Document Z4x5JZ1aX3agez60vYdk6YKap

Crestwood Equity Partners, LP Arrow Pipeline, LLC- Station 7 Compressor Station Full Compliance Evaluation (FCE) On-Site Inspection Inspection Date: June 15, 2023 Inspection Report Date: September 6, 2023 EPA Representatives: Youn Joo Kim, Environmental Scientist, US EPA Region 8 Katelyn Bergl, Environmental Scientist, US EPA Region 8 Tribal Representatives: None Company Representatives: Josh Swann, Environmental Construction Manager Inspection Report Prepared By: Youn Joo Kim, Environmental Scientist, US EPA Region 8 Lindsey Barnes, Scientist, US EPA Region 8 Inspection Report Reviewed By: Last CAA Inspection: Scott Patefield, Manager, Enforcement and Compliance Assurance Division, Air and Toxics Enforcement Branch SCOTT PATEFIELD Digitally signed by SCOTT PATEFIELD Date: 2023.09.21 09:38:27 -06'00' Never CAA Applicable Rules: Tribal Minor New Source Review (TMNSR) Synthetic Minor Permit #SMNSR-TAT-000661-2017.003 40 C.F.R. Part 60, Subpart JJJJ--Standards of Performance for Stationary Spark Ignition Internal Combustion Engines (NSPS JJJJ) 40 C.F.R. Part 60, Subpart OOOO-- Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution (NSPS OOOO) CAA Permit History: EPA issued Arrow Pipeline, LLC the TMNSR synthetic minor permit #SMNSR-TAT-000661-2013.001 on May 15, 2014. The startup notice was received on 5/9/2016. EPA issued Arrow Pipeline LLC the TMNSR synthetic minor permit SMNSR-TAT-000661-2017.003 on January 10, 2018. General Source Information Parent Company Name: Mailing Address: Facility Contact: Facility Operator & Names: Facility Location: EPA Region: County, State: Crestwood Equity Partners LP 811 Main Street, Suite 3400 Houston, Texas 77002 Patricia Whitenight, Air Quality Manager Arrow Pipeline, LLC: Station 7 Compressor Station Latitude 47.672167, Longitude -102.401833 8 Dunn County, North Dakota 1 Reservation: Tribe: Responsible Official: SIC Codes: ICIS ID: Other CAA Permits: Fort Berthold Indian Reservation MHA Nation (Three Affiliated Tribes) Jeff Stovall, Senior Vice President, Bakken Operations 4922- Pipeline Transportation of Natural Gas 0800000002501 There are no other CAA permits for this facility. Overall Inspection Findings/ Areas of Concern On the day of the inspection, continuous VOC emission from the condensate tank was observed. The serial number for unit 760 was 3150228 (consistent with NSPS JJJJ Performance Test reports) during the time of the inspection, however in the requested data follow-up, the serial number is recorded as 5283702040. From the data requested after the inspection, engine Unit 761, Serial Number 5283703441 had missing records of the catalytic inlet pressure and catalytic pressure differential without sufficient notes indicating whether the engine was operating. On the day of the inspection, some of the differential pressure readings for engine catalyst exceeded +/- 2 inches of H2O limit. During the inspection, the differential catalytic pressure was -15.167 in H2O 6/1/23 reading in the engine logbook recorded -9 in H2O. In the records sent to the EPA after the inspection, EPA inspectors observed missing catalyst inlet temperature and catalyst pressure difference on Unit 761 from November 2022 to May 2023 without corresponding notes on operational status of the engine. Description of Operations The operation consists of natural gas gathering from several customers in the region and transmission to a central delivery point (CDP) located within the exterior boundaries of the Fort Berthold Indian Reservation. General Inspection Observations and Commentary Opening Conference: On June 15, 2023, at 8:17 AM, EPA inspectors Youn Joo Kim and Katelyn Bergl met with Crestwood LP/Arrow Pipelines LLC representative Josh Swann onsite at Compressor Station 7. An opening conference was conducted (previously at Station 6 at the beginning of the inspection day), during which EPA inspectors presented credentials. A brief safety orientation was also completed, and EPA inspectors informed Josh Swann that the site would be surveyed using a forward-looking infrared camera and confirmed no hot work permit was required to use the equipment. A summary of arrival and departure times as well as general observations of tanks and flares can be found in Table 1. The summary of engines inspected is in Table 2. The meteorological condition during the inspection is described below: Temperature: 63 degrees Fahrenheit Wind Speed:8 mph Wind Direction: West Cloud Coverage: Cloudy At the time of the inspection Station 7 had the inlet pressure of 50.2 psi and outlet pressure of 61.4 psi. Station 7 receives gasses from wells 6 and 7 located east of the station and sends the compressed gas to 4. Josh Swann shared that XTO's Stephen Bird (a new well) is starting up near by and sending gasses to be flared at Station 7, which results in the inlet pressure and the outlet pressure being so close. 2 Additionally, there were two engines, unit 760 and unit 761 operating at the time of the inspection. Table 1: Station 7 General Inspection Observations Arrival Departure Tanks Emissions Media Time Time Flare Emissions Detectable Odors 8:17 AM 8:59 AM Yes, Continuous MOV_0234.mp4, No No MOV_0235.mp4 Table 2: Engine Inspection Data Unit Serial number Catalyst Inlet Catalyst D/P (in H2O) Temperature (F) 760 3150228 815.9 -15.167 761 5283703441 Not operating at the time of the inspection *Per TMNSR I.E.2(e) engine exit/catalyst inlet exhaust temp must be between 450 and 1350 F ** Per TMNSR I.E.2(f) catalyst pressure drop must be within 2 inches of water of the baseline pressure drop set during most recent performance test (see NSPS JJJJ section). Table 3: Summary of Catalyst Bed Pressure Drop Readings MONTHS SEP OCT NOV DEC JAN FEB MAR APR MAY JUN Engine Stack Test Baseline Date (in H2O) Catalytic Differential Pressure (+/- 2 inches H2O) 760 May 2022 6 May 2023 3.1 0 1 4 -5.2 4.9 5 761 July 2022 1.6 No No 2 0 0 Record Record 2 Blanks indicated missing data points. 5.7 -5 No Record 0 -5.4 -9 No 0 Record Permit Number #SMNSR-TAT-000661-2013.001 Requirements and Compliance Status Inspector notes discussing compliance status will follow each relevant permit requirement in bold blue font. Only the observations during the inspection and observation made from the requested data will have a comment. A. Applicability 1. This Conditional Permit to Construct is being issued under the authority of the Tribal Minor New Source Review Program at 40 CFR part 49 (MNSR). 2. The requirements in this permit have been created, at the Permittee's request, to establish legally and practically enforceable requirements for limiting emissions of volatile organic compounds (VOCs), nitrogen oxide (NOx), carbon monoxide (CO), and individual and total hazardous air pollutants (HAPs). 3. Any conditions established for this facility or any specific units at this facility pursuant to any Conditional Permit to Construct issued under the authority of the Prevention of 3 Significant Deterioration Permit Program at 40 CFR part 52 (PSD) or MNSR shall continue to apply. 4. By issuing this permit, the EPA does not assume any risk of loss which may occur as a result of the operation of the permitted facility by the Permittee, Owner, and/or Operator, if the conditions of this permit are not met by the Permittee, Owner, and/or Operator. B. Requirements for Emission Limits, Construction and Operation 1. Emission Limits (a) VOC emissions shall not exceed 92 tons during any consecutive 12 months. (b) NOx emissions shall not exceed 92 tons during any consecutive 12 months. (c) CO emissions shall not exceed 92 tons during any consecutive 12 months. (d) Individual HAP emissions shall not exceed 9.8 tons during any consecutive 12 months. (e) Total HAP emissions shall not exceed 24.5 tons during any consecutive 12 months. (f) Emission limits specified in this permit shall apply at all times. 2. Construction and Operational Limits (a) The Permittee shall limit the total maximum engine capacity at the station to 7,000 horsepower (hp). (b) All engine capacities shall be based on the manufacturer's maximum site rated hp of each engine. (c) The Permittee shall only install two (2) - 400-barrel natural gas condensate tanks operated and controlled as specified in the Requirements for Tanks section of this permit. (d) The Permittee shall only install one (1) - 400-barrel produced water storage tank operated and controlled as specified in the Requirements for Tanks section of this permit. (e) The Permittee shall limit the combined produced water and natural gas condensate throughput to 80,500 barrels in any given consecutive 12-month period. 4 (f) All produced water and natural gas collection, storage, and handling operations, regardless of size, shall be designed, operated, and maintained by the Permittee so as to minimize leakage of hydrocarbon emissions to the atmosphere. 3. Testing Requirements Within 1 year of the first day that operations begin, the Permittee shall obtain an extended laboratory analysis of the produced water and natural gas condensate entering the station to confirm the accuracy of the emissions estimates provided in the application for this permit. Thereafter, the Permittee shall obtain an extended laboratory analysis of the produced water and natural gas condensates received at the station every 5 years and use the new data for emissions calculations required in this permit. 