National Emission Standards for Hazardous Air Pollutants and New Source Performance Standards: Petroleum Refinery Sector Amendments, 15458-15490 [2018-06223]
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ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 60 and 63
[EPA–HQ–OAR–2010–0682; FRL–9976–00–
OAR]
RIN 2060–AT50
National Emission Standards for
Hazardous Air Pollutants and New
Source Performance Standards:
Petroleum Refinery Sector
Amendments
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
This action proposes
amendments to the National Emission
Standards for Hazardous Air Pollutants
(NESHAP) Refinery MACT 1 and
Refinery MACT 2 regulations to clarify
the requirements of these rules and to
make technical corrections and minor
revisions to requirements for work
practice standards, recordkeeping and
reporting. This action also proposes
technical corrections for the New
Source Performance Standards (NSPS)
for Petroleum Refineries.
DATES: Comments. Comments must be
received on or before May 25, 2018.
Under the Paperwork Reduction Act
(PRA), comments on the information
collection provisions are best assured of
consideration if the Office of
Management and Budget (OMB)
receives a copy of your comments on or
before May 10, 2018.
Public Hearing. If a public hearing is
requested by April 16, 2018, then we
will hold a public hearing on April 25,
2018 at the location described in the
ADDRESSES section. The last day to preregister in advance to speak at the
public hearing will be April 23, 2018.
ADDRESSES: Comments. Submit your
comments, identified by Docket ID No.
EPA–HQ–OAR–2010–0682, at https://
www.regulations.gov. Follow the online
instructions for submitting comments.
Once submitted, comments cannot be
edited or removed from Regulations.gov.
Regulations.gov is our preferred method
of receiving comments. However, other
submission formats are accepted. To
ship or send mail via the United States
Postal Service, use the following
address: U.S. Environmental Protection
Agency, EPA Docket Center, Docket ID
No. EPA–HQ–OAR–2010–0682, Mail
Code 28221T, 1200 Pennsylvania
Avenue NW, Washington, DC 20460.
Use the following Docket Center address
if you are using express mail,
commercial delivery, hand delivery, or
courier: EPA Docket Center, EPA WJC
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SUMMARY:
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West Building, Room 3334, 1301
Constitution Avenue NW, Washington,
DC 20004. Delivery verification
signatures will be available only during
regular business hours.
Do not submit electronically any
information you consider to be
Confidential Business Information (CBI)
or other information whose disclosure is
restricted by statute. See section I.C of
this preamble for instructions on
submitting CBI.
The EPA may publish any comment
received to its public docket.
Multimedia submissions (audio, video,
etc.) must be accompanied by a written
comment. The written comment is
considered the official comment and
should include discussion of all points
you wish to make. The EPA will
generally not consider comments or
comment contents located outside of the
primary submission (i.e., on the Web,
cloud, or other file sharing system). For
additional submission methods, the full
EPA public comment policy,
information about CBI or multimedia
submissions, and general guidance on
making effective comments, please visit
https://www2.epa.gov/dockets/
commenting-epa-dockets.
Public Hearing. If a public hearing is
requested, it will be held at EPA
Headquarters, EPA WJC East Building,
1201 Constitution Avenue NW,
Washington, DC 20004. If a public
hearing is requested, then we will
provide details about the public hearing
on our website at: https://www.epa.gov/
stationary-sources-air-pollution/
petroleum-refinery-sector-risk-andtechnology-review-and-new-source. The
EPA does not intend to publish another
document in the Federal Register
announcing any updates on the request
for a public hearing. Please contact
Virginia Hunt at (919) 541–0832 or by
email at hunt.virginia@epa.gov to
request a public hearing, to register to
speak at the public hearing, or to inquire
as to whether a public hearing will be
held.
The EPA will make every effort to
accommodate all speakers who arrive
and register. If a hearing is held at a U.S.
government facility, individuals
planning to attend should be prepared
to show a current, valid state- or federalapproved picture identification to the
security staff in order to gain access to
the meeting room. An expired form of
identification will not be permitted.
Please note that the Real ID Act, passed
by Congress in 2005, established new
requirements for entering federal
facilities. If your driver’s license is
issued by a noncompliant state, you
must present an additional form of
identification to enter a federal facility.
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Acceptable alternative forms of
identification include: Federal
employee badge, passports, enhanced
driver’s licenses, and military
identification cards. Additional
information on the Real ID Act is
available at https://www.dhs.gov/realid-frequently-asked-questions. In
addition, you will need to obtain a
property pass for any personal
belongings you bring with you. Upon
leaving the building, you will be
required to return this property pass to
the security desk. No large signs will be
allowed in the building, cameras may
only be used outside of the building,
and demonstrations will not be allowed
on federal property for security reasons.
FOR FURTHER INFORMATION CONTACT: For
questions about this proposed action,
contact Ms. Brenda Shine, Sector
Policies and Programs Division (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) 541–0516; and email address:
shine.brenda@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, EPA
WJC South Building (Mail Code 2227A),
1200 Pennsylvania Avenue NW,
Washington, DC 20460; telephone
number: (202) 564–7027; and email
address: malave.maria@epa.gov.
SUPPLEMENTARY INFORMATION:
Docket. The EPA has established a
docket for this rulemaking under Docket
ID No. EPA–HQ–OAR–2010–0682. All
documents in the docket are listed in
the Regulations.gov index. Although
listed in the index, some information is
not publicly available, e.g., 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.
Publicly available docket materials are
available either electronically in
Regulations.gov or in hard copy at the
EPA Docket Center, Room 3334, EPA
WJC West Building, 1301 Constitution
Avenue NW, Washington, DC. The
Public Reading Room is open from 8:30
a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The
telephone number for the Public
Reading Room is (202) 566–1744, and
the telephone number for the EPA
Docket Center is (202) 566–1742.
Instructions. Direct your comments to
Docket ID No. EPA–HQ–OAR–2010–
0682. The EPA’s policy is that all
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comments received will be included in
the public docket without change and
may be made available online at https://
www.regulations.gov, including any
personal information provided, unless
the comment includes information
claimed to be CBI or other information
whose disclosure is restricted by statute.
Do not submit information that you
consider to be CBI or otherwise
protected through https://
www.regulations.gov or email. This type
of information should be submitted by
mail as discussed in section I.C of this
preamble. The https://
www.regulations.gov website is an
‘‘anonymous access’’ system, which
means the EPA will not know your
identity or contact information unless
you provide it in the body of your
comment. If you send an email
comment directly to the EPA without
going through https://
www.regulations.gov, your email
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the internet. If you
submit an electronic comment, the EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If the EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, the EPA may not
be able to consider your comment.
Electronic files should not include
special characters or any form of
encryption and be free of any defects or
viruses. For additional information
about the EPA’s public docket, visit the
EPA Docket Center homepage at https://
www.epa.gov/dockets.
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:
AFPM American Fuel and Petrochemical
Manufacturers
API American Petroleum Institute
AWP Alternative Work Practice
CAA Clean Air Act
CBI Confidential Business Information
CDX Central Data Exchange
CEDRI Compliance and Emissions Data
Reporting Interface
CEMS continuous emission monitoring
system
CFR Code of Federal Regulations
COMS continuous opacity monitoring
system
CPMS continuous parameter monitoring
system
CRU catalytic reforming unit
DCU delayed coking unit
EPA Environmental Protection Agency
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ERT Electronic Reporting Tool
FCCU fluid catalytic cracking unit
FR Federal Register
HAP hazardous air pollutant(s)
HCN hydrogen cyanide
HON hazardous organic NESHAP
LEL lower explosive limit
MACT maximum achievable control
technology
NESHAP national emission standards for
hazardous air pollutants
NOCS Notification of Compliance Status
NSPS new source performance standards
NTTAA National Technology Transfer and
Advancement Act
OAQPS Office of Air Quality Planning and
Standards
OEL open-ended lines
OMB Office of Management and Budget
PDF portable document format
PM particulate matter
PRA Paperwork Reduction Act
PRD pressure relief device
RFA Regulatory Flexibility Act
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
Organization of this Document. The
information in 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?
C. What should I consider as I prepare my
comments for the EPA?
II. Background
III. What actions are we proposing?
A. Clarifications and Technical Corrections
to Refinery MACT 1
B. Clarifications and Technical Corrections
to Refinery MACT 2
C. Clarifications and Technical Corrections
to NSPS Ja
IV. Summary of Cost, Environmental, and
Economic Impacts
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Executive Order 13771: Reducing
Regulations and Controlling Regulatory
Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act
(UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
H. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
I. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
J. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
part 51
K. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations.
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I. General Information
A. Does this action apply to me?
Table 1 of this preamble lists the
NESHAP, NSPS, and associated
regulated industrial source categories
that are the subject of this proposal.
Table 1 is not intended to be exhaustive,
but rather provides a guide for readers
regarding the entities that this proposed
action is likely to affect. The proposed
standards, once promulgated, will be
directly applicable to the affected
sources. Federal, state, local, and tribal
government entities would not be
affected by this proposed action. As
defined in the Initial List of Categories
of Sources Under Section 112(c)(1) of
the Clean Air Act Amendments of 1990
(see 57 FR 31576, July 16, 1992), the
Petroleum Refineries—Catalytic
Cracking (Fluid and Other) Units,
Catalytic Reforming Units, and Sulfur
Plant Units source category includes
any facility engaged in producing
gasoline, napthas, kerosene, jet fuels,
distillate fuel oils, residual fuel oils,
lubricants, or other products from crude
oil or unfinished petroleum derivatives.
This category includes the following
refinery process units: Catalytic
cracking (fluid and other) units,
catalytic reforming units, and sulfur
plant units. The Petroleum Refineries—
Other Sources Not Distinctly Listed
includes any facility engaged in
producing gasoline, napthas, kerosene,
jet fuels, distillate fuel oils, residual fuel
oils, lubricants, or other products from
crude oil or unfinished petroleum
derivatives. This category includes the
following refinery process units not
listed in the Petroleum Refineries—
Catalytic Cracking (Fluid and Other)
Units, Catalytic Reforming Units, and
Sulfur Plant Units source category. The
refinery process units in this source
category include, but are not limited to,
thermal cracking, vacuum distillation,
crude distillation, hydroheating/
hydrorefining, isomerization,
polymerization, lube oil processing, and
hydrogen production.
TABLE 1—NESHAP AND INDUSTRIAL
SOURCE CATEGORIES AFFECTED BY
THIS PROPOSED ACTION
Source category
Petroleum Refineries.
1 North
System.
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40 CFR part 63,
subpart CC.
40 CFR part 63,
subpart UUU.
40 CFR part 60,
subpart Ja.
American
10APP2
NAICS
code 1
NESHAP
Industry
324110
Classification
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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 action
is available on the internet. Following
signature by the EPA Administrator, the
EPA will post a copy of this proposed
action at https://www.epa.gov/
stationary-sources-air-pollution/
petroleum-refinery-sector-risk-andtechnology-review-and-new-source.
Following publication in the Federal
Register, the EPA will post the Federal
Register version of the proposal and key
technical documents at this same
website.
A redline version of the regulatory
language that incorporates the proposed
changes in this action is available in the
docket for this action (Docket ID No.
EPA–HQ–OAR–2010–0682).
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C. What should I consider as I prepare
my comments for the EPA?
Submitting CBI. Do not submit
information containing CBI to the EPA
through https://www.regulations.gov or
email. Clearly mark the part or all of the
information that you claim to be CBI.
For CBI information on a disk or CD–
ROM that you mail to the EPA, mark the
outside of the disk or CD–ROM as CBI
and then identify electronically within
the disk or CD–ROM the specific
information that is claimed as CBI. In
addition to one complete version of the
comments that includes information
claimed as CBI, you must submit a copy
of the comments that does not contain
the information claimed as CBI for
inclusion in the public docket. If you
submit a CD–ROM or disk that does not
contain CBI, mark the outside of the
disk or CD–ROM clearly that it does not
contain CBI. Information not marked as
CBI will be included in the public
docket and the EPA’s electronic public
docket without prior notice. Information
marked as CBI will not be disclosed
except in accordance with procedures
set forth in 40 Code of Federal
Regulations (CFR) part 2. Send or
deliver information identified as CBI
only to the following address: OAQPS
Document Control Officer (C404–02),
OAQPS, U.S. Environmental Protection
Agency, Research Triangle Park, North
Carolina 27711, Attention Docket ID No.
EPA–HQ–OAR–2010–0682.
II. Background
On December 1, 2015 (80 FR 75178),
the EPA finalized amendments to the
Petroleum Refinery NESHAP in 40 CFR
part 63, subparts CC and UUU, referred
to as Refinery MACT 1 and 2,
respectively and the NSPS for
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petroleum refineries in 40 CFR part 60,
subparts J and Ja. The final amendments
to Refinery MACT 1 include a number
of new requirements, such as those for
maintenance vents, pressure relief
devices (PRDs), delayed coking units
(DCUs), fenceline monitoring, and
flares. The final amendments to
Refinery MACT 2 include revisions to
the continuous compliance alternatives
for catalytic cracking units and
provisions specific to startup and
shutdown of catalytic cracking units
and sulfur recovery plants. The
December 2015 action also finalized
technical corrections and clarifications
to Refinery NSPS subparts J and Ja to
address issues raised by the American
Petroleum Institute (API) in their 2008
and 2012 petitions for reconsideration
of the final NSPS Ja rule that had not
been previously addressed. These
include corrections and clarifications to
provisions for sulfur recovery plants,
performance testing, and control device
operating parameters.
In the process of implementing these
new requirements, numerous questions
and issues have been identified and we
are proposing clarifications or technical
amendments to address these questions
and issues. These issues were raised in
petitions for reconsideration and in
separately issued letters from industry
and in meetings with industry groups.
The EPA received three separate
petitions for reconsideration. Two
petitions were jointly filed by the API
and American Fuel and Petrochemical
Manufacturers (AFPM). The first of
these petitions was filed on January 19,
2016, and requested an administrative
reconsideration under section
307(d)(7)(B) of the Clean Air Act (CAA)
of certain provisions of Refinery MACT
1 and 2, as promulgated in the
December 2015 final rule. Specifically,
API and AFPM requested that the EPA
reconsider the maintenance vent
provisions in Refinery MACT 1 for
sources constructed on or before June
30, 2014; the alternate startup,
shutdown, or hot standby standards for
fluid catalytic cracking units (FCCUs)
constructed on or before June 30, 2014,
in Refinery MACT 2; the alternate
startup and shutdown for sulfur
recovery units constructed on or before
June 30, 2014, in Refinery MACT 2; and
the new catalytic reforming units
(CRUs) purging limitations in Refinery
MACT 2. The request pertained to
providing and/or clarifying the
compliance time for these sources.
Based on this request and additional
information received, the EPA issued a
proposal on February 9, 2016 (81 FR
6814), and a final rule on July 13, 2016
(81 FR 45232), fully responding to the
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January 19, 2016, petition for
reconsideration. The second petition
from API and AFPM was filed on
February 1, 2016, and outlined a
number of specific issues related to the
work practice standards for PRDs and
flares, and the alternative water
overflow provisions for DCUs, as well as
a number of other specific issues on
other aspects of the rule. The third
petition was filed on February 1, 2016,
by Earthjustice on behalf of Air Alliance
Houston, California Communities
Against Toxics, the Clean Air Council,
the Coalition for a Safe Environment,
the Community In-Power and
Development Association, the Del Amo
Action Committee, the Environmental
Integrity Project, the Louisiana Bucket
Brigade, the Sierra Club, the Texas
Environmental Justice Advocacy
Services, and Utah Physicians for a
Healthy Environment. The Earthjustice
petition claimed that several aspects of
the revisions to Refinery MACT 1 were
not proposed, and, thus, the public was
precluded from commenting on them
during the public comment period,
including: (1) Work practice standards
for PRDs and flares; (2) alternative water
overflow provisions for DCUs; (3)
reduced monitoring provisions for
fenceline monitoring; and (4)
adjustments to the risk assessment to
account for these new work practice
standards. On June 16, 2016, the EPA
sent letters to petitioners granting
reconsideration on issues where
petitioners claimed they had not been
provided an opportunity to comment.
These petitions and letters granting
reconsideration are available for review
in the rulemaking docket (see Docket
Item Nos. EPA–HQ–OAR–2010–0682–
0860, EPA–HQ–OAR–2010–0682–0891
and EPA–HQ–OAR–2010–0682–0892).
On October 18, 2016 (81 FR 71661),
the EPA proposed for public comment
the issues for which reconsideration
was granted in the June 16, 2016, letters.
The EPA identified five issues in the
proposal: (1) The work practice
standards for PRDs; (2) the work
practice standards for emergency flaring
events; (3) the assessment of risk as
modified based on implementation of
these PRD and emergency flaring work
practice standards; (4) the alternative
work practice (AWP) standards for
DCUs employing the water overflow
design; and (5) the provision allowing
refineries to reduce the frequency of
fenceline monitoring at sampling
locations that consistently record
benzene concentrations below 0.9
micrograms per cubic meter. In that
notice, the EPA also proposed two
minor clarifying amendments to correct
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a cross referencing error and to clarify
that facilities complying with
overlapping equipment leak provisions
must still comply with the PRD work
practice standards in the 2015 final rule.
The February 1, 2016, API and AFPM
petition for reconsideration included a
number of recommendations for
technical amendments and clarifications
that were not specifically addressed in
the October 18, 2016, proposal.1 In
addition, API and AFPM asked for
clarification on various requirements of
the final amendments in a July 12, 2016,
letter.2 The EPA addressed many of the
clarification requests from the July 2016
letter and the petition for
reconsideration in a letter issued on
April 7, 2017.3 API and AFPM also
raised additional issues associated with
the implementation of the final rule
amendments in a March 28, 2017, letter
to the EPA 4 and provided a list of
typographical errors in the rule in a
January 27, 2017, meeting 5 with the
EPA. On January 10, 2018, AFPM
submitted a letter containing a
comparison of the electronic CFR, CFR,
the Federal Register documents, and the
redline versions of the December 2015
and October 2016 amendments to the
Refinery Sector Rule noting
discrepancies providing suggestions as
to how these discrepancies should be
resolved.6 These items are located in
Docket ID No. EPA–HQ–OAR–2016–
0682. This proposal addresses many of
the issues and clarifications identified
by API and AFPM in their February
2016 petition for reconsideration and
their subsequent communications with
the EPA.
1 Supplemental Request for Administrative
Reconsideration of Targeted Elements of EPA’s
Final Rule ‘‘Petroleum Refinery Sector Risk and
Technology Review and New Source Performance
Standards; Final Rule,’’ Howard Feldman, API, and
David Friedman, AFPM. February 1, 2016. Docket
Item No. EPA–HQ–OAR–2010–0682–0892.
2 Letter from Matt Todd, API, and David
Friedman, AFPM, to Penny Lassiter, EPA. July 12,
2016. Available in Docket ID No. EPA–HQ–OAR–
2010–0682.
3 Letter from Peter Tsirigotis, EPA, to Matt Todd,
API, and David Friedman, AFPM. April 7, 2017.
Available at: https://www.epa.gov/stationarysources-air-pollution/december-2015-refinerysector-rule-response-letters-qa.
4 Letter from Matt Todd, API, and David
Friedman, AFPM, to Penny Lassiter, EPA. March
28, 2017. Available in Docket ID No. EPA–HQ–
OAR–2010–0682.
5 Meeting minutes for January 27, 2017, EPA
meeting with API. Available in Docket ID No. EPA–
HQ–OAR–2010–0682.
6 David Friedman, ‘‘Comparison of Official CFR
and e-CFR Postings Regarding MACT CC/UUU and
NSPS Ja Postings.’’ Message to Penny Lassiter and
Brenda Shine. January 10, 2018. Email.
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III. What actions are we proposing?
A. Clarifications and Technical
Corrections to Refinery MACT 1
1. Definitions
We are proposing to clarify the
Refinery MACT 1 rule requirements by
revising several definitions and adding
one definition.
a. Flare Purge Gas
In their March 28, 2017, letter seeking
additional clarifications, API and AFPM
noted that the definition of ‘‘flare purge
gas’’ could be interpreted to preclude
the flaring of purge gas that may be
introduced for safety reasons other than
to prevent oxygen infiltration, such as to
prevent freezing at the flare tip.7 They
requested that the EPA revise the
definition to include gas necessary for
other safety reasons. In the definition of
the term, ‘‘flare purge gas,’’ we included
a reference to a primary reason flare
purge gas is added at the flare tip,
namely to prevent oxygen infiltration,
but did not intend for refiners to
interpret this as not allowing them to
add flare purge gas for other safety
reasons. To reflect our intent, we are
proposing to revise the definition to
clarify that flare purge gas may also
include gas needed for other safety
reasons.
b. Flare Supplemental Gas
In their February 1, 2016, petition for
reconsideration, API and AFPM
requested a change to the definition of
‘‘flare supplemental gas’’ on the basis
that the definition’s reference to ‘‘all gas
that improves the combustion in the
flare combustion zone’’ could be
interpreted to include assist air and
assist steam. API and AFPM noted, in
contrast, that the way the term ‘‘flare
supplemental gas’’ is used throughout
the rule appears to only include gases
that increase combustion efficiency by
raising the heat content of the
combustion zone. This is evidenced by
the fact that the definition of flare vent
gas specifically includes flare
supplemental gas and specifically
excludes total steam or assist air.
Further, they claimed that the rule
incorrectly assumes that supplemental
gas is always natural gas, and uses the
term ‘‘natural gas’’ in the equations,
and, thus, limiting a refiner’s ability to
use fuel gas as supplemental gas.
We agree that, as written, the
definition could be misinterpreted and
we are proposing to revise the definition
of ‘‘flare supplemental gas’’ at 40 CFR
63.641. We also agree that we did not
intend to limit flare supplemental gas to
7 API
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only natural gas, so throughout the rule,
we are proposing to replace all instances
of the term ‘‘supplemental natural gas’’
with the defined term ‘‘flare
supplemental gas.’’ The specific
instances of these replacements are
provided in Table 2 of this preamble
(see section III.A.7).
c. Pressure Relief Device and Relief
Valve
In their February 1, 2016, petition for
reconsideration, API and AFPM noted
that Refinery MACT 1 interchangeably
uses the term ‘‘relief valve’’ and the
term ‘‘pressure relief device,’’ and
instead should be using the term
‘‘pressure relief device’’ throughout
because a relief valve is only one type
of pressure relief device. They requested
that a definition of pressure relief device
be added to Refinery MACT 1 to clarify
that it includes different types of relief
devices, such as relief valves and
rupture disks. We agree, and we are
proposing a definition of pressure relief
device, proposing to revise the
definition of relief valve, and proposing
to consistently use the term ‘‘pressure
relief device’’ throughout the rule.
d. Reference Control Technology for
Storage Vessels
In their February 1, 2016, petition for
reconsideration, API and AFPM noted
that the Refinery MACT 1 storage vessel
provisions at 40 CFR 63.660 require
Group 1 storage vessels with floating
roofs to comply with all the
requirements of 40 CFR part 63, subpart
WW, including requirements for fitting
controls. However, the Refinery MACT
1 definition of ‘‘reference control
technology for storage vessels’’ at 40
CFR 63.641 omits reference to these
fitting requirements. They requested
that the EPA revise the definition in 40
CFR 63.641 of Refinery MACT 1 to be
consistent with the Refinery MACT 1
requirements for storage vessels at 40
CFR 63.660. They also noted that the
term, ‘‘reference control technology for
storage vessels,’’ is never actually used
in the Refinery MACT 1 storage vessel
provisions at 40 CFR 63.660. We agree
and are revising the definition of
reference control technology for storage
vessels to be consistent with the storage
vessel rule requirements at 40 CFR
63.660. As it relates to storage vessels,
the only use of the term, ‘‘reference
control technology,’’ is in the Refinery
MACT 1 provisions pertaining to
emissions averaging in 40 CFR 63.652.
2. Miscellaneous Process Vent
Provisions
Petitioners requested a number of
amendments and clarifications to the
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requirements identifying and managing
the subset of miscellaneous process
vents that result from maintenance
activities.
a. Notice of Compliance Status (NOCS)
Report
In their March 28, 2017, letter, API
and AFPM noted that the miscellaneous
process vent provision at 40 CFR
63.643(c) does not require an owner or
operator to designate a maintenance
vent as a Group 1 or Group 2
miscellaneous process vent. However,
they stated that the reporting
requirements at 40 CFR 63.655(f)(1)(ii)
are unclear as to whether a NOCS report
is needed for maintenance vents. We
did not intend for the maintenance
vents to be included in the NOCS report
since we do not require the owner or
operator to designate a maintenance
vent as a Group 1 or Group 2
miscellaneous process vent. The rule
has separate requirements for
characterizing, recording, and reporting
maintenance vents in 40 CFR 63.655
(g)(13) and (h)(12); therefore, it is not
necessary to identify each and every
place where equipment may be opened
for maintenance in a NOCS report. To
clarify, we are proposing to add
language to 40 CFR 63.643(c) to
explicitly state that maintenance vents
need not be identified in the NOCS
report.
daltland on DSKBBV9HB2PROD with PROPOSALS2
b. Availability of a Pure Hydrogen
Supply for Compliance With
Maintenance Vent Provisions
Under 40 CFR 63.643(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. Facilities generally must
comply with one of three conditions
prior to venting maintenance vents to
the atmosphere (40 CFR 63.643(c)(1)(i–
iii)). However, 40 CFR 63.643(c)(1)(iv) of
the rule currently provides some
flexibility for maintenance vents
associated with equipment containing
pyrophoric catalyst (e.g., hydrotreaters
and hydrocrackers) at refineries that do
not have a pure hydrogen supply. This
is because catalytic reformer hydrogen
(the other primary hydrogen source)
contains appreciable concentrations of
light hydrocarbons which limits the
ability to reduce the lower explosive
limit (LEL) to 10 percent or less. For
these vents, 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.
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API and AFPM requested that the
EPA reconsider the standards in 40 CFR
63.643(c)(1)(iv) for equipment
containing pyrophoric catalyst, e.g.,
hydrotreaters or hydrocrackers; in
particular, they requested the EPA to reexamine the phrase ‘‘. . . at refineries
with a pure hydrogen supply.’’
Specifically, they pointed out that many
facilities have a pure hydrogen supply
that is not used at hydrotreaters or
hydrocrackers for a variety of reasons,
including the fact that these units may
be far removed from the on-site pure
hydrogen production unit and piping
the pure hydrogen supply to the unit is
expensive. In addition, a facility could
have a pure hydrogen production unit
that is idled or shut down because a
catalytic reforming unit produces
adequate hydrogen for the facility.
Petitioners suggested that the alternative
limit for equipment containing
pyrophoric catalyst should be provided
whenever an active supply of pure
hydrogen is not available at the unit.
As pyrophoric units (e.g.,
hydrocrackers and hydrotreaters)
require hydrogen to operate, at the time
we finalized the amendments, we
expected that pyrophoric units at a
refinery with pure hydrogen supply
would each have a pure hydrogen
supply. That is, we did not specifically
consider that some pyrophoric units at
the refinery would have a pure
hydrogen supply and others would not.
We established this requirement under
the authority of CAA section 112 (c)(2)
and (c)(3) to address emissions from
maintenance events which had been
exempted from the process vent
standards as episodic and non-routine
emission sources in order to ensure that
the maximum achievable control
technology (MACT) included standards
that apply at all times. We based these
work practices, including those
applicable to units without a pure
hydrogen supply, on practices generally
employed by the best performers.
We reviewed the recent comments
received and the additional information
provided by API and AFPM.8 The
information confirmed that a single
refinery may have many pyrophoric
units, some that have a pure hydrogen
supply and some that do not have a
pure hydrogen supply. Thus, our
assumption at the time we issued the
final rule regarding which units would
use a pure hydrogen supply is incorrect.
Thus, we are proposing to revise the
regulations such that units without a
8 Letter from Matt Todd, API, and David
Friedman, AFPM, to Penny Lassiter, EPA. August
1, 2017. Available in Docket ID No. EPA–HQ–OAR–
2010–0682.
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pure hydrogen supply, even though
there may be a pure hydrogen supply
somewhere else at the facility, could
comply with the standard in 40 CFR
63.643(c)(1)(iv).
Specifically, we are proposing to
amend 40 CFR 63.643(c)(1)(iv) to read
(new text highlighted in bold): ‘‘If the
maintenance vent is associated with
equipment containing pyrophoric
catalyst (e.g., hydrotreaters and
hydrocrackers) and a pure hydrogen
supply is not available at the equipment
at the time of the startup, shutdown,
maintenance, or inspection activity, 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.’’
c. Control Requirements for
Maintenance Vents
Paragraph 63.643(a) specifies that
Group 1 miscellaneous process vents
must be controlled by 98 percent or to
20 parts per million by volume or to a
flare meeting the requirements in 40
CFR 63.670. This paragraph also states
in the second sentence that
requirements for maintenance vents are
specified in 40 CFR 63.643(c), ‘‘and the
owner or operator is only required to
comply with the requirements in
§ 63.643(c).’’ Paragraphs (c)(1) through
(3) then specify requirements for
maintenance vents. Paragraph (c)(1)
requires that equipment must be
depressured to a control device, fuel gas
system, or back to the process until one
of the conditions in paragraph (c)(1)(i)
through (iv) is met. In reviewing these
rule requirements, the EPA noted that
we did not specify that the control
device in (c)(1) must also meet
requirements in paragraph (a). The
second sentence in 40 CFR 63.643(a)
could be misinterpreted to mean that a
facility complying with the maintenance
vent provisions in 40 CFR 63.643(c)
must only comply with the
requirements in paragraph (c) and not
the control requirements in paragraph
(a) for the control device referenced by
paragraph (c)(1). The second sentence
was meant to clarify that there is no
obligation for characterizing and
reporting miscellaneous process vents
as Group 1 and Group 2 if these are
maintenance vents. However, we
inadvertently did not specify control
device requirements for the control
referenced by paragraph (c)(1) in
paragraph (c). In omitting these
requirements, we did not intend that the
control requirement for maintenance
vents prior to atmospheric release
would not be compliant with Group 1
controls as specified under 40 CFR
63.643(a). These control requirements
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are consistent with control requirements
for other Group 1 miscellaneous process
vents. In order to clarify our intent, we
are proposing to amend 40 CFR
63.643(c)(1) to read: ‘‘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 meeting
requirements in paragraphs (a)(1) or (2)
of this section, a fuel gas system, or back
to the process until one of the following
conditions, as applicable, is met.’’
d. Additional Maintenance Vent
Alternative for Equipment Blinding
We received several requests to
address equipment blinding in the
maintenance venting provisions of 40
CFR 63.643(c). Equipment blinding is
conducted to isolate equipment for
maintenance activities. During the
installation of the blind flange, a flanged
connection in the equipment piping
must be opened, allowing vapors in the
equipment to be released to the
atmosphere. Additionally, while the
piping is open, a small amount of purge
gas is typically used to ensure air
(oxygen) does not enter the process
equipment. The introduction of purge
gas also results in emissions.
In their February 1, 2016, petition for
reconsideration, API and AFPM
requested clarification that emissions
that occur when ‘‘opening a flange on a
CRU reactor to install a blind’’ are
considered emissions from a
maintenance vent rather than a CRU
vent. Additionally, API provided
separate submissions with example
scenarios and emissions data for CRU
vents to the EPA on September 11,
2017,9 and January 16, 2018.10 In the
response to comment document
supporting the December 2015 final rule
(see Section 10.2 of Docket Item No.
EPA–HQ–OAR–2010–0682–0802), we
noted that only ‘‘catalytic reformer
regeneration vents’’ are excluded from
the definition of miscellaneous process
vents (MPV) and thereby excluded from
using the maintenance vent provisions.
However, we also indicated that other
CRU vents could meet the definition of
a maintenance vent (i.e., an MPV that is
only used as a result of startup,
shutdown, maintenance, or inspection
of equipment), and that those vents
could comply with the maintenance
vent provisions in 40 CFR 63.643(c).
Specifically, we noted that the entire
CRU is shut down for semi-regenerative
9 Matt Todd, ‘‘Examples.’’ Message to Brenda
Shine. September 11, 2017. Email.
10 Karin C. Ritter, ‘‘API Submitting: Flare Flow
Meter Accuracy White Paper & CRU Data &
Summary.’’ Message to Penny Lassiter and Brenda
Shine. January 16, 2018. Email.
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units and that the maintenance vent
provisions may apply in this case. We
are clarifying in this preamble that vents
(separate from the depressurization and
purge cycle vent(s) covered under
Refinery MACT 2) associated with
opening a flange to install a blind after
complete CRU shutdown may comply
with the maintenance vent provisions.
In their March 28, 2017, letter, API
and AFPM raised additional concerns
with the maintenance vent requirements
and the need to address the installation
of blinds to isolate equipment for
certain maintenance activities. They
claimed there may be situations where
refiners may not be able to meet the
requirements in 40 CFR 63.643(c)(1)(i)
through (iv) for maintenance vents, but
they must be able to conduct these
activities. For example, they may not be
able to achieve the 10-percent LEL
criterion in 40 CFR 63.643(c)(1)(i) prior
to atmospheric venting because a valve
used to isolate the equipment will not
seat fully so organic material may
continually leak into the isolated
equipment.
We agree that installing a blind to
prepare equipment for maintenance may
be necessary and may not currently
meet the conditions specified in 40 CFR
63.643(c)(1). To limit the emissions
during the blind installation, we are
proposing an additional condition
addressed by the maintenance vent
provisions as 40 CFR 63.643(c)(1)(v). We
are proposing to require depressuring
the equipment to 2 pounds (lb) per
square inch gauge (psig) or less prior to
equipment opening and maintaining
pressure of the equipment where purge
gas enters the equipment at or below 2
psig during the blind flange installation.
The low allowable pressure limit will
reduce the amount of process gas that
will be released during the initial
equipment opening and ongoing 2-psig
pressure requirement will limit the rate
of purge gas use. Together, these
requirements will limit the emissions
during blind flange installation and will
result in comparable emissions allowed
under the existing maintenance vent
provisions. While we acknowledge that
there may be circumstances where
equipment blinding prior to achieving
the 10-percent LEL criterion may be
necessary, we expect these situations to
be rare and that the owner or operator
would remedy the situation as soon as
practical (e.g., replace the isolation
valve or valve seat during the next
turnaround in the example provided
above). Therefore, at 40 CFR
63.643(c)(1)(v), we are proposing that
this alternative maintenance vent limit
be used under those situations where
the primary limits are not achievable
PO 00000
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15463
and blinding of the equipment is
necessary. We are proposing to require
refinery owners or operators to
document each circumstance under
which this provision is used, providing
an explanation why the other criteria
could not be met prior to equipment
blinding and an estimate of the
emissions that occurred during the
equipment blinding process.
e. Recordkeeping for Maintenance Vents
on Equipment Containing Less Than 72
Pounds (lbs) of Volatile Organic
Compounds (VOC)
Under 40 CFR 63.643(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 rule specifies that prior to
venting a maintenance vent to the
atmosphere, process liquids must be
removed from the equipment as much
as practical and the equipment must be
depressured to a control device, fuel gas
system, or back to the process until one
of several conditions, as applicable, is
met (40 CFR 63.643(c)(1)). One
condition specifies that equipment
containing less than 72 lbs/day of
volatile organic compounds (VOC) can
be depressured directly to the
atmosphere provided that the mass of
VOC in the equipment is determined
and provided that refiners keep records
of the process units or equipment
associated with the maintenance vent,
the date of each maintenance vent
opening, and records used to estimate
the total quantity of VOC in the
equipment at the time of vent opening.
Therefore, each maintenance vent
opening would be documented on an
event-basis.
Industry petitioners noted that there
are numerous routine maintenance
activities, such as replacing sampling
line tubing or replacing a pressure
gauge, that involve potential release of
very small amounts of VOC, often less
than 1 lb per day, that are well below
the 72 lbs/day of VOC threshold
provided in 40 CFR 63.643(c)(1)(iii).
They claimed that documenting each
individual event is burdensome and
unnecessary. We agree that
documentation of each release from
maintenance vents which serve
equipment containing less than 72 lbs of
VOC is not necessary, as long as there
is a demonstration that the event is
compliant with the requirement that the
equipment contains less than 72 lbs of
VOC. We are, therefore, proposing to
revise these provisions to require a
record demonstrating that the total
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quantity of VOC in the equipment based
on the type, size, and contents is less
than 72 lbs of VOC at the time of the
maintenance vent opening. However,
event-specific records are still required
for each maintenance vent opening for
which the deinventory procedures were
not followed or for which the
equipment opened exceeds the type and
size limits established in the records for
equipment containing less than 72
pounds of VOC.
daltland on DSKBBV9HB2PROD with PROPOSALS2
f. Bypass Monitoring for Open-Ended
Lines (OEL)
API and AFPM 11 requested
clarification of the bypass monitoring
provisions in 40 CFR 63.644(c) for openended lines (OEL). This provision
exempts from bypass monitoring
components subject to the Refinery
MACT 1 equipment leak provisions in
40 CFR 63.648. Noting that the
provisions in 40 CFR 63.648 only apply
to components in organic hazardous air
pollutant (HAP) service (i.e., greater
than 5-weight percent HAP), API and
AFPM asked whether the EPA also
intended to exempt open-ended valves
or lines that are in VOC service (less
than 5-weight percent HAP) and are
capped and plugged in compliance with
the standards in NSPS subpart VV or
VVa or the Hazardous Organic NESHAP
(HON; 40 CFR part 63, subpart H) that
are substantively equivalent to the
Refinery MACT 1 equipment leak
provisions in 40 CFR 63.648. Petitioners
noted that OELs in conveyances
carrying a Group 1 miscellaneous
process vent could be in less than 5weight percent HAP service, but could
still be capped and plugged in
accordance with another rule, such as
NSPS subpart VV or VVa or the HON.
The EPA agrees that, because the use of
a cap, blind flange, plug, or second
valve for an open-ended valve or line is
sufficient to prevent a bypass, the
bypass monitoring requirements in 40
CFR 63.644(c) are redundant with NSPS
subpart VV in these cases. We are
proposing to amend 40 CFR 63.644(c) to
make clear that open-ended valves or
lines that are capped and plugged
sufficiently to meet the standards in
NSPS subpart VV at 40 CFR 60.482–
6(a)(2), (b) and (c), are exempt from the
bypass monitoring in 40 CFR 63.644(c).
3. Pressure Relief Device Provisions
In their February 1, 2016, petition,
API and AFPM sought reconsideration
of certain aspects of the requirements
for PRDs in 40 CFR 63.648(j)(1) through
(5). As finalized, 40 CFR 63.648(j)(1)
11 API and AFPM, February 1, 2016, and March
28, 2017.
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provides operating requirements for
PRDs in organic HAP gas or vapor
service. Section 63.648(j)(2) specifies
pressure release requirements for PRDs
in organic HAP gas or vapor service.
Section 63.648(j)(3) (discussed in greater
detail below) specifies requirements for
pressure release management for all
PRDs in organic HAP service. Sections
63.648(j)(4) and (j)(5) provide
exemptions from the requirements in
(j)(1), (2), and (3) if all releases and
potential leaks from a PRD are routed
through a compliant control device or if
the PRDs meet certain criteria.
As noted above, 40 CFR 63.648(j)(3)
specifies requirements for pressure
release management for all PRDs in
organic HAP service, specifically:
(j)(3)(i) provides requirements for
monitoring affected PRDs; (j)(3)(ii) lists
options for three redundant release
prevention measures that must be
applied to affected PRDs; (j)(3)(iii)
requires root cause analysis and
corrective action if an affected PRD
releases to the atmosphere as a result of
a pressure release event; (j)(3)(iv)
stipulates how the facility must
determine the number of release events
during the calendar year for each
affected PRD; and (j)(3)(v) specifies what
release events are deemed a violation of
the pressure release management work
practice standards. Section 63.648(j)(5)
identifies the types of PRDs exempted
from pressure release management
requirements in (j)(3).
a. Clarification of Requirements for PRD
‘‘in organic HAP service’’
Regarding the applicability of the PRD
requirements in 40 CFR 63.648(j), API
and AFPM requested that we clarify
whether releases listed in paragraph 40
CFR 63.648(j)(3)(v) are limited to PRDs
‘‘in organic HAP service.’’ The heading
for 40 CFR 63.648(j)(3)(v), i.e., 40 CFR
63.648(j)(3) unambiguously states that
the ‘‘requirements specified in
paragraphs (j)(3)(i) through (v) of this
section’’ apply to ‘‘all pressure relief
devices in organic HAP service’’ and
reflects the Agency’s intent when
promulgating these provisions.
Subparagraphs (j)(3)(i) through (iv) use
the phrase ‘‘affected pressure relief
device,’’ and for consistency and clarity,
we are proposing to add that phrase—
‘‘affected pressure relief device’’— to
paragraph (j)(3)(v) to clarify that the
requirements in (j)(3)(v) also apply only
to releases from PRDs that are in organic
HAP service.
We also are proposing to amend the
introductory text in paragraph (j).
Currently, paragraph (j) states ‘‘Except
as specified in paragraphs (j)(4) and (5)
of this section, the owner or operator
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must also comply with the requirements
specified in paragraph (j)(3) of this
section for all pressure relief devices.’’
