oklahoma department of environmental qualitythe caterpillar g3516 ulb engines are based on the...

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

MEMORANDUM February 26, 2018

TO: Phillip Fielder, P.E., Permits and Engineering Group Manager,

Air Quality Division

THROUGH: Richard Groshong, Environmental Programs Manager, Compliance

and Enforcement Section

THROUGH: Phil Martin, P.E., Engineering Manager, New Source Permits Section

THROUGH: Amalia Talty, P.E., Existing Source Permit Section

FROM: Lisa Cox, P.E., Existing Source Permit Section

SUBJECT: Evaluation of Permit Application No. 2015-0197-C (M-1)

Woodford Express, LLC

Grady Gas Plant (Facility ID: 12235)

Section 11, Township 3N, Range 5W; Grady County, Oklahoma

Latitude: 34.752° N, Longitude: 97.702° W

Directions: From Lindsay, go 3.7 miles south on OK-76 S, go 4 miles west on

E1540 Rd., go 1 mile south on N2990 Rd., go 1 mile west on E1550 Rd., go 1

mile south on N2980 Rd., go 1 mile west on E1560 Rd., and the facility will

be on the left.

SECTION I. INTRODUCTION

Woodford Express, LLC (Woodford) has requested a construction permit for their Grady Gas

Plant (SIC 1321/NAICS 21112) which is located in Grady County. The facility has been issued a

major source construction permit (Permit No. 2015-0197-C, issued January 26, 2016) and two

Authorizations to Construct under the General Permit for Oil and Gas Facilities (Authorization

Nos. 2013-2243-NOI, issued December 16, 2013, and 2014-1849-NOI, issued September 15,

2014). Woodford requests a major source construction permit to expand the facility further. The

facility is a major source of NOx and CO criteria pollutants. After construction, the facility will

also be a major source of VOC emissions. Total facility emissions will be below the 250 TPY

threshold that would require Prevention of Significant Deterioration (PSD) review. This permit

is Tier II and requires public and EPA review.

Legion Energy Services, Inc. was authorized to construct the facility under the General Permit

for Oil and Gas Facilities (GP-OGF) on December 16, 2013 (Authorization No. 2013-2243-

NOI). The facility was sold to Xplorer Midstream on March 12, 2014. Woodford Express, LLC

is a subsidiary of Xplorer Midstream. Woodford applied for a second authorization to construct

under the GP-OGF on September 15, 2014 (Authorization No. 2014-1849-NOI). Woodford

decided to expand the facility to a major source in the summer of 2014. This was subsequent to

the purchase of the existing facility, but prior to Woodford requesting Authorization No. 2014-

DRAFT/PROPOSED

PERMIT MEMORANDUM 2015-0197-C (M-1) DRAFT/PROPOSED 2

1849-NOI. The second authorization to construct was submitted in error. Therefore the facility

was limited to construction activities authorized by 2013-2243-NOI. Woodford submitted an

application for a major source construction permit on February 3, 2015, to include amine

treatment at the facility. It was determined Woodford would submit the major source

construction permit including modeling and state Best Available Control Technology (BACT)

review. Permit 2015-0197-C was issued on January 26, 2016. Woodford has requested to

modify the construction permit to include additional emissions units. This permit will review the

emissions sources, review PSD applicability, and provide a BACT review that includes VOC

emissions sources.

Upon completion, the facility will consist of eleven (11) 1,380-hp Caterpillar G3516 ULB

natural gas-fired engine driven compressors with oxidation catalysts (OC), one (1) 1,341-hp

Caterpillar C32 ATAAC diesel-fired engine driven emergency generator, one (1) 27.2-hp

Generac 2.3L diesel-fired engine driven emergency generator, two (2) 315-hp Caterpillar C7.1

DITA diesel-fired engine driven emergency generators, uncontrolled compressor blowdown

emissions, three (3) 240-MMSCFD amine units, two (2) 20.6-MMBTUH thermal oxidizers, one

(1) 16.7-MMBTUH thermal oxidizer, one (1) 8.0-MMBTUH stabilizer reboiler, one (1) 9.5-

MMBTUH dehydrator regeneration heater, one (1) 30-MMBTUH hot oil heater, two (2) 53.1-

MMBTUH hot oil heaters, two (2) 20.2-MMBTUH dehydrator regenerator heaters, one (1) 40-

MMBTUH amine regenerator heater, eight (8) 1,000-bbl condensate storage tanks, two (2) 210-

bbl produced water storage tanks, two (2) 500-bbl produced water storage tanks, two (2) 10-

MMBTUH process flares, one (1) 6-MMBTUH loading combustor, condensate truck loading,

monitored fugitive emissions, non-monitored fugitive emissions, and various support operations.

SECTION II. PROCESS DESCRIPTION

The facility is a natural gas processing plant, responsible for processing gathered pipeline gas

with a nominal design throughput of 720-MMSCFD. Natural gas dehydration, condensate

storage, condensate truck loading, produced water storage, and produced water truck loading will

occur on-site as well.

The gas stream will enter the facility and will be sent to the three amine units for removal of

carbon dioxide and hydrogen sulfide. The amine units’ still vents will be controlled by thermal

oxidizers for control of emissions. The amine units’ flash tanks will be vented to the fuel gas

system or to the process flares. Gas from the amine units will then be dehydrated in four

molecular sieve dehydration units. A portion of the gas stream will be compressed by four

1,380-hp Caterpillar G3516 ULB natural gas-fired engine driven compressors w/OC. The

balance will be compressed by electric motor driven compressors. The gas will then be

processed in one of four cryogenic natural gas liquids (NGL) recovery skids, which include

closed loop propane refrigeration systems, for the removal of NGL products. The NGL products

will be delivered to a pipeline. A portion of the residue gas from the NGL recovery units will

then be compressed by seven 1,380-hp Caterpillar G3516 ULB natural gas-fired engine driven

compressors equipped w/OC. The balance will be compressed by electric motor driven

compressors. Condensate will be separated from the inlet gas stream, stabilized in a closed

system prior to entering the storage tanks, and stored in eight 1,000-bbl condensate storage tanks

prior to being loaded onto trucks. Truck loading emissions will be controlled by a 6-MMBTUH


combustor. Produced water and fluid from the skid drains will be stored in two 210-bbl and

three 500-bbl produced water storage tanks.

In addition, the facility will include one 27.2-hp Generac 2.3L diesel-fired engine driven

emergency generator, one 1,341-hp Caterpillar C32 ATAAC diesel-fired engine driven

emergency generator, two 315-hp Caterpillar C7.1 DITA diesel-fired engine driven emergency

generators, and two process flares. The generators will each be limited to 500 hours of operation

per year.

SECTION III. EQUIPMENT

Sources of emissions are grouped together in Emission Unit Groups (EUGs) as follows.

EUG-01A: Stationary Compressor Engines

EU

Emission

Unit

Description

Horsepower Control

Construction/Modification Date

E-01 through

E-11

Caterpillar

G3516 ULB 1,380

Oxidation

Catalyst

E-01 through E-07: 3/20/2015

E-08 through E-11: Pending

EUG-01B: Stationary Generator Engines

EU Emission Unit

Description Horsepower Control

Construction/Modification

Date

GEN1 Caterpillar C32 ATAAC 1,341 none 7/15/2015

GEN2 Generac 2.3L 27.2 none 11/1/2015

GEN3 Caterpillar 7.1 DITA 315 none Pending

GEN4 Caterpillar 7.1 DITA 315 none Pending

EUG-01C: Uncontrolled Compressor Blowdowns

EU Emission Unit

Description Volume (SCF/yr)


Date

B1 Uncontrolled Compressor

Blowdowns 2,260,430 3/20/2015

EUG-02: Amine Units

EU EU

Description Throughput Controls


Date

A-01 Amine Unit 240-MMSCFD thermal oxidizer or process flare Pending

A-02 Amine Unit 240-MMSCFD thermal oxidizer or process flare 2/7/2016

A-03 Amine Unit 240-MMSCFD thermal oxidizer or process flare Pending

EUG-03: Thermal Oxidizers

EU Emission Unit Description Firing Rate Construction/Modification Date

TO-01 Thermal Oxidizer 20.6-MMBTUH Pending

TO-02 Thermal Oxidizer 16.7-MMBTUH 2/7/2016

TO-03 Thermal Oxidizer 20.6-MMBTUH Pending


EUG-04: Additional Heaters

EU Emission Unit Description Firing Rate Construction/Modification

Date

HEAT1 Stabilizer Reboiler 8.0-MMBTUH 6/7/2015

HEAT2 Dehy Regenerator Heater 9.5-MMBTUH 3/20/2016

HEAT3 Hot Oil Heater 30.0-MMBTUH 6/29/2015

HEAT4 Amine Regenerator Heater 40.0-MMBTUH 2/7/2016

HEAT5 Hot Oil Heater 53.1-MMBTUH Pending

HEAT6 Dehy Regenerator Heater 20.2-MMBTUH Pending

HEAT7 Hot Oil Heater 53.1-MMBTUH Pending

HEAT8 Dehy Regenerator Heater 20.2-MMBTUH Pending

EUG-05A: Condensate Tanks

EU Emission Unit Description Volume Construction/Modification

Date

TK-451 Condensate Storage Tank 1,000-bbl 6/7/2015




TK-455 Condensate Storage Tank 1,000-bbl Pending




EUG-05B: Produced Water Tanks

EU Emission Unit Description Volume Construction/Modification

Date

TK-891 Produced Water Storage Tank 210-bbl Pending

TK-892 Produced Water Storage Tank 210-bbl Pending

TK-2891 Produced Water Storage Tank 500-bbl 8/31/2015

TK2892 Produced Water Storage Tank 500-bbl Pending

EUG-06: Plant Flares and Combustor

EU Emission Unit Description Construction/Modification Date

FLARE1 10-MMBTUH Process Flare 3/20/2015

FLARE2 10-MMBTUH Process Flare Pending

COMB1 6-MMBTUH Loading Combustor Pending

EUG-07: Truck Loading


LOAD1 Condensate Truck Loading 6/7/2015

EUG-08A: Unmonitored Fugitive Emissions


FUG1 Unmonitored Process Piping Fugitive Emissions 6/7/2015


EUG-08B: Monitored Fugitive Emissions


FUG2 Monitored Process Piping Fugitive Emissions 6/7/2015

EUG-09: Insignificant Tanks

EU Emission Unit Description Volume

TK-886 Compressor Skid Drain Sump 395-gal




TK-3686 Compressor Skid Drain Sump 1,000-gal




TK-2803 Amine Unit Drain Sump 1,680-gal


TK-3804 Expander Skid Drain Sump 750-gal

TK-3805 HMO Skid Drain Sump 2,000-gal

TK-3806 Refrigeration Skid Drain Sump 1,500-gal





The facility may also contain ancillary equipment that is not subject to emissions limitations or

requirements. These are addressed as insignificant activities.

SECTION IV. POTENTIAL EMISSIONS

Criteria Pollutants

Estimated emissions from the Caterpillar G3516 ULB natural gas-fired engines (E-01 through E-

11) are based on manufacturer’s data, AP-42 (7/00) Table 3.2-2, and manufacturer specified

control efficiencies for the oxidation catalysts. The manufacturer supplied emission factors at

full load are as follows: NOx = 0.50 g/hp-hr, CO = 2.85 g/hp-hr, VOCNMNEHC = 0.82 g/hp-hr, and

formaldehyde = 0.42 g/hp-hr. The controlled emission factors are as follows: NOx = 0.50 g/hp-

hr, CO = 0.45 g/hp-hr (84% control), VOCNMNEHC = 0.22 g/hp-hr (73% control), and

formaldehyde = 0.07 g/hp-hr (84% control). The AP-42 emission factors used to calculate

emissions were 0.0099871 lb/MMBtu for PM and 0.000588 lb/MMBtu for SO2. Emissions from

the Caterpillar G3516 ULB engines are based on the maximum rated horsepower, a brake

specific fuel consumption of 7,977 Btu/hp-hr, and 8,760 hours of operation per year.

Estimated emissions from the 1,341-hp Caterpillar C32 ATAAC diesel-fired engine driven

emergency generator (GEN1) are based on manufacturer’s data and AP-42 (10/96) Table 3.4-3.

Emissions from the Caterpillar C32 ATAAC emergency generator engine are based on the

maximum rated horsepower, a brake specific fuel consumption of 6,903 Btu/hp-hr, and 500


hours of operation per year for each engine. Formaldehyde emissions were estimated to be 0.003

TPY.

Estimated emissions from the 27.2-hp Generac 2.3L diesel-fired engine driven emergency

generator (GEN2) are based on manufacturer’s data and AP-42 (7/00) Table 3.3-2. Emissions

from the Generac 2.3L engine are based on the maximum rated horsepower, a brake specific fuel

consumption of 9,247 Btu/hp-hr, and 500 hours of operation per year. Formaldehyde emissions

were estimated to be 0.0001 TPY.

Estimated emissions from the two (2) 315-hp Caterpillar C7.1 DITA diesel-fired engine driven

emergency generators (GEN3 and GEN4) are based on manufacturer’s data and AP-42 (7/00)

Table 3.3-2. Emissions from the Caterpillar C7.1 DITA engines are based on the maximum

rated horsepower, a brake specific fuel consumption of 6,424 Btu/hp-hr, and 500 hours of

operation per year. Formaldehyde emissions were estimated to be 0.001 TPY.

Engine Emission Factors

Description NOX CO VOC PM SO2 HCHO

g/hp-hr g/hp-hr g/hp-hr see below lb/MMBtu see below

E-01 through E-11 0.50 0.45 0.22 0.0099871

lb/MMBtu 0.000588

0.07

g/hp-hr

GEN1 4.93 0.13 0.01 0.02 g/hp-hr 0.29 0.00118

lb/MMBtu

GEN2 4.77 1.27 0.075 0.14 g/hp-hr 0.29 0.00118

lb/MMBtu

GEN3 and GEN4 2.78 0.98 --(1) 0.13 g/hp-hr 0.29 0.00118

lb/MMBtu (1) – VOC emission factors for GEN3 and GEN4 are included in the NOx emissions.

Uncontrolled compressor blowdown emissions (B1) at the facility were estimated based on inlet

and residue gas analyses, the volume per blowdown estimates, and 26 blowdown events per year.

Uncontrolled

Blowdown Type Estimated Volume Each

Estimated Total Annual

Volume

Inlet Gas 37,572 scf/blowdown 976,875 scf/yr

Residue Gas 49,368 scf/blowdown 1,283,555 scf/yr

Total 2,260,430 scf/yr

Emissions from the amine units (A-01, A-02, and A-03) are calculated using the ProMax process

simulation software, a natural gas feed rate of 240-MMSCFD each unit, a maximum amine

circulation rate of 350-GPM at each unit, and an extended gas analysis. The amine unit still vent

vapors are captured with at least 97% efficiency and routed to a thermal oxidizer with a control

efficiency of 98% or greater. The amine units are equipped with flash tanks. Flash tank vapors

are routed to the amine unit reboiler fuel system or the process flare with a control efficiency of

98%.

NOx, CO, and PM emissions from the thermal oxidizers TO-01, TO-02, and TO-03 at the

facility were calculated using AP-42 (7/98) factors for commercial boilers found in Table 1.4-1


through Table 1.4-3, the burner ratings of 20.6-MMBTUH, 16.7-MMBTUH, and 20.6-

MMBTUH, respectively, and 8,760 hours of operation per year. The still vent vapors are routed

to a thermal oxidizer or flare, resulting in 97% capture efficiency from the amine unit still vents

and 98% control efficiency of the captured vapors. Additionally, potential SO2 emissions

assume that 98% of the potential H2S emissions from the amine unit still vents are oxidized into

SO2.

Emissions from the heaters at the facility (HEAT1 through HEAT8) were calculated using AP-

42 (7/98) factors for commercial boilers found in Table 1.4-1 through Table 1.4-3. Emissions

were calculated based on each unit’s firing rate as listed in Section III. Equipment table EUG-04:

Additional Heaters and continuous operation.

Working and breathing VOC emissions from the storage tanks at the facility were calculated

using EPA’s TANKS 4.0 computer program, a facility wide condensate throughput of 76,650,000-

gal/year, and a facility wide produced water throughput of 2,299,500-gal/year. Produced water

emissions were estimated equal to 1% of the emissions estimated for an equal volume of

condensate. Flashing from the liquids at the facility occur upstream of the facility at well sites,

prior to entering the storage tanks; therefore, no flashing losses were calculated for the storage

tanks at the facility.

VOC emissions from the roof landings of the internal floating roof (IFR) tanks were calculated

using AP-42 (11/06), Section 7.1 with the assumption of 8 total events per year, a tank diameter

of 15 ft, and a roof leg setting of 4.5 ft.

Standing idle losses for each roof landing event were calculated based on Equation 2-20 as

follows:

𝐿𝐶 = 0.042𝐶𝑆𝑊𝑙(𝐴𝑟𝑒𝑎)

Where:

LC = clingage loss from the drain-dry tank, lb,

0.042 = conversion factor, gal/bbl,

CS = clingage factor, 0.006 bbl/1,000 ft2,

Wl = density of the liquid, 7.1 lb/gal, and

Area = area of the tank bottom, ft2.

Filling losses were calculated for each roof landing event based on Equation 2-26, as follows:

𝐿𝐹𝐿 = (𝑃𝑉𝑉𝑅𝑇

)𝑀𝑉𝑆

Where:

LFL = filling loss during roof landing, lb,

P = true vapor pressure of the liquid within the tank, 6.25 psia,

VV = volume of the vapor space, ft3,


R = ideal gas constant, 10.731 psia-ft3/(lb-mol-°R),

T = average temperature of the vapor and liquid below the floating roof, 521.6 R,

Mv = stock vapor molecular weight, 66 lb/lb-mol,

S = filling saturation factor, dimension less (0.15 for a drain-dry tank).

NOx and CO emissions from the process flares (FLARE1 and FLARE2) were based on AP-42

(1/95) Table 13.5-1 for industrial flares and the estimated heating rate of vapors directed to the

flare. VOC emissions from FLARE1 and FLARE2 were estimated based on the volume of

VOCs vented to each flare, a material balance, and assuming 98% destruction of VOCs in each

flare. The still vents from A-02 and A-03 can be vented to the flares when the thermal oxidizers

are inoperable. Flared emissions from A-02 and A-03 are equal to the emissions estimated for

the thermal oxidizers. Emissions from flaring potential emissions from A-02 and A-03 are

accounted for at emissions points TO-02 and TO-03. H2S and SO2 emissions from the flares

were estimated assuming a 4-ppm maximum H2S concentration in the gas.

Emissions from condensate loading into tank trucks are estimated based on AP-42 (1/95),

Section 5.2 Equation 1, and the following parameters. Tank truck loading is controlled by a

loading combustor (COMB1) with an assumed capture efficiency of 70% and 98% control

efficiency for the VOC emissions from the combustor. NOx and CO emissions from the loading

combustor (COMB1) were based on AP-42 (11/95) Table 13.5-1 for industrial flares, a 6-

MMBTUH maximum heat capacity, and 8,760 hours of operation per year.

