OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY€¦ · triethylene glycol (TEG) dehydration process by entering the TEG contactor, ... The helium plant consists of a purifier and a

DRAFT

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

MEMORANDUM April 21, 2009

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

Air Quality Division

THROUGH: Kendal Stegmann, Sr. Environmental Manager, Compliance & Enforcement

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

THROUGH: Peer Review

FROM: Iftekhar Hossain, P.E., Engineering Section

SUBJECT: Evaluation of Permit Application No. 97-242-TV

Midstream Energy Services, L.L.C.

Sturgis Compressor Station and Helium Plant

Latitude: 36.843oN and Longitude: -102.184

oW

Section 3, Township 4N, Range 8E, Cimarron County, Oklahoma

Directions: 4 miles east of Keyes on Hwy 56.

SECTION I. INTRODUCTION

Originally, Colorado Interstate Gas (CIG) Company submitted a Title V operating permit

application for the above referenced facility (SIC 1311). The facility, which was constructed in

the 1970’s, was largely “grandfathered” until this Title V permit application was filed on March

5, 1997. The facility was issued the following permits as follows:

Permit Date of Issue Purpose

1. 72-021-O January 8, 1974 750-hp Waukesha L7042GU

2. R-90-007 March 19, 1990 452-hp Superior 6G825

3. 95-293-O January 12, 1996 Helium Plant

4. 96-180-C August 8, 1996 505-hp Cummins GTA-28 Emergency Generator

5. 97-242-C November 5, 1997 110-hp Ford V-8 Emergency Generator

6. 97-242-C (M-1) March 11, 1998 110-hp Ford V-8 Compressor

7. 97-242-C (M-2) December 7, 2006 TEG Dehydration Unit

Nathaniel Energy Corporation (Nathaniel) acquired the ownership of this facility in April of

2003. On March 7, 2006, Midstream Energy Services, LLC (Midstream) purchased this facility

and has been operating under Permits No. 97-242-C (M-2) and 95-293-O. This facility has gone

through several changes at different points in time as per their need and continued operations.

PERMIT MEMORANDUM 97-242-TV DRAFT Page 2

On March 19, 1990, CIG relocated a 452-hp Superior 6G825 (CG-08) grandfathered compressor

engine with 57.1 TPY of NOx emissions to this facility. It was their understanding that the

engine retained its grandfathered status under Relocation Permit Number R-90-007. However,

after proceeding through the Title V application process the facility became aware of DEQ’s

intention to remove the grandfathered status from this engine upon relocation. As a result the

facility was referred to Air Quality’s Compliance and Enforcement section. This enforcement

action has been resolved.

The facility installed a catalytic converter on engine CG-08 to bring its NOx emission level

below 40 TPY, the PSD significance level. However, this engine was subsequently removed

from service, disconnected from fuel, and is stored on site. The facility also replaced engines

CG-05 and CG-07 in 2006 and 2007, respectively. These replacements lead to a referral to Air

Quality’s Compliance and Enforcement section. Pursuant to the resolution of this matter,

catalytic converters were installed on CG-05 and CG-07, and also on CG-06 as a Supplemental

Environmental Project (SEP). All three of these engines which were previously

grandfathered/permit exempt, lost their grandfathered/permit exempt status due to replacement

and/or modification. Therefore, they are now subject to quarterly testing requirements.

On November 8, 2006, Midstream submitted a construction permit application for the

replacement of an existing ethylene glycol (EG) dehydration unit with a new TEG unit (97-242-C

(M-2)). This increased the VOC emissions from the new TEG by 69.7 TPY, which triggered an

inquiry into PSD review issue. As a result the matter was referred to Air Quality’s Compliance

and Enforcement section. This enforcement action has been resolved and the facility has

installed a condenser and has routed the condenser overhead to a combustion device, such as,

regenerator heater, resulting in VOC emission level below 40 TPY, the PSD significance level.

The facility will start recordkeeping and reporting as laid out in TEG’s Specific Conditions of the

permit upon issuance of the permit.

On October 28, 2008, the applicant filed a self-report pursuant to OAC 252:4-9-5 regarding

potential non-compliance associated with flashing emissions at the facility. As a result this

matter was referred to Air Quality’s Compliance and Enforcement section. This enforcement

action has been resolved. As per Consent Order Case No. 09-002, executed on February 3, 2009,

the facility will add tank and piping equipment to control the VOC flashing emissions within 120

days of the final execution of Consent Order. The facility proposes to install a low-pressure two-

phase separator and replace an existing 210-barrel storage tank with another 210-barrel storage

tank. The liquids from the separator will be dumped into the 210-barrel storage tank, where

condensate and water will be separated. The overhead from the low-pressure separator will be

routed to the facility inlet. This system will bring its flashing VOC emissions from condensate

tanks to a level below 40 TPY, the PSD significance level. The facility will start recordkeeping

and reporting as laid out in condensate tanks’ Specific Conditions of the permit upon issuance of

the permit.

The facility emits more than 100 TPY of a regulated pollutant and is subject to Title V permitting

requirements. Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) in

the “Equipment” section.


SECTION II. FACILITY DESCRIPTION

The facility now operates with four natural gas compressor units, a glycol dehydration unit

(installed 1982, replaced 2006), an “amine unit” (manufactured 1981, installed 1994), a purifier,

a liquefier, and several storage tanks. Pipeline quality or field-grade natural gas is the primary

fuel with the engines being operated continuously. There are no flares at the facility. The

maximum gas processing rate of this facility is 12.5 MMSCFD.

Natural gas enters the facility through a pipeline gathering system and passes through the inlet

scrubber to remove any free liquids. The liquids are collected in the condensate tanks and

shipped off-site via tank-truck.

Natural gas is compressed up to 550-700 psi through three stages. The natural gas then enters the

amine process where CO2 is removed from the inlet gas stream. Small amounts of H2S may also

be present in the inlet gas and are removed by the amine unit. The natural gas then enters the

triethylene glycol (TEG) dehydration process by entering the TEG contactor, where moisture is

removed. The TEG is then regenerated by a heater where the water is vaporized.

The helium plant consists of a purifier and a liquefier. The purifier separates the helium from the

BLM pipeline gas stream, releasing unwanted components to the atmosphere. The liquefier then

liquefies the purified helium in preparation for storage and subsequent shipment off-site via

trucks. The natural gas off the purifier vent is discharged to the atmosphere.

SECTION III. EQUIPMENT

Table 1: Changes in Emission Units since filing of Title V permit application in 1997

EU Point Make/Model Size Serial # Installation

Date

Removal/Replacement Date

CG-01 EP-1 Waukesha 7042G 712 HP 192723 1970 Removed on 08/2006



CG-05 EP-5 Superior 12G825 1,100 HP 270799X 1977 Installed C/C on 09/2006

CG-06 EP-6 Superior 12G825 1,100 HP 270819 1977 Installed C/C on 03/2007

CG-07 EP-7 Superior 12G825 1,100 HP 270799 1977 Installed C/C on 08/2006

CG-08 EP-8 Superior 6G825 452 HP 179000 1990 Removed on 12/2006

V-01 EG-9 Dehy. Still Vent 12.5

MMSCFD --- 1982

Replaced on 12/2006;

Condenser Installed on 05/2008

EUG 2 Exempted Engine

EU Point Make/Model HP Serial # Installed Date

CG-04 EP-4 Waukesha 7042GU 822 243032 1973


EUG 3 Permitted Engines

EU Point Make/Model HP Serial # Installed/Modified

Date

CG-05 EP-5 Superior 12G825 1,100 270799X 1977/2006

CG-06 EP-6 Superior 12G825 1,100 270819 1977/2007

CG-07 EP-7 Superior 12G825 1,100 270799 1977/2006

EUG 4 Glycol Dehydration Vent

EU Point Equipment Contactor Capacity Installed/Modified

Date

V-01 EG-9 Glycol Dehy. Still Vent 12.5 MMscf/day 2006/2008

EUG 4A Amine Unit Reboiler

EU Point Equipment Capacity/Throughput Installed Date

A-01 EG-11 Amine Unit 12.5 MMscf/day 1994

EUG 5 Helium Plant Vent

EU Point Equipment Gas Throughput Installed Date

V-02 EG-10 Purifier Vent 262 MMscf/yr 1995

EUG 6 Insignificant Activities: Heaters and Reboilers

EU Point Equipment MMBtu/hr Installed Date

H-01 EG-9B Glycol Reboiler 0.5 2006

H-02 EG-12 Amine Unit Reboiler 1.6 1995

EUG 7 Condensate Storage Tanks

EU

ID#

Point

ID#

Material

Stored

Capacity

(gallons)

Throughput

(gallons/yr)

