OKLAHOMA DEPARTMENT OF … OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION...
Transcript of 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
EU-CM-2 P-CM-2 Waukesha L7042 GSI
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
EU-GEN-3 P-GEN-3 Waukesha VLRO
Generator
653-hp 1031668 1957
EUG-4 Glycol Dehydrator
EU Point Description Construction Date
EU-TEGV-1 P-TEGV-1 Glycol Dehydrator 1973
EU-TEGV-2 P-TEGV-2 Glycol Dehydrator 2008
EU-TEGV-3 P-TEGV-3 Glycol Dehydrator 2009
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 3
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
EU Point Description MMBTUH Serial No. Construction
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
EU-HTR-4 P-HTR-4 Regen. Heater 0.125 2009
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
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 4
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 5
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
lb/hr TPY lb/hr TPY lb/hr TPY
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 6
Post Project Emissions
EU NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 7
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
stoichiometric ratio of 2 SCF of water per SCF of natural gas fuel.
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
stoichiometric ratio of 2 SCF of water per SCF of natural gas fuel.
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
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 8
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 9
Pollutant EU-TEGV-1 EU-TEGV-2 Total Emissions
lb/hr TPY lb/hr TPY lb/hr TPY
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
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 10
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 11
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
Maximum 3 hr. avg. 650
Maximum 24 hr. avg. 130
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).
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 12
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 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
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 13
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
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 14
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 15
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
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 16
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 17
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.
PERMIT MEMORANDUM 2004-030-C (M-6) DRAFT/PROPOSED 18
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
EU-CM-1 P-CM-1 Waukesha L7042 GSI
Engine
1,232 2003/1975
EU-CM-2 P-CM-2 Waukesha L7042 GSI
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
lb/hr TPY lb/hr TPY lb/hr TPY
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
EU-GEN-2 P-GEN-2 Waukesha VLRO
Generator
653 1005435 2008
EU NOx CO VOC
lb/hr TPY lb/hr TPY lb/hr TPY
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
EU-GEN-3 P-GEN-3 Waukesha VLRO
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 __________
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 3
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.
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
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.
EU Point Description MMBTUH Serial No. Construction
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
EU-HTR-4 P-HTR-4 Regen. Heater 0.125 2009
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:
Allowable SO2 emissions (lb/hr) = 28(Heat Release (MMBTUH) – 1) + 36
Where Heat Release (MMBTUH) = Flare Gas Flow Rate (MMSCF/H)*Comingled Flare
Gas Heating Value (467 BTU/SCF).
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 4
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
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 5
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.
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 6
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
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 7
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)]
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 8
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.
SPECIFIC CONDITIONS 2004-030-C (M-6) DRAFT/PROPOSED 9
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
continuously using an
in-line thermocouple.
Exhaust gas
temperature is
measured
continuously using an
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,
logging and reporting
in semiannual report
The indicator range is
above 750oF, but
lower than 1,250oF.
Excursions trigger
corrective action,
logging and reporting
in semiannual report.
The indicator range is
above 800oF, but
lower than 1,300oF.
Excursions trigger
corrective action,
logging and reporting
in semiannual report.
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
AIR QUALITY DIVISION
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)
Madill Gas Processing Company, L.L.C.
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
Madill Gas Processing Company, L.L.C.
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
AIR QUALITY DIVISION
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 Processing Company, L.L.C.
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
AIR QUALITY DIVISION
Mr. Robert Mitchell
Madill Gas Processing Company, L.L.C.
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
AIR QUALITY DIVISION
Enclosures