United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-90-016b
March 1993
Air
Reactor Final
Processes in the EIS
Synthetic Organic
Chemical
Manufacturing
Industry--
Background
Information for
Promulgated
Standards
-------
-------
EPA-450/3-90-016b
Reactor Processes in the
Synthetic Organic Chemical
Manufacturing Industry -
Background Information
for Promulgated Standards
Emission Standards Division
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
March 1993
-------
-------
U. S. ENVIRONMENTAL PROTECTION AGENCY
Background Information
and Final Environmental Impact Statement
for Volatile Organic Compound Emissions
from Reactor Processes in
Synthetic Organic Chemical- Manufacturing
Prepared by:
Bruce C. Jordan ~ ~ (Date)
Director, Emission Standards Division
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
1. The promulgated standards of performance will limit
emissions of volatile organic compounds from new, modified
and reconstructed reactor processes. Section ill of the
Clean Air Act (.42 U.S.C. 7411), as amended, directs the
Administrator to establish standards of performance for- any
category of new stationary source of air pollution that
. . . causes or contributes significantly to air pollution
which may reasonably be anticipated to endanger public
health or welfare." .
2. Copies of this document have been sent to the following
Federal Departments: Labor, Health and Human Services
Defense, Transportation, Agriculture, Commerce, Interior
and Energy; the National Science Foundation; State and
Territorial Air Pollution Program Administrators- EPA
Regional Administrators; Local Air Pollution Control
Officials; Office of Management and Budget; and other
interested parties.
3. For additional information contact:
Ms. Sheila Milliken
U. S. Environmental Protection Agency
Standards Development Branch (MD-13)
Research Triangle Park, North Carolina 27711
Telephone: (919) 541-2625
4. Copies of this document may. be-obtained from:
U. S. Environmental Protection Agency
Library (MD-35)
Research Triangle Park, North Carolina 27711
Telephone: (919) 541-2777
National Technical Information Service
5285 Port Royal Road
Springfield, Virginia 22161
11
-------
-------
This report has been reviewed by the Emission Standards Division
of the Office of Air Quality Planning and Standards, EPA, and
approved for publication. Mention of trade names or commercial
products is not intended to constitute endorsement or
recommendation for use. Copies of this report are available
through the Library Services Office (MD-35), U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711
or from National Technical Information Services, 5285 Port Roval
Road,,Springfield, Virginia 22161. •
in
-------
-------
CONTENTS
Disclaimer
• ....... iii
v
1.0 Summary
1.1 Summary of Changes Since Proposal! * ." ." * * * 1-1
1.1.1 Applicability of the Standards." .* " * * 1-1
1.1.2 Standardization of the Total
Resource Effectiveness Equation .... 1-2
1.1.3 Flow Indicators * "' * 1-2
1.1.4 Primary Fuel Systems. ...'..... lls
1.1.5 Vent Streams Fired as a Secondary Fuel"
or Introduced with Combustion Air . . . 1-3
1.1.6 Temperature Monitoring in Firebox . . .* 1-3
1.1.7 Carbon Bed Cool Down Temperature. . . * 1-4
1.1.8 Definition of Total Organic
Compounds 1-4
1.2 Summary of Impacts of Promulgated" Act ion .* '. '. 1-4
1.2.1 Alternatives to Promulgated Action. . .' 1-4
1.2.2 Environmental Impacts of Promulgated
-Action 1_5
1.2.3 Energy and Economic Impacts of
Promulgated Action !_5
1.2.4 Other Considerations ] ." , [ ' 1-5
1.2.4.1 Irreversible and Irretrievable
Commitment of Resources. . . . 1-5
1.2.4.2 Environmental and Energy
Impacts of Delayed
Standards , . . . . . .1-5
Summary of Public Comments 21
2.1 Applicability of the Standards 9*1
2.2 Definitions 2 12
2.3 Selection of Best Demonstrated
Technology ..... -> 1fl
2.4 Format of Standards 2 19
2.5 Modification/Reconstruction. " -?~o-v
2:..6- Monitoring . .. ] [' \ ~ ] ~ " •' ' t'H
2.7 Performance Testing and Measurement "
Methods 2
2.8 Reporting and Recordkeeping.* . '. '. ?~lt
2.9 General
2.0
-------
-------
TABLES
Number
Page
2-1 List of Commenters on the Proposed Standards
of Performance for Reactor Processes in the
Synthetic Organic Chemical Manufacturing
Industry 2_2
2-2 Monitoring and Reporting/Recordkeeping
Requirements for Complying with
98 Weight-Percent Reduction of TOG
Emissions or a Limit of 20 ppmv 2-48
2-3 Monitoring and Reporting/Recordkeeping
for Affected Facilities Complying with
Flare Specifications. 2-49
2-4 Monitoring and Reporting/Recordkeeping
Requirements for Maintaining a TRE
Index Value >l.o 2-50
-------
-------
1.0- SUMMARY
On June 29, 1990, the Environmental Protection Agency (EPA)
proposed standards of performance for reactor processes in the
synthetic organic chemical manufacturing industry (SOCMI)
(55 FR 26953) under the authority of Section 111 of the Clean Air
Act (CAA). Public comments were requested on the proposal in the
Federal Register. Fifteen commenters, most of whom were industry
representatives, submitted written comments during the comment
period. Two of these commenters submitted additional comments
after the comment period had ended. Comments were also received
from a State environmental protection department. The comments
that were submitted, along with responses .to these comments, are
summarized in this document. The comments and subsequent
responses serve as the basis for the revisions made to the
regulation between proposal and promulgation.
1.1 SUMMARY OF CHANGES SINCE PROPOSAL
Several changes and clarifications were made in the
regulation as a result of the review of public comments. These
changes and clarifications were made in the following areas:
(a) applicability of the standards; (b) standardization of the •
total resource effectiveness (TRE) equation; (c) flow indicators;
(d) primary fuel systems; (e) vent streams fired through a
secondary burner or with combustion air; (f) temperature
monitoring in firebox; (g) carbon bed cool down temperature; and
(h) definition of total organic compounds (TOO.
1-1-1 Applicability of the St^nrixrrta
In order to clarify the applicability of the standards,
several exemptions have been added to the reactors NSPS. An
exemption has been added to the standards for those reactor
processes subject to the distillation NSPS, those reactor
.processes producing beverage alcohols, and those reactor
processes subject to the NSPS for polymer manufacturing. A
1-1
-------
definition for "relief valve" has been added to clarify that
relief valves are not covered by the reactors NSPS. Lastly, an
exemption from emission control has been added for those reactor
processes with vent stream concentrations of TOG less than
300 ppmv as measured by Method 18 or less than 150 ppmv (or
0.50 x 300 ppmv) as measured by Method 25A. For demonstrating
applicability, Method 25A will be allowed as an alternate
screening method to Method 18 for those owners or operators
seeking this exemption.
1•1•2 Standardization of the Total Resource Effectiveness
Equation ~
Table 1 of the regulation for reactor processes presents the
coefficients associated with the THE index equation. The TRE
coefficients that were proposed for the reactors NSSPS differ
slightly from those promulgated for the distillation NSPS
(55 PR 26947)and air oxidation NSfcS (55 PR 269...) because the
derivations were based on different cost years. The difference,
however, is insignificant. To reduce confusion and to ensure
consistency in calculating the TRE values, the TRE coefficients
are being standardized in the final reactors rule.
1.1.3 Plow Indicators
Because flow indicators located in the vent pipe between the
emission source and the control device prior to being joined with
another vent stream may be insufficient to meet the intent of the
standard, the flow indicator position is, being altered. The new
location would be at the entrance to any bypass line that could
divert the vent stream to the atmosphere before it reaches the
control device. In addition, the frequency of recording the flow
indicator results will be changed to at least once every
IS minutes rather than once per hour. More frequent collection
of flow/no flow data is appropriate when the purpose of the
monitoring is to detect flow to the atmosphere rather than to a
control device. Further, an alternate provision is being added
for those facilities that use a car-seal or a lock-and-key type
configuration to maintain the bypass line closed during normal
1-2
-------
operations. A once per month visual inspection will be required.
1.1.4 Primary Fuel
The proposed standard required performance testing and
monitoring for boilers and process heaters with heat input
capacities less than 44 MW (150 million Btu/hr) . The final
standards do not require testing and monitoring for boilers and
process heaters when the reactor proces vent stream is mixed with
the primary fuel. When the vent stream passes through the flame
front it would, on average, be combusted at higher temperatures
than if introduced with combustion air. Also, emission factor
calculations (AP-42) and submitted test results indicate the
expected efficiency would be greater than 99.99 percent for
primary fuel use. This information indicates that a vent stream
combusted as a primary fuel woulof achieve greater combustion
efficiency than the 98 percent level required by the proposed
standards. For this reason, performance testing and temperature
monitoring for "these boilers are being deleted. Also, owners or
operators who are using a control device to comply with the
standards must maintain a schematic diagram of the affected vent
stream, collection system, fuel system, control device (s>, and
bypass systems.
1-1. S Vent Streams Fired as a Secondary Fuel or Infcynrin-f P>H wifh
Combustion Air " ~~ - ~ - ^^
For those affected vent streams that are fired as a
secondary fuel or introduced with combustion air prior to being
combusted in a process heater or boiler, an initial performance
test using Method 18 will still be required. However, a
requirement is being added to the standards that these sources
test the combined streams (including the fuel plus the affected-
vent stream) to determine if total TOG' (minus methane and ethane)
is reduced by 98 percent or to 20 ppmv.
'1.1.6 Temperature Monitoring in Pirrghmr
To clarify placement of the temperature monitoring device
for the firebox, a change has been made to the incinerator
monitoring provisions . It may be difficult to install the
1-3,
-------
monitoring device in the firebox because of radiant, heat from the
flame; therefore, an alternate provision is being, added that
allows the temperature monitor to be placed in the ductwork
immediately downstream of the firebox in the incinerator.
1.1.7 Carbon Bed Cool Down Temperature
To avoid penalizing those owners or operators who are
operating their carbon beds at lower, more efficient
temperatures, a minimum cool down temperature within 5°C of the
temperature achieved during the performance test is being, added
as an alternative to the proposed requirement. The proposed
requirement allows a cool down temperature- within 10 percent of
the temperature achieved during the performance test.
1.1.8 Definition of Total Organic Compounds
To clarify the definition of TOG, the current list of
Federal Register citations identifying compounds th=it the
Administrator has determined contribute to the formation of ozone
will be listed in the preamble. However, 'the definition of TOG
in the standards will retain the language "... those compounds
that the Administrator has determined do not contribute
appreciably to the formation of ozone are to be excluded." The
specific compounds will not be listed because they may be updated
periodically. By defining TOG in this manner, any changes that
the Administrator makes to the list of compounds would be
automatically incorporated into the definition of TOG in the
standard.
1.2 SUMMARY OF IMPACTS OF PROMULGATED ACTION
1.2.1 Alternatives to Promulgated Action
The regulatory alternatives are discussed in Chapter 6.0 of
the proposal BID. These regulatory alternatives reflect the
different estimated percentages of facilities required to reduce
emissions by 98 weight-percent or to 20 parts per million by
volume (ppmv) under a particular cost-effectiveness cutoff.
These regulatory alternatives were used for selection of the best
demonstrated technology (BDT), considering the estimated cost
impacts, nonair quality health impacts, environmental impacts,
1-4
-------
and economic impacts associated with each alternative. These
alternatives have not been changed.
1>2'2 Environmental Impacts of Promilgaf.ed Action
The changes in the regulation will have a negligible impact
on the air quality impacts, water quality impacts, and solid
waste impacts attributed to the standards as originally proposed.
These impacts are described in Chapter 7.0 of the proposal BID
. and now constitute the final Environmental Impact Statement for
the promulgated standards.
1-2-3 Energy and Economic Impacts of Promilqat-.ed Action
Section 7.5 of the proposal BID describes the energy, impacts
and Chapter 9.0 describes the economic impacts of the proposed
standards. The changes in the regulation described above will
have a negligible effect on these impacts.