For consistency and clarity, we are
proposing to add ‘‘in organic HAP
service’’ to the end of this sentence to
clearly indicate that the word ‘‘all’’
includes organic HAP liquid service
PRDs.
b. Redundant Release Prevention
Measures in 40 CFR 63.648(j)(3)(ii)
As stated earlier, section (j)(3)(ii) lists
options for three redundant release
prevention measures that must be
applied to affected PRDs. The
prevention measures in (j)(3)(ii) 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; and (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.
The API and AFPM February 1, 2016,
petition for reconsideration requested
clarification as to whether two
prevention measures can be selected
from the list in 40 CFR
63.648(j)(3)(ii)(A). The rule does not
state that the measures in paragraph
(j)(3)(ii)(A) are to be considered a single
prevention measure. These measures
were grouped in subparagraph A
because of similarities they have;
however, they are separate measures.
For example, a liquid level monitor
discontinues the feed to the unit when
the liquid level exceeds a set point and
an overhead pressure monitor
discontinues the feed to the unit if the
pressure exceeds a certain level. If these
measures operate independently, the
EPA considers them two separate
redundant prevention measures—that
is, if the pressure exceeds a certain set
point, then the feed to the unit is
discontinued regardless of the liquid
level and vice a versa. If both the
pressure limit and the liquid level must
be exceeded to trigger shutting off the
feed to the unit, then that would be
considered a single prevention measure.
We also note that there may be
occasions where the same type of
monitor is used, but the parameter
monitored is different. For example, a
temperature monitor on the feed to a
unit may be used to trigger feed shut-off
to the unit, and a separate temperature
monitor may be used for the vessel
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overhead that also triggers feed shut-off
to the unit. As the temperature monitors
are not monitoring the same process
stream and the actions of the monitors
are independent, these systems would
be considered two separate ‘‘redundant
prevention measures.’’ To clarify this,
we are proposing to revise 40 CFR
63.648(j)(3)(ii)(A) to make clear that
independent, non-duplicative systems
count as separate redundant prevention
measures.
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c. Pilot-Operated PRD and Balanced
Bellows PRD
In a letter dated March 28, 2017, API
and AFPM requested clarification on
whether pilot-operated PRDs are
required to comply with the pressure
release management provisions of 40
CFR 63.648(j)(1) through (3).
A pilot-operated or balanced bellows
PRD is often used to relieve back
pressure so that the main PRD with
which it is associated can be routed to
a control device, back into the process
or to the fuel gas system. Pilot-operated
and balanced bellows PRDs are
primarily used for pressure relief when
the back pressure of the discharge vent
may be high or variable. Conventional
pressure relief devices act on a
differential pressure between the
process gas and the discharge vent. If
the discharge vent pressure increases,
the vessel pressure at which the PRD
will open increases, potentially leading
to vessel over-pressurization that could
cause vessel failure. For systems that
have high or variable back pressure,
either balanced bellows or pilotoperated PRDs are used. Balanced
bellows PRDs use a bellow to shield the
pressure relief stem and top portion of
the valve seat from the discharge vent
pressure. A balanced bellows PRD will
not discharge gas to the atmosphere
during a release event, except for leaks
through the bellows vent due to bellows
failure or fatigue. Pilot-operated PRDs
use a small pilot safety valve that
discharges to the atmosphere to effect
actuation of the main valve or piston,
which then discharges to a control
device. Balanced bellows or pilot
operated PRDs are a reasonable and
necessary means to safely control the
primary PRD release.
Pilot-operated and balanced bellows
PRDs are subject to the requirements at
40 CFR 63.648(j)(1) and (2) to ensure the
PRDs do not leak and properly reseat
following a release. However, based on
our understanding of pilot-operated
PRDs (see memorandum, ‘‘Pilotoperated PRD,’’ in Docket ID No. EPA–
HQ–OAR–2010–0682) and balanced
bellows PRDs, we are proposing that
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these PRDs are not subject to the
requirements of 40 CFR 63.648(j)(3).
Section 63.648(j)(5) identifies the
types of PRDs not subject to the pressure
release management requirements in
(j)(3). These include PRDs 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 (40 CFR
63.648(j)(5)(v)). In most cases, we expect
that pilot-operated PRDs would release
less than 72 lbs of VOC/day. However,
this provision does not apply to all pilot
vents because some have the potential
to emit greater than 72 lbs/day of VOC.
Even for releases greater than 72 lbs/day
of VOC, we agree that the root cause
analysis and corrective action is not
necessary because the main release vent
is not an atmospheric vent, but is
instead routed to the flare header.
Unless this event contributes to a flaring
event resulting in visible emissions or
velocity exceedance, the flare is
operating as intended and controlling
the PRD release. Although we expect
pilot vent discharges will release less
than 72 lbs/day of VOC, to ensure these
vent discharges are indeed small, and to
encourage low-emitting (e.g., nonflowing) pilot-operated PRDs, we are
proposing to amend the reporting
requirements at 40 CFR 63.655(g)(10)
and the recordkeeping requirements at
40 CFR 63.655(i)(11) to retain the
requirements to report and keep records
of each release to the atmosphere
through the pilot vent that exceeds 72
lbs/day of VOC, including the duration
of the pressure release through the pilot
vent and the estimate of the mass
quantity of each organic HAP release.
4. Delayed Coking Unit Decoking
Operation Provisions
The provisions in 40 CFR 63.657(a)
require owners or operators of DCU to
depressure each coke drum to a closed
blowdown system until the coke drum
vessel pressure or temperature meets the
applicable limits specified in the rule (2
psig or 220 degrees Fahrenheit for
existing sources). Special provisions are
provided in 40 CFR 63.657(e) and (f) for
DCU using ‘‘water overflow’’ or
‘‘double-quench’’ method of cooling,
respectively. According to 40 CFR
63.657(e), the owner or operator of a
DCU using the ‘‘water overflow’’
method of coke cooling must hardpipe
the overflow water (i.e., via an overhead
line) 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 provision in 40 CFR
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15465
63.657(e) also provides that 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.
In the October 18, 2016,
reconsideration proposal, we opened
the provisions in 40 CFR 63.657(e) for
public comment, but we did not
propose to amend the requirements. In
response to the October 18, 2016,
reconsideration proposal, we received
several comments regarding the
provisions in 40 CFR 63.657(e) for DCU
using the water overflow method of
coke cooling. API and AFPM wanted
clarification that the water overflow
requirements in 40 CFR 63.657(e) are
only applicable if the primary pressure
or temperature limits in 40 CFR
63.657(a) were not met prior to
overflowing any water. We agree that an
owner or operator of a DCU with a water
overflow design does not need to
comply with the provisions in 40 CFR
63.657(e) unless they cannot comply
with the primary pressure or
temperature limits in 40 CFR 63.657(a)
prior to overflowing any water.
However, if water overflow is used
before the primary pressure or
temperature limits in 40 CFR 63.657(a)
are met, then the owner or operator
must use ‘‘controlled’’ water overflow
until the applicable temperature limit is
achieved. This is required because the
primary pressure limits are based on the
vessel pressure, which is the pressure of
the gas at the top of the coke drum, and
once the water starts to overflow, we do
not consider the pressure in the liquid
filled overhead line to be representative
of the DCU vessel pressure. We are
proposing to clarify these points in 40
CFR 63.657(e).
In addition, environmental petitioners
questioned whether the submerged fill
requirement would effectively reduce
emissions if gas is entrained into the
overflow water leaving the coke drum
such that the gas could then be emitted
to the air out of the overflow water
storage tank. We reviewed schematics of
water overflow design DCU and found
that a typical water overflow DCU uses
a separator to prevent gas entrainment
with the overflow water.12 The
overhead gas from the separator is
routed to the DCU’s closed blowdown
system. The liquids accumulate at the
bottom of the separator and are then
routed to a storage vessel. We do not
have information on the design of all
12 Email correspondence from Dave Pavlich,
Phillips 66, to Brenda Shine, EPA. March 6, 2017.
Available in Docket ID No. EPA–HQ–OAR–2010–
0682.
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water overflow DCUs. If there are DCUs
that do not use a separator, it is possible
to entrain gases with the DCU water
overflow and the submerged fill
requirement would not effectively
reduce emissions from the overflow
water storage tank if gas is entrained in
the water overflow. Therefore, we are
also proposing to add provisions to 40
CFR 63.657(e) requiring the use of a
separator or disengaging device
operated in a manner to prevent
entrainment of gases from the coke
drum vessel to the overflow water
storage tank. Gases from the separator
must be routed to a closed vent
blowdown system or otherwise
controlled following the requirements
for a Group 1 miscellaneous process
vent. As separators appear to be an
integral part of the water overflow
system design, we are not projecting any
capital investment or additional
operating costs associated with this
proposed amendment.
5. Fenceline Monitoring Provisions
We are proposing several
amendments to the fenceline monitoring
provisions in Refinery MACT 1. Many
of the proposed revisions to the
fenceline monitoring provisions are
related to requirements for reporting
monitoring data.
The December 1, 2015, final rule
established provisions for monitoring
fugitive emissions at refinery fencelines
(40 CFR 63.658). Under the fenceline
monitoring provisions, an owner/
operator must monitor benzene
concentrations around the perimeter
(fenceline) of their facility using a
network of passive air monitors that
contain sorbent tubes (40 CFR
63.658(c)). Facilities are required to
collect the tubes and analyze them for
benzene every 2 weeks (40 CFR
63.658(e)), but may request an
alternative test method for collecting
and/or analyzing samples (40 CFR
63.658(k)). Facilities must then calculate
the difference in the highest and lowest
2-week benzene concentrations reported
at the facility fenceline, called the Dc
(40 CFR 63.658(f)). If the annual rolling
average Dc exceeds an action level of 9
micrograms per cubic meter (mg/m3)
benzene (40 CFR 63.658(f)(3)), the
facility must conduct a root cause
analysis and implement initial
corrective action (40 CFR 63.658(g)). If
the annual rolling Dc value for the next
2-week sampling period after the initial
corrective action is greater than 9 mg/m3,
or if all corrective action measures
identified require more than 45 days to
implement, the owner or operator must
develop a corrective action plan (40 CFR
63.658(h)).
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The December 1, 2015, final rule
included new EPA Methods 325A and
B specifying monitor siting and
quantitative sample analysis
procedures. Method 325A requires an
additional monitor be placed near
known VOC emission sources if the
VOC emissions source is located within
50 meters of the monitoring perimeter
and the source is between two monitors.
The December 1, 2015, final rule at 40
CFR 63.658(c)(1) provides ‘‘known
sources of VOCs . . . 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.’’ In their February 1,
2016, petition for reconsideration, API
and AFPM recommended that the EPA
exclude sources requiring control under
the miscellaneous process vent
requirements of 40 CFR 63.643 and the
equipment leak requirements of 40 CFR
63.648 from the known sources of VOC
specified in 40 CFR 63.658(c)(1) so that
these emission sources would not
trigger the need for additional fenceline
monitors. In response, we are proposing
an alternative to the additional monitor
siting requirement for pumps, valves,
connectors, sampling connections, and
open-ended lines sources that are
actively monitored monthly using
audio, visual, or olfactory means and
quarterly using Method 21 or the AWP.
We believe this is reasonable because
these sources may be insignificant and,
under these circumstances, the
timeframe for discovery of a leak (1
month to 3 months) and repair (within
15 days of discovery) is consistent with
the timeframe needed to analyze a
passive monitor sample (45 days) and
complete the initial root cause analysis
and corrective action (45 days after
discovery). We consider this
requirement to be an adequate
alternative to the additional monitor
requirement.
In their February 1, 2016, petition for
reconsideration, API and AFPM
suggested that if the Dc for the 2-week
sampling period following an
exceedance of the annual average Dc
action level is 9 mg/m3 or less, then
appropriate corrective action measures
may be assumed to already be
implemented and the root cause
analysis and corrective action analysis
does not need to be performed. We are
clarifying in this preamble that if a root
cause analysis was performed and
corrective action measures were
implemented prior to the exceedance of
the annual average Dc action level, then
these documented actions can be used
to fulfill the root cause analysis and
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corrective action requirements in 40
CFR 63.658(g) and recordkeeping in 40
CFR 63.655(i)(8)(viii).
In addition, we are proposing a
revision to the reporting requirements
for the fenceline data in 40 CFR
63.655(h)(8). Consistent with requests
from API and AFPM in their February
1, 2016, petition for reconsideration, we
are proposing that the quarterly reports
are to cover calendar year quarters (i.e.,
Quarter 1 is from January 1 through
March 31; Quarter 2 is from April 1
through June 30; Quarter 3 is from July
1 through September 30; and Quarter 4
is from October 1 through December 31)
rather than being directly tied to the
date compliance monitoring began. This
proposed change will simplify reporting
by putting all refinery reports on the
same schedule and reducing confusion
regarding when refiners are required to
report, especially if they own more than
one facility.
We are also proposing several
measures that would reduce burden and
clarify reporting associated with
collecting and analyzing quality
assurance/quality control samples (field
blanks and duplicates) associated with
the fenceline monitoring requirements
in 40 CFR 63.658(c)(3). First, we are
proposing to require only one field
blank per sampling period rather than
two as currently required. Second, we
are proposing to decrease the number of
duplicate samples that must be
collected each sample period. Instead of
requiring a duplicate sample for every
10 monitoring locations, we propose
that facilities with 19 or fewer
monitoring locations only be required to
collect one duplicate sample per
sampling period and facilities with 20
or more sampling locations only be
required to collect two duplicate
samples per sampling period. These
proposed changes reflect current
practices and the needed quality
assurance/quality control of blanks and
samples. The reduced need for quality
assurance/quality control samples is a
result of enhancement and refinement of
sample preparation and sorbent tube
manufacturing, leading to an increase in
precision of blanks and lower levels of
containments in blanks as compared to
the developmental stage of the method.
We received questions during the
fenceline reporting webinars on how to
report duplicate sample results and
whether duplicate sample results are to
be used in the calculation of Dc. Because
there are two analytical results for each
set of duplicate samples and the final
rule was unclear on how to report these
results, facilities were uncertain
whether they should choose one of the
two results for use in the calculation of
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Dc or whether the results should be
averaged. In order to clarify how the
results of the duplicate sample analyses
are to be used, we are proposing to
require that duplicate samples be
averaged together to determine the
sampling location’s benzene
concentration for the purposes of
calculating Dc.
Consistent with the requirements in
40 CFR 63.658(k) for requesting an
alternative test method for collecting
and/or analyzing samples, we are
proposing to revise the Table 6 entry for
40 CFR 63.7(f) to indicate that 40 CFR
63.7(f) applies except that alternatives
directly specified in 40 CFR part 63,
subpart CC do not require additional
notification to the Administrator or the
approval of the Administrator. We also
are proposing editorial revisions to the
fenceline monitoring section; these
proposed revisions are included in
Table 2 in section III.A.7 of this
preamble.
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6. Flare Control Device Provisions
API and AFPM requested clarification
in a December 1, 2016, letter to EPA 13
regarding assist steam line designs that
entrain air into the lower or upper steam
at the flare tip. The industry
representatives noted that many of the
steam-assisted flare lines have this type
of air entrainment and likely were part
of the dataset analyzed to develop the
standards established in the 2015 final
rule for steam-assisted flares. API and
AFPM, therefore, maintain that these
flares should not be considered to have
assist air, and that they are
appropriately and adequately regulated
under the final standards for steamassisted flares. Because flares with assist
air are required to comply with both a
combustion zone net heating value
(NHVcz) and a net heating value dilution
parameter (NHVdil), there is increased
burden in having to comply with two
operating parameters, and API and
AFPM contend that this burden is
unnecessary.
Assist air is defined to mean all air
intentionally 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 air includes
premix assist air and perimeter assist
air. Assist air does not include the
surrounding ambient air. Air
entrainment through steam nozzles is
13 Letter from Matt Todd, API, and David
Friedman, AFPM, to Penny Lassiter, EPA.
December 1, 2016. Available in Docket ID No. EPA–
HQ–OAR–2010–0682.
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intentionally introduced prior to or at
the flare tip and, therefore, it is
considered assist air. However, if this is
the only assist air introduced prior to or
at the flare tip, it is reasonable in most
cases for the owner or operator to only
need to comply with the NHVcz
operating limit. This is because an
exceedance of the NHVcz operating limit
would also cause an exceedance of the
NHVdil operating limit in many cases.
We calculated the amount of air that
must be entrained in the steam to cause
a flare meeting the NHVcz operating
limit of 270 British thermal units per
standard cubic foot (Btu/scf) to be below
the NHVdil operating limit of 22 Btu per
square foot (Btu/ft2). The NHVdil
parameter is a function of flare tip
diameter. For flare tips with an effective
tip diameter of 9 inches or more, there
are no flare tip steam induction designs
that can entrain enough assist air to
cause a flare operator to have a
deviation of the NHVdil operating limit
without first deviating from the NHVcz
operating limit. Therefore, we are
proposing to allow owners or operators
of flares whose only assist air is from
perimeter assist air entrained in lower
and upper steam at the flare tip and
with a flare tip diameter of 9 inches or
greater to comply only with the NHVcz
operating limit.
Steam-assisted flares with perimeter
assist air and an effective tip diameter
of less than 9 inches would remain
subject to the requirement to account for
the amount of assist air intentionally
entrained within the calculation of
NHVdil. We recognize that this assist air
cannot be directly measured, but the
quantity of air entrained is dependent
on the assist steam rate and the design
of the steam tube’s air entrainment
system. We are proposing to add
provisions to specify that owners or
operators of these smaller diameter
steam-assisted flares use the steam flow
rate and the maximum design air-tosteam ratio of the steam tube’s air
entrainment system for determining the
flow rate of this assist air. Using the
maximum design ratio will tend to overestimate the assist air flow rate, which
is conservative with respect to ensuring
compliance with the NHVdil operating
limit.
In addition to these revisions, for air
assisted flares, we also are providing
clarification on determining air flow
rates. While we specifically provided for
the use of engineering calculations for
determining the flow rate, we received
questions in the February 1, 2016,
petition as to whether or not this
allowed the use of fan curves for
determining air assist flow rates. In the
December 2015 final rule in the
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15467
introductory paragraph of 40 CFR
63.670(i), we stated that continuously
monitoring fan speed or power and
using fan curves is an acceptable
method for continuously monitoring
assist air flow rates. To further clarify
this point, we are proposing to include
specific provisions for continuously
monitoring fan speed or power and
using fan curves for determining assist
air flow rates.
In response to the February 1, 2016,
petition for reconsideration from API
and AFPM, we are also proposing to
clarify the requirements for conducting
visible emissions monitoring. API and
AFPM raised a concern that the current
language in 40 CFR 63.670(h) is unclear
and could be interpreted to require
facilities to flare regulated materials in
order to conduct the required visible
emissions monitoring. We recognize
that many flares are used only during
startup, shutdown, or emergency events
and we agree that it is not reasonable to
require refiners to flare regulated
materials intentionally in order to
conduct a visible emissions compliance
demonstration. We are proposing to
clarify that the initial 2-hour visible
emissions demonstration should be
conducted the first time regulated
materials are routed to the flare. We are
also proposing to clarify 40 CFR
63.670(h)(1) to provide that the daily 5minute observations must only be
conducted on days the flare receives
regulated material and that the
additional visible emissions monitoring
is specific to cases when visible
emissions are observed while regulated
material is routed to the flare.
API and AFPM requested in their
February 1, 2016, petition for
reconsideration that we specify the
averaging period for establishing the
limit for the smokeless capacity of the
flare and that it be a 15-minute average
consistent with other flow parameters
and velocity requirements. Owners or
operators would use the cumulative
flow rate and/or flare tip velocity
determined according to 40 CFR
63.670(k) for assessing exceedances of
the smokeless capacity, and this flow
rate is specifically determined on a 15minute block average. Consistent with
these requirements, we are proposing to
clarify, at 40 CFR 63.670(o)(1)(iii)(B),
that the owner or operator must
establish the smokeless capacity of the
flare in a 15-minute block average and
at 40 CFR 63.670(o)(3)(i) that the
exceedance of the smokeless capacity of
the flare is based on a 15-minute block
average. We are also correcting an error
in the units for the cumulative
volumetric flow used in the flare tip
velocity equation in 40 CFR
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63.670(k)(3). We are revising the units to
specify standard cubic feet rather than
actual cubic feet consistent with the
cumulative volumetric flow monitoring
requirements in 40 CFR 63.670(i)(1) and
as stated in our response to public
comments (Docket Item No. EPA–HQ–
OAR–2010–0682–0802) in the
discussion under 3.3.5.–Velocity Limit
and Calculation Method. These specific
edits are included in the summary of
editorial corrections provided in Table 2
of his preamble (see section III.A.7).
Industry stakeholders with input from
vendors have also made
submissions 14 15 16 expressing concerns
over the ability to meet the flare vent gas
flow rate minimum accuracy
requirements in 40 CFR 60.107a(f)(1)(ii)
and in Table 13 of 40 CFR part 63,
subpart CC when vent streams have low
molecular weight. These requirements
specify an accuracy of ±20 percent of
the flow rate at velocities ranging from
0.1 to 1 foot per second and an accuracy
of ±5 percent of the flow rate for
velocities greater than 1 foot per second.
Stakeholders stated that the accuracy
requirements could not be met for some
historical flow events when molecular
weight of the flare vent gas was low,
including: plant power outages caused
by weather, compressor surges due to
lightning strikes, compressor shutdowns
due to high vibration events, hydrogen
plant startup and shutdown, CRU plant
startups, flare header maintenance
activities and routing of high hydrogen
process streams to the flare during
maintenance events and process upsets.
The EPA recognizes that flares can
receive a wide range of process streams
over a wide range of flows. We are
clarifying in this preamble that
certification of compliance for these
flare vent gas flow meter accuracy
requirements can be made based on the
typical range of flare gas compositions
expected for a given flare.
7. Other Corrections
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We received comments from API and
AFPM in their February 1, 2016,
petition for reconsideration regarding
the incorporation of 40 CFR part 63,
subpart WW storage vessel provisions
and 40 CFR part 63, subpart SS closed
vent systems and control device
provisions into Refinery MACT 1
14 Kris A. Battleson, ‘‘Chevron-vendor
information for call at 12 PDT, 3 EDT.’’ Message to
Gerri Garwood and Brenda Shine. August 29, 2017.
Email.
15 Kris A. Battleson, ‘‘meter QA/QC.’’ Message to
Brenda Shine. September 19, 2017. Email.
16 Karin C. Ritter, ‘‘API Submitting: Flare Flow
Meter Accuracy White Paper & CRU Data &
Summary.’’ Message to Penny Lassiter and Brenda
Shine. January 16, 2018. Email.
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requirements for Group 1 storage vessels
at 40 CFR 63.660. The pre-amended
version of the Refinery MACT 1 rule
specified (by cross reference at 40 CFR
63.646) that storage vessels containing
liquids with a vapor pressure of 76.6
kilopascals (11.0 pounds per square
inch (psi)) or greater must be vented to
a closed vent system or to a control
device consistent with the requirements
in the HON. The petitioners pointed out
that the EPA did not retain this
provision at 40 CFR 63.660 in the
December 2015 final rule. In reviewing
the introductory text at 40 CFR 63.660,
we agree that the language was
inadvertently omitted. We did not
intend to deviate from the longstanding
requirement limiting the vapor pressure
of material that can be stored in a
floating roof tank. We are, therefore,
proposing to revise the introductory text
in 40 CFR 63.660 to clarify that owners
or operators of affected Group 1 storage
vessels storing liquids with a maximum
true vapor pressure less than 76.6
kilopascals (11.0 psi) can comply with
either the requirements in 40 CFR part
63, subpart WW or SS and that owners
or operators storing liquids with a
maximum true vapor pressure greater
than or equal to 76.6 kilopascals (11.0
psi) must comply with the requirements
in 40 CFR part 63, subpart SS.
We also received comments from API
and AFPM in their February 1, 2016,
petition for reconsideration regarding
provisions in 40 CFR 63.660(b). Section
63.660(b)(1) allows Group 1 storage
vessels to comply with alternatives to
those specified in 40 CFR 63.1063(a)(2)
of subpart WW. Section 63.660(b)(2)
specifies additional controls for ladders
having at least one slotted leg. The
petitioners explained that 40 CFR
63.1063(a)(2)(ix) provides extended
compliance time for these controls, but
that it is unclear whether this additional
compliance time extends to the use of
the alternatives to comply with 40 CFR
63.660(b). We are proposing language to
make clear that the additional
compliance time applies to the
implementation of controls in 40 CFR
63.660(b).
We received several questions from
industry pertaining to the requirement
in paragraphs 40 CFR 63.655(f) and 40
CFR 63.655(f)(6) to submit a NOCS
report. The final rule allows sources that
are newly subject to Refinery MACT 1
to submit the NOCS in a periodic report
rather than in a separate notification
submission (40 CFR 63.655(f)(6)). It is
reasonable that any source with a
compliance date on or after February 1,
2016, should be able to follow the same
approach. We are proposing to amend
paragraphs 40 CFR 63.655(f) and 40 CFR
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63.655(f)(6) to expressly provide that
sources having a compliance date on or
after February 1, 2016, may submit the
NOCS in the periodic report rather than
as a separate submission.
We are also proposing to clarify at 40
CFR 63.660(e) that the initial inspection
requirements that applied with initial
filling of the storage vessels are not
required again simply because the
source transitions from the requirements
in 40 CFR 63.646 to 40 CFR 63.660.
We also received comments from API
and AFPM 17 that the deadlines in the
December 2015 final rule for reporting
results of performance tests are
inconsistent. The electronic reporting
requirements in 40 CFR 63.655(h)(9)
provide that the results of performance
tests must be reported within 60 days of
completing the performance test, while
the NOCS report in 40 CFR 63.655(f),
which is required to contain the
performance test results, is due 150 days
from the compliance date in the rule.
We note that while some performance
tests may be required prior to the
requirement to submit the NOCS report,
others may be performed when no
NOCS report is due. We are proposing
revisions to 40 CFR 63.655(f)(1)(i)(B)(3)
and (C)(2), (f)(1)(iii), (f)(2), and (f)(4) to
clarify that when the results of
performance tests [or performance
evaluations] are to be reported in the
NOCS, the results are due by the date
the NOCS report is due (report is due
150 days from the compliance date)
whether the results are reported using
the Compliance and Emissions Data
Reporting Interface (CEDRI) or in hard
copy as part of the NOCS report. If the
source submits the test results using
CEDRI, we are also proposing to specify
that the source need not resubmit those
results in the NOCS, but may instead
submit specified information identifying
that a performance test [or performance
evaluation] was conducted and the
unit(s) and pollutant(s) that were tested.
We are also proposing to add the phrase
‘‘Unless otherwise specified by this
subpart’’ to 40 CFR 63.655(h)(9)(i) and
(ii) to make clear that test results
associated with a NOCS report are not
due within 60 days of completing the
performance test or performance
evaluation. We are also amending
several references in Table 6—General
Provisions Applicability to Subpart CC
that discuss reporting requirements for
performance tests or performance
evaluations. As the General Provisions
sections currently only address
submissions of written test reports, we
are proposing to clarify these entries in
Table 6 to recognize that performance
17 API
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test results may be written or electronic.
Specifically, we are proposing to make
these clarifications in Table 6 entries for
40 CFR 63.6(f)(3), 63.6(h)(8), 63.7(a)(2),
and 63.8(e).
We also received questions from API
and AFPM 18 on other aspects of the
electronic reporting requirements.
Industry representatives requested that
electronic reporting only be required if
all the test methods used to determine
the emissions are supported by the
Electronic Reporting Tool (ERT) (e.g.,
methods for velocity as well as pollutant
concentration). We recognize that the
ERT does not support all test methods
and that there is little value in
submitting a stack flow electronically
and the pollutant concentration in
written format or PDF. We are revising
the ERT website to clarify that
electronic reporting is not required
where the ERT does not support the test
method for the pollutant of interest.
We recognize that there are instances
when two primary pollutants may be
measured during a single performance
test, one supported by the ERT and one
not supported by the ERT. For
petroleum refineries, this occurs if the
owner or operator conducts a particulate
matter (PM) performance test coincident
with the hydrogen cyanide performance
test. Since the PM test methods
(Methods 5, 5B, and 5F) are supported
by the ERT, we require that this
performance test be submitted via the
ERT. However, testing for hydrogen
cyanide is not supported by the ERT.
The owner or operator may meet the
reporting requirement for the hydrogen
cyanide test by either including the test
report as an attachment to the ERT
submission so that both results are
submitted electronically or by
submitting the test report in hard copy
or other agreed upon format.
Industry representatives also
recommended that the requirement to
report electronically be suspended until
a reliable system is in place. We note
that the submission of ERT-formatted
performance test and performance
evaluation reports using CEDRI is fully
operational, and there are no known or
reported system issues. CEDRI accepts
all ERT version 5 report submissions
that are properly created using the ERT.
If the ERT zip file being uploaded to
CEDRI is not created from the ERT or
does not meet the file format
requirements established by the EPA,
CEDRI will not accept the file upload
and will provide the user instructions
on how to resolve the error(s). In
addition, the Central Data Exchange
(CDX) Helpdesk staff are available
18 API
and AFPM, March 28, 2017.
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during regular business hours to support
industry users in completing their
submissions electronically using CEDRI.
Any user concerns that cannot be
resolved by the CDX Helpdesk are
escalated to either EPA staff or the
application support contractors for
resolution. To date, over 3,400 ERT files
have been submitted to the EPA through
CEDRI. There have been 43 calls to the
Helpdesk for assistance. The CDX
Helpdesk resolved 34 of these calls, and
the EPA and their support contractors
resolved the remaining nine. We
encourage all users to continue to
contact the CDX Helpdesk with any
issues encountered during the
submission process.
We have also identified two broad
circumstances in which electronic
reporting extensions may be provided.
In both circumstances, the decision to
accept a claim of needing additional
time to report is within the discretion of
the Administrator, and reporting should
occur as soon as possible. In 40 CFR
63.655(h)(10)(i), we address the
situation where an extension may be
warranted due to outages of the EPA’s
CDX or CEDRI which preclude a user
from accessing the system and
submitting required reports. If either the
CDX or CEDRI is unavailable at any time
beginning 5 business days prior to the
date that the submission is due, and the
unavailability prevents a user from
submitting a report by the required date,
users may assert a claim of EPA system
outage. We consider 5 business days
prior to the reporting deadline to be an
appropriate timeframe because, if the
system is down prior to this time, users
still have 1 week to complete reporting
once the system is back online.
However, if the CDX or CEDRI is down
during the week a report is due, we
realize that this could greatly impact the
ability to submit a required report on
time. We will notify users about known
outages as far in advance as possible by
CHIEF Listserv notice, posting on the
CEDRI website, and posting on the CDX
website so that users can plan
accordingly and still meet reporting
deadlines. However, if a planned or
unplanned outage occurs and users
believe that it will affect or it has
affected their ability to comply with an
electronic reporting requirement, we
have provided a process to assert such
a claim.
Consistent with 40 CFR 63.655(h)(10),
a source may seek an extension of the
time to comply with an electronic
reporting requirement. We are
proposing to revise this provision to
address the situation where an
extension may be warranted due to a
force majeure event, which is defined as
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an event that will be or has been caused
by circumstances beyond the control of
the affected facility, its contractors, or
any entity controlled by the affected
facility that prevents them from
complying with the requirement to
submit a report electronically as
required by this rule. Examples of such
events are acts of nature, acts of war or
terrorism, or equipment failure or safety
hazards beyond the control of the
facility. If such an event occurs or is still
occurring or if there are still lingering
effects of the event in the 5 business
days prior to a submission deadline, we
are proposing a process to assert a claim
of force majeure as a basis for extending
the reporting deadline to protect refiners
from noncompliance in cases where
they cannot successfully submit a report
by the reporting deadline for reasons
outside of their control.
We received questions from API and
AFPM 19 regarding the integrity checks
required for the temperature and
pressure monitor inspections in Table
13 (40 CFR part 63, subpart CC) and in
Items 2, 4, 6, 7, 9, and 10 of Table 41
(40 CFR part 63, subpart UUU).
Commenters noted that 40 CFR
63.657(b)(4), which applies to delayed
coker pressure monitoring, indicates
that the ‘‘. . . pressure monitoring
system must be visually inspected for
integrity . . .’’ and suggested that the
table entries likewise specify that visual
inspections are required/acceptable. The
continuous parameter monitoring
system (CPMS) pressure monitoring
addressed in Tables 13 and 41 is
broader than the monitoring
requirement in 40 CFR 657(b)(4) and
visual monitoring is not required for
monitoring other systems as it is for
delayed coker pressure monitoring.
However, we agree that visual
inspections are acceptable for those
other systems, though, for those
systems, there may be other methods of
assessing integrity, such as current
meters for wiring, that are not visual. In
recognition of the fact that not all
checks will be ‘‘visual,’’ we did not
specify ‘‘visual’’ inspections in Tables
13 and 41.
In codifying the amendments to 40
CFR 63.655(i)(5), the specific
recordkeeping requirements in the
subparagraphs for regulation as it
existed prior to the revisions were not
retained in the regulations as published
by the CFR. As reflected in the
instructions to the amendments, we
intended to move the heat exchanger
recordkeeping requirements from
paragraph (i)(4) to (i)(5) and to revise the
introductory text to new paragraph (i)(5)
19 API
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(see instructions 27.j. and 27.l. in 80 FR
75247). These revisions were
incorporated into the CFR; however, the
subparagraphs, which were not being
revised, were not included in the CFR.
We are proposing to revise 40 CFR
63.655(i)(5) to include the
subparagraphs (as previously codified in
subparagraph (i)(4)) that were
inadvertently not included in the
published CFR.
Similarly, the amendments to 40 CFR
63.655(h)(5)(iii) included in the
December 2015 final rule Federal
Register document (80 FR 75247) were
not included in the regulations as
published by the CFR. As reflected in
the instructions to the amendments, we
intended for the option to use an
automated data compression recording
system to be an approved monitoring
alternative. In reviewing this
amendment, the EPA noted that 40 CFR
63.655(h)(5) specifically addresses
mechanisms for owners or operators to
request approval for alternatives to the
continuous operating parameter
monitoring and recordkeeping
provisions, while the provisions in 40
CFR 63.655(i)(3) specifically include
options already approved for CPMS.
Consistent with our intent for the use of
an automated data compression
recording system to be an approved
monitoring alternative, we are
proposing to move the paragraphs at 40
CFR 63.655(h)(5)(iii) to 40 CFR
63.655(i)(3)(ii)(C).
There are several additional revisions
that we are proposing to Refinery MACT
1 to correct typographical errors,
grammatical errors, and cross-reference
errors. Table 2 of this preamble
summarizes these editorial changes as
well as other changes as discussed in
this preamble.
TABLE 2—SUMMARY OF PROPOSED EDITORIAL AND OTHER CORRECTIONS TO REFINERY MACT 1
Provision
Proposed revision
MPV:
Last sentence in § 63.643(c) ............
§ 63.643(c)(1)(ii) ...............................
§ 63.643(c)(1)(iii) ..............................
PRD:
§ 63.648(a) .......................................
§ 63.648(c) .......................................
Last sentence in § 63.648(j)(3)(iv) ...
DCU:
§ 63.655(i)(7)(iii)(B) ..........................
§ 63.657(a)(1)(i) and (ii);
§ 63.657(a)(2)(i) and (ii).
§ 63.657(b)(5) ...................................
Fenceline:
Second sentence in § 63.658(c)(2)
and § 63.658(e).
§ 63.658(d)(1) ...................................
§ 63.658(d)(2) ...................................
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§ 63.658(e)(3)(iv) ..............................
Flares:
§ 63.670(o) .......................................
§ 63.670(j)(6) ....................................
§ 63.670(k)(3) equation term for
Qcum.
§§§ 63.670(i), (m)(2) including equation terms, and (n)(2) including
equation terms.
§ 63.670(o)(1)(ii)(B) ..........................
§§ 63.670(o)(1)(iii)(B) and (o)(3)(i) ...
Table 13, Hydrogen Analyzer Requirements for Sampling Location.
Storage Vessels:
§ 63.655(f)(1)(i)(A)(1) through (3) ....
§ 63.655(g)(2)(B)(1) ..........................
§ 63.655(h)(2)(ii) ...............................
§ 63.660(b)(1) ...................................
§ 63.660(i)(2) ....................................
Other:
Table 6, Comment for Reference
§ 63.7(h)(3).
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Replace ‘‘owner of operator’’ with ‘‘owner or operator.’’
Define the term ‘‘psig’’ as pounds per square inch gauge and remove the last occurrence of ‘‘equipment.’’
Define the term ‘‘VOC’’ as total volatile organic compounds.
Correct reference to ‘‘paragraphs (a)(1) through (2)’’ to ‘‘paragraphs (a)(1) through (3).’’ Also, correct
reference to ‘‘paragraphs (c) through (i)’’ to ‘‘paragraphs (c) through (j).’’
Correct reference to ‘‘paragraphs . . . (e) through (i) . . . ’’ to ‘‘paragraphs . . . (e) through (j) . . .’’
Add space between majeure and events.
Adjust recordkeeping requirement to the 5-minute period prior to pre-vent draining, rather than 15minute period.
Correct the temperature and pressure limits to be expressed as maximums by adding ‘‘or less’’ to
each numerical limit.
Clarify that the output of the pressure monitoring system must be reviewed only when the drum is in
service, so the provision reads, ‘‘The output of the pressure monitoring system must be reviewed
each day the unit is operated to ensure . . .’’
Replace ‘‘owner of operator’’ with ‘‘owner or operator.’’
Correct the reference to ‘‘paragraph (i)(1)’’ to ‘‘paragraph (i)(2).’’
Update the reference to Section 8.3 of Method 325A to more specifically reference Sections 8.3.1
through 8.3.3 of Method 325A.
Delete the word ‘‘an’’ in the first sentence.
Correct the reference to ‘‘paragraphs (o)(1) through (8)’’ to ‘‘paragraphs (o)(1) through (7).’’
Correct the reference to subparagraphs ‘‘(j)(6)(i) through (v)’’ to ‘‘(j)(6)(i) through (iii).’’
Correct units for Qcum to be ‘‘standard cubic feet.’’
Update the reference to ‘‘supplemental natural gas’’ to the defined term ‘‘flare supplemental gas.’’
Correct the reference to paragraph ‘‘§ 63.648(j)(5)’’ to ‘‘§ 63.648(j)(3)(ii)(A) through (E).’’ 20
Edit the paragraphs to refer to a 15-minute block averaging time relative to the smokeless design capacity of the flare.
Add ‘‘Where feasible’’ to the description of sampling location for the hydrogen analyzer.
Add a reference to the option to comply with § 63.660 in addition to compliance with § 63.646.
Add the word ‘‘area’’ to the end of the sentence consistent with the same requirement in the HON.
Correct the reference to ‘‘§ 63.1063(d)(3)’’ to ‘‘§ 63.1062(d)(3).’’
Correct the reference to ‘‘§ 63.1063(a)(2)(vii)’’ to ‘‘§ 63.1063(a)(2)(viii).’’
Delete the second use of the word ‘‘to.’’
Correct the reference ‘‘§ 63.7(g)(3)’’ to ‘‘§ 63.7(h)(3)(i).’’
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B. Clarifications and Technical
Corrections to Refinery MACT 2
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1. FCCU Provisions
In order to demonstrate compliance
with the alternative PM standard for
FCCU at 40 CFR 63.1564(a)(5)(ii), the
outlet (exhaust) gas flow rate of the
catalyst regenerator must be determined.
Refinery MACT 2 provides that owners
or operators may determine this flow
rate using a flow CPMS or the
alternative provided in 40 CFR
63.1573(a). Currently, the language in 40
CFR 63.1573(a) restricts the use of the
alternative to occasions when ‘‘the unit
does not introduce any other gas
streams into the catalyst regenerator
vent.’’ API and AFPM 21 claim that
while this restriction is appropriate for
determining the flow rate for applying
emissions limitations downstream of the
regenerator because additional gases
introduced to the vent would not be
measured using this method, it is not a
necessary constraint for determining
compliance with the alternative PM
limit. This is because the alternative PM
standard applies at the outlet of the
regenerator prior to the primary cyclone
inlet and this is the flow measured by
the alternative in 40 CFR 63.1573(a). We
agree that there should be no such
restriction when determining the outlet
flow rate to the regenerator for the
purposes of demonstrating compliance
with the alternate PM standard at 40
CFR 63.1564(a)(5)(ii), and are proposing
to amend 40 CFR 63.1573(a) to remove
that restriction.
