[Federal Register Volume 83, Number 80 (Wednesday, April 25, 2018)]
[Notices]
[Pages 18034-18042]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-08575]


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ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-OAR-2014-0738 and EPA-HQ-OAR-2010-0682; FRL-9976-29-OAR]


Notice of Requests for Approval of Alternative Means of Emission 
Limitation

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice; request for comments.

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SUMMARY: This action provides public notice and solicits comment on the 
alternative means of emission limitation (AMEL) requests from 
ExxonMobil Corporation; Marathon Petroleum Company, LP (for itself and 
on behalf of its subsidiary, Blanchard Refining, LLC); and Chalmette 
Refining, LLC, under the Clean Air Act (CAA), to operate flares at 
several refineries in Texas and Louisiana, as well as the AMEL request 
from LACC, LLC to operate flares at a chemical plant in Louisiana.

DATES: Comments. Comments must be received on or before June 11, 2018.
    Public Hearing. If a public hearing is requested by April 30, 2018, 
then we will hold a public hearing on May 10, 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 May 8, 2018.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2014-0738, at http://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 
methods 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-2014-0738, 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 statue. See the SUPPLEMENTARY INFORMATION 
section 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 http://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://www3.epa.gov/ttn/atw/groundflares/groundflarespg.html. 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 Ms. Virginia Hunt of the Sector Policies and Programs Division 
(E143-01), Office of Air Quality Planning and Standards, Environmental 
Protection Agency, Research Triangle Park, NC 27711; telephone number: 
(919) 541-0832; email address: [email protected]; to request a 
public hearing, to register to speak at the public hearing, or to 
inquire as to whether or not 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

[[Page 18035]]

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 action, 
contact Ms. Angie Carey, Sector Policies and Programs Division (E143-
01), Office of Air Quality Planning and Standards (OAQPS), U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; telephone number: (919) 541-2187; fax number: (919) 541-0516; 
and email address: [email protected].

SUPPLEMENTARY INFORMATION: 
    Docket. The EPA has established a docket for this rulemaking under 
Docket ID No. EPA-HQ-OAR-2014-0738. 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-
2014-0738. The EPA's policy is that all comments received will be 
included in the public docket without change and may be made available 
online at http://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 http://www.regulations.gov or email. This 
type of information should be submitted by mail as discussed below. The 
http://www.regulations.gov website site 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 http://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 http://www.epa.gov/dockets.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through http://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 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-2014-
0738.
    Acronyms and Abbreviations. We use multiple acronyms and terms in 
this notice. While this list may not be exhaustive, to ease the reading 
of this notice and for reference purposes, the EPA defines the 
following terms and acronyms here:

AMEL alternative means of emission limitation
BTU/scf British thermal units per standard cubic foot
CAA Clean Air Act
CBI Confidential Business Information
CFR Code of Federal Regulations
EPA Environmental Protection Agency
Eqn equation
HAP hazardous air pollutants
LFL lower flammability limit
LFLcz lower flammability limit of combustion zone gas
LFLvg lower flammability limit of flare vent gas
LRGO linear relief gas oxidizer
MPGF multi-point ground flares
NESHAP national emission standards for hazardous air pollutants
NHV net heating value
NHVcz net heating value of combustion zone gas
NHVvg net heating value of flare vent gas
NSPS new source performance standards
OAQPS Office of Air Quality Planning and Standards
scf standard cubic feet
SKEC steam-assisted kinetic energy combustor
VOC volatile organic compounds

    Organization of This Document. The information in this notice is 
organized as follows:

I. Background
    A. Regulatory Flare Requirements and AMEL Requests
II. Requests for AMEL
    A. ExxonMobil Corporation Baytown Refinery Flexicoker Flare
    B. Marathon Petroleum Company Garyville, Louisiana, and 
Blanchard Refining's Galveston Bay Refinery MPGFs
    C. Chalmette Refinery Request
    D. LACC, LLC Request
    E. Information Supporting Flare AMEL Requests
III. AMEL for the Flares
IV. Request for Comments

I. Background

A. Regulatory Flare Requirements and AMEL Requests

    In this action, the U.S. Environmental Protection Agency (EPA) is 
soliciting comment on all aspects of these AMEL

[[Page 18036]]