4. Monitoring Requirements (a) The Permittee shall monitor the total maximum engine capacity at the station upon commencement of operations, at the end of each calendar year, and anytime an engine is installed, moved or replaced. All engine capacities shall be based on the maximum site rated hp of each engine. (b) The Permittee shall measure the throughput volume of produced water and natural gas condensate processed through the station according to the Requirements for Tanks section of this permit. (c) The Permittee shall calculate, at the end of each calendar month, the produced water and natural gas condensate throughput at the station, in barrels, beginning with the first calendar month that permitted operations commence. Prior to 12 full months of operation, the Permittee shall, at the end of each calendar month, add the produced water and natural gas condensate throughput for that calendar month to the calculated produced water and condensate throughput for all previous calendar months since operations commenced and record the total. Thereafter, the Permittee shall, at the end of each calendar month add the produced water and natural gas condensate throughput for that calendar month to the calculated produced water and natural gas condensate throughput for the preceding 11 calendar months and calculate a new 12-month total. (d) The Permittee shall calculate, at the end of each calendar month, the VOC, NOx, CO, and HAP emissions beginning with the first calendar month that permitted operations commence. Prior to 12 full months of operation, the Permittee shall, at the end of each month, add the emissions for that month to the calculated emissions for all previous months since operations commenced and record the total. Thereafter, the Permittee shall, at the end of each month add the emissions for that month to the 5 calculated emissions for the preceding 11 months and calculate a new 12-month total. (e) Emissions from all controlled and uncontrolled emission sources shall be included in the monthly and consecutive 12-month calculations, including, but not limited to: the natural gas condensate tanks; produced water storage tanks; truck load-out operations; produced water and natural gas system receivers; fuel gas coalescers; slug catchers; filter separators; pig launchers and receivers; pneumatic pumps; pneumatic controls; compressor blow-downs; engines; equipment leaks; enclosed combustors; utility flares; or other EPA-approved control device. (f) Emissions from each approved emitting unit shall be calculated by the Permittee as specified in this permit. (g) Where sufficient to meet the monitoring requirements of this permit, the Permittee may use a Supervisory Control and Data Acquisition (SCADA) system to monitor the needed data in this permit. (h) Alternative monitoring methods may be used by the Permittee upon EPA approval. 5. Recordkeeping Requirements (a) The Permittee shall maintain a record of the monthly and consecutive 12-month barrels of produced water and natural gas condensate received at the station. (b) The Permittee shall maintain a record of the monthly and consecutive 12-month VOC, NOx, CO, and HAP emissions, in tons per year (tpy) from the station. (c) The Permittee shall maintain a record of the results of each extended laboratory analysis of the produced water and natural gas condensate received at the station. (d) The Permittee shall maintain a record of all input parameters and calculations used to determine the monthly emissions from all controlled and uncontrolled emission sources. (e) The Permittee shall maintain a record of all deviations from the requirements of this permit. (f) Where sufficient to meet all the recordkeeping requirements of this permit, the Permittee may use a SCADA system to record the needed data in this permit. (g) Alternative methods of recordkeeping may be used by the Permittee upon EPA approval. 6 C. Requirements for Engines 1. Emission Limits (a) Emissions from each natural gas-fired lean-bum engine shall not exceed the following: (i) NOx: 2.0 grams/horse power-hour (g/hp-hr); (ii) CO: 1.3 g/hp-hr; (iii) VOC: 0.75 g/hp-hr; and (iv) Formaldehyde (CH2O): 0.2 g/hp-hr. (b) Emissions from each natural gas-fired rich-bum engine shall not exceed the following: (i) NOx: 1.0 g/hp-hr; (ii) CO: 2.0 g/hp-hr; (iii) VOC: 0.7 g/hp-hr; and (iv) CH2O: 0.1 g/hp-hr. 2. Control and Operational Requirements (a) The Permittee shall equip each 4-stroke lean-bum engine with an air-to-fuel ratio (AFR) controller to ensure that the engine continues to operate as a lean-bum engine. The oxygen sensor associated with each AFR controller must be replaced after every 2,190 hours of engine run time. (b) The Permittee shall equip and operate each 4-stroke rich-bum engine with an AFR controller to ensure that the engine continues to operate as a rich-bum engine. The oxygen sensor associated with each AFR controller must be replaced after every 2,190 hours of engine run time. (c) The Permittee shall equip and operate each 4-stroke rich-bum engine with a nonselective catalytic reduction (NSCR) control system capable of reducing the uncontrolled emissions of NOx, CO, VOC, and CH2O to meet the emission limits specified in this permit. EPA inspectors confirmed the engines equipped with NSCR. (d) The Permittee shall install, operate, and maintain temperature sensing devices (i.e., thermocouple or resistance temperature detectors) before the NSCR control system on each engine in order to continuously monitor the exhaust temperature at the inlet of the catalyst bed. Each temperature sensing device shall be calibrated and operated by the Permittee according to manufacturer and/or vendor specifications or equivalent specifications developed by the Permittee or vendor. EPA inspectors observed temperature sensing device at the inlet of NSCR to 7 monitor catalyst bed temperature. (e) Except during startups, which shall not exceed 30 minutes, the engine exhaust temperature of each engine, at the inlet to the catalyst bed, shall be maintained at all times the engines operate with an inlet temperature of at least 450 F and no more than 1,350 F. EPA inspectors reviewed engine monitoring data submitted after the inspection and confirmed that all engines operate within an inlet temperature of at least 450 F and no more than 1350 F. (f) During operation, the pressure drop across the catalyst bed on each engine shall be maintained to within 2 inches of water from the baseline pressure drop measured during the most recent performance test. The baseline pressure drop for the catalyst bed shall be determined at 100% 10% of the engine load measured during the most recent performance test. (g) The Permittee shall only fire each engine with natural gas. EPA inspectors confirmed the use of natural gas to fuel every engine. (h) The Permittee shall follow, for each engine and its respective catalytic control system, the manufacturer and/or vendor recommended maintenance schedule and procedures or equivalent maintenance schedule and procedures developed by the Permittee or vendor to ensure optimum performance of each engine and its respective catalytic control system. (i) The Permittee may rebuild an existing permitted engine or replace an existing permitted engine with an engine of the same horsepower rating, and configured to operate in the same manner as the engine being rebuilt or replaced. Any emission limits, requirements, control technologies, testing or other provisions that apply to the permitted engines that are replaced shall also apply to the rebuilt and replaced engines. (j) The Permittee may resume operation without the catalytic control system during an engine break-in period, not to exceed 200 operating hours, for rebuilt and replaced engines. 3. Performance Testing Requirements (a) Performance tests shall be conducted on each engine for measuring NOx, CO, VOC, and CH2O emissions to demonstrate compliance with each emission limitation in this permit. The performance tests shall be conducted in accordance with appropriate reference methods specified in 40 CPR part 63, appendix A and 40 CPR part 60, appendix A, or an EPA-approved American Society for Testing and Materials (ASTM) method. The Permittee may submit to the EPA a written request for approval of an alternate test method, but shall only use that alternate test method after obtaining approval from 8 Commented [A1]: comment the EPA. (i) The initial performance test for each engine shall be conducted within 90 calendar days of startup of a new engine. Table 4: Engines Subject to NSPS JJJJ Emission Limitations- Greater than 500 hp Make Model Serial # Max HP Fuel JJJJ Initial JJJJ Initial Perf Test Notice Rec'd Waukesha F18G 5283702610 400 NG 4/16/2014 NA Waukesha L7042GSI 5283702041 1480 NG 4/17/2014 3/10/2014 (ii) Subsequent performance tests for VOC and CH2O emissions shall be conducted within 12 months of the most recent performance test. (iii) Performance tests shall be conducted within 90 calendar days of each catalyst replacement. (iv) Performance tests shall be conducted within 90 calendar days of startup of all rebuilt and replaced engines. (b) The Permittee shall not perform