DRAFT
OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY
AIR QUALITY DIVISION
MEMORANDUM
June 8, 2007
TO:
Phillip Fielder, P.E., Engineering Manager. III, Air Quality Division
THROUGH:
Matt Paque, Supervising Attorney, Air Quality Division
THROUGH:
Kendal Stegmann, Senior Environmental Manager, Compliance and
Enforcement
THROUGH:
David Schutz, P.E., New Source Permit Section
THROUGH:
Phil Martin, P.E., Engineering Section
THROUGH:
Peer Review
FROM:
Grover R. Campbell, P.E., Existing Source Permit Section
SUBJECT:
Evaluation of Permit Application No. 2004-163-TVR (M-2)
ONEOK Field Services Company, L.L.C.
Maysville Gas Plant
Section 18, T4N, R2W, Garvin County
Latitude 34.817º, Longitude -97.453 º
Located 2 miles west the intersection of Hwy 74 & Hwy 19 in Maysville
SECTION I. INTRODUCTION
ONEOK Field Services Company, L.L.C. (OFS) has requested a significant modification of their
Part 70 permit for the Maysville Gas Plant, Permit No. 2004-163-TVR (M-1). The plant is a PSD
major source and is classified as a SIC 1321 facility. The facility is a cryogenic natural gas
liquids (NGL) extraction plant with a gas processing capacity of 137 MMSCFD. Residue gas is
delivered to a sales pipeline after the recovery of NGL. Current plant gas throughput is 80 to 90
MMSCFD. The facility was originally constructed in 1948 by Warren Petroleum Company and
consisted of 24 internal combustion engines and 5 gas-fired heaters in hot oil, steam generation,
and regeneration-gas service. The plant inlet gas contains a small amount of H2S (up to 13.5
ppm), which is removed in amine units and flared in the acid gas flare.
From 1985 to 1996, several plant modifications were permitted, in which engines were removed
and added, a new cryogenic skid was constructed, and more furnace capacity was installed. The
present facility consists of 20 grandfathered and 16 permitted internal combustion engines, 3
cryogenic skids, 5 heaters, 4 boilers, 1 glycol regeneration unit, 1 amine regeneration unit, 1
process/emergency flare, 1 VOC flare, 1 acid gas flare, 54 pressurized product storage tanks, 4
PERMIT MEMORANDUM 2004-163-TVR (M-2)
DRAFT
2
pressurized spheroid tanks, 2 methanol storage tanks, 2 scrubber oil tanks, 1 condensate tank, 1
water/condensate pit tank, 1 gasoline storage tank, 1 Stoddard solvent tank, and miscellaneous
smaller tanks.
On June 4, 2004, OFS submitted three self-disclosures pertaining to (1) NAAQS for NOX
emissions, (2) MAAC for formaldehyde, (3) NESHAP Subpart HH, (4) NSPS Subpart KKK, and
(5) general control requirements for flares. The TVR application contained compliance plans to
address each of these issues. OFS submitted quarterly progress reports to update the status of
compliance during the Part 70 permit application review period, including the notifications
required by NESHAP Subpart HH and NSPS Subpart KKK. A compliance plan to bring the
facility in compliance with the NAAQS for NOX emissions was submitted to ODEQ and became
a part of Consent Order 06-063. Consent Order 06-063 also placed some additional requirements
on the facility. The TVR was issued with completion of the NAAQS for NOX compliance plan
as a permit specific condition. The facility has made combustion modifications to engines in
EUG-1 and in March of 2007 submitted air dispersion modeling which demonstrates compliance
with the NAAQS for NOX.
For modification (M-1), OFS requested that the procedure for monitoring the amount of H2S
combusted in the acid gas flare be revised to allow calculations using either measurement of the
amount of H2S concentration and flow of inlet gas streams, or using measurement of the amount
of H2S concentration and flow of the total acid gas stream between the amine contactors and the
acid gas flare. OFS also requested a change in the data collection procedures for Indicator No. 1,
flare flame indicator for the CAM plan for the glycol dehydration unit. These proposed changes
were minor and the application was processed under Tier I.
For this modification (M-2), OFS has requested a federally enforceable condition to limit the
horsepower for five generators so that they will be exempt from emissions and operating
limitations under 40 CFR Part 63 Subpart ZZZZ (RICE MACT). OFS has also requested that
emissions factors for engines in EUG-1 be revised as part of the compliance plan required by
Consent Order 06-063 dated April 6, 2006, to demonstrate compliance with the NAAQS for
NOX. OFS has also requested that language be included in the modified permit to clarify
applicability of 40 CFR Part 60 Subpart NNN.
The five generator engines are 1948 vintage Ingersoll-Rand PKVG-6 four-stroke rich-burn
engines that are factory rated at 660-hp. While designated as rich-burn engines, the engines run
with oxygen exhaust concentrations ranging from near 3% down to 1%. It could be argued that
the engines are actually existing lean-burn engines (defined in the RICE MACT as an engine that
has 2% oxygen in the exhaust), which would exempt them from the RICE MACT. Also, the
exhaust temperatures of the engines are typically less than 600°F and OFS has been unable to
find a NSCR catalyst vendor who would guarantee the formaldehyde removal efficiency
necessary to be in compliance with the RICE MACT. In addition, the RICE MACT requires
compliance with a minimum catalyst inlet temperature of 750°F, which the engines do not
obtain. In order to resolve the site specific problems for complying with the RICE MACT for
these 50 year old engines, OFS has requested and AQD (Permitting, Compliance, and Legal)
have agreed to allow the source to take federally enforceable limitations on engine horsepower
PERMIT MEMORANDUM 2004-163-TVR (M-2)
DRAFT
3
such that the site-rated horsepower would be considered less than 500-hp. The existing engines
will then be exempt from the RICE MACT standards. The limit will be enforced by placing a
generator output limit of 330-KW on each engine. This power output is equivalent to an engine
power output of less than 500-hp when considering the mechanical efficiency and shaft losses for
the generator sets. AQD and OFS have agreed to issuance of a Consent Order to make these
limitations enforceable prior to the RICE MACT compliance date of June 15, 2007.
SECTION II. PROCESS DESCRIPTION
The plant inlet gas consists of multiple low-pressure (~5 psig) and high-pressure (~200 psig)
streams. The inlet gas is compressed to about 730 psig before processing. Inlet gas flows to the
amine contactor towers (north amine unit and south amine unit) where all of the H2S and part of
the CO2 is removed. Rich amine from two contactors flows to rich amine flash tanks, which are
vented to the acid gas flare. Rich amine from the flash tanks flows to the amine regeneration
stills where the acid gas is removed overhead. The acid gas is vented to the acid gas flare for
incineration of the H2S.
Sweetened gas is processed in three NGL recovery process skids operate in parallel with about
60% inlet gas through Skid #3, 30% through Skid #1, and 10% through Skid # 2. The sweetened
gas in skids #1 and #2 flows through molecular sieve beds for dehydration. Gas-fired heaters
supply the heat for molecular sieve regeneration. The sweetened gas in skid #3 flows through a
glycol contactor for dehydration. Rich glycol from the contactor flows to the rich glycol flash
tank, which is vented to the low-pressure inlet gas stream. Rich glycol from the flash tank flows
to the glycol regeneration still for removal of absorbed water. Vapors (water, VOC, and HAPs)
from the glycol still are vented through a condenser and any remaining vapors are either recycled
to the low-pressure inlet gas stream or vented to the plant’s process/emergency flare (PFL-1).
The propane refrigeration compressor seals and product pump seals are vented to the VOC flare.
After dehydration, the sweet and dry inlet gas is processed through a cryogenic unit on each skid
to recover NGL. Overhead gas from the demethanizer towers is sent to a natural gas pipeline.
The demethanizer bottoms (raw NGL) contain ethane and heavier hydrocarbons. All of the raw
NGL flows to a single NGL fractionation train for separation of NGL products. The fractionation
train consists of a deethanizer, depropanizer, de-butanizer, and deisobutanizer columns. An
ethane-propane (EP) product is shipped directly via pipeline. The other NGL products, propane,
iso-butane, normal butane, and #14 gasoline, are stored in bullet tanks and spheroid tanks before
shipment either by tank trucks or by pipeline. All of the above tanks are pressurized with
working pressures ranging from 5 to 200 psig.
Low-pressure inlet gas scrubbers remove condensate (oil & water) prior to compression of the
natural gas. These fluids are dumped to condensate tank #19 (TK-1), which is vented to the plant
process/emergency flare. Lighter condensate from the compressor interstage scrubbers flows to a
condensate stabilizer system where light-end hydrocarbons are stripped out and returned to the
plant inlet gas stream. The stabilized heavier hydrocarbon liquids are stored in four pressurized
bullet tanks before leaving the facility via pipeline. Water/condensate from these four bullet
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
4
tanks also flows to condensate tank #19 (TK-1). Liquids from tank #19 flow to scrubber oil
tanks (TK-2 and TK-3) for further oil/water separation. These tanks also receive scrubber oils
and drip from remote locations. Separated scrubber oil and condensate are transported off-site by
truck. Any overflow from these tanks is temporarily stored in a 100-barrel wastewater open-top
pit tank (TK-4). Bottom sediment and water (BS&W) from this tank and other open pits is
emptied by vacuum truck for off-site disposal.
SECTION III. EQUIPMENT
Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) as follow. All fuelburning units at the station use pipeline-quality natural gas or field gas with a sulfur content of
less than 343-ppmv. The engines operate continuously.
EUG-1. Grandfathered Engines
EU
C-1
C-2
C-3 (2)
C-4 (2)
C-5 (2)
C-6 (2)
C-7
C-8 (2)
C-9 (2)
C-10 (2)
C-11 (2)
C-12
C-13 (2)
C-14
C-15
G-1 (3)
G-2 (3)
G-3 (3)
G-4 (3)
G-5 (3)
Point
P-1
P-2
P-3
P-4
P-5
P-6
P-7
P-8
P-9
P-10
P-11
P-12
P-13
P-14
P-15
P-30
P-31
P-32
P-33
P-34
Make/Model
Clark RA-8
Clark RA-8
Clark RA-8
Clark RA-6
Clark RA-6
Clark RA-8
Clark RA-8
Clark HRA-8
Clark HRA-8
Clark HRA-8
Clark HBA-8
Clark HBA-8
Clark HBA-8
Clark HBA-5
Clark HBA-5
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
HP
800
800
800
600
600
800
800
880
880
880
1,760
1,760
1,100
<500
<500
<500
<500
<500
Serial #
25938
25937
25936
21133
21132
25927
25928
A25567
A25568
A25572
30269
30271
35601
6HZ131
6HZ132
6HZ134
6HZ136
6NZ182
Construction Date
1948
1948
1948
1948
1948
1948
1948
1948
1948
1948
1948
(1)
1948
1948
(1)
1948
1948
1948
1948
1948
1. Engine C-12 was permanently shutdown on July 19, 2003 per C.O. 03-165. Engine C-15
has been permanently removed from service.
2. These engines have modified pressure fuel systems installed per Consent Order 06-063,
but are considered “existing engines” for purposes of MACT Subpart ZZZZ and
permitting. See AD # 97-222-AD (M-3) dated June 20, 2005.
3. Factory rating is 660-hp, but the engines will be limited to <500-hp by limiting actual
KW power production from each engine to 330-KW based on a 30-day rolling average.
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
5
EUG-2. Permitted Engines
EU
C-16 (1)
C-17 (1)
C-18 (1)
C-19 (1)
C-20
C-21 (2)
C-22
C-23 (1)
C-24 (1)
C-25.3
C-26
C-27
C-28
C-29
G-6 (1)
G-7 (1)
Point
P-16
P-17
P-18
P-19
P-20
P-21
P-22
P-23
P-24
P-25
P-26
P-27
P-28
P-29
P-35
P-36
Make/Model
Waukesha L7042 GSIU
Waukesha L7042 GSIU
Waukesha L7042 GSIU
Waukesha L5108 GU
Superior 16GTLA
Superior 16GTLA
Superior 16GTLA
Superior 8G825
Superior 6G825
Superior 8GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Waukesha L3711
Waukesha L3711
HP
922
922
922
492
2,078
2,078
2,078
800
600
1,039
1,558
1,558
1,558
1,558
335
335
Serial #
387562
387563
387652
387653
306999
306599
291649
282349
292229
293159
304699
304979
304989
295909
48027
48028
Construction Date
12/13/84
12/14/84
12/15/84
1/11/85
~12/12/85
~10/12/85
~7/91
~12/91-1/92
12/82
03/05
~6/86
~6/86
~6/86
2/12/90
1990
1990
1. With NSCR and AFRC.
2. Overhauled in 2003 per C.O. 03-165.
EUG-3. Tanks
EU
TK-1
TK-2
TK-3
TK-4
TK-5
TK-6
TK-7
TK-8
Point
P-50
P-51
P-52
P-53
P-54
P-55
P-56
P-57
Contents
Condensate / BS&W
Scrubber Oil, North
Scrubber Oil, South
BS&W / Condensate
Methanol
Methanol
Gasoline
Solvent < 1.5 psia vapor pressure
Gallons
23,400
23,200
22,000
4,200
8,820
1,730
3,000
580
Construction Date
pre 1974
pre 1974
pre 1974
post 1974
pre 1974
post 1974
post 1974
post 1974
EUG-4. Fugitive Components (Not Subject to NSPS Subpart KKK or MACT Subpart HH)
EU
FUG-1
Type of Equipment
Connectors
Valves
Open Ended Lines
Flanges
Compressor Seals
Pump Seals
Relief Valves
Estimated Number of Items
7,000
3,500
280
4,378
56
113
38
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
EUG-5. Fugitive Components (Subject to NSPS Subpart KKK)
EU
Type of Equipment
Connectors
Valves
Open Ended Lines
Flanges
Compressor Seals
Pump Seals
Relief Valves
FUG-2
Estimated Number of Items
5,802
2,901
232
3,626
25
-
EUG-6. Heaters & Boilers
EU
H-1
H-2
H-3
H-4
H-5
H-6
H-7
B-1
B-2
Point
Equipment
P-37
P-38
P-39
P-40
P-41
P-42
P-43
P-44
P-45
MMBtu/hr
Hot Oil Heater (West)
Hot Oil Heater (East)
Regen. Gas Heater (Plant #1)
Regen. Gas Heater (Plant #2)
Glycol Reboiler
Amine Reboiler
Regen. Gas Heater (Plant #3)
Boiler #1 (North, OK36454)
Boiler #2 (South, OK43476)
49.8
41.5
5.0
1.5
1.5
5.25
7.5
2.0
2.0
Serial #
617
620
75122
41593
0132
5991
1276
1740
9777
Construction
Date
1997 (1)
1948
1976
1985
1985
1985
1985
1976
1988
1. Modified in October 1997 with more efficient burners.
EUG-7. Process/Emergency Flare
EU
Point
MMBtu/hr
PFL-1
FL-1
27,000
Diameter,
inches
24
Height,
feet
110
Construction
Date
1948
Diameter,
inches
24
Height,
feet
110
Construction
Date
1985
EUG-8. Acid Gas Flare
EU
Point
MMBtu/hr
AU-1
FL-1
1.5
Note: The acid gas flare runs up the side of the process/emergency flare.
Equipment vented to the acid gas flare includes the DGA north
amine treater (Plants 1 and 2) and the DEA south amine treater
(Plant 3).
