there may be a greater tendency to overestimate risk in the sense that
further study might support development of reference values that are
higher (i.e., less potent) because fewer default assumptions are
needed. However, for some pollutants, it is possible that risks may be
underestimated.
---------------------------------------------------------------------------

    \20\ According to the NRC report, Science and Judgment in Risk
Assessment (NRC, 1994) ``[Default] options are generic approaches,
based on general scientific knowledge and policy judgment, that are
applied to various elements of the risk assessment process when the
correct scientific model is unknown or uncertain.'' The 1983 NRC
report, Risk Assessment in the Federal Government: Managing the
Process, defined default option as ``the option chosen on the basis
of risk assessment policy that appears to be the best choice in the
absence of data to the contrary'' (NRC, 1983a, p. 63). Therefore,
default options are not rules that bind the Agency; rather, the
Agency may depart from them in evaluating the risks posed by a
specific substance when it believes this to be appropriate. In
keeping with EPA's goal of protecting public health and the
environment, default assumptions are used to ensure that risk to
chemicals is not underestimated (although defaults are not intended
to overtly overestimate risk). See EPA, 2004, An Examination of EPA
Risk Assessment Principles and Practices, EPA/100/B-04/001 available
at: http://www.epa.gov/osa/pdfs/ratf-final.pdf.
---------------------------------------------------------------------------

    While collectively termed ``UF,'' these factors account for a
number of different quantitative considerations when using observed
animal (usually rodent) or human toxicity data in the development of
the RfC. The UF are intended to account for: (1) Variation in
susceptibility among the members of the human population (i.e., inter-
individual variability); (2) uncertainty in extrapolating from
experimental animal data to humans (i.e., interspecies differences);
(3) uncertainty in extrapolating from data obtained in a study with
less-than-lifetime exposure (i.e., extrapolating from sub-chronic to
chronic exposure); (4) uncertainty in extrapolating the observed data
to obtain an estimate of the exposure associated with no adverse
effects; and (5) uncertainty when the database is incomplete or there
are problems with the applicability of available studies.
    Many of the UF used to account for variability and uncertainty in
the development of acute reference values are quite similar to those
developed for chronic durations, but they more often use individual UF
values that may be less than 10. The UF are applied based on chemical-
specific or health effect-specific information (e.g., simple irritation
effects do not vary appreciably between human individuals, hence a
value of 3 is typically used), or based on the purpose for the
reference value (see the following paragraph). The UF

applied in acute reference value derivation include: (1) Heterogeneity
among humans; (2) uncertainty in extrapolating from animals to humans;
(3) uncertainty in lowest observable adverse effect (exposure) level to
no observed adverse effect (exposure) level adjustments; and (4)
uncertainty in accounting for an incomplete database on toxic effects
of potential concern. Additional adjustments are often applied to
account for uncertainty in extrapolation from observations at one
exposure duration (e.g., 4 hours) to derive an acute reference value at
another exposure duration (e.g., 1 hour).
    Not all acute reference values are developed for the same purpose
and care must be taken when interpreting the results of an acute
assessment of human health effects relative to the reference value or
values being exceeded. Where relevant to the estimated exposures, the
lack of short-term dose-response values at different levels of severity
should be factored into the risk characterization as potential
uncertainties.
    Although every effort is made to identify appropriate human health
effect dose-response assessment values for all pollutants emitted by
the sources in this risk assessment, some HAP emitted by these source
categories are lacking dose-response assessments. Accordingly, these
pollutants cannot be included in the quantitative risk assessment,
which could result in quantitative estimates understating HAP risk. To
help to alleviate this potential underestimate, where we conclude
similarity with a HAP for which a dose-response assessment value is
available, we use that value as a surrogate for the assessment of the
HAP for which no value is available. To the extent use of surrogates
indicates appreciable risk, we may identify a need to increase priority
for new IRIS assessment of that substance. We additionally note that,
generally speaking, HAP of greatest concern due to environmental
exposures and hazard are those for which dose-response assessments have
been performed, reducing the likelihood of understating risk. Further,
HAP not included in the quantitative assessment are assessed
qualitatively and considered in the risk characterization that informs
the risk management decisions, including with regard to consideration
of HAP reductions achieved by various control options.
    For a group of compounds that are unspeciated (e.g., glycol
ethers), we conservatively use the most protective reference value of
an individual compound in that group to estimate risk. Similarly, for
an individual compound in a group (e.g., ethylene glycol diethyl ether)
that does not have a specified reference value, we also apply the most
protective reference value from the other compounds in the group to
estimate risk.
e. Uncertainties in the Multipathway Assessment
    For each source category, we generally rely on site-specific levels
of PB-HAP emissions to determine whether a refined assessment of the
impacts from multipathway exposures is necessary. This determination is
based on the results of a two-tiered screening analysis that relies on
the outputs from models that estimate environmental pollutant
concentrations and human exposures for four PB-HAP. Two important types
of uncertainty associated with the use of these models in RTR risk
assessments and inherent to any assessment that relies on environmental
modeling are model uncertainty and input uncertainty.\21\
---------------------------------------------------------------------------

    \21\ In the context of this discussion, the term ``uncertainty''
as it pertains to exposure and risk encompasses both variability in
the range of expected inputs and screening results due to existing
spatial, temporal, and other factors, as well as uncertainty in
being able to accurately estimate the true result.
---------------------------------------------------------------------------

    Model uncertainty concerns whether the selected models are
appropriate for the assessment being conducted and whether they
adequately represent the actual processes that might occur for that
situation. An example of model uncertainty is the question of whether
the model adequately describes the movement of a pollutant through the
soil. This type of uncertainty is difficult to quantify. However, based
on feedback received from previous EPA SAB reviews and other reviews,
we are confident that the models used in the screen are appropriate and
state-of-the-art for the multipathway risk assessments conducted in
support of RTR.
    Input uncertainty is concerned with how accurately the models have
been configured and parameterized for the assessment at hand. For Tier
I of the multipathway screen, we configured the models to avoid
underestimating exposure and risk. This was accomplished by selecting
upper-end values from nationally-representative data sets for the more
influential parameters in the environmental model, including selection
and spatial configuration of the area of interest, lake location and
size, meteorology, surface water and soil characteristics and structure
of the aquatic food web. We also assume an ingestion exposure scenario
and values for human exposure factors that represent reasonable maximum
exposures.
    In Tier II of the multipathway assessment, we refine the model
inputs to account for meteorological patterns in the vicinity of the
facility versus using upper-end national values and we identify the
actual location of lakes near the facility rather than the default lake
location that we apply in Tier I. By refining the screening approach in
Tier II to account for local geographical and meteorological data, we
decrease the likelihood that concentrations in environmental media are
overestimated, thereby increasing the usefulness of the screen. The
assumptions and the associated uncertainties regarding the selected
ingestion exposure scenario are the same for Tier I and Tier II.
    For both Tiers I and II of the multipathway assessment, our
approach to addressing model input uncertainty is generally cautious.
We choose model inputs from the upper end of the range of possible
values for the influential parameters used in the models, and we assume
that the exposed individual exhibits ingestion behavior that would lead
to a high total exposure. This approach reduces the likelihood of not
identifying high risks for adverse impacts.
    Despite the uncertainties, when individual pollutants or facilities
do screen out, we are confident that the potential for adverse
multipathway impacts on human health is very low. On the other hand,
when individual pollutants or facilities do not screen out, it does not
mean that multipathway impacts are significant, only that we cannot
rule out that possibility and that a refined multipathway analysis for
the site might be necessary to obtain a more accurate risk
characterization for the source categories.
    For further information on uncertainties and the Tier I and II
screening methods, refer to the risk document Appendix 4, Technical
Support Document for TRIM-Based Multipathway Tiered Screening
Methodology for RTR.
f. Uncertainties in the Environmental Risk Screening Assessment
    For each source category, we generally rely on site-specific levels
of environmental HAP emissions to perform an environmental screening
assessment. The environmental screening assessment is based on the
outputs from models that estimate environmental HAP concentrations. The
same models, specifically the TRIM.FaTE multipathway model and the
AERMOD air dispersion model, are used to estimate environmental HAP

concentrations for both the human multipathway screening analysis and
for the environmental screening analysis. Therefore, both screening
assessments have similar modeling uncertainties.
    Two important types of uncertainty associated with the use of these
models in RTR environmental screening assessments--and inherent to any
assessment that relies on environmental modeling--are model uncertainty
and input uncertainty.\22\
---------------------------------------------------------------------------

    \22\ In the context of this discussion, the term
``uncertainty,'' as it pertains to exposure and risk assessment,
encompasses both variability in the range of expected inputs and
screening results due to existing spatial, temporal, and other
factors, as well as uncertainty in being able to accurately estimate
the true result.
---------------------------------------------------------------------------

    Model uncertainty concerns whether the selected models are
appropriate for the assessment being conducted and whether they
adequately represent the movement and accumulation of environmental HAP
emissions in the environment. For example, does the model adequately
describe the movement of a pollutant through the soil? This type of
uncertainty is difficult to quantify. However, based on feedback
received from previous EPA SAB reviews and other reviews, we are
confident that the models used in the screen are appropriate and state-
of-the-art for the environmental risk assessments conducted in support
of our RTR analyses.
    Input uncertainty is concerned with how accurately the models have
been configured and parameterized for the assessment at hand. For Tier
I of the environmental screen for PB-HAP, we configured the models to
avoid underestimating exposure and risk to reduce the likelihood that
the results indicate the risks are lower than they actually are. This
was accomplished by selecting upper-end values from nationally-
representative data sets for the more influential parameters in the
environmental model, including selection and spatial configuration of
the area of interest, the location and size of any bodies of water,
meteorology, surface water and soil characteristics and structure of
the aquatic food web. In Tier I, we used the maximum facility-specific
emissions for cadmium compounds, dioxins/furans, POM, and mercury and
each of the media when comparing to ecological benchmarks. This is
consistent with the conservative design of Tier I of the screen. In
Tier II of the environmental screening analysis for PB-HAP, we refine
the model inputs to account for meteorological patterns in the vicinity
of the facility versus using upper-end national values, and we identify
the locations of water bodies near the facility location. By refining
the screening approach in Tier II to account for local geographical and
meteorological data, we decrease the likelihood that concentrations in
environmental media are overestimated, thereby increasing the
usefulness of the screen. To better represent widespread impacts, the
modeled soil concentrations are averaged in Tier II to obtain one
average soil concentration value for each facility and for each PB-HAP.
For PB-HAP concentrations in water, sediment and fish tissue, the
highest value for each facility for each pollutant is used.
    For the environmental screening assessment for acid gases, we
employ a single-tiered approach. We use the modeled air concentrations
and compare those with ecological benchmarks.
    For both Tiers I and II of the environmental screening assessment,
our approach to addressing model input uncertainty is generally
cautious. We choose model inputs from the upper end of the range of
possible values for the influential parameters used in the models, and
we assume that the exposed organism (e.g., invertebrate, fish) exhibits
ingestion behavior that would lead to a high total exposure. This
approach reduces the likelihood of not identifying potential risks for
adverse environmental impacts.
    Uncertainty also exists in the ecological benchmarks for the
environmental risk screening analysis. We established a hierarchy of
preferred benchmark sources to allow selection of benchmarks for each
environmental HAP at each ecological assessment endpoint. In general,
EPA benchmarks used at a programmatic level (e.g., Office of Water,
Superfund Program) were used if available. If not, we used EPA
benchmarks used in regional programs (e.g., Superfund). If benchmarks
were not available at a programmatic or regional level, we used
benchmarks developed by other agencies (e.g., NOAA) or by state
agencies.
    In all cases (except for lead, which was evaluated through a
comparison to the NAAQS), we searched for benchmarks at the following
three effect levels, as described in section III.A.6 of this preamble:
    1. A no-effect level (i.e., NOAEL).
    2. Threshold-effect level (i.e., LOAEL).
    3. Probable effect level (i.e., PEL).
    For some ecological assessment endpoint/environmental HAP
combinations, we could identify benchmarks for all three effect levels,
but for most, we could not. In one case, where different agencies
derived significantly different numbers to represent a threshold for
effect, we included both. In several cases, only a single benchmark was
available. In cases where multiple effect levels were available for a
particular PB-HAP and assessment endpoint, we used all of the available
effect levels to help us to determine whether risk exists and if the
risks could be considered significant and widespread.
    The EPA evaluated the following seven HAP in the environmental risk
screening assessment: Cadmium, dioxins/furans, POM, mercury (both
inorganic mercury and methyl mercury), lead compounds, HCl and HF.
These seven HAP represent pollutants that can cause adverse impacts for
plants and animals either through direct exposure to HAP in the air or
through exposure to HAP that is deposited from the air onto soils and
surface waters. These seven HAP also represent those HAP for which we
can conduct a meaningful environmental risk screening assessment. For
other HAP not included in our screening assessment, the model has not
been parameterized such that it can be used for that purpose. In some
cases, depending on the HAP, we may not have appropriate multipathway
models that allow us to predict the concentration of that pollutant.
The EPA acknowledges that other HAP beyond the seven HAP that we are
evaluating may have the potential to cause adverse environmental
effects and, therefore, the EPA may evaluate other relevant HAP in the
future, as modeling science and resources allow.
    Further information on uncertainties and the Tier I and II
environmental screening methods is provided in Appendix 5 of the
document Technical Support Document for TRIM-Based Multipathway Tiered
Screening Methodology for RTR: Summary of Approach and Evaluation.
Also, see the Draft Residual Risk Assessment for the Petroleum Refining
Source Sector, available in the docket for this action (Docket ID
Number EPA-HQ-OAR-2010-0682).

