Combination of two permits into one. Updating plant emissions. Permit Application was designated as TVR (M-1). 01/07/10

Transcription

1 OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION MEMORANDUM April 18, 2013 TO: THROUGH: THROUGH: THROUGH: FROM: SUBJECT: Phillip Fielder, P.E., Permits and Engineering Group Manager Kendal Stegmann, Senior Environmental Manager Compliance and Enforcement Phil Martin, P.E., Engineering Manager, Existing Source Permits Section Peer Review Mark Chen, P.E., New Source Permits Section Evaluation of Title-V Permit Renewal Application No TVR2 DCP Midstream, L.P. Beaver County No. 12 Compressor Station Latitude N º, Longitude W º Section 4, Township 3N, Range 23ECM Beaver County, Oklahoma Directions: From Elmwood, go 8.6 miles north on U.S. Highway 270 (also SH 23), turn west onto paved County Road EW 18 and go 3 miles, then turn north onto County Road NS 136 and go 0.5 mile, and turn west 0.3 mile into the station. SECTION I. INTRODUCTION DCP Midstream, L.P. (DCPM) has applied for a renewal of the Part 70 Title V operating permit for their Beaver County No. 12 Compressor Station (SIC Code 4922, NAICS Code ). The facility is currently operated under two separate operating permits: (1) Permit No TVR, which was issued to Northern Natural Gas Company (NNG) on April 17, 2006, for the compressor station, and (2) Permit No TVR, which was issued to DCPM on July 21, 2008, for one 400-bbl condensate tank (designated as T-1 in this permit). The condensate tank is collocated at the site and also part of the facility operation. On October 9, 2008, DCP acquired the Beaver County No. 12 Compressor Station from NNG. From October 2008 to January 2013, DCP submitted several modifications for the plant operations and emission limits, which are listed in the Table 1. Table 1 Facility Modification Date Received Modification 10/29/09 Combination of two permits into one. Updating plant emissions. Permit Application was designated as TVR (M-1). 01/07/10 Title V permit renewal application for Permit No TVR. Permit Application was designated as TVR2 12/03/10 Significant Modification to convert the facility to a Synthetic Minor Source 01/14/13 Title V permit renewal application for Permit No TVR. Permit Application is designated as TVR2.

2 2 All permit modification applications related to updated operations and modified emissions, which were received by Air Quality Division (AQD) since October 2008, are included into this Title V renewal permit, No TVR2. Therefore, Permits No TVR (M-1) and No TVR2 are incorporated into this action. AQD also uses this opportunity to update applicable state rules and federal regulations related to the facility. This permit will be finally issued as a synthetic minor source permit with the permit number converted to Permit No O after processed through a Tier II permitting procedure. SECTION II. FACILITY DESCRIPTION This facility operates a natural gas gathering system which compresses and transports wet natural gas from the wellhead to a natural gas processing plant. The field natural gas stream enters the station through an inlet separator, where free liquids are removed and stored in a 400-bbl condensate tank. Presently, the facility has four natural gas-fired compressor engines, which are operated with psig at the suction side and psig at the discharge side. The facility is designed to operate at a maximum capacity of 25 MMSCF/day (including safety factor). There is no dehydration unit at the facility. Condensate is transported off-site for sale. The separated water from condensate is also collected and is periodically transported off-site for disposal. Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) as outlined below in Section III, Equipment. SECTION III. EQUIPMENT EUG 1 Permitted Internal Combustion Engines EU ID# Point ID# EU Name/Model Serial No. Construction Date ENG hp Waukesha L7042GU 4-stroke rich-burn with Cata. Conv ENG hp Waukesha L7042GU 4-stroke rich-burn with Cata. Conv ENG hp Waukesha L7042GU 4-stroke rich-burn with Cata. Conv The facility was originally constructed in 1973 with three 818-hp Waukesha L7042GU engines (ENG1, ENG2, and ENG3). In 1974, an additional 818-hp Waukesha L7042GU engine was added to the facility (ENG4). These three engines are grandfathered. These four engines were exempted from permitting by a regulatory exemption which was in effect from 1972 to In December 2010, DCP equipped all four engines with nonselective catalytic reduction (NSCR) emission controls. The NSCR controls reduce the potential facility-wide emissions below 100 TPY major source threshold. All four engines lost their exempted status and became permitted engines. This requires a significant permit modification and Tier II permitting procedure. ENG1 was removed from service in September 2011 and its emissions are also removed from the permit. EUG 2A Condensate Storage Tank EU ID# Point ID# Contents Barrels Gallons Construction Date Tanks T-1 Condensate ,

