oklahoma department of … oklahoma department of environmental quality air quality division...

DRAFT/PROPOSED

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

MEMORANDUM March 16, 2009

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

Air Quality Division

THROUGH: Kendal Stegmann, Sr. Environmental Manager

Compliance & Enforcement

THROUGH: Phil Martin, P.E., Engineering Section

THROUGH: Peer Review

FROM: Jian Yue, P.E., Engineering Section

SUBJECT: Evaluation of Permit Application No. 2004-030-C (M-6)

Madill Gas Processing Company, L.L.C.

Madill Gas Plant

Sec. 32-T5S-R7E, Madill, Marshall County

Latitude: 34.078o, Longitude: -96.592

o

Proceed 10 miles east of Madill on Hwy 199

SECTION I. INTRODUCTION

Madill Gas Processing Company has applied for a construction permit for Madill Gas Plant (SIC

Code 1321). Proposed modification includes the following:

Add a 1,340-hp Caterpillar G-3516TALE engine with oxidation catalyst for outlet

compression.

Add oxidation catalyst on engine CM-7.

Add a cryogenic gas processing plant to improve NGL recovery.

Add a second dehydrator rated for 25 MMscf/day with 5 gpm glycol circulation and

controlled by a condenser.

Add a 1.2 MMBTUH mole sieve regeneration heater.

Add a regen gas dehydrator rated for 1 MMscf/day with 1 gpm glycol circulation and one

0.125 MMBTUH reboiler.

Add a 30,000 gallon NGL storage tank (pressurized).

The facility is an existing PSD source. Controlled emission increases from this modification will

be below PSD significance levels.

PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 2

SECTION II. EQUIPMENT

Emission units have been arranged into Emission Unit Groups (EUGs) as outlined following.

Emission units that emit the same regulated air pollutants, trigger the same applicable

requirements, share the same compliance demonstration methods, and share the same proposed

compliance assurance certifications are combined as one EUG.

EUG-1 Facility Wide

This emission unit group is facility-wide. It includes all emission units and is established to

discuss the applicability of those rules or compliance demonstrations which may affect all

sources within the facility.

EUG-2 Compressor Engines

EU Point Description Size

HP

Serial No. Construction/

Manufactured

Date

EU-CM-1 P-CM-1 Waukesha L7042 GSI

Engine

1,232 306000 2003/1975


Engine

1,232 307750 2002/1977

EU-CM-3 P-CM-3 Waukesha L7042G Engine 896 299870 2004/1975

EU-CM-6 P-CM-6 Caterpillar 3516 Low NOx 1,340 4EK03365 2003/2003

EU-CM-7 P-CM-7 White/Superior 16SGTB 2,650 31849 2005/2005

EU-CM-8 P-CM-8 Caterpillar G3516LE w.

Oxidation Catalyst

1,340 - 2008

EU-C-9 P-CM-9 Caterpillar G3516LE w.

Oxidation Catalyst

1,340 - 2009

EUG-3 Generators

EU Point Description Size Serial # Const. Date

EU-GEN-1 P-GEN-1 Cummins V-12 350-hp/

2.975 MMBTUH

10354249 2005

EU-GEN-2 P-GEN-2 Waukesha VLRO

Generator w. Catalytic

Converter

653-hp 1005435 2008


Generator

653-hp 1031668 1957

EUG-4 Glycol Dehydrator

EU Point Description Construction Date

EU-TEGV-1 P-TEGV-1 Glycol Dehydrator 1973




EUG-5 Firetube Reboiler

EU Point Description MMBTUH Serial No. Construction

Date

EU-TEGH-1 P-TEGH-1 Firetube Reboiler 0.5 S.O.94360 2006

EUG-6 Heaters


Date

EU-HTR-1 P-HTR-1 Hot Oil Heater 3.6 200RB-8211-757 1999

EU-HTR-2 P-HTR-2 Regen. Heater 1.5 114 1999

EU-HTR-3 P-HTR-3 Regen. Heater 1.2 2008


EUG-7 Storage Tank

EU Point Description Capacity

(gallon)

Construction Date

EU-TK-2224 P-TK-2224 Condensate Tank 12,600 2007

EU-TK-2230 P-TK-2230 Pressurized NGL Tank 30,000 2008

EUG-8 Flares

EU Point Description Pilot Gas Rate

(Scf/hr)

Flare Gas Rate

(Mcf/yr)

Construction

Date

EU-F-1 P-F-1 Amine Flare 3,000 72,550 1979

EU-F-2 P-F-2 Plant Flare 600 13 Pre-1972

EU-F-3 P-F-3 Emergency Flare 600 0 Pre-1972

EUG-9 Miscellaneous Process Piping Fugitives

Component Service Components #

Existing

Valves Gas/Vapor 2214

Valves Light Liquid 198

Valves Yard Piping 1677

Flanges Gas/Vapor 1772

Flanges Light Liquid 65

Flanges Yard Piping 1421

Connectors Gas/Vapor 4551

Connectors Light Liquid 413

Connectors Yard Piping 3576

Addition with the J-T Plant

Valves Gas 20

Relief Valves Gas 2

Flanges/Connectors Gas 40

Addition with proposed modification

Valves 400


Component Service Components #

Relief Valves 15

Open-ended Lines 0

Compressors 2

Pump Seals 15

Flanges/Connections 1000

SECTION III. EMISSIONS

Engine emissions are based on manufacturer’s data listed in the following table except as noted:

Engines NOx

g/hp-hr

CO

g/hp-hr

VOC

g/hp-hr

EU-CM-1 2 3 0.4

EU-CM-2 2 3 0.4

EU-CM-3 2 3 0.4

EU-CM-6 1.5 1.9 0.46

EU-CM-7c 1.5 0.32 0.12

EU-CM-8c 2 1 0.09

EU-CM-9c 2 1 0.09

EU-GEN-1a 2.21E+00

lb/MMBTU

3.72E+00

lb/MMBTU

3.58E-01

lb/MMBTU

EU-GEN-2 2 3 0.2

EU-GEN-3b 18 2 2

a based on AP-42 (7/2000), Table 3.2-3.

b.based on manufacturer’s data plus a degree of safety

determined by facility personnel’s engineering judgment. c controlled with oxidation catalyst.

Emissions from engines EU-CM-1 through EM-CM-3 are based on the original permitted

horsepower of 930 hp. One generator is expected to run continuously and the other two are used as

standby units. Heater emissions are based on AP-42 (7/98) Tables 1.4-2 and 1.4-3. VOC

emissions from the glycol dehydrators are based on GRI-GLYCalc analysis with a maximum gas

flow rate of 35 MMSCF/day for TEGV-1 and 25 MMSCF/day for TEGV-2, glycol recirculation

rate of 6 gallon/minute for TEGV-1 and 5 gallon/minute for TEGV-2, and a condensers on the still

vents with the condenser off gas controlled by a combustion device with a 90% destruction

efficiency. Off gases from the flash tanks/separators are recycled for fuel. Flare emissions are

based on AP-42 (1/95) Table 13.5-1. Fugitive emissions are based on “Protocol for Equipment

Leak Emissions Estimates,” EPA-453/R-93-026. Tank emissions are based on the EPA TANKS4

program. The applicant stated that field inlet condensate is stored in a pressure tank first at a

pressure of 7 psig. All vapors from this tank, including “Flash” are captured by closed system and

routed back to the inlet stream. After condensate stabilization, the product is transferred to Tank

EU-TK-2224 for storage until trucked off-site. Since flash emissions are captured at the pressure

tank, any flash emissions associated with Tank EU-TK-2224 will be insignificant (The facility

produced 8,605 bbl. of condensate in year 2005). Total facility-wide emissions are listed in the

following page.


