified separately and the concentrations of each determined.
 Continuous monitoring of all the individual compounds would be too
 expensive to be practical.
     The other possible  monitoring method is continuous combustion control
device measurement.   Certain parameters, such as temperature and flow
 rate, when measured,  can reflect the level of achievable control device
efficiency.  It has been demonstrated that a decrease in combustion
 temperatures from the design value can cause significant decreases in
control device efficiency.  Because temperature monitors are relatively

                                   7-15
-------
inexpensive and easy to operate, it is recommended that the owner or
operator of an affected facility should be required to install,  calibrate,
maintain, and operate a temperature measurement device according to
manufacturer's instructions.
     Flow indicators are also relatively inexpensive and easy to operate.
Flow indicators determine control device efficiency by indicating whether
or not organic-laden streams are being routed for destruction.  It is
recommended that the owner or operator of an affected facility should be
required to install, calibrate, maintain, and operate a flow indicator
according to the manufacturer's specifications.  It is recommended that
the flow indicator be installed at the entrance to any bypass line that
could divert the stream away from the combustion device to that
atmosphere.
7.7.2  Flares
     In order comply with the recommended RACT requirements (see
Section 7.5), flares must be operated in accordance with 40 CFR 60.18.
Visual inspection is one method of determining whether a flame is present;
however, if the flare is operating smokelessly, visual inspection would be
difficult.  An inexpensive heat sensing device, such as an ultra-violet
beam sensor or a thermocouple, is recommended for use at the pilot light
to indicate continuous presence of a flame.  Measuring combustion
parameters (as recommended for incinerators), such as temperature and flow
rate, is not feasible for flares because these parameters are more
variable in an unenclosed combustion zone.
     It is also recommended that flow rate and heat content of the flared
stream be determined by a flow indicator in the vent stream of the
affected facility.  This should be performed at a point closest to the
flare and before the stream is joined with any other vent stream.
7.7.3  Boiler or Process Heater
     To ensure that a boiler or process heater is operating properly as a
combustion control device, it is recommended that the owner or operator
maintain steam production (or equivalent) records.  The owner or operator
should also install and operate a flow indicator that provides a record of
vent stream flow to the boiler (or process heater).  It is recommended
that temperature be monitored for boilers and process heaters of less than

                                   7-16
-------
150 MMBtu/hr design heat input capacity.  Any boiler or process heater in
which all vent streams are introduced with primary fuel is exempt from
this requirement.
7.7.4  Recovery Devices
     Facilities using product recovery devices to determine compliance
with the recommended RACT, should ensure that the measured flow rate and
VOC concentration have not changed since the time of the initial
performance test.  To accomplish this the facility owner or operator
should monitor product recovery device parameters that correlate with
proper operation of the device.  The type of parameters to be monitored
depends on the final device in the product recovery system.
     For an absorber, two operating parameters are recommended as adequate
determinants of performance:  the specific gravity of the absorbing liquid
and the flow rate of the absorbing liquid.  For a condenser, the exit
stream temperature is recommended as the main determinant of performance.
For a carbon adsorber, the carbon bed temperature (after regeneration and
completion of any cooling cycle) and the quantity of steam used to
regenerate the carbon bed are recommended as the main determinants of
performance.
     As an alternative to monitoring the above parameters, the EPA
recommends that a vent stream (post-recovery system) organic monitoring
device with a continuous recorder be allowed.
7.8  REPORTING/RECORDKEEPING REQUIREMENTS
     Each facility subject to the RACT requirements should keep records of
certain key parameters that would indicate compliance.  First, the
facility should identify the control method selected to meet the RACT
requirements.  Next, the results of any performance testing results
(discussed in Section 7.6) should be recorded.  Further, the facility
should record all parameters monitored on a routine basis to determine
continued compliance with the RACT emission limit.  These parameters
(listed in Section 7.7) differ depending on the means by which the RACT
requirements are met.  Any deviations of the monitored parameters listed
in Section 7.7 should also be recorded along with any corrective actions.
                                   7-17
-------
7.9  REFERENCES

 1.  Federal Register.  Standards of Performance for New Stationary
     Sources; Volatile Organic Compound (VOC) Emissions from the Synthetic
     Organic Chemical Manufacturing Industry (SOCMI) Distillation
     Operations.  Final rule.  55 FR 26931-26952.  June 29, 1990.

 2.  U. S. Environmental Protection Agency.  Code of Federal Regulations.
     Chapter 40, Part 60.  Washington, D.C.  Office of the Federal
     Register.  July 1, 1990.  pp. 630 through 633.
                                   7-18
-------
            APPENDIX A

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                                                                  A-39
-------
      APPENDIX B
EMISSION DATA PROFILES
-------
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                                                  B-l
-------
TABLE B-I DISTILLATION EMISSION DATA PROFILE
PRODUCT
PROCESS
Chlorobenzeoe
Aniline
Chlorobenzene
Chiorooenzene
Aniline
Chlorobenzene
Terephthalic Acid
Confidential
Ethyl benzene
Methyl MethacryUte
84
Acetone
Acetone
Acetic ACid
Chloroprene
Malic Anhydride
Confidential
Dimethyl Terephthalate
Chloroprene
Acetic Anhydride
Phtnalic Anhydride
Ethytacetate
Ethyldichlonde
Alkyl Benzene
Acetic Anhydride
Perchlorocthylene
Acetone
Acetone
Acetic Acid
Acetone
Nitrobenzene
Methyl Methaciylate
Chloroprene
Dichlorobenzene
Acetic Acid
Diphcnytamiac
Methyl Ethyl Ketone
Ethyiene Onde
Ethylacetate
Vinyl Acetate
Ethyldichlonde
Phthalic Anhydride
Terephthalic Acid
Methyl Methaciylate
Dtchlorobenzene
86
Acetic Anhydride
Dimethyl Terephthalate
EthanoUminet
Acetone Cyanooydride
EthyMichtoride
Methyl Ethyl Ketooe
Acetic Anhydride
Ethyldichloride
Milk Anhydride
Ethylbenzene
Ethyldichloride
Dimethyl Terephthalate
Methyl MethacryUte
Acrybc Acid
Ethyldichloride
Acetic Anhydride
NUMBER OP
COLUMNS AND
OPERATING
CONDITIONS
1NV
IV
1NV
1NV
IV
1NV
1NV
ICO
1NV
1NV
2NV
IV
2NV
1NV
1NV
3V
ICO
IV
IV
ICO
IV
1NV
IV
1 NV
ICO
1NV
1NV
IV
1NV
1NV
IV
1NV
2V
IV
ICO
IV
1NV
1NV
1 NV
1NV
1NV
IV
1NV
IV
IV
1NV
ICO
1NV
IV
1NV
IV
1NV
ICO
2NV
IV
1NV
1NV
1NV
1NV
IV
1NV
4 CO
PLOWRATE
CSCTM)
0.005
0.007
0.012
0.013
0.02
0.02
0.02
0.02
0.063
0.1
0.1
0.1
0.1
0.18
0.2
02
026
0.3
0.4
0.48
OS
0.7
0.9
12
1.2
1-3
U9
1.39
1.45
U
1.5
1.7
1.8
1.8
1.94
2
22
23
23
23
2.4
2.4
2-5
2.6
2.6
33
3.66
42
23
4.4
4£
4.9
4.98
6
63
63
6.94
7
7.4
7.4
8.1
8.16
HEAT CONTENT
(BTU/SCF)
133
3752
374
755
3047
432
169
0
7
1056
834
360
36
207
2778
0
1375
4978
2224
1024
3602
680
1024
3643
1024
143
966
966
903
1225
352
1483
858
651
68
0
1183
1191
1012
781
1024
260
114
2870
62
90
1024
180
0
190
53
2003
1024
727
0
1286
727
0
439
0
91
1024
VOC FLOWRATE
(LB/HR)
0.004
0.11
0.025
0.034
0.29
0.031
0.02
0
0
0.4
0.25
0.2
02
0.08
2
0
1.83
4.9
4.9
1.53
11.5
0.4
14 I
15
3.81
3.4
6.04
6.04
1.6
10.4
1.8
13.6
4.9
8.1
0.8
0.003
10
13.8
6.4
5.2
38
4
1.9
41
13
28.8
11.61
5
0
4
3.9
3168
15.81
63.9
0
3
55
10
12
0
6.6
25.88
                       B-2
-------
TABLE B-l DISTILLATION EMISSION DATA PROFILE* (Continued)
PRODUCT
PROCESS
Dimethyl TerephthaUte
Dimethyl TerephthaUte
Vuiyi Acetate
Phthalic Anhydride
ChJorobenzene
DichJorobeazeoe
Chloroprene
Acrylonitrik
Vinyl Acetate
Chloroprene
Acetone
ElhyklichkHHk
Formaldehyde
Ethyldichlonde
Phthalic Anhydride
Acrylic Acid
Perchloroethytene
Dimethyl Terephthtltte
Vinyl Acetate
Dimethyl TerephthtUte
as
Dimethyl TerephthtUte
Phthalic Anhydride
Acetone
Methyl MethacryUte
EthanoUuninef
Ethylbenzene
Acrylic Acid
Acetone
Butadiene
Acrylic Acid
Aciylonitrik
Cyclohexanone/cyclohexaaol
ChJoroprene
Acrytom trite
Chlorobenzene
Phthalic Anhydride
Ethyl Acrytate
Acrylic Acid
Acetone Cyanohydrid*
Acrylic Ecten
Chlorobenzene
85
Acetone Cymnooydride
Confidential
ConfidentiaJ
Acetic Acid
Acetone
Dimethyl Terepbthalate
Methanol
CydohexanoM/cyclohenDOl
Methyl MethacryUte
Ad tponi trite
Ethytene Gtycol
Confidential
Dimethyl TerephthtUte
86
Hexamethytene Diamine
Alkyt Benzene
Methyl MethacryUte
NUMBER OF
COLUMNS AND
OPERATING
CONDmONS
1NV
2V
1NV
IV
IV
IV
IV
1NV
1 NV
2V
IV
1NV
2V
IV
IV
2V
1NV
1 NV
1 NV
2V
4 NV
1 NV
IV
1NV
1 V
3V
1 V
2V
1NV
1NV
IV
IV
3V
1NV
IV
IV
2V
2V
2V
1NV
3V
1 NV
7V
IV
3 CO
4 CO
3NV
1NV
2V
1NV
IV
IV
9V
6V
ICO
1 NV
1NV
7V
IV
IV
FLOWRATB
(SCFM)
8.4
8.9
9
9.5
9.9
9.9
10
10.2
10.5
11.0
1115
115
115
13
13.2
13.2
13.6
15
15
15
16.7
17.4
17.9
18
18.3
19.5
19.7
20
21.13
22J
22.6
2Z7
22.701
23.6
25.6
26.1
27
27.2
27.6
31.5
33.9
34.9
36.701
39.2
40.59
49.6
50
50.4
54.6
63.4
68.7
72.9
75
75.1
77 32
793
80
81.1
85.9
96.2
HEAT CONTENT
(BTU/SCF)
236
47
1308
690
177
177
3
379
74
30
0
727
9
183
979
8
6
236
149
47
1464
12S2
69
0
2870
0
0
0
2592
1453
92
439
18
0
346
346
505
69
400
1916
168
495
123
4
0
0
4
70
47
449
72
66
0
0
6
1453
9
0
104
295
VOC FLOWRATE
(LB/HR)
13
2.2
34.8
417
6
2
0.2
15.8
15.2
1.1
0
98.8
0.8
313
84.1
0.6
11
12
6.6
5
0.1
120.5
8 I
0
289
0
0
0
170.2
100.5
105
44
15
0
37.9
43.1
100
5.6
55.8
289
15.7
59
13.498
0.18
0.09
0.56
1.1
16.9
17
399.3
26.3
A* g
26.5
0
0
1-36
601
1 Q £
19.0
0
30.6
148.8
                               B-3
-------
                        TABLE B-2. DISTILLATION EMISSION DATA PROFILE1 (Continued)

PRODUCT
PROCESS

Ethyldichlonde
Acetone Cyanohydride
Dimethyl Terephthalatt
Methyl Methacrylate
CMoropreneMethyl
MethacryUte
Dimethyl Trephthalate
Methyl Methacrylate
Ethyl Acrylate
Dimethyl Terephthalate
Acetic Acid
Acrylic Acid
Ethyldichlonde
Methtno)
Acetic Acid
Isophthalk Acid
Acetaldehyde
84
NUMBER OF
COLUMNS AND
OPERATING
CONDITIONS
1NV
2V
1NV
2NV
3V
IV
2V
1NV
2V
1NV
1NV
1NV
1 NV
1NV
1NV
1NV
2NV
6NV

FLOWRATE


100
lOlJ
123.8
126.4
145
152
176
178J
219
281
358
364
535.5
560
575
637
647.3
656

HEAT CONTENT
(BTU/SCF)

6
4
768
155
12
13
47
1316
45
768
333
150
804
1258
380
19
293
6

VOC FLOWRATE
(LB/HR)

8J
U
628J
116J
7.2
9*
57
1300
454
1426
375
289
3050
3668
600
123
183
19
* Emiwoni data taken from Appendix C of DUtillation Operation! in Synthetic Ornnic Minuficrunni • Backiround Information
 for Proooted Standards (EPA-450/3«-005a).
                                                B-4
-------
   APPENDIX C
COST CALCULATIONS
-------
                                APPENDIX C

                            COST CALCULATIONS


C.I  SIZING CALCULATIONS FOR THERMAL INCINERATOR

     Hand Calculations for the VENTCOST Program - Incineration Procedure

     •    Used to assess control equipment costs for the SOCMI CTG for
          Reactor Process and Distillation Vents.

     •    Calculations based on OAQPS Control Cost Manual, Chapter 3.

     •    The stream costed in this example is model stream R-LFHH.  Its
          characteristics are as follows:
     A.
          VOC to be controlled
          MW
          Flow rate (total)
          VOC flow rate
          Heat value
          Oxygen content
          Inert content
                       Ethyl Chloride*
                       64.5 Ib/lb mole
                       3.839 scfm
                       8.4 Ib/hr
                       1,286 Btu/scf
                       0%
                       Assume all N2
*Most of the following calculations are based on the actual
 compound in the SOCMI Profile.  However, the combustion and
 dilution air calculations are based on the design molecule
 ^2.85^5.700.63* which represents the average ratio of carbon,
 hydrogen, and oxygen for streams in the SOCMI profile.  The
 molecular weight of this "design molecule" is 50 Ib/lb-mole.

Check to see if the stream to be controlled is halogenated--yes,
ethyl chloride contains chlorine.  Since the stream is
halogenated, the following applies.

1.   No heat recovery is allowed for halogenated streams.

2.   A scrubber will be required to remove acidic vapors from
     the flue gas following combustion.  Scrubber sizing and
     costing calculations for this vent stream immediately
     follow the incinerator calculations (see Section C.2).
                                    C-l
-------
B.   Calculate total moles of the vent stream, and quantify moles of
     VOC, 02 and inerts.
     1.   VOC moles only:
          VOC moles - (8.4 lb/hr)(hr/60 min)(lb-mole/64.5 Ib)
                    * 0.0022 Ib-moles/min
     2.   Total vent stream moles:
          Vent moles - (3.839 scfm)(lb-mole/392 scf)
                     - 0.0098 Ib-moles/min
     3.   Oxygen moles:
          02 moles - 0
     4.   Inert moles:
          Inert moles * Vent moles - VOC moles - 02 moles
                      = (0.0098 - 0.0022 - 0) Ib-mole/min
                      = 0.0076 Ib'mole/min
C.   Calculation of Molar Ratio of Air to VOC
     Please note that the combustion and dilution air calculations
     are based on the design molecule C2.85H5.70o.63» which
     represents the average ratio of carbon, hydrogen, and oxygen.
     The molecular weight of this "design molecule" is 50 Ib/lb-mole.
     Assume 3.96 moles of 02 are required for each VOC mole.
     1.   Since no oxygen is present in the stream, additional
          combustion air must be added, to insure proper combustion.
     2.   Calculate the ratio of 02 to VOC required for combustion.
          02 theory * 3.96 - 02 ratio already in stream*
         *Additional air is not required if sufficient oxygen is
          already present in the vent stream.
     3.   Since air is 21% 02 the necessary ratio of air to VOC is:
          Air ratio - (3.96)/0.21 - 18.86 moles air/mole VOC
D.   Calculation of molar ratios of inert moles to moles VOC
     1,   Inert ratio « inert moles/VOC moles
                      = 0.0076/0.0022
                      - 3.4545 moles inert/mole VOC
                              C-2
-------
E.   In order to ensure sufficient 62 is present in the combustion
     chamber, enough air must be added to provide 3% 03 in the
     exhaust (flue) gas stream after combustion.  The 62 material
     balance is :

     (Initial 02%}(vent stream) + (0.21)(dilution air) =
           (0.03)(exhaust)

     Initial 62% = 0; therefore,

     (0.21)(Dilution air) - (0.03)(exhaust stream)

     (0.21)(Dilution air) - (0.03)(dilution air + vent stream)*

     *Assume no increase in moles after combustion

     (0.21)(Dilution air) * (0.03)(dilution air) +
           (0.03)(vent stream)

     Dilution air = (0.03)7(0.21 - 0.03) (Vent stream flow)

     *This factor will be used later.