6
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
EUG-9. VOC Flare
EU
Point
MMBtu/hr
FL-2
FL-2
40
Diameter,
inches
12
Height,
feet
15
Construction
Date
1986
EUG-10. Glycol Dehydration Unit
EU
D-1
Point
FL-1
Equipment
Still Overhead Vent
Construction Date
1986
EUG-11. Condensate/Scrubber Oil Truck Loading
EU
TL-1
Point
TL-1
Equipment
Truck Loading
Construction Date
1948
EUG 12. Fugitive Components (Subject to NESHAP Subpart HH)
EU
FUG-3
Type of Equipment
Connectors
Valves
Pressure Relief Valves
Pump Seals
Estimated Number of
Items
Natural
Condensate
Gasoline
2,187
10
625
325
19
19
5
4
EUG-13. Miscellaneous Venting Activities
EU ID #
VENT
Point #
VENT
Emission Units
Miscellaneous Process Vents
Date Constructed
1948
EUG-FW. Facility-Wide Emissions
Engine Stack Parameters
EU
C-1A, B *
C-2A, B *
C-3A, B *
C-4A, B *
C-5A, B *
C-6
Source
Clark RA-8
Clark RA-8
Clark RA-8
Clark RA-6
Clark RA-6
Clark RA-8
Height,
feet
40
40
40
41
41
43
Diameter,
inches
10
10
10
10
10
10
Flow,
ACFM
3,540
3,540
3,540
2,598
2,598
3,539
Temp,
F
725
725
725
700
700
725
7
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
EU
C-7A, B *
C-8
C-9
C-10
C-11
C-12
C-13
C-14
C-15
C-16
C-17
C-18
C-19
C-20
C-21
C-22
C-23
C-24
C-25.3
C-26
C-27
C-28
C-29
G-1
G-2
G-3
G-4
G-5
G-6
G-7
*
Source
Clark RA-8
Clark HRA-8
Clark HRA-8
Clark HRA-8
Clark HBA-8
Clark HBA-8 (removed)
Clark HBA-8
Clark HBA-5
Clark HBA-5 (removed)
Waukesha L7042 GSIU
Waukesha L7042 GSIU
Waukesha L7042 GSIU
Waukesha L5108 GU
Superior 16GTLA
Superior 16GTLA
Superior 16GTLA
Superior 8G825
Superior 6G825
Superior 8GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Waukesha L3711
Waukesha L3711
Height,
feet
42
45
45
45
56
56
24
20
20
20
26
28
28
28
18
22
16
19
19
19
21
37
37
37
37
37
27
27
Diameter,
inches
10
14
14
14
18
18
16
8
8
8
8
16
16
16
12
12
14
18
18
18
18
10
10
10
10
10
8
8
Flow,
ACFM
3,540
3,763
3,763
3,763
11,335
11,335
6,917
4,085
4,085
4,085
2,135
12,007
12,007
12,007
5,359
4,437
6,654
7,921
7,921
7,921
7,921
2,889
2,889
2,889
2,889
2,889
1,500
1,500
8
Temp,
F
725
675
675
675
875
875
800
1007
1007
1007
800
808
808
808
1,330
1,250
934
801
801
801
801
975
975
975
975
975
850
850
Dual stacks
SECTION IV. EMISSIONS
All emission estimates are based on continuous operation.
A. Criteria Emissions
NOX and CO emission factors for the Clark engines are based on stack tests and operating
experience after combustion modifications. NOX and CO emission factors for the Ingersoll Rand
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
9
engines are based on AP-42 (7/00) Table 3.2-3 and a horsepower of 499. VOC emission factors
for all engines are based on AP-42 (7/00) Tables 3.2-1 and 3.2-3.
Source
Type
Clark RA-8 and RA-6
Clark RA-8 and RA-6
(modified)
Clark HRA-8 (modified)
Clark HBA-8 (modified)
Clark HBA-5
Ingersoll-Rand PKVG-6
2SLB
Fuel,
Btu/hp-hr
9,000
2SLB
9,000
600
2SLB
2SLB
2SLB
4SRB
9,000
9,000
9,000
8,000
880
1,760
1,100
<500
HP
800
Emission Factor, g/hp-hr
NOX
CO
VOC
22
3.5
0.49
14
14
14
22
8.0
3.5
0.49
2.0
6.0
6.0
13.5
0.49
0.49
0.49
0.11
NOX, CO, and VOC emission factors for the permitted engines in EUG-2 are based on the permit
limits of Permit No. 97-222-TV.
Source
Type
Waukesha L7042 GSIU *
Waukesha L5108 GU *
Superior 16GTLA
Superior 8G825 *
Superior 6G825 *
Superior 8GTLA
Superior 12GTLA
Waukesha L3711 *
4SRB
4SRB
4SLB
4SRB
4SRB
4SLB
4SLB
4SRB
*
Fuel,
HP
Btu/hp-hr
8,000
922
8,000
492
8,500
2,080
8,000
800
8,000
600
8,500
1,040
8,500
1,560
8,000
335
Emission Factor, g/hp-hr
NOX
CO
VOC
2.0
5.65
1.0
2.0
4.80
1.0
2.0
3.0
1.0
2.0
3.0
1.0
2.0
3.0
1.0
2.0
3.0
1.0
2.0
3.0
1.0
2.0
5.65
1.0
Equipped with NSCR and AFRC.
EUG-1. Grandfathered Engines
EU
C-1
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-11
Engine
Clark RA-8
Clark RA-8
Clark RA-8
Clark RA-6
Clark RA-6
Clark RA-8
Clark RA-8
Clark HRA-8
Clark HRA-8
Clark HRA-8
Clark HBA-8
Criteria Emissions
NOX
CO
lb/hr
TPY
lb/hr
24.7
108
6.2
24.7
108
6.2
24.7
108
6.2
18.5
81
4.6
18.5
81
4.6
24.7
108
6.2
38.8
170
6.2
27.2
119
3.9
27.2
119
3.9
27.2
119
3.9
54.3
238
23
TPY
27
27
27
20
20
27
27
17
17
17
100
VOC
lb/hr
TPY
0.86
3.8
0.86
3.8
0.86
3.8
0.65
2.8
0.65
2.8
0.86
3.8
0.86
3.8
0.95
4.2
0.95
4.2
0.95
4.2
1.9
8.3
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
EU
C-12 *
C-13
C-14
C-15 *
G-1
G-2
G-3
G-4
G-5
*
Engine
Clark HBA-8
Clark HBA-8
Clark HBA-5
Clark HBA-5
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Total
NOX
0
0
54.3
238
53.4
234
0
0
8.8
39
8.8
39
8.8
39
8.8
39
8.8
39
462
2,026
CO
0
23
14.5
0
15
15
15
15
15
187
0
100
63.7
0
66
66
66
66
66
820
10
VOC
0
0
1.9
8.3
1.2
5.2
0
0
0.12
0.6
0.12
0.6
0.12
0.6
0.12
0.6
0.12
0.6
14.0
62.0
C-12 was shutdown per Consent Order No. 03-165. Emissions decrease is not to be used for
future PSD netting purposes. C-15 has been permanently removed from service. Emissions
decrease may be used for PSD netting purposes.
EUG-2. Permitted Engines
EU
Engine
C-16 *
C-17 *
C-18 *
C-19 *
C-20
C-21
C-22
C-23 *
C-24 *
C-25.3
C-26
C-27
C-28
C-29
G-6 *
G-7 *
*
Waukesha L7042 GSIU
Waukesha L7042 GSIU
Waukesha L7042 GSIU
Waukesha L5108 GU
Superior 16GTLA
Superior 16GTLA
Superior 16GTLA
Superior 8G825
Superior 6G825
Superior 8GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Waukesha L3711
Waukesha L3711
Total
Criteria Emissions
NOX
CO
lb/hr
TPY
lb/hr
TPY
4.07
17.8
11.5
50.3
4.07
17.8
11.5
50.3
4.07
17.8
11.5
50.3
2.17
9.5
5.21
22.8
9.16
40.1
13.7
60.0
9.16
40.1
13.7
60.0
9.16
40.1
13.7
60.0
3.53
15.5
5.29
23.2
2.65
11.6
3.97
17.4
4.58
20.1
6.87
30.1
6.87
30.1
10.3
45.1
6.87
30.1
10.3
45.1
6.87
30.1
10.3
45.1
6.87
30.1
10.3
45.1
1.48
6.47
4.17
18.3
1.48
6.47
4.17
18.3
83.04 363.7
146.6
642.0
Equipped with NSCR and AFRC. Subject to 40 CFR Part 64, CAM rule.
VOC
lb/hr
TPY
2.03
8.90
2.03
8.90
2.03
8.90
1.08
4.75
4.58
20.1
4.58
20.1
4.58
20.1
1.76
7.72
1.32
5.79
2.29
10.0
3.43
15.0
3.43
15.0
3.43
15.0
3.43
15.0
0.74
3.2
0.74
3.2
41.52 181.9
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
11
EUG-3. Tanks
Tank TK-1 is vented to the plant/emergency flare. All other tank emissions are considered
insignificant activities.
EU
Point
Contents
TK-1
TK-2
TK-3
TK-4
TK-5
TK-6
TK-7
TK-8
P-50
P-51
P-52
P-53
P-54
P-55
P-56
P-57
Condensate / BS&W
Scrubber Oil, North
Scrubber Oil, South
BS&W / Condensate, Open Pit
Methanol
Methanol
Gasoline, Unleaded
Solvent < 1.5 psia vapor pressure
Estimated throughput,
gallons per year
5,735,000
487,200
462,630
218,400
-
EUG-4 (Exempt from NSPS Subpart KKK and MACT Subpart HH), EUG-5 (Subject to NSPS
Subpart KKK), and EUG-12 (Subject to MACT Subpart HH) Fugitive Components
Potential fugitive VOC emissions are estimated based on EPA’s 1995 Protocol for Equipment
Leak Estimates (EPA-453/R-95-017), component count for each fugitive type, and VOC content
of the process streams. Fugitive emissions from components monitored under an LDAR program
are calculated with appropriate reduction credits claimed.
Emissions, TPY (Component Count) *
Equipment
Valves
Flanges
Connectors
Open-Ended
Lines
Compressor
Seals
Relief
Valves
Pump Seals
Subtotal
(TPY)
Wet Gas
Residue Gas
Light Liquids
Propane
[24 wt% VOC]
[10 wt% VOC]
[100 wt% VOC]
[100 wt% VOC]
11.5 (2,386)
2.7 (2,983)
2.19 (4,772)
1.1 (250)
0.12 (313)
0.1 (500)
64.9 (3,531)
4.7 (4,414)
14.3 (7,062)
0.25 (191)
0.04
(20)
2.6
0.81
0.08
(10)
-
(40)
(282)
[100 wt% VOC]
7.4
1.1
0.9
(235)
(294)
(470)
-
0.2
(19)
-
0.5
(6)
-
-
-
2.8
(38)
-
-
-
-
7.1
(65)
-
0.4
17.5
1.4
96.4
10.2
0.4
Total = 126 TPY
*
Heavy
Liquids
Fugitive emissions and component counts are best estimates
(73)
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
12
EUG-6. Heaters & Boilers
Estimated NOX, CO, and VOC emissions for the heaters and boilers are based on AP-42 (7/98),
Tables 1.4-1 and 1.4-2 and a fuel gas HHV of 1,000 Btu/scf.
EU
Equipment
H-1
H-2
H-3
H-4
H-5
H-6
H-7
B-1
B-2
Hot Oil Heater (West)
Hot Oil Heater (East)
Regen. Gas Heater (Plant #1)
Regen. Gas Heater (Plant #2)
Glycol Reboiler
Amine Reboiler
Regen. Gas Heater (Plant #3)
Boiler #1 (North, OK36454)
Boiler #2 (South, OK43476)
Total
NOX
lb/hr TPY
4.98
21.8
4.15
18.2
0.50
2.19
0.15
0.66
0.25
1.10
0.60
2.63
0.75
3.29
0.20
0.86
0.20
0.86
11.78
51.6
CO
lb/hr
TPY
4.18
18.3
3.49
15.3
0.42
1.84
0.13
0.55
0.21
0.92
0.50
2.21
0.63
2.76
0.16
0.72
0.16
0.72
9.88
43.3
VOC
lb/hr TPY
0.28
1.2
0.23
1.0
0.03
0.13
0.01
0.04
0.02
0.09
0.03
0.13
0.04
0.18
0.02
0.09
0.02
0.09
0.70
3.0
EUG-7. Process/Emergency Flare (Subject to NSPS Subpart A)
Short-term emission estimates are based on a main plant upset where 90 MMscf of gas would be
released in 4 to 6 hours. The maximum per hour rate would be about 22.5 MMscf, diminishing
as valves are closed and gas is routed elsewhere. Emission estimates of SO2 and H2S are based
on an H2S maximum concentration of 13.5 ppm in the inlet gas, a mass balance, and a
conversion rate of 98%. NOX, CO, and VOC emission estimates are based on AP-42 (9/91),
Table 13.5-1, the gas rate of 22.5 MMscf/hr, and a heating value of 1,200 Btu/scf.
EUG-7
Process / Emergency Flare
Unit
lb/hr
NOX
1,840
CO
9,990
VOC
3,860
SO2
50.3
H2 S
0.55
Annual emission estimates of NOX, CO, and VOC from process flaring are based on AP-42
(9/91), Table 13.5-1, an estimated flare throughput of 16.2 MMscf/yr for the glycol regeneration
overhead vent stream, propane refrigerant compressor blowdowns, and Tank #19 vent, and
propane properties. Flare pilot emissions are based on a pilot gas rate of 0.1 MMBtu/hr and a
heating value of 1,000 Btu/scf.
EUG-7
Process / Emergency Flare
Unit
TPY
NOX
1.31
CO
7.12
VOC
19.3
EUG-8. Acid Gas Flare (Not Subject to NSPS Subpart A)
Acid gases from the rich amine flash tank and the amine regeneration still are vented to the acid
gas flare for conversion of H2S to SO2. Emission estimates of SO2 and H2S are based on an inlet
gas rate of 137 MMSCFD, an H2S concentration of 13.5 ppmv in the inlet gas, a mass balance,
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
13
and a conversion rate of 98%. NOX, CO, and VOC emission estimates are based on AP-42
(9/91), Table 13.5-1, and a flare heat rate of 1.5 MMBtu/hr.
EUG-8
Acid Gas Flare
Unit
lb/hr
TPY
NOX
0.10
0.45
CO
0.56
2.45
VOC
1.70
7.45
SO2
12.8
55.9
H2 S
0.14
0.61
EUG-9. VOC Flare (Subject to NSPS Subpart A)
NOX, CO, and VOC emission estimates are based on AP-42 (9/91), Table 13.5-1 and Table 13.52 and a maximum flare heat rate of 40 MMBtu/hr.
EUG-9
Unit
lb/hr
TPY
VOC Flare
NOX
2.7
12
CO
15
66
VOC
2.5
11
EUG-10. Glycol Dehydration Unit
Emissions from the dehydration regenerator still are vented through a condenser and any
remaining vapors are either recycled to the low-pressure inlet gas stream or vented to the
process/emergency flare. Flash vapors from the rich glycol flash tank are recycled to the lowpressure inlet gas stream. Therefore, there are no significant pollutant emissions.
EUG-11. Condensate/Scrubber Oil Truck Loading
Emissions from the loading of condensate are based on AP-42 (1/95), Section 5.2-5, Equation 1.
ID #
TL-1
Throughput
Loading Loss, lb/1000
VOC
bbl/yr
164,363
gallons
5.11
TPY
17.7
EUG-13. Miscellaneous Venting Activities
Emissions from miscellaneous venting activities (i.e., compressor blowdowns) are based on
1,200,000 scf/yr of blowdown volume and VOC content of the inlet gas.
EU ID #
Blowdown Volume (scf/yr)
VENT
1,200,000
VOC
(TPY)
7.8
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
14
EUG-FW. Facility-Wide Emissions
Total Criteria Pollutant Emissions
EUG
Source
Engines-1 (4)
Engines-2 (4)
Tanks (1)
Fugitives
Heaters/Boilers
Process/Emergency
Flare (2)
Acid Gas Flare
VOC Flare
Glycol Unit (3)
Truck Loading
Misc. Venting
Total (5)
Previous Total
Change for M-2
1
2
3
4, 5, 12
6
7
8
9
10
11
13
1.
2.
3.
4.
5.
NOX
lb/hr TPY
462
2,026
83.0
364
12
52
-
1.3
CO
lb/hr TPY
187
820
147
642
9.9
43
-
7.1
0.1
0.5
0.6
2.5
2.7
12
15
66
560
2,456
360 1,581
693
3,038
398 1,749
-133
-582
-38
-168
VOC
SO2
lb/hr TPY lb/hr TPY
14.0
62.0
0.1
0.4
41.5
182
0.1
0.4
28.8
126
0.7
3.0
-
19.3
-
-
1.7
2.5
89.2
91.0
-1.8
7.5
11
17.7
7.8
436
439
-3
12.7
12.9
12.7
0.2
55.9
56.6
55.9
0.7
Tank emissions are either controlled or insignificant.
The process/emergency flare is for process and emergency use and its short-term emissions
estimates are for ambient air modeling purposes only and are not counted for facility emission
estimates.
Glycol regenerator still vent is controlled by the process/emergency flare. Rich glycol flash
tank off-gases are recycled back to the low-pressure inlet gas stream.
SO2 emissions added for engines by applicant.
After fuel system modifications to grandfathered engines and shutdown of engine C-15.
B. HAP Emissions
Engines
The internal combustion engines have emissions of HAP, the most significant being
formaldehyde and acrolein. The following table presents emission factors for formaldehyde and
acrolein. Emission factors for formaldehyde are based as noted. Emission factors for acrolein
are based on AP-42 (7/00) Tables 3.2-1 and 3.2-3, except as noted.