Project Added Emissions

EU NOx CO VOC

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

EU-TEGV-2 - - - - 0.34 1.49

EU-HTR-3 0.12 0.52 0.10 0.43 0.007 0.03

EU-TEGV-3 - - - - 0.39 1.69

EU-HTR-4 0.01 0.05 0.01 0.045 0.001 0.003

EU-CM-9 5.90 25.86 2.95 12.93 0.27 1.16

Fugitive - - - - 0.01 0.04

Project Total 6.03 26.43 3.06 13.41 1.018 4.413

Project total emission increases are below PSD significance levels so no further PSD review is

required.

Existing Emissions

EU NOx CO VOC


EU-CM-1* 4.10 17.96 6.15 26.94 0.90 3.95

EU-CM-2* 4.10 17.96 6.15 26.94 0.90 3.95

EU-CM-3 3.95 17.30 5.92 25.93 0.79 3.46

EU-CM-6 4.43 19.39 5.61 24.56 1.36 5.95

EU-CM-7 8.76 38.37 9.34 40.91 3.50 15.33

EU-CM-8 5.90 25.86 2.95 12.93 0.27 1.16

EU-GEN-1 -

EU-GEN-3 25.89 113.40 2.88 12.61 2.88 12.61

EU-TEGV-1 0 0 0 0 0.41 1.78

EU-TEGH-1 0.05 0.22 0.04 0.18 0.003 0.013

EU-HTR-1 0.36 1.56 0.30 1.31 0.02 0.09

EU-HTR-2 0.15 0.65 0.12 0.54 0.01 0.04

EU-TK-2224 0 0 0 0 0.37 1.61

EU-F-1 0.89 3.90 1.78 7.79 1.49 0.34

EU-F-2 0.01 0.06 0.03 0.12 0.002 0.01

EU-F-3 0.01 0.06 0.03 0.12 0.002 0.01

Fugitive 0 0 0 0 10.42 45.64

Total 58.6 256.69 41.3 180.88 23.33 95.94 *Emissions from these two engines are limited to the current permitted emissions.


Post Project Emissions

EU NOx CO VOC


EU-CM-1* 4.10 17.96 6.15 26.94 0.90 3.95

EU-CM-2* 4.10 17.96 6.15 26.94 0.90 3.95

EU-CM-3 3.95 17.30 5.92 25.93 0.79 3.46

EU-CM-6 4.43 19.39 5.61 24.56 1.36 5.95

EU-CM-7+ 8.76 38.37 1.87 8.18 0.70 3.07

EU-CM-8 5.90 25.86 2.95 12.93 0.27 1.16

EU-CM-9 5.90 25.86 2.95 12.93 0.27 1.16

EU-GEN-1 -

EU-GEN-3 25.89 113.40 2.88 12.61 2.88 12.61

EU-TEGV-1 0 0 0 0 0.41 1.78

EU-TEGV-2 0 0 0 0 0.34 1.49

EU-TEGV-3 0 0 0 0 0.39 1.69

EU-TEGH-1 0.05 0.22 0.04 0.18 0.003 0.013

EU-HTR-1 0.36 1.56 0.30 1.31 0.02 0.09

EU-HTR-2 0.15 0.65 0.12 0.54 0.01 0.04

EU-HTR-3 0.12 0.52 0.10 0.43 0.007 0.03

EU-HTR-4 0.01 0.05 0.01 0.045 0.001 0.003

EU-TK-2224 0 0 0 0 0.37 1.61

EU-F-1 0.89 3.90 1.78 7.79 1.49 0.34

EU-F-2 0.01 0.06 0.03 0.12 0.002 0.01

EU-F-3 0.01 0.06 0.03 0.12 0.002 0.01

Fugitive 0 0 0 0 10.43 45.68

Total Post

Project

64.63 283.12 36.89 161.555 21.545 88.096

Total Existing 58.6 256.69 41.3 180.88 23.33 95.94

Net Changes 6.03 26.43 -4.41 -19.325 -1.785 -7.844 *Emissions from these two engines are limited to the current permitted emissions.

+ This engine will be equipped with an

oxidation catalyst.

Fuel consumption for the 1,232-hp Waukesha L7042 GSI engines has been listed as 7,800

BTU/hp-hr for a fuel consumption of 9,020 SCFH (natural gas heating value of 1,065 Btu/SCF).

Air emissions from each engine will be discharged through a stack 35 feet above grade, at a rate

of 5,486.2 ACFM at 980 F. Moisture content of stack gases has been estimated at 12% from fuel

usage and the stoichiometric ratio of 2 SCF of water per SCF of natural gas fuel.

Fuel consumption for the 896-hp Waukesha L7042 G engine has been listed as 7,800 BTU/hp-hr

for a fuel consumption of 6,560 SCFH. Air emissions from the engine will be discharged

through a stack 35 feet above grade, at a rate of 4,251.8 ACFM at 980 F. Moisture content of

stack gases has been estimated at 15% from fuel usage and the stoichiometric ratio of 2 SCF of

water per SCF of natural gas fuel.

Fuel consumption for the 1,340-hp Caterpillar Low NOx engine has been listed as 7,690 BTU/hp-

hr for a fuel consumption of 9,675 SCFH. Air emissions from the engine will be discharged

through a stack 1.0 feet in diameter, 20 feet above grade, at a rate of 7,685 ACFM at 855 F.


Moisture content of stack gases has been estimated at 10% from fuel usage and the

stoichiometric ratio of 2 SCF of water per SCF of natural gas fuel.

Fuel consumption for the 2,650-hp White/Superior lean burn engine has been listed as 7,600

BTU/hp-hr for a fuel consumption of 18,900 SCFH. Air emissions from the engine will be

discharged through a stack 1.0 feet in diameter, 20 feet above grade, at a rate of 19,796 ACFM at

900 F. Moisture content of stack gases has been estimated at 10% from fuel usage and the


Fuel consumption for the 1,340-hp Caterpillar G3516TALE engines have been listed as 7,540

BTU/hp-hr for a fuel consumption of 10,103 SCFH. Air emissions from the engines will be

discharged through a stack 1.0 feet in diameter, 16 feet above grade, at a rate of 8,002 ACFM at

877 F. Moisture content of stack gases has been estimated at 10.7% from fuel usage and the


Formaldehyde emissions from engines are based on emission factors from AP-42 (7/00), Chapter

3.2, Table 3.2-3 for rich burn engines, with 75 % reduction taken for non-selective catalytic

converter control, Table 3.2-1 for lean-burn 2-stroke engines, and Table 3.3-2 for lean burn 4-

stroke engines, except for caterpillar engines as noted. Total formaldehyde emissions are

estimated and listed below.

Formaldehyde Emissions

aAQD default for Caterpillar lean burn engines.

bOxidation catalyst manufacturer’s guarantee.

cOnly one generator will run at a time, the other two are standby units.