3 3 EUG 2B Miscellaneous Storage Tanks EU ID# Point ID# Contents Barrels Gallons Construction Date Tanks T-4 Mop Water T-5 Antifreeze T-6 Antifreeze 38 1, T-7 Lube Oil 35 1, T-8 Used Oil 25 1, T-9 Methanol 43 1, EUG 3 Fugitive VOC Emission Sources EU ID# Point Number* Gas Liquid FUG Connectors Flanges Valves Open Lines 30 4 Others 18 2 Pump Seals 0 2 * Estimate only, not a permit limit EUG 4. Miscellaneous VOC Emissions EU ID# Name/Description Installation Date B-1 Compressor Engine Blowdown 1974 LOAD Condensate Truck Loadout Emissions 1974 SECTION IV. AIR EMISSIONS Table 2. Engine Specifications and Stack Parameters Parameter Manufacturer Model Control ENG2 to ENG4 Waukesha L7042GU Cat. Conv. & AFR Controller Input Parameter Horsepower (max) 818 Fuel Consumption (BTU/hp-hr) 7,239 Fuel Usage (SCFH) 5,922 Stack Diameter (Inches) 10 Height above Grade (Feet) 16 Exhaust Flow (ACFM) 3,735 Exhaust Temperature ( F) 1,011 Calculated Parameter Moisture Content (%) 16.6

4 4 Table 3. Engines Emissions Factors EU ID# Qty NOx(g/hp-hr) CO(g/hp-hr) VOC(g/hp-hr) ENG2 to ENG4, 818-hp Waukesha L7042GU with Catalytic Converter Table 2 lists the engine specifications and stack parameters. Based on manufacturer s data (including safety factor for operational flexibility), the emission factors for compressor engines are presented in Table 3. The criteria pollutant emissions are estimated from the compressor engines based on 8,760 hours per year operation. Table 4 lists the fugitive VOC emissions from the facility. Fugitive emissions are based on Table 2-4 of 1995 Protocol for Equipment Leak Emission Estimates (EPA 453/R ), Oil and Gas Production Operations Average Emission Factors. VOC content in the vapor lines is analyzed and estimated at 18.48% by weight. Table 4. Fugitive VOC Emissions Emission Units Number of Units VOC (lb/hr-source) VOC Emissions Gas Liquid Gas Liquid lb/hr TPY Connectors Flanges Valves Open Lines Others Pump Seals Subtotal Condensate tank emissions (working and breathing VOC losses) were calculated using the TANKS 4.0.9d computer software using a total annual throughput of 302,400 gallons for the condensate tank T-1, a molecular weight of 66 lb/lb-mole, and an average vapor pressure of 5.09 psia. VOC flash emissions due to the condensate transfer from the separator (70 psig) to the atmospheric storage tank (T-1) were estimated based on the Vasquez-Beggs solution gas-to-oil ratio correlation method using default parameters. VOC emissions for the condensate truck loadout operation are estimated using AP-42 (1/95), Equation (1) in Section 5.2, Transportation and Marketing of Petroleum Liquids, and Tables and VOC loadout emissions were calculated based on 0.6 saturation factor, 57 F bulk temperature, 5.2 psia vapor pressure, and 66 lb/lb-mole molecular weight. VOC emissions from pipeline vents and the engine blowdown (B-1) emissions for maintenance activities were estimated using analyzed gas composition at the site and volume of 480,000 SCF per year emitted and 18.48% VOC by weight. Molar volume conversion factor is 380 SCF/lbmole of gas at 60 F and 14.7 psia, and the molecular weight is lb/lb-mole. The annual throughput for methanol tank, T-9, is 21,600 gallon per year. The VOC emissions from methanol tank and engine blowdown B-1 are used as a reference and not to be used as a permit limitation. VOC emissions from the lube oil tank, used oil tank, and antifreeze tanks are considered negligible. Table 5 lists the total facility-wide emissions.

