MEMORANDUM April 10, Phillip Fielder, P.E., Permits and Engineering Group Manager

Transcription

1 OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION DRAFT MEMORANDUM April 10, 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., Manager, Existing Source Permits Section Peer Review David Schutz, P.E., New Source Permit Section Evaluation of Permit Application No C (M-4) Arkoma Holdings LLC Stonewall, Tupelo and Coalgate Gas Plants Section 6, Township 1S, Range 10E Coal County, Oklahoma Driving Directions: From Coalgate, Northwest on US Miles, South to Plant Site Latitude: o, Longitude o SECTION I. INTRODUCTION Arkoma Holdings LLC (Arkoma) has requested a construction permit for their Coalgate and Tupelo Gas Plants (SIC 1321). The facility is currently operating under Permit No TV (M-1) issued February 12, The construction permit will authorize addition of an additional gas plant, the Stonewall Gas Plant, adjacent to the existing facilities. The additional gas plant will add 200 MMSCFD processing capacity, bringing the site capacity to 430 MMSCFD. The proposed construction will add the following units: - Five 2,370-hp Caterpillar G3608LE engines with oxidation catalysts or equivalent controls (EUG-COMP3); - A MMBTUH hot oil heater in demethanization trim reboiler service (EUG-HOH); - A 5.61 MMBTUH hot oil heater in mole sieve regeneration service (EUG-HOH); - A MMBTUH hot oil heater in amine regeneration service (EUG-HOH); - A 10 MMBTUH hot oil heater in amine regeneration service (EUG-HOH); - A 2.0 MMBTUH glycol reboiler (EUG-INSIG-HTR); - A 1.5 MMBTUH glycol reboiler (EUG-INSIG-HTR); - Four 400-bbl condensate tanks (EUG-TANK);

2 PERMIT MEMORANDUM C (M-4) DRAFT 2 - Two 2,923-hp emergency generator diesel engines (EUG-EMRGEN); - An additional emergency flare (EUG-TO); - And additional fugitive VOC leakage components (valves, flanges, etc.) (EUG-SFUGS). The facility currently includes eight 1,478-hp Waukesha Model L7042GSI four-stroke rich-burn compressor engines (all equipped with catalytic converters), six 1,775-hp Caterpillar 3606LE engines (all with oxidative catalysts), two 1,380 Caterpillar 3516B compressor engines (all with oxidative catalysts), a glycol dehydration unit with a 2.0 MMBTUH reboiler and a BTEX Eliminator (condenser), an amine sweetening unit, a 25 MMBTUH hot oil heater, a MMBTUH hot oil heater, an amine unit with a 5.5 MMBTUH regeneration heater, a glycol reboiler with a 2.0 MMBTUH reboiler and a BTEX Eliminator, an emergency flare, seven 400- bbl atmospheric condensate tanks that are controlled with vapor recovery units (VRUs), six 60,000- gallon pressurized NGL tanks (part of facility fugitive VOC emissions), a truck loading operation, and a thermal oxidizer rated at 98% efficiency for control of VOC emissions. Two diesel engine emergency generators (1,881-hp and 2,346-hp) are also present. This expansion of the facility is being commenced two years following the previous expansion (installation of the Tupelo Gas Plant), and is being conducted by the new owner. It is a separate project from the previous expansion. Since added emissions of criteria pollutants are below 100 TPY, BACT is not required. The applicant has received catalyst manufacturer specifications indicating that higher formaldehyde control efficiency can be achieved and is therefore willing to accept federally enforceable limits so that the facility does not become a major source of HAPs. Facility-wide formaldehyde emissions after the modification will be 9.67 TPY. H 2 S in the inlet gas is non-detectable, therefore the amine units are not subject to emissions control requirements of NSPS Subpart LLL (which are applicable only to processing of sour gas). For permitting purposes, the inlet gas will be limited to 4 ppm H 2 S. The facility proposes to install scavenger injection which will reduce H 2 S emissions to below 0.3 lb/hr, the level at which flaring or other controls would be required. Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) in the following outline. Except for the emergency engines, natural gas is the primary fuel with the nonemergency engines being operated continuously. SECTION II. PROCESS DESCRIPTION There are 2-different pressure gas streams entering the gas plants. Mid-pressure inlet gas enters the plants from F at approximately 650 psig. The gas is routed through an inlet gas separator. Some gas then proceeds to the Booster Compressors (TC-1 and TC-2) where the pressure is raised from approximately 650 psig to 900 psig in one compression stage, and is then routed only to the Tupelo Gas Plant. Other mid-pressure gas proceeds directly to the Coalgate Gas Plant. High Pressure (~900 psig) inlet gas enters directly into the Tupelo and Stonewall Gas Plants at F, after passing through inlet separation equipment.