1-2.4 Other Consideration^
-1-2'4-1 Irreversible and irretrievable Commitment: of
Resources . Chapter 7.0 of the proposal BID concludes that other
than fuels required for the operation of volatile organic
compounds (VOC's) control equipment, there, is no apparent
irreversible or irretrievable commitment of resources associated
with the standards. The use of the THE concept encourages the
use of recovery techniques or process changes to recover
pollutants' as products. The control of VOC emissions using
recovery techniques or process changes might be an alternative to
adding combustion controls for some reactor process facilities.
This would result in the conservation of both chemicals and
fuels. The changes in the regulation described above will have
no impact on the commitment of resources.
1 ' 2 • 4 ' 2 Environmental and Energy Imnact-.a of Delaer! '
Standards. Table 1-1 -in the proposal BID contains a- summary of
the estimated environmental and energy impacts associated with
promulgation of the standards. If the standards were delayed
adverse impacts on air quality could result. A delay in
promulgation would mean that affected facilities would be
controlled to the level specified in the appropriate State
1 - 5".
-------
implementation plan (SIP) . Emission levels would consequently be
higher than would be the case if the standards were in effect.
1-6
-------
2.0 SUMMARY OF PUBLIC COMMENTS
A total of 17 letters (2 conmenters submitted 2 letters)
commenting on the proposed standards were received. A public
hearing on the proposed standards was not requested. The'
17 comment letters have been recorded and placed in the docket.
The list of commenters, their affiliation, and the
U. S. Environmental Protection Agency (EPA) docket number for
each of the comments are shown in Table 2-1. The docket
reference is indicated in parentheses in each comment. Unless
otherwise noted, all docket references are part of Docket
No. A-83-29, Category IV. The comments have been organized into
the following 9 categories:
•
• Applicability of the Standards
• Definitions
• Selection of Best Demonstrated Technology
» Format of the Standards
• Modification and Reconstruction
• Monitoring
• Performance Testing and Measurement Methods
. • Reporting and Recordkeeping
• General
2 .1. APPLICABILITY OF-' THE. STANDARDS..
2.1.1 Comment
Two commenters (IV-D-01, IV-D-ll) requested that a specific
exemption be added for reactor processes that do not discharge a
vent stream directly or indirectly into the atmosphere. One
commenter (IV-D-01) stated that those reactors, discharging
directly into a distillation unit subject to Subpart NNN should
2-1
-------
COMMENTERS ON THE
«„ REACTOR PROCESSES J.N THE qv
ORGANIC CHEMICAL MANUFACTURING IND?STR?
Docket Number A-83-29, IV
Mr. L. A. Mattioli
Manager, Pollution Control
Allied- Signal, Incorporated
Post Office Box 1017
Marcus Hook, Pennsylvania 19061
Mr. Brian L. Taranto
l^nn0^en^al1Affairs Department
Exxon Chemxcal Americas
Post Office Box 3272
Houston, Texas 77253-3272
Ms. *;,ary jr. Legatski
Manager, Government Affairs
Synthetic Organic Chemical
Docket
reference
D-l
D-2
D-3
r ,
Connecticut Avenue, NW
Washington, B.C. 20036-1702
Mr. John Stein
Incorporated
Enslnesr in*
.D-4
Washington, D.C. '20006
Mr. Paul F. Cash
Manager, Environmental Control
D-5
Post Office Box 1037
Princeton, New Jersey 03543-1037
Mr. Richard L. Waters
Armstrong, Teasdale, Schlaflv,
Davis & Dicus
One Metropolitan Square
St. Louis, Missouri 63102-2740
D-6
2-2
(continued)
-------
TABLE 2-1. (Conti
nued)
Addressee
55P-
«° KS.'SSS
Ms Lynne j. Omlie
General Counsel '
or
2030 Building >
Jillard H. Dow Center
ixdla n
* - Geraldine v. Cox
M Street Ass°ciation
*shington, D.C. 20037
Docket
reference
D-7
D-8
D-9
D-10
D-H
D-12
2-3
'^••^^
(continued)
-------
TABLE 2-1. (Continued)
Addressee ' Docket
reference
Mr. Albert F. Appleton - n .,,
Commissioner U--LJ
City of New York Department of
Environmental Protection
2358 Municipal Building
New York, New York 10007
Ms. Vivian M. Mclntire n , .
Environmental Affairs u-J.^
Eastman Chemical Company (Kodak)
Post Office Box 511
Kingsport, Tennessee 37662
Mr. Paul M. King D
Corporate Counsel, Environment,
Health & Safety
PPG Industries, Incorporated
One PPG Place
Pittsburgh, Pennsylvania 15272
Mr. C. Bruce Barbre G -
Environmental Coordinator
Baton Rouge Chemical Plant
Exxon Chemical Americas
Post Office Box 241
Baton Rouge, Louisiana 70821-0241
Mr. Richard Sigman G -
Associate Director, Air Programs
Chemical Manufacturers Association
2501 M Street, NW
Washington, D.C. 20037
2-4
-------
be exempt from this standard. This commenter pointed out that
monitoring and recordkeeping requirements for such units would be
redundant and unnecessary.
A second commenter (IV-D-ll) remarked that the regulation is
written as if all reactor processes create a vent stream
requiring downstream controls.' This commenter called for a
specific exemption in Section 60.700(c) to eliminate confusion
for those reactor processes that do not emit a vent stream
directly or indirectly into the atmosphere.
Response
The EPA agrees that a reactor process vent stream routed
through a distillation unit subject to 40 CFR 60, Subpart NNN for
distillation operations before it is released to the air would be
subject to the provisions of Subpart NNN rather than Subpart RRR
for reactor processes. To avoid confusion with possible overlap
concerning applicability of these two standards, an additional
exemption is being added to Section 60.700(c) (5) which states:
If the vent stream from an affected facility is routed
to a distillation unit subject to Subpart NNN and has
no other releases to the air except for a pressure
relief valve, the facility is exempt from all
provisions of this subpart except for recordkeeoinq and
reporting in Section 60..70S(r). *
Recordkeeping and reporting requirements are being revised
to eliminate redundant reporting. These reactor processes are
required only to submit'an initial notification of this
particular process design and to maintain a schematic of the
overall process design for the life of the equipment. No other
records or reports -would be required unless process design
changes are made. Provided the process design change does not
change the applicability status, to: the-: reactor or distillation
new source- performance standards (NSPS), che owner or operator
would only need to submit the process design change to the
Administrator and maintain documentation of the change for the
life of the equipment.
2-5V
-------
Recordkeeping and reporting requirements in
Section 60.705(r) for these operations will be revised to read as
follows:
Each owner or operator who seeks to demonstrate
compliance with Section 60.700(c)(5) shall submit to
the Administrator a process design description as part
of the initial report. This process design description
shall be retained for the life of the process. No
other records or reports would be reouired unless
process changes are made.
2.1.2 Comment
One commenter (IV-D-01) stated that the proposed regulation
was unclear concerning those reactors that only vent through
relief valves during emergencies. This commenter felt that
reactors venting through relief valves only during emergencies
should be exempt from the regulations.
Response
Most reactors typically do possess relief valves for
purposes of relieving pressure buildup. It is not the intent of
the proposed reactors NSPS to cover pressure relief valve
discharges. In the proposed rule, relief valve discharges were
specifically excluded from coverage under the definition of "vent
stream." This definition has been retained in the final rule.
In addition, a definition for "relief valve" has been added to
Section 60.701 to clarify this term as follows:
Relief valve means a valve used only to release an
unplanned, nonroutine discharge. A relief valve
discharge results from an operator error, a malfunction
such as a power failure or equipment failure, or other
unexpected cause that requires immediate venting of gas
from process equipment in order to avoid safety hazards
or equipment damage.
2.1.3 Comment
Two commenters (IV-D-02, IV-D-08) expressed concern about
the list of chemicals covered by the reactors NSPS. One
commenter (IV-D-02) stated that some of the chemicals listed in
the standard for reactors are used in processes covered by other
NSPS besides the one for distillation operations. The commenter
-------
stressed that this overlap is confusing and that dual
applicability of the standards needs to be avoided.
In reviewing the list of chemicals in Section 60.707, one
connnenter (IV-D-08) noted an overlap with the chemicals listed in
the air oxidation NSPS. This commenter reviewed its processes
for air oxidation applicability and determined that several of
the chemicals shown on the air oxidation list were not produced
by air oxidation processes, but were produced via the reactor
process route. This commenter also found that the converse was
true. This commenter pointed out that on page 3-6 of Table 3-2
in the "Reactor Processes in Synthetic Organic Chemical
Manufacturing Industry--Background Information for Proposed
Standards" (Proposal BID for Reactors) it is stated that
"26 chemicals are produced 'solely- by nonreactor processes,
specifically by air oxidation, distillation, or other nonreactor
processes." The commenter felt that including these chemicals on
the list of 173 chemicals in Section 60.707 would confuse the
regulated community. The commenter recommended that these
26 chemicals be removed^from the list or, alternatively, a
provision be included stating that where one of the chemicals
listed in Section 60.707 is produced by a process other than a
reactor process, that process is not subject to the standards.
Response
In addition to the proposed reactors NSPS, there are two
other final NSPS that cover process vents: the air oxidation
NSPS (40 CFR 60, Subpart III) and the distillation NSPS
(40 CFR 60, Subpart NNN). Each NSPS includes a separate list of
chemicals. In some cases, the listed chemicals overlap between
the three SOCMI NSPS. This overlap exists because various
chemicals can potentially be manufactured via different
processes. The type of process by which the chemical is produced
will determine to which of the three SOCMI NSPS a particular
process vent would be subject. Most SOCMI product processes
would be covered by two NSPS--the distillation NSPS and either
the air oxidation NSPS or reactors NSPS. However, in no case
2 - 7
-------
would a particular process vent stream be regulated by more than
one of the three SOCMI NSPS.
The standard is clear that if a facility produces a chemical
listed in Section 60.707 by a reactor process, then production of
that chemical is subject to the-reactors NSPS. As described in
Section 60.700(b), if an affected facility does not produce any
of the 173 chemicals listed in Section 60.707 via one or more
reactor processes, then that facility is not subject to the
reactors NSPS. The list of 173 chemicals was developed based on
all chemical production routes that are currently used and
expected to remain competitive in the future for synthetic
organic chemicals produced by reactor processes. The list in
Section 60.707 may include chemicals currently produced by
nonreactor processes. However, these chemicals were included on
the list because available data indicated that some have in the
past been produced by reactor processes, and that they may, at
some time in the future, be produced by reactor processes. •
2.1.4 Comment
Four commenters (IV-D-04, IV-D-06, IV-D-07, IV-D-09)
expressed concern about the applicability of this NSPS to ethanol
created by the natural breakdown of sugars, a process used in the
production of food and beverage alcohols. These commenters noted
that the intended scope of this rule is virtually identical to
the distillation NSPS and that production of beverage alcohols is
specifically exempt from the distillation NSPS. To remain
consistent with previous rulemakings, these commenters urged that
the regulation of beverage alcohol be specifically exempt from
the reactors NSPS. One commenter (IV-D-09) also pointed out that
the Proposal BID for reactors expressly excludes ethanol produced
for human consumption from the scope of the reactors NSPS. One
commenter (IV-D-06) added that the description of affected
facilities and the definition of "reactor processes" are broad
enough to encompass ethanol generated directly and indirectly
from food manufacturing.
2-8
-------
Response
The EPA agrees with the*commenter that the intended scope of
the reactors NSPS'is very similar to the distillation NSPS and
that neither NSPS is intended to apply to ethanol created by the
natural production of beverage alcohols. These sources are not
included on the priority list of sources for which standards are
to be promulgated and, as indicated in the notice announcing
EPA's promulgation of the NSPS Priority List (44 PR 49222), are
not within the scope of the SOCMI source category. For this
reason, an exemption similar to the one that appears in the
distillation NSPS will be added to Section 60.700(c)(6) in the
reactors NSPS. This provision will specifically exempt the
production of beverage alcohols from the reactors NSPS.
