Via e-mail to: r8airpermitting@epa.gov

December 29, 2011

US Environmental Protection Agency

Minor NSR Permitting Coordinator

U.S. EPA, Region 8

1595 Wynkoop Street, 8P-AR

Denver, CO 80202-1129

Re: QEP Energy Company

Indian Country Minor Source Permit Application

Facility Name: 13-24G

Fort Berthold Indian Reservation, North Dakota 

Dear Sir or Madam:

As required by 40 CFR 49.154, attached please find a completed application for the abovereferenced facility. 

This facility is listed in Administrative Complaint and Consent Agreement (CA) Docket No.

CAA-08-2011-026, Appendix A, Table A-4 (revised by letter from QEP Energy Company

(QEPE) to EPA, dated October 14, 2011). 

This application represents discussions and correspondence between representatives of QEPE, 

the North Dakota Petroleum Council and EPA Region 8. QEPE has prepared this application to 

reflect that communication and we greatly appreciate the efforts of, and guidance provide by 

EPA. 

If you have any questions concerning this application, please contact me. 

Sincerely,

Daniel Ryan 

Daniel Ryan

Sr. Environmental Engineer

Cc: Randy Judge

Matt Thompson

EPA via USPS

TAT

 

Independence Plaza

1050 17th Street, Suite 500

Denver, CO 80265

Tel 303 672 6900 - Fax 303 294 9632
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Region 8 Air Program 

FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY 

Check List – Application for New Construction 

(Form NEW) 

Please check all that apply to show how you are using this form 

9 Proposed Construction of a New Facility 

o Proposed Construction of New Equipment at an Existing Facility 

o Proposed Modification of an Existing Facility 

o Other – Please Explain 

Use of this information request form is voluntary and not yet approved by the Office of Management and Budget. 

The following is a check list of the type of information that Region 8 will use to process information on your proposed 

project. While submittal of this form is not required, it does offer details on the information we will use to complete your 

requested approval and providing the information requested may help expedite the process. Use of application forms for 

this program is currently under Office of Management and Budget review and these information request forms will be 

replaced/updated after that review is completed. 

Please submit information to following two entities: 

Minor NSR Permitting Coordinator 

U.S. EPA, Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

The Tribal Environmental Contact for the specific reservation: 

If you need assistance in identifying the appropriate Tribal 

Environmental Contact and address, please contact the EPA 

Region 8 Tribal Air Coordinator: 

Alexis North, EPA Region 8 Tribal Air Coordinator 

303-312-7005 

north.alexis@epa.gov

A. GENERAL FACILITY INFORMATION 

1. (a) Company Name 

 QEP Energy Company 

 (b) Operator Name

2. Facility Name

 13-24G 

3. Type of Operation 

Oil & Gas Well Facility

4. Portable Source?  Yes ; No 

5. Temporary Source?  Yes ; No 

6. NAICS Code 

211111

7. SIC Code 

131101

8. Physical Address (home base for portable sources)

9. Reservation* 

Fort Berthold

10. County* 

Dunn

11a. Latitude* 

47.62027

11b. Longitude* 

-102.35064

12a. Quarter Quarter Section* 

SWSW

12b. Section* 

24

12c. Township* 

148N

12d. Range* 

92W

*Provide all proposed locations of operation for portable sources 
B. PREVIOUS PERMIT ACTIONS (Provide information in this format for each permit that has 

been issued to this facility. Provide as an attachment if additional space is necessary) 

Facility Name on the Permit 

NEW FACILITY - NOT APPLICABLE 

Permit Number (xx-xxx-xxxxx-xxxx.xx) 

Date of the Permit Action 

Facility Name on the Permit 

NEW FACILITY - NOT APPLICABLE

Permit Number (xx-xxx-xxxxx-xxxx.xx) 

Date of the Permit Action 

Facility Name on the Permit 

NEW FACILITY - NOT APPLICABLE

Permit Number (xx-xxx-xxxxx-xxxx.xx) 

Date of the Permit Action 

Facility Name on the Permit 

NEW FACILITY - NOT APPLICABLE

Permit Number (xx-xxx-xxxxx-xxxx.xx) 

Date of the Permit Action 

Facility Name on the Permit 

NEW FACILITY - NOT APPLICABLE

Permit Number (xx-xxx-xxxxx-xxxx.xx) 

Date of the Permit Action 
C. CONTACT INFORMATION 

Company Contact 

Dan Ryan

Title 

Sr. Environmental Engineer

Mailing Address

1050 17th Street, Suite 500, Denver, CO 80265

Email Address 

Dan.Ryan@qepres.com

Telephone Number

(303) 672-6900

Facsimile Number

(303) 294-9632

Operator Contact (if different from company contact) Title 

Mailing Address

Email Address 

Telephone Number Facsimile Number

Facility Contact 

Dan Ryan

Title 

Sr. Environmental Engineer

Mailing Address

1050 17th Street, Suite 500, Denver, CO 80265

Email Address 

Dan.Ryan@qepres.com

Telephone Number

(303) 672-6900

Facsimile Number

(303) 294-9632

Compliance Contact 

Dan Ryan

Title 

Sr. Environmental Engineer

Mailing Address

1050 17th Street, Suite 500, Denver, CO 80265

Email Address 

Dan.Ryan@qepres.com

Telephone Number

(303) 308-3070

Facsimile Number

(303) 294-9632
D. ATTACHMENTS 

Include all of the following information (see the attached instructions) 

9 FORM SYNMIN - New Source Review Synthetic Minor Limit Request Form, if synthetic minor limits are 

being requested. 

9 Narrative description of the proposed production processes. This description should follow the flow of 

the process flow diagram to be submitted with this application. 

9 Process flow chart identifying all proposed processing, combustion, handling, storage, and emission control 

equipment. 

9 A list and descriptions of all proposed emission units and air pollution-generating activities.

9 Type and quantity of fuels, including sulfur content of fuels, proposed to be used on a daily, annual and 

maximum hourly basis. 

9 Type and quantity of raw materials used or final product produced proposed to be used on a daily, annual and 

maximum hourly basis. 

9 Proposed operating schedule, including number of hours per day, number of days per week and number of 

weeks per year. 

9 A list and description of all proposed emission controls, control efficiencies, emission limits, and monitoring 

for each emission unit and air pollution generating activity. 

9 Criteria Pollutant Emissions - Estimates of Current Actual Emissions, Current Allowable Emissions, PostChange Uncontrolled Emissions, and Post-Change Allowable Emissions for the following air pollutants: 

particulate matter, PM10, PM2.5, sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO), volatile 

organic compound (VOC), lead (Pb) and lead compounds, fluorides (gaseous and particulate), sulfuric acid 

mist (H2SO4), hydrogen sulfide (H2S), total reduced sulfur (TRS) and reduced sulfur compounds, including all 

calculations for the estimates. 

9 These estimates are to be made for each emission unit, emission generating activity, and the project/facility in 

total. 

9 Modeling – Air Quality Impact Analysis (AQIA) 

9 ESA (Endangered Species Act) 

9 NHPA (National Historic Preservation Act)
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.1

FORM SYNMIN

1. This facility proposes a limitation of Volatile Organic Compounds (VOC) through the use of an enclosed

flare or utility flare.

This limitation will reduce storage tank VOC emissions by 98% through the installation of a enclosed

flare or utility flare.

2. The enclosed flare or utility flare will be designed in accordace with 40 CFR 60.18 and should be

considered to achieve 98% destruction of VOC.  No testing of the flare destruction efficiency is

anticipated.

The flare will be manually monitored by observing that the flare is burning during periodic visits to the facility.

R d k i ti i t d l i d b it

Uncontrolled Volatile Organic Compound (VOC) emissions from this facility would be considered major

for Prevention of Significant Deterioration (PSD) and Part 71 (Title V) regulations, storage tank VOC  

emissions are controlled by utility flare to make this facility a synthetic monor for both PSD and Title V.

Record keeping or reporting is not proposed unless required by permit.

3. The enclosed flare or utility flare will be designed in accordace with 40 CFR 60.18 and should be

considered to achieve 98% destruction of VOC.

4. Estimates of post emissions based on the use of the control are located in the summary table

labeled "controlled production Equipment Emissions" and calculations are shown in Attachment D.4.

