Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards, 75177-75354 [2015-26486]
Download as PDF
Vol. 80
Tuesday,
No. 230
December 1, 2015
Part II
Environmental Protection Agency
tkelley on DSK3SPTVN1PROD with RULES2
40 CFR Parts 60 and 63
Petroleum Refinery Sector Risk and Technology Review and New Source
Performance Standards; Final Rule
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00001
Fmt 4717
Sfmt 4717
E:\FR\FM\01DER2.SGM
01DER2
75178
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 60 and 63
[EPA–HQ–OAR–2010–0682; FRL–9935–40–
OAR]
RIN 2060–AQ75
Petroleum Refinery Sector Risk and
Technology Review and New Source
Performance Standards
Environmental Protection
Agency (EPA).
ACTION: Final rule.
AGENCY:
This action finalizes the
residual risk and technology review
conducted for the Petroleum Refinery
source categories regulated under
national emission standards for
hazardous air pollutants (NESHAP)
Refinery MACT 1 and Refinery MACT 2.
It also includes revisions to the Refinery
MACT 1 and MACT 2 rules in
accordance with provisions regarding
establishment of MACT standards. This
action also finalizes technical
corrections and clarifications for the
new source performance standards
(NSPS) for petroleum refineries to
improve consistency and clarity and
address issues related to a 2008 industry
petition for reconsideration.
Implementation of this final rule will
result in projected reductions of 5,200
tons per year (tpy) of hazardous air
pollutants (HAP) which will reduce
cancer risk and chronic health effects.
DATES: This final action is effective on
February 1, 2016. The incorporation by
reference of certain publications for part
63 listed in the rule is approved by the
Director of the Federal Register as of
February 1, 2016. The incorporation by
reference of certain publications for part
60 listed in the rule were approved by
the Director of the Federal Register as of
June 24, 2008.
ADDRESSES: The Environmental
Protection Agency (EPA) has established
a docket for this action under Docket ID
No. EPA–HQ–OAR–2010–0682. All
documents in the docket are listed on
the www.regulations.gov Web site.
Although listed in the index, some
information is not publicly available,
e.g., confidential business information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
available either electronically through
https://www.regulations.gov, or in hard
copy at the EPA Docket Center, WJC
tkelley on DSK3SPTVN1PROD with RULES2
SUMMARY:
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
West Building, Room Number 3334,
1301 Constitution Ave. NW.,
Washington, DC. The Public Reading
Room hours of operation are 8:30 a.m.
to 4:30 p.m. Eastern Standard Time
(EST), Monday through Friday. The
telephone number for the Public
Reading Room is (202) 566–1744, and
the telephone number for the Air and
Radiation Docket and Information
Center is (202) 566–1742.
FOR FURTHER INFORMATION CONTACT: For
questions about this final action, contact
Ms. Brenda Shine, Sector Policies and
Programs Division, Refining and
Chemicals Group (E143–01), Office of
Air Quality Planning and Standards,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina,
27711; telephone number: (919) 541–
3608; fax number: (919) 541–0246; and
email address: shine.brenda@epa.gov.
For specific information regarding the
risk modeling methodology, contact Mr.
Ted Palma, Health and Environmental
Impacts Division (C539–02), Office of
Air Quality Planning and Standards,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina
27711; telephone number: (919) 541–
5470; fax number: (919) 541–0840; and
email address: palma.ted@epa.gov. For
information about the applicability of
the NESHAP to a particular entity,
contact Ms. Maria Malave, Office of
Enforcement and Compliance
Assurance, U.S. Environmental
Protection Agency, William Jefferson
Clinton Building, 1200 Pennsylvania
Ave. NW., Washington, DC 20460;
telephone number: (202) 564–7027; fax
number: (202) 564–0050; and email
address: malave.maria@epa.gov.
SUPPLEMENTARY INFORMATION:
Preamble Acronyms and
Abbreviations. We use multiple
acronyms and terms in this preamble.
While this list may not be exhaustive, to
ease the reading of this preamble and for
reference purposes, the EPA defines the
following terms and acronyms here:
10/25 tpy emissions equal to or greater than
10 tons per year of a single pollutant or 25
tons per year of cumulative pollutants
AEGL acute exposure guideline levels
APCD air pollution control devices
API American Petroleum Institute
BAAQMD Bay Area Air Quality
Management District
BDT best demonstrated technology
BLD bag leak detectors
BSER best system of emission reductions
Btu/ft2 British thermal units per square foot
Btu/scf British thermal units per standard
cubic foot
CAA Clean Air Act
CBI confidential business information
CCU catalytic cracking units
CDX Central Data Exchange
PO 00000
Frm 00002
Fmt 4701
Sfmt 4700
CEDRI Compliance and Emissions Data
Reporting Interface
CEMS continuous emission monitoring
system
CFR Code of Federal Regulations
CO carbon monoxide
CO2 carbon dioxide
CO2e carbon dioxide equivalents
COMS continuous opacity monitoring
system
COS carbonyl sulfide
CPMS continuous parameter monitoring
system
CRA Congressional Review Act
CRU catalytic reforming units
CS2 carbon disulfide
DCU delayed coking units
EPA Environmental Protection Agency
ERPG emergency response and planning
guidelines
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FCCU fluid catalytic cracking unit
FGCD fuel gas combustion device
FMP flare management plan
FR Federal Register
FTIR Fourier transform infrared
spectroscopy
GC gas chromatograph
GHG greenhouse gases
H2S hydrogen sulfide
HAP hazardous air pollutants
HCl hydrogen chloride
HCN hydrogen cyanide
HF hydrogen fluoride
HFC highest fenceline concentration
HI hazard index
HQ hazard quotient
ICR information collection request
IRIS Integrated Risk Information System
km kilometers
LAER lowest achievable emission rate
lb/day pounds per day
LDAR leak detection and repair
LEL lower explosive limit
LTD long tons per day
MACT maximum achievable control
technology
MIR maximum individual risk
mph miles per hour
MPV miscellaneous process vent
NAICS North American Industry
Classification System
NESHAP National Emissions Standards for
Hazardous Air Pollutants
NFS near-field interfering source
NHVCZ combustion zone net heating value
Ni nickel
NOX nitrogen oxides
NRDC Natural Resources Defense Council
NSPS new source performance standards
NTTAA National Technology Transfer and
Advancement Act
OAQPS Office of Air Quality Planning and
standards
OECA Office of Enforcement and
Compliance Assurance
OEHHA Office of Environmental Health
Hazard Assessment
OEL open-ended line
OMB Office of Management and Budget
PM particulate matter
PM2.5 particulate matter 2.5 micrometers in
diameter and smaller
ppbv parts per billion by volume
ppm parts per million
E:\FR\FM\01DER2.SGM
01DER2
75179
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
ppmv parts per million by volume
PRA Paperwork Reduction Act
PRD pressure relief device 1
psia pounds per square inch absolute
psig pounds per square inch gauge
REL reference exposure level
REM Model Refinery Emissions Model
RFA Regulatory Flexibility Act
RTC response to comment
RTR Risk and Technology Review
SAB Science Advisory Board
SBA Small Business Administration
SCAQMD South Coast Air Quality
Management District
SCR selective catalytic reduction
SISNOSE significant economic impact on a
substantial number of small entities
SO2 sulfur dioxide
SRP sulfur recovery plant
SRU sulfur recovery unit
SSM startup, shutdown and malfunction
TOSHI target organ-specific hazard index
tpy tons per year
UMRA Unfunded Mandates Reform Act
URE unit risk estimate
UV–DOAS ultraviolet differential optical
absorption spectroscopy
VCS voluntary consensus standards
VOC volatile organic compounds
°F degrees Fahrenheit
DC the concentration difference between
the highest measured concentration and
the lowest measured concentration
mg/m3 micrograms per cubic meter
tkelley on DSK3SPTVN1PROD with RULES2
Background Information. On June 30,
2014, the EPA proposed revisions to
both of the petroleum refinery NESHAP
based on our residual risk and
technology review (RTR). In that action,
we also proposed to revise the NESHAP
pursuant to CAA section 112(d)(2) and
(3), to revise the SSM provisions in the
NESHAP, and to make technical
corrections to the NSPS to address
issues related to reconsideration of the
final NSPS subpart Ja rule in 2008. In
this action, we are finalizing decisions
and revisions for these rules. We
summarize some of the more significant
comments received regarding the
proposed rule and provide our
responses in this preamble. A summary
of all other public comments on the
proposal and the EPA’s responses to
those comments is provided in the
‘‘Response to Comment’’ document,
which is available in Docket ID No.
EPA–HQ–OAR–2010–0682. The ‘‘track
changes’’ version of the regulatory
language that incorporates the changes
in this final action is also available in
the docket for this rulemaking.
Organization of this Document. This
preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document
and other related information?
1 This term is common vernacular to describe the
variety of devices regulated as pressure relief valves
subject to the requirements in 40 CFR part 63
subpart CC.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
C. Judicial Review and Administrative
Reconsideration
II. Background
A. What is the statutory authority for this
action?
B. How do the NESHAP and NSPS regulate
air pollutant emissions from refineries?
C. What changes did we propose for the
Petroleum Refinery NESHAP and NSPS
in our June 30, 2014 RTR proposal?
III. What is included in this final rule?
A. What are the final NESHAP
amendments based on the risk review for
the Petroleum Refinery source
categories?
B. What are the final NESHAP
amendments based on the technology
review for the Petroleum Refinery source
categories?
C. What are the final NESHAP
amendments pursuant to section
112(d)(2) & (3) for the Petroleum
Refinery source categories?
D. What are the final NESHAP
amendments addressing emissions
during periods of SSM?
E. What other revisions to the NESHAP
and NSPS are being promulgated?
F. What are the requirements for
submission of performance test data to
the EPA?
G. What are the effective and compliance
dates of the NESHAP and NSPS?
H. What materials are being incorporated
by reference?
IV. What is the rationale for our final
decisions and amendments to the
Petroleum Refinery NESHAP and NSPS?
A. Residual Risk Review for the Petroleum
Refinery Source Categories
B. Technology Review for the Petroleum
Refinery Source Categories
C. Refinery MACT Amendments Pursuant
to CAA section 112(d)(2) and (d)(3)
D. NESHAP Amendments Addressing
Emissions During Periods of SSM
E. Technical Amendments to Refinery
MACT 1 and 2
F. Technical Amendments to Refinery
NSPS Subparts J and Ja
V. Summary of Cost, Environmental, and
Economic Impacts and Additional
Analyses Conducted
A. What are the affected facilities, the air
quality impacts and cost impacts?
B. What are the economic impacts?
C. What are the benefits?
D. Impacts of This Rulemaking on
Environmental Justice Populations
E. Impacts of This Rulemaking on
Children’s Health
VI. Statutory and Executive Order Reviews
A. Executive Orders 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act
(UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
PO 00000
Frm 00003
Fmt 4701
Sfmt 4700
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution or Use
I. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
part 51
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
I. General Information
A. Does this action apply to me?
Regulated Entities. Categories and
entities potentially regulated by this
action are shown in Table 1 of this
preamble.
TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS FINAL
ACTION
NAICS a
Code
NESHAP and source category
Petroleum Refining Industry .........
a North
American
Industry
324110
Classification
System.
Table 1 of this preamble is not
intended to be exhaustive, but rather to
provide a guide for readers regarding
entities likely to be affected by the final
action for the source categories listed.
To determine whether your facility is
affected, you should examine the
applicability criteria in the appropriate
NESHAP or NSPS. If you have any
questions regarding the applicability of
any aspect of these NESHAP or NSPS,
please contact the appropriate person
listed in the preceding FOR FURTHER
INFORMATION CONTACT section of this
preamble.
B. Where can I get a copy of this
document and other related
information?
In addition to being available in the
docket, an electronic copy of this final
action will also be available on the
Internet through the Technology
Transfer Network (TTN) Web site, a
forum for information and technology
exchange in various areas of air
pollution control. Following signature
by the EPA Administrator, the EPA will
post a copy of this final action at:
https://www.epa.gov/ttn/atw/petref.html.
Following publication in the Federal
Register, the EPA will post the Federal
Register version and key technical
documents at this same Web site.
Additional information is available on
the RTR Web site at https://www.epa.
gov/ttn/atw/rrisk/rtrpg.html. This
information includes an overview of the
RTR program, links to project Web sites
E:\FR\FM\01DER2.SGM
01DER2
75180
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
for the RTR source categories, and
detailed emissions and other data we
used as inputs to the risk assessments.
C. Judicial Review and Administrative
Reconsideration
Under CAA section 307(b)(1), judicial
review of this final action is available
only by filing a petition for review in
the United States Court of Appeals for
the District of Columbia Circuit by
February 1, 2016. Under CAA section
307(b)(2), the requirements established
by this final rule may not be challenged
separately in any civil or criminal
proceedings brought by the EPA to
enforce the requirements.
Section 307(d)(7)(B) of the CAA
further provides that ‘‘[o]nly an
objection to a rule or procedure which
was raised with reasonable specificity
during the period for public comment
(including any public hearing) may be
raised during judicial review.’’ This
section also provides a mechanism for
the EPA to reconsider the rule ‘‘[i]f the
person raising an objection can
demonstrate to the Administrator that it
was impracticable to raise such
objection within [the period for public
comment] or if the grounds for such
objection arose after the period for
public comment (but within the time
specified for judicial review) and if such
objection is of central relevance to the
outcome of the rule.’’ Any person
seeking to make such a demonstration
should submit a Petition for
Reconsideration to the Office of the
Administrator, U.S. EPA, Room 3000,
WJC Building, 1200 Pennsylvania Ave.
NW., Washington, DC 20460, with a
copy to both the person(s) listed in the
preceding FOR FURTHER INFORMATION
CONTACT section, and the Associate
General Counsel for the Air and
Radiation Law Office, Office of General
Counsel (Mail Code 2344A), U.S. EPA,
1200 Pennsylvania Ave. NW.,
Washington, DC 20460.
II. Background
tkelley on DSK3SPTVN1PROD with RULES2
A. What is the statutory authority for
this action?
1. NESHAP
Section 112 of the CAA establishes a
two-stage regulatory process to address
emissions of hazardous air pollutants
(HAP) from stationary sources. In the
first stage, we must identify categories
of sources emitting one or more of the
HAP listed in CAA section 112(b) and
then promulgate technology-based
NESHAP for those sources. ‘‘Major
sources’’ are those that emit, or have the
potential to emit, any single HAP at a
rate of 10 tons per year (tpy) or more,
or 25 tpy or more of any combination of
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
HAP. For major sources, these standards
are commonly referred to as maximum
achievable control technology (MACT)
standards and must reflect the
maximum degree of emission reductions
of HAP achievable (after considering
cost, energy requirements, and non-air
quality health and environmental
impacts). In developing MACT
standards, CAA section 112(d)(2) directs
the EPA to consider the application of
measures, processes, methods, systems
or techniques, including but not limited
to those that reduce the volume of or
eliminate HAP emissions through
process changes, substitution of
materials, or other modifications;
enclose systems or processes to
eliminate emissions; collect, capture, or
treat HAP when released from a process,
stack, storage, or fugitive emissions
point; are design, equipment, work
practice, or operational standards; or
any combination of the above.
For these MACT standards, the statute
specifies certain minimum stringency
requirements, which are referred to as
MACT floor requirements, and which
may not be based on cost
considerations. See CAA section
112(d)(3). For new sources, the MACT
floor cannot be less stringent than the
emission control achieved in practice by
the best-controlled similar source. The
MACT standards for existing sources
can be less stringent than floors for new
sources, but they cannot be less
stringent than the average emission
limitation achieved by the bestperforming 12-percent of existing
sources in the category or subcategory
(or the best-performing 5 sources for
categories or subcategories with fewer
than 30 sources). In developing MACT
standards, we must also consider
control options that are more stringent
than the floor, under CAA section
112(d)(2). We may establish standards
more stringent than the floor, based on
the consideration of the cost of
achieving the emissions reductions, any
non-air quality health and
environmental impacts, and energy
requirements.
In the second stage of the regulatory
process, the CAA requires the EPA to
undertake 2 different analyses, which
we refer to as the technology review and
the residual risk review. Under the
technology review, we must review the
technology-based standards and revise
them ‘‘as necessary (taking into account
developments in practices, processes,
and control technologies)’’ no less
frequently than every eight years,
pursuant to CAA section 112(d)(6).
Under the residual risk review, we must
evaluate the risk to public health
remaining after application of the
PO 00000
Frm 00004
Fmt 4701
Sfmt 4700
technology-based standards and revise
the standards, if necessary, to provide
an ample margin of safety to protect
public health or to prevent, taking into
consideration costs, energy, safety and
other relevant factors, an adverse
environmental effect. The residual risk
review is required within eight years
after promulgation of the technologybased standards, pursuant to CAA
section 112(f). In conducting the
residual risk review, if the EPA
determines that the current standards
provide an ample margin of safety to
protect public health, it is not necessary
to revise the MACT standards pursuant
to CAA section 112(f).2 For more
information on the statutory authority
for this rule, see 79 FR 36879.
2. NSPS
Section 111 of the CAA establishes
mechanisms for controlling emissions of
air pollutants from stationary sources.
Section 111(b) of the CAA provides
authority for the EPA to promulgate
NSPS that apply only to newly
constructed, reconstructed and modified
sources. Once the EPA has elected to set
NSPS for new and modified sources in
a given source category, CAA section
111(d) calls for regulation of existing
sources, with certain exceptions
explained below.
Specifically, section 111(b) of the
CAA requires the EPA to establish
emission standards for any category of
new and modified stationary sources
that the Administrator, in his or her
judgment, finds ‘‘causes, or contributes
significantly to, air pollution which may
reasonably be anticipated to endanger
public health or welfare.’’ The EPA has
previously made endangerment findings
under this section of the CAA for more
than 60 stationary source categories and
subcategories that are now subject to
NSPS.
Section 111 of the CAA gives the EPA
significant discretion to identify the
affected facilities within a source
category that should be regulated. To
define the affected facilities, the EPA
can use size thresholds for regulation
and create subcategories based on
source type, class or size. Emission
limits also may be established either for
equipment within a facility or for an
entire facility. For listed source
categories, the EPA must establish
‘‘standards of performance’’ that apply
2 The U.S. Court of Appeals has affirmed this
approach of implementing CAA section
112(f)(2)(A): NRDC v. EPA, 529 F.3d 1077, 1083
(D.C. Cir. 2008) (‘‘If EPA determines that the
existing technology-based standards provide an
‘ample margin of safety,’ then the Agency is free to
readopt those standards during the residual risk
rulemaking.’’).
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
to sources that are constructed,
modified or reconstructed after the EPA
proposes the NSPS for the relevant
source category.3
The EPA also has significant
discretion to determine the appropriate
level for the standards. Section 111(a)(1)
of the CAA provides that NSPS are to
reflect the degree of emission limitation
achievable through the application of
the best system of emission reduction
which (taking into account the cost of
achieving such reduction and any nonair quality health and environmental
impact and energy requirements) the
Administrator determines has been
adequately demonstrated. This level of
control is commonly referred to as best
demonstrated technology (BDT) or the
best system of emission reduction
(BSER). The standard that the EPA
develops, based on the BSER achievable
at that source, is commonly a numerical
emission limit, expressed as a
performance level (i.e., a rate-based
standard). Generally, the EPA does not
prescribe a particular technological
system that must be used to comply
with a NSPS. Rather, sources remain
free to elect whatever combination of
measures will achieve equivalent or
greater control of emissions.
Costs are also considered in
evaluating the appropriate standard of
performance for each category or
subcategory. The EPA generally
compares control options and estimated
costs and emission impacts of multiple,
specific emission standard options
under consideration. As part of this
analysis, the EPA considers numerous
factors relating to the potential cost of
the regulation, including industry
organization and market structure,
control options available to reduce
emissions of the regulated pollutant(s)
and costs of these controls.
tkelley on DSK3SPTVN1PROD with RULES2
B. How do the NESHAP and NSPS
regulate air pollutant emissions from
refineries?
The EPA promulgated the petroleum
refinery NESHAP pursuant to CAA
section 112(d)(2) and (3) for refineries
located at major sources in two separate
rules. On August 18, 1995, the first
3 Specific statutory and regulatory provisions
define what constitutes a modification or
reconstruction of a facility. 40 CFR 60.14 provides
that an existing facility is modified and, therefore,
subject to an NSPS, if it undergoes any physical
change in the method of operation which increases
the amount of any air pollutant emitted by such
source or which results in the emission of any air
pollutant not previously emitted. 40 CFR 60.15, in
turn, provides that a facility is reconstructed if
components are replaced at an existing facility to
such an extent that the capital cost of the new
equipment/components exceed 50-percent of what
is believed to be the cost of a completely new
facility.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
petroleum refinery MACT standard was
promulgated in 40 CFR part 63, subpart
CC (60 FR 43620). This rule is known
as ‘‘Refinery MACT 1’’ and covers the
‘‘Sources Not Distinctly Listed,’’
meaning it includes all emissions
sources from petroleum refinery process
units, except those listed separately
under the section 112(c) source category
list and expected to be regulated by
other MACT standards (for example,
boilers and process heaters). Some of
the emission sources regulated in
Refinery MACT 1 include miscellaneous
process vents (MPV), storage vessels,
wastewater, equipment leaks, gasoline
loading racks, marine tank vessel
loading and heat exchange systems.
On April 11, 2002 (67 FR 17762), EPA
promulgated a second MACT standard
regulating certain process vents that
were listed as a separate source category
under CAA section 112(c) and that were
not addressed as part of the Refinery
MACT 1. This standard, which is
referred to as ‘‘Refinery MACT 2’’,
covers process vents on catalytic
cracking units (CCU) (including FCCU),
CRU and SRU and is codified as 40 CFR
part 63, subpart UUU.
Finally, on October 28, 2009, we
revised Refinery MACT 1 by adding
MACT standards for heat exchange
systems, which the EPA had not
addressed in the original 1995 Refinery
MACT 1 rule (74 FR 55686). In this
same 2009 action, we updated the crossreferences to the General Provisions in
40 CFR part 63. On June 20, 2013 (78
FR 37133), we promulgated minor
revisions to the heat exchange
provisions of Refinery MACT 1.
On September 27, 2012, Air Alliance
Houston, California Communities
Against Toxics and other environmental
and public health groups filed a lawsuit
alleging that the EPA missed statutory
deadlines to review and revise Refinery
MACT 1 and 2. The EPA reached an
agreement to settle that litigation and
entered into a Consent Decree. The
Consent Decree provides for the
Administrator to sign a final action no
later than September 30, 2015.
Refinery NSPS subparts J and Ja
regulated criteria pollutant emissions,
including particulate matter (PM), sulfur
dioxide (SO2), nitrogen oxides (NOX)
and carbon monoxide (CO) from FCCU
catalyst regenerators, fuel gas
combustion devices (FGCD) and sulfur
recovery plants. Refinery NSPS subpart
Ja also regulates criteria pollutant
emissions from fluid coking units and
DCU.
The NSPS for petroleum refineries (40
CFR part 60, subpart J) were
promulgated in 1974, amended in 1976
and amended again in 2008, following
PO 00000
Frm 00005
Fmt 4701
Sfmt 4700
75181
a review of the standards. As part of the
review that led to the 2008 amendments
to the Refinery NSPS subpart J, the EPA
developed separate standards of
performance for new process units (40
CFR part 60, subpart Ja). However, the
EPA received multiple petitions for
reconsideration on issues related to
those standards. The Administrator
granted the petitions for
reconsideration. The EPA addressed
petition issues related to process heaters
and flares by promulgating amendments
to the Refinery NSPS subparts J and Ja
on September 12, 2012 (77 FR 56422).
In this action, we are finalizing
technical corrections and clarifications
to NSPS subparts J and Ja raised by
American Petroleum Institute (API) in
their 2008 petition for reconsideration
that were not addressed by the final
NSPS amendments of 2012.
The petroleum refining industry
consists of facilities that engage in
converting crude oil into refined
products, including liquefied petroleum
gas, gasoline, kerosene, aviation fuel,
diesel fuel, fuel oils, lubricating oils and
feedstocks for the petrochemical
industry. Currently, 142 facilities have
emission sources regulated by either or
both Refinery MACT 1 and 2.
Petroleum refinery activities start
with the receipt of crude oil for storage
at the refinery, include all the petroleum
handling and refining operations, and
terminate with loading of refined
products into pipelines, tank or rail
cars, tank trucks, or ships or barges that
take products from the refinery to
distribution centers. Petroleum-specific
process units include FCCU and CRU.
Other units and processes found at
petroleum refineries (as well as at many
other types of manufacturing facilities)
include storage vessels and wastewater
treatment plants. HAP emitted by this
industry include organics (e.g.,
acetaldehyde, benzene, formaldehyde,
hexane, phenol, naphthalene, 2methylnaphthalene, dioxins, furans,
ethyl benzene, toluene and xylene);
reduced sulfur compounds (i.e.,
carbonyl sulfide (COS), carbon disulfide
(CS2))); inorganics (e.g., hydrogen
chloride (HCl), hydrogen cyanide
(HCN), chlorine, hydrogen fluoride
(HF)); and metals (e.g., antimony,
arsenic, beryllium, cadmium,
chromium, cobalt, lead, mercury,
manganese and nickel (Ni)). This
industry also emits criteria pollutants
and other non-HAP, including NOX,
PM, SO2, volatile organic compounds
(VOC), CO, greenhouse gases (GHG) and
total reduced sulfur.
E:\FR\FM\01DER2.SGM
01DER2
75182
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
C. What changes did we propose for the
Petroleum Refinery NESHAP and NSPS
in our June 30, 2014, RTR proposal?
On June 30, 2014, the EPA published
a proposed rule in the Federal Register
addressing the RTR for the Petroleum
Refinery NESHAP, 40 CFR part 63,
subparts CC and UUU. The proposal
also included changes pursuant to
section 112(d)(2) and (3) and technical
revisions to the NSPS. Specifically, we
proposed:
(1) Pursuant to CAA sections
112(d)(2) and (3):
a. Refinery MACT 1:
• Adding MACT Standards for DCU
decoking operations.
• Adding operational requirements
for flares used as APCD in Refinery
MACT 1 and 2.
• Adding requirements and
clarifications for vent control bypasses
in Refinery MACT 1.
b. Refinery MACT 2:
• Revising the CRU purge vent
exemption.
(2) Pursuant to CAA sections
112(d)(6) and 112(f)(2):
• Revising Refinery MACT 1 to crossreference the corresponding storage
vessel requirements in the Generic
MACT (40 CFR part 63, subpart WW, as
applicable), and revising the definition
of Group 1 storage vessels to include
smaller capacity storage vessels and to
include storage vessels storing materials
with lower vapor pressures.
(3) Pursuant to CAA section 112(d)(6):
a. Refinery MACT 1:
• Allowing refineries to meet the leak
detection and repair (LDAR)
requirements in Refinery MACT 1 by
monitoring for leaks using optical gas
imaging in place of EPA Method 21,
once the monitoring protocol set forth in
Appendix K is promulgated.
• Amending the Marine Tank Vessel
Loading Operations NESHAP, 40 CFR
part 63, subpart Y, to delete the
exclusion for marine vessel loading
operations at petroleum refineries.
• Establishing a fenceline monitoring
work practice standard to improve the
management of fugitive emissions.
b. Refinery MACT 2:
• Incorporating requirements
consistent with those in Refinery NSPS
subpart Ja for FCCU including:
• Requiring the use of 3-hour
averages rather than daily averages for
parameter operating limits (e.g.,
depending on the type of control device:
Opacity, total power, secondary current,
pressure drop, and/or liquid-to-gas
ratio).
• Removing the Refinery NSPS
subpart J incremental PM emissions
allowance for post combustion devices
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
when burning liquid or solid fuels, and
removing the 30 percent opacity limit
for units complying with NSPS subpart
J.
• Adding requirements for FCCU
controls to include bag leak detectors
(BLD) as an option to continuous
opacity monitoring system (COMS).
• Incorporating total power and the
secondary current operating limits for
electrostatic precipitators (ESP).
• Requiring daily checks of the air or
water pressure to the spray nozzles on
jet ejector-type wet scrubber or other
type of wet scrubber equipped with
atomizing spray nozzles.
• Requiring FCCU periodic
performance testing on a frequency of
once every 5 years, as opposed to the
current rule, which only requires an
initial performance test.
• Including a correlation equation for
the use of oxygen-enriched air for SRU.
• Allowing SRU subject to Refinery
NSPS subpart Ja with a capacity greater
than 20 long tons per day (LTD) to
comply with Refinery NSPS subpart Ja
as a means of complying with Refinery
MACT 2.
(4) Other proposed changes include:
• Removing exemptions from the rule
requirements for periods of SSM in
order to ensure that the NESHAP are
consistent with the court decision in
Sierra Club v. EPA, 551 F. 3d 1019 (D.C.
Cir. 2008).
• Clarifying requirements related to
open-ended valves or lines.
• Adding electronic reporting
requirements.
• Updating the General Provisions
cross-reference tables.
• Making technical corrections and
clarifications to NSPS subparts J and Ja.
subparts J and Ja to address issues raised
in the reconsideration of these rules.
III. What is included in this final rule?
This action finalizes the EPA’s
determinations pursuant to the RTR
provisions of CAA section 112 for the
Petroleum Refinery source categories
and amends the Petroleum Refinery
NESHAP based on those
determinations. This action also
finalizes other changes to the NESHAP
including revising Refinery MACT 1
and 2 pursuant to CAA section 112
(d)(2) and (3), including revising
requirements for flares and pressure
relief devices (PRD). This action
finalizes changes to the SSM provisions
to ensure that the subparts are
consistent with the court decision in
Sierra Club v. EPA, 551 F. 3d 1019 (D.C.
Cir. 2008), adds electronic reporting
requirements in Refinery MACT 1 and
2; and updates the General Provisions
cross-reference tables. Finally, this
action finalizes technical corrections
and clarifications to Refinery NSPS
We determined that there are
developments in practices, processes
and control technologies that warrant
revisions to the MACT standards for this
source category. Therefore, to satisfy the
requirements of CAA section 112(d)(6),
we are revising the MACT standards to
amend 40 CFR part 63, subpart Y to
delete the exclusion for marine vessel
loading operations at petroleum
refineries. Removing this exclusion will
require small marine vessel loading
operations (i.e., operations with HAP
emissions less than 10/25 tpy) and
offshore marine vessel loading
operations to use submerged filling
based on the cargo filling line
requirements in 46 CFR 153.282, as
proposed.
We are also finalizing a fenceline
monitoring work practice standard to
improve the management of fugitive
emissions and finalizing EPA Methods
325A and 325B to support the work
PO 00000
Frm 00006
Fmt 4701
Sfmt 4700
A. What are the final NESHAP
amendments based on the risk review
for the Petroleum Refinery source
categories?
The EPA is promulgating final
amendments to the Petroleum Refinery
NESHAP pursuant to CAA section
112(f) that expand the existing Refinery
MACT 1 control requirements and
extend these requirements to smaller
tanks and tanks with lower vapor
pressures. Specifically, consistent with
the proposal, the EPA is amending
Refinery MACT 1 by revising the
definition of Group 1 storage vessels to
include storage vessels with capacities
greater than or equal to 20,000 gallons
but less than 40,000 gallons if the
maximum true vapor pressure is 1.0
psia or greater and to include storage
tanks greater than 40,000 gallons if the
maximum true vapor pressure is 0.75
psia or greater. The EPA is also adding
a cross-reference to the storage vessel
requirements in the Generic MACT (40
CFR part 63, subpart WW and subpart
CC), which include requirements for
guide pole controls and other fittings as
well as inspection requirements. After
considering the public comments, the
final amendments include minor
changes from our proposed
requirements to clarify language and
correct typographical and referencing
errors.
B. What are the final NESHAP
amendments based on the technology
review for the Petroleum Refinery source
categories?
1. Refinery MACT 1
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
practice, with some changes from
proposal to address issues raised by
commenters. Key revisions include:
New provisions for reduced monitoring
for facilities with consistently low
fenceline concentrations; requirements
for alternatives to passive monitoring;
revised placement guidance to allow
perimeter monitoring within a facility’s
property boundary provided all sources
are encompassed within the monitoring
perimeter; reductions in the number of
monitors required for subareas and
segregated areas; clarifications on
monitor placement for internal
roadways or other right-of-ways and
marine docks; and revised timelines for
submitting periodic reports (quarterly
rather than semiannually) and
implementing the work practice
standard (2 years after promulgation
rather than 3 years as proposed). We are
also revising Refinery MACT 1 storage
vessel requirements as described above
under the risk review, as proposed.
2. Refinery MACT 2
We determined that there are
developments in practices, processes
and control technologies that warrant
revisions to the MACT standards for this
source category. Therefore, to satisfy the
requirements of CAA section 112(d)(6),
we are revising the Refinery MACT 2
standard for FCCU subject to Refinery
NSPS subpart J or those electing to
comply with the Refinery NSPS subpart
J requirements. As proposed, we are
removing the incremental PM limit
when burning liquid or solid fuels. We
are finalizing a 20-percent opacity
operating limit evaluated on a 3-hour
average, which differs from the proposal
to eliminate the 30-percent opacity limit
and instead allow only for a site-specific
opacity operating limit or control device
parameter monitoring. As proposed, we
are finalizing requirements to make
Refinery MACT 2 consistent with
Refinery NSPS subpart Ja for FCCU by
including 3-hour averages rather than
daily averages for parameter operating
limits, and by including 3-hour averages
rather than daily averages for the sitespecific opacity operating limit. We are
also finalizing requirements, as
proposed, for FCCU controls to include
adding BLD as an option to COMS,
incorporating total power and the
secondary current operating limits for
ESP and requiring daily checks of the
air or water pressure to the spray
nozzles on jet ejector-type wet scrubbers
or other types of wet scrubbers
equipped with atomizing spray nozzles.
Finally, we are finalizing, as
proposed, requirements for FCCU
periodic performance testing at a
frequency of once every 5 years rather
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
than the current requirements for a onetime initial performance test. However,
for owners or operators complying with
the Refinery NSPS subpart J option
(with the 20-percent opacity operating
limit discussed above), if the PM
emissions are within 80-percent of the
PM limit during any periodic
performance test (i.e., emissions exceed
0.8 lb PM/1,000 lbs of coke burn-off),
the refinery owner or operator must
conduct subsequent performance tests
on an annual basis. Based on comments
received, we are also adding
requirements in the final rule for owners
or operators of FCCU to conduct a onetime test for HCN emissions from the
FCCU concurrent with their first
periodic performance test, which must
be conducted on or before August 1,
2017 for all FCCU subject to Refinery
MACT 2.
For SRU, as proposed, we are
finalizing a correlation equation for the
use of oxygen-enriched air.
Additionally, as proposed, we are
finalizing requirements to allow sulfur
recovery plants subject to Refinery
NSPS subpart Ja with a capacity greater
than 20 LTD to comply with Refinery
NSPS subpart Ja as a means of
complying with Refinery MACT 2.
C. What are the final NESHAP
amendments pursuant to section
112(d)(2) & (3) for the Petroleum
Refinery source categories?
1. Refinery MACT 1
We are finalizing MACT standards for
DCU decoking operations that require
that each coke drum be depressured to
a closed blowdown system until the
coke drum pressure is 2 psig with minor
revisions from proposal. Specifically,
we are finalizing provisions for existing
DCU affected sources to average over a
60-cycle (i.e., 60 batch) basis to comply
with the 2 psig limit, rather than the
proposed requirement to meet the 2 psig
limit on a per venting event basis. In
addition, we are finalizing requirements
for new DCU affected sources to
depressure to 2.0 psig on a per-event,
not-to-exceed basis, adding one
significant digit to the limit for new
DCU affected sources. For both new and
existing DCU affected sources, we are
finalizing specific provisions for DCU
with water overflow design and for
double quenching.
We are finalizing operational
requirements and the associated
monitoring, recordkeeping and
reporting requirements for flares used as
APCD in Refinery MACT 1 and 2 with
revisions to the requirements proposed.
Prior to these amendments, Refinery
MACT 1 and 2 cross-referenced the
PO 00000
Frm 00007
Fmt 4701
Sfmt 4700
75183
General Provisions requirements at 40
CFR 63.11(b). As proposed, this final
action replaces the cross reference to the
General Provisions and incorporates
enhanced flare operational requirements
directly into the Refinery MACT
regulations. As proposed, the final rule
amendments require that refinery flares
operate with continuously lit pilot
flames at all times. Consistent with our
proposal, we are finalizing requirements
for flares to operate with no visible
emissions and comply with
consolidated requirements related to
flare tip velocity, but in the final rule
these direct emissions limits apply
when flare vent gas flow is below the
smokeless capacity of the flare rather
than at all times. Above the smokeless
capacity of the flare, we are establishing
a work practice standard related to the
visible emissions and velocity limits;
these work practice standards are
described in more detail in section
III.D.1 of this preamble.
We are finalizing new operational
requirements related to combustion
zone gas properties with revisions from
proposal. In response to comments on
the proposal, we are finalizing
requirements that flares meet a
minimum operating limit of 270 BTU/
scf NHVcz on a 15-minute average, and
are allowing refinery owners or
operators to use a corrected heat content
of 1,212 BTU/scf for hydrogen to
demonstrate compliance with this
operating limit. We had proposed two
separate sets of limits, one being more
stringent if an olefins/hydrogen mixture
was present in the waste gas. For each
set of limits, we proposed three different
alternative combustion zone operating
limits: One based on the combustion
zone net heat content with no correction
for the heat content of hydrogen, one
based on the lower flammability limit
and one based on the combustibles
concentration. We proposed that these
limits be determined on a 15-minute
‘‘feed-forward’’ block average approach
(i.e., compositional data are collected
every 15 minutes, after which
adjustments are made). We have
included an additional option for
refiners to comply where more frequent
data are collected (using direct net
heating value monitoring) to calculate
the combustion limit using net heating
value data from the same 15-minute
block period. We are simplifying the
compliance approach to a single
operating limit based only on the
combustion zone net heating value
(with a hydrogen correction). As
proposed, we are requiring refinery
owners or operators to characterize the
composition of waste gas, assist gas and
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75184
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
fuel to demonstrate compliance with the
operational requirements.
As proposed, we are also finalizing in
this rule a burden reduction option to
use grab sampling every 8 hours rather
than continuous vent gas composition
or heat content monitors. We are also
including, based on public comment,
provisions to conduct limited initial
sampling and process knowledge to
characterize flare gas composition for
flares in ‘‘dedicated’’ service as an
alternative to collecting grab samples
during each specific event. We are
finalizing a requirement for daily visible
emissions observations as proposed,
but, based on public comment, we are
allowing owners or operators to use
video surveillance cameras to
demonstrate compliance with the
visible emissions limit as an alternative
to the daily visible emissions
observations.
For PRD, we are finalizing
requirements for monitoring systems
that are capable of identifying and
recording the time and duration of each
pressure release to the atmosphere, as
proposed. Certain PRD with low set
pressures or low emission potential or
in liquid service would not be subject to
these monitoring requirements. We are
finalizing requirements to minimize or
prevent atmospheric releases of HAP
through PRD. Instead of the proposed
prohibition on such releases, we are
finalizing work practice requirements
that require both preventive measures as
well as root cause analysis and
corrective action that will incentivize
refinery owners or operators to
eliminate the causes of the releases.
We are finalizing requirements for
bypass lines with minor revisions from
those proposed. Specifically, we are not
adopting the proposed requirement to
install quantitative flow monitors and
thus are leaving in place the
requirement to use flow indicators on
bypass lines. In addition, we are
maintaining the requirements to
estimate and report the quantity of
organic HAP released. In response to
public comment, we are also clarifying
changes to remove the proposed
reference to air intrusion and specifying
that reporting of bypasses is only
required when ‘‘regulated material’’ is
discharged to the atmosphere as a result
of a bypass of a control device.
We are also finalizing revisions to the
definition of miscellaneous process
vent, as proposed. These revisions
include deletion of exclusions
associated with episodic releases and
vents from in situ sampling systems. As
proposed, the final amendments require
that these vents must meet the standards
applicable to MPV.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
2. Refinery MACT 2
For CRU vents, we are finalizing the
vessel pressure limit exclusion of 5 psig
to apply only to passive
depressurization, as proposed.
D. What are the final NESHAP
amendments addressing emissions
during periods of SSM?
We are finalizing, as proposed,
changes to Refinery MACT 1 and 2 to
eliminate the SSM exemption.
Consistent with Sierra Club v. EPA, 551
F. 3d 1019 (D.C. Cir. 2008), the EPA has
established standards in this rule that
apply at all times. EPA is revising Table
6 of subpart CC of 40 CFR part 63 and
Table 44 to subpart UUU of 40 CFR part
63 (the General Provisions Applicability
Tables) to change several references
related to requirements that apply
during periods of SSM. We also are
eliminating or revising certain
recordkeeping and reporting
requirements related to the eliminated
SSM exemptions. We also are removing
or modifying inappropriate,
unnecessary or redundant language in
the absence of the SSM exemption.
Further, for certain emission sources in
both MACT 1 and 2, we are establishing
standards to address emissions during
these periods. These are described
below.
1. Refinery MACT 1
We are finalizing a work practice
standard for PRD that requires refinery
owners or operators to establish
prevention measures for each PRD in
organic HAP service. Under the work
practice standard, where a direct release
occurs, the refinery is required to
perform root cause analysis and
implement corrective action. The work
practice standard also limits the number
of events that a PRD may release to the
atmosphere during a 3-year period, as
explained further in the section IV.D. of
this preamble.
We are also finalizing a work practice
standard for emergency flaring events
that requires refinery owners or
operators to establish prevention
measures, including the development of
a flare management plan (FMP), and
perform root cause analysis and
implement corrective action following
flaring events during which the velocity
of waste gas going to the flare or visible
emissions limits (i.e., opacity) at the
flare tip are exceeded, and to limit the
number of these events allowed in a 3year period, as explained further in
section IV.D. of this preamble. Both of
these work practice standards are
consistent with the EPA’s goal to
improve the effectiveness of the rules.
PO 00000
Frm 00008
Fmt 4701
Sfmt 4700
These requirements will provide a
strong incentive for facilities, over time,
to better operate their processes to
prevent PRD and flare releases.
We are also finalizing requirements
for opening process equipment to the
atmosphere during maintenance events
after draining and purging to a closed
system, provided the hydrocarbon
content is less than or equal to 10percent of the lower explosive limit
(LEL). For those situations where 10percent LEL cannot be demonstrated,
the equipment may be opened and
vented to the atmosphere if the pressure
is less than or equal to 5 psig, provided
there is no active purging of the
equipment to the atmosphere until the
LEL criterion is met. This 5 psig
allowance is only available during
shutdown. We are also providing
additional allowances for situations
where it is not technically feasible to
depressurize a control system where
there is no more than 72 lbs VOC per
day vented to the atmosphere,
consistent with our Group 1
applicability cutoff for control of
process vents, or for catalyst changeout
activities where hydrotreater pyrophoric
catalyst must be purged. Provisions to
demonstrate that process equipment is
opened only after the LEL, pressure or
mass in the vessel requirement is met
includes documenting the procedures
for equipment openings and procedures
for verifying that the openings meet the
specific, above-discussed requirements
using site-specific procedures used to
de-inventory equipment for safety
purposes (i.e., hot work or vessel entry
procedures).
2. Refinery MACT 2
The Refinery MACT 2 standards
regulate all HAP emissions from the
three refinery process vents subject to
Refinery MACT 2. For FCCU, the
standard specifies a CO limit as a
surrogate for organic HAP and specifies
a PM limit (or Ni limit) as a surrogate
for metal HAP. Compliance with the
organic HAP emissions limit is
demonstrated using a continuous CO
monitor; compliance with the metal
HAP emissions limit is demonstrated
using either COMS or control device
parameter monitoring systems (CPMS).
At proposal, with the removal of the
exemptions in the Refinery MACT 2
rule for periods of startup and
shutdown, we recognized the need for
alternative standards during some
startup and shutdown situations, and
we proposed alternative requirements.
For this final rule, we are including a
1-percent minimum oxygen limit as an
alternative to the 500 ppmv hourly CO
limit during FCCU startup for partial
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
burn FCCU with CO boilers, as
proposed. We are extending that
alternative limit to all FCCU and
extending it to apply during shutdown.
We are not finalizing the proposed
alternative opacity limit for FCCU
during startup. Instead, based on public
comments received, we are finalizing an
alternative minimum cyclone face
velocity limit as a means to demonstrate
compliance with the PM limit during
both startup and shutdown, regardless
of the type of FCCU and its control
device. We are finalizing alternative
standards for sulfur recovery plant
(SRP) incinerator temperature and
excess oxygen limits during SRP
shutdown, as proposed, and we are
extending the proposed alternative
standards to startup as well.
tkelley on DSK3SPTVN1PROD with RULES2
E. What other revisions to the NESHAP
and NSPS are being promulgated?
We are finalizing technical
amendments to NSPS subparts J and Ja
with limited changes from what we
proposed. First, in response to
comments, we are revising the NSPS
requirements that a flow sensor have a
‘‘measurement sensitivity’’ of no more
than 5-percent of the flow rate to an
‘‘accuracy’’ requirement that the flow
sensor have an accuracy of 5-percent of
the flow rate. This change will make the
requirements more clear and consistent
between the flow meter requirements in
the NSPS and the MACT standards
since it is the same flow meter subject
to these requirements. We are also
revising flare flow rate accuracy
requirements in Refinery NSPS subpart
Ja to make them consistent with those
we are finalizing in Refinery MACT 1.
Finally, we are revising 40 CFR
60.101a(b) to begin as ‘‘Except for flares
and delayed coking units . . .’’ to
correct an inadvertent error. We
proposed revisions to this sentence
solely to allow sources subject to
Refinery NSPS subpart J to comply with
the provisions in Refinery NSPS subpart
Ja instead. However, the words ‘‘and
delayed coking units’’ were
inadvertently omitted from the initial
part of the sentence. Thus, as intended,
we are finalizing revisions to this
sentence to allow sources subject to
Refinery NSPS subpart J to comply with
the provisions in Refinery NSPS subpart
Ja.
F. What are the requirements for
submission of performance test data to
the EPA?
As proposed, the EPA is taking a step
to increase the ease and efficiency of
data submittal and data accessibility.
Specifically, the EPA is finalizing the
requirement for owners or operators of
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Petroleum Refinery facilities to submit
electronic copies of certain required
performance test reports through the
EPA’s Central Data Exchange (CDX)
using the Compliance and Emissions
Data Reporting Interface (CEDRI). The
EPA believes that the electronic
submittal of the reports addressed in
this rulemaking will increase the
usefulness of the data contained in
those reports, is in keeping with current
trends in data availability, will further
assist in the protection of public health
and the environment and will
ultimately result in less burden on the
regulated community. Electronic
reporting can also eliminate paperbased, manual processes, thereby saving
time and resources, simplifying data
entry, eliminating redundancies,
minimizing data reporting errors and
providing data quickly and accurately to
the affected facilities, air agencies, the
EPA and the public.
As mentioned in the preamble of the
proposal, the EPA Web site that stores
the submitted electronic data, WebFIRE,
will be easily accessible to everyone and
will provide a user-friendly interface
that any stakeholder could access. By
making the records, data and reports
addressed in this rulemaking readily
available, the EPA, the regulated
community and the public will benefit
when the EPA conducts its CAArequired technology and risk-based
reviews. As a result of having reports
readily accessible, our ability to carry
out comprehensive reviews will be
increased and achieved within a shorter
period of time.
We anticipate fewer or less substantial
information collection requests (ICRs) in
conjunction with prospective CAArequired technology and risk-based
reviews may be needed. We expect this
to result in a decrease in time spent by
industry to respond to data collection
requests. We also expect the ICRs to
contain less extensive stack testing
provisions, as we will already have
stack test data electronically. Reduced
testing requirements would be a cost
savings to industry. The EPA should
also be able to conduct these required
reviews more quickly. While the
regulated community may benefit from
a reduced burden of ICRs, the general
public benefits from the agency’s ability
to provide these required reviews more
quickly, resulting in increased public
health and environmental protection.
Air agencies could benefit from more
streamlined and automated review of
the electronically submitted data.
Having reports and associated data in
electronic format will facilitate review
through the use of software ‘‘search’’
options, as well as the downloading and
PO 00000
Frm 00009
Fmt 4701
Sfmt 4700
75185
analyzing of data in spreadsheet format.
The ability to access and review air
emission report information
electronically will assist air agencies to
more quickly and accurately determine
compliance with the applicable
regulations, potentially allowing a faster
response to violations which could
minimize harmful air emissions. This
benefits both air agencies and the
general public.
For a more thorough discussion of
electronic reporting required by this
rule, see the discussion in the preamble
of the proposal. In summary, in addition
to supporting regulation development,
control strategy development, and other
air pollution control activities, having
an electronic database populated with
performance test data will save
industry, air agencies, and the EPA
significant time, money, and effort
while improving the quality of emission
inventories, air quality regulations, and
enhancing the public’s access to this
important information.
G. What are the effective and
compliance dates of the NESHAP and
NSPS?
The final amendments to the NESHAP
and NSPS in this action are effective on
February 1, 2016. As proposed, new
sources must comply with these
requirements by the effective date of the
final rule or upon startup, whichever is
later.
As proposed, existing sources are
required to comply with the final DCU
and CRU requirements no later than 3
years after the effective date of the final
rule. Similarly, as proposed, owners or
operators are required to comply with
the new operating and monitoring
requirements for existing flares no later
than 3 years after the effective date of
the final rule.
We proposed to provide 3 years from
the effective date of the final rule for
refinery owners or operators to install
and begin monitoring (collecting
samples) around the fenceline of their
existing facility. If refinery owners and
operators determined that a site-specific
monitoring plan was needed, they
would also need to submit and receive
approval for such a plan during the 3year compliance period. Based on
information submitted during the
comment period, we are finalizing
requirements that refinery owners or
operators begin collecting samples
around the fenceline within 2 years of
the effective date of the final rule. Based
on information submitted during the
comment period, 1 year is sufficient
time to identify proper monitoring
locations and to install the required
monitoring stations around the facility
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75186
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
fenceline. However, owners or operators
may need additional monitoring
systems to account for near-field
interfering sources (NFS), for which the
development and approval of a sitespecific fenceline monitoring plan is
required. We expect that the sitespecific fenceline monitoring plans can
take an additional year to develop,
submit and obtain approval.
Consequently, we are providing 2 years
from the effective date of the final rule
for refinery owners or operators to
install and begin collecting samples
around the fenceline of their facility.
As proposed, we are requiring that
existing sources comply with the
submerged filling requirement for
marine vessel loading on the effective
date of the final rule.
As proposed, we are providing 18
months after the effective date of the
final rule to conduct required
performance tests and comply with any
revised operating limits for FCCU.
We proposed to require refinery
owners or operators to comply with the
revisions to the SSM provisions of
Refinery MACT 1 and 2 on the effective
date of the final rule. As proposed, this
final rule requires refinery owners or
operators to comply with the limits in
Refinery MACT 2 or the alternative
limits in this final rule during startup
and shutdown for FCCU and SRU on the
effective date of the final rule.
The flare work practice standards for
high-load flaring events (events
exceeding the smokeless capacity of the
flare) require development of FMP (or
revision of an existing plan) to
specifically consider emergency
shutdown and other high load events. In
this FMP, refinery owners or operators
must consider measures that can be
implemented to reduce the frequency
and magnitude of these high-load flaring
events. This may include installation of
a flare gas recovery system.
Additionally, the work practice
standards will require refinery owners
or operators to identify and implement
measures that may involve process
changes. Therefore, we are establishing
a compliance date of 3 years from the
effective date of the final rule for
refinery owners or operators to comply
with the work practice standards for
high load flaring events. We also note
that this compliance period is consistent
with the compliance time provided for
the flare operating limits.
For atmospheric PRD in HAP service
we are establishing a work practice
standard that requires a process hazard
analysis and implementation of a
minimum of three redundant measures
to prevent atmospheric releases.
Alternately, refinery owners or
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
operators may elect to install closed
vent systems to route these PRD to a
flare, drain (for liquid thermal relief
valves) or other control system. We
anticipate that sources will need to
identify the most appropriate preventive
measures or control approach; design,
install and test the system; install
necessary process instrumentation and
safety systems; and may need to time
installations with equipment shutdown
or maintenance outages. Therefore, we
have established a compliance date of 3
years from the effective date of the final
rule for refinery owners or operators to
comply with the work practice
standards for atmospheric PRD.
As proposed, we are requiring
compliance with the electronic
reporting provisions for performance
tests conducted for Refinery MACT 1
and 2 on the effective date of the final
rule.
Finally, we are finalizing additional
requirements for storage vessels under
CAA sections 112(d)(6) and (f)(2) with a
compliance date 90 days after the
effective date of the final rule, as
proposed.
H. What materials are being
incorporated by reference?
In this final rule, the EPA is including
regulatory text that includes
incorporation by reference. In
accordance with requirements of 1 CFR
51.5, the EPA is incorporating by
reference the following documents
described in the amendments to 40 CFR
63.14:
• ASTM D1945–03 (Reapproved
2010), Standard Test Method for
Analysis of Natural Gas by Gas
Chromatography, (Approved January 1,
2010).
• ASTM D1945–14, Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography.
• ASTM D6196–03 (Reapproved
2009), Standard Practice for Selection of
Sorbents, Sampling, and Thermal
Desorption Analysis Procedures for
Volatile Organic Compounds in Air,
(Approved March 1, 2009).
• ASTM D6348–03 (Reapproved
2010), Standard Test Method for
Determination of Gaseous Compounds
by Extractive Direct Interface Fourier
Transform Infrared (FTIR) Spectroscopy,
including Annexes A1 through A8,
(Approved October 1, 2010).
• ASTM D6348–12e1, Standard Test
Method for Determination of Gaseous
Compounds by Extractive Direct
Interface Fourier Transform Infrared
(FTIR) Spectroscopy.
• ASTM D6420–99 (Reapproved
2010), Standard Test Method for
Determination of Gaseous Organic
PO 00000
Frm 00010
Fmt 4701
Sfmt 4700
Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry.
• ASTM UOP539–12, Refinery Gas
Analysis by GC.
• BS EN 14662–4:2005, Ambient air
quality—Standard method for the
measurement of benzene
concentrations—Part 4: Diffusive
sampling followed by thermal
desorption and gas chromatography,
June 27, 2005.
• EPA–454/B–08–002, Quality
Assurance Handbook for Air Pollution
Measurement Systems, Volume IV:
Meteorological Measurements, Version
2.0 (Final), March 2008.
• EPA–454/R–99–005, Meteorological
Monitoring Guidance for Regulatory
Modeling Applications, February 2000.
• ISO 16017–2:2003(E): Indoor,
ambient and workplace air—Sampling
and analysis of volatile organic
compounds by sorbent tube/thermal
desorption/capillary gas
chromatography—Part 2: Diffusive
sampling, May 15, 2003.
• Air Stripping Method (Modified El
Paso Method) for Determination of
Volatile Organic Compound Emissions
from Water Sources’’ Revision Number
One, dated January 2003, Sampling
Procedures Manual, Appendix P:
Cooling Tower Monitoring, prepared by
Texas Commission on Environmental
Quality, January 31, 2003.4
The EPA has made, and will continue
to make, these documents available
electronically through
www.regulations.gov and/or in hard
copy at the appropriate EPA office (see
the ADDRESSES section of this preamble
for more information).
IV. What is the rationale for our final
decisions and amendments to the
Petroleum Refinery NESHAP and
NSPS?
A. Residual Risk Review for the
Petroleum Refinery Source Categories
1. What did we propose pursuant to
CAA section 112(f) for the Petroleum
Refinery source categories?
The results of our residual risk review
for the Petroleum Refinery source
categories were published in the June
30, 2014 proposal at (79 FR 36934
through 36942), and included
assessment of chronic and acute
inhalation risk, as well as multipathway
and environmental risk, to inform our
decisions regarding acceptability and
ample margin of safety. The results
indicated that both the actual and
4 The requirements in § 63.655(i)(5)(iii)(G)
associated with this incorporation by reference have
not changed, but are being modified to properly be
incorporated into § 63.14(s).
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
allowable inhalation cancer risks to the
individual most exposed are no greater
than approximately 100-in-1 million,
which is the presumptive limit of
acceptability. In addition, the maximum
chronic non-cancer target organ-specific
hazard index (TOSHI) due to inhalation
exposures was less than 1. The
evaluation of acute non-cancer risks,
which was conservative, showed acute
risks below a level of concern. Based on
the results of the refined site-specific
multipathway analysis, we also
concluded that the ingestion cancer risk
to the individual most exposed through
ingestion is considerably less than 100in-1 million. In determining risk
acceptability, we also evaluated
population impacts because of the large
number of people living near facilities
in the source category. We estimated
that 5-million people are exposed to
increased cancer risks of greater than 1in-1 million and 100,000 people are
exposed to increased cancer risks of
greater than 10-in-1 million, but, as
noted previously, no individual is
exposed to increased cancer risks of
greater than 100-in-1 million.
Considering the above information, we
proposed that the risks remaining after
implementation of the existing NESHAP
for the Refinery MACT 1 and 2 source
categories is acceptable. However, we
noted that the risks based on allowable
emissions are at the presumptive limit
of acceptable risk, and that a large
number of people are exposed to risks
of greater than 1-in-1 million, and we
solicited comment on whether EPA
should conclude that the risk was
unacceptable based on the health
information before the Agency. We also
proposed that the original Refinery
MACT 1 and 2 MACT standards, along
with the proposed requirements for
storage vessels, provide an ample
margin of safety to protect public health.
Finally, we proposed that it is not
necessary to set a more stringent
standard to prevent, taking into
consideration costs, energy, safety, and
other relevant factors, an adverse
environmental effect.
2. How did the risk review change for
the Petroleum Refinery source
categories?
As part of the final risk assessment,
we conducted a screening level analysis
of how the information we received
during the public comment period,
along with the changes we are making
to the proposed rule, would change our
proposed risk estimates (More details
can be found in the ‘‘Final Residual Risk
Assessment for the Petroleum Refining
Source Sector’’, Docket ID No. EPA–
HQ–OAR–2010–0682).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
First, we received approximately 20
emissions inventory updates for specific
facilities. These updates included
revised emission estimates, revised
release latitude/longitude locations and
other release characteristic revisions.
The updates provided evidence that the
quantity of HAP emitted at these
specific facilities is lower than
considered in the risk modeling for the
proposed rule. Our assessment of the
effects of these changes suggests that the
cancer maximum individual risk (MIR)
based on actual emissions may be closer
to 40-in-1 million, as opposed to 60-in1 million, as projected at proposal. We
did not quantify the reductions in
chronic or acute non-cancer risks from
these updates. We calculated allowable
emissions using the Refinery Emissions
Model (REM), which estimates
emissions based on each refinery’s
capacities and throughputs [See
discussion at 79 FR 36888, June 30,
2014.] The allowable emission estimates
for point and fugitive sources were not
specific to a particular latitude/
longitude location so we assumed them
to release from the centroid of the
facility. Therefore, the predicted cancer
MIR of approximately 100-in-1 million
based on allowable emissions and
reported in the proposal risk
characterization does not change based
on the submitted emissions revisions.
We did not quantify changes to other
actual risk metrics as part of the
screening level analysis (i.e., incidence,
populations in risk bins, multipathway
and ecological analyses), but we would
expect some minor reductions from
those presented in the proposed risk
characterization.
Second, we are establishing work
practice standards in the final rule for
PRD releases and emergency flaring
events, which under the proposed rule
would not have been allowed. Thus,
because we did not consider such nonroutine emissions under our risk
evaluation for the proposed rule, we
performed a screening assessment of
risk associated with these non-routine
events for the final rule. [We provide
further details on the screening
approach in ‘‘Final Residual Risk
Assessment for the Petroleum Refining
Source Sector’’ in Docket ID No. EPA–
HQ–OAR–2010–0682.] We extracted
information on these events from the
2011 Petroleum Refinery ICR data that
included the process unit identification,
mass of emissions, duration of release,
and description of the incident. We
identified the highest HAP mass
releases for both PRDs and flares from
these non-routine events. We assumed
these HAP emission releases could
PO 00000
Frm 00011
Fmt 4701
Sfmt 4700
75187
occur at any facility in the source
category. Our analysis suggests that
these HAP emissions could increase the
MIR based on actual emissions by as
much as 2-in-1 million. Because the
PRD and flaring events were the worst
case HAP mass emission release events
reported in the 2011 Refinery ICR for
the source category, we are assuming
that actual and allowable risks are no
different for these events (i.e., a MIR of
2-in-1 million). A MIR increase of 2-in1 million attributable to these events,
added to our previous estimate for
allowable risk at proposal will not
appreciably change our proposed
determination that the MIR based on
allowable emissions are approximately
100-in-1 million. We note that the MIR
estimate attributable to these nonroutine PRD and flaring events was
estimated using a conservative,
screening-level assessment, while the
MIR estimate at proposal was based on
a refined risk assessment. By adding a
screening estimate to a refined risk
estimate, we are merely defining an
upper limit that we expect the
combined risks from both the routine
and non-routine emissions to be.
Similarly, we estimate chronic noncancer hazard index (HI) values
attributable to the additional exposures
resulting from non-routine flaring and
PRD HAP emissions to be well below 1
(HIimmune-system of 0.007) such that there
is no appreciable change in the
maximum chronic non-cancer HI of 0.9
estimated at proposal for routine
emissions, which was based on
neurological effects.
The screening analysis projects that
the maximum predicted acute noncancer risk from non-routine PRD and
flare emissions results in a hazard
quotient (HQ) based on a recommended
reference exposure level limit (REL) of
up to 14 from benzene emissions. While
the analysis shows that there is a
potential for HQs exceeding 1 for
benzene, because of the many
uncertainties and conservative nature of
this screening analysis, the likelihood of
such exposure and risk are low. At
proposal, we projected a HQ based on
the REL for benzene of up to 2 from
routine emissions. If we conservatively
combine the routine and non-routine
emissions analyses, we would expect
the potential for HQs based on the REL
for benzene to have the potential to
increase above 2. However, as projected
at proposal, we estimate that the acute
HQs calculated using acute exposure
guideline levels (AEGL) and emergency
response and planning guidelines
(ERPG) values for all pollutants
including benzene would still be well
E:\FR\FM\01DER2.SGM
01DER2
75188
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
below 1 considering both routine and
non-routine emissions.
Considering all of these factors, we do
not project risks to be significantly
different from what we proposed. Based
on the risk analysis, as informed by the
screening level analysis based on
information obtained during the
comment period, we are finalizing our
determination that the risk remaining
after promulgation of the NESHAP is
acceptable.
3. What key comments did we receive
on the risk review and what are our
responses?
We received numerous comments on
the residual risk assessment analyses
and results. We summarize the key
comments received below, along with
our responses. A complete summary of
all public comments received and our
responses are in the ‘‘Response to
Comment’’ Document in the public
docket (Docket ID No. EPA–HQ–OAR–
2010–0682).
Comment: Several commenters agreed
that the EPA has correctly concluded
that the proposed rule requirements
protect the public with an ample margin
of safety from refinery emissions. Other
commenters noted that EPA found
residual risks remaining after
implementation of the MACT standards
to be acceptable, and in light of the
acceptability determination argued that
the proposed changes to the rule are not
justified. The commenters noted that the
EPA’s detailed emissions inventory
assessment and risk modeling results
demonstrated that, at every U.S.
refinery, category-specific risks are
below the EPA’s presumptive limit of
acceptable risk (i.e., cancer risk of less
than 100-in-1 million).
Other commenters stated the EPA’s
risk estimates are understated and that
the EPA should reduce the benchmark
of what it considers acceptable lifetime
cancer risk instead of the upper limit of
100-in-1 million. One commenter
provided an extensive critique of the
cancer, chronic and acute affects levels
used in the risk assessment and
recommended that the EPA use
California Office of Environmental
Health Hazard Assessment’s (OEHHA)
new toxicity values for several
chemicals. The commenter provided
some references for the approaches used
to derive the California values. The
commenter also asserted that risks
would be unacceptable had these more
protective values been used in the risk
assessment. Some commenters stated
the risks from petroleum refinery
emissions are underestimated because
the EPA did not but should have
included interaction of multiple
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
pollutants, accounted for exposure to
multiple sources, and assessed the
cumulative risks from facility-wide
emissions and multiple nearby sources
impacting an area.
Response: The approximately 100-in1 million benchmark was established in
the Benzene NESHAP (54 FR 38044,
September 14, 1989), which Congress
specifically referenced in CAA section
112(f)(2)(B). While this presumptive
level provides a benchmark for judging
the acceptability of MIR, it is important
to recognize that it does not constitute
a rigid line for making that
determination. The EPA considers the
specific uncertainties of the emissions,
health effects and risk information for
the source category in question when
deciding whether the risk posed by that
source category is acceptable. In
addition, the source category-specific
decision of what constitutes an
acceptable level of risk is a holistic one;
that is, the EPA considers all potential
health impacts—chronic and acute,
cancer and non-cancer, and
multipathway—along with their
uncertainties, when determining
whether the source category presents an
unacceptable risk.
Regarding the comment that in light
of the acceptability determination the
proposed changes to the rule are not
justified, we note that we also are
required to ensure that the standards
provide an ample margin of safety to
protect public health. That analysis is
separate from the acceptability analysis,
and the determination of acceptability
does not automatically lead us to
conclude that the standards provide an
ample margin of safety to protect public
health.
Regarding the comments that the EPA
should use the new California OEHHA
values, we disagree. The EPA’s
chemical-specific toxicity values are
derived using risk assessment
guidelines and approaches that are well
established and vetted through the
scientific community, and follow
rigorous peer review processes.5 The
RTR program gives preference to the
EPA values for use in risk assessments
and uses other values, as appropriate,
when those values are derived with
methods and peer review processes
consistent with those followed by the
EPA. The approach for selecting
appropriate toxicity values for use in the
RTR Program has been endorsed by the
Science Advisory Board (SAB).6
5 Integrated Risk Information System (IRIS). IRIS
Guidance documents available at https://www.epa.
gov/iris/backgrd.html.
6 https://yosemite.epa.gov/sab/sabproduct.nsf/0/
b031ddf79cffded38525734f00649caf!Open
Document&TableRow=2.3#2.
PO 00000
Frm 00012
Fmt 4701
Sfmt 4700
The EPA scientists reviewed the
information provided by the commenter
regarding the California values and
concluded that further information is
needed to evaluate the scientific basis
and rationale for the recent changes in
California OEHHA risk assessment
methods. The EPA will work on
gathering the necessary information to
conduct an evaluation of the scientific
merit and the appropriateness of the use
of California OEHHA’s new toxicity
values in the agency decisions. Until the
EPA has completed its evaluation, it is
premature to determine what role these
values might play in the RTR process.
Therefore, the EPA did not use the new
California OEHHA toxicity values as
part of this current action. For more
detailed responses regarding
appropriate reference values for specific
pollutants, see the ‘‘Response to
Comment’’ document in the public
docket (Docket ID No. EPA–HQ–OAR–
2010–0682).
Concerning comments that we should
consider aggregate risks from multiple
pollutants and sources, we note that we
have done this to the extent it is
appropriate to do so. We modeled
whole-facility risks for both chronic
cancer and non-cancer impacts to
understand the risk contribution of the
sources within the Petroleum Refinery
source categories. The individual cancer
risks for the source categories were
aggregated for all carcinogens. In
assessing non-cancer hazard from
chronic exposures to pollutants that
have similar modes of action or (where
this information is absent) that affect the
same target organ, we summed the HQs.
This process creates, for each target
organ, a TOSHI, defined as the sum of
HQs for individual HAP that affect the
same organ or organ system. Wholefacility risks were estimated based on
the 2011 ICR emissions data obtained
from facilities, which included
emissions from all sources at the
refinery, not just Refinery MACT 1 and
2 emission sources (e.g., emissions were
included for combustion units and units
subject to the Hazardous Organic
NESHAP, if present at the refinery). We
disagree with the commenter’s assertion
that additional quantitative assessment
of risks from sources outside the source
category is required under the statute.
The statute requires the EPA to provide
the quantitative risk information
necessary to inform RTR regulatory
decisions, and to this end, the EPA
conducted a comprehensive assessment
of the risks associated with exposure to
the HAP emitted by the source category
and supplemented that with additional
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
information available about other
possible concurrent and relevant risks.
Further, the risk assessment modeling
accounts for the effects of multiple
facilities that may be in close proximity
when estimating concentration and risk
impacts at each block centroid. When
evaluating the risks associated with a
particular source category, we combined
the impacts of all facilities within the
same source category and assessed
chronic exposure and risk for all census
blocks with at least one resident (i.e.,
locations where people may reasonably
be assumed to reside). The MIR
considers the combined impacts of all
sources in the category that may be in
close proximity (i.e., cumulative impact
of all refineries).
Comment: Several commenters stated
that the EPA underestimated exposure
because emissions are underreported
and underestimated. The commenters
noted that for the risk assessment for the
refineries rule, the EPA evaluated (1) the
emissions reported to the agency
pursuant to the 2011 Petroleum Refinery
ICR as sources’ ‘‘actual’’ emissions, and
(2) the emissions the EPA estimates that
the existing standards currently allow
sources to emit using the REM, which
it describes as ‘‘allowable’’ emissions.
According to the commenters, both the
EPA’s ‘‘actual’’ and ‘‘allowable’’
emissions data sets are incomplete and
undercount emissions, causing the EPA
to significantly underestimate the
resulting risk in its risk analysis. For
example, the commenters noted that the
EPA assumed the flare destruction
efficiency to be 98 percent, while the
EPA’s own estimates suggest flare
efficiency is 93.9 percent. The
commenters also noted that the EPA has
further understated risks by ignoring
emissions during unplanned SSM
events and by ignoring HAP for which
no reference values are established. One
commenter cited the TCEQ Emissions
Event Database as evidence that SSM
emissions are a severe public health
problem because data show that nearly
1 million pounds of HAP are reported
from Texas refineries between 2009 and
2013. According to these commenters,
the EPA needs to adopt standards that
provide greater protection, including
protection from the risks of accidents.
Response: We used the best and most
robust facility-specific HAP emissions
inventory available to us, which was the
2011 ICR, in performing the analysis for
the proposed rule. We conducted a
thorough and exhaustive review of the
data submitted through the ICR and we
followed up on source-specific
information on a facility-by-facility
basis, as documented in the ‘‘Emissions
Data Quality Memorandum and
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Development of the Risk Model Input
File’’ (see Docket ID No. EPA–HQ–
OAR–2010–0682–0076). In addition, we
took steps ahead of issuing the 2011 ICR
to make sure that facilities could, as
accurately as practicable, estimate their
HAP emissions for purposes of
responding to the inventory portion of
that ICR. We prepared a Refinery
Protocol to provide guidance to refinery
owners or operators to use the best
available, site-specific data when
developing their emissions inventory, to
ensure all emission sources are included
in the inventory, and to have a
consistent set of emission factors that all
respondents use if no site-specific
emissions data were available. If sitespecific emissions data were available,
sites were to use these data
preferentially over the default factors.
We developed the default factors
provided in the protocol from the best
data available at the time.
The ICR-submitted information for
allowable emissions did not include
emission estimates for all HAP and all
emission sources. Consequently, we
used the REM to estimate allowable
emissions. The REM relies on model
plants that vary based on throughput
capacity. Each model plant contains
process-specific default emission
factors, adjusted for compliance with
the Refinery MACT 1 and 2 emission
standards.
We agree with the commenters that
studies have shown that many refinery
flares are operating less efficiently than
98 percent. Prior to proposing this rule,
we conducted a flare ad hoc peer review
to advise the EPA on factors affecting
flare performance (see discussion in the
June 30, 2014, proposal at 79 FR 36905).
However, we disagree with the
commenters that the risk analysis
should consider this level of
performance since the existing MACT
standard does not allow it. For purposes
of the risk analysis, we evaluate whether
it is necessary to tighten the existing
MACT standard in order to provide an
ample margin of safety. Thus, in
reviewing whether the existing
standards provide an ample margin of
safety, we review the level of emissions
the MACT standards allow. In the
present case, we considered the level of
performance assumed in establishing
the MACT standard for purposes of
determining whether the MACT
standard provides an ample margin of
safety. However, we did recognize that
facilities were experiencing
performance issues with flares and that
many flares were not meeting the
assumed performance level at the time
we promulgated the MACT standard.
Thus, we proposed, and are finalizing,
PO 00000
Frm 00013
Fmt 4701
Sfmt 4700
75189
revisions to the flare operating
requirements to ensure that the flares
meet the required performance level.
These provisions are consistent with the
EPA’s goals to improve the effectiveness
of our rules.
Similarly, we do not include startup,
shutdown (including maintenance
events) and malfunction emissions that
are not allowed under the standard as
part of our evaluation of whether the
standards provide an ample margin of
safety. Regarding the HAP emissions
from SSM events that the commenter is
concerned with, we note that our review
of the TCEQ incident database indicates
that many of the large reported release
events were of SO2 emissions and only
a few had significant HAP emissions.
Because in the final rule we are
establishing work practice standards for
PRD and emergency flaring events, we
performed a screening-level risk
analysis to address changes in facility
HAP emission releases due to these
events. Details on this analysis are
presented in the final risk report for the
source category (For more details see
Appendix 13 of the ‘‘Final Residual Risk
Assessment for the Petroleum Refining
Source Sector,’’ Docket ID No. EPA–
HQ–OAR–2010–0682).
As for HAP with no reference value,
the SAB addressed this issue in its May
7, 2010, response to the EPA
Administrator. In that response, the
SAB Panel recommended that, for HAP
that do not have dose-response values
from the EPA’s list, the EPA should
consider and use, as appropriate,
additional sources for such values that
have undergone adequate and rigorous
scientific peer review. The SAB panel
further recommended that the inclusion
of additional sources of dose-response
values into the EPA’s list should be
adequately documented in a transparent
manner in any residual risk assessment
case study. We agree with this approach
and have considered other sources of
dose-response data when conducting
our risk determinations under RTR.
However, in some instances no sources
of information beyond the EPA’s list are
available. Compounds without health
benchmarks are typically those without
significant health effects compared to
compounds with health benchmarks,
and in such cases we assume these
compounds will have a negligible
contribution to the overall health risks
from the source category. A tabular
summary of HAPs that have dose
response values for which an exposure
assessment was conducted is presented
in Table 3.1–1 of the ‘‘Final Residual
Risk Assessment for the Petroleum
Refining Source Sector’’, Docket ID No.
EPA–HQ–OAR–2010–0682.
E:\FR\FM\01DER2.SGM
01DER2
75190
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
Comment: A few commenters asserted
that the EPA should decide that it is
unjust and inconsistent with the CAA’s
health protection purpose to allow the
high health risks caused by refineries to
fall disproportionately on communities
of color and lower income communities
who are least equipped to deal with the
resulting health effects. Because of that
disparity, the commenter stated that the
EPA should recognize that the risks
found are unacceptable and set stronger
national standards for all exposed
Americans.
Response: For this rulemaking, the
EPA conducted both pre- and postcontrol risk-based assessments with
analysis of various socio-economic
factors for populations living near
petroleum refineries (see Docket ID Nos.
EPA–HQ–OAR–2010–0682–0226 and
–0227) and determined that there are
more African-Americans, Other and
multiracial groups, Hispanics, lowincome individuals, and individuals
with less than a high school diploma
compared to national averages. In
determining the need for tighter residual
risk standards, the EPA strives to limit
to no higher than 100-in-1 million the
estimated cancer risk for persons living
near a plant if exposed to the maximum
pollutant concentration for 70 years and
to protect the greatest number of
persons to an individual lifetime risk of
no higher than 1-in-1 million. Although
we consider the risk for all people
regardless of racial or socioeconomic
status, communities near petroleum
refineries will particularly benefit from
the risk reductions associated with this
rule. In particular, as discussed later,
the fenceline monitoring work practice
standard will be a further improvement
in the way fugitive emissions are
managed and will provide an extra
measure of protection for surrounding
communities.
4. What is the rationale for our final
decisions for the risk review?
As described in section IV.A.2 of this
preamble, we performed a screeninglevel analysis to assess the risks
associated with inventory updates we
received for specific facilities and with
emissions events that were previously
not included in the risk assessment
because the proposed rule did not allow
them. Because we are finalizing work
practice standards to regulate emission
events associated with PRD releases and
emergency flaring, we considered the
effect these work practice standards
would have on risks. As discussed in
section IV.A.2 of this preamble, we
project that accounting for these
emergency events in the baseline risks
after implementation of the MACT
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
standards does not appreciably change
the risks, and at most, could increase
the proposed rule estimate of MIR by
approximately 2-in-1 million. Therefore,
we would project that any controls
applied to these emergency events,
including the work practice standards
for PRDs and emergency flaring in this
final rule, would not appreciably change
the proposed post-control risks.
Although we would anticipate minimal
additional risk reductions, we reviewed
more stringent alternatives to the work
practice standards for PRD releases and
emergency flaring events included in
this final rule, and we found that the
costs of increasing flare capacity to
control all PRD releases and to eliminate
all visible emissions during emergency
flaring were too high. We estimate the
capital costs of applying the velocity
and visible emissions limit at all times
would be approximately $3 billion, and
we estimate that the costs of controlling
all PRD releases with flares would be
approximately $300 million. [See the
discussion in the ‘‘Flare Control Option
Impacts for Final Refinery Sector Rule’’,
Docket ID No. EPA–HQ–OAR–2010–
0682 and the PRD work practice
standard discussion in section IV.C of
this preamble.] Further, we did not
receive comments on additional control
technologies that we should have
considered for other emission sources
(e.g., tanks, DCUs) beyond those
considered and described at proposal.
Consequently, as discussed in section
IV.A.2, we conclude that the risks from
the Petroleum Refinery source
categories are acceptable and that, with
the additional requirements for storage
vessels that we are finalizing, as
proposed, the Refinery MACT 1 and 2
rules provide an ample margin of safety
to protect public health. We also
maintain, based on the rationale
presented in the preamble to the
proposed rule, that the current
standards prevent, taking into
consideration costs, energy, safety and
other relevant factors, an adverse
environmental effect.
B. Technology Review for the Petroleum
Refinery Source Categories
1. What did we propose pursuant to
CAA section 112(d)(6) for the Refinery
MACT 1 (40 CFR part 63, subpart CC)
source category?
The results of our technology review
for the Petroleum Refinery source
categories were published in the June
30, 2014, proposal at (79 FR 36913
through 36928). The technology review
was conducted for both MACT source
categories as described below.
PO 00000
Frm 00014
Fmt 4701
Sfmt 4700
a. Refinery MACT 1
Refinery MACT 1 sources include
MPV, storage vessels, equipment leaks,
gasoline loading racks, marine vessel
loading operations, cooling towers/heat
exchange systems and wastewater.
Based on technology reviews for the
sources described above, we proposed
that it was not necessary to revise
Refinery MACT 1 requirements for
MPV, gasoline loading racks, cooling
towers/heat exchange systems, and
wastewater. For storage vessels, we
proposed revisions pursuant to the
technology review. Specifically, we
proposed to cross-reference the storage
vessel requirements in the Generic
MACT (40 CFR part 63, subpart WW) to
require controls on floating roof fittings
(e.g., guidepoles, ladder wells and
access hatches) and to revise the
definition of Group 1 storage vessels to
include smaller tanks with lower vapor
pressures. For equipment leaks, we
proposed to allow refineries to meet
LDAR requirements in Refinery MACT
1 by monitoring for leaks via optical gas
imaging in place of the EPA Method 21,
using monitoring requirements to be
specified in a not-yet-proposed
appendix K to 40 CFR part 60. For
marine vessel loading, we proposed to
amend the Marine Tank Vessel Loading
Operations MACT standards (40 CFR
part 63, subpart Y) to require small
marine vessel loading operations (i.e.,
operations with HAP emissions less
than 10/25 tpy) and offshore marine
vessel loading operations at petroleum
refineries to use submerged filling based
on the cargo filling line requirements in
46 CFR 153.282.
We also proposed an additional work
practice standard under the technology
review to manage fugitive emissions
from the entire petroleum refinery
through a fenceline monitoring and
corrective action standard. As part of
the work practice standard, we specified
the monitoring technology and
approach that must be used, and we
developed a fenceline benzene
concentration action level above which
refinery owners or operators would be
required to implement corrective action
to reduce their fenceline concentration
to below this action level. The action
level we proposed was consistent with
the emissions projected from fugitive
sources compliant with the provisions
of the refinery MACT standards as
modified by the additional controls
proposed for storage vessels.
b. Refinery MACT 2
The Refinery MACT 2 source category
regulates HAP emissions from FCCU,
CRU and SRU process vents. We
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
proposed to revise Refinery MACT 2 to
incorporate the developments in
monitoring practices and control
technologies reflected in Refinery NSPS
subpart Ja (73 FR 35838). This included
proposing to incorporate the Refinery
NSPS subpart Ja PM limit for new FCCU
sources and to revise the monitoring
provisions in Refinery MACT 2 to
require all FCCU sources to meet
operating limits consistent with the
requirements in Refinery NSPS subpart
Ja. The existing MACT standard
provided that a refiner could
demonstrate compliance with the PM
limit in the MACT by meeting the 30percent opacity limit requirement of
Refinery NSPS subpart J; we proposed
to eliminate that provision and instead
establish control device operating limits
or site-specific opacity limits similar to
those required in Refinery NSPS subpart
Ja. We also proposed to incorporate the
use of 3-hour averages rather than daily
averages for monitoring data to
demonstrate compliance with the FCCU
site-specific opacity and Ni operating
limits. We proposed additional control
device-specific monitoring alternatives
for various control devices on FCCU,
including BLD monitoring as an option
to COMs for owners or operators of
FCCU using fabric filter-type control
systems, and total power and secondary
current operating limits for owners or
operators of ESPs. We also proposed to
add a requirement to perform daily
checks of the air or water pressure to
atomizing spray nozzles for owners or
operators of FCC wet gas scrubbers.
Finally, we proposed to require a
performance test once every 5 years for
all FCCU in place of the one-time
performance test required by the current
Refinery MACT 2.
At proposal, we did not identify any
developments in practices, processes
and control technologies for CRU
process vents based on our technology
review. For SRU, we proposed to
include the Refinery NSPS subpart Ja
allowance for oxygen-enriched air as a
development in practice and to allow
SRU to comply with Refinery NSPS
subpart Ja as a means of complying with
Refinery MACT 2.
tkelley on DSK3SPTVN1PROD with RULES2
2. How did the technology review
change for the Petroleum Refinery
source categories?
a. Refinery MACT 1
We are finalizing most of our
technology review decisions for
Refinery MACT 1 emissions sources as
proposed; however, as described briefly
below, we are revising certain proposed
requirements.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
We are not taking final action
adopting the use of appendix K to 40
CFR part 60 for optical gas imaging for
refinery equipment subject to the LDAR
requirements in Refinery MACT 1
because we have not yet proposed
appendix K.
After considering the public
comments, we are finalizing the
proposed fenceline monitoring
requirements, with a few revisions.
First, we have made numerous
clarifications in this final rule to the
language for the fenceline monitoring
siting method and analytical method
(i.e., Methods 325 A and B,
respectively). Specific comments on
these methods, along with our responses
and explanations of the revisions to the
regulatory text are discussed in the
‘‘Response to Comment’’ document.
Second, we are finalizing a revised
compliance schedule for fenceline
monitoring, which will require refinery
owners or operators to have the
fenceline monitors in place and
collecting benzene concentration data
no later than 2 years from the effective
date of the final rule, as opposed to 3
years in the proposed rule. Third, we
have removed the requirement for
refinery owners or operators to obtain
the EPA approval for the corrective
action plan. Fourth, we are requiring the
submittal of the fenceline monitoring
data on a quarterly basis, as opposed to
on a semiannual basis as proposed.
Fifth, we are providing guidelines for
operators to use in requesting use of an
alternative fenceline monitoring
technology to the passive sorbent
samplers set forth in Method 325B.
Finally, to reduce the burden of
monitoring, we are finalizing provisions
that would allow refinery owners or
operators to reduce the frequency of
fenceline monitoring for areas that
consistently stay well below the
fenceline benzene concentration action
level. Specifically, we are allowing
refinery owners or operators to monitor
every other two weeks (i.e., skip period
monitoring) if over a two-year period,
each sample collected at a specific
monitoring location is at or below 0.9
mg/m3. If every sample collected from
that sampling location during the
subsequent 2-years is at or below 0.9 mg/
m3, the monitoring frequency may be
reduced from every other two weeks to
quarterly. After an additional two years,
the monitoring can be reduced to
semiannually and finally to annually,
provided the samples continue to be at
or below 0.9 mg/m3 during all sampling
events at that location. If at any time a
sample for a monitoring location that is
monitored at a reduced frequency
PO 00000
Frm 00015
Fmt 4701
Sfmt 4700
75191
returns a concentration greater than 0.9
mg/m3, the owner or operator must
return to the original sampling
requirements for one quarter (monitor
every two weeks for the next six
monitoring periods for that location); if
every sample collected from this quarter
is at or below 0.9 ug/m3, then the
sampling frequency reverts back to the
reduced monitoring frequency for that
monitoring location; if not then the
sampling frequency reverts back to the
original biweekly monitoring frequency.
b. Refinery MACT 2
We are finalizing, as proposed, our
determination that it is not necessary to
revise the requirements for CRU
pursuant to the technology review and
we are finalizing our determination that
it is necessary to revise the MACT for
SRU and FCCU. For SRU, we are
finalizing the revisions as proposed. For
FCCU, we are making modifications to
the proposed requirements in light of
public comment.
As discussed previously, we proposed
to remove the alternative in Refinery
MACT 2 for owners or operators to
demonstrate compliance with the PM
limits on FCCU by meeting a 30-percent
opacity standard as provided in
Refinery NSPS subpart J and instead
make the FCCU operating limits in
Refinery MACT 2 consistent with
Refinery NSPS subpart Ja. Based on the
Refinery NSPS subpart J review in 2008,
we determined that a 30-percent opacity
limit does not adequately assure
compliance with the PM emissions limit
(see discussion in the proposed rule at
79 FR 36929, June 30, 2014). Thus, we
included other monitoring approaches
in Refinery NSPS subpart Ja.
Comments received on this proposal,
along with data available to the Agency,
confirmed that the 30-percent opacity
standard is not adequate on its own to
demonstrate compliance with the PM
(or metal HAP) emissions limit in
Refinery MACT 2. We also received
comments that the site-specific opacity
alternative, which is the only
compliance option proposed for FCCU
with tertiary cyclones, would essentially
require owners or operators with these
FCCU configurations to meet an opacity
limit of 10-percent. According to
commenters, opacity increases with
decreasing particle size, so that it is
common to exceed 10-percent opacity
during soot blowing or other similar
events that produce very fine
particulates even though mass
emissions have not changed
appreciably.
Based on the available data, we have
determined that a 20-percent opacity
operating limit is well correlated with
E:\FR\FM\01DER2.SGM
01DER2
75192
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
facilities meeting a limit of 1.0 lb PM/
1,000 lbs coke burn-off. Therefore, we
are retaining the option in Refinery
MACT 2 to comply with Refinery NSPS
subpart J except we are adding a 20percent opacity operating limit in
Refinery MACT 2, evaluated on a 3-hour
basis. To ensure that FCCU owners or
operators complying with the Refinery
NSPS subpart J option can meet the 1.0
lb PM/1,000 lbs emissions limit at all
times, we are finalizing requirements
that owners or operators conduct the
performance test during higher PM
periods, such as soot blowing. Where
the PM emissions are within 80-percent
of the PM limit during any periodic
performance test, we are requiring the
refinery owner or operator to conduct
subsequent performance tests on an
annual basis instead of on a 5-year basis.
We are finalizing our proposed
requirement that compliance with the
control device operating limits in the
other compliance alternatives be
demonstrated on a 3-hour basis, instead
of the 24-hour basis currently allowed
in Refinery MACT 2.
3. What key comments did we receive
on the technology review, and what are
our responses?
a. Refinery MACT 1
The majority of comments received
regarding the proposed amendments to
Refinery MACT 1 pursuant to our
technology review dealt with the
proposed fenceline monitoring
requirements. The primary comments
on the fenceline monitoring
requirements are in this section along
with our responses. Comment
summaries and the EPA’s responses for
additional issues raised regarding the
proposed requirements resulting from
our technology review are in the
‘‘Response to Comment’’ document in
the public docket (Docket ID No. EPA–
HQ–OAR–2010–0682).
tkelley on DSK3SPTVN1PROD with RULES2
i. Legal Authority and Need for
Fenceline Monitoring
Comment: Numerous commenters
claimed that the proposed fenceline
monitoring program would unlawfully
impose what is effectively an ambient
air quality standard for benzene, which
is not authorized by CAA section 112,
which only authorizes the control of
emission sources. The commenters
argued it is an ambient standard because
sources are required to meet the
benzene level set or ‘‘perform injunctive
relief which may or may not address the
source of the benzene.’’ The commenter
quoted language from the proposal as
support that EPA has described the
benzene level as an ambient standard:
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
‘‘We are proposing a HAP concentration
to be measured in the ambient air
around a refinery, that if exceeded,
would trigger corrective action to
minimize fugitive emissions.’’ 79 FR at
36920 (June 30, 2014). The commenter
further noted that this requirement is
not just ‘‘monitoring’’ because it
establishes a ‘‘not-to-be exceeded’’ level.
Therefore, the commenters stated, the
EPA should not finalize this portion of
the proposal.
Response: We disagree with the
comment that the fenceline proposal is
an ambient air standard. First, the
owner or operator must place the
monitors on the facility fenceline to
measure emissions from the facility, i.e.,
on the property of the refiner. While we
recognize that we used the term
‘‘ambient air’’ in the preamble to the
proposal, we note that the placement
requirements for the monitors make
clear that the monitors are not
monitoring ambient air, which EPA has
defined at 40 CFR 50.1(e) as ‘‘that
portion of the atmosphere, external to
buildings, to which the general public
has access.’’ Second, the proposed EPA
Method 325A sets out procedures to
subtract background concentrations and
contributions to the fenceline benzene
concentrations from non-refinery
emission sources, so that the benzene
concentrations measured are
attributable to the refinery. In other
words, the fenceline monitoring work
practice standard uses a benzene
concentration difference, referred to as
the DC (essentially an upwind and
downwind concentration difference) to
isolate the refinery’s emissions
contribution.
Furthermore, we disagree that the fact
that refiners are required to perform
corrective action if the fenceline
benzene concentration action level is
exceeded makes the benzene action
level an ambient standard. As an initial
matter sources are not directly
responsible for demonstrating that an
area is meeting an ambient standard;
rather that burden falls on states. See
e.g., CAA section 110(a)(2). Moreover,
the ‘‘corrective action’’ is simply that
sources must ensure that fugitive
emission sources on the property are not
emitting HAP at levels that will result
in exceedances of the fenceline benzene
concentration action level. In other
words, the purpose of the fenceline
monitoring work practice is to ensure
that sources are limiting HAP emissions
at the fenceline, which are solely
attributable to emissions from sources
within the facility. In fact, the fenceline
benzene concentration action level was
established using emissions inventories
reported by the facilities, assuming
PO 00000
Frm 00016
Fmt 4701
Sfmt 4700
compliance with the MACT standards.
Finally, monitoring is conducted as part
of the work practice standard to identify
sources that will require additional
controls to reduce their impact on the
fenceline benzene concentration. In that
sense, the fenceline monitoring work
practice standard is not different than,
for example, our MACT standard for
refinery heat exchangers. If a facility is
exceeding the relevant cooling water
pollutant concentration ‘‘level’’ when it
performs a periodic test, it must
undertake corrective action to bring the
concentration down below the action
level.
Comment: Several commenters noted
that EPA’s authority under section
112(d) is to set ‘‘emissions standards’’
and quoted the CAA definition of that
term: ‘‘A requirement . . . which limits
the quantity, rate, or concentration of
emissions of air pollutants on a
continuous basis, including any
requirement relating to the operation or
maintenance of a source to assure
continuous emission reduction, and any
design, equipment, work practice or
operational standard promulgated under
this Act.’’ 42 U.S.C. 7602(k). The
commenters argued that the proposed
fenceline monitoring standard does not
meet this definition because it would
not ‘‘limit the quantity, rate, or
concentration of emissions’’ from any
given emissions point. Also, the
commenters claimed that the EPA did
not designate fenceline monitoring as a
work practice under CAA section 112(h)
since the EPA did not even mention
CAA section 112(h), nor did it conduct
any analysis to show that fenceline
monitoring meets the CAA section
112(h) factors.
Response: We disagree with the
commenters’ assertion that the proposed
fenceline monitoring work practice
standard is not authorized under CAA
section 112(d)(6). Contrary to the
commenter’s claims, we specifically
proposed the fenceline monitoring
standard under CAA section 112(d)(6) to
be a work practice standard that is
applied broadly to fugitive emissions
sources located at petroleum refineries.
As discussed above, the proposed
standard does more than impose
monitoring as some commenters
suggested; it also will limit emissions
from refineries because it requires the
owner or operator to identify and reduce
HAP emissions through a monitoring
and repair program, as do many work
practice standards authorized under
CAA Section 112(h) and 112(d).
We note that the sources addressed by
the fenceline monitoring standard—
refinery fugitive emissions sources such
as wastewater collection and treatment
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
operations, equipment leaks, heat
exchange systems and storage vessels in
the Refinery MACT 1 rule—are already
subject to work practice standards. Our
review of these requirements indicates
that this fenceline monitoring work
practice standard would be a further
improvement in the way fugitive
emissions are managed and would
provide an extra measure of protection
for surrounding communities. The
commenter claims EPA did not analyze
how the fenceline monitoring
requirement meets the criteria in section
112(h). However, that is a
misinterpretation of how the criteria
apply. The criteria are assessed with
regard to whether it is feasible to
‘‘prescribe or enforce an emission
standard for a source’’, and do not apply
to the work practice standard.
Consistent with the criteria in section
112(h)(2), we determined and
established that work practice standards
are appropriate for these Refinery
MACT fugitive emissions at the time we
established the initial MACT standard.
In the proposal, (79 FR at 36919, June
30, 2014), we reaffirmed that it is
impracticable to directly measure
fugitive emission sources at refineries
but did not consider it necessary to
reiterate these findings as part of this
proposal to revise the existing MACT for
these sources under CAA section
112(d)(6). We note that the commenters
do not provide any grounds to support
a reevaluation of whether these fugitive
emission sources are appropriately
regulated by a work practice standard.
Comment: Several commenters
questioned the EPA’s authority under
the CAA to promulgate a rule that
amounts to an ongoing information
gathering and reporting obligation. The
commenters stated that the EPA has not
demonstrated that the proposed
fenceline monitoring program
represents an actual emission reduction
technology improvement. A commenter
stated that compliance assurance
methods, including monitoring, for
fugitive emissions and other emission
standards are established as part of the
emission standard and EPA’s authority
to gather information that is not directly
required for compliance with a specific
standard but is related to air emissions
is found in CAA section 114. Under
CAA section 114, the requirement must
be related to one of the stated purposes
and must be reasonable. The commenter
did not believe that the EPA has
demonstrated that the costs of fenceline
monitoring are reasonable in light of the
information already available to the EPA
and in light of many other means by
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
which the EPA could obtain such
information.
Response: We disagree with the
commenters’ assertion that the authority
for the fenceline monitoring
requirement falls under CAA section
114 and not CAA section 112(d) because
it is an ‘‘ongoing information gathering
and reporting obligation.’’ The issue
here is not whether EPA could have
required the fenceline monitoring
requirement under CAA section 114, but
rather did EPA support that it was a
development in processes practices or
controls technology under section
112(d)(6).
As an initial matter, we disagree with
the commenters’ characterization of the
fenceline monitoring standard as ‘‘an
information gathering and reporting
obligation.’’ We have repeatedly stated
that we consider the fenceline
monitoring requirement to be a work
practice standard that will ensure
sources take corrective action if
monitored benzene levels (as a surrogate
for HAP emissions from fugitive
emissions sources) exceed the fenceline
benzene concentration action level. The
standard requires refinery owners or
operators to monitor the benzene
concentration at the refinery perimeter,
to evaluate the refinery’s contribution as
estimated by taking the concentration
difference between the highest and
lowest concentrations (DC) in each
period, and to conduct root cause
analysis and take corrective action to
minimize emissions if the concentration
difference is higher (on an annual
average) than the benzene concentration
action level. Thus, the fenceline
monitoring requirement goes well
beyond ‘‘information gathering and
reporting.’’
In addition, the commenters again
read section 112(d)(6) too narrowly by
suggesting that a program considered as
a development must be a ‘‘technology’’
improvement. Section 112(d)(6) of the
CAA requires the EPA to review and
revise the MACT standards, as
necessary, taking into account
developments in ‘‘practices, processes
and control technologies.’’ Consistent
with our long-standing practice for the
technology review of MACT standards,
in section III.C of the proposal (see 79
FR 36900, June 30, 2014), we list five
types of ‘‘developments’’ we consider.
Fenceline monitoring fits squarely
within two of those five types of
developments (emphasis added):
• Any add-on control technology or
other equipment that was not identified
and considered during development of
the original MACT standards.
• Any work practice or operational
procedure that was not identified or
PO 00000
Frm 00017
Fmt 4701
Sfmt 4700
75193
considered during development of the
original MACT standards.
As used here, ‘‘other equipment’’ is
clearly separate from and in addition to
‘‘add-on control’’ technology and is
broad enough to include monitoring
equipment. In this case, fenceline
monitoring is a type of equipment that
we did not identify and consider during
development of the original MACT
standards. Additionally, the fenceline
standard is a work practice standard,
involving monitoring, root cause
analysis and corrective action not
identified at the time of the original
MACT standards. Therefore, the
fenceline requirements are a
development in practices that will
improve how facilities manage fugitive
emissions and EPA appropriately relied
on section 112(d)(6) in requiring this
standard.
Comment: Some commenters
contended that because the fenceline
monitoring standard is in essence an
ambient standard, the only justification
that can be used to support it would be
under CAA section 112(f)(2). The
commenters stated that EPA determined
that the MACT standards pose an
acceptable level of risk and protect the
public health with an ample margin of
safety and thus, section 112(f) does not
support imposition of the fenceline
monitoring requirement. Several
commenters stated that the Agency
expressly acknowledges that imposition
of additional emission standards for
fugitive emissions from refinery sources
are not warranted under CAA section
112(f). Some commenters suggested that
because the existing MACT standards
protect public health with an ample
margin of safety, the fenceline
monitoring requirement imposes an
unnecessary burden on industry
because it is not necessary to achieve
acceptable risk or provide an ample
margin of safety.
Response: EPA is not relying on
section 112(f)(2) as the basis for the
fenceline monitoring requirement. As
provided in a previous response to
comment, we disagree with the
commenters that the fenceline
monitoring requirement is an ambient
standard and therefore, we do not need
to consider what authority would be
appropriate for establishing an ambient
standard that would apply to fugitive
sources of emissions at refineries. We
also disagree with the commenters who
suggest that EPA may not require
fenceline monitoring pursuant to
section 112(d)(6) because EPA has not
determined that fenceline monitoring is
necessary to ensure an acceptable level
of risk or the provide an ample margin
of safety. Section 112(d)(6) does not
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75194
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
require EPA to factor in the health
considerations provided in section
112(f)(2) when making a determination
whether it is ‘‘necessary’’ to revise the
MACT.
Comment: Commenters stated that the
pilot studies undertaken by the EPA and
pilot studies undertaken by the refining
industry (see the API Fenceline Study in
the docket for this rulemaking)
demonstrate either that there is no
underestimation of emissions and thus,
no need for the fenceline monitoring
work practice standard, or that fenceline
benzene data cannot be used to validate
emission estimates. Commenters stated
that none of the refineries in the API
study of the proposed refinery fenceline
standard had study-averaged DC
concentrations that exceeded the
proposed action level of 9 mg/m3 and
thus the study provides some evidence
that U.S. refineries are not
underestimating emissions.
Furthermore, the commenter stated that
there is significant ambient air
monitoring performed that further
supports low benzene concentrations in
the vicinities of refineries and cited
ambient monitoring data collected by
the Southeast Texas Regional Planning
Commission Air Quality Group and the
Texas Commission on Environmental
Quality (TCEQ).
Response: We disagree that the API
fenceline study demonstrates that there
is no underestimation of emissions. The
API report referred to by the commenter
actually shows higher DC concentrations
than what we expected, when we
compare the distribution of DC’s
presented in the API fenceline study to
the distribution of benzene
concentrations at the 142 refineries we
modeled (see memorandum ‘‘Fenceline
Ambient Benzene Concentrations
Surrounding Petroleum Refineries’’,
EPA–HQ–OAR–2010–0682–0208). [Note
that API did not identify the facilities in
their study, so we were not able to
perform a one-to-one comparison of the
measured DC concentrations with the
modeled fenceline concentrations.]
Furthermore, the API conducted the
study primarily during the fall and
winter months (October to March) when
the ambient temperatures are lower than
the annual averages. While this may not
impact equipment leak emissions,
temperature can have a significant
impact on emissions from storage
vessels and wastewater treatment
systems, so it is likely that the annual
average DC for the facilities tested could
be higher than the ‘‘winter’’ averages
measured in the API study. Based on
our review of the API study data, we
interpret the results to indicate that
there may be higher concentrations of
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
benzene on the fenceline attributable to
fugitive emissions than anticipated at
some facilities. These studies are an
indication that the standard we are
finalizing will achieve the goal of
ensuring that the owners or operators
manage fugitive emissions within the
refinery.
This regulatory approach also fits
with the EPA’s goals to improve the
effectiveness of rules. Specifically, in
this case, we are improving the
effectiveness of the rule in two ways.
First, we are establishing a fenceline
benzene trigger to manage overall
fugitive HAP emissions, rather than
establishing further requirements on
many individual emission points.
Secondly, the rule incentivizes facilities
to reduce fugitive HAP emissions below
the fenceline benzene trigger by
providing regulatory options for
reduced monitoring.
Regarding ambient monitoring data,
we note that existing ambient monitors
are not located at the fenceline; they are
located away from sources, and
concentrations typically decrease
exponentially with distance from the
emissions source. We are encouraged
that data referenced by the commenter
indicate that ambient levels of benzene
are within levels that are protective of
human health in communities, but note
that analysis of benzene concentrations
in communities does not necessarily
indicate that refineries located near
these communities are adequately
managing their fugitive HAP emissions.
Comment: Several commenters
reiterated that they do not believe the
proposed fenceline monitoring is a
technology development for equipment
leaks, storage vessels or wastewater
sources. However, if the EPA finalizes
the fenceline monitoring requirements,
the commenters suggested that there is
no longer a need or regulatory basis for
imposing both the fenceline monitoring
requirements and the existing MACT
standards for fugitive HAP emission
sources. Thus, the EPA should remove
the current MACT requirements for
LDAR, storage vessels and wastewater
handling and treatment from Refinery
MACT 1 if the EPA promulgates
fenceline monitoring. Addition of
fenceline monitoring on top of the
existing MACT requirements, they
argue, would violate the Executive
Order 12866 mandate to avoid
redundant, costly regulatory
requirements that provide no emission
reductions.
Response: We disagree that the
fenceline monitoring standards we are
finalizing in this rule are redundant to
MACT emissions standards for fugitive
HAP emissions sources. The MACT
PO 00000
Frm 00018
Fmt 4701
Sfmt 4700
standards impose requirements on
fugitive HAP emissions sources
consistent with the requirements in
CAA section 112(d)(2) & (3), and the
fenceline monitoring requirement is not
a replacement for those requirements.
Rather, based on our review of these
standards, we concluded that fenceline
monitoring is a development in
practices, processes or control
technologies that would improve
management of fugitive emissions in a
cost-effective manner. In selecting this
development as an across-the-board
means of improving management of
fugitive emissions, we rejected other
more costly developments that would
have applied independently to each
fugitive emissions source. Requiring
refineries to establish a fenceline
monitoring program that identifies HAP
emission sources that cause elevated
benzene concentrations at the fenceline
and correcting high emissions through a
more focused effort augments but does
not replace the existing requirements.
We found that, through early
identification of significant fugitive
HAP releases through fenceline
monitoring, compliance with the
existing MACT standards for these
emissions sources could be improved
and that it was necessary to revise the
existing standards because fenceline
monitoring is a cost-effective
development in processes, practices,
and control technologies.