engine tuning or make any adjustments to engine settings, catalytic control system settings, or processes or operational parameters the day of the engine testing or during the engine testing for the purpose of passing a performance test. Any such tuning or adjustments may result in a determination by the EPA that the test is invalid. The Permittee shall record the reason for and result of any adjustments made on the day of or during any performance test. Artificially increasing an engine load to meet testing requirements is not considered engine tuning or adjustments. (c) The Permittee shall not abort any engine tests that demonstrate non-compliance with the emission limits in this permit. (d) All performance tests conducted on each engine shall meet the following requirements: (i) The pressure drop across each catalyst bed and the inlet temperature to each catalyst bed shall be measured and recorded at least once during each performance test. (ii) All tests for CO and NOx emissions shall be performed simultaneously. (iii) All tests shall be performed at a maximum operating rate (90% to 110% of the maximum achievable engine load available on the day of the test). The Permittee may submit to the EPA a written request for approval of an alternate load level for testing, but shall only test at that alternate load level after obtaining approval from the EPA. (iv) During each test run, data shall be collected on all parameters necessary to document how emissions were measured and calculated (such as test run length, minimum sample volume, volumetric flow rate, moisture and oxygen corrections, etc.). (v) Each test shall consist of at least three I-hour or longer valid test runs. Emission results shall be reported as the arithmetic average of all valid test 9 runs and shall be in terms of the emission limits in this permit. (vi) Performance test plans shall be submitted to the EPA for approval 60 calendar days prior to the date the test is planned. Performance test plans that have already been approved by the EPA for the emission units approved in this permit may be used in lieu of new test plans unless the EPA requires the submittal and approval of new test plans. The Permittee may submit new plans for EPA approval at any time. (vii) The test plans shall include and address the following elements: (A) Purpose of the test; (B) Engines and catalytic control systems to be tested; (C) Expected engine operating rate(s) during the test; (D) Sampling and analysis procedures (sampling locations, test methods, laboratory identification); (E) Quality assurance plan (calibration procedures and frequency, sample recovery and field documentation, chain of custody procedures); and (F) Data processing and reporting (description of data handling and quality control procedures, report content). (e) The Permittee shall notify the EPA at least 30 calendar days prior to scheduled performance testing. The Permittee shall notify the EPA at least 1 week prior to scheduled performance testing, or as soon as practicable prior to a scheduled performance test, if the testing cannot be performed. (t) If the results of a performance test of the emissions from any permitted engine demonstrate noncompliance with the emission limits in this permit, the engine shall be shut down as soon as safely possible, and appropriate corrective action shall be taken (e.g., repairs, catalyst cleaning, catalyst replacement). The engine must be retested within 7 days of being restarted and the emissions must meet the applicable limits in this permit. If the retest shows that the emissions continue to exceed the limits in this permit, the engine shall again be shut down as soon as safely possible, and the engine may not operate, except for purposes of startup and testing, until the Permittee demonstrates through testing that the emissions do not exceed the emission limits in this permit. (f) If a permitted engine is not operating, the Permittee does not need to start up the engine solely to conduct a performance test. The performance test requirements apply when the facility begins operating again. The following is a summary of results from performance test on May 3, 2023. Table 5: NSPS JJJJ Engines Most Recent Performance Test Make Model Serial # Pressure CO (g/hp- NOx NMNEHC CH2O 10 Waukesha L7044GS1 3150228 Drop (psi) hr) 3.1 0.161 (g/hp-hr) 0.160 (g/hp-hr) 0.065 (g/hp-hr) 0.001 4. Monitoring Requirements (a) The Permittee shall continuously monitor the engine exhaust temperature of each engine at the inlet to the catalyst bed. (b) Except during startups, which shall not exceed 30 minutes, if the engine's exhaust temperature at the inlet to the catalyst bed deviates from the acceptable ranges specified in this permit then the following actions shall be taken. The Permittee's completion of any or all of these actions shall not constitute, nor qualify as, an exemption from any other emission limits in this permit. (i) Within 24 hours of determining a deviation of the engine exhaust temperature at the inlet to the catalyst bed, the Permittee shall investigate. The investigation shall include testing the temperature sensing device, inspecting the engine for performance problems and assessing the catalytic control system for possible damage that could affect catalytic system effectiveness (including, but not limited to, catalyst housing damage, and fouled, destroyed or poisoned catalyst). (ii) If the engine exhaust temperature at the inlet to the catalyst bed can be corrected by following the engine manufacturer and/or vendor recommended procedures or equivalent procedures developed by the Permittee or vendor, and the catalytic control system has not been damaged, then the Permittee shall correct the engine exhaust temperature at the inlet to the catalyst bed within 24 hours of inspecting the engine and catalytic control system. (iii) If the engine exhaust temperature at the inlet to the catalyst bed cannot be corrected using the engine manufacturer and/or vendor recommended procedures or equivalent procedures developed by the Permittee or vendor, or the catalytic control system has been damaged, then the affected engine shall cease operating immediately and shall not be returned to routine service until the following has been met: (A) The engine exhaust temperature at the inlet to the catalyst bed is measured and found to be within the acceptable temperature range for that engine; and (B) The catalytic control system has been repaired or replaced, if necessary. At the time of the inspection, EPA inspectors confirmed monitoring of catalytic system effectiveness monitoring of the engine, such as engine exhaust temperature at the inlet to the catalyst bed. In the records received for unit 760 and 761, there are significant portions of data missing for Unit 761 from November to May without adequate explanation other than "station was not accessible. 11 (c) The Permittee shall monitor the pressure drop across the catalyst bed on each engine every 30 days using pressure sensing devices before and after the catalyst bed to obtain a direct reading of the pressure drop (also referred to as the differential pressure). [Note to Permittee: Differential pressure measurements, in general, are used to show the pressure across the filter elements. This information will determine when the elements of the catalyst bed are fouling, blocked or blown out and thus require cleaning or replacement.] During the review of data received from Arrow Pipeline LLC post inspection, EPA inspectors noticed missing catalyst pressure drop data for unit 761 without adequate explanation on whether or not the engine was operating. The only explanation recorded from November to May was "station was not accessible" however there were continuous engine monitoring data recorded for unit 760. (d) The Permittee shall perform the first measurement of the pressure drop across the catalyst bed on each engine no more than 30 days from the date of the initial performance test. Thereafter, the Permittee shall measure the pressure drop across the catalyst bed, at a minimum, every 30 days. Subsequent performance tests, as required in this permit, can be used to meet the periodic pressure drop monitoring requirements provided it occurs within the 30-day window. The pressure drop reading can be a one-time measurement on that day, the average of performance test runs conducted on that day, or an average of all the measurements taken on that day if continuous readings are taken. During the review of the data received from Arrow Pipelines LLC post inspection, EPA inspectors noticed missing catalyst pressure drop data for unit 761 without adequate explanation on whether or not the engine was operating during that time period. The only explanation recorded from November to May was "station was not accessible" however there were continuous engine monitoring data recorded for unit 760.l (e) The Permittee shall measure NOx and CO emissions from each engine at least quarterly to demonstrate compliance with each engine's emission limits in this permit. To meet this requirement, the Permittee shall: (i) Measure NOx and CO emissions at the normal operating load using a portable analyzer and a monitoring protocol approved by the EPA or conduct a performance test as specified