5. Potential green house gas emissions (both pre and post control) are less than 100,000 TPY CO2e

but greater than 250 TPY on a mass basis.
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Region 8 Air Program 

FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY 

Checklist - Synthetic Minor Limit Request 

(Form SYNMIN) 

Use of this information request form is voluntary and not yet approved by the Office of Management and Budget. The 

following is a check list of the type of information that Region 8 will use to process information on your proposed project. While 

submittal of this form is not required, it does offer details on the information we will use to complete your requested approval and 

providing the information requested may help expedite the process. Use of application forms for this program is currently under

Office of Management and Budget review and these information request forms will be replaced/updated after that review is 

completed. 

Please submit information to following two entities: 

Federal Minor NSR Permit Coordinator 

U.S. EPA, Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

The Tribal Environmental Contact for the specific reservation: 

If you need assistance in identifying the appropriate Tribal 

Environmental Contact and address, please contact the EPA 

Region 8 Tribal Air Coordinator: 

Alexis North, EPA Region 8 Tribal Air Coordinator 

303-312-7005 

north.alexis@epa.gov

A. GENERAL INFORMATION 

Company Name 

QEP Energy Company

Facility Name 

13-24G 

Company Contact or Owner Name 

Dan Ryan

Title 

Sr. Environmental Engineer

Mailing Address 

1050 17th Street, Suite 500, Denver, CO 80265

Email Address 

Dan.Ryan@qepres.com

Telephone Number 

(303) 308-3070

Facsimile Number 

(303) 294-9632

B. ATTACHMENTS 

For each criteria air pollutant, hazardous air pollutant and for all emission units and air pollutantgenerating activities to be covered by a limitation, include the following: 

9 Item 1 - The proposed limitation and a description of its effect on current actual, allowable and the potential to 

emit. 

9 Item 2 - The proposed testing, monitoring, recordkeeping, and reporting requirements to be used to demonstrate 

and assure compliance with the proposed limitation. 

9 Item 3 - A description of estimated efficiency of air pollution control equipment under present or anticipated 

operating conditions, including documentation of the manufacturer specifications and guarantees. 

9 Item 4 - Estimates of the Post-Change Allowable Emissions that would result from compliance with the proposed 

limitation, including all calculations for the estimates. 

9 Item 5 – Estimates of the potential emissions of Greenhouse Gas (GHG) pollutants before and after proposed 

emission controls. 
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.1 Part B

Additional Compliance Information
1

Attachment D.1.B to Application for Facility: _13-24G_ : 

Proposed Permit Section Language and 

Additional Compliance Information 

Requested Full Section I.E of permit: 

I. E. Control System Options and Requirements for VOC (or VOC and HAP) Emissions

1. Closed-Vent Systems

(a) Closed-vent systems (CVS) shall be used to route all VOC (or VOC and HAP) emissions 

from the VOC emitting devices to the control devices required by this permit. 

(b) All components making up the CVS (lines, connections, fittings, valves, relief valves, or 

any other appurtenance employed to contain and collect gases, vapors, and fumes and 

transport them to control the VOC (or VOC and total HAP) control equipment) shall be 

maintained and operated during any time the control equipment is operating. 

(c) Each closed-vent system shall be designed and operated with no visible emissions. 

(d) If any closed-vent system contains one or more bypass devices that could be used to 

divert all or a portion of the gases, vapors, or fumes from entering the equipment to 

control devices required by this permit, the permittee shall meet the one of following 

requirements for each bypass device: 

i. At the inlet to the bypass device that could divert the stream away from the 

enclosed combustor to the atmosphere, properly install, calibrate, maintain, and 

operate a flow indicator that is capable of taking periodic readings and sounding 

an alarm when the bypass device is open such that the stream is being, or could 

be, diverted away from the control device to the atmosphere; or 

ii. Label the bypass device valve installed at the inlet to indicate that the nondiverting position is the correct position for normal operation and that the valve 

should only be switched to the divert position in an emergency or other malfunction 

situation. 

2. Enclosed Combustors and Utility Flares

(a) Each enclosed combustor shall be designed to have sufficient capacity to achieve at least 

98.0% destruction efficiency for the anticipated minimum and maximum hydrocarbon 

volumetric flow rate and BTU content routed to the device. 

(b) Each utility flare shall be designed and operated in accordance with the requirements of 40 

CFR 60.18 and 40 CFR 63.11 and have sufficient capacity to achieve at least a 98.0% destruction 

efficiency for the minimum and maximum hydrocarbon volumetric flow rate and BTU content 

routed to the device. 

[Note: “Maximum” means instantaneous peak, i.e., the flash emissions resulting from 

a liquid dump event upstream of the tank into which the liquid is dumping.] 
2

(c) Enclosed combustors and utility flares shall be operated: 

i. At all times that VOC emissions are routed to it; 

ii. Operated with a liquid knock out box to collect condensable vapors (to prevent form 

going through to the control device; 

iii. Equipped with one or more of the following: 

a. a thermocouple and continuous recording device such as a chart recorder, 

data logger or similar device, to document the presence of a pilot flame; with 

alarm; or 

b. a visual site glass to detect the presence of a pilot flame; or 

c. a gas/vapor flow detector and auto igniter which lights the combustor burner 

or pilot burner when flow is detected; 

iv. Maintained in a leak-free condition; and 

v. Operated in a smokeless mode. 

(d) The permittee shall monitor the utility flare and enclosed combustor operations to 

confirm proper operation as follows: 

i. If using a thermo-couple/recording device/alarm, continuously monitor the pilot flame 

and respond to any alarms; check the thermocouple and recording device and the 

pilot flames to insure proper operation, quarterly at a minimum. 

ii. If using a visual site glass, visually check for the presence of a pilot flame, during 

routine operations and at least quarterly. 

iii. If using a gas/vapor flow detector and auto igniter, check the system proper operation 

during routine operations and at least quarterly. 

iii. Visually confirm that no smoke is present during operation of any enclosed 

combustor or utility flare, during routine operations and at least quarterly. 

3. Pit Flares

(a) A pit flare may be used for the following operations: 

i. To control emissions during well completions and re-completions; 

ii. To control emissions in the event the produced hydrocarbon gas that is being 

recovered for sale or other beneficial purpose must be diverted to an emergency 

control device and no utility flare is currently installed or operating at the facility for 

any purpose; 

iii. To control emissions in the event the VOC (or VOC and HAP) emissions that are being 

recovered from emission units for sale or other beneficial purpose must be diverted to an 

emergency control device due to sudden, infrequent, and unavoidable events, and 

enclosed combustors have not been installed at the facility for the purpose of controlling 

VOC (or VOC and HAP) emissions from any units at the facility; or 

iv. Within the first 90 days after the first date of production, as specified under Section 

I.D.2(b),(c) 

(b) The permittee shall only use the pit flare under the following conditions and limitations:

i. The pit flare is operated with at least a 90.0% destruction efficiency; and 

ii. The facility-wide VOC (or VOC, total HAP, and each individual HAP) is not 

exceeded; and 
3

ing 

iii. Use of the pit flare is limited to no more than 900 hours in any January 1 – December 31 

calendar year; and 

iv. The 90 day initial production period of allowed pit flare operation (Sections I.D.2(b),(c)) is 

not included in the 900 hour per year limit for pit flare operation. 

v. A demonstration of compliance with the hours of operation limit is made by keep

log entry records during each period of time that the pit flare is operating. The 

records shall be kept onsite at the source and shall contain the following 

information: 

(A) Date and time the flare was started up and subsequently shut down; 

(B) Running total of the hours operated for the previous consecutive 12 months; and 

(C) Brief description of the justification for operation; 

vi. The pit flare is visually inspected daily, or at an appropriate frequency determined by the 

permittee, for proper operation (presence of pilot flame or other indicator) during its use. 

If improper operation is observed it shall be corrected as soon as practicable; and 

vi. The permittee shall not deposit or cause to be deposited into a flare pit any oil field 

fluids or oil and gas wastes other than those designed to go to the pit flare. 

4. Other Control Devices

Control devices other than those listed above that are capable of achieving 98.0% destruction 

efficiency may be utilized, as specified in this permit or immediately after the permittee 

notifies EPA, subject to the requirements of Section II of this permit. 

5. Recordkeeping Requirements

(a) Records shall be kept of all required testing and monitoring of the control device 

operations. 

(b) Records shall be kept of any instances in which any closed-vent system or control device 

was bypassed or down in each calendar month, the reason for each incident, its duration, 

and the corrective actions taken or the preventative measures adopted to avoid such 

bypasses or downtimes. 