requests and the corresponding operating conditions that would 
demonstrate that the requested AMEL would achieve a reduction in 
emissions of volatile organic compounds (VOC) and hazardous air 
pollutants (HAP) at least equivalent to the reduction in emissions 
required by various standards in 40 Code of Federal Regulations (CFR) 
parts 60, 61, and 63 that apply to emission sources controlled by these 
flares. These standards incorporate the flare design and operating 
requirements in the parts 60 and 63 General Provisions (i.e., 40 CFR 
60.18(b) and 63.11(b)) into the individual new source performance 
standards (NSPS) and maximum achievable control technology (MACT) 
subparts, except for the Petroleum Refinery MACT, 40 CFR part 63, 
subpart CC, which specifies its flare requirements within the subpart 
(i.e., 40 CFR 63.670). Four of the requests are for flares located at 
petroleum refineries, while the request from LACC, LLC is for a flare 
design at a chemical manufacturing facility. None of the flares located 
at petroleum refineries can meet the flare tip velocity limits in the 
Petroleum Refinery MACT, 40 CFR part 63, subpart CC. In addition, 
flares at these refineries and at LACC's chemical plant that are 
subject to other part 60 and 63 standards cannot meet the flare tip 
velocity limits contained in the applicable General Provisions to part 
60 and 63. Based on our review of these requests and their supporting 
information, we conclude that, by following the conditions specified in 
this notice, the proposed flares will achieve at least equivalent 
emissions reductions as flares complying with the requirements of 40 
CFR 60.18(b), 63.11(b) and/or 63.670(d), whichever is applicable.\1\
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    \1\ Per 40 CFR 63.640(s), flares that are subject to the 
provisions of 40 CFR 63.670 are required only to comply with 40 CFR 
63.670 and not the General Provisions at 40 CFR 60.18 and 63.11.
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    Alternative Means of Emission Limitation requests were submitted to 
the EPA for flares that cannot comply with the applicable flare tip 
velocity requirements in the Petroleum Refinery MACT, 40 CFR part 63, 
subpart CC and General Provisions to parts 60 and 63. These maximum 
flare tip velocity requirements ensure that the flame does not ``lift 
off'' or separate from the flare tip, which could cause flame 
instability and/or potentially result in a portion of the flare gas 
being released without proper combustion. Proper combustion for flares 
is considered to be 98-percent destruction efficiency or greater for 
organic HAP and VOC. The flares in these requests are designed to 
operate with tip exit velocities greater than those allowed in 40 CFR 
60.18, 63.11, and 63.670 while achieving >=96.5-percent combustion 
efficiency and 98-percent destruction efficiency. Requests from 
ExxonMobil Corporation, Marathon Petroleum Company, LP, Blanchard 
Refining, LLC, and Chalmette Refining, LLC were submitted to the EPA on 
November 7, 2017; October 7, 2016; September 20, 2017; and August 10, 
2017, respectively. These requests, which seek AMEL for flares to be 
used at certain refineries subject to the Petroleum Refinery MACT, 40 
CFR part 63, subpart CC, followed the AMEL framework specified in 40 
CFR part 63, subpart CC at 40 CFR 63.670(r).\2\ On May 7, 2017, LACC, 
LLC submitted an AMEL request for flares to be used at a chemical plant 
in Louisiana according to the framework for pressure assisted multi-
point ground flares (MPGFs) that was published in the Federal Register 
on April 21, 2016 (see 81 FR 23486). The flare designs in these 
requests vary from a single tip design that is gas-assisted to multi-
point tip designs which employ large numbers of tips at varying heights 
from close to ground level (these are termed multi-point ground flares 
[MPGF]) to an elevated multi-point design. The EPA has reviewed these 
requests and deemed them to be complete.
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    \2\ Although the Marathon, Blanchard, and Chalmette refineries 
are subject to other national emission standards for hazardous air 
pollutants (NESHAP) and NSPS (and, therefore, the General Provisions 
at 40 CFR 60.18 and 63.11) in addition to NESHAP subpart CC, 40 CFR 
63.640(s) of subpart CC allows flares that are subject to flare 
requirements in both subpart CC and General Provisions to elect to 
comply only with the subpart CC flare requirements at 40 CFR 63.670.
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    The ExxonMobil Corporation Baytown Refinery in Baytown, Texas, is 
seeking an AMEL to operate a gas-assisted flare during periods of 
startup, shutdown, upsets, and emergency events, as well as during fuel 
gas imbalance events. Marathon Petroleum Company, LP's Garyville, 
Louisiana Refinery, and Blanchard Refining, LLC's Galveston Bay 
Refinery (GBR) in Texas City, Texas, are seeking AMELs to operate their 
flares only during periods of startup, shutdown, upsets, and emergency 
events. Chalmette Refining, LLC in Chalmette, Louisiana, is seeking an 
AMEL to operate its flare during periods of upset and emergency events. 
LACC, LLC is seeking an AMEL to operate flares at its chemical plant in 
Lake Charles, Louisiana, during startups, shutdowns, upsets, and 
emergency events. See Table 1 for a list of regulations, by subparts, 
that each refinery and chemical plant has identified as applicable to 
the flares described above.

                                   Table 1--Summary of Applicable Rules That May Apply to Streams Controlled by Flares
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                          Exxon
                                          Mobil       Marathon      Blanchard                                 Rule citation from       Provisions for
  Applicable rules with vent streams    Baytown,    Garyville, LA    Refining    Chalmette No.     LACC       Title 40 CFR that     alternative means of
      going to control device(s)          Texas         MPGF         GBR MPGF       1 Flare                   allow for use of a    emission limitation
                                        Flare 26                                                                    flare
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NSPS Subpart VV......................  ..........              x            x   ..............  ..........  60.482-10(d).........  60.484(a)-(f).
NSPS Subpart VVa.....................  ..........              x            x   ..............          x   60.482-10a(d)........  60.484a(a)-(f).
NSPS Subpart NNN.....................  ..........              x            x               x           x   60.662(b)............  CAA section
                                                                                                                                    111(h)(3).
NSPS Subpart QQQ.....................  ..........              x            x   ..............  ..........  60.692-5(c)..........  42 U.S.C. 7411(h)(3).
NSPS Subpart RRR.....................  ..........              x            x   ..............          x   60.702(b)............  CAA section
                                                                                                                                    111(h)(3).
NSPS Subpart Kb......................  ..........              x            x   ..............          x   60.112b(a)(3)(ii)....  60.114b.
NESHAP Subpart V.....................  ..........              x            x   ..............          x   61.242-11(d).........  40 CFR 63.6(g); 42
                                                                                                                                    U.S.C. 7412(h)(3).
NESHAP Subpart J.....................  ..........  ..............  ...........  ..............          x   61.242-11(d).........  40 CFR 63.6(g); 42
                                                                                                                                    U.S.C. 7412(h)(3).
NESHAP Subpart Y.....................  ..........              x            x   ..............  ..........  61.271-(c)(2)........  40 CFR 63.6(g); 40
                                                                                                                                    CFR 61.273; 42
                                                                                                                                    U.S.C. 7412(h)(3).
NESHAP Subpart BB....................  ..........              x            x   ..............  ..........  61.302(c)............  40 CFR 63.6(g); 42
                                                                                                                                    U.S.C. 7412(h)(3).
NESHAP Subpart FF....................  ..........              x            x   ..............          x   61.349(a)(2).........  61.353(a); also see
                                                                                                                                    61.12(d).
NESHAP Subpart F.....................  ..........              x            x   ..............          x   63.103(a)............  63.6(g); 42 U.S.C.
                                                                                                                                    7412(h)(3).

