Document m4dN8jqwYq4vrz5RdoVX9OJ

EPA Inspection Report - Page 1 of 94 Region 6 - Compliance Assurance and Enforcement Division INSPECTION REPORT Inspection Date(s): Media Program: Regulatory Program(s) 05/19/2025 to 05/23/2025 Air Consent Decree, Civil Action 07-CV-00248-MAC Company Name: Facility Name: Facility Physical Location: (city, state, zip code) Mailing address: (city, state, zip code) County/Parish: Facility Phone Number Facility Contact: TotalEnergies Petrochemicals and Refining USA, Inc. Port Arthur Refinery 7600 32nd Street Port Arthur, TX 77642-7901 P.O. Box 849 Port Arthur, TX 77641-0849 Jefferson County (409) 963-6800 Sam Breaux Environmental Superintendent Sam.breaux@totalenergies.com FRS Number: Identification/Permit Number: Media Identifier Number: NAICS: SIC: 110000755200 RN102457520, NSR 46396, PSDTX1073M3 and N044, FOP O1267 ICIS-Air TX0000004824500037 324110 2911 Personnel participating in inspection: Prince Nfodzo US EPA R6 ECDAR Kim Nguyen US EPA R6 ECDAR Nicolas Studebaker US EPA R6 ECDAR Sam Breaux TotalEnergies Port Arthur Refinery Isaac Bankole TotalEnergies Port Arthur Refinery Amanda Trammel TotalEnergies Port Arthur Refinery Kristopher Beard TotalEnergies Port Arthur Refinery Anthony McLaughlin TotalEnergies Port Arthur Refinery Environmental Engineer Environmental Scientist Physical Scientist Environmental Superintendent Industrial Performance Environmental Specialist Environmental Engineering Advisor Environmental Specialist EPA Lead Inspector Signature/Date Supervisor Signature/Date Nfodzo, Prince Prince Nfodzo KAYLA BUCHANAN Kayla Buchanan Digitally signed by Nfodzo, Prince Date: 2025.06.27 12:00:22 -05'00' Digitally signed by KAYLA BUCHANAN Date: 2025.06.27 13:35:19 -05'00' Date Date 6ENFORM-019-R3 (11/14/2013) EPA Inspection Report - Page 2 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 Section I - INTRODUCTION PURPOSE OF THE INSPECTION EPA Region 6 inspectors Kim Nguyen, Nicolas Studebaker, and I (Prince Nfodzo) arrived at TotalEnergies Petrochemicals and Refining USA, Inc. ("TotalEnergies"), formerly TOTAL Petrochemicals USA, Inc ("TOTAL"), Port Arthur Refinery ("PAR") at 2:20 pm on May 19, 2025, for an announced inspection. We conducted a fenceline survey and did not observe anything of concern. We met with TotalEnergies PAR representatives at 2:45 pm for an opening conference. I presented my credentials to Ms. Connie Howard, Environmental Engineering Advisor, and informed the representatives that this was an EPA inspection to evaluate compliance with the facility's federally issued consent decree (Civil Action Number 07-CV-00248-MAC). The attendees sign-in sheet for the opening conference is included as Appendix 3. The scope of the inspection is a partial compliance evaluation (PCE) focused on the four marquee issues addressed by the consent decree: (i) emissions control at the Fluidized Catalytic Cracking Unit (FCCU), Heaters, and Boilers; (ii) emissions control at Sulfur Recovery Plants (SRPs) and flaring; (iii) Benzene Waste Operations NESHAP (BWON) program enhancements; and (iv) Leak Detection and Repair (LDAR) program enhancements. The consent decree addresses the requirements of nitrogen oxides (NOx), sulfur dioxide (SO2), carbon monoxide (CO), particulate matter (PM), volatile organic compounds (VOCs), and benzene emission reductions through various construction projects, process additives, and process and/or program enhancements. FACILITY DESCRIPTION The TotalEnergies Port Arthur Refinery is an integrated petroleum refinery with associated petrochemical operations and a crude processing capacity of 238,000 barrels per day. Crude oil is delivered to the refinery to be processed and refined into various petrochemical products such as gasoline, diesel, jet fuel, heating oils, and aromatics. Crude oil arrives via pipeline and marine vessel. The crude is split into various petroleum fractions via distillation. Products leave the facility by pipeline, railcar, trucks, and maritime shipping. A plant wide process flow diagram, and written facility description are included as Appendix 4. Section II - OBSERVATIONS TotalEnergies operates a mobile continuous emissions monitoring system ("CEMS") trailer that has all the calibration gases used to conduct quarterly cylinder gas audits ("CGAs"). We verified that the certifications and concentrations of the gases were current and accurate. Photographs of the CEMS trailer are included as Photo Nos. 3 and 4 in Appendix 1. Part V. New Source Review/Prevention of Significant Deterioration (NSR/PSD) A. Control of NOx Emissions Reduction from FCCU Program Summary: TOTAL shall limit NOx emissions from any FCCU to 30 ppmvd or less on a 365- day rolling average basis and 60 ppmvd or less on a 7-day rolling average basis, each at 0% Oxygen (O2). TOTAL shall use a NOx CEMS to monitor the performance of any FCCU and to report compliance with the terms and conditions of the consent decree. EPA Inspection Report - Page 3 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 TotalEnergies complies with the NOx emissions limits mainly by adjusting temperature and oxygen levels and occasionally using low-NOx combustion promoters. TotalEnergies fully incorporated the NOx emission limits in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024. We observed that TotalEnergies installed and is operating NOx and O2 CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. Photographs of the outlet and inlet CEMS analyzers are included as Photo Nos. 1 and 2 respectively, in Appendix 1. The trends for the FCCU NOx emission limits from May 1, 2024 - April 30, 2025 is included as Appendix 5. There was no exceedance of the 7-day rolling average limit, however TotalEnergies exceeded the 365day rolling average limit throughout the entire period [see Area of Concern ("AOC") #1]. I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period January 2018 - December 2024 (see AOC #2). B. Control of SO2 Emissions from FCCU Program Summary: TOTAL shall limit SO2 emissions from any FCCU at the refinery to 25 ppmvd on a 365-day rolling average and 50 ppm on a 7-day rolling average, each at 0% O2. TOTAL shall use a SO2 CEMS to monitor the performance of any FCCU and to report compliance with the terms and conditions of the consent decree. TotalEnergies installed and operates a wet gas scrubber to comply with the SO2 emissions limits. TotalEnergies fully incorporated the SO2 emission limits in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024. We observed that TotalEnergies installed and is operating SO2 and O2 CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. Photographs of the outlet and inlet CEMS analyzers are included as Photo Nos. 1 and 2 respectively, in Appendix 1. The trends for the FCCU SO2 emission limits from May 1, 2024 - April 30, 2025 is included as Appendix 5. There was no exceedance of the limits during the period. I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period January 2018 - December 2024 (see AOC #2). C. Control of PM Emissions from FCCU Program Summary: TOTAL shall limit PM emissions from any FCCU at the refinery to 0.5 pounds or less per 1000 pounds of coke burned on a 3-hour average basis. TotalEnergies has fully incorporated the PM emission limit in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024, and conducts performance tests to demonstrate compliance with the PM emission limit. The PM emission limit was not exceeded during performance tests conducted on March 20, 2024, and May 8, 2024. EPA Inspection Report - Page 4 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 D. Control of CO Emissions from FCCU Program Summary: TOTAL shall limit CO emissions from any FCCU at the refinery to 500 ppmvd or less on a 1-hour average basis and 100 ppmvd or less on a 365-day rolling average basis. TOTAL shall use a CO CEMS to monitor the performance of any FCCU and to report compliance with the terms and conditions of the consent decree. TotalEnergies complies with the CO emissions limits mainly by adjusting temperature and oxygen levels. TotalEnergies fully incorporated the CO emission limits in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024. We observed that TotalEnergies installed and is operating CO and O2 CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. Photographs of the outlet and inlet CEMS analyzers are included as Photo Nos. 1 and 2, respectively, in Appendix 1. The trends for the FCCU CO emission limits from May 1, 2024 - April 30, 2025, is included as Appendix 5. There was no exceedance of the CO limits during the period. I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period of January 2018 - December 2024 (see AOC #2). E. NSPS Subparts A and J Applicability to FCCU Regenerator Program Summary: Any FCCU Catalyst Regenerator at the refinery shall be an "affected facility" as the term is used in 40 C.F.R. Part 60, Subparts A and J, and therefore subject to, and required to comply with, the requirements of 40 C.F.R. Part 60, Subparts A and J, for each relevant pollutant. TOTAL shall continuously monitor and record (1) the pressure drop across the wet gas scrubber, and (2) the scrubber liquid to gas ratio. TotalEnergies fully incorporated the FCCU NSPS A and J requirements for SO2, CO, PM and Opacity emission limits in Federal Operating Permit O1267 issued August 13, 2010. In lieu of continuous opacity monitoring, TotalEnergies obtained an alternative monitoring plan that monitors the pressure drop across the wet gas scrubber (P) and the liquid to gas (L/G) ratio. TotalEnergies incorporated this requirement in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024. The trends for the P and L/G ratio limits from May 1, 2024 - April 30, 2025, is included as Appendix 5. TotalEnergies did not meet the minimum limits for both P and the L/G ratio multiple times during the period (see AOC #1). F. Control of NOx Emissions from Heaters and Boilers Program Summary: TOTAL shall install NOx control technology on or otherwise limit NOx emissions from the covered Heaters and Boilers as listed in Appendix A of the consent decree such that, the refinery-wide weighted-average NOx emission is no greater than 0.040 lbs.-NOx/mmBtu. TOTAL shall monitor each covered Heater or Boiler as follows: (i) For a Covered Heater or Boiler with a Heat Input Capacity greater than 100 MMBTU/hr (HHV), TOTAL shall install or continue to operate a CEMS for NOx; (ii) For a Covered Heater or Boiler with a Heat Input Capacity of less than or equal to 100 MMBTU/hr (HHV), TOTAL shall conduct an initial performance test and any periodic tests that may be required by EPA or by the applicable State or local permitting authority under the applicable regulatory authority. EPA Inspection Report - Page 5 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 TotalEnergies complies with the emission reduction from Heaters and Boilers at the refinery by limiting NOx emissions on some units. The final update for covered Heaters and Boilers is included as Appendix 6. TotalEnergies has not included the limits for some of the covered heaters in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024 (see AOC #3). TotalEnergies also used inaccurate NOx limits in excess emissions reporting (see AOC #4). We observed that TotalEnergies installed NOx converter on the Heater and Boiler CEMS analyzers to convert NOx to NO, and is operating NO and O2 CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. Photographs of some of the CEMS analyzers are included as Photo Nos. 5, 6, and 8 in Appendix 1. The trends for the Heater and Boilers NOx emission limits from May 1, 2024 - April 30, 2025, are included as Appendix 7. All the heaters exceeded the annual NOx lb/mmBtu limit multiple times during the period (see AOC #1). I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period January 2018 - December 2024 (see AOC #2). G. Control of SO2 emissions from Heaters and Boilers Program Summary: All heaters and boilers at the Refinery shall be "affected facilities," as that term is used in 40 C.F.R. Part 60, Subparts A and J, and therefore subject to, and required to comply with 40 C.F.R. Part 60, Subparts A and J for fuel combustion devices. TOTAL shall not burn Fuel Oil in any combustion unit at the Refinery. TotalEnergies is required to comply with H2S concentration limit of 162 ppmv on a 3-hour rolling average basis for fuel gas combusted in heaters and boilers. TotalEnergies incorporated the fuel gas H2S concentration limit in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024, but the requirement that TotalEnergies will not burn fuel oil in any combustion device is not incorporated in the permit (see AOC #3). TotalEnergies monitors the refinery fuel gas at two locations identified as V106A and V106. We observed that TotalEnergies has installed and is operating the H2S CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. Photographs of representative CEMS analyzers are included as Photo Nos. 5, 6, and 8 in Appendix 1. The trends for the refinery fuel gas H2S concentration limit on a 3-hour rolling average basis from May 1, 2024 - April 30, 2025, for V106A is included as Appendix 8. TotalEnergies exceeded the 3-hour rolling average concentration limit of 162 ppmv once during the period. I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period of January 2018 - December 2024 (see AOC #2). EPA Inspection Report - Page 6 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 Part VI. New Source Performance Standards (NSPS) and Flaring A. NSPS Applicability to Sulfur Recovery Plants Program Summary: All