Construction

Date

T-09 (TK-01) T-01 Condensate 8,820

550,000

2009

T-10 (TK-02) T-02 Condensate 8,820 1972

T-11 (TK-03) T-03 Condensate 8,820 1974

T-12 (TK-04) T-04 Condensate 8,820 1980

EUG 8 Insignificant Activities: Tanks

EU ID # Contents Gallons Installed Date

T-05 (T-01a) Ambitrol 5,277 1970

T-06(T-09) Ethylene Glycol 1,500 1982

T-07 Used Oil 250 1970

T-08 Lean TEG 500 1977

T-02a Used Oil 5,277


EU ID # Contents Gallons Installed Date

T-05 Clean Oil (lube) 5,277

T-10 Underground sump water 90

T-12 Water Tank 4,000

T-13 TEG Tank 1,020 2006

T-14 DEA Tank 1,500

T-15 Clean Lube Oil 564


T-17 Waste Oil/Water Mix 1,500

SECTION IV. EMISSIONS

Emissions estimates for the engines are based on continuous operations and emission factors

shown in Table 1 below. The triethylene glycol dehydration (TEG) unit is equipped with a

reboiler. Estimated emissions from the TEG unit’s reboiler are based on AP-42 (7/98), Section

1.4 with 100% safety factor. Emissions from the glycol dehydration unit still vent are estimated

using GRI-GLYCalc™ version 4.0 software model with a glycol recirculation rate of 7.0 gallons

per minute (gpm) and an estimated throughput of 12.5 MMscf/day. The dehydration unit is

equipped with a flash tank, which routes overhead to recycle/recompression. The dehydration

unit still vent is equipped with a vapor condenser. Condenser overhead is routed to the burner of

the glycol regenerator heater. Emissions from the amine unit’s still vent are estimated using

AmineCalc™ version 1.0 software program. The emissions from the glycol reboiler and the

amine reboiler are based on AP-42 (7/98), Section 1.4. Estimated VOC emissions for the tanks

are based on AP-42 (1/95), Chapter 7.1 and computer software TANKS4.0 and that from flashing

losses are estimated using process simulation (WinSim, ver. 10.0) software. The VOC emissions

due to flashing are controlled by using two-phase low-pressure separator and routing the VOC to

the facility inlet. Estimated VOC emissions from the truck loading are based on AP-42 (1/95),

Chapter 5.2, an emission factor of 8.60 lb/1,000 gallons, and an estimated condensate throughput

of 550,000 gallons/year. Fugitive VOC emissions for process piping fugitives from valves, seals,

flanges, and connections are estimated using EPA’s document, “1995 Protocol for Equipment

Leak Emission Estimates,” EPA-453/R-95-017, Table 2-4, Oil and Gas Production Operations

Average Emissions Factors, an estimated number of components, and a recent gas analysis.

Table 2: Emissions Factors

Engine Specifications NOx CO VOC

g/hp-hr g/hp-hr g/hp-hr Waukesha 7042 G 12.0 12.0 0.35

Superior 12G825 with C/C* 4.0 4.0 0.4 *C/C = with catalytic converter

Table 3: Exempted Engine Emissions Calculations (EUG-2)

EU Point Make/Model HP* NOx CO VOC

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

CG-04 EP-4 Waukesha 7042 G 822 21.75 95.25 21.75 95.25 0.63 2.78 *HP are adjusted for altitude


Table 4: Permitted Engine Emissions Calculations (EUG-3)

EU Point Make/Model HP* NOx CO VOC


CG-05 EP-5 Superior 12G825 1,100 9.7 42.49 9.7 42.49 0.97 4.25

CG-06 EP-6 Superior 12G825 1,100 9.7 42.49 9.7 42.49 0.97 4.25

CG-07 EP-7 Superior 12G825 1,100 9.7 42.49 9.7 42.49 0.97 4.25 *HP are adjusted for altitude; All three (3) engines above are now subject to quarterly testing.

Table 5: Emissions from the Dehydration Unit and Reboiler

EU Point Description Capacity NOx CO VOC


V-01 EG-9 Dehy Still Vent 12.5 MMscf/day -- -- -- -- 0.64 2.79

H-01 EG-9B Reboiler Unit 0.50 MMBtu/hr 0.11 0.48 0.09 0.39 0.006 0.03

Table 5A: Emissions from Amine Unit and Reboiler (EUG 4A)

EU# Point Emission Units Capacity NOx CO VOC


A-01 EG-11 Amine Unit’s

Still Vent

12.5

MMscf/day -- -- -- -- 0.19 0.84

H-02 EG-12 Amine Reboiler 1.6 MMBtu/hr 0.16 0.70 0.13 0.59 0.01 0.04

Table 6: Emissions from Helium Plant Vent

EU Point Description Gas Throughput NOx CO VOC


V-02 EG-10 Purifier Vent 262 MMscf/yr -- -- -- -- 5.71 25.00

Table 7: Stack Parameters

EU #

Source Height Diameter

Fuel

Usage

Moisture

Content Flow Temp.

(feet) (inches) (scfh) (%) (acfm) (deg F)

CG-04 Waukesha 7042 G 15 10 6,348 13 4,155 1,033

CG-05 Superior 12G825 18 12 8,130 17 6,891 1,240

CG-06 Superior 12G825 18 12 8,130 17 6,891 1,240

CG-07 Superior 12G825 18 12 8,130 17 6,891 1,240

Table 8: Fugitive Emissions Calculations (FUG-01)

Source Description Number of

Sources

TOC Emission Factors Control

Efficiency

wt%

VOC

VOC Emissions

lb/hr/source lb/hr TPY

Valves – gas 552 0.00992 0% 15.92% 0.87 3.82

Flanges – gas 817 0.00086 0% 15.92% 0.11 0.49

Pressure relief valves - gas 32 0.01940 0% 15.92% 0.01 0.43

Open-ended lines - gas 70 0.00441 0% 15.92% 0.05 0.22

Compressor seals - gas 40 0.01940 0% 15.92% 0.12 0.54

TOTAL 1.26 5.50


Table 9A: Facility-wide Emissions at the time of initial TV submittal (in 1997)

Unit ID # Source NOx CO VOC


CG-01, 02, 03 Waukesha 7042 G (Grandfathered Engines) 56.4 247.2 7.5 33.0 3.3 14.7

CG-04 Waukesha 7042 GU (Exempted Engine) 19.2 84.2 2.6 11.2 1.1 5.0

CG-05, 06, 07 Superior 12G825 (Exempted Engines) 77.1 337.2 10.2 45.0 4.5 20.1

CG-08 Superior 6G825 with C/C* 2.0 8.7 2.0 8.7 0.4 1.8

V-01 Glycol Dehy. Still Vent (EG unit) -- -- -- -- 3.43 15.0

H-01 Glycol Reboiler Unit 0.11 0.48 0.09 0.39 0.006 0.03

A-01 Amine Unit’s Still Vent -- -- -- -- 0.19 0.84

H-02 Amine Reboiler 0.16 0.70 0.13 0.59 0.01 0.04

V-02 Purifier Vent -- -- -- -- 5.71 25.0

FUG-01 Fugitive Emissions -- -- -- -- 0.79 3.45

FLASH-01† Emissions from Condensate Tanks -- -- -- -- -- 3.79

LOAD-01 Loading Emissions from Truck Loading -- -- -- -- -- 0.66

Total Emissions 154.97 678.48 22.52 98.88 19.44 90.41

*C/C = with catalytic converter; †includes working and breathing losses and flash emissions.

Table 9B: Currently Facility-wide Emissions

Unit ID # Source NOx CO VOC


CG-04 Waukesha 7042G (Exempted Engine) 21.75 95.25 21.75 95.25 0.63 2.78

CG-05 Superior 12G825 (Permitted Engines)* 9.7 42.49 9.7 42.49 0.97 4.25



V-01 Glycol Dehy. Still Vent (TEG unit) -- -- -- -- 0.64 2.79

H-01 Glycol Reboiler Unit 0.11 0.48 0.09 0.39 0.006 0.03

A-01 Amine Unit’s Still Vent -- -- -- -- 0.19 0.84

H-02 Amine Reboiler 0.16 0.70 0.13 0.59 0.01 0.04

V-02 Purifier Vent -- -- -- -- 5.71 25.0

FUG-01 Fugitive Emissions -- -- -- -- 1.26 5.50

FLASH-01† Emissions from Condensate Tanks -- -- -- -- 9.02 39.52

†

LOAD-01 Loading Emissions from Truck Loading -- -- -- -- -- 2.36

Total Emissions 51.12 223.90 51.07 223.70 20.38 91.61

*C/C = with catalytic converter; †includes working and breathing losses and flash emissions.

Hazardous Air Pollutants (HAPs)

Glycol Dehydration Unit

Glycol Dehydration units using glycol desiccants emit benzene, toluene, ethyl benzene, xylenes,

and n-hexane from the still vent stack, which are regulated as hazardous air pollutants (HAPs).

The applicant has analyzed the concentrations of HAPs emissions of this unit using GRI-

GLYCalc™ version 4.0 software model, an extended inlet gas analysis, a glycol recirculation rate

of 7.0 gallons per minute (gpm), an estimated throughput of 12.5 MMscf/day, the

recycle/recompress option on the flash tank, a condenser on the still vent, and condenser


overhead being routed to the regenerator heater. Estimated HAP emissions from the glycol

dehydration unit are shown in the following table.

