PERMIT MEMORANDUM NO. 2003-276-TVR (PSD)(M-1) 28
OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY
AIR QUALITY DIVISION
MEMORANDUM December 26, 2006
TO: Dawson Lasseter, P.E., Chief Engineer, Air Quality Division
THROUGH: Kendall Stegmann, Supervising Attorney, Air Quality Division
THROUGH: Rick Groshong, Environmental Program Manager, Enforcement Section
THROUGH: Grover Campbell, P.E., Existing Source Permits Section
THROUGH: Phil Martin, P.E., New Source Permits Section
THROUGH: Peer Review
FROM: David Schutz, P.E., New Source Permits Section
SUBJECT: Evaluation of Permit Application No. 2003-276-TVR (PSD)(M-1)
Oklahoma Municipal Power Authority
Ponca City Municipal Steam Plant
Section 21, T26N, R2E, Kay County, Oklahoma
Directions: US-60 into Ponca City, North on Waverly, East on Grand,
North on Union
Latitude: 36.723oN, Longitude 97.086oW
SECTION I. INTRODUCTION
The Oklahoma Municipal Power Authority (OMPA) has requested a modification to their current Part 70 operating permit. The facility is currently operating under Permit No. 2003-276-TVR (PSD) issued June 29, 2004. The facility is an electricity generation plant (SIC Code 4911) located in an attainment area.
The facility is requesting a limit on the hours of operation of Unit 2 of 4,000 hours per year. This limit will allow the facility to stay below applicability thresholds of the new “Best Available Retrofit Technology” (“BART”) rules. By taking a limit to avoid an otherwise-applicable requirement, this permit modification meets the definition of a “significant” modification. Tier II processing is required. Only the one boiler is affected by this change.
SECTION II. FACILITY DESCRIPTION
The Ponca City Municipal Steam Plant consists of 4 primary electric generating units and 7 standby diesel-generator units (28 MW total of standby generating units).
- Unit 1 steam turbine receives steam from Unit 3’s heat-recovery steam generator forming Unit 3 combined cycle operations. The original Unit 1 boiler was deactivated in 1994. (The name “Unit 1” was retained from when the unit had an associated boiler; the original Unit 1 boiler was deactivated in 1994.) When operated in the combined-cycle mode with Unit 3, this unit can produce up to 20 MW.
- Unit 2 is a 493 MMBTUH gas-fired boiler which generates steam for the existing steam turbine No. 2 to produce a maximum output of 41.5 MW.
- Unit 3 is a General Electric (GE) LM6000 SprintTM natural gas or fuel oil fired turbine (aeroderivative type) connected to a heat recovery steam generator (HRSG) combined cycle combustion turbine firing natural gas or fuel oil with associated natural gas fired duct burners and various storage tanks. Unit 3 is coupled to an electric generator producing a maximum output of 45 MW utilizing water injection for air emissions control and it can exhaust either to a bypass stack or the duct-fired heat recovery steam generator (HRSG) for combined-cycle operation (approximately 65 MW with duct burner).
- Unit 4 is a General Electric (GE) LM6000 SprintTM simple cycle natural gas fired turbine (aeroderivative type). The turbine is rated at approximately 45 megawatts (MW) and utilizes water injection for air emissions control. Unit 4 is anticipated to be operated no more than 1,750 hours per year.
- The 7 dual-fuel (natural gas or diesel) generators will operate less than 500 hours each and are included as insignificant sources.
Both Unit 2 and Unit 3 use monitoring systems to determine emissions of NOx, SO2, and CO2 for compliance with the 40 CFR 75 Acid Rain requirements. Additionally, Unit 3 monitors O2 for determining NOx emissions. Unit 3 determines NOx emissions based on an analyzer and the heat input rate, while Unit 2 uses four formulas based upon correlation tests and the heat input of the unit. Based on fuel flow, gross caloric value of natural gas, and calculated heat input SO2 emissions are calculated for both units. Emissions from Unit 4 are not directly monitored (as a peaking unit, it is exempt from CEM requirements under 40 CFR Part 75), but water injection rates are monitored to ensure compliance with NSPS Subpart GG.
