reductions anticipated from implementation of controls used to meet the
proposed standards and to achieve additional HAP emission reductions.
Though we have not proposed to prescribe additional specific controls
to the existing inventories because remaining emissions are fugitive in
nature and less certain in terms of frequency of events and
characterization of emissions, there are still measures that are likely
available that could be employed to address emission sources in a more
directed manner. For example, identifying and reducing emissions from
sources such as maintenance events that could not be accounted for in
the post control modeling exercise would be effective in achieving
additional emission reductions. In addition to proposing this fenceline
monitoring work practice standard under CAA section 112(d)(6)
reflecting developments in practices, processes, and control
technologies, we also request comment on whether it would be
appropriate, in the final rulemaking, to promulgate these proposed
fenceline monitoring work practice standards, including the proposed
fenceline action levels for EtO and chloroprene, under the second step
of the CAA section 112(f)(2) residual risk decision framework to
provide an ample margin of safety to protect public health. Making such
a determination might be warranted, for example, in light of the fact
that we considered the facility-wide risk as an additional factor not
considered in the source category-specific risk acceptability decisions
for the SOCMI and Neoprene Production source categories that are both
the subject of this single combined rulemaking action.
    For further details of the analysis, see the document titled Clean
Air Act Section 112(d)(6) Technology Review for Fenceline Monitoring
located in the SOCMI Source Category that are Associated with Processes
Subject to HON and for Fenceline Monitoring that are Associated with
Processes Subject to Group I Polymers and Resins NESHAP, which is
available in the docket for this rulemaking.
    Non-source category emissions. This proposed approach also
considers the possibility that offsite sources could contribute to
modeled concentrations at a facility's fenceline. Additionally, non-HON
and non-P&R I sources could be located within facility property
boundaries that also contribute to monitor readings. In this proposal,
we are allowing the subtraction of offsite interfering sources (as they
are not within the control of the owner or operator) through site
specific monitoring plans, but we are not providing this option for
onsite, non-source category emissions. The action levels above were
based on facility-wide emissions, and therefore these non-source
category sources have been considered in their development. Applying
the fenceline standard to the whole facility will also limit emissions
of toxic HAP from all sources and provide more certainty in decisions
being made on whether the entire facility emissions align with what is
expected from the EPA's analysis. It will also provide assurances to
fenceline communities that emission reductions are achieved and
maintained. This is important in the chemical sector, where there could
be numerous source

categories that can be collocated within a larger facility, and have
common tank farms, wastewater systems, heat exchangers, APCDs, fuel gas
systems, etc., that may be assigned or apportioned to various source
categories.
    Corrective action requirements. The proposed fenceline monitoring
provisions would require the initiation of root cause analysis upon
exceeding the annual average concentration as determined on a rolling
average every sampling period. The root cause analysis is an assessment
conducted through a process of investigation to determine the primary
underlying cause and other contributing causes of an exceedance of the
action level. The root cause analysis would be required to be initiated
within 5 days of determining that an updated annual average
concentration of a target pollutant exceeds the applicable action
level. A root cause analysis must be conducted following each 14-day
sampling period in which the annual average concentration(s) remain
above the action level to determine whether the monitoring results and
associated data indicate additional sources of emissions contributing
to concentrations remaining above the action level. If the owner or
operator cannot determine the root cause of the exceedance within 30
days of determining there was an exceedance of an action level, the
owner or operator would be required to use real-time sampling
techniques (e.g., mobile gas chromatographs) to determine the root
cause of the exceedance.
    If the underlying causes of the action level exceedance are deemed
to be from sources under the control of the owner or operator, the
owner or operator would be required to take corrective action to
address the underlying cause of the exceedance and to bring
concentrations back below the action level as expeditiously as
possible. Completion of the root cause analysis and initial corrective
action would be required within 45 days of determining that there was
an exceedance of an action level. If the owner or operator requires
longer than 45 days to implement the corrective actions identified by
the root cause analysis, the owner or operator would be required to
submit a corrective action plan no later than 60 days after completion
of the root cause analysis.
    After completion of the initial corrective action, if the delta c
for the next sampling period for samples collected by EPA Methods 325A/
B or the next three sampling periods for samples collected by EPA
Method 327 \116\ are below the action level, then the corrective action
is assumed to have fixed the problem, and the owner and/or operator
would have no further obligation for additional corrective action.
However, if the delta c for the subsequent sampling periods after
initial corrective action is over the action level, then the owner or
operator would have to submit a corrective action plan and schedule for
implementing design, operation, and maintenance changes to eliminate as
quickly as possible and prevent recurrence of the primary cause and
other contributing causes to the exceedance of the action level in
order to reduce annual average concentrations below the action level.
The owner or operator would be required to include the implementation
of real-time sampling techniques to locate the primary and other
contributing causes of the exceedance in the corrective action plan.
While the action level(s) are based on annual average concentrations,
once an action level is exceeded, each sampling period that exceeds the
action level contributes to the delta c remaining above the action
level. An investigation must be conducted following these high biweekly
periods to determine the root cause and, if appropriate, to correct the
root cause expeditiously in order to bring the annual average delta c
below the action level.
---------------------------------------------------------------------------

    \116\ The EPA is proposing that three sample periods must remain
below the action level for samples taken by EPA Method 327 because
three is equal to the number of samples that would be taken during
one sample period for EPA Methods 325A/B. Requiring three sample
periods also ensures that a sample will have been taken at every
monitoring location at the site following the completion of the
corrective action.
---------------------------------------------------------------------------

    Costs associated with fenceline monitoring requirements. We
estimated costs to monitor for benzene, 1,3-butadiene, chloroprene, and
ethylene dichloride at the fenceline using final rule costs for passive
diffusive tube monitoring using the medium model plant costs for the
2015 Petroleum Refinery Sector final rule (80 FR 75178, December 1,
2015) and scaled costs to 2021 dollars. For EtO and vinyl chloride, we
estimated fenceline monitoring costs for 8 summa cannisters around the
fenceline every 5 days. We also note that there a number of HON
facilities that are either collocated with refineries who are already
conducting passive diffusion tube fenceline monitoring for benzene as
well as some HON facilities under consent decree conducting fenceline
monitoring for benzene with passive diffusion tubes, so costs to add
laboratory analysis for a second analyte under this action are minimal
(i.e., $1,300 more per year) for these facilities, and why monitoring
scenario 2 in the table below for the HON is less costly than
monitoring scenario 1 even though more facilities fall into the
monitoring scenario 2 category. In total for this proposed rulemaking
package, we estimate nationwide impacts for fenceline monitoring to be
$9,881,000 for total capital investment and $33,310,000 per year for
total annualized cost, and estimate that 126 of the 207 HON facilities
and 12 of the 19 P&R I facilities would be required to conduct
fenceline monitoring as they emit at least one of the six HAP of
interest. Tables 26 and 27 provide the breakdown of estimated
nationwide costs for fenceline monitoring as applied to all HON and P&R
I sources. Note that ten facilities have collocated sources subject to
multiple NESHAP (i.e., the HON and P&R I) and would be required to
conduct fenceline monitoring under both rules, therefore where this
occurred, we assigned costs and included the facility under the SOCMI
source category for impacts to avoid double counting. For further
information, see the document titled Clean Air Act Section 112(d)(6)
Technology Review for Fenceline Monitoring located in the SOCMI Source
Category that are Associated with Processes Subject to HON and for
Fenceline Monitoring that are Associated with Processes Subject to
Group I Polymers and Resins NESHAP, which is available in the docket
for this rulemaking.

                        Table 26--Nationwide Cost Impacts of Fenceline Monitoring for HON
----------------------------------------------------------------------------------------------------------------
                                                                                Total
                                         Number           Monitoring option        Total capital    annualized
        Monitoring scenario            facilities            description          investment ($)  costs (million
                                        impacted                                                       $/yr)
----------------------------------------------------------------------------------------------------------------
1..................................              35  Passives only (1 analyte)..       4,016,000       2,141,000
2..................................              46  Passives only (2 analytes).       2,295,000       1,282,000
3..................................               9  Cannisters only............         115,500       5,366,000
4..................................              16  Cannisters and passives (1        1,606,000      10,397,000
                                                      analyte).
5..................................              20  Cannisters and passives (2        1,721,000      12,869,000
                                                      analytes).
----------------------------------------------------------------------------------------------------------------

                       Table 27--Nationwide Cost Impacts of Fenceline Monitoring for P&R I
----------------------------------------------------------------------------------------------------------------
                                         Number                                                        Total
        Monitoring scenario            facilities         Monitoring option        Total capital    annualized
                                        impacted             description          investment ($)   costs ($/yr)
----------------------------------------------------------------------------------------------------------------
1..................................               1  Cannisters and passives (2          114,700         659,000
                                                      analytes).
2..................................               1  Cannisters only............          12,800         596,000
----------------------------------------------------------------------------------------------------------------

    Additional requirements of the fenceline monitoring program. The
EPA is proposing at 40 CFR 63.182(e) that fenceline data be reported on
a quarterly basis. Each report would contain the results for each
sample where the field portion of sampling is completed by the end of
the quarter, as well as for associated field and method blanks (i.e.,
each report would contain data for at least 6, 2-week sampling periods
and 18 canister sampling periods). These data would be reported
electronically to the EPA within 45 days of the end of each quarterly
period. See section III.E.3 of this preamble for further discussion on
electronic reporting and section III.F.1 of this preamble for further
discussion on the compliance dates we are proposing.

D. What actions related to CAA section 112(d)(2) and (3) are we taking
in addition to those identified in the CAA sections 112(f)(2) and
(d)(6) risk and technology reviews and CAA section 111(b)(1)(B) NSPS
reviews?

    In addition to the proposed actions discussed in this section III.B
of this preamble to reduce risk from EtO emission sources (from HON
processes) and chloroprene emission sources (from P&R I affected
sources producing neoprene), and our proposed actions discussed in this
section III.C of this preamble on NESHAP technology reviews, we are
also proposing other requirements for the HON, P&R I, and P&R II based
on analyses performed pursuant to CAA section 112(d)(2) and (3),\117\
and that are consistent with Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), ensuring that CAA section 112 standards apply continuously.
We are proposing to: (1) Add new monitoring and operational
requirements for HON and P&R I flares, (2) add work practice standards
for periods of SSM for certain HON and P&R I vent streams (i.e., PRD
releases, maintenance vents, and planned routine maintenance of storage
vessels), (3) clarify regulatory provisions for vent control bypasses
for certain HON and P&R I vent streams (i.e., closed vent systems
containing bypass lines), (4) add dioxins and furans emission limits to
the HON, P&R I, and P&R II, (5) add new monitoring requirements for HON
and P&R I pressure vessels, (6) add new emission standards for HON &
P&R I surge control vessels and bottoms receivers, (7) revise the
applicability threshold for HON transfer racks, (8) add requirements to
P&R II for heat exchange systems, and (9) add requirements to P&R II
for WSR sources and equipment leaks. See the subsections below for
specific details regarding these proposed actions, and for which rules
(i.e., HON, P&R I, and/or P&R II) we are proposing these actions.
---------------------------------------------------------------------------

    \117\ The EPA has authority under CAA section 112(d)(2) and (3)
to set MACT standards for previously unregulated emission points.
The EPA also retains the discretion to revise a MACT standard under
the authority of CAA section 112(d)(2) and (3) (see Portland Cement
Ass'n v. EPA, 665 F.3d 177, 189 (D.C. Cir. 2011)), such as when it
identifies an error in the original standard. See also Medical Waste
Inst. v. EPA, 645 F.3d 420, 426 (D.C. Cir. 2011) (upholding the EPA
action establishing MACT floors, based on post-compliance data, when
originally-established floors were improperly established).
---------------------------------------------------------------------------

1. Flares
    The EPA is proposing under CAA section 112(d)(2) and (3) to amend
the operating and monitoring requirements for flares used as APCDs in
the SOCMI and P&R I source categories because we have determined that
the current requirements for flares are not adequate to ensure the
level of destruction efficiency needed to conform with the MACT
standards in the HON and P&R I.\118\ As previously mentioned in section
III.C.3.b of this preamble, we are also proposing these same operating
and monitoring requirements for flares for NSPS subparts IIIa, NNNa,
and RRRa under CAA section 111(b)(1)(B). Flares are commonly used
within the SOCMI and P&R I source categories. The requirements
applicable to flares, which are used to control emissions from various
emission sources (e.g., process vents, storage vessels, transfer racks,
equipment leaks, wastewater streams), are set forth in the General
Provisions to 40 CFR part 63 and are cross-referenced in the HON and
P&R I. In general, flares used as APCDs are expected to achieve 98
percent HAP destruction efficiencies when designed and operated
according to the requirements in the General Provisions. Studies on
flare performance,\119\ however, indicate that these General Provision
requirements are inadequate to ensure proper performance of flares at
refineries and other petrochemical facilities (including SOCMI
facilities), particularly when either assist steam or assist air is
used. In addition, over the last decade, flare minimization efforts at
these facilities have led to an increasing number of flares operating
at well below their

design capacity, and while these efforts have resulted in reduced
flaring of gases, situations of over assisting with either steam or air
have become exacerbated, leading to the degradation of flare combustion
efficiency. Many HON and P&R I facilities operate directly downstream
from refineries and other petrochemical plants (e.g., ethylene
production plants) and, consequently, likely burn similar types of
waste gas constituents to a refinery or petrochemical plant (e.g.,
olefins and hydrogen). Given that flares at petrochemical plants, SOCMI
facilities, and a polymers and resins plant were also included in the
flare dataset that formed the underlying basis of the new standards for
refinery flares, we are proposing to apply the finalized suite of
operational and monitoring requirements for refinery flares \120\ to
those flares in the SOCMI source category that control emissions from
HON and P&R I processes. Therefore, these proposed amendments at 40 CFR
63.108 (for HON) and 40 CFR 63.508 (for P&R I) will ensure that
continuous compliance with the CAA section 112(d)(2) and (3) standards
is achieved for HON and P&R I facilities that use flares as APCDs to
meet the MACT standards at all times when controlling HAP emissions.
---------------------------------------------------------------------------