Table 10: HAP Emissions from Glycol Dehydration Unit

Pollutant CAS# Estimated Emissions

lb/hr TPY

Benzene 71-43-2 0.031 0.1360

Toluene 108-88-3 0.014 0.0613

Ethylbenzene 75-04-7 0.003 0.0125

Xylene 1330-20-7 0.007 0.0319

n-Hexane 110-54-3 0.049 0.2156

Total 0.104 0.4572

IC Engines

The engines have emissions of HAPs, the most significant being formaldehyde. Emissions

estimates for the engines are based on continuous operations. Estimated emissions of

formaldehyde for 4-cycle, rich-burn engines shown here are based on AP-42 (7/00), Section 3.2,

Table 3.2-3 factors (0.0205 lb/MMBtu) for the Waukesha engine (CG-04) and Superior engines

(CG-05, CG-06, and CG-07). Table 11 presents the formaldehyde emission factors and

estimated formaldehyde emissions from the engines.

Table 11: Formaldehyde Emissions from Engines

EU ID #

Point

Source

H.P.

Fuel Usage‡

Emission

Factor

Formaldehyde

Emission

(Scf/hr) MMBtu/hr lb/MMBtu lb/hr TPY

CG-04 EP-4 Waukesha 7042 G 822 6,348 6.35 0.0205 0.13 0.57

CG-05 EP-5 Superior 12G825 1,100 8,690 8.69 0.0205 0.18 0.78

CG-06 EP-6 Superior 12G825 1,100 8,690 8.69 0.0205 0.18 0.78

CG-07 EP-7 Superior 12G825 1,100 8,690 8.69 0.0205 0.18 0.78

Total 0.67 2.91 ‡Based on 1,000 Btu/scf of fuel.

The estimation shows that the facility emits 2.91 TPY of formaldehyde from engines. Aggregate

HAP emissions from the compressor engines and the dehydrator equal 3.37 TPY. The facility is

a minor source for HAP and subject to area source provisions of 40 CFR Part 63, Subparts HH.

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.

(a) *Stationary reciprocating engines burning natural gas, gasoline, aircraft fuels, or diesel

fuel which are either used exclusively for emergency power generation or for peaking


power service not exceeding 500 hours/year. The facility has an emergency generator

and other emergency engines may be used in the future.

(b) Space heaters, boilers, process heaters, and emergency flares less than or equal to 5

MMBTUH heat input (commercial natural gas). The facility has a 0.5 and a 1.6

MMBTUH heater.

(c) Emissions from crude oil or condensate marine and truck loading equipment operations

at crude oil and natural gas production sites where the loading rate does not exceed

10,000 gallons per day averaged over a 30-day period. Unloading of the condensate

tank into tank trucks is less than 10,000 gallons/day. Emissions from tank unloading

were based on approximately 8,000 gallons per year.

(d) * Emissions from crude oil and condensate storage tanks with a capacity of less than or

equal to 420,000 gallons that store crude oil and condensate prior to custody transfer as

defined by Subpart Kb. The condensate tank stores condensate prior to custody transfer

and has a capacity of less than 420,000 gallons.

(e) * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria

pollutant. Fugitive VOC leakage and VOC emissions from various auxiliary tanks are

in this category, and other activities may be used in the future.

SECTION VI. OKLAHOMA AIR POLLUTION CONTROL RULES

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

Subchapter 1 includes definitions but there are no regulatory requirements.

OAC 252:100-2 (Incorporation by Reference) [Applicable]

This subchapter incorporates by reference applicable provisions of Title 40 of the Code of

Federal Regulations. These requirements are addressed in the “Federal Regulations” section.

OAC 252:100-3 (Air Quality Standards and Increments) [Applicable]

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

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

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

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

emission inventory annually on forms obtained from the Air Quality Division. The facility has

submitted inventory information in the past.

OAC 252:100-7 (Permits for Minor Facilities) [Not Applicable]

No person may construct or operate a minor source without obtaining a permit from ODEQ.

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

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

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

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

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


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

calendar year emissions do not exceed the following limits:

5 TPY of any one criteria pollutant

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

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

Refer to Section IV for the complete emissions evaluation. Limitations to all sources are

established from this operating application

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

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

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

knowledge of such emissions, but no later than 4:30 p.m. the next working day following the

malfunction or release. 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. In addition, if the owner or operator wishes to be

considered for the exemption established in 252:100-9-3.3, a Demonstration of Cause must be

submitted within thirty (30) calendar days after the occurrence has ended.

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

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

specific examples and under the conditions listed in this subchapter.

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

This subchapter specifies a particulate matter (PM) emissions limitation of 0.6 lb/MMBTU from

fuel-burning equipment with a rated heat input of 10 MMBTUH or less. For 4-cycle rich-burn

and lean-burn engines burning natural gas, AP-42 (7/00), Section 3.2 lists the total PM emissions

as approximately 0.01 lb/MMBTU. For external combustion engines burning natural gas, AP-42

(7/98), Table 1.4-2 lists the total PM emissions to be 7.6 lb/million SCF or about 0.0076

lb/MMBTU which is in compliance with this subchapter. The permit requires the use of natural

gas for all fuel-burning equipment to ensure compliance with Subchapter 19.

This subchapter also limits emissions of PM from industrial processes. Per AP-42 factors, there

are no significant PM emissions from any industrial activities at this facility.

OAC 252:100-25 (Visible Emissions and Particulate Matter) [Applicable]

No discharge of greater than 20% opacity is allowed except for short-term occurrences which

consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed

three such periods in any consecutive 24 hours. In no case, shall the average of any six-minute

period exceed 60% opacity. When burning natural gas there is little possibility of exceeding the

opacity standards.

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

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

property line on which the emissions originate in such a manner as to damage or to interfere with


the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the

maintenance of air quality standards. Under normal operating conditions, this facility will not

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

taken.

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

Part 2 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 µg/m3 in a 5-minute period of

any hour, 1,200 µg/m3 for a 1-hour average, 650 g/m

3 for a 3-hour average, 130 µg/m

3 for a 24-

hour average, or 80 µg/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 µg/m3).

Part 5 limits sulfur dioxide emissions from new fuel-burning equipment (constructed after July 1,

1972). For gaseous fuels the limit is 0.2 lb/MMBTU heat input averaged over 3 hours. For fuel

gas having a gross calorific value of 1,000 BTU/SCF, this limit corresponds to fuel sulfur content

of 1,203 ppmv. The permit requires the use of gaseous fuel with sulfur content less than 343

ppmv to ensure compliance with Subchapter 31.

Part 5 requires removal or oxidation of H2S from the exhaust gas of any new petroleum or natural

gas process equipment. This part allows direct oxidation of H2S to SO2, without sulfur recovery,

when the exhaust gas will contain no more than 100 lbs/hr SO2 (2-hour average). Compliance

with the 100 lb/hr can be demonstrated by establishing that the acid gas stream contains 0.54

long tons per day (LTD) of sulfur or less. Oxidation of the H2S must be conducted in a system

that assures at least a 95% reduction of the H2S in the exhaust gases and that is equipped with an

alarm system to signal non-combustion of the exhaust gases. These requirements do not apply if

H2S emissions do not exceed 0.3 lb/hr.

The amine unit mainly processes NGL derived from “sweet” field gas. The permit will limit the

facility’s throughput to a value in mmscfd expressed by dividing 81.58 by the ppmv H2S, which

is equivalent to 0.3 lb/hr H2S. This will allow the facility the flexibility to limit throughput and/or

H2S concentration to comply with the 0.3 lb/hr H2S emission limitation. The permit will also

require quarterly testing of the inlet gas to ensure compliance with this limit.

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

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

greater than or equal to 50 MMBTUH. The engines do not exceed the 50 MMBTUH threshold.

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

None of the following affected processes are located at this facility: gray iron cupola, blast

furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic

reforming unit.

OAC 252:100-37 (Volatile Organic Compounds) [Part 3 and Part 7 Applicable]

Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of 400 gallons

or more 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. The storage tanks (all


tanks with the exceptions of T-01 through T-04 condensate) containing ambitrol, glycol, water

used oil and lube oil have vapor pressures below the 1.5 psia are not subject to this part. The

condensate tanks (T-01 to T-04) are subject to this part and all are equipped with submerged fill

pipes.

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 and is not subject to this requirement.

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

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

of the facility and equipment, which is exempt.

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

of VOC. The equipment at this location is subject to this requirement.

Part 7 requires all effluent water separators, which receive water containing more than 200

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

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

No effluent water separators are located at this facility.

OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable]

This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in

areas of concern (AOC). Any work practice, material substitution, or control equipment required

by the Department prior to June 11, 2004, to control a TAC, shall be retained, unless a

modification is approved by the Director. Since no AOC has been designated there are no

specific requirements for this facility at this time.

OAC 252:100-43 (Sampling and Testing Methods) [Applicable]

This subchapter provides general requirements for testing, monitoring and recordkeeping and

applies to any testing, monitoring or recordkeeping activity conducted at any stationary source.

To determine compliance with emissions limitations or standards, the Air Quality Director may

require the owner or operator of any source in the state of Oklahoma to install, maintain and

operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant

source. All required testing must be conducted by methods approved by the Air Quality Director

and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol

shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests.

