MEMORANDUM February 19, Phillip Fielder, P.E., Permits and Engineering Group Manager Air Quality Division

Transcription

1 DRAFT OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION MEMORANDUM February 19, 2010 TO: THROUGH: THROUGH: THROUGH: FROM: SUBJECT: Phillip Fielder, P.E., Permits and Engineering Group Manager Air Quality Division Kendal Stegmann, Senior Environmental Manager Compliance and Enforcement Phil Martin, P.E., Engineering Section Peer Review Eric L. Milligan, P.E., Engineering Section Evaluation of Permit Application No TVR2 Bluestem Gas Services, LLC N.E. Mayfield Gas Sweetening Plant (1311) NE/4 of Section 3, T10N, R25W, Beckham County Latitude: N; Longitude: W Directions: from Junction of I-40 and SH 152 travel 14 miles northwest on Highway 152 and then 0.5 miles south on County Road N1770, the facility is located on west side of the road. SECTION I. INTRODUCTION Bluestem Gas Services, LLC, has requested renewal of their current Part 70 operating permit for the N.E. Mayfield Gas Sweetening Plant. The facility is currently operating as authorized by Permit TVR (M-1) which was issued on August 10, The applicant also submitted a modification to revise emissions based on actual stack heights and ambient impact limits of OAC 252: The modification was incorporated into this permit. SECTION II. FACILITY DESCRIPTION Normal Operation The facility is a natural gas sweetening plant and is classified under primary SIC 1311 and secondary SIC Up to 61 MMSCFD of a lean and sour natural gas can be sweetened and dehydrated. Wet inlet gas flows to an amine contactor where acid gases (CO 2 and H 2 S) are removed by contact with an aqueous solution of methyl-diethanolamine (MDEA). H 2 S is removed completely and CO 2 is partially removed.

2 PERMIT MEMORANDUM TVR2 DRAFT Page 2 Rich amine from the contactor flows to the rich amine flash tank. Flash gas (acid gas and hydrocarbons) is vented to the plant fuel system. The rich amine then flows to the amine regenerator for final removal of acid gases and absorbed hydrocarbons. A 31.6 MMBTUH natural gas fired heater supplies heat for a Therminol hot oil system. The hot oil provides heat for the amine regenerator and heat for other plant heat exchangers. The amine regenerator has a reflux condenser. Acid gas from the amine still overhead flows to a Selectox sulfur recovery unit for processing. Lean amine is re-circulated to the amine contactor. Treated gas exits the amine contactor and flows to the glycol dehydrator contactor. Triethylene glycol (TEG) is used to dry the sweet natural gas. Sweet and dry sales gas leaves the contactor overhead and exits the facility. Rich glycol from the contactor flows to the glycol flash tank where dissolved gases are removed and sent to the plant fuel system. The rich glycol then flows to the glycol regenerator for removal of absorbed water and hydrocarbons from the glycol. The regenerator has a natural gas fired 2.24 MMBTUH reboiler. Water vapor and hydrocarbons are vented to the emergency flare from the glycol regenerator vent. Acid gas from the amine regenerator is preheated and then mixed with excess air before entering the Selectox catalytic converter. The reaction produces SO 2, elemental sulfur, and un-reacted H 2 S. The reactor effluent is cooled to condense and remove elemental sulfur. The acid gas is then fed to two Claus catalytic reactors in series where the H 2 S and SO 2 react to form additional elemental sulfur. The sulfur is condensed and separated from the process stream after each reactor. After the second Claus reactor, the acid gas flows to the Selectox tail gas incinerator where any remaining H 2 S is oxidized to SO 2 at an efficiency of 98%. A 9.5 MMBTUH natural gas fired heater supplies heat for a Therminol hot oil system for exchangers in the sulfur recovery unit. Upsets/SRU Shutdown During upsets or SRU shutdown, the sour inlet gas is routed directly to the emergency acid gas flare. Treated gas or acid gas from the amine system, and/or acid gas from the SRU may be routed to an emergency acid gas flare. Sweet fuel gas (with a small amount of sour process flash gas) is used to fuel the emergency acid gas flare, the amine unit heater, the SRU heater, and the glycol regenerator reboiler. Alternative Operating Scenario (AOS) When operating under the AOS, the sour natural gas production wells will be shut-in and up to 55 MMSCFD of sweet gas with a maximum H 2 S content of 10 ppmv will be processed at the facility. This is equivalent to an inlet H 2 S rate of LT/D, expressed as sulfur. All of the acid gas from the amine still overhead will be vented to the facility s emergency acid gas flare for combustion of H 2 S to SO 2 at a minimum conversion efficiency of 98%. The SRU will not be operated and, therefore, the SRU heater and tail gas incinerator will not be in operation, except for possibly maintaining pilot flames for more rapid startup after short SRU downtimes. Emissions from the emergency acid gas flare will include pollutants from combustion of the acid gas, the dehydrator regenerator still vent gas, and supplemental fuel gas to maintain the BTU content of the flared gas above 200 BTU/SCF.