Sulfur Recovery Plants at the refinery shall be "affected facilities," as that term is used in 40 C.F.R. Part 60, Subparts A and J. All Sulfur Recovery Plants at the Refinery shall be subject to, and required to comply with, the requirements of 40 C.F.R. Part 60, Subparts A and J. TOTAL shall monitor emissions from each SRP with CEMS at each emission point, unless an SO2 alternative monitoring procedure has been approved by EPA, per 40 C.F.R. 60.13(i), for any of the emission points. TOTAL shall continue to route, or will route, all sulfur pit emissions at the Refinery so that they are eliminated, controlled, or included and monitored as part of a SRP's emissions subject to the NSPS Subpart J limit for SO2 at 40 C.F.R. 60.104(a)(2). TotalEnergies's Port Arthur refinery operates four sulfur recovery plants identified as SRU #1, SRU #3 SRU #4, and SRU #5. SRUs #1 and #3 share a common tail gas treatment unit and thermal oxidizer. TotalEnergies incorporated the requirements to comply with SO2 emission limits, and the control of sulfur pit emissions in permit 46396, PSDTX1073M3 and N044 issued April 4, 2024. We observed that TotalEnergies installed and is operating the SO2 CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. We also observed that sulfur pit emissions were routed to the tail gas treatment units. Photographs of representative CEMS analyzers are included as Photo Nos. 11, and 12 in Appendix 1. The trends for the sulfur recovery plant SO2 emission limits on a 12-hour rolling average basis from May 1, 2024 - April 30, 2025, are included as Appendix 9. TotalEnergies exceeded the 12-hour rolling average emission limit of 250 ppm multiple times at SRUs #1, #3, and #4, and once at SRU #5 during the period (see AOC #1). We viewed the tail gas treatment units with an optical gas imaging (OGI) camera, and observed hydrocarbon emissions from the SRU #5 thermal oxidizer (see Video FLIR0301 in Appendix 2, AOC #5) I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period of January 2018 - December 2024 (see AOC #2). F. NSPS Applicability to Flaring Devices Program Summary: Each Flaring Device shall be an "affected facility," as that term is used in 40 C.F.R. Part 60, Subparts A and J, and therefore subject to, and required to comply with, the requirements of 40 C.F.R. Part 60, Subparts A and J, for fuel gas combustion devices. TotalEnergies operates four flares at the Port Arthur refinery identified as North, South, East and Middle flares, and is complying with H2S concentration limit of 162 ppmv on a 3-hour rolling average basis for fuel gas combusted in the flares. We observed that TotalEnergies has installed and is operating H2S CEMS in accordance with the applicable requirements, and certification and concentrations of calibration gases were accurate and current. We did not observe visible emissions from any of the flares during the inspection; however, we observed hydrocarbon emissions from the flares with optical gas imaging (OGI) camera (see Video FLIR0288, FLIR0296, and FLIR0297 in Appendix 2, AOC #5). I reviewed flaring incidents and noted that there was an increasing trend in the number of occurrences per year (see AOC #6) EPA Inspection Report - Page 7 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 I noted that TotalEnergies did not conduct quarterly CEMS audits in accordance with the applicable requirements for the period January 2018 - December 2024 (see AOC #2). J. Flare Gas Recovery Systems Program Summary: To the extent that TOTAL currently operates or will operate a flare gas recovery system, TOTAL will take all reasonable measures to minimize emissions while periodic maintenance is being performed. TotalEnergies operates two interconnected flare gas recovery systems (FGRS) to control continuous or routine combustion in the flaring devices (FGR1 and FGR2). At the time of the inspection, one of the three compressors on FGR1 was out of service and sent out for repairs. We viewed the units with an OGI camera and did not observe any significant trailing hydrocarbon emissions. Part VII. Benzene Waste Operations NESHAP ("BWON") Program Enhancements Program Summary: TOTAL shall comply with the compliance option set forth at 40 C.F.R. 61.342(e) ("6 BQ Compliance Option"), along with all other applicable requirements of 40 C.F.R. Part 61, Subpart FF ("Benzene Waste Operations NESHAP" or "Subpart FF"). TOTAL shall continue to operate dual carbon canisters, in series, at all locations within the refinery where a carbon canister(s) is used as a control device under Subpart FF. TOTAL shall conduct audits of all laboratories that perform analyses of TOTAL's Subpart FF samples to ensure that proper analytical and quality assurance/quality control procedures are followed for such samples. TOTAL shall develop and begin implementation of annual training for all employees asked to draw benzene waste samples for Subpart FF compliance. TotalEnergies is complying with the 6 BQ compliance option and operates dual carbon canisters in series as a control device. A written description of the BWON sampling plan and simplified process diagram are included as Appendix 10. I reviewed carbon canister monitoring records for May 1, 2024 - April 30, 2025, and noted that TotalEnergies monitored for breakthrough and replaced carbon canisters as required. TotalEnergies operates 18 tanks in BWON service that hold recovered oil, process water, storm water, slop oil and sour water. We viewed the tanks and drain system with an OGI camera and did not observe hydrocarbon emissions. We noted one instance of a drainpipe wrapped with an ice bag, shown as Photo No. 15 in Appendix 1 (see AOC #7). We observed employees conduct sampling at the Process Water Treating Complex (PWTC) laboratory sampling point. Photographs of the employee's field records and chain of custody are included as Photo Nos. 18, and 19 in Appendix 1. I reviewed records of audits conducted at laboratories that perform BWON sample analyses, and noted that TotalEnergies conducted audits of the Eurofins Xenco laboratory biennially as required by the consent decree in 2018, 2020, 2021, and 2023. I reviewed annual training records of employees that draw benzene samples from 2018 - 2024, and noted lapses in the employee training (see AOC #8). EPA Inspection Report - Page 8 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 VIII. Leak Detection and Repair ("LDAR") Program Program Summary: TOTAL shall implement measures to enhance the refinery's LDAR program under 40 CFR Subpart GGG, Part 61 Subparts J and V and Part 63 Subparts F, H and CC. TOTAL shall develop a written description of a Refinery-wide program designed to achieve and maintain compliance with all applicable federal and state LDAR regulations, as well as all requirements imposed by this Part. TOTAL shall implement a training program at the Refinery for LDAR personnel. TOTAL shall conduct periodic refinery-wide audits of TOTAL's compliance with all applicable LDAR requirements at the Refinery. TotalEnergies uses Atlas Technical Consultants (formerly Dexter Field Services) to implement the LDAR program. We verified that TotalEnergies conducts mid-day and end-of-shift drift checks, as required by the CD. We observed that TotalEnergies calibrated monitoring instruments (Phoenix 21) accurately. I verified that certification and concentrations of calibration gases were accurate and current, and that TotalEnergies uses electronic data collection for LDAR monitoring with data loggers, and leak tracking and reporting software (LeakDAS). TotalEnergies consistently maintains equipment calibration records, and conducted LDAR program audits in 2019, 2021, and 2023 as required by the consent decree. I reviewed annual training records of LDAR personnel and noted some lapses (see AOC #9). We walked through the units and observed that some components were not properly tagged (see AOC #10). Photographs of some of the tagging issues are shown as Photo Nos. 7, 9, 13, 14, and 17 in Appendix 1. We also observed some leaking components with an OGI camera (see Videos FLIR0290, FLIR0291, FLIR0292, FLIR0293, FLIR0294, FLIR 0295, FLIR0298, and FLIR0299 in Appendix 2, see AOC #5) Section III - AREAS OF CONCERN 1. Emission limit exceedances: The consent decree requires TotalEnergies to control emissions and comply with emission limits. TotalEnergies exceeded the emission limits at the following units during the period of May 1, 2024, - April 30, 2025: a. FCCU 30 ppm NOx 365-day rolling average for the entire period of May 1, 2024, - April 30, 2025. Though the 60 ppm 7-day rolling average was not exceeded, it was above 30 ppm most of the period, and thus impacting the length of time it will take to come into compliance with the 365-day rolling average limit. b. FCCU Wet Gas Scrubber alternative monitoring parameters; pressure drop across the wet gas scrubber (P) and the liquid to gas (L/G) ratio 3-hour averages almost the entire period of May 1, 2024, - April 30, 2025. c. Heaters and Boilers NOx lb/mmBtu for most of the period of May 1, 2024 - April 30, 2025 at eight (8) heaters that TotalEnergies uses to comply with the refinery-wide weighted-average NOx emission limit of 0.040 lbs.-NOx/mmBtu. d. Sulfur Recovery Plant 250 ppm SO2 12-hour rolling average multiple times during the period at SRU #s 1, 3, and 4. 2. CEMS audit issues: a. FCCU - TotalEnergies conducted CGAs instead of RATA during the 4th quarter of 2021 and conducted successive audits closer than two months apart between 3rd and 4th quarters of 2024. b. Heaters and Boilers - TotalEnergies conducted two audits in 1st quarter of 2021 and did not conduct an audit in 2nd quarter of 2021 at ACU H-101; did not conduct audit in 4th EPA Inspection Report - Page 9 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 quarter of 2024 at ACU H-201; conducted successive audits closer than two months apart between 4th quarter of 2023 and 1st quarter of 2024 at VDU H-301; conducted successive audits closer than two months apart between 1st and 2nd quarters of 2018, 3rd and 4th quarters of 2020, and did not conduct an audit in 4th quarter of 2021 at Unibon 13H-1; and conducted successive audits closer than two months apart between 3rd and 4th quarters of 2018 at Boilers H-300 and H-350. c. Sulfur Recovery Plants - TotalEnergies did not conduct RATAs in 2021-2024, and conducted successive audits closer than two months apart between 2nd and 3rd quarters of 2018 and 2nd and 3rd quarters of 2020 at SRU #1 and #3; did not conduct an audit in the 1st quarter of 2023 at SRU #4; and did not conduct an audit in 2nd quarter of 2023 at SRU #5. d. Flares - TotalEnergies conducted successive audits closer than two months apart between 2nd and 3rd quarters of 2019 at North and South Flares; 1st and 2nd quarters of 2019, and 2nd and 3rd quarters of 2020 at East Flare; and 2nd and 3rd quarters of 2018, and 2nd and 3rd quarters of 2019 at Middle Flare. e. Refinery Fuel Gas - TotalEnergies did not conduct RATA in 2018 at V106, and did not conduct quarterly audits in 2nd quarter of 2022 at V106 and V106A. 3. Permit deficiencies in TotalEnergies' permit 46396, PSDTX1073M3 and N044 issued April 4, 2024: a. Special Condition (SC) 9 states that "The permittee shall comply with the maximum hourly firing rates represented in Attachment A." Attachment A does not include the following heaters which are included in TotalEnergies' 2023 updated list of covered Heaters and Boilers under the consent decree NOx reduction plan: (i) No. 1 Crude Heater, ACU-1 H-101 (ii) No. 2 Crude Heater, ACU-2 H-201 (iii) Vacuum Distillation Unit 1 Heater, VDU-1 H-301 (iv) Demex Heater 3H-1 (v) Unibon Heater 13H-1 (vi) DHT Heaters 51H-1, 52H-1 and 52H-2 (vii) Condensate Splitter Heater H-1 b. SC 11 states in part that "The permittee shall comply with the nitrogen oxides (NOx) and carbon monoxide (CO) emission limits represented in Attachment B." Attachment B includes annual NOx lb/mmBtu limits for only four (4) of the covered heaters; DHT Heaters 51H-1 and 52H-2, Condensate Splitter Heater H-1, and Unibon Heater 13H-1 4. Heaters and Boilers excess emissions reporting errors: TotalEnergies is required to limit NOx emissions from the covered Heaters and Boilers as listed in Appendix A of the consent decree such that, the refinery-wide weighted-average NOx emission is no greater than 0.040 lbs.-NOx/mmBtu. TotalEnergies took NOx limits for each of the covered Heaters and Boilers to achieve the refinery-wide weighted average of 0.040 lb/mmBtu as shown in TotalEnergies' 2023 updated list of covered Heaters and Boilers under the consent decree NOx reduction plan. TotalEnergies submitted semi-annual excess emissions and CEMS downtime reports for 2018 - 2024. Some of the excess emissions reported were based on a 0.08 lb/mmBtu hourly limit instead of the limits required under the consent decree. TotalEnergies must review all the reports and resubmit with the actual emission limits as applicable. 5. Hydrocarbon emissions were observed emanating from flares, a sulfur recovery plant tail gas thermal oxidizer, and some LDAR components using forward-looking infrared OGI camera. 6. Increasing flaring incidents: There is a gradual increase in the number of flaring incidents from 2022 to 2024, and TotalEnergies must take appropriate actions to eliminate or reduce flaring incidents. 7. Wrapping an ice bag around a drainpipe to temporarily direct water into a drain is not an acceptable practice. TotalEnergies must take appropriate corrective actions to direct water from the defective pipe into the drain. 