5 5 Table 5. Total Facility-Wide Emissions ID # Source NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY ENG2 818-hp Waukesha L7042GU w/c.c ENG3 818-hp Waukesha L7042GU w/c.c ENG4 818-hp Waukesha L7042GU w/c.c T bbl Condensate Tank * T-9 Methanol Tank FUG Fugitive VOC Emissions LOAD T-8 Truck Loading B-1 Engine Blowdown Emissions Total Emissions * Combined emissions from working loss, breathing loss, and flash emissions. C.C.= Catalytic Converter The primary hazardous air pollutant (HAP) emission from the engine is formaldehyde (HCHO). Formaldehyde emissions from the rich-burn engines are estimated based on formaldehyde emission factor derived from AP-42 (7/00), Section 3.2, Table 3.2-3, for uncontrolled 4-stroke rich-burn natural gas-fired stationary engines, lb/mmbtu. The reduction of HCHO emissions due to catalytic converter is 76%. After reduction, the emission factor becomes lb/mmbtu. Table 6 lists annual formaldehyde emissions based on 8,760 hours per year operation. The facility-wide formaldehyde emissions do not exceed the major source threshold, 10 TPY. Table 6. Formaldehyde Emissions Emissions Source Formaldehyde lb/hr TPY ENG2, 818-hp Waukesha L7042GU with Catalytic Converter ENG3, 818-hp Waukesha L7042GU with Catalytic Converter ENG4, 818-hp Waukesha L7042GU with Catalytic Converter Total Potential Greenhouse Gas (GHG) emissions from the facility were estimated using engineering calculations and gas analysis data (mole % value of gas component) from the facility. GHG emissions are expressed as CO 2 e. All CO 2 e emissions from combustion of natural gas are based on the default factors for natural gas combustion from 40 CFR Part 98, Subpart C, Tables C-1 and C-2, and the related global warming potential factors from 40 CFR Part 98, Subpart A, Table A-1 regarding CO 2, CH 4, and N 2 O emissions (A combined CO 2 e average emission factor of 117 lb/mmbtu for engines). All other CO 2 e emissions are related to CO 2 or CH 4 emissions and the related global warming potential factor. Emissions from fugitive VOC emissions, FUG, are estimated using API Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry, Section 6.0, Tables 6-12 and Emissions from tank sources and emissions from truck loading are estimated using API Compendium Sections 5.4 and 5.5, and Appendix B. Table 7 lists annual potential facility-wide Greenhouse Gas emissions. GHG emissions are estimated and presented as metric ton per year (MTPY) and ton per year (TPY).

6 6 The GHG emissions do not exceed a PTE of 100,000 TPY CO 2 e. This facility is not a major source of GHG emissions. Table 7. Facility-Wide Greenhouse Gas Emissions Emissions Source Total CO 2 e MTPY TPY ENG2, 818-hp Waukesha L7042GU with Catalytic Converter 2, , ENG3, 818-hp Waukesha L7042GU with Catalytic Converter 2, , ENG4, 818-hp Waukesha L7042GU with Catalytic Converter 2, , T-1, 400-bbl Condensate Tank FUG, Fugitive VOC Emissions 2, , LOAD, T-1 Truck Loading B-1, Engine Blowdown Emissions Total 11, , SECTION V. 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. OAC 252:100-3 (Air Quality Standards and Increments) Primary Standards are in Appendix E and Secondary Standards are in Appendix F of the Air Pollution Control Rules. 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. Emission inventories have been submitted and fees paid for the past years. 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. This project meets the conditions for a minor facility operating permit because there is no emission of any regulated pollutant of 100 TPY or more and HAP emissions do not exceed the 10/25 TPY thresholds. As such, major source BACT consideration and public review are not required. OAC 252:100-8 (Permits for Part 70 Sources) Part 5 establishes general administrative requirements for Part 70/Title V Permits. Any changes in the operation of the facility which could potentially result in emissions not authorized in the permit and which do not meet the definitions of Insignificant Activities or Trivial Activities may require prior notification to AQD and/or a permit modification. Insignificant Activities