    \118\ P&R II sources do not use flares as APCDs as they are
making resins from chlorinated chemicals (i.e., epichlorohydrin
feedstocks), and chlorinated chemicals are not controlled with
flares.
    \119\ For a list of studies, refer to the technical report
titled Parameters for Properly Designed and Operated Flares, in
Docket ID Item No. EPA-HQ-OAR-2010-0682-0191.
    \120\ See 40 CFR 63.670 and 40 CFR 63.671 (originally finalized
in 80 FR 75178 on December 1, 2015; and amended in 81 FR 45232 on
July 13, 2016, in 83 FR 60696 on November 26, 2018, and in 85 FR
6064 on February 4, 2020).
---------------------------------------------------------------------------

    The General Provisions of 40 CFR 63.11(b) specify that flares be:
(1) Steam-assisted, air-assisted, or non-assisted; (2) operated at all
times when emissions may be vented to them; (3) designed for and
operated with no visible emissions (except for periods not to exceed a
total of 5 minutes during any 2 consecutive hours); and (4) operated
with the presence of a pilot flame at all times. These General
Provisions also specify both the minimum heat content of gas combusted
in the flare and maximum exit velocity at the flare tip. The General
Provisions specify monitoring for the presence of the pilot flame and
the operation of a flare with no visible emissions. We are proposing to
revise the General Provisions table to NESHAP subpart F (Table 3) and
the General Provisions table to NESHAP subpart U (Table 1), entries for
40 CFR 63.8(a)(4) and 40 CFR 63.11 such that these provisions do not
apply to flares because we are proposing to replace these provisions
with new standards we are proposing for flares used to comply with the
MACT standards in the HON and P&R I.
    In 2012, the EPA compiled information and test data collected on
flares and summarized its preliminary findings on operating parameters
that affect flare combustion efficiency in a technical report titled
Parameters for Properly Designed and Operated Flares, in Docket ID Item
No. EPA-HQ-OAR-2010-0682-0191.\121\ The EPA submitted this report,
along with a charge statement and a set of charge questions, to an
external peer review panel.\122\ The panel, consisting of individuals
representing a variety of backgrounds and perspectives (i.e., industry,
academia, environmental experts, and industrial flare consultants),
concurred with the EPA's assessment that the following three primary
factors affect flare performance: (1) The flow of the vent gas to the
flare; (2) the amount of assist media (e.g., steam or air) added to the
flare; and (3) the combustibility of the vent gas/assist media mixture
in the combustion zone (i.e., the net heating value, lower
flammability, and/or combustibles concentration) at the flare tip. In
response to peer review comments, the EPA performed a validation and
usability analysis on all available test data as well as a failure
analysis on potential parameters discussed in the technical report as
indicators of flare performance. The peer review comments are in the
document titled Peer Review of Parameters for Properly Designed and
Operated Flares, available in Docket ID Item No. EPA-HQ-OAR-2010-0682-
0193, which has been incorporated into the docket for this rulemaking.
These analyses resulted in a change to the population of test data that
the EPA used and helped form the basis for the flare operating limits
promulgated in the 2015 Petroleum Refinery Sector MACT final rule at 40
CFR part 63, subpart CC (80 FR 75178).\123\ We are also relying on the
same analyses and proposing the same operating limits for flares used
as APCDs in the SOCMI source category that control emissions from HON
processes (hereafter referred to as ``HON flares''). The Agency
believes, given the results from the various data analyses conducted
for the Petroleum Refinery Sector rule, that the operating limits
promulgated for flares used in the petroleum refinery sector are also
appropriate and reasonable for HON flares, and will ensure that these
flares meet the HAP destruction and removal efficiency at all times.
Therefore, we are proposing at 40 CFR 63.108 (for HON processes) and 40
CFR 63.508 (for P&R I processes) to replace all flare requirements
throughout the HON \124\ and P&R I \125\ with the Petroleum Refinery
Sector rule flare definitions and requirements in 40 CFR part 63,
subpart CC, with certain clarifications and exemptions discussed in
this section of the preamble, including, but not limited to, specifying
that several definitions in 40 CFR part 63, subpart CC, that apply to
petroleum refinery flares also apply to flares in the SOCMI source
category, adding a definition and requirements for pressure-assisted
multi-point flares, and specifying additional requirements when a gas
chromatograph or mass spectrometer is used for compositional analysis.
---------------------------------------------------------------------------

    \121\ See section II.D of this preamble, which addresses the
incorporation by reference of certain docket files such as this one
into the docket for this rulemaking.
    \122\ These documents can also be found at https://www.epa.gov/stationary-sources-air-pollution/review-peer-review-parameters-properly-designed-and-operated-flares.
    \123\ See the document titled Flare Performance Data: Summary of
Peer Review Comments and Additional Data Analysis for Steam-Assisted
Flares, in Docket ID Item No. EPA-HQ-OAR-2010-0682-0200 for a more
detailed discussion of the data quality and analysis; the document
titled Petroleum Refinery Sector Rule: Operating Limits for Flares,
in Docket ID Item No. EPA-HQ-OAR-2010-0682-0206 for a more detailed
discussion of the failure analysis and the document titled Flare
Control Option Impacts for Final Refinery Sector Rule, in Docket ID
Item No. EPA-HQ-OAR-2010-0682-0748 for additional analyses on flare
performance standards based on public comments received on the
proposed Petroleum Refinery Sector rule.
    \124\ Refer to proposed 40 CFR 63.108(a)(1) through (a)(22) for
a list of HON provisions that would no longer apply.
    \125\ Refer to proposed 40 CFR 63.508(a)(1) through (a)(32) for
a list of P&R I provisions that would no longer apply.
---------------------------------------------------------------------------

    The remainder of this section of the preamble includes a discussion
of requirements that we are proposing for HON and P&R I flares, along
with impacts and costs associated with these proposed revisions.
Specifically, this action proposes that HON and P&R I flares operate
pilot flame systems continuously and that flares operate with no
visible emissions (except for periods not to exceed a total of 5
minutes during any 2 consecutive hours) when the flare vent gas flow
rate is below the smokeless capacity of the flare. In addition, this
action proposes to consolidate measures related to flare tip velocity
and proposes new operational and monitoring requirements related to the
combustion zone gas. Further, in keeping with the elimination of the
SSM exemption as discussed in section III.E.1 of this preamble, this
action proposes a work practice standard related to the visible
emissions during periods when the flare is operated above its smokeless
capacity (e.g., periods of emergency flaring). Currently, the MACT
standards in the HON and P&R I cross-reference the General Provisions
at 40 CFR

63.11(b) for the operational requirements for flares used as APCD. This
proposal eliminates cross-references to the General Provisions and
instead specifies all new operational and monitoring requirements that
are intended to apply to flares used as APCDs in the HON and P&R I
standards. We are also proposing to include provisions at 40 CFR
63.110(j) that address compliance with the proposed operating and
monitoring requirements for flares in lieu of flare-related
requirements of any other 40 CFR part 60, 61, or 63 rule.
a. Pilot Flames
    The HON and P&R I reference the flare requirements in 40 CFR
63.11(b), which specify that a flare used as an APCD should operate
with a pilot flame present at all times. Pilot flames are proven to
improve flare flame stability, and even short durations of an
extinguished pilot could cause a significant reduction in flare
destruction efficiency. In this proposal, we are proposing to remove
the cross-reference to the General Provisions for HON and P&R I flares
and instead cross-reference 40 CFR part 63, subpart CC, to include in
the HON the existing provision that flares operate with a pilot flame
at all times and be continuously monitored for a pilot flame using a
thermocouple or any other equivalent device. We are also proposing to
add a continuous compliance measure that would consider each 15-minute
block when there is at least 1 minute where no pilot flame is present
when regulated material is routed to the flare as a deviation from the
standard. Refer to 40 CFR 63.108 (for HON), 40 CFR 63.508 (for P&R I),
and 40 CFR 63.670(b) and (g) for these proposed requirements. See
section III.D.1.e of this preamble for our rationale for proposing to
use a 15-minute block averaging period for determining continuous
compliance. We solicit comment on the proposed revisions for flare
pilot flames.
b. Visible Emissions
    The HON and P&R I reference 40 CFR 63.11(b), which specifies that a
flare used as an APCD should operate with visible emissions for no more
than 5 minutes in a 2-hour period. Owners or operators of these flares
are required to conduct an initial performance demonstration for
visible emissions using Method 22 of Appendix A-7 to 40 CFR part 60
(``Method 22''). We are proposing to remove the cross-reference to the
General Provisions for HON and P&R I flares and instead cross-reference
40 CFR part 63, subpart CC, to include this same limitation on visible
emissions. We are also proposing to clarify that the initial 2-hour
visible emissions demonstration should be conducted the first time
regulated materials are routed to the flare.
    With regard to continuous compliance with the visible emissions
limitation, we are proposing daily visible emissions monitoring for HON
and P&R I flares whenever regulated material is routed to the flare and
also visible emissions monitoring whenever visible emissions are
observed from the flare. On days that the flare receives regulated
material, we are proposing that owners or operators of HON and P&R I
flares monitor visible emissions at a minimum of once per day while the
flare is receiving regulated material using an observation period of 5
minutes and Method 22. Additionally, whenever regulated material is
routed to a flare and there are visual emissions from the flare, we are
proposing that another 5-minute visible emissions observation period be
performed using Method 22, even if the minimum required daily visible
emission monitoring has already been performed. For example, if an
employee observes visible emissions, the owner or operator of the flare
would perform a 5-minute Method 22 observation to check for compliance
upon initial observation or notification of such event. In addition, in
lieu of daily visible emissions observations performed using Method 22,
we are proposing that owners and operators be allowed to use video
surveillance cameras. We believe that video surveillance cameras would
be at least as effective as the proposed daily 5-minute visible
emissions observations using Method 22.
    We are also proposing to extend the observation period for a HON or
P&R I flare to 2 hours whenever visible emissions are observed for
greater than 1 continuous minute during any of the 5-minute observation
periods. Refer to 40 CFR 63.108 (for HON), 40 CFR 63.508 (for P&R I),
and 40 CFR 63.670(c) and (h) for these proposed requirements. We
acknowledge that operating a flare near the incipient smoke point (the
point at which black smoke begins to form within the flame) results in
good combustion at the flare tip; however, smoking flares can
contribute significantly to emissions of particulate matter that is 2.5
micrometers in diameter or smaller (PM2.5). Thus, while
increasing the allowable period for visible emissions may be useful
from an operational perspective, we do not believe the allowable period
for visible emissions should be increased to more than 5 minutes in any
2-hour period. We solicit comment on the proposed allowable period for
visible emissions from flares.
    As discussed later in this section, we are proposing additional
operational and monitoring requirements for HON and P&R I flares that
we expect will result in owners or operators of CMPUs installing
equipment that can be used to fine-tune and control the amount of
assist steam or air introduced at the flare tip such that combustion
efficiency of the flare will be maximized. These monitoring and control
systems will assist these flare owners or operators to operate near the
incipient smoke point without exceeding the visible emissions limit.
While combustion efficiency may be highest at the incipient smoke
point, it is not significantly higher than the combustion efficiency
achieved by the proposed operating limits discussed in section
III.D.1.d of this preamble. As seen in the performance curves for
flares, there is very limited improvement in flare performance beyond
the performance achieved at the proposed operating limits (see document
titled Petroleum Refinery Sector Rule: Operating Limits for Flares, in
Docket ID Item No. EPA-HQ-OAR-2010-0682-0206, which has been
incorporated into the docket for this rulemaking). We solicit comments
and data on appropriate periods of visible emissions that would
encourage operation at the incipient smoke point.
    In addition, we are proposing that the owner or operator establish
the smokeless capacity of each HON and P&R I flare based on design
specification of the flare, and that the visible emissions limitation
only apply when the flare vent gas flow rate is below its smokeless
capacity. We are proposing a work practice standard for the limited
times (i.e., during emergency releases) when the flow to a flare
exceeds the smokeless capacity of the flare, based on comments the EPA
received on the proposed Petroleum Refinery Sector rule. Refer to 40
CFR 63.108 (for HON), 40 CFR 63.508 (for P&R I), and 40 CFR 63.670(o)
for these proposed provisions. In the Petroleum Refinery Sector final
rule, the EPA explained that numerous comments on the proposal
suggested that flares are not designed to meet the visible emissions
requirements when operated beyond their smokeless capacity (80 FR
75178). According to commenters, flares are typically designed to
operate in a smokeless manner at 20 to 30 percent of full hydraulic
load. Thus, they claimed, flares have two different design capacities:
A ``smokeless capacity'' to handle normal operations and typical
process variations and a ``hydraulic load capacity'' to handle very
large volumes