Emissions and other data required to demonstrate compliance with any federal or state emission

limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, and

submitted as required by this subchapter, an applicable rule, or permit requirement. Data from

any required testing or monitoring not conducted in accordance with the provisions of this

subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive

use, of any credible evidence or information relevant to whether a source would have been in

compliance with applicable requirements if the appropriate performance or compliance test or

procedure had been performed.


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

OAC 252:100-11 Alternative Emissions Reduction not requested

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

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

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

OAC 252:100-24 Grain, Feed, or Seed Operations not in source category

OAC 252:100-33 Nitrogen Oxides not type of emission unit

OAC 252:100-35 Carbon Monoxide not type of emission unit

OAC 252:100-39 Nonattainment Areas not in area category

OAC 252:100-47 Landfills not in source category

SECTION VII. FEDERAL REGULATIONS

PSD, 40 CFR Part 52 [Not Applicable]

Total potential emissions of any criteria pollutants, considering controls, does not exceed the

PSD-major source threshold of 250 TPY. The facility is not among the 26 industry categories

defined as “major sources” at an emission level of 100 TPY.

NSPS, 40 CFR Part 60 [Subpart LLL is Applicable]

Subparts K, Ka, Kb, VOL Storage Vessels. The VOL tanks are not subject to the subparts since

the tanks were installed prior to Subpart Kb and the capacity of the tanks are less then the de

minimis level of 40,000 gallons in Subparts K and Ka.

Subpart GG, Stationary Gas Turbines. No turbine is located at this facility.

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

constructed, reconstructed or modified after January 20, 1984. The facility does not meet the

definition of a natural gas liquid processing plant and is therefore not subject to this subpart.

Subpart LLL, Onshore Natural Gas Processing: SO2 Emissions. This subpart sets standards for

natural gas sweetening units. The amine unit is an affected facility per 40 CFR 60.640(a) and

(d). However, the amine unit is exempt from the control requirements because the design

capacity is less than 2 long tons per day (LT/D) of H2S in the acid gas expressed as sulfur. The

amine unit is required to comply with 40 CFR 60.647(c) by maintaining an analysis

demonstrating that the facility’s design capacity is less than 2 LT/D of H2S expressed as sulfur.

These records need to be maintained for the life of the facility.

Subpart IIII, Stationary Compression Ignition (CI) Internal Combustion Engines (ICE). This

subpart affects CI ICE manufactured after 2007. There are no CI ICE located at this facility.

Subpart JJJJ, Stationary Spark Ignition Internal Combustion Engines (SI-ICE), promulgates

emission standards for all new SI engines ordered after June 12, 2006, and all SI engines

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

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

rating, lean-burn or rich-burn, fuel type, duty (emergency or non-emergency), and numerous

manufacture dates. Engine manufacturers are required to certify certain engines to meet the

emission standards and may voluntarily certify other engines. An initial notification is required


only for owners and operators of engines greater than 500 HP that are non-certified. Emergency

engines will be required to be equipped with a non-resettable hour meter and are limited to 100

hours per year of operation excluding use in an emergency (the length of operation and the reason

the engine was in operation must be recorded). All existing engines were manufactured prior to

January 2007 and have not been modified or reconstructed after that date; therefore, would not be

subject to this subpart.

NESHAP, 40 CFR Part 61 [Not Applicable]

There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene,

coke oven emissions, mercury, radionuclides or vinyl chloride except for trace amounts of

benzene. Subpart J, Equipment Leaks of Benzene only affects process streams, which contain

more than 10% benzene by weight. All process streams at this facility are below this threshold.

NESHAP, 40 CFR Part 63 [Subpart HH is Applicable]

Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission

points that are located at facilities that are major or area sources of HAP 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. The facility will be a minor

source of HAP.

This MACT was extended to area sources on January 3, 2007. The dehydrator was constructed

in 2006, and is not located within an Urban-1 County. As an area source it is potentially subject

to the glycol optimization requirements of 40 CFR 63.764(d)(2)(i) through (iii). In the current

instance, benzene emissions calculated by GLY Calc 4.0 amount to 0.14 TPY, which is less than

the exemption level of 0.9 megagrams per year (1 TPY) defined in §63.764(e)(1)(ii). Thus this

facility only has to keep records of the de minimis level. All applicable requirements have been

incorporated into the permit.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

for CO. Owner and operators of new or reconstructed stationary RICE, located at an area source,

must meet the requirements of 40 CFR Subpart IIII or Subpart JJJJ. All existing engines were

manufactured prior to January 2007 and have not been modified or reconstructed after that date;

therefore, would not be subject to this subpart.


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

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

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

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

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

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

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

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

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

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

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

determination is not needed for sources potentially subject to a vacated MACT, including

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

facility is not a major source of HAP.

CAM, 40 CFR Part 64 [Not Applicable]

Compliance Assurance Monitoring (CAM) applies to any pollutant specific emission unit at a

major source, that is required to obtain a Part 70 permit, if it meets all of the following criteria:

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

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

standard

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

pollutant greater than major source thresholds.

Engines CG-05, CG-06, and CG-07 use control devices to achieve compliance with the

enforceable emission limit and the potential to emit (pre-control device) emissions are more than

the major source thresholds. Therefore, these engines are subject to the CAM plan. However,

the facility is not subject to CAM plan until renewal of their Title V permit.

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

This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant

and the Accidental Release Prevention Provisions are applicable to this facility. The facility was

required to submit the appropriate accidental release emergency response program plan prior to

June 21, 1999. 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 hydro-

chlorofluorocarbons (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.

Subpart F requires that any persons servicing, maintaining, or repairing appliances except for

motor vehicle air conditioners; persons disposing of appliances, including motor vehicle air

conditioners; refrigerant reclaimers, appliance owners, and manufacturers of appliances and

recycling and recovery equipment comply with the standards for recycling and emissions

reduction.

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

SECTION VIII. COMPLIANCE

Tier Classification and Public Review

This application has been determined to be Tier II based on the request for an initial Title V

operating permit. The permittee has submitted an affidavit that they are not seeking a permit for

land use or for any operation upon land owned by others without their knowledge. The affidavit

certifies that the application involves only land owned by applicant business.

The applicant published the “Notice of Filing a Tier II Application” in the Boise City News, a

weekly newspaper in the Boise City, Cimarron County, on March 19, 1997. The notice stated

that the application may be reviewed at the Soutar Memorial Public Library, Boise City,

Oklahoma. A draft of this permit will be made available for public review for a period of 30

days as stated in another newspaper announcement. All Tier II permit drafts are also available

for public review in the Air Quality section of the DEQ web page: //www.deq.state.ok.us/. This

site is within 50 miles of the Oklahoma-Texas, Oklahoma-Colorado, Oklahoma-Kansas, and

Oklahoma-New Mexico borders, and these bordering states have been notified of the draft

permit.

Inspection

On August 2, 2007, a full compliance evaluation (FCE) was conducted at the Sturgis Compressor

Station of Midstream Energy Services. Brad Flaming, Environmental Programs Manager, Air

Quality Division conducted the inspection. Midstream was represented by Eugene Kear, Plant

Manager, Chris Wood, Helium Operator and Misty Curler, Environmental Consultant.

Identification plate and serial number was attached on the engines. Periodic engine testing

records and other required records are maintained at the facility.


Testing

Portable engine analyzer testing was performed for the following engines in September 23, 2008,

as shown in the table below:

EU ID # Make/Model Test date NOX (lb/hr) CO (lb/hr)

Test value Limit Test value Limit

CG-05 1,100-hp Superior 12G825* 9/23/08 2.71 9.70 1.62 9.70

CG-06 1,100-hp Superior 12G825* 9/23/08 3.70 9.70 5.34 9.70

CG-07 1,100-hp Superior 12G825* 9/23/08 6.58 9.70 8.66 9.70

*with Catalytic Converter

Fees Paid

Initial Title V operating permit application fee of $2,000.

SECTION IX. SUMMARY

The facility was constructed and is operating as described in the permit application and

supplemental information. Ambient air quality standards are not threatened at this site. There

are no active Air Quality compliance or enforcement issues concerning this facility. Issuance of

the permit is recommended, contingent on public and EPA review.

DRAFT

PERMIT TO OPERATE

AIR POLLUTION CONTROL FACILITY

SPECIFIC CONDITIONS

Midstream Energy Services, L.L.C. Permit Number 97-242-TV

Sturgis Compressor Station

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

Quality on March 5, 1997, with supplemental information received June 20, 2000, December 24,

2002, March 15, 2004, July 7, 2005, October 28, 2008, February 23, 2009, and other numerous

correspondences. The Evaluation Memorandum, dated April 21, 2009, explains the derivation of

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

limitations or permit requirements. Continuing operations under this permit constitutes acceptance

of, and consent to, the conditions contained herein:

1. Points of emissions and emissions limitations for each point: [OAC 252:100-8-6(a)]

EUG 2 Exempted Engine: Emission unit CG-04 is exempt, based on DEQ regulations,

between 1972 and 1979 and there are no lb/hr or TPY emission limits applied to this unit

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

EU Point Make/Model Serial #

CG-04 EP-4 Waukesha 7042GU 243032

EUG 3 Permitted Engines: The emission units EU CG-05, CG-06, and CG-07 are subject

to emission limitations for the pollutants and subject to quarterly testing.