(c) Records shall be kept of any instances in which the pilot flame or auto igniter system 

(ATS) is not operating in the enclosed combustor or the utility flare, the date and times 

that the pilot or ATS was not operating, and the corrective actions taken or the 

preventative measures adopted to restore operation. 

(d) Records shall be kept of any instances in which the thermocouple (or other heat sensing 

monitoring device) installed to detect the presence of a flame in the enclosed combustor 

or utility flare is not operational, the time period during which it was not operational, and 

the and the corrective measures taken. 

(e) Records shall be kept of any instances in which the recording device installed to 

record data from the thermocouple is not operational. 

(f) Records shall be kept of any time periods in which visible emissions are 

observed emanating from a control system. 
4

Requested Full Section I.F. of permit: 

I. F. Equipment Leaks – VOC (or VOC & HAP)

1. Work Practice and Operational Requirements

(a) The permittee shall minimize leaks of volatile organics from each piece of equipment in 

hydrocarbon service at this facility. 

b) The permittee shall monitor and repair leaks at vent lines, flanges, connections, fittings, or 

other devices employed to contain, collect or convey gases and vapors at the facility. 

Such monitoring and repair shall be performed at least quarterly minimum.

(c) Any leaking equipment shall be repaired as soon as practicable, after the leak is initially 

detected, unless the repair is technically infeasible without a facility shutdown. 

(d) The permittee shall make the first attempt to repair any leaking equipment within five 

days after the leak is detected. 

(e) Any leaking equipment shall be repaired as soon as practicable, but no later than 15 days 

after the leak is initially detected, unless the repair is technically infeasible without a 

facility shutdown, parts are not available locally, or specialty repair is required. Such 

equipment shall be repaired before the end of the first facility shutdown after the leak is 

initially detected. 

2. Monitoring Requirements

 

(a) The permittee’s quarterly equipment leak detection protocol consists of: 

• A qualified permittee representative, who is familiar with the facility equipment, visits 

the facility on foot and uses audio, visual and olfactory observations (AVO) to check 

for leaks; 

• Any emissions detected under the protocol are defined as a leak unless screened with 

Method 21 (40 CFR Part 60, Appendix A-7) monitoring, in which case, 10,000 ppm 

or greater is designated as a leak. 

• All leak detection inspection records shall include, at a minimum, the following 

information: 

 The date and time of the inspection; 

 All documentation and/or images produced in the inspection; 

 Location of any leaks and specific equipment involved; 

 Quantification of leaks or suspected leaks using optional Method 21, if 

performed; 

 Any corrective action taken or any first attempt to repair made; and the outcome 

of such attempts 

 The inspector's name and signature. 

3. Recordkeeping requirements

The permittee shall maintain the records from the above leak detection and repair 

inspections. Those records shall be used to demonstrate that all leaks detected are repaired within 
5

the timeframes and other requirements specified in the above protocol. 

Requested Full Section I. H. of example permit: 

I. H. Requirements for Hydrocarbon Storage Tanks

1. Hydrocarbon storage tanks (HSTs) include tanks that store hydrocarbon products and 

hydrocarbon production waste streams such as, oil production tanks; condensate productions 

tanks; and slop oil tanks. Produced water tanks at this facility are considered to be HSTs only if 

they are connected by piping, or by interconnected or common vent lines to other HSTs. 

2. The permittee shall install, maintain, and operate each hydrocarbon storage tank such that the 

long-term facility-wide emission limit requirements in this permit will be met when the total 

emissions from the tanks are included in the consecutive 12-month facility-wide total. This 

shall be achieved by meeting one or more of the following emission control techniques: 

(a) Limit the operational throughput of the tanks constructed and operated at the facility; 

and/or 

(b) Use a control device operated as specified by this permit; and/or 

(c) Use equipment designed to capture the VOC (or VOC and total HAP) emissions for sale 

or other beneficial purpose. 

3. For each hydrocarbon storage tank with the potential for flash emissions, the permittee shall perform 

the following inspections and any necessary repairs on a quarterly basis: 

(a) Check that thief hatch covers are weighted and properly seated and the gaskets are in good 

condition to prevent venting of emissions; 

(b) Check that pressure relief valves (PRV) are set to release at a pressure that will ensure 

flashing, and standing/ working/breathing losses are routed to an emissions control device 

as specified in this permit, under normal operating conditions, including the maximum 

instantaneous fill rate that may occur during liquid dumping events by upstream vessels. 

 

4. The permittee shall document and maintain a record of the quarterly inspections. All inspection 

records shall include, at a minimum, the following information: 

(a) The date of the inspection; 

(b) The findings of the inspection; 

(c) Any required repairs; and 

(d) The inspector's name and signature. 

5. The permittee shall follow, for each storage tank, the manufacturer’s recommended 

maintenance schedule and operating procedures to ensure good air pollution control practices 

for minimizing emissions. 
6

6. Records shall be kept of all scheduled maintenance and repairs. 

7. Records shall be kept of the emissions calculations included in the consecutive 12-month 

facility-wide total. 

(Requested additional paragraph to Section I.D.3.(a): 

I.D.3.(a) Facility – Wide Emission Requirements, Monitoring Requirements 

“The permittee shall calculate monthly emission for each emission source type (tanks, process 

devices, etc.) using the ratio of: actual production throughput, operating hours, or other appropriate 

parameter, divided by the appropriate production parameter value used to calculate the estimated monthly 

emissions in the permit application. The emission ratio thus derived will be multiplied by emission value 

calculated for each source type in the application, to determine the calculated emissions for each month 

for each source type. “ 

Requested revised Section I.K.3. : 

I.K.3. Requirements for Testing Engines over 500 horsepower

For each engine with a site-rated bhp greater than or equal to 500, the permittee shall conduct an initial 

EPA Reference Method performance test within one year of startup, measure VOC emissions. The 

permittee shall also conduct subsequent performance tests on each engine thereafter, every 8,760 hours of 

operation or 3 years, whichever comes first. The results of the performance tests shall be used to 

calculate the actual engine emissions included in the consecutive 12-month facility-wide total. 

Requested revised Section I.K.4. : 

I.K.4. Requirements for Catalyst-Equipped Engines 

For each engine over 500 site-rated horsepower, if equipped with a catalytic control system: 

(a) Install, operate, and maintain pressure-sensing devices at the inlet and outlet of the catalyst to 

measure and record the pressure drop across the catalyst. 

(b) Install, operate, and maintain temperature-sensing devices to measure the temperature of the 

engine exhaust at the inlet of the catalyst. 

(c) Measure and record the pressure drop across the catalyst and the temperature of the engine 

exhaust at the inlet of the catalyst, at least monthly, to ensure that the pressure drop and 

temperature are maintained within the operating limits specified by the catalyst manufacturer. 

Other Requested Changes Revisions: 

Other requested changes to permit language include additional items not discussed above, but which 

were listed or requested under “Technical Clarifications” in a letter from the North Dakota Petroleum 

Council to Mr. Jim Martin, EPA, dated December 7, 2011. 
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.2

Process Description, Plot Plan/Process Flow Diagram and Site Location

Prepared for: Prepared by:

QEP Energy Company Lesair Environmental, Inc.

www.Lesair.com
QEP Energy Company 

Fort Berthold 

13-24G 

Process Description

This is a multi-well facility that will separate production from four (4) proposed oil and natural 

gas exploration and production wells drilled at this location. Each well will flow to its respective 

process equipment; this equipment is similar in construction and function. The typical process 

train is described below. 

The commingled fluid stream (containing natural gas, condensate and produced water) flows 

from each well. The well fluids flow to its respective 6' x 20' vertical heater treater (0.5 

MMBtu/hr burner duty rating). In this vertical treater, the fluid is heated to a desired 

temperature range to aid in separation of the condensate, natural gas and produced water. 

The hydrocarbon liquid (condensate) and produced water flow to their respective storage 

tanks. 

The natural gas stream from the vertical heater treater is expected to be metered into a natural 

gas sales pipeline. If the pipeline is not immediately available or if it becomes unavailable the 

natural gas will go to a utility flare. 

From the condensate storage tanks, the condensate is metered through a L.A.C.T. (Lease 

Automated Custody Transfer) unit and is sold as it is pumped, using electric motor driven 

pumps, into a condensate sales pipeline. If the condensate does not meet sales quality 

standards it is automatically diverted to one of the "divert" tanks where it will be treated until it 

can meet sales specifications and be sold. 