Additionally, API and AFPM noted in
their February 1, 2016, petition for
reconsideration that the FCCU
alternative organic HAP standard for
startup, shutdown, and hot standby in
40 CFR 63.1565(a)(5)(ii) requires
maintaining the oxygen concentration in
the regenerator exhaust gas at or above
1 vol. percent (dry) (i.e., greater than or
equal to 1-percent oxygen (O2) measured
on a dry basis); however, they claim
process O2 analyzers measure O2 on a
wet basis. Therefore, the commenters
explained that they would need to take
a moisture measurement and use the
measurement to correct the measured O2
in order to demonstrate compliance
with the standard. Industry commenters
explained that this is unnecessary as an
20 A similar revision was included in the October
18, 2016, reconsideration notice and proposed rule
(81 FR 71661). In the reconsideration notice and
proposed rule, we proposed to correct the reference
to paragraph ‘‘§ 63.648(j)(5)’’ to ‘‘§ 63.648(j)(3)(ii).’’
In this proposal, we are including a more specific
reference to the subparagraphs in 40 CFR
63.648(j)(3) to clarify that the rule requires owners
and operators to evaluate the list of prevention
measures in these subparagraphs.
21 API and AFPM, March 28, 2017.
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FCCU meeting the 1-percent O2
alternative standard measured on a wet
basis will be compliant with the 1percent limit on a dry basis. We agree
that meeting the 1-percent O2 standard
on a wet basis measurement will always
mean that there is more O2 than if the
concentration value is corrected to a dry
basis. As such, a wet basis measurement
of 1-percent O2 is adequate to
demonstrate compliance with the
minimum O2 alternative limit in 40 CFR
63.1565(a)(5)(ii). Therefore, we are
proposing to amend 40 CFR
63.1565(a)(5)(ii) and Table 10 to allow
for the use of a wet O2 measurement for
demonstrating compliance with the
standard so long as it is used directly
with no correction for moisture content.
2. Other Corrections
API and AFPM commented in their
February 1, 2016, petition for
reconsideration that the amendments to
the provision for CPMS monitoring and
data collection in Refinery MACT 2 at
40 CFR 63.1572(d)(1) which do not
exclude periods of monitoring system
malfunction, associated repairs, and
quality assurance or control activities is
inconsistent with paragraph (d)(2)
which specifies that data recorded
during required quality assurance or
control activities may not be used.
Additionally, API and AFPM stated that
an analogous provision in 40 CFR
63.1572(d) for CPMS monitoring and
data collection was maintained in the
final Refinery MACT 1 at 40 CFR
63.671(a)(4). We agree that we should
maintain consistency between Refinery
MACT 1 and Refinery MACT 2
whenever possible and, in this case,
there is no good reason for the two
subparts to differ. CPMS readings taken
during periods of monitoring system
malfunctions and repairs do not provide
accurate or valid data. In order to repair
a monitoring system, the CPMS must
generally be taken offline or completely
out of service, and, therefore, there
would be no data to record. During a
monitoring system malfunction, while
there may or may not be data to record,
the malfunction will affect the accuracy
of the data. This is the reason why these
data are generally excluded from data
averages (as noted in 40 CFR 63.8(g)(5)).
Therefore, we are proposing to amend
the language in Refinery MACT 2 at 40
CFR 63.1572(d)(1) so that the language
is the same as that in Refinery MACT 1
at 40 CFR 63.671(a)(4).
The final amendments provide
alternative emission limits during
periods of startup and shutdown for
some units, such as the FCCU
alternative organic HAP standard for
startup, shutdown, and hot standby in
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40 CFR 63.1565(a)(5)(ii). API and AFPM
questioned in their February 1, 2016,
petition for reconsideration whether the
recordkeeping requirements in 40 CFR
63.1576(a)(2)(i) apply when the owners
or operators elect to comply with the
otherwise applicable emissions
limitations during periods of startup
and shutdown. Separate recordkeeping
requirements apply when a source is
subject to the otherwise applicable
emissions limits; thus, it is not
necessary for the recordkeeping
requirements in 40 CFR 63.1576(a)(2)(i)
to also apply. Therefore, we are
proposing to amend the recordkeeping
requirement in 40 CFR 63.1576(a)(2)(i)
to apply only when facilities elect to
comply with the alternative startup and
shutdown standards provided in 40 CFR
63.1564(a)(5)(ii) or 40 CFR
63.1565(a)(5)(ii) or 40 CFR
63.1568(a)(4)(ii) or (iii).
We are proposing to revise Refinery
MACT 2 to address the same issue
raised for Refinery MACT 1 regarding
the reporting of initial performance
tests. We are proposing to amend 40
CFR 63.1574(a)(3) to clarify that the
results of performance tests conducted
to demonstrate initial compliance are to
be reported by the date the NOCS report
is due (150 days from the compliance
date) whether the results are reported
using CEDRI or in hard copy as part of
the NOCS report and to clarify the
information to be included in the NOCS
if the test results are submitted through
CEDRI. Unlike Refinery MACT 1,
Refinery MACT 2 has on-going
performance test requirements. We are
proposing that the results of periodic
performance tests and the one-time
hydrogen cyanide (HCN) test required
by 40 CFR 63.1571(a)(5) and (6) must be
reported with the semi-annual
compliance reports as specified in 40
CFR 63.1575(f) instead of within 60
days of completing the performance
evaluation. Similarly, we are also
proposing to streamline reporting of the
results of performance evaluations for
continuous monitoring systems (as
provided in entry 2 to Table 43) to align
with the semi-annual compliance
reports as specified in 40 CFR
63.1575(f), rather than requiring a
separate report submittal. We are
proposing to add the phrase ‘‘Unless
otherwise specified by this subpart’’ to
40 CFR 63.1575(k)(1) and (2) to indicate
that any performance tests or
performance evaluations required to be
reported in a NOCS report or a semiannual compliance report are not
subject to the 60-day deadline specified
in these paragraphs. We are also
proposing to add 40 CFR 63.1575(l) to
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address extensions to electronic
reporting deadlines.
Similar to the revisions in Table 6 to
40 CFR part 63, subpart CC (see section
III. A.7), we are proposing to revise
selected entries in Table 44 to Subpart
UUU of Part 63—Applicability of
NESHAP General Provisions to Subpart
UUU, to clarify several sections of the
General Provisions (40 CFR part 63,
subpart A) that the reporting can be
written or electronic, the timing of these
reports is specified in 40 CFR part 63,
subpart UUU, and the subpart UUU
provisions supersede the General
Provisions. Specifically, we are
proposing to revise Table 44 entries for
40 CFR 63.6(f)(3), 63.7(h)(7)(i),
63.6(h)(8), 63.7(a)(2), 63.7(g), 63.8(e),
63.10(d)(2), 63.10(e)(1), 63.10(e)(2), and
63.10(e)(4) to explain that 40 CFR part
63, subpart UUU specifies how and
when to report the results of
performance tests or performance
evaluations.
There are several additional revisions
that we are proposing to Refinery MACT
2 to correct typographical errors,
grammatical errors, and cross-reference
errors. These editorial corrections are
summarized in Table 3 of this preamble.
TABLE 3—SUMMARY OF PROPOSED EDITORIAL AND MINOR CORRECTIONS TO REFINERY MACT 2
Provision
Proposed revision
§ 63.1564(b)(4)(iii) ...........................
§ 63.1564(c)(3) ................................
§ 63.1564(c)(4) ................................
§ 63.1564(c)(5)(iii) ...........................
§ 63.1569(c)(2) ................................
§ 63.1571(a)(5) and (6); and Table
6, Item 1.ii.
§ 63.1571(d)(1) ................................
§ 63.1571(d)(2) ................................
§ 63.1572(c)(1) ................................
Correct the reference to ‘‘paragraph (a)(1)(iii)’’ to ‘‘paragraph (a)(1)(v).’’
Correct the reference to ‘‘paragraph (a)(1)(iii)’’ to ‘‘paragraph (a)(1)(v).’’
Correct the reference to ‘‘paragraph (a)(1)(iv)’’ to ‘‘paragraph (a)(1)(vi).’’
Correct the units of measure for velocity to ft/sec.
Correct the reference to ‘‘paragraph (a)(2)’’ to ‘‘paragraph (a)(3).’’
Add ‘‘or within 60 days of startup of a new unit’’ to the compliance time for the periodic performance testing requirement for PM or Ni and to the one-time performance testing requirement for HCN.
Correct the reference to ‘‘paragraph (a)(1)(iii)’’ to ‘‘paragraph (a)(1)(v).’’
Correct the reference to ‘‘paragraph (a)(1)(iv)’’ to ‘‘paragraph (a)(1)(vi).’’
Delete duplicative sentence, ‘‘You must install, operate, and maintain each continuous parameter monitoring system according to the requirements in Table 41 of this subpart.’’
Correct the spelling of the word ‘‘continuous’’ in the table’s title.
Delete the words, ‘‘the coke burn-off rate or.’’ Correct the footnote reference from ‘‘3’’ to ‘‘1.’’
Correct the reference to ‘‘§ 60.120a(b)(1)’’ to ‘‘§ 60.102a(b)(1).’’
Correct the reference to ‘‘Equation 2 of § 63.571’’ to ‘‘Equation 1 of § 63.571, if applicable.’’
Correct the reference to ‘‘item 6.c.’’ to ‘‘item 9.c.’’ and add ‘‘if applicable’’ after reference to Equation 2 of
§ 63.571.
Correct the reference to ‘‘60.102a(b)(1)(i)’’ to ‘‘60.102a(b)(1)(ii),’’ and correct the reference to ‘‘1.0 g/kg (1.0
lb/1,000 lb)’’ to ‘‘0.5 g/kg (0.5 lb PM/1,000 lb).’’
Delete ’’ and 30% opacity’’ as this is not part of Option 1b.
Correct the compliance date to the effective date of the rule (February 1, 2016).
Table
Table
Table
Table
Table
3 ............................................
3, Item 2.c .............................
3, Items 6 through 9 .............
4, Item 9.c .............................
4, Item 10.c ...........................
Table 5, Item 3 ................................
Table 6, Item 7 ................................
Table 43, Item 2 ..............................
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C. Clarifications and Technical
Corrections to NSPS Ja
During recent implementation efforts,
it was brought to our attention that the
testing requirement in 40 CFR
60.105a(b)(2)(ii) differs from similar
requirements in 40 CFR 60.105a(d)(4),
(f)(4), and (g)(4) where we allow use of
Method 3, 3A, or 3B, both for the
performance tests and the relative
accuracy tests. The language in 40 CFR
60.105a(b)(2)(ii) does not currently
include Methods 3A and 3B (and the
alternative ANSI/ASME method for EPA
Method 3B) and mistakenly cites
Appendix A–3 rather than Appendix A–
2. We are proposing to revise 40 CFR
60.105a(b)(2)(ii), consistent with the
other similar requirements in NSPS
subpart Ja listed above, to read as
follows, ‘‘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, 3A or 3B
of appendix A–2 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981, ‘‘Flue and Exhaust Gas
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Analyses,’’ (incorporated by reference—
see § 60.17) is an acceptable alternative
to EPA Method 3B of appendix A–2 to
part 60.’’ The EPA is proposing a
corresponding change to 40 CFR
60.17(g)(14) to add 40 CFR 60.105a(b) to
the list of regulations in which this
method has been incorporated by
reference. It should be noted that
through this revision, the EPA is
proposing to include in a final EPA rule
regulatory text that includes
incorporation by reference. In
accordance with requirements of 1 CFR
51.5(a), the EPA is proposing to
incorporate by reference the ANSI/
ASME PTC 19.10–1981 test method.
The EPA has made, and will continue
to make, this document generally
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).
We also identified that the second
sentence of 40 CFR 60.106a(a)(1)(iii)
includes the following clause, ‘‘. . . and
Method 3 or 3A of appendix A–2 of part
60 for conducting the relative accuracy
evaluations’’ which is redundant to 40
CFR 60.106a(a)(1)(vi) (and again, does
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not include all three Methods). We are
proposing to delete this clause. We are
also proposing to change the word
‘‘Methods’’ to ‘‘Method’’ in the second
sentence of 40 CFR 60.106a(a)(1)(iii) to
better reflect our intent for facilities to
select a single performance evaluation
method.
IV. Summary of Cost, Environmental,
and Economic Impacts
This proposed rule is expected to
result in overall cost and burden
reductions. Specifically, the proposed
amendments expected to reduce burden
are: Revisions of the maintenance vent
provisions related to the availability of
a pure hydrogen supply for equipment
containing pyrophoric catalyst,
revisions of recordkeeping requirements
for maintenance vents associated with
equipment containing less than 72 lbs
VOC, inclusion of specific provisions
for pilot-operated and balanced bellows
PRDs, and inclusion of specific
provisions related to steam tube air
entrainment for flares. These proposed
amendments are described in detail in
sections III.A.2.b, III.A.2.d, III.A.3.c, and
III.A.5 of this preamble, respectively.
The other proposed amendments will
have an insignificant effect on the
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compliance costs associated with these
standards. Additionally, none of the
proposed amendments are projected to
appreciably impact the emissions
reductions associated with these
standards.
Some of the cost reductions
associated with this proposed rule were
not fully captured in the impacts
estimated for the December 2015 final
rule. The total capital investment cost of
the December 2015 final rule was
estimated at $283 million, $112 million
from the final amendments for storage
vessels, DCUs, and fenceline
monitoring, and $171 million from
standards for flares and PRDs. The
annualized costs of the final
amendments for storage vessels, DCUs,
and fenceline monitoring were
estimated to be approximately $13.0
million and the annualized costs of the
final standards for flares and PRDs were
estimated to be approximately $50.2
million. There were no capital costs
estimated for the maintenance vent
provisions in the December 2015 final
rule and only limited recordkeeping and
reporting costs. Furthermore, while
significant capital and operating costs
were projected for flares, we may have
underestimated the number of steamassisted flares that would also have to
demonstrate compliance with the
NHVdil operating limit.
As described previously in section
III.A.2.b of this preamble, we did not
specifically consider that some units
with pyrophoric catalyst at the refinery
would have a pure hydrogen supply and
others would not. Therefore, we did not
include costs in the December 2015
final rule impacts for refineries that
have a pure hydrogen supply to add
new piping (and possibly increase their
hydrogen production capacity) to bring
pure hydrogen to units with pyrophoric
catalyst that were not currently piped to
receive pure hydrogen. Based on
information provided by industry
petitioners, the capital investment cost
to supply pure hydrogen to pyrophoric
units that currently do not have a pure
hydrogen supply (but that are located at
refineries with a pure hydrogen supply)
is estimated to be approximately $76
million. Using a capital recovery of
0.0944 based on 20-year equipment life
and 7-percent interest, hydrogen supply
upgrades would have increased the
previously estimated annualized cost by
$7,174,400 per year. Table 4 provides
the cost reduction expected for the
proposed amendments concerning
hydrogen supply for pyrophoric units,
as well as other proposed amendments.
TABLE 4—PROJECTED IMPACTS OF THE PROPOSED AMENDMENTS TO REFINERY MACT 1
Current
estimate of
Dec 2015
rule capital
investment
costs,
million $
daltland on DSKBBV9HB2PROD with PROPOSALS2
Maintenance vents provisions for equipment with
pyrophoric catalyst ...........................................................
MPV recordkeeping requirements .......................................
PRD requirements ...............................................................
Flare monitoring for steam-assisted flares with air entrainment ..................................................................................
For the proposed amendments to the
recordkeeping requirements for
equipment containing less than 72 lbs of
VOC, the impacts in the December 2015
final rule only included one-time
planning costs for how to comply with
the maintenance vent requirements; it
was assumed that facilities would have
maintenance records for each activity,
so no additional recordkeeping burden
was estimated. According to industry
petitioners, there are numerous
activities, such as replacing pressure
transducers or tubing that would qualify
under the less than 72 lbs of VOC
provisions, but for which event-specific
records are not traditionally maintained.
Based on the per event recordkeeping
requirement for maintenance vents
using the 72 lbs VOC provision in the
December 2015 rule, we now estimate
that there would be 500 of these small
maintenance vent openings per year per
refinery and that 0.1 hour would be
required to record each individual
event, resulting in a nationwide burden
of $678,625 per year. The revisions in
the proposed rule, would only require
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Current
estimate of
Dec 2015 rule
annualized
costs,
million $/yr
Frm 00017
Estimated
annualized
cost if
proposed
rule is
implemented,
million $/yr
Reduction in
annualized
cost of refinery
standards,
million $/yr
76
0
11.1
7.17
0.678
3.33
0
0
10.0
0
0.001
3.00
7.17
0.677
0.33
130
26.9
130
23.6
3.31
records that should be part of the annual
planning assessment and records for
events not following the deinventory
procedures included in these plans. We
estimate that each facility would spend
0.1 hour for each non-conforming event
and would only have one such event
each year with an estimated nationwide
burden of $1,357 per year. Thus, the
proposed amendments are estimated to
yield savings of approximately $677,268
per year considering the actual
estimated annualized burden of the
December 2015 final rule.
We estimated the PRD requirements
in the December 2015 rule would result
in a capital investment of $11.1 million
to implement prevention measures and
flow monitoring systems on PRDs.
Combined with the recordkeeping and
reporting requirements, the annualized
cost of the PRD provisions in the
December 2015 final rule was estimated
to be $3.3 million per year. We estimate
that approximately 10 percent of PRDs
at refineries are either pilot-operated or
balanced bellows. Thus, if there is a
commensurate 10-percent decrease in
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capital
investment
cost if
proposed
rule is
implemented,
million $
Fmt 4701
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these costs based on the proposed
provisions for pilot-operated or
balanced bellows PRD, we estimate the
proposed amendments would yield a
reduction in capital investment of $1.1
million and a reduction in annualized
costs of $330,000 per year.
We estimated that the provisions for
steam-assisted flares in the December
2015 rule would result in a capital
investment of $130 million and
annualized costs of $23.6 million.
However, these costs did not include
costs to also assess compliance with the
NHVdil operating limit for those steamassisted flares that used intentional air
entrainment within the steam tubes.
There is no way to measure this air
entrainment rate, but engineering
calculations were allowed to be used.
We estimated that there were 190 steamassisted flares that received routine
flow. We estimate that 0.5 additional
hour would be required each day to
assess compliance with the NHVdil
operating limits for these flares. If all
190 steam-assisted flares were designed
for air entrainment in the steam tubes,
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this would suggest that the annualized
cost of the December 2015 final rule for
steam-assisted flares is closer to $26.9
million per year and that the proposed
amendments allowing owners or
operators of certain steam-assisted flares
with air entrainment at the flare tip to
comply only with the NHVcz operating
limits would reduce annualized costs by
approximately $3.3 million.
A detailed memorandum
documenting the estimated burden
reduction has been included in the
docket for this rulemaking (see
memorandum titled, ‘‘Impact Estimates
for the 2017 Proposed Revisions to
Refinery MACT 1,’’ in Docket ID No.
EPA–HQ–OAR–2010–0682).
V. Statutory and Executive Order
Reviews
Additional information about these
statutes and Executive Orders can be
found at https://www2.epa.gov/lawsregulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is not a significant
regulatory action and was, therefore, not
submitted to OMB for review.
daltland on DSKBBV9HB2PROD with PROPOSALS2
B. Executive Order 13771: Reducing
Regulations and Controlling Regulatory
Costs
This action is expected to be an
Executive Order 13771 deregulatory
action. Details on the estimated cost
savings of this proposed rule can be
found in EPA’s analysis of the potential
costs and benefits associated with this
action.
C. Paperwork Reduction Act (PRA)
The information collection activities
in this proposed rule have been
submitted for approval to OMB under
the PRA. The Information Collection
Request (ICR) document that the EPA
prepared has been assigned EPA ICR
number 1692.11. You can find a copy of
the ICR in the docket for this rule, and
it is briefly summarized here.
One of the proposed technical
amendments included in this notice
impacts the recordkeeping requirements
in 40 CFR part 63, subpart CC for certain
maintenance vents associated with
equipment containing less than 72 lbs
VOC as found at 40 CFR
63.655(i)(12)(iv). The new
recordkeeping requirement specifies
records used to estimate the total
quantity of VOC in the equipment and
the type and size limits of equipment
that contain less than 72 lb of VOC at
the time of the maintenance vent
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opening be maintained. As specified in
40 CFR 63.655(i)(12)(iv), additional
records are required if the deinventory
procedures were not followed for each
maintenance vent opening or if the
equipment opened exceeded the type
and size limits (i.e., 72 lbs VOC). These
additional records include 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. These records will assist
the EPA with determining compliance
with the standards set forth in 40 CFR
63.643(c)(iv).
Respondents/affected entities:
Owners or operators of existing or new
major source petroleum refineries that
are major sources of HAP emissions.
The NAICS code is 324110 for
petroleum refineries.
Respondent’s obligation to respond:
All data in the ICR that are recorded are
required by the proposed amendments
to 40 CFR part 63, subpart CC—National
Emission Standards for Hazardous Air
Pollutants for Petroleum Refineries.
Estimated number of respondents:
142.
Frequency of response: Once per year
per respondent.
Total estimated burden: 16 hours (per
year). Burden is defined at 5 CFR
1320.3(b).
Total estimated cost: $1,640 (per
year), includes $0 annualized capital or
operation and maintenance costs.
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 the EPA’s regulations in 40
CFR are listed in 40 CFR part 9.
Submit your comments on the
Agency’s need for this information, the
accuracy of the provided burden
estimates and any suggested methods
for minimizing respondent burden to
the EPA using the docket identified at
the beginning of this rule. You may also
send your ICR-related comments to
OMB’s Office of Information and
Regulatory Affairs via email to OIRA_
submission@omb.eop.gov, Attention:
Desk Officer for the EPA. Since OMB is
required to make a decision concerning
the ICR between 30 and 60 days after
receipt, OMB must receive comments no
later than May 10, 2018.
The EPA will respond to any ICRrelated comments in the final rule.
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D. Regulatory Flexibility Act (RFA)
I certify that this action will not have
a significant economic impact on a
substantial number of small entities
under the RFA. In making this
determination, the impact of concern is
any significant adverse economic
impact on small entities. An agency may
certify that a rule will not have a
significant economic impact on a
substantial number of small entities if
the rule relieves regulatory burden, has
no net burden, or otherwise has a
positive economic effect on the small
entities subject to the rule. The action
consists of amendments, clarifications,
and technical corrections which are
expected to reduce regulatory burden.
As described in section IV of this
preamble, we expect burden reduction
for: Revisions of the maintenance vent
provisions related to the availability of
a pure hydrogen supply for equipment
containing pyrophoric catalyst,
revisions of recordkeeping requirements
for maintenance vents associated with
equipment containing less than 72 lbs
VOC, inclusion of specific provisions
for pilot-operated and balanced bellows
PRDs, and inclusion of specific
provisions related to steam tube air
entrainment for flares. Furthermore, as
noted in section IV of this preamble, we
do not expect the proposed amendments
to change the expected economic impact
analysis performed for the existing rule.
We have, therefore, concluded that this
action will relieve regulatory burden for
all directly regulated small entities.
E. Unfunded Mandates Reform Act
(UMRA)
This action does not contain any
unfunded mandate as described in
UMRA, 2 U.S.C. 1531–1538, and does
not significantly or uniquely affect small
governments. The action imposes no
enforceable duty on any state, local, or
tribal governments or the private sector.
F. 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.
G. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications as specified in Executive
Order 13175. It will not have substantial
direct effect on tribal governments, on
the relationship between the federal
government and Indian tribes, or on the
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distribution of power and
responsibilities between the federal
government and Indian tribes, as
specified in Executive Order 13175.
Thus, Executive Order 13175 does not
apply to this action.
H. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
This action is not subject to Executive
Order 13045 because it is not
economically significant as defined in
Executive Order 12866, and because the
EPA does not believe the environmental
health or safety risks addressed by this
action present a disproportionate risk to
children. The proposed amendments
serve to make technical clarifications
and corrections. We expect the
proposed revisions will have an
insignificant effect on emission
reductions. Therefore, the proposed
amendments should not appreciably
increase risk for any populations.
I. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not subject to Executive
Order 13211 because it is not a
significant regulatory action under
Executive Order 12866.
daltland on DSKBBV9HB2PROD with PROPOSALS2
J. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
Part 51
This rulemaking involves technical
standards. As described in section III.C
of this preamble, the EPA proposes to
use the voluntary consensus standard
ANSI/ASME PTC 19–10–1981—Part 10
‘‘Flue and Exhaust Gas Analyses’’ as an
acceptable alternative to EPA Methods
3A and 3B for the manual procedures
only and not the instrumental
procedures. This method is available at
the American National Standards
Institute (ANSI), 1899 L Street NW, 11th
floor, Washington, DC 20036 and the
American Society of Mechanical
Engineers (ASME), Three Park Avenue,
New York, NY 10016–5990. See https://
wwww.ansi.org and https://
www.asme.org.
K. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
The EPA believes that this action does
not have disproportionately high and
adverse human health or environmental
effects on minority populations, lowincome populations, and/or indigenous
peoples, as specified in Executive Order
12898 (59 FR 7629, February 16, 1994).
The proposed amendments serve to
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make technical clarifications and
corrections. We expect the proposed
revisions will have an insignificant
effect on emission reductions.
Therefore, the proposed amendments
should not appreciably increase risk for
any populations.
List of Subjects in 40 CFR Parts 60 and
63
Environmental protection,
Administrative practice and procedures,
Air pollution control, Hazardous
substances, Incorporation by reference,
Intergovernmental relations, Reporting
and recordkeeping requirements.
Dated: March 20, 2018.
E. Scott Pruitt,
Administrator.
For the reasons stated in the
preamble, title 40, chapter I, of the Code
of Federal Regulations is proposed to be
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 A—General Provisions
2. Section 60.17 is amended by
revising paragraph (g)(14) to read as
follows:
■
Incorporations by reference.
*
*
*
*
*
(g) * * *
(14) ASME/ANSI PTC 19.10–1981,
Flue and Exhaust Gas Analyses [Part 10,
Instruments and Apparatus], (Issued
August 31, 1981), IBR approved for
§§ 60.56c(b), 60.63(f), 60.106(e),
60.104a(d), (h), (i), and (j), 60.105a(b),
(d), (f), and (g), § 60.106a(a),
§ 60.107a(a), (c), and (d), tables 1 and 3
to subpart EEEE, tables 2 and 4 to
subpart FFFF, table 2 to subpart JJJJ,
§ 60.285a(f), §§ 60.4415(a), 60.2145(s)
and (t), 60.2710(s), (t), and (w),
60.2730(q), 60.4900(b), 60.5220(b),
tables 1 and 2 to subpart LLLL, tables 2
and 3 to subpart MMMM, 60.5406(c),
60.5406a(c), 60.5407a(g), 60.5413(b),
60.5413a(b) and 60.5413a(d).
*
*
*
*
*
Subpart Ja—Standards of Performance
for Petroleum Refineries for Which
Construction, Reconstruction, or
Modification Commenced After May 14,
2007
3. Section 60.105a is amended by
revising paragraph (b)(2)(ii) to read as
follows:
■
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§ 60.105a Monitoring of emissions and
operations for fluid catalytic cracking units
(FCCU) and fluid coking units (FCU).
*
*
*
*
*
(b) * * *
(2) * * *
(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, 3A or 3B
of appendix A–2 to this part for
conducting the relative accuracy
evaluations. The method ANSI/ASME
PTC 19.10–1981, ‘‘Flue and Exhaust Gas
Analyses,’’ (incorporated by reference—
see § 60.17) is an acceptable alternative
to EPA Method 3B of appendix A–2 to
part 60.
*
*
*
*
*
■ 4. Section 60.106a is amended by
revising paragraph (a)(1)(iii) to read as
follows:
§ 60.106a Monitoring of emissions and
operations for sulfur recovery plants.
■
§ 60.17
15475
(a) * * *
(1) * * *
(iii) The owner or operator shall
conduct performance evaluations of
each SO2 monitor according to the
requirements in § 60.13(c) and
Performance Specification 2 of
appendix B to part 60. The owner or
operator shall use Method 6 or 6C of
appendix A–4 to part 60. The method
ANSI/ASME PTC 19.10–1981, ‘‘Flue
and Exhaust Gas Analyses,’’
(incorporated by reference—see § 60.17)
is an acceptable alternative to EPA
Method 6.
*
*
*
*
*
PART 63—NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS FOR SOURCE
CATEGORIES
5. The authority citation for part 63
continues to read as follows:
■
Authority: 42 U.S.C. 7401 et seq.
Subpart CC—National Emission
Standards for Hazardous Air Pollutants
From Petroleum Refineries
6. Section 63.641 is amended by:
a. Revising the definitions of ‘‘Flare
purge gas’’, ‘‘Flare supplemental gas’’
and ‘‘Relief valve’’;
■ b. Adding a new definition of
‘‘Pressure relief device’’; and
■ c. Revising paragraphs (1)(i) and (ii) of
the definition of ‘‘Reference control
technology for storage vessels.’’
The revisions and addition read as
follows:
■
■
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Definitions.
*
*
*
*
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
or for other safety reasons. 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 to improve the
heat content of combustion zone gas.
Flare supplemental gas does not include
assist air or assist steam.
*
*
*
*
*
Pressure relief device means a valve,
rupture disk, or similar device used
only to release an unplanned,
nonroutine discharge of gas from
process equipment in order to avoid
safety hazards or equipment damage. A
pressure relief device discharge can
result from an operator error, a
malfunction such as a power failure or
equipment failure, or other unexpected
cause. Such devices include
conventional, spring-actuated relief
valves, balanced bellows relief valves,
pilot-operated relief valves, rupture
disks, and breaking, buckling, or
shearing pin devices.
*
*
*
*
*
Reference control technology for
storage vessels means either:
(1) * * *
(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),
(a)(2), and (b) and § 63.660(b)(2);
(ii) An external floating roof meeting
the specifications of § 63.1063(a)(1)(ii),
(a)(2), and (b) and § 63.660(b)(2); or
*
*
*
*
*
Relief valve means a type of pressure
relief device that is designed to re-close
after the pressure relief.
*
*
*
*
*
■ 7. Section 63.643 is amended by:
■ a. Revising paragraphs (c)
introductory text, (c)(1), and (c)(1)(ii)
through (iv); and
■ b. Adding a new paragraph (c)(1)(v).
The revisions and addition read as
follows:
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*
§ 63.643 Miscellaneous process vent
provisions.
*
*
*
*
*
(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
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service. The owner or operator does not
need to designate a maintenance vent as
a Group 1 or Group 2 miscellaneous
process vent nor identify maintenance
vents in a Notification of Compliance
Status report. The owner or operator
must comply with the applicable
requirements in paragraphs (c)(1)
through (3) of this section for each
maintenance vent according to the
compliance dates specified in table 11
of this subpart, unless an extension is
requested in accordance with the
provisions in § 63.6(i).
(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 meeting requirements in
paragraphs (a)(1) or (2) of this section,
a fuel gas system, or back to the process
until one of the following conditions, as
applicable, is met.
(i) * * *
(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
pounds per square inch gauge (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) is
less than 10 percent.
(iii) The equipment served by the
maintenance vent contains less than 72
pounds of total volatile organic
compounds (VOC).
(iv) If the maintenance vent is
associated with equipment containing
pyrophoric catalyst (e.g., hydrotreaters
and hydrocrackers) and a pure hydrogen
supply is not available at the equipment
at the time of the startup, shutdown,
maintenance, or inspection activity, 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
considering all such maintenance vents
at the refinery.
(v) If, after applying best practices to
isolate and purge equipment served by
a maintenance vent, none of the
applicable criterion in paragraphs
(c)(1)(i) through (iv) can be met prior to
installing or removing a blind flange or
similar equipment blind, the pressure in
the equipment served by the
maintenance vent is reduced to 2 psig
or less, Active purging of the equipment
may be used provided the equipment
pressure at the location where purge gas
is introduced remains at 2 psig or less.
*
*
*
*
*
■ 8. Section 63.644 is amended by
revising paragraph (c) introductory text
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and adding paragraph (c)(3) to read as
follows:
§ 63.644 Monitoring provisions for
miscellaneous process vents.
*
*
*
*
*
(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), (2), or (3) 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).
*
*
*
*
*
(3) Use a cap, blind flange, plug, or a
second valve for an open-ended valve or
line following the requirements
specified in § 60.482–6(a)(2), (b) and (c).
*
*
*
*
*
■ 9. Section 63.648 is amended by:
■ a. Revising the introductory text of
paragraphs (a), (c), and (j);
■ b. Revising paragraphs (j)(3)(ii)(A) and
(E), (j)(3)(iv), (j)(3)(v) introductory text,
and (j)(4).
The revisions and additions read as
follows:
§ 63.648
Equipment leak standards.
(a) Each owner or operator of an
existing source subject to the provisions
of this subpart shall comply with the
provisions of 40 CFR part 60, subpart
VV, and paragraph (b) of this section
except as provided in paragraphs (a)(1)
through (3), and (c) through (j) of this
section. Each owner or operator of a
new source subject to the provisions of
this subpart shall comply with subpart
H of this part except as provided in
paragraphs (c) through (j) of this section.
*
*
*
*
*
(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 (j) of this
section.
*
*
*
*
*
(j) Except as specified in paragraph
(j)(4) of this section, the owner or
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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 in
organic HAP service.
*
*
*
*
*
(3) * * *
(ii) * * *
(A) Flow, temperature, liquid level
and pressure indicators with deadman
switches, monitors, or automatic
actuators. Independent, non-duplicative
systems within this category count as
separate redundant prevention
measures.
(B) * * *
(C) * * *
(D) * * *
(E) Staged relief system where initial
pressure relief device (with lower set
release pressure) discharges to a flare or
other closed vent system and control
device.
*
*
*
*
*
(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 majeure event, 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
from an affected pressure relief device
are a violation of the pressure release
management work practice standards.
*
*
*
*
*
(4) Pressure relief devices routed to a
control device. (i) 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.
(ii) If a pilot-operated pressure relief
device is used and the primary release
valve is 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 required to comply
only with paragraphs (j)(1) and (2) of
this section for the pilot discharge vent
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and is not required to comply with
paragraph (j)(3) of this section for the
pilot-operated pressure relief device.
(iii) If a balanced bellows pressure
relief device is used and the primary
release valve is 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
required to comply only with
paragraphs (j)(1) and (2) of this section
for the bonnet vent and is not required
to comply with paragraph (j)(3) of this
section for the balanced bellows
pressure relief device.
(iv) Both the closed vent system and
control device (if applicable) referenced
in paragraphs (j)(4)(i) through (iii) of
this section 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.’’
(v) 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.
*
*
*
*
*
■ 10. Section 63.655 is amended by:
■ a. Revising the introductory text of
paragraph (f);
■ b. Revising paragraphs (f)(1)(i)(A)(1)
through (3), (f)(1)(i)(B)(3), (f)(1)(i)(C)(2),
(f)(1)(iii), (f)(2), (f)(4), (f)(6), (g)(2)(B)(1)
and (g)(10) introductory text;
■ c. Redesignating paragraph (g)(10)(iii)
as (g)(10)(iv);
■ d. Adding new paragraph (g)(10)(iii);
■ e. Revising paragraph (g)(13)
introductory text and paragraphs
(h)(2)(ii);
■ f. Removing and reserving paragraph
(h)(5)(iii)(B);
■ g. Revising paragraph (h)(8);
■ h. Revising paragraphs (h)(9)(i)
introductory text and (ii) introductory
text;
■ i. Adding new paragraph (h)(10);
■ j. Revising paragraph (i)(3)(ii)(B);
■ k. Adding new paragraphs (i)(3)(ii)(C),
(i)(5)(i) through (v);
■ l. Revising paragraphs (i)(7)(iii)(B) and
(i)(11) introductory text;
■ m. Adding new paragraph (i)(11)(iv);
■ n. Revising paragraph (i)(12)
introductory text and paragraph
(i)(12)(iv); and adding new paragraph
(i)(12)(vi).
The revisions and additions read as
follows:
§ 63.655 Reporting and recordkeeping
requirements.
*
*
*
*
*
(f) Each owner or operator of a source
subject to this subpart shall submit a
Notification of Compliance Status report
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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), for storage vessels subject
to the compliance schedule specified in
§ 63.640(h)(2), and for sources listed in
Table 11 of this subpart that have a
compliance date on or after February 1,
2016. Notification of Compliance Status
reports required by § 63.640(l)(3), for
storage vessels subject to the
compliance dates specified in
§ 63.640(h)(2), and for sources listed in
Table 11 of this subpart that have a
compliance date on or after February 1,
2016 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 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) * * *
(i) * * *
(A) * * *
(1) For each Group 1 storage vessel
complying with either § 63.646 or
§ 63.660 that is not included in an
emissions average, the method of
compliance (i.e., internal floating roof,
external floating roof, or closed vent
system and control device).
(2) For storage vessels subject to the
compliance schedule specified in
§ 63.640(h)(2) that are not complying
with § 63.646 or § 63.660 as applicable,
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 or § 63.660, as applicable, and
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the Group 1 storage vessels described in
§ 63.640(l), the actual compliance date.
(B) * * *
(3) If the owner or operator elects to
submit the results of a performance test,
identification of the storage vessel and
control device for which the
performance test will be submitted, and
identification of the emission point(s)
that share the control device with the
storage vessel and for which the
performance test will be conducted. If
the performance test is submitted
electronically through the EPA’s
Compliance and Emissions Data
Reporting Interface (CEDRI) in
accordance with § 63.655(h)(9), the
process unit(s) tested, the pollutant(s)
tested, and the date that such
performance test was conducted may be
submitted in the Notification of
Compliance Status in lieu of the
performance test results. The
performance test results must be
submitted to CEDRI by the date the
Notification of Compliance Status is
submitted.
(C) * * *
(2) If a performance test is conducted
instead of a design evaluation, results of
the performance test demonstrating that
the control device achieves greater than
or equal to the required control
efficiency. A performance test
conducted prior to the compliance date
of this subpart can be used to comply
with this requirement, provided that the
test was conducted using EPA methods
and that the test conditions are
representative of current operating
practices. If the performance test is
submitted electronically through the
EPA’s Compliance and Emissions Data
Reporting Interface in accordance with
§ 63.655(h)(9), the process unit(s) tested,
the pollutant(s) tested, and the date that
such performance test was conducted
may be submitted in the Notification of
Compliance Status in lieu of the
performance test results. The
performance test results must be
submitted to CEDRI by the date the
Notification of Compliance Status is
submitted.
*
*
*
*
*
(iii) For miscellaneous process vents
controlled by control devices required
to be tested under § 63.645 of this
subpart and § 63.116(c) of subpart G of
this part, performance test results
including the information in paragraphs
(f)(1)(iii)(A) and (B) of this section.
Results of a performance test conducted
prior to the compliance date of this
subpart can be used provided that the
test was conducted using the methods
specified in § 63.645 and that the test
conditions are representative of current
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operating conditions. If the performance
test is submitted electronically through
the EPA’s Compliance and Emissions
Data Reporting Interface in accordance
with § 63.655(h)(9), the process unit(s)
tested, the pollutant(s) tested, and the
date that such performance test was
conducted may be submitted in the
Notification of Compliance Status in
lieu of the performance test results. The
performance test results must be
submitted to CEDRI by the date the
Notification of Compliance Status is
submitted.
*
*
*
*
*
(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, for data collected using test
methods supported by the EPA’s
Electronic Reporting Tool (ERT) as
listed on the EPA’s ERT website
(https://www.epa.gov/electronicreporting-air-emissions/electronicreporting-tool-ert) at the time of the test,
you must submit the results in
accordance with § 63.655(h)(9) by the
date that you submit the Notification of
Compliance Status, and you must
include the process unit(s) tested, the
pollutant(s) tested, and the date that
such performance test was conducted in
the Notification of Compliance Status.
All other performance test results must
be reported in the Notification of
Compliance Status.
*
*
*
*
*
(4) Results of any continuous
monitoring system performance
evaluations shall be included in the
Notification of Compliance Status
report, unless the results are required to
be submitted electronically by
§ 63.655(h)(9). For performance
evaluation results required to be
submitted through CEDRI, submit the
results in accordance with § 63.655(h)(9)
by the date that you submit the
Notification of Compliance Status and
include the process unit where the CMS
is installed, the parameter measured by
the CMS, and the date that the
performance evaluation was conducted
in the Notification of Compliance
Status.
*
*
*
*
*
(6) Notification of Compliance Status
reports required by § 63.640(l)(3), for
storage vessels subject to the
compliance dates specified in
§ 63.640(h)(2), and for sources listed in
Table 11 of this subpart that have a
compliance date on or after February 1,
2016 shall be submitted no later than 60
days after the end of the 6-month period
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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 or the requirements with
compliance dates on or after February 1,
2016, became effective, and may be
combined with the periodic report. Sixmonth periods shall be the same 6month periods specified in paragraph
(g) of this section. The Notification of
Compliance Status report shall include
the information specified in paragraphs
(f)(1) through (f)(5) 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, as
part of the periodic report, or in any
combination of these four. If the
required information has been
submitted before the date 60 days after
the end of the 6-month period in which
the addition of the Group 1 emission
point took place, a separate Notification
of Compliance Status report is not
required within 60 days after the end of
the 6-month period. If an owner or
operator submits the information
specified in paragraphs (f)(1) through
(f)(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.
*
*
*
*
*
(g) * * *
(2) * * *
(B) * * *
(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 area.
*
*
*
*
*
(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 (iv) of this section.