Truck Loading

Throughput

gal/yr

Emission Factor

lb/1,000 gal

Reduction Claimed

Wt.%

Capture Efficiency

Wt. %

76,650,000 4.46 0 70

VOC emissions from unmonitored process piping fugitives (FUG1) and monitored process piping

fugitives (FUG2) are based on EPA’s natural gas processing factors for process piping fugitive

emissions and EPA’s document, “1995 Protocol for Equipment Leak Emission Estimates (EPA-

453/R-95-017)”, an estimated number of components, and a representative gas analysis with VOC

content of 16.31% for components in gas service.

Facility-Wide Emissions

EU Description NOX CO VOC

lb/hr TPY lb/hr TPY lb/hr TPY

E-01 1,380-hp Caterpillar G3516 ULB1 1.52 6.66 1.36 5.97 0.66 2.91














GEN1 1,341-hp Caterpillar C32 ATAAC2 14.57 3.64 0.38 0.10 0.03 0.01

GEN2 27-hp Generac 2.3L2 0.29 0.07 0.08 0.02 <0.01 <0.01

GEN3 315-hp Caterpillar C7.1 DITA2 1.93 0.48 0.68 0.17 -- --

GEN4 315-hp Caterpillar C7.1 DITA2 1.93 0.48 0.68 0.17 -- --

B1 Uncontrolled Blowdowns -- -- -- -- -- 4.54

A-01 240-MMSCFD Amine Unit -- -- -- -- 0.71 3.11



TO-01 20.6-MMBTUH Thermal Oxidizer 2.02 8.85 1.70 7.43 0.16 0.70



HEAT1 8.0-MMBTUH Stabilizer Reboiler 0.78 3.44 0.66 2.89 0.04 0.19

HEAT2 9.5-MMBTUH Dehy Regen Heater 0.93 4.08 0.78 3.43 0.05 0.22

HEAT3 30-MMBTUH Hot Oil Heater 2.94 12.88 2.47 10.82 0.16 0.71

HEAT4 40-MMBTUH Amine Regen Heater 3.92 17.18 3.29 14.43 0.22 0.94

HEAT5 53.1-MMBTUH Hot Oil Heater 5.21 22.80 4.37 19.15 0.29 1.25


HEAT7 53.1-MMBTUH Hot Oil Heater 5.21 22.80 4.37 19.15 0.29 1.25


TK-451 1,000-bbl Condensate Tank -- -- -- -- --

3.29








LAND IFR Tank Roof Landings -- -- -- -- -- 0.04

TK-891 210-bbl Produced Water Tank -- -- -- -- -- 0.02




FLARE1 Process Flare 252.91 3.34 1,376.15 18.16 629.32 8.63

FLARE2 Process Flare 252.91 3.34 1,376.15 18.16 629.32 8.63

COMB1 Loading Combustor 0.41 1.79 2.22 9.72 0.50 2.19

LOAD1 Condensate Truck Loading -- -- -- -- 10.71 51.30

FUG1 Unmonitored Fugitive Emissions -- -- -- -- 1.96 8.57




FUG2 Monitored Fugitive Emissions -- -- -- -- 0.67 2.93

Total 569.89 211.53 2,793.10 215.87 1,272.47 139.17

1 – Equipped with oxidation catalyst. 2 – Based on 500 hours per year.

Sulfur and Particulate Emissions

The facility estimated emissions for particulate matter (PM), sulfur dioxide (SO2), and hydrogen

sulfide (H2S). PM is emitted from fuel burning activities and was estimated to be 3.63 lb/hr or

14.87 TPY based on the emissions factor presented in the following table. SO2 is emitted from

fuel burning activities and the thermal oxidizers based on the emissions factors presented in the

following table.

Particulate Matter Emissions Factors

EU Emissions Factor Emissions Factor Source

Diesel-fired Emergency

Generators 0.02 g/hp-hr Manufacturer’s Data

Natural gas-fired engines 0.0099 lb/MMBTU AP-42 (8/00) Section 3.2

Thermal Oxidizers / Process

Flares / Heaters 7.6 lb/MMSCF AP-42 (7/98) Section 1.4

SO2 Emissions Factors

EU Emissions Factor Emissions Factor Source

Diesel-fired Emergency

Generators 0.29 lb/MMBTU AP-42 (10/96) Section 3.3

Natural gas-fired engines 0.000588 lb/MMBTU AP-42 (8/00) Section 3.2

Heaters 0.6 lb/MMSCF AP-42 (7/98) Section 1.4

Thermal Oxidizers Material Balance from

ProMax 98% Control

H2S emissions from the amine units are oxidized by the thermal oxidizers which results in SO2

formation. The still vent vapors contain H2S, and are either routed to the thermal oxidizers or the

process flares for a 97% capture efficiency. H2S is emitted from the amine units, the storage

tanks, truck loading, and fugitive sources. Emissions from the amine unit still vents are

controlled with 98% efficiency. Emissions from the amine unit flash tanks are controlled with

98% efficiency Amine unit H2S emissions are estimated to be 0.02 TPY. The facility wide SO2

emissions estimates are estimated to be 50.04 lb/hr or 86.37 TPY. Facility wide H2S emissions

estimates are estimated to be 1.02 lb/hr or 3.21 TPY.

Hazardous Air Pollutants (HAP)

The applicant has analyzed the incoming wet gas for concentrations of HAPs and estimated the

HAP emissions using the ProMax simulation program. Emissions are based on a facility-wide

gas throughput of 720-MMSCFD and an amine circulation rate of 350-GPM each unit. The

HAP emissions from the amine unit still vents are routed to the thermal oxidizers, captured with

at least 97% efficiency, and controlled with 98% efficiency. Flash tank emissions from the


amine units are routed to the amine unit reboiler fuel system or one of the process flares with

98% control efficiency. Emissions include a 50% safety factor.

Total HAP Emissions from Amine Units

Pollutant A-01 A-02 A-03


Hexanes 0.01 0.03 0.01 0.03 0.01 0.03

The internal combustion engines have emissions of HAP, the most significant being

formaldehyde. Emissions of formaldehyde for the lean-burn engines are based on continuous

operation and oxidation catalysts with formaldehyde control efficiencies of 84%. The diesel-

fired engines (GEN1 through GEN4) and heaters (HEAT1 through HEAT8) have negligible

emissions of formaldehyde. The following table lists estimated formaldehyde emissions for the

natural gas-fired engines at the facility.

Controlled Formaldehyde Emissions from Natural Gas-Fired Engines

EU Description Manufacturer

Emission Factor

Potential Controlled1

lb/hr TPY lb/hr TPY

E-01 1,380-hp Caterpillar G3516 ULB 0.42 g/hp-hr 1.28 5.60 0.20 0.90











Totals 14.06 61.56 2.25 9.85 1 Controlled emissions estimates are based on the engine using an oxidation catalyst with 84% control efficiency.

SECTION V. STATE BACT REVIEW

Since emissions of NOX, CO, and VOC exceed 100 TPY for the facility, a state BACT review is

required by OAC 252:100-8-5(d). The permit No. 2015-0197-C addressed BACT analysis for

NOx and CO. Since the modification in this permit, 2015-0197-C (M-1), requests VOC

emissions from the facility greater than 100 TPY, an updated BACT analysis has been completed

which includes VOC. The applicant submitted the following BACT analyses.

Compressor Engines

NOx and CO

A review of the RBLC database and recently issued ODEQ PSD permit applications indicates

that NOx and CO BACT for ultra lean-burn natural gas-fired compressor engines are as follows:

NOX is 0.50 g/hp-hr and CO is between 0.36 and 0.55 g/hp-hr. This requires add-on catalytic


converters for rich-burn engines or the use of low-NOX lean-burn engines with oxidation

catalysts or non-selective catalytic reduction controls.

The eleven (11) Caterpillar G3516 ULB natural gas-fired compressor engines (E-01 through E-

11), rated at 1,380 hp each, are lean-burn engines and are each equipped with oxidation catalysts

in order to meet these emission limitations. Additionally, the engines are subject to the emission

limitations of 40 CFR Part 60 Subpart JJJJ and 40 CFR Part 63 Subpart ZZZZ. The natural gas-

fired engines proposed by Woodford have NOx emissions equal to or less than 0.50 g/Hp-hr and

CO emissions less than 0.45 g/Hp-hr. Therefore, BACT is selected for the natural gas-fired

compressor engines as lean burn engines at an emission rate of 0.50 g/hp-hr for NOx and

oxidation catalysts at an emission rate of 0.45 g/hp-hr for CO.

VOC

A review of the Reasonable Available Control Technology (RACT) /BACT/ Lowest Achievable

Emission Rate (LAER) Clearinghouse (RBLC) database and recently issued ODEQ PSD permit

applications indicates that BACT for VOC is 0.7 g/hp-hr. This requires add-on catalytic

converters for rich-burn engines or the use of low-NOx lean-burn engines with oxidation

catalysts.

The natural gas-fired engines proposed by Woodford have VOC emissions less than 0.7 g/hp-hr.

The eleven (11) Caterpillar G3516 ULB natural gas-fired compressor engines (E-01 through E-

11), rated at 1,380-hp each, are lean-burn engines and are each equipped with oxidation catalysts

in order to meet these emission limitations. Additionally, the engines are subject to the

emissions limitations of 40 CFR Part 60 Subpart JJJJ and 40 CFR Part 63 Subpart ZZZZ.

Therefore, BACT is selected as the use of oxidation catalysts on the natural gas-fired compressor

engines resulting in 0.22 g/hp-hr VOC.

Summary of Selected BACT for Compressor Engines

Pollutant Control Technology Emission Limits

NOx Lean Burn Combustion 0.50 g/hp-hr

CO Oxidation Catalyst 0.45 g/hp-hr

VOC Oxidation Catalyst 0.22 g/hp-hr

Emergency Engines

NOx, CO, and VOC

The following methodology for performing a top-down BACT analysis has been developed from

the US EPA’s 1990 Draft New Source Review Workshop Manual - BACT Guidance. The

analysis utilizes five key steps to identify the most suited BACT option for the project.

Step 1. Identify Available Control Technologies

Identification of possible BACT options were derived from EPA and state BACT

clearinghouses, recently issued regulations and permit decisions from similar projects. The

following activities were identified as BACT options to control emissions from the emergency

generators. Woodford is proposing to install two additional generators that are NSPS Subpart

IIII compliant, which meet EPA Tier III off-road standards. The EPA has mandated the use of

Tier IV engines for continuous power generation, but acknowledges that an “emergency use”


engine has significantly less potential emissions. Therefore, the control options studied in this

analysis are the proposed Tier III generator compared to a Tier IV generator. Two control

options are shown in the following table:

Option Description

1. NSPS III (Tier III) Compliant Engine

2. EPA Tier IV Engine

NSPS IIII Complaint Engine – This level of control has been accepted as the standard in

New Source Performance Standards (NSPS) Subpart IIII-Standards of Performance for

Stationary Compression Ignition Internal Combustion Engines.

EPA Tier IV Compliant Engine – EPA require Tier IV engines for continuous power

generation and peak shaving.

Step 2. Eliminate Technically Infeasible Options At this step, an evaluation of the technical feasibility of each control alternative is made. Each

alternative that is determined to be technically infeasible will be excluded from further BACT

evaluation and eliminated as a potential option.

Manufacturers do not offer smaller Tier IV compliant emergency engines. Therefore, purchasing

a Tier IV emergency generator of this size is not a technically feasible option. BACT for the

emergency generator is selected as NSPS IIII (Tier III) engines with limits no greater than those

listed below:

Engine Name Engine Size NOx + NMHC (TPY) CO (TPY)

GEN1 HP>750 4.8 2.6

GEN2 25HP50 5.6 4.1

GEN3 175HP 3.0 2.6

GEN4 175HP 3.0 2.6

Amine Unit (VOC)

A review of the RBLC database indicates that the typical add-on controls for amine units are

flares or thermal oxidizers. Woodford proposes to control the still vents from the amine units

with thermal oxidizers or flares with 97% capture / 98% destruction efficiencies for VOCs. The

flash tanks from the amine units are routed to the fuel system with 100% capture and combustion

as a fuel source or to the flares with 97% capture / 98% destruction efficiencies. BACT is

selected as thermal oxidizers or flares with 97% capture / 98% destruction efficiencies for VOCs

resulting in 3.11 TPY VOCs per unit.

Heaters

A review of the RBLC database and recently issued ODEQ PSD permit applications indicates

that BACT for small heaters less than or equal to 100 MMBtu/hr has listed no add-on controls

are required for NOx, CO and VOC. These pollutants are controlled via good combustion

practices and burning natural gas as fuel. Therefore, BACT is good combustion practices and

burning natural gas as fuel with the emissions factors as summarized following, which are taken

from AP-42 (7/98), Section 1.4 for heaters.


Summary of Selected BACT for Heaters

Pollutant Control Technology Emission Limits

NOx Good Combustion Practices 100 lb/MMSCF

CO Good Combustion Practices 84 lb/MMSCF

VOC Good Combustion Practices 5.5 lb/MMSCF

Condensate Tanks (VOC)

A review of the RBLC and recently issued ODEQ PSD permit applications indicate that typical

add-on controls for condensate tanks of 1,000 bbl or less in size are fixed roof tanks routing the

emissions to either a combustion device or vapor recovery unit (VRU). The condensate stored at

the Facility will be stabilized in a closed system prior to entering the storage tanks. Therefore,

the flashing losses from the tanks are negligible. The only source of VOC emissions from the

condensate storage tanks are breathing and working losses, which result in emissions of

approximately 0.4 TPY per storage tank. Additionally, the condensate storage tanks are equipped

with internal floating roofs; therefore, additional controls are not warranted. BACT is selected as

the use of internal floating roof tanks for the condensate storage tanks.

VOC







following activities were identified as BACT options to control emissions from the condensate

storage tanks. Woodford is proposing to install four additional condensate storage tanks with

internal floating roof (IFR).

Control Technologies

Routing Vapor Space to a Control Device

Thermal Incinerator

Flare

Vapor Combustor

Roof Selection

EFR, IFR

Fixed Roof

Routing Vapor Space to a Control Device Evaporative losses from tanks can be routed to a variety of control devices with varying destruction

efficiencies. Combustion type controls, including flares, combustors, and incinerators, destroy VOCs

with auxiliary fuel injection. Destruction efficiencies range from 98-99.9%, depending on the

material.


Roof Selection Three basic roof types are considered: external floating roof, internal floating roof, and fixed roof.

Fixed roof tanks – These tanks consist of a cylindrical steel shell with a permanently fixed roof that

can be either cone-shaped, dome-shaped, or flat. Evaporative losses occur in these tanks through

vapor expansion and contraction and from working losses as filling vapors are expelled from the

tank.

External floating roof tanks (EFRs) – These tanks consist of an open cylindrical steel shell with a

roof, or deck, which floats on the surface of the stored liquid. The roof height changes with the liquid

level of the material stored within the tank, effectively minimizing vapor space. A rim seal system is

attached to the deck’s perimeter and makes contact with the tank wall. These two systems combine to

reduce VOC emissions from the stored material. Losses from these tanks originate from exposed

liquid at the rim seal system and deck fittings. In addition to the basic tank configuration, there are

several add-on options to further reduce emissions and are listed as follows:

Cone Roof Add-on with Vapor Space Routed to a Control Device. This option would involve

installing a fixed cone roof over the top of each tank at the plant, thereby creating internal

floating roof tanks from the previous EFR tank. The coned exterior roofs would be supported

by columns that penetrate through the floating roof inside each tank. The fixed coned roof

design acts to block the wind flow across the top of each tank and be part of a system to

collect emissions coming out the top of the floating roof of each tank. A dedicated vapor

collection system would be installed to route emissions from each tank to a dedicated control

device as listed in the previous control technology category (Routing Vapor Space to a

Control Device).

Cone Roof Add-on Only – This option involves installing a fixed coned roof as in the

previous option except without installation of a control device as discussed in the previous

control technology category and associated collection piping. The primary function of the

fixed external roof in this alternative would be to block the wind and decrease standing and

withdrawal emissions from each tank. This option is estimated to provide a control efficiency

of up to 44%.

Domed External Floating Roof – This option involves constructing a self-supporting

geodesic dome over the existing external floating roof on each tank at the terminal. Similar to

the cone roof add-on option, geodesic domes are utilized to minimize the wind over the top

of the external floating roof. The domed tanks are generally vented with circulation vents at

the top of each roof. Emissions from each domed EFR tank would not be piped to a control

device. Since the geodesic domes would be self-supporting, the installation of column

supports penetrating through the floating roof would not be necessary and gaps in the floating

roof would be minimized. This design is still referred to as an external floating roof because

it utilizes the existing heavier-duty, double-sealed fully intact EFR, though for emission

estimation purposes it is treated as an IFR with no support columns. This option is estimated

to provide a control efficiency of up to 73%.

Internal floating roof tanks (IFRs) – These tanks are simply EFRs with an additional, fixed roof

above the floating roof. The fixed roof serves as a vapor barrier and blocks air movement.

Additionally, the internal floating roof tank deck is lighter than those used in external roof tanks.

Losses from these tanks are the same as EFRs, with the exception that emissions induced by air

movement are reduced. Woodford has selected IFRs over fixed roof tanks.


Step 2. Eliminate Technically Infeasible Options All control options are technically feasible when considered individually. These options are further

considered in the following steps of the top-down BACT analysis.

Step 3: Rank Remaining Control Options by Control Effectiveness

Floating roof tanks reduce vapor space emissions more effectively than fixed roof tanks because the

deck rests atop the liquid surface and reduces the vapor space within the tank.

Add-on control options add additional emission control beyond the basic required components of

each tank.

Routing Vapor Space to a Control Device is the most effective option (50-99.9%), submerged fill,

and then good operating and maintenance practices.

In addition to control effectiveness and emissions considerations, each BACT option must also be

evaluated for economic impacts, environmental, and energy impacts. These considerations are further

discussed in Step 4.

Step 4: Evaluate and Eliminate Control Technologies Based on Energy, Environmental, and

Economic Impacts

Since NSPS Subpart Kb requires an EFR or IFR, Woodford has assumed this control option to be the

baseline requirement and has selected IFR tanks which provide the same level of control as an EFR.

Under this assumption, submerged fill would be meaningless since there will be no vapor space for

splash loading to occur.

The economic consideration for each remaining BACT option is based on a cost analysis, in part,

total capital costs, direct costs, and total derived annualized cost. The cost analysis was based on

industry cost estimates for combustion devices constructed and EPA’s Cost Control Manual. Note,

sizing of the thermal oxidizer depends on the hourly rate of controlled VOC, and annual operating

costs (utilities, pilot fuel, etc.) vary based on mode of operation (e.g. continuously for normal

operations and intermittently for landings and cleanings).