F.   Exhaust gas consists of noncombustibles (N2) + C02 + H20 (see
     "Combustion Stoichiometry Memo")

     1.   Exhaust ratio - (0.79)(air ratio) + 2.85 + 2.85
                        =20.6 moles exhaust/mole VOC

     2.   Dilution ratio = 0.03/(0.21 - 0.03)
                             (Inert ratio + Exhaust ratio)

G.   Calculate flows of stream components based on calculated ratios

     1.   Dilution ratio - Factor * (Inert ratio - Exhaust ratio)
                         - (0.1667)(3.4545 + 20.6)
                         = 4.009

     2.   Dilution air flow - (Dilution air ratio)(VOC moles)
                                (392 scf/lb-mole)

          Dilution air flow - (4.009)(0.0022)(392)
                            =3.457 scfm

     3.   Combustion air flow - (Air ratio)(VOC moles)(392)
                              = (18.86)(0.0022)(392)
                              - 16.26 scfm

          Combined air flow = Combustion air + Dilution air
                            - (16.26 +  3.4545)
                            - 19.7 scfm
                               C-3
-------
      4.    Inert  gas  flow =  (Inert  ratio)(VOC moles)(392)
                          =  (3.4545)(0.0022)(392)
                          =2.98  scfm

      5.    Total  flow «  Combined  air flow +  Initial  vent  stream  flow
                        + Inert gas flow
                      -  19.7  + 3.839 scfm

           New  flow - 26.519  scfm

H.    Recalculate heat value  of the stream after adding air  streams
      (prior to combustion)

      1.    Heatval «  (Initial flow * Initial heatval)/New  flow
                  «  (3.839 * 1.286J/26.519
                  «  186.2 Btu/scf

I.    Check the heat  value of the precombustion vent stream,  to  see if
      it is acceptable from a safety perspective

      1.    Streams containing halogens must  have a heat value
           < 95 Btu/scf,  nonhalogens < 98 Btu/scf.

           186.2  > 95

      2.    Dilute  stream  to have  a heat value < 95 Btu/scf.

           Dilution air -  [New flow * (Heatval - 95)]/95
                       -  [26.5 * (186.2 - 95)]/95
                       - 25.5 scfm

           Heatval «  95 Btu/scf

           New  flow =  26.5 + 25.5
                   =52.0 scfm

J.   Minimum incinerator flow is 50 scfm.  Streams less than 50 scfm
     will   be increased by addition of air.

     52 scfm > 50 scfm

K.   Establish temperature that incinerator operates:

     Halogenated:  2,000°F

     Nonhalogenated:   1,600°F
                              C-4
-------
L.   Nonhalogenated streams are potential candidates for heat
     recovery.

     If addition of air flows results in lowering the heat value of
     the entire vent stream below 13 Btu/scf («25% LEL), then the
     entire vent stream is eligible for heat (energy) recovery in a
     heat exchanger.

     High heat value streams cannot be heated in a preheater because
     of combustion/explosion concerns, but the VENTCOST program will
     calculate economic options that allow preheating of the air
     stream only.

     The energy recovery equations are weighted to account for the
     mass of the heated streams since the flows being preheated may
     be smaller than the exhaust (flue) gas flows.

     No calculations are presented here since the example stream is
     halogenated, and,  therefore, heat recovery is not allowed.

M.   Calculate the auxiliary fuel (Qaf) requirement

     Qaf • [0.0739 * new flow * [0.255 * (1.1 * incinerator
           temperature - temperature gas - 0.1 * 77) -
           (heatval/0.0739))] + [0.0408 * [21,502 -
           (1.1 * .255 * (incinerator temperature - 77))]

     -*    Incinerator Temperature = 2,000 °F

     *See OAQPS Control Cost Manual, Incinerator Chapter for
      Derivation and Assumptions.

                [.0739 * 52 * [.255 * (1.1 * 2,000 -
     Qaf = 	77 - 0.1 * 77) - (2097.0739)11	
           [0.0408 * [21,502 - (1.1 * .255 * (2,000 - 77)]]

     Qaf - f.0739 * 52 * (-2288)1
                   855.27

     Qaf = -10.3 scfm

     Negative value indicates no auxiliary fuel is theoretically
     needed.  Therefore, set Qaf = 0.

N.   Calculate sufficient auxiliary fuel to stabilize flame  (5% of
     TEI).

     1.   Thermal Energy Input (TEI) = 0.0739 * (new flow +  Qaf) *
                                         (0.255 * (incinerator
                                         temperature - 77)

          TEI - 0.0739 * (52 + 0) * 0.255 * (2,000 - 77)
              = 1,884

                               C-5
-------
          2.   Qaf - (0.05 * 1,884)/(0.0408 * 21,502)
                   - 0.107 - 0.1 scfm
     0.   Calculate the total volumetric flow rate of gas through the
          incinerator, Qf-j.  Include auxiliary air for the natural gas.
          1.   Qfi - new flow + Qaf + combustion air for fuel
          2.   Assuming the fuel is methane, CH4, the combustion reaction
               is:
               CH4 + 202 - C02 - C02 + 2H20
               So two moles of 0? are required for each mole of fuel.
               Since air is 21% 02.
               2/0.21 = 9.5 moles air/mole of fuel
               Combustion air for fuel - (Qaf * 9.5)
          3.   Qfi - New flow + Qaf + (Qaf * 9.5)
                   * 52 + 0.107 + (0.107 * 9.5)
                   = 53 scfm
C.2  COST ANALYSIS - ESTIMATING INCINERATOR TOTAL CAPITAL INVESTMENT
     A.   The equipment cost algorithms are only good for the range of
          500 scfm to 50,000 scfm.   The minimum design size is 500 scfm,
          so capital costs are based on 500 scfm, and annual operating
          costs are based on calculated
          1.    Design Q = 500 scfm
          For 0% heat recovery, equipment cost, EC, is:
          EC  = 10,294 * (Design QA-2355) * (# incinerators) *
               (CE INDEX/340.1)
          EC  = 10,294 * (500A-2355) * \ * (355.6/340.1)
          EC  - $46,510.
          Add duct cost.   Based on an article in Chemical Engineering
          (5/90)  and assuming 1/8-in. carbon steel  and 24-in. diameter
          with two elbows per 100 feet.
          Ductcost - [(210 * 24*0-839) + (2 * 4.52  * 24*1-43) *
                     (length/100) * (CE INDEX/352.4)]
          Ductcost « $11,722.52 (for length of 300  ft)
                                   C-6
-------
     D.   Add auxiliary collection fan cost, based on 1988 Richardson
          manual.
          Fancost  = (96.96418 * Initial Q*0.5472) * 355.6/342.5
                  * 210.18
     E.   Total  Equipment Cost, ECjoT* is given by:
          ECjQT *  EC + Ductcost + Fancost
                =  46,510 + 11,723 + 210.18
                -  $58,443
     F.   Purchased Equipment Cost, PCE, is:
          PCE - 1.18 * ECjQT
              = $68,963
     G.   Estimate Total Capital Investment, TCI
          if Design Q > 20,000, installation factor * 1.61
          if Design Q < 20,000, installation factor = 1.25
          TCI = 1.25 * PCE
              = 1.25 * $68,963
              = $86,203
C.3  CALCULATING ANNUAL COSTS FOR INCINERATORS
     A.   Operating labor including supervision (15%)
          1.   Assume operating labor rate - $15.64/hr (1/2 hour per
               shift)
               Op  labor = (0.5 * Op hours)/8 * ($15.64/hr)(1.15)
                          (Op hours = 8,760)
               Op  labor = $9,847.34/yr
     B.   Maintenance labor and materials
            M labor - (0.5/8 * 8,760) * ($17.21/hr)
                    - $9,422.48
          Materials = M labor = $9,422.48
     C.   Utilities  *= Natural Gas & Electrical Costs
          Assume value of natural gas = $3.30/1,000 scf
          1.   Natural gas - (3.30/1,000) * Qaf * 60 min/hr * Op hours
               Natural gas = (3.30/1,000) * 0.107 scfm * 60 * 8,760
                           = $186/yr
          2.   Power = (1.17 * 10A'4 * Qfi * 4)/0.60
               Power = (1.17 * 10'4 * 53 * 4)/0.60
                     = 0.0413 kW
                                    C-7
-------
          3.   ElecCost - (0.061 $/kWh) * (0.0413) * (8,760)
                        - $22.07
     D.   Calculate total direct costs, TDC
          TDC = Op_Labor + M_Labor + Material + NatGas + ElecCost
              - (9,847 + 9,422 + 9,422 + 186 + 22.07)
              - $28,899/yr
     E.   Overhead - 0.60 * (Op_Labor + M_Labor + Material)
                   - $17,214.6/yr
     F.   Administrative - 2% of TCI
          Admin - (0.02)(86,203)
                - $l,724/yr
G.
H.

Tax = 1% of TCI
Tax - $862/yr
Insurance * 1% of TCI
Ins = 0.01 * TCI
= $862/yr
     I.   Annualized Capital Recovery Costs, Anncap, is:
          AnnCap <= 0.16275 * $86,203
                 = $14,029.54/yr
     J.   Total Indirect Capital Cost, 1C, is:
          1C = overhead + administrative + tax + insurance + Anncap
             = (17,215 + 1,724 + 862 + 862 + 14,029) $/yr
             = 34,692 $/yr
     K.   Total Annual Cost, TAC, is:
          TAC = 1C + DC
              - 34,692 + 28,899
              = 63,591 $/yr
C.4  SIZING CALCULATIONS FOR SCRUBBER
     Hand Calculations for the Ventcost Program Scrubber Procedure
     •    Stream to be costed is R-LFHH as it exists after combustion in
          incinerator
                                    C-8
-------
Calculate stream parameters after combustion.  Assume 98 percent
VOC destruction

-»•    Ethyl chloride is the VOC in stream R-LFHH.  There is one
     mole of Cl for every mole of VOC.  Therefore, for every
     mole of VOC destroyed, one mole of HC1 is created.

VOC destroyed = (initial VOC flow-lb/hr)(0.98) - VOC MW
              - (8.4 lb/hr)(0.98)/(64.5 Ib/lb-mole)
              • 0.13 Ib-mole/hr

HC1 created =0.13 Ib-mole/hr

HC1 (Ib/hr) = (0.13 lb.mole/hr)(36.5 Ib/lb-mole)
            = 4.66 Ib/hr

Calculate inlet halogen concentration

HC1 (scfm) = (4.66 lb/hr)(lb-mole/36.5 Ib) * 392 scf/lb-mole *
               1 hr/60 min
           *  0.83 scfm/min

HC1 (ppm) = (0.83 scfm)/Qfi * 10A6
          = (0.83/53) * 10*6
          = 15,660 ppm  (inlet concentration)

The halogen is chlorine, therefore

Molecular weight (Hal_MW) - 35.5

Slope of operating curve (slope) = 0.10

Schmidt No. for HC1 in air (SCG) = 0.809

Schmidt No. for HC1 in water (SCL) = 381.0

Calculate the solvent flow rate.

New flow = 53 scfm

Gas moles - (53 scfm)(.075 lb/ft3)(lb-mole/29 lb)(60 min/hr)
          - (53)(0.155)
          = 8.22 Ib-mole/hr

Assume L/g = 17 gpm/1,000 scfm

Convert to unitless ratio

L/G = 17 * (8.34 * 60)/[(1,000/392) * 60 * 29]  =  1.916
                          C-9
-------
Absorption  factor  (AF) =  (L/G)/slope

AF  =  1.916/0.1
AF  =  19.16

Liquid moles =  (slope of  operating curve) (adsorption factor AF)
                 (gas moles)
             =  15.75 Ib-mole/hr

 Liquid flow  (gal/min) =  (15.75 lb-mole/hr)(18 Ib/lb-mole)/
                         (62.43 Ib/ft3)/60 min/hr * 7.48 gal/ft3

          Liquid flow =  0.57 gal/min

  Liquid flow (Ib/hr) =  (0.57 gal/min)(8,34 1b/gal)(60 min/hr)
                      =  283.3 Ib/hr

 Calculate Column Diameter

 Density of air  = 0.0739  lb/ft3 (from ideal gas law)

 Density of liquid = 62.2 lb/ft3

 MW of gas stream = MW HCL x Volume Fraction + MW Air x Volume
                   Fraction

 MW stream =  36.5 * (15,660/10*6) + 29 * [(10A6-15,880)/10A6]
          =  36.5 * 0.0157 + 29 * 0.98434
          =  29.12 Ib/lb-mole

-»    Column  diameter based on correlation for flooding rate in
     randomly packed towers (see HAP manual)

     ABSCISSA = (liquid  lb/hr)/(gas Ib/hr) *
                  (density of gas/density ot liquid)*0-^
          ABS - [283.3/[8.22 * 29)] * (0. 0739/62. 2)A°-5
          ABS = 0.0410

 ORD = 0.9809237 * (ABS)A(-0. 0065226 * log [ABS]) +
      (ABS)A(-0. 021897)
    = 0.9809237*(0.0410)A(-0. 0065226 * log[0.0410]) +
      (0.0410)A(-0. 012897)
 ORD - 0.15

 Calculate G_Area (Ib/ft^.sec)  based on column cross sectional
 area at flooding conditions.

 G_Area = F * (ORD * density of gas * density of liquid *
         32.2/69.1 * 0.85A0.2)A0.5
       = 0.6 *  (0.15 * 0.0739 * 62.2 * 32.2/69.1 * 0.85A0.2)A°-5
       = 0.34
                         C-10
-------
Calculate the Area of the Column

Area of column = (MW stream * gas moles)/ (3, 600 * G_Area)
    Area (ft?) = (29.12 * 8.22)7(3,600 * 0.34)
    Area (ft2) = 0.19 ft2  •

Calculate Diameter of Column

D_col = [(4//7) Area]A°-5
      - 1.27 (Area)A0-5
      = 0.5 ft

Calculate liquid flux rate

LL (Ib/hr-ft2) = (liquid flow lb/hr)/Area
            LL = (283.3)/(0.19)
               = 1,491

Calculate the number of gas transfer units (NOG) (Assume 98%
removal efficiency)

NOG - In [(Hal concentration/(0.02 * Hal concentration)) *
        (1-U/AF)) + (1/AF)]/(1-(1/AF))]

    = In [(15,660/(0.02 * 15,660))* (1-1/19.16) +
NOG = 4.07

Calculate the height of the overall gas transfer unit (HOG)
using:

HOG = Hg + (1/AF) HL

where

     HQ = Height of a single gas transfer unit (ft)
     H|_ = Height of a liquid transfer unit (ft)

Based on generalized correlations:

HQ = [b * (3,600 * G_Area)Ac/(LLAd)](SCG)A°-5

H|_ = Y * (LL/liquid viscosity)AS * (SCL)A°-5 assuming 2-in.
     ceramic raschig rings for packing

b = 3.82

c = 0.41

d = 0.45
                         C-ll
-------
s = 0.22

Y = 0.0125

-*    To convert  from centipoise to Ib/hr * ft2

Liquid viscosity = 0.85 * 2.42

               9 = 11.13

               r = 0.00295

Therefore,

HG = [3.82 *  (3,600 * 0.34)A0-41/U,491A0-45)] * SCGA0-5

   = 2.63 x 0.809A°-5 = 2.37

HL = (0.0125) *  (1,491/2.05)A0-22 * SCLA°-5

   = 0.051 *  381A°-5 = 1.0

Solving for HOG:

HOG = HG + (1/AF) * HL
    = 2.37 +  (1/19.16) * 1.0
    = 2.42

Calculate the height of the packed column from HOG  and NOG.
Allow for 2 ft of freeboard above and below the packing for gas
disentanglement, and additional height based on column.

Height (Ht) = (NOG)(HOG) + 2 + 0.25 * Diam. Col
            = (4.07)(2.42) + 2 + 0.25 * 0.5
            = 12 ft

Calculate Volume of Packing

Volume = (/7/4) * (D)2 * (NOG * HOG)
       = (/7/4) * (.5)2 * (4.07 * 2.42)
       = 1.93 ft3

Calculate Volume of Column

Volume = (77/4)(Diam col)2 x Ht
       = (0.785)(0.5)A2 x 12
       = 2.36 ft3

Calculate Pressure Drop

DelPa = (g x  10'8) * [10A(r * LL/liquid density)] *
        [(3,600 * G_Area)A2]/gas density
                         C-12
-------
     •    DelPa - (11.13 x 10-8) * (10^(0.00295 * 1,491/62.2)) *
                  ((3600 * 0.34)A2)/o.Q739
          Del Pa - 2.66
          Del Ptot « Del Pa * (NOG + HOG)/5.2
                   - 2.66 * (4.07 * 2.42J/5.2
                   - 5.09
C.5  COST ANALYSIS-ESTIMATING SCRUBBER TOTAL CAPITAL INVESTMENT
     •    Total Cost of Tower 1s:
          wt - (48 * Diam * ht) + 39 * D1am2
             - (48 * 0.5 * 12) + 39 * (0.5)2
          wt - 297.8 Ibs
          TCost - [1.900604 * (wt/1,000)A0.93839] * 1,000 * (355.6/298.2)
          TCost « [1.900604 * (297.8/1,000)A0.93839] * 1,000 *
                  (355.6/298.2)
                - 727
     •    Cost of Packing
          Packcost - Volume of packing * 20
                   - 1.93 * 20
                   - 38.6
     •    Assume Cost of Duct Work and Fan
          Duct cost - 3,907.5
          Fan cost  - 488.9
     •    Calculate Platform Cost.  For columns less than 3 ft in diameter
          design diam (DO) « 3.
          Platform Cost - 10A(0.78884 * In (diam) + 3.325) * (355.6/298.2)
                        - 10A(0.7884 * In (0.5) + 3.325) * (355.6/298.2)
                        * 715.6
     •    Assume Stackcost - 5,000
     •    Calculate Total Capital Investment (TCI)
          TCI - (towercost + packcost + ductcost + fancost +
                platform cost + stackcost) * 1.18 * 2.2
                                   C-13
-------
          TCI - (727 + 38.6 + 3,907 + 488.9 + 715.6  + 5,000)  *
                1.18 * 2.2
              = $28,237
C.6  CALCULATING ANNUAL COSTS FOR SCRUBBERS
     •    Calculate Water Costs
          Water - (liquid flow lb/hr)/8.34 Ib/gal  *  price per 1,000 gal  *
                    8,760 hr/yr
          Water - (283.4)/(8.34)  * 0.22/1,000 * 8,760
          Water - 65.49
     •    Calculate Electrical Costs Based on Pressure Drop
          Elec - 0.0002 * new flow * DelPtot * 8,760 * elec_cost  $/KW-Hr
               - 0.0002 * 53 * 5.09 * 8,760 * 0.061
               = 29 $/yr
     •    Calculate Cost of Labor, Supervision,  Maintenance
          Op labor - (1/2 hour per 8 hour shift )  *
                       (Annual operating hours)  *  (Op labor rate)
          Op labor - 0.5/8 * 8,760 * 15.64
          Op labor = 8,563 $/yr
          Supervision = 0.15 * Op_Labor
          Supervision - 0.15 * 8,563 = 1,284.44
          Maintenance labor = 0.5/8 * 8,760 * 17.21
          Maintenance labor = 9,422.48 $/yr
          Maintenance materials - 9,428.48 $/yr
     •    Calculate Direct Operating Costs
          Dir Op Cost » Water + electric + opjlabor  + supervision  +
                          main labor + maintenance materials
          Dir Op Cost = 65.49 + 29 + 8,563 + 1,284.44 +
                        9,422.5 + 9,422.5
          Dir Op Cost * 28,786 $/yr

                                   C-14
-------
     •    Calculate cost of overhead,  tax,  insurance,  administrative,  and
          capital  recovery costs

                     Tax = 0.01 * TCI  * 282.4

               Insurance - 0.01 * TCI  - 282.4

          Administrative - 0.02 * TCI  « 564.7

                     CRC - 0.16275 * TCI -  4,596

                Overhead - 0.6 * (op_labor  + supervision +
                           main_La + maint)

                Overhead - 17,215

     •    Calculate indirect operating costs

          Ind Op Cost = Overhead + Tax + Insurance + Administrative + CRC
                      = 17,215.44 + 282.4 + 282.4 + 564.7 + 4,596
                      = 22,940

     •    Annual Operating Cost, Anncost

          Anncost = 28,786 + 22,940

          Anncost = 51,726 $/yr

C.7  SIZING CALCULATIONS FOR FLARES

     Hand Calculations for the VENTCOST Program - Flare Procedure

     •    Used to assess control equipment  cost for the SOCMI CTG

     •    Calculations based on OAQPS Control Cost Manual, Chapter 7.