SO2 emissions from EU-F-1 were originally permitted at 413.25 lb/hr and 1810 TPY based on acid

gas flow rate of 72.55 MMSCF/yr (heating value of 73 BTU/SCF), supplemental fuel gas flow rate

of 50 MMSCF/yr (heating value of 1,040 BTU/SCF), H2S mole percent of 30%, and 1,685 lb

SO2/MMCF H2S. It was recently discovered that the heat release of 22 MMBTUH used in

SCREEN 3 modeling originally to demonstrate compliance with OAC 252:100-31 ambient air

Source

HP

Fuel

MMBTU/hp-hr

Emission Factor

(lb/MMBTUH)

lb/hr

TPY

EU-CM-1 1,232 0.0078 0.0205 0.048 0.211

EU-CM-2 1,232 0.0078 0.0205 0.048 0.211

EU-CM-3 896 0.0078 0.0205 0.035 0.154

EU-CM-6a 1,340 0.00769 0.3 g/hp-hr 0.885 3.878

EU-CM-7b 2,650 0.0076 0.01 g/hp-hr 0.213 0.931

EU-CM-8b 1,340 0.00769 0.018 g/hp-hr 0.053 0.233

EU-CM-9b 1,340 0.00769 0.018 g/hp-hr 0.053 0.233

EU-GEN-1c 350 0.0085 0.0205

0.11 0.50 EU-GEN-2c 653 0.0085 0.0205

EU-GEN-3c 653 0.0085 0.0205

Total 1.445 6.351


concentration limits was incorrect. With the correct heat release (6.5 MMBTUH based on the

maximum flow rate and a commingled gas heating value of 467 BTU/SCF), the original SO2

emission limit would violate the standards. However, the applicant stated that actual SO2 emissions

have always been far below the original limit and is willing to take daily calculated allowable SO2

emission limits that would comply with the standards. SCREEN3 modeling was performed and

indicated that the 24-hr average standard was the limiting standard. Compliance with the other

average period standards is ensured by compliance with the 24-hr average standard. Since the

ambient impact depends on two factors: emission and heat release, the following table lists SO2

emissions that would comply with the 24-hr average standard based on different heat release.

Heat Release* Allowed SO2

Emissions

Ambient Impact

24-hr Average

Standard

24-hr Average

MMBTUH lb/hr µg/m3 µg/m

3

6.5 190 129.29

130

6 176 127.2

5 148 123.3

4 120 118.54

3 92 113.38

2 64 106.9

1 36 94.18

*Heat release is based on a heating value of 467 btu/scf of the commingled gas (acid gas and

supplemental fuel).

A formula to calculate allowable SO2 emissions can be drawn from this table:

Allowable SO2 emissions (lb/hr) = 28(Heat Release (MMBTUH) – 1) + 36

The applicant currently monitors flare gas flow rate and H2S mole percent on daily basis and will be

required to maintain a spreadsheet that calculates actual SO2 emissions, heat release, and allowable

SO2 emissions based on the above formula on a daily basis to demonstrate compliance.

Dehydration units using glycol desiccants emit benzene, toluene, ethyl benzene, xylene, and n-

hexane from the glycol reboiler vapor stack. These compounds are regulated as HAPs. The

applicant has analyzed the incoming gas for the concentrations of BTEX, estimating HAP

emissions using the GRI-GLYCalc program with a maximum gas flow rate of 35 MMSCF/day for

TEGV-1 and 25 MMSCFD for TEGV-2, glycol recirculation rate of 6 gpm for TEGV-1 and 5 gpm

for TEGV-2, and a condenser on each still vent with the condenser off gas controlled by a

combustion device with a 90% destruction efficiency. Off gases from the flash tank/separator are

recycled for fuel. The following table lists estimates of HAP emissions from TEGV-1 and TEGV-

2. HAP emissions from the regen. dehydrator is negligible except for n-Hexane, which is included

in total emissions in the following table on page 9.


Pollutant EU-TEGV-1 EU-TEGV-2 Total Emissions


Benzene 0.03 0.11 0.02 0.09 0.05 0.20

Toluene 0.009 0.04 0.008 0.03 0.017 0.07

Ethyl benzene* 0.00 0.00 0.00 0.00 0.00 0.00

Xylene 0.002 0.01 0.002 0.008 0.004 0.018

n-Hexane 0.01 0.05 0.009 0.004 0.036** 0.126**

Total HAPs 0.107 0.414

*The extended gas analysis conducted on January 15, 2006 by Southern Petroleum Lab.

Indicated 0% ethyl benzene.

**Include emissions from TEGV-3.

SECTION IV. INSIGNIFICANT ACTIVITIES

The insignificant activities identified and justified on Part 1b of the forms in the application and

duplicated below were confirmed by the initial operating permit inspection. Appropriate

recordkeeping on activities indicated below with “*”, is required.

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

There is one 3.6 MMBTUH hot oil heater and one 1.5 MMBTUH regenerating heater on-site.

SECTION V. 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]

Primary Standards are in Appendix E and Secondary Standards are in Appendix F of the Air

Pollution Control Rules. At this time, all of Oklahoma is in attainment of these standards.

OAC 252:100-5 (Registration, Emission Inventory, and Annual Operating Fees) [Applicable]

The owner or operator of any facility that is a source of air emissions shall submit a complete

emission inventory annually on forms obtained from the Air Quality Division. An emission

inventory was submitted and fees paid for previous years as required.

OAC 252:100-8 (Permits for Part 70 Sources) [Applicable]

Part 5 includes the general administrative requirements for Part 70 permits. Any planned

changes in the operation of the facility which result in emissions not authorized in the permit and

which exceed the “Insignificant Activities” or “Trivial Activities” thresholds require prior

notification to AQD and may require a permit modification. Insignificant activities mean


individual emission units that either are on the list in Appendix I (OAC 252:100) or whose actual

calendar year emissions do not exceed the following limits:

5 TPY of any one criteria pollutant

2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAPs or 20%

of any threshold less than 10 TPY for single HAP that the EPA may establish by rule

Emission limits for the facility are based on information in the permit application.

OAC 252:100-9 (Excess Emission Reporting Requirements) [Applicable]

In the event of any release which results in excess emissions, the owner or operator of such

facility shall notify the Air Quality Division as soon as the owner or operator of the facility has

knowledge of such emissions, but no later than 4:30 p.m. the next working day. Within ten (10)

working days after the immediate notice is given, the owner or operator shall submit a written

report describing the extent of the excess emissions and response actions taken by the facility. In

addition, if the owner or operator wishes to be considered for the exemption established in

252:100-9-3.3, a Demonstration of Cause must be submitted within 30 calendar days after the

occurrence has ended.

OAC 252:100-13 (Open Burning) [Applicable]

Open burning of refuse and other combustible material is prohibited except as authorized in the

specific examples and under the conditions listed in this subchapter.

OAC 252:100-19 (Particulate Matter) [Applicable]

This subchapter limits particulate emissions from fuel-burning equipment with a rated heat input

of 20 million BTU per hour (MMBTUH) or less to 0.5 lb/MMBTU. AP-42, Table 1.4-2 (7/98)

lists the total PM emissions for natural gas to be 7.6 lb/MMcf or about 0.0076 lb/MMBTU. For 2

cycle/4 cycle engines, AP-42 (7/00), Section 3.2 lists the total PM emissions for natural gas to be

0.0091 lbs/MMBTU. This permit requires the use of natural gas for all fuel-burning equipment 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 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. Since this facility only burns natural gas, compliance with the

standards is assured and no specific monitoring is required.

OAC 252:100-29 (Fugitive Dust) [Applicable]

No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the

property line on which the emissions originate in such a manner as to damage or 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 will not cause

a problem in this area, therefore it is not necessary to require specific precautions to be taken.


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

Part 2 lists the following maximum ambient air concentration limits of different average periods

for new (constructed after July 1, 1972) and existing equipment (constructed before July 1,

1972).