in this permit; (ii) Measure the NOx and CO emissions simultaneously; and (iii) Commence monitoring for NOx and CO emissions within 6 months of the Permittee's submittal of the initial performance test results for NOx and CO emissions to the EPA. (f) The Permittee shall not perform engine tuning or make any adjustments to engine settings, catalytic control system settings, or processes or operational parameters on the day of or during measurements for the purpose of meeting the emission limits in this permit. Any such tuning or adjustments may result in a determination by the EPA that the result is invalid. The Permittee shall record the reason for and result of any 12 adjustments made on the day of or during any measurements. Artificially increasing an engine load to meet the testing requirements is not considered engine tuning or adjustments. (g) If the pressure drop reading exceeds 2 inches of water from the baseline pressure drop established during the most recent performance test, or if the results of any quarterly emissions monitoring demonstrate non-compliance with the emission limits in this permit, then the following actions shall be taken. The Permittee's completion of any or all of these actions shall not constitute, nor qualify as, an exemption from any other emission limits in this permit: (i) Within 24 hours of determining a deviation of the pressure drop across the catalyst bed or the emission limits in this permit, the Permittee shall investigate. The investigation shall include testing the pressure transducers and assessing the catalytic control system for possible damage that could affect catalytic system effectiveness (including, but not limited to, catalyst housing damage, and plugged, fouled, destroyed or poisoned catalyst). (ii) If the pressure drop across the catalyst bed, or the elevated emission rates, can be corrected by following the catalytic control system manufacturer and/or vendor recommended procedures or equivalent procedures developed by the Permittee or vendor, and the catalytic control system has not been damaged, then the Permittee shall correct the problem within 24 hours of inspecting the catalytic control system. (iii) If the pressure drop across the catalyst bed, or the elevated emission rates, cannot be corrected using the catalytic control system manufacturer and/or vendor recommended procedures or equivalent procedures developed by the Permittee or vendor, or the catalytic control system is damaged, then the Permittee shall do one of the following: (A) Conduct a performance test within 90 calendar days, as specified in this permit, to ensure that the NOx, CO, VOC, and CH2O emission limits are being met and to re-establish the pressure drop across the catalyst bed. The Permittee shall perform a portable analyzer test for CO and NOx emissions and establish a new temporary pressure drop baseline until a performance test can be scheduled and completed; or (B) Cease operating the affected engine immediately. The engine shall not be returned to routine service until the pressure drop is measured and found to be within the acceptable pressure range for that engine as determined from the most recent performance test and the emission rates are found to be in compliance with the emission limits in this permit. Corrective action may include removal and cleaning of the catalyst or replacement of the catalyst. (h) For any one (1) engine: If the results of 2 consecutive quarterly portable analyzer measurements demonstrate compliance with the NOx and CO emission limits, the required monitoring frequency may change from quarterly to semi-annually. 13 (i) For any one (1) engine: If the results of any subsequent portable analyzer measurements demonstrate non-compliance with the NOx or CO emission limits, required monitoring frequency shall change from semi-annually to quarterly. (i) The Permittee shall submit portable analyzer specifications and monitoring protocols for NOx and CO to the EPA at the following address for approval at least 45 calendar days prior to the date of initial portable analyzer monitoring: U.S. Environmental Protection Agency, Region 8 Office of Enforcement, Compliance & Environmental Justice Air Toxics and Technical Enforcement Program, 8ENF-AT 1595 Wynkoop Street Denver, Colorado 80202 (k) Portable analyzer specifications and monitoring protocols that have already been approved by the EPA for the emission units approved in this permit may be used in lieu of new protocols unless the EPA requires the submittal and approval of a new protocol. The Permittee may submit a new protocol for EPA approval at any time. (1) The Permittee is not required to conduct emissions monitoring ofNOx, CO, VOC, and CH2O emissions, and parametric monitoring of exhaust temperature and catalyst differential pressure on engines that have not operated during the monitoring period. The Permittee shall certify that the engine(s) did not operate during the monitoring period in the annual report specified in this permit. 5. Recordkeeping Requirements (a) Records shall be kept of manufacturer and/or vendor specifications or equivalent specifications developed by the Permittee or vendor, and maintenance requirements for each engine, AFR controller, NSCR control system, temperature sensing device, and pressure measuring device. The serial number for unit 760 was 3150228 (consistent with NSPS JJJJ Performance Test reports) during the time of the inspection, however in the requested data follow-up, the serial number is recorded as 5283702040. (b) Records shall be kept of all calibration and maintenance conducted for each engine, AFR controller, NSCR control system, temperature sensing device, and pressure measuring device. EPA inspectors observed records of calibration and maintenance on the monthly log sheets next to each engine. However, there was a big gap in the records for Unit 761 which didn't show whether or not the engine was operating, or down for maintenance. (c) Records shall be kept of all temperature measurements required in this permit, as well as a description of any corrective actions taken pursuant to this permit. 14 EPA inspectors observed temperature data missing for Unit 761 from November 2022 to May 2023. (d) Records shall be kept of all pressure drop measurements required in this permit, as well as a description of any corrective actions taken pursuant to this permit. (e) Records shall be kept of all required testing and monitoring in this permit. The records shall include the following: (i) The date, place, and time of sampling or measurements; (ii) The date(s) analyses were performed; (iii) The company or entity that performed the analyses; (iv) The analytical techniques or methods used; (v) The results of such analyses or measurements; and (vi) The operating conditions as existing at the time of sampling or measurement. In the records sent by Arrow Pipelines LLC following the inspection, EPA inspectors observed missing catalyst pressure drop readings for unit 761 for December 2022, and January 2023 without any clear memo regarding the operating status of the engine. (f) Records shall be kept of all AFR controller, oxygen sensor, and NSCR control system replacements or repairs, engine rebuilds and engine replacements. (g) Records shall be kept of each rebuilt or replaced engine break-in period, pursuant to the requirements of this permit, where an existing engine that has been rebuilt or replaced resumes operation without the catalyst control system, for a period not to exceed 200 operating hours. (h) Records shall be kept of each time any engine is shut-down due to a deviation of the inlet temperature to the catalyst bed or pressure drop across the catalyst bed. The Permittee shall include in the record the cause of the problem, the corrective action taken, and the timeframe for bringing the pressure drop and inlet temperature range into compliance. In the records sent by Arrow Pipelines LLC following the inspection, EPA inspectors observed records of engine shutdown. D. Requirements for Tanks 1. All natural gas condensate tanks and produced water storage tanks are subject to the requirements of this permit. 2. The Permittee shall follow, for each tank, the manufacturer's recommended maintenance schedule and procedures or equivalent procedures developed by the Permittee or vendor to ensure good air pollution control practices for minimizing hydrocarbon emissions. 