7 7 refer to individual emission units that either are specifically identified in Appendix I (OAC 252:100) or for which actual calendar year emissions do not exceed the following limits: 5 TPY of any one criteria pollutant; 2 TPY of any one HAP or 5 TPY of multiple HAPs or 20% of any threshold less than 10 TPY for single HAP that the EPA may establish by rule; Emission limits for the facility are based on the previous Title V permits, Permit No TVR, and Permit No TVR, and the permit renewal application. OAC 252:100-9 (Excess Emissions Reporting Requirements) Except as provided in OAC 252: (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: , 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: (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: (Particulate Matter) This subchapter specifies a particulate matter (PM) emissions limitation of 0.60 lb/mmbtu from fuel-burning equipment with a rated heat input of 10 MMBTUH or less. For 2-cycle leanburn engines, AP-42 (7/00), Table lists the total PM emissions for natural gas to be 0.05 lbs/mmbtu. For 4-cycle rich-burn engines, AP-42 (7/00), Table lists the total PM emissions for natural gas to be 0.02 lbs/mmbtu. AP-42 (7/98), Table lists total PM emissions for natural gas combustion from heaters, boilers, etc., to be 0.01 lbs/mmbtu. The permit requires the use of natural gas for all fuel-burning units to ensure compliance with Subchapter 19. This subchapter also limits emissions of PM from industrial processes. Per AP-42 factors, there are no significant PM emissions from any other industrial activities at this facility. OAC 252: (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. When burning natural gas there is little possibility of exceeding the opacity standards.

8 8 OAC 252: (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: (Sulfur Compounds) Part 5 limits sulfur dioxide emissions from new petroleum or natural gas process 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. 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. OAC 252: (Nitrogen Oxides) [Not Applicable] This subchapter limits NOx emissions from new fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH to emissions of 0.2 lb of NOx per MMBTU. There are no equipment items that exceed the 50 MMBTUH threshold. OAC 252: (Carbon Monoxide) [Not Applicable] None of the following affected processes are located at this facility: gray iron cupola, blast furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic reforming unit. OAC 252: (Volatile Organic Compounds) Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of 400 gallons or more and storing a VOC with a vapor pressure greater than 1.5 psia at maximum storage temperature to be equipped with a permanent submerged fill pipe or with an organic vapor recovery system. This applies to the condensate (T-1) storage tank. The other VOL storage tanks are exempted from the requirement because the capacity and/or the vapor pressure of the material stored in the tanks are below the de minimis level. 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. This facility does not have the physical equipment (loading arm and pump) to conduct this type of loading and is not subject to this requirement. Part 5 limits the VOC content of coatings from any coating line or other coating operation. This facility does not normally conduct coating or painting operations except for routine maintenance of the facility and equipment. No coating operation is located at this facility. Part 7 requires fuel-burning and refuse-burning equipment to be operated to minimize emissions of VOC. The equipment at this location is subject to this requirement. Part 7 requires all effluent water separator openings which 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. No effluent water separators are located at this facility.

9 9 OAC 252: (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. OAC 252: (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. The following Oklahoma Air Pollution Control Rules are not applicable to this facility: OAC 252: Alternative Emissions Reduction not requested OAC 252: Mobile Sources not in source category OAC 252: Incinerators not type of emission unit OAC 252: Cotton Gins not type of emission unit OAC 252: Grain Elevators not in source category OAC 252: Nonattainment Areas not in area category OAC 252: Municipal Solid Waste Landfills not in source category SECTION VI. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Not Applicable] Final total emissions are less than the major source threshold of 250 TPY of any single regulated pollutant and the facility is not one of the 26 specific industries with a threshold of 100 TPY. NSPS, 40 CFR Part 60 [Not Applicable] Subparts K, Ka, Kb, VOL Storage Vessels. Subpart Kb regulates hydrocarbon storage tanks larger than 19,813 gallons capacity and built after July 23, All tanks on site are below the threshold, 19,813 gallons. This subpart is not applicable. Subpart GG, Stationary Gas Turbines. There are no turbines at this facility. The compressors onsite are powered by reciprocating engines.