3 PERMIT MEMORANDUM C (M-4) DRAFT 3 The gas will then flow to each plant s respective amine units. The inlet gas contains CO 2 but almost no H 2 S, so the amine unit is designed to remove the CO 2. The rich amine is sent to the heaters (CH-1, H-701, SA-1, and SA-2) where it is regenerated so that the lean amine can be recirculated back to the amine units. The CO 2 and trace amounts of hydrocarbons are vented to the atmosphere (CAV-1, TAV-1, and SAV-1 and SAV-2). The treated gas is routed from the amine units through TEG dehydration units where any entrained water is removed. The rich TEG is sent to the reboilers (CRB-1, TRB-1, and SRB-1 and SRB-2) where it is regenerated so that the lean TEG can be returned to the processes. BTEX Eliminators control the potential benzene, toluene, ethylbenzene and xylene (BTEX) emissions from the reboiler still vents (CSV-1, TSV- 1, and SSV-1 and SSV-2). The BTEX Eliminators condense the still vent gas stream and route the non-condensable vapors back to the dehy s firebox, which utilizes a continuous ignition system. The dried gas from the TEG contactor goes to the cryogenic skid where it passes through a mole sieve bed to remove the remainder of the water, and then through a series of heat exchangers, including propane refrigeration, therefore pre-cooling the gas in order to create higher plant efficiencies. The pre-cooled gas is then expanded to approximately psig through a turboexpander to further chill the gas. Residue gas at this point passes through heat exchangers for energy recovery, is compressed by the turbine side of the turbo-expander, and is then compressed by residue gas compressors (C-1000 to C-1600, TC-3 through TC-8, and SC-1 through SC-6) to pipeline delivery pressure (~ psig). Free-liquids collected in inlet separators are sent to intermediate flash separators, which operate between psig. Then Coalgate and Tupelo Plant s free liquids are routed to a Stabilizer, and after stabilization they are sent to the atmospheric condensate/water storage tanks (TK-801 through TK-808); the Stonewall Plant free liquids will proceed from its flash separator to condensate storage tanks TK-809 through TK-812. Flash emissions, breathing and working losses from the condensate storage tanks, and flash vapors from the intermediate flash separators are currently controlled by a vapor recovery system. The vapor recovery units (VRU-1 through VRU-4) operate as a closed-looped system and have no associated emissions. Condensate loadout for all three plants will continue to be loaded out via the existing Coalgate Tupelo truck loadout. The Y-Grade liquids recovered from the cryogenic process go to the NGL pipeline. The Coalgate and Tupelo Plants also have four pressurized Natural Gas Liquids (NGL) storage tanks (NGL-1 through NGL-4) that can store NGL when needed. These tanks are included in the Title V Permit, although it should be noted that the only potential emissions are accounted for in the plant fugitive emissions calculations. Therefore, they have not been included as a separate emission source in this Permit Application. No additional pressure tanks will be constructed at the Stonewall Plant. In order to prevent the facility from becoming a major source of Hazardous Air Pollutants (HAPs), Arkoma elected to improve the catalyst control systems for the Tupelo and Stonewall engines. Formaldehyde control efficiency will increase from 76% to 88% and reduce the formaldehyde emissions so that emissions are less than 10 TPY.

4 PERMIT MEMORANDUM C (M-4) DRAFT 4 SECTION III. EQUIPMENT Sources of emissions are listed in the following table. The facility may also contain ancillary equipment such as lube oil, ethylene glycol, and TEG storage tanks that are not subject to any emissions limitations or requirements and are not addressed any further. EUG-COMP1: Stationary Engines Not Subject to NSPS Subpart JJJJ EU Emission Unit Description Manufacture Serial Date Number C-900 1,478-hp Waukesha L7042GSI with Catalytic Converter 8/1/06 C-16473/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 11/1/06 C-17207/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 11/1/06 C-17209/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 11/1/06 C-17208/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 9/1/06 C-17115/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 5/1/07 C-16938/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 5/1/07 C-16940/1 C ,478-hp Waukesha L7042GSI with Catalytic Converter 5/1/07 C-16941/1 EUG-COMP2: Stationary Engines Subject to NSPS Subpart JJJJ EU Emission Unit Description Manufacture Date TC-1 1,380-hp Caterpillar G3516B with oxidation catalyst May 2011 TC-2 1,380-hp Caterpillar G3516B with oxidation catalyst May 2011 TC-3 1,775-hp Caterpillar G3606 LE with Not yet oxidation catalyst installed TC-4 1,775-hp Caterpillar G3606 LE with oxidation catalyst April 2011 TC-5 1,775-hp Caterpillar G3606 LE with oxidation catalyst October 2011 TC-6 1,775-hp Caterpillar G3606 LE with September oxidation catalyst 2008 TC-7 1,775-hp Caterpillar G3606 LE with oxidation catalyst August 2010 TC-8 1,775-hp Caterpillar G3606 LE with February oxidation catalyst 2011 Serial Number JEF01180 JEF01179 TBD 4ZS ZS ZS ZS ZS01515

