OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION DRAFT MEMORANDUM December 9, 2008 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 David Schutz, P.E., New Source Permits Section Evaluation of Permit Application No. 2004-235-C (M-3) Enogex Products LLC Cox City Processing Plant Section 26, T4N, R6W, Grady County Direction: From the Junction of US-81 and SH-17 at Rush Springs, 10 Miles East, Two Miles North, West Into Facility Latitude: 34.796 o N, Longitude 97.798 o W SECTION I. INTRODUCTION Enogex has applied for a construction permit to merge two existing, separate facilities into one combined facility. The two facilities are the Cox City Processing Plant and the Comanche Tie Compressor Station. A pipeline will be installed between the two adjacent facilities to allow them to operate as a single natural gas processing plant (SIC 1321). The Cox City facility is currently operating under Permit No. 2004-235-O (M-2) issued October 24, 2005, while the Comanche Tie Compressor Station is currently operated under Permit No. 93-132-O (M-1) issued July 15, 2005. Individually, the two facilities are minor sources. Collectively, the two combined together constitute a major source. The construction project is subject to Tier II review. However, since no new equipment is being added, BACT requirements are not applicable. Current limits for dehydration units at the Cox City plant will be altered given the change in gas throughput allowed by the increase in available gas and available compression horsepower.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 2 SECTION II. FACILITY DESCRIPTIONS a. Cox City Processing Plant This facility currently consists of one 1,478-hp Waukesha Model L7042GSI stationary internal combustion engine equipped with a catalytic converter; two 1,232-hp Waukesha Model L7042 GSI engines with catalytic converters; one 1,100-hp White-Superior Model 8GTLE stationary internal combustion engine; two glycol dehydration units, each equipped with a 0.75 MMBTUH reboiler; four 400-bbl condensate tanks; one 400-bbl methanol tank; one 3.3 MMBTUH gas-fired process heater; one 2.15 MMBTUH regeneration heater; one 2.7 MMBTUH regeneration heater; one 7.0 MMBTUH hot oil heater; a condensate stabilizer unit; a truck loading operation for condensate; two cryogenic skids for extraction of natural gas liquids from field gas; and two emergency flares. The facility includes 8 electrically-powered compressors. There are also tanks storing produced water, wastewater, engine oil and antifreeze. The equipment has been divided into three areas, designated Cox City No. 1 and No. 2, Cox City No. 3, and Cox City No. 4. b. Comanche Tie Compressor Station The facility consists of one 4,500-hp Solar Centaur turbine (C-5), one 1,300-hp Solar Saturn turbine, and one 300-bbl condensate tank. SECTION III. PROCESS DESCRIPTIONS a. Cox City Processing Plant Natural gas is transported to the facility by a pipeline gathering system. The field gas enters the facility through inlet separators where produced condensate and water are separated from the gas stream. This condensate is processed by a stabilizer to remove light hydrocarbons and eliminate flash emissions during storage. The gas is first compressed in inlet compressors, then processed by two glycol dehydration units. A second dehydration step is conducted by a molecular sieve unit. Dehydrated gas flows to a cryogenic processing skid for removal of natural gas liquids (ethane, propane, butane, pentane, etc.). Some of the natural gas liquids are processed to distill out propane, which is stored in pressurized tanks. Remaining natural gas liquids and residue gas from cryogenic processing leave the facility by pipelines. b. Comanche Tie Compressor Station The facility is a natural gas transmission station responsible for the compression of natural gas into a pipeline. Storage of condensate occurs on-site as well. Natural gas is transported to the facility via a pipeline transmission system. The gas stream enters the Facility through an inlet separator where condensate and produced water are removed from the inlet gas stream. The gas stream is then compressed by one (1) Solar Centaur turbine (COMP5) driven compressor rated at 4,500 horsepower (Hp) and one (1) Solar Saturn turbine (COMP6) driven compressor rated at
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 3 1,300 horsepower (Hp). After the inlet gas passes through the compressors, the gas exits the facility for transmission via pipeline. SECTION IV. EQUIPMENT EUG 1. Engines EU Point Make/Model HP Serial # Installed Date COMP1 152 Waukesha L7042GSI 1,478 387240 2000 COMP2 544 Waukesha L7042GSI 1,232 306628 1992 COMP3 545 Waukesha L7042GSI 1,232 179133 1992 COMP4 546 White-Superior 8GTLE 1,100 20548 1992 EUG 2. Turbines EU Point Make/Model HP Serial # Installed Date COMP5 415 Solar Centaur 4,500 OHD08-C0513 1994 COMP6 411 Solar Saturn 1,300 1150S 1990 EUG 3 is shown on the application as electric compressor engines. Since electrical drivers will not have air emissions, they are omitted from this permit. EUG 4. Dehydration Units EU Point Equipment Throughput MMSCFD Installed Date DEHY1 D-1 West Dehydration Unit 100 1995 DEHY2 D-2 East Dehydration Unit 100 1995 EUG 5A. Other Fuel-Burning Equipment EU Point Equipment MMBTUH Installed Date HEAT1 H-1 Regeneration Heater 2.15 1992 HEAT2 H-2 Hot Oil Heater 7.0 1992 HEAT3 H-3 West Dehydration Reboiler 0.75 1995 HEAT4 H-4 East Dehydration Reboiler 0.75 1995 HEAT5 H-5 Gas Heater 3.3 1995 HEAT6 H-6 Regeneration Heater 2.7 1992 EUG 5B. Plant Flares EU Point Equipment MMBTUH Installed Date FLARE1 F-1 Plant No. 3 Flare 0.05 1994 FLARE2 F-2 Plant No. 4 Flare 0.15 1995