10 10 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. This subpart applies to natural gas processing plants that commence construction, reconstruction, or modification after January 20, 1984, and prior to August 23, This site does not engage in this type of activity. Therefore, this facility is not subject to Subpart KKK. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. There is no natural gas sweetening operation at this site. Subpart IIII, Stationary Compression Ignition (CI) Internal Combustion Engines (ICE). This subpart affects CI ICE manufactured after There are no CI-ICE at this facility. Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI-ICE). This subpart promulgates emission standards for new SI engines ordered after June 12, 2006, that are manufactured after certain dates, and for SI engines modified or reconstructed after June 12, The specific emission standards (either in g/hp-hr or as a concentration limit) vary based on engine class, engine power rating, lean-burn or rich-burn, fuel type, duty (emergency or nonemergency), and manufacture date. Engine manufacturers are required to certify certain engines to meet the emission standards and may voluntarily certify other engines. An initial notification is required only for owners and operators of engines greater than 500 HP that are non-certified. Emergency engines will be required to be equipped with a non-resettable hour meter and are limited to 100 hours per year of operation excluding use in an emergency (the length of operation and the reason the engine was in operation must be recorded). All four engines in this permit are manufactured prior to June 12, 2006, and have not been reconstructed, therefore, all four engines are not subject to this subpart. Subpart KKKK, Stationary Combustion Turbines. This subpart establishes emission standards and compliance schedules for the control of emissions from stationary combustion turbines with a heat input at peak load equal to or greater than 10 MMBTUH, based on the higher heating value of the fuel, that commenced construction, modification, or reconstruction after February 18, There are no turbines at this facility. Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This subpart was promulgated August 16, 2012, and affects the following sources that commence construction, reconstruction, or modification after August 23, 2011: 1. Each single gas well; 2. Single centrifugal compressors using wet seals that are located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment; 3. Reciprocating compressors which are single reciprocating compressors located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment; 4. Single continuous bleed natural gas driven pneumatic controllers with a natural gas bleed rate greater than 6 SCFH, which commenced construction after August 23, 2011, located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment and not located at a natural gas processing plant; 5. Single continuous bleed natural gas driven pneumatic controllers which commenced construction after August 23, 2011, and is located at a natural gas processing plant; 6. Single storage vessels located in the oil and natural gas production segment, natural gas processing segment, or natural gas transmission and storage segment;

11 11 7. All equipment, except compressors, within a process unit at an onshore natural gas processing plant; 8. Sweetening units located at onshore natural gas processing plants. There are no gas wells, centrifugal compressors, or sweetening units located at this facility and this facility is not a gas plant. 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. The compressors at the facility are considered existing and have not been modified or reconstructed. Any new or modified compressors will have to comply with this subpart in the future. Single continuous bleed natural gas driven pneumatic controllers constructed, reconstructed, or modified one year after promulgation of the rule shall not have a natural gas bleed rate greater than 6 SCFH and must be tagged. All pneumatic controllers installed one year after promulgation of this rule at this facility will have to comply with this subpart in the future. 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 storage vessels at the facility are considered existing and have not been modified or reconstructed. All new or modified storage vessels will have to comply with 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 This facility is not a gas plant. A sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream. There are no sweetening units at this facility. The permit will require the facility to comply with all applicable requirements of NSPS, Subpart OOOO. 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 applies to process streams which contain more than 10% benzene by weight. Analysis of Oklahoma natural gas indicates a maximum benzene content of less than 1%. NESHAP, 40 CFR Part 63 [Subpart ZZZZ is Applicable] Subpart HH, Oil and Natural Gas Production Facilities. The EPA promulgated the final rule for Subpart HH at area oil and gas production facilities, effective January 3, This MACT was also extended to area sources on January 3, This subpart applies to triethylene glycol (TEG) dehydration units at area sources affected emission points that are located at facilities that

12 12 are major sources of HAP emissions 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. For the purposes of this subpart, natural gas enters the natural gas transmission and storage source category after the natural gas processing plant, when present. If no natural gas processing plant is present, natural gas enters the natural gas transmission and storage source category after the point of custody transfer. There is no dehydration unit at the facility and the potential HAP emissions are below the 10/25 TPY threshold, so this subpart is not applicable. Subpart HHH, Natural Gas Transmission and Storage Facilities. Since this facility is a production facility, this subpart does not apply. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects any existing, new, or reconstructed stationary RICE at a major or area source of HAP emissions, except if the stationary RICE is being tested at a stationary RICE test cell/stand. The following table differentiates existing, new, or reconstructed units based on their construction dates. Construction/Reconstruction Dates Engines >500 hp Engines 500hp Existing Unit Located at Major HAP Source Before 12/19/02 Before 6/12/06 Located at Area HAP Source Before 6/12/06 New or Reconstructed Unit Located at Major HAP Source On and After 12/19/02 On and After 6/12/06 Located at Area HAP Source On and After 6/12/06 The following table lists the status of each engine at this facility: EU ID# Make/Model Construction Date Status ENG2 818-hp Waukesha L7042GU 4-stroke rich-burn with Cata. Conv Existing ENG3 818-hp Waukesha L7042GU 4-stroke rich-burn with Cata. Conv Existing ENG4 818-hp Waukesha L7042GU 4-stroke rich-burn with Cata. Conv Existing All three engines fall under existing units located at an area HAP source category and shall comply with applicable emission limitations and operating limitations no later than October 19, Initial performance test or other initial compliance demonstration according to Tables 4 and 5 to this subpart shall be conducted within 180 days after the compliance date. Specific requirements in are listed in the following table. Engine Category Existing Non-Emergency, Non-Black Start, 4SLB > 500-hp, Remote Stationary RICE Existing Non-Emergency, Non-Black Start, 4SLB > 500-hp, Non-Remote RICE Requirements From Table 2d to Subpart ZZZZ of Part 63 Change oil and filter, inspect spark plugs, and inspect all hoses and belts every 2,160 hours of operation or annually, whichever comes first. Install an oxidation catalyst to reduce HAP emissions from the Stationary RICE