5 PERMIT MEMORANDUM C (M-4) DRAFT 5 EUG-COMP3: Stationary Engines Subject to NSPS Subpart JJJJ EU Emission Unit Description Manufacture Serial Construction Date Number Date SC-1 2,370-hp Caterpillar G3608LE with oxidation catalyst TBD TBD TBD SC-2 2,370-hp Caterpillar G3608LE with oxidation catalyst TBD TBD TBD SC-3 2,370-hp Caterpillar G3608LE with oxidation catalyst TBD TBD TBD SC-4 2,370-hp Caterpillar G3608LE with oxidation catalyst TBD TBD TBD SC-5 2,370-hp Caterpillar G3608LE with oxidation catalyst TBD TBD TBD EUG-HOH: Hot Oil Heaters EU Emission Unit Description Construction Date CH-1 20-MMBTUH Heater (Coalgate Plant) 2007 H MMBTUH Heater (Tupelo Plant) 2011 H MMBTUH Amine Heater (Tupelo Plant) 2011 H MMBTUH Hot Oil Heater (Stonewall Plant) TBD SA MMBTUH Amine Heater (Stonewall Plant) TBD SA-2 10-MMBTUH Amine Heater (Stonewall Plant) TBD EUG-INSIG HTR: Insignificant Heaters EU Emission Unit Description Construction Date CRB-1 2 MMBTUH Dehydrator Reboiler (Coalgate Plant) 2007 TRB-1 2 MMBTUH Dehydrator Reboiler (Tupelo Plant) 2011 SRB MMBTUH Dehydrator Reboiler (Stonewall Plant) TBD SRB-2 2 MMBTUH Dehydrator Reboiler (Stonewall Plant) TBD H MMBTUH Mol Sieve Heater (Stonewall Plant) TBD H MMBTUH - Heater (Tupelo Plant) 2011 EUG-AMINE: Amine Units EU Emission Unit Description Construction Date CAV-1 Amine Unit Still Vent (Coalgate Plant) 2007 TAV-1 Amine Unit Still Vent (Tupelo Plant) 2011 SAV-1 Amine Still Vent (Stonewall Plant) TBD SAV-2 Amine Still Vent (Stonewall Plant) TBD

6 PERMIT MEMORANDUM C (M-4) DRAFT 6 EUG-DEHY: Glycol Dehydration Units EU Emission Unit Description Construction Date CSV-1 Dehydration Unit Still Vent / BTEX Eliminator (Coalgate Plant) TSV-1 Dehydration Unit Still Vent / BTEX Eliminator (Tupelo Plant) SSV-1 Dehydration Unit Still Vent / BTEX Eliminator (Stonewall Plant) TBD SSV-2 Dehydration Unit Still Vent / BTEX Eliminator (Stonewall Plant) TBD H MMBTUH Thermal Oxidizer (Coalgate Plant) NOTE: H-5801 is currently idle but being maintained on location as an emergency back-up if needed. EUG-TANK: Condensate Tanks EU Emission Unit Description Construction Date T bbl Condensate Storage Tank 2007 T bbl Condensate Storage Tank 2007 T bbl Condensate Storage Tank 2007 T bbl Condensate Storage Tank 2007 T bbl Condensate Storage Tank T bbl Condensate Storage Tank T bbl Condensate Storage Tank T bbl Produced Water Storage Tank T bbl Condensate Storage Tank TBD T bbl Condensate Storage Tank TBD T bbl Condensate Storage Tank TBD T bbl Condensate Storage Tank TBD Note: pressurized storage tanks and vapor recovery units are part of facility fugitive VOC emissions. EUG-EMRGEN: Stationary Engines Subject to NSPS Subpart IIII EU Emission Unit Description Construction Manufacture Date Date EMRGEN 1,881-hp Kohler 1250REOZMB (Coalgate) diesel engine EMRGEN1 2,346-hp Kohler 1600REOZMB (Tupelo) diesel engine SEG-1 2,923-hp Kohler 1750REOZMB (Stonewall) SEG-2 (Stonewall) diesel engine 2,923-hp Kohler 1750REOZMB diesel engine Serial Number TBD TBD 2013 TBD TBD EUG-TO: Flares EU Emission Unit Description Construction Date TF-1 Emergency Flare 0.13 MMBTUH 2011 SF-1 Stonewall Plant Emergency Flare 0.13 MMBTUH TBD