SO2 Standard ( g/m3)

Maximum 1 hr. avg. 1200



Annual 80

The amine unit was installed before 1968. A sulfur recovery unit (SRU) was installed in 1968

and ceased in use in 1976. Acid gas was then sent to an existing flare, which was replaced with

another flare in 1979. Permit No. 96-536-O issued in April 1997 determined that the

replacement would not make the new flare subject to requirements for new processing

equipment. On February 21, 2006, Air Quality Division (AQD) of DEQ issued NOV NO. 06-

AQN-044 alleging that since the change in the method of operation in 1976, Madill gas has

operated in violation of OAC 252:100-31-26(a)(2) sulfur dioxide standards by failing to reduce

sulfur emissions from the amine sweetening unit with a sulfur recovery unit. On September 14,

2006, a closure letter was issued by AQD stating that the alleged changed in operation does not

subject the gas plant to OAC 252:100-31-26(a)(2) because it was verified that there was no

emission increase after the sulfur recovery unit was taken out of service and the acid gas stream

was routed to the acid gas flare. NOV No. 06-AQN-044 was considered resolved and closed.

SO2 emissions from EU-F-1 can be calculated based on acid gas and supplemental fuel gas flow

rate, H2S mole percent, and 1,685 lb SO2/MMCF H2S. To ensure compliance with OAC 252:100-

31 ambient air concentration limits, SCREEN3 modeling was performed and indicated that the 24-

hr average standard was the limiting standard. Compliance with the other average period standard

is ensured by compliance with the 24-hr average standard. Since the ambient impact depends on

two factors: emission and heat release, the following table lists SO2 emissions that would comply

with the 24-hr average standard based on different heat release.

Heat Release* Allowed SO2

Emissions

Ambient Impact

24-hr Average

Standard

24-hr Average

MMBTUH lb/hr µg/m3 µg/m

3

6.5 190 129.29

130

6 176 127.2

5 148 123.3

4 120 118.54

3 92 113.38

2 64 106.9

1 36 94.18

*Heat release is based on a heating value of 467 btu/scf of the commingled gas (acid gas and

supplemental fuel).


A formula to calculate allowable SO2 emissions can be drawn from this table:


The applicant monitors flare gas flow rate and H2S mole percent on daily basis and will be required

to maintain a spreadsheet that calculates actual SO2 emissions, heat release, and allowable SO2

emissions based on the above formula on a daily basis.

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. This is equivalent to approximately 0.2

weight percent sulfur in the fuel gas which is equivalent to 2,000 ppmw sulfur. Thus, a

limitation of 343 ppmv sulfur in a field gas supply will be in compliance. The permit requires

the use of pipeline-grade natural gas or field gas with a maximum sulfur content of 343 ppmv for

all fuel-burning equipment to ensure compliance with Subchapter 31. The plant engines run on

processed fuel. The outlet of the amine treater is continuously monitored by an analyzer that is

connected to the control system. The plant will be shut down if the H2S goes out of spec. H2S

usually runs between 1 – 2 ppm after the amine treatment and is recorded on the daily report.

OAC 252:100-33 (Nitrogen Oxides) [Not Applicable]

This subchapter limits new gas-fired fuel-burning equipment with a rated heat input greater than

or equal to 50 MMBTUH to emissions of 0.2 lb of NOx per MMBTU. There are no equipment

items that exceed the 50 MMBTUH threshold.

OAC 252:100-35 (Carbon Monoxide) [Not Applicable]

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 400 gallons

or more and containing a VOC with a vapor pressure greater than 1.5 psia at maximum storage

temperature to be equipped with a permanent submerged fill pipe or with an organic vapor

recovery system. The 300-bbl condensate tank is subject.

Part 3 requires VOC 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 and is not subject to this requirement.

Part 5 limits the VOC content of coatings from any coating line or other coating operation. This

facility does not normally conduct coating or painting operations except for routine maintenance

of the facility and equipment which is a trivial activity.

Part 7 requires fuel-burning and refuse-burning equipment to be operated to minimize emissions

of VOC. Temperature and available air must be sufficient to provide essentially complete

combustion.

Part 7 requires all effluent water separator openings, which receive water containing more than

200 gallons per day of any VOC, to be sealed or the separator to be equipped with an external


floating roof or a fixed roof with an internal floating roof or a vapor recovery system. There are

no effluent water separators located at this facility.

Part 7 also requires all reciprocating pumps and compressors handling VOCs to be equipped with

packing glands and rotating pumps and compressors handling VOCs to be equipped with

mechanical seals. All of the pumps and compressors at this facility are subject to these

requirements.

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.

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

OAC 252:100-11 Alternative Reduction not requested

OAC 252:100-15 Mobile Sources not in source category

OAC 252:100-17 Incinerators not type of emission units

OAC 252:100-23 Cotton Gins not type of emission unit

OAC 252:100-24 Feed & Grain Facility not in source category

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

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


SECTION VI. FEDERAL REGULATIONS

PSD, 40 CFR Part 52 [Not Applicable]

Total potential emissions of SO2 are greater than the PSD threshold of 250 TPY. Any future

emission increases must be evaluated for PSD if they exceed a significance level (40 TPY NOX,

100 TPY CO, and 40 TPY VOC).

NSPS, 40 CFR Part 60 [Subpart KKK Applicable]

Subpart Kb, VOL Storage Vessels, regulates hydrocarbon storage tanks larger than 19,813 gallons

capacity and built after July 23, 1984. There is only one condensate tank with a capacity of

12,600 gallons on-site which is less than the lowest threshold level of 19,813 gallons.

Subpart GG, Stationary Gas Turbines. This subpart affects turbines which commenced

construction, reconstruction, or modification after October 3, 1977, with heat input at peak load

of greater than or equal to 10 MMBTUH based on the lower heating value of the fuel. There are

no turbines on-site.

Subpart VV, Equipment Leaks of VOC in the Synthetic Organic Chemical Manufacturing

Industry. The equipment is not in a SOCMI plant.

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

subpart applies to affected facilities that commence construction, reconstruction, or modification

after January 20, 1984. Affected facilities include a compressor in VOC service or in wet gas

service and the group of all equipment except compressors within a process unit. A compressor

station, dehydration unit, sweetening unit, underground storage tank, field gas gathering system

or liquefied natural gas unit is covered by this subpart if it is located at an onshore natural gas

processing plant. The old cryogenic unit was manufactured in the 1960s, the Waukesha

compressors were manufactured in 1977, the dehydration unit EU-TEGV-1 was installed in

1973, and the amine unit was installed prior to 1976. The compressor for engine CM-9 is

manufactured after January 20, 1984, but is not in wet service. The JT-Plant installed in 2007, as

well as the new cryogenic plant and the two dehydrator proposed in this permit are subject to this

subpart. The compressors for Engines CM-6, CM-7, and CM-8 are manufactured after January

20, 1984 and are in wet gas service, thus they are subject to this subpart. Per 60.633(f),

reciprocating compressors in wet gas service are exempt from the compressor control

requirements of 60.482-3. Therefore, these three compressors are only subject to the

recordkeeping requirements of 60.635(c). However, associated equipment such as valves and

connectors are still subject to the monitoring requirement of this subpart. All valves and

flanges/connectors associated with the cryogenic plant are subject to this subpart.

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

units and sweetening units followed by a sulfur recover unit which commence construction or

modification after January 20, 1984. The amine regenerator was installed prior to 1976 and is

not applicable to this subpart because it was constructed prior to the effective date of this

standard.

Subpart IIII, 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. There are no stationary compression ignition

internal combustion engines at this facility.