3. The Permittee shall install, maintain and operate each tank such that all the emission limits in this permit will be met. 15 During the inspection, EPA inspectors observed continuous emissions from the condensate tanks with the FLIR. 4. The Permittee shall ensure that the produced water storage tank is an enclosed tank. During the inspection, EPA inspectors observed continuous emissions from the condensate tanks with the FLIR. 5. The Permittee shall limit the hydrocarbon emissions from handling natural gas condensate using one or more of the following techniques: (a) Route all hydrocarbon emissions through a closed-vent system to an operating system designed to recover and inject the emissions into a natural gas gathering pipeline system for sale or other beneficial purpose; and/or (b) Route all hydrocarbon emissions through a closed-vent system to a control device as specified in the Requirements for Control Systems for Hydrocarbon Emissions section of this permit. During the inspection, EPA inspectors observed continuous emissions from the condensate tanks with the FLIR. 6. Covers: The Permittee shall equip all openings on each natural gas condensate tank with a cover to ensure that all hydrocarbon emissions are efficiently being routed through a closed-vent system to a natural gas pipeline system for sale or other beneficial purpose and/or a control device as specified in the Requirements for Control Systems for Hydrocarbon Emissions section of this permit. (a) The Permittee shall ensure that each cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves, and gauge wells) form a continuous impermeable barrier over the entire surface area of the tanks. During the inspection, EPA inspectors observed continuous emissions from the condensate tanks with the FLIR. In the monthly AVO documents sent to the EPA after the inspection, EPA inspectors did not find any records of leak. During the inspection, Josh Swann confirmed that Arrow Pipelines LLC does not own or use FLIR camera to observe VOC leaks. (b) Each cover opening shall be secured in a closed, sealed position (e.g., covered by a gasketed lid or cap) whenever material is in a tank on which the cover is installed except during those times when it is necessary to use an opening as follows: (i) To add material to, or remove material from the tank (this includes openings necessary to equalize or balance the internal pressure of the tank following changes in the level of the material in the tank); (ii) To inspect or sample the material in the tank; or (iii) To inspect, maintain, repair, or replace equipment located inside the tank. 16 (c) Each thief hatch cover shall be weighted and properly seated. (d) Pressure relief valves shall be set to release at a pressure that will ensure that all hydrocarbon emissions are routed through the closed-vent system to a natural gas pipeline system for sale or other beneficial purpose and/or a control device as specified in the Requirements for Control Systems for Hydrocarbon Emissions section of this permit under normal operating conditions. 7. Monitoring Requirements (a) The Permittee shall perform quarterly visual inspections of the natural gas condensate tank covers, thief hatches, seals, pressure relief valves, and closed-vent systems to ensure proper condition and functioning and repair any damaged equipment. The quarterly inspections shall be performed while the tanks are being filled. EPA inspectors received monthly AVO inspection records from Arrow Pipelines from September 2022 to May 2023. However, during the inspection, Josh Swann confirmed that they do not use any equipment, such as FLIR to observe and detect leaks. (b) The Permittee shall perform quarterly inspections of each closed-vent system and control device of each natural gas condensate storage tank as specified in the Requirements for Equipment Leaks from Closed-Vent Systems section of this permit to ensure that the pressure and vacuum relief set-points are not being exceeded in a way that has resulted, or may result, in venting of hydrocarbon emissions and possible damage to equipment. EPA inspectors received monthly AVO inspection records from Arrow Pipelines from September 2022 to May 2023. However, during the inspection, Josh Swann confirmed that they do not use any equipment, such as FLIR to observe and detect leaks. (c) The Permittee shall follow the instructions in the "Onshore Oil and Gas Operations; Federal and Indian Oil & Gas Leases; Onshore Oil and Gas Order No. 4; Measurement of Oil," Section 111.C; "Oil Measurement by Tank Gauging," developed by the US Department of the Interior's Bureau of Land Management, to measure the volume of produced water and natural gas condensate routed to each tank to use in subsequently determining the volume of produced water and natural gas condensate processed through the station as required in the Requirements for Emission Limits, Construction and Operation section of this permit. Other measurement methods may be used upon prior written approval by the EPA. [Note: The EPA is incorporating by reference the measurement methodologies described in this document only. There are no other enforcement implications intended. The Onshore Oil and Gas Operations; Federal and Indian Oil & Gas Leases; Onshore Oil and Gas Order No. 4 can be found 43 CFR 3160; Federal RegisterNol. 54, No. 36 or on line at https:/lwww.blm.gov/programs/energy-and-mineralsloil-and-gas/operations- and production/anshore-orde rs7 17 (d) The Permittee shall calculate the VOC and HAP emissions from each tank. The VOC and HAP emissions at the station shall be determined using: the measured monthly volume of produced water and natural gas condensate routed to the tanks; the most recent extended laboratory analysis of the produced water and natural gas condensate entering the station as required in the Requirements for Emission Limits, Construction and Operation section of this permit; E&P Tanks V2.0 and/or EPA Tanks 4.0.9d, as appropriate; and the most recent tested control efficiency of the control device being used, as required in the Requirements for Emission Limits, Construction and Operation section of this permit. Other calculation methods may be used upon prior written approval by the EPA. Arrow Pipelines submitted the calculation of VOC and HAPs emission from each tank in the most recently submitted annual emission inventory on March 29, 2023. 8. Record Keeping Requirements (a) The Permittee shall maintain records of the monthly volume of produced water and natural gas condensate handled by each tank. In the documents sent by Arrow Pipelines LLC after the inspection, EPA inspectors observed monthly volume of produced water and condensate measured in tank levels. (b) The Permittee shall maintain a record of all quarterly inspections. All inspection records shall include, at a minimum, the following information: (i) The date of the inspection; (ii) The findings of the inspection; (iii) Any required repairs; and (iv) The inspector's name and signature. In the documents sent by Arrow Pipelines after the inspection, EPA inspectors confirmed above information are included in the daily monitoring worksheet (separate from monthly AVOs). (c) The Permittee shall maintain records of the date of installation of each tank, the manufacturer's recommended maintenance schedule and procedures or equivalent procedures developed by the Permittee or vendor and all scheduled maintenance and repairs. (d) The Permittee shall maintain records of the VOC and HAP emission calculations for each tank. Arrow Pipelines submitted the calculation of VOC and HAP emissions for each tank ins annual emission inventory. EPA has received the most recent emission inventory on March 29, 2023. E. Requirements for Control Systems for Hydrocarbon Emissions 1. Closed-Vent Systems: The Permittee shall meet the following requirements for closedvent systems: (a) Each closed-vent system shall route all hydrocarbon emissions from the natural gas condensate tanks to a natural gas pipeline system for sale or other beneficial 18 purpose and/or a control device as specified in this section of the permit. (b) All vent lines, connections, fittings, valves, pressure relief valves, or any other appurtenance employed to contain and collect hydrocarbon emissions from the natural gas condensate tanks to transport them to a natural gas pipeline system for sale or other beneficial purpose and/or a control device as specified in this section of the permit shall be maintained and operated properly at all times. (c) Each closed-vent system shall be designed to operate with no detectable hydrocarbon emissions, as required in the Requirements for Equipment Leaks from Closed-Vent Systems section of this permit. (d) If any closed-vent system contains one or more bypass devices that could be used to divert all or a portion of the hydrocarbon emissions, from entering a natural gas pipeline system for sale or other beneficial purpose and/or a control device as specified in this section of the permit, the Permittee shall meet one of following requirements for each bypass device: (i) At the inlet to the bypass device that could divert the hydrocarbon emissions away from a natural gas pipeline or a control device and into the atmosphere, properly install, calibrate, maintain, and operate a flow indicator that is capable of taking continuous readings and sounding an alarm when the bypass device is open such that hydrocarbon emissions are being, or could be, diverted away from a natural gas pipeline or a control device and into the atmosphere; or (ii) Secure the bypass device valve installed at the inlet in the non-diverting position using a car-seal or a lock-and-key type configuration. (e) Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devices are not subject to the requirements applicable to bypass devices. During the inspection, EPA inspectors observed continuous emissions from the condensate tanks with the FLIR. 2. Enclosed Combustors and Utility Flares: The Permittee shall meet the following requirements for enclosed combustors and utility flares: (a) Follow, for each enclosed combustor or utility