Formaldehyde and Acrolein Emission Factors
Fuel,
EF, lb/MMBtu
Source
Type
HP
Btu/hp-hr
Formaldehyde
Acrolein
(1)
Clark RA-8
2SLB
9,000
800 0.24 (g/hp-hr)
0.00778
(1)
Clark RA-6
2SLB
9,000
600 0.24 (g/hp-hr)
0.00778
(1)
Clark HRA-8
2SLB
9,000
880 0.27 (g/hp-hr)
0.00778
Clark HBA-8
2SLB
9,000
1,760 0.38 (g/hp-hr) (1)
0.00778
(1)
Clark HBA-5
2SLB
9,000
1,100 0.24 (g/hp-hr)
0.00778
(2)
Waukesha L7042 GSIU
4SRB
8,000
922 0.0103
0.00132 (2)
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
Source
Type
Waukesha L5108 GU
Superior 16GTLA
Superior 8G825
Superior 6G825
Superior 8GTLA
Superior 12GTLA
Ingersoll-Rand PKVG-6
Waukesha L3711
1.
2.
3.
4.
4SRB
4SLB
4SRB
4SRB
4SLB
4SLB
4SRB
4SRB
Fuel,
HP
Btu/hp-hr
8,000
492
8,500
2,078
8,000
800
8,000
600
8,500
1,039
8,500
1,558
8,000
660
8,000
335
EF, lb/MMBtu
Formaldehyde
Acrolein
(2)
0.0103
0.00132 (2)
(3)
0.1 (g/hp-hr)
0.00514
0.0103 (2)
0.00132 (2)
0.0103 (2)
0.00132 (2)
0.1 (g/hp-hr) (3)
0.00514
0.1 (g/hp-hr) (3)
0.00514
(4)
0.0205
0.00263
(2)
0.0103
0.00132 (2)
Based on stack tests for Clark 2SLB engines, factors shown in g/hp-hr.
Based on AP-42 (7/00), Table 3.2-3 with 50% catalytic reduction.
Based on stack tests for White Superior 4SLB engines, factors shown in g/hp-hr.
Based on AP-42, Table 3.2-3.
EU
C-1A, B
C-2A, B
C-3A, B
C-4A, B
C-5A, B
C-6
C-7A, B
C-8
C-9
C-10
C-11
C-12
C-13
C-14
C-15
C-16
C-17
C-18
C-19
C-20
C-21
C-22
C-23
C-24
C-25.3
C-26
Formaldehyde and Acrolein Emissions
Formaldehyde
Source
lb/hr
TPY
Clark RA-8
0.42
1.86
Clark RA-8
0.42
1.86
Clark RA-8
0.42
1.86
Clark RA-6
0.32
1.39
Clark RA-6
0.32
1.39
Clark RA-8
0.42
1.86
Clark RA-8
0.42
1.86
Clark HRA-8
0.52
2.29
Clark HRA-8
0.52
2.29
Clark HRA-8
0.52
2.29
Clark HBA-8
1.47
6.46
Clark HBA-8 (removed)
0
0
Clark HBA-8
1.47
6.46
Clark HBA-5
0.58
2.55
Clark HBA-5 (removed)
0
0
Waukesha L7042 GSIU
0.08
0.33
Waukesha L7042 GSIU
0.08
0.33
Waukesha L7042 GSIU
0.08
0.33
Waukesha L5108 GU
0.04
0.18
Superior 16GTLA
0.46
2.01
Superior 16GTLA
0.46
2.01
Superior 16GTLA
0.46
2.01
Superior 8G825
0.07
0.29
Superior 6G825
0.05
0.22
Superior 8GTLA
0.23
1.00
Superior 12GTLA
0.34
1.50
Acrolein
lb/hr
TPY
0.056
0.25
0.056
0.25
0.056
0.25
0.042
0.18
0.042
0.18
0.056
0.25
0.056
0.25
0.062
0.27
0.062
0.27
0.062
0.27
0.123
0.54
0
0
0.123
0.54
0.077
0.34
0
0
0.01
0.04
0.01
0.04
0.01
0.04
0.005
0.02
0.091
0.40
0.091
0.40
0.091
0.40
0.008
0.04
0.006
0.03
0.045
0.20
0.068
0.30
15
DRAFT
PERMIT MEMORANDUM 2004-163-TVR (M-2)
EU
C-27
C-28
C-29
G-1
G-2
G-3
G-4
G-5
G-6
G-7
Source
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Waukesha L3711
Waukesha L3711
Total
Formaldehyde
lb/hr
TPY
0.34
1.50
0.34
1.50
0.34
1.50
0.11
0.47
0.11
0.47
0.11
0.47
0.11
0.47
0.11
0.47
0.03
0.12
0.03
0.12
11.82
51.72
16
Acrolein
lb/hr
TPY
0.068
0.30
0.068
0.30
0.068
0.30
0.014
0.06
0.014
0.06
0.014
0.06
0.014
0.06
0.014
0.06
0.0035 0.02
0.0035 0.02
1.589
6.99
The facility is a major source of formaldehyde emissions.
Glycol Dehydration Unit
Glycol dehydration units in natural gas service typically emit benzene, toluene, ethyl benzene,
xylene, and n-hexane from the rich glycol flash tank and the regenerator still vent. These
compounds are regulated as HAP. Emission estimates for the glycol unit are based on GRIGLYCalc 3.0, a wet gas extended analysis dated December 17, 2004, a lean glycol circulation
rate of 13 gpm, and a dry gas rate of 70 MMSCFD. Vapors from the rich glycol flash tank are
recycled back to the low-pressure inlet gas stream. Uncontrolled emissions from the glycol
regenerator still vent are listed in the table below.
Pollutant
Benzene
Toluene
Ethyl benzene
Xylene
n-Hexane
Total
Uncontrolled HAP
CAS
Emissions
Number
lb/hr
TPY
71432
4.04
17.7
108883
4.06
17.8
100414
0.21
0.93
1330207
2.15
9.40
110543
1.83
8.0
12.29
53.8
The glycol regenerator still vent emissions are vented to a condenser. Any uncondensed vapors
are then vented to the plant’s process/emergency flare or are recycled to the low-pressure inlet
gas stream. Controlled emissions are listed in the table below.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
Pollutant
Benzene
Toluene
Ethyl benzene
Xylene
n-Hexane
Total
DRAFT
17
Controlled HAP
CAS
Emissions
Number
lb/hr
TPY
71432
0.08
0.35
108883
0.08
0.36
100414
<0.01
0.02
1330207
0.04
0.19
110543
0.04
0.16
0.25
1.08
SECTION V. INSIGNIFICANT ACTIVITIES
The insignificant activities identified and justified in the application are duplicated below.
Records are available to confirm the insignificance of the activities. Appropriate recordkeeping
of activities indicated below with “*” is specified in the Specific Conditions.
1. Space heaters, boilers, process heaters and emergency flares less than or equal to 5
MMBtu/hr heat input fired by commercial natural gas. The facility has several portable space
heaters for the office buildings and various plant buildings. All are rated less than 5
MMBtu/hr. The 2.0 MMBtu/hr boilers (B-1 and B-2) are also in this category.
2. * Emissions from condensate tanks with a design capacity of 400 gallons or less in ozone
attainment areas. None identified, but may be added in the future.
3. Surface coating operations which do not exceed a combined total usage of more than 60
gallons/month of coatings, thinners, and clean-up solvents at any one emissions unit. The
facility conducts painting operations and engine cleaning exclusively for maintenance
purposes, which is a trivial activity; therefore, no records are required.
4. * Activities having the potential to emit no more than 5 TPY (actual) of any criteria pollutant.
The methanol and ethylene glycol tanks and compressor blowdowns fit in this category. Also
included are the three regeneration-gas heaters (H-3, H-4, and H-7), the glycol reboiler (H-5),
and the amine reboiler (H-6).
SECTION VI. PSD/NAAQS COMPLIANCE
In 1985, a major modification of the facility was made which triggered Prevention of Significant
Deterioration (PSD) review. PSD modeling was conducted to demonstrate compliance with
National Ambient Air Quality Standards (NAAQS) for NO2, CO, SO2, and ozone. The modeling
indicated compliance with all standards.
Since issuance of the original Part 70 permit, other modifications made at the facility have not
required a PSD review since emission increases did not exceed the PSD significance thresholds.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
DRAFT
18
In the TVR permit application, OFS requested to upgrade emissions estimates for many of the
engines. The change in emissions estimates resulted in an increase of approximately 681 TPY of
NOX and 500 TPY of CO. The emission increases in NOX and CO were not subject to PSD
review since they were based on a change in the basis for emission estimates and not due to a
physical or operational change at the facility. However, due to the large increase in PTE for NOX
and CO, OFS performed air dispersion modeling using EPA’s AERMOD program and five years
of meteorological data to determine if there would be a violation of the National Ambient Air
Quality Standards (NAAQS). The results of that modeling are shown in the following table.
Compliance with NAAQS for Facility Total PTE
CO
Ozone
SO2
NO2
Parameter
Annual
1-Hour
8-Hour 1-Hour 24-Hour
Average
Average Average Average Average
Background Concentration, ug/m3
12
3,660
3,660
44
42
Maximum Impacts, ug/m3
78
3,549
2,187
43
73
3
Total Impacts, ug/m
90
7,209
5,847
87
115
3
NAAQS, ug/m
100
40,000
10,000
235
365
Radius of Impact, km
4.5
NA
NA
NA
NA
The modeling showed ambient air concentrations for NO2 just below the NAAQS. However, the
background concentration was later determined to be 19 ug/m3. This suggested that the facility
had the potential to violate the NAAQS for NO2. The facility conducted more testing of some of
the engines and more dispersion modeling using the EPA AERMOD program. This modeling
showed the facility just above the NAAQS for NO2 and Consent Order 06-063 was issued to
bring the facility into compliance with the NAAQS.
The facility has made fuel system modifications to most of the engines in EUG-1 in accordance
with the schedule in Consent Order 06-063 in order to bring the facility in compliance with the
NAAQS for NO2. The facility submitted air modeling on April 5, 2007 demonstrating
compliance with the NAAQS as shown in the following table. The maximum annual
concentration occurred at a boundary receptor and decreased beyond the property line. AQD is
still reviewing the air modeling submitted by the facility, so Consent Order 06-063 is still in
effect.
Compliance with NAAQS for NO2 - Facility Total PTE
NO2 Annual
Parameter
Average
3
Background Concentration, ug/m
17.0 *
Maximum Impacts, ug/m3
76.5
3
Total Impacts, ug/m
93.5
3
NAAQS, ug/m
100
* Background for OKC approved for use by AQD.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
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SECTION VII. OKLAHOMA AIR POLLUTION CONTROL RULES
OAC 252:100-1 (General Provisions)
Subchapter 1 includes definitions but there are no regulatory requirements.
[Applicable]
OAC 252:100-3 (Air Quality Standards and Increments)
[Applicable]
Subchapter 3 enumerates the primary and secondary ambient air quality standards and the
significant deterioration increments. At this time, all of Oklahoma is in attainment of these
standards.
OAC 252:100-4 (New Source Performance Standards)
[Applicable]
Federal regulations in 40 CFR Part 60 are incorporated by reference as they exist on July 1, 2005,
except for the following: Subpart A (Sections 60.4, 60.9, 60.10, and 60.16), Subpart B, Subpart
C, Subpart Cb, Subpart Cc, Subpart Cd, Subpart AAA, Subpart BBBB, Subpart DDDD, Subpart
HHHH, and Appendix G. These requirements are addressed in the “Federal Regulations” section.
OAC 252:100-5 (Registration, Emission Inventory, and Annual Operating Fees)
[Applicable]
Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission
inventories annually, and pay annual operating fees based upon total annual emissions of
regulated pollutants. An emissions inventory has been submitted and fees paid for prior 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 HAP or 20% of
any threshold less than 10 TPY for single HAP that the EPA may establish by rule
Emission limitations and operational requirements necessary to assure compliance with all
applicable requirements for all sources are taken from the operating permit application, or
developed from the applicable requirements.
Part 7 summarizes Prevention of Significant Deterioration (PSD) requirements. See the “Federal
Regulations” section for a discussion of PSD regulations.
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)
PERMIT MEMORANDUM 2004-163-TVR (M-2)
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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.
OAC 252:100-13 (Open Burning)
[Applicable]
Open burning of refuse and other combustible material is prohibited except as authorized in the
specific examples and under the conditions listed in this subchapter.
OAC 252:100-19 (Control of Emission of Particulate Matter)
[Applicable]
Section 19-4 regulates emissions of particulate matter (PM) from new and existing fuel-burning
equipment, with emission limits based on maximum design heat input rating. Fuel-burning
equipment is defined in OAC 252:100-1 as “combustion devices used to convert fuel or wastes to
usable heat or power.” Thus, the gas-fired heaters and reboilers and engines are subject to the
requirements of this subchapter. The facility’s flares are not subject since they do not produce
any “usable heat or power”. Appendix C specifies a PM emission limitation range of 0.6
lb/MMBtu to 0.35 for fuel-burning equipment with a rated heat input range of 10 MMBtu/hr or
less up to 100 MMBtu/hr. AP-42 (7/98) Table 1.4-2 lists total PM emissions as 0.0076
lb/MMBtu for natural gas combustion. AP-42 (7/00) Section 3.2 lists total PM emissions from
natural gas-fired reciprocating internal combustion engines as about 0.01 lb/MMBtu. This permit
requires the use of natural gas for all fuel-burning units to ensure compliance with Subchapter
19.
OAC 252:100-25 (Visible Emissions and Particulates)
[Applicable]
No discharge of greater than 20% opacity is allowed except for short-term occurrences that
consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed
three such periods in any consecutive 24 hours. In no case shall the average of any six-minute
period exceed 60% opacity. There is little possibility of exceeding these standards when burning
natural gas. This permit requires the use of natural gas for all fuel-burning units to ensure
compliance with Subchapter 25.
OAC 252:100-29 (Control of Fugitive Dust)
[Applicable]
No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the
property line on which the emissions originate in such a manner as to damage or to interfere with
the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the
maintenance of air quality standards. Under normal operating conditions, this facility has negligible
potential to violate this requirement; therefore, it is not necessary to require specific precautions to
be taken.
OAC 252:100-31 (Sulfur Compounds)
[Applicable]
Part 2 limits emissions of sulfur dioxide from any one existing source or any one new petroleum
and natural gas process source subject to OAC 252:100-31-26(a)(1). Ambient air concentration
of sulfur dioxide at any given point shall not be greater than 1,300 g/m3 in a 5-minute period of
any hour, 1,200 g/m3 for a 1-hour average, 650 g/m3 for a 3-hour average, 130 g/m3 for a 24hour average, and 80 g/m3 for an annual average. Part 2 also limits the ambient air impact of
hydrogen sulfide emissions from any new or existing source to 0.2 ppm for a 24-hour average
(equivalent to 280 g/m3). For the acid gas flare, EPA SCREEN3 dispersion modeling was
PERMIT MEMORANDUM 2004-163-TVR (M-2)
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conducted based on the stack parameters listed below and emissions rates of 13 lb/hr of SO2 and
0.14 lb/hr of H2S. The 1-hour impacts predicted by SCREEN3 were converted to 5-minute, 3hour, 24-hour, and annual averaging periods using factors of 1.6, 0.9, 0.4, and 0.08 respectively,
as presented in “Screening Procedures for Estimating the Air Quality Impact from Stationary
Sources”, Revised (EPA-454/R-92-019). The SCREEN3 results are tabulated in the following
table.
Acid Gas Flare
Stack Height:
Stack Diameter:
Heat Release:
110 ft
24 inch
0.50 MMBtu/hr
(A lower heat release than the 1.5 MMBtu/hr maximum rate was
used for a conservative estimate)
Ambient Impacts of SO2 (13 lb/hr)
Standard
Ground Level Concentration
Averaging Time
3
g/m
g/m3
5-minute
1,300
157
1-hour
1,200
96
3-hour
650
86
24-hour
130
38
Annual
80
8
Ambient Impacts of H2S (0.14 lb/hr)
Standard
Ground Level Concentration
Averaging Time
3
g/m
g/m3
24-hour
280
0.41
For the process/emergency flare, EPA SCREEN3 dispersion modeling was conducted based on
the stack parameters listed below and emissions rates of 50.3 lb/hr of SO2 and 0.55 lb/hr of H2S.
The 1-hour impacts predicted by SCREEN3 were converted to 5-minute, 3-hour, 24-hour, and
annual averaging periods using factors of 1.6, 0.9, 0.4, and 0.08 respectively, as presented in
“Screening Procedures for Estimating the Air Quality Impact from Stationary Sources”, Revised
(EPA-454/R-92-019). The SCREEN3 results are tabulated in the following table.
Process/Emergency Flare
Stack Height:
Stack Diameter:
Heat Release:
110 ft
24 inches
40 MMBtu/hr (a lower heat release than the 27,000 MMBtu/hr
maximum rate was used for a conservative estimate)
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Ambient Impacts of SO2
51.3 lb/hr SO2
Averaging Standard
3
Time
g/m
GLC, g/m3
5- minute
1,300
43
1-hr
1,200
27
3-hr
650
24
24-hr
130
11
Annual
80
2
Ambient Impacts of H2S (0.55 lb/hr)
Standard
Ground Level Concentration
Averaging Time
3
g/m
g/m3
24-hour
280
0.1
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 0.2weight 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.