3 PERMIT MEMORANDUM TVR2 DRAFT Page 3 SECTION III. EQUIPMENT EUG A. Gas-Fired Heaters EU Point ID Description MMBTUH Date Installed E-TEGDEHY P-EXHSTKTEG Glycol Regen Reboiler E-SELECTOX P-EXHSTKSEL SRU Heater E-REGENHTR1 P-EXHSTKHTR1 Amine Unit Heater EUG B. Sulfur Recovery Unit EU Point ID Emission Unit Date Installed E-GASTRAIN1 P-VENTINCIN1 Tail Gas Incinerator Vent Stack 1985 EUG C. Emergency Acid Gas Flare EU Point ID Emission Unit Date Installed C-FLARE1 P-FLARE1 Emergency Acid Gas Flare 1985 Stack Parameters Point ID Easting (m) Northing (m) Height (feet) Dia. (inches) Flow (ACFM) Temp. ( F) P-EXHSTKTEG , P-EXHSTKSEL , P-EXHSTKHTR , P-VENTINCIN , P-FLARE N/A 1,800 N/A The flow rate for the flare fluctuates with the amount and type of gases being flared. SECTION IV. EMISSIONS Normal Operation Emissions estimates for the amine unit heater, the SRU heater, and the glycol regenerator reboiler are based on maximum heat input, continuous operation, emission factors from AP-42 (7/98), Section 1.4, and a fuel sulfur content of 343 ppmv (0.057 lb/mmbtu). SO 2 and H 2 S emissions estimates for the sulfur recovery unit are based on a sulfur feed rate of 20.6 LT/D, an H 2 S to elemental sulfur recovery efficiency of 94.5% (required reduction efficiency per OAC 20.6 LTPD), and a tail gas incinerator efficiency of 98% for H 2 S to SO 2 conversion. VOC fugitive emissions are insignificant because the inlet gas is very lean (C %).

4 PERMIT MEMORANDUM TVR2 DRAFT Page 4 Estimates of lb/hr emissions associated with upset conditions of the amine unit, or shutdown of the SRU unit, are based on the worst case conditions where 61 MMSCFD of sour inlet gas with a gross heating value of 928 BTU/SCF is flared for a short time. Short-term emissions of NO X and CO are based on the low BTU (<1,000 BTU/SCF) gas stream emission factors from the TCEQ document Air Permit Technical Guidance for Chemical Sources: Flares & Thermal Oxidizers - RG-109 (Draft) September 2000, (NO X lb/mmbtu; CO lb/mmbtu). Short-term emissions of VOC are based on the total hydrocarbon factor from AP-42 (9/91), Section 13.5, which includes methane and ethane. Short-term emissions of SO 2 and H 2 S are based on the maximum sulfur loading to the flare of 20.8 LT/D and 98% conversion of H 2 S to SO 2. The emissions are listed here for completeness. Criteria Pollutant and H 2 S Emissions EU Point ID Unit SO 2 NO X CO VOC H 2 S E-TEGDEHY lb/hr <0.01 P-EXHSTKTEG TPY E-SELECTOX lb/hr P-EXHSTKSEL TPY E-REGENHTR1 lb/hr E-XHSTKHTR1 TPY E-GASTRAIN1 lb/hr P-VENTINCIN1 TPY C-FLARE1 lb/hr 3, , P-FLARE1 TPY Total Emissions lb/hr 3, , TPY Demonstration of compliance with the ambient standards of OAC 252: during flaring events depends on the specific gases being flared, the total heat content of those gases, the amount of H 2 S being flared and compliance with the standards cannot be assured or practically enforced. In addition to the ambient standards the facility would also have to demonstrate compliance with the daily sulfur reduction efficiencies to be in compliance with OAC 252: Therefore, the facility will not be permitted for the emergency flaring events. Emergency flaring events are considered excess emissions that have to be reported as required under OAC 252:100-9.

5 PERMIT MEMORANDUM TVR2 DRAFT Page 5 Alternative Operating Scenario (AOS) The SRU heater and thermal incinerator will have zero emissions during the AOS, except for possible negligible emissions from maintaining pilot flames. Emissions estimates for the amine unit heater and the glycol regenerator reboiler are based on the maximum heat input, continuous operation, and emission factors from AP-42 (7/98), Tables and Potential acid gas and rich amine flash gas rates were estimated using AMINECalc Version 1.0, the maximum amine circulation rate of 300 gpm, and an inlet gas rate of 55 MMSCFD with 10 ppmv H 2 S. The AMINECalc results demonstrated that 100% of the inlet H 2 S is vented to the flare from the regenerator still vent. Emissions of NO X and CO are based on emission factors from the TCEQ document Air Permit Technical Guidance for Chemical Sources: Flares & Thermal Oxidizers RG-109 (Draft) September 2000, (NO X lb/mmbtu; CO lb/mmbtu). These factors are based on heat input to the flare (~15.95 MMBTUH). Emissions of VOC are based on AP-42 (9/91), Section 13.5 using the TOC, which includes methane and ethane, as the factor for VOC. SO 2 and H 2 S emissions were estimated based on 98% conversion of H 2 S to SO 2. Criteria Pollutant and H 2 S Emissions EU Point ID Unit SO 2 NO X CO VOC H 2 S E-TEGDEHY lb/hr <0.01 P-EXHSTKTEG TPY E-SELECTOX * lb/hr P-EXHSTKSEL TPY E-REGENHTR1 lb/hr P-EXHSTKHTR1 TPY E-GASTRAIN1 * lb/hr P-VENTINCIN1 TPY C-FLARE1 lb/hr P-FLARE1 TPY Total Emissions lb/hr TPY * Down during alternative operating scenario.