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 all new SI engines ordered after June 12, 2006 and all SI

engines modified or reconstructed after June 12, 2006, regardless of size. The specific emission

standards (either in g/hp-hr or as a concentration limit) vary based on engine class, engine power

rating, lean-burn or rich-burn, fuel type, duty (emergency or non-emergency), and 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). Applicability of this subpart to engines CM-8 and CM-9 will be

determined in the operating permit. The other engines were installed prior to June 12, 2006 and

are not subject to this subpart.

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. Analysis of Oklahoma natural gas indicates a maximum

benzene content of less than 1%.

NESHAP, 40 CFR Part 63 [Applicable]

Subpart HH, Oil and Natural Gas Production Facilities: Area Sources. The final rule for area

sources were promulgated on January 3, 2007. This final rule affects each TEG dehydration unit

located at an area source oil and natural gas production facility that processes, upgrades, or stores

hydrocarbon liquids to the point of custody transfer and natural gas from the well up to and

including the natural gas processing plant. Sources with either an annual average natural gas

flow rate less than 3 MMSCF/D or benzene emissions less than 1.0 TPY are exempt from control

requirements. The three dehydrators at this facility emits 0.2 TPY of benzene and are only

required to keep records of the determination of these criteria as required in 63.774(d)(1).

Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart previously

affected only RICE with a site-rating greater than 500 brake horsepower that are located at a

major source of HAP emissions. On January 18, 2008, the EPA published a final rule that

promulgates standards for new and reconstructed engines (after June 12, 2006) with a site rating

less than or equal to 500 HP located at major sources, and for new and reconstructed engines

(after June 12, 2006) located at area sources. Owners and operators of new or reconstructed

engines at area sources and of new or reconstructed engines with a site rating equal to or less than

500 HP located at a major source (except new or reconstructed 4-stroke lean-burn engines with a

site rating greater than or equal to 250 HP and less than or equal to 500 HP located at a major

source) must meet the requirements of Subpart ZZZZ by complying with either 40 CFR Part 60

Subpart IIII (for CI engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines). Owners and

operators of new or reconstructed 4SLB engines with a site rating greater than or equal to 250 HP

and less than or equal to 500 HP located at a major source are subject to the same MACT

standards previously established for 4SLB engines above 500 HP at a major source, and must


also meet the requirements of 40 CFR Part 60 Subpart JJJJ, except for the emissions standards

for CO. Applicability of this subpart will be determined in the operating permit.

Subpart DDDDD, Industrial Boilers and Process Heaters. Subpart DDDDD regulated HAP

emissions from industrial boilers and process heaters. In March, 2007, the EPA filed a motion to

vacate and remand this rule back to the agency. The rule was vacated by court order, subject to

appeal, on June 8, 2007. No appeals were made and the rule was vacated on July 30, 2007.

Existing and new small gaseous fuel boilers and process heaters (less than 10 MMBtu/hr heat

rating) were not subject to any standards, recordkeeping, or notifications under Subpart DDDDD.

EPA is planning on issuing guidance (or a rule) on what actions applicants and permitting

authorities should take regarding MACT determinations under either Section112(g) or Section

112(j) for sources that were affected sources under Subpart DDDDD and other vacated MACTs.

It is expected that the guidance (or rule) will establish a new timeline for submission of section

112(j) applications for vacated MACT standards. At this time, AQD has determined that a

112(j) determination is not needed for sources potentially subject to a vacated MACT, including

Subpart DDDDD. This permit may be reopened to address Section 112(j) when necessary.

CAM, 40 CFR Part 64 [Applicable]

Compliance Assurance Monitoring (CAM), as published in the Federal Register on October 22,

1997, applies to any pollutant specific emission unit at a major source, that is required to obtain a

Title V permit, if it meets all of the following criteria:

It is subject to an emission limit or standard for an applicable regulated air pollutant.

It uses a control device to achieve compliance with the applicable emission limit or standard.

It has potential emissions, prior to the control device, of the applicable regulated air

pollutant in excess of major source levels.

EU-CM-1 and EU-CM-2 are subject to emission limits, have potential emissions above 100 TPY

without control, and utilize catalytic converters to achieve compliance, thus they are subject to

CAM. Specifications for CAM for these units are incorporated in the permit. The dehydrators

are subject to emission limits and will be equipped with a control, but potential emissions are

below 100 TPY without control, therefore not subject to this subpart.

Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable]

The definition of a stationary source does not apply to transportation, including storage incident to

transportation, of any regulated substance or any other extremely hazardous substance under the

provisions of this part. The definition of a stationary source also does not include naturally

occurring hydrocarbon reservoirs. Naturally occurring hydrocarbon mixtures, prior to entry into a

natural gas processing plant or a petroleum refining process unit, including: condensate, crude oil,

field gas, and produced water, are exempt for the purpose of determining whether more than a

threshold quantity of a regulated substance (Section 112r of the Clean Air Act 1990 amendment) is

present at the stationary source.


Stratospheric Ozone Protection, 40 CFR Part 82 [Subpart A and F Applicable]

These standards require phase out of Class I & II substances, reductions of emissions of Class I

& II substances to the lowest achievable level in all use sectors, and banning use of nonessential

products containing ozone-depleting substances (Subparts A & C); control servicing of motor

vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations

which meet phase out requirements and which maximize the substitution of safe alternatives to

Class I and Class II substances (Subpart D); require warning labels on products made with or

containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon

disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds

under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons

(Subpart H).

Subpart A identifies ozone-depleting substances and divides them into two classes. Class I

controlled substances are divided into seven groups; the chemicals typically used by the

manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform

(Class I, Group V). A complete phase-out of production of Class I substances is required by

January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are

hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs.

Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances,

scheduled in phases starting by 2002, is required by January 1, 2030.

This facility does not utilize any Class I & II substances.

SECTION VII. COMPLIANCE

Tier Classification and Public Review

This application has been determined to be a Tier II based on the request for a significant

modification to a Part 70 source construction permit.

The permittee has submitted an affidavit that they are not seeking a permit for land use or for any

operation upon land owned by others without their knowledge. The affidavit certifies that the

applicant owns the property.

The applicant will publish a “Notice of Filing a Tier II Application” and a “Notice of Draft Tier

II Permit” in a local newspaper. The draft permit is also available for public review on the Air

Quality section of the DEQ web page at http://www.deq.state.ok.us. Applicant has requested

concurrent public and EPA review, the draft permit will also be sent to EPA Region VI as

“Proposed” for a concurrent 45-day review period. This facility is located within 50 miles of the

border of Texas and Oklahoma. A Notice has been provided to the state of Texas.

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 property.

http://www.deq.state.ok.us/


Fee Paid

Construction permit fee of $1500.

SECTION VIII. SUMMARY

The applicant has demonstrated the ability to achieve compliance with all applicable Air Quality

Rules. Ambient air quality standards are not threatened at this site. There are no active Air

Quality compliance or enforcement issues. Issuance of the construction permit is recommended,

contingent on public and EPA review.

