Document ID: EPA-HQ-OAR-2014-0738-0087
Agency: epa
Document Type: Notice
Title: Notice of Final Approval for an Alternative Means of Emission Limitation at ExxonMobil Corporation; Marathon Petroleum Company, LP (for Itself and on Behalf of Its Subsidiary, Blanchard Refining, LLC); Chalmette Refining, LLC; and LACC, LLC; Notice; Final Approval
Posted Date: 2018-09-17T04:00Z

[Federal Register Volume 83, Number 180 (Monday, September 17, 2018)]
[Notices]
[Pages 46939-46945]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-20148]

=======================================================================
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ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-OAR-2014-0738 and EPA-HQ-OAR-2010-0682; FRL-9983-26-OAR]

Notice of Final Approval for an Alternative Means of Emission 
Limitation at ExxonMobil Corporation; Marathon Petroleum Company, LP 
(for Itself and on Behalf of Its Subsidiary, Blanchard Refining, LLC); 
Chalmette Refining, LLC; and LACC, LLC

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice; final approval.

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SUMMARY: This notice announces our approval of the Alternative Means of 
Emission Limitation (AMEL) requests under the Clean Air Act (CAA) 
submitted from ExxonMobil Corporation; Marathon Petroleum Company, LP 
(for itself and on behalf of its subsidiary, Blanchard Refining, LLC); 
and Chalmette Refining, LLC to operate flares and multi-point ground 
flares (MPGFs) at several refineries in Texas and Louisiana, and from 
LACC, LLC to operate flares at a chemical plant in Louisiana. This 
approval notice specifies the operating conditions and monitoring, 
recordkeeping, and reporting requirements that these facilities must 
follow to demonstrate compliance with the approved AMEL.

DATES: The approval of the AMEL requests from ExxonMobil Corporation; 
Marathon Petroleum Company, LP (for itself and on behalf of its 
subsidiary, Blanchard Refining, LLC); Chalmette Refining, LLC; and 
LACC, LLC to operate certain flares at the refineries and a chemical 
plant, as specified in this notice, is effective on September 17, 2018.

ADDRESSES: The Environmental Protection Agency (EPA) has established a 
docket for this action under Docket ID No. EPA-HQ-OAR-2014-0738. All 
documents in the docket are listed on the https://www.regulations.gov 
website. Although listed, some information is not publicly available, 
e.g., confidential business information (CBI) or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, is not placed on the internet and will be 
publicly available only in hard copy form. Publicly available docket 
materials are available either electronically through http://www.regulations.gov or in hard copy at EPA Docket Center, EPA WJC West 
Building, Room Number 3334, 1301 Constitution Ave. NW, Washington, DC. 
The Public Reading Room hours of operation are 8:30 a.m. to 4:30 p.m. 
Eastern Standard Time (EST), Monday through Friday. The telephone 
number for the Public Reading Room is (202) 566-1744, and the telephone 
number for the Docket Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For questions about this final action, 
contact Ms. Angie Carey, 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) 541-2187; fax number: (919) 541-0516; and email 
address: [email protected].

SUPPLEMENTARY INFORMATION: Preamble acronyms and abbreviations. We use 
multiple acronyms and terms in this preamble. While this list may not 
be exhaustive, to ease the reading of this preamble and for reference 
purposes, the EPA defines the following terms and acronyms here:

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
g/mol grams per gram mole
HAP hazardous air pollutants
HP high pressure
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 flare
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
TCEQ Texas Commission on Environmental Quality
VOC volatile organic compounds

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

I. Background
    A. Summary
    B. Regulatory Flare Requirements
II. Summary of Public Comments on the AMEL Requests
III. AMEL for the Flares

I. Background

A. Summary

    In a Federal Register notice dated April 25, 2018, the EPA provided 
public notice and solicited comment on the requests under the CAA from 
ExxonMobil Corporation; Marathon Petroleum Company, LP (for itself and 
on behalf of its subsidiary, Blanchard Refining, LLC's); and Chalmette 
Refining, LLC for the operation of flares and MPGFs at several 
refineries in Texas and Louisiana, and from LACC, LLC to operate flares 
at a chemical plant in Louisiana (see 83 FR 18034). This action 
solicited comment on all aspects of the AMEL requests, including the 
operating conditions specified in that action that are necessary to 
achieve a reduction in emissions of volatile organic compounds and 
organic hazardous air pollutants at least equivalent to the reduction 
in emissions required by various standards in 40 CFR parts 60, 61, and 
63 that apply to emission sources that would be controlled by these 
flares and MPGFs. These standards incorporate the flare design and 
operating requirements in 40 CFR part 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

[[Page 46940]]

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 40 CFR part 60 and 63 standards cannot meet the 
flare tip velocity limits contained in the applicable General 
Provisions to 40 CFR part 60 and 63.
    This action provides a summary of the comments received as part of 
the public review process, our response to those comments, and our 
approval of these AMEL requests.