Cost Analysis (Storage Tanks – Normal Operations)

IFR & Vapor Collection

Purchased Equipment

Costs

Flare $750,000

Piping from Tanks to

Thermal Oxidizer

$250,000

Direct Costs

Total Capital Investment $1,643,506

Total Annual Cost $ 499,911

Annualized Cost Estimation

Interest 6%

Equipment life (yrs) 15

Total Annual Cost $499,911

Emissions Reductions

Baseline Emissions (tpy) 3.3 (combined emissions from all tanks)

Control Efficiency 98%

Emissions Reduced (tpy) 3.23

BACT Cost ($/ton reduced) $154,792

From the table above, the per ton reduced is approximately $154,792. This value represents a

significant economic impact. Due to the extremely high and unreasonable economic impact for this

BACT option, it is an inappropriate BACT alternative beyond the baseline NSPS Subpart Kb

standards for new tanks.

Environmental and energy impacts from the IFR & vapor collection option are as follows: increase in

NOx emissions, increase in CO emissions, noise, and fuel consumption.

Step 5: Select BACT and Document the Selection as BACT

Woodford has proposed to implement the following design elements and work practices:

• Internal floating roof compliant with NSPS Subpart Kb standards,

• Primary mechanical shoe seal and secondary seal, and

• Good operation and maintenance practices.

As mentioned previously, the resulting BACT standard is an emission limit unless technological or

economic limitations of the measurement methodology would make the imposition of an emissions

standard infeasible, in which case a work practice or operating standard can be imposed. For the

proposed storage tanks, Woodford proposes a VOC BACT emission limit of 3.29 tons of VOC per

year based on a 12-month rolling average basis, internal floating roof compliant with NSPS Subpart

Kb standards, primary mechanical shoe seal and secondary seal, and good operation and maintenance

practices.

DEQ evaluated the BACT proposal from Woodford and agrees that their proposal is acceptable as

state level BACT.


Produced Water Tanks (VOC)


add-on controls for produced water storage tanks are routing the emissions to either a

combustion device or vapor recovery unit (VRU). The produced water storage tank emission

calculations 1% oil in the water. The total emissions from these tanks is 0.12 TPY. Due to the

location of the tanks, the low VOC emissions and the distance to the flare, the addition of

blowers to route the vapors to the flare is not technically feasible. However, a cost to add a

combustion device is listed below:


Vapor Collection

Purchased Equipment

Costs

Flare $500,000

Installation Costs $448,996

Direct Costs

Total Capital Investment $950,496



Interest 6%




Baseline Emissions (tpy) 0.12 (combined emissions from all tanks)



BACT Cost ($/ton reduced) $3,487,537

From the table above, the per ton reduced is approximately $3,487,537. This value represents a


BACT option, it is an inappropriate BACT alternative beyond the baseline of fixed roof tank for new

tanks.

Environmental and energy impacts from the vapor collection option are as follows: increase in NOx

emissions, increase in CO emissions, noise, and fuel consumption.

Select BACT and Document the Selection as BACT


• Fixed roof tank,





proposed storage tanks, Woodford proposes a VOC BACT emission limit of 0.12 tons of VOC per

year based on a 12-month rolling average basis, a fixed roof tank, and good operation and

maintenance practices.


DEQ evaluated the BACT proposal from Woodford and agrees that their proposal is acceptable

as state level BACT.

Roof Landing Losses (VOC)

Step 1. Identify Available Control Technologies When it comes to controlling VOC emissions during roof landings, degassing, and refilling the

following were identified:

1. Routing Vapor Space to a Control Device

a. Thermal incinerator

b. Flare

c. Vapor Combustor

d. Carbon Adsorption

2. Mobile Degassing

a. Thermal Oxidizer

b. Carbon Adsorption

3. Roof landings conducted per NSPS Subpart Kb

4. Tanks with Dry Drain design

5. Work practice standards to limit emissions generated

Step 2. Eliminate Technically Infeasible Options Woodford proposes to utilize internal floating roof tanks designed per NSPS Subpart Kb and

with a dry drain design. In addition, roof landings, degassing, and refilling emissions are

expected to occur no more than 2 times per year per tank and the emissions are estimated at 0.04

TPY, total for all tanks. BACT is selected as Roof landings conducted per NSPS Subpart Kb

with 0.04 TPY VOC emissions. Woodford proposes that cost analysis of the other available

control technologies is not warranted due to the low emission levels resulting from roof landings.

DEQ evaluated the BACT proposal from Woodford and agrees that their proposal is acceptable

as state level BACT.

Condensate Truck Loading

A review of the RBLC database indicates that add-on controls for condensate truck loading are

typically a flare or vapor balancing. The capture efficiency for a flare is 70% for condensate

truck loading with a destruction efficiency of 98%. This application proposes the use of a flare to

control loading. BACT is selected as vapor capture with 70% capture efficiency and 98%

destruction at the flare with 51.3 TPY VOC emissions based on a throughput of 76,650,000

gallons/year.

Fugitives

A review of the RBLC and recently issued ODEQ PSD permit applications indicate that LDAR

programs, using air-driven pneumatic controllers, and implementing audio-visual-olfactory

(AVO) monitoring can be used to limit fugitive VOC emissions. The Facility will be subject to

the limitations and LDAR monitoring requirements of 40 CFR Part 60 Subpart OOOO. BACT is

LDAR monitoring per 40 CFR Part 60 Subpart OOOO, the use of air-driven pneumatic

controllers, and implementation of an AVO monitoring program as BACT for fugitive VOC

emissions.


Blow Downs

The facility will have blowdowns as part of the facility startup and shutdown procedures.

Blowdowns on compressor units will occur on an “as needed” basis for maintenance and

operational activities. When blowdowns are required, on-skid piping and valves will be

manipulated to allow the entire unit to be equalized with the lowest available process pressure

thereby reducing the total mass of the blowdown.







following activities were identified as BACT options to control emissions from the blowdowns

from the engines associated with Trains 1 & 2.

Control Technologies

Routing blowdowns to a Control Device

Good Operating and Maintenance Practices

Routing blowdowns to a Control Device Blowdowns may be routed to a flare or vented to atmosphere with good operating and maintenance

practices. Destruction efficiencies for a flare range from 98-99.9%, depending on the material.

Step 2. Eliminate Technically Infeasible Options All control options are technically feasible when considered individually. These options are further

considered in the following steps of the top-down BACT analysis.

Step 3: Rank Remaining Control Options by Control Effectiveness

Routing blowdowns to a Control Device is the most effective option (98-99.9%), and then good

operating and maintenance practices.

In addition to control effectiveness and emissions considerations, each BACT option must also be

evaluated for economic impacts, environmental, and energy impacts. These considerations are further

discussed in Step 4.

Step 4: Evaluate and Eliminate Control Technologies Based on Energy, Environmental, and

Economic Impacts

The economic consideration for each remaining BACT option is based on a cost analysis, in part,

total capital costs, direct costs, and total derived annualized cost. The cost analysis was based on

industry cost estimates for combustion devices constructed and EPA’s Cost Control Manual. Note,

sizing of the flare depends on the hourly rate of controlled VOC, and annual operating costs (utilities,

pilot fuel, etc.) vary based on mode of operation (e.g. continuously for normal operations and

intermittently for landings and cleanings).


Train 1 and Train 2 Engine Blowdowns (VOC)


add-on controls for blowdown events are routing the emissions to a combustion device or good

operating practices. The total emissions from Train 1 and Train 2 natural gas-fired engine

blowdowns is 4.54 TPY. Due to the location of the engines, the low VOC emissions and the

distance to the flare, the addition of blowers to route the vapors to the flare is not technically

feasible. However, a cost to add a combustion device is listed below:


Vapor Collection

Purchased Equipment

Costs

Flare $700,000

Installation Costs $350,371

Direct Costs

Total Capital Investment $1,420,371



Interest 6%




Baseline Emissions (tpy) 4.54



BACT Cost ($/ton reduced) $113,176

From the table above, the cost per ton reduced is approximately $113,176. This value represents a


BACT option, it is an inappropriate BACT alternative beyond the baseline for Train 1 and Train 2

engine blowdowns.

Environmental and energy impacts from the vapor collection option are as follows: increase in NOx

emissions, increase in CO emissions, noise, and fuel consumption.

Select BACT and Document the Selection as BACT






proposed engine blowdowns, Woodford proposes a VOC BACT emission limit of 4.54 tons of VOC

per year based on a 12-month rolling average basis and good operation and maintenance practices.


DEQ evaluated the BACT proposal from Woodford and agrees that their proposal is acceptable as

state level BACT.

SECTION VI. 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 generation or for peaking power

service not exceeding 500 hours per year.

2. Emissions from stationary internal combustion engines rated less than 50-hp output.

3. *Space heaters, boilers, process heaters and emergency flares less than or equal to 5-

MMBTUH heat input fired by commercial natural gas.

4. *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.

5. *Activities having the potential to emit no more than 5 TPY (actual) of any criteria pollutant.

SECTION VII. NAAQS COMPLIANCE

Introduction

Woodford is proposing to construct a 720-MMSCFD gas processing plant located approximately

six miles south and six miles west of Lindsay, Oklahoma in Grady County. The Facility will

have potential emissions of NOx, CO, and VOCs that are greater than 100 TPY. Therefore, per

the Major Source Construction Permit Advice document, Woodford is required to perform air

dispersion modeling for the Facility. 40 CFR Part 51 Appendix W, Guideline on Air Quality

Models (GAQM) establishes the models that can be used for air quality modeling analysis to

demonstrate compliance with federal clean air standards, such as NAAQS.

Ozone (O3) Modeling

EPA conducted photochemical modeling studies and evaluated hypothetical single-source

impacts on downwind O3 concentrations in Guidance on the Development of Modeled Emission

Rates for Precursors (MERPs) as a Tier 1 Demonstration Tool for Ozone and PM2.5 under the

PSD Permitting Program (EPA-454/R-16-006, December 2016 - Draft). This guidance can be

used to estimate single source impacts by region and source type. For this analysis, since NOX

and VOC are both precursors for O3, the impacts from emissions of NOX and VOC were

considered. Using the guidance document, the estimated impact from 500 TPY of NOX in

Canadian County Oklahoma for a low level source is 0.57 ppb. The estimated impact from 500

TPY of VOC in Canadian County Oklahoma for a low level source is 0.07 ppb. This facility will

emit 208 TPY of NOX and 144 TPY of VOC. Therefore, the predicted impact of this facility is

approximately 0.3 ppb. Listed below are the closest monitoring sites with the most recent

monitoring data.


Ozone Monitoring Data

Site Name Distance 2014-20161 2015-20172

40-087-1073 Goldsby 31 miles NNW 66 ppb 66 ppb

40-031-0651 Lawton 42 miles WSW 65 ppb 64 ppb

40-015-9008 Anadarko 40 miles NW 55 ppb

1 - based on the 3 year average of highest fourth high.

2 - based on the 3 year average of the highest fourth high through December 11, 2017.

Background monitored concentrations combined with the predicted impacts from the project are

below the NAAQS of 70 ppb.

Source Parameters and Emission Rates

The pollutants evaluated in the AERMOD modeling analysis are NO2, CO, SO2, and H2S.

Detailed emission calculation methodology information for the proposed emission sources was

included in the construction permit application. The source parameter summary includes stack

locations and orientation, base elevations, stack heights, stack exit temperature, flow rate,

velocity, and stack diameter. Source locations are based on Universal Transverse Mercator

(UTM) North America Datum (NAD) 83.

AERMOD Source Parameters

Source

ID

Easting

(m)

Northing

(m)

Base

Elev

(m)

Stack

Height

(ft)

Temp

(ºF)

Stack

Flow

(acfm)

Exit

Vel

(ft/s)

Stack

Dia (ft)

E-01 618,749 3,846,207 379 25 990 8,716 82.2 1.50

E-02 618,749 3,846,221 379 25 990 8,716 82.2 1.50

E-03 618,749 3,846,235 378 25 990 8,716 82.2 1.50

E-04 618,794 3,846,172 378 25 990 8,716 82.2 1.50

E-05 618,808 3,846,172 377 25 990 8,716 82.2 1.50

E-06 618,822 3,846,172 376 25 990 8,716 82.2 1.50

E-07 618,836 3,846,172 376 25 990 8,716 82.2 1.50

E-08 619,230 3,846,263 373 25 990 8,716 82.2 1.50

E-09 619,230 3,846,239 372 25 990 8,716 82.2 1.50

E-10 619,229 3,846,209 372 25 990 8,716 82.2 1.50

E-11 619,231 3,846,180 372 25 990 8,716 82.2 1.50

A-01 618,796 3,846,282 375 75 120 471 12.9 0.88

A-02 619,074 3,846,288 373 75 120 471 12.9 0.88

A-03 619,296 3,846,291 373 75 120 471 12.9 0.88

TO-01 618,865 3,846,357 376 70 1600 4,275 7.0 3.60

TO-02 619,108 3,846,318 374 70 1600 4,275 7.0 3.60

TO-03 619,334 3,846,326 373 70 1600 4,275 7.0 3.60

HEAT1 618,707 3,846,496 376 14 375 2,564 54.4 1.00

HEAT2 618,843 3,846,351 376 15 375 3,210 10.9 2.50

HEAT3 618,854 3,846,357 376 26 700 6,656 22.6 2.50

HEAT4 618,937 3,846,294 374 24 700 8,836 30.0 2.50

HEAT5 619,106 3,846,287 373 26 700 6,656 22.6 2.50


HEAT6 619,108 3,846,303 373 24 700 8,836 30.0 2.50

HEAT7 619,333 3,846,292 373 26 700 6,656 22.6 2.50

HEAT8 619,332 3,846,307 373 24 700 8,836 30.0 2.50

FLARE1 618,803 3,846,437 378 115 1800 5,469 65.6 1.33

FLARE2 619,483 3,846,212 376 115 1800 5,469 65.6 1.33

COMB1 618,862 3,846,486 379 19 1832 5,117 65.6 1.29

Model Selection

The most recent version of the EPA’s American Meteorological Society/Environmental

Protection Agency Regulatory Model (AERMOD), (version 16216r) was used. The AERMOD

software was purchased from ORIS. The ORIS version of the AERMOD algorithm that will be

used is known as “BEEST for Windows, Version 11.08” and has been approved by the ODEQ

for regulatory modeling applications.

The AERMOD model, a steady-state plume dispersion model used for assessment of pollutant

concentrations from a variety of sources, has become the primary model used for conducting

refined modeling analyses. AERMOD incorporates air dispersion based on planetary boundary

layer turbulence structure and scaling concepts, including treatment of both surface and elevated

sources, and both simple and complex terrain.

Terrain

Based on ODEQ guidance, modeling with elevated terrain was used for this analysis. AERMAP,

a terrain preprocessor that incorporates complex terrain using USGS Digital Elevation Data was

used to determine stack, building, and receptor elevations/hill heights. The latest versions of the

National Elevation Dataset (NED) for the quadrangles surrounding the Facility were downloaded

from the Seamless Service. The elevations imported into the model are the highest elevation

based on the USGS 1/3 arc-second (approximately 10 meters) resolution for the area surrounding

the facility. The elevations of the sources and structures are approximately 375 meters (1,230

feet) above mean sea level (msl) based upon the NED data. The elevations for the receptors

ranged from approximately 293 meters (961 feet) to 400 meters (1,312 feet) above msl.

Stack GEP Analysis

The emissions from the sources within the Facility have the potential to be affected by building

downwash. All emission point sources that are less than GEP stack height, and are within 5L of

a building or nearby structure, where "L" is the lesser of the nearby building's height or its

maximum projected width, will be affected by downwash from nearby structures or buildings.

However, the buildings at the Facility are greater than 5L and therefore, building downwash

affects will not be accounted for in the modeling analysis.


Arm Modeling Options

AERMOD contains several default and non-default regulatory options for Tier 1, Tier 2, and Tier

3 modeling methodologies. One of these options is Ambient Ratio Method (ARM) which

accounts for 75% conversion of NOX to NO2. Due to the unique challenges presented by new 1-

hr NO2 standard, Woodford utilized the Tier 2 ARM to demonstrate compliance with the 1-hr

NO2 standard.

Meteorological Data

The ODEQ provided actual surface meteorological data from the Ketchum Ranch Station

collected by the Oklahoma Mesonet Network for the years 2011 through 2015 for this proposed

analysis. The data set combines surface meteorological data (e.g., wind speed and direction,

temperature) from the Ketchum Ranch Station. The air surface characteristics are included in the

surface data. Upper air data for the same time period was from the Norman, Oklahoma station.

Data were processed using the AERMET module of the AERMOD modeling system by ODEQ.

Air Quality Monitoring Data

Per the Tyler Fox memorandum dated June 2011, “The monitored NO2 design value, i.e., the

98th-percentile of the annual distribution of daily maximum 1-hour values averaged across the

most recent three years of monitored data, should be used irrespective of the meteorological

data period used in the dispersion modeling.” The Facility is located in Grady County and there

are no NO2 monitors located in Grady County. Therefore, Woodford proposed a regional

monitor be used as a representative background concentration. Per ODEQ guidance, Woodford

is utilizing the rural Sequoyah, OK monitor (ID# 40-135-9021) for NO2 background data. The

annual background value of 9.51 g/m3 was based on the annual mean from 2016. The hourly

background monitoring data was incorporated in the model run. The hourly background NO2

monitoring data file contains monitored concentrations for each hour during the years modeled.

The hourly background NO2 monitoring data was provided by ODEQ.

There are no CO monitors located in Grady County, therefore, Woodford proposed a regional

monitor be used as a representative background concentration. Woodford is utilizing the

Oklahoma City, OK monitor (ID# 40-109-1037) for CO background data. The hourly

background value of 1,488.50 g/m3 was based on the second highest high from 2016. The 8-

hour background value of 1,030.50 g/m3 was based on the second highest high from 2016.

There are no SO2 monitors located in Grady County, therefore, Woodford proposed a regional

monitor be used as a representative background concentration. Woodford is utilizing the

Oklahoma City, OK monitor (ID# 40-109-1037) for SO2 background data. The hourly

background value of 7.86 g/m3 was based on a three year average of the fourth highest high

(99th percentile) for 2014, 2015, and 2016. The 3-hour background value is based on the second

highest high for the most recent year, however, the 3-hour SO2 background value is no longer

available in monitoring data. Therefore, Woodford did not add a background concentration for

3-hour SO2.

Selection of Dispersion Coefficient Option

The AERMOD model is executed using dispersion coefficients that are based upon the

predominant land use. An Auer Land Use Analysis, which classifies all regions within three

kilometers of the Facility using published rural and urban land use classifications, is used to


quantify the percentages of the region having urban and rural land usage and thereby determine

whether the rural or urban dispersion coefficient mode is appropriate for the modeling analysis.

Based upon the land classification within three kilometers, rural land use classification is

appropriate for the modeling analysis.

Receptor Grid

Fenceline Receptor Grid - The AERMOD model will incorporate discrete receptors spaced no

more than 100 meters apart around the fenceline of the Facility.

Discrete Receptor Grids - Five different rectangular grids made up of nested discrete receptors

will be used in the AERMOD modeling analysis. ODEQ has developed a generalized acceptable

grid spacing of 100 m out to 1 km, 250 m out to 2.5 km, 500 m out to 5 km, 750 m out to 7.5 km,

and 1 km out to 10 km from the Facility fenceline.

Modeling Results

The following sections detail the results of the air quality analyses.