6 PERMIT MEMORANDUM TVR2 DRAFT Page 6 SECTION V. INSIGNIFICANT ACTIVITIES The insignificant activities identified and justified in the application are listed below. Records are available to confirm the insignificance of the activities. Record keeping for activities indicated with * is required in the Specific Conditions. 1. Storage tanks with less than or equal to 10,000 gallons capacity that store volatile organic liquids with a true vapor pressure less than or equal to 1.0 psia at maximum storage temperature. There is a 210-bbl lube oil storage tank on the site. Vapor pressure for the lube oil is less than 1.0 psia. 2. * Activities having the potential to emit no more than 5.0 TPY of any criteria pollutant. None identified but may be in the future. SECTION VI. OKLAHOMA AIR QUALITY RULES OAC 252:100-1 (General Provisions) Subchapter 1 includes definitions but there are no regulatory requirements. [Applicable] OAC 252:100-2 (Incorporation by Reference) [Applicable] 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) [Applicable] 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) [Applicable] 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 252:100-8 (Permits for Part 70 Sources) [Applicable] Part 5 includes the general administrative requirements for Part 70 permits. Any planned changes in the operation of the facility which result in emissions not authorized in the permit and which exceed the Insignificant Activities or Trivial Activities thresholds require prior notification to AQD and may require a permit modification. Insignificant activities mean individual emission units that either are on the list in Appendix I (OAC 252:100) or whose actual calendar year emissions do not exceed the following limits: 5 TPY of any one criteria pollutant 2 TPY of any one hazardous air pollutant (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

7 PERMIT MEMORANDUM TVR2 DRAFT Page 7 Emission limitations and operational requirements necessary to assure compliance with all applicable requirements for all sources are taken from the operating permit application, or developed from the applicable requirements. OAC 252:100-9 (Excess Emissions Reporting Requirements) [Applicable] 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) [Applicable] 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: (Control of Emission of Particulate Matter) [Applicable] Section 19-4 regulates emissions of particulate matter (PM) from new and existing fuel-burning equipment, with emission limits based on maximum design heat input rating. Fuel-burning equipment is defined in OAC 252:100-1 as combustion devices used to convert fuel or wastes to usable heat or power. Thus, the gas-fired heaters and reboilers are subject to the requirements of this subchapter. The thermal incinerator and the emergency acid gas flare are not subject since they do not produce any usable heat or power. Appendix C specifies a PM emission limitation range of 0.6 lb/mmbtu to 0.43 lb/mmbtuh for fuel-burning equipment with a rated heat input range of 10 MMBTUH or less up to 40 MMBTUH. AP-42 (7/98) Table lists total PM emissions as lb/mmbtu for natural gas combustion. This permit requires the use of natural gas for all fuel-burning units to ensure compliance with Subchapter 19. OAC 252: (Visible Emissions and Particulates) [Applicable] 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 very little possibility of exceeding these standards. This permit requires the use of natural gas for all fuel-burning units to ensure compliance with Subchapter 25. OAC 252: (Control of Fugitive Dust) [Applicable] 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