     •    The stream costed in this example is model stream D-HFLH.  Its
          characteristics are the following:
          VOC to be controlled
          MW
          Flow rate (total)
          VOC flow rate
          Heat value
          Oxygen content
Isophthalic acid
166 Ib/lb mole
632.401 scfm
6.15 Ib/hr
19 Btu/scf
0%
     A.   Flare tip diameter is generally sized on a velocity basis.
          Flare tip sizing is governed by EPA rules defined in the
          Federal Register.  For flares with a heat value less than
          300 Btu/scf the maximum velocity is 60 ft/sec.

          1.   The net heating value of vent stream * 19 Btu/scf


                                   C-15
-------
2.   Thus maximum velocity (Vmax), = 60 ft/sec.  (It is standard
     practice to size flares at 80 percent of
3.   Calculate the heat released by combustion of the vent
     stream
     Heatrel (Btu/hr) - Vent Flow * heat value * 60 min/hr
                      - 632,401 scfm * 19 Btu/scf * 60
                      - 720,937 Btu/hr
4.   Flare height (ft) is determined using Equation 7-3 in OAQPS
     SOCMI flares chapter.
     Height - (TFOyr/j-k)0-5
     where
          T = Fraction of heat intensity transmitted
          F = Fraction of heat radiated
          Q = Heat release (Btu/hr) - 720,937 Btu/hr
          k = allowable radiation, (500 Btu/hr-ft2)
     Assuming (a) no wind effects, (b) center of radiation at
     the base of the flare, and (c) thermal radiation limited at
     base of the flare.
          T * 1
          F = 0.2
          k - 500
     Substituting and simplifying,
     Height = ((heatrel)°-5)-/177.24
     (Note that this assumes allowable radiation =
     500 Btu/hr- ft?)
     Height - 4.79 ft
     The minimum flare height is 30 ft.  Therefore,
     Height - 30 ft
                         C-16
-------
          Calculate the auxiliary fuel flow required to sustain a
          stable flame.  A minimum heat value of 300 Btu/scf is
          required by 40 CFR, Section 60.18.  Therefore, the
          auxiliary fuel flow, Qaf (scfm) is:

               Qaf - Vent flow * (300 - heat value)/(1000-300)
                   - 632 * (300-19)/(1000-300)
                   - 253.70 scfm

          Calculate total stream flow, Qjot (scfm):
               Qtot " Vent flow + Qaf
                    - 632 + 253.7
                    - 886 scfm

     7.   Calculate minimum flare tip diameter, D, (in.) by

               D = 12[4/ir * (Qtot/60)/0 8 VMAX]°-5
                 = 12[4//7 * (886/60)]°-5
                 = 12(0.392)0.5
                 - 7.51 in.

          Since the calculated diameter is rounded up to the next
          commercially available size, available in 2-in. increments,
          the diameter would be D » 8 in.

B.   Purge Gas Requirement - Purge gas is used to maintain a minimum
     required constant flow through the system.  Using the
     conservative value of 0.04 ft/sec (gas velocity) and knowing the
     flare diameter, the annual P volume can be calculated.

     1.   P(scfm/yr) - (0.04) * ((/7)/4) * (D2)/144 * 60
                     = 0.006 scfm

C.   Pilot Gas Requirement

     1.   Since the number of pilot burners (n) is based on flare
          size (flare diameter 1 to 10 in. - 1 pilot burner) this
          stream would require 1 burner (our flare tip is 8 in.)

     2.   Pilot gas flow (fp)

          Fp - (70 scf/hr) * N * (hr/60 min)
             - 1.167 scfm

D.   Steam Requirement

     The steam requirement depends on the composition of the vent gas
     being flared, the steam velocity from the injection nozzle, and
     the flare tip diameter.
                              C-17
-------
1.   The steam requirement can be calculated based on steam -
     C02 weight ratio of 0.68 (see Equation 7-7, OCCM flares
     chapter).
     Wsteam = flow * (0.075 * 60) * 0.4
            = 632 * (0.075 * 60) * 0.4
            = 1,137 Ib/hr
Knockout Drum
The dropout velocity, U, of a particle in a stream, or the
maximum design vapor velocity, is calculated by:
1.   U = K x  ((P1 - Pv)/pv)0-5 ft/sec
     where
           k = design vapor velocity factor =  .2 assumed as
               representative of the k range of 0.15 to 0.25
          P-| = 37 = liquid density, assumed
          Pv = 0.1125 vapor density, assumed
     U = 3.62
The maximum vessel cross-sectional area, A, can be calculated
by:
A = Q (ft3/min)/(60 x U (ft/sec), ft?
Q = 632 scfm
A = 632/(60 x 3.62)
A = 2.91
Calculate vessel  diameter
1.   The vessel  diameter, dm-jn, is calculated  by:
     dmin - 12 (in/ft)  x (4 x A (ft2)/,7)0.5, in.
     dmin = 12 x (4 x 2.91//r)0.5
     dmin = 23.1  in.
2.   In accordance with standard head sizes, drum diameters in
     6-in.  increments are assumed so:
     d = dm-jn to the next largest 6 in.
     d = 24 in.
                         C-18
-------
          3.   The vessel height, h, is determined by:
               h = 3 x d, in.
               h = 3 x 24 = 72 in.
C.8  COST ANALYSIS - ESTIMATING TOTAL CAPITAL INVESTMENT FOR FLARES
     (*Assuming March 1990 Dollars)
     A.   Flare costs (Cf) are calculated as a function of stack height,
          H (ft) and tip diameter, D, (in), and are based on support type.
          Derrick support group was not considered since the stack height
          is < 100 ft.
          1.   Self Support Group
               Cf = [78 + 9.14 (D) + .75 (H)]2
               Cf = [78 + 9.14 (8) + .75 (30)]2
               Cf = 30,144
          2.   Guy Support Group:
               Cf = [103.17 + 8.68(8) + .47 (30)]2
               Cf = 34,861
               Since Self Support  is < Guy Support, the cheaper is chosen.
     B.   Cost for 100 ft of transfer and header pipe, Cp, assuming
          400 length needed.
          Cp = (127.4 x D-) x 4
          Cp = (127.4 x Si-*2*) x 4
          Cp = 5,243
     C.   Cost for knockout drum, C^, is a function of drum diameter,
          d (ft) and height (ft)
          Cfc = 14.2 x [d x t x  (h + 0.0812 x d)]0-737
          where
               t = vessel thickness (in.)
                                   C-19
-------
      vessel  thickness  is determined based on drum diameter.  Since
          Drum diameter, d  -  24  in. - 2.0  ft and
             Drum  height, h  -  90  1n. - 7.5  ft,
          Drum thickness, t •  0.25 in.
      C|< - 14.2 x  [24 x 0.25 x  (90 + 0.0812  x 24)]°-737
      Ck - 1,484
D.    Collection Fan Cost
          Cfan •  (96.96418 x 632 scfm°- 547 1969) x 355.6/342.5
               -  3,431
      Collection Fan Cost based on 1988 Richardson Manual; see Chris
      Bagley's March 9, 1990, calculation placed in the polystyrene
      file.
E.    Flare system equipment cost, EC, is the total of the calculated
      flare,  knockout drum, manifold piping, and collection fan cost.
          EC - [Cf + Ck + Cp) * 355.6/354.6] + Cfan
          Ec - [30,144 + 1,484 + 5,243) * 355.6/354.6] + 3,431
          EC - 41,712
F.   Purchased equipment cost, PEC, is equal to equipment cost, EC,
     plus factors for instrumentation (.10), sales taxes (0.03), and
     freight (0.05) or
          PEC - EC x (1 + 0.10 + 0.03 + 0.05)
          PEC - 1.18 x 41,712
          PEC - 49,220
6.   Installation Costs:  The total capital investment, TCI, is
     obtained by multiplying the purchased equipment costs, PEC, by
     an installation factor of 1.92
          TCI - 1.92 x PEC
          TCI - 1.92 x 48,916
          TCI - 94,502
                              C-20
-------
C.9  CALCULATING ANNUAL COST FOR FLARES
     A.   Direct Annual Cost
          1.   Total natural gas cost}  Cf,  to operate a flare system
               includes pilot,  Cp,  auxiliary fuel,  Ca,  and purge cost Cpu:
                    Cf - Cp + Ca + Cpu
               where Cp is equal to the annual volume of pilot gas,  fp,
               multiplied by the cost per scf
                    Cn ($/yr) - Flow *  60 * 8,760
                              - fp (scf/yr) x ($/scf)
                    Assume price of natural gas - 3.30 $/Mscf
                           Cp = 1.167 scfm * 60 * 8,760 x (3.30 $/Mscf)
                           Cp - $2,024/yr
          2.   Annual Purge gas cost CDU -  247.68 x D^ (Mscf/yr) *
               (3.3 $/Mscf)
                      Annual Cpu « $817.3/yr
          3.   Auxiliary Gas Cost Ca
                    133,350 Mscf/yr x 3.3 $/Mscf -  $440,055/yr
          4.   Cf = 2,024 + 817.3 + 440,055 - $442,896/yr
     B.   Calculate Steam Cost  (Cs) required to eliminate smoking
               Cs  ($/yr) - 8,760 (hr/yr) x steam use (Ib/hr) x ($/lb)
               Cs = 8,760 x 1,137 x 4.65 x  10"3
               Cs - $46,315
     C.   Calculate operating labor cost, based on  630 manhours/yr
          Operator labor - 0.5/8 * 8,760 *  $15.64 « 8,562
          Supervisor labor 8,572 x .15   -  1.286
          Total  labor -                    9,848
     D.   Maintenance labor cost and materials
          Maintenance labor ($/yr)  - (1/2 hr/8 hrs  shift) x 8,760 hr/yr  x
                                     $17.21/hr - $9,422/yr
          Materials assumed equal to maintenance labor - $9,422/yr

                                   C-21
-------
E.   Overhead Cost

     = 0.60 x (op labor + supervisor + labor + materials)
     = 0.60 x (8,572 + 1,286 + 9,422 + 9,422)
     = 17,221

F.   Capital Recovery Factor:  Assume 15 year life and 10% interest
                               so CRF = 0.1314

     Capital recovery cost = 0.1314 x TCI
                           = 0.1314 x 94,502
                           = $12,418

G.   General and Administrative, Taxes, and Insurance Costs

     Assume 4% of total capital investment

     4% of 94,502

     = 3,780

H.   Utilities — Power consumption based on actual minimum flow

     Pressure drop = [1.238 * 10'6 * flow - (1.15 * 10'4)] *
                     length of pipe
                   = [1.238 * It)'5 * 632 - 1.15 * 10'4] * 400
                   = 0.27 in. H20

     Power = (1.17 * 1(H * flow * pressure drop)/0.6
           = [1.17 * 10'4 * 632 * 0.27)/0.6
           = 0.03 kW

I.  Elec cost = Power x op hours x elec price ($/1000 kW-hrs)
              = (0.03)(8,760)(0.061)
              = 16.03

J.   Calculating total  Annual Costs (Indirect and Direct)

     1.   Direct Annual Cost

          Direct Cost = Cost electricity + materials +
                        maintenance labor + supervisors +
                        operation labor + steam cost + fuel cost

          Direct cost = 16.03 + 9,422 + 9,422 + 1,286 + 8,562 +
                        46,315 + 443,162

                      = 518,383
                              C-22
-------
     2.   Indirect Annual Cost
          IAC = general + capital recovery cost + overhead
          IAC = 3,757 + 12,341 + 17,221
          IAC = 33,320
K.   Annual Cost = Direct cost + Indirect Cost
                 = 518,383 + 33,320
                 = 551,702
                               C-23
-------
                   APPENDIX D

SYNTHETIC ORGANIC CHEMICAL MANUFACTURING INDUSTRY
    CONTROL TECHNIQUES GUIDELINE EXAMPLE RULE
-------
                                                            EXAMPLE ONLY
                                APPENDIX D
             SYNTHETIC  ORGANIC  CHEMICAL  MANUFACTURING  INDUSTRY
                 CONTROL  TECHNIQUES  GUIDELINE  EXAMPLE  RULE
D.I  INTRODUCTION
     This appendix presents an example rule limiting volatile organic
compound (VOC) emissions from reactor processes and distillation
operations.  The example rule is for informational purposes only and, as
such, is not legally binding.  The purpose of the example rule is to
provide a model containing information on the sections and typical issues
that need to be considered in writing a rule to ensure clarity and
enforceability of the standards.
     Two points concerning implementation of the recommended reasonably
available control technology (RACT) in Chapter 6.0 warrant consideration
in drafting a regulation.  First, Chapter 6.0 recommended that any reactor
process or distillation vent stream for which an existing combustion
device is employed to control VOC emissions should not be required to meet
the 98 percent destruction or 20 parts per million by volume emissions
limit until the combustion device is replaced for other reasons.  Second,
Chapter 6.0 recommended that the total resource effectiveness index limit
be applied on an individual process vent stream basis for a given process
unit.
     An additional point warranting consideration when drafting a
regulation pertains to the reporting requirements.  Section 7.8 stated
that reporting frequency is left to the discretion of State air quality
management agencies; however, this model rule provides example
                                    D-l
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                                                            EXAMPLE ONLY
requirements to make the example rule more complete.  These requirements
may also be revised by the State agencies.
     The remainder of this appendix constitutes the example rule.
Sections are provided on the following rule elements:  applicability,
definitions, control requirements, performance testing, monitoring
requirements, and reporting/recordkeeping requirements.
D.2  APPLICABILITY
     (a)  The provisions of this rule apply to any vent stream originating
from a process unit in which a reactor process or distillation operation
is located.  A decision tree is provided (Figure D.I) to facilitate
determination of applicability to this guideline on a per vent basis.
     (b)  Exemptions from the provisions of this guideline are as follows:
     (1)  Any reactor process or distillation operation that is designed
and operated in a batch mode is not subject to the provisions of this
rule.
     (2)  Any reactor process or distillation operation that is part of a
polymer manufacturing operation is not subject to the provisions of this
guideline.
     (3)  Any reactor process or distillation operation operating in a
process unit with a total design capacity of less than 1 gigagram per year
for all chemicals produced within that unit is not subject to the
provisions of this guideline except for the reporting and recordkeeping
requirements listed in D.7(e).
     (4)  Any vent stream for a reactor process or distillation operation
with a flow rate less than 0.0085 standard cubic meter per minute or a
total VOC concentration less than 500 parts per million by volume is not
subject to the provisions of this guideline except for the performance
testing requirement listed in D.5(c)(2), D.5(i) and the reporting and
recordkeeping requirements listed in D.7(d).
                                    D-2
-------
                                                               EXAMPLE ONLY
                                                    NA
      SOCMI
   VOC Sources?
(Produces One or More
    Chemicals in
     Appendix
       A)
                         Is the
                     Vent Controlled
                     Via Combustion
                        Does the
                   Process Unit Produce
                      Over 1 Gg/yr
                        Vent Flow
                   Over 0.0085 scmm ?
                       Vent Total
                    VOC Concentration
                     Over 500 ppmv?
i nc s i t "' — ~ 	 —

Y
i • I. i .
98% Reduction [20 ppm Flares
1 i i i •
i


Monitoring
* <
Repc



Figure  D.I.  Synthetic  organic chemical manufacturing industry
              reactor/distillation  control  techniques guideline
              logic diagram per vent.
                                 D-3
-------
                                                            EXAMPLE ONLY
D.3  DEFINITIONS
     Batch mode means a noncontinuous operation or process in which a
discrete quantity or batch of feed is charged into a process unit and
distilled or reacted at one time.
     Boiler means any enclosed combustion device that extracts useful
energy  in the form of steam.
     By compound means by individual stream components, not carbon
equivalents.
     Continuous recorder means a data recording device recording an
instantaneous data value at least once every 15 minutes.
     Distillation operation means an operation separating one or more feed
stream(s) into two or more exit stream(s), each exit stream having
component concentrations different from those in the feed stream(s).  The
separation is achieved by the redistribution of the components between the
liquid  and vapor-phase as they approach equilibrium within the
distillation unit.
     Distillation unit means a device or vessel in which distillation
operations occur, including all associated internals (such as trays or
packing) and accessories (such as reboiler, condenser, vacuum pump, stream
jet, etc.), plus any associated recovery system.
     Flame zone means the portion of the combustion chamber in a boiler
occupied by the flame envelope.
     Flow indicator means a device that indicates whether gas flow is
present in a vent stream.
     Haloqenated vent stream means any vent stream determined to have a
total concentration of halogen atoms (by volume) contained in organic
compounds of 200 parts per million by volume or greater determined by
Method  18 of 40 CFR 60, Appendix A, or other test or data validated by
Method 301 of 40 CFR 63, Appendix A, or by engineering assessment or
process knowledge that no halogenated organic compounds are present.  For
example, 150 parts per million by volume of ethylene dichloride would
contain 300 parts per million by volume of total halogen atoms.
     Incinerator means any enclosed combustion device that is used for
destroying organic compounds.  Auxiliary fuel may be used to heat waste