Similarly, it .is not the intent of the reactors NSPS to
regulate ethanol that is generated either directly or indirectly
during food manufacturing. Ethanol generated during baking or
other food manufacturing processes is produced neither for sale
nor for further use. Based on the definition of "product" in
Section 60.611, ethanol generated during food manufacturing would
not be considered a product and, therefore, would not be subject
to the reactors NSPS.
2.1.5 Comment
One commenter (IV-D-05) stated that if the definition of
"product" in the regulation includes raw materials, then those
facilities that use raw materials listed under Section 60.707 and
that are subject to the provisions of the NSPS for polymer
manufacturing (Subpart DDD), should be exempt from the reactors
NSPS. This commenter suggested an exemption which reads: "Any
reactor process that is subject to the provisions of Subpart DDD
is not an affected facility."
Response
It is not the intent of the reactors NSPS to regulate
process vents that are subject to the NSPS for polymer
manufacturing under 40 CFR 60, Subpart DDD (55 PR 51010). To
ensure that these facilities are not subject to both standards,
an exemption identical to the one that appears- in the
2-9
-------
distillation NSPS will be added to Section 60.700(c)(7) of the
reactors NSPS. This exemption will exclude from regulation under
the reactors NSPS any reactor process that is subject'to the
provisions of Subpart DDD for polymer manufacturing.
2.1.6 Comment
One commenter (IV-D-11) indicated that an exemption or a
minimum emission rate should be added to the low flow provision
to exclude vent streams that are greater than the minimum flow
rate of 0.011 scm/min (0.39 scfm) but that contain relatively low
concentrations of total organic compounds (TOG). The commenter
felt that this exemption is needed because it is conceivable that
a concentrated stream with a low flow rate [less tha.n
0.011 scm/min (0.39 scfm)] could contain higher emissions
(greater than 20 ppm) than a dilute vent stream with a large flow
rate, making the control cost significant.
Response
In reevaluating the applicability criteria of the reactors
NSPS, a low concentration cutoff of 300 ppmv has been added to
the standard. The low concentration exemption was established so
sources would not have to bear the unnecessary cost of
determining the THE index value. The cutoff was set such that
the TRE index value would not be less than 1.0 for this low
concentration stream even if the stream heat content and flow
were worst case. Below this concentration level, the owner or
operator would not be required to make an assessment of the TRE
index value for a vent stream. This level was set as the minimum
concentration level below which the TRE index value would always
be expected to exceed a value of 1.0. Measurement of the
concentration level of a vent stream could be made using
Reference Method 18. If the resulting concentration value is
less than 300 ppmv TOC, then a TRE calculation is noc needed and
combustion is not required. The basis for this 300 ppmv level is
documented in a memorandum entitled, "Selection of the Low
Concentration Cutoff" (Docket No. A-83-29, Item No. IV-B-1).
Alternatively, Reference Method 25A could be used as a screening
method in lieu of Method 13. However, if Method 25A is used, the
2-10
-------
measured concentration of TOC must be less than 150 ppmv to
qualify for the exemption. See Comment 2.7.4 for further
discussion.
The total cost of control per unit of VOC removed could vary
considerably among the different types-of reactor process vent
streams due to variations 'in the vent stream characteristics of
flow rate, heat content, and concentration of organic compounds.
For this reason, the efficiency of controlling a particular vent
stream is taken into consideration in the regulation by the TRE
calculation. An additional cutoff based on minimum emission is
not needed.
The standard also contains a mechanism for exempting any
vent stream for which compliance would be unreasonably costly.
This means of measuring the cost of control is embodied in the
total resource effectiveness (TRE) index. Equations are included
in the regulation for determining the TRE index of a vent stream
from an affected facility.
2.1.7 Comment
One commenter (IV-D-15) stated that Section 60.707 should be
amended to delete phosgene from the list of chemicals affected by
Subpart RRR. The commenter felt that it has been adequately
demonstrated to the Agency in past industry studies that phosgene
is not photochemically reactive.
Response
Phosgene is included on EPA's list of photochemically
reactive chemicals. Phosgene is also included on the list of
chemicals subject to the reactors NSPS in Section 60.709.
Because air emissions of phosgene could result from reactor
processes, it will remain on EPA's list of chemicals subject to
the reactors NSPS. In addition, phosgene is a highly toxic
compound. No additional supporting information is available that
warrants removal of phosgene from the reactors NSPS chemicals
list. Phosgene will be retained on the list of chemicals subject
to the reactors NSPS.
_ .2-11
-------
2.1.8 Comment
One commenter (IV-G-01) questioned whether a vent stream
that is mixed and used as a primary fuel in a fuel gas system
comprised of boilers and process heaters rather than as a product
in subsequent chemical processes would-be subject to the reactors
NSPS.
Response
For any chemical listed in Section 60.707 that is being
produced as a product by reactor processes, the resulting vent
stream is required to be controlled to a level sufficient to meet
the standard regardless of whether that resulting vent stream is
routed for further use as a primary fuel. However, as discussed
later in response to Comment 2.7.7, performance testing and
temperature monitoring requirements are being deleted from the
standards for those affected vent streams being combusted as
primary fuel in boilers and process heaters. To distinguish
between fuel types, definitions for primary fuel and secondary
fuel will be added to Section 60.702 as follows:
Primary fuel means the fuel fired through a burner or a
number of similar burners. The primary fuel provides
the principal heat input to the device, and the amount
of fuel is sufficient to sustain operation without the
addition of other fuels.
Secondary fuel means a fuel fired through a burner other
than a primary fuel burner. The secondary fuel may provide
supplementary heat in addition to the heat provided by the
primary fuel.
2.2 DEFINITIONS
2.2.1 Comment
One commenter (IV-D-01) requested a clarification to ensure
consistency in the definition of TOC. This commenter pointed out
that the definition of TOC in Section 60.701 of the reactors NSPS
excludes "... those compounds that, in the future,, the
Administrator has determined do not contribute appreciably to the
formation of ozone . . . ." This commenter speculated that EPA
is intending to exclude new hydrofluorocarbons and
hydrochlorofluorocarbons that were mentioned in 54 FR 1988,
2-12
-------
published on January 18, 1989. The commenter pointed out that
the definition of TOC in the distillation NSPS does not include
the compounds mentioned in 54 FR 1988.
Response
The EPA did intend to exclude from the definition of TOC in
Section 60.701 specific compounds that the Administrator has
determined do not contribute appreciably to the formation of
ozone. The current list of exempt compounds, which is identified
in separate Federal Register notices (54 FR 1988, 42 FR 35314,
44 FR 32042, 45 FR 32424, 45 FR 48941), is as follows: methane;
ethane; 1,1,1-trichloroethane; methylene chloride;
trichlorofluoromethane; dichlorodifluoromethane;
chlorodifluoromethane; trifluoromethane;
trichlorotrifluoroethane; dichlorotetrafluoroethane;
chloropentafluoroethane; dichlorotrifluoroethane;
tetrafluoroethane; dichloroethane; and chlorodifluoroethane. As
the commenter noted, the list of specific compounds that the
Administrator has determined do not contribute appreciably to the
formation of ozone may be updated periodically. If, in the
future, the Administrator adds to the list of chemicals defining
TOC, these added chemicals will be identified in future
Federal Register notices. The current definition of TOC in the
reactors NSPS will be retained to reference but not specifically
list those compounds that the Administrator has determined do not
contribute appreciably to the formation of ozone. Finally, by
defining TOC in this manner, any changes that the Administrator
makes to the list of compounds would be automatically
incorporated into the definition of TOC in the reactors NSPS.
2.2.2 Comment
Six commenters (IV-D-02, IV-D-05, IV-D-08, IV-D-11, IV-D-12,
IV-D-14) objected to the definition of "product." Two commenters
(IV-D-02, IV-D-12) felt that the definition is confusing for
determining the applicability of the reactors NSPS. Four
commenters (IV-D-02, IV-D-08, IV-D-12, IV-D-14) recommended that
the definition of "product" in the distillation NSPS be used,
with the necessary revision to reference the reactor process list
2-13
-------
of chemicals in Section 60.707. These commenters objected to the
phrase "or is used for the production of other chemicals or
compounds." These commenters were concerned that this language
could be interpreted to expand applicability of this NSPS to all
facilities that use any of the 173 listed chemicals in their
production processes, even if they do not manufacture any of the
173 compounds as a product, by-product, or co-product.
One commenter (IV-D-05) stated that the definition of
"product" is unclear and it could be interpreted to include those
cliemicals listed in Section 60.707 which are purchased as raw
materials in the production of other chemicals or compounds.
This commenter felt that the definition should be identical to
the one in the air oxidation NSPS and recommended the following
definition: "Product means any compound or chemical listed in
Section 60.707 that is produced for sale as a final product as
that chemical or is produced for use in a process that needs that
chemical for the production of other chemicals in another
facility. By-products, co-products, and intermediates are
considered to be products." (The underlined phrases indicate the
changes suggested by the commenter.)
Response
The EPA agrees with the commenters that the language in the
definition of "product" in Section 60.701 of the proposed
standards could be misleading and could expand applicability of
the reactors NSPS to facilities that were not intended to be
impacted by this regulation. The definition of "product" similar
to the one found in the distillation NSPS has been included in
the reactors NSPS. It states that a "product" is "any compound
or chemical listed in Section 60.707 that is produced for sale as
a final product as that chemical, or for use in the production of
other chemicals or compounds." This definition is consistent
with EPA's intent of coverage under the reactors NSPS.
2.2.3 Comment
Two commenters (IV-D-11, IV-D-12) requested further
clarification of the definition of the phrase "prod\ict,
co-product, by-product, or intermediate." These commenters
2-14
-------
recommended that wording similar to that found in the preamble of
the distillation NSPS should be included 'in the reactors NSPS
preamble to clarify the intent.
Response
As suggested by the commenters, the following language is
presented to clarify the intent of the definition of "product."
The EPA considers it appropriate for the reactors NSPS to apply
to any reactor process facility within a process unit producing
any of the listed chemicals as a product, by-product, co-product,
or intermediate. The standards were developed from data on
reactor processes within process units that produce the chemicals
listed in Section 60.707 in any of the forms listed above. The
cost of controlling emissions from the production of a listed
chemical as a by-product, co-product, or intermediate is similar
"to the cost of controlling emissions from the production of that
chemical as a product. Furthermore, the application of the
standards to facilities producing any of the listed chemicals was
found to be reasonable. Therefore, EPA considers the word
"product" to also represent by-products, co-products, and
intermediates.
The standards are also applicable to reactor processes that
are used to recover waste or feedstock components as long as the
facility is within a process unit producing any of the listed
chemicals as a product. The main factor in determining if a
listed chemical is produced as a product is the use of the
chemical after the process unit. The EPA considers either of the
following downstream uses as indicative of the production of a
listed chemical as a product: (1) Production for sale as that
listed chemical, or (2) use in another process where that listed
chemical is needed. However, if a listed chemical is only part
of a mixed stream exiting a process unit and cannot be sold or
used in another process as the listed chemical, then that
chemical is not considered to be produced as a product.
2.2.4 Comment
Two commenters, (IV-D-05, IV-D-08) indicated that the
definition of "by-product" is unclear. One commenter (IV-D-05)
2-15
-------
questioned whether the term by-product includes those compounds
that are unintentionally created as a result of a chemical
reaction and that are contained within a final product. To avoid
confusion, the commenter recommended establishing a de minimis
level (i.e., less than one percent) to-exclude a contaminant from
the definition of by-product.
The other commenter also requested clarification for
by-products that are produced during reactor processes but are
not pure enough for sale and, generally, are disposed of as
waste. This commenter felt that it is not the intent of the
reactors NSPS to regulate these by-products because they are
neither intended for sale nor used in the production of other
chemicals.