We note that the existing MACT
requirements are based on the MACT
floor (the best performers), and as such,
provide a significant degree of emission
reductions from the baseline. The action
level for the fenceline work practice
standard, by contrast, is not based on
the best performers but rather on the
highest value expected on the fenceline
from any refinery, based on the
modeling of refinery emission
inventories. As such it is not
representative of the best performers
and could not be justified as meeting the
requirements of section 112(d)(2)and
(3). If we were to remove the existing
standards for fugitive emission sources
at the refinery, we would not be able to
justify that sources are meeting the level
of control we identified as the MACT
floor when we first promulgated the
MACT. Nor could we justify the
fenceline monitoring program we are
promulgating as representing the MACT
floor because we considered cost (and
not the best performers as previously
noted) in identifying the components of
the program. Although the fenceline
monitoring standard on its own cannot
be justified as meeting the MACT floor
requirement for each of the separate
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
types of fugitive emission sources, that
does not mean that it is not an effective
enhancement of those MACT
requirements. To the contrary, it works
in tandem with the existing MACT
requirements to provide improved
management of fugitive emissions and,
in that sense, it is precisely the type of
program that we believe Congress had in
mind when enacting section 112(d)(6).
ii. Rule Should Require Real-Time
Monitoring Technology for Fenceline
Monitoring.
Comment: Numerous commenters
stated that the proposed fenceline
standards, which require monitoring
using 2-week integrated passive
samplers, are flawed and weak for a
number of reasons, including that the
monitoring method does not provide
real-time data, does not provide
adequate spatial coverage of the
fenceline, and does not provide a
mechanism to identify the specific
emission source impacting the fenceline
to manage fugitive emissions. Several
commenters suggested that this
monitoring technology is not state of the
art. They claimed that there are superior
systems in place at refineries that are
technically and economically feasible,
including at Shell Deer Park, Texas; BP
Whiting, Indiana; and Chevron
Richmond, California. Further, they
claimed that these systems more
effectively achieve the objective of
reducing fugitive emissions. They
claimed several systems are superior to
the proposed system, including openpath systems such as ultraviolet
differential optical absorption (UV
DOAS) and Fourier transform infrared
spectroscopy (FTIR), as well as point
monitors such as gas chromatographs. A
number of commenters suggested that
open-path monitors should be required,
stating that this technology is capable of
providing real-time analysis and data on
air pollution, is able to analyze multiple
pollutants simultaneously at low, nearambient concentrations, and is capable
of providing more complete geographic
coverage.
The commenters also stated that the
benefits of real-time monitors are
particularly important in communities
close to refineries, where they believe
refinery emissions are a major source of
toxic pollutants and short-term upset
events that can have significant public
health impacts. In particular, the
commenters stated that open-path
monitors promote an individual’s rightto-know, in real-time, about harmful
pollution events affecting their
communities, and will allow refinery
owners or operators to immediately
identify fugitive emissions and
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
undertake swift corrective action to
reduce these emissions. Some
commenters suggested that, if the EPA
rejects these open-path real-time
monitors, then at a minimum the EPA
should require the use of active daily
monitoring, such as auto-gas
chromatograph (GC) systems.
Finally, a number of commenters
recommended that the EPA provide
sufficient flexibility in its regulations to
allow state and local jurisdictions to
develop, demonstrate, and subsequently
require the use of alternative monitoring
programs, provided these monitoring
programs are at least equivalent to those
in the final rule.
Response: We understand that many
commenters believe real-time
monitoring would not only help refinery
owners or operators in identifying
emission sources, but also would warn
the community of releases in real time.
Both open-path systems and active
sampling systems (such as auto-GCs)
mentioned by the commenters, are
monitoring systems capable of yielding
monitoring data quickly—ranging from
a few minutes to about a day. However,
these ‘‘real-time’’ systems have not been
demonstrated to be able to achieve all of
the goals stated by the commenters—
specifically, able to provide real-time
analysis and data on multiple pollutants
simultaneously at low-, near-ambient
concentrations, with more complete
geographic (or spatial) coverage of the
fenceline.
The real-time open-path systems
suggested by the commenters are all
limited in that they are not sensitive
enough to detect benzene at the levels
needed to ensure that fenceline
monitoring achieves its intended goal.
The fenceline monitoring system needs
to be capable of measuring at sub-ppbv
levels—well below the 9 mg/m3
fenceline benzene concentration action
level in the final rule, in order to
determine the DC. In the proposal, we
discussed two open-path monitoring
technologies, FTIR and UV–DOAS. For
the proposed rule, we analyzed the
feasibility of employing UV–DOAS over
FTIR because the UV–DOAS is more
sensitive to detection of benzene than
FTIR, as we described in the proposal.
We reviewed performance data on
several UV–DOAS systems in support of
the proposed rule, and for this final
rule, we considered information
submitted during the comment period.
We found that the lowest detection limit
reported for any commercially-available
UV–DOAS system is on the order of 3
ppbv over a 200-meter path length,
whereas the fenceline benzene
concentration action level is 2.8 ppbv
(equivalent concentration to 9 mg/m3).
PO 00000
Frm 00019
Fmt 4701
Sfmt 4700
75195
This system is being installed at the
Shell Deer Park refinery but has not
been field validated yet. Thus, we do
not yet know the detection capabilities
of the system, as installed. Based on the
lowest reported detection limit, it
cannot achieve the detection levels
needed to demonstrate compliance with
the fenceline standard in this final rule.
This system also will only cover
approximately 5 percent of the fenceline
at Shell Deer Park, instead of the full
fenceline coverage of the passive
diffusive tube monitoring system we
proposed. Facilities would have to
deploy a monitoring system consisting
of many open-path monitors to achieve
the same spatial coverage as the passive
diffusive tube monitoring system.
For the final rule, we also reviewed
other UV–DOAS systems in operation at
refineries that commenters identified.
However, reported detection limits for
these systems are even higher than for
the type of system being installed at
Shell Deer Park. For example, we
reviewed the open-path UV–DOAS
system information from BP Whiting
and found that they were able to verify
a detection limit of 8 ppbv path average
concentration for benzene over a 1,500meter optical path. This is well above
the 2.8 ppbv fenceline benzene
concentration action level, let alone the
sub-ppbv levels necessary to determine
the DC. Moreover, this system, though
commercially available, was optimized
by developing alternative software to
improve the detection limit (see
memorandum ‘‘Meeting Minutes for
April 21, 2015, Meeting Between the
U.S. EPA and BP Whiting’’ in Docket ID
No. EPA–HQ–OAR–2010–0682). Thus,
the system, as installed, would not be
readily available to other refineries. We
reviewed data for the UV–DOAS system
at the Chevron Richmond refinery and
found that this system, with optical path
lengths ranging from 500 to 1,000
meters, has a reported benzene
detection limit of 5 ppbv averaged over
the path length. Again, this is above the
fenceline benzene concentration action
level at the fenceline established in this
final rule. In addition, we could not find
any information to support the reported
detection limit. We note that the public
Web site operated by the City of
Richmond, California indicates that
information provided by the system is
informational only, not quality assured,
and not to be used for emergency
response or health purposes.
We also disagree with the
commenter’s claim that if the EPA does
not finalize requirements for real-time
open-path monitors then, at a minimum,
the EPA should require active daily
monitoring. There are two methods of
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75196
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
active monitoring. One method, which
we will refer to as the ‘‘auto-GC
method,’’ uses a dedicated gas
chromatograph at each monitoring
location and can return ambient air
concentration results multiple times a
day or even hourly. The other method,
which we refer to as ‘‘method 2,’’ uses
an active pump to collect gas in a
sorbent tube or in an evacuated canister
over a 1-day period, for later analysis at
a central location. While active
sampling monitoring networks are
capable of measuring multiple
pollutants and would likely be able to
detect benzene at sub-ppbv levels as
necessary to demonstrate compliance
with the fenceline requirements in this
final rule, they consist of discreet
monitors and would not provide any
better spatial coverage of the refinery
fenceline than a passive diffusive tube
monitoring network. Further, as shown
in Table 9 of the proposed rule (see 79
FR 36923, June 30, 2014), like open-path
systems, an active sampling monitoring
network would cost many times that of
a passive diffusive tube monitoring
network. At proposal, we estimated the
costs of active daily sampling based on
‘‘method 2’’ to be approximately 10
times higher than for the proposed
passive monitoring (see memorandum
‘‘Fenceline Monitoring Technical
Support Document’’, Docket ID No.
EPA–HQ–OAR–2010–0682–0210). We
note that this type of active daily
sampling based on method 2 does not
necessarily yield results within 24 hours
as the sample analysis would be
conducted separately. We did not
specifically estimate the costs of an
auto-GC alternative, but the capital costs
would be at least 20 to 30 times that for
the passive diffusive tube system, would
require shelters and power supplies at
all monitoring locations and would have
operating costs similar to the ‘‘method
2’’ active monitoring option we
considered.
To date, there are no commerciallyavailable, real-time open-path monitors
capable of detecting benzene at the subppbv levels necessary to demonstrate
compliance with the fenceline
requirements in this final rule. Only a
system that can detect such levels will
result in effective action by facilities to
identify and control fugitive emissions
in excess of those contemplated by the
MACT standards. Further, active
monitoring systems, while potentially
capable of detecting benzene at subppbv levels, like open-path systems,
become very costly when enough
monitors are located around the facility
to approach the spatial coverage of the
passive diffusive tubes. However, we
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
believe that the state of technology is
advancing and that the capabilities of
these systems will continue to improve
and that the costs will likely decrease.
If a refinery owner or operator can
demonstrate that a particular technology
would be able to comply with the
fenceline standards, the owner or
operator can request the use of an
alternative test method under the
provisions of 40 CFR 63.7(f). A
discussion of the specific requirements
for these requests can be found in the
first comment and response summary of
Chapter 8.3 of the ‘‘Response to
Comment’’ document.
Comment: One commenter stated that
the required monitoring should include
real-time monitoring of all chemicals
released by refineries that pose risks to
human health. The commenter stated
that the limited scope of monitoring
required by the proposed rule appears to
be guided by the EPA’s judgment that
fugitive, or ‘‘unintended’’ emissions
pose the greatest threat to public health.
On the contrary, communities may well
suffer from the effects of chemicals
released into the air under normal,
permitted emissions. A more expansive
monitoring strategy would account for
both routine and fugitive emissions.
Several commenters noted that
monitoring is limited to benzene as
opposed to multiple HAP. One
commenter noted that ill health
experienced by refinery neighbors is
due in large part to the synergistic
effects of multiple chemicals. Therefore,
the commenter stated that it is essential
that the rule require monitoring of the
full range of chemicals with health
implications. Other commenters
recommended that the fenceline
monitoring requirement be amended to
include additional contaminants, such
as VOC, that may negatively impact
human health and the environment.
Conversely, other commenters stated
that the EPA has appropriately selected
benzene as a target analyte and
surrogate for HAP emissions from
petroleum refineries, as benzene is a
common constituent in refinery
feedstocks and numerous refinery
streams, and is present in most HAPcontaining streams in a refinery.
Response: As part of the CAA section
112(d)(6) technology review, the EPA
identified the fenceline monitoring
standard as a development in practices,
processes or control technologies that
could improve management of fugitive
HAP emissions. Thus, to the extent the
commenter is suggesting that the EPA
require the fenceline monitoring system
to monitor for emissions of non-HAP
pollutants, such request goes beyond the
scope of our action. Furthermore, to the
PO 00000
Frm 00020
Fmt 4701
Sfmt 4700
extent that the commenter is raising
health concerns, although we address
residual risk remaining after
implementation of the MACT standards
under CAA section 112(f)(2), we note
that the MACT standards themselves,
including this requirement, are aimed at
protecting public health, especially in
surrounding communities. As we
explained in the proposal, and as we
determine for this final rule, the MACT
standards as modified by additional
requirements for storage vessels,
provide an ample margin of safety to
protect public health. We did not
propose and are not finalizing a
fenceline monitoring requirement as
necessary to provide an ample margin of
safety under CAA section 112(f)(2).
Petroleum refining emissions can
contain hundreds of different
compounds, including many different
HAP, and no single method can detect
every HAP potentially emitted from
refineries. While several HAP are
amenable to quantification via passive
diffusive tube monitoring using the
same adsorbent tubes used for benzene
(e.g., toluene, xylenes and ethyl
benzene, which have uptake rates in
Table 12.1 in Method 325B), we selected
benzene as a surrogate because it is
present in nearly all refinery fugitive
emissions. By selecting a single HAP as
a surrogate for all fugitive HAP, we are
able to establish a clear action level,
which simplifies the determination of
compliance for refinery owners or
operators and simplifies the ability of
regulators and the public to determine
whether sources are complying with the
work practice standard. As described in
the proposal preamble, benzene is
ubiquitous at refineries and present in
nearly all refinery process streams,
including crude oil, gasoline and
wastewater. Additionally, benzene is
primarily emitted from ground level,
fugitive sources that are the focus of the
work practice standard. Thus, we
conclude that monitoring of benzene is
appropriate and sufficient to identify
emission events for which the
monitoring program is targeting.
Consequently, we are not requiring
quantification of other pollutants
although refinery owners or operators
could choose to analyze the diffusive
tube samples for additional HAP in
conducting root cause analysis and
corrective action.
iii. Fenceline Monitoring Action Level
Comment: Several commenters stated
that the action level for fenceline
monitoring (i.e., 9 mg/m3 or 2.8 ppbv),
was set too high. Some of these
commenters noted that the EPA selected
9 mg/m3 as the highest modeled benzene
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
concentration at any refinery fenceline.
One commenter stated that this was
arbitrary and capricious and stated the
action threshold level makes little sense
because only 2 of the 142 modeled
facilities are expected to have fenceline
concentrations above 4 mg/m3. Several
commenters noted that the average
modeled benzene concentration is 0.8
mg/m3, which is more than an order of
magnitude less than the proposed
fenceline benzene concentration action
level.
Two commenters argued for a lower
action level threshold, citing the
proposed California OEHHA rule, which
finalized new and revised benzene
reference exposure levels (REL) that are
more stringent than the ones the EPA
used in the residual risk assessment
supporting the proposed rule.
Two commenters stated that while the
fenceline benzene concentration action
level of 9 mg/m3 is relatively protective
compared to standards adopted by many
states, including Louisiana and Texas, it
is still 80-percent higher than the
European Union’s standard of 5 mg/m3.
The commenter urged the agency to
consider adopting a stricter standard
comparable to what other industrialized
nations use.
Several commenters stated that the
EPA’s 9 mg/m3 action level is
inconsistent with the statutory text and
objectives of CAA sections 112(d) and
(f), which direct the EPA to focus on the
best-performing, lowest-emitting
sources, in order to require the
‘‘maximum achievable’’ emission
reductions. The commenters stated that
the EPA promulgated the 9 mg/m3 limit
without properly following the statutory
requirements for establishing MACT
floor limits, pointing out that the EPA
made no determination of whether or
not these general models were
representative of the emissions levels
actually achieved by the submitting
refinery, and no connection was drawn
between the best performing sources
and the eventual 9 mg/m3 limit.
On the other hand, several
commenters opposed the 9 mg/m3 action
level suggesting that it was not
achievable and that it is arbitrary. Some
commenters noted that emission/
dispersion models are always very sitespecific and do not necessarily yield a
result that is reliable or reproducible.
Several commenters stated that
additional studies are necessary to allow
the agency to account for these variables
and set a more appropriate
concentration corrective action level.
Commenters suggested a 2-year data
gathering effort at all refineries and data
evaluation before determining a specific
threshold to use.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Several commenters recommended
action levels ranging from 15 mg/m3 to
20 mg/m3 of benzene to account for the
variability expected in monitoring data.
The commenters stated that modeling
biases have underestimated the
necessary action level to achieve the
stated goals of the program.
Response: First, it is important to note
that the purpose of the standard has not
changed between proposal and
promulgation, namely that it is a
technology-based standard that is an
advancement in practices to manage
fugitive emissions. It is not intended to
be a separate or new MACT standard
promulgated pursuant to CAA sections
112(d)(2) and (3) for which a ‘‘floor’’
analysis would be required.7 Nor is it a
standard that we are promulgating
pursuant to CAA section 112(f)(2) as
necessary to provide an ample margin of
safety to protect public health or
prevent an adverse environmental
effect.8 Thus, claims that a standard
should reflect European Union healthbased standards or the California
OEHHA rule are misplaced. We also
disagree with the suggestion that the
proposed monitoring requirement will
allow for higher emissions. As noted
elsewhere, we are retaining all of the
source-specific requirements for fugitive
emissions sources that exist in Refinery
MACT 1.
We disagree with the commenters that
suggest that the proposed action level of
9 mg/m3 is too low and may not be
achievable even for well-performing
facilities. As discussed in the preamble
for the proposed rule, we selected the 9
mg/m3 benzene action level because it is
the highest value on the fenceline
predicted by the dispersion modeling
and, thus, is a level that we estimate
that no refinery should exceed when in
full compliance with the MACT
standards, as amended by this final rule.
All of the results of our pilot study, the
API study, and the other ambient
monitoring data near refineries clearly
indicate that this level is achievable.
Furthermore, we expect the fenceline
concentration difference measured
following the procedures in the final
7 To the extent that the commenters are
suggesting that EPA must re-perform the MACT
floor analysis for purposes of setting a standard
pursuant to section 112(d)(6), we note that the D.C.
Circuit has rejected this argument numerous times,
most recently in National Association for Surface
Finishing et al. v. EPA No. 12–1459 in the U.S.
Court of Appeals for the District of Columbia.
8 Although we did not establish this limit to
address residual risk under CAA section 112(f)(2),
the limit was derived from the same inventory used
for our risk modelling. Thus, based on our current
reference concentration for benzene, the 9 mg/m3
action level will also ensure that people living near
the refinery will not be exposed to cancer risks
exceeding 100-in-1 million.
PO 00000
Frm 00021
Fmt 4701
Sfmt 4700
75197
rule to be indicative of refinery source
contributions and we have provided
procedures to isolate these
concentrations from outside sources, as
well as background.
We expect that the fenceline
monitoring standard will result in
improved fugitive HAP emissions
management as it will alert the refinery
owners or operators of fugitive sources
releasing high levels of HAPs, such as
large leaks, faulty tank seals, etc.
iv. Fenceline Monitoring Root Cause
Analysis and Corrective Action
Provisions
Comment: A number of commenters
objected to the proposal’s ‘‘open-ended’’
provisions allowing the EPA to direct
refinery owners or operators to change
their operations in order to achieve the
fenceline limit, with no regulatory
limits on costs and without
consideration of the impact to safe
operations or operability of the plant.
Another commenter stated that the EPA
must properly assess the costs
associated with the root cause analysis/
corrective action requirements and
should establish a cost effectiveness
threshold for any required root cause
analysis/corrective action to ensure that
limited resources are effectively and
efficiently applied for the control of
emissions.
One commenter stated the proposed
fenceline benzene concentration action
level is effectively an ambient air
standard, because corrective action to
achieve that level is required and that if
a facility’s initial corrective action is
unsuccessful, the rule provides that
further action is required and the EPA
must approve that further corrective
action plan. Thus, the commenter
argued, the EPA would essentially be
able to dictate corrective actions, with
no bounds on what could be required
and no consideration of whether any
cost-effective actions are available to
assure the action level is met. The
commenter continued that such a
requirement converts a work practice
program to an emission limitation and
such ambient air limits are not
authorized by CAA section 112. Several
commenters noted that LDAR and
current work practice programs have no
similar requirement for the EPA
approval, and the commenters suggested
that the requirement for the EPA
approval of any second corrective action
should not be included in 40 CFR
63.658(h).
Another commenter recommended
that, if after corrective action, a facility
still has an exceedance for the next
sampling episode, then the facility
should be required to do more than it
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75198
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
did after the first root cause analysis, as
the prior corrective action clearly did
not correct the problem. The commenter
stated that one corrective action
measure the EPA should include in all
such instances is higher-quality
monitoring such as UV–DOAS for at
least 1 year to monitor, identify, correct
and assure ongoing compliance after the
exceedance problem is fixed.
Response: The ‘‘on-going’’
requirement to achieve the fenceline
benzene concentration action level is no
different in concept from the LDAR
requirements for equipment or heat
exchange systems in the Refinery MACT
1 rule, which requires the refinery
owner or operator to repair the source
of the emissions regardless of what it
takes until compliance with the
standard is achieved.
We disagree with the claim that the
EPA must assess the costs associated
with the root cause analysis/corrective
action requirements and establish a cost
effectiveness threshold for any required
root cause analysis/corrective action to
ensure that limited resources are
effectively and efficiently applied for
the control of emissions. We did not
attempt to project the costs of the root
cause analysis/corrective action for at
least two reasons. First, based on the
dispersion modeling of the benzene
emissions reported in response to the
inventory section of the 2011 ICR, we
project that no refinery should exceed
that fenceline benzene concentration
action level if in full compliance with
the MACT standards, as amended by
this action. Thus, assuming compliance
with the MACT standards, we would
expect that there are no costs for root
cause analysis/corrective action. To the
extent that there are exceedances of the
action level, the premise of the fenceline
monitoring is to provide the refinery
owners or operators with the flexibility
to identify the most efficient approaches
to reduce the emissions that are
impacting the fenceline level. Since the
choice of control is a very site-specific
decision, we would have no way to
know how to estimate the costs. Thus,
the source is in the best position to
ensure that resources are effectively and
efficiently spent to address any
exceedance.
We intended the proposed
requirement for refinery owners or
operators to submit a corrective action
plan for the EPA approval to provide the
Administrator with information that
they were making a good-faith effort to
reduce emissions below the fenceline
benzene concentration action level, as
expeditiously as practicable. However,
we understand the importance for
refinery owners or operators to begin
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
corrective action as soon as possible,
without having to wait for the EPA
approval. Therefore, we are finalizing
the requirement for refinery owners or
operators to submit such plans but we
are not finalizing the requirement that
the EPA must approve the plan prior to
the corrective action being taken.
We previously responded to
comments regarding UV–DOAS or other
open-path monitoring systems in this
section, explaining that the current
detection limits for these systems
exceeds the action level threshold and,
thus, these systems would not provide
usable data to inform corrective action.
Thus, we disagree that the EPA should
require these systems for all facilities
whose first attempt at corrective action
is ineffective.
v. Fenceline Monitor Siting
Requirements
Comment: Numerous commenters
provided suggestions on, or requested
clarification of, the monitor siting
requirements. Several commenters
stated that proposed Method 325A uses
the terms ‘‘fenceline or property
boundary,’’ while it should consistently
use the term ‘‘property boundary’’ or
even ‘‘property line’’ as the fenceline
location. Several commenters stated that
Sections 8.2.2.1.4 and 8.2.2.3 of Draft
Method 325A specify that samplers be
placed just beyond the intersection
where the measured angle intersects the
property boundary and this could
require placing monitors on other
people’s property, in a road, in a water
body or in a railroad right-of-way. The
commenters suggested that facilities
should be allowed to place monitors at
any vector location that meets other
requirements between the property
boundary and the source nearest the
property boundary. They stated that
facilities need this clarification to avoid
obstructions (e.g., buildings or trees)
that may be at the property line.
Numerous commenters requested that
the rule clarify where monitors need to
be placed in special circumstance, such
as refineries bisected by a road, railroad
or other public right-of-way or a
boundary next to a navigable waterway.
Several commenters stated that refiners
should not need to place monitors on
these property boundaries or other
property boundaries where there are no
residences within 500 feet of the
property line. Commenters also asked if
areas that had non-refinery operations,
but are still inside the property
boundary, would be included for
purposes of determining where to site
monitors.
A few commenters expressed concern
about the approach for determining the
PO 00000
Frm 00022
Fmt 4701
Sfmt 4700
number of required monitors at a site
based on the acreage, noting that it is
unfair to small facilities and will leave
gaps in monitoring coverage for very
large facilities. Some commenters
recommended amending the proposed
rule to require the placement of
fenceline monitors at fixed distances
along facilities’ perimeters with no
maximum number of monitors. Some
commenters stated that the rule should
specify an acceptable range on the
2,000-foot spacing requirement or the
radial placement requirement as it may
be necessary to address accessibility or
safety concerns. Several commenters
suggested that a lower minimum
number of sampling monitors should be
required for very small refineries or
small ‘‘subareas.’’ These commenters
noted that refineries often include
disconnected parcels that can be very
small (e.g., 10 acres or less). If each
disconnected parcel must be treated as
a separate subarea, then both sampler
siting options in Draft Method 325A
would result in unnecessarily large
numbers of samplers extremely close
together. Some commenters
recommended that Method 325A
specify that samplers need not be placed
closer than 500 feet (versus the normal
2,000-foot interval specified in Option
2) along the fenceline from an adjoining
sampler, regardless of whether the
radial or linear approach is used and
should waive the minimum number of
samplers specified in Sections 8.2.2.1.1,
8.2.2.2.1, and 8.2.3.1. Another
commenter added that the rule should
waive the requirement for additional
samplers in Sections 8.2.2.1.5 and
8.2.3.5 if the 500-foot minimum spacing
criterion is compromised.
Response: We agree that the Method
325A should provide clear and
consistent language. We have revised
the language to be consistent in referring
to the ‘‘property boundary’’. We have
also revised the Method to allow
placement of monitors at any radial
distance along either a vector location or
linear location (that meets the other
placement requirements) between the
property boundary and the source
nearest the property boundary. That is,
the monitors do not need to be placed
exactly on the property boundary or
outside of the property boundary. They
may be placed within the property
closer to the center of the plant as long
as the monitor is still external to all
potential emission sources. We do note
that if the monitors are placed farther in
from the property boundary, the owner
or operator should take care to ensure,
if possible, that the radial distance from
the sources to the monitors is at least 50
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
meters. If the perimeter line of the
actual placement of the fenceline
monitors is closer than 50 meters to one
or more sources, then the additional
monitor citing requirements will apply.
We have revised subparagraphs of
Section 8.2.2 to provide this allowance.
This clarification should address issues
related to obstructions such as tall walls
located at the facility boundary.
We intended that the fenceline
monitoring would create a monitoring
perimeter capable of detecting
emissions from all fugitive emission
sources at the refinery facility. We have
long established that a road or other
right of way that bisects a plant site does
not make the plant site two separate
facilities, and, thus, would not be
considered part of the property
boundary. As we agree that monitors
need only be placed around the
property boundary of the facility, it
would not be necessary to place
monitors along a road or other right-ofway that bisects a facility. We have
clarified this in the final rule and
Method 325A.
If the facility is bounded by a
waterway on one or more sides, then the
shoreline is the facility boundary and
monitors should be placed along this
boundary. If the waterway bisects the
facility, the waterway would be
considered internal to the facility and
monitors would only be needed at the
facility perimeter.
Regarding the comment that monitors
should not be required where there is no
residence within 500 feet of the
property line, we disagree. We proposed
and are finalizing the fenceline
monitoring standards under CAA
section 112(d)(6) as a means to improve
fugitive HAP emissions management,
regardless of whether there are people
living near a given boundary of the
facility.
Regarding the clarification requested
about monitor placement considering
non-refinery operations, the property
boundary monitors should be placed
outside of all sources at the refinery.
This is because moving the monitoring
line inward to exclude the non-refinery
source could lead to an underestimation
of the DC compared to the monitoring
external of the entire site. If the nonrefinery source is suspected of
contributing significantly to the
maximum concentration measured at
the fenceline, a site-specific monitoring
plan and monitoring location specific
near-field interfering source (NFS)
corrections will be needed to address
this situation.
Section 8.2.3 of Method 325A
includes language to provide some
flexibility when using the linear
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
placement (±10% or ±250 feet). We
consider it reasonable to provide similar
placement allowance criteria for the
radial placement option (±1 degree). We
are not providing requirements that
would allow small area refineries to use
fewer than 12 monitoring sites. We do
not consider that any refinery would be
so small as to warrant fewer than 12
monitors; however, we did not
necessarily consider very small subareas
for irregularly shaped facilities or
segregated operations. When
considering these subareas, we agree
that fewer than 12 monitoring sites
should be appropriate. Therefore, we
have provided that monitors do not
need to be placed closer than 152 meters
(500 feet) (or 76 meters (250 feet) if
known sources are within 50 meters
(162 feet) of the monitoring perimeter,
which is likely for these subareas or
segregated areas) with a stipulation that
a minimum of 3 monitoring locations be
used per subarea or segregated area. We
note, however, that this distance
provision does not obviate the near
source extra monitoring siting
requirements or the requirement to have
a minimum of three monitors per
subarea or segregated area.
If facility owners or operators have
questions regarding the required
locations of monitors for a specific
application, they should contact the
EPA (or designated authority) to resolve
questions about acceptable monitoring
placement.
vi. Compliance Time for Fenceline
Monitoring Requirements
Comment: Some commenters
supported EPA’s proposal to provide 3
years to put a fenceline monitoring
program in place, but the commenters
believe that timing is unclear in the
proposed regulatory language, which
appears in Table 11 to subpart CC, and
requested that the EPA add the initial
compliance date to 40 CFR 63.658(a).
One commenter stated that instituting
this program for all 142 major source
U.S. refineries would require
considerable time. Based on their
experience with their pilot study, one
commenter noted that commercially
available weather guards meeting the
specifications of proposed Method 325A
are not available and would need to be
fabricated. Additionally, a commenter
stated that only a limited number of
laboratories in the U.S. are able to
perform the necessary analyses.
According to the commenter,
considerable time and effort will be
needed to qualify additional laboratories
and to expand the capacity of existing
laboratories to handle the samples from
142 refineries.
PO 00000
Frm 00023
Fmt 4701
Sfmt 4700
75199
Other commenters disagreed with the
EPA’s proposed compliance time and
suggested that the EPA shorten the
timeline for implementation at
refineries so that possible corrective
action occurs much sooner than
proposed. The commenters suggested
that deployment of passive samplers can
proceed more promptly than proposed,
especially since the EPA has
simultaneously proposed specific
‘‘monitor siting and sample collection
requirements as EPA method 325A of 40
CFR part 63, Appendix A, and specific
methods analyzing the sorbent tube
samples as EPA Method 325B of 40 CFR
part 63, Appendix A.’’ Moreover, the
commenter noted, a principal reason
that the EPA selected passive monitors
over active monitors was due to the
relative ‘‘ease of deployment.’’ The
commenter claimed this ease of
deployment rationale is undermined by
a 3-year grace period to deploy passive
monitors when the EPA is providing
very specific criteria for their use. The
commenter suggested that the EPA
require full compliance with the passive
monitoring requirement within 1 year of
the effective date of the rule.
Response: While we realize that it
will take some time for the refinery
owners or operators to understand the
final rule and develop a compliant
monitoring program, we agree that in
requiring the passive sampler
monitoring system, we recognized the
ease of implementation and
deployment. Although industry
commenters identified issues they faced
in the API pilot study while trying to
implement the monitoring method, we
note that the 12 facilities that
participated in the API pilot study
installed the fenceline monitors and
began sampling in late 2013 with
relative ease and within months of
obtaining the draft methods. Thus, we
disagree with the suggestion that 3 years
is insufficient and agree with other
commenters that 3 years is in fact too
long. However, we also are aware that
the API pilot facilities used the direct
DC approach proposed and did not
attempt to develop site-specific
monitoring programs to correct for
interfering near-field sources. Although
we expect that facilities could complete
direct implementation of the proposed
fenceline monitoring requirement
within 1 year after the effective date of
the rule, as suggested by some
commenters, facilities that choose to
develop a site-specific monitoring plan
would need a longer period of time.
Therefore, we are finalizing
requirements that specify that facilities
must begin monitoring for the official
E:\FR\FM\01DER2.SGM
01DER2
75200
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
determination of DC values no later than
2 years after the effective date of the
rule.
vii. Fenceline Monitoring
Recordkeeping and Reporting
Requirements
Comment: Some commenters
suggested that facilities should be
required to submit the monitoring data
via the ERT only if they exceed the
fenceline benzene concentration action
level and that all remaining data should
be kept on-site and available for
inspection or upon request of the EPA,
citing that this is consistent with EPA’s
semiannual NESHAP reporting of only
exceptions (i.e., deviations). Other
commenters requested that the EPA
only post the rolling annual average
concentration values and not the 2-week
monitoring data. These commenters
indicated concern that if errors are
present in the raw data that are
submitted semiannually to the EPA, the
data, errors and all, will be released to
the public and correcting them will not
take place or will not take place in a
timely manner. One commenter added
that there is very little useful
information that can be gleaned from
the raw data and posting it simply
invites misunderstandings.
Commenters also stated that the EPA
should adopt reporting requirements to
ensure that facilities report the
monitoring data appropriately.
Specifically, commenters recommended
that 40 CFR 63.655(h)(8)(i) should be
clarified to only require reporting of
valid data and cautioned that data
should be processed to allow accurate
calculations of annual averages to be
used for reporting and evaluation. To
accomplish this, commenters
recommended that the rule provide 75
days from the end of a 6-month
sampling period to report to the EPA,
rather than the proposed 45-day period,
in order to provide adequate time to
obtain quality-assured results for all 2week sampling periods.
One commenter applauded the
proposal’s requirements for electronic
reporting of the fenceline concentration
data and making the resulting
information publicly available.
However, the commenter recommended
that the EPA consider a more truncated
data reporting period that is more
consistent with the associated
milestones of collecting a 14-day
sampling episode. As is, the commenter
claimed, the proposed rule would have
a lag time of up to 7.5 months between
data collection and posting. The
commenter indicated that data reporting
on a more frequent schedule will not
only provide transparency, but will
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
provide states and local agencies with
information about air quality at
refineries at a frequency that could
allow informed activities to address
leaks much more quickly and protect
public health.
Response: We disagree with the
commenters who suggest that facilities
only report the rolling annual average or
only exceedances of the fenceline
benzene concentration action level
because the commenters believe there is
little information to be gleaned from the
raw data. Monitoring data are useful in
understanding emissions, testing
programs, and in determining and
ensuring compliance. We generally
require reporting of all test data, not just
values calculated from test data and/or
where a facility exceeds an emissions or
operating limit. For example, when we
conduct risk and technology reviews for
source categories, we are adding
requirements for facilities to submit
performance test data into the ERT, not
just performance test data that indicates
an exceedance of an applicable
requirement. In the Mercury and Air
Toxics Rule, we require facilities to
report direct measurements made with
CEMS, such as gas concentrations, and
we require hourly reporting of all
measured and calculated emissions
values (see discussion at 77 FR 9374,
February 16, 2012). In particular, for the
fenceline monitoring requirements in
this final rule, we offer facilities options
for delineating background benzene
emissions and benzene emissions not
attributable to the refinery, and we offer
options for reduced monitoring, making
it even more necessary that we have all
of the data to review to ensure that
testing and analyses are being done
correctly and in compliance with the
requirements set out in the regulations,
and that root cause analyses and
corrective actions are being performed
where necessary. Therefore, as
proposed, we are finalizing the
requirements that facilities report the
individual 2-week sampling period
results for each monitor, in addition to
the calculated DC values in their
quarterly reporting.
Regarding commenters’ concerns that
facilities post accurate data and have
sufficient time to perform quality
assurance on the data, in the final rule,
we have established provisions for how
sources are to address outliers and data
corrections. Additionally, as proposed,
we do not require an initial report until
facilities have collected 1 year of data so
that facilities do not report the data
until a rolling annual average value can
be determined. This will allow refinery
staff and analytical laboratories to iron
out any issues that might arise as they
PO 00000
Frm 00024
Fmt 4701
Sfmt 4700
implement these methods for the first
time. Once this initial data collection
period is complete, we anticipate that
data quality issues should be infrequent.
Therefore, we are providing a 45-day
period following each quarterly period
before facilities must submit the
monitoring results, which should
provide facilities adequate time to
correct any data errors prior to reporting
the data.
Regarding comments that suggest
reporting each 2-week sample result
soon after its collection, we disagree.
This frequency would put undue
burden on the refinery owners or
operators in trying to collect, review and
quality assure the data prior to
reporting. However, we agree with
commenters that more frequent
reporting of the fenceline monitoring
data would be useful. Therefore, we
have revised the reporting frequency for
the fenceline monitoring data to be
quarterly in the final rule rather than
semiannually as proposed.
Additionally, we understand that there
is a lot of interest in how these data will
be presented to the public, and we plan
to reach out to all stakeholders on
appropriate approaches for presenting
this information in ways that are helpful
and informative.
b. Refinery MACT 2
This section provides comment and
responses for the key comments
received regarding the technology
review amendments proposed for
Refinery MACT 2. Comment summaries
and the EPA’s responses for additional
issues raised regarding the proposed
requirements resulting from our
technology review are in the ‘‘Response
to Comment’’ document in the public
docket (Docket ID No. EPA–HQ–OAR–
2010–0682).
i. FCCU
We received comments on the
consideration of developments in
pollution controls, the averaging time
for FCCU PM limits, and the FCCU
opacity limit, as discussed below.
Comment: One commenter stated that
the EPA failed to consider
developments in pollution controls for
HAP from FCCUs for two reasons. First,
the commenter contended that cost is
not a valid consideration to evaluate if
a ‘‘development’’ in pollution control is
necessary pursuant to section
7412(d)(2), (3), (6), unless the EPA is
setting a ‘‘beyond-the-floor’’
requirement.
Second, the commenter claimed that
the EPA’s review of developments is
nearly 10 years old and misses some
important pollution control
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
improvements in the industry. For
example, the commenter noted that
Valero Benicia installed a combination
of controls in 2012 including a scrubber,
SCR and CO Boiler that combine
exhaust streams from the FCCU and
coking and reportedly eliminate HAP
emissions entirely from these sources.
The commenter also asserted that EPA
consent decrees impose lower effective
limits on PM than the EPA considered
under the technology review. The
commenter identified the BP Whiting
facility as subject to 0.7 lb PM/1,000 lbs
coke burn-off at one FCCU and 0.9 lb
PM/1,000 lbs coke burn-off at another
and claimed these limits are lower than
the 1.0 lb PM/1,000 lbs coke burn-off
limit currently mandated by Refinery
MACT 2.
Response: We disagree that we cannot
consider costs when determining if it is
necessary to revise an existing MACT
standard based on developments in
practices, processes and control
technologies. The commenter suggests
that we cannot consider costs because of
the requirements in CAA section
112(d)(2) and (3) for establishing initial
MACT standards and which do not
allow for consideration of costs until the
second, ‘‘beyond the floor’’ phase of the
analysis. As discussed previously in this
preamble where we respond to
comments on the fenceline monitoring
requirements, to the extent that the
commenters are suggesting that EPA
must re-perform the MACT floor
analysis for purposes of setting a
standard pursuant to section 112(d)(6),
we note that the D.C. Circuit has
rejected this argument numerous times,
most recently in National Association
for Surface Finishing et al. v. EPA No.
12–1459 in the U.S. Court of Appeals for
the District of Columbia.
Regarding the claim that the EPA did
not consider the types of controls at the
Valero and BP facilities, we disagree.
The control measures for both of those
facilities are controls that existed at the
time of the development of the MACT
standard. Thus, we did not identify
these technologies as developments in
control technologies during the
technology review. However, we did
identify developments in processes or
practices that reflect better control by
the existing technology and we
reviewed modified emission limits that
reflect that better level of control. The
commenter suggested that we failed to
consider a level of zero when the Valero
facility was able to achieve zero
emissions through a combined SCR,
boiler and scrubber. However, the
commenter provided no information to
support such a claim and we are
skeptical that such a result could be
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
achieved. We note that the SCR is
designed specifically to reduce NOX
emissions, and would not be capable of
reducing significantly, much less
eliminating completely, HAP emissions.
Similarly, based on our long-standing
understanding of the processes, neither
a boiler nor a scrubber could achieve
such a result. Regarding the level of
emissions achieved at the BP Whiting
facility, we note that we evaluated
control systems that can meet 0.5 lb PM/
1,000 lb coke burn-off, which is a lower
limit than that at BP Whiting. We
determined that these were costeffective to require for new units that
are installing a new control system.
However, we determined that
retrofitting controls designed to meet a
PM limit of 1.0 lb PM/1,000 lbs coke
burn-off to now meet a limit of 0.5 lb
PM/1,000 lbs coke burn-off was not
cost-effective when considering PM and
PM2.5 emissions reductions. We
projected the cost of the 0.5 lb PM/1,000
lbs coke burn-off limit in retrofit cases
to be $23,000 per ton PM emissions
reduced. To meet a limit of 0.7 lb PM/
1,000 lbs coke burn-off or 0.9 lb PM/
1,000 lbs coke burn-off, as is the case for
BP Whiting, the retrofit costs would be
similar to this 0.5 lb PM/1,000 lb coke
burn-off option, but the reductions
would be even less, resulting in costs
over $23,000 per ton. As metal HAP
content of FCCU PM is approximately
0.1 to 0.2-percent of the total PM, the
cost of requiring this lower limit for
existing FCCU is over $10 million per
ton of metal HAP reduced. Therefore,
we determined that it is not necessary
to revise the PM standard for existing
FCCU sources.
Comment: Refinery MACT 2 requires
the owner or operator to demonstrate
compliance with the PM FCCU limits by
complying with the operating limits
established during the performance test
on a daily (i.e., 24-hour) average basis.
Several commenters objected to the
EPA’s proposal to revise this
requirement to a 3-hour averaging time.
Commenters restated EPA’s arguments
for 3-hour averaging time as: (1) Daily
average could allow FCCUs to exceed
limits for short periods while still
complying with the daily average, (2)
consistency with NSPS subpart Ja and
(3) consistency with duration of testing.
The commenters stated that the EPA
had not provided any data that show
that the daily average could allow
FCCUs to exceed limits for short periods
and, therefore, the EPA is using a
hypothetical compliance assurance
argument to change emission limits. The
commenters stated that a change in
emission limits is not authorized by
PO 00000
Frm 00025
Fmt 4701
Sfmt 4700
75201
CAA section 112 because the emission
limitations in Refinery MACT 2 for
FCCUs were established as daily
averages following the floor and ample
margin of safety requirements in section
112(d)(2) of the CAA.
The commenters also state that the
EPA’s additional arguments for the
change to a 3-hour average are irrelevant
and legally deficient. The commenters
stated that the combination of a
numerical emission limit and an
averaging period frames the stringency
of a limitation and that a reduction in
either of those factors results in a
significant lowering of the operating
limit. The commenters conclude that
the EPA has proposed to change the
stringency of the requirements without
justification, and the CAA requires that
such a change in stringency be justified
pursuant to CAA section 112(d)(6) or
(f)(2). The commenters stated that
increasing stringency for consistency
with NSPS rules is not a criterion for a
CAA section 112(d)(6) action. Rather
that section requires a change to be due
to ‘‘developments.’’ The only change in
technology since the 2002 promulgation
of Refinery MACT 2 is the availability
of PM continuous emission monitoring
system (CEMS), which is unproven.
One commenter noted that changing
the averaging time is a very significant
modification considering that the
compliance limits would apply for
periods of SSM. This commenter stated
that it is unlikely that existing
operations can consistently be in
compliance with a new 3-hour average
since the current daily averaging was
put in place to recognize that there will
be periods of operating variability that
do not represent the longer term
performance of an FCCU. The
commenters recommended that the EPA
retain the daily averaging requirement.
Response: We disagree with the
commenters’ statement that reducing
the averaging time from a 24-hour basis
to a 3-hour basis for demonstrating
compliance with the FCCU PM emission
limit, using operating limits established
during the performance test, is a change
to the MACT floor. The emission limit
of 1.0 lb PM/1,000 lbs coke burn-off is
the MACT floor, and we are not
changing the PM emissions limit (or
alternate Ni limits) in Table 1 to subpart
UUU (except to remove the incremental
PM limit that did not comport with the
MACT floor emissions limitation).
However, whether or not it is a
change from the MACT floor is not
relevant. Pursuant to CAA section
112(d)(6), the EPA must revise MACT
standards ‘‘as necessary’’ considering
developments in practices, processes
and control technologies. For this
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75202
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
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).
In determining whether there are
‘‘developments,’’ we review, among
other things, EPA regulations
promulgated after adoption of the
MACT, such as the NSPS we identified
in this instance. We identified the
enhanced monitoring requirements for
these operating limits as a development
in practices that will help ensure FCCU
owners or operators are properly
operating control devices and, thus, are
meeting the PM emission limit at all
times. We further determined that this
enhanced monitoring was cost effective
and proposed that it was necessary to
revise the existing standard pursuant to
CAA section 112(d)(6).
While we do not have continuous PM
emissions data that show actual
deviations of the PM limit, we do not
need such data in order to conclude that
such deviations could occur when daily
averages are used. The Refinery MACT
2 (i.e., subpart UUU) rule requires
owners or operators to establish
operating limits based on three 1-hour
runs during the performance test. As a
matter of simple mathematics, a source
could demonstrate that it is meeting the
operating limit based on a 24-hour
average but could be exceeding the 1.0
lb PM/1,000 lbs coke burn-off emission
limit based on a 24-hour average or for
one or more individual 3-hour periods
during that 24-hour average. For
example, an owner or operator could
operate with a power input 5-percent
higher than the operating limit for 23
hours, have the ESP off (zero power) for
one hour, and still comply with a 24hour average operating limit. However,
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
it would be difficult for this same unit
to meet the 1.0 lb PM/1,000 lbs coke
burn-off emissions limit over a 24-hour
period, and it certainly would not meet
the limit for every 3-hour period during
that day. As the operating limit can be
established to correspond with 1.0 lb
PM/1,000 lbs coke burn-off, the 5percent higher power input would
likely correspond with a 0.95 lb PM/
1,000 lbs coke burn-off emissions rate
(5-percent lower). Uncontrolled
emissions are typically 6 to 8 lbs/1,000
lbs coke burn-off. Thus, this unit would
have emissions averaging approximately
1.2 lbs PM/1,000 lbs coke burn-off
during this 24-hour period [i.e.,
(0.95*23+7)/24], but would be in
compliance with the 24-hour average
operating limit. The unit would
obviously also be out of compliance
with the 3-hour average over the period
when the power was turned off. We also
have concerns that the operating limits
are not always linear with the
emissions, so that the longer averaging
times do not effectively ensure
compliance with the PM emissions
limit. Therefore, as proposed, we are
finalizing the requirement for owners or
operators to comply with the operating
limits on a 3-hour basis, rather than the
24-hour basis currently in the rule.
Comment: The technology review for
FCCUs resulted in the EPA proposing to
remove the 30-percent opacity
alternative limit for demonstrating
compliance with the PM emissions limit
that is available for refineries complying
with the Refinery NSPS 40 CFR part 63,
subpart J. Two commenters supported
the EPA’s proposed removal of the 30percent opacity limit for FCCUs. Other
commenters stated that current
technology is good enough for a 10- or
20-percent opacity limit. On the other
hand, several commenters stated that
the proposed removal of the 30-percent
opacity limit must meet the criteria
specified in CAA section 112(d)(6) and
(f)(2), which requires analysis of the
statutory basis, environmental impacts,
costs, operational and compliance
feasibility and impacts, that the EPA has
not conducted. The commenters
claimed that had the EPA conducted a
proper analysis, the EPA would have
determined that the proposed change to
remove the 30-percent opacity limit is
not necessary or supportable.
Additionally, these commenters stated
that since the underlying PM emissions
limit is unchanged, there is no emission
reduction justification for this proposed
change, and the change would not meet
the CAA section 112(d)(6) requirement
of being cost effective. The commenters
also noted that processes or practices for
PO 00000
Frm 00026
Fmt 4701
Sfmt 4700
existing FCCUs have not changed, as
required for a CAA section 112(d)(6)
revision.
Several commenters urged the EPA to
maintain the 30-percent opacity limit
for these FCCUs. As a practicable and
cost-effective alternative to address the
EPA’s concern as to whether
compliance with a 30-percent opacity
limit ensures compliance with the PM
emissions limit, commenters suggested
annual performance tests to confirm that
the FCCU is meeting the PM emissions
limit, rather than performance tests
every 5 years, as proposed.
One commenter stated that the EPA
never intended for the opacity limit in
Refinery NSPS subpart J to be used to
demonstrate compliance with the PM
emissions limit, but instead to assure
the PM controls operate properly. The
commenter stated that the EPA’s
conclusion that the 30-percent opacity
limit may not be sufficiently stringent to
ensure compliance with the underlying
PM emissions limit is based on a false
premise as to the purpose of the opacity
standard because as the EPA states,
‘‘Opacity of emissions is indicative of
whether control equipment is properly
maintained and operated.’’
Several commenters stated that the
proposed elimination of the 30-percent
opacity limit currently in Refinery
MACT 2 leaves existing FCCUs that use
cyclones with no viable alternative
approach to demonstrate compliance
with the PM emissions limit without
adding or replacing controls. They
stated the other approaches for
demonstrating compliance with the PM
emissions limit in Refinery MACT 2
(such as development of a site-specific
opacity limit) do not work for them. The
commenters stated that although they
believe that more frequent performance
tests would show that the FCCUs are in
fact meeting the PM emissions limit, the
absence of the 30-percent opacity limit
would force FCCUs using cyclones for
PM control to install additional, costly
PM controls (e.g., ESPs or wet gas
scrubbers). They projected that these
additional controls would cost tens of
millions of dollars per FCCU and would
require at least 3 years of compliance
time. Additionally, one commenter
stated that even FCCUs with additional
downstream PM controls would not be
able to achieve a site-specific limit at all
times and needed the availability of the
alternative 30-percent opacity limit. One
commenter estimated that installing an
ESP to meet the proposed 10-percent
opacity limit would cost approximately
$121,000/ton, assuming a 32 tpy PM
emission reduction. The commenter
noted that the ESP would also increase
GHG emissions and require more energy
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
resources from the facility. The
commenter concluded that installing an
ESP is neither cost effective nor
appropriate considering non-air quality
environmental and health impacts and
energy requirements, and recommended
that the EPA maintain the current NSPS
subpart J alternative limits and add
additional alternative limits into
Refinery MACT 2 only as optional limits
for demonstrating compliance with the
PM emissions limit.
Response: In promulgating Refinery
MACT 2, the EPA identified the 1.0 lb
PM/1,000 lbs coke burn-off limit as the
MACT floor but allowed a compliance
option for FCCUs subject to Refinery
NSPS subpart J to comply with an
opacity limit up to 30 percent with one
6-minute allowance to exceed the 30percent opacity in any 1-hour period. As
stated in the proposal, compliance
studies have shown that the 30-percent
opacity limit does not correlate well
with the 1.0 lb PM/1,000 lbs coke burnoff limit, and that an FCCU can comply
with the 30-percent opacity limit while
its emissions exceed the PM emissions
limit.9 Regardless of whether the 30percent opacity limit in Refinery NSPS
subpart J was designed to ‘‘ensure that
the control device was operated
properly,’’ Refinery MACT 2 allows
sources subject to NSPS subpart J to use
the 30-percent opacity limit to
demonstrate continuous compliance
with the PM emissions limit. We have
determined that the 30-percent opacity
limit is inadequate for the purpose of
demonstrating continuous compliance
with the PM emissions limits in
Refinery MACT 2. As such, we
proposed to remove this opacity limit
and require the owner or operator to
either demonstrate compliance with the
PM emissions limit by continuously
monitoring the control device
parameters established during the
performance test or establish and
monitor a site-specific opacity limit. For
clarity, we note that we proposed to
allow a site-specific opacity limit, not a
10-percent opacity limit as some
commenters suggest. The site-specific
opacity limit can be significantly higher
than 10 percent, but it cannot be lower
than 10 percent.
While the compliance study indicates
that a 30-percent opacity limit does not
correlate well with a 1.0 lb PM/1,000 lbs
coke burn-off emissions limit, further
review of this same study indicates that
a 20-percent opacity limit provides a
reasonable correlation with units
9 Compliance Investigations and Enforcement of
Existing Air Emission Regulations at Region 5
Petroleum Refineries. U.S. Environmental
Protection Agency, Region 5—Air and Radiation,
Chicago, Illinois. March 9, 1998.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
meeting the 1.0 lb PM/1,000 lbs coke
burn-off emissions limit. We also
reviewed the data submitted by the
commenters regarding PM emissions
and opacity correlation. While the data
suggest that there is variability and
uncertainty in the PM/opacity
correlation, the data do not support that
a 30-percent opacity limit would ensure
compliance even when considering the
uncertainty associated with the PM/
opacity correlation. Based on the
variability of the 3-run average opacity
limits, we determined that, if the 3-hour
average opacity exceeded 20-percent,
then it was highly likely (98 to 99percent confidence) that the FCCU
emissions from the unit tested would
exceed the PM emissions limit.
After considering the public
comments, reviewing the data submitted
with those comments, and further
review of the compliance study, in this
final rule we are adding a 20-percent
opacity limit, evaluated on a 3-hour
average basis for units subject to NSPS
subpart J. As we noted above, a 20percent opacity limit provides a
reasonable correlation with the PM
emissions limit, and an exceedance of
this 20-percent opacity limit will
provide evidence that the PM emissions
limit is exceeded. However, it is
possible that units could still exceed the
PM emissions limit while complying
with the 20-percent opacity limit, if
those units operate close to the 1 lb PM/
1,000 lbs coke burn-off emissions limit.
To address this concern, we considered
the commenters’ suggestion to require a
performance test annually rather than
once every 5 years. Some commenters
suggested that this option specifically
apply to FCCUs with cyclones, but this
option is applicable to any control
system operating very near the PM
emissions limit and using an opacity
limit to demonstrate continuous
compliance. We have determined that
the Refinery NSPS subpart J compliance
procedures in Refinery MACT 2, in
combination with a 20-percent opacity
limit demonstrated on a 3-hour average
basis and with annual performance tests
when a test indicates PM emissions are
greater than 80-percent of the limit (i.e.,
0.80 lb PM/1,000 lbs coke burn-off), will
ensure continuous compliance with the
PM emissions limit. FCCUs with
measured PM emissions during the
performance test at or below 0.80 lb PM/
1000 lbs of coke burn-off will remain
subject to the requirement to conduct
performance tests once every 5 years,
consistent with the requirements we
proposed.
We do not agree with commenters
that the proposed opacity revision
would add significant cost or
PO 00000
Frm 00027
Fmt 4701
Sfmt 4700
75203
compliance burden. The control devicespecific monitoring parameters that
were proposed rely on parameters
commonly used to control the operation
of the control device, so the monitoring
systems should be already available.
Further, since we are merely changing
the opacity limit, we expect these units
will already have opacity monitoring
systems needed to demonstrate
compliance with the PM emissions limit
and would not incur costs for new
equipment.
Comment: Several commenters stated
that they agree with the EPA’s
determination in the proposal that the
current CO limits provide adequate
control of HCN. Two commenters stated
that there are limited HCN emissions
data and that more data are needed
before the Agency can appropriately
determine whether an HCN standard is
necessary and justified. One commenter
noted that the process undertaken by
the EPA to estimate HCN emissions was
flawed, and likely overestimates HCN
emissions significantly. Another
commenter stated that they performed
HCN stack testing at three refineries and
subsequent modeling at two refineries
and concluded that the ambient HCN
emissions were well below the
applicable health limits.
In contrast, some commenters
expressed concerns about high HCN
levels. One commenter stated that the
EPA should consider re-evaluating the
benefit of low NOX emissions from the
FCCU, if that is indeed the cause of
higher HCN emissions, because
exposing people to HCN is not
acceptable. The commenter also noted
that the community now also has the
increased dangers of storing and
transporting aqueous ammonia, which
is used in some cases to achieve low
NOX emissions from the FCCU.
One commenter stated that the EPA
must set stronger HCN standards on
FCCU emissions because of the high
release amounts reported, the fact that
non-cancer risk is driven by emissions
of HCN from FCCU, and the fact that the
EPA has never set standards for HCN
emissions. The commenter provided a
report that they believe shows that the
EPA has not shown that CO is a
reasonable or lawful surrogate to control
HCN and has not shown that the
conditions necessary for a surrogate are
met with regard to CO and HCN, which
is an inorganic nonmetallic HAP.
Further, the report indicates that SCR is
a reasonable and cost effective method
for controlling HCN and that the EPA
failed to review and consider other
viable methods to control HCN and
must do so to satisfy its legal obligations
in this rulemaking.
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75204
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Response: At the time we
promulgated the MACT, we determined
that the control strategy used by the best
performing facilities to reduce organic
HAP emissions was the use of complete
combustion, which occurs when the CO
concentration is reduced to 500 ppmv
(see the proposal for Refinery MACT 2
at 63 FR 48899, September 11, 1998).
We rejected arguments that some
facilities operate at CO levels well
below 500 ppmv and, thus, the MACT
floor should be set at a lower CO
concentration because once CO
concentrations reached 500 ppmv, there
was no longer a correlation between
reduced CO concentrations and reduced
HAP concentrations. And, in fact,
emissions of certain HAP, such as
formaldehyde, tended to increase as CO
concentrations were reduced below 500
ppmv.10
In the current rulemaking action, we
determined at the time of the proposed
rule that this also holds true for HCN
emissions. That is, once CO emissions
are reduced to below 500 ppmv (i.e.,
complete combustion is achieved), we
no longer see a direct correlation
between CO concentrations and HCN
emissions.
All of the HCN emissions data we
have were reported from units operating
at or below the 500 ppmv CO limit (i.e.,
in the complete combustion range), so it
is not surprising that there is not a
strong correlation between CO and HCN
from the FCCU ICR source test data.
However, catalyst vendor data and
combustion kinetic theory support the
fact that, in the partial burn mode (with
CO concentrations of 2 to 6-percent,
which is 20,000 to 60,000 ppmv), HCN
concentrations exiting the FCCU
regenerator are much greater than for
units using complete combustion FCCU
regenerators or the concentration exiting
a post-combustion device used in
conjunction with a partial burn FCCU
regenerator. Therefore, we maintain that
complete combustion is the primary
control needed to achieve controlled
levels of HCN emissions.
We initially thought the higher levels
of HCN emissions that were reported by
sources achieving complete combustion
might be due to a switch away from
platinum-based combustion promoters
to palladium-based combustion
promoters. However, many of the units
that were tested and that had some of
the lowest HCN emissions used
palladium-based oxygen promoters.
Therefore, it appears unlikely that
10 U.S. EPA, 2001. Petroleum Refineries: Catalytic
Cracking Units, Catalytic Reforming Units, and
Sulfur Recovery Units—Background Information for
Promulgated Standards and Response to Comments.
Final Report.EPA–453/R–01–011. June. p. 1–19.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
palladium-based catalyst promoters are
linked to the higher HCN emissions. We
also evaluated one commenter’s
argument that CO is not a good
surrogate for HCN emissions, but that
SCR are a reasonable and cost-effective
control strategy. We are not aware of
any data that suggest that an SCR
removes HCN and the commenter did
not provide any support for that
premise. At proposal, we evaluated
HCN control on units using extra
oxygen or converting back to platinumbased promoters to oxidize any HCN
formed. This would cause more NOX
formation, which would then require
post-combustion NOX control, such as
an SCR. However, if HCN emissions are
not a function of CO concentration
beyond that required to achieve
complete combustion (as noted by the
commenter), then more aggressive
combustion conditions and the use of an
SCR (to remove the NOX formed) may
not be a viable control strategy.
Therefore, considering all of the data
currently available and the comments
received regarding HCN emissions and
controls, we maintain that the only
proven control technique is the use of
complete combustion as defined by a
CO level of 500 ppmv or less. We are
not establishing a more stringent CO
level because, once complete
combustion is achieved, (i.e., CO
concentrations drop below 500 ppmv),
no further reduction in HCN emissions
are achieved.
For the purposes of Refinery MACT 2,
we consider the emission limits and
operating requirements for organic HAP
in Tables 8 through 14 to subpart UUU
of part 63 adequate to also limit HCN
emissions.
Finally, we understand concerns
about the reported HCN emissions being
higher than anticipated and the need for
more data to better determine HCN
emissions levels. To address these
concerns, we are finalizing a
requirement that facility owners or
operators conduct a performance test for
HCN from all FCCU at the same time
they conduct the first PM performance
test on the FCCU following
promulgation of this rule. Facility
owners or operators that conducted a
performance test for HCN from a FCCU
in response to the refinery ICR or
subsequent to the 2011 Petroleum
Refinery ICR following appropriate
methods are not required to retest that
FCCU.
PO 00000
Frm 00028
Fmt 4701
Sfmt 4700
4. What is the rationale for our final
approach for the technology review?
a. Refinery MACT 1
We did not receive substantive
comments concerning our proposal that
it was not necessary to revise Refinery
MACT 1 requirements for MPV, gasoline
loading racks and cooling towers/heat
exchange systems. Based on the
rationale provided in the preamble to
the proposed rule, we are taking final
action concluding that it is not
necessary pursuant to CAA section
112(d)(6) to revise the MACT
requirements for MPV, gasoline loading
racks and cooling towers/heat exchange
systems emission sources at refineries.
We proposed that the options for
additional wastewater controls are not
cost effective and thus it was not
necessary to revise the MACT for these
emission sources. We received public
comments suggesting that emissions
from wastewater systems are higher
than modeled and that we should
develop additional technology
standards for wastewater treatment
systems regardless of cost. As we
discussed in the proposal, emissions
from wastewater are difficult to measure
and emission estimates rely on process
data and empirical correlations, which
introduces uncertainty into the
estimates. Although we do not have
evidence, based on the process data we
collected, that emissions are higher than
modeled at proposal, we note that the
fenceline monitoring program
effectively ensures that wastewater
emissions are not significantly greater
than those included in the emissions
inventory and modeled in the risk
assessment. Furthermore, we believe
that cost is a valid consideration in
determining whether it is necessary
within the meaning of section 112(d)(6)
to revise requirements and that we are
not required to establish additional
controls regardless of cost.
Consequently, we conclude that it is not
necessary to revise the Refinery MACT
1 requirements for wastewater systems
pursuant to CAA section 112(d)(6).
For storage vessels, we identified a
number of options, including requiring
tank fitting controls for external and
internal floating roof tanks, controlling
smaller tanks with lower vapor
pressures and requiring additional
monitoring to prevent roof landings,
liquid level overfills and to identify
leaking vents as developments in
practices, processes and control
technology. We proposed to crossreference the storage vessel
requirements in the Generic MACT
(effectively requiring additional control
for tank roof fittings) and to revise the
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
definition of Group 1 storage vessels to
include smaller tanks with lower vapor
pressures. We received comments that
we could have required additional
controls on tanks and monitoring for
landings, overfills and leaking vents
described above. We also received
comments related to clarifications of
specific rule references and overlap
provisions. We addressed these
comments in the ‘‘Response to
Comments’’ document, and we maintain
that the additional control options
described by the commenters (tank roof
landing/degassing requirements or use
of geodesic domes to retrofit external
floating roofs) are not cost-effective.
Consequently, based on the rationale
provided in the preamble to the
proposed rule and our consideration of
public comments, we are finalizing the
requirements as proposed with minor
clarifications of the rule references.
However, as with wastewater systems,
we note that the fenceline monitoring
program will ensure that the owner or
operator is effectively managing fugitive
emissions sources and should detect
landings, overfills, and leaking vents.
For equipment leaks, we identified
specific developments in practices,
processes and control technologies that
included requiring repair of leaking
components at lower leak definitions,
requiring monitoring of connectors, and
allowing the use of the optical imaging
camera as an alternative method of
monitoring for leaks. We proposed to
establish an alternative method for
refineries to meet LDAR requirements in
Refinery MACT 1. This alternative
would allow refineries to monitor for
leaks via optical gas imaging in place of
EPA Method 21, using monitoring
requirements to be specified in a not yet
proposed appendix K to 40 CFR part 60.
However, the development of appendix
K is taking longer than anticipated.
Therefore, we are not finalizing this
alternative monitoring method in
Refinery MACT 1.
We received comments suggesting
that additional requirements be imposed
to further reduce emissions from leaking
equipment components, such as
requiring ‘‘leakless’’ equipment,
reducing the leak threshold, and
eliminating delay of repair provisions.
As provided in the ‘‘Response to
Comments’’ document, we do not agree
that these additional requirements are
cost-effective. Based on the rationale
provided in the preamble to the
proposed rule and our consideration of
public comments, we conclude that it is
not necessary to revise the Refinery
MACT 1 requirements for equipment
leaks. Again, however, the fenceline
monitoring program is intended to
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
ensure that large leaks from fugitive
emissions sources, including equipment
leaks, are more quickly identified and
repaired, thereby helping to reduce
emissions from leaking equipment
components.
For marine vessel loading, we
identified control of marine vessel
loading operations with HAP emissions
of less than 10/25 tpy and the use of
lean oil absorption systems as
developments that we considered in the
technology review. We proposed to
amend 40 CFR part 63, subpart Y to
require small marine vessel loading
operations (i.e., operations with HAP
emissions less than 10/25 tpy) and
offshore marine vessel loading
operations to use submerged filling
based on the cargo filling line
requirements in 46 CFR 153.282. We
received comments that other options
considered during the technology
review of the standard were costeffective for small marine vessel loading
operations and should be required. As
provided in the ‘‘Response to
Comments,’’ we continue to believe
those other controls are not costeffective because of the high costs of
controls for limited additional organic
HAP emission reduction. Therefore, we
are finalizing these amendments as
proposed.
Finally, we proposed that it was
necessary to revise the MACT to require
fenceline monitoring as a means to
manage fugitive emissions from the
entire petroleum refinery, which
includes sources such as wastewater
collection and treatment operations,
equipment leaks and storage vessels. We
received numerous comments regarding
the proposed requirement to conduct
fenceline monitoring, many of which we
address above and the remainder of
which we respond to in the ‘‘Response
to Comments’’ document. After
considering comments, we maintain
that the proposed work practice
standard is authorized under section
112 of the CAA and will improve
fugitive management at the refinery.
Therefore, we are finalizing the key
components of fenceline monitoring
work practice as proposed. These
requirements include the use of passive
diffusive tube samplers (although we are
providing a mechanism to request
approval for alternative monitoring
systems provided certain criteria are
met), the 9 mg/m3 on a rolling annual
average basis action level, and the need
to perform corrective action to comply
with the action level.
Based on public comments received,
we are making numerous revisions to
clarify the fenceline monitor siting
requirements. This includes provisions
PO 00000
Frm 00029
Fmt 4701
Sfmt 4700
75205
to allow siting of monitors within the
property boundary as long as all
emissions sources at the refinery are
included within the monitoring
perimeter. We are also clarifying that we
do not consider public roads or public
waterways that bisect a refinery to be
property boundaries, and owners or
operators do not need to place monitors
along the internal public right-of-ways.
We are also providing provisions to
allow fixed placement of monitors at
500 feet intervals (with a minimum of
3 monitors) for subareas or segregated
areas. If an emissions source is near the
monitoring perimeter, an additional
monitor siting requirement would still
apply. The 500 feet provision is
provided to reduce burden for facilities
with irregular shapes or noncontiguous
property areas that we did not fully
consider at proposal.
We also received comments on the
compliance time and reporting
requirements associated with the
fenceline monitoring provisions. Upon
consideration of public comments, we
have revised the compliance period to 2
years after the effective date of the final
rule. Thus, beginning no later than 2
years after the effective date of the rule,
the source must have a fenceline
monitoring system that is collecting
samples such that the first rolling
annual average DC value would be
completed no later than 3 years after the
effective date of the final rule. Facilities
will have 45 days after the completion
of the first year of sampling, as
proposed, to submit the initial data set.
We are reducing the proposed
compliance period from 3 years to 2
years because the passive diffusive tube
monitors are easy to deploy and pilot
study demonstrations indicate that
significant time is not needed to deploy
the monitors. However, the reduced
compliance period still provides time to
resolve site-specific monitor placement
issues and to provide time to develop
and implement a site-specific
monitoring plan, if needed. We are
increasing the fenceline monitoring
reporting frequency (after the first year
of data collection) from semiannually to
quarterly to provide more timely
dissemination of the data collected via
this monitoring program.
b. Refinery MACT 2
We proposed to revise Refinery
MACT 2 to incorporate the
developments in monitoring practices
and control technologies reflected in the
Refinery NSPS subpart Ja limits and
monitoring provisions (73 FR 35838,
June 24, 2008). We are finalizing most
of these provisions as proposed.
Specifically, we are incorporating the
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75206
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Refinery NSPS subpart Ja PM limit for
new FCCU sources. We are also
finalizing compliance options for FCCU
that are not subject to Refinery NSPS
subpart J or Ja. These options would
allow such sources to elect to comply
with the Refinery NSPS subpart Ja
monitoring provisions to demonstrate
compliance with the emissions PM
limit. We are revising the averaging
period for the control device operating
limits or site-specific opacity limits to
be on a 3-hour average basis in order to
more directly link the operating limit to
the duration of the performance test
runs, on which they are based, as
proposed. We are incorporating
additional control device-specific
monitoring alternatives for various
control devices on FCCU, including
BLD monitoring as an option to COMS
for owners or operators of FCCU using
fabric filter-type control systems and
total power and secondary current
operating limits for owners or operators
of ESPs. We are adding an additional
requirement to perform daily checks of
the air or water pressure to atomizing
spray nozzles for owners or operators of
FCCU wet gas scrubbers not subject to
the pressure drop operating limit, as
proposed. Finally, we finalizing
requirements to conduct a performance
test at least once every 5 years for all
FCCU, as proposed. These requirements
are being finalized to ensure that control
devices are continuously operated in a
manner similar to the operating
conditions of the performance test and
to ensure that the emissions limits,
which are assessed based on the results
of three 1-hour test runs, are achieved
at all times.
We also proposed to eliminate the
Refinery NSPS subpart J compliance
option that allows refineries to meet the
30-percent opacity emissions limit
requirement and revise the MACT to
include control device operating limits
or site-specific opacity limits identical
to those required in Refinery NSPS
subpart Ja. We received numerous
comments, particularly from owners or
operators of FCCU that employ tertiary
cyclones to control FCCU PM emissions.
According to the commenters, opacity is
not a direct indicator of PM emissions
because finer particles will increase
opacity readings without a
corresponding mass increase in PM
emissions. Additionally, the
commenters stated that the site-specific
opacity limit generally leads to a sitespecific operating limit of 10-percent
opacity, which is too stringent and does
not adequately account for variability
between PM emissions and opacity
readings. According to the commenters,
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
FCCU with tertiary cyclones would
need to be retrofitted with expensive
and costly controls in order to meet the
10-percent opacity limit, even though
they are meeting the 1 lb/1000 lbs coke
burn PM emissions limit. It was not our
intent to require units to retrofit their
controls simply to meet the site-specific
opacity limit. However, the existing 30percent opacity limit in the subpart J
compliance option is not adequate to
ensure compliance with the PM
emissions limit at all times. After
reviewing the public comments and
available data, we determined that,
rather than removing the subpart J
compliance option altogether, it is
sufficient to add an opacity operating
limit of 20-percent opacity determined
on a 3-hour average basis to the existing
subpart J compliance option and to
require units complying with this
operating limit to conduct annual
performance tests (rather than one every
5 years) when the PM emissions
measured during the source test are
greater than 0.80 lb PM/1,000 lbs coke
burn-off. These provisions improve
assurance that these units are, in fact,
achieving the required PM emissions
limitation without requiring units to
retrofit controls due to variability in the
correlation of PM emissions and
opacity.
We did not propose to revise the
organic HAP emissions limits for FCCU
to further address HCN emissions. We
received numerous comments on this
issue. We continue to believe that
complete combustion is the appropriate
control needed to control HCN
emissions. Consequently, for the
purposes of Refinery MACT 2, we are
not changing the MACT standards to
further reduce emissions of HCN.
However, we understand that there are
uncertainties and high variability in
HCN emissions measured from FCCU.
In order to address the need for more
data to better characterize HCN
emissions levels, we are finalizing a
requirement for refinery owners or
operators to conduct a performance test
for HCN from all FCCU (except those
units that were tested previously using
acceptable methods as outlined in the
2011 Refinery ICR) during the first PM
test required as part of the on-going
compliance requirements for FCCU
metal HAP emissions. These data will
be useful to the EPA in understanding
HCN emissions from FCU and may help
to inform future regulatory reviews for
this source category.
We proposed that there have been no
developments in practices, processes,
and control technologies for CRU based
on our technology review and that
therefore it is not necessary to revise
PO 00000
Frm 00030
Fmt 4701
Sfmt 4700
these standards. Based on the rationale
provided in the preamble to the
proposed rule and our consideration of
public comments, we are finalizing our
conclusion.
For SRU, we identified the Refinery
NSPS subpart Ja allowance for oxygenenriched air as a development in
practice and we proposed that it was
necessary to revise the MACT to allow
SRU to comply with Refinery subpart Ja
as a means of complying with Refinery
MACT 2. The key issue identified by
commenters was that Refinery NSPS
subpart Ja includes a flow monitoring
alternative for determining the average
oxygen concentration in the enriched air
stream and that this was not included in
the proposed amendments to Refinery
MACT 2. This was an oversight on our
part. We are, based on the rationale
provided in the preamble to the
proposed rule and our consideration of
public comments, finalizing the SRU
revisions as proposed but with
inclusion of the flow monitoring
alternative provisions that are in
Refinery NSPS subpart Ja for this
source.
C. Refinery MACT Amendments
Pursuant to CAA Section 112(d)(2) and
(d)(3)
1. What did we propose pursuant to
CAA section 112(d)(2) and (d)(3) for the
Petroleum Refinery source categories?
We proposed the following revisions
to the Refinery MACT 1 and 2 standards
pursuant to CAA section 112(d)(2) and
(3) 11: (1) Adding MACT standards for
DCU decoking operations; (2) revising
the CRU purge vent pressure exemption;
(3) adding operational requirements for
flares used as APCD in Refinery MACT
1 and 2; and (4) adding requirements
and clarifications for vent control
bypasses in Refinery MACT 1.
For DCU, we proposed to require that
prior to venting or draining, each coke
drum must be depressured to a closed
blowdown system until the coke drum
vessel pressure is 2 psig or less. As
proposed, the 2 psig limit would apply
to each vessel opening/venting/draining
event at new or existing affected DCU
facilities.
For the CRU, we proposed to require
that any emissions during the active
11 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 postcompliance data, when originally-established floors
were improperly established).
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
purging or depressuring of CRU vessels
meet the applicable organic HAP
emission limitations in Tables 15 and 16
to subpart UUU regardless of the vessel
pressure.
For flares, we proposed to remove
cross references to the General
Provisions requirements for flares used
as control devices at 40 CFR 63.11(b)
and to incorporate enhanced flare
operational requirements directly into
the Refinery MACT rules. The proposed
rule amendments included:
• A ban on flaring of halogenated
vent streams.
• A requirement to operate with
continuously lit pilot flames at all times
and to equip the pilot system with an
automated device to relight the pilot if
it is extinguished.
• A requirement to operate with no
visible emissions except for periods not
to exceed a total of 5 minutes during
any 2 consecutive hours and to monitor
for visible emissions daily.
• A requirement to operate with the
flare tip velocity less than 60-feet-persecond or the velocity limit calculated
by an equation provided in the
proposed rule.
• A requirement to meet one of three
combustion zone gas properties
operating limits based on the net
heating value, lower flammability limit,
or combustion concentration. Owners or
operators could elect to comply with
any one of the three limits at any time.
Two separate sets of operating limits
were proposed: One for gas streams not
meeting all three ‘‘hydrogen-olefin
interaction criteria’’ specified in the rule
and a more stringent set of limits for gas
streams meeting all three hydrogenolefin interaction criteria. The
combustion zone net heating value
considered steam assist rates but not
‘‘perimeter air’’ assist rates.
• For air-assisted flares, a
requirement to meet an additional
‘‘dilution parameter’’ operating limit
determined based on the combustion
zone net heating values above, the
diameter of the flare and the perimeter
air assist rates.
The proposed amendments for flares
also included detailed monitoring
requirements to determine these
operating parameters either through
continuous parameter monitoring
systems or grab sampling, detailed
calculation instructions for determining
these parameters on a 15-minute block
average, and detailed recordkeeping and
reporting requirements. We also
proposed provisions to allow owners or
operators to request alternative
emissions limitations that would apply
in place of the proposed operating
limits.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
We proposed to revise the definition
of MPV to remove the current exclusion
for in situ sampling systems (onstream
analyzers). We also proposed to limit
the exclusion for gaseous streams routed
to a fuel gas system to apply only to
those systems for which any flares
receiving gas from the fuel gas system
are in compliance with the proposed
flare monitoring and operating limits.
We note that we also proposed revisions
related to monitoring of bypass lines,
but these revisions were proposed to
address concerns related to SSM
releases and are described in further
detail in section IV.D. of this preamble.
We proposed that emissions of HAP
may not be discharged to the
atmosphere from PRD in organic HAP
service to address concerns related to
SSM releases. To ensure compliance
with this proposed amendment, we
proposed to require that sources
monitor PRD 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. This
proposed requirement was addressed in
section IV.A.4. of the preamble for the
proposal.
2. How did the revisions pursuant to
CAA section 112(d)(2) and (3) change
since proposal?
We proposed identical standards for
existing and new DCU decoking
operations, but we are finalizing
standards for new and existing sources
that are not identical. We are finalizing
provisions that will require owners or
operators of existing DCU sources to
comply with a 2 psig limit averaged
over 60 cycles (i.e., 60 venting events),
rather than meet the 2 psig limit on a
per venting event basis, as proposed. We
are finalizing provisions that will
require owners or operators of new DCU
sources to comply with a 2.0 psig limit
on a per event, not-to-exceed basis. We
are adding one significant digit to the
limit for new DCU affected sources
because our re-review of permit
requirements conducted in response to
comments identified that the best
performing DCU source is required to
comply with a 2.0 psig limit on a per
event basis. In response to comments
regarding the proposed prohibition on
draining prior to achieving the pressure
limit, we are finalizing specific
provisions for DCU with water overflow
design and for double quenching.
For flares, we are not finalizing the
ban that we proposed on halogenated
vent streams and we are not finalizing
the proposed requirement to equip the
flare pilot system with an automated
device to relight an extinguished pilot.
PO 00000
Frm 00031
Fmt 4701
Sfmt 4700
75207
We are revising the MACT to include
the proposed no visible emissions limit
and the flare tip velocity limit as direct
emissions limits only when the flare
vent gas flow rate is below the
smokeless capacity of the flare. Under
the revised standard, when the flare is
operating above the smokeless capacity,
an exceedance of the no visible
emission limit and/or flare tip velocity
limit is not a violation of the standard
but instead triggers a work practice
standard. Flares operate above the
smokeless capacity only when there is
an emergency release event and thus the
work practice standard is intended to
address emissions during such
emergency release events. (See section
IV.D. of this preamble for more details
regarding this work practice standard).
We are also adding provisions that
would allow sources to use video
surveillance of the flare as an alternative
to daily Method 22 visible emissions
observations.
For flares, we are also simplifying the
combustion zone gas property operating
limits by finalizing a requirement only
for the net heating value of the
combustion zone gas. We are finalizing
requirements that flares meet a
minimum operating limit of 270 BTU/
scf NHVcz on a 15-minute average, as
proposed, and we are allowing refinery
owners or operators to use a corrected
heat content of 1212 BTU/scf for
hydrogen to demonstrate compliance
with this operating limit. We are not
finalizing separate combustion zone
operating limits for gases meeting the
hydrogen-olefin interaction criteria that
were proposed. We are also not
finalizing the alternative combustion
zone operating limits based on lower
flammability limit or combustibles
concentration.
We are finalizing ‘‘dilution
parameter’’ requirements for air-assisted
flares, but we are providing a limit only
for the net heating value dilution
parameter. Similar to the requirements
we are finalizing for the combustion
zone parameters, we are finalizing
requirements that flares meet a
minimum operating limit of 22 BTU/ft2
NHVdil on a 15-minute average, as
proposed, and we are allowing refinery
owners or operators to use a corrected
heat content of 1,212 BTU/scf for
hydrogen to demonstrate compliance
with this operating limit. We are not
finalizing separate dilution parameter
operating limits for gases meeting the
hydrogen-olefin interaction criteria that
were proposed. We are also not
finalizing the alternative dilution
parameter operating limits based on
lower flammability limit or
combustibles concentration.
E:\FR\FM\01DER2.SGM
01DER2
75208
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
We are providing an alternative to use
initial sampling period and process
knowledge for flares in dedicated
service as an alternative to continuous
or on-going grab sample requirements
for determining waste gas net heat
content.
We are finalizing revisions to the
definition of MPV, as proposed.
We are establishing work practice
standards that apply to PRD releases in
place of the proposed prohibition on
PRD releases to the atmosphere. The
work practice standards that we are
finalizing for PRD require refiners to
establish proactive, preventative
measures for each PRD to identify and
correct direct releases of HAP to the
atmosphere as a result of pressure
release events. Over time, these
proactive measures will reduce the
occurrence of releases and the
magnitude of releases when they occur,
while avoiding the environmental
disbenefits of having additional flare
capacity on standby to control these
unpredictable and infrequent events.
Refinery owners or operators will be
required to perform a root cause
analysis/corrective action following
such pressure release events. In
addition, a second release event in a 3year period from the same PRD with the
same root cause on the same equipment
is a deviation of the work practice
standard. A third release event in a
3-year period from the same PRD is a
deviation of the work practice standard
regardless of the root cause. PRD release
events related to force majeure events
are not considered in these hard limits.
3. What key comments did we receive
on the proposed revisions pursuant to
CAA section 112(d)(2) and (3) and what
are our responses?
tkelley on DSK3SPTVN1PROD with RULES2
i. DCU
Comment: Several commenters argued
that the EPA incorrectly set the MACT
floor emission limitation for DCU.
Commenters noted that CAA section
112(d)(3)(A) states that the MACT limit
for existing sources ‘‘shall not be less
stringent, and may be more stringent
than the average emission limitation
achieved by the best performing 12percent of the existing sources’’
excluding those first achieving that level
within 18 months prior to proposal or
30 months prior to promulgation,
whichever is later. According to the
commenters, the EPA failed to follow
this procedure in setting the 2 psig vent
limit as a MACT floor because the EPA
incorrectly considered permit limits and
other non-performance based criteria
instead of basing the MACT floor on the
actual performance of sources.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Commenters stated that the EPA
improperly considered permit limits
that should have been excluded from
consideration, as well as considering
permit limits for closed facilities instead
of using more accurate data from
operating DCUs at sources that
submitted actual emissions data.
Specifically, commenters stated that the
DCU at the non-operational plant
(Hovensa) should not be included. One
commenter noted that they operate one
of the South Coast DCU listed as subject
to a 2 psig limit and asserted that it does
not currently meet that emission
limitation. The commenter claimed that
significant capital investment would be
required in order for the DCU to comply
with the 2 psig limit. According to one
commenter, data for six of the eight
DCU they claim the EPA considered for
the MACT floor should not be counted
in determining the limit that represents
the average emission limitation actually
achieved 18 months prior to the
proposal.
Response: CAA section 112(d)(3)(A)
states that the existing source standard
shall not be less stringent than the
average emission limitation achieved by
the best performing 12-percent of the
existing sources (for which the
Administrator has emissions
information), excluding those sources
that have, within 18 months before the
emission standard is proposed or within
30 months before such standard is
promulgated, whichever is later, first
achieved a level of emission rate or
emission reduction which complies, or
would comply if the source is not
subject to such standard, with the
lowest achievable emission rate (as
defined by section 171) applicable to the
source category and prevailing at the
time, in the category or subcategory for
categories and subcategories with 30 or
more sources. We consider a 2 psig
emissions limitation to be equivalent to
the lowest achievable emission rate
(LAER) emission limits. Thus, we agree
with the commenter that sources that
first meet the 2 psig limit on or after
December 30, 2012, should be excluded
from the MACT floor analysis. We also
agree that under CAA section
112(d)(3)(A), the MACT floor analysis
focuses on those sources that are
achieving the emission limit (i.e., the
emission limitation ‘‘achieved by
. . . ’’). The EPA has previously
determined that the 6th-percentile unit
is a reasonable estimate of the average
emission limitation achieved by the best
performing 12-percent of sources
especially when averaging across units
with and without control requirements.
As noted in our DCU MACT floor
PO 00000
Frm 00032
Fmt 4701
Sfmt 4700
analysis memorandum (Docket ID No.
EPA–HQ–OAR–2010–0682–0203), the
6th-percentile is represented by the
fifth-best performing DCU. If we exclude
the two South Coast refineries and the
two Marathon Garyville DCU because
these sources were not implementing
the 2 psig permit limit prior to
December 30, 2012, the fifth-best
performing DCU would be represented
by the Bay Area refineries (4.6 psig).
However, based on the 2011 Petroleum
Refinery ICR responses, 25 out of 75 (33percent) DCU have a ‘‘typical coke drum
pressure when first vented to the
atmosphere’’ of 2 psig or less and 10 out
of 75 (13-percent) DCU have a ‘‘typical
coke drum pressure when first vented to
the atmosphere’’ of 1 psig or less. While
we acknowledge that these data
represent ‘‘typical’’ operations and not
necessarily a never-to-be-exceeded
emissions limitation, we conclude that
this information is sufficient for us to
conclude that the average emission
limitation achieved by the best
performing 12-percent of sources is
consistent with a 2 psig emissions
limitation. This is because facility
owners or operators commonly target to
operate at approximately half the
allowable emissions limit to ensure that
they can comply with the emissions
limit at all times. Therefore, we
maintain that an average venting
pressure of 2 psig is the MACT floor
level for decoking operation at existing
sources based on the ICR responses and
considering the average performance
expected.
Comment: Four commenters
suggested that the 2 psig limit, if
finalized, should be based on a rolling
30-day average per DCU rather than a
never to be exceeded ‘‘instantaneous’’
standard. According to the commenters,
an instantaneous standard is
unnecessary to address HAPs with
chronic health impacts and adds cost
and compliance challenges. According
to the commenters, chronic health
impacts are not materially affected by
short-term variability, but instead
depend on the average concentration of
exposure over a 70-year lifetime;
therefore, there is no health based or
environmental reason for requiring an
instantaneous limit. The commenters
noted that there would be additional
capital costs to comply with a 2 psig
not-to-be-exceeded limit compared to a
30-day average 2 psig limit vent
pressure. One commenter specifically
requested that the EPA also confirm that
a pressure of 2.4 psig is compliant with
the 2 psig limit vent pressure. Another
commenter also requested clarification
that the vent pressure can be rounded to
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
one significant figure when determining
compliance.
Response: For new sources, the
MACT floor emission limit for DCU is
based on the best-performing source.
Based on this and other comments
received, we again reviewed existing
permit conditions. Based on this review,
we found that one of the permit
requirements specified the pressure
limit as 2.0 psig for each coke drum
venting event. Therefore, we are
finalizing the new source MACT floor as
2.0 psig on a per coke drum venting
event basis.
As discussed in response to the
previous comment, we are basing the
MACT floor for existing source DCU on
responses we received from the 2011
Petroleum Refinery ICR. Because the
ICR requested the ‘‘typical coke drum
pressure when first vented to the
atmosphere,’’ we do not consider the
information provided in ICR responses
to reflect a ‘‘never-to-be-exceeded’’
limit. Therefore, we evaluated whether
it is reasonable to allow averaging, and
if so, what averaging period should be
provided.
Health risks are not considered in
establishing MACT requirements, so we
do not consider the argument that
chronic effects are evaluated over a 70year period to be relevant to a
determination of the MACT floor.
However, a primary consideration
regarding averaging periods is how the
averaging period was considered in
setting the floor and whether the
intended reductions will occur under a
different averaging period. According to
the heat balance method for estimating
DCU emissions, DCU decoking
operations emissions are directly
proportional to the average bed
temperature. While the relationship is
not exactly linear, the average bed
temperature is expected to be a function
of the venting pressure. Moreover, the
shape of the pressure-temperature
correlation curve is such that the
emissions at 6 psig are almost exactly
but not quite three times the emissions
at 2 psig. Given the expected linearity
of the emissions with venting pressures,
we are not concerned with an
occasional venting event above 2 psig
because the average emissions from a
facility meeting an average 2 psig
pressure limit would be identical to the
emissions achieved by a facility that
vented each time at 2 psig. That is,
given the expected linearity in the
projected DCU emissions to the venting
pressure, we conclude that it is
reasonable to allow averaging across
events and that the precise averaging
period is not a critical concern.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Most industry commenters requested
a 30-day average. However, different
facilities have different numbers of
DCU, different numbers of drums per
DCU and different cycle times.
Consequently, basing the averaging
period across a given time period would
result in significantly different number
of venting events included in a 30-day
average for different facilities and
generally provide more flexibility to
larger refineries and less flexibility to
smaller refineries. Based on the ICR
responses, almost half of all DCU
operate with two drums and about 90percent of DCU have two to four coke
drums; however, a few DCU have six or
even eight drums. Also, based on the
ICR responses, the average complete
coke drum cycle time is 32 hours, but
can be as short as 18 hours and as long
as 48 hours. Reviewing the ICR
responses, we found that a 30-day
average would include 30 events for
some facilities and more than 250
events at other facilities.
Since the existing source MACT
standards apply ‘‘in combination’’ to
‘‘all releases associated with decoking
operations’’ at a given facility, we
determined that it was reasonable to
consider an averaging period that
applies to the number of venting events
from all coke drums at the facility rather
than to all coke drums for a specific
DCU for a specified period of time. This
provides a more consistent basis for the
averaging period and allows the same
operational flexibility for small
refineries as large refineries. Based on
the ICR responses, the median (typical)
DCU has 60 venting events in a 30-day
period. Providing an averaging period of
60 venting events provides a more
consistent averaging basis for all
facilities, regardless of the number of
DCU at the facility and the number of
drums and cycle times for different
DCU. Additionally, it eliminates issues
with respect to how to handle operating
days versus non-operating days, e.g., in
the event of a turn-around resulting in
a limited number of venting events in a
30-calendar day period. Therefore, we
are establishing a 2 psig limit based on
a 60-event average considering all coke
drum venting events at an existing
source and we are finalizing a 2.0 psig
limit on a per coke drum venting event
for DCU at new sources.
We have consistently maintained our
policy to round to the last digit
provided in the emission limit, a
pressure of 2.4 psig would round to 2
psig and would be compliant with a
requirement to depressure each coke
drum to a closed blowdown system
until the coke drum vessel pressure is
2 psig or less, but it would not be
PO 00000
Frm 00033
Fmt 4701
Sfmt 4700
75209
compliant with the revised new source
provision to depressure until the coke
drum vessel pressure is 2.0 psig or less.
A coke drum pressure of 2.04, however,
would be compliant with the revised
new source requirement pressure limit
of 2.0 psig.
ii. Refinery Flares
Comment: Several commenters
suggested that the proposed flare
operating limits were too complex. The
commenters recommended that the EPA
eliminate the dual flare combustion
zone heat content limits related to the
proposed hydrogen-olefin interaction
criteria and instead finalize a single
combustion zone net heating value of
approximately 200 BTU/scf, which
would minimize the unnecessary
burning of supplemental gas but still
ensure good combustion efficiency.
A few commenters suggested that the
EPA based the proposed combustion
zone limits on an invalid data analysis,
that the 1 minute PFTIR data should not
be used to establish combustion
efficiency correlations, and that the
emission limits should be set so as to
provide an equal chance of false
positives and negatives. A few
commenters suggested that the EPA
should assign hydrogen a heating value
of 1,212 BTU/scf to more accurately
reflect its flammability in a NHV basis
and that doing so is consistent with
some recent flare consent decrees and
would help reduce natural gas
supplementation for facilities
complying only with the NHVcz metric.
Several commenters suggested that
neither scientific literature nor the
available flare test data support the
EPA’s claim of an adverse hydrogenolefin interaction on combustion
efficiency and that the EPA should not
finalize the more restrictive combustion
zone operating limits for all flare types.
These commenters suggested that the
EPA did not provide any evidence the
assumed hydrogen-olefin effect actually
exists; that statistical analysis
demonstrates the EPA developed their
limit based on random differences in
data; that the PFTIR data analysis
method of using the individual minuteby-minute data instead of the test
average data is flawed and leads to
invalid conclusions; and that proper
analysis of the data demonstrates the
more stringent operating limits for
hydrogen-olefin conditions cannot be
supported.
Some commenters suggested that
there is evidence to support more
stringent flare combustion zone limits
for a narrowly defined high
concentration propylene-only condition
as outlined in some of the recent flare
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75210
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
consent decrees but that the flare test
data do not support more stringent
operating limits for the proposed
hydrogen-olefins criteria by the EPA.
Additionally, one commenter suggested
that if the EPA decides to proceed with
the more restrictive combustion zone
limits for the hydrogen-olefins
interaction cases then the final rule
should not expand beyond an
interaction between hydrogen and
propylene.
Several commenters suggested that
the proposed 15-minute feed forward
averaging time for flares (e.g.,
combustion zone parameters, air-assist
dilution parameters and associated flow
rates) is arbitrary, unrealistic and
unworkable and that the feed forward
compliance determination should not be
finalized and, if it is finalized, the
averaging time should be extended to
1-hour, 3-hour, or 24-hour. To support
these suggested averaging periods,
commenters claimed that typical
standards for combustion devices are
averaged over these suggested
timeframes, noting as an example,
recent refinery flare consent decrees that
contain a 3-hour average. The
commenters also asserted that both a GC
and calorimeter will be needed to obtain
data rapidly enough to try and maintain
a 15-minute average; that the feed
forward approach requires calculation
artifices to attempt to correct for the fact
that compliance cannot be determined
until the averaging period is over; and
that a longer averaging time is needed
for instrument and control response
time.
Response: In addressing these
comments, we further analyzed the flare
emissions test data. First, to address
concerns that the minute-by-minute
analysis produced flawed results, we recompiled the data into approximate
‘‘15-minute averages’’ to the extent
practical based on the duration of a
given test run (e.g., a 10-minute run was
used as 1 run and a 32-minute run was
divided into 2 runs of 16 minutes each).
We do not find significant differences in
the data or that different conclusions
would be drawn from the data based on
this approach as compared with the
minute-by-minute analysis used for the
proposed rule.
Next, we evaluated the 15-minute run
data using the normal net heating value
for hydrogen of 274 Btu/scf, which is
the value we used in the analysis for the
proposed rule and also evaluated the
data using the 1,212 Btu/scf, the value
recommended by some commenters.
The 1,212 Btu/scf value is based on a
comparison between the lower
flammability limit and net heating value
of hydrogen compared to light organic
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
compounds and has been used in
several consent decrees to which the
EPA is a party. Based on our analysis,
we determined that using a 1,212 Btu/
scf value for hydrogen greatly improves
the correlation between combustion
efficiency and the combustion zone net
heating value over the entire array of
data. Using the net heating value of
1,212 Btu/scf for hydrogen also greatly
reduced the number of ‘‘type 2 failures’’
(instances when the combustion
efficiency is high, but the gas does not
meet the NHVcz limit). One of the
primary motivations for the proposed
approach to provide alternative limits
based on lower flammability limits and
combustibles concentrations was to
reduce these type 2 failures. Therefore,
we proposed all three of these
parameters (i.e., NHVcz, LFL and total
combustibles) and allowed flare owners
or operators to comply with any of the
parameter limits at any time. When
using the net heating value of 1,212 Btu/
scf for hydrogen, the other two
alternatives no longer provide any
improvement in the ability to predict
good flare performance. Consequently,
we are simplifying the operating limits
to use only NHVcz.
Next, we re-evaluated whether to
finalize the proposed dual combustion
zone operating limits for refinery flares
that met certain hydrogen-olefins
interactions or to finalize a single
combustion zone net heating value
limit. The newly re-compiled PFTIR run
average flare dataset suggests that higher
operating limits may be appropriate for
some olefin-hydrogen mixtures.
However, the dataset using 15-minute
test average runs is much smaller than
the set using 1-minute runs and thus
creates a greater level of uncertainty. In
addition, we cannot definitively
conclude that a dual combustion zone
limit for refinery flares meeting certain
hydrogen-olefins interactions is
appropriate given these uncertainties.
Thus, in order to minimize these
uncertainties and streamline the
compliance requirements, we used all of
the 15-minute test run average data
together as a single dataset in an effort
to determine an appropriate, singular
combustion zone net heating value
operational limit.
Finally, we conducted a Monte Carlo
analysis to help assess the impacts of
extending the averaging time on the test
average flare dataset of 15-minute runs
to 1-hour or 3-hour averaging time
alternatives. While we consider it
reasonable to provide a longer averaging
time for logistical reasons, the Monte
Carlo analysis demonstrated, consistent
with concerns described in our
proposal, that short periods of poor
PO 00000
Frm 00034
Fmt 4701
Sfmt 4700
performance can dramatically limit the
ability of a flare to achieve the desired
control efficiency. Consequently, we
find it necessary to finalize the
proposed 15-minute averaging period to
ensure that the 98-percent control
efficiency for flares is achieved at all
times. However, we understand that
flare vent gas flow and composition are
variable. While a short averaging time is
needed to ensure adequate control given
this variability, we also understand the
complications that this variability
places on flare process control in efforts
to meet the NHVcz limit. Therefore, we
are clarifying that the 270 Btu/scf
NHVcz value is an operational limit that
must be calculated according to the
requirements in this rule. We also
clarify that compliance with this
operational limit must be evaluated
using the equations and calculation
methods provided in the rule. We
proposed a feed forward calculation
method to allow refinery owners or
operators a means by which to adjust
steam (or air) and, if necessary,
supplemental natural gas flow, in order
to meet the limit. In other words, ‘‘feed
forward’’ refers to the fact that the rule
requires the refinery owners or
operators to use the net heating value of
the vent gas (NHVvg) going into the flare
in one 15-minute period to adjust the
assist media (i.e., steam or air) and/or
the supplemental gas in the next 15minute period, as necessary for the
equation in the rule to calculate an
NHVcz limit of 270 BTU/scf or greater.
We recognize that when a subsequent
measurement value is determined, the
instantaneous NHVcz based on that
compositional analysis and the flow
rates that exist at the time may not be
above 270 Btu/scf. We clarify that this
is not a deviation of the operating limit.
Rather, the owner or operator is only
required to make operational
adjustments based on that information
to achieve, at a minimum, the net
heating value limit for the subsequent
15-minute block average. Failure to
make adjustments to assist media or
supplemental natural gas using the
equation provided for calculating an
NHVcz limit of 270 BTU/scf, using the
NHVvg from the previous period, would
be a deviation of the operating limit.
Alternatively, if the owner or operator
is able to directly measure the NHVvg
on a more frequent basis, such as with
a calorimeter (and optional hydrogen
analyzer), the process control system is
able to adjust more quickly, and the
owner or operator can make adjustments
to assist media or supplemental natural
gas more quickly. In this manner, the
owner or operator is not limited by
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
relying on NHVvg data that may not
represent the current conditions.
Therefore, the owner or operator may
opt to use the NHVvg from the same
period to comply with the operating
limit.
Based on the results of all of our
analyses, the EPA is finalizing a single
minimum NHVcz operating limit for
flares subject to the Petroleum Refinery
MACT standards of 270 BTU/scf during
any 15-minute period. The agency
believes, given the results from the
various data analyses conducted, that
this operating limit is appropriate,
reasonable and will ensure that refinery
flares meet 98-percent destruction
efficiency at all times when operated in
concert with the other suite of
requirements refinery flares need to
achieve (e.g., flare tip velocity
requirements, visible emissions
requirements, and continuously lit pilot
flame requirements). For more detail
regarding our data re-analysis, please
see the memorandum titled ‘‘Flare
Control Option Impacts for Final
Refinery Sector Rule’’ in Docket ID No.
EPA–HQ–OAR–2010–0682.
Comment: Numerous commenters
objected to the proposed requirements
to have the velocity and visible
emissions limits apply at all times for
flares. Commenters suggested that flares
are not designed to meet the visible
emissions and flare tip velocity
requirements when being operated
beyond their smokeless capacity and
suggested several alternative
approaches: remove the visible
emissions and flare tip velocity
requirements from the rule altogether;
exempt flares from these requirements
during emergencies; or add a
requirement to maintain a visible flame
present at all times or include a work
practice standard in the rule when flares
are operated beyond their smokeless
capacity at full hydraulic load. The
commenters identified full hydraulic
load as the maximum flow the flare can
receive based on the piping diameter of
the flare header and operating pressure
of processes connected to the flare
header system. They also specified that
full hydraulic load would only occur if
all sources connected to the flare header
vented at the same time, which might
result from an emergency shutdown due
to a plant-wide power failure.
According to commenters, flares are
typically designed to operate in a
smokeless manner at 20 to 30-percent of
full hydraulic load. Thus, they claimed,
flares have two different design
capacities: A ‘‘smokeless capacity’’ to
handle normal operations and typical
process variations and a ‘‘hydraulic load
capacity’’ to handle very large volumes
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
of gases discharged to the flare as a
result of an emergency shutdown.
According to commenters, this is
inherent in all flare designs and it has
not previously been an issue because
the flare operating limits did not apply
during malfunction events. However, if
flares are required to operate in a
smokeless capacity during emergency
releases, the commenters claimed that
refineries would have to quadruple the
number of flares at each refinery to
control an event that may occur once
every 2 to 5 years.
To support their suggestions,
commenters pointed out that flaring
during emergencies is the optimum way
of handling very large releases and that
the flare test data clearly demonstrate
that visible emissions and/or high flare
tip velocity do not suggest poor
destruction efficiency during such
events. The commenters also argued
that operators should not have
conflicting safety and environmental
considerations to deal with during these
times. The commenters stated that
refiners are still subject to a civil suit
even if the EPA uses its enforcement
discretion where such a release would
violate the limit and in order to avoid
such liability, many new flares would
have to be built. Commenters estimated
that 500 new large flare systems at a
capital cost in excess of $10–20 billion
would need to be built because of the
amount of smokeless design capacity
that would be needed and that this
significant investment would take the
industry at least a decade to install.
Response: At the time of the proposed
rule, we did not have any information
indicating that flares were commonly
operated during emergency releases at
exit velocities greater than 400 ft/sec
(which is 270 miles per hour (mph)).
Similarly, we did not have information
to indicate that flares were commonly
designed to have a smokeless capacity
that is only 20 to 30-percent of their
‘‘hydraulic load capacity.’’ While we are
uncertain that refineries actually would
install additional flares to the degree the
commenters claim, based on the
possibility that there may be an event
every 2 to 5 years that would result in
a deviation of the smokeless limit, we
also recognize that it would be
environmentally detrimental to operate
hundreds of flares on hot standby in an
effort to never have any releases to a
flare that exceed the smokeless capacity
of that flare. This is because operating
hundreds of new flares to prevent
smoking during these rare events will
generate more ongoing emissions from
idling flares than the no visible
emissions limit might prevent during
one of these events. Therefore, we
PO 00000
Frm 00035
Fmt 4701
Sfmt 4700
75211
considered alternative operating limits
or alternative standards that could apply
during these emergency release events.
As an alternative to the proposed
requirement that flares meet the visible
emissions and velocity limits at all
times, we considered a work practice
standard for the limited times when the
flow to the flare exceeds the smokeless
capacity of the flare. Owners or
operators of flares would establish the
smokeless capacity of the flare based on
design specification of the flare. Below
this smokeless capacity, the velocity
and visible emissions standards would
apply as proposed. Above the smokeless
capacity, flares would be required to
perform root cause analysis and take
corrective action to prevent the
recurrence of a similarly caused event.
Multiple events from the same flare in
a given time period would be a
deviation of the work practice standard.
Force majeure events would not be
included in the event count for this
requirement.
Based on industry claims that there is
a hydraulic load flaring event, on
average, every 4.4 years, we assumed
the best performers would have no more
than one event every 6 years, or a
probability of 16.7-percent of having an
event in any given year. We found that,
over a long period of time such as 20
years, half of these best performers
would have 2 events in a 3 year period,
which would still result in over half the
‘‘best performing’’ flares having a
deviation of the work practice standard
if it was limited to 2 events in 3 years.
Conversely, only 6 percent would have
3 events in 3 years over this same time
horizon. Based on this analysis, 3 events
in 3 years would appear to be
‘‘achievable’’ for the average of the best
performing flares.
Pursuant to CAA section 112(d)(2)
and (3), we are finalizing a work
practice standard for flares that is based
on the best practices of the industry,
and considers the rare hydraulic load
events that inevitably occur at even the
best performing facilities.
The best performing facilities have
flare management plans that include
measures to minimize flaring during
events that may cause a significant
release of material to a flare. Therefore,
we are requiring owners or operators of
affected flares to develop a flare
management plan specifically to
identify procedures that will be
followed to limit discharges to the flare
as a result of process upsets or
malfunctions that cause the flare to
exceed its smokeless capacity. We are
specifically requiring refinery owners or
operators to implement appropriate
prevention measures applicable to these
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75212
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
emergency flaring events (similar to the
prevention measures we are requiring in
this final rule to minimize the
likelihood of a PRD release). Refiners
will be required to develop a flare
minimization plan that describes these
proactive measures and reports
smokeless capacity. Refiners will need
to conduct a specific root cause analysis
and take corrective action for any flare
event above smokeless design capacity
that also exceeds the velocity and/or
visible emissions limit. If the root cause
analysis indicates that the exceedance is
caused by operator error or poor
maintenance, the exceedance is a
deviation from the work practice
standard. A second event within a
rolling 3-year period from the same root
cause on the same equipment is a
deviation from the standard. Events
caused by force majeure, which is
defined in this subpart, would be
excluded from a determination of
whether there has been a second event.