[[Page 18037]]

 
NESHAP Subpart G.....................  ..........              x            x   ..............          x   63.113(a)(1)(i),       63.6(g); 42 U.S.C.
                                                                                                             63.116(a)(2),          7412(h)(3).
                                                                                                             63.116(a)(3),
                                                                                                             63.119(e),
                                                                                                             63.120(e)(1) through
                                                                                                             (4),
                                                                                                             63.126(b)(2)(i),
                                                                                                             63.128(b),
                                                                                                             63.139(c)(3),
                                                                                                             63.139(d)(3),
                                                                                                             63.145(j).
NESHAP Subpart H.....................  ..........              x            x   ..............          x   63.172(d), 63.180(e).  63.177; 42 U.S.C.
                                                                                                                                    7412(h)(3).
NESHAP Subpart SS....................  ..........              x            x   ..............          x   63.982(b)............  CAA section
                                                                                                                                    112(h)(3).
NESHAP Subpart CC....................          x               x            x               x   ..........  63.643(a)(1).........  63.670(r).
NESHAP Subpart UU....................  ..........  ..............  ...........  ..............          x   63.1034..............  63.1021(a)-(d).
NESHAP Subpart YY....................  ..........  ..............  ...........  ..............          x   Table 7 to 63.1103(e)  63.1113.
                                                                                                             cross-references to
                                                                                                             NESHAP subpart SS
                                                                                                             above.
NESHAP Subpart EEEE..................  ..........              x            x   ..............  ..........  63.2378(a), 63.2382,   63.6(g); 42 U.S.C.
                                                                                                             63.2398.               7412(h)(3).
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    The provisions in each NSPS and NESHAP cited above, which ensure 
that flares meet certain specific operating requirements when used to 
satisfy the requirements of the NSPS or NESHAP were established as work 
practice standards pursuant to CAA sections 111(h)(1) or 112(h)(1). For 
standards established according to these provisions, CAA sections 
111(h)(3) and 112(h)(3) allow the EPA to permit the use of an AMEL by a 
source if, after notice and opportunity for comment,\3\ it is 
established to the Administrator's satisfaction that such an AMEL will 
achieve emissions reductions at least equivalent to the reductions 
required under the applicable CAA section 111(h)(1) or 112(h)(1) 
standards. As noted in Table 1, many of the identified NSPS and NESHAP 
also include specific regulatory provisions allowing sources to request 
an AMEL.
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    \3\ CAA section 111(h)(3) requires that the EPA provide an 
opportunity for a hearing.
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    ExxonMobil, Marathon, Blanchard, Chalmette, and LACC submitted AMEL 
requests to operate above the applicable maximum permitted velocity 
requirements for flares in the General Provisions in 40 CFR parts 60 
and 63 and/or in 40 CFR 63.670. ExxonMobil, Marathon, Blanchard, 
Chalmette, and LACC provided information that the flare designs achieve 
a reduction in emissions at least equivalent to the reduction in 
emissions for flares complying with the applicable General Provisions 
and/or MACT subpart CC requirements. For further information on 
ExxonMobil's, Marathon's, Blanchard's, Chalmette's, and LACC's AMEL 
requests, see supporting materials from ExxonMobil, Marathon, 
Blanchard, Chalmette, and LACC at Docket ID No. EPA-HQ-OAR-2010-0682 
and EPA-HQ-OAR-2014-0738.

II. Requests for AMEL

A. ExxonMobil Corporation Baytown Refinery Flexicoker Flare

    ExxonMobil submitted an AMEL for Flare 26 at the ExxonMobil Baytown 
Refinery. Flare 26 is an elevated flare, with an approximate height of 
284 feet. Flare 26 will be modified to install a 52-inch gas-assisted 
flare tip. Gas-assisted means that natural gas is discharged near or at 
the flare tip exit and is used to improve the combustion efficiency in 
the combustion zone, but it is not part of the vent gas, and, as such, 
does not contribute to the vent gas volume that determines the exit tip 
velocity. Still, this flare cannot meet the exit velocity limitation in 
40 CFR 63.670(d). Flare 26 receives low BTU gas (LBG) from episodic and 
maintenance events from the Flexicoking LBG system during startup, 
shutdown, and other non-routine operations. Flare 26 will also accept 
flow from the Flexicoking LBG system during normal operations where 
there is a fuel gas imbalance.