Significance Analysis

The modeled results were compared to the modeling significance level (MSL) for NO2, CO, and

SO2 and OAC 252:100-31-7(b) for H2S. Since each proposed source was modeled based on

potential emission rates, this represents the most conservative method for determining ambient

impacts from the Facility for comparison with the MSL. The results of the Significance Analysis

are summarized in the following table.

Significance Analysis Results UTM Location Concentration (µg/m3)

Pollutant Averaging

Period Year

Easting

(m)

Northing

(m)

Modeled

Concentration MSL

Below

MSL? NO2 1-hour 2011 618,600 3,846,600 222.55 7.5 NO

2012 618,700 3,846,900 359.37 7.5 NO

2013 618,600 3,846,500 217.95 7.5 NO

2014 618,900 3,846,600 225.99 7.5 NO

2015 620,200 3,846,000 328.60 7.5 NO

NO2 Annual1 2011 618,800 3,846,800 17.43 1 NO

2012 618,800 3,846,800 17.05 1 NO

2013 618,800 3,846,800 15.55 1 NO

2014 618,800 3,846,800 16.13 1 NO

2015 618,800 3,846,800 15.48 1 NO

CO 1-hour2 2011 618,900 3,846,600 1,510.49 2,000 YES

2012 618,700 3,846,900 2,280.49 2,000 NO

2013 618,600 3,846,400 1,484.89 2,000 YES

2014 618,900 3,846,600 1,589.75 2,000 YES

2015 620,400 3,845,900 1,929.10 2,000 YES


UTM Location Concentration (µg/m3)

Pollutant Averaging

Period Year

Easting

(m)

Northing

(m)

Modeled

Concentration MSL

Below

MSL?

CO 8-hour2 2011 618,670 3,846,131 934.00 500 NO

2012 618,670 3,846,226 888.08 500 NO

2013 619,000 3,846,600 912.96 500 NO

2014 618,800 3,846,700 911.74 500 NO

2015 618,670 3,846,131 926.07 500 NO

SO2 1-hour2 2011 619,667 3,846,336 45.72 7.9 NO

2012 618,700 3,847,000 71.95 7.9 NO

2013 618,600 3,846,500 45.56 7.9 NO

2014 618,600 3,846,500 46.01 7.9 NO

2015 619,900 3,846,100 82.08 7.9 NO

SO2 3-hour2 2011 618,600 3,846,600 34.28 25 NO

2012 618,500 3,846,500 36.67 25 NO

2013 618,600 3,846,500 37.10 25 NO

2014 618,669 3,846,510 39.22 25 NO

2015 618,500 3,846,500 36.30 25 NO

SO2 24-hour2 2011 618,700 3,846,000 16.31 5 NO

2012 618,500 3,846,600 20.87 5 NO

2013 618,200 3,846,600 18.38 5 NO

2014 618,800 3,846,000 18.48 5 NO

2015 618,500 3,846,600 16.39 5 NO

SO2 Annual1 2011 618,800 3,846,800 4.21 1 NO

2012 618,800 3,846,800 4.18 1 NO

2013 618,800 3,846,800 3.94 1 NO

2014 618,800 3,846,800 4.01 1 NO

2015 618,800 3,846,800 3.82 1 NO

H2S 24-hour2 2011 618,600 3,846,400 0.77 278.6 YES

2012 618,600 3,846,500 0.73 278.6 YES

2013 618,600 3,846,300 0.79 278.6 YES

2014 618,600 3,846,200 0.92 278.6 YES

2015 618,679 3,846,522 0.64 278.6 YES

1 – For the annual averaging periods, the results are conservatively based on the maximum modeled concentration

over five years of meteorological data.

2 – For the short-term averaging period, the maximum modeled concentration was used for the modeling

significance analysis.


Since the maximum CO, NO2, and SO2 concentrations are greater than the corresponding MSLs,

a Full Impact Analysis is required for these pollutants and averaging periods.

Air Quality Pre-Construction Monitoring

The U.S. EPA’s monitoring de minimis concentrations establish the levels at which a facility

may need to conduct pre-construction ambient air quality monitoring to demonstrate compliance

with the NAAQS and PSD Increment. If modeling analyses show that maximum concentrations

from a project do not exceed the monitoring de minimis concentrations, the permitting authority

has discretionary authority to exempt Woodford from the pre-construction monitoring

requirement.

The maximum modeled impact from the Facility results in ambient concentrations greater than

the monitoring de minimis levels for all standards. Based on the Ambient Monitoring Guidelines

for PSD (EPA-450/4-87-007, May 1987), if the proposed source will be constructed in an area

that is generally free from the impact of other point sources and area sources associated with

human activities, monitoring data from a “regional” site may be used as representative data.

Such a site could be out of the maximum impact area, but must be similar in nature to the impact

area. This site would be characteristic of air quality across a broad region including that in

which the proposed source or modification is located.

The Woodford Facility is located in a relatively remote area that is generally free from the

impact of other point sources and area sources associated with human activities. The

background concentrations used to determine compliance with the NO2 NAAQS were taken

from a monitor located in Sequoyah, OK, monitor ID# 40-135-9021, which is an area

representative of the areas surrounding the Woodford Facility. The background concentrations

used to determine compliance with the CO and SO2 NAAQS were taken from a monitor located

in Oklahoma City, OK, monitor ID# 40-109-1037. These monitors were considered a

conservative representative monitor to determine background concentrations for the Facility.

Full Impact Analysis

The Significance Analysis shows that the MSL is exceeded for NO2, CO, and SO2. Therefore, a

Full Impact Analysis, consisting of both a NAAQS analysis and a PSD Increment analysis was

performed for these pollutants and averaging periods. Per ODEQ guidance, increment standards

have not been set for the NO2 or SO2 1-hour standards and the CO standards. Therefore, these

were only modeled for NAAQS compliance.

NAAQS Analysis

The results of the NAAQS analysis are summarized below. NO2, CO, and SO2 emissions due to

the facility will not cause or contribute to a violation of the NAAQS.


Summary of AERMOD Results

Pollutant Ave

Period Year


Easting

(m)

Northing

(m)

Modeled

Conc

Background

Conc1 Total NAAQS

NO2 1-hour 2 2011-2015

618,500 3,846,600 159.17 --- 159.2 188

NO2 Annual 3 2011 618,800 3,846,800 17.43 9.51 26.9 100

2012 618,800 3,846,800 17.05 9.51 26.6 100

2013 618,800 3,846,800 15.55 9.51 25.1 100

2014 618,800 3,846,800 16.13 9.51 25.6 100

2015 618,800 3,846,800 15.48 9.51 25.0 100

CO 1-hour 4 2011 618,900 3,846,600 1,454.07 1,488.50 2,942.6 40,000

2012 618,600 3,846,500 1,464.22 1,488.50 2,952.7 40,000

2013 618,900 3,846,600 1,452.08 1,488.50 2,940.6 40,000

2014 618,900 3,846,600 1,506.30 1,488.50 2,994.8 40,000

2015 618,670 3,846,321 1,443.59 1,488.50 2,932.1 40,000

CO 8-hour 4 2011 618,670 3,846,131 863.91 1,031.50 1,895.4 10,000

2012 618,700 3,846,100 824.36 1,031.50 1,855.9 10,000

2013 618,670 3,846,131 859.02 1,031.50 1,890.5 10,000

2014 618,800 3,846,700 829.00 1,031.50 1,860.5 10,000

2015 619,000 3,846,700 864.49 1,031.50 1,896.0 10,000

SO2 1-hour 5 2011-2015

618,600 3,846,500 42.24 7.86 50.1 196

SO2 3-hour 6 2011 618,600 3,846,600 33.60 --- 33.6 1,300

2012 618,600 3,846,500 32.67 --- 32.7 1,300

2013 618,600 3,846,500 34.30 --- 34.3 1,300

2014 618,669 3,846,510 33.14 --- 33.1 1,300

2015 618,500 3,846,500 35.72 --- 35.7 1,300

1 – Background concentrations for NO2 were obtained from the Sequoyah monitor (monitor ID 40-135-9021).

Background concentrations for CO and SO2 were obtained from the Oklahoma City monitor (monitor ID 40-

109-1037). Hourly background monitor data for 1-hour NO2 was included in the model run. 3-hour SO2

background monitor data is no longer available.

2 – The 1-hour standard is based on the 8th highest high over 5 years.

3 – The annual standard is the average over 5 years.

4 – The 1-hour and 8-hour standard is based on the highest second high modeled results for each year.

5 – The 1-hour standard is based on the 4th highest high over 5 years.

6 – The 3-hr standard is based on the highest second high modeled result for each year.


PSD Increment Analysis

The results of the PSD Increment Analysis are summarized in following table.

PSD Increment Analysis Results


Pollutant Averaging

Period

Year Easting

(m)

Northing

(m)

Modeled

Concentration

PSD

Increment

NO2 Annual 1 2011 618,800 3,846,800 17.43 25

2012 618,800 3,846,800 17.05 25

2013 618,800 3,846,800 15.55 25

2014 618,800 3,846,800 16.13 25

2015 618,800 3,846,800 15.48 25

SO2 3-hour 2 2011 618,600 3,846,600 33.60 512

2012 618,600 3,846,500 32.67 512

2013 618,600 3,846,500 34.30 512

2014 618,669 3,846,510 33.14 512

2015 618,500 3,846,500 35.72 512

SO2 24-hour 2 2011 618,600 3,846,600 15.60 91

2012 618,600 3,846,700 15.68 91

2013 618,500 3,846,600 17.23 91

2014 618,700 3,846,800 15.00 91

2015 618,700 3,846,800 14.47 91

SO2 Annual 1 2011 618,800 3,846,800 4.21 20

2012 618,800 3,846,800 4.18 20

2013 618,800 3,846,800 3.94 20

2014 618,800 3,846,800 4.01 20

2015 618,800 3,846,800 3.82 20

1 – For the annual averaging period, the results are conservatively based on the maximum modeled concentration

over five (5) years of meteorological data.

2 – For the 3-hour averaging period, the maximum modeled concentration is based on the highest second high

modeled result for each year.

Based on the modeling analysis results, it is anticipated that the proposed sources of air

emissions at the Facility will not cause or contribute to a violation of the NAAQS or PSD

Increment.

SECTION VIII. OKLAHOMA AIR POLLUTION CONTROL RULES

OAC 252:100-1 (General Provisions) [Applicable]

Subchapter 1 includes definitions but there are no regulatory requirements.

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 maintain 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 Emission Reporting Requirements) [Applicable]

Except as provided in OAC 252:100-9-7(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 mitigation, as

described in OAC 252:100-9-8, shall be included in the excess emission event report.

Additional reporting may be required in the case of ongoing emission events and in the case of

excess emissions reporting required by 40 CFR Parts 60, 61, or 63.

OAC 252:100-13 (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 (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 heaters, thermal oxidizers, and engines are subject to the

requirements of this subchapter. The facility’s flares 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 1.4-2 lists total PM emissions as 0.0076

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 0.01 lb/MMBTU. AP-42 (10/96)

Section 3.3 lists PM10 emissions for diesel-fired engines less than 600-hp as 0.31 lb/MMBTU.

The 1,341-hp Caterpillar C32 ATAAC generator engine has a heat input of 9.26 MMBTUH.

OAC 252:100 Appendix C provides a calculation to determine the Subchapter 19 limit. The

Appendix C limit is 0.59 lb/MMBTU. AP-42 (10/96) Section 3.4 lists PM10 emissions for

diesel-fired engines greater than 600-hp as 0.1 lb/MMBTU. This permit requires the use of

natural gas or diesel fuel for all fuel-burning units to ensure compliance with Subchapter 19.

OAC 252:100-25 (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 or diesel fuel. This permit requires the use of natural gas or low-sulfur

diesel fuel for all fuel-burning units to ensure compliance with Subchapter 25.

OAC 252:100-29 (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.

OAC 252:100-31 (Sulfur Compounds) [Applicable]

Part 2 limits emissions of sulfur dioxide from any one existing source or any one new

petroleum and natural gas process source. OAC 252:100-31-7(b) limits H2S emissions to less

than 0.2ppm at standard conditions, 24-hour average. Modeling has demonstrated the ability to

comply with this limit.

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 to ensure compliance with Subchapter 31.

Subchapter 31 limits SO2 emissions from new liquid fueled equipment to 0.8 lb/MMBTU. This

is equivalent to a sulfur content of 0.79% by weight. Subpart IIII currently limits sulfur to 500-


ppm (0.05% by weight) and, after October 1, 2010, limits sulfur to 15-ppm. Using No. 2 diesel

with 0.05% sulfur will result in SO2 emissions of 0.05 lb/MMBTU, which is in compliance

with Subchapter 31.

Part 5 limits H2S emissions from new petroleum and natural gas process equipment

(constructed or modified after December 31, 1974) to 0.3 lb/hr, two-hour average. For

facilities with H2S emissions greater than 0.3 lb/hr, OAC 252:100-31-26 requires that the H2S

contained in the waste gas stream from any petroleum or natural gas process equipment shall be

reduced by 95% by removal or by being oxidized to SO2 prior to being emitted to the ambient

air. Woodford will maintain H2S emissions below 0.3 lb/hr based on a two-hour average with a

control device. The control device will be at least 98% effective at oxidizing H2S to SO2.

Part 5 requires that a sulfur recovery unit be used if emissions of SO2 would exceed 100 lb/hr,

two-hour average. This subchapter also states any gas sweetening unit or petroleum refinery

process equipment with an emission rate of 100 lb/hr or less of SOx expressed as SO2, two-hour

average, shall be considered to be below the 0.54 LT/D threshold, therefore the requirements of

OAC 252:100-31-26(2) are not applicable. Emissions of SO2 from the conversion of H2S to

SO2 are 1.02 lb/hr, which is less than the 100 lb/hr threshold. Therefore, a sulfur recovery unit

prior to flaring is not required.

OAC 252:100-33 (Nitrogen Oxides) [Applicable]

This subchapter limits NOX emissions from new fuel-burning equipment with rated heat input

greater than or equal to 50 MMBTUH. None of the engines exceed the 50 MMBTUH

threshold.

OAC 252:100-35 (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 252:100-37 (Volatile Organic Compounds) [Applicable]

Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of greater than

40,000 gallons and storing a VOC shall be a pressure vessel capable of maintaining working

pressures that prevent the loss of VOC to the atmosphere or shall be equipped with an external

floating roof, an organic vapor recovery system, or other equipment methods that are of equal

efficiency for purposes of air pollution control may be used with Division Director approval. The

condensate storage tanks are equipped with a fixed roof in combination with an internal floating

cover and are therefore not subject to OAC 252:100-37-15 requirements.

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.

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 252:100-42 (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 anywhere in the

state, 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 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. Engine testing is subject to

this requirement.

The following Oklahoma Air Quality Rules are not applicable to this facility:

OAC 252:100-7 Permits for Minor Facilities not in source category

OAC 252:100-11 Alternative Emissions Reduction not eligible

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 Grain, Feed, or Seed Facility not in source category

OAC 252:100-39 Non-attainment Areas not in a subject area

OAC 252:100-47 Municipal Solid Waste Landfills not type of source category

SECTION IX. FEDERAL REGULATIONS

PSD, 40 CFR Part 52 [Not Applicable]

Potential emissions for NOx, CO, and VOC are less than the level of significance of 250 TPY

for this source category.


NSPS, 40 CFR Part 60 [Subparts Dc, Kb, IIII, JJJJ, OOOO, and OOOOa are Applicable]

Subpart Dc, Industrial-Commercial-Institutional Steam Generating Units. This subpart affects

industrial-commercial-institutional steam generating units with a design capacity between 10

and 100 MMBTUH heat input and which commenced construction or modification after June

9, 1989. The hot oil heaters are rated greater than 10-MMBTUH and are subject to the

recordkeeping requirements of this subpart. The other heaters are considered process heaters

and are not subject to this subpart.

Subpart Kb, VOL Storage Vessels. This subpart regulates hydrocarbon storage tanks larger

than 19,813 gallons capacity and built after July 23, 1984. The 42,000-gallon condensate tanks

at the facility do not receive any liquids after custody transfer; however, if the facility begins

receiving condensate after custody transfer, each 42,000-gallon condensate storage tank is

equipped with a fixed roof in combination with an internal floating roof for control of

emissions. Therefore, the facility will be in compliance with Subpart Kb if applicable.

Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants

constructed, reconstructed, or modified after January 20, 1984. This subpart sets standards for

natural gas processing plants, which are defined as any site engaged in the extraction of natural

gas liquids from field gas, fractionation of natural gas liquids, or both. This Facility will utilize

cryogenic processes to extract natural gas liquids from the gas streams; however, the process

units at the Facility will be installed after August 23, 2011. Therefore, NSPS Subpart KKK

will not be applicable.

Subpart LLL, Onshore Natural Gas Processing: SO2 Emissions. This subpart affects

sweetening units and sweetening units followed by a sulfur recovery unit which commences

construction or modification after January 20, 1984. This subpart requires facilities with a

design capacity less than 2 LT/D of H2S in the acid gas (expressed as sulfur) to keep, for the

life of the facility, a record demonstrating that the facility’s design capacity is less than 2 LT/D

of H2S. If the gas treated by the amine unit contains less than 0.25 grains H2S per 100 SCF (4

ppmv H2S) then the amine unit is not subject to this subpart since it does not treat sour natural

gas. The facility shall keep records that demonstrate the facility is not subject to this subpart.

Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal

Combustion Engines. This subpart 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, 2005. For the purposes of this

subpart, the date that construction commences is the date the engine is ordered by the owner or

operator. Compliance with this subpart is required in this permit for engines GEN1, GEN2,

GEN3, and GEN4 (EUG-01B).

Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion

Engines (SI-ICE). This subpart was published in the Federal Register on January 18, 2008. It

promulgates emission standards for new SI engines ordered after June 12, 2006, that are

manufactured after certain dates, and for SI engines modified or reconstructed after June 12,

2006. 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 manufacture date. Engine manufacturers are required to certify certain

engines to meet the emission standards and may voluntarily certify other engines. An initial

notification is required only for owners and operators of engines greater than 500 HP that are

non-certified. Emergency engines will be required to be equipped with a non-resettable hour

meter and are limited to 100 hours per year of operation excluding use in an emergency (the

length of operation and the reason the engine was in operation must be recorded). It is assumed


engines E-01 through E-11 (EUG-01A) are subject to Subpart JJJJ. Subpart JJJJ applicability

will be determined in the operating permit.

Owners and operators of certified engines may demonstrate compliance by operating and

maintaining their stationary engine and after-treatment control device (if any) according to the

manufacturer’s emission-related written instructions and do not have to conduct any

performance testing. Owners and operators of all SI engines (certified and non-certified) must

keep records of maintenance conducted on the engine. If an owner or operator of a certified

engine does not follow the manufacturer’s emission-related operation and maintenance

instructions, that engine is considered a non-certified engine and is subject to performance

testing, unless the engine is less than 100 HP. Owners and operators of non-certified engines,

which include certified engines operating in a non-certified manner, must keep a maintenance

plan. An initial performance test must be conducted within the first year of operation for any

certified engine operating in a non-certified manner that is equal to or greater than 100 HP. In

addition, non-certified engines, including certified engines operating in a non-certified manner,

that are greater than 500 HP must conduct the initial performance test and 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. Engines E-01

through E-11 (EUG-01A) are subject to the following limitations under this subpart.

