DRAFT OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION MEMORANDUM November 22, 2016 TO: THROUGH: THROUGH: THROUGH: FROM: SUBJECT: Phillip Fielder, P.E., Permits and Engineering Group Manager Rick Groshong, Environmental Manager, Compliance and Enforcement Richard Kienlen, P.E., Engr. Mgr. II, New Source Permits Section Amalia Talty, E.I., Existing Source Permit Section Sharon Alder, E.I., New Source Permit Section Evaluation of Operating Permit Application No. 2016-0664-O Citation Oil and Gas Corporation Healdton Arbuckle Unit (SIC 1311) Facility ID.: 15568 Latitude: 34.23559 N, Longitude: 97.509309 W Section 3, Township 4S, Range 3W, Carter County, Oklahoma Directions: From the intersection of SW 8 th St. and E. Texas in Healdton, travel west for 1 mile, north on Red Steele Rd. for 0.2 miles to the site gate. INTRODUCTION Citation Oil and Gas Corporation (Citation) has submitted an individual minor source operating permit application for their Healdton Arbuckle Unit (SIC 1311/NAICS 211111) in Carter County, Oklahoma. The facility does not have any current permits from the Department of Environmental Quality, Air Quality Division (DEQ, AQD). The facility is currently a potential major source for sulfur dioxide (SO 2 ) emissions and volatile organic compounds (VOC). The facility is not a new major stationary source under the new source review requirements of the Federal Clean Air Act (FCAA), Part C (Prevention of Significant Deterioration [PSD]). Citation requests a federally enforceable limitation of 11.15 million standard cubic feet per year (MMScf/yr) of produced gas, with a 5% hydrogen sulfide (H 2 S) concentration, to be sent to the emergency flare to maintain SO 2 emissions below major source thresholds for PSD. Therefore, the facility will be a synthetic minor source. The facility consists of the two (2) 2.0-MMBtu/hr heater treaters, one (1) 9.28-MMBtu/hr emergency flare, one (1) 0.96-MMBtu/hr vapor combustor unit, one (1) 0.28-MMBtu/hr vapor combustor unit, four (4) 500-bbl crude oil storage tanks, four (4) 1,500-bbl crude oil storage tanks, two (2) 500-bbl produced water storage tanks, two (2) 3,000-bbl produced water storage tanks, sales oil truck loading, and various support operations.
PERMIT MEMORANDUM 2016-0664-O DRAFT 2 A self-disclosure was submitted under separate cover to address potential compliance issues, and was closed on February 23, 2016. Issuance of this permit will resolve the compliance and enforcement issues. The four (4) 500-bbl crude oil storage tanks (EUG-1) were constructed July 2014, which is after August 23, 2011, however, the potential emissions from these tanks are under six (6) TPY, because flash emissions occur before the crude oil is sent to these four (4) crude oil sales tanks and they are vented to the atmosphere (uncontrolled). Therefore, they are not affected sources under New Source Performance Standards (NSPS) Subpart OOOO. All other storage tanks were constructed prior to the August 23, 2011 applicability date. Therefore, they are not subject to NSPS Subpart OOOO. This facility qualifies for a synthetic minor permit because the controlled emissions of each of the criteria pollutants are below the major source threshold of 100 TPY and the HAP emissions are below the 10 TPY threshold for a single HAP and below the 25 TPY threshold for any combination of HAPs. PROCESS DESCRIPTION Healdton Arbuckle Unit (HAU) Incoming crude oil, produced water and produced gas enters the inlet separators where fluids are separated. From the inlet separators, liquids are sent to the free-water knockouts (FWKO), and gas is transmitted to a sales pipeline. From the FWKOs, produced water is routed to the water storage tanks; oil and gas are sent through the Chem Electric separator where the gas and oil are transmitted to the crude oil tanks. Any additional water separated out is routed to the water storage tanks. From the crude oil storage tanks, oil is routed to the crude oil sales tank, where it is loaded into tanker trucks and delivered to customers. Produced water is injected into the subsurface. Emissions from the crude oil and produced water storage tanks, as well as from the crude oil loading activities, are controlled by an enclosed vapor combustor unit. The crude oil sales tank (HAUTK5) is vented to the atmosphere. As an Alternate Operating Scenario (AOS), in the event the sales pipeline is unavailable, sales gas from the HAU will be sent to the on-site emergency flare. This will occur no more than 5% of the year with an annual maximum throughput of 11.15-MMscf/yr. Healdton Unit 3 (Unit 3) Incoming crude oil and produced water enter the FWKO where the fluids are separated. From the FWKOs, produced water is routed to the water storage tanks; oil is sent through the Chem Electric separator to remove any additional water, which is then routed to the water storage tanks. Crude Oil is routed to the crude oil storage tanks and then to the crude oil sales tanks, where it is loaded into tanker trucks and delivered to customers. Produced water is sent to the injection well via pipeline. Tank vapors from the crude oil and produced water storage tanks are