8. BWON employee training lapses: EPA Inspection Report - Page 10 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 TotalEnergies is required to develop and implement an annual training for all employees that draw benzene waste samples. Training records show some gaps in employee training. For example, there is no record of a particular employee's training in 2021, but there are records of training in 2020, 2022, 2023, and 2024. Additionally, there is significant variability in the number of employees that had annual training (2018 and 2019-1, 2020-5, 2021-4, 2022-3, 2023-11, and 2024-7). 9. LDAR personnel training lapses: TotalEnergies is required to conduct annual training for all persons assigned LDAR responsibilities as a primary job function, such as monitoring technicians, database users, QA/QC personnel, and the LDAR Coordinator. Training records show some gaps in personnel training. For example, there is no record of a particular employee's training in 2021 and 2022, but there is records of training in 2018, 2019, 2020, 2023, and 2024. Additionally, there is significant variability in the number of employees that had annual training (2018-4, 2019 and 2020-5, 2021-6, 2022-12, 2023-21, and 2024-16). 10. LDAR tag issues: Untagged components, tag on the ground, repair tags still hanging after leak repair is completed, difficult to read tags, and component tagged "unknown" are some of the issues of concern with the LDAR program. Closing Conference EPA Region 6 inspectors Kim Nguyen, Nicolas Studebaker, and I (Prince Nfodzo) conducted a closing conference at TotalEnergies PAR at 10.00 am on May 23, 2025, for the inspection. During the closing conference, I reviewed the Areas of Concern noted during the inspection (AOC #s 1, 3-7, and 10), fielded questions from facility personnel, and provided information about the next steps in the inspection process. Additionally, AOCs #s 2, 8 and 9 were determined after the conclusion of the inspection and were not included in the closing conference. The attendees sign-in sheet for the closing conference is included as Appendix 3. Section IV - FOLLOW UP Some information and documents requested during the inspection were received from May 26-30, 2025. I had a follow-up Teams call on June 12, 2025, with Mr. Sam Breaux [Environmental Superintendent], Ms. Connie Howard [Environmental Engineering Advisor], Mr. Charles Joynor [Sr. Analyzer Specialist] and Mr. Larry Nguyen [On-Stream Analyzer Technician] to discuss how TotalEnergies operates the CEMS trailer. Mr. Joynor explained that the trailer system is equipped with an umbilical cord which connects a gas bottle to a CEMS analyzer and typically conducts analysis on one analyzer at a time, although it can run two analyzers simultaneously if necessary. The system is fully automated and integrated into the Data Acquisition System (DAS), and operators do not manually record any data. EPA Inspection Report - Page 11 of 94 TotalEnergies Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 Section V - LIST OF APPENDICES Appendix 1 - Photo Log Appendix 2 - Video Log Appendix 3 - Opening and Closing Conference Sign-in Sheets Appendix 4 - Plant-wide Process Flow Diagram and Process Description Appendix 5 - FCCU NOx CO, SO2, L/G and P Trends Appendix 6 - Heaters and Boilers NOx Control Plan Appendix 7 - Heaters and Boilers NOx Trends Appendix 8 - Refinery Fuel Gas H2S Trends Appendix 9 - Sulfur Recovery Plants SO2 Emission Trends Appendix 10 - BWON end-of-line Sampling Plan and Process Flow Diagram Appendix CBI - (None) EPA Inspection Report - Page 12 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendices EPA Inspection Report - Page 13 of 94 Total Petrochemicals and Refining USA, Inc./Port Arthur Refinery 5/19/2025 to 05/23/2025 Appendix 1 Photograph Log Note: Wrong year on date stamp, should be 2025 instead of 2021 EPA Inspection Report - Page 14 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 1 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1057.JPG Date of Photo: 05/20/25 Time of Photo: 10:04 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: FCCU CEMS (Outlet). NO = 26.67 ppm SO2 = 6.9 ppm EPA Inspection Report - Page 15 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 2 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1058.JPG Date of Photo: 05/20/25 Time of Photo: 10:09 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: FCCU CEMS (Inlet). EPA Inspection Report - Page 16 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 3 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1059.JPG Date of Photo: 05/20/25 Time of Photo: 10:43 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Mobile CGA Calibration Trailer. EPA Inspection Report - Page 17 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 4 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1060.JPG Date of Photo: 05/20/25 Time of Photo: 10:45 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Calibration gas cylinders in Mobile CGA Calibration Trailer. EPA Inspection Report - Page 18 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 5 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1061.JPG Date of Photo: 05/20/25 Time of Photo: 11:47 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Boiler's H-350 and H-300 CEMS. (Shared stack) EPA Inspection Report - Page 19 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 6 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1062.JPG Date of Photo: 05/20/25 Time of Photo: 11:50 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Boiler's H-350 and H-300 CEMS recording system. (Shared stack) EPA Inspection Report - Page 20 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 7 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1063.JPG Date of Photo: 05/21/25 Time of Photo: 08:54 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Environmental Leak Tag (Tag # 184924T) at H-202B's area. EPA Inspection Report - Page 21 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 8 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1064.JPG Date of Photo: 05/21/25 Time of Photo: 09:18 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Crude Heater 202B CEMS. NOx = 31.14 ppm CO = 0.100 ppm EPA Inspection Report - Page 22 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 9 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1065.JPG Date of Photo: 05/21/25 Time of Photo: 09:29 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Environmental Leak Tag (tag # 0092.07) at H-101. EPA Inspection Report - Page 23 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 10 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1066.JPG Date of Photo: 05/21/25 Time of Photo: 10:04 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Calibration Gas at H-201 CEMS. EPA Inspection Report - Page 24 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 11 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1067.JPG Date of Photo: 05/21/25 Time of Photo: 01:47 PM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: SRU 4 CEMS. SO2 = 101 ppm (0-500) SO2 = 109 ppm (0-20000) O2 = 4.06 % NO = 28 ppm CO = 21 ppm EPA Inspection Report - Page 25 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 12 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1068.JPG Date of Photo: 05/21/25 Time of Photo: 03:42 PM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: SRU 1 and 3 CEMS (Shared Stack). EPA Inspection Report - Page 26 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 13 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1069.JPG Date of Photo: 05/22/25 Time of Photo: 10:10 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: "UNKNOWN" White Tag at Flare Gas Recovery Unit 2. EPA Inspection Report - Page 27 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 14 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1070.JPG Date of Photo: 05/22/25 Time of Photo: 10:51 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: "BWON VISUAL INSPECTION FAIL" flagged on top of Tag DR40PS78. EPA Inspection Report - Page 28 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 15 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1071.JPG Date of Photo: 05/22/25 Time of Photo: 11:28 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Ice bag covering a drain at Tag 4PS117. EPA Inspection Report - Page 29 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 16 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1072.JPG Date of Photo: 05/22/25 Time of Photo: 03:11 PM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: Out-of-service pump at Water Treatment Plant area. EPA Inspection Report - Page 30 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 17 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1073.JPG Date of Photo: 05/22/25 Time of Photo: 03:14 PM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: LDAR Technician flagged missing component with white tag for tag MT1110200. EPA Inspection Report - Page 31 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 18 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1074.JPG Date of Photo: 05/23/25 Time of Photo: 08:30 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: BWON Sampling Plan. EPA Inspection Report - Page 32 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Photograph Log Photo No. 19 Location: Total Petrochemicals and Refining USA Inc., Port Arthur Refinery City: Port Arthur County/Parish: Jefferson State: Texas Photo File Name: DSCN1075.JPG Date of Photo: 05/23/25 Time of Photo: 08:30 AM Photographer: Prince Nfodzo Site Name: Port Arthur Refinery Description: BWON Sampling's Chain of Custody. EPA Inspection Report - Page 33 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery Inspection Dates 05/19/2025 - 05/23/2025 Appendix 2 Video Log EPA Inspection Report - Page 34 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Video Log Appendix 2 Location: TotalEnergies Port Arthur Refinery City: Port Arthur County: Jefferson State: Texas Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0288 05/20/2025 09:34 Nicolas Studebaker North Flare - Pilot light lit, view of trailing emissions from operational flare. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0289 05/21/2025 08:43 Nicolas Studebaker Video cut short. Not referred to in the associated inpsection report. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0290 05/21/2025 08:45 Nicolas Studebaker H202B - View of emissions from a valve located on the pilot gas line. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0291 05/21/2025 09:32 Nicolas Studebaker H201 - View of emissions from the burner 16 pilot gas line union. Page 1 of 4 EPA Inspection Report - Page 35 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Video Log Appendix 2 Location: TotalEnergies Port Arthur Refinery City: Port Arthur County: Jefferson State: Texas Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0292 05/21/2025 09:44 Nicolas Studebaker H201 - View of emissions from the burner 5 pilot gas line union. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0293 05/21/2025 09:50 Nicolas Studebaker H301 - View of emissions from the burner 2 refinery fuel gas hose. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0294 05/21/2025 09:59 Nicolas Studebaker H301 - View of emissions from a plug on the pilot gas supply line. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0295 05/21/2025 12:59 Nicolas Studebaker Reformer - View of emissions from a pipe valve from 17V-19. Page 2 of 4 EPA Inspection Report - Page 36 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Video Log Appendix 2 Location: TotalEnergies Port Arthur Refinery City: Port Arthur County: Jefferson State: Texas Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0296 05/21/2025 14:09 Nicolas Studebaker South Flare - Pilot light lit, view of trailing emissions from operational flare. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0297 05/21/2025 14:16 Nicolas Studebaker East Flare - Pilot light lit, view of trailing emissions from operational flare. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0298 05/21/2025 14:44 Nicolas Studebaker H1 - View of emissions from burner C pilot line 5. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0299 05/21/2025 14:49 Nicolas Studebaker H1 - View of emissions from burner H pilot line 3. Page 3 of 4 EPA Inspection Report - Page 37 of 94 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Video Log Location: TotalEnergies Port Arthur Refinery City: Port Arthur County: Jefferson State: Texas Appendix 2 Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0300 05/22/2025 10:15 Nicolas Studebaker Video cut short. Not referred to in the associated inpsection report. Video File Name: Date of Video: Time of Video: Videographer: Description: FLIR0301 05/22/2025 2:51 pm Nicolas Studebaker TTO5 - Pilot light lit, view of trailing emissions from operational thermal oxidizer. Page 4 of 4 EPA Inspection Report - Page 38 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 3 Opening and Closing Conference Sign-in Sheets = -------'4= ,- (I 0. (1 .- - N N fcl I ; ( ,' c_ '- -----. i . -- __ = = - =N('1 9- o a) 0) C) = C) =3 =3 t- t- .- .- N N .- - I - - . ., - - - .. ,- .. ' -- '- I J.. . -- .. 1--. -: -,. ' - c E C) .- C) -' C- ' _) - c__k - z bO '- __ - - - -' i .- r . - I) ':.; - - -. - S . (^ .$ \J -o I C) ' . - - :4 .E z C) C) 0 C) .2 C) 1- . d ' - -4-. C) C) ,- _- ct) 4_ j c-' -( . -' 4-. C) C) =3 =E 0 t- C.) . . - C) . .. __'\ \ '-' rf -.. 