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, 46939-46945 [2018-20148]

Download as PDF Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices of the protest or intervention to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426. This filing is accessible on-line at http://www.ferc.gov, using the eLibrary link and is available for electronic review in the Commission’s Public Reference Room in Washington, DC. There is an eSubscription link on the website that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email FERCOnlineSupport@ferc.gov, or call (866) 208–3676 (toll free). For TTY, call (202) 502–8659. Comment Date: 5:00 p.m. Eastern Time on September 28, 2018. Dated: September 11, 2018. Kimberly D. Bose, Secretary. [FR Doc. 2018–20101 Filed 9–14–18; 8:45 am] BILLING CODE 6717–01–P 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 Environmental Protection Agency (EPA). ACTION: Notice; final approval. AGENCY: 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 daltland on DSKBBV9HB2PROD with NOTICES SUMMARY: VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 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: carey.angela@epa.gov. SUPPLEMENTARY INFORMATION: Preamble acronyms and abbreviations. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: 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 PO 00000 Frm 00030 Fmt 4703 Sfmt 4703 46939 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 E:\FR\FM\17SEN1.SGM 17SEN1 46940 Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices 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 Applicable rules with vent streams going to control device(s) Exxon Mobil Baytown, Texas Flare 26 Marathon Garyville, LA MPGF Blanchard Refining GBR MPGF Chalmette No. 1 Flare LACC Rule citation from title 40 CFR that allow for use of a flare Provisions for alternative means of emission limitation NSPS Subpart VV .... NSPS Subpart VVa .. NSPS Subpart NNN NSPS Subpart QQQ NSPS Subpart RRR NSPS Subpart Kb .... NESHAP Subpart V .................... .................... .................... .................... .................... .................... .................... x x x x x x x x x x x x x x .................... .................... x .................... .................... .................... .................... ................ x x ................ x x x 60.482–10(d) ................................ 60.482–10a(d) .............................. 60.662(b) ...................................... 60.692–5(c) .................................. 60.702(b) ...................................... 60.112b(a)(3)(ii) ........................... 61.242–11(d) ................................ NESHAP Subpart J .. .................... .................... .................... .................... x 61.242–11(d) ................................ NESHAP Subpart Y .................... x x .................... ................ 61.271–(c)(2) ............................... NESHAP Subpart BB .................... x x .................... ................ 61.302(c) ...................................... NESHAP Subpart FF NESHAP Subpart F NESHAP Subpart G .................... .................... .................... x x x x x x .................... .................... .................... x x x NESHAP NESHAP NESHAP NESHAP NESHAP .................... .................... x .................... .................... x x x .................... .................... x x x .................... .................... .................... .................... x .................... .................... x x ................ x x .................... x x .................... ................ 61.349(a)(2) ................................. 63.103(a) ...................................... 63.113(a)(1)(i), 63.116(a)(2), 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). 63.172(d), 63.180(e) .................... 63.982(b) ...................................... 63.643(a)(1) ................................. 63.1034 ........................................ Table 7 to 63.1103(e) cross-references to NESHAP subpart SS above. 63.2378(a),63.2382, 63.2398 ...... 60.484(a)–(f). 60.484a(a)–(f). CAA section 111(h)(3). 42 U.S.C. 7411(h)(3). CAA section 111(h)(3). 60.114b. 40 CFR 63.6(g); 42 U.S.C. 7412(h)(3). 40 CFR 63.6(g); 42 U.S.C. 7412(h)(3). 40 CFR 63.6(g); 40 CFR 61.273; 42 U.S.C. 7412(h)(3). 40 CFR 63.6(g); 42 U.S.C. 7412(h)(3). 61.353(a); also see 61.12(d). 63.6(g); 42 U.S.C. 7412(h)(3). 63.6(g); 42 U.S.C. 7412(h)(3). Subpart Subpart Subpart Subpart Subpart daltland on DSKBBV9HB2PROD with NOTICES NESHAP Subpart EEEE. H SS CC UU YY 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 VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 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 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. PO 00000 Frm 00031 Fmt 4703 Sfmt 4703 63.177; 42 U.S.C. 7412(h)(3). CAA section 112(h)(3). 63.670(r). 63.1021(a)–(d). 63.1113. 63.6(g); 42 U.S.C. 7412(h)(3). regulatory provisions allowing sources to request an AMEL. 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 E:\FR\FM\17SEN1.SGM 17SEN1 daltland on DSKBBV9HB2PROD with NOTICES Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices 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). 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 pressureassisted 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, 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. VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 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 PO 00000 Frm 00032 Fmt 4703 Sfmt 4703 46941 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 crosslighting 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, E:\FR\FM\17SEN1.SGM 17SEN1 46942 Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices 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 AMEL submitted Company Affected facilities Flare type(s) 11/7/17 ........... ExxonMobil ............ Elevated gas-assist flare. ≥270 BTU/scf NHVcz and velocity ≤361 (ft/sec). 10/7/17 ........... Marathon ................ Baytown, TX Flexicoker Flare 26. Garyville, LA .......... 2 MPGFs ................ 10/7/17 ........... 9/19/17 ........... Marathon/Blanchard Refining. Chalmette Refining GBR (Texas City, TX). Chalmette, LA ........ When both SKEC and LRGO burners are being used, the higher of ≥600 BTU/scf NHVcz or ≥127.27 ln(vvg)¥110.87 NHVcz. When only the SKEC burner is being used ≥127.27 ln(vvg)¥110.87 NHVcz. NHVvg ≥600 BTU/scf for the LH burner, and NHVcz ≥600 BTU/scf for LRGO burners. ≥1,000 BTU/scf NHVcz or LFLcz ≤6.5 vol%. 5/1/17 ............. LACC ..................... Lake Charles, LA ... VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 ≥1075 BTU/scf NHVcz for INDAIR Burners; ≥800 BTU/scf NHVcz for LRGO only. (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. PO 00000 Frm 00033 Fmt 4703 Sfmt 4703 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 gasassisted burner, NHVcz is calculated using Equation 3. Where: NHVcz = Net heating value of combustion E:\FR\FM\17SEN1.SGM 17SEN1 EN17SE18.004</GPH> 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 (°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 °C for ‘‘standard temperature.’’ Table 3 summarizes component properties including net heating values. EN17SE18.003</GPH> 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 Elevated multi-point flare. 2 MPGFs ............... EN17SE18.002</GPH> daltland on DSKBBV9HB2PROD with NOTICES (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 15minute 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: MPGF .................... Alternative operating conditions 46943 Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices 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. (ii) For non-assisted flare burners, LFLvg = LFLcz. (c) Calculation of Vtip For the ExxonMobil Flare 26, the owner or operator shall calculate the 15minute block average Vtip by using the following equation: (b) Calculation of LFLcz (i) The owner or operator shall determine LFLcz from compositional analysis data by using the following equation: 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 15minute block average. 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. ci = 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 = ∞, so that cN2/LFLN2 = 0). LFL values for common flare vent gas components are provided in Table 3. (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 °C (68 °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: Where: Qvol = Volumetric flow rate, scf/sec. Qmass = Mass flow rate, pounds per sec. 385.3 = Conversion factor, scf per poundmole. MWt = Molecular weight of the gas at the flow monitoring location, pounds per poundmole. (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. Acetylene ......................................................................................................... Benzene ........................................................................................................... 1,2-Butadiene .................................................................................................. 1,3-Butadiene .................................................................................................. iso-Butane ........................................................................................................ n-Butane .......................................................................................................... cis-Butene ........................................................................................................ iso-Butene ........................................................................................................ trans-Butene .................................................................................................... Carbon Dioxide ................................................................................................ Carbon Monoxide ............................................................................................ Cyclopropane ................................................................................................... Ethane ............................................................................................................. Ethylene ........................................................................................................... Hydrogen ......................................................................................................... Hydrogen Sulfide ............................................................................................. Methane ........................................................................................................... Methyl-Acetylene ............................................................................................. Nitrogen ........................................................................................................... Oxygen ............................................................................................................ Pentane+ (C5+) ............................................................................................... Propadiene ...................................................................................................... Propane ........................................................................................................... Propylene ......................................................................................................... C2H2 .............. C6H6 .............. C4H6 .............. C4H6 .............. C4H10 ............. C4H10 ............. C4H8 .............. C4H8 .............. C4H8 .............. CO2 ................ CO ................. C3H6 .............. C2H6 .............. C2H4 .............. H2 ................... H2S ................ CH4 ................ C3H4 .............. N2 ................... O2 .................. C5H12 ............. C3H4 .............. C3H8 .............. C3H6 .............. VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 PO 00000 Frm 00034 Fmt 4703 Sfmt 4703 MWi (pounds per pound-mole) E:\FR\FM\17SEN1.SGM 26.04 78.11 54.09 54.09 58.12 58.12 56.11 56.11 56.11 44.01 28.01 42.08 30.07 28.05 2.02 34.08 16.04 40.06 28.01 32.00 72.15 40.06 44.10 42.08 17SEN1 NHVi (BTU/scf) 1,404 3,591 2,794 2,690 2,957 2,968 2,830 2,928 2,826 0 316 2,185 1,595 1,477 * 1,212 587 896 2,088 0 0 3,655 2,066 2,281 2,150 LFLi (volume %) 2.5 1.3 2.0 2.0 1.8 1.8 1.6 1.8 1.7 ∞ 12.5 2.4 3.0 2.7 4.0 4.0 5.0 1.7 ∞ ∞ 1.4 2.16 2.1 2.4 EN17SE18.007</GPH> Molecular formula EN17SE18.006</GPH> Component EN17SE18.005</GPH> daltland on DSKBBV9HB2PROD with NOTICES TABLE 3—INDIVIDUAL COMPONENT PROPERTIES 46944 Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices TABLE 3—INDIVIDUAL COMPONENT PROPERTIES—Continued Component Molecular formula Water ............................................................................................................... H2O ................ MWi (pounds per pound-mole) NHVi (BTU/scf) 18.02 LFLi (volume %) 0 ∞ * 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 rate at velocities ranging from 0.1 to 1 foot per second. ±5 percent of flow rate at velocities greater than 1 foot per second. Flow Rate for All Flows Other Than Flare Vent Gas. ±5 percent over the normal range of flow measured or 1.9 liters per minute (0.5 gallons per minute), whichever is greater, for liquid flow. Performance evaluation biennially (every 2 years) and following any period of more than 24 hours throughout which the flow rate exceeded the maximum rated flow rate of the sensor, or the data 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. Conduct a flow sensor calibration check at least biennially (every 2 years); conduct a calibration check following any period of more than 24 hours throughout which the flow rate exceeded the manufacturer’s specified maximum rated flow rate or install a new flow sensor. At least quarterly, inspect all components for leakage, unless the continuous parameter monitoring system (CPMS) has a redundant flow sensor. daltland on DSKBBV9HB2PROD with NOTICES ±5 percent over the normal range of flow measured or 280 liters per minute (10 cubic feet per minute), whichever is greater, for gas flow. ±5 percent over the normal range measured for mass flow. Pressure ............................ ±5 percent over the normal range measured or 0.12 kilopascals (0.5 inches of water column), whichever is greater. Net Heating Value by Calorimeter. ±2 percent of span ....................................................... Net Heating Value by Gas Chromatograph. As specified in Performance Standard (PS) 9 of 40 CFR part 60, appendix B. Hydrogen Analyzer ............ ±2 percent over the concentration measured, or 0.1 volume, percent, whichever is greater. (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 VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 Record the results of each calibration check and inspection. Locate the flow sensor(s) and other necessary equipment (such as straightening vanes) in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances. Review pressure sensor readings at least once a week for straight-line (unchanging) pressure and perform corrective action to ensure proper 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. 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. Follow the procedure in PS 9 of 40 CFR part 60, appendix B, except that a single daily mid-level calibration check can be used (rather than triplicate analysis), the multi-point calibration can be conducted quarterly (rather than monthly), and the sampling line temperature must be maintained at a minimum temperature of 60 °C (rather than 120 °C). Specify calibration requirements in your site specific CPMS monitoring plan. Calibration requirements—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. 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 PO 00000 Frm 00035 Fmt 4703 Sfmt 4703 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 E:\FR\FM\17SEN1.SGM 17SEN1 daltland on DSKBBV9HB2PROD with NOTICES Federal Register / Vol. 83, No. 180 / Monday, September 17, 2018 / Notices 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 VerDate Sep<11>2014 17:47 Sep 14, 2018 Jkt 244001 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 PO 00000 Frm 00036 Fmt 4703 Sfmt 4703 46945 ENVIRONMENTAL PROTECTION AGENCY [FRL–9983–85—Region 3] Clean Water Act: West Virginia’s NPDES Program Revision Environmental Protection Agency (EPA). ACTION: Notice of revision, public comment period, and opportunity to request a public hearing. AGENCY: The State of West Virginia has submitted revisions to its authorized National Pollutant Discharge Elimination System (NPDES) program for the U.S. Environmental Protection Agency’s (EPA) review. These revisions consist of amendments to the West Virginia Water Pollution Control Act codified in Senate Bill 357 (SB 357) and to West Virginia’s Code of State Regulations codified as House Bill 2283 (HB 2283). The EPA has determined that the submitted revisions constitute a substantial revision to West Virginia’s authorized NPDES program. Accordingly, the EPA is requesting public comment and providing a notice of an opportunity to request a public hearing. Copies of SB357 and HB2283 are available for public inspection as indicated below. DATES: Comments must be submitted in writing to EPA on or before October 17, 2018. ADDRESSES: Comments on the WV NPDES Program revisions should be sent to Francisco Cruz, Water Protection Division (3WP41), U.S. Environmental Protection Agency Region 3, 1650 Arch Street, Philadelphia, PA 19103–2019 or email to cruz.francisco@epa.gov. Oral comments will not be considered. Underlying documents from the administrative record for this decision are available for public inspection at the above address. Please contact Mr. Francisco Cruz to schedule an inspection. The public, during the term of this Federal Register notice, can request a public hearing. Such a hearing will be held if there is significant public interest based on requests received. FOR FURTHER INFORMATION CONTACT: For additional information, contact Francisco Cruz at (215) 814–5734. SUPPLEMENTARY INFORMATION: Section 402 of the Federal Clean Water Act (CWA) created the NPDES program under which the EPA may issue permits for the discharge of pollutants into waters of the United States under conditions required by the CWA. Section 402(b) allows states to assume NPDES program responsibilities upon approval by the EPA. On May 10, 1982, SUMMARY: E:\FR\FM\17SEN1.SGM 17SEN1

Agencies

[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.

-----------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

    \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