*
*
*
*
*
(iii) For pilot-operated pressure relief
devices in organic HAP service, report
each pressure release to the atmosphere
through the pilot vent that equals or
exceeds 72 pounds of VOC per day,
including duration of the pressure
release through the pilot vent and
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estimate of the mass quantity of each
organic HAP released.
*
*
*
*
*
(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;
owners or operators complying with
§ 63.643(c)(1)(v) must report each
venting event conducted under those
provisions and include an explanation
for each event as to why utilization of
this alternative was required.
*
*
*
*
*
(h) * * *
(2) * * *
(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 § 63.1063(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.
*
*
*
*
*
(8) For fenceline monitoring systems
subject to § 63.658, each owner or
operator shall submit the following
information to the EPA’s Compliance
and Emissions Data Reporting Interface
(CEDRI) on a quarterly basis. (CEDRI can
be accessed through the EPA’s Central
Data Exchange (CDX) (https://
cdx.epa.gov/). The first quarterly report
must be submitted once the owner or
operator has obtained 12 months of
data. The first quarterly report must
cover the period beginning on the
compliance date that is specified in
Table 11 of this subpart and ending on
March 31, June 30, September 30 or
December 31, whichever date is the first
date that occurs after the owner or
operator has obtained 12 months of data
(i.e., the first quarterly report will
contain between 12 and 15 months of
data). Each subsequent quarterly report
must cover one of the following
reporting periods: Quarter 1 from
January 1 through March 31; Quarter 2
from April 1 through June 30; Quarter
3 from July 1 through September 30; and
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Quarter 4 from October 1 through
December 31. Each quarterly report
must be electronically submitted no
later than 45 calendar days following
the end of the reporting period.
(i) Facility name and address.
(ii) Year and reporting quarter (i.e.,
Quarter 1, Quarter 2, Quarter 3, or
Quarter 4).
(iii) For the first reporting period and
for any reporting period in which a
passive monitor is added or moved, for
each passive monitor: the latitude and
longitude location coordinates; the
sampler name; and identification of the
type of sampler (i.e., regular monitor,
extra monitor, duplicate, field blank,
inactive). 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.
(iv) The beginning and ending dates
for each sampling period.
(v) Individual sample results for
benzene reported in units of mg/m3 for
each monitor for each sampling period
that ends during the reporting period.
Results below the method detection
limit shall be flagged as below the
detection limit and reported at the
method detection limit.
(vi) Data flags that indicate each
monitor that was skipped for the
sampling period, if the owner or
operator uses an alternative sampling
frequency under § 63.658(e)(3).
(vii) Data flags for each outlier
determined in accordance with Section
9.2 of Method 325A of appendix A of
this part. For each outlier, the owner or
operator must submit the individual
sample result of the outlier, as well as
the evidence used to conclude that the
result is an outlier.
(viii) Based on the information
provided for the individual sample
results, CEDRI will calculate the
biweekly concentration difference (Dc)
for benzene for each sampling period
and the annual average Dc for benzene
for each sampling period. The owner or
operator may change these calculated
values, but an explanation must be
provided whenever a calculated value is
changed.
(9) * * *
(i) Unless otherwise specified by this
subpart, 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.
*
*
*
*
*
(ii) Unless otherwise specified by this
subpart, within 60 days after the date of
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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.
*
*
*
*
*
(10) Extensions to electronic reporting
deadlines.
(i) If you are required to electronically
submit a report through the Compliance
and Emissions Data Reporting Interface
(CEDRI) in the EPA’s Central Data
Exchange (CDX), and due to a planned
or actual outage of either the EPA’s
CEDRI or CDX systems within the
period of time beginning 5 business
days prior to the date that the
submission is due, you will be or are
precluded from accessing CEDRI or CDX
and submitting a required report within
the time prescribed, you may assert a
claim of EPA system outage for failure
to timely comply with the reporting
requirement. You must submit
notification to the Administrator in
writing as soon as possible following the
date you first knew, or through due
diligence should have known, that the
event may cause or caused a delay in
reporting. You must provide to the
Administrator a written description
identifying the date, time and length of
the outage; a rationale for attributing the
delay in reporting beyond the regulatory
deadline to the EPA system outage;
describe the measures taken or to be
taken to minimize the delay in
reporting; and identify a date by which
you propose to report, or if you have
already met the reporting requirement at
the time of the notification, the date you
reported. In any circumstance, the
report must be submitted electronically
as soon as possible after the outage is
resolved. The decision to accept the
claim of EPA system outage and allow
an extension to the reporting deadline is
solely within the discretion of the
Administrator.
(ii) If you are required to
electronically submit a report through
CEDRI in the EPA’s CDX and a force
majeure event is about to occur, occurs,
or has occurred or there are lingering
effects from such an event within the
period of time beginning 5 business
days prior to the date the submission is
due, the owner or operator may assert a
claim of force majeure for failure to
timely comply with the reporting
requirement. For the purposes of this
paragraph, a force majeure event is
defined as an event that will be or has
been caused by circumstances beyond
the control of the affected facility, its
contractors, or any entity controlled by
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the affected facility that prevents you
from complying with the requirement to
submit a report electronically within the
time period prescribed. Examples of
such events are acts of nature (e.g.,
hurricanes, earthquakes, or floods), acts
of war or terrorism, or equipment failure
or safety hazard beyond the control of
the affected facility (e.g., large scale
power outage). If you intend to assert a
claim of force majeure, you must submit
notification to the Administrator in
writing as soon as possible following the
date you first knew, or through due
diligence should have known, that the
event may cause or caused a delay in
reporting. You must provide to the
Administrator a written description of
the force majeure event and a rationale
for attributing the delay in reporting
beyond the regulatory deadline to the
force majeure event; describe the
measures taken or to be taken to
minimize the delay in reporting; and
identify a date by which you propose to
report, or if you have already met the
reporting requirement at the time of the
notification, the date you reported. In
any circumstance, the reporting must
occur as soon as possible after the force
majeure event occurs. The decision to
accept the claim of force majeure and
allow an extension to the reporting
deadline is solely within the discretion
of the Administrator.
*
*
*
*
*
(i) * * *
(3) * * *
(ii) * * *
(B) Block average values for 1 hour or
shorter periods calculated from all
measured data values during each
period. If values are measured more
frequently than once per minute, a
single value for each minute may be
used to calculate the hourly (or shorter
period) block average instead of all
measured values; or
(C) All values that meet the set criteria
for variation from previously recorded
values using an automated data
compression recording system.
(1) The automated data compression
recording system shall be designed to:
(i) Measure the operating parameter
value at least once every hour.
(ii) Record at least 24 values each day
during periods of operation.
(iii) Record the date and time when
monitors are turned off or on.
(iv) Recognize unchanging data that
may indicate the monitor is not
functioning properly, alert the operator,
and record the incident.
(v) Compute daily average values of
the monitored operating parameter
based on recorded data.
(2) You must maintain a record of the
description of the monitoring system
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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 demonstration that
the system meets all criteria of
paragraph (i)(3)(ii)(C)(1) of this section.
*
*
*
*
*
(5) * * *
(i) Identification of all petroleum
refinery process unit heat exchangers at
the facility and the average annual HAP
concentration of process fluid or
intervening cooling fluid estimated
when developing the Notification of
Compliance Status report.
(ii) Identification of all heat exchange
systems subject to the monitoring
requirements in § 63.654 and
identification of all heat exchange
systems that are exempt from the
monitoring requirements according to
the provisions in § 63.654(b). For each
heat exchange system that is subject to
the monitoring requirements in
§ 63.654, this must include
identification of all heat exchangers
within each heat exchange system, and,
for closed-loop recirculation systems,
the cooling tower included in each heat
exchange system.
(iii) Results of the following
monitoring data for each required
monitoring event:
(A) Date/time of event.
(B) Barometric pressure.
(C) El Paso air stripping apparatus
water flow milliliter/minute (ml/min)
and air flow, ml/min, and air
temperature, °Celsius.
(D) FID reading (ppmv).
(E) Length of sampling period.
(F) Sample volume.
(G) Calibration information identified
in Section 5.4.2 of the ‘‘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 (incorporated by
reference—see § 63.14).
(iv) The date when a leak was
identified, the date the source of the
leak was identified, and the date when
the heat exchanger was repaired or
taken out of service.
(v) If a repair is delayed, the reason
for the delay, the schedule for
completing the repair, the heat exchange
exit line flow or cooling tower return
line average flow rate at the monitoring
location (in gallons/minute), and the
estimate of potential strippable
hydrocarbon emissions for each
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required monitoring interval during the
delay of repair.
*
*
*
*
*
(7) * * *
(iii) * * *
(B) The pressure or temperature of the
coke drum vessel, as applicable, for the
5-minute period prior to the pre-vent
draining.
*
*
*
*
*
(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. For each pilot-operated
pressure relief device subject to the
requirements at § 63.648(j)(4)(ii) or (iii),
the owner or operator shall keep the
records specified in paragraph (i)(11)(iv)
of this section.
*
*
*
*
*
(iv) For pilot-operated pressure relief
devices, general or release-specific
records for estimating the quantity of
VOC released from the pilot vent during
a release event, and records of
calculations used to determine the
quantity of specific HAP released for
any event or series of events in which
72 or more pounds of VOC are released
in a day.
(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 (vi) of this section.
*
*
*
*
*
(iv) If complying with the
requirements of § 63.643(c)(1)(iii),
records used to estimate the total
quantity of VOC in the equipment and
the type and size limits of equipment
that contain less than 72 pounds of VOC
at the time of maintenance vent
opening. For each maintenance vent
opening for which the deinventory
procedures specified in paragraph
(i)(12)(i) of this section are not followed
or for which the equipment opened
exceeds the type and size limits
established in the records specified in
this paragraph, 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.
*
*
*
*
*
(vi) If complying with the
requirements of § 63.643(c)(1)(v),
identification of the maintenance vent,
the process units or equipment
associated with the maintenance vent,
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records documenting actions taken to
comply with other applicable
alternatives and why utilization of this
alternative was required, the date of
maintenance vent opening, the
equipment pressure and lower explosive
limit of the vapors in the equipment at
the time of discharge, an indication of
whether active purging was performed
and the pressure of the equipment
during the installation or removal of the
blind if active purging was used, the
duration the maintenance vent was
open during the blind installation or
removal process, 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.
*
*
*
*
*
■ 11. Section 63.657 is amended by
revising paragraphs (a)(1)(i) and (ii),
(a)(2)(i) and (ii), (b)(5), and (e) to read as
follows:
daltland on DSKBBV9HB2PROD with PROPOSALS2
§ 63.657 Delayed coking unit decoking
operation standards.
(a) * * *
(1) * * *
(i) An average vessel pressure of 2
psig or less determined on a rolling 60event average; or
(ii) An average vessel temperature of
220 degrees Fahrenheit or less
determined on a rolling 60-event
average.
(2) * * *
(i) A vessel pressure of 2.0 psig or less
for each decoking event; or
(ii) A vessel temperature of 218
degrees Fahrenheit or less for each
decoking event.
*
*
*
*
*
(b) * * *
(5) The output of the pressure
monitoring system must be reviewed
each day the unit is operated 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.
*
*
*
*
*
(e) The owner or operator of a delayed
coking unit using the ‘‘water overflow’’
method of coke cooling prior to
complying with the applicable
requirements in paragraph (a) of this
section must overflow the water to a
separator or similar disengaging device
that is operated in a manner to prevent
entrainment of gases from the coke
drum vessel to the overflow water
storage tank. Gases from the separator or
disengaging device must be routed to a
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closed blowdown system or otherwise
controlled following the requirements
for a Group 1 miscellaneous process
vent. The liquid from the separator or
disengaging device must be hardpiped
to the overflow water storage tank or
similarly transported to prevent
exposure of the overflow water to the
atmosphere. The overflow water storage
tank may be an open or uncontrolled
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 subject to this
paragraph shall determine the coke
drum vessel temperature as specified in
paragraphs (c) and (d) of this section
and shall not otherwise drain or vent
the coke drum until the coke drum
vessel temperature is at or below the
applicable limits in paragraph (a)(1)(ii)
or (a)(2)(ii) of this section.
*
*
*
*
*
■ 12. Section 63.658 is amended by
revising paragraphs (c)(1), (c)(2), (c)(3),
(d)(1), (d)(2), (e) introductory text,
(e)(3)(iv), (f)(1)(i), and (f)(1)(i)(B) to read
as follows:
§ 63.658
Fenceline monitoring provisions.
*
*
*
*
*
(c) * * *
(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 vessel
loading operations, one passive monitor
should be sited on the shoreline
adjacent to the dock. For this subpart,
an additional monitor is not required if
the only emission sources within 50
meters of the monitoring boundary are
equipment leak sources satisfying all of
the conditions in paragraphs (c)(1)(i)
through (iv) of this section.
(i) The equipment leak sources in
organic HAP service within 50 meters of
the monitoring boundary are limited to
valves, pumps, connectors, sampling
connections, and open-ended lines. If
compressors, pressure relief devices, or
agitators in organic HAP service are
present within 50 meters of the
monitoring boundary, the additional
passive monitoring location specified in
Section 8.2.1.3 in Method 325A of
appendix A of this part must be used.
(ii) All equipment leak sources in gas
or light liquid service (and in organic
HAP service), including valves, pumps,
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15481
connectors, sampling connections and
open-ended lines, must be monitored
using EPA Method 21 of 40 CFR part 60,
appendix A–7 no less frequently than
quarterly with no provisions for skip
period monitoring, or according to the
provisions of 63.11(c) Alternative Work
practice for monitoring equipment for
leaks. For the purpose of this provision,
a leak is detected if the instrument
reading equals or exceeds the applicable
limits in paragraphs (c)(1)(ii)(A) through
(E) of this section:
(A) For valves, pumps or connectors
at an existing source, an instrument
reading of 10,000 ppmv.
(B) For valves or connectors at a new
source, an instrument reading of 500
ppmv.
(C) For pumps at a new source, an
instrument reading of 2,000 ppmv.
(D) For sampling connections or openended lines, an instrument reading of
500 ppmv above background.
(E) For equipment monitored
according to the Alternative Work
practice for monitoring equipment for
leaks, the leak definitions contained in
63.11 (c) (6)(i) through (iii).
(iii) All equipment leak sources in
organic HAP service, including sources
in gas, light liquid and heavy liquid
service, must be inspected using visual,
audible, olfactory, or any other
detection method at least monthly. A
leak is detected if the inspection
identifies a potential leak to the
atmosphere or if there are indications of
liquids dripping.
(iv) All leaks identified by the
monitoring or inspections specified in
paragraphs (c)(1)(ii) or (iii) of this
section must be repaired no later than
15 calendar days after it is detected with
no provisions for delay of repair. If a
repair is not completed within 15
calendar days, the additional passive
monitor specified in Section 8.2.1.3 in
Method 325A of appendix A of this part
must be used.
(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 or 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) If there are 19 or fewer monitoring
locations, the owner or operator shall
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collect at least one co-located duplicate
sample per sampling period and at least
one field blank per sampling period. If
there are 20 or more monitoring
locations, the owner or operator shall
collect at least two co-located duplicate
samples per sampling period and at
least one field blank per sampling
period. The co-located duplicates may
be collected at any of the perimeter
sampling locations.
*
*
*
*
*
(d) * * *
(1) If a near-field source correction is
used as provided in paragraph (i)(2) of
this section or if an alternative test
method is used that provides timeresolved measurements, the owner or
operator shall:
*
*
*
*
*
(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 8.3.1 through 8.3.3 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.
*
*
*
*
*
(e) The owner or operator shall use a
sampling period and sampling
frequency as specified in paragraphs
(e)(1) through (3) of this section.
*
*
*
*
*
(3) * * *
(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 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.
*
*
*
*
*
(f) * * *
(1) * * *
(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. Co-located
samples must be averaged together for
the purposes of determining the
benzene concentration for that sampling
location, and, if applicable, for
determining Dc. The owner or operator
shall adhere to the following procedures
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when one or more samples for the
sampling period are below the method
detection limit for benzene:
*
*
*
*
*
(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 and
zero as the lowest sample result when
calculating Dc.
*
*
*
*
*
■ 13. Section 63.660 is amended by
revising the undesignated introductory
text, paragraph (b) introductory text,
paragraphs (b)(1), (e) and (i)(2) 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 storing liquid with a maximum
true vapor pressure less than 76.6
kilopascals (11.0 pounds per square
inch) that is part of a new or existing
source shall comply with either the
requirements in subpart WW or SS of
this part according to the requirements
in paragraphs (a) through (i) of this
section and the owner or operator of a
Group 1 storage vessel storing liquid
with a maximum true vapor pressure
greater than or equal to 76.6 kilopascals
(11.0 pounds per square inch) that is
part of a new or existing source shall
comply with the requirements in
subpart SS of this part according to the
requirements in paragraphs (a) through
(i) of this section.
*
*
*
*
*
(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. If the
floating roof storage vessel does not
meet the requirements of
§ 63.1063(a)(2)(i) through (a)(2)(viii) as
of June 30, 2014, these requirements do
not apply until the next time the vessel
is completely emptied and degassed, or
January 30, 2026, whichever occurs
first.
(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)(viii) using a flexible
enclosure device and either a gasketed
or welded cap on the top of the
guidepole.
*
*
*
*
*
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(e) For storage vessels previously
subject to requirements in § 63.646,
initial inspection requirements in
§ 63.1063(c)(1) and (2)(i) (i.e., those
related to the initial filling of the storage
vessel) or in § 63.983(b)(1)(A), as
applicable, are not required. Failure to
perform other inspections and
monitoring required by this section
shall constitute a violation of the
applicable standard of this subpart.
*
*
*
*
*
(i) * * *
(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 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
§ 63.648 are not subject to this
paragraph (i)(2).
*
*
*
*
*
■ 14. Section 63.670 is amended by:
■ a. Revising paragraph (f);
■ b. Revising paragraphs (h)
introductory text, (h)(1), and (i)
introductory text;
■ c. Adding new paragraphs (i)(5) and
(6);
■ d. Revising paragraphs (j)(6);
■ h. Revising the definition of the Qcum
term in the equation in paragraph (k)(3);
■ i. Revising paragraph (m)(2)
introductory text;
■ j. Revising the definitions of the QNG2,
QNG1, and NHVNG terms in the equation
in paragraph (m)(2);
■ j. Revising paragraph (n)(2)
introductory text and the definitions of
the QNG2, QNG1, and NHVNG terms in the
equation in paragraph (n)(2); and
■ l. Revising paragraphs (o) introductory
text, (o)(1)(ii)(B), (o)(1)(iii)(B), and
(o)(3)(i). The revisions and additions
read as follows:
§ 63.670 Requirements for flare control
devices.
*
*
*
*
*
(f) Dilution operating limits for flares
with perimeter assist air. Except as
provided in paragraph (f)(1) of this
section, for each flare actively receiving
perimeter assist air, the owner or
operator shall operate the flare to
maintain the net heating value dilution
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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.
(1) If the only assist air provided to a
specific flare is perimeter assist air
intentionally entrained in lower and
upper steam at the flare tip and the flare
tip diameter is 9 inches or greater, the
owner or operator shall comply only
with the NHVcz operating limit in
paragraph (e) of this section for that
flare.
(2) Reserved.
*
*
*
*
*
(h) Visible emissions monitoring. The
owner or operator shall conduct an
initial visible emissions demonstration
using an observation period of 2 hours
using Method 22 at 40 CFR part 60,
appendix A–7. The initial visible
emissions demonstration should be
conducted the first time regulated
materials are routed to the flare.
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 for each day
regulated material is routed to the flare,
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
while regulated material is routed to the
flare, 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 5-minute observation period,
the observation period using Method 22
at 40 CFR part 60, appendix A–7 must
be extended to 2 hours or until 5minutes of visible emissions are
observed. Daily 5-minute Method 22
observations are not required to be
conducted for days the flare does not
receive any regulated material.
*
*
*
*
*
(i) Flare vent gas, steam assist and air
assist flow rate monitoring. The owner
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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 flare supplemental gas used.
Different flow monitoring methods may
be used to measure different gaseous
streams that make up 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. Flow monitoring system
requirements and acceptable
alternatives are provided in paragraphs
(i)(1) through (6) of this section.
*
*
*
*
*
(5) Continuously monitoring fan
speed or power and using fan curves is
an acceptable method for continuously
monitoring assist air flow rates.
(6) For perimeter assist air
intentionally entrained in lower and
upper steam, the monitored steam flow
rate and the maximum design air-tosteam volumetric flow ratio of the
entrainment system may be used to
determine the assist air flow rate.
(j) * * *
(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 (iii) of
this section.
*
*
*
*
*
(k) * * *
(3) * * *
*
*
*
*
*
Qcum = Cumulative volumetric flow over
15-minute block average period, standard
cubic feet.
*
*
*
*
*
(m) * * *
(2) Owners or operators of flares that
use the feed-forward calculation
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
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directly monitor flare supplemental gas
flow additions to the flare must
determine the 15-minute block average
NHVcz using the following equation.
*
*
*
*
*
QNG2 = Cumulative volumetric flow of flare
supplemental gas during the 15-minute block
period, scf.
QNG1 = Cumulative volumetric flow of flare
supplemental gas during the previous 15minute block period, scf. For the first 15minute block period of an event, use the
volumetric flow value for the current 15minute block period, i.e., QNG1=QNG2.
NHVNG = Net heating value of flare
supplemental gas for the 15-minute block
period determined according to the
requirements in paragraph (j)(5) of this
section, Btu/scf.
*
*
*
*
*
(n) * * *
(2) Owners or operators of flares that
use the feed-forward calculation
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 flare supplemental 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
volumetric flow of perimeter assist air,
the 15-minute block average NHVdil
parameter does not need to be
calculated.
*
*
*
*
*
QNG2 = Cumulative volumetric flow of flare
supplemental gas during the 15-minute block
period, scf.
QNG1 = Cumulative volumetric flow of flare
supplemental gas during the previous 15minute block period, scf. For the first 15minute block period of an event, use the
volumetric flow value for the current 15minute block period, i.e., QNG1 =QNG2.
NHVNG = Net heating value of flare
supplemental gas for the 15-minute block
period determined according to the
requirements in paragraph (j)(5) of this
section, Btu/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 (7) of this
section.
(1) * * *
(ii) * * *
(B) Implementation of prevention
measures listed for pressure relief
devices in § 63.648(j)(3)(ii)(A) through
(E) for each pressure relief device that
can discharge to the flare.
*
*
*
*
*
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(iii) * * *
(B) The smokeless capacity of the flare
based on a 15-minute block average and
design conditions. Note: A single value
must be provided for the smokeless
capacity of the flare.
*
*
*
*
*
(3) * * *
(i) The vent gas flow rate exceeds the
smokeless capacity of the flare based on
a 15-minute block average and visible
emissions are present from the flare for
more than 5 minutes during any 2
consecutive hours during the release
event.
*
*
*
*
*
15. Table 6 to Subpart CC is amended
by revising the entries ‘‘63.6(f)(3)’’,
‘‘63.6(h)(8)’’, 63.7(a)(2)’’, ‘‘63.7(f)’’,
‘‘63.7(h)(3)’’, and ‘‘63.8(e)’’ to read as
follows:
■
TABLE 6—GENERAL PROVISIONS APPLICABILITY TO SUBPART CC a
Reference
Applies to
subpart CC
Comment
*
*
63.6(f)(3) ...................................
Yes ..............
*
*
*
*
*
Except the cross-references to § 63.6(f)(1) and (e)(1)(i) are changed to § 63.642(n) and performance test results may be written or electronic.
*
*
63.6(h)(8) ..................................
Yes ..............
*
*
63.7(a)(2) ..................................
Yes ..............
*
*
63.7(f) .......................................
Yes ..............
*
*
63.7(h)(3) ..................................
Yes ..............
*
*
63.8(e) ......................................
Yes ..............
*
*
*
*
*
*
Except performance test results may be written or electronic.
*
*
*
*
*
*
Except that additional notification or approval is not required for alternatives directly specified in
Subpart CC.
*
*
*
*
*
Yes, except site-specific test plans shall not be required, and where § 63.7(h)(3)(i) specifies
waiver submittal date, the date shall be 90 days prior to the Notification of Compliance Status report in § 63.655(f).
*
*
*
*
Except that results are to be submitted electronically if required by § 63.655(h)(9).
*
*
*
*
*
*
*
*
Except test results must be submitted in the Notification of Compliance Status report due 150
days after compliance date, as specified in § 63.655(f) of subpart CC, unless they are required to be submitted electronically in accordance with § 63.655(h)(9). Test results required
to be submitted electronically must be submitted by the date the Notification of Compliance
Status report is submitted.
*
*
*
*
*
*
*
*
16. Table 13 to Subpart CC is
amended by revising the entry
‘‘Hydrogen analyzer’’ to read as follows:
■
TABLE 13—CALIBRATION AND QUALITY CONTROL REQUIREMENTS FOR CPMS
Minimum accuracy
requirements
Parameter
*
*
*
Hydrogen analyzer ............... ±2 percent over the concentration measured or
0.1 volume percent,
whichever is greater.
Calibration requirements
*
*
*
*
Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements should follow manufacturer’s recommendations at a minimum.
daltland on DSKBBV9HB2PROD with PROPOSALS2
Where feasible, 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 occurs.
*
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19. Section 63.1569 is amended by
revising paragraph (c)(2) to read as
follows:
Subpart UUU—National Emission
Standards for Hazardous Air Pollutants
for Petroleum Refineries: Catalytic
Cracking Units, Catalytic Reforming
Units, and Sulfur Recovery Units
■
17. Section 63.1564 is amended by
revising the first sentence in paragraphs
(b)(4)(iii), (c)(3), and (c)(4) and revising
paragraph (c)(5)(iii) to read as follows:
*
■
§ 63.1564 What are my requirements for
metal HAP emissions from catalytic
cracking units?
*
*
*
*
*
(b) * * *
(4) * * *
(iii) If you elect Option 3 in paragraph
(a)(1)(v) of this section, the Ni lb/hr
emission limit, compute your Ni
emission rate using Equation 5 of this
section and your site-specific Ni
operating limit (if you use a continuous
opacity monitoring system) using
Equations 6 and 7 of this section as
follows: * * *
*
*
*
*
*
(c) * * *
(3) If you use a continuous opacity
monitoring system and elect to comply
with Option 3 in paragraph (a)(1)(v) of
this section, determine continuous
compliance with your site-specific Ni
operating limit by using Equation 11 of
this section as follows: * * *
(4) If you use a continuous opacity
monitoring system and elect to comply
with Option 4 in paragraph (a)(1)(vi) of
this section, determine continuous
compliance with your site-specific Ni
operating limit by using Equation 12 of
this section as follows: * * *
(5) * * *
(iii) Calculating the inlet velocity to
the primary internal cyclones in feet per
second (ft/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).
*
*
*
*
*
■ 18. Section 63.1565 is amended by
revising paragraph (a)(5)(ii) to read as
follows:
daltland on DSKBBV9HB2PROD with PROPOSALS2
§ 63.1565 What are my requirements for
organic HAP emissions from catalytic
cracking units?
(a) * * *
(5) * * *
(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) or 1 volume percent
(wet basis with no moisture correction).
*
*
*
*
*
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§ 63.1569 What are my requirements for
HAP emissions from bypass lines?
*
*
*
*
(c) * * *
(2) Demonstrate continuous
compliance with the work practice
standard in paragraph (a)(3) of this
section by complying with the
procedures in your operation,
maintenance, and monitoring plan.
■ 20. Section 63.1571 is amended by
revising the paragraphs (a) introductory
text, (a)(5) introductory text and (a)(6)
introductory text, and by revising
paragraphs (d)(1) and (d)(2) to read as
follows:
§ 63.1571 How and when do I conduct a
performance test or other initial compliance
demonstration?
(a) When must I conduct a
performance test? You must conduct
initial performance tests and report the
results by no later than 150 days after
the compliance date specified for your
source in § 63.1563 and according to the
provisions in § 63.7(a)(2) and
§ 63.1574(a)(3). If you are required to do
a performance evaluation or test for a
semi-regenerative catalytic reforming
unit catalyst regenerator vent, you may
do them at the first regeneration cycle
after your compliance date and report
the results in a followup Notification of
Compliance Status report due no later
than 150 days after the test. You must
conduct additional performance tests as
specified in paragraphs (a)(5) and (6) of
this section and report the results of
these performance tests according to the
provisions in § 63.1575(f).
*
*
*
*
*
(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 or within 60 days
of startup of a new unit.
*
*
*
*
*
(6) One-time performance testing for
Hydrogen Cyanide (HCN). Conduct a
performance test for HCN from each
catalytic cracking unit no later than
August 1, 2017 or within 60 days of
startup of a new unit according to the
applicable requirements in paragraphs
(a)(6)(i) and (ii) of this section.
*
*
*
*
*
(d) * * *
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15485
(1) If you must meet the HAP metal
emission limitations in § 63.1564, you
elect the option in paragraph (a)(1)(v) in
§ 63.1564 (Ni lb/hr), 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. Section
63.1564(b)(2) allows you to adjust the
laboratory measurements of the
equilibrium catalyst Ni concentration to
the maximum level. You must make this
adjustment using Equation 1 of this
section as follows: * * *
(2) If you must meet the HAP metal
emission limitations in § 63.1564, you
elect the option in paragraph (a)(1)(vi)
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. Section
63.1564(b)(2) allows you to adjust the
laboratory measurements of the
equilibrium catalyst Ni concentration to
the maximum level. You must make this
adjustment using Equation 2 of this
section as follows: * * *
*
*
*
*
*
■ 21. Section 63.1572 is amended by
revising paragraphs (c)(1) and (d)(1) to
read as follows:
§ 63.1572 What are my monitoring
installation, operation, and maintenance
requirements?
*
*
*
*
*
(c) * * *
(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
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.
*
*
*
*
*
(d) * * *
(1) Except for monitoring
malfunctions, associated repairs, and
required quality assurance or control
activities (including as applicable,
calibration checks and required zero
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and span adjustments), you must
conduct all monitoring in continuous
operation (or collect data at all required
intervals) at all times the affected source
is operating.
*
*
*
*
*
■ 22. Section 63.1573 is amended by
revising paragraph (a)(1) introductory
text to read as follows:
§ 63.1573 What are my monitoring
alternatives?
(a) What are the approved alternatives
for measuring gas flow rate? (1) You
may use this alternative to a continuous
parameter monitoring system for the
catalytic regenerator exhaust gas flow
rate for your catalytic cracking unit if
the unit does not introduce any other
gas streams into the catalyst
regeneration vent (i.e., complete
combustion units with no additional
combustion devices). You may also use
this alternative to a continuous
parameter monitoring system for the
catalytic regenerator atmospheric
exhaust gas flow rate for your catalytic
reforming unit during the coke burn and
rejuvenation cycles if the unit operates
as a constant pressure system during
these cycles. You may also use this
alternative to a continuous parameter
monitoring system for the gas flow rate
exiting the catalyst regenerator to
determine inlet velocity to the primary
internal cyclones as required in
§ 63.1564(c)(5) regardless of the
configuration of the catalytic regenerator
exhaust vent downstream of the
regenerator (i.e., regardless of whether
or not any other gas streams are
introduced into the catalyst regeneration
vent). If you use this alternative, you
shall use the same procedure for the
performance test and for monitoring
after the performance test. You shall:
*
*
*
*
*
■ 23. Section 63.1574 is amended by
revising paragraph (a)(3)(ii) to read as
follows:
daltland on DSKBBV9HB2PROD with PROPOSALS2
§ 63.1574 What notifications must I submit
and when?
(a) * * *
(3) * * *
(ii) For each initial compliance
demonstration that includes a
performance test, you must submit the
notification of compliance status no
later than 150 calendar days after the
compliance date specified for your
affected source in § 63.1563. For data
collected using test methods supported
by the EPA’s Electronic Reporting Tool
(ERT) as listed on the EPA’s ERT
website (https://www.epa.gov/
electronic-reporting-air-emissions/
electronic-reporting-tool-ert) at the time
of the test, you must submit the results
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in accordance with § 63.1575(k)(1)(i) by
the date that you submit the Notification
of Compliance Status, and you must
include the process unit(s) tested, the
pollutant(s) tested, and the date that
such performance test was conducted in
the Notification of Compliance Status.
For performance evaluations of
continuous monitoring systems (CMS)
measuring relative accuracy test audit
(RATA) pollutants that are supported by
the EPA’s ERT as listed on the EPA’s
ERT website at the time of the
evaluation, you must submit the results
in accordance with § 63.1575(k)(2)(i) by
the date that you submit the Notification
of Compliance Status, and you must
include the process unit where the CMS
is installed, the parameter measured by
the CMS, and the date that the
performance evaluation was conducted
in the Notification of Compliance
Status. All other performance test and
performance evaluation results (i.e.,
those not supported by EPA’s ERT) must
be reported in the Notification of
Compliance Status.
*
*
*
*
*
■ 24. Section 63.1575 is amended by
revising paragraphs (f)(1), (k)(1)
introductory text and (k)(2) introductory
text, and adding paragraph (l) to read as
follows.
§ 63.1575
when?
What reports must I submit and
*
*
*
*
*
(f) * * *
(1) A copy of any performance test or
performance evaluation of a CMS done
during the reporting period on any
affected unit, if applicable. The report
must 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
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. For data
collected using test methods supported
PO 00000
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by the EPA’s Electronic Reporting Tool
(ERT) as listed on the EPA’s ERT
website (https://www.epa.gov/
electronic-reporting-air-emissions/
electronic-reporting-tool-ert) at the time
of the test, you must submit the results
in accordance with § 63.1575(k)(1)(i) by
the date that you submit the compliance
report, and instead of including a copy
of the test report in the compliance
report, you must include the process
unit(s) tested, the pollutant(s) tested,
and the date that such performance test
was conducted in the compliance
report. For performance evaluations of
CMS measuring relative accuracy test
audit (RATA) pollutants that are
supported by the EPA’s ERT as listed on
the EPA’s ERT website at the time of the
evaluation, you must submit the results
in accordance with § 63.1575(k)(2)(i) by
the date that you submit the compliance
report, and you must include the
process unit where the CMS is installed,
the parameter measured by the CMS,
and the date that the performance
evaluation was conducted in the
compliance report. All other
performance test and performance
evaluation results (i.e., those not
supported by EPA’s ERT) must be
reported in the compliance report.
*
*
*
*
*
(k) * * *
(1) Unless otherwise specified by this
subpart, 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.
*
*
*
*
*
(2) Unless otherwise specified by this
subpart, 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.
*
*
*
*
*
(l) Extensions to electronic reporting
deadlines. (1) If you are required to
electronically submit a report through
the Compliance and Emissions Data
Reporting Interface (CEDRI) in the EPA’s
Central Data Exchange (CDX), and due
to a planned or actual outage of either
the EPA’s CEDRI or CDX systems within
the period of time beginning 5 business
days prior to the date that the
submission is due, you will be or are
precluded from accessing CEDRI or CDX
and submitting a required report within
the time prescribed, you may assert a
claim of EPA system outage for failure
to timely comply with the reporting
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requirement. You must submit
notification to the Administrator in
writing as soon as possible following the
date you first knew, or through due
diligence should have known, that the
event may cause or caused a delay in
reporting. You must provide to the
Administrator a written description
identifying the date, time and length of
the outage; a rationale for attributing the
delay in reporting beyond the regulatory
deadline to the EPA system outage;
describe the measures taken or to be
taken to minimize the delay in
reporting; and identify a date by which
you propose to report, or if you have
already met the reporting requirement at
the time of the notification, the date you
reported. In any circumstance, the
report must be submitted electronically
as soon as possible after the outage is
resolved. The decision to accept the
claim of EPA system outage and allow
an extension to the reporting deadline is
solely within the discretion of the
Administrator.
(2) If you are required to
electronically submit a report through
CEDRI in the EPA’s CDX and a force
majeure event is about to occur, occurs,
or has occurred or there are lingering
effects from such an event within the
period of time beginning 5 business
days prior to the date the submission is
due, the owner or operator may assert a
claim of force majeure for failure to
timely comply with the reporting
requirement. For the purposes of this
section, a force majeure event is defined
as an event that will be or has been
caused by circumstances beyond the
control of the affected facility, its
contractors, or any entity controlled by
the affected facility that prevents you
from complying with the requirement to
submit a report electronically within the
time period prescribed. Examples of
such events are acts of nature (e.g.,
hurricanes, earthquakes, or floods), acts
of war or terrorism, or equipment failure
or safety hazard beyond the control of
the affected facility (e.g., large scale
power outage). If you intend to assert a
claim of force majeure, you must submit
notification to the Administrator in
writing as soon as possible following the
date you first knew, or through due
diligence should have known, that the
event may cause or caused a delay in
reporting. You must provide to the
Administrator a written description of
the force majeure event and a rationale
for attributing the delay in reporting
beyond the regulatory deadline to the
force majeure event; describe the
measures taken or to be taken to
minimize the delay in reporting; and
identify a date by which you propose to
report, or if you have already met the
reporting requirement at the time of the
notification, the date you reported. In
any circumstance, the reporting must
occur as soon as possible after the force
majeure event occurs. The decision to
accept the claim of force majeure and
allow an extension to the reporting
deadline is solely within the discretion
of the Administrator.
■ 25. Section 63.1576 is amended by
revising paragraph (a)(2)(i) to read as
follows:
§ 63.1576 What records must I keep, in
what form, and for how long?
(a) * * *
(2) * * *
(i) Record the date, time, and duration
of each startup and/or shutdown period
for which the facility elected to comply
with the alternative standards in
§ 63.1564(a)(5)(ii) or § 63.1565(a)(5)(ii)
or § 63.1568(a)(4)(ii) or (iii).
*
*
*
*
*
■ 26. Table 3 to Subpart UUU is
amended by revising the table title and
entries for items 2.c, 6, 7, 8 and 9 to read
as follows:
*
*
*
*
*
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 . . .
*
*
*
2. * * *
c. Wet scrubber ..................
daltland on DSKBBV9HB2PROD with PROPOSALS2
*
*
*
6. Option 1a: Elect NSPS subpart J, PM per coke burnoff 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, PM per coke burnoff limit, not subject to the NSPS for PM in 40 CFR
60.102 or 60.102a(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 60.102a(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).
*
*
*
*
*
VerDate Sep<11>2014
*
*
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.
*
*
17:14 Apr 09, 2018
Continuous parameter monitoring system to measure
and record the pressure drop across the scrubber,2
the gas flow rate entering or exiting the control device,1 and total liquid (or scrubbing liquor) flow rate
to the control device.
*
*
*
27. Table 4 to Subpart UUU of Part 63
is amended by revising the entries for
items 9.c and 10.c to read as follows:
*
*
*
*
*
■
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*
*
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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
...
You must . . .
*
Using . . .
*
According to these requirements . . .
*
*
*
*
*
9. * * *
c. Determine the equilibrium
catalyst Ni concentration.
*
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.
*
*
*
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 1 of
§ 63.1571, if applicable.
*
*
*
10. * * *
c. Determine the equilibrium
catalyst Ni concentration.
*
*
*
See item 9.c. of this table .......
*
*
*
*
*
*
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, if applicable.
*
*
*
28. Table 5 to Subpart UUU is
amended by revising the entry for item
3 to read as follows:
*
*
*
*
*
■
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 . . .
For the following emission limit . . .
*
*
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 You have already conducted a performance test to demonstrate initial
g/kg (0.5 lb PM/1,000 lb) of coke
compliance with the NSPS and the measured PM emission rate is
burn-off).
less than or equal to 0.5 g/kg (0.5 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 demonstrated compliance if . . .
*
*
*
*
29. Table 6 to Subpart UUU is
amended by revising the entries for
items 1.a.ii and 7 to read as follows:
*
*
*
*
*
daltland on DSKBBV9HB2PROD with PROPOSALS2
■
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 . . .
1. * * * ...........................................
a. * * * ...........................................
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You shall demonstrate continuous compliance by . . .
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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 . . .
ii. Conducting a performance test before August 1, 2017 or within 60
days of startup of a new unit and thereafter following the testing frequency in § 63.1571(a)(5) as applicable to your unit.
*
*
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 1.0 See item 2 of this table.
g/kg (1.0 lb PM/1,000 lb) of coke
burn-off.
*
*
*
*
*
*
*
*
30. Table 10 to Subpart UUU is
amended by revising the entry for item
3 to read as follows:
*
*
*
*
*
■
TABLE 10 TO SUBPART UUU OF PART 63—CONTINUOUS MONITORING SYSTEMS FOR ORGANIC HAP EMISSIONS FROM
CATALYTIC CRACKING UNITS
For each new or existing catalytic cracking unit . . .
*
*
3. During periods of startup, shutdown
or hot standby electing to comply with
the
operating
limit
in
§ 63.1565(a)(5)(ii).
And you use this
type of control device for your vent . .
.
*
Any .........................
You shall install, operate, and maintain this type of continuous monitoring system . . .
*
*
*
*
Continuous parameter monitoring system to measure and record the concentration by volume (wet or dry basis) of oxygen from each catalyst regenerator
vent. If measurement is made on a wet basis, you must comply with the limit
as measured (no moisture correction).