The produced water uses electric motor driven water transfer pumps to pump the produced 

water to a centralized water handling facility for disposal. 

The hydrocarbon vapors from all of the storage tanks are sent to a utility flare through a 

common tank piping system. 

If conditions do not allow the use of the pipelines to transport the produced water or 

condensate, then the liquids will be loaded into tanker trucks and hauled from the facility. 

There are fugitive emissions associated with the piping connections, flanges, valves, etc. 

These emissions occur due to the potential seeping of gas from connections, seats, and seals. 

A trailer mounted dual fueled (diesel and natural gas) engine driven generator will be utilized 

for facility power until utility power is available. This generator will supply the power necessary 

to operate the LACT pumps, an electric motor driven pumping unit, and other facility power 

needs. 

N 

13-24G 

Topographic Map 

Questar Exploration & Production CO. 

Dunn County, North Dakota 

Latitude: 47.62027 N 

Longitude: -102.35064 W 

Drawn by: MAC 

Date: December 2011 

13-24G 
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.3

Proposed Equipment and Estimated Emission Summary

Prepared for: Prepared by:

QEP Energy Company Lesair Environmental, Inc.

www.Lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

NOx CO SO2 Particulates VOC Total HAPs

Ref No. Equipment Note lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY

001 (8) 400 bbl. Condensate Storage Tanks a 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 409.14 1792.05 4.01 17.55002 (4) 400 bbl. Divert Tanks b 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00003 (4) 400 bbl. Produced Water Tanks c 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

004 (1) 0.5 MMBtu/hr Heater Treater d, e 0.07 0.30 0.06 0.25 0.00 0.00 0.01 0.02 373.56 1636.18 8.69 38.07005 (1) 0.5 MMBtu/hr Heater Treater d, e 0.07 0.30 0.06 0.25 0.00 0.00 0.01 0.02 373.56 1636.18 8.69 38.07006 (1) 400 hp Generator f 4.23 18.52 2.29 10.03 0.82 3.59 0.13 0.58 0.88 3.86 0.00 0.00007 Truck Loading g 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 33.02 0.00 0.56008 Fugitives h 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.53 2.33 0.00 0.00

Total 4.37 19.13 2.41 10.54 0.82 3.60 0.14 0.62 1157.67 5103.62 21.98 94.26

NOTES:

a - Condensate tanks emissions estimated using the process simulation software BR&E ProMAX and a like kind pressurized condensate analysis (Rupple).

b - Divert tanks are used only during upset conditions (i.e., when condensate does not meet sales specifications), quantification of emissions is not required.

c - Produced water tank vent lines are connected to the condensate tank vent system and accounted for at source (001) "Condensate Storage Tanks". Produced water is not

 an emission source but the small amount of condensate that carries over in the water is the source of emissions, condensate tank emissions account for all of these emissions.

d - Burner emissions based on EPA AP-42 emission factors from Section 1.4, Tables 1.4-1 and 1.4-2 for uncontrolled natural gas burners (July 1998), the worst case assumption that burners operate 8,760 hours per year and a fuel heating value of 1430 Btu/SCF.e - Heater Treater uncontrolled vent (casing head gas) VOC and HAP emissions represent a worst-case scenerio in which casing head gas does not go to pipeline.f - Generator engine emissions are estimated using 400 Hp diesel fueled tier II engine emission factors. These engines are trailer mounted and are expected to be portable. 

 Engine emissions have been listed here to ensure that all emissions sources have been identified due to uncertainty of when utility power will be available.

g - Truck loadout emissions were based on worst case assumption that produced liquids will be trucked from the facility year round due to uncertainty of pipeline

EPA Region 8 Minor Source Permitting Program

Uncontrolled Production Equipment Emissions

g - Truck loadout emissions were based on worst case assumption that produced liquids will be trucked from the facility year round, due to uncertainty of pipeline.

h - Fugitive component type and count is an estimate, the emissions were calculated using EPA Table 2-4 for E&P production facilities.

Lesair Environmental, Inc.www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

EPA Region 8 Minor Source Permitting Program

NOx CO SO2 Particulates VOC Total HAPs

Ref No. Equipment Note lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY

001 (8) 400 bbl. Condensate Storage Tanks a 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00002 (4) 400 bbl. Divert Tanks b 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00003 (4) 400 bbl. Produced Water Tanks c 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

004 (1) 0.5 MMBtu/hr Heater Treater d,e 0.07 0.30 0.06 0.25 0.00 0.00 0.01 0.02 0.00 0.02 0.00 0.00005 (1) 0.5 MMBtu/hr Heater Treater d,e 0.07 0.30 0.06 0.25 0.00 0.00 0.01 0.02 0.00 0.02 0.00 0.00006 (1) 400 hp Generator f 4.23 18.52 2.29 10.03 0.82 3.59 0.13 0.58 0.88 3.86 0.00 0.00007 Truck Loading g 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 33.02 0.00 0.56008 Fugitives h 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.53 2.33 0.00 0.00

009 Enclosed Flare or Utility Flare i 5.41 23.69 10.80 47.30 0.00 0.00 0.00 0.00 23.14 101.37 0.43 1.88

Total 9.78 42.82 13.21 57.84 0.82 3.60 0.14 0.62 24.56 140.61 1.02 2.44

NOTES:

a - Condensate tanks emissions are controlled by a 98% DRE control device, emissions have been accounted for at source (010) "Enclose Flare or Utility Flare".

b - Divert tanks are used only during upset conditions (i.e., when condensate does not meet sales specifications), quantification of emissions is not required.

c - Produced water tank vent lines are connected to the condensate tank vent system and go to flare, these controlled emissions are accounted for at source (010) "Enclosed 

 Flare or Utility Flare".d - Burner emissions based on EPA AP-42 emission factors from Section 1.4, Tables 1.4-1 and 1.4-2 for uncontrolled natural gas burners (July 1998), the worst case assumption that burners operate 8,760 hours per year and a fuel heating value of 1430 Btu/SCF.e - Heater Treater vent (casing head gas) VOC and HAP emissions are routed to flare if there is no pipeline availability. These controlled emissions are accounted for at 

 source (010) "Enclosed Flare or Utility Flare", representing a worst-case scenerio in which casing head gas goes to flare and not to pipeline.

f Generator engine emissions are estimated using 400 Hp diesel fueled tier II engine emission factors These engines are trailer mounted and are expected to be portable

Controlled Production Equipment Emissions

f - Generator engine emissions are estimated using 400 Hp diesel fueled tier II engine emission factors. These engines are trailer mounted and are expected to be portable. 

 Engine emissions have been listed here to ensure that all emissions sources have been identified due to uncertainty of when utility power will be available.

g - Truck loadout emissions were based on worst case assumption that produced liquids will be trucked from the facility year round, due to uncertainty of pipeline.h - Fugitive component type and count is an estimate, the emissions were calculated using EPA Table 2-4 for E&P production facilities.i - All casing head gas (from heater treater) and condensate storage tank emissions are sent to a 98% DRE Enclosed Flare or Utility Flare.

Lesair Environmental, Inc.www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Methane Methane CO2ef NOx NOx CO2ef CO2 Total CO2e

Ref No. Equipment Note lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY

001 (8) 400 bbl. Condensate Storage Tanks a 5.91 25.88 135.91 595.30 1.30 5.71 403.92 1769.15 1.25 5.47 541.08 2369.93002 (4) 400 bbl. Divert Tanks b 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00003 (4) 400 bll. Produced Water Tanks c 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00004 (1) 0.5 MMBtu/hr Heater Treater d,e 202.74 887.99 4662.94 20423.66 0.07 0.30 21.45 93.97 84.12 368.44 4768.51 20886.07005 (1) 0.5 MMBtu/hr Heater Treater d,e 202.74 887.99 4662.94 20423.66 0.07 0.30 21.45 93.97 84.12 368.44 4768.51 20886.07006 (1) 400 hp Generator 0.00 0.00 0.00 0.00 4.23 18.52 1311.01 5742.24 460.00 2014.80 1771.01 7757.04008 Fugitives 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Total 411.38 1801.85 9461.79 41442.63 5.67 24.84 1757.84 7699.32 629.49 2757.15 11849.11 51899.10