B. Marathon Petroleum Company Garyville, Louisiana, and Blanchard 
Refining's Galveston Bay Refinery MPGFs

    Marathon submitted an AMEL for their two MPGFs at their Garyville 
refinery and also for one MPGF at their subsidiary, Blanchard 
Refining's GBR. These three MPGFs were included in a single AMEL 
request because the principle is the same for each MPGF. All three 
MPGFs are designed to operate with tip exit velocities greater than 
those allowed in 40 CFR 60.18, 63.11, and 63.670, while achieving 
>96.5-percent combustion efficiency and 98-percent destruction 
efficiency. The scope of the AMELs include steam-assisted steam kinetic 
energy combustors (SKEC burners) at Garyville, pressure-assisted linear 
relief gas oxidizers (LRGO burners) at Garyville and GBR, and an air-
assisted burner (LH burner) at GBR. All three of the MPGFs covered in 
this AMEL request were manufactured by John Zink Company, LLC (John 
Zink). Marathon is seeking AMELs to operate these flares during periods 
of startup, shutdown, upsets, and emergency events.

C. Chalmette Refinery Request

    Chalmette Refining, LLC submitted an AMEL for their No. 1 Flare. 
The No. 1 Flare was designed by John Zink and constructed in 1982. The 
flare is an 8-stage candelabra style raised pressure-assisted flare 
with multiple flare tips comprised of two designs. The flare is 
elevated 171.92 feet above ground. Stage one is equipped with John Zink 
LRGO-Spider model burners. All other stages have John Zink model LRGO-
FF burners. The gases being flared can range in composition and flow, 
but the flare only operates during upset and emergency conditions.

D. LACC, LLC Request

    LACC, LLC submitted an AMEL for two MPGF operating in series. This 
system consists of an enclosed ground flare and a high-pressure ground 
flare that operates as a cascading system whereby the enclosed ground 
flare serves as the primary relief control device and the high-pressure 
ground flare serves as the secondary relief control device should the 
enclosed ground flare approach burner utilization capacity. The high-
pressure header portion of these ground flares are MPGF and utilize two 
different types of pressure assisted burners; LRGO-HC (both flares) and 
INDAIR (enclosed ground flare only). Both are designed and produced by 
John Zink. The high[hyphen]pressure header MPGFs will be used for 
destruction of vent streams

[[Page 18038]]

during startups, shutdowns, upsets, and emergency events.

E. Information Supporting Flare AMEL Requests

    As mentioned above, ExxonMobil, Marathon, Blanchard, and Chalmette 
provided the information specified in the flare AMEL framework at 40 
CFR 63.670(r) to support their AMEL requests. LACC provided the 
information specified in the flare AMEL framework finalized on April 
21, 2016 (81 FR 23486), to support its AMEL request. The information 
specified in both frameworks includes, but is not limited to: (1) 
Details on the project scope and background; (2) information on 
regulatory applicability; (3) flare test data on destruction 
efficiency/combustion efficiency; (4) flare stability testing data; (5) 
flare cross-light testing data; (6) information on flare reduction 
considerations; and (7) information on appropriate flare monitoring and 
operating conditions. (For further information on the supporting 
materials provided, see Docket ID No. EPA-HQ-OAR-2010-0682 and EPA-HQ-
OAR-2014-0738.)
    Information supplied by these companies indicates that the flares 
can achieve adequate combustion efficiency if operated under certain 
conditions. Generally, testing of burners for the vent gas mixture 
determined to be representative of the flare operation was used to set 
the appropriate combustion zone net heating value (NHVcz) minimum 
limit. Exxon Mobil conducted a series of combustion efficiency tests 
over a range of operating conditions and vent gas velocities to 
establish limits on a representative gas-assisted burner. Marathon and 
Blanchard submitted combustion efficiency test data for all three 
different types of burners to establish their minimum NHVcz. Burners in 
these flares include steam assisted (SKEC) and non-assisted (LRGO) 
burners at Garyville and an air-assisted (LH) and non-assisted (LRGO) 
at the Blanchard GBR. At the Garyville Refinery, the MPGFs are operated 
in series such that the flare gas is directed to the SKEC burners in 
stages 1 through 4, and then to the LRGO burners in stages 5 through 
11. Therefore, we selected an operating limit of the higher of 600 BTU/
standard cubic feet (scf) NHVcz or the NHVcz value resulting from the 
equation of the line presented in Table 2 appropriate for the SKEC 
burner. At the Blanchard GBR, we selected a value of 600 BTU/scf NHVcz 
based on the successful combustion efficiency test at 600 BTU/scf for 
the representative waste gas. The LRGO operating limit is limiting 
because the LRGO burners follow the air-assisted LH burner at the GBR.
    Chalmette Refining submitted required information and requested a 
minimum NHVcz of 1000 BTU/scf or a maximum lower flammability limit 
(LFL) of less than or equal to 6.5 percent, based on the conditions 
that were demonstrated to cross light flare stage 8A from adjacent 
stages 5 and 7 and stage 8B from stages 6 and 7. Stages 8A and B are 
not equipped with pilots, and, therefore, lighting of these stages 
relies on lighting from adjacent stages. Chalmette also requested that 
video records be used to show that cross lighting is successful, even 
if the NHVcz or LFL conditions are not met. However, we do not intend 
to allow an alternate compliance method based on visual indication and 
have not included this in the proposed alternatives.
    Finally, LACC requested two separate limits to account for the two 
sets of burners on their MPGF, LRGO, and INDAIR burners operating on 
waste gas from ethylene and downstream chemical manufacturing (ethylene 
oxide and monoethylene glycol) processes. LACC cited previous 
combustion efficiency information for the LRGO burners and successful 
cross light and stability at 800 BTU/scf for the representative waste 
gas composition. The combustion efficiencies for the INDAIR burners 
testing showed that a minimum of 1,067 BTU/scf for NHVcz was necessary 
to achieve the desired combustion efficiency. For process control, LACC 
requested a minimum limit of 1,075 BTU/scf for these burners. It is 
also important to note that LACC has the ability to lock out the stages 
containing the four INDAIR burners so that they can meet the 800 BTU/
scf minimum for the LRGO burners only.