7 PERMIT MEMORANDUM C (M-4) DRAFT 7 EUG-CONDLOAD: Condensate Loading EU Emission Unit Description Construction Date LOAD Condensate Loading 2007 EUG-FUGS: Process Piping Fugitive Emissions EU Emission Unit Description Construction Date FUGS Process Piping Fugitive Emissions EUG-SFUGS: Stonewall Plant Process Piping Fugitive Emissions EU Emission Unit Description Construction Date SFUGS Process Piping Fugitive Emissions TBD SECTION IV. POTENTIAL EMISSIONS Criteria Pollutants Emissions were calculated using the following methods: - Engine emissions were calculated using manufacturer emission factors for NOx, CO, VOC, and formaldehyde with the use of dual catalytic converters or oxidation catalysts (CO control approximately 79-93%) for all engines except the emergency generators. The emergency generator emissions were based on 100 hours per year, while all other engines emissions were based on 8,760 hours per year. Engine ID C-900 to C-1600 TC-1 and TC-2 TC-3 to TC-8 EMRGEN EMERGEN1 SC-1 to SC-5 SEG-1 SEG-2 Engine Type 1,478-hp Waukesha L7042GSI with catalytic converter 1,380-hp Caterpillar G3516B with oxidative catalyst 1,775-hp Caterpillar G3606 LE with oxidative catalyst Kohler 1250REOZMB (1,881-hp) Kohler 1600REOZMB (2,346-hp) 2,370-hp Caterpillar G3608 LE with oxidative catalyst Kohler 1750REOZMB (2,923-hp) Formaldehyde g/hp-hr NOx g/hp-hr CO g/hp-hr VOC g/hp-hr

8 PERMIT MEMORANDUM C (M-4) DRAFT 8 - Emissions from the glycol reboilers and hot oil heaters are based on AP-42 (7/00), Section 1.4. For H-781 and H-741, a 20% safety factor was added to AP-42 factors. - Emissions from the Coalgate glycol dehydration unit were calculated using Gly-CALC version 4.0, a recent gas analysis, a maximum natural gas processing capacity of 80 MMSCFD, and a glycol circulation rate of 30 GPM. The still vent is routed to the BTEX Eliminator. Flash tank off-gases are shown in the Gly-Calc run as being vented to the fuel gas and BTEX Eliminator. The reboiler has a continuous igniter to keep burning VOC when the heater cycles off. The two methods have a control efficiency of 98%. - Emissions from the Tupelo glycol dehydration unit were calculated using Gly-CALC version 4.0, a recent gas analysis, a maximum natural gas processing capacity of 125 MMSCFD, and a glycol circulation rate of 30 GPM. The still vent is routed to the BTEX Eliminator. The flash tank is vented to the fuel gas system and the BTEX Eliminator with an overall 98% control. - Emissions from the Stonewall Plant glycol dehydration units were calculated using Gly- CALC version 4.0, a recent gas analysis, a maximum natural gas processing capacity of 120 MMSCFD and a glycol circulation rate of 32.3 GPM for Stonewall Unit 1 and 80 MMSCFD and 22 GPM for Stonewal Unit 2. The still vents are routed to BTEX Eliminators. Flash tank off-gases are shown in the Gly-Calc runs as being recovered and recycled. The reboilers have continuous igniters to keep burning VOC when the heater cycles off. The two methods have a control efficiency of 98%. - Emergency flare emissions were calculated using Texas Commission on Environmental Quality Guidance Document factors: lb/mmbtu NOx and lb/mmbtu CO. Heat input of 0.13 MMBTUH was used for each flare. - VOC emissions from each amine unit vent were calculated using VOC content determined from grab samples collected from the Coalgate and Tupelo amine vents on June 20, 2012 and ratioed up for maximum potential amine vent flow rates, including a safety factor. - Emissions from the atmospheric condensate tanks are controlled by a vapor recovery unit (VRU). - Emissions from the Coalgate and Tupolo condensate truck loading operation were calculated using 12,600,000 gallons per year throughput, 90 molecular weight, 1.45 saturation factor, and 1 psia vapor pressure, using the methods of AP-42 (1/95), Section 5.2. Emissions from the Stonewall Plant condensate truck loading operation were calculated 7,199,808 gallons throughput, 81 molecular weight, 0.6 saturation factor, and 1.6 psia vapor pressure. - Emissions from fugitive equipment leaks are based on EPA s document, 1995 Protocol for Equipment Leak Emission Estimates, Table 2-4, Oil and Gas Operations Average Emissions Factors for process piping fugitives, and counts of components.

9 PERMIT MEMORANDUM C (M-4) DRAFT 9 Coalgate & Tupelo Plants Component Number of Emission Factor, Percent VOC Leakage Components lb/hr/component VOC lb/hr TPY Gas/Vapor Valves % Light Liquid Valves % Heavy Liquid Valves % Light Liquid Pump Seals % Heavy Liquid Pump Seals % Gas/Vapor Flanges % Light Liquid Flanges % Heavy Liquid Flanges % Gas/Vapor Relief Valves % Compressors % Gas/Vapor Connectors 1, % Light Liquid Connectors % Heavy Liquid Connectors % TOTALS Stonewall Plant Component Number of Emission Factor, Percent VOC Leakage Components lb/hr/component VOC lb/hr TPY Gas/Vapor Valves % Light Liquid Valves % Heavy Liquid Valves % Light Liquid Pump Seals % Heavy Liquid Pump Seals % Gas/Vapor Flanges % Light Liquid Flanges % Heavy Liquid Flanges % Gas/Vapor Relief Valves % Compressors % Gas/Vapor Connectors % Light Liquid Connectors % Heavy Liquid Connectors % TOTALS