EU Point Make/Model HP NOx CO VOC


CG-05 EP-5 Superior 12G825* 1,100 9.7 42.49 9.7 42.49 0.97 4.25

CG-06 EP-6 Superior 12G825* 1,100 9.7 42.49 9.7 42.49 0.97 4.25

CG-07 EP-7 Superior 12G825* 1,100 9.7 42.49 9.7 42.49 0.97 4.25

*C/C = with catalytic converter All three (3) engines above are now subject to quarterly testing.

EUG 4 Glycol Dehydration Vent

EU Point Equipment Contactor Cap.

V-01 EG-9 Glycol Dehy. Still Vent 12.5 MMscf/day

(a) Emissions from the glycol dehydrator still column shall be vented to a condenser.

Condenser overhead shall be directed to a combustion device, such as the regenerator

heater.

(b) The lean glycol recirculation rate shall not exceed 7.0 gallons per minute. The natural

gas throughput of the glycol dehydration unit shall not exceed 12.5 MMscf/day.

(c) The glycol dehydration unit shall be operated with a flash tank routed to

recycle/recompression.

SPECIFIC CONDITIONS PERMIT NO. 97-242-TV DRAFT Page 2

(d) The permittee shall monitor and record the lean glycol circulation rate at least once a

month. When three consecutive months show no exceedance of the limit, the frequency

may be reduced to quarterly. Upon any showing of non-compliance, the monitoring and

recordkeeping frequency shall revert to monthly.

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

Circulation rate, as found (gal/min, strokes/min)

Circulation rate, as left (gal/min, strokes/min)

Date of inspection

Inspected by

EU Point Description Capacity VOC

lb/hr TPY

V-01 EG-9 Dehy Still Vent 12.5 MMscf/day 0.638 2.79

EUG 4A Amine Unit Reboiler The emissions limitations of the amine unit reboiler are as

follows:

EU# Point Emission Units Capacity

A-01 EG-11 Amine Unit’s Still Vent 12.5 MMscf/day

(a) Emissions of H2S shall not cause the ambient air concentration to exceed 0.20 ppmv for

any 24-hour period. [OAC 252:100-31-7(b)]

(b) Emissions of H2S shall not exceed 0.30 lb/hr, as a two hour maximum.

[OAC 252:100-31-26(b)(1)]

(c) The plant throughput shall not exceed the amount calculated using the following formula

and the H2S concentration (ppmv) of the inlet gas into the plant: MMSCF per day =

81.58/inlet gas H2S concentration (ppmv), up to an inlet concentration of 6.5 ppmv of

H2S concentration when the plant throughput is at a maximum of 12.5MMscf/day.

[OAC 252:100-31-26(b)(1)]

(d) The permittee shall test the H2S concentration of the inlet gas quarterly using a “stain

tube” analysis or similar method to determine the H2S concentration to within 0.5 ppmv.

EUG 5 Helium Plant Vent The emissions limitations of the helium process vent are as

follows:

EUG 6 Insignificant Activities: Heaters and Reboilers: Emissions from the heater and

the reboiler are insignificant and there are no specific limitations.

EU Point Equipment MMBtu/hr

H-01 EG-9B Glycol Reboiler 0.5

H-02 EG-12 Amine Unit Reboiler 1.6

EU Point Description Gas Throughput VOC

lb/hr TPY

V-02 EG-10 Purifier Vent 262 MMscf/yr 5.71 25.00


EUG 7 Condensate Storage Tanks: The emission limitations of the condensate tanks are

as follows:

EU

ID#

Point

ID#

Material

Stored

Capacity

(gallons)

Throughput

(gallons/yr)

VOC Emissions

(TPY)


550,000 39.52†



T-12 (TK-04) T-04 Condensate 8,820 †includes working and breathing losses and flash emissions.

(a) The total throughput of four condensate tanks shall not exceed 550,000 gallons per any rolling

12-month period.

(b) The inlet separator and compressor inter-stage separators shall be routed to an intermediate

separator which shall be vented to the pig leg separator.

EUG 8 Insignificant Activities: Tanks: The following emissions units are “Insignificant

Activities” since emissions are less than 5 TPY and there are no specific limitation for those

tanks.

EU Contents Gallons

T-01a Ambitrol 5,277

T-02a Used Oil 5,277

T-05 Lube Oil (Clean Oil) 5,277

T-07 Used Oil/Water Mix 250

T-08 Lean TEG 500

T-09 Ethylene Glycol 1,500

T-10 Sump Water 90

T-12 Water 4,000

T-13 TEG Glycol 1,020

T-14 DEA 1,500



T-17 Waste Oil/Water Mix 1,500

2. 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)]

3. The fuel-burning equipment shall use pipeline-grade natural gas or field gas with a

maximum sulfur content of 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. [OAC 252:100-31]

4. 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]


5. Engines CG-05, EG-06, and EG-07 in EUG 3 shall be set to operate with exhaust gases

passing through a properly functioning catalytic converter. [OAC 252:100-8-6(a)]

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

emissions from the engine(s) in EUG 3, and from each replacement engine/turbine when

operating under representative conditions for that period. Testing is required for any

engine/turbine that runs for more than 220 hours during that calendar quarter. A quarterly

test may be conducted no sooner than 20 calendar days after the most recent test. Testing

shall be conducted using a portable analyzer in accordance with a protocol meeting the

requirements of the latest AQD Portable Analyzer Guidance document, or an equivalent

method approved by Air Quality. When four consecutive quarterly tests show the

engine/turbine to be in compliance with the emissions limitations shown in the permit, then

the testing frequency may be reduced to semi-annual testing. A semi-annual test may be

conducted no sooner than 60 calendar days nor later than 180 calendar days after the most

recent test. Likewise, when the following two consecutive semi-annual tests show

compliance, the testing frequency may be reduced to annual testing. An annual test may be

conducted no sooner than 120 calendar days nor later than 365 calendar days after the most

recent test. Upon any showing of non-compliance with emissions limitations or testing that

indicates that emissions are within 10% of the emission limitations, the testing frequency

shall revert to quarterly. Reduced testing frequency does not apply to engines with catalytic

converters. Any reduction in the testing frequency shall be noted in the next required

semiannual monitoring and deviation report. [OAC 252:100-8-6 (a)(3)(A)]

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

limits in Specific Condition Number 1, the permittee shall comply with the provisions of

OAC 252:100-9. [OAC 252:100-9]

8. 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 of lesser or equal emissions of each pollutant (in lbs/hr and TPY) are authorized under

the following conditions. [OAC 252:100-8-6 (f)(2)]

(a) The permittee shall notify AQD in writing not later than 7 days prior to start-up of the

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

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

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

horsepower for the altitude/location.

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

confirm continued compliance with NOX and CO 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), and pollutant emission rates (g/hp-hr,

lbs/hr, and TPY) at maximum rated horsepower for the altitude/location.


(c) Replacement equipment and emissions are limited to equipment and emissions

which are not a modification under NSPS or NESHAP, or a significant modification

under PSD. For existing PSD facilities, the permittee shall calculate the PTE or the

net emissions increase resulting from the replacement to document that it does not

exceed significance levels and submit the results with the notice required by a. of this

Specific Condition.

(d) Engines installed as allowed under the replacement allowances in this Specific

Condition that are subject to 40 CFR Part 63, Subpart ZZZZ and/or 40 CFR Part 60,

Subpart JJJJ shall comply with all applicable requirements.

9. The glycol dehydration unit at this facility is subject to 40 CFR Part 63, Subpart HH, and

shall comply with all applicable requirements. [40 CFR 63.760 - 777]

(a) § 63.760 Applicability and designation of affected source.

(b) § 63.761 Definitions.

(c) § 63.762 Startups, shutdowns, and malfunctions.

(d) § 63.764 General standards.

(e) § 63.771 Control equipment requirements.

(f) § 63.772 Test methods, compliance procedures, and compliance determinations.

(g) § 63.773 Inspection and monitoring requirements.

(h) § 63.774 Recordkeeping requirements.

(i) § 63.775 Reporting requirements.

10. The permittee shall comply with the Standards of Performance for Onshore Natural Gas

Processing: SO2 Emissions, NSPS Subpart LLL, for the amine unit.

[40 CFR 60.640 to 60.648]

(a) Facilities that have a design capacity less than 2 long tons per day (LT/D) of

hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to comply

with § 60.647(c) but are not required to comply with §§ 60.642 through 60.646.

[§ 60.640(b)]

(b) To certify that a facility is exempt from the control requirements of these standards,

each owner or operator of a facility with a design capacity less that 2 LT/D of H2S in

the acid gas (expressed as sulfur) shall keep, for the life of the facility, an analysis

demonstrating that the facility’s design capacity is less than 2 LT/D of H2S expressed

as sulfur. [§ 60.647(c)]

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

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

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

(a) Periodic emission testing for engines and each replacement engine or operating

hours of each engine if less than 220 hours/quarter and not tested;

(b) For fuel(s) burned, the appropriate document(s) as described in Specific Condition 3

(annually);


(c) Analysis of inlet gas H2S concentration and amine plant throughput limitation

calculations (quarterly);

(d) O&M records for any engine not tested in any 6 month period;

(e) Lean glycol pump recirculation rate, gal/min (recorded a minimum of once per

month and reverting to quarterly as allowed under Specific Condition 1, EUG4(c);

(f) Throughput of the glycol dehydration unit (monthly average);

(g) Condensate throughput for the facility (monthly and 12-month rolling total);

(h) Records as required by NSPS, Subpart LLL, and

(i) Records as required by NESHAP, Subpart HH.