B. How did we consider the risk results in making decisions for this
proposal?

    As discussed in section II.A.1 of this preamble, in evaluating and
developing standards under CAA section 112(f)(2), we apply a two-step
process to address residual risk. In the first step, the EPA determines
whether risks are acceptable. This determination ``considers all health
information, including risk estimation uncertainty, and includes a
presumptive limit on maximum individual lifetime

[cancer] risk (MIR) \23\ of approximately [1-in-10 thousand] [i.e.,
100-in-1 million].'' 54 FR 38045, September 14, 1989. If risks are
unacceptable, the EPA must determine the emissions standards necessary
to bring risks to an acceptable level without considering costs. In the
second step of the process, the EPA considers whether the emissions
standards provide an ample margin of safety ``in consideration of all
health information, including the number of persons at risk levels
higher than approximately 1-in-1 million, as well as other relevant
factors, including costs and economic impacts, technological
feasibility, and other factors relevant to each particular decision.''
Id. The EPA must promulgate tighter emission standards if necessary to
provide an ample margin of safety.
---------------------------------------------------------------------------

    \23\ Although defined as ``maximum individual risk,'' MIR refers
only to cancer risk. MIR, one metric for assessing cancer risk, is
the estimated risk were an individual exposed to the maximum level
of a pollutant for a lifetime.
---------------------------------------------------------------------------

    In past residual risk actions, the EPA considered a number of human
health risk metrics associated with emissions from the categories under
review, including the MIR, the number of persons in various risk
ranges, cancer incidence, the maximum non-cancer HI and the maximum
acute non-cancer hazard. See, e.g., 72 FR 25138, May 3, 2007; 71 FR
42724, July 27, 2006. The EPA considered this health information for
both actual and allowable emissions. See, e.g., 75 FR 65068, October
21, 2010, and 75 FR 80220, December 21, 2010). The EPA also discussed
risk estimation uncertainties and considered the uncertainties in the
determination of acceptable risk and ample margin of safety in these
past actions. The EPA considered this same type of information in
support of this action.
    The agency is considering these various measures of health
information to inform our determinations of risk acceptability and
ample margin of safety under CAA section 112(f). As explained in the
Benzene NESHAP, ``the first step of judgment on acceptability cannot be
reduced to any single factor,'' and thus ``[t]he Administrator believes
that the acceptability of risk under [previous] section 112 is best
judged on the basis of a broad set of health risk measures and
information.'' 54 FR 38046, September 14, 1989. Similarly, with regard
to making the ample margin of safety determination, ``the Agency again
considers all of the health risk and other health information
considered in the first step. Beyond that information, additional
factors relating to the appropriate level of control will also be
considered, including cost and economic impacts of controls,
technological feasibility, uncertainties, and any other relevant
factors.'' Id.
    The Benzene NESHAP approach provides flexibility regarding factors
the EPA may consider in making determinations and how the EPA may weigh
those factors for each source category. In responding to comment on our
policy under the Benzene NESHAP, the EPA explained that:

[t]he policy chosen by the Administrator permits consideration of
multiple measures of health risk. Not only can the MIR figure be
considered, but also incidence, the presence of non-cancer health
effects, and the uncertainties of the risk estimates. In this way,
the effect on the most exposed individuals can be reviewed as well
as the impact on the general public. These factors can then be
weighed in each individual case. This approach complies with the
Vinyl Chloride mandate that the Administrator ascertain an
acceptable level of risk to the public by employing [her] expertise
to assess available data. It also complies with the Congressional
intent behind the CAA, which did not exclude the use of any
particular measure of public health risk from the EPA's
consideration with respect to CAA section 112 regulations, and
thereby implicitly permits consideration of any and all measures of
health risk which the Administrator, in [her] judgment, believes are
appropriate to determining what will `protect the public health.'

See 54 FR at 38057, September 14, 1989. Thus, the level of the MIR is
only one factor to be weighed in determining acceptability of risks.
The Benzene NESHAP explained that ``an MIR of approximately one in 10
thousand should ordinarily be the upper end of the range of
acceptability. As risks increase above this benchmark, they become
presumptively less acceptable under CAA section 112, and would be
weighed with the other health risk measures and information in making
an overall judgment on acceptability. Or, the Agency may find, in a
particular case, that a risk that includes MIR less than the
presumptively acceptable level is unacceptable in the light of other
health risk factors.'' Id. at 38045. Similarly, with regard to the
ample margin of safety analysis, the EPA stated in the Benzene NESHAP
that: ``EPA believes the relative weight of the many factors that can
be considered in selecting an ample margin of safety can only be
determined for each specific source category. This occurs mainly
because technological and economic factors (along with the health-
related factors) vary from source category to source category.'' Id. at
38061. We also consider the uncertainties associated with the various
risk analyses, as discussed earlier in this preamble, in our
determinations of acceptability and ample margin of safety.
    The EPA notes that it has not considered certain health information
to date in making residual risk determinations. At this time, we do not
attempt to quantify those HAP risks that may be associated with
emissions from other facilities that do not include the source
categories in question, mobile source emissions, natural source
emissions, persistent environmental pollution or atmospheric
transformation in the vicinity of the sources in these categories.
    The agency understands the potential importance of considering an
individual's total exposure to HAP in addition to considering exposure
to HAP emissions from the source category and facility. We recognize
that such consideration may be particularly important when assessing
non-cancer risks, where pollutant-specific health reference levels
(e.g., RfCs) are based on the assumption that thresholds exist for
adverse health effects. For example, the agency recognizes that,
although exposures attributable to emissions from a source category or
facility alone may not indicate the potential for increased risk of
adverse non-cancer health effects in a population, the exposures
resulting from emissions from the facility in combination with
emissions from all of the other sources (e.g., other facilities) to
which an individual is exposed may be sufficient to result in increased
risk of adverse non-cancer health effects. In May 2010, the SAB advised
the EPA ``that RTR assessments will be most useful to decision makers
and communities if results are presented in the broader context of
aggregate and cumulative risks, including background concentrations and
contributions from other sources in the area.'' \24\
---------------------------------------------------------------------------

    \24\ EPA's responses to this and all other key recommendations
of the SAB's advisory on RTR risk assessment methodologies (which is
available at: http://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf)
are outlined in a memo to this rulemaking docket from David Guinnup
entitled, EPA's Actions in Response to the Key Recommendations of
the SAB Review of RTR Risk Assessment Methodologies.
---------------------------------------------------------------------------

    In response to the SAB recommendations, the EPA is incorporating
cumulative risk analyses into its RTR risk assessments, including those
reflected in this proposal. The agency is: (1) Conducting facility-wide
assessments, which include source category emission points as well as
other emission points within the facilities; (2) considering sources in
the same category whose emissions result in exposures to the same
individuals; and (3) for some persistent and

bioaccumulative pollutants, analyzing the ingestion route of exposure.
In addition, the RTR risk assessments have always considered aggregate
cancer risk from all carcinogens and aggregate non-cancer hazard
indices from all non-carcinogens affecting the same target organ
system.
    Although we are interested in placing source category and facility-
wide HAP risks in the context of total HAP risks from all sources
combined in the vicinity of each source, we are concerned about the
uncertainties of doing so. Because we have not conducted in-depth
studies of risks due to emissions from sources other those at
refineries subject to this RTR review, such estimates of total HAP
risks would have significantly greater associated uncertainties than
the source category or facility-wide estimates. Such aggregate or
cumulative assessments would compound those uncertainties, making the
assessments too unreliable.

C. How did we perform the technology review?

    Our technology review focused on the identification and evaluation
of developments in practices, processes and control technologies that
have occurred since the MACT standards were promulgated. Where we
identified such developments, in order to inform our decision of
whether it is ``necessary'' to revise the emissions standards, we
analyzed the technical feasibility of applying these developments, and
the estimated costs, energy implications, non-air environmental
impacts, as well as considering the emission reductions. We also
considered the appropriateness of applying controls to new sources
versus retrofitting existing sources.
    Based on our analyses of the available data and information, we
identified potential developments in practices, processes and control
technologies. For this exercise, we considered any of the following to
be a ``development'':
     Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards.
     Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT standards) that could result in additional emissions
reduction.
     Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards.
     Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT
standards.
     Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT standards).
    We reviewed a variety of data sources in our investigation of
potential practices, processes or controls to consider. Among the
sources we reviewed were the NESHAP for various industries that were
promulgated since the MACT standards being reviewed in this action. We
reviewed the regulatory requirements and/or technical analyses
associated with these regulatory actions to identify any practices,
processes and control technologies considered in these efforts that
could be applied to emission sources subject to Refinery MACT 1 or 2,
as well as the costs, non-air impacts and energy implications
associated with the use of these technologies. Additionally, we
requested information from facilities as described in section II.C of
this preamble. Finally, we reviewed information from other sources,
such as state and/or local permitting agency databases and industry-
supported databases.