Part 5 also limits hydrogen sulfide emissions from new equipment (constructed after July 1,
1972). Removal of hydrogen sulfide in the exhaust stream, or oxidation to sulfur dioxide, is
required unless hydrogen sulfide emissions would be less than 0.3 lb/hr for a two-hour average.
Hydrogen sulfide emissions shall be reduced by a minimum of 95% of the hydrogen sulfide in
the exhaust gas. Direct oxidation of hydrogen sulfide is allowed for units whose emissions
would be less than 100 lb/hr of sulfur dioxide for a two-hour average. Acid gas from the amine
treater rich amine flash tanks and the amine regenerator still vents are vented to the acid gas flare,
which has a conversion efficiency of 98%.
OAC 252:100-33 (Nitrogen Oxides)
[Not Applicable]
This subchapter limits new gas-fired fuel-burning equipment with rated heat input greater than or
equal to 50 MMBtu/hr to emissions of 0.2 lb of NOX per MMBtu, three-hour average. There are
no equipment items that equal or exceed the 50 MMBtu/hr 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 storing a VOC with a vapor pressure greater than 1.5 psia to be equipped with a
permanent submerged fill pipe or with an organic vapor recovery system. Tanks TK-1, TK-2, TK3, and TK-5 were constructed prior to 1974 and are exempt from this requirement. Tanks TK-4,
PERMIT MEMORANDUM 2004-163-TVR (M-2)
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TK-6, and TK-7 are subject to this requirement and are equipped with submerged fill pipes. Tank
TK-8 stores material with a vapor pressure less than 1.5 psia and is exempt from this requirement.
Part 3 requires loading facilities with a throughput equal to or less than 40,000 gallons per day to
be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the
vehicle is greater than 200 gallons. This facility does not have the physical equipment (loading
arm and pump) to conduct this type of loading. Therefore, this requirement is not applicable.
Part 7 requires fuel-burning equipment to be operated and maintained to minimize emissions of
VOC. All fuel-burning equipment at this location is subject to this requirement.
Part 7 regulates VOC/water separators that receive water containing more than 200 gallons per
day of VOC. There is no VOC/water separator at this location. Tank T-4 and five open pits
recover water from the condensate tank area, rainwater runoff, and the plant drain system. Most
of the oil/water mixtures captured by these units are removed by vacuum truck for off-site
disposal. A small amount of the skimmed oil is sold occasionally.
Part 7 also requires all reciprocating pumps and compressors handling VOCs to be equipped with
packing glands that are properly installed and maintained in good working order and all rotating
pumps and compressors handling VOCs to be equipped with mechanical seals or other
equipment of equal efficiency. The equipment at this facility is subject to this requirement.
OAC 252:100-41 (Hazardous Air Pollutants)
[Applicable]
Part 3 addresses hazardous air contaminants. NESHAP, as found in 40 CFR Part 61, are adopted
by reference as they exist on September 1, 2005, with the exception of Subparts B, H, I, K, Q, R,
T, W and Appendices D and E, all of which address radionuclides. In addition, General
Provisions as found in 40 CFR Part 63, Subpart A, and the Maximum Achievable Control
Technology (MACT) standards as found in 40 CFR Part 63, Subparts F, G, H, I, L, M, N, O, Q,
R, S, T, U, W, X, Y, AA, BB, CC, DD, EE, GG, HH, II, JJ, KK, LL, MM, OO, PP, QQ, RR, SS,
TT, UU, VV, WW, XX, YY, CCC, DDD, EEE, GGG, HHH, III, JJJ, LLL, MMM, NNN, OOO,
PPP, QQQ, RRR, TTT, UUU, VVV, XXX, AAAA, CCCC, DDDD, EEEE, FFFF, GGGG,
HHHH, IIII, JJJJ, KKKK, MMMM, NNNN, OOOO, PPPP, QQQQ, RRRR, SSSS, TTTT,
UUUU, VVVV, WWWW, XXXX, YYYY, ZZZZ, AAAAA, BBBBB, CCCCC, EEEEE,
FFFFF, GGGGG, HHHHH, IIIII, JJJJJ, KKKKK, LLLLL, MMMMM, NNNNN, PPPPP,
QQQQQ, RRRRR, SSSSS and TTTTT are hereby adopted by reference as they exist on
September 1, 2005. These standards apply to both existing and new sources of HAP. These
requirements are covered in the “Federal Regulations” section.
Part 5 was a state-only requirement governing sources of toxic air contaminants that have
emissions exceeding a de minimis level. However, Part 5 of Subchapter 41 has been superseded
by OAC 252:100-42, effective June 15, 2006.
OAC 252:100-42 (Toxic Air Contaminants (TAC))
[Applicable]
Part 5 of OAC 252:100-41 was superceded by this subchapter. 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 Area of
Concern (AOC) has been designated anywhere in the state, there are no specific requirements for
this facility at this time.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
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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 Quality Rules are not applicable to this facility:
OAC 252:100-11
OAC 252:100-15
OAC 252:100-17
OAC 252:100-23
OAC 252:100-24
OAC 252:100-39
OAC 252:100-47
Alternative Emissions Reduction
Mobile Sources
Incinerators
Cotton Gins
Grain, Feed, or Seed Facility
Non-attainment Areas
Municipal Solid Waste Landfills
not eligible
not in source category
not type of emission unit
not type of emission unit
not in source category
not in a subject area
not type of source category
SECTION VIII. FEDERAL REGULATIONS
PSD, 40 CFR Part 52
[Not Applicable]
Total potential emissions of NOX, CO, and VOC are greater than the threshold level of 250 TPY.
Any future increases of emissions must be evaluated for PSD if they exceed a significance level
(100 TPY CO, 40 TPY NOX, 40 TPY SO2, 40 TPY VOC, 15 TPY PM10, 10 TPY H2S).
NSPS, 40 CFR Part 60
[Subparts A, Dc, KKK, and LLL Applicable]
Subpart A, General Provisions. The VOC flare (FL-2) is used to control emissions from relief
valves within the gas liquids extraction equipment that are subject to NSPS Subpart KKK and to
control emissions from the seal degassing systems of compressors C-19, C-24 and C-25. The
plant process/emergency flare (FL-1) is used to control emissions from the TEG dehydration still
vent and from relief valves that are subject to NSPS Subpart KKK. The VOC flare and the plant
process/emergency flare are subject to Subpart A and shall comply with all applicable
requirements for flares in §60.18. The acid gas flare is used to control the acid gas from the DGA
and DEA units. However, it is not used to comply with NSPS Subpart LLL even though the DGA
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and DEA are both subject to NSPS Subpart LLL because the H2S design capacity of both amine
units is less than 2 LT/D. Therefore, the acid gas flare is not subject to Subpart A §60.18.
Subpart Dc, Small Industrial-Commercial-Institutional Steam Generating Units. This subpart
affects steam generating units constructed after June 9, 1989, and with capacity between 10 and 100
MMBtu/hr. Hot oil heaters H-1 and H-2 are “Steam Generating Units” as that term is defined in
this subpart. The heaters were constructed prior to June 9, 1989; however, new burners were
installed in H-1 in 1997 that would reduce NOX and CO emissions, but allowed for a very slight
increase in SO2 emissions that triggered Subpart Dc. Since H-1 is fired with natural gas, only initial
notification and records of the type of fuel and amount combusted each day is required.
Subparts K, Ka, Kb, Volatile Organic Liquid (VOL) Storage Vessels. All tanks were either
constructed prior to the effective date of these subparts or are below the 19, 813 gallon threshold
for Subpart Kb.
Subpart GG, Stationary Gas Turbines. There are no stationary gas turbines at this facility.
Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants
constructed, reconstructed, or modified after January 20, 1984. This subpart sets standards for
natural gas processing plants, which are defined as any site engaged in the extraction of natural
gas liquids from field gas, fractionation of natural gas liquids, or both. Compressors C-16
through C-23 and C-25 through C-29 are affected facilities since they were constructed/modified
after January 20, 1984. Subpart KKK specifically exempts reciprocating compressors in wet gas
service, and compressors that are not in VOC service, from all but notification and recordkeeping
requirements. Compressors C-20, C-21, C-22, and C-23 are in wet gas service and all must meet
the monitoring, demonstration and recordkeeping requirements of §60.486(j) and §60.635(a) and
(c). Compressors C-16, C-17, C-18, C-26, C-27, C-28 and C-29 are in wet gas/residue gas service.
Compressors C-19, C-24 and C-25 are in propane refrigeration service and subject to §60.482-3
control requirements. The permittee will be required to maintain a leak detection and repair
(LDAR) program for C-19, C-24, C-25, and associated equipment.
The TEG dehydrator unit (Plant 3 TEG System) was constructed in 1986 and is an affected facility.
The amine units (Plants 1 & 2 DGA North Amine Treater and Plant 3 DEQ South Amine Treater)
were constructed/reconstructed after 1984 and are affected facilities. Multiple inlet gas streams
(Inlet Gas South Low, Inlet Gas South High, Anadarko Inlet and Waukesha Inlet) are affected
facilities. Other process units have some equipment components constructed or modified after
January 20, 1984. EUG-5 contains those equipment components subject to Subpart KKK. The
permittee will be required to maintain an LDAR program for those components.
Subpart LLL sets standards for natural gas sweetening units, and sweetening units followed by a
sulfur recovery unit, which commenced construction or modification after January 20, 1984. The
north amine unit (DGA) was reconstructed after the applicability date of Subpart LLL. The south
amine unit (DEA) was constructed in 1985. Both are subject to this subpart. However, facilities
with a design capacity of less than 2 long tons per day (LT/D) of H2S in the acid gas, expressed
as sulfur, are exempted from the control requirements of the standard. The applicant has provided
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an analysis demonstrating that the amine units at this facility have a design capacity of less than 2
LT/D of sulfur. Therefore, the north and south amine units are subject only to §60.647 (c), which
requires the facility to keep, for the life of the facility, an analysis demonstrating that the amine
units’ design capacities are less than 2 LT/D of H2S, expressed as sulfur.
Subpart NNN, VOC Emissions from SOCMI Distillation Operations. This subpart applies to each
affected facility (distillation units and recovery systems) that is part of a process unit that produces
any of the chemicals listed in §60.667 as a product, co-product, by-product, or intermediate. The
affected facilities are (1) each distillation unit not discharging its vent stream into a recovery
system, (2) each combination of distillation unit and the recovery system into which its vent
stream is discharged, or (3) each combination of two or more distillation units and the common
recovery system into which their vent streams are discharged. The definition of “vent stream”
excludes relief valves and fugitive equipment leaks. Propane, butane, and isobutane are listed
chemicals in §60.667 and an Applicability Determination from EPA Region VI dated December
14, 2006 states that Subpart NNN applied to distillation operations at a natural gas processing
plant operated by ConocoPhillips Company. However, OFS has determined that only relief
valves and fugitive leaks are vented to the atmosphere at this facility’s depropanizer and
debutanizer columns; therefore, there are no applicable requirements under Subpart NNN.
Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion
Engines, 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. The facility does not
presently operate any engines subject to this subpart since all engines were constructed prior to
July 11, 2005.
Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion
Engines, was proposed in the Federal Register on June 12, 2006. It will affect all new engines
and those modified or reconstructed after June 6, 2006. It will impose categories of standards for
NOX, CO, NMHC, based on engine power rating, lean-burn or rich-burn, fuel type, and
manufacture date. The facility does not presently operate any engines subject to this subpart since
all engines were constructed prior to June 12, 2006.
Subpart KKKK, Standards of Performance for Stationary Combustion Turbines, establishes
emission standards and compliance schedules for the control of emissions from stationary
combustion turbines with a heat input at peak load equal to or greater than 10 MMBtu per hour,
based on the higher heating value of the fuel, which commenced construction, modification, or
reconstruction after February 18, 2005. Stationary combustion turbines regulated under this
subpart are exempt from the requirements of Subpart GG of this part. Heat recovery steam
generators and duct burners regulated under this subpart are exempted from the requirements of
subparts Da, Db, and Dc of this part. There are no turbines at this facility.
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NESHAP, 40 CFR Part 61
[Not Applicable]
There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene,
coke oven emissions, mercury, radionuclides, or vinyl chloride except for trace amounts of
benzene. Subpart J (Equipment Leaks of Benzene) concerns only process streams, which contain
more than 10% benzene by weight. All process streams at this facility are below this threshold.
NESHAP, 40 CFR Part 63
[Subparts A, HH, ZZZZ, and DDDDD are Applicable]
Subpart A, General Provisions. The facility is subject to the reporting requirements of 40 CFR
§60.9, but is not subject to the flare requirements of 40 CFR §63.11. Neither of the two flares
(FL-1 nor FL-2) at the plant is used to comply with MACT Subpart HH. The General Standards
require compliance with 40 CFR §63.771 or 40 CFR §63.11 for “flares that are used to comply
with Subpart HH.” GLYCOL UNITS: The process/emergency flare (FL-1) was used to control
emissions from the TEG dehydration still vent prior to June 17, 2002 and the requirement to
recycle or flare the glycol vent gas was a federally enforceable permit limit prior to June 17, 2002.
Because the benzene from that flare is < 0.90 megagrams per year, the glycol unit and flare are
exempt under 40 CFR §63.764(e)(1)(ii). ANCILLARY EQUIPMENT: 40 CFR §63.769(b)
exempts sources “meeting the requirements specified in 40 CFR Part 60, subpart KKK” from 40
CFR §63.769, which includes 40 CFR §63.11(b).
Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission
points that are located at facilities which are major sources of HAP, or TEG dehydration units
only located at an area source, and either process, upgrade, or store hydrocarbons prior to the
point of custody transfer or prior to which the natural gas enters the natural gas transmission and
storage source category. Subpart HH affects glycol dehydration unit process vents, storage
vessels with potential for flash emissions, and compressors and ancillary equipment (valves,
flanges, etc.) in VHAP service (i.e., more than 10% by weight HAP) that are located at gas
processing plants. This facility is a major source of HAP and must meet the compliance,
reporting, and recordkeeping requirements of Subpart HH.
Emissions from the glycol dehydrator still vent are controlled by a condenser and by recycle or
combustion in the plant’s process/emergency flare. The applicant has stated and demonstrated
that the glycol unit is exempt from the control requirements of §63.764 and §63.765 by meeting
the exemption of §63.764(e)(1) for actual benzene emissions below 1.0 TPY.
The natural gasoline system, equipment handling condensate, and the engine jacket cooling water
systems (using ethylene glycol) have ancillary equipment components in VHAP service. The
facility has implemented and will maintain a leak detection and repair program (LDAR) for those
equipment components in VHAP service.
All condensate and scrubber oil storage tanks are exempt from the standards of this subpart as
none have a throughput above 21,000 gallons per day. None of the facility’s compressors are in
VHAP service.
Recordkeeping is required for notifications required by 40 CFR §63.9, for the LDAR monitoring,
for the records required by 40 CFR §63.772(a) that demonstrate which streams are in VHAP
PERMIT MEMORANDUM 2004-163-TVR (M-2)
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service and which streams are not in VHAP service, and for the exemptions documented
according to 40 CFR §63.764(e)(1)(ii), §63.774(d)(1)(ii) and §63.774(d)(2).
Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart affects RICE
with a site-rating greater than 500 brake horsepower that are located at a major source of HAP
emissions. On June 12, 2006, the EPA published a proposed rule to amend Subpart ZZZZ to
cover engines with a site-rating less than or equal to 500 brake horsepower located at a major
source of HAP and engines located at an area source of HAP. The proposed rule does not
contain any emissions limitations, recordkeeping, or notification requirements for existing
engines with a site-rating less than or equal to 500 brake horsepower located at a major source of
HAP. The existing lean-burn engines are exempt from any standards in Subpart ZZZZ. All
existing rich-burn engines with a site-rating greater than 500 brake horsepower are subject to
emission and operating limitations in Subpart ZZZZ and must comply with the standards by June
15, 2007. The permit will require compliance with this subpart. As previously explained, OFS is
taking a federally enforceable limit on the horsepower output for the engines driving generators
G-1, G-2, G-3, G-4, and G-5 in order to avoid applicability to the RICE MACT.