NOTES:

a - Condensate tanks emissions estimated using the process simulation software BR&E ProMAX and a like kind pressurized condensate analysis.b - Divert tanks are used only during upset conditions (i.e., when condensate does not meet sales specifications), quantification of emissions is not required.c - Produced water tank vent lines are connected to the condensate tank vent system and goes to flare. Produced water is not an emission source but the condensate that carries over is, QEP condensate emissions account for all of the potential emissions.d - Burner emissions based on EPA AP-42 emission factors from Section 1.4, Tables 1.4-1 and 1.4-2 for uncontrolled natural gas burners (July 1998), the worst case assumption that burners operate 8,760 hours per year and a fuel heating value of 1430 Btu/SCF.e - Heater treater emissions include casinghead gas to represent a worst-case scenerio in which gas is neither flared nor routed to pipeline, and all produced gas is

vented to the atmosphere through each heater treater.

f - CO2 equivalents calculated using Global Warming Potentials (GWPs) from 40 CFR Part 98 Subpart A table A-1

EPA Region 8 Minor Source Permitting Program

Potential GHG Emissions for Uncontrolled Emissions

Lesair Environmental, Inc.www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

EPA Region 8 Minor Source Permitting Program

Methane Methane CO2ef NOx NOx CO2ef CO2 Total CO2e

Ref No. Equipment Note lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY

001 (8) 400 bbl. Condensate Storage Tanks a 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00002 (4) 400 bbl. Divert Tanks b 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00003 (4) 400 bll. Produced Water Tanks c 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00004 (1) 0.5 MMBtu/hr Heater Treater d 0.00 0.00 0.00 0.00 0.07 0.30 21.45 93.97 83.04 363.74 104.50 457.70005 (1) 0.5 MMBtu/hr Heater Treater d 0.00 0.00 0.00 0.00 0.07 0.30 21.45 93.97 83.04 363.74 104.50 457.70006 (1) 400 hp Generator d 0.00 0.00 0.00 0.00 4.23 18.52 1311.01 5742.24 460.00 2014.80 1771.01 7757.04009 Fugitives 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00010 Enclosed Flare or Utility Flare e 8.23 36.04 189.24 828.85 5.41 23.69 1676.76 7344.22 4610.34 20193.30 6476.34 28366.37

Total 8.23 36.04 189.24 828.85 9.78 42.82 3030.68 13274.39 5236.43 22935.58 8456.35 37038.82

NOTES:

a - Condensate tanks emissions estimated using the process simulation software BR&E ProMAX and a like kind pressurized condensate analysis.b - Divert tanks are used only during upset conditions (i.e., when condensate does not meet sales specifications), quantification of emissions is not required.c - Produced water tank vent lines are connected to the condensate tank vent system and goes to flare. Produced water is not an emission source but the condensate that carries over is, QEP condensate emissions account for all of the potential emissions.d - Burner emissions based on EPA AP-42 emission factors from Section 1.4, Tables 1.4-1 and 1.4-2 for uncontrolled natural gas burners (July 1998), the worst case assumption that burners operate 8,760 hours per year and a fuel heating value of 1430 Btu/SCF.e- Emission factors for Methane and CO2 calculations were taken from Table 12.2 API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. 

Section 4-Combustion Emission Estimation Methods, 2004.

f - CO2 equivalents calculated using Global Warming Potentials (GWPs) from 40 CFR Part 98 Subpart A table A-1

Potential GHG Emissions for Controlled Emissions

Lesair Environmental, Inc.www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.4

Emission Calculations

Prepared for: Prepared by:

QEP Energy Company Lesair Environmental, Inc.

www.Lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Condensate Storage Tank Emissions Calculations

VOC, Benzene & n-Hexane Emissions

Annualized Production (BPY): 301,730 Control Description: Utility Flare

Production While Controls Operational: 301,730 Control Efficiency: 98%

Production forecasts are based on the first year of production for similar wells in the area. Production decline was built into the

annualized total.

VOC lb/bbl was calculated using BRE Promax software and a representative pressurized liquid analysis (Rupple).

Production while controls operational represents the portion of this facilities production where the tank emissions were

controlled.

NOx and CO emission factors were taken from Table 4 of the Texas Natural Resource Conservation Commission's (TNRCC) 

"Air Permit Technical Guidance for Chemical Sources - Flares and Vapor Oxidizers" document. The waste gas stream is assumed

to be high-Btu (> 1,000 Btu/scf).

Facility County VOC 

(lb/bbl)

Total HAP 

(lb/bbl)

n-Hexane 

(lb/bbl)

NOx 

(lb/MMBtu)

CO

(lb/MMBtu)

Dunn 11.878 0.116 0.104 0.138 0.2755

Actual Emission Calculations:

VOC 

(ton/yr)

Total HAP 

(TPY)

n-Hexane 

(TPY)

Flash Gas

(MMBtu/yr)

1,792.0 17.6 15.8 82,709

VOC Total HAP n-Hexane NOx CO 

Controlled Emissions

Uncontrolled Emissions

(ton/yr) (TPY) (TPY) (ton/yr)

35.8 0.4 0.3 5.71 11.39

*N-hexane is the largest HAP, it is used to indicate potential for Title V applicability.

Example Calculations:

NOTE: Flash gas heat content, molecular weight and VOC fraction are estimated based on ProMax 3.0 emission simulations

using composite flash gas analysis for these facilities.

(ton/yr)

⎟

⎠

⎞ ⎜

⎝

⎛ ⋅ ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ =⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

bbl

lb Emission Factor

yr

bbl Annual Uncontrolled Throughput

yr

lb Uncontrolled Emissions

( )

⎟

⎠

⎞ ⎜

⎝

⎛ ⋅ ⎟

⎟

⎠

⎞

⎜

⎜

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⎛

+

⎟⋅ − ⎠

⎞ ⎜

⎝

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⎟

⎠

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⎜

⎜

⎝

⎛ =⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

bbl

lb Emission Factor

yr

bbl Annual Uncontrolled Throughput

Control Effciency bbl

lb Emission Factor

yr

bbl Annual Controlled Throughput

yr

lb Controlled Emissions 1

⎟

⎠

⎞ ⎜

⎝

⎛

⋅ ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ ⎟⋅

⎠

⎞ ⎜

⎝

⎛ =⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

lb

ton

yr

MMBtu Flash Gas

MMBtu

lb Emission Factor

yr

ton NOx CO

2000

1 &

⎟

⎠

⎞ ⎜

⎝

⎛ ⎟⋅

⎠

⎞ ⎜

⎝

⎛ ⎟⋅

⎠

⎞ ⎜

⎝

⎛ ⎟⋅

⎠

⎞ ⎜

⎝

⎛

− ⋅ ⎟

⎟

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⎜

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⎝

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⋅ ⎟

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⎜

⎝

⎛

=⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

Btu

MMBtu

SCF

Btu Heat Content

lb mol VOC

SCF Gas

ton Gas MW

lb

yr

ton Uncontrolled VOC

yr

MMBtu Flash Gas

6 10

1

%

2,000 1 379.41 1

⎟

⎠

⎞ ⎜

⎝

⎛

⋅ ⎟

⎟

⎠

⎞

⎜

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⎛ =⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

lb

ton

yr

lb Emissions

yr

tons VOC Emissions

2,000

1

Lesair Environmental, Inc.

www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Flash Gas Flash Gas

(lb/h) (lb/bbl)

Methane 0.071 0.172

Ethane 0.732 1.756

Propane 2.233 5.359

i-Butane 0.454 1.091

n-Butane 1.447 3.472

Neo-Pentane 0.000 0.000

i-Pentane 0.268 0.644

n-Pentane 0.329 0.790

2-2-Dimethylbutane 0.001 0.001

2-3-Dimethylbutane 0.013 0.032

2-Methylpentane 0.042 0.100

3-Methylpentane 0.027 0.065

n-Hexane 0.044 0.104

n-Heptane 0.055 0.131

n-Octane 0.021 0.050

n-Nonane 0.003 0.008

n-Decane 0.008 0.018

Nitrogen 0.001 0.003

Carbon Dioxide 0.015 0.036

Benzene 0.001 0.003

T louene 0.002 0.004 0 002 0 004

Ethylbenzene 0.001 0.002

m-Xylene 0.001 0.002

Total mass Flow 5.769 13.845

Total VOC 4.949 11.878

Total HAP 0.048 0.116

Total Methane 0.071 0.172

Total CO2 0.015 0.036

Flash Gas values based on a BRE ProMax output using representative liquid analysis from the