of gases discharged to the flare as a result of an emergency shutdown.
According to commenters, this is inherent in all flare designs and has
not previously been an issue because flare operating limits did not
apply during malfunction events.
    For this proposed work practice standard, owners or operators would
need to develop a flare management plan for HON and P&R I flares that
identifies procedures for limiting discharges to the flare as a result
of process upsets or malfunctions that cause the flare to exceed its
smokeless capacity. In addition, for any flare that exceeds both the
smokeless design capacity and visible emissions limit, we are proposing
that owners or operators would need to conduct a specific root cause
analysis and take corrective action to prevent the recurrence of a
similarly caused event (similar to the prevention measures we are
proposing in this rule to minimize the likelihood of a PRD release, see
section III.D.2.a of this preamble). We are proposing that if the root
cause analysis indicates that the exceedance of the visible emissions
limit is caused by operator error or poor maintenance, then the
exceedance would be considered a deviation from the work practice
standard. We are also proposing that a second event within a rolling 3-
year period from the same root cause on the same equipment would be
considered a deviation from the standard. Finally, we are proposing
that a third visible emissions limit exceedance occurring from the same
flare in a rolling 3-year period would be a deviation from the work
practice standard, regardless of the cause.
    In several of the EPA's previous impact analyses (for petroleum
refinery flares and ethylene production flares),\126\ the EPA
established the number of events in a given time period that would be
the ``backstop'' (i.e., a violation of the standard). In each of these
analyses, the EPA evaluated four different timing alternatives (2 in 5
years; 2 in 3 years; 3 in 5 years; and 3 in 3 years) based on the
number of existing flares evaluated over a 20-year period, and
ultimately the EPA concluded that 3 events in 3 years would be
``achievable'' for the average of the best performing flares. We see no
reason why this would be any different for HON and P&R I flares. Even
if a best-performing flare ``typically'' only has one event every seven
years, the fact that these events are random by nature (unpredictable,
not under the direct control of the owner or operator) makes it
difficult to use a 5-year time span. Based on this analysis, three
events in 3 years would appear to be ``achievable'' for the average of
the best performing flares.
---------------------------------------------------------------------------

    \126\ See EPA-HQ-OAR-2010-0682-0793, EPA-HQ-OAR-2010-0682-0794,
and EPA-HQ-OAR-2017-0357-0017.
---------------------------------------------------------------------------

c. Flare Tip Velocity
    This action consolidates provisions related to flare tip velocity
for HON and P&R I flares. The HON and P&R I reference the flare
provisions in 40 CFR 63.11(b), which specify maximum flare tip
velocities based on flare type (non-assisted, steam-assisted, or air-
assisted) and the net heating value of the flare vent gas. Based on
data provided to EPA in response to our CAA section 114 request (see
section II.C of this preamble), 10 of the 18 flares that HON and P&R I
facilities reported using as APCDs are either steam- or air-assisted
(see the document titled Control Option Impacts for Flares Located in
the SOCMI Source Category that Control Emissions from Processes Subject
to HON and for Flares that Control Emissions from Processes Subject to
Group I and Group II Polymers and Resins NESHAPs, which is available in
the docket for this rulemaking). Maximum flare tip velocities are
required to ensure that the flame does not ``lift off'' the flare
(i.e., a condition where a flame separates from the tip of the flare
and there is space between the flare tip and the bottom of the flame),
which could cause flame instability and/or potentially result in a
portion of the flare gas being released without proper combustion. We
are proposing to remove the cross-reference to the General Provisions
for HON and P&R I flares and instead cross-reference 40 CFR part 63,
subpart CC, to consolidate the provisions for maximum flare tip
velocity into the HON and P&R I as a single equation, irrespective of
flare type (i.e., steam-assisted, air-assisted, or non-assisted). Refer
to 40 CFR 63.108 (for HON), 40 CFR 63.508 (for P&R I), and 40 CFR
63.670(d), (i), and (k) for these proposed provisions.
    Based on analysis conducted for the Petroleum Refinery Sector rule,
the EPA identified air-assisted test runs with high flare tip
velocities that had high combustion efficiencies (see the document
titled Petroleum Refinery Sector Rule: Evaluation of Flare Tip Velocity
Requirements, in Docket ID Item No. EPA-HQ-OAR-2010-0682-0212). These
test runs exceeded the maximum flare tip velocity limits for air-
assisted flares using the linear equation in 40 CFR 63.11(b)(8). When
these test runs were compared with the test runs for non-assisted and
steam-assisted flares, air-assisted flares appeared to have the same
operating envelope as the non-assisted and steam-assisted flares.
Therefore, for air-assisted HON and P&R I flares, we are proposing the
use of the same equation that non-assisted and steam-assisted flares
currently use to establish the flare tip velocity operating limit. We
are also proposing that the owner or operator determine the flare tip
velocity on a 15-minute block average basis. See section III.D.1.e of
this preamble for our rationale for proposing to use a 15-minute block
averaging period for determining continuous compliance.
    Finally, we are also proposing not to include the provision for the
special flare tip velocity equation in the General Provisions at 40 CFR
63.11(b)(6)(i)(A) for non-assisted HON and P&R I flares with hydrogen
content greater than 8 percent. This equation, which was developed
based on limited data from a chemical manufacturer, has very limited
applicability for flares used as APCDs in the SOCMI source category
because it only provides an alternative for non-assisted flares with
large quantities of hydrogen. Available data indicates that
approximately 50 percent of the flares used at HON and P&R I facilities
are either steam-assisted or air-assisted, which seems to indicate that
approximately 50 percent are non-assisted flares. Instead, we are
proposing compliance alternatives that we believe provide a better way
for HON and P&R I flares with high hydrogen content to comply with the
rule while ensuring proper destruction performance of the flare (see
section III.D.1.d of this preamble for the proposed compliance
alternatives). Therefore, for non-assisted HON and P&R I flares with
hydrogen content greater than 8 percent that are used as ACPDs, we are
not proposing to include this special flare tip velocity equation as a
compliance alternative. We request comment on the need to include this
equation.
d. Net Heating Value of the Combustion Zone Gas
    The current provisions for flares in 40 CFR 63.11(b) specify that
the flare vent gas meet a minimum net heating value of 200 British
thermal units per standard cubic foot (Btu/scf) for non-assisted flares
and 300 Btu/scf for air- and steam-assisted flares. The HON and P&R I
reference these provisions, but neither the General Provisions nor the
HON or P&R I include specific requirements for monitoring the net
heating value of the flare vent gas. Moreover, recent flare testing
results indicate that meeting a minimum net heating value limit alone
does not address instances when the flare may be

over-assisted because it only considers the net heating value of the
gas being combusted in the flare and nothing else (e.g., no assist
media). However, many industrial flares use steam or air as an assist
medium to protect the design of the flare tip, promote turbulence for
the mixing, induce air into the flame, and operate with no visible
emissions. Using excessive steam or air results in dilution and cooling
of flared gases and can lead to operating a flare outside its stable
flame envelope, reducing the destruction efficiency of the flare. In
extreme cases, over-steaming or excess aeration can snuff out a flame
and allow regulated material to be released into the atmosphere without
complete combustion. As previously noted, because available data
indicate that a preponderance of all HON and P&R I flares are either
steam- or air-assisted, it is critical that we ensure the assist media
is accounted for in some form. Recent flare test data have shown that
the best way to account for situations of over-assisting is to consider
the gas mixture properties at the flare tip in the combustion zone when
evaluating the ability to combust efficiently. As discussed in the
introduction to this section, the external peer review panel concurred
with our assessment that the combustion zone properties at the flare
tip are critical parameters to know in determining whether a flare will
achieve good combustion. The General Provisions, however, solely rely
on the net heating value of the flare vent gas, and we have determined
that is not sufficient for the flares at issue.
    In this proposal, in lieu of requiring compliance with the
operating limits for net heating value of the flare vent gas in the
General Provisions, we are proposing to cross-reference 40 CFR part 63,
subpart CC, to include in the HON and P&R I a single minimum operating
limit for the net heating value in the combustion zone gas (NHVcz) of
270 Btu/scf during any 15-minute period for steam-assisted, air-
assisted, and non-assisted HON and P&R I flares. Refer to 40 CFR 63.108
(for HON), 40 CFR 63.508 (for P&R I), and 40 CFR 63.670I and (m) for
these proposed provisions. The Agency believes, given the results from
the various data analyses conducted for the Petroleum Refinery Sector
rule, that this NHVcz operating limit promulgated for flares in the
Petroleum Refinery Sector source category is also appropriate and
reasonable and will ensure HON and P&R I flares meet the HAP
destruction efficiencies in the standard at all times when operated in
concert with the other proposed flare provisions (e.g., pilot flame,
visible emissions, and flare tip velocity requirements) (see the
memoranda titled: Petroleum Refinery Sector Rule: Operating Limits for
Flares and Flare Control Option Impacts for Final Refinery Sector Rule,
in Docket ID Item No. EPA-HQ-OAR-2010-0682-0206 and EPA-HQ-OAR-2010-
0682-0748, respectively). In addition, we are proposing that owners or
operators may use a corrected heat content of 1,212 Btu/scf for
hydrogen, instead of 274 Btu/scf, to demonstrate compliance with the
NHVcz operating limit for HON and P&R I flares; however, owners or
operators who wish to use the corrected hydrogen heat content must have
a system capable of monitoring for the hydrogen content in the flare
vent gas. The 1,212 Btu/scf value is based on a comparison between the
lower flammability limit and net heating value of hydrogen compared to
light organic compounds and has been used in several consent decrees
issued by the EPA. Based on analyses conducted for the Petroleum
Refinery Sector rule (see the document titled Flare Control Option
Impacts for Final Refinery Sector in Docket ID Item No. EPA-HQ-OAR-
2010-0682-0748), the EPA determined that using a 1,212 Btu/scf value
for hydrogen greatly improves the correlation between combustion
efficiency and the combustion zone net heating value over the entire
array of data.
    Furthermore, in addition to the NHVcz operating limit, we are
proposing a net heating value dilution parameter (NHVdil) for certain
HON and P&R I flares that operate with perimeter assist air. Refer to
40 CFR 63.108 (for HON), 40 CFR 63.508 (for P&R I), and 40 CFR
63.670(f) and (n) for these proposed provisions. For air-assisted
flares, use of too much perimeter assist air can lead to poor flare
performance. Furthermore, based on our analysis of the air-assisted
flare datasets (see the document titled Petroleum Refinery Sector Rule:
Operating Limits for Flares, in Docket ID Item No. EPA-HQ-OAR-2010-
0682-0206), we determined a NHVdil of 22 British thermal units per
square foot is necessary to ensure that there is enough combustible
material available to adequately combust the gas and pass through the
flammability region and also ensure that degradation of flare
performance from excess aeration does not occur. We found that
including the flow rate of perimeter assist air in the calculation of
the NHVcz does not identify all instances of excess aeration and could
(in some instances) even allow facilities to send very dilute vent
gases to the flare that would not combust (i.e., vent gases below their
lower flammability limit could be sent to flare). Instead, the data
suggest that the diameter of the flare tip, in concert with the amount
of perimeter assist air (and other parameters used to determine NHVcz),
provide the inputs necessary to calculate whether this type of flare is
over-assisted. This dilution parameter is consistent with the
combustion theory that the more time the gas spends in the flammability
region above the flare tip, the more likely it will combust. Also,
because both the volume of the combustion zone (represented by the
diameter) and how quickly this gas is diluted to a point below the
flammability region (represented by perimeter assist air flow rate)
characterize this time, it is logical that we propose such a parameter.
    We also found that some assist steam lines are purposely designed
to entrain air into the lower or upper steam at the flare tip; and for
flare tips with an effective tip diameter of 9 inches or more, there
are no flare tip steam induction designs that can entrain enough assist
air to cause a flare operator to have a deviation from the NHVdil
operating limit without first deviating from the NHVcz operating limit.
Therefore, we are proposing to allow owners or operators of HON and P&R
I flares whose only assist air is from perimeter assist air entrained
in lower and upper steam at the flare tip and with a flare tip diameter
of 9 inches or greater to comply only with the NHVcz operating limit.
Steam-assisted flares with perimeter assist air and an effective tip
diameter of less than 9 inches would remain subject to the requirement
to account for the amount of assist air intentionally entrained within
the calculation of NHVdil. However, we recognize that this assist air
cannot be directly measured, but the quantity of air entrained is
dependent on the assist steam rate and the design of the steam tube's
air entrainment system. Therefore, we are proposing provisions to
specify that owners or operators of these smaller diameter steam-
assisted HON flares use the steam flow rate and the maximum design air-
to-steam ratio of the steam tube's air entrainment system for
determining the flow rate of this assist air. Using the maximum design
ratio will tend to over-estimate the assist air flow rate, which is
conservative with respect to ensuring compliance with the NHVdil
operating limit.
    Finally, we are proposing that owners or operators record and
calculate 15-minute block average values for these parameters. Our
rationale for selecting a