DRAFT/PROPOSED

PERMIT TO CONSTRUCT

AIR POLLUTION CONTROL FACILITY

SPECIFIC CONDITIONS

Madill Gas Processing Company, L.L.C. Permit Number 2004-030-C (M-6)

Madill Gas Plant

The permittee is authorized to construct in conformity with the specifications submitted to Air

Quality on February 4, 2009. The Evaluation Memorandum, dated March 16, 2009, explains the

derivation of applicable permit requirements and estimates of emissions; however, it does not

contain operating limitations or permit requirements. Commencing construction or operation

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)]

EUG-2: Compressor Engines

EU Point Description Size

HP

Construction/

Manufactured Date


Engine

1,232 2003/1975


Engine

1,232 2002/1977

EU-CM-3 P-CM-3 Waukesha L7042G Engine 896 2004/1975

EU-CM-6 P-CM-6 Caterpillar 3516 Low NOx 1,340 2003/2003

EU-CM-7 P-CM-7 White/Superior 16SGTB 2,650 2005/2005

EU-CM-8 P-CM-8 Caterpillar G3516TALE 1,340 2008

EU-CM-9 P-CM-9 Caterpillar G3516TALE 1,340 2009

EU NOx CO VOC


EU-CM-1 4.10 17.96 6.15 26.94 0.90 3.95

EU-CM-2 4.10 17.96 6.15 26.94 0.90 3.95

EU-CM-3 3.95 17.30 5.92 25.93 0.79 3.46

EU-CM-6 4.43 19.39 5.61 24.56 1.36 5.95

EU-CM-7 8.76 38.37 1.87 8.18 0.7 3.07

EU-CM-8 5.90 25.86 2.95 12.93 0.27 1.16

EU-CM-9 5.90 25.86 2.95 12.93 0.27 1.16

SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 2

EUG-3: Generators

EU Point Description HP Serial # Const. Date

EU-GEN-1 P-GEN-1 Cummins V-12 350 10354249 2005


Generator

653 1005435 2008

EU NOx CO VOC


EU-GEN-1 6.59 28.85 11.09 48.55 0.09 0.39

EU-GEN-2 2.88 12.60 4.32 18.90 0.29 1.26

The third generator is a grandfathered unit, which is limited to the existing equipment as it is.

EU Point Description HP Serial # Const. Date


Generator

653 1031668 1957

Only one generator shall operate at a time, the other two may only operate as a backup.

EUG-4: Dehydrators.

EU VOC

lb/hr TPY

EU-TEGV-1 0.33 1.47

EU-TEGV-2 0.35 1.52

EU-TEGV-3 0.39 1.69

EU-TEGV-1 and EU-TEGV-2

a. Each shall be operated with a condenser on the still vent. The condenser off gas shall be

controlled by a combustion device with a 90% destruction efficiency.

b. All emissions from the glycol dehydration unit’s still vent shall be vented through the

condenser.

c. Each glycol dehydration unit shall be equipped with a flash tank on the rich glycol

stream. Off gases from the flash tank/separator shall be recycled for fuel.

d. The lean glycol recirculation rates of the glycol dehydration units shall not exceed 6 gpm

for TEGV-1 and 5 gpm for TEGV-2 and shall be recorded at least once per month. The

natural gas throughputs of the glycol dehydration units shall not exceed 35 MMSCFD for

TEGV-1 and 25 MMSCFD for TEGV-2 (monthly average based on actual operation

hours).

e. With each inspection the lean glycol circulation rate shall be recorded as follows:

i. Circulation rate, as found (gal/min, strokes/min) __________

ii. Circulation rate, as left (gal/min, strokes/min) __________

iii. Date of inspection __________

iv. Inspected by __________


EU-TEGV-3

a. The lean glycol recirculation rates of the glycol dehydration unit shall not exceed 1 gpm

and shall be recorded at least once per month. The natural gas throughputs of the glycol

dehydration unit shall not exceed 1 MMSCFD (monthly average based on actual

operation hours).

EUG-5: Firetube Reboiler

This emission group consists of insignificant activities. There are no emission limits applied to

these units under Title V but they are limited to the existing equipment as it is.


Date

EU-TEGH-1 P-TEGH-1 Firetube Reboiler 0.5 S.O.94360 2006

EUG-6: Heaters

This emission group consists of insignificant activities. There are no emission limits applied to

these units under Title V but they are limited to the existing equipment as it is.


Date

EU-HTR-1 P-HTR-1 Hot Oil Heater 3.6 200RB-8211-757 1999

EU-HTR-2 P-HTR-2 Regen. Heater 1.5 114 1999



EUG-7: Storage tank VOC emissions are insignificant based on existing equipment items and do

not have a specific limitation.

EU Point Description Capacity

(gallon)

Construction Date

EU-TK-2224 P-TK-2224 Condensate Tank 126,000 2007

EU-TK-2230 P-TK-2230 Pressurized NGL Tank 30,000 2008

EUG-8: Flares

This emission group consists of grandfathered sources except for EU-F-1. There are no emission

limits applied to grandfathered units under Title V but they are limited to the existing equipment

as it is.

EU Point Description MCF/yr Construction

Date

EU-F-1 P-F-1 Amine Flare 72,550 1979

EU-F-2 P-F-2 Plant Flare 13 Pre-1972

EU-F-3 P-F-3 Emergency Flare 0 Pre-1972

a. Allowable SO2 emissions from EU-F-1 shall be calculated as the following:


Where Heat Release (MMBTUH) = Flare Gas Flow Rate (MMSCF/H)*Comingled Flare

Gas Heating Value (467 BTU/SCF).


b. The applicant shall monitor flare gas flow rate and H2S mole percent on daily basis and

shall maintain a spreadsheet that calculates actual SO2 emissions, heat release, and

allowable SO2 emissions based on the above formula on a daily basis.

EUG-09: Fugitive VOC emissions from piping/valves/connections are insignificant based on

existing equipment items and do not have a specific limitation.

2. The fuel-burning equipment shall be fired with pipeline grade natural gas or other gaseous fuel

with a sulfur content less than 343 ppmv. Compliance can be shown by the following methods: for

pipeline grade natural gas, a current gas company bill; for other gaseous fuel, a current lab analysis,

stain-tube analysis, gas contract, tariff sheet, and other approved methods. Compliance shall be

demonstrated at least once annually. [OAC 252:100-31]

3. Each engine at the facility shall have a permanent identification plate attached which shows the

make, model number, and serial number. [OAC 252:100-43]

4. EU-CM-1, EU-CM-2, EU-CM-3, and EU-GEN-2 shall be each set to operate with an Air-Fuel-

Ratio controller and with exhaust gases passing through a functional catalytic converter. EU-CM-7,

EU-CM-8, and EU-CM-9 shall each be set to operate with exhaust gases passing through a

functional oxidation catalyst.

[OAC 252:100-8-6(a)(1)]

5. At least once per calendar quarter, the permittee shall conduct tests of NOx and CO emissions

in exhaust gases from each engine listed in EUG-2 and EU-GEN-1 and EU-GEN-2 in EUG-3

under Specific Condition No. 1 and from each replacement engine/turbine when operating under

representative conditions for that period. Testing is required for any engine/turbine that runs for

more than 220 hours during that calendar quarter. 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. [OAC 252:100-8-6 (a)(3)(A)]

6. When periodic compliance testing shows engine exhaust emissions in excess of the lb/hr

limits listed 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]

7. The permittee shall test H2S concentration in the inlet gas twice a week and record the H2S

concentration at the outlet of the amine unit daily. [OAC 252:100-31-25(a)(1)]

8. Replacement (including temporary periods of 6 months or less for maintenance purposes), of the

internal combustion engines with emissions specified in this permit with engines/turbines of lesser

or equal emissions of each pollutant (in lbs/hr and TPY) are authorized under the following

conditions.

a. The permittee shall notify AQD in writing not later than 7 days in advance of start-up of

the replacement engine(s)/turbine(s). Said notice shall identify the old engine/turbine and

shall include the new engine/turbine make and model, serial number, horsepower rating,

fuel usage, stack flow (ACFM), stack temperature ( F), stack height (feet), stack diameter

(inches), and pollutant emission rates (g/hp-hr, lb/hr, and TPY) at maximum horsepower

for the altitude/location.

b. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be conducted to

confirm continued compliance with NOx and CO emissions limitations. A copy of the first

quarter testing shall be provided to AQD within 60 days of start-up of each replacement

engine/turbine. The test report shall include the engine/turbine fuel usage, stack flow

(ACFM), stack temperature (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 subject to NSPS, NESHAP, or PSD review. [OAC 252:100-8-6 (f)(2)]

d. The permittee shall calculate 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 8.a.