IV. Analytical Results and Proposed Decisions

A. What actions are we taking pursuant to CAA sections 112(d)(2) and
112(d)(3)?

    In this action, we are proposing the following revisions to the
Refinery MACT 1 and 2 standards pursuant to CAA section 112(d)(2) and
(3) \25\: (1) Adding MACT standards for DCU decoking operations; (2)
revising the CRU purge vent pressure exemption; (3) adding operational
requirements for flares used as air pollution control devices (APCD) in
Refinery MACT 1 and 2; and (4) adding requirements and clarifications
for vent control bypasses in Refinery MACT 1. The results and proposed
decisions based on the analyses performed pursuant to CAA section
112(d)(2) and (3) are presented below.
---------------------------------------------------------------------------

    \25\ The EPA has authority under CAA section 112(d)(2) and
(d)(3) to set MACT standards for previously unregulated emission
points. EPA also retains the discretion to revise a MACT standard
under the authority of 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 Institute v. EPA, 645 F. 3d at 426 (upholding EPA
action establishing MACT floors, based on post-compliance data, when
originally-established floors were improperly established).
---------------------------------------------------------------------------

1. Delayed Coking Units
a. Description of Delayed Coker Process Operations and Emissions
    We are proposing to establish MACT standards specific to the DCU
pursuant to CAA section 112(d)(2) and (3). The DCU uses thermal
cracking to upgrade heavy feedstocks and to produce petroleum coke.
Unlike most other refinery operations that are continuous, the DCU
operates in a semi-batch system. Most DCU consist of a large process
heater, two or more coking drums, and a single product distillation
column. The DCU feed is actually fed to the unit's distillation column.
Bottoms from the distillation column are heated to near cracking
temperatures and the resulting heavy oil is fed to one of the coking
drums. As the cracking reactions occur, coke is produced in the drum
and begins to fill the drum with sponge-like solid coke material.
During this process, the DCU is a closed system, with the produced gas
streams piped to the unit's distillation column for product recovery.
    When the first coke drum becomes filled with coke, the feed is
diverted to the second coke drum and processing continues via the
second coke drum. The full coke drum, which is no longer receiving oil
feed, is taken through a number of steps, collectively referred to as
decoking operations, to remove the coke from the drum and prepare the
drum for subsequent oil feed processing. The decoking steps include:
purging, cooling/quenching, venting, draining, deheading, and coke
cutting. A description of these steps and the potential emissions from
these activities are provided in the next several paragraphs. Once the
coke is removed, the vessel is re-sealed (i.e., the drain valve is
closed and the ``head'' is re-attached), pressure tested (typically
using steam), purged to remove oxygen, then slowly heated to processing
temperatures so it can go back on-line. When the second coke drum
becomes filled with coke, feed is diverted back to the first coke drum
and the second drum is then decoked. In this manner, the DCU allows for
continuous processing of oil even though the individual coke drums
operate in cyclical batch fashion.
    The first step in decoking operations is to purge the coke drum
with steam. This serves to cool the coke bed and to flush oil or
reaction products from the coke bed. The steam purge is initially sent
to the product distillation column and then diverted to the unit's
blowdown system. The blowdown system serves to condense the steam and
other liquids entrained in the

steam. Nearly all DCU operate a ''closed blowdown'' system, such that
uncondensed gases from the blowdown system are sent to the product
distillation column or the facility's light gas plant, recovered as
fuel gas, or combusted in a flare. In an open blowdown system, these
uncondensed gases would be vented directly to atmosphere. The DCU vent
discharge to the blowdown system is specifically defined in Refinery
MACT 1 as the ``delayed coker vent.''
    The next step in the decoking process is cooling/quenching the coke
drum and its contents via the addition of water, commonly referred to
as quench water, at the bottom of the coke drum. The water added to the
vessel quickly turns to steam due to the high temperature of the coke
bed. The water/steam helps to further cool the coke bed and ``quench''
any residual coking reactions that may still occur within the hot coke
bed. As with the steam purge, steam off-gas from the cooling/quenching
cycle is recovered in the unit's blowdown system and this vent
discharge is specifically defined in Refinery MACT 1 as the ``delayed
coker vent.''
    After several hours, the coke drum is sufficiently cooled so that
the water level in the drum can be raised to entirely cover the coke
bed. Although water covers the coke bed, the upper portion of the coke
bed may still be well above 212 degrees Fahrenheit ([deg]F) and will
continue to generate steam. In fact, since the coke drum vessel
pressure is greater than atmospheric pressure, the equilibrium boiling
point of water in the vessel is greater than 212[emsp14][deg]F.
Therefore, the water at the top of the coke drum is typically well
above 212[emsp14][deg]F (superheated water). As the coke drum and its
contents continue to cool from the evaporative cooling effect of the
steam generation, the steam generation rate and the pressure within the
vessel will decrease.
    Owners or operators of DCU may use different indicators or set
points to determine when the system has cooled sufficiently to move to
the venting step; however, one of the most common indicators monitored
is the pressure of the coke drum vessel (or steam vent line just above
the coke drum, where steam exits the coke drum en route to the blowdown
system). When the vessel has cooled sufficiently (e.g., when the coke
drum vessel pressure reaches the desired set point), valves are opened
to allow the steam generated in the coke drum to vent directly to the
atmosphere rather than the closed blowdown system. This vent is
commonly referred to as the ``coker steam vent'' and is typically the
first direct atmospheric emission release during the decoking
operations when an enclosed blowdown system is used. While this vent
gas contains predominately steam, methane and ethane, a variety of HAP
are also emitted with this steam. These HAP include light aromatics
(e.g., benzene, toluene, and xylene) and light POM (predominately
naphthalene and 2-methyl naphthalene). The level of HAP emitted from
the DCU has been found to be a function of the quantity of steam
generated (see the technical memorandum entitled Impacts Estimates for
Delayed Coking Units in Docket ID Number EPA-HQ-OAR-2010-0682).
    In general, the next step in the decoking process is draining the
water from the coke drum by opening a large valve at the bottom of the
coke drum. The drain water typically falls from the coke drum onto a
slanted concrete pad that directs the water to the coke pit area (where
water and coke are collected and separated). Some DCU owners or
operators initiate draining at the same time they initiate venting;
other owners or operators may allow the vessel to vent for 20 or more
minutes prior to initiating draining. While draining immediately may
reduce the amount of steam exiting the unit via the stack, as explained
below, it is not expected to alter the overall emissions from the unit.
During the venting and draining process, the pressure of the system
falls to atmospheric. Steam will be generated until the evaporative
cooling effect of that steam generation cools the coker quench water to
212[emsp14][deg]F. If draining is initiated immediately, some of the
superheated water may drain from the DCU before being cooled. A portion
of that drained water will then convert to steam during the draining
process as that superheated water contacts the open atmosphere.
Therefore, draining quickly is not expected to alter the total amount
of steam generated from the unit nor alter the overall emissions from
the unit. It will, however, alter the relative proportion of the
emissions that are released via the vent versus the quench water drain
area.
    The next step in the decoking process is ``deheading'' the coke
drum. At the top of the coke drum is a large 3- to 5-foot diameter
opening, which is sealed with a gasketed lid during normal operations.
When the steam generation rate from the coke drum has sufficiently
subsided, this gasketed lid is removed to allow access for a water
drill that will be used to remove coke from the drum. The process of
removing this lid is referred to as ``deheading'' the coke drum.
Different DCU owners or operators may use different criteria for when
to dehead the coke drum. If the coke drum is deheaded soon after
venting is initiated, some steam and associated HAP emissions may be
released from this opening. As with draining, it is anticipated that
the total volume of steam generated will be a function of the
temperature/pressure of the coke drum. Deheading the coke drum prior to
the coke drum contents reaching 212[emsp14][deg]F will generally mean
that some of the steam will be released from the coke drum head
opening. However, this will not alter the total amount of steam
generated; it merely alters the location of the release (coke drum head
opening versus steam vent). The HAP emissions from the deheading
process are expected to be proportional to the amount of steam released
in the same manner as the emissions from the steam vent.
    The final step of the decoking process is coke cutting. A high-
pressure water jet is used to drill or cut the coke out of the vessel.
The drilling water and coke slurry exits the coke drum via the drain
opening and collects in the coke pit. Generally, the coke drum and its
contents are sufficiently cooled so that this process is not expected
to yield significant HAP emissions. However, if the other decoking
steps are performed too quickly, hot spots may exist within the coke
bed and HAP emissions may occur as water contacts these hot spots and
additional steam and emissions are released.
    Once the coke is cut out of the drum, the drum is closed and
prepared to go back on-line. This process includes pressurizing with
steam to ensure there are no leaks (i.e., that the head is properly
attached and sealed and the drain valve is fully closed). The vessel is
then purged to remove any oxygen and heated by diverting the produced
gas from the processing coke drum through the empty drum prior to
sending it to the unit's distillation column. A coke drum cycle is
typically 28 to 36 hours from start of feed to start of the next feed.
b. How Delayed Coker Vents Are Addressed in Refinery MACT 1
    Delayed coker vents are specifically mentioned as an example within
the first paragraph of the definition of ``miscellaneous process vent''
in 40 CFR 63.641 of Refinery MACT 1. However, the definition of
``miscellaneous process vent'' also excludes coking unit vents
associated with coke drum depressuring (at or below a coke drum outlet
pressure of 15 pounds per square inch gauge [psig]), deheading,
draining, or decoking (coke cutting) or pressure testing after
decoking. Refinery MACT 1 also

includes a definition of ``delayed coker vent'' in 40 CFR 63.641. This
vent is typically intermittent in nature, and usually occurs only
during the initiation of the depressuring cycle of the decoking
operation when vapor from the coke drums cannot be sent to the
fractionator column for product recovery, but instead is routed to the
atmosphere through a closed blowdown system or directly to the
atmosphere in an open blowdown system. The emissions from the decoking
phases of DCU operations, which include coke drum deheading, draining,
or decoking (coke cutting), are not considered to be delayed coker
vents.
    The first paragraph of the definition of ``miscellaneous process
vent'' also includes blowdown condensers/accumulators as an example of
a miscellaneous process vent. Therefore, the DCU blowdown system is a
miscellaneous process vent regardless of whether or not the blowdown
system is associated with a DCU or another process unit. Further, the
inclusion of the ``delayed coker vent'' as an example of a
miscellaneous process vent makes it clear that the DCU's blowdown
system vent (if an open blowdown system is used) is considered a
miscellaneous process vent. It is less clear from the regulatory text
whether the direct venting of the coke drum to the atmosphere via the
steam vent during the final depressurization is considered to be a
``delayed coker vent'' (i.e., whether direct venting to the atmosphere
is equivalent to venting ``directly to the atmosphere in an open
blowdown system'').
    The regulatory text is clear that this steam vent is exempt from
the definition of ``miscellaneous process vent'' when the pressure of
the vessel is less than 15 psig. It is also clear that the subsequent
release points from the decoking operations (i.e., deheading, draining,
and coke cutting) are excluded from both the definition of ``delayed
coker vent'' and the definition of ``miscellaneous process vent.''
Further, based on the statements in the background information document
for the August 1995 final Refinery MACT 1 rule,\26\ the 15 psig
pressure limit for the direct venting of the DCU to the atmosphere was
not established as a MACT floor control level; it was established to
accommodate all DCU at whatever pressure they typically switched from
venting to the closed blowdown system to venting directly to the
atmosphere. Based on this information, as well as the data from the
2011 Refinery ICR, refinery enforcement settlements and other
information available, which indicate that all refineries depressurize
the coke drum below 15 psig, we have determined that the direct
atmospheric releases from the DCU decoking operations are currently
unregulated emissions. These unregulated releases include emissions
during atmospheric depressuring (i.e., the steam vent), deheading,
draining, and coke cutting.
---------------------------------------------------------------------------