PERMIT MEMORANDUM 2016-0664-O DRAFT 3 sent to a vapor combustor. Vapors from the crude oil sales tanks (U3TK5 and U3TK6) are vented to the atmosphere. Dundee Sales Tank Crude oil enters the crude oil sales tank (DTK1) through a pipeline from the Dundee Sand Unit. The crude oil is then loaded into tanker trucks and delivered to customers. Tank vapors are vented to the atmosphere. EQUIPMENT EUG-1 EU ID# Point ID# Contents Barrels Gallons HAUTK5 U3TK5 U3TK6 DTK1 EUG-2 HAUTK5 U3TK5 U3TK6 DTK1 HAU Crude Oil Sales Storage Tank Unit 3 Crude Oil Sales Storage Tank Unit 3 Crude Oil Sales Storage Tank #2 Dundee Crude Oil Sales Storage Tank Const. Date 500 21,000 July 2014 500 21,000 July 2014 500 21,000 July 2014 500 21,000 July 2014 EU ID# Point ID# Contents Barrels Gallons HAUFL2 HAUFL2 HAUFL2 HAUFL2 U3FL1 U3FL1 U3FL1 U3FL1 HAUTK1 HAUTK2 HAUTK3 HAUTK4 U3TK1 U3TK2 U3TK3 U3TK4 HAU Tank#1/Crude Oil Storage Tank HAU Tank#2/Crude Oil Storage Tank HAU Tank#3/Produced Water Storage Tank HAU Tank#4/Produced Water Storage Tank Unit 3 Tank #1/Crude Oil Storage Tank Unit 3 Tank #2/Crude Oil Storage Tank Unit 3 Tank #3/Produced Water Storage Tank Unit 3 Tank #4/Produced Water Storage Tank Const. Date 1,500 63,000 Pre-2011 1,500 63,000 Pre-2011 500 21,000 Pre-2011 500 21,000 Pre-2011 1,500 63,000 Pre-2011 1,500 63,000 Pre-2011 3,000 126,000 Pre-2011 3,000 126,000 Pre-2011
PERMIT MEMORANDUM 2016-0664-O DRAFT 4 EUG-3 EUG-4 EUG-5 EUG-6 EMISSIONS EU ID# Point ID# Contents HAUL1 HAUL1 HAU Sales Crude Oil Truck Loading U3L1 U3L1 Unit 3 Sales Crude Oil Truck Loading DL1 DL1 Dundee Sales Crude Oil Truck Loading EU ID# Point ID# Contents HAUFUG HAUFUG HAU Fugitives U3FUG U3FUG Unit 3 Fugitives EU ID# Point ID# Contents HAUHT HAUHT HAU Heater Treater U3HT U3HT Unit 3 Heater Treater EU ID# Point ID# Contents HAUFL1 HAUFL1 HAU 9.28-MMBtu/hr Emergency Flare HAUFL2 HAUFL2 HAU 0.96-MMBtu/hr Vapor Combustion Unit U3FL1 U3FL1 U3 0.28-MMBtu/hr Vapor Combustion Unit Emissions from the natural gas heaters are based on AP-42 (7/98), Section 1.4, 1,020 Btu/scf fuel heating value, and continuous operation, 8,760 hours per year. Emissions of H 2 S were calculated based on a conservative natural gas H 2 S content of 24 ppm, and maximum firing rate of the produced gas and assuming 98% conversion to SO 2. Heater Emission Factors Point NOx CO VOC Description (lb/mmscf) (lb/mmscf) (lb/mmscf) HAUHT 2.0-MMBtu/hr Heater Treater 100 84 5.5 U3HT 2.0-MMBtu/hr Heater Treater 100 84 5.5 For HAU, emissions of VOCs, H 2 S, and HAPs from the crude oil and produced water storage tanks were estimated using ProMax process simulator. The ProMax model accounts for both flash emissions from the change in liquid stream pressure from the separator to ambient conditions, and the working/breathing losses. The emissions are based on the average daily production rates, design operating pressure and temperature of separators, and the material analyses. The sales oil tank is stable oil; therefore, there are
PERMIT MEMORANDUM 2016-0664-O DRAFT 5 no flash emissions. During normal operations, emissions from the crude oil and produced water storage tanks are routed to the vapor combustor units, and the sales oil tank is vented to the atmosphere. For U3, working and breathing emissions of VOC, H 2 S, and HAPs from the crude oil and produced water storage tanks were estimated using the EPA Tanks 4.0.9d program. Flash emissions from the oil storage tanks were estimated using the lab Gas-Oil-Ratio (GOR) method. This method utilizes the lab measured GOR (reported in units of standard cubic feet (scf) of flash gas/barrels of oil produced), pressure, temperature, and molecular weight of the flash gas from the lab analysis, combined with the daily throughput resulting in flash emissions from the tanks based on the ideal gas law. Similarly, flash emissions from the produced water tanks were estimated using the lab Gas-Water-Ratio (GWR) reported in units of scf of flash gas/barrels of water produced. The sales oil tanks working and breathing emissions were estimated using EPA Tanks 4.0.9d. For the Dundee Sales Oil Tank, emissions of VOC, H 2 S, and HAPs were estimated using ProMax. This model accounts for the working/breathing losses. The emissions are based on the average daily production rates, design operating pressure and temperature of separators, and the material analyses. There are no flash emissions from the stable sales oil tank. Tank vapors are vented to the atmosphere. Source Annual Throughput gal/yr Storage Tanks (VOC) Emissions Working & Flash Breathing TPY TPY Flare Capture Total VOC Efficiency (%) TPY HAUTK1 827,820 6.74 6.21 100% --- * HAUTK2 827,820 6.74 6.21 100% --- * HAUTK3 136,682,280 <0.01 11.27 100% --- * HAUTK4 136,682,280 <0.01 11.27 100% --- * HAUTK5 1,655,640 3.62 --- --- 3.62 ** U3TK1 2,928,030 10.08 13.05 100% --- * U3TK2 2,928,030 10.08 13.05 100% --- * U3TK3 533,913,240 --- 44.93 100% --- * U3TK4 533,913,240 --- 44.93 100% --- * U3TK5 2,928,030 3.63 --- --- 3.63 ** U3TK6 2,928,030 3.63 --- --- 3.63 ** DTK1 2,713,410 4.06 --- --- 4.06 ** Total 14.37 * Emissions are accounted for on the flare calculations. ** PTE is below 6TPY for the sales crude oil tanks because flashing occurs before the crude oil is sent to these tanks and they are vented to the atmosphere (not controlled by a flare). Emissions from the one (1) 9.28-MMBtu/hr emergency flare (HAUFL1), the one (1) 0.96-MMBtu/hr vapor combustor unit, and the one (1) 0.28-MMBtu/hr vapor combustor unit (VCU) (HAUFL2 and U3FL1) were estimated using the Draft TCEQ Technical Guidance Package (RG-109) for Flares and Vapor Oxidizers (10/2000), based on the
PERMIT MEMORANDUM 2016-0664-O DRAFT 6 maximum expected flow rate and heating value of each stream routed to the flare and VCUs. Under normal operating conditions, sales gas at HAU is routed to an offsite flare. When the sales line is unavailable, the gas is routed to the emergency flare assuming a maximum annual gas throughput of 11.15-MMScf. The flare and VCUs have a 99% destruction efficiency. Emissions from truck loading were calculated using Equation 1 from Section 5.2 of AP- 42 (6/08) assuming following values. L L = 12.46 SPM/T, where For HAUL1: L L is the loading loss in pounds of VOC per 1,000 gallons loaded, S is the saturation factor (0.6), P is the true vapor pressure of the liquid (3.82 psia), M is the molecular weight of the vapor (40.7 lb/lb-mole), and T is the average temperature of the liquid (535 R). For an estimated throughput of 1,655,640 gallons per year, VOC emissions are 0.82 TPY. For U3L1: L L is the loading loss in pounds of VOC per 1,000 gallons loaded, S is the saturation factor (0.6), P is the true vapor pressure of the liquid (5.34 psia), M is the molecular weight of the vapor (44.2 lb/lb-mole), and T is the average temperature of the liquid (535 R). For an estimated throughput of 5,856,060 gallons per year, VOC emissions are 5.27 TPY. For Dundee: L L is the loading loss in pounds of VOC per 1,000 gallons loaded, S is the saturation factor (0.6), P is the true vapor pressure of the liquid (3.96 psia), M is the molecular weight of the vapor (43.0 lb/lb-mole), and T is the average temperature of the liquid (535 R). For an estimated throughput of 2,713,410 gallons per year, VOC emissions are 1.65 TPY. Emissions from fugitive equipment leaks (FUG) are based on EPA s 1995 Protocol for Equipment Leak Emission Estimates (11/95, EPA-453/R-95-017), Oil and Gas Production Operations average emission factors for process piping fugitive emissions, a number of components from the facility, and a representative gas analysis from the facility.
PERMIT MEMORANDUM 2016-0664-O DRAFT 7 Facility-Wide Emissions (TPY) Point Source NO X CO VOC SO 2 H 2 S Healdton Arbuckle Unit (HAU) HAUTK1 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- HAUTK2 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- HAUTK3 500-bbl Produced Water Storage Tank --- --- --- --- --- HAUTK4 500-bbl Produced Water Storage Tank --- --- --- --- --- HAUTK5 500-bbl Sales/Crude Oil Storage Tank --- --- 3.62 --- 0.72 HAUHT 2.0-MMBtu/hr Heater Treater 0.86 0.72 0.05 0.01 <0.01 HAUFL1 9.28-MMBtu/hr Emergency Flare 1.07 2.14 3.47 47.08 0.50 HAUFL2 0.96-MMBtu/hr Vapor Combustor Unit 0.58 1.16 1.36 51.37 0.55 HAUL1 Sales Crude Oil Truck Loading --- --- 0.58 --- 0.12 HAUFUG Fugitives --- --- 2.00 --- 0.08 Total 2.51 4.02 11.08 98.46 1.96 Healdton Unit 3 (U3) U3TK1 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- U3TK2 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- U3TK3 3,000-bbl Produced Water Storage Tank --- --- --- --- --- U3TK4 3,000-bbl Produced Water Storage Tank --- --- --- --- --- U3TK5 500-bbl Sales/Crude Oil Storage Tank --- --- 3.63 --- <0.01 U3TK6 500-bbl Sales/Crude Oil Storage Tank --- --- 3.63 --- <0.01 U3HT 2.0-MMBtu/hr Heater Treater 0.86 0.72 0.05 0.01 <0.01 U3FL1 0.28-MMBtu/hr Vapor Combustor Unit 0.80 1.60 2.15 0.01 <0.01 U3L1 Sales Oil Truck Loading --- --- 5.27 --- <0.01 U3FUG Fugitives --- --- 1.55 --- --- Total 1.66 2.32 16.29 0.01 <0.01 Dundee Sales Oil Tank DTK1 500-bbl Sale/Crude Oil Storage Tank --- --- 4.06 --- --- DL1 Dundee Sales Crude Oil Truck Loading --- --- 1.65 --- --- Total --- --- 5.71 --- --- Aggregate Total 4.17 6.34 33.09 98.47 1.96 Hazardous Air Pollutants (HAP) A total emission of combined HAPs is estimated to be 0.68 TPY from process piping components and equipment leakage. OKLAHOMA AIR POLLUTION CONTROL RULES OAC 252:100-1 (General Provisions) Subchapter 1 includes definitions but there are no regulatory requirements. OAC 252:100-2 (Incorporation by Reference) This subchapter incorporates by reference applicable provisions of Title 40 of the Code of Federal Regulations. These requirements are addressed in the Federal Regulations section.