31. Table 43 to Subpart UUU is
amended by revising the entry for item
2 to read as follows:
*
*
*
*
*
■
TABLE 43 TO SUBPART UUU OF PART 63—REQUIREMENTS FOR REPORTS
You must submit . . .
The report must contain . . .
You shall submit the report . . .
*
*
2. Performance test and CEMS performance
evaluation data.
*
*
*
On and after February 1, 2016, the information
specified in § 63.1575(k)(1).
*
*
Semiannually according to the requirements in
§ 63.1575(b) and (f).
32. Table 44 to Subpart UUU is
amended by revising the entries
‘‘63.6(f)(3)’’, ‘‘63.67(h)(7)(i)’’,
‘‘63.6(h)(8)’’, ‘‘63.7(a)(2)’’, ‘‘63.7(g)’’,
‘‘63.8(e)’’, ‘‘63.10(d)(2)’’, ‘‘63.10(e)(1)–
(2)’’, and ‘‘63.10(e)(4)’’ to read as
follows:
*
*
*
*
*
■
daltland on DSKBBV9HB2PROD with PROPOSALS2
TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU
Citation
Subject
Applies to subpart UUU
Explanation
*
§ 63.6(f)(3) ..........................
*
*
............................................
*
Yes .....................................
*
*
*
Except the cross-references to § 63.6(f)(1) and (e)(1)(i)
are changed to § 63.1570(c) and this subpart specifies how and when the performance test results are
reported.
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TABLE 44 TO SUBPART UUU OF PART 63—APPLICABILITY OF NESHAP GENERAL PROVISIONS TO SUBPART UUU—
Continued
Citation
Subject
Applies to subpart UUU
Explanation
*
§ 63.6(h)(7)(i) ......................
*
*
Report COM Monitoring
Data from Performance
Test.
*
Yes .....................................
*
*
*
Except this subpart specifies how and when the performance test results are reported.
*
§ 63.6(h)(8) .........................
*
*
Determining Compliance
with Opacity/VE Standards.
*
Yes .....................................
*
*
*
Except this subpart specifies how and when the performance test results are reported.
*
§ 63.7(a)(2) .........................
*
*
Performance Test Dates ....
*
Yes .....................................
*
*
*
Except this subpart specifies that the results of initial
performance tests must be submitted within 150
days after the compliance date.
*
§ 63.7(g) .............................
*
*
Data Analysis, Recordkeeping, Reporting.
*
Yes .....................................
*
*
*
Except this subpart specifies how and when the performance test or performance evaluation results are
reported and § 63.7(g)(2) is reserved and does not
apply.
*
§ 63.8(e) .............................
*
*
CMS Performance Evaluation.
*
Yes .....................................
*
*
*
Except this subpart specifies how and when the performance evaluation results are reported.
*
§ 63.10(d)(2) .......................
*
*
Performance Test Results
*
No ......................................
*
*
*
This subpart specifies how and when the performance
test results are reported.
*
§ 63.10(e)(1)–(2) .................
*
*
Additional CMS Reports ....
*
Yes .....................................
*
*
*
Except this subpart specifies how and when the performance evaluation results are reported.
*
§ 63.10(e)(4) .......................
*
*
COMS Data Reports ..........
*
Yes .....................................
*
*
*
Except this subpart specifies how and when the performance test results are reported.
*
*
*
*
*
*
[FR Doc. 2018–06223 Filed 4–9–18; 8:45 am]
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Agencies
[Federal Register Volume 83, Number 69 (Tuesday, April 10, 2018)]
[Proposed Rules]
[Pages 15458-15490]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-06223]
[[Page 15457]]
Vol. 83
Tuesday,
No. 69
April 10, 2018
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 60 and 63
National Emission Standards for Hazardous Air Pollutants and New Source
Performance Standards: Petroleum Refinery Sector Amendments; Proposed
Rule
Federal Register / Vol. 83 , No. 69 / Tuesday, April 10, 2018 /
Proposed Rules
[[Page 15458]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2010-0682; FRL-9976-00-OAR]
RIN 2060-AT50
National Emission Standards for Hazardous Air Pollutants and New
Source Performance Standards: Petroleum Refinery Sector Amendments
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: This action proposes amendments to the National Emission
Standards for Hazardous Air Pollutants (NESHAP) Refinery MACT 1 and
Refinery MACT 2 regulations to clarify the requirements of these rules
and to make technical corrections and minor revisions to requirements
for work practice standards, recordkeeping and reporting. This action
also proposes technical corrections for the New Source Performance
Standards (NSPS) for Petroleum Refineries.
DATES: Comments. Comments must be received on or before May 25, 2018.
Under the Paperwork Reduction Act (PRA), comments on the
information collection provisions are best assured of consideration if
the Office of Management and Budget (OMB) receives a copy of your
comments on or before May 10, 2018.
Public Hearing. If a public hearing is requested by April 16, 2018,
then we will hold a public hearing on April 25, 2018 at the location
described in the ADDRESSES section. The last day to pre-register in
advance to speak at the public hearing will be April 23, 2018.
ADDRESSES: Comments. Submit your comments, identified by Docket ID No.
EPA-HQ-OAR-2010-0682, at https://www.regulations.gov. Follow the online
instructions for submitting comments. Once submitted, comments cannot
be edited or removed from Regulations.gov. Regulations.gov is our
preferred method of receiving comments. However, other submission
formats are accepted. To ship or send mail via the United States Postal
Service, use the following address: U.S. Environmental Protection
Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2010-0682, Mail
Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460. Use the
following Docket Center address if you are using express mail,
commercial delivery, hand delivery, or courier: EPA Docket Center, EPA
WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington,
DC 20004. Delivery verification signatures will be available only
during regular business hours.
Do not submit electronically any information you consider to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. See section I.C of this preamble
for instructions on submitting CBI.
The EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). For additional submission methods, the full EPA
public comment policy, information about CBI or multimedia submissions,
and general guidance on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
Public Hearing. If a public hearing is requested, it will be held
at EPA Headquarters, EPA WJC East Building, 1201 Constitution Avenue
NW, Washington, DC 20004. If a public hearing is requested, then we
will provide details about the public hearing on our website at:
https://www.epa.gov/stationary-sources-air-pollution/petroleum-refinery-sector-risk-and-technology-review-and-new-source. The EPA does
not intend to publish another document in the Federal Register
announcing any updates on the request for a public hearing. Please
contact Virginia Hunt at (919) 541-0832 or by email at
[email protected] to request a public hearing, to register to speak
at the public hearing, or to inquire as to whether a public hearing
will be held.
The EPA will make every effort to accommodate all speakers who
arrive and register. If a hearing is held at a U.S. government
facility, individuals planning to attend should be prepared to show a
current, valid state- or federal-approved picture identification to the
security staff in order to gain access to the meeting room. An expired
form of identification will not be permitted. Please note that the Real
ID Act, passed by Congress in 2005, established new requirements for
entering federal facilities. If your driver's license is issued by a
noncompliant state, you must present an additional form of
identification to enter a federal facility. Acceptable alternative
forms of identification include: Federal employee badge, passports,
enhanced driver's licenses, and military identification cards.
Additional information on the Real ID Act is available at https://www.dhs.gov/real-id-frequently-asked-questions. In addition, you will
need to obtain a property pass for any personal belongings you bring
with you. Upon leaving the building, you will be required to return
this property pass to the security desk. No large signs will be allowed
in the building, cameras may only be used outside of the building, and
demonstrations will not be allowed on federal property for security
reasons.
FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Ms. Brenda Shine, Sector Policies and Programs Division
(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) 541-0516;
and email address: [email protected]. 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, EPA WJC South Building (Mail Code
2227A), 1200 Pennsylvania Avenue NW, Washington, DC 20460; telephone
number: (202) 564-7027; and email address: [email protected].
SUPPLEMENTARY INFORMATION:
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2010-0682. All documents in the docket are
listed in the Regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., 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. Publicly available docket
materials are available either electronically in Regulations.gov or in
hard copy at the EPA Docket Center, Room 3334, EPA WJC West Building,
1301 Constitution Avenue NW, Washington, DC. The Public Reading Room is
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding
legal holidays. The telephone number for the Public Reading Room is
(202) 566-1744, and the telephone number for the EPA Docket Center is
(202) 566-1742.
Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2010-0682. The EPA's policy is that all
[[Page 15459]]
comments received will be included in the public docket without change
and may be made available online at https://www.regulations.gov,
including any personal information provided, unless the comment
includes information claimed to be CBI or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through https://www.regulations.gov or email. This type of information should be
submitted by mail as discussed in section I.C of this preamble. The
https://www.regulations.gov website is an ``anonymous access'' system,
which means the EPA will not know your identity or contact information
unless you provide it in the body of your comment. If you send an email
comment directly to the EPA without going through https://www.regulations.gov, your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the internet. If you submit an electronic
comment, the EPA recommends that you include your name and other
contact information in the body of your comment and with any disk or
CD-ROM you submit. If the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should not include
special characters or any form of encryption and be free of any defects
or viruses. For additional information about the EPA's public docket,
visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
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:
AFPM American Fuel and Petrochemical Manufacturers
API American Petroleum Institute
AWP Alternative Work Practice
CAA Clean Air Act
CBI Confidential Business Information
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
COMS continuous opacity monitoring system
CPMS continuous parameter monitoring system
CRU catalytic reforming unit
DCU delayed coking unit
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FCCU fluid catalytic cracking unit
FR Federal Register
HAP hazardous air pollutant(s)
HCN hydrogen cyanide
HON hazardous organic NESHAP
LEL lower explosive limit
MACT maximum achievable control technology
NESHAP national emission standards for hazardous air pollutants
NOCS Notification of Compliance Status
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OEL open-ended lines
OMB Office of Management and Budget
PDF portable document format
PM particulate matter
PRA Paperwork Reduction Act
PRD pressure relief device
RFA Regulatory Flexibility Act
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
Organization of this Document. The information in 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?
C. What should I consider as I prepare my comments for the EPA?
II. Background
III. What actions are we proposing?
A. Clarifications and Technical Corrections to Refinery MACT 1
B. Clarifications and Technical Corrections to Refinery MACT 2
C. Clarifications and Technical Corrections to NSPS Ja
IV. Summary of Cost, Environmental, and Economic Impacts
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR part 51
K. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations.
I. General Information
A. Does this action apply to me?
Table 1 of this preamble lists the NESHAP, NSPS, and associated
regulated industrial source categories that are the subject of this
proposal. Table 1 is not intended to be exhaustive, but rather provides
a guide for readers regarding the entities that this proposed action is
likely to affect. The proposed standards, once promulgated, will be
directly applicable to the affected sources. Federal, state, local, and
tribal government entities would not be affected by this proposed
action. As defined in the Initial List of Categories of Sources Under
Section 112(c)(1) of the Clean Air Act Amendments of 1990 (see 57 FR
31576, July 16, 1992), the Petroleum Refineries--Catalytic Cracking
(Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant
Units source category includes any facility engaged in producing
gasoline, napthas, kerosene, jet fuels, distillate fuel oils, residual
fuel oils, lubricants, or other products from crude oil or unfinished
petroleum derivatives. This category includes the following refinery
process units: Catalytic cracking (fluid and other) units, catalytic
reforming units, and sulfur plant units. The Petroleum Refineries--
Other Sources Not Distinctly Listed includes any facility engaged in
producing gasoline, napthas, kerosene, jet fuels, distillate fuel oils,
residual fuel oils, lubricants, or other products from crude oil or
unfinished petroleum derivatives. This category includes the following
refinery process units not listed in the Petroleum Refineries--
Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units,
and Sulfur Plant Units source category. The refinery process units in
this source category include, but are not limited to, thermal cracking,
vacuum distillation, crude distillation, hydroheating/hydrorefining,
isomerization, polymerization, lube oil processing, and hydrogen
production.
Table 1--NESHAP and Industrial Source Categories Affected by This
Proposed Action
------------------------------------------------------------------------
NAICS
Source category NESHAP code \1\
------------------------------------------------------------------------
Petroleum Refineries................. 40 CFR part 63, subpart 324110
CC.
40 CFR part 63, subpart
UUU.
40 CFR part 60, subpart
Ja.
------------------------------------------------------------------------
\1\ North American Industry Classification System.
[[Page 15460]]
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 action is available on the internet. Following signature by the
EPA Administrator, the EPA will post a copy of this proposed action at
https://www.epa.gov/stationary-sources-air-pollution/petroleum-refinery-sector-risk-and-technology-review-and-new-source. Following
publication in the Federal Register, the EPA will post the Federal
Register version of the proposal and key technical documents at this
same website.
A redline version of the regulatory language that incorporates the
proposed changes in this action is available in the docket for this
action (Docket ID No. EPA-HQ-OAR-2010-0682).
C. What should I consider as I prepare my comments for the EPA?
Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov or email. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
a disk or CD-ROM that you mail to the EPA, mark the outside of the disk
or CD-ROM as CBI and then identify electronically within the disk or
CD-ROM the specific information that is claimed as CBI. In addition to
one complete version of the comments that includes information claimed
as CBI, you must submit a copy of the comments that does not contain
the information claimed as CBI for inclusion in the public docket. If
you submit a CD-ROM or disk that does not contain CBI, mark the outside
of the disk or CD-ROM clearly that it does not contain CBI. Information
not marked as CBI will be included in the public docket and the EPA's
electronic public docket without prior notice. Information marked as
CBI will not be disclosed except in accordance with procedures set
forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver
information identified as CBI only to the following address: OAQPS
Document Control Officer (C404-02), OAQPS, U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
Attention Docket ID No. EPA-HQ-OAR-2010-0682.
II. Background
On December 1, 2015 (80 FR 75178), the EPA finalized amendments to
the Petroleum Refinery NESHAP in 40 CFR part 63, subparts CC and UUU,
referred to as Refinery MACT 1 and 2, respectively and the NSPS for
petroleum refineries in 40 CFR part 60, subparts J and Ja. The final
amendments to Refinery MACT 1 include a number of new requirements,
such as those for maintenance vents, pressure relief devices (PRDs),
delayed coking units (DCUs), fenceline monitoring, and flares. The
final amendments to Refinery MACT 2 include revisions to the continuous
compliance alternatives for catalytic cracking units and provisions
specific to startup and shutdown of catalytic cracking units and sulfur
recovery plants. The December 2015 action also finalized technical
corrections and clarifications to Refinery NSPS subparts J and Ja to
address issues raised by the American Petroleum Institute (API) in
their 2008 and 2012 petitions for reconsideration of the final NSPS Ja
rule that had not been previously addressed. These include corrections
and clarifications to provisions for sulfur recovery plants,
performance testing, and control device operating parameters.
In the process of implementing these new requirements, numerous
questions and issues have been identified and we are proposing
clarifications or technical amendments to address these questions and
issues. These issues were raised in petitions for reconsideration and
in separately issued letters from industry and in meetings with
industry groups.
The EPA received three separate petitions for reconsideration. Two
petitions were jointly filed by the API and American Fuel and
Petrochemical Manufacturers (AFPM). The first of these petitions was
filed on January 19, 2016, and requested an administrative
reconsideration under section 307(d)(7)(B) of the Clean Air Act (CAA)
of certain provisions of Refinery MACT 1 and 2, as promulgated in the
December 2015 final rule. Specifically, API and AFPM requested that the
EPA reconsider the maintenance vent provisions in Refinery MACT 1 for
sources constructed on or before June 30, 2014; the alternate startup,
shutdown, or hot standby standards for fluid catalytic cracking units
(FCCUs) constructed on or before June 30, 2014, in Refinery MACT 2; the
alternate startup and shutdown for sulfur recovery units constructed on
or before June 30, 2014, in Refinery MACT 2; and the new catalytic
reforming units (CRUs) purging limitations in Refinery MACT 2. The
request pertained to providing and/or clarifying the compliance time
for these sources. Based on this request and additional information
received, the EPA issued a proposal on February 9, 2016 (81 FR 6814),
and a final rule on July 13, 2016 (81 FR 45232), fully responding to
the January 19, 2016, petition for reconsideration. The second petition
from API and AFPM was filed on February 1, 2016, and outlined a number
of specific issues related to the work practice standards for PRDs and
flares, and the alternative water overflow provisions for DCUs, as well
as a number of other specific issues on other aspects of the rule. The
third petition was filed on February 1, 2016, by Earthjustice on behalf
of Air Alliance Houston, California Communities Against Toxics, the
Clean Air Council, the Coalition for a Safe Environment, the Community
In-Power and Development Association, the Del Amo Action Committee, the
Environmental Integrity Project, the Louisiana Bucket Brigade, the
Sierra Club, the Texas Environmental Justice Advocacy Services, and
Utah Physicians for a Healthy Environment. The Earthjustice petition
claimed that several aspects of the revisions to Refinery MACT 1 were
not proposed, and, thus, the public was precluded from commenting on
them during the public comment period, including: (1) Work practice
standards for PRDs and flares; (2) alternative water overflow
provisions for DCUs; (3) reduced monitoring provisions for fenceline
monitoring; and (4) adjustments to the risk assessment to account for
these new work practice standards. On June 16, 2016, the EPA sent
letters to petitioners granting reconsideration on issues where
petitioners claimed they had not been provided an opportunity to
comment. These petitions and letters granting reconsideration are
available for review in the rulemaking docket (see Docket Item Nos.
EPA-HQ-OAR-2010-0682-0860, EPA-HQ-OAR-2010-0682-0891 and EPA-HQ-OAR-
2010-0682-0892).
On October 18, 2016 (81 FR 71661), the EPA proposed for public
comment the issues for which reconsideration was granted in the June
16, 2016, letters. The EPA identified five issues in the proposal: (1)
The work practice standards for PRDs; (2) the work practice standards
for emergency flaring events; (3) the assessment of risk as modified
based on implementation of these PRD and emergency flaring work
practice standards; (4) the alternative work practice (AWP) standards
for DCUs employing the water overflow design; and (5) the provision
allowing refineries to reduce the frequency of fenceline monitoring at
sampling locations that consistently record benzene concentrations
below 0.9 micrograms per cubic meter. In that notice, the EPA also
proposed two minor clarifying amendments to correct
[[Page 15461]]
a cross referencing error and to clarify that facilities complying with
overlapping equipment leak provisions must still comply with the PRD
work practice standards in the 2015 final rule.
The February 1, 2016, API and AFPM petition for reconsideration
included a number of recommendations for technical amendments and
clarifications that were not specifically addressed in the October 18,
2016, proposal.\1\ In addition, API and AFPM asked for clarification on
various requirements of the final amendments in a July 12, 2016,
letter.\2\ The EPA addressed many of the clarification requests from
the July 2016 letter and the petition for reconsideration in a letter
issued on April 7, 2017.\3\ API and AFPM also raised additional issues
associated with the implementation of the final rule amendments in a
March 28, 2017, letter to the EPA \4\ and provided a list of
typographical errors in the rule in a January 27, 2017, meeting \5\
with the EPA. On January 10, 2018, AFPM submitted a letter containing a
comparison of the electronic CFR, CFR, the Federal Register documents,
and the redline versions of the December 2015 and October 2016
amendments to the Refinery Sector Rule noting discrepancies providing
suggestions as to how these discrepancies should be resolved.\6\ These
items are located in Docket ID No. EPA-HQ-OAR-2016-0682. This proposal
addresses many of the issues and clarifications identified by API and
AFPM in their February 2016 petition for reconsideration and their
subsequent communications with the EPA.
---------------------------------------------------------------------------
\1\ Supplemental Request for Administrative Reconsideration of
Targeted Elements of EPA's Final Rule ``Petroleum Refinery Sector
Risk and Technology Review and New Source Performance Standards;
Final Rule,'' Howard Feldman, API, and David Friedman, AFPM.
February 1, 2016. Docket Item No. EPA-HQ-OAR-2010-0682-0892.
\2\ Letter from Matt Todd, API, and David Friedman, AFPM, to
Penny Lassiter, EPA. July 12, 2016. Available in Docket ID No. EPA-
HQ-OAR-2010-0682.
\3\ Letter from Peter Tsirigotis, EPA, to Matt Todd, API, and
David Friedman, AFPM. April 7, 2017. Available at: https://www.epa.gov/stationary-sources-air-pollution/december-2015-refinery-sector-rule-response-letters-qa.
\4\ Letter from Matt Todd, API, and David Friedman, AFPM, to
Penny Lassiter, EPA. March 28, 2017. Available in Docket ID No. EPA-
HQ-OAR-2010-0682.
\5\ Meeting minutes for January 27, 2017, EPA meeting with API.
Available in Docket ID No. EPA-HQ-OAR-2010-0682.
\6\ David Friedman, ``Comparison of Official CFR and e-CFR
Postings Regarding MACT CC/UUU and NSPS Ja Postings.'' Message to
Penny Lassiter and Brenda Shine. January 10, 2018. Email.
---------------------------------------------------------------------------
III. What actions are we proposing?
A. Clarifications and Technical Corrections to Refinery MACT 1
1. Definitions
We are proposing to clarify the Refinery MACT 1 rule requirements
by revising several definitions and adding one definition.
a. Flare Purge Gas
In their March 28, 2017, letter seeking additional clarifications,
API and AFPM noted that the definition of ``flare purge gas'' could be
interpreted to preclude the flaring of purge gas that may be introduced
for safety reasons other than to prevent oxygen infiltration, such as
to prevent freezing at the flare tip.\7\ They requested that the EPA
revise the definition to include gas necessary for other safety
reasons. In the definition of the term, ``flare purge gas,'' we
included a reference to a primary reason flare purge gas is added at
the flare tip, namely to prevent oxygen infiltration, but did not
intend for refiners to interpret this as not allowing them to add flare
purge gas for other safety reasons. To reflect our intent, we are
proposing to revise the definition to clarify that flare purge gas may
also include gas needed for other safety reasons.
---------------------------------------------------------------------------
\7\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------
b. Flare Supplemental Gas
In their February 1, 2016, petition for reconsideration, API and
AFPM requested a change to the definition of ``flare supplemental gas''
on the basis that the definition's reference to ``all gas that improves
the combustion in the flare combustion zone'' could be interpreted to
include assist air and assist steam. API and AFPM noted, in contrast,
that the way the term ``flare supplemental gas'' is used throughout the
rule appears to only include gases that increase combustion efficiency
by raising the heat content of the combustion zone. This is evidenced
by the fact that the definition of flare vent gas specifically includes
flare supplemental gas and specifically excludes total steam or assist
air. Further, they claimed that the rule incorrectly assumes that
supplemental gas is always natural gas, and uses the term ``natural
gas'' in the equations, and, thus, limiting a refiner's ability to use
fuel gas as supplemental gas.
We agree that, as written, the definition could be misinterpreted
and we are proposing to revise the definition of ``flare supplemental
gas'' at 40 CFR 63.641. We also agree that we did not intend to limit
flare supplemental gas to only natural gas, so throughout the rule, we
are proposing to replace all instances of the term ``supplemental
natural gas'' with the defined term ``flare supplemental gas.'' The
specific instances of these replacements are provided in Table 2 of
this preamble (see section III.A.7).
c. Pressure Relief Device and Relief Valve
In their February 1, 2016, petition for reconsideration, API and
AFPM noted that Refinery MACT 1 interchangeably uses the term ``relief
valve'' and the term ``pressure relief device,'' and instead should be
using the term ``pressure relief device'' throughout because a relief
valve is only one type of pressure relief device. They requested that a
definition of pressure relief device be added to Refinery MACT 1 to
clarify that it includes different types of relief devices, such as
relief valves and rupture disks. We agree, and we are proposing a
definition of pressure relief device, proposing to revise the
definition of relief valve, and proposing to consistently use the term
``pressure relief device'' throughout the rule.
d. Reference Control Technology for Storage Vessels
In their February 1, 2016, petition for reconsideration, API and
AFPM noted that the Refinery MACT 1 storage vessel provisions at 40 CFR
63.660 require Group 1 storage vessels with floating roofs to comply
with all the requirements of 40 CFR part 63, subpart WW, including
requirements for fitting controls. However, the Refinery MACT 1
definition of ``reference control technology for storage vessels'' at
40 CFR 63.641 omits reference to these fitting requirements. They
requested that the EPA revise the definition in 40 CFR 63.641 of
Refinery MACT 1 to be consistent with the Refinery MACT 1 requirements
for storage vessels at 40 CFR 63.660. They also noted that the term,
``reference control technology for storage vessels,'' is never actually
used in the Refinery MACT 1 storage vessel provisions at 40 CFR 63.660.
We agree and are revising the definition of reference control
technology for storage vessels to be consistent with the storage vessel
rule requirements at 40 CFR 63.660. As it relates to storage vessels,
the only use of the term, ``reference control technology,'' is in the
Refinery MACT 1 provisions pertaining to emissions averaging in 40 CFR
63.652.
2. Miscellaneous Process Vent Provisions
Petitioners requested a number of amendments and clarifications to
the
[[Page 15462]]
requirements identifying and managing the subset of miscellaneous
process vents that result from maintenance activities.
a. Notice of Compliance Status (NOCS) Report
In their March 28, 2017, letter, API and AFPM noted that the
miscellaneous process vent provision at 40 CFR 63.643(c) does not
require an owner or operator to designate a maintenance vent as a Group
1 or Group 2 miscellaneous process vent. However, they stated that the
reporting requirements at 40 CFR 63.655(f)(1)(ii) are unclear as to
whether a NOCS report is needed for maintenance vents. We did not
intend for the maintenance vents to be included in the NOCS report
since we do not require the owner or operator to designate a
maintenance vent as a Group 1 or Group 2 miscellaneous process vent.
The rule has separate requirements for characterizing, recording, and
reporting maintenance vents in 40 CFR 63.655 (g)(13) and (h)(12);
therefore, it is not necessary to identify each and every place where
equipment may be opened for maintenance in a NOCS report. To clarify,
we are proposing to add language to 40 CFR 63.643(c) to explicitly
state that maintenance vents need not be identified in the NOCS report.
b. Availability of a Pure Hydrogen Supply for Compliance With
Maintenance Vent Provisions
Under 40 CFR 63.643(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.
Facilities generally must comply with one of three conditions prior to
venting maintenance vents to the atmosphere (40 CFR 63.643(c)(1)(i-
iii)). However, 40 CFR 63.643(c)(1)(iv) of the rule currently provides
some flexibility for maintenance vents associated with equipment
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers)
at refineries that do not have a pure hydrogen supply. This is because
catalytic reformer hydrogen (the other primary hydrogen source)
contains appreciable concentrations of light hydrocarbons which limits
the ability to reduce the lower explosive limit (LEL) to 10 percent or
less. For these vents, 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.
API and AFPM requested that the EPA reconsider the standards in 40
CFR 63.643(c)(1)(iv) for equipment containing pyrophoric catalyst,
e.g., hydrotreaters or hydrocrackers; in particular, they requested the
EPA to re-examine the phrase ``. . . at refineries with a pure hydrogen
supply.'' Specifically, they pointed out that many facilities have a
pure hydrogen supply that is not used at hydrotreaters or hydrocrackers
for a variety of reasons, including the fact that these units may be
far removed from the on-site pure hydrogen production unit and piping
the pure hydrogen supply to the unit is expensive. In addition, a
facility could have a pure hydrogen production unit that is idled or
shut down because a catalytic reforming unit produces adequate hydrogen
for the facility. Petitioners suggested that the alternative limit for
equipment containing pyrophoric catalyst should be provided whenever an
active supply of pure hydrogen is not available at the unit.
As pyrophoric units (e.g., hydrocrackers and hydrotreaters) require
hydrogen to operate, at the time we finalized the amendments, we
expected that pyrophoric units at a refinery with pure hydrogen supply
would each have a pure hydrogen supply. That is, we did not
specifically consider that some pyrophoric units at the refinery would
have a pure hydrogen supply and others would not. We established this
requirement under the authority of CAA section 112 (c)(2) and (c)(3) to
address emissions from maintenance events which had been exempted from
the process vent standards as episodic and non-routine emission sources
in order to ensure that the maximum achievable control technology
(MACT) included standards that apply at all times. We based these work
practices, including those applicable to units without a pure hydrogen
supply, on practices generally employed by the best performers.
We reviewed the recent comments received and the additional
information provided by API and AFPM.\8\ The information confirmed that
a single refinery may have many pyrophoric units, some that have a pure
hydrogen supply and some that do not have a pure hydrogen supply. Thus,
our assumption at the time we issued the final rule regarding which
units would use a pure hydrogen supply is incorrect. Thus, we are
proposing to revise the regulations such that units without a pure
hydrogen supply, even though there may be a pure hydrogen supply
somewhere else at the facility, could comply with the standard in 40
CFR 63.643(c)(1)(iv).
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\8\ Letter from Matt Todd, API, and David Friedman, AFPM, to
Penny Lassiter, EPA. August 1, 2017. Available in Docket ID No. EPA-
HQ-OAR-2010-0682.
---------------------------------------------------------------------------
Specifically, we are proposing to amend 40 CFR 63.643(c)(1)(iv) to
read (new text highlighted in bold): ``If the maintenance vent is
associated with equipment containing pyrophoric catalyst (e.g.,
hydrotreaters and hydrocrackers) and a pure hydrogen supply is not
available at the equipment at the time of the startup, shutdown,
maintenance, or inspection activity, 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.''
c. Control Requirements for Maintenance Vents
Paragraph 63.643(a) specifies that Group 1 miscellaneous process
vents must be controlled by 98 percent or to 20 parts per million by
volume or to a flare meeting the requirements in 40 CFR 63.670. This
paragraph also states in the second sentence that requirements for
maintenance vents are specified in 40 CFR 63.643(c), ``and the owner or
operator is only required to comply with the requirements in Sec.
63.643(c).'' Paragraphs (c)(1) through (3) then specify requirements
for maintenance vents. Paragraph (c)(1) requires that equipment must be
depressured to a control device, fuel gas system, or back to the
process until one of the conditions in paragraph (c)(1)(i) through (iv)
is met. In reviewing these rule requirements, the EPA noted that we did
not specify that the control device in (c)(1) must also meet
requirements in paragraph (a). The second sentence in 40 CFR 63.643(a)
could be misinterpreted to mean that a facility complying with the
maintenance vent provisions in 40 CFR 63.643(c) must only comply with
the requirements in paragraph (c) and not the control requirements in
paragraph (a) for the control device referenced by paragraph (c)(1).
The second sentence was meant to clarify that there is no obligation
for characterizing and reporting miscellaneous process vents as Group 1
and Group 2 if these are maintenance vents. However, we inadvertently
did not specify control device requirements for the control referenced
by paragraph (c)(1) in paragraph (c). In omitting these requirements,
we did not intend that the control requirement for maintenance vents
prior to atmospheric release would not be compliant with Group 1
controls as specified under 40 CFR 63.643(a). These control
requirements
[[Page 15463]]
are consistent with control requirements for other Group 1
miscellaneous process vents. In order to clarify our intent, we are
proposing to amend 40 CFR 63.643(c)(1) to read: ``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
meeting requirements in paragraphs (a)(1) or (2) of this section, a
fuel gas system, or back to the process until one of the following
conditions, as applicable, is met.''
d. Additional Maintenance Vent Alternative for Equipment Blinding
We received several requests to address equipment blinding in the
maintenance venting provisions of 40 CFR 63.643(c). Equipment blinding
is conducted to isolate equipment for maintenance activities. During
the installation of the blind flange, a flanged connection in the
equipment piping must be opened, allowing vapors in the equipment to be
released to the atmosphere. Additionally, while the piping is open, a
small amount of purge gas is typically used to ensure air (oxygen) does
not enter the process equipment. The introduction of purge gas also
results in emissions.
In their February 1, 2016, petition for reconsideration, API and
AFPM requested clarification that emissions that occur when ``opening a
flange on a CRU reactor to install a blind'' are considered emissions
from a maintenance vent rather than a CRU vent. Additionally, API
provided separate submissions with example scenarios and emissions data
for CRU vents to the EPA on September 11, 2017,\9\ and January 16,
2018.\10\ In the response to comment document supporting the December
2015 final rule (see Section 10.2 of Docket Item No. EPA-HQ-OAR-2010-
0682-0802), we noted that only ``catalytic reformer regeneration
vents'' are excluded from the definition of miscellaneous process vents
(MPV) and thereby excluded from using the maintenance vent provisions.
However, we also indicated that other CRU vents could meet the
definition of a maintenance vent (i.e., an MPV that is only used as a
result of startup, shutdown, maintenance, or inspection of equipment),
and that those vents could comply with the maintenance vent provisions
in 40 CFR 63.643(c). Specifically, we noted that the entire CRU is shut
down for semi-regenerative units and that the maintenance vent
provisions may apply in this case. We are clarifying in this preamble
that vents (separate from the depressurization and purge cycle vent(s)
covered under Refinery MACT 2) associated with opening a flange to
install a blind after complete CRU shutdown may comply with the
maintenance vent provisions.
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\9\ Matt Todd, ``Examples.'' Message to Brenda Shine. September
11, 2017. Email.
\10\ Karin C. Ritter, ``API Submitting: Flare Flow Meter
Accuracy White Paper & CRU Data & Summary.'' Message to Penny
Lassiter and Brenda Shine. January 16, 2018. Email.
---------------------------------------------------------------------------
In their March 28, 2017, letter, API and AFPM raised additional
concerns with the maintenance vent requirements and the need to address
the installation of blinds to isolate equipment for certain maintenance
activities. They claimed there may be situations where refiners may not
be able to meet the requirements in 40 CFR 63.643(c)(1)(i) through (iv)
for maintenance vents, but they must be able to conduct these
activities. For example, they may not be able to achieve the 10-percent
LEL criterion in 40 CFR 63.643(c)(1)(i) prior to atmospheric venting
because a valve used to isolate the equipment will not seat fully so
organic material may continually leak into the isolated equipment.
We agree that installing a blind to prepare equipment for
maintenance may be necessary and may not currently meet the conditions
specified in 40 CFR 63.643(c)(1). To limit the emissions during the
blind installation, we are proposing an additional condition addressed
by the maintenance vent provisions as 40 CFR 63.643(c)(1)(v). We are
proposing to require depressuring the equipment to 2 pounds (lb) per
square inch gauge (psig) or less prior to equipment opening and
maintaining pressure of the equipment where purge gas enters the
equipment at or below 2 psig during the blind flange installation. The
low allowable pressure limit will reduce the amount of process gas that
will be released during the initial equipment opening and ongoing 2-
psig pressure requirement will limit the rate of purge gas use.
Together, these requirements will limit the emissions during blind
flange installation and will result in comparable emissions allowed
under the existing maintenance vent provisions. While we acknowledge
that there may be circumstances where equipment blinding prior to
achieving the 10-percent LEL criterion may be necessary, we expect
these situations to be rare and that the owner or operator would remedy
the situation as soon as practical (e.g., replace the isolation valve
or valve seat during the next turnaround in the example provided
above). Therefore, at 40 CFR 63.643(c)(1)(v), we are proposing that
this alternative maintenance vent limit be used under those situations
where the primary limits are not achievable and blinding of the
equipment is necessary. We are proposing to require refinery owners or
operators to document each circumstance under which this provision is
used, providing an explanation why the other criteria could not be met
prior to equipment blinding and an estimate of the emissions that
occurred during the equipment blinding process.
e. Recordkeeping for Maintenance Vents on Equipment Containing Less
Than 72 Pounds (lbs) of Volatile Organic Compounds (VOC)
Under 40 CFR 63.643(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 rule specifies that prior to venting a maintenance vent to the
atmosphere, process liquids must be removed from the equipment as much
as practical and the equipment must be depressured to a control device,
fuel gas system, or back to the process until one of several
conditions, as applicable, is met (40 CFR 63.643(c)(1)). One condition
specifies that equipment containing less than 72 lbs/day of volatile
organic compounds (VOC) can be depressured directly to the atmosphere
provided that the mass of VOC in the equipment is determined and
provided that refiners keep records of the process units or equipment
associated with the maintenance vent, the date of each maintenance vent
opening, and records used to estimate the total quantity of VOC in the
equipment at the time of vent opening. Therefore, each maintenance vent
opening would be documented on an event-basis.
Industry petitioners noted that there are numerous routine
maintenance activities, such as replacing sampling line tubing or
replacing a pressure gauge, that involve potential release of very
small amounts of VOC, often less than 1 lb per day, that are well below
the 72 lbs/day of VOC threshold provided in 40 CFR 63.643(c)(1)(iii).
They claimed that documenting each individual event is burdensome and
unnecessary. We agree that documentation of each release from
maintenance vents which serve equipment containing less than 72 lbs of
VOC is not necessary, as long as there is a demonstration that the
event is compliant with the requirement that the equipment contains
less than 72 lbs of VOC. We are, therefore, proposing to revise these
provisions to require a record demonstrating that the total
[[Page 15464]]
quantity of VOC in the equipment based on the type, size, and contents
is less than 72 lbs of VOC at the time of the maintenance vent opening.
However, event-specific records are still required for each maintenance
vent opening for which the deinventory procedures were not followed or
for which the equipment opened exceeds the type and size limits
established in the records for equipment containing less than 72 pounds
of VOC.
f. Bypass Monitoring for Open-Ended Lines (OEL)
API and AFPM \11\ requested clarification of the bypass monitoring
provisions in 40 CFR 63.644(c) for open-ended lines (OEL). This
provision exempts from bypass monitoring components subject to the
Refinery MACT 1 equipment leak provisions in 40 CFR 63.648. Noting that
the provisions in 40 CFR 63.648 only apply to components in organic
hazardous air pollutant (HAP) service (i.e., greater than 5-weight
percent HAP), API and AFPM asked whether the EPA also intended to
exempt open-ended valves or lines that are in VOC service (less than 5-
weight percent HAP) and are capped and plugged in compliance with the
standards in NSPS subpart VV or VVa or the Hazardous Organic NESHAP
(HON; 40 CFR part 63, subpart H) that are substantively equivalent to
the Refinery MACT 1 equipment leak provisions in 40 CFR 63.648.
Petitioners noted that OELs in conveyances carrying a Group 1
miscellaneous process vent could be in less than 5-weight percent HAP
service, but could still be capped and plugged in accordance with
another rule, such as NSPS subpart VV or VVa or the HON. The EPA agrees
that, because the use of a cap, blind flange, plug, or second valve for
an open-ended valve or line is sufficient to prevent a bypass, the
bypass monitoring requirements in 40 CFR 63.644(c) are redundant with
NSPS subpart VV in these cases. We are proposing to amend 40 CFR
63.644(c) to make clear that open-ended valves or lines that are capped
and plugged sufficiently to meet the standards in NSPS subpart VV at 40
CFR 60.482-6(a)(2), (b) and (c), are exempt from the bypass monitoring
in 40 CFR 63.644(c).
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\11\ API and AFPM, February 1, 2016, and March 28, 2017.
---------------------------------------------------------------------------
3. Pressure Relief Device Provisions
In their February 1, 2016, petition, API and AFPM sought
reconsideration of certain aspects of the requirements for PRDs in 40
CFR 63.648(j)(1) through (5). As finalized, 40 CFR 63.648(j)(1)
provides operating requirements for PRDs in organic HAP gas or vapor
service. Section 63.648(j)(2) specifies pressure release requirements
for PRDs in organic HAP gas or vapor service. Section 63.648(j)(3)
(discussed in greater detail below) specifies requirements for pressure
release management for all PRDs in organic HAP service. Sections
63.648(j)(4) and (j)(5) provide exemptions from the requirements in
(j)(1), (2), and (3) if all releases and potential leaks from a PRD are
routed through a compliant control device or if the PRDs meet certain
criteria.
As noted above, 40 CFR 63.648(j)(3) specifies requirements for
pressure release management for all PRDs in organic HAP service,
specifically: (j)(3)(i) provides requirements for monitoring affected
PRDs; (j)(3)(ii) lists options for three redundant release prevention
measures that must be applied to affected PRDs; (j)(3)(iii) requires
root cause analysis and corrective action if an affected PRD releases
to the atmosphere as a result of a pressure release event; (j)(3)(iv)
stipulates how the facility must determine the number of release events
during the calendar year for each affected PRD; and (j)(3)(v) specifies
what release events are deemed a violation of the pressure release
management work practice standards. Section 63.648(j)(5) identifies the
types of PRDs exempted from pressure release management requirements in
(j)(3).
a. Clarification of Requirements for PRD ``in organic HAP service''
Regarding the applicability of the PRD requirements in 40 CFR
63.648(j), API and AFPM requested that we clarify whether releases
listed in paragraph 40 CFR 63.648(j)(3)(v) are limited to PRDs ``in
organic HAP service.'' The heading for 40 CFR 63.648(j)(3)(v), i.e., 40
CFR 63.648(j)(3) unambiguously states that the ``requirements specified
in paragraphs (j)(3)(i) through (v) of this section'' apply to ``all
pressure relief devices in organic HAP service'' and reflects the
Agency's intent when promulgating these provisions. Subparagraphs
(j)(3)(i) through (iv) use the phrase ``affected pressure relief
device,'' and for consistency and clarity, we are proposing to add that
phrase--``affected pressure relief device''-- to paragraph (j)(3)(v) to
clarify that the requirements in (j)(3)(v) also apply only to releases
from PRDs that are in organic HAP service.