Response
If a mixture is produced in a reactor process as a "product"
and contains a chemical listed in Section 60.707 that is
intentionally included in the'mixture for use of its chemical
characteristics, the process would be subject to Subpart RRR. A
mixture would not be subject if the listed chemical is included
only as a contaminant, that is, the chemical is not included in
the process for its chemical characteristics. To further clarify
this distinction, sometimes a listed chemical can be formed
during the reaction process as a contaminant from side reactions
as a consequence of producing other chemicals that are not
listed. These contaminants would not be considered to be
produced by the reactor process if they are not recovered to be
sold or used in the production of a final product.
The EPA has decided that for the purpose of these standards,
it is more appropriate to determine applicability according to
whether a listed chemical is produced as a product, instead of
setting a minimum concentration level of a listed chemical as a
means of defining what may constitute production as a product.
It is not feasible to set any one concentration limit for listed
chemicals below which the chemical is always an impxirity or
waste. It is not feasible because the necessary concentration or
purity for a listed chemical to be considered a product can vary
2-16
-------
from site to site. For example, a chemical that is produced as
90 percent pure from one process may only be 80 percent pure to
be considered a product for another process. Due to diversity of
the SOCMI, it would not be practicable for EPA to establish
different concentration limits for all-of the processes covered
by the standards. Therefore, the applicability of the standards
is determined according to whether a listed chemical is produced
as a product.
2.2.5 Comment
One commenter (IV-D-ll) stated that the definition of "vent
stream" is difficult to interpret and needs additional
clarification. This commenter pointed out that the definition of
vent stream also applies to any gas stream emitted from a reactor
that indirectly discharges to the atmosphere after being diverted
through other process equipment. This commenter noted that
nearly all product streams leave a reactor process for further
handling as a vapor but are not considered a vent stream at the
point when they exit from the reactor process. The commenter
felt that the proposed definition for "vent stream" could result
in an overlap in regulations if the vent stream is ultimately
discharged from a distillation unit that is covered by the recent
distillation NSPS.
Response
As previously discussed in the response to Comment 2,1.1, if
a vent stream is discharged exclusively to a distillation unit
subject to the distillation NSPS, then that vent stream would not
be subject to the control provisions in the reactors NSPS.
Typically, a vent stream is routed directly through a recovery
device such as an absorber, a condenser, or a carbon adsorber.
In some cases, however, the vent stream may be diverted first
through other process equipment before being routed indirectly
through a recovery device. For example, in a typical fixed bed,
regeneration carbon adsorption system, the process offgases pass
through a filtering and cooling system before entering the carbon
bed. (The filtering process prevents bed contamination and the
cooling process allows the bed to be-maintained at the optimum
2-17
-------
operating temperature and prevents fires or polymerization of the
VOC.) Even though this vent stream is routed through a filtering
and cooling system before reaching the recovery device, it is
still subject to the standard.
2.3 SELECTION OF BEST DEMONSTRATED TECHNOLOGY
2.3.1 Comment
One commenter (IV-D-01) stated that a cryogenic unit,
although not specifically considered a condenser but nonetheless
capable of achieving 98 percent or greater, reduction of
emissions, should be considered a condenser for the purposes of
an exemption from the provisions of Section 60.703(e).
Response
A cryogenic unit, such as the one mentioned by the
commenter, would be considered a condenser for the purposes of
the reactors NSPS and, therefore, would be subject to the.
condenser requirements under this regulation. The owner or
operator would be required to maintain a TRE index value greater
than 1.0 at the outlet of the condenser. Otherwise, if the TRE
is less than or equal to 1.0, the stream's emissions must be
reduced by 98 percent or to 20 ppmv. Monitoring of process
parameters outlined in the regulation would be required unless
the owner or operator elected to demonstrate compliance with an
alternative process parameter allowed under Section 60.703(e).
2.3.2 Comment
One commenter (IV-D-10) requested that although the preamble
discussion states that "any control can be used as long as it can
be demonstrated that it is at least as effective as BDT at
reducing VOC emissions," this stipulation should also be
specifically spelled out in Section 60.702 of the regulation.
Response
Because the standards is expressed in terms of an emission
limitation and not an equipment standard, the EPA believes that
the wording in Section 60.702(a) is clear in its intent that any
control device can be used to achieve the emission limitation.
Any VOC control device, including an incinerator, boiler, process
heater, or other combustion device, can be used to comply with
2-18
-------
thzs requirement. Alternatively, a flare can be used to comply
wxth Section 60.702(b). in addition, any VOC recovery device
including an absorber, condenser, carbon adsorber, or other '
recovery device, can be used to comply with Section 60.702(c) to
maintain the TRE index greater than.1.0. it should be noted that
the TRE. value for a vent stream is determined at the point that
the stream exits the final VOC recovery device and before it
enters a VOC control device.
If an owner or operator elects to use a control device othe-
than an incinerator, boiler, process heater, or flare- or a
recovery device other than an absorber, condenser, or'carbon
absorber, that facility would be required to provide information
to the Administrator describing the device and the process
parameter(s) that .would indicate proper operation. The '
documentation should be submitted to the appropriate enforcement
offxcer. As necessary, EPA Headquarters may be consulted to
determine the adequacy of monitoring alternative process
parameters.
2.4 FORMAT OF STANDARDS
2.4.1 Comment
Three commenters (IV-D-08, IV-D-12, lv-D-14) stated that the
use of the TRE index value as a standard is appropriate; however
these commenters recommended that the TEE aquations be
standardized in 40 CFR Part SO, Subpart III, subpart NNN, and
Subpart ERR. one commenter (IV-D-08) pointed out that an
important feature of the TRE index value noted in the reactors
NSPS preamble is that "it is independent of cost changes over
time so that it is not necessary to periodically revise the
calculation to reflect current year dollars." Two commenters
(IV-D-08, IV-D-12) noted that the-only change to the TEE eouation
between the distillation NSPS and air oxidation NSPS and tTe
proposed reactors NSPS was a revision of the coefficients to
account for various cost changes from a 1978 to a 1982 base year.
Both of these commenters noted that the purpose for changing the
develop^ the
2-19
-------
Two commenters (IV-D-12, IV-D-14) pointed out that for a
given process vent, the revised coefficients result in TRE index
values that are about 3 percent greater. Both commenters
recommended that the TRE equation coefficients be standardized.
Both commenters noted that by standardizing the coefficients in
all three regulations, applicability and compliance
determinations for many facilities would be simplified without
appreciably changing the impact of the rules. One commenter
(IV-D-12) argued that although the change in the coefficients is
minimal, it creates needless complication for a facility that
must use one set of coefficients to determine the compliance
status of one process vent while using another set of
coefficients to determine the compliance status of a second
process vent. This commenter also pointed out that in
standardizing the TRE coefficients, considerable time would be
saved in developing process vent regulations in the future that
incorporate the TRE index format.
Response
The TRE equation developed for the SOCMI regulcitions was
derived from an algebraic reduction based on a cost algorithm.
However, the utility prices and the labor rates used in the
derivation of the two TRE equations were extracted from different
base cost years. The TRE coefficients in the air oxidation NSPS
and distillation NSPS were based on actual 1978 rates, whereas
the TRE coefficients in the reactors NSPS were based on actual
1982 rates. It would appear that when the annual rsite increases
are computed, the numerator and denominator of the TRE equation
would increase by the same factor so that no net change is
reflected in the final TRE index value. However, this is not the
case. The utility prices and labor rates did not increase
uniformly from the 1978 base year to the 1982 base year so that a
slight difference in the resultant TRE index value is noted when
comparing the calculation of the TRE index value based on the
1978 coefficients with the calculation of the TRE index value
based on 1982 coefficients. This difference in the resulting TRE
values is documented in a memorandum entitled "Comparison of
2-20
-------
Total Resource Effectiveness (TRE) Index Values using 1978 and
1982 TRE Coefficients" (Docket No. A-83-29, Item IV-B-3).
The EPA agrees that the TRE coefficients in the reactors
NSPS should be identical to those used in the air oxidation and
distillation NSPS and has made this.change to the final reactors
NSPS. This standardization is important to reduce confusion and
add consistency in calculating TRE values, especially in those
cases where a facility has several vent streams subject to
different SOCMI NSPS. The resulting difference in the computed
TRE values would be insignificant using the adjusted TRE
coefficients.
2.4.2 Comment
Two commenters (IV-D-ll, IV-D-15) cited difficulties with
using the TRE index. One commenter (IV-D-ll) felt that the
practical application of the TRE index is cumbersome. The
commenter pointed out that with the regulations', it is difficult
to determine exactly where the reactor process and the associated
internal optimization ends, and the recovery device begins, for
determining the TRE index.
The commenter pointed out that, in many cases, the primary
condenser on a downstream column is adequate to achieve and
maintain a TRE index greater than 1.0 without additional emission
controls because of the properties of the material involved. The
commenter added that the reactors NSPS refers to the final
recovery system and not a primary condenser. The commenter
recommended that clarification is needed to specify when the TRE
index calculation should be performed.
The other commenter (IV-D-15) stated that he was unable to
understand the rationale behind the TRE equation. The commenter
suggested that a simplified calculation be included with a clear,
concise explanation of how it is designed to achieve its purpose.
Response
The EPA believes that application of the TRE index is
straightforward. It also allows flexibility for the owner or
operator to choose a method of compliance and provides an
incentive for product recovery. The owner or operator can elect
2-21
-------
to do one of the following: use a VOC combustion device and
reduce TOG by 98 percent or to 20 ppmv; combust the vent stream
in a flare; or maintain a TRE index greater than 1.0 at the
outlet of the final recovery device. If the TRE index is less
than 1.0 at the point of measurement, the owner or 'operator could
elect either to install an additional recovery device that
results in a TRE index greater than 1.0 or to control the vent
stream.
A recovery device is defined as an individual unit of
equipment, such as an absorber, carbon adsorber, or condenser,
capable of and used for the purpose of recovering chemicals for
use, reuse, or sale. The TRE index should be calculated
following the last recovery device but prior to a VOC control
device. A VOC control device is a device such as a flare or an
incinerator. For example, if the vent stream from a reactor
process is routed through two condensers in series, the TRE index
would be calculated at the outlet of the final condenser. If the
calculated TRE index is 1.0 or lower, the owner or operator can
elect to upgrade the VOC removal efficiency of existing recovery
devices, install additional recovery devices, or add a control
device.
2.5 MODIFICATION/RECONSTRUCTION
2.5.1 Comment
One commenter (IV-D-08) stated that the discusssion of
modification/reconstruction considerations found in 55 FR 26965
and in Chapter 5.0 of the BID does not reflect the decision by
the United States Court of Appeals for the 7th Circuit, in
Wisconsin Electric Power Company v. Reilly (WEPCO), 893 F.2d 901
(7th Cir. 1990). The commenter stated that it would be
appropriate to include in the final reactors NSPS preamble a
discussion of "like-kind" replacements and other issues raised in
the WEPCO decision.
2-22
-------
Reapongg
alia 'thaf *** deClSi°n' "" COUrt •8EMd "ith EPA- **~
alia, that nonroutme renovations to existing plants thaTextend
th~r life expectancy and increase the rate L eJsioTto thT
at.osphere are "Modifications' for NSPS proses as defLd in
and not only physical changes ^ are ^^ t ^
examptlon found at 40 CFR S0.M(.,. ^ Court aQ ^
nterpretation that for NSPS purposes, an increLe in
"lned ^ 1
but at the
,.„ , . . . issue in the WEPCO case pertains
to determining applicability to the Prevention of Significant
J J^^ y^ ^^T^T ^Vy ?3 4" J .^VK / T^C^T^ \ **•* J» ^ V^G,^x O
itffao; program. The PSD program cons
past operating history in establishing app'
the NSPS, which bases applicability on the readilv
:
2-5.2 Comment-
Two commenters (IV-D-i? rw n i/i\
iJ-v D 12, IV-D-14) requested that the types
---
should be clarified. These concenters
referred to the sxan-ples of process, eo^ipnent changes Lntioned
2-23
-------
rate to the at.ospLe " " 1Mr~~ in "* -^"
The comenters believe chat it 'is not the intent of th.