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 4 EUG 6. Condensate Tanks EU Point Contents Gallons Installed Date TANK1 T-1 Condensate 16,800 1999 TANK2 T-2 Condensate 16,800 2000 TANK3 T-3 Condensate 16,800 2000 TANK4 T-4 Condensate 16,800 1994 TANK5 T-5 Condensate 12,600 2004 EUG 7A. Other Tanks (Not Subject to OAC 252:100-37) EU Point Contents Gallons Installed Date TANK11 T-11 Engine Oil 500 NA TANK12 T-12 Engine Oil 500 NA TANK13 T-13 Engine Oil 500 NA TANK14 T-14 Engine Oil 500 NA TANK15 T-15 Engine Oil 500 NA TANK16 T-16 Engine Oil 500 NA TANK17 T-17 Engine Oil 8,400 NA TANK18 T-18 Engine Oil 600 NA TANK19 T-19 Engine Oil 500 NA TANK20 T-20 Engine Oil 500 NA TANK21 T-21 Engine Oil 600 NA TANK22 T-22 Engine Oil 500 NA TANK25 T-25 Methanol 300 NA TANK26 T-26 Methanol 300 NA TANK27 T-27 Methanol 300 NA TANK28 T-28 Methanol 300 NA TANK29 T-29 Methanol 300 NA TANK30 T-30 Methanol 300 NA TANK31 T-31 Methanol 300 NA TANK32 T-32 Methanol 300 NA TANK 33 T-33 Coolant 500 NA TANK 34 T-34 Coolant 500 NA TANK 35 T-35 Coolant 500 NA TANK 36 T-36 Produced Water 8,820 NA TANK 37 T-37 Produced Water 8,820 NA TANK 38 T-38 Produced Water 16,800 NA TANK 39 T-39 Soap 500 NA TANK 40 T-40 Triethylene Glycol 500 NA TANK 41 T-41 Triethylene Glycol 500 NA TANK 42 T-42 Triethylene Glycol 1,500 NA TANK 43 T-43 Diesel 300 NA
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 5 EUG 7B. Other Tanks (Subject to OAC 252:100-37) EU Point Contents Gallons Construction Date TANK6 T-6 Propane (pressure tank) 41,000 1984 TANK7 T-7 Propane (pressure tank) 41,000 1984 TANK8 T-8 Propane (pressure tank) 29,858 1984 TANK9 T-9 Propane (pressure tank) 29,858 1984 TANK10 T-10 Propane (pressure tank) 1,000 1981 TANK23 T-23 Methanol 16,800 1981 TANK24 T-24 Methanol 2,000 >1974 EUG 8. Truck Loading EU Point Equipment Maximum Anticipated Annual Throughput, Gallons Installed Date LOAD1 L-1 Cox City Plant Truck Loading 6,200,000 1992 LOAD2 L-2 Comanche Tie Truck Loading 30,660 1995 EUG 9. Process Piping Fugitive VOC Leakage EU Point Description Number of Items F-FUG P-FUG Fugitive VOC Leakage 3,445 Valves 5,541 Flanges 175 Relief Valves 96 Pump Seals Installed Date 1992 to present SECTION V. EMISSIONS Emissions were calculated using the following methods: EUG -1: Engine emissions are based on the following operating hours and manufacturer s data, except for formaldehyde from the White-Superior engine which was estimated using AP-42 &7/00), Section 3.2. Unit ID COMP1 COMP2 COMP3 COMP4 Description 1,478-HP Waukesha L7042GSI 1,232-HP Waukesha L7042GSI 1,232-HP Waukesha L7042GSI 1,100-HP White- Superior 8GTLE Hours of Operations Per Year NOx g/hphr CO g/hphr VOC g/hp-hr Formaldehyde g/hp-hr 3,500 2.0 2.0 0.15 0.015 8,760 2.0 2.0 0.15 0.015 8,760 2.0 2.0 0.15 0.015 8,760 2.0 2.0 1.25 0.183
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 6 EUG-2: Turbine emissions are based on the following operating hours and manufacturer s data. Unit ID Description Hours of Operations Per Year NOx g/hphr CO g/hphr VOC g/hp-hr Formaldehyde lb/mmbtu COMP5 4,500-HP Solar Centaur 8,760 1.75 1.0 0.30 0.00479 COMP6 1,300 Solar Saturn 8,760 1.75 1.0 0.30 0.00479 EUG-4: VOC and HAP emissions from the dehydration units were estimated using the GRI software, GLYCalc 4.0 using the Atmospheric Rich/Lean method, an extended gas analysis, and maximum glycol circulation capacity. A gas flow of 100 MMSCFD and a glycol circulation rate of 7.8 GPM were entered into the program for each of the two dehydration units. A combined control efficiency of 95% was used for a condenser on each dehydration unit and combustion of the uncondensed gases. EUG-5A: Emissions from the plant heaters were estimated using factors from AP-42 (7/98), Section 1.4. EUG-5B: Emissions from the flares were based on pilot flame fuel combustion and factors in AP-42 (1/95), Section 13.5. EUG-6: Condensate tanks TANK1, TANK2, TANK3, and TANK4 emissions were calculated using the TANKS 4.09 computer software using a maximum total annual throughput of 6,200,000 gallons (1,550,000 gallons per year per tank) and an average vapor pressure of 5.4 psia. The applicant has not estimated flash emissions from these tanks since light hydrocarbons are distilled from the condensate in the condensate stabilizer unit. Condensate tank TANK5 emissions were calculated using the TANKS 4.09 computer software using a maximum annual throughput of 30,660 gallons and an average vapor pressure of 6.02 psia. Flash emissions were calculated using the Vasquez-Beggs correlation with default parameters used. EUG-7A and EUG-7B: VOC emissions from the pressure tanks and auxiliary tanks are expected to be negligible. EUG-8: Emissions from the Cox City Plant condensate truck loading operation were calculated using 6,200,000 gallons per year throughput and 5.4 psia vapor pressure, using the methods of AP-42 (1/95), Section 5.2. Emissions from the Comanche Tie Compressor Station condensate truck loading operation were calculated using 30,660 gallons per year throughput and 6.02 psia vapor pressure, using the methods of AP-42 (1/95), Section 5.2. EUG-9: 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.