Finally, and again excluding force
majeure events, a third opacity or
velocity limit exceedance occurring
from the same flare in a rolling 3-year
period is a deviation of the work
practice standard, regardless of the
cause.
Comment: Several commenters
suggested that the EPA should revise the
combustion efficiency requirements to
apply only to steam-assisted flares used
as Refinery MACT control devices
during periods of time that the flares are
controlling Refinery MACT regulated
streams. One commenter suggested that
the EPA misused the TCEQ data in
proposing the NHVcz metric and that the
proposed limits are overly conservative.
The commenter requested that the EPA
work with stakeholders to conduct
additional testing to determine what, if
any, operating parameters are
appropriate and necessary to achieve an
adequate destruction efficiency for nonsteam-assisted flares.
Response: We disagree with the
commenters that the combustion
efficiency requirements should apply
only to steam-assisted flares. The
available data (for runs where steam
assist is turned off) as well as the
available combustion theories suggest
that the combustion zone net heating
value minimum limit, which is the vent
gas net heating value for unassisted or
perimeter air-assisted flares, is
necessary to ensure proper flare
performance. While we agree that
additional data on air-assisted flares
would allow for a more robust analysis,
the data we do have strongly indicate
that air-assisted flares can be overassisted and that the combustion
efficiency of air-assisted flares that are
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
over-assisted is below 98-percent
control efficiency.
Comment: A few commenters
suggested that the proposed flare
regulations should not apply to part 63,
subpart R (gasoline loading) and subpart
Y (marine vessel loading) facilities, and
to part 61, subpart FF (benzene waste)
facilities. The commenters
recommended that flares associated
with gasoline loading, marine vessel
loading and wastewater treatment
emissions need to comply only with the
General Provisions for flares. Some of
these commenters argued that these
sources are more consistent in flow and
composition than other refinery sources,
so the new requirements are not
necessary to ensure good combustion for
these ‘‘dedicated’’ flares. Some
commenters suggested that operators of
flares with consistent flow and
composition be allowed to use process
knowledge or engineering judgment
rather than be required to install
continuous monitors or be subject to
ongoing grab sampling requirements.
Some commenters noted that the
required control efficiency for some
refinery emissions sources subject to
subpart CC sources is 95-percent. One
commenter also requested that the EPA
provide overlap provisions so flares
used to control sources from different
MACT sources would not have
duplicative requirements.
Response: The regulatory revisions
that we are finalizing apply to
petroleum refinery sources subject to
part 63, subparts CC and UUU. Gasoline
loading, marine vessel loading and
wastewater treatment operations that are
part of the refinery affected source as
defined at 40 CFR 63.640 are subject to
subpart CC. Gasoline loading, marine
vessel loading and wastewater treatment
operations located at non-refinery
source categories are not subject to part
63, subpart CC and, thus, would not be
subject to the revisions to subpart CC
being finalized in this action. To the
extent that the commenters are
requesting that the EPA establish flare
requirements that would apply to flares
that are not part of the refinery affected
source, that request is beyond the scope
of this rulemaking, which only
addresses revisions to Refinery MACT 1
and 2. When we issue rules addressing
requirements for other sources with
flares, we will consider issues similar to
those we considered in this action and
determine at that time whether revisions
to those other flare requirements are
necessary.
The commenters note that some
subpart CC emissions sources have only
a control efficiency requirement of 95percent. While this may be true, where
PO 00000
Frm 00036
Fmt 4701
Sfmt 4700
the owner or operator chooses to control
these sources through the use of a flare,
operation of that flare was subject to
operational requirements in the General
Provisions at 40 CFR 63.11 and the best
performing flares were achieving 98percent control at the time the General
Provisions were promulgated. At the
time the General Provisions were
promulgated, we received no comments
that the EPA should set different
operational limits for flares that are
controlling emissions from sources
where the standard may vary by level of
control efficiency and we see no basis
to do so now. The purpose of the
revisions to the flare operating
requirements is to ensure that flares are
operating consistent with the MACT
floor requirements for any and all
sources that may use flares as a control
device (79 FR 36905, June 30, 2014). As
the MACT floor control requirements of
certain refinery sources that allow the
use of a flare as a control device is 98percent, we established operational
limits to ensure flares used as control
devices meet this MACT requirement.
To the extent that the commenters are
requesting that the EPA establish an
alternative monitoring approach for
flares in dedicated service that have
consistent composition and flow, we
agree that these types of flares, which
have limited flare vent gas streams, do
not need to have the same type of ongoing monitoring requirements as those
with more variable waste streams. Thus,
we are establishing an option that
refinery owners or operators can use to
demonstrate compliance with the
operating requirements for flares that
are in dedicated service to a specific
emission source, such as a wastewater
treatment operation. Refinery owners or
operators will need to submit an
application for the use of this
alternative. The application must
include a description of the system,
characterization of the vent gases that
could be routed to the flare based on a
minimum of 7 grab samples (14 daily
grab samples for continuously operated
flares) and specification of the net
heating value that will be used for all
flaring events (based on the minimum
net heating value of the grab samples).
We are also allowing engineering
estimates to characterize the amount of
gas flared and the amount of assist gas
introduced into the system. For
example, the use of fan curves to
estimate air assist rates is acceptable.
Flare owners or operators would use the
net heating value determined from the
initial sampling phase and measured or
estimated flare vent gas and assist gas
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
flow rates, if applicable, to demonstrate
compliance with the standards.
Comment: A few commenters
suggested that the EPA’s proposed work
practice and monitoring standards for
flares are CAA section 112(d)
‘‘developments’’ required by law and
supported by the evidence, and reflect
best practices at many refineries today.
One commenter suggested that the EPA
must allow companies with consent
decrees to meet their consent decree
requirements as an alternative
compliance approach and in lieu of the
proposed requirements.
Response: We proposed the enhanced
monitoring requirements and operating
limits under authority of CAA sections
112(d)(2) and (d)(3) to ensure that flares
used to control regulated Refinery
MACT 1 or 2 gas streams are meeting
the prescribed control efficiencies
established at the time the MACT
standard was promulgated. And, we
continue to believe that these revisions
are appropriate under CAA sections
112(d)(2) and (d)(3). The commenter has
not suggested, and we do not believe,
that the revisions promulgated would
differ in substance if they were instead
promulgated under CAA section
112(d)(6).
In general, we expect that the NHVcz
monitoring requirements that we are
finalizing for flares will be consistent
with the requirements in various
consent decrees. However, we have not
conducted a rigorous evaluation of
equivalency between various
requirements and therefore we are not at
this time providing an allowance for
flare owners or operators to comply
with the NHVcz operating limits and any
provisions for necessary monitoring
needed in the consent decree in lieu of
the NHVcz limits and monitoring
requirements established in this rule. In
the event that an owner or operator
wishes to continue complying only with
the requirements of a consent decree,
the rule contains provisions by which
owner or operator can seek approval for
alternative limits that are at least
equivalent to the performance achieved
from complying with the operating
limits included in the final rule.
iii. Pressure Relief Devices
Comment: Several commenters
suggested that the EPA develop a work
practice approach for atmospheric PRD
rather than a prohibition on releases.
One commenter recommended that the
EPA establish a work practice standard
for atmospheric PRDs that requires
refiners to implement a base level of
preventative measures including: Basic
process controls, instrumented alarms,
documented and verified routine
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
inspection and maintenance programs,
safety-instrumented systems, disposal
systems, provide redundant equipment,
increase vessel design pressure and
systems that reduce fire exposure on
equipment. Additionally, the
commenter recommended that the EPA
require refiners to perform root cause
analysis and implement corrective
action in the event of a release. The
commenter stated these requirements
would be similar to the root cause
analysis/corrective action requirements
recently promulgated for flares under
NSPS subpart Ja and provided specific
regulatory language for a proposed work
practice approach. (See section 2.4.1.8
in Docket item EPA–HQ–OAR–2010–
0682–0583.) One commenter requested
that the EPA allow a process for
companies to submit an application for
case-by-case limits to be approved by
the agency, either the EPA or a
delegated state similar to the alternate
NOX limits for process heaters provided
in NSPS subpart Ja. This commenter
recommended that the EPA establish
reasonable work practice standards,
specifically suggesting that the EPA
develop work practice standards
consistent with API 521. The
commenter stated that the EPA should
provide an implementation period for
compliance that goes beyond the
timeframe provided under CAA section
112(d). The commenter added that the
EPA should adopt specified changes to
the definition of an atmospheric
pressure relief safety valve and provided
suggested regulatory language for a
proposed work practice standard for
PRDs in EPA–HQ–OAR–2010–0682–
0549.
Another commenter stated that the
EPA should require, as the Bay Area Air
Quality Management District
(BAAQMD) does, that any refinery that
has a reportable PRD event must take
certain steps to prevent such releases in
the future (BAAQMD Rule 8–28–304).
In particular, such a refinery must create
a Process Hazard Analysis, meet the
Prevention Measures Procedures
specified in section 8–28–405, and
conduct a failure analysis of the
incident, to prevent recurrence of
similar incidents (Id. Reg. section 8–28–
304.1). If a second release occurs, then,
within one year, the facility must vent
its PRDs to a vapor recovery or disposal
system that meets certain requirements
(Id. Reg. section 8–28–304.2). The
commenter asserted that the EPA’s
prohibition on releases to the
atmosphere from PRD will ensure that
refineries take the necessary steps to
prevent such releases, or install control
devices so that any releases from PRDs
PO 00000
Frm 00037
Fmt 4701
Sfmt 4700
75213
that must occur are vented through a
control device to reduce the amount of
toxic air pollution they emit. At a
minimum, the commenter stated, the
EPA must prohibit these uncontrolled
emissions and require monitoring and
reporting to assure compliance and
ensure that the emission standards
apply at all times, as required by the
Act. The commenter argued that the
EPA must also, however, consider
requiring the additional developments
that have been put into place in the
BAAQMD and also require control
devices to be used for all PRD, as some
local air districts require. In addition,
the commenter supported the EPA’s
monitoring and reporting requirements
for PRD releases and the proposed
electronic reporting requirements,
which the EPA recognized are needed to
assure compliance and assist with
future rulemakings and as that provision
requires, the EPA also must make all
information reported publicly available
online promptly and in an accessible
and understandable format.
Response: We agree that, under the
proposal, refineries would consider
installing add-on controls to comply
with the prohibition on atmospheric
releases from PRDs. In addition, they
would consider venting these control
devices to existing control devices,
including flares. However, it may not be
feasible to vent some or all of the PRDs
to existing flares if the flares are near
their hydraulic load capacity based on
the processes already connected to the
flares. Flares have negative secondary
impacts when operated at idle
conditions for the vast majority of time,
which could be the case if they were
installed solely to address PRD releases.
These secondary impacts result from
GHG, CO and NOX emissions. Some
PRDs may vent materials that are not
compatible with flare control and would
need to be vented to other controls.
To estimate the impact of the
proposed prohibition on venting PRDs
to the atmosphere, we estimated that at
least one new flare per facility would be
required to handle releases from PRDs,
based on the number of atmospheric
PRDs reported at refineries; that 60percent of the PRDs could be piped to
existing controls at minimal costs and
the other 40-percent would have to be
piped to new flares; and that, on
average, each new flare would service
40 PRDs. Based on these assumptions,
151 new flares would be needed or
approximately one new flare per
refinery. At a capital cost of $2 million
for each new flare, which would not
include long pipe runs, if needed, to
PRD that are dispersed across the plant,
we estimate that the capital cost of the
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75214
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
prohibition on venting to the
atmosphere would exceed $300 million.
Considering the fuel needed
(approximately 50,000 scf/day per flare)
and a natural gas price of $4.50 per
1,000 scf, we estimate the annual
operating cost for these new flares to be
$12 million.
PRDs are unique in that they are
designed for the purpose of releasing or
‘‘popping’’ as a safety measure to
address pressure build-up in various
systems—pipes, tanks, reactors—at a
facility. These pressure build-ups are
typically a sign of a malfunction of the
underlying equipment. While it would
be difficult to regulate most malfunction
events because they are unpredictable
and can vary widely, in the case of
PRDs, they are equipment installed
specifically to release during
malfunctions and as such, we have
information on PRDs in our 2011
Refinery ICR and through the SCAAMD
and BAAQ rules to establish standards
for them. After reviewing these
comments, we thus examined whether it
would be feasible to regulate these
devices under CAA section 112(d)(2)
and (3).
After reviewing the comments, we
agree with the commenters who suggest
that the BAAQMD rule, as well as a
similar South Coast Air Quality
Management District (SCAQMD) rule
that address PRD releases (SCAQMD
Rule 1173), provide work practice
standards that reflect the level of control
that applies to the best performers.
Consequently, we developed a work
practice standard for PRD based on a
detailed MACT analysis considering the
requirements in these rules. Our
rationale for the selected MACT
requirements is provided in section
IV.C.4 of this preamble. The work
practice standards that we are finalizing
for PRDs require refiners to establish
proactive measures for each affected
PRD to prevent direct release of HAP to
the atmosphere as a result of pressure
release events. In the event of an
atmospheric release, we are requiring
refinery owners or operators to conduct
root cause analysis to determine the
cause of a PRD release event. If the root
cause was due to operator error or
negligence, then the release would be a
deviation of the standard. For any other
release (not including those caused by
force majeure events), the owner or
operator would have to implement
corrective action. A second release due
to the same root cause for the same
equipment in a 3-year period would be
a deviation of the work practice
standard. Finally, a third release in a 3year period would be a deviation of the
work practice standard, regardless of the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
root cause. Force majeure events would
not count in determining whether there
has been a second or third event.
With respect to defining ‘‘atmospheric
pressure relief safety valve’’ as
suggested by the commenter, we note
that the June 30, 2014, proposed
amendments in 40 CFR 63.648(j) used
the term ‘‘relief valve’’ because this was
a defined term in Refinery MACT 1.
However, the proposed amendments
included clauses such as ‘‘if the relief
valve does not consist of or include a
rupture disk.’’ Thus, we specifically
intended to apply the pressure relief
management requirements broadly to
‘‘pressure relief devices’’ and not just
‘‘valves.’’ To clarify this, we have
revised the regulatory language to use
the term ‘‘pressure relief device’’ rather
than ‘‘relief valve’’ to clearly include
rupture disks or similar types of
equipment that may be used for
pressure relief.
4. What is the rationale for our final
approach and final decisions for the
revisions pursuant to CAA section
112(d)(2) and (3)?
We revised the MACT floor
determination for DCU sources. CAA
section 112(d)(3)(A) requires the MACT
floor for existing sources to exclude
‘‘. . . those sources that have, within 18
months before the emission standard is
proposed or within 30 months before
such standard is promulgated,
whichever is later, first achieved a level
of emission rate or emission reduction
which complies, or would comply if the
source is not subject to such standard,
with the lowest achievable emission rate
(as defined by section 171) applicable to
the source category and prevailing at the
time, in the category or subcategory for
categories and subcategories with 30 or
more sources.’’ Because we have
determined that a 2 psig emissions
limitation is equivalent with a LAER
emission limit for DCU, we revised the
MACT floor analysis in order to exclude
sources that first met the 2 psig limit on
or after December 30, 2012. For existing
sources, based on the revised MACT
analysis, we concluded that the MACT
floor is still 2 psig. However, because
the information on which we relied was
submitted in response to the 2011
Petroleum Refinery ICR which
requested ‘‘typical’’ venting pressures
and because providing an allowance to
average across venting periods does not
reduce the emissions reductions
achieved, we are providing a 60-event
averaging period for existing sources in
response to public comments received.
For new DCU sources, our revised
analysis identified one DCU subject to
permit emission limitations of 2.0 psig
PO 00000
Frm 00038
Fmt 4701
Sfmt 4700
pressure limit prior to venting on a per
event basis. Under CAA section
112(d)(3), the MACT standard for new
sources cannot be less stringent than the
emission control achieved in practice by
the best-controlled similar source. Thus,
we are finalizing a limit of 2.0 for new
DCU sources. We note that as 2.0 psig
limit is more stringent than a 2 psig
limit because of the rounding
convention of rounding to the number
of significant digits for which the
standard is expressed. For example, a
2.4 psig venting pressure is compliant
with a 2 psig limit, while it is not
compliant with a 2.0 psig limit.
We evaluated the costs of requiring
existing sources to meet a 2.0 psig limit
as a beyond-the-MACT-floor option. We
determined the incremental cost of
going from a 2 psig limit with an
allowance to average over 60 events to
a 2.0 psig limit on a per event basis was
approximately $70,000 per ton of HAP
reduced considering VOC credits. Based
on this high incremental costeffectiveness, we concluded that the
MACT floor requirement for existing
DCU sources was MACT. As discussed
in detail in the proposal, we do not
consider it technically feasible to meet
a 1 psig pressure limit (effectively a 1.4
psig limit) on a not-to-be-exceeded
basis. Thus, we rejected this beyond the
floor control option for both existing
and new DCU sources. See the
memorandum titled ‘‘Reanalysis of
MACT for Delayed Coking Unit
Decoking Operations’’ in Docket ID No.
EPA–HQ–OAR–2010–0682 for
additional details regarding our reanalysis of MACT for DCU decoking
operations.
In response to comments received on
the prohibition of draining prior to
achieving the proposed pressure limit
(see Section 7.2.1 in the ‘‘National
Emission Standards for Hazardous Air
Pollutants from Petroleum Refineries—
Background Information for Final
Amendments: Summary of Public
Comments and Responses’’ in Docket ID
No. EPA–HQ–OAR–2010–0682), we are
providing specific provisions to allow
for draining under special conditions.
The specific provision and our rationale
for providing them are provided below.
First, we learned that certain DCU are
designed to completely fill the drum
with water and allow the water to
overflow in the overhead line and drain
to a receiving tank in order to more
effectively cool the coke bed. Owners or
operators of this DCU design were
concerned that the water overflow may
be considered a drain and also stated
that overhead temperature rather than
pressure would be a better indicator of
effective bed cooling. In reviewing this
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
type of DCU design, we find that this
design has some unique advantages to
traditional DCU to effect better cooling
of the coke drum, and therefore we do
not want to preclude its use. Based on
saturated steam properties, we
determined that an overhead
temperature of 220 °F would achieve
equivalent or greater emissions
reductions than a 2 psig pressure
limitation and an overhead temperature
of 218 °F would achieve equivalent or
greater emissions reductions than a 2.0
psig pressure limitation. Therefore, we
are including these temperature limits
as alternatives to the 2 or 2.0 psig
pressure limitations for existing and
new DCU affected sources, respectively.
With respect to the overflow ‘‘drain,’’
we remain concerned with emissions
from draining superheated water.
However, if submerged fill is used in the
atmospheric tank receiving the overflow
water, the superheated water will be
cooled by the water within the tank and
emissions that occur during the
conventional draining of water (from the
flashing of superheated water into
steam) can be prevented. Therefore, we
are allowing the use of water overflow
provided the overflow ‘‘drain’’ water is
hard-piped to the receiving tank via a
submerged fill pipe (pipe below the
existing liquid level) whenever the
overflow water exceeds 220 °F.
Second, we received comments that,
for conventional DCU (those not
designed to allow water overflow), there
is a limit to the maximum water level
in the drum, which limits to some
extent how much cooling water can be
added to the coke drum. In rare cases,
the coke drum does not cool sufficiently
using the typical cooling steps. In this
case, the common industry practice is to
partially drain the coke drum and refill
it with additional cooling water. This
‘‘double-quench’’ process is needed for
safety reasons to sufficiently cool the
coke drum contents prior to the
decoking operations. Therefore,
commenters requested provisions to
allow double-quenching of the coke
drum. We recognize the safety issues
associated with coke blow-out during
coke cutting if there is a portion of the
coke bed that is not sufficiently cooled
and we agree that double-quenching is
an effective means to cool the coke
drum in those rare instances that the
typical cooling cycle does not
sufficiently cool the coke drum
contents, so we considered granting the
commenters’ request. As noted
previously, the primary concern with
early draining of the coke drum is the
emissions that are expected to occur as
a result of draining superheated water.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
We recognize, however, that the water
temperature near the bottom of the coke
drum is typically much lower than at
the top of the coke drum. If the
temperature of the water drained from
the bottom of the coke drum remains
below 210 °F, this would minimize
steam flashing and associated HAP
emissions since the water drained
would not be superheated. We conclude
that the use of double quenching is
appropriate for cases when the coke
drum is not sufficiently cooled using the
normal cooling procedures provided the
temperature of the water drained
remains below 210 °F, and it is
consistent with the practices of the best
performing sources. Consequently, we
are finalizing provisions to allow the
use of double-quenching for DCU
provided the temperature of the water
drained remains below 210 °F.
For the CRU, we are finalizing the
proposed revisions to require CRU that
employ active purging to meet the
MACT emissions limitations in Tables
15 and 16 in subpart UUU at all times
regardless of vessel pressure. We
received limited comments regarding
our proposal; these comments generally
concerned the costs associated with the
proposed emissions limitations. As
discussed in our proposal, and based on
data submitted in response to the ICR,
emissions using active purging are
much higher than those not using active
purging. In the original rule, we based
the MACT floor on the best performing
facilities that used sequential
pressurizations and depressurizations
rather than active purging. Thus, in the
proposal, we concluded that allowing
owners or operators to actively purge
while at low pressures was inconsistent
with the MACT floor emissions
limitations achieved by the best
performing 12-percent of sources when
the MACT floor was originally
established. As we are simply requiring
these facilities to meet the same
emission levels determined to be
MACT, we do not consider costs of
potential additional controls to be a
viable rationale to allow these units to
emit several times more HAP than the
units upon which the MACT
requirements were based and the
emissions levels achieved in practice by
the vast majority of other CRU sources.
For flares, we are finalizing proposed
revisions to include detailed flare
monitoring and operating requirements.
We are including the flaring provisions
for refineries in the Refinery MACT
rules and removing the cross-references
to the flaring requirements in the
General Provisions. The final regulatory
requirements differ from the proposed
requirements in several respects. First,
PO 00000
Frm 00039
Fmt 4701
Sfmt 4700
75215
we are not finalizing the ban on
halogenated vent streams because we
did not include sufficient justification
or include cost estimates for this
proposed provision and we did not
include any monitoring requirements to
ensure compliance with this ban on
halogenated vent streams.
We are finalizing the proposed no
visible emissions limit and the flare tip
velocity limit but they will apply only
when the flare vent gas flow rate is
below the smokeless capacity of the
flare. We received a number of
comments stating that the no visible
emissions limit and the flare tip velocity
limit cannot be met during large
malfunctions and emergency shutdown
events. In response to comments, we are
finalizing work practice standards for
emergency flaring events using the
proposed no visible emission limit and
flare tip velocity limit as thresholds in
the final rule to trigger root cause
analysis when the flare vent gas flow
rate is above the smokeless capacity of
the flare. The final work practice
standard includes requirements to
develop a flare management plan, to
implement prevention measures, and to
perform root cause analysis and
implement corrective action following
each flaring event that exceeds the
smokeless capacity of the flare. There is
also a limit on the number of these
flaring events that a given flare may
have in the 3-year period. We are
establishing these provisions because
we now recognize that flares have two
different design capacities: A smokeless
design capacity and a hydraulic load
capacity. We determined that the
proposed visible emissions limit and the
flare tip velocity limit for very large
flow events are not the MACT floor for
such events. The final work practice
standards for flaring events are based on
the best performing facilities and will
result in emission reductions in a
technically feasible manner without any
negative secondary impacts.
We consider it appropriate to
establish a work practice standard for
flares as provided in CAA section
112(h). While it is possible to monitor
gaseous streams going into the flare (as
we have required for the flare operating
requirements) it is not possible to design
and construct a conveyance to capture
the emissions from a flare. While
knowledge of the composition and flow
of gases entering the flare provides a
reasonable basis for establishing
operating requirements for normal
operations, we have no data on flare
performance under conditions in the
hydraulic load range. While smoke in
the flare exhaust is an indication of
incomplete combustion, it is uncertain
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75216
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
how much deterioration of HAP
destruction efficiency occurs during a
smoking event. We also consider that
the application of a measurement
methodology for flare exhaust is not
practicable due to technological and
economic limitations. Passive FTIR has
been used to determine combustion
efficiency in flare exhaust, but these are
essentially manual tests, and the
measurement accuracy is dependent on
how well the monitor is aligned with
the flare exhaust plume. Changes in
wind direction require manual
movement of the monitoring system. It
is also unclear if these systems can
accurately measure combustion
efficiency during high smoking events.
These systems also require very
specialized expertise, and we consider
that it is both technologically and
economically infeasible to measure flare
exhaust emissions, particularly during
high load events. Consequently, for
emergency flare releases, we conclude
that it is appropriate to establish a work
practice standard as provided in CAA
section 112(h).
We also received comments that the
daily visible emissions observations
were burdensome and unnecessary and
some commenters suggested that
facilities be allowed to use video
surveillance cameras. We concluded
that video surveillance cameras would
be at least as effective as the proposed
daily 5-minute visible emissions
observations using Method 22. We are
finalizing the proposed visible
emissions monitoring requirements
Method 22 and the alternative of using
video surveillance cameras.
We are simplifying the combustion
zone gas property operating limits in
response to public comments received.
Specifically, we are finalizing
requirements that all flares meet a
minimum operating limit of 270 BTU/
scf NHVcz on a 15-minute average, and
we are providing that refiners use a
corrected heat content of 1,212 BTU/scf
for hydrogen to demonstrate compliance
with this operating limit. We
determined that a corrected heat content
of 1212 BTU/scf for hydrogen provided
a better indication of flare performance
than without the correction. We also
determined that the other combustion
zone parameters, which were primarily
proposed to provide suitable methods
for flares that had high hydrogen
concentrations, were no longer
necessary when a 1,212 Btu/scf net
heating value is used for hydrogen.
Therefore, we are not finalizing the
alternative combustion zone operating
limits based on lower flammability limit
or combustibles concentration. We are
also not finalizing separate combustion
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
zone operating limits for gases meeting
the proposed hydrogen-olefin
interaction criteria. In our revised
analysis of the data, we analyzed all of
the data together and determined the
270 Btu/scf NHVcz operating limit
provided in the final rule would
adequately ensure that flares achieve the
desired 98-percent control efficiency
regardless of the composition of gas sent
to the flare.
For air-assisted flares, we are
finalizing the additional ‘‘dilution
parameter’’ operating limit only for the
net heating value dilution parameter,
NHVdil. Similar to the requirements we
are finalizing for the combustion zone
parameters, we are finalizing
requirements that flares meet a
minimum operating limit of 22 BTU/ft2
NHVdil on a 15-minute average, and we
are providing that refiners use a
corrected heat content of 1,212 BTU/scf
for hydrogen to demonstrate compliance
with this operating limit. For the
reasons explained above, we are not
finalizing the proposed alternative
dilution parameter operating limits
based on lower flammability limit or
combustibles concentration, and we are
not finalizing separate dilution
parameter operating limits for gases
meeting the proposed hydrogen-olefin
interaction criteria.
For flares in dedicated service, we are
establishing an alternative to continuous
or on-going grab sample requirements
for determining waste gas net heating
content to reduce the burden of
sampling for flare waste gases that have
consistent compositions. Flares in
dedicated service can use initial
sampling period and process knowledge
to determine a fixed net heating value
of the flare vent gas to be used in the
calculations of NHVcz and, if applicable,
NHVdil.
We are revising the definition of MPV
to remove the exemption for in situ
sampling systems for the reasons
provided in the proposed rule.
We received comments
recommending that a work practice
standard be adopted for PRD rather than
the proposed prohibition of atmospheric
PRD releases. Commenters stated that
the prohibition was infeasible due to the
proposed immediate timing of the
requirement and impractical due to cost
considerations. After reviewing these
comments as well as the BAAQMD rule
(Regulation 8, Rule 8–28–304) and the
SCAQMD rule (Rule 1173), we have
determined that the work practice
standards in these rules reflect the level
of control that applies to the best
performers. Therefore, we proceeded to
evaluate appropriate MACT
PO 00000
Frm 00040
Fmt 4701
Sfmt 4700
requirements based on the provisions in
these rules.
The BAAQMD rule requires sources
to implement a minimum of three
prevention measures to limit the
possibility of a release. The BAAQMD
uses a ‘‘release event’’ threshold of 10
lbs/day of organic or inorganic
pollutants; the SCAQMD rule effectively
uses a release event threshold of 500 lbs
VOC/day. When a release event occurs,
both rules require that the refiner
perform a root cause analysis and take
corrective action (including additional
prevention measures). In addition, both
rules require piping the PRD to a flare
if there are more than two release events
(releases above a certain release size
threshold) in a 5-year period. Both rules
include a number of exemptions for
certain types of PRD that are not
expected to release significant amounts
of pollutants to the air or that are not
feasible to control because of pressure
considerations. These include PRD
associated with storage tanks, vacuum
systems and equipment in heavy liquid
service as well as liquid thermal relief
valves that are vented to process drains.
There are five refineries subject to the
BAAQMD rule and seven refineries
subject to the SCAQMD rule, accounting
for 8-percent of refineries nationwide
and representing the industry’s best
performers. We consider the BAAQMD
rule to be the more stringent of the two
because this rule requires sources to
implement a minimum of three
prevention measures to limit the
possibility of a release (the SCAQMD
rule has no similar requirement) and
uses a lower mass threshold for what is
considered a ‘‘release event’’ (10 lbs/day
of organic or inorganic pollutants versus
the 500 lbs VOC release threshold in the
SCAQMD rule). Therefore, the
BAAQMD rule is considered to be the
MACT floor requirement for PRDs
associated with new affected sources
and the SCAQMD rule is considered to
be the MACT floor for PRDs associated
with existing affected sources.
In general, an open PRD is essentially
the same as a miscellaneous process
vent that is vented directly to the
atmosphere. Consistent with our
treatment of miscellaneous process
vents and consistent with the two
California rules, we believe that it is
appropriate to exclude certain types of
PRD that have very low potential to emit
based on their type of service, size and/
or pressure. For example, PRD that have
a potential to emit less than 72 pounds
per day of VOC, considering the size of
the valve opening, design release
pressure, and equipment contents,
would be considered in a similar
manner as Group 2 miscellaneous
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
process vents and would not require
additional control. The two California
rule requirements do not apply to PRD
on storage tanks and vacuum systems.
Most of these PRD have a design release
pressure of 2.5 psig and thus have a very
limited potential to emit. It is
technically infeasible to pipe these
sources to a flare (or other similar
control system) because the back
pressure in the flare header system
generally exceeds 2.5 psig. We note that
some storage tanks can operate at
elevated pressure (i.e., pressure tanks).
Therefore, rather than follow exactly the
requirements in the California rules, we
determined it more practical to exclude
PRD with design release pressure of less
than 2.5 psig.
Any release from a PRD in heavy
liquid service would have a visual
indication of a leak and any repairs to
the valve would have to be further
inspected and, if necessary, repaired
under the existing equipment leak
provisions. Therefore, consistent with
the BAAQMD rule, we are exempting
PRD in heavy liquid service from the
work practice standards we are
establishing in this final rule.
Both the BAAQMD and SCAQMD
rules exempt thermal expansion valves
that are ‘‘vented to process drains or
back to the pipeline.’’ We are unclear
what is meant by ‘‘vented to process
drains’’; however, if a liquid is released
from a PRD via hard-piping to a drain
system that meets the control
requirements specified in Refinery
MACT 1, we consider that these PRD are
controlled and they would not be
subject to the work practice standard
established in this final rule. Similarly,
all PRD in light liquid service that are
hard-piped to a controlled drain system
(or back to the process or pipeline) are
otherwise subject to a MACT
requirement and would not be subject to
the work practice standard.
In considering thermal relief valves
not vented to process drains or back to
the pipeline, we expect that releases
from these thermal relief valves will be
small and generally under the release
event thresholds specified in the
California rules. Therefore, the work
practice standards do not apply to PRD
that are designed solely to release due
to liquid thermal expansion.
The primary goal of the PRD work
practice standard is to reduce the size
and frequency of releases. The
SCAQMD rule is targeted towards fairly
large releases (compared to the direct
PRD releases reported in response to the
Refinery ICR), so it will reduce the
frequency of large releases, but it does
little to reduce the frequency of smaller
releases. To more effectively reduce the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
size and frequency of all releases, we
consider it important to require the
implementation of prevention measures
(as required in the BAAQMD rule) and
require root cause analysis and
corrective action for PRD releases from
all PRD subject to the work practice
standard. While we recognize that if a
PRD opens for a short period of time,
the release might be below the release
thresholds in the SCAQMD rules, we
believe the release may be indicative of
an important issue or design flaw.
Because the potential for large
emissions exist from the PRD subject to
the work practice standard, we think it
is reasonable to require a root cause
analysis be conducted and appropriate
corrective action implemented to
potentially identify this issue and
prevent a second release which, if the
issue remains uncorrected, could be
significant.
Requiring that prevention measures
be implemented on all PRD subject to
the work practice standard and not
establishing a release threshold for
release events is a variation from the
SCAQMD rule. However, we also
considered the allowable release
frequency. We believe that our adoption
of this approach is balanced by our not
adopting the SCAQMD provisions
requiring that PRD be vented to a flare
or other control system or that refiners
pay a fee if there are multiple releases
of a certain size within a specified
timeframe.12 In place of this system, we
are limiting the number of events from
each PRD that can occur in a 3 year time
period (2, if root causes are different),
and in place of a fine, or routing to
control, stating that the 3rd release in 3
years for any root cause is a deviation
of the standard.
Because we are not including a size
threshold for release events as in the
SCAQMD rule, it is natural to assume
release events would occur more
frequently than release events subject to
the SCAQMD rules. Also, based on our
Monte Carlo analysis of random rare
events, we note that it is quite likely to
have two or three events in a 5-year
period when a long time horizon (e.g.,
20 years) is considered. Therefore,
considering our analysis of emergency
12 The SCAQMD rule requires PRD to be vented
to a flare or other control device if there is a single
release in excess of 2,000 pounds of VOC in a 24hour period or three releases in excess of 500
pounds of VOC in a 5-year period or, alternatively,
pay a $350,000 fee. Thus, the SCAQMD rule would
allow, for example, two releases of over 500 pounds
of VOC each within a 5-year period without any
penalty provided a third event did not occur. If a
third event did occur, the refinery owner or
operator would then have to vent the PRD to a flare
or other control system or pay a fee ($350,000) for
the third release over 500 pounds of VOC.
PO 00000
Frm 00041
Fmt 4701
Sfmt 4700
75217
flaring events and the lack of a 500 lb/
day release threshold, we considered it
reasonable to use a 3-year period rather
than a 5-year period as the basis of a
deviation of the work practice standard.
The SCAQMD work practice
standards do not apply to releases that
are demonstrated to ‘‘result from natural
disasters, acts of war or terrorism, or
external power curtailment beyond the
refinery’s control, excluding power
curtailment due to an interruptible
service agreement.’’ These types of
events, which we are referring to as
‘‘force majeure’’ events, are beyond the
control of the refinery owner or
operator. We are providing that these
events should not be included in the
event count, but that they would be
subject to the root cause analysis in
order to confirm whether the release
was caused by a force majeure event.
Consistent with the requirements in
the SCAQMD rule, we are requiring
refinery owners or operators to conduct
a root cause analysis for a PRD release
event. If the root cause was due to
operator error or negligence, then the
release would be a deviation of the
standard. For any other release (not
including those caused by force majeure
events), the owner or operator would
have to implement corrective action. We
consider that a second release due to the
same root cause for the same equipment
in a 3-year period would be a deviation
of the work practice standard. This
provision will help ensure that root
cause/corrective action are conducted
effectively. Finally, a third release in a
3-year period (not including those
caused by force majeure events) would
be a deviation of the work practice
standard, regardless of the root cause.
While we are using a 3-year interval
rather than the 5-year interval provided
in the SCAQMD, we consider that the
requirements as included in this final
rule (i.e., the inclusion of prevention
measure requirements and no
thresholds for release events) will
achieve equivalent if not greater
emissions reductions than the SCAQMD
rule. We also consider that, given the
prevention measure requirements and a
3-year period, there is less likelihood of
unusual random events that happen
over a short period of time that may
cause refinery owners or operators to
feel compelled to vent the PRD to a flare
to eliminate concerns regarding
potential non-compliance. Thus, we
project that the requirements that we
have included in the final rule will
achieve emissions reductions
commensurate to or exceeding the
requirements in the SCAQMD rule (that
serves as the MACT floor for existing
sources) but will achieve those
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75218
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
reductions in a more cost-effective
manner.
We also considered requiring all PRD
to be vented through a closed vent
system to a control device as an
alternative beyond-the-MACT floor
requirement. While this requirement
would provide additional emission
reductions beyond those we are
establishing as the MACT floor, these
reduction come at significant costs.
Capital costs for requiring control of all
atmospheric PRD is estimated to be
approximately $300 million compared
to $11 million for the requirements
described above. The total annualized
cost for requiring control of all
atmospheric PRD is estimated to be
approximately $41 million/year
compared to $3.3 million/year for the
requirements described above. We
estimate that the incremental costeffectiveness of requiring control of all
atmospheric PRD compared to the
requirements described above exceeds
$1 million per ton of HAP reduced.
Consequently, we conclude that this is
not a cost-effective option for existing
sources.
The final requirements that we have
developed for PRD achieve equal or
greater emission reductions than those
achieved by the SCAQMD rule (MACT
floor). To the extent those requirements
are more stringent that the SCAQMD,
they are cost-effective. We could not
identify an alternative requirement that
provided further emission reductions in
a cost-effective manner. Thus, we
conclude that the work practice
standards described above represent
MACT for existing sources.
The BAAQMD rule, which represents
the requirements applicable to the best
performing sources, is the basis for new
source MACT for PRD. Based on the
specific provisions for PRD in the
BAAQMD rule, we conclude that the
MACT floor requirement is to have all
PRD in HAP service associated with a
new affected source vented through a
closed vent system to a control device.
As with existing sources, the PRD WPS
would also contain the same exclusions
(e.g., heavy liquid service PRDs, thermal
expansion valves, liquid PRDs that are
hard-piped to controlled drains, PRD
with release pressures of less than 2.5
psig, PRD with emission potential of
less than 72 lbs/day, and PRD on mobile
equipment). These provisions are
similar to the applicability provisions of
the BAAQMD rule. Thus, we retain the
same applicability of the work practice
standard for PRDs on new or existing
equipment, but all affected PRD on a
new source would be required to be
controlled. This is essentially equivalent
to the proposed requirement of no
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
atmospheric releases. We could not
identify a control option more stringent
than the BAAQMD rule as applied to
new sources. Therefore, we conclude
that venting all PRD in HAP service
through a closed vent system to a flare
or similar control system is MACT for
PRD associated with new affected
sources.
We consider it appropriate to
establish a work practice standard for
PRD as provided in CAA section 112(h).
While it may be possible to design and
construct a conveyance for PRD
releases, we consider that the
application of a measurement
methodology for PRDs is not practicable
due to technological and economic
limitations. First, it is not practicable to
use a measurement methodology for
PRD releases. The venting time can be
very short and may vary widely in
composition and flow rate. The oftenshort duration of an event makes it
infeasible to collect a grab sample of the
gases when a release occurs, and a
single grab sample would not account
for potential variation in vent gas
composition. It would be economically
prohibitive to construct an appropriate
conveyance and install and operate
continuous monitoring systems for each
individual PRD in order to attempt to
quantitatively measure a release event
that may occur only a few times in a 3year period. Additionally, we have not
identified an available, technically
feasible continuous emission
monitoring systems that can determine
a mass VOC or HAP release quantity
accurately given the flow, composition
and composition variability of potential
PRD releases from refineries.
Consequently, we conclude that it is
appropriate to establish a work practice
standard for PRD releases as provided in
CAA section 112(h).
D. NESHAP Amendments Addressing
Emissions During Periods of SSM
1. What amendments did we propose to
address emissions during periods of
SSM?
We proposed to eliminate the SSM
exemption in 40 CFR part 63, subparts
CC and UUU. Consistent with Sierra
Club v. EPA, we proposed standards in
these rules that apply at all times. We
also proposed several revisions to Table
6 of subpart CC of 40 CFR part 63 and
to Table 44 to subpart UUU of 40 CFR
part 63 (the General Provisions
Applicability tables for each subpart),
including eliminating the incorporation
of the General Provisions’ requirement
that the source develop an SSM plan,
and eliminating and revising certain
recordkeeping and reporting
PO 00000
Frm 00042
Fmt 4701
Sfmt 4700
requirements related to the SSM
exemption.
For Refinery MACT 1, we proposed
that the use of a bypass at any time to
divert a Group 1 miscellaneous process
vent to the atmosphere is a deviation of
the emission standard, and specified
that refiners install, maintain and
operate a continuous parameter
monitoring system (CPMS) for flow that
is capable of recording the volume of
gas that bypasses the APCD.
We also proposed to revise the
definition of MPV to remove the
exclusion for ‘‘Episodic or non-routine
releases such as those associated with
startup, shutdown, malfunction,
maintenance, depressuring and catalyst
transfer operations.’’ We also proposed
that the control requirements for Group
1 MPV apply at all times, including
startup and shutdowns.
For Refinery MACT 2, we proposed
alternate standards for three emission
sources for periods of startup or
shutdown. We proposed PM standards
for startup of FCCU controlled with an
ESP under Refinery MACT 2 because of
safety concerns associated with
operating an ESP during an FCCU
startup. For FCCU controlled by an ESP,
we proposed a 30-percent opacity limit
(on a 6-minute rolling average basis)
during the period that torch oil is used
during FCCU startup. For startup of
FCCU without a post-combustion device
under Refinery MACT 2, we proposed a
CO standard based on an excess oxygen
concentration of 1 volume percent (dry
basis) based on a 1-hour average. For
periods of SRU shutdown, we proposed
to allow diverting the SRU purge gases
to a flare meeting the design and
operating requirements in 40 CFR
63.670 (or, for a limited transitional
time period, 40 CFR 63.11) or to a
thermal oxidizer operated at a minimum
temperature of 1,200 °F and a minimum
outlet oxygen concentration of 2 volume
percent (dry basis). For other emission
sources in Refinery MACT 2, we
proposed that the requirements that
apply during normal operations should
apply during startup and shutdown.
2. How did the SSM provisions change
since proposal?
a. Refinery MACT 1
We proposed that when process
equipment is opened to the atmosphere
(e.g., for maintenance), the existing MPV
emissions limits apply. In this final rule,
we are instead finalizing startup and
shutdown provisions that apply to these
venting events. These startup and
shutdown provisions are work practice
standards that allow refinery owners or
operators to open process equipment
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
during startup and shutdown provided
that the equipment is drained and
purged to a closed system until the
hydrocarbon content is less than or
equal to 10-percent of the LEL. For those
situations where 10-percent LEL cannot
be demonstrated (no direct
measurement location), the equipment
may be opened and vented to the
atmosphere if the pressure is less than
or equal to 5 psig. Active purging of the
equipment is only allowed after the 10percent LEL level is achieved, regardless
of the pressure of the equipment/vessel.
We are establishing a separate
requirement for very small process
equipment, defined as equipment where
it is physically impossible to release
more than 72 lbs VOC per equipment
opening based on the size and contents
of the equipment. This definition is
consistent with the Group 1
applicability cutoff for control of
miscellaneous process vents. We also
developed requirements specific to
catalyst changeout activities where
pyrophoric catalyst (e.g., hydrotreater or
hydrocracker catalysts) must be purged
using recovered hydrogen. These
provisions include: Documenting the
procedures for equipment openings and
procedures for verifying that events
meet the specific conditions above using
site procedures used to de-inventory
equipment for safety purposes (i.e., hot
work or vessel entry procedures) and
documenting any deviations from the
work practice standard requirements.
b. Refinery MACT 2
tkelley on DSK3SPTVN1PROD with RULES2
We are expanding the proposed 1percent minimum oxygen operating
limit alternative for organic HAP to
apply for all FCCU startup and
shutdown events (rather than only
partial burn FCCU with CO boilers
during startup). We are replacing the
proposed opacity limit alternative to the
metal HAP standard with a minimum
cyclone face velocity limit and we are
extending that alternative limit to all
FCCU (regardless of control device) for
both startup and shutdown in this final
rule.
We are extending the proposed
alternative for SRU to monitor
incinerator temperature and excess
oxygen limits during SRU shutdowns to
also apply during periods of startup.
3. What key comments did we receive
on the SSM revisions and what are our
responses?
a. Refinery MACT 1
Comment: Many commenters stated
that the proposed extension of the MPV
definition to episodic maintenance
startup and shutdown vents and
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
elimination of the SSM exception for
storage tanks would create hundreds or
thousands of new vents per refinery per
year and generate massive on-going
burdens. The commenters argued that
the EPA has not included in the record
any analysis of the potential
environmental benefits, costs or
operational and compliance feasibility
and impacts associated with this
requirement and that many of these
requirements will result in delayed and
extended equipment and process
outages. One commenter asserted that
the EPA has articulated no justification
for applying emission standards to these
events, nor any analysis consistent with
CAA section 112 for a determination
that MACT standards are appropriately
applied to these emission events under
the criteria in CAA section 112(d).
Many commenters stated that every
time a vessel is opened for inspection or
maintenance each vent point will have
to be evaluated as a potential MPV or
storage tank vent. If a particular vent
point (e.g., bleeder) used for
maintenance, startup or shutdown
handles material that is initially greater
than 20 ppm HAP, then it is a MPV. If
there is a potential to emit greater than
or equal 72 lbs/day of VOC, then it is
a Group 1 MPV and must be controlled.
If there is a potential of less than 72 lb/
day VOC release, then it is a Group 2
MPV and subject to recordkeeping
requirements. Commenters stated that in
a refinery there would be tens or more
such activities per day associated with
normal maintenance and inspection;
during turnarounds, there could be
hundreds of such MPVs. Commenters
added that these MPVs may then need
to be individually accounted for and
permitted creating an unnecessary
permitting and recordkeeping burden
for these periodic emissions.
Commenters recommended a general
set of work practice requirements for
maintenance, startup and shutdown of
vents, based on state requirements, that
do not impose the permitting, notice
and evaluation requirements associated
with identifying these vents
individually. Commenters explained
that states have dealt with these
episodic vents by establishing them as
a special class of process vent with
limited recordkeeping requirements and
subject to a work practice standard,
rather than the normal MPV
requirements. A key element of these
work practices is clear identification of
the criteria for releasing these vents to
the atmosphere and for routing these
vents to control after hydrocarbon is
reintroduced, which the commenters
asserted the current rule does not
provide. Commenters proposed that a
PO 00000
Frm 00043
Fmt 4701
Sfmt 4700
75219
work practice standard could include
removing process liquids to the extent
practical and depressuring smaller
volume equipment until a pressure of
<5 psig is achieved and/or purging and
depressuring to a control device until
the vent has a hydrocarbon
concentration of less than 10-percent of
the LEL. The commenters suggested that
these standards should provide clear
easily monitored criteria for when this
equipment can be vented to the
atmosphere, and should not impose the
permitting, notice and evaluation
requirements associated with
identifying these vents as individual
MPVs. One commenter provided draft
regulatory language for a work practice
requirement.
Response: We proposed to eliminate
the episodic and non-routine emission
exclusion in order to ensure that the
MACT includes emission limits that
apply at all times consistent with the
holding in Sierra Club. At the time of
the proposal, we expected that
essentially all SSM event emissions
would be routed to flares that are
subject to the MACT standards and,
thus, would serve to control these
emissions. However, we recognize that
maintenance activities that require
equipment openings are a separate class
of startup/shutdown emissions because
there must be a point in time when the
vessel can be opened and any emissions
vented to the atmosphere. We
acknowledge that it would require a
significant effort to identify and
characterize each of these potential
release points for permitting purposes.
In considering these comments and
whether we should establish a separate
limit that would apply to these
equipment openings, we reviewed state
permit requirements and the practices
employed by the best performing
sources. We found that some state or
local agencies required depressuring to
5 psig prior to atmospheric releases
while others required the gases to have
organic concentrations at or below 10percent of LEL prior to atmospheric
venting. In the final rule, we are
establishing a requirement that prior to
opening process equipment to the
atmosphere, the equipment must first be
drained and purged to a closed system
so that the hydrocarbon content is less
than or equal to 10-percent of the LEL.
For those situations where 10-percent
LEL cannot be demonstrated, the
equipment may be opened and vented
to the atmosphere if the pressure is less
than or equal to 5 psig, provided there
is no active purging of the equipment to
the atmosphere until the LEL criterion
is met. For equipment where it is not
technically possible to depressurize to a
E:\FR\FM\01DER2.SGM
01DER2
75220
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
control system, we allow venting to the
atmosphere where there is no more than
72 lbs VOC per day potential, consistent
with our Group 1 applicability cutoff for
control of process vents. For catalyst
changeout activities where hydrotreater
pyrophoric catalyst must be purged we
have provided limited allowances for
direct venting. Provisions to
demonstrate compliance with this work
practice include documenting the
procedures for equipment openings and
procedures for verifying that events
meet the specific conditions above using
site procedures used to de-inventory
equipment for safety purposes (i.e., hot
work or vessel entry procedures).
b. Refinery MACT 2
Comment: Several commenters noted
that there was a proposed specific
alternative metal HAP/PM standard for
startup of an FCCU controlled with an
ESP, but took issue with the fact that no
alternative PM limits were proposed for
startup of FCCU equipped with other
types of PM controls, or for any FCCU
during periods of shutdown or hot
standby. Regarding the proposed
alternative for startup, which would
provide an alternative in the form of an
opacity limit when torch oil is in use,
commenters stated that there are serious
process safety concerns which prevent
most FCCU ESPs from being operated
when torch oil is in the regenerator, that
is, during periods of startup, shutdown
and hot standby. To avoid the
possibility of a fire and explosion, the
commenters claimed ESPs are usually
de-energized and bypassed during these
periods and, consequently, these FCCUs
are generally unable to meet the
proposed 30-percent opacity limit.
Several commenters stated that the
EPA’s limits on FCCU opacity during
SSM are unreasonable and ignore the
technical requirements for transitional
operations of those units. The
commenters indicated that they have
ESPs located downstream of the CO
boiler and claimed that for safety
reasons the CO boiler cannot operate
during startup, shutdown or hot
standby. Further, a commenter
indicated that the ESP cannot operate if
the CO boiler is not operating and thus
both the CO boiler and the ESP must be
bypassed during startup, shutdown, and
hot standby operations.
Another commenter stated that the
EPA offers no data to support the
achievability of this requirement in
practice and discusses information for
26 startup/shutdown events that found
that none complied with a 30-percent
opacity requirement. Several
commenters also noted that experience
has shown that the 30-percent opacity
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
limit is unachievable during these
periods for FCCUs controlled with
tertiary cyclones, when regenerator gas
flow is below cyclone minimum design
flow.
Several commenters suggested that
the EPA establish a standard based on
the operation of FCCU catalyst
regenerators’ internal cyclones that
function to retain the catalyst in the
regenerators and thereby minimize
catalyst and metal HAP emissions from
the regenerators. Additional control to
meet the Refinery MACT 2 emission
limit of not more than 1.0 lb PM/1,000
lbs coke burn-off is provided by a bag
house, wet gas scrubber (WGS), ESP or
tertiary (external) cyclone. The
efficiency of a cyclone is a function of
the inlet gas velocity. Assuring adequate
velocity to the internal cyclones ensures
that the catalyst sent to these additional
controls is minimized and ensures that
they are operating as effectively as
possible. Similarly, even if the FCCU
cannot meet the normal opacity limits
during startup, shutdown or hot standby
(e.g. due to the ESP being off-line for
safety reasons or the tertiary cyclones or
WGS operating at non-routine
conditions), assuring adequate velocity
to the internal regenerator cyclones will
control and minimize particulate
emissions. Several commenters stated
support for another commenter’s
position that all FCCUs should be
allowed the option of complying with a
20 feet/second minimum inlet velocity
to the primary regenerator cyclones
during periods of startup and shutdown,
including hot standby, and these
commenters provided additional
technical explanations in their
comments.
On the other hand, some commenters
seemed to support the proposed opacity
limits, but suggested minor revisions.
One commenter noted that the
SCAQMD has granted Valero’s request
for variances from visible emission
standards during startup of the FCCU of
up to 65-percent opacity for up to five
minutes, in aggregate, during any 1-hour
period, and 30-percent as an hourly
average for the remaining period, during
startup events. The application of this
variance reflects the unavailability and/
or ineffectiveness of the ESP during the
startup condition. Another commenter
recommended that either the opacity
standard should be raised or the time
period for averaging should be extended
so FCCUs can be operated safely during
SSM events and still remain in
compliance.
Response: We have reviewed the data
submitted by the commenters to support
their assertion that the 30-percent
opacity limit (determined on a 6-minute
PO 00000
Frm 00044
Fmt 4701
Sfmt 4700
average basis) is not achievable during
startup and shutdown events. While the
data are limited, and it is unclear if the
data provided are indicative of the
performance achieved by the best
performing sources, we do not have
adequate data to refute the assertion that
the 30-percent opacity limit (determined
on a 6-minute average basis) is not
achievable during startup and shutdown
events. We considered the two options
suggested by the commenters, the
minimum velocity for the internal FCCU
regenerator cyclones and the 30-percent
hourly average opacity limit excluding 5
minutes not exceeding 65-percent
opacity. Again, due to the limited data
available during startup and shutdown
events, we are not able to determine
which requirement would provide
greater HAP emissions reduction.
However, we note that some facilities
may not be required to have an opacity
monitoring system in place and opacity
monitoring is not applicable for FCCU
controlled with wet scrubbers.
Therefore, we find that the minimum
internal cyclone inlet velocity
requirement is more broadly applicable
than the opacity limit. Also, based on
the data provided by the commenters,
the minimum internal cyclone inlet
velocity requirement will provide PM
(and therefore metal HAP) emissions
reductions during startup and shutdown
periods. Therefore, considering the
available data, we conclude that MACT
for FCCU startup and shutdown events
is maintaining the minimum internal
cyclone inlet velocity of 20 feet/second.
Comment: Several commenters stated
that the EPA should provide alternate
standards for startups of FCCU
equipped with CO boilers and for any
FCCU during periods of shutdown and
hot standby. The commenters stated that
the EPA incorrectly assumes that
refiners are able to safely and reliably
start up their FCCU with flue gas boilers
in service and meet the normal
operating limit of 500 ppm CO. They
claimed that most refiners are unable to
reliably start up their FCCU with flue
gas boilers in service due to the design
of the boiler and the fact that many
boilers are not able to safely and reliably
handle the transient FCCU operations
that can occur during startup,
shutdown, and hot standby. One
commenter stated that FCCU built with
CO boilers experience issues with flame
stability due to fluctuating flue gas
compositions and rates when starting up
and shutting down. Accordingly, the
commenter stated, startup and
shutdown activities at FCCU using a
boiler as an APCD are not currently
meeting the Refinery MACT 2 standard
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
of 500 ppm CO on a 1-hour basis, and
this level of control does not qualify as
the MACT floor. The commenter gave
examples of facilities where FCCU,
including those equipped with postcombustion control systems, do not
consistently demonstrate compliance
with a 500 ppm CO concentration
standard during all startup and
shutdown events.
Commenters stated that reliable boiler
operation is critical to the overall
refinery steam system and refineries
must avoid jeopardizing boiler
operation to prevent major upsets of
process operations. A major upset or
site-wide shutdown could result in
flaring and emissions of HAP far in
excess of that emitted while bypassing
the CO boiler.
Commenters stated that combustion of
torch oil in the FCCU regenerator during
startup is one of the primary reasons the
CO limit cannot be met during these
operations. Torch oil is also used during
shutdown to control the cooling rate
(and potential equipment damage) and
during hot standby and, thus, the
normal CO standard cannot be met at
these times either. Hot standby is used
to hold an FCCU regenerator at
operating temperature for outages where
a regenerator shutdown is not needed
and to avoid full FCCU shutdowns. Full
cold shutdown also increases personnel
exposures associated with removing
catalyst and securing equipment.
Additionally, this can produce
additional emissions over maintaining
the unit in hot standby. Commenters
claimed that because of the variability of
CO during torch oil operations, it is not
possible for the EPA to establish a CAA
section 112(d) standard for startup and
shutdown activities at FCCU because
refineries cannot measure a constant
level of emissions reductions.
The commenters recommended
expansion of the proposed standard of
greater than 1-percent hourly average
excess regenerator oxygen to all FCCU,
including units with fired boilers. These
commenters suggested that maintaining
an adequate level of excess oxygen for
the combustion of fuel in the
regenerator is the best way to minimize
CO and organic HAP emissions from
FCCU during these periods.
Response: After reviewing the
comments and discussing CO boiler
operations with facility operators, we
agree that the 1-percent minimum
oxygen limit should be more broadly
applicable to FCCU startup and
shutdown regardless of the control
device configuration and have revised
the final rule accordingly.
Comment: Several commenters stated
that the proposed alternative standards
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
for SRP shutdowns should be extended
to startups as well since the normal SRP
emission limitation cannot always be
achieved during SRP startups. Several
commenters gave examples of startup
activities where this relief is needed,
and noted there may be other startup
activities that also need this relief.
Response: For the control of sulfur
HAP, we determined that incineration
effectively controls these HAP. We were
not aware that there would be unusual
sulfur loads in the SRU tail gas during
startup. We agree that the alternative
standard we proposed for periods of
shutdown is also the MACT floor for
periods of startup because incineration
meeting the limits proposed will
achieve the MACT control requirements
for sulfur HAP during periods of either
startup or shutdown even though sulfur
loadings during these periods may be
elevated. For many SRU configurations,
compliance during normal operations is
demonstrated by monitoring SO2
emissions. However, during startup and
shutdown, high sulfur loadings in the
SRU tail gas entering the incinerator
will cause high SO2 emissions even
though sulfur HAP emissions are well
controlled. Consequently, the proposed
incinerator operating limits provide a
better indication of sulfur HAP control
during startup and shutdown than SO2
emissions. Owners or operators that use
incinerators or thermal oxidizers during
normal operations may meet the sitespecific temperature and excess oxygen
operating limits that were determined
based on their performance test during
periods of startup and shutdown.
4. What is the rationale for our final
approach and final decisions to address
emissions during periods of SSM?
a. Refinery MACT 1
We did not receive comments
regarding the proposed amendments to
Table 6 of subpart CC of 40 CFR part 63;
therefore, for the reasons provided in
the preamble to the proposed rule, we
finalizing these amendments as
proposed.
We determined that it was overly
burdensome and in most cases
technically infeasible to consider every
potential equipment or vessel opening
and classify these ‘‘openings’’ (newly
classified as MPV in the proposal) as
either Group 1 or Group 2 MPV. We also
determined that it is not always
technically feasible, depending on the
opening, to demonstrate compliance
with the MPV emissions limitations.
After considering the public comments,
we determined it was appropriate to
establish separate startup and shutdown
provisions for MPV associated with
PO 00000
Frm 00045
Fmt 4701
Sfmt 4700
75221
process equipment openings. We
reviewed state and local requirements
and based the final rule requirements on
the emissions limitations required to be
followed by the best performing sources.
Therefore, we are finalizing
requirements for refinery owners or
operators to open process equipment
during these startup and shutdown
events without directly permitting these
‘‘vents’’ as Group 1 or Group 2 MPV
provided that the equipment is drained
and purged to a closed system until the
hydrocarbon content is less than or
equal to 10-percent of the LEL. As
described in further detail previously in
this section, we have provided
provisions for special cases where the
10-percent LEL limit cannot be
demonstrated and provisions for less
significant equipment openings,
consistent with the practices used by
the best performing facilities.
b. Refinery MACT 2
We did not receive significant
comments regarding the proposed
amendments to Table 44 to subpart
UUU of 40 CFR part 63; therefore, we
finalizing these amendments as
proposed.
In response to comments, we
determined that the limited provisions
that were provided for startup only or
for shutdown only were too limited and
we have expanded the proposed
provisions to both startup and
shutdown regardless of control device
used. For the FCCU organic HAP
emissions limit, we are finalizing an
alternative limit for periods of startup of
no less than 1-percent oxygen in the
exhaust gas as proposed, but we are
extending that alternative limit to
shutdown and to all FCCU in this final
rule.
For the FCCU metal HAP emissions
limit, we proposed a specific startup
limit for FCCU controlled be an ESP of
30-percent opacity. We received
comments along with limited data
suggesting that this limit was not
achievable. Commenters suggested that
the best performing units maintain a
minimum face velocity of at least 20
feet/second to minimize catalyst PM
losses during startup and shutdowns.
Operators of wet scrubbers also noted
that they cannot maintain pressure
drops and that one cannot meet the PM
emissions limit normalized by coke
burn-off rate when the coke burn-off rate
approaches zero. Consequently,
commenters stated that the alternative
limits should be provided for startup
and shutdown regardless of control
device. Upon consideration of the
comments, we determined that it was
necessary to revise the proposed
E:\FR\FM\01DER2.SGM
01DER2
75222
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
alternative to be based on minimum
inlet face velocity to the FCCU
regenerator internal cyclones and
provide the alternative for both startup
and shutdown. We also expanded this
limit to all FCCU; however, we also
required FCCU with wet scrubbers to
meet only the liquid to gas ratio
operating limit during periods of startup
and shutdown to allow wet scrubbers to
use a consistent compliance method at
all times.
For SRU, we are finalizing an
alternative standard during periods of
startup and shutdown to use a flare that
meets the operating limits included in
the final rule or a thermal oxidizer or
incinerator operated at a minimum
hourly average temperature of 1,200 °F
and a minimum hourly average outlet
oxygen concentration of 2 volume
percent (dry basis). We proposed these
alternatives for periods of shutdown
only, but based on comments received
regarding startup issues, we determined
that high sulfur loadings can occur
during periods of startup and that the
alternative limit proposed was
appropriate for both startup and
shutdown.
E. Technical Amendments to Refinery
MACT 1 and 2
tkelley on DSK3SPTVN1PROD with RULES2
1. What other amendments did we
propose for Refinery MACT 1 and 2?
We proposed a number of
amendments to Refinery MACT 1 and 2
to address technical issues such as rule
language clarifications and reference
corrections. First, we proposed to
amend Refinery MACT 1 to clarify what
is meant by ‘‘seal’’ for open-ended
valves and lines that are ‘‘sealed’’ by the
cap, blind flange, plug, or second valve
by stating that sealed means when there
are no detectable emissions from the
open-ended valve or line at or above an
instrument reading of 500 ppm. Second,
we also proposed electronic reporting
requirements where owners or operators
of petroleum refineries must submit
electronic copies of required
performance test and performance
evaluation reports for compliance with
Refinery MACT 1 and 2 by direct
computer-to-computer electronic
transfer using EPA-provided software.
Third, we proposed to update the
General Provisions Tables 6 (for
Refinery MACT 1) and 44 (for Refinery
MACT 2) to correct cross references and
to incorporate additional sections of the
General Provisions that are necessary to
implement these rules.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
2. How did the other amendments for
Refinery MACT 1 and 2 change since
proposal?
We are not finalizing the definition of
‘‘seal’’ for open-ended lines as
proposed. We are finalizing changes to
update the General Provisions crossreference tables as proposed, with one
minor change to provide an option for
the administrator to issue guidance on
performance test reporting timeframes
in order to address issues relating to
submittal of data to the ERT.
3. What key comments did we receive
on the other amendments for Refinery
MACT 1 and 2 and what are our
responses?
Comment: Numerous commenters
objected to the proposal to clarify the
meaning of ‘‘seal’’ as it relates to openended line (OEL) standards.
Commenters contend that there is no
basis for the EPA to assert that the
proposed definition merely ‘‘clarifies’’
an established interpretation of the term
‘‘seal’’ and stated that the proposed
revision constitutes an illegal change in
the requirements for OELs, and the
clarification should not be finalized.
One commenter stated that none of
the MACT standards in place before this
proposal have stated or suggested that a
‘‘sealed’’ OEL is one with detectable
emissions below 500 ppm. This
commenter added this unique
interpretation of the requirement to
‘‘seal’’ an OEL with a cap or plug is
incompatible with the historical
interpretation of this requirement by
affected facilities and by the EPA, and
the EPA has not issued any sort of
definitive guidance or interpretation
setting out this position. The commenter
detailed numerous references to
considerations the EPA has made
relative to OEL requirements in LDAR
programs. In addition to the examples
cited, the commenter noted that in 2006,
the EPA proposed to add a ‘‘no
detectible emissions’’ limit and
monitoring requirement for OELs to
NSPS VV (71 FR 65317, November 7,
2006). Two commenters noted that the
proposed monitoring was not finalized
in either NSPS VV or VVa (72 FR 64860,
November 16, 2007) because it was not
considered BDT due to the low emission
reductions and the cost effectiveness of
the requirement. Another commenter
agreed that there is no explanation
provided for why this information could
now support the need for a new OEL
seal standard that requires monitoring to
ensure compliance when it was deemed
to be unjustified previously.
In addition, the commenter collected
OEL monitoring data and submitted it to
PO 00000
Frm 00046
Fmt 4701
Sfmt 4700
the EPA (see Docket Item No. EPA–HQ–
OAR–2010–0869–0058). Based on these
data, the commenter asserted that the
existence of leaks from OELs that are
not properly sealed is extremely low.
The commenter noted that the EPA is
claiming this change is only a
clarification of current requirements,
allowing the EPA to bypass the need to
cite a CAA authorization for this change
to the existing CAA section 112(d)(2)
standard or meet the process
requirements associated with such a
change, including providing emission
reduction, cost and burden estimates in
the record and the associated PRA
Information Collection Request (ICR).
Several commenters claimed that this
clarification would result in retroactive
impact and also addressed the
implication of the proposed change on
other fugitive emissions standards. One
commenter stated that the EPA cannot
retroactively reinterpret the OEL
requirements or define the word ‘‘seal’’
and added that the EPA should account
for the thousands of additional
monitoring events per year per refinery
that this new requirement would add to
LDAR programs and provide proper cost
justification under CAA sections
112(d)(6) or 112(f)(2).
Several commenters also stated that
the proposed definition will effectively
change all equipment leak rules in parts
40 CFR parts 60, 61 and 63 and the
change should not be finalized. One
commenter added that by claiming this
change is only a clarification of current
requirements, the EPA would set a
precedent applicable to all OELs in all
industries subject to any similar OEL
equipment leak requirement.
Response: We have decided not to
finalize the proposed clarification of the
term ‘‘seal’’ for OELs at this time. The
fenceline monitoring requirements we
are finalizing will detect any significant
leaks from a cap, blind flange, plug or
second valve that does not properly seal
an OEL, as well as significant leaks from
numerous other types of fugitive
emission sources.
Comment: A few commenters stated
that the proposed use of the ERT is not
appropriate because the costs and
burdens imposed are additive to the
costs of producing and submitting the
written report, and there is no benefit
that justifies the additional cost. One
commenter also stated that the EPA has
not developed or articulated a
reasonable approach to using
information that would be uploaded to
the ERT. The commenters
recommended that the EPA remove this
portion of the proposal until the ERT is
demonstrated to handle all the
information from refinery performance
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tests (rather than only portions), thereby
eliminating the need for both written
and electronic reporting and until the
Agency demonstrates that it is using the
electronic data to develop improved air
quality emission factors.
Other commenters stated that the ERT
requirement does not supersede or
replace any state reporting requirements
and thus the regulated industry will be
subject to dual reporting requirements.
These commenters disagreed with the
preamble claim that eliminating the
recordkeeping requirements for
performance test reports is a burden
savings, and stated that it may duplicate
burdens already borne by the regulated
community.
The commenters expressed further
concern that duplicative reporting
requirements will strain the regulated
industry to comply with deadlines
established by rule for report submittals.
One commenter stated that there is no
mechanism for obtaining extensions for
special circumstances. Under proposed
40 CFR 63.655(h)(9)(i), all reports are
due in 60 days. The commenter claimed
that by not referencing reporting
requirements to the General Provisions
in 40 CFR 63.10(d)(2), there is no
allowance for obtaining additional time
due to unforeseen circumstances or due
to the difficulties involved with
completing particularly complex
reports.
One commenter stated that the
primary performance test method
(Method 18) required for determining
compliance is not currently included in
the list of methods supported by the
ERT. The commenter stated that the
regulated community’s experience with
Method 18 is that it is a very broad
methodology and can be exceptionally
complex to execute and to report. The
commenter stated that the EPA is aware
that Method 18 reporting is complex,
that it may be difficult to incorporate
into the ERT, and that no time schedule
has been defined for development or
implementation for this method.
The commenter also stated that
without formal notice of changes to the
ERT, the regulated community is at risk
of non-compliance. The only way for
the regulated community to know that
changes have occurred in the ERT is to
monitor the Web site directly because
the EPA does not formally announce
changes to the ERT in the Federal
Register. As such, it would be possible
for a regulated entity to be unaware of
changes made such as the incorporation
of Method 18. The commenter
expressed concern that the proposal
language is an open-ended commitment
subject to change without notice. The
commenter stated that the EPA should
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
clearly indicate when facilities would
be required to use the ERT when new
test methods are included in the ERT.
Response: We disagree that use of the
ERT for completing stack test reports is
an added cost and burden. While the
requirement to report the results of stack
tests with the ERT does not supersede
state reporting requirements, we are
aware of several states that already
require the use of the ERT, and we are
aware of more states that are
considering requiring its use. We note
that where states will not accept an
electronic ERT submittal, the ERT
provides an option to print the report,
and the printed report can be mailed to
the state agency. We have no reason to
believe that the time savings in the
ability to reuse data elements within
reports does not, at a minimum, offset
the cost incurred by printing out and
mailing a copy of the report and the
commenters have provided no support
for their cost claims.
Furthermore, based on the analysis
performed for the Electronic Reporting
and Recordkeeping Requirements for
the New Source Performance Standards
Rulemaking (ERRRNSPS) (80 FR 15100),
electronic reporting results in an overall
cost savings to industry when
annualized over a 20-year period. The
cost savings is achieved through means
such as standardization of data,
embedded quality assurance checks,
automatic calculation routines and
reduced data entry through the ability to
reuse data in files instead of starting
from scratch with each test. As outlined
in the ERRRNSPS, there are many
benefits to electronic reporting. These
benefits span all users of the data—the
EPA, state and local regulators, the
regulated entities and the public. We
note that in the preamble to this
proposed rule we provided a number of
reasons why the use of the ERT will
provide benefit going forward and that
most of the benefits we outlined were
longer-term benefits (e.g., reducing
burden of future information collection
requests). Additionally, we note that in
2011, in response to Executive Order
13563, the EPA developed a plan 13 to
periodically review its regulations to
determine if they should be modified,
streamlined, expanded or repealed in an
effort to make regulations more effective
and less burdensome. The plan includes
replacing outdated paper reporting with
electronic reporting. In keeping with
this plan and the White House’s Digital
13 EPA’s
‘‘Final Plan for Periodic Retrospective
Reviews,’’ August 2011. Available at: https://www.
epa.gov/regdarrt/retrospective/documents/
eparetroreviewplan-aug2011.pdf.
PO 00000
Frm 00047
Fmt 4701
Sfmt 4700
75223
Government Strategy, 14 in 2013 the
EPA issued an agency-wide policy
specifying that new regulations will
require reports to be electronic to the
maximum extent possible. By requiring
electronic submission of stack test
reports in this rule, we are taking steps
to implement this policy. We also
disagree that we have not developed or
articulated a reasonable approach to
using information that would be
uploaded to the ERT. To the contrary,
we have discussed at length our plans
for the use of stack test data collected
via the ERT. In 2009, we published an
advanced notice of proposed
rulemaking (74 FR 52723) for the
Emissions Factors Program
Improvements. In that notice, we first
outlined our intended approach for
revising our emissions factors
development procedures. This approach
included using stack test data collected
with the ERT. We reiterated this
position in our ‘‘Recommended
Procedures for the Development of
Emissions Factors and Use of the
WebFIRE Database’’ (https://www.epa.
gov/ttn/chief/efpac/procedures/
procedures81213.pdf), which was
subject to public notice and comment
before being finalized in 2013. Finally,
we discussed uses of these data in the
preamble to the proposed rule and at
length in the preamble to the
ERRRNSPS.
We think that it is a circular argument
to say that the agency should eliminate
the use of the ERT until it demonstrates
that it is using the electronic data. It
would be impossible for the agency to
use data that it does not have. We can
only use electronic data once we have
electronic data. We do note that we are
nearing completion of programming the
WebFIRE database with our new
emissions factor development
procedures and anticipate running the
routines on existing data sets in the near
future.
We continue to improve and upgrade
the ERT on an ongoing basis. The
current version of the ERT supports 41
methods, including EPA Methods 1–4,
5, 5B, 5F, 25A 26, and 26A. We note
that the ERT does not currently support
EPA Method 18, and for performance
tests using Method 18, the source will
still have to produce a paper report.
However, we are aware of the need to
add Method 18 to the ERT, and we are
currently looking at developing this
capability. As noted in the ERRRNSPS,
when new methods are added to the
14 Digital Government: Building a 21st Century
Platform to Better Serve the American People, May
2012. Available at: https://www.whitehouse.gov/
sites/default/files/omb/egov/digital-government/
digital-government-strategy.pdf.
E:\FR\FM\01DER2.SGM
01DER2
75224
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
ERT, we will not only post them to the
Web site; we will also send out a listserv
notice to the Clearinghouse for
Inventories and Emissions Factors
(CHIEF) listserv. Information on joining
the CHIEF listserv can be found at
https://www.epa.gov/ttn/chief/
listserv.html#chief. We are requiring the
use of the ERT if the method is
supported by the ERT, as listed on the
ERT Web site (https://www.epa.gov/ttn/
chief/ert/ert_info.html) at the time of the
test. We do not agree that it is overly
burdensome to check a Web site for
updates prior to conducting a
performance test.
We did revise the MACT 1 and 2
tables referencing reporting
requirements to the general provisions
(Table 6 for Refinery MACT 1 and Table
44 for Refinery MACT 2) to provide
flexibility in the 60-day reporting
timeline to accommodate unforeseen
circumstances or difficulties involved
with completing particularly complex
reports.
4. What is the rationale for our final
approach and final decisions for the
other amendments for Refinery MACT 1
and 2?
We are not finalizing the definition of
seal, as proposed. The fenceline
monitoring work practice standard will
detect any significant leaks from a cap,
blind flange, plug or second valve that
does not properly seal an OEL, as well
as significant leaks from numerous other
types of fugitive emission sources.
We are finalizing requirements for
electronic reporting, as proposed, with a
minor clarification. Specifically, we are
revising Tables 6 in subpart CC and 44
in subpart UUU, which cross-reference
the applicable provisions in the General
Provisions to provide flexibility in the
ERT 60-day reporting timeline. Refiners
can seek approval from the EPA or a
delegated state additional time for
submittal of data due to unforeseen
circumstances or due to the difficulties
involved with completing particularly
complex reports.
F. Technical Amendments to Refinery
NSPS Subparts J and Ja
tkelley on DSK3SPTVN1PROD with RULES2
1. What amendments did we propose for
Refinery NSPS Subparts J and Ja?
We proposed a number of
amendments to Refinery NSPS subparts
J and Ja to address reconsideration
issues and minor technical
clarifications. First, we proposed
revisions to 40 CFR 60.100a(b) to
include a provision that sources subject
to Refinery NSPS subpart J could elect
to comply instead with the provisions of
Refinery NSPS subpart Ja.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Second, we proposed a series of
amendments to the requirements for
SRP in 40 CFR 60.102a, to clarify the
applicable emission limits for different
types of SRP based on whether oxygen
enrichment is used. The amendments
proposed also clarified that emissions
averaging across a group of emission
points within a given SRP is allowed for
each of the different types of SRP, and
that emissions averaging is specific to
the SO2 or reduced sulfur standards
(and not to the 10 ppmv hydrogen
sulfide (H2S) limit). We also proposed a
series of corresponding amendments in
40 CFR 60.106a to clarify the monitoring
requirements, particularly when oxygen
enrichment or emissions averaging is
used. We also proposed clarifications in
40 CFR 60.106a to consistently use the
term ‘‘reduced sulfur compounds’’
when referring to the emission limits
and monitoring devices needed to
comply with the reduced sulfur
compound emission limits for sulfur
recovery plants with reduction control
systems not followed by incineration.
Third, we proposed amendments to
40 CFR 60.102a(g)(1) to clarify that CO
boilers, while part of the FCCU affected
facility, can also be FGCD.
Fourth, we proposed several revisions
to 40 CFR 60.104a to clarify the
performance testing requirements. We
proposed revision to 40 CFR 60.104a(a)
to clarify that an initial compliance
demonstration is needed for the H2S
concentration limit in 40 CFR
60.103a(h). We proposed revisions to
the annual PM testing requirement in 40
CFR 60.104a(b) to clarify that annually
means once per calendar year, with an
interval of at least 8 months but no more
than 16 months between annual tests.
We also proposed to amend 40 CFR
60.104a(f) to clarify that the provisions
of that paragraph are specific to owners
or operators of an FCCU or FCU that use
a cyclone to comply with the PM
emissions limit in 40 CFR 60.102a(b)(1)
and not to facilities electing to comply
with the PM emissions limit using a PM
CEMS. We also proposed to amend 40
CFR 60.104a(j) to delete the
requirements to measure flow for the
H2S concentration limit for fuel gas.
Fifth, we proposed several
amendments to clarify the requirements
for control device operating parameters
in 40 CFR 60.105a. Specifically, we
proposed amendments to 40 CFR
60.105a(b)(1)(ii)(A) to require corrective
action be completed to repair faulty
(leaking or plugged) air or water lines
within 12 hours of identification of an
abnormal pressure reading during the
daily checks. We also proposed
revisions to 40 CFR 60.105a(i) to specify
that periods when abnormal pressure
PO 00000
Frm 00048
Fmt 4701
Sfmt 4700
readings for a jet ejector-type wet
scrubber (or other type of wet scrubber
equipped with atomizing spray nozzles)
are not corrected within 12 hours of
identification and periods when a bag
leak detection system alarm (for a fabric
filter) is not alleviated within the time
period specified in the rule are
considered to be periods of excess
emissions.
We also proposed amendments to 40
CFR 60.105(b)(1)(iv) and
60.107a(b)(1)(iv) to provide flexibility in
span range to accommodate different
manufacturers of the length-of-stain
tubes. We also proposed to delete the
last sentence in 40 CFR 60.105(b)(3)(iii).
Finally, we proposed clarification to
the performance test requirements for
the H2S concentration limit for affected
flares in 40 CFR 60.107a(e)(1)(ii) and
(e)(2)(ii) to remove the distinction
between flares with or without routine
flow.
2. How did the amendments to Refinery
NSPS Subparts J and Ja change since
proposal?
We are making very few changes to
the amendments proposed for Refinery
NSPS subparts J and Ja. In response to
comments, we are revising the NSPS
requirements to replace the
‘‘measurement sensitivity’’ requirements
with accuracy requirements consistent
with those used in Refinery MACT 1
and 2. Specifically, we are revising 40
CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to
require use of a flow sensor meeting an
accuracy requirement of ±5-percent over
the normal range of flow measured or
10-cubic-feet-per-minute, whichever is
greater. We are also revising the flare
accuracy requirements in 40 CFR
60.107a(f)(1)(ii) to require use of a flow
sensor meeting an accuracy requirement
of ±20-percent of the flow rate at
velocities ranging from 0.1 to 1 feet per
second and an accuracy of ±5-percent of
the flow rate for velocities greater than
1-feet-per-second.
Finally, we are revising 40 CFR
60.101a(b) to correct an inadvertent
error where the phrase ‘‘and delayed
coking units’’ was not included in the
proposed sentence revision.
3. What key comments did we receive
on the amendments to Refinery NSPS
Subparts J and Ja and what are our
responses?
Comment: Two commenters noted
concern with the term ‘‘measurement
sensitivity’’ in proposed 40 CFR
60.106a(a)(6)(i)(B) and (a)(7)(i)(B) for
sulfur recovery unit monitoring
alternatives and in existing regulations
40 CFR 60.107a(f)(1)(ii) for flares
because ‘‘sensitivity’’ is not a term
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
found on typical monitoring system data
sheets. Typical flow meter
characteristics include terms such as
accuracy and resolution and the
commenters requested that the EPA
revise the terminology to match the
wording found in 40 CFR part 63,
subpart CC, Table 13 for flow meters
(i.e., accuracy requirements).
Additionally, several commenters
suggested that the EPA flow monitor
accuracy specifications are inconsistent
with those in the SCAQMD Flare Rule
and many refinery consent decrees. The
commenters recommended revising
both the flare flow meter sensitivity
specification and accuracy specification
in Refinery MACT 1 Table 13 and in
Refinery NSPS subpart Ja to be
consistent with the accuracy
specification from the Shell Deer Park
Consent Decree, Appendix 1.10, which
specifies the required flare flow meter
accuracy as ‘‘±20% of reading over the
velocity range of 0.1–1 feet per second
(ft/s) and ±5% of reading over the
velocity range of 1–250 ft/s.’’
Response: We proposed the term
‘‘measurement sensitivity’’ in proposed
40 CFR 60.106a(a)(6)(i)(B) and
(a)(7)(i)(B) to be internally consistent
within Refinery NSPS subpart Ja [i.e.,
consistent with the existing language in
§ 60.107a(f)(1)(ii)]. However, we agree
with the commenters that this term may
be unclear. This term is not defined in
Refinery NSPS subpart Ja and it is not
commonly used in the flow monitoring
system’s technical specification sheets.
Therefore, to be consistent with the
terminology used by instrument vendors
and used in Refinery MACT 1 and 2, we
are revising these sections to replace the
term ‘‘measurement sensitivity’’ with
‘‘accuracy.’’ We are also revising the
flow rate accuracy provisions specific
for flares to provide an accuracy
requirement of ±20-percent over the
velocity range of 0.1–1 ft/s and ±5% for
velocities exceeding 1 ft/s in 40 CFR
60.107a(f)(1)(ii) and in Table 13 of
subpart CC. We are providing this
provision specifically for flares because
they commonly operate at high
turndown ratios. For other flow
measurements, we are retaining the 10cubic-foot-per-minute accuracy
requirement. We are also clarifying that
the ±5-percent accuracy requirement for
the SRU alternatives apply to the ‘‘the
normal range of flow measured’’
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
consistent with the requirements in
Refinery MACT 1 and 2.
Comment: One commenter stated that
in the proposed revisions to 40 CFR
60.100a, (79 FR 36956), the EPA
proposes to remove the phrase ‘‘and
delayed coker units’’ from 40 CFR
60.100a(b). However, we state the
compliance date for both flares and
delayed coker units separately in the
same paragraph. The commenter
believes the EPA should explain the
reason for and implications of the
removal of this phrase.
Response: The removal of the phrase
‘‘and delayed coking units’’ from the
first sentence in 40 CFR 60.100a(b) was
an inadvertent error. The only revision
that we intended to make in 40 CFR
60.100a was to allow owners or
operators subject to subpart J to elect to
comply with the requirements in
subpart Ja. In the final amendments, we
have included the phrase ‘‘and delayed
coking units’’ in the first sentence in 40
CFR 60.100a(b).
4. What is the rationale for our final
approach and final decisions for the
amendments to Refinery NSPS Subparts
J and Ja?
We are finalizing amendments for
Refinery NSPS subparts J and Ja as
proposed with minor revisions. In
response to comments, we are revising
the ‘‘measurement sensitivity’’
requirements to be an ‘‘accuracy’’
requirement. This change will make the
requirements more clear and consistent
between the flow meter requirements in
the NSPS and the MACT standards
since the same flow meter will be
subject to each of these requirements.
We are also providing a dual accuracy
requirement for flare flow meters. This
accuracy requirement is necessary
because flares, which can have large
diameters to accommodate high flows,
are commonly operated at low flow
rates. Together, this makes it technically
infeasible for many flares to meet the
lower flow 10 cfm accuracy
requirement. Therefore, we are
providing specific accuracy
requirements for flares of ±20-percent
over the velocity range of 0.1–1 ft/s and
±5-percent for velocities exceeding 1 ft/
s, consistent with recent consent
decrees and equipment vendor
specifications.
Finally, we are revising the
introductory phrase in the first sentence
PO 00000
Frm 00049
Fmt 4701
Sfmt 4700
75225
in 40 CFR 60.101a(b) to read ‘‘Except for
flares and delayed coking units . . .’’ to
correct an inadvertent error. We
intended to revise this sentence only to
include the proposed provision to allow
sources subject to Refinery NSPS
subpart J to comply with Refinery NSPS
subpart Ja. The redline text posted on
our Web site showed no revisions to this
introductory phrase, but the amendatory
text did not include the words ‘‘and
delayed coking units’’ in this phrase.
This was an inadvertent error, which we
are correcting in the final rule.
V. Summary of Cost, Environmental
and Economic Impacts and Additional
Analyses Conducted
A. What are the affected facilities, the
air quality impacts and cost impacts?
The sources affected by significant
amendments to the petroleum refinery
standards include flares, storage vessels,
pressure relief devices, fugitive
emissions and DCU. The amendments
for other sources subject to one or more
of the petroleum refinery standards are
expected to have minimal air quality
and cost impacts.
The total capital investment cost of
the final amendments and standards is
estimated at $283 million, $112 million
from the final amendments for storage
vessels, DCU and fenceline monitoring
and $171 million from standards to
ensure compliance. We estimate
annualized costs of the final
amendments for storage vessels, DCU
and fenceline monitoring to be
approximately $13.0 million, which
includes an estimated $11.0 million for
recovery of lost product and the
annualized cost of capital. We also
estimated annualized costs of the final
standards to ensure compliance to be
approximately $50.2 million. The final
amendments for storage vessels, DCU
and fenceline monitoring would achieve
a nationwide HAP emission reduction
of 1,323 tpy, with a concurrent
reduction in VOC emissions of 16,660
tpy and a reduction in methane
emissions of 8,700 metric tonnes per
year. Table 2 of this preamble
summarizes the cost and emission
reduction impacts of the final
amendments, and Table 3 of this
preamble summarizes the costs of the
final standards to ensure compliance.
E:\FR\FM\01DER2.SGM
01DER2
75226
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 2—NATIONWIDE IMPACTS OF FINAL AMENDMENTS (2010$)
Affected source
Total capital
investment
(million $)
Total
annualized
cost without
credit
(million $/yr)
Product
recovery
credit
(million $/yr)
Total
annualized
costs
(million $/yr)
Methane
emission
reductions
(metric tpy)
VOC
emission
reductions
(tpy)
Cost
effectiveness
($/ton VOC)
HAP
emission
reductions
(tpy)
Cost
effectiveness
($/ton HAP)
Storage Vessels ........................
Delayed Coking Units ...............
Fugitive Emissions (Fenceline
Monitoring) .............................
18.5
81
3.13
14.5
(8.16)
(2.80)
(5.03)
11.7
....................
8,700
14,600
2,060
(345)
5,680
910
413
(5,530)
28,330
12.5
6.36
....................
6.36
....................
....................
....................
....................
....................
Total ...................................
112
24.0
(11.0)
13.0
8,700
16,660
780
1,323
9,830
TABLE 3—NATIONWIDE COSTS OF FINAL AMENDMENTS TO ENSURE COMPLIANCE (2010$)
Total
annualized
cost without
credit
(million $/yr)
Product
recovery
credit
(million $/yr)
Total
annualized
costs
(million $/yr)
Affected Source
Total capital
investment
(million $)
Relief Device Monitoring ..................................................................................
Flare Monitoring ...............................................................................................
FCCU Testing ..................................................................................................
11.1
160
........................
3.3
46.5
0.4
........................
........................
........................
3.3
46.5
0.4
Total ..........................................................................................................
171
50.2
........................
50.2
The impacts shown in Table 2 do not
include costs, product recovery credits,
or emissions reductions associated with
any root cause analysis or corrective
action taken in response to the final
amendments for fenceline monitoring.
The impacts shown in Table 3 do not
include (i) the costs or emissions
reductions associated with any root
cause analysis and corrective action
taken in response to the final source
performance testing at the FCCUs, or (ii)
emissions reductions associated with
corrective action taken in response to
pressure relief device or (iii) emissions
reductions associated with the flare
operating and monitoring provisions.
The operational and monitoring
requirements for flares at refineries have
the potential to reduce excess emissions
from flares by up to approximately
3,900 tpy of HAP and 33,000 tpy of
VOC. The operational and monitoring
requirements for flares also have the
potential to reduce methane emissions
by 25,800 metric tonnes per year while
increasing emissions of carbon dioxide
(CO2) and nitrous oxide by 267,000
metric tonnes per year and 2 metric
tonnes per year, respectively, yielding a
net reduction in GHG emissions of
377,000 metric tonnes per year of CO2
equivalents (CO2e).
tkelley on DSK3SPTVN1PROD with RULES2
B. What are the economic impacts?
We performed a national economic
impact analysis for petroleum product
producers. All petroleum product
refiners will incur annual compliance
costs of less than 1-percent of their
sales. For all firms, the minimum costto-sales ratio is <0.01-percent; the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
maximum cost-to-sales ratio is 0.87percent; and the mean cost-to-sales ratio
is 0.03-percent. Therefore, the overall
economic impact of this proposed rule
should be minimal for the refining
industry and its consumers.
In addition, the EPA performed a
screening analysis for impacts on small
businesses by comparing estimated
annualized engineering compliance
costs at the firm-level to firm sales. The
screening analysis found that the ratio
of compliance cost to firm revenue falls
below 1-percent for the 28 small
companies likely to be affected by the
proposal. For small firms, the minimum
cost-to-sales ratio is <0.01-percent; the
maximum cost-to-sales ratio is 0.62percent; and the mean cost-to-sales ratio
is 0.07-percent.
More information and details of this
analysis is provided in the technical
document ‘‘Economic Impact Analysis
for Petroleum Refineries Proposed
Amendments to the National Emissions
Standards for Hazardous Air
Pollutants’’, which is available in the
docket for this rule (Docket ID No. EPA–
HQ–OAR–2010–0682).
C. What are the benefits?
The final rule is anticipated to result
in a reduction of 1,323 tpy of HAP
(based on allowable emissions under the
MACT standards) and 16,660 tpy of
VOC, not including potential emission
reductions that may occur as a result of
the operating and monitoring
requirements for flares and fugitive
emission sources via fenceline
monitoring. These avoided emissions
will result in improvements in air
PO 00000
Frm 00050
Fmt 4701
Sfmt 4700
quality and reduced negative health
effects associated with exposure to air
pollution of these emissions; however,
we have not quantified or monetized the
benefits of reducing these emissions for
this rulemaking.
D. Impacts of This Rulemaking on
Environmental Justice Populations
To examine the potential impacts on
vulnerable populations (minority, lowincome and indigenous communities)
that might be associated with the
Petroleum Refinery source categories
addressed in this final rule, we
evaluated the percentages of various
social, demographic and economic
groups in the at-risk populations living
near the facilities where these sources
are located and compared them to
national averages. Our analysis of the
demographics of the population with
estimated risks greater than 1-in-1
million indicates potential disparities in
risks between demographic groups
including the African American, Other
and Multiracial, Hispanic, Below the
Poverty Level, and Over 25 without a
High School Diploma when compared
to the nationwide percentages of those
groups. These groups will benefit the
most from the emission reductions
achieved by this final rulemaking,
which is projected to result in 1 million
fewer people exposed to risks greater
than 1-in-1 million.
Additionally, these communities will
benefit from this rulemaking, as this
rulemaking for the first time ever
requires fenceline monitoring, and
reporting of fenceline data. The agency
during the pre-proposal period and
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
during the comment period received
feedback from communities on the
importance of having fenceline
monitoring in their communities and
the importance of communities having
access to this data. The EPA believes
that vulnerable communities will
benefit from this data and the
requirements that EPA has put in place
in this rulemaking to manage fugitive
emissions.
E. Impacts of This Rulemaking on
Children’s Health
Under Executive Order 13045 the EPA
must evaluate the effects of the planned
regulation on children’s health and
safety. This action’s health and risk
assessments are contained in section
IV.A of this preamble. We believe we
have adequately estimated risk for
children, and we do not believe that the
environmental health risks addressed by
this action present a disproportionate
risk to children. When the EPA derives
exposure reference concentrations and
unit risk estimates (URE) for HAP, it
also considers the most sensitive
populations identified (i.e., children) in
the available literature, and importantly,
these are the values used in our risk
assessments. With regard to children’s
potentially greater susceptibility to noncancer toxicants, the assessments rely
on the EPA (or comparable) hazard
identification and dose-response values
which have been developed to be
protective for all subgroups of the
general population, including children.
With respect to cancer, the EPA uses the
age-dependent adjustment factor
approach, and applies these factors to
carcinogenic pollutants that are known
to act via mutagenic mode of action.
Further details are provided in the
‘‘Final Residual Risk Assessment for the
Petroleum Refining Source Sector’’,
Docket ID No. EPA–HQ–OAR–2010–
0682.
tkelley on DSK3SPTVN1PROD with RULES2
VI. Statutory and Executive Order
Reviews
A. Executive Orders 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is an economically
significant regulatory action that was
submitted to the Office of Management
and Budget (OMB) for review. Any
changes made in response to OMB
recommendations have been
documented in the docket. The EPA
prepared an analysis of the potential
costs and benefits associated with this
action. This analysis, ‘‘Economic Impact
Analysis: Petroleum Refineries—Final
Amendments to the National Emissions
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Standards for Hazardous Air Pollutants
and New Source Performance
Standards’’ is available in Docket ID
Number EPA–HQ–OAR–2010–0682.
B. Paperwork Reduction Act (PRA)
The information collection
requirements in this rule have been
submitted for approval to the Office of
Management and Budget (OMB) under
the Paperwork Reduction Act, 44 U.S.C.
3501 et se. The information collection
requirements are not enforceable until
OMB approves them.
Adequate recordkeeping and
reporting are necessary to ensure
compliance with these standards as
required by the CAA. The ICR
information collected from
recordkeeping and reporting
requirements is also used for
prioritizing inspections and is of
sufficient quality to be used as evidence
in court.
The ICR document prepared by the
EPA for the amendments to the
Petroleum Refinery MACT standards for
40 CFR part 63, subpart CC has been
assigned the EPA ICR number 1692.08.
Burden changes associated with these
amendments would result from new
monitoring, recordkeeping and
reporting requirements. The estimated
annual increase in recordkeeping and
reporting burden hours is 99,722 hours;
the frequency of response is quarterly
and semiannual for reports for all
respondents that must comply with the
rule’s reporting requirements; and the
estimated average number of likely
respondents per year is 95 (this is the
average in the second year). The cost
burden to respondents resulting from
the collection of information includes
the total capital cost annualized over the
equipment’s expected useful life (about
$18 million, which includes monitoring
equipment for fenceline monitoring,
pressure relief devices, and flares), a
total operation and maintenance
component (about $21 million per year
for fenceline and flare monitoring), and
a labor cost component (about $8.3
million per year, the cost of the
additional 99,722 labor hours). Burden
is defined at 5 CFR 1320.3(b).
The ICR document prepared by the
EPA for the amendments to the
Petroleum Refinery MACT standards for
40 CFR part 63, subpart UUU has been
assigned the EPA ICR number 1844.06.
Burden changes associated with these
amendments would result from new
testing, recordkeeping and reporting
requirements being finalized with this
action. The estimated average burden
per response is 25 hours; the frequency
of response ranges from annually up to
every 5 years for respondents that have
PO 00000
Frm 00051
Fmt 4701
Sfmt 4700
75227
FCCU, and the estimated average
number of likely respondents per year is
67. The cost burden to respondents
resulting from the collection of
information includes the performance
testing costs (approximately $778,000
per year over the first 3 years for the
initial PM and one-time HCN
performance tests and $235,000 per year
starting in the fourth year), and a labor
cost component (approximately
$410,000 per year for 4,940 additional
labor hours). Burden is defined at 5 CFR
1320.3(b).
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for EPA’s regulations in 40
CFR are listed in 40 CFR part 9. When
this ICR is approved by OMB, the
Agency will publish a technical
amendment to 40 CFR part 9 in the
Federal Register to display the OMB
control number for the approved
information collection requirements
contained in this final rule.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have
a significant economic impact on a
substantial number of small entities
(SISNOSE) under the RFA. The small
entities subject to the requirements of
this action are small businesses, small
organizations and small governmental
jurisdictions. For purposes of assessing
the impacts of this rule on small
entities, a small entity is defined as: (1)
A small business in the petroleum
refining industry having 1,500 or fewer
employees (Small Business
Administration (SBA), 2011); (2) a small
governmental jurisdiction that is a
government of a city, county, town,
school district or special district with a
population of less than 50,000; and (3)
a small organization that is any not-forprofit enterprise which is independently
owned and operated and is not
dominant in its field. Details of this
analysis are presented in the economic
impact analysis which can be found in
the docket for this rule (Docket ID No.
EPA–HQ–OAR–2010–0682).
D. Unfunded Mandates Reform Act
(UMRA)
This action does not contain an
unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C.
1531–1538, and does not significantly or
uniquely affect small governments. As
discussed earlier in this preamble, these
amendments result in nationwide costs
of $63.2 million per year for the private
sector. Additionally, the rule contains
no requirements that apply to small
E:\FR\FM\01DER2.SGM
01DER2
75228
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
governments and does not impose
obligations upon them.
E. Executive Order 13132: Federalism
This action does not have federalism
implications. It will not have substantial
direct effects on the states, on the
relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications, as specified in Executive
Order 13175. The final amendments
impose no requirements on tribal
governments. Thus, Executive Order
13175 does not apply to this action.
Consistent with the EPA Policy on
Consultation and Coordination with
Indian Tribes, the EPA consulted with
tribal officials during the development
of the proposed rule and specifically
solicited comment on the proposed
amendments from tribal officials.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
This action is not subject to Executive
Order 13045 because the EPA does not
believe the environmental health or
safety risks addressed by this action
present a disproportionate risk to
children. This action’s health and risk
assessments are contained in section
IV.A of this preamble.
tkelley on DSK3SPTVN1PROD with RULES2
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution or Use
This action is not a ‘‘significant
energy action’’ because it is not likely to
have a significant adverse effect on the
supply, distribution or use of energy.
The overall economic impact of this
final rule should be minimal for the
refining industry and its consumers.
I. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
Part 51
This rulemaking involves technical
standards. Therefore, the EPA
conducted searches for the Petroleum
Refinery Sector Risk and Technology
Review and New Source Performance
Standards through the Enhanced
National Standards Systems Network
(NSSN) Database managed by the
American National Standards Institute
(ANSI). We also contacted voluntary
consensus standards (VCS)
organizations and accessed and
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
searched their databases. We conducted
searches for EPA Methods 18, 22, 320,
325A, and 325B of 40 CFR parts 60 and
63, appendix A. No applicable VCS
were identified for EPA Method 22.
The following voluntary consensus
standards were identified as acceptable
alternatives to the EPA test methods for
the purpose of this rule.
The voluntary consensus standard
ISO 16017–2:2003(E) ‘‘Air quality—
Sampling and analysis of volatile
organic compounds in ambient air,
indoor air and workplace air by sorbent
tube/thermal desorption/capillary gas
chromatography. Part 2: Diffusive
sampling’’ is an acceptable alternative to
Method 325A, Sections 1.2, 6.1 and 6.5
and Method 325B Sections 1.3, 7.1.2,
7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and A.2.
This voluntary consensus standard gives
general guidance for the sampling and
analysis of volatile organic compounds
in air. It is applicable to indoor, ambient
and workplace air. This standard is
available at International Organization
for Standardization, ISO Central
Secretariat, Chemin de Blandonnet 8,
CP 401, 1214 Vernier, Geneva,
Switzerland. See https://www.iso.org.
The voluntary consensus standard BS
EN 14662–4:2005 ‘‘Ambient Air Quality:
Standard Method for the Measurement
of Benzene Concentrations—Part 4:
Diffusive Sampling Followed By
Thermal Desorption and Gas
Chromatography’’ is an acceptable
alternative to Method 325A, Section 1.2
and Method 325B, Sections 1.3, 7.1.3,
7.1.4, 12.2.4, 13.0, A.1.1, and A.2. This
voluntary consensus standard gives
general guidance for the sampling and
analysis of benzene in air by diffusive
sampling, thermal desorption and
capillary gas chromatography. This
standard is available the European
Committee for Standardization, Avenue
Marnix 17—B–1000 Brussels. See
https://www.cen.eu.
The voluntary consensus standard
ASTM D6420–99 (2010) ‘‘Test Method
for Determination of Gaseous Organic
Compounds by Direct Interface Gas
Chromatography/Mass Spectrometry’’ is
an acceptable alternative to EPA Method
18. This voluntary consensus standard
employs a direct interface gas
chromatography/mass spectrometer
(GCMS) to identify and quantify a list of
36 volatile organic compounds (the
compounds are listed in the method).
The voluntary consensus standard
ASTM D6196–03 (Reapproved 2009)
‘‘Standard Practice for Selection of
Sorbents, Sampling, and Thermal
Desorption Analysis Procedures for
Volatile Organic Compounds in Air’’ is
an acceptable alternative to Method
325A, Sections 1.2 and 6.1, and Method
PO 00000
Frm 00052
Fmt 4701
Sfmt 4700
325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4,
13.0, A.1.1, and A.2. This voluntary
consensus standard is intended to assist
in the selection of sorbents and
procedures for the sampling and
analysis of ambient, indoor, and
workplace atmospheres for a variety of
common volatile organic compounds.
The voluntary consensus standards
ASTM D1945–03 and later revision
ASTM D1945–14 ‘‘Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography’’ are acceptable for
natural gas analysis. This voluntary
consensus standard covers the
determination of the chemical
composition of natural gases and similar
gaseous mixtures. This test method may
be abbreviated for the analysis of lean
natural gases containing negligible
amounts of hexanes and higher
hydrocarbons, or for the determination
of one or more components, as required.
The voluntary consensus standard
ASTM UOP539–12 ‘‘Refinery Gas
Analysis by GC’’ is acceptable for
refinery gas analysis. This voluntary
consensus standard is for determining
the composition of refinery gas streams
or vaporized liquefied petroleum gas
using a preconfigured, commercially
available gas chromatograph.
The voluntary consensus standard
ASTM D6348–03 (Reapproved 2010)
including Annexes A1 through A8,
‘‘Determination of Gaseous Compounds
by Extractive Direct Interface Fourier
Transform (FTIR) Spectroscopy’’ is an
acceptable alternative to EPA Method
320. This voluntary consensus standard
is a field test method that employs an
extractive sampling system to direct
stationary source effluent to an FTIR
spectrometer for the identification and
quantification of gaseous compounds.
This field test method provides near real
time analysis of extracted gas samples
from stationary sources.
The voluntary consensus standard
ASTM D6348–12e1 ‘‘Determination of
Gaseous Compounds by Extractive
Direct Interface Fourier Transform
(FTIR) Spectroscopy’’ is an acceptable
alternative to EPA Method 320 with the
following two caveats: (1) The test plan
preparation and implementation in the
Annexes to ASTM D 6348–03
(Reapproved 2010), Sections A1 through
A8 are mandatory; and (2) In ASTM
D6348–03 (Reapproved 2010) Annex A5
(Analyte Spiking Technique), the
percent (%) R must be determined for
each target analyte (Equation A5.5). In
order for the test data to be acceptable
for a compound, %R must be 70% ≥ R
≤ 130%. If the %R value does not meet
this criterion for a target compound, the
test data is not acceptable for that
compound and the test must be repeated
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
for that analyte (i.e., the sampling and/
or analytical procedure should be
adjusted before a retest). The %R value
for each compound must be reported in
the test report, and all field
measurements must be corrected with
the calculated %R value for that
compound by using the following
equation:
Reported Result = (Measured
Concentration in the Stack × 100)/
% R.
This voluntary consensus standard is
a field test method that employs an
extractive sampling system to direct
stationary source effluent to an FTIR
spectrometer for the identification and
quantification of gaseous compounds.
This field test method provides near real
time analysis of extracted gas samples
from stationary sources.
The EPA solicited comments on VCS
and invited the public to identify
potentially-applicable VCS; however,
we did not receive comments regarding
this aspect of 40 CFR part 60, subparts
J and Ja, and part 63, subparts CC, UUU,
and Y. Under 40 CFR 63.7(f) and 63.8(f),
a source may apply to the EPA for
permission to use alternative test
methods or alternative monitoring
requirements in place of any required
testing methods, performance
specifications, or procedures in this
final rule.
tkelley on DSK3SPTVN1PROD with RULES2
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order 12898 (59 FR 7629;
February 16, 1994) establishes federal
executive policy on environmental
justice. Its main provision directs
federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies and activities on minority
populations and low-income
populations in the U.S. The EPA defines
environmental justice as the fair
treatment and meaningful involvement
of all people regardless of race, color,
national origin or income with respect
to the development, implementation
and enforcement of environmental laws,
regulations and policies. The EPA has
this goal for all communities and
persons by working to ensure that
everyone enjoys the same degree of
protection from environmental and
health hazards and equal access to the
decision-making process to have a
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
healthy environment in which to live,
learn and work.