flare, manufacturer and/or vendor written operating instructions, procedures and maintenance schedules or equivalent operating instructions, procedures, and maintenance schedules developed by the Permittee or vendor to ensure good air pollution control practices for minimizing hydrocarbon emissions; (b) Ensure, for each enclosed combustor or utility flare, that there is sufficient capacity to reduce the mass content of VOCs in the hydrocarbon emissions routed to it by at least 95% for the minimum and maximum volumetric flow rate and BTU content routed to the device; 19 (c) Operate each enclosed combustor or utility flare such that the mass content of VOCs in the hydrocarbon emissions routed to it are reduced by at least 95%; and (d) Ensure that each utility flare is designed and operated in accordance with requirements of the General Provisions for the New Source Performance Standards (NSPS subpart A) at 60.18(b), for such flares except for 60.18(c)(2) and 60.18()(2) for those utility flares operated with an auto ignition system. (e) The Permittee shall ensure that each enclosed combustor is: (i) A model demonstrated by a manufacturer to the meet the 95% VOC destruction efficiency requirements of the New Source Performance Standards for Natural Gas Production, Transmission and Distribution at 40 CFR part 60, subpart 0000 (NSPS 0000), using the procedure specified in 60.5413(d), by the due date of the first annual report; or (ii) Demonstrated to meet the 95% VOC destruction efficiency requirements of NSPS 0000 using EPA-approved performance test methods specified in 60.54 l 3(b). (f) The Permittee shall ensure that each enclosed combustor and utility flare is: (i) Operated properly at all times that hydrocarbon emissions are routed to it; (ii) Operated with a liquid knock-out system to collect any condensable vapors (to prevent liquids from going through the control device); (iii) Equipped with a flash-back flame arrestor; (iv) Equipped with one of the following: (A) A continuous burning pilot flame, a thermocouple, and a malfunction alarm and notification system if the pilot flame fails; or (BJ An electronically controlled auto-ignition system with a malfunction alarm and notification system if the flame fails while hydrocarbon gas emissions are flowing to the enclosed combustor or utility flare. (v) Equipped with a continuous recording device, such as a chart recorder, data logger or similar device, or connected to a SCADA system, to monitor and document proper operation of the enclosed combustor or utility flare; (vi) Maintained in a leak-free condition; and (vii) Operated with no visible smoke emissions, as defined in EPA Reference Method 22 of 40 CFR part 60, appendix A. During the inspection, EPA inspectors observed continuously lit pilot flame on the flare and 20 no visible emissions (smoke). At the time of the inspection, Station 7 was not actively flaring. 3. Other Control Devices: Upon written approval by the EPA, the Permittee may use control devices other than those listed above that are capable of reducing the mass content of VOCs in the hydrocarbon emissions routed to it by at least 95%, provided that: (a) In operating such control devices, the Permittee shall follow the manufacturer's written operating instructions, procedures, and maintenance schedules or equivalent operating instructions, procedures, and maintenance schedules developed by the Permittee or vendor to ensure good air pollution control practices for minimizing hydrocarbon em1ss10ns; (b) The Permittee shall ensure there is sufficient capacity to reduce the mass content of VOCs in the hydrocarbon emissions routed to such other control devices by at least 95% for the minimum and maximum natural gas volumetric flow rate and BTU content routed to each device; and (c) The Permittee shall operate such a control device to reduce the mass content of VOCs in the hydrocarbon emissions routed to it by at least 95%. 4. Testing Requirements: Within 180 days after initial startup at each station, and every 5 years thereafter, the Permittee shall conduct a performance test of the closed-vent system to demonstrate that it is operating in a leak free condition, and a performance test of the control device to which hydrocarbon emissions are routed, to demonstrate 95% destruction efficiency. (a) Testing of the closed-vent system shall be conducted in accordance with EPA Reference Method 21, listed in 40 CFR part 60, appendix A. (b) Testing of the enclosed combustor VOC destruction efficiency shall be conducted in accordance with EPA Reference Method 25A, listed in 40 CFR part 60, appendix A. (c) A 95% VOC destruction efficiency can be assumed for utility flares provide they are designed and operated in accordance with 60.18(b) of NSPS subpart A. (d) The Permittee may submit a written request to the EPA for an alternate testing method, but shall only use that test method upon receipt of written approval by the EPA. 5. Monitoring Requirements: (a) The Permittee shall monitor the operation of each enclosed combustor and utility 21 flare to confirm proper operation as follows: (i) Continuously monitor the enclosed combustor and utility flare operation, using a malfunction alarm and notification system for failures, and checking the alarm and notification system for proper operation whenever an operator is on site, at a minimum quarterly; (ii) Monitor for visible smoke during operation of any enclosed combustor or utility flare each time an operator is on site, at a minimum quarterly. Upon observation of visible smoke, use EPA Reference Method 22 of 40 CFR part 60, appendix A, to confirm that no visible smoke emissions are present for more than 2 minutes in any hour. The observation period shall be 1 hour; and (iii) Respond to any observation of improper monitoring equipment operation or any malfunction and notification alarm system to ensure the monitoring equipment is returned to proper operation as soon as practicable and safely possible after an observation or an alarm sounds. During the inspection, EPA inspectors observed daily monitoring AVO worksheet for flare operations. (b) Where sufficient to meet the monitoring requirements the Permittee may use a SCADA system to monitor and record the required data. (c) The Permittee shall calculate VOC, NOx, CO and HAP emissions from each enclosed combustor and utility flare using the following: (i) The monitored volume of hydrocarbon emissions from the produced water storage tank and natural gas condensate tanks, as required in the Requirements for Tanks section of this permit; (ii) The most recent extended laboratory analysis of the produced water and natural gas condensate received at each station; (iii) The most recent performance test results of the closed-vent system and control device; and (iv) The emission factors in AP-42 Chapter 1.4, Natural Gas Combustion. The calculation of VOC, NOx, CO and HAP emissions are included in the annual emissions inventory. The most recent annual emissions inventory was submitted to the EPA on March 29, 2023. 6. Recordkeeping Requirements The Permittee shall keep records of the following: (a) The site-specific design input parameters provided by the manufacturer or vendor and used to properly size the control device to assure the minimum 95% reduction requirements; (b) All required monitoring of the control device operations; 22 (c) Any deviations from the operating parameters specified in the manufacturer or vendor site-specific designs. The records shall include the control's total operating time during the calendar month in which the exceedance occurred, the date, time and length of time that the parameters were exceeded, and the corrective actions taken and any preventative measures adopted to operate the controls within that operating parameter; (d) Any instances in which any closed-vent system or control device was bypassed or down in each calendar month, the reason for each incident, its duration, and the corrective actions taken and any preventative measures adopted to avoid such bypasses or downtimes; (e) Any instances in which the pilot flame is not present in an enclosed combustor or the utility flare while hydrocarbon emissions are vented to it, the date and times that the pilot was not present and the corrective actions taken or any preventative measures adopted to improve the operation of the pilot flame; (f) Any instances in which the thermocouple (or other heat sensing monitoring device) installed to detect the presence of a flame in an enclosed combustor or engineered flare while hydrocarbon emissions are vented to it is not operational, the time period during which it was not operational, and the corrective measures taken; (g) Any instances in which the recording device installed to record data from the thermocouple is not operational; (h) Any time periods in which visible emissions are observed emanating from a control system; and (i) The VOC, NOx, CO, and HAP emissions calculations included in the consecutive 12- month total for all units covered by this permit. F. Requirements for Truck Loading Operations EPA inspectors did not make observations regarding truck loading observations during FY23 inspection. 