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 7 A. Pre-Project CRITERIA POLLUTANT EMISSIONS NO x CO VOC Source Unit ID lb/hr TPY lb/hr TPY lb/hr TPY Cox City Plant No. 4 1,478-hp Waukesha 7042GSI, S/N 387240 COMP1 6.52 11.40 6.52 11.40 0.49 0.86 West Dehydration Unit Still Vent D-1 -- -- -- -- 1.26 5.51 West Dehydration Unit Reboiler (0.75 MMBTUH) H-3 0.07 0.32 0.06 0.27 0.01 0.02 East Dehydration Unit Still Vent D-2 -- -- -- -- 1.26 5.51 East Dehydration Unit Reboiler (0.75 MMBTUH) H-4 0.07 0.32 0.06 0.27 0.01 0.02 Direct-Fired Gas Heater (3.3 MMBTUH) H-5 0.32 1.42 0.27 1.19 0.02 0.08 Process Piping Fugitive VOC Leakage P-FUG -- -- -- -- 6.39 27.97 400-bbl Condensate Storage Tank T-1 -- -- -- -- 400-bbl Condensate Storage Tank T-2 -- -- -- -- 400-bbl Condensate Storage Tank T-3 -- -- -- -- -- 11.94 Emergency Flare P-11 0.01 0.05 0.06 0.25 0.02 0.09 Truck Loading L-1 -- -- -- -- -- 15.64 Cox City Plant No. 3 Emergency Flare F-1 0.01 0.02 0.02 0.08 0.01 0.03 1,232-hp Waukesha 7042GSI, S/N 306628 COMP2 5.43 23.79 5.43 23.79 0.41 1.78 1,232-hp Waukesha 7042GSI, S/N 179133 COMP3 5.43 23.79 5.43 23.79 0.41 1.78 1,100-hp White-Superior 8GTLE, S/N 20548 COMP4 4.85 21.24 4.85 21.24 3.03 13.28 Regeneration Heater, 2.15 MMBTUH H-1 0.21 0.92 0.18 0.78 0.01 0.05 Hot Oil Heater, 7.0 MMBTUH H-2 0.69 3.01 0.58 2.52 0.04 0.17 400-bbl Condensate Storage Tank T-4 -- -- -- -- -- 1.37 400-bbl Methanol Storage Tank T-23 -- -- -- -- -- 0.08 Process Piping Fugitive VOC Leakage P-FUG -- -- -- -- 1.03 4.53 Cox City Plants No. 1 and 2 2.7 MMBTUH Process Heater H-6 0.26 1.16 0.22 0.97 0.01 0.06 Process Piping Fugitive VOC Leakage P-FUG -- -- -- -- 1.92 8.27 Totals 23.87 87.44 23.68 86.55 16.33 99.04
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 8 A. Post-Project NO x CO VOC Source Unit ID lb/hr TPY lb/hr TPY lb/hr TPY Cox City Plant No. 4 1,478-hp Waukesha 7042GSI, S/N 387240 COMP1 6.52 11.40 6.52 11.40 0.49 0.86 West Dehydration Unit Still Vent D-1 -- -- -- -- 4.35 19.04 West Dehydration Unit Reboiler (0.75 MMBTUH) H-3 0.07 0.32 0.06 0.27 0.01 0.02 East Dehydration Unit Still Vent D-2 -- -- -- -- 4.35 19.04 East Dehydration Unit Reboiler (0.75 MMBTUH) H-4 0.07 0.32 0.06 0.27 0.01 0.02 Direct-Fired Gas Heater (3.3 MMBTUH) H-5 0.32 1.42 0.27 1.19 0.02 0.08 Process Piping Fugitive VOC Leakage P-FUG -- -- -- -- 6.39 27.97 400-bbl Condensate Storage Tank T-1 -- -- -- -- 400-bbl Condensate Storage Tank T-2 -- -- -- -- 400-bbl Condensate Storage Tank T-3 -- -- -- -- -- 11.94 Emergency Flare P-11 0.01 0.05 0.06 0.25 0.02 0.09 Truck Loading L-1 -- -- -- -- -- 15.64 Cox City Plant No. 3 Emergency Flare F-1 0.01 0.02 0.02 0.08 0.01 0.03 1,232-hp Waukesha 7042GSI, COMP2 5.43 23.79 5.43 23.79 0.41 1.78 S/N 306628 1,232-hp Waukesha 7042GSI, S/N 179133 COMP3 5.43 23.79 5.43 23.79 0.41 1.78 1,100-hp White-Superior 8GTLE, S/N 20548 COMP4 4.85 21.24 4.85 21.24 3.03 13.28 Regeneration Heater, 2.15 MMBTUH H-1 0.21 0.92 0.18 0.78 0.01 0.05 Hot Oil Heater, 7.0 MMBTUH H-2 0.69 3.01 0.58 2.52 0.04 0.17 400-bbl Condensate Storage Tank T-4 -- -- -- -- -- 1.37 400-bbl Methanol Storage Tank T-23 -- -- -- -- -- 0.08 Process Piping Fugitive VOC P-FUG -- -- -- -- 1.03 4.53 Cox City Plants No. 1 and 2 2.7 MMBTUH Process Heater H-6 0.26 1.16 0.22 0.97 0.01 0.06 Process Piping Fugitive VOC P-FUG -- -- -- -- 1.88 8.23 Comanche Tie Compressor 4,500-hp Solar Centaur turbine COMP5 17.36 76.04 9.92 43.45 2.98 13.04 1,300-hp Solar Saturn turbine COMP6 5.02 21.97 2.87 12.55 0.86 3.77 300-bbl Condensate Tank T-5 -- -- -- -- -- 49.76 Truck Loading L-2 -- -- -- -- -- 0.09 Process Piping Fugitive VOC P-FUG -- -- -- -- 0.41 1.81 Totals 46.25 185.45 36.47 142.55 26.72 194.53 Pre-Project Emissions 23.87 87.44 23.68 86.55 16.33 99.04 NET EMISSIONS CHANGES 22.38 98.01 12.79 56.00 10.39 95.49
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 9 Fuel consumption for the 1,478-hp Waukesha Model L7042GSI compressor engine was stated at 11,560 SCFH. Air emissions from the engine are discharged through a 12-inch diameter stack, 20 ft. above grade, at a rate of 6,967 ACFM at 1,125 o F. Moisture content of stack gases has been estimated at 17% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. Fuel consumption for each 1,232-hp Waukesha Model L7042GSI compressor engines was stated at 9,340 SCFH. Air emissions from each engine are discharged through a 12-inch diameter stack, 20 ft. above grade, at a rate of 5,377 ACFM at 1,055 o F. Moisture content of stack gases has been estimated at 17% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. Fuel consumption for the 1,100-hp White-Superior Model 8GTLE compressor engine was stated at 8,415 SCFH. Air emissions from the engine are discharged through a 12-inch diameter stack, 20 ft. above grade, at a rate of 6,394 ACFM at 788 o F. Moisture content of stack gases has been estimated at 10% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. Brake-specific fuel consumption for the 4,500-hp Solar Centaur turbine is listed at 8,167 BTU/hp-hr at 15,700 RPM for a fuel consumption of 36,750 SCFH. Air emissions from the turbine are discharged through a stack 2 feet in diameter, 25 feet above grade, at a rate of 80,500 ACFM at 838 o F. Moisture content of stack gases has been estimated at 4% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. Brake-specific fuel consumption for the 1,300-hp Solar Saturn turbine is listed at 10,770 BTU/hp-hr at 22,300 RPM for a fuel consumption of 14,000 SCFH. Air emissions