-
emission rate feSUfflS^aSSre rSnS lncrease in ^e
the atmosphere^ - reacfnr nroeefla_voI±« to
(The coMnenter- s suggested wording is underlined )
Sesoonaa
«« outlined in
ae=tefa=iit «°uld apply ,:o any
2 . 6 MONITORING
2-6-l Comment-
state
the
to operate at
commenter recc
2-24
ze acxiiies tt
efficient te.piratnres Thi " ^^ "= 1OW"
einperatures. This commenter reoommendecj a
-------
temperature range, to be determined by EPA, instead of a
percentage value.
Response
The EPA does not intend to penalize those owners or
operators who are operating their carbon beds at lower, more
efficient temperatures. The commenter is correct in pointing out
that by allowing a 10 percent variation in temperature from the
performance test for the carbon bed following regeneration, some
inequities may result. To eliminate possible inequities, a
minimum temperature difference of 5°C will be added as an
alternative to the 10 percent provision in
Section 60.705(f)(3)(ii). As discussed in the memorandum
entitled, "Documentation of Carbon Adsorber Cool Down
Temperature" (Docket No. A-83-29, Item IV-B-2), the minimum value
of 5°C is derived from 10 percent of 50°C, a typical carbon bed
cool down temperature. To reflect this addition,
Section 60.705(f)(3)(ii) will be revised to'read as follows:
All carbon bed regeneration cycles during which the
temperature of the carbon bed after regeneration [and
after completion of any cooling cycle(s)] was more than
10 percent or 5°C greater, whichever is less stringent
than the carbon bed temperature (in degrees Celsius)
during the most recent performance test.
This alternative provides more flexibility to those owners
or operators who are operating their carbon beds at lower, more
efficient temperatures. As an example, an owner or operator may
be able to achieve a carbon bed cool down temperature of 5QC when
conducting the performance test. However, using the 10 percent
provision to maintain compliance with the regulation, the owner
or operator must cool the carbon bed down to at least 5.soc. The
alternative added to the regulation would allow the owner or
operator to cool the carbon bed down to 10°C.
2.6.2 Comment
Three commenters (IV-D-ll, IV-D-12, IV-D-14) expressed
concern about the requirement for flow indicators. One commenter
(IV-D-ll) requested that flexibility be included in the final
regulation to allow an affected facility to use any means
2-25
-------
available to indicate vent stream flow. He cited several
monitoring techniques that were not mentioned in the regulation,
including a computer signal that utilizes either a flow or a no
flow indication signal to assess whether a system is venting, or
a flow indicator on the inlet feed stream or other process
parameters. This commenter felt that flexibility is needed to
allow a flow indicator to be located in a place other than the
point closest to the inlet of the control device.
The second commenter (IV-D-12) stated that the requirement
for facilities to determine the presence of vent stream flow
before the stream is combined with other streams should be
deleted. This commenter pointed out that existing reactor
process vent streams are frequently combined with other vent
streams in a vent header prior to being routed to a combustion
device. This commenter noted that in these cases, conventional
design provides for flow indicators to be placed only at a point
close to the control device and downstream from all individual
vents. The commenter observed that the logic for this
arrangement is related to total flow. This commenter recommended
that facilities be allowed to comply with the flow indication
requirement by using existing instrumentation that is located
close.to the control device and after the affected facility vent
stream has been joined by other vent streams.
The third commenter (IV-D-14) noted that the specification
for locating a flow indicator to check the operation of a control
device as explained in the preamble is inconsistent with the
provisions specified in the standard. This commenter pointed out
that good engineering design and the efficient operation of
control devices are related to total flow. The commenter
believed that the provisions in the preamble, which state that
the "flow indicator would be required to be installed at the
combustion device inlet", are more appropriate than the
provisions specified in Section 60.702 (a), (b), and (c) which
require that:
The flow indicator shall be installed in the vent
stream from each affected facility at a point closest
2-26
-------
« e
to _ the inlet of each incinerator and before beincr
joined with any otlfer vent stream.
Response ~
The EPA considers It very important to ensure that vent
streams are continuously vented to the flare or other control
device. The primary intent of the flow monitoring requirement in
the reactors NSPS was to provide a means for indicating when vent
streams were bypassing the flare or other control device. In the
June 29, 1990 proposed-rule for reactor processes, flow
indicators were proposed to be installed in the vent stream from
the affected facility at "a point closest to the inlet of the
control device and before being joined with any other vent
stream. The presence o£~flow was to be recorded at least once
every hour. The flow indicators envisioned by EPA were to
provide an indication of flow/no flow,- and not to provide
quantitative estimates of flow rates.
The EPA has reevaluated the use of flow indicators in
reactor process vent streams as proposed in light of the comments
received. Because flow indicators located on the vent stream
between the emission source and the control device may be
insufficient to meet the intent of the standard (although, this is
what was proposed), EPA has decided to alter the flow indicator
location. The new flow indicator location would be at the
entrance to any bypass line that could divert the vent stream
before it reaches the control device. This location would
indicate those periods of times when uncontrolled, emissions are
being diverted to the atmosphere. In those instances when the
vent stream is rerouted to another control device, the second
control device must also conduct a performance test and meet the
requirements of the standard. -The flow indicator required in-
each- bypass line to the atmosphere- can- be used in conjunction
with any type of seal mechanism to ensure that flow is not
diverted.
In some situations, there may be no bypass lines that could
divert the vent stream to the atmosphere. In these cases, there
will be no flow indicator requirement. In addition, engineering
2-27
-------
records that show an emission stream is hardpiped to a control
device are sufficient to demonstrate that the entire flow will be
vented to the control device. Other piping arrangements can be
used, but flow indicators located in any bypass line that could
divert a portion of the flow to the atmosphere, either directly
or indirectly, become necessary.
Considering the above conclusions, EPA is now requiring in
Section 60.705(s) of the reactors regulation that engineering
records be retained that describe the piping arrangement for
venting the affected vent streams to a control device. This
requirement will further ensure that each reactor process vent
stream of the affected facility is being continuously vented to
the control device. If the piping arrangement for the reactor
process changes, then the facility must revise and retain the
information. Little or no additional burden would be expected
from this requirement since engineering design specifications
that describe the piping arrangements are already being
maintained.
At proposal, EPA required that hourly recordings of flow to
the control device be taken. However, the Agency believes that
more frequent collection of flow/no flow data is appropriate when
the purpose of the monitoring is to detect flow to the atmosphere
rather than to a control device. Thus, the final reactors NSPS
requires flow indicators to be equipped to indicate and record
whether or not flow exists at least once every IS minutes (rather
than once every hour). Because the monitor collects flow/no flow
data on a continuous basis, this additional recording would not
be an additional burden. If an owner or operator believes that
an alternative frequency or placement of a flow indicator is
equally appropriate, then the owner or operator can petition the
Administrator, as provided by the General Provisions, to use an
alternative monitoring scheme.
Other flow monitoring systems, such as the computer signal
technique suggested by the commenter, would also be allowed so
long as they are used in conjunction with the flow indicator and
readings are taken at least once every IS minutes.
2-28
-------
2.6.3 Comment
Three commenters (IV-D-08, IV-D-ll, IV-D-12) requested that
alternate methods be allowed for determining vent stream flow/no
flow for an affected facility. One commenter (IV-D-08) cited
difficulties in meeting compliance with installation of a "flow
indicator" on the vent stream to the control device. This
commenter mentioned that one of his facilities seeking compliance
with a similar provision in the distillation NSPS found it
necessary to ask for permission to•use an alternative method for
ensuring that the vent stream flow reached the control device (in
this case, a flare). This commenter's system had a continuous
nitrogen purge on its vent stream to the flare header to keep it
from plugging up with organics. This nitrogen system was used to
avoid an upset that could result in a possible release of
organics to the atmosphere. However, the commenter pointed out
that this continuous nitrogen purge precluded accurate
measurement of vent stream flow to the flare.
The commenter also explained that each column in his system
has a manual vent valve used for initial purging at startup to
remove oxygen from the system and to prevent a flammable mixture
in the flare header. According to the commenter, the alternative
that this facility requested was to lock the manual vent valves
in the closed position during normal operations, with periodic
visual checking to ensure no release to the atmosphere. The
manual vent valve lock suggested by the commenter would be
secured in place with a lock and key. The key to the lock would
be kept in the custody of the foreman or chief operator.
Alternatively, the commenter explained that the valves could be
locked electronically with a remote control valve on a control
panel, or computer-activated.. The commenter felt that this type
of problem was not an isolated case and recommended adding a
provision to Section 60.703 which allows an appropriate
administrative compliance alternative method for flow
measurement, with a direct reference to Section 60.13(1) of the
General Provisions as the means by which a source could seek
approval.
2-29,
-------
Response
As discussed in the response to Comment 2.6.2, the position
of the flow indicator has been changed to the entrance to any
bypass line that could divert the vent stream to the atmosphere
before it reaches the control device. -In addition to this
change, EPA agrees with the commenters that alternate provisions
should be allowed for indicating vent stream flow/no flow for an
affected facility. An alternate provision is being added to the
reactors NSPS for those facilities that use a car-seal or a
lock-and-key type configuration to maintain the bypass line
closed. This alternate provision would require all lines that
allow emissions to bypass to the atmosphere from the control
device to be car-sealed closed or secured with a lock-and-key
type configuration. For clarification purposes, a definition for
car-seal is being added to Section 60.702 as follows:
gar-seal means a seal that is placed on a device that
is used to change the position of a valve (e.g.., from
opened to closed) in such a way that the position of
the valve cannot be changed without breaking the seal.
For'those affected facilities that use any other alternate type
of locking mechanism (such as a computer-activated electronic
locking system), those affected facilities would be required to
install a flow indicator in the bypass line.
This alternative is being added to the reactors NSPS to
ensure that the vent streams are not routinely bypassed to the
atmosphere rather than being routed to the control device. If
the owner or operator elects to comply with this alternative, a
visual inspection of the seal mechanism and valves would be
required at least once per month to report and record any time
the seal mechanism is broken or lock is open, and to report and
record any time the valve position has changed and the duration
of the release to the atmosphere.
If at any time a flow indicator positioned in any bypass
line to the atmosphere indicates gas flow, this shall constitute
a violation under Section 60.702(a), except during periods of
startup, shutdown, or malfunction. For purposes of determining
-2-30
-------
compliance, malfunctions shall be events deemed to occur
infrequently, unforseeably, and unavoidably. Consequently,
recurring instances of flow through any bypass line to the
atmosphere shall not constitute a malfunction under this
standard. -
2.6.4 Comment
One commenter (IV-D-11) observed that the requirement to
install temperature monitoring devices in the "firebox" of an
incinerator should be modified to allow for additional
flexibility. This commenter remarked that with many
incinerators, the technology does not exist to maintain a
reliable temperature monitor inside the firebox. The commenter
noted that, in practice, most temperature monitors are installed
in the exhaust gas downstream of the firebox. The commenter
thought that flexibility should be. .allowed in the final
regulation to allow for the placement of the temperature monitor
in an appropriate location to address situations where it is not
practical or where the technology does not exist to install these
devices in the firebox.
Response
For purposes of measuring the firebox temperature in an
incinerator, EPA considers it appropriate to locate the
temperature monitor in a position before any substantial heat
exchange is encountered. For the purposes of this regulation,
the location of the temperature monitoring device will be allowed
in the ductwork immediately downstream of the firebox. To
reflect this clarification, the language in
Section 60.703(a)(1)(i) will be revised to read as follows:
Where an incinerator other than a catalytic incinerator
is used, a temperature monitoring device shall be
installed in the firebox or in the ductwork immediately
downstream of the firebox in a position before any
substantial heat exchange is encountered.