'T - C) '. - - i c-y- =3 C) 0 =3 C) C-) bO '0 --4-. N C) 0 C) C) C) =3 L0) 0 =3 C) Z . E __ _ EPA Inspection Report - Page 39 of 94 r 3 LI tr >0 ?J -3 -'.i- d 9) i?III I'; L .3 'I c) ) ( 0 t 4 EPA Inspection Report - Page 40 of 94 -. F 1;H1 I rr 'I H i4 - - -: -- - : :t L 'V.- -' 'I.'I I __ . 'Th :c -- ?..1c3 EPA Inspection Report - Page 41 of 94 r - I. ., ' .-1 - ) ' . I f- -J \._i 'I - - -. -. '-i 1 ii - 1 -zE. -C '- '- (1 -: }- ; : - EPA Inspection Report - Page 42 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 4 Plant-wide Process Flow Diagram and Process Description EPA Inspection Report - Page 43 of 94 Process Description The refinery manufactures transportation fuels: gasoline, diesel, jet fuel, propane, butane, and bunker oil. The refinery also makes asphalt and recovers benzene, toluene, and xylene - the basic building blocks for plastics - from its fuel products. The refinery is a high conversion facility. The process units at the site, described as follows, are: Process Waste Water Treating Complex (PWTC), Cogen/ Steam Boilers, LPG Loading Rack, Truck Loading Rack, OM&S, Marine Docks and Vapor Recovery Unit, Pressure Swing Adsorption Unit (PSA), Coker Naphtha Hydrotreater Unit (KNHT), Amine Regeneration Unit (ARU-2), Distillate Hydrotreater No. 3 (DHT-3), Delayed Coker Unit (DCU), Condensate Splitter, Fluidized Catalytic Cracking Unit (FCCU), Alkylation, DEMEX, UNIBON, Sulfur Recovery Units #1, #3, #4, and #5 (SRUs 1, 3, 4, and 5), Sour Water Strippers #1, #2,#3 and #4 (SWS-1, 2, 3 and 4), Distillate Hydrotreater # 2, Gas Rerun Unit (GRU), Distillate Hydrotreater #1 (DHT-1), Gas Rerun Unit (GRU), and Toluene Disproportionation (TDP). Atmospheric Crude #1 (ACU1) and Atmospheric Crude #2 (ACU2) The Atmospheric Crude Units 1 and 2 are used to process crude oil into its various components, which are then sent to other units throughout the refinery for further processing. The heavy residuals from ACU-1 and ACU-2 go to the Vacuum Tower prior to being pumped to other units. The crude is pumped from tankage by crude charge pumps, is preheated, and is sent to the desalter. The crude mixture is desalted by passing through a high-voltage field; it goes through this process twice. The crude oil is then heated via a series of heat exchangers and heaters, and is directed to the Crude Fractionator. The heated crude is introduced into the flash zone of the fractionation tower, where liquid and vapor separation takes place. The crude oil components produced through this process are heavy naphtha, jet fuel, furnace oil, atmospheric gas oil and atmospheric residuals are routed to numerous units. Waste gases generated are routed to the Fuel Gas recovery system and/or the Refinery Flare System. Vacuum Distillation Units (VDU1 and VDU2) VDU1 and VDU2 take a combination of reduced crude from the bottom of the Atmospheric Crude Units (ACU1 & ACU2) and purchased atmospheric residuals. The combined feed is pumped and heated in the Vacuum Charge Heater (where it is partially vaporized). The partially vaporized residual leaves the heater and enters the flash zone, where again, vapor-liquid separation occurs. Light hydrocarbon vapors vent from the top and are burned. LVGO (light vacuum gas oil) is drawn off and is pumped to the Unibon Unit. HVGO (heavy vacuum gas oil) is drawn off and is recycled to the Vacuum Tower, pumped to the Unibon, or pumped to the FCCU. Residual liquid from the flash zone is directed, in part, to the Demex Unit and, in part, to #6 fuel oil blending. Distillation under vacuum in VDU 2 will produce the following fractions: vacuum tower bottoms (residue), heavy vacuum gas oil (HVGO), light vacuum gas oil (LVGO), and untreated fuel gas. Vacuum tower bottoms will be further processed into higher value products in the Coker Unit; whereas the light and heavy vacuum gas oils will be hydrotreated and/or processed in the FCCU. Waste gases generated are routed to the Fuel Gas Recovery system and/or the Refinery Flare System. Naphtha Hydrotreater (NHT) The Naphtha Hydrotreater removes poisons from the naphtha feeding the Reformer by means of catalytic and fractionation sections. The feed to the NHT comes from the Crude Unit to the Sat Gas Unit where the C-5 pentanes and lighter are removed in the Naphtha Stabilizer before going to the EPA Inspection Report - Page 44 of 94 NHT. The NHT is a catalytic process using a select catalyst in the presence of hydrogen to convert and remove organic sulfur, oxygen, nitrogen, and metallic compounds which will poison the Continuous Catalytic Reformer catalyst. The NHT also contains a fractionation tower to remove pentanes and lighter from the naphtha prior to being fed to the Continuous Catalytic Reformer. The NHT product is sweet (desulfurized) Naphtha which is fed to the Continuous Catalytic Reformer unit. Continuous Catalytic Reformer The Continuous Catalyst Regeneration (CCR) Reformer converts low octane naphtha to a high octane gasoline blending component. The CCR Reformer feed is sweet (desulfurized) naphtha from the NHT. The CCR Reforming process consists of two steps: reforming and fractionation. The reforming step uses a high temperature, catalytic process in which low-octane naphtha is converted to a high-octane gasoline for blending or processing in the Sulfolane and BTX units. Hydrogen is a major by-product of the reaction and is sent to numerous refinery units (e.g., NHT, Unibon unit, TDP, Total Isomerization Unit). The fractionating step separates the reacted products into overhead vapor, overhead liquid, and a heavy reformate product. The liquid overhead stream is fed to the Saturate Liquid unit for stabilization and is then sent to Total Isomerization as feed. Light distillate from the unit is also used as a gasoline blending component. The waste gasses from the process vents are routed to the Fuel Gas Recovery System and or the Refinery Flare System. Sulfolane Unit The Sulfolane unit separate high purity aromatic fractions from hydrocarbon streams containing both aromatics and non-aromatics. The feedstocks are the drag from the BTX unit and the Light Reformate stream from the Continuous Catalytic Reformer unit. The name Sulfolane refers to the chemical name of the solvent used in the process. The Sulfolane process utilizes a "Sulfolane" solvent in extraction, extractive distillation, and distillation operations in the unit to recover high purity benzene, toluene, and mixed xylenes. The non-aromatic product streams (Raffinate) are sent to the Raffinate Splitter and the aromatic extract stream is sent to the BTX unit. The waste gasses from the process vents are routed to the Fuel Gas Recovery System. Total Isomerization The ISOM Unit converts normal paraffins contained in the pentane/hexane feedstock into higher octane branched isomers. The primary feedstocks to the ISOM unit are the Light Raffinate stream from the Raffinate Splitter in the Sulfolane unit and the Pentane stream from the Debutanizer Tower which is a part of the Saturate Liquids Unit. The isomerization process is a steady state operation that converts normal to isomers in the presence of hydrogen via the utilization of a catalyst. The adsorption process is an unsteady state system that separates normal hydrocarbons from nonnormals by adsorbing the normals into the cavities of the adsorbent. The normals are desorbed by stripping with hydrogen. The integration consists of placing the adsorption process in the hydrogen circulation loop ahead of the isomerization reactor. Conventional equipment is used to move, heat, cool and separate the process streams. The product stream from the Isom unit is Isomerate which is sent to tankage and used in gasoline blending. The waste gasses from the process vents are routed to the Fuel Gas Recovery System and or to the Flare System. Saturate Liquids The Saturate Liquids takes the light ends from other units and separate out the components of naphtha, pentane/hexane, mixed butanes, propane, and fuel gas. Feed to the naphtha stabilizer is unstabilized, light naphtha from both atmospheric crude units. The naphtha stabilizer overhead liquid EPA Inspection Report - Page 45 of 94 is amine treated (for H2S removal), and then caustic treated (for mercaptan removal) before going to the deethanizer. NHT Fractionator overhead liquid is amine treated (for H2S removal) then sent to the debutanizer. The overhead from the debutanizer combines with the stabilizer overhead and goes to the deethanizer. Deethanizer bottoms provide the feed for the depropanizer. Deethanizer vapor product goes either to the Cogen unit or to the Fuel Gas Recovery System. Depropanizer bottoms product is mixed butanes. The overhead propane product is sent to the KOH treaters to remove traces of water and H2S and then goes to tank storage. Benzene/Toluene/Xylene (BTX) The BTX unit separates the mixed BTX (benzene, toluene, xylene) streams into benzene, toluene, xylene, and C9+ aromatics. Feed to the BTX unit is clay-treated, aromatic extract from the Sulfolane unit and BTX from the TDP unit. A distillation process is used to separate BTX into benzene, toluene,and mixed xylenes, which are sent to storage tanks and ultimately sold as product or used for gasoline blending. The waste gasses from the process vents in the BTX unit are routed to the Fuel Gas Recovery System. Toluene Disproportionation (TDP) The TDP unit converts toluene into the more valuable products benzene and xylenes. Toluene feed enters the unit directly from the toluene tower of the BTX unit. If necessary, it can also be pumped in from tank storage. The toluene is mixed with recycle hydrogen and heated in exchangers and in the TDP charge heater. It enters the reactor where in the presence of catalyst, one-half of the toluene is converted to benzene, mixed xylenes, toluene, and C9+ aromatics, and non-aromatics. The product stream goes on to a high pressure separator section where the vapor portion, which is mainly hydrogen, is routed to the compressor after being mixed with makeup hydrogen from the reformer. The liquid stream which is mainly toluene, benzene, and mixed xylenes, goes on to a stabilization section. This section runs the stream through a tower to remove C3's (Depropanizer Tower) and lighter compounds. The vapor stream from the stabilizer section is added to the refinery fuel gas, or sent to the unit heater to be used as fuel. The liquid product stream is used as feed to the BTX unit, where it is separated into benzene, toluene, xylene, and C9+ aromatics. The benzene and xylene are sold as products. The C9+ aromatics are used in the gasoline blending pool. The toluene is recycled back to the TDP feed. The waste gasses from the process vents are routed to the Fuel Gas Recovery System and or the Refinery Flare System. Gas Rerun Unit (GRU) The Gasoline Rerun Unit (GRU) produces TOTAL Aromatic Solvent 150, FAS-150, Atosol or a finished furnace oil (FFO). The GRU is designed to take a feed, usually the xylene column bottoms but can also process the reformer's heavy reformate, and distill it to produce the desired products. The mode of operation governs which product is made. FAS-150 is collected as bottoms product and sent to tankage, to finished furnace oil, or to gasoline blending. It can also be sent to the front of the unit as charge. Atosol is collected as an overhead product and can be sent to tankage or to gasoline blending. Distillate Hydrotreater #1 (DHT-1) The Distillate Hydrotreater #1 (DHT-1) removes sulfur compounds from the unfinished middle distillates (jet fuel and furnace oil). The unit feed is composed of straight run kerosene from the Atmospheric Crude Units and the Condensate Splitter. The sulfur in the feed is converted into EPA Inspection Report - Page 46 of 94 hydrogen sulfide in the presence of catalyst so that it can be removed from the gas stream more easily. The unit produces jet fuel or kerosene. The final jet product is then sent to tank storage. The waste gasses from the process vents are routed to the Fuel Gas Recovery System and or the Refinery Flare System. Distillate Hydrotreater # 2 DHT-2 produces low sulfur diesel as a finished product. The unit processes atmospheric gas oil, AGO, from both atmospheric crude units, and light vacuum gas oil, LVGO, from the two vacuum distillation units (VDU1 and VDU2). After the feed is preheated, it is sent to the reactor where sulfur and nitrogen compounds in the feed are reacted with hydrogen to form hydrogen sulfide and ammonia. After cooling and liquid separation, the gas stream enters the amine section where the hydrogen sulfide is removed and sent to the sulfur recovery unit (SRU). The liquid from the hot high pressure separator then enters the fractionation section. The fractionation section separates the products of the reaction section. It produces hydrotreated gas oil, naphtha, and a middle distillate. Sour Water Strippers #1, #2, #3 and #4 (SWS-1, 2, 3 and 4) The sour water strippers remove dissolved hydrogen sulfide and ammonia from process waste water streams of refinery process units, including: DHT-1, DHT-2, DHT-3, UNIBON, DEMEX, Amine, SCOT, NHT, KNHT,ACU-1, ACU-2, VDU1, VDU2 and the flare area. The waste water streams are fed into a surge drum from their various sources. This step helps to remove entrained liquid hydrocarbons and dissolved gases due to the change in pressure. This water is then sent to one of the available tanks (Tanks 1000, 1001, and 1002) to settle and to prevent fluctuations in feed from upsetting the unit. Hydrocarbons that settle on the top are manually skimmed and sent to the refinery slop oil. The sour water is then preheated through heat exchange with the reboiler and