from the turbine are discharged through a stack 1.5 feet in diameter, 24 feet above grade, at a rate of 27,735 ACFM at 905 o F. Moisture content of stack gases has been estimated at 3% from fuel usage and the stoichiometric ratio of two SCF of water per SCF of natural gas fuel. The engines and turbines will have emissions of HAPs, the most significant being formaldehyde. Emissions of formaldehyde were calculated using the manufacturer emission factor of 0.015 g/hp-hr for the Waukesha engines and 0.00479 lb/mmbtu for the Solar turbines. Emissions of formaldehyde were calculated using AP-42 (7/00) Table 3.2-2 emission factor of 0.183 g/hp-hr for the White-Superior engine. Formaldehyde emissions are below major source levels. FORMALDEHYDE EMISSIONS Source Formaldehyde lb/hr TPY COMP1, 1,478-hp Waukesha L-7042 GSI 0.05 0.09 COMP2, 1,232-hp Waukesha L-7042 GSI 0.04 0.18 COMP3, 1,232-hp Waukesha L-7042 GSI 0.04 0.18 COMP4, 1,100-hp White-Superior 8GTLE 0.44 1.95 COMP5, 4,500-hp Solar Centaur 0.18 0.77 COMP6, 1,300-hp Solar Saturn 0.07 0.29 TOTALS 0.82 3.46
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 10 DEHYDRATION UNITS HAP EMISSIONS Pollutant C A S Number Maximum Emissions lb/hr TPY Benzene 71432 0.26 1.14 Toluene 108883 0.66 2.86 Ethyl Benzene 100414 0.02 0.12 Xylene 1330207 0.18 0.76 Hexane 110543 0.22 0.98 TOTALS 1.39 5.95 HAP emissions are less than the 10/25 TPY thresholds. SECTION V. INSIGNIFICANT ACTIVITIES The insignificant activities identified and justified in the application are duplicated below. Appropriate record keeping of activities indicated below with * is specified in the Specific Conditions. 1. Space heaters, boilers, process heaters, and emergency flares less than or equal to 5 MMBTUH heat input (commercial natural gas). Heaters 1, 3, 4, 5, and 6 are rated less than 5 MMBTUH. The flares, although rated below 5 MMBTUH, are subject to NSPS, therefore cannot be classified as insignificant activities. 2. Emissions from fuel storage/dispensing equipment operated solely for facility owned vehicles if fuel throughput is not more than 2,175 gallons per day, averaged over a 30-day period. 3. * 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. Glycol and lube oil storage tanks all have capacities less than 10,000 gallons and store liquids with a vapor pressure below 1.0 psia. 4. * Emissions from storage tanks constructed with a capacity less than 39,894 gallons which store VOC with a vapor pressure less than 1.5 psia at maximum storage temperature. 5. Cold degreasing operations utilizing solvents that are denser than air. One parts washer is located at the facility and it uses a solvent that is denser than air. 6. * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria pollutant. This category includes Heater H-2.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 11 SECTION VII. FEDERAL REGULATIONS PSD, 40 CFR Part 52 [Not Applicable] Final total emissions are less than the threshold of 250 TPY of any single regulated pollutant and the facility is not one of the 26 specific industries with a threshold of 100 TPY. NSPS, 40 CFR Part 60 [Subparts GG and KKK Applicable] Subpart Kb, VOL Storage Vessels. This subpart regulates hydrocarbon storage tanks larger than 19,813-gallons capacity and built after July 23, 1984. All storage tank capacities at this facility are less than the threshold level. Subpart GG, Stationary Gas Turbines. This subpart sets standards for stationary gas turbines, with a heat input at peak load of greater than or equal to 10.7 gigajoules per hour (10 MMBTUH) based on the lower heating value (LHV) of the fuel and that commenced construction, reconstruction, or modification after October 3, 1977. These units are subject to the nitrogen oxide emission limitations of 40 CFR 60.332(a)(2), the sulfur dioxide emission limitations of 40 CFR 60.333(a) or (b), and the fuel monitoring requirements of 40 CFR 60.334(b). Monitoring of fuel nitrogen content shall not be required as long as the permittee does not take an allowance for fuel bound nitrogen. Sulfur dioxide standards specify that no fuel shall be used which exceeds 0.8% by weight sulfur nor shall exhaust gases contain in excess of 150 ppm SO 2. The owner or operator may elect not to monitor the total sulfur content of the gaseous fuel combusted if the gaseous fuel is demonstrated to meet the definition of natural gas using either the gas quality characteristics in a current, valid purchase contract, tariff sheet, or transportation contract, or using representative fuel sampling data. The maximum total sulfur content of natural gas is 20 grains/100 SCF (680 ppmw or 338 ppmv) or less. 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. The standards of Subpart KKK have been incorporated into the permit. Subpart LLL, Onshore Natural Gas Processing: SO 2 Emissions. This subpart sets standards for natural gas sweetening units. There is no natural gas sweetening operation at this site. 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. All engines at this facility were manufactured prior to the applicability date of Subpart JJJJ. Subpart KKKK affects stationary gas turbines that commenced construction, modification, or reconstruction after February 18, 2005. These turbines were manufactured prior to Subpart KKKK. NESHAP, 40 CFR Part 61 [Not Applicable] There are no emissions of any of the regulated pollutants: arsenic, asbestos, benzene, beryllium, coke oven emissions, mercury, radionuclides, or vinyl chloride except for trace amounts of benzene. Subpart J, Equipment Leaks of Benzene, concerns only process streams that contain more than 10% benzene by weight. Analysis of Oklahoma natural gas indicates a maximum benzene content of less than 1%.