EUG

ID Description

NOx CO VOC

g/hp-hr ppm * g/hp-hr ppm * g/hp-hr ppm *

EUG-01A 1,380-hp Caterpillar

G3516 ULB w/OC 1.0 82 2.0 270 0.7 60

* corrected to 15% oxygen.

Subpart OOOO, Crude Oil and Natural Gas Production, Transmission, and Distribution for

which construction, modification, or reconstruction commenced after August 23, 2011, and on

or before September 18, 2015:

1. Each single gas well;

2. Single centrifugal compressors using wet seals that are located between the wellhead and

the point of custody transfer to the natural gas transmission and storage segment;

3. Reciprocating compressors which are single reciprocating compressors located between

the wellhead and the point of custody transfer to the natural gas transmission and

storage segment;

4. Single continuous bleed natural gas driven pneumatic controllers with a natural gas bleed

rate greater than 6 SCFH, which commenced construction after August 23, 2011,

located between the wellhead and the point of custody transfer to the natural gas

transmission and storage segment and not located at a natural gas processing plant;

5. Single continuous bleed natural gas driven pneumatic controllers which commenced

construction after August 23, 2011, and is located at a natural gas processing plant;

6. Single storage vessels located in the oil and natural gas production segment, natural gas

processing segment, or natural gas transmission and storage segment;

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.

Evaluation of each of the eight (8) parameters:

1. This facility is not a gas well. Therefore, facility is not in source category.

2. This facility does not have centrifugal compressors. Therefore, facility is not in source

category.

3. 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. A gas plant is the point of custody transfer and there are no requirements

of the compressors under this subpart.

4. The facility is a gas plant. Therefore, the facility shall comply with this subpart for single

continuous bleed natural gas driven pneumatic controllers with a bleed rate of greater

than 6 SCFH.

5. The facility is a gas plant. Therefore, the facility shall comply with this subpart for single

continuous bleed natural gas driven pneumatic controllers.

6. 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. Storage vessels subject to Subpart Kb are exempt from this subpart. The

facility will comply with Subpart OOOO requirements for any affected storage vessel.

7. 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 §60.5401. This facility is a gas plant subject to this requirement.

8. A sweetening unit means a process device that removes hydrogen sulfide and/or carbon

dioxide from the sour natural gas stream. The amine unit functions to remove CO2.

The facility handles only sweet (<4ppm sulfur) gas. Therefore, the facility is not

subject to Subpart OOOO for sweetening units. The facility shall maintain records that

demonstrate the facility does not operate sweeting units.

The permit will require the facility to comply with all applicable requirements of NSPS,

Subpart OOOO.

Subpart OOOOa, Crude Oil and Natural Gas Facilities for which construction, modification, or

reconstruction commenced after September 18, 2015. This subpart affects the following

onshore affected facilities:

1. Each well affected facility, which is a single well that conducts a well completion

operation following hydraulic fracturing or refracturing.

2. Each centrifugal compressor affected facility, which is a single centrifugal compressor

using wet seals. A centrifugal compressor located at a well site, or an adjacent well site

and servicing more than one well site, is not an affected facility under this subpart.

3. Each reciprocating compressor affected facility, which is a single reciprocating

compressor. A reciprocating compressor located at a well site, or an adjacent well site

and servicing more than one well site, is not an affected facility under this subpart.

4. Each pneumatic controller affected facility:

a. Each pneumatic controller affected facility not located at a natural gas processing


plant, which is a single continuous bleed natural gas-driven pneumatic controller

operating at a natural gas bleed rate greater than 6 SCFH.

b. Each pneumatic controller affected facility located at a natural gas processing plant,

which is a single continuous bleed natural gas-driven pneumatic controller.

5. Each storage vessel affected facility, which is a single storage vessel with the potential

for VOC emissions equal to or greater than 6 TPY as determined according to

§60.5365a(e).

6. The group of all equipment within a process unit located at an onshore natural gas

processing plant is an affected facility. Equipment within a process unit of an affected

facility located at onshore natural gas processing plants are exempt from this subpart if

they are subject to and controlled according to Subparts VVa, GGG, or GGGa.

7. Sweetening units located at onshore natural gas processing plants that process natural gas

produced from either onshore or offshore wells.

8. Each pneumatic pump affected facility:

a. For natural gas processing plants, each pneumatic pump affected facility, which is a

single natural gas-driven diaphragm pump.

b. For well sites, each pneumatic pump affected facility, which is a single natural gas-

driven diaphragm pump.

9. The collection of fugitive emissions components at a well site, as defined in §60.5430a, is

an affected facility, except as provided in § 60.5365a(i)(2).

10. The collection of fugitive emissions components at a compressor station, as defined in §

60.5430a, is an affected facility.

Evaluation of each of the ten (10) parameters:

1. This facility is not a gas well. Therefore, facility is not in source category.

2. This facility does not have centrifugal compressors. Therefore, facility is not in source

category.

3. The reciprocating compressors at the facility were installed prior to September 18,

2015, therefore, they are not subject to the requirements of this subpart.

4. The facility is a natural gas processing plant; therefore, the single continuous bleed

natural gas-driven pneumatic controllers installed after September 18, 2015, will be

subject to this subpart.

5. The storage tanks were installed prior to September 18, 2015, therefore, they are not

subject to the requirements of this subpart.

6. The facility is a natural gas processing plant; therefore, the equipment installed after

September 18, 2015, will be subject to this subpart.

7. The amine unit A-03 will be constructed after September 18, 2015, and the facility has a

design capacity less than 2 long tons per day (LT/D) of H2S in acid gas; therefore, A-03

will only be subject to the recordkeeping and reporting requirements of this subpart.

8. There are no pneumatic pumps at this facility.

9. This facility is not a well site. Therefore, facility is not in source category.

10. This facility is not a compressor station. Therefore, facility is not in source category.


NESHAP, 40 CFR Part 61 [Not Applicable]

There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium,

benzene, coke oven emissions, mercury, radionuclides, or vinyl chloride except for trace

amounts of benzene. Subpart J (Equipment Leaks of Benzene) concerns only process streams,

which contain more than 10% benzene by weight. All process streams at this facility are below

this threshold.

NESHAP, 40 CFR Part 63 [Subpart ZZZZ is Applicable]

Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected

emission points that are located at facilities which are major sources of HAP, or TEG

dehydration units only located at an area source, 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. Subpart HH affects glycol dehydration

unit process vents, storage vessels with potential for flash emissions, and compressors and

ancillary equipment (valves, flanges, etc.) in VHAP service (i.e., more than 10% by weight

HAP) that are located at gas processing plants. The facility will not include any TEG

dehydration units; therefore subpart HH area source requirements will not be applicable.

Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects any

existing, new, or reconstructed stationary RICE located at a major or area source of HAP

emissions. Owners and operators of the following new or reconstructed RICE 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):

1) Stationary RICE located at an area source;

2) The following Stationary RICE located at a major source of HAP emissions:

i) 2SLB and 4SRB stationary RICE with a site rating of ≤ 500 brake HP;

ii) 4SLB stationary RICE with a site rating of < 250 brake HP;

iii) Stationary RICE with a site rating of ≤ 500 brake HP which combust landfill or digester

gas equivalent to 10% or more of the gross heat input on an annual basis;

iv) Emergency or limited use stationary RICE with a site rating of ≤ 500 brake HP; and

v) CI stationary RICE with a site rating of ≤ 500 brake HP.

No further requirements apply for engines subject to NSPS under this part. A stationary RICE

located at an area source of HAP emissions is new if construction commenced on or after June

12, 2006. The new engines are subject to this subpart and will comply with this subpart by

complying with NSPS Subpart IIII or NSPS Subpart JJJJ. All applicable requirements have

been incorporated into the permit.

Subpart JJJJJJ, Industrial, Commercial, and Institutional Boilers Area Sources. This subpart

affects new and existing boilers located at area sources of HAP, except for gas-fired boilers.

Boiler means an enclosed device using controlled flame combustion in which water is heated to

recover thermal energy in the form of steam or hot water. Gas fired boilers are defined as any

boiler that burns gaseous fuel not combined with any solid fuels, liquid fuel only during periods

of gas curtailment, gas supply emergencies, or periodic testing on liquid fuel. All fuel-burning

heaters at this facility are natural gas-fired. Therefore, the facility is not subject to this subpart.

CAM, 40 CFR Part 64 [Not Applicable]

Compliance Assurance Monitoring (CAM) 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:


1. It is subject to an emission limit or standard for an applicable regulated air pollutant.

2. It uses a control device to achieve compliance with the applicable emission limit or

standard.

3. It has potential emissions, prior to the control device, of the applicable regulated air

pollutant of 100 TPY for a criteria pollutant, 10 TPY for an individual HAP, or 25

TPY for all HAP.

The engines at the facility are subject to NSPS Subpart IIII or NSPS JJJJ limitations. Under 40

CFR Part 60.64.2(b)(i), CAM does not affect emissions limits or standards proposed by the

Administrator after November 15, 1990, pursuant to Section 111 or 112 of the Act. There are

no other emission units at the facility potentially subject to this subpart.

Chemical Accident Prevention Provisions, 40 CFR Part 68 [Applicable]

This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant

and is subject to this Subpart (Section 112r of the Clean Air Act 1990 Amendments). A Risk

Management Plan was submitted to EPA Region 6 on June 14, 1999 and deemed complete on

June 16, 1999. An update to the RMP was received on September 23, 1999 and judged

complete on September 28, 1999. An update to the RMP was submitted on September 16,

2004. EPA Notice of Confirmation was dated September 24, 2004. More information on this

federal program is available on the web page: www.epa.gov/rmp

Stratospheric Ozone Protection, 40 CFR Part 82 [Subparts A and F are Applicable]

These standards require phase out of Class I & II substances, reductions of emissions of Class I

& II substances to the lowest achievable level in all use sectors, and banning use of

nonessential products containing ozone-depleting substances (Subparts A & C); control

servicing of motor vehicle air conditioners (Subpart B); require Federal agencies to adopt

procurement regulations which meet phase out requirements and which maximize the

substitution of safe alternatives to Class I and Class II substances (Subpart D); require warning

labels on products made with or containing Class I or II substances (Subpart E); maximize the

use of recycling and recovery upon disposal (Subpart F); require producers to identify

substitutes for ozone-depleting compounds under the Significant New Alternatives Program

(Subpart G); and reduce the emissions of halons (Subpart H).

Subpart A identifies ozone-depleting substances and divides them into two classes. Class I

controlled substances are divided into seven groups; the chemicals typically used by the

manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform

(Class I, Group V). A complete phase-out of production of Class I substances is required by

January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are

hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs.

Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances,

scheduled in phases starting by 2002, is required by January 1, 2030.

This facility does not produce, consume, recycle, import, or export any controlled substances or

controlled products as defined in this part, nor does this facility perform service on motor

(fleet) vehicles that involves ozone-depleting substances. Therefore, as currently operated, this


facility is not subject to these requirements. To the extent that the facility has air-conditioning

units that apply, the permit requires compliance with Part 82.

Subpart F requires that any persons servicing, maintaining, or repairing appliances except for

motor vehicle air conditioners; persons disposing of appliances, including motor vehicle air

conditioners; refrigerant reclaimers, appliance owners, and manufacturers of appliances and

recycling and recovery equipment comply with the standards for recycling and emissions

reduction.

The Standard Conditions of the permit address the requirements specified at §82.156 for persons

opening appliances for maintenance, service, repair, or disposal; §82.158 for equipment used

during the maintenance, service, repair, or disposal of appliances; §82.161 for certification by an

approved technician certification program of persons performing maintenance, service, repair, or

disposal of appliances; §82.166 for recordkeeping; § 82.158 for leak repair requirements; and

§82.166 for refrigerant purchase records for appliances normally containing 50 or more pounds

of refrigerant.

SECTION X. COMPLIANCE

Tier Classification This application has been determined to be a Tier II based on the request for a construction permit

for a Title V facility.

The permittee has submitted an affidavit that they are not seeking a permit for land use or for any

operation upon land owned by others without their knowledge. The affidavit certifies that the

applicant owns the land.

Public Review

The applicant published the DEQ “Notice of Tier II Permit Application Filing” in the Express

Star, a newspaper in circulation in Grady County, on August 31, 2017. The notice stated that the

application was available for public review at the facility and at the AQD main office. The

applicant will publish a “Notice of Draft Permit,” stating that the draft permit will be available

for public review for a period of thirty days at the Lindsay Community Library in Lindsay,

Oklahoma, at the AQD main office, and on the Air Quality section of the DEQ web page at

http://www.deq.state.ok.us. This facility is not located within 50 miles of the border of

Oklahoma and any other state.

EPA Review

Concurrent to the public comment period, the permit will also be submitted for review by EPA

Region 6.

Fees Paid

Application fee of $7,500 for a Part 70 source construction permit has been paid.

http://www.deq.state.ok.us/


SECTION XI. SUMMARY

The facility has demonstrated the ability to comply with the requirements of the several air

pollution control rules and regulations. Ambient air quality standards are not threatened at this

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

Woodford Express, LLC Permit Number 2015-0197-C (M-1)

Grady Gas Plant

The permittee is authorized to construct in conformity with the specifications submitted to Air

Quality on June 16, 2017. The Evaluation Memorandum dated February 26, 2018, explains the

derivation of applicable permit requirements and estimates of emissions; however, it does not

contain operating limitations or permit requirements. Commencing construction under this

permit constitutes acceptance of, and consent to, the conditions contained herein:

1. Points of emissions and emissions limitations for each point: [OAC 252:100-8-6(a)(1)]

A. Emissions from EUG-01 are limited as follows. Limits shown are per engine.

EUG-01A: Stationary Compressor Engines



E-01 through E-ll 1,380-hp Caterpillar G3516

ULB w/ oxidation catalyst 1.52 6.66 1.36 5.97 0.66 2.91

BACT Limits

Name/Model

NOX

(g/hp-hr)

CO

(g/hp-hr)

VOC

(g/hp-hr)

E-01 through E-ll ,1,380-hp Caterpillar G3516 ULB w/

oxidation catalyst 0.50 0.45 0.22

i. Engines E-01 through E-11 are authorized to operate continuously (8,760 hours per

year).

ii. The engines shall only be fired with natural gas having a maximum sulfur content of

0.25 grains or less of total sulfur (as hydrogen sulfide) per 100 standard cubic feet (< 4

ppmv). Compliance can be shown by the following methods: for gaseous fuel, a current

gas company bill, lab analysis, stain-tube analysis, gas contract, tariff sheet, or other

approved methods. Compliance shall be demonstrated at least once every calendar year.

[OAC 252:100-31]

iii. Each lean-burn engine shall be equipped with properly functioning oxidation catalyst.

[OAC 252:100-8-5(d)(1)(A)]

iv. Compliance with the requirement that individual HAP emissions shall not equal or

exceed 10 TPY, subjecting the facility to the major source requirements of NESHAP (40

CFR 63) Subpart ZZZZ, requires demonstration. Within 180 days of operational start-up

of the new engines, the permittee shall conduct testing of emissions of formaldehyde

from at least one engine of each model on location and furnish a written report to AQD

DRAFT/PROPOSED

SPECIFIC CONDITIONS 2015-0197-C (M-1) DRAFT/PROPOSED 2

documenting that formaldehyde emissions are below major source thresholds. Testing

shall be conducted while the engines are operating within 10% of the maximum site

rated horsepower. The following US EPA methods shall be used for testing of the

formaldehyde emissions unless an alternative is approved by Air Quality: Method 320 or

Method 323 for formaldehyde concentrations, Method 3A for the oxygen concentrations,

and Method 19 or Methods 1 – 4 for the mass emission rates. In addition to reporting

measured concentrations and mass emission rates for formaldehyde, the permittee shall

report an emissions factor for formaldehyde in units of g/hp-hr. At least 30 days

advanced notice of testing with a testing protocol shall be provided to AQD to allow the

opportunity to have an observer present. The DEQ shall be provided with a protocol

describing the test procedures at least 30 days before each test or group of tests.

[OAC 252:100-43]

v. Engines E-01 through E-11 are subject to 40 CFR Part 63 Subpart ZZZZ. Per 40 CFR

63.6590(c), the permittee must meet the requirements of this part by meeting the

requirements of 40 CFR Part 60 Subpart JJJJ, and no further requirements apply to the

engines under this part. [40 CFR §63.6590(c)]

vi. The permittee shall comply with all applicable requirements in 40 CFR Part 60

Subpart JJJJ for all stationary spark ignition (SI) internal combustion engines (ICE)

subject to Subpart JJJJ including, but not limited to, the following.

[40 CFR §60.4230 to §60.4246]

What This Subpart Covers

§60.4230 Am I subject to this subpart?

Emission Standards for Manufacturers

§60.4231 What emission standards must I meet if I am a manufacturer of stationary SI

internal combustion engines or equipment containing such engines?

§60.4232 How long must my engines meet the emission standards if I am a

manufacturer of stationary SI internal combustion engines?

Emission Standards for Owners and Operators

§60.4233 What emission standards must I meet if I am an owner or operator of a

stationary SI internal combustion engine?

§60.4234 How long must I meet the emission standards if I am an owner or operator of

a stationary SI internal combustion engine?

Other Requirements for Owners and Operators

§60.4235 What fuel requirements must I meet if I am an owner or operator of a

stationary SI gasoline fired internal combustion engine subject to this subpart?

§60.4236 What is the deadline for importing or installing stationary SI ICE produced in

previous model years?

§60.4237 What are the monitoring requirements if I am an owner or operator of an

emergency stationary SI internal combustion engine?

Compliance Requirements for Manufacturers

§60.4238 What are my compliance requirements if I am a manufacturer of stationary SI

internal combustion engines ≤19 KW (25 HP) or a manufacturer of equipment

containing such engines?

http://www.ecfr.gov/cgi-bin/text-idx?node=sp40.7.60.jjjj#sg40.7.60.jjjj.sg104

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internal combustion engines >19 KW (25 HP) that use gasoline or a manufacturer of

equipment containing such engines?


internal combustion engines >19 KW (25 HP) that are rich burn engines that use LPG or

a manufacturer of equipment containing such engines?


internal combustion engines participating in the voluntary certification program or a

manufacturer of equipment containing such engines?

§60.4242 What other requirements must I meet if I am a manufacturer of stationary SI

internal combustion engines or equipment containing stationary SI internal combustion

engines or a manufacturer of equipment containing such engines?

Compliance Requirements for Owners and Operators

§60.4243 What are my compliance requirements if I am an owner or operator of a

stationary SI internal combustion engine?

Testing Requirements for Owners and Operators

§60.4244 What test methods and other procedures must I use if I am an owner or

operator of a stationary SI internal combustion engine?

Notification, Reports, and Records for Owners and Operators

§60.4245 What are my notification, reporting, and recordkeeping requirements if I am

an owner or operator of a stationary SI internal combustion engine?