10 PERMIT MEMORANDUM C (M-4) DRAFT 10 Sources EXISTING EMISSIONS C-900, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1000, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1100, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1200, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1300, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1400, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1500, 1,478-hp Waukesha L7042GSI with Catalytic Converter C-1600, 1,478-hp Waukesha L7042GSI with Catalytic Converter EMRGEN, 1,881-hp Kohler 1250 REOZMB emergency generator EMRGEN1, 2,346-hp Kohler 1600 REOZMB emergency generator TC-1, 1,380-hp Caterpillar G3516B with oxidative catalyst TC-2, 1,380-hp Caterpillar G3516B with oxidative catalyst TC-3, 1,775-hp Caterpillar G3606LE with oxidative catalyst TC-4, 1,775-hp Caterpillar G3606LE with oxidative catalyst TC-5, 1,775-hp Caterpillar G3606LE with oxidative catalyst TC-6, 1,775-hp Caterpillar G3606LE with oxidative catalyst TC-7, 1,775-hp Caterpillar G3606LE with oxidative catalyst TC-8, 1,775-hp Caterpillar G3606LE Facility-Wide Emissions NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY with oxidative catalyst CH-1, 20 MMBTUH Hot Oil Heater H-771, MMBTUH Hot Oil Heater H-701, MMBTUH Amine Unit Heater

11 PERMIT MEMORANDUM C (M-4) DRAFT 11 Sources NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY TRB-1, 2.0 MMBTUH Glycol Reboiler CRB-1, 2.0 MMBTUH Glycol Reboiler Condensate Tanks * * Condensate Truck Loading NGL-1 NGL-6, NGL Product Tanks ** ** Site Process Fugitives TF-1, Emergency Flare (0.13 MMBTUH) TSV-1, Tupelo Dehydration Unit and BTEX Eliminator CSV-1, Coalgate Dehydration Unit and BTEX Eliminator CAV-1, Coalgate Amine Unit Vent TAV-1, Tupelo Amine Unit Vent H-700, 5.5 MMBTUH Amine Unit Heater Totals ADDED EMISSIONS (STONEWALL) SC-1, Caterpillar G3608LE with oxidative catalyst SC-2, Caterpillar G3608LE with oxidative catalyst SC-3, Caterpillar G3608LE with oxidative catalyst SC-4, Caterpillar G3608LE with oxidative catalyst SC-5, Caterpillar G3608LE with oxidative catalyst SEG-1, 2,923-hp Kohler 1750 REOZMB emergency generator SEG-2, 2,923-hp Kohler 1750 REOZMB emergency generator H-781, MMBTUH Hot Oil Heater H-741, 5.61 MMBTUH Regen Heater SA-1, MMBTUH Amine Heater SA-2, 10 MMBTUH Amine Heater SAV-1, Amine Still Vent SAV-2, Amine Still Vent SRB-1, 1.5 MMBTUH Reboiler SSV-1, Dehydrator Still Vent SRB-2, 2.0 MMBTUH Reboiler

12 PERMIT MEMORANDUM C (M-4) DRAFT 12 Sources NOx CO VOC lb/hr TPY lb/hr TPY lb/hr TPY SSV-2, Dehydrator Still Vent Condensate Tanks * * Condensate Truck Loading SF-1, Emergency Flare (0.13 MMBTUH) SFUG, Stonewall Plant Fugitive VOCs TOTAL ADDED EMISSIONS TOTAL EMISSIONS AFTER MODIFICATION *atmospheric condensate tanks are vented to vapor recovery units (VRUs), with only fugitive emissions. ** emissions from pressurized tanks are a component of fugitive VOC leakage. Greenhouse Gas Emissions Existing potential greenhouse gas emissions were stated at 117,915 TPY CO 2 e, and added GHG emissions were shown at 69,061 TPY CO 2 e, for a total of 186,976 TPY CO 2 e. The facility is a major source of GHG but added emissions do not exceed the PSD threshold of 75,000 TPY. Hazardous Air Pollutants (HAP) Dehydration units using glycol desiccants emit benzene, toluene, ethyl benzene, and xylene (BTEX) and n-hexane from the glycol still vent. The applicant has analyzed the incoming wet gas for concentrations of n-hexane and BTEX and estimated the HAP emissions using GRI- GLYCalc TM. Dehydration Unit HAP Emissions HAP Coalgate Tupelo Stonewall Stonewall SSV-1 SSV-2 TOTALS lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY Benzene Toluene Ethyl Benzene Xylene Hexane Totals