                                    D-4
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                                                            EXAMPLE ONLY
gas to combustion temperatures.  Any energy recovery section present is
not physically formed into one section; rather, the energy recovery system
is a separate section following the combustion section and the two are
joined by ducting or connections that carry fuel gas.
     Primary fuel means the fuel that provides the principal heat input to
the device.  To be considered primary, the fuel must be able to sustain
operation without the addition of other fuels.
     Process heater means a device that transfers heat liberated by
burning fuel to fluids contained in tubes, including all fluids except
water that is heated to produce steam.
     Process unit means equipment assembled and connected by pipes or
ducts to produce, as intermediates or final products, one or more SOCHI
chemicals (see Appendix A of this document).  A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient product storage facilities.
     Product means any compound or SOCMI chemical (see Appendix A of this
document) that is produced as that chemical for sale as a product,
by-product, co-product, or intermediate or for use in the production of
other chemicals or compounds.
     Reactor processes mean unit operations in which one or more
chemicals, or reactants other than air, are combined or decomposed in such
a way that their molecular structures are altered and one or more new
organic compounds are formed.
     Recovery device means an individual unit of equipment, such as an
adsorber, carbon adsorber, or condenser, capable of and used for the
purpose of recovering chemicals for use, reuse, or sale.
     Recovery system means an individual recovery device or series of such
devices applied to the same vent stream.
     Total organic compounds or "TOC" means those compounds measured
according to the procedures of Method 18 of 40 CFR 60, Appendix A.  For
the purposes of measuring molar composition as required in D.5(c)(4);
hourly emissions rate as required in D.5(e)(4) and D.4(b); and TOC
concentration as required in D.7(a)(4) and D.7(b).  The definition of TOC
excludes those compounds that the Administrator designates as having

                                    D-5
-------
                                                            EXAMPLE ONLY
negligible photochemical reactivity.  The Administrator has designated the
following organic compounds as negligibly reactive:  methane; ethane;
1,1,1-trichloroethane; methylene chloride, trichlorofluoromethane;
dichlorodif1uoromethane; chlorodif1uoromethane; tri f1uoromethane;
trichlorotrifluoroethane; dichlorotetrafluoroethane; and
chloropentaf1uoroethane.
     Total resource effectiveness index value or "TRE index value" means a
measure of the supplemental total resource requirement per unit reduction
of organic hazardous air pollutants associated with a process vent stream,
based on vent stream flow rate, emission rate of volatile organic
compound, net heating value, and corrosion properties (whether or not the
vent stream contains halogenated compounds) as quantified by the given
equations.  The TRE index is a decision tool used to determined if the
annual cost of controlling a given vent gas stream is acceptable when
considering the emissions reduction achieved.
     Vent stream means any gas stream discharge directly from a
distillation operation or reactor process to the atmosphere or indirectly
to the atmosphere after diversion through other process equipment.  The
vent stream excludes relief valve discharges and equipment leaks
including, but not limited to, pumps, compressors, and valves.
D.4  CONTROL REQUIREMENTS
     (a)  For individual vent streams within a process unit with a TRE
index value less than or equal to 1.0, the owner or operator shall comply
with paragraphs (1) or (2) of this section.
     (1)  Reduce emission of TOC (less methane and ethane) by
98 weight-percent, or to 20 parts per million by volume, on a dry basis
corrected to 3 percent oxygen, whichever is less stringent.  If a boiler
or process heater is used to comply with this paragraph, then the vent
stream shall be introduced into the flame zone of the boiler or process
heater.
     (2)  Combust emissions in a flare.  Flares used to comply with this
paragraph shall  comply with the requirements of 40 CFR 60.18.  The flare
operation requirement does not apply if a process, not subject to this
CTG,  vents an emergency relief discharge into a common flare header and

                                    D-6
-------
                                                            EXAMPLE ONLY
causes the flare servicing the process subject to this CTG to be out of
compliance with one or more of the provisions of the flare operation rule.
     (b)  For each individual vent streams within a process unit with a
TRE index value greater than 1.0, the owner or operator shall maintain
vent stream parameters that result in a calculated total  resource
effectiveness greater than 1.0 without the use of a volatile organic
compound control device.  The TRE index shall be calculated at the outlet
of the final recovery device.
D.5  TOTAL RESOURCE EFFECTIVENESS DETERMINATION, PERFORMANCE TESTING, AND
     EXEMPTION TESTING
     (a)  For the purpose of demonstrating compliance with the TRE index
value in D.4(b), engineering assessment may be used to determine process
vent stream flow rate, net heating value, and TOC emission rate for the
representative operating condition expected to yield the lowest TRE index
value.
     (1)  If the TRE value calculated using such engineering assessment
and the TRE equation in paragraph D.5(f)(l) is greater than 4.0, then it
is not recommended that the owner or operator perform the measures
specified in Section D.5(e).
     (2)  If the TRE value calculated using such engineering assessment
and the TRE equation in paragraph D.5(f)(l) is less than or equal to 4.0,
then it is recommended that the owner or operator perform the measurements
specified in Section D.5(e).
     (3)  Engineering assessment includes, but is not limited to, the
following:
     (i)  Previous test results proved the test are representative of
current operating practices at the process unit.
     (ii)  Bench-scale or pilot-scale test data representative of the
process under representative operating conditions.
     (iii)  Maximum flow rate specified or implied within a permit limit
applicable to the process vent.
     (iv)  Design analysis based on accepted chemical engineering
principles, measurable process parameters, or physical or chemical laws or
                                    D-7
-------
                                                            EXAMPLE ONLY
properties.  Examples for analytical methods include, but are not limited
to:
     (A)  Use of material balances based on process stoichiometry to
estimate maximum VOC concentrations.
     (B)  Estimation of maximum flow rate based on physical equipment
design such as pump or blower capacities.
     (C)  Estimation of TOC concentrations based on saturation conditions.
     (D)  Estimation of maximum expected net heating value based on the
stream concentration of each organic compound, or, alternatively, as if
all TOC in the stream were the compound with the highest heating value.
     (v)  All data, assumptions, and procedures used in the engineering
assessment shall be documented.
     (b)  For the purpose of demonstrating compliance with the control
requirements of this rule, the process unit shall be run at representative
operating conditions and flow rates during any performance test.
     (c)  The following methods in 40 CFR 60, Appendix A, shall be used to
demonstrate compliance with the emission limit or percent reduction
efficiency requirement listed in D.4(a)(l).
     (1)  Method 1 or 1A, as appropriate, for selection of the sampling
sites.   The control device inlet sampling site for determination of vent
stream molar composition or TOC (less methane and ethane) reduction
efficiency shall be located after the last recovery device but prior to
the inlet of the control device, prior to any dilution of the process vent
stream, and prior to release to the atmosphere.
     (2)  Method 2, 2A, 2C, or 2D, as appropriate, for determination of
gas stream volumetric flow rate.
     (3)  The emission rate correction factor, integrated sampling, and
analysis procedure of Method 3 shall be used to determine the oxygen
concentration (% 0£d) for the purpose of determining compliance with the
20 parts per million by volume limit.  The sampling site shall be the same
as that of the TOC samples, and samples shall be taken during the same
                                    D-8
-------
                                                            EXAMPLE ONLY
time that the TOC samples are taken.  The TOC concentration corrected to
3 percent oxygen (Cc) shall be computed using the following equation:
                                      20.9« 02d
where:
     cc    - Concentration of TOC (minus methane and ethane) corrected to
             3 percent Q£, dry basis, parts per million by volume.
     CjOC  " Concentration of TOC (minus methane and ethane), dry basis,
             parts per million by volume.
             Concentration of oxygen, dry basis, percent by volume.
     (4)  Method 18 to determine the concentration of TOC (less methane
and ethane) at the outlet of the control device when determining
compliance with the 20 parts per million by volume limit, or at both the
control device inlet and outlet when the reduction efficiency of the
control device is to be determined.
     (i)  The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or four grab samples shall be taken.   If grab
sampling is used then the samples shall be taken at 15-minute intervals.
     (ii)  The emission reduction (R) of TOC (less methane and ethane)
shall be determined using the following equation:

                              R - Ei ' E° x 100
                                     El
where:
      R - Emission reduction, percent by weight.
     Ei = Mass rate of TOC (minus methane and ethane) entering the control
          device, kilogram TOC per hour.
     E0 = Mass rate of TOC (minus methane and ethane) discharged to the
          atmosphere, kilogram TOC per hour.
                                    D-9
-------
                                                            EXAMPLE ONLY

      (iii)  The mass rates of TOC  (E-j, E0) shall be computed using the

following equations:


                           Ei - K2  ( ZCijMij) Qi
                                    J ™ •*•


                           E0 • K2  ( I CojM0j) Qo
                                    j-l

where:

      Cij> CQJ = Concentration of sample component "j" of the gas stream at
                the inlet and outlet of the control device, respectively,
                dry basis, parts per million by volume.

      Mij> MOJ * Molecular weight of sample component "j" of the gas stream
                at the  inlet and outlet of the control device,
                respectively, grams per gram-mole.

       Qi, Q0 - flow rate of gas stream at the inlet and outlet of the
                control device, respectively, dry standard cubic meters
                per minute.

           «2 = 2.494 x 10'6 (liters per minute) (gram-mole per standard
                cubic meter) (kilogram per gram)(minute per hour), where
                standard temperature for (gram-mole per standard cubic
                meter)  is 20 °C.

      (iv)  The TOC concentration (Cjoc) ^s tne sum °f tne individual
components and shall be computed for each run using the following

equation:
                            CTOC -  *
                                   J-i
where:
     CTQC = Concentration of TOC (minus methane and ethane), dry basis,
            parts by million by volume.

       Cj - Concentration of sample component "j", dry basis, parts per
            million by volume.

        n - Number of components in the sample.
                                   D-10
-------
                                                            EXAMPLE ONLY
     (5)  When a boiler or process heater with a design heat input
capacity of 44 megawatts or greater, or a boiler or process heater into
which the process vent stream is introduced with the primary fuel,  is
used to comply with the control requirements, an initial performance test
is not required.
     (d)  When a flare is used to comply with the control requirements of
this rule, the flare shall comply with the requirements of 40 CFR 60.18.
     (e)  The following test methods shall be used to determine compliance
with the TRE index value.
     (1)  Method 1 or 1A, as appropriate, for selection of the sampling
site.
     (i)  The sampling site for the vent stream molar composition
determination and flow rate prescribed in D.5(e)(2) and (e)(3) shall be,
except for the situations outlined in paragraph (e)(l)(ii) of this
section, after the final recovery device, if a recovery system is present,
prior to the inlet of any control device, and prior to any post-reactor or
post-distillation unit introduction of halogenated compounds into the
process vent stream.  No traverse site selection method is needed for
vents smaller than 10 centimeters in diameter.
     (ii)  If any gas stream other than the reactor or distillation vent
stream is normally conducted through the final recovery device:
     (A)  The sampling site for vent stream flow rate and molar
composition shall be prior to the final recovery device and prior to the
point at which any nonreactor or nondistillation stream or stream from a
nonaffected reactor or distillation unit is introduced.  Method 18 shall
be used to measure organic compound concentrations at this site.
     (B)  The efficiency of the final recovery device is determined by
measuring the organic compound concentrations using Method 18 at the inlet
to the final recovery device after the introduction of all vent streams
and at the outlet of the final recovery device.
     (C)  The efficiency of the final recovery device determined according
to D.5(e)(l)(ii)(B) shall be applied to the organic compound
concentrations measured according to D.5(e)(l)(11)(A) to determine the
concentrations of organic compounds from the final recovery device

                                   D-ll
-------
                                                            EXAMPLE ONLY
attributable to the reactor or distillation vent stream.  The resulting
organic compound concentrations are then used to perform the calculations
outlined in D.5(e)(4).
      (2)  The molar composition of the vent stream shall be determined as
follows:
      (i)  Method 18 to measure the concentration of organic compounds
including those containing halogens.
      (ii)  ASTM D1946-77 to measure the concentration of carbon monoxide
and hydrogen.
      (iii)  Method 4 to measure the content of water vapor.
      (3)  The volumetric flow rate shall be determined using Method 2, 2A,
2C, or 2D, as appropriate.
      (4)  The emission rate of TOC (minus methane and ethane) (Ejoc) in
the vent stream shall be calculated using the following equation:

                          ETOC - K2   Z   CjMj   Qs
                                     J~ 1
where:
      Ejoc = Emission rate of TOC (minus methane and ethane)
            in the sample, kilograms per hour.
       K2 = Constant, 2.494 x 10'6 (liters per parts per
            mill ion)(gram-moles per standard cubic meter)(kilogram per
            gram)(minute per hour), where standard temperature for
            (gram-mole per standard cubic meter)(g-mole/scm) is 20 °C.
       Cj = Concentration of compound j, on a dry basis, in parts per
            million as measured by Method 18, as indicated in D.5(c)(3).
       MJ - Molecular weight of sample j, grams per gram-mole.
       Qs = Vent stream flow rate (standard cubic meters per minute) at a
            temperature of 20 °C.
      (5)  The total process vent stream concentration (by volume) of
compounds containing halogens (parts per million by volume, by compound)
shall  be summed from the individual concentrations of compounds containing
halogens which were measured by Method 18.
                                   D-12
-------
                                                            EXAMPLE ONLY

     (6)  The net heating value of the vent stream shall be calculated
using the equation:


                       HT - KI £ Cj Hj  {1 . BWS)


where:

      Hf « Net heating value of the sample (megajoule per standard cubic
           meter), where the net enthaply per mole of vent stream is based
           on combustion at 25 °C and 760 millimeters of mercury, but the
           standard temperature for determining the volume corresponding
           to one mole is 20 °C, as in the definition of Qs (vent stream
           flow rate).

      KI * Constant, 1.740 x 10"7 (parts per million)'1 (gram-mole per
           standard cubic meter), (megajoule per kilocalorie), where
           standard temperature for (gram-mole per standard cubic meter)
           is 20 °C.

     Bws * Water vapor content of the vent stream, proportion by volume;
           except that if the vent stream passes through a final stream
           jet and is not condensed, it shall be assumed that Bws * 0.023
           in order to correct to 2.3 percent moisture.

      Cj = Concentration on a dry basis of compound j in parts per
           million, as measured for all organic compounds by
           Method 18 and measured for hydrogen and carbon monoxide by
           the American Society for Testing and Materials D1946-77.

      HJ = Net heat of combustion of compound j, kilocalorie per
           gram-mole, based on combustion at 25 °C and 760 millimeters of
           mercury.  The heats of combustion of vent stream components
           shall be determined using American Society for Testing and
           Materials D2382-76 if published values are not available or
           cannot be calculated.

     (f)(l)  The total resource effectiveness index value of the vent

shall be calculated using the following equation:

              TRE - _1_ [a + b (Qs) + c (HT) + d (ETOc)]
                    ETOC

where:

         TRE - TRE index value.

        ETQC = Hourly emission rate of TOC (kilograms per hour) as
               calculated in D.5(e)(4).