8 PERMIT MEMORANDUM TVR2 DRAFT Page 8 maintenance of air quality standards. Under normal operating conditions, this facility has negligible potential to violate this requirement; therefore, it is not necessary to require specific precautions to be taken. OAC 252: (Sulfur Compounds) [Applicable] Part 2 limits the ambient air concentration of sulfur dioxide (SO 2 ) emitted from any existing facility or any new petroleum and natural gas process facility with equipment subject to OAC 252: (a)(1). The SO 2 ambient air concentration limits are listed in the table below. Part 2 also limits the ambient air concentration of hydrogen sulfide (H 2 S) emissions from any new or existing source to 0.2 ppmv (24-hour average) which is equivalent to 279 g/m 3. For normal operation and during operation under the AOS, air dispersion modeling was conducted. US EPA s air dispersion model AERMOD (07026) was used for the modeling analyses. AERMOD is a refined, steady-state, multiple source, Gaussian dispersion model and is the preferred model for these analyses. The modeling analysis was performed using the regulatory default models settings, which include stack heights adjusted for stack-tip downwash and missing data processing. Source and building elevations were obtained from engineering elevation drawings. Receptor terrain elevations entered into the model were the highest elevations extracted from USGS 7.5 minute digital elevation model (DEM) data of the area surrounding the site. For each receptor elevation, the maximum terrain elevation associated with the four DEM points surrounding the receptor was selected. As described in the Air Dispersion Modeling Guidelines for Oklahoma Air Quality Permits, meteorological data was derived from Oklahoma Mesonet surface data, National Climactic Data Center (NCDC) Integrated Surface Hourly (ISH) data, and FSL/NCDC Radiosonde upper air data. Oklahoma Mesonet data was provided to the AQD courtesy of the Oklahoma Mesonet, a cooperative venture between Oklahoma State University and The University of Oklahoma and supported by the taxpayers of Oklahoma. The model runs were performed using meteorological data using NWS surface observations from Clinton-Sherman AFB, upper air measurements from Amarillo, Texas, and adjusting the surface data using the Oklahoma Mesonet data from Erik, OK. The data set used in this analysis was provided by the AQD. A single Cartesian grid containing receptors spaced at 100 meter intervals extending from the facility fence line out to at least 1800 m was used. Ambient Impacts of SO 2 Averaging Time Standard Operating Scenario & Max Impacts g/m 3 Normal, g/m 3 AOS, g/m 3 1-hour 1,200 1, hour hour Annual

9 PERMIT MEMORANDUM TVR2 DRAFT Page 9 Ambient Impacts of SO 2 Standard Operating Scenario & Max Impacts Averaging Time g/m 3 Normal, g/m 3 AOS, g/m 3 24-hour As previously mentioned, compliance could not be demonstrated for individual flaring events. This is due to the fact that the effective stack height, diameter, and flow rate for flares is determined based on the heat input to the flare. Since the heat input to the flare for a specific flaring event is variable, there was no way to model all of the potential flaring possibilities and/or to show compliance with the ambient standards. Part 5 limits SO 2 emissions from new fuel-burning equipment (constructed after July 1, 1972). For gaseous fuels the limit is 0.2 lb SO 2 /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 gaseous fuel with sulfur content less than 343 ppmv to ensure compliance with Subchapter 31. Part 5 also requires H 2 S from any new petroleum or natural gas process equipment (constructed after July 1, 1972) to be removed from the exhaust stream or to be oxidized to SO 2 unless H 2 S emissions would be less than 0.3 lb/hr, two-hour average. H 2 S emissions must be reduced by 95% of the H 2 S in the exhaust gas. Direct oxidation of H 2 S is allowed for units whose SO 2 emissions would be less than 100 lb/hr, two-hour average. Otherwise, the facility must comply with the sulfur reduction efficiencies of OAC 252: (a)(2). Emissions from the flash tank of the amine unit are vented to the gas plant s fuel system. During normal operation of the facility the amine unit still vent is vented to a sulfur recovery unit which complies with the sulfur reduction efficiencies of OAC 252: (a)(2). During operation of the facility under the AOS, the amine unit still vent is vented to the emergency acid gas flare with a combustion efficiency of 98%. Part 5, Section (a)(2) requires SO 2 emissions from any new gas sweetening plant to be reduced by use of a sulfur recovery plant prior to release of the exhaust gases to the atmosphere. The requirements of OAC 252: (a)(2) can be met alternatively by establishing that the sulfur content of the acid gas stream from any gas sweetening plant or refinery process is 0.54 Long Tons Per Day (LT/D) or less. The sulfur recovery plant is required to meet the sulfur reduction efficiencies of OAC 252: (a)(2)(C) through (F) depending on the sulfur content of the acid gas stream (X) in LT/D. Part 5, Section (a)(2)(c), When the sulfur content of an acid gas stream from a new gas sweetening unit is greater than 0.54 LT/D, but less than or equal to 5.0 LT/D the sulfur reduction efficiency of the sulfur recovery plant must be at least 75%. The facility is currently operating at a sulfur content of less than 5.0 LT/D and is achieving sulfur reduction efficiencies of 75% or greater. Part 5, Section (a)(2)(d), When the sulfur content of an acid gas stream from a new gas sweetening unit is greater than 5.0 LT/D, but less than or equal to 150 LT/D, the minimum required sulfur recovery efficiency (Z) is calculated using the following equation (rounded to one decimal place): Z ( X )