12. The following records shall be maintained on-site to verify insignificant activities. No

recordkeeping is required for those activities which qualify as Trivial Activities.

[OAC 252:100-43]

(a) Stationary reciprocating engines burning natural gas, gasoline, aircraft fuels, or

diesel fuel which are either used exclusively for emergency power generation or for

peaking power service not exceeding 500 hours/year. The facility has an emergency

generator and other emergency engines may be used in the future.

(b) For crude oil and condensate storage tanks with a capacity of less than or equal to

420,000 gallons that store crude oil and condensate prior to custody transfer:

records of capacity of the tanks and the amount of throughput (annual).

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

pollutant: The type of activity and the amount of emissions from that activity

(annual).

13. The applicant shall submit a CAM plan for the engines CG-05, CG-06, and CG-07 along

with Title V renewal application. [40 CFR Part 64]

14. No later than 30 days after each anniversary date of the issuance of this permit, 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) & (D)]

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

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

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

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

OAC 252:100-11 Alternative Emissions Reduction not eligible

OAC 252:100-15 Mobile (Motor Vehicle) Sources not in source category

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

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

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

OAC 252:100-33 Nitrogen Oxides not type of emission unit

OAC 252:100-35 Carbon Monoxide not type of emission unit

OAC 252:100-39 Nonattainment Areas not in area category

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


16. This permit supersedes all previous Air Quality permits for this facility which are now null

and void.

MAJOR SOURCE AIR QUALITY PERMIT

STANDARD CONDITIONS

(December 22, 2008)

SECTION I. DUTY TO COMPLY

A. This is a permit to operate / construct this specific facility in accordance with the federal

Clean Air Act (42 U.S.C. 7401, et al.) and under the authority of the Oklahoma Clean Air Act

and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma

Department of Environmental Quality (DEQ). The permit does not relieve the holder of the

obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or

ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

C. The permittee shall comply with all conditions of this permit. Any permit noncompliance

shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement

action, permit termination, revocation and reissuance, or modification, or for denial of a permit

renewal application. All terms and conditions are enforceable by the DEQ, by the Environmental

Protection Agency (EPA), and by citizens under section 304 of the Federal Clean Air Act

(excluding state-only requirements). This permit is valid for operations only at the specific

location listed.

[40 C.F.R. §70.6(b), OAC 252:100-8-1.3 and OAC 252:100-8-6(a)(7)(A) and (b)(1)]

D. It shall not be a defense for a permittee in an enforcement action that it would have been

necessary to halt or reduce the permitted activity in order to maintain compliance with the

conditions of the permit. However, nothing in this paragraph shall be construed as precluding

consideration of a need to halt or reduce activity as a mitigating factor in assessing penalties for

noncompliance if the health, safety, or environmental impacts of halting or reducing operations

would be more serious than the impacts of continuing operations. [OAC 252:100-8-6(a)(7)(B)]

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from an emergency and/or posing an imminent and substantial

danger to public health, safety, or the environment shall be reported in accordance with Section

XIV (Emergencies). [OAC 252:100-8-6(a)(3)(C)(iii)(I) & (II)]

B. Deviations that result in emissions exceeding those allowed in this permit shall be reported

consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements.

[OAC 252:100-8-6(a)(3)(C)(iv)]

C. Every written report submitted under this section shall be certified as required by Section III

(Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.

[OAC 252:100-8-6(a)(3)(C)(iv)]

MAJOR SOURCE STANDARD CONDITIONS December 22, 2008 Page 2

SECTION III. MONITORING, TESTING, RECORDKEEPING & REPORTING

A. The permittee shall keep records as specified in this permit. These records, including

monitoring data and necessary support information, shall be retained on-site or at a nearby field

office for a period of at least five years from the date of the monitoring sample, measurement,

report, or application, and shall be made available for inspection by regulatory personnel upon

request. Support information includes all original strip-chart recordings for continuous

monitoring instrumentation, and copies of all reports required by this permit. Where appropriate,

the permit may specify that records may be maintained in computerized form.

[OAC 252:100-8-6 (a)(3)(B)(ii), OAC 252:100-8-6(c)(1), and OAC 252:100-8-6(c)(2)(B)]

B. Records of required monitoring shall include:

(1) the date, place and time of sampling or measurement;

(2) the date or dates analyses were performed;

(3) the company or entity which performed the analyses;

(4) the analytical techniques or methods used;

(5) the results of such analyses; and

(6) the operating conditions existing at the time of sampling or measurement.

[OAC 252:100-8-6(a)(3)(B)(i)]

C. No later than 30 days after each six (6) month period, after the date of the issuance of the

original Part 70 operating permit, the permittee shall submit to AQD a report of the results of any

required monitoring. All instances of deviations from permit requirements since the previous

report shall be clearly identified in the report. Submission of these periodic reports will satisfy

any reporting requirement of Paragraph E below that is duplicative of the periodic reports, if so

noted on the submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)]

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or

operator shall comply with the provisions of Section II (Reporting Of Deviations From Permit

Terms) of these standard conditions.

[OAC 252:100-8-6(a)(3)(C)(iii)]

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this

permit, monitoring and reporting may be required under the provisions of OAC 252:100-43,

Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean

Air Act or Oklahoma Clean Air Act. [OAC 252:100-43]

F. Any document submitted in accordance with this permit shall be certified by a responsible

official. This certification shall be signed by a responsible official, and shall contain the

following language: “I certify, based on information and belief formed after reasonable inquiry,

the statements and information in the document are true, accurate, and complete.” However, an

exceedance report that must be submitted within ten days of the exceedance under Section II

(Reporting Of Deviations From Permit Terms) or Section XIV (Emergencies) may be submitted


without a certification, if an appropriate certification is provided within ten days thereafter,

together with any corrected or supplemental information required concerning the exceedance.

[OAC 252:100-8-5(f), OAC 252:100-8-6(a)(3)(C)(iv), OAC 252:100-8-6(c)(1) and OAC

252:100-9-3.1(c)]

G. Any owner or operator subject to the provisions of New Source Performance Standards

(“NSPS”) under 40 CFR Part 60 or National Emission Standards for Hazardous Air Pollutants

(“NESHAPs”) under 40 CFR Parts 61 and 63 shall maintain a file of all measurements and other

information required by the applicable general provisions and subpart(s). These records shall be

maintained in a permanent file suitable for inspection, shall be retained for a period of at least

five years as required by Paragraph A of this Section, and shall include records of the occurrence

and duration of any start-up, shutdown, or malfunction in the operation of an affected facility,

any malfunction of the air pollution control equipment; and any periods during which a

continuous monitoring system or monitoring device is inoperative.

[40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q]

I. The permittee of a facility that is operating subject to a schedule of compliance shall submit

to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for

achieving the activities, milestones or compliance required in the schedule of compliance and the

dates when such activities, milestones or compliance was achieved. The progress reports shall

also contain an explanation of why any dates in the schedule of compliance were not or will not

be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)]

J. All testing must be conducted under the direction of qualified personnel by methods

approved by the Division Director. All tests shall be made and the results calculated in

accordance with standard test procedures. The use of alternative test procedures must be

approved by EPA. When a portable analyzer is used to measure emissions it shall be setup,

calibrated, and operated in accordance with the manufacturer’s instructions and in accordance

with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document

or an equivalent method approved by Air Quality.

[OAC 252:100-8-6(a)(3)(A)(iv), and OAC 252:100-43]

K. The reporting of total particulate matter emissions as required in Part 7 of OAC 252:100-8

(Permits for Part 70 Sources), OAC 252:100-19 (Control of Emission of Particulate Matter), and

OAC 252:100-5 (Emission Inventory), shall be conducted in accordance with applicable testing

or calculation procedures, modified to include back-half condensables, for the concentration of

particulate matter less than 10 microns in diameter (PM10). NSPS may allow reporting of only

particulate matter emissions caught in the filter (obtained using Reference Method 5).

L. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required

by 40 C.F.R. Part 60, 61, and 63, for all equipment constructed or operated under this permit

subject to such standards. [OAC 252:100-8-6(c)(1) and OAC 252:100, Appendix Q]


SECTION IV. COMPLIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70

operating permit, 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)]

B. The compliance certification shall describe the operating permit term or condition that is the

basis of the certification; the current compliance status; whether compliance was continuous or

intermittent; the methods used for determining compliance, currently and over the reporting

period; 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. The compliance certification shall contain a certification by a responsible official as to the

results of the required monitoring. This certification shall be signed by a responsible official, and

shall contain the following language: “I certify, based on information and belief formed after

reasonable inquiry, the statements and information in the document are true, accurate, and

complete.”