                                   D-13
-------
                                                            EXAMPLE ONLY
          Qs = Vent stream flow rate standard cubic meters per minute at a
               standard temperature of 20 °C.
          Hj - Vent stream net heating value (megajoules per standard
               cubic meter), as calculated in D.5(e)(6).
        EJOC = Hourly emission rate of TOC (minus methane and ethane),
               (kilograms per hour) as calculated in paragraph D.5(e)(4).
     a,b,c,d = Coefficients presented in Table D-l.
     (2)  The owner or operator of a vent stream shall use the applicable
coefficients in Table D-l to calculate the TRE index value based on a
flare, a thermal incinerator with 0 percent heat recovery, and a thermal
incinerator with 70 percent heat recovery, and shall select the lowest TRE
index value.
     (3)  The owner or operator of a unit with a halogenated vent stream,
determined as any stream with a total concentration of halogen atoms
contained in organic compounds of 200 parts per million by volume or
greater, shall use the applicable coefficients in Table D-l to calculate
the total resource effectiveness index value based on a thermal
incinerator and scrubber.
     (g)  Each owner or operator of an affected facility seeking to comply
with D.4(b) shall recalculate the flow rate and TOC concentration for that
affected facility whenever process changes are made.  Examples of process
changes include changes in production capacity, feedstock type, or
catalyst type, or whenever there is replacement, removal, or addition of
recovery equipment.  The flow rate and VOC concentration shall be
recalculated based on test data, or on best engineering estimates of the
effects of the change to the recovery system.
     (h)  Where the recalculated values yield a total resource
effectiveness index <1.0, the owner or operator shall notify the State air
quality management agency within 1 week of the recalculation and shall
conduct a performance test according to the methods and procedures
required by D.5.
                                   D-14
-------







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D-15
-------
                                                            EXAMPLE ONLY
      (i)   For the purpose of demonstrating that a process vent stream has
a VOC concentration below 500 parts per million by volume, the following
to set procedures shall be followed:
      (1)   The sampling site shall be selected as specified in D.5(c)(l).
      (2)   Method 18 or Method 25A of Part 60, Appendix A shall be used to
measure concentration; alternatively, any other method or data that has
been  validated according to the protocol in Method 301 of Part 63,
Appendix A may be used.
      (3)   Where Method 18 is used, the following procedures shall be used
to calculate parts per million by volume concentration:
      (i)   The minimum sampling time for each run shall be 1 hour in which
either an  integrated sample or four grab samples shall be taken.  If grab
sampling is used, then the samples shall be taken at approximately equal
intervals  in time, such as 15 minute intervals during the run.
      (ii)  The concentration of TOC (minus methane and ethane) shall be
calculated using Method 18 according to D.5(c)(4).
      (4)   Where Method 25A is used, the following procedures shall be used
to calculate parts per million by volume TOC concentration:
      (i)   Method 25A shall be used only if a single VOC is greater than
50 percent of total VOC, by volume, in the process vent stream.
      (ii)  The process vent stream composition may be determined by either
process knowledge, test data collected using an appropriate EPA Method or
a method of data collection validated according to the protocol in
Method 301 of Part 63, Appendix A.  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 process vent stream conditions.
      (iii)  The VOC used as the calibration gas for Method 25A shall be
the single VOC present at greater than 50 percent of the total VOC by
volume.
     (iv)  The span value for Method 25A shall be 50 parts per million by
volume.
     (v)  Use of Method 25A is acceptable if the response from the
high-level  calibration gas is at least 20 times the standard deviation of

                                   D-16
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                                                            EXAMPLE ONLY
the response from the zero calibration gas when the instrument is zeroed
on the most sensitive scale.
     (vi)  The concentration of TOC shall be corrected to 3 percent oxygen
using the procedures and equation in D.5(c)(3).
     (5)  The owner or operator shall demonstrate that the concentration
of TOC including methane and ethane measured by Method 25A is below
250 parts per million by volume with VOC concentration below 500 parts per
million by volume to qualify for the low concentration exclusion.
D.6  MONITORING REQUIREMENTS
     (a)  The owner or operator of an affected facility that uses an
incinerator to seek to comply with the TOC emission limit specified under
D.4(a)(l) shall install, calibrate, maintain, and operate according to
manufacturer's specifications:  a temperature monitoring device equipped
with a continuous recorder and having an accuracy of ±0.5 °C, whichever is
greater.
     (1)  Where an incinerator other than a catalytic incinerator is used,
a temperature monitoring device shall be installed in the firebox.
     (2)  Where a catalytic incinerator is used, temperature monitoring
devices shall be installed in the gas stream immediately before and after
the catalyst bed.
     (b)  The owner or operator of an affected facility that uses a flare
to seek to comply with D.4(a)(2) shall install, calibrate, maintain, and
operate according to manufacturer's specifications, a heat-sensing device,
such as a ultraviolet beam sensor or thermocouple, at the pilot light to
indicate continuous presence of a flame.
     (c)  The owner or operator of an affected facility that uses a boiler
or process heater with a design heat input capacity less than 44 megawatts
to seek to comply with D.4(a)(l) shall install, calibrate, maintain, and
operate according to the manufacturer's specifications, a temperature
monitoring device in the firebox.  The monitoring device should be
equipped with a continuous recorder and having an accuracy of ±1 percent
of the temperature being measured expressed in degrees Celsius or ±0.5 °C,
whichever is greater.  Any boiler or process heater in which all vent
streams are introduced with primary fuel is exempt from this requirement.

                                   D-17
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                                                            EXAMPLE ONLY
      (d)  The owner or operator of an affected facility that seeks to
demonstrate compliance with the total resource effectiveness index limit
specified under D.4(b) shall install, calibrate, maintain, and operate
according to manufacturer's specifications the following equipment:
      (1)  Where an absorber is the final recovery device in the recovery
system:
      (i)  A scrubbing liquid temperature monitor equipped with a
continuous recorder.
      (ii)  Specific gravity monitor equipped with continuous recorders.
      (2)  Where a condenser is the final recovery device in the recovery
system, a condenser exit  (product side) temperature monitoring device
equipped with a continuous recorder and having an accuracy of ±1 percent
of the temperature being monitored expressed in degrees Celsius or
±0.5  °C, whichever is greater.
      (3)  Where a carbon adsorber is the final recovery device unit in the
recovery system, an integrating regeneration stream flow monitoring device
having an accuracy of ±10 percent, capable of recording the total
regeneration stream mass flow for each regeneration cycle; and a carbon
bed temperature monitoring device having an accuracy of ±1 percent of the
temperature being monitored expressed in degrees Celsius of ±0.5 °C,
capable of recording the carbon bed temperature after each regeneration
and within 15 minutes of completing any cooling cycle.
      (4)  Where an absorber scrubs halogenated streams after an
incinerator, boiler, or process heater, the following monitoring equipment
is required for the scrubber.
      (i)  A pH monitoring device equipped with a continuous recorder.
      (ii)  Flow meters equipped with a continuous recorders to be located
at the scrubber influent for liquid flow and the scrubber inlet for gas
stream flow.
      (e)  The owner or operator of a process vent using a vent system that
contains bypass lines that could divert a vent stream away from the
combustion device used shall either:
      (1)  Install, calibrate, maintain, and operate a flow indicator that
provides a record of vent stream flow at least once every 15 minutes.  The

                                   D-18
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                                                            EXAMPLE ONLY
flow indicator shall be installed at the entrance to any bypass line that
could divert the vent stream away from the combustion device to the
atmosphere; or
     (2) Secure the bypass line valve in the closed position with a
car-seal or a lock-and-key type configuration.  A visual inspection of the
seal or closure mechanism shall be performed at least once every month to
ensure that the valve is maintained in the closed position and the vent
stream is not diverted through the bypass line.
D.7  REPORTING/RECORDKEEPING REQUIREMENTS
     (a)  Each reactor process or distillation operation subject to this
rule shall keep records of the following parameters measured during a
performance test or TRE determination required under D.5, and required to
be monitored under D.6.
     (1)  Where an owner or operator subject to the provisions of this
subpart seeks to demonstrate compliance with D.4(a)(l) through use of
either a thermal or catalytic incinerator:
     (i)  The average firebox temperature of the incinerator (or the
average temperature upstream and downstream of the catalyst bed for a
catalytic incinerator), measured at least every 15 minutes and averaged
over the same time period of the performance testing, and
     (ii)  The percent reduction of TOC determined as specified in D.5(c)
achieved by the incinerator, or the concentration of TOC (parts per
million by volume, by compound) determined as specified in D.5(c) at the
outlet of the control device on a dry basis corrected to 3 percent oxygen.
     (2)  Where an owner or operator subject to the provisions of this
subpart seeks to demonstrate compliance with D.4(a)(l) through use of a
boiler or process heater:
     (i)  A description of the location at which the vent stream is
introduced into the boiler or process heater, and
     (ii)  The average combustion temperature of the boiler or process
heater with a design heat input capacity of less than 44 megawatt measured
at least every 15 minutes and averaged over the same time period of the
performance testing.
                                   D-19
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                                                            EXAMPLE ONLY
      (iii)  Any boiler or process heater in which all vent streams are
 introduced with primary  fuel are exempt from these requirements.
      (3)  Where an owner or operator subject to the provisions of this
 subpart seeks to demonstrate compliance with 0.4(a)(2) through use of a
 smokeless flare; flare design  (i.e., steam-assisted, air-assisted, or
 nonassisted), all visible emission readings, heat content determinations,
 flow  rate measurements,  and exit velocity determinations made during the
 performance test, continuous records of the flare pilot flame monitoring,
 and records of all periods of  operations during which the pilot flame is
 absent.
      (4)  Where an owner or operator subject to the provisions of this
 subpart seeks to demonstrate compliance with D.4(b):
      (i)  Where an absorber is the final recovery device in the recovery
 system, the exit specific gravity (or alternative parameter which is a
 measure of the degree of absorbing liquid saturation, if approved, by the
 permitting authority), and average exit temperature of the absorbing
 liquid measured at least 15 minutes and averaged over the same time period
 of the performance testing (both measured while the vent stream is
 normally routed and constituted), or
      (ii)  Where a condenser is the final recovery device the recovery
 system, the average exit (product side) temperature measured at least
 every 15 minutes and averaged  over the same time period of the performance
 testing while the vent stream  is routed and constituted normally, or
      (iii)  Where a carbon adsorber is the final recovery device in the
 recovery system, the total stream mass or volumetric flow measured at
 least every 15 minutes and averaged over the same time period of the
 performance test (full carbon  bed cycle), temperature of the carbon bed
 after regeneration (and  within 15 minutes of completion of any cooling
cycle(s)), and duration  of the carbon bed steaming cycle (all measured
while the vent stream is routed and constituted normally), or
     (iv)  As an alternative to D.7(a)(4)(i), (a)(4)(ii) or (a)(4)(iii),
the concentration level  or reading indicated by the organics monitoring
device at the outlet of  the absorber, condenser, or carbon adsorber,
measured at least every  15 minutes and averaged over the same time period

                                   D-20
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                                                            EXAMPLE ONLY
as the performance testing while the vent stream is normally routed and
constituted.
     (v)  All measurements and calculations performed to determine the
flow rate, and volatile organic compound concentration, heating value, and
TRE index value of the vent stream.
     (b)  Each reactor process or distillation operation subject to this
guideline will also be subject to the exceedance reporting requirements of
the draft Enhanced Monitoring Guideline.  The specifics of the
requirements will be added to this document when the Enhanced Monitoring
Guideline is quotable.
     (c)  Each reactor process or distillation operation seeking to comply
with D.4(b) shall also keep records of the following information:
     (1)  Any changes in production capacity, feedstock type, or catalyst
type, or of any replacement, removal, and addition of recovery equipment
or reactors and distillation units.
     (2)  Any recalculation of the flow rate, TOC concentration, or TRE
value performed according to D.5(g).
     (d)  Each reactor process or distillation operation seeking to comply
With the flow rate or concentration exemption level in D.2(b)(4) shall
keep records to indicate that the stream flow rate is less than
0.0085 standard cubic meters per minute or the concentration is less than
500 parts per million by volume.
     (e)  Each reactor process or distillation operation seeking to comply
with the production capacity exemption level of 1 gigagrams per year shall
keep records of the design production capacity or any changes in equipment
or process operation that may affect design production capacity of the
affected process unity.
                                   D-21
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            APPENDIX E
ENVIRONMENTAL IMPACTS CALCULATIONS
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                                APPENDIX E

                    ENVIRONMENTAL IMPACTS CALCULATIONS


E.I  CALCULATION OF SECONDARY AIR IMPACTS

     Calculations will be based on model stream R-LFHH, the same stream

used as an example in Appendix C.

E.2  ESTIMATING CARBON MONOXIDE EMISSIONS

     Calculate total heat input of the stream to be combusted.

     (1)  HI = Initial heat input of waste stream
          HI = (flow rate)(heat value)
             = (23.54 scfm)(209.7 Btu/scf)
             = 4,936 Btu/min x (60 min/hr) x (8,760 hr/yr) x
               (MMBtu/106 Btu)
             = 2,595 MMBtu/yr

     (2)  H£ = Heat input from auxiliary fuel
          H2 = (flow rate)(heat value)
             - (0.1 scfm)(1,000 Btu/scf)
             = 100 Btu/min
             =52.5 MMBtu/yr

     (3)  Total heat input = Hi + Hp
                           = (2,595 + 52.5) MMBtu/yr
                           = 2,648 MMBtu/yr


     Calculate carbon monoxide (CO) emissions using AP-42 factor of 20 Ib
CO/MMscf of fuel.

     (1)  Convert MMBtu/yr to equivalent fuel flow (Qp)
          QF = (2,698 MMBtu/yr)(scf/1,000 Btu)
             =2.6 MMscf/yr

     (2)  C0em = (2.6 MMscf/yr)(20 lb/MMscf)(Mg/2,207 Ib)
               =0.02 Mg/yr of CO
                                    E-l
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E.3  ESTIMATING NITROGEN OXIDES EMISSIONS
     Determine method of control (flare or incinerator).  Model stream
R-LFHH is cheapest to control using incinerator with scrubber  (see
Appendix C for costing analysis).
     For incinerators, two nitrous oxide (NOX) emission factors are used:
one for streams containing nitrogen compounds, and one for streams without
nitrogen compounds.  Inert nitrogen gas (Ng) is not included.  The NOX
factors for incinerators are as follows:
        with nitrogen compounds:  200 ppm in exhaust
     without nitrogen compounds:  21.5 ppm in exhaust
The model stream R-LFHH has no nitrogen, so 21.5 ppm will be used.  These
factors reflect testing data that was gathered for the Air Oxidation
Reactor processes CTG and the Polymers and Resins CTG.
     Calculate total outlet flow, as explained in Appendix C.  As shown in
Section C.4, the total outlet flow exiting the incinerator/scrubber system
is 53 scfm.
     (1)  NOX emissions = (53 scfm)(21.5/106)/(392 scf/lb-mole) x
                          (46 Ib/lb-mole)
          NOX emissions = (0.000134 Ib/min) x (60 min/hr) x
                          (8,760 hr/yr) x (Mg/2,207 Ib)
                        - 0.032 Mg/yr
     (2)  If the total outlet flow rate from the incinerator is not known,
the following emission factors may be used to calculate NOX emissions:
        with nitrogen compounds:  0.41 Ib NOx/MMBtu
     without nitrogen compounds:  0.08 Ib NOx/MMBtu
     As calculated in E.2 (3), the total heat input is 2,648 MMBtu/yr.
Therefore,  the NOX emissions estimated using this factor are calculated
by:
     NOX emissions - (2,648 MMBtu/yr)(0.08 Ib NOx/MMBtu) x (Mg/2,207 Ib)
                   =0.10 Mg/yr
                                    E-2
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                        APPENDIX F

RESPONSE TO PUBLIC COMMENTS RECEIVED ON THE DRAFT SYNTHETIC
 ORGANIC CHEMICAL MANUFACTURING INDUSTRY REACTOR PROCESSES
 AND DISTILLATION OPERATIONS CONTROL TECHNIQUES  GUIDELINE
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                                APPENDIX  F
        RESPONSE TO PUBLIC COMMENTS RECEIVED ON THE DRAFT SYNTHETIC
         ORGANIC CHEMICAL MANUFACTURING INDUSTRY REACTOR PROCESSES
         AND  DISTILLATION  OPERATIONS CONTROL TECHNIQUES  GUIDELINE

F.I   INTRODUCTION
      On December 12,  1991, the U.  S. Environmental Protection Agency  (EPA)
announced the availability of a draft control  techniques guideline (CTG)
document for "The Control of Volatile Organic Compound Emissions from
Reactor Processes and Distillation Operations Processes in the Synthetic
Organic Chemical Manufacturing Industry" (56 FR 64785).  Public comments
were requested on the draft CTG in that Federal Register notice.  Thirteen
comments were received.  Table F.l-1 lists the commenters, their
affiliations, and the EPA docket number assigned to their correspondence.
The major topics of the comments were:   the recommendation to incorporate a
total resource effectiveness (TRE) index approach for determining
applicability; the recommendation for less stringent flow cutoffs; and a
concern that the cost of complying with the recommended control level is
too high.  The comments that were submitted, along with responses to these
comments, are summarized in this appendix.  The summary of comments and
responses serve as the basis for the revisions made to the CTG between the
draft and final document.
F.2   SUMMARY  OF CHANGES  TO THE DRAFT CONTROL TECHNIQUES  GUIDELINE
      Several  changes  and clarifications were made  in  the  CTG  as  a  result
of review of public comments.  These changes and clarifications were made
in the following areas:  (1) use of the TRE index equations;
(2) aggregation of vent streams to a control device;  (3) location of flow
indicators; (4) definition of total organic compounds  (TOC's);
(5) description of catalytic incinerators; (6) applicable chemicals;
                                    F-l
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             TABLE F.l-1.  LIST OF COMMENTERS AND AFFILIATIONS


Docket item
number3                        Commenter and affiliation
IV-D-1                  Mr. Charles D. Malloch
                        Director, Regulatory Management
                        Environment, Safety and Health
                        Monsanto Company
                        800 N. Lindbergh Boulevard
                        St. Louis, Missouri  63167

IV-D-2                  Mr. R.L. Arscott, General Manager
                        Health, Environmental and Loss
                          Protection
                        Chevron Corporation
                        Post Office Box 7924
                        San Francisco, California  94120-7924

IV-D-3                  Mr. David W. Gustafson
                        Environmental Quality
                        Mr. Sam P. Jordan
                        Environmental Law
                        The Dow Chemical Company
                        Midland, Michigan  48667

IV-D-4                  Mr. John A. Dege
                        CAA Issue Manager
                        DuPont Chemicals
                        Wilmington, Delaware  19898

IV-D-5                  V.M. Mclntire
                        Environmental Affairs
                        Eastman Chemical Company
                        Post Office Box 511
                        Kingsport, Tennessee  37662

IV-D-6                  Ms. Sherry L. Edwards, Manager
                        Government Relations
                        Synthetic Organic Chemical Manufacturers
                          Association, Incorporated
                        1330 Connecticut Avenue, N.W., Suite 300
                        Washington, D.C.  20036-1702

IV-G-2                  M.L. Mullins
                        Vice President, Regulatory Affairs
                        Chemical Manufacturers Association
                        2501 M Street, N.W.
                        Washington, D.C.  20037
                                    F-2
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             TABLE F.l-1.  LIST OF COMMENTERS AND AFFILIATIONS
                                       (CONCLUDED)


Docket item
number3                        Commenter and affiliation
IV-G-3                  Mr. E. G. Collier
                        Chairman, Control Techniques
                        Guidelines Subcommittee
                        Texas Chemical Council

IV-G-4                  Mr. B.L. Taranto
                        Environmental Affairs Department
                        Exxon Chemical Americas
                        Post Office Box 3272
                        Houston, Texas  77253-3272

IV-G-5                  Ms. Regina M. Flahie
                        Chief
                        Division of Interagency and International
                          Affairs
                        U. S. Department of Labor, Occupational
                        Safety and Health Administration
                        Washington, D.C.  20210

IV-G-6                  Mr. G. E. Addison
                        Manager, Planning and Development
                        ARI Technologies, Incorporated
                        600 N. First Bank Drive
                        Palatine, Illinois  60067

IV-G-7                  Mr. Raymond J. Connor
                        Technical Director
                        Manufacturers of Emission Controls
                          Association
                        1707 L Street, N.W., Suite 570
                        Washington, D.C.  20036-4201