III. AMEL for the Flares

    Based upon our review of the AMEL requests, we have concluded that, 
by complying with the proposed AMEL specified in Table 2 and 
accompanying paragraphs, the flares will achieve emission reductions at 
least equivalent to reduction in emissions being controlled by flares 
complying with the flare requirements under the applicable NESHAP and 
NSPS identified in Table 1. We are seeking the public's input on the 
requests that the EPA approve AMELs for these flares. Specifically, the 
EPA seeks the public's input on the conditions specified in this 
document in the following paragraphs. The EPA's proposed AMEL for 
Chalmette Refining does not include the requested provision to allow a 
source not to meet the limits in Table 2 as long as evidence of cross 
light and combustion exists.

                               Table 2--Proposed Alternative Operating Conditions
----------------------------------------------------------------------------------------------------------------
                                                                                                   Proposed
                                                                                                 alternative
       AMEL submitted               Company        Affected facilities     Flare type(s)          operating
                                                                                                 conditions.
----------------------------------------------------------------------------------------------------------------
11/7/17....................  ExxonMobil..........  Baytown, TX          Elevated gas-assist  >=270 BTU/scf NHV
                                                    Flexicoker Flare     flare.               and velocity <361
                                                    26.                                       feet per second
                                                                                              (ft/sec).
10/7/17....................  Marathon............  Garyville, LA......  2 MPGFs............  When both SKEC and
                                                                                              LRGO burners are
                                                                                              being used, the
                                                                                              higher of >=600
                                                                                              BTU/scf NHVcz or
                                                                                              >=127.27 ln(v)-
                                                                                              110.87 NHVcz. When
                                                                                              only the SKEC
                                                                                              burner is being
                                                                                              used >=127.27
                                                                                              ln(v)-110.87
                                                                                              NHVcz.
10/7/17....................  Marathon/ Blanchard   GBR (Texas City,     MPGF...............  >=600 BTU/scf NHV.
                              Refining.             TX).
9/19/17....................  Chalmette Refining..  Chalmette, LA......  Elevated multi-      >=1000 BTU/scf NHV
                                                                         point flare.         or LFL<=6.5 vol%.
5/1/17.....................  LACC................  Lake Charles, LA...  2 MPGFs............  >=1075 BTU/scf NHV
                                                                                              for INDAIR
                                                                                              Burners; >=800 BTU/
                                                                                              scf NHV for LRGO
                                                                                              only.
----------------------------------------------------------------------------------------------------------------

    (1) All flares must be operated such that the combustion zone gas 
net heating value (NHVcz) or the lower flammability in the combustion 
zone (LFLcz) as specified in Table 2 is met. Owners or operators must 
demonstrate compliance with the applicable NHVcz or LFLcz specified in 
Table 2 on a 15-minute block average. Owners or

[[Page 18039]]

operators must calculate and monitor for the NHVcz or LFLcz according 
to the following:

(a) Calculation of NHVcz

    (i) If an owner or operator elects to use a monitoring system 
capable of continuously measuring (i.e., at least once every 15 
minutes), calculating, and recording the individual component 
concentrations present in the flare vent gas, NHVvg shall be calculated 
using the following equation:
[GRAPHIC] [TIFF OMITTED] TN25AP18.000


Where:

NHVvg = Net heating value of flare vent gas, BTU/scf. Flare vent gas 
means all gas found just prior to the tip. This gas includes all 
flare waste gas (i.e., gas from facility operations that is directed 
to a flare for the purpose of disposing the gas), flare sweep gas, 
flare purge gas, and flare supplemental gas, but does not include 
pilot gas.
i = Individual component in flare vent gas.
n = Number of components in flare vent gas.
xi = Concentration of component i in flare vent gas, volume 
fraction.
NHVi = Net heating value of component i determined as the heat of 
combustion where the net enthalpy per mole of offgas is based on 
combustion at 25 degrees Celsius ([deg]C) and 1 atmosphere (or 
constant pressure) with water in the gaseous state from values 
published in the literature, and then the values converted to a 
volumetric basis using 20 [deg]C for ``standard temperature.'' Table 
3 summarizes component properties including net heating values.

    (ii) If the owner or operator uses a continuous net heating value 
monitor, the owner or operator may, at their discretion, install, 
operate, calibrate, and maintain a monitoring system capable of 
continuously measuring, calculating, and recording the hydrogen 
concentration in the flare vent gas. The owner or operator shall use 
the following equation to determine NHVvg for each sample measured via 
the net heating value monitoring system.
[GRAPHIC] [TIFF OMITTED] TN25AP18.001


Where:

NHVvg = Net heating value of flare vent gas, BTU/scf.
NHVmeasured = Net heating value of flare vent gas stream as measured 
by the continuous net heating value monitoring system, BTU/scf.
xH2 = Concentration of hydrogen in flare vent gas at the time the 
sample was input into the net heating value monitoring system, 
volume fraction.
938 = Net correction for the measured heating value of hydrogen 
(1,212-274), BTU/scf.