PERMIT MEMORANDUM 2016-0664-O DRAFT 8 OAC 252:100-3 (Air Quality Standards and Increments) Subchapter 3 enumerates the primary and secondary ambient air quality standards and the significant deterioration increments. At this time, all of Oklahoma is in attainment of these standards. OAC 252:100-5 (Registration, Emissions Inventory and Annual Operating Fees) Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission inventories annually, and pay annual operating fees based upon total annual emissions of regulated pollutants. Required annual information (Turn-Around Document) shall be provided to Air Quality. OAC 252:100-7 (Permits for Minor Facilities) Subchapter 7 sets forth the permit application fees and the basic substantive requirements of permits for minor facilities. Since criteria pollutant emissions are less than 100 TPY for each pollutant, and emissions of Hazardous Air Pollutants (HAP) will not exceed 10 TPY for any one HAP or 25 TPY for any aggregate of HAP, the facility is defined as a minor source. As such, BACT is not required. OAC 252:100-8 (Permits for Part 70 Sources) The potential to emit (PTE) for VOC and SO 2 exceeds Part 70 thresholds. HAP emissions do not exceed the 10/25 TPY threshold. Citation is requesting that an individual synthetic minor source permit be issued to the facility since actual emissions will be below Part 70 thresholds. OAC 252:100-9 (Excess Emission Reporting Requirements) Except as provided in OAC 252:100-9-7(a)(1), the owner or operator of a source of excess emissions shall notify the Director as soon as possible but no later than 4:30 p.m. the following working day of the first occurrence of excess emissions in each excess emission event. No later than thirty (30) calendar days after the start of any excess emission event, the owner or operator of an air contaminant source from which excess emissions have occurred shall submit a report for each excess emission event describing the extent of the event and the actions taken by the owner or operator of the facility in response to this event. Request for affirmative defense, as described in OAC 252:100-9-8, shall be included in the excess emission event report. Additional reporting may be required in the case of ongoing emission events and in the case of excess emissions reporting required by 40 CFR Parts 60, 61, or 63. OAC 252:100-13 (Open Burning) Open burning of refuse and other combustible material is prohibited except as authorized in the specific examples and under the conditions listed in this subchapter. OAC 252:100-19 (Particulate Matter (PM)) This subchapter specifies a particulate matter (PM) emissions limitation of 0.6 lb/mmbtu for all fuel-burning equipment at this facility. AP-42 (7/00), Section 3.2, lists the total PM emissions from a natural gas fueled engine to be 0.0483 lb/mmbtu; AP-42 (7/98), Section 1.4 lists total PM emissions from natural gas fueled heaters to be 0.0076 lb/mmbtu. This permit requires the use of natural gas for all fuel-burning equipment to ensure compliance with Subchapter 19.
PERMIT MEMORANDUM 2016-0664-O DRAFT 9 This subchapter also limits emissions of particulate matter from industrial processes and directfired fuel-burning equipment based on their process weight rates. Since there are no significant particulate emissions from the nonfuel-burning processes at the facility compliance with the standard is assured without any special monitoring provisions. OAC 252:100-25 (Visible Emissions and Particulates) No discharge of greater than 20% opacity is allowed except for short-term occurrences that consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. In no case shall the average of any six-minute period exceed 60% opacity. The permit will require that fuel-burning units be fueled only with natural gas to ensure compliance with these requirements OAC 252:100-29 (Fugitive Dust) No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the property line on which the emissions originate in such a manner as to damage or to interfere with the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the maintenance of air quality standards. Under normal operating conditions, this facility will not cause a problem in this area; therefore it is not necessary to require specific precautions to be taken. OAC 252:100-31 (Sulfur Compounds) Part 2 limits the ambient air impact of hydrogen sulfide emissions from any new or existing source to 0.2 ppmv for a 24-hour average (equivalent to 280 µg/m 3 ). AERSCREEN dispersion modeling was performed and showed that the H 2 S impacts are 79.3 µg/m 3 for the 1-hr H 2 S concentration and 48.7 µg/m 3 for the 24-hr H 2 S concentration. This is below the limits required by this subchapter. Therefore, the facility complies with this subchapter. Part 5 also limits hydrogen sulfide emissions from new equipment (constructed after July 1, 1972). For gaseous fuels the limit is 0.2 lb/mmbtu heat input averaged over 3 hours. For fuel gas having a gross calorific value of 1,000 Btu/SCF, this limit corresponds to fuel sulfur content of 1,203 ppmv. Gas produced from oil and gas wells having 343 ppmv or less total sulfur will ensure compliance with Subchapter 31. The permit requires the use of pipeline-grade natural gas or field gas with a maximum sulfur content of 343 ppmv for all fuel-burning equipment to ensure compliance with Subchapter 31. Removal of hydrogen sulfide in the exhaust stream, or oxidation to sulfur dioxide, is required unless hydrogen sulfide emissions would be less than 0.3 lb/hr for a two-hour average. Hydrogen sulfide emissions shall be reduced by a minimum of 95% of the hydrogen sulfide in the exhaust gas. Direct oxidation of hydrogen sulfide is allowed for units whose emissions would be less than 100 lb/hr of sulfur dioxide for a two-hour average. A limit of 11.15-MMscf/d of produced gas routed to the emergency flare will ensure SO 2 emissions are below the 100 TPY limit. All emissions from the crude oil and produced water storage tanks are vented to the facility vapor combustor units (VCU) for conversion of hydrogen sulfide to sulfur dioxide at an efficiency of 100%. Part 5 requires the owner or operator shall install, maintain, and operate an alarm system that will signal a malfunction for all thermal devices used to control H 2 S emissions from petroleum and natural gas processing facilities regulated under this subparagraph. The acid gas streams will be routed to a monitored and alarmed flare for combustion to SO 2.