15-minute block averaging period is provided in section III.D.1.e of
this preamble. We solicit comment on the proposed revisions related to
NHVcz.
e. Data Averaging Periods for Flare Gas Operating Limits
    Except for the visible emissions operating limits as described in
section III.D.1.b of this preamble, we are proposing to use a 15-minute
block averaging period for each proposed flare operating parameter
(i.e., presence of a pilot flame, flare tip velocity, and NHVcz) to
ensure that HON and P&R I flares are operated within the appropriate
operating conditions. We consider a short averaging time to be the most
appropriate for assessing proper flare performance because flare vent
gas flow rates and composition can change significantly over short
periods of time. Furthermore, because destruction efficiency can fall
precipitously when a flare is controlling vent gases below (or outside)
the proposed operating limits, short time periods where the operating
limits are not met could seriously impact the overall performance of
the flare. Refer to the Petroleum Refinery Sector rule preambles (79 FR
36880 and 80 FR 75178) for further details supporting why we believe a
15-minute averaging period is appropriate.
    Given the short averaging times for the operating limits, we are
proposing special calculation methodologies to enable owners or
operators to use ``feed forward'' calculations to ensure compliance
with the operating limits on a 15-minute block average for HON and P&R
I flares. Specifically, we propose using the results of the
compositional analysis determined just prior to a 15-minute block
period for the next 15-minute block average. Owners or operators of HON
and P&R I flares will then know the vent gas properties for the
upcoming 15-minute block period and can adjust assist gas flow rates
relative to vent gas flow rates to comply with the proposed operating
limits. In other words, ``feed forward'' means that owners or operators
would use the net heating value in the vent gas (NHVvg) going into the
flare in one 15-minute period to adjust the assist media (i.e., steam
or air) and/or the supplemental gas in the next 15-minute period, as
necessary, to calculate an NHVcz limit of 270 Btu/scf or greater using
the proposed equation. We recognize that when a subsequent measurement
value is determined, the instantaneous NHVcz based on that
compositional analysis and the flow rates that exist at the time may
not be above 270 Btu/scf. We are proposing that this is not a deviation
from the operating limit. Rather, we propose that the owner or operator
is only required to make operational adjustments based on that
information to achieve, at a minimum, the net heating value limit for
the subsequent 15-minute block average. We are, however, proposing that
failure to make adjustments to assist media or supplemental natural gas
using the NHVvg from the previous period in the equation provided for
calculating an NHVcz limit of 270 Btu/scf, would be a deviation from
the operating limit. Alternatively, because the owner or operator could
directly measure the NHVvg on a more frequent basis, such as with a
calorimeter (and optional hydrogen analyzer), the process control
system is able to adjust more quickly, and the owner or operator can
make adjustments to assist media or supplemental natural gas more
quickly. In this manner, the owner or operator is not limited by
relying on NHVvg data that may not represent the current conditions. We
are, therefore, also proposing that the owner or operator may opt to
use the NHVvg in such instances from the same period to comply with the
operating limit. For examples of ``feed forward'' calculations, please
see Attachment 3 of the document titled Flare Control Option Impacts
for Final Refinery Sector Rule, in Docket ID Item No. EPA-HQ-OAR-2010-
0682-0748.
    We are also proposing to clarify that when determining compliance
with the flare tip velocity and combustion zone operating limits
specified in 40 CFR 63.670(d) and (e), the initial 15-minute block
period starts with the 15-minute block that includes a full 15 minutes
of the flaring event. In other words, we are proposing to clarify that
the owner or operator demonstrate compliance with the velocity and
NHVcz requirements starting with the block that contains the fifteenth
minute of a flaring event; and the owner or operator is not required to
demonstrate compliance for the previous 15-minute block in which the
event started and contained only a fraction of flow. We solicit comment
on these proposed revisions.
f. Flares in Dedicated Service
    In lieu of requiring the composition of the vent gas and the NHVvg
to be continuously monitored, we are proposing an alternative
monitoring approach for HON and P&R I flares that are in dedicated
service that have consistent composition and flow. We believe that
these types of flares, which have limited flare vent gas streams, do
not need to have the same type of ongoing monitoring requirements as
those with more variable waste streams. Thus, we are proposing an
option that owners or operators can use to demonstrate compliance with
the operating requirements for HON and P&R I flares that are in
dedicated service to a specific emission source, such as a transfer
rack operation consistently loading the same material. We are proposing
that owners or operators will need to submit an application for the use
of this alternative compliance option. We are proposing that the
application include a description of the system, characterization of
the vent gases that could be routed to the flare based on a minimum of
seven grab samples (14 daily grab samples for continuously operated
flares), and specification of the net heating value that will be used
for all flaring events (based on the minimum net heating value of the
grab samples). In other words, for HON and P&R I flares that are in
dedicated service, we are proposing that the minimum NHVvg determined
from the grab samples could be used in the equation at 40 CFR
63.670(m)(1) for all flaring events to determine NHVcz. We are also
proposing to allow engineering estimates to characterize the amount of
gas flared and the amount of assist gas introduced into the system. For
example, we believe that the use of fan curves to estimate air assist
rates would be acceptable. We propose that flare owners or operators
would use the net heating value determined from the initial sampling
phase and measured or estimated flare vent gas and assist gas flow
rates, if applicable, to demonstrate compliance with the standards.
Refer to 40 CFR 63.108 and 40 CFR 63.670(j)(6) for these proposed
provisions. Finally, for owners and operators that must comply with the
continuous monitoring requirements, we are proposing additional
clarifications and requirements at 40 CFR 63.108 when using a gas
chromatograph or mass spectrometer for compositional analysis. We
solicit comment on the proposed revisions related to flares in
dedicated service.
g. Pressure-Assisted Multi-Point Flares
    The EPA is also proposing to add requirements into the HON (but not
P&R I) for pressure-assisted multi-point flares given that these types
of APCD are used to control waste gases from processes subject to the
HON during SSM. Pressure-assisted flares are conceptually similar, yet
technically different in both design and operation compared to more
traditional elevated flare tip designs (e.g., steam-assisted, air-
assisted, and non-assisted flare tips). Pressure-assisted flares
operate by taking advantage of the pressure upstream of

the flare tip to create a condition whereby air is drawn into contact
and mixed with high exit velocity flared gas, resulting in smokeless
flare operation and emissions reductions at least equivalent to those
of traditional flare types, if properly designed and operated.
Pressure-assisted flares can be used in a single flare burner type
layout or in staged arrays with many identical flare burners. These
staged arrays can be elevated or at ground level; however, we are only
aware of ground level staged array systems, that are commonly referred
to as multi-point ground flares (MPGFs), at six facilities used as
APCDs in the SOCMI source category that control emissions from HON
processes.\127\ MPGFs have multiple (e.g., hundreds) flare burners at
ground level. The flare burners in a MPGF are designed with a staging
system that opens and closes staging valves according to gas pressure
in the flare header such that the stages, and accompanying flare
burners for those stages, are activated to control emissions as the
flare vent gas flow and pressure increase in the flare header, or are
deactivated as the flare vent gas flow and pressure decrease in the
flare header. The flare burners in a MPGF are typically lit with a
pilot flame system where the first burners on a stage are lit by the
pilot flame and the flame propagates (i.e., cross-lights) down the
stage to the remaining burners on the stage (similar to how burners on
a gas grill would light). The MPGF system is surrounded by a panel type
fence to allow air in for combustion as well as to protect nearby
workers from the radiant heat of the flare system.
---------------------------------------------------------------------------

    \127\ One HON flare was reported as a pressure-assisted ground
flare in response to our CAA section 114 request. Based on this
information, in addition to information from alternative means of
emission limitation requests (see Docket ID No. EPA-HQ-OAR-2014-
0738), we estimate there are 6 pressure-assisted MPGF located in the
SOCMI source category that control emissions from processes subject
to the HON.
---------------------------------------------------------------------------

    MPGF are often used as secondary flares to control large emissions
events that result during periods of SSM. With the elimination of the
SSM exemption (see section III.E.1 of this preamble for additional
discussion), proposing requirements for this unique flare type for HON
flares is an important consideration given that some facilities
currently use them as APCD. Based on our review of recently approved
alternative means of emission limitation (AMEL) requests for MPGF and
the underlying data analyses that supported those decisions (see
section II.D of this preamble), MPGF can achieve reductions in VOC and
organic HAP at least equivalent to those from traditional elevated
flares; however, different operating requirements are needed for these
flare types to ensure a high level of control is achieved given that
the individual flare burners are designed to operate at high velocities
(i.e., up to sonic velocity). Important considerations for proper
design and operation of MPGF center around the following: (1) Flare
flame stability, (2) pilot flame presence and its interplay with proper
cross-lighting, (3) operation of the MPGF with no visible emissions,
and (4) monitoring of certain parameters of the MPGF and the vent gases
it controls for purposes of compliance assurance.
    In reviewing the initial MPGF AMEL requests by Dow Chemical and
ExxonMobil (80 FR 8023-8030, February 13, 2015), the Agency noted two
general conclusions from the test data supporting the AMEL requests
that were consistent with 1985 studies \128\ conducted by the EPA on
pressure-assisted flares. The first general conclusion was that flare
head design can influence the flame stability curve. The second general
conclusion was that stable flare flames and high (greater than 98-99
percent) combustion and destruction efficiencies are attained when
flares are operated within operating envelopes specific to each flare
burner and gas mixture tested. Operation beyond the edge of the
operating envelope can result in rapid flame de-stabilization and a
decrease in combustion and destruction efficiencies. In reviewing all
the available data in the MPGF AMEL docket (i.e., Docket ID No. EPA-HQ-
OAR-2014-0738), we found these two general observations were still
valid conclusions. The data clearly show that for some test runs flare
flameouts occurred, meaning the flares were not operated within the
proper envelope to produce a stable flame. In reviewing these data, we
observed that all flare flameouts occurred for the various burners/
waste gas mixtures tested below an NHVcz of 800 Btu/scf. Thus, we
selected a minimum NHVcz of 800 Btu/scf to ensure the MPGF at
facilities in the SOCMI source category that control emissions from HON
processes are operated within the proper envelope to produce a stable
flame and achieve high destruction efficiencies at least equivalent to
those as the underlying HON MACT standards. Above this level, no flare
flameouts are observed, and high combustion/destruction efficiencies at
least equivalent to those as the underlying HON MACT standards are
achieved. Thus, to that end, we are proposing to not allow use of the
``feed forward'' calculation approach (discussed in section III.D.1.e
of this preamble) to demonstrate compliance with the NHVcz limit of 800
Btu/scf.
---------------------------------------------------------------------------

    \128\ Pohl, J. and N. Soelberg. 1985. Evaluation of the
efficiency of industrial flares: Flare head design and gas
composition. EPA-600/2-85-106. Prepared for U.S. EPA Office of Air
Quality Planning and Standards.
---------------------------------------------------------------------------

    Another unique characteristic of MPGF is that they may use a cross-
lighting pilot flame system as a means of ignition to initially combust
the waste gases sent to the flare burners on a particular staged array.
Thus, we also reviewed the equipment-specific set-ups in the test data
that allowed for successful cross-lighting of MPGF. Based on review of
the data, it appears that one option would be for facilities to conduct
performance demonstrations to demonstrate successful cross-lighting on
a minimum of three burners (i.e., as outlined in the Framework for
Streamlining Approval of Future Pressure-Assisted MPGF AMEL Requests,
81 FR 23480, April 21, 2016). However, given the data before us in the
MPGF AMEL docket, and rather than requiring facilities to conduct a
performance demonstration, it appears that an equipment standard that
sets an upper limit on the distance between burners of 6 feet will
ensure a successful cross-lighting on a stage of burners in a MPGF.
    Furthermore, in reviewing the site-specific AMEL standards that
facilities are complying with for MPGF,\129\ we believe these same
site-specific standards, if applied to all MPGF in the specified
subset, would demonstrate at least equivalent emissions reductions to
the underlying HON MACT standards as well as demonstrate at least
equivalent reductions to the new operational and monitoring
requirements we are proposing for more traditional, elevated flare
tips. Therefore, we are proposing at 40 CFR 63.108(i) that owners or
operators of MPGF at facilities in the SOCMI source category that
control emissions from HON processes: (1) Maintain an NHVcz greater
than or equal to 800 Btu/scf over a short averaging period (i.e., 15-
minutes); (2) continuously monitor the NHVcz and flare vent gas flow
rate; (3) continuously monitor for the presence of a pilot flame, and
if cross-lighting is occurring on a particular stage of burners,
ensuring that each stage of burners that cross-lights must have at
least two pilots with at least one continuously lit and capable of
igniting all regulated material
---------------------------------------------------------------------------

    \129\ 80 FR 52426, August 31, 2015; 81 FR 23480, April 21, 2016;
and 82 FR 27822, June 19, 2017.