Since the facility emits more than 100 TPY of a regulated pollutant, it is subject to Title V permitting requirements. Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) in the following outline. There are two significant operating scenarios, dependent on the mode of operation (gas or fuel oil).
SECTION III. EQUIPMENT
EUG 1 Combustion Turbine (Unit 3)
EU / Point / Make/Model / Fuel / Heat Input MMBTUH / Power Output MW / Construction Date1 / 1 / General Electric LM 6000 / natural gas or No. 2 diesel / 454 / 45 / 1994
EUG 2 Duct Burners (Part of Unit 3)
EU / Point / Make/Model / Fuel / Heat Input MMBTUH / Construction Date2 / 1 / Callidus Technologies / natural gas / 94.4 / 1994
EUG 3 Boiler (Unit 2)
EU / Point / Make/Model / Fuel / Heat Input MMBTUH / Power Output MW / Construction Date3 / 3 / Foster-Wheeler / natural gas / 493 / 42 / 1975
EUG 4 Storage Tanks
EU / Point / Contents / CapacityGallons / Construction Date
T1 / T1 / Diesel / 17,768 / 1965
T2 / T2 / Diesel / 11,746 / 1965
T3 / T3 / Diesel / 11,858 / 1965
T4 / T4 / Engine Lube Oil / 7,955 / 1965
T5 / T5 / No. 2 Fuel Oil / 21,000 / 1965
T6 / T6 / Inactive / 2,100,000 / 1965
EUG 5 Generator Engines
EU / Point / Description / Fuel / Heat Input MMBTUH / Fuel Usage GPH / Construction Date5-1 / 5-1 / 7,000 KW generator / natural gas or No. 2 diesel / 153 (total all 7 units) / 1,077 (total all 7 units) / 1965
5-2 / 5-2 / 2,775 KW generator / 1965
5-6 / 5-6 / 1,690 KW generator / 1965
5-7 / 5-7 / 3,320 KW generator / 1965
5-8 / 5-8 / 4,000 KW generator / 1965
5-9 / 5-9 / 7,000 KW generator / 1965
5-10 / 5-10 / 2,500 KW generator / 1965
EUG 6 Combustion Turbine (Unit 4)
4 / 4 / General Electric LM 6000 / natural gas / 454 / 45 / 2003
SECTION IV. EMISSIONS
Emissions were calculated using the following methods and factors:
- EUG 1 and EUG 2: emissions for the Unit 3 combustion turbine and associated duct burner are taken from Permit No. 92-016-O (M-2) and are based on manufacturers data, continuous operations, and stack test data for H2SO4. Short-term emissions rates of the turbine correspond to times when the duct burner is not operating. Short-term emissions of CO and VOC on a lb/MMBTU basis are significantly higher at 50% load than at 100% load, hence hourly emissions do not extrapolate evenly to annual rates. However, the conditions which produce the maximum hourly CO and VOC emissions are an air inlet temperature of -8oF. The average annual inlet temperature is approximately 48oF. The maximum hourly emissions resulting from 50% load and 48oF were extrapolated to 8,760 hours to determine annual emissions rates. Sulfur dioxide emissions are based on sweet natural gas containing 4 ppm or less sulfur or distillate fuel oil No. 2 containing 0.1% by weight or less sulfur.
- EUG 3: emission limitations for the Foster Wheeler boiler (Unit 2), are based on the NSPS limit of 0.1 lb/MMBTU for PM, OAC 252:100-31 limit of 0.2 lb/MMBTU for SO2, NSPS limit of 0.2 lb/MMBTU for NOx, and AP-42 (7/98) Chapter 1.4 Tables 1.4-1and 1.4-2 for VOC and CO. Annual operating hours will be limited to 4,000 hours.
- EUG 4: VOC emissions from storage tanks were based on the EPA program TANKS4.09.
- EUG 5: standby generator emissions were taken from AP-42 (7/00), Section 3.2, for gas fuel and AP-42 (10/96), Section 3.3, for diesel fuel.
- EUG 6: emissions from the new GE LM-6000 turbine were taken from manufacturer data as listed in Permit No. 96-366-C (M-1).