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 12 NESHAP, 40 CFR Part 63 [Subpart HH Applicable] Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission points that are located at facilities that are major sources and area sources of HAPs and either process, upgrade, or store hydrocarbons prior to the point of custody transfer or prior to which the natural gas enters the natural gas transmission and storage source category. The facility is a minor source of HAPs. Sources with either an annual average natural gas flowrate less than 3 MMSCF/D or benzene emissions less than 0.9 megagrams (1.0 TPY) are exempt from control requirements. Each dehydrator at the facility has the potential to emit 0.57 TPY of benzene. Since the TEG units were constructed/reconstructed before July 8, 2005, and are not located within an Urban-1 County or in an Urban Area plus offset or Urban Cluster, they are considered existing sources. As existing sources, they are not subject to the requirements of this subpart until January 5, 2009. A requirement to comply with the standard by the applicable effective date has been incorporated into the permit. Subpart HHH, Natural Gas Transmission and Storage. This subpart was published in the Federal Register on June 17, 1999, and affects Natural Gas Transmission and Storage Facilities. It applies to affected emission points that are located at facilities that are major sources of HAPs, as defined in this subpart, and that transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end user. This facility is a minor source of HAPs. Subpart YYYY, Stationary Combustion Turbines. This subpart was promulgated on March 5, 2004 and affects stationary combustion turbines that are located at major source of HAP. The turbines were both built in 2002, therefore, are existing gas-fueled turbines. There are no standards in Subpart YYYY for existing units. Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart previously affected only RICE with a site-rating greater than 500 brake horsepower that are located at a major source of HAP emissions. On January 18, 2008, the EPA published a final rule that promulgates standards for new and reconstructed engines (after June 12, 2006) with a site rating less than or equal to 500 HP located at major sources, and for new and reconstructed engines (after June 12, 2006) located at area sources. Owners and operators of new or reconstructed engines at area sources and of new or reconstructed engines with a site rating equal to or less than 500 HP located at a major source (except new or reconstructed 4-stroke lean-burn engines with a site rating greater than or equal to 250 HP and less than or equal to 500 HP located at a major source) must meet the requirements of Subpart ZZZZ by complying with either 40 CFR Part 60 Subpart IIII (for CI engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines). Owners and operators of new or reconstructed 4SLB engines with a site rating greater than or equal to 250 HP and less than or equal to 500 HP located at a major source are subject to the same MACT standards previously established for 4SLB engines above 500 HP at a major source, and must also meet the requirements of 40 CFR Part 60 Subpart JJJJ, except for the emissions standards for CO. The engines at this facility were all constructed prior to the applicability dates of this subpart and are not affected emission units.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 13 Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial and Institutional 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, 2007. No appeals were made and the rule was vacated on July 30, 2007. Existing and new small gaseous fuel boilers and process heaters (less than 10 MMBtu/hr 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. At this time, 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. CAM, 40 CFR Part 64 [Applicable] Compliance Assurance Monitoring (CAM) as published in the Federal Register on October 20, 1997, applies to any pollutant specific emission unit at a major source, that is required to obtain a Title V 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 The facility will have until renewal of their Title V operating permit to submit CAM plans for the engines with catalytic converters and the dehydration units condensers. Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable] The definition of a stationary source does not apply to transportation, including storage incident to transportation, of any regulated substance or any other extremely hazardous substance under the provisions of this part. Naturally occurring hydrocarbon mixtures, prior to entry into a natural gas processing plant or a petroleum refining process unit, including: condensate, crude oil, field gas, and produced water, are exempt for the purpose of determining whether more than a threshold quantity of a regulated substance is present at the stationary source. More information on this federal program is available on the web page: www.epa.gov/ceppo. Stratospheric Ozone Protection, 40 CFR Part 82 [Subpart A and F 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).