Subpart DDDDD, Industrial/Commercial/Institutional Boilers and Process Heaters. This subpart
affects new, reconstructed, and existing boilers and process heaters fired with solid, liquid, and
gaseous fuels at major sources of HAP. Hot oil heaters H-1 and H-2 are process heaters rated
above 10 MMBtu/hr, which meets the definition of “large gaseous fuel subcategory” as defined
in Subpart DDDDD. As such, the heaters are only subject to the initial notification requirements
of §63.9(b), and are not subject to any standards in this subpart. OFS submitted an initial
notification letter to ODEQ on December 13, 2004 for H-1 and H-2. H-3, H-4, H-5, H-6, H-7, B1, and B-2 are existing small gaseous fuel heaters and boilers that are not subject to any
requirements in Subpart DDDDD.
CAM, 40 CFR Part 64
[Applicable]
Compliance Assurance Monitoring (CAM) applies to any pollutant specific emission unit at a
major source that is required to obtain a Title V permit, if it meets all of the following criteria:
1. It is subject to an emission limit or standard for an applicable regulated air pollutant.
2. It uses a control device to achieve compliance with the applicable emission limit or
standard.
3. It has potential emissions, prior to the control device, of the applicable regulated air
pollutant of 100 TPY for a criteria pollutant, 10 TPY for an individual HAP, or 25 TPY
for all HAP.
Pre-control emissions from the glycol regenerator still vent are above 100 TPY for VOC and a
control device is used to meet the permit emission limits. Therefore, since the glycol dehydration
unit is exempt from the control standards of Subpart HH, the unit and its controls are subject to
CAM. Engines C-16, C-17, C-18, C-19, C-23, C-24, G-6, and G-7 have pre-control emissions
above major source levels and are equipped with catalytic converters (NSCR) to meet permit
emission limits. Therefore, all these engines and their control components are subject to CAM.
The applicant has submitted and AQD has approved CAM plans for the dehydration unit and the
PERMIT MEMORANDUM 2004-163-TVR (M-2)
DRAFT
29
subject engines. All of these engines, except for C-19 (492-hp), G-6 (335-hp) and G-7 (335-hp)
are subject to emission limitations in 40 CFR Part 63, Subpart ZZZZ and once the engines
demonstrate compliance with those MACT standards, the engines are no longer required to have
a CAM plan.
Chemical Accident Prevention Provisions, 40 CFR Part 68
[Applicable]
This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant
and is subject to this Subpart (Section 112r of the Clean Air Act 1990 Amendments). A Risk
Management Plan was submitted to EPA Region 6 on June 14, 1999 and deemed complete on
June 16, 1999. An update to the RMP was received on September 23, 1999 and judged complete
on September 28, 1999. An update to the RMP was submitted on September 16, 2004. EPA
Notice of Confirmation was dated September 24, 2004. More information on this federal
program is available on the web page: www.epa.gov/ceppo
Stratospheric Ozone Protection, 40 CFR Part 82
[Subpart A and F Applicable]
These standards require phase out of Class I & II substances, reductions of emissions of Class I
& II substances to the lowest achievable level in all use sectors, and banning use of nonessential
products containing ozone-depleting substances (Subparts A & C); control servicing of motor
vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations
which meet phase out requirements and which maximize the substitution of safe alternatives to
Class I and Class II substances (Subpart D); require warning labels on products made with or
containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon
disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds
under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons
(Subpart H).
Subpart A identifies ozone-depleting substances and divides them into two classes. Class I
controlled substances are divided into seven groups; the chemicals typically used by the
manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform
(Class I, Group V). A complete phase-out of production of Class I substances is required by
January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are
hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs.
Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances,
scheduled in phases starting by 2002, is required by January 1, 2030.
This facility does not produce, consume, recycle, import, or export any controlled substances or
controlled products as defined in this part, nor does this facility perform service on motor (fleet)
vehicles that involves ozone-depleting substances. Therefore, as currently operated, this facility
is not subject to these requirements. To the extent that the facility has air-conditioning units that
apply, the permit requires compliance with Part 82.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
DRAFT
30
SECTION IX. COMPLIANCE
Inspection
John Munro, AQD Environmental Programs Specialist, conducted a full compliance evaluation
of the facility on April 24 and 25, 2002. Texaco E&P Inc. owned the facility at the time.
Representatives from Texaco and from Trinity Consultants were present. The facility was
constructed and operating per the TV permit. However, several violations were reported,
including an invalid LDAR program due to lack of compliance with calibration procedures,
failure to report excess emissions from engines, and lateness in various compliance reports. An
NOV (02-AQN-084) was issued that resulted in filing of Consent Order No. 03-165. The order
required OFS, the new owner, to upgrade the LDAR program to meet standards, pay stipulated
fines, and to implement a Supplemental Environmental Project (SEP). The SEP required
shutdown of a “grandfathered” engine C-12 and refurbishment of engine C-21. OFS completed
all requirements and Consent Order No. 03-165 was closed on December 29, 2003.
Kevin Carter and Kyle Jantzen, AQD Environmental Programs Specialists, conducted a full
compliance evaluation of the facility on June 24, 2004. Donnie Wallis, Environmental
Specialist, and Dennis Alder, EH&S Coordinator, represented OFS. A few compliance issues
were discovered during the inspection regarding the LDAR program and reporting of excess
oxygen concentrations in engines exhausts. Consent Order 05-041 addressed those issues and
was closed on May 11, 2005.
On June 4, 2004, OFS submitted self-disclosures for violations related to exceedance of
NAAQS, NSPS Subpart KKK, and NESHAP Subpart HH. Consent Order 06-063 has been
issued and contains a compliance schedule for the facility to meet the NAAQS for NO2. OFS has
submitted air dispersion modeling demonstrating compliance with the NAAQS for NO2, but the
consent order has not been closed at this date.
Brandi Fitzgerald, AQD Environmental Programs Specialist, conducted a full compliance
evaluation of the facility on March 3, 2006. Donnie Wallis, Environmental Specialist,
represented OFS. Some minor violations were reported, but remedial actions were taken and
compliance has closed the enforcement case.
A facility inspection is not needed for this permit modification.
Testing
Engine tests for engines C-16 through C-29, G-6, and G-7 are from the June 24, 2004 inspection
report, which was issued on July 14, 2004.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
Permitted Engine Testing
NOX
CO
EU
Engine
Limit
Test
Limit
Test
lb/hr
lb/hr
lb/hr
lb/hr
C-16
Waukesha L7042 GSIU
4.06
2.1
11.5
4.6
C-17
Waukesha L7042 GSIU
4.06
0.6
11.5
2.1
C-18
Waukesha L7042 GSIU
4.06
4.0
11.5
7.3
C-19
Waukesha L5108 GU
2.17
0.03
5.23
0.9
C-20
Superior 16GTLA
9.15
4.8
13.7
7.4
C-21
Superior 16GTLA
9.15
3.7
13.7
9.2
C-22
Superior 16GTLA
9.15
3.5
13.7
7.1
C-23
Superior 8G825
3.52
3.0
5.29
1.5
C-24
Superior 6G825
2.64
1.8
3.96
3.1
C-25.3 Superior 8GTLA
4.58
0.7
6.87
4.6
C-26
Superior 12GTLA
6.86
3.2
10.3
7.6
C-27
Superior 12GTLA
6.86
6.4
10.3
7.0
C-28
Superior 12GTLA
6.86
5.9
10.3
6.0
C-29
Superior 12GTLA
6.86
6.2
10.3
6.5
G-6
Waukesha L3711
1.48
0.02
4.17
1.2
G-7
Waukesha L3711
1.48
0.16
4.17
0.4
DRAFT
31
Testing
Date
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
2nd Q 2004
Tier Classification and Public Review
This application has been determined to be a Tier II based on the request for a significant
modification of a Part 70 permit. The applicant published the DEQ “Notice of Tier II Permit
Application Filing” in the Maysville News, a newspaper of general circulation in Garvin County,
on May 24, 2007. The notice stated that the application was available for public review at the
Elliott Lasater Maysville Library, 508 Williams, Maysville, Oklahoma. The facility will also
publish the DEQ “Notice of Tier II Draft Permit” in the same paper. Information on all permit
actions is available for review by the public in the Air Quality section of the DEQ Web page:
www.deq.state.ok.us.
The permittee has submitted an affidavit that they are not seeking a permit for land use or for any
operation upon land owned by others without their knowledge. The affidavit certifies that the
applicant owns the land.
Information on all permit actions is available for review by the public in the Air Quality section
of the DEQ Web Page: www.deq.state.ok.us.
Fees Paid
A significant modification to a Part 70 permit application fee of $1,000 has been paid.
PERMIT MEMORANDUM 2004-163-TVR (M-2)
DRAFT
32
SECTION IX. SUMMARY
The facility is constructed and operated as described in the permit application. Ambient air
quality standards are not threatened at this site and OFS has submitted modeling demonstrating
that the facility is in compliance with the NAAQS for NO2, although Consent Order 06-063
remains open at this date. There are no active compliance or enforcement Air Quality issues that
affect the issuance of this permit. AQD Compliance and Enforcement and Legal agree to
issuance of this permit. Issuance of the modified permit is recommended, contingent on public
and EPA review.
DRAFT
PERMIT TO OPERATE
AIR POLLUTION CONTROL FACILITY
SPECIFIC CONDITIONS
ONOEK Field Services Company, L.L.C.
Maysville Gas Plant
Permit Number 2004-163-TVR (M-2)
The permittee is authorized to operate in conformity with the specifications submitted to Air
Quality on June 8, 2004, and with supplemental information submitted on August 9, 2004,
September 2, 2004, September 27, 2004, December 6, 2004, January 4, 2005, March 7, 2005, June
3, 2005, September 12, 2005, September 21, 2005, December 12, 2005, March 7, 2006, May 22,
2006, June 23, 2006, January 4, 2007, and April 30, 2007. The Evaluation Memorandum dated
June 8, 2007 explains the derivation of applicable permit requirements and estimates of
emissions; however, it does not contain operating limitations or permit requirements. Operating
under this permit constitutes acceptance of, and consent to, the conditions contained herein:
1.
Points of emissions and emissions limitations for each point:
[OAC 252:100-8-6(a)(1)]
EUG 1 and EUG 2. Grandfathered Engines and Permitted Engines
EUG 1. Grandfathered Engines - no emission limits are applied to these engines under Title V,
but emissions are limited to the existing equipment as it is.
EU
C-1
C-2
C-3
C-4
C-5
C-6
C-7
C-8
C-9
C-10
C-11
C-13
C-14
G-1
G-2
G-3
G-4
G-5
Engine
Clark RA-8
Clark RA-8
Clark RA-8
Clark RA-6
Clark RA-6
Clark RA-8
Clark RA-8
Clark HRA-8
Clark HRA-8
Clark HRA-8
Clark HBA-8
Clark HBA-8
Clark HBA-5
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Ingersoll-Rand PKVG-6
Hp
800
800
800
600
600
800
800
880
880
880
1,760
1,760
1,100
< 500
< 500
< 500
< 500
< 500
Serial #
25938
25937
25936
21133
21132
25927
25928
A25567
A25568
A25572
30269
30271
35601
6HZ131
6HZ132
6HZ134
6HZ136
6NZ182
DRAFT
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
2
EUG 2. Permitted engines - emissions for these units are limited as follows.
EU
Engine
Serial #
C-16
C-17
C-18
C-19
C-20
C-21
C-22
C-23
C-24
C-25.3
C-26
C-27
C-28
C-29
G-6
G-7
WaukeshaL7042 GSIU
WaukeshaL7042 GSIU
WaukeshaL7042 GSIU
Waukesha L5108 GU
Superior 16GTLA
Superior 16GTLA
Superior 16GTLA
Superior 8G825
Superior 6G825
Superior 8GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Superior 12GTLA
Waukesha L3711
Waukesha L3711
387562
387563
387652
387653
306999
306599
291649
282349
292229
293109
304699
304979
304989
295909
48027
48028
NOX
lb/hr
TPY
4.07
17.8
4.07
17.8
4.07
17.8
2.17
9.5
9.16
40.1
9.16
40.1
9.16
40.1
3.53
15.5
2.65
11.6
4.58
20.1
6.87
30.1
6.87
30.1
6.87
30.1
6.87
30.1
1.48
6.47
1.48
6.47
CO
lb/hr
11.5
11.48
11.48
5.21
13.7
13.7
13.7
5.29
3.97
6.87
10.3
10.3
10.3
10.3
4.17
4.17
TPY
50.3
50.3
50.3
22.8
60.2
60.2
60.2
23.2
17.4
30.1
45.1
45.1
45.1
45.1
18.3
18.3
VOC
lb/hr
TPY
2.03
8.90
2.03
8.90
2.03
8.90
1.08
4.75
4.58
20.1
4.58
20.1
4.58
20.1
1.76
7.72
1.32
5.79
2.29
10.0
3.43
15.0
3.43
15.0
3.43
15.0
3.43
15.0
0.74
3.2
0.74
3.2
a. 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]
b. The permittee shall at all times properly operate and maintain all engines in a manner that
will minimize emissions of hydrocarbons or other organic materials.
[OAC 252:100-37-36]
c. The permittee shall keep operation and maintenance (O&M) records for the grandfathered
engines (EUG 1) and for each permitted engine (EUG 2) that is not tested in a quarter.
Such records shall at a minimum include the dates of operation and maintenance, type of
work performed, and the increase, if any, in emissions as a result.
[OAC 252:100-8-6 (a)(3)(B)]
d. At least once per calendar quarter, the permittee shall conduct tests of NOX and CO
emissions in exhaust gases from each engine in EUG 2 and from each replacement
engine/turbine when operating under representative conditions for that period. Testing is
required for each engine in EUG 2 or any replacement engine/turbine that runs for more
than 220 hours during that calendar quarter. A quarterly test may be conducted no sooner
than 20 calendar days after the most recent test. Testing shall be conducted using a
portable analyzer in accordance with a protocol meeting the requirements of the latest
AQD Portable Analyzer Guidance document, or an equivalent method approved by Air
Quality. When four consecutive quarterly tests show the engine/turbine to be in
compliance with the emissions limitations shown in the permit, then the testing frequency
may be reduced to semi-annual testing. A semi-annual test may be conducted no sooner
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
3
than 60 calendar days nor later than 180 calendar days after the most recent test.
Likewise, when the following two consecutive semi-annual tests show compliance, the
testing frequency may be reduced to annual testing. An annual test may be conducted no
sooner than 120 calendar days nor later than 365 calendar days after the most recent test.
Upon any showing of non-compliance with emissions limitations or testing that indicates
that emissions are within 10% of the emission limitations, the testing frequency shall
revert to quarterly. Reduced testing frequency does not apply to engines with catalytic
converters. Any reduction in the testing frequency shall be noted in the next required
compliance certification.
[OAC 252:100-8-6 (a)(3)(A)]
e. When periodic compliance testing shows exhaust emissions from the engines in excess of
the lb/hr limits in Specific Condition No. 1, the permittee shall comply with the
provisions of OAC 252:100-9. Requirements of OAC 252:100-9 include immediate
notification and written notification of Air Quality and demonstrations that the excess
emissions meet the criteria specified in OAC 252:100-9.
[OAC 252:100-9]
f. Replacement (including temporary periods of 6 months or less for maintenance purposes)
of internal combustion engines/turbines with emissions limitations specified in this
permit with engines/turbines of lesser or equal emissions of each pollutant (in lb/hr and
TPY) are authorized under the following conditions.
[OAC 252:100-8-6 (a)(3)(A)]
i. The permittee shall notify AQD in writing not later than 7 days in advance of the
start-up of the replacement engine(s)/turbine(s). Said notice shall identify the
equipment removed and shall include the new engine/turbine make, model, and
horsepower; date of the change, and any change in emissions.
ii. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be
conducted to confirm continued compliance with NOX and CO emission
limitations. A copy of the first quarter testing shall be provided to AQD within
60 days of start-up of each replacement engine/turbine. The test report shall
include the engine/turbine fuel usage, 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.
iii. Replacement equipment and emissions are limited to equipment and emissions
that are not subject to NSPS, NESHAP, or PSD.
[OAC 252:100-8-6 (f)]
g. The rich-burn engines with catalytic converters (C-16, C-17, C-18, C-19, C-23, C-24, G-6
and G-7) shall be allowed to exceed the hourly NOx, CO and VOC limits during the
initial startup of new or reprocessed catalyst for a period not to exceed 100 hours.
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
4
h. The rich-burn engines with horsepower greater than 500 (C-16, C-17, C-18, C-23, and C24) are subject to 40 CFR 63, Subpart ZZZZ and shall comply with all requirements no
later than June 15, 2007. These requirements include, but are not limited to, the
following.
[40 CFR §63.6580 to §63.6675]
i. §63.6600 Emission and Operating Limitations. Reduce formaldehyde emissions by
76 percent or more or limit formaldehyde emissions to 350 ppbvd or less at 15% O2.