The EPA believes the human health or
environmental risk addressed by this
action will not have potential
disproportionately high and adverse
human health or environmental effects
on minority, low-income or indigenous
populations. As discussed in section
V.D. of this preamble, the EPA
conducted an analysis of the
characteristics of the population with
greater than 1-in-1 million risk living
within 50 km of the 142 refineries
affected by this rulemaking and
determined that there are more AfricanAmericans, Other and multiracial
groups, Hispanics, low-income
individuals, individuals with less than
a high school diploma compared to
national averages. Therefore, these
populations are expected to experience
the benefits of the risk reductions
associated with this rule. The results of
this evaluation are contained in two
technical reports, ‘‘Risk and Technology
Review—Analysis of Socio-Economic
Factors for Populations Living Near
Petroleum Refineries’’, available in the
docket for this action (See Docket ID
Nos. EPA–HQ–OAR–2010–0682–0226
and -0227). Additionally, a discussion
of the final risk analysis is included in
Sections IV.A and V.D of this preamble.
The EPA has determined that this
final rule will not have
disproportionately high and adverse
human health or environmental effects
on minority, low-income or indigenous
populations because it maintains or
increases the level of environmental
protection for all affected populations
without having any disproportionately
high and adverse human health or
environmental effects on any
population, including any minority,
low-income or indigenous populations.
Further, the EPA believes that
implementation of this rule will provide
an ample margin of safety to protect
public health of all demographic groups.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and
the EPA will submit a rule report to
each House of the Congress and to the
Comptroller General of the United
States. This action is a ‘‘major rule’’ as
defined by 5 U.S.C. 804(2).
List of Subjects
40 CFR Part 60
Environmental protection,
Administrative practice and procedures,
Air pollution control, Hazardous
substances, Incorporation by reference,
Intergovernmental relations, Reporting
and recordkeeping requirements.
PO 00000
Frm 00053
Fmt 4701
Sfmt 4700
75229
40 CFR Part 63
Environmental protection,
Administrative practice and procedures,
Air pollution control, Hazardous
substances, Incorporation by reference,
Intergovernmental relations, Reporting
and recordkeeping requirements.
Dated: September 29, 2015.
Gina McCarthy,
Administrator.
For the reasons stated in the
preamble, title 40, chapter I, of the Code
of Federal Regulations is amended as
follows:
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
1. The authority citation for part 60
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
Subpart J—Standards of Performance
for Petroleum Refineries
2. Section 60.105 is amended by
revising paragraphs (b)(1)(iv) and
(b)(3)(iii) to read as follows:
■
§ 60.105 Monitoring of emissions and
operations.
*
*
*
*
*
(b) * * *
(1) * * *
(iv) The supporting test results from
sampling the requested fuel gas stream/
system demonstrating that the sulfur
content is less than 5 ppmv. Sampling
data must include, at minimum, 2
weeks of daily monitoring (14 grab
samples) for frequently operated fuel gas
streams/systems; for infrequently
operated fuel gas streams/systems,
seven grab samples must be collected
unless other additional information
would support reduced sampling. The
owner or operator shall use detector
tubes (‘‘length-of-stain tube’’ type
measurement) following the ‘‘Gas
Processors Association Standard 2377–
86 (incorporated by reference—see
§ 60.17), using tubes with a maximum
span between 10 and 40 ppmv inclusive
when 1≤N≤10, where N = number of
pump strokes, to test the applicant fuel
gas stream for H2S; and
*
*
*
*
*
(3) * * *
(iii) If the operation change results in
a sulfur content that is outside the range
of concentrations included in the
original application and the owner or
operator chooses not to submit new
information to support an exemption,
the owner or operator must begin H2S
monitoring using daily stain sampling to
demonstrate compliance using length-of
E:\FR\FM\01DER2.SGM
01DER2
75230
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Subpart Ja—Standards of Performance
for Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After May 14,
2007
3. Section 60.100a is amended by
revising the first sentence of paragraph
(b) to read as follows:
■
*
*
*
*
*
(b) Except for flares and delayed
coking units, the provisions of this
subpart apply only to affected facilities
under paragraph (a) of this section
which either commence construction,
modification or reconstruction after May
14, 2007, or elect to comply with the
provisions of this subpart in lieu of
complying with the provisions in
subpart J of this part. * * *
*
*
*
*
*
■ 4. Section 60.101a is amended by:
■ a. Revising the definition of
‘‘Corrective action’’; and
■ b. Adding, in alphabetical order, a
definition for ‘‘Sour water’’.
The revision and addition read as
follows:
tkelley on DSK3SPTVN1PROD with RULES2
Definitions.
*
*
*
*
*
Where:
ELS = Emission limit for large sulfur recovery
plant, ppmv (as SO2, dry basis at zero
percent excess air);
k1 = Constant factor for emission limit
conversion: k1 = 1 for converting to the
SO2 limit for a sulfur recovery plant with
an oxidation control system or a
reduction control system followed by
incineration and k1 = 1.2 for converting
to the reduced sulfur compounds limit
for a sulfur recovery plant with a
reduction control system not followed by
incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner,
percent by volume (dry basis). If only
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
§ 60.102a
Emissions limitations.
*
§ 60.100a Applicability, designation of
affected facility, and reconstruction.
§ 60.101a
Corrective action means the design,
operation and maintenance changes that
one takes consistent with good
engineering practice to reduce or
eliminate the likelihood of the
recurrence of the primary cause and any
other contributing cause(s) of an event
identified by a root cause analysis as
having resulted in a discharge of gases
from an affected facility in excess of
specified thresholds.
*
*
*
*
*
Sour water means water that contains
sulfur compounds (usually H2S) at
concentrations of 10 parts per million
by weight or more.
*
*
*
*
*
■ 5. Section 60.102a is amended by
revising paragraphs (b)(1)(i) and (iii), (f),
and (g)(1) introductory text to read as
follows:
*
*
*
*
(b) * * *
(1) * * *
(i) 1.0 gram per kilogram (g/kg) (1
pound (lb) per 1,000 lb) coke burn-off
or, if a PM continuous emission
monitoring system (CEMS) is used,
0.040 grain per dry standard cubic feet
(gr/dscf) corrected to 0 percent excess
air for each modified or reconstructed
FCCU.
*
*
*
*
*
(iii) 1.0 g/kg (1 lb/1,000 lb) coke burnoff or, if a PM CEMS is used, 0.040 grain
per dry standard cubic feet (gr/dscf)
corrected to 0 percent excess air for each
affected FCU.
*
*
*
*
*
(f) Except as provided in paragraph
(f)(3) of this section, each owner or
operator of an affected sulfur recovery
plant shall comply with the applicable
emission limits in paragraph (f)(1) or (2)
of this section.
ambient air is used for the Claus burner
or if the owner or operator elects not to
monitor O2 concentration of the air/
oxygen mixture used in the Claus burner
or for non-Claus sulfur recovery plants,
use 20.9% for %O2.
(ii) For a sulfur recovery plant with a
reduction control system not followed
by incineration, the owner or operator
shall not discharge or cause the
discharge of any gases into the
atmosphere containing reduced sulfur
compounds in excess of the emission
limit calculated using Equation 1 of this
section. For Claus units that use only
PO 00000
Frm 00054
Fmt 4701
Sfmt 4700
(1) For a sulfur recovery plant with a
design production capacity greater than
20 long tons per day (LTD), the owner
or operator shall comply with the
applicable emission limit in paragraph
(f)(1)(i) or (ii) of this section. If the
sulfur recovery plant consists of
multiple process trains or release points,
the owner or operator shall comply with
the applicable emission limit for each
process train or release point
individually or comply with the
applicable emission limit in paragraph
(f)(1)(i) or (ii) as a flow rate weighted
average for a group of release points
from the sulfur recovery plant provided
that flow is monitored as specified in
§ 60.106a(a)(7); if flow is not monitored
as specified in § 60.106a(a)(7), the
owner or operator shall comply with the
applicable emission limit in paragraph
(f)(1)(i) or (ii) for each process train or
release point individually. For a sulfur
recovery plant with a design production
capacity greater than 20 long LTD and
a reduction control system not followed
by incineration, the owner or operator
shall also comply with the H2S emission
limit in paragraph (f)(1)(iii) of this
section for each individual release
point.
(i) For a sulfur recovery plant with an
oxidation control system or a reduction
control system followed by incineration,
the owner or operator shall not
discharge or cause the discharge of any
gases into the atmosphere (SO2) in
excess of the emission limit calculated
using Equation 1 of this section. For
Claus units that use only ambient air in
the Claus burner or that elect not to
monitor O2 concentration of the air/
oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery
plants, this SO2 emissions limit is 250
ppmv (dry basis) at zero percent excess
air.
ambient air in the Claus burner or for
non-Claus sulfur recovery plants, this
reduced sulfur compounds emission
limit is 300 ppmv calculated as ppmv
SO2 (dry basis) at 0-percent excess air.
(iii) For a sulfur recovery plant with
a reduction control system not followed
by incineration, the owner or operator
shall not discharge or cause the
discharge of any gases into the
atmosphere containing hydrogen sulfide
(H2S) in excess of 10 ppmv calculated
as ppmv SO2 (dry basis) at zero percent
excess air.
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.000
stain tubes with a maximum span
between 200 and 400 ppmv inclusive
when 1≤N≤5, where N = number of
pump strokes. The owner or operator
must begin monitoring according to the
requirements in paragraph (a)(1) or (2)
of this section as soon as practicable but
in no case later than 180 days after the
operation change. During daily stain
tube sampling, a daily sample exceeding
162 ppmv is an exceedance of the 3hour H2S concentration limit.
*
*
*
*
*
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75231
control system followed by incineration,
the owner or operator shall not
discharge or cause the discharge of any
gases into the atmosphere containing
SO2 in excess of the emission limit
calculated using Equation 2 of this
section. For Claus units that use only
ambient air in the Claus burner or that
elect not to monitor O2 concentration of
the air/oxygen mixture used in the
Claus burner or for non-Claus sulfur
recovery plants, this SO2 emission limit
is 2,500 ppmv (dry basis) at zero percent
excess air.
the sulfur pit, which shall not exceed
240 hours per year. The owner or
operator must document the time
periods during which the sulfur pit
vents were not controlled and measures
taken to minimize emissions during
these periods. Examples of these
measures include not adding fresh
sulfur or shutting off vent fans.
(g) * * *
(1) Except as provided in (g)(1)(iii) of
this section, for each fuel gas
combustion device, the owner or
operator shall comply with either the
emission limit in paragraph (g)(1)(i) of
this section or the fuel gas concentration
limit in paragraph (g)(1)(ii) of this
section. For CO boilers or furnaces that
are part of a fluid catalytic cracking unit
or fluid coking unit affected facility, the
owner or operator shall comply with the
fuel gas concentration limit in
paragraph (g)(1)(ii) for all fuel gas
streams combusted in these units.
*
*
*
*
*
■ 6. Section 60.104a is amended by:
■ a. Revising the first sentence of
paragraph (a) and paragraphs (b), (f)
introductory text, and (h) introductory
text;
■ b. Adding paragraph (h)(6); and
■ c. Removing and reserving paragraphs
(j)(1) through (3).
The revisions and additions read as
follows:
requirement in § 60.103a(h) according to
the requirements of § 60.8. * * *
(b) The owner or operator of a FCCU
or FCU that elects to monitor control
device operating parameters according
to the requirements in § 60.105a(b), to
use bag leak detectors according to the
requirements in § 60.105a(c), or to use
COMS according to the requirements in
§ 60.105a(e) shall conduct a PM
performance test at least annually (i.e.,
once per calendar year, with an interval
of at least 8 months but no more than
16 months between annual tests) and
furnish the Administrator a written
report of the results of each test.
*
*
*
*
*
(f) The owner or operator of an FCCU
or FCU that uses cyclones to comply
with the PM per coke burn-off emissions
limit in § 60.102a(b)(1) shall establish a
site-specific opacity operating limit
according to the procedures in
paragraphs (f)(1) through (3) of this
section.
*
*
*
*
*
(h) The owner or operator shall
determine compliance with the SO2
emissions limits for sulfur recovery
plants in § 60.102a(f)(1)(i) and (f)(2)(i)
and the reduced sulfur compounds and
H2S emissions limits for sulfur recovery
plants in § 60.102a(f)(1)(ii), (f)(1)(iii),
(f)(2)(ii), and (f)(2)(iii) using the
following methods and procedures:
*
*
*
*
*
(6) If oxygen or oxygen-enriched air is
used in the Claus burner and either
Equation 1 or 2 of this subpart is used
to determine the applicable emissions
limit, determine the average O2
concentration of the air/oxygen mixture
supplied to the Claus burner, in percent
by volume (dry basis), for the
performance test using all hourly
average O2 concentrations determined
(ii) For a sulfur recovery plant with a
reduction control system not followed
by incineration, the owner or operator
shall not discharge or cause the
discharge of any gases into the
atmosphere containing reduced sulfur
compounds in excess of the emission
limit calculated using Equation 2 of this
section. For Claus units that use only
ambient air in the Claus burner or for
non-Claus sulfur recovery plants, this
reduced sulfur compounds emission
limit is 3,000 ppmv calculated as ppmv
SO2 (dry basis) at zero percent excess
air.
(iii) For a sulfur recovery plant with
a reduction control system not followed
by incineration, the owner or operator
shall not discharge or cause the
discharge of any gases into the
atmosphere containing H2S in excess of
100 ppmv calculated as ppmv SO2 (dry
basis) at zero percent excess air.
(3) The emission limits in paragraphs
(f)(1) and (2) of this section shall not
apply during periods of maintenance of
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
§ 60.104a
Performance tests.
(a) The owner or operator shall
conduct a performance test for each
FCCU, FCU, sulfur recovery plant and
fuel gas combustion device to
demonstrate initial compliance with
each applicable emissions limit in
§ 60.102a and conduct a performance
test for each flare to demonstrate initial
compliance with the H2S concentration
PO 00000
Frm 00055
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.001
§ 60.106a(a)(7); if flow is not monitored
as specified in § 60.106a(a)(7), the
owner or operator shall comply with the
applicable emission limit in paragraph
(f)(2)(i) or (ii) for each process train or
release point individually. For a sulfur
recovery plant with a design production
capacity of 20 LTD or less and a
reduction control system not followed
by incineration, the owner or operator
shall also comply with the H2S emission
limit in paragraph (f)(2)(iii) of this
section for each individual release
point.
(i) For a sulfur recovery plant with an
oxidation control system or a reduction
Where:
ESS = Emission limit for small sulfur recovery
plant, ppmv (as SO2, dry basis at zero
percent excess air);
k1 = Constant factor for emission limit
conversion: k1 = 1 for converting to the
SO2 limit for a sulfur recovery plant with
an oxidation control system or a
reduction control system followed by
incineration and k1 = 1.2 for converting
to the reduced sulfur compounds limit
for a sulfur recovery plant with a
reduction control system not followed by
incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner,
percent by volume (dry basis). If only
ambient air is used in the Claus burner
or if the owner or operator elects not to
monitor O2 concentration of the air/
oxygen mixture used in the Claus burner
or for non-Claus sulfur recovery plants,
use 20.9% for %O2.
tkelley on DSK3SPTVN1PROD with RULES2
(2) For a sulfur recovery plant with a
design production capacity of 20 LTD or
less, the owner or operator shall comply
with the applicable emission limit in
paragraph (f)(2)(i) or (ii) of this section.
If the sulfur recovery plant consists of
multiple process trains or release points,
the owner or operator may comply with
the applicable emission limit for each
process train or release point
individually or comply with the
applicable emission limit in paragraph
(f)(2)(i) or (ii) as a flow rate weighted
average for a group of release points
from the sulfur recovery plant provided
that flow is monitored as specified in
75232
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
during the test runs using the
procedures in § 60.106a(a)(5) or (6).
*
*
*
*
*
■ 7. Section 60.105a is amended by:
■ a. Revising paragraphs (b)(1)(i),
(b)(1)(ii)(A), (b)(2), (h)(1), (h)(3)(i), and
(i)(1);
■ b. Redesignating paragraphs (i)(2)
through (6) as (i)(3) through (7);
■ c. Adding paragraph (i)(2); and
■ d. Revising newly redesignated
paragraph (i)(7).
The revisions and additions read as
follows:
§ 60.105a Monitoring of emissions and
operations for fluid catalytic cracking units
(FCCU) and fluid coking units (FCU).
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
(b) * * *
(1) * * *
(i) For units controlled using an
electrostatic precipitator, the owner or
operator shall use CPMS to measure and
record the hourly average total power
input and secondary current to the
entire system.
(ii) * * *
(A) As an alternative to pressure drop,
the owner or operator of a jet ejector
type wet scrubber or other type of wet
scrubber equipped with atomizing spray
nozzles must conduct a daily check of
the air or water pressure to the spray
nozzles and record the results of each
check. Faulty (e.g., leaking or plugged)
air or water lines must be repaired
within 12 hours of identification of an
abnormal pressure reading.
*
*
*
*
*
(2) For use in determining the coke
burn-off rate for an FCCU or FCU, the
owner or operator shall install, operate,
calibrate, and maintain an instrument
for continuously monitoring the
concentrations of CO2, O2 (dry basis),
and if needed, CO in the exhaust gases
prior to any control or energy recovery
system that burns auxiliary fuels. A CO
monitor is not required for determining
coke burn-off rate when no auxiliary
fuel is burned and a continuous CO
monitor is not required in accordance
with paragraph (h)(3) of this section.
(i) The owner or operator shall install,
operate, and maintain each CO2 and O2
monitor according to Performance
Specification 3 of appendix B to this
part.
(ii) The owner or operator shall
conduct performance evaluations of
each CO2 and O2 monitor according to
the requirements in § 60.13(c) and
Performance Specification 3 of
appendix B to this part. The owner or
operator shall use Method 3 of appendix
A–3 to this part for conducting the
relative accuracy evaluations.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(iii) If a CO monitor is required, the
owner or operator shall install, operate,
and maintain each CO monitor
according to Performance Specification
4 or 4A of appendix B to this part. If this
CO monitor also serves to demonstrate
compliance with the CO emissions limit
in § 60.102a(b)(4), the span value for
this instrument is 1,000 ppm; otherwise,
the span value for this instrument
should be set at approximately 2 times
the typical CO concentration expected
in the FCCU of FCU flue gas prior to any
emission control or energy recovery
system that burns auxiliary fuels.
(iv) If a CO monitor is required, the
owner or operator shall conduct
performance evaluations of each CO
monitor according to the requirements
in § 60.13(c) and Performance
Specification 4 of appendix B to this
part. The owner or operator shall use
Method 10, 10A, or 10B of appendix A–
3 to this part for conducting the relative
accuracy evaluations.
(v) The owner or operator shall
comply with the quality assurance
requirements of procedure 1 of
appendix F to this part, including
quarterly accuracy determinations for
CO2 and CO monitors, annual accuracy
determinations for O2 monitors, and
daily calibration drift tests.
*
*
*
*
*
(h) * * *
(1) The owner or operator shall
install, operate, and maintain each CO
monitor according to Performance
Specification 4 or 4A of appendix B to
this part. The span value for this
instrument is 1,000 ppmv CO.
*
*
*
*
*
(3) * * *
(i) The demonstration shall consist of
continuously monitoring CO emissions
for 30 days using an instrument that
meets the requirements of Performance
Specification 4 or 4A of appendix B to
this part. The span value shall be 100
ppmv CO instead of 1,000 ppmv, and
the relative accuracy limit shall be 10
percent of the average CO emissions or
5 ppmv CO, whichever is greater. For
instruments that are identical to Method
10 of appendix A–4 to this part and
employ the sample conditioning system
of Method 10A of appendix A–4 to this
part, the alternative relative accuracy
test procedure in section 10.1 of
Performance Specification 2 of
appendix B to this part may be used in
place of the relative accuracy test.
*
*
*
*
*
(i) * * *
(1) If a CPMS is used according to
paragraph (b)(1) of this section, all 3hour periods during which the average
PM control device operating
PO 00000
Frm 00056
Fmt 4701
Sfmt 4700
characteristics, as measured by the
continuous monitoring systems under
paragraph (b)(1), fall below the levels
established during the performance test.
If the alternative to pressure drop CPMS
is used for the owner or operator of a jet
ejector type wet scrubber or other type
of wet scrubber equipped with
atomizing spray nozzles, each day in
which abnormal pressure readings are
not corrected within 12 hours of
identification.
(2) If a bag leak detection system is
used according to paragraph (c) of this
section, each day in which the cause of
an alarm is not alleviated within the
time period specified in paragraph (c)(3)
of this section.
*
*
*
*
*
(7) All 1-hour periods during which
the average CO concentration as
measured by the CO continuous
monitoring system under paragraph (h)
of this section exceeds 500 ppmv or, if
applicable, all 1-hour periods during
which the average temperature and O2
concentration as measured by the
continuous monitoring systems under
paragraph (h)(4) of this section fall
below the operating limits established
during the performance test.
■ 8. Section 60.106a is amended by:
■ a. Revising paragraph (a)(1)(i);
■ b. Adding paragraphs (a)(1)(iv)
through (vii);
■ c. Revising paragraphs (a)(2)
introductory text, (a)(2)(i) and (ii), and
the first sentence of paragraph (a)(2)(iii);
■ d. Removing paragraphs (a)(2)(iv) and
(v);
■ e. Redesignating paragraphs (a)(2)(vi)
through (ix) as (a)(2)(iv) through (vii);
■ f. Revising the first sentence of
paragraph (a)(3) introductory text and
paragraph (a)(3)(i);
■ g. Adding paragraphs (a)(4) through
(7); and
■ h. Revising paragraphs (b)(2) and (3).
The revisions and additions read as
follows:
§ 60.106a Monitoring of emissions and
operations for sulfur recovery plants.
(a) * * *
(1) * * *
(i) The span value for the SO2 monitor
is two times the applicable SO2
emission limit at the highest O2
concentration in the air/oxygen stream
used in the Claus burner, if applicable.
*
*
*
*
*
(iv) The owner or operator shall
install, operate, and maintain each O2
monitor according to Performance
Specification 3 of appendix B to this
part.
(v) The span value for the O2 monitor
must be selected between 10 and 25
percent, inclusive.
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(vi) The owner or operator shall
conduct performance evaluations for the
O2 monitor according to the
requirements of § 60.13(c) and
Performance Specification 3 of
appendix B to this part. The owner or
operator shall use Methods 3, 3A, or 3B
of appendix A–2 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference—see § 60.17) is an acceptable
alternative to EPA Method 3B of
appendix A–2 to this part.
(vii) The owner or operator shall
comply with the applicable quality
assurance procedures of appendix F to
this part for each monitor, including
annual accuracy determinations for each
O2 monitor, and daily calibration drift
determinations.
(2) For sulfur recovery plants that are
subject to the reduced sulfur
compounds emission limit in
§ 60.102a(f)(1)(ii) or (f)(2)(ii), the owner
or operator shall install, operate,
calibrate, and maintain an instrument
for continuously monitoring and
recording the concentration of reduced
sulfur compounds and O2 emissions
into the atmosphere. The reduced sulfur
compounds emissions shall be
calculated as SO2 (dry basis, zero
percent excess air).
(i) The span value for the reduced
sulfur compounds monitor is two times
the applicable reduced sulfur
compounds emission limit as SO2 at the
highest O2 concentration in the air/
oxygen stream used in the Claus burner,
if applicable.
(ii) The owner or operator shall
install, operate, and maintain each
reduced sulfur compounds CEMS
according to Performance Specification
5 of appendix B to this part.
(iii) The owner or operator shall
conduct performance evaluations of
each reduced sulfur compounds
monitor according to the requirements
in § 60.13(c) and Performance
Specification 5 of appendix B to this
part. * * *
*
*
*
*
*
(3) In place of the reduced sulfur
compounds monitor required in
paragraph (a)(2) of this section, the
owner or operator may install, calibrate,
operate, and maintain an instrument
using an air or O2 dilution and
oxidation system to convert any reduced
sulfur to SO2 for continuously
monitoring and recording the
concentration (dry basis, 0 percent
excess air) of the total resultant SO2.
* * *
(i) The span value for this monitor is
two times the applicable reduced sulfur
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
compounds emission limit as SO2 at the
highest O2 concentration in the air/
oxygen stream used in the Claus burner,
if applicable.
*
*
*
*
*
(4) For sulfur recovery plants that are
subject to the H2S emission limit in
§ 60.102a(f)(1)(iii) or (f)(2)(iii), the
owner or operator shall install, operate,
calibrate, and maintain an instrument
for continuously monitoring and
recording the concentration of H2S, and
O2 emissions into the atmosphere. The
H2S emissions shall be calculated as
SO2 (dry basis, zero percent excess air).
(i) The span value for this monitor is
two times the applicable H2S emission
limit.
(ii) The owner or operator shall
install, operate, and maintain each H2S
CEMS according to Performance
Specification 7 of appendix B to this
part.
(iii) The owner or operator shall
conduct performance evaluations for
each H2S monitor according to the
requirements of § 60.13(c) and
Performance Specification 7 of
appendix B to this part. The owner or
operator shall use Methods 11 or 15 of
appendix A–5 to this part or Method 16
of appendix A–6 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference—see § 60.17) is an acceptable
alternative to EPA Method 15A of
appendix A–5 to this part.
(iv) The owner or operator shall
install, operate, and maintain each O2
monitor according to Performance
Specification 3 of appendix B to this
part.
(v) The span value for the O2 monitor
must be selected between 10 and 25
percent, inclusive.
(vi) The owner or operator shall
conduct performance evaluations for the
O2 monitor according to the
requirements of § 60.13(c) and
Performance Specification 3 of
appendix B to this part. The owner or
operator shall use Methods 3, 3A, or 3B
of appendix A–2 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference—see § 60.17) is an acceptable
alternative to EPA Method 3B of
appendix A–2 to this part.
(vii) The owner or operator shall
comply with the applicable quality
assurance procedures of appendix F to
this part for each monitor, including
annual accuracy determinations for each
O2 monitor, and daily calibration drift
determinations.
(5) For sulfur recovery plants that use
oxygen or oxygen enriched air in the
PO 00000
Frm 00057
Fmt 4701
Sfmt 4700
75233
Claus burner and that elects to monitor
O2 concentration of the air/oxygen
mixture supplied to the Claus burner,
the owner or operator shall install,
operate, calibrate, and maintain an
instrument for continuously monitoring
and recording the O2 concentration of
the air/oxygen mixture supplied to the
Claus burner in order to determine the
allowable emissions limit.
(i) The owner or operator shall install,
operate, and maintain each O2 monitor
according to Performance Specification
3 of appendix B to this part.
(ii) The span value for the O2 monitor
shall be 100 percent.
(iii) The owner or operator shall
conduct performance evaluations for the
O2 monitor according to the
requirements of § 60.13(c) and
Performance Specification 3 of
appendix B to this part. The owner or
operator shall use Methods 3, 3A, or 3B
of appendix A–2 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference—see § 60.17) is an acceptable
alternative to EPA Method 3B of
appendix A–2 to this part.
(iv) The owner or operator shall
comply with the applicable quality
assurance procedures of appendix F to
this part for each monitor, including
annual accuracy determinations for each
O2 monitor, and daily calibration drift
determinations.
(v) The owner or operator shall use
the hourly average O2 concentration
from this monitor for use in Equation 1
or 2 of § 60.102a(f), as applicable, for
each hour and determine the allowable
emission limit as the arithmetic average
of 12 contiguous 1-hour averages (i.e.,
the rolling 12-hour average).
(6) As an alternative to the O2 monitor
required in paragraph (a)(5) of this
section, the owner or operator may
install, calibrate, operate, and maintain
a CPMS to measure and record the
volumetric gas flow rate of ambient air
and oxygen-enriched gas supplied to the
Claus burner and calculate the hourly
average O2 concentration of the air/
oxygen mixture used in the Claus
burner as specified in paragraphs
(a)(6)(i) through (iv) of this section in
order to determine the allowable
emissions limit as specified in
paragraphs (a)(6)(v) of this section.
(i) The owner or operator shall install,
calibrate, operate and maintain each
flow monitor according to the
manufacturer’s procedures and
specifications and the following
requirements.
(A) Locate the monitor in a position
that provides a representative
measurement of the total gas flow rate.
E:\FR\FM\01DER2.SGM
01DER2
75234
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
monitor for physical and operational
integrity and all electrical connections
for oxidation and galvanic corrosion if
the flow monitor is not equipped with
a redundant flow sensor.
(E) Recalibrate the flow monitor in
accordance with the manufacturer’s
procedures and specifications biennially
(every two years) or at the frequency
specified by the manufacturer.
(ii) The owner or operator shall use
20.9 percent as the oxygen content of
the ambient air.
(iii) The owner or operator shall use
product specifications (e.g., as reported
in material safety data sheets) for
percent oxygen for purchased oxygen.
For oxygen produced onsite, the percent
oxygen shall be determined by periodic
measurements or process knowledge.
(iv) The owner or operator shall
calculate the hourly average O2
concentration of the air/oxygen mixture
used in the Claus burner using Equation
10 of this section:
Where:
%O2 = O2 concentration of the air/oxygen
mixture used in the Claus burner,
percent by volume (dry basis);
20.9 = O2 concentration in air, percent dry
basis;
Qair = Volumetric flow rate of ambient air
used in the Claus burner, dscfm;
%O2,oxy = O2 concentration in the enriched
oxygen stream, percent dry basis; and
Qoxy = Volumetric flow rate of enriched
oxygen stream used in the Claus burner,
dscfm.
reduced sulfur compounds emission
limit in § 60.102a(f)(1)(ii) or (f)(2)(ii) as
a flow rate weighted average for a group
of release points from the sulfur
recovery plant rather than for each
process train or release point
individually shall install, calibrate,
operate, and maintain a CPMS to
measure and record the volumetric gas
flow rate of each release point within
the group of release points from the
sulfur recovery plant as specified in
paragraphs (a)(7)(i) through (iv) of this
section.
(i) The owner or operator shall install,
calibrate, operate and maintain each
flow monitor according to the
manufacturer’s procedures and
specifications and the following
requirements.
(A) Locate the monitor in a position
that provides a representative
measurement of the total gas flow rate.
(B) Use a flow sensor meeting an
accuracy requirement of ±5 percent over
the normal range of flow measured or 10
cubic feet per minute, whichever is
greater.
(C) Use a flow monitor that is
maintainable online, is able to
continuously correct for temperature,
pressure, and moisture content, and is
able to record dry flow in standard
conditions (as defined in § 60.2) over
one-minute averages.
(D) At least quarterly, perform a visual
inspection of all components of the
monitor for physical and operational
integrity and all electrical connections
for oxidation and galvanic corrosion if
the flow monitor is not equipped with
a redundant flow sensor.
(E) Recalibrate the flow monitor in
accordance with the manufacturer’s
procedures and specifications biennially
(every two years) or at the frequency
specified by the manufacturer.
(ii) The owner or operator shall
correct the flow to 0 percent excess air
using Equation 11 of this section:
20.9c = 20.9 percent O2¥0.0 percent O2
(defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry
basis, percent.
(iii) The owner or operator shall
calculate the flow weighted average SO2
or reduced sulfur compounds
concentration for each hour using
Equation 12 of this section:
(v) The owner or operator shall use
the hourly average O2 concentration
determined using Equation 8 of
§ 60.104a(d)(8) for use in Equation 1 or
2 of § 60.102a(f), as applicable, for each
hour and determine the allowable
emission limit as the arithmetic average
of 12 contiguous 1-hour averages (i.e.,
the rolling 12-hour average).
(7) Owners or operators of a sulfur
recovery plant that elects to comply
with the SO2 emission limit in
§ 60.102a(f)(1)(i) or (f)(2)(i) or the
ER01DE15.003
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00058
Fmt 4701
Sfmt 4725
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.002
tkelley on DSK3SPTVN1PROD with RULES2
Where:
Qadj = Volumetric flow rate adjusted to 0
percent excess air, dry standard cubic
feet per minute (dscfm);
Cmeas = Volumetric flow rate measured by the
flow meter corrected to dry standard
conditions, dscfm;
ER01DE15.004
(B) Use a flow sensor meeting an
accuracy requirement of ±5 percent over
the normal range of flow measured or 10
cubic feet per minute, whichever is
greater.
(C) Use a flow monitor that is
maintainable online, is able to
continuously correct for temperature,
pressure and, for ambient air flow
monitor, moisture content, and is able to
record dry flow in standard conditions
(as defined in § 60.2) over one-minute
averages.
(D) At least quarterly, perform a visual
inspection of all components of the
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
(iv) For sulfur recovery plants that use
oxygen or oxygen enriched air in the
Claus burner, the owner or operator
shall use Equation 10 of this section and
the hourly emission limits determined
in paragraph (a)(5)(v) or (a)(6)(v) of this
section in-place of the pollutant
concentration to determine the flow
weighted average hourly emission limit
for each hour. The allowable emission
limit shall be calculated as the
arithmetic average of 12 contiguous 1hour averages (i.e., the rolling 12-hour
average).
(b) * * *
(2) All 12-hour periods during which
the average concentration of reduced
sulfur compounds (as SO2) as measured
by the reduced sulfur compounds
continuous monitoring system required
under paragraph (a)(2) or (3) of this
section exceeds the applicable emission
limit; or
(3) All 12-hour periods during which
the average concentration of H2S as
measured by the H2S continuous
monitoring system required under
paragraph (a)(4) of this section exceeds
Where:
Fd = F factor on dry basis at 0% excess air,
dscf/MMBtu.
Xi = mole or volume fraction of each
component in the fuel gas.
MEVi = molar exhaust volume, dry
standard cubic feet per mole (dscf/mol).
MHCi = molar heat content, Btu per mole
(Btu/mol).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
the applicable emission limit (dry basis,
0 percent excess air).
■ 9. Section 60.107a is amended by
revising paragraphs (a)(1)(i) and (ii),
(b)(1)(iv), the first sentence of paragraph
(b)(3)(iii), (d)(3), (e)(1) introductory text,
(e)(1)(ii), (e)(2) introductory text,
(e)(2)(ii), (e)(2)(vi)(C), (e)(3), (f)(1)(ii),
and (h)(5) to read as follows:
§ 60.107a Monitoring of emissions and
operations for fuel gas combustion devices
and flares.
(a) * * *
(1) * * *
(i) The owner or operator shall install,
operate, and maintain each SO2 monitor
according to Performance Specification
2 of appendix B to this part. The span
value for the SO2 monitor is 50 ppmv
SO2.
(ii) The owner or operator shall
conduct performance evaluations for the
SO2 monitor according to the
requirements of § 60.13(c) and
Performance Specification 2 of
appendix B to this part. The owner or
operator shall use Methods 6, 6A, or 6C
of appendix A–4 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference—see § 60.17) is an acceptable
alternative to EPA Method 6 or 6A of
appendix A–4 to this part. Samples
taken by Method 6 of appendix A–4 to
this part shall be taken at a flow rate of
approximately 2 liters/min for at least
30 minutes. The relative accuracy limit
shall be 20 percent or 4 ppmv,
whichever is greater, and the calibration
drift limit shall be 5 percent of the
established span value.
*
*
*
*
*
(b) * * *
(1) * * *
(iv) The supporting test results from
sampling the requested fuel gas stream/
system demonstrating that the sulfur
content is less than 5 ppmv H2S.
Sampling data must include, at
1,000,000 = unit conversion, Btu per
MMBtu.
*
*
*
*
*
(e) * * *
(1) Total reduced sulfur monitoring
requirements. The owner or operator
shall install, operate, calibrate and
maintain an instrument or instruments
for continuously monitoring and
recording the concentration of total
PO 00000
Frm 00059
Fmt 4701
Sfmt 4700
minimum, 2 weeks of daily monitoring
(14 grab samples) for frequently
operated fuel gas streams/systems; for
infrequently operated fuel gas streams/
systems, seven grab samples must be
collected unless other additional
information would support reduced
sampling. The owner or operator shall
use detector tubes (‘‘length-of-stain
tube’’ type measurement) following the
‘‘Gas Processors Association Standard
2377–86 (incorporated by reference—
see § 60.17), using tubes with a
maximum span between 10 and 40
ppmv inclusive when 1≤N≤10, where N
= number of pump strokes, to test the
applicant fuel gas stream for H2S; and
*
*
*
*
*
(3) * * *
(iii) If the operation change results in
a sulfur content that is outside the range
of concentrations included in the
original application and the owner or
operator chooses not to submit new
information to support an exemption,
the owner or operator must begin H2S
monitoring using daily stain sampling to
demonstrate compliance using lengthof-stain tubes with a maximum span
between 200 and 400 ppmv inclusive
when 1≤N≤5, where N = number of
pump strokes. * * *
*
*
*
*
*
(d) * * *
(3) As an alternative to the
requirements in paragraph (d)(2) of this
section, the owner or operator of a gasfired process heater shall install, operate
and maintain a gas composition
analyzer and determine the average F
factor of the fuel gas using the factors in
Table 1 of this subpart and Equation 13
of this section. If a single fuel gas system
provides fuel gas to several process
heaters, the F factor may be determined
at a single location in the fuel gas
system provided it is representative of
the fuel gas fed to the affected process
heater(s).
reduced sulfur in gas discharged to the
flare.
*
*
*
*
*
(ii) The owner or operator shall
conduct performance evaluations of
each total reduced sulfur monitor
according to the requirements in
§ 60.13(c) and Performance
Specification 5 of appendix B to this
part. The owner or operator of each total
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.005
Where:
Cave = Flow weighted average concentration
of the pollutant, ppmv (dry basis, zero
percent excess air). The pollutant is
either SO2 (if complying with the SO2
emission limit in § 60.102a(f)(1)(i) or
(f)(2)(i)) or reduced sulfur compounds (if
complying with the reduced sulfur
compounds emission limit in
§ 60.102a(f)(1)(ii) or (f)(2)(ii));
N = Number of release points within the
group of release points from the sulfur
recovery plant for which emissions
averaging is elected;
Cn = Pollutant concentration in the nth release
point within the group of release points
from the sulfur recovery plant for which
emissions averaging is elected, ppmv
(dry basis, zero percent excess air);
Qadj,n = Volumetric flow rate of the nth release
point within the group of release points
from the sulfur recovery plant for which
emissions averaging is elected, dry
standard cubic feet per minute (dscfm,
adjusted to 0 percent excess air).
75235
75236
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
reduced sulfur monitor shall use EPA
Method 15A of appendix A–5 to this
part for conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference-see § 60.17) is an acceptable
alternative to EPA Method 15A of
appendix A–5 to this part. The
alternative relative accuracy procedures
described in section 16.0 of Performance
Specification 2 of appendix B to this
part (cylinder gas audits) may be used
for conducting the relative accuracy
evaluations, except that it is not
necessary to include as much of the
sampling probe or sampling line as
practical.
*
*
*
*
*
(2) H2S monitoring requirements. The
owner or operator shall install, operate,
calibrate, and maintain an instrument or
instruments for continuously
monitoring and recording the
concentration of H2S in gas discharged
to the flare according to the
requirements in paragraphs (e)(2)(i)
through (iii) of this section and shall
collect and analyze samples of the gas
and calculate total sulfur concentrations
as specified in paragraphs (e)(2)(iv)
through (ix) of this section.
*
*
*
*
*
(ii) The owner or operator shall
conduct performance evaluations of
each H2S monitor according to the
requirements in § 60.13(c) and
Performance Specification 7 of
appendix B to this part. The owner or
operator shall use EPA Method 11, 15 or
15A of appendix A–5 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981 (incorporated by
reference—see § 60.17) is an acceptable
alternative to EPA Method 15A of
appendix A–5 to this part. The
alternative relative accuracy procedures
described in section 16.0 of Performance
Specification 2 of appendix B to this
part (cylinder gas audits) may be used
for conducting the relative accuracy
evaluations, except that it is not
necessary to include as much of the
sampling probe or sampling line as
practical.
*
*
*
*
*
(vi) * * *
(C) Determine the acceptable range for
subsequent weekly samples based on
the 95-percent confidence interval for
the distribution of daily ratios based on
the 10 individual daily ratios using
Equation 14 of this section.
Where:
AR = Acceptable range of subsequent ratio
determinations, unitless.
RatioAvg = 10-day average total sulfur-toH2S concentration ratio, unitless.
2.262 = t-distribution statistic for 95percent 2-sided confidence interval for 10
samples (9 degrees of freedom).
SDev = Standard deviation of the 10 daily
average total sulfur-to-H2S concentration
ratios used to develop the 10-day average
total sulfur-to-H2S concentration ratio,
unitless.
requirements in paragraph (a)(1) of this
section, determine the F factor of the
fuel gas at least daily according to the
requirements in paragraphs (d)(2)
through (4) of this section, determine
the higher heating value of the fuel gas
at least daily according to the
requirements in paragraph (d)(7) of this
section, and calculate the total sulfur
content (as SO2) in the fuel gas using
Equation 15 of this section.
*
*
*
*
(f) * * *
(1) * * *
(ii) Use a flow sensor meeting an
accuracy requirement of ±20 percent of
the flow rate at velocities ranging from
0.1 to 1 feet per second and an accuracy
of ±5 percent of the flow rate for
velocities greater than 1 feet per second.
*
*
*
*
*
(h) * * *
(5) Daily O2 limits for fuel gas
combustion devices. Each day during
which the concentration of O2 as
measured by the O2 continuous
monitoring system required under
paragraph (c)(6) or (d)(8) of this section
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
exceeds the O2 operating limit or
operating curve determined during the
most recent biennial performance test.
PART 63—NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS FOR SOURCE
CATEGORIES
10. The authority citation for part 63
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et se.
c. Revising newly redesignated
paragraph (h)(78);
■ d. Adding paragraphs (h)(15), (74),
(79), (85), (104) and (j)(2);
■ e. Redesignating paragraph (m)(3)
through (21) as (m)(5) through (23),
respectively, and paragraph (m)(2) as
(m)(3).
■ f. Adding paragraphs (m)(2) and (4)
and (n)(3); and
■ g. Revising paragraph (s)(1).
The revisions and additions read as
follows:
■
Subpart A—General Provisions
§ 63.14
11. Section 63.14 is amended by:
a. Revising paragraph (h)(14);
■ b. Redesignating paragraphs (h)(82)
through (99) as (h)(86) through (103),
paragraphs (h)(77) through (81) as
(h)(80) through (84), paragraphs (h)(73)
through (76) as paragraphs (h)(75)
through (78), and paragraphs (h)(15)
through (72) as (16) through (73),
respectively;
*
■
■
PO 00000
Frm 00060
Fmt 4701
Sfmt 4700
Incorporation by reference.
*
*
*
*
(h) * * *
(14) ASTM D1945–03 (Reapproved
2010), Standard Test Method for
Analysis of Natural Gas by Gas
Chromatography, Approved January 1,
2010, IBR approved for §§ 63.670(j),
63.772(h), and 63.1282(g).
(15) ASTM D1945–14, Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography, Approved
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.007
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
(3) SO2 monitoring requirements. The
owner or operator shall install, operate,
calibrate, and maintain an instrument
for continuously monitoring and
recording the concentration of SO2 from
a process heater or other fuel gas
combustion device that is combusting
gas representative of the fuel gas in the
flare gas line according to the
ER01DE15.006
Where:
TSFG = Total sulfur concentration, as SO2,
in the fuel gas, ppmv.
CSO2 = Concentration of SO2 in the exhaust
gas, ppmv (dry basis at 0-percent excess air).
Fd = F factor gas on dry basis at 0-percent
excess air, dscf/MMBtu.
HHVFG = Higher heating value of the fuel
gas, MMBtu/scf.
*
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
November 1, 2014, IBR approved for
§ 63.670(j).
*
*
*
*
*
(74) ASTM D6196–03 (Reapproved
2009), Standard Practice for Selection of
Sorbents, Sampling, and Thermal
Desorption Analysis Procedures for
Volatile Organic Compounds in Air,
Approved March 1, 2009, IBR approved
for appendix A to this part: Method
325A and Method 325B.
*
*
*
*
*
(78) ASTM D6348–03 (Reapproved
2010), Standard Test Method for
Determination of Gaseous Compounds
by Extractive Direct Interface Fourier
Transform Infrared (FTIR) Spectroscopy,
including Annexes A1 through A8,
Approved October 1, 2010, IBR
approved for § 63.1571(a), tables 4 and
5 to subpart JJJJJ, tables 4 and 6 to
subpart KKKKK, tables 1, 2, and 5 to
subpart UUUUU and appendix B to
subpart UUUUU.
*
*
*
*
*
(79) ASTM D6348–12e1, Standard
Test Method for Determination of
Gaseous Compounds by Extractive
Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, Approved
February 1, 2012, IBR approved for
§ 63.1571(a).
*
*
*
*
*
(85) ASTM D6420–99 (Reapproved
2010), Standard Test Method for
Determination of Gaseous Organic
Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry,
Approved October 1, 2010, IBR
approved for § 63.670(j) and appendix A
to this part: Method 325B.
*
*
*
*
*
(104) ASTM UOP539–12, Refinery
Gas Analysis by GC, Copyright 2012 (to
UOP), IBR approved for § 63.670(j).
*
*
*
*
*
(j) * * *
(2) BS EN 14662–4:2005, Ambient air
quality standard method for the
measurement of benzene
concentrations—Part 4: Diffusive
sampling followed by thermal
desorption and gas chromatography,
Published June 27, 2005, IBR approved
for appendix A to this part: Method
325A and Method 325B.
*
*
*
*
*
(m) * * *
(2) EPA–454/B–08–002, Office of Air
Quality Planning and Standards
(OAQPS), Quality Assurance Handbook
for Air Pollution Measurement Systems,
Volume IV: Meteorological
Measurements, Version 2.0 (Final),
March 24, 2008, IBR approved for
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
§ 63.658(d) and appendix A to this part:
Method 325A.
*
*
*
*
*
(4) EPA–454/R–99–005, Office of Air
Quality Planning and Standards
(OAQPS), Meteorological Monitoring
Guidance for Regulatory Modeling
Applications, February 2000, IBR
approved for appendix A to this part:
Method 325A.
*
*
*
*
*
(n) * * *
(3) ISO 16017–2:2003(E): Indoor,
ambient and workplace air—sampling
and analysis of volatile organic
compounds by sorbent tube/thermal
desorption/capillary gas
chromatography—Part 2: Diffusive
sampling, May 15, 2003, IBR approved
for appendix A to this part: Method
325A and Method 325B.
*
*
*
*
*
(s) * * *
(1) ‘‘Air Stripping Method (Modified
El Paso Method) for Determination of
Volatile Organic Compound Emissions
from Water Sources,’’ Revision Number
One, dated January 2003, Sampling
Procedures Manual, Appendix P:
Cooling Tower Monitoring, January 31,
2003, IBR approved for §§ 63.654(c) and
(g), 63.655(i), and 63.11920.
*
*
*
*
*
Subpart Y—National Emission
Standards for Marine Tank Vessel
Loading Operations
12. Section 63.560 is amended by
revising paragraph (a)(4) to read as
follows:
■
§ 63.560 Applicability and designation of
affected source.
(a) * * *
(4) Existing sources with emissions
less than 10 and 25 tons must meet the
submerged fill standards of 46 CFR
153.282.
*
*
*
*
*
Subpart CC—National Emission
Standards for Hazardous Air Pollutants
From Petroleum Refineries
13. Section 63.640 is amended by:
a. Revising paragraphs (a)
introductory text and (c) introductory
text;
■ c. Adding paragraph (c)(9);
■ d. Revising paragraphs (d)(5), (h),
(k)(1), (l) introductory text, (l)(2)
introductory text, (l)(2)(i), (l)(3)
introductory text, (m) introductory text,
(n) introductory text, (n)(1) through (5),
(n)(8) introductory text, and (n)(8)(ii);
■ e. Adding paragraphs (n)(8)(vii) and
(viii);
■ f. Revising paragraph (n)(9)(i);
■
■
PO 00000
Frm 00061
Fmt 4701
Sfmt 4700
75237
g. Adding paragraph (n)(10);
h. Revising paragraph (o)(2)(i)
introductory text;
■ i. Adding paragraph (o)(2)(i)(D);
■ j. Revising paragraph (o)(2)(ii)
introductory text; and
■ k. Adding paragraphs (o)(2)(ii)(C) and
(s).
The revisions and additions read as
follows:
■
■
§ 63.640 Applicability and designation of
affected source.
(a) This subpart applies to petroleum
refining process units and to related
emissions points that are specified in
paragraphs (c)(1) through (9) of this
section that are located at a plant site
and that meet the criteria in paragraphs
(a)(1) and (2) of this section:
*
*
*
*
*
(c) For the purposes of this subpart,
the affected source shall comprise all
emissions points, in combination, listed
in paragraphs (c)(1) through (9) of this
section that are located at a single
refinery plant site.
*
*
*
*
*
(9) All releases associated with the
decoking operations of a delayed coking
unit, as defined in this subpart.
(d) * * *
(5) Emission points routed to a fuel
gas system, as defined in § 63.641,
provided that on and after January 30,
2019, any flares receiving gas from that
fuel gas system are subject to § 63.670.
No other testing, monitoring,
recordkeeping, or reporting is required
for refinery fuel gas systems or emission
points routed to refinery fuel gas
systems.
*
*
*
*
*
(h) Sources subject to this subpart are
required to achieve compliance on or
before the dates specified in table 11 of
this subpart, except as provided in
paragraphs (h)(1) through (3) of this
section.
(1) Marine tank vessels at existing
sources shall be in compliance with this
subpart, except for §§ 63.657 through
63.660, no later than August 18, 1999,
unless the vessels are included in an
emissions average to generate emission
credits. Marine tank vessels used to
generate credits in an emissions average
shall be in compliance with this subpart
no later than August 18, 1998, unless an
extension has been granted by the
Administrator as provided in § 63.6(i).
(2) Existing Group 1 floating roof
storage vessels meeting the applicability
criteria in item 1 of the definition of
Group 1 storage vessel shall be in
compliance with § 63.646 at the first
degassing and cleaning activity after
August 18, 1998, or August 18, 2005,
whichever is first.
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75238
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(3) An owner or operator may elect to
comply with the provisions of
§ 63.648(c) through (i) as an alternative
to the provisions of § 63.648(a) and (b).
In such cases, the owner or operator
shall comply no later than the dates
specified in paragraphs (h)(3)(i) through
(iii) of this section.
(i) Phase I (see table 2 of this subpart),
beginning on August 18, 1998;
(ii) Phase II (see table 2 of this
subpart), beginning no later than August
18, 1999; and
(iii) Phase III (see table 2 of this
subpart), beginning no later than
February 18, 2001.
*
*
*
*
*
(k) * * *
(1) The reconstructed source,
addition, or change shall be in
compliance with the new source
requirements in item (1), (2), or (3) of
table 11 of this subpart, as applicable,
upon initial startup of the reconstructed
source or by August 18, 1995,
whichever is later; and
*
*
*
*
*
(l) If an additional petroleum refining
process unit is added to a plant site or
if a miscellaneous process vent, storage
vessel, gasoline loading rack, marine
tank vessel loading operation, heat
exchange system, or decoking operation
that meets the criteria in paragraphs
(c)(1) through (9) of this section is added
to an existing petroleum refinery or if
another deliberate operational process
change creating an additional Group 1
emissions point(s) (as defined in
§ 63.641) is made to an existing
petroleum refining process unit, and if
the addition or process change is not
subject to the new source requirements
as determined according to paragraph (i)
or (j) of this section, the requirements in
paragraphs (l)(1) through (4) of this
section shall apply. Examples of process
changes include, but are not limited to,
changes in production capacity, or feed
or raw material where the change
requires construction or physical
alteration of the existing equipment or
catalyst type, or whenever there is
replacement, removal, or addition of
recovery equipment. For purposes of
this paragraph (l) and paragraph (m) of
this section, process changes do not
include: Process upsets, unintentional
temporary process changes, and changes
that are within the equipment
configuration and operating conditions
documented in the Notification of
Compliance Status report required by
§ 63.655(f).
*
*
*
*
*
(2) The added emission point(s) and
any emission point(s) within the added
or changed petroleum refining process
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
unit shall be in compliance with the
applicable requirements in item (4) of
table 11 of this subpart by the dates
specified in paragraph (l)(2)(i) or (ii) of
this section.
(i) If a petroleum refining process unit
is added to a plant site or an emission
point(s) is added to any existing
petroleum refining process unit, the
added emission point(s) shall be in
compliance upon initial startup of any
added petroleum refining process unit
or emission point(s) or by the applicable
compliance date in item (4) of table 11
of this subpart, whichever is later.
*
*
*
*
*
(3) The owner or operator of a
petroleum refining process unit or of a
storage vessel, miscellaneous process
vent, wastewater stream, gasoline
loading rack, marine tank vessel loading
operation, heat exchange system, or
decoking operation meeting the criteria
in paragraphs (c)(1) through (9) of this
section that is added to a plant site and
is subject to the requirements for
existing sources shall comply with the
reporting and recordkeeping
requirements that are applicable to
existing sources including, but not
limited to, the reports listed in
paragraphs (l)(3)(i) through (vii) of this
section. A process change to an existing
petroleum refining process unit shall be
subject to the reporting requirements for
existing sources including, but not
limited to, the reports listed in
paragraphs (l)(3)(i) through (vii) of this
section. The applicable reports include,
but are not limited to:
*
*
*
*
*
(m) If a change that does not meet the
criteria in paragraph (l) of this section
is made to a petroleum refining process
unit subject to this subpart, and the
change causes a Group 2 emission point
to become a Group 1 emission point (as
defined in § 63.641), then the owner or
operator shall comply with the
applicable requirements of this subpart
for existing sources, as specified in item
(4) of table 11 of this subpart, for the
Group 1 emission point as expeditiously
as practicable, but in no event later than
3 years after the emission point becomes
Group 1.
*
*
*
*
*
(n) Overlap of this subpart with other
regulations for storage vessels. As
applicable, paragraphs (n)(1), (3), (4),
(6), and (7) of this section apply for
Group 2 storage vessels and paragraphs
(n)(2) and (5) of this section apply for
Group 1 storage vessels.
(1) After the compliance dates
specified in paragraph (h) of this
section, a Group 2 storage vessel that is
subject to the provisions of 40 CFR part
PO 00000
Frm 00062
Fmt 4701
Sfmt 4700
60, subpart Kb, is required to comply
only with the requirements of 40 CFR
part 60, subpart Kb, except as provided
in paragraph (n)(8) of this section. After
the compliance dates specified in
paragraph (h) of this section, a Group 2
storage vessel that is subject to the
provisions of 40 CFR part 61, subpart Y,
is required to comply only with the
requirements of 40 CFR part 61, subpart
Y, except as provided in paragraph
(n)(10) of this section.
(2) After the compliance dates
specified in paragraph (h) of this
section, a Group 1 storage vessel that is
also subject to 40 CFR part 60, subpart
Kb, is required to comply only with
either 40 CFR part 60, subpart Kb,
except as provided in paragraph (n)(8)
of this section or this subpart. After the
compliance dates specified in paragraph
(h) of this section, a Group 1 storage
vessel that is also subject to 40 CFR part
61, subpart Y, is required to comply
only with either 40 CFR part 61, subpart
Y, except as provided in paragraph
(n)(10) of this section or this subpart.
(3) After the compliance dates
specified in paragraph (h) of this
section, a Group 2 storage vessel that is
part of a new source and is subject to
40 CFR 60.110b, but is not required to
apply controls by 40 CFR 60.110b or
60.112b, is required to comply only
with this subpart.
(4) After the compliance dates
specified in paragraph (h) of this
section, a Group 2 storage vessel that is
part of a new source and is subject to
40 CFR 61.270, but is not required to
apply controls by 40 CFR 61.271, is
required to comply only with this
subpart.
(5) After the compliance dates
specified in paragraph (h) of this
section, a Group 1 storage vessel that is
also subject to the provisions of 40 CFR
part 60, subpart K or Ka, is required to
only comply with the provisions of this
subpart.
*
*
*
*
*
(8) Storage vessels described by
paragraph (n)(1) of this section are to
comply with 40 CFR part 60, subpart
Kb, except as provided in paragraphs
(n)(8)(i) through (vi) of this section.
Storage vessels described by paragraph
(n)(2) electing to comply with part 60,
subpart Kb of this chapter shall comply
with subpart Kb except as provided in
paragraphs (n)(8)(i) through (viii) of this
section.
*
*
*
*
*
(ii) If the owner or operator
determines that it is unsafe to perform
the seal gap measurements required in
§ 60.113b(b) of this chapter or to inspect
the vessel to determine compliance with
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
§ 60.113b(a) of this chapter because the
roof appears to be structurally unsound
and poses an imminent danger to
inspecting personnel, the owner or
operator shall comply with the
requirements in either § 63.120(b)(7)(i)
or (ii) of subpart G (only up to the
compliance date specified in paragraph
(h) of this section for compliance with
§ 63.660, as applicable) or either
§ 63.1063(c)(2)(iv)(A) or (B) of subpart
WW.
*
*
*
*
*
(vii) To be in compliance with
§ 60.112b(a)(1)(iv) or (a)(2)(ii) of this
chapter, guidepoles in floating roof
storage vessels must be equipped with
covers and/or controls (e.g., pole float
system, pole sleeve system, internal
sleeve system or flexible enclosure
system) as appropriate to comply with
the ‘‘no visible gap’’ requirement.
(viii) If a flare is used as a control
device for a storage vessel, on and after
January 30, 2019, the owner or operator
must meet the requirements of § 63.670
instead of the requirements referenced
from part 60, subpart Kb of this chapter
for that flare.
(9) * * *
(i) If the owner or operator determines
that it is unsafe to perform the seal gap
measurements required in
§ 60.113a(a)(1) of this chapter because
the floating roof appears to be
structurally unsound and poses an
imminent danger to inspecting
personnel, the owner or operator shall
comply with the requirements in either
§ 63.120(b)(7)(i) or (ii) of subpart G (only
up to the compliance date specified in
paragraph (h) of this section for
compliance with § 63.660, as applicable)
or either § 63.1063(c)(2)(iv)(A) or (B) of
subpart WW.
*
*
*
*
*
(10) Storage vessels described by
paragraph (n)(1) of this section are to
comply with 40 CFR part 61, subpart Y,
except as provided in paragraphs
(n)(10)(i) through (vi) of this section.
Storage vessels described by paragraph
(n)(2) electing to comply with 40 CFR
part 61, subpart Y, shall comply with
subpart Y except as provided for in
paragraphs (n)(10)(i) through (viii) of
this section.
(i) Storage vessels that are to comply
with § 61.271(b) of this chapter are
exempt from the secondary seal
requirements of § 61.271(b)(2)(ii) of this
chapter during the gap measurements
for the primary seal required by
§ 61.272(b) of this chapter.
(ii) If the owner or operator
determines that it is unsafe to perform
the seal gap measurements required in
§ 61.272(b) of this chapter or to inspect
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
the vessel to determine compliance with
§ 61.272(a) of this chapter because the
roof appears to be structurally unsound
and poses an imminent danger to
inspecting personnel, the owner or
operator shall comply with the
requirements in either § 63.120(b)(7)(i)
or (ii) of subpart G (only up to the
compliance date specified in paragraph
(h) of this section for compliance with
§ 63.660, as applicable) or either
§ 63.1063(c)(2)(iv)(A) or (B) of subpart
WW.
(iii) If a failure is detected during the
inspections required by § 61.272(a)(2) of
this chapter or during the seal gap
measurements required by § 61.272(b)(1)
of this chapter, and the vessel cannot be
repaired within 45 days and the vessel
cannot be emptied within 45 days, the
owner or operator may utilize up to two
extensions of up to 30 additional
calendar days each. The owner or
operator is not required to provide a
request for the extension to the
Administrator.
(iv) If an extension is utilized in
accordance with paragraph (n)(10)(iii) of
this section, the owner or operator shall,
in the next periodic report, identify the
vessel, provide the information listed in
§ 61.272(a)(2) or (b)(4)(iii) of this
chapter, and describe the nature and
date of the repair made or provide the
date the storage vessel was emptied.
(v) Owners and operators of storage
vessels complying with 40 CFR part 61,
subpart Y, may submit the inspection
reports required by § 61.275(a), (b)(1),
and (d) of this chapter as part of the
periodic reports required by this
subpart, rather than within the 60-day
period specified in § 61.275(a), (b)(1),
and (d) of this chapter.
(vi) The reports of rim seal
inspections specified in § 61.275(d) of
this chapter are not required if none of
the measured gaps or calculated gap
areas exceed the limitations specified in
§ 61.272(b)(4) of this chapter.
Documentation of the inspections shall
be recorded as specified in § 61.276(a) of
this chapter.
(vii) To be in compliance with
§ 61.271(a)(6) or (b)(3) of this chapter,
guidepoles in floating roof storage
vessels must be equipped with covers
and/or controls (e.g., pole float system,
pole sleeve system, internal sleeve
system or flexible enclosure system) as
appropriate to comply with the ‘‘no
visible gap’’ requirement.
(viii) If a flare is used as a control
device for a storage vessel, on and after
January 30, 2019, the owner or operator
must meet the requirements of § 63.670
instead of the requirements referenced
from part 61, subpart Y of this chapter
for that flare.
PO 00000
Frm 00063
Fmt 4701
Sfmt 4700
75239
(o) * * *
(2) * * *
(i) Comply with paragraphs
(o)(2)(i)(A) through (D) of this section.
*
*
*
*
*
(D) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of 40 CFR part 61, subpart
FF, and subpart G of this part, or the
requirements of § 63.670.
(ii) Comply with paragraphs
(o)(2)(ii)(A) through (C) of this section.
*
*
*
*
*
(C) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of 40 CFR part 61, subpart
FF, and subpart G of this part, or the
requirements of § 63.670.
*
*
*
*
*
(s) Overlap of this subpart with other
regulation for flares. On January 30,
2019, flares that are subject to the
provisions of 40 CFR 60.18 or 63.11 and
subject to this subpart are required to
comply only with the provisions
specified in this subpart. Prior to
January 30, 2019, flares that are subject
to the provisions of 40 CFR 60.18 or
63.11 and elect to comply with the
requirements in §§ 63.670 and 63.671
are required to comply only with the
provisions specified in this subpart.
■ 14. Section 63.641 is amended by:
■ a. Adding, in alphabetical order,
definitions of ‘‘Assist air,’’ ‘‘Assist
steam,’’ ‘‘Center steam,’’ ‘‘Closed
blowdown system,’’ ‘‘Combustion
zone,’’ ‘‘Combustion zone gas,’’
‘‘Decoking operations,’’ ‘‘Delayed coking
unit,’’ ‘‘Flare,’’ ‘‘Flare purge gas,’’ ‘‘Flare
supplemental gas,’’ ‘‘Flare sweep gas,’’
‘‘Flare vent gas,’’ ‘‘Flexible enclosure
device,’’ ‘‘Force majeure event,’’ ‘‘Lower
steam,’’ ‘‘Net heating value,’’ ‘‘Perimeter
assist air,’’ ‘‘Pilot gas,’’ ‘‘Premix assist
air,’’ ‘‘Regulated material,’’ ‘‘Thermal
expansion relief valve,’’ ‘‘Total steam,’’
and ‘‘Upper steam’’; and
■ b. Revising the definitions of
‘‘Delayed coker vent,’’ ‘‘Emission
point,’’ ‘‘Group 1 storage vessel,’’
‘‘Miscellaneous process vent,’’
‘‘Periodically discharged,’’ and
‘‘Reference control technology for
storage vessels.’’
The revisions and additions read as
follows:
§ 63.641
Definitions.
*
*
*
*
*
Assist air means all air that
intentionally is introduced prior to or at
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75240
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
a flare tip through nozzles or other
hardware conveyance for the purposes
including, but not limited to, protecting
the design of the flare tip, promoting
turbulence for mixing or inducing air
into the flame. Assist air includes
premix assist air and perimeter assist
air. Assist air does not include the
surrounding ambient air.
Assist steam means all steam that
intentionally is introduced prior to or at
a flare tip through nozzles or other
hardware conveyance for the purposes
including, but not limited to, protecting
the design of the flare tip, promoting
turbulence for mixing or inducing air
into the flame. Assist steam includes,
but is not necessarily limited to, center
steam, lower steam and upper steam.
*
*
*
*
*
Center steam means the portion of
assist steam introduced into the stack of
a flare to reduce burnback.
Closed blowdown system means a
system used for depressuring process
vessels that is not open to the
atmosphere and is configured of piping,
ductwork, connections, accumulators/
knockout drums, and, if necessary, flow
inducing devices that transport gas or
vapor from process vessel to a control
device or back into the process.
*
*
*
*
*
Combustion zone means the area of
the flare flame where the combustion
zone gas combines for combustion.
Combustion zone gas means all gases
and vapors found just after a flare tip.
This gas includes all flare vent gas, total
steam, and premix air.
*
*
*
*
*
Decoking operations means the
sequence of steps conducted at the end
of the delayed coking unit’s cooling
cycle to open the coke drum to the
atmosphere in order to remove coke
from the coke drum. Decoking
operations begin at the end of the
cooling cycle when steam released from
the coke drum is no longer discharged
via the unit’s blowdown system but
instead is vented directly to the
atmosphere. Decoking operations
include atmospheric depressuring
(venting), deheading, draining, and
decoking (coke cutting).
Delayed coker vent means a
miscellaneous process vent that
contains uncondensed vapors from the
delayed coking unit’s blowdown
system. Venting from the delayed coker
vent is typically intermittent in nature,
and occurs primarily during the cooling
cycle of a delayed coking unit coke
drum when vapor from the coke drums
cannot be sent to the fractionator
column for product recovery. The
emissions from the decoking operations,
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
which include direct atmospheric
venting, deheading, draining, or
decoking (coke cutting), are not
considered to be delayed coker vents.
Delayed coking unit means a refinery
process unit in which high molecular
weight petroleum derivatives are
thermally cracked and petroleum coke
is produced in a series of closed, batch
system reactors. A delayed coking unit
includes, but is not limited to, all of the
coke drums associated with a single
fractionator; the fractionator, including
the bottoms receiver and the overhead
condenser; the coke drum cutting water
and quench system, including the jet
pump and coker quench water tank; and
the coke drum blowdown recovery
compressor system.
*
*
*
*
*
Emission point means an individual
miscellaneous process vent, storage
vessel, wastewater stream, equipment
leak, decoking operation or heat
exchange system associated with a
petroleum refining process unit; an
individual storage vessel or equipment
leak associated with a bulk gasoline
terminal or pipeline breakout station
classified under Standard Industrial
Classification code 2911; a gasoline
loading rack classified under Standard
Industrial Classification code 2911; or a
marine tank vessel loading operation
located at a petroleum refinery.
*
*
*
*
*
Flare means a combustion device
lacking an enclosed combustion
chamber that uses an uncontrolled
volume of ambient air to burn gases. For
the purposes of this rule, the definition
of flare includes, but is not necessarily
limited to, air-assisted flares, steamassisted flares and non-assisted flares.
Flare purge gas means gas introduced
between a flare header’s water seal and
the flare tip to prevent oxygen
infiltration (backflow) into the flare tip.
For a flare with no water seal, the
function of flare purge gas is performed
by flare sweep gas and, therefore, by
definition, such a flare has no flare
purge gas.
Flare supplemental gas means all gas
introduced to the flare in order to
improve the combustible characteristics
of combustion zone gas.
Flare sweep gas means, for a flare
with a flare gas recovery system, the gas
intentionally introduced into the flare
header system to maintain a constant
flow of gas through the flare header in
order to prevent oxygen buildup in the
flare header; flare sweep gas in these
flares is introduced prior to and
recovered by the flare gas recovery
system. For a flare without a flare gas
recovery system, flare sweep gas means
PO 00000
Frm 00064
Fmt 4701
Sfmt 4700
the gas intentionally introduced into the
flare header system to maintain a
constant flow of gas through the flare
header and out the flare tip in order to
prevent oxygen buildup in the flare
header and to prevent oxygen
infiltration (backflow) into the flare tip.
Flare vent gas means all gas found just
prior to the flare tip. This gas includes
all flare waste gas (i.e., gas from facility
operations that is directed to a flare for
the purpose of disposing of the gas), that
portion of flare sweep gas that is not
recovered, flare purge gas and flare
supplemental gas, but does not include
pilot gas, total steam or assist air.
Flexible enclosure device means a seal
made of an elastomeric fabric (or other
material) which completely encloses a
slotted guidepole or ladder and
eliminates the vapor emission pathway
from inside the storage vessel through
the guidepole slots or ladder slots to the
outside air.
*
*
*
*
*
Force majeure event means a release
of HAP, either directly to the
atmosphere from a relief valve or
discharged via a flare, that is
demonstrated to the satisfaction of the
Administrator to result from an event
beyond the refinery owner or operator’s
control, such as natural disasters; acts of
war or terrorism; loss of a utility
external to the refinery (e.g., external
power curtailment), excluding power
curtailment due to an interruptible
service agreement; and fire or explosion
originating at a near or adjoining facility
outside of the refinery owner or
operator’s control that impacts the
refinery’s ability to operate.
*
*
*
*
*
Group 1 storage vessel means:
(1) Prior to February 1, 2016:
(i) A storage vessel at an existing
source that has a design capacity greater
than or equal to 177 cubic meters and
stored-liquid maximum true vapor
pressure greater than or equal to 10.4
kilopascals and stored-liquid annual
average true vapor pressure greater than
or equal to 8.3 kilopascals and annual
average HAP liquid concentration
greater than 4 percent by weight total
organic HAP;
(ii) A storage vessel at a new source
that has a design storage capacity greater
than or equal to 151 cubic meters and
stored-liquid maximum true vapor
pressure greater than or equal to 3.4
kilopascals and annual average HAP
liquid concentration greater than 2
percent by weight total organic HAP; or
(iii) A storage vessel at a new source
that has a design storage capacity greater
than or equal to 76 cubic meters and
less than 151 cubic meters and stored-
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
liquid maximum true vapor pressure
greater than or equal to 77 kilopascals
and annual average HAP liquid
concentration greater than 2 percent by
weight total organic HAP.
(2) On and after February 1, 2016:
(i) A storage vessel at an existing
source that has a design capacity greater
than or equal to 151 cubic meters
(40,000 gallons) and stored-liquid
maximum true vapor pressure greater
than or equal to 5.2 kilopascals (0.75
pounds per square inch) and annual
average HAP liquid concentration
greater than 4 percent by weight total
organic HAP;
(ii) A storage vessel at an existing
source that has a design storage capacity
greater than or equal to 76 cubic meters
(20,000 gallons) and less than 151 cubic
meters (40,000 gallons) and storedliquid maximum true vapor pressure
greater than or equal to 13.1 kilopascals
(1.9 pounds per square inch) and annual
average HAP liquid concentration
greater than 4 percent by weight total
organic HAP;
(iii) A storage vessel at a new source
that has a design storage capacity greater
than or equal to 151 cubic meters
(40,000 gallons) and stored-liquid
maximum true vapor pressure greater
than or equal to 3.4 kilopascals (0.5
pounds per square inch) and annual
average HAP liquid concentration
greater than 2 percent by weight total
organic HAP; or
(iv) A storage vessel at a new source
that has a design storage capacity greater
than or equal to 76 cubic meters (20,000
gallons) and less than 151 cubic meters
(40,000 gallons) and stored-liquid
maximum true vapor pressure greater
than or equal to 13.1 kilopascals (1.9
pounds per square inch) and annual
average HAP liquid concentration
greater than 2 percent by weight total
organic HAP.
*
*
*
*
*
Lower steam means the portion of
assist steam piped to an exterior annular
ring near the lower part of a flare tip,
which then flows through tubes to the
flare tip, and ultimately exits the tubes
at the flare tip.
*
*
*
*
*
Miscellaneous process vent means a
gas stream containing greater than 20
parts per million by volume organic
HAP that is continuously or periodically
discharged from a petroleum refining
process unit meeting the criteria
specified in § 63.640(a). Miscellaneous
process vents include gas streams that
are discharged directly to the
atmosphere, gas streams that are routed
to a control device prior to discharge to
the atmosphere, or gas streams that are
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
diverted through a product recovery
device prior to control or discharge to
the atmosphere. Miscellaneous process
vents include vent streams from: Caustic
wash accumulators, distillation tower
condensers/accumulators, flash/
knockout drums, reactor vessels,
scrubber overheads, stripper overheads,
vacuum pumps, steam ejectors, hot
wells, high point bleeds, wash tower
overheads, water wash accumulators,
blowdown condensers/accumulators,
and delayed coker vents. Miscellaneous
process vents do not include:
(1) Gaseous streams routed to a fuel
gas system, provided that on and after
January 30, 2019, any flares receiving
gas from the fuel gas system are in
compliance with § 63.670;
(2) Pressure relief device discharges;
(3) Leaks from equipment regulated
under § 63.648;
(4) [Reserved]
(5) In situ sampling systems (onstream
analyzers) until January 30, 2019. After
this date, these sampling systems will
be included in the definition of
miscellaneous process vents;
(6) Catalytic cracking unit catalyst
regeneration vents;
(7) Catalytic reformer regeneration
vents;
(8) Sulfur plant vents;
(9) Vents from control devices such as
scrubbers, boilers, incinerators, and
electrostatic precipitators applied to
catalytic cracking unit catalyst
regeneration vents, catalytic reformer
regeneration vents, and sulfur plant
vents;
(10) Vents from any stripping
operations applied to comply with the
wastewater provisions of this subpart,
subpart G of this part, or 40 CFR part 61,
subpart FF;
(11) Emissions associated with
delayed coking unit decoking
operations;
(12) Vents from storage vessels;
(13) Emissions from wastewater
collection and conveyance systems
including, but not limited to,
wastewater drains, sewer vents, and
sump drains; and
(14) Hydrogen production plant vents
through which carbon dioxide is
removed from process streams or
through which steam condensate
produced or treated within the
hydrogen plant is degassed or deaerated.
Net heating value means the energy
released as heat when a compound
undergoes complete combustion with
oxygen to form gaseous carbon dioxide
and gaseous water (also referred to as
lower heating value).
*
*
*
*
*
Perimeter assist air means the portion
of assist air introduced at the perimeter
PO 00000
Frm 00065
Fmt 4701
Sfmt 4700
75241
of the flare tip or above the flare tip.
Perimeter assist air includes air
intentionally entrained in lower and
upper steam. Perimeter assist air
includes all assist air except premix
assist air.
Periodically discharged means
discharges that are intermittent and
associated with routine operations,
maintenance activities, startups,
shutdowns, malfunctions, or process
upsets.
*
*
*
*
*
Pilot gas means gas introduced into a
flare tip that provides a flame to ignite
the flare vent gas.
*
*
*
*
*
Premix assist air means the portion of
assist air that is introduced to the flare
vent gas, whether injected or induced,
prior to the flare tip. Premix assist air
also includes any air intentionally
entrained in center steam.
*
*
*
*
*
Reference control technology for
storage vessels means either:
(1) For Group 1 storage vessels
complying with § 63.660:
(i) An internal floating roof, including
an external floating roof converted to an
internal floating roof, meeting the
specifications of § 63.1063(a)(1)(i) and
(b);
(ii) An external floating roof meeting
the specifications of § 63.1063(a)(1)(ii),
(a)(2), and (b); or
(iii) [Reserved]
(iv) A closed-vent system to a control
device that reduces organic HAP
emissions by 95 percent, or to an outlet
concentration of 20 parts per million by
volume (ppmv).
(v) For purposes of emissions
averaging, these four technologies are
considered equivalent.
(2) For all other storage vessels:
(i) An internal floating roof meeting
the specifications of § 63.119(b) of
subpart G except for § 63.119(b)(5) and
(6);
(ii) An external floating roof meeting
the specifications of § 63.119(c) of
subpart G except for § 63.119(c)(2);
(iii) An external floating roof
converted to an internal floating roof
meeting the specifications of § 63.119(d)
of subpart G except for § 63.119(d)(2); or
(iv) A closed-vent system to a control
device that reduces organic HAP
emissions by 95 percent, or to an outlet
concentration of 20 parts per million by
volume.
(v) For purposes of emissions
averaging, these four technologies are
considered equivalent.
*
*
*
*
*
Regulated material means any stream
associated with emission sources listed
E:\FR\FM\01DER2.SGM
01DER2
75242
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
in § 63.640(c) required to meet control
requirements under this subpart as well
as any stream for which this subpart or
a cross-referencing subpart specifies that
the requirements for flare control
devices in § 63.670 must be met.
*
*
*
*
*
Thermal expansion relief valve means
a pressure relief valve designed to
protect equipment from excess pressure
due to thermal expansion of blocked
liquid-filled equipment or piping due to
ambient heating or heat from a heat
tracing system. Pressure relief valves
designed to protect equipment from
excess pressure due to blockage against
a pump or compressor or due to fire
contingency are not thermal expansion
relief valves.
*
*
*
*
*
Total steam means the total of all
steam that is supplied to a flare and
includes, but is not limited to, lower
steam, center steam and upper steam.
Upper steam means the portion of
assist steam introduced via nozzles
located on the exterior perimeter of the
upper end of the flare tip.
*
*
*
*
*
■ 15. Section 63.642 is amended by:
■ a. Adding paragraph (b);
■ b. Revising paragraphs (d)(3), (e), (i),
(k) introductory text, (k)(1), (l)
introductory text, and (l)(2); and
■ c. Adding paragraph (n).
The revisions and additions read as
follows:
§ 63.642
General standards.
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
(b) The emission standards set forth in
this subpart shall apply at all times.
*
*
*
*
*
(d) * * *
(3) Performance tests shall be
conducted according to the provisions
of § 63.7(e) except that performance
tests shall be conducted at maximum
representative operating capacity for the
process. During the performance test, an
owner or operator shall operate the
control device at either maximum or
minimum representative operating
conditions for monitored control device
parameters, whichever results in lower
emission reduction. An owner or
operator shall not conduct a
performance test during startup,
shutdown, periods when the control
device is bypassed or periods when the
process, monitoring equipment or
control device is not operating properly.
The owner/operator may not conduct
performance tests during periods of
malfunction. The owner or operator
must record the process information
that is necessary to document operating
conditions during the test and include
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
in such record an explanation to
support that the test was conducted at
maximum representative operating
capacity. Upon request, the owner or
operator shall make available to the
Administrator such records as may be
necessary to determine the conditions of
performance tests.
*
*
*
*
*
(e) All applicable records shall be
maintained as specified in § 63.655(i).
*
*
*
*
*
(i) The owner or operator of an
existing source shall demonstrate
compliance with the emission standard
in paragraph (g) of this section by
following the procedures specified in
paragraph (k) of this section for all
emission points, or by following the
emissions averaging compliance
approach specified in paragraph (l) of
this section for specified emission
points and the procedures specified in
paragraph (k)(1) of this section.
*
*
*
*
*
(k) The owner or operator of an
existing source may comply, and the
owner or operator of a new source shall
comply, with the applicable provisions
in §§ 63.643 through 63.645, 63.646 or
63.660, 63.647, 63.650, and 63.651, as
specified in § 63.640(h).
(1) The owner or operator using this
compliance approach shall also comply
with the requirements of §§ 63.648 and/
or 63.649, 63.654, 63.655, 63.657,
63.658, 63.670 and 63.671, as
applicable.
*
*
*
*
*
(l) The owner or operator of an
existing source may elect to control
some of the emission points within the
source to different levels than specified
under §§ 63.643 through 63.645, 63.646
or 63.660, 63.647, 63.650, and 63.651, as
applicable according to § 63.640(h), by
using an emissions averaging
compliance approach as long as the
overall emissions for the source do not
exceed the emission level specified in
paragraph (g) of this section. The owner
or operator using emissions averaging
shall meet the requirements in
paragraphs (l)(1) and (2) of this section.
*
*
*
*
*
(2) Comply with the requirements of
§§ 63.648 and/or 63.649, 63.654, 63.652,
63.653, 63.655, 63.657, 63.658, 63.670
and 63.671, as applicable.
*
*
*
*
*
(n) At all times, the owner or operator
must operate and maintain any affected
source, including associated air
pollution control equipment and
monitoring equipment, in a manner
consistent with safety and good air
pollution control practices for
PO 00000
Frm 00066
Fmt 4701
Sfmt 4700
minimizing emissions. The general duty
to minimize emissions does not require
the owner operator to make any further
efforts to reduce emissions if levels
required by the applicable standard
have been achieved. Determination of
whether a source is operating in
compliance with operation and
maintenance requirements will be based
on information available to the
Administrator which may include, but
is not limited to, monitoring results,
review of operation and maintenance
procedures, review of operation and
maintenance records, and inspection of
the source.
■ 16. Section 63.643 is amended by
revising paragraphs (a) introductory text
and (a)(1) and adding paragraph (c) to
read as follows:
§ 63.643 Miscellaneous process vent
provisions.
(a) The owner or operator of a Group
1 miscellaneous process vent as defined
in § 63.641 shall comply with the
requirements of either paragraph (a)(1)
or (2) of this section or, if applicable,
paragraph (c) of this section. The owner
or operator of a miscellaneous process
vent that meets the conditions in
paragraph (c) of this section is only
required to comply with the
requirements of paragraph (c) of this
section and § 63.655(g)(13) and (i)(12)
for that vent.
(1) Reduce emissions of organic
HAP’s using a flare. On and after
January 30, 2019, the flare shall meet
the requirements of § 63.670. Prior to
January 30, 2019, the flare shall meet
the requirements of § 63.11(b) of subpart
A or the requirements of § 63.670.
*
*
*
*
*
(c) An owner or operator may
designate a process vent as a
maintenance vent if the vent is only
used as a result of startup, shutdown,
maintenance, or inspection of
equipment where equipment is emptied,
depressurized, degassed or placed into
service. The owner of operator does not
need to designate a maintenance vent as
a Group 1 or Group 2 miscellaneous
process vent. The owner or operator
must comply with the applicable
requirements in paragraphs (c)(1)
through (3) of this section for each
maintenance vent.
(1) Prior to venting to the atmosphere,
process liquids are removed from the
equipment as much as practical and the
equipment is depressured to a control
device, fuel gas system, or back to the
process until one of the following
conditions, as applicable, is met.
(i) The vapor in the equipment served
by the maintenance vent has a lower
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
explosive limit (LEL) of less than 10
percent.
(ii) If there is no ability to measure the
LEL of the vapor in the equipment based
on the design of the equipment, the
pressure in the equipment served by the
maintenance vent is reduced to 5 psig
or less. Upon opening the maintenance
vent, active purging of the equipment
cannot be used until the LEL of the
vapors in the maintenance vent (or
inside the equipment if the maintenance
is a hatch or similar type of opening)
equipment is less than 10 percent.
(iii) The equipment served by the
maintenance vent contains less than 72
pounds of VOC.
(iv) If the maintenance vent is
associated with equipment containing
pyrophoric catalyst (e.g., hydrotreaters
and hydrocrackers) at refineries that do
not have a pure hydrogen supply, the
LEL of the vapor in the equipment must
be less than 20 percent, except for one
event per year not to exceed 35 percent.
(2) Except for maintenance vents
complying with the alternative in
paragraph (c)(1)(iii) of this section, the
owner or operator must determine the
LEL or, if applicable, equipment
pressure using process instrumentation
or portable measurement devices and
follow procedures for calibration and
maintenance according to
manufacturer’s specifications.
(3) For maintenance vents complying
with the alternative in paragraph
(c)(1)(iii) of this section, the owner or
operator shall determine mass of VOC in
the equipment served by the
maintenance vent based on the
equipment size and contents after
considering any contents drained or
purged from the equipment. Equipment
size may be determined from equipment
design specifications. Equipment
contents may be determined using
process knowledge.
■ 17. Section 63.644 is amended by
revising paragraphs (a) introductory
text, (a)(2), and (c) to read as follows:
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.644 Monitoring provisions for
miscellaneous process vents.
(a) Except as provided in paragraph
(b) of this section, each owner or
operator of a Group 1 miscellaneous
process vent that uses a combustion
device to comply with the requirements
in § 63.643(a) shall install the
monitoring equipment specified in
paragraph (a)(1), (2), (3), or (4) of this
section, depending on the type of
combustion device used. All monitoring
equipment shall be installed, calibrated,
maintained, and operated according to
manufacturer’s specifications or other
written procedures that provide
adequate assurance that the equipment
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
will monitor accurately and, except for
CPMS installed for pilot flame
monitoring, must meet the applicable
minimum accuracy, calibration and
quality control requirements specified
in table 13 of this subpart.
*
*
*
*
*
(2) Where a flare is used prior to
January 30, 2019, a device (including
but not limited to a thermocouple, an
ultraviolet beam sensor, or an infrared
sensor) capable of continuously
detecting the presence of a pilot flame
is required, or the requirements of
§ 63.670 shall be met. Where a flare is
used on and after January 30, 2019, the
requirements of § 63.670 shall be met.
*
*
*
*
*
(c) The owner or operator of a Group
1 miscellaneous process vent using a
vent system that contains bypass lines
that could divert a vent stream away
from the control device used to comply
with paragraph (a) of this section either
directly to the atmosphere or to a
control device that does not comply
with the requirements in § 63.643(a)
shall comply with either paragraph
(c)(1) or (2) of this section. Use of the
bypass at any time to divert a Group 1
miscellaneous process vent stream to
the atmosphere or to a control device
that does not comply with the
requirements in § 63.643(a) is an
emissions standards violation.
Equipment such as low leg drains and
equipment subject to § 63.648 are not
subject to this paragraph (c).
(1) Install, calibrate and maintain a
flow indicator that determines whether
a vent stream flow is present at least
once every hour. A manual block valve
equipped with a valve position
indicator may be used in lieu of a flow
indicator, as long as the valve position
indicator is monitored continuously.
Records shall be generated as specified
in § 63.655(h) and (i). The flow indicator
shall be installed at the entrance to any
bypass line that could divert the vent
stream away from the control device to
the atmosphere; or
(2) Secure the bypass line valve in the
non-diverting position with a car-seal or
a lock-and-key type configuration. A
visual inspection of the seal or closure
mechanism shall be performed at least
once every month to ensure that the
valve is maintained in the non-diverting
position and that the vent stream is not
diverted through the bypass line.
*
*
*
*
*
18. Section 63.645 is amended by
revising paragraphs (e)(1) and (f)(2) to
read as follows:
■
PO 00000
Frm 00067
Fmt 4701
Sfmt 4700
75243
§ 63.645 Test methods and procedures for
miscellaneous process vents.
*
*
*
*
*
(e) * * *
(1) Methods 1 or 1A of 40 CFR part
60, appendix A–1, as appropriate, shall
be used for selection of the sampling
site. For vents smaller than 0.10 meter
in diameter, sample at the center of the
vent.
*
*
*
*
*
(f) * * *
(2) The gas volumetric flow rate shall
be determined using Methods 2, 2A, 2C,
2D, or 2F of 40 CFR part 60, appendix
A–1 or Method 2G of 40 CFR part 60,
appendix A–2, as appropriate.
*
*
*
*
*
■ 19. Section 63.646 is amended by
adding introductory text and revising
paragraph (b)(2) to read as follows:
§ 63.646
Storage vessel provisions.
Upon a demonstration of compliance
with the standards in § 63.660 by the
compliance dates specified in
§ 63.640(h), the standards in this section
shall no longer apply.
*
*
*
*
*
(b) * * *
(2) When an owner or operator and
the Administrator do not agree on
whether the annual average weight
percent organic HAP in the stored liquid
is above or below 4 percent for a storage
vessel at an existing source or above or
below 2 percent for a storage vessel at
a new source, an appropriate method
(based on the type of liquid stored) as
published by EPA or a consensus-based
standards organization shall be used.
Consensus-based standards
organizations include, but are not
limited to, the following: ASTM
International (100 Barr Harbor Drive,
P.O. Box CB700, West Conshohocken,
Pennsylvania 19428–B2959, (800) 262–
1373, https://www.astm.org), the
American National Standards Institute
(ANSI, 1819 L Street NW., 6th floor,
Washington, DC 20036, (202) 293–8020,
https://www.ansi.org), the American Gas
Association (AGA, 400 North Capitol
Street NW., 4th Floor, Washington, DC
20001, (202) 824–7000, https://
www.aga.org), the American Society of
Mechanical Engineers (ASME, Three
Park Avenue, New York, NY 10016–
5990, (800) 843–2763, https://
www.asme.org), the American
Petroleum Institute (API, 1220 L Street
NW., Washington, DC 20005–4070,
(202) 682–8000, https://www.api.org),
and the North American Energy
Standards Board (NAESB, 801 Travis
Street, Suite 1675, Houston, TX 77002,
(713) 356–0060, https://www.naesb.org).
*
*
*
*
*
E:\FR\FM\01DER2.SGM
01DER2
75244
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
20. Section 63.647 is amended by:
a. Revising paragraph (a);
b. Redesignating paragraph (c) as
paragraph (d); and
■ c. Adding paragraph (c).
The revisions and additions read as
follows:
■
■
■
§ 63.647
Wastewater provisions.
(a) Except as provided in paragraphs
(b) and (c) of this section, each owner
or operator of a Group 1 wastewater
stream shall comply with the
requirements of §§ 61.340 through
61.355 of this chapter for each process
wastewater stream that meets the
definition in § 63.641.
*
*
*
*
*
(c) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of part 61, subpart FF of
this chapter, or the requirements of
§ 63.670.
*
*
*
*
*
■ 21. Section 63.648 is amended by:
■ a. Adding paragraph (a)(3);
■ b. Revising paragraph (c) introductory
text; and
■ c. Adding paragraphs (c)(11) and (12)
and (j).
The revisions and additions read as
follows:
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.648
Equipment leak standards.
(a) * * *
(3) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of part 60, subpart VV of
this chapter, or the requirements of
§ 63.670.
*
*
*
*
*
(c) In lieu of complying with the
existing source provisions of paragraph
(a) in this section, an owner or operator
may elect to comply with the
requirements of §§ 63.161 through
63.169, 63.171, 63.172, 63.175, 63.176,
63.177, 63.179, and 63.180 of subpart H
except as provided in paragraphs (c)(1)
through (12) and (e) through (i) of this
section.
*
*
*
*
*
(11) [Reserved]
(12) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of §§ 63.172 and 63.180, or
the requirements of § 63.670.
*
*
*
*
*
(j) Except as specified in paragraph
(j)(4) of this section, the owner or
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
operator must comply with the
requirements specified in paragraphs
(j)(1) and (2) of this section for pressure
relief devices, such as relief valves or
rupture disks, in organic HAP gas or
vapor service instead of the pressure
relief device requirements of § 60.482–4
or § 63.165, as applicable. Except as
specified in paragraphs (j)(4) and (5) of
this section, the owner or operator must
also comply with the requirements
specified in paragraph (j)(3) of this
section for all pressure relief devices.
(1) Operating requirements. Except
during a pressure release, operate each
pressure relief device in organic HAP
gas or vapor service with an instrument
reading of less than 500 ppm above
background as detected by Method 21 of
40 CFR part 60, appendix A–7.
(2) Pressure release requirements. For
pressure relief devices in organic HAP
gas or vapor service, the owner or
operator must comply with the
applicable requirements in paragraphs
(j)(2)(i) through (iii) of this section
following a pressure release.
(i) If the pressure relief device does
not consist of or include a rupture disk,
conduct instrument monitoring, as
specified in § 60.485(b) or § 63.180(c), as
applicable, no later than 5 calendar days
after the pressure relief device returns to
organic HAP gas or vapor service
following a pressure release to verify
that the pressure relief device is
operating with an instrument reading of
less than 500 ppm.
(ii) If the pressure relief device
includes a rupture disk, either comply
with the requirements in paragraph
(j)(2)(i) of this section (not replacing the
rupture disk) or install a replacement
disk as soon as practicable after a
pressure release, but no later than 5
calendar days after the pressure release.
The owner or operator must conduct
instrument monitoring, as specified in
§ 60.485(b) or § 63.180(c), as applicable,
no later than 5 calendar days after the
pressure relief device returns to organic
HAP gas or vapor service following a
pressure release to verify that the
pressure relief device is operating with
an instrument reading of less than 500
ppm.
(iii) If the pressure relief device
consists only of a rupture disk, install a
replacement disk as soon as practicable
after a pressure release, but no later than
5 calendar days after the pressure
release. The owner or operator may not
initiate startup of the equipment served
by the rupture disk until the rupture
disc is replaced. The owner or operator
must conduct instrument monitoring, as
specified in § 60.485(b) or § 63.180(c), as
applicable, no later than 5 calendar days
after the pressure relief device returns to
PO 00000
Frm 00068
Fmt 4701
Sfmt 4700
organic HAP gas or vapor service
following a pressure release to verify
that the pressure relief device is
operating with an instrument reading of
less than 500 ppm.
(3) Pressure release management.
Except as specified in paragraphs (j)(4)
and (5) of this section, the owner or
operator shall comply with the
requirements specified in paragraphs
(j)(3)(i) through (v) of this section for all
pressure relief devices in organic HAP
service no later than January 30, 2019.
(i) The owner or operator must equip
each affected pressure relief device with
a device(s) or use a monitoring system
that is capable of:
(A) Identifying the pressure release;
(B) Recording the time and duration
of each pressure release; and
(C) Notifying operators immediately
that a pressure release is occurring. The
device or monitoring system may be
either specific to the pressure relief
device itself or may be associated with
the process system or piping, sufficient
to indicate a pressure release to the
atmosphere. Examples of these types of
devices and systems include, but are not
limited to, a rupture disk indicator,
magnetic sensor, motion detector on the
pressure relief valve stem, flow monitor,
or pressure monitor.
(ii) The owner or operator must apply
at least three redundant prevention
measures to each affected pressure relief
device and document these measures.
Examples of prevention measures
include:
(A) Flow, temperature, level and
pressure indicators with deadman
switches, monitors, or automatic
actuators.
(B) Documented routine inspection
and maintenance programs and/or
operator training (maintenance
programs and operator training may
count as only one redundant prevention
measure).
(C) Inherently safer designs or safety
instrumentation systems.
(D) Deluge systems.
(E) Staged relief system where initial
pressure relief valve (with lower set
release pressure) discharges to a flare or
other closed vent system and control
device.
(iii) If any affected pressure relief
device releases to atmosphere as a result
of a pressure release event, the owner or
operator must perform root cause
analysis and corrective action analysis
according to the requirement in
paragraph (j)(6) of this section and
implement corrective actions according
to the requirements in paragraph (j)(7) of
this section. The owner or operator must
also calculate the quantity of organic
HAP released during each pressure
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
release event and report this quantity as
required in § 63.655(g)(10)(iii).
Calculations may be based on data from
the pressure relief device monitoring
alone or in combination with process
parameter monitoring data and process
knowledge.
(iv) The owner or operator shall
determine the total number of release
events occurred during the calendar
year for each affected pressure relief
device separately. The owner or
operator shall also determine the total
number of release events for each
pressure relief device for which the root
cause analysis concluded that the root
cause was a force majeureevent, as
defined in this subpart.
(v) Except for pressure relief devices
described in paragraphs (j)(4) and (5) of
this section, the following release events
are a violation of the pressure release
management work practice standards.
(A) Any release event for which the
root cause of the event was determined
to be operator error or poor
maintenance.
(B) A second release event not
including force majeure events from a
single pressure relief device in a 3
calendar year period for the same root
cause for the same equipment.
(C) A third release event not including
force majeure events from a single
pressure relief device in a 3 calendar
year period for any reason.
(4) Pressure relief devices routed to a
control device. If all releases and
potential leaks from a pressure relief
device are routed through a closed vent
system to a control device, back into the
process or to the fuel gas system, the
owner or operator is not required to
comply with paragraph (j)(1), (2), or (3)
(if applicable) of this section. Both the
closed vent system and control device
(if applicable) must meet the
requirements of § 63.644. When
complying with this paragraph (j)(4), all
references to ‘‘Group 1 miscellaneous
process vent’’ in § 63.644 mean
‘‘pressure relief device.’’ If a pressure
relief device complying with this
paragraph (j)(4) is routed to the fuel gas
system, then on and after January 30,
2019, any flares receiving gas from that
fuel gas system must be in compliance
with § 63.670.
(5) Pressure relief devices exempted
from pressure release management
requirements. The following types of
pressure relief devices are not subject to
the pressure release management
requirements in paragraph (j)(3) of this
section.
(i) Pressure relief devices in heavy
liquid service, as defined in § 63.641.
(ii) Pressure relief devices that only
release material that is liquid at
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
standard conditions (1 atmosphere and
68 degrees Fahrenheit) and that are
hard-piped to a controlled drain system
(i.e., a drain system meeting the
requirements for Group 1 wastewater
streams in § 63.647(a)) or piped back to
the process or pipeline.
(iii) Thermal expansion relief valves.
(iv) Pressure relief devices designed
with a set relief pressure of less than 2.5
psig.
(v) Pressure relief devices that do not
have the potential to emit 72 lbs/day or
more of VOC based on the valve
diameter, the set release pressure, and
the equipment contents.
(vi) Pressure relief devices on mobile
equipment.
(6) Root cause analysis and corrective
action analysis. A root cause analysis
and corrective action analysis must be
completed as soon as possible, but no
later than 45 days after a release event.
Special circumstances affecting the
number of root cause analyses and/or
corrective action analyses are provided
in paragraphs (j)(6)(i) through (iv) of this
section.
(i) You may conduct a single root
cause analysis and corrective action
analysis for a single emergency event
that causes two or more pressure relief
devices installed on the same
equipment to release.
(ii) You may conduct a single root
cause analysis and corrective action
analysis for a single emergency event
that causes two or more pressure relief
devices to release, regardless of the
equipment served, if the root cause is
reasonably expected to be a force
majeure event, as defined in this
subpart.
(iii) Except as provided in paragraphs
(j)(6)(i) and (ii) of this section, if more
than one pressure relief device has a
release during the same time period, an
initial root cause analysis shall be
conducted separately for each pressure
relief device that had a release. If the
initial root cause analysis indicates that
the release events have the same root
cause(s), the initially separate root cause
analyses may be recorded as a single
root cause analysis and a single
corrective action analysis may be
conducted.
(7) Corrective action implementation.
Each owner or operator required to
conduct a root cause analysis and
corrective action analysis as specified in
paragraphs (j)(3)(iii) and (j)(6) of this
section shall implement the corrective
action(s) identified in the corrective
action analysis in accordance with the
applicable requirements in paragraphs
(j)(7)(i) through (iii) of this section.
(i) All corrective action(s) must be
implemented within 45 days of the
PO 00000
Frm 00069
Fmt 4701
Sfmt 4700
75245
event for which the root cause and
corrective action analyses were required
or as soon thereafter as practicable. If an
owner or operator concludes that no
corrective action should be
implemented, the owner or operator
shall record and explain the basis for
that conclusion no later than 45 days
following the event.
(ii) For corrective actions that cannot
be fully implemented within 45 days
following the event for which the root
cause and corrective action analyses
were required, the owner or operator
shall develop an implementation
schedule to complete the corrective
action(s) as soon as practicable.
(iii) No later than 45 days following
the event for which a root cause and
corrective action analyses were
required, the owner or operator shall
record the corrective action(s)
completed to date, and, for action(s) not
already completed, a schedule for
implementation, including proposed
commencement and completion dates.
■ 22. Section 63.649 is amended by
revising definition of Cc term in the
equation in paragraph (c)(6)(i) to read as
follows:
§ 63.649 Alternative means of emission
limitation: Connectors in gas/vapor service
and light liquid service.
*
*
(c) * *
(6) * *
(i) * *
*
*
*
*
*
*
Cc = Optional credit for removed connectors
= 0.67 × net number (i.e., the total
number of connectors removed minus
the total added) of connectors in organic
HAP service removed from the process
unit after the applicability date set forth
in § 63.640(h)(3)(iii) for existing process
units, and after the date of start-up for
new process units. If credits are not
taken, then Cc = 0.
*
*
*
*
*
23. Section 63.650 is amended by
revising paragraph (a) and adding
paragraph (d) to read as follows:
■
§ 63.650
Gasoline loading rack provisions.
(a) Except as provided in paragraphs
(b) through (d) of this section, each
owner or operator of a Group 1 gasoline
loading rack classified under Standard
Industrial Classification code 2911
located within a contiguous area and
under common control with a
petroleum refinery shall comply with
subpart R of this part, §§ 63.421,
63.422(a) through (c) and (e), 63.425(a)
through (c) and (e) through (i), 63.427(a)
and (b), and 63.428(b), (c), (g)(1), (h)(1)
through (3), and (k).
*
*
*
*
*
E:\FR\FM\01DER2.SGM
01DER2
75246
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(d) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of subpart R of this part,
or the requirements of § 63.670.
■ 24. Section 63.651 is amended by
revising paragraphs (a) and (d) and
adding paragraph (e) to read as follows:
§ 63.651 Marine tank vessel loading
operation provisions.
(a) Except as provided in paragraphs
(b) through (e) of this section, each
owner or operator of a marine tank
vessel loading operation located at a
petroleum refinery shall comply with
the requirements of §§ 63.560 through
63.568.
*
*
*
*
*
(d) The compliance time of 4 years
after promulgation of 40 CFR part 63,
subpart Y, does not apply. The
compliance time is specified in
§ 63.640(h)(1).
(e) If a flare is used as a control
device, on and after January 30, 2019,
the flare shall meet the requirements of
§ 63.670. Prior to January 30, 2019, the
flare shall meet the applicable
requirements of subpart Y of this part,
or the requirements of § 63.670.
■ 25. Section 63.652 is amended by:
■ a. Revising paragraph (a);
■ b. Removing and reserving paragraph
(f)(2); and
■ c. Revising paragraphs (g)(2)(iii)(B)(1),
(h)(3), (k) introductory text, and (k)(3).
The revisions and additions read as
follows:
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.652
Emissions averaging provisions.
(a) This section applies to owners or
operators of existing sources who seek
to comply with the emission standard in
§ 63.642(g) by using emissions averaging
according to § 63.642(l) rather than
following the provisions of §§ 63.643
through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651. Existing
marine tank vessel loading operations
located at the Valdez Marine Terminal
source may not comply with the
standard by using emissions averaging.
*
*
*
*
*
(g) * * *
(2) * * *
(iii) * * *
(B) * * *
(1) The percent reduction shall be
measured according to the procedures
in § 63.116 of subpart G if a combustion
control device is used. For a flare
meeting the criteria in § 63.116(a) of
subpart G or § 63.670, as applicable, or
a boiler or process heater meeting the
criteria in § 63.645(d) or § 63.116(b) of
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
subpart G, the percentage of reduction
shall be 98 percent. If a noncombustion
control device is used, percentage of
reduction shall be demonstrated by a
performance test at the inlet and outlet
of the device, or, if testing is not
feasible, by a control design evaluation
and documented engineering
calculations.
*
*
*
*
*
(h) * * *
(3) Emissions from storage vessels
shall be determined as specified in
§ 63.150(h)(3) of subpart G, except as
follows:
(i) For storage vessels complying with
§ 63.646:
(A) All references to § 63.119(b) in
§ 63.150(h)(3) of subpart G shall be
replaced with: § 63.119(b) or § 63.119(b)
except for § 63.119(b)(5) and (6).
(B) All references to § 63.119(c) in
§ 63.150(h)(3) of subpart G shall be
replaced with: § 63.119(c) or § 63.119(c)
except for § 63.119(c)(2).
(C) All references to § 63.119(d) in
§ 63.150(h)(3) of subpart G shall be
replaced with: § 63.119(d) or § 63.119(d)
except for § 63.119(d)(2).
(ii) For storage vessels complying
with § 63.660:
(A) Section 63.1063(a)(1)(i), (a)(2), and
(b) or § 63.1063(a)(1)(i) and (b) shall
apply instead of § 63.119(b) in
§ 63.150(h)(3) of subpart G.
(B) Section 63.1063(a)(1)(ii), (a)(2),
and (b) shall apply instead of § 63.119(c)
in § 63.150(h)(3) of subpart G.
(C) Section 63.1063(a)(1)(i), (a)(2), and
(b) or § 63.1063(a)(1)(i) and (b) shall
apply instead of § 63.119(d) in
§ 63.150(h)(3) of subpart G.
*
*
*
*
*
(k) The owner or operator shall
demonstrate that the emissions from the
emission points proposed to be
included in the average will not result
in greater hazard or, at the option of the
State or local permitting authority,
greater risk to human health or the
environment than if the emission points
were controlled according to the
provisions in §§ 63.643 through 63.645,
63.646 or 63.660, 63.647, 63.650, and
63.651, as applicable.
*
*
*
*
*
(3) An emissions averaging plan that
does not demonstrate an equivalent or
lower hazard or risk to the satisfaction
of the State or local permitting authority
shall not be approved. The State or local
permitting authority may require such
adjustments to the emissions averaging
plan as are necessary in order to ensure
that the average will not result in greater
hazard or risk to human health or the
environment than would result if the
emission points were controlled
PO 00000
Frm 00070
Fmt 4701
Sfmt 4700
according to §§ 63.643 through 63.645,
63.646 or 63.660, 63.647, 63.650, and
63.651, as applicable.