Rupple 1-4H-150-90 using an average of 10 BOPD, or 3650 BOPY
This section of the document has been redacted because it 

contains copyrighted information. The redacted information 

can be viewed from the hard copy of the docket, which is 

available at the EPA Region 8 Office upon request. 
Company Name: QEP Energy Company

Facility Name: 13-24G 

Well No. 1 Well No. 2 Well No. 3 Well No. 4 Total Pad Production

Month # Oil (bbl) Gas (mcf) Oil (bbl) Gas (mcf) Oil (bbl) Gas (mcf) Oil (bbl) Gas (mcf) Oil (bbl) Gas (mcf)

1 13,805 8,283 13,805 8,283 13,805 8,283 13,805 8,283 55,221 33,133

2 9,505 5,703 9,505 5,703 9,505 5,703 9,505 5,703 38,020 22,8123 7,726 4,636 7,726 4,636 7,726 4,636 7,726 4,636 30,904 18,5424 6,681 4,008 6,681 4,008 6,681 4,008 6,681 4,008 26,722 16,0335 5,971 3,583 5,971 3,583 5,971 3,583 5,971 3,583 23,884 14,3306 5,449 3,269 5,449 3,269 5,449 3,269 5,449 3,269 21,795 13,0777 5,043 3,026 5,043 3,026 5,043 3,026 5,043 3,026 20,173 12,1048 4,717 2,830 4,717 2,830 4,717 2,830 4,717 2,830 18,868 11,3219 4,447 2,668 4,447 2,668 4,447 2,668 4,447 2,668 17,787 10,672

10 4,218 2,531 4,218 2,531 4,218 2,531 4,218 2,531 16,873 10,12411 4,022 2,413 4,022 2,413 4,022 2,413 4,022 2,413 16,087 9,65212 3,850 2,310 3,850 2,310 3,850 2,310 3,850 2,310 15,401 9,241

Total 75,433 75,433 75,433 75,433 301,733 181,040BOPD 206.67 206.67 206.67 206.67

Estimate Annual Production
Company Name: QEP Energy Company

Facility Name: 13-24G 

Enclosed Flare Emission Analysis Worksheet

(Based on Office of Air Quality Planning and Standards, EPA, AP-42 Manual, Fifth Edition, January 1995, Section 13.5)

Source with vapors sent to the 

Combustion Chamber

Vapor Volume 

(MSCFD)

Vapor 

Heating 

Value 

(Btu/scf)

H2S 

Content 

(%)

Nox

(lb/hr)

NOx 

(TPY)

CO

(lb/hr)

CO

(TPY)

SO2 

(lb/hr)

SO2

(TPY)

VOC 

(lb/hr)

VOC

(TPY)

HAPs

(lb/hr)

HAPs

(TPY)

Casing head Gas 496 1438 0 4.10 17.96 8.19 35.9 0.00 0.00 14.94 65.45 0.35 1.52Condensate Tank Vapors 93 2443 0 1.30 5.71 2.60 11.4 0.00 0.00 8.18 35.84 0.08 0.35Pilot Gas 0.6 1438 0 0.00 0.02 0.01 0.0 0.00 0.00 0.02 0.08 0.00 0.00

Total 589 5.41 23.69 10.80 47.30 0.00 0.00 23.14 101.37 0.43 1.88

NOTES: 1 - Condensate vapors are based on 112.2 SCF/bbl from BR&E ProMax simulation from a representative liquid analysis (Rupple).

2 - Enclosed flare or Utility Flare VOC emissions based on 98% destruction efficiency of the control equipment.3 - NOx and CO emission factors were taken from Table 4 of the Texas Natural Resource Conservation Commission's (TNRCC)  "Air Permit Technical Guidance for Chemical Sources - Flares and Vapor Oxidizers" document. The waste gas stream is assumed to be high-Btu (> 1,000 Btu/scf).

Pilot Gas 

(SCF/hr) (hrs/day)

Pilot Gas 

(SCFD)

25 24 600

Lesair Environmental, Inc.www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Emission Calculation for Internal Combustion Sources

Diesel Engine Emission Claulations

(For Estimating Emissions, Using Emission Factors from EPA AP-42, Table 3.3-1)

Generator Data

Annual Fuel

I.D. Quantity Engine Equipment1 Op Time Type

No. (Hp) (hours)

006 1 400 Portable Generator 8760 Diesel

1 - Portable diesel (Dual Fueled, Tier II) engine driven generators are trailer mounted, they are accounted for as it is 

 unknown when utility power will become available.

Emission Factors

Reference Generator

No. HP NOx CO SO2 PM TOC 2 VOC 3 CO2

(g/hp-hr) (g/hp-hr) (g/hp-hr) (g/hp-hr) (g/hp-hr) (g/hp-hr) (g/hp-hr)

006 400 4.800 2.600 0.931 0.150 1.000 1.000 522.100

Tier II Tier II AP-42 Tier II Tier II Tier II AP-42

2- Total Organic Compunds (TOC)

3 - VOC emission factor determined by using worst case TOC factor.

4 - SO2 and CO2 emission factors are from AP-42 Table 3.3-1, all other emission factors are based on EPA Tier II Emissions Standards.

Emissions (Lb/Hr) = E.F. (g/hp-hr)*(1lb/454g) * Horsepower

Emissions (TPY) = Emissions (Lb/Hr) * Annual Operating Time (Hr/Yr) * 1 ton/2,000 Lb

Reference

No.

(Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY)

006 4.23 18.52 2.29 10.03 0.82 3.59 0.13 0.58 0.88 3.86 460.00 2014.80

Emission Factors

Source Emissions

CO2

EF Source

Source Emissions

NOx CO SO2 PM VOC

TOTAL 4.23 18.52 2.29 10.03 0.82 3.59 0.13 0.58 0.88 3.86 460.00 2014.80

Lesair Environmental, Inc.

www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Emission Calculation for External Combustion Sources

AP-42 Calculation Method

(For Estimating Emissions, Using Emission Factors from EPA AP-42, Table 1.4-1 and Table 1.4-2)

Burner Data

Burner Annual Fuel Fuel Htg Fraction

I.D. QTY Rating Equipment Op Time Type Value of

No. (MMBtu/Hr) (hours) (Btu/scf) VOC 1

004 1 0.500 Heater Treater 8760 Field 1440 0.47

005 1 0.500 Heater Treater 8760 Field 1440 0.47

1 - Fraction of VOC is derived from the fuel gas analysis (MWVOC/MWTOTAL)

Emission Factors

Reference Burner

No. Rating NOx CO SO2 PM TOC 2 VOC 3 CO2

(MMBtu/Hr) (Lb/MMFt3

) (Lb/MMFt3) (Lb/MMFt3) (Lb/MMFt3) (Lb/MMFt3) (Lb/MMFt3) (Lb/MMFt3)

004 0.500 100.0 84.0 0.6 7.6 11.0 5.1 120000.0

005 0.500 100.0 84.0 0.6 7.6 11.0 5.1 120000.0

AP-42 AP-42 AP-42 AP-42 AP-42 Estimate AP-42

2- Total Organic Compunds (TOC)

3 - VOC emission factor determined by taking TOC factor times fraction of fuel gas that was VOC.

Emissions (Lb/Hr) = E.F. (Lb/MMft3) * FHV/1020 * Burner Rating (MMbtu/Hr) * 1/1020 (btu/scf) * 1 MMft3/1x106 ft3 * 1x106 Btu/MMbtu

Emissions (TPY) = Emissions (Lb/Hr) * Annual Operating Time (Hr/Yr) * 1 ton/2,000 Lb

Reference

No.

(Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY)

CO2

Emission Factors

EF Source

NOx CO SO2 PM VOC

Source Emissions

Source Emissions

(Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY) (Lb/Hr) (TPY)

004 0.07 0.30 0.06 0.25 0.00 0.00 0.01 0.02 0.00 0.02 83.04 363.74

005 0.07 0.30 0.06 0.25 0.00 0.00 0.01 0.02 0.00 0.02 83.04 363.74

TOTAL 0.14 0.61 0.12 0.51 0.00 0.00 0.01 0.05 0.01 0.03 166.09 727.47

Lesair Environmental, Inc.

www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Fugitives Emission Calculation

Equipment Service Category

Component Type Gas Heavy Oil3 Light Oil Water/Light Oil2

(<20 API Gravity) (>20 API Gravity)

(lbs/hr/component) (lbs/hr/component) (lbs/hr/component) (lbs/hr/component)

Connectors 2.00E-04 7.50E-06 2.10E-04 1.10E-04

Flanges 3.90E-04 3.90E-07 1.10E-04 2.90E-06

Open-ended Lines 2.00E-03 1.40E-04 1.40E-03 2.50E-04

Pumps 2.40E-03 0.00E+00 1.30E-02 2.40E-05

Valves 4.50E-03 8.40E-06 2.50E-03 9.80E-05

Other1 8.80E-03 3.20E-05 7.50E-03 1.40E-02

* - All factors are for total organic compound emission rates (includes non-VOC's such as methane and ethane).