---------------------------------------------------------------------------

that is routed to that stage of burners; (4) operate the MPGF with no
visible emissions (except for 5 minutes during any 2 consecutive
hours); (5) maintain a distance of no greater than 6 feet between any
two burners on a stage of burners that use cross-lighting; \130\ and
(6) monitor to ensure the staging valves for each stage of the MPGF
operate properly so that the flare will control vent gases within the
range of the tested conditions based on the flare manufacturer's
recommendations.
---------------------------------------------------------------------------

    \130\ We are proposing that this burner-to-burner distance is
the distance when measured from the center of one burner to the next
burner.
---------------------------------------------------------------------------

    Finally, although we are unaware of any HON facilities that use
multi-point elevated flares in the specified flare subset, we recognize
that an owner or operator may elect to use this type of flare design in
the future. Given the design similarities of a multi-point elevated
flare when compared to a MPGF (i.e., each flare type uses pressure-
assisted burners with staged arrays), we determined that our analyses
of the test data (including our review of approved AMEL requests)
related to MPGF that control waste gases could also apply to multi-
point elevated flares in the specified subset that combust waste gases.
Therefore, we are proposing that owners and operators of multi-point
elevated flares meet the same requirements that we are proposing for
MPGF. In other words, the proposed requirements discussed in this
section of the preamble would apply to all pressure-assisted multi-
point flares (i.e., MPGF and multi-point elevated flares) at facilities
in the SOCMI source category that control emissions from HON processes.
We are soliciting comment on whether this approach is appropriate, and
whether test data are available for multi-point elevated flares that
control waste gases from HON facilities. Also, given that some owners
and operators of CMPUs are currently operating under an approved AMEL,
and these owners and operators are likely to have already installed
more sophisticated equipment (e.g., a gas chromatograph) than what is
required to comply with these proposed requirements for pressure-
assisted multi-point flares, we are proposing that pressure-assisted
multi-point flares subject to an approved AMEL may continue to comply
with the approved AMEL in lieu of these proposed requirements for
pressure-assisted multi-point flares. We also are soliciting comment on
whether we should extend allowance of this option to P&R I facilities,
as many sources are collocated with HON and may use this same type of
control device as a backup. As we are currently unaware of any P&R I
facilities using pressure-assisted multi-point flares, we solicit
comment whether test data are available for these flare types that
control waste gases from P&R I processes.
h. Impacts of the Proposed Flare Operating and Monitoring Requirements
    The EPA expects that the newly proposed requirements for flares
used as APCDs in the SOCMI source category discussed in this section
will affect all flares at HON and P&R I processes. Based on facility
responses to our CAA section 114 request, we estimate that there are
345 flares of traditional elevated flare tip designs (e.g., steam-
assisted, air-assisted, and non-assisted flare tips) operating at HON
CMPUs that receive flare vent gas flow on a regular basis (i.e., other
than during periods of SSM). We estimate that there are 31 flares of
traditional elevated flare tip designs operating at P&R I EPPUs that
receive flare vent gas flow on a regular basis. Also, based on facility
responses to our CAA section 114 request and information received from
AMEL requests (see section II.D of this preamble), we estimate there
are six pressure-assisted MPGF used to control waste gases from
processes subject to the HON during SSM. Costs were estimated for each
flare for a given facility, considering current monitoring systems
already installed on each individual flare. Given that the same type of
equipment is used for flares in the SOCMI source category and for the
petroleum refinery sector, costs for any additional monitoring systems
needed were estimated based on installed costs received from petroleum
refineries and, if installed costs were unavailable, costs were
estimated based on vendor-purchased equipment. The baseline emission
estimate and the emission reductions achieved by the proposed rule were
estimated based on current vent gas and steam flow data submitted by
industry representatives. The results of the impact estimates are
summarized in Table 28 of this preamble for Flares in the SOCMI Source
Category that control emissions from HON processes including P&R I & II
flares collocated with HON processes. The results of the impact
estimates are summarized in Table 29 of this preamble for Flares in the
SOCMI source category that control emissions from P&R I processes. We
note that the requirements for HON and P&R I flares that we are
proposing will ensure compliance with the MACT standards in the HON and
P&R I when flares are used as an APCD. Because we are not changing the
underlying MACT standards in the HON and P&R I, we did not include any
of the estimated excess emissions from flares in the summary of total
estimated emissions reductions for this action. However, we estimate
that the proposed operational and monitoring requirements have the
potential to reduce excess emissions from HON flares (including from
P&R I flares collocated with HON processes) by approximately 4,717 tpy
of HAP and 19,325 tpy of VOC; and from P&R I flares (not collocated
with HON processes) by approximately 141 tpy of HAP and 564 tpy of VOC.
The VOC compounds are non-methane, non-ethane total hydrocarbons.
According to the emissions inventory file we used to assess residual
risk (see section II.F.1 of this preamble), there are approximately 80
individual HAP compounds included in the emission inventory for flares,
but many of these are emitted in trace quantities. Almost half of the
HAP emissions from flares are attributable to hexane, benzene, and
methanol, followed by 1,3-butadiene and vinyl acetate. For more detail
on the impact estimates, see the document titled Control Option Impacts
for Flares Located in the SOCMI Source Category that Control Emissions
from Processes Subject to HON and for Flares that Control Emissions
from Processes Subject to Group I and Group II Polymers and Resins
NESHAPs, which is available in the docket for this rulemaking. As
previously mentioned in section III.C.3.b of this preamble, we are also
proposing these same flare operating and monitoring requirements for
NSPS subpart IIIa, NNNa, and RRRa under CAA section 111(b)(1)(B).

    Table 28--Nationwide Cost Impacts for Flares in the SOCMI Source
   Category That Control Emissions From HON Processes Including P&R I
                  Flares Collocated With HON Processes
------------------------------------------------------------------------
                                                               Total
                                           Total capital    annualized
           Control description              investment    costs (million
                                            (million $)        $/yr)
------------------------------------------------------------------------
Flare Operational and Monitoring                   323.1            67.8
 Requirements...........................
Work Practice Standards for Flares                  3.34            0.79
 Operating Above Their Smokeless
 Capacity...............................
                                         -------------------------------
    Total...............................           326.4            68.7
------------------------------------------------------------------------

    Table 29--Nationwide Cost Impacts for Flares in the SOCMI Source
          Category That Control Emissions From P&R I Processes
------------------------------------------------------------------------
                                                               Total
                                           Total capital    annualized
           Control description              investment         costs
                                            (million $)   (million $/yr)
------------------------------------------------------------------------
Flare Operational and Monitoring                    6.93            1.46
 Requirements...........................
Work Practice Standards for Flares                  0.08            0.02
 Operating Above Their Smokeless
 Capacity...............................
                                         -------------------------------
    Total...............................            7.01            1.48
------------------------------------------------------------------------

2. PRDs
    The HON defines several terms applicable to process vents at 40 CFR
63.101 and 40 CFR 63.107; similarly, P&R I defines several terms
applicable to process vents at 40 CFR 63.482. The current HON
definition of ``process vent'' excludes a ``relief valve discharge,''
(see 40 CFR 63.107(h)(1)) and the term ``process vent'' in P&R I at 40
CFR 63.482 excludes ``pressure releases.'' Instead, these MACT
standards in the HON and P&R I recognize HON relief valve discharges
and P&R I pressure releases to be the result of malfunctions. The
acronym ``PRD'' means pressure relief device and is common vernacular
to describe the variety of devices regulated as pressure relief valves
(to provide clarity, see the end of this section for our proposed
revision to the definition of ``pressure relief device'' for the HON
and P&R I, our proposed definition of ``relief valve'' for the HON and
P&R I, and our proposal to add a definition in P&R II for ``pressure
relief device''). PRDs are designed to remain closed during normal
operation. Typically, the Agency considers PRD releases as the result
of an overpressure in the system caused by operator error, a
malfunction such as a power failure or equipment failure, or other
unexpected cause that results in immediate venting of gas from process
equipment to avoid safety hazards or equipment damage. The discussion
that follows within this section of the preamble primarily focuses on
the HON and P&R I because any release of HAP to the atmosphere from a
P&R II PRD should already be accounted for when determining compliance
with the production-based emission rate MACT standard (e.g., pounds HAP
per million pounds BLR or WSR produced).
    The HON and P&R I currently regulate PRDs when they are seated
through equipment leak provisions that are applied only after the
pressure release event occurs (i.e., conduct monitoring with EPA Method
21 of appendix A-7 to 40 CFR part 60 after each pressure release using
a leak definition of 500 ppm); however, these provisions do not apply
to an emissions release from a PRD. In addition, the HON and P&R I
follow the EPA's pre-2008 practice of exempting SSM events from
otherwise applicable emission standards. Consequently, with PRD
releases treated as unplanned, nonroutine, and the result of
malfunctions, the HON and P&R I did not restrict PRD releases to the
atmosphere but instead treated them in the same manner as malfunctions
subject to the SSM exemption provision. In Sierra Club v. EPA, 551 F.3d
1019 (D.C. Cir. 2008), the Court determined that the SSM exemption
violates the CAA. We have previously explained the relationship between
this ruling and PRDs in other rulemakings revising section 112
standards (see, e.g., 85 FR 6067, February 4, 2020, and 85 FR 40386,
July 6, 2020). Section III.E.1 of this preamble contains additional
discussions on the removal of the SSM exemption provision for the SOCMI
and P&R I source categories. As a result, we evaluated the MACT
standards in the HON and P&R I for PRD HAP releases to the atmosphere
to ensure a standard continuously applies during these malfunction
events, consistent with the Sierra Club decision.
    CAA section 112(d)(1) specifies that the EPA may ``distinguish
among classes, types, and sizes of sources'' when establishing
standards. (In establishing standards under CAA section 112(d), the EPA
may ``distinguish among classes, types, and sizes of sources within a
category or sub-category.'' CAA section 112(d)(1). See Sierra Club v.
EPA, 479 F.3d 875, 885 (D.C. Cir. 2007)). We are proposing two
subcategories of PRDs for the MACT standard in the HON and P&R I to
distinguish between classes of PRDs: (1) PRDs designed to vent through
a closed-vent system to a control device or to a process, fuel gas
system, or drain system (referred to as PRDs that vent to a control
system); and (2) PRDs designed to vent to the atmosphere, if a release
were to occur. We are proposing to subcategorize PRDs by class because
of design differences between the numerous PRDs at HON and P&R I
facilities that vent to a control system and that vent to the
atmosphere. Currently, HON and P&R I facilities are required to
evaluate PRDs as part of their risk management and process safety
management programs. When implementing these programs, facilities
identify PRDs that they intend to control as compared to those they
elect not to control (and that have the potential to vent to the
atmosphere if a release were to occur). Facilities do not control
certain PRDs because of technical or site-specific safety
considerations, such as PRDs that release chemicals that could be
incompatible with vent streams in downstream controls.