*
*
*
*
*
■ 26. Section 63.653 is amended by
revising paragraphs (a) introductory
text, (a)(3)(i) and (ii), and (a)(7) to read
as follows:
§ 63.653 Monitoring, recordkeeping, and
implementation plan for emissions
averaging.
(a) For each emission point included
in an emissions average, the owner or
operator shall perform testing,
monitoring, recordkeeping, and
reporting equivalent to that required for
Group 1 emission points complying
with §§ 63.643 through 63.645, 63.646
or 63.660, 63.647, 63.650, and 63.651, as
applicable. The specific requirements
for miscellaneous process vents, storage
vessels, wastewater, gasoline loading
racks, and marine tank vessels are
identified in paragraphs (a)(1) through
(7) of this section.
*
*
*
*
*
(3) * * *
(i) Perform the monitoring or
inspection procedures in § 63.646 and
either § 63.120 of subpart G or § 63.1063
of subpart WW, as applicable; and
(ii) For closed vent systems with
control devices, conduct an initial
design evaluation as specified in
§ 63.646 and either § 63.120(d) of
subpart G or § 63.985(b) of subpart SS,
as applicable.
*
*
*
*
*
(7) If an emission point in an
emissions average is controlled using a
pollution prevention measure or a
device or technique for which no
monitoring parameters or inspection
procedures are specified in §§ 63.643
through 63.645, 63.646 or 63.660,
63.647, 63.650, and 63.651, as
applicable, the owner or operator shall
establish a site-specific monitoring
parameter and shall submit the
information specified in § 63.655(h)(4)
in the Implementation Plan.
*
*
*
*
*
■ 27. Section 63.655 is amended by:
■ a. Revising paragraphs (f) introductory
text, (f)(1) introductory text, (f)(1)(i)(A)
introductory text, (f)(1)(i)(A)(2) and (3),
(f)(1)(i)(B) introductory text,
(f)(1)(i)(B)(2), (f)(1)(i)(D)(2), (f)(1)(iv)
introductory text, and (f)(1)(iv)(A);
■ b. Adding paragraphs (f)(1)(vii) and
(viii);
■ c. Revising paragraphs (f)(2)
introductory text, (f)(3) introductory
text, the first sentence of (f)(6), (g)
introductory text, (g)(1) through (5),
(g)(6)(i)(D), (g)(6)(iii), and (g)(7)(i);
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
d. Adding paragraphs (g)(10) through
(14);
■ e. Removing and reserving paragraph
(h)(1);
■ f. Revising paragraphs (h)(2)
introductory text, (h)(2)(i)(B), (h)(2)(ii),
and (h)(5)(iii);
■ g. Adding paragraphs (h)(8) and (9)
and (i) introductory text;
■ h. Revising paragraph (i)(1)
introductory text and paragraph
(i)(1)(ii);
■ i. Adding paragraphs (i)(1)(v) and (vi);
■ j. Redesignating paragraphs (i)(4) and
(5) as paragraphs (i)(5) and (6),
respectively;
■ k. Adding paragraph (i)(4);
■ l. Revising newly redesignated
paragraph (i)(5) introductory text; and
■ m. Adding paragraphs (i)(7) through
(12).
The revisions and additions read as
follows:
■
§ 63.655 Reporting and recordkeeping
requirements.
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
(f) Each owner or operator of a source
subject to this subpart shall submit a
Notification of Compliance Status report
within 150 days after the compliance
dates specified in § 63.640(h) with the
exception of Notification of Compliance
Status reports submitted to comply with
§ 63.640(l)(3) and for storage vessels
subject to the compliance schedule
specified in § 63.640(h)(2). Notification
of Compliance Status reports required
by § 63.640(l)(3) and for storage vessels
subject to the compliance dates
specified in § 63.640(h)(2) shall be
submitted according to paragraph (f)(6)
of this section. This information may be
submitted in an operating permit
application, in an amendment to an
operating permit application, in a
separate submittal, or in any
combination of the three. If the required
information has been submitted before
the date 150 days after the compliance
date specified in § 63.640(h), a separate
Notification of Compliance Status report
is not required within 150 days after the
compliance dates specified in
§ 63.640(h). If an owner or operator
submits the information specified in
paragraphs (f)(1) through (5) of this
section at different times, and/or in
different submittals, later submittals
may refer to earlier submittals instead of
duplicating and resubmitting the
previously submitted information. Each
owner or operator of a gasoline loading
rack classified under Standard
Industrial Classification Code 2911
located within a contiguous area and
under common control with a
petroleum refinery subject to the
standards of this subpart shall submit
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
the Notification of Compliance Status
report required by subpart R of this part
within 150 days after the compliance
dates specified in § 63.640(h).
(1) The Notification of Compliance
Status report shall include the
information specified in paragraphs
(f)(1)(i) through (viii) of this section.
(i) * * *
(A) Identification of each storage
vessel subject to this subpart, and for
each Group 1 storage vessel subject to
this subpart, the information specified
in paragraphs (f)(1)(i)(A)(1) through (3)
of this section. This information is to be
revised each time a Notification of
Compliance Status report is submitted
for a storage vessel subject to the
compliance schedule specified in
§ 63.640(h)(2) or to comply with
§ 63.640(l)(3).
*
*
*
*
*
(2) For storage vessels subject to the
compliance schedule specified in
§ 63.640(h)(2) that are not complying
with § 63.646, the anticipated
compliance date.
(3) For storage vessels subject to the
compliance schedule specified in
§ 63.640(h)(2) that are complying with
§ 63.646 and the Group 1 storage vessels
described in § 63.640(l), the actual
compliance date.
(B) If a closed vent system and a
control device other than a flare is used
to comply with § 63.646 or § 63.660, the
owner or operator shall submit:
*
*
*
*
*
(2) The design evaluation
documentation specified in
§ 63.120(d)(1)(i) of subpart G or
§ 63.985(b)(1)(i) of subpart SS (as
applicable), if the owner or operator
elects to prepare a design evaluation; or
*
*
*
*
*
(D) * * *
(2) All visible emission readings, heat
content determinations, flow rate
measurements, and exit velocity
determinations made during the
compliance determination required by
§ 63.120(e) of subpart G or § 63.987(b) of
subpart SS or § 63.670(h), as applicable;
and
*
*
*
*
*
(iv) For miscellaneous process vents
controlled by flares, initial compliance
test results including the information in
paragraphs (f)(1)(iv)(A) and (B) of this
section.
(A) All visible emission readings, heat
content determinations, flow rate
measurements, and exit velocity
determinations made during the
compliance determination required by
§§ 63.645 and 63.116(a) of subpart G or
§ 63.670(h), as applicable; and
*
*
*
*
*
PO 00000
Frm 00071
Fmt 4701
Sfmt 4700
75247
(vii) For pressure relief devices in
organic HAP service subject to the
requirements in § 63.648(j)(3)(i) and (ii),
this report shall include the information
specified in paragraphs (f)(1)(vii)(A) and
(B) of this section.
(A) A description of the monitoring
system to be implemented, including
the relief devices and process
parameters to be monitored, and a
description of the alarms or other
methods by which operators will be
notified of a pressure release.
(B) A description of the prevention
measures to be implemented for each
affected pressure relief device.
(viii) For each delayed coking unit,
identification of whether the unit is an
existing affected source or a new
affected source and whether monitoring
will be conducted as specified in
§ 63.657(b) or (c).
(2) If initial performance tests are
required by §§ 63.643 through 63.653,
the Notification of Compliance Status
report shall include one complete test
report for each test method used for a
particular source. On and after February
1, 2016, performance tests shall be
submitted according to paragraph (h)(9)
of this section.
*
*
*
*
*
(3) For each monitored parameter for
which a range is required to be
established under § 63.120(d) of subpart
G or § 63.985(b) of subpart SS for storage
vessels or § 63.644 for miscellaneous
process vents, the Notification of
Compliance Status report shall include
the information in paragraphs (f)(3)(i)
through (iii) of this section.
*
*
*
*
*
(6) Notification of Compliance Status
reports required by § 63.640(l)(3) and for
storage vessels subject to the
compliance dates specified in
§ 63.640(h)(2) shall be submitted no
later than 60 days after the end of the
6-month period during which the
change or addition was made that
resulted in the Group 1 emission point
or the existing Group 1 storage vessel
was brought into compliance, and may
be combined with the periodic
report. * * *
(g) The owner or operator of a source
subject to this subpart shall submit
Periodic Reports no later than 60 days
after the end of each 6-month period
when any of the information specified
in paragraphs (g)(1) through (7) of this
section or paragraphs (g)(9) through (14)
of this section is collected. The first 6month period shall begin on the date the
Notification of Compliance Status report
is required to be submitted. A Periodic
Report is not required if none of the
events identified in paragraphs (g)(1)
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75248
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
through (7) of this section or paragraphs
(g)(9) through (14) of this section
occurred during the 6-month period
unless emissions averaging is utilized.
Quarterly reports must be submitted for
emission points included in emission
averages, as provided in paragraph (g)(8)
of this section. An owner or operator
may submit reports required by other
regulations in place of or as part of the
Periodic Report required by this
paragraph (g) if the reports contain the
information required by paragraphs
(g)(1) through (14) of this section.
(1) For storage vessels, Periodic
Reports shall include the information
specified for Periodic Reports in
paragraphs (g)(2) through (5) of this
section. Information related to gaskets,
slotted membranes, and sleeve seals is
not required for storage vessels that are
part of an existing source complying
with § 63.646.
(2) Internal floating roofs. (i) An
owner or operator who elects to comply
with § 63.646 by using a fixed roof and
an internal floating roof or by using an
external floating roof converted to an
internal floating roof shall submit the
results of each inspection conducted in
accordance with § 63.120(a) of subpart G
in which a failure is detected in the
control equipment.
(A) For vessels for which annual
inspections are required under
§ 63.120(a)(2)(i) or (a)(3)(ii) of subpart G,
the specifications and requirements
listed in paragraphs (g)(2)(i)(A)(1)
through (3) of this section apply.
(1) A failure is defined as any time in
which the internal floating roof is not
resting on the surface of the liquid
inside the storage vessel and is not
resting on the leg supports; or there is
liquid on the floating roof; or the seal is
detached from the internal floating roof;
or there are holes, tears, or other
openings in the seal or seal fabric; or
there are visible gaps between the seal
and the wall of the storage vessel.
(2) Except as provided in paragraph
(g)(2)(i)(A)(3) of this section, each
Periodic Report shall include the date of
the inspection, identification of each
storage vessel in which a failure was
detected, and a description of the
failure. The Periodic Report shall also
describe the nature of and date the
repair was made or the date the storage
vessel was emptied.
(3) If an extension is utilized in
accordance with § 63.120(a)(4) of
subpart G, the owner or operator shall,
in the next Periodic Report, identify the
vessel; include the documentation
specified in § 63.120(a)(4) of subpart G;
and describe the date the storage vessel
was emptied and the nature of and date
the repair was made.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(B) For vessels for which inspections
are required under § 63.120(a)(2)(ii),
(a)(3)(i), or (a)(3)(iii) of subpart G (i.e.,
internal inspections), the specifications
and requirements listed in paragraphs
(g)(2)(i)(B)(1) and (2) of this section
apply.
(1) A failure is defined as any time in
which the internal floating roof has
defects; or the primary seal has holes,
tears, or other openings in the seal or
the seal fabric; or the secondary seal (if
one has been installed) has holes, tears,
or other openings in the seal or the seal
fabric; or, for a storage vessel that is part
of a new source, the gaskets no longer
close off the liquid surface from the
atmosphere; or, for a storage vessel that
is part of a new source, the slotted
membrane has more than a 10 percent
open.
(2) Each Periodic Report shall include
the date of the inspection, identification
of each storage vessel in which a failure
was detected, and a description of the
failure. The Periodic Report shall also
describe the nature of and date the
repair was made.
(ii) An owner or operator who elects
to comply with § 63.660 by using a fixed
roof and an internal floating roof shall
submit the results of each inspection
conducted in accordance with
§ 63.1063(c)(1), (d)(1), and (d)(2) of
subpart WW in which a failure is
detected in the control equipment. For
vessels for which inspections are
required under § 63.1063(c) and (d), the
specifications and requirements listed
in paragraphs (g)(2)(ii)(A) through (C) of
this section apply.
(A) A failure is defined in
§ 63.1063(d)(1) of subpart WW.
(B) Each Periodic Report shall include
a copy of the inspection record required
by § 63.1065(b) of subpart WW when a
failure occurs.
(C) An owner or operator who elects
to use an extension in accordance with
§ 63.1063(e)(2) of subpart WW shall, in
the next Periodic Report, submit the
documentation required by
§ 63.1063(e)(2).
(3) External floating roofs. (i) An
owner or operator who elects to comply
with § 63.646 by using an external
floating roof shall meet the periodic
reporting requirements specified in
paragraphs (g)(3)(i)(A) through (C) of
this section.
(A) The owner or operator shall
submit, as part of the Periodic Report,
documentation of the results of each
seal gap measurement made in
accordance with § 63.120(b) of subpart
G in which the seal and seal gap
requirements of § 63.120(b)(3), (4), (5),
or (6) of subpart G are not met. This
documentation shall include the
PO 00000
Frm 00072
Fmt 4701
Sfmt 4700
information specified in paragraphs
(g)(3)(i)(A)(1) through (4) of this section.
(1) The date of the seal gap
measurement.
(2) The raw data obtained in the seal
gap measurement and the calculations
described in § 63.120(b)(3) and (4) of
subpart G.
(3) A description of any seal condition
specified in § 63.120(b)(5) or (6) of
subpart G that is not met.
(4) A description of the nature of and
date the repair was made, or the date the
storage vessel was emptied.
(B) If an extension is utilized in
accordance with § 63.120(b)(7)(ii) or
(b)(8) of subpart G, the owner or
operator shall, in the next Periodic
Report, identify the vessel; include the
documentation specified in
§ 63.120(b)(7)(ii) or (b)(8) of subpart G,
as applicable; and describe the date the
vessel was emptied and the nature of
and date the repair was made.
(C) The owner or operator shall
submit, as part of the Periodic Report,
documentation of any failures that are
identified during visual inspections
required by § 63.120(b)(10) of subpart G.
This documentation shall meet the
specifications and requirements in
paragraphs (g)(3)(i)(C)(1) and (2) of this
section.
(1) A failure is defined as any time in
which the external floating roof has
defects; or the primary seal has holes or
other openings in the seal or the seal
fabric; or the secondary seal has holes,
tears, or other openings in the seal or
the seal fabric; or, for a storage vessel
that is part of a new source, the gaskets
no longer close off the liquid surface
from the atmosphere; or, for a storage
vessel that is part of a new source, the
slotted membrane has more than 10
percent open area.
(2) Each Periodic Report shall include
the date of the inspection, identification
of each storage vessel in which a failure
was detected, and a description of the
failure. The Periodic Report shall also
describe the nature of and date the
repair was made.
(ii) An owner or operator who elects
to comply with § 63.660 by using an
external floating roof shall meet the
periodic reporting requirements
specified in paragraphs (g)(3)(ii)(A) and
(B) of this section.
(A) For vessels for which inspections
are required under § 63.1063(c)(2),
(d)(1), and (d)(3) of subpart WW, the
owner or operator shall submit, as part
of the Periodic Report, a copy of the
inspection record required by
§ 63.1065(b) of subpart WW when a
failure occurs. A failure is defined in
§ 63.1063(d)(1).
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(B) An owner or operator who elects
to use an extension in accordance with
§ 63.1063(e)(2) or (c)(2)(iv)(B) of subpart
WW shall, in the next Periodic Report,
submit the documentation required by
those paragraphs.
(4) [Reserved]
(5) An owner or operator who elects
to comply with § 63.646 or § 63.660 by
installing a closed vent system and
control device shall submit, as part of
the next Periodic Report, the
information specified in paragraphs
(g)(5)(i) through (v) of this section, as
applicable.
(i) The Periodic Report shall include
the information specified in paragraphs
(g)(5)(i)(A) and (B) of this section for
those planned routine maintenance
operations that would require the
control device not to meet the
requirements of either § 63.119(e)(1) or
(2) of subpart G, § 63.985(a) and (b) of
subpart SS, or § 63.670, as applicable.
(A) A description of the planned
routine maintenance that is anticipated
to be performed for the control device
during the next 6 months. This
description shall include the type of
maintenance necessary, planned
frequency of maintenance, and lengths
of maintenance periods.
(B) A description of the planned
routine maintenance that was performed
for the control device during the
previous 6 months. This description
shall include the type of maintenance
performed and the total number of
hours during those 6 months that the
control device did not meet the
requirements of either § 63.119(e)(1) or
(2) of subpart G, § 63.985(a) and (b) of
subpart SS, or § 63.670, as applicable,
due to planned routine maintenance.
(ii) If a control device other than a
flare is used, the Periodic Report shall
describe each occurrence when the
monitored parameters were outside of
the parameter ranges documented in the
Notification of Compliance Status
report. The description shall include:
Identification of the control device for
which the measured parameters were
outside of the established ranges, and
causes for the measured parameters to
be outside of the established ranges.
(iii) If a flare is used prior to January
30, 2019 and prior to electing to comply
with the requirements in § 63.670, the
Periodic Report shall describe each
occurrence when the flare does not meet
the general control device requirements
specified in § 63.11(b) of subpart A and
shall include: Identification of the flare
that does not meet the general
requirements specified in § 63.11(b) of
subpart A, and reasons the flare did not
meet the general requirements specified
in § 63.11(b) of subpart A.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(iv) If a flare is used on or after the
date for which compliance with the
requirements in § 63.670 is elected,
which can be no later than January 30,
2019, the Periodic Report shall include
the items specified in paragraph (g)(11)
of this section.
(v) An owner or operator who elects
to comply with § 63.660 by installing an
alternate control device as described in
§ 63.1064 of subpart WW shall submit,
as part of the next Periodic Report, a
written application as described in
§ 63.1066(b)(3) of subpart WW.
(6) * * *
(i) * * *
(D) For data compression systems
under paragraph (h)(5)(iii) of this
section, an operating day when the
monitor operated for less than 75
percent of the operating hours or a day
when less than 18 monitoring values
were recorded.
*
*
*
*
*
(iii) For periods in closed vent
systems when a Group 1 miscellaneous
process vent stream was detected in the
bypass line or diverted from the control
device and either directly to the
atmosphere or to a control device that
does not comply with the requirements
in § 63.643(a), report the date, time,
duration, estimate of the volume of gas,
the concentration of organic HAP in the
gas and the resulting mass emissions of
organic HAP that bypassed the control
device. For periods when the flow
indicator is not operating, report the
date, time, and duration.
(7) * * *
(i) Results of the performance test
shall include the identification of the
source tested, the date of the test, the
percentage of emissions reduction or
outlet pollutant concentration reduction
(whichever is needed to determine
compliance) for each run and for the
average of all runs, and the values of the
monitored operating parameters.
*
*
*
*
*
(10) For pressure relief devices subject
to the requirements § 63.648(j), Periodic
Reports must include the information
specified in paragraphs (g)(10)(i)
through (iii) of this section.
(i) For pressure relief devices in
organic HAP gas or vapor service,
pursuant to § 63.648(j)(1), report any
instrument reading of 500 ppm or
greater.
(ii) For pressure relief devices in
organic HAP gas or vapor service subject
to § 63.648(j)(2), report confirmation
that any monitoring required to be done
during the reporting period to show
compliance was conducted.
(iii) For pressure relief devices in
organic HAP service subject to
PO 00000
Frm 00073
Fmt 4701
Sfmt 4700
75249
§ 63.648(j)(3), report each pressure
release to the atmosphere, including
duration of the pressure release and
estimate of the mass quantity of each
organic HAP released, and the results of
any root cause analysis and corrective
action analysis completed during the
reporting period, including the
corrective actions implemented during
the reporting period and, if applicable,
the implementation schedule for
planned corrective actions to be
implemented subsequent to the
reporting period.
(11) For flares subject to § 63.670,
Periodic Reports must include the
information specified in paragraphs
(g)(11)(i) through (iv) of this section.
(i) Records as specified in paragraph
(i)(9)(i) of this section for each 15minute block during which there was at
least one minute when regulated
material is routed to a flare and no pilot
flame is present.
(ii) Visible emission records as
specified in paragraph (i)(9)(ii)(C) of this
section for each period of 2 consecutive
hours during which visible emissions
exceeded a total of 5 minutes.
(iii) The 15-minute block periods for
which the applicable operating limits
specified in § 63.670(d) through (f) are
not met. Indicate the date and time for
the period, the net heating value
operating parameter(s) determined
following the methods in § 63.670(k)
through (n) as applicable.
(iv) For flaring events meeting the
criteria in § 63.670(o)(3):
(A) The start and stop time and date
of the flaring event.
(B) The length of time for which
emissions were visible from the flare
during the event.
(C) The periods of time that the flare
tip velocity exceeds the maximum flare
tip velocity determined using the
methods in § 63.670(d)(2) and the
maximum 15-minute block average flare
tip velocity recorded during the event.
(D) Results of the root cause and
corrective actions analysis completed
during the reporting period, including
the corrective actions implemented
during the reporting period and, if
applicable, the implementation
schedule for planned corrective actions
to be implemented subsequent to the
reporting period.
(12) For delayed coking units, the
Periodic Report must include the
information specified in paragraphs
(g)(12)(i) through (iv) of this section.
(i) For existing source delayed coking
units, any 60-cycle average exceeding
the applicable limit in § 63.657(a)(1).
(ii) For new source delayed coking
units, any direct venting event
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75250
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
exceeding the applicable limit in
§ 63.657(a)(2).
(iii) The total number of double
quenching events performed during the
reporting period.
(iv) For each double quenching
draining event when the drain water
temperature exceeded 210 °F, report the
drum, date, time, the coke drum vessel
pressure or temperature, as applicable,
when pre-vent draining was initiated,
and the maximum drain water
temperature during the pre-vent
draining period.
(13) For maintenance vents subject to
the requirements in § 63.643(c), Periodic
Reports must include the information
specified in paragraphs (g)(13)(i)
through (iv) of this section for any
release exceeding the applicable limits
in § 63.643(c)(1). For the purposes of
this reporting requirement, owners or
operators complying with
§ 63.643(c)(1)(iv) must report each
venting event for which the lower
explosive limit is 20 percent or greater.
(i) Identification of the maintenance
vent and the equipment served by the
maintenance vent.
(ii) The date and time the
maintenance vent was opened to the
atmosphere.
(iii) The lower explosive limit, vessel
pressure, or mass of VOC in the
equipment, as applicable, at the start of
atmospheric venting. If the 5 psig vessel
pressure option in § 63.643(c)(1)(ii) was
used and active purging was initiated
while the lower explosive limit was 10
percent or greater, also include the
lower explosive limit of the vapors at
the time active purging was initiated.
(iv) An estimate of the mass of organic
HAP released during the entire
atmospheric venting event.
(14) Any changes in the information
provided in a previous Notification of
Compliance Status report.
(h) * * *
(2) For storage vessels, notifications of
inspections as specified in paragraphs
(h)(2)(i) and (ii) of this section.
(i) * * *
(B) Except as provided in paragraph
(h)(2)(i)(C) of this section, if the internal
inspection required by § 63.120(a)(2),
(a)(3), or (b)(10) of subpart G or
§ 63.1063(d)(1) of subpart WW is not
planned and the owner or operator
could not have known about the
inspection 30 calendar days in advance
of refilling the vessel with organic HAP,
the owner or operator shall notify the
Administrator at least 7 calendar days
prior to refilling of the storage vessel.
Notification may be made by telephone
and immediately followed by written
documentation demonstrating why the
inspection was unplanned. This
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
notification, including the written
documentation, may also be made in
writing and sent so that it is received by
the Administrator at least 7 calendar
days prior to the refilling.
*
*
*
*
*
(ii) In order to afford the
Administrator the opportunity to have
an observer present, the owner or
operator of a storage vessel equipped
with an external floating roof shall
notify the Administrator of any seal gap
measurements. The notification shall be
made in writing at least 30 calendar
days in advance of any gap
measurements required by § 63.120(b)(1)
or (2) of subpart G or § 63.1062(d)(3) of
subpart WW. The State or local
permitting authority can waive this
notification requirement for all or some
storage vessels subject to the rule or can
allow less than 30 calendar days’ notice.
*
*
*
*
*
(5) * * *
(iii) An owner or operator may use an
automated data compression recording
system that does not record monitored
operating parameter values at a set
frequency (for example, once every
hour) but records all values that meet
set criteria for variation from previously
recorded values.
(A) The system shall be designed to:
(1) Measure the operating parameter
value at least once every hour.
(2) Record at least 24 values each day
during periods of operation.
(3) Record the date and time when
monitors are turned off or on.
(4) Recognize unchanging data that
may indicate the monitor is not
functioning properly, alert the operator,
and record the incident.
(5) Compute daily average values of
the monitored operating parameter
based on recorded data.
(B) You must maintain a record of the
description of the monitoring system
and data compression recording system
including the criteria used to determine
which monitored values are recorded
and retained, the method for calculating
daily averages, and a demonstrations
that they system meets all criteria of
paragraph (h)(5)(iii)(A) of this section.
*
*
*
*
*
(8) For fenceline monitoring systems
subject to § 63.658, within 45 calendar
days after the end of each quarterly
reporting period covered by the periodic
report, each owner or operator shall
submit the following information to the
EPA’s Compliance and Emissions Data
Reporting Interface (CEDRI). (CEDRI can
be accessed through the EPA’s Central
Data Exchange (CDX) (https://
cdx.epa.gov/). The owner or operator
need not transmit this data prior to
obtaining 12 months of data.
PO 00000
Frm 00074
Fmt 4701
Sfmt 4700
(i) Individual sample results for each
monitor for each sampling period
during the quarterly reporting period.
For the first reporting period and for any
period in which a passive monitor is
added or moved, the owner or operator
shall report the coordinates of all of the
passive monitor locations. The owner or
operator shall determine the coordinates
using an instrument with an accuracy of
at least 3 meters. Coordinates shall be in
decimal degrees with at least five
decimal places.
(ii) The biweekly annual average
concentration difference (Dc) values for
benzene for the quarterly reporting
period.
(iii) Notation for each biweekly value
that indicates whether background
correction was used, all measurements
in the sampling period were below
detection, or whether an outlier was
removed from the sampling period data
set.
(9) On and after February 1, 2016, if
required to submit the results of a
performance test or CEMS performance
evaluation, the owner or operator shall
submit the results according to the
procedures in paragraphs (h)(9)(i) and
(ii) of this section.
(i) Within 60 days after the date of
completing each performance test as
required by this subpart, the owner or
operator shall submit the results of the
performance tests following the
procedure specified in either paragraph
(h)(9)(i)(A) or (B) of this section.
(A) For data collected using test
methods supported by the EPA’s
Electronic Reporting Tool (ERT) as
listed on the EPA’s ERT Web site
(https://www.epa.gov/ttn/chief/ert/
index.html) at the time of the test, the
owner or operator must submit the
results of the performance test to the
EPA via the CEDRI. (CEDRI can be
accessed through the EPA’s CDX.)
Performance test data must be submitted
in a file format generated through the
use of the EPA’s ERT or an alternate
electronic file format consistent with the
extensible markup language (XML)
schema listed on the EPA’s ERT Web
site. If an owner or operator claims that
some of the performance test
information being submitted is
confidential business information (CBI),
the owner or operator must submit a
complete file generated through the use
of the EPA’s ERT or an alternate
electronic file consistent with the XML
schema listed on the EPA’s ERT Web
site, including information claimed to
be CBI, on a compact disc, flash drive
or other commonly used electronic
storage media to the EPA. The electronic
storage media must be clearly marked as
CBI and mailed to U.S. EPA/OAQPS/
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
CORE CBI Office, Attention: Group
Leader, Measurement Policy Group, MD
C404–02, 4930 Old Page Rd., Durham,
NC 27703. The same ERT or alternate
file with the CBI omitted must be
submitted to the EPA via the EPA’s CDX
as described earlier in this paragraph
(h)(9)(i)(A).
(B) For data collected using test
methods that are not supported by the
EPA’s ERT as listed on the EPA’s ERT
Web site at the time of the test, the
owner or operator must submit the
results of the performance test to the
Administrator at the appropriate
address listed in § 63.13.
(ii) Within 60 days after the date of
completing each CEMS performance
evaluation as required by this subpart,
the owner or operator must submit the
results of the performance evaluation
following the procedure specified in
either paragraph (h)(9)(ii)(A) or (B) of
this section.
(A) For performance evaluations of
continuous monitoring systems
measuring relative accuracy test audit
(RATA) pollutants that are supported by
the EPA’s ERT as listed on the EPA’s
ERT Web site at the time of the
evaluation, the owner or operator must
submit the results of the performance
evaluation to the EPA via the CEDRI.
(CEDRI can be accessed through the
EPA’s CDX.) Performance evaluation
data must be submitted in a file format
generated through the use of the EPA’s
ERT or an alternate file format
consistent with the XML schema listed
on the EPA’s ERT Web site. If an owner
or operator claims that some of the
performance evaluation information
being submitted is CBI, the owner or
operator must submit a complete file
generated through the use of the EPA’s
ERT or an alternate electronic file
consistent with the XML schema listed
on the EPA’s ERT Web site, including
information claimed to be CBI, on a
compact disc, flash drive or other
commonly used electronic storage
media to the EPA. The electronic storage
media must be clearly marked as CBI
and mailed to U.S. EPA/OAQPS/CORE
CBI Office, Attention: Group Leader,
Measurement Policy Group, MD C404–
02, 4930 Old Page Rd., Durham, NC
27703. The same ERT or alternate file
with the CBI omitted must be submitted
to the EPA via the EPA’s CDX as
described earlier in this paragraph
(h)(9)(ii)(A).
(B) For any performance evaluations
of continuous monitoring systems
measuring RATA pollutants that are not
supported by the EPA’s ERT as listed on
the EPA’s ERT Web site at the time of
the evaluation, the owner or operator
must submit the results of the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
performance evaluation to the
Administrator at the appropriate
address listed in § 63.13.
(i) Recordkeeping. Each owner or
operator of a source subject to this
subpart shall keep copies of all
applicable reports and records required
by this subpart for at least 5 years except
as otherwise specified in paragraphs
(i)(1) through (12) of this section. All
applicable records shall be maintained
in such a manner that they can be
readily accessed within 24 hours.
Records may be maintained in hard
copy or computer-readable form
including, but not limited to, on paper,
microfilm, computer, flash drive, floppy
disk, magnetic tape, or microfiche.
(1) Each owner or operator subject to
the storage vessel provisions in § 63.646
shall keep the records specified in
§ 63.123 of subpart G except as specified
in paragraphs (i)(1)(i) through (iv) of this
section. Each owner or operator subject
to the storage vessel provisions in
§ 63.660 shall keep records as specified
in paragraphs (i)(1)(v) and (vi) of this
section.
*
*
*
*
*
(ii) All references to § 63.122 in
§ 63.123 of subpart G shall be replaced
with § 63.655(e).
*
*
*
*
*
(v) Each owner or operator of a Group
1 storage vessel subject to the provisions
in § 63.660 shall keep records as
specified in § 63.1065 or § 63.998, as
applicable.
(vi) Each owner or operator of a Group
2 storage vessel shall keep the records
specified in § 63.1065(a) of subpart WW.
If a storage vessel is determined to be
Group 2 because the weight percent
total organic HAP of the stored liquid is
less than or equal to 4 percent for
existing sources or 2 percent for new
sources, a record of any data,
assumptions, and procedures used to
make this determination shall be
retained.
*
*
*
*
*
(4) For each closed vent system that
contains bypass lines that could divert
a vent stream away from the control
device and either directly to the
atmosphere or to a control device that
does not comply with the requirements
in § 63.643(a), the owner or operator
shall keep a record of the information
specified in either paragraph (i)(4)(i) or
(ii) of this section, as applicable.
(i) The owner or operator shall
maintain records of periods when flow
was detected in the bypass line,
including the date and time and the
duration of the flow in the bypass line.
For each flow event, the owner or
operator shall maintain records
PO 00000
Frm 00075
Fmt 4701
Sfmt 4700
75251
sufficient to determine whether or not
the detected flow included flow of a
Group 1 miscellaneous process vent
stream requiring control. For periods
when the Group 1 miscellaneous
process vent stream requiring control is
diverted from the control device and
released either directly to the
atmosphere or to a control device that
does not comply with the requirements
in § 63.643(a), the owner or operator
shall include an estimate of the volume
of gas, the concentration of organic HAP
in the gas and the resulting emissions of
organic HAP that bypassed the control
device using process knowledge and
engineering estimates.
(ii) Where a seal mechanism is used
to comply with § 63.644(c)(2), hourly
records of flow are not required. In such
cases, the owner or operator shall record
the date that the monthly visual
inspection of the seals or closure
mechanisms is completed. The owner or
operator shall also record the
occurrence of all periods when the seal
or closure mechanism is broken, the
bypass line valve position has changed
or the key for a lock-and-key type lock
has been checked out. The owner or
operator shall include an estimate of the
volume of gas, the concentration of
organic HAP in the gas and the resulting
mass emissions of organic HAP from the
Group 1 miscellaneous process vent
stream requiring control that bypassed
the control device or records sufficient
to demonstrate that there was no flow of
a Group 1 miscellaneous process vent
stream requiring control during the
period.
(5) The owner or operator of a heat
exchange system subject to this subpart
shall comply with the recordkeeping
requirements in paragraphs (i)(5)(i)
through (v) of this section and retain
these records for 5 years.
*
*
*
*
*
(7) Each owner or operator subject to
the delayed coking unit decoking
operations provisions in § 63.657 must
maintain records specified in
paragraphs (i)(7)(i) through (iii) of this
section.
(i) The average pressure or
temperature, as applicable, for the 5minute period prior to venting to the
atmosphere, draining, or deheading the
coke drum for each cooling cycle for
each coke drum.
(ii) If complying with the 60-cycle
rolling average, each 60-cycle rolling
average pressure or temperature, as
applicable, considering all coke drum
venting events in the existing affected
source.
(iii) For double-quench cooling
cycles:
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75252
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(A) The date, time and duration of
each pre-vent draining event.
(B) The pressure or temperature of the
coke drum vessel, as applicable, for the
15 minute period prior to the pre-vent
draining.
(C) The drain water temperature at 1minute intervals from the start of prevent draining to the complete closure of
the drain valve.
(8) For fenceline monitoring systems
subject to § 63.658, each owner or
operator shall keep the records specified
in paragraphs (i)(8)(i) through (x) of this
section on an ongoing basis.
(i) Coordinates of all passive
monitors, including replicate samplers
and field blanks, and if applicable, the
meteorological station. The owner or
operator shall determine the coordinates
using an instrument with an accuracy of
at least 3 meters. The coordinates shall
be in decimal degrees with at least five
decimal places.
(ii) The start and stop times and dates
for each sample, as well as the tube
identifying information.
(iii) Sampling period average
temperature and barometric pressure
measurements.
(iv) For each outlier determined in
accordance with Section 9.2 of Method
325A of appendix A of this part, the
sampler location of and the
concentration of the outlier and the
evidence used to conclude that the
result is an outlier.
(v) For samples that will be adjusted
for a background, the location of and the
concentration measured simultaneously
by the background sampler, and the
perimeter samplers to which it applies.
(vi) Individual sample results, the
calculated Dc for benzene for each
sampling period and the two samples
used to determine it, whether
background correction was used, and
the annual average Dc calculated after
each sampling period.
(vii) Method detection limit for each
sample, including co-located samples
and blanks.
(viii) Documentation of corrective
action taken each time the action level
was exceeded.
(ix) Other records as required by
Methods 325A and 325B of appendix A
of this part.
(x) If a near-field source correction is
used as provided in § 63.658(i), records
of hourly meteorological data, including
temperature, barometric pressure, wind
speed and wind direction, calculated
daily unit vector wind direction and
daily sigma theta, and other records
specified in the site-specific monitoring
plan.
(9) For each flare subject to § 63.670,
each owner or operator shall keep the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
records specified in paragraphs (i)(9)(i)
through (xii) of this section up-to-date
and readily accessible, as applicable.
(i) Retain records of the output of the
monitoring device used to detect the
presence of a pilot flame as required in
§ 63.670(b) for a minimum of 2 years.
Retain records of each 15-minute block
during which there was at least one
minute that no pilot flame is present
when regulated material is routed to a
flare for a minimum of 5 years.
(ii) Retain records of daily visible
emissions observations or video
surveillance images required in
§ 63.670(h) as specified in the
paragraphs (i)(9)(ii)(A) through (C), as
applicable, for a minimum of 3 years.
(A) If visible emissions observations
are performed using Method 22 at 40
CFR part 60, appendix A–7, the record
must identify whether the visible
emissions observation was performed,
the results of each observation, total
duration of observed visible emissions,
and whether it was a 5-minute or 2-hour
observation. If the owner or operator
performs visible emissions observations
more than one time during a day, the
record must also identify the date and
time of day each visible emissions
observation was performed.
(B) If video surveillance camera is
used, the record must include all video
surveillance images recorded, with time
and date stamps.
(C) For each 2 hour period for which
visible emissions are observed for more
than 5 minutes in 2 consecutive hours,
the record must include the date and
time of the 2 hour period and an
estimate of the cumulative number of
minutes in the 2 hour period for which
emissions were visible.
(iii) The 15-minute block average
cumulative flows for flare vent gas and,
if applicable, total steam, perimeter
assist air, and premix assist air specified
to be monitored under § 63.670(i), along
with the date and time interval for the
15-minute block. If multiple monitoring
locations are used to determine
cumulative vent gas flow, total steam,
perimeter assist air, and premix assist
air, retain records of the 15-minute
block average flows for each monitoring
location for a minimum of 2 years, and
retain the 15-minute block average
cumulative flows that are used in
subsequent calculations for a minimum
of 5 years. If pressure and temperature
monitoring is used, retain records of the
15-minute block average temperature,
pressure and molecular weight of the
flare vent gas or assist gas stream for
each measurement location used to
determine the 15-minute block average
cumulative flows for a minimum of 2
years, and retain the 15-minute block
PO 00000
Frm 00076
Fmt 4701
Sfmt 4700
average cumulative flows that are used
in subsequent calculations for a
minimum of 5 years.
(iv) The flare vent gas compositions
specified to be monitored under
§ 63.670(j). Retain records of individual
component concentrations from each
compositional analyses for a minimum
of 2 years. If NHVvg analyzer is used,
retain records of the 15-minute block
average values for a minimum of 5
years.
(v) Each 15-minute block average
operating parameter calculated
following the methods specified in
§ 63.670(k) through (n), as applicable.
(vi) [Reserved]
(vii) All periods during which
operating values are outside of the
applicable operating limits specified in
§ 63.670(d) through (f) when regulated
material is being routed to the flare.
(viii) All periods during which the
owner or operator does not perform flare
monitoring according to the procedures
in § 63.670(g) through (j).
(ix) Records of periods when there is
flow of vent gas to the flare, but when
there is no flow of regulated material to
the flare, including the start and stop
time and dates of periods of no
regulated material flow.
(x) Records when the flow of vent gas
exceeds the smokeless capacity of the
flare, including start and stop time and
dates of the flaring event.
(xi) Records of the root cause analysis
and corrective action analysis
conducted as required in § 63.670(o)(3),
including an identification of the
affected facility, the date and duration
of the event, a statement noting whether
the event resulted from the same root
cause(s) identified in a previous
analysis and either a description of the
recommended corrective action(s) or an
explanation of why corrective action is
not necessary under § 63.670(o)(5)(i).
(xii) For any corrective action analysis
for which implementation of corrective
actions are required in § 63.670(o)(5), a
description of the corrective action(s)
completed within the first 45 days
following the discharge and, for
action(s) not already completed, a
schedule for implementation, including
proposed commencement and
completion dates.
(10) [Reserved]
(11) For each pressure relief device
subject to the pressure release
management work practice standards in
§ 63.648(j)(3), the owner or operator
shall keep the records specified in
paragraphs (i)(11)(i) through (iii) of this
section.
(i) Records of the prevention measures
implemented as required in
§ 63.648(j)(3)(ii), if applicable.
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(ii) Records of the number of releases
during each calendar year and the
number of those releases for which the
root cause was determined to be a force
majeure event. Keep these records for
the current calendar year and the past
five calendar years.
(iii) For each release to the
atmosphere, the owner or operator shall
keep the records specified in paragraphs
(i)(11)(iii)(A) through (D) of this section.
(A) The start and end time and date
of each pressure release to the
atmosphere.
(B) Records of any data, assumptions,
and calculations used to estimate of the
mass quantity of each organic HAP
released during the event.
(C) Records of the root cause analysis
and corrective action analysis
conducted as required in
§ 63.648(j)(3)(iii), including an
identification of the affected facility, the
date and duration of the event, a
statement noting whether the event
resulted from the same root cause(s)
identified in a previous analysis and
either a description of the recommended
corrective action(s) or an explanation of
why corrective action is not necessary
under § 63.648(j)(7)(i).
(D) For any corrective action analysis
for which implementation of corrective
actions are required in § 63.648(j)(7), a
description of the corrective action(s)
completed within the first 45 days
following the discharge and, for
action(s) not already completed, a
schedule for implementation, including
proposed commencement and
completion dates.
(12) For each maintenance vent
opening subject to the requirements in
§ 63.643(c), the owner or operator shall
keep the applicable records specified in
(i)(12)(i) through (v) of this section.
(i) The owner or operator shall
maintain standard site procedures used
to deinventory equipment for safety
purposes (e.g., hot work or vessel entry
procedures) to document the procedures
used to meet the requirements in
§ 63.643(c). The current copy of the
procedures shall be retained and
available on-site at all times. Previous
versions of the standard site procedures,
is applicable, shall be retained for five
years.
(ii) If complying with the
requirements of § 63.643(c)(1)(i) and the
lower explosive limit at the time of the
vessel opening exceeds 10 percent,
identification of the maintenance vent,
the process units or equipment
associated with the maintenance vent,
the date of maintenance vent opening,
and the lower explosive limit at the time
of the vessel opening.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(iii) If complying with the
requirements of § 63.643(c)(1)(ii) and
either the vessel pressure at the time of
the vessel opening exceeds 5 psig or the
lower explosive limit at the time of the
active purging was initiated exceeds 10
percent, identification of the
maintenance vent, the process units or
equipment associated with the
maintenance vent, the date of
maintenance vent opening, the pressure
of the vessel or equipment at the time
of discharge to the atmosphere and, if
applicable, the lower explosive limit of
the vapors in the equipment when
active purging was initiated.
(iv) If complying with the
requirements of § 63.643(c)(1)(iii),
identification of the maintenance vent,
the process units or equipment
associated with the maintenance vent,
the date of maintenance vent opening,
and records used to estimate the total
quantity of VOC in the equipment at the
time the maintenance vent was opened
to the atmosphere for each applicable
maintenance vent opening.
(v) If complying with the
requirements of § 63.643(c)(1)(iv),
identification of the maintenance vent,
the process units or equipment
associated with the maintenance vent,
records documenting the lack of a pure
hydrogen supply, the date of
maintenance vent opening, and the
lower explosive limit of the vapors in
the equipment at the time of discharge
to the atmosphere for each applicable
maintenance vent opening.
28. Section 63.656 is amended by
revising paragraph (c)(1) to read as
follows:
■
§ 63.656
Implementation and enforcement.
*
*
*
*
*
(c) * * *
(1) Approval of alternatives to the
requirements in §§ 63.640, 63.642(g)
through (l), 63.643, 63.646 through
63.652, 63.654, 63.657 through 63.660,
and 63.670. Where these standards
reference another subpart, the cited
provisions will be delegated according
to the delegation provisions of the
referenced subpart. Where these
standards reference another subpart and
modify the requirements, the
requirements shall be modified as
described in this subpart. Delegation of
the modified requirements will also
occur according to the delegation
provisions of the referenced subpart.
*
*
*
*
*
29. Section 63.657 is added to read as
follows:
■
PO 00000
Frm 00077
Fmt 4701
Sfmt 4700
75253
§ 63.657 Delayed coking unit decoking
operation standards.
(a) Except as provided in paragraphs
(e) and (f) of this section, each owner or
operator of a delayed coking unit shall
depressure each coke drum to a closed
blowdown system until the coke drum
vessel pressure or temperature
measured at the top of the coke drum or
in the overhead line of the coke drum
as near as practical to the coke drum
meets the applicable limits specified in
paragraph (a)(1) or (2) of this section
prior to venting to the atmosphere,
draining or deheading the coke drum at
the end of the cooling cycle.
(1) For delayed coking units at an
existing affected source, meet either:
(i) An average vessel pressure of 2
psig determined on a rolling 60-event
average; or
(ii) An average vessel temperature of
220 degrees Fahrenheit determined on a
rolling 60-event average.
(2) For delayed coking units at a new
affected source, meet either:
(i) A vessel pressure of 2.0 psig for
each decoking event; or
(ii) A vessel temperature of 218
degrees Fahrenheit for each decoking
event.
(b) Each owner or operator of a
delayed coking unit complying with the
pressure limits in paragraph (a)(1)(i) or
(a)(2)(i) of this section shall install,
operate, calibrate, and maintain a
monitoring system, as specified in
paragraphs (b)(1) through (5) of this
section, to determine the coke drum
vessel pressure.
(1) The pressure monitoring system
must be in a representative location (at
the top of the coke drum or in the
overhead line as near as practical to the
coke drum) that minimizes or eliminates
pulsating pressure, vibration, and, to the
extent practical, internal and external
corrosion.
(2) The pressure monitoring system
must be capable of measuring a pressure
of 2.0 psig within ±0.5 psig.
(3) The pressure monitoring system
must be verified annually or at the
frequency recommended by the
instrument manufacturer. The pressure
monitoring system must be verified
following any period of more than 24
hours throughout which the pressure
exceeded the maximum rated pressure
of the sensor, or the data recorder was
off scale.
(4) All components of the pressure
monitoring system must be visually
inspected for integrity, oxidation and
galvanic corrosion every 3 months,
unless the system has a redundant
pressure sensor.
(5) The output of the pressure
monitoring system must be reviewed
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75254
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
daily to ensure that the pressure
readings fluctuate as expected between
operating and cooling/decoking cycles
to verify the pressure taps are not
plugged. Plugged pressure taps must be
unplugged or otherwise repaired prior
to the next operating cycle.
(c) Each owner or operator of a
delayed coking unit complying with the
temperature limits in paragraph (a)(1)(ii)
or (a)(2)(ii) of this section shall install,
operate, calibrate, and maintain a
continuous parameter monitoring
system to measure the coke drum vessel
temperature (at the top of the coke drum
or in the overhead line as near as
practical to the coke drum) according to
the requirements specified in table 13 of
this subpart.
(d) The owner or operator of a delayed
coking unit shall determine the coke
drum vessel pressure or temperature, as
applicable, on a 5-minute rolling
average basis while the coke drum is
vented to the closed blowdown system
and shall use the last complete 5-minute
rolling average pressure or temperature
just prior to initiating steps to isolate the
coke drum prior to venting, draining or
deheading to demonstrate compliance
with the requirements in paragraph (a)
of this section. Pressure or temperature
readings after initiating steps to isolate
the coke drum from the closed
blowdown system just prior to
atmospheric venting, draining, or
deheading the coke drum shall not be
used in determining the average coke
drum vessel pressure or temperature for
the purpose of compliance with the
requirements in paragraph (a) of this
section.
(e) The owner or operator of a delayed
coking unit using the ‘‘water overflow’’
method of coke cooling must hardpipe
the overflow water or otherwise prevent
exposure of the overflow water to the
atmosphere when transferring the
overflow water to the overflow water
storage tank whenever the coke drum
vessel temperature exceeds 220 degrees
Fahrenheit. The overflow water storage
tank may be an open or fixed-roof tank
provided that a submerged fill pipe
(pipe outlet below existing liquid level
in the tank) is used to transfer overflow
water to the tank. The owner or operator
of a delayed coking unit using the
‘‘water overflow’’ method of coke
cooling shall determine the coke drum
vessel temperature as specified in
paragraphs (c) and (d) of this section
regardless of the compliance method
used to demonstrate compliance with
the requirements in paragraph (a) of this
section.
(f) The owner or operator of a delayed
coking unit may partially drain a coke
drum prior to achieving the applicable
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
limits in paragraph (a) of this section in
order to double-quench a coke drum
that did not cool adequately using the
normal cooling process steps provided
that the owner or operator meets the
conditions in paragraphs (f)(1) and (2) of
this section.
(1) The owner or operator shall
install, operate, calibrate, and maintain
a continuous parameter monitoring
system to measure the drain water
temperature at the bottom of the coke
drum or in the drain line as near as
practical to the coke drum according to
the requirements specified in table 13 of
this subpart.
(2) The owner or operator must
maintain the drain water temperature
below 210 degrees Fahrenheit during
the partial drain associated with the
double-quench event.
■ 30. Section 63.658 is added to read as
follows:
§ 63.658
Fenceline monitoring provisions.
(a) The owner or operator shall
conduct sampling along the facility
property boundary and analyze the
samples in accordance with Methods
325A and 325B of appendix A of this
part and paragraphs (b) through (k) of
this section.
(b) The target analyte is benzene.
(c) The owner or operator shall
determine passive monitor locations in
accordance with Section 8.2 of Method
325A of appendix A of this part.
(1) As it pertains to this subpart,
known sources of VOCs, as used in
Section 8.2.1.3 in Method 325A of
appendix A of this part for siting
passive monitors means a wastewater
treatment unit, process unit, or any
emission source requiring control
according to the requirements of this
subpart, including marine vessel
loading operations. For marine loading
operations that are located offshore, one
passive monitor should be sited on the
shoreline adjacent to the dock.
(2) The owner or operator may collect
one or more background samples if the
owner or operator believes that an
offsite upwind source or an onsite
source excluded under § 63.640(g) may
influence the sampler measurements. If
the owner or operator elects to collect
one or more background samples, the
owner of operator must develop and
submit a site-specific monitoring plan
for approval according to the
requirements in paragraph (i) of this
section. Upon approval of the sitespecific monitoring plan, the
background sampler(s) should be
operated co-currently with the routine
samplers.
(3) The owner or operator shall collect
at least one co-located duplicate sample
PO 00000
Frm 00078
Fmt 4701
Sfmt 4700
for every 10 field samples per sampling
period and at least two field blanks per
sampling period, as described in Section
9.3 in Method 325A of appendix A of
this part. The co-located duplicates may
be collected at any one of the perimeter
sampling locations.
(4) The owner or operator shall follow
the procedure in Section 9.6 of Method
325B of appendix A of this part to
determine the detection limit of benzene
for each sampler used to collect
samples, background samples (if the
owner or operator elects to do so), colocated samples and blanks.
(d) The owner or operator shall collect
and record meteorological data
according to the applicable
requirements in paragraphs (d)(1)
through (3) of this section.
(1) If a near-field source correction is
used as provided in paragraph (i)(1) of
this section or if an alternative test
method is used that provides timeresolved measurements, the owner or
operator shall:
(i) Use an on-site meteorological
station in accordance with Section 8.3
of Method 325A of appendix A of this
part.
(ii) Collect and record hourly average
meteorological data, including
temperature, barometric pressure, wind
speed and wind direction and calculate
daily unit vector wind direction and
daily sigma theta.
(2) For cases other than those
specified in paragraph (d)(1) of this
section, the owner or operator shall
collect and record sampling period
average temperature and barometric
pressure using either an on-site
meteorological station in accordance
with Section 8.3 of Method 325A of
appendix A of this part or, alternatively,
using data from a United States Weather
Service (USWS) meteorological station
provided the USWS meteorological
station is within 40 kilometers (25
miles) of the refinery.
(3) If an on-site meteorological station
is used, the owner or operator shall
follow the calibration and
standardization procedures for
meteorological measurements in EPA–
454/B–08–002 (incorporated by
reference—see § 63.14).
(e) The owner of operator shall use a
sampling period and sampling
frequency as specified in paragraphs
(e)(1) through (3) of this section.
(1) Sampling period. A 14-day
sampling period shall be used, unless a
shorter sampling period is determined
to be necessary under paragraph (g) or
(i) of this section. A sampling period is
defined as the period during which
sampling tube is deployed at a specific
sampling location with the diffusive
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
sampling end cap in-place and does not
include the time required to analyze the
sample. For the purpose of this subpart,
a 14-day sampling period may be no
shorter than 13 calendar days and no
longer than 15 calendar days, but the
routine sampling period shall be 14
calendar days.
(2) Base sampling frequency. Except
as provided in paragraph (e)(3) of this
section, the frequency of sample
collection shall be once each contiguous
14-day sampling period, such that the
beginning of the next 14-day sampling
period begins immediately upon the
completion of the previous 14-day
sampling period.
(3) Alternative sampling frequency for
burden reduction. When an individual
monitor consistently achieves results at
or below 0.9 mg/m3, the owner or
operator may elect to use the applicable
minimum sampling frequency specified
in paragraphs (e)(3)(i) through (v) of this
section for that monitoring site. When
calculating Dc for the monitoring period
when using this alternative for burden
reduction, zero shall be substituted for
the sample result for the monitoring site
for any period where a sample is not
taken.
(i) If every sample at a monitoring site
is at or below 0.9 mg/m3 for 2 years (52
consecutive samples), every other
sampling period can be skipped for that
monitoring site, i.e., sampling will occur
approximately once per month.
(ii) If every sample at a monitoring
site that is monitored at the frequency
specified in paragraph (e)(3)(i) of this
section is at or below 0.9 mg/m3 for 2
years (i.e., 26 consecutive ‘‘monthly’’
samples), five 14-day sampling periods
can be skipped for that monitoring site
following each period of sampling, i.e.,
sampling will occur approximately once
per quarter.
(iii) If every sample at a monitoring
site that is monitored at the frequency
specified in paragraph (e)(3)(ii) of this
section is at or below 0.9 mg/m3 for 2
years (i.e., 8 consecutive quarterly
samples), twelve 14-day sampling
periods can be skipped for that
monitoring site following each period of
sampling, i.e., sampling will occur twice
a year.
(iv) If every sample at a monitoring
site that is monitored at the frequency
specified in paragraph (e)(3)(iii) of this
section is at or below 0.9 mg/m3 for an
2 years (i.e., 4 consecutive semi-annual
samples), only one sample per year is
required for that monitoring site. For
yearly sampling, samples shall occur at
least 10 months but no more than 14
months apart.
(v) If at any time a sample for a
monitoring site that is monitored at the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
frequency specified in paragraphs
(e)(3)(i) through (iv) of this section
returns a result that is above 0.9 mg/m3,
the sampling site must return to the
original sampling requirements of
contiguous 14-day sampling periods
with no skip periods for one quarter (six
14-day sampling periods). If every
sample collected during this quarter is
at or below 0.9 mg/m3 , the owner or
operator may revert back to the reduced
monitoring schedule applicable for that
monitoring site prior to the sample
reading exceeding 0.9 mg/m3 If any
sample collected during this quarter is
above 0.9 mg/m3, that monitoring site
must return to the original sampling
requirements of contiguous 14-day
sampling periods with no skip periods
for a minimum of two years. The burden
reduction requirements can be used
again for that monitoring site once the
requirements of paragraph (e)(3)(i) of
this section are met again, i.e., after 52
contiguous 14-day samples with no
results above 0.9 mg/m3 .
(f) Within 45 days of completion of
each sampling period, the owner or
operator shall determine whether the
results are above or below the action
level as follows:
(1) The owner or operator shall
determine the facility impact on the
benzene concentration (Dc) for each 14day sampling period according to either
paragraph (f)(1)(i) or (ii) of this section,
as applicable.
(i) Except when near-field source
correction is used as provided in
paragraph (i) of this section, the owner
or operator shall determine the highest
and lowest sample results for benzene
concentrations from the sample pool
and calculate Dc as the difference in
these concentrations. The owner or
operator shall adhere to the following
procedures when one or more samples
for the sampling period are below the
method detection limit for benzene:
(A) If the lowest detected value of
benzene is below detection, the owner
or operator shall use zero as the lowest
sample result when calculating Dc.
(B) If all sample results are below the
method detection limit, the owner or
operator shall use the method detection
limit as the highest sample result.
(ii) When near-field source correction
is used as provided in paragraph (i) of
this section, the owner or operator shall
determine Dc using the calculation
protocols outlined in the approved sitespecific monitoring plan and in
paragraph (i) of this section.
(2) The owner or operator shall
calculate the annual average Dc based
on the average of the 26 most recent 14day sampling periods. The owner or
operator shall update this annual
PO 00000
Frm 00079
Fmt 4701
Sfmt 4700
75255
average value after receiving the results
of each subsequent 14-day sampling
period.
(3) The action level for benzene is 9
micrograms per cubic meter (mg/m3) on
an annual average basis. If the annual
average Dc value for benzene is less than
or equal to 9 mg/m3, the concentration
is below the action level. If the annual
average Dc value for benzene is greater
than 9 mg/m3, the concentration is above
the action level, and the owner or
operator shall conduct a root cause
analysis and corrective action in
accordance with paragraph (g) of this
section.
(g) Within 5 days of determining that
the action level has been exceeded for
any annual average Dc and no longer
than 50 days after completion of the
sampling period, the owner or operator
shall initiate a root cause analysis to
determine the cause of such exceedance
and to determine appropriate corrective
action, such as those described in
paragraphs (g)(1) through (4) of this
section. The root cause analysis and
initial corrective action analysis shall be
completed and initial corrective actions
taken no later than 45 days after
determining there is an exceedance.
Root cause analysis and corrective
action may include, but is not limited
to:
(1) Leak inspection using Method 21
of part 60, appendix A–7 of this chapter
and repairing any leaks found.
(2) Leak inspection using optical gas
imaging and repairing any leaks found.
(3) Visual inspection to determine the
cause of the high benzene emissions and
implementing repairs to reduce the level
of emissions.
(4) Employing progressively more
frequent sampling, analysis and
meteorology (e.g., using shorter
sampling periods for Methods 325A and
325B of appendix A of this part, or
using active sampling techniques).
(h) If, upon completion of the
corrective action analysis and corrective
actions such as those described in
paragraph (g) of this section, the Dc
value for the next 14-day sampling
period for which the sampling start time
begins after the completion of the
corrective actions is greater than 9 mg/
m3 or if all corrective action measures
identified require more than 45 days to
implement, the owner or operator shall
develop a corrective action plan that
describes the corrective action(s)
completed to date, additional measures
that the owner or operator proposes to
employ to reduce fenceline
concentrations below the action level,
and a schedule for completion of these
measures. The owner or operator shall
submit the corrective action plan to the
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75256
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Administrator within 60 days after
receiving the analytical results
indicating that the Dc value for the 14day sampling period following the
completion of the initial corrective
action is greater than 9 mg/m3 or, if no
initial corrective actions were
identified, no later than 60 days
following the completion of the
corrective action analysis required in
paragraph (g) of this section.
(i) An owner or operator may request
approval from the Administrator for a
site-specific monitoring plan to account
for offsite upwind sources or onsite
sources excluded under § 63.640(g)
according to the requirements in
paragraphs (i)(1) through (4) of this
section.
(1) The owner or operator shall
prepare and submit a site-specific
monitoring plan and receive approval of
the site-specific monitoring plan prior to
using the near-field source alternative
calculation for determining Dc provided
in paragraph (i)(2) of this section. The
site-specific monitoring plan shall
include, at a minimum, the elements
specified in paragraphs (i)(1)(i) through
(v) of this section. The procedures in
Section 12 of Method 325A of appendix
A of this part are not required, but may
be used, if applicable, when
determining near-field source
contributions.
(i) Identification of the near-field
source or sources. For onsite sources,
documentation that the onsite source is
excluded under § 63.640(g) and
identification of the specific provision
in § 63.640(g) that applies to the source.
(ii) Location of the additional
monitoring stations that shall be used to
determine the uniform background
concentration and the near-field source
concentration contribution.
(iii) Identification of the fenceline
monitoring locations impacted by the
near-field source. If more than one nearfield source is present, identify the nearfield source or sources that are expected
to contribute to the concentration at that
monitoring location.
(iv) A description of (including
sample calculations illustrating) the
planned data reduction and calculations
to determine the near-field source
concentration contribution for each
monitoring location.
(v) If more frequent monitoring or a
monitoring station other than a passive
diffusive tube monitoring station is
proposed, provide a detailed description
of the measurement methods,
measurement frequency, and recording
frequency for determining the uniform
background or near-field source
concentration contribution.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(2) When an approved site-specific
monitoring plan is used, the owner or
operator shall determine Dc for
comparison with the 9 mg/m3 action
level using the requirements specified
in paragraphs (i)(2)(i) through (iii) of
this section.
(i) For each monitoring location,
calculate Dci using the following
equation.
Dci = MFCi ¥ NFSi ¥ UB
Where:
Dci = The fenceline concentration, corrected
for background, at measurement location
i, micrograms per cubic meter (mg/m3).
MFCi = The measured fenceline
concentration at measurement location i,
mg/m3.
NFSi = The near-field source contributing
concentration at measurement location i
determined using the additional
measurements and calculation
procedures included in the site-specific
monitoring plan, mg/m3. For monitoring
locations that are not included in the
site-specific monitoring plan as impacted
by a near-field source, use NFSi = 0 mg/
m3.
UB = The uniform background concentration
determined using the additional
measurements included in the sitespecific monitoring plan, mg/m3. If no
additional measurements are specified in
the site-specific monitoring plan for
determining the uniform background
concentration, use UB = 0 mg/m3.
(ii) When one or more samples for the
sampling period are below the method
detection limit for benzene, adhere to
the following procedures:
(A) If the benzene concentration at the
monitoring location used for the
uniform background concentration is
below the method detection limit, the
owner or operator shall use zero for UB
for that monitoring period.
(B) If the benzene concentration at the
monitoring location(s) used to
determine the near-field source
contributing concentration is below the
method detection limit, the owner or
operator shall use zero for the
monitoring location concentration when
calculating NFSi for that monitoring
period.
(C) If a fenceline monitoring location
sample result is below the method
detection limit, the owner or operator
shall use the method detection limit as
the sample result.
(iii) Determine Dc for the monitoring
period as the maximum value of Dci
from all of the fenceline monitoring
locations for that monitoring period.
(3) The site-specific monitoring plan
shall be submitted and approved as
described in paragraphs (i)(3)(i) through
(iv) of this section.
PO 00000
Frm 00080
Fmt 4701
Sfmt 4700
(i) The site-specific monitoring plan
must be submitted to the Administrator
for approval.
(ii) The site-specific monitoring plan
shall also be submitted to the following
address: U.S. Environmental Protection
Agency, Office of Air Quality Planning
and Standards, Sector Policies and
Programs Division, U.S. EPA Mailroom
(E143–01), Attention: Refinery Sector
Lead, 109 T.W. Alexander Drive,
Research Triangle Park, NC 27711.
Electronic copies in lieu of hard copies
may also be submitted to refineryrtr@
epa.gov.
(iii) The Administrator shall approve
or disapprove the plan in 90 days. The
plan shall be considered approved if the
Administrator either approves the plan
in writing, or fails to disapprove the
plan in writing. The 90-day period shall
begin when the Administrator receives
the plan.
(iv) If the Administrator finds any
deficiencies in the site-specific
monitoring plan and disapproves the
plan in writing, the owner or operator
may revise and resubmit the sitespecific monitoring plan following the
requirements in paragraphs (i)(3)(i) and
(ii) of this section. The 90-day period
starts over with the resubmission of the
revised monitoring plan.
(4) The approval by the Administrator
of a site-specific monitoring plan will be
based on the completeness, accuracy
and reasonableness of the request for a
site-specific monitoring plan. Factors
that the Administrator will consider in
reviewing the request for a site-specific
monitoring plan include, but are not
limited to, those described in
paragraphs (i)(4)(i) through (v) of this
section.
(i) The identification of the near-field
source or sources. For onsite sources,
the documentation provided that the
onsite source is excluded under
§ 63.640(g).
(ii) The monitoring location selected
to determine the uniform background
concentration or an indication that no
uniform background concentration
monitor will be used.
(iii) The location(s) selected for
additional monitoring to determine the
near-field source concentration
contribution.
(iv) The identification of the fenceline
monitoring locations impacted by the
near-field source or sources.
(v) The appropriateness of the
planned data reduction and calculations
to determine the near-field source
concentration contribution for each
monitoring location.
(vi) If more frequent monitoring is
proposed, the adequacy of the
description of the measurement and
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
recording frequency proposed and the
adequacy of the rationale for using the
alternative monitoring frequency.
(j) The owner or operator shall
comply with the applicable
recordkeeping and reporting
requirements in § 63.655(h) and (i).
(k) As outlined in § 63.7(f), the owner
or operator may submit a request for an
alternative test method. At a minimum,
the request must follow the
requirements outlined in paragraphs
(k)(1) through (7) of this section.
(1) The alternative method may be
used in lieu of all or a partial number
of passive samplers required in Method
325A of appendix A of this part.
(2) The alternative method must be
validated according to Method 301 in
appendix A of this part or contain
performance based procedures and
indicators to ensure self-validation.
(3) The method detection limit must
nominally be at least an order of
magnitude below the action level, i.e.,
0.9 mg/m3 benzene. The alternate test
method must describe the procedures
used to provide field verification of the
detection limit.
(4) The spatial coverage must be equal
to or better than the spatial coverage
provided in Method 325A of appendix
A of this part.
(i) For path average concentration
open-path instruments, the physical
path length of the measurement shall be
no more than a passive sample footprint
(the spacing that would be provided by
the sorbent traps when following
Method 325A). For example, if Method
325A requires spacing monitors A and
B 610 meters (2000 feet) apart, then the
physical path length limit for the
measurement at that portion of the
fenceline shall be no more than 610
meters (2000 feet).
(ii) For range resolved open-path
instrument or approach, the instrument
or approach must be able to resolve an
average concentration over each passive
sampler footprint within the path length
of the instrument.
(iii) The extra samplers required in
Sections 8.2.1.3 of Method 325A may be
omitted when they fall within the path
length of an open-path instrument.
(5) At a minimum, non-integrating
alternative test methods must provide a
minimum of one cycle of operation
(sampling, analyzing, and data
recording) for each successive 15minute period.
(6) For alternative test methods
capable of real time measurements (less
than a 5 minute sampling and analysis
cycle), the alternative test method may
allow for elimination of data points
corresponding to outside emission
sources for purpose of calculation of the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
high point for the two week average.
The alternative test method approach
must have wind speed, direction and
stability class of the same time
resolution and within the footprint of
the instrument.
(7) For purposes of averaging data
points to determine the Dc for the 14day average high sample result, all
results measured under the method
detection limit must use the method
detection limit. For purposes of
averaging data points for the 14-day
average low sample result, all results
measured under the method detection
limit must use zero.
■ 31. Section 63.660 is added to read as
follows:
§ 63.660
Storage vessel provisions.
On and after the applicable
compliance date for a Group 1 storage
vessel located at a new or existing
source as specified in § 63.640(h), the
owner or operator of a Group 1 storage
vessel that is part of a new or existing
source shall comply with the
requirements in subpart WW or SS of
this part according to the requirements
in paragraphs (a) through (i) of this
section.
(a) As used in this section, all terms
not defined in § 63.641 shall have the
meaning given them in subpart A, WW,
or SS of this part. The definitions of
‘‘Group 1 storage vessel’’ (paragraph (2))
and ‘‘Storage vessel’’ in § 63.641 shall
apply in lieu of the definition of
‘‘Storage vessel’’ in § 63.1061.
(1) An owner or operator may use
good engineering judgment or test
results to determine the stored liquid
weight percent total organic HAP for
purposes of group determination. Data,
assumptions, and procedures used in
the determination shall be documented.
(2) When an owner or operator and
the Administrator do not agree on
whether the annual average weight
percent organic HAP in the stored liquid
is above or below 4 percent for a storage
vessel at an existing source or above or
below 2 percent for a storage vessel at
a new source, an appropriate method
(based on the type of liquid stored) as
published by EPA or a consensus-based
standards organization shall be used.
Consensus-based standards
organizations include, but are not
limited to, the following: ASTM
International (100 Barr Harbor Drive,
P.O. Box CB700, West Conshohocken,
Pennsylvania 19428–B2959, (800) 262–
1373, https://www.astm.org), the
American National Standards Institute
(ANSI, 1819 L Street NW., 6th Floor,
Washington, DC 20036, (202) 293–8020,
https://www.ansi.org), the American Gas
Association (AGA, 400 North Capitol
PO 00000
Frm 00081
Fmt 4701
Sfmt 4700
75257
Street NW., 4th Floor, Washington, DC
20001, (202) 824–7000, https://
www.aga.org), the American Society of
Mechanical Engineers (ASME, Three
Park Avenue, New York, NY 10016–
5990, (800) 843–2763, https://
www.asme.org), the American
Petroleum Institute (API, 1220 L Street
NW., Washington, DC 20005–4070,
(202) 682–8000, https://www.api.org),
and the North American Energy
Standards Board (NAESB, 801 Travis
Street, Suite 1675, Houston, TX 77002,
(713) 356–0060, https://www.naesb.org).
(b) A floating roof storage vessel
complying with the requirements of
subpart WW of this part may comply
with the control option specified in
paragraph (b)(1) of this section and, if
equipped with a ladder having at least
one slotted leg, shall comply with one
of the control options as described in
paragraph (b)(2) of this section.
(1) In addition to the options
presented in §§ 63.1063(a)(2)(viii)(A)
and (B) and 63.1064, a floating roof
storage vessel may comply with
§ 63.1063(a)(2)(vii) using a flexible
enclosure device and either a gasketed
or welded cap on the top of the
guidepole.
(2) Each opening through a floating
roof for a ladder having at least one
slotted leg shall be equipped with one
of the configurations specified in
paragraphs (b)(2)(i) through (iii) of this
section.
(i) A pole float in the slotted leg and
pole wipers for both legs. The wiper or
seal of the pole float must be at or above
the height of the pole wiper.
(ii) A ladder sleeve and pole wipers
for both legs of the ladder.
(iii) A flexible enclosure device and
either a gasketed or welded cap on the
top of the slotted leg.
(c) For the purposes of this subpart,
references shall apply as specified in
paragraphs (c)(1) through (6) of this
section.
(1) All references to ‘‘the proposal
date for a referencing subpart’’ and ‘‘the
proposal date of the referencing
subpart’’ in subpart WW of this part
mean June 30, 2014.
(2) All references to ‘‘promulgation of
the referencing subpart’’ and ‘‘the
promulgation date of the referencing
subpart’’ in subpart WW of this part
mean February 1, 2016.
(3) All references to ‘‘promulgation
date of standards for an affected source
or affected facility under a referencing
subpart’’ in subpart SS of this part mean
February 1, 2016.
(4) All references to ‘‘the proposal
date of the relevant standard established
pursuant to CAA section 112(f)’’ in
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
subpart SS of this part mean June 30,
2014.
(5) All references to ‘‘the proposal
date of a relevant standard established
pursuant to CAA section 112(d)’’ in
subpart SS of this part mean July 14,
1994.
(6) All references to the ‘‘required
control efficiency’’ in subpart SS of this
part mean reduction of organic HAP
emissions by 95 percent or to an outlet
concentration of 20 ppmv.
(d) For an uncontrolled fixed roof
storage vessel that commenced
construction on or before June 30, 2014,
and that meets the definition of ‘‘Group
1 storage vessel’’, paragraph (2), in
§ 63.641 but not the definition of
‘‘Group 1 storage vessel’’, paragraph (1),
in § 63.641, the requirements of § 63.982
and/or § 63.1062 do not apply until the
next time the storage vessel is
completely emptied and degassed, or
January 30, 2026, whichever occurs
first.
(e) Failure to perform inspections and
monitoring required by this section
shall constitute a violation of the
applicable standard of this subpart.
(f) References in § 63.1066(a) to initial
startup notification requirements do not
apply.
(g) References to the Notification of
Compliance Status in § 63.999(b) mean
the Notification of Compliance Status
required by § 63.655(f).
(h) References to the Periodic Reports
in §§ 63.1066(b) and 63.999(c) mean the
Periodic Report required by § 63.655(g).
(i) Owners or operators electing to
comply with the requirements in
subpart SS of this part for a Group 1
storage vessel must comply with the
requirements in paragraphs (i)(1)
through (3) of this section.
(1) If a flare is used as a control
device, the flare shall meet the
requirements of § 63.670 instead of the
flare requirements in § 63.987.
(2) If a closed vent system contains a
bypass line, the owner or operator shall
comply with the provisions of either
§ 63.983(a)(3)(i) or (ii) for each closed
vent system that contains bypass lines
that could divert a vent stream either
directly to the atmosphere or to a
control device that does not comply
with the requirements in subpart SS of
this part. Except as provided in
paragraphs (i)(2)(i) and (ii) of this
section, use of the bypass at any time to
divert a Group 1 storage vessel to either
directly to the atmosphere or to a
control device that does not comply
with the requirements in subpart SS of
this part is an emissions standards
violation. Equipment such as low leg
drains and equipment subject to
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
§ 63.648 are not subject to this
paragraph (i)(2).
(i) If planned routine maintenance of
the control device cannot be performed
during periods that storage vessel
emissions are vented to the control
device or when the storage vessel is
taken out of service for inspections or
other planned maintenance reasons, the
owner or operator may bypass the
control device.
(ii) Periods for which storage vessel
control device may be bypassed for
planned routine maintenance of the
control device shall not exceed 240
hours per calendar year.
(3) If storage vessel emissions are
routed to a fuel gas system or process,
the fuel gas system or process shall be
operating at all times when regulated
emissions are routed to it. The
exception in § 63.984(a)(1) does not
apply.
■ 32. Section 63.670 is added to read as
follows:
§ 63.670 Requirements for flare control
devices.
On or before January 30, 2019, the
owner or operator of a flare used as a
control device for an emission point
subject to this subpart shall meet the
applicable requirements for flares as
specified in paragraphs (a) through (q)
of this section and the applicable
requirements in § 63.671. The owner or
operator may elect to comply with the
requirements of paragraph (r) of this
section in lieu of the requirements in
paragraphs (d) through (f) of this
section, as applicable.
(a) [Reserved]
(b) Pilot flame presence. The owner or
operator shall operate each flare with a
pilot flame present at all times when
regulated material is routed to the flare.
Each 15-minute block during which
there is at least one minute where no
pilot flame is present when regulated
material is routed to the flare is a
deviation of the standard. Deviations in
different 15-minute blocks from the
same event are considered separate
deviations. The owner or operator shall
monitor for the presence of a pilot flame
as specified in paragraph (g) of this
section.
(c) Visible emissions. The owner or
operator shall specify the smokeless
design capacity of each flare and operate
with no visible emissions, except for
periods not to exceed a total of 5
minutes during any 2 consecutive
hours, when regulated material is routed
to the flare and the flare vent gas flow
rate is less than the smokeless design
capacity of the flare. The owner or
operator shall monitor for visible
PO 00000
Frm 00082
Fmt 4701
Sfmt 4700
emissions from the flare as specified in
paragraph (h) of this section.
(d) Flare tip velocity. For each flare,
the owner or operator shall comply with
either paragraph (d)(1) or (2) of this
section, provided the appropriate
monitoring systems are in-place,
whenever regulated material is routed to
the flare for at least 15-minutes and the
flare vent gas flow rate is less than the
smokeless design capacity of the flare.
(1) Except as provided in paragraph
(d)(2) of this section, the actual flare tip
velocity (Vtip) must be less than 60 feet
per second. The owner or operator shall
monitor Vtipusing the procedures
specified in paragraphs (i) and (k) of this
section.
(2) Vtip must be less than 400 feet per
second and also less than the maximum
allowed flare tip velocity (Vmax) as
calculated according to the following
equation. The owner or operator shall
monitor Vtip using the procedures
specified in paragraphs (i) and (k) of this
section and monitor gas composition
and determine NHVvg using the
procedures specified in paragraphs (j)
and (l) of this section.
Where:
Vmax = Maximum allowed flare tip velocity,
ft/sec.
NHVvg = Net heating value of flare vent gas,
as determined by paragraph (l)(4) of this
section, Btu/scf.
1,212 = Constant.
850 = Constant.
(e) Combustion zone operating limits.
For each flare, the owner or operator
shall operate the flare to maintain the
net heating value of flare combustion
zone gas (NHVcz) at or above 270 British
thermal units per standard cubic feet
(Btu/scf) determined on a 15-minute
block period basis when regulated
material is routed to the flare for at least
15-minutes. The owner or operator shall
monitor and calculate NHVcz as
specified in paragraph (m) of this
section.
(f) Dilution operating limits for flares
with perimeter assist air. For each flare
actively receiving perimeter assist air,
the owner or operator shall operate the
flare to maintain the net heating value
dilution parameter (NHVdil) at or above
22 British thermal units per square foot
(Btu/ft2) determined on a 15-minute
block period basis when regulated
material is being routed to the flare for
at least 15-minutes. The owner or
operator shall monitor and calculate
NHVdil as specified in paragraph (n) of
this section.
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.008
tkelley on DSK3SPTVN1PROD with RULES2
75258
(g) Pilot flame monitoring. The owner
or operator shall continuously monitor
the presence of the pilot flame(s) using
a device (including, but not limited to,
a thermocouple, ultraviolet beam
sensor, or infrared sensor) capable of
detecting that the pilot flame(s) is
present.
(h) Visible emissions monitoring. The
owner or operator shall monitor visible
emissions while regulated materials are
vented to the flare. An initial visible
emissions demonstration must be
conducted using an observation period
of 2 hours using Method 22 at 40 CFR
part 60, appendix A–7. Subsequent
visible emissions observations must be
conducted using either the methods in
paragraph (h)(1) of this section or,
alternatively, the methods in paragraph
(h)(2) of this section. The owner or
operator must record and report any
instances where visible emissions are
observed for more than 5 minutes
during any 2 consecutive hours as
specified in § 63.655(g)(11)(ii).
(1) At least once per day, conduct
visible emissions observations using an
observation period of 5 minutes using
Method 22 at 40 CFR part 60, appendix
A–7. If at any time the owner or
operator sees visible emissions, even if
the minimum required daily visible
emission monitoring has already been
performed, the owner or operator shall
immediately begin an observation
period of 5 minutes using Method 22 at
40 CFR part 60, appendix A–7. If visible
emissions are observed for more than
one continuous minute during any 5minute observation period, the
observation period using Method 22 at
40 CFR part 60, appendix A–7 must be
extended to 2 hours or until 5-minutes
of visible emissions are observed.
(2) Use a video surveillance camera to
continuously record (at least one frame
every 15 seconds with time and date
stamps) images of the flare flame and a
reasonable distance above the flare
flame at an angle suitable for visual
emissions observations. The owner or
operator must provide real-time video
surveillance camera output to the
control room or other continuously
manned location where the camera
images may be viewed at any time.
(i) Flare vent gas, steam assist and air
assist flow rate monitoring. The owner
or operator shall install, operate,
calibrate, and maintain a monitoring
system capable of continuously
measuring, calculating, and recording
the volumetric flow rate in the flare
header or headers that feed the flare as
well as any supplemental natural gas
used. Different flow monitoring
methods may be used to measure
different gaseous streams that make up
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
the flare vent gas provided that the flow
rates of all gas streams that contribute to
the flare vent gas are determined. If
assist air or assist steam is used, the
owner or operator shall install, operate,
calibrate, and maintain a monitoring
system capable of continuously
measuring, calculating, and recording
the volumetric flow rate of assist air
and/or assist steam used with the flare.
If pre-mix assist air and perimeter assist
are both used, the owner or operator
shall install, operate, calibrate, and
maintain a monitoring system capable of
separately measuring, calculating, and
recording the volumetric flow rate of
premix assist air and perimeter assist air
used with the flare. Continuously
monitoring fan speed or power and
using fan curves is an acceptable
method for continuously monitoring
assist air flow rates.
(1) The flow rate monitoring systems
must be able to correct for the
temperature and pressure of the system
and output parameters in standard
conditions (i.e., a temperature of 20 °C
(68 °F) and a pressure of 1 atmosphere).
(2) Mass flow monitors may be used
for determining volumetric flow rate of
flare vent gas provided the molecular
weight of the flare vent gas is
determined using compositional
analysis as specified in paragraph (j) of
this section so that the mass flow rate
can be converted to volumetric flow at
standard conditions using the following
equation.
Where:
Qvol = Volumetric flow rate, standard cubic
feet per second.
Qmass = Mass flow rate, pounds per second.
385.3 = Conversion factor, standard cubic
feet per pound-mole.
MWt = Molecular weight of the gas at the
flow monitoring location, pounds per
pound-mole.
(3) Mass flow monitors may be used
for determining volumetric flow rate of
assist air or assist steam. Use equation
in paragraph (i)(2) of this section to
convert mass flow rates to volumetric
flow rates. Use a molecular weight of 18
pounds per pound-mole for assist steam
and use a molecular weight of 29
pounds per pound-mole for assist air.
(4) Continuous pressure/temperature
monitoring system(s) and appropriate
engineering calculations may be used in
lieu of a continuous volumetric flow
monitoring systems provided the
molecular weight of the gas is known.
For assist steam, use a molecular weight
of 18 pounds per pound-mole. For assist
air, use a molecular weight of 29 pounds
PO 00000
Frm 00083
Fmt 4701
Sfmt 4700
75259
per pound-mole. For flare vent gas,
molecular weight must be determined
using compositional analysis as
specified in paragraph (j) of this section.
(j) Flare vent gas composition
monitoring. The owner or operator shall
determine the concentration of
individual components in the flare vent
gas using either the methods provided
in paragraph (j)(1) or (2) of this section,
to assess compliance with the operating
limits in paragraph (e) of this section
and, if applicable, paragraphs (d) and (f)
of this section. Alternatively, the owner
or operator may elect to directly monitor
the net heating value of the flare vent
gas following the methods provided in
paragraphs (j)(3) of this section and, if
desired, may directly measure the
hydrogen concentration in the flare vent
gas following the methods provided in
paragraphs (j)(4) of this section. The
owner or operator may elect to use
different monitoring methods for
different gaseous streams that make up
the flare vent gas using different
methods provided the composition or
net heating value of all gas streams that
contribute to the flare vent gas are
determined.
(1) Except as provided in paragraphs
(j)(5) and (6) of this section, the owner
or operator shall install, operate,
calibrate, and maintain a monitoring
system capable of continuously
measuring (i.e., at least once every 15minutes), calculating, and recording the
individual component concentrations
present in the flare vent gas.
(2) Except as provided in paragraphs
(j)(5) and (6) of this section, the owner
or operator shall install, operate, and
maintain a grab sampling system
capable of collecting an evacuated
canister sample for subsequent
compositional analysis at least once
every eight hours while there is flow of
regulated material to the flare.
Subsequent compositional analysis of
the samples must be performed
according to Method 18 of 40 CFR part
60, appendix A–6, ASTM D6420–99
(Reapproved 2010), ASTM D1945–03
(Reapproved 2010), ASTM D1945–14 or
ASTM UOP539–12 (all incorporated by
reference—see § 63.14).
(3) Except as provided in paragraphs
(j)(5) and (6) of this section, the owner
or operator shall install, operate,
calibrate, and maintain a calorimeter
capable of continuously measuring,
calculating, and recording NHVvg at
standard conditions.
(4) If the owner or operator uses a
continuous net heating value monitor
according to paragraph (j)(3) of this
section, the owner or operator may, at
their discretion, install, operate,
calibrate, and maintain a monitoring
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.009
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
75260
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
system capable of continuously
measuring, calculating, and recording
the hydrogen concentration in the flare
vent gas.
(5) Direct compositional or net
heating value monitoring is not required
for purchased (‘‘pipeline quality’’)
natural gas streams. The net heating
value of purchased natural gas streams
may be determined using annual or
more frequent grab sampling at any one
representative location. Alternatively,
the net heating value of any purchased
natural gas stream can be assumed to be
920 Btu/scf.
(6) Direct compositional or net
heating value monitoring is not required
for gas streams that have been
demonstrated to have consistent
composition (or a fixed minimum net
heating value) according to the methods
in paragraphs (j)(6)(i) through (v) of this
section.
(i) The owner or operator shall submit
to the Administrator a written
application for an exemption from
monitoring. The application must
contain the following information:
(A) A description of the flare gas
stream/system to be considered,
including submission of a portion of the
appropriate piping diagrams indicating
the boundaries of the flare gas stream/
system and the affected flare(s) to be
considered;
(B) A statement that there are no
crossover or entry points to be
introduced into the flare gas stream/
system (this should be shown in the
piping diagrams) prior to the point
where the flow rate of the gas streams
is measured;
(C) An explanation of the conditions
that ensure that the flare gas net heating
value is consistent and, if flare gas net
heating value is expected to vary (e.g.,
due to product loading of different
material), the conditions expected to
produce the flare gas with the lowest net
heating value;
(D) The supporting test results from
sampling the requested flare gas stream/
system for the net heating value.
Sampling data must include, at
minimum, 2 weeks of daily
measurement values (14 grab samples)
for frequently operated flare gas
streams/systems; for infrequently
operated flare gas streams/systems,
seven grab samples must be collected
unless other additional information
would support reduced sampling. If the
flare gas stream composition can vary,
samples must be taken during those
conditions expected to result in lowest
net heating value identified in
paragraph (j)(6)(i)(C) of this section. The
owner or operator shall determine net
heating value for the gas stream using
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
either gas composition analysis or net
heating value monitor (with optional
hydrogen concentration analyzer)
according to the method provided in
paragraph (l) of this section; and
(E) A description of how the 2 weeks
(or seven samples for infrequently
operated flare gas streams/systems) of
monitoring results compares to the
typical range of net heating values
expected for the flare gas stream/system
going to the affected flare (e.g., ‘‘the
samples are representative of typical
operating conditions of the flare gas
stream going to the loading rack flare’’
or ‘‘the samples are representative of
conditions expected to yield the lowest
net heating value of the flare gas stream
going to the loading rack flare’’).
(F) The net heating value to be used
for all flows of the flare vent gas from
the flare gas stream/system covered in
the application. A single net heating
value must be assigned to the flare vent
gas either by selecting the lowest net
heating value measured in the sampling
program or by determining the 95th
percent confidence interval on the mean
value of all samples collected using the
t-distribution statistic (which is 1.943
for 7 grab samples or 1.771 for 14 grab
samples).
(ii) The effective date of the
exemption is the date of submission of
the information required in paragraph
(j)(6)(i) of this section.
(iii) No further action is required
unless refinery operating conditions
change in such a way that affects the
exempt fuel gas stream/system (e.g., the
stream composition changes). If such a
change occurs, the owner or operator
shall follow the procedures in paragraph
(j)(6)(iii)(A), (B), or (C) of this section.
(A) If the operation change results in
a flare vent gas net heating value that is
still within the range of net heating
values included in the original
application, the owner or operator shall
determine the net heating value on a
grab sample and record the results as
proof that the net heating value assigned
to the vent gas stream in the original
application is still appropriate.
(B) If the operation change results in
a flare vent gas net heating value that is
lower than the net heating value
assigned to the vent gas stream in the
original application, the owner or
operator may submit new information
following the procedures of paragraph
(j)(6)(i) of this section within 60 days (or
within 30 days after the seventh grab
sample is tested for infrequently
operated process units).
(C) If the operation change results in
a flare vent gas net heating value has
greater variability in the flare gas
stream/system such the owner or
PO 00000
Frm 00084
Fmt 4701
Sfmt 4700
operator chooses not to submit new
information to support an exemption,
the owner or operator must begin
monitoring the composition or net heat
content of the flare vent gas stream
using the methods in this section (i.e.,
grab samples every 8 hours until such
time a continuous monitor, if elected, is
installed).
(k) Calculation methods for
cumulative flow rates and determining
compliance with Vtip operating limits.
The owner or operator shall determine
Vtip on a 15-minute block average basis
according to the following requirements.
(1) The owner or operator shall use
design and engineering principles to
determine the unobstructed cross
sectional area of the flare tip. The
unobstructed cross sectional area of the
flare tip is the total tip area that vent gas
can pass through. This area does not
include any stability tabs, stability rings,
and upper steam or air tubes because
flare vent gas does not exit through
them.
(2) The owner or operator shall
determine the cumulative volumetric
flow of flare vent gas for each 15-minute
block average period using the data from
the continuous flow monitoring system
required in paragraph (i) of this section
according to the following requirements,
as applicable. If desired, the cumulative
flow rate for a 15-minute block period
only needs to include flow during those
periods when regulated material is sent
to the flare, but owners or operators may
elect to calculate the cumulative flow
rates across the entire 15-minute block
period for any 15-minute block period
where there is regulated material flow to
the flare.
(i) Use set 15-minute time periods
starting at 12 midnight to 12:15 a.m.,
12:15 a.m. to 12:30 a.m. and so on
concluding at 11:45 p.m. to midnight
when calculating 15-minute block
average flow volumes.
(ii) If continuous pressure/
temperature monitoring system(s) and
engineering calculations are used as
allowed under paragraph (i)(4) of this
section, the owner or operator shall, at
a minimum, determine the 15-minute
block average temperature and pressure
from the monitoring system and use
those values to perform the engineering
calculations to determine the
cumulative flow over the 15-minute
block average period. Alternatively, the
owner or operator may divide the 15minute block average period into equal
duration subperiods (e.g., three 5minute periods) and determine the
average temperature and pressure for
each subperiod, perform engineering
calculations to determine the flow for
each subperiod, then add the volumetric
E:\FR\FM\01DER2.SGM
01DER2
Where:
Vtip = Flare tip velocity, feet per second.
Qcum = Cumulative volumetric flow over 15minute block average period, actual
cubic feet.
Area = Unobstructed area of the flare tip,
square feet.
900 = Conversion factor, seconds per 15minute block average.
tkelley on DSK3SPTVN1PROD with RULES2
(4) If the owner or operator chooses to
comply with paragraph (d)(2) of this
section, the owner or operator shall also
determine the net heating value of the
flare vent gas following the
requirements in paragraphs (j) and (l) of
this section and calculate Vmax using the
equation in paragraph (d)(2) of this
section in order to compare Vtip to Vmax
on a 15-minute block average basis.
(l) Calculation methods for
determining flare vent gas net heating
value. The owner or operator shall
determine the net heating value of the
flare vent gas (NHVvg) based on the
composition monitoring data on a 15minute block average basis according to
the following requirements.
(1) If compositional analysis data are
collected as provided in paragraph (j)(1)
or (2) of this section, the owner or
operator shall determine NHVvg of a
specific sample by using the following
equation.
Where:
NHVvg = Net heating value of flare vent gas,
Btu/scf.
i = Individual component in flare vent gas.
n = Number of components in flare vent gas.
xi = Concentration of component i in flare
vent gas, volume fraction.
NHVi = Net heating value of component i
according to table 12 of this subpart, Btu/
scf. If the component is not specified in
table 12 of this subpart, the heats of
combustion may be determined using
any published values where the net
enthalpy per mole of offgas is based on
combustion at 25 °C and 1 atmosphere
(or constant pressure) with offgas water
in the gaseous state, but the standard
temperature for determining the volume
corresponding to one mole of vent gas is
20 °C.
(2) If direct net heating value
monitoring data are collected as
provided in paragraph (j)(3) of this
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
section but a hydrogen concentration
monitor is not used, the owner or
operator shall use the direct output of
the monitoring system(s) (in Btu/scf) to
determine the NHVvg for the sample.
(3) If direct net heating value
monitoring data are collected as
provided in paragraph (j)(3) of this
section and hydrogen concentration
monitoring data are collected as
provided in paragraph (j)(4) of this
section, the owner or operator shall use
the following equation to determine
NHVvg for each sample measured via the
net heating value monitoring system.
NHVvg = NHVmeasured + 938xH2
Where:
NHVvg = Net heating value of flare vent gas,
Btu/scf.
NHVmeasured = Net heating value of flare vent
gas stream as measured by the
continuous net heating value monitoring
system, Btu/scf.
xH2 = Concentration of hydrogen in flare vent
gas at the time the sample was input into
the net heating value monitoring system,
volume fraction.
938 = Net correction for the measured
heating value of hydrogen (1,212 ¥ 274),
Btu/scf.
(4) Use set 15-minute time periods
starting at 12 midnight to 12:15 a.m.,
12:15 a.m. to 12:30 a.m. and so on
concluding at 11:45 p.m. to midnight
when calculating 15-minute block
averages.
(5) When a continuous monitoring
system is used as provided in paragraph
(j)(1) or (3) of this section and, if
applicable, paragraph (j)(4) of this
section, the owner or operator may elect
to determine the 15-minute block
average NHVvg using either the
calculation methods in paragraph
(l)(5)(i) of this section or the calculation
methods in paragraph (l)(5)(ii) of this
section. The owner or operator may
choose to comply using the calculation
methods in paragraph (l)(5)(i) of this
section for some flares at the petroleum
refinery and comply using the
calculation methods (l)(5)(ii) of this
section for other flares. However, for
each flare, the owner or operator must
elect one calculation method that will
apply at all times, and use that method
for all continuously monitored flare
vent streams associated with that flare.
If the owner or operator intends to
change the calculation method that
applies to a flare, the owner or operator
must notify the Administrator 30 days
in advance of such a change.
(i) Feed-forward calculation method.
When calculating NHVvg for a specific
15-minute block:
(A) Use the results from the first
sample collected during an event, (for
PO 00000
Frm 00085
Fmt 4701
Sfmt 4700
periodic flare vent gas flow events) for
the first 15-minute block associated
with that event.
(B) If the results from the first sample
collected during an event (for periodic
flare vent gas flow events) are not
available until after the second 15minute block starts, use the results from
the first sample collected during an
event for the second 15-minute block
associated with that event.
(C) For all other cases, use the results
that are available from the most recent
sample prior to the 15-minute block
period for that 15-minute block period
for all flare vent gas steams. For the
purpose of this requirement, use the
time that the results become available
rather than the time the sample was
collected. For example, if a sample is
collected at 12:25 a.m. and the analysis
is completed at 12:38 a.m., the results
are available at 12:38 a.m. and these
results would be used to determine
compliance during the 15-minute block
period from 12:45 a.m. to 1:00 a.m.
(ii) Direct calculation method. When
calculating NHVvg for a specific 15minute block:
(A) If the results from the first sample
collected during an event (for periodic
flare vent gas flow events) are not
available until after the second 15minute block starts, use the results from
the first sample collected during an
event for the first 15-minute block
associated with that event.
(B) For all other cases, use the
arithmetic average of all NHVvg
measurement data results that become
available during a 15-minute block to
calculate the 15-minute block average
for that period. For the purpose of this
requirement, use the time that the
results become available rather than the
time the sample was collected. For
example, if a sample is collected at
12:25 a.m. and the analysis is completed
at 12:38 a.m., the results are available at
12:38 a.m. and these results would be
used to determine compliance during
the 15-minute block period from 12:30
a.m. to 12:45 a.m.
(6) When grab samples are used to
determine flare vent gas composition:
(i) Use the analytical results from the
first grab sample collected for an event
for all 15-minute periods from the start
of the event through the 15-minute
block prior to the 15-minute block in
which a subsequent grab sample is
collected.
(ii) Use the results from subsequent
grab sampling events for all 15 minute
periods starting with the 15-minute
block in which the sample was collected
and ending with the 15-minute block
prior to the 15-minute block in which
the next grab sample is collected. For
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.011
flows for the subperiods to determine
the cumulative volumetric flow of vent
gas for the 15-minute block average
period.
(3) The 15-minute block average Vtip
shall be calculated using the following
equation.
75261
ER01DE15.010
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75262
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(6) of this section and a flow-weighted
average of the gas stream net heating
values shall be used to determine the
15-minute block average net heating
value of the cumulative flare vent gas.
(m) Calculation methods for
determining combustion zone net
heating value. The owner or operator
shall determine the net heating value of
the combustion zone gas (NHVcz) as
specified in paragraph (m)(1) or (2) of
this section, as applicable.
(1) Except as specified in paragraph
(m)(2) of this section, determine the 15minute block average NHVcz based on
the 15-minute block average vent gas
and assist gas flow rates using the
following equation. For periods when
there is no assist steam flow or premix
assist air flow, NHVcz = NHVvg.
Where:
NHVcz = Net heating value of combustion
zone gas, Btu/scf.
NHVvg = Net heating value of flare vent gas
for the 15-minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare
vent gas during the 15-minute block
period, scf.
Qs = Cumulative volumetric flow of total
steam during the 15-minute block
period, scf.
Qa,premix = Cumulative volumetric flow of
premix assist air during the 15-minute
block period, scf.
this section and that monitor gas
composition or net heating value in a
location representative of the
cumulative vent gas stream and that
directly monitor supplemental natural
gas flow additions to the flare must
determine the 15-minute block average
NHVcz using the following equation.
Where:
NHVcz = Net heating value of combustion
zone gas, Btu/scf.
NHVvg = Net heating value of flare vent gas
for the 15-minute block period, Btu/scf.
Qvg = Cumulative volumetric flow of flare
vent gas during the 15-minute block
period, scf.
QNG2 = Cumulative volumetric flow of
supplemental natural gas to the flare
during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of
supplemental natural gas to the flare
during the previous 15-minute block
period, scf. For the first 15-minute block
period of an event, use the volumetric
flow value for the current 15-minute
block period, i.e., QNG1=QNG2.
NHVNG = Net heating value of supplemental
natural gas to the flare for the 15-minute
block period determined according to the
requirements in paragraph (j)(5) of this
section, Btu/scf.
Qs = Cumulative volumetric flow of total
steam during the 15-minute block
period, scf.
Qa,premix = Cumulative volumetric flow of
premix assist air during the 15-minute
block period, scf.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(2) Owners or operators of flares that
use the feed-forward calculation
PO 00000
Frm 00086
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.015
Qs = Cumulative volumetric flow of total
steam during the 15-minute block
period, scf.
Qa,premix = Cumulative volumetric flow of
premix assist air during the 15-minute
block period, scf.
Qa,perimeter = Cumulative volumetric flow of
perimeter assist air during the 15-minute
block period, scf.
methodology in paragraph (l)(5)(i) of
this section and that monitor gas
composition or net heating value in a
location representative of the
cumulative vent gas stream and that
directly monitor supplemental natural
gas flow additions to the flare must
determine the 15-minute block average
NHVdil using the following equation
only during periods when perimeter
assist air is used. For 15-minute block
periods when there is no cumulative
ER01DE15.014
(n) Calculation methods for
determining the net heating value
dilution parameter. The owner or
operator shall determine the net heating
value dilution parameter (NHVdil) as
specified in paragraph (n)(1) or (2) of
this section, as applicable.
(1) Except as specified in paragraph
(n)(2) of this section, determine the 15minute block average NHVdil based on
the 15-minute block average vent gas
and perimeter assist air flow rates using
the following equation only during
periods when perimeter assist air is
used. For 15-minute block periods when
there is no cumulative volumetric flow
of perimeter assist air, the 15-minute
block average NHVdil parameter does not
need to be calculated.
ER01DE15.013
Where:
NHVdil = Net heating value dilution
parameter, Btu/ft2.
NHVvg = Net heating value of flare vent gas
determined for the 15-minute block
period, Btu/scf.
Qvg = Cumulative volumetric flow of flare
vent gas during the 15-minute block
period, scf.
Diam = Effective diameter of the
unobstructed area of the flare tip for flare
vent gas flow, ft. Use the area as
determined in paragraph (k)(1) of this
section and determine the diameter as
(2) Owners or operators of flares that
use the feed-forward calculation
methodology in paragraph (l)(5)(i) of
ER01DE15.012
tkelley on DSK3SPTVN1PROD with RULES2
the purpose of this requirement, use the
time the sample was collected rather
than the time the analytical results
become available.
(7) If the owner or operator monitors
separate gas streams that combine to
comprise the total flare vent gas flow,
the 15-minute block average net heating
value shall be determined separately for
each measurement location according to
the methods in paragraphs (l)(1) through
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Where:
NHVdil = Net heating value dilution
parameter, Btu/ft2.
NHVvg = Net heating value of flare vent gas
determined for the 15-minute block
period, Btu/scf.
Qvg = Cumulative volumetric flow of flare
vent gas during the 15-minute block
period, scf.
QNG2 = Cumulative volumetric flow of
supplemental natural gas to the flare
during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of
supplemental natural gas to the flare
during the previous 15-minute block
period, scf. For the first 15-minute block
period of an event, use the volumetric
flow value for the current 15-minute
block period, i.e., QNG1 =QNG2.
NHVNG = Net heating value of supplemental
natural gas to the flare for the 15-minute
block period determined according to the
requirements in paragraph (j)(5) of this
section, Btu/scf.
Diam = Effective diameter of the
unobstructed area of the flare tip for flare
vent gas flow, ft. Use the area as
determined in paragraph (k)(1) of this
section and determine the diameter as
prevented during periods of startup,
shutdown, or emergency releases. The
flare minimization assessment must (at
a minimum) consider the items in
paragraphs (o)(1)(ii)(A) through (C) of
this section. The assessment must
provide clear rationale in terms of costs
(capital and annual operating), natural
gas offset credits (if applicable),
technical feasibility, secondary
environmental impacts and safety
considerations for the selected
minimization alternative(s) or a
statement, with justifications, that flow
reduction could not be achieved. Based
upon the assessment, each owner or
operator of an affected flare shall
identify the minimization alternatives
that it has implemented by the due date
of the flare management plan and shall
include a schedule for the prompt
implementation of any selected
measures that cannot reasonably be
completed as of that date.
(A) Modification in startup and
shutdown procedures to reduce the
quantity of process gas discharge to the
flare.
(B) Implementation of prevention
measures listed for pressure relief
devices in § 63.648(j)(5) for each
pressure relief valve that can discharge
to the flare.
(C) Installation of a flare gas recovery
system or, for facilities that are fuel gas
rich, a flare gas recovery system and a
co-generation unit or combined heat and
power unit.
(iii) A description of each affected
flare containing the information in
paragraphs (o)(1)(iii)(A) through (G) of
this section.
(A) A general description of the flare,
including whether it is a ground flare or
elevated (including height), the type of
assist system (e.g., air, steam, pressure,
non-assisted), whether the flare is used
on a routine basis or if it is only used
during periods of startup, shutdown or
emergency release, and whether the
flare is equipped with a flare gas
recovery system.
(B) The smokeless capacity of the flare
based on design conditions. Note: A
single value must be provided for the
smokeless capacity of the flare.
(C) The maximum vent gas flow rate
(hydraulic load capacity).
(D) The maximum supplemental gas
flow rate.
tkelley on DSK3SPTVN1PROD with RULES2
Qs = Cumulative volumetric flow of total
steam during the 15-minute block
period, scf.
Qa,premix = Cumulative volumetric flow of
premix assist air during the 15-minute
block period, scf.
Qa,perimeter = Cumulative volumetric flow of
perimeter assist air during the 15-minute
block period, scf.
(o) Emergency flaring provisions. The
owner or operator of a flare that has the
potential to operate above its smokeless
capacity under any circumstance shall
comply with the provisions in
paragraphs (o)(1) through (8) of this
section.
(1) Develop a flare management plan
to minimize flaring during periods of
startup, shutdown, or emergency
releases. The flare management plan
must include the information described
in paragraphs (o)(1)(i) through (vii) of
this section.
(i) A listing of all refinery process
units, ancillary equipment, and fuel gas
systems connected to the flare for each
affected flare.
(ii) An assessment of whether
discharges to affected flares from these
process units, ancillary equipment and
fuel gas systems can be minimized or
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00087
Fmt 4701
Sfmt 4700
(E) For flares that receive assist steam,
the minimum total steam rate and the
maximum total steam rate.
(F) For flares that receive assist air, an
indication of whether the fan/blower is
single speed, multi-fixed speed (e.g.,
high, medium, and low speeds), or
variable speeds. For fans/blowers with
fixed speeds, provide the estimated
assist air flow rate at each fixed speed.
For variable speeds, provide the design
fan curve (e.g., air flow rate as a
function of power input).
(G) Simple process flow diagram
showing the locations of the flare
following components of the flare: Flare
tip (date installed, manufacturer,
nominal and effective tip diameter, tip
drawing); knockout or surge drum(s) or
pot(s) (including dimensions and design
capacities); flare header(s) and
subheader(s); assist system; and ignition
system.
(iv) Description and simple process
flow diagram showing all gas lines
(including flare waste gas, purge or
sweep gas (as applicable), supplemental
gas) that are associated with the flare.
For purge, sweep, supplemental gas,
identify the type of gas used. Designate
which lines are exempt from
composition or net heating value
monitoring and why (e.g., natural gas,
gas streams that have been
demonstrated to have consistent
composition, pilot gas). Designate which
lines are monitored and identify on the
process flow diagram the location and
type of each monitor. Designate the
pressure relief devices that are vented to
the flare.