    \26\ National Emission Standards for Hazardous Air Pollutants
Petroleum Refineries--Background Information for Final Standards;
EPA-453/R-95-015b.
---------------------------------------------------------------------------

c. Evaluation of MACT Emission Limitations for Delayed Coking Units
    We evaluated emissions and controls during DCU decoking operations
in order to identify appropriate MACT emission limitations pursuant to
CAA section 112(d)(2) and (3). Establishing a lower pressure set point
at which a DCU owner or operator can switch from venting to an enclosed
blowdown system to venting to the atmosphere is the control technique
identified for reducing emissions from delayed coking operations.
Essentially, there is a fixed quantity of steam that will be generated
as the coke drum and its contents cool. The lower pressure set point
will require the DCU to vent to the closed blowdown system longer,
where the organic HAP can be recovered or controlled. This will result
in fewer emissions released during the venting, draining and deheading
process.
    We consider this control technique, which is a work practice
standard, appropriate for the DCU for the reasons discussed below for
each of the four possible emission points at the DCU: draining,
deheading, coke cutting and the steam vent. For the first three steps,
the emissions cannot be emitted through a conveyance designed and
constructed to emit or capture such pollutant. For example, during
draining, the drain water typically falls from the coke drum onto a
slanted concrete pad that directs the water to an open coke pit area
(where water and coke are collected and separated). When the coke drum
is deheaded, the coke drum head must be removed to provide an
accessible opening in the drum so the coke cutting equipment can be
lowered into the drum. This opening cannot be sealed during coke
cutting because the drilling shaft will occupy the opening and the
shaft must be free to be lowered or raised during the coke cutting
process.
    While the emissions from the fourth point, the DCU steam vent, are
released via a conveyance designed and constructed to emit or capture
such pollutant, as provided in CAA section 112(h)(2)(B), it is not
feasible to prescribe or enforce an emission standard for the DCU steam
vent because the application of a measurement methodology for this
source is not practicable due to technological and economic
limitations.
    First, it is not practicable to use a measurement methodology for
the DCU steam vent. The emissions from the vent typically contain 99
percent water, which interferes with common sample collection and
analysis techniques. Also, the flow rate from this vent is not
constant; rather, it decreases during the venting process as the
pressure in the DCU coke drum approaches atmospheric pressure.
Additionally, the venting time can be very short. As part of the ICR,
we requested stack testing of eight DCU. After discussions with stack
testing experts within the agency and with outside contractors used by
industry to perform the tests, we concluded that sources with venting
times less than 20 minutes would not be able to perform an emissions
test that would yield valid results. Therefore, only two of the eight
facilities actually performed the tests. We anticipate all units
complying with the proposed standards for DCU steam vents would vent
for less than 20 minutes.
    Second, it is not feasible to enforce an emission standard only on
the steam vent because the timing of drainage and deheading can alter
the portion of the decoking emissions that are released from the actual
steam vent. If draining and deheading are initiated quickly after
venting, this will reduce the emissions discharged from the vent
(although as explained above, it does not reduce the emissions from the
collective set of decoking operations release points).
    Consequently, due to the unique nature of DCU emissions, the
difficulties associated with monitoring the DCU steam vent, and the
inability to construct a conveyance to capture emissions from all
decoking release points, we are proposing that it is appropriate to
develop work practice standards in place of emission limits for the
DCU.
    To establish the MACT floor, we then reviewed regulations, permits
and consent decrees that require coke controls. Refinery NSPS Ja
establishes a pressure limit of 5 psig prior to allowing the coke drum
to be vented to the atmosphere. Based on a review of permit limits and
consent decrees, we found that coke drum vessel pressure limits have
been established (and achieved) as low as 2 psig. There are 75
operating DCU according to the Refinery ICR responses, so the sixth
percentile is represented by the fifth-best performing DCU. We
identified eight DCU with

permit requirements or consent decrees specifying a coke drum venting
pressure limit of 2 psig; we did not identify any permit or consent
decree requirements more stringent than 2 psig. Refinery owners and
operators were asked to provide the ``typical coke drum pressure just
prior to venting'' for each DCU in their responses to the Refinery ICR,
and the responses indicate that four DCU operate such that the typical
venting pressure is 1 psig or less. However, this ``typical coke drum
pressure'' does not represent a not-to-be-exceeded pressure limit; it
is expected that these units are operated this way to meet a pressure
limit of 2 psig. We do not have information to indicate whether these
facilities are always depressurized at 1 psig or less. Moreover, there
were only four units for which a typical venting pressure of 1 psig was
identified and the MACT floor for existing sources is represented by
the fifth-best operating DCU, not the best-performing unit. Therefore,
we are proposing that the MACT floor for DCU decoking operations is to
depressure at 2 psig or less prior to venting to the atmosphere for
existing sources. We are also proposing that the MACT floor for new
sources is 2 psig, since the best-performing source is permitted to
depressure at 2 psig or less. For additional details on the MACT floor
analysis, see memorandum entitled MACT Analysis for Delayed Coking Unit
Decoking Operations in Docket ID Number EPA-HQ-OAR-2010-0682.
    We then considered control options beyond the floor level of 2 psig
to determine if additional emission reductions could be cost-
effectively achieved. We considered establishing a venting pressure
limit of 1 psig or less, since four facilities reported in the ICR that
the typical coke drum pressure prior to depressurizing was 1 psig.
There are several technical difficulties associated with establishing a
pressure limit at this lower level. First, the lowest pressure at any
point in a closed blowdown system is generally designed to be no lower
than 0.5 psig. Consequently, the DCU compressor system would operate
with an inlet pressure of no less than 0.5 psig. Second, there are
several valves and significant piping (for cooling and condensing
steam) between the DCU drum and the recovery compressor. There is an
inherent pressure drop when a fluid flows through a pipe or valve. Two
valves are used for all DCU lines to make sure that the unit is either
blocked off from the processing fluids or blocked in so there are no
product losses out the steam line during processing. Considering the
need for two valves and piping needed in the cooling system, DCU
designed for a minimal pressure loss will generally still have a 0.5 to
1 psig pressure drop between the DCU drum and the recovery compressor
inlet, even for a new DCU designed to minimize this pressure drop.
Finally, in order to meet a 1 psig pressure limit at all times, the DCU
closed vent system would need to be designed to achieve a vessel
pressure of approximately 0.5 psig. Given the above considerations, it
is not technically feasible for new or existing DCU to routinely
achieve a vessel pressure of 0.5 psig in order to comply with a never-
to-be-exceeded drum vessel pressure of 1 psig. As noted previously,
facilities that ``typically'' achieve vessel pressures of about 1 psig
or less are expected to do so in order to meet a never-to-be-exceeded
drum vessel pressure limit of 2 psig and they are not expected to be
able to comply with a never-to-be-exceeded drum vessel pressure limit
of 1 psig.
    We considered setting additional work practice standards regarding
draining, deheading, and coke cutting. The decoking emissions can be
released from a variety of locations, and the 2-psig-or-less limit for
depressurizing the coke drum will effectively reduce the emissions from
all of these emission points, provided that atmospheric venting via the
DCU steam vent is the first step in the decoking process. However, it
is possible to start draining water prior to opening the steam vent. We
are concerned that owners or operators may adopt this practice as a
means to reduce pressure in the coke drum prior to venting the drum to
the atmosphere. Initiating water draining prior to reaching 2 psig
would result in draining water that is hotter than it would be had the
drum been sufficiently cooled (i.e., the pressure limit achieved) prior
to draining the vessel, effectively diverting HAP emissions to the
water drain area rather than capturing these HAP in the enclosed
blowdown system, where they can be either recovered or controlled.
Therefore, we are proposing that the coke drum must reach 2 psig or
less prior to any decoking operations, which includes atmospheric
venting, draining, deheading, and coke cutting.
    We could not identify any other emission reduction options that
could lower the emissions from the DCU decoking operations. Since we
could not identify a technically feasible control option beyond the
MACT floor, we determined that the MACT floor pressure limit of 2 psig
is MACT for existing sources. We also determined that the same
technical limitations of going beyond the 2 psig pressure limit for
existing sources exist for new sources; therefore we determined that
the MACT floor pressure limit of 2 psig is MACT for new sources. We
request comment on whether depressurizing to 2 psig prior to venting to
the atmosphere is the appropriate MACT floor and whether it is
appropriate to include restrictions for the other three decoking
operations draining, deheading and coke cutting, in the MACT
requirements. We request comments on whether we have adequately
interpreted the information that indicates that there is currently no
applicable MACT floor for delayed coking. If Refinery MACT 1 currently
provided standards for DCU based on the MACT floor, we would evaluate
whether it is necessary to revise such delayed coking standards under
the risk and technology review requirements of the Act (i.e., CAA
section 112(f) and 112(d)(6)) as discussed later in this preamble.
    Finally, we request comment and supporting information on any other
practices that may be used to limit emissions during the decoking
operations.
d. Evaluation of Cost and Environmental Impacts of MACT Emission
Limitations for Delayed Coking Units
    DCU that cannot currently meet the 2 psig pressure limit would be
expected to install a device (compressor or steam ejector system) to
lower the DCU vessel pressure. In the Refinery NSPS Ja impact analysis,
facilities not able to meet the pressure threshold were assumed to
purchase and install a larger compressor to lower the blowdown system
pressure. Other approaches to lowering blowdown system (and coke drum)
pressure exist. Specifically, steam ejectors have been identified as a
method to help existing units depressurize more fully in order to
achieve a set vessel pressure or drum bed temperature. Upgrading the
closed vent system to reduce pressure losses or to increase steam
condensing capacity may also allow the DCU to depressurize more quickly
while the emissions are still vented to the closed blowdown system.
This is important because delays in the decoking operations may impact
process feed rates. That is, if the decoking and drum preparation steps
take too long, the feed rate to the other coke unit must be reduced to
prevent overfilling one coke drum prior to being able to switch to the
other coke drum. This issue is less critical for DCU that operate with
3 or 4 drums per distillation column, but a consistent increase in the
decoking times across all

drums may still limit the capacity of the DCU at some petroleum
refineries.
    For existing sources, we assumed all DCU that reported a ``typical
drum pressure prior to venting'' of more than 2 psig would install and
operate a steam ejector system to reduce the coke drum pressure to 2
psig prior to venting to atmosphere or draining.
    The operating costs of the steam ejector system are offset, to some
extent, by the additional recovered vapors. Vapors from the additional
gases routed to the blowdown system contain high levels of methane
(approximately 70 percent by volume on a dry basis) based on DCU steam
vent test data. If these vapors are directed to the closed blowdown
system rather than to the atmosphere, generally the dry gas can be
recovered in the refinery fuel gas system or light-ends gas plant. This
recovered methane is expected to off-set natural gas purchases for the
fuel gas system.
    For new sources, it is anticipated that the DCU's closed vent
system could be designed to achieve a 2 psig vessel pressure with no
significant increase in capital or operating costs. Designing the
system to vent at a lower pressure would also result in additional
vapor recovery, which is expected to off-set any additional capital
costs associated with the low pressure design closed vent system.
    The costs of complying with the 2 psig coke drum threshold prior to
venting or draining are summarized in Table 2 of this preamble. The
costs are approximately $1,000 per ton of VOC reduced and approximately
$5,000 per ton of organic HAP reduced when considering VOC and methane
recovery credits. In addition to VOC and HAP reductions, the proposed
control option will result in a reduction in methane emissions of
18,000 tpy or 343,000 metric tonnes per year of carbon dioxide
equivalents (CO2e), assuming a global warming potential of
21 for methane.