10 PERMIT MEMORANDUM TVR2 DRAFT Page 10 Based on a permitted sulfur feed rate (X) of 20.6 LT/D, Subchapter 31 requires a minimum recovery efficiency of 94.5%. Performance testing was conducted on the unit on June 24, Testing demonstrated a recovery efficiency of 95.4% and an SO 2 emission rate of 203 lb/hr while the facility was processing 24.4 LT/D of sulfur. These results are in compliance with the required sulfur reduction efficiencies of OAC 252: (a)(2) and NSPS Subpart LLL. Testing was conducted with the tail gas catalytic incinerator operating in the range of F. A minimum operating temperature of 500 F was specified in the previous permits and has been retained in this permit. For this permit, during normal operation emission limits have been established at lb/hr for SO 2 and 2.25 lb/hr for H 2 S based on a sulfur feed rate limit of 20.6 LT/D, a required sulfur reduction efficiency of 94.5% for the SRU, and an H 2 S to SO 2 conversion efficiency of 98% for the tail gas incinerator. During operation under the AOS, the sulfur reduction efficiencies of OAC 252: (a)(2) are not applicable because the sulfur content of the acid gas from the amine unit is less than 0.54 LT/D (inlet sulfur is ~ LT/D). OAC 252: (Nitrogen Oxides) [Not Applicable] This subchapter limits new gas-fired fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH to emissions of 0.2 lb of NO X per MMBTU, three-hour average. 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) [Applicable] 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 to be equipped with a permanent submerged fill pipe or with an organic vapor recovery system. There are no tanks storing organic materials with a vapor pressure greater than 1.5 psia. Part 3 requires 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. Therefore, this requirement is not applicable. Part 7 requires fuel-burning equipment to be operated and maintained to minimize emissions of VOC. All fuel-burning equipment at this location is subject to this requirement. Part 7 regulates VOC/water separators that receive water containing more than 200 gallons per day of VOC. There is no VOC/water separator at this location. OAC 252: (Toxic Air Contaminants (TAC)) [Applicable] 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 Area of Concern (AOC) has been designated anywhere in the state, there are no specific requirements for this facility at this time.

11 PERMIT MEMORANDUM TVR2 DRAFT Page 11 OAC 252: (Testing, Monitoring, and Recordkeeping) [Applicable] 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 Quality Rules are not applicable to this facility: OAC 252: Alternative Emissions Reduction not eligible 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, Feed, or Seed Facility not in source category OAC 252: Non-attainment Areas not in a subject area OAC 252: Municipal Solid Waste Landfills not type of source category SECTION VII. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Not Applicable At This Time] Total potential emissions of SO 2 are greater than the major source threshold of 250 TPY. Any future increases of emissions must be evaluated for PSD if they exceed a significance level (100 TPY CO, 40 TPY NO X, 40 TPY SO 2, 40 TPY VOC, 15 TPY PM 10, 10 TPY H 2 S). NSPS, 40 CFR Part 60 [Subpart LLL is Applicable] Subpart Dc, Small Industrial-Commercial-Institutional Steam Generating Units. This subpart affects steam-generating units constructed after June 9, 1989, and with capacity between 10 and 100 MMBTUH. The amine unit Therminol heater is a Steam Generating Unit as that term is defined in this subpart and is rated above 10 MMBTUH; however, the unit was constructed prior to June 9, 1989 and, therefore, is not subject to this subpart. Subpart GG, Stationary Gas Turbines. There are no turbines at this facility.

12 PERMIT MEMORANDUM TVR2 DRAFT Page 12 Subpart Kb, VOL Storage Vessels. This subpart regulates hydrocarbon storage tanks larger than 19,813-gal capacity and built after July 23, There are no tanks storing materials with a vapor pressure greater than 1.5 psia and all tanks have capacities less than the threshold. Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants. This subpart sets standards for natural gas processing plants which are defined as any site engaged in the extraction of natural gas liquids from field gas, fractionation of natural gas liquids, or both. This facility does not engage in natural gas processing. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. This subpart sets standards for natural gas sweetening units, and sweetening units followed by a sulfur recovery unit, which commenced construction or modification after January 20, The natural gas sweetening system was constructed in The SRU is subject to Subpart LLL. Since the facility processes a gas stream containing greater than 2 LT/D of H 2 S, expressed as sulfur, it is required to meet specific sulfur dioxide reduction standards. Subpart LLL specifies dual standards for initial operation and continuous operation Initial Operations: Z ( X )( Y ) Continuous Operations: Z ( X )( Y ) where Z is the minimum required sulfur dioxide (SO 2 ) emission reduction efficiency achieved in percent; X is the sulfur feed rate in LT/D; Y is the mole percent of H 2 S (dry basis) in the acid gas from the sweetening unit. Based on a sulfur feed rate of 20.6 LT/D and an H 2 S concentration of 17% in the acid gas to the SRU, the minimum continuous efficiency required by Subpart LLL is 92.4%. OAC 252: requires a minimum efficiency of 94.5%, which is more stringent than Subpart LLL. However, the facility is still subject to all the requirements of Subpart LLL including minimum efficiency, compliance monitoring, and recordkeeping. For an SRU with a sulfur feed rate greater than 2.0 LT/D, but less than or equal to 5.0 LT/D, Subpart LLL requires a minimum SO 2 reduction efficiency of 74.0%. The permit requires compliance with all applicable requirements. Subpart JJJJ, Stationary Spark Ignition (SI) Internal Combustion Engines (ICE). There are no SI ICE at this facility. 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) concerns only process streams, which contain more than 10% benzene by weight. All process streams at this facility are below this threshold. NESHAP, 40 CFR 63 [Subpart HH is Applicable] Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission points that are located at facilities that are major and area sources of HAP, and either process, upgrade, or store hydrocarbon liquids prior to custody transfer or that process, upgrade, or store natural gas prior to entering the natural gas transmission and storage source category. For purposes of this subpart natural gas enters the natural gas transmission and storage source category after the natural gas processing plant, if present. Since the TEG dehydration unit was