PERMIT MEMORANDUM 2016-0664-O DRAFT 10 Part 5 requires that a sulfur recovery unit be used if emissions of SO 2 would exceed 100 lb/hr, two-hour average. This subchapter also states any gas sweetening unit or petroleum refinery process equipment with an emission rate of 100 lb/hr or less of SO x expressed as SO 2, two-hour average, shall be considered to be below the 0.54 LT/D threshold, therefore the requirements of OAC 252:100-31-26(2) are not applicable. Emissions of SO 2 from the conversion of H 2 S to SO 2 are 68.46 lb/hr after the flare, which is less than the 100 lb/hr threshold. Therefore, a sulfur recovery unit prior to flaring is not required. OAC 252:100-33 (Nitrogen Oxides) [Not Applicable] This subchapter limits NO X emissions from new fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH to emissions of 0.2 lbs of NO X per MMBTU. There are no equipment items that exceed the 50 MMBTUH threshold. OAC 252:100-35 (Carbon Monoxide) [Not Applicable] This subchapter affects gray iron cupolas, blast furnaces, basic oxygen furnaces, petroleum catalytic cracking units, and petroleum catalytic reforming units. This facility has none of the affected sources. OAC 252:100-37 (Volatile Organic Compounds) Part 3 requires each VOC storage vessel with a capacity of more than 40,000 gallons (151m 3 ) to be a pressure vessel capable of maintaining working pressures that prevents the loss of VOCs to the atmosphere or be equipped with a vapor-loss control device. This facility collects all crude oil and produced water storage tank vapors, which are subsequently destroyed in the vapor combustor units. Sales crude oil tanks have a capacity of less than 40,000 gallons. Part 3 requires storage tanks with a capacity of 400 gallons or more and storing a VOC to be equipped with a permanent submerged fill pipe or vapor recovery system. The facility is a production facility and the storage tanks are located prior to lease custody transfer. Therefore, the storage tanks are exempt from this requirement. Part 3 requires VOC loading facilities with a throughput equal to or less than 40,000 gallons per day to be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the vehicle is greater than 200 gallons. The facility is subject to this requirement. Part 7 requires fuel-burning equipment to be operated and maintained so as to minimize VOC emissions. Temperature and available air must be sufficient to provide essentially complete combustion. Part 7 requires all effluent water separator openings that receive water containing more than 200 gallons per day of any VOC, to be sealed or the separator to be equipped with an external floating roof or a fixed roof with an internal floating roof or a vapor recovery system. There are no effluent water separators located at this facility. OAC 252:100-42 (Toxic Air Contaminants (TAC)) This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in areas of concern (AOC). Any work practice, material substitution, or control equipment required by the Department prior to June 11, 2004, to control a TAC, shall be retained, unless a modification is approved by the Director. Since no AOC has been designated there are no specific requirements for this facility at this time.
PERMIT MEMORANDUM 2016-0664-O DRAFT 11 OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) This subchapter provides general requirements for testing, monitoring and recordkeeping and applies to any testing, monitoring or recordkeeping activity conducted at any stationary source. To determine compliance with emissions limitations or standards, the Air Quality Director may require the owner or operator of any source in the state of Oklahoma to install, maintain and operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant source. All required testing must be conducted by methods approved by the Air Quality Director and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests. Emissions and other data required to demonstrate compliance with any federal or state emission limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, and submitted as required by this subchapter, an applicable rule, or permit requirement. Data from any required testing or monitoring not conducted in accordance with the provisions of this subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive use, of any credible evidence or information relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Not Applicable] Final total emissions will be less than the major source threshold of 250 TPY of any single regulated pollutant and the facility is not one of the listed stationary sources with a threshold of 100 TPY. NSPS, 40 CFR Part 60 [Not Applicable] Subparts K, Ka, Kb, VOL Storage Vessels. This subpart regulates hydrocarbon storage tanks larger than 19,813 gallons capacity for Kb and 40,000 gallons for K and Ka. The crude oil storage tanks are before any processing as there has not been any operations other than separating gas from liquids. The crude oil has not been conditioned or stabilized, nor has there been any separation of NGLs or other products. The crude oil storage tanks at the facility are prior to custody transfer. Therefore, this subpart is not applicable. Subpart GG, Stationary Gas Turbines. There are no turbines at this facility. Subpart VV, Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry. This facility is not a SOCMI plant. Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants concerns facilities that extract natural gas liquids from field gas, which this facility does not do. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. This facility does not have a natural gas sweetening operation. Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This subpart was promulgated on August 16, 2012, and affects the following sources that commence construction, reconstruction, or modification after August 23, 2011: 1. Each gas well affected facility, which is a single natural gas well. 2. Each centrifugal compressor affected facility, which is a single centrifugal compressor using wet seals that is located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment.
PERMIT MEMORANDUM 2016-0664-O DRAFT 12 3. Each reciprocating compressor affected facility, which is a single reciprocating compressor located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment. 4. Each pneumatic controller affected facility, which is: i. For the oil production segment (between the wellhead and the point of custody transfer to an oil pipeline): a single continuous bleed natural gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 SCFH. ii. For the natural gas production segment (between the wellhead and the point of custody transfer to the natural gas transmission and storage segment and not including natural gas processing plants): a single continuous bleed natural gasdriven pneumatic controller operating at a natural gas bleed rate greater than 6 iii. SCFH. For natural gas processing plants: a single continuous bleed natural gas-driven pneumatic controller. 5. Each storage vessel affected facility, which is a single storage vessel, located in the oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment. On April 12, 2013, EPA proposed revisions to NSPS, Subpart OOOO revising the affected facilities to only those storage vessels that emit more than 6 TPY and revising the definition to only include those storage vessels that contain crude oil, condensate, intermediate hydrocarbon liquids, or produced water. 6. The group of all equipment, except compressors, within a process unit is an affected facility. i. Addition or replacement of equipment for the purpose of process improvement that is accomplished without a capital expenditure shall not by itself be considered a modification under this subpart. ii. Equipment associated with a compressor station, dehydration unit, sweetening unit, underground storage vessel, field gas gathering system, or liquefied natural gas unit is covered by 60.5400, 60.5401, 60.5402, 60.5421, and 60.5422 if it is located at an onshore natural gas processing plant. 7. Sweetening units located at onshore natural gas processing plants that process natural gas produced from either onshore or offshore wells. i. Each sweetening unit that processes natural gas is an affected facility; and ii. iii. Each sweetening unit that processes natural gas followed by a sulfur recovery unit is an affected facility. Facilities that have a design capacity less than 2 long tons per day (LT/D) of hydrogen sulfide (H 2 S) in the acid gas (expressed as sulfur) are required to comply with recordkeeping and reporting requirements specified in 60.5423(c) but are not required to comply with 60.5405 through 60.5407 and 60.5410(g) and 60.5415(g) of this subpart. For each reciprocating compressor the owner/operator must replace the rod packing before 26,000 hours of operation or prior to 36 months. If utilizing the number of hours, the hours of operation must be continuously monitored. Commenced construction is based on the date of installation of the compressor (excluding relocation) at the facility. Any new or modified compressors will have to comply with this subpart. There are no compressors at the facility. Therefore, the facility is not an affect source under this subpart.