2.6.5 Comment
Two commenters (IV-D-08, IV-D-12) do not believe that
continuous organic monitoring devices are proven technologies
and, therefore, believe that it is inappropriate to recommend
2-31-
-------
their use in the reactors NSPS. These commenters cited a
discussion of the results of a survey on hydrocarbon monitoring
which is found in the preamble to the proposed rule for hazardous
waste-burning in boilers, published on April 27, 1990
(55 FR 17887). These commenters noted-that only six incinerators
were attempting to use these continuous monitoring devices and
all of them were using conditioned systems rather than heated
systems. These commenters reported that limited data about
continuous monitoring systems indicate that heated systems would
detect two to four times the mass of organic compounds than would
be detected by conditioned systems. These commenters felt that
heated systems have a number of operating problems which have not
been resolved.
One commenter (IV-D-08) felt that continuous organic
monitoring devices are unreliable and, therefore, should not be
referenced as an allowable technology in the reactors NSPS. The
other commenter felt that facilities should not be required to
use continuous organic monitoring devices for demonstrating
compliance with the reactors NSPS. One commenter (IV-D-08)
recommended that all references to this technology be removed
from the reactors NSPS until the devices can be proven reliable
and accurate. If at some time in the future these devices become
proven technologies, these commenters suggested that EPA could
issue a notice stating that this alternative mode of monitoring
compliance would be acceptable.
Response
The performance of organic monitors is not relevant to the
reactors NSPS because these monitors are not required for use on
combustion sources. However, organic monitors are allowed as an
alternative for monitoring the performance of VOC recovery
devices. The EPA is aware* chat these devices are currently
available and has no reason to preclude their use for certain
applications, in each case where an organic monitor is allowed
in the reactors NSPS, an alternate monitoring device is also
specified. For example, use of either a scrubbing liquid
temperature monitor or an organic monitor can be used to.
2-32
-------
demonstrate the performance of an absorber, in each case, the
reactors NSPS allows the owner or operator to select the device
that is most appropriate for the situation. Although the
reactors NSPS does not require continuous organic monitors, these
monitors will continue to be allowed as a method for
demonstrating compliance.
2.7 PERFORMANCE TESTING AND MEASUREMENT METHODS
2.7.1 Comment
Four commenters (IV-D-08, IV-D-ll, IV-D-14) requested that
guidance be provided for the performance test requirements for
facilities that are constructed, reconstructed, or modified
between the date of proposal and the date of promulgation. All
four commenters felt that the timing requirement of 60 days for
the-initial performance test was unrealistically tight. They
recommended allowing a minimum of 120 days for the initial
performance test. Three
commenters (IV-D-08, IV-D-12, IV-D-14) do not believe that
facilities can anticipate the final rule because changes are
likely to occur after proposal as a result of public comments.
One commenter (IV-D-14) pointed out that even subtle changes can
affect the applicability of the regulations to a facility so that
companies must review the final regulations thoroughly before
scheduling compliance methods and procedures. All three of these
commenters explained that it usually takes several weeks before
copies of a final regulation as printed in the Federal Register
are available to the regulated public. One commenter (IV-D-08)
noted that his facility had a difficult time in meeting the
compliance dates for the distillation NSPS and air oxidation
NSPS.
All four commenters. stated that considerable time is-needed
to perform the requisite analyses and tests. One commenter
(IV-D-12) stated that those affected facilities electing to
comply with the TRE index format would have to perform stack
tests, which would take 10 to 12 weeks and, therefore, have an
extremely difficult time in meeting the 30-day notification
deadline. Two commenters (IV-D-12", IV-D-14) pointed out that
2-33
-------
many steps are involved when conducting a performance test,
including setup, testing, and sample analysis. One commenter
(XV-D-14) added that in many cases, a facility must contract
outside help to conduct its performance testing. The commenter
elaborated that projects must be sc9ped, contractors must be
contacted, bids must be received and studied, contracts must be
negotiated, work must be scheduled, production schedules must be
manipulated, analytical determination sometimes requires off-site
work, and results must be related to the applicability or
compliance determination. Both of these commenters agreed that
120 days provides a more reasonable time to complete testing.
Response
In regard to performance tests, the owner or operator must
conduct performance tests and submit a written report of the
results of such tests to EPA within 60 days after achieving the
max:ir.Tum production rate at which the facility will be operated,
but not later than ISO days after initial startup of the
facility, in some instances, however, the initial startup of a
facility may occur before the date of promulgation. As stated
for monitoring requirements, EPA has a policy of allowing
facilities to conduct and report the results of'performance tests
within 60 days from the date of promulgation, unless maximum
production has not been achieved. In the latter case, the
facility must conduct and submit the results of a performance
test no later than 180 days after the date of promulgation, it
is believed that this is a reasonable amount of time for the
owner or operator of a reactor process unit to achieve
compliance. All sources subject to the NSPS must meet these
general requirements.
2.7.2 Comment,
Four commenters (IV-D-OS, IV-D-ll, IV-D-12, IV-D-14)
expressed concern about the provision which requires facilities
that are built, modified, or reconstructed between proposal and
promulgation that have not achieved maximum operating capacity
before promulgation to conduct their performance test within
180 days of promulgation. Two commenters (IV-D-ll, :EV-D-12)
2-34
-------
pointed out that Section 60.704(a) clearly states that facilities
must be run at full operating conditions and flow rates during
performance tests. Three commenters (IV-D-ll, IV-D-12, IV-D-14)
stated that if a facility does not achieve maximum operating
conditions within 180 days of promulgation, then it cannot
conduct a performance test without violating the provisions of
Section 60.704(a). These three commenters recommended that
facilities either be allowed to conduct their performance test
after the maximum operating rate has been achieved, or that
Section 60.704(a) be revised to accommodate facilities that have
not yet achieved their maximum operating rate.
One commenter (IV-D-08) stated that the initial performance
test required in Section 60.702 may not be achievable within
180 days after the initial startup. This commenter supported his
statement by saying that as chemical processing facilities become
more complex, contain more sophisticated equipment and
procedures, it may not always"be possible to achieve full
production rates and capacity operations within 180 days. This
commenter further explained that where there are changes, even
small changes, between proposal and promulgation, facilities may
need to purchase and install new equipment to run the performance
tests. For these reasons, this commenter felt that guidance must
be provided in the final rule as to how the performance test
requirement should be handled in the event that a facility is
unable to achieve full capacity operation within 180 days.
Response
The requirement for the initial performance test to be
conducted within 180 days following initial startup will remain
unchanged. If, however, a facility foresees a problem in
achieving compliance (i.e., if the facility is, unable to achieve
maximum capacity within ISO days), then the owner or operator of
that facility must notify the State, which has been delegated
implementation authority, or the appropriate EPA Regional Office
at the earliest possible time.
2.7.3 Comment
2-35
-------
One commenter (IV-D-08) expressed concern about the expected
cost and the amount of time required by a source to run Reference
Method 18's future validation method. This commenter stated that
each vent stream possesses its own set of unique characteristics
so that each vent stream will require a separate test once the
new validation protocol is issued. This commenter requested some
discussion and guidance in the final reactor processes preamble
on possible ways to reduce this time and cost burden.
Response
The protocol mentioned by the commenter has been published
as EPA Method 301: entitled "Field Validation of Emission
Concentrations from Stationary Sources,» in Appendix A to 40 CFR
Part 63. This method is not a mandatory procedure for complying
with the Method 18 requirements specified in the reactors NSPS.
Rather, it is intended for use in validating results of emission
testing, particularly when there is no performance test mechod
specified. Because Method 18 is specified in the reactors NSPS,
Method 301 is not required by the NSPS. but may prove useful in
some situations. To use Method 301, the owner or operator would
have to request and receive approval for its use under the
alternative methods provisions found in Section 60.13(1) of the
General Provisions.
2.7.4 Comment
Two commenters (IV-D-li, IV-D-14) felt that the use of
Reference Method 18 to determine the concentration of TOG would
be extremely labor intensive, especially if there are a number of
compounds present. One commenter (IV-D-li) pointed out that
Reference Method 18 does not specify chemicals to be analyzed and
that extensive efforts could be expended quantifying trace
components to ensure that compliance with the method is achieved.
This commenter recommended that the analytical burden could be
reduced by stating that for purposes of achieving compliance, the
analytical efforts should focus only on the compounds expected to
be present. This commenter suggested that expected compounds
could be determined by knowledge of the process or by an initial
analytical screening. The second commenter (IV-D-14) suggested
2-36
-------
that Reference Method 25 would be a more adequate method for this
determination.
Response
Reference Method 18 includes performance specifications,
which are internal to the method. These specifications offer
guidance on the steps needed to measure approximately 90 percent
of the total gaseous organic compounds that are present in the
vent stream. However, before implementing Reference Method 18,
it is necessary to have some preknowledge of the source. When
designing the analytical scheme for conducting the Method 18
performance test, it is necessary to have some prior knowledge of
the identity and concentration of species that are present. It
is also necessary to be familiar with the chemical process being
tested and to perform an initial analytical screening. As
discussed in Reference Method 18, presurvey sampling and analysis
is required to confirm the identities and approximate
concentrations of the organic emissions.
In response to the suggested use of Reference Method 25 as
an appropriate method, this method is not suitable at levels as
low as 20 ppmv. Because the 20 ppmv level is specified in the
reactors NSPS for compliance with the combustion device control,
Reference Method 25 is not considered appropriate for compliance
testing purposes.
As discussed in Comment 2.1.6, a low concentration cutoff of
300 ppmv (measured using Reference Method 18) has been added to
the standards. Reference Method 25A is allowed as an alternate
screening method for those owners or operators seeking an
exclusion for vent streams with low concentration levels.
Although Method 25A does not identify speciated compounds, when
calibrated to the primary constituent in the vent stream it can
provide a sufficiently accurate measurement of TOG for comparison
to the low concentration applicability cutoff. However, because
vent streams are often composed of a mixture of multiple organic
compounds, and some are more easily detected by Method 25A than
others, the regulation includes certain procedures for using
Method 25A. •-••••
2-37
-------
Reference Method 25A can only be used if one organic
compound accounts for over 50 percent of the vent stream TOC.
This compound is referred to as the primary constituent. The
primary organic constituent may be determined by either process
knowledge or test data collected using-an appropriate EPA
Reference Method. Examples of information that could constitute
process knowledge include calculations based on material
balances, process stoichiometry, or previous test results
provided the results are still relevant to the current reactor
process vent stream conditions. The primary constituent must be
used as the calibration gas for Method 25A. The span value for
Method 25A must be set at 300 ppmv. Note that use of Method 25A
is acceptable only if the response from the high-level
calibration gas is at least 20 times the standard deviation of
the response from the zero calibration gas when the instrument is
zeroed on the most sensitive scale.
Because the compound to which the method is calibrated may
be only half of the total TOC, the TOC concentration measured by
Method 25A muse be less than 150 ppmv (or 0.50 x 300 ppmv) to
demonstrate cc,:>::liance with the low concentration cutoff. This
300 w cut-off level was selected as described in the
mem ndum entitled, ^Selection of the Low Concentration Cutoff"
(Do : No. A-83-29, Item IV-B-1). This requirement accounts for
sonu rganics that may not be well detected when the method is
cali_,.a.ted to the primary constituent. Method 25A measurements
include methane and ethane.
2.7.5 Comment
One commenter (IV-D-10) acknowledged that Section 60.705
includes a provision that if at a later date the owner or
operator elects to use an alternative provision of Section 60.702
to achieve compliance, then the Administrator must be notified
90 days before implementing the change. Upon implementing the
change, a performance test must be performed within 180 days.
The commenter expressed confusion about when performance tests
should be conducted in this situation. The commenter explained
that one might presume that performance tests should be conducted
2-38
-------
in this situation. The commenter explained that although we
might presume that performance tests should be conducted within
180 days of startup, it would eliminate any questions relative to
compliance if the regulations specifically stated when the
performance test is required.
Response
The requirements of Section 60.705(a) explicitly state that
when an owner or operator wishes to change the method of
compliance to a. different provision of Section 60.702, then that
owner or operator must notify the Administrator within 90 days
and conduct a performance test within 180 days of implementing
the change. Further, the requirements of the General Provisions
apply unless alternate provisions are spelled out in the
regulation. It is stated in Section 60.8(a) of the General
Provisions that 'the performance test should be conducted not
later than 180-days after initial startup. Therefore, there is
no need to repeat this language in the reactors NSPS.