               Table 2--Nationwide Emissions Reduction and Cost Impacts of Control Option for Delayed Coking Units at Petroleum Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Total
                                                                         Annualized                                            annualized   Overall cost
                                                                           costs                                               costs with  effectiveness
                                                             Capital      without     Emissions    Emissions        Cost          VOC         with VOC
                      Control option                           cost       recovery    reduction,   reduction,  effectiveness    recovery      recovery
                                                           (million $)    credits     VOC  (tpy)   HAP  (tpy)    ($/ton HAP)     credit     credit  ($/
                                                                        (million $/                                           (million $/     ton HAP)
                                                                            yr)                                                   yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2 psig...................................................           52         10.2        4,250          850        12,000          3.98         4,700
--------------------------------------------------------------------------------------------------------------------------------------------------------

2. CRU Vents
    A CRU is designed to reform (i.e., change the chemical structure
of) naphtha into higher-octane aromatics. Over time, coke deposits form
on the reforming catalyst, which reduces the catalyst activity. When
catalyst activity is reduced to a certain point, the catalyst is
regenerated by burning the coke off of the catalyst. Prior to this coke
burn-off process, the catalyst (or reactor vessel containing the
catalyst) must be removed from active service and organics remaining on
the catalyst (or in the reactor) must be purged from the system. This
is generally accomplished by depressurizing the vessel to a certain
vessel pressure, then re-pressurizing the vessel with nitrogen and
depressurizing the vessel again. The re-pressurization and
depressurization process is repeated several times until all organics
have been purged from the system. The organic HAP emissions from this
depressurization/purge cycle vent are typically controlled by directing
the purge gas directly to the CRU process heater or venting the gas to
a flare.
    Refinery MACT 2 requires a 98-percent reduction of organic HAP
measured as total organic carbon (TOC) or non-methane TOC or an outlet
concentration of 20 ppmv or less (dry basis, as hexane, corrected to 3-
percent oxygen), whichever is less stringent, for this CRU
depressurization/purge cycle vent (purging prior to coke-burn-off). The
emission limits for organic HAP for the CRU do not apply to emissions
from process vents during depressuring and purging operations when the
reactor vent pressure is 5 psig or less. The Refinery MACT 2
requirements were based on the typical operation of CRU utilizing
sequential pressurization and passive depressurization. The 5 psig
pressure limit exclusion was provided based on state permit conditions,
which recognized that depressurization to an APCD (without other active
motive of flow) is limited by the back pressure of the control system,
which is often a flare or process heater. Source testing information
collected from the 2011 Refinery ICR indicates that facilities have
interpreted the rule to allow the 5 psig pressure limit exclusion to be
used by units using active purging techniques (such as continuous
nitrogen purge or vacuum pump on the CRU reactor at low pressures) to
discharge to the atmosphere without emission controls. The information
collected indicates that HAP emissions from a continuous, active
purging technique could result in emissions of HAP from CRU
depressurization vents much higher than expected to be allowed under
the Refinery MACT 2 requirements, which presumed sequential re-
pressurization and purging cycles. The testing information received
indicated that at one facility, the active purge vent had non-methane
TOC concentrations of 700 to 10,000 ppmv (dry basis, as hexane,
corrected to 3-percent oxygen) compared to less than 10 ppmv for the
typical passive purge vent tested. The annual HAP emissions for the CRU
with the active purge vent were estimated to exceed 10 tpy, while a
comparable unit using the cyclic re-pressurization and passive
depressurization purge technique is projected to have HAP emissions of
less than 0.1 tpy.
    Therefore, we are proposing to amend the exclusion in 40 CFR
63.1566(a)(4) to clarify the application of the 5 psig exclusion,
consistent with the MACT floor under CAA section 112(d)(2) and (3).
Specifically, we are limiting the vessel pressure limit exclusion to
apply only to passive vessel depressurization. Units utilizing active
purging techniques have a motive of flow that can be used to direct the
purge gas to a control system, regardless of the CRU vessel pressure.
If a CRU owner or operator uses active purging techniques (e.g., a
continual nitrogen purge) or active vessel depressurization (e.g.,
vacuum pump), then the 98-percent reduction or 20 ppmv TOC emission
limits would apply to these discharges regardless of the vessel
pressure.
3. Refinery Flares
    The EPA is proposing under CAA section 112(d)(2) and (3) to amend
the operating and monitoring requirements for petroleum refinery
flares. We have determined that the current requirements for flares are
not adequate to ensure compliance with the Refinery MACT standards. In
the development of Refinery MACT 1, the EPA determined that the average
emission limitation achieved by the best-performing 12

percent of existing sources was established as the use of combustion
controls for miscellaneous process vents. Further, the EPA stated that
``data analyses conducted in developing previous NSPS and the [National
Emission Standards for Organic Hazardous Air Pollutants (40 CFR part
63, subparts F, G, and H)] HON determined that combustion controls can
achieve 98-percent organic HAP reduction or an outlet organic HAP
concentration of 20 ppmv for all vent streams'' (59 FR 36139, July 15,
1994). The requirements applicable to flares at refineries are set
forth in the General Provisions to 40 CFR part 63 and are cross-
referenced in Refinery MACT 1 and 2. In general, flares used as APCD
were expected to achieve 98-percent HAP destruction efficiencies when
designed and operated according to the requirements in the General
Provisions. Recent studies on flare performance, however, indicate that
these General Provisions requirements are inadequate to ensure proper
performance of refinery flares, particularly when assist steam or
assist air is used. Over the last decade, flare minimization efforts at
petroleum refineries have led to an increasing number of flares
operating at well below their design capacity, and while this effort
has resulted in reduced flaring of gases at refineries, situations of
over-assisting with steam or air have become exacerbated, leading to
the degradation of flare combustion efficiency. Therefore, these
amendments are necessary to ensure that refineries that use flares as
APCD meet the MACT standards at all times when controlling HAP
emissions.
    Refinery MACT 1 and 2 require flares used as an APCD to meet the
operational requirements set forth in the General Provisions at 40 CFR
63.11(b). These General Provisions requirements specify that flares
shall 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. The
General Provisions also specify requirements for both the minimum heat
content of gas combusted in the flare and maximum exit velocity at the
flare tip. The General Provisions only specify monitoring requirements
for the presence of the pilot flame and the operation of a flare with
no visible emissions. For all other operating limits, Refinery MACT 1
and 2 require an initial performance evaluation to demonstrate
compliance but there are no specific monitoring requirements to ensure
continuous compliance. As noted previously, flare performance tests
conducted over the past few years suggest that the current regulatory
requirements are insufficient to ensure that refinery flares are
operating consistently with the 98-percent HAP destruction efficiencies
that we determined were the MACT floor.
    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 (see technical report,
Parameters for Properly Designed and Operated Flares, in Docket ID
Number EPA-HQ-OAR-2010-0682). The EPA submitted the report, along with
a charge statement and a set of charge questions to an external peer
review panel.\27\ The panel concurred with the EPA's assessment that
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.
---------------------------------------------------------------------------

    \27\ These documents can also be found at http://www.epa.gov/ttn/atw/petref.html.
---------------------------------------------------------------------------

    Following is a discussion of requirements we are proposing for
refinery flares, along with impacts and costs associated with these new
requirements. Specifically, this action proposes that refinery flares
operate pilot flame systems continuously and with automatic re-ignition
systems and that refinery flares operate with no visible emissions. In
addition, this action also consolidates requirements related to flare
tip velocity and proposes new operational and monitoring requirements
related to the combustion zone gas. Prior to these proposed amendments,
Refinery MACT 1 and 2 cross-reference the General Provisions
requirements at 40 CFR 63.11(b) for the operational requirements for
flares used as APCD. Rather than revising the General Provisions
requirements for flares, which would impact dozens of different source
categories, this proposal will specify all refinery flare operational
and monitoring requirements specifically in Refinery MACT 1 and cross-
reference these same requirements in Refinery MACT 2. All of the
requirements for flares operating at petroleum refineries in this
proposed rulemaking are intended to ensure compliance with the Refinery
MACT 1 and 2 standards when using a flare as an APCD.
a. Pilot Flames
    Refinery MACT 1 and 2 reference the flare requirements in the
General Provisions, which require a flare used as an APCD device to
operate with a pilot flame present at all times. Pilot flames are
proven to improve flare flame stability; even short durations of an
extinguished pilot could cause a significant reduction in flare
destruction efficiency. In this action, we are proposing to remove the
cross-reference to the General Provisions and instead include the
requirement that flares operate with a pilot flame at all times and be
continuously monitored for using a thermocouple or any other equivalent
device in Refinery MACT 1 and 2. We are also proposing to amend
Refinery MACT 1 and 2 to add a new operational requirement to use
automatic relight systems for all flare pilot flames. An automatic
relight system provides a quicker response time to relighting a
snuffed-out flare compared to manual methods and thereby results in
improved flare flame stability. In comparison, manual relighting is
much more likely to result in a longer period where the pilot remains
unlit. Because of safety issues with manual relighting, we anticipate
that nearly all refinery flares are already equipped with an automated
device to relight the pilot flame in the event it is extinguished.
Also, due to the possibility that a delay in relighting the pilot could
result in a flare not meeting the 98-percent destruction efficiency for
the period when the pilot flame is out, we are proposing to amend
Refinery MACT 1 and 2 to add this requirement to ensure that the pilot
operates at all times.
b. Visible Emissions
    Refinery MACT 1 and 2 reference the flare requirements in the
General Provisions, which require a flare used as an APCD to 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 EPA Method 22 of
40 CFR part 60, Appendix A-7. We are proposing to remove the cross-
reference to the General Provisions and include the limitation on
visible emissions in Refinery MACT 1 and 2. In addition, we are
proposing to amend Refinery MACT 1 and 2 to add a requirement that a
visible emissions test be conducted each day and whenever visible
emissions are observed from the flare. We are proposing that owners or

operators of flares monitor visible emissions at a minimum of once per
day using an observation period of 5 minutes and EPA Method 22 of 40
CFR part 60, Appendix A-7. Additionally, any time there are visual
emissions from the flare, we are proposing that another 5-minute
visible emissions observation period be performed using EPA Method 22
of 40 CFR part 60, Appendix A-7, even if the minimum required daily
visible emission monitoring has already been performed. For example, if
an employee observes visual emissions or receives notification of such
by the community, the owner or operator of the flare would be required
to perform a 5-minute EPA Method 22 observation in order to check for
compliance upon initial observation or notification of such event. We
are also proposing that if visible emissions are observed for greater
than one continuous minute during any of the required 5-minute
observation periods, the monitoring period shall be extended to 2
hours.
    Industry representatives have suggested to the EPA that flare
combustion efficiency is highest at the incipient smoke point (the
point at which black smoke begins to form within the flame). They
stated that the existing limit for visible emissions could be increased
from 5 minutes to 10 minutes in a 2-hour period to encourage operation
near the incipient smoke point (see memorandum, Meeting Minutes for
February 19, 2013, Meeting Between the U.S. EPA and Representatives
from the Petroleum Refining Industry, in Docket ID Number EPA-HQ-OAR-
2010-0682). While we agree that operating near the incipient smoke
point results in good combustion at the flare tip, we disagree that the
allowable period for visible emissions be increased from 5 to 10
minutes for a 2-hour period. Smoking flares can contribute
significantly to emissions of particulate matter 2.5 micrometers in
diameter and smaller (PM2.5) emissions, and we are concerned
that increasing the allowable period of visible emissions from 5
minutes to 10 minutes for every 2-hour period could result in an
increase in the PM2.5 emissions from flares.
    As discussed later in this section, we are proposing additional
operational and monitoring requirements for refinery flares which we
expect will result in refineries 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 refinery
flare owners or operators operating 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 these
proposed operating limits, discussed in section IV.A.3.d of this
preamble. As seen in the performance curves for flares (see technical
memorandum, Petroleum Refinery Sector Rule: Operating Limits for
Flares, in Docket ID Number EPA-HQ-OAR-2010-0682), there is very
limited improvement in flare performance beyond the performance
achieved at these proposed operating limits. We solicit comments and
data on appropriate periods of visible emissions that would encourage
operation at the incipient smoke point while not significantly
increasing PM2.5 emissions.
c. Flare Tip Velocity
    The General Provisions at 40 CFR 63.11(b) 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. These
maximum flare tip velocities are required to ensure that the flame does
not ``lift off'' the flare, 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 and consolidate the requirements for maximum
flare tip velocity into Refinery MACT 1 and 2 as a single equation,
irrespective of flare type (i.e., steam-assisted, air-assisted or non-
assisted). Based on our analysis of the various studies for air-
assisted flares, we identified air-assisted test runs with high flare
tip velocities that had high combustion efficiencies (see technical
memorandum, Petroleum Refinery Sector Rule: Evaluation of Flare Tip
Velocity Requirements, in Docket ID Number EPA-HQ-OAR-2010-0682). 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, the air-assisted flares appeared to have the
same operating envelope as the non-assisted and steam-assisted flares.
Therefore, we are proposing that air-assisted flares at refineries use
the same equation that non-assisted and steam-assisted flares currently
use to establish the flare tip velocity operating limit.
    In developing these proposed flare tip velocity requirements, we
considered whether any adjustments to these velocity equations were
necessary. The flare tip velocity equations require the input of the
net heating value of the vent gas going to the flare, as opposed to the
net heating value of the gas mixture at the flare tip (i.e., the
combustion zone gas). As discussed later in this section, we found that
the performance of the flare was much more dependent on the net heating
value of the gas mixture in the combustion zone than on the net heating
value of only the vent gas going into the flare (excluding all assist
media). We considered replacing the term in the velocity equation for
the net heating value of the vent gas going into the flare with the net
heating value of the gas mixture in the combustion zone. However, the
steam addition rates were not reported for the tests conducted to
evaluate flame stability as a function of flare tip velocity, so direct
calculation of all the terms needed for calculating the net heating
value in the combustion zone could not be made. At higher flare tip
velocities, we expect that the steam assist rates would be small in
comparison to the total vent gas flow rate, so there would not be a
significant difference between the net heating value of the vent gas
going into the flare and the combustion zone gas net heating value for
the higher velocity flame stability tests. We request comment on the
need and/or scientific reasons to use the flare vent gas net heating
value versus the combustion zone net heating value when determining the
maximum allowable flare tip velocity.
    In the 2012 flare peer review, we also discussed the effect of
flame lift off and velocity on flare flame stability (see technical
report, Parameters for Properly Designed and Operated Flares, in Docket
ID Number EPA-HQ-OAR-2010-0682). In looking at ways of trying to
prohibit flame instability, we examined the use of the Shore equation
as a means to limit flare tip velocity. However, after receiving many
comments on use of this equation from the peer reviewers, the
uncertainty with how well the Shore equation models the large range of
flare operation, and the limited dataset with which recent testing used
high velocities (all recent test runs were performed at 10 feet per
second or less), we determined that use of the existing velocity
equation discussed above was still warranted.
    We are also proposing for Refinery MACT 1 and 2 to not include the
special flare tip velocity equation in the General Provisions at 40 CFR
63.11(b)(6)(i)(A) for non-assisted flares with hydrogen content greater
than 8 percent. This equation, which was developed based on limited
data from a chemicals manufacturer, has very limited