13 PERMIT MEMORANDUM C (M-4) DRAFT 13 The compressor engines have emissions of HAP, the most significant being formaldehyde. The table below lists estimated potential controlled formaldehyde emissions for the compressor engines based on continuous operation. Formaldehyde control from the dual catalysts is approximately 77%. Formaldehyde Emissions Sources Emission Factor, Formaldehyde g/hp-hr lbs/hr TPY C-900, 1,478-hp Waukesha G-L7042GSI C-1000, 1,478-hp Waukesha G-L7042GSI C-1100, 1,478-hp Waukesha G-L7042GSI C-1200, 1,478-hp Waukesha G-L7042GSI C-1300, 1,478-hp Waukesha G-L7042GSI C-1400, 1,478-hp Waukesha G-L7042GSI C-1500, 1,478-hp Waukesha G-L7042GSI C-1600, 1,478-hp Waukesha G-L7042GSI TC-1, 1380-hp Caterpillar G3516B TC-2, 1380-hp Caterpillar G3516B TC-3, 1,775-hp Caterpillar G3606LE TC-4, 1,775-hp Caterpillar G3606LE TC-5, 1,775-hp Caterpillar G3606LE TC-6, 1,775-hp Caterpillar G3606LE TC-7, 1,775-hp Caterpillar G3606LE TC-8, 1,775-hp Caterpillar G3606LE SC-1, 2,370-hp Caterpillar G3608LE SC-2, 2,370-hp Caterpillar G3608LE SC-3, 2,370-hp Caterpillar G3608LE SC-4, 2,370-hp Caterpillar G3608LE SC-5, 2,370-hp Caterpillar G3608LE ,881-hp Kohler 1250REOZMB diesel engine ,346-hp Kohler 1600REOZMB diesel engine SEG-1, 2,923-hp Kohler 1750REOZMB SEG-2, 2,923-hp Kohler 1750REOZMB Totals Emissions of each HAP are less than 10 TPY, and total HAP emissions are less than 25 TPY. The facility is, therefore, an area source of HAPs. Fuel consumption for each 1,478-hp Waukesha G-L7042GSI engine has been listed at 7,824 BTU/hp-hr for a fuel consumption of MSCFH per engine. Air emissions from each engine are discharged through a stack 12 inches in diameter, 20 feet above grade, at a rate of 6,967 ACFM at 1,125 o F. Moisture content of stack gases has been estimated at 16.6% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel.

14 PERMIT MEMORANDUM C (M-4) DRAFT 14 Fuel consumption for each 1,775-hp Caterpillar G3606 LE engine has been listed at 6,781 BTU/hp-hr for a fuel consumption of MSCFH per engine. Air emissions from each engine are discharged through a stack 16 inches in diameter, 23 feet above grade, at a rate of 12,004 ACFM at 867 o F. Moisture content of stack gases has been estimated at 8.4% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. Fuel consumption for each 1,380-hp Caterpillar G3516 B engine has been listed at 7,301 BTU/hp-hr for a fuel consumption of 10.1 MSCFH per engine. Air emissions from each engine are discharged through a stack 16 inches in diameter, 23 feet above grade, at a rate of 9,126 ACFM at 992 o F. Moisture content of stack gases has been estimated at 10.1% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. Fuel consumption for each 2,370-hp Caterpillar G3608LE engine has been listed at 7,525 BTU/hp-hr for a fuel consumption of 16.1 MMBTU per engine. Air emissions from each engine are discharged through a stack 22 inches in diameter, 23 feet above grade, at a rate of 16,106 ACFM at 857 o F. Moisture content of stack gases has been estimated at 8.3% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. SECTION V. INSIGNIFICANT ACTIVITIES The insignificant activities identified and justified in the application are duplicated below. Records are available to confirm the insignificance of the activities. Appropriate recordkeeping of activities indicated below with * is specified in the Specific Conditions. 1. * Stationary reciprocating engines burning natural gas, gasoline, aircraft fuels, or diesel fuel which are either used exclusively for emergency power or for peaking power service not exceeding 500 hours/year. The emergency generators are subject to NSPS Subpart IIII, therefore, are not insignificant activities. 2. * Space heaters, boilers, process heaters and emergency flares less than or equal to 5 MMBTUH heat input fired by commercial natural gas. The glycol reboiler heaters and emergency flare are less than 5 MMBTUH. 3. Emissions from crude oil and condensate storage tanks with a capacity of less than or equal to 420,000 gallons that store crude oil and condensate prior to custody transfer. The condensate tanks store condensate prior to custody transfer and each has a capacity of less than 420,000 gallons; however, since these tanks are to be vented to a VRU, no records will be required. 4. * Emissions from storage tanks constructed with a capacity less than 39,894 gallons which store a VOC with a vapor pressure less than 1.5 psia at maximum storage temperature. All of the tanks at the facility, other than the condensate tanks, have capacities less than 39,894 gallons and store products having a vapor pressure less than 1.5 psia.