2.7.6 Comment
One commenter (IV-D-li) requested clarification for the
flare requirement in Section 60.705(b)(3). The commenter thought
that instead of stating that the requirements for the
demonstration of compliance on a flare should be made during the
performance test, it could be clarified that the determination
should be made "for the purposes of complying with
Section 60.18."
Response
When using a flare to meet the standard, the owner or
operator of"the affected facility must comply with the
requirements of Section 60.18 of the General Provisions.
Reference to Section 60.13, for flares is specifically given in
Section 60-.702'(b) of the reactors NSPS. For this reason, it is
not necessary to include a specific reference requiring
compliance with Section 60.18 in Section 60.705(b)(3).
2.7.7 Comment
Two commenters (IV-G-01, IV-G-02) cited problems applying
performance tests and monitoring requirements set out in the
2-39
-------
regulation to fuel systems that collect and mix affected reactor
vent streams with natural gas or other fuel gas for use as a
primary fuel source. One of the commenters (IV-G-01) indicated
that his plant-wide fuel system provides fuel for numerous
(100 or more) process heaters and boilers.
One commenter (IV-G-01) stated that although the monitoring
and testing requirements set out in the regulation may be
appropriate for incinerators combusting waste vent streams, they
are not appropriate for fuel gas systems such as this. This
commenter pointed out that for such a fuel system, the required
temperature monitoring parameter does not correlate to VOC
removal. This commenter explained that it would be difficult and
costly to demonstrate that each of the boilers or process heaters
in the system is achieving the required 98 percent reduction
efficiency.
This commenter added that as long as the process heaters and
boilers in the system are operating properly and ignition is
maintained,-the 98 percent reduction efficiency required by the
NSPS would be greatly exceeded. This commenter further stated
that for process and safety reasons, fuel flow to the boiler or
process heater is-always stopped if a flame is not present. This
commenter felt that due to the ability of these boilers and
process heaters to achieve the 98 percent destruction efficiency,
these fuel systems should be able to monitor operating parameters
appropriate to their particular operations to ensure that
sufficient combustion is being achieved.
One commenter (IV-G-Ol) stated that at least 98 percent
destruction efficiency based on good combustion practices,
including adequate residence time, temperature, and mixing, was
reported for the example operations. Examples of these
operations were cited by the commenter. The commenter requested
that EPA allow facilities that combust reactor vent gases in
boilers and heaters to identify an appropriate operating
parameter for each combustion device to monitor as an indicator
that combustion is present. Because normal monitoring of
combustion devices is essential to ensure proper operation, the
2-40
-------
commenter stated that facilities generally have in place
appropriate monitoring procedures to enable the identification
and control of combustion process malfunctions such as flame
loss.
Response -
The EPA agrees that when a vent stream is combusted as
primary fuel, the fuel gas is passing through the flame front
and, on average, it is combusted at a higher temperature than if
it were being introduced into the flame with combustion air.
Based on emission calculations for natural gas fuel combustion,
it has been demonstrated that boilers and process heaters with
design capacities ranging from 10 to 100 million British thermal
units per hour (MM BTU/hr) achieve greater than 99.99 percent
combustion efficiency. In general, it is expected that SQCMI
chemicals affected by this standard would be easier to combust
than natural gas. One commenter submitted results of a Reference
Method 25A performance test conducted on a unit with design
capacity of 70 MM BTU/hr. The results of this test demonstrated
that TOG was reduced by greater than 99.99 percent. The above
information supports the commenter's claim that an affected vent
stream combusted in a boiler or process heater as primary fuel
.would achieve greater combustion efficiency than the 98 percent •
level required by the standards.
It is also in the best interest of the owner or operator to
achieve the greatest combustion efficiency possible when using
the vent stream as primary fuel. The process heaters and boilers
in the fuel system are operated to produce steam or heat, so that
greater combustion efficiency would minimize the amount of
supplemental fuel required and reduce operating costs.
In addition, for safety reasons, the fuel flow to a unit in
a fuel system of the type described by the commenter would be
shut down immediately if the combustion device fails to operate.
Fuel collecting inside a unit in the absence of combustion could
result in a highly flammable and dangerous situation once the
flame is reinstated. The EPA believes that, to avoid an
explosion, the owner or operator would ensure that any vent
2-41
-------
stream being used as fuel does not pass through the combustion
device without a flame present. In a case such as this, the vent
stream would be diverted to another control device that would
have to comply with NSPS requirements.
For the above reasons, EPA has.determined that performance
testing and temperature monitoring for those boilers and process
heaters combusting vent streams as primary fuel is not warranted;
furthermore, based on the performance of these types of units, it
is believed that they would already be achieving the levels
required by the standards. In view of this, the performance
testing and temperature monitoring requirements are not deemed
necessary to ensure compliance with the standards. The EPA,
therefore, is deleting performance testing and temperature
monitoring requirements for those affected vent streams combusted
as primary fuel in process heaters and boilers. However,.
performance testing and monitoring is required for all
incinerators, and for boilers'and process heaters with design
capacity less than 150 MM Btu/hr that are not combusting their
vent streams as primary fuel.
To demonstrate that affected vent streams are being routed
to appropriate control devices, EPA is adding a requirement for
any type of control device used, that the owner or operator
retain a schematic diagram of the affected vent stream,
collection system, fuel system, combustion device(s), and any
bypass systems. To demonstrate where or how the affected vent
stream is being controlled, EPA is adding a requirement for all
affected vent streams being controlled in a control device. The
requirement specifies that the owner or operator retain a
schematic diagram of the affected vent stream, collection system,
fuel system, control devices, and any bypass systems. The EPA
expects ao additional burden associated with this requirement.
Retaining a schematic diagram on site would provide an
enforcement mechanism to ensure that the affected vent stream is
being routed to an appropriate control device. The schematic
diagram would also indicate whether or not the vent stream is
2-42
-------
being diverted to the atmosphere or to an additional control
device. ~"
2.7.8 Comment
One commenter (IV-G-01) questioned the usefulness of flow
indicators on the type of fuel gas system where the vent stream
that is used as primary fuel is never vented to the atmosphere.
Response
As discussed previously, EPA has reevaluated the use of flow
indicators and has decided to alter the position of the flow
indicator so that it would provide an indication of those times
when the vent stream is being diverted to the atmosphere. See
the response to Comment 2.6.2. If no bypass lines to the
atmosphere are present, then flow indicators would not be
required.. However, if a vent stream is diverted to another
control device, such as a flare, that device must also comply
with the standards.
The proposed requirement'for monitoring periods of boiler or
process heater operation is not included in the final standards.
As explained in the previous response, boilers or process heaters
are typically operated continuously, and due to safety reasons a
vent stream is not expected to be introduced into a boiler or
process heater without a flame present. Any bypass of the
combustion device would be recorded due to the flow indicator
requirements. Therefore, a requirement to monitor periods of
operation of the boiler or process heater is unnecessary.
2.7.9 Comment
One commenter (IV-G-02) was aware of l) the use of process
vent streams as fuel gas in separate burners in process heaters
and boilers, and 2) the combustion of a vent stream combined with
combustion air and routed to a heater or boiler.
Response
Although this commenter was aware of situations in which
process vent streams are combusted as a secondary fuel in a
separate burner or are combined with combustion air, the
commenter did not provide any performance test data or emission
2-43": '
-------
calculations indicating that 98 percent organics reduction
efficiency was being met in these situations.
The EPA is concerned about situations in which vent streams
represent a small percentage of the total fuel input to a boiler
or process heater and are not mixed.with the primary fuel. When
vent gases are fed into the combustion system through a separate
burner, the potential exists for unstable burner operation and
burner "flame-out." When vent gases are mixed with combustion
air prior to entering the burners, the potential exists for the
vent gases to bypass the main flame zone due to poor adjustment
of burner air registers.
Based on discussion with combustion system operators and
review of other information, EPA concluded that the potential for
significant bypass, of vent gases around the combustion zone of
larger boilers and process heaters is small due to (l) the
residence time, temperature, and turbulence associated with the
flame zone in larger combustion systems, (2) the use of burner
management systems on most large combustion systems that reduce
the potential for undetected flame-outs, and (3) the presence of
operating staffs that would detect a problem if it occurred.
Therefore, as at proposal, performance testing and temperature
monitoring are not required for boilers or process heaters with
capacities of ISO MM Btu/hr or greater.
The situation for smaller boilers and process heaters is
different, however. For example, many small combustion systems
are not equipped with flame scanner systems that automatically
stop the flow of vent gases used as a secondary fuel in the event
of a burner flame-out. Also, the smaller devices do not have the
residence time or temperature of the larger combustion systems.
Furthermore, as stated above, no data were provided by the
commenter to assure such systems would achieve 98 percent
reduction of organics. As a result, the requirements for
performance testing and temperature monitoring are being retained
for vent streams being used as secondary fuels or combined with
combustion air in boilers and process heaters smaller than 150 MM
Btu/hr.
2-44
-------
2.7.10 Comment
One commenter (IV-G-02) indicated that it would be difficult
to determine the organics destruction efficiency of vent streams
that represent a small fraction of the total fuel input to a
combustion system. • -
Response
After further review, EPA agrees that it may be difficult
for boilers and process heaters in which vent streams are
secondary fuels to determine the destruction efficiency
specifically for the vent gases. As a result, a provision has
been added to the rule clarifying that Method 18 should be used
to demonstrate that the reduction in TOG emissions (minus methane
and ethane) by 98 percent or to 20 ppmv should be based on the
combined stream (the vent stream plus the primary fuel and all .-
secondary fuels), rather than on the vent gases only.
2.8 REPORTING AND RECORDKEEPING
2.8.1 Comment
One commenter (IV-D-08) recommended that an annual
performance test be included as an alternative to the extensive
reporting requirements set out in Section 60.705(b)(4). Based on
results from implementing the requirements set out in the air
oxidation NSPS and distillation NSPS, this commenter felt that
the requirements of the reactors NSPS would pose a significant
recordkeeping burden. This commenter noted that although
performance testing is expensive, there will be some situations
where it may be less costly to a complex plant than maintaining
an extensive amount of records.
Response
Conducting an annual performance test in lieu of the
required reporting,requirements- is not an appropriate alternative
to monitoring a process parameter. An annual performance test
would not indicate compliance through the year. The reporting
and recordkeeping requirements provide a means of documenting
monitoring compliance on a continuous basis and allow the source
to demonstrate a continuous ability to meet the standard.'
2.-4S
-------
2.8.2 Comment
One commenter (IV-D-08) recommended that to eliminate
confusion, Section 60.705 should directly reference the
recordkeeping time period from Section 60.7(d) of the General
Provisions, which states that "the file shall be retained for at
least 2 years following the date of such measurements,
maintenance, reports, and records."
Response
As stated in two previous responses (see Comments 2.7.5
and 2.7.7), unless alternative requirements are given in the
regulation, the General Provisions would apply. Section 60.7(d)
of the General Provisions states that records "shall be retained
for at least 2 years following the date of such measurements,
maintenance, reports, and records." Therefore, records kept for
compliance purposes for the reactors NSPS are required to be
retained for at least 2 years. There is no need to repeat this
language in the reactors NSPS.
2.8.3 Comment
One commenter (IV-D-ll) stated that the requirements for
reporting and recordkeeping are very detailed and should be
simplified in cases where the intent can be satisfied by an
alternative means. The commenter further explained that to avoid
the possibility of numerous reports on a scattered basis, these
reporting and recordkeeping requirements should be summarized
into a semiannual report to be submitted, for example, in January
and July of each year.