General Provisions

§60.4246 What parts of the General Provisions apply to me?

Mobile Source Provisions

§60.4247 What parts of the mobile source provisions apply to me if I am a

manufacturer of stationary SI internal combustion engines or a manufacturer of

equipment containing such engines?

Definitions

§60.4248 What definitions apply to this subpart?

vii. The permittee shall comply with all applicable requirements in 40 CFR Part 63

Subpart ZZZZ for all stationary spark ignition (SI) internal combustion engines (ICE)

subject to Subpart ZZZZ including, but not limited to, the following.

[40 CFR §63.6580 to §63.6675]


§63.6580 What is the purpose of subpart ZZZZ?

§63.6585 Am I subject to this subpart?

§63.6590 What parts of my plant does this subpart cover?

§63.6595 When do I have to comply with this subpart?

Emission and Operating Limitations

§63.6600 What emission limitations and operating limitations must I meet if I own or

operate a stationary RICE with a site rating of more than 500 brake HP located at a

major source of HAP emissions?

§63.6601 What emission limitations must I meet if I own or operate a new or

reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250

brake HP and less than or equal to 500 brake HP located at a major source of HAP

emissions?































§63.6602 What emission limitations and other requirements must I meet if I own or

operate an existing stationary RICE with a site rating of equal to or less than 500 brake

HP located at a major source of HAP emissions?

§63.6603 What emission limitations, operating limitations, and other requirements must

I meet if I own or operate an existing stationary RICE located at an area source of HAP

emissions?

§63.6604 What fuel requirements must I meet if I own or operate a stationary CI RICE?

General Compliance Requirements

§63.6605 What are my general requirements for complying with this subpart?

Testing and Initial Compliance Requirements

§63.6610 By what date must I conduct the initial performance tests or other initial

compliance demonstrations if I own or operate a stationary RICE with a site rating of

more than 500 brake HP located at a major source of HAP emissions?


compliance demonstrations if I own or operate a new or reconstructed 4SLB SI

stationary RICE with a site rating of greater than or equal to 250 and less than or equal

to 500 brake HP located at a major source of HAP emissions?


compliance demonstrations if I own or operate an existing stationary RICE with a site

rating of less than or equal to 500 brake HP located at a major source of HAP emissions

or an existing stationary RICE located at an area source of HAP emissions?

§63.6615 When must I conduct subsequent performance tests?

§63.6620 What performance tests and other procedures must I use?

§63.6625 What are my monitoring, installation, collection, operation, and maintenance

requirements?

§63.6630 How do I demonstrate initial compliance with the emission limitations,

operating limitations, and other requirements?

Continuous Compliance Requirements

§63.6635 How do I monitor and collect data to demonstrate continuous compliance?

§63.6640 How do I demonstrate continuous compliance with the emission limitations,

operating limitations, and other requirements?

Notification, Reports, and Records

§63.6645 What notifications must I submit and when?

§63.6650 What reports must I submit and when?

§63.6655 What records must I keep?

§63.6660 In what form and how long must I keep my records?

Other Requirements and Information

§63.6665 What parts of the General Provisions apply to me?

§63.6670 Who implements and enforces this subpart?

§63.6675 What definitions apply to this subpart?


EUG-01B: Stationary Generator Engines(1)



GEN1 1,341-hp Caterpillar C32 ATAAC 14.57 3.64 0.38 0.10 0.03 0.01

GEN2 27.2-hp Generac 2.3L 0.29 0.07 0.08 0.02 <0.01 <0.01

GEN3 315-hp Caterpillar C7.1 DITA 1.93 0.48 0.68 0.17 -- --

GEN4 315-hp Caterpillar C7.1 DITA 1.93 0.48 0.68 0.17 -- -- (1) TPY limits are also BACT limits

viii.The engines GEN1, GEN2, GEN3, and GEN4 shall be fueled with No. 2 diesel with

a maximum sulfur content of 15ppm by weight. [40 CFR 60.4207 and 80.510(b)]

ix. The engines shall be operated no more than 500 hours per year, 12-month rolling

total.

x. Engines GEN1, GEN2, GEN3, and GEN4 are subject to 40 CFR Part 63 Subpart

ZZZZ. Per 40 CFR 63.6590(c), the permittee must meet the requirements of this part by

meeting the requirements of 40 CFR Part 60 Subpart IIII, and no further requirements

apply to the engines under this part. [40 CFR §63.6590(c)]

xi. The emergency generators are subject to 40 CFR Part 60, Subpart IIII, and shall

comply with all applicable requirements including, but not limited to, the following.

[40 CFR §60.4200 to §60.4219]


§60.4200: Am I subject to this subpart?

Emission Standards for Manufacturers

§60.4201 What emission standards must I meet for non-emergency engines if I

am a stationary CI internal combustion engine manufacturer?

§60.4202: What emissions standards must I meet for emergency engines if I am a

stationary CI internal combustion engine manufacture?

§60.4203 How long must my engines meet the emission standards if I am a

manufacturer of stationary CI internal combustion engines?

Emission Standards for Owners and Operators

§60.4204: What emissions standards must I meet for non-emergency engines if I

am an owner or operator of a stationary CI internal combustion engine?

§60.4205: What emissions standards must I meet for emergency engines if I am an

owner or operator of a stationary CI internal combustion engine?

§60.4206: How long must my engines meet the emissions standards if I am a

owner or operator of a stationary CI internal combustion engine?

Fuel Requirements for Owners and Operators

§60.4207: What fuel requirements must I meet if I am an owner or operator of a

stationary CI internal combustion engine subject to this subpart?

Other Requirements for Owners and Operators

§60.4208: What is the deadline for importing or installing stationary CI ICE

produced in the previous model year?

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§60.4209: What are the monitoring requirements if I am an owner or operator of a

stationary CI internal combustion engine?

Compliance Requirements

§60.4210 What are my compliance requirements if I am a stationary CI internal

combustion engine manufacturer?

§60.4211: What are my compliance requirements if I am an owner or operator of a

stationary CI internal combustion engine?

Testing Requirements for Owners and Operators

§60.4212: What test methods and other procedures must I use if I am an owner or

operator of a stationary CI internal combustion engine with a displacement of less

than 30 liters per cylinder?

§60.4213: What test methods and other procedures must I use if I am an owner or

operator of a stationary CI internal combustion engine with a displacement of

greater than or equal to 30 liters per cylinder?

Notification, Reports, and Records for Owners and Operators

§60.4214: What are my notification, reporting, and recordkeeping requirements if I

am an owner or operator of a stationary CI internal combustion engine?

Special Requirements

§60.4215 What requirements must I meet for engines used in Guam, American

Samoa, or the Commonwealth of the Northern Mariana Islands?

§60.4216 What requirements must I meet for engines used in Alaska?

§60.4217: What emission standards must I meet if I am an owner or operator of a

stationary internal combustion engine using special fuels?

General Provisions

§60.4218: What parts of the General Provisions apply to me?

§60.4219: What definitions apply to this subpart?

Requirements for all engines:

xi. Each engine at the facility shall have a permanent identification plate attached that is

accessible and legible, which shows the make, model number, and serial number.

[OAC 252:100-43]

xii. The permittee shall at all times properly operate and maintain all engines in a manner

that will minimize emissions of hydrocarbons or other organic materials.

[OAC 252:100-37-36]

xiii. The permittee shall keep operation and maintenance (O&M) records for each engine

that is not tested in a quarter. Such records shall at a minimum include the dates of

operation and maintenance and type of work performed. [OAC 252:100-8-6 (a)(3)(B)]

xiv. At least once per calendar quarter, the permittee shall conduct tests of NOX and CO

emissions in exhaust gases from each engine/turbine and from each replacement

engine/turbine when operating under representative conditions for that period. Testing is

required for each engine or any replacement engine/turbine that runs for more than 220

hours during that calendar quarter. A quarterly test may be conducted no sooner than 20

calendar days after the most recent test. Testing shall be conducted using a portable







analyzer in accordance with a protocol meeting the requirements of the latest 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. A semi-annual test may be conducted

no sooner than 60 calendar days, nor later than 180 calendar days after the most recent

test. Likewise, when the following two consecutive semi-annual tests show compliance,

the testing frequency may be reduced to annual testing. An annual test may be

conducted no sooner than 120 calendar days, nor later than 365 calendar days after the

most recent test. Upon any showing of non-compliance with emissions limitations or

testing that indicates that emissions are within 10% of the emission limitations, the

testing frequency shall revert to quarterly. Reduced testing frequency does not apply to

engines with catalytic converters. Any reduction in the testing frequency shall be noted

in the next required compliance certification.

[OAC 252:100-8-6 (a)(3)(A)]

xv. When periodic compliance testing shows exhaust emissions from the engines in

excess of the lb/hr limits in Specific Condition No. 1, the permittee shall comply with the

provisions of OAC 252:100-9. 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. [OAC 252:100-9]

xvi. Replacement (including temporary periods of 6 months or less for maintenance

purposes) of internal combustion engines/turbines with emissions limitations specified in

this permit with engines/turbines of lesser or equal emissions of each pollutant (in lb/hr

and TPY) are authorized under the following conditions.

[OAC 252:100-8-6 (a)(3)(A)]

a. The permittee shall notify AQD in writing not later than 7 days in advance of the

start-up of the replacement engine(s)/turbine(s). Said notice shall identify the

equipment removed and shall include the new engine/turbine make, model, and

horsepower; date of the change, and any change in emissions.

b. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be

conducted to confirm continued compliance with NOX 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, serial number, stack flow (ACFM), stack temperature (oF),

stack height (feet), stack diameter (inches), and pollutant emission rates (g/hp-hr,

lbs/hr, and TPY) at maximum rated horsepower for the altitude/location.

c. Replacement equipment and emissions are limited to equipment and emissions

which are not 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 a. of this

Specific Condition.


d. 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 IIII or JJJJ shall comply with all applicable requirements.

EUG-01C: Uncontrolled Compressor Blowdowns

EU Emission Unit Description VOC (TPY)

B1 Uncontrolled Compressor Blowdowns 4.54

BACT Limits

EU Emission Unit Description Volume (MMSCF/yr)

B1 Uncontrolled Compressor Blowdowns 2.26

xvii. The permittee shall calculate and record VOC emissions from uncontrolled

blowdown events. The records shall include discharge volumes and VOC content.

(monthly, 12-month rolling total). [OAC 252:100-37]

B. Emissions from EUG-02 are limited as follows.

EUG-02: Amine Units

EU Description VOC (TPY) H2S (lb/hr)

A-01 240-MMSCFD Amine Unit 3.11 0.16



i. The amine units are authorized to operate continuously (8,760 hours per year).

ii. The natural gas throughput of amine units A-01, A-02, and A-03 shall not exceed 240-

MMSCFD on a per unit basis, based on a monthly average (30-day rolling total). The

facility shall record natural gas throughputs for each amine unit (monthly, 12-month

rolling total). 12-month rolling totals are based on 365 days per year.

[OAC 252:100-8-6(a)(3)]

iii. The amine units shall only process natural gas with a maximum sulfur content of 0.25

grains or less of total sulfur (as hydrogen sulfide) per 100 standard cubic feet (< 4

ppmv). The H2S content shall be measured at least monthly and the measurement shall

be accurate to at least ±0.5 ppm H2S. [OAC 252:100-31]

iv. Each amine unit shall be equipped with a flash tank. The flash tank shall be vented to

the amine reboiler fuel system or an equivalent control device with 100% capture

efficiency. The amine unit flash tank controls shall have 98% or greater control

efficiency. [OAC 252:100-31-26]

v. Still vent emissions at the facility shall be captured with at least 97% efficiency and

routed to the thermal oxidizers or equivalent control devices with a destruction efficiency

of at least 98%.


C. Emissions from EUG-03 are limited as follows.

EUG-03: Thermal Oxidizers

EU Description NOx CO VOC SO2

TPY TPY TPY TPY

TO-01 20.6-MMBTUH Thermal Oxidizer 8.85 7.43 0.70 28.03



i. The thermal oxidizers are authorized to operate continuously (8,760 hours per year).

ii. The thermal oxidizers shall only be fired with natural gas having a maximum sulfur

content of 0.25 grains or less of total sulfur (as hydrogen sulfide) per 100 standard cubic

feet (< 4 ppmv). Compliance can be shown by the following methods: for pipeline grade

natural gas, a current gas company bill; for other gaseous fuel, a current lab analysis,

stain-tube analysis, gas contract, tariff sheet, or other approved methods. Compliance

shall be demonstrated at least once per calendar year. [OAC 252:100-31]

iii. The thermal oxidizers shall have alarm systems to signal non-combustion of the exhaust

gases. [OAC 252:100-31]

iv. Records shall be kept of thermal oxidizer downtime. Records shall identify the thermal

oxidizer which is out of service. Records shall include the dates and durations the

thermal oxidizer is out of service. Records shall include the volume of gas directed to an

equivalent control device corresponding to the dates and durations the thermal oxidizer is

out of service.

D. Emissions from EUG-04 are limited as follows.

EUG-04: Additional Heaters

EU Description NOx CO VOC

TPY TPY TPY

HEAT1 8.0- MMBTUH Stabilizer Reboiler 3.44 2.89 0.19

HEAT2 9.5-MMBTUH Dehy Regeneration Heater 4.08 3.43 0.22

HEAT3 30-MMBTUH Hot Oil Heater 12.88 10.82 0.71

HEAT4 40-MMBTUH Amine Regeneration Heater 17.18 14.43 0.94

HEAT5 53.1-MMBTUH Hot Oil Heater 22.80 19.15 1.25


HEAT7 53.1-MMBTUH Hot Oil Heater 22.80 19.15 1.25



BACT Limits

Name/Description

NOX

(lb/MMSCF)

CO (lb/MMSCF)

VOC (lb/MMSCF)

HEAT1 through HEAT8, Additional Heaters 100 84 5.5

i. Heaters HEAT1 through HEAT8 are authorized to operate continuously (8,760 hours

per year).

ii. Heaters HEAT1 through HEAT8 shall only be fired with natural gas having a

maximum sulfur content of 0.25 grains or less of total sulfur (as hydrogen sulfide) per

100 standard cubic feet (< 4 ppmv). Compliance can be shown by the following

methods: for pipeline grade natural gas, a current gas company bill; for other gaseous

fuel, a current lab analysis, stain-tube analysis, gas contract, tariff sheet, or other

approved methods. Compliance shall be demonstrated at least once per calendar year.

[OAC 252:100-31]

E. Emissions from EUG-05 are limited as follows:

EUG-05A Condensate Tanks

EU Description VOC (TPY)

TK-451 1,000-bbl Condensate Tank

3.29








i. Condensate throughput is limited to 76,650,000 gallons/year. [OAC 252:100-43]

ii. The condensate tanks shall be equipped with internal floating roofs. Roof landings shall

be limited to a total of 8 events per year, 12-month rolling total and 0.04 TPY resulting

emissions. [OAC 252:100-43]

iii. If applicable, the condensate tanks (TK-451 through TK-458) will comply with 40 CFR

60, NSPS Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage

Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction,

Reconstruction, or Modification Commenced After July 23, 1984.

[40 CFR §60.4200 to §60.4219]

a. §60.110b Applicability and designation of affected facility.

b. §60.111b Definitions.

c. §60.112b Standard for volatile organic compounds (VOC).

d. §60.113b Testing and procedures.

e. §60.114b Alternative means of emission limitation.

http://www.ecfr.gov/cgi-bin/text-idx?node=sp40.7.60.k_0b#se40.7.60_1110b






f. §60.115b Reporting and recordkeeping requirements.

g. §60.116b Monitoring of operations.

h. §60.117b Delegation of authority.

EUG-05B: Produced Water Tanks


TK-891 and TK-892 Produced Water Storage Tank 210-bbl

TK-2891 and TK-2892 Produced Water Storage Tank 500-bbl

BACT Limits

EU Emission Unit Description VOC

(TPY)

TK-891, -892, -2891,

and -2892 Produced Water Storage Tanks 0.12

iv. The produced water tanks are insignificant activities and shall keep records as prescribed

for insignificant activities. [OAC 252:100-8]

F. Emissions from EUG-06 are limited as follows:

EUG-06: Process Flares

EU Description NOx CO VOC

TPY TPY TPY

FLARE1 Process Flare 3.34 18.16 8.63

FLARE2 Process Flare 3.34 18.16 8.63

i. FLARE1 or FLARE2 shall control emissions from blowdown events from the overhead

stabilizer compressors located at the condensate stabilizer (locations C-151 and C-152),

refrigeration compressors located at Train 3 (locations C-3141, C-3142, and C-3143),

and from the and from the refrigeration compressors located at Train 1 and Train 2

(locations C-140, C-141, C-2140, and C-2141). Blowdown emissions shall be directed

to the flare with 100% capture efficiency. The permittee shall calculate and record VOC

emissions from controlled blowdown events routed to each flare. Controlled blowdowns

shall be controlled with at least 98% efficiency from the flare. The records shall include

discharge volumes and VOC content (monthly, 12-month rolling total).

[OAC 252:100-37]

ii. The flare pilots shall only be fired with natural gas having a maximum sulfur content of

0.25 grains or less of total sulfur (as hydrogen sulfide) per 100 standard cubic feet (< 4

ppmv). Compliance can be shown by the following methods: for pipeline grade natural

gas, a current gas company bill; for other gaseous fuel, a current lab analysis, stain-tube

analysis, gas contract, tariff sheet, or other approved methods. Compliance shall be

demonstrated at least once per calendar year.

[OAC 252:100-31]





iii. The flash tanks of the amine units may be vented to the flares. The amine unit flash tank

off gases shall be controlled with at least 98% control efficiency from FLARE1 and

FLARE2.

iv. Each flare shall have an alarm system to signal non-combustion of the exhaust gases.

[OAC 252:100-31 and OAC 252:100-37]

G. Emissions from EUG-07 are limited as follows:

EUG-07: Truck Loading

EU Description Throughput (gal/yr) VOC (TPY)

LOAD1 Condensate Loading 76,650,000 51.30

[OAC 252:100-37]

i. Condensate loading shall be conducted using a vapor collection system which is designed

to collect the vapors displaced from the tank truck during loading of crude oil or

condensate. The loading operations, vapor collection system, and vapor disposal system

shall be operated in accordance with the following: [OAC 252:100-37]

a) When loading crude oil or condensate into tank trucks, the tank trucks shall be bottom

loaded with hatches closed (vapor tight).

b) When loading crude oil or condensate into tank trucks, a vapor collection line shall be

connected from the tank truck to the vapor collection system and shall route all vapors

generated during loading to the vapor collection system.

c) All loading and vapor lines shall be equipped with fittings that make vapor-tight

connections and which must be closed when disconnected or which close

automatically when disconnected.

d) A means shall be provided to prevent VOC drainage from the loading device when it

is removed from any tank truck or trailer, or to accomplish complete drainage before

removal.

e) The vapor collection systems shall be properly maintained and operated with a

maximum assumed collection efficiency of 70%.

f) The owner or operator shall act to assure that the terminal's and the tank truck's

vapor collection systems are connected during each loading of a tank truck at the

affected facility. Examples of actions to accomplish this include training drivers in

the hookup procedures and posting visible reminder signs at the affected loading

racks.

g) The vapor disposal system shall route all vapors to a combustor with a minimum

destruction efficiency of 98%.

h) When loading crude oil or condensate, the presence of a combustor pilot flame

shall be monitored using a thermocouple or any other equivalent device to detect

the presence of a flame.

i) Records of pilot flame(s) outages during loading operations shall be maintained

along with the time and duration of all periods during which the pilot flame is/was

absent.