[OAC 252:100-8-5(f) and OAC 252:100-8-6(c)(1)]

D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions

units or stationary sources that are not in compliance with all applicable requirements. This

schedule shall include a schedule of remedial measures, including an enforceable sequence of

actions with milestones, leading to compliance with any applicable requirements for which the

emissions unit or stationary source is in noncompliance. This compliance schedule shall

resemble and be at least as stringent as that contained in any judicial consent decree or

administrative order to which the emissions unit or stationary source is subject. Any such

schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the

applicable requirements on which it is based, except that a compliance plan shall not be required

for any noncompliance condition which is corrected within 24 hours of discovery.

[OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)]

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE

PERMIT TERM

The permittee shall comply with any additional requirements that become effective during the

permit term and that are applicable to the facility. Compliance with all new requirements shall

be certified in the next annual certification. [OAC 252:100-8-6(c)(6)]


SECTION VI. PERMIT SHIELD

A. Compliance with the terms and conditions of this permit (including terms and conditions

established for alternate operating scenarios, emissions trading, and emissions averaging, but

excluding terms and conditions for which the permit shield is expressly prohibited under OAC

252:100-8) shall be deemed compliance with the applicable requirements identified and included

in this permit. [OAC 252:100-8-6(d)(1)]

B. Those requirements that are applicable are listed in the Standard Conditions and the Specific

Conditions of this permit. Those requirements that the applicant requested be determined as not

applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6(d)(2)]

SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT

The permittee shall file with the AQD an annual emission inventory and shall pay annual fees

based on emissions inventories. The methods used to calculate emissions for inventory purposes

shall be based on the best available information accepted by AQD.

[OAC 252:100-5-2.1, OAC 252:100-5-2.2, and OAC 252:100-8-6(a)(8)]

SECTION VIII. TERM OF PERMIT

A. Unless specified otherwise, the term of an operating permit shall be five years from the date

of issuance. [OAC 252:100-8-6(a)(2)(A)]

B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely

and complete renewal application has been submitted at least 180 days before the date of

expiration. [OAC 252:100-8-7.1(d)(1)]

C. A duly issued construction permit or authorization to construct or modify will terminate and

become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction

is not commenced within 18 months after the date the permit or authorization was issued, or if

work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)]

D. The recipient of a construction permit shall apply for a permit to operate (or modified

operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)]

SECTION IX. SEVERABILITY

The provisions of this permit are severable and if any provision of this permit, or the application

of any provision of this permit to any circumstance, is held invalid, the application of such

provision to other circumstances, and the remainder of this permit, shall not be affected thereby.

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


SECTION X. PROPERTY RIGHTS

A. This permit does not convey any property rights of any sort, or any exclusive privilege.

[OAC 252:100-8-6(a)(7)(D)]

B. This permit shall not be considered in any manner affecting the title of the premises upon

which the equipment is located and does not release the permittee from any liability for damage

to persons or property caused by or resulting from the maintenance or operation of the equipment

for which the permit is issued. [OAC 252:100-8-6(c)(6)]

SECTION XI. DUTY TO PROVIDE INFORMATION

A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty

(60) days of the request unless the DEQ specifies another time period, any information that the

DEQ may request to determine whether cause exists for modifying, reopening, revoking,

reissuing, terminating the permit or to determine compliance with the permit. Upon request, the

permittee shall also furnish to the DEQ copies of records required to be kept by the permit.

[OAC 252:100-8-6(a)(7)(E)]

B. The permittee may make a claim of confidentiality for any information or records submitted

pursuant to 27A O.S. § 2-5-105(18). Confidential information shall be clearly labeled as such

and shall be separable from the main body of the document such as in an attachment.

[OAC 252:100-8-6(a)(7)(E)]

C. Notification to the AQD of the sale or transfer of ownership of this facility is required and

shall be made in writing within thirty (30) days after such sale or transfer.

[Oklahoma Clean Air Act, 27A O.S. § 2-5-112(G)]

SECTION XII. REOPENING, MODIFICATION & REVOCATION

A. The permit may be modified, revoked, reopened and reissued, or terminated for cause.

Except as provided for minor permit modifications, the filing of a request by the permittee for a

permit modification, revocation and reissuance, termination, notification of planned changes, or

anticipated noncompliance does not stay any permit condition.

[OAC 252:100-8-6(a)(7)(C) and OAC 252:100-8-7.2(b)]

B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the

following circumstances:

(1) Additional requirements under the Clean Air Act become applicable to a major source

category three or more years prior to the expiration date of this permit. No such

reopening is required if the effective date of the requirement is later than the expiration

date of this permit.

(2) The DEQ or the EPA determines that this permit contains a material mistake or that the

permit must be revised or revoked to assure compliance with the applicable requirements.


(3) The DEQ or the EPA determines that inaccurate information was used in establishing the

emission standards, limitations, or other conditions of this permit. The DEQ may revoke

and not reissue this permit if it determines that the permittee has submitted false or

misleading information to the DEQ.

(4) DEQ determines that the permit should be amended under the discretionary reopening

provisions of OAC 252:100-8-7.3(b).

[OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)]

C. The permit may be reopened for cause by EPA, pursuant to the provisions of OAC 100-8-

7.3(d). [OAC 100-8-7.3(d)]

D. The permittee shall notify AQD before making changes other than those described in Section

XVIII (Operational Flexibility), those qualifying for administrative permit amendments, or those

defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). The

notification should include any changes which may alter the status of a “grandfathered source,”

as defined under AQD rules. Such changes may require a permit modification.

[OAC 252:100-8-7.2(b) and OAC 252:100-5-1.1]

E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that

are not specifically approved by this permit are prohibited. [OAC 252:100-8-6(c)(6)]

SECTION XIII. INSPECTION & ENTRY

A. Upon presentation of credentials and other documents as may be required by law, the

permittee shall allow authorized regulatory officials to perform the following (subject to the

permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18)

for confidential information submitted to or obtained by the DEQ under this section):

(1) enter upon the permittee's premises during reasonable/normal working hours where a

source is located or emissions-related activity is conducted, or where records must be

kept under the conditions of the permit;

(2) have access to and copy, at reasonable times, any records that must be kept under the

conditions of the permit;

(3) inspect, at reasonable times and using reasonable safety practices, any facilities,

equipment (including monitoring and air pollution control equipment), practices, or

operations regulated or required under the permit; and

(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times

substances or parameters for the purpose of assuring compliance with the permit.

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

SECTION XIV. EMERGENCIES

A. Any exceedance resulting from an emergency shall be reported to AQD promptly but no later

than 4:30 p.m. on the next working day after the permittee first becomes aware of the


exceedance. This notice shall contain a description of the emergency, the probable cause of the

exceedance, any steps taken to mitigate emissions, and corrective actions taken.

[OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)]

B. Any exceedance that poses an imminent and substantial danger to public health, safety, or the

environment shall be reported to AQD as soon as is practicable; but under no circumstance shall

notification be more than 24 hours after the exceedance.

[OAC 252:100-8-6(a)(3)(C)(iii)(II)]

C. An "emergency" means any situation arising from sudden and reasonably unforeseeable

events beyond the control of the source, including acts of God, which situation requires

immediate corrective action to restore normal operation, and that causes the source to exceed a

technology-based emission limitation under this permit, due to unavoidable increases in

emissions attributable to the emergency. An emergency shall not include noncompliance to the

extent caused by improperly designed equipment, lack of preventive maintenance, careless or

improper operation, or operator error. [OAC 252:100-8-2]

D. The affirmative defense of emergency shall be demonstrated through properly signed,

contemporaneous operating logs or other relevant evidence that:

(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.

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

E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an

emergency shall have the burden of proof. [OAC 252:100-8-6(e)(3)]

F. Every written report or document submitted under this section shall be certified as required

by Section III (Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.

[OAC 252:100-8-6(a)(3)(C)(iv)]

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop

and register with the appropriate agency a risk management plan by June 20, 1999, or the

applicable effective date. [OAC 252:100-8-6(a)(4)]

SECTION XVI. INSIGNIFICANT ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to

operate individual emissions units that are either on the list in Appendix I to OAC Title 252,


Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below.

Any activity to which a State or Federal applicable requirement applies is not insignificant even

if it meets the criteria below or is included on the insignificant activities list.

(1) 5 tons per year of any one criteria pollutant.

(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an

aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year

for single HAP that the EPA may establish by rule.

[OAC 252:100-8-2 and OAC 252:100, Appendix I]

SECTION XVII. TRIVIAL ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to

operate any individual or combination of air emissions units that are considered inconsequential

and are on the list in Appendix J. Any activity to which a State or Federal applicable

requirement applies is not trivial even if included on the trivial activities list.

[OAC 252:100-8-2 and OAC 252:100, Appendix J]

SECTION XVIII. OPERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the

need for any permit revision or any notification to the DEQ (unless specified otherwise in the

permit). When an operating scenario is changed, the permittee shall record in a log at the facility

the scenario under which it is operating. [OAC 252:100-8-6(a)(10) and (f)(1)]

B. The permittee may make changes within the facility that:

(1) result in no net emissions increases,

(2) are not modifications under any provision of Title I of the federal Clean Air Act, and

(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit

to be exceeded;

provided that the facility provides the EPA and the DEQ with written notification as required

below in advance of the proposed changes, which shall be a minimum of seven (7) days, or

twenty four (24) hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the

DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such

change, the written notification required above shall include a brief description of the change

within the permitted facility, the date on which the change will occur, any change in emissions,

and any permit term or condition that is no longer applicable as a result of the change. The

permit shield provided by this permit does not apply to any change made pursuant to this

paragraph.