13 PERMIT MEMORANDUM TVR2 DRAFT Page 13 constructed before July 8, 2005, and it is not located within an Urban-1 County, it is considered an existing source. Even though the existing TEG dehydration unit at this facility is considered an affected area source it is exempt from the requirements of (d)(2) since the actual average emissions of benzene from the glycol dehydration unit process vents to the atmosphere are less than 0.90 Mg, as determined by the procedures specified in (b)(2). However, the facility must maintain records of the de minimis determination as required in (d)(1). All applicable requirements have been incorporated into the permit. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). There are no RICE at this facility. Subpart DDDDD, Industrial Boilers and Process Heaters. Subpart DDDDD regulated HAP emissions from industrial boilers and process heaters. In March, 2007, the EPA filed a motion to vacate and remand this rule back to the agency. The rule was vacated by court order, subject to appeal, on June 8, No appeals were made and the rule was vacated on July 30, Existing and new small gaseous fuel boilers and process heaters (less than 10 MMBTUH heat rating) were not subject to any standards, recordkeeping, or notifications under Subpart DDDDD. EPA is planning on issuing guidance (or a rule) on what actions applicants and permitting authorities should take regarding MACT determinations under either Section112(g) or Section 112(j) for sources that were affected sources under Subpart DDDDD and other vacated MACTs. It is expected that the guidance (or rule) will establish a new timeline for submission of section 112(j) applications for vacated MACT standards. Until such time as more guidance is received, AQD has determined that a 112(j) determination is not needed for sources potentially subject to a vacated MACT, including Subpart DDDDD. This permit may be reopened to address Section 112(j) when necessary. Compliance Assurance Monitoring (CAM), 40 CFR Part 64 [Not Applicable] This part applies to any pollutant-specific emission unit at a major source that is required to obtain an operating permit, for any application for an initial operating permit submitted after April 18, 1998, that addresses large emissions units, or any application that addresses large emissions units as a significant modification to an operating permit, or for any application for renewal of an operating permit, if it meets all of the following criteria: It is subject to an emission limit or standard for an applicable regulated air pollutant It uses a control device to achieve compliance with the applicable emission limit or standard It has potential emissions, prior to the control device, of the applicable regulated air pollutant of 100 TPY of a criteria pollutant, 10 TPY of a HAP, or 25 TPY of total HAPs This facility is subject to NSPS Subpart LLL, which requires a continuous compliance determination method to the emission standard. The requirement is incorporated into this permit and, therefore, the facility is exempted from CAM per 64.2(b)(1)(vi). Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable] 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

14 PERMIT MEMORANDUM TVR2 DRAFT Page 14 substance is present at the stationary source. This facility is not a natural gas processing plant as defined in 68.3(b) of 40 CFR Part 68. More information on this federal program is available on the web page: 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 banning use of nonessential products containing ozone-depleting substances (Subparts A & C); control servicing of motor vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations which meet phase out requirements and which maximize the substitution of safe alternatives to Class I and Class II substances (Subpart D); require warning labels on products made with or containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons (Subpart H). Subpart A identifies ozone-depleting substances and divides them into two classes. Class I controlled substances are divided into seven groups; the chemicals typically used by the manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform (Class I, Group V). A complete phase-out of production of Class I substances is required by January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs. Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances, scheduled in phases starting by 2002, is required by January 1, This facility does not produce, consume, recycle, import, or export any controlled substances or controlled products as defined in this part, nor does this facility perform service on motor (fleet) vehicles that involves ozone-depleting substances. Therefore, as currently operated, this facility is not subject to these requirements. To the extent that the facility has air-conditioning units that apply, the permit requires compliance with Part 82. SECTION VIII. COMPLIANCE Tier Classification This application has been determined to be Tier II based on the request for renewal of a Part 70 operating permit. 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 owns the land. Inspection A full compliance evaluation was conducted on August 20, 2009, by Melanie Foster, Sean Walker, and Mike Hixon of AQD and Mark Keitz, EH&S Specialist, and Brad Watkins, Midstream Operations Foreman for Bluestem Gas Services. The facility was operating as described in the permit application.