applicability for petroleum refinery flares in that it only provides an
alternative for non-assisted flares with large quantities of hydrogen.
Approximately 90 percent of all refinery flares are either steam- or
air-assisted. Furthermore, we are proposing compliance alternatives in
this section that we believe provide a better way for flares at
petroleum refineries with high hydrogen content to comply with the rule
while ensuring proper destruction performance of the flare (see section
IV.A.3.d of this preamble for additional details). Therefore, we are
proposing to not include this special flare tip velocity equation as a
compliance alternative for refinery flares. We request comment on the
need to include this equation. If a commenter supports inclusion of
this equation, we request that the commenter submit supporting
documentation regarding the vent gas composition and flows and, if
available, combustion efficiency determinations that indicate that this
additional equation is needed and is appropriate for refinery flares.
We also request documentation that the maximum allowable flare tip
velocity predicted by this equation adequately ensures proper
combustion efficiency.
    The General Provisions require an initial demonstration that a
flare used as an APCD meets the applicable flare tip velocity
requirement in 40 CFR 63.11(b). However, most refinery flares can have
highly variable vent gas flows and a single initial demonstration is
insufficient to demonstrate continuous compliance with the flare tip
velocity requirement. Consequently, we are proposing to amend Refinery
MACT 1 and 2 to require continuous monitoring to determine flare tip
velocity, calculated by monitoring the flare vent gas volumetric flow
rate and dividing by the cross-sectional area of the flare tip. As an
alternative to installing continuous volumetric flow rate monitors, we
are proposing that the owner or operator may elect to install a
pressure- and temperature-monitoring system and use engineering
calculations to determine the flare tip velocity.
d. Refinery Flare Operating and Monitoring Requirements
    The current requirements for flares in the General Provisions
specify that the flare vent gas must 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.
Refinery MACT 1 and 2 reference these requirements, but neither the
General Provisions nor Refinery MACT 1 and 2 include specific
monitoring requirements to monitor the net heating value of the vent
gas. Moreover, recent flare testing results indicate that this
parameter alone does not adequately address instances when the flare
may be over-assisted since it only considers 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 actually snuff out a flame and allow
regulated material to be released into the atmosphere completely
uncombusted. Since approximately 90 percent of all flares at refineries
are either steam- or air-assisted, it is critical that we ensure the
assist media be accounted for in some form or fashion. Recent flare
test data have shown that the best way to account for situations of
over-assisting is to consider the properties of the mixture of all
gases 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.
    We are proposing to add definitions of two key terms relevant to
refinery flare performance. First, we are proposing to define ``flare
vent gas'' to include all waste gas, sweep gas, purge gas and
supplemental gas, but not include pilot gas or assist media. We are
proposing this definition because information about ``flare vent gas''
(e.g., flow rate and composition) is one of the necessary inputs needed
to evaluate the make-up of the combustion zone gas. To that end, we are
also proposing to define the ``combustion zone gas'' as flare vent gas
plus the total steam-assist media and premix assist air that is
supplied to the flare.
    Based on our review of the recent flare test data, we have
determined that the following combustion zone operational limits can be
used to determine good combustion: Net heating value (Btu/scf), lower
flammability limit (LFL) or a total combustibles fraction (e.g., a
simple carbon count). In this action, we are proposing these new
operational limits, along with methods for determining these limits in
the combustion zone at the flare tip for steam-assisted, air-assisted
and non-assisted flares to ensure that there is enough combustible
material readily available to achieve good combustion.
    For air-assisted flares, use of too much perimeter assist air can
lead to poor flare performance. Based on our analysis, we found that
including the flow rate of perimeter assist air in the calculation of
combustion zone operational limits in itself does not identify all
instances of excess aeration. The data suggest that the diameter of the
flare tip, in concert with the amount of perimeter assist air, provides
the inputs necessary to calculate whether or not this type of flare is
over-assisted. Therefore, we are proposing that in addition to
complying with combustion zone operational limits to ensure that there
is enough combustible material available to adequately combust the gas
and pass through the flammability region, air-assisted flares would
also comply with an additional dilution parameter that factors in the
flow rate of the flare vent gas, flow rates of all assist media
(including perimeter assist air), and diameter of flare tip to ensure
that degradation of flare performance from excess aeration does not
occur. 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 better it will combust. Also, since both the volume
of the combustion zone (represented by the diameter here) 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 makes sense that we propose such a term (see technical
memorandum, Petroleum Refinery Sector Rule: Operating Limits for
Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
    It should be noted that in the 2012 flare peer review report, we
considered a limit for perimeter assist air via the stoichiometric air
ratio. This stoichiometric air ratio is the ratio of the actual mass
flow rate of assist air to the theoretical stoichiometric mass flow
rate of air (based on complete chemical combustion of fuel to carbon
dioxide (CO2) and water) needed to combust the flare vent
gas. However, we are not proposing to include this term as part of the
calculation methodology, as we have determined that the dilution
parameter discussed in this section better assures that air-assisted
flare performance is not degraded due to excess aeration.

    The proposed rule allows the owner or operator flexibility to
select the form of the combustion zone operational limit (i.e., net
heating value, LFL, or total combustibles fraction) with which to
comply in order to provide facilities the option of using monitors they
may already have in place. The monitoring methods we are proposing take
into account the combustible properties of all gas going to the flare
(i.e., flare vent gas, assist gas, and premix air) that affects
combustion efficiency, and they can be used to determine whether a
flare has enough combustible material to achieve the desired level of
control (and whether it is being over-assisted). These methods require
the owner or operator to input the flow of the vent gas to the flare,
the characteristics of the vent gas going to the flare (i.e., either a
heat content (Btu/scf), LFL, or total combustible fuel content,
depending on how the operational limit is expressed), and the flow of
assist media added to the flare.
    To estimate the LFL, we are proposing to use a calculation method
based on the Le Chatelier equation. The Le Chatelier calculation uses
the reciprocal of the volume-weighted average over the LFL of the
individual compounds in the gas mixture to estimate the LFL of the gas
mixture. Although Le Chatelier's equation was originally limited to
binary mixtures of combustible gases, we are proposing a method that
was developed by Karim, et al. (1985) and assumes a LFL of infinity for
inert gases. We are also aware of other methods and/or adjustments that
can be made to the Le Chatelier equation in order to calculate a more
accurate estimate of the LFL of a gas mixture (see technical
memorandum, Parameters for Properly Designed and Operated Flares, in
Docket ID Number EPA-HQ-OAR-2010-0682). We are soliciting comment on
the use of this proposed method.
    Recent data indicate that one set of operational limits may not be
sufficient for all refinery flares. Flares that receive vent gas
containing significant levels of both hydrogen and olefins often
exhibit lower combustion efficiencies than flares that receive vent gas
with only one (or none) of these compounds. Therefore, we are proposing
more stringent operational limits for flares that simultaneously
receive vent gas containing significant levels of both hydrogen and
olefins (see technical memorandum, Petroleum Refinery Sector Rule:
Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
Although the minimum net heating value in the combustion zone (i.e.,
Btu/scf) is a good indicator of combustion efficiency, as noted in the
flare peer review report, the LFL and combustibles concentration (or
total combustibles) in the combustion zone are also good indicators of
flare combustion efficiency. For some gas mixtures, such as gases with
high hydrogen content, the LFL or combustibles concentration in the
combustion zone may be better indicators of performance than net
heating value. Consequently, we are proposing operational limits
expressed all three ways, along with associated monitoring requirements
discussed later in this section.
    The three operating limits were established in such a way that each
limit is protective on its own. As such, the owner or operator may
elect to comply with any of the three alternative operating limits at
any time, provided they use a monitoring system capable of determining
compliance with each of the proposed alternative operating limits on
which they rely (see technical memorandum, Petroleum Refinery Sector
Rule: Operating Limits for Flares, in Docket ID Number EPA-HQ-OAR-2010-
0682). For example, the owner or operator may elect to install
monitoring for only one of the three alternative operating limits, in
which case the owner or operator must comply with that selected
operating limit at all times. If the owner or operator installs a
system capable of monitoring for all three of the alternative operating
limits, the owner or operator can choose which of the three operating
limits the source will rely on to demonstrate compliance.
    A summary of the operating limits specified in this proposed rule
is provided in Table 3 of this preamble. We are proposing that owners
or operators of flares used as APCD would conduct an initial
performance test to determine the values of the parameters to be
monitored (e.g., the flow rate and heat content of the incoming flare
vent gas, the assist media flow rate, and pre-mix air flow rate, if
applicable) in order to demonstrate continuous compliance with the
operational limits in Table 3. We are proposing to require owners or
operators to 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 IV.A.3.e of this preamble.

      Table 3--Operating Limits for Flares in This Proposed Action
------------------------------------------------------------------------
                                Operating limits:     Operating limits:
                                 Flares without          Flares with
   Operating parameter \a\       hydrogen-olefin       hydrogen-olefin
                                 interaction \b\       interaction \b\
------------------------------------------------------------------------
                Combustion zone parameters for all flares
------------------------------------------------------------------------
NHVcz.......................  >=270 Btu/scf.......  >=380 Btu/scf.
LFLcz.......................  <=0.15 volume         <=0.11 volume
                               fraction.             fraction.
Ccz.........................  >=0.18 volume         >=0.23 volume
                               fraction.             fraction.
------------------------------------------------------------------------
        Dilution parameters for flares using perimeter assist air
------------------------------------------------------------------------
NHVdil......................  >=22 Btu/ft\2\......  >=32 Btu/ft\2\.
LFLdil......................  <=2.2 volume          <=1.6 volume
                               fraction/ft.          fraction/ft.
Cdil........................  >=0.012 volume        >=0.015 volume
                               fraction-ft.          fraction-ft.
------------------------------------------------------------------------
\a\ The operating parameters are:
NHVcz = combustion zone net heating value.
LFLcz = combustion zone lower flammability limit.
Ccz = combustion zone combustibles concentration.
NHVdil = net heating value dilution parameter.
LFLdil = lower flammability limit dilution parameter.
Cdil = combustibles concentration dilution parameter.
\b\ Hydrogen-Olefin interactions are assumed to be present when the
  concentration of hydrogen and olefins in the combustion zone exceed
  all three of the following criteria:
(1) The concentration of hydrogen in the combustion zone is greater than
  1.2 percent by volume.
(2) The cumulative concentration of olefins in the combustion zone is
  greater than 2.5 percent by volume.