9. The permittee shall maintain records of operations as listed below. These records shall be

maintained on-site or at a local field office for at least five years after the date of recording and

shall be provided to regulatory personnel upon request. [OAC 252:100-8-6 (a)(3)(B)]

a. O&M log for any engine/turbine not tested in each 6 month period.

b. Periodic emission testing for each engine and replacement engine/turbine or hours of

operation if not tested each quarter.

c. For fuel(s) burned, the appropriate document(s) as described in Specific Condition 2.

d. For SO2 emissions from EU-F-1, a spread sheet that contains flare gas flow rate (daily),

H2S mole percent (daily), and calculate heat release (MMBTUH), actual SO2 emissions

(lb/hr), and allowable SO2 emissions (lb/hr) daily.

e. Generator operating hours (monthly and 12-month rolling total).

f. Glycol circulation rates and gas throughputs of glycol dehydrators, and condenser outlet

temperatures (monthly).

g. The permittee shall maintain records on-site to document total benzene emissions from

TEGV-1, TEGV-2, and TEGV-3 as less than 1 TPY to demonstrate their exempt status

with regard to 40 CFR Part 63, Subpart HH.

h. Records required by Specific Condition No. 15 for Compliance Assurance Monitoring.


i. Records required by NSPS Subpart KKK.

10. The permittee shall certify compliance with the terms and conditions of this permit. The

certification of compliance shall be submitted no later than 30 days after each anniversary of the

issuance date of the original Part 70 operating permit (7/2/1999) for this facility, to the Air

Quality Division of DEQ, with a copy to the US EPA, Region 6.

[OAC 252:100-8-6 (c)(5)(A) & (D)]

11. The following records shall be maintained on-site to verify the status of insignificant

activities. [OAC 252:100-43]

a For activities that have the potential to emit less than 5 TPY (actual) of any criteria

pollutant: the type of activities, the amount of emissions (cumulative annual).

12. The permittee shall comply with the Standards of Performance for Equipment Leaks of VOC

from Onshore Natural Gas Processing Plants NSPS Subpart KKK, for each of the affected

facilities. [40 CFR 60.630 to 60.636]

JT-Plant Installed in 2007, New Cryogenic Plant, The Two New Dehydrators

a. The owner/operator shall comply with the requirements of § 60.482-1(a), (b), and (d),

and §§ 60.482-2 through 60.482-10 except as provided in § 60.333 [§ 60.632(a)]

(1) The owner/operator shall demonstrate compliance with §§ 60.482-1 to 60.482-10

for all affected equipment within 180 days of initial startup which shall be

determined by review of records, reports, performance test results, and inspection

using methods and procedures specified in § 60.485 unless the equipment is in

vacuum service and is identified as required by § 60.486(e)(5).

[§ 60.482-1(a), (b), & (d)]

(2) The owner/operator shall comply with the monitoring, inspection, and repair

requirements, for pumps in light liquid service, of § 60.482-2(a), (b), and (c) except

as provided in §§ 60.482-2(d), (e), (f), and 60.633(d).

(3) Information and data used to demonstrate that a reciprocating compressor is in wet

gas service or is not in VOC service shall be recorded in a log that is kept in a readily

accessible location. [§§ 60.633(f), 60.635(c), & 60.486(j)]

(4) The owner/operator shall comply with the operation and monitoring requirements,

for pressure relief devices in gas/vapor service, of § 60.482-4(a) and (b) except as

provided in §§ 60-482-4(c) and 60.633(b).

(5) Sampling and connection systems are exempt from the requirements of § 60.482-5.

[§ 60.633(c)]

(6) Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a

second valve, except as provided in § 60.632(c). The cap, blind flange, plug, or

second valve shall seal the open end at all times except during operations requiring

process fluid flow through the open-ended valve or line. Each open-ended valve or

line equipped with a second valve shall be operated in a manner such that the valve

on the process fluid end is closed before the second valve is closed. When a

double block-and-bleed system is being used, the bleed valve or line may remain


open during operations that require venting the line between the block valves but

shall be closed at all other times. [§ 60.482-6]

(7) The owner/operator shall comply with the monitoring, inspection, and repair

requirements, for valves in gas/vapor service and light liquid service, of § 60.482-

7(b) through (e), except as provided in §§ 60.633(d), 60.482-7(f), (g), and (h),

60.483-1, 60.483-2, and 60.482-1(c). [§ 60.482-7(a)]

(8) The owner/operator shall comply with the monitoring and repair requirements, for

pumps and valves in heavy liquid service, pressure relief devices in light liquid or

heavy liquid service, and flanges and other connectors, of § 60.482-8(a) through

(d). [§ 60.482-8]

(9) Delay of repair of equipment is allowed if it meets one of the requirements of §

60.482-9(a) through (e).

(10) The owner/operators using a closed vent system and control device to comply with

these provisions shall comply with the design, operation, monitoring and other

requirements of § 60.482-10(b) through (g). [§ 60.482-10(a)]

b. An owner/operator may elect to comply with the alternative requirements for valves of

§§ 60.483-1 and 60.483-2. [§ 60.632(b) & § 60.482-1(b)]

c. An owner/operator may apply to the Administrator for permission to use an alternative

means of emission limitation that achieves a reduction in emissions of VOC at least

equivalent to that achieved by the controls required in NSPS Subpart KKK. In doing so,

the owner or operator shall comply with requirements of § 60.634. [§ 60.632(c)]

d. The owner/operator shall comply with the test method and procedures of § 60.485

except as provided in §§ 60.632(f) and 60.633(h). [§ 60.632(d)]

e. The owner/operator shall comply with the recordkeeping requirements of § 60.486 and

the reporting requirements of § 60.487 except as provided in §§ 60.633, 60.635, and

60.636. [§ 60.632(e)]

f. The owner/operator shall comply with the recordkeeping requirements of § 60.635(b)

and (c) in addition to the requirements of § 60.486. [§ 60.635(a)]

g. The owner/operator shall comply with the reporting requirements of § 60.636(b) and (c)

in addition to the requirements of § 60.487. [§ 60.636(a)]

Compressors for Engines CM-6, CM-7, and CM-8

- Information and data used to demonstrate that a reciprocating compressor is in wet gas

service to apply for the exemption in 60.633 (f) shall be recorded in a log that is kept in

a readily accessible location.