B. Regulatory Flare Requirements

    ExxonMobil, Marathon, Blanchard, and Chalmette provided the 
information specified in the flare AMEL framework set forth in the 
Petroleum Refinery MACT 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 ExxonMobil Corporation Baytown Refinery in Baytown, 
Texas, is seeking an AMEL to operate a gas-assisted flare, Flare 26, 
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, No. 1 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
   Applicable rules with vent       Baytown,      Marathon      Blanchard     Chalmette               Rule citation from title       Provisions for
    streams going to control       Texas Flare   Garyville,   Refining GBR   No. 1 Flare     LACC       40 CFR that allow for     alternative means of
            device(s)                  26          LA MPGF        MPGF                                     use of a flare          emission limitation
--------------------------------------------------------------------------------------------------------------------------------------------------------
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).
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).
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The provisions for the NSPS and National Emission Standards for 
Hazardous Air Pollutants (NESHAP) cited in Table 1 that ensure flares 
meet certain specific 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,\1\ it is 
established to the Administrator's satisfaction that such an AMEL will 
achieve emission reductions at least equivalent to the reductions 
required under the CAA section 111(h)(1) or 112(h)(1) standard. As 
noted in Table 1, many of the NSPS and NESHAP in the table above also 
include specific regulatory provisions allowing sources to request an 
AMEL.
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    \1\ CAA section 111(h)(3) specifically requires that the EPA 
provide an opportunity for a public hearing. The EPA provided an 
opportunity for a public hearing in the April 25, 2018, Federal 
Register action. However, no public hearing was requested.
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II. Summary of Public Comments on the AMEL Requests

    The EPA received four public comments on this action. Specifically, 
the EPA received suggested changes and clarifications from LACC, LLC, 
Marathon Petroleum Company, LP (for itself and on behalf of its 
subsidiary, Blanchard Refining, LLC), and ExxonMobil Corporation. The 
EPA also received one comment that does not mention any of the AMEL 
requests at issue and is, therefore, outside the scope

[[Page 46941]]

of the action. As discussed in more detail below, we have modified or 
otherwise clarified certain operating conditions in response to 
comments.\2\ All of the comments within the scope of the AMEL requests 
were supportive of the EPA approving the AMEL requests, and none of the 
comments raised issues with the EPA's authority to approve these AMEL 
requests under the CAA. None of the commenters asserted that the EPA 
lacked authority to approve the AMEL requests or that the AMEL requests 
would not achieve at least equivalent emissions reductions as flares 
that meet the standards in the General Provisions or in the Petroleum 
Refinery MACT at 40 CFR 63.670(r).
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    \2\ As explained below, we have clarified the reporting 
requirements for Exxon's Flare 26 in response to a comment by Exxon. 
We have similarly clarified Marathon's Garyville's and GBR's MPGFs 
reporting requirements as a result of this comment.
---------------------------------------------------------------------------