13 13 Engine Category Existing Non-Emergency, Non-Black Start, 2SLB Existing Non-Emergency, Non-Black Start, 4SRB > 500-hp, Remote Stationary RICE Existing Non-Emergency, Non-Black Start, 4SRB > 500-hp, Non-Remote RICE Existing Non-Emergency, Non-Black Start, 4SRB 500-hp Requirements From Table 2d to Subpart ZZZZ of Part 63 Change oil and filter, inspect spark plugs, and inspect all hoses and belts every 4,320 hours of operation or annually, whichever comes first. Change oil and filter, inspect spark plugs, and inspect all hoses and belts every 2,160 hours of operation or annually, whichever comes first. Install NSCR to reduce HAP emissions from the Stationary RICE Change oil and filter, inspect spark plugs, and inspect all hoses and belts every 1,440 hours of operation or annually, whichever comes first. All three existing engines, (ENG2 to ENG4), are 4-stroke rich-burn 818-hp engines and equipped with NSCR catalytic converters. The reduction of H 2 CO is achieved by the performance of catalytic converters, therefore, all three existing engines are subject to this subpart. 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 process or store more than the threshold quantity of any regulated substance (Section 112r of the Clean Air Act 1990 Amendments). More information on this federal program is available on the web page: SECTION VII. COMPLIANCE Tier Classification and Public Review This application has been classified as Tier II based upon a request for renewal of a Title V operating permit and a request for a significant modification as defined in OAC 252: (b)(2)(A). Information on all permit actions is available for review by the public on the Air Quality section of the DEQ web page at 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 applicant has a current lease or easement which is given to accomplish the permitted purpose and that the landowner has been notified. The applicant published the Notice of Filing a Tier II Application in The Herald-Democrat, a weekly newspaper printed and published in the City of Beaver, Beaver County, Oklahoma on

14 14 January 20, The notice stated that the permit application was available for public review at the Beaver County Library, 201 North Douglas Street, Beaver, Oklahoma 73932, or at the Air Quality Division s Main Office in Oklahoma City, Oklahoma. A draft of this permit will also be made available for public review for a period of 30 days as stated in another newspaper announcement and will be available on the AQD Section of the DEQ Web site. This facility is located within 50 miles of the Oklahoma - Kansas border and the Oklahoma - Texas border. The states of Kansas and Texas will be notified of the draft permit. Information on all permit actions is available for review by the public in the Air Quality Section of DEQ Web Page: Testing For all engines, from ENG2 to ENG4, the last engine emission testing was conducted on March 1, All results are presented below and show compliance with the applicable permit conditions. EU Source Testing Permit Limitations Test Results NOx CO NOx CO Date lb/hr lb/hr lb/hr lb/hr ENG2 818-hp Waukesha L7042GU w/c.c. 03/01/ ENG3 818-hp Waukesha L7042GU w/c.c. 03/01/ ENG4 818-hp Waukesha L7042GU w/c.c. 03/01/ Inspection An initial compliance inspection was conducted on October 12, Present for the inspection were Ms. Emily Larkin, Environmental Specialist, Mr. Greg Hayes, Area Superintendent of DCP Midstream, and Mark Chen of Air Quality Division. The facility was constructed and is operating as described in the permit application. Identification plate and serial numbers are on the engines. The compressor engine #3 was not running around 3:30 PM and the natural gas throughput was at 7.4 MMSCFD around 2:00 PM when the facility was inspected on October 12, It was also confirmed that the condensate storage tanks are operated with submerged fill pipe. Operational records, calibration, repair and test data are maintained at the local office at the Guymon District office. Fees Paid Part 70 operating permit renewal application fee of $7,500 was received for the Permit No TVR2. AQD also received permit modification fee of $500 for the Permit No TVR (M-1), and permit renewal application fee of $1,000 for the Permit No TVR2. Since Permits No TVR (M-1) and No TVR2 are incorporated into this action, the application fee will not be refunded.