(v) For each flow rate, gas
composition, net heating value or
hydrogen concentration monitor
identified in paragraph (o)(1)(iv) of this
section, provide a detailed description
of the manufacturer’s specifications,
including, but not limited to, make,
model, type, range, precision, accuracy,
calibration, maintenance and quality
assurance procedures.
(vi) For each pressure relief valve
vented to the flare identified in
paragraph (o)(1)(iv) of this section,
provide a detailed description of each
pressure release valve, including type of
relief device (rupture disc, valve type)
diameter of the relief valve, set pressure
of the relief valve and listing of the
prevention measures implemented. This
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.017
parameter does not need to be
calculated.
ER01DE15.016
volumetric flow of perimeter assist air,
the 15-minute block average NHVdil
75263
tkelley on DSK3SPTVN1PROD with RULES2
75264
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
information may be maintained in an
electronic database on-site and does not
need to be submitted as part of the flare
management plan unless requested to
do so by the Administrator.
(vii) Procedures to minimize or
eliminate discharges to the flare during
the planned startup and shutdown of
the refinery process units and ancillary
equipment that are connected to the
affected flare, together with a schedule
for the prompt implementation of any
procedures that cannot reasonably be
implemented as of the date of the
submission of the flare management
plan.
(2) Each owner or operator required to
develop and implement a written flare
management plan as described in
paragraph (o)(1) of this section must
submit the plan to the Administrator as
described in paragraphs (o)(2)(i) through
(iii) of this section.
(i) The owner or operator must
develop and implement the flare
management plan no later than January
30, 2019 or at startup for a new flare that
commenced construction on or after
February 1, 2016.
(ii) The owner or operator must
comply with the plan as submitted by
the date specified in paragraph (o)(2)(i)
of this section. The plan should be
updated periodically to account for
changes in the operation of the flare,
such as new connections to the flare or
the installation of a flare gas recovery
system, but the plan need be resubmitted to the Administrator only if
the owner or operator alters the design
smokeless capacity of the flare. The
owner or operator must comply with the
updated plan as submitted.
(iii) All versions of the plan submitted
to the Administrator shall also be
submitted to the following address: U.S.
Environmental Protection Agency,
Office of Air Quality Planning and
Standards, Sector Policies and Programs
Division, U.S. EPA Mailroom (E143–01),
Attention: Refinery Sector Lead, 109
T.W. Alexander Drive, Research
Triangle Park, NC 27711. Electronic
copies in lieu of hard copies may also
be submitted to refineryRTR@epa.gov.
(3) The owner or operator of a flare
subject to this subpart shall conduct a
root cause analysis and a corrective
action analysis for each flow event that
contains regulated material and that
meets either the criteria in paragraph
(o)(3)(i) or (ii) of this section.
(i) The vent gas flow rate exceeds the
smokeless capacity of the flare and
visible emissions are present from the
flare for more than 5 minutes during any
2 consecutive hours during the release
event.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(ii) The vent gas flow rate exceeds the
smokeless capacity of the flare and the
15-minute block average flare tip
velocity exceeds the maximum flare tip
velocity determined using the methods
in paragraph (d)(2) of this section.
(4) A root cause analysis and
corrective action analysis must be
completed as soon as possible, but no
later than 45 days after a flare flow
event meeting the criteria in paragraph
(o)(3)(i) or (ii) of this section. Special
circumstances affecting the number of
root cause analyses and/or corrective
action analyses are provided in
paragraphs (o)(4)(i) through (v) of this
section.
(i) You may conduct a single root
cause analysis and corrective action
analysis for a single continuous flare
flow event that meets both of the criteria
in paragraphs (o)(3)(i) and (ii) of this
section.
(ii) You may conduct a single root
cause analysis and corrective action
analysis for a single continuous flare
flow event regardless of the number of
15-minute block periods in which the
flare tip velocity was exceeded or the
number of 2 hour periods that contain
more the 5 minutes of visible emissions.
(iii) You may conduct a single root
cause analysis and corrective action
analysis for a single event that causes
two or more flares that are operated in
series (i.e., cascaded flare systems) to
have a flow event meeting the criteria in
paragraph (o)(3)(i) or (ii) of this section.
(iv) You may conduct a single root
cause analysis and corrective action
analysis for a single event that causes
two or more flares to have a flow event
meeting the criteria in paragraph
(o)(3)(i) or (ii) of this section, regardless
of the configuration of the flares, if the
root cause is reasonably expected to be
a force majeure event, as defined in this
subpart.
(v) Except as provided in paragraphs
(o)(4)(iii) and (iv) of this section, if more
than one flare has a flow event that
meets the criteria in paragraph (o)(3)(i)
or (ii) of this section during the same
time period, an initial root cause
analysis shall be conducted separately
for each flare that has a flow event
meeting the criteria in paragraph
(o)(3)(i) or (ii) of this section. If the
initial root cause analysis indicates that
the flow events have the same root
cause(s), the initially separate root cause
analyses may be recorded as a single
root cause analysis and a single
corrective action analysis may be
conducted.
(5) Each owner or operator of a flare
required to conduct a root cause
analysis and corrective action analysis
as specified in paragraphs (o)(3) and (4)
PO 00000
Frm 00088
Fmt 4701
Sfmt 4700
of this section shall implement the
corrective action(s) identified in the
corrective action analysis in accordance
with the applicable requirements in
paragraphs (o)(5)(i) through (iii) of this
section.
(i) All corrective action(s) must be
implemented within 45 days of the
event for which the root cause and
corrective action analyses were required
or as soon thereafter as practicable. If an
owner or operator concludes that no
corrective action should be
implemented, the owner or operator
shall record and explain the basis for
that conclusion no later than 45 days
following the event.
(ii) For corrective actions that cannot
be fully implemented within 45 days
following the event for which the root
cause and corrective action analyses
were required, the owner or operator
shall develop an implementation
schedule to complete the corrective
action(s) as soon as practicable.
(iii) No later than 45 days following
the event for which a root cause and
corrective action analyses were
required, the owner or operator shall
record the corrective action(s)
completed to date, and, for action(s) not
already completed, a schedule for
implementation, including proposed
commencement and completion dates.
(6) The owner or operator shall
determine the total number of events for
which a root cause and corrective action
analyses was required during the
calendar year for each affected flare
separately for events meeting the criteria
in paragraph (o)(3)(i) of this section and
those meeting the criteria in paragraph
(o)(3)(ii) of this section. For the purpose
of this requirement, a single root cause
analysis conducted for an event that met
both of the criteria in paragraphs
(o)(3)(i) and (ii) of this section would be
counted as an event under each of the
separate criteria counts for that flare.
Additionally, if a single root cause
analysis was conducted for an event that
caused multiple flares to meet the
criteria in paragraph (o)(3)(i) or (ii) of
this section, that event would count as
an event for each of the flares for each
criteria in paragraph (o)(3) of this
section that was met during that event.
The owner or operator shall also
determine the total number of events for
which a root cause and correct action
analyses was required and the analyses
concluded that the root cause was a
force majeure event, as defined in this
subpart.
(7) The following events would be a
violation of this emergency flaring work
practice standard.
(i) Any flow event for which a root
cause analysis was required and the root
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
cause was determined to be operator
error or poor maintenance.
(ii) Two visible emissions exceedance
events meeting the criteria in paragraph
(o)(3)(i) of this section that were not
caused by a force majeure event from a
single flare in a 3 calendar year period
for the same root cause for the same
equipment.
(iii) Two flare tip velocity exceedance
events meeting the criteria in paragraph
(o)(3)(ii) of this section that were not
caused by a force majeure event from a
single flare in a 3 calendar year period
for the same root cause for the same
equipment.
(iv) Three visible emissions
exceedance events meeting the criteria
in paragraph (o)(3)(i) of this section that
were not caused by a force majeure
event from a single flare in a 3 calendar
year period for any reason.
(v) Three flare tip velocity exceedance
events meeting the criteria in paragraph
(o)(3)(ii) of this section that were not
caused by a force majeure event from a
single flare in a 3 calendar year period
for any reason.
(p) Flare monitoring records. The
owner or operator shall keep the records
specified in § 63.655(i)(9).
(q) Reporting. The owner or operator
shall comply with the reporting
requirements specified in
§ 63.655(g)(11).
(r) Alternative means of emissions
limitation. An owner or operator may
request approval from the Administrator
for site-specific operating limits that
shall apply specifically to a selected
flare. Site-specific operating limits
include alternative threshold values for
the parameters specified in paragraphs
(d) through (f) of this section as well as
threshold values for operating
parameters other than those specified in
paragraphs (d) through (f) of this
section. The owner or operator must
demonstrate that the flare achieves 96.5
percent combustion efficiency (or 98
percent destruction efficiency) using the
site-specific operating limits based on a
performance evaluation as described in
paragraph (r)(1) of this section. The
request shall include information as
described in paragraph (r)(2) of this
section. The request shall be submitted
and followed as described in paragraph
(r)(3) of this section.
(1) The owner or operator shall
prepare and submit a site-specific test
plan and receive approval of the sitespecific performance evaluation plan
prior to conducting any flare
performance evaluation test runs
intended for use in developing sitespecific operating limits. The sitespecific performance evaluation plan
shall include, at a minimum, the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
elements specified in paragraphs (r)(1)(i)
through (ix) of this section. Upon
approval of the site-specific
performance evaluation plan, the owner
or operator shall conduct performance
evaluation test runs for the flare
following the procedures described in
the site-specific performance evaluation
plan.
(i) The design and dimensions of the
flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted,
pressure-assisted, or non-assisted), and
description of gas being flared,
including quantity of gas flared,
frequency of flaring events (if periodic),
expected net heating value of flare vent
gas, minimum total steam assist rate.
(ii) The operating conditions (vent gas
compositions, vent gas flow rates and
assist flow rates, if applicable) likely to
be encountered by the flare during
normal operations and the operating
conditions for the test period.
(iii) A description of (including
sample calculations illustrating) the
planned data reduction and calculations
to determine the flare combustion or
destruction efficiency.
(iv) Site-specific operating parameters
to be monitored continuously during the
flare performance evaluation. These
parameters may include but are not
limited to vent gas flow rate, steam and/
or air assist flow rates, and flare vent gas
composition. If new operating
parameters are proposed for use other
than those specified in paragraphs (d)
through (f) of this section, an
explanation of the relevance of the
proposed operating parameter(s) as an
indicator of flare combustion
performance and why the alternative
operating parameter(s) can adequately
ensure that the flare achieves the
required combustion efficiency.
(v) A detailed description of the
measurement methods, monitored
pollutant(s), measurement locations,
measurement frequency, and recording
frequency proposed for both emission
measurements and flare operating
parameters.
(vi) A description of (including
sample calculations illustrating) the
planned data reduction and calculations
to determine the flare operating
parameters.
(vii) The minimum number and
length of test runs and range of
operating values to be evaluated during
the performance evaluation. A sufficient
number of test runs shall be conducted
to identify the point at which the
combustion/destruction efficiency of the
flare deteriorates.
(viii) [Reserved]
(ix) Test schedule.
PO 00000
Frm 00089
Fmt 4701
Sfmt 4700
75265
(2) The request for flare-specific
operating limits shall include sufficient
and appropriate data, as determined by
the Administrator, to allow the
Administrator to confirm that the
selected site-specific operating limit(s)
adequately ensures that the flare
destruction efficiency is 98 percent or
greater or that the flare combustion
efficiency is 96.5 percent or greater at all
times. At a minimum, the request shall
contain the information described in
paragraphs (r)(2)(i) through (iv) of this
section.
(i) The design and dimensions of the
flare, flare type (air-assisted only, steamassisted only, air- and steam-assisted,
pressure-assisted, or non-assisted), and
description of gas being flared,
including quantity of gas flared,
frequency of flaring events (if periodic),
expected net heating value of flare vent
gas, minimum total steam assist rate.
(ii) Results of each performance
evaluation test run conducted,
including, at a minimum:
(A) The measured combustion/
destruction efficiency.
(B) The measured or calculated
operating parameters for each test run.
If operating parameters are calculated,
the raw data from which the parameters
are calculated must be included in the
test report.
(C) Measurement location
descriptions for both emission
measurements and flare operating
parameters.
(D) Description of sampling and
analysis procedures (including number
and length of test runs) and any
modifications to standard procedures. If
there were deviations from the approved
test plan, a detailed description of the
deviations and rationale why the test
results or calculation procedures used
are appropriate.
(E) Operating conditions (e.g., vent
gas composition, assist rates, etc.) that
occurred during the test.
(F) Quality assurance procedures.
(G) Records of calibrations.
(H) Raw data sheets for field
sampling.
(I) Raw data sheets for field and
laboratory analyses.
(J) Documentation of calculations.
(iii) The selected flare-specific
operating limit values based on the
performance evaluation test results,
including the averaging time for the
operating limit(s), and rationale why the
selected values and averaging times are
sufficiently stringent to ensure proper
flare performance. If new operating
parameters or averaging times are
proposed for use other than those
specified in paragraphs (d) through (f) of
this section, an explanation of why the
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
75266
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
alternative operating parameter(s) or
averaging time(s) adequately ensures the
flare achieves the required combustion
efficiency.
(iv) The means by which the owner or
operator will document on-going,
continuous compliance with the
selected flare-specific operating limit(s),
including the specific measurement
location and frequencies, calculation
procedures, and records to be
maintained.
(3) The request shall be submitted as
described in paragraphs (r)(3)(i) through
(iv) of this section.
(i) The owner or operator may request
approval from the Administrator at any
time upon completion of a performance
evaluation conducted following the
methods in an approved site-specific
performance evaluation plan for an
operating limit(s) that shall apply
specifically to that flare.
(ii) The request must be submitted to
the Administrator for approval. The
owner or operator must continue to
comply with the applicable standards
for flares in this subpart until the
requirements in § 63.6(g)(1) are met and
a notice is published in the Federal
Register allowing use of such an
alternative means of emission
limitation.
(iii) The request shall also be
submitted to the following address: U.S.
Environmental Protection Agency,
Office of Air Quality Planning and
Standards, Sector Policies and Programs
Division, U.S. EPA Mailroom (E143–01),
Attention: Refinery Sector Lead, 109
T.W. Alexander Drive, Research
Triangle Park, NC 27711. Electronic
copies in lieu of hard copies may also
be submitted to refineryrtr@epa.gov.
(iv) If the Administrator finds any
deficiencies in the request, the request
must be revised to address the
deficiencies and be re-submitted for
approval within 45 days of receipt of the
notice of deficiencies. The owner or
operator must comply with the revised
request as submitted until it is
approved.
(4) The approval process for a request
for a flare-specific operating limit(s) is
described in paragraphs (r)(4)(i) through
(iii) of this section.
(i) Approval by the Administrator of
a flare-specific operating limit(s) request
will be based on the completeness,
accuracy and reasonableness of the
request. Factors that the EPA will
consider in reviewing the request for
approval include, but are not limited to,
those described in paragraphs
(r)(4)(i)(A) through (C) of this section.
(A) The description of the flare design
and operating characteristics.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(B) If a new operating parameter(s)
other than those specified in paragraphs
(d) through (f) of this section is
proposed, the explanation of how the
proposed operating parameter(s) serves
a good indicator(s) of flare combustion
performance.
(C) The results of the flare
performance evaluation test runs and
the establishment of operating limits
that ensures that the flare destruction
efficiency is 98 percent or greater or that
the flare combustion efficiency is 96.5
percent or greater at all times.
(D) The completeness of the flare
performance evaluation test report.
(ii) If the request is approved by the
Administrator, a flare-specific operating
limit(s) will be established at the level(s)
demonstrated in the approved request.
(iii) If the Administrator finds any
deficiencies in the request, the request
must be revised to address the
deficiencies and be re-submitted for
approval.
■ 33. Section 63.671 is added to read as
follows:
§ 63.671 Requirements for flare monitoring
systems.
(a) Operation of CPMS. For each
CPMS installed to comply with
applicable provisions in § 63.670, the
owner or operator shall install, operate,
calibrate, and maintain the CPMS as
specified in paragraphs (a)(1) through
(8) of this section.
(1) Except for CPMS installed for pilot
flame monitoring, all monitoring
equipment must meet the applicable
minimum accuracy, calibration and
quality control requirements specified
in table 13 of this subpart.
(2) The owner or operator shall ensure
the readout (that portion of the CPMS
that provides a visual display or record)
or other indication of the monitored
operating parameter from any CPMS
required for compliance is readily
accessible onsite for operational control
or inspection by the operator of the
source.
(3) All CPMS must complete a
minimum of one cycle of operation
(sampling, analyzing and data
recording) for each successive 15minute period.
(4) Except for periods of monitoring
system malfunctions, repairs associated
with monitoring system malfunctions
and required monitoring system quality
assurance or quality control activities
(including, as applicable, calibration
checks and required zero and span
adjustments), the owner or operator
shall operate all CPMS and collect data
continuously at all times when
regulated emissions are routed to the
flare.
PO 00000
Frm 00090
Fmt 4701
Sfmt 4700
(5) The owner or operator shall
operate, maintain, and calibrate each
CPMS according to the CPMS
monitoring plan specified in paragraph
(b) of this section.
(6) For each CPMS except for CPMS
installed for pilot flame monitoring, the
owner or operator shall comply with the
out-of-control procedures described in
paragraph (c) of this section.
(7) The owner or operator shall reduce
data from a CPMS as specified in
paragraph (d) of this section.
(8) The CPMS must be capable of
measuring the appropriate parameter
over the range of values expected for
that measurement location. The data
recording system associated with each
CPMS must have a resolution that is
equal to or better than the required
system accuracy.
(b) CPMS monitoring plan. The owner
or operator shall develop and
implement a CPMS quality control
program documented in a CPMS
monitoring plan that covers each flare
subject to the provisions in § 63.670 and
each CPMS installed to comply with
applicable provisions in § 63.670. The
owner or operator shall have the CPMS
monitoring plan readily available onsite at all times and shall submit a copy
of the CPMS monitoring plan to the
Administrator upon request by the
Administrator. The CPMS monitoring
plan must contain the information listed
in paragraphs (b)(1) through (5) of this
section.
(1) Identification of the specific flare
being monitored and the flare type (airassisted only, steam-assisted only, airand steam-assisted, pressure-assisted, or
non-assisted).
(2) Identification of the parameter to
be monitored by the CPMS and the
expected parameter range, including
worst case and normal operation.
(3) Description of the monitoring
equipment, including the information
specified in paragraphs (b)(3)(i) through
(vii) of this section.
(i) Manufacturer and model number
for all monitoring equipment
components installed to comply with
applicable provisions in § 63.670.
(ii) Performance specifications, as
provided by the manufacturer, and any
differences expected for this installation
and operation.
(iii) The location of the CPMS
sampling probe or other interface and a
justification of how the location meets
the requirements of paragraph (a)(1) of
this section.
(iv) Placement of the CPMS readout,
or other indication of parameter values,
indicating how the location meets the
requirements of paragraph (a)(2) of this
section.
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
(v) Span of the CPMS. The span of the
CPMS sensor and analyzer must
encompass the full range of all expected
values.
(vi) How data outside of the span of
the CPMS will be handled and the
corrective action that will be taken to
reduce and eliminate such occurrences
in the future.
(vii) Identification of the parameter
detected by the parametric signal
analyzer and the algorithm used to
convert these values into the operating
parameter monitored to demonstrate
compliance, if the parameter detected is
different from the operating parameter
monitored.
(4) Description of the data collection
and reduction systems, including the
information specified in paragraphs
(b)(4)(i) through (iii) of this section.
(i) A copy of the data acquisition
system algorithm used to reduce the
measured data into the reportable form
of the standard and to calculate the
applicable averages.
(ii) Identification of whether the
algorithm excludes data collected
during CPMS breakdowns, out-ofcontrol periods, repairs, maintenance
periods, instrument adjustments or
checks to maintain precision and
accuracy, calibration checks, and zero
(low-level), mid-level (if applicable) and
high-level adjustments.
(iii) If the data acquisition algorithm
does not exclude data collected during
CPMS breakdowns, out-of-control
periods, repairs, maintenance periods,
instrument adjustments or checks to
maintain precision and accuracy,
calibration checks, and zero (low-level),
mid-level (if applicable) and high-level
adjustments, a description of the
procedure for excluding this data when
the averages calculated as specified in
paragraph (e) of this section are
determined.
(5) Routine quality control and
assurance procedures, including
descriptions of the procedures listed in
paragraphs (b)(5)(i) through (vi) of this
section and a schedule for conducting
these procedures. The routine
procedures must provide an assessment
of CPMS performance.
(i) Initial and subsequent calibration
of the CPMS and acceptance criteria.
(ii) Determination and adjustment of
the calibration drift of the CPMS.
(iii) Daily checks for indications that
the system is responding. If the CPMS
system includes an internal system
check, the owner or operator may use
the results to verify the system is
responding, as long as the system
provides an alarm to the owner or
operator or the owner or operator checks
the internal system results daily for
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
proper operation and the results are
recorded.
(iv) Preventive maintenance of the
CPMS, including spare parts inventory.
(v) Data recording, calculations and
reporting.
(vi) Program of corrective action for a
CPMS that is not operating properly.
(c) Out-of-control periods. For each
CPMS installed to comply with
applicable provisions in § 63.670 except
for CPMS installed for pilot flame
monitoring, the owner or operator shall
comply with the out-of-control
procedures described in paragraphs
(c)(1) and (2) of this section.
(1) A CPMS is out-of-control if the
zero (low-level), mid-level (if
applicable) or high-level calibration
drift exceeds two times the accuracy
requirement of table 13 of this subpart.
(2) When the CPMS is out of control,
the owner or operator shall take the
necessary corrective action and repeat
all necessary tests that indicate the
system is out of control. The owner or
operator shall take corrective action and
conduct retesting until the performance
requirements are below the applicable
limits. The beginning of the out-ofcontrol period is the hour a performance
check (e.g., calibration drift) that
indicates an exceedance of the
performance requirements established
in this section is conducted. The end of
the out-of-control period is the hour
following the completion of corrective
action and successful demonstration
that the system is within the allowable
limits. The owner or operator shall not
use data recorded during periods the
CPMS is out of control in data averages
and calculations, used to report
emissions or operating levels, as
specified in paragraph (d)(3) of this
section.
(d) CPMS data reduction. The owner
or operator shall reduce data from a
CPMS installed to comply with
applicable provisions in § 63.670 as
specified in paragraphs (d)(1) through
(3) of this section.
(1) The owner or operator may round
the data to the same number of
significant digits used in that operating
limit.
(2) Periods of non-operation of the
process unit (or portion thereof)
resulting in cessation of the emissions to
which the monitoring applies must not
be included in the 15-minute block
averages.
(3) Periods when the CPMS is out of
control must not be included in the 15minute block averages.
(e) Additional requirements for gas
chromatographs. For monitors used to
determine compositional analysis for
net heating value per § 63.670(j)(1), the
PO 00000
Frm 00091
Fmt 4701
Sfmt 4700
75267
gas chromatograph must also meet the
requirements of paragraphs (e)(1)
through (3) of this section.
(1) The quality assurance
requirements are in table 13 of this
subpart.
(2) The calibration gases must meet
one of the following options:
(i) The owner or operator must use a
calibration gas or multiple gases that
include all of compounds listed in
paragraphs (e)(2)(i)(A) through (K) of
this section that may be reasonably
expected to exist in the flare gas stream
and optionally include any of the
compounds listed in paragraphs
(e)(2)(i)(L) through (O) of this section.
All of the calibration gases may be
combined in one cylinder. If multiple
calibration gases are necessary to cover
all compounds, the owner or operator
must calibrate the instrument on all of
the gases.
(A) Hydrogen.
(B) Methane.
(C) Ethane.
(D) Ethylene.
(E) Propane.
(F) Propylene.
(G) n-Butane.
(H) iso-Butane.
(I) Butene (general). It is not necessary
to separately speciate butene isomers,
but the net heating value of trans-butene
must be used for co-eluting butene
isomers.
(J) 1,3-Butadiene. It is not necessary to
separately speciate butadiene isomers,
but you must use the response factor
and net heating value of 1,3-butadiene
for co-eluting butadiene isomers.
(K) n-Pentane. Use the response factor
for n-pentane to quantify all C5+
hydrocarbons.
(L) Acetylene (optional).
(M) Carbon monoxide (optional).
(N) Propadiene (optional).
(O) Hydrogen sulfide (optional).
(ii) The owner or operator must use a
surrogate calibration gas consisting of
hydrogen and C1 through C5 normal
hydrocarbons. All of the calibration
gases may be combined in one cylinder.
If multiple calibration gases are
necessary to cover all compounds, the
owner or operator must calibrate the
instrument on all of the gases.
(3) If the owner or operator chooses to
use a surrogate calibration gas under
paragraph (e)(2)(ii) of this section, the
owner or operator must comply with
paragraphs (e)(3)(i) and (ii) of this
section.
(i) Use the response factor for the
nearest normal hydrocarbon (i.e., nalkane) in the calibration mixture to
quantify unknown components detected
in the analysis.
(ii) Use the response factor for npentane to quantify unknown
E:\FR\FM\01DER2.SGM
01DER2
75268
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
components detected in the analysis
that elute after n-pentane.
■ 34. The appendix to subpart CC is
amended in table 6 by:
■ a. Revising the entries ‘‘63.5(d)(1)(ii)’’
and ‘‘63.5(f)’’;
■ b. Removing the entry ‘‘63.6(e)(1)’’;
■ c. Adding, in numerical order, the
entries ‘‘63.6(e)(1)(i) and (ii)’’ and
‘‘63.6(e)(1)(iii)’’;
■ d. Revising the entries ‘‘63.6(e)(3)(i),’’
‘‘63.6(e)(3)(iii)–63.6(e)(3)(ix),’’ and
‘‘63.6(f)(1)’’;
■ e. Removing the entry ‘‘63.6(f)(2) and
(3)’’;
■ f. Adding, in numerical order, the
entries ‘‘63.6(f)(2)’’ and ‘‘63.6(f)(3)’’;
■ g. Removing the entry ‘‘63.6(h)(1) and
63.6(h)(2)’’;
h. Adding, in numerical order, the
entries ‘‘63.6(h)(1)’’ and ‘‘63.6(h)(2)’’;
■ i. Revising the entries ‘‘63.7(b)’’ and
‘‘63.7(e)(1)’’;
■ j. Removing the entry ‘‘63.8(a)’’;
■ k. Adding, in numerical order, the
entries ‘‘63.8(a)(1) and (2),’’ ‘‘63.8(a)(3),’’
and ‘‘63.8(a)(4)’’;
■ l. Revising the entry ‘‘63.8(c)(1)’’;
■ m. Adding, in numerical order, the
entries ‘‘63.8(c)(1)(i)’’ and
‘‘63.8(c)(1)(iii)’’;
■ n. Revising the entries ‘‘63.8(c)(4),’’
‘‘63.8(c)(5)–63.8(c)(8),’’ ‘‘63.8(d),’’
‘‘63.8(e),’’ ‘‘63.8(g),’’ ‘‘63.10(b)(2)(i),’’
‘‘63.10(b)(2)(ii),’’ ‘‘63.10(b)(2)(iv),’’
‘‘63.10(b)(2)(v),’’ and ‘‘63.10(b)(2)(vii)’’;
■ o. Removing the entry ‘‘63.10(c)(9)–
63.10(c)(15)’’;
■
p. Adding, in numerical order, the
entries ‘‘63.10(c)(9),’’ ‘‘63.10(c)(10)–
63.10(c)(11),’’ and ‘‘63.10(c)(12)–
63.10(c)(15)’’;
■ q. Revising the entry ‘‘63.10(d)(2)’’;
■ r. Removing the entries
‘‘63.10(d)(5)(i)’’ and ‘‘63.10(d)(5)(ii)’’;
■ s. Adding, in numerical order, the
entry ‘‘63.10(d)(5)’’;
■ t. Removing the entry ‘‘63.11–63.16’’;
■ u. Adding, in numerical order, the
entries ‘‘63.11’’ and ‘‘63.12–63.16’’;
■ v. Revising footnote a.
■ w. Removing footnote b.
The revisions and additions read as
follows:
■
Appendix to Subpart CC of Part 63—
Tables
*
*
TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART
*
*
*
CC a
Applies to
subpart CC
Comment
*
*
63.5(d)(1)(ii) .............................................
*
Yes ...................
*
*
*
*
Except that for affected sources subject to this subpart, emission estimates specified in § 63.5(d)(1)(ii)(H) are not required, and § 63.5(d)(1)(ii)(G) and (I) are Reserved and do not apply.
*
*
63.5(f) .......................................................
*
Yes ...................
*
*
*
*
Except that the cross-reference in § 63.5(f)(2) to § 63.9(b)(2) does not apply.
*
*
63.6(e)(1)(i) and (ii) ..................................
63.6(e)(1)(iii) .............................................
*
No .....................
Yes.
*
*
See § 63.642(n) for general duty requirement.
*
*
63.6(e)(3)(i) ..............................................
*
*
No.
*
*
63.6(e)(3)(iii)–63.6(e)(3)(ix) ......................
63.6(f)(1) ..................................................
63.6(f)(2) ..................................................
*
No.
No.
Yes ...................
*
63.6(f)(3) ..................................................
Yes ...................
*
*
63.6(h)(1) .................................................
63.6(h)(2) .................................................
*
No.
Yes ...................
*
*
63.7(b) ......................................................
*
Yes ...................
*
*
*
*
Except this subpart requires notification of performance test at least 30 days (rather than 60 days) prior to the performance test.
*
*
63.7(e)(1) .................................................
tkelley on DSK3SPTVN1PROD with RULES2
Reference
*
No .....................
*
See § 63.642(d)(3).
*
*
*
*
*
63.8(a)(1) and (2) .....................................
63.8(a)(3) .................................................
63.8(a)(4) .................................................
*
Yes.
No .....................
Yes ...................
*
*
*
*
*
*
63.8(c)(1) ..................................................
63.8(c)(1)(i) ..............................................
63.8(c)(1)(iii) .............................................
*
Yes ...................
No .....................
No.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00092
*
*
*
*
*
*
*
*
Except the phrase ‘‘as specified in § 63.7(c)’’ in § 63.6(f)(2)(iii)(D) does not apply
because this subpart does not require a site-specific test plan.
Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are changed to
§ 63.642(n).
*
*
*
*
Except § 63.6(h)(2)(ii), which is reserved.
Reserved.
Except that for a flare complying with § 63.670, the cross-reference to § 63.11 in
this paragraph does not include § 63.11(b).
*
*
Except § 63.8(c)(1)(i) and (iii).
See § 63.642(n).
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
*
01DER2
*
75269
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a—Continued
Reference
Applies to
subpart CC
Comment
*
*
63.8(c)(4) ..................................................
*
Yes ...................
63.8(c)(5)–63.8(c)(8) ................................
63.8(d) ......................................................
No .....................
No .....................
*
*
*
*
Except that for sources other than flares, this subpart specifies the monitoring
cycle frequency specified in § 63.8(c)(4)(ii) is ‘‘once every hour’’ rather than ‘‘for
each successive 15-minute period.’’
This subpart specifies continuous monitoring system requirements.
This subpart specifies quality control procedures for continuous monitoring systems.
63.8(e) ......................................................
Yes.
*
*
63.8(g) ......................................................
*
No .....................
*
*
63.10(b)(2)(i) ............................................
63.10(b)(2)(ii) ...........................................
*
No.
No .....................
*
*
63.10(b)(2)(iv) ..........................................
63.10(b)(2)(v) ...........................................
No.
No.
*
*
63.10(b)(2)(vii) ..........................................
*
No .....................
*
*
*
*
§ 63.655(i) specifies records to be kept for parameters measured with continuous
monitors.
*
*
63.10(c)(9) ................................................
63.10(c)(10)–63.10(c)(11) ........................
63.10(c)(12)–63.10(c)(15) ........................
*
No .....................
No .....................
No.
*
*
*
Reserved.
§ 63.655(i) specifies the records that must be kept.
*
*
63.10(d)(2) ...............................................
*
No .....................
*
*
*
*
Although § 63.655(f) specifies performance test reporting, EPA may approve other
timeframes for submittal of performance test data.
*
*
63.10(d)(5) ...............................................
*
No .....................
*
*
§ 63.655(g) specifies the reporting requirements.
*
*
63.11 ........................................................
*
Yes ...................
*
*
*
*
Except that flares complying with § 63.670 are not subject to the requirements of
§ 63.11(b).
63.12–63.16 .............................................
Yes.
*
*
*
*
This subpart specifies data reduction procedures in §§ 63.655(i)(3) and 63.671(d).
*
*
*
*
*
*
§ 63.655(i) specifies the records that must be kept.
*
*
*
*
*
*
a Wherever
subpart A of this part specifies ‘‘postmark’’ dates, submittals may be sent by methods other than the U.S. Mail (e.g., by fax or courier). Submittals shall be sent by the specified dates, but a postmark is not required.
35. The appendix to subpart CC is
amended in table 10 by:
■ a. Redesignating the entry ‘‘Flare’’ as
‘‘Flare (if meeting the requirements of
§§ 63.643 and 63.644)’’;
■ b. Adding the entry ‘‘Flare (if meeting
the requirements of §§ 63.670 and
■
63.671)’’ after newly redesignated entry
‘‘Flare (if meeting the requirements of
§§ 63.643 and 63.644)’’;
■ c. Revising the entry ‘‘All control
devices’’; and
■ d. Revising footnote i.
The revisions and additions read as
follows:
Appendix to Subpart CC of Part 63—
Tables
*
*
*
*
*
TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR
COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS
PER MILLION BY VOLUME
tkelley on DSK3SPTVN1PROD with RULES2
Control device
Parameters to be monitored a
Recordkeeping and reporting requirements for monitored parameters
*
*
Flare (if meeting the requirements
of §§ 63.670 and 63.671).
All control devices ..........................
*
*
The parameters specified in
§ 63.670.
Presence of flow diverted to the atmosphere from the control device (§ 63.644(c)(1)) or
*
*
*
1. Records as specified in § 63.655(i)(9).
2. Report information as specified in § 63.655(g)(11)—PR.g
1. Hourly records of whether the flow indicator was operating and
whether flow was detected at any time during each hour.
Record and report the times and durations of all periods when the
vent stream is diverted through a bypass line or the monitor is not
operating—PR.g
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00093
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75270
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 10—MISCELLANEOUS PROCESS VENTS—MONITORING, RECORDKEEPING AND REPORTING REQUIREMENTS FOR
COMPLYING WITH 98 WEIGHT-PERCENT REDUCTION OF TOTAL ORGANIC HAP EMISSIONS OR A LIMIT OF 20 PARTS
PER MILLION BY VOLUME—Continued
Parameters to be monitored a
Control device
Monthly inspections of
valves (§ 63.644(c)(2)).
sealed
Recordkeeping and reporting requirements for monitored parameters
1. Records that monthly inspections were performed.
2. Record and report all monthly inspections that show the valves are
not closed or the seal has been changed—PR.g
a Regulatory
citations are listed in parentheses.
*
*
*
*
*
*
*
g PR = Periodic Reports described in § 63.655(g).
*
*
*
*
*
*
*
i Process vents that are routed to refinery fuel gas systems are not regulated under this subpart provided that on and after January 30, 2019,
any flares receiving gas from that fuel gas system are in compliance with § 63.670. No monitoring, recordkeeping, or reporting is required for
boilers and process heaters that combust refinery fuel gas.
36. The appendix to subpart CC is
amended by adding table 11 to read as
follows:
■
Appendix to Subpart CC of Part 63—
Tables
*
*
*
*
*
TABLE 11—COMPLIANCE DATES AND REQUIREMENTS
If the construction/reconstruction
date a is . . .
Then the owner or operator must
comply with . . .
And the owner or operator must
achieve compliance . . .
Except as provided in . . .
(1) After June 30, 2014 .................
(i) Requirements for new sources
in §§ 63.640 through 63.642,
63.647, 63.650 through 63.653,
and 63.656 through 63.660.
(ii) The new source requirements
in § 63.654 for heat exchange
systems.
(i) Requirements for new sources
in §§ 63.640 through 63.653
and 63.656 b c.
(ii) Requirements for new sources
in §§ 63.640 through 63.645,
§§ 63.647 through 63.653, and
§§ 63.656 and 63.657 b.
(iii) Requirements for existing
sources in § 63.658.
(iv) Requirements for new sources
in § 63.660 c.
(v) The new source requirements
in § 63.654 for heat exchange
systems.
(i) Requirements for new sources
in §§ 63.640 through 63.653
and 63.656 d e.
(ii) Requirements for new sources
in §§ 63.640 through 63.645,
63.647 through 63.653, and
63.656 and 63.657 d.
(iii) Requirements for existing
sources in § 63.658.
(iv) Requirements for new sources
in § 63.660 e.
(v) The existing source requirements in § 63.654 for heat exchange systems.
(i) Requirements for existing
sources in §§ 63.640 through
63.653 and 63.656 f g.
Upon initial startup or February 1,
2016, whichever is later.
§ 63.640(k), (l) and (m).
Upon initial startup or October 28,
2009, whichever is later.
§ 63.640(k), (l) and (m).
Upon initial startup ........................
§ 63.640(k), (l) and (m).
On or before January 30, 2019 ....
§ 63.640(k), (l) and (m).
On or before January 30, 2018 ....
§ 63.640(k), (l) and (m).
On or before April 29, 2016 .........
§ 63.640(k), (l) and (m).
Upon initial startup or October 28,
2009, whichever is later.
§ 63.640(k), (l) and (m).
Upon initial startup or August 18,
1995, whichever is later.
§ 63.640(k), (l) and (m).
On or before January 30, 2019 ....
§ 63.640(k), (l) and (m).
On or before January 30, 2018 ....
§ 63.640(k), (l) and (m).
On or before April 29, 2016 .........
§ 63.640(k), (l) and (m).
On or before October 29, 2012 ....
§ 63.640(k), (l) and (m).
(a) On or before August 18, 1998
(1) § 63.640(k), (l) and (m).
(2) § 63.6(c)(5) of subpart A of
this part or unless an extension
has been granted by the Administrator as provided in
§ 63.6(i) of subpart A of this
part.
§ 63.640(k), (l) and (m).
(2) After September 4, 2007 but on
or before June 30, 2014.
(3) After July 14, 1994 but on or
before September 4, 2007.
tkelley on DSK3SPTVN1PROD with RULES2
(4) On or before July 14, 1994 ......
(ii) Requirements for existing
sources in §§ 63.640 through
63.645, 63.647 through 63.653,
and 63.656 and 63.657 f.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00094
Fmt 4701
On or before January 30, 2019 ....
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75271
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 11—COMPLIANCE DATES AND REQUIREMENTS—Continued
If the construction/reconstruction
date a is . . .
Then the owner or operator must
comply with . . .
(v) The existing source requirements in § 63.654 for heat exchange systems
And the owner or operator must
achieve compliance . . .
Except as provided in . . .
(iii) Requirements for existing
sources in § 63.658.
(iv) Requirements for existing
sources in § 63.660 g.
On or before October 29, 2012 ....
On or before January 30, 2018 ....
§ 63.640(k), (l) and (m).
On or before April 29, 2016 .........
§ 63.640(k), (l) and (m).
§ 63.640(k), (l) and (m).
a For purposes of this table, the construction/reconstruction date means the date of construction or reconstruction of an entire affected source
or the date of a process unit addition or change meeting the criteria in § 63.640(i) or (j). If a process unit addition or change does not meet the
criteria in § 63.640(i) or (j), the process unit shall comply with the applicable requirements for existing sources.
b Between the compliance dates in items (2)(i) and (2)(ii) of this table, the owner or operator may elect to comply with either the requirements
in item (2)(i) or item (2)(ii) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(ii) of this table.
c Between the compliance dates in items (2)(i) and (2)(iv) of this table, the owner or operator may elect to comply with either the requirements
in item (2)(i) or item (2)(iv) of this table. The requirements in item (2)(i) of this table no longer apply after demonstrated compliance with the requirements in item (2)(iv) of this table.
d Between the compliance dates in items (3)(i) and (3)(ii) of this table, the owner or operator may elect to comply with either the requirements
in item (3)(i) or item (3)(ii) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(ii) of this table.
e Between the compliance dates in items (3)(i) and (3)(iv) of this table, the owner or operator may elect to comply with either the requirements
in item (3)(i) or item (3)(iv) of this table. The requirements in item (3)(i) of this table no longer apply after demonstrated compliance with the requirements in item (3)(iv) of this table.
f Between the compliance dates in items (4)(i) and (4)(ii) of this table, the owner or operator may elect to comply with either the requirements in
item (4)(i) or item (4)(ii) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(ii) of this table.
g Between the compliance dates in items (4)(i) and (4)(iv) of this table, the owner or operator may elect to comply with either the requirements
in item (4)(i) or item (4)(iv) of this table. The requirements in item (4)(i) of this table no longer apply after demonstrated compliance with the requirements in item (4)(iv) of this table.
37. The appendix to subpart CC is
amended by adding table 12 to read as
follows:
■
Appendix to Subpart CC of Part 63—
Tables
*
*
*
*
*
TABLE 12—INDIVIDUAL COMPONENT PROPERTIES
MWi
(pounds per
pound-mole)
tkelley on DSK3SPTVN1PROD with RULES2
Component
Molecular
formula
Acetylene .............................................................................
Benzene ...............................................................................
1,2-Butadiene ......................................................................
1,3-Butadiene ......................................................................
iso-Butane ............................................................................
n-Butane ..............................................................................
cis-Butene ............................................................................
iso-Butene ............................................................................
trans-Butene ........................................................................
Carbon Dioxide ....................................................................
Carbon Monoxide ................................................................
Cyclopropane .......................................................................
Ethane .................................................................................
Ethylene ...............................................................................
Hydrogen .............................................................................
Hydrogen Sulfide .................................................................
Methane ...............................................................................
Methyl-Acetylene .................................................................
Nitrogen ...............................................................................
Oxygen ................................................................................
Pentane+ (C5+) ...................................................................
Propadiene ..........................................................................
Propane ...............................................................................
Propylene .............................................................................
Water ...................................................................................
C2H2 ...............
C6H6 ...............
C4H6 ...............
C4H6 ...............
C4H10 .............
C4H10 .............
C4H8 ...............
C4H8 ...............
C4H8 ...............
CO2 ................
CO .................
C3H6 ...............
C2H6 ...............
C2H4 ...............
H2 ...................
H2S ................
CH4 ................
C3H4 ...............
N2 ...................
O2 ...................
C5H12 .............
C3H4 ...............
C3H8 ...............
C3H6 ...............
H2O ................
NHVi
(British
thermal units
per standard
cubic foot)
CMNi
(mole per
mole)
26.04
78.11
54.09
54.09
58.12
58.12
56.11
56.11
56.11
44.01
28.01
42.08
30.07
28.05
2.02
34.08
16.04
40.06
28.01
32.00
72.15
40.06
44.10
42.08
18.02
2
6
4
4
4
4
4
4
4
1
1
3
2
2
0
0
1
3
0
0
5
3
3
3
0
1,404
3,591
2,794
2,690
2,957
2,968
2,830
2,928
2,826
0
316
2,185
1,595
1,477
1,212a
587
896
2,088
0
0
3,655
2,066
2,281
2,150
0
LFLi
(volume %)
2.5
1.3
2.0
2.0
1.8
1.8
1.6
1.8
1.7
∞
12.5
2.4
3.0
2.7
4.0
4.0
5.0
1.7
∞
∞
1.4
2.16
2.1
2.4
∞
a The theoretical net heating value for hydrogen is 274 Btu/scf, but for the purposes of the flare requirement in this subpart, a net heating value
of 1,212 Btu/scf shall be used.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00095
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75272
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
38. The appendix to subpart CC is
amended by adding table 13 to read as
follows:
■
Appendix to Subpart CC of Part 63—
Tables
*
*
*
*
*
TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS
Parameter
Minimum accuracy requirements
Calibration requirements
Temperature ....................................
±1 percent over the normal range
of temperature measured, expressed in degrees Celsius (C),
or 2.8 degrees C, whichever is
greater.
Flow Rate for All Flows Other Than
Flare Vent Gas.
±5 percent over the normal range
of flow measured or 1.9 liters
per minute (0.5 gallons per
minute), whichever is greater,
for liquid flow.
±5 percent over the normal range
of flow measured or 280 liters
per minute (10 cubic feet per
minute), whichever is greater,
for gas flow.
±5 percent over the normal range
measured for mass flow.
Conduct calibration checks at least annually; conduct calibration
checks following any period of more than 24 hours throughout
which the temperature exceeded the manufacturer’s specified maximum rated temperature or install a new temperature sensor.
At least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion,
unless the CPMS has a redundant temperature sensor.
Record the results of each calibration check and inspection.
Locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system
from electromagnetic interference and chemical contaminants.
Conduct a flow sensor calibration check at least biennially (every two
years); conduct a calibration check following any period of more
than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow
sensor.
At least quarterly, inspect all components for leakage, unless the
CPMS has a redundant flow sensor.
±20 percent of flow rate at velocities ranging from 0.03 to 0.3
meters per second (0.1 to 1 feet
per second).
±5 percent of flow rate at velocities greater than 0.3 meters per
second (1 feet per second).
Pressure ..........................................
±5 percent over the normal operating range or 0.12 kilopascals
(0.5 inches of water column),
whichever is greater.
Net Heating Value by Calorimeter ..
tkelley on DSK3SPTVN1PROD with RULES2
Flare Vent Gas Flow Rate ..............
±2 percent of span ........................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00096
Fmt 4701
Record the results of each calibration check and inspection.
Locate the flow sensor(s) and other necessary equipment (such as
straightening vanes) in a position that provides representative flow;
reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
Conduct a flow sensor calibration check at least biennially (every two
years); conduct a calibration check following any period of more
than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow
sensor.
At least quarterly, inspect all components for leakage, unless the
CPMS has a redundant flow sensor.
Record the results of each calibration check and inspection.
Locate the flow sensor(s) and other necessary equipment (such as
straightening vanes) in a position that provides representative flow;
reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
Review pressure sensor readings at least once a week for
straightline (unchanging) pressure and perform corrective action to
ensure proper pressure sensor operation if blockage is indicated.
Using an instrument recommended by the sensor’s manufacturer,
check gauge calibration and transducer calibration annually; conduct calibration checks following any period of more than 24 hours
throughout which the pressure exceeded the manufacturer’s specified maximum rated pressure or install a new pressure sensor.
At least quarterly, inspect all components for integrity, all electrical
connections for continuity, and all mechanical connections for leakage, unless the CPMS has a redundant pressure sensor.
Record the results of each calibration check and inspection.
Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and minimizes or eliminates
pulsating pressure, vibration, and internal and external corrosion.
Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s
recommendations at a minimum.
Temperature control (heated and/or cooled as necessary) the sampling system to ensure proper year-round operation.
Where feasible, select a sampling location at least two equivalent diameters downstream from and 0.5 equivalent diameters upstream
from the nearest disturbance. Select the sampling location at least
two equivalent duct diameters from the nearest control device,
point of pollutant generation, air in-leakages, or other point at
which a change in the pollutant concentration or emission rate occurs.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75273
TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS—Continued
Parameter
Minimum accuracy requirements
Calibration requirements
Net Heating Value by Gas Chromatograph.
As specified in Performance Specification 9 of 40 CFR part 60,
appendix B
Hydrogen analyzer ..........................
±2 percent over the concentration
measured or 0.1 volume percent, whichever is greater.
Follow the procedure in Performance Specification 9 of 40 CFR part
60, appendix B, except that a single daily mid-level calibration
check can be used (rather than triplicate analysis), the multi-point
calibration can be conducted quarterly (rather than monthly), and
the sampling line temperature must be maintained at a minimum
temperature of 60 °C (rather than 120 °C).
Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s
recommendations at a minimum.
Select the sampling location at least two equivalent duct diameters
from the nearest control device, point of pollutant generation, air inleakages, or other point at which a change in the pollutant concentration occurs.
39. Section 63.1562 is amended by
revising paragraphs (b)(3) and (f)(5) to
read as follows:
■
§ 63.1562 What parts of my plant are
covered by this subpart?
*
*
*
*
*
(b) * * *
(3) The process vent or group of
process vents on Claus or other types of
sulfur recovery plant units or the tail gas
treatment units serving sulfur recovery
plants that are associated with sulfur
recovery.
*
*
*
*
*
(f) * * *
(5) Gaseous streams routed to a fuel
gas system, provided that on and after
January 30, 2019, any flares receiving
gas from the fuel gas system are subject
to § 63.670.
■ 40. Section 63.1564 is amended by:
■ a. Revising paragraphs (a)(1) and (2);
■ b. Adding paragraph (a)(5);
■ c. Removing the equation following
paragraph (b)(4)(ii) and adding it after
paragraph (b)(4)(iii) introductory text;
■ d. Revising paragraphs (b)(2), (b)(4)(i)
and (ii), and (b)(4)(iv); and
■ e. Adding paragraph (c)(5).
The revisions and additions read as
follows:
§ 63.1564 What are my requirements for
metal HAP emissions from catalytic
cracking units?
tkelley on DSK3SPTVN1PROD with RULES2
(a) * * *
Where:
Rc = Coke burn-off rate, kg/hr (lb/hr);
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(1) Except as provided in paragraph
(a)(5) of this section, meet each emission
limitation in Table 1 of this subpart that
applies to you. If your catalytic cracking
unit is subject to the NSPS for PM in
§ 60.102 of this chapter or is subject to
§ 60.102a(b)(1) of this chapter, you must
meet the emission limitations for NSPS
units. If your catalytic cracking unit is
not subject to the NSPS for PM, you can
choose from the four options in
paragraphs (a)(1)(i) through (vi) of this
section:
(i) You can elect to comply with the
NSPS for PM in § 60.102 of this chapter
(Option 1a);
(ii) You can elect to comply with the
NSPS for PM coke burn-off emission
limit in § 60.102a(b)(1) of this chapter
(Option 1b);
(iii) You can elect to comply with the
NSPS for PM concentration limit in
§ 60.102a(b)(1) of this chapter (Option
1c);
(iv) You can elect to comply with the
PM per coke burn-off emission limit in
§ 60.102a(b)(1) of this chapter (Option
2);
(v) You can elect to comply with the
Nickel (Ni) lb/hr emission limit (Option
3); or
(vi) You can elect to comply with the
Ni per coke burn-off emission limit
(Option 4).
(2) Comply with each operating limit
in Table 2 of this subpart that applies to
you. When a specific control device may
be monitored using more than one
continuous parameter monitoring
system, you may select the parameter
with which you will comply. You must
provide notice to the Administrator (or
Qr = Volumetric flow rate of exhaust gas from
catalyst regenerator before adding air or
PO 00000
Frm 00097
Fmt 4701
Sfmt 4700
other designated authority) if you elect
to change the monitoring option.
*
*
*
*
*
(5) During periods of startup,
shutdown and hot standby, you can
choose from the two options in
paragraphs (a)(5)(i) and (ii) of this
section:
(i) You can elect to comply with the
requirements in paragraphs (a)(1) and
(2) of this section, except catalytic
cracking units controlled using a wet
scrubber must maintain only the liquid
to gas ratio operating limit (the pressure
drop operating limit does not apply); or
(ii) You can elect to maintain the inlet
velocity to the primary internal cyclones
of the catalytic cracking unit catalyst
regenerator at or above 20 feet per
second.
(b) * * *
(2) Conduct a performance test for
each catalytic cracking unit according to
the requirements in § 63.1571 and under
the conditions specified in Table 4 of
this subpart.
*
*
*
*
*
(4) * * *
(i) If you elect Option 1b or Option 2
in paragraph (a)(1)(ii) or (iv) of this
section, compute the PM emission rate
(lb/1,000 lb of coke burn-off) for each
run using Equations 1, 2, and 3 (if
applicable) of this section and the sitespecific opacity limit, if applicable,
using Equation 4 of this section as
follows:
gas streams. Example: You may measure
upstream or downstream of an
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.018
Subpart UUU-—National Emission
Standards for Hazardous Air Pollutants
for Petroleum Refineries: Catalytic
Cracking Units, Catalytic Reforming
Units, and Sulfur Recovery Units
75274
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Qsd = Volumetric flow rate of the catalytic
cracking unit catalyst regenerator flue
gas as measured by Method 2 in
appendix A–1 to part 60 of this chapter,
dscm/hr (dscf/hr);
Rc = Coke burn-off rate, kg coke/hr (1,000 lb
coke/hr); and
K = Conversion factor, 1.0 (kg2/g)/(1,000 kg)
(1,000 lb/(1,000 lb)).
Where:
Es = Emission rate of PM allowed, kg/1,000
kg (1b/1,000 lb) of coke burn-off in
catalyst regenerator;
1.0 = Emission limitation, kg coke/1,000 kg
(lb coke/1,000 lb);
A = Allowable incremental rate of PM
emissions. Before August 1, 2017, A =
0.18 g/million cal (0.10 lb/million Btu).
On or after August 1, 2017, A = 0 g/
million cal (0 lb/million Btu);
H = Heat input rate from solid or liquid fossil
fuel, million cal/hr (million Btu/hr).
Make sure your permitting authority
approves procedures for determining the
heat input rate;
Rc = Coke burn-off rate, kg coke/hr (1,000 lb
coke/hr) determined using Equation 1 of
this section; and
K′ = Conversion factor to units to standard,
1.0 (kg2/g)/(1,000 kg) (103 lb/(1,000 lb)).
Where:
Opacity Limit = Maximum permissible
hourly average opacity, percent, or 10
percent, whichever is greater;
Opacityst = Hourly average opacity measured
during the source test, percent; and
PMEmRst = PM emission rate measured
during the source test, lb/1,000 lb coke
burn.
(ii) If you elect Option 1c in paragraph
(a)(1)(iii) of this section, the PM
concentration emission limit, determine
the average PM concentration from the
initial performance test used to certify
your PM CEMS.
*
*
*
*
*
(iv) If you elect Option 4 in paragraph
(a)(1)(vi) of this section, the Ni per coke
burn-off emission limit, compute your
Ni emission rate using Equations 1 and
8 of this section and your site-specific
Ni operating limit (if you use a
continuous opacity monitoring system)
using Equations 9 and 10 of this section
as follows:
Where:
ENi2 = Normalized mass emission rate of Ni,
mg/kg coke (lb/1,000 lb coke).
ER01DE15.023
Qoxy = Volumetric flow rate of oxygenenriched air stream to regenerator, as
determined from instruments in the
catalytic cracking unit control room,
dscm/min (dscf/min); and
%Oxy = Oxygen concentration in oxygenenriched air stream, percent by volume
(dry basis).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00098
Fmt 4701
Sfmt 4725
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.019
ER01DE15.020
ER01DE15.021
ER01DE15.022
%CO = Carbon monoxide concentration in
regenerator exhaust, percent by volume
(dry basis);
%O2 = Oxygen concentration in regenerator
exhaust, percent by volume (dry basis);
K1 = Material balance and conversion factor,
0.2982 (kg-min)/(hr-dscm-%) (0.0186 (lbmin)/(hr-dscf-%));
K2 = Material balance and conversion factor,
2.088 (kg-min)/(hr-dscm) (0.1303 (lbmin)/(hr-dscf));
K3 = Material balance and conversion factor,
0.0994 (kg-min)/(hr-dscm-%) (0.0062 (lbmin)/(hr-dscf-%));
Where:
E = Emission rate of PM, kg/1,000 kg (lb/
1,000 lb) of coke burn-off;
Cs = Concentration of PM, g/dscm (lb/dscf);
tkelley on DSK3SPTVN1PROD with RULES2
electrostatic precipitator, but you must
measure upstream of a carbon monoxide
boiler, dscm/min (dscf/min). You may
use the alternative in either
§ 63.1573(a)(1) or (2), as applicable, to
calculate Qr;
Qa = Volumetric flow rate of air to catalytic
cracking unit catalyst regenerator, as
determined from instruments in the
catalytic cracking unit control room,
dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in
regenerator exhaust, percent by volume
(dry basis);
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
NiEmR2st = Average Ni emission rate
calculated as the arithmetic average Ni
emission rate using Equation 8 of this
Where:
Ni Operating Limit2 = Maximum permissible
hourly average Ni operating limit,
percent-ppmw-acfm-hr/kg coke, i.e.,
your site-specific Ni operating limit; and
Rc,st = Coke burn rate from Equation 1 of this
section, as measured during the initial
performance test, kg coke/hr.
§ 63.1565 What are my requirements for
organic HAP emissions from catalytic
cracking units?
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
(c) * * *
(5) If you elect to comply with the
alternative limit in paragraph (a)(5)(ii) of
this section during periods of startup,
shutdown, and hot standby,
demonstrate continuous compliance by:
(i) Collecting the volumetric flow rate
from the catalyst regenerator (in acfm)
and determining the average flow rate
for each hour. For events lasting less
than one hour, determine the average
flow rate during the event.
(ii) Determining the cumulative crosssectional area of the primary internal
cyclone inlets in square feet (ft2) using
design drawings of the primary (firststage) internal cyclones to determine the
inlet cross-sectional area of each
primary internal cyclone and summing
the cross-sectional areas for all primary
internal cyclones in the catalyst
regenerator or, if primary cyclones. If all
primary internal cyclones are identical,
you may alternatively determine the
inlet cross-sectional area of one primary
internal cyclone using design drawings
and multiply that area by the total
number of primary internal cyclones in
the catalyst regenerator.
(iii) Calculating the inlet velocity to
the primary internal cyclones in square
feet per second (ft2/sec) by dividing the
average volumetric flow rate (acfm) by
the cumulative cross-sectional area of
the primary internal cyclone inlets (ft2)
and by 60 seconds/minute (for unit
conversion).
(iv) Maintaining the inlet velocity to
the primary internal cyclones at or
above 20 feet per second for each hour
during the startup, shutdown, or hot
standby event or, for events lasting less
than 1 hour, for the duration of the
event.
■ 41. Section 63.1565 is amended by
revising paragraph (a)(1) introductory
text and adding paragraph (a)(5) to read
as follows:
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
(a) * * *
(1) Except as provided in paragraph
(a)(5) of this section, meet each emission
limitation in Table 8 of this subpart that
applies to you. If your catalytic cracking
unit is subject to the NSPS for carbon
monoxide (CO) in § 60.103 of this
chapter or is subject to § 60.102a(b)(4) of
this chapter, you must meet the
emission limitations for NSPS units. If
your catalytic cracking unit is not
subject to the NSPS for CO, you can
choose from the two options in
paragraphs (a)(1)(i) through (ii) of this
section:
*
*
*
*
*
(5) During periods of startup,
shutdown and hot standby, you can
choose from the two options in
paragraphs (a)(5)(i) and (ii) of this
section:
(i) You can elect to comply with the
requirements in paragraphs (a)(1) and
(2) of this section; or
(ii) You can elect to maintain the
oxygen (O2) concentration in the
exhaust gas from your catalyst
regenerator at or above 1 volume
percent (dry basis).
*
*
*
*
*
■ 42. Section 63.1566 is amended by
revising paragraphs (a)(1) introductory
text, (a)(1)(i), and (a)(4) to read as
follows:
§ 63.1566 What are my requirements for
organic HAP emissions from catalytic
reforming units?
(a) * * *
(1) Meet each emission limitation in
Table 15 of this subpart that applies to
you. You can choose from the two
options in paragraphs (a)(1)(i) and (ii) of
this section.
(i) You can elect to vent emissions of
total organic compounds (TOC) to a
flare (Option 1). On and after January
30, 2019, the flare must meet the
requirements of § 63.670. Prior to
January 30, 2019, the flare must meet
the control device requirements in
§ 63.11(b) or the requirements of
§ 63.670.
*
*
*
*
*
PO 00000
Frm 00099
Fmt 4701
Sfmt 4700
section for each of the performance test
runs, mg/kg coke.
(4) The emission limitations in Tables
15 and 16 of this subpart do not apply
to emissions from process vents during
passive depressuring when the reactor
vent pressure is 5 pounds per square
inch gauge (psig) or less. The emission
limitations in Tables 15 and 16 of this
subpart do apply to emissions from
process vents during active purging
operations (when nitrogen or other
purge gas is actively introduced to the
reactor vessel) or active depressuring
(using a vacuum pump, ejector system,
or similar device) regardless of the
reactor vent pressure.
*
*
*
*
*
■ 43. Section 63.1568 is amended by
revising paragraphs (a)(1) introductory
text and (a)(1)(i) and adding paragraph
(a)(4) to read as follows:
§ 63.1568 What are my requirements for
HAP emissions from sulfur recovery units?
(a) * * *
(1) Meet each emission limitation in
Table 29 of this subpart that applies to
you. If your sulfur recovery unit is
subject to the NSPS for sulfur oxides in
§ 60.104 or § 60.102a(f)(1) of this
chapter, you must meet the emission
limitations for NSPS units. If your sulfur
recovery unit is not subject to one of
these NSPS for sulfur oxides, you can
choose from the options in paragraphs
(a)(1)(i) through (ii) of this section:
(i) You can elect to meet the NSPS
requirements in § 60.104(a)(2) or
§ 60.102a(f)(1) of this chapter (Option 1);
or
*
*
*
*
*
(4) During periods of startup and
shutdown, you can choose from the
three options in paragraphs (a)(4)(i)
through (iii) of this section.
(i) You can elect to comply with the
requirements in paragraphs (a)(1) and
(2) of this section.
(ii) You can elect to send any startup
or shutdown purge gases to a flare. On
and after January 30, 2019, the flare
must meet the requirements of § 63.670.
Prior to January 30, 2019, the flare must
meet the design and operating
requirements in § 63.11(b) or the
requirements of § 63.670.
(iii) You can elect to send any startup
or shutdown purge gases to a thermal
oxidizer or incinerator operated at a
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.024
Where:
Opacity2 = Opacity value for use in Equation
10 of this section, percent, or 10 percent,
whichever is greater; and
75275
75276
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
minimum hourly average temperature of
1,200 degrees Fahrenheit in the firebox
and a minimum hourly average outlet
oxygen (O2) concentration of 2 volume
percent (dry basis).
*
*
*
*
*
44. Section 63.1570 is amended by
revising paragraphs (a) through (d) and
removing paragraph (g) to read as
follows:
■
§ 63.1570 What are my general
requirements for complying with this
subpart?
(a) You must be in compliance with
all of the non-opacity standards in this
subpart at all times.
(b) You must be in compliance with
the opacity and visible emission limits
in this subpart at all times.
(c) At all times, you must operate and
maintain any affected source, including
associated air pollution control
equipment and monitoring equipment,
in a manner consistent with safety and
good air pollution control practices for
minimizing emissions. The general duty
to minimize emissions does not require
you to make any further efforts to
reduce emissions if levels required by
the applicable standard have been
achieved. Determination of whether a
source is operating in compliance with
operation and maintenance
requirements will be based on
information available to the
Administrator which may include, but
is not limited to, monitoring results,
review of operation and maintenance
procedures, review of operation and
maintenance records, and inspection of
the source.
(d) During the period between the
compliance date specified for your
affected source and the date upon which
continuous monitoring systems have
been installed and validated and any
applicable operating limits have been
set, you must maintain a log that
documents the procedures used to
minimize emissions from process and
emissions control equipment according
to the general duty in paragraph (c) of
this section.
*
*
*
*
*
45. Section 63.1571 is amended by:
a. Adding paragraphs (a)(5) and (6);
■ b. Revising paragraph (b)(1);
■ c. Removing paragraph (b)(4);
■ d. Redesignating paragraph (b)(5) as
paragraph (b)(4); and
■ e. Revising the first sentence of
paragraph (d)(2) and paragraph (d)(4).
The revisions and additions read as
follows:
■
tkelley on DSK3SPTVN1PROD with RULES2
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
§ 63.1571 How and when do I conduct a
performance test or other initial compliance
demonstration?
(a) * * *
(5) Periodic performance testing for
PM or Ni. Except as provided in
paragraphs (a)(5)(i) and (ii) of this
section, conduct a periodic performance
test for PM or Ni for each catalytic
cracking unit at least once every 5 years
according to the requirements in Table
4 of this subpart. You must conduct the
first periodic performance test no later
than August 1, 2017.
(i) Catalytic cracking units monitoring
PM concentration with a PM CEMS are
not required to conduct a periodic PM
performance test.
(ii) Conduct a performance test
annually if you comply with the
emission limits in Item 1 (NSPS subpart
J) or Item 4 (Option 1a) in Table 1 of this
subpart and the PM emissions measured
during the most recent performance
source test are greater than 0.80 g/kg
coke burn-off.
(6) One-time performance testing for
HCN. Conduct a performance test for
HCN from each catalytic cracking unit
no later than August 1, 2017 according
to the applicable requirements in
paragraphs (a)(6)(i) and (ii) of this
section.
(i) If you conducted a performance
test for HCN for a specific catalytic
cracking unit between March 31, 2011
and February 1, 2016, you may submit
a request to the Administrator to use the
previously conducted performance test
results to fulfill the one-time
performance test requirement for HCN
for each of the catalytic cracking units
tested according to the requirements in
paragraphs (a)(6)(i)(A) through (D) of
this section.
(A) The request must include a copy
of the complete source test report, the
date(s) of the performance test and the
test methods used. If available, you
must also indicate whether the catalytic
cracking unit catalyst regenerator was
operated in partial or complete
combustion mode during the test, the
control device configuration, including
whether platinum or palladium
combustion promoters were used during
the test, and the CO concentration
(measured using CO CEMS or manual
test method) for each test run.
(B) You must submit a separate
request for each catalytic cracking unit
tested and you must submit each
request to the Administrator no later
than March 30, 2016.
(C) The Administrator will evaluate
each request with respect to the
completeness of the request, the
completeness of the submitted test
report and the appropriateness of the
PO 00000
Frm 00100
Fmt 4701
Sfmt 4700
test methods used. The Administrator
will notify the facility within 60 days of
receipt of the request if it is approved
or denied. If the Administrator fails to
respond to the facility within 60 days of
receipt of the request, the request will
be automatically approved.
(D) If the request is approved, you do
not need to conduct an additional HCN
performance test. If the request is
denied, you must conduct an additional
HCN performance test following the
requirements in (a)(6)(ii) of this section.
(ii) Unless you receive approval to use
a previously conducted performance
test to fulfill the one-time performance
test requirement for HCN for your
catalytic cracking unit as provided in
paragraph (a)(6)(i) of this section,
conduct a performance test for HCN for
each catalytic cracking unit no later
than August 1, 2017 according to
following requirements:
(A) Select sampling port location,
determine volumetric flow rate, conduct
gas molecular weight analysis and
measure moisture content as specified
in either Item 1 of Table 4 of this
subpart or Item 1 of Table 11 of this
subpart.
(B) Measure HCN concentration using
Method 320 of appendix A of this part.
The method ASTM D6348–03
(Reapproved 2010) including Annexes
A1 through A8 (incorporated by
reference—see § 63.14) is an acceptable
alternative to EPA Method 320 of
appendix A of this part. The method
ASTM D6348–12e1 (incorporated by
reference—see § 63.14) is an acceptable
alternative to EPA Method 320 of
appendix A of this part with the
following two caveats:
(1) The test plan preparation and
implementation in the Annexes to
ASTM D6348–03 (Reapproved 2010),
Sections A1 through A8 are mandatory;
and
(2) In ASTM D6348–03 (Reapproved
2010) Annex A5 (Analyte Spiking
Technique), the percent (%) R must be
determined for each target analyte
(Equation A5.5). In order for the test
data to be acceptable for a compound,
%R must be 70% ≥ R ≤ 130%. If the %R
value does not meet this criterion for a
target compound, the test data is not
acceptable for that compound and the
test must be repeated for that analyte
(i.e., the sampling and/or analytical
procedure should be adjusted before a
retest). The %R value for each
compound must be reported in the test
report, and all field measurements must
be corrected with the calculated %R
value for that compound by using the
following equation:
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Reported Result = (Measured
Concentration in the Stack × 100÷/
% R.
(C) Measure CO concentration as
specified in either Item 2 or 3a of Table
11 of this subpart.
(D) Record and include in the test
report an indication of whether the
catalytic cracking unit catalyst
regenerator was operated in partial or
complete combustion mode and the
control device configuration, including
whether platinum or palladium
combustion promoters were used during
the test.
(b) * * *
(1) Performance tests shall be
conducted according to the provisions
of § 63.7(e) except that performance
tests shall be conducted at maximum
representative operating capacity for the
process. During the performance test,
you must operate the control device at
either maximum or minimum
representative operating conditions for
monitored control device parameters,
whichever results in lower emission
reduction. You must not conduct a
performance test during startup,
shutdown, periods when the control
device is bypassed or periods when the
process, monitoring equipment or
control device is not operating properly.
You may not conduct performance tests
during periods of malfunction. You
must record the process information
that is necessary to document operating
conditions during the test and include
in such record an explanation to
support that the test was conducted at
maximum representative operating
capacity. Upon request, you must make
available to the Administrator such
records as may be necessary to
determine the conditions of
performance tests.
*
*
*
*
*
(d) * * *
(2) If you must meet the HAP metal
emission limitations in § 63.1564, you
elect the option in paragraph (a)(1)(iv)
in § 63.1564 (Ni per coke burn-off), and
you use continuous parameter
monitoring systems, you must establish
an operating limit for the equilibrium
catalyst Ni concentration based on the
laboratory analysis of the equilibrium
catalyst Ni concentration from the
initial performance test. * * *
*
*
*
*
*
(4) Except as specified in paragraph
(d)(3) of this section, if you use
continuous parameter monitoring
systems, you may adjust one of your
monitored operating parameters (flow
rate, total power and secondary current,
pressure drop, liquid-to-gas ratio) from
the average of measured values during
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
the performance test to the maximum
value (or minimum value, if applicable)
representative of worst-case operating
conditions, if necessary. This
adjustment of measured values may be
done using control device design
specifications, manufacturer
recommendations, or other applicable
information. You must provide
supporting documentation and rationale
in your Notification of Compliance
Status, demonstrating to the satisfaction
of your permitting authority, that your
affected source complies with the
applicable emission limit at the
operating limit based on adjusted
values.
*
*
*
*
*
■ 46. Section 63.1572 is amended by
revising paragraphs (c) introductory
text, (c)(1), (3), and (4) and (d)(1) and (2)
to read as follows:
§ 63.1572 What are my monitoring
installation, operation, and maintenance
requirements?
*
*
*
*
*
(c) Except for flare monitoring
systems, you must install, operate, and
maintain each continuous parameter
monitoring system according to the
requirements in paragraphs (c)(1)
through (5) of this section. For flares, on
and after January 30, 2019, you must
install, operate, calibrate, and maintain
monitoring systems as specified in
§§ 63.670 and 63.671. Prior to January
30, 2019, you must either meet the
monitoring system requirements in
paragraphs (c)(1) through (5) of this
section or meet the requirements in
§§ 63.670 and 63.671.
(1) You must install, operate, and
maintain each continuous parameter
monitoring system according to the
requirements in Table 41 of this subpart.
You must also meet the equipment
specifications in Table 41 of this subpart
if pH strips or colormetric tube
sampling systems are used. You must
install, operate, and maintain each
continuous parameter monitoring
system according to the requirements in
Table 41 of this subpart. You must meet
the requirements in Table 41 of this
subpart for BLD systems. Alternatively,
before August 1, 2017, you may install,
operate, and maintain each continuous
parameter monitoring system in a
manner consistent with the
manufacturer’s specifications or other
written procedures that provide
adequate assurance that the equipment
will monitor accurately.
*
*
*
*
*
(3) Each continuous parameter
monitoring system must have valid
hourly average data from at least 75
PO 00000
Frm 00101
Fmt 4701
Sfmt 4700
75277
percent of the hours during which the
process operated, except for BLD
systems.
(4) Each continuous parameter
monitoring system must determine and
record the hourly average of all recorded
readings and if applicable, the daily
average of all recorded readings for each
operating day, except for BLD systems.
The daily average must cover a 24-hour
period if operation is continuous or the
number of hours of operation per day if
operation is not continuous, except for
BLD systems.
*
*
*
*
*
(d) * * *
(1) You must conduct all monitoring
in continuous operation (or collect data
at all required intervals) at all times the
affected source is operating.
(2) You may not use data recorded
during required quality assurance or
control activities (including, as
applicable, calibration checks and
required zero and span adjustments) for
purposes of this regulation, including
data averages and calculations, for
fulfilling a minimum data availability
requirement, if applicable. You must
use all the data collected during all
other periods in assessing the operation
of the control device and associated
control system.
■ 47. Section 63.1573 is amended by:
■ a. Redesignating paragraphs (b), (c),
(d), (e), and (f) as paragraphs (c), (d), (e),
(f), and (g);
■ b. Adding paragraph (b); and
■ c. Revising newly redesignated
paragraphs (c) introductory text, (d)
introductory text, (f) introductory text,
and (g)(1) introductory text.
The revisions and additions read as
follows:
§ 63.1573 What are my monitoring
alternatives?
*
*
*
*
*
(b) What is the approved alternative
for monitoring pressure drop? You may
use this alternative to a continuous
parameter monitoring system for
pressure drop if you operate a jet ejector
type wet scrubber or other type of wet
scrubber equipped with atomizing spray
nozzles. You shall:
(1) Conduct a daily check of the air or
water pressure to the spray nozzles;
(2) Maintain records of the results of
each daily check; and
(3) Repair or replace faulty (e.g.,
leaking or plugged) air or water lines
within 12 hours of identification of an
abnormal pressure reading.
(c) What is the approved alternative
for monitoring pH or alkalinity levels?
You may use the alternative in
E:\FR\FM\01DER2.SGM
01DER2
75278
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
paragraph (c)(1) or (2) of this section for
a catalytic reforming unit.
*
*
*
*
*
(d) Can I use another type of
monitoring system? You may use an
automated data compression system. An
automated data compression system
does not record monitored operating
parameter values at a set frequency (e.g.,
once every hour) but records all values
that meet set criteria for variation from
previously recorded values. You must
maintain a record of the description of
the monitoring system and data
recording system, including the criteria
used to determine which monitored
values are recorded and retained, the
method for calculating daily averages,
and a demonstration that the system
meets all of the criteria in paragraphs
(d)(1) through (5) of this section:
*
*
*
*
*
(f) How do I request to monitor
alternative parameters? You must
submit a request for review and
approval or disapproval to the
Administrator. The request must
include the information in paragraphs
(f)(1) through (5) of this section.
*
*
*
*
*
(g) * * *
(1) You may request alternative
monitoring requirements according to
the procedures in this paragraph if you
meet each of the conditions in
paragraphs (g)(1)(i) through (iii) of this
section:
*
*
*
*
*
■ 48. Section 63.1574 is amended by
revising paragraphs (a)(3) introductory
text and (f)(1) to read as follows:
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.1574 What notifications must I submit
and when?
(a) * * *
(3) If you are required to conduct an
initial performance test, performance
evaluation, design evaluation, opacity
observation, visible emission
observation, or other initial compliance
demonstration, you must submit a
notification of compliance status
according to § 63.9(h)(2)(ii). You can
submit this information in an operating
permit application, in an amendment to
an operating permit application, in a
separate submission, or in any
combination. In a State with an
approved operating permit program
where delegation of authority under
section 112(l) of the CAA has not been
requested or approved, you must
provide a duplicate notification to the
applicable Regional Administrator. If
the required information has been
submitted previously, you do not have
to provide a separate notification of
compliance status. Just refer to the
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
earlier submissions instead of
duplicating and resubmitting the
previously submitted information.
*
*
*
*
*
(f) * * *
(1) You must submit the plan to your
permitting authority for review and
approval along with your notification of
compliance status. While you do not
have to include the entire plan in your
permit under part 70 or 71 of this
chapter, you must include the duty to
prepare and implement the plan as an
applicable requirement in your part 70
or 71 operating permit. You must
submit any changes to your permitting
authority for review and approval and
comply with the plan as submitted until
the change is approved.
*
*
*
*
*
■ 49. Section 63.1575 is amended by:
■ a. Revising paragraphs (d)
introductory text and (d)(1) and (2);
■ b. Adding paragraph (d)(4);
■ c. Revising paragraph (e) introductory
text;
■ d. Removing and reserving paragraph
(e)(1);
■ e. Revising paragraphs (e)(4) and (6)
and (f)(1) and (2);
■ f. Removing and reserving paragraph
(h); and
■ g. Adding paragraph (k).
The revisions and additions read as
follows:
§ 63.1575
when?
What reports must I submit and
*
*
*
*
*
(d) For each deviation from an
emission limitation and for each
deviation from the requirements for
work practice standards that occurs at
an affected source where you are not
using a continuous opacity monitoring
system or a continuous emission
monitoring system to comply with the
emission limitation or work practice
standard in this subpart, the semiannual
compliance report must contain the
information in paragraphs (c)(1) through
(3) of this section and the information
in paragraphs (d)(1) through (4) of this
section.
(1) The total operating time of each
affected source during the reporting
period and identification of the sources
for which there was a deviation.
(2) Information on the number, date,
time, duration, and cause of deviations
(including unknown cause, if
applicable).
*
*
*
*
*
(4) The applicable operating limit or
work practice standard from which you
deviated and either the parameter
monitor reading during the deviation or
a description of how you deviated from
the work practice standard.
PO 00000
Frm 00102
Fmt 4701
Sfmt 4700
(e) For each deviation from an
emission limitation occurring at an
affected source where you are using a
continuous opacity monitoring system
or a continuous emission monitoring
system to comply with the emission
limitation, you must include the
information in paragraphs (c)(1) through
(3) of this section, in paragraphs (d)(1)
through (3) of this section, and in
paragraphs (e)(2) through (13) of this
section.
*
*
*
*
*
(4) An estimate of the quantity of each
regulated pollutant emitted over the
emission limit during the deviation, and
a description of the method used to
estimate the emissions.
*
*
*
*
*
(6) A breakdown of the total duration
of the deviations during the reporting
period and into those that are due to
control equipment problems, process
problems, other known causes, and
other unknown causes.
*
*
*
*
*
(f) * * *
(1) You must include the information
in paragraph (f)(1)(i) or (ii) of this
section, if applicable.
(i) If you are complying with
paragraph (k)(1) of this section, a
summary of the results of any
performance test done during the
reporting period on any affected unit.
Results of the performance test include
the identification of the source tested,
the date of the test, the percentage of
emissions reduction or outlet pollutant
concentration reduction (whichever is
needed to determine compliance) for
each run and for the average of all runs,
and the values of the monitored
operating parameters.
(ii) If you are not complying with
paragraph (k)(1) of this section, a copy
of any performance test done during the
reporting period on any affected unit.
The report may be included in the next
semiannual compliance report. The
copy must include a complete report for
each test method used for a particular
kind of emission point tested. For
additional tests performed for a similar
emission point using the same method,
you must submit the results and any
other information required, but a
complete test report is not required. A
complete test report contains a brief
process description; a simplified flow
diagram showing affected processes,
control equipment, and sampling point
locations; sampling site data;
description of sampling and analysis
procedures and any modifications to
standard procedures; quality assurance
procedures; record of operating
conditions during the test; record of
E:\FR\FM\01DER2.SGM
01DER2
tkelley on DSK3SPTVN1PROD with RULES2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
preparation of standards; record of
calibrations; raw data sheets for field
sampling; raw data sheets for field and
laboratory analyses; documentation of
calculations; and any other information
required by the test method.
(2) Any requested change in the
applicability of an emission standard
(e.g., you want to change from the PM
standard to the Ni standard for catalytic
cracking units or from the HCl
concentration standard to percent
reduction for catalytic reforming units)
in your compliance report. You must
include all information and data
necessary to demonstrate compliance
with the new emission standard
selected and any other associated
requirements.
*
*
*
*
*
(k) Electronic submittal of
performance test and CEMS
performance evaluation data. For
performance tests or CEMS performance
evaluations conducted on and after
February 1, 2016, if required to submit
the results of a performance test or
CEMS performance evaluation, you
must submit the results according to the
procedures in paragraphs (k)(1) and (2)
of this section.
(1) Within 60 days after the date of
completing each performance test as
required by this subpart, you must
submit the results of the performance
tests following the procedure specified
in either paragraph (k)(1)(i) or (ii) of this
section.
(i) For data collected using test
methods supported by the EPA’s
Electronic Reporting Tool (ERT) as
listed on the EPA’s ERT Web site
(https://www.epa.gov/ttn/chief/ert/
index.html) at the time of the test, you
must submit the results of the
performance test to the EPA via the
Compliance and Emissions Data
Reporting Interface (CEDRI). (CEDRI can
be accessed through the EPA’s Central
Data Exchange (CDX) (https://
cdx.epa.gov/).) Performance test data
must be submitted in a file format
generated through use of the EPA’s ERT
or an alternate electronic file format
consistent with the extensible markup
language (XML) schema listed on the
EPA’s ERT Web site. If you claim that
some of the performance test
information being submitted is
confidential business information (CBI),
you must submit a complete file
generated through the use of the EPA’s
ERT or an alternate electronic file
consistent with the XML schema listed
on the EPA’s ERT Web site, including
information claimed to be CBI, on a
compact disc, flash drive or other
commonly used electronic storage
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
media to the EPA. The electronic storage
media must be clearly marked as CBI
and mailed to U.S. EPA/OAQPS/CORE
CBI Office, Attention: Group Leader,
Measurement Policy Group, MD C404–
02, 4930 Old Page Rd., Durham, NC
27703. The same ERT or alternate file
with the CBI omitted must be submitted
to the EPA via the EPA’s CDX as
described earlier in this paragraph
(k)(1)(i).
(ii) For data collected using test
methods that are not supported by the
EPA’s ERT as listed on the EPA’s ERT
Web site at the time of the test, you must
submit the results of the performance
test to the Administrator at the
appropriate address listed in § 63.13.
(2) Within 60 days after the date of
completing each CEMS performance
evaluation required by § 63.1571(a) and
(b), you must submit the results of the
performance evaluation following the
procedure specified in either paragraph
(k)(2)(i) or (ii) of this section.
(i) For performance evaluations of
continuous monitoring systems
measuring relative accuracy test audit
(RATA) pollutants that are supported by
the EPA’s ERT as listed on the EPA’s
ERT Web site at the time of the
evaluation, you must submit the results
of the performance evaluation to the
EPA via the CEDRI. (CEDRI is accessed
through the EPA’s CDX.) Performance
evaluation data must be submitted in a
file format generated through the use of
the EPA’s ERT or an alternate file format
consistent with the XML schema listed
on the EPA’s ERT Web site. If you claim
that some of the performance evaluation
information being submitted is CBI, you
must submit a complete file generated
through the use of the EPA’s ERT or an
alternate electronic file consistent with
the XML schema listed on the EPA’s
ERT Web site, including information
claimed to be CBI, on a compact disc,
flash drive or other commonly used
electronic storage media to the EPA. The
electronic storage media must be clearly
marked as CBI and mailed to U.S. EPA/
OAQPS/CORE CBI Office, Attention:
Group Leader, Measurement Policy
Group, MD C404–02, 4930 Old Page Rd.,
Durham, NC 27703. The same ERT or
alternate file with the CBI omitted must
be submitted to the EPA via the EPA’s
CDX as described earlier in this
paragraph (k)(2)(i).
(ii) For any performance evaluations
of continuous monitoring systems
measuring RATA pollutants that are not
supported by the EPA’s ERT as listed on
the EPA’s ERT Web site at the time of
the evaluation, you must submit the
results of the performance evaluation to
the Administrator at the appropriate
address listed in § 63.13.
PO 00000
Frm 00103
Fmt 4701
Sfmt 4700
75279
50. Section 63.1576 is amended by
revising paragraphs (a)(2) and (b)(3) and
(5) to read as follows:
■
§ 63.1576 What records must I keep, in
what form, and for how long?
(a) * * *
(2) The records specified in
paragraphs (a)(2)(i) through (iv) of this
section.
(i) Record the date, time, and duration
of each startup and/or shutdown period,
recording the periods when the affected
source was subject to the standard
applicable to startup and shutdown.
(ii) In the event that an affected unit
fails to meet an applicable standard,
record the number of failures. For each
failure record the date, time and
duration of each failure.
(iii) For each failure to meet an
applicable standard, record and retain a
list of the affected sources or equipment,
an estimate of the volume of each
regulated pollutant emitted over any
emission limit and a description of the
method used to estimate the emissions.
(iv) Record actions taken to minimize
emissions in accordance with
§ 63.1570(c) and any corrective actions
taken to return the affected unit to its
normal or usual manner of operation.
*
*
*
*
*
(b) * * *
(3) The performance evaluation plan
as described in § 63.8(d)(2) for the life
of the affected source or until the
affected source is no longer subject to
the provisions of this part, to be made
available for inspection, upon request,
by the Administrator. If the performance
evaluation plan is revised, you must
keep previous (i.e., superseded) versions
of the performance evaluation plan on
record to be made available for
inspection, upon request, by the
Administrator, for a period of 5 years
after each revision to the plan. The
program of corrective action should be
included in the plan required under
§ 63.8(d)(2).
*
*
*
*
*
(5) Records of the date and time that
each deviation started and stopped.
*
*
*
*
*
■ 51. Section 63.1579 is amended by:
■ a. Revising the introductory text;
■ b. Adding, in alphabetical order, a
new definition of ‘‘Hot standby’’; and
■ c. Revising the definitions of
‘‘Deviation’’ and ‘‘PM’’.
The revisions read as follows:
§ 63.1579
subpart?
What definitions apply to this
Terms used in this subpart are
defined in the Clean Air Act (CAA), in
40 CFR 63.2, the General Provisions of
E:\FR\FM\01DER2.SGM
01DER2
75280
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
this part (§§ 63.1 through 63.15), and in
this section as listed. If the same term
is defined in subpart A of this part and
in this section, it shall have the meaning
given in this section for purposes of this
subpart.
*
*
*
*
*
Deviation means any instance in
which an affected source subject to this
subpart, or an owner or operator of such
a source:
(1) Fails to meet any requirement or
obligation established by this subpart,
including but not limited to any
emission limit, operating limit, or work
practice standard; or
(2) Fails to meet any term or condition
that is adopted to implement an
applicable requirement in this subpart
and that is included in the operating
permit for any affected source required
to obtain such a permit.
*
*
*
*
*
Hot standby means periods when the
catalytic cracking unit is not receiving
fresh or recycled feed oil but the
catalytic cracking unit is maintained at
elevated temperatures, typically using
torch oil in the catalyst regenerator and
recirculating catalyst, to prevent a
complete shutdown and cold restart of
the catalytic cracking unit.
*
*
*
*
*
PM means, for the purposes of this
subpart, emissions of particulate matter
that serve as a surrogate measure of the
total emissions of particulate matter and
metal HAP contained in the particulate
matter, including but not limited to:
Antimony, arsenic, beryllium,
cadmium, chromium, cobalt, lead,
manganese, nickel, and selenium as
measured by Methods 5, 5B or 5F in
appendix A–3 to part 60 of this chapter
or by an approved alternative method.
*
*
*
*
*
52. Table 1 to subpart UUU of part 63
is revised to read as follows:
As stated in § 63.1564(a)(1), you shall
meet each emission limitation in the
following table that applies to you.
■
TABLE 1 TO SUBPART UUU OF PART 63—METAL HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS
For each new or existing catalytic cracking unit . . .
You shall meet the following emission limits for
each catalyst regenerator vent . . .
1. Subject to new source performance standard (NSPS) for PM in 40
CFR 60.102 and not electing § 60.100(e).
PM emissions must not exceed 1.0 gram per kilogram (g/kg) (1.0 lb/
1,000 lb) of coke burn-off, and the opacity of emissions must not exceed 30 percent, except for one 6-minute average opacity reading in
any 1-hour period. Before August 1, 2017, if the discharged gases
pass through an incinerator or waste heat boiler in which you burn
auxiliary or in supplemental liquid or solid fossil fuel, the incremental
rate of PM emissions must not exceed 43.0 grams per Gigajoule (g/
GJ) or 0.10 pounds per million British thermal units (lb/million Btu) of
heat input attributable to the liquid or solid fossil fuel; and the opacity
of emissions must not exceed 30 percent, except for one 6-minute
average opacity reading in any 1-hour period.
PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1,000 lb) of coke
burn-off or, if a PM CEMS is used, 0.040 grain per dry standard
cubic feet (gr/dscf) corrected to 0 percent excess air.
PM emissions must not exceed 0.5 g/kg coke burn-off (0.5 lb/1000 lb
coke burn-off) or, if a PM CEMS is used, 0.020 gr/dscf corrected to 0
percent excess air.
PM emissions must not exceed the limits specified in Item 1 of this
table.
2. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(i); or 40 CFR
60.102 and electing § 60.100(e).
3. Subject to NSPS for PM in 40 CFR 60.102a(b)(1)(ii) ..........................
4. Option 1a: Elect NSPS subpart J requirements for PM per coke burn
limit and 30% opacity, not subject to the NSPS for PM in 40 CFR
60.102 or 60.102a(b)(1).
5. Option 1b: Elect NSPS subpart Ja requirements for PM per coke
burn-off limit, not subject to the NSPS for PM in 40 CFR 60.102 or
60.102a(b)(1).
6. Option 1c: Elect NSPS subpart Ja requirements for PM concentration limit, not subject to the NSPS for PM in 40 CFR 60.102 or
60.102a(b)(1).
7. Option 2: PM per coke burn-off limit, not subject to the NSPS for PM
in 40 CFR 60.102 or 60.102a(b)(1).
8. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40 CFR
60.102 or 60.102a(b)(1).
9. Option 4: Ni per coke burn-off limit, not subject to the NSPS for PM
in 40 CFR 60.102 or 60.102a(b)(1).
53. Table 2 to subpart UUU of part 63
is revised to read as follows:
■
PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1000 lb) of coke
burn-off.
PM emissions must not exceed 0.040 gr/dscf corrected to 0 percent
excess air.
PM emissions must not exceed 1.0 g/kg (1.0 lb PM/1000 lb) of coke
burn-off in the catalyst regenerator.
Nickel (Ni) emissions must not exceed 13,000 milligrams per hour (mg/
hr) (0.029 lb/hr).
Ni emissions must not exceed 1.0 mg/kg (0.001 lb/1,000 lb) of coke
burn-off in the catalyst regenerator.
As stated in § 63.1564(a)(2), you shall
meet each operating limit in the
following table that applies to you.
tkelley on DSK3SPTVN1PROD with RULES2
TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING
UNITS
For each new or existing catalytic
cracking unit . . .
For this type of continuous
monitoring system . . .
For this type of control
device . . .
You shall meet this operating
limit . . .
1. Subject to the NSPS for PM in
40 CFR 60.102 and not electing
§ 60.100(e).
Continuous
system.
Any ................................................
Maintain the 3-hour rolling average opacity of emissions from
your catalyst regenerator vent
no higher than 20 percent.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
opacity
PO 00000
monitoring
Frm 00104
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75281
TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING
UNITS—Continued
For each new or existing catalytic
cracking unit . . .
For this type of continuous
monitoring system . . .
For this type of control
device . . .
You shall meet this operating
limit . . .
2. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i) or electing
§ 60.100(e).
a. PM CEMS .................................
Any ................................................
Not applicable.
b. Continuous opacity monitoring
system used to comply with a
site-specific opacity limit.
Cyclone or electrostatic precipitator.
c. Continuous parameter monitoring systems.
Electrostatic precipitator ...............
d. Continuous parameter monitoring systems.
Wet scrubber ................................
e. Bag leak detection (BLD) system.
Fabric filter ....................................
Any ................................................
Any ................................................
Any ................................................
Any ................................................
Maintain the 3-hour rolling average opacity of emissions from
your catalyst regenerator vent
no higher than the site-specific
opacity limit established during
the performance test.
i. Maintain the daily average coke
burn-off rate or daily average
flow rate no higher than the
limit established in the performance test.
ii. Maintain the 3-hour rolling average total power and secondary
current above the limit established in the performance test.
i. Maintain the 3-hour rolling average liquid-to-gas ratio above
the limit established in the performance test.
ii. Except for periods of startup,
shutdown, and hot standby,
maintain the 3-hour rolling average pressure drop above the
limit established in the performance test.1
Maintain particulate loading below
the BLD alarm set point established in the initial adjustment
of the BLD system or allowable
seasonal adjustments.
The applicable operating limits in
Item 2 of this table.
See Item 1 of this table.
Any ................................................
Any ................................................
The applicable operating limits in
Item 2.b, 2.c, 2.d, and 2.e of
this table.
PM CEMS .....................................
Any ................................................
Not applicable.
a. Continuous opacity monitoring
system used to comply with a
site-specific opacity limit.
Cyclone, fabric filter, or electrostatic precipitator.
b. Continuous parameter monitoring systems.
i. Electrostatic precipitator ............
See Item 2.b of this table. Alternatively, before August 1, 2017,
you may maintain the hourly
average opacity of emissions
from your catalyst generator
vent no higher than the sitespecific opacity limit established
during the performance test.
(1) See Item 2.c.i of this table.
(2) See item 2.c.ii of this table. Alternatively, before August 1,
2017, you may maintain the
daily average voltage and secondary current above the limit
established in the performance
test.
tkelley on DSK3SPTVN1PROD with RULES2
3. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(ii).
4. Option 1a: Elect NSPS subpart
J requirements for PM per coke
burn limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
5. Option 1b: Elect NSPS subpart
Ja requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
6. Option 1c: Elect NSPS subpart
Ja requirements for PM concentration limit, not subject to
the NSPS for PM in 40 CFR
60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off
limit not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00105
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75282
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING
UNITS—Continued
For each new or existing catalytic
cracking unit . . .
For this type of continuous
monitoring system . . .
For this type of control
device . . .
You shall meet this operating
limit . . .
ii. Wet scrubber ............................
(1) See Item 2.d.i of this table. Alternatively, before August 1,
2017, you may maintain the
daily average liquid-to-gas ratio
above the limit established in
the performance test.
(2) See Item 2.d.ii of the table. Alternatively, before August 1,
2017, you may maintain the
daily average pressure drop
above the limit established in
the performance test (not applicable to a wet scrubber of the
non-venturi jet-ejector design).
See item 2.e of this table.
Fabric filter ....................................
b. Continuous parameter monitoring systems.
8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40
CFR 60.102.
c. Bag leak detection (BLD) system.
a. Continuous opacity monitoring
system.
i. Electrostatic precipitator ............
Cyclone, fabric filter, or electrostatic precipitator.
ii. Wet scrubber ............................
tkelley on DSK3SPTVN1PROD with RULES2
c. Bag leak detection (BLD) system.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00106
Fmt 4701
Fabric filter ....................................
Sfmt 4700
E:\FR\FM\01DER2.SGM
Maintain the 3-hour rolling average Ni operating value no higher than the limit established
during the performance test. Alternatively, before August 1,
2017, you may maintain the
daily average Ni operating
value no higher than the limit
established during the performance test.
(1) See Item 2.c.i of this table.
(2) Maintain the monthly rolling
average of the equilibrium catalyst Ni concentration no higher
than the limit established during
the performance test.
(3) See Item 2.c.ii of this table. Alternatively, before August 1,
2017, you may maintain the
daily average voltage and secondary current (or total power
input) above the established
during the performance test.
(1) Maintain the monthly rolling
average of the equilibrium catalyst Ni concentration no higher
than the limit established during
the performance test.
(2) See Item 2.d.i of this table. Alternatively, before August 1,
2017, you may maintain the
daily average liquid-to-gas ratio
above the limit established during the performance test.
(3) See Item 2.d.ii of this table. Alternatively, before August 1,
2017, you may maintain the
daily average pressure drop
above the limit established during the performance test (not
applicable to a non-venturi wet
scrubber of the jet-ejector design).
See item 2.e of this table.
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75283
TABLE 2 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR METAL HAP EMISSIONS FROM CATALYTIC CRACKING
UNITS—Continued
For each new or existing catalytic
cracking unit . . .
For this type of continuous
monitoring system . . .
For this type of control
device . . .
You shall meet this operating
limit . . .
9. Option 4: Ni per coke burn-off
limit not subject to the NSPS for
PM in 40 CFR 60.102.
a. Continuous opacity monitoring
system.
Cyclone, fabric filter, or electrostatic precipitator.
b. Continuous parameter monitoring systems.
i. Electrostatic precipitator ............
Maintain the 3-hour rolling average Ni operating value no higher than Ni operating limit established during the performance
test. Alternatively, before August 1, 2017, you may elect to
maintain the daily average Ni
operating value no higher than
the Ni operating limit established during the performance
test.
(1) Maintain the monthly rolling
average of the equilibrium catalyst Ni concentration no higher
than the limit established during
the performance test.
(2) See Item 2.c.ii of this table. Alternatively, before August 1,
2017, you may maintain the
daily average voltage and secondary current (or total power
input) above the limit established during the performance
test.
(1) Maintain the monthly rolling
average of the equilibrium catalyst Ni concentration no higher
than the limit established during
the performance test.
(2) See Item 2.d.i of this table. Alternatively, before August 1,
2017, you may maintain the
daily average liquid-to-gas ratio
above the limit established during the performance test.
(3) See Item 2.d.ii of this table. Alternatively, before August 1,
2017, you may maintain the
daily average pressure drop
above the limit established during the performance test (not
applicable to a non-venturi wet
scrubber of the jet-ejector design).
See item 2.e of this table.
ii. Wet scrubber ............................
10. During periods of startup, shutdown, or hot standby.
c. Bag leak detection (BLD) system.
Any ................................................
Fabric filter ....................................
Any ................................................
Meet
the
requirements
§ 63.1564(a)(5).
in
1 If you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in
§ 63.1573(b), and comply with the daily inspections, recordkeeping, and repair provisions, instead of a continuous parameter monitoring system
for pressure drop across the scrubber.
54. Table 3 to subpart UUU of part 63
is revised to read as follows:
■
As stated in § 63.1564(b)(1), you shall
meet each requirement in the following
table that applies to you.
tkelley on DSK3SPTVN1PROD with RULES2
TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS
For each new or existing catalytic
cracking unit . . .
If you use this type of control device for your vent . . .
You shall install, operate, and maintain a . . .
1. Subject to the NSPS for PM in
40 CFR 60.102 and not electing
§ 60.100(e).
Any .................................................
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00107
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75284
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
If you use this type of control device for your vent . . .
You shall install, operate, and maintain a . . .
2. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i); or in
§ 60.102
and
electing
§ 60.100(e); electing to meet the
PM per coke burn-off limit.
a. Cyclone ......................................
b. Electrostatic precipitator ............
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent.
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent; or continuous parameter monitoring systems to measure and record the
coke burn-off rate or the gas flow rate entering or exiting the control device,1 the voltage, current, and secondary current to the control device.
Continuous parameter monitoring system to measure and record the
pressure drop across the scrubber,2 the coke burn-off rate or the
gas flow rate entering or exiting the control device,3 and total liquid
(or scrubbing liquor) flow rate to the control device.
Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent.
Continuous emission monitoring system to measure and record the
concentration of PM and oxygen from each catalyst regenerator
vent.
c. Wet scrubber .............................
d. Fabric Filter ...............................
3. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i); or in
§ 60.102
and
electing
§ 60.100(e); electing to meet the
PM concentration limit.
4. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(ii) electing to
meet the PM per coke burn-off
limit.
5. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(ii) electing to
meet the PM concentration limit.
6. Option 1a: Elect NSPS subpart
J, PM per coke burn-off limit, not
subject to the NSPS for PM in 40
CFR 60.102 or 60.120a(b)(1).
7. Option 1b: Elect NSPS subpart
Ja, PM per coke burn-off limit,
not subject to the NSPS for PM
in
40
CFR
60.102
or
60.120a(b)(1).
8. Option 1c: Elect NSPS subpart
Ja, PM concentration limit not
subject to the NSPS for PM in 40
CFR 60.102 or 60.120a(b)(1).
9. Option 2: PM per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.120a(b)(1).
10. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40
CFR 60.102 or 60.102a(b)(1).
Any .................................................
Any .................................................
The applicable continuous monitoring systems in item 2 of this table.
Any .................................................
See item 3 of this table.
Any .................................................
See item 1 of this table.
Any .................................................
The applicable continuous monitoring systems in item 2 of this table.
Any .................................................
See item 3 of this table.
Any .................................................
The applicable continuous monitoring systems in item 2 of this table.
a. Cyclone ......................................
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the
gas flow rate entering or exiting the control device.1
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the
gas flow rate entering or exiting the control device 1; or continuous
parameter monitoring systems to measure and record the coke
burn-off rate or the gas flow rate entering or exiting the control device 1 and the voltage and current (to measure the total power to
the system) and secondary current to the control device.
Continuous parameter monitoring system to measure and record the
pressure drop across the scrubber,2 gas flow rate entering or
exiting the control device,1 and total liquid (or scrubbing liquor) flow
rate to the control device.
Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or the monitoring systems specified in item 10.a of this
table.
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the
coke burn-off rate and the gas flow rate entering or exiting the control device.1
b. Electrostatic precipitator ............
c. Wet scrubber .............................
tkelley on DSK3SPTVN1PROD with RULES2
d. Fabric Filter ...............................
11. Option 4: Ni per coke burn-off
limit not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
VerDate Sep<11>2014
23:11 Nov 30, 2015
a. Cyclone ......................................
Jkt 238001
PO 00000
Frm 00108
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75285
TABLE 3 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
If you use this type of control device for your vent . . .
You shall install, operate, and maintain a . . .
b. Electrostatic precipitator ............
Continuous opacity monitoring system to measure and record the
opacity of emissions from each catalyst regenerator vent and continuous parameter monitoring system to measure and record the
coke burn-off rate and the gas flow rate entering or exiting the control device 1; or continuous parameter monitoring systems to measure and record the coke burn-off rate or the gas flow rate entering
or exiting the control device 1 and voltage and current (to measure
the total power to the system) and secondary current to the control
device.
Continuous parameter monitoring system to measure and record the
pressure drop across the scrubber,2 gas flow rate entering or
exiting the control device,1 and total liquid (or scrubbing liquor) flow
rate to the control device.
Continuous bag leak detection system to measure and record increases in relative particulate loading from each catalyst regenerator vent or the monitoring systems specified in item 11.a of this
table.
Continuous parameter monitoring system to measure and record the
gas flow rate exiting the catalyst regenerator.1
c. Wet scrubber .............................
d. Fabric Filter ...............................
12. Electing to comply with the operating
limits
in
§ 63.1566(a)(5)(iii) during periods
of startup, shutdown, or hot
standby.
Any .................................................
1 If
applicable, you can use the alternative in § 63.1573(a)(1) instead of a continuous parameter monitoring system for gas flow rate.
you use a jet ejector type wet scrubber or other type of wet scrubber equipped with atomizing spray nozzles, you can use the alternative in
§ 63.1573(b) instead of a continuous parameter monitoring system for pressure drop across the scrubber.
2 If
55. Table 4 to subpart UUU of part 63
is revised to read as follows:
■
As stated in §§ 63.1564(b)(2) and
63.1571(a)(5), you shall meet each
requirement in the following table that
applies to you.
TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS
For each new or existing catalytic
cracking unit catalyst regenerator
vent . . .
Using . . .
According to these
requirements . . .
a. Select sampling port’s location
and the number of traverse
ports.
Method 1 or 1A in appendix A–1
to part 60 of this chapter.
Sampling sites must be located at
the outlet of the control device
or the outlet of the regenerator,
as applicable, and prior to any
releases to the atmosphere.
b. Determine velocity and volumetric flow rate.
1. Any .............................................
You must . . .
Method 2, 2A, 2C, 2D, or 2F in
appendix A–1 to part 60 of this
chapter, or Method 2G in appendix A–2 to part 60 of this
chapter, as applicable.
Method 3, 3A, or 3B in appendix
A–2 to part 60 of this chapter,
as applicable.
Method 4 in appendix A–3 to part
60 of this chapter.
tkelley on DSK3SPTVN1PROD with RULES2
c. Conduct gas molecular weight
analysis.
d. Measure moisture content of
the stack gas.
e. If you use an electrostatic precipitator, record the total number of fields in the control system and how many operated
during the applicable performance test.
f. If you use a wet scrubber,
record the total amount (rate) of
water (or scrubbing liquid) and
the amount (rate) of make-up
liquid to the scrubber during
each test run.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00109
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75286
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit catalyst regenerator
vent . . .
2. Subject to the NSPS for PM in
40 CFR 60.102 and not elect
§ 60.100(e).
You must . . .
Using . . .
According to these
requirements . . .
a. Measure PM emissions ............
Method 5, 5B, or 5F (40 CFR part
60, appendix A–3) to determine
PM emissions and associated
moisture content for units without wet scrubbers. Method 5 or
5B (40 CFR part 60, appendix
A–3) to determine PM emissions and associated moisture
content for unit with wet scrubber.
Equations 1, 2, and 3 of
§ 63.1564 (if applicable).
You must maintain a sampling
rate of at least 0.15 dry standard cubic meters per minute
(dscm/min) (0.53 dry standard
cubic feet per minute (dscf/
min)).
Continuous
system.