    We evaluated each subcategory of PRDs separately to ensure that a
standard continuously applies. Essentially, PRDs that vent to a control
system are already complying with the process vent standards and are,
thus, presumably, already appropriately controlled. However, PRDs that
vent to atmosphere do not meet the current continuous process vent
standards. Therefore, we examined how to regulate PRDs that vent to
atmosphere under CAA section 112(d)(2) and (3). CAA section 112(h)(1)
states that the Administrator may prescribe a work practice standard or
other requirements, consistent with the provisions of CAA sections
112(d) or (f), in those cases where, in the judgment of the
Administrator, it is not feasible to enforce an emission standard. CAA
section 112(h)(2)(B) further defines the term ``not feasible'' in this
context to apply when ``the application of measurement technology to a
particular class of sources is not practicable due to technological and
economic limitations.'' As detailed here, we identified as the MACT
level of control work practice standards to regulate PRDs that vent to
atmosphere under CAA section 112(h), and are proposing such work
practice standards at proposed 40 CFR 63.165(e) (for HON) and proposed
40 CFR 63.502(a)(1) and (a)(2) (which references 40 CFR 63.165, for P&R
I) that are intended to reduce the number of PRD releases and will
incentivize owners or operators to eliminate the causes of PRD releases
to the atmosphere.
    No HON or P&R I facility is subject to numeric emission limits for
PRDs that vent to the atmosphere.\131\ Further, we do not believe it is
appropriate to subject PRDs that vent to the atmosphere to numeric
emission limits due to technological and economical limitations that
make it impracticable to measure emissions from such PRDs. CAA section
112(h)(1) states that the EPA may prescribe a work practice standard or
other requirement, consistent with the provisions of CAA sections
112(d) or (f), in those cases where, in the judgment of the
Administrator, it is not feasible to enforce an emission standard. CAA
section 112(h)(2)(B) further defines the term ``not feasible'' in this
context as meaning that ``the application of measurement technology to
a particular class of sources is not practicable due to technological
and economic limitations.'' We consider it appropriate to establish a
work practice standard for PRDs that vent to atmosphere as provided in
CAA section 112(h), because the application of a measurement
methodology for PRDs that vent to atmosphere is not practicable due to
technological and economic limitations. First, it is not practicable to
use a measurement methodology for PRD releases that vent to atmosphere.
PRDs are designed to remain closed during normal operations and release
emissions only during nonroutine and unplanned events, and the venting
time can be very short and may vary widely in composition and flow
rate. These unique event characteristics make it infeasible to collect
a grab sample of the gases when a PRD release occurs, and a single grab
sample would also likely not account for potential variation in vent
gas composition. Additionally, it would not be cost-effective to
construct an appropriate conveyance and install and operate continuous
monitoring systems for each individual PRD that vents to atmosphere in
order to attempt to quantitatively measure a release event that may
occur only a few times in a 3-year period. (See U.S. Sugar Corp. v.
EPA, 830 F.3d 579, 664-67 (2016).) Further, we have not identified any
available, technically feasible CEMS that can accurately determine a
mass release quantity of VOC or HAP given the flow, composition, and
composition variability of potential PRD releases that vent to the
atmosphere from CMPUs or EPPUs. Rather, we have identified only
monitoring systems capable of alerting an owner or operator when a PRD
release occurs. Consequently, we have concluded that it is appropriate
to establish a work practice standard for PRDs that vent to the
atmosphere as provided in CAA section 112(h).
---------------------------------------------------------------------------

    \131\ As previously mentioned, P&R II is different from the HON
and P&R I because P&R II defines a process vent as a ``a point of
emission from a unit operation. Typical process vents include
condenser vents, vacuum pumps, steam ejectors, and atmospheric vents
from reactors and other process vessels.'' As such, P&R II does not
exclude PRD releases from its production-based emission rate MACT
standard.
---------------------------------------------------------------------------

    We also reviewed information about HON and P&R I facilities to
determine how the best performers are minimizing emissions from PRDs
that vent to the atmosphere. We first reviewed the requirements in the
EPA's Chemical Accident Prevention Provisions (40 CFR part 68) and
Occupational Safety and Health Administration's (OSHA) Process Safety
Management rule (29 CFR 1910.119). These rules focus on planning for
and minimizing or preventing scenarios which would result in releases
of chemicals. For example, as stated in Appendix C to the OSHA rule,
``Process safety management is the proactive identification, evaluation
and mitigation or prevention of chemical releases that could occur as a
result of failures in process, procedures or equipment.'' The rules are
applicable to any equipment in the process, and relief valves are
identified in each rule as an applicable source to evaluate. The EPA
and OSHA rules have similar requirements, except that the applicability
determinations are unique to each rule. Owners or operators are subject
to the EPA's Chemical Accident Prevention Provisions at 40 CFR part 68
if a process has more than a threshold quantity of a regulated
substance. Regulated substances and their thresholds are listed at 40
CFR 68.130. Owners or operators are subject to OSHA's Process Safety
Management rule at 29 CFR 1910.119 if a process involves either a
chemical that is at or above specified threshold quantities (listed in
appendix A to 29 CFR 1910.119) or a Category 1 flammable gas (as
defined in 29 CFR 1910.1200(c)) or flammable liquid with a flashpoint
below 100 degrees Fahrenheit. HON and P&R I facilities may be subject
to the Chemical Accident Prevention Provisions rule, as identified in
their title V permit (40 CFR 68.215 requires permits to list part 68 as
an applicable requirement, if subject). As a result, we further
reviewed this rule for consideration in developing the work practice
standard.
    The EPA's Chemical Accident Prevention Provisions require a
prevention program. Facilities subject to the HON or P&R I would fall
under prevention program 3. Prevention program 3 includes the
following: Documentation of process safety information, conducting a
hazard analysis, documentation of operating procedures, employee
training, on-going maintenance, and incident investigations. The
process safety information documented must include information
pertaining to the hazards of the regulated substances in the process,
the technology of the process, and the process equipment (including
relief valves). When conducting the hazard analysis, facilities must
identify, evaluate, and control the hazards in the process; controls
may consider the application of detection methodologies (e.g., process
monitoring and control instrumentation) to provide early warning of
releases. The operating procedures must address multiple operating
scenarios (e.g., normal operations, startup, emergency shutdown) and
provide instructions for safely conducting process activities.
Conducting the hazard analysis and

documenting operating procedures are similar to prevention measures,
discussed below, though we note a specific number of measures or
controls is not specified for the program 3 prevention program.
Incident investigations must document the factors that contributed to
an incident and any resolutions and corrective actions (incident
investigations are consistent with root cause analysis and corrective
action, discussed below). Facilities are also required to document this
information in a Risk Management Plan that must be updated at least
every 5 years.
    Next, we considered that some companies operating HON and P&R I
facilities also own and operate petroleum refineries and may have
established company-wide best practices as a result of specific state
and federal requirements. For example, petroleum refineries and
chemical plants located in certain counties in California are subject
to and complying with specific requirements for PRDs such as the Bay
Area Air Quality Management District (BAAQMD) Rule 8-28-304 and South
Coast Air Quality Management District (SCAQMD) Rule 1173. The BAAQMD
rule requires implementation of three prevention measures, and both
rules require root cause analysis and corrective action for certain
PRDs. These rules also formed the basis of the work practice standards
promulgated at 40 CFR 63.648(j) for PRD releases at petroleum
refineries in the Petroleum Refinery Sector RTR performed by the EPA
(80 FR 75178, December 1, 2015).
    Considering our review of the EPA's Chemical Accident Prevention
Provisions and company-wide best practices that HON and P&R I
facilities may have implemented, we expect that the best performing HON
and P&R I facilities have implemented a program for PRDs that vent to
the atmosphere that consists of using at least three prevention
measures and performing root cause analysis and corrective action in
the event that a PRD does release emissions directly to the atmosphere.
In fact, we confirmed this to be true for HON facilities based on
facility responses to our CAA section 114 request. We used this
information as the basis of the work practice standards that we are
proposing at 40 CFR 63.165(e) (for HON) and 40 CFR 63.502(a)(1) and (2)
(which references 40 CFR 63.165, for P&R I). Examples of prevention
measures include the following: Flow indicators, level indicators,
temperature indicators, pressure indicators, routine inspection and
maintenance programs, operator training, inherently safer designs,
safety instrumentation systems, deluge systems, and staged relief
systems where the initial PRD discharges to a control system.
    We are also proposing a limit on the number of PRD releases that
can take place within a 3-yr period. Any PRD releases in excess of the
limit would result in a deviation from the work practice standard for
PRDs that vent to the atmosphere. We believe setting criteria to
determine a deviation is necessary for the work practice to be
effective. We considered limits on the number of PRD releases in both
3- and 5-year periods. Based on a Monte Carlo analysis of random rare
events (as conducted for the Petroleum Refinery Sector rule \132\), we
note that it is quite likely to have two or three events in a 5-year
period when a long time horizon (e.g., 20 years) is considered.
Therefore, we are proposing to limit the number of PRD releases from a
single PRD to either one, two, or three (depending on the root cause)
in a 3-year period as the basis of a deviation from the work practice
standard. We are proposing that it is a deviation from the work
practice standard if a single PRD that vents to atmosphere has two
releases within a 3-year period due to the same root cause. We believe
that this provision will help ensure that root cause/corrective actions
are conducted effectively. Otherwise, we are proposing that it is a
deviation from the work practice standard if a single PRD that vents to
the atmosphere has three releases within a 3-year period for any
reason. In addition, we are proposing that any PRD release for which
the root cause was determined to be operator error or poor maintenance
is a deviation from the work practice standard. Refer to proposed 40
CFR 63.165(e)(3)(v) (for HON) and proposed 40 CFR 63.502(a)(1) and (2)
(which references 40 CFR 63.165, for P&R I) for these proposed
provisions. Based on our cost assumptions, the nationwide capital cost
for complying with the PRD work practice requirements for the HON is
$13.7 million and the annualized capital costs is $7.1 million; and for
P&R I is $0.41 million and the annualized capital costs is $0.12
million.
---------------------------------------------------------------------------

    \132\ See 80 FR 75217, December 1, 2015.
---------------------------------------------------------------------------

    In addition, we believe that it is appropriate to exclude certain
types of PRDs that have very low/no potential to emit based on their
type of service, size, and/or pressure from the proposed work practice
standard for PRD releases that vent to atmosphere, provided they are
subject to other continuously applicable emission standards. Both the
Chemical Accident Prevention Provisions and the California petroleum
refinery PRD rules also exempt or impose simpler requirements for
certain PRDs. We are proposing at 40 CFR 63.165(e)(5) (for HON) and 40
CFR 63.502(a)(1) and (2) (which references 40 CFR 63.165, for P&R I)
that the following types of PRDs would not be subject to the work
practice standard for PRDs that vent to the atmosphere, but instead
would be covered by other continuously applicable emission
standards:\133\ (1) PRDs in heavy liquid service; (2) PRDs that are
designed solely to release due to liquid thermal expansion; (3) PRDs on
mobile equipment, and (4) pilot-operated and balanced bellows PRDs if
the primary release valve associated with the PRD is vented through a
closed vent system to a control device or back into the process, to the
fuel gas system, or to a drain system. Each of the types of PRDs that
we are proposing would not be subject to the work practice standard are
discussed in greater detail here. With regard to PRDs in heavy liquid
service, any HAP release to the atmosphere from a PRD in heavy liquid
service would have a visual indication of a leak and any repairs to the
valve would have to be further inspected and, if necessary, repaired
under the existing equipment leak provisions. Therefore, we are
proposing that PRDs in heavy liquid service need not be additionally
subject to the work practice standard. In addition, we are proposing
that PRDs designed solely to release due to liquid thermal expansion
would not be subject to the work practice standard. We expect that
releases from these thermal relief valves would be insignificant.
Finally, we are also proposing that pilot-operated PRDs (where
emissions can be released to the atmosphere through a pilot discharge
vent) and balanced bellow PRDs (where emissions can be released to the
atmosphere through a bonnet vent) would not be subject to the work
practice standard, if the primary release valve associated with the
pilot-operated or balanced bellows PRD is vented through a closed vent
system to a control device or back into the process, to the fuel gas
system, or to a drain system. Pilot-operated and balanced bellows PRDs
are primarily used for pressure relief when the back pressure of the
discharge vent may be high or variable. Conventional PRDs act on a
differential pressure between the process gas and the discharge vent.
If the discharge vent pressure increases, the vessel pressure at which
the PRD will open increases, potentially leading

to vessel over-pressurization that could cause vessel failure. Balanced
bellows PRDs use a bellow to shield the pressure relief stem and top
portion of the valve seat from the discharge vent pressure. A balanced
bellows PRD will not discharge gas to the atmosphere during a release
event, except for leaks through the bonnet vent due to bellows failure
or fatigue. Pilot-operated PRDs use a small pilot safety valve that
discharges to the atmosphere to effect actuation of the primary valve
or piston, which then discharges to a control system. Balanced bellows
or pilot operated PRDs are considered a reasonable and necessary means
to safely control the primary PRD release.
---------------------------------------------------------------------------

    \133\ Pursuant to 40 CFR 63.165(a), each pressure relief device
in organic HAP gas or vapor service must continue to be operated
with an instrument reading of less than 500 ppm above background.
---------------------------------------------------------------------------