    (iii) For non-assisted flare burners, NHVvg = NHVcz. For assisted 
burners, such as the Marathon Garyville MPGF SKEC burners, the 
Blanchard Refining MPGF LH burner, and the ExxonMobil gas-assisted 
burner, NHVcz should be calculated using Equation 3.
[GRAPHIC] [TIFF OMITTED] TN25AP18.002


Where:

NHVcz = Net heating value of combustion zone gas, BTU/scf.
NHVvg = Net heating value of flare vent gas for the 15-minute block 
period as determined according to (1)(a)(i), BTU/scf.
Qvg = Cumulative volumetric flow of flare vent gas during the 15-
minute block period, scf.
Qag = Cumulative volumetric flow of assist gas during the 15-minute 
block period, standard cubic feet flow rate, scf.
NHVag = Net heating value of assist gas, BTU/scf; this is zero for 
air or for steam.

(b) Calculation of LFLcz

    (i) The owner or operator shall determine LFLcz from compositional 
analysis data by using the following equation:
[GRAPHIC] [TIFF OMITTED] TN25AP18.003


Where:

LFLvg = Lower flammability limit of flare vent gas, volume percent 
(vol %).
n = Number of components in the vent gas.
i = Individual component in the vent gas.
[chi]i = Concentration of component i in the vent gas, vol %.
LFLi = Lower flammability limit of component i as determined using 
values published by the U.S. Bureau of Mines (Zabetakis, 1965), vol 
%. All inerts, including nitrogen, are assumed to have an infinite 
LFL (e.g., LFLN2 = [infin], so that [chi]N2LFLN2 = 0). LFL values 
for common flare vent gas components are provided in Table 3.

    (ii) For non-assisted flare burners, LFLvg = LFLcz.

(c) Calculation of Vtip

    For the ExxonMobil flexicoker flare (F-26), the owner or operator 
shall calculate the 15-minute block average Vtip by using the following 
equation:
[GRAPHIC] [TIFF OMITTED] TN25AP18.004



[[Page 18040]]


Where:

Vtip = Flare tip velocity, ft/sec.
Qvg = Cumulative volumetric flow of vent gas over 15-minute block 
average period, scf.
Area = Unobstructed area of the flare tip, square ft.
900 = Conversion factor, seconds per 15-minute block average.

    (d) For all flare systems specified in this document, the operator 
shall install, operate, calibrate, and maintain a monitoring system 
capable of continuously measuring the volumetric flow rate of flare 
vent gas (Qvg), the volumetric flow rate of total assist steam (Qs), 
the volumetric flow rate of total assist air (Qa), and the volumetric 
flow rate of total assist gas (Qag).
    (i) The flow rate monitoring systems must be able to correct for 
the temperature and pressure of the system and output parameters in 
standard conditions (i.e., a temperature of 20 [deg]C (68 
[deg]Fahrenheit) and a pressure of 1 atmosphere).
    (ii) Mass flow monitors may be used for determining volumetric flow 
rate of flare vent gas provided the molecular weight of the flare vent 
gas is determined using compositional analysis so that the mass flow 
rate can be converted to volumetric flow at standard conditions using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TN25AP18.005


Where:

Qvol = Volumetric flow rate, scf/sec.
Qmass = Mass flow rate, pounds per sec.
385.3 = Conversion factor, scf per pound-mole.
MWt = Molecular weight of the gas at the flow monitoring location, 
pounds per pound-mole.

    (e) For each measurement produced by the monitoring system used to 
comply with (1)(a)(ii), the operator shall determine the 15-minute 
block average as the arithmetic average of all measurements made by the 
monitoring system within the 15-minute period.
    (f) The operator must follow the calibration and maintenance 
procedures according to Table 4. Maintenance periods, instrument 
adjustments, or checks to maintain precision and accuracy and zero and 
span adjustments may not exceed 5 percent of the time the flare is 
receiving regulated material.

                                    Table 3--Individual Component Properties
----------------------------------------------------------------------------------------------------------------
                                                                  MW (pounds per
               Component                   Molecular  formula       pound-mole)    NHV (BTU/scf)  LFL (volume %)
 
----------------------------------------------------------------------------------------------------------------
Acetylene.............................  C2H2....................           26.04           1,404             2.5
Benzene...............................  C6H6....................           78.11           3,591             1.3
1,2-Butadiene.........................  C4H6....................           54.09           2,794             2.0
1,3-Butadiene.........................  C4H6....................           54.09           2,690             2.0
iso-Butane............................  C4H10...................           58.12           2,957             1.8
n-Butane..............................  C4H10...................           58.12           2,968             1.8
cis-Butene............................  C4H8....................           56.11           2,830             1.6
iso-Butene............................  C4H8....................           56.11           2,928             1.8
trans-Butene..........................  C4H8....................           56.11           2,826             1.7
Carbon Dioxide........................  CO2.....................           44.01               0         [infin]
Carbon Monoxide.......................  CO......................           28.01             316            12.5
Cyclopropane..........................  C3H6....................           42.08           2,185             2.4
Ethane................................  C2H6....................           30.07           1,595             3.0
Ethylene..............................  C2H4....................           28.05           1,477             2.7
Hydrogen..............................  H2......................            2.02         * 1,212             4.0
Hydrogen Sulfide......................  H2S.....................           34.08             587             4.0
Methane...............................  CH4.....................           16.04             896             5.0
Methyl-Acetylene......................  C3H4....................           40.06           2,088             1.7
Nitrogen..............................  N2......................           28.01               0         [infin]
Oxygen................................  O2......................           32.00               0         [infin]
Pentane+ (C5+)........................  C5H12...................           72.15           3,655             1.4
Propadiene............................  C3H4....................           40.06           2,066            2.16
Propane...............................  C3H8....................           44.10           2,281             2.1
Propylene.............................  C3H6....................           42.08           2,150             2.4
Water.................................  H2O.....................           18.02               0         [infin]
----------------------------------------------------------------------------------------------------------------
* The theoretical net heating value for hydrogen is 274 BTU/scf, but for the purposes of the flare requirement
  in this subpart, a net heating value of 1,212 BTU/scf shall be used.