sent to the top of the tower. Steam is injected into the bottom of the tower and draws the ammonia and hydrogen sulfide into that stream. The wet over head vapor rich in hydrogen sulfide and ammonia is sent to the sulfur recovery units (SRUs). The stripped water is either sent to the crude units to be used as desalting water, or to refinery process units to be injected as wash water. It may also be sent to PWTC to be treated and discharged. Sulfur Recovery Units #1, #3, #4, and #5 (SRUs 1, 3, 4, and 5) The Sulfur Recovery Units recover the sulfur content from the incoming refinery amine system acid gas streams and/or sour gas from the SWSs as elemental sulfur by using state of the art Claus SRUs followed by tail gas treatment to maximize sulfur recovery. Acid gas (composed primarily H2S and ammonia) will be fed to the trains from the Amine Regeneration Unit-1&2, Unibon, DHT-1&2, and SWS(s). The combined acid gas stream will be fed to the reaction furnace along with a limited amount of air. Inside the reaction furnace, the mixture of acid gas and air will be heated sufficiently to oxidize a portion of the H2S into elemental sulfur and SO2. Reaction conditions will be controlled to achieve optimum H2S to SO2 ratios. The thermal reactor will also destroy ammonia in the acid gas feed. The gas exiting the thermal reactor and catalytic converters passes through a condenser to recover elemental sulfur. The SRU exhaust will consist primarily of H2S, sulfur vapor, SO2, water and nitrogen and is routed to the Tail Gas Unit (TGU). The TGU system will convert sulfur compounds in the tailgas into H2S, and will selectively remove H2S from the converted gas and route the treated gas to a Tail Gas Incinerator (TGI) or Tailgas Thermal Oxidizer (TTO). The H2S removed in the TGU system will be recycled to the front-end of the SRUs for further conversion into sulfur. Effluent gases from the TGU Amine Contactor will be combined with SRU complex storage pit/truck loading sweep gases and flow to the new incinerator where natural gas and combustion air will be added to a burner to convert any remaining sulfur compounds to SO2. EPA Inspection Report - Page 47 of 94 Unibon Unit The Unibon unit (called a hydrotreater) reduces the concentration of impurities (sulfur, nitrogen, metals, carbon) from a portion of the charge to the FCCU. The feed to the Unibon reactors is composed of: HVGO, DMO, resin, and hydrogen. Impurities in the charge to the Unibon are converted to hydrogen sulfide (H2S) and ammonia (NH3) and separated from the liquid phase. Some of the impurities remain in the product. H2S and NH3 are sent to the Sulfur Recovery Unit (SRU) and Sour Water Stripper (SWS) for further processing. Metals in the feed are retained on the catalyst. The liquid phase is sent to a fractionation section where it is split into various products, unibon product to FCCU, diesel, naphtha. Demex Unit The Demex removes a valuable gasoil product from vacuum tower bottoms (VTB) from other products used for heavy oil blending. The unit feed is VTBs from the Atmospheric Crude Units. The Demex unit utilizes a solvent deasphalting process that utilizes liquid-liquid extraction. The Demex unit is a solvent deasphalting process that utilizes liquid-liquid extraction and supercritical butane or isopentane solvent to extract two streams called demetalized oil (DMO) and resin from heavier asphaltenes. After extraction and separation, residual solvent is removed from the DMO, resin and asphaltene streams in individual stripping columns. DMO and resin are then sent to the Unibon unit, though resin may also be used for road asphalt blending. Asphaltenes are sent to road asphalt blending or 6 Oil. Waste gases generated are routed to the Fuel Gas Recovery System and/or the Refinery Flare System. Alkylation Unit The Alkylation (Alky) unit produces a high octane alkylate which boils in the aviation gasoline range by the chemical reaction of olefin hydrocarbons (usually normal and isobutylene) with isoparaffin (isobutane) in the presence of sulfuric acid catalyst. This conversion of C4 olefins with isobutene into highly branched isoparrafins results in the formation of alkylate. The C4 olefin feedstock comes from the Fluid Catalytic Cracking Unit (FCCU) and the isobutene feed comes from the Saturated Liquids Unit. The alkylate product is sent to tankage and used in gasoline blending. The spent acid is shipped offsite, the liquid waste is sent to the Wastewater Treatment Unit and the waste gasses are sent to the Fuel Gas Recovery System and/or the refinery flare system. Fluidized Catalytic Cracking Unit (FCCU) The FCCU cracks heavy hydrocarbons in gas oils into smaller molecular hydrocarbons, which are processed into more profitable products. The feed to the FCC consists of gas oil, usually coming from tankage and other units within the refinery such as the Unibon and Crude Units. Gas oil enters the reactor riser through feed distribution nozzles. These nozzles help vaporize the feed for better contacting with the fluidized catalyst. The oil and catalyst react as they travel up the riser. The catalyst then travels down through the reactor stripper and to the regenerator. At the regenerator, coke deposits on the catalyst are burned and then the catalyst returns to the reactor. The products from the burning of the coke (flue gas) are sent to the wet gas scrubber to remove SO2 and particulate matter. The reaction products disengage from the catalyst at the top of the reactor and go to the main column. The fractionator separates the products into slurry, Heavy Cycle Oil, Light Cycle Oil, Heavy Cat Naphtha, and Light Cat Naphtha and lighter. The LCN stream is amine and HCN streams are each treated for sulfur in the GHT before they are sent to storage. The LPG stream is EPA Inspection Report - Page 48 of 94 amine and Merox treated to remove sulfur and then separated into propane/propylene and butane/butylene streams and sent to storage. The fuel gas is then sent to the Offgas Treater to remove contaminants before being sent to the steam cracker. Waste gases generated are routed to the Fuel Gas Recovery System and/or the Refinery Flare System. Condensate Splitter The Condensate Splitter Process is designed to separate Sleipner or Oso light crude condensates producing jet fuel, diesel, gas oil, heavy naphtha, and light naphtha. The condensates are fed to the feed surge drum from storage tanks. The separation process is achieved through a fractionating column and the naphtha splitter column. Heavy naphtha is used as NHT reformer feed, and the light naphtha is sent to the steam cracker as feed. The jet and diesel is sent directly to tank storage. Gas oil is sent to FCCU for feed. Delayed Coker Unit (DCU) The Delayed Coker Unit (DCU) will primarily process vacuum residue and PITCH/ Resin to produce LPGs, unfinished transportation fuels (Coker Naphtha, Light Coker Gas Oil, Heavy Coker Gas Oil), fuel coke, and untreated fuel gas. Feed is supplied to Delayed Coker unit from Vacuum Tower, VDU2, DEMEX unit and Storage. Feed is typically composed of C34+ hydrocarbons containing contaminants such as water, sulfur, nitrogen, and oxygen compounds, as well as trace amounts of heavy metals (nickel, vanadium, lead, iron, etc). The Coker uses a delayed coking process whereby heavy hydrocarbons (resid) are quickly brought to thermal cracking temperature in the heaters. The DCU feed stream is introduced into the bottom of the fractionators where it is heated, in the presence of velocity steam, in the Coker heaters to facilitate oil thermal cracking and to further the delayed coking process in the Coker drum(s). Coker Heaters are provided with ultra low NOx burners and selective catalyst reduction (SCR) for further NOx control. Once coking cycle is complete, steam will be used to strip the volatile hydrocarbon vapors from the coke. The overhead vapor is sent first to Fractionator and switched to the blowdown system while the coke remains in the drum. Following steam stripping the coke is cooled with water. After the coke in the drum is cooled, the coke will be removed by hydraulic cutting, stored in the coke pad, and then sent to coke pile, where it will be processed for transferring off-site via barge or ship. The C3 product is normally blended off into FCC C3 product, BB product is routed to storage on flow control, Coker naphtha product is normally routed to the KNHT, LKGO Product is cooled for its disposition to storage, to be used as feed to DHT-3 unit, and HKGO product is normally routed to UNIBON unit. Waste gasses are sent to the Fuel Gas Recovery System and/or the refinery flare system. Heater flue gases are routed to the SCR reactor where they are contacted with vaporized ammonia. The flue gases and gaseous ammonia contact a selective catalyst to reduce nitrogen oxides to diatomic (two atom) nitrogen (N2) and water. Distillate Hydrotreater No. 3 (DHT-3) The DHT-3 will remove sulfur entrained in distillate to produce ultra low sulfur diesel (ULSD). DHT-3 will receive feed from Crude Unit, FCCU, Coker , DHT-2 and Unibon. DHT-3 feed with recycle hydrogen will be preheated by heat exchangers and then brought to reaction temperature utilizing a feed charge heater (source of emission) before entering the inlet of the reactor. The hydrotreater reactions are exothermic and will cause a temperature rise in the reactants; water is injected into the reactor effluent upstream of the product separator to minimize corrosion, minimize deposits of ammonium salts, and to remove ammonia. The hydrogen is separated from diesel in the separator and recycled using back to the front of the unit after amine scrubbing. Some hydrogen may be purged to improve the recycle hydrogen purity. The separator off-gas, high in hydrogen, will be sent to PSA unit for hydrogen recovery. The recycle hydrogen is treated with lean amine to remove H2S. The rich EPA Inspection Report - Page 49 of 94 amine will be routed to the new Amine Regenerator Unit. The liquid stream from the separator will be routed to a stripper where naphtha, fuel gas, and treated distillate are fractionated prior to unit discharge. The treated distillate will be vacuum dried and cooled before sending it to storage. The sour water recovered from the stripper overhead receiver will be either used in reactor effluent washing or processed in the refinery sour water system. Amine Regeneration Unit (ARU-2) Amine is circulated within the refinery scrubbers to treat fuel gas and LPG streams by absorbing H2S. The purpose of the amine regeneration unit is to continuously regenerate the amine by removing absorbed H2S in a stripper tower. Rich amine, laden with H2S produced in the various refinery process units, is collected in a common system and fed to the amine regeneration unit. After stripping, lean amine is pumped from the regeneration unit back to the refinery process units. Coker Naphtha Hydrotreater Unit (KNHT) The feed for KNHT will come from Coker. The KNHT will remove sulfur entrained in unfinished naphtha to produce finished (or low sulfur) naphtha. Then KNHT feed and recycle hydrogen will be preheated by heat exchangers and then brought to reaction temperature utilizing a feed charge heater before entering the inlet of the reactor. The hydrotreater reactions are exothermic and will cause a temperature rise in the reactants; water is injected into the reactor effluent upstream of the product separator to minimize corrosion, minimize deposits of ammonium salts, and to remove ammonia. The hydrogen is separated from diesel in the separator and recycled using back to the front of the unit after amine scrubbing. Some hydrogen may be purged to improve the recycle hydrogen purity. The separator off-gas, high in hydrogen, will be sent to PSA unit for hydrogen recovery. The recycle hydrogen is treated with lean amine to remove H2S. The rich amine will be routed to the new Amine Regenerator Unit. The liquid stream from the separator will be routed to existing NHT for stripping. Pressure Swing Adsorption Unit (PSA) The low purity hydrogen from Reformer, NHT purge, DHT-3 purge, DHT-2 purge and KNHT purge is sent to PSA make high purity hydrogen. The Pressure Swing Adsorption Unit (PSA) is a purification unit. The purifier consists of ten adsorber vessels with adsorbent, one skid containing process valves and piping, and a control unit. The hydrogen purifier uses a pressure swing adsorption process to purify the low purity hydrogen stream and produce a high purity hydrogen product stream. The impurities are adsorbed from the feed gas at the high feed gas pressure and then desorbed at a low pressure. The process operates on a repeated cycle having two basic steps, adsorption and regeneration. During normal operation two vessels are on adsorption and the others are in various stages of regeneration. No change in temperature occurs except for that caused by the heats of adsorption and desorption. The off gas is sent to amine unit using a tail gas compressor. Marine Docks and Vapor Recovery Unit The marine terminal docks are used to unload/load raw materials/products at the refinery. The marine terminal consists of 4 berths where vessels, ships, and barges dock to load or discharge crude oil or refined products. The Docks/Terminal Area consists of the docks (marine terminal) and terminal. Products and crude are transferred between the docks and on-shore tankage over pipelines. The boundaries of the Docks and Dock activities generally extend from the tank discharge valve of all the product shipping (via docks) tanks and crude receiving