We also are proposing to amend the introductory text in paragraph
(j). Currently, paragraph (j) states ``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.'' For consistency and clarity,
we are proposing to add ``in organic HAP service'' to the end of this
sentence to clearly indicate that the word ``all'' includes organic HAP
liquid service PRDs.
b. Redundant Release Prevention Measures in 40 CFR 63.648(j)(3)(ii)
As stated earlier, section (j)(3)(ii) lists options for three
redundant release prevention measures that must be applied to affected
PRDs. The prevention measures in (j)(3)(ii) 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; and (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.
The API and AFPM February 1, 2016, petition for reconsideration
requested clarification as to whether two prevention measures can be
selected from the list in 40 CFR 63.648(j)(3)(ii)(A). The rule does not
state that the measures in paragraph (j)(3)(ii)(A) are to be considered
a single prevention measure. These measures were grouped in
subparagraph A because of similarities they have; however, they are
separate measures. For example, a liquid level monitor discontinues the
feed to the unit when the liquid level exceeds a set point and an
overhead pressure monitor discontinues the feed to the unit if the
pressure exceeds a certain level. If these measures operate
independently, the EPA considers them two separate redundant prevention
measures--that is, if the pressure exceeds a certain set point, then
the feed to the unit is discontinued regardless of the liquid level and
vice a versa. If both the pressure limit and the liquid level must be
exceeded to trigger shutting off the feed to the unit, then that would
be considered a single prevention measure. We also note that there may
be occasions where the same type of monitor is used, but the parameter
monitored is different. For example, a temperature monitor on the feed
to a unit may be used to trigger feed shut-off to the unit, and a
separate temperature monitor may be used for the vessel
[[Page 15465]]
overhead that also triggers feed shut-off to the unit. As the
temperature monitors are not monitoring the same process stream and the
actions of the monitors are independent, these systems would be
considered two separate ``redundant prevention measures.'' To clarify
this, we are proposing to revise 40 CFR 63.648(j)(3)(ii)(A) to make
clear that independent, non-duplicative systems count as separate
redundant prevention measures.
c. Pilot-Operated PRD and Balanced Bellows PRD
In a letter dated March 28, 2017, API and AFPM requested
clarification on whether pilot-operated PRDs are required to comply
with the pressure release management provisions of 40 CFR 63.648(j)(1)
through (3).
A pilot-operated or balanced bellows PRD is often used to relieve
back pressure so that the main PRD with which it is associated can be
routed to a control device, back into the process or to the fuel gas
system. Pilot-operated and balanced bellows PRDs are primarily used for
pressure relief when the back pressure of the discharge vent may be
high or variable. Conventional pressure relief devices act on a
differential pressure between the process gas and the discharge vent.
If the discharge vent pressure increases, the vessel pressure at which
the PRD will open increases, potentially leading to vessel over-
pressurization that could cause vessel failure. For systems that have
high or variable back pressure, either balanced bellows or pilot-
operated PRDs are used. Balanced bellows PRDs use a bellow to shield
the pressure relief stem and top portion of the valve seat from the
discharge vent pressure. A balanced bellows PRD will not discharge gas
to the atmosphere during a release event, except for leaks through the
bellows vent due to bellows failure or fatigue. Pilot-operated PRDs use
a small pilot safety valve that discharges to the atmosphere to effect
actuation of the main valve or piston, which then discharges to a
control device. Balanced bellows or pilot operated PRDs are a
reasonable and necessary means to safely control the primary PRD
release.
Pilot-operated and balanced bellows PRDs are subject to the
requirements at 40 CFR 63.648(j)(1) and (2) to ensure the PRDs do not
leak and properly reseat following a release. However, based on our
understanding of pilot-operated PRDs (see memorandum, ``Pilot-operated
PRD,'' in Docket ID No. EPA-HQ-OAR-2010-0682) and balanced bellows
PRDs, we are proposing that these PRDs are not subject to the
requirements of 40 CFR 63.648(j)(3).
Section 63.648(j)(5) identifies the types of PRDs not subject to
the pressure release management requirements in (j)(3). These include
PRDs 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 (40 CFR 63.648(j)(5)(v)). In most cases, we expect
that pilot-operated PRDs would release less than 72 lbs of VOC/day.
However, this provision does not apply to all pilot vents because some
have the potential to emit greater than 72 lbs/day of VOC. Even for
releases greater than 72 lbs/day of VOC, we agree that the root cause
analysis and corrective action is not necessary because the main
release vent is not an atmospheric vent, but is instead routed to the
flare header. Unless this event contributes to a flaring event
resulting in visible emissions or velocity exceedance, the flare is
operating as intended and controlling the PRD release. Although we
expect pilot vent discharges will release less than 72 lbs/day of VOC,
to ensure these vent discharges are indeed small, and to encourage low-
emitting (e.g., non-flowing) pilot-operated PRDs, we are proposing to
amend the reporting requirements at 40 CFR 63.655(g)(10) and the
recordkeeping requirements at 40 CFR 63.655(i)(11) to retain the
requirements to report and keep records of each release to the
atmosphere through the pilot vent that exceeds 72 lbs/day of VOC,
including the duration of the pressure release through the pilot vent
and the estimate of the mass quantity of each organic HAP release.
4. Delayed Coking Unit Decoking Operation Provisions
The provisions in 40 CFR 63.657(a) require owners or operators of
DCU to depressure each coke drum to a closed blowdown system until the
coke drum vessel pressure or temperature meets the applicable limits
specified in the rule (2 psig or 220 degrees Fahrenheit for existing
sources). Special provisions are provided in 40 CFR 63.657(e) and (f)
for DCU using ``water overflow'' or ``double-quench'' method of
cooling, respectively. According to 40 CFR 63.657(e), the owner or
operator of a DCU using the ``water overflow'' method of coke cooling
must hardpipe the overflow water (i.e., via an overhead line) 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 provision in 40 CFR 63.657(e) also provides that 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.
In the October 18, 2016, reconsideration proposal, we opened the
provisions in 40 CFR 63.657(e) for public comment, but we did not
propose to amend the requirements. In response to the October 18, 2016,
reconsideration proposal, we received several comments regarding the
provisions in 40 CFR 63.657(e) for DCU using the water overflow method
of coke cooling. API and AFPM wanted clarification that the water
overflow requirements in 40 CFR 63.657(e) are only applicable if the
primary pressure or temperature limits in 40 CFR 63.657(a) were not met
prior to overflowing any water. We agree that an owner or operator of a
DCU with a water overflow design does not need to comply with the
provisions in 40 CFR 63.657(e) unless they cannot comply with the
primary pressure or temperature limits in 40 CFR 63.657(a) prior to
overflowing any water. However, if water overflow is used before the
primary pressure or temperature limits in 40 CFR 63.657(a) are met,
then the owner or operator must use ``controlled'' water overflow until
the applicable temperature limit is achieved. This is required because
the primary pressure limits are based on the vessel pressure, which is
the pressure of the gas at the top of the coke drum, and once the water
starts to overflow, we do not consider the pressure in the liquid
filled overhead line to be representative of the DCU vessel pressure.
We are proposing to clarify these points in 40 CFR 63.657(e).
In addition, environmental petitioners questioned whether the
submerged fill requirement would effectively reduce emissions if gas is
entrained into the overflow water leaving the coke drum such that the
gas could then be emitted to the air out of the overflow water storage
tank. We reviewed schematics of water overflow design DCU and found
that a typical water overflow DCU uses a separator to prevent gas
entrainment with the overflow water.\12\ The overhead gas from the
separator is routed to the DCU's closed blowdown system. The liquids
accumulate at the bottom of the separator and are then routed to a
storage vessel. We do not have information on the design of all
[[Page 15466]]
water overflow DCUs. If there are DCUs that do not use a separator, it
is possible to entrain gases with the DCU water overflow and the
submerged fill requirement would not effectively reduce emissions from
the overflow water storage tank if gas is entrained in the water
overflow. Therefore, we are also proposing to add provisions to 40 CFR
63.657(e) requiring the use of a separator or disengaging device
operated in a manner to prevent entrainment of gases from the coke drum
vessel to the overflow water storage tank. Gases from the separator
must be routed to a closed vent blowdown system or otherwise controlled
following the requirements for a Group 1 miscellaneous process vent. As
separators appear to be an integral part of the water overflow system
design, we are not projecting any capital investment or additional
operating costs associated with this proposed amendment.
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\12\ Email correspondence from Dave Pavlich, Phillips 66, to
Brenda Shine, EPA. March 6, 2017. Available in Docket ID No. EPA-HQ-
OAR-2010-0682.
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5. Fenceline Monitoring Provisions
We are proposing several amendments to the fenceline monitoring
provisions in Refinery MACT 1. Many of the proposed revisions to the
fenceline monitoring provisions are related to requirements for
reporting monitoring data.
The December 1, 2015, final rule established provisions for
monitoring fugitive emissions at refinery fencelines (40 CFR 63.658).
Under the fenceline monitoring provisions, an owner/operator must
monitor benzene concentrations around the perimeter (fenceline) of
their facility using a network of passive air monitors that contain
sorbent tubes (40 CFR 63.658(c)). Facilities are required to collect
the tubes and analyze them for benzene every 2 weeks (40 CFR
63.658(e)), but may request an alternative test method for collecting
and/or analyzing samples (40 CFR 63.658(k)). Facilities must then
calculate the difference in the highest and lowest 2-week benzene
concentrations reported at the facility fenceline, called the [Delta]c
(40 CFR 63.658(f)). If the annual rolling average [Delta]c exceeds an
action level of 9 micrograms per cubic meter ([micro]g/m\3\) benzene
(40 CFR 63.658(f)(3)), the facility must conduct a root cause analysis
and implement initial corrective action (40 CFR 63.658(g)). If the
annual rolling [Delta]c value for the next 2-week sampling period after
the initial corrective action is greater than 9 [micro]g/m\3\, or if
all corrective action measures identified require more than 45 days to
implement, the owner or operator must develop a corrective action plan
(40 CFR 63.658(h)).
The December 1, 2015, final rule included new EPA Methods 325A and
B specifying monitor siting and quantitative sample analysis
procedures. Method 325A requires an additional monitor be placed near
known VOC emission sources if the VOC emissions source is located
within 50 meters of the monitoring perimeter and the source is between
two monitors. The December 1, 2015, final rule at 40 CFR 63.658(c)(1)
provides ``known sources of VOCs . . . 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.'' In their February 1, 2016, petition for reconsideration,
API and AFPM recommended that the EPA exclude sources requiring control
under the miscellaneous process vent requirements of 40 CFR 63.643 and
the equipment leak requirements of 40 CFR 63.648 from the known sources
of VOC specified in 40 CFR 63.658(c)(1) so that these emission sources
would not trigger the need for additional fenceline monitors. In
response, we are proposing an alternative to the additional monitor
siting requirement for pumps, valves, connectors, sampling connections,
and open-ended lines sources that are actively monitored monthly using
audio, visual, or olfactory means and quarterly using Method 21 or the
AWP. We believe this is reasonable because these sources may be
insignificant and, under these circumstances, the timeframe for
discovery of a leak (1 month to 3 months) and repair (within 15 days of
discovery) is consistent with the timeframe needed to analyze a passive
monitor sample (45 days) and complete the initial root cause analysis
and corrective action (45 days after discovery). We consider this
requirement to be an adequate alternative to the additional monitor
requirement.
In their February 1, 2016, petition for reconsideration, API and
AFPM suggested that if the [Delta]c for the 2-week sampling period
following an exceedance of the annual average [Delta]c action level is
9 [micro]g/m\3\ or less, then appropriate corrective action measures
may be assumed to already be implemented and the root cause analysis
and corrective action analysis does not need to be performed. We are
clarifying in this preamble that if a root cause analysis was performed
and corrective action measures were implemented prior to the exceedance
of the annual average [Delta]c action level, then these documented
actions can be used to fulfill the root cause analysis and corrective
action requirements in 40 CFR 63.658(g) and recordkeeping in 40 CFR
63.655(i)(8)(viii).
In addition, we are proposing a revision to the reporting
requirements for the fenceline data in 40 CFR 63.655(h)(8). Consistent
with requests from API and AFPM in their February 1, 2016, petition for
reconsideration, we are proposing that the quarterly reports are to
cover calendar year quarters (i.e., Quarter 1 is from January 1 through
March 31; Quarter 2 is from April 1 through June 30; Quarter 3 is from
July 1 through September 30; and Quarter 4 is from October 1 through
December 31) rather than being directly tied to the date compliance
monitoring began. This proposed change will simplify reporting by
putting all refinery reports on the same schedule and reducing
confusion regarding when refiners are required to report, especially if
they own more than one facility.
We are also proposing several measures that would reduce burden and
clarify reporting associated with collecting and analyzing quality
assurance/quality control samples (field blanks and duplicates)
associated with the fenceline monitoring requirements in 40 CFR
63.658(c)(3). First, we are proposing to require only one field blank
per sampling period rather than two as currently required. Second, we
are proposing to decrease the number of duplicate samples that must be
collected each sample period. Instead of requiring a duplicate sample
for every 10 monitoring locations, we propose that facilities with 19
or fewer monitoring locations only be required to collect one duplicate
sample per sampling period and facilities with 20 or more sampling
locations only be required to collect two duplicate samples per
sampling period. These proposed changes reflect current practices and
the needed quality assurance/quality control of blanks and samples. The
reduced need for quality assurance/quality control samples is a result
of enhancement and refinement of sample preparation and sorbent tube
manufacturing, leading to an increase in precision of blanks and lower
levels of containments in blanks as compared to the developmental stage
of the method.
We received questions during the fenceline reporting webinars on
how to report duplicate sample results and whether duplicate sample
results are to be used in the calculation of [Delta]c. Because there
are two analytical results for each set of duplicate samples and the
final rule was unclear on how to report these results, facilities were
uncertain whether they should choose one of the two results for use in
the calculation of
[[Page 15467]]
[Delta]c or whether the results should be averaged. In order to clarify
how the results of the duplicate sample analyses are to be used, we are
proposing to require that duplicate samples be averaged together to
determine the sampling location's benzene concentration for the
purposes of calculating [Delta]c.
Consistent with the requirements in 40 CFR 63.658(k) for requesting
an alternative test method for collecting and/or analyzing samples, we
are proposing to revise the Table 6 entry for 40 CFR 63.7(f) to
indicate that 40 CFR 63.7(f) applies except that alternatives directly
specified in 40 CFR part 63, subpart CC do not require additional
notification to the Administrator or the approval of the Administrator.
We also are proposing editorial revisions to the fenceline monitoring
section; these proposed revisions are included in Table 2 in section
III.A.7 of this preamble.
6. Flare Control Device Provisions
API and AFPM requested clarification in a December 1, 2016, letter
to EPA \13\ regarding assist steam line designs that entrain air into
the lower or upper steam at the flare tip. The industry representatives
noted that many of the steam-assisted flare lines have this type of air
entrainment and likely were part of the dataset analyzed to develop the
standards established in the 2015 final rule for steam-assisted flares.
API and AFPM, therefore, maintain that these flares should not be
considered to have assist air, and that they are appropriately and
adequately regulated under the final standards for steam-assisted
flares. Because flares with assist air are required to comply with both
a combustion zone net heating value (NHVcz) and a net
heating value dilution parameter (NHVdil), there is
increased burden in having to comply with two operating parameters, and
API and AFPM contend that this burden is unnecessary.
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\13\ Letter from Matt Todd, API, and David Friedman, AFPM, to
Penny Lassiter, EPA. December 1, 2016. Available in Docket ID No.
EPA-HQ-OAR-2010-0682.
---------------------------------------------------------------------------
Assist air is defined to mean all air intentionally 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 air includes premix assist air and perimeter assist
air. Assist air does not include the surrounding ambient air. Air
entrainment through steam nozzles is intentionally introduced prior to
or at the flare tip and, therefore, it is considered assist air.
However, if this is the only assist air introduced prior to or at the
flare tip, it is reasonable in most cases for the owner or operator to
only need to comply with the NHVcz operating limit. This is
because an exceedance of the NHVcz operating limit would
also cause an exceedance of the NHVdil operating limit in
many cases.
We calculated the amount of air that must be entrained in the steam
to cause a flare meeting the NHVcz operating limit of 270
British thermal units per standard cubic foot (Btu/scf) to be below the
NHVdil operating limit of 22 Btu per square foot (Btu/
ft\2\). The NHVdil parameter is a function of flare tip
diameter. For flare tips with an effective tip diameter of 9 inches or
more, there are no flare tip steam induction designs that can entrain
enough assist air to cause a flare operator to have a deviation of the
NHVdil operating limit without first deviating from the
NHVcz operating limit. Therefore, we are proposing to allow
owners or operators of flares whose only assist air is from perimeter
assist air entrained in lower and upper steam at the flare tip and with
a flare tip diameter of 9 inches or greater to comply only with the
NHVcz operating limit.
Steam-assisted flares with perimeter assist air and an effective
tip diameter of less than 9 inches would remain subject to the
requirement to account for the amount of assist air intentionally
entrained within the calculation of NHVdil. We recognize
that this assist air cannot be directly measured, but the quantity of
air entrained is dependent on the assist steam rate and the design of
the steam tube's air entrainment system. We are proposing to add
provisions to specify that owners or operators of these smaller
diameter steam-assisted flares use the steam flow rate and the maximum
design air-to-steam ratio of the steam tube's air entrainment system
for determining the flow rate of this assist air. Using the maximum
design ratio will tend to over-estimate the assist air flow rate, which
is conservative with respect to ensuring compliance with the
NHVdil operating limit.
In addition to these revisions, for air assisted flares, we also
are providing clarification on determining air flow rates. While we
specifically provided for the use of engineering calculations for
determining the flow rate, we received questions in the February 1,
2016, petition as to whether or not this allowed the use of fan curves
for determining air assist flow rates. In the December 2015 final rule
in the introductory paragraph of 40 CFR 63.670(i), we stated that
continuously monitoring fan speed or power and using fan curves is an
acceptable method for continuously monitoring assist air flow rates. To
further clarify this point, we are proposing to include specific
provisions for continuously monitoring fan speed or power and using fan
curves for determining assist air flow rates.
In response to the February 1, 2016, petition for reconsideration
from API and AFPM, we are also proposing to clarify the requirements
for conducting visible emissions monitoring. API and AFPM raised a
concern that the current language in 40 CFR 63.670(h) is unclear and
could be interpreted to require facilities to flare regulated materials
in order to conduct the required visible emissions monitoring. We
recognize that many flares are used only during startup, shutdown, or
emergency events and we agree that it is not reasonable to require
refiners to flare regulated materials intentionally in order to conduct
a visible emissions compliance demonstration. We are proposing to
clarify that the initial 2-hour visible emissions demonstration should
be conducted the first time regulated materials are routed to the
flare. We are also proposing to clarify 40 CFR 63.670(h)(1) to provide
that the daily 5-minute observations must only be conducted on days the
flare receives regulated material and that the additional visible
emissions monitoring is specific to cases when visible emissions are
observed while regulated material is routed to the flare.
API and AFPM requested in their February 1, 2016, petition for
reconsideration that we specify the averaging period for establishing
the limit for the smokeless capacity of the flare and that it be a 15-
minute average consistent with other flow parameters and velocity
requirements. Owners or operators would use the cumulative flow rate
and/or flare tip velocity determined according to 40 CFR 63.670(k) for
assessing exceedances of the smokeless capacity, and this flow rate is
specifically determined on a 15-minute block average. Consistent with
these requirements, we are proposing to clarify, at 40 CFR
63.670(o)(1)(iii)(B), that the owner or operator must establish the
smokeless capacity of the flare in a 15-minute block average and at 40
CFR 63.670(o)(3)(i) that the exceedance of the smokeless capacity of
the flare is based on a 15-minute block average. We are also correcting
an error in the units for the cumulative volumetric flow used in the
flare tip velocity equation in 40 CFR
[[Page 15468]]
63.670(k)(3). We are revising the units to specify standard cubic feet
rather than actual cubic feet consistent with the cumulative volumetric
flow monitoring requirements in 40 CFR 63.670(i)(1) and as stated in
our response to public comments (Docket Item No. EPA-HQ-OAR-2010-0682-
0802) in the discussion under 3.3.5.-Velocity Limit and Calculation
Method. These specific edits are included in the summary of editorial
corrections provided in Table 2 of his preamble (see section III.A.7).
Industry stakeholders with input from vendors have also made
submissions 14 15 16 expressing concerns over the ability to
meet the flare vent gas flow rate minimum accuracy requirements in 40
CFR 60.107a(f)(1)(ii) and in Table 13 of 40 CFR part 63, subpart CC
when vent streams have low molecular weight. These requirements specify
an accuracy of 20 percent of the flow rate at velocities
ranging from 0.1 to 1 foot per second and an accuracy of 5
percent of the flow rate for velocities greater than 1 foot per second.
Stakeholders stated that the accuracy requirements could not be met for
some historical flow events when molecular weight of the flare vent gas
was low, including: plant power outages caused by weather, compressor
surges due to lightning strikes, compressor shutdowns due to high
vibration events, hydrogen plant startup and shutdown, CRU plant
startups, flare header maintenance activities and routing of high
hydrogen process streams to the flare during maintenance events and
process upsets. The EPA recognizes that flares can receive a wide range
of process streams over a wide range of flows. We are clarifying in
this preamble that certification of compliance for these flare vent gas
flow meter accuracy requirements can be made based on the typical range
of flare gas compositions expected for a given flare.
---------------------------------------------------------------------------
\14\ Kris A. Battleson, ``Chevron-vendor information for call at
12 PDT, 3 EDT.'' Message to Gerri Garwood and Brenda Shine. August
29, 2017. Email.
\15\ Kris A. Battleson, ``meter QA/QC.'' Message to Brenda
Shine. September 19, 2017. Email.
\16\ Karin C. Ritter, ``API Submitting: Flare Flow Meter
Accuracy White Paper & CRU Data & Summary.'' Message to Penny
Lassiter and Brenda Shine. January 16, 2018. Email.
---------------------------------------------------------------------------
7. Other Corrections
We received comments from API and AFPM in their February 1, 2016,
petition for reconsideration regarding the incorporation of 40 CFR part
63, subpart WW storage vessel provisions and 40 CFR part 63, subpart SS
closed vent systems and control device provisions into Refinery MACT 1
requirements for Group 1 storage vessels at 40 CFR 63.660. The pre-
amended version of the Refinery MACT 1 rule specified (by cross
reference at 40 CFR 63.646) that storage vessels containing liquids
with a vapor pressure of 76.6 kilopascals (11.0 pounds per square inch
(psi)) or greater must be vented to a closed vent system or to a
control device consistent with the requirements in the HON. The
petitioners pointed out that the EPA did not retain this provision at
40 CFR 63.660 in the December 2015 final rule. In reviewing the
introductory text at 40 CFR 63.660, we agree that the language was
inadvertently omitted. We did not intend to deviate from the
longstanding requirement limiting the vapor pressure of material that
can be stored in a floating roof tank. We are, therefore, proposing to
revise the introductory text in 40 CFR 63.660 to clarify that owners or
operators of affected Group 1 storage vessels storing liquids with a
maximum true vapor pressure less than 76.6 kilopascals (11.0 psi) can
comply with either the requirements in 40 CFR part 63, subpart WW or SS
and that owners or operators storing liquids with a maximum true vapor
pressure greater than or equal to 76.6 kilopascals (11.0 psi) must
comply with the requirements in 40 CFR part 63, subpart SS.
We also received comments from API and AFPM in their February 1,
2016, petition for reconsideration regarding provisions in 40 CFR
63.660(b). Section 63.660(b)(1) allows Group 1 storage vessels to
comply with alternatives to those specified in 40 CFR 63.1063(a)(2) of
subpart WW. Section 63.660(b)(2) specifies additional controls for
ladders having at least one slotted leg. The petitioners explained that
40 CFR 63.1063(a)(2)(ix) provides extended compliance time for these
controls, but that it is unclear whether this additional compliance
time extends to the use of the alternatives to comply with 40 CFR
63.660(b). We are proposing language to make clear that the additional
compliance time applies to the implementation of controls in 40 CFR
63.660(b).
We received several questions from industry pertaining to the
requirement in paragraphs 40 CFR 63.655(f) and 40 CFR 63.655(f)(6) to
submit a NOCS report. The final rule allows sources that are newly
subject to Refinery MACT 1 to submit the NOCS in a periodic report
rather than in a separate notification submission (40 CFR
63.655(f)(6)). It is reasonable that any source with a compliance date
on or after February 1, 2016, should be able to follow the same
approach. We are proposing to amend paragraphs 40 CFR 63.655(f) and 40
CFR 63.655(f)(6) to expressly provide that sources having a compliance
date on or after February 1, 2016, may submit the NOCS in the periodic
report rather than as a separate submission.
We are also proposing to clarify at 40 CFR 63.660(e) that the
initial inspection requirements that applied with initial filling of
the storage vessels are not required again simply because the source
transitions from the requirements in 40 CFR 63.646 to 40 CFR 63.660.
We also received comments from API and AFPM \17\ that the deadlines
in the December 2015 final rule for reporting results of performance
tests are inconsistent. The electronic reporting requirements in 40 CFR
63.655(h)(9) provide that the results of performance tests must be
reported within 60 days of completing the performance test, while the
NOCS report in 40 CFR 63.655(f), which is required to contain the
performance test results, is due 150 days from the compliance date in
the rule. We note that while some performance tests may be required
prior to the requirement to submit the NOCS report, others may be
performed when no NOCS report is due. We are proposing revisions to 40
CFR 63.655(f)(1)(i)(B)(3) and (C)(2), (f)(1)(iii), (f)(2), and (f)(4)
to clarify that when the results of performance tests [or performance
evaluations] are to be reported in the NOCS, the results are due by the
date the NOCS report is due (report is due 150 days from the compliance
date) whether the results are reported using the Compliance and
Emissions Data Reporting Interface (CEDRI) or in hard copy as part of
the NOCS report. If the source submits the test results using CEDRI, we
are also proposing to specify that the source need not resubmit those
results in the NOCS, but may instead submit specified information
identifying that a performance test [or performance evaluation] was
conducted and the unit(s) and pollutant(s) that were tested. We are
also proposing to add the phrase ``Unless otherwise specified by this
subpart'' to 40 CFR 63.655(h)(9)(i) and (ii) to make clear that test
results associated with a NOCS report are not due within 60 days of
completing the performance test or performance evaluation. We are also
amending several references in Table 6--General Provisions
Applicability to Subpart CC that discuss reporting requirements for
performance tests or performance evaluations. As the General Provisions
sections currently only address submissions of written test reports, we
are proposing to clarify these entries in Table 6 to recognize that
performance
[[Page 15469]]
test results may be written or electronic. Specifically, we are
proposing to make these clarifications in Table 6 entries for 40 CFR
63.6(f)(3), 63.6(h)(8), 63.7(a)(2), and 63.8(e).
---------------------------------------------------------------------------
\17\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------
We also received questions from API and AFPM \18\ on other aspects
of the electronic reporting requirements. Industry representatives
requested that electronic reporting only be required if all the test
methods used to determine the emissions are supported by the Electronic
Reporting Tool (ERT) (e.g., methods for velocity as well as pollutant
concentration). We recognize that the ERT does not support all test
methods and that there is little value in submitting a stack flow
electronically and the pollutant concentration in written format or
PDF. We are revising the ERT website to clarify that electronic
reporting is not required where the ERT does not support the test
method for the pollutant of interest.
---------------------------------------------------------------------------
\18\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------
We recognize that there are instances when two primary pollutants
may be measured during a single performance test, one supported by the
ERT and one not supported by the ERT. For petroleum refineries, this
occurs if the owner or operator conducts a particulate matter (PM)
performance test coincident with the hydrogen cyanide performance test.
Since the PM test methods (Methods 5, 5B, and 5F) are supported by the
ERT, we require that this performance test be submitted via the ERT.
However, testing for hydrogen cyanide is not supported by the ERT. The
owner or operator may meet the reporting requirement for the hydrogen
cyanide test by either including the test report as an attachment to
the ERT submission so that both results are submitted electronically or
by submitting the test report in hard copy or other agreed upon format.
Industry representatives also recommended that the requirement to
report electronically be suspended until a reliable system is in place.
We note that the submission of ERT-formatted performance test and
performance evaluation reports using CEDRI is fully operational, and
there are no known or reported system issues. CEDRI accepts all ERT
version 5 report submissions that are properly created using the ERT.
If the ERT zip file being uploaded to CEDRI is not created from the ERT
or does not meet the file format requirements established by the EPA,
CEDRI will not accept the file upload and will provide the user
instructions on how to resolve the error(s). In addition, the Central
Data Exchange (CDX) Helpdesk staff are available during regular
business hours to support industry users in completing their
submissions electronically using CEDRI. Any user concerns that cannot
be resolved by the CDX Helpdesk are escalated to either EPA staff or
the application support contractors for resolution. To date, over 3,400
ERT files have been submitted to the EPA through CEDRI. There have been
43 calls to the Helpdesk for assistance. The CDX Helpdesk resolved 34
of these calls, and the EPA and their support contractors resolved the
remaining nine. We encourage all users to continue to contact the CDX
Helpdesk with any issues encountered during the submission process.
We have also identified two broad circumstances in which electronic
reporting extensions may be provided. In both circumstances, the
decision to accept a claim of needing additional time to report is
within the discretion of the Administrator, and reporting should occur
as soon as possible. In 40 CFR 63.655(h)(10)(i), we address the
situation where an extension may be warranted due to outages of the
EPA's CDX or CEDRI which preclude a user from accessing the system and
submitting required reports. If either the CDX or CEDRI is unavailable
at any time beginning 5 business days prior to the date that the
submission is due, and the unavailability prevents a user from
submitting a report by the required date, users may assert a claim of
EPA system outage. We consider 5 business days prior to the reporting
deadline to be an appropriate timeframe because, if the system is down
prior to this time, users still have 1 week to complete reporting once
the system is back online. However, if the CDX or CEDRI is down during
the week a report is due, we realize that this could greatly impact the
ability to submit a required report on time. We will notify users about
known outages as far in advance as possible by CHIEF Listserv notice,
posting on the CEDRI website, and posting on the CDX website so that
users can plan accordingly and still meet reporting deadlines. However,
if a planned or unplanned outage occurs and users believe that it will
affect or it has affected their ability to comply with an electronic
reporting requirement, we have provided a process to assert such a
claim.
Consistent with 40 CFR 63.655(h)(10), a source may seek an
extension of the time to comply with an electronic reporting
requirement. We are proposing to revise this provision to address the
situation where an extension may be warranted due to a force majeure
event, which is defined as an event that will be or has been caused by
circumstances beyond the control of the affected facility, its
contractors, or any entity controlled by the affected facility that
prevents them from complying with the requirement to submit a report
electronically as required by this rule. Examples of such events are
acts of nature, acts of war or terrorism, or equipment failure or
safety hazards beyond the control of the facility. If such an event
occurs or is still occurring or if there are still lingering effects of
the event in the 5 business days prior to a submission deadline, we are
proposing a process to assert a claim of force majeure as a basis for
extending the reporting deadline to protect refiners from noncompliance
in cases where they cannot successfully submit a report by the
reporting deadline for reasons outside of their control.
We received questions from API and AFPM \19\ regarding the
integrity checks required for the temperature and pressure monitor
inspections in Table 13 (40 CFR part 63, subpart CC) and in Items 2, 4,
6, 7, 9, and 10 of Table 41 (40 CFR part 63, subpart UUU). Commenters
noted that 40 CFR 63.657(b)(4), which applies to delayed coker pressure
monitoring, indicates that the ``. . . pressure monitoring system must
be visually inspected for integrity . . .'' and suggested that the
table entries likewise specify that visual inspections are required/
acceptable. The continuous parameter monitoring system (CPMS) pressure
monitoring addressed in Tables 13 and 41 is broader than the monitoring
requirement in 40 CFR 657(b)(4) and visual monitoring is not required
for monitoring other systems as it is for delayed coker pressure
monitoring. However, we agree that visual inspections are acceptable
for those other systems, though, for those systems, there may be other
methods of assessing integrity, such as current meters for wiring, that
are not visual. In recognition of the fact that not all checks will be
``visual,'' we did not specify ``visual'' inspections in Tables 13 and
41.
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\19\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------
In codifying the amendments to 40 CFR 63.655(i)(5), the specific
recordkeeping requirements in the subparagraphs for regulation as it
existed prior to the revisions were not retained in the regulations as
published by the CFR. As reflected in the instructions to the
amendments, we intended to move the heat exchanger recordkeeping
requirements from paragraph (i)(4) to (i)(5) and to revise the
introductory text to new paragraph (i)(5)
[[Page 15470]]
(see instructions 27.j. and 27.l. in 80 FR 75247). These revisions were
incorporated into the CFR; however, the subparagraphs, which were not
being revised, were not included in the CFR. We are proposing to revise
40 CFR 63.655(i)(5) to include the subparagraphs (as previously
codified in subparagraph (i)(4)) that were inadvertently not included
in the published CFR.
Similarly, the amendments to 40 CFR 63.655(h)(5)(iii) included in
the December 2015 final rule Federal Register document (80 FR 75247)
were not included in the regulations as published by the CFR. As
reflected in the instructions to the amendments, we intended for the
option to use an automated data compression recording system to be an
approved monitoring alternative. In reviewing this amendment, the EPA
noted that 40 CFR 63.655(h)(5) specifically addresses mechanisms for
owners or operators to request approval for alternatives to the
continuous operating parameter monitoring and recordkeeping provisions,
while the provisions in 40 CFR 63.655(i)(3) specifically include
options already approved for CPMS. Consistent with our intent for the
use of an automated data compression recording system to be an approved
monitoring alternative, we are proposing to move the paragraphs at 40
CFR 63.655(h)(5)(iii) to 40 CFR 63.655(i)(3)(ii)(C).
There are several additional revisions that we are proposing to
Refinery MACT 1 to correct typographical errors, grammatical errors,
and cross-reference errors. Table 2 of this preamble summarizes these
editorial changes as well as other changes as discussed in this
preamble.
Table 2--Summary of Proposed Editorial and Other Corrections to Refinery
MACT 1
------------------------------------------------------------------------
Provision Proposed revision
------------------------------------------------------------------------
MPV:
Last sentence in Sec. Replace ``owner of operator'' with
63.643(c). ``owner or operator.''
Sec. 63.643(c)(1)(ii)....... Define the term ``psig'' as pounds
per square inch gauge and remove
the last occurrence of
``equipment.''
Sec. 63.643(c)(1)(iii)...... Define the term ``VOC'' as total
volatile organic compounds.
PRD:
Sec. 63.648(a).............. Correct reference to ``paragraphs
(a)(1) through (2)'' to
``paragraphs (a)(1) through (3).''
Also, correct reference to
``paragraphs (c) through (i)'' to
``paragraphs (c) through (j).''
Sec. 63.648(c).............. Correct reference to ``paragraphs .
. . (e) through (i) . . . '' to
``paragraphs . . . (e) through (j)
. . .''
Last sentence in Sec. Add space between majeure and
63.648(j)(3)(iv). events.
DCU:
Sec. 63.655(i)(7)(iii)(B)... Adjust recordkeeping requirement to
the 5-minute period prior to pre-
vent draining, rather than 15-
minute period.
Sec. 63.657(a)(1)(i) and Correct the temperature and pressure
(ii); Sec. 63.657(a)(2)(i) limits to be expressed as maximums
and (ii). by adding ``or less'' to each
numerical limit.
Sec. 63.657(b)(5)........... Clarify that the output of the
pressure monitoring system must be
reviewed only when the drum is in
service, so the provision reads,
``The output of the pressure
monitoring system must be reviewed
each day the unit is operated to
ensure . . .''
Fenceline:
Second sentence in Sec. Replace ``owner of operator'' with
63.658(c)(2) and Sec. ``owner or operator.''
63.658(e).
Sec. 63.658(d)(1)........... Correct the reference to ``paragraph
(i)(1)'' to ``paragraph (i)(2).''
Sec. 63.658(d)(2)........... Update the reference to Section 8.3
of Method 325A to more specifically
reference Sections 8.3.1 through
8.3.3 of Method 325A.
Sec. 63.658(e)(3)(iv)....... Delete the word ``an'' in the first
sentence.
Flares:
Sec. 63.670(o).............. Correct the reference to
``paragraphs (o)(1) through (8)''
to ``paragraphs (o)(1) through
(7).''
Sec. 63.670(j)(6)........... Correct the reference to
subparagraphs ``(j)(6)(i) through
(v)'' to ``(j)(6)(i) through
(iii).''
Sec. 63.670(k)(3) equation Correct units for Qcum to be
term for Qcum. ``standard cubic feet.''
Sec. Sec. Sec. 63.670(i), Update the reference to
(m)(2) including equation ``supplemental natural gas'' to the
terms, and (n)(2) including defined term ``flare supplemental
equation terms. gas.''
Sec. 63.670(o)(1)(ii)(B).... Correct the reference to paragraph
``Sec. 63.648(j)(5)'' to ``Sec.
63.648(j)(3)(ii)(A) through (E).''
\20\
Sec. Sec. Edit the paragraphs to refer to a 15-
63.670(o)(1)(iii)(B) and minute block averaging time
(o)(3)(i). relative to the smokeless design
capacity of the flare.
Table 13, Hydrogen Analyzer Add ``Where feasible'' to the
Requirements for Sampling description of sampling location
Location. for the hydrogen analyzer.
Storage Vessels:
Sec. 63.655(f)(1)(i)(A)(1) Add a reference to the option to
through (3). comply with Sec. 63.660 in
addition to compliance with Sec.
63.646.
Sec. 63.655(g)(2)(B)(1)..... Add the word ``area'' to the end of
the sentence consistent with the
same requirement in the HON.
Sec. 63.655(h)(2)(ii)....... Correct the reference to ``Sec.
63.1063(d)(3)'' to ``Sec.
63.1062(d)(3).''
Sec. 63.660(b)(1)........... Correct the reference to ``Sec.
63.1063(a)(2)(vii)'' to ``Sec.
63.1063(a)(2)(viii).''
Sec. 63.660(i)(2)........... Delete the second use of the word
``to.''
Other:
Table 6, Comment for Reference Correct the reference ``Sec.
Sec. 63.7(h)(3). 63.7(g)(3)'' to ``Sec.
63.7(h)(3)(i).''
------------------------------------------------------------------------
[[Page 15471]]
B. Clarifications and Technical Corrections to Refinery MACT 2
---------------------------------------------------------------------------
\20\ A similar revision was included in the October 18, 2016,
reconsideration notice and proposed rule (81 FR 71661). In the
reconsideration notice and proposed rule, we proposed to correct the
reference to paragraph ``Sec. 63.648(j)(5)'' to ``Sec.
63.648(j)(3)(ii).'' In this proposal, we are including a more
specific reference to the subparagraphs in 40 CFR 63.648(j)(3) to
clarify that the rule requires owners and operators to evaluate the
list of prevention measures in these subparagraphs.
---------------------------------------------------------------------------
1. FCCU Provisions
In order to demonstrate compliance with the alternative PM standard
for FCCU at 40 CFR 63.1564(a)(5)(ii), the outlet (exhaust) gas flow
rate of the catalyst regenerator must be determined. Refinery MACT 2
provides that owners or operators may determine this flow rate using a
flow CPMS or the alternative provided in 40 CFR 63.1573(a). Currently,
the language in 40 CFR 63.1573(a) restricts the use of the alternative
to occasions when ``the unit does not introduce any other gas streams
into the catalyst regenerator vent.'' API and AFPM \21\ claim that
while this restriction is appropriate for determining the flow rate for
applying emissions limitations downstream of the regenerator because
additional gases introduced to the vent would not be measured using
this method, it is not a necessary constraint for determining
compliance with the alternative PM limit. This is because the
alternative PM standard applies at the outlet of the regenerator prior
to the primary cyclone inlet and this is the flow measured by the
alternative in 40 CFR 63.1573(a). We agree that there should be no such
restriction when determining the outlet flow rate to the regenerator
for the purposes of demonstrating compliance with the alternate PM
standard at 40 CFR 63.1564(a)(5)(ii), and are proposing to amend 40 CFR
63.1573(a) to remove that restriction.
---------------------------------------------------------------------------
\21\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------
Additionally, API and AFPM noted in their February 1, 2016,
petition for reconsideration that the FCCU alternative organic HAP
standard for startup, shutdown, and hot standby in 40 CFR
63.1565(a)(5)(ii) requires maintaining the oxygen concentration in the
regenerator exhaust gas at or above 1 vol. percent (dry) (i.e., greater
than or equal to 1-percent oxygen (O2) measured on a dry
basis); however, they claim process O2 analyzers measure
O2 on a wet basis. Therefore, the commenters explained that
they would need to take a moisture measurement and use the measurement
to correct the measured O2 in order to demonstrate
compliance with the standard. Industry commenters explained that this
is unnecessary as an FCCU meeting the 1-percent O2
alternative standard measured on a wet basis will be compliant with the
1-percent limit on a dry basis. We agree that meeting the 1-percent
O2 standard on a wet basis measurement will always mean that
there is more O2 than if the concentration value is
corrected to a dry basis. As such, a wet basis measurement of 1-percent
O2 is adequate to demonstrate compliance with the minimum
O2 alternative limit in 40 CFR 63.1565(a)(5)(ii). Therefore,
we are proposing to amend 40 CFR 63.1565(a)(5)(ii) and Table 10 to
allow for the use of a wet O2 measurement for demonstrating
compliance with the standard so long as it is used directly with no
correction for moisture content.