    Comment: LACC, LLC commented that the monitoring requirement in 
section (3) to install a video camera capable of continuously recording 
(i.e., at least one frame every 15 seconds with time and date stamps) 
images of the flare flame at a reasonable distance and suitable angle, 
will work for their MPGF, but not for their enclosed ground flare. LACC 
stated that it is not technically feasible to install a video camera 
and monitor the flare flame within the enclosed ground flare. 
Alternatively, LACC stated that it can monitor for the presence of 
visible emissions from the enclosed ground flare by using a video 
camera to monitor at the exit of the stack exhaust.
    Response: We agree that, although the camera would not be able to 
directly monitor visible emissions from the flare flame because of the 
enclosure, conducting visible emissions observations at the stack would 
be a reliable indicator of compliance with the requirements in section 
(3) below. Therefore, we accept this alternative and have made the 
appropriate change in section (3) below.
    Comment: Marathon Petroleum Company, LP commented that the 
operating conditions in Table 2 do not reflect what they requested in 
their AMEL for the MPGF at their Garyville refinery. They stated that 
they needed separate NHVcz limits for the pressure-assisted linear 
relief gas oxidizers (LRGO burners) and the steam-assisted steam 
kinetic energy combustors (SKEC burners) when both are being used 
simultaneously. Marathon explained that the SKEC burners would have a 
considerably different NHVcz value because of steam assist. This is 
because the steam assist is included in the NHVcz calculation for the 
SKEC burners, but not for the LRGO burners, given that the LRGO burners 
do not have steam assist.
    Response: The EPA acknowledges that the April notice did not 
reflect Marathon Petroleum Company, LP's supplemental request for the 
Garyville MPGF to maintain separate burner limits such that the SKEC 
burners would meet the NHVcz target from the SKEC equation and the LRGO 
burners would meet 600 British thermal units per standard cubic feet 
(BTU/scf). We discussed with Marathon its supplemental request upon 
receiving the comment. As we explained in that discussion, based on our 
review of the information provided by Marathon, the steam-to-vent gas 
ratio for the SKEC burners is not high enough to significantly affect 
the NHVcz during the high pressure flaring scenario. Therefore, we 
conclude that the burner requirements as set out in the April 25, 2018, 
AMEL document are appropriate. Marathon concurred with this conclusion 
in an email response after the comment period closed (available in 
Docket ID No. EPA-HQ-OAR-2014-0738 and EPA-HQ-OAR-2010-0682).
    Comment: Marathon Petroleum Company, LP commented that the 
requirement should be NHVvg = NHVcz with a limit of >=600 BTU/scf for 
the LH burner, and NHVcz >=600 BTU/scf for LRGO burners. Marathon notes 
that, as explained in its February 2, 2018, and March 27, 2018, 
supplemental letters, since the LH burner is air-assisted, therefore, 
the LH burner limitations provided in its request correspond to the 
NHVvg and not the NHVcz. Marathon further notes that the Petroleum 
Refinery requirements at 40 CFR 63.670(m)(1) states that NHVvg = NHVcz 
when there is no premix assist air flow.
    Response: For the reasons provided in Marathon's comment, we agree 
that for the LH burner, which is perimeter air assisted and not pre-mix 
air assisted, the NHVvg equals NHVcz. We, therefore, made this change 
in Table 2 below.
    Comment: ExxonMobil Corporation commented on a typographical 
correction in Table 2 for the Baytown, Texas, Flexicoker Flare 26. The 
proposed alternative operating condition was listed as >=270 BTU/scf 
NHVcz and velocity of <361 feet per second (ft/sec). However, the 
performance test results for the Flare 26 demonstrate that the 
destruction efficiency met 98 percent at 361 ft/sec.
    Response: We accept this correction and made the change in Table 2 
to <=361 ft/sec.
    Comment: ExxonMobil Corporation commented that the EPA should 
include a default molecular weight for pipeline natural gas that 
corresponds to an NHV of 920 BTU/scf listed in 40 CFR 63.670(j)(5).
    Response: We agree and are specifying the molecular weight of 
pipeline natural gas as 16.85 grams per gram mole (g/mol). It would be 
burdensome for Exxon to take samples of natural gas to determine 
molecular weight, when very little changes in molecular weight are 
expected. Therefore, we are specifying the molecular weight of natural 
gas of 16.85 can be used. This molecular weight is based on our default 
natural gas composition that was used to determine the net heating 
value in 40 CFR 63.670.
    Comment: ExxonMobil Corporation commented that the accuracy and 
calibration requirements in section (1)(f) of the initial Federal 
Register document should apply only to flares at chemical plants 
seeking AMEL approval since flares such as Exxon's Flare 26 is already 
subject to the accuracy and calibration requirements in the Petroleum 
Refinery MACT at 40 CFR 63.671(a)(1) and (4) and Table 13.
    Response: We agree and have clarified in section (1)(f) below that 
the accuracy and calibration requirements listed in Table 4 do not 
apply to refinery flares subject to requirements at 40 CFR 63.671(a)(1) 
and (4) and Table 13 of 40 CFR part 63, subpart CC.
    Comment: ExxonMobil Corporation commented that the Flare 26 follows 
the Petroleum Refinery MACT requirement at 40 CFR part 63, subpart CC, 
for pilot flame operations and does not use cross-lighting for the 
flare operation. They stated that the EPA should clarify in section (2) 
that the Flare 26 is only required to maintain flare pilots per the 
Petroleum Refinery MACT requirements in 40 CFR 63.670(b).
    Response: We agree that the requirements in section (2), which 
apply to flares that cross light, should not apply to Flare 26 because 
it does not use cross-lighting. We have made this change in section (2) 
below.
    Comment: ExxonMobil Corporation commented that the EPA should 
clarify which reporting requirements apply to the Flare 26 in section 
(6) and clarify that the reporting requirements for the flare tip 
velocity and NHVcz are applicable when regulated material is routed to 
the flare for at least 15 minutes.
    Response: While we believe that the records required in section 
(6)(c) are essentially the same as the reporting requirements in 
Petroleum Refinery NESHAP, 40 CFR part 63, subpart CC, section (6)(c) 
requires additional records related to the operation of MPGFs, which do 
not apply to Flare 26. Further,