Valves Associated with Compressors for Engines CM-6 and CM-7 and with JT-Plant

a. The owner/operator shall comply with the monitoring, inspection, and repair

requirements, for valves in gas/vapor service and light liquid service, of § 60.482-7(a)

through (e), except as provided in §§ 60.633(d), 60.482-7(f), (g), and (h), 60.483-1,

60.483-2, and 60.482-1(c). [§ 60.482-7(a)]

b. An owner/operator may elect to comply with the alternative requirements for valves of

§§ 60.483-1 and 60.483-2. [§ 60.632(b) & § 60.482-1(b)]


c. An owner/operator may apply to the Administrator for permission to use an alternative

means of emission limitation that achieves a reduction in emissions of VOC at least

equivalent to that achieved by the controls required in NSPS Subpart KKK. In doing so,

the owner or operator shall comply with requirements of § 60.634. [§ 60.632(c)]

d. The owner/operator shall comply with the test method and procedures of § 60.485

except as provided in §§ 60.632(f) and 60.633(h). [§ 60.632(d)]

e. The owner/operator shall comply with the recordkeeping requirements of § 60.486 and

the reporting requirements of § 60.487 except as provided in §§ 60.633, 60.635, and

60.636. [§ 60.632(e)]

f. The owner/operator shall comply with the recordkeeping requirements of § 60.635(b)

and (c) in addition to the requirements of § 60.486. [§ 60.635(a)]

g. The owner/operator shall comply with the reporting requirements of § 60.636(b) and (c)

in addition to the requirements of § 60.487. [§ 60.636(a)]

13. The Permit Shield (Standard Conditions, Section VI) is extended to the following

requirements that have been determined to be inapplicable to this facility:

[OAC 252:100-8-6(d)(2)]

a. 40 CFR Part 57, Primary Nonferrous Smelter Orders

b. 40 CFR Part 60, New Source Performance Standards (NSPS), Subpart K

c. 40 CFR Part 60, NSPS, Subpart Ka

d. 40 CFR Part 60, NSPS, Subpart Kb

e. 40 CFR Part 60, NSPS, Subpart GG

f. 40 CFR Part 61, National Emission Standards for Hazardous Air Pollutants

(NESHAP)

g. 40 CFR Part 63, NESHAP, Subpart HHH

h. 40 CFR Parts 72-78, Acid Rain Program

i. OAC 252:100-7, Permits for Minor Facilities

j. OAC 252:100-8-4 (a)(2), Case-by-Case MACT

k. OAC 252:100-15, Mobile Sources

l. OAC 252:100-17, Incinerators

m. OAC 252:100-23, Cotton Gins

n. OAC 252:100-24, Grain Elevators

o. OAC 252:100-39, Nonattainment Areas

p. OAC 252:100-47, Municipal Solid Waste Landfills

q. OAC 252:100-33, Control of Emissions of Nitrogen Oxides

r. OAC 252:100-35, Control of Emission of Carbon Monoxide

14. The permittee shall apply for a modification to the issued Title V operating permit renewal

(2003-030-TVR) within 180 days of commencement of operations.


15. Engines EU-CM-1 and EU-CM-2 are subject to Compliance Assurance Monitoring (CAM)

and shall comply with all applicable requirements and shall perform monitoring as approved

below. Indicator No. 1 Indicator No. 2 Indicator No. 3* Indicator No 4*

I. Indicator O2 from engines Pressure drop across

the catalyst.

Temperature of

exhaust gas into

catalyst.

Temperature of

exhaust gas out of

catalyst.

Measurement

Approach

O2 concentration into

the catalyst is

measured

continuously using an

in-line O2 sensor.

Pressure drop across

the catalyst beds is

measured monthly

using a differential

pressure gauge or a

water manometer.

Exhaust gas

temperature is

measured


in-line thermocouple.

Exhaust gas

temperature is

measured


in line thermocouple.

II. Indicator Range The indicator is

alarm-based. The

indicator range is no

alarmed event lasting

30 minutes or longer.

Excursions trigger

corrective action,

logging and reporting

in semiannual report.

The indicator range is

a pressure drop

deviation of less than

2 in. H2O from the

benchmark.

Excursions trigger

corrective action,


in semiannual report


above 750oF, but

lower than 1,250oF.

Excursions trigger

corrective action,




above 800oF, but

lower than 1,300oF.

Excursions trigger

corrective action,



III. Performance

Criteria

A. Data

Representa-

iveness

Observations are

performed at the

engine exhaust while

the engine is

operating.

Pressure drop across

the catalyst is

measured at the

catalyst inlet and

exhaust. The

minimum accuracy of

the device is ±0.25 in.

H2O.

Temperature is

measured at the inlet

to the catalyst by a

thermocouple. The

minimum accuracy is

±5oF.

Temperature is

measured at the outlet

of the catalyst by a

thermocouple. The

minimum accuracy is

±5oF.

B. QA/QC –

Practices and

Criteria

O2 sensor replaced

quarterly.

Pressure gauge

calibrated quarterly.

Pressure taps checked

monthly for plugging.

Thermocouple

visually checked

quarterly and tested

/replaced annually.

Thermocouple

visually checked

quarterly and tested

/replaced annually.

C. Monitoring

Frequency

O2 percent monitored

continuously.

Pressure drop is

measured monthly.

Temperature is

measured at least

daily when operated.

Temperature is

measured at least

daily when operated.

D. Data

Collection

Procedures

Records are

maintained to

document alarmed

events and any

required maintenance.

Records are

maintained to

document monthly

readings and any

required maintenance.

A strip chart records

the temperature

continuously or an

operator or computer

may record at least

once per day**.

A strip chart records

the temperature

continuously or an

operator or computer

may record at least

once per day**.

E. Averaging

period

None, not to exceed

maximum.

None, not to exceed

maximum.

None, not to exceed

minimums and

maximums.

None, not to exceed

minimums and

maximums.

*Minimum requirement is to include at least one of these two indicators.

**Both engines have controlled emissions less than 100 TPY, therefore, recording the

temperature once per day is acceptable.

DEQ Form #100-885 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. 2004-030-C (M-6)


having complied with the requirements of the law, is hereby granted permission to operate

the Madill Gas Plant located at Section 32, T5S, R7E, near Madill, Marshall County,

Oklahoma, subject to standard conditions dated December 22, 2008 and specific conditions,

both attached.

This permit shall expire 18 months from the issuance date, except as Authorized under

Section B of the Standard Conditions.

_________________________________

Division Director, Air Quality Division Date

Mr. Robert Mitchell


6120 S. Yale, Suite 1640

Tulsa, OK 74136

Subject: Operating Permit No. 2004-030-C (M-6)

Madill Gas Plant

Madill, Marshall County

Dear Mr. Mitchell:

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) 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.

In addition, you are also required to publish a Notice of Filing Tier II Air Quality Application in

at least one newspaper of general circulation within the county where the facility is located.

(Instruction enclosed) and send to AQD a copy of the proof of publication notice.

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, Jian Yue, at (405) 702-4205.

Sincerely,

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


Enclosures

Texas Commission on Environmental Quality

Operating Permits Division (MC 163)

P.O. Box 13087

Austin, TX 78711-3087

SUBJECT: Construction Permit No. 2004-030-C (M-6)


Madill Gas Plant

Madill, Marshall County, Oklahoma

Dear Sir / Madame:

The subject facility has requested a construction permit. Air Quality Division has completed the

initial review of the application and prepared a draft permit for public review. Since this facility is

within 50 miles of the Oklahoma - Texas border, a copy of the proposed permit will be provided to

you upon request. Information on all permit and a copy of this draft permit are available for review

by the public in the Air Quality Section of DEQ Web Page: http://www.deq.state.ok.us.

Thank you for your cooperation. If you have any questions, please refer to the permit number

above and contact me or the permit writer at (405) 702-4100.

Sincerely,

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


Mr. Robert Mitchell


6120 S. Yale, Suite 1640

Tulsa, OK 74136

Subject: Operating Permit No. 2004-030-C (M-6)

Madill Gas Plant

Madill, Marshall County

Dear Mr. Mitchell:

Enclosed is the permit authorizing operation of the referenced facility. Please note that this permit is

issued subject to the certain standards 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. If you have any questions, please refer to the permit number above

and contact the permit writer at (405) 702-4100.

Sincerely,

Jian Yue, P.E.

Engineering Section


Enclosures

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