1. The Permittee shall operate truck loading operations such that the emission limits in this permit are met. 2. The Permittee shall install, operate and maintain a piping system designed for submerged loading by either bottom loading or loading through a submerged fill pipe. The submerged fill pipe shall be no more than 12 inches from the bottom of the truck tank. The Permittee shall not conduct truck loading operations unless submerged loading is used. 3. Monitoring Requirements: VOC and HAP emissions from the truck loading operations for each calendar month shall be calculated by the Permittee using the following: 23 (a) The total measured volume of produced water and natural gas condensate, in barrels, loaded for the month; (b) The actual physical and chemical properties of the produced water and natural gas condensate and its associated vapors from the most recent extended laboratory analysis of the produced water and natural gas condensate received at the station; and (c) The procedures outlined in AP-42 Chapter 5.2, Transportation and Marketing of Petroleum Liquids for the actual method of truck loading for VOC, and HAP emissions. 4. Recordkeeping Requirements (a) Records shall be kept by the Permittee of the manufacturer and/or vendor specifications or equivalent specifications developed by the Permittee or vendor, and all scheduled maintenance and repairs on the truck loading equipment. (b) Records shall be kept of the VOC and HAP emissions calculations included in the consecutive 12-month total for all units covered by this permit. G. Requirements for Pneumatic Pumps, Pneumatic Controllers and Compressor Blowdowns Pneumatic Pumps, Pneumatic Controllers and Compressor Blowdowns were not observed during the FY23 inspection. 1. Pneumatic Pumps and Controllers (a) The Permittee shall install, maintain, and operate any pneumatic pumps and controllers such that the consecutive 12-month emission limit requirements in this permit will be met. This shall be achieved by meeting one or more of the following emission control techniques: (i) (ii) (iii) (iv) (v) (vi) Operate air actuated controllers and pneumatic pumps; Operate solar or electric actuated controllers and pneumatic pumps; Operate low-bleed natural gas actuated controllers (6 standard cubic feet per hour); Operate no-bleed natural gas actuated controllers; Route any natural gas emissions discharge streams to an operating system designed to recover and inject the emissions into a natural gas gathering pipeline system for sale or other beneficial purpose, such as fuel supply; and/or Route any natural gas emissions discharge stream to a control device as specified in the Requirements for Control Systems for Hydrocarbon Emissions section of this permit. 24 (b) Each natural gas actuated pneumatic pump and controller shall be operated and maintained according to the manufacturer or vendor specifications or equivalent specifications developed by the Permittee or vendor. (c) Records shall be kept of the date of installation of each natural gas actuated pneumatic pump and controller. (d) Records shall be kept of a description of the steps taken to minimize the emissions from any natural gas actuated pneumatic pump and controller, and a description of emission estimation methods used to calculate VOC and HAP emissions. (e) Emissions from all natural gas actuated pneumatic pumps and controllers shall be included in the entire gathering and transmission operation's consecutive 12-month total. 2. Compressor Blowdowns (a) During manual and automated blow down episodes associated with maintenance or repair, hydrate clearing, emergency operations, equipment depressurization, etc., the Permittee shall limit emissions such that the emission limits in this permit are met. (b) The Permittee' s personnel shall remain on site during manual blow downs. (c) The Permittee shall keep records of the date and time of each compressor blowdown event, the volume of gas released during the episode, calculated based on a representative emission factor, and a description of emission estimation methods used to calculate the VOC and HAP emissions. (d) Compressor blowdown emissions shall be included in the consecutive 12-month total of all units covered by this permit. I. Requirements for Equipment Leaks from Closed-Vent Systems 1. The Permittee shall minimize leaks of hydrocarbon gases from each vent line, connection, fitting, valve, pressure relief device, or any other appurtenance employed to contain and collect hydrocarbon emissions to transport them such that the emission limits in this permit are met. During the inspection EPA inspectors observed continuous VOC emissions from condensate/produced water tanks with the FLIR camera. EPA inspectors confirmed the observation with Josh Swann who was able to agree using the FLIR camera. EPA received the follow up work performed on the tanks to mitigate continuous emissions, by email on July 3, 2023. 2. The Permittee shall develop a written leak inspection and repair protocol that, at a minimum, specifies the following: 25 (a) A detailed description of the procedures to be used for leak detection, which may include, but is not limited to, audio, visual, and/or or olfactory techniques; (b) A schedule of inspections to be conducted, at a minimum, quarterly; (c) A definition of when a "leak" is detected; (d) A repair schedule for leaking equipment (including delay ofrepair); and (e) A log book that contains a list, summary description, and diagram showing the location of all equipment that is part of a closed-vent system at the facility, and a record of type of inspections performed, the date of inspections, the results of the inspections, and the date of repairs performed on leaking equipment. 3. In the event that the EPA determines that the protocol on record is not meeting its intended goals, the Permittee shall develop a revised protocol upon request by the EPA. 4. Total emissions from equipment leaks shall be determined by assuming 8,760 hours of operation in a year and with maximum leakage of all components from equipment in hydrocarbon service. J. Requirements for Minimizing Fugitive Dust EPA inspectors did not make observations regarding fugitive dusts during the inspection in FY23 inspection. 1. Work Practice and Operational Requirements (a) The Permittee shall take all reasonable precautions to prevent fugitive dust emissions at each station and shall construct, maintain, and operate each station to minimize fugitive dust emissions. Reasonable precautions include, but are not limited to the following: (i) Use, where possible, of water or chemicals for control of dust during construction and operations, grading of roads, or clearing of land; (ii) Application of asphalt, water, or other suitable chemicals on unpaved roads, materials stockpiles, and other surfaces, located at the facilities, that can create airborne dust; (iii) The prompt removal from paved surfaces, located at the station, of earth or other material that does or may become airborne; or (iv) Restricting vehicle speeds. (b) The Permittee shall prepare and implement a written fugitive dust emission prevention plan, approved by the EPA, that specifies the reasonable precautions to 26 be taken and the procedures to be followed to prevent fugitive dust emissions. 2. Monitoring Requirements (a) The Permittee shall survey the station during construction and operation to determine if there are obvious visible dust plumes. This survey must be done at a minimum once per week in all active areas and during daylight hours. (b) The Permittee shall document the results of the survey, including the date and time of the survey, identification of the cause of any visible dust plumes observed, and the precautions taken to prevent continued fugitive dust emissions. 3. Recordkeeping Requirements The Permittee shall maintain records for 5 years that document the fugitive dust prevention plan, the periodic surveys, and the reasonable precautions that were taken to prevent fugitive dust em1ss10ns. K. Requirements for Records Retention 1. The Permittee shall retain all records required by this permit for a period of at least 5 years from the date the record was created. 2. Records shall be kept in the vicinity of the facility, such as at the facility, the location that has day-to-day operational control over the facility, or the location that has day-to-day responsibility for compliance of the facility. L. Requirements for Reporting 1. Annual Emission Reports (a) The Permittee shall submit a written annual report of the actual annual emissions from all emission units at the facility covered under this permit, including emissions from start ups, shutdowns, and malfunctions, each year no later than April 1st The annual report shall cover the period for the previous calendar year. All reports shall be certified to truth and accuracy by the person primarily responsible for Clean Air Act compliance for the Permittee. (b) The report shall include facility-wide emission ofNOx, CO, VOC, each individual HAP, and total HAP emissions. (c) The report shall be submitted to: 27 U.S. Environmental Protection Agency, Region 8 Office of Partnerships and Regulatory Assistance Tribal Air Permitting Program, 8P-AR 1595 Wynkoop Street Denver, Colorado 80202 The report may be submitted via electronic mail to r8AirPermitting@epa.gov. 2. All other documents required to be submitted under this permit, with the exception of the Annual Emission Reports, shall be submitted to: U.S. Environmental Protection Agency, Region 8 Office of Enforcement, Compliance & Environmental Justice Air Toxics and Technical Enforcement Program, 8ENF-AT 1595 Wynkoop Street Denver, Colorado 80202 All documents may be submitted electronically to r8airreportenforcement@epa.gov. Annual Emissions Report of Station 7 has been received electronically through the email listed above. 