15 PERMIT MEMORANDUM TVR2 DRAFT Page 15 Public Review The applicant published the Notice of Filing a Tier II Application in The Sayre Record a weekly newspaper in Beckham County on November 4, The notice stated that the application was available for public review for a period of 30 days at the Sayre Public Library located at 113 E. Poplar Street, Sayre, Oklahoma and that the application was also available for public review at the Air Quality Division main office. The applicant will also publish the Notice of Draft Permit in The Sayre Record a weekly newspaper in Beckham County. The notice will state that the draft permit will be available for public review for a period of 30 days at the Sayre Public Library located at 113 E. Poplar Street, Sayre, Oklahoma and that the draft permit will also be available for public review at the Air Quality Division main office and on the Air Quality section of the DEQ web page at State Review This facility is located within 50 miles of the Oklahoma - Texas Border. The state of Texas was notified of the draft permit. EPA Review The proposed permit will be forwarded to EPA for review for a 45-day period. Fees Paid Part 70 source operating permit renewal application fee of $1,000. SECTION IX. 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 which would prohibit issuance of this permit. Issuance of the operating permit is recommended, contingent on public and EPA review.

16 DRAFT PERMIT TO OPERATE AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS Bluestem Gas Services, LLC N.E. Mayfield Gas Sweetening Plant Permit Number TVR2 The permittee is authorized to operate in conformity with the specifications submitted to Air Quality on October 26, 2004, and May 20, 2009 and all supplemental materials. The Evaluation Memorandum dated February 19, 2010, 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: [OAC 252: (a)(1)] Normal Operation EUG A: Emission limitations: EU Point ID Unit SO 2 NO X CO VOC H 2 S E-TEGDEHY lb/hr <0.01 P-EXHSTKTEG TPY E-SELECTOX lb/hr P-EXHSTKSEL TPY E-REGENHTR1 lb/hr E-XHSTKHTR1 TPY EUG B: Emission limitations: EU Point ID Unit SO 2 NO X CO VOC H 2 S E-GASTRAIN1 lb/hr P-VENTINCIN1 TPY EUG C: Continuous emissions from the emergency acid gas flare based on not venting the acid gas to the emergency acid gas flare are estimated based on existing equipment items but do not have a specific limitation.

17 SPECIFIC CONDITIONS TVR2 DRAFT Page 2 During emergency flaring periods, enough supplemental fuel shall be flared with the acid gas to insure smokeless burning. All emissions during flaring of acid gas from the amine unit other than during operation under the AOS, constitutes an excess emission and shall be reported in accordance with OAC 252: [OAC 252:100-9] Alternative Operating Scenario (AOS) EUG A: Emission limitations: EU Point ID Unit SO 2 NO X CO VOC H 2 S E-TEGDEHY lb/hr <0.01 P-EXHSTKTEG TPY E-SELECTOX * lb/hr P-EXHSTKSEL TPY E-REGENHTR1 lb/hr P-EXHSTKHTR1 TPY * Down during alternative operating scenario. EUG B: Emission limitations: EU Point ID Unit SO 2 NO X CO VOC H 2 S E-GASTRAIN1 * lb/hr P-VENTINCIN1 TPY * Down during alternative operating scenario. EUG C: Emission limitations: EU Point ID Unit SO 2 NO X CO VOC H 2 S C-FLARE1 lb/hr P-FLARE1 TPY

18 SPECIFIC CONDITIONS TVR2 DRAFT Page 3 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 annually. [OAC 252:100-31] 3. The permittee shall be authorized to operate this facility continuously (24 hours per day, every day of the year). [OAC 252: (a)] 4. The daily sulfur feed rate to the sweetening unit (i.e., the H 2 S in the acid gas), expressed as sulfur, shall not exceed 20.6 LT/D. H 2 S concentration and/or the flow rate of the total plant inlet gas stream shall be limited to ensure compliance with this daily sulfur feed rate limit. [OAC 252:100-31] 5. During operation under the AOS, the daily sulfur feed rate from the sweetening unit (i.e., the H 2 S in the acid gas), expressed as sulfur, shall not exceed LT/D. H 2 S concentration and/or the flow rate of the total plant inlet gas stream shall be limited to ensure compliance with this daily sulfur feed rate limit. [OAC 252:100-31] 6. Flash gas from the rich glycol flash tank shall be vented to the plant flare or to plant fuel gas. [OAC 252: (a)] 7. Flash gas from the rich amine flash tank shall be vented to the plant flare or to plant fuel gas. [OAC 252:100-31] 8. Emissions from the glycol regenerator still vent shall be vented to the plant flare. [OAC 252: (a)] 9. The emergency gas flare is subject to certain general OAC requirements. a. The flare shall have installed, calibrated, maintained, and operated an alarm system that will signal non-combustion of the acid gas. [OAC 252: (c)] 10. The facility is subject to federal New Source Performance Standards, 40 CFR 60, Subpart LLL, Standards of Performance for Onshore Natural Gas Processing: SO 2 Emissions, and OAC 252: Petroleum and natural gas processes and shall comply with all applicable standards contained therein, including but not limited to: [40 CFR to & OAC 252; ] a Applicability and designation of affected facilities. b Definitions. c Standards for sulfur dioxide. i. Whenever the daily sulfur feed rate from the sweetening unit (i.e., the H 2 S in the acid gas), expressed as sulfur, is more than 5.0 LT/D, the permittee shall achieve