15 PERMIT MEMORANDUM C (M-4) DRAFT 15 SECTION VI. OKLAHOMA AIR POLLUTION CONTROL 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] Subchapter 3 enumerates the primary and secondary ambient air quality standards and the significant deterioration increments. At this time, all of Oklahoma is in attainment of these standards. OAC 252:100-5 (Registration, Emission 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. The applicant will be required to submit an emissions inventory and submit fees. 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 HAP or 20% of any threshold less than 10 TPY for single HAP that the EPA may establish by rule Emission limitations and operational requirements necessary to assure compliance with all applicable requirements for all sources are taken from the 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

16 PERMIT MEMORANDUM C (M-4) DRAFT 16 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, reboilers, and engines are subject to the requirements of this subchapter. The facility s flare and thermal oxidizer 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 0.35 for fuel-burning equipment with a rated heat input range of 10 MMBTUH or less up to 100 MMBTUH. AP-42 (7/98) Table lists total PM emissions as lb/mmbtu for natural gas combustion. AP-42 (7/00) Section 3.2 lists total PM emissions from natural gas-fired reciprocating internal combustion engines as about 0.01 lb/mmbtu. This permit requires the use of natural gas for all fuel-burning units except for the emergency generators to ensure compliance with Subchapter 19. For the emergency generators, the heat input is stated at 12.7 MMBTUH and TSP emissions are stated at 0.15 g/hp-hr (0.62 lb/hr). This is equivalent to lb/mmbtu, which is in compliance with the limitation of 0.58 lb/mmbtu. 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. There is little possibility of exceeding these standards when burning natural gas. This permit requires the use of natural gas for all fuel-burning units except the emergency generators 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 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.

17 PERMIT MEMORANDUM C (M-4) DRAFT 17 OAC 252: (Sulfur Compounds) [Applicable] Part 2 limits the ambient air impact of hydrogen sulfide emissions from any new or existing source to 0.2 ppm for a 24-hour average (equivalent to 280 g/m 3 ). The gas processed at this facility has negligible amounts of H 2 S, therefore, compliance with these standards is assured. H 2 S emissions and impacts were based on a worst-case 0.4 ppm in inlet gas at Stonewall, 1.0 ppm in inlet gas at Coalgate and 0.64 ppm at Tupelo (recalling that any higher concentrations will be treated to reduce to 1 ppm or less, and the efficiency of the amine unit in removing H 2 S is low at low concentrations), with emission rates as calculated by the mass balance, assuming all H2S is emitted at the amine units. For the Amine Units, EPA SCREEN3 dispersion modeling was conducted based on the stack parameters listed below. The 1-hour impacts predicted by SCREEN3 were converted to 24-hour impacts using a factor of 0.4, as presented in Screening Procedures for Estimating the Air Quality Impact from Stationary Sources, Revised (EPA- 454/R ). The SCREEN3 results are tabulated below. Amine Unit Gas Rate MMSCFD H 2 S Emissions lb/hr * Stack Diam. Ft Stack Height Ft Stack Velocity ft/sec Stack Temp o F 24-hour Impacts ug/m 3 Coalgate Tupelo Stonewall TOTALS 8.4 *These values are calculated assuming all H 2 S in the inlet gas is emitted from the amine units. According to AMINECALC, only about half of the H 2 S is removed by the amine units. Part 5 limits sulfur dioxide emissions from new equipment (constructed after July 1, 1972). For gaseous fuels, the limit is 0.2 lb/mmbtu heat input. For fuel gas having a gross calorific value of 1,000 BTU/scf, this limit corresponds to a fuel sulfur content of approximately 1,200 ppmv. Thus, a limitation of 343-ppmv sulfur in a field gas supply will be in compliance. The permit requires the use of natural gas with a maximum sulfur content of 343-ppmv for all fuel-burning equipment except the emergency generators to ensure compliance with Subchapter 31. For the emergency generators, NSPS Subpart IIII limits the fuel sulfur content to 500 ppm, which is equivalent to 0.05 lb/mmbtu. This emission rate is in compliance with the liquid fuel standard of Subchapter 31 of 0.8 lb/mmbtu. Part 5 also limits hydrogen sulfide (H 2 S) emissions from new petroleum or natural gas process equipment (constructed after July 1, 1972). Removal of H 2 S in the exhaust stream, or oxidation to sulfur dioxide (SO 2 ), is required unless H 2 S emissions would be less than 0.3 lb/hr for a twohour average. With a maximum H 2 S concentration of 0.4 ppm in gas at Stonewall, 1 ppm in gas at Coalgate, and 0.64 ppm in gas at Tupelo, the facility meets the 0.3 lb/hr exemption level. 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 equal or exceed the 50 MMBTUH threshold.

18 PERMIT MEMORANDUM C (M-4) DRAFT 18 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. The condensate storage tanks are subject to this requirement. 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 facility. 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 AOC has been designated anywhere in the state, there are no specific requirements for this facility at this time. 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.