H. Emission points for EUG-08 are as follows:

EUG-08A: Unmonitored Fugitive Emissions

EU Type of Equipment Type of Service Component Count(1)

FUG1

Valves Gas/Vapor 390

Flanges/Connectors Gas/Vapor 800

Compressor Seals Gas/Vapor 60

Relief Valves Gas/Vapor 36

Valves Light Liquid 100

Flanges/Connectors Light Liquid 400

Pump Seals Light Liquid 4

Relief Valves Light Liquid 10 (1) – Component count is estimated.

i. No emission limits are applied to EUG-08A.

EUG-08B: Monitored Fugitive Emissions

EU Type of Equipment Type of Service Component Count(1)

FUG2

Valves Gas/Vapor 784

Flanges/Connectors Gas/Vapor 5,479

Comp. Seals Gas/Vapor 39

Relief Valves Gas/Vapor 15

Valves Light Liquid 646

Flanges/Connectors Light Liquid 3,120

Pump Seals Light Liquid 9

Relief Valves Light Liquid 0 (1) – Component count is estimated.

ii. The facility is subject to NSPS Subpart OOOO or Subpart OOOOa and shall comply

with all applicable requirements.

[40 CFR 60.5360 to 60.5430 or 40 CFR 60.5360a to 60.5499a]

iii. The following requirements represent BACT:

a. The facility is subject to a leak detection and repair (LDAR) monitoring program

which meets or exceeds the standards presented in per 40 CFR Part 60 Subpart

OOOO,

b. The facility shall use air-driven pneumatic controllers,

c. The facility shall use an audio-visual-olfactory (AVO) monitoring program.


I. Emissions from EUG-09 are limited as follows:

EUG-09: Insignificant Tanks



















i. Emissions from EUG-09 shall be insignificant as defined by OAC 252:100-8-2 and OAC

252:100 Appendix I.

2. The following records shall be maintained on-site to verify Insignificant Activities. No

recordkeeping is required for those operations that qualify as Trivial Activities.

[OAC 252:100-8-6 (a)(3)(B)]

a. For stationary reciprocating engines burning natural gas, gasoline, aircraft fuels, or diesel

fuel which are either used exclusively for emergency power generation or for peaking

power service not exceeding 500 hours/year: records of engine service and annual

operating hours.

b. For space heaters, boilers, process heaters, and emergency flares less than or equal to 5

MMBTUH heat input fired by commercial natural gas: records of design heat input and

type of gas fired.

c. For 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: records of tank capacity and true vapor pressure at maximum

storage temperature.

d. For activities having the potential to emit no more than 5 TPY (actual) of any criteria

pollutant: records of the type of activity and the amount of emissions from that activity

(annual).


3. The permittee shall comply with NSPS, Subpart OOOO, Standards of Performance for Crude Oil and Natural Gas Production, Transportation, and Distribution, for all affected facilities

located at this facility. [40 CFR 60.5360 to 60.5430]

a. § 60.5360 What is the purpose of this subpart?

b. § 60.5365 Am I subject to this subpart?

c. § 60.5370 When must I comply with this subpart?

d. § 60.5375 What standards apply to gas well affected facilities?

e. § 60.5380 What standards apply to centrifugal compressor affected facilities?

f. § 60.5385 What standards apply to reciprocating compressor affected facilities?

g. § 60.5390 What standards apply to pneumatic controller affected facilities?

h. § 60.5395 What standards apply to storage vessel affected facilities?

i. § 60.5400 What equipment leak standards apply to affected facilities at an onshore

natural gas processing plant?

j. § 60.5401 What are the exceptions to the equipment leak standards for affected facilities

at onshore natural gas processing plants?

k. § 60.5402 What are the alternative emission limitations for equipment leaks from

onshore natural gas processing plants?

l. § 60.5405 What standards apply to sweetening units at onshore natural gas processing

plants?

m. § 60.5406 What test methods and procedures must I use for my sweetening units affected

facilities at onshore natural gas processing plants?

n. § 60.5407 What are the requirements for monitoring of emissions and operations from

my sweetening unit affected facilities at onshore natural gas processing plants?

o. § 60.5408 What is an optional procedure for measuring hydrogen sulfide in acid gas-

Tutwiler Procedure?

p. § 60.5410 How do I demonstrate initial compliance with the standards for my gas well

affected facility, my centrifugal compressor affected facility, my reciprocating

compressor affected facility, my pneumatic controller affected facility, my storage vessel

affected facility, and my equipment leaks and sweetening unit affected facilities at

onshore natural gas processing plants?

q. § 60.5411 What additional requirements must I meet to determine initial compliance for

my closed vent systems routing emissions from storage vessels or centrifugal compressor

wet seal fluid degassing systems?

r. § 60.5412 What additional requirements must I meet for determining initial compliance

with control devices used to comply with the emission standards for my storage vessel or

centrifugal compressor affected facility?

s. § 60.5413 What are the performance testing procedures for control devices used to

demonstrate compliance at my storage vessel or centrifugal compressor affected facility?

t. § 60.5415 How do I demonstrate continuous compliance with the standards for my gas

well affected facility, my centrifugal compressor affected facility, my stationary

reciprocating compressor affected facility, my pneumatic controller affected facility, my

storage vessel affected facility, and my affected facilities at onshore natural gas

processing plants?


u. § 60.5416 What are the initial and continuous cover and closed vent system inspection

and monitoring requirements for my storage vessel or centrifugal compressor affected

facility?

v. § 60.5417 What are the continuous control device monitoring requirements for my

storage vessel or centrifugal compressor affected facility?

w. § 60.5420 What are my notification, reporting, and recordkeeping requirements?

x. § 60.5421 What are my additional recordkeeping requirements for my affected facility

subject to VOC requirements for onshore natural gas processing plants?

y. § 60.5422 What are my additional reporting requirements for my affected facility subject

to VOC requirements for onshore natural gas processing plants?

z. § 60.5423 What additional recordkeeping and reporting requirements apply to my

sweetening unit affected facilities at onshore natural gas processing plants?

aa. § 60.5425 What parts of the General Provisions apply to me?

bb. § 60.5430 What definitions apply to this subpart?

4. The permittee shall comply with NSPS, Subpart OOOOa, Standards of Performance for

Crude Oil and Natural Gas Production, Transportation, and Distribution, for all affected

facilities located at this site for which construction, modified, or reconstructed after

September 18, 2015. [40 CFR 60.5360a through 60.5432a]

a. §60.5360a What is the purpose of this subpart?

b. §60.5365a Am I subject to this subpart?

c. §60.5370a When must I comply with this subpart?

d. §60.5375a What GHG and VOC standards apply to well affected facilities?

e. §60.5380a What GHG and VOC standards apply to centrifugal compressor affected

facilities?

f. §60.5385a What GHG and VOC standards apply to reciprocating compressor affected

facilities?

g. §60.5390a What GHG and VOC standards apply to pneumatic controller affected

facilities?

h. §60.5393a What GHG and VOC standards apply to pneumatic pump affected facilities?

i. §60.5395a What VOC standards apply to storage vessel affected facilities?

j. §60.5397a What fugitive emissions GHG and VOC standards apply to the affected

facility which is the collection of fugitive emissions components at a well site and the

affected facility which is the collection of fugitive emissions components at a compressor

station?

k. §60.5398a What are the alternative means of emission limitations for GHG and VOC

from well completions, reciprocating compressors, the collection of fugitive emissions

components at a well site and the collection of fugitive emissions components at a

compressor station?

l. §60.5400a What equipment leak GHG and VOC standards apply to affected facilities at

an onshore natural gas processing plant?

m. §60.5401a What are the exceptions to the equipment leak GHG and VOC standards for

affected facilities at onshore natural gas processing plants?

n. §60.5402a What are the alternative means of emission limitations for GHG and VOC

equipment leaks from onshore natural gas processing plants?


o. §60.5405a What standards apply to sweetening unit affected facilities at onshore natural

gas processing plants?

p. §60.5406a What test methods and procedures must I use for my sweetening unit affected


q. §60.5407a What are the requirements for monitoring of emissions and operations from

my sweetening unit affected facilities at onshore natural gas processing plants?

r. §60.5408a What is an optional procedure for measuring hydrogen sulfide in acid gas—

Tutwiler Procedure?

s. §60.5410a How do I demonstrate initial compliance with the standards for my well,

centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump,

storage vessel, collection of fugitive emissions components at a well site, collection of

fugitive emissions components at a compressor station, and equipment leaks and


t. §60.5411a What additional requirements must I meet to determine initial compliance for

my covers and closed vent systems routing emissions from centrifugal compressor wet

seal fluid degassing systems, reciprocating compressors, pneumatic pumps and storage

vessels?

u. §60.5412a What additional requirements must I meet for determining initial compliance

with control devices used to comply with the emission standards for my centrifugal

compressor, and storage vessel affected facilities?

v. §60.5413a What are the performance testing procedures for control devices used to

demonstrate compliance at my centrifugal compressor and storage vessel affected

facilities?

w. §60.5415a How do I demonstrate continuous compliance with the standards for my well,

centrifugal compressor, reciprocating compressor, pneumatic controller, pneumatic pump,

storage vessel, collection of fugitive emissions components at a well site, and collection of

fugitive emissions components at a compressor station affected facilities, and affected


x. §60.5416a What are the initial and continuous cover and closed vent system inspection

and monitoring requirements for my centrifugal compressor, reciprocating compressor,

pneumatic pump and storage vessel affected facilities?

y. §60.5417a What are the continuous control device monitoring requirements for my

centrifugal compressor and storage vessel affected facilities?

z. §60.5420a What are my notification, reporting, and recordkeeping requirements?

aa. §60.5421a What are my additional recordkeeping requirements for my affected facility

subject to GHG and VOC requirements for onshore natural gas processing plants?

bb. §60.5422a What are my additional reporting requirements for my affected facility subject

to GHG and VOC requirements for onshore natural gas processing plants?

cc. §60.5423a What additional recordkeeping and reporting requirements apply to my


dd. §60.5425a What parts of the General Provisions apply to me?

ee. §60.5430a What definitions apply to this subpart?

ff. §60.5432a How do I determine whether a well is a low pressure well using the low

pressure well equation?


5. The permittee shall maintain records of operations in the following list. These records shall

be maintained on-site for at least five years after the date of recording and shall be provided to

regulatory personnel upon request. [OAC 252:100-43]

a. O&M records for any engine if operated less than 220 hours per quarter and not tested.

b. Periodic testing for NOX and CO for each engine/turbine.

c. For the fuel burned the appropriate document(s) as described:

1. Specific Condition 1. A. ii.

2. Specific Condition 1. A. vi.

3. Specific Condition 1. C. iii.

4. Specific Condition 1. D. ii.

5. Specific Condition 1. F. iii.

d. Hours of operation for each emergency generator engine (monthly, 12-month rolling

total).

e. Natural gas throughput for each amine unit (monthly, 12-month rolling total).

f. Amine unit H2S emissions compliance demonstration records as required by Specific

Condition 1, EUG-02 (weekly and/or monthly as appropriate).

g. Records of thermal oxidizer downtimes and the corresponding volumes of gas vented.

h. Sulfur content of the natural gas processed at the facility at each inlet (monthly). Records

shall be kept for natural gas inlets that are out of service during sampling events.

i. Condensate throughput (monthly and 12-month rolling total).

j. Records required by 40 CFR §60, Subpart Kb if facility begins receiving condensate after

custody transfer.

k. Records of estimated gas volume(s) directed to FLARE1, corresponding VOC contents,

and calculations of the resulting VOC emissions. (monthly, 12-month rolling total).

l. Records of estimated gas volume(s) directed to FLARE2, corresponding VOC contents,

and calculations of the resulting VOC emissions. (monthly, 12-month rolling total).

m. Records of insignificant activities.

n. Records required by 40 CFR §60, Subpart IIII.

o. Records required by 40 CFR §60, Subpart JJJJ.

p. Records required by 40 CFR §60, Subpart OOOO.

q. Records required by 40 CFR §60, Subpart OOOOa.

r. Records required by 40 CFR §63, Subpart ZZZZ.

6. The permittee shall apply for an initial Part 70 operating permit within 180 days of startup.


Mr. Kyle Kauk, EHS Specialist

5550 N Francis Avenue

Oklahoma City, OK 73118

SUBJECT: Permit No. 2015-0197-C (M-1)

Grady Gas Plant (Facility ID 12235)


Dear Mr. Kauk:

Enclosed is the permit authorizing construction of the referenced facility. Please note that this

permit is issued subject to standard and specific conditions, which are attached. These conditions

must be carefully followed since they define the limits of the permit and will be confirmed by

periodic inspections.

Also note that you are required to annually submit an emissions inventory for this facility. An

emissions inventory must be completed on approved AQD forms and submitted (hardcopy or

electronically) by April 1st of every year. Any questions concerning the form or submittal

process should be referred to the Emissions Inventory Staff at 405-702-4100.

Thank you for your cooperation in this matter. If we may be of further service, please contact

our office at (405)702-4100.

Sincerely,

Phillip Fielder, P.E., Permits and Engineering Group Manager


Enclosures


Mr. Kyle Kauk, EHS Specialist

5550 N Francis Avenue

Oklahoma City, OK 73118

SUBJECT: Permit No. 2015-0197-C (M-1)

Grady Gas Plant (Facility ID 12235)


Dear Mr. Kauk:

Air Quality Division has completed the initial review of your permit application referenced

above. This application has been determined to be a Tier II. In accordance with 27A O.S. § 2-

14-301 & 302 and OAC 252:4-7-13(c) the application and enclosed draft permit are now ready

for public review. The requirements for public review include the following steps which you

must accomplish:

1. Publish at least one legal notice (one day) of a “Notice of Tier II Draft Permit” in at

least one newspaper of general circulation within the county where the facility is located.

(Instructions enclosed)

2. Provide for public review (for a period of 30 days following the date of the newspaper

announcement) a copy of this draft permit and a copy of the application at a convenient

location (preferably a public location) within the county of the facility.

3. Send to AQD a copy of the proof of publication notice from Item #1 above together

with any additional comments or requested changes which you may have on the draft

permit.

Thank you for your cooperation. If you have any questions, please refer to the permit number

above and contact me at (405) 702-4100 or the permit writer, Lisa Cox, at (405) 702-4201.

Sincerely,

Phillip Fielder, P.E., Permits and Engineering Group Manager

AIR QUALITY DIVISION Enclosures

DEQ Form # 100-890 Revised 10/20/06

PART 70 PERMIT


STATE OF OKLAHOMA

DEPARTMENT OF ENVIRONMENTAL QUALITY

707 NORTH ROBINSON, SUITE 4100

P.O. BOX 1677

OKLAHOMA CITY, OKLAHOMA 73101-1677

Permit No. 2015-0197-C (M-1)

Woodford Express, L.L.C.

having complied with the requirements of the law, is hereby granted permission to

construct the Grady Gas Plant located in Section 11, Township 3N, Range 5W; Grady

County, Oklahoma, subject to Specific Conditions and Standard Conditions dated June 21,

2016, both of which are attached.

In the absence of construction commencement, this permit shall expire 18 months from the

issuance date of this permit, except as authorized under Section VIII of the Standard

Conditions.

_____________________________________

Division Director Date

Air Quality Division

DRAFT/PROPOSED

DEQ Form # 100-890 Revised 10/20/06

MAJOR SOURCE AIR QUALITY PERMIT

STANDARD CONDITIONS

(June 21, 2016)

SECTION I. DUTY TO COMPLY

A. This is a permit to operate / construct this specific facility in accordance with the federal

Clean Air Act (42 U.S.C. 7401, et al.) and under the authority of the Oklahoma Clean Air Act

and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma

Department of Environmental Quality (DEQ). The permit does not relieve the holder of the

obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or

ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

C. The permittee shall comply with all conditions of this permit. Any permit noncompliance

shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement

action, permit termination, revocation and reissuance, or modification, or for denial of a permit

renewal application. All terms and conditions are enforceable by the DEQ, by the

Environmental Protection Agency (EPA), and by citizens under section 304 of the Federal Clean

Air Act (excluding state-only requirements). This permit is valid for operations only at the

specific location listed.

[40 C.F.R. §70.6(b), OAC 252:100-8-1.3 and OAC 252:100-8-6(a)(7)(A) and (b)(1)]

D. It shall not be a defense for a permittee in an enforcement action that it would have been

necessary to halt or reduce the permitted activity in order to maintain compliance with the

conditions of the permit. However, nothing in this paragraph shall be construed as precluding

consideration of a need to halt or reduce activity as a mitigating factor in assessing penalties for

noncompliance if the health, safety, or environmental impacts of halting or reducing operations

would be more serious than the impacts of continuing operations. [OAC 252:100-8-6(a)(7)(B)]

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from an emergency and/or posing an imminent and substantial

danger to public health, safety, or the environment shall be reported in accordance with Section

XIV (Emergencies). [OAC 252:100-8-6(a)(3)(C)(iii)(I) & (II)]

B. Deviations that result in emissions exceeding those allowed in this permit shall be reported

consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements.

[OAC 252:100-8-6(a)(3)(C)(iv)]

C. Every written report submitted under this section shall be certified as required by Section III

(Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.

[OAC 252:100-8-6(a)(3)(C)(iv)]

MAJOR SOURCE STANDARD CONDITIONS June 21, 2016 2

SECTION III. MONITORING, TESTING, RECORDKEEPING & REPORTING

A. The permittee shall keep records as specified in this permit. These records, including

monitoring data and necessary support information, shall be retained on-site or at a nearby field

office for a period of at least five years from the date of the monitoring sample, measurement,

report, or application, and shall be made available for inspection by regulatory personnel upon

request. Support information includes all original strip-chart recordings for continuous

monitoring instrumentation, and copies of all reports required by this permit. Where appropriate,

the permit may specify that records may be maintained in computerized form.

[OAC 252:100-8-6 (a)(3)(B)(ii), OAC 252:100-8-6(c)(1), and OAC 252:100-8-6(c)(2)(B)]

B. Records of required monitoring shall include:

(1) the date, place and time of sampling or measurement;

(2) the date or dates analyses were performed;

(3) the company or entity which performed the analyses;

(4) the analytical techniques or methods used;

(5) the results of such analyses; and

(6) the operating conditions existing at the time of sampling or measurement.