[[Page 18041]]


             Table 4--Accuracy and Calibration Requirements
------------------------------------------------------------------------
                                     Accuracy           Calibration
           Parameter               requirements         requirements
------------------------------------------------------------------------
Flare Vent Gas Flow Rate        20     Performance
                                 percent of flow    evaluation
                                 rate at            biennially (every 2
                                 velocities         years) and following
                                 ranging from 0.1   any period of more
                                 to 1 foot per      than 24 hours
                                 second             throughout which the
                                5       flow rate exceeded
                                 percent of flow    the maximum rated
                                 rate at            flow rate of the
                                 velocities         sensor, or the data
                                 greater than 1     recorder was off
                                 foot per second.   scale. Checks of all
                                                    mechanical
                                                    connections for
                                                    leakage monthly.
                                                    Visual inspections
                                                    and checks of system
                                                    operation every 3
                                                    months, unless the
                                                    system has a
                                                    redundant flow
                                                    sensor.
                                                   Select a
                                                    representative
                                                    measurement location
                                                    where swirling flow
                                                    or abnormal velocity
                                                    distributions due to
                                                    upstream and
                                                    downstream
                                                    disturbances at the
                                                    point of measurement
                                                    are minimized.
Flow Rate for All Flows Other   5      Conduct a flow sensor
 Than Flare Vent Gas             percent over the   calibration check at
                                 normal range of    least biennially
                                 flow measured or   (every 2 years);
                                 1.9 liters per     conduct a
                                 minute (0.5        calibration check
                                 gallons per        following any period
                                 minute),           of more than 24
                                 whichever is       hours throughout
                                 greater, for       which the flow rate
                                 liquid flow.       exceeded the
                                                    manufacturer's
                                                    specified maximum
                                                    rated flow rate or
                                                    install a new flow
                                                    sensor.
                                5      At least quarterly,
                                 percent over the   inspect all
                                 normal range of    components for
                                 flow measured or   leakage, unless the
                                 280 liters per     continuous parameter
                                 minute (10 cubic   monitoring system
                                 feet per           (CPMS) has a
                                 minute),           redundant flow
                                 whichever is       sensor.
                                 greater, for gas
                                 flow.
                                5      Record the results of
                                 percent over the   each calibration
                                 normal range       check and
                                 measured for       inspection.
                                 mass flow.        Locate the flow
                                                    sensor(s) and other
                                                    necessary equipment
                                                    (such as
                                                    straightening vanes)
                                                    in a position that
                                                    provides
                                                    representative flow;
                                                    reduce swirling flow
                                                    or abnormal velocity
                                                    distributions due to
                                                    upstream and
                                                    downstream
                                                    disturbances.
Pressure                        5      Review pressure
                                 percent over the   sensor readings at
                                 normal range       least once a week
                                 measured or 0.12   for straight-line
                                 kilopascals (0.5   (unchanging)
                                 inches of water    pressure and perform
                                 column),           corrective action to
                                 whichever is       ensure proper
                                 greater.           pressure sensor
                                                    operation if
                                                    blockage is
                                                    indicated.
                                                   Performance
                                                    evaluation annually
                                                    and following any
                                                    period of more than
                                                    24 hours throughout
                                                    which the pressure
                                                    exceeded the maximum
                                                    rated pressure of
                                                    the sensor, or the
                                                    data recorder was
                                                    off scale. Checks of
                                                    all mechanical
                                                    connections for
                                                    leakage monthly.
                                                    Visual inspection of
                                                    all components for
                                                    integrity,
                                                    oxidation, and
                                                    galvanic corrosion
                                                    every 3 months,
                                                    unless the system
                                                    has a redundant
                                                    pressure sensor.
                                                   Select a
                                                    representative
                                                    measurement location
                                                    that minimizes or
                                                    eliminates pulsating
                                                    pressure, vibration,
                                                    and internal and
                                                    external corrosion.
Net Heating Value by            2      Calibration
 Calorimeter                     percent of span.   requirements should
                                                    follow
                                                    manufacturer's
                                                    recommendations at a
                                                    minimum.
                                                   Temperature control
                                                    (heated and/or
                                                    cooled as necessary)
                                                    the sampling system
                                                    to ensure proper
                                                    year-round
                                                    operation.
                                                   Where feasible,
                                                    select a sampling
                                                    location at least 2
                                                    equivalent diameters
                                                    downstream from and
                                                    0.5 equivalent
                                                    diameters upstream
                                                    from the nearest
                                                    disturbance. Select
                                                    the sampling
                                                    location at least 2
                                                    equivalent duct
                                                    diameters from the
                                                    nearest control
                                                    device, point of
                                                    pollutant
                                                    generation, air in-
                                                    leakages, or other
                                                    point at which a
                                                    change in the
                                                    pollutant
                                                    concentration or
                                                    emission rate
                                                    occurs.
Net Heating Value by Gas        As specified in    Follow the procedure
 Chromatograph                   Performance        in PS 9 of 40 CFR
                                 Standard (PS) 9    part 60, appendix B,
                                 of 40 CFR part     except that a single
                                 60, appendix B.    daily mid-level
                                                    calibration check
                                                    can be used (rather
                                                    than triplicate
                                                    analysis), the multi-
                                                    point calibration
                                                    can be conducted
                                                    quarterly (rather
                                                    than monthly), and
                                                    the sampling line
                                                    temperature must be
                                                    maintained at a
                                                    minimum temperature
                                                    of 60 [deg]C (rather
                                                    than 120 [deg]C).
Hydrogen Analyzer               2      Specify calibration
                                 percent over the   requirements in your
                                 concentration      site specific CPMS
                                 measured, or 0.1   monitoring plan.
                                 volume, percent,   Calibration
                                 whichever is       requirements should
                                 greater.           follow
                                                    manufacturer's
                                                    recommendations at a
                                                    minimum.
                                                   Specify the sampling
                                                    location at least 2
                                                    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.
------------------------------------------------------------------------