PERMIT MEMORANDUM 2016-0664-O DRAFT 13 There are no pneumatic controllers with a bleed rate of 6 SCFH and this facility is not a gas plant. Storage vessels constructed, modified or reconstructed after August 23, 2011, with VOC emissions equal to or greater than 6 TPY must reduce VOC emissions by 95.0 % or greater. The sales crude oil storage tanks (HAUTK5, U3TK5, U3TK6, and DTK1) were constructed after August 23, 2011, but prior to September 18, 2015, and are potentially affected sources under 40 CFR 60.5365. However, potential emissions are less than 6 TPY. Therefore, they are not subject to this subpart. The crude oil and produced water storage tanks (HAUTK1, HAUTK2, HAUTK3, HAUTK4, U3TK1, U3TK2, U3TK3, and U3TK4) were constructed prior to August 23, 2011, and are not subject to this subpart. The group of all equipment, except compressors, within a process unit at a natural gas processing plant must comply with the requirements of NSPS, Subpart VVa, except as provided in 60.5401. This facility is not a gas plant. NESHAP, 40 CFR Part 61 [Not Applicable] There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene, coke oven emissions, mercury, radionuclides or vinyl chloride except for trace amounts of benzene. Subpart J, Equipment Leaks of Benzene, only affects process streams which contain more than 10% benzene by weight. Analysis of Oklahoma natural gas indicates a maximum benzene content of less than 1%. All process streams at this facility are below this threshold. NESHAP, 40 CFR Part 63 [Not Applicable] Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission points that are located at facilities that are major or area sources of HAP and either process, upgrade, or store hydrocarbons prior to the point of custody transfer or prior to which the natural gas enters the natural gas transmission and storage source category. This facility is not a major source of HAP, and does not have a glycol dehydrator. Therefore, the facility is not subject to this subpart. Subpart HHH, affects Natural Gas Transmission and Storage Facilities that are major sources of HAP. This subpart applies to owners and operators of natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline and that are major sources of hazardous air pollutants (HAP) emissions. The facility does not meet the definition of a natural gas transmission or storage facility. Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable] The definition of a stationary source does not apply to transportation, including storage incident to transportation, of any regulated substance or any other extremely hazardous substance under the provisions of this part. The definition of a stationary source also does not include naturally occurring hydrocarbon reservoirs. Naturally occurring hydrocarbon mixtures, prior to entry into a natural gas processing plant or a petroleum refining process unit, including: condensate, crude oil, field gas, and produced water, are exempt for the purpose of determining whether more than a threshold quantity of a regulated substance is present at the stationary source. This facility does not store any regulated substance above the applicable threshold limits. More information on this federal program is available on the web page: https://www.epa.gov/rmp.
PERMIT MEMORANDUM 2016-0664-O DRAFT 14 Stratospheric Ozone Protection, 40 CFR Part 82 [Not Applicable] These standards require phase out of Class I & II substances, reductions of emissions of Class I & II substances to the lowest achievable level in all use sectors, and other requirements. This facility does not utilize any Class I & II substances. COMPLIANCE Tier Classification and Public Review This application has been determined to be a Tier II based on being the application for an operating permit for a major source. This facility is located within 50 miles of the Oklahoma - Texas border. A letter will be sent to the State of Texas to notify them of the draft permit The applicant published the Notice of Filing a Tier II Application in The Ardmoreite, a daily newspaper published in Carter County, on November 16, 2016. The notice stated that the application was available for public review at the Ardmore Public Library, or at the DEQ Air Quality Division s Main Office in Oklahoma City, 707 N Robinson, Oklahoma City, Oklahoma 73101. The applicant will also publish a Notice of Draft Tier II Permit. Information on all permit actions is available for review by the public in the Air Quality Section of the DEQ web page: www.deq.state.ok.us. The permittee has submitted an affidavit that they are not seeking a permit for land use or for any operation upon land owned by others without their knowledge. The affidavit certifies that the application has a current lease to accomplish the permitted process. Fee Paid A total fee of $7,500 for an individual synthetic minor source operating permit for a facility operating as a major source without a permit is required. A payment of $7,500 was received on June 20, 2016. Testing Results There is no equipment at the facility with a testing requirement. Inspection No inspection is required because the only equipment at the facility is storage tanks and flares. SUMMARY The facility is operating as described in the permit application. Ambient air quality standards are not threatened at this site. There are no active Air Quality compliance and enforcement issues concerning this facility. Issuance of the operating permit is recommended