[[Page 46942]]

we agree that the operating limits for NHVcz and Vtip apply whenever 
regulated material is routed to the flares for at least 15 minutes, as 
specified by 40 CFR part 63, subpart CC; Therefore, we are requiring 
that Flare 26 comply with the reporting requirements in the Petroleum 
Refinery NESHAP, 40 CFR part 63, subpart CC, instead of section (6) as 
part of this AMEL approval. However, MPGFs located at petroleum 
refineries must comply with the additional reporting requirements for 
MPGFs in (6)(c)(iv) and (v). To avoid other potential confusion, we are 
clarifying the applicability of section (6)(c) to all the flares 
covered in this notice. Specifically, section (6)(c) below provides 
that flares at refineries must meet the requirements in the Petroleum 
Refinery MACT in 40 CFR 63.655(g)(11)(i)-(iii), except that the 
applicable alternative operating conditions listed in Table 2 apply 
instead of the operating limits specified in 40 CFR 63.670(d) through 
(f). In addition, for refinery flares that are MPGFs, notification 
shall also include records specified in section (6)(c)(iv)-(v). For 
LACC MPGFs, the notification shall include the records specified in 
section (6)(c)(i)-(v).

III. AMEL for the Flares

    Based upon our review of the AMEL requests and the comments 
received through the public comment period, we are approving these AMEL 
requests and are establishing operating conditions for the flares at 
issue. The AMEL and the associated operating conditions are specified 
in Table 2 and accompanying paragraphs. These operating conditions will 
ensure that these flares will achieve emission reductions at least 
equivalent to flares complying with the flare requirements under the 
applicable NESHAP and NSPS identified in Table 1.

                                    Table 2--Alternative Operating Conditions
----------------------------------------------------------------------------------------------------------------
                                               Affected
    AMEL submitted          Company           facilities       Flare type(s)    Alternative operating conditions
----------------------------------------------------------------------------------------------------------------
11/7/17..............  ExxonMobil.......  Baytown, TX        Elevated gas-      >=270 BTU/scf NHV and velocity
                                           Flexicoker Flare   assist flare.      <=361 (ft/sec).
                                           26.
10/7/17..............  Marathon.........  Garyville, LA....  2 MPGFs..........  When both SKEC and LRGO burners
                                                                                 are being used, the higher of
                                                                                 >=600 BTU/scf NHV or >=127.27
                                                                                 ln(v)-110.87 NHV. When only the
                                                                                 SKEC burner is being used
                                                                                 >=127.27 ln(v)-110.87 NHV.
10/7/17..............  Marathon/          GBR (Texas City,   MPGF.............  NHV >=600 BTU/scf for the LH
                        Blanchard          TX).                                  burner, and NHV >=600 BTU/scf
                        Refining.                                                for LRGO burners.
9/19/17..............  Chalmette          Chalmette, LA....  Elevated multi-    >=1,000 BTU/scf NHV or LFL <=6.5
                        Refining.                             point flare.       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 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] TN17SE18.002

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] TN17SE18.003

    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, and the GBR LH burner, NHVvg 
= NHVcz. For assisted burners, such as the Marathon Garyville MPGF SKEC 
burners, and the Exxon Flare 26 gas-assisted burner, NHVcz is 
calculated using Equation 3.
[GRAPHIC] [TIFF OMITTED] TN17SE18.004

Where:

NHVcz = Net heating value of combustion

[[Page 46943]]

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, scf 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] TN17SE18.005

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]N2/LFLN2 = 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 Flare 26, the owner or operator shall calculate 
the 15-minute block average Vtip by using the following equation:
[GRAPHIC] [TIFF OMITTED] TN17SE18.006

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 owner or 
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[emsp14][deg]F) 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] TN17SE18.007

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 owner or operator must follow the accuracy and calibration 
procedures according to Table 4. Flares at refineries must meet the 
accuracy and calibration requirements in the Petroleum Refinery MACT at 
40 CFR 63.671(a)(1) and (4) and Table 13. 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

[[Page 46944]]

 
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.