Response
The compliance procedures seem complicated because there are
several different routes to comply with the reactors NSPS. For
example, the owner or operator may elect to comply with the NSPS
by installing an additional condenser or by combusting emissions
in a flare or other device. In each case, specific monitoring,
reporting, and recordkeeping provisions must be specified in the
final regulation. These requirements are nearly identical to the
requirements in the distillation and air oxidation NSPS. To
remain consistent and because industry has become familiar with
2-46
-------
these requirements, the monitoring, reporting, and recordkeeping
provisions will not be revised. However, Tables 2-2 through 2-4
are provided to give a general summary of the monitoring,
reporting, and recordkeeping requirements. This general summary
should assist the owner or operator in.identifying and
locating the applicable requirements and locating these
requirements in the regulation for reactor processes.
Semiannual reports for each affected facility are required
under Section 60.705(1) of the reactors NSPS. The semiannual
report should include the following types of information:
• any exceedances of monitored parameters;
• any periods of time when the vent stream is diverted to
the atmosphere from the control device;
• any periods of time and duration when the pilot flame
of a flare is absent;
• any change made in equipment or process operations that
increases the operating vent stream flow rate above the
low flow exemption level;
• any recalculation of the THE index;
• any periods of time and duration when the seal
mechanism is broken or the by-pass line valve pos- tio:
changes; and
• any change made in equipment or process operatic that
increases the vent stream concentration above tht. low
concentration exemption level.
An exact month for submitting the report is not specified. The
initial report would be submitted 6 months following the startup
date of the affected facility, and subsequent reports would be
submitted in 6-month intervals following that date.
2.8.4 Comment
Four commenters (IV-D-08, IV-D-11, IV-D-12, IV-D-14)
requested that guidance be provided for the initial notification
requirements for facilities that are constructed, reconstructed,
or modified between the date of proposal and the date of
promulgation of the reactors NSPS. One commenter (IV-D-12) noted
2-47
-------
TABLE 2-2. MONITORING AND REPORTING/RECORDKEEPING REQUIREMENTS
FOR COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL
ORGANIC COMPOUND EMISSIONS OR A LIMIT OF 20 ppmv
Type of control device
used for compliance
Monitoring equipment
required3
Parameters
to be monitored
Recordkeeping
requirements
Parameter boundary
exceedances to report
Thermal incinerator
Catalytic incinerator
•oiler or process
heater
Boiler or process
heater (design heat
input capacity <4A HW,
except mere vent
stream used as primary
fuel)
Temperature monitoring
device (installed in
firebox or ductwork
immediately down-
stream) equipped with
a continuous recorder
[60.703(a)(1)(i)3
Flow indicator at
entrance to bypass
line equipped with a
continuous recorder
[60.703(a)(2)(i)3B
Temperature monitoring
device (installed in
gas stream imediately
before and after
catalyst bed) equipped
with a continuous
recorder
[60.703(a)(1)(ii)3
Average firebox
temperature
Continuous records
Flow indicator
equipped with a
continuous recorder
[60.703(a)(2)35
Flow indicator
equipped with a
continuous recorder
[60.703(c)(1Xi)3B
Temperature monitoring
device with continuous
recorder
[60.703(0(2)3
Presence of flow away
from incinerator, at
least once every
15 minutes
Average temperature
upstream and
downstream of the
catalyst bed
Continuous records;
schematic diagram
Continuous records
Presence of flow away
from incinerator, at
least once every
15 minutes
Presence of flow away
from boiler or
process heater, at
least once every
15 minutes
Average combustion
temperature
Continuous records;;
schematic diagrams
Continuous records;;
schematic diagrams
Continuous records
All 3-hour periods of
operation when average
combustion temperature
is >28°C (50°F) below
the average value
measured during the most
recent performance test
[60.705(0(1)3
Periods when the vent
stream is diverted from
the combustion device
[60.705(0(2)3
All 3-hour periods of
operation when the
average temperature of
vent stream upstream of
the catalyst bed is
>28°C (50°F) below the
average value from the
most recent performance
test [60.705(0(2)]
All 3-hour periods of
operation when the
average temperature,
difference across the
catalyst bed is
80 percent of the average
temperature difference
measured during the most
recent performance test
[60.705(0(2)3
Periods when the vent
stream is diverted from
the combustion device
[60.705(0(2)3
Periods when the vent
stream is diverted from
the combustion device
[60.705(1X2)3
All 3-hour periods of
operation when average
combustion temperature
is >28°C (50°F) below
the average value from
the most recent
performance test where
the vent stream is
introduced with
combustion air or as a
secondary fuel
£60.705(0(3)3
•Regulatory citations are listed in brackets.
''Where the by-pass line is secured in the closed position with a car-seal or lock-and-key type configuration, a flow
indicator is not required. Visual inspection is required at least once per month.
2-50
-------
TABLE 2-3.
MONITORING AND REPORTING/RECORDKEEPING REQUIREMENTS
FOR AFFECTED FACILITIES COMPLYING
WITH FLARE SPECIFICATIONS
Type of control device
used for compliance
Monitoring equipment
required3
Parameters
to be monitored
Recordkeeping
requi rements
Parameter boundary
exceedances to report
Flare
Heat sensing device
[60.703(b>(1)3
Flow indicator*3
[60.703(b)(2)(i)3
Presence of a flame
at the pilot light
Presence of flow
diverted away from
flare, at least once
every 15 minutes
Continuous records
Continuous records;
schematic diagrams
All periods when the
pilot flame is absent
[60.705(1X3)3
Periods when the vent
stream is diverted from
the combustion device
[60.705(1X2)3
aRegulatory citations are listed in brackets.
bwhere the by-pass line is secured in the closed position with a car-seal or lock-and-key type configuration a flow
indicator is not required. Visual inspection is required at least once per month. connguration, a flow
2-51
-------
TABLE 2-4. MONITORING AND REPORTING/RECORDKEEPING REQUIREMENTS FOR
MAINTAINING A TOTAL RESOURCE EFFECTIVENESS INDEX VALUE >1.0
Final recovery device
Monitoring equipment
required3
Parameters
to be monitored
Recordkeeping
requi rements
Boundary
exceedances to report3
Absorber
Condenser
Carbon adsorber
Scrubbing liquid
temperature monitor
equipped with a
continuous recorder
[60.703(d)(1)(i>]
Specific gravity
monitor equipped
with a continuous
recorder
£60.703(d)(1)(i)3
Organic monitoring
device equipped with
continuous recorder
r60.703(d)(1)(ii)3fa
Condenser exit
temperature
monitoring device
equipped with
continuous recorder
[60.703(d)(2)(i)]
Organic monitoring
device equipped with
continuous recorder
[60.703(d)(2)(ii)]fa
Integrating steam
flow monitoring
device and carbon
bed temperature
monitoring device,
each equipped with a
continuous recorder
[60.703]
Average exit
temperature of the
absorbing liquid
Exit specific gravity
(or alternative
parameter that
measures the degree
of absorbing liquid
saturation, if
approved by the
(Administrator)
Concentration level
or reading indicated
by the organic
monitoring device
at the outlet of the
absorber
Average exit (product
side) temperature
Continuous records;
Continuous records;
Continuous records
Continuous records
Concentration level
or reading indicated
by the organic
monitoring device at
at the outlet of the
condenser
Total steam mass flow
during carbon bed
regeneration cycle(s)
Continuous records
Continuous records
All 3-hour periods of
operation when average
temperature is >1°C
(20°F) above the average
value from the most
recent performance
test
C60.705(f)(1)(i)]
All 3-hour periods of
operation when average
liquid specific gravity
is >0.1 unit above or
below the average value
from the most recent
performance test
t60.705(f)(1)(ii)]
All 3-hour periods of
operation showing
>20 percent of the
amount measured by the
monitoring device during
the most recent
performance test
t60.705(f )(/>,
All 3-hour periods of
operation when average
temperature is >6°C
(11°F> above the average
value from the most
recent performance test
[60.705(f)(2)3
All 3-hour periods of
operation showing
>20 percent of the amount
measured by the
monitoring device during
the most recent
performance test
[60.705(f)(4)J
When <10 percent below
the value measured during
most recent performance
test t60.705(f)(3)(i)]
(continued)
2-52
-------
TABLE 2-4. (Continued)
Final recovery device
Carbon adsorber
(continued)
Monitoring equipment
required3
Parameters :'
to be monitored
Temperature of the
carbon bed after
Recordkeeping
requi rements
Continuous records
Boundary
exceedances to report3
When >10 percent or 5°C
more than thp valna
Organic monitoring
device equipped with
continuous recorder
[60.703(dX3Xii)]fa
regeneration [and
within 15 minutes
of completing any
cooling cycle(s)]
Concentration level
or reading indicated
by the organic
monitoring device
at the outlet of
the carbon adsorber
Continuous records
measured during the most
recent performance test
[60.70520 percent of the amount
measured by the
monitoring device during
the most recent
performance test
[60.705(f)(4>]
"Regulatory citations are listed in brackets.
Concentrat1on level «** ^ monitored as an alternative to monitoring the other parameters) listed for
2-53
-------
that the requirement in 40 CFR 60.7 specifies the timetable for
facilities to submit initial notification to EPA; however, no
specific provision is given for facilities that are constructed,
modified, or reconstructed between proposal and promulgation.
All four commenters felt that .the timing requirement of 30 days
for initial notification is unrealistically tight." They
recommended allowing a minimum of 90 days after promulgation for
the initial notification.
IK
Response
The owner or operator of an affected source must submit a
notification of the anticipated date of initial startup of the
facility no more than 60 days nor less than 30 days prior to such
date [Section 60.7(a) (2)], and a notification of the actual date
of initial startup of the affected facility within 15 days after
such date [Section 60.7(a) (3)] .- In some instances, however, the
initial startup of the facility may occur before the date of
promulgation. In cases such as this, EPA has a policy of
allowing these facilities to make initial notification within
30 days after promulgation.
2.8.5 Comment
One commenter (IV-D-08) requested that the reactors NSPS
address exceedances that occur during startup or shutdown. The
commenter also pointed out that Section 60.8(c) of the General
Provisions states that such exceedances would not be considered a
violation unless specified in the applicable standard. The
commenter suggested that Section 60.705 of the reactors NSPS be
modified to address startup/shutdown exceedances.
Response
Section 60.8(c) of the General Provisions specifies that
emissions in excess of the level of the applicable emission limit
during periods of startup and shutdown are not considered a
violation of the applicable emission limit. This means that
emission levels during these periods are not counted as
violations if they exceed the levels specified in the standards.
Because exceedances are not addressed in the reactors NSPS, the
language of Section 60.8(c) applies. Because the commenter
neither provided information on controls that would be applicable
2-54
-------
in this situation nor indicated knowledge of any such technology,
no basis exists for modifying the standard to require emissions
control during the startup or shutdown period. Because
exceedances are not addressed in the reactors NSPS, the language
of Section 60.8(c) applies. .Therefore, exceedances that occur
during startup or shutdown should not be reported as violations.
2.9 GENERAL
2.9.1 Comment
One commenter (IV-D-15) requested that in the regulation,
English measurements be included in parentheses following the
currently expressed metric measurements. The commenter
recognized that"EPA is committed to using the metric measurement
system; however, the commenter pointed out that many members of
the regulated community are still somewhat unfamiliar with it.
The commenter cited an illustration saying that measurements such
as 1 gigagram are not immediately recognizable to a significant
number of members of the regulated community.
Response
The EPA agrees with the commenter that, in some cases,
certain English measurements may be more commonly used than their
metric equivalents. For this reason, EPA will include in the
regulation English conversions for the less well known metric
measurements, such as gigagram per- year and megajoules per
kilocalorie.
2-55
-------
-------
TECHNICAL REPORT DATA
IT'lease read Instructions on the reverse before completing)
I. REPORT NO.
EPA-450/3-90-016b
3. RECIPIENT'S ACCESSION NO.
i. TITLE AND SUBTITLE
Reactor Processes in Synthetic Organic Chemical
Manufacturing Industry—Background Information for
Promulgated Standards
5. REPORT DATE
February 1993
6. PERFORMING ORGANIZATION CODE
iUTHOR
-------
------- |