2. Other Corrections
API and AFPM commented in their February 1, 2016, petition for
reconsideration that the amendments to the provision for CPMS
monitoring and data collection in Refinery MACT 2 at 40 CFR
63.1572(d)(1) which do not exclude periods of monitoring system
malfunction, associated repairs, and quality assurance or control
activities is inconsistent with paragraph (d)(2) which specifies that
data recorded during required quality assurance or control activities
may not be used. Additionally, API and AFPM stated that an analogous
provision in 40 CFR 63.1572(d) for CPMS monitoring and data collection
was maintained in the final Refinery MACT 1 at 40 CFR 63.671(a)(4). We
agree that we should maintain consistency between Refinery MACT 1 and
Refinery MACT 2 whenever possible and, in this case, there is no good
reason for the two subparts to differ. CPMS readings taken during
periods of monitoring system malfunctions and repairs do not provide
accurate or valid data. In order to repair a monitoring system, the
CPMS must generally be taken offline or completely out of service, and,
therefore, there would be no data to record. During a monitoring system
malfunction, while there may or may not be data to record, the
malfunction will affect the accuracy of the data. This is the reason
why these data are generally excluded from data averages (as noted in
40 CFR 63.8(g)(5)). Therefore, we are proposing to amend the language
in Refinery MACT 2 at 40 CFR 63.1572(d)(1) so that the language is the
same as that in Refinery MACT 1 at 40 CFR 63.671(a)(4).
The final amendments provide alternative emission limits during
periods of startup and shutdown for some units, such as the FCCU
alternative organic HAP standard for startup, shutdown, and hot standby
in 40 CFR 63.1565(a)(5)(ii). API and AFPM questioned in their February
1, 2016, petition for reconsideration whether the recordkeeping
requirements in 40 CFR 63.1576(a)(2)(i) apply when the owners or
operators elect to comply with the otherwise applicable emissions
limitations during periods of startup and shutdown. Separate
recordkeeping requirements apply when a source is subject to the
otherwise applicable emissions limits; thus, it is not necessary for
the recordkeeping requirements in 40 CFR 63.1576(a)(2)(i) to also
apply. Therefore, we are proposing to amend the recordkeeping
requirement in 40 CFR 63.1576(a)(2)(i) to apply only when facilities
elect to comply with the alternative startup and shutdown standards
provided in 40 CFR 63.1564(a)(5)(ii) or 40 CFR 63.1565(a)(5)(ii) or 40
CFR 63.1568(a)(4)(ii) or (iii).
We are proposing to revise Refinery MACT 2 to address the same
issue raised for Refinery MACT 1 regarding the reporting of initial
performance tests. We are proposing to amend 40 CFR 63.1574(a)(3) to
clarify that the results of performance tests conducted to demonstrate
initial compliance are to be reported by the date the NOCS report is
due (150 days from the compliance date) whether the results are
reported using CEDRI or in hard copy as part of the NOCS report and to
clarify the information to be included in the NOCS if the test results
are submitted through CEDRI. Unlike Refinery MACT 1, Refinery MACT 2
has on-going performance test requirements. We are proposing that the
results of periodic performance tests and the one-time hydrogen cyanide
(HCN) test required by 40 CFR 63.1571(a)(5) and (6) must be reported
with the semi-annual compliance reports as specified in 40 CFR
63.1575(f) instead of within 60 days of completing the performance
evaluation. Similarly, we are also proposing to streamline reporting of
the results of performance evaluations for continuous monitoring
systems (as provided in entry 2 to Table 43) to align with the semi-
annual compliance reports as specified in 40 CFR 63.1575(f), rather
than requiring a separate report submittal. We are proposing to add the
phrase ``Unless otherwise specified by this subpart'' to 40 CFR
63.1575(k)(1) and (2) to indicate that any performance tests or
performance evaluations required to be reported in a NOCS report or a
semi-annual compliance report are not subject to the 60-day deadline
specified in these paragraphs. We are also proposing to add 40 CFR
63.1575(l) to
[[Page 15472]]
address extensions to electronic reporting deadlines.
Similar to the revisions in Table 6 to 40 CFR part 63, subpart CC
(see section III. A.7), we are proposing to revise selected entries in
Table 44 to Subpart UUU of Part 63--Applicability of NESHAP General
Provisions to Subpart UUU, to clarify several sections of the General
Provisions (40 CFR part 63, subpart A) that the reporting can be
written or electronic, the timing of these reports is specified in 40
CFR part 63, subpart UUU, and the subpart UUU provisions supersede the
General Provisions. Specifically, we are proposing to revise Table 44
entries for 40 CFR 63.6(f)(3), 63.7(h)(7)(i), 63.6(h)(8), 63.7(a)(2),
63.7(g), 63.8(e), 63.10(d)(2), 63.10(e)(1), 63.10(e)(2), and
63.10(e)(4) to explain that 40 CFR part 63, subpart UUU specifies how
and when to report the results of performance tests or performance
evaluations.
There are several additional revisions that we are proposing to
Refinery MACT 2 to correct typographical errors, grammatical errors,
and cross-reference errors. These editorial corrections are summarized
in Table 3 of this preamble.
Table 3--Summary of Proposed Editorial and Minor Corrections to Refinery
MACT 2
------------------------------------------------------------------------
Provision Proposed revision
------------------------------------------------------------------------
Sec. 63.1564(b)(4)(iii)......... Correct the reference to ``paragraph
(a)(1)(iii)'' to ``paragraph
(a)(1)(v).''
Sec. 63.1564(c)(3).............. Correct the reference to ``paragraph
(a)(1)(iii)'' to ``paragraph
(a)(1)(v).''
Sec. 63.1564(c)(4).............. Correct the reference to ``paragraph
(a)(1)(iv)'' to ``paragraph
(a)(1)(vi).''
Sec. 63.1564(c)(5)(iii)......... Correct the units of measure for
velocity to ft/sec.
Sec. 63.1569(c)(2).............. Correct the reference to ``paragraph
(a)(2)'' to ``paragraph (a)(3).''
Sec. 63.1571(a)(5) and (6); and Add ``or within 60 days of startup
Table 6, Item 1.ii. of a new unit'' to the compliance
time for the periodic performance
testing requirement for PM or Ni
and to the one-time performance
testing requirement for HCN.
Sec. 63.1571(d)(1).............. Correct the reference to ``paragraph
(a)(1)(iii)'' to ``paragraph
(a)(1)(v).''
Sec. 63.1571(d)(2).............. Correct the reference to ``paragraph
(a)(1)(iv)'' to ``paragraph
(a)(1)(vi).''
Sec. 63.1572(c)(1).............. Delete duplicative sentence, ``You
must install, operate, and maintain
each continuous parameter
monitoring system according to the
requirements in Table 41 of this
subpart.''
Table 3........................... Correct the spelling of the word
``continuous'' in the table's
title.
Table 3, Item 2.c................. Delete the words, ``the coke burn-
off rate or.'' Correct the footnote
reference from ``3'' to ``1.''
Table 3, Items 6 through 9........ Correct the reference to ``Sec.
60.120a(b)(1)'' to ``Sec.
60.102a(b)(1).''
Table 4, Item 9.c................. Correct the reference to ``Equation
2 of Sec. 63.571'' to ``Equation
1 of Sec. 63.571, if
applicable.''
Table 4, Item 10.c................ Correct the reference to ``item
6.c.'' to ``item 9.c.'' and add
``if applicable'' after reference
to Equation 2 of Sec. 63.571.
Table 5, Item 3................... Correct the reference to
``60.102a(b)(1)(i)'' to
``60.102a(b)(1)(ii),'' and correct
the reference to ``1.0 g/kg (1.0 lb/
1,000 lb)'' to ``0.5 g/kg (0.5 lb
PM/1,000 lb).''
Table 6, Item 7................... Delete '' and 30% opacity'' as this
is not part of Option 1b.
Table 43, Item 2.................. Correct the compliance date to the
effective date of the rule
(February 1, 2016).
------------------------------------------------------------------------
C. Clarifications and Technical Corrections to NSPS Ja
During recent implementation efforts, it was brought to our
attention that the testing requirement in 40 CFR 60.105a(b)(2)(ii)
differs from similar requirements in 40 CFR 60.105a(d)(4), (f)(4), and
(g)(4) where we allow use of Method 3, 3A, or 3B, both for the
performance tests and the relative accuracy tests. The language in 40
CFR 60.105a(b)(2)(ii) does not currently include Methods 3A and 3B (and
the alternative ANSI/ASME method for EPA Method 3B) and mistakenly
cites Appendix A-3 rather than Appendix A-2. We are proposing to revise
40 CFR 60.105a(b)(2)(ii), consistent with the other similar
requirements in NSPS subpart Ja listed above, to read as follows, ``The
owner or operator shall conduct performance evaluations of each
CO2 and O2 monitor according to the requirements
in Sec. 60.13(c) and Performance Specification 3 of appendix B to this
part. The owner or operator shall use Method 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, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.'' The EPA is
proposing a corresponding change to 40 CFR 60.17(g)(14) to add 40 CFR
60.105a(b) to the list of regulations in which this method has been
incorporated by reference. It should be noted that through this
revision, the EPA is proposing to include in a final EPA rule
regulatory text that includes incorporation by reference. In accordance
with requirements of 1 CFR 51.5(a), the EPA is proposing to incorporate
by reference the ANSI/ASME PTC 19.10-1981 test method. The EPA has
made, and will continue to make, this document generally 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).
We also identified that the second sentence of 40 CFR
60.106a(a)(1)(iii) includes the following clause, ``. . . and Method 3
or 3A of appendix A-2 of part 60 for conducting the relative accuracy
evaluations'' which is redundant to 40 CFR 60.106a(a)(1)(vi) (and
again, does not include all three Methods). We are proposing to delete
this clause. We are also proposing to change the word ``Methods'' to
``Method'' in the second sentence of 40 CFR 60.106a(a)(1)(iii) to
better reflect our intent for facilities to select a single performance
evaluation method.
IV. Summary of Cost, Environmental, and Economic Impacts
This proposed rule is expected to result in overall cost and burden
reductions. Specifically, the proposed amendments expected to reduce
burden are: Revisions of the maintenance vent provisions related to the
availability of a pure hydrogen supply for equipment containing
pyrophoric catalyst, revisions of recordkeeping requirements for
maintenance vents associated with equipment containing less than 72 lbs
VOC, inclusion of specific provisions for pilot-operated and balanced
bellows PRDs, and inclusion of specific provisions related to steam
tube air entrainment for flares. These proposed amendments are
described in detail in sections III.A.2.b, III.A.2.d, III.A.3.c, and
III.A.5 of this preamble, respectively. The other proposed amendments
will have an insignificant effect on the
[[Page 15473]]
compliance costs associated with these standards. Additionally, none of
the proposed amendments are projected to appreciably impact the
emissions reductions associated with these standards.
Some of the cost reductions associated with this proposed rule were
not fully captured in the impacts estimated for the December 2015 final
rule. The total capital investment cost of the December 2015 final rule
was estimated at $283 million, $112 million from the final amendments
for storage vessels, DCUs, and fenceline monitoring, and $171 million
from standards for flares and PRDs. The annualized costs of the final
amendments for storage vessels, DCUs, and fenceline monitoring were
estimated to be approximately $13.0 million and the annualized costs of
the final standards for flares and PRDs were estimated to be
approximately $50.2 million. There were no capital costs estimated for
the maintenance vent provisions in the December 2015 final rule and
only limited recordkeeping and reporting costs. Furthermore, while
significant capital and operating costs were projected for flares, we
may have underestimated the number of steam-assisted flares that would
also have to demonstrate compliance with the NHVdil
operating limit.
As described previously in section III.A.2.b of this preamble, we
did not specifically consider that some units with pyrophoric catalyst
at the refinery would have a pure hydrogen supply and others would not.
Therefore, we did not include costs in the December 2015 final rule
impacts for refineries that have a pure hydrogen supply to add new
piping (and possibly increase their hydrogen production capacity) to
bring pure hydrogen to units with pyrophoric catalyst that were not
currently piped to receive pure hydrogen. Based on information provided
by industry petitioners, the capital investment cost to supply pure
hydrogen to pyrophoric units that currently do not have a pure hydrogen
supply (but that are located at refineries with a pure hydrogen supply)
is estimated to be approximately $76 million. Using a capital recovery
of 0.0944 based on 20-year equipment life and 7-percent interest,
hydrogen supply upgrades would have increased the previously estimated
annualized cost by $7,174,400 per year. Table 4 provides the cost
reduction expected for the proposed amendments concerning hydrogen
supply for pyrophoric units, as well as other proposed amendments.
Table 4--Projected Impacts of the Proposed Amendments to Refinery MACT 1
----------------------------------------------------------------------------------------------------------------
Estimated
Current Current capital Estimated Reduction in
estimate of estimate of investment annualized annualized
Dec 2015 rule Dec 2015 rule cost if cost if cost of
capital annualized proposed rule proposed rule refinery
investment costs, million is is standards,
costs, million $/yr implemented, implemented, million $/yr
$ million $ million $/yr
----------------------------------------------------------------------------------------------------------------
Maintenance vents provisions for 76 7.17 0 0 7.17
equipment with pyrophoric
catalyst.......................
MPV recordkeeping requirements.. 0 0.678 0 0.001 0.677
PRD requirements................ 11.1 3.33 10.0 3.00 0.33
Flare monitoring for steam- 130 26.9 130 23.6 3.31
assisted flares with air
entrainment....................
----------------------------------------------------------------------------------------------------------------
For the proposed amendments to the recordkeeping requirements for
equipment containing less than 72 lbs of VOC, the impacts in the
December 2015 final rule only included one-time planning costs for how
to comply with the maintenance vent requirements; it was assumed that
facilities would have maintenance records for each activity, so no
additional recordkeeping burden was estimated. According to industry
petitioners, there are numerous activities, such as replacing pressure
transducers or tubing that would qualify under the less than 72 lbs of
VOC provisions, but for which event-specific records are not
traditionally maintained. Based on the per event recordkeeping
requirement for maintenance vents using the 72 lbs VOC provision in the
December 2015 rule, we now estimate that there would be 500 of these
small maintenance vent openings per year per refinery and that 0.1 hour
would be required to record each individual event, resulting in a
nationwide burden of $678,625 per year. The revisions in the proposed
rule, would only require records that should be part of the annual
planning assessment and records for events not following the
deinventory procedures included in these plans. We estimate that each
facility would spend 0.1 hour for each non-conforming event and would
only have one such event each year with an estimated nationwide burden
of $1,357 per year. Thus, the proposed amendments are estimated to
yield savings of approximately $677,268 per year considering the actual
estimated annualized burden of the December 2015 final rule.
We estimated the PRD requirements in the December 2015 rule would
result in a capital investment of $11.1 million to implement prevention
measures and flow monitoring systems on PRDs. Combined with the
recordkeeping and reporting requirements, the annualized cost of the
PRD provisions in the December 2015 final rule was estimated to be $3.3
million per year. We estimate that approximately 10 percent of PRDs at
refineries are either pilot-operated or balanced bellows. Thus, if
there is a commensurate 10-percent decrease in these costs based on the
proposed provisions for pilot-operated or balanced bellows PRD, we
estimate the proposed amendments would yield a reduction in capital
investment of $1.1 million and a reduction in annualized costs of
$330,000 per year.
We estimated that the provisions for steam-assisted flares in the
December 2015 rule would result in a capital investment of $130 million
and annualized costs of $23.6 million. However, these costs did not
include costs to also assess compliance with the NHVdil
operating limit for those steam-assisted flares that used intentional
air entrainment within the steam tubes. There is no way to measure this
air entrainment rate, but engineering calculations were allowed to be
used. We estimated that there were 190 steam-assisted flares that
received routine flow. We estimate that 0.5 additional hour would be
required each day to assess compliance with the NHVdil
operating limits for these flares. If all 190 steam-assisted flares
were designed for air entrainment in the steam tubes,
[[Page 15474]]
this would suggest that the annualized cost of the December 2015 final
rule for steam-assisted flares is closer to $26.9 million per year and
that the proposed amendments allowing owners or operators of certain
steam-assisted flares with air entrainment at the flare tip to comply
only with the NHVcz operating limits would reduce annualized
costs by approximately $3.3 million.
A detailed memorandum documenting the estimated burden reduction
has been included in the docket for this rulemaking (see memorandum
titled, ``Impact Estimates for the 2017 Proposed Revisions to Refinery
MACT 1,'' in Docket ID No. EPA-HQ-OAR-2010-0682).
V. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is not a significant regulatory action and was,
therefore, not submitted to OMB for review.
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
This action is expected to be an Executive Order 13771 deregulatory
action. Details on the estimated cost savings of this proposed rule can
be found in EPA's analysis of the potential costs and benefits
associated with this action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this proposed rule have
been submitted for approval to OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 1692.11. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here.
One of the proposed technical amendments included in this notice
impacts the recordkeeping requirements in 40 CFR part 63, subpart CC
for certain maintenance vents associated with equipment containing less
than 72 lbs VOC as found at 40 CFR 63.655(i)(12)(iv). The new
recordkeeping requirement specifies records used to estimate the total
quantity of VOC in the equipment and the type and size limits of
equipment that contain less than 72 lb of VOC at the time of the
maintenance vent opening be maintained. As specified in 40 CFR
63.655(i)(12)(iv), additional records are required if the deinventory
procedures were not followed for each maintenance vent opening or if
the equipment opened exceeded the type and size limits (i.e., 72 lbs
VOC). These additional records include 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. These records will
assist the EPA with determining compliance with the standards set forth
in 40 CFR 63.643(c)(iv).
Respondents/affected entities: Owners or operators of existing or
new major source petroleum refineries that are major sources of HAP
emissions. The NAICS code is 324110 for petroleum refineries.
Respondent's obligation to respond: All data in the ICR that are
recorded are required by the proposed amendments to 40 CFR part 63,
subpart CC--National Emission Standards for Hazardous Air Pollutants
for Petroleum Refineries.
Estimated number of respondents: 142.
Frequency of response: Once per year per respondent.
Total estimated burden: 16 hours (per year). Burden is defined at 5
CFR 1320.3(b).
Total estimated cost: $1,640 (per year), includes $0 annualized
capital or operation and maintenance costs.
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 the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to the EPA using the docket identified at
the beginning of this rule. You may also send your ICR-related comments
to OMB's Office of Information and Regulatory Affairs via email to
[email protected], Attention: Desk Officer for the EPA. Since
OMB is required to make a decision concerning the ICR between 30 and 60
days after receipt, OMB must receive comments no later than May 10,
2018.
The EPA will respond to any ICR-related comments in the final
rule.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. An agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden, or otherwise has a positive economic effect on the small
entities subject to the rule. The action consists of amendments,
clarifications, and technical corrections which are expected to reduce
regulatory burden. As described in section IV of this preamble, we
expect burden reduction for: Revisions of the maintenance vent
provisions related to the availability of a pure hydrogen supply for
equipment containing pyrophoric catalyst, revisions of recordkeeping
requirements for maintenance vents associated with equipment containing
less than 72 lbs VOC, inclusion of specific provisions for pilot-
operated and balanced bellows PRDs, and inclusion of specific
provisions related to steam tube air entrainment for flares.
Furthermore, as noted in section IV of this preamble, we do not expect
the proposed amendments to change the expected economic impact analysis
performed for the existing rule. We have, therefore, concluded that
this action will relieve regulatory burden for all directly regulated
small entities.
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain any unfunded mandate as described in
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect
small governments. The action imposes no enforceable duty on any state,
local, or tribal governments or the private sector.
F. 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.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. It will not have substantial direct effect on
tribal governments, on the relationship between the federal government
and Indian tribes, or on the
[[Page 15475]]
distribution of power and responsibilities between the federal
government and Indian tribes, as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to Executive Order 13045 because it is
not economically significant as defined in Executive Order 12866, and
because the EPA does not believe the environmental health or safety
risks addressed by this action present a disproportionate risk to
children. The proposed amendments serve to make technical
clarifications and corrections. We expect the proposed revisions will
have an insignificant effect on emission reductions. Therefore, the
proposed amendments should not appreciably increase risk for any
populations.
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not subject to Executive Order 13211 because it is
not a significant regulatory action under Executive Order 12866.
J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This rulemaking involves technical standards. As described in
section III.C of this preamble, the EPA proposes to use the voluntary
consensus standard ANSI/ASME PTC 19-10-1981--Part 10 ``Flue and Exhaust
Gas Analyses'' as an acceptable alternative to EPA Methods 3A and 3B
for the manual procedures only and not the instrumental procedures.
This method is available at the American National Standards Institute
(ANSI), 1899 L Street NW, 11th floor, Washington, DC 20036 and the
American Society of Mechanical Engineers (ASME), Three Park Avenue, New
York, NY 10016-5990. See https://wwww.ansi.org and https://www.asme.org.
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The
proposed amendments serve to make technical clarifications and
corrections. We expect the proposed revisions will have an
insignificant effect on emission reductions. Therefore, the proposed
amendments should not appreciably increase risk for any populations.
List of Subjects in 40 CFR Parts 60 and 63
Environmental protection, Administrative practice and procedures,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.
Dated: March 20, 2018.
E. Scott Pruitt,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--General Provisions
0
2. Section 60.17 is amended by revising paragraph (g)(14) to read as
follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(g) * * *
(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved
for Sec. Sec. 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i),
and (j), 60.105a(b), (d), (f), and (g), Sec. 60.106a(a), Sec.
60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and
4 to subpart FFFF, table 2 to subpart JJJJ, Sec. 60.285a(f),
Sec. Sec. 60.4415(a), 60.2145(s) and (t), 60.2710(s), (t), and (w),
60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL,
tables 2 and 3 to subpart MMMM, 60.5406(c), 60.5406a(c), 60.5407a(g),
60.5413(b), 60.5413a(b) and 60.5413a(d).
* * * * *
Subpart Ja--Standards of Performance for Petroleum Refineries for
Which Construction, Reconstruction, or Modification Commenced After
May 14, 2007
0
3. Section 60.105a is amended by revising paragraph (b)(2)(ii) to read
as follows:
Sec. 60.105a Monitoring of emissions and operations for fluid
catalytic cracking units (FCCU) and fluid coking units (FCU).
* * * * *
(b) * * *
(2) * * *
(ii) The owner or operator shall conduct performance evaluations of
each CO2 and O2 monitor according to the
requirements in Sec. 60.13(c) and Performance Specification 3 of
appendix B to this part. The owner or operator shall use Method 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, ``Flue and Exhaust
Gas Analyses,'' (incorporated by reference--see Sec. 60.17) is an
acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
* * * * *
0
4. Section 60.106a is amended by revising paragraph (a)(1)(iii) to read
as follows:
Sec. 60.106a Monitoring of emissions and operations for sulfur
recovery plants.
(a) * * *
(1) * * *
(iii) The owner or operator shall conduct performance evaluations
of each SO2 monitor according to the requirements in Sec.
60.13(c) and Performance Specification 2 of appendix B to part 60. The
owner or operator shall use Method 6 or 6C of appendix A-4 to part 60.
The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec. 60.17) is an acceptable
alternative to EPA Method 6.
* * * * *
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
5. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart CC--National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries
0
6. Section 63.641 is amended by:
0
a. Revising the definitions of ``Flare purge gas'', ``Flare
supplemental gas'' and ``Relief valve'';
0
b. Adding a new definition of ``Pressure relief device''; and
0
c. Revising paragraphs (1)(i) and (ii) of the definition of ``Reference
control technology for storage vessels.''
The revisions and addition read as follows:
[[Page 15476]]
Sec. 63.641 Definitions.
* * * * *
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 or for other safety reasons. 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 to
improve the heat content of combustion zone gas. Flare supplemental gas
does not include assist air or assist steam.
* * * * *
Pressure relief device means a valve, rupture disk, or similar
device used only to release an unplanned, nonroutine discharge of gas
from process equipment in order to avoid safety hazards or equipment
damage. A pressure relief device discharge can result from an operator
error, a malfunction such as a power failure or equipment failure, or
other unexpected cause. Such devices include conventional, spring-
actuated relief valves, balanced bellows relief valves, pilot-operated
relief valves, rupture disks, and breaking, buckling, or shearing pin
devices.
* * * * *
Reference control technology for storage vessels means either:
(1) * * *
(i) An internal floating roof, including an external floating roof
converted to an internal floating roof, meeting the specifications of
Sec. 63.1063(a)(1)(i), (a)(2), and (b) and Sec. 63.660(b)(2);
(ii) An external floating roof meeting the specifications of Sec.
63.1063(a)(1)(ii), (a)(2), and (b) and Sec. 63.660(b)(2); or
* * * * *
Relief valve means a type of pressure relief device that is
designed to re-close after the pressure relief.
* * * * *
0
7. Section 63.643 is amended by:
0
a. Revising paragraphs (c) introductory text, (c)(1), and (c)(1)(ii)
through (iv); and
0
b. Adding a new paragraph (c)(1)(v).
The revisions and addition read as follows:
Sec. 63.643 Miscellaneous process vent provisions.
* * * * *
(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 or
operator does not need to designate a maintenance vent as a Group 1 or
Group 2 miscellaneous process vent nor identify maintenance vents in a
Notification of Compliance Status report. The owner or operator must
comply with the applicable requirements in paragraphs (c)(1) through
(3) of this section for each maintenance vent according to the
compliance dates specified in table 11 of this subpart, unless an
extension is requested in accordance with the provisions in Sec.
63.6(i).
(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 meeting requirements in paragraphs
(a)(1) or (2) of this section, a fuel gas system, or back to the
process until one of the following conditions, as applicable, is met.
(i) * * *
(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 pounds per
square inch gauge (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) is less than 10
percent.
(iii) The equipment served by the maintenance vent contains less
than 72 pounds of total volatile organic compounds (VOC).
(iv) If the maintenance vent is associated with equipment
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers)
and a pure hydrogen supply is not available at the equipment at the
time of the startup, shutdown, maintenance, or inspection activity, 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 considering all such
maintenance vents at the refinery.
(v) If, after applying best practices to isolate and purge
equipment served by a maintenance vent, none of the applicable
criterion in paragraphs (c)(1)(i) through (iv) can be met prior to
installing or removing a blind flange or similar equipment blind, the
pressure in the equipment served by the maintenance vent is reduced to
2 psig or less, Active purging of the equipment may be used provided
the equipment pressure at the location where purge gas is introduced
remains at 2 psig or less.
* * * * *
0
8. Section 63.644 is amended by revising paragraph (c) introductory
text and adding paragraph (c)(3) to read as follows:
Sec. 63.644 Monitoring provisions for miscellaneous process vents.
* * * * *
(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 Sec. 63.643(a)
shall comply with either paragraph (c)(1), (2), or (3) 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 Sec. 63.643(a) is an emissions
standards violation. Equipment such as low leg drains and equipment
subject to Sec. 63.648 are not subject to this paragraph (c).
* * * * *
(3) Use a cap, blind flange, plug, or a second valve for an open-
ended valve or line following the requirements specified in Sec.
60.482-6(a)(2), (b) and (c).
* * * * *
0
9. Section 63.648 is amended by:
0
a. Revising the introductory text of paragraphs (a), (c), and (j);
0
b. Revising paragraphs (j)(3)(ii)(A) and (E), (j)(3)(iv), (j)(3)(v)
introductory text, and (j)(4).
The revisions and additions read as follows:
Sec. 63.648 Equipment leak standards.
(a) Each owner or operator of an existing source subject to the
provisions of this subpart shall comply with the provisions of 40 CFR
part 60, subpart VV, and paragraph (b) of this section except as
provided in paragraphs (a)(1) through (3), and (c) through (j) of this
section. Each owner or operator of a new source subject to the
provisions of this subpart shall comply with subpart H of this part
except as provided in paragraphs (c) through (j) of this section.
* * * * *
(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 Sec. Sec. 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 (j) of
this section.
* * * * *
(j) Except as specified in paragraph (j)(4) of this section, the
owner or
[[Page 15477]]
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 Sec. 60.482-4 or
Sec. 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 in organic HAP service.
* * * * *
(3) * * *
(ii) * * *
(A) Flow, temperature, liquid level and pressure indicators with
deadman switches, monitors, or automatic actuators. Independent, non-
duplicative systems within this category count as separate redundant
prevention measures.
(B) * * *
(C) * * *
(D) * * *
(E) Staged relief system where initial pressure relief device (with
lower set release pressure) discharges to a flare or other closed vent
system and control device.
* * * * *
(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 majeure event, 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 from an
affected pressure relief device are a violation of the pressure release
management work practice standards.
* * * * *
(4) Pressure relief devices routed to a control device. (i) 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.
(ii) If a pilot-operated pressure relief device is used and the
primary release valve is 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 required to comply only with paragraphs (j)(1) and
(2) of this section for the pilot discharge vent and is not required to
comply with paragraph (j)(3) of this section for the pilot-operated
pressure relief device.
(iii) If a balanced bellows pressure relief device is used and the
primary release valve is 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 required to comply only with paragraphs (j)(1) and
(2) of this section for the bonnet vent and is not required to comply
with paragraph (j)(3) of this section for the balanced bellows pressure
relief device.
(iv) Both the closed vent system and control device (if applicable)
referenced in paragraphs (j)(4)(i) through (iii) of this section must
meet the requirements of Sec. 63.644. When complying with this
paragraph (j)(4), all references to ``Group 1 miscellaneous process
vent'' in Sec. 63.644 mean ``pressure relief device.''
(v) 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 Sec. 63.670.
* * * * *
0
10. Section 63.655 is amended by:
0
a. Revising the introductory text of paragraph (f);
0
b. Revising paragraphs (f)(1)(i)(A)(1) through (3), (f)(1)(i)(B)(3),
(f)(1)(i)(C)(2), (f)(1)(iii), (f)(2), (f)(4), (f)(6), (g)(2)(B)(1) and
(g)(10) introductory text;
0
c. Redesignating paragraph (g)(10)(iii) as (g)(10)(iv);
0
d. Adding new paragraph (g)(10)(iii);
0
e. Revising paragraph (g)(13) introductory text and paragraphs
(h)(2)(ii);
0
f. Removing and reserving paragraph (h)(5)(iii)(B);
0
g. Revising paragraph (h)(8);
0
h. Revising paragraphs (h)(9)(i) introductory text and (ii)
introductory text;
0
i. Adding new paragraph (h)(10);
0
j. Revising paragraph (i)(3)(ii)(B);
0
k. Adding new paragraphs (i)(3)(ii)(C), (i)(5)(i) through (v);
0
l. Revising paragraphs (i)(7)(iii)(B) and (i)(11) introductory text;
0
m. Adding new paragraph (i)(11)(iv);
0
n. Revising paragraph (i)(12) introductory text and paragraph
(i)(12)(iv); and adding new paragraph (i)(12)(vi).
The revisions and additions read as follows:
Sec. 63.655 Reporting and recordkeeping requirements.
* * * * *
(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 Sec. 63.640(h) with the
exception of Notification of Compliance Status reports submitted to
comply with Sec. 63.640(l)(3), for storage vessels subject to the
compliance schedule specified in Sec. 63.640(h)(2), and for sources
listed in Table 11 of this subpart that have a compliance date on or
after February 1, 2016. Notification of Compliance Status reports
required by Sec. 63.640(l)(3), for storage vessels subject to the
compliance dates specified in Sec. 63.640(h)(2), and for sources
listed in Table 11 of this subpart that have a compliance date on or
after February 1, 2016 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 Sec. 63.640(h), a separate
Notification of Compliance Status report is not required within 150
days after the compliance dates specified in Sec. 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 the
Notification of Compliance Status report required by subpart R of this
part within 150 days after the compliance dates specified in Sec.
63.640(h).
(1) * * *
(i) * * *
(A) * * *
(1) For each Group 1 storage vessel complying with either Sec.
63.646 or Sec. 63.660 that is not included in an emissions average,
the method of compliance (i.e., internal floating roof, external
floating roof, or closed vent system and control device).
(2) For storage vessels subject to the compliance schedule
specified in Sec. 63.640(h)(2) that are not complying with Sec.
63.646 or Sec. 63.660 as applicable, the anticipated compliance date.
(3) For storage vessels subject to the compliance schedule
specified in Sec. 63.640(h)(2) that are complying with Sec. 63.646 or
Sec. 63.660, as applicable, and
[[Page 15478]]
the Group 1 storage vessels described in Sec. 63.640(l), the actual
compliance date.
(B) * * *
(3) If the owner or operator elects to submit the results of a
performance test, identification of the storage vessel and control
device for which the performance test will be submitted, and
identification of the emission point(s) that share the control device
with the storage vessel and for which the performance test will be
conducted. If the performance test is submitted electronically through
the EPA's Compliance and Emissions Data Reporting Interface (CEDRI) in
accordance with Sec. 63.655(h)(9), the process unit(s) tested, the
pollutant(s) tested, and the date that such performance test was
conducted may be submitted in the Notification of Compliance Status in
lieu of the performance test results. The performance test results must
be submitted to CEDRI by the date the Notification of Compliance Status
is submitted.
(C) * * *
(2) If a performance test is conducted instead of a design
evaluation, results of the performance test demonstrating that the
control device achieves greater than or equal to the required control
efficiency. A performance test conducted prior to the compliance date
of this subpart can be used to comply with this requirement, provided
that the test was conducted using EPA methods and that the test
conditions are representative of current operating practices. If the
performance test is submitted electronically through the EPA's
Compliance and Emissions Data Reporting Interface in accordance with
Sec. 63.655(h)(9), the process unit(s) tested, the pollutant(s)
tested, and the date that such performance test was conducted may be
submitted in the Notification of Compliance Status in lieu of the
performance test results. The performance test results must be
submitted to CEDRI by the date the Notification of Compliance Status is
submitted.
* * * * *
(iii) For miscellaneous process vents controlled by control devices
required to be tested under Sec. 63.645 of this subpart and Sec.
63.116(c) of subpart G of this part, performance test results including
the information in paragraphs (f)(1)(iii)(A) and (B) of this section.
Results of a performance test conducted prior to the compliance date of
this subpart can be used provided that the test was conducted using the
methods specified in Sec. 63.645 and that the test conditions are
representative of current operating conditions. If the performance test
is submitted electronically through the EPA's Compliance and Emissions
Data Reporting Interface in accordance with Sec. 63.655(h)(9), the
process unit(s) tested, the pollutant(s) tested, and the date that such
performance test was conducted may be submitted in the Notification of
Compliance Status in lieu of the performance test results. The
performance test results must be submitted to CEDRI by the date the
Notification of Compliance Status is submitted.
* * * * *
(2) If initial performance tests are required by Sec. Sec. 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, for data collected
using test methods supported by the EPA's Electronic Reporting Tool
(ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at
the time of the test, you must submit the results in accordance with
Sec. 63.655(h)(9) by the date that you submit the Notification of
Compliance Status, and you must include the process unit(s) tested, the
pollutant(s) tested, and the date that such performance test was
conducted in the Notification of Compliance Status. All other
performance test results must be reported in the Notification of
Compliance Status.
* * * * *
(4) Results of any continuous monitoring system performance
evaluations shall be included in the Notification of Compliance Status
report, unless the results are required to be submitted electronically
by Sec. 63.655(h)(9). For performance evaluation results required to
be submitted through CEDRI, submit the results in accordance with Sec.
63.655(h)(9) by the date that you submit the Notification of Compliance
Status and include the process unit where the CMS is installed, the
parameter measured by the CMS, and the date that the performance
evaluation was conducted in the Notification of Compliance Status.
* * * * *
(6) Notification of Compliance Status reports required by Sec.
63.640(l)(3), for storage vessels subject to the compliance dates
specified in Sec. 63.640(h)(2), and for sources listed in Table 11 of
this subpart that have a compliance date on or after February 1, 2016
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 or the requirements with compliance dates on or
after February 1, 2016, became effective, and may be combined with the
periodic report. Six-month periods shall be the same 6-month periods
specified in paragraph (g) of this section. The Notification of
Compliance Status report shall include the information specified in
paragraphs (f)(1) through (f)(5) 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, as part of the
periodic report, or in any combination of these four. If the required
information has been submitted before the date 60 days after the end of
the 6-month period in which the addition of the Group 1 emission point
took place, a separate Notification of Compliance Status report is not
required within 60 days after the end of the 6-month period. If an
owner or operator submits the information specified in paragraphs
(f)(1) through (f)(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.
* * * * *
(g) * * *
(2) * * *
(B) * * *
(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 area.
* * * * *
(10) For pressure relief devices subject to the requirements Sec.
63.648(j), Periodic Reports must include the information specified in
paragraphs (g)(10)(i) through (iv) of this section.
* * * * *
(iii) For pilot-operated pressure relief devices in organic HAP
service, report each pressure release to the atmosphere through the
pilot vent that equals or exceeds 72 pounds of VOC per day, including
duration of the pressure release through the pilot vent and
[[Page 15479]]
estimate of the mass quantity of each organic HAP released.
* * * * *
(13) For maintenance vents subject to the requirements in Sec.
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 Sec. 63.643(c)(1). For the purposes
of this reporting requirement, owners or operators complying with Sec.
63.643(c)(1)(iv) must report each venting event for which the lower
explosive limit is 20 percent or greater; owners or operators complying
with Sec. 63.643(c)(1)(v) must report each venting event conducted
under those provisions and include an explanation for each event as to
why utilization of this alternative was required.
* * * * *
(h) * * *
(2) * * *
(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
Sec. 63.120(b)(1) or (2) of subpart G or Sec. 63.1063(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.
* * * * *
(8) For fenceline monitoring systems subject to Sec. 63.658, each
owner or operator shall submit the following information to the EPA's
Compliance and Emissions Data Reporting Interface (CEDRI) on a
quarterly basis. (CEDRI can be accessed through the EPA's Central Data
Exchange (CDX) (https://cdx.epa.gov/). The first quarterly report must
be submitted once the owner or operator has obtained 12 months of data.
The first quarterly report must cover the period beginning on the
compliance date that is specified in Table 11 of this subpart and
ending on March 31, June 30, September 30 or December 31, whichever
date is the first date that occurs after the owner or operator has
obtained 12 months of data (i.e., the first quarterly report will
contain between 12 and 15 months of data). Each subsequent quarterly
report must cover one of the following reporting periods: Quarter 1
from January 1 through March 31; Quarter 2 from April 1 through June
30; Quarter 3 from July 1 through September 30; and Quarter 4 from
October 1 through December 31. Each quarterly report must be
electronically submitted no later than 45 calendar days following the
end of the reporting period.
(i) Facility name and address.
(ii) Year and reporting quarter (i.e., Quarter 1, Quarter 2,
Quarter 3, or Quarter 4).
(iii) For the first reporting period and for any reporting period
in which a passive monitor is added or moved, for each passive monitor:
the latitude and longitude location coordinates; the sampler name; and
identification of the type of sampler (i.e., regular monitor, extra
monitor, duplicate, field blank, inactive). 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.
(iv) The beginning and ending dates for each sampling period.
(v) Individual sample results for benzene reported in units of
[micro]g/m\3\ for each monitor for each sampling period that ends
during the reporting period. Results below the method detection limit
shall be flagged as below the detection limit and reported at the
method detection limit.
(vi) Data flags that indicate each monitor that was skipped for the
sampling period, if the owner or operator uses an alternative sampling
frequency under Sec. 63.658(e)(3).
(vii) Data flags for each outlier determined in accordance with
Section 9.2 of Method 325A of appendix A of this part. For each
outlier, the owner or operator must submit the individual sample result
of the outlier, as well as the evidence used to conclude that the
result is an outlier.
(viii) Based on the information provided for the individual sample
results, CEDRI will calculate the biweekly concentration difference
([Delta]c) for benzene for each sampling period and the annual average
[Delta]c for benzene for each sampling period. The owner or operator
may change these calculated values, but an explanation must be provided
whenever a calculated value is changed.
(9) * * *
(i) Unless otherwise specified by this subpart, 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.
* * * * *
(ii) Unless otherwise specified by this subpart, 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.
* * * * *
(10) Extensions to electronic reporting deadlines.
(i) If you are required to electronically submit a report through
the Compliance and Emissions Data Reporting Interface (CEDRI) in the
EPA's Central Data Exchange (CDX), and due to a planned or actual
outage of either the EPA's CEDRI or CDX systems within the period of
time beginning 5 business days prior to the date that the submission is
due, you will be or are precluded from accessing CEDRI or CDX and
submitting a required report within the time prescribed, you may assert
a claim of EPA system outage for failure to timely comply with the
reporting requirement. You must submit notification to the
Administrator in writing as soon as possible following the date you
first knew, or through due diligence should have known, that the event
may cause or caused a delay in reporting. You must provide to the
Administrator a written description identifying the date, time and
length of the outage; a rationale for attributing the delay in
reporting beyond the regulatory deadline to the EPA system outage;
describe the measures taken or to be taken to minimize the delay in
reporting; and identify a date by which you propose to report, or if
you have already met the reporting requirement at the time of the
notification, the date you reported. In any circumstance, the report
must be submitted electronically as soon as possible after the outage
is resolved. The decision to accept the claim of EPA system outage and
allow an extension to the reporting deadline is solely within the
discretion of the Administrator.