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


SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS

A. The following applicable requirements and state-only requirements apply to the facility

unless elsewhere covered by a more restrictive requirement:

(1) Open burning of refuse and other combustible material is prohibited except as authorized

in the specific examples and under the conditions listed in the Open Burning Subchapter.

[OAC 252:100-13]

(2) No particulate emissions from any fuel-burning equipment with a rated heat input of 10

MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19]

(3) For all emissions units not subject to an opacity limit promulgated under 40 C.F.R., Part

60, NSPS, no discharge of greater than 20% opacity is allowed except for:

(a) Short-term occurrences which consist of not more than one six-minute period in any

consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours.

In no case shall the average of any six-minute period exceed 60% opacity;

(b) Smoke resulting from fires covered by the exceptions outlined in OAC 252:100-13-7;

(c) An emission, where the presence of uncombined water is the only reason for failure to

meet the requirements of OAC 252:100-25-3(a); or

(d) Smoke generated due to a malfunction in a facility, when the source of the fuel

producing the smoke is not under the direct and immediate control of the facility and

the immediate constriction of the fuel flow at the facility would produce a hazard to

life and/or property.

[OAC 252:100-25]

(4) No visible fugitive dust emissions shall be discharged beyond the property line on which

the emissions originate in such a manner as to damage or to interfere with the use of

adjacent properties, or cause air quality standards to be exceeded, or interfere with the

maintenance of air quality standards. [OAC 252:100-29]

(5) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2

lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur

dioxide. [OAC 252:100-31]

(6) Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and

with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia or

greater under actual conditions shall be equipped with a permanent submerged fill pipe or

with a vapor-recovery system. [OAC 252:100-37-15(b)]

(7) All fuel-burning equipment shall at all times be properly operated and maintained in a

manner that will minimize emissions of VOCs. [OAC 252:100-37-36]

SECTION XX. STRATOSPHERIC OZONE PROTECTION

A. The permittee shall comply with the following standards for production and consumption of

ozone-depleting substances:


(1) Persons producing, importing, or placing an order for production or importation of certain

class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the

requirements of §82.4;

(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain

class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping

requirements at §82.13; and

(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons,

HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane

(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include

HCFCs.

[40 CFR 82, Subpart A]

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:

(1) Persons opening appliances for maintenance, service, repair, or disposal must comply

with the required practices pursuant to § 82.156;

(2) Equipment used during the maintenance, service, repair, or disposal of appliances must

comply with the standards for recycling and recovery equipment pursuant to § 82.158;

(3) Persons performing maintenance, service, repair, or disposal of appliances must be

certified by an approved technician certification program pursuant to § 82.161;

(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply

with record-keeping requirements pursuant to § 82.166;

(5) Persons owning commercial or industrial process refrigeration equipment must comply

with leak repair requirements pursuant to § 82.158; and

(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant

must keep records of refrigerant purchased and added to such appliances pursuant to §

82.166.

[40 CFR 82, Subpart F]

SECTION XXI. TITLE V APPROVAL LANGUAGE

A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is

not inconsistent with Federal requirements, to provide for incorporation of requirements

established through construction permitting into the Source’s Title V permit without causing

redundant review. Requirements from construction permits may be incorporated into the Title V


permit through the administrative amendment process set forth in OAC 252:100-8-7.2(a) only if

the following procedures are followed:

(1) The construction permit goes out for a 30-day public notice and comment using the

procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice to

the public that this permit is subject to EPA review, EPA objection, and petition to

EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit

will be incorporated into the Title V permit through the administrative amendment

process; that the public will not receive another opportunity to provide comments when

the requirements are incorporated into the Title V permit; and that EPA review, EPA

objection, and petitions to EPA will not be available to the public when requirements

from the construction permit are incorporated into the Title V permit.

(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR §

70.8(a)(1).

(3) A copy of the draft construction permit is sent to any affected State, as provided by 40

C.F.R. § 70.8(b).

(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period

as provided by 40 C.F.R.§ 70.8(a) and (c).

(5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day

comment period of any EPA objection to the construction permit. The DEQ shall not

issue the permit until EPA’s objections are resolved to the satisfaction of EPA.

(6) The DEQ complies with 40 C.F.R. § 70.8(d).

(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8(a).

(8) The DEQ shall not issue the proposed construction permit until any affected State and

EPA have had an opportunity to review the proposed permit, as provided by these

permit conditions.

(9) Any requirements of the construction permit may be reopened for cause after

incorporation into the Title V permit by the administrative amendment process, by DEQ

as provided in OAC 252:100-8-7.3(a), (b), and (c), and by EPA as provided in 40

C.F.R. § 70.7(f) and (g).

(10) The DEQ shall not issue the administrative permit amendment if performance tests fail

to demonstrate that the source is operating in substantial compliance with all permit

requirements.

B. To the extent that these conditions are not followed, the Title V permit must go through the

Title V review process.

SECTION XXII. CREDIBLE EVIDENCE

For the purpose of submitting compliance certifications or establishing whether or not a person

has violated or is in violation of any provision of the Oklahoma implementation plan, nothing

shall preclude the use, including the exclusive use, of any credible evidence or information,

relevant to whether a source would have been in compliance with applicable requirements if the

appropriate performance or compliance test or procedure had been performed.

[OAC 252:100-43-6]

Midstream Energy Services, LLC

Attn: Mr. David Wilkins

P. O. Box 1087

Sturgis, OK 73848

Re: Permit Application No. 97-242-TV

Midstream Energy Services, L.L.C.

Sturgis Compressor Station

Section 3-T4N-R8E, Cimarron County, Oklahoma

Dear Mr. Wilkins:

Air Quality Division has completed the initial review of your major source operating 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 252:002-31 the enclosed draft permit is now

ready for public review. The requirement 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. (Instruction enclosed)

2. Provide for public review (for a period of 30 days following the date of the newspaper

announcement) a copy of this draft permit and a copy of the application at a convenient

location (preferably a public location) within the county of the facility.

3. Send to AQD a copy of the proof of publication notice from Item #1 above together with any

additional comments or requested changes, which you may have on the draft permit.

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

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

Sincerely,

Phillip Fielder, P.E.

Permits & Engineering Group Manager


Enclosures

Texas Commission on Environmental Quality

Operating Permits Divisions (MC 163)

P. O. Box 13087

Austin, Texas 78711-3087

RE: Title V Operating Permit, Permit Number: 97-242-TV

Facility: Sturgis Compressor Station and Gas Plant

Location: Section 3-T4N-R8E, Cimarron County, Oklahoma

Permit Writer: Iftekhar Hossain

Dear Sir / Madame:

The subject facility has requested a Title V operating permit under 40 CFR Part 70. Air Quality

Division has completed the initial review of the application and prepared a draft permit for public

review. Since this facility is within 50 miles of the Oklahoma-Texas border, a copy of the

proposed permit will be provided to you upon request. Information on all permit and a copy of

this draft permit are available for review by the public in the Air Quality Section of DEQ Web

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


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

Sincerely,




Department of Public Health and Environment

4300 Cherry Creek Drive South, A130

Denver, CO 80246-1530





Dear Sir / Madame:



review. Since this facility is within 50 miles of the Oklahoma-Colorado border, a copy of the






Sincerely,




KDHE, BAR

Forbes Field, Building 283

Topeka, KS 66620





Dear Sir / Madame:



review. Since this facility is within 50 miles of the Oklahoma-Kansas border, a copy of the






Sincerely,




Air Quality Bureau, Title V Section

New Mexico Environment Department

2048 Galisteo Street

Santa Fe, NM 87502





Dear Sir / Madame:



review. Since this facility is within 50 miles of the Oklahoma-New Mexico border, a copy of

the proposed permit will be provided to you upon request. Information on all permit and a copy

of this draft permit are available for review by the public in the Air Quality Section of DEQ Web




Sincerely,




DEQ Form #100-890 Revised 10/20/06

PART 70 PERMIT AIR QUALITY DIVISION

STATE OF OKLAHOMA

DEPARTMENT OF ENVIRONMENTAL QUALITY

707 N. ROBINSON STREET, SUITE 4100

P.O. BOX 1677

OKLAHOMA CITY, OKLAHOMA 73101-1677

Permit No. 97-242-TV

Midstream Energy Services, L.L.C.,

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

a natural gas compressor station and gas plant in Sec. 3–T4N–R8E near Keyes, Cimarron

County, Oklahoma, subject to standard conditions dated January 24, 2008 and specific

conditions, both attached:

This permit shall expire five (5) years from the date below, except as authorized under

Section VIII of the Standard Conditions.

Director, Air Quality Division Issuance Date

Documents

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY€¦ · triethylene glycol (TEG) dehydration process by entering the TEG contactor, ... The helium plant consists of a purifier and a