Emissions of hazardous air pollutants were taken from AP-42 (7/98), Section 1.4 for turbines and boilers and Section 3.4 for the stationary engines. Gas fuel factors were used for all units as being the most representative of maximum emissions. Since Section 3.4 did not list emission factors for inorganic pollutants, emissions for the engines were estimated based on data in Section 1.4.
Facility Emissions
Scenario 1: Natural Gas Fuel
EUG / Pollutant / Emission Factor / lb/hr /TPY
1 / PM10 / 1.30E-02 lb/MMBTU / 5.30 / 23.23SO2
/ 1.50E-03 lb/MMBTU / 0.61 / 2.68NOx / 0.11 lb/MMBTU / 44.88 / 196.57
VOC / 1.15E+01 lb/hr / 11.50 / 28.60
CO / 152.30 lb/hr / 152.30 / 193.16
2 / PM10 / 0.011 lb/MMBTU / 1.04 / 4.55
SO2
/ 0.0015 lb/MMBTU / 0.14 / 0.62NOx / 0.11 lb/MMBTU / 10.38 / 45.48
VOC / 5.40 lb/hr / 5.40 / 23.65
CO / 8.60 lb/hr / 8.60 / 37.67
3 / PM10 / 0.1 lb/MMBTU / 49.30 / 98.60
SO2
/ 0.2 lb/MMBTU / 98.60 / 197.20NOx
/ 0.2 lb/MMBTU / 98.60 / 197.20VOC / 5.50 lb/MMcf / 2.71 / 5.42
CO / 84.00 lb/MMcf / 41.41 / 82.82
5 / PM10 / 0.0095 lb/MMBTU / 1.45 / 0.36
SOx
/ 0.0056 lb/MMBTU / 0.86 / 0.21NOx
/ 2.21 lb/MMBTU / 338.13 / 84.53VOC / 0.0296 lb/MMBTU / 4.53 / 1.13
CO / 3.72 lb/MMBTU / 569.16 / 142.29
6 / PM10 / 0.0117 lb/MMBTU / 5.31 / 4.65
SO2
/ 0.0056 lb/MMBTU / 2.54 / 2.22NOx
/ 0.11 lb/MMBTU / 44.95 / 39.33VOC / 0.014 lb/hr / 6.36 / 5.56
CO / 0.098 lb/hr / 44.49 / 38.93
T1-T6 / VOC / TANKS4.09 / -- / 0.06
TOTAL EMISSIONS
PM10 / 62.41 / 131.39SO2
/ 102.75 / 202.94NOx / 536.94 / 563.11
VOC / 30.50 / 64.43
CO / 815.96 / 494.87
H2SO4 / 32.30 / 141.47
NET CHANGES
PM10 / 0 / -117.33
SO2
/ 0 / -234.67NOx / 0 / -234.67
VOC / 0 / -6.45
CO / 0 / -98.56
Facility Emissions
Scenario 2: Diesel Fuel For Unit 3 Turbine and Standby Generators
EUG / Pollutant / Emission Factor / lb/hr /TPY
1A / PM10 / 0.033 lb/MMBTU / 13.46 / 58.97SO2
/ 0.110 lb/MMBTU / 44.88 / 196.57NOx / 0.26 lb/MMBTU / 106.08 / 464.63
VOC / 30.60 lb/hr / 30.60 / 14.89
CO / 748.60 lb/hr / 748.60 / 904.21
2 / PM10 / 0.011 lb/MMBTU / 1.04 / 4.55
SO2
/ 0.0015 lb/MMBTU / 0.14 / 0.62NOx / 0.11 lb/MMBTU / 10.38 / 45.48
VOC / 9.20 lb/hr / 5.40 / 23.65
CO / 15.60 lb/hr / 8.60 / 37.67
3 / PM10 / 0.1 lb/MMBTU / 49.30 / 98.60
SO2
/ 0.2 lb/MMBTU / 98.60 / 197.20NOx
/ 0.2 lb/MMBTU / 98.60 / 197.20VOC / 5.50 lb/MMcf / 2.71 / 5.42
CO / 84.00 lb/MMcf / 41.41 / 82.82
5A / PM10 / 0.10 lb/MMBTU / 15.30 / 3.83