(3) The cumulative concentration of olefins in the combustion zone plus
  the concentration of hydrogen in the combustion zone is greater than
  7.4 percent by volume.
Btu/ft\2\ = British thermal units per square foot.

    We are soliciting comment on the appropriateness of the operating
limits and dilution parameters in Table 3 of this preamble and whether
they ensure that refinery flares operate in a manner that that will
ensure compliance with the MACT requirements for vents to achieve a 98-
percent organic HAP reduction.
    Combustion zone gas monitoring alternatives. As discussed
previously in this section, we are proposing to define the combustion
zone gas as the mixture of gas at the flare tip consisting of the flare
vent gas, the total steam-assist media and premix assist air. In order
to demonstrate compliance with the three combustion zone parameter
operating limits of net heating value, LFL and total combustibles
fraction, the owner or operator would need to monitor four things: (1)
Flow rate of the flare vent gas; (2) flow rate of total steam assist
media; (3) flow rate of premix assist air and (4) specific
characteristics associated with the flare vent gas (e.g., heat content,
composition). In order to monitor the flow rates of the flare vent gas,
total steam assist media, and premix assist air, we are proposing that
refinery owners or operators use a continuous volumetric flow rate
monitoring system or a pressure- and temperature-monitoring system with
use of engineering calculations. We are also proposing use of either of
these monitoring methods for purposes of determining the flow rate of
perimeter assist air (for compliance with the dilution parameter).
However, the one component that will determine how many combustion zone
parameter operating limits an owner or operator can comply with is the
specific type of monitor used to characterize the flare vent gas.
    Monitoring the individual component concentrations of the flare
vent gas using an on-line gas chromatograph (GC) along with monitoring
vent gas and assist gas flow rates will allow the owner or operator to
determine compliance with any of the three proposed combustion zone
operating limits and any of the three proposed dilution operating
limits (if using air-assisted flares). We considered requiring all
refinery owners or operators of flares to only use a GC to monitor the
flare vent gas composition but since facilities may have other non-GC
monitors already in place (e.g., calorimeters), we are not proposing
such a requirement at this time. However, use of a GC can improve
refinery flare operation and management of resources. For example, use
of a GC to characterize the flare vent gas can lead to product/cost
savings for refiners because they could more readily identify and
correct instances of product being unintentionally sent to a flare,
either through a leaking pressure relief valve or other conveyance that
is ultimately routed to the flare header system. In addition, an owner
or operator that chooses to use a GC (in lieu of one of the other
proposed monitoring alternatives) will be more likely to benefit from
the ability to continuously fine-tune their operations (by reducing
assist gas addition and/or supplemental gas to the flare) in order to
meet any one of the three operating limits. Furthermore, some
facilities are already required to use a GC to demonstrate compliance
with state flare requirements. We are soliciting comment on the
additional benefits that using a GC offers and whether it would be
reasonable to require a GC on all refinery flares.
    As an alternative to a continuous compositional monitoring system,
we are proposing to allow the use of grab samples along with
engineering calculations to determine the individual component
concentration. Like the on-line GC, the grab sampling option relies on
compound speciation and is therefore flexible to use with any form of
the operational limits we are proposing. The disadvantage of this
option is that if a grab sample indicates non-compliance with the
operational limits, the permitting authority could presume non-
compliance from the time of the previous grab sample indicating
compliance, which would include all 15-minute periods in that time
period. However, there are a number of situations where the refinery
owner or operator may find this option advantageous. For example, some
flares receive flows only from a specific process with a consistent
composition and high heat content. In this case, the owner or operator
may elect to actively adjust the assist gas flow rates using the
expected vent gas composition and rely on the analysis of the grab
sample to confirm the expected vent gas composition. This alternative
may also be preferred for flares that are used infrequently (non-
routine flow flares) or that have flare gas recovery systems designed
and operated to recover 100 percent of the flare gas under typical
conditions. For these flares, flaring events may be so seldom that the
refinery owner or operator may prefer the uncertainty in proactive
control to the higher cost of continuous monitors that would seldom be
used.
    As an alternative to performing a compositional analysis with use
of a GC (through either on-line monitoring or analysis of the grab
sample), we are proposing that owners or operators of flares may elect
to install a device that directly monitors vent gas net heating value
(i.e., a calorimeter). If the owner or operator elects this monitoring
method, we are proposing that they must comply with the operating
limits that are based on the net heating value operating limit.
Similarly, we are also proposing that owners or operators of flares may
elect to install a device that directly monitors the total hydrocarbon
content of the flare vent gas (as a measure of the combustibles
concentration). If the owner or operator elects this monitoring method,
they must comply with the operating limits that are based on the
combustibles concentration.
e. Data Averaging Periods for Flare Gas Operating Limits
    We are proposing to use a 15-minute block averaging period for each
proposed flare operating parameter (including flare tip velocity) to
ensure that the flare is operated within the appropriate operating
conditions. As flare vent gas flow rates and composition can change
significantly over short periods of time, a short averaging time was
considered to be the most appropriate for assessing proper flare
performance. Furthermore, since flare destruction efficiencies can fall
precipitously fast below the proposed operating limits, short time
periods where the operating limits are not met could seriously impact
the overall performance of the flare. With longer averaging times,
there may be too much opportunity to mask these short periods of poor
performance (i.e., to achieve the longer-term average operating limit
while not achieving a high destruction efficiency over that time period
because of short periods of poor performance).
    Moreover, a 15-minute averaging period is in line with the test
data and the analysis used to establish the operating limits in this
proposed rule. Ninety-three percent of the flare test runs used as a
basis for establishing the proposed operating limits ranged in duration
from 5 to 30 minutes, and 77

percent of the runs ranged in duration from 5 to 20 minutes. The
failure analysis (discussed in section IV.A.3.f of this preamble)
considered minute-by-minute test run data, but as there are limitations
on how quickly compositional analyses can be conducted, many of the
compositional data still reflect set values over 10- to 15-minute time
intervals. Because the GC compositional analyses generally require 10
to 15 minutes to conduct, shorter averaging times are not practical. To
be consistent with the available test data and to ensure there are no
short periods of significantly poor performance, we are proposing 15-
minute block averaging times.
    Given the short averaging times for the operating limits, we are
proposing special calculation methodologies to enable refinery owners
or operators to use ``feed forward'' calculations to ensure compliance
with the operating limits on a 15-minute block average. Specifically,
the results of the compositional analysis determined just prior to a
15-minute block period are to be used for the next 15-minute block
average. Owners or operators of 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.
    Owners or operators of flares that elect to use grab sampling and
engineering calculations to determine compliance must still assess
compliance on a 15-minute block average. The composition of each grab
sample is to be used for the duration of the episode or until the next
grab sample is taken. We are soliciting comment on whether this
approach is appropriate, and whether grab samples are needed on a more
frequent basis to ensure compliance with the operating limits.
f. Other Peer Review Considerations
    In an effort to better inform the proposed new requirements for
refinery flares, in the spring of 2012 the EPA summarized its
preliminary findings on operating parameters that affect flare
combustion efficiency in a technical report and put this report out for
a letter review. Based on the feedback received, the EPA considered
many of the concerns peer reviewers expressed in their comments in the
development of this proposal for refinery flares (see memorandum, Peer
Review of ``Parameters for Properly Designed and Operated Flares'', in
Docket ID Number EPA-HQ-OAR-2010-0682). While the more substantive
issues have been previously discussed in sections IV.A.3.a through e of
this preamble, the following discussion addresses other peer review
considerations that the EPA either discussed in the peer review
technical document or considered from comments received by the peer
review panel that played a role in the development of this proposal.
    Test data quality and analysis. For steam-assisted flares, we asked
peer reviewers to comment on our criteria for excluding available flare
test data from our analyses. In general, peer reviewers considered the
EPA's reasons for removing certain test data (prior to performing any
final analysis) to be appropriate; however, one reviewer suggested the
EPA complete an analysis of quality on the data before applying any
criteria, and several reviewers commented on the level of scrutiny of
the 10 data points specifically discussed in the technical report for
not meeting the combustion zone LFL trend. These reviewers stated it
appeared the EPA had scrutinized test data more if it were inconsistent
with the LFL threshold conclusions made in the report. Although we felt
it was appropriate to discuss specific test data not fitting the trend,
we do agree with the reviewers that a more general and standard set of
criteria should be applied to all test data prior to making any
conclusion. In addition, other peer reviewers saw no reason why the EPA
should exclude 0-percent combustion efficiency data points, or data
points where smoking occurs, or single test runs when there was also a
comparable average test run. Therefore, in response to these peer
review comments, the EPA performed a validation and usability analysis
on all available test data. This resulted in a change to the population
of test data used in our final analysis (see technical memorandum,
Flare Performance Data: Summary of Peer Review Comments and Additional
Data Analysis for Steam-Assisted Flares, in Docket ID Number EPA-HQ-
OAR-2010-0682 for a more detailed discussion of the data quality and
analysis).
    To help determine appropriate operating limits, several peer
reviewers suggested the EPA perform a false-positive-to-false-negative
comparison (or failure type) analysis between the potential parameters
discussed in the technical report as indicators of flare performance.
The reviewers suggested that the EPA attempt to minimize the standard
error of all false positives (i.e., poor observed combustion efficiency
when the correlation would predict good combustion) and false negatives
(i.e., good observed combustion efficiency when the correlation would
predict poor combustion). In response to these comments, the EPA has
conducted a failure analyses of these parameters which helped form the
basis for the operating limits we are proposing for flares (see
technical memorandum, Petroleum Refinery Sector Rule: Operating Limits
for Flares, in Docket ID Number EPA-HQ-OAR-2010-0682).
    Some peer reviewers contended that it is appropriate for the EPA to
round each established operating limit to the nearest whole number,
because using a decimal implies far more accuracy and reliability than
can be determined from the test data. Based on these comments, we have
given more consideration to the number of significant figures used in
the operating limits, and we are proposing to use two significant
figures for the flare operating limits in these proposed amendments.
    Multiple peer reviewers performed additional analyses to try and
determine the appropriateness of the limits raised in the technical
report. Some peer reviewers tried to fit the data to a curve, others
performed various failure analyses, while others looked at different
metrics not discussed in the technical report (see memorandum, Peer
Review of ``Parameters for Properly Designed and Operated Flares'', in
Docket ID Number EPA-HQ-OAR-2010-0682). Based on the conclusions drawn
from these various analyses, a range of combustion zone net heating
value targets from 200 Btu/scf to 450 Btu/scf were identified as
metrics that would provide a high level of certainty regarding good
combustion in flares (Note: 450 Btu/scf was the assumed to be
approximately equivalent to a combustion zone LFL of 10 percent). We
solicit comment on this range and the appropriateness for which the
operating limits selected in this proposal will ensure compliance with
the MACT requirements for vents at petroleum refineries.
    Effect of supplemental gas use. Most flares normally operate at a
high turndown ratio, which means the actual flare gas flow rate is much
lower than what the flare is designed to handle. In addition, steam-
assisted flares have a manufacturers' minimum steam requirement in
order to protect the flare tip. A combination of high turndown ratio
and minimum steam requirement will likely require some owners or
operators to add supplemental gas to achieve one of the combustion zone
gas operating limits we are proposing here (e.g., combustion zone
combustibles concentration (Ccz) >= 18 volume percent;
combustion zone lower flammability limit (LFLcz) <= 15
volume percent; or combustion zone net heating value (NHVcz)
>= 270 Btu/scf). However, fine-