19 SPECIFIC CONDITIONS TVR2 DRAFT Page 4 a sulfur emissions reduction efficiency (Z) that is greater than an efficiency calculated by both of the following equations: A. Z 85.35(X )(Y ) [40 CFR (b)] B. Z (X ) [OAC 252: (a)(2)(D)] Where: Z = the sulfur emissions reduction efficiency achieved in percent, carried to one decimal place; X = the sulfur feed rate from the sweetening unit (i.e., the H 2 S in the acid gas) expressed as long tons per day (LT/D) of sulfur, rounded to one decimal place; and Y = the mole percent of H 2 S (dry basis) in the acid gas from the sweetening unit, expressed as a decimal, rounded to one decimal place. ii. Whenever the daily sulfur feed rate from the sweetening unit (i.e., the H 2 S in the acid gas), expressed as sulfur, is less than or equal to 5.0 LT/D and greater than 0.54 LT/D, the permittee shall achieve a sulfur emissions reduction efficiency (Z) that is greater than both of the following: A. Z 74.0% [40 CFR (b)] B. Z 75.0% [OAC 252: (a)(2)(C)] d Compliance provisions. e Test methods and procedures. f Monitoring of emissions and operations. i. The owner or operator shall install, calibrate, maintain, and operate monitoring devices or perform measurements to determine the following operations information on a daily basis: [40 CFR (a)] A. The accumulation of sulfur product over each 24-hour period; B. The H 2 S concentration in the acid gas from the sweetening unit for each 24-hour period; C. The average acid gas flow rate from the sweetening unit; D. The sulfur feed rate (X); and E. The required sulfur dioxide emission reduction efficiency for the 24-hour period. ii. Except as specified in (e), where compliance is achieved through the use of an oxidation control system or a reduction control system followed by a continually operated incineration device, the owner or operator shall install, calibrate, maintain, and operate monitoring devices and continuous emission monitors as follows: [40 CFR (b)] A. A continuous monitoring system to measure the total sulfur emission rate (E) of SO 2 in the gases discharged to the atmosphere which shall be calibrated at least annually according to the manufacturer's specifications. B. A monitoring device to measure the temperature of the gas leaving the combustion zone of the incinerator. At all times during the operation of the facility, the owner or operator shall maintain the 24-hr average temperature of the gas leaving the combustion zone of the incinerator at or above 500 F.

20 SPECIFIC CONDITIONS TVR2 DRAFT Page 5 g Recordkeeping and reporting requirements. i. Each owner or operator shall submit a written report of excess emissions to the Administrator semiannually. For the purpose of these reports, excess emissions are defined as: [40 CFR (b)] A. Any 24-hour period (at consistent intervals) during which the average sulfur emission reduction efficiency (R) is less than the minimum required efficiency (Z). B. Any 24-hour period during which the average temperature of the gases leaving the combustion zone of an incinerator is less than the appropriate operating temperature. Each 24-hour period must consist of at least 96 temperature measurements equally spaced over the 24 hours. h Optional procedure for measuring hydrogen sulfide in acid gas Tutwiler Procedure. 11. The permittee shall maintain records of operations as listed below. These records shall be maintained on-site or at a local field office for at least five years after the date of recording and shall be provided to regulatory personnel upon request. [OAC 252: (a)(3)(B)] a. Occurrence and duration of any start-up, shutdown, or malfunction of the Sulfur Recovery Unit (SRU). b. A record of emergency flare operations (excluding operation under the AOS) including dates, number of hours of flare operation, and amount of H 2 S flared per hour. c. During operation under the AOS, a record of dates and hours of operation, total inlet flowrate (MMSCFD), and H 2 S concentration (ppmv measured daily). Draeger tube sampling for H 2 S concentration is sufficient. d. All records and reports required by NSPS, Subpart LLL. e. For fuel(s) burned, the appropriate document(s) as described in Specific Condition No Records shall be maintained on-site to verify any insignificant activities having the potential to emit no more than 5.0 TPY of any criteria pollutant. List the activity with estimated actual annual emissions. [OAC 252: (a)(3)(B)] 14. No later than 30 days after each anniversary date of the issuance of the original Part 70 permit (February 10, 2000), the permittee shall submit to Air Quality Division of DEQ, with a copy to the US EPA, Region 6, a certification of compliance with the terms and conditions of this permit. [OAC 252: (c)(5)(a) & (D)] 15. All process heaters shall have a permanent identification plate attached that shows the make, model number, serial number, and heat input rating of the heater. The emergency flare stack and tail gas incinerator stack shall be a minimum of 180 feet in height. [OAC 252:100-43]