(ii) If you are required to electronically submit a report through
CEDRI in the EPA's CDX and a force majeure event is about to occur,
occurs, or has occurred or there are lingering effects from such an
event within the period of time beginning 5 business days prior to the
date the submission is due, the owner or operator may assert a claim of
force majeure for failure to timely comply with the reporting
requirement. For the purposes of this paragraph, a force majeure event
is defined as an event that will be or has been caused by circumstances
beyond the control of the affected facility, its contractors, or any
entity controlled by
[[Page 15480]]
the affected facility that prevents you from complying with the
requirement to submit a report electronically within the time period
prescribed. Examples of such events are acts of nature (e.g.,
hurricanes, earthquakes, or floods), acts of war or terrorism, or
equipment failure or safety hazard beyond the control of the affected
facility (e.g., large scale power outage). If you intend to assert a
claim of force majeure, you must submit notification to the
Administrator in writing as soon as possible following the date you
first knew, or through due diligence should have known, that the event
may cause or caused a delay in reporting. You must provide to the
Administrator a written description of the force majeure event and a
rationale for attributing the delay in reporting beyond the regulatory
deadline to the force majeure event; describe the measures taken or to
be taken to minimize the delay in reporting; and identify a date by
which you propose to report, or if you have already met the reporting
requirement at the time of the notification, the date you reported. In
any circumstance, the reporting must occur as soon as possible after
the force majeure event occurs. The decision to accept the claim of
force majeure and allow an extension to the reporting deadline is
solely within the discretion of the Administrator.
* * * * *
(i) * * *
(3) * * *
(ii) * * *
(B) Block average values for 1 hour or shorter periods calculated
from all measured data values during each period. If values are
measured more frequently than once per minute, a single value for each
minute may be used to calculate the hourly (or shorter period) block
average instead of all measured values; or
(C) All values that meet the set criteria for variation from
previously recorded values using an automated data compression
recording system.
(1) The automated data compression recording system shall be
designed to:
(i) Measure the operating parameter value at least once every hour.
(ii) Record at least 24 values each day during periods of
operation.
(iii) Record the date and time when monitors are turned off or on.
(iv) Recognize unchanging data that may indicate the monitor is not
functioning properly, alert the operator, and record the incident.
(v) Compute daily average values of the monitored operating
parameter based on recorded data.
(2) 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 demonstration that the
system meets all criteria of paragraph (i)(3)(ii)(C)(1) of this
section.
* * * * *
(5) * * *
(i) Identification of all petroleum refinery process unit heat
exchangers at the facility and the average annual HAP concentration of
process fluid or intervening cooling fluid estimated when developing
the Notification of Compliance Status report.
(ii) Identification of all heat exchange systems subject to the
monitoring requirements in Sec. 63.654 and identification of all heat
exchange systems that are exempt from the monitoring requirements
according to the provisions in Sec. 63.654(b). For each heat exchange
system that is subject to the monitoring requirements in Sec. 63.654,
this must include identification of all heat exchangers within each
heat exchange system, and, for closed-loop recirculation systems, the
cooling tower included in each heat exchange system.
(iii) Results of the following monitoring data for each required
monitoring event:
(A) Date/time of event.
(B) Barometric pressure.
(C) El Paso air stripping apparatus water flow milliliter/minute
(ml/min) and air flow, ml/min, and air temperature, [deg]Celsius.
(D) FID reading (ppmv).
(E) Length of sampling period.
(F) Sample volume.
(G) Calibration information identified in Section 5.4.2 of the
``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 (incorporated by reference--see Sec. 63.14).
(iv) The date when a leak was identified, the date the source of
the leak was identified, and the date when the heat exchanger was
repaired or taken out of service.
(v) If a repair is delayed, the reason for the delay, the schedule
for completing the repair, the heat exchange exit line flow or cooling
tower return line average flow rate at the monitoring location (in
gallons/minute), and the estimate of potential strippable hydrocarbon
emissions for each required monitoring interval during the delay of
repair.
* * * * *
(7) * * *
(iii) * * *
(B) The pressure or temperature of the coke drum vessel, as
applicable, for the 5-minute period prior to the pre-vent draining.
* * * * *
(11) For each pressure relief device subject to the pressure
release management work practice standards in Sec. 63.648(j)(3), the
owner or operator shall keep the records specified in paragraphs
(i)(11)(i) through (iii) of this section. For each pilot-operated
pressure relief device subject to the requirements at Sec.
63.648(j)(4)(ii) or (iii), the owner or operator shall keep the records
specified in paragraph (i)(11)(iv) of this section.
* * * * *
(iv) For pilot-operated pressure relief devices, general or
release-specific records for estimating the quantity of VOC released
from the pilot vent during a release event, and records of calculations
used to determine the quantity of specific HAP released for any event
or series of events in which 72 or more pounds of VOC are released in a
day.
(12) For each maintenance vent opening subject to the requirements
in Sec. 63.643(c), the owner or operator shall keep the applicable
records specified in (i)(12)(i) through (vi) of this section.
* * * * *
(iv) If complying with the requirements of Sec. 63.643(c)(1)(iii),
records used to estimate the total quantity of VOC in the equipment and
the type and size limits of equipment that contain less than 72 pounds
of VOC at the time of maintenance vent opening. For each maintenance
vent opening for which the deinventory procedures specified in
paragraph (i)(12)(i) of this section are not followed or for which the
equipment opened exceeds the type and size limits established in the
records specified in this paragraph, 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.
* * * * *
(vi) If complying with the requirements of Sec. 63.643(c)(1)(v),
identification of the maintenance vent, the process units or equipment
associated with the maintenance vent,
[[Page 15481]]
records documenting actions taken to comply with other applicable
alternatives and why utilization of this alternative was required, the
date of maintenance vent opening, the equipment pressure and lower
explosive limit of the vapors in the equipment at the time of
discharge, an indication of whether active purging was performed and
the pressure of the equipment during the installation or removal of the
blind if active purging was used, the duration the maintenance vent was
open during the blind installation or removal process, 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.
* * * * *
0
11. Section 63.657 is amended by revising paragraphs (a)(1)(i) and
(ii), (a)(2)(i) and (ii), (b)(5), and (e) to read as follows:
Sec. 63.657 Delayed coking unit decoking operation standards.
(a) * * *
(1) * * *
(i) An average vessel pressure of 2 psig or less determined on a
rolling 60-event average; or
(ii) An average vessel temperature of 220 degrees Fahrenheit or
less determined on a rolling 60-event average.
(2) * * *
(i) A vessel pressure of 2.0 psig or less for each decoking event;
or
(ii) A vessel temperature of 218 degrees Fahrenheit or less for
each decoking event.
* * * * *
(b) * * *
(5) The output of the pressure monitoring system must be reviewed
each day the unit is operated 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.
* * * * *
(e) The owner or operator of a delayed coking unit using the
``water overflow'' method of coke cooling prior to complying with the
applicable requirements in paragraph (a) of this section must overflow
the water to a separator or similar disengaging device that is operated
in a manner to prevent entrainment of gases from the coke drum vessel
to the overflow water storage tank. Gases from the separator or
disengaging device must be routed to a closed blowdown system or
otherwise controlled following the requirements for a Group 1
miscellaneous process vent. The liquid from the separator or
disengaging device must be hardpiped to the overflow water storage tank
or similarly transported to prevent exposure of the overflow water to
the atmosphere. The overflow water storage tank may be an open or
uncontrolled 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 subject to
this paragraph shall determine the coke drum vessel temperature as
specified in paragraphs (c) and (d) of this section and shall not
otherwise drain or vent the coke drum until the coke drum vessel
temperature is at or below the applicable limits in paragraph
(a)(1)(ii) or (a)(2)(ii) of this section.
* * * * *
0
12. Section 63.658 is amended by revising paragraphs (c)(1), (c)(2),
(c)(3), (d)(1), (d)(2), (e) introductory text, (e)(3)(iv), (f)(1)(i),
and (f)(1)(i)(B) to read as follows:
Sec. 63.658 Fenceline monitoring provisions.
* * * * *
(c) * * *
(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
vessel loading operations, one passive monitor should be sited on the
shoreline adjacent to the dock. For this subpart, an additional monitor
is not required if the only emission sources within 50 meters of the
monitoring boundary are equipment leak sources satisfying all of the
conditions in paragraphs (c)(1)(i) through (iv) of this section.
(i) The equipment leak sources in organic HAP service within 50
meters of the monitoring boundary are limited to valves, pumps,
connectors, sampling connections, and open-ended lines. If compressors,
pressure relief devices, or agitators in organic HAP service are
present within 50 meters of the monitoring boundary, the additional
passive monitoring location specified in Section 8.2.1.3 in Method 325A
of appendix A of this part must be used.
(ii) All equipment leak sources in gas or light liquid service (and
in organic HAP service), including valves, pumps, connectors, sampling
connections and open-ended lines, must be monitored using EPA Method 21
of 40 CFR part 60, appendix A-7 no less frequently than quarterly with
no provisions for skip period monitoring, or according to the
provisions of 63.11(c) Alternative Work practice for monitoring
equipment for leaks. For the purpose of this provision, a leak is
detected if the instrument reading equals or exceeds the applicable
limits in paragraphs (c)(1)(ii)(A) through (E) of this section:
(A) For valves, pumps or connectors at an existing source, an
instrument reading of 10,000 ppmv.
(B) For valves or connectors at a new source, an instrument reading
of 500 ppmv.
(C) For pumps at a new source, an instrument reading of 2,000 ppmv.
(D) For sampling connections or open-ended lines, an instrument
reading of 500 ppmv above background.
(E) For equipment monitored according to the Alternative Work
practice for monitoring equipment for leaks, the leak definitions
contained in 63.11 (c) (6)(i) through (iii).
(iii) All equipment leak sources in organic HAP service, including
sources in gas, light liquid and heavy liquid service, must be
inspected using visual, audible, olfactory, or any other detection
method at least monthly. A leak is detected if the inspection
identifies a potential leak to the atmosphere or if there are
indications of liquids dripping.
(iv) All leaks identified by the monitoring or inspections
specified in paragraphs (c)(1)(ii) or (iii) of this section must be
repaired no later than 15 calendar days after it is detected with no
provisions for delay of repair. If a repair is not completed within 15
calendar days, the additional passive monitor specified in Section
8.2.1.3 in Method 325A of appendix A of this part must be used.
(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 Sec. 63.640(g) may influence the
sampler measurements. If the owner or operator elects to collect one or
more background samples, the owner or 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
site-specific monitoring plan, the background sampler(s) should be
operated co-currently with the routine samplers.
(3) If there are 19 or fewer monitoring locations, the owner or
operator shall
[[Page 15482]]
collect at least one co-located duplicate sample per sampling period
and at least one field blank per sampling period. If there are 20 or
more monitoring locations, the owner or operator shall collect at least
two co-located duplicate samples per sampling period and at least one
field blank per sampling period. The co-located duplicates may be
collected at any of the perimeter sampling locations.
* * * * *
(d) * * *
(1) If a near-field source correction is used as provided in
paragraph (i)(2) of this section or if an alternative test method is
used that provides time-resolved measurements, the owner or operator
shall:
* * * * *
(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 8.3.1 through
8.3.3 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.
* * * * *
(e) The owner or operator shall use a sampling period and sampling
frequency as specified in paragraphs (e)(1) through (3) of this
section.
* * * * *
(3) * * *
(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 [micro]g/m\3\ for 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.
* * * * *
(f) * * *
(1) * * *
(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 [Delta]c as the difference in these
concentrations. Co-located samples must be averaged together for the
purposes of determining the benzene concentration for that sampling
location, and, if applicable, for determining [Delta]c. 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:
* * * * *
(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 and zero as the lowest sample result when calculating
[Delta]c.
* * * * *
0
13. Section 63.660 is amended by revising the undesignated introductory
text, paragraph (b) introductory text, paragraphs (b)(1), (e) and
(i)(2) to read as follows:
Sec. 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 Sec.
63.640(h), the owner or operator of a Group 1 storage vessel storing
liquid with a maximum true vapor pressure less than 76.6 kilopascals
(11.0 pounds per square inch) that is part of a new or existing source
shall comply with either the requirements in subpart WW or SS of this
part according to the requirements in paragraphs (a) through (i) of
this section and the owner or operator of a Group 1 storage vessel
storing liquid with a maximum true vapor pressure greater than or equal
to 76.6 kilopascals (11.0 pounds per square inch) that is part of a new
or existing source shall comply with the requirements in subpart SS of
this part according to the requirements in paragraphs (a) through (i)
of this section.
* * * * *
(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. If the
floating roof storage vessel does not meet the requirements of Sec.
63.1063(a)(2)(i) through (a)(2)(viii) as of June 30, 2014, these
requirements do not apply until the next time the vessel is completely
emptied and degassed, or January 30, 2026, whichever occurs first.
(1) In addition to the options presented in Sec. Sec.
63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage
vessel may comply with Sec. 63.1063(a)(2)(viii) using a flexible
enclosure device and either a gasketed or welded cap on the top of the
guidepole.
* * * * *
(e) For storage vessels previously subject to requirements in Sec.
63.646, initial inspection requirements in Sec. 63.1063(c)(1) and
(2)(i) (i.e., those related to the initial filling of the storage
vessel) or in Sec. 63.983(b)(1)(A), as applicable, are not required.
Failure to perform other inspections and monitoring required by this
section shall constitute a violation of the applicable standard of this
subpart.
* * * * *
(i) * * *
(2) If a closed vent system contains a bypass line, the owner or
operator shall comply with the provisions of either Sec.
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 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
Sec. 63.648 are not subject to this paragraph (i)(2).
* * * * *
0
14. Section 63.670 is amended by:
0
a. Revising paragraph (f);
0
b. Revising paragraphs (h) introductory text, (h)(1), and (i)
introductory text;
0
c. Adding new paragraphs (i)(5) and (6);
0
d. Revising paragraphs (j)(6);
0
h. Revising the definition of the Qcum term in the equation
in paragraph (k)(3);
0
i. Revising paragraph (m)(2) introductory text;
0
j. Revising the definitions of the QNG2, QNG1,
and NHVNG terms in the equation in paragraph (m)(2);
0
j. Revising paragraph (n)(2) introductory text and the definitions of
the QNG2, QNG1, and NHVNG terms in the
equation in paragraph (n)(2); and
0
l. Revising paragraphs (o) introductory text, (o)(1)(ii)(B),
(o)(1)(iii)(B), and (o)(3)(i). The revisions and additions read as
follows:
Sec. 63.670 Requirements for flare control devices.
* * * * *
(f) Dilution operating limits for flares with perimeter assist air.
Except as provided in paragraph (f)(1) of this section, for each flare
actively receiving perimeter assist air, the owner or operator shall
operate the flare to maintain the net heating value dilution
[[Page 15483]]
parameter (NHVdil) at or above 22 British thermal units per square foot
(Btu/ft\2\) 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.
(1) If the only assist air provided to a specific flare is
perimeter assist air intentionally entrained in lower and upper steam
at the flare tip and the flare tip diameter is 9 inches or greater, the
owner or operator shall comply only with the NHVcz operating
limit in paragraph (e) of this section for that flare.
(2) Reserved.
* * * * *
(h) Visible emissions monitoring. The owner or operator shall
conduct an initial visible emissions demonstration using an observation
period of 2 hours using Method 22 at 40 CFR part 60, appendix A-7. The
initial visible emissions demonstration should be conducted the first
time regulated materials are routed to the flare. 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 Sec.
63.655(g)(11)(ii).
(1) At least once per day for each day regulated material is routed
to the flare, 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 while regulated material is routed to the flare, 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 5-minute 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. Daily 5-minute
Method 22 observations are not required to be conducted for days the
flare does not receive any regulated material.
* * * * *
(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 flare supplemental gas
used. Different flow monitoring methods may be used to measure
different gaseous streams that make up 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. Flow monitoring system requirements and
acceptable alternatives are provided in paragraphs (i)(1) through (6)
of this section.
* * * * *
(5) Continuously monitoring fan speed or power and using fan curves
is an acceptable method for continuously monitoring assist air flow
rates.
(6) For perimeter assist air intentionally entrained in lower and
upper steam, the monitored steam flow rate and the maximum design air-
to-steam volumetric flow ratio of the entrainment system may be used to
determine the assist air flow rate.
(j) * * *
(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 (iii) of this section.
* * * * *
(k) * * *
(3) * * *
* * * * *
Qcum = Cumulative volumetric flow over 15-minute
block average period, standard cubic feet.
* * * * *
(m) * * *
(2) Owners or operators of flares that use the feed-forward
calculation 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 flare supplemental gas flow additions to the flare must
determine the 15-minute block average NHVcz using the
following equation.
* * * * *
QNG2 = Cumulative volumetric flow of flare
supplemental gas during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of flare
supplemental gas 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 flare supplemental gas
for the 15-minute block period determined according to the
requirements in paragraph (j)(5) of this section, Btu/scf.
* * * * *
(n) * * *
(2) Owners or operators of flares that use the feed-forward
calculation 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 flare supplemental 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
volumetric flow of perimeter assist air, the 15-minute block average
NHVdil parameter does not need to be calculated.
* * * * *
QNG2 = Cumulative volumetric flow of flare
supplemental gas during the 15-minute block period, scf.
QNG1 = Cumulative volumetric flow of flare
supplemental gas 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 flare supplemental gas
for the 15-minute block period determined according to the
requirements in paragraph (j)(5) of this section, Btu/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 (7) of this section.
(1) * * *
(ii) * * *
(B) Implementation of prevention measures listed for pressure
relief devices in Sec. 63.648(j)(3)(ii)(A) through (E) for each
pressure relief device that can discharge to the flare.
* * * * *
[[Page 15484]]
(iii) * * *
(B) The smokeless capacity of the flare based on a 15-minute block
average and design conditions. Note: A single value must be provided
for the smokeless capacity of the flare.
* * * * *
(3) * * *
(i) The vent gas flow rate exceeds the smokeless capacity of the
flare based on a 15-minute block average and visible emissions are
present from the flare for more than 5 minutes during any 2 consecutive
hours during the release event.
* * * * *
0
15. Table 6 to Subpart CC is amended by revising the entries
``63.6(f)(3)'', ``63.6(h)(8)'', 63.7(a)(2)'', ``63.7(f)'',
``63.7(h)(3)'', and ``63.8(e)'' to read as follows:
Table 6--General Provisions Applicability to Subpart CC a
----------------------------------------------------------------------------------------------------------------
Reference Applies to subpart CC Comment
----------------------------------------------------------------------------------------------------------------
* * * * * * *
63.6(f)(3).............................. Yes........................ Except the cross-references to Sec.
63.6(f)(1) and (e)(1)(i) are changed to
Sec. 63.642(n) and performance test
results may be written or electronic.
* * * * * * *
63.6(h)(8).............................. Yes........................ Except performance test results may be
written or electronic.
* * * * * * *
63.7(a)(2).............................. Yes........................ Except test results must be submitted in
the Notification of Compliance Status
report due 150 days after compliance
date, as specified in Sec. 63.655(f)
of subpart CC, unless they are required
to be submitted electronically in
accordance with Sec. 63.655(h)(9).
Test results required to be submitted
electronically must be submitted by the
date the Notification of Compliance
Status report is submitted.
* * * * * * *
63.7(f)................................. Yes........................ Except that additional notification or
approval is not required for
alternatives directly specified in
Subpart CC.
* * * * * * *
63.7(h)(3).............................. Yes........................ Yes, except site-specific test plans
shall not be required, and where Sec.
63.7(h)(3)(i) specifies waiver submittal
date, the date shall be 90 days prior to
the Notification of Compliance Status
report in Sec. 63.655(f).
* * * * * * *
63.8(e)................................. Yes........................ Except that results are to be submitted
electronically if required by Sec.
63.655(h)(9).
* * * * * * *
----------------------------------------------------------------------------------------------------------------
* * * * *
0
16. Table 13 to Subpart CC is amended by revising the entry ``Hydrogen
analyzer'' to read as follows:
Table 13--Calibration and Quality Control Requirements for CPMS
----------------------------------------------------------------------------------------------------------------
Minimum accuracy
Parameter requirements Calibration requirements
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Hydrogen analyzer....................... 2 percent over Specify calibration requirements in your
the concentration measured site specific CPMS monitoring plan.
or 0.1 volume percent, Calibration requirements should follow
whichever is greater. manufacturer's recommendations at a
minimum.
Where feasible, 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
occurs.
* * * * * * *
----------------------------------------------------------------------------------------------------------------
[[Page 15485]]
Subpart UUU--National Emission Standards for Hazardous Air
Pollutants for Petroleum Refineries: Catalytic Cracking Units,
Catalytic Reforming Units, and Sulfur Recovery Units
0
17. Section 63.1564 is amended by revising the first sentence in
paragraphs (b)(4)(iii), (c)(3), and (c)(4) and revising paragraph
(c)(5)(iii) to read as follows:
Sec. 63.1564 What are my requirements for metal HAP emissions from
catalytic cracking units?
* * * * *
(b) * * *
(4) * * *
(iii) If you elect Option 3 in paragraph (a)(1)(v) of this section,
the Ni lb/hr emission limit, compute your Ni emission rate using
Equation 5 of this section and your site-specific Ni operating limit
(if you use a continuous opacity monitoring system) using Equations 6
and 7 of this section as follows: * * *
* * * * *
(c) * * *
(3) If you use a continuous opacity monitoring system and elect to
comply with Option 3 in paragraph (a)(1)(v) of this section, determine
continuous compliance with your site-specific Ni operating limit by
using Equation 11 of this section as follows: * * *
(4) If you use a continuous opacity monitoring system and elect to
comply with Option 4 in paragraph (a)(1)(vi) of this section, determine
continuous compliance with your site-specific Ni operating limit by
using Equation 12 of this section as follows: * * *
(5) * * *
(iii) Calculating the inlet velocity to the primary internal
cyclones in feet per second (ft/sec) by dividing the average volumetric
flow rate (acfm) by the cumulative cross-sectional area of the primary
internal cyclone inlets (ft\2\) and by 60 seconds/minute (for unit
conversion).
* * * * *
0
18. Section 63.1565 is amended by revising paragraph (a)(5)(ii) to read
as follows:
Sec. 63.1565 What are my requirements for organic HAP emissions from
catalytic cracking units?
(a) * * *
(5) * * *
(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) or 1 volume percent (wet basis with
no moisture correction).
* * * * *
0
19. Section 63.1569 is amended by revising paragraph (c)(2) to read as
follows:
Sec. 63.1569 What are my requirements for HAP emissions from bypass
lines?
* * * * *
(c) * * *
(2) Demonstrate continuous compliance with the work practice
standard in paragraph (a)(3) of this section by complying with the
procedures in your operation, maintenance, and monitoring plan.
0
20. Section 63.1571 is amended by revising the paragraphs (a)
introductory text, (a)(5) introductory text and (a)(6) introductory
text, and by revising paragraphs (d)(1) and (d)(2) to read as follows:
Sec. 63.1571 How and when do I conduct a performance test or other
initial compliance demonstration?
(a) When must I conduct a performance test? You must conduct
initial performance tests and report the results by no later than 150
days after the compliance date specified for your source in Sec.
63.1563 and according to the provisions in Sec. 63.7(a)(2) and Sec.
63.1574(a)(3). If you are required to do a performance evaluation or
test for a semi-regenerative catalytic reforming unit catalyst
regenerator vent, you may do them at the first regeneration cycle after
your compliance date and report the results in a followup Notification
of Compliance Status report due no later than 150 days after the test.
You must conduct additional performance tests as specified in
paragraphs (a)(5) and (6) of this section and report the results of
these performance tests according to the provisions in Sec.
63.1575(f).
* * * * *
(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 or within 60 days of startup of a new unit.
* * * * *
(6) One-time performance testing for Hydrogen Cyanide (HCN).
Conduct a performance test for HCN from each catalytic cracking unit no
later than August 1, 2017 or within 60 days of startup of a new unit
according to the applicable requirements in paragraphs (a)(6)(i) and
(ii) of this section.
* * * * *
(d) * * *
(1) If you must meet the HAP metal emission limitations in Sec.
63.1564, you elect the option in paragraph (a)(1)(v) in Sec. 63.1564
(Ni lb/hr), 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. Section
63.1564(b)(2) allows you to adjust the laboratory measurements of the
equilibrium catalyst Ni concentration to the maximum level. You must
make this adjustment using Equation 1 of this section as follows: * * *
(2) If you must meet the HAP metal emission limitations in Sec.
63.1564, you elect the option in paragraph (a)(1)(vi) in Sec. 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. Section 63.1564(b)(2) allows you to adjust the laboratory
measurements of the equilibrium catalyst Ni concentration to the
maximum level. You must make this adjustment using Equation 2 of this
section as follows: * * *
* * * * *
0
21. Section 63.1572 is amended by revising paragraphs (c)(1) and (d)(1)
to read as follows:
Sec. 63.1572 What are my monitoring installation, operation, and
maintenance requirements?
* * * * *
(c) * * *
(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 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.
* * * * *
(d) * * *
(1) Except for monitoring malfunctions, associated repairs, and
required quality assurance or control activities (including as
applicable, calibration checks and required zero
[[Page 15486]]
and span adjustments), you must conduct all monitoring in continuous
operation (or collect data at all required intervals) at all times the
affected source is operating.
* * * * *
0
22. Section 63.1573 is amended by revising paragraph (a)(1)
introductory text to read as follows:
Sec. 63.1573 What are my monitoring alternatives?
(a) What are the approved alternatives for measuring gas flow rate?
(1) You may use this alternative to a continuous parameter monitoring
system for the catalytic regenerator exhaust gas flow rate for your
catalytic cracking unit if the unit does not introduce any other gas
streams into the catalyst regeneration vent (i.e., complete combustion
units with no additional combustion devices). You may also use this
alternative to a continuous parameter monitoring system for the
catalytic regenerator atmospheric exhaust gas flow rate for your
catalytic reforming unit during the coke burn and rejuvenation cycles
if the unit operates as a constant pressure system during these cycles.
You may also use this alternative to a continuous parameter monitoring
system for the gas flow rate exiting the catalyst regenerator to
determine inlet velocity to the primary internal cyclones as required
in Sec. 63.1564(c)(5) regardless of the configuration of the catalytic
regenerator exhaust vent downstream of the regenerator (i.e.,
regardless of whether or not any other gas streams are introduced into
the catalyst regeneration vent). If you use this alternative, you shall
use the same procedure for the performance test and for monitoring
after the performance test. You shall:
* * * * *
0
23. Section 63.1574 is amended by revising paragraph (a)(3)(ii) to read
as follows:
Sec. 63.1574 What notifications must I submit and when?
(a) * * *
(3) * * *
(ii) For each initial compliance demonstration that includes a
performance test, you must submit the notification of compliance status
no later than 150 calendar days after the compliance date specified for
your affected source in Sec. 63.1563. For data collected using test
methods supported by the EPA's Electronic Reporting Tool (ERT) as
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of
the test, you must submit the results in accordance with Sec.
63.1575(k)(1)(i) by the date that you submit the Notification of
Compliance Status, and you must include the process unit(s) tested, the
pollutant(s) tested, and the date that such performance test was
conducted in the Notification of Compliance Status. For performance
evaluations of continuous monitoring systems (CMS) measuring relative
accuracy test audit (RATA) pollutants that are supported by the EPA's
ERT as listed on the EPA's ERT website at the time of the evaluation,
you must submit the results in accordance with Sec. 63.1575(k)(2)(i)
by the date that you submit the Notification of Compliance Status, and
you must include the process unit where the CMS is installed, the
parameter measured by the CMS, and the date that the performance
evaluation was conducted in the Notification of Compliance Status. All
other performance test and performance evaluation results (i.e., those
not supported by EPA's ERT) must be reported in the Notification of
Compliance Status.
* * * * *
0
24. Section 63.1575 is amended by revising paragraphs (f)(1), (k)(1)
introductory text and (k)(2) introductory text, and adding paragraph
(l) to read as follows.
Sec. 63.1575 What reports must I submit and when?
* * * * *
(f) * * *
(1) A copy of any performance test or performance evaluation of a
CMS done during the reporting period on any affected unit, if
applicable. The report must 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 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. For data collected using test methods supported by the
EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT
website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test, you must submit
the results in accordance with Sec. 63.1575(k)(1)(i) by the date that
you submit the compliance report, and instead of including a copy of
the test report in the compliance report, you must include the process
unit(s) tested, the pollutant(s) tested, and the date that such
performance test was conducted in the compliance report. For
performance evaluations of CMS measuring relative accuracy test audit
(RATA) pollutants that are supported by the EPA's ERT as listed on the
EPA's ERT website at the time of the evaluation, you must submit the
results in accordance with Sec. 63.1575(k)(2)(i) by the date that you
submit the compliance report, and you must include the process unit
where the CMS is installed, the parameter measured by the CMS, and the
date that the performance evaluation was conducted in the compliance
report. All other performance test and performance evaluation results
(i.e., those not supported by EPA's ERT) must be reported in the
compliance report.
* * * * *
(k) * * *
(1) Unless otherwise specified by this subpart, 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.
* * * * *
(2) Unless otherwise specified by this subpart, within 60 days
after the date of completing each CEMS performance evaluation required
by Sec. 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.
* * * * *
(l) Extensions to electronic reporting deadlines. (1) If you are
required to electronically submit a report through the Compliance and
Emissions Data Reporting Interface (CEDRI) in the EPA's Central Data
Exchange (CDX), and due to a planned or actual outage of either the
EPA's CEDRI or CDX systems within the period of time beginning 5
business days prior to the date that the submission is due, you will be
or are precluded from accessing CEDRI or CDX and submitting a required
report within the time prescribed, you may assert a claim of EPA system
outage for failure to timely comply with the reporting
[[Page 15487]]
requirement. You must submit notification to the Administrator in
writing as soon as possible following the date you first knew, or
through due diligence should have known, that the event may cause or
caused a delay in reporting. You must provide to the Administrator a
written description identifying the date, time and length of the
outage; a rationale for attributing the delay in reporting beyond the
regulatory deadline to the EPA system outage; describe the measures
taken or to be taken to minimize the delay in reporting; and identify a
date by which you propose to report, or if you have already met the
reporting requirement at the time of the notification, the date you
reported. In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved. The
decision to accept the claim of EPA system outage and allow an
extension to the reporting deadline is solely within the discretion of
the Administrator.
(2) If you are required to electronically submit a report through
CEDRI in the EPA's CDX and a force majeure event is about to occur,
occurs, or has occurred or there are lingering effects from such an
event within the period of time beginning 5 business days prior to the
date the submission is due, the owner or operator may assert a claim of
force majeure for failure to timely comply with the reporting
requirement. For the purposes of this section, a force majeure event is
defined as an event that will be or has been caused by circumstances
beyond the control of the affected facility, its contractors, or any
entity controlled by the affected facility that prevents you from
complying with the requirement to submit a report electronically within
the time period prescribed. Examples of such events are acts of nature
(e.g., hurricanes, earthquakes, or floods), acts of war or terrorism,
or equipment failure or safety hazard beyond the control of the
affected facility (e.g., large scale power outage). If you intend to
assert a claim of force majeure, you must submit notification to the
Administrator in writing as soon as possible following the date you
first knew, or through due diligence should have known, that the event
may cause or caused a delay in reporting. You must provide to the
Administrator a written description of the force majeure event and a
rationale for attributing the delay in reporting beyond the regulatory
deadline to the force majeure event; describe the measures taken or to
be taken to minimize the delay in reporting; and identify a date by
which you propose to report, or if you have already met the reporting
requirement at the time of the notification, the date you reported. In
any circumstance, the reporting must occur as soon as possible after
the force majeure event occurs. The decision to accept the claim of
force majeure and allow an extension to the reporting deadline is
solely within the discretion of the Administrator.
0
25. Section 63.1576 is amended by revising paragraph (a)(2)(i) to read
as follows:
Sec. 63.1576 What records must I keep, in what form, and for how
long?
(a) * * *
(2) * * *
(i) Record the date, time, and duration of each startup and/or
shutdown period for which the facility elected to comply with the
alternative standards in Sec. 63.1564(a)(5)(ii) or Sec.
63.1565(a)(5)(ii) or Sec. 63.1568(a)(4)(ii) or (iii).
* * * * *
0
26. Table 3 to Subpart UUU is amended by revising the table title and
entries for items 2.c, 6, 7, 8 and 9 to read as follows:
* * * * *
Table 3 to Subpart UUU of Part 63--Continuous Monitoring Systems for
Metal HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
If you use this
For each new or existing type of control You shall install,
catalytic cracking unit . . . device for your operate, and maintain
vent . . . a . . .
------------------------------------------------------------------------
* * * * * * *
2. * * *
c. Wet scrubber.. Continuous parameter
monitoring system to
measure and record
the pressure drop
across the
scrubber,\2\ the gas
flow rate entering
or exiting the
control device,\1\
and total liquid (or
scrubbing liquor)
flow rate to the
control device.
* * * * * * *
6. Option 1a: Elect NSPS Any.............. See item 1 of this
subpart J, PM per coke burn- table.
off limit, not subject to the
NSPS for PM in 40 CFR 60.102
or 60.102a(b)(1).
7. Option 1b: Elect NSPS Any.............. The applicable
subpart Ja, PM per coke burn- continuous
off limit, not subject to the monitoring systems
NSPS for PM in 40 CFR 60.102 in item 2 of this
or 60.102a(b)(1). table.
8. Option 1c: Elect NSPS Any.............. See item 3 of this
subpart Ja, PM concentration table.
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- Any.............. The applicable
off limit, not subject to the continuous
NSPS for PM in 40 CFR 60.102 monitoring systems
or 60.102a(b)(1). in item 2 of this
table.
* * * * * * *
------------------------------------------------------------------------
* * * * *
0
27. Table 4 to Subpart UUU of Part 63 is amended by revising the
entries for items 9.c and 10.c to read as follows:
* * * * *
[[Page 15488]]
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 You must . . . Using . . . According to these
catalyst requirements . . .
regenerator vent
. . .
------------------------------------------------------------------------
* * * * * * *
9. * * *
c. Determine XRF procedure You must obtain 1
the in appendix A sample for each of
equilibrium to this the 3 test runs;
catalyst Ni subpart1; or determine and
concentration. EPA Method record the
6010B or 6020 equilibrium
or EPA Method catalyst Ni
7520 or 7521 concentration for
in SW-8462; or each of the 3
an alternative samples; and you
to the SW-846 may adjust the
method laboratory results
satisfactory to the maximum
to the value using
Administrator. Equation 1 of Sec.
63.1571, if
applicable.
* * * * * * *
10. * * *
c. Determine See item 9.c. You must obtain 1
the of this table. sample for each of
equilibrium the 3 test runs;
catalyst Ni determine and
concentration. 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 Sec.
63.1571, if
applicable.
* * * * * * *
------------------------------------------------------------------------
* * * * *
0
28. Table 5 to Subpart UUU is amended by revising the entry for item 3
to read as follows:
* * * * *
Table 5 to Subpart UUU of Part 63--Initial Compliance With Metal HAP
Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
For the following
For each new and existing emission limit . You have demonstrated
catalytic cracking unit . . . . . compliance if . . .
------------------------------------------------------------------------
* * * * * * *
3. Subject to NSPS for PM in PM emissions must You have already
40 CFR 60.102a(b)(1)(ii), not exceed 0.5 g/ conducted a
electing to meet the PM per kg (0.5 lb PM/ performance test to
coke burn-off limit. 1,000 lb) of demonstrate initial
coke burn-off). compliance with the
NSPS and the
measured PM emission
rate is less than or
equal to 0.5 g/kg
(0.5 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 Sec.
63.1572.
* * * * * * *
------------------------------------------------------------------------
0
29. Table 6 to Subpart UUU is amended by revising the entries for items
1.a.ii and 7 to read as follows:
* * * * *
Table 6 to Subpart UUU of Part 63--Continuous Compliance With Metal HAP
Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
Subject to this
emission limit You shall demonstrate
For each new and existing for your catalyst continuous compliance
catalytic cracking unit . . . regenerator vent by . . .
. . .
------------------------------------------------------------------------
1. * * *...................... a. * * *......... .....................
[[Page 15489]]
ii. Conducting a
performance test
before August 1,
2017 or within 60
days of startup of a
new unit and
thereafter following
the testing
frequency in Sec.
63.1571(a)(5) as
applicable to your
unit.
* * * * * * *
7. Option 1b: Elect NSPS PM emissions must See item 2 of this
subpart Ja requirements for not exceed 1.0 g/ table.
PM per coke burn-off limit, kg (1.0 lb PM/
not subject to the NSPS for 1,000 lb) of
PM in 40 CFR 60.102 or coke burn-off.
60.102a(b)(1).
* * * * * * *
------------------------------------------------------------------------
0
30. Table 10 to Subpart UUU is amended by revising the entry for item 3
to read as follows:
* * * * *
Table 10 to Subpart UUU of Part 63--Continuous Monitoring Systems for
Organic HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
You shall install,
And you use this operate, and maintain
For each new or existing type of control this type of
catalytic cracking unit . . . device for your continuous monitoring
vent . . . system . . .
------------------------------------------------------------------------
* * * * * * *
3. During periods of startup, Any.............. Continuous parameter
shutdown or hot standby monitoring system to
electing to comply with the measure and record
operating limit in Sec. the concentration by
63.1565(a)(5)(ii). volume (wet or dry
basis) of oxygen
from each catalyst
regenerator vent. If
measurement is made
on a wet basis, you
must comply with the
limit as measured
(no moisture
correction).
------------------------------------------------------------------------
0
31. Table 43 to Subpart UUU is amended by revising the entry for item 2
to read as follows:
* * * * *
Table 43 to Subpart UUU of Part 63--Requirements for Reports
------------------------------------------------------------------------
The report must You shall submit
You must submit . . . contain . . . the report . . .
------------------------------------------------------------------------
* * * * * * *
2. Performance test and CEMS On and after Semiannually
performance evaluation data. February 1, 2016, according to the
the information requirements in
specified in Sec. Sec. 63.1575(b)
63.1575(k)(1). and (f).
------------------------------------------------------------------------
0
32. Table 44 to Subpart UUU is amended by revising the entries
``63.6(f)(3)'', ``63.67(h)(7)(i)'', ``63.6(h)(8)'', ``63.7(a)(2)'',
``63.7(g)'', ``63.8(e)'', ``63.10(d)(2)'', ``63.10(e)(1)-(2)'', and
``63.10(e)(4)'' to read as follows:
* * * * *
Table 44 to Subpart UUU of Part 63--Applicability of NESHAP General Provisions to Subpart UUU
----------------------------------------------------------------------------------------------------------------
Applies to subpart UUU
Citation Subject Explanation
----------------------------------------------------------------------------------------------------------------
* * * * * * *
Sec. 63.6(f)(3).................. ...................... Yes................... Except the cross-references
to Sec. 63.6(f)(1) and
(e)(1)(i) are changed to
Sec. 63.1570(c) and this
subpart specifies how and
when the performance test
results are reported.
[[Page 15490]]
* * * * * * *
Sec. 63.6(h)(7)(i)............... Report COM Monitoring Yes................... Except this subpart
Data from Performance specifies how and when the
Test. performance test results
are reported.
* * * * * * *
Sec. 63.6(h)(8).................. Determining Compliance Yes................... Except this subpart
with Opacity/VE specifies how and when the
Standards. performance test results
are reported.
* * * * * * *
Sec. 63.7(a)(2).................. Performance Test Dates Yes................... Except this subpart
specifies that the results
of initial performance
tests must be submitted
within 150 days after the
compliance date.
* * * * * * *
Sec. 63.7(g)..................... Data Analysis, Yes................... Except this subpart
Recordkeeping, specifies how and when the
Reporting. performance test or
performance evaluation
results are reported and
Sec. 63.7(g)(2) is
reserved and does not
apply.
* * * * * * *
Sec. 63.8(e)..................... CMS Performance Yes................... Except this subpart
Evaluation. specifies how and when the
performance evaluation
results are reported.
* * * * * * *
Sec. 63.10(d)(2)................. Performance Test No.................... This subpart specifies how
Results. and when the performance
test results are reported.
* * * * * * *
Sec. 63.10(e)(1)-(2)............. Additional CMS Reports Yes................... Except this subpart
specifies how and when the
performance evaluation
results are reported.
* * * * * * *
Sec. 63.10(e)(4)................. COMS Data Reports..... Yes................... Except this subpart
specifies how and when the
performance test results
are reported.
* * * * * * *
----------------------------------------------------------------------------------------------------------------
[FR Doc. 2018-06223 Filed 4-9-18; 8:45 am]
BILLING CODE 6560-50-P