tuning the actual steam flow to the flare should significantly reduce
the need for supplemental gas. We considered proposing a steam-to-vent
gas ratio limitation on steam-assisted flares. However, a steam-to-vent
gas ratio alone cannot fully address over-steaming because it would not
account for the variability of chemical properties within the flare
gas. We request that commenters on this issue provide supporting
documentation on their potential to reduce steam as well as their use
of supplemental gas to achieve the proposed operating limit(s), and how
it could affect cost and potential emissions. We emphasize that the
amount and cost of supplemental gas should be reflective of conditions
after any excess steam use has been rectified. It would not be valuable
to consider situations where large amounts of supplemental gas are
added, while steam is simultaneously added far in excess of the amount
recommended by the flare manufacturer or other guidance documents.
    In assessing the combustion zone gas and looking at all the gas at
the flare tip, another potential source of added heat content comes
from the gas being used as fuel to maintain a continuously lit pilot
flame. However, since pilot gas is being used as fuel for a continuous
ignition source and is burned to create a flame prior to (or at the
periphery of) the combustion zone, this gas does not directly
contribute to the heat content or flammability of the gas being sent to
the flare to be controlled under Refinery MACT 1 or 2. In addition, in
looking at available test data, the pilot gas flow rate is generally so
small that it does not significantly impact the combustion zone
properties at all. Furthermore, by leaving pilot gas out of the
combustion zone operating limit calculations, the equations become
simplified and a requirement to continuously monitor pilot gas flow
rate can be avoided. Therefore, we are proposing that the owner or
operator not factor in the pilot gas combustible component (or net
heating value) contribution when determining any of the three proposed
combustion zone gas operating limits (Ccz, LFLcz,
or NHVcz).
    Effects of wind on flame performance. Several published studies
have investigated the significance of wind on the fluid mechanics of a
flare flame (see technical memorandum, Parameters for Properly Designed
and Operated Flares, in Docket ID Number EPA-HQ-OAR-2010-0682). These
studies were conducted in wind tunnels at crosswind velocities up to
about 60 miles per hour (mph) and have illustrated that increased
crosswind velocity can have a strong effect on flare flame dimensions
and shape, causing the flame to become segmented or discontinuous, and
wake-dominated (i.e., where the flame is bent over on the downwind side
of a flare pipe and is imbedded in the wake of the flare tip), which
may lead to poor flare performance due to fuel stripping. However, the
majority of this research is confined to laboratory studies on flares
with effective diameters less than 3 inches, which have been shown not
to be representative of industrial-sized flares. Research that does
include performance tests conducted on flares scalable to refinery
flares (i.e., 3-inch, 4-inch, and 6-inch pipe flares) was conducted
with flare tip velocities as low as 0.49 feet per second and crosswind
velocities of about 26 mph and less; all tests resulted in good flare
performance. Furthermore, there is no indication that crosswind
velocities negatively impact flare performance in the recent flare
performance tests. These tests were conducted on various sizes of
industrial flares (i.e., effective diameters ranging between 12 and 54
inches) in winds of about 22 mph and less, and at relatively low flare
tip velocities (i.e., 10 feet per second or less). (See Parameters for
Properly Designed and Operated Flares, in Docket ID Number EPA-HQ-OAR-
2010-0682.)
    We are aware of flare operating parameters that consider crosswind
velocity; however, using the available flare performance test data, we
were unable to determine a clear correlation that would be appropriate
for all refinery flares. For example, the momentum flux ratio (MFR) is
a measure of momentum strength of the flare exit gas relative to the
crosswind (i.e., the product of flare exit gas density and velocity
squared divided by the product of air density and crosswind velocity
squared). The plume buoyancy factor is the ratio of crosswind velocity
to the flare exit gas velocity, and considers the area of the flare
pipe. The power factor is the ratio of the power of the crosswind to
the power of combustion of the flare gas. Because the available flare
performance test data have relatively low flare tip velocities, and
crosswind velocities were relatively constant during each test run, we
are unable to examine these parameters to the fullest extent.
    In light of the data available from performance tests (Gogolek et
al., 2010), we asked peer reviewers whether the MFR could be used in
crosswind velocities greater than 22 mph at the flare tip to indicate
wake-dominated flame situations. We also asked for comment on
observations that in the absence of crosswind greater than 22 mph, a
low MFR does not necessarily indicate poor flare performance. Peer
reviewers suggested that there are no data available from real
industrial flares in winds greater than 22 mph to support that MFR
could be used to identify wake-dominated flame situations. In addition,
we received no further peer review comments that have caused us to
reconsider the observation we made in the April 2012 technical report
that in the absence of crosswind greater than 22 mph, a low MFR does
not necessarily indicate poor flare performance. We request comment
with supporting data and rationale on any of these, or other
parameters, as a measure of wind effects on flare combustion
efficiency.
    We considered including observation requirements for detecting
segmented or discontinuous wake-dominated flames, especially for winds
greater than 22 mph (where limited test data is available). However,
owners or operators of flares cannot control the wind speed, and it
would be detrimental to increase the quantity of flared gases in high
crosswind conditions in efforts to improve the MFR and reduce wake-
dominated flow conditions. Furthermore, there is no indication that
crosswind velocities negatively impact flare performance in the recent
flare performance tests. For these reasons, we are not proposing any
flare operating parameter(s) to minimize wind effects on flare
combustion efficiency.
g. Impacts of the Flare Operating and Monitoring Requirements
    The EPA expects that the newly proposed requirements for refinery
flares discussed in this section will affect all flares at petroleum
refineries. Based on data received as a result of the Refinery ICR, we
estimate that there are 510 flares operating at petroleum refineries
and that 285 of these receive flare vent gas flow on a regular basis
(i.e., other than during periods of startup, shutdown, and
malfunction). Costs were estimated for each flare for a given refinery,
considering operational type (e.g., receive flare vent gas flow on a
regular basis, use flare gas recovery systems to recover 100 percent of
routine flare flow, handle events during startup, shutdown, or
malfunction only, etc.) and current monitoring systems already
installed on each individual flare. 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 4 of this preamble. We note that the requirements for refinery
flares we are proposing in this action will ensure compliance with the
Refinery MACT standards when flares are used as an APCD. As such, these
proposed operational and monitoring requirements for flares at
refineries have the potential to reduce excess emissions from flares by
approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and 327,000 metric
tonnes per year of CO2e. The VOC compounds are non-methane,
non-ethane total hydrocarbons. According to the Component 2 database
from the Refinery ICR, there are approximately 50 individual HAP
compounds included in the emission inventory for flares, but many of
these are emitted in trace quantities. A little more than half of the
HAP emissions from flares are attributable to hexane, followed next by
benzene, toluene, xylenes, and 1,3-butadiene. For more detail on the
impact estimates, see the technical memorandum Petroleum Refinery
Sector Rule: Flare Impact Estimates in Docket ID Number EPA-HQ-OAR-
2010-0682.

Table 4--Nationwide Cost Impacts of Proposed Amendments To Ensure Proper
                            Flare Performance
------------------------------------------------------------------------
                                                              Total
                                         Total capital      annualized
            Affected source                investment     costs (million
                                          (million $)         $/yr)
------------------------------------------------------------------------
Flare Monitoring......................             147             36.3
------------------------------------------------------------------------

4. Vent Control Bypasses
a. Relief Valve Discharges
    Refinery MACT 1 recognized relief valve discharges to be the result
of malfunctions. Relief valves are designed to remain closed during
normal operation and only release as the result of unplanned and/or
unpredictable events. A release from a relief valve usually occurs
during an over pressurization of the system. However, emissions vented
directly to the atmosphere by relief valves in organic HAP service
contain HAP that are otherwise regulated under Refinery MACT 1.
    Refinery MACT 1 regulated relief valves through equipment leak
provisions that applied only after the pressure relief occurred. In
addition the rule followed the EPA's then-practice of exempting
startup, shutdown and malfunction (SSM) events from otherwise
applicable emission standards. Consequently, with relief valve releases
defined as unplanned and nonroutine and the result of malfunctions,
Refinery MACT 1 did not restrict relief valve releases to the
atmosphere but instead treated them the same as all malfunctions
through 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. See section IV.E of
this preamble for additional discussion. To ensure this standard is
consistent with that decision, these proposed amendments remove the
malfunction exemption in Refinery MACT 1 and 2 and provide that
emissions of HAP may not be discharged to the atmosphere from relief
valves in organic HAP service. To ensure compliance with this
amendment, we are also proposing to require that sources monitor relief
valves 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
relief valves to the atmosphere have the potential to emit large
quantities of HAP. Where 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 each relief valve that vents to
the 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 is $9.54 million and the annualized capital cost is $1.36
million per year.
    As defined in the Refinery MACT standards, relief valves are valves
used only to release unplanned, nonroutine discharges. A relief valve
discharge results from an operator error, a malfunction such as a power
failure or equipment failure, or other unexpected cause that requires
immediate venting of gas from process equipment in order to avoid
safety hazards or equipment damage. Even so, to the extent that there
are atmospheric HAP emissions from relief valves, we are required to
follow the Sierra Club ruling to address those emissions in our rule,
and we can no longer exempt them as permitted malfunction emissions as
we did under Refinery MACT 1. Our information indicates that there are
approximately 12,000 pressure relief valves that vent to the atmosphere
(based on the ICR responses) and that the majority of relief valves in
the refining industry are not atmospheric, but instead are routed to
flares (see letter from API, Docket Item Number EPA-HQ-OAR-2010-0682-
0012). We request comment on our approach and on alternatives to our
approach to regulating releases from pressure relief valves and also
request commenters to provide information supporting any such comments.
b. Bypass Lines
    For a closed vent system containing bypass lines that can divert
the stream away from the APCD to the atmosphere, Refinery MACT 1
requires the owner or operator to either: (1) Install, maintain and
operate a continuous parametric monitoring system (CPMS) for flow on
the bypass line that is capable of detecting whether a vent stream flow
is present at least once every hour, 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
(see 40 CFR 63.644(c) for more details). We are proposing under CAA
section 112(d)(2) and (3) that the use of a bypass at any time to
divert a Group 1 miscellaneous process vent is a violation of the
emission standard, and to specify that if option 1 is chosen, the owner
or operator would be required to install,

maintain and operate a CPMS for flow that is capable of recording the
volume of gas that bypasses the APCD. The CMPS must be equipped with an
automatic alarm system that will alert an operator immediately when
flow is detected in the bypass line. We are proposing this revision
because, as noted above, APCD are not to be bypassed because doing so
could result in a release of regulated organic HAP to the atmosphere.
In Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the Court
determined that standards under CAA section 112(d) must provide for
compliance at all times and a release of uncontrolled HAP to the
atmosphere is inconsistent with that requirement.
c. In Situ Sampling Systems (Onstream Analyzers)
    The current Refinery MACT 1 definition of ``miscellaneous process
vent'' states that ``in situ sampling systems (onstream analyzers)''
are not miscellaneous process vents. 40 CFR 63.641. For several
reasons, we are proposing to remove ``in situ sampling systems
(onstream analyzers)'' from the list of vents not considered
miscellaneous process vents. First, the language used in this exclusion
is inconsistent. We generally consider ``in situ sampling systems'' to
be non-extractive samplers or in-line samplers. There are certain in
situ sampling systems where the measurement is determined directly via