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 14 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, 2030. This facility does not utilize any Class I & II substances. SECTION VIII. 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. Emissions inventories have been submitted and fees paid for previous 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 that result in emissions not authorized in the permit and that exceed the Insignificant Activities or Trivial Activities thresholds require prior notification to AQD and may require a permit modification. Insignificant activities refer to those individual emission units either listed in Appendix I 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 a 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 requirement.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 15 OAC 252:100-9 (Excess Emission Reporting Requirements) [Applicable] In the event of any release which results in excess emissions, the owner or operator of such facility shall notify the Air Quality Division as soon as the owner or operator of the facility has knowledge of such emissions, but no later than 4:30 p.m. the next working day. Within ten (10) working days after the immediate notice is given, the owner or operator shall submit a written report describing the extent of the excess emissions and response actions taken by the facility. In addition, if the owner or operator wishes to be considered for the exemption established in 252:100-9-3.3, a Demonstration of Cause must be submitted within 30 calendar days after the occurrence has ended. OAC 252:100-13 (Prohibition of 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 252:100-19 (Particulate Matter) [Applicable] Section 19-4 regulates emissions of 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 252:100-19 as any internal combustion engine or gas turbine, or other combustion device used to convert the combustion of fuel into usable energy. Thus, the listed equipment items following are subject to the requirements of this subchapter. This permit requires the use of natural gas for all fuel-burning equipment to ensure compliance with Subchapter 19. Equipment Maximum Heat Input (MMBTUH) Appendix C Emission Limit (lbs/mmbtu) Potential Emission Rate (lbs/mmbtu) 1,478-HP Waukesha 11.56 0.59 0.01 1,232-HP Waukesha 9.34 0.60 0.01 1,232-HP Waukesha 9.34 0.60 0.01 1,100-HP White-Superior 8.42 0.60 0.01 4,500-hp Solar Centaur 36.75 0.44 0.0066 1,300-hp Solar Saturn 14.00 0.56 0.0066 Regeneration Heater 2.15 0.60 0.0076 Hot Oil Heater 7.0 0.60 0.0076 West Dehydration Reboiler 0.75 0.60 0.0076 East Dehydration Reboiler 0.75 0.60 0.0076 Gas Heater 3.3 0.60 0.0076 Regeneration Heater 2.7 0.60 0.0076 OAC 252:100-25 (Visible Emissions and Particulates) [Applicable] This subchapter states that no person shall allow the discharge of any fumes, aerosol, mist, gas, smoke, vapor, particulate matter, or any combination thereof exhibiting greater than 20% opacity except for short term occurrences, which consist of not more than one six-minute (6) period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24-hour period. In no case shall the average of any six-minute (6) period exceed 60% opacity. When burning natural gas, there is very little possibility of exceeding the opacity standards.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 16 OAC 252:100-29 (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 interfere with the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the maintenance of air quality standards. Under normal operating conditions, this facility will not cause a problem in this area, there it is not necessary to require specific precautions to be taken. OAC 252:100-31 (Sulfur Compounds) [Applicable] Part 5 limits sulfur dioxide emissions from new fuel-burning equipment (constructed after July 1, 1972). For gaseous fuels the limit is 0.2 lb/mmbtu heat input averaged over 3 hours. For fuel gas having a gross calorific value of 1,000 BTU/SCF, this limit corresponds to fuel sulfur content of 1,203 ppmv. The permit requires the use of gaseous fuel with sulfur content less than 343 ppmv to ensure compliance with Subchapter 31. OAC 252:100-33 (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 NOx per MMBTU. There are no equipment items that exceed the 50 MMBTUH threshold. OAC 252:100-35 (Carbon Monoxide) [Not Applicable] This facility has none of the affected sources: gray iron foundry, blast furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic reforming unit. OAC 252:100-37 (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 tanks, propane tanks, and methanol tanks larger than 400-gallons are subject to this requirement. The lube oil and antifreeze tanks have vapor pressures below the 1.5 psia de minimis level. 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 5 limits the VOC content of coating of parts and products. Any painting operation will involve maintenance coatings of building and equipment and emit less than 100 pounds per day of VOCs and so is exempt. Part 7 requires fuel-burning and refuse-burning equipment to be operated to minimize emissions of VOC. The equipment at this location is subject to this requirement. Part 7 also requires effluent water separators which receive water containing more than 200 gallons per day of any VOC to be equipped with vapor control devices. There is no water effluent separator at this location. Part 7 also requires all rotating pumps or compressors handling VOCs to be equipped with mechanical seals or other equipment of equal efficiency. All reciprocating pumps or compressors handling VOCs are to be equipped with packing glands that are properly installed and in good working order such that emissions from the drain recovery system are limited to two cubic inches of VOC in any 15 minute period at standard conditions per pump or compressor. The equipment at this location is subject to this requirement.