15 15 SECTION VIII. SUMMARY The facility was constructed and 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 or enforcement issues concerning this facility that would prohibit issuance of the permit. Issuance of the permit is recommended, contingent on public and EPA review.

16 PERMIT TO OPERATE AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS DCP Midstream, L.P. Beaver County No. 12 Compressor Station Permit No TVR2 The permittee is authorized to operate in conformity with the specifications submitted to Air Quality and received by Air Quality on October 29, 2009, and additional information received on January 7, 2010, February 2, 2010, December 3, 2010, February 17, 2011, February 6, 2012, January 14, 2013, and April 17, The Evaluation Memorandum dated April 18, 2013, 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 emissions limitations for each point: ID # Source NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY ENG2 818-hp Waukesha L7042GU w/c.c ENG3 818-hp Waukesha L7042GU w/c.c ENG4 818-hp Waukesha L7042GU w/c.c T bbl Condensate Tank * LOAD T-8 Truck Loading B-1 Engine Blowdown Emissions * Combined emissions from working loss, breathing loss, and flash emissions. C.C.= Catalytic Converter 2. The fuel-burning equipment shall be fired with pipeline grade natural gas or other gaseous fuel with a 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. 3. The permittee shall be authorized to operate this facility continuously (24 hours per day, every day of the year). 4. Each engine at the facility shall have a permanent identification plate attached, which shows the make, model number, and serial number. 5. At least once per calendar quarter, the permittee shall conduct tests of NOx and CO emissions in exhaust gases from the engines in Specific Condition No.1 and each replacement engine when operating under representative conditions for that period. Testing is required for any engine or replacement engine, which runs for more than 220 hours during that calendar quarter. Engines shall be tested no sooner than 20 days after the last test. Testing shall be conducted using a portable engine analyzer in accordance with a protocol meeting the requirements of the AQD Portable Analyzer Guidance document or an equivalent

17 SPECIFIC CONDITIONS TVR2 2 method approved by Air Quality. When four consecutive quarterly tests show an engine to be in compliance with the emissions limitations shown in the permit, then the testing frequency may be reduced to semi-annual testing. A semi-annual test may be conducted no sooner than 60 calendar days nor later than 180 calendar days after the most recent test. Likewise, when the following two consecutive semi-annual tests show compliance, the testing frequency may be reduced to annual testing. An annual test may be conducted no sooner than 120 calendar days nor later than 365 calendar days after the most recent test. Upon any showing of non-compliance with emissions limitations or testing that indicate that emissions are within 10% of the emission limitation, the testing frequency shall revert to quarterly. Reduced engine testing does not apply to engines with catalytic converters or oxidation catalysts. 6. All compressor engines, ENG2 to ENG4, shall each be equipped with an AFRC and be set to operate with exhaust gases passing through a properly functioning catalytic converter. 7. Condensate facility-wide throughput for VOL storage tank, T-1, shall not exceed its throughput limit, 302,400 gallons, in any 12-month period. 8. Total volume of gas released from engine blowdowns and process vents shall not exceed 480,000 SCF on a 12-month rolling total. 9. Replacement (including temporary periods of up to six months for maintenance, etc.) of internal combustion engines shown in this permit with engines of lesser or equal emissions of each pollutant is authorized under the following conditions: a. The permittee shall notify AQD in writing within 10 days of start-up of the replacement engine(s)/turbine(s). Said notice shall identify the old engine/turbine and shall include the new engine/turbine make and model, serial number, horsepower rating, fuel usage, stack flow (ACFM), stack temperature ( F), stack height (feet), stack diameter (inches), and pollutant emission rates (g/hp-hr, lb/hr, and TPY) at maximum horsepower for the altitude/location. b. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be conducted to confirm continued compliance with NOx and CO emissions limitations. A copy of the first quarter testing shall be provided to AQD within 60 days of start-up of each replacement engine/turbine. The test report shall include the engine/turbine fuel usage, stack flow (ACFM), stack temperature ( o F), stack height (feet), stack diameter (inches), and pollutant emission rates (g/hp-hr, lbs/hr, and TPY) at maximum rated horsepower for the altitude/location. c. Replacement equipment and emissions are limited to equipment and emissions which are not subject to NSPS, NESHAP, or PSD. 11. When periodic compliance testing shows engine exhaust emissions in excess of the lb/hr limits in Specific Condition No. 1, the permittee shall comply with the provisions of OAC 252:100-9.