tanks in the Refinery to the cargo (hose-tovessel) connection. Waste gases generated during the loading of some refinery products are routed EPA Inspection Report - Page 50 of 94 to a marine vapor recovery system and ultimate the marine terminal thermal oxidizers. Waste gases generated during the loading of minimally volatile refinery products vent directly to atmosphere during loading. OM&S The storage and transfer of petroleum products at the Port Arthur TOTAL refinery is the primary responsibility of the Oil Movement and Storage Department. It includes everything that is not included in a unit battery limits: tanks, pumps outside of units, pipelines, and all the supporting equipment. Truck Loading Rack The truck terminal is loads either regular, premium, mid-grade, diesel or FAS-150 solvent. Blended gasoline, Diesel and FAS 150 is blended and tested before being sent to the Fuel Truck Terminal Storage Tanks. From the tankage, these materials are loaded through the rack manually by drivers into trucks. Displaced vapors are controlled by a loading rack flare. LPG Loading Rack The LPG Loading and Storage Area provides storage and pumping facilities for Propane, Butane, Refinery Grade Propylene, Isobutane and Butylene. Pumping facilities are provided to pump propane to pipeline and the Truck Loading Rack. Cogen/ Steam Boilers The Cogen and associated equipment are used in the Refinery to burn natural gas, reformer hydrogen and deethanizer off-gas to power a turbine which generates electrical power that is consumed in the refining process. The by-product of this operation is waste heat in the turbine exhaust which is utilized to generate steam. The unit also produces water suitable for high pressure boiler feedwater (HPBFW) which is used in boilers or generators. Other equipment associated with the Cogen Unit include a raw water clarifier, drinking water section, and cooling tower section. The steam boilers and associated equipment's primary purpose is to produce steam for the Refinery in order to supply process heat and mechanical energy. The control of the unit is based on maintenance of the pressure in the steam system. This includes backup of the waste heat generators in the Refinery in case they shutdown (i.e. Cogen, Cat Cracker). The boilerhouse also pumps and treats water for utility purposes, low pressure boiler feedwater (LPBFW), and water suitable for demineralization. The boilerhouse pumps raw water from the LNVA canal to the process area in order to remove contaminates to provide water for cooling tower makeup, Low Pressure Boiler Feedwater, and Demineralizer feed. Process Wastewater Treating Complex (PWTC) The process waste water treating complex (PWTC) provides a means to treat the refinery's generated waste waters so that they may be safely discharged back into the environment. The PWTC receives feed the refinery's process water and storm water sewer systems. Treatment of the water is accomplished by mechanical, chemical and biological processes/separation that occurs in the NESHAP Pretreatment Unit, Biological Pretreatment Unit, Biological Treatment Unit, Solids/Liquids Separation System, Recovered Oil System, North Oily Water System, and the South Storm System . EPA Inspection Report - Page 51 of 94 EPA Inspection Report - Page 52 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 5 FCCU NOx CO, SO2, L/G Ratio, and P Trends EPA Inspection Report - Page5533ooff9944 600.00 FCCU CO Emission Trends 500.00 400.00 300.00 200.00 100.00 0.00 5/1/2024 6/1/2024 7/1/2024 8/1/2024 9/1/2024 10/1/2024 CO ppm 1 hour average CO ppm 1 hour average limit 11/1/2024 12/1/2024 1/1/2025 CO ppm 365 day average 2/1/2025 3/1/2025 4/1/2025 CO ppm 365 day average limit EPA Inspection Report - Page5544ooff9944 70.00 FCCU NOx Emission Trends 60.00 50.00 40.00 30.00 20.00 10.00 0.00 05/01/24 06/01/24 07/01/24 08/01/24 09/01/24 10/01/24 NOx ppm 7 day average NOx ppm 7 day average limit 11/01/24 12/01/24 01/01/25 NOx ppm 365 day average 02/01/25 03/01/25 04/01/25 NOx ppm 365 day average limit EPA Inspection Report - Page5555ooff9944 FCCU Pressure Drop and Liquid to Gas Ratio Trends 150.00 130.00 110.00 90.00 70.00 50.00 30.00 10.00 05/01/24 -10.00 06/01/24 07/01/24 08/01/24 09/01/24 10/01/24 11/01/24 12/01/24 01/01/25 Min PD 3 hour average Min PD 3 hour average limit Min LG Ratio 3 hour average 02/01/25 03/01/25 04/01/25 Min LG Ratio 3 hour limit EPA Inspection Report - Page5566ooff9944 FCCU SO2 Emissions Trends 140.00 120.00 100.00 80.00 60.00 40.00 20.00 0.00 05/01/24 06/01/24 07/01/24 08/01/24 SO2 ppm 7 Day Average 09/01/24 10/01/24 SO2 7 Day limit - 50 ppm 11/01/24 12/01/24 01/01/25 SO2 ppm 365 Day Rolling 02/01/25 03/01/25 04/01/25 SO2 365 Day 50 ppm limit EPA Inspection Report - Page 57 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 6 Heaters and Boilers NOx Control Plan EPA Inspection Report - Page 58 of 94 EPA Inspection Report - Page 59 of 94 EPA Inspection Report - Page 60 of 94 TotalEnergies Petr ochem itaJs & Rdining USA, Inc. Port Arth ur Refinery APPENDIX A Initial Inventory of Covered Ileatcr.s And Boil ers Annual Update for Calcnd:-tr Year 2023-Submitled i\fa rch 28, 2024 Unit No. 1 Crude Souru Typ, Emission Point Numbtr (EPN) Ducriptlon Currtnt NOx. Umlt OblMMDtu) CEM Equipptd and OptrationaJ IlotquO,uiy "t,Ulo>b) Sourte forllul Input C1patity Healer OIACU III IOI ACUI C~vge, HIOI 0.040 y 145.00 rrcEQ Table 6 - Healers and Boilers (Submined \\ith Pennit Package) No. 2 Crude Huter OlACU2H201 ACU-2 Ckugc, H-2011 0.030 No. I Crude Heater OIACUl202A ACUI Ch.lrge, H-202A 0.060 No. I Crude Heater OIACUl202B ACU-1Charse, H-2028 0.060 V2cuwn Distilbtion Unit I Heater 01 VACTilJOI VDU-I Chlrge,. H-3012 0.030 D<me., Healer l ODEMEXIJ.2 DEMEX Aspb.111, 3H2 0.035 Jxmcx Uru'bon Heater IODEMEXH4 Heater 13UNT8H301 DEMEX DMO Plu5e, ) H-41 Unibon Chlrge, 13H-1 0.035 0.030 NHTl Healer 17NHTHTRS N1IT 17H-10t2 0.030 NHT I Rcfonncr Heater 17NlffilTRS l\1-ff 17Hl02l Hea!er 17NHTHTRS ReformcrCh.uge 11.2 0.030 0.0)3 Reformer Healer l714llllfTRS Reformer Ch3rge 2 1.2 0.033 Reformer Heater l7NHTIURS Refonncr Clurge) 1.2 0.033 Refonncr He.1ter 17NHTHTRS Reformer Chuge 4 u 0.033 BTX BTX DHT! Heater ~BTXl!53 Heater ~BTX. 1152 Hea!er 5 1DHTllll !x)'leneTrim Heater, 4H- ~) Tolucn:Trim Healer, Ul-52 DHTCNrge,SIHl 0.060 0.060 o.~o y 129.00 trCEQ T.!.blc 6 - Healers and Boilers (Submitted with Pcnnit Package) Attxlvnc,t A- He.ater M.1.'dmum FiringRa:e (Spcci.al Con:iitions - Permit y 187.00 Nwnben 6396, PSDTXI073Ml, a.nd N0-14) Dcctmbcr8, 2014 Attaehmen. A - Hea!erMa\iinum Firiog Rate (S~Lll Corditions - Pcnrut y 187.00 Sumber, 46396, PSDTXI073MI, am N044) Dmmbcr 8, 2014 y 105.00 rrcEQTable6 - Hea1ersard Boilers (Subrruucd \\ilh Pennit Pad:.age) ~ttachrmnl A- Heater M.uimwn Firin& Ra!e (Special Corditions-Permit N 70.00 ~'umber,46396, PSDTX1073MI, am 1"044) P<ccmbcr8, 2014 1A11achmcnt A - Huter ~U.\imum FiringRate (Spcc:ial Coalitions-Permit N 98.00 !Number, 6396, PSDTX1013MI, am 1''04-1) IDtm'oerS,2014 y 100.00 TCEQ Table 6 - Heaters100 Boilers (Subcniucd \\ithPermit P.Kbge) Atladvncrt A - Healtr Ma\imurns firing Rate (Special Conditions - Perm.it N 56.60 'umber, 6396, PSDTX1013MI, am NOU) December 8, 2014 Att.aehmcnt A- Heater Ma.'Cimwnfiriag Rate (Special Corditioru - Pemrlt N 69.00 Nwnber,46396, PSDTX1073M, am h'OU) D<ccmbcr8, 2014 ;A.tticlvncnt A - Heater Ma.UfflwnFiring Rate (Sped.al Corrlitions- Permit y 127.16 !Number, 46396, PSDTXIOJ3MI, am N044) Pcmber 8, 2014 1A11achmcrt A - Healer Maximum Firing Rate (Special Corditions -Pcnnit y 144. 12 Number, 6396, PSDTX1013Ml , arid N044) Pcmbcr8, 2014 ~ttachmenl A - HeaterMa-..:imum FiringRate (Spcdal Corrlitions - Permit y 79.S2 ~'umber, 46396, PSDTX I073Ml , aJ>I 1''()44) II>cc,mbcr 8, 2014 1A11achrncrt A HealerMa:<imum Firing Rate (Special Corditions Penrut y 5 6.2 1 !Number, 46)96, PSDTXIOJ3MI, am N044) Pcmbcr8, 20H Attachment A- HCJter Ma.xi.mumFiring Ralc (Special Cooo.itions -Permit N 6S.OO :umber, 6396, PSDTX1013Ml, aJ>l 1''04-1) Dcmbcr8, 2014 AttaclvncDl A- He.1terMuimwn Firing Rate (Sp,:dal CordiLions - Ptnnit N 63.00 Numbcis46)96, PSDTX l07JM1, m:INOH) Dcmbcr8, 2014 N 46.44 TCEQTabte 6 -Heaters and Boilers (Submitttd ,,ith Pennit Package) DHT2 Hulcr 52DHT2Hl DHT2 Clur&e, 52HI 0.0)5 N 46.45 TCEQ Tab1e6 - Heate rs and Boiltn (Submitted ,,ith Pennit Package) DHTl Heater S2DHT2H-2 DHT-2 Florida, 52H2 0.035 N Condcns.1te Splitter Heater 40CSPLTHI CoMCru:1~ SplitterH-1 0.050 y Utility Boiler 61BLRIBOO Boller H-300., 0.035 y Utility Boiler 618LRH3SO BoUerH-350., 0.035 y , HCJ:erS routed 10 commoostaek CEMSoncommon 51.!Ck.. ,SO:< Conlrols proposed on lu1ers for ~!ting on NSR Pennit (Nh'067) submitted on June 20, 2006, to the EPA/I'CEQ. ToUlEncigies ffll.f use 106 tons or less ofoffstts from NO.'< emissions from these he.aim for the offsets ~uirtd by NSR Permit appUaition 6N067 should a permit betuued unde rtJut app!.kationor \\ideranother application for th: same projecL , Boilers routed to common ~k - CEMS on COmm)R stack. There were no clwlg(s to 1be initial hn'tntory ofCoYettd Hearers and Boilers dwingcalerdar)'ear202). 52.6] 2)0.00 249.00 249.00 TCEQTable 6 -Heaters and Boilers (Submitted \\ith Permit Pacbge) TCEQ Table 6-Hc.atersand Boilcn (Submitted "ith Permit Package) 'Febnwy 3 2012 TCEQ Table 6 Heaten and Boilers (Submitted \\ith Ptnnil Pacb.ge) TCEQTable 6 - Heaters an1 Boilers (Submitted nith Permit P.ckagc) EPA Inspection Report - Page 61 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 7 Heaters and Boilers NOx Trends EPA Inspection Report - Page6622ooff9944 ACU-1 Charge, H-101 0.200 0.180 0.160 0.140 0.120 0.100 0.080 0.060 0.040 0.020 0.000 5/1/2024 5/31/2024 6/30/2024 7/30/2024 8/29/2024 9/28/2024 10/28/2024 11/27/2024 12/27/2024 1/26/2025 H101 NOX/MMBTU 0.04 NOX lb/MMBTU Limit 2/25/2025 3/27/2025 4/26/2025 EPA Inspection Report - Page6633ooff9944 ACU-1 Charge, H-202A 1.600 1.400 1.200 1.000 0.800 0.600 0.400 0.200 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 11/27/24 12/27/24 H202A NOX/MMBTU 0.06 NOX lb/MMBTU Limit 01/26/25 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page6644ooff9944 ACU-1 Charge, H-202B 1.600 1.400 1.200 1.000 0.800 0.600 0.400 0.200 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 11/27/24 12/27/24 H202B NOX/MMBTU 0.06 NOX lb/MMBTU Limit 01/26/25 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page6655ooff9944 ACU-2 Charge, H-201 0.100 0.090 0.080 0.070 0.060 0.050 0.040 0.030 0.020 0.010 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 11/27/24 12/27/24 01/26/25 02/25/25 03/27/25 04/26/25 H201 NOX/MMBTU ACU-2 Charge, H-201 Consent Decree NOX lb/mmbtu Limit EPA Inspection Report - Page6666ooff9944 Boiler H-300/H-350 0.040 0.035 0.030 0.025 0.020 0.015 0.010 0.005 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 Boilers NOx Emission Factor 11/27/24 12/27/24 01/26/25 0.035 NOX lb/MMBTU Limit 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page6677ooff9944 0.700 Condensate Splitter H-1 0.600 0.500 0.400 0.300 0.200 0.100 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 COND SPLITTER H1 NOX/MMBTU 11/27/24 12/27/24 01/26/25 0.05 NOX lb/MMBTU Limit 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page6688ooff9944 0.350 Reformer Charge 1-6 0.300 0.250 0.200 0.150 0.100 0.050 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 REFORMER HTR 1-6 NOX/MMBTU 11/27/24 12/27/24 01/26/25 0.033 NOX lb/MMBTU Limit 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page6699ooff9944 0.200 Unibon Charge, 13H-1 0.160 0.120 0.080 0.040 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 11/27/24 12/27/24 UNIBON NOX/MMBTU 0.03 NOX lb/MMBTU Limit 01/26/25 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page7700ooff9944 0.200 Vacuum Charge, H-301 0.150 0.100 0.050 0.000 05/01/24 05/31/24 06/30/24 07/30/24 08/29/24 09/28/24 10/28/24 11/27/24 12/27/24 H301 NOX/MMBTU 0.03 NOX lb/MMBTU Limit 01/26/25 02/25/25 03/27/25 04/26/25 EPA Inspection Report - Page 71 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 8 Refinery Fuel Gas H2S Trends EPA Inspection Report - Page7722ooff9944 Refinery Fuel Gas H2S Emissions Trend 400.00 350.00 300.00 250.00 200.00 150.00 100.00 50.00 0.00 04/30/24 05/31/24 06/30/24 07/31/24 08/31/24 09/30/24 H2S Analyzer 3Hour Average (PPM) 10/31/24 11/30/24 12/31/24 01/31/25 H2S Analyzer 3Hour Average Limit (PPM) 02/28/25 03/31/25 04/30/25 EPA Inspection Report - Page 73 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 9 Sulfur Recovery Plants SO2 Emission Trends EPA Inspection Report - Page 74 of 94 EPA Inspection Report - Page 75 of 94 EPA Inspection Report - Page 76 of 94 EPA Inspection Report - Page 77 of 94 TotalEnergies Petrochemical and Refining USA, Inc./Port Arthur Refinery 05/19/2025 to 05/23/2025 Appendix 10 BWON end-of-line Sampling Plan and Process Flow Diagram EPA Inspection Report - Page7788ooff9944 Wastewater Collection and Treatment Process Flow Schematic and End-of-Line Sampling Plan Consent Decree Reference Case No. 90-5-2-1-08283/3 TOTAL Petrochemicals USA, Inc Port Arthur Refinery, Port Arthur, Texas Revised June 22, 2011 EPA Inspection Report - Page7799ooff9944 TABLE OF CONTENTS 1 Introduction ...........................................................................................................................................................1-1 2 Overview of the Refinery Process Wastewater Treatment Complex ................................................................2-1 2.1 61.342(c)(1) Controlled Waste Streams.............................................................................................2-1 2.2 