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 17 OAC 252:100-42 (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 there are no specific requirements for this facility at this time. OAC 252:100-43 (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 to demonstrate compliance with any federal or state emission limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, and submitted as required by this subchapter, an applicable rule, or permit requirement. Data from any required testing or monitoring not conducted in accordance with the provisions of this subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive use, of any credible evidence or information relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. The following Oklahoma Air Pollution Control Rules are not applicable to this facility: OAC 252:100-11 Alternative Reduction not requested OAC 252:100-15 Mobile Sources not in source category OAC 252:100-17 Incinerators not type of emission unit OAC 252:100-23 Cotton Gins not type of emission unit OAC 252:100-24 Feed & Grain Facility not in source category OAC 252:100-39 Nonattainment Areas not in a subject area OAC 252:100-47 Landfills not type of source category SECTION IX. COMPLIANCE Tier Classification and Public Review This application has been determined to be a Tier II based on the request for a construction permit which changes a minor source to a major source. Public review of the application and permit are required. The applicant has submitted a signed affidavit from the The Chickasha Express-Star, a daily newspaper printed in Grady County, that a Notice of Filing a Tier II Application was published on August 26, 2008. The notice stated that the application was available for public review at Chickasha Public Library (527 Iowa Avenue) or at the Air Quality Division s main office. The applicant will also publish a Notice of Tier II Draft Permit.
PERMIT MEMORANDUM 2004-235-C (M-3) DRAFT 18 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 real property. Information on all permit actions is available for review by the public in the Air Quality section of the DEQ Web Page: http://www.deq.state.ok.us. Fees Paid Major source construction permit fee of $2,000 SECTION X. SUMMARY The applicant has demonstrated the ability to achieve compliance with the requirements of the several air pollution control rules and regulations. Ambient air quality standards are not threatened at the site. There are no active Air Quality compliance or enforcement issues concerning this facility. Issuance of the construction permit is recommended, contingent on public and EPA review.
PERMIT TO CONSTRUCT AIR POLLUTION CONTROL FACILITY SPECIFIC CONDITIONS DRAFT Enogex Products LLC Cox City Processing Plant Permit No. 2004-235-C (M-3) The permittee is authorized to construct in conformity with the specifications submitted to the Air Quality Division on October 3, 2005, with supplemental information received August 22, October 10, and November 7, 2008. The Evaluation Memorandum dated December 9, 2008, explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Commencing construction or operations under this permit constitutes acceptance of, and consent to, the conditions contained herein: 1. Points of emissions and emission limitations: [OAC 252:100-8-6(a)(1)] EUG 1. Engines NO x CO VOC Source Unit ID lb/hr TPY lb/hr TPY lb/hr TPY 1,478-hp Waukesha 7042GSI COMP1 6.52 11.40 6.52 11.40 0.49 0.86 1,232-hp Waukesha 7042GSI COMP2 5.43 23.79 5.43 23.79 0.41 1.78 1,232-hp Waukesha 7042GSI COMP3 5.43 23.79 5.43 23.79 0.41 1.78 1,100-hp White-Superior 8GTLE COMP4 4.85 21.24 4.85 21.24 3.03 13.28 A. The 1,478-HP Waukesha 7042 GSI (COMP1) shall be operated no more than 3,500 hours in any rolling 12-month period. B. The make, model number and serial number shall be permanently identified on the engines at the facility. C. Engines COMP1, COMP2, and COMP3 shall be operated with exhaust gases passing through functional catalytic converters. D. At least once per calendar quarter, the permittee shall conduct tests of NO x and CO emissions in exhaust gases from the engines in EUG-1 and from each replacement engine/turbine when operating under representative conditions for that period. Testing is required for any engine/turbine that runs for more than 220 hours during that calendar quarter. Engines/turbines shall be tested no sooner than 20 calendar days after the last test. Testing shall be conducted using a portable analyzer in accordance with a protocol meeting the requirements of the AQD Portable Analyzer Guidance document or an equivalent method approved by Air Quality. When four consecutive quarterly tests show the engine/turbine to be in compliance with the emissions limitations shown in the permit, then the testing frequency may be reduced to semi-annual testing. Likewise, when the following two consecutive semi-annual tests show compliance, the testing frequency may be reduced to annual testing. Upon any showing of non-compliance with emissions limitations or testing that indicates that emissions are within 10% of the