                                 Table 4--Accuracy and Calibration Requirements
----------------------------------------------------------------------------------------------------------------
               Parameter                     Accuracy requirements              Calibration requirements
----------------------------------------------------------------------------------------------------------------
Flare Vent Gas Flow Rate..............  20 percent of flow  Performance evaluation biennially (every
                                         rate at velocities ranging      2 years) and following any period of
                                         from 0.1 to 1 foot per second.  more than 24 hours throughout which the
                                        5 percent of flow    flow rate exceeded the maximum rated
                                         rate at velocities greater      flow rate of the sensor, or the data
                                         than 1 foot per second.         recorder was off 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 Than      5 percent over the  Conduct a flow sensor calibration check
 Flare Vent Gas.                         normal range of flow measured   at least biennially (every 2 years);
                                         or 1.9 liters per minute (0.5   conduct a calibration check following
                                         gallons per minute),            any period of more than 24 hours
                                         whichever is greater, for       throughout which the flow rate exceeded
                                         liquid flow.                    the manufacturer's specified maximum
                                                                         rated flow rate or install a new flow
                                                                         sensor.
                                        5 percent over the  At least quarterly, inspect all
                                         normal range of flow measured   components for leakage, unless the
                                         or 280 liters per minute (10    continuous parameter monitoring system
                                         cubic feet per minute),         (CPMS) has a redundant flow sensor.
                                         whichever is greater, for gas
                                         flow.
                                        5 percent over the  Record the results of each calibration
                                         normal range measured for       check and 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 percent over the  Review pressure sensor readings at least
                                         normal range measured or 0.12   once a week for straight-line
                                         kilopascals (0.5 inches of      (unchanging) pressure and perform
                                         water column), whichever is     corrective action to 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 Calorimeter......  2 percent of span.  Calibration requirements--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 Chromatograph  As specified in Performance     Follow the procedure in PS 9 of 40 CFR
                                         Standard (PS) 9 of 40 CFR       part 60, appendix B, except that a
                                         part 60, appendix B.            single daily mid-level calibration
                                                                         check can be used (rather than
                                                                         triplicate analysis), the multi-point
                                                                         calibration can be conducted quarterly
                                                                         (rather than monthly), and the sampling
                                                                         line temperature must be maintained at
                                                                         a minimum temperature of 60 [deg]C
                                                                         (rather than 120 [deg]C).
Hydrogen Analyzer.....................  2 percent over the  Specify calibration requirements in your
                                         concentration measured, or      site specific CPMS monitoring plan.
                                         0.1 volume, percent,            Calibration requirements--follow
                                         whichever is greater.           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's No. 1 Flare, 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. The ExxonMobil flare, Flare 26, and 
GBR's LH flare must meet the requirements in the Petroleum Refinery 
MACT at 40 CFR 63.670(b) instead of the requirements herein in section 
(2).
    (3) Flares at refineries shall comply with the Petroleum Refinery 
MACT requirements of 40 CFR 63.670(h). For LACC, LLC's MPGFs, the flare 
system shall be operated with no visible emissions except for periods 
not to exceed a total of 5 minutes during any

[[Page 46945]]

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. For 
LACC's enclosed ground flare, LACC must install a video camera that is 
capable of continuously recording (i.e., at least one frame every 15 
seconds with time and date stamps) the stack exhaust exit at a 
reasonable distance and at an angle suitable for visible emissions 
observation in order 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 manned location where 
the video camera images may be viewed at any time.
    (4) For the MPGFs and Chalmette's No. 1 Flare, the owner or 
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. Flares at refineries must meet the 
accuracy and calibration requirements in the Petroleum Refinery MACT at 
40 CFR 63.671(a)(1) and (4) and Table 13. The pressure monitor at LACC 
shall meet the accuracy and calibration 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 owner or operator of 
refinery flares shall meet the reporting requirements in the Petroleum 
Refinery MACT in 40 CFR 63.655(g)(11)(i)-(iii), except that the 
applicable alternative operating conditions listed in Table 2 apply 
instead of the operating limits specified in 40 CFR 63.670(d) through 
(f). In addition, for refinery flares that are MPGFs, notification 
shall also include records specified in section (iv)-(v) below. For 
LACC MPGFs, the notification shall include the records specified in 
section (i)-(v) below.
    (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 condition (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.

    Dated: September 11, 2018.
Panagiotis Tsirigotis,
Director, Office of Air Quality Planning and Standards.
[FR Doc. 2018-20148 Filed 9-14-18; 8:45 am]
BILLING CODE 6560-50-P