    (2) The flare system shall be operated with a flame present at all 
times when in use. Additionally, each stage that cross-lights must have 
at least two pilots with a continuously lit pilot flame, except for 
Chalmette Refining, which has one pilot for each stage, excluding 
stages 8A and 8B. Each pilot flame must be continuously monitored by a 
thermocouple or any other equivalent device used to detect the presence 
of a flame. The time, date, and duration of any complete loss of pilot 
flame on any of the burners must be recorded. Each monitoring device 
must be maintained or replaced at a frequency in accordance with the 
manufacturer's specifications.
    (3) Flares at refineries shall comply with the requirements of 40 
CFR 63.670(h). For LACC, LLC, the flare system shall be operated with 
no visible emissions except for periods not to exceed a total of 5 
minutes during any 2 consecutive hours. A video camera that is capable 
of continuously recording (i.e., at least one frame every 15 seconds 
with time and date stamps) images of the flare flame and a reasonable 
distance above the flare flame at an angle suitable for visible 
emissions observations must be used to demonstrate compliance with this 
requirement. The owner or operator must provide real-time video 
surveillance camera output to the control room or other continuously

[[Page 18042]]

manned location where the video camera images may be viewed at any 
time.
    (4) For the MPGF and the Chalmette elevated multi-point flare, the 
operator of a flare system shall install and operate pressure 
monitor(s) on the main flare header, as well as a valve position 
indicator monitoring system capable of monitoring and recording the 
position for each staging valve to ensure that the flare operates 
within the range of tested conditions or within the range of the 
manufacturer's specifications. The pressure monitor shall meet the 
requirements in Table 4. Maintenance periods, instrument adjustments or 
checks to maintain precision and accuracy, and zero and span 
adjustments may not exceed 5 percent of the time the flare is receiving 
regulated material.
    (5) Recordkeeping Requirements
    (a) All data must be recorded and maintained for a minimum of 3 
years or for as long as required under applicable rule subpart(s), 
whichever is longer.
    (6) Reporting Requirements
    (a) The information specified in section III (6)(b) and (c) below 
must be reported in the timeline specified by the applicable rule 
subpart(s) for which the flare will control emissions.
    (b) Owners or operators shall include the final AMEL operating 
requirements for each flare in their initial Notification of Compliance 
status report.
    (c) The owner or operator shall notify the Administrator of periods 
of excess emissions in their Periodic Reports. The notification shall 
include:
    (i) Records of each 15-minute block for all flares during which 
there was at least 1 minute when regulated material was routed to the 
flare and a complete loss of pilot flame on a stage of burners 
occurred, and for all flares, records of each 15-minute block during 
which there was at least 1 minute when regulated material was routed to 
the flare and a complete loss of pilot flame on an individual burner 
occurred.
    (ii) Records of visible emissions events (including the time and 
date stamp) that exceed more than 5 minutes in any 2-hour consecutive 
period.
    (iii) Records of each 15-minute block period for which an 
applicable combustion zone operating limit (i.e., NHVcz or LFLcz) is 
not met for the flare when regulated material is being combusted in the 
flare. Indicate the date and time for each period, the NHVcz and/or 
LFLcz operating parameter for the period, the type of monitoring system 
used to determine compliance with the operating parameters (e.g., gas 
chromatograph or calorimeter), and also indicate which high-pressure 
stages were in use.
    (iv) Records of when the pressure monitor(s) on the main flare 
header show the flare burners are operating outside the range of tested 
conditions or outside the range of the manufacturer's specifications. 
Indicate the date and time for each period, the pressure measurement, 
the stage(s) and number of flare burners affected, and the range of 
tested conditions or manufacturer's specifications.
    (v) Records of when the staging valve position indicator monitoring 
system indicates a stage of the flare should not be in operation and is 
or when a stage of the flare should be in operation and is not. 
Indicate the date and time for each period, whether the stage was 
supposed to be open, but was closed, or vice versa, and the stage(s) 
and number of flare burners affected.

IV. Request for Comments

    We solicit comments on all aspects of ExxonMobil's, Marathon's, 
Blanchard's, Chalmette's, and LACC's requests for approval of an AMEL 
for flares to be used to comply with the standards specified in Table 
1. We specifically seek comment regarding whether or not the 
alternative operating requirements listed in section III above will 
achieve emission reductions at least equivalent to emissions being 
controlled by flares complying with the applicable flare requirements 
in 40 CFR 60.18(b), 63.11(b), and/or 63.670.

    Dated: April 18, 2018.
Panagiotis Tsirigotis,
Director, Office of Air Quality Planning and Standards.
[FR Doc. 2018-08575 Filed 4-24-18; 8:45 am]
 BILLING CODE 6560-50-P