For those engines using NSCR, the catalyst must be maintained so that the pressure
drop across the catalyst does not change by more than two inches of water from the
pressure drop across the catalyst that was measured during the initial performance
test. The temperature of the engine exhaust must be maintained so that the catalyst
inlet temperature is greater than or equal to 750˚F and less than or equal to 1,250˚F.
ii. §63.6605 General Compliance Requirements. The engine and catalyst must be
operated and maintained in a manner consistent with good air pollution control
practices for minimizing emissions at all times.
iii. §63.6610-6630 Testing and Initial Compliance Requirements. An initial performance
test and subsequent semiannual or annual performance tests (in accordance with Table
3 of this subpart) are required and must be conducted at any load condition within
plus or minus 10 percent of 100 percent full load. Tests shall be performed in
accordance with the requirements of §63.6620.
iv. §63.6635-6640 Continuous Compliance Requirements. For those engines using
NSCR, continuous compliance with the emissions limitations shall be demonstrated
by: (1) collecting the catalyst inlet temperature data and reducing the data to 4-hour
rolling averages, and (2) maintaining the 4-hour rolling averages within the operating
limitations for the catalyst inlet, and (3) measuring the pressure drop across the
catalyst once per month and demonstrating that the pressure drop across the catalyst is
within the operating limitation established during the performance test. Any
deviations from the emissions limitations or operating limitations must be reported.
v. §63.6645-6660 Notification, Reports, and Records. The permittee shall comply with
all notification, reports, and records procedures and dates.
i. All of the permitted engines in EUG-2 that are equipped with catalytic converters (C-16,
C-17, C-18, C-19, C-23, C-24, G-6, and G-7) are subject to Compliance Assurance
Monitoring (CAM) and shall comply with all applicable requirements and shall perform
monitoring as approved in Table 1 of this permit. Engines C-16, C-17, C-18, C-23, and
C-24 will not be subject to CAM once in compliance with 40 CFR Part 63, Subpart ZZZZ
per Specific Condition No. 1.h.
[40 CFR Part 64]
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
5
j. The permittee shall comply with the Standards of Performance for Equipment Leaks of
VOC from Onshore Natural Gas Processing Plants, NSPS 40 CFR Part 60, Subpart KKK
including, but not limited to, the following:
[40 CFR §60.630 to §60.636]
i. 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 as per §60.635(c).
ii. Information and data used to demonstrate that a reciprocating compressor is not in VOC
service shall be recorded in a log that is kept in a readily accessible location as per
§60.486(j).
iii. C-19, C-24, and C-25 shall be equipped with a VOC leakage capture system operated
and maintained in proper working order per §60.482-3 (h).
iv. As an alternative to iii above, for each compressor subject to the control standards of
40 CFR §§60.482-3(a) thru (h), the permittee may choose to apply the exemption of
40 CFR §60.482-3(i) (no detectable emissions, as indicated by an instrument reading
of less than 500 ppm above background) by monitoring the compressor initially,
annually, and at any other time requested by AQD. The permittee shall keep records
as required by 40 CFR §60.486(e) (1) and (2).
k. The engines for generators G-1, G-2, G-3, G-4, and G-5 are each limited to an output of
less than 500-hp. The permittee shall demonstrate compliance by limiting the power
output from each generator to no more than 330-KW based on the average KW generated
for the hours that each generator operates during a calendar month. Once each day, the
permittee shall record the KW output from each generator during normal operation.
EUG 3. Tanks
Total throughput is limited as follows:
EU
TK-1
Content
Condensate / BS&W
[OAC 252:100-8-6(a)(1)]
Throughput, gallons per day
19,000
a. The throughput limit shall be based on a daily average calculated by dividing a rolling 12month total by 365 days.
b. Emissions from TK-1 shall be vented to the plant process/emergency flare.
Emissions from the tanks listed below are considered insignificant because emissions are less
than 5 TPY; therefore, these units do not have any specific emission limitations.
DRAFT
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
EU
TK-2
TK-3
TK-4
TK-5
TK-6
TK-7
TK-8
Contents
Scrubber Oil, North
Scrubber Oil, South
BS&W / Condensate
Methanol
Methanol
Gasoline
Solvent < 1.5 psia vapor pressure
6
Gallons
23,200
22,000
4,200
8,820
1,730
3,000
580
Tanks TK-4, TK-5, TK-6, and TK-7 shall be equipped with a submerged fill pipe.
[OAC 252:100-37-15(b)]
EUG-4. Fugitive Components (Not subject to NSPS Subpart KKK or MACT Subpart HH)
No emission limits are applied to this EUG under Title V, but emissions are limited to the
existing equipment as it is.
EU
FUG-1
*
Type of Equipment
Connectors
Valves
Open Ended Lines
Flanges
Compressor Seals
Pump Seals
Relief Valves
Estimated Number of
Items
7,000
3,500
280
4,378
56
113
38
Estimated only, not a permit limit.
EUG-5. Fugitive Components (Subject to NSPS Subpart KKK)
No emission limits are applied to this EUG under Title V, but emissions are limited to the
existing equipment as it is.
EU
FUG-2
*
Type of Equipment
Connectors
Valves
Open Ended Lines
Flanges
Compressor Seals
Pump Seals
Relief Valves
Estimated Number of
Items
5,802
2,901
232
3,626
25
-
Estimated only, not a permit limit.
DRAFT
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
7
a. New, modified or reconstructed Process Units at the Maysville Gas Plant are subject to
NSPS 40 CFR Part 60, Subpart KKK. These include, but are not limited to, the two liquids
extraction units (Plant 3 cryo and South Refrigeration System), four inlet headers (Inlet Gas
South Low and High, Anadarko Inlet, and Waukesha Inlet), the glycol dehydration unit
(TEG System), the demethanizer system, Plant 3 regeneration system, the two amine units
that are in VOC service (DGA North Amine Treater and DEA South Amine Treater), and
compressors C-19, C-24 and C-25. The permittee shall comply with this subpart including,
but not limited to, the following requirements:
[40 CFR 60.630-636]
i. §60.632: Standards.
ii. §60.635: Recordkeeping requirements.
iii. §60.636: Reporting requirements.
iv. Information and data used to demonstrate that ancillary equipment is not in VOC
service shall be recorded in a log that is kept in a readily accessible location as per
§60.486(j).
v. Any new construction, reconstruction or modification will be subject to 40 CFR Part
60, Subpart KKK for affected components in VOC service.
EUG 6. Heaters & Boilers
No emission limits are applied to the grandfathered heater H-2 under Title V, but emissions are
limited to the existing equipment as it is. Emissions from heater H-1 are limited as follows.
EU
H-1
H-2
Equipment
Hot Oil Heater (West)
Hot Oil Heater (East)
NOX
lb/hr TPY
4.98
21.8
-
CO
lb/hr
TPY
4.18
18.3
-
VOC
lb/hr TPY
0.28
1.2
-
a. Compliance with the emissions limits for H-1 is demonstrated by the heater’s design heat
input rating of 50 MMBtu/hr and by firing natural gas.
[OAC 252:100-43]
b. Heater H-1 is subject to NSPS Subpart Dc, but must comply only with the initial
notification requirements of 40 CFR §60.48c (a)(1) and the recordkeeping requirements of
40 CFR §60.48c (g).
[40 CFR Part 60 Subpart Dc]
DRAFT
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
8
Emissions from the units listed below are considered insignificant because emissions are less
than 5 TPY; therefore, these units do not have any specific emission limitations.
EU
H-3
H-4
H-5
H-6
H-7
B-1
B-2
Equipment
Regen. Gas Heater (Plant #1)
Regen. Gas Heater (Plant #2)
Glycol Reboiler
Amine Reboiler
Regen. Gas Heater (Plant #3)
Boiler #1 (North, OK36454)
Boiler #2 (South, OK43476)
MMBtu/hr
5.0
1.5
2.5
6.0
7.5
2.0
2.0
Serial #
75122
41593
0132
5991
1276
1740
9777
EUG-7. Process/Emergency Flare
No emission limits are applied to this unit under Title V, but emissions are limited to the existing
equipment as it is.
EU
MMBtu/hr
PFL-1
27,000
Diameter,
inches
24
Height,
feet
110
The process/emergency flare is subject to 40 CFR §60.18 General Control Requirements and the
permittee shall comply with all requirements, including, but not limited to, the following.
[40 CFR §60.18]
a. The flare shall be operated at all times when emissions may be vented to it.
b. The presence of a pilot flame shall be monitored using a thermocouple or any other
equivalent device to detect the presence of a flame.
EUG-8. Acid Gas Flare
Emissions are limited as follows:
EUG-8
Acid Gas Flare
Unit
lb/hr
TPY
NOX
0.10
0.45
CO
0.56
2.45
VOC
1.70
7.45
SO2
12.8
55.9
H2 S
0.14
0.61
a. Emissions of NOX, CO, and VOC are limited by the flare’s design heat rating of 1.5
MMBtu/hr.
[OAC 252:100-43]
DRAFT
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
9
b. H2S concentration and/or the flow rate of the plant inlet gas streams or the acid gas
stream(s) shall be limited to ensure that the emission limits for SO2 are not exceeded.
[OAC 252:100-31-7 (a) and (b)]
i.
The daily sulfur feed rate from the north amine unit and the south amine unit (i.e.,
the H2S in the acid gas), expressed as sulfur, shall be no more than 0.071 LT/D.
H2S concentration and/or the flow rate of the plant inlet gas streams or the acid gas
stream(s) shall be limited to ensure compliance with this daily sulfur feed rate limit.
The daily rate shall be calculated based on daily gas flow rate(s) and a quarterly
measured H2S concentration. Flow and H2S concentration shall be measured at one
of the following locations: (1) plant inlet gas streams, or (2) total acid gas stream
prior to the acid gas flare.
ii.
Compliance with the annual emission limits of SO2 shall be based on a 12-month
rolling total. The permittee shall calculate the total SO2 emissions from the acid
gas flare stack based on 98% conversion of H2S. The calculations shall be based
on a quarterly tested H2S concentration and the daily average gas flow rate for that
month measured at one of the following locations: (1) plant inlet gas streams, or
(2) total acid gas stream prior to the acid gas flare. These calculations will be
submitted with the semiannual monitoring and deviation report.
c. The flare shall have installed, calibrated, maintained, and operated an alarm system that
will signal non-combustion of the gas.
[OAC 252:100-31-26(c)]
EUG-9. VOC Flare
Emissions are limited as follows:
EUG-9
VOC Flare
Unit
lb/hr
TPY
NOX
2.7
12
CO
15
66
VOC
2.5
11
a. Emissions of NOX, CO, and VOC are limited by the flare’s design heat rating of 40
MMBtu/hr.
[OAC 252:100-43]
b. The VOC flare is subject to 40 CFR §60.18 General Control Requirements and the
permittee shall comply with all requirements, including, but not limited to, the following:
[40 CFR §60.18]
i.
The flare shall be operated at all times when emissions may be vented to it.
ii.
The presence of a pilot flame shall be monitored using a thermocouple or any
other equivalent device to detect the presence of a flame.
DRAFT
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
10
EUG-10. Glycol Dehydration Unit
The dehydration unit shall be operated in such a way that benzene emissions are less than 1.0 tpy.
a. Vapors from the rich glycol flash tank shall be vented to the plant inlet gas stream.
b. Vapors from the glycol regenerator still vent shall be either vented to the plant inlet gas
stream or combusted in the process/emergency flare.
c. The permittee shall determine actual average benzene emissions using the model GRIGLYCalc™ Version 3.0 or higher, as required by MACT Subpart HH. Inputs to the
model shall be representative of actual operating conditions. The permittee shall also
maintain records as required by MACT Subpart HH to document compliance with the
benzene limit.
EUG-11. Condensate/Scrubber Oil Truck Loading
Emissions and throughput are limited as follows.
ID #
TL-1
Throughput
VOC
bbl/yr
164,363
TPY
17.7
The throughput limit is based on a 12-month rolling total. Compliance with the throughput limit
demonstrates compliance with the emissions limit.
EUG-12. Fugitive Components (subject to NESHAP Subpart HH)
No emission limits are applied to this EUG under Title V, but emissions are limited to the
existing equipment as it is.
EU
Type of Equipment
FUG-1
Connectors
Valves
Pressure Relief Valves
Pump Seals
*
Number of
Components *
2,197
950
38
9
Estimated only, not a permit limit.
EUG 13. Miscellaneous Process Vent VOC emissions are estimated based on existing
equipment items but do not have a specific limitation.
EU ID #
VENT
Point #
VENT
Emission Units
Miscellaneous Process Vents
Date Constructed
1948
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
11
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, or other approved methods.
Compliance shall be demonstrated at least once annually.
3. The permittee shall be authorized to operate this facility continuously (24 hours per day, every
day of the year).
[OAC 252:100-8-6(a)]
4. a. The fugitive components of EUG 12 and the glycol dehydrator of EUG 10 are subject to
CFR 40 Part 63, Subpart HH for affected components in VHAP service (defined as HAP
content greater than 10% by weight) and shall comply with all applicable requirements
including, but not limited to, the following.
[40 CFR §63.760 to §63.779]
i. 40 CFR 63.762: Startup, shutdowns, and malfunctions
ii. 40 CFR 63.764: General standards
iii. 40 CFR 63.765: Glycol dehydration unit process vents standards. Emissions from the
rich glycol flash tank and the glycol regenerator still vent are subject to Subpart HH,
but are exempt from the standards per §63.764(e)(1)(ii). The permittee shall maintain
records per §63.774(d)(1) demonstrating that actual benzene emissions are below 0.90
megagram (1.0 TPY) using the methods outlined in §63.772(b)(2).
iv. 40 CFR 63.766: Storage vessel standards. Tank TK-1 is not an affected source since
it has a federally enforceable throughput limit of 19,000 gallons per day based on an
annual average.
v. 40 CFR 63.769: Equipment leak standards. All components in vapor service and light
liquid service are below the 10% by weight threshold except those components in
natural gasoline service, condensate service, and the engine jacket water systems,
which use ethylene glycol. Documentation of those components exempt from the
standards must be made per §63.764(e)(2) and records kept per §63.774(d)(1).
vi. 40 CFR 63.772:
demonstrations
Test
methods, compliance procedures, and compliance
vii. 40 CFR 63.774: Recordkeeping requirements
viii. 40 CFR 63.775: Reporting requirements
ix. 40 CFR 63.776: Delegation of authority
x.
40 CFR 63.777: Alternate means of emission limitation
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
12
b. Quarterly visual inspections of equipment in ethylene glycol VHAP service may be used
as a monitoring alternative to Method 21.
[40 CFR §63.8(b)(ii)]
c. Ancillary equipment and compressors that are subject to this subpart (40 CFR Part 63,
Subpart HH) and are also subject to 40 CFR Part 60, Subpart KKK, are only required to
comply with the requirements of 40 CFR Part 60, Subpart KKK as an approved
monitoring alternative. The permittee shall document that they are complying with 40
CFR Part 60, Subpart KKK by keeping the records specified in 40 CFR 63.774(b)(9).
5. The north (DGA) and south (DEA) amine units are subject to 40 CFR Part 60, Subpart LLL,
but are exempt from any control standards. The permittee shall comply with §60.647 (c),
which requires the facility to keep, for the life of the facility, an analysis demonstrating that the
facility’s design capacity is less than 2 long tons per day (LT/D) of H2S in the acid gas
(expressed as sulfur).
[40 CFR §60.40 to §60.648]
6. The glycol dehydration unit in EUG-10 shall be equipped with a condenser and uncondensed
regenerator vent vapors shall be routed either to the plant inlet or to the process/emergency
flare. The unit is subject to Compliance Assurance Monitoring (CAM) and shall comply
with all applicable requirements and shall perform monitoring as approved in Table 2,
Appendix A of this permit.
[40 CFR Part 64]
7. The following records shall be maintained on-site to verify Insignificant Activities. No
recordkeeping is required for those operations that qualify as Trivial Activities.
[OAC 252:100-8-6 (a)(3)(B)]
a. For emissions from condensate tanks with a design capacity of 400 gallons or less in
ozone attainment areas: the tank capacity and contents.
b. For surface coating operations which do not exceed a combined total usage of more than
60 gallons/month of coatings, thinners, and clean-up solvents at any one emissions unit:
the total gallons used (monthly).
c. For activities having the potential to emit no more than 5 TPY (actual) of any criteria
pollutant: the type of activity and the amount of emissions from that activity (annual).
8. The permittee shall maintain records of operations as listed below. These records shall be
maintained on-site for at least five years after the date of recording and shall be provided to
regulatory personnel upon request.
[OAC 252:100-43]
a. O&M records for each “grandfathered” engine in EUG-1.
b. O&M records for any engine in EUG-2, if operated less than 220 hours per quarter
and not tested.
c. Periodic testing for NOX and CO for each engine in EUG-2.