61.342(e)(2) Uncontrolled Waste Streams.........................................................................................2-1 2.3 Major Features of the TOTAL PAR Process Wastewater Treatment Complex ..................................2-2 3 Description of End -of-line sampling flow Schematic ........................................................................................3-1 4 End-of-Line Sampling Plan ..................................................................................................................................4-1 4.1 End-of-Line Sampling Locations.........................................................................................................4-1 Point 1 - Tank 905 Sump ......................................................................................................4-2 Point 2 - East-Side of DAF Sump.........................................................................................4-2 Point 3 - Wash Slab Sump ....................................................................................................4-2 Point 4 - PWTC 67T-301 Sump............................................................................................4-2 Point 5 - PWTC 67T-412 Sump............................................................................................4-2 Point 6 - PWTC 67P-414 Lab Sump.....................................................................................4-2 Point 7 - Storm Water Return Pumps Sample Line ..............................................................4-2 Point 8 - Solid Liquids Separation Unit Sump ......................................................................4-2 Point 9 - North CPI Sludge ...................................................................................................4-2 Point 10 - South CPI Sludge .................................................................................................4-2 Point 11 - GHT-1 Manway (temporary sample point)..........................................................4-2 4.2 End-of-Line Benzene Quantity Calculation.........................................................................................4-2 4.3 Detailed Description of EOL Sampling Locations ..............................................................................4-4 4.3.1 Point 1 - Tank 905 Sump ......................................................................................................4-4 4.3.2 Point 2 - East-Side DAF Sump .............................................................................................4-4 4.3.3 Point 3 - Wash Slab Sump ....................................................................................................4-4 4.3.4 Point 4 - PWCT 67T-301 Sump............................................................................................4-4 4.3.5 Point 5 - PWTC 67T-412 Sump............................................................................................4-4 4.3.6 Point 6 - PWTC 67P-414 Lab Sump.....................................................................................4-4 4.3.7 Point 7 - Storm Water Return Pumps Sample Line ..............................................................4-4 4.3.1 Point 8 - Solid Liquids Separation Unit Sump......................................................................4-5 4.3.2 Point 9 - North CPI Sludge ...................................................................................................4-5 4.3.1 Point 10 - South CPI Sludge .................................................................................................4-5 NRI CD - EOL Sampling Plan Revised June 2011_ Final.doc ii TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8800ooff9944 TABLE OF CONTENTS 4.3.2 Point 11 - GHT-1 Manway ...................................................................................................4-5 4.4 Point of Generation Sampling..............................................................................................................4-5 4.4.1 Uncontrolled Waste Streams Greater Than 0.05 Mg/yr ........................................................4-6 4.5 Sampling Schedule and Methodology .................................................................................................4-6 Appendices APPENDIX A Wastewater Collection and Treatment System Process Flow Schematic APPENDIX B EOL Sampling flow Schematic NRI CD - EOL Sampling Plan Revised June 2011_ Final.doc ii TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8811ooff9944 SECTION 1 INTRODUCTION On November 9, 2007, pursuant to Paragraphs 82 and 83 of the Consent Decree, the TOTAL Petrochemicals USA, Inc. Port Arthur Refinery (TOTAL PAR), submitted its Benzene Waste Operations NESHAP End of Line Sampling Plan ("BWON Sampling Plan"). The BWON Sampling Plan identified seven (7) end-of-line (EOL) sampling points. TOTAL PAR began collecting samples from those sampling points in the 1st quarter 2008 and collected samples, and reported the results there from, for each calendar quarter since that time. Effective June 30, 2011, TOTAL PAR completed installation of new vapor controls on underground sewer vents and other process sewer structures open to the atmosphere to reduce the quantity of benzene released to the atmosphere from uncontrolled waste water sources. Installation of these vapor controls has resulted in the need to establish new EOL sampling locations for measuring uncontrolled benzene quantities. Pursuant to Paragraph 84 of the Consent Decree, TOTAL PAR is required to submit a revised BWON Sampling Plan to EPA for approval if changes in processes, operations, or other factors lead TOTAL to conclude that its approved BWON Sampling Plan may no longer provide an accurate measure of the Refinery's quarterly benzene quantity in uncontrolled benzene waste streams. Because the seven EOL sampling points are now on a controlled system, new EOL sampling points need to be identified to accurately quantify the uncontrolled benzene managed by the refinery. Accordingly, TOTAL PAR hereby submits this revised BWON Sampling Plan. Included as Appendix A herein is the "Wastewater Collection and Treatment System" process flow diagram, which shows the previous end-of-line sampling points as now controlled. Also attached as Appendix B is a schematic titled "EOL Sampling Flow Schematic" that shows the newly established EOL sampling locations. The descriptive overview of the TOTAL PAR wastewater collection and treatment system is provided in Section 2. A description of the color coding and nomenclature of the "Wastewater Collection and Treatment System" process flow diagram and EOL Sampling Flow Schematic is provided in Section 3. The EOL Sampling Plan is provided in Section 4. NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 1-1 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8822ooff9944 SECTION 2 OVERVIEW OF THE REFINERY PROCESS WASTEWATER TREATMENT COMPLEX The wastewater streams at TOTAL PAR are generally managed in one of three pretreatment systems: the North process wastewater system, South process wastewater system, and Benzene NESHAP Pretreatment. The refinery uncontrolled sewer systems manage wastes that are not controlled pursuant to the Benzene Waste Operations NESHAP (BWON). The NESHAP sewer system, controlled oil recovery system, and the recovered/slop oil tankage manage those waste streams that are required to be controlled pursuant to the requirements of the BWON. Paragraph 62 of the TOTAL consent decree requires that TOTAL PAR comply with a reduced uncontrolled benzene quantity of 4.2 Mg/yr, according to the requirements of the 6 BQ compliance option. Therefore, each waste stream at TOTAL PAR was grouped into one of the two following categories to identify the method of compliance for that stream under the BWON. Streams managed in controlled waste management units [61.342(c)(1)] Streams managed in uncontrolled waste management units that sum to less than 4.2 Mg/yr benzene (4.2 BQ) [61.342(e)(2), Consent Decree Paragraph 62] Streams selected as uncontrolled under the provisions of 61.342(e)(2) are identified on the Appendix B schematic. A detailed discussion of each of the three categories of waste streams at the TOTAL PAR is provided below. 2.1 61.342(c)(1) Controlled Waste Streams Organic and aqueous streams that have been chosen for control are managed in controlled waste management units (WMU). The aqueous wastes subject to 61.342(c)(1) are managed in controlled WMU up to the point where the benzene concentration is below 10 ppmw and the waste has reached the refinery's Enhanced Biodegradation Unit (EBU) as provided for in 61.348(b)(2). The organic (hydrocarbon) or hydrocarbon skim streams are generally managed in the recovered/slop oil tankage system. The recovered oil is managed in controlled WMU (i.e., tankage) prior to recycle pursuant to the requirements of 61.342(c)(1)(iii). The greater than 10 ppmw streams that are managed in controlled WMU are comingled with streams with a benzene content of less than 10 ppmw and/or are not selected for control as provided by 61.348(e)(2) in order to facilitate management in the EBU. 2.2 61.342(e)(2) Uncontrolled Waste Streams Streams not selected for control under 61.342(c)(1) are not required to be managed in controlled WMUs as long as the total benzene quantity of these streams sums to 4.2 Mg/yr or less. NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 2-1 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8833ooff9944 2.3 Major Features of the TOTAL PAR Process Wastewater Treatment Complex The BWON compliance strategy at TOTAL PAR was to segregate and treat selected highbenzene containing waste streams and to control refinery slop oils in WMUs operated according to the requirements of the BWON. Effective June 30, 2011, TOTAL PAR completed a project by which most of the streams associated with the BWON-uncontrolled refinery wastewater collection system contributing to the North Gravity Sewer1 and the South Gravity Sewer2 subsystems are now controlled. The remaining uncontrolled streams are now discrete EOL sample points and are identified in this plan. 1 The North Gravity Sewer collects wastewater from the northern portion of the refinery which is sent to the North Corrugated Plate Interceptor (CPI) for initial oil separation. The North CPI recovered oil is sent to controlled slop tankage and the water is sent to the induced gas flotation units (IGFs) en route to biological treatment in the EBU. 2 The South Gravity Sewer collects wastewater from the southern portion of the refinery and tank farm areas which is sent to the South CPIs for initial oil separation. The South CPI recovered oil is sent to controlled slop tankage and the water is also sent to the IGFs en route to biological treatment in the EBU. NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 2-2 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8844ooff9944 SECTION 3 DESCRIPTION OF END -OF-LINE SAMPLING FLOW S C H E M AT I C The schematic, entitled "EOL Sampling Flow Schematic " incorporated in Appendix B identifies the location of the waste streams (and associated WMU's) that are uncontrolled under the Benzene Waste Operations NESHAP (BWON). NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 3-1 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8855ooff9944 SECTION 4 END-OF-LINE SAMPLING PLAN The primary purpose of the schematic in Appendix B is to identify the locations of the uncontrolled waste streams that will be sampled under the new EOL Sampling Program. As discussed above, the BWON control strategy at TOTAL PAR is to remove waste streams that contain relatively high benzene concentrations and waste flows from the refinery's open sewer system. These waste streams are hard piped through controlled waste management units for oil removal prior to mixing with waste from the open sewer system to facilitate treatment in the EBU. In addition, TOTAL PAR continues to operate recovered/slop oil tankage that collects refinery oily wastes from maintenance, blowdown, turnaround events, some vacuum truck movements, and other sources. The recovered oil system consists of hard piping to floating roof storage tanks that meet 40 CFR Part 60, Subpart Kb design standards. The waste management units within the recovered oil system are controlled per the BWON. The decanted oils from the recovered oil system are then returned to the refinery's crude unit for reprocessing. Therefore, the oils are no longer considered a waste under BWON per 40 CFR 61.342(c)(1)(iii). However, the water separated from the oils within the recovered oil system is sent to the closed (controlled) wastewater treatment system (referred to as the Benzene NESHAP Pretreatment System) for further oil recovery prior to biological treatment in the EBU. The wastewaters in the open sewer system are considered controlled wastes because the refinery's individual drain systems now meet the control requirements of the BWON3. The EOL Sampling Plan quantifies the amount of wastes managed in the uncontrolled or open system and identifies "end-of-line" sampling locations to generate a total uncontrolled benzene quantity for the refinery. 