IV-G-8                  Mr. Kevin Ewing
                        Market Manager
                        Thermotron Industries
                        291 Kollen Park Drive
                        Holland, Michigan  49423
aThe docket number for this project is SOCMI CTG A-91-38.  Dockets  are  on
 file at the EPA Air Docket in Washington, D.C.
                                    F-3
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 (7) definition of product; (8) definition of halogenated stream;
 (9) exemption of streams with a flow rate or concentration below a cutoff
 value; and  (10) definition of affected facility.
      The comments  summarized  in this appendix  have  been organized  into the
 following categories:  Applicability of the Control Techniques Guideline;
 Recommendation of Reasonably Available Control Technology; Cost
 Effectiveness, Monitoring and Testing,  and Editorial.
 F.3   APPLICABILITY  OF  THE CONTROL  TECHNIQUES GUIDELINE
 F.3.1  Comment:  One commenter (IV-G-4) disagreed with the assertion on
 pages 6-7 and 6-8 of the draft CTG that the recommended applicability
 criteria provide an incentive for pollution prevention.  The commenter
 stated that since control by combustion (or equivalent control) would be
 required for the residual emissions from virtually any recovery device, the
 incentive to install such a device would be diminished.  The commenter
 suggested that an incentive could be provided for control  of vent emissions
 by combusting the residuals as primary fuel.
      Response:  The incentive  referred to  on pages  6-7 and 6-8  of  the
 draft CTG pertains  to  an incentive for any pollution prevention or
 recycling practice  that lowers emissions below the cutoff level.  Pollution
 prevention  and recycling can include any process change—including the
 addition of recovery devices—that significantly reduces the amount of
 pollutants  that are emitted from the process unit.  In the case of this
 CTG, the recommended presumptive norm for reasonably available control
 technology  (RACT) would allow an affected facility to avoid having to
 install an  add-on combustion control device if the affected facility lowers
 emissions below the cutoff.   The EPA believes that this provision
 encourages pollution prevention and recycling.
 F.3.2  Comment:  One commenter (IV-D-5) requested that the EPA include in
 this CTG a  statement that distillation operations that are part of polymer
manufacturing processes are not covered by this CTG.  The commenter
 reasoned that this would be consistent with the applicability criteria for
 the new source performance standards (NSPS) for distillation operations
 (40 CFR Part 60 Subpart NNN).
      Response:  It  is  not the  intent of this CTG  to provide guidance  for
process vents that are subject to regulations for the polymer manufacturing
                                    F-4
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industry.  To clarify that these facilities are not subject to this CTG,  an
exemption statement has been added to this document (see Section 7.4).
F.3.3  Comment:  Two commenters (IV-D-2, IV-G-2) suggested that the CTG
provide a more detailed discussion of the overlap between the source
categories and chemicals covered under this CTG, and the source categories
and hazardous air pollutants (HAP's) covered under Title III of the Clean
Air Act (CAA), as amended in 1990.
      One  commenter  (IV-G-2)  further  stated  that the EPA  should  strive  for
consistency between Title I RACT and Title III maximum achievable control
technology (MACT) with respect to the application of control standards,
testing, monitoring, and reporting requirements.
      Response:   The EPA understands  that more  clarification  is  needed  to
explain which chemicals within the SOCMI source category are applicable to
this CTG and which are subject to Title III of the CAA.  The SOCMI is a
broad source category that includes any manufacturer of synthetic organic
chemicals.  Appendix A of this CTG has been revised to present the organic
chemicals that are subject to this CTG.  Appendix A also indicates which
chemicals in this list are listed as part of the SOCMI source category and
which chemicals are subject to the proposed Hazardous Organic National
Emission Standard for Hazardous Air Pollutants (HON),  or any of the
following regulations:  the air oxidation processes NSPS; distillation
operations NSPS; and the reactor processes NSPS.  The regulations' and
rules' applicability criteria is based on the chemical manufactured.  For
example, hexanedioic acid is manufactured using a reactor and distillation
unit and is subject to this CTG, the distillation NSPS, and the reactor
process NSPS.  However, hexanedioic acid is not manufactured using an air
oxidation process and, therefore, is not subject to the air oxidation
process NSPS.
      Although  there are appropriate  differences with  respect to
applicability, the EPA wants to eliminate duplicate performance testing,
reporting and recordkeeping, and monitoring requirements.  The  EPA is
considering options to deal with the interface between regulations
promulgated under Section 112 of the Clean Air Act and RACT rules.
Specifically, the EPA is developing a policy statement for emission points
that will be affected both by the HON and RACT rules.  This policy
statement will be published in the Federal Register when completed.

                                    F-5
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 Pursuant to the CTG, recordkeeping and reporting requirements have been
 left to the discretion of the State air quality management agencies as
 stated in Section 7.7 (Reporting/Recordkeeping Requirements) of the CTG
 document; however, emission points subject to the HON would be subject to
 the recordkeeping and reporting requirements of the HON.
     The  controls  required  to  comply  with  the  SOCMI NSPS,  CTG's  and  the
 HON are the same and are based on the same control technology--that is,
 combustion.  The cutoff levels for applicability may be different, however,
 because VOC's are the subject of the CTG's and the NSPS, and organic HAP's
 are the subject of the proposed HON.
 F.3.4  Comment:  Several commenters (IV-D-3, IV-D-4, IV-D-5, IV-D-6,
 IV-G-2, IV-G-3) recommended the incorporation of a TRE index as another
 option to the already suggested presumptive norm for RACT.  Two commenters
 (IV-D-3, IV-G-2) suggested that using a TRE index would help to achieve a
 more cost-effective VOC control by using the least amount of energy,
 capital, and total resources.  The commenters also suggested that
 incorporation of a TRE index furthers the application of pollution
 prevention principles by encouraging increased product recovery techniques
 and other process modifications that ultimately reduce VOC emissions, often
 by using more cost-effective techniques.
     Response:  To  remain consistent  with  the  other SOCMI  regulations, the
 EPA has decided to incorporate the TRE index applicability approach to
 replace the flow and concentration limits that appeared in the draft CTG.
 This decision was reached after the draft CTG document was made available
 for public comment.  The final copy of the CTG includes the TRE index.
     The TRE  index  equation  is  a decision  tool  used to determine  if  the
 annual  cost of controlling a given vent stream (as determined using the
 standard procedure described in Chapter 5) is acceptable when considering
 the emission reductions achieved.  The TRE index is a measure of the total
 resource burden associated with emission control for a given vent stream.
 The TRE index equation is normalized so that the decision point has a
 defined value of 1.0.  The variables in the TRE index equation are the
 stream characteristics (i.e., flow rate, heat content, VOC emission rate).
 This TRE index equation is developed from a multivariable linear regression
 of the cost algorithm.  It is recommended that the owner or operator
demonstrate that a TRE index is greater than 1.0 at the outlet of the final

                                    F-6
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recovery device in order to avoid having to control  VOC emissions.   If the
TRE index is less than or equal to 1.0 at the point  of measurement,  the
owner or operator could elect either to modify the process or,  install an
additional recovery device or a control device that  results in  a TRE index
greater than 1.0.
     The  cost-effectiveness criteria built into the TRE index equation
allow for greater emission reductions at the same cost compared to the flow
and concentration limits alone.  With the TRE equation, the CTG allows the
flexibility to reduce VOC emission by whatever means the owner  or operator
prefers.  Pollution prevention that increases product or raw material
recovery may be the most cost-effective (and even the most beneficial)
method to reduce VOC emissions and is encouraged.
F.3.5  Comment:  Several commenters (IV-D-3,  IV-D-5, IV-G-2, IV-G-3,
IV-G-4) questioned the feasibility and stringency of the CTG combined vent
criteria.  Several commenters (IV-D-3, IV-D-5, IV-G-2, IV-G-3)  argued that
the concentration and flow cutoff should apply only to individual vent
streams and not the combination of all vent streams in the process unit.
Two commenters (IV-D-3, IV-G-2) also pointed out that the combined vent
criteria appear to be more stringent than those in the NSPS because the CTG
flow cutoff applies to multiple vents, regardless of whether a  common
recovery system into which the vents are discharged exists.
     Several commenters  (IV-D-3,  IV-G-2,  IV-G-3,  IV-G-4)  suggested  that
situations exist where it is not technically feasible, economical, or safe
to combine vent streams.  One commenter (IV-G-3) noted the following two
examples that illustrate the safety concerns:
     •     Combining  two  streams  where one stream is  below the  lower
           explosive  limit and  another stream  is  above the explosive
           limit, or
     •     Combining  two  streams  that  are chemically  reactive.
     Response:   The combined  stream criteria were included in this  CTG
because the practice of combining streams is often used in industry  for
similar process vent streams within the same process unit.  The EPA
recognizes that circumstances exist where it may not be technically
feasible, economical, or safe to combine vent streams  and, therefore,  it
should not be a control criterion.  Because this approach  cannot be
generalized across the entire industry, the combined vent  applicability
                                    F-7
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approach has been omitted from the CTG document.  Furthermore, it should be
noted that the applicability limits were written for individual streams and
were not intended to determine applicability limitations on a combined
stream basis.  The applicability calculations continue to be conducted on
an individual vent stream basis after the CTG was revised to incorporate
the TRE.
F.3.6  Comment:  One commenter (IV-D-1) noted that on page 2-7 of the draft
CTG, the EPA refers to "176 high-volume chemicals" that "involve reactor
processes."  The commenter further noted that on page 2-33, the EPA refers
to the scope of the reactor processes covered in the CTG as representing
"one of the 173 reactor process chemicals."  The commenter recommended that
the EPA revise Appendix A of the CTG to indicate 173 chemicals (thus
representing the similar list used in the NSPS), which the CTG intended to
cover under reactor processes.
      In  addition,  the  commenter noted  that  the  final NSPS  for  distillation
operations lists the chemicals for its applicability.  The commenter
recommended that Appendix A of the draft CTG be shortened to include only
those chemicals used for determining applicability of distillation
operations.  The commenter then suggested that the applicability statement
in Section D.2.a on page D-l of Appendix D in the draft CTG should be
expanded to state that the process unit subject to this CTG should be one
for which a chemical is listed in Appendix A.
      Response:  The  reference on page  2-7 of the document  is  an  industry
characterization.   There is no statement to suggest that the
176 high-volume chemicals listed there are the only chemicals within the
scope of this CTG.  These 176 chemicals are a subset of SOCMI chemicals
that are produced in large quantities.   Appendix A lists the 719 chemicals
subject to this CTG.  This list also identifies those chemicals that are
also subject to the Distillation NSPS,  Air Oxidation NSPS, the Reactor
Process NSPS, the HON and other chemicals under the SOCMI source category.
It is the intent of the EPA to make subject of this CTG, any distillation
column or reactor operating as part of a process unit that makes one of the
chemicals listed in Appendix A.   The applicability statement in Appendix D
has been expanded to state that the applicability of this CTG is based on
the chemicals that are listed in Appendix A.
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F.3.7  Comment:  One commenter (IV-D-1) recommended that Table 2-5 on
page 2-47 of the draft CTG be revised to address more clearly the minimal
emissions occurring from atmospheric distillation operations.  The
commenter said that, as drafted,  the table does not identify what type of
operation corresponds to either the high or low emission rates.  The
commenter cited personal experience that atmospheric distillation columns
used with low vapor pressure chemicals, such as adiponitrile or
hexamethylene diamine, do not have any detectable emissions from the
atmospheric vent.
     The  commenter  also  argued that  condensers  between  the  steam  jets and
sometimes on the final jet discharge are very effective in controlling
emissions from distillation columns that process low-volatility chemicals,
with control efficiencies exceeding 95 percent in situations as described
above.
     Response:   Table  2-5  of  the CTG document lists the average operating
characteristics of the distillation emission profile, in addition to the
range for these characteristics.   The EPA realizes that the types of
operations that correspond to the values listed are not identified and that
processes may exist that are below those values.
     With respect to  the alternative VOC emissions reduction  approach
described by the commenter, the EPA would like to clarify that the RACT
presumptive norm would not preclude the use of a condenser to reduce VOC
emissions from affected vent streams.  If use of such a condenser were to
result in a TRE index value for the vent stream that is above the limit,
then no additional control would be required.
F.4  RECOMMENDATION OF REASONABLE AVAILABLE  CONTROL TECHNOLOGY
F.4.1  Comment:  Several commenters  (IV-D-2, IV-D-4, IV-D-6,  IV-G-2,
IV-G-4) expressed concern that the recommended control  applicability cutoff
is too stringent.  Six commenters (IV-D-4, IV-D-5, IV-D-6,  IV-G-2, IV-G-3,
IV-G-4) pointed out that the proposed RACT de minimus flow rate is up to
four times more stringent than the distillation operations NSPS
requirements.
     One  commenter  (IV-G-4) said that  CTG  cutoffs  of  0.1  standard cubic
feet per minute (scfm) and 0.05 weight-percent VOC would result in a
calculated TRE of approximately 6,000 using the TRE equation  from the
proposed HON.  The commenter also noted that the proposed cutoffs

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correspond to a VOC emission rate of less than 5 pounds per year (Ib/yr),
and compared this emission rate to that of a single "nonleaking" valve in
light liquid service, which has an emission rate of 6 Ib/yr as calculated
using the EPA emission factors.
      Two commenters  (IV-D-6,  IV-G-2)  suggested that the CTG adopt Option 3
(e.g., flow rate <0.5 scfm and VOC weight percent <1)  in Table 6-1 as the
RACT cutoff.  One commenter (IV-D-6) emphasized that this option reduces
nationwide emissions by over 73 percent, and reduces the nationwide cost of
control  by nearly 60 percent; yet still obtains almost 77 percent of the
emissions reduction achieved by the RACT cutoff proposed by the EPA.
      Response:  The  EPA  has reevaluated the applicability cutoff, as
mentioned in the response to comment number F.3.6, and the TRE index
equation will replace the flow or concentration limits that appeared in  the
draft CTG.  As pointed out by the commenters,  use of the TRE equation will
provide  consistency with the distillation NSPS and HON requirements.
F.4.2  Comment:  One commenter (IV-D-3) noted that it is not obvious
whether  the RACT cutoffs recommended by the CTG refer to instantaneous or
average  values.  The commenter suggested that the EPA specifically state
that the cut-off criteria for the concentration and flow are to be based on
an annual weighted average.
      Response:  The  inputs to  the TRE  index equation  are stream flow rate,
VOC emission rate, and heat content.  These parameters should be average
values over the period of the performance test.  The performance test
should be conducted under typical operating conditions, the specifics of
which are defined in the example rule (Appendix D).
F.4.3  Comment:  One commenter (IV-D-6) stated that by definition in the
CAA, RACT requirements are less stringent than MACT requirements.
Therefore, the proposed RACT for SOCHI should be less stringent than MACT
for the  same source categories.
      Response:  There  is  some  confusion between MACT  and RACT  and the
level of stringency for each requirement.   One cannot compare the
stringency levels of the two requirements because they are applicable to
two different groups of pollutants;  MACT is applied to HAP's listed in
Section  112(b) of the CAA as amended in 1990,  whereas RACT is applicable to
various of the criteria pollutants,  including VOC, a precursor to ozone.
In some cases, the same vent stream may be subject to RACT criteria but  not

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MACT criteria.  Regardless of the applicability criteria,  the control
requirement in all SOCMI regulations is 98 percent reduction of pollutants
or pollutant reduction down to a concentration level  of 20 parts per
million by volume (ppmv) on a dry basis, corrected to 3 percent oxygen.
F.4.4  Comment;  One commenter (IV-G-2) stated that the presumptive norm
described in the CTG document for SOCMI does not accurately describe the
types of emissions found to be emitted from reactor processes and
distillation operations.  Although the VOC concentration cutoff and flow
rate cutoff help to ensure that insignificant vent streams do not require
unnecessary cost controls, the cutoffs do not account for the variation
that occurs from stream to stream due to chemical properties and associated
heating values.  The commenter argued that a low heating value stream would
result in a much higher control cost than a high heating value stream, and
may not be appropriate as a presumptive norm for RACT.
      Response:  The  EPA  understands that  in  some  cases  low  heating  value
streams could result in higher costs than high heating value streams to
control, and has, therefore, incorporated the TRE index equation to the
applicability section.  The TRE index identifies only those streams that
can be controlled in a cost-effective manner.
F.4.5  Comment;  One commenter (IV-G-2) observed that the de minimus levels
suggested in the CTG document are incompatible with the levels found in the
NSPS.  The commenter said that the establishment of such a low level will
prove to be of little use to the regulated community and, furthermore, by
setting a level that is inconsistent with current NSPS regulations, the EPA
places facilities in the awkward position of trying to comply with two
conflicting levels of control.
      Response;  This comment  is  resolved  by  the  incorporation  of TRE.   As
indicated in the previous response, the parameters incorporated  into the
TRE equation will allow for control of only those streams that can be
controlled on a cost-effective basis.
F.5   COST  EFFECTIVENESS  AND COST ESTIMATION
F.5.1  Comment;  One commenter (IV-G-3) suggested that because a scrubber
is needed to remove hydrogen chloride (HC1) from the incinerator flue gas,
the discharge from this scrubber may significantly contaminate wastewater,
which would require treatment prior to discharge.  Another commenter
(IV-D-5) questioned the EPA's judgment that costs associated with the