1 - "Other" equipment type includes compressors, pressure relief valves, relief valves, diaphrams, drains,

dump arms, hatches, instruments, meters, polished rods and vents.

2 - Water/Light Oil factors apply to water streams in oil service with a water content greater than 50% to 99%

For streams with water content greater than 99%, the emission rate is considered negligable.

3 - The emission factor for pumps was not derived in the actual protocol, the factor for "other" has been

substituted for completeness.

INPUTS:

1. List the quantity of each type of component in each type of service at the applicant's facility:

Equipment Service Category

Component Type Gas Heavy Oil Light Oil Water/Light Oil

(<20 API Gravity) (>20 API Gravity)

Connectors 797 0 286 0

Flanges 17 0 4 0

Open-ended Lines 12 0 4 0

Pumps 000 0

Valves 110 0 58 0

Other 000 0

NOTE: This component count is based on estimates of counts at similar facilitie

Equipment Leak Emission Estimates for Oil and Gas Production Operations

(Emission Factors Derived From Table 2-4, EPA-453/R-95-017, "Protocol for Equipment Leak emission Estimates", November 1995)

 This component count is based on estimates of counts at similar facilitie

Sample Calculation:

TOC (TPY) = component quantity * component factor * 8,760 hr/yr * 1 ton/2,000 lb.s

VOC (TPY) = TOC * VOC Fraction from gas analysis (wt%)

Equipment Service Category

Component Type Gas Heavy Oil Light Oil Water/Light Oil

(<20 API Gravity) (>20 API Gravity)

(TPY of TOC) (TPY of TOC) (TPY of TOC) (TPY of TOC)

Connectors 0.698172 0.000000 0.263063 0.000000

Flanges 0.029039 0.000000 0.001927 0.000000

Open-ended Lines 0.105120 0.000000 0.024528 0.000000

Pumps 0.000000 0.000000 0.000000 0.000000

Valves 2.168100 0.000000 0.635100 0.000000

Other 0.000000 0.000000 0.000000 0.000000

TOTAL 3.000431 0.000000 0.924618 0.000000

Weight VOC Fraction 0.4670 0.00 1.00 1.00

Weight Benzene Fraction 0.0001 0.00 0.033 0.033

Weight Toluene Fraction 0.0001 0.00 0.033 0.033

Weight Ethylbenzene Fraction 0.0000 0.00 0.033 0.033

Weight Xylenes Fraction 0.0000 0.00 0.033 0.033

Weight n-Hexane Fraction 0.0004 0.00 0.033 0.033

TPY VOC 1.40 0.00 0.92 0.00

lb/yrs VOC 2802.15 0.00 1849.24 0.00

TPY Benzene 0.00 0.00 0.03 0.00

lb/yrs Benzene 0.43 0.00 61.02 0.00

TPY Toluene 0.00 0.00 0.03 0.00

lb/yrs Toluene 0.44 0.00 61.02 0.00

TPY Ethylbenzene 0.00 0.00 0.03 0.00

lb/yrs Ethylbenzene 0.02 0.00 61.02 0.00

TPY Xylenes 0.00 0.00 0.03 0.00

lb/yrs Xylenes 0.13 0.00 61.02 0.00

TPY n-Hexane 0.00 0.00 0.03 0.00

lb/yrs n-Hexane 2.13 0.00 61.02 0.00

(lb/yr) (TPY) (lb/yr) (TPY) Source VOC Total HAPs Lesair Environmental, Inc.

www.lesair.com (lb/yr) (TPY) (lb/yr) (TPY)

Fugitives 4651.39 2.33 308.28 0.15
Company Name: QEP Energy Company

Facility Name: 13-24G 

LL= 12.46 * S P M /T

LL = Loading loss (Lb/1,000 gal.), of liquid loaded

S = Saturation factor (from AP-42 Table 5.2-1)

P = True vapor pressure of liquid loaded (psia), (from AP-42 Figure 7.1-13a)

M = Molecular weight of vapors (Lb/Lb-mole), (from composition of vapor phase as per Tanks 4.0.9d)

T = Temperature of liquid loaded (°R = 460 + °F) (Annual Average Temperature)

S= 0.6 (For dedicated Hydrocarbon service, submerged loading)

P= 7.25 True Vapor Pressure (psia) @ T=60 for a RVP=10 fluid

M= 50 Lb/Lb-mole (Crude Oil RVP=5 Tanks 4.0.9d fluid properties)

T= 60 °F or 520 °R

LL= 5.2116 Lb/1,000 gal. Loaded

-For a facility making: 301,730 bbl/yr or 826.66 bbl/day

LL (TPY) = LL (Lb/1,000 gal) * annual production (bbl/yr) * 42 gal/bbl * 1ton/2000Lbs

Truck Loadout Emissions = 33.02 TPY of VOC

LL (lb/hr) = LL (Lb/1,000 gal) * 200 bbl tank truck * 42 gal/bbl * 1 hr loadout duration

Truck Loadout Emissions = 43.78 lb/hr of VOC

LL (lb/ ) B LL (TPY) VOC * 2000 (t /lb ) / (13 7 (lb/bbl) / 0 024 (lb/bbl))

PTE Volatile Organic Compound Emission Calculation for Truck Loading

Lesair Environmental, Inc.

www.lesair.com

LL (lb/yr) Benzene= LL (TPY) VOC * 2000 (ton/lbs) / (13.7 (lb/bbl) / 0.024 (lb/bbl))

LL (lb/yr) n-Hexane = LL (TPY) VOC * 2000 (ton/lbs) / (13.7 (lb/bbl) / 0.21 (lb/bbl))

Truck Loadout Emissions = 115.70 lb/yr of Benzene

Truck Loadout Emissions = 1012.37 lb/yr of n-Hexane

Lesair Environmental, Inc.

www.lesair.com
Company Name: QEP Energy Company

Facility Name: 13-24G 

Gas Analysis Calculation Sheet

Based on: Rupple 1-4 H-150-90

LHV HHV

BTU Content BTU Content

Component Mole % Mole Frac. Lb/Lb mole MW VOC HAP Btu/scf Btu/scf*Mole Frac Btu/scf Btu/scf*Mole Frac

Helium 0.000 0.0000 4.00 0.00 0.0 0.00 0.0 0.00

Nitrogen 8.530 0.0853 28.02 2.39 0.0 0.00 0.0 0.00

Other Inerts 0.003 0.0000 30.00 0.00 0.0 0.00 0.0 0.00

Carbon Dioxide 0.090 0.0009 44.01 0.04 0.0 0.00 0.0 0.00

Methane 46.408 0.4641 16.04 7.44 909.4 422.04 1010.0 468.72

Ethane 19.230 0.1923 30.07 5.78 1618.7 311.28 1769.6 340.30

Propane 15.387 0.1539 44.09 6.78 6.78 2314.9 356.18 2516.1 387.14

Isobutane 1.805 0.0180 58.12 1.05 1.05 3000.4 54.15 3251.9 58.68

n-butane 5.115 0.0512 58.12 2.97 2.97 3010.8 154.01 3262.3 166.87

Isopentane 0.965 0.0097 72.15 0.70 0.70 3699.0 35.70 4000.9 38.61

n-pentane 1.210 0.0121 72.15 0.87 0.87 3706.9 44.86 4008.9 48.51

Cyclopentane 0.000 0.0000 70.08 0.00 0.00 3512.2 0.00 3763.4 0.00 y p

n-Hexane 0.248 0.0025 86.18 0.21 0.21 0.21 4404.1 10.94 4750.2 11.80

Cyclohexane 0.027 0.0003 84.18 0.02 0.02 4179.9 1.11 4481.2 1.19

Other Hexanes 0.464 0.0046 86.18 0.40 0.40 4392.7 20.40 4744.5 22.03

Heptanes 0.315 0.0032 100.21 0.32 0.32 5100.3 16.08 5500.4 17.34

Methylcyclohexane 0.026 0.0003 98.19 0.03 0.03 4863.9 1.25 5215.7 1.34

2,2,4 Trimethylpentane 0.070 0.0007 114.22 0.08 0.08 0.08 5779.1 4.05 6231.5 4.37