DRAFT PERMIT TO OPERATE AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS Citation Oil and Gas Corporation Healdton Arbuckle Unit Permit No. 2016-0664-O The permittee is authorized to operate in conformity with the specifications submitted to the Air Quality Division on June 20, 2016, and supplemental information submitted on September 29, 2016. The Evaluation Memorandum dated November 22, 2016, explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Continuing operations under this permit constitutes acceptance of, and consent to, the conditions contained herein. 1. Points of emissions and emission limitations for each point. Point Source NO X CO VOC SO 2 H 2 S Healdton Arbuckle Unit (HAU) TPY HAUTK1 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- HAUTK2 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- HAUTK3 500-bbl Produced Water Storage Tank --- --- --- --- --- HAUTK4 500-bbl Produced Water Storage Tank --- --- --- --- --- HAUTK5 500-bbl Sales/Crude Oil Storage Tank --- --- 3.62 --- 0.72 HAUHT 2.0-MMBtu/hr Heater Treater 0.86 0.72 0.05 0.01 <0.01 HAUFL1 9.28-MMBtu/hr Emergency Flare 1.07 2.14 3.47 47.08 0.50 HAUFL2 0.96-MMBtu/hr Vapor Combustor Unit 0.58 1.16 1.36 51.37 0.55 HAUL1 Sales Crude oil Truck Loading --- --- 0.58 --- 0.12 Healdton Unit 3 (U3) U3TK1 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- U3TK2 1,500-bbl Crude Oil Storage Tank --- --- --- --- --- U3TK3 3,000-bbl Produced Water Storage Tank --- --- --- --- --- U3TK4 3,000-bbl Produced Water Storage Tank --- --- --- --- --- U3TK5 500-bbl Sales/Crude Oil Storage Tank --- --- 3.63 --- <0.01 U3TK6 500-bbl Sales/Crude Oil Storage Tank --- --- 3.63 --- <0.01 U3HT 2.0-MMBtu/hr Heater Treater 0.86 0.72 0.05 0.01 <0.01 U3FL1 0.28-MMBtu/hr Vapor Combustor Unit 0.80 1.60 2.15 0.01 <0.01 U3L1 Sales Oil Truck Loading --- --- 5.27 --- <0.01 Dundee Sales Oil Tank DTK1 500-bbl Sale/Crude Oil Storage Tank --- --- 4.06 --- --- DL1 Dundee Sales Crude oil Truck Loading --- --- 1.65 --- --- 2. The fuel-burning equipment shall be fired with field grade natural gas or other gaseous fuel having sulfur content less than 343 ppmv. Compliance can be shown by the following methods: for pipeline grade natural gas, a current gas company bill; for other gaseous fuel, a current lab analysis, stain-tube analysis, gas contract, tariff sheet, or other approved methods. Compliance shall be demonstrated at least once every calendar year.
SPECIFIC CONDITIONS 2016-0664-O 2 DRAFT 3. Upon issuance of the operating permit, the permittee is authorized to operate this facility continuously (24 hours per day, every day of the year, 8760 hours). 4. Each tank, to which these specific conditions apply, shall have a permanent means of identification, which distinguishes it from other equipment. 5. All emissions from the HAU tanks and loading activities shall be routed to the vapor combustion unit, HAUFL2. HAUTK5 is vented to the atmosphere. 6. All emissions from the Unit 3 tanks shall be routed to the vapor combustion unit, U3FL1. 7. At least once per quarter, the inlet and produced natural gas shall be analyzed for sulfur content. Testing shall be conducted using the Tutwiler Method, ASTM E-260 as specified in NSPS Subpart OOOO, or an equivalent method approved by Air Quality, such as a stain tube analysis to show a combined inlet concentration of H 2 S of 50,005 ppmv. The following formula shall be used to show compliance with the TPY emission limits for SO 2: ( 1 lb mole H 2S 379.1 SCF ) (1 lb mole SO 2 1 lb mole H 2 S ) SO 2 = Q inlet (C inlet C residue ) ( 1 lb mole SO 2 2,000 lb ) ( 64.065 lb SO 2 1 ton ) 0.98% Compliance with the annual emission limits of SO 2 shall be based on a 12-month rolling total. The permittee shall calculate the total SO 2 emissions from the acid gas combustion device stack based on 100% conversion of H 2 S. The calculations shall be based on monthly tested H 2 S concentration measured at the following locations: (1) facility inlet gas streams, and (2) facility outlet gas stream and the daily average inlet gas flow rate for that month. 8. The permittee shall comply with the following requirements for all vapor combustion units and emergency flares. a. The flare shall be operated at all times when emissions may be vented to it. b. The presence of a pilot flame shall be monitored using a thermocouple or any other equivalent device to detect the presence of a flame and equipped with an auto-ignite pilot system that provides automatic flare startup. The combustion device (flare) shall have an alarm system to signal non combustion of the exhaust gases. c. The vapor combustion units and emergency flare shall have a 99% destruction efficiency. 9. Venting of produced gas to the emergency flare shall not exceed 11.15-MMScf/yr.
SPECIFIC CONDITIONS 2016-0664-O 3 DRAFT 10. The permittee shall maintain records of operations as listed below. These records shall be retained on-site or at a local field office for a period of at least five years following dates of recording, and shall be made available to regulatory personnel upon request. a. For the fuel burned, the appropriate document(s), as described in Specific Condition No. 2 (updated whenever the supply changes). b. Records of crude oil throughput (monthly and 12-month rolling totals). c. Records of produced gas H 2 S content to both vapor combustion units and the emergency flare (updated quarterly) to show compliance with the limits of Specific Condition 7. d. Records of produced gas throughput to the emergency flare to show compliance with the limits in Specific Condition 9. 11. This permit supersedes all previous Air Quality operating permits for this facility, which are now canceled.