    For all PRDs in organic HAP service, owners or operators would
still be required to comply with the LDAR provisions, as they are
currently applicable. Therefore, all PRDs that vent to the atmosphere
would still perform LDAR to ensure the PRD properly reseats if a
release does occur, and PRDs that vent to control systems would still
be exempt from LDAR requirements given that if a release were to occur
from this specific class of PRDs, it would vent to a closed vent system
and control device.
    Finally, to ensure compliance with the proposed work practice
standard for PRDs that vent to the atmosphere, we are also proposing at
40 CFR 63.165(e)(3) (for HON) and 40 CFR 63.502(a)(1) and (2) (which
references 40 CFR 63.165, for P&R I) that sources monitor these PRDs
using a system that is capable of identifying and recording the time
and duration of each pressure release and of notifying operators that a
pressure release has occurred. Pressure release events from PRDs that
vent to the atmosphere have the potential to emit large quantities of
HAP. When a pressure release occurs, it is important to identify and
mitigate it as quickly as possible. For purposes of estimating the
costs of this requirement, we assumed that operators would install
electronic monitors on PRDs that vent to atmosphere to identify and
record the time and duration of each pressure release. However, we are
proposing to allow owners and operators to use a range of methods to
satisfy these requirements, including the use of a parameter monitoring
system (that may already be in place) on the process operating pressure
that is sufficient to indicate that a pressure release has occurred as
well as record the time and duration of that pressure release. Based on
our cost assumptions, the nationwide capital cost of installing these
electronic monitors for the HON is $3.1 million and the annualized
capital costs are $0.41 million; and for P&R I is $0.09 million and the
annualized capital costs are $0.01 million.
    We also considered requiring all PRDs to be vented to a control
device as a beyond-the-floor requirement. While this would provide
additional emission reductions beyond those we are establishing as the
MACT floor, these reductions come at significant costs. For example,
the EPA estimated that the capital cost for controlling MON PRDs ranged
from $2,540 million to $5,070 million, and the annualized cost ranged
from $330 million to $660 million; and the incremental cost
effectiveness for requiring control of all MON PRDs that vent to the
atmosphere compared to the requirements described above exceeded $80
million per ton of HAP reduced (see 84 FR 69182, December 17, 2019).
Consequently, we conclude that this is not a cost-effective option.
    The EPA is also proposing a requirement that any future installed
pilot-operated PRDs be the non-flowing type. As previously noted, under
CAA section 112(d)(1), the EPA may ``distinguish among classes, types,
and sizes of sources'' when establishing standards. There are two
designs of pilot-operated PRDs: flowing and non-flowing. When a flowing
pilot-operated PRD is actuated, the pilot discharge vent continuously
releases emissions; however, when a non-flowing pilot-operated PRD is
actuated, the pilot discharge vent does not vent continuously. Although
we expect pilot discharge vent emissions to be minimal for both
designs, limiting the future use of flowing pilot-operated PRDs is
warranted to prevent continuous release of emissions. Therefore, we are
proposing at 40 CFR 63.165(e)(8) (for HON) and 40 CFR 63.502(a)(1) and
(2) (which references 40 CFR 63.165, for P&R I) to require future
installation and operation of non-flowing pilot-operated PRDs at all
affected sources.
    We are also proposing at 40 CFR 63.101 (for HON) and 40 CFR 63.482
(for P&R I) to clarify the definitions of ``pressure release,''
``pressure relief device,'' and ``relief valve.'' We are proposing to
define ``pressure release'' as the emission of materials resulting from
the system pressure being greater than the set pressure of the pressure
relief device. This release can be one release or a series of releases
over a short time period. We are proposing to define ``pressure relief
device'' as a valve, rupture disk, or similar device used only to
release an unplanned, nonroutine discharge of gas from process
equipment in order to avoid safety hazards or equipment damage. A
pressure relief device discharge can result from an operator error, a
malfunction such as a power failure or equipment failure, or other
unexpected cause. Such devices include conventional, spring-actuated
relief valves, balanced bellows relief valves, pilot-operated relief
valves, rupture disks, and breaking, buckling, or shearing pin devices.
We are proposing to define ``relief valve'' as a type of pressure
relief device that is designed to re-close after the pressure relief.
For clarity, we are also proposing for P&R II the same definition of
``pressure relief device'' that we are proposing for the HON and P&R I
because P&R II currently does not define this term. Although we are not
proposing for P&R II the same work practice standard for PRDs that vent
to the atmosphere that we are proposing for the HON and P&R I (because
as explained earlier in this section of the preamble any release of HAP
to the atmosphere from a P&R II pressure relief device should already
be accounted for when determining compliance with the production-based
emission rate MACT standard), we are proposing at 40 CFR 63.527(f) and
40 CFR 63.528(a)(6), that owners and operators keep records and report
the start and end time and date of each pressure release to the
atmosphere, an estimate of the mass quantity in pounds of each organic
HAP released, as well as any data, assumptions, and calculations used
to estimate of the mass quantity of each organic HAP released during
the event. These proposed records and reports for P&R II will assist
stakeholders in determining compliance with the production-based
emission rate MACT standard.
    We solicit comment on all of the proposed revisions for PRDs. See
the document titled Review of Regulatory Alternatives for Certain Vent
Streams in the SOCMI Source Category that are Associated with Processes
Subject to HON and Processes Subject to Group I and Group II Polymers
and Resins NESHAPs, in the docket for this rulemaking for details on
the assumptions and methodologies used in this analysis.
3. Closed Vent System Containing Bypass Lines
    For a closed-vent system containing bypass lines that can divert
the stream away from the APCD to the atmosphere, the HON and P&R I
require the owner or operator to either: (1) Install, maintain, and
operate a continuous parametric monitoring system for flow on the
bypass line that is capable of detecting whether a vent stream flow is
present at least once every 15 minutes or (2) secure the bypass line
valve in the

non-diverting position with a car-seal or a lock-and-key type
configuration. Under option (2), the owner or operator is also required
to inspect the seal or closure mechanism at least once per month to
verify the valve is maintained in the non-diverting position (e.g., see
40 CFR 63.114(d)(2) for more details). To ensure standards apply to HON
and P&R I emission sources at all times, we are proposing at 40 CFR
63.114(d)(3), 40 CFR 63.127(d)(3), 40 CFR 63.148(f)(4), and 40 CFR
63.172(j)(4) (for HON), and 40 CFR 63.485(x), 40 CFR 63.489(d)(3), and
40 CFR 63.502(a)(2) (for P&R I) that an owner or operator may not
bypass the APCD at any time, that a bypass is a violation (see proposed
40 CFR 63.118(a)(5) and (f)(7), 40 CFR 63.130(a)(2)(iv), (b)(3), and
(d)(7), 40 CFR 63.148(i)(3)(iii) and (j)(4), Tables 3, 7, and 20 to 40
CFR 63, subpart G, 40 CFR 63.181(g)(3)(iii), and 40 CFR 63.182(d)(xix)
(for HON), and 40 CFR 63.485(x), 40 CFR 63.489(d)(3), and 40 CFR
63.502(a)(2) (for P&R I)), and owners and operators must estimate and
report the quantity of organic HAP released. We are proposing this
revision because bypassing an APCD could result in a release of
regulated organic HAP to the atmosphere and to be consistent with
Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), where the Court
determined that standards under CAA section 112(d) must provide for
compliance at all times. These requirements are consistent with CAA
section 112(d) controls and reflect the MACT floor. We did not identify
any additional options beyond this (i.e., beyond-the-floor options) for
minimizing emissions from closed-vent systems that are used to comply
with the emission standards. We are also proposing that the use of a
cap, blind flange, plug, or second valve on an OEL (following the
requirements specified in 40 CFR 60.482-6(a)(2), (b), and (c) or
following requirements codified in another regulation that are the same
as 40 CFR 60.482-6(a)(2), (b), and (c)) is sufficient to prevent a
bypass. We solicit comment on these proposed revisions.
4. Maintenance Activities
    The EPA is proposing that emission limits apply at all times
consistent with Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008). We
recognize that this proposed change for vent streams that are
periodically discharged will affect certain maintenance activities such
as those that require equipment openings, and we consider maintenance
activities a separate class of startup and shutdown emissions because
there must be a point in time when the equipment can be opened, and any
remaining emissions are vented to the atmosphere. We also acknowledge
that it would require a significant effort to identify and characterize
each of these potential release points (e.g., for permitting purposes).
CAA section 112(h)(1) states that the Administrator may prescribe a
work practice standard or other requirements, consistent with the
provisions of CAA sections 112(d) or (f), in those cases where, in the
judgment of the Administrator, it is not feasible to enforce an
emission standard. We are proposing work practices instead of numeric
emission limits for maintenance activities because it is ``not feasible
to prescribe or enforce an emission standard'' for these emissions.
Maintenance activities are not ``emitted through a conveyance designed
and constructed to emit or capture such pollutant'' (see CAA section
112(h)(2)(A)) and it is not possible to characterize each of these
potential release points. The discussion that follows within this
section of the preamble primarily focuses on the HON and P&R I because
any release to the atmosphere from P&R II maintenance activities should
already be accounted for when determining compliance with the
production-based emission rate MACT standard (e.g., pounds HAP per
million pounds BLR or WSR produced).
a. Equipment Openings (Excluding Storage Vessel Degassing)
    We reviewed state permit conditions and determined the best
performers' permits specify that they meet certain conditions before
they open equipment to the atmosphere. The conditions include
thresholds regarding the LEL and the mass of gas that may be emitted.
These requirements are consistent with CAA section 112(d) controls and
reflect the level of performance analogous to a MACT floor. Therefore,
we are proposing a work practice standard at 40 CFR 63.113(k)(1)(i)
(for HON), and at 40 CFR 63.485(x) and 40 CFR 63.487(i)(1)(i) (for P&R
I), that prior to opening process equipment to the atmosphere during
maintenance events, the equipment first be drained and purged to a
closed system so that the hydrocarbon content is less than or equal to
10 percent of the LEL. For those situations where 10-percent LEL cannot
be demonstrated, we are proposing at 40 CFR 63.113(k)(1)(ii) (for HON),
and at 40 CFR 63.485(x) and 40 CFR 63.487(i)(1)(ii) (for P&R I), that
the equipment may be opened and vented to the atmosphere if the
pressure is less than or equal to 5 psig, provided there is no active
purging of the equipment to the atmosphere until the LEL criterion is
met. We are proposing this 5 psig threshold to acknowledge that a
certain minimum pressure must exist for the flare header system (or
other similar control system) to operate properly. We are also
proposing at 40 CFR 63.113(k)(1)(iii) (for HON), and at 40 CFR
63.485(x) and 40 CFR 63.487(i)(1)(iii) (for P&R I), that equipment may
be opened when there is less than 50 pounds of VOC that may be emitted
to the atmosphere.
    We also acknowledge that installing a blind flange to prepare
equipment for maintenance may be necessary and by doing so, the owner
or operator may not be able to meet the proposed maintenance vent
conditions mentioned above (e.g., a valve used to isolate the equipment
will not seat fully, so organic material may continually leak into the
isolated equipment). To limit the emissions during the blind flange
installation, we are proposing at 40 CFR 63.113(k)(1)(iv) (for HON),
and at 40 CFR 63.485(x) and 40 CFR 63.487(i)(1)(iv) (for P&R I),
depressurizing the equipment to 2 psig or less prior to equipment
opening and maintaining pressure of the equipment where purge gas
enters the equipment at or below 2 psig during the blind flange
installation. The low allowable pressure limit will reduce the amount
of process gas that will be released during the initial equipment
opening, and the ongoing 2 psig pressure requirement will limit the
purge gas rate. Together, these proposed provisions will limit the
emissions during blind flange installation and will result in
comparable emissions allowed under the proposed maintenance vent
conditions mentioned above. We expect these situations to be rare and
that the owner or operator would remedy the situation as soon as
practical (e.g., replace the isolation valve or valve seat during the
next turnaround in the example provided above). Therefore, we are only
proposing that this alternative maintenance vent limit be used under
those situations where the proposed primary limits (i.e., hydrocarbon
content is less than or equal to 10 percent of the LEL, pressure is
less than or equal to 5 psig, or VOC is less than 50 pounds) are not
achievable and blinding of the equipment is necessary. We did not
identify any additional options beyond those identified above (i.e.,
beyond-the-floor options) for controlling emissions from equipment
openings.
    We expect that all HON and P&R I facilities already have standard
procedures in place when performing equipment openings (at the very
least for safety reasons). As such, the only costs incurred are for
recordkeeping

after each non-conforming event. We are proposing that owners or
operators document each circumstance under which the alternative
maintenance vent limit is used, providing an explanation as to why
other criteria could not be met prior to equipment blinding and an
estimate of the emissions that occurred during the equipment blinding
process. For the HON, we calculated the annual costs to be $94,250 per
year. For P&R I, we calculated the annual costs to be $8,650 per year.
We solicit comment on the proposed revisions related to maintenance
activities. For additional details and discussion, see the document
titled Review of Regulatory Alternatives for Certain Vent Streams in
the SOCMI Source Category that are Associated with Processes Subject to
HON and Processes Subject to Group I and Group II Polymers and Resins
NESHAPs, which is available in the docket for this rulemaking. As
previously mentioned in section III.C.3.b of this preamble, we are also
proposing these same maintenance vent standards for NSPS subpart IIIa,
NNNa, and RRRa under CAA section 111(b)(1)(B).
b. Storage Vessel Degassing
    With the proposed removal of SSM requirements, a standard specific
to storage vessel degassing does not exist when storage vessels are
using control devices to comply with the requirements in 40 CFR
63.119(a)(2) (for HON) and 40 CFR 63.484(a) (for P&R I, which
references 40 CFR 63.119). We acknowledge that storage vessel degassing
is similar to maintenance vents (e.g., equipment openings) and that
there must be a point in time when the storage vessel can be opened and
any emissions vented to the atmosphere. We reviewed available data to
determine how the best performers are controlling storage vessel
degassing emissions.
    We are aware of three regulations regarding storage vessel
degassing, two in the state of Texas and the third for the SCAQMD in
California. Texas has degassing provisions in the TAC \134\ and through
permit conditions,\135\ while Rule 1149 contains the SCAQMD degassing
provisions.\136\ The TAC requirements are the least stringent and
require control of degassing emissions until the vapor space
concentration is less than 35,000 ppmv as methane or 50 percent of the
LEL. The Texas permit conditions require control of degassing emissions
until the vapor space concentration is less than 10 percent of the LEL
or until the VOC concentration is less than 10,000 ppmv, and SCAQMD
Rule 1149 requires control of degassing emissions until the vapor space
concentration is less than 5,000 ppmv as methane. The Texas permit
conditions requiring compliance with 10 percent of the LEL and SCAQMD
Rule 1149 control requirements are considered equivalent because 5,000
ppmv as methane equals 10 percent of the LEL for methane.
---------------------------------------------------------------------------