18 SPECIFIC CONDITIONS TVR The permittee shall comply with all applicable requirements of the NESHAP (40 CFR Part 63) for Stationary Reciprocating Internal Combustion Engines (RICE), Subpart ZZZZ, for each affected engine including but not limited to: [40 CFR through ] What This Subpart Covers a What is the purpose of subpart ZZZZ? b Am I subject to this subpart? c What parts of my plant does this subpart cover? d When do I have to comply with this subpart? Emission and Operating Limitations e What emission limitations and operating limitations must I meet if I own or operate an existing stationary RICE located at an area source of HAP emissions? General Compliance Requirements f What are my general requirements for complying with this subpart? Testing and Initial Compliance Requirements g What are my monitoring, installation, operation, and maintenance requirements? h How do I demonstrate initial compliance with the emission limitations and operating limitations? Continuous Compliance Requirements i How do I demonstrate continuous compliance with the emission limitations and operating limitations? Notifications, Reports, and Records j What reports must I submit and when? k What records must I keep? l In what form and how long must I keep my records? Other Requirements and Information m What parts of the General Provisions apply to me? n Who implements and enforces this subpart? o What definitions apply to this subpart? 13. The permittee shall comply with NSPS, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transportation, and Distribution, for each affected facility, if applicable. [40 CFR to ] a What is the purpose of this subpart? b Am I subject to this subpart? c When must I comply with this subpart? d What standards apply to gas well affected facilities? e What standards apply to centrifugal compressor affected facilities? f What standards apply to reciprocating compressor affected facilities? g What standards apply to pneumatic controller affected facilities? h What standards apply to storage vessel affected facilities? i What equipment leak standards apply to affected facilities at an onshore natural gas processing plant? j What are the exceptions to the equipment leak standards for affected facilities at onshore natural gas processing plants?

19 SPECIFIC CONDITIONS TVR2 4 k What are the alternative emission limitations for equipment leaks from onshore natural gas processing plants? l What standards apply to sweetening units at onshore natural gas processing plants? m What test methods and procedures must I use for my sweetening units affected facilities at onshore natural gas processing plants? n What are the requirements for monitoring of emissions and operations from my sweetening unit affected facilities at onshore natural gas processing plants? o What is an optional procedure for measuring hydrogen sulfide in acid gas- Tutwiler Procedure? p How do I demonstrate initial compliance with the standards for my gas well affected facility, my centrifugal compressor affected facility, my reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my equipment leaks and sweetening unit affected facilities at onshore natural gas processing plants? q What additional requirements must I meet to determine initial compliance for my closed vent systems routing emissions from storage vessels or centrifugal compressor wet seal fluid degassing systems? r What additional requirements must I meet for determining initial compliance with control devices used to comply with the emission standards for my storage vessel or centrifugal compressor affected facility? s What are the performance testing procedures for control devices used to demonstrate compliance at my storage vessel or centrifugal compressor affected facility? t How do I demonstrate continuous compliance with the standards for my gas well affected facility, my centrifugal compressor affected facility, my stationary reciprocating compressor affected facility, my pneumatic controller affected facility, my storage vessel affected facility, and my affected facilities at onshore natural gas processing plants? u What are the initial and continuous cover and closed vent system inspection and monitoring requirements for my storage vessel or centrifugal compressor affected facility? v What are the continuous control device monitoring requirements for my storage vessel or centrifugal compressor affected facility? w What are my notification, reporting, and recordkeeping requirements? x What are my additional recordkeeping requirements for my affected facility subject to VOC requirements for onshore natural gas processing plants? y What are my additional reporting requirements for my affected facility subject to VOC requirements for onshore natural gas processing plants? z What additional recordkeeping and reporting requirements apply to my sweetening unit affected facilities at onshore natural gas processing plants? aa What parts of the General Provisions apply to me? bb What definitions apply to this subpart? 13. No later than 30 days after the issuance of this synthetic minor operating permit, the permittee shall submit to Air Quality Division of DEQ, with a copy to the US EPA, Region