[OAC 252:100-8-6(a)(3)(B)(i)]

C. No later than 30 days after each six (6) month period, after the date of the issuance of the

original Part 70 operating permit or alternative date as specifically identified in a subsequent Part

70 operating permit, the permittee shall submit to AQD a report of the results of any required

monitoring. All instances of deviations from permit requirements since the previous report shall

be clearly identified in the report. Submission of these periodic reports will satisfy any reporting

requirement of Paragraph E below that is duplicative of the periodic reports, if so noted on the

submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)]

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or

operator shall comply with the provisions of Section II (Reporting Of Deviations From Permit

Terms) of these standard conditions. [OAC 252:100-8-6(a)(3)(C)(iii)]

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this

permit, monitoring and reporting may be required under the provisions of OAC 252:100-43,

Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean

Air Act or Oklahoma Clean Air Act. [OAC 252:100-43]

F. Any Annual Certification of Compliance, Semi Annual Monitoring and Deviation Report,

Excess Emission Report, and Annual Emission Inventory submitted in accordance with this

permit shall be certified by a responsible official. This certification shall be signed by a

responsible official, and shall contain the following language: “I certify, based on information

and belief formed after reasonable inquiry, the statements and information in the document are

true, accurate, and complete.”

[OAC 252:100-8-5(f), OAC 252:100-8-6(a)(3)(C)(iv), OAC 252:100-8-6(c)(1), OAC

252:100-9-7(e), and OAC 252:100-5-2.1(f)]


G. Any owner or operator subject to the provisions of New Source Performance Standards

(“NSPS”) under 40 CFR Part 60 or National Emission Standards for Hazardous Air Pollutants

(“NESHAPs”) under 40 CFR Parts 61 and 63 shall maintain a file of all measurements and other

information required by the applicable general provisions and subpart(s). These records shall be

maintained in a permanent file suitable for inspection, shall be retained for a period of at least

five years as required by Paragraph A of this Section, and shall include records of the occurrence

and duration of any start-up, shutdown, or malfunction in the operation of an affected facility,

any malfunction of the air pollution control equipment; and any periods during which a

continuous monitoring system or monitoring device is inoperative.

[40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q]

H. The permittee of a facility that is operating subject to a schedule of compliance shall submit

to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for

achieving the activities, milestones or compliance required in the schedule of compliance and the

dates when such activities, milestones or compliance was achieved. The progress reports shall

also contain an explanation of why any dates in the schedule of compliance were not or will not

be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)]

I. All testing must be conducted under the direction of qualified personnel by methods

approved by the Division Director. All tests shall be made and the results calculated in

accordance with standard test procedures. The use of alternative test procedures must be

approved by EPA. When a portable analyzer is used to measure emissions it shall be setup,

calibrated, and operated in accordance with the manufacturer’s instructions and in accordance

with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document

or an equivalent method approved by Air Quality.

[OAC 252:100-8-6(a)(3)(A)(iv), and OAC 252:100-43]

J. The reporting of total particulate matter emissions as required in Part 7 of OAC 252:100-8

(Permits for Part 70 Sources), OAC 252:100-19 (Control of Emission of Particulate Matter), and

OAC 252:100-5 (Emission Inventory), shall be conducted in accordance with applicable testing

or calculation procedures, modified to include back-half condensables, for the concentration of

particulate matter less than 10 microns in diameter (PM10). NSPS may allow reporting of only

particulate matter emissions caught in the filter (obtained using Reference Method 5).

K. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required

by 40 C.F.R. Part 60, 61, and 63, for all equipment constructed or operated under this permit

subject to such standards. [OAC 252:100-8-6(c)(1) and OAC 252:100, Appendix Q]

SECTION IV. COMPLIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70

operating permit or alternative date as specifically identified in a subsequent Part 70 operating

permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a

certification of compliance with the terms and conditions of this permit and of any other

applicable requirements which have become effective since the issuance of this permit.

[OAC 252:100-8-6(c)(5)(A), and (D)]


B. The compliance certification shall describe the operating permit term or condition that is the

basis of the certification; the current compliance status; whether compliance was continuous or

intermittent; the methods used for determining compliance, currently and over the reporting

period. The compliance certification shall also include such other facts as the permitting

authority may require to determine the compliance status of the source.

[OAC 252:100-8-6(c)(5)(C)(i)-(v)]

C. The compliance certification shall contain a certification by a responsible official as to the

results of the required monitoring. This certification shall be signed by a responsible official,

and shall contain the following language: “I certify, based on information and belief formed

after reasonable inquiry, the statements and information in the document are true, accurate, and

complete.” [OAC 252:100-8-5(f) and OAC 252:100-8-6(c)(1)]

D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions

units or stationary sources that are not in compliance with all applicable requirements. This

schedule shall include a schedule of remedial measures, including an enforceable sequence of

actions with milestones, leading to compliance with any applicable requirements for which the

emissions unit or stationary source is in noncompliance. This compliance schedule shall

resemble and be at least as stringent as that contained in any judicial consent decree or

administrative order to which the emissions unit or stationary source is subject. Any such

schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the

applicable requirements on which it is based, except that a compliance plan shall not be required

for any noncompliance condition which is corrected within 24 hours of discovery.

[OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)]

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE

PERMIT TERM

The permittee shall comply with any additional requirements that become effective during the

permit term and that are applicable to the facility. Compliance with all new requirements shall

be certified in the next annual certification. [OAC 252:100-8-6(c)(6)]

SECTION VI. PERMIT SHIELD

A. Compliance with the terms and conditions of this permit (including terms and conditions

established for alternate operating scenarios, emissions trading, and emissions averaging, but

excluding terms and conditions for which the permit shield is expressly prohibited under OAC

252:100-8) shall be deemed compliance with the applicable requirements identified and included

in this permit. [OAC 252:100-8-6(d)(1)]

B. Those requirements that are applicable are listed in the Standard Conditions and the Specific

Conditions of this permit. Those requirements that the applicant requested be determined as not

applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6(d)(2)]


SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT

The permittee shall file with the AQD an annual emission inventory and shall pay annual fees

based on emissions inventories. The methods used to calculate emissions for inventory purposes

shall be based on the best available information accepted by AQD.

[OAC 252:100-5-2.1, OAC 252:100-5-2.2, and OAC 252:100-8-6(a)(8)]

SECTION VIII. TERM OF PERMIT

A. Unless specified otherwise, the term of an operating permit shall be five years from the date

of issuance. [OAC 252:100-8-6(a)(2)(A)]

B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely

and complete renewal application has been submitted at least 180 days before the date of

expiration. [OAC 252:100-8-7.1(d)(1)]

C. A duly issued construction permit or authorization to construct or modify will terminate and

become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction

is not commenced within 18 months after the date the permit or authorization was issued, or if

work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)]

D. The recipient of a construction permit shall apply for a permit to operate (or modified

operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)]

SECTION IX. SEVERABILITY

The provisions of this permit are severable and if any provision of this permit, or the application

of any provision of this permit to any circumstance, is held invalid, the application of such

provision to other circumstances, and the remainder of this permit, shall not be affected thereby.

[OAC 252:100-8-6 (a)(6)]

SECTION X. PROPERTY RIGHTS

A. This permit does not convey any property rights of any sort, or any exclusive privilege.

[OAC 252:100-8-6(a)(7)(D)]

B. This permit shall not be considered in any manner affecting the title of the premises upon

which the equipment is located and does not release the permittee from any liability for damage

to persons or property caused by or resulting from the maintenance or operation of the equipment

for which the permit is issued. [OAC 252:100-8-6(c)(6)]

SECTION XI. DUTY TO PROVIDE INFORMATION

A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty

(60) days of the request unless the DEQ specifies another time period, any information that the

DEQ may request to determine whether cause exists for modifying, reopening, revoking,


reissuing, terminating the permit or to determine compliance with the permit. Upon request, the

permittee shall also furnish to the DEQ copies of records required to be kept by the permit.

[OAC 252:100-8-6(a)(7)(E)]

B. The permittee may make a claim of confidentiality for any information or records submitted

pursuant to 27A O.S. § 2-5-105(18). Confidential information shall be clearly labeled as such

and shall be separable from the main body of the document such as in an attachment.

[OAC 252:100-8-6(a)(7)(E)]

C. Notification to the AQD of the sale or transfer of ownership of this facility is required and

shall be made in writing within thirty (30) days after such sale or transfer.

[Oklahoma Clean Air Act, 27A O.S. § 2-5-112(G)]

SECTION XII. REOPENING, MODIFICATION & REVOCATION

A. The permit may be modified, revoked, reopened and reissued, or terminated for cause.

Except as provided for minor permit modifications, the filing of a request by the permittee for a

permit modification, revocation and reissuance, termination, notification of planned changes, or

anticipated noncompliance does not stay any permit condition.

[OAC 252:100-8-6(a)(7)(C) and OAC 252:100-8-7.2(b)]

B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the

following circumstances: [OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)]

(1) Additional requirements under the Clean Air Act become applicable to a major source

category three or more years prior to the expiration date of this permit. No such

reopening is required if the effective date of the requirement is later than the expiration

date of this permit.

(2) The DEQ or the EPA determines that this permit contains a material mistake or that the

permit must be revised or revoked to assure compliance with the applicable requirements.

(3) The DEQ or the EPA determines that inaccurate information was used in establishing the

emission standards, limitations, or other conditions of this permit. The DEQ may revoke

and not reissue this permit if it determines that the permittee has submitted false or

misleading information to the DEQ.

(4) DEQ determines that the permit should be amended under the discretionary reopening

provisions of OAC 252:100-8-7.3(b).

C. The permit may be reopened for cause by EPA, pursuant to the provisions of OAC 100-8-

7.3(d). [OAC 100-8-7.3(d)]

D. The permittee shall notify AQD before making changes other than those described in Section

XVIII (Operational Flexibility), those qualifying for administrative permit amendments, or those

defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). The

notification should include any changes which may alter the status of a “grandfathered source,”

as defined under AQD rules. Such changes may require a permit modification.

[OAC 252:100-8-7.2(b) and OAC 252:100-5-1.1]


E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that

are not specifically approved by this permit are prohibited. [OAC 252:100-8-6(c)(6)]

SECTION XIII. INSPECTION & ENTRY

A. Upon presentation of credentials and other documents as may be required by law, the

permittee shall allow authorized regulatory officials to perform the following (subject to the

permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(17)

for confidential information submitted to or obtained by the DEQ under this section):

(1) enter upon the permittee's premises during reasonable/normal working hours where a

source is located or emissions-related activity is conducted, or where records must be

kept under the conditions of the permit;

(2) have access to and copy, at reasonable times, any records that must be kept under the

conditions of the permit;

(3) inspect, at reasonable times and using reasonable safety practices, any facilities,

equipment (including monitoring and air pollution control equipment), practices, or

operations regulated or required under the permit; and

(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times

substances or parameters for the purpose of assuring compliance with the permit.

[OAC 252:100-8-6(c)(2)]

SECTION XIV. EMERGENCIES

A. Any exceedance resulting from an emergency shall be reported to AQD promptly but no later

than 4:30 p.m. on the next working day after the permittee first becomes aware of the

exceedance. This notice shall contain a description of the emergency, the probable cause of the

exceedance, any steps taken to mitigate emissions, and corrective actions taken.

[OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)]

B. Any exceedance that poses an imminent and substantial danger to public health, safety, or the

environment shall be reported to AQD as soon as is practicable; but under no circumstance shall

notification be more than 24 hours after the exceedance. [OAC 252:100-8-6(a)(3)(C)(iii)(II)]

C. An "emergency" means any situation arising from sudden and reasonably unforeseeable

events beyond the control of the source, including acts of God, which situation requires

immediate corrective action to restore normal operation, and that causes the source to exceed a

technology-based emission limitation under this permit, due to unavoidable increases in

emissions attributable to the emergency. An emergency shall not include noncompliance to the

extent caused by improperly designed equipment, lack of preventive maintenance, careless or

improper operation, or operator error. [OAC 252:100-8-2]

D. The affirmative defense of emergency shall be demonstrated through properly signed,

contemporaneous operating logs or other relevant evidence that: [OAC 252:100-8-6 (e)(2)]


(1) an emergency occurred and the permittee can identify the cause or causes of the

emergency;

(2) the permitted facility was at the time being properly operated;

(3) during the period of the emergency the permittee took all reasonable steps to minimize

levels of emissions that exceeded the emission standards or other requirements in this

permit.

E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an

emergency shall have the burden of proof. [OAC 252:100-8-6(e)(3)]

F. Every written report or document submitted under this section shall be certified as required

by Section III (Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.

[OAC 252:100-8-6(a)(3)(C)(iv)]

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop

and register with the appropriate agency a risk management plan by June 20, 1999, or the

applicable effective date. [OAC 252:100-8-6(a)(4)]

SECTION XVI. INSIGNIFICANT ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to

operate individual emissions units that are either on the list in Appendix I to OAC Title 252,

Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below.

Any activity to which a State or Federal applicable requirement applies is not insignificant even

if it meets the criteria below or is included on the insignificant activities list.

(1) 5 tons per year of any one criteria pollutant.

(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an

aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year

for single HAP that the EPA may establish by rule.

[OAC 252:100-8-2 and OAC 252:100, Appendix I]

SECTION XVII. TRIVIAL ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to

operate any individual or combination of air emissions units that are considered inconsequential

and are on the list in Appendix J. Any activity to which a State or Federal applicable

requirement applies is not trivial even if included on the trivial activities list.

[OAC 252:100-8-2 and OAC 252:100, Appendix J]

SECTION XVIII. OPERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the

need for any permit revision or any notification to the DEQ (unless specified otherwise in the


permit). When an operating scenario is changed, the permittee shall record in a log at the facility

the scenario under which it is operating. [OAC 252:100-8-6(a)(10) and (f)(1)]

B. The permittee may make changes within the facility that:

(1) result in no net emissions increases,

(2) are not modifications under any provision of Title I of the federal Clean Air Act, and

(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit

to be exceeded;

provided that the facility provides the EPA and the DEQ with written notification as required

below in advance of the proposed changes, which shall be a minimum of seven (7) days, or

twenty four (24) hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the

DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such

change, the written notification required above shall include a brief description of the change

within the permitted facility, the date on which the change will occur, any change in emissions,

and any permit term or condition that is no longer applicable as a result of the change. The

permit shield provided by this permit does not apply to any change made pursuant to this

paragraph. [OAC 252:100-8-6(f)(2)]

SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS

A. The following applicable requirements and state-only requirements apply to the facility

unless elsewhere covered by a more restrictive requirement:

(1) Open burning of refuse and other combustible material is prohibited except as authorized

in the specific examples and under the conditions listed in the Open Burning Subchapter.

[OAC 252:100-13]

(2) No particulate emissions from any fuel-burning equipment with a rated heat input of 10

MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19]

(3) For all emissions units not subject to an opacity limit promulgated under 40 C.F.R., Part

60, NSPS, no discharge of greater than 20% opacity is allowed except for:

[OAC 252:100-25]

(a) Short-term occurrences which 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;

(b) Smoke resulting from fires covered by the exceptions outlined in OAC 252:100-13-7;

(c) An emission, where the presence of uncombined water is the only reason for failure

to meet the requirements of OAC 252:100-25-3(a); or

(d) Smoke generated due to a malfunction in a facility, when the source of the fuel

producing the smoke is not under the direct and immediate control of the facility and

the immediate constriction of the fuel flow at the facility would produce a hazard to

life and/or property.


(4) No visible fugitive dust emissions shall be discharged 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. [OAC 252:100-29]

(5) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2

lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur

dioxide. [OAC 252:100-31]

(6) Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and

with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia

or greater under actual conditions shall be equipped with a permanent submerged fill pipe

or with a vapor-recovery system. [OAC 252:100-37-15(b)]

(7) All fuel-burning equipment shall at all times be properly operated and maintained in a

manner that will minimize emissions of VOCs. [OAC 252:100-37-36]

SECTION XX. STRATOSPHERIC OZONE PROTECTION

A. The permittee shall comply with the following standards for production and consumption of

ozone-depleting substances: [40 CFR 82, Subpart A]

(1) Persons producing, importing, or placing an order for production or importation of certain

class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the

requirements of §82.4;

(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain

class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping

requirements at §82.13; and

(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons,

HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane

(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include

HCFCs.

B. If the permittee performs a service on motor (fleet) vehicles when this service involves an

ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air

conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term

“motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the

vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the

air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger

buses using HCFC-22 refrigerant. [40 CFR 82, Subpart B]

C. The permittee shall comply with the following standards for recycling and emissions

reduction except as provided for MVACs in Subpart B: [40 CFR 82, Subpart F]

(1) Persons opening appliances for maintenance, service, repair, or disposal must comply

with the required practices pursuant to § 82.156;

(2) Equipment used during the maintenance, service, repair, or disposal of appliances must


comply with the standards for recycling and recovery equipment pursuant to § 82.158;

(3) Persons performing maintenance, service, repair, or disposal of appliances must be

certified by an approved technician certification program pursuant to § 82.161;

(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply

with record-keeping requirements pursuant to § 82.166;

(5) Persons owning commercial or industrial process refrigeration equipment must comply

with leak repair requirements pursuant to § 82.158; and

(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant

must keep records of refrigerant purchased and added to such appliances pursuant to §

82.166.

SECTION XXI. TITLE V APPROVAL LANGUAGE

A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is

not inconsistent with Federal requirements, to provide for incorporation of requirements

established through construction permitting into the Source’s Title V permit without causing

redundant review. Requirements from construction permits may be incorporated into the Title V

permit through the administrative amendment process set forth in OAC 252:100-8-7.2(a) only if

the following procedures are followed:

(1) The construction permit goes out for a 30-day public notice and comment using the

procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice to

the public that this permit is subject to EPA review, EPA objection, and petition to

EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit

will be incorporated into the Title V permit through the administrative amendment

process; that the public will not receive another opportunity to provide comments when

the requirements are incorporated into the Title V permit; and that EPA review, EPA

objection, and petitions to EPA will not be available to the public when requirements

from the construction permit are incorporated into the Title V permit.

(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR §

70.8(a)(1).

(3) A copy of the draft construction permit is sent to any affected State, as provided by 40

C.F.R. § 70.8(b).

(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period

as provided by 40 C.F.R.§ 70.8(a) and (c).

(5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day

comment period of any EPA objection to the construction permit. The DEQ shall not

issue the permit until EPA’s objections are resolved to the satisfaction of EPA.

(6) The DEQ complies with 40 C.F.R. § 70.8(d).

(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8(a).

(8) The DEQ shall not issue the proposed construction permit until any affected State and

EPA have had an opportunity to review the proposed permit, as provided by these

permit conditions.

(9) Any requirements of the construction permit may be reopened for cause after

incorporation into the Title V permit by the administrative amendment process, by


DEQ as provided in OAC 252:100-8-7.3(a), (b), and (c), and by EPA as provided in 40

C.F.R. § 70.7(f) and (g).

(10) The DEQ shall not issue the administrative permit amendment if performance tests fail

to demonstrate that the source is operating in substantial compliance with all permit

requirements.

B. To the extent that these conditions are not followed, the Title V permit must go through the

Title V review process.

SECTION XXII. CREDIBLE EVIDENCE

For the purpose of submitting compliance certifications or establishing whether or not a person

has violated or is in violation of any provision of the Oklahoma implementation plan, 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.

[OAC 252:100-43-6]

oklahoma department of environmental qualitythe caterpillar g3516 ulb engines are based on the...

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