SO2
/ 0.8 lb/MMBTU / 122.40 / 30.60NOx
/ 3.2 lb/MMBTU / 489.60 / 122.40VOC / 0.09 lb/MMBTU / 13.77 / 3.44
CO / 0.85 lb/MMBTU / 130.05 / 32.51
6 / PM10 / 0.0117 lb/MMBTU / 5.31 / 4.65
SO2
/ 0.0056 lb/MMBTU / 2.54 / 2.22NOx
/ 0.099 lb/MMBTU / 44.95 / 39.33VOC / 0.014 lb/MMBTU / 6.36 / 5.56
CO / 0.098 lb/MMBTU / 44.49 / 38.93
T1-T6 / VOC / TANKS4.09 / -- / 0.06
TOTAL POTENTIAL EMISSIONS
PM10 / 84.41 / 287.93SO2
/ 268.56 / 661.89NOx / 749.61 / 1103.71
VOC / 58.84 / 59.42
CO / 973.15 / 1194.71
NET CHANGES
PM10 / 0 / -117.33
SO2
/ 0 / -234.67NOx / 0 / -234.67
VOC / 0 / -6.45
CO / 0 / -98.56
HAP Emissions
lb/hr / TPY
2-Methyl naphthalene / 1321944 / 0.003 / 0.001
3-Methyl chloranthrene / 56495 / 0.001 / 0.001
Acenaphthene / 83329 / 0.001 / 0.001
Acenaphthylene / 208968 / 0.001 / 0.001
Acrolein / 107028 / 1.190 / 0.298
Anthracene / 1201217 / 0.001 / 0.001
Benzo-a-anthracene / 56553 / 0.001 / 0.001
Benzene / 71432 / 0.300 / 0.084
Benzo-a-pyrene / 50328 / 0.001 / 0.001
Benzo-a-fluoranthene / 205992 / 0.001 / 0.001
Benzo-(g,h,I) perylene / 191242 / 0.001 / 0.001
Benzo-k-fluoranthene / 207089 / 0.001 / 0.001
Chrysene / 218019 / 0.001 / 0.001
Dibenzo-a,h-anthracene / 53703 / 0.001 / 0.001
Dichlorobenzene / 95501 / 0.002 / 0.006
Fluoranthene / 206440 / 0.001 / 0.001
Fluorine / 86737 / 0.001 / 0.001
Formaldehyde / 50000 / 8.554 / 2.468
Hexane / 110543 / 2.677 / 8.580
Indeno-1,2,3,c,d-pyrene / 193395 / 0.001 / 0.001
Naphthalene / 91203 / 0.016 / 0.007
Phenanthrene / 85018 / 0.001 / 0.001
Pyrene / 129000 / 0.001 / 0.001
Toluene / 108883 / 0.152 / 0.053
Arsenic / 7440382 / 0.001 / 0.001
Beryllium / 7440417 / 0.001 / 0.001
Cadmium / 7440439 / 0.002 / 0.005
Chromium / 7440473 / 0.002 / 0.007
Cobalt / 7440484 / 0.001 / 0.001
Manganese / 7439965 / 0.001 / 0.002
Mercury / 7439976 / 0.001 / 0.001
Nickel / 7440020 / 0.003 / 0.010
Selenium / 7782492 / 0.001 / 0.001
* HAP. Total HAP emissions = 11.225 TPY.
Stack Parameters
Fuel
Type / Height(feet) / Diameter
(feet) / Temperature
(degrees F) / Flowrate
(ACFM)
1 / gas / 100 / 10 / 835 / 582,600
oil / 100 / 10 / 838 / 578,200
2 / gas / 70 / 9.25 / 269 / 329,100
oil / 70 / 9.25 / 272 / 327,400
3 / gas / 120* / 8 / 295 / 155,426
4 / gas / 100 / 9 / 835 / 582,600
5 / gas / 120 / 10.3 / 300 / 50,000
*By-pass stack is 100 ft tall and 9.25 ft in diameter
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.