19 PERMIT MEMORANDUM C (M-4) DRAFT 19 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] Total added potential emissions of regulated pollutants are less than the threshold level of 250 TPY. NSPS, 40 CFR Part 60 [Subparts Dc, KKK, IIII, JJJJ, and OOOO Are Applicable] Subpart Dc (Small Steam Generating Units) sets standards of performance for steam generating units with a maximum design heat input capacity of 100 MMBTUH or less, but greater than 10 MMBTUH that were constructed after June 9, The natural gas-fired hot oil heaters (CH-1, H-771, H-701, SA-1, SA-2 and H-781) are subject to this subpart. The only standard applicable to gas-fired units is to keep records showing the amount of each fuel used. Subpart Dc excludes process heaters, and the regeneration heaters do not meet the definition of steam generating unit in Subpart Dc. Subparts K, Ka, Kb, Volatile Organic Liquid (VOL) Storage Vessels. All tanks are below the 19, 813 gallon threshold for Subpart Kb. Subpart GG, Stationary Gas Turbines. There are no stationary gas turbines at this facility. Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants constructed, reconstructed, or modified after January 20, 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. The facility will be subject to Subpart KKK once the gas plant is constructed. Subpart KKK specifically exempts reciprocating compressors in wet gas service, and compressors that are not in VOC service, from all but notification and recordkeeping requirements of (j) and (a) and (c). The permittee will be required to maintain a leak detection and repair (LDAR) program for all equipment that is in VOC service at the existing Coalgate and Tupelo Plants. New equipment at the proposed Stonewall Plant will be subject to NSPS Subpart OOOO instead of Subpart KKK. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. This subpart sets standards for natural gas sweetening units. Subpart LLL affects units which sweeten sour natural gas, which is defined as gas having more than 4 ppm H 2 S. Since H 2 S is non-detectable in the inlet gas and will be limited to 4 ppm, the amine units are not subject to Subpart LLL.

20 PERMIT MEMORANDUM C (M-4) DRAFT 20 Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines, affects stationary compression ignition (CI) internal combustion engines (ICE) based on power and displacement ratings, depending on date of construction, beginning with those constructed after July 11, For the purposes of this subpart, the date that construction commences is the date the engine is ordered by the owner or operator. Model year 2007 and later engines which are not fire pump engines which have a cylinder displacement less than 10 liters per cylinder and a rated capacity less than 3,000-hp are subject to the fuel sulfur limit of , the emissions limits of Table 1 to Subpart IIII for engines between 750 and 3,000-hp, and to manufacturer certification requirements. EMRGEN, EMERGEN1, SEG-1 and SEG-2 are subject. Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI-ICE), promulgates emission standards for all new SI engines ordered after June 12, 2006, and all SI engines modified or reconstructed after June 12, 2006, regardless of size. 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 non-emergency), and numerous manufacture dates. The applicability date of rich-burn non-emergency spark-ignition engines is July 1, 2007; all existing rich-burn engines were manufactured prior to this date. The new 1,380- hp Caterpillar G3516B, 1,775-hp Caterpillar G3606 LE engines, and 2,370-hp Caterpillar G3608LE engines are subject to the requirements of Subpart JJJJ. An initial performance test must be conducted; in addition, engines that are greater than 500 HP must conduct a performance test every 8,760 hours of operation or every 3 years thereafter, whichever comes first. Rich burn engines operating with three-way catalysts or non-selective catalytic reduction must be equipped with an air-to-fuel ratio controller operated in an appropriate manner to ensure proper operation of the engine and control device in order to minimize emissions. Engine ID Description C-190 1,478-hp Waukesha to C- L7042GSI 1600 TC-1 to 1,380-hp Caterpillar TC-2 G3516B TC-3 to 1,775-hp Caterpillar TC-8 G3606 LE SC-1 to 2,370-hp Caterpillar SC-5 G3608LE * corrected to 15% oxygen. Effective Date NOx CO VOC g/hp-hr ppm * g/hp-hr ppm * g/hp-hr ppm * 7/1/ /1/ /1/ /1/ Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution. This subpart was promulgated on August 16, 2012, and affects the following sources that commence construction, reconstruction, or modification after August 23, 2011:

21 PERMIT MEMORANDUM C (M-4) DRAFT 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; 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. For each reciprocating compressor the owner/operator must replace the rod packing before 26,000 hours of operation or prior to 36 months. If utilizing the number of hours, the hours of operation must be continuously monitored. Commenced construction is based on the date of installation of the compressor (excluding relocation) at the facility. Any new or modified compressors will have to comply with this subpart. There are no pneumatic controllers with a bleed rate of 6 SCFH. 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. All storage vessels utilize vapor recovery compressors, thus emissions are negligible and below the 6.0 TPY threshold. 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 standard will affect the new Stonewall Plant. A sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream. There are two sweetening units at this facility and two more will be added. Sweetening plants which process less than 2.0 LT/D sulfur are required to comply only with recordkeeping requirements. The permit will require the facility to comply with all applicable requirements of NSPS, Subpart OOOO.