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
13
d. For the fuel burned, the appropriate document(s) as described in Specific Condition No. 2.
e. Records required by 40 CFR §63, Subpart ZZZZ.
f. Records required by 40 CFR §60, Subpart KKK, including, but not limited to, records
demonstrating that a reciprocating compressor is in wet gas service or is not in VOC
service, records demonstrating that equipment components are not in VOC service, and
records required by LDAR program provisions.
g. Records required by 40 CFR §60.647 (c) demonstrating that both the north (DGA) and
south (DEA) amine units have a design capacity less than 2 long tons per day (LT/D) of H2S
in the acid gas (expressed as sulfur).
h. Throughput of tank TK-1 (rolling 12-month total).
i. Records of quarterly tested H2S concentration and the daily average gas flow rate(s)
measured at one of the following locations: (1) plant inlet gas streams, or (2) total acid
gas stream prior to the acid gas flare. And calculations of SO2 emissions from the acid
gas flare (12-month rolling total).
j. Records required by 40 CFR §63, Subpart HH, including, but not limited to, records
demonstrating that actual average benzene emissions from the glycol unit vents are
less than 1.0 TPY (annual), records documenting equipment components that are
exempt from the standards of Subpart HH, and records required by LDAR program
provisions.
k. Records required by 40 CFR §64, CAM.
l. Monthly records of the average KW output from generators G-1, G-2, G-3, G-4, and
G-5.
9. No later than 30 days after each anniversary date of the issuance of the original Part 70 permit
(December 8, 1999), the permittee shall submit to Air Quality Division of DEQ, with a copy
to the US EPA, Region 6, a certification of compliance with the terms and conditions of this
permit
[OAC 252:100-8-6 (c)(5)(A), (C) & (D)]
10. This permit supersedes all previous air quality permits for this facility, which are now null
and void.
11. The permittee shall complete the NAAQS for NOX compliance plan as defined in Consent
Order 06-063.
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
TABLE 1. ONEOK FIELD SERVICES COMPANY, L.L.C. COMPLIANCE ASSURANCE MONITORING FOR THE
ENGINES WITH CATALYTIC CONVERTERS
I.
Indicator
Measurement Approach
II. Indicator Range
III. Performance Criteria
A. Data
Representativeness
Indicator No. 1
Temperature of exhaust gas into catalyst.
Exhaust gas temperature is measured
continuously using an inline
thermocouple and translated by a temp.
scanner or other end device.
The indicator range is above 700ºF, but
lower than 1,250ºF. Excursions trigger
corrective action, logging, and reporting
in semiannual report.
Temperature is measured at the inlet to
the catalyst by a thermocouple with a
minimum accuracy of +/-5ºF.
Indicator No 2
Pressure differential (decrease) of
exhaust gas (press. in - press. out across
catalyst)
Pressure differential is measured weekly
using a water column (w.c.) or gauge or
other device indicating pressure for inlet
and outlet pressures.
The indicator range differential is above
0.5 inches w.c., but less than 5 inches.
Excursions trigger corrective action,
logging, and reporting in semiannual
report.
Pressure is measured at the inlet and
outlet of the catalyst by pressure gauge.
The minimum accuracy is +/-0.1 inches
w.c.
Guarantee from gauge manufacturer.
B. Verification of
Operational Status
Guarantee from thermocouple
manufacturer.
C. QA/QC Practices
and Criteria
D. Monitoring
Frequency
Thermocouple scanner or other end
device is calibrated annually.
Temperature measured continuously and
recorded on log sheets once daily.
Compliance assumed daily if no
corrective action events occur.
Temperature data recorded on log sheet
once daily. Otherwise, excursions
trigger corrective action, logging, and
reporting in semiannual report.
Gauge or other end device is calibrated
annually.
Pressure differential is measured weekly
and recorded on log sheets. Compliance
assumed weekly if no corrective action
events occur.
Pressure data recorded on log sheet once
weekly. Otherwise, excursions trigger
corrective action, logging, and reporting
in semiannual report.
None, not to exceed minimums and
maximums.
None, not to exceed minimums and
maximums.
Data Collection
Procedures
Averaging period
Indicator No. 3
Inspection & Preventative Maintenance
(I/PM).
Monthly inspection according to PM plan;
maintenance performed as needed.
Excursions trigger corrective action, logging,
and reporting in semiannual report.
Inspections are performed on the engine,
AFR, and the catalyst.
After 3,000 hours or less, the AFR system is
tested for operability and the AFR set points
are verified. Monthly PM inspections verify
operating characteristics of the system.
Qualified personnel perform inspections.
Monthly inspection in accordance with PM
plan.
Records are maintained to document the
monthly inspections and any required
maintenance. Record any excursions that
required corrective action. If no excursions,
compliance is assumed on a monthly basis.
NA
SPECIFIC CONDITIONS 2004-163-TVR (M-2)
DRAFT
TABLE 2. ONEOK FIELD SERVICES COMPANY, L.L.C. COMPLIANCE
ASSURANCE
MONITORING FOR THE GLYCOL DEHYDRATION UNIT
I.
Indicator
Measurement Approach
II. Indicator Range
III. Performance Criteria
A. Data
Representativeness
B. Verification of
Operational Status
C. QA/QC Practices
and Criteria
D. Monitoring
Frequency
Data Collection
Procedures
Averaging period
Indicator No. 1
Flare flame indicator.
Flame is continuously monitored using
an inline thermocouple or flame sensor
and translated by a temperature scanner
or other end device.
The indicator range is positive only.
Excursions trigger corrective action,
logging, and reporting in semiannual
report.
Presence of flame is monitored at the
flare outlet by thermocouple or flame
sensor.
Guarantee from sensor manufacturer.
Sensor or other end device is calibrated
annually.
Flame sensor will operate continuously,
recorded on log sheets once daily.
Compliance assumed daily if no
corrective action events.
Operating status (“OK” or “ALARM”)
recorded on log sheet once daily.
Otherwise, excursions trigger corrective
action, logging, and reporting in
semiannual report.
None.
Indicator No. 2
Inspection & Preventative Maintenance
(I/PM).
Monthly inspection according to PM plan;
maintenance performed as needed.
Excursions trigger corrective action, logging,
and reporting in semiannual report.
Inspections are performed on the condenser
system.
Monthly PM inspections verify operating
characteristics of the system.
Qualified personnel perform inspections.
Monthly inspection in accordance with PM
plan.
Records are maintained to document the
monthly inspections and any required
maintenance. Record any excursions that
required corrective action. If no excursions,
compliance is assumed on a daily basis.
NA
TITLE V (PART 70) PERMIT TO OPERATE / CONSTRUCT
STANDARD CONDITIONS
(December 6, 2006)
SECTION I.
DUTY TO COMPLY
A. This is a permit to operate / construct this specific facility in accordance with Title V of the
federal Clean Air Act (42 U.S.C. 7401, et seq.) and under the authority of the Oklahoma Clean
Air Act and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]
B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma
Department of Environmental Quality (DEQ). The permit does not relieve the holder of the
obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or
ordinances.
[Oklahoma Clean Air Act, 27A O.S. § 2-5-112]
C. The permittee shall comply with all conditions of this permit. Any permit noncompliance
shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement
action, for revocation of the approval to operate under the terms of this permit, or for denial of an
application to renew this permit. All terms and conditions (excluding state-only requirements)
are enforceable by the DEQ, by EPA, and by citizens under section 304 of the Clean Air Act.
This permit is valid for operations only at the specific location listed.
[40 CFR §70.6(b), OAC 252:100-8-1.3 and 8-6 (a)(7)(A) and (b)(1)]
D. It shall not be a defense for a permittee in an enforcement action that it would have been
necessary to halt or reduce the permitted activity in order to maintain compliance with the
conditions of the permit.
[OAC 252:100-8-6 (a)(7)(B)]
SECTION II.
REPORTING OF DEVIATIONS FROM PERMIT TERMS
A. Any exceedance resulting from emergency conditions and/or posing an imminent and
substantial danger to public health, safety, or the environment shall be reported in accordance
with Section XIV.
[OAC 252:100-8-6 (a)(3)(C)(iii)]
B. Deviations that result in emissions exceeding those allowed in this permit shall be reported
consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements.
[OAC 252:100-8-6 (a)(3)(C)(iv)]
C. Oral notifications (fax is also acceptable) shall be made to the AQD central office 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 the permittee becomes aware of the exceedance. Within ten (10) working
days after the immediate notice is given, the owner operator shall submit a written report
describing the extent of the excess emissions and response actions taken by the facility. Every
written report submitted under OAC 252:100-8-6 (a)(3)(C)(iii) shall be certified by a responsible
official.
[OAC 252:100-8-6 (a)(3)(C)(iii)]
TITLE V PERMIT STANDARD CONDITIONS
SECTION III.
2
MONITORING, TESTING, RECORDKEEPING & REPORTING
A. The permittee shall keep records as specified in this permit. Unless a different retention
period or retention conditions are set forth by a specific term in this permit, these records,
including monitoring data and necessary support information, shall be retained on-site or at a
nearby field office for a period of at least five years from the date of the monitoring sample,
measurement, report, or application, and shall be made available for inspection by regulatory
personnel upon request. Support information includes all original strip-chart recordings for
continuous monitoring instrumentation, and copies of all reports required by this permit. Where
appropriate, the permit may specify that records may be maintained in computerized form.
[OAC 252:100-8-6 (a)(3)(B)(ii), 8-6 (c)(1), and 8-6 (c)(2)(B)]
B. Records of required monitoring shall include:
(1) the date, place and time of sampling or measurement;
(2) the date or dates analyses were performed;
(3) the company or entity which performed the analyses;
(4) the analytical techniques or methods used;
(5) the results of such analyses; and
(6) the operating conditions as existing at the time of sampling or measurement.
[OAC 252:100-8-6 (a)(3)(B)(i)]
C. No later than 30 days after each six (6) month period, after the date of the issuance of the
original Part 70 operating permit, the permittee shall submit to AQD a report of the results of any
required monitoring. All instances of deviations from permit requirements since the previous
report shall be clearly identified in the report.
[OAC 252:100-8-6 (a)(3)(C)(i) and (ii)]
D. If any testing shows emissions in excess of limitations specified in this permit, the owner or
operator shall comply with the provisions of Section II of these standard conditions.
[OAC 252:100-8-6 (a)(3)(C)(iii)]
E. In addition to any monitoring, recordkeeping or reporting requirement specified in this
permit, monitoring and reporting may be required under the provisions of OAC 252:100-43,
Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean
Air Act or Oklahoma Clean Air Act.
F. Submission of quarterly or semi-annual reports required by any applicable requirement that
are duplicative of the reporting required in the previous paragraph will satisfy the reporting
requirements of the previous paragraph if noted on the submitted report.
G. Every report submitted under OAC 252:100-8-6 and OAC 252:100-43 shall be certified by a
responsible official.
[OAC 252:100-8-6 (a)(3)(C)(iv)]
H. Any owner or operator subject to the provisions of NSPS shall maintain records of the
occurrence and duration of any start-up, shutdown, or malfunction in the operation of an affected
facility or any malfunction of the air pollution control equipment.
[40 CFR 60.7 (b)]
TITLE V PERMIT STANDARD CONDITIONS
3
I. Any owner or operator subject to the provisions of NSPS shall maintain a file of all
measurements and other information required by the subpart recorded in a permanent file suitable
for inspection. This file shall be retained for at least two years following the date of such
measurements, maintenance, and records.
[40 CFR 60.7 (d)]
J. The permittee of a facility that is operating subject to a schedule of compliance shall submit
to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for
achieving the activities, milestones or compliance required in the schedule of compliance and the
dates when such activities, milestones or compliance was achieved. The progress reports shall
also contain an explanation of why any dates in the schedule of compliance were not or will not
be met, and any preventative or corrective measures adopted.
[OAC 252:100-8-6 (c)(4)]
K. All testing must be conducted by methods approved by the Division Director under the
direction of qualified personnel. All tests shall be made and the results calculated in accordance
with standard test procedures. The use of alternative test procedures must be approved by EPA.
When a portable analyzer is used to measure emissions it shall be setup, calibrated, and operated
in accordance with the manufacturer’s instructions and in accordance with a protocol meeting the
requirements of the “AQD Portable Analyzer Guidance” document or an equivalent method
approved by Air Quality. [40 CFR §70.6(a), 40 CFR §51.212(c)(2), 40 CFR § 70.7(d), 40 CFR
§70.7(e)(2), OAC 252:100-8-6 (a)(3)(A)(iv), and OAC 252:100-43]
The reporting of total particulate matter emissions as required in Part 70, PSD, OAC 252:100-19,
and Emission Inventory, shall be conducted in accordance with applicable testing or calculation
procedures, modified to include back-half condensables, for the concentration of particulate
matter less than 10 microns in diameter PM10. NSPS may allow reporting of only particulate
matter emissions caught in the filter (obtained using Reference Method 5). [US EPA Publication
(September 1994). PM10 Emission Inventory Requirements - Final Report. Emission Inventory
Branch: RTP, N.C.]; [Federal Register: Volume 55, Number 74, 4/17/90, pp.14246-14249. 40
CFR Part 51: Preparation, Adoption, and Submittal of State Implementation Plans; Methods for
Measurement of PM10 Emissions from Stationary Sources]; [Letter from Thompson G. Pace,
EPA OAQPS to Sean Fitzsimmons, Iowa DNR, March 31, 1994 (regarding PM10 Condensables)]
L. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required
by 40 CFR Part 60, 61, and 63, for all equipment constructed or operated under this permit
subject to such standards.
[OAC 252:100-4-5 and OAC 252:100-41-15]
SECTION IV.
COMPLIANCE CERTIFICATIONS
A. No later than 30 days after each anniversary date of the issuance of the original Part 70
operating permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a
certification of compliance with the terms and conditions of this permit and of any other
applicable requirements which have become effective since the issuance of this permit. The
compliance certification shall also include such other facts as the permitting authority may
require to determine the compliance status of the source.
[OAC 252:100-8-6 (c)(5)(A), (C)(v), and (D)]
TITLE V PERMIT STANDARD CONDITIONS
4
B. The certification shall describe the operating permit term or condition that is the basis of the
certification; the current compliance status; whether compliance was continuous or intermittent;
the methods used for determining compliance, currently and over the reporting period; and a
statement that the facility will continue to comply with all applicable requirements.
[OAC 252:100-8-6 (c)(5)(C)(i)-(iv)]
C. Any document required to be submitted in accordance with this permit shall be certified as
being true, accurate, and complete by a responsible official. This certification shall state that,
based on information and belief formed after reasonable inquiry, the statements and information
in the certification are true, accurate, and complete.
[OAC 252:100-8-5 (f) and OAC 252:100-8-6 (c)(1)]
D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions
units or stationary sources that are not in compliance with all applicable requirements. This
schedule shall include a schedule of remedial measures, including an enforceable sequence of
actions with milestones, leading to compliance with any applicable requirements for which the
emissions unit or stationary source is in noncompliance. This compliance schedule shall
resemble and be at least as stringent as that contained in any judicial consent decree or
administrative order to which the emissions unit or stationary source is subject. Any such
schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the
applicable requirements on which it is based, except that a compliance plan shall not be required
for any noncompliance condition which is corrected within 24 hours of discovery.
[OAC 252:100-8-5 (e)(8)(B) and OAC 252:100-8-6 (c)(3)]
SECTION V.
REQUIREMENTS THAT BECOME APPLICABLE DURING THE
PERMIT TERM
The permittee shall comply with any additional requirements that become effective during the
permit term and that are applicable to the facility. Compliance with all new requirements shall
be certified in the next annual certification.
[OAC 252:100-8-6 (c)(6)]
SECTION VI.
PERMIT SHIELD
A. Compliance with the terms and conditions of this permit (including terms and conditions
established for alternate operating scenarios, emissions trading, and emissions averaging, but
excluding terms and conditions for which the permit shield is expressly prohibited under OAC
252:100-8) shall be deemed compliance with the applicable requirements identified and included
in this permit.
[OAC 252:100-8-6 (d)(1)]
B. Those requirements that are applicable are listed in the Standard Conditions and the Specific
Conditions of this permit. Those requirements that the applicant requested be determined as not
applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6 (d)(2)]
TITLE V PERMIT STANDARD CONDITIONS
SECTION VII.
5
ANNUAL EMISSIONS INVENTORY & FEE PAYMENT
The permittee shall file with the AQD an annual emission inventory and shall pay annual fees
based on emissions inventories. The methods used to calculate emissions for inventory purposes
shall be based on the best available information accepted by AQD.
[OAC 252:100-5-2.1, -5-2.2, and OAC 252:100-8-6 (a)(8)]
SECTION VIII.
TERM OF PERMIT
A. Unless specified otherwise, the term of an operating permit shall be five years from the date
of issuance.