3. The Permittee shall promptly submit to the EPA a written report of any deviations of permit requirements and a description of the probable cause of such deviations and any corrective actions or preventative measures taken. A "prompt" deviation report is one that is post marked or submitted via electronic mail to r8airreportenforcement(a).epa.gov as follows: (a) Within 30 days from the discovery of any deviation of the emission or operational limits that is left un-corrected for more than 5 days after discovering the deviation; and (b) By April 1st for the discovery of a deviation of recordkeeping or other permit conditions during the preceding calendar year that do not affect the Permittee's ability to meet the emission limits. Annual Deviation Report for Station 7 was received electronically on March 30, 2023. 4. The Permittee shall submit a written report for any required performance tests to the EPA Regional Office within 60 days after completing the tests. 5. The Permittee shall submit any record or report required by this permit upon EPA request. 28 II. General Provisions A. Conditional Approval Pursuant to the authority of 40 CFR 49.151, the EPA hereby conditionally grants this permit to construct. This authorization is expressly conditioned as follows: 1. Document Retention and Availability: This permit and any required attachments shall be retained and made available for inspection upon request at the location set forth herein. 2. Permit Application: The Permittee shall abide by all representations, statements of intent and agreements contained in the application submitted by the Permittee. The EPA shall be notified 10 days in advance of any significant deviation from this permit application as well as any plans, specifications or supporting data furnished. 3. Permit Deviations: The issuance of this permit may be suspended or revoked if the EPA determines that a significant deviation from the permit application, specifications, and supporting data furnished has been or is to be made. If the proposed source is constructed, operated, or modified not in accordance with the terms of this permit, the Permittee will be subject to appropriate enforcement action. 4. Compliance with Permit: The Permittee shall comply with all conditions of this permit, including emission limitations that apply to the affected emissions units at the permitted facility/source. Noncompliance with any permit term or condition is a violation of this permit and may constitute a violation of the Clean Air Act and is grounds for enforcement action and for a permit termination or revocation. 5. Fugitive Emissions: The Permittee shall take all reasonable precautions to prevent and/or minimize fugitive emissions during the construction period. 6. National Ambient Air Quality Standard and PSD Increment: The permitted source shall not cause or contribute to a National Ambient Air Quality Standard violation or a PSD increment violation. 7. Compliance with Federal and Tribal Rules, Regulations, and Orders: Issuance of this permit does not relieve the Permittee of the responsibility to comply fully with all other applicable federal and tribal rules, regulations, and orders now or hereafter in effect. 8. Enforcement: It is not a defense, for the Permittee, in an enforcement action, to claim that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 29 9. Modifications of Existing Permitted Emission Units/Limits: For proposed modifications, as defined at 49.152(d), that would increase an emissions unit's allowable emissions of pollutants above its existing permitted annual allowable emissions limit, the Permittee shall first obtain a permit modification pursuant to the MNSR regulations approving the increase. For a proposed modification that is not otherwise subject to review under the PSD or MNSR regulations, such proposed increase in the annual allowable emissions limit shall be approved through an administrative permit revision as provided at 49.159(). 10. Relaxation of Legally and Practically Enforceable Limits: At such time that a new or modified source within this permitted facility/source or modification of this permitted facility/source becomes a major stationary source or major modification solely by virtue of a relaxation in any legally and practically enforceable limitation which was established after August 7, 1980, on the capacity of the permitted facility/source to otherwise emit a pollutant, such as a restriction on hours of operation, then the requirements of the PSD regulations shall apply to the source or modification as though construction had not yet commenced on the source or modification. 11. Revise, Reopen, Revoke and Reissue, or Terminate for Cause: This permit may be revised, reopened, revoked and reissued, or terminated for cause. The filing of a request by the Permittee, for a permit revision, revocation and reissuance, or termination, or of a notification of planned changes or anticipated noncompliance does not stay any permit condition. The EPA may reopen this permit for a cause on its own initiative, e.g., if this permit contains a material mistake or the Permittee fails to assure compliance with the applicable requirements. 12. Severability Clause: The provisions of this permit are severable, and in the event of any challenge to any portion of this permit, or if any portion is held invalid, the remaining permit conditions shall remain valid and in force. 13. Property Rights: This permit does not convey any property rights of any sort or any exclusive privilege. 14. Information Requests: The Permittee shall furnish to the EPA, within a reasonable time, any information that the EPA may request in writing to determine whether cause exists for revising, revoking and reissuing, or terminating this permit or to determine compliance with this permit. For any such information claimed to be confidential, you shall also submit a claim of confidentiality in accordance with 40 CFR part 2, subpart B. 15. Inspection and Entry: The EPA or its authorized representatives may inspect this permitted facility/source during normal business hours for the purpose of ascertaining compliance with all conditions of this permit. Upon presentation of proper credentials, the Permittee shall allow the EPA or its authorized representative to: 30 (a) Enter upon the premises where this permitted facility/source is located or emissions related activity is conducted, or where records are required to be kept under the conditions of this permit; (b) Have access to and copy, at reasonable times, any records that are required to be kept under the conditions of this permit; (c) Inspect, during normal business hours or while this permitted facility/source is in operation, any facilities, equipment (including monitoring and air pollution control equipment), practices, or operations regulated or required under this permit; (d) Sample or monitor, at reasonable times, substances or parameters for the purpose of assuring compliance with this permit or other applicable requirements; and (e) Record any inspection by use of written, electronic, magnetic and photographic media. 16. Permit Effective Date: This permit is effective immediately upon issuance unless comments resulted in a change in the proposed permit, in which case the permit is effective 30 days after issuance. The Permittee may notify the EPA, in writing, that this permit or a term or condition of it is rejected. Such notice should be made within 30 days ofreceipt of this permit and should include the reason or reasons for rejection. 17. Permit Transfers: Permit transfers shall be made in accordance with 40 CFR 49.l 59(f). The Air Program Director shall be notified in writing at the address shown below if the company is sold or changes its name. U.S. Environmental Protection Agency, Region 8 Office of Partnerships & Regulatory Assistance Tribal Air Permitting Program, 8P-AR 1595 Wynkoop Street Denver, Colorado 80202 18. Invalidation of Permit: This permit becomes invalid if construction is not commenced within 18 months after the effective date of this permit, construction is discontinued for 18 months or more, or construction is not completed within a reasonable time. The EPA may extend the 18-month period upon a satisfactory showing that an extension is justified. This provision does not apply to the time period between the construction of the approved phases of a 31 phased construction project. The Permittee shall commence construction of each such phase within 18 months of the projected and approved commencement date. 19. Notification of Start-Up: The Permittee shall submit a notification of the anticipated date of initial start-up of this permitted source to the EPA within 60 days of such date, unless this permitted source is an existing source. 32