You must collect opacity monitoring data every 10 seconds
during the entire period of the
Method 5, 5B, or 5F performance test and reduce the data
to 6-minute averages.
You must maintain a sampling
rate of at least 0.15 dscm/min
(0.53 dscf/min).
b. Compute coke burn-off rate
and PM emission rate (lb/1,000
lb of coke burn-off).
c. Measure opacity of emissions ..
3. Subject to the NSPS for PM in
40 CFR 60.102a(b)(1) or elect
§ 60.100(e), electing the PM for
coke burn-off limit.
a. Measure PM emissions ............
b. Compute coke burn-off rate
and PM emission rate (lb/1,000
lb of coke burn-off).
c. Establish site-specific limit if
you use a COMS.
tkelley on DSK3SPTVN1PROD with RULES2
4. Subject to the NSPS for PM in
40 CFR 60.102a(b)(1) or elect
§ 60.100(e).
a. Measure PM emissions ............
5. Option 1a: Elect NSPS subpart
J requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
6. Option 1b: Elect NSPS subpart
Ja requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
See item 2 of this table.
VerDate Sep<11>2014
23:11 Nov 30, 2015
opacity
monitoring
Method 5, 5B, or 5F (40 CFR part
60, appendix A–3) to determine
PM emissions and associated
moisture content for units without wet scrubbers. Method 5 or
5B (40 CFR part 60, appendix
A–3) to determine PM emissions and associated moisture
content for unit with wet scrubber.
Equations 1, 2, and 3 of
§ 63.1564 (if applicable).
Continuous
system.
opacity
monitoring
Method 5, 5B, or 5F (40 CFR part
60, appendix A–3) to determine
PM emissions and associated
moisture content for units without wet scrubbers. Method 5 or
5B (40 CFR part 60, appendix
A–3) to determine PM emissions and associated moisture
content for unit with wet scrubber.
.......................................................
If you elect to comply with the
site-specific opacity limit in
§ 63.1564(b)(4)(i), you must collect opacity monitoring data
every 10 seconds during the
entire period of the Method 5,
5B, or 5F performance test. For
site specific opacity monitoring,
reduce the data to 6-minute
averages; determine and record
the average opacity for each
test run; and compute the sitespecific opacity limit using
Equation 4 of § 63.1564.
You must maintain a sampling
rate of at least 0.15 dscm/min
(0.53 dscf/min).
See item 3 of this table.
Jkt 238001
PO 00000
Frm 00110
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75287
TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit catalyst regenerator
vent . . .
7. Option 1c: Elect NSPS requirements for PM concentration, not
subject to the NSPS for PM in
40 CFR 60.102 or 60.102a(b)(1).
8. Option 2: PM per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
9. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40
CFR 60.102 or 60.102a(b)(1).
You must . . .
According to these
requirements . . .
Using . . .
See item 4 of this table.
See item 3 of this table.
a. Measure concentration of Ni ....
b. Compute Ni emission rate (lb/
hr).
c. Determine the equilibrium catalyst Ni concentration.
Method 29 (40 CFR part 60, appendix A–8).
Equation 5 of § 63.1564.
XRF procedure in appendix A to
this subpart1; or EPA Method
6010B or 6020 or EPA Method
7520 or 7521 in SW–8462; or
an alternative to the SW–846
method satisfactory to the Administrator.
d. If you use a continuous opacity
monitoring system, establish
your site-specific Ni operating
limit.
10. Option 4: Ni per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
i. Equations 6 and 7 of § 63.1564
using data from continuous
opacity monitoring system, gas
flow rate, results of equilibrium
catalyst Ni concentration analysis, and Ni emission rate from
Method 29 test.
a. Measure concentration of Ni.
Method 29 (40 CFR part 60, appendix A–8).
Equations 1 and 8 of § 63.1564.
b. Compute Ni emission rate (lb/
1,000 lb of coke burn-off).
c. Determine the equilibrium catalyst Ni concentration.
tkelley on DSK3SPTVN1PROD with RULES2
d. If you use a continuous opacity
monitoring system, establish
your site-specific Ni operating
limit.
VerDate Sep<11>2014
23:11 Nov 30, 2015
You must obtain 1 sample for
each of the 3 test runs; determine and record the equilibrium
catalyst Ni concentration for
each of the 3 samples; and you
may adjust the laboratory results to the maximum value
using Equation 2 of § 63.1571.
(1) You must collect opacity monitoring data every 10 seconds
during the entire period of the
initial Ni performance test; reduce the data to 6-minute averages; and determine and record
the average opacity from all the
6-minute averages for each test
run.
(2) You must collect gas flow rate
monitoring data every 15 minutes during the entire period of
the initial Ni performance test;
measure the gas flow as near
as practical to the continuous
opacity monitoring system; and
determine and record the hourly
average actual gas flow rate for
each test run.
Jkt 238001
PO 00000
Frm 00111
Fmt 4701
See item 6.c. of this table ............
i.
Equations 9 and 10 of
§ 63.1564 with data from continuous opacity monitoring system, coke burn-off rate, results
of equilibrium catalyst Ni concentration analysis, and Ni
emission rate from Method 29
test.
Sfmt 4700
E:\FR\FM\01DER2.SGM
You must obtain 1 sample for
each of the 3 test runs; determine and record the equilibrium
catalyst Ni concentration for
each of the 3 samples; and you
may adjust the laboratory results to the maximum value
using Equation 2 of § 63.1571.
(1) You must collect opacity monitoring data every 10 seconds
during the entire period of the
initial Ni performance test; reduce the data to 6-minute averages; and determine and record
the average opacity from all the
6-minute averages for each test
run.
01DER2
75288
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit catalyst regenerator
vent . . .
You must . . .
According to these
requirements . . .
Using . . .
(2) You must collect gas flow rate
monitoring data every 15 minutes during the entire period of
the initial Ni performance test;
measure the gas flow rate as
near as practical to the continuous opacity monitoring system; and determine and record
the hourly average actual gas
flow rate for each test run.
11. If you elect item 5 Option 1b in
Table 1, item 7 Option 2 in
Table 1, item 8 Option 3 in
Table 1, or item 9 Option 4 in
Table 1 of this subpart and you
use continuous parameter monitoring systems.
e. Record the catalyst addition
rate for each test and schedule
for the 10-day period prior to
the test.
a. Establish each operating limit in
Table 2 of this subpart that applies to you.
Data from the continuous parameter monitoring systems and
applicable performance test
methods.
VerDate Sep<11>2014
23:11 Nov 30, 2015
i. Data from the continuous parameter monitoring systems
and applicable performance test
methods.
c. Electrostatic precipitator: Total
power (voltage and current) and
secondary current.
tkelley on DSK3SPTVN1PROD with RULES2
b. Electrostatic precipitator or wet
scrubber: Gas flow rate.
i. Data from the continuous parameter monitoring systems
and applicable performance test
methods.
Jkt 238001
PO 00000
Frm 00112
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
(1) You must collect gas flow rate
monitoring data every 15 minutes during the entire period of
the initial performance test; determine and record the average
gas flow rate for each test run.
(2) You must determine and
record the 3-hr average gas
flow rate from the test runs. Alternatively, before August 1,
2017, you may determine and
record the maximum hourly average gas flow rate from all the
readings.
(1) You must collect voltage, current, and secondary current
monitoring data every 15 minutes during the entire period of
the performance test; and determine and record the average
voltage, current, and secondary
current for each test run. Alternatively, before August 1, 2017,
you may collect voltage and
secondary current (or total
power input) monitoring data
every 15 minutes during the entire period of the initial performance test.
(2) You must determine and
record the 3-hr average total
power to the system for the test
runs and the 3-hr average secondary current from the test
runs. Alternatively, before August 1, 2017, you may determine and record the minimum
hourly average voltage and
secondary current (or total
power input) from all the readings.
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75289
TABLE 4 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR METAL HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit catalyst regenerator
vent . . .
Results of analysis for equilibrium
catalyst Ni concentration.
i. Data from the continuous parameter monitoring systems
and applicable performance test
methods.
f.
Liquid-to-gas
i. Data from the continuous parameter monitoring systems
and applicable performance test
methods.
g. Alternative procedure for gas
flow rate.
tkelley on DSK3SPTVN1PROD with RULES2
According to these
requirements . . .
e. Wet scrubber: Pressure drop
(not applicable to non-venturi
scrubber of jet ejector design).
VerDate Sep<11>2014
Using . . .
d. Electrostatic precipitator or wet
scrubber: Equilibrium catalyst
Ni concentration.
1 Determination
You must . . .
i. Data from the continuous parameter monitoring systems
and applicable performance test
methods.
You must determine and record
the average equilibrium catalyst
Ni concentration for the 3 runs
based on the laboratory results.
You may adjust the value using
Equation 1 or 2 of § 63.1571 as
applicable.
(1) You must collect pressure
drop monitoring data every 15
minutes during the entire period
of the initial performance test;
and determine and record the
average pressure drop for each
test run.
(2) You must determine and
record the 3-hr average pressure drop from the test runs. Alternatively, before August 1,
2017, you may determine and
record the minimum hourly average pressure drop from all
the readings.
(1) You must collect gas flow rate
and total water (or scrubbing
liquid) flow rate monitoring data
every 15 minutes during the entire period of the initial performance test; determine and record
the average gas flow rate for
each test run; and determine
the average total water (or
scrubbing liquid) flow for each
test run.
(2) You must determine and
record the hourly average liquid-to-gas ratio from the test
runs. Alternatively, before August 1, 2017, you may determine and record the hourly average gas flow rate and total
water (or scrubbing liquid) flow
rate from all the readings.
(3) You must determine and
record the 3-hr average liquidto-gas ratio. Alternatively, before August 1, 2017, you may
determine and record the minimum liquid-to-gas ratio.
(1) You must collect air flow rate
monitoring data or determine
the air flow rate using control
room instrumentation every 15
minutes during the entire period
of the initial performance test.
(2) You must determine and
record the 3-hr average rate of
all the readings from the test
runs. Alternatively, before August 1, 2017, you may determine and record the hourly average rate of all the readings.
(3) You must determine and
record the maximum gas flow
rate using Equation 1 of
§ 63.1573.
Wet
ratio.
scrubber:
of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure).
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00113
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75290
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
2 EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, and EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration are
included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–
846 and Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government
Publishing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road,
Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air
Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite
700, Washington, DC.
56. Table 5 to subpart UUU of part 63
is revised to read as follows:
■
As stated in § 63.1564(b)(5), you shall
meet each requirement in the following
table that applies to you.
TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC
CRACKING UNITS
For each new and existing catalytic
cracking unit catalyst regenerator
vent . . .
For the following emission
limit . . .
You have demonstrated initial compliance if . . .
1. Subject to the NSPS for PM in
40 CFR 60.102 and not electing
§ 60.100(e).
PM emissions must not exceed
1.0 g/kg (1.0 lb/1,000 lb) of coke
burn-off, and the opacity of
emissions must not exceed 30
percent, except for one 6-minute
average opacity reading in any
1-hour period. Before August 1,
2017, if the discharged gases
pass through an incinerator or
waste heat boiler in which you
burn auxiliary or supplemental
liquid or solid fossil fuel, the incremental rate of PM must not
exceed 43.0 g/GJ or 0.10 lb/million Btu of heat input attributable
to the liquid or solid fossil fuel;
and the opacity of emissions
must not exceed 30 percent, except for one 6-minute average
opacity reading in any 1-hour
period.
PM emissions must not exceed
1.0 g/kg (1.0 lb PM/1,000 lb) of
coke burn-off.
You have already conducted a performance test to demonstrate initial
compliance with the NSPS and the measured PM emission rate is
less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in
the catalyst regenerator. As part of the Notification of Compliance
Status, you must certify that your vent meets the PM limit. You are
not required to do another performance test to demonstrate initial
compliance. You have already conducted a performance test to
demonstrate initial compliance with the NSPS and the average
hourly opacity is no more than 30 percent, except that one 6minute average in any 1-hour period can exceed 30 percent. As
part of the Notification of Compliance Status, you must certify that
your vent meets the 30 percent opacity limit. As part of your Notification of Compliance Status, you certify that your continuous opacity monitoring system meets the requirements in § 63.1572.
2. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i); or in
§ 60.102
and
electing
§ 60.100(e); electing to meet the
PM per coke burn-off limit.
PM emissions must not exceed
0.5 g/kg (0.5 lb PM/1,000 lb) of
coke burn-off).
4. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i), electing to
meet the PM concentration limit.
tkelley on DSK3SPTVN1PROD with RULES2
3. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i), electing to
meet the PM per coke burn-off
limit.
If a PM CEMS is used, 0.040
grain per dry standard cubic feet
(gr/dscf) corrected to 0 percent
excess air.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00114
Fmt 4701
You have already conducted a performance test to demonstrate initial
compliance with the NSPS and the measured PM emission rate is
less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in
the catalyst regenerator. As part of the Notification of Compliance
Status, you must certify that your vent meets the PM limit. You are
not required to do another performance test to demonstrate initial
compliance. As part of your Notification of Compliance Status, you
certify that your BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system meets the requirements in § 63.1572.
You have already conducted a performance test to demonstrate initial
compliance with the NSPS and the measured PM emission rate is
less than or equal to 1.0 g/kg (1.0 lb/1,000 lb) of coke burn-off in
the catalyst regenerator. As part of the Notification of Compliance
Status, you must certify that your vent meets the PM limit. You are
not required to do another performance test to demonstrate initial
compliance. As part of your Notification of Compliance Status, you
certify that your BLD; CO2, O2, or CO monitor; or continuous opacity monitoring system meets the requirements in § 63.1572.
You have already conducted a performance test to demonstrate initial
compliance with the NSPS and the measured PM concentration is
less than or equal to 0.040 grain per dry standard cubic feet (gr/
dscf) corrected to 0 percent excess air. As part of the Notification
of Compliance Status, you must certify that your vent meets the
PM limit. You are not required to do another performance test to
demonstrate initial compliance. As part of your Notification of Compliance Status, you certify that your PM CEMS meets the requirements in § 63.1572.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75291
TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC
CRACKING UNITS—Continued
For each new and existing catalytic
cracking unit catalyst regenerator
vent . . .
For the following emission
limit . . .
You have demonstrated initial compliance if . . .
5. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(ii), electing to
meet the PM concentration limit.
If a PM CEMS is used, 0.020 gr/
dscf corrected to 0 percent excess air.
6. Option 1a: Elect NSPS subpart J
requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
PM emissions must not exceed
1.0 gram per kilogram (g/kg)
(1.0 lb/1,000 lb) of coke burnoff, and the opacity of emissions
must not exceed 30 percent, except for one 6-minute average
opacity reading in any 1-hour
period. Before August 1, 2017,
PM emission must not exceed
1.0 g/kg (1.0 lb/1,000 lb) of coke
burn-off in the catalyst regenerator; if the discharged gases
pass through an incinerator or
waste heat boiler in which you
burn auxiliary or supplemental
liquid or solid fossil fuel, the incremental rate of PM must not
exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input attributable to the liquid or solid fossil
fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute
average opacity reading in any
1-hour period.
PM emissions must not exceed
1.0 g/kg (1.0 lb/1,000 lb) of coke
burn-off.
You have already conducted a performance test to demonstrate initial
compliance with the NSPS and the measured PM concentration is
less than or equal to 0.020 gr/dscf corrected to 0 percent excess
air. As part of the Notification of Compliance Status, you must certify that your vent meets the PM limit. You are not required to do
another performance test to demonstrate initial compliance. As part
of your Notification of Compliance Status, you certify that your PM
CEMS meets the requirements in § 63.1572.
The average PM emission rate, measured using EPA Method 5, 5B,
or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with
a wet scrubber) (40 CFR part 60, appendix A–3), over the period
of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission
rate is calculated using Equations 1, 2, and 3 of § 63.1564. As part
of the Notification of Compliance Status, you must certify that your
vent meets the PM limit. The average hourly opacity is no more
than 30 percent, except that one 6-minute average in any 1-hour
period can exceed 30 percent. As part of the Notification of Compliance Status, you must certify that your vent meets the 30 percent opacity limit. If you use a continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572.
7. Option 1b: Elect NSPS subpart
Ja requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
PM emissions must not exceed
0.040 gr/dscf corrected to 0 percent excess air.
9. Option 2: PM per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
tkelley on DSK3SPTVN1PROD with RULES2
8. Option 1c: Elect NSPS subpart
Ja requirements for PM concentration limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
PM emissions must not exceed
1.0 g/kg (1.0 lb/1,000 lb) of coke
burn-off.
10. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40
CFR 60.102 or 60.102a(b)(1).
Nickel (Ni) emissions from your
catalyst regenerator vent must
not exceed 13,000 mg/hr (0.029
lb/hr).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00115
Fmt 4701
The average PM emission rate, measured using EPA Method 5, 5B,
or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with
a wet scrubber) (40 CFR part 60, appendix A–3), over the period
of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission
rate is calculated using Equations 1, 2, and 3 of § 63.1564. If you
use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring
system, your performance evaluation shows the system meets the
applicable requirements in § 63.1572.
The average PM concentration, measured using EPA Method 5, 5B,
or 5F (for a unit without a wet scrubber) or Method 5 or 5B (for a
unit with a wet scrubber) (40 CFR part 60, appendix A–3), over the
period of the initial performance test, is less than or equal to 0.040
gr/dscf corrected to 0 percent excess air. Your performance evaluation shows your PM CEMS meets the applicable requirements in
§ 63.1572.
The average PM emission rate, measured using EPA Method 5, 5B,
or 5F (for a unit without a wet scrubber) or 5 or 5B (for a unit with
a wet scrubber) (40 CFR part 60, appendix A–3), over the period
of the initial performance test, is no higher than 1.0 g/kg coke burnoff (1.0 lb/1,000 lb) in the catalyst regenerator. The PM emission
rate is calculated using Equations 1, 2, and 3 of § 63.1564. If you
use a BLD; CO2, O2, CO monitor; or continuous opacity monitoring
system, your performance evaluation shows the system meets the
applicable requirements in § 63.1572.
The average Ni emission rate, measured using Method 29 (40 CFR
part 60, appendix A–8) over the period of the initial performance
test, is not more than 13,000 mg/hr (0.029 lb/hr). The Ni emission
rate is calculated using Equation 5 of § 63.1564; and if you use a
BLD; CO2, O2, or CO monitor; or continuous opacity monitoring
system, your performance evaluation shows the system meets the
applicable requirements in § 63.1572.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75292
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 5 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC
CRACKING UNITS—Continued
For each new and existing catalytic
cracking unit catalyst regenerator
vent . . .
For the following emission
limit . . .
You have demonstrated initial compliance if . . .
11. Option 4: Ni per coke burn-off
limit not subject to the NSPS for
PM.
Ni emissions from your catalyst regenerator vent must not exceed
1.0 mg/kg (0.001 lb/1,000 lb) of
coke burn-off in the catalyst regenerator.
The average Ni emission rate, measured using Method 29 (40 CFR
part 60, appendix A–8) over the period of the initial performance
test, is not more than 1.0 mg/kg (0.001 lb/1,000 lb) of coke burn-off
in the catalyst regenerator. The Ni emission rate is calculated using
Equation 8 of § 63.1564; and if you use a BLD; CO2, O2, or CO
monitor; or continuous opacity monitoring system, your performance evaluation shows the system meets the applicable requirements in § 63.1572.
57. Table 6 to subpart UUU of part 63
is revised to read as follows:
■
As stated in § 63.1564(c)(1), you shall
meet each requirement in the following
table that applies to you.
TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC
CRACKING UNITS
For each new and existing catalytic
cracking unit . . .
Subject to this emission limit for
your catalyst regenerator vent . . .
You shall demonstrate continuous compliance by . . .
1. Subject to the NSPS for PM in
40 CFR 60.102 and not electing
§ 60.100(e).
a. PM emissions must not exceed
1.0 g/kg (1.0 lb/1,000 lb) of coke
burn-off, and the opacity of
emissions must not exceed 30
percent, except for one 6-minute
average opacity reading in any
1-hour period. Before August 1,
2017, if the discharged gases
pass through an incinerator or
waste heat boiler in which you
burn auxiliary or supplemental
liquid or solid fossil fuel, the incremental rate of PM must not
exceed 43.0 g/GJ (0.10 lb/million Btu) of heat input attributable to the liquid or solid fossil
fuel; and the opacity of emissions must not exceed 30 percent, except for one 6-minute
average opacity reading in any
1-hour period.
i. Determining and recording each day the average coke burn-off rate
(thousands of kilograms per hour) using Equation 1 in § 63.1564
and the hours of operation for each catalyst regenerator.
tkelley on DSK3SPTVN1PROD with RULES2
2. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i), electing to
meet the PM per coke burn-off
limit.
PM emissions must not exceed
1.0 g/kg (1.0 lb PM/1,000 lb) of
coke burn-off.
3. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(ii), electing to
meet the PM per coke burn-off
limit.
PM emissions must not exceed
0.5 g/kg coke burn-off (0.5 lb/
1000 lb coke burn-off).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00116
Fmt 4701
ii. Conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit.
iii. Collecting the continuous opacity monitoring data for each catalyst
regenerator vent according to § 63.1572 and maintaining each 6minute average at or below 30 percent, except that one 6-minute
average during a 1-hour period can exceed 30 percent.
iv. Before August 1, 2017, if applicable, determining and recording
each day the rate of combustion of liquid or solid fossil fuels (liters/
hour or kilograms/hour) and the hours of operation during which
liquid or solid fossil-fuels are combusted in the incinerator-waste
heat boiler; if applicable, maintaining the incremental rate of PM at
or below 43 g/GJ (0.10 lb/million Btu) of heat input attributable to
the solid or liquid fossil fuel.
Determining and recording each day the average coke burn-off rate
(thousands of kilograms per hour) using Equation 1 in § 63.1564
and the hours of operation for each catalyst regenerator; maintaining PM emission rate below 1.0 g/kg (1.0 lb PM/1,000 lb) of coke
burn-off; and conducting a performance test once every year.
Determining and recording each day the average coke burn-off rate
(thousands of kilograms per hour) using Equation 1 in § 63.1564
and the hours of operation for each catalyst regenerator; maintaining PM emission rate below 0.5 g/kg (0.5 lb/1,000 lb) of coke burnoff; and conducting a performance test once every year.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75293
TABLE 6 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH METAL HAP EMISSION LIMITS FOR CATALYTIC
CRACKING UNITS—Continued
For each new and existing catalytic
cracking unit . . .
Subject to this emission limit for
your catalyst regenerator vent . . .
You shall demonstrate continuous compliance by . . .
4. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(i), electing to
meet the PM concentration limit.
If a PM CEMS is used, 0.040
grain per dry standard cubic feet
(gr/dscf) corrected to 0 percent
excess air.
If a PM CEMS is used, 0.020 gr/
dscf corrected to 0 percent excess air.
See item 1 of this table .................
Maintaining PM concentration below 0.040 gr/dscf corrected to 0 percent excess air.
5. Subject to NSPS for PM in 40
CFR 60.102a(b)(1)(ii), electing to
meet the PM concentration limit.
6. Option 1a: Elect NSPS subpart J
requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
7. Option 1b: Elect NSPS subpart
Ja requirements for PM per coke
burn-off limit and 30% opacity,
not subject to the NSPS for PM
in
40
CFR
60.102
or
60.102a(b)(1).
8. Option 1c: Elect NSPS subpart
Ja requirements for PM concentration limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
9. Option 2: PM per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
Maintaining PM concentration below 0.020 gr/dscf corrected to 0 percent excess air.
See item 1 of this table.
PM emissions must not exceed
1.0 g/kg (1.0 lb PM/1,000 lb) of
coke burn-off.
See item 2 of this table.
PM emissions must not exceed
0.040 gr/dscf corrected to 0 percent excess air.
See item 4 of this table.
PM emissions must not exceed
1.0 g/kg (1.0 lb PM/1,000 lb) of
coke burn-off.
Determining and recording each day the average coke burn-off rate
and the hours of operation and the hours of operation for each catalyst regenerator by Equation 1 of § 63.1564 (you can use process
data to determine the volumetric flow rate); maintaining PM emission rate below 1.0 g/kg (1.0 lb PM/1,000 lb) of coke burn-off; and
conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit.
Maintaining Ni emission rate below 13,000 mg/hr (0.029 lb/hr); and
conducting a performance test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit.
Determining and recording each day the average coke burn-off rate
(thousands of kilograms per hour) and the hours of operation for
each catalyst regenerator by Equation 1 of § 63.1564 (you can use
process data to determine the volumetric flow rate); and maintaining Ni emission rate below 1.0 mg/kg (0.001 lb/1,000 lb) of coke
burn-off in the catalyst regenerator; and conducting a performance
test before August 1, 2017 and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit.
10. Option 3: Ni lb/hr limit, not subject to the NSPS for PM in 40
CFR 60.102 or 60.102a(b)(1).
Ni emissions must not exceed
13,000 mg/hr (0.029 lb/hr).
11. Option 4: Ni per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
Ni emissions must not exceed 1.0
mg/kg (0.001 lb/1,000 lb) of
coke burn-off in the catalyst regenerator.
58. Table 7 to subpart UUU of part 63
is revised to read as follows:
■
As stated in § 63.1564(c)(1), you shall
meet each requirement in the following
table that applies to you.
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS
If you use . . .
1. Subject to NSPS for PM in 40
CFR 60.102 and not electing
§ 60.100(e).
tkelley on DSK3SPTVN1PROD with RULES2
For each new or existing catalytic
cracking unit . . .
Continuous
system.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
For this operating limit . . .
opacity
PO 00000
monitoring
Frm 00117
Fmt 4701
You shall demonstrate continuous
compliance by . . .
The 3-hour average opacity of
emissions from your catalyst regenerator vent must not exceed
20 percent.
Collecting the continuous opacity
monitoring data for each regenerator
vent
according
to
§ 63.1572 and maintain each 3hour rolling average opacity of
emissions no higher than 20
percent.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75294
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
If you use . . .
For this operating limit . . .
You shall demonstrate continuous
compliance by . . .
2. Subject to NSPS for PM in 40
CFR 60.102a(b)(1); or 40 CFR
60.102 and elect § 60.100(e),
electing to meet the PM per
coke burn-off limit.
a. Continuous opacity monitoring
system, used for site-specific
opacity limit—Cyclone or electrostatic precipitator.
The average opacity must not exceed the opacity established
during the performance test.
b. Continuous parametric monitoring
systems—electrostatic
precipitator.
i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during
the performance test.
Collecting the hourly and 3-hr rolling average opacity monitoring
data according to § 63.1572;
maintaining the 3-hr rolling average opacity at or above the
site-specific limit established
during the performance test.
Collecting the hourly and daily average coke burn-off rate or average gas flow rate monitoring
data according to § 63.1572;
and maintaining the daily average coke burn-off rate or average gas flow rate at or below
the limit established during the
performance test.
Collecting the hourly and 3-hr rolling average total power and
secondary current monitoring
data according to § 63.1572;
and maintaining the 3-hr rolling
average total power and secondary current at or above the
limit established during the performance test.
Collecting the hourly and 3-hr rolling average gas flow rate and
scrubber liquid flow rate monitoring
data
according
to
§ 63.1572; determining and recording the 3-hr liquid-to-gas
ratio; and maintaining the 3-hr
rolling average liquid-to-gas
ratio at or above the limit established during the performance
test.
ii. The average total power and
secondary current to the control
device must not fall below the
operating limit established during the performance test.
c. Continuous parametric monitoring systems—wet scrubber.
i. The average liquid-to-gas ratio
must not fall below the operating limit established during
the performance test.
ii. Except for periods of startup,
shutdown and hot standby, the
average pressure drop across
the scrubber must not fall below
the operating limit established
during the performance test.
Increases in relative particulate ....
3. Subject to NSPS for PM in 40
CFR 60.102a(b)(1), electing to
meet the PM concentration limit.
4. Option 1a: Elect NSPS subpart
J requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
tkelley on DSK3SPTVN1PROD with RULES2
d. BLD—fabric filter ......................
PM CEMS .....................................
Not applicable ...............................
Continuous
system.
monitoring
The 3-hour average opacity of
emissions from your catalyst regenerator vent must not exceed
20 percent.
5. Option 1b: Elect NSPS subpart
Ja requirements for PM per coke
burn-off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
a. Continuous opacity monitoring
system.
The opacity of emissions from
your catalyst regenerator vent
must not exceed the site-specific opacity operating limit established during the performance test.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
opacity
PO 00000
Frm 00118
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
Collecting the hourly and 3-hr rolling average pressure drop
monitoring data according to
§ 63.1572; and except for periods of startup, shutdown and
hot standby, maintaining the 3hr rolling average pressure drop
at or above the limit established
during the performance test.
Collecting
and
maintaining
records of BLD system output;
determining the cause of the
alarm within 1 hour of the
alarm; and alleviating the cause
of the alarm within 3 hours by
corrective action.
Complying with Table 6 of this
subpart, item 4 or 5.
Collecting the 3-hr rolling average
continuous opacity monitoring
system data according to
§ 63.1572; and maintaining the
3-hr rolling average opacity no
higher than 20 percent.
Collecting the 3-hr rolling average
continuous opacity monitoring
system data according to
§ 63.1572; maintaining the 3-hr
rolling average opacity at or
below the site-specific limit.
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75295
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
For this operating limit . . .
You shall demonstrate continuous
compliance by . . .
b. Continuous parametric monitoring
systems—electrostatic
precipitator.
c. Continuous parametric monitoring systems—wet scrubber.
d. BLD—fabric filter ......................
PM CEMS .....................................
See item 2.b of this table .............
See item 2.b of this table.
See item 2.c of this table .............
See item 2.c of this table.
See item 2.d of this table .............
Not applicable ...............................
See item 2.d of this table.
Complying with Table 6 of this
subpart, item 4.
a. Continuous opacity monitoring
system.
The opacity of emissions from
your catalyst regenerator vent
must not exceed the site-specific opacity operating limit established during the performance test.
b. Continuous parameter monitoring
systems—electrostatic
precipitator.
6. Option 1c: Elect NSPS subpart
Ja requirements for PM concentration limit, not subject to
the NSPS for PM in 40 CFR
60.102 or 60.102a(b)(1).
7. Option 2: PM per coke burn-off
limit, not subject to the NSPS for
PM in 40 CFR 60.102 or
60.102a(b)(1).
If you use . . .
i. The average coke burn-off rate
or average gas flow rate entering or exiting the control device
must not exceed the operating
limit established during the performance test.
Collecting the hourly and 3-hr rolling average continuous opacity
monitoring system data according to § 63.1572; and maintaining the 3-hr rolling average
opacity at or below the site-specific limit established during the
performance test. Alternatively,
before August 1, 2017, collecting the hourly average continuous opacity monitoring system
data
according
to
§ 63.1572; and maintaining the
hourly average opacity at or
below the site-specific limit.
Collecting the hourly and daily average coke burn-off rate or gas
flow rate monitoring data according to § 63.1572; and maintaining the daily coke burn-off
rate or average gas flow rate at
or below the limit established
during the performance test.
Collecting the hourly and 3-hr rolling average total power and
secondary current monitoring
data according to § 63.1572;
and maintaining the 3-hr rolling
average total power and secondary current at or above the
limit established during the performance test. Alternatively, before August 1, 2017, collecting
the hourly and daily average
voltage and secondary current
(or total power input) monitoring
data according to § 63.1572;
and maintaining the daily average voltage and secondary current (or total power input) at or
above the limit established during the performance test.
tkelley on DSK3SPTVN1PROD with RULES2
ii. The average total power (voltage and current) and secondary
current to the control device
must not fall below the operating limit established during
the performance test.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00119
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75296
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
If you use . . .
For this operating limit . . .
You shall demonstrate continuous
compliance by . . .
c. Continuous parameter monitoring systems—wet scrubber.
i. The average liquid-to-gas ratio
must not fall below the operating limit established during
the performance test.
Collecting the hourly and 3-hr rolling average gas flow rate and
scrubber liquid flow rate monitoring
data
according
to
§ 63.1572; determining and recording the 3-hr liquid-to-gas
ratio; and maintaining the 3-hr
rolling average liquid-to-gas
ratio at or above the limit established during the performance
test. Alternatively, before August 1, 2017, collecting the
hourly average gas flow rate
and water (or scrubbing liquid)
flow rate monitoring data according to § 63.1572 1; determining and recording the hourly
average liquid-to-gas ratio; determining and recording the
daily average liquid-to-gas ratio;
and maintaining the daily average liquid-to-gas ratio above
the limit established during the
performance test.
Collecting the hourly and 3-hr rolling average pressure drop
monitoring data according to
§ 63.1572; and except for periods of startup, shutdown and
hot standby, maintaining the 3hr rolling average pressure drop
at or above the limit established
during the performance test. Alternatively, before August 1,
2017, collecting the hourly and
daily average pressure drop
monitoring data according to
§ 63.1572; and maintaining the
daily average pressure drop
above the limit established during the performance test.
See item 2.d of this table.
(1) Collecting the hourly average
continuous opacity monitoring
system data according to
§ 63.1572; determining and recording equilibrium catalyst Ni
concentration at least once a
week 2; collecting the hourly average gas flow rate monitoring
data according to § 63.1572 1;
and determining and recording
the hourly average Ni operating
value using Equation 11 of
§ 63.1564.
ii. Except for periods of startup,
shutdown and hot standby, the
average pressure drop across
the scrubber must not fall below
the operating limit established
during the performance test.
tkelley on DSK3SPTVN1PROD with RULES2
8. Option 3: Ni lb/hr limit not subject to the NSPS for PM in 40
CFR 60.102.
VerDate Sep<11>2014
23:11 Nov 30, 2015
d. BLD—fabric filter ......................
a. Continuous opacity monitoring
system.
Jkt 238001
PO 00000
Frm 00120
Fmt 4701
See item 2.d of this table .............
i. The daily average Ni operating
value must not exceed the sitespecific Ni operating limit established during the performance
test.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75297
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
If you use . . .
b. Continuous parameter monitoring
systems—electrostatic
precipitator.
c. Continuous parameter monitoring systems—wet scrubber.
tkelley on DSK3SPTVN1PROD with RULES2
d. BLD—fabric filter ......................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
You shall demonstrate continuous
compliance by . . .
For this operating limit . . .
Frm 00121
Fmt 4701
i. The average gas flow rate entering or exiting the control device must not exceed the operating limit established during
the performance test.
ii. The average total power (voltage and current) and secondary
current must not fall below the
level established in the performance test.
iii. The monthly rolling average of
the equilibrium catalyst Ni concentration must not exceed the
level established during the performance test.
i. The average liquid-to-gas ratio
must not fall below the operating limit established during
the performance test..
ii. Except for periods of startup,
shutdown and hot standby, the
average pressure drop must not
fall below the operating limit established in the performance
test.
iii. The monthly rolling average
equilibrium catalyst Ni concentration must not exceed the
level established during the performance test.
i. Increases in relative particulate
Sfmt 4700
E:\FR\FM\01DER2.SGM
(2) Determining and recording the
3-hour rolling average Ni operating value and maintaining the
3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance
test. Alternatively, before August 1, 2017, determining and
recording the daily average Ni
operating value and maintaining
the daily average Ni operating
value below the site-specific Ni
operating limit established during the performance test.
See item 7.b.i of this table.
See item 7.b.ii of this table.
Determining and recording the
equilibrium catalyst Ni concentration at least once a
week 2; determining and recording the monthly rolling average
of the equilibrium catalyst Ni
concentration once each week
using the weekly or most recent
value; and maintaining the
monthly rolling average below
the limit established in the performance test.
See item 7.c.i of this table.
See item 7.c.ii of this table.
Determining and recording the
equilibrium catalyst Ni concentration at least once a
week 2; determining and recording the monthly rolling average
of equilibrium catalyst Ni concentration once each week
using the weekly or most recent
value; and maintaining the
monthly rolling average below
the limit established in the performance test.
See item 7.d of this table.
01DER2
75298
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
You shall demonstrate continuous
compliance by . . .
ii. The monthly rolling average of
the equilibrium catalyst Ni concentration must not exceed the
level established during the performance test.
9. Option 4: Ni per coke burn-off
limit not subject to the NSPS for
PM in 40 CFR 60.102.
For this operating limit . . .
If you use . . .
Determining and recording the
equilibrium catalyst Ni concentration at least once a
week 2; determining and recording the monthly rolling average
of the equilibrium catalyst Ni
concentration once each week
using the weekly or most recent
value; and maintaining the
monthly rolling average below
the limit established in the performance test.
(1) Collecting the hourly average
continuous opacity monitoring
system data according to
§ 63.1572; collecting the hourly
average coke burn rate and
hourly average gas flow rate
monitoring data according to
§ 63.15721; determining and recording equilibrium catalyst Ni
concentration at least once a
week 2; and determining and recording the hourly average Ni
operating value using Equation
12 of § 63.1564.
(2) Determining and recording the
3-hour rolling average Ni operating value and maintaining the
3-hour rolling average Ni operating value below the site-specific Ni operating limit established during the performance
test Alternatively, before August
1, 2017, determining and recording the daily average Ni operating value and maintaining
the daily average Ni operating
value below the site-specific Ni
operating limit established during the performance test.
See item 7.b.i of this table.
a. Continuous opacity monitoring
system.
i. The daily average Ni operating
value must not exceed the sitespecific Ni operating limit established during the performance
test.
b. Continuous parameter monitoring
systems—electrostatic
precipitator.
i. The average gas flow rate to
the control device must not exceed the level established in
the performance test.
ii. The average voltage and secondary current (or total power
input) must not fall below the
level established in the performance test.
iii. The monthly rolling average
equilibrium catalyst Ni concentration must not exceed the
level established during the performance test.
i. The average liquid-to-gas ratio
must not fall below the operating limit established during
the performance test.
ii. Except for periods of startup,
shutdown and hot standby, the
daily average pressure drop
must not fall below the operating limit established in the
performance test.
tkelley on DSK3SPTVN1PROD with RULES2
c. Continuous parameter monitoring systems—wet scrubber.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00122
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
See item 7.b.ii of this table.
See item 8.b.iii of this table.
See item 7.c.i of this table.
See item 7.c.ii of this table.
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75299
TABLE 7 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR METAL HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic
cracking unit . . .
For this operating limit . . .
You shall demonstrate continuous
compliance by . . .
iii. The monthly rolling average
equilibrium catalyst Ni concentration must not exceed the
level established during the performance test.
i. See item 2.d of this table ..........
ii. The monthly rolling average of
the equilibrium catalyst Ni concentration must not exceed the
level established during the performance test.
See item 8.c.iii of this table.
d. BLD—fabric filter ......................
10. During periods of startup, shutdown, or hot standby.
If you use . . .
Any control device, if elected .......
The inlet velocity limit to the primary internal cyclones of the
catalytic cracking unit catalyst
regenerator
in
§ 63.1564(a)(5)(ii).
See item 2.d of this table.
Determining and recording the
equilibrium catalyst Ni concentration at least once a
week 2; determining and recording the monthly rolling average
of the equilibrium catalyst Ni
concentration once each week
using the weekly or most recent
value; and maintaining the
monthly rolling average below
the limit established in the performance test.
Meeting the requirements in
§ 63.1564(c)(5).
1 If applicable, you can use the alternative in § 63.1573(a)(1) for gas flow rate instead of a continuous parameter monitoring system if you used
the alternative method in the initial performance test.
2 The equilibrium catalyst Ni concentration must be measured by the procedure, Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure) in appendix A to this subpart; or by EPA Method 6010B, Inductively Coupled Plasma-Atomic Emission Spectrometry, EPA Method 6020, Inductively Coupled Plasma-Mass Spectrometry, EPA Method 7520, Nickel Atomic Absorption, Direct Aspiration, or
EPA Method 7521, Nickel Atomic Absorption, Direct Aspiration; or by an alternative to EPA Method 6010B, 6020, 7520, or 7521 satisfactory to
the Administrator. The EPA Methods 6010B, 6020, 7520, and 7521 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for
purchase from the Superintendent of Documents, U.S. Government Publishing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the
EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or
at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at https://www.
epa.gov/epaoswer/hazwaste/test/main.htm.
59. Table 8 to subpart UUU of part 63
is revised to read as follows:
■
As stated in § 63.1565(a)(1), you shall
meet each emission limitation in the
following table that applies to you.
TABLE 8 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC CRACKING UNITS
For each new and existing catalytic cracking unit . . .
You shall meet the following emission limit for each catalyst
regenerator vent . . .
1. Subject to the NSPS for carbon monoxide (CO) in 40 CFR 60.103 or
60.102a(b)(4).
CO emissions from the catalyst regenerator vent or CO boiler serving
the catalytic cracking unit must not exceed 500 parts per million volume (ppmv) (dry basis).
a. CO emissions from the catalyst regenerator vent or CO boiler serving the catalytic cracking unit must not exceed 500 ppmv (dry basis).
b. If you use a flare to meet the CO limit, then on and after January
30, 2019, the flare must meet the requirements of § 63.670. Prior to
January 30, 2019, the flare must meet the requirements for control
devices in § 63.11(b) and visible emissions must not exceed a total
of 5 minutes during any 2 consecutive hours, or the flare must meet
the requirements of § 63.670.
2. Not subject to the NSPS for CO in 40 CFR 60.103 or 60.102a(b)(4)
60. Table 9 to subpart UUU of part 63
is revised to read as follows:
tkelley on DSK3SPTVN1PROD with RULES2
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
As stated in § 63.1565(a)(2), you shall
meet each operating limit in the
following table that applies to you.
PO 00000
Frm 00123
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75300
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 9 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC CRACKING
UNITS
For each new or existing catalytic
cracking unit . . .
For this type of continuous
monitoring system . . .
For this type of control
device . . .
You shall meet this operating
limit . . .
1. Subject to the NSPS for carbon
monoxide (CO) in 40 CFR
60.103 or 60.102a(b)(4).
2. Not subject to the NSPS for CO
in
40
CFR
60.103
or
60.102a(b)(4).
Continuous emission monitoring
system.
Not applicable ...............................
Not applicable.
a.
moni-
Not applicable ...............................
Not applicable.
b. Continuous parameter monitoring systems.
i. Thermal incinerator ....................
Maintain the daily average combustion
zone
temperature
above the limit established during the performance test; and
maintain the daily average oxygen concentration in the vent
stream (percent, dry basis)
above the limit established during the performance test.
Maintain the daily average combustion
zone
temperature
above the limit established in
the performance test.
Continuous emission
toring system.
ii. Boiler or process heater with a
design heat input capacity
under 44 MW or a boiler or
process heater in which all vent
streams are not introduced into
the flame zone.
iii. Flare .........................................
3. During periods of startup, shutdown or hot standby.
Any ................................................
61. Table 10 to subpart UUU of part
63 is revised to read as follows:
Any ................................................
On and after January 30, 2019,
the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare pilot
light must be present at all
times and the flare must be operating at all times that emissions may be vented to it, or
the flare must meet the requirements of § 63.670.
Meet
the
requirements
in
§ 63.1565(a)(5).
As stated in § 63.1565(b)(1), you shall
meet each requirement in the following
table that applies to you.
■
TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS
And you use this type of control device for
your vent . . .
You shall install, operate, and maintain this
type of continuous monitoring system . . .
1. Subject to the NSPS for carbon monoxide
(CO) in 40 CFR 60.103 or 60.102a(b)(4).
Not applicable ...................................................
2. Not subject to the NSPS for CO in 40 CFR
60.103 or 60.102a(b)(4).
tkelley on DSK3SPTVN1PROD with RULES2
For each new or existing catalytic cracking
unit . . .
a. Thermal incinerator ......................................
Continuous emission monitoring system to
measure and record the concentration by
volume (dry basis) of CO emissions from
each catalyst regenerator vent.
Continuous emission monitoring system to
measure and record the concentration by
volume (dry basis) of CO emissions from
each catalyst regenerator vent; or continuous parameter monitoring systems to
measure and record the combustion zone
temperature and oxygen content (percent,
dry basis) in the incinerator vent stream.
Continuous emission monitoring system to
measure and record the concentration by
volume (dry basis) of CO emissions from
each catalyst regenerator vent; or continuous parameter monitoring systems to
measure and record the combustion zone
temperature.
b. Process heater or boiler with a design heat
input capacity under 44 MW or process
heater or boiler in which all vent streams
are not introduced into the flame zone.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00124
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75301
TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS—Continued
For each new or existing catalytic cracking
unit . . .
And you use this type of control device for
your vent . . .
You shall install, operate, and maintain this
type of continuous monitoring system . . .
c. Flare .............................................................
On and after January 30, 2019, the monitoring
systems required in §§ 63.670 and 63.671.
Prior to January 30, 2019, monitoring device such as a thermocouple, an ultraviolet
beam sensor, or infrared sensor to continuously detect the presence of a pilot flame,
or the monitoring systems required in
§§ 63.670 and 63.671.
Continuous emission monitoring system to
measure and record the concentration by
volume (dry basis) of CO emissions from
each catalyst regenerator vent.
Continuous parameter monitoring system to
measure and record the concentration by
volume (dry basis) of oxygen from each catalyst regenerator vent.
d. No control device .........................................
3. During periods of startup, shutdown or hot
standby electing to comply with the operating limit in § 63.1565(a)(5)(ii).
Any ...................................................................
62. Table 11 to subpart UUU of part
63 is amended by revising the entry for
item 3 to read as follows:
*
*
*
*
*
■
TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS
FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON
MONOXIDE (CO)
According to these
requirements . . .
You must . . .
Using . . .
*
3. Each catalytic cracking unit catalyst regenerator vent if you use
continuous parameter monitoring systems.
*
*
a. Measure the CO concentration
(dry basis) of emissions exiting
the control device.
*
*
Method 10, 10A, or 10B in appendix A–4 to part 60 of this chapter, as applicable.
b. Establish each operating limit in
Table 9 of this subpart that applies to you.
c. Thermal incinerator combustion
zone temperature.
Data from the continuous parameter monitoring systems.
d. Thermal incinerator: oxygen,
content (percent, dry basis) in
the incinerator vent stream.
tkelley on DSK3SPTVN1PROD with RULES2
For . . .
Data from the continuous parameter monitoring systems.
e. If you use a process heater or
boiler with a design heat input
capacity under 44 MW or process heater or boiler in which all
vent streams are not introduced
into the flame zone, establish
operating limit for combustion
zone temperature.
Data from the continuous parameter monitoring systems.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00125
Fmt 4701
Data from the continuous parameter monitoring systems.
Sfmt 4700
E:\FR\FM\01DER2.SGM
*
Collect temperature monitoring
data every 15 minutes during
the entire period of the CO initial performance test; and determine and record the minimum
hourly
average
combustion
zone temperature from all the
readings.
Collect oxygen concentration (percent, dry basis) monitoring data
every 15 minutes during the entire period of the CO initial performance test; and determine
and record the minimum hourly
average percent excess oxygen
concentration from all the readings.
Collect the temperature monitoring
data every 15 minutes during
the entire period of the CO initial performance test; and determine and record the minimum
hourly
average
combustion
zone temperature from all the
readings.
01DER2
75302
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 11 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS
FROM CATALYTIC CRACKING UNITS NOT SUBJECT TO NEW SOURCE PERFORMANCE STANDARD (NSPS) FOR CARBON
MONOXIDE (CO)—Continued
You must . . .
Using . . .
According to these
requirements . . .
f. If you use a flare, conduct visible emission observations.
Method 22 (40 CFR part 60, appendix A–7).
g. If you use a flare, determine
that the flare meets the requirements for net heating value of
the gas being combusted and
exit velocity.
For . . .
40 CFR 63.11(b)(6) through (8) ....
On and after January 30, 2019,
meet the requirements of
§ 63.670. Prior to January 30,
2019, maintain a 2-hour observation period; and record the
presence of a flame at the pilot
light over the full period of the
test or meet the requirements of
§ 63.670.
On and after January 30, 2019,
the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must
meet the control device requirements in § 63.11(b) or the requirements of § 63.670.
63. Table 12 to subpart UUU of part
63 is revised to read as follows:
■
As stated in § 63.1565(b)(4), you shall
meet each requirement in the following
table that applies to you.
TABLE 12 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC
CRACKING UNITS
For each new and existing catalytic
cracking unit . . .
For the following emission
limit . . .
You have demonstrated initial compliance if . . .
1. Subject to the NSPS for carbon
monoxide (CO) in 40 CFR
60.103,
60.100(e),
or
60.102a(b)(4).
CO emissions from your catalyst
regenerator vent or CO boiler
serving the catalytic cracking
unit must not exceed 500 ppmv
(dry basis).
2. Not subject to the NSPS for CO
in 40 CFR 60.103 60.102a(b)(4).
a. CO emissions from your catalyst regenerator vent or CO boiler serving the catalytic cracking
unit must not exceed 500 ppmv
(dry basis).
You have already conducted a performance test to demonstrate initial
compliance with the NSPS and the measured CO emissions are
less than or equal to 500 ppm (dry basis). As part of the Notification of Compliance Status, you must certify that your vent meets
the CO limit. You are not required to conduct another performance
test to demonstrate initial compliance. You have already conducted
a performance evaluation to demonstrate initial compliance with the
applicable performance specification. As part of your Notification of
Compliance Status, you must certify that your continuous emission
monitoring system meets the applicable requirements in § 63.1572.
You are not required to conduct another performance evaluation to
demonstrate initial compliance.
i. If you use a continuous parameter monitoring system, the average
CO emissions measured by Method 10 over the period of the initial
performance test are less than or equal to 500 ppmv (dry basis).
b. If you use a flare, visible emissions must not exceed a total of
5 minutes during any 2 operating hours.
64. Table 13 to subpart UUU of part
63 is revised to read as follows:
tkelley on DSK3SPTVN1PROD with RULES2
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
ii. If you use a continuous emission monitoring system, the hourly average CO emissions over the 24-hour period for the initial performance test are not more than 500 ppmv (dry basis); and your performance evaluation shows your continuous emission monitoring
system meets the applicable requirements in § 63.1572.
On and after January 30, 2019, the flare meets the requirements of
§ 63.670. Prior to January 30, 2019, visible emissions, measured
by Method 22 during the 2-hour observation period during the initial
performance test, are no higher than 5 minutes, or the flare meets
the requirements of § 63.670.
As stated in § 63.1565(c)(1), you shall
meet each requirement in the following
table that applies to you.
PO 00000
Frm 00126
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75303
TABLE 13 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR
CATALYTIC CRACKING UNITS
For each new and existing
catalytic cracking unit . . .
Subject to this emission limit for
your catalyst regenerator
vent . . .
1. Subject to the NSPS for carbon
monoxide (CO) in 40 CFR
60.103,
60.100(e),
or
60.102a(b)(4).
2. Not subject to the NSPS for CO
in
40
CFR
60.103
or
60.102a(b)(4).
If you must . . .
You shall demonstrate continuous
compliance by . . .
CO emissions from your catalyst
regenerator vent or CO boiler
serving the catalytic cracking
unit must not exceed 500 ppmv
(dry basis).
Continuous emission monitoring
system.
a. CO emissions from your catalyst regenerator vent or CO
boiler serving the catalytic
cracking unit must not exceed
500 ppmv (dry basis).
b. CO emissions from your catalyst regenerator vent or CO
boiler serving the catalytic
cracking unit must not exceed
500 ppmv (dry basis).
c. Visible emissions from a flare
must not exceed a total of 5
minutes during any 2-hour period.
Continuous emission monitoring
system.
Collecting the hourly average CO
monitoring data according to
§ 63.1572; and maintaining the
hourly average CO concentration at or below 500 ppmv (dry
basis).
Same as item 1.
65. Table 14 to subpart UUU of part
63 is revised to read as follows:
■
Continuous parameter monitoring
system.
Maintaining the hourly average
CO concentration below 500
ppmv (dry basis).
Control device-flare ......................
On and after January 30, 2019,
meeting the requirements of
§ 63.670. Prior to January 30,
2019, maintaining visible emissions below a total of 5 minutes
during any 2-hour operating period, or meeting the requirements of § 63.670.
As stated in § 63.1565(c)(1), you shall
meet each requirement in the following
table that applies to you.
TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS
For each new existing catalytic
cracking unit . . .
For this operating limit . . .
If you use . . .
1. Subject to NSPS for carbon Continuous emission monitoring
monoxide (CO) in 40 CFR
system.
60.103, 60.100(e), 60.102a(b)(4).
2. Not subject to the NSPS for CO a. Continuous emission moniin
40
CFR
60.103
or
toring system.
60.102a(b)(4).
b. Continuous parameter monitoring systems—thermal incinerator.
You shall demonstrate continuous
compliance by . . .
Not applicable ...............................
Complying with Table 13 of this
subpart, item 1.
Not applicable ...............................
Complying with Table 13 of this
subpart, item 2.a.
i. The daily average combustion
zone temperature must not fall
below the level established during the performance test.
Collecting the hourly and daily average temperature monitoring
data according to § 63.1572;
and maintaining the daily average combustion zone temperature above the limit established
during the performance test.
Collecting the hourly and daily average oxygen concentration
monitoring data according to
§ 63.1572; and maintaining the
daily average oxygen concentration above the limit established during the performance
test.
Collecting the average hourly and
daily temperature monitoring
data according to § 63.1572;
and maintaining the daily average combustion zone temperature above the limit established
during the performance test.
tkelley on DSK3SPTVN1PROD with RULES2
ii. The daily average oxygen concentration in the vent stream
(percent, dry basis) must not
fall below the level established
during the performance test.
c. Continuous parameter monitoring systems—boiler or process heater with a design heat
input capacity under 44 MW or
boiler or process heater in
which all vent streams are not
introduced into the flame zone.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00127
Fmt 4701
The daily combustion zone temperature must not fall below the
level established in the performance test.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75304
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 14 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP
EMISSIONS FROM CATALYTIC CRACKING UNITS—Continued
For each new existing catalytic
cracking unit . . .
If you use . . .
You shall demonstrate continuous
compliance by . . .
d. Continuous parameter monitoring system—flare.
3. During periods of startup, shutdown or hot standby electing to
comply with the operating limit in
§ 63.1565(a)(5)(ii).
For this operating limit . . .
The flare pilot light must be
present at all times and the
flare must be operating at all
times that emissions may be
vented to it.
Any control device ........................
The oxygen concentration limit in
§ 63.1565(a)(5)(ii).
On and after January 30, 2019,
meeting the requirements of
§ 63.670. Prior to January 30,
2019, collecting the flare monitoring
data
according
to
§ 63.1572 and recording for
each 1-hour period whether the
monitor was continuously operating and the pilot light was
continuously present during
each 1-hour period, or meeting
the requirements of § 63.670.
Collecting the hourly average oxygen concentration monitoring
data according to § 63.1572
and maintaining the hourly average oxygen concentration at
or above 1 volume percent (dry
basis).
66. Table 15 to subpart UUU of part
63 is amended by revising the entry for
item 1 to read as follows:
*
*
*
*
*
■
TABLE 15 TO SUBPART UUU OF PART 63—ORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS
For each applicable process vent for a
new or existing catalytic reforming
unit . . .
You shall meet this emission limit during initial catalyst depressuring and catalyst purging
operations . . .
1. Option 1 ................................................
On and after January 30, 2019, vent emissions to a flare that meets the requirements of § 63.670.
Prior to January 30, 2019, vent emissions to a flare that meets the requirements for control devices in § 63.11(b) and visible emissions from a flare must not exceed a total of 5 minutes during
any 2-hour operating period, or vent emissions to a flare that meets the requirements of § 63.670.
*
*
*
*
*
*
*
67. Table 16 to subpart UUU of part
63 is amended by revising the entry for
item 1 to read as follows:
*
*
*
*
*
■
TABLE 16 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR ORGANIC HAP EMISSIONS FROM CATALYTIC
REFORMING UNITS
For each new or existing catalytic
reforming unit . . .
For this type of control device . . .
You shall meet this operating limit during initial catalyst depressuring
and purging operations. . .
1. Option 1: Vent to flare ...............
Flare ...............................................
On and after January 30, 2019, the flare must meet the requirements
of § 63.670. Prior to January 30, 2019, the flare pilot light must be
present at all times and the flare must be operating at all times that
emissions may be vented to it, or the flare must meet the requirements of § 63.670.
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
*
68. Table 17 to subpart UUU of part
63 is amended by revising the entry for
item 1 to read as follows:
*
*
*
*
*
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00128
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
*
75305
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 17 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM
CATALYTIC REFORMING UNITS
For each applicable process vent
for a new or existing catalytic
reforming unit . . .
If you use this type of control
device . . .
You shall install and operate this type of continuous monitoring
system . . .
1. Option 1: Vent to a flare ............
Flare ...............................................
On and after January 30, 2019, the monitoring systems required in
§§ 63.670 and 63.671. Prior to January 30, 2019, monitoring device
such as a thermocouple, an ultraviolet beam sensor, or infrared
sensor to continuously detect the presence of a pilot flame, or the
monitoring systems required in §§ 63.670 and 63.671.
*
*
*
69. Table 18 to subpart UUU of part
63 is amended by revising the column
*
*
*
*
headings and the entry for item 1 to read
as follows:
*
*
*
*
*
■
TABLE 18 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR ORGANIC HAP EMISSIONS
FROM CATALYTIC REFORMING UNITS
For each new or existing catalytic
reforming unit . . .
You must . . .
Using . . .
According to these
requirements . . .
1. Option 1: Vent to a flare ...........
a. Conduct visible emission observations.
Method 22 (40 CFR part 60, appendix A–7).
b. Determine that the flare meets
the requirements for net heating
value of the gas being combusted and exit velocity.
40 CFR 63.11(b)(6) through (8) ....
On and after January 30, 2019,
the flare must meet the requirements of § 63.670. Prior to January 30, 2019, 2-hour observation period. Record the presence of a flame at the pilot light
over the full period of the test,
or the requirements of § 63.670.
On and after January 30, 2019,
the flare must meet the requirements of § 63.670. Prior to January 30, 2019, the flare must
meet the control device requirements in § 63.11(b) or the requirements of § 63.670.
*
*
*
*
*
*
*
70. Table 19 to subpart UUU of part
63 is amended by revising the entry for
item 1 to read as follows:
*
*
*
*
*
■
TABLE 19 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR CATALYTIC
REFORMING UNITS
For each applicable process vent for a new or
existing catalytic reforming unit . . .
For the following emission limit . . .
You have demonstrated initial compliance
if . . .
Option 1 ............................................................
Visible emissions from a flare must not exceed
a total of 5 minutes during any 2 consecutive hours.
On and after January 30, 2019, the flare
meets the requirements of § 63.670. Prior to
January 30, 2019, visible emissions, measured using Method 22 over the 2-hour observation period of the performance test, do
not exceed a total of 5 minutes, or the flare
meets the requirements of § 63.670.
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
*
71. Table 20 to subpart UUU of part
63 is amended by revising the entry for
item 1 to read as follows:
*
*
*
*
*
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00129
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
*
75306
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 20 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH ORGANIC HAP EMISSION LIMITS FOR
CATALYTIC REFORMING UNITS
You shall demonstrate continuous compliance
during initial catalyst depressuring and catalyst
purging operations by . . .
For each applicable process vent for a new or
existing catalytic reforming unit . . .
For this emission limit . . .
1. Option 1 ........................................................
Vent emissions from your process vent to a
flare.
*
*
*
*
On and after January 30, 2019, meeting the
requirements of § 63.670. Prior to January
30, 2019, maintaining visible emissions from
a flare below a total of 5 minutes during any
2 consecutive hours, or meeting the requirements of § 63.670.
*
*
*
72. Table 21 to subpart UUU of part
63 is amended by revising the entry for
item 1 to read as follows:
*
*
*
*
*
■
TABLE 21 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR ORGANIC HAP
EMISSIONS FROM CATALYTIC REFORMING UNITS
You shall demonstrate continuous
compliance during initial catalyst
depressuring and purging
operations by . . .
For each applicable process vent
for a new or existing catalytic
reforming unit . . .
If you use . . .
For this operating limit . . .
1. Option 1 ....................................
Flare ..............................................
The flare pilot light must be
present at all times and the
flare must be operating at all
times that emissions may be
vented to it.
*
*
*
*
On and after January 30, 2019,
meeting the requirements of
§ 63.670. Prior to January 30,
2019, collecting flare monitoring
data according to § 63.1572 and
recording for each 1-hour period
whether the monitor was continuously operating and the pilot
light was continuously present
during each 1-hour period, or
meeting the requirements of
§ 63.670.
*
*
*
73. Table 22 to subpart UUU of part
63 is amended by revising the entries for
items 2 and 3 to read as follows:
*
*
*
*
*
■
TABLE 22 TO SUBPART UUU OF PART 63—INORGANIC HAP EMISSION LIMITS FOR CATALYTIC REFORMING UNITS
You shall meet this emission limit for each applicable catalytic
reforming unit process vent during coke burn-off and catalyst
rejuvenation . . .
For . . .
tkelley on DSK3SPTVN1PROD with RULES2
*
*
*
*
*
*
*
2. Each existing cyclic or continuous catalytic reforming unit .................. Reduce uncontrolled emissions of HCl by 97 percent by weight or to a
concentration of 10 ppmv (dry basis), corrected to 3 percent oxygen.
3. Each new semi-regenerative, cyclic, or continuous catalytic reform- Reduce uncontrolled emissions of HCl by 97 percent by weight or to a
ing unit.
concentration of 10 ppmv (dry basis), corrected to 3 percent oxygen.
74. Table 24 to subpart UUU of part
63 is amended by revising the entries for
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
items 2 through 4 and footnote 2 to read
as follows:
*
*
*
*
*
PO 00000
Frm 00130
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75307
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 24 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR INORGANIC HAP EMISSIONS FROM
CATALYTIC REFORMING UNITS
You shall install and operate this type of continuous monitoring
system . . .
If you use this type of control device for your vent . . .
*
*
*
*
*
*
*
2. Internal scrubbing system or no control device (e.g., hot regen sys- Colormetric tube sampling system to measure the HCl concentration in
tem) to meet HCl outlet concentration limit.
the catalyst regenerator exhaust gas during coke burn-off and catalyst rejuvenation. The colormetric tube sampling system must meet
the requirements in Table 41 of this subpart.
3. Internal scrubbing system to meet HCl percent reduction standard ... Continuous parameter monitoring system to measure and record the
gas flow rate entering or exiting the internal scrubbing system during
coke burn-off and catalyst rejuvenation; and continuous parameter
monitoring system to measure and record the total water (or scrubbing liquid) flow rate entering the internal scrubbing system during
coke burn-off and catalyst rejuvenation; and continuous parameter
monitoring system to measure and record the pH or alkalinity of the
water (or scrubbing liquid) exiting the internal scrubbing system during coke burn-off and catalyst rejuvenation.2
4. Fixed-bed gas-solid adsorption system ................................................ Continuous parameter monitoring system to measure and record the
temperature of the gas entering or exiting the adsorption system during coke burn-off and catalyst rejuvenation; and colormetric tube
sampling system to measure the gaseous HCl concentration in the
adsorption system exhaust and at a point within the absorbent bed
not to exceed 90 percent of the total length of the absorbent bed
during coke burn-off and catalyst rejuvenation. The colormetric tube
sampling system must meet the requirements in Table 41 of this
subpart.
*
*
*
*
*
*
*
*
*
*
*
*
*
*
2 If applicable, you can use the alternative in § 63.1573(c)(1) instead of a continuous parameter monitoring system for pH of the water (or
scrubbing liquid) or the alternative in § 63.1573(c)(2) instead of a continuous parameter monitoring system for alkalinity of the water (or scrubbing
liquid).
*
*
*
*
*
75. Table 25 to subpart UUU of part
63 is amended by revising the entries for
■
items 2.a and 4.a and footnote 1 to read
as follows:
*
*
*
*
*
TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS
FROM CATALYTIC REFORMING UNITS
For each new and existing
catalytic reforming unit
using . . .
You shall . . .
*
*
2. Wet scrubber ............................
*
*
*
a. Establish operating limit for pH i. Data from continuous parameter
level or alkalinity.
monitoring systems.
According to these
requirements . . .
Using . . .
tkelley on DSK3SPTVN1PROD with RULES2
ii. Alternative pH procedure in
§ 63.1573(b)(1).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00131
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
*
*
Measure and record the pH or alkalinity of the water (or scrubbing liquid) exiting scrubber
every 15 minutes during the entire period of the performance
test. Determine and record the
minimum hourly average pH or
alkalinity level from the recorded values.
Measure and record the pH of the
water (or scrubbing liquid)
exiting the scrubber during coke
burn-off and catalyst rejuvenation using pH strips at least
three times during each test
run. Determine and record the
average pH level for each test
run. Determine and record the
minimum test run average pH
level.
01DER2
75308
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 25 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR INORGANIC HAP EMISSIONS
FROM CATALYTIC REFORMING UNITS—Continued
For each new and existing
catalytic reforming unit
using . . .
According to these
requirements . . .
iii. Alternative alkalinity method in
§ 63.1573(c)(2).
4.
Using . . .
Measure and record the alkalinity
of the water (or scrubbing liquid) exiting the scrubber during
coke burn-off and catalyst rejuvenation using discrete titration
at least three times during each
test run. Determine and record
the average alkalinity level for
each test run. Determine and
record the minimum test run average alkalinity level.
*
*
*
a. Establish operating limit for pH i. Data from continuous parameter
level or alkalinity.
monitoring system.
*
*
Measure and record the pH alkalinity of the water (or scrubbing
liquid) exiting the internal scrubbing system every 15 minutes
during the entire period of the
performance test. Determine
and record the minimum hourly
average pH or alkalinity level
from the recorded values.
Measure and in record pH of the
water (or scrubbing liquid)
exiting the internal scrubbing
system during coke burn-off and
catalyst rejuvenation using pH
strips at least three times during
each test run. Determine and
record the average pH level for
each test run. Determine and
record the minimum test run average pH level.
Measure and record the alkalinity
water (or scrubbing liquid)
exiting the internal scrubbing
system during coke burn-off and
catalyst rejuvenation using discrete titration at least three
times during each test run. Determine and record the average
alkalinity level for each test run.
Determine and record the minimum test run average alkalinity
level.
You shall . . .
*
*
Internal scrubbing system
meeting HCl percent reduction
standard.
ii.
Alternative pH
§ 63.1573(c)(1).
method
in
iii. Alternative alkalinity method in
§ 63.1573(c)(2).
*
*
*
*
*
*
*
1 The
EPA Methods 5050, 9056, 9212 and 9253 are included in ‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA
Publication SW–846, Revision 5 (April 1998). The SW–846 and Updates (document number 955–001–00000–1) are available for purchase from
the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical
Information Services (NTIS), 5285 Port Royal Road, Springfield, VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building (Air Docket), Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the
Federal Register, 800 North Capitol Street NW., Suite 700, Washington, DC. These methods are also available at https://www.epa.gov/epaoswer/
hazwaste/test/main.htm.
76. Table 28 to subpart UUU of part
63 is amended by revising the entry for
tkelley on DSK3SPTVN1PROD with RULES2
■
item 5 and footnotes 1 and 3 to read as
follows:
*
*
*
*
*
TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP
EMISSIONS FROM CATALYTIC REFORMING UNITS
For each new and existing catalytic reforming
unit using this type of control device or
system . . .
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
For this operating limit . . .
PO 00000
Frm 00132
Fmt 4701
Sfmt 4700
You shall demonstrate continuous compliance
during coke burn-off and catalyst rejuvenation
by . . .
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75309
TABLE 28 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR INORGANIC HAP
EMISSIONS FROM CATALYTIC REFORMING UNITS—Continued
For each new and existing catalytic reforming
unit using this type of control device or
system . . .
*
*
5. Moving-bed gas-solid adsorption system
(e.g., ChlorsorbTM System).
You shall demonstrate continuous compliance
during coke burn-off and catalyst rejuvenation
by . . .
For this operating limit . . .
*
*
*
a. The daily average temperature of the gas
entering or exiting the adsorption system
must not exceed the limit established during
the performance test.
b. The weekly average chloride level on the
sorbent entering the adsorption system must
not exceed the design or manufacturer’s
recommended limit (1.35 weight percent for
the ChlorsorbTM System).
c. The weekly average chloride level on the
sorbent exiting the adsorption system must
not exceed the design or manufacturer’s
recommended limit (1.8 weight percent for
the ChlorsorbTM System).
*
*
Collecting the hourly and daily average temperature monitoring data according to
§ 63.1572; and maintaining the daily average temperature below the operating limit
established during the performance test.
Collecting samples of the sorbent exiting the
adsorption system three times per week (on
non-consecutive days); and analyzing the
samples for total chloride3; and determining
and recording the weekly average chloride
concentration; and maintaining the chloride
concentration below the design or manufacturer’s recommended limit (1.35 weight percent for the ChlorsorbTM System).
Collecting samples of the sorbent exiting the
adsorption system three times per week (on
non-consecutive days); and analyzing the
samples for total chloride concentration; and
determining and recording the weekly average chloride concentration; and maintaining
the chloride concentration below the design
or manufacturer’s recommended limit (1.8
weight percent ChlorsorbTM System).
1 If applicable, you can use either alternative in § 63.1573(c) instead of a continuous parameter monitoring system for pH or alkalinity if you
used the alternative method in the initial performance test.
*
*
*
*
*
*
*
3 The total chloride concentration of the sorbent material must be measured by the procedure, ‘‘Determination of Metal Concentration on Catalyst Particles (Instrumental Analyzer Procedure)’’ in appendix A to this subpart; or by using EPA Method 5050, Bomb Preparation Method for
Solid Waste, combined either with EPA Method 9056, Determination of Inorganic Anions by Ion Chromatography, or with EPA Method 9253,
Chloride (Titrimetric, Silver Nitrate); or by using EPA Method 9212, Potentiometric Determination of Chloride in Aqueous Samples with Ion-Selective Electrode, and using the soil extraction procedures listed within the method. The EPA Methods 5050, 9056, 9212 and 9253 are included in
‘‘Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,’’ EPA Publication SW–846, Revision 5 (April 1998). The SW–846 and
Updates (document number 955–001–00000–1) are available for purchase from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, (202) 512–1800; and from the National Technical Information Services (NTIS), 5285 Port Royal Road, Springfield,
VA 22161, (703) 487–4650. Copies may be inspected at the EPA Docket Center, William Jefferson Clinton (WJC) West Building, (Air Docket),
Room 3334, 1301 Constitution Ave. NW., Washington, DC; or at the Office of the Federal Register, 800 North Capitol Street NW., Suite 700,
Washington, DC. These methods are also available at https://www.epa.gov/epaoswer/hazwaste/test/main.htm.
77. Table 29 to subpart UUU of part
63 is revised to read as follows:
■
As stated in § 63.1568(a)(1), you shall
meet each emission limitation in the
following table that applies to you.
TABLE 29 TO SUBPART UUU OF PART 63—HAP EMISSION LIMITS FOR SULFUR RECOVERY UNITS
For . . .
You shall meet this emission limit for each process vent . . .
1. Subject to NSPS. Each new or existing Claus sulfur recovery unit
part of a sulfur recovery plant with design capacity greater than 20
long tons per day (LTD) and subject to the NSPS for sulfur oxides in
40 CFR 60.104(a)(2) or 60.102a(f)(1).
a. 250 ppmv (dry basis) of sulfur dioxide (SO2) at zero percent excess
air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use an oxidation control system or if you use
a reduction control system followed by incineration.
b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2
(dry basis) at zero percent excess air, or concentration determined
using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction
control system without incineration.
a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR 60.102a(f)(1)(i), if
you use an oxidation control system or if you use a reduction control
system followed by incineration.
b. 300 ppmv of reduced sulfur compounds calculated as ppmv SO2
(dry basis) at zero percent excess air, or concentration determined
using Equation 1 of 40 CFR 60.102a(f)(1)(i), if you use a reduction
control system without incineration.
300 ppmv of total reduced sulfur (TRS) compounds, expressed as an
equivalent SO2 concentration (dry basis) at zero percent oxygen.
tkelley on DSK3SPTVN1PROD with RULES2
2. Option 1: Elect NSPS. Each new or existing sulfur recovery unit
(Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1).
3. Option 2: TRS limit. Each new or existing sulfur recovery unit (Claus
or other type, regardless of size) not subject to the NSPS for sulfur
oxides in 40 CFR 60.104(a)(2) or 60.102a(f)(1).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00133
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75310
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
78. Table 30 to subpart UUU of part
63 is revised to read as follows:
As stated in § 63.1568(a)(2), you shall
meet each operating limit in the
following table that applies to you.
■
TABLE 30 TO SUBPART UUU OF PART 63—OPERATING LIMITS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS
For . . .
If use this type of control device . . .
You shall meet this operating limit . . .
1. Subject to NSPS. Each new or existing
Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater
than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
2. Option 1: Elect NSPS. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
3. Option 2: TRS limit, if using continuous emissions monitoring systems. Each new or existing sulfur recovery unit (Claus or other type,
regardless of size) not subject to the NSPS
for sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
4. Option 2: TRS limit, if using continuous parameter monitoring systems. Each new or existing sulfur recovery unit (Claus or other
type, regardless of size) not subject to the
NSPS for sulfur oxides in 40 CFR
60.104(a)(2) or 60.102a(f)(1).
Not applicable ..................................................
Not applicable.
Not applicable ..................................................
Not applicable.
Not applicable ..................................................
Not applicable.
Thermal incinerator ..........................................
5. Startup or shutdown option 1: Electing to
comply with § 63.1568(a)(4)(ii). Each new or
existing sulfur recovery unit (Claus or other
type, regardless of size) during periods of
startup or shutdown.
6. Startup or shutdown option 2: Electing to
comply with § 63.1568(a)(4)(iii). Each new or
existing sulfur recovery unit (Claus or other
type, regardless of size) during startup or
shutdown events.
Flare .................................................................
Maintain the daily average combustion zone
temperature above the limit established during the performance test; and maintain the
daily average oxygen concentration in the
vent stream (percent, dry basis) above the
limit established during the performance
test.
On and after January 30, 2019, meet the applicable requirements of § 63.670. Prior to
January 30, 2019, meet the applicable requirements of either § 63.11(b) or § 63.670.
79. Table 31 to subpart UUU is revised
to read as follows:
■
Thermal incinerator or thermal oxidizer ...........
Maintain the hourly average combustion zone
temperature at or above 1,200 degrees
Fahrenheit and maintain the hourly average
oxygen concentration in the exhaust gas
stream at or above 2 volume percent (dry
basis).
As stated in § 63.1568(b)(1), you shall
meet each requirement in the following
table that applies to you.
TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR
RECOVERY UNITS
For this limit . . .
You shall install and operate this continuous
monitoring system . . .
1. Subject to NSPS. Each new or existing
Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater
than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
tkelley on DSK3SPTVN1PROD with RULES2
For . . .
a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or
reduction control system followed by incineration.
Continuous emission monitoring system to
measure and record the hourly average
concentration of SO2 (dry basis) at zero
percent excess air for each exhaust stack.
This system must include an oxygen monitor for correcting the data for excess air.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00134
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75311
TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR
RECOVERY UNITS—Continued
For this limit . . .
You shall install and operate this continuous
monitoring system . . .
b. 300 ppmv of reduced sulfur compounds
calculated as ppmv SO2 (dry basis) at zero
percent excess air if you use a reduction
control system without incineration.
For . . .
Continuous emission monitoring system to
measure and record the hourly average
concentration of reduced sulfur and oxygen
(O2) emissions. Calculate the reduced sulfur emissions as SO2 (dry basis) at zero
percent excess air. Exception: You can use
an instrument having an air or SO2 dilution
and oxidation system to convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry
basis) at zero percent excess air of the resultant SO2 instead of the reduced sulfur
monitor. The monitor must include an oxygen monitor for correcting the data for excess oxygen.
i. Complete either item 1.a or item 1.b; and
ii. Either a continuous emission monitoring
system to measure and record the O2 concentration for the inlet air/oxygen supplied
to the system or a continuous parameter
monitoring system to measure and record
the volumetric gas flow rate of ambient air
and purchased oxygen-enriched gas.
Continuous emission monitoring system to
measure and record the hourly average
concentration of SO2 (dry basis), at zero
percent excess air for each exhaust stack.
This system must include an oxygen monitor for correcting the data for excess air.
Continuous emission monitoring system to
measure and record the hourly average
concentration of reduced sulfur and O2
emissions for each exhaust stack. Calculate
the reduced sulfur emissions as SO2 (dry
basis), at zero percent excess air. Exception: You can use an instrument having an
air or O2 dilution and oxidation system to
convert the reduced sulfur to SO2 for continuously monitoring and recording the concentration (dry basis) at zero percent excess air of the resultant SO2 instead of the
reduced sulfur monitor. The monitor must
include an oxygen monitor for correcting the
data for excess oxygen.
i. Complete either item 2.a or item 2.b; and
ii. Either a continuous emission monitoring
system to measure and record the O2 concentration for the inlet air/oxygen supplied
to the system, or a continuous parameter
monitoring system to measure and record
the volumetric gas flow rate of ambient air
and purchased oxygen-enriched gas.
i. Continuous emission monitoring system to
measure and record the hourly average
concentration of TRS for each exhaust
stack; this monitor must include an oxygen
monitor for correcting the data for excess
oxygen; or
ii. Continuous parameter monitoring systems
to measure and record the combustion
zone temperature of each thermal incinerator and the oxygen content (percent, dry
basis) in the vent stream of the incinerator.
c. If you use Equation 1 of 40 CFR
60.102a(f)(1)(i) to set your emission limit.
2. Option 1: Elect NSPS. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
a. 250 ppmv (dry basis) of SO2 at zero percent excess air if you use an oxidation or
reduction control system followed by incineration.
b. 300 ppmv of reduced sulfur compounds
calculated as ppmv SO2 (dry basis) at zero
percent excess air if you use a reduction
control system without incineration.
c. If you use Equation 1 of 40 CFR
60.102a(f)(1)(i) to set your emission limit.
tkelley on DSK3SPTVN1PROD with RULES2
3. Option 2: TRS limit. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
a. 300 ppmv of total reduced sulfur (TRS)
compounds, expressed as an equivalent
SO2 concentration (dry basis) at zero percent oxygen.
PO 00000
Frm 00135
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75312
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 31 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR HAP EMISSIONS FROM SULFUR
RECOVERY UNITS—Continued
For . . .
For this limit . . .
You shall install and operate this continuous
monitoring system . . .
4. Startup or shutdown option 1: electing to
comply with § 63.1568(a)(4)(ii). Each new or
existing sulfur recovery unit (Claus or other
type, regardless of size) during periods of
startup or shutdown.
Any ...................................................................
5. Startup or shutdown option 2: electing to
comply with § 63.1568(a)(4)(iii). Each new or
existing sulfur recovery unit (Claus or other
type, regardless of size) during periods of
startup or shutdown.
Any ...................................................................
On and after January 30, 2019, monitoring
systems as specified in §§ 63.670 and
63.671. Prior to January 30, 2019, either
continuous parameter monitoring systems
following the requirements in § 63.11 (to detect the presence of a flame; to measure
and record the net heating value of the gas
being combusted; and to measure and
record the volumetric flow of the gas being
combusted) or monitoring systems as specified in §§ 63.670 and 63.671.
Continuous parameter monitoring systems to
measure and record the firebox temperature of each thermal incinerator or oxidizer
and the oxygen content (percent, dry basis)
in the exhaust vent from the incinerator or
oxidizer.
80. Table 32 to subpart UUU of part
63 is revised to read as follows:
■
As stated in § 63.1568(b)(2) and (3),
you shall meet each requirement in the
following table that applies to you.
TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM
SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES
For . . .
You must . . .
Using . . .
According to these
requirements . . .
1. Option 1: Elect NSPS. Each
new and existing sulfur recovery
unit.
a. Measure SO2 concentration (for
an oxidation or reduction system followed by incineration) or
measure the concentration of
reduced sulfur (or SO2 if you
use an instrument to convert
the reduced sulfur to SO2) for a
reduction control system without incineration.
b. Measure O2 concentration for
the inlet air/oxygen supplied to
the system, if using Equation 1
of 40 CFR 60.102a(f)1)(i) to set
your emission limit. You may
use either an O2 CEMS method
in item 1.b.i of this table or the
flow monitor in item 1.b.ii of this
table.
Data from continuous emission
monitoring system.
Collect SO2 monitoring data every
15 minutes for 24 consecutive
operating hours. Reduce the
data to 1-hour averages computed from four or more data
points equally spaced over
each 1-hour period.
i. Data from continuous emission
monitoring system; or
Collect O2 monitoring data every
15 minutes for 24 consecutive
operating hours. Reduce the
data to 1-hour averages computed from four or more data
points equally spaced over
each 1-hour period; and average over the 24-hour period for
input to Equation 1 of 40 CFR
60.102a(f)(1)(i).
Collect gas flow rate monitoring
data every 15 minutes for 24
consecutive operating hours.
Reduce the data to 1-hour
averages computed from 4 or
more data points equally
spaced over each 1-hour period; calculate the hourly O2
percent using Equation 10 of 40
CFR 60.106a(a)(6)(iv); and average over the 24-hour period
for input to Equation 1 of 40
CFR 60.102a(f)(1)(i).
Collect TRS data every 15 minutes for 24 consecutive operating hours. Reduce the data to
1-hour averages computed from
four or more data points equally
spaced over each 1-hour period.
tkelley on DSK3SPTVN1PROD with RULES2
ii. Data from flow monitor for ambient air and purchased oxygen-enriched gas.
2. Option 2: TRS limit, using
CEMS. Each new and existing
sulfur recovery unit.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Measure the concentration of reduced sulfur (or SO2 if you use
an instrument to convert the reduced sulfur to SO2).
Jkt 238001
PO 00000
Frm 00136
Fmt 4701
Data from continuous emission
monitoring system.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75313
TABLE 32 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR PERFORMANCE TESTS FOR HAP EMISSIONS FROM SULFUR RECOVERY UNITS NOT SUBJECT TO THE NEW SOURCE PERFORMANCE STANDARDS FOR SULFUR OXIDES—Continued
For . . .
You must . . .
Using . . .
According to these
requirements . . .
3. Option 2: TRS limit, if using
continuous parameter monitoring
systems. Each new and existing
sulfur recovery unit.
a. Select sampling port’s location
and the number of traverse
ports.
Method 1 or 1A in Appendix A–1
to part 60 of this chapter.
Sampling sites must be located at
the outlet of the control device
and prior to any releases to the
atmosphere.
b. Determine velocity and volumetric flow rate.
Method 2, 2A, 2C, 2D, or 2F in
appendix A–1 to part 60 of this
chapter, or Method 2G in appendix A–2 to part 60 of this
chapter, as applicable.
Method 3, 3A, or 3B in appendix
A–2 to part 60 of this chapter,
as applicable.
c. Conduct gas molecular weight
analysis; obtain the oxygen
concentration needed to correct
the emission rate for excess air.
d. Measure moisture content of
the stack gas.
Method 4 in appendix A–3 to part
60 of this chapter.
e. Measure the concentration of
TRS.
Method 15 or 15A in appendix A–
5 to part 60 of this chapter, as
applicable.
f. Calculate the SO2 equivalent for
each run after correcting for
moisture and oxygen.
g. Correct the reduced sulfur
samples to zero percent excess
air.
h. Establish each operating limit in
Table 30 of this subpart that
applies to you.
i. Measure thermal incinerator:
combustion zone temperature.
Data from the continuous parameter monitoring system.
81. Table 33 to subpart UUU of part
63 is revised to read as follows:
tkelley on DSK3SPTVN1PROD with RULES2
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Make your sampling time for each
Method 4 sample equal to that
for 4 Method 15 samples.
If the cross-sectional area of the
duct is less than 5 square meters (m2) or 54 square feet, you
must use the centroid of the
cross section as the sampling
point. If the cross-sectional area
is 5 m2 or more and the centroid is more than 1 meter (m)
from the wall, your sampling
point may be at a point no closer to the walls than 1 m or 39
inches. Your sampling rate
must be at least 3 liters per
minute or 0.10 cubic feet per
minute to ensure minimum residence time for the sample inside the sample lines.
The arithmetic average of the SO2
equivalent for each sample during the run.
Equation 1 of § 63.1568 ...............
j. Measure thermal incinerator: oxygen concentration (percent,
dry basis) in the vent stream.
Take the samples simultaneously
with reduced sulfur or moisture
samples.
Jkt 238001
Data from the continuous parameter monitoring system.
Data from the continuous parameter monitoring system.
Collect temperature monitoring
data every 15 minutes during
the entire period of the performance test; and determine and
record the minimum hourly average temperature from all the
readings.
Collect oxygen concentration (percent, dry basis) data every 15
minutes during the entire period
of the performance test; and
determine and record the minimum hourly average percent
excess oxygen concentration.
As stated in § 63.1568(b)(5), you shall
meet each requirement in the following
table that applies to you.
PO 00000
Frm 00137
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75314
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY
UNITS
For . . .
For the following emission limit . . .
You have demonstrated initial
compliance if . . .
1. Subject to NSPS: Each new or existing
Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater
than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
a. 250 ppmv (dry basis) SO2 at zero percent
excess air, or concentration determined
using
Equation
1
of
40
CFR
60.102a(f)(1)(i), if you use an oxidation or
reduction control system followed by incineration.
You have already conducted a performance
test to demonstrate initial compliance with
the NSPS and each 12-hour rolling average
concentration of SO2 emissions measured
by the continuous emission monitoring system is less than or equal to 250 ppmv (dry
basis) at zero percent excess air, or the
concentration determined using Equation 1
of 40 CFR 60.102a(f)(1)(i). As part of the
Notification of Compliance Status, you must
certify that your vent meets the SO2 limit.
You are not required to do another performance test to demonstrate initial compliance.
You have already conducted a performance
evaluation to demonstrate initial compliance
with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets
the applicable requirements in § 63.1572.
You are not required to do another performance evaluation to demonstrate initial compliance.
You have already conducted a performance
test to demonstrate initial compliance with
the NSPS and each 12-hour rolling average
concentration of reduced sulfur compounds
measured by your continuous emission
monitoring system is less than or equal to
300 ppmv, calculated as ppmv SO2 (dry
basis) at zero percent excess air, or the
concentration determined using Equation 1
of 40 CFR 60.102a(f)(1)(i). As part of the
Notification of Compliance Status, you must
certify that your vent meets the SO2 limit.
You are not required to do another performance test to demonstrate initial compliance.
You have already conducted a performance
evaluation to demonstrate initial compliance
with the applicable performance specification. As part of your Notification of Compliance Status, you must certify that your continuous emission monitoring system meets
the applicable requirements in § 63.1572.
You are not required to do another performance evaluation to demonstrate initial compliance.
Each 12-hour rolling average concentration of
SO2 emissions measured by the continuous
emission monitoring system during the initial performance test is less than or equal to
250 ppmv (dry basis) at zero percent excess air, or the concentration determined
using
Equation
1
of
40
CFR
60.102a(f)(1)(i); and your performance evaluation shows the monitoring system meets
the applicable requirements in § 63.1572.
Each 12-hour rolling average concentration of
reduced sulfur compounds measured by the
continuous emission monitoring system during the initial performance test is less than
or equal to 300 ppmv, calculated as ppmv
SO2 (dry basis) at zero percent excess air,
or the concentration determined using
Equation 1 of 40 CFR 60.102a(f)(1)(i); and
your performance evaluation shows the
continuous emission monitoring system
meets the applicable requirements in
§ 63.1572.
b. 300 ppmv of reduced sulfur compounds
calculated as ppmv SO2 (dry basis) at zero
percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use a reduction control system without incineration.
tkelley on DSK3SPTVN1PROD with RULES2
2. Option 1: Elect NSPS. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use an oxidation or
reduction control system followed by incineration.
b. 300 ppmv of reduced sulfur compounds
calculated as ppmv SO2 (dry basis) at zero
percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use a reduction control system without incineration.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00138
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75315
TABLE 33 TO SUBPART UUU OF PART 63—INITIAL COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR RECOVERY
UNITS—Continued
For . . .
For the following emission limit . . .
You have demonstrated initial
compliance if . . .
3. Option 2: TRS limit. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
300 ppmv of TRS compounds expressed as
an equivalent SO2 concentration (dry basis)
at zero percent oxygen.
If you use continuous parameter monitoring
systems, the average concentration of TRS
emissions measured using Method 15 during the initial performance test is less than
or equal to 300 ppmv expressed as equivalent SO2 concentration (dry basis) at zero
percent oxygen. If you use a continuous
emission monitoring system, each 12-hour
rolling average concentration of TRS emissions measured by the continuous emission
monitoring system during the initial performance test is less than or equal to 300 ppmv
expressed as an equivalent SO2 (dry basis)
at zero percent oxygen; and your performance evaluation shows the continuous
emission monitoring system meets the applicable requirements in § 63.1572.
82. Table 34 to subpart UUU of part
63 is revised to read as follows:
As stated in § 63.1568(c)(1), you shall
meet each requirement in the following
table that applies to you.
■
TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR
RECOVERY UNITS
For . . .
For this emission limit . . .
You shall demonstrate continuous compliance
by . . .
1. Subject to NSPS. Each new or existing
Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater
than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use an oxidation or
reduction control system followed by incineration.
Collecting the hourly average SO2 monitoring
data (dry basis, percent excess air) and, if
using
Equation
1
of
40
CFR
60.102a(f)(1)(i), collecting the hourly O2
concentration or flow monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12-hour
rolling average concentration of SO2 at or
below the applicable emission limitation;
and reporting any 12-hour rolling average
concentration of SO2 greater than the applicable emission limitation in the semiannual
compliance report required by § 63.1575.
Collecting the hourly average reduced sulfur
(and air or O2 dilution and oxidation) monitoring data and, if using Equation 1 of 40
CFR 60.102a(f)(1)(i), collecting the hourly
O2 concentration or flow monitoring data
according to § 63.1572; determining and recording each 12-hour rolling average concentration of reduced sulfur; maintaining
each 12-hour rolling average concentration
of reduced sulfur at or below the applicable
emission limitation; and reporting any 12hour rolling average concentration of reduced sulfur greater than the applicable
emission limitation in the semiannual compliance report required by § 63.1575.
tkelley on DSK3SPTVN1PROD with RULES2
b. 300 ppmv of reduced sulfur compounds
calculated as ppmv SO2 (dry basis) at zero
percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use a reduction control system without incineration.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00139
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75316
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 34 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH HAP EMISSION LIMITS FOR SULFUR
RECOVERY UNITS—Continued
For . . .
For this emission limit . . .
You shall demonstrate continuous compliance
by . . .
2. Option 1: Elect NSPS. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
a. 250 ppmv (dry basis) of SO2 at zero percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use an oxidation or
reduction control system followed by incineration.
Collecting the hourly average SO2 data (dry
basis, percent excess air) and, if using
Equation 1 of 40 CFR 60.102a(f)(1)(i), collecting the hourly O2 concentration or flow
monitoring data according to § 63.1572; determining and recording each 12-hour rolling average concentration of SO2; maintaining each 12-hour rolling average concentration of SO2 at or below the applicable emission limitation; and reporting any 12-hour
rolling average concentration of SO2 greater
than the applicable emission limitation in
the semiannual compliance report required
by § 63.1575.
Collecting the hourly average reduced sulfur
(and air or O2 dilution and oxidation) monitoring data and, if using Equation 1 of 40
CFR 60.102a(f)(1)(i), collecting the hourly
O2 concentration or flow monitoring data
according to § 63.1572; determining and recording each 12-hour rolling average concentration of reduced sulfur; maintaining
each 12-hour rolling average concentration
of reduced sulfur at or below the applicable
emission limitation; and reporting any 12hour rolling average concentration of reduced sulfur greater than the applicable
emission limitation in the semiannual compliance report required by § 63.1575.
i. If you use continuous parameter monitoring
systems, collecting the hourly average TRS
monitoring data according to § 63.1572 and
maintaining each 12-hour average concentration of TRS at or below the applicable
emission limitation; or
ii. If you use a continuous emission monitoring system, collecting the hourly average
TRS
monitoring
data
according
to
§ 63.1572, determining and recording each
12-hour rolling average concentration of
TRS; maintaining each 12-hour rolling average concentration of TRS at or below the
applicable emission limitation; and reporting
any 12-hour rolling average TRS concentration greater than the applicable emission
limitation in the semiannual compliance report required by § 63.1575.
b. 300 ppmv of reduced sulfur compounds
calculated as ppmv SO2 (dry basis) at zero
percent excess air, or concentration determined using Equation 1 of 40 CFR
60.102a(f)(1)(i), if you use a reduction control system without incineration.
3. Option 2: TRS limit. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
83. Table 35 to subpart UUU of part
63 is revised to read as follows:
300 ppmv of TRS compounds, expressed as
an SO2 concentration (dry basis) at zero
percent oxygen or reduced sulfur compounds calculated as ppmv SO2 (dry basis)
at zero percent excess air.
As stated in § 63.1568(c)(1), you shall
meet each requirement in the following
table that applies to you.
■
TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS
FROM SULFUR RECOVERY UNITS
tkelley on DSK3SPTVN1PROD with RULES2
For . . .
For this operating limit . . .
You shall demonstrate continuous compliance
by . . .
1. Subject to NSPS. Each new or existing
Claus sulfur recovery unit part of a sulfur recovery plant with design capacity greater
than 20 LTD and subject to the NSPS for sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
Not applicable ..................................................
Meeting the requirements of Table 34 of this
subpart.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00140
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75317
TABLE 35 TO SUBPART UUU OF PART 63—CONTINUOUS COMPLIANCE WITH OPERATING LIMITS FOR HAP EMISSIONS
FROM SULFUR RECOVERY UNITS—Continued
For . . .
For this operating limit . . .
You shall demonstrate continuous compliance
by . . .
2. Option 1: Elect NSPS. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
3. Option 2: TRS limit. Each new or existing
sulfur recovery unit (Claus or other type, regardless of size) not subject to the NSPS for
sulfur oxides in 40 CFR 60.104(a)(2) or
60.102a(f)(1).
Not applicable ..................................................
Meeting the requirements of Table 34 of this
subpart.
a. Maintain the daily average combustion
zone temperature above the level established during the performance test.
Collecting the hourly and daily average temperature monitoring data according to
§ 63.1572; and maintaining the daily average combustion zone temperature at or
above the limit established during the performance test
Collecting the hourly and daily average O2
monitoring data according to § 63.1572; and
maintaining the average O2 concentration
above the level established during the performance test.
On and after January 30, 2019, complying
with the applicable requirements of
§ 63.670. Prior to January 30, 2019, complying with the applicable requirements of
either § 63.11(b) or § 63.670.
Collecting continuous (at least once every 15
minutes) and hourly average temperature
monitoring data according to § 63.1572; and
maintaining the daily average firebox temperature at or above 1,200 degrees Fahrenheit.
Collecting continuous (at least once every 15
minutes) and hourly average O2 monitoring
data according to § 63.1572; and maintaining the average O2 concentration at or
above 2 volume percent (dry basis).
b. The daily average oxygen concentration in
the vent stream (percent, dry basis) must
not fall below the level established during
the performance test..
4. Startup or shutdown option 1: Electing to
comply with § 63.1568(a)(4)(ii). Each new or
existing sulfur recovery unit (Claus or other
type, regardless of size) during periods of
startup or shutdown.
5. Startup or shutdown option 2: Electing to
comply with § 63.1568(a)(4)(iii). Each new or
existing sulfur recovery unit (Claus or other
type, regardless of size) during periods of
startup or shutdown.
Using a flare meeting the requirements in
§ 63.11(b) or § 63.670.
a. Minimum hourly average temperature of
1,200 degrees Fahrenheit.
b. Minimum hourly average outlet oxygen
concentration of 2 volume percent (dry
basis).
84. Table 40 to subpart UUU of part
63 is revised to read as follows:
■
As stated in § 63.1572(a)(1) and (b)(1),
you shall meet each requirement in the
following table that applies to you.
TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF
CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS
This type of continuous opacity or emission monitoring system . . .
Must meet these requirements . . .
1. Continuous opacity monitoring system ................................................
2. PM CEMS; this monitor must include an O2 monitor for correcting
the data for excess air.
3. CO continuous emission monitoring system ........................................
Performance specification 1 (40 CFR part 60, appendix B).
The requirements in 40 CFR 60.105a(d).
tkelley on DSK3SPTVN1PROD with RULES2
4. CO continuous emission monitoring system used to demonstrate
emissions average under 50 ppm (dry basis).
5. SO2 continuous emission monitoring system for sulfur recovery unit
with oxidation control system or reduction control system; this monitor must include an O2 monitor for correcting the data for excess air.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00141
Fmt 4701
Performance specification 4 (40 CFR part 60, appendix B); span value
of 1,000 ppm; and procedure 1 (40 CFR part 60, appendix F) except
relative accuracy test audits are required annually instead of quarterly.
Performance specification 4 (40 CFR part 60, appendix B); and span
value of 100 ppm.
Performance specification 2 (40 CFR part 60, appendix B); span value
of 500 ppm SO2, or if using Equation 1 of 40 CFR 60.102a(f)(1)(i),
span value of two times the limit at the highest O2 concentration; use
Methods 6 or 6C (40 CFR part 60, appendix A–4) for certifying the
SO2 monitor and Methods 3A or 3B (40 CFR part 60, appendix A–2)
for certifying the O2 monitor; and procedure 1 (40 CFR part 60, appendix F) except relative accuracy test audits are required annually
instead of quarterly.
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75318
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 40 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF
CONTINUOUS OPACITY MONITORING SYSTEMS AND CONTINUOUS EMISSION MONITORING SYSTEMS—Continued
This type of continuous opacity or emission monitoring system . . .
Must meet these requirements . . .
6. Reduced sulfur and O2 continuous emission monitoring system for
sulfur recovery unit with reduction control system not followed by incineration; this monitor must include an O2 monitor for correcting the
data for excess air unless exempted.
Performance specification 5 (40 CFR part 60, appendix B), except calibration drift specification is 2.5 percent of the span value instead of 5
percent; span value is 450 ppm reduced sulfur, or if using Equation
1 of 40 CFR 60.102a(f)(1)(i), span value of two times the limit at the
highest O2 concentration; use Methods 15 or 15A (40 CFR part 60,
appendix A–5) for certifying the reduced sulfur monitor and Methods
3A or 3B (40 CFR part 60, appendix A–2) for certifying the O2 monitor; if Method 3A or 3B yields O2 concentrations below 0.25 percent
during the performance evaluation, the O2 concentration can be assumed to be zero and the O2 monitor is not required; and procedure
1 (40 CFR part 60, appendix F), except relative accuracy test audits,
are required annually instead of quarterly.
Performance specification 5 (40 CFR part 60, appendix B); span value
of 375 ppm SO2 or if using Equation 1 of 40 CFR 60.102a(f)(1)(i),
span value of two times the limit at the highest O2 concentration; use
Methods 15 or 15A (40 CFR part 60, appendix A–5) for certifying the
reduced sulfur monitor and 3A or 3B (40 CFR part 60, appendix A–
2) for certifying the O2 monitor; and procedure 1 (40 CFR part 60,
appendix F), except relative accuracy test audits, are required annually instead of quarterly.
Performance specification 5 (40 CFR part 60, appendix B).
7. Instrument with an air or O2 dilution and oxidation system to convert
reduced sulfur to SO2 for continuously monitoring the concentration
of SO2 instead of reduced sulfur monitor and O2 monitor.
8. TRS continuous emission monitoring system for sulfur recovery unit;
this monitor must include an O2 monitor for correcting the data for
excess air.
9. O2 monitor for oxygen concentration ...................................................
85. Table 41 to subpart UUU of part
63 is revised to read as follows:
■
If necessary due to interferences, locate the oxygen sensor prior to the
introduction of any outside gas stream; performance specification 3
(40 CFR part 60, appendix B; and procedure 1 (40 CFR part 60, appendix F), except relative accuracy test audits, are required annually
instead of quarterly.
As stated in § 63.1572(c)(1), you shall
meet each requirement in the following
table that applies to you.
TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF
CONTINUOUS PARAMETER MONITORING SYSTEMS
If you use . . .
You shall . . .
1. pH strips ............
2. pH meter ............
Use pH strips with an accuracy of ±10 percent.
Locate the pH sensor in a position that provides a representative measurement of pH; ensure the sample is properly
mixed and representative of the fluid to be measured.
Use a pH sensor with an accuracy of at least ±0.2 pH units.
Check the pH meter’s calibration on at least one point at least once daily; check the pH meter’s calibration on at least two
points at least once quarterly; at least monthly, inspect all components for integrity and all electrical components for
continuity; record the results of each calibration check and inspection.
Use a colormetric tube sampling system with a printed numerical scale in ppmv, a standard measurement range of 1 to 10
ppmv (or 1 to 30 ppmv if applicable), and a standard deviation for measured values of no more than ±15 percent. System must include a gas detection pump and hot air probe if needed for the measurement range.
a. Locate the concentration sensor so that it provides a representative measurement of the content of the exit gas stream;
ensure the sample is properly mixed and representative of the gas to be measured.
3. Colormetric tube
sampling system.
tkelley on DSK3SPTVN1PROD with RULES2
4. CO2, O2, and CO
monitors for coke
burn-off rate.
5. BLD ....................
6. Voltage, secondary current, or
total power input
sensors.
VerDate Sep<11>2014
Use a sensor with an accuracy of at least ±1 percent of the range of the sensor or to a nominal gas concentration of ±0.5
percent, whichever is greater.
Use a monitor that is able to measure concentration on a dry basis or is able to correct for moisture content and record on
a dry basis.
Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours
throughout which the sensor reading exceeds the manufacturer’s specified maximum operating range or install a new
sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity; record the results of each calibration and inspection.
b. As an alternative, the requirements in 40 CFR 60.105a(b)(2) may be used.
Follow the requirements in 40 CFR 60.105a(c).
Use meters with an accuracy of at least ±5 percent over the operating range.
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00142
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75319
TABLE 41 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR INSTALLATION, OPERATION, AND MAINTENANCE OF
CONTINUOUS PARAMETER MONITORING SYSTEMS—Continued
If you use . . .
You shall . . .
7. Pressure/Pressure drop1 sensors.
8. Air flow rate, gas
flow rate, or total
water (or scrubbing liquid) flow
rate sensors.
9. Temperature
sensors.
10. Oxygen content
sensors 2.
Each time that the unit is not operating, confirm that the meters read zero. Conduct a calibration check at least annually;
conduct calibration checks following any period of more than 24 hours throughout which the meter reading exceeds the
manufacturer’s specified maximum operating range; at least monthly, inspect all components of the continuous parameter monitoring system for integrity and all electrical connections for continuity; record the results of each calibration
check and inspection.
Locate the pressure sensor(s) in a position that provides a representative measurement of the pressure and minimizes or
eliminates pulsating pressure, vibration, and internal and external corrosion.
Use a gauge with an accuracy of at least ±5 percent over the normal operating range or 0.12 kilopascals (0.5 inches of
water column), whichever is greater.
Review pressure sensor readings at least once a week for straightline (unchanging) pressure and perform corrective action to ensure proper pressure sensor operation if blockage is indicated; using an instrument recommended by the sensor’s manufacturer, check gauge calibration and transducer calibration annually; conduct calibration checks following
any period of more than 24 hours throughout which the pressure exceeded the manufacturer’s specified maximum rated
pressure or install a new pressure sensor; at least quarterly, inspect all components for integrity, all electrical connections for continuity, and all mechanical connections for leakage, unless the CPMS has a redundant pressure sensor;
record the results of each calibration check and inspection.
Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
If you elect to comply with Option 3 (Ni lb/hr) or Option 4 (Ni lb/1,000 lb of coke burn-off) for the HAP metal emission
limitations in § 63.1564, install the continuous parameter monitoring system for gas flow rate as close as practical to the
continuous opacity monitoring system; and if you don’t use a continuous opacity monitoring system, install the continuous parameter monitoring system for gas flow rate as close as practical to the control device.
Use a flow rate sensor with an accuracy of at least ±5 percent over the normal range of flow measured, or 1.9 liter per
minute (0.5 gallons per minute), whichever is greater, for liquid flow.
Use a flow rate sensor with an accuracy of at least ±5 percent over the normal range of flow measured, or 280 liters per
minute (10 cubic feet per minute), whichever is greater, for gas flow.
Conduct a flow sensor calibration check at least biennially (every two years); conduct a calibration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow
rate or install a new flow sensor; at least quarterly, inspect all components for leakage, unless the CPMS has a redundant flow sensor; record the results of each calibration check and inspection.
Locate the temperature sensor in the combustion zone, or in the ductwork immediately downstream of the combustion
zone before any substantial heat exchange occurs or in the ductwork immediately downstream of the regenerator; locate the temperature sensor in a position that provides a representative temperature; shield the temperature sensor system from electromagnetic interference and chemical contaminants.
Use a temperature sensor with an accuracy of at least ±1 percent over the normal range of temperature measured, expressed in degrees Celsius (C), or 2.8 degrees C, whichever is greater.
Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours
throughout which the temperature exceeded the manufacturer’s specified maximum rated temperature or install a new
temperature sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity,
oxidation, and galvanic corrosion, unless the CPMS has a redundant temperature sensor; record the results of each
calibration check and inspection.
Locate the oxygen sensor so that it provides a representative measurement of the oxygen content of the exit gas stream;
ensure the sample is properly mixed and representative of the gas to be measured.
Use an oxygen sensor with an accuracy of at least ±1 percent of the range of the sensor or to a nominal gas concentration of ±0.5 percent, whichever is greater.
Conduct calibration checks at least annually; conduct calibration checks following any period of more than 24 hours
throughout which the sensor reading exceeds the manufacturer’s specified maximum operating range or install a new
oxygen sensor; at least quarterly, inspect all components for integrity and all electrical connections for continuity; record
the results of each calibration and inspection.
1 Not
applicable to non-venturi wet scrubbers of the jet-ejector design.
does not replace the requirements for oxygen monitors that are required to use continuous emissions monitoring systems. The requirements in this table apply to oxygen sensors that are continuous parameter monitors, such as those that monitor combustion zone oxygen concentration and regenerator exit oxygen concentration.
2 This
86. Table 43 to subpart UUU is revised
to read as follows:
tkelley on DSK3SPTVN1PROD with RULES2
■
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
As stated in § 63.1575(a), you shall
meet each requirement in the following
table that applies to you.
PO 00000
Frm 00143
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75320
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 43 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR REPORTS
You must submit . . .
The report must contain . . .
You shall submit the report . . .
1. A compliance report ....................
If there are no deviations from any emission limitation or work practice standard that applies to you, a statement that there were no
deviations from the standards during the reporting period and that
no continuous opacity monitoring system or continuous emission
monitoring system was inoperative, inactive, out-of-control, repaired, or adjusted; if you have a deviation from any emission limitation or work practice standard during the reporting period, the report must contain the information in § 63.1575(c) through (e).
On and after January 30, 2019, the information specified in
§ 63.1575(k)(1).
Semiannually according to the requirements in § 63.1575(b).
2. Performance test and CEMS
performance evaluation data.
87. Table 44 to subpart UUU of part
63 is revised to read as follows:
■
Within 60 days after the date of
completing each test according
to
the
requirements
in
§ 63.1575(k).
As stated in § 63.1577, you shall meet
each requirement in the following table
that applies to you.
TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU
Citation
Subject
Applies to subpart
UUU
§ 63.1(a)(1)–(4) .....................................
§ 63.1(a)(5) ............................................
§ 63.1(a)(6) ............................................
General Applicability ...........................
[Reserved] ..........................................
.............................................................
Yes .............................
Not applicable ............
Yes .............................
§ 63.1(a)(7)–(9) .....................................
§ 63.1(a)(10)–(12) .................................
[Reserved] ..........................................
.............................................................
Not applicable ............
Yes .............................
§ 63.1(b)(1) ............................................
Yes .............................
§ 63.1(c)(2) ............................................
Initial Applicability Determination for
this part.
[Reserved] ..........................................
.............................................................
Applicability of this part after a Relevant Standard has been set under
this part.
.............................................................
No ...............................
§ 63.1(c)(3)–(4) .....................................
§ 63.1(c)(5) ............................................
§ 63.1(d) ................................................
§ 63.1(e) ................................................
§ 63.2 ....................................................
[Reserved] ..........................................
.............................................................
[Reserved] ..........................................
Applicability of Permit Program ..........
Definitions ...........................................
Not applicable ............
Yes .............................
Not applicable ............
Yes .............................
Yes .............................
§ 63.3 ....................................................
§ 63.4(a)(1)–(2) .....................................
§ 63.4(a)(3)–(5) .....................................
§ 63.4(b)–(c) ..........................................
§ 63.5(a) ................................................
§ 63.5(b)(1) ............................................
§ 63.5(b)(2) ............................................
§ 63.5(b)(3)–(4) .....................................
Units and Abbreviations .....................
Prohibited Activities ............................
[Reserved] ..........................................
Circumvention and Fragmentation .....
Construction and Reconstruction .......
.............................................................
[Reserved] ..........................................
.............................................................
Yes .............................
Yes .............................
Not applicable ............
Yes .............................
Yes .............................
Yes .............................
Not applicable ............
Yes .............................
§ 63.5(b)(5) ............................................
§ 63.5(b)(6) ............................................
§ 63.5(c) ................................................
§ 63.5(d)(1)(i) ........................................
[Reserved] ..........................................
.............................................................
[Reserved] ..........................................
Application for Approval of Construction or Reconstruction—General
Application Requirements.
Not applicable ............
Yes .............................
Not applicable ............
Yes .............................
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.1(b)(2) ............................................
§ 63.1(b)(3) ............................................
§ 63.1(c)(1) ............................................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00144
Fmt 4701
Explanation
Except the correct mail drop (MD)
number is C404–04.
Except that this subpart specifies calendar or operating day.
Not applicable ............
Yes .............................
Yes .............................
Sfmt 4700
E:\FR\FM\01DER2.SGM
Area sources are not subject to this
subpart.
§ 63.1579 specifies that if the same
term is defined in subparts A and
UUU of this part, it shall have the
meaning given in this subpart.
In § 63.5(b)(4), replace the reference
to § 63.9(b) with § 63.9(b)(4) and
(5).
Except this subpart specifies the application is submitted as soon as
practicable before startup but not
later than 90 days after the promulgation date if construction or reconstruction had commenced and initial startup had not occurred before
promulgation.
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75321
TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU—
Continued
Citation
Subject
Applies to subpart
UUU
Explanation
§ 63.5(d)(1)(ii) ........................................
.............................................................
Yes .............................
§ 63.5(d)(1)(iii) .......................................
.............................................................
No ...............................
Except that emission estimates specified in § 63.5(d)(1)(ii)(H) are not required, and § 63.5(d)(1)(ii)(G) and
(I) are Reserved and do not apply.
This subpart specifies submission of
notification of compliance status.
§ 63.5(d)(2) ............................................
§ 63.5(d)(3) ............................................
§ 63.5(d)(4) ............................................
§ 63.5(e) ................................................
.............................................................
.............................................................
.............................................................
Approval of Construction or Reconstruction.
Approval of Construction or Reconstruction Based on State Review.
.............................................................
Yes
Yes
Yes
Yes
Compliance with Standards and
Maintenance—Applicability.
Compliance Dates for New and Reconstructed Sources.
.............................................................
Yes .............................
[Reserved] ..........................................
Compliance Dates for New and Reconstructed Area Sources That Become Major.
Compliance
Dates
for
Existing
Sources.
Not applicable ............
Yes .............................
[Reserved] ..........................................
Compliance Dates for Existing Area
Sources That Become Major.
[Reserved] ..........................................
General Duty to Minimize Emissions
Not applicable ............
Yes .............................
Requirement to Correct Malfunctions
as Soon as Possible.
Compliance with Standards and
Maintenance Requirements.
[Reserved] ..........................................
Startup, Shutdown, and Malfunction
Plan Requirements.
[Reserved] ..........................................
.............................................................
SSM Exemption ..................................
Compliance with Standards and
Maintenance Requirements.
.............................................................
.............................................................
.............................................................
No ...............................
§ 63.5(f)(1) .............................................
§ 63.5(f)(2) .............................................
§ 63.6(a) ................................................
§ 63.6(b)(1)–(4) .....................................
§ 63.6(b)(5) ............................................
§ 63.6(b)(6) ............................................
§ 63.6(b)(7) ............................................
§ 63.6(c)(1)–(2) .....................................
§ 63.6(c)(3)–(4) .....................................
§ 63.6(c)(5) ............................................
§ 63.6(d) ................................................
§ 63.6(e)(1)(i) ........................................
§ 63.6(e)(1)(ii) ........................................
§ 63.6(e)(1)(iii) .......................................
§ 63.6(e)(2) ............................................
§ 63.6(e)(3)(i) ........................................
§ 63.6(e)(3)(ii) ........................................
§ 63.6(e)(3)(iii)–(ix) ................................
§ 63.6(f)(1) .............................................
§ 63.6(f)(2)(i)–(iii)(C) ..............................
§ 63.6(f)(2)(iii)(D) ...................................
§ 63.6(f)(2)(iv)–(v) .................................
§ 63.6(f)(3) .............................................
§ 63.6(g) ................................................
§ 63.6(h)(1) ............................................
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.6(h)(2)(i) ........................................
§ 63.6(h)(2)(ii) ........................................
§ 63.6(h)(2)(iii) .......................................
§ 63.6(h)(3) ............................................
§ 63.6(h)(4) ............................................
§ 63.6(h)(5) ............................................
§ 63.6(h)(6) ............................................
§ 63.6(h)(7)(i) ........................................
§ 63.6(h)(7)(ii) ........................................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Alternative Standard ...........................
SSM Exemption for Opacity/VE
Standards.
Determining Compliance with Opacity/VE Standards.
[Reserved] ..........................................
.............................................................
[Reserved] ..........................................
Notification of Opacity/VE Observation Date.
Conducting Opacity/VE Observations
Records of Conditions During Opacity/VE Observations.
Report COM Monitoring Data from
Performance Test.
Using COM Instead of Method 9 .......
Jkt 238001
PO 00000
Frm 00145
Fmt 4701
.............................
.............................
.............................
.............................
Yes .............................
Yes .............................
Except that the cross-reference to
§ 63.9(b)(2) does not apply.
Yes .............................
Yes .............................
Yes .............................
Not applicable ............
No ...............................
Except that this subpart specifies different
compliance
dates
for
sources.
Except that this subpart specifies different compliance dates for sources
subject to Tier II gasoline sulfur
control requirements.
See § 63.1570(c) for general duty requirement.
Yes .............................
Not Applicable ............
No ...............................
Not applicable ............
No ...............................
No ...............................
Yes .............................
Yes .............................
Yes .............................
Yes .............................
Except the cross-references to
§ 63.6(f)(1)
and
(e)(1)(i)
are
changed to § 63.1570(c).
Yes .............................
No ...............................
No ...............................
Not applicable ............
Yes .............................
Not applicable ............
Yes .............................
No ...............................
Yes .............................
This subpart specifies methods.
Applies to Method 22 (40 CFR part
60, appendix A–7) tests.
Applies to Method 22 (40 CFR part
60, appendix A–7) observations.
Yes .............................
No ...............................
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75322
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU—
Continued
Citation
Subject
Applies to subpart
UUU
§ 63.6(h)(7)(iii) .......................................
Averaging Time for COM during Performance Test.
COM Requirements ............................
COMS Results and Visual Observations.
Determining Compliance with Opacity/VE Standards.
Adjusted Opacity Standard ................
Extension of Compliance ...................
Yes .............................
§ 63.6(h)(7)(iv) .......................................
§ 63.6(h)(7)(v) .......................................
§ 63.6(h)(8) ............................................
§ 63.6(h)(9) ............................................
§ 63.6(i)(1)–(14) ....................................
Yes .............................
Yes .............................
Yes .............................
Yes .............................
Yes .............................
§ 63.6(i)(15) ...........................................
§ 63.6(i)(16) ...........................................
§ 63.6(j) .................................................
§ 63.7(a)(1) ............................................
[Reserved] ..........................................
.............................................................
Presidential Compliance Exemption ..
Performance Test Requirements Applicability.
Not applicable ............
Yes .............................
Yes .............................
Yes .............................
§ 63.7(a)(2) ............................................
Performance Test Dates ....................
Yes .............................
§ 63.7(a)(3) ............................................
§ 63.7(a)(4) ............................................
§ 63.7(b) ................................................
Section 114 Authority .........................
Force Majeure ....................................
Notifications ........................................
Yes .............................
Yes .............................
Yes .............................
§ 63.7(c) ................................................
Quality Assurance Program/Site-Specific Test Plan.
Yes .............................
§ 63.7(d) ................................................
§ 63.7(e)(1) ............................................
§ 63.7(e)(2)–(4) .....................................
§ 63.7(f) .................................................
§ 63.7(g) ................................................
Performance Test Facilities ................
Performance Testing ..........................
Conduct of Tests ................................
Alternative Test Method .....................
Data Analysis, Recordkeeping, Reporting.
Yes .............................
No ...............................
Yes .............................
Yes .............................
Yes .............................
§ 63.7(h) ................................................
§ 63.8(a)(1) ............................................
§ 63.8(a)(2) ............................................
§ 63.8(a)(3) ............................................
§ 63.8(a)(4) ............................................
Waiver of Tests ..................................
Monitoring Requirements-Applicability
Performance Specifications ................
[Reserved] ..........................................
Monitoring with Flares ........................
Yes .............................
Yes .............................
Yes .............................
Not applicable ............
Yes .............................
§ 63.8(b)(1) ............................................
§ 63.8(b)(2)–(3) .....................................
Conduct of Monitoring ........................
Multiple Effluents and Multiple Monitoring Systems.
Monitoring System Operation and
Maintenance.
General Duty to Minimize Emissions
and CMS Operation.
Keep Necessary Parts for CMS .........
Requirement to Develop SSM Plan
for CMS.
Yes .............................
Yes .............................
§ 63.8(c)(1) ............................................
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.8(c)(1)(i) .........................................
§ 63.8(c)(1)(ii) ........................................
§ 63.8(c)(1)(iii) .......................................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00146
Fmt 4701
Explanation
Extension of compliance under
§ 63.6(i)(4) not applicable to a facility that installs catalytic cracking
feed hydrotreating and receives an
extended compliance date under
§ 63.1563(c).
Except that this subpart specifies the
applicable test and demonstration
procedures.
Except test results must be submitted
in the Notification of Compliance
Status report due 150 days after
the compliance date.
Except that this subpart specifies notification at least 30 days prior to
the scheduled test date rather than
60 days.
Except that when this subpart specifies to use 40 CFR part 60, appendix F, out of control periods are to
be defined as specified in part 60,
appendix F.
See § 63.1571(b)(1).
Except performance test reports must
be submitted with notification of
compliance status due 150 days
after the compliance date, and
§ 63.7(g)(2) is reserved and does
not apply.
Except that for a flare complying with
§ 63.670, the cross-reference to
§ 63.11 in this paragraph does not
include § 63.11(b).
This subpart specifies the required
monitoring locations.
Yes .............................
No ...............................
See § 63.1570(c).
Yes .............................
No ...............................
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75323
TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU—
Continued
Citation
Subject
Applies to subpart
UUU
Explanation
§ 63.8(c)(2)–(3) .....................................
Monitoring System Installation ...........
Yes .............................
Except that this subpart specifies that
for continuous parameter monitoring systems, operational status
verification includes completion of
manufacturer written specifications
or installation, operation, and calibration of the system or other written procedures that provide adequate assurance that the equipment will monitor accurately.
§ 63.8(c)(4) ............................................
Yes .............................
§ 63.8(c)(5) ............................................
§ 63.8(c)(6) ............................................
§ 63.8(c)(7)–(8) .....................................
§ 63.8(d)(1)–(2) .....................................
§ 63.8(d)(3) ............................................
§ 63.8(e) ................................................
Continuous Monitoring System Requirements.
COMS Minimum Procedures ..............
CMS Requirements ............................
CMS Requirements ............................
Quality Control Program for CMS ......
Written Procedures for CMS ..............
CMS Performance Evaluation ............
Yes .............................
Yes .............................
Yes .............................
Yes .............................
No ...............................
Yes .............................
§ 63.8(f)(1)–(5) ......................................
Alternative Monitoring Methods ..........
Yes .............................
§ 63.8(f)(6) .............................................
Alternative to Relative Accuracy Test
Yes .............................
§ 63.8(g)(1)–(4) .....................................
Reduction of Monitoring Data ............
Yes .............................
§ 63.8(g)(5) ............................................
§ 63.9(a) ................................................
Data Reduction ...................................
Notification Requirements—Applicability.
No ...............................
Yes .............................
§ 63.9(b)(1)–(2) .....................................
Initial Notifications ..............................
Yes .............................
§ 63.9(b)(3) ............................................
§ 63.9(b)(4)–(5) .....................................
[Reserved] ..........................................
Initial Notification Information .............
Not applicable ............
Yes .............................
§ 63.9(c) ................................................
§ 63.9(d) ................................................
Request for Extension of Compliance
New Source Notification for Special
Compliance Requirements.
Notification of Performance Test ........
Yes .............................
Yes .............................
§ 63.9(e) ................................................
§ 63.9(f) .................................................
§ 63.9(g) ................................................
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.9(h) ................................................
§ 63.9(i) .................................................
§ 63.9(j) .................................................
63.10(a) .................................................
§ 63.10(b)(1) ..........................................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Yes .............................
Notification of VE/Opacity Test ..........
Additional Notification Requirements
for Sources with Continuous Monitoring Systems.
Notification of Compliance Status ......
Except § 63.9(b)(4)(ii)–(iv), which are
reserved and do not apply.
Except that notification is required at
least 30 days before test.
Yes .............................
Yes .............................
Adjustment of Deadlines ....................
Change in Previous Information .........
Recordkeeping and Reporting Applicability.
General Recordkeeping Requirements.
Except that results are to be submitted as part of the Notification
Compliance Status due 150 days
after the compliance date.
Except that this subpart specifies procedures for requesting alternative
monitoring systems and alternative
parameters.
Applicable to continuous emission
monitoring systems if performance
specification requires a relative accuracy test audit.
Applies to continuous opacity monitoring system or continuous emission monitoring system.
This subpart specifies requirements.
Duplicate Notification of Compliance
Status report to the Regional Administrator may be required.
Except that notification of construction
or reconstruction is to be submitted
as soon as practicable before startup but no later than 30 days after
the effective date if construction or
reconstruction had commenced but
startup had not occurred before the
effective date.
Yes .............................
Yes .............................
Yes .............................
Jkt 238001
PO 00000
Frm 00147
Fmt 4701
Yes .............................
Except that this subpart specifies the
notification is due no later than 150
days after compliance date, and
except that the reference to
§ 63.5(d)(1)(ii)(H) in § 63.9(h)(5)
does not apply.
Yes .............................
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
75324
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU—
Continued
Citation
Subject
Applies to subpart
UUU
§ 63.10(b)(2)(i) ......................................
Recordkeeping of Occurrence and
Duration of Startups and Shutdowns.
Recordkeeping of Malfunctions ..........
No ...............................
§ 63.10(b)(2)(ii) ......................................
§ 63.10(b)(2)(iii) .....................................
§ 63.10(b)(2)(iv)–(v) ..............................
§ 63.10(b)(2)(vi) .....................................
§ 63.10(b)(2)(vii)–(xiv) ...........................
§ 63.10(b)(3) ..........................................
§ 63.10(c)(1)–(6) ...................................
§ 63.10(c)(7)–(8) ...................................
§ 63.10(c)(9) ..........................................
§ 63.10(c)(10) ........................................
§ 63.10(c)(11) ........................................
§ 63.10(c)(12)–(14) ...............................
Maintenance Records ........................
Actions Taken to Minimize Emissions
During SSM.
Recordkeeping for CMS Malfunctions
Other CMS Requirements ..................
Recordkeeping for Applicability Determinations..
Additional Records for Continuous
Monitoring Systems.
Additional Recordkeeping Requirements
for
CMS—Identifying
Exceedances and Excess Emissions.
[Reserved] ..........................................
Recording Nature and Cause of Malfunctions.
Recording Corrective Actions .............
No ...............................
Yes .............................
Yes .............................
Yes .............................
Yes .............................
Not applicable ............
No ...............................
No ...............................
No ...............................
Yes .............................
No ...............................
§ 63.10(d)(3) ..........................................
§ 63.10(d)(4) ..........................................
§ 63.10(d)(5) ..........................................
Opacity or VE Observations ...............
Progress Reports ...............................
SSM Reports ......................................
Yes .............................
Yes .............................
No ...............................
§ 63.10(e)(1)–(2) ...................................
Additional CMS Reports .....................
Yes .............................
§ 63.10(e)(3) ..........................................
Excess Emissions/CMS Performance
Reports.
COMS Data Reports ..........................
Recordkeeping/Reporting Waiver ......
Control Device and Work Practice
Requirements Applicability.
Flares ..................................................
No ...............................
tkelley on DSK3SPTVN1PROD with RULES2
§ 63.11(c)–(e) ........................................
§ 63.12
§ 63.13
§ 63.14
§ 63.15
..................................................
..................................................
..................................................
..................................................
§ 63.16 ..................................................
VerDate Sep<11>2014
23:11 Nov 30, 2015
Alternative Work Practice for Monitoring Equipment for Leaks.
State Authority and Delegations ........
Addresses ...........................................
Incorporation by Reference ................
Availability of Information and Confidentiality.
Performance Track Provisions ...........
Jkt 238001
PO 00000
Frm 00148
Fmt 4701
Except § 63.10(c)(2)–(4), which are
Reserved and do not apply.
Yes .............................
§ 63.10(c)(15) ........................................
§ 63.10(d)(1) ..........................................
§ 63.10(d)(2) ..........................................
§ 63.11(b) ..............................................
See § 63.1576(a)(2) for recordkeeping
of (1) date, time and duration; (2)
listing of affected source or equipment, and an estimate of the volume of each regulated pollutant
emitted over the standard; and (3)
actions taken to minimize emissions and correct the failure.
Yes .............................
No ...............................
Additional CMS Recordkeeping Requirements.
Use of SSM Plan ................................
General Reporting Requirements ......
Performance Test Results ..................
§ 63.10(e)(4) ..........................................
§ 63.10(f) ...............................................
§ 63.11(a) ..............................................
Explanation
See § 63.1576(a)(2) for malfunctions
recordkeeping requirements.
See § 63.1576(a)(2) for malfunctions
recordkeeping requirements.
Yes .............................
This subpart requires performance
test results to be reported as part
of the Notification of Compliance
Status due 150 days after the compliance date.
See § 63.1575(d) for CPMS malfunction reporting and § 63.1575(e) for
COMS and CEMS malfunction reporting.
Except that reports of performance
evaluations must be submitted in
Notification of Compliance Status.
This subpart specifies the applicable
requirements.
Yes .............................
Yes .............................
Yes .............................
Yes .............................
Except that flares complying with
§ 63.670 are not subject to the requirements of § 63.11(b).
Yes .............................
Yes
Yes
Yes
Yes
.............................
.............................
.............................
.............................
Yes .............................
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
88. Appendix A to subpart UUU of
part 63 is amended by revising the first
sentence of section 2.1 and section 7.1.3
to read as follows:
■
Appendix A to Subpart UUU of Part
63—Determination of Metal
Concentration on Catalyst Particles
(Instrumental Analyzer Procedure)
*
*
*
*
*
2.1 A representative sample of catalyst
particles is collected, prepared, and analyzed
for analyte concentration using either energy
or wavelength dispersive X-ray fluorescent
(XRF) spectrometry instrumental analyzers.
* * *
*
*
*
*
*
7.1.3 Low-Range Calibration Standard.
Concentration equivalent to 1 to 20 percent
of the span. The concentration of the lowrange calibration standard should be selected
so that it is less than either one-fourth of the
applicable concentration limit or of the
lowest concentration anticipated in the
catalyst samples.
*
*
*
*
*
89. Appendix A to part 63 is amended
by adding Method 325A and Method
325B in numerical order to read as
follows:
■
Appendix A to Part 63—Test Methods
Pollutant Measurement Methods From
Various Waste Media
*
*
*
*
*
tkelley on DSK3SPTVN1PROD with RULES2
Method 325A—Volatile Organic
Compounds from Fugitive and Area Sources:
Sampler Deployment and VOC Sample
Collection
1.0 Scope and Application
1.1 This method describes collection of
volatile organic compounds (VOCs) at or
inside a facility property boundary or from
fugitive and area emission sources using
passive (diffusive) tube samplers (PS). The
concentration of airborne VOCs at or near
these potential fugitive- or area-emission
sources may be determined using this
method in combination with Method 325B.
Companion Method 325B (Sampler
Preparation and Analysis) describes
preparation of sampling tubes, shipment and
storage of exposed sampling tubes, and
analysis of sampling tubes collected using
either this passive sampling procedure or
alternative active (pumped) sampling
methods.
1.2 This method may be used to
determine the average concentration of the
select VOCs using the corresponding uptake
rates listed in Method 325B, Table 12.1.
Additional compounds or alternative
sorbents must be evaluated as described in
Addendum A of Method 325B or by one of
the following national/international standard
methods: ISO 16017–2:2003(E), ASTM
D6196–03 (Reapproved 2009), or BS EN
14662–4:2005 (all incorporated by
reference—see § 63.14), or reported in the
peer-reviewed open literature.
1.3 Methods 325A and 325B are valid for
the measurement of benzene. Supporting
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
literature (References 1–8) indicates that
benzene can be measured by flame ionization
detection or mass spectrometry over a
concentration range of approximately 0.5
micrograms per cubic meter (mg/m3) to at
least 500 mg/m3 when industry standard (3.5
inch long × 0.25 inch outside diameter (o.d.)
× 5 mm inner diameter (i.d.)) inert-coated
stainless steel sorbent tubes packed with
CarbographTM 1 TD, CarbopackTM B, or
CarbopackTM X or equivalent are used and
when samples are accumulated over a period
of 14 days.
1.4 This method may be applied to
screening average airborne VOC
concentrations at facility property boundaries
or monitoring perimeters over an extended
period of time using multiple sampling
periods (e.g., 26 × 14-day sampling periods).
The duration of each sampling period is
normally 14 days.
1.5 This method requires the collection of
local meteorological data (wind speed and
direction, temperature, and barometric
pressure). Although local meteorology is a
component of this method, non-regulatory
applications of this method may use regional
meteorological data. Such applications risk
that the results may not identify the precise
source of the emissions.
2.0
Summary of the Method
2.1 Principle of the Method
The diffusive passive sampler collects VOC
from air for a measured time period at a rate
that is proportional to the concentration of
vapor in the air at that location.
2.1.1 This method describes the
deployment of prepared passive samplers,
including determination of the number of
passive samplers needed for each survey and
placement of samplers along or inside the
facility property boundary depending on the
size and shape of the site or linear length of
the boundary.
2.1.2 The rate of sampling is specific to
each compound and depends on the
diffusion constants of that VOC and the
sampler dimensions/characteristics as
determined by prior calibration in a standard
atmosphere (Reference 1).
2.1.3 The gaseous VOC target compounds
migrate through a constant diffusion barrier
(e.g., an air gap of fixed dimensions) at the
sampling end of the diffusion sampling tube
and adsorb onto the sorbent.
2.1.4 Heat and a flow of inert carrier gas
are then used to extract (desorb) the retained
VOCs back from the sampling end of the tube
and transport/transfer them to a gas
chromatograph (GC) equipped with a
chromatographic column to separate the
VOCs and a detector to determine the
quantity of target VOCs.
2.1.5 Gaseous or liquid calibration
standards loaded onto the sampling ends of
clean sorbent tubes must be used to calibrate
the analytical equipment.
2.1.6 This method requires the use of
field blanks to ensure sample integrity
associated with shipment, collection, and
storage of the passive samples. It also
requires the use of field duplicates to validate
the sampling process.
2.1.7 At the end of each sampling period,
the passive samples are collected, sealed, and
PO 00000
Frm 00149
Fmt 4701
Sfmt 4700
75325
shipped to a laboratory for analysis of target
VOCs by thermal desorption gas
chromatography, as described in Method
325B.
2.2 Application of Diffusive Sampling
2.2.1 This method requires deployment of
passive sampling tubes on a monitoring
perimeter encompassing all known emission
sources at a facility and collection of local
meteorological data. It may be used to
determine average concentration of VOC at a
facility’s ‘‘fenceline’’ using time integrated
passive sampling (Reference 2).
2.2.2 Collecting samples and
meteorological data at progressively higher
frequencies may be employed to resolve
shorter term concentration fluctuations and
wind conditions that could introduce
interfering emissions from other sources.
2.2.3 This passive sampling method
provides a low cost approach to screening of
fugitive or area emissions compared to active
sampling methods that are based on pumped
sorbent tubes or time weighted average
canister sampling.
2.2.3.1 Additional passive sampling tubes
may be deployed at different distances from
the facility property boundary or from the
geometric center of the fugitive emission
source.
2.2.3.2 Additional meteorological
measurements may also be collected as
needed to perform preliminary gradientbased assessment of the extent of the
pollution plume at ground level and the
effect of ‘‘background’’ sources contributing
to airborne VOC concentrations at the
location.
2.2.4 Time-resolved concentration
measurements coupled with time-resolved
meteorological monitoring may be used to
generate data needed for source
apportionment procedures and mass flux
calculations.
3.0 Definitions
(See also Section 3.0 of Method 325B.)
3.1 Fenceline means the property
boundary of a facility or internal monitoring
perimeter established in accordance with the
requirements in Section 8.2 of this method.
3.2 Passive sampler (PS) means a specific
type of sorbent tube (defined in this method)
that has a fixed dimension air (diffusion) gap
at the sampling end and is sealed at the other
end.
3.3 Passive sampling refers to the activity
of quantitatively collecting VOC on sorbent
tubes using the process of diffusion.
3.4 PSi is the annual average for all PS
concentration results from location i.
3.5 PSi3 is the set of annual average
concentration results for PSi and two sorbent
tubes nearest to the PS location i.
3.6 PSip is the concentration from the
sorbent tube at location i for the test period
or episode p.
3.7 Sampling period is the length of time
each passive sampler is exposed during field
monitoring. The sampling period for this
method is 14 days.
3.8 Sorbent tube (Also referred to as tube,
PS tube, adsorbent tube, and sampling tube)
is an inert coated stainless steel tube.
Standard PS tube dimensions for this method
E:\FR\FM\01DER2.SGM
01DER2
75326
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
are 3.5-inch (89 mm) long × 0.25-inch (6.4
mm) o.d. with an i.d. of 5 mm, a crosssectional area of 19.6 mm2 and an air gap of
15 mm. The central portion of the tube is
packed with solid adsorbent material
contained between 2 × 100-mesh stainless
steel gauzes and terminated with a diffusion
cap at the sampling end of the tube. These
axial passive samplers are installed under a
protective hood during field deployment.
Note: Glass and glass- (or fused silica-)
lined stainless steel sorbent tubes (typically
4 mm i.d.) are also available in various
lengths to suit different makes of thermal
desorption equipment, but these are rarely
used for passive sampling because it is more
difficult to adequately define the diffusive air
gap in glass or glass-line tubing. Such tubes
are not recommended for this method.
4.0
Sampling Interferences
4.1 General Interferences
Passive tube samplers should be sited at a
distance beyond the influence of possible
obstructions such as trees, walls, or buildings
at the monitoring site. Complex topography
and physical site obstructions, such as bodies
of water, hills, buildings, and other structures
that may prevent access to a planned PS
location must be taken into consideration.
You must document and report siting
interference with the results of this method.
4.2 Background Interference
Nearby or upwind sources of target
emissions outside the facility being tested
can contribute to background concentrations.
Moreover, because passive samplers measure
continuously, changes in wind direction can
cause variation in the level of background
concentrations from interfering sources
during the monitoring period. This is why
local meteorological information, particularly
wind direction and speed, is required to be
collected throughout the monitoring period.
Interfering sources can include neighboring
industrial facilities, transportation facilities,
fueling operations, combustion sources,
short-term transient sources, residential
sources, and nearby highways or roads. As
PS data are evaluated, the location of
potential interferences with respect to PS
locations and local wind conditions should
be considered, especially when high PS
concentration values are observed.
tkelley on DSK3SPTVN1PROD with RULES2
4.3 Tube Handling
You must protect the PS tubes from gross
external contamination during field
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
sampling. Analytical thermal desorption
equipment used to analyze PS tubes must
desorb organic compounds from the interior
of PS tubes and exclude contamination from
external sampler surfaces in the analytical/
sample flow path. If the analytical equipment
does not comply with this requirement, you
must wear clean, white, cotton or powderfree nitrile gloves to handle sampling tubes
to prevent contamination of the external
sampler surfaces. Sampling tubes must be
capped with two-piece, brass, 0.25 inch,
long-term storage caps fitted with combined
polytetrafluoroethylene ferrules (see Section
6.1 and Method 325B) to prevent ingress of
airborne contaminants outside the sampling
period. When not being used for field
monitoring, the capped tubes must be stored
in a clean, air-tight, shipping container to
prevent the collection of VOCs (see Section
6.4.2 of Method 325B).
4.4 Local Weather Conditions and
Airborne Particulates
Although air speeds are a constraint for
many forms of passive samplers, axial tube
PS devices have such a slow inherent uptake
rate that they are largely immune to these
effects (References 4,5). Passive samplers
must nevertheless be deployed under nonemitting weatherproof hoods to moderate the
effect of local weather conditions such as
solar heating and rain. The cover must not
impede the ingress of ambient air. Sampling
tubes should also be orientated vertically and
pointing downwards, to minimize
accumulation of particulates.
4.5 Temperature
The normal working range for field
sampling for sorbent packing is 0–40 °C
(References 6,7). Note that most published
passive uptake rate data for sorbent tubes is
quoted at 20 °C. Note also that, as a rough
guide, an increase in temperature of 10 °C
will reduce the collection capacity for a given
analyte on a given sorbent packing by a factor
of 2, but the uptake rate will not change
significantly (Reference 4).
5.0 Safety
This method does not purport to include
all safety issues or procedures needed when
deploying or collecting passive sampling
tubes. Precautions typical of field air
sampling projects are required. Tripping,
falling, electrical, and weather safety
considerations must all be included in plans
to deploy and collect passive sampling tubes.
PO 00000
Frm 00150
Fmt 4701
Sfmt 4700
6.0 Sampling Equipment and Supplies, and
Pre-Deployment Planning
This section describes the equipment and
supplies needed to deploy passive sampling
monitoring equipment at a facility property
boundary. Details of the passive sampling
tubes themselves and equipment required for
subsequent analysis are described in Method
325B.
6.1
Passive Sampling Tubes
The industry standard PS tubes used in
this method must meet the specific
configuration and preparation requirements
described in Section 3.0 of this method and
Section 6.1 of Method 325B.
Note: The use of PS tubes packed with
various sorbent materials for monitoring a
wide variety of organic compounds in
ambient air has been documented in the
literature (References 4–10). Other sorbents
may be used in standard passive sampling
tubes for monitoring additional target
compound(s) once their uptake rate and
performance has been demonstrated
following procedures in Addendum A to
Method 325B. Guidance on sorbent selection
can also be obtained from relevant national
and international standard methods such as
ASTM D6196–03 (Reapproved 2009)
(Reference 14) and ISO 16017–2:2003(E)
(Reference 13) (both incorporated by
reference—see § 63.14).
6.2
Passive or Diffusive Sampling Cap
One diffusive sampling cap is required per
PS tube. The cap fits onto the sampling end
of the tube during air monitoring. The other
end of the tube remains sealed with the longterm storage cap. Each diffusive sampling cap
is fitted with a stainless steel gauze, which
defines the outer limit of the diffusion air
gap.
6.3
Sorbent Tube Protection Cover
A simple weatherproof hood, suitable for
protecting passive sampling tubes from the
worst of the weather (see Section 4.4)
consists of an inverted cone/funnel
constructed of an inert, non-outgassing
material that fits over the diffusive tube, with
the open (sampling) end of the tube
projecting just below the cone opening. An
example is shown in Figure 6.1 (Adapted
from Reference 13).
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Thermal Desorption Apparatus
If the analytical thermal desorber that will
subsequently be used to analyze the passive
sampling tubes does not meet the
requirement to exclude outer surface
contaminants from the sample flow path (see
Section 6.6 of Method 325B), then clean,
white, cotton or powder-free nitrile gloves
must be used for handling the passive
sampling tubes during field deployment.
6.5
Sorbent Selection
Sorbent tube configurations, sorbents or
other VOC not listed in this method must be
evaluated according to Method 325B,
Addendum A or ISO 16017–2:2003(E)
(Reference 13) (incorporated by reference—
see § 63.14). The supporting evaluation and
verification data described in Method 325B,
Addendum A for configurations or
compounds different from the ones described
in this method must meet the performance
requirements of Method 325A/B and must be
submitted with the test plan for your
measurement program.
7.0
Reagents and Standards
No reagents or standards are needed for the
field deployment and collection of passive
sampling tubes. Specifications for sorbents,
gas and liquid phase standards, preloaded
standard tubes, and carrier gases are covered
in Section 7 of Method 325B.
tkelley on DSK3SPTVN1PROD with RULES2
8.0 Sample Deployment, Recovery, and
Storage
Pre-deployment and planning steps are
required before field deployment of passive
sampling tubes. These activities include but
are not limited to conducting a site visit,
determining suitable and required
monitoring locations, and determining the
monitoring frequency to be used.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
8.1 Conducting the Site Visit
8.1.1 Determine the size and shape of the
facility footprint in order to determine the
required number of monitoring locations.
8.1.2 Identify obstacles or obstructions
(buildings, roads, fences), hills and other
terrain issues (e.g., bodies of water or swamp
land) that could interfere with air parcel flow
to the sampler or that prevent reasonable
access to the location. You may use the
general guidance in Section 4.1 of this
method during the site visit to identify
sampling locations. You must evaluate the
placement of each passive sampler to
determine if the conditions in this section are
met.
8.1.3 Identify to the extent possible and
record potential off-site source interferences
(e.g., neighboring industrial facilities,
transportation facilities, fueling operations,
combustion sources, short-term transient
sources, residential sources, nearby
highways).
8.1.4 Identify the closest available
meteorological station. Identify potential
locations for one or more on-site or near-site
meteorological station(s) following the
guidance in EPA–454/B–08–002 (Reference
11) (incorporated by reference—see § 63.14).
8.2 Determining Sampling Locations
(References 2, 3)
8.2.1 The number and placement of the
passive samplers depends on the size, the
shape of the facility footprint or the linear
distance around the facility, and the
proximity of emission sources near the
property boundaries. Aerial photographs or
site maps may be used to determine the size
(acreage) and shape of the facility or the
length of the monitoring perimeter. Place
passive samplers on an internal monitoring
perimeter on or inside the facility boundary
encompassing all emission sources at the
facility at different angles circling the
PO 00000
Frm 00151
Fmt 4701
Sfmt 4700
geometric center of the facility or at different
distances based on the monitoring perimeter
length of the facility.
Note: In some instances, permanent air
monitoring stations may already be located in
close proximity to the facility. These stations
may be operated and maintained by the site,
or local or state regulatory agencies. If access
to the station is possible, a PS may be
deployed adjacent to other air monitoring
instrumentation. A comparison of the
pollutant concentrations measured with the
PS to concentrations measured by site
instrumentation may be used as an optional
data quality indicator to assess the accuracy
of PS results.
8.2.1.1 The monitoring perimeter may be
located between the property boundary and
any potential emission source near the
property boundary, as long as the distance
from the source to the monitoring perimeter
is at least 50 meters (162 feet). If a potential
emissions source is within 50 meters (162
feet) of the property boundary, the property
boundary shall be used as the monitoring
perimeter near that source.
8.2.1.2 Samplers need only be placed
around the monitoring perimeter and not
along internal roads or other right of ways
that may bisect the facility.
8.2.1.3 Extra samplers must be placed
near known sources of VOCs if the potential
emission source is within 50 meters (162
feet) of the boundary and the source location
is between two monitors. Measure the
distance (x) between the two monitors and
place another monitor halfway between (x/2)
the two monitors. For example, in Figure 8.1,
the facility added three additional monitors
(i.e., light shaded sampler locations) and in
Figure 8.2, the facility added two additional
monitors to provide sufficient coverage of all
area sources.
BILLING CODE 6560–50–P
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.025
6.4
75327
75328
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
~
0
:!::
c
0
E
ro
c
0
:-e
"'0
"'0
<(
Refinery (20% Angle)
Note: Shaded sources are within 50 meters of the property boundary
and are located between two monitors. Additional coverage required
by this method was accomplished by placing the monitors halfway
between two existing monitors.
Figure 8.1. Facility with a Regular Shape Between 750 and 1,500
Acres in Area
(f)
(f)
(f)
(f)
(f)
Refinery (24,000 Feet Perimeter)
Figure 8.2. Facility with a Boundary Length of 24,000 feet
8.2.2 Option 1 for Determining Sampling
Locations.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
8.2.2.1 For facilities with a regular
(circular, triangular, rectangular, or square)
PO 00000
Frm 00152
Fmt 4701
Sfmt 4700
shape, determine the geographic center of the
facility.
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.026
tkelley on DSK3SPTVN1PROD with RULES2
Note: Shaded sources are within 50 meters of the property boundary
and are located between two monitors. Additional coverqe required
by this method was accomplished by placing the monitors halfway
between two existing monitors.
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75329
determine sampling locations. The subareas
must be defined such that a circle can
reasonably encompass the subarea. Then
determine the geometric center point of each
of the subareas.
8.2.2.2.1 If a subarea is less than or equal
to 750 acres (e.g., Figure 8.3), measure angles
of 30 degrees from the center point for a total
of twelve 30 degree measurements (±1
degree).
center for a total of twenty-four 15 degree
measurements (±1 degree).
8.2.2.2.4 Locate each sampling point
where the measured angle intersects the
outer monitoring perimeter. Sampling points
need not be placed closer than 152 meters
(500 feet) apart (or 76 meters (250 feet) if
known sources are within 50 meters (162
feet) of the monitoring perimeter), as long as
a minimum of 3 monitoring locations are
used for each subarea.
8.2.2.2.5 Sampling sites are not needed at
the intersection of an inner boundary with an
adjacent subarea. The sampling location must
be sited where the measured angle intersects
the subarea’s outer monitoring perimeter.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00153
Fmt 4701
Sfmt 4700
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.027
acres. Monitor placements are represented
with black dots along the property boundary.
8.2.2.1.3 For facilities covering an area
greater than 1,500 acres, measure angles of 15
degrees from the center point for a total of
twenty-four 15 degree measurements evenly
spaced (±1 degree).
8.2.2.1.4 Locate each sampling point
where the measured angle intersects the
outer monitoring perimeter.
8.2.2.2 For irregularly shaped facilities,
divide the area into a set of connecting
subarea circles, triangles or rectangles to
8.2.2.2.2 If a subarea is greater than 750
acres but less than or equal to 1,500 acres
(e.g., Figure 8.4), measure angles of 20
degrees from the center point for a total of
eighteen 20 degree measurements (±1
degree).
8.2.2.2.3 If a subarea is greater than 1,500
acres, measure angles of 15 degrees from the
tkelley on DSK3SPTVN1PROD with RULES2
8.2.2.1.1 For facilities with an area of less
than or equal to 750 acres, measure angles of
30 degrees from the center point for a total
of twelve 30 degree measurements evenly
spaced (±1 degree).
8.2.2.1.2 For facilities covering an area
greater than 750 acres but less than or equal
to 1,500 acres, measure angles of 20 degrees
from the center point for a total of eighteen
20 degree measurements evenly spaced (±1
degree). Figure 8.1 shows the monitor
placement around the property boundary of
a facility with an area between 750 and 1,500
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with RULES2
8.2.3 Option 2 for Determining Sampling
Locations.
8.2.3.1 For facilities with a monitoring
perimeter length of less than 7,315 meters
(24,000 feet), a minimum of twelve sampling
locations evenly spaced ±10 percent of the
location interval is required.
8.2.3.2 For facilities with a monitoring
perimeter length greater than 7,315 meters
(24,000 feet), sampling locations are spaced
610 ±76 meters (2,000 ± 250 feet) apart.
8.3 Siting a Meteorological Station
A meteorological station is required at or
near the facility you are monitoring. A
number of commercially available
meteorological stations can be used.
Information on meteorological instruments
can be found in EPA–454/R–99–005
(Reference 11) (incorporated by reference—
see § 63.14). Some important considerations
for siting of meteorological stations are
detailed below.
8.3.1 Place meteorological stations in
locations that represent conditions affecting
the transport and dispersion of pollutants in
the area of interest. Complex terrain may
require the use of more than one
meteorological station.
8.3.2 Deploy wind instruments over level,
open terrain at a height of 10 meters (33 feet).
If possible, locate wind instruments at a
distance away from nearby structures that is
equal to at least 10 times the height of the
structure.
8.3.3 Protect meteorological instruments
from thermal radiation and adequately
ventilate them using aspirated shields. The
temperature sensor must be located at a
distance away from any nearby structures
that is equal to at least four times the height
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
of the structure. Temperature sensors must be
located at least 30 meters (98 feet) from large
paved areas.
8.3.4 Collect and record meteorological
data, including wind speed, wind direction,
temperature and barometric pressure on an
hourly basis. Calculate average unit vector
wind direction, sigma theta, temperature and
barometric pressure per sampling period to
enable calculation of concentrations at
standard conditions. Supply this information
to the laboratory.
8.3.5 Identify and record the location of
the meteorological station by its GPS
coordinate.
8.4 Monitoring Frequency
8.4.1 Sample collection may be
performed for periods up to 14 days.
8.4.2 A site screening protocol that meets
method requirements may be performed by
collecting samples for a year where each PS
accumulates VOC for a 14-day sampling
period. Study results are accumulated for the
sampling periods (typically 26) over the
course of one calendar year. To the extent
practical, sampling tubes should be changed
at approximately the same time of day at
each of the monitoring sites.
8.5 Passive Sampler Deployment
8.5.1 Clean (conditioned) sorbent tubes
must be prepared and packaged by the
laboratory as described in Method 325B and
must be deployed for sampling within 30
days of conditioning.
8.5.2 Allow the tubes to equilibrate with
ambient temperature (approximately 30
minutes to 1 hour) at the monitoring location
before removing them from their storage/
shipping container for sample collection.
PO 00000
Frm 00154
Fmt 4701
Sfmt 4700
8.5.3 If there is any risk that the
analytical equipment will not meet the
requirement to exclude contamination on
outer tube surfaces from the sample flow
path (see Section 6.6 of Method 325B),
sample handlers must wear clean, white,
cotton or powder-free nitrile gloves during
PS deployment and collection and
throughout any other tube handling
operations.
8.5.4 Inspect the sampling tubes
immediately prior to deployment. Ensure
that they are intact, securely capped, and in
good condition. Any suspect tubes (e.g.,
tubes that appear to have leaked sorbent)
should be removed from the sampling set.
8.5.5 Secure passive samplers so the
bottom of the diffusive sampling cap is 1.5
to 3 meters (4.9 to 9.8 feet) above ground
using a pole or other secure structure at each
sampling location. Orient the PS vertically
and with the sampling end pointing
downward to avoid ingress of particulates.
Note: Duplicate sampling assemblies must
be deployed in at least one monitoring
location for every 10 monitoring locations
during each field monitoring period.
8.5.6 Protect the PS from rain and
excessive wind velocity by placing them
under the type of protective hood described
in Section 6.1.3 or equivalent.
8.5.7 Remove the storage cap on the
sampling end of the tube and replace it with
a diffusive sampling cap at the start of the
sampling period. Make sure the diffusion cap
is properly seated and store the removed
storage caps in the empty tube shipping
container.
8.5.8 Record the start time and location
details for each sampler on the field sample
data sheet (see example in Section 17.0.).
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.028
75330
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
8.6 Sorbent Tube Recovery and
Meteorological Data Collection
Recover deployed sampling tubes and field
blanks as follows:
8.6.1 After the sampling period is
complete, immediately replace the diffusion
end cap on each sampled tube with a longterm storage end cap. Tighten the seal
securely by hand and then tighten an
additional quarter turn with an appropriate
tool. Record the stop date and time and any
additional relevant information on the
sample data sheet.
8.6.2 Place the sampled tubes, together
with the field blanks, in the storage/shipping
container. Label the storage container, but do
not use paints, markers, or adhesive labels to
identify the tubes. TD-compatible electronic
(radio frequency identification (RFID)) tube
labels are available commercially and are
compatible with some brands of thermal
desorber. If used, these may be programmed
with relevant tube and sample information,
which can be read and automatically
transcribed into the sequence report by the
TD system.
Note: Sampled tubes must not be placed in
the same shipping container as clean
conditioned sampling tubes.
8.6.3 Sampled tubes may be shipped at
ambient temperature to a laboratory for
sample analysis.
8.6.4 Specify whether the tubes are field
blanks or were used for sampling and
document relevant information for each tube
using a Chain of Custody form (see example
in Section 17.0) that accompanies the
samples from preparation of the tubes
through receipt for analysis, including the
tkelley on DSK3SPTVN1PROD with RULES2
Where:
PSi = Annual average for location i.
PSip = Sampling period specific
concentration from Method 325B.
i = Location of passive sampler (0 to 360°).
p = The sampling period.
N = The number of sampling periods in the
year (e.g., for 14-day sampling periods,
from 1 to 26).
Note: PSip is a function of sampling
location-specific factors such as the
contribution from facility sources, unusual
localized meteorological conditions,
contribution from nearby interfering sources,
the background caused by integrated far-field
sources and measurement error due to
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
following information: Unique tube
identification numbers for each sampled
tube; the date, time, and location code for
each PS placement; the date, time, and
location code for each PS recovery; the GPS
reference for each sampling location; the
unique identification number of the
duplicate sample (if applicable); and
problems or anomalies encountered.
8.6.5 If the sorbent tubes are supplied
with electronic (e.g., RFID) tags, it is also
possible to allocate a sample identifier to
each PS tube. In this case, the recommended
format for the identification number of each
sampled tube is AA–BB–CC–DD–VOC,
where:
AA = Sequence number of placement on
route (01, 02, 03 . . .)
BB = Sampling location code (01, 02,
03 . . .)
CC = 14-day sample period number (01 to 26)
DD = Sample code (SA = sample, DU =
duplicate, FB = field blank)
VOC = 3-letter code for target compound(s)
(e.g., BNZ for benzene or BTX for
benzene, toluene, and xylenes)
Note: Sampling start and end times/dates
can also be logged using RFID tube tags.
9.0 Quality Control
9.1 Most quality control checks are
carried out by the laboratory and associated
requirements are in Section 9.0 of Method
325B, including requirements for laboratory
blanks, field blanks, and duplicate samples.
9.2 Evaluate for potential outliers the
laboratory results for neighboring sampling
tubes collected over the same time period. A
potential outlier is a result for which one or
more PS tube does not agree with the trend
in results shown by neighboring PS tubes—
particularly when data from those locations
have been more consistent during previous
sampling periods. Accidental contamination
by the sample handler must be documented
before any result can be eliminated as an
outlier. Rare but possible examples of
contamination include loose or missing
storage caps or contaminated storage/
shipping containers. Review data from the
same and neighboring monitoring locations
deployment, handling, siting, or analytical
errors.
12.2 Identify Sampling Locations of
Interest
If data from neighboring sampling
locations are significantly different, then you
may add extra sampling points to isolate
background contributions or identify facilityspecific ‘‘hot spots.’’
12.3
Evaluate Trends
You may evaluate trends and patterns in
the PS data over multiple sampling periods
to determine if elevated concentrations of
target compounds are due to operations on
PO 00000
Frm 00155
Fmt 4701
Sfmt 4700
for the subsequent sampling periods. If the
anomalous result is not repeated for that
monitoring location, the episode can be
ascribed to transient contamination and the
data in question must be flagged for potential
elimination from the dataset.
9.3
Duplicates and Field Blanks
9.3.1 Collect at least one co-located/
duplicate sample for every 10 field samples
to determine precision of the measurements.
9.3.2 Collect at least two field blanks
sorbent samples per sampling period to
ensure sample integrity associated with
shipment, collection, and storage. You must
use the entire sampling apparatus for field
blanks including unopened sorbent tubes
mounted in protective sampling hoods. The
tube closures must not be removed. Field
blanks must be placed in two different
quadrants (e.g., 90° and 270°) and remain at
the sampling location for the sampling
period.
10.0
Calibration and Standardization
Follow the calibration and standardization
procedures for meteorological measurements
in EPA–454/B–08–002 March 2008
(Reference 11) (incorporated by reference—
see § 63.14). Refer to Method 325B for
calibration and standardization procedures
for analysis of the passive sampling tubes.
11.0
Analytical Procedures
Refer to Method 325B, which provides
details for the preparation and analysis of
sampled passive monitoring tubes
(preparation of sampling tubes, shipment and
storage of exposed sampling tubes, and
analysis of sampling tubes).
12.0 Data Analysis, Calculations and
Documentation
12.1 Calculate Annual Average Fenceline
Concentration.
After a year’s worth of sampling at the
facility fenceline (for example, 26 14-day
samples), the average (PSi) may be calculated
for any specified period at each PS location
using Equation 12.1.
the facility or if contributions from
background sources are significant.
12.3.1 Obtain meteorological data
including wind speed and wind direction or
unit vector wind data from the on-site
meteorological station. Use this
meteorological data to determine the
prevailing wind direction and speed during
the periods of elevated concentrations.
12.3.2 As an option you may perform
preliminary back trajectory calculations
(https://ready.arl.noaa.gov/HYSPLIT.php) to
aid in identifying the source of the
background contribution to elevated target
compound concentrations.
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.029
8.5.9 Expose the sampling tubes for the
required sampling period-normally 14-days.
8.5.10 Field blank tubes (see Section 9.3
of Method 325B) are stored outside the
shipping container at representative
sampling locations around the site, but with
both long-term storage caps kept in place
throughout the monitoring exercise. Collect
at least two field blanks sorbent samples per
sampling period to ensure sample integrity
associated with shipment, collection, and
storage.
75331
75332
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
12.3.3 Information on published or
documented events on- and off-site may also
be included in the associated sampling
period report to explain elevated
concentrations if relevant. For example, you
would describe if there was a chemical spill
on site, or an accident on an adjacent road.
12.3.4 Additional monitoring for shorter
periods (See section 8.4) may be necessary to
allow better discrimination/resolution of
contributing emission sources if the
measured trends and associated meteorology
do not provide a clear assessment of facility
contribution to the measured fenceline
concentration.
12.3.5 Additional records necessary to
calculate sampling period average target
compound concentration can be found in
Section 12.1 of Method 325B.
13.0 Method Performance
Method performance requirements are
described in Method 325B.
14.0 Pollution Prevention
[Reserved]
15.0 Waste Management
[Reserved]
tkelley on DSK3SPTVN1PROD with RULES2
16.0 References
1. Ambient air quality—Standard method for
measurement of benzene
concentrations—Part 4: Diffusive
sampling followed by thermal desorption
and gas chromatography, BS EN 14662–
4:2005.
2. Thoma, E.D., Miller, C.M., Chung, K.C.,
Parsons, N.L. and Shine, B.C. Facility
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Fence Line Monitoring using Passive
Samplers, J. Air & Waste Mange. Assoc.
2011, 61:834–842.
3. Quality Assurance Handbook for Air
Pollution C Systems, Volume II: Ambient
Air Quality Monitoring Program, EPA–
454/B–13–003, May 2013. Available at
https://www.epa.gov/ttnamti1/files/
ambient/pm25/qa/QA-Handbook-VolII.pdf.
4. Brown, R.H., Charlton, J. and Saunders,
K.J.: The development of an improved
diffusive sampler. Am. Ind. Hyg. Assoc.
J. 1981, 42(12): 865–869.
5. Brown, R. H. Environmental use of
diffusive samplers: evaluation of reliable
diffusive uptake rates for benzene,
toluene and xylene. J. Environ. Monit.
1999, 1 (1), 115–116.
6. Ballach, J.; Greuter, B.; Schultz, E.;
Jaeschke, W. Variations of uptake rates in
benzene diffusive sampling as a function
of ambient conditions. Sci. Total
Environ. 1999, 244, 203–217.
7. Brown, R. H. Monitoring the ambient
environment with diffusive samplers:
theory and practical considerations. J
Environ. Monit. 2000, 2 (1), 1–9.
8. Buzica, D.; Gerboles, M.; Plaisance, H. The
equivalence of diffusive samplers to
reference methods for monitoring O3,
benzene and NO2 in ambient air. J.
Environ. Monit. 2008, 10 (9), 1052–1059.
9. Woolfenden, E. Sorbent-based sampling
methods for volatile and semi-volatile
organic compounds in air. Part 2.
Sorbent selection and other aspects of
optimizing air monitoring methods. J.
PO 00000
Frm 00156
Fmt 4701
Sfmt 4700
Chromatogr. A 2010, 1217, (16), 2685–
94.
10. Pfeffer, H. U.; Breuer, L. BTX
measurements with diffusive samplers in
the vicinity of a cokery: Comparison
between ORSA-type samplers and
pumped sampling. J. Environ. Monit.
2000, 2 (5), 483–486.
11. US EPA. 2000. Meteorological Monitoring
Guidance for Regulatory Modeling
Applications. EPA–454/R–99–005. Office
of Air Quality Planning and Standards,
Research Triangle Park, NC. February
2000. Available at https://www.epa.gov/
scram001/guidance/met/mmgrma.pdf.
12. Quality Assurance Handbook for Air
Pollution Measurement Systems. Volume
IV: Meteorological Measurements
Version 2.0 Final, EPA–454/B–08–002
March 2008. Available at https://www.
epa.gov/ttnamti1/files/ambient/met/
Volume%20IV_Meteorological_
Measurements.pdf.
13. ISO 16017–2:2003(E), Indoor, ambient
and workplace air—Sampling and
analysis of volatile organic compounds
by sorbent tube/thermal desorption/
capillary gas chromatography. Part 2:
Diffusive sampling.
14. ASTM D6196–03 (Reapproved 2009):
Standard practice for selection of
sorbents, sampling, and thermal
desorption analysis procedures for
volatile organic compounds in air.
17.0 Tables, Diagrams, Flowcharts and
Validation Data
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
75333
Method 325 A/B
EXAMPLE FIELD TEST DATA SHEET (FTDS)
AND
CHAIN OF CUSTODY
I. GENERAL INFORMATION
SITE NAME:
SITE LOCATION ADDRESS:
CITY:
STATE:
ZIP:
II. SAMPLING DATA
Sample
ID
(Tube)
#
Sorbent
Sample
or
blank
Start
Date
Start
Time
Stop
Date
Stop
Time
Location
(gps)
Ambient
Temp.
(oF)
Barometric
Pressure
(in. Hg)
III. CUSTODY INFORMATION
COLLECTED BY:
Relinquished to Shipper Name:
Date:
Received by Laboratory Date:
Name
Sample condition upon receipt:
Time
Time
Analysis Required:
Figure 17.1. Example Field Data Form and Chain of Custody
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
PO 00000
Frm 00157
Fmt 4701
Sfmt 4725
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.030
tkelley on DSK3SPTVN1PROD with RULES2
Comments:
75334
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Method 325B—Volatile Organic Compounds
from Fugitive and Area Sources:
tkelley on DSK3SPTVN1PROD with RULES2
Sampler Preparation and Analysis
1.0 Scope and Application
1.1 This method describes thermal
desorption/gas chromatography (TD/GC)
analysis of volatile organic compounds
(VOCs) from fugitive and area emission
sources collected onto sorbent tubes using
passive sampling. It could also be applied to
the TD/GC analysis of VOCs collected using
active (pumped) sampling onto sorbent tubes.
The concentration of airborne VOCs at or
near potential fugitive- or area-emission
sources may be determined using this
method in combination with Method 325A.
Companion Method 325A (Sampler
Deployment and VOC Sample Collection)
describes procedures for deploying the
sorbent tubes and passively collecting VOCs.
1.2 The preferred GC detector for this
method is a mass spectrometer (MS), but
flame ionization detectors (FID) may also be
used. Other conventional GC detectors such
as electron capture (ECD), photoionization
(PID), or flame photometric (FPD) may also
be used if they are selective and sensitive to
the target compound(s) and if they meet the
method performance criteria provided in this
method.
1.3 There are 97 VOCs listed as
hazardous air pollutants in Title III of the
Clean Air Act Amendments of 1990. Many of
these VOC are candidate compounds for this
method. Compounds with known uptake
rates for CarbographTM 1 TD, CarbopackTM B,
or CarbopackTM X are listed in Table 12.1.
This method provides performance criteria to
demonstrate acceptable performance of the
method (or modifications of the method) for
monitoring one or more of the compounds
listed Table 12.1. If standard passive
sampling tubes are packed with other
sorbents or used for other analytes than those
listed in Table 12.1, then method
performance and relevant uptake rates
should be verified according to Addendum A
to this method or by one of the following
national/international standard methods: ISO
16017–2:2003(E), ASTM D6196–03
(Reapproved 2009), or BS EN 14662–4:2005
(all incorporated by reference—see § 63.14),
or reported in the peer-reviewed open
literature.
1.4 The analytical approach using TD/
GC/MS is based on previously published
EPA guidance in Compendium Method TO–
17 (https://www.epa.gov/ttnamti1/airtox.
html#compendium) (Reference 1), which
describes active (pumped) sampling of VOCs
from ambient air onto tubes packed with
thermally stable adsorbents.
1.5 Inorganic gases not suitable for
analysis by this method include oxides of
carbon, nitrogen and sulfur, ozone (O3), and
other diatomic permanent gases. Other
pollutants not suitable for this analysis
method include particulate pollutants, (i.e.,
fumes, aerosols, and dusts), compounds too
labile (reactive) for conventional GC analysis,
and VOCs that are more volatile than
propane.
2.0 Summary of Method
2.1 This method provides procedures for
the preparation, conditioning, blanking, and
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
shipping of sorbent tubes prior to sample
collection.
2.2 Laboratory and field personnel must
have experience of sampling trace-level
VOCs using sorbent tubes (References 2,5)
and must have experience operating thermal
desorption/GC/multi-detector
instrumentation.
2.3 Key steps of this method as
implemented for each sample tube include:
Stringent leak testing under stop flow,
recording ambient temperature conditions,
adding internal standards, purging the tube,
thermally desorbing the sampling tube,
refocusing on a focusing trap, desorbing and
transferring/injecting the VOCs from the
secondary trap into the capillary GC column
for separation and analysis.
2.4 Water management steps incorporated
into this method include: (a) Selection of
hydrophobic sorbents in the sampling tube;
(b) optional dry purging of sample tubes prior
to analysis; and (c) additional selective
elimination of water during primary (tube)
desorption (if required) by selecting trapping
sorbents and temperatures such that target
compounds are quantitatively retained while
water is purged to vent.
3.0 Definitions
(See also Section 3.0 of Method 325A).
3.1 Blanking is the desorption and
confirmatory analysis of conditioned sorbent
tubes before they are sent for field sampling.
3.2 Breakthrough volume and associated
relation to passive sampling. Breakthrough
volumes, as applied to active sorbent tube
sampling, equate to the volume of air
containing a constant concentration of
analyte that may be passed through a sorbent
tube at a given temperature before a
detectable level (5 percent) of the input
analyte concentration elutes from the tube.
Although breakthrough volumes are directly
related to active rather than passive
sampling, they provide a measure of the
strength of the sorbent-sorbate interaction
and therefore also relate to the efficiency of
the passive sampling process. The best direct
measure of passive sampling efficiency is the
stability of the uptake rate. Quantitative
passive sampling is compromised when the
sorbent no longer acts as a perfect sink—i.e.,
when the concentration of a target analyte
immediately above the sorbent sampling
surface no longer approximates to zero. This
causes a reduction in the uptake rate over
time. If the uptake rate for a given analyte on
a given sorbent tube remains relatively
constant —i.e., if the uptake rate determined
for 48 hours is similar to that determined for
7 or 14 days—the user can be confident that
passive sampling is occurring at a constant
rate. As a general rule of thumb, such ideal
passive sampling conditions typically exist
for analyte:sorbent combinations where the
breakthrough volume exceeds 100 L
(Reference 4).
3.3 Continuing calibration verification
sample (CCV). Single level calibration
samples run periodically to confirm that the
analytical system continues to generate
sample results within acceptable agreement
to the current calibration curve.
3.4 Focusing trap is a cooled, secondary
sorbent trap integrated into the analytical
PO 00000
Frm 00158
Fmt 4701
Sfmt 4700
thermal desorber. It typically has a smaller
i.d. and lower thermal mass than the original
sample tube allowing it to effectively refocus
desorbed analytes and then heat rapidly to
ensure efficient transfer/injection into the
capillary GC analytical column.
3.5 High Resolution Capillary Column
Chromatography uses fused silica capillary
columns with an inner diameter of 320 mm
or less and with a stationary phase film
thickness of 5 mm or less.
3.6 h is time in hours.
3.7 i.d. is inner diameter.
3.8 min is time in minutes.
3.9 Method Detection Limit is the lowest
level of analyte that can be detected in the
sample matrix with 99% confidence.
3.10 MS–SCAN is the mode of operation
of a GC quadrupole mass spectrometer
detector that measures all ions over a given
mass range over a given period of time.
3.11 MS–SIM is the mode of operation of
a GC quadrupole mass spectrometer detector
that measures only a single ion or a selected
number of discrete ions for each analyte.
3.12 o.d. is outer diameter.
3.13 ppbv is parts per billion by volume.
3.14 Thermal desorption is the use of
heat and a flow of inert (carrier) gas to extract
volatiles from a solid matrix. No solvent is
required.
3.15 Total ion chromatogram is the
chromatogram produced from a mass
spectrometer detector collecting full spectral
information.
3.16 Two-stage thermal desorption is the
process of thermally desorbing analytes from
a sorbent tube, reconcentrating them on a
focusing trap (see Section 3.4), which is then
itself rapidly heated to ‘‘inject’’ the
concentrated compounds into the GC
analyzer.
3.17 VOC is volatile organic compound.
4.0 Analytical Interferences
4.1 Interference from Sorbent Artifacts.
Artifacts may include target analytes as well
as other VOC that co-elute
chromatographically with the compounds of
interest or otherwise interfere with the
identification or quantitation of target
analytes.
4.1.1 Sorbent decomposition artifacts are
VOCs that form when sorbents degenerate,
e.g., when exposed to reactive species during
sampling. For example, benzaldehyde,
phenol, and acetophenone artifacts are
reported to be formed via oxidation of the
polymeric sorbent Tenax® when sampling
high concentration (100–500 ppb) ozone
atmospheres (Reference 5).
4.1.2 Preparation and storage artifacts are
VOCs that were not completely cleaned from
the sorbent tube during conditioning or that
are an inherent feature of that sorbent at a
given temperature.
4.2 Humidity. Moisture captured during
sampling can interfere with VOC analysis.
Passive sampling using tubes packed with
hydrophobic sorbents, like those described in
this method, minimizes water retention.
However, if water interference is found to be
an issue under extreme conditions, one or
more of the water management steps
described in Section 2.4 can be applied.
4.3 Contamination from Sample
Handling. The type of analytical thermal
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
6.0 Equipment and Supplies
6.1 Tube Dimensions and Materials. The
sampling tubes for this method are 3.5-inches
(89 mm) long, 1⁄4 inch (6.4 mm) o.d., and 5
6.2 Tube Conditioning Apparatus
6.2.1 Freshly packed or newly purchased
tubes must be conditioned as described in
Section 9 using an appropriate dedicated
tube conditioning unit or the thermal
desorber. Note that the analytical TD system
should be used for tube conditioning if it
supports a dedicated tube conditioning mode
in which effluent from contaminated tubes is
directed to vent without passing through key
parts of the sample flow path such as the
focusing trap.
6.2.2 Dedicated tube conditioning units
must be leak-tight to prevent air ingress,
allow precise and reproducible temperature
selection (±5 °C), offer a temperature range at
least as great as that of the thermal desorber,
and support inert gas flows in the range up
to 100 mL/min.
Note: For safety and to avoid laboratory
contamination, effluent gases from freshly
packed or highly contaminated tubes should
be passed through a charcoal filter during the
conditioning process to prevent desorbed
VOCs from polluting the laboratory
atmosphere.
with relevant tube and sample information,
which can be read and automatically
transcribed into the sequence report by the
TD system (see Section 8.6 of Method 325A).
6.3 Tube Labeling
6.3.1 Label the sample tubes with a
unique permanent identification number and
an indication of the sampling end of the tube.
Labeling options include etching and TDcompatible electronic (radio frequency
identification (RFID)) tube labels.
6.3.2 To avoid contamination, do not
make ink markings of any kind on clean
sorbent tubes or apply adhesive labels.
Note: TD-compatible electronic (RFID) tube
labels are available commercially and are
compatible with some brands of thermal
desorber. If used, these may be programmed
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
6.4 Blank and Sampled Tube Storage
Apparatus
6.4.1 Long-term storage caps. Seal clean,
blank and sampled sorbent tubes using inert,
long-term tube storage caps comprising nongreased, 2-piece, 0.25-inch, metal
SwageLok®-type screw caps fitted with
combined polytetrafluoroethylene ferrules.
6.4.2 Storage and transportation
containers. Use clean glass jars, metal cans or
rigid, non-emitting polymer boxes.
Note: You may add a small packet of new
activated charcoal or charcoal/silica gel to
the shipping container for storage and
transportation of batches of conditioned
sorbent tubes prior to use. Coolers without
ice packs make suitable shipping boxes for
containers of tubes because the coolers help
to insulate the samples from extreme
temperatures (e.g., if left in a parked vehicle).
6.5 Unheated GC Injection Unit for Loading
Standards Onto Blank Tubes
A suitable device has a simple push fit or
finger-tightening connector for attaching the
sampling end of blank sorbent tubes without
damaging the tube. It also has a means of
controlling carrier gas flow through the
injector and attached sorbent tube at 50–100
mL/min and includes a low emission septum
cap that allows the introduction of gas or
liquid standards via appropriate syringes.
Reproducible and quantitative transfer of
higher boiling compounds in liquid
standards is facilitated if the injection unit
PO 00000
Frm 00159
Fmt 4701
Sfmt 4700
mm i.d. passive sampling tubes (see Figure
6.1). The tubes are made of inert-coated
stainless steel with the central section (up to
60 mm) packed with sorbent, typically
supported between two 100 mesh stainless
steel gauze. The tubes have a cross sectional
area of 19.6 square mm (5 mm i.d.). When
used for passive sampling, these tubes have
an internal diffusion (air) gap (DG) of 1.5 cm
between the sorbent retaining gauze at the
sampling end of the tube, and the gauze in
the diffusion cap.
allows the tip of the syringe to just touch the
sorbent retaining gauze inside the tube.
6.6 Thermal Desorption Apparatus
The manual or automated thermal
desorption system must heat sorbent tubes
while a controlled flow of inert (carrier) gas
passes through the tube and out of the
sampling end. The apparatus must also
incorporate a focusing trap to quantitatively
refocus compounds desorbed from the tube.
Secondary desorption of the focusing trap
should be fast/efficient enough to transfer the
compounds into the high resolution capillary
GC column without band broadening and
without any need for further pre- or oncolumn focusing. Typical TD focusing traps
comprise small sorbent traps (Reference 16)
that are electrically-cooled using multistage
Peltier cells (References 17, 18). The
direction of gas flow during trap desorption
should be the reverse of that used for
focusing to extend the compatible analyte
volatility range. Closed cycle coolers offer
another cryogen-free trap cooling option.
Other TD system requirements and
operational stages are described in Section 11
and in Figures 17–2 through 17–4.
6.7 Thermal Desorber—GC Interface
6.7.1 The interface between the thermal
desorber and the GC must be heated
uniformly and the connection between the
transfer line insert and the capillary GC
analytical column itself must be leak tight.
6.7.2 A portion of capillary column can
alternatively be threaded through the heated
transfer line/TD interface and connected
directly to the thermal desorber.
Note: Use of a metal syringe-type needle or
unheated length of fused silica pushed
through the septum of a conventional GC
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.031
standard to establish appropriate field and
laboratory safety and health practices prior to
use.
5.2 Laboratory analysts must exercise
extreme care in working with high-pressure
gas cylinders.
5.3 Due to the high temperatures
involved, operators must use caution when
conditioning and analyzing tubes.
5.0 Safety
5.1 This method does not address all of
the safety concerns associated with its use. It
is the responsibility of the user of this
tkelley on DSK3SPTVN1PROD with RULES2
desorption equipment selected should
exclude the possibility of outer tube surface
contamination entering the sample flow path
(see Section 6.6). If the available system does
not meet this requirement, sampling tubes
and caps must be handled only while
wearing clean, white cotton or powder free
nitrile gloves to prevent contamination with
body oils, hand lotions, perfumes, etc.
75335
75336
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
injector is not permitted as a means of
interfacing the thermal desorber to the
chromatograph. Such connections result in
cold spots, cause band broadening and are
prone to leaks.
6.8 GC/MS Analytical Components
6.8.1 The GC system must be capable of
temperature programming and operation of a
high resolution capillary column. Depending
on the choice of column (e.g., film thickness)
and the volatility of the target compounds, it
may be necessary to cool the GC oven to
subambient temperatures (e.g., ¥50 °C) at the
start of the run to allow resolution of very
volatile organic compounds.
6.8.2 All carrier gas lines supplying the
GC must be constructed from clean stainless
steel or copper tubing. Nonpolytetrafluoroethylene thread sealants. Flow
controllers, cylinder regulators, or other
pneumatic components fitted with rubber
components are not suitable.
6.9 Chromatographic Columns
High-resolution, fused silica or equivalent
capillary columns that provide adequate
separation of sample components to permit
identification and quantitation of target
compounds must be used.
Note: 100-percent methyl silicone or 5percent phenyl, 95-percent methyl silicone
fused silica capillary columns of 0.25- to
0.32-mm i.d. of varying lengths and with
varying thicknesses of stationary phase have
been used successfully for non-polar and
moderately polar compounds. However,
given the diversity of potential target lists,
GC column choice is left to the operator,
subject to the performance criteria of this
method.
6.10 Mass Spectrometer
Linear quadrupole, magnetic sector, ion
trap or time-of-flight mass spectrometers may
be used provided they meet specified
performance criteria. The mass detector must
be capable of collecting data from 35 to 300
atomic mass units (amu) every 1 second or
less, utilizing 70 volts (nominal) electron
energy in the electron ionization mode, and
producing a mass spectrum that meets all the
instrument performance acceptance criteria
in Section 9 when 50 hg or less of pbromofluorobenzene is analyzed.
tkelley on DSK3SPTVN1PROD with RULES2
7.0
Reagents and Standards
7.1 Sorbent Selection
7.1.1 Use commercially packed tubes
meeting the requirements of this method or
prepare tubes in the laboratory using sieved
sorbents of particle size in the range 20 to 80
mesh that meet the retention and quality
control requirements of this method.
7.1.2 This passive air monitoring method
can be used without the evaluation specified
in Addendum A if the type of tubes
described in Section 6.1 are packed with 4–
6 cm (typically 400–650 mg) of the sorbents
listed in Table 12.1 and used for the
respective target analytes.
Note: Although CarbopackTM X is the
optimum sorbent choice for passive sampling
of 1,3-butadiene, recovery of compounds
with vapor pressure lower than benzene may
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
be difficult to achieve without exceeding
sorbent maximum temperature limitations
(see Table 8.1). See ISO 16017–2:2003(E) or
ASTM D6196–03 (Reapproved 2009) (both
incorporated by reference—see § 63.14) for
more details on sorbent choice for air
monitoring using passive sampling tubes.
7.1.3 If standard passive sampling tubes
are packed with other sorbents or used for
analytes other than those tabulated in Section
12.0, method performance and relevant
uptake rates should be verified according to
Addendum A to this method or by following
the techniques described in one of the
following national/international standard
methods: ISO 16017–2:2003(E), ASTM
D6196–03 (Reapproved 2009), or BS EN
14662–4:2005 (all incorporated by
reference—see § 63.14)—or reported in the
peer-reviewed open literature. A summary
table and the supporting evaluation data
demonstrating the selected sorbent meets the
requirements in Addendum A to this method
must be submitted to the regulatory authority
as part of a request to use an alternative
sorbent.
7.1.4 Passive (diffusive) sampling and
thermal desorption methods that have been
evaluated at relatively high atmospheric
concentrations (i.e., mid-ppb to ppm) and
published for use in workplace air and
industrial/mobile source emissions testing
(References 9–20) may be applied to this
procedure. However, the validity of any
shorter term uptake rates must be verified
and adjusted if necessary for the longer
monitoring periods required by this method
by following procedures described in
Addendum A to this method or those
presented in national/international standard
methods: ISO 16017–2:2003(E), ASTM
D6196–03 (Reapproved 2009), or BS EN
14662–4:2005 (all incorporated by referencesee § 63.14).
7.1.5 Suitable sorbents for passive
sampling must have breakthrough volumes of
at least 20 L (preferably >100 L) for the
compounds of interest and must
quantitatively release the analytes during
desorption without exceeding maximum
temperatures for the sorbent or
instrumentation.
7.1.6 Repack/replace the sorbent tubes or
demonstrate tube performance following the
requirements in Addendum A to this method
at least every 2 years or every 50 uses,
whichever occurs first.
7.2 Gas Phase Standards
7.2.1 Static or dynamic standard
atmospheres may be used to prepare
calibration tubes and/or to validate passive
sampling uptake rates and can be generated
from pure chemicals or by diluting
concentrated gas standards. The standard
atmosphere must be stable at ambient
pressure and accurate to ±10 percent of the
target gas concentration. It must be possible
to maintain standard atmosphere
concentrations at the same or lower levels
than the target compound concentration
objectives of the test. Test atmospheres used
for validation of uptake rates must also
contain at least 35 percent relative humidity.
Note: Accurate, low-(ppb-) level gas-phase
VOC standards are difficult to generate from
PO 00000
Frm 00160
Fmt 4701
Sfmt 4700
pure materials and may be unstable
depending on analyte polarity and volatility.
Parallel monitoring of vapor concentrations
with alternative methods, such as pumped
sorbent tubes or sensitive/selective on-line
detectors, may be necessary to minimize
uncertainty. For these reasons, standard
atmospheres are rarely used for routine
calibration.
7.2.2 Concentrated, pressurized gas phase
standards. Accurate (±5 percent or better),
concentrated gas phase standards supplied in
pressurized cylinders may also be used for
calibration. The concentration of the
standard should be such that a 0.5–5.0 mL
volume contains approximately the same
mass of analytes as will be collected from a
typical air sample.
7.2.3 Follow manufacturer’s guidelines
concerning storage conditions and
recertification of the concentrated gas phase
standard. Gas standards must be recertified a
minimum of once every 12 months.
7.3 Liquid Standards
Target analytes can also be introduced to
the sampling end of sorbent tubes in the form
of liquid calibration standards.
7.3.1 The concentration of liquid
standards must be such that an injection of
0.5–2 ml of the solution introduces the same
mass of target analyte that is expected to be
collected during the passive air sampling
period.
7.3.2 Solvent Selection. The solvent
selected for the liquid standard must be pure
(contaminants <10 percent of minimum
analyte levels) and must not interfere
chromatographically with the compounds of
interest.
7.3.3 If liquid standards are sourced
commercially, follow manufacturer’s
guidelines concerning storage conditions and
shelf life of unopened and opened liquid
stock standards.
Note: Commercial VOC standards are
typically supplied in volatile or noninterfering solvents such as methanol.
7.3.4 Working standards must be stored at
6 °C or less and used or discarded within two
weeks of preparation.
7.4 Gas Phase Internal Standards
7.4.1 Gas-phase deuterated or fluorinated
organic compounds may be used as internal
standards for MS-based systems.
7.4.2 Typical compounds include
deuterated toluene, perfluorobenzene and
perfluorotoluene.
7.4.3 Use multiple internal standards to
cover the volatility range of the target
analytes.
7.4.4 Gas-phase standards must be
obtained in pressurized cylinders and
containing vendor certified gas
concentrations accurate to ±5 percent. The
concentration should be such that the mass
of internal standard components introduced
is similar to those of the target analytes
collected during field monitoring.
7.5 Preloaded Standard Tubes
Certified, preloaded standard tubes,
accurate within ±5 percent for each analyte
at the microgram level and ±10 percent at the
nanogram level, are available commercially
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
and may be used for auditing and quality
control purposes. (See Section 9.5 for audit
accuracy evaluation criteria.) Certified
preloaded tubes may also be used for routine
calibration.
Note: Proficiency testing schemes are also
available for TD/GC/MS analysis of sorbent
tubes preloaded with common analytes such
as benzene, toluene, and xylene.
filters must be installed in the carrier gas
lines supplying the analytical system
according to the manufacturer’s instructions.
Keep records of filter and oxygen scrubber
replacement.
7.6 Carrier Gases
Use inert, 99.999-percent or higher purity
helium as carrier gas. Oxygen and organic
75337
8.1.2 New tubes should be conditioned for
2 hours to supplement the vendor’s
conditioning procedure. Recommended
temperatures for tube conditioning are given
in Table 8.1.
8.1.3 After conditioning, the blank must
be verified on each new sorbent tube and on
10 percent of each batch of reconditioned
tubes. See Section 9.0 for acceptance criteria.
8.1.1 Sampling tubes must be
conditioned using the apparatus described in
Section 6.2.
8.0 Sorbent Tube Handling (Before and
After Sampling)
8.1
Sample Tube Conditioning
TABLE 8.1—EXAMPLE SORBENT TUBE CONDITIONING PARAMETERS
Maximum
temperature
(°C)
Sampling sorbent
Carbotrap® C ...............................................................................................................................
CarbopackTM C
Anasorb® GCB2
CarbographTM 1 TD
Carbotrap®
CarbopackTM B
Anasorb® GCB1
Tenax® TA
CarbopackTM X ............................................................................................................................
8.2 Capping, Storage and Shipment of
Conditioned Tubes
tkelley on DSK3SPTVN1PROD with RULES2
8.2.1 Conditioned tubes must be sealed
using long-term storage caps (see Section 6.4)
pushed fully down onto both ends of the PS
sorbent tube, tightened by hand and then
tighten an additional quarter turn using an
appropriate tool.
8.2.2 The capped tubes must be kept in
appropriate containers for storage and
transportation (see Section 6.4.2). Containers
of sorbent tubes may be stored and shipped
at ambient temperature and must be kept in
a clean environment.
8.2.3 You must keep batches of capped
tubes in their shipping boxes or wrap them
in uncoated aluminum foil before placing
them in their storage container, especially
before air freight, because the packaging
helps hold caps in position if the tubes get
very cold.
8.3 Calculating the Number of Tubes
Required for a Monitoring Exercise
8.3.1 Follow guidance given in Method
325A to determine the number of tubes
required for site monitoring.
8.3.2 The following additional samples
will also be required: Laboratory blanks as
specified in Section 9.1.2 (one per analytical
sequence minimum), field blanks as specified
in Section 9.3.2 (two per sampling period
minimum), CCV tubes as specified in Section
10.9.4. (at least one per analysis sequence or
every 24 hours), and duplicate samples as
specified in Section 9.4 (at least one
duplicate sample is required for every 10
sampling locations during each monitoring
period).
8.4 Sample Collection
8.4.1 Allow the tubes to equilibrate with
ambient temperature (approximately 30
minutes to 1 hour) at the monitoring location
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
before removing them from their storage/
shipping container for sample collection.
8.4.2 Tubes must be used for sampling
within 30 days of conditioning (Reference 4).
8.4.3 During field monitoring, the longterm storage cap at the sampling end of the
tube is replaced with a diffusion cap and the
whole assembly is arranged vertically, with
the sampling end pointing downward, under
a protective hood or shield—See Section 6.1
of Method 325A for more details.
8.5
Sample Storage
8.5.1 After sampling, tubes must be
immediately resealed with long-term storage
caps and placed back inside the type of
storage container described in Section 6.4.2.
8.5.2 Exposed tubes may not be placed in
the same container as clean tubes. They
should not be taken back out of the container
until ready for analysis and after they have
had time to equilibrate with ambient
temperature in the laboratory.
8.5.3 Sampled tubes must be inspected
before analysis to identify problems such as
loose or missing caps, damaged tubes, tubes
that appear to be leaking sorbent or container
contamination. Any and all such problems
must be documented together with the
unique identification number of the tube or
tubes concerned. Affected tubes must not be
analyzed but must be set aside.
8.5.4 Intact tubes must be analyzed
within 30 days of the end of sample
collection (within one week for limonene,
carene, bis-chloromethyl ether, labile sulfur
or nitrogen-containing compounds, and other
reactive VOCs).
Note: Ensure ambient temperatures stay
below 23 °C during transportation and
storage. Refrigeration is not normally
required unless the samples contain reactive
compounds or cannot be analyzed within 30
days. If refrigeration is used, the atmosphere
PO 00000
Frm 00161
Fmt 4701
Sfmt 4700
Conditioning
temperature
(°C)
Carrier gas
flow rate
>400
350
100 mL/min
350
330
100 mL/min
inside the refrigerator must be clean and free
of organic solvents.
9.0
Quality Control
9.1
Laboratory Blank
The analytical system must be
demonstrated to be contaminant free by
performing a blank analysis at the beginning
of each analytical sequence to demonstrate
that the secondary trap and TD/GC/MS
analytical equipment are free of any
significant interferents.
9.1.1 Laboratory blank tubes must be
prepared from tubes that are identical to
those used for field sampling.
9.1.2 Analysis of at least one laboratory
blank is required per analytical sequence.
The laboratory blank must be stored in the
laboratory under clean, controlled ambient
temperature conditions.
9.1.3 Laboratory blank/artifact levels
must meet the requirements of Section 9.2.2
(see also Table 17.1). If the laboratory blank
does not meet requirements, stop and
perform corrective actions and then reanalyze laboratory blank to ensure it meets
requirements.
9.2
Tube Conditioning
9.2.1 Conditioned tubes must be
demonstrated to be free of contaminants and
interference by running 10 percent of the
blank tubes selected at random from each
conditioned batch under standard sample
analysis conditions (see Section 8.1).
9.2.2 Confirm that artifacts and
background contamination are ≤ 0.2 ppbv or
less than three times the detection limit of
the procedure or less than 10 percent of the
target compound(s) mass that would be
collected if airborne concentrations were at
the regulated limit value, whichever is larger.
Only tubes that meet these criteria can be
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
9.4 Duplicate Samples
Duplicate (co-located) samples collected
must be analyzed and reported as part of
method quality control. They are used to
evaluate sampling and analysis precision.
Relevant performance criteria are given in
Section 9.9.
9.5 Method Performance Criteria
Unless otherwise noted, monitoring
method performance specifications must be
demonstrated for the target compounds using
the procedures described in Addendum A to
this method and the statistical approach
presented in Method 301.
9.6 Method Detection Limit
Determine the method detection limit
under the analytical conditions selected (see
9.8
Where:
A1 = A measurement value taken from one
spiked tube.
A2 = A measurement value taken from a
second spiked tube.
A = The average of A1 and A2.
tkelley on DSK3SPTVN1PROD with RULES2
Where:
Spiked Value = A known mass of VOCs
added to the tube.
Measured Value = Mass determined from
analysis of the tube.
9.9
Where:
F1 = A measurement value (mass) taken from
one of the two field replicate tubes used
in sampling.
F2 = A measurement value (mass) taken from
the second of two field replicate tubes
used in sampling.
F = The average of F1 and F2.
9.10.1 Quantitative (>95 percent)
compound recovery must be demonstrated by
repeat analyses on a same standard tube.
9.10.2 Compound recovery through the
TD system can also be demonstrated by
comparing the calibration check sample
response factor obtained from direct GC
injection of liquid standards with that
obtained from thermal desorption analysis
response factor using the same column under
identical conditions.
9.10.3 If the relative response factors
obtained for one or more target compounds
introduced to the column via thermal
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
Field Replicate Precision
Use Equation 9.3 to determine and
report replicate precision for duplicate
field samples (see Section 9.4). The
level of agreement between duplicate
9.10 Desorption Efficiency and Compound
Recovery
The efficiency of the thermal desorption
method must be determined.
Analytical Precision
Demonstrate an analytical precision within
±20 percent using Equation 9.2. Analytical
precision must be demonstrated during
PO 00000
Frm 00162
Fmt 4701
Sfmt 4700
Section 11.3) using the procedure in Section
15 of Method 301. The method detection
limit is defined for each system by making
seven replicate measurements of a
concentration of the compound of interest
within a factor of five of the detection limit.
Compute the standard deviation for the seven
replicate concentrations, and multiply this
value by three. The results should
demonstrate that the method is able to detect
analytes such as benzene at concentrations as
low as 50 ppt or 1/3rd (preferably 1/10th) of
the lowest concentration of interest,
whichever is larger.
Note: Determining the detection limit may
be an iterative process as described in 40 CFR
part 136, Appendix B.
9.7
Analytical Bias
Analytical bias must be demonstrated to be
within ±30 percent using Equation 9.1.
Analytical bias must be demonstrated during
initial setup of this method and as part of the
CCV carried out with every sequence of 10
samples or less (see Section 9.14). Calibration
standard tubes (see Section 10.0) may be
used for this purpose.
initial setup of this method and at least once
per year. Calibration standard tubes may be
used (see Section 10.0) and data from CCV
may also be applied for this purpose.
field samples is a measure of the
precision achievable for the entire
sampling and analysis procedure. Flag
data sets for which the duplicate
samples do not agree within 30 percent.
desorption fail to meet the criteria in Section
9.10.1, you must adjust the TD parameters to
meet the criteria and repeat the experiment.
Once the thermal desorption conditions have
been optimized, you must repeat this test
each time the analytical system is
recalibrated to demonstrate continued
method performance.
9.11
Audit Samples
Certified reference standard samples must
be used to audit this procedure (if available).
Accuracy within 30 percent must be
E:\FR\FM\01DER2.SGM
01DER2
ER01DE15.034
9.3 Field Blanks
9.3.1 Field blank tubes must be prepared
from tubes that are identical to those used for
field sampling—i.e., they should be from the
same batch, have a similar history, and be
conditioned at the same time.
9.3.2 Field blanks must be shipped to the
monitoring site with the sampling tubes and
must be stored at the sampling location
throughout the monitoring exercise. The field
blanks must be installed under a protective
hood/cover at the sampling location, but the
long-term storage caps must remain in place
throughout the monitoring period (see
Method 325A). The field blanks are then
shipped back to the laboratory in the same
container as the sampled tubes. One field
blank tube is required for every 10 sampled
tubes on a monitoring exercise and no less
than two field blanks should be collected,
regardless of the size of the monitoring study.
9.3.3 Field blanks must contain no greater
than one-third of the measured target analyte
or compliance limit for field samples (see
Table 17.1). If either field blank fails, flag all
data that do not meet this criterion with a
note that the associated results are estimated
and likely to be biased high due to field
blank background.
ER01DE15.033
used for field monitoring, field or laboratory
blanks, or for system calibration.
9.2.3 If unacceptable levels of VOCs are
observed in the tube blanks, then the
processes of tube conditioning and checking
the blanks must be repeated.
ER01DE15.032
75338
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
demonstrated for relevant ambient air
concentrations (0.5 to 25 ppb).
Verify the instrument performance by
analyzing a 50 hg injection of
bromofluorobenzene. Prior to the beginning
of each analytical sequence or every 24 hours
during continuous GC/MS operation for this
9.12 Mass Spectrometer Tuning Criteria
Tune the mass spectrometer (if used)
according to manufacturer’s specifications.
75339
method demonstrate that the
bromofluorobenzene tuning performance
criteria in Table 9.1 have been met.
TABLE 9.1—GC/MS TUNING CRITERIA 1
Target mass
Rel. to mass
50 .................................................................................................................................................
75 .................................................................................................................................................
95 .................................................................................................................................................
96 .................................................................................................................................................
173 ...............................................................................................................................................
174 ...............................................................................................................................................
175 ...............................................................................................................................................
176 ...............................................................................................................................................
177 ...............................................................................................................................................
95
95
95
95
174
95
174
174
176
Lower limit %
Upper limit %
8
30
100
5
0
50
4
93
5
40
66
100
9
2
120
9
101
9
1 All ion abundances must be normalized to m/z 95, the nominal base peak, even though the ion abundance of m/z 174 may be up to 120 percent that of m/z 95.
9.13 Routine CCV at the Start of a
Sequence
Run CCV before each sequence of analyses
and after every tenth sample to ensure that
the previous multi-level calibration (see
Section 10.6.3) is still valid.
9.13.1 The sample concentration used for
the CCV should be near the mid-point of the
multi-level calibration range.
9.13.2 Quantitation software must be
updated with response factors determined
from the CCV standard. The percent
deviation between the initial calibration and
the CCV for all compounds must be within
30 percent.
9.14 CCV at the End of a Sequence
Run another CCV after running each
sequence of samples. The initial CCV for a
subsequent set of samples may be used as the
final CCV for a previous analytical sequence,
provided the same analytical method is used
and the subsequent set of samples is
analyzed immediately (within 4 hours) after
the last CCV.
9.15 Additional Verification
Use a calibration check standard from a
second, separate source to verify the original
calibration at least once every three months.
9.16 Integration Method
Document the procedure used for
integration of analytical data including field
samples, calibration standards and blanks.
tkelley on DSK3SPTVN1PROD with RULES2
9.17 QC Records
Maintain all QC reports/records for each
TD/GC/MS analytical system used for
application of this method. Routine quality
control requirements for this method are
listed below and summarized in Table 17.1.
10.0 Calibration and Standardization
10.1 Calibrate the analytical system using
standards covering the range of analyte
masses expected from field samples.
10.2 Analytical results for field samples
must fall within the calibrated range of the
analytical system to be valid.
10.3 Calibration standard preparation
must be fully traceable to primary standards
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
of mass and/or volume, and/or be confirmed
using an independent certified reference
method.
10.3.1 Preparation of calibration standard
tubes from standard atmospheres.
10.3.1.1 Subject to the requirements in
Section 7.2.1, low-level standard
atmospheres may be introduced to clean,
conditioned sorbent tubes in order to
produce calibration standards.
10.3.1.2 The standard atmosphere
generator or system must be capable of
producing sufficient flow at a constant rate
to allow the required analyte mass to be
introduced within a reasonable time frame
and without affecting the concentration of
the standard atmosphere itself.
10.3.1.3 The sampling manifold may be
heated to minimize risk of condensation but
the temperature of the gas delivered to the
sorbent tubes may not exceed 100 °F.
10.3.1.4 The flow rates passed through
the tube should be in the order of 50–100
mL/min and the volume of standard
atmosphere sampled from the manifold or
chamber must not exceed the breakthrough
volume of the sorbent at the given
temperature.
10.4 Preparation of calibration standard
tubes from concentrated gas standards.
10.4.1 If a suitable concentrated gas
standard (see Section 7.2.2) can be obtained,
follow the manufacturer’s recommendations
relating to suitable storage conditions and
product lifetime.
10.4.2 Introduce precise 0.5 to 500.0 mL
aliquots of the standard to the sampling end
of conditioned sorbent tubes in a 50–100 mL/
min flow of pure carrier gas.
Note: This can be achieved by connecting
the sampling end of the tube to an unheated
GC injector (see Section 6.6) and introducing
the aliquot of gas using a suitable gas syringe.
Gas sample valves could alternatively be
used to meter the standard gas volume.
10.4.3 Each sorbent tube should be left
connected to the flow of gas for 2 minutes
after standard introduction. As soon as each
spiked tube is removed from the injection
unit, seal it with long-term storage caps and
place it in an appropriate tube storage/
PO 00000
Frm 00163
Fmt 4701
Sfmt 4700
transportation container if it is not to be
analyzed within 24 hours.
10.5 Preparation of calibration standard
tubes from liquid standards.
10.5.1 Suitable standards are described in
Section 7.3.
10.5.2 Introduce precise 0.5 to 2 ml
aliquots of liquid standards to the sampling
end of sorbent tubes in a flow (50–100 mL/
min) of carrier gas using a precision syringe
and an unheated injector (Section 6.5). The
flow of gas should be sufficient to completely
vaporize the liquid standard.
Note: If the analytes of interest are higher
boiling than n-decane, reproducible analyte
transfer to the sorbent bed is optimized by
allowing the tip of the syringe to gently touch
the sorbent retaining gauze at the sampling
end of the tube.
10.5.3 Each sorbent tube is left connected
to the flow of gas for 5 minutes after liquid
standard introduction.
10.5.3.1 As soon as each spiked tube is
removed from the injection unit, seal it with
long-term storage caps and place it in an
appropriate tube storage container if it is not
to be analyzed within 24 hours.
Note: In cases where it is possible to
selectively purge the solvent from the tube
while all target analytes are quantitatively
retained, a larger 2 mL injection may be made
for optimum accuracy. However, if the
solvent cannot be selectively purged and will
be present during analysis, the injection
volume should be as small as possible (e.g.,
0.5 mL) to minimize solvent interference.
Note: This standard preparation technique
requires the entire liquid plug including the
tip volume be brought into the syringe barrel.
The volume in the barrel is recorded, the
syringe is inserted into the septum of the
spiking apparatus. The liquid is then quickly
injected. Any remaining liquid in the syringe
tip is brought back into the syringe barrel.
The volume in the barrel is recorded and the
amount spiked onto the tube is the difference
between the before spiking volume and the
after spiking volume. A bias occurs with this
method when sample is drawn continuously
up into the syringe to the specified volume
E:\FR\FM\01DER2.SGM
01DER2
75340
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
and the calibration solution in the syringe tip
is ignored.
10.6 Preparation of calibration standard
tubes from multiple standards.
10.6.1 If it is not possible to prepare one
standard containing all the compounds of
interest (e.g., because of chemical reactivity
or the breadth of the volatility range),
standard tubes can be prepared from multiple
gas or liquid standards.
10.6.2 Follow the procedures described
in Sections 10.4 and 10.5, respectively, for
introducing each gas and/or liquid standard
to the tube and load those containing the
highest boiling compounds of interest first
and the lightest species last.
10.7 Additional requirements for
preparation of calibration tubes.
10.7.1 Storage of Calibration Standard
Tubes
10.7.1.1 Seal tubes with long-term storage
caps immediately after they have been
disconnected from the standard loading
manifold or injection apparatus.
10.7.1.2 Calibration standard tubes may
be stored for no longer than 30 days and
should be refrigerated if there is any risk of
chemical interaction or degradation. Audit
standards (see section 9.11) are exempt from
this criteria and may be stored for the shelflife specified on their certificates.
10.8 Keep records for calibration standard
tubes to include the following:
10.8.1 The stock number of any
commercial liquid or gas standards used.
10.8.2 A chromatogram of the most recent
blank for each tube used as a calibration
standard together with the associated
analytical conditions and date of cleaning.
10.8.3 Date of standard loading.
10.8.4 List of standard components,
approximate masses and associated
confidence levels.
10.8.5 Example analysis of an identical
standard with associated analytical
conditions.
10.8.6 A brief description of the method
used for standard preparation.
10.8.7 The standard’s expiration date.
10.9 TD/GC/MS using standard tubes to
calibrate system response.
10.9.1 Verify that the TD/GC/MS
analytical system meets the instrument
performance criteria given in Section 9.1.
10.9.2 The prepared calibration standard
tubes must be analyzed using the analytical
conditions applied to field samples (see
Section 11.0) and must be selected to ensure
quantitative transfer and adequate
chromatographic resolution of target
compounds, surrogates, and internal
standards in order to enable reliable
identification and quantitation of compounds
of interest. The analytical conditions should
also be sufficiently stringent to prevent
buildup of higher boiling, non-target
contaminants that may be collected on the
tubes during field monitoring.
10.9.3 Calibration range. Each TD/GC/MS
system must be calibrated at five
concentrations that span the monitoring
range of interest before being used for sample
analysis. This initial multi-level calibration
determines instrument sensitivity under the
analytical conditions selected and the
linearity of GC/MS response for the target
compounds. One of the calibration points
must be within a factor of five of the
detection limit for the compounds of interest.
10.9.4 One of the calibration points from
the initial calibration curve must be at the
same concentration as the daily CCV
standard (e.g., the mass collected when
sampling air at typical concentrations).
10.9.5 Calibration frequency. Each GC/
MS system must be recalibrated with a full
5-point calibration curve following corrective
action (e.g., ion source cleaning or repair,
column replacement) or if the instrument
fails the daily calibration acceptance criteria.
10.9.5.1 CCV checks must be carried out
on a regular routine basis as described in
Section 9.14.
10.9.5.2 Quantitation ions for the target
compounds are shown in Table 10.1. Use the
primary ion unless interferences are present,
in which case you should use a secondary
ion.
TABLE 10.1—CLEAN AIR ACT VOLATILE ORGANIC COMPOUNDS FOR PASSIVE SORBENT SAMPLING
Compound
Vapor
pressure
(mmHg) a
BP
(°C)
CAS No.
Characteristic ion(s)
MW b
Primary
Secondary
1,1-Dichloroethene .............................
3-Chloropropene ................................
1,1,2-Trichloro-1,2,2-trifluoroethane1,1-Dichloroethane .........................
75–35–4
107–05–1
32
44.5
500
340
96.9
76.5
61
76
96
41, 39, 78
75–34–3
57.0
230
99
63
1,2-Dichloroethane .............................
1,1,1-Trichloroethane .........................
Benzene .............................................
Carbon tetrachloride ..........................
1,2-Dichloropropane ...........................
Trichloroethene ..................................
1,1,2-Trichloroethane .........................
Toluene ..............................................
Tetrachloroethene ..............................
Chlorobenzene ...................................
Ethylbenzene .....................................
m,p-Xylene .........................................
107–06–2
71–55–6
71–43–2
56–23–5
78–87–5
79–01–6
79–00–5
108–88–3
127–18–4
108–90–7
100–41–4
108–38–3,
106–42–3
100–42–5
95–47–6
106–46–7
83.5
74.1
80.1
76.7
97.0
87.0
114
111
121
132
136
138
61.5
100
76.0
90.0
42.0
20.0
19.0
22.0
14.0
8.8
7.0
6.5
99
133.4
78
153.8
113
131.4
133.4
92
165.8
112.6
106
106.2
62
97
78
117
63
95
83
92
164
112
91
106
65, 83, 85, 98,
100
98
99, 61
..............................
119
112
97, 130, 132
97, 85
91
129, 131, 166
77, 114
106
91
145
144
173
6.6
5.0
0.60
104
106.2
147
104
106
146
78
91
111, 148
Styrene ...............................................
o-Xylene .............................................
p-Dichlorobenzene .............................
a Pressure
b Molecular
tkelley on DSK3SPTVN1PROD with RULES2
11.0
in millimeters of mercury.
weight.
Analytical Procedure
11.1 Preparation for Sample Analysis
11.1.1 Each sequence of analyses must be
ordered as follows:
11.1.1.1 CCV.
11.1.1.2 A laboratory blank.
11.1.1.3 Field blank.
11.1.1.4 Sample(s).
11.1.1.5 Field blank.
11.1.1.6 CCV after 10 field samples.
VerDate Sep<11>2014
23:11 Nov 30, 2015
Jkt 238001
11.1.1.7
batch.
CCV at the end of the sample
11.2 Pre-desorption System Checks and
Procedures
11.2.1 Ensure all sample tubes and field
blanks are at ambient temperature before
removing them from the storage container.
11.2.2 If using an automated TD/GC/MS
analyzer, remove the long-term storage caps
from the tubes, replace them with
PO 00000
Frm 00164
Fmt 4701
Sfmt 4700
appropriate analytical caps, and load them
into the system in the sequence described in
Section 11.1. Alternatively, if using a manual
system, uncap and analyze each tube, one at
a time, in the sequence described in Section
11.1.
11.2.3 The following thermal desorption
system integrity checks and procedures are
required before each tube is analyzed.
E:\FR\FM\01DER2.SGM
01DER2
Federal Register / Vol. 80, No. 230 / Tuesday, December 1, 2015 / Rules and Regulations
Note: Commercial thermal desorbers
should implement these steps automatically.
11.2.3.1 Tube leak test: Each tube must be
leak tested as soon as it is loaded into the
carrier gas flow path before analysis to ensure
data integrity.
11.2.3.2 Conduct the leak test at the GC
carrier gas pressure, without heat or gas flow
applied. Tubes that fail the leak test should
not be analyzed, but should be resealed and
stored intact. On automated systems, the
instrument should continue to leak test and
analyze subsequent tubes after a given tube
has failed. Automated systems must also
store and record which tubes in a sequence
have failed the leak test. Information on
failed tubes should be downloaded with the
batch of sequence information from the
analytical system.
11.2.3.3 Leak test the sample flow path.
Leak check the sample flow path of the
thermal desorber before each analysis
without heat or gas flow applied to the
sample tube. Stop the automatic sequence of
tube desorption and GC analysis if any leak
is detected in the main sample flow path.
This process may be carried out as a separate
step or as part of Section 11.2.3.2.
11.2.4 Optional Dry Purge
11.2.4.1 Tubes may be dry purged with a
flow of pure dry gas passing into the tube
from the sampling end, to remove water
vapor and other very volatile interferents if
required.
11.2.5 Internal Standard (IS) Addition
11.2.5.1 Use the internal standard
addition function of the automated thermal
desorber (if available) to introduce a precise
aliquot of the internal standard to the
sampling end of each tube after the leak test
and shortly before primary (tube)
desorption).
Note: This step can be combined with dry
purging the tube (Section 11.2.4) if required.
11.2.5.2 If the analyzer does not have a
facility for automatic IS addition, gas or
liquid internal standard can be manually
introduced to the sampling end of tubes in
a flow of carrier gas using the types of
procedure described in Sections