DRAFT Lee Ann Elsom, Regulatory Compliance Manager Citation Oil and Gas Corporation 144077 Cutten Road Houston, TX 77069 SUBJECT: Operating Permit No. 2016-0664-O Healdton Arbuckle Unit Facility ID No.: 15568 Section 3, Township 4S, Range 3W Healdton, Carter County, Oklahoma Dear Ms. Elsom: Enclosed is the permit authorizing operation of the referenced facility. Please note that this permit is issued subject to standard and specific conditions, which are attached. These conditions must be carefully followed since they define the limits of the permit and will be confirmed by periodic inspections. Also, note that you are required to annually submit an emission inventory for this facility. An emission inventory must be completed on approved AQD forms and submitted (hardcopy or electronically) by April 1 st of every year. Any questions concerning the form or submittal process should be referred to the Emission Inventory Staff at (405) 702-4100. Thank you for your cooperation. If you have any questions, please refer to the permit number above and contact me at sharon.alder@deq.ok.gov or (405) 702-4209. Sincerely, Sharon Alder, E.I. New Source Permit Section AIR QUALITY DIVISION Enclosure
PERMIT AIR QUALITY DIVISION STATE OF OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY 707 N. ROBINSON, SUITE 4100 P.O. BOX 1677 OKLAHOMA CITY, OKLAHOMA 73101-1677 Permit No. 2016-0664-O Citation Oil and Gas Corporation, having complied with the requirements of the law, is hereby granted permission to operate all equipment at the Healdton Arbuckle Unit in Section 3, Township 4S, Range 3W, Healdton, Carter County, Oklahoma, subject to standard conditions dated July 12, 2012, and specific conditions, both of which are attached. Phillip Fielder, P.E. Permits and Engineering Group Manager Date
MINOR SOURCE PERMIT TO OPERATE / CONSTRUCT AIR POLLUTION CONTROL FACILITY STANDARD CONDITIONS (July 12, 2012) A. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma Department of Environmental Quality (DEQ) in accordance with and under the authority of the Oklahoma Clean Air Act. The permit does not relieve the holder of the obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or ordinances. This specifically includes compliance with the rules of the other Divisions of DEQ: Land Protection Division and Water Quality Division. B. A duly issued construction permit or authorization to construct or modify will terminate and become null and void (unless extended as provided in OAC 252:100-7-15(g)) if the construction is not commenced within 18 months after the date the permit or authorization was issued, or if work is suspended for more than 18 months after it is commenced. [OAC 252:100-7-15(f)] C. The recipient of a construction permit shall apply for a permit to operate (or modified operating permit) within 180 days following the first day of operation. [OAC 252:100-7-18(a)] D. Unless specified otherwise, the term of an operating permit shall be unlimited. E. Notification to the Air Quality Division of DEQ of the sale or transfer of ownership of this facility is required and shall be made in writing by the transferor within 30 days after such date. A new permit is not required. [OAC 252:100-7-2(f)] F. The following limitations apply to the facility unless covered in the Specific Conditions: 1. No person shall cause or permit the discharge of emissions such that National Ambient Air Quality Standards (NAAQS) are exceeded on land outside the permitted facility. [OAC 252:100-3] 2. All facilities that emit air contaminants are required to file an emission inventory and pay annual operating fees based on the inventory. Instructions and forms are available on the Air Quality section of the DEQ web page. www.deq.state.ok.us [OAC 252:100-5] 3. Deviations that result in emissions exceeding those allowed in this permit shall be reported consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements. [OAC 252:100-9] 4. Open burning of refuse and other combustible material is prohibited except as authorized in the specific examples and under the conditions listed in the Open Burning subchapter. [OAC 252:100-13] 5. No particulate emissions from new fuel-burning equipment with a rated heat input of 10 MMBTUH or less shall exceed 0.6 lbs/mmbtu. [OAC 252:100-19] 6. No discharge of greater than 20% opacity is allowed except for short-term occurrences which consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. In no case shall the average of any six-minute period exceed 60% opacity. [OAC 252:100-25] 7. No visible fugitive dust emissions shall be discharged beyond the property line on which the emissions originate in such a manner as to damage or to interfere with the use of adjacent
MINOR SOURCE STANDARD CONDITIONS July 12, 2012 2 properties, or cause air quality standards to be exceeded, or interfere with the maintenance of air quality standards. [OAC 252:100-29] 8. No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2 lbs/mmbtu. No existing source shall exceed the listed ambient air standards for sulfur dioxide. [OAC 252:100-31] 9. Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia or greater under actual conditions shall be equipped with a permanent submerged fill pipe or with an organic material vapor-recovery system. [OAC 252:100-37-15(b)] 10. All fuel-burning equipment shall at all times be properly operated and maintained in a manner that will minimize emissions of VOCs. [OAC 252:100-37-36] G. Any owner or operator subject to provisions of NSPS shall provide written notification as follows: [40 CFR 60.7 (a)] 1. A notification of the date construction (or reconstruction as defined under 60.15) of an affected facility is commenced postmarked no later than 30 days after such date. This requirement shall not apply in the case of mass-produced facilities which are purchased in completed form. 2. A notification of any physical or operational change to an existing facility which may increase the emission rate of any air pollutant to which a standard applies, unless that change is specifically exempted under an applicable subpart or in 60.14(e). This notice shall be postmarked 60 days or as soon as practicable before the change is commenced and shall include information describing the precise nature of the change, present and proposed emission control systems, productive capacity of the facility before and after the change, and the expected completion date of the change. The Administrator may request additional relevant information subsequent to this notice. 3. A notification of the actual date of initial start-up of an affected facility postmarked within 15 days after such date. 4. If a continuous emission monitoring system is included in the construction, a notification of the date upon which the test demonstrating the system performance will commence, along with a pretest plan, postmarked no less than 30 days prior to such a date. H. Any owner or operator subject to provisions of NSPS shall maintain records of the occurrence and duration of any start-up, shutdown, or malfunction in the operation of an affected facility or any malfunction of the air pollution control equipment. [40 CFR 60.7 (b)] I. Any owner or operator subject to the provisions of NSPS shall maintain a file of all measurements and other information required by this subpart recorded in a permanent file suitable for inspection. This file shall be retained for at least five years following the date of such measurements, maintenance, and records. [40 CFR 60.7 (f)] J. Any owner or operator subject to the provisions of NSPS shall conduct performance test(s) and furnish to AQD a written report of the results of such test(s). Test(s) shall be conducted within 60 days after achieving the maximum production rate at which the facility will be operated, but not later than 180 days after initial start-up. [40 CFR 60.8]