SPECIFIC CONDITIONS 2004-235-C (M-3) 2 DRAFT emission limitations, the testing frequency shall revert to quarterly. Any reduction in the testing frequency shall be noted in the next required compliance certification. Reduced testing frequency does not apply to engines with catalytic converters. E. When periodic compliance testing shows engine exhaust emissions in excess of the lb/hr limits in Specific Condition Number 1, the permittee shall comply with the provisions of OAC 252:100-9 for excess emissions during start-up, shut-down, and malfunction of air pollution control equipment. Requirements of OAC 252:100-9 include immediate notification and written notification of Air Quality and demonstrations that the excess emissions meet the criteria specified in OAC 252:100-9. F. Replacement, including temporary periods (6 months or less for maintenance purposes) of the internal combustion engine shown in this permit with an engine of lesser or equal emissions of each pollutant, is authorized under the following conditions: 1. The permittee shall notify AQD in writing not later than 7 days prior to start-up of the replacement engine(s)/turbine(s). Said notice shall identify the old engine/turbine and shall include the new engine/turbine make and model, serial number, horsepower rating, and pollutant emission rates (g/hp-hr, lb/hr, and TPY) at maximum horsepower for the altitude/location. 2. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be conducted to confirm continued compliance with NO X and CO emission limitations. A copy of the first quarter testing shall be provided to AQD within 60 days of start-up of each replacement engine/turbine. The test report shall include the engine/turbine fuel usage, stack flow (ACFM), stack temperature ( o F), and pollutant emission rates (g/hp-hr, lbs/hr, and TPY) at maximum rated horsepower for the altitude/location. 3. Replacement equipment and emissions are limited to equipment and emissions which are not a modification under NSPS or NESHAP, or a significant modification under PSD. For existing PSD facilities, the permittee shall calculate the PTE or the net emissions increase resulting from the replacement to document that it does not exceed significance levels and submit the results with the notice required by F.1 of this Specific Condition. 4. Engines installed as allowed under the replacement allowances in this Specific Condition that are subject to 40 CFR Part 63, Subpart ZZZZ and/or 40 CFR Part 60, Subpart JJJJ shall comply with all applicable requirements.
SPECIFIC CONDITIONS 2004-235-C (M-3) 3 DRAFT EUG 2. Turbines NO x CO VOC Source Unit ID lb/hr TPY lb/hr TPY lb/hr TPY 4,500-hp Solar Centaur turbine COMP5 17.36 76.04 9.92 43.45 2.98 13.04 1,300-hp Solar Saturn turbine COMP6 5.02 21.97 2.87 12.55 0.86 3.77 A. The make, model number and serial number shall be permanently identified on the turbines at the facility. B. At least once per calendar quarter, the permittee shall conduct tests of NO x and CO emissions in exhaust gases from the turbines in EUG-2 and from each replacement engine/turbine when operating under representative conditions for that period. Testing is required for any engine/turbine that runs for more than 220 hours during that calendar quarter. Engines/turbines shall be tested no sooner than 20 calendar days after the last test. Testing shall be conducted using a portable analyzer in accordance with a protocol meeting the requirements of the AQD Portable Analyzer Guidance document or an equivalent method approved by Air Quality. When four consecutive quarterly tests show the engine/turbine to be in compliance with the emissions limitations shown in the permit, then the testing frequency may be reduced to semiannual testing. Likewise, when the following two consecutive semi-annual tests show compliance, the testing frequency may be reduced to annual testing. Upon any showing of non-compliance with emissions limitations or testing that indicates that emissions are within 10% of the emission limitations, the testing frequency shall revert to quarterly. Any reduction in the testing frequency shall be noted in the next required compliance certification. C. When periodic compliance testing shows turbine exhaust emissions in excess of the lb/hr limits in Specific Condition Number 1, the permittee shall comply with the provisions of OAC 252:100-9 for excess emissions during start-up, shut-down, and malfunction of air pollution control equipment. Requirements of OAC 252:100-9 include immediate notification and written notification of Air Quality and demonstrations that the excess emissions meet the criteria specified in OAC 252:100-9. D. Replacement, including temporary periods (6 months or less for maintenance purposes) of the turbines shown in this permit with an engine of lesser or equal emissions of each pollutant, is authorized under the following conditions: 1. The permittee shall notify AQD in writing not later than 7 days prior to start-up of the replacement engine(s)/turbine(s). Said notice shall identify the old engine/turbine and shall include the new engine/turbine make and model, serial number, horsepower rating, and pollutant emission rates (g/hp-hr, lb/hr, and TPY) at maximum horsepower for the altitude/location.