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disposal of salty wastewater formed by the neutralization of acidic
scrubber effluent were not significant.  The commenter suggested that the
opportunity to use on-site wells is significantly limited, not only by
geographic considerations, but also regulatory concerns.  Direct and
indirect discharges could also be limited by aquatic toxicity limits of the
National Pollutant Discharge Elimination Standards (NPDES) permit program.
      Response:   It  is  the decision  of the EPA  not to  include  the costs
associated with the disposal of salty wastewater in the cost equation for
VOC control devices.  This decision was based on earlier work done on the
SOCMI reactor process NSPS.  The effects from the discharge of wastewater
from the scrubbers were presented in  1984 in the background information
document (BID) for the Reactor Process NSPS.  The water pollution impacts
were studied in 1982, at which time it was determined that the costs
associated with the disposal of the salty wastewater are not significant in
comparison to the overall control costs and, therefore, were not included
in the projected cost impacts.  The specific reference in the Reactor
Process NSPS docket that explains the methodology is EPA Docket
No. A-83-29, Item No. II-B-25.
F.5.2  Comment:  Several commenters (IV-D-4, IV-D-6 IV-G-2, IV-G-3)
emphasized that the EPA underestimated the installed equipment costs,
resulting in lower average cost-effectiveness numbers than industry is
currently experiencing.  Three commenters (IV-D-4, IV-G-2, IV-G-3) noted
that the EPA indicated an installation factor of 1.61, which is much lower
than installation factors of 3 to 10 commonly encountered in the chemical
industry.
      Response:  The  installed  equipment costs  and the  installation  factor
of 1.61 were determined using the EPA's Office of Air Quality Planning and
Standards Control Cost Manual (OCCM).  Each chapter of the OCCM underwent
extensive industry review prior to finalization making this document the
accepted source by the EPA.   The EPA believes that this installation factor
is consistent with what the majority of facilities from different
industries that install incinerators would encounter.
F.5.3  Comment:  Two commenters (IV-G-4, IV-D-6) suggested that the
cost-effectiveness analysis is flawed and does not support the
applicability criteria.  One commenter (IV-G-4) noted that in Table 6-1 of
the CTG, the average emission reduction per vent in the increment going

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from Option 3 to Option 2 is 0.0035 megagrams per year (Mg/yr).   However,
vents of less than 0.003 Mg/yr would have to be controlled by the 0.1  scfm
and 0.05 weight percent applicability criteria given in the draft CTG.
Thus, the incremental cost effectiveness is calculated on a basis that
misrepresents the recommended applicability criteria by more than four
orders of magnitude.  The commenter further noted that the cost
effectiveness of controlling a 0.1 scfm and 0.05 weight percent  vent stream
is not addressed, and it should be in order to support its selection.
     The commenter  also  felt that the cost data used to analyze  regulatory
options is very low and unrealistic and should be updated or corrected to
reflect actual costs based on real plant experience.  The commenter noted a
cost of $5,274 was assumed for 400 feet of an 8-inch flare collection
header, and suggested that the actual cost for this piping would exceed
$34,000, even in a noncongested area where pipe supports already exist.
The commenter also expressed concern that the flare cost estimate does not
appear to include the cost of piping and pumps to manage liquid  from the
knockout drum, or the cost of piping and controls for the water  supply to
the water seal drum, or for the air, steam, or gas to the flare  tip.
     Two commenters (IV-D-4, IV-D-6) stated  that under the  recommended
minimum emission levels, an emission flow rate of 0.11 scfm, with VOC
concentration of 0.06 weight-percent (which corresponds to 2.6 Ib/yr),
would require incineration and control.  The cost effectiveness  for the low
flow low heat case  in Table 5-6 is $23,954 per megagram (Mg) for a
1.3 Ib/hr VOC inlet flow.  The de minimus flow rate mentioned above emits
400 times less.  The commenter then said that by simple multiplication, the
cost effectiveness balloons to $96,000,000 per megagram.
     Response:   The incremental cost effectiveness  was calculated
correctly in the draft CTG document.  The data base used for this analysis
contains many streams with high flow rates, but low concentrations.
Therefore, some streams with relatively high VOC loadings are not included
in the analysis until the most stringent options are imposed.  Again,
further discussion  of this table and calculated cost effectiveness is no
longer appropriate  because the applicability format has been changed to
incorporate a TRE index equation.  The TRE equation takes into account
these high cost considerations.
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      As  stated in  response  F.5.2,  all  costing  analyses  are  in  accordance
with the OCCM.  The duct work cost assumptions are believed to represent
industry averages.  The flare costs do include water seals and steam piping
to flare tip.  Piping costs are accounted for by an installation factor.
F.5.4  Comment:  Three commenters  (IV-D-5, IV-G-2, IV-G-7) questioned
whether the EPA accounted for full "costing" of controls.  One commenter
(IV-D-5) expressed concern that the EPA neither acknowledged nor adequately
considered the upstream impact of the control equipment in their emissions
analysis.  The commenter suggested that there is a direct usage of fuel to
run control devices, as well as indirect emission impacts of:
(1) producing the fuels consumed as energy to produce the controls;
(2) producing the raw materials, such as caustic, to operate the control
devices; and (3) transporting these materials.  The commenter asserted that
the EPA should consider these upstream impacts by including a factor, such
as an economic or cash flow multiplier, that would account for these
indirect impacts in the decision process as to what levels of controls are
actually environmentally beneficial.
      Another  consideration  regarding full costing of controls  was made  by
two commenters (IV-G-2, IV-G-7) who requested that the EPA give greater
consideration to secondary air impacts due to the application of the
suggested control technologies.  One commenter (IV-G-2) noted that by the
EPA's own admission, the recommended 98 percent control requirements
generate additional oxides of nitrogen (NOX), sulfur dioxide ($03), carbon
monoxide (CO) and particulate matter (PM).  The commenter suggested that by
reducing the required level  of control  efficiency, secondary air impacts
will be reduced.  One commenter (IV-G-7) argued that a significant issue
with thermal incineration is the production of NOX and CO as secondary
pollutants when large amounts of fuel are combusted to sustain the high
temperatures needed to operate these units.   The commenter further cited
several disadvantages of thermal incineration including:
      •     High operating temperatures usually mean additional fuel
           requirements and associated higher  fuel costs;
      •     High generating temperatures require  the use of  special,  more
           costly heat resistant materials;
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     •      Longer  residence times  (greater than 1.5 seconds) than those
            cited in the draft CTG  mean larger, heavier reactors, which
            generally must be installed at ground level rather than roof
            mounted, resulting in additional expenses.
     The commenter recommended that these should be viewed as
disadvantages for this control  technology,  and that Sections 3.1.2.1  and
3.1.2.2 of the CTG be expanded to include those disadvantages.
     Response:  With respect to  "upstream" effects, it is beyond the scope
of this CTG to include in the costing equation those indirect emission
impacts listed by the commenter.   However,  the EPA generally includes
secondary air impacts due to the application of the suggested control
technologies in the analysis of RACT.  These secondary air impacts are
explained in the environmental  impacts discussion in Section 4.1.2 of the
draft CTG document rather than in the process description discussion.
Local agencies should consider the NOX and CO emissions associated with
control devices and may allow lower levels of VOC control to mitigate
secondary impacts  if appropriate.
     The disadvantages concerning  thermal incineration cited in the
comment are realized by the EPA;  however, recommendations for control
technologies assume average stream characteristics therefore, while thermal
incineration may not be appropriate for some lines, it would be a cost
effective means of control for others.  The EPA need not consider the
"worst case" in developing the CTG.
F.5.5  Comment:  One commenter (IV-G-4) recommended that the costs of
performance tests,  monitoring,  recordkeeping, and reporting also be
included in the CTG cost analysis.
     One commenter (IV-G-3) argued that  as the level  of  control and
monitoring continues to increase and as the regulatory guidelines for
"Enhanced Monitoring" evolve, the costs associated with the required
monitoring of new  incineration devices are continuing to increase.  The
commenter recommended that the present instrumentation cost factor of 0.10A
(e.g., instrument  cost = 0.10 * [incinerator + auxiliary costs]) should be
reevaluated in light of the increasing costs associated with regulatory
monitoring requirements.
     Response:  The EPA's OCCM was used  to determine  the cost  of
combustion technologies for control of VOC emissions.  The capital costs
are presented in Table 5.2.  As indicated in Table 5.2, performance test
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costs are included  in the  indirect cost of the control.  Also in Table 5.2,
listed under the purchased equipment cost, is the instrumentation cost
required for the control device.  This instrumentation would be used for
monitoring the control device.  For example, temperature instrumentation
can be used to monitor the control efficiency of the control device.
      The  "Enhanced  Monitoring"  rule  requirements are  under  development,
and that package will address the potential cost of the requirements of
that regulation, including additional costs placed on sources that are
already subject to  some type of monitoring.  The recordkeeping and
reporting requirements will vary among the States and, therefore, are not
included here.
F.5.6  Comment:  One commenter  (IV-G-4) thought that the annual operating
cost for an incinerator seems to be reasonably accurate but on the low
side.
      Response:  The EPA  intends to  investigate  any documented  numbers  the
public may have, and invites this commenter to submit any documented
numbers to the EPA.  Again, the annual operating costs were calculated from
the EPA's OCCM (see the response to comment F.5.2).
F.6   MONITORING AND TESTING
F.6.1  Comment:  Two commenters (IV-D-4, IV-D-6) stated that the
requirements for scrubbing liquid temperature and specific gravity may not
be pertinent compliance information for some scrubbers, such as a
once-through water  scrubber.  They added that instrumentation should be
required only if it provides information essential  to emission compliance.
      Response:  The CTG document  has  been  revised to  address the  issue of
absorbers used as recovery devices versus absorbers used as scrubbers to
scrub halogens from a vent stream following an incinerator.  The EPA
assumes that if an  absorber is used in a recovery system, then the absorber
recycles (or has the potential to recycle) a portion of its effluent and is
not a once-though scrubber.  Furthermore, the EPA assumes that the latter
use of absorbers,  that is, to scrub halogens from an incinerator's
effluent,  is the absorber the commenter refers to as a once-through
scrubber.   As such,  there are two sets of monitoring and testing
requirements in the model  rule (Appendix D of the CTG) for the two absorber
types just described.  For absorbers used in recovery systems,  a scrubbing
liquid temperature monitor and a specific gravity monitor are required,

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both with continuous recordkeeping.  For absorbers used after an
incinerator (a once-through scrubber), a pH monitoring device and flow
meter to measure scrubber liquid influent and inlet gas flow rates are
required, both with continuous recordkeeping.
F.6.2  Comment:  One commenter (IV-D-6) suggested that as an alternative to
monitoring low flow rate vents, engineering calculations, and/or mass
balances information should be allowed to demonstrate an exemption from
control requirements.
     Response:   In  order to be consistent with the draft HON, the EPA has
revised the section of the model rule [Section D.5(h)] addressing this
issue.   Engineering assessment is recommended in the model  rule as an
option to calculate process vent stream flow parameters for those streams
with a TRE index of 4.0 or greater.
F.6.3  Comment
     Two commenters (IV-D-4,  IV-D-6)  said that Section  D-5  of the CTG
document, "Performance Testing," should not be more restrictive than what
was proposed in the Enhanced Monitoring Guidelines for existing sources.
One commenter (IV-D-6) also suggested that an applicability paragraph be
added that excludes small sources.
     Response:   The draft  Enhanced Monitoring Guidelines for existing
sources has not been proposed, making it difficult to comment on stringency
comparison between  its requirements and those within this CTG.   With
respect to the applicability paragraph, it was difficult to interpret  if
commenter IV-D-6 was requesting an applicability cutoff for performance
testing or general  facility applicability.  However, it should be noted
that facilities with a very low capacity (less than 1 gigagram of chemicals
per year) were exempt from recommended RACT requirements.  Additionally,
the CTG has been revised to recommend exempting certain individual streams
with low flow rates from TRE testing.
F.6.4  Comment;  Two commenters (IV-D-3, IV-G-4) argued that requiring flow
indicators on individual streams prior to a control device  is an excessive
cost that is not necessary in determining when a flow is diverted.
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      One commenter (IV-D-3)  recommended  that  the  current  reference to flow
indicators in D.6(a)(2), (b)(2), and (c)(l) be eliminated and replaced with
language  similar to the following:
      (i)   Install  a flow  indicator  at  the  entrance  to  any bypass  line that
could divert the vent stream away from the control device to the
atmosphere; or
      (ii) Secure  the  bypass line valve  in the closed  position with
car-seal, locked,  or otherwise secured arrangement.  A visual inspection of
the secured arrangement shall be performed once a month to ensure that the
valve is  maintained in the closed position and that the vent stream is not
diverted  through the bypass line.
      Response:   The EPA considers it very  important to ensure that vent
streams are continuously vented to the flare  (or other combustion device).
The primary intent of the flow monitoring recommendation  in this CTG was to
provide a means for indicating when vent streams are bypassing the flare or
other combustion device.  The flow indicators envisioned  by the EPA were
intended  to provide an indication of flow or no flow,  and not to provide
quantitative estimates of flow rates.
      The  EPA has reevaluated the use of  flow  indicators  in process vent
streams in light of the comments received for the SOCMI Reactor Process
NSPS as proposed.  Because flow indicators located on the vent stream
between the emission source and the combustion device may be insufficient
to meet the intent of the CTG, the EPA has decided to alter the flow
indicator location.  The CTG will be revised to indicate  that the new flow
indicator location will be at the entrance to any bypass  line that could
divert the vent stream before it reaches the combustion 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 combustion device,  a performance test would
need to be conducted on the second combustion to determine if it meets the
control requirements.
      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 recommendation.   Language similar to the commenter's suggested
paragraph (ii)  have been added to the CTG document.  In addition, records
that show an  emission stream is hardpiped to a combustion source are

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sufficient to demonstrate that the entire flow will  be vented to the
combustion 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.
If the piping arrangement for the process changes, then it is recommended
that the facility revise and retain the information.
     The CTG was  revised to suggest  a flow indicator  be equipped to
indicate and record whether or not flow exists at least once every
15 minutes.  Because the monitor collects flow or no flow data on a
continuous basis, this additional recording would not be an additional
burden.  If an owner or operator believes that an alternate recording
frequency or placement of a flow indicator is equally appropriate, then the
owner or operator can petition the State regulating agency.
F.6.5  Comment:  One commenter (IV-D-1) said that the requirement that
temperature monitors be equipped "with strip charts" is too narrowly drawn.
The commenter pointed out that many instrument systems in the modern
chemical plant are computer driven and the recordkeeping is not via the
"old" strip chart method.  The commenter suggested that the EPA require
continuous temperature monitoring, without a reference to the recordkeeping
mode selected by the source.
     Response:  The  temperature  monitoring recording  requirements  have
been revised, omitting any specific reference to a strip chart.
F.6.6  Comment:  One commenter (IV-D-1) noted that on page D-9 of the draft
CTG, subparagraphs (a)(2), (b)(2) and (c)(l), require the installation of a
"flow indicator" on the vent stream to the control device.  The commenter
emphasized that difficulties were encountered when attempting to comply
with similar requirements promulgated in the NSPS for air oxidation unit
processes and distillation operations.  Specifically, the vent streams from
the affected distillation systems were hardpiped to a common flare header
with no means to automatically divert the vent stream to the atmosphere.
Each system had a nitrogen purge on its vent stream to the flare header to
control plugging caused by the polymerization of organics.  The continuous
nitrogen purge precludes accurate measurement of vent stream flow to the
flare.  The commenter suggested the problem may be widespread, noting that
a number of organic compounds will polymerize under the right set of
conditions.  In addition to causing line pluggage, the commenter added that

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polymerization can also plug flow measuring devices, negating any
opportunity to select appropriate instrumentation.  The commenter then
recommended adding a provision to this CTG that allows an appropriate
compliance alternative method for flow indication, with a reference to the
means by which a source could seek approval.
      Response:   The  paragraphs  cited in  the  comment  contain  a discussion
about the need to monitor the flow of streams before they are joined with
similar streams to a common control device.  As a result of public comments
from this CTG and the distillation operations NSPS, these paragraphs have
been deleted from the final CTG document for two reasons:  (1) the EPA is
no longer requiring that similar vent streams be combined due to technical
and safety concerns that may exist at some facilities (see response to
Comment F.3.5), and (2) the EPA has revised the purpose of flow indicators
so that they now continuously monitor the presence, not the extent, of vent
stream flow.  Please refer to the response to comment number F.6.4 to
determine how the flow indicator section is being revised in the CTG.  The
owner or operator can petition the State agency if it is felt that an
alternate method for flow indication should be conducted.
F.6.7  Comment;  One commenter (IV-D-1) cited a significant recordkeeping
burden in complying with requirements promulgated in the NSPS for air
oxidation processes and the NSPS for distillation operations, and that the
CTG contains the same recordkeeping requirements.  The commenter then
recommended that the source be allowed to select an annual performance test
as an alternative means of compliance.
      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 its continuous ability
to meet the standard.
F.6.8  Comment:  One commenter (IV-D-3) noted that the reporting
requirements for the control  and recovery devices in Section D.7(b) of the
CTG document require exceedance reports when temperatures or flows deviate
by more than a set level.  The commenter further noted that current
interpretations of reporting requirements have identified situations where

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"deviations" require reporting, even when the regulated vent stream has
been shut down for maintenance and a vent is not actually flowing to the
control or recovery device.  The commenter requested that language be added
to ensure that this reporting is required only during those periods when a
vent stream is actually flowing to the control or recovery device.
     Response:  The exceedance reporting requirement section of  the CTG is
being revised.  The final document will incorporate the language for these
requirements from the draft Enhanced Monitoring Guideline.
F.7  CONTROL  TECHNOLOGY
F.7.1  Comment:  Several commenters (IV-D-5, IV-D-6, IV-G-6, IV-G-7,
IV-G-8) argued that RACT should not be limited to combustion control
devices.  One commenter (IV-G-8) suggested that rather than choosing
combustion devices or the most widely applicable control technique and
critically analyzing the limitations of alternative methods, the CTG should
point out applications or guidelines that indicate when use of each
technique is appropriate.  The commenter was also disappointed that the EPA
had chosen to emphasize control devices that destroy rather than recover
solvents, noting that this decision seemed to be a counterproductive
solution to pollution prevention.
     Three  commenters  (IV-D-5,  IV-G-6,  IV-G-7)  recommended  that  catalytic
oxidation be recognized as an acceptable control alternative.  By excluding
catalytic oxidation in the CTG, one commenter (IV-D-5) expressed concern
that the EPA is unnecessarily limiting its use since the lengthy approval
process required for alternative controls effectively precludes their use
within the defined compliance time limit.
     Two  commenters  (IV-G-6,  IV-G-7)  provided data  to  support  the
conclusions that modern catalytic oxidation systems perform well in almost
all circumstances, require minimum maintenance, minimize the formation of
secondary air pollutants, and commonly achieve values as high as
99.0 percent destruction for years without interruption.  The commenters
requested that the CTG reflect this information when it is  issued in its
final form.
     One  commenter  (IV-G-7)  cited  personal  experience  that  has shown  that
catalytic oxidizers operate very successfully on SOCHI exhaust streams and
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 recommended  that  the  EPA delete the present statement In Section 3.1.4.3
 and  replace  It with the following new language:

      Catalytic oxidation  is very  effective in controlling  VOC
      emissions;  it is an  extremely  flexible technology  that can be
      applied to  a variety of SOCMI  processes.  It is basically a
      chemical  process which operates  at much  lower temperature than
      thermal incineration and thereby minimizes fuel and other costs.
      In addition, catalytic oxidation does not produce  secondary air
      emissions such  as NOX and CO as  occurs with thermal
      incineration.  High  destruction  efficiency (>98 percent) is
      achieved  through catalytic oxidation. Catalytic streams are
      successfully operating on SOCMI  vent streams.  The SOCMI
      exhausts  are generally very  clean  and are therefore suitable for
      catalytic systems.   The SOCMI  industry has been accustomed to
      using a variety  of process catalysts and are very  skilled in
      understanding and maintaining  catalytic  systems at maximum
      performance.  Sulfur resistant and halocarbon resistant
      catalysts are available when needed.