    \134\ See 30 TAC Chapter 115, Subchapter F, Division 3,
available at https://texreg.sos.state.tx.us/public/readtac%24ext.ViewTAC?tac_view=5&ti=30&pt=1&ch=115&sch=F÷=3&rl=Y.
    \135\ See https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/mss/chem-mssdraftconditions.pdf.
    \136\ See http://www.aqmd.gov/docs/default-source/rule-book/reg-xi/rule-1149.pdf.
---------------------------------------------------------------------------

    HON and P&R I facilities located in Texas are subject to the permit
conditions, but no HON or P&R I facility is subject to the SCAQMD rule.
Of the 207 currently operating HON facilities, 78 are in Texas (four of
which are collocated with P&R I processes). Of the 19 currently
operating P&R I facilities, 6 are in Texas (including the four
collocated with HON processes). Therefore, the Texas permit conditions
relying on storage vessel degassing until 10 percent of the LEL is
achieved reflect what the best performers have implemented for storage
vessel degassing, and we considered this information as the MACT floor
for both new and existing HON and P&R I sources.
    We reviewed Texas permit condition 6 (applicable to floating roof
storage vessels) and permit condition 7 (applicable to fixed roof
storage vessels) for key information that could be implemented to form
the basis of a standard for storage vessel degassing. The Texas permit
conditions require control of degassing emissions for floating roof and
fixed roof storage vessels until the vapor space concentration is less
than 10 percent of the LEL. The permit conditions also specify that
facilities can also degas a storage vessel until they meet a VOC
concentration of 10,000 ppmv, but we do not consider 10,000 ppmv to be
equivalent to or as stringent as the compliance option to meet 10
percent of the LEL and are not including this as a compliance option.
We also do not expect the best performers would be using this
concentration for compliance because the Texas permit conditions allow
facilities to calibrate their LEL monitor using methane. Storage
vessels may be vented to the atmosphere once the storage vessel
degassing concentration threshold is met (i.e., less than 10 percent of
the LEL) and all standing liquid has been removed from the vessel to
the extent practicable. We are proposing that these requirements are
considered MACT floors for both new and existing HON and P&R I sources;
therefore, we are proposing these requirements at 40 CFR 63.119(a)(6)
(for HON) and 40 CFR 63.484(a) and (t) (which references 40 CFR 63.119,
for P&R I). Additionally, in petitions for reconsideration that the EPA
recently received on the MON, EMACT standards, the Petroleum Refinery
Sector rule, and OLD NESHAP, petitioners asserted that it is necessary
to make connections to a temporary control device to control the
floating roof storage vessel degassing emissions, which may require
opening the storage vessel to make these connections. While we do not
believe the current language precludes a facility from taking this
step, we are revising the standard to include related language for
clarity. Therefore, we are proposing that a floating roof storage
vessel may be opened prior to degassing to set up equipment (i.e., make
connections to a temporary control device), but this must be done in a
limited manner and must not actively purge the storage vessel while
connections are made.
    We calculated the impacts due to controlling storage vessel
degassing emissions by evaluating the population of storage vessels
that are subject to control under 40 CFR 63.119(a)(2) (for HON) and 40
CFR 63.484(a) (for P&R I, which references 40 CFR 63.119), and not
located in Texas. Storage vessels regulated by the HON or P&R I in
Texas would already be subject to the degassing requirements, and there
would not be additional costs or emissions reductions for these
facilities. We estimated there are an average of four Group 1 HON
storage vessels per CMPU and two Group 1 P&R I storage vessels per
EPPU. We applied these counts to the number of HON and P&R I processes
that are not located in Texas, resulting in 1,580 HON storage vessels
and 26 P&R I storage vessels newly applicable to vessel degassing
requirements. Based on a review of facility responses to our CAA
section 114 request, most storage vessels are degassed an average of
once every 13 years. Using this average and the population of storage
vessels that are not in Texas, we estimated 122 HON storage vessel
degassing events and two P&R I storage vessel degassing events would be
newly subject to control each year. Controlling HON storage vessel
degassing would reduce HAP emissions by 106 tpy, with a total annual
cost of approximately $751,500. Controlling P&R I storage vessel
degassing would reduce HAP emissions by 1.70 tpy, with

a total annual cost of approximately $12,300. See the document titled
Degassing Cost and Emissions Impacts for Storage Vessels Located in the
SOCMI Source Category that are Associated with Processes Subject to HON
and for Storage Vessels Subject to Either the Group I Polymers and
Resins NESHAP or Group II Polymers and Resins NESHAP, which is
available in the docket for this rulemaking, for details on the
assumptions and methodologies used in this analysis. We also considered
options beyond-the-floor, but we did not identify and are not aware of
storage vessel degassing control provisions more stringent than those
discussed above and being proposed in this rule; therefore, no beyond-
the-floor option was evaluated.
c. Planned Routine Maintenance for Storage Vessels
    Although the HON and P&R I currently allow owners and operators to
disconnect the fixed roof vessel vent from the closed vent system and
control device, fuel gas system, or process equipment for up to 240
hours per year during planned, routine maintenance (see 40 CFR
63.119(e)(3) through (5) (for HON) and 40 CFR 63.484(a) (for P&R I)),
we are proposing at 40 CFR 63.119(e)(7) that owners and operators would
not be permitted to fill the storage vessel during these periods (such
that the vessel would emit HAP to the atmosphere for a limited amount
of time due to breathing losses only). The removal of the 240-hr
exemption provisions except for vessel breathing losses is based upon
our position that removal is needed to satisfy Sierra Club v. EPA, 551
F.3d 1019 (D.C. Cir. 2008). These requirements are consistent with CAA
section 112(d) controls and reflect the MACT floor, as all working loss
emissions from storage vessels would be controlled during these
periods, ensuring a CAA section 112 standard is in place at this time.
We note that in 2018, the EPA finalized these same work practice
standards for the Amino/Phenolic Resins NESHAP (83 FR 51842, October
15, 2018). To evaluate the impacts of this proposed change to the HON
and P&R I, we assumed owners and operators would install a secondary
control device system (to control emissions from vessels during periods
of planned routine maintenance of the primary control device) and that
activated carbon canisters would be chosen as the method of control.
Based on vendor quotes, we determined that the total capital cost of a
55-gallon activated carbon drum with two connections, including piping
and duct work, is approximately $1,040. Following the guidelines of the
EPA's Seventh Edition OAQPS Control Cost Manual,\137\ we estimate that
the annual cost per CMPU or EPPU is $180. We also used information
about fixed roof storage vessels (including stored materials) that
industry provided to EPA in response to our CAA section 114 request
(see section II.C of this preamble). We estimate that there could be up
to 4 fixed roof storage vessels per CMPU requiring emissions control
under the HON. We multiplied this estimate (4) by the total HON
processes nationwide (634) and approximated that there are 2,536 fixed
roof storage vessels requiring emissions control under the HON
nationwide. For P&R I, we assumed that each P&R I facility has two
fixed roof storage vessels per EPPU that are subject to control.\138\
We also assumed that each facility has one P&R process. Using these
assumptions, we approximated that there are 38 fixed roof storage
vessels requiring emissions control under P&R I nationwide. We then
estimated that the highest amount of HAP emissions that would be
expected to occur from a HON or P&R I fixed roof storage vessel during
the 240 hours of planned routine maintenance would be 19.3 pounds, if
the emissions are not controlled. These emissions were based on the
largest vessel capacity and highest vapor pressure material stored in a
vessel that was reported in response to our CAA section 114 request,
and estimated using the emission estimation procedures from Chapter 7
of EPA's Compilation Of Air Pollutant Emission Factors,\139\ assuming
that only breathing losses would occur during this period. We assumed
that activated carbon canisters would achieve a 95 percent reduction in
HAP emissions, which would reduce emissions per vessel by 18.3 lbs HAP.
Based on our cost and emissions assumptions, the nationwide capital
cost for removal of the 240-hr exemption provisions (except for vessel
breathing losses) for the HON is $2.64 million and the annualized
capital costs is $0.46 million; and for P&R I is $0.04 million and the
annualized capital costs is about $0.01 million. See the document
titled Cost and Emissions Impacts for 240 Hour Planned Routine
Maintenance Work Practice Standard on Storage Vessels Located in the
SOCMI Source Category that are Associated with Processes Subject to HON
and for Storage Vessels Subject to the Group I Polymers and Resins
NESHAP, which is available in the docket for this rulemaking, for
details on the assumptions and methodologies used in this analysis.
---------------------------------------------------------------------------

    \137\ Air Pollution Control Cost Manual--Section 3: VOC
Controls; Section 3.1: VOC Recapture Controls, Carbon Adsorbers
Calculation Spreadsheet. Retrieved from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution. October 2018.
    \138\ This assumption is based on the median between four and
zero because our HON average is four, and the one facility that
received the CAA section 114 request and is subject to both the HON
and P&R I, reported zero Group 1 storage vessels subject to P&R I.
    \139\ Compilation of Air Pollutant Emission Factors. Volume 1:
Stationary Point and Area Sources. AP-42, Fifth Edition. Chapter 7:
Liquid Storage Tanks. Office of Air Quality Planning and Standards,
Research Triangle Park, NC.
---------------------------------------------------------------------------

    As a beyond-the-floor control option, we considered requiring
owners and operators to also control breathing losses from storage
vessels during periods of planned routine maintenance of the emission
control system. However, this option is expected to be not cost
effective. For example, the EPA estimated a cost of $62,400 per ton of
HAP emissions reduced in their analysis conducted for this same option
in the Amino/Phenolic Resins NESHAP (82 FR 40103, August 24, 2017).
5. Dioxins and Furans Emission Limits
    The HON, P&R I, and P&R II do not currently regulate emissions of
polychlorinated dibenzo-p-dioxins (dioxins) and polychlorinated
dibenzofurans (furans). Dioxins and furans can be formed when
chlorinated compounds are present and combusted in, for example, a
thermal oxidizer. HON facilities that release dioxins and furans
include those that manufacture chlorinated SOCMI chemicals (e.g.,
chloroform, chloroprene, ethylene dichloride, methyl chloride,
trichloroethylene, vinyl chloride). While the HON has 207 facilities
and 634 CMPUs, we estimated that at least 18 HON facilities and 34
CMPUs manufacture these chlorinated compounds and would have emissions
of dioxins and furans. As neoprene production facilities and
epichlorohydrin elastomer facilities in P&R I use, produce, or emit
chlorinated chemicals and all P&R II facilities use epichlorohydrin as
a feedstock, they can also produce and emit dioxins and furans through
combustion controls. Since dioxins and furans are currently an
unregulated pollutant in these NESHAP, we are proposing dioxins and
furans MACT standards under CAA section 112(d)(2) and (3) for the HON,
P&R I, and P&R II.
    The MACT standard setting process starts with determining the level
of HAP emissions limitation that is currently achieved by the best-
controlled similar source (for new source standards) or by the average
of the best-performing

sources (for existing source standards). Specifically for categories
with 30 or more sources, the MACT floor for existing sources must be at
least as stringent as the average emissions limitation achieved by the
best performing 12 percent of existing sources for which the EPA has
emissions information. For source categories with fewer than 30
sources, the MACT floor for existing sources is the average emission
limitation achieved by the best performing five sources. See CAA
sections 112(d)(2)-(3)(A) and (B). We applied the upper prediction
limit (UPL) and information on the RDL to calculate the MACT floor.
Once the UPL is calculated for new sources and existing sources, the
UPL must be compared to the three times the RDL value as a final step
to assess variability. If the three times the RDL value is greater than
the UPL, then three times the RDL is selected as the MACT floor
emission level.
    Dioxins and furans stack test data are available for nine HON
facilities, and we assessed this data to conduct our MACT analyses and