4.1 End-of-Line Sampling Locations TOTAL PAR proposes to establish eleven (11) new EOL sampling locations to replace the points sampled under the November 2007 sampling plan. Each new sampling location is denoted on the Appendix B schematic and identified by the following point numbers: 3 The waste streams managed in the "open" system generally fall into two categories: (1) waste streams with less than 10 parts per million by weight (ppmw) benzene managed in uncontrolled management units [61.342(c)(2)], and (2) waste streams with greater than 10 ppmw benzene managed in uncontrolled waste management units that sum to less than 4.2 Mg/yr benzene (4.2 BQ) [61.342(c)(3)]. See Section 2 for a detailed discussion of these categories. NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 4-1 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8866ooff9944 Point 1 - Tank 905 Sump Point 2 - East-Side of DAF Sump Point 3 - Wash Slab Sump Point 4 - PWTC4 67T-301 Sump Point 5 - PWTC 67T-412 Sump Point 6 - PWTC 67P-414 Lab Sump Point 7 - Storm Water Return Pumps Sample Line Point 8 - Solid Liquids Separation Unit Sump Point 9 - North CPI Sludge Point 10 - South CPI Sludge Point 11 - GHT-1 Manway (temporary sample point) Please note that Point 11 will be controlled upon receipt of the pressure vacuum safety valve (PVSV) in August 2011. 4.2 End-of-Line Benzene Quantity Calculation Conceptually, the uncontrolled benzene mass balance (or EOL compliance determination) will be calculated as follows: End-of-Line Uncontrolled Benzene Quantity = (QH2Oi x H2O x CH2Oi) + (QOILi x OILi x COILi) or, specifically: ((QH2O1 x H2O x CH2O1) + (QOIL1 x OIL1 x COIL1) + (QOIL2 x OIL2 x COIL2) + (QH2O2 x H2O x CH2O2) + (QH2O3 x H2O x CH2O3) + (QOIL3 x OIL3 x COIL3) + (QH2O4 x H2O x CH2O4) + (QOIL4 x OIL4 x COIL4) + (QH2O5 x H2O x CH2O5) + (QOIL5 x OIL5 x COIL5) + (QH2O6 x H2O x CH2O6) + (QOIL6 x OIL6 x COIL6) + (QH2O7 x H2O x CH2O7) + (QOIL7 x OIL7 x COIL7) + (QH2O8 x H2O x CH2O8) + (QOIL8 x OIL8 x COIL8) + (QH2O9 x H2O x CH2O9) + (QOIL9 x OIL9 x COIL9) + (QH2O10 x H2O x CH2O10) + (QOIL10 x OIL10 x COIL10) + (QH2O11 x H2O x CH2O11) + (QOIL11 x OIL11 x COIL11)) 4 PWTC - Process Wastewater Treatment Complex NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 4-2 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8877ooff9944 Where: Numbers 1-11 are the End-of-Line locations identified in the attached schematic: QOILi = Oil Phase Flow Rate for Stream i COILi = Benzene Concentration in Oil Phase for Stream i QH2Oi = Aqueous Phase Flow Rate for Stream i CH2Oi = Benzene Concentration in Aqueous Phase for Stream i H2O = Density of Water OIL = Specific Gravity of Oil x Density of Water The flow rate for each sample point will be determined as described below. The flow rate at EOL Point 1, Tank 905 Sump will be determined based upon the measured rain fall for the site and an estimation of the drainage surface area to the sump. Flow meters will be installed on EOL Points 2 and 3, East-Side DAF Sump and Wash Slab Sump, and will be used to determine flow. The flow rates for EOL Points 4 and 5, PWCT 67T-301 Sump and PWTC 67T-412 Sump, will be measured using a grab sample device. The streams entering the sumps are a result of a continuous sample purge at a constant rate. The sample schedule for the PWTC is used to determine the flow from EOL Point 6, PWTC 67P-414 Lab Sump. The only material flowing to this sump would be the discarded wastewater laboratory samples. The flow rate for EOL Point 7, Storm Water Return Pumps Sample Line, will be determined based upon the measured rain fall for the site and an estimation of the amount of wastewater purged from the sampling points when the pumps are operating. The flow rate at EOL Point 8, Solid Liquids Separation Unit Sump, will be determined based upon the measured rain fall for the refinery and any vacuum truck movement associated with this sump. The material collected at EOL Points 9 and 10, North CPI Sludge and South CPI Sludge, is a solid. Samples are taken of the material and sent to an outside laboratory for determining the benzene concentration. The weight of the material and measured benzene concentration are used to determine the benzene quantity. While EOL Point 11, GHT-1 Manway, is a temporary sample point, the flow has been determined using the catch basin piping and applying some fluid calculations. The outlet piping to the modeled catch basin was shown to have a large slope. The pipe drops over 4 feet for a run that is assumed to be less than 20 feet. The pronounced slope calculated a maximum flow through the 10" pipe of 116 gpm assuming the catch basin to be 1-inch higher than the bottom of the pipe. NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 4-3 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8888ooff9944 4.3 Detailed Description of EOL Sampling Locations 4.3.1 Point 1 - Tank 905 Sump This EOL Point is intended to account for wastewater that is captured in the tank dike associated with Tank 905, containment slop oil drains for the pump 67P-905, the NESHAP process water transfer pumps 67P-312 and 67P-313 (these pumps are associated with the operation of the recovered oil Tank 905); the water pump 23P-105B, sump pumps 67P-14A/B, and the sump at the Veolia solid/liquids separation process during storm events. 4.3.2 Point 2 - East-Side DAF Sump This EOL Point is intended to account for wastewater that is collected from within the Dissolved Air Floatation (DAF) unit and Induced Gas Flotation (IGF) boundaries and containment slop oil drains from the IGF float tank, 67T-660, and the de-inventory pumps 67P-104A or B during storm events. 4.3.3 Point 3 - Wash Slab Sump This EOL Point is intended to account for any waste water deposited from vacuum trucks and the cleaning of equipment at the Refinery's "wash slab". 4.3.4 Point 4 - PWCT 67T-301 Sump The NESHAP process area storm water sump 67T-301 collects rain water and spills within the limits of the NESHAP Pretreatment Unit. The Dissolved Nitrogen Flotation (DNF) effluent sample lines also drain to this sump. This EOL Point is intended to account for the wastewater from these sources and is considered uncontrolled. 4.3.5 Point 5 - PWTC 67T-412 Sump The containment areas for the Equalization tank apron and pH adjustment/splitter tank area drain to pH Adjustment/Splitter Area Sump, 67T-412. Sample streams collected for pH and process control evaluation are purged to this sump as well. This EOL Point is intended to account for the wastewater from these sources and is considered uncontrolled. 4.3.6 Point 6 - PWTC 67P-414 Lab Sump This EOL Point is intended to account for any wastewater sample streams collected for analysis and deposited into the PWTC Control Building Laboratory Sump, 67P-414. 4.3.7 Point 7 - Storm Water Return Pumps Sample Line Process storm water collected within the refinery is conveyed to the Biological Pretreatment Unit from the South Process Storm Water Surge Tank System. There are two centrifugal storm water transfer pumps (67P-212 and 67P-501) and three centrifugal storm water transfer pumps NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 4-4 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page8899ooff9944 (67P-502A, B, and C) from which wastewater samples are collected when the pumps are operating. This EOL Point is intended to account for the wastewater purged to the sump when collecting samples. 4.3.1 Point 8 - Solid Liquids Separation Unit Sump This EOL Point is intended to account for oily water and sludges that may be deposited into this sump when vacuum truck transfers are made into or out of the Gravity Separation Tanks, TK679, TK-680 and TK-681. This sump captures any liquid or sludge that may be released when vacuum truck hoses are connected or disconnected to make a transfer. The function of the Gravity Separation Tanks is to separate sludge into solids, water, and oil by gravity with the aid of heat. 4.3.2 Point 9 - North CPI Sludge This EOL Point is intended to account for any benzene-containing sludge wastes periodically removed from the North CPI. This waste is collected from the uncontrolled points of waste generation sent to the North Gravity Sewer. 4.3.1 Point 10 - South CPI Sludge This EOL Point is intended to account for any benzene-containing sludge wastes periodically removed from the South CPI. This waste is collected from the uncontrolled points of waste generation sent to the South Gravity Sewer. 4.3.2 Point 11 - GHT-1 Manway This EOL Point is intended to account for any wastewater draining due to storm water runoff into the wastewater sewer from within the unit boundaries of the number 1 Gasoline Hydrotreating Unit (GHT-1). This EOL Point is temporary in that plans are underway to control the vent off the cited manway. This system should be completed by August 30, 2011. 4.4 Point of Generation Sampling In addition to identifying proposed sampling locations, paragraph 82 of the Consent Decree requires the BWON Sampling Plan to include proposed quarterly sampling at the "point of waste generation" of each waste stream that contributes 0.05 Mg/yr or more to the TOTAL PAR's 4.2 Mg uncontrolled benzene quantity. Several waste streams accounted for in the refinery's TAB are cumulative waste streams consisting of small sources such as pump, exchanger, filter, and instrument leg maintenance, uncontrolled vacuum truck movements, and others. In addition, included on the TAB are cooling waters and process storm water that may contribute 0.05 Mg/yr or more to the refinery's uncontrolled benzene quantity. It is impractical to sample these streams because they are small and intermittent. Therefore, they will not be sampled as part of the point of generation sampling . Below is a description of the waste streams at the point of generation that contribute greater than 0.05 Mg/yr to the refinery's uncontrolled benzene quantity. NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 4-5 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page9900ooff9944 4.4.1 Uncontrolled Waste Streams Greater Than 0.05 Mg/yr TOTAL PAR has determined there are a total of three waste streams that contribute greater than 0.05 Mg/yr at their point of waste generation to the uncontrolled benzene quantity. One of the three streams represents conglomerations of numerous small waste streams that are grouped by classification to facilitate stream accounting in the TAB. That waste stream is identified as "Wastes Shipped Off-Site for Disposal". The two5 remaining waste streams that contribute greater than 0.05 Mg/yr to the refinery's uncontrolled benzene quantity can be characterized as "discrete" points of waste generation and thus will be sampled quarterly. The streams that are to be sampled under this category include the following: ACU-2 First Stage Desalter Rag Layer Visual Check Reformer/NHT Fuel Gas Knockout Drum 4.5 Sampling Schedule and Methodology The EOL sampling will be performed at least monthly to arrive at the EOL calculation. The point of generation sampling will be performed at least quarterly. However, sampling may be performed at a greater overall frequency to minimize the effect of operating condition anomalies during the sampling. The sampling will follow 40 CFR 61.355 procedures to the extent possible along with the TOTAL PAR BWON Sampling Protocol and Training Manual. A notation in the sampling log book will be made if a sample cannot be taken according to the 61.355 procedures. In certain situations, it may not be possible to collect samples from open systems with the cooling coil. In the case of samples taken without the cooling coil, the samples will be placed on ice immediately. 5 Two of the samples previously considered, the Jet Treater Mericat II Phase Separator Spent Caustic and Jet Treater Water Wash Phase Separator Rag Layer, have been deleted. The Jet Treater operation was discontinued as part of the Delayed Coker Project (DCP). Jet is now processed through the Distillate Hydrotreater Unit No. 1 (DHT-1). NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal 4-6 TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page9911ooff9944 APPENDIX A WASTEWATER COLLECTION AND TREATMENT SYSTEM PROCESS FLOW SCHEMATIC NRI CD - EOL Sampling Plan Revised June 2011_ Final.docFinal TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page9922ooff9944 APPENDIX B EOL SAMPLING FLOW SCHEMATIC NRI CD - EOL Sampling Plan Revised June 2011_ Final.doc TOTAL Petrochemicals USA, INC. - TOTAL PAR EPA Inspection Report - Page 93 of 94 EPA Inspection Report - Page 94 of 94 CONTAINMENT SLOP OIL DRAINS FOR 23P-105B, 67P-14A/B 1 TK 905 TANK DIKE; CONTAINMENT SLOP OIL DRAINS FOR 67P-905 & 67P-313 TK 905 SUMP VEOLIA SOLID/LIQUIDS SEPARATION SUMP DAF/IGF RAIN WATER RUN OFF FROM UNIT 2 CONTAINMENT STOP DRAINS 67T-660 DEINVENTORY OF PUMPS, 67P-104A&B EAST SIDE DAF SUMP 3 VACUUM TRUCK MOVEMENTS EQUIPMENT CLEANING OLD WASH SLAB SUMP 4 RAIN WATR AND SPILLS FROM UNIT BOUNDARIES FOR NESHAP PRETREATMENT PWTC 67T-501 SUMP DNF EFFLUENT SAMPLE LINES EQUALIZATION TANK CONTAINMENT AREA 5 pH ADJUSTMENT/SPLITTER TANK DRAIN AREA SAMPLE STREAM PURGES PWTC 67T-412 SUMP 67P-212 67P-501 (SAMPLE PURGE) PWTC LAB 67P-502A/B/C (SAMPLE PURGE) 6 PWTC 67P-414 LAB SUMP 7 SW RETURN PUMPS SUMP 8 VACUUM TRUCK TRANSFER IN & OUT OF TK-679, TK-680, & TK-681 SOLID LIQUIDS SEPARATION SUMP 9 N. CPI SLUDGE S. CPI SLUDGE 10 GHT MANWAY 11 SOUTH DIVERSION BOX RAPID MIX TANK EQ TANKS VIA VACUUM TRUCK RECOVERED OIL SYSTEM VIA VACUUM TRUCK VEOLIA SOLID/LIQUID SEPARATION PROCESS MH-01 REV DESCRIPTION LEGEND 1 NESHAP UNCONTROLLED STREAMS NESHAP CONTROLLED STREAMS (750-D-50-1288A - REV.4) END OF THE LINE SAMPLING POINTS NOTE: EOL SAMPLING POINT NO. 11 IS TEMPORARY AND WILL BE CONTROLLED ON OR BEFORE AUGUST 30, 2011. TOTAL PETROCHEMICALS USA, INC. PORT ARTHUR REFINERY P. O. BOX 849 PORT ARTHUR, TEXAS END OF LINE SAMPLING PLAN APPENDIX B: EOL SAMPLING FLOW SCHEMATIC JN 7/11 BY DATE 750-D-50-4138 0