[OAC 252:100-8-6 (a)(2)(A)]
B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely
and complete renewal application has been submitted at least 180 days before the date of
expiration.
[OAC 252:100-8-7.1 (d)(1)]
C. A duly issued construction permit or authorization to construct or modify will terminate and
become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction
is not commenced within 18 months after the date the permit or authorization was issued, or if
work is suspended for more than 18 months after it is commenced.
[OAC 252:100-8-1.4(a)]
D. The recipient of a construction permit shall apply for a permit to operate (or modified
operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)]
SECTION IX.
SEVERABILITY
The provisions of this permit are severable and if any provision of this permit, or the application
of any provision of this permit to any circumstance, is held invalid, the application of such
provision to other circumstances, and the remainder of this permit, shall not be affected thereby.
[OAC 252:100-8-6 (a)(6)]
SECTION X.
PROPERTY RIGHTS
A. This permit does not convey any property rights of any sort, or any exclusive privilege.
[OAC 252:100-8-6 (a)(7)(D)]
B. This permit shall not be considered in any manner affecting the title of the premises upon
which the equipment is located and does not release the permittee from any liability for damage
to persons or property caused by or resulting from the maintenance or operation of the equipment
for which the permit is issued.
[OAC 252:100-8-6 (c)(6)]
SECTION XI.
DUTY TO PROVIDE INFORMATION
A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty
(60) days of the request unless the DEQ specifies another time period, any information that the
TITLE V PERMIT STANDARD CONDITIONS
6
DEQ may request to determine whether cause exists for modifying, reopening, revoking,
reissuing, terminating the permit or to determine compliance with the permit. Upon request, the
permittee shall also furnish to the DEQ copies of records required to be kept by the permit.
[OAC 252:100-8-6 (a)(7)(E)]
B. The permittee may make a claim of confidentiality for any information or records submitted
pursuant to 27A O.S. 2-5-105(18). Confidential information shall be clearly labeled as such and
shall be separable from the main body of the document such as in an attachment.
[OAC 252:100-8-6 (a)(7)(E)]
C. Notification to the AQD of the sale or transfer of ownership of this facility is required and
shall be made in writing within 10 days after such date.
[Oklahoma Clean Air Act, 27A O.S. § 2-5-112 (G)]
SECTION XII.
REOPENING, MODIFICATION & REVOCATION
A. The permit may be modified, revoked, reopened and reissued, or terminated for cause.
Except as provided for minor permit modifications, the filing of a request by the permittee for a
permit modification, revocation, reissuance, termination, notification of planned changes, or
anticipated noncompliance does not stay any permit condition.
[OAC 252:100-8-6 (a)(7)(C) and OAC 252:100-8-7.2 (b)]
B. The DEQ will reopen and revise or revoke this permit as necessary to remedy deficiencies in
the following circumstances:
[OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)]
(1) Additional requirements under the Clean Air Act become applicable to a major source
category three or more years prior to the expiration date of this permit. No such
reopening is required if the effective date of the requirement is later than the expiration
date of this permit.
(2) The DEQ or the EPA determines that this permit contains a material mistake or that the
permit must be revised or revoked to assure compliance with the applicable requirements.
(3) The DEQ or the EPA determines that inaccurate information was used in establishing the
emission standards, limitations, or other conditions of this permit. The DEQ may revoke
and not reissue this permit if it determines that the permittee has submitted false or
misleading information to the DEQ.
C. If “grandfathered” status is claimed and granted for any equipment covered by this permit, it
shall only apply under the following circumstances:
[OAC 252:100-5-1.1]
(1) It only applies to that specific item by serial number or some other permanent
identification.
(2) Grandfathered status is lost if the item is significantly modified or if it is relocated outside
the boundaries of the facility.
TITLE V PERMIT STANDARD CONDITIONS
7
D. To make changes other than (1) those described in Section XVIII (Operational Flexibility),
(2) administrative permit amendments, and (3) those not defined as an Insignificant Activity
(Section XVI) or Trivial Activity (Section XVII), the permittee shall notify AQD. Such changes
may require a permit modification.
[OAC 252:100-8-7.2 (b)]
E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that
are not specifically approved by this permit are prohibited.
[OAC 252:100-8-6 (c)(6)]
SECTION XIII.
INSPECTION & ENTRY
A. Upon presentation of credentials and other documents as may be required by law, the
permittee shall allow authorized regulatory officials to perform the following (subject to the
permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18)
for confidential information submitted to or obtained by the DEQ under this section):
[OAC 252:100-8-6 (c)(2)]
(1) enter upon the permittee's premises during reasonable/normal working hours where a
source is located or emissions-related activity is conducted, or where records must be
kept under the conditions of the permit;
(2) have access to and copy, at reasonable times, any records that must be kept under the
conditions of the permit;
(3) inspect, at reasonable times and using reasonable safety practices, any facilities,
equipment (including monitoring and air pollution control equipment), practices, or
operations regulated or required under the permit; and
(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times
substances or parameters for the purpose of assuring compliance with the permit.
SECTION XIV.
EMERGENCIES
A. Any emergency and/or exceedance that poses an imminent and substantial danger to public
health, safety, or the environment shall be reported to AQD as soon as is practicable; but under
no circumstance shall notification be more than 24 hours after the exceedance.
[OAC 252:100-8-6 (a)(3)(C)(iii)(II)]
B. An "emergency" means any situation arising from sudden and reasonably unforeseeable
events beyond the control of the source, including acts of God, which situation requires
immediate corrective action to restore normal operation, and that causes the source to exceed a
technology-based emission limitation under this permit, due to unavoidable increases in
emissions attributable to the emergency.
[OAC 252:100-8-2]
C. An emergency shall constitute an affirmative defense to an action brought for noncompliance
with such technology-based emission limitation if the conditions of paragraph D below are met.
[OAC 252:100-8-6 (e)(1)]
TITLE V PERMIT STANDARD CONDITIONS
8
D. The affirmative defense of emergency shall be demonstrated through properly signed,
contemporaneous operating logs or other relevant evidence that:
[OAC 252:100-8-6 (e)(2), (a)(3)(C)(iii)(I) and (IV)]
(1) an emergency occurred and the permittee can identify the cause or causes of the
emergency;
(2) the permitted facility was at the time being properly operated;
(3) during the period of the emergency the permittee took all reasonable steps to minimize
levels of emissions that exceeded the emission standards or other requirements in this
permit;
(4) the permittee submitted timely notice of the emergency to AQD, pursuant to the
applicable regulations (i.e., for emergencies that pose an “imminent and substantial
danger,” within 24 hours of the time when emission limitations were exceeded due to the
emergency; 4:30 p.m. the next business day for all other emergency exceedances). See
OAC 252:100-8-6(a)(3)(C)(iii)(I) and (II). This notice shall contain a description of the
emergency, the probable cause of the exceedance, any steps taken to mitigate emissions,
and corrective actions taken; and
(5) the permittee submitted a follow up written report within 10 working days of first
becoming aware of the exceedance.
E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an
emergency shall have the burden of proof.
[OAC 252:100-8-6 (e)(3)]
SECTION XV.
RISK MANAGEMENT PLAN
The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop
and register with the appropriate agency a risk management plan by June 20, 1999, or the
applicable effective date.
[OAC 252:100-8-6 (a)(4)]
SECTION XVI.
INSIGNIFICANT ACTIVITIES
Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to
operate individual emissions units that are either on the list in Appendix I to OAC Title 252,
Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below.
Any activity to which a State or federal applicable requirement applies is not insignificant even if
it meets the criteria below or is included on the insignificant activities list. [OAC 252:100-8-2]
(1) 5 tons per year of any one criteria pollutant.
(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an
aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year
for single HAP that the EPA may establish by rule.
TITLE V PERMIT STANDARD CONDITIONS
SECTION XVII.
9
TRIVIAL ACTIVITIES
Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to
operate any individual or combination of air emissions units that are considered inconsequential
and are on the list in Appendix J. Any activity to which a State or federal applicable requirement
applies is not trivial even if included on the trivial activities list.
[OAC 252:100-8-2]
SECTION XVIII.
OPERATIONAL FLEXIBILITY
A. A facility may implement any operating scenario allowed for in its Part 70 permit without the
need for any permit revision or any notification to the DEQ (unless specified otherwise in the
permit). When an operating scenario is changed, the permittee shall record in a log at the facility
the scenario under which it is operating.
[OAC 252:100-8-6 (a)(10) and (f)(1)]
B. The permittee may make changes within the facility that:
(1) result in no net emissions increases,
(2) are not modifications under any provision of Title I of the federal Clean Air Act, and
(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit
to be exceeded;
provided that the facility provides the EPA and the DEQ with written notification as required
below in advance of the proposed changes, which shall be a minimum of 7 days, or 24 hours for
emergencies as defined in OAC 252:100-8-6 (e). The permittee, the DEQ, and the EPA shall
attach each such notice to their copy of the permit. For each such change, the written notification
required above shall include a brief description of the change within the permitted facility, the
date on which the change will occur, any change in emissions, and any permit term or condition
that is no longer applicable as a result of the change. The permit shield provided by this permit
does not apply to any change made pursuant to this subsection.
[OAC 252:100-8-6 (f)(2)]
SECTION XIX.
OTHER APPLICABLE & STATE-ONLY REQUIREMENTS
A. The following applicable requirements and state-only requirements apply to the facility
unless elsewhere covered by a more restrictive requirement:
(1) No person shall cause or permit the discharge of emissions such that National Ambient
Air Quality Standards (NAAQS) are exceeded on land outside the permitted facility.
[OAC 252:100-3]
(2) Open burning of refuse and other combustible material is prohibited except as authorized
in the specific examples and under the conditions listed in the Open Burning Subchapter.
[OAC 252:100-13]
(3) No particulate emissions from any fuel-burning equipment with a rated heat input of 10
MMBTUH or less shall exceed 0.6 lb/MMBTU.
[OAC 252:100-19]
(4) For all emissions units not subject to an opacity limit promulgated under 40 CFR, Part 60,
NSPS, no discharge of greater than 20% opacity is allowed except for short-term
TITLE V PERMIT STANDARD CONDITIONS
(5)
(6)
(7)
(8)
10
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.
[OAC 252:100-25]
No visible fugitive dust emissions shall be discharged beyond the property line on which
the emissions originate in such a manner as to damage or to interfere with the use of
adjacent properties, or cause air quality standards to be exceeded, or interfere with the
maintenance of air quality standards.
[OAC 252:100-29]
No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2
lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur
dioxide.
[OAC 252:100-31]
Volatile Organic Compound (VOC) storage tanks built after December28, 1974, and with
a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia or
greater under actual conditions shall be equipped with a permanent submerged fill pipe or
with a vapor-recovery system.
[OAC 252:100-37-15(b)]
All fuel-burning equipment shall at all times be properly operated and maintained in a
manner that will minimize emissions of VOCs.
[OAC 252:100-37-36]
SECTION XX.
STRATOSPHERIC OZONE PROTECTION
A. The permittee shall comply with the following standards for production and consumption of
ozone-depleting substances.
[40 CFR 82, Subpart A]
1. Persons producing, importing, or placing an order for production or importation of certain
class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the
requirements of §82.4.
2. Producers, importers, exporters, purchasers, and persons who transform or destroy certain
class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping
requirements at §82.13.
3. Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons,
HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane
(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include
HCFCs.
B. If the permittee performs a service on motor (fleet) vehicles when this service involves an
ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air
conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term
“motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the
vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the
air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger
buses using HCFC-22 refrigerant.
[40 CFR 82, Subpart B]
C. The permittee shall comply with the following standards for recycling and emissions
reduction except as provided for MVACs in Subpart B.
[40 CFR 82, Subpart F]
TITLE V PERMIT STANDARD CONDITIONS
11
(1) Persons opening appliances for maintenance, service, repair, or disposal must comply
with the required practices pursuant to § 82.156.
(2) Equipment used during the maintenance, service, repair, or disposal of appliances must
comply with the standards for recycling and recovery equipment pursuant to § 82.158.
(3) Persons performing maintenance, service, repair, or disposal of appliances must be
certified by an approved technician certification program pursuant to § 82.161.
(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply
with record-keeping requirements pursuant to § 82.166.
(5) Persons owning commercial or industrial process refrigeration equipment must comply
with leak repair requirements pursuant to § 82.158.
(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant
must keep records of refrigerant purchased and added to such appliances pursuant to §
82.166.
SECTION XXI.
TITLE V APPROVAL LANGUAGE
A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is
not inconsistent with Federal requirements, to provide for incorporation of requirements
established through construction permitting into the Sources’ Title V permit without causing
redundant review. Requirements from construction permits may be incorporated into the Title V
permit through the administrative amendment process set forth in Oklahoma Administrative
Code 252:100-8-7.2(a) only if the following procedures are followed:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
The construction permit goes out for a 30-day public notice and comment using the
procedures set forth in 40 Code of Federal Regulations (CFR) § 70.7 (h)(1). This
public notice shall include notice to the public that this permit is subject to
Environmental Protection Agency (EPA) review, EPA objection, and petition to EPA,
as provided by 40 CFR § 70.8; that the requirements of the construction permit will be
incorporated into the Title V permit through the administrative amendment process;
that the public will not receive another opportunity to provide comments when the
requirements are incorporated into the Title V permit; and that EPA review, EPA
objection, and petitions to EPA will not be available to the public when requirements
from the construction permit are incorporated into the Title V permit.
A copy of the construction permit application is sent to EPA, as provided by 40 CFR §
70.8(a)(1).
A copy of the draft construction permit is sent to any affected State, as provided by 40
CFR § 70.8(b).
A copy of the proposed construction permit is sent to EPA for a 45-day review period
as provided by 40 CFR § 70.8(a) and (c).
The DEQ complies with 40 CFR § 70.8 (c) upon the written receipt within the 45-day
comment period of any EPA objection to the construction permit. The DEQ shall not
issue the permit until EPA’s objections are resolved to the satisfaction of EPA.
The DEQ complies with 40 CFR § 70.8 (d).
A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8
(a).
TITLE V PERMIT STANDARD CONDITIONS
12
(8)
The DEQ shall not issue the proposed construction permit until any affected State and
EPA have had an opportunity to review the proposed permit, as provided by these
permit conditions.
(9) Any requirements of the construction permit may be reopened for cause after
incorporation into the Title V permit by the administrative amendment process, by DEQ
as provided in OAC 252:100-8-7.3 (a), (b), and (c), and by EPA as provided in 40 CFR
§ 70.7 (f) and (g).
(10) The DEQ shall not issue the administrative permit amendment if performance tests fail
to demonstrate that the source is operating in substantial compliance with all permit
requirements.
B. To the extent that these conditions are not followed, the Title V permit must go through the
Title V review process.
SECTION XXII.
CREDIBLE EVIDENCE
For the purpose of submitting compliance certifications or establishing whether or not a person
has violated or is in violation of any provision of the Oklahoma implementation plan, nothing
shall preclude the use, including the exclusive use, of any credible evidence or information,
relevant to whether a source would have been in compliance with applicable requirements if the
appropriate performance or compliance test or procedure had been performed.
[OAC 252:100-43-6]
ONEOK Field Services Company, L.L.C.
Ms. Lynn Reed, P.E.
Compliance Engineer
P.O. Box 871
Tulsa, OK 74102-0871
SUBJECT:
Facility: Maysville Gas Plant
Location: Garvin County
Permit No. 2004-163-TVR (M-2)
Date Received: January 4, 2007
Dear Ms. Reed:
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. § 2-14-302 and OAC
252:002-4-7-13(c) the enclosed draft permit is 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 public location within the county
of the facility such as the public library in the county seat.
3. Send to AQD a copy of the proof of publication notice from Item #1 above together with any
additional comments or requested changes that you may have on the draft permit.
Thank you for your cooperation. If you have any questions, please refer to the permit number above and
contact me at (405) 702-4200.
Sincerely,
Grover R. Campbell, P.E.
Existing Source Permit Section
AIR QUALITY DIVISION
Enclosure
PART 70 PERMIT
AIR QUALITY DIVISION
STATE OF OKLAHOMA
DEPARTMENT OF ENVIRONMENTAL QUALITY
707 N. ROBINSON, SUITE 4100
P.O. BOX 1677
OKLAHOMA CITY, OKLAHOMA 73101-1677
Permit No. 2004-163-TVR (M-2)
ONEOK Field Service Company, L.L.C.,
having complied with the requirements of the law, is hereby granted permission to operate
the Maysville Gas Plant, Section 18, T4N, R2W, Garvin County, Oklahoma subject to the
Standard Conditions dated December 6, 2006 and Specific Conditions, both attached.
This permit shall expire five (5) years from October 23, 2006, except as Authorized under
Section VIII of the Standard Conditions.
_________________________________
Director, Air Quality Division
Date