      One commenter (IV-D-6) stated  that recovery devices and other

 upstream process  changes should be allowed  to  demonstrate  RACT  control.

 Furthermore, to enable the  use of these  alternative  pollution prevention
 techniques,  a suitable before control emission  point must  be  defined.  The

 commenter  recommended the following definition  for before  control

 emissions:

      Emissions  after  the  first reflux/product recovery  condenser,  or
      actual  hourly average  emission  rate, after all  control  for the
      years 1987  to present, whichever is greater.

      Response:   It is not  the intent  of this  CTG to  limit  the owner  or

 operator to  only  one VOC control technology, many technologies  are
 presented  in the  CTG.  For  the purpose of calculating national  impacts,
 however, combustion via thermal incineration or  flaring was chosen as  the
 control technology.  This decision was based on  the wide applicability and
 ability of combustion devices to achieve  98 percent destruction efficiency

 for SOCMI reactor  and distillation vents.  Additionally, even though

 pollution prevention in the form of product or  solvent recovery may be more

 economical,  these  control techniques require modifications within the

 process and  are site specific, making it  difficult to generalize these

modifications across the entire industry.  Appropriate applications for

each control technology are given in Chapter 3.0 of the CTG.  Catalytic
                                    F-22
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incinerators are, in fact, recognized as acceptable alternative controls as
discussed in the CTG document.
     The  EPA appreciates  the  comment regarding Section 3.1.4.3 of the
document and has revised that section to incorporate some of the language
suggested.
F.7.2  Comment:  One commenter (IV-D-3) said that the monitoring
requirements for carbon adsorbers should be modified to accommodate the
various types of regeneration systems currently in use.  The commenter
recommended the following:
     •     All  references to  the use of  "steam" for carbon adsorbers be
           replaced with  the  term  "regeneration   stream."  Changing to
           this recommended language allows the owner  or operator to use
           either steam,  a regeneration  gas, heated nitrogen, or similar
           technologies in the absorber  system without requiring specific
           waivers  in  a case-by-case basis.
     •     The  recordkeeping  and reporting requirements associated with
           carbon absorber units refer only to "mass"  flow measurements.
           Rather than specifically referring to  mass, we recommend that
           either a mass  or volumetric flow rate  is appropriate.
     Response:   The EPA realizes that  steam is not the sole method of
carbon adsorber regeneration.   The CTG document has been revised to reflect
the commenters  recommendations to modify the monitoring requirements for
carbon adsorbers.
F.7.3  Comment:  One commenter (IV-G-5) expressed concern that two proposed
controlled techniques may pose worker safety or health hazards.
Specifically,  the commenter named the combustion of VOC's in flares with
high velocity steam injection nozzles,  and combustion of VOC's in boilers
or process heaters as potentially hazardous.  The commenter noted that the
safety concern  of high velocity steam injection nozzles is the increased
noise.   Also,  the variation in the flow rate and organic content of the
vent stream could lead to explosive mixtures with a boiler furnace.
     Response:   The proposed  control techniques discussed in  the CTG
document must be installed in compliance with Occupational Safety and
Health Administration  (OSHA)  requirements.  Specifically, the flares must
be installed at such a height and location to minimize noise.
     The  venting of streams to boiler  furnaces is listed  as  an  alternative
control technology because it is not appropriate for all vent streams for
the exact reasons the commenter listed.  As stated in the CTG, "variations
                                    F-23
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 in vent stream flow rate and/or heating value could affect the heat output
 or flame stability...and should be considered when using these combustion
 devices."
 F.7.4  Comment:  One commenter (IV-G-8) recommended that the discussion in
 the CTG regarding condensation as an emission control technique needs
 clarification.
      Regarding Section  3.2.3.1, the  commenter noted  that
 chlorofluorocarbons, hydrochlorofluorocarbons, and hydrofluorocarbons can
 be used in single stage or cascade cycles to reach condensation
 temperatures below -73 °C (-100 °F), and liquid chillers using d-limonene
 are capable of reaching temperatures below -62 °C (-80 °F).
      With  reference to  Section 3.2.3.2, the  commenter  stated  that
 condenser efficiencies are frequently in excess of 95 percent, with
 recovery by condensation working particularly well for low flow rates (less
 than 2,000 cubic feet per minute [cfm]) and high VOC concentration (greater
 than 5,000 ppmv).  The commenter said that it is below the 5,000 ppmv
 concentration level that the recovery efficiency of condensation drops
 below 95 percent, and, furthermore, since condensation is not recommended
 for use in applications involving concentration levels below 5,000 ppmv, it
 does not make sense for the CTG to state that "efficiencies of condensers
 usually vary from 50 to 95 percent."
      Regarding Section  3.2.3.3, the  commenter requested that  the CTG
 document state that condensation is applicable in many cases where other
 control methods are not, including when lower explosion limits are too
 high, when flow rates are too low; and when recovery rather than
 destruction is required.
      Response:   The ranges listed  in the CTG document  (e.g.,  "below
 -34 °C") include the specific examples cited by the commenter.
      In Section  3.2.3.2 of the draft CTG,  it  is stated that the condenser
efficiency ranges depend on the flow parameters of the vent stream and the
operating parameters of the condenser.   A statement has been added to the
CTG explaining that the higher efficiencies are expected for the low flow
 (less than 2,000 cubic feet per minute [cfm]), high VOC concentration
 (greater than 5,000 ppmv)  streams.  Finally,  the CTG document has been
revised to state those cases where condensation is applicable and other
control methods are not.

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F.8   EDITORIAL
F.8.1  Comment:  Two commenters (IV-D-6) recommended that the introduction
state clearly what sources are included and excluded by this CTG,
preferably in the opening paragraph.
      Response:  Chapter  1.0 of the  CTG document has been revised to
incorporate a discussion of the applicable chemicals.
F.8.2  Comment.  Four commenters (IV-D-3, IV-D-5,  IV-D-6, IV-G-2)  observed
that the flow rate cutoffs do not appear to be consistent,  and requested
additional clarification.  The commenters noted that the flow rate cutoff
in D.2(b)(3) is 0.011 scm/min (0.4 scfm), but the RACT summary on page 6-7
refers to the presumptive norm for RACT by requiring controls on streams
with a flow rate greater than 0.1 scfm.
      Response:  The  units listed  in D.2(b)(3) contained  a typographical
error in the draft CTG document; however, this comment is no longer of
concern because the low flow cutoff for individual streams will be
calculated by determining the flow rate which identifies those streams with
a TRE index less than or equal to 1.0 when the stream characteristics from
the data base are inserted into the TRE equation.   Furthermore, the
comparison of this number with the flow and concentration cutoff is no
longer of concern because the latter is being replaced with the TRE index
equation to determine applicability.
F.8.3  Comment:  Several commenters (IV-D-3, IV-D-5, IV-D-6, IV-G-2) said
that in Section D.6 of the CTG, paragraph (a)(l),  the temperature
monitoring requirements for incineration appear to be incomplete and
additional language (e.g., ±1 percent of temperature) is necessary.
      Response:  The  CTG  document  has been revised to reflect this  comment.
F.8.4  Comment;  Two commenters (IV-D-4, IV-D-6) argued that the definition
of "total organic compounds" should be changed to exclude all compounds
accepted by the EPA as photochemically nonreactive.
      Response:  The  EPA  agrees with this comment.   The current, updated
list of compounds considered photochemically nonreactive by the
Administrator has been incorporated into the document (see page D-5).
F.8.5  Comment:  One commenter (IV-D-3) requested that the use of the term
"recovery device" be clarified.  The commenter noted that the current
recovery device definition states that the equipment is capable of and  used
for the purpose of recovering chemicals for use, reuse, or sale.  The

                                    F-25
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commenter emphasized that situations exist where the recovered material
from an absorber or condenser does not technically meet the recovery device
definition and it would not be subject to the monitoring and reporting
standards of the rule.  In addition, the commenter stated that if the
concentration at the outlet vent of the condenser falls below the
concentration and flow cutoff, and if it is the only vent for the process,
then only minimum recordkeeping applies.  The commenter asserted that this
type of "recovery device" also meets the intent of the rule and that many
compliance interpretation issues could be eliminated by revising the
definition.  The definition recommended by the commenter is "...an
individual unit of equipment, used for the purposes of recovering chemicals
for use, reuse, sale, or treatment."
     Response:  The  EPA appreciates this comment  and the CTG document  has
been revised to reflect this comment.
F.8.6  Comment:  One commenter (IV-D-3) pointed out that the text that
identifies the examples in Figures 2-6 and 2-7 does not currently match the
diagrams.
     Response;  Figures 2-6  and  2-7 represent  specific  examples of  a
direct reactor process vent and a recovery vent applied to the vent stream
from a liquid phase reactor, respectively.   More specifically, Figure 2-6
presents a schematic of nitrobenzene production venting to the atmosphere,
whereas Figure 2-7 depicts an alkylation unit process used to produce
ethyl benzene.  The EPA believes the figures do correspond to the text.  The
EPA invites the commenter to call the EPA for further clarification if this
is still unclear.
F.8.7  Comment:  Two commenters (IV-D-5, IV-G-2) suggested that the
Chemical Abstracts Service (CAS) number of the individual chemicals listed
in Appendix A should be provided.
     Response:  The  EPA agrees with this comment  and the CTG document  has
been revised to reflect this comment.
F.8.8  Comment;  One commenter (IV-D-6) noted that in the Ks definition in
the middle of page D-6, Ks should be Kg.
     Response:  The  EPA agrees with this comment  and the document has  been
revised to reflect this comment.
F.8.9  Comment;  One commenter (IV-D-1) recommended that the definition of
"product" would be clearer if the EPA would define it as "any compound or

                                    F-26
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chemical listed in Appendix A which is produced as that chemical  for sale
as a final product, by-product, co-product, or intermediate or for use in
the production of other chemicals or compounds."
     Response:  The EPA agrees with this comment  and the CTG document has
been revised to reflect this comment.
F.8.10  Comment:   One commenter (IV-D-1) said that the definition of
"affected facility" would be easier to follow if it were changed as
follows:  "an affected facility is an individual reactor process or
distillation operation with its own individual recovery system (if any)  or
the combination of two or more reactor processes or distillation operations
and the common recovery system they share."  The commenter noted that
reactor processes and distillation columns are not single pieces of
equipment, but embrace several other components which are considered part
of the system.  The commenter suggested that rewording this definition
would help make this distinction more apparent to the reader.
     Response:  The EPA agrees with this comment  and the CTG document has
been revised to reflect this comment.
F.8.11  Comment:   One commenter (IV-D-1) noted that the CTG states that of
the three possible emission limitation formats, the regulatory agency
should consider applying the "percent reduction format" since the EPA
believes it "best represents performance capabilities of the control
devices used to comply with the RACT regulation."  The commenter suggested
that there are other opportunities which would present themselves for using
one of the other two formats.  The commenter then recommended that the
wording at the top of page 7-4 be changed in the second line by eliminating
"...are not preferred because they	"  The commenter noted that this does
not change the general intent of the statements contained on the page, but
does remove a direct inference that the other two formats should not be
used.
     Response:  This  comment  is  no  longer  applicable because  the
applicability format has been revised to incorporate the TRE index
equation.  The CTG now recommends reduction of VOC emissions until the TRE
index is greater than one.
F.8.12  Comment;   One commenter (IV-G-2) requested that any deviation from
the list of chemicals established in the corresponding NSPS for reactor
processes and distillation operations be explained in the CTG.

                                    F-27
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      Response:   The list of applicable chemicals  for this  CTG correspond

 to  all  appropriate  chemicals addressed by previous NSPS plus  chemicals in

 the SOCHI source category.  Any deviations in the list of chemicals in this

 CTG from the list presented in previous NSPS result from the  inclusion of
 SOCMI chemicals.

 F.8.13  Comment:  One commenter (IV-G-7) recommended the following language

 changes in Section  3.1.4.1:

      •      Paragraph 1,  sentence  5,  change to  read:   "Combustion  catalysts
            include  palladium and  platinum group metals, manganese oxide,
            copper oxide,  chromium and cobalt."

      •      Paragraph 3,  sentence  1,  charge to  read:   "The  operating
            temperatures  of combustion catalysts usually range from 500  °F
            to 800 OF."

      •      Paragraph 3,  sentence  3,  change to  read:   "Temperatures greater
            than 1,350 °F may result  in shortened  catalyst  life."   Delete
            the  rest of the original  sentence because it is not true  that
            the  catalyst  or substrate will evaporate  or melt at higher
            temperatures  (>1,200 °F).   In order  for a metal  substrate  to
            melt the temperature must exceed  2,600 °F."

      •      Paragraph 3,  add the following after the  last sentence:
            "Materials accumulated on the catalyst can be removed  by
            physical or chemical means,  thus  restoring the  catalyst
            activity to its original  (fresh)  level.   Condensed organics
            accumulated on the  catalyst can be  removed with thermal
            treatment.

      The commenter  also  stated that  not all  of  the poisons listed in

paragraph 3 of Section 3.1.4.1 are detrimental  to VOC  catalysts.  The

commenter suggested  that masking  of the catalyst by particulate or

carbon-based materials is  reversible, and catalysts are commercially

available to handle  many of the poisons listed, including sulfur,

halocarbons, and phosphorous.

      Response:   The EPA  agrees with  all these  comments and will  revise  the

CTG document to reflect them.

F.8.14  Comment:  One commenter (IV-G-7) said that the example cited  in

Section 3.1.4.2 is  an oversimplification and is not VOC species specific.

The commenter stated that  at 840  °F and a space velocity of 30,000/seconds

(the example shown), many  VOC's can be reduced by 99 percent  or more with

catalytic oxidation  technology.
                                    F-28
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      Response:   The  EPA  believes  that  the  commenter cited  an example that
verifies the referenced numbers in the document.  The CTG document stated
that "catalytic oxidizers have been reported to achieve efficiencies of
98 percent or greater," and the 99 percent reduction reported by the
commenter does fall within the 98 percent or greater range.
F.8.15  Comment.  One commenter (IV-G-7) recommended that sentence 2 of
paragraph 2 in Section 3.3 be deleted.  The commenter stated that there are
not technical obstacles preventing catalytic oxidation from achieving at
least 98 percent destruction efficiency, and that this level of control is
becoming the rule rather than the exception.
      Response;   The  sentence  the  commenter is  referring  to states that,
with the exception of catalytic oxidizers, the other combustion devices
listed are applicable to a wide range of vent streams.  The EPA agrees with
this comment and has revised the CTG document to reflect this comment.
F.8.16  Comment:  One commenter (IV-G-7) requested that several statements
in Section 6.2 of the draft CTG be modified to present a more neutral
treatment of catalytic oxidation and to ensure that this technology is not
excluded from consideration as an available control technology.
      Response:   The  EPA  has revised the CTG document  to  reflect this
request.
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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing]
1. REPORT NO.
  EPA-450/4-91-031
             3. RECIPIENT'S ACCESSION NO
4. TITLE AND SUBTITLE
Control  of Volatile Organic  Compound Emissions from
Reactor  Processes and Distillation Operations Processes
in  the Synthetic Organic Chemical Manufacturing Industry
                                                           5. REPORT DATE
              August
             6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
                                                           8 PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  Office  of Air Quality Planning and Standards
  U.S.  Environmental Protection  Agency
  Research Triangle Park, North  Carolina  27711
                                                            10 PROGRAM ELEMENT NO
             11 CONTRACT/GRANT NO
             68-D1-0117
12. SPONSORING AGENCY NAME AND ADDRESS
 Director,  Office of Air Quality Planning and Standards
 Office  of  Air and Radiation
 U.S.  Environmental Protection  Agency
 Research Triangle Park, North  Carolina  27711    	
                                                            13. TYPE OF REPORT AND PERIOD COVERED
             14. SPONSORING AGENCY CODE


              EPA/200/04
15 SUPPLEMENTARY NOTES
16. ABSTRACT

        This report provides  the necessary guidance  for State and local air  pollution
   authorities to control emissions of volatile organic compounds (VOC's)  from
   reactor processes and distillation operations  in  the synthetic organic  chemical
   manufacturing industry.  Emissions are characterized and VOC control options are
   described.  A reasonably available control technology (RACT) is defined for process
   vents from reactor processes and distillation  operations.  Information  on the cost
   of  control, environmental  impacts of the controls and a "model rule" are  provided.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                              b.IDENTIFIERS/OPEN ENDED TERMS
                                                                         c.  COSATi Field/Group
 Air Pollution
 Pollution Control
 Volatile Organic Compounds
 Synthetic Organic Chemical Manufacturing
   Industry
 Reactor Processes
 Distillation Operations
 Process Vents	
Air Pollution Control
Synthetic  Organic Chemica
  Manufacturing Industry
                          1
18. DISTRIBUTION STATEMENT

 Release Unlimited
19 SECURITY CLASS
Unclassified
                                                              7»J Reports
                           • I. NO. OF PAGES
                             275
                                              20 SECURITY CLASS (Tins page/
                                               Unclassified
                                                                         22. PRICE
EPA Form 2220-1 (R«v. 4-77)   PREVIOUS EDITION is OBSOLETE
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