Benzene 0.011 0.0001 78.11 0.01 0.01 0.01 3591.1 0.39 3741.5 0.40

Toluene 0.011 0.0001 92.14 0.01 0.01 0.01 4273.7 0.48 4474.5 0.51

Ethylbenzene 0.002 0.0000 106.17 0.00 0.00 0.00 4970.7 0.09 5221.7 0.10

Xylenes 0.004 0.0000 106.17 0.00 0.00 0.00 4957.4 0.19 5208.4 0.20

C8+ Heavies 0.082 0.0008 315.00 0.26 0.26 5796.3 4.75 5794.1 4.75

Totals 100.00 1.0000 29.3727 13.7158 0.3191 1437.94 1572.86

Fraction of Vapors that are VOC: 0.4670 Fraction of Vapors that are Benzene: 0.0001Fraction of Vapors that are HAP: 0.0109 Fraction of Vapors that are Toluene: 0.0001Gas Specific Gravity: 1.0139 Fraction of Vapors that are Ethylbenzene: 0.0000

Fraction of Vapors that are Xylenes: 0.0000

Fraction of Vapors that are n-Hexane: 0.0004

Lesair Environmental, Inc.www.lesair.com
 QUESTAR APPLIED TECHNOLOGY

1210 D. Street, Rock Springs, Wyoming 82901

(307) 352-7292

LIMS ID: N/A Description: Rupple 1-4 H-150-90

Analysis Date/Time: 8/31/2011 1:47 PM Field: Ft. Berthold

Analyst Initials: PRP ML#: QEP / 8654

Instrument ID: Instrument 1 GC Method: Quesbtex

Data File: QPC89.D

Date Sampled: 8/23/2011

Component Mol% Wt% LV%

Methane 46.4083 25.5070 36.1847

Ethane 19.2301 19.8106 23.7217

Propane 15.3866 23.2452 19.5149

Isobutane 1.8046 3.5935 2.7172

n-Butane 5.1151 10.1855 7.4226

Neopentane 0.0035 0.0088 0.0063

Isopentane 0.9616 2.3770 1.6201

n-Pentane 1.2101 2.9912 2.0173

2,2-Dimethylbutane 0.0031 0.0092 0.0060

2,3-Dimethylbutane 0.0687 0.2027 0.1295

2-Methylpentane 0.2398 0.7081 0.4581

3-Methylpentane 0.1528 0.4511 0.2869

n-Hexane 0.2484 0.7335 0.4701

Heptanes 0.4596 1.5071 0.8694

Octanes 0.0677 0.2628 0.1524

Nonanes Nonanes 0 0185 . 0 0773 . 0 0435 .

Decanes plus 0.0015 0.0074 0.0043

Nitrogen 8.5304 8.1869 4.3047

Carbon Dioxide 0.0896 0.1351 0.0703

Oxygen 0.0000 0.0000 0.0000

Hydrogen Sulfide 0.0000 0.0000 0.0000

Total 100.0000 100.0000 100.0000

Global Properties Units

Gross BTU/Real CF 1586.1 BTU/SCF at 60°F and14.73 psia

Sat.Gross BTU/Real CF 1560.0 BTU/SCF at 60°F and14.73 psia

Gas Compressibility (Z) 0.9933

Specific Gravity 1.0095 air=1

Avg Molecular Weight 29.189 gm/mole

Propane GPM 4.216893 gal/MCF

Butane GPM 2.197498 gal/MCF

Gasoline GPM 1.246112 gal/MCF

26# Gasoline GPM 2.855964 gal/MCF

Total GPM 7.661883 gal/MCF

Base Mol% 97.801 %v/v

Sample Temperature: 68 °F

Sample Pressure: 20 psig

H2SLength of Stain Tube N/A ppm
Component Mol% Wt% LV%

Benzene 0.0108 0.0290 0.0139

Toluene 0.0113 0.0358 0.0175

Ethylbenzene 0.0019 0.0070 0.0034

M&P Xylene 0.0033 0.0122 0.0060

O-Xylene 0.0006 0.0022 0.0010

2,2,4-Trimethylpentane 0.0701 0.2743 0.1621

Cyclopentane 0.0000 0.0000 0.0000

Cyclohexane 0.0265 0.0763 0.0415

Methylcyclohexane 0.0257 0.0863 0.0475

Description: Rupple 1-4 H-150-90

GRI GlyCalc Information

Component Mol% Wt% LV%

Carbon Dioxide 0.0896 0.1351 0.0703

Hydrogen Sulfide 0 0.0000 0.0000

Nitrogen 8.5304 8.1869 4.3047

Methane 46.4083 25.5070 36.1847

Ethane 19.2301 19.8106 23.7217

Propane 15.3866 23.2452 19.5149

Isobutane 1.8046 3.5935 2.7172

n-Butane 5.1151 10.1855 7.4226

Isopentane 0.9651 2.3858 1.6264

n-Pentane 1.2101 2.9912 2.0173 e ta e 0 99 0 3

Cyclopentane 0 0.0000 0.0000

n-Hexane 0.2484 0.7335 0.4701

Cyclohexane 0.0265 0.0763 0.0415

Other Hexanes 0.4644 1.3711 0.8805

Heptanes 0.3152 1.0054 0.5869

Methylcyclohexane 0.0257 0.0863 0.0475

2,2,4 Trimethylpentane 0.0701 0.2743 0.1621

Benzene 0.0108 0.0290 0.0139

Toluene 0.0113 0.0358 0.0175

Ethylbenzene 0.0019 0.0070 0.0034

Xylenes 0.0039 0.0144 0.0070

C8+ Heavies 0.0819 0.3261 0.1898

Subtotal 100.0000 100.0000 100.0000

Oxygen 0 0.0000 0.0000

Total 100.0000 100.0000 100.0000
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.5

Other Requested Data

1. Field natural gas is used as fuel for the burners associated with the vertical heater

treaters. The quanitity of natural gas used varies due to fuel consumption being

regulated by a thermostat.

2. This facility typically operates 24 hours per day, 7 days a week, 52 weeks a year.

3. The only emission control anticipated for use at this facility is an enclosed flare or 

utility flare.

4. Air dispersion modeling is not being supplied with this application. This facility

is located in an attainment area, in an undeveloped area of the Fort Berthold

Reservation. The potential impacts from this facility should not require air

dispersion modeling.
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment D.6

Evaluation of ESA and NHPA
ATTACHMENT D.6

Endangered Species Act/EA/NHPA Information for

Permit Application 13‐24G   

Permission was acquired to survey the site from the allottees and BIA and the required NEPA/EA

Process commenced.  Environmental on‐site surveys are currently being performed (BIA, Site survey,

Biology, Archeology, Tribal historic preservation, Company Rep.) for AVOID, MOVE, and MITIGATE

consideration.   The environmental on‐site survey phase is estimated to be completed by May 2012.

   

After the above surveys/studies are completed, the Third Party consultant (TP) will submit the

Solicitation of View (SOV) letter to all affected Agencies, at which time the 30‐day SOV comment

period will begin.   

After the 30‐day SOV comment period closes, the TP submits a draft EA to the BIA, taking into

account comments received during the SOV period.  The BIA Regional Office will review the Draft EA

and SOV comment letters, and recommend any required revisions of the EA to the TP.  If any and all

issues raised during the SOV/draft EA process are resolved, a FONSI will be issued and signed by BIA,

after which the 30‐day public scoping period for the FONSI begins.    

   

If no unresolved issues are raised during the 30‐day public scoping period, and if all the allottee

signatures are in place, BIA will approve and transmit the FONSI to the permittee.  

No permits from BIA and/or BLM will be issued and no disturbance or development of the

referenced facility can commence until all steps in the above process are completed, a FONSI is

issued, and all related approvals are obtained from BLM/BIA.     

/S2
Company Name: QEP Energy Company

Facility Name: 13-24G 

Attachment E

Facility Emissions Summary
E. TABLE OF ESTIMATED EMISSIONS 

The following tables provide the total emissions in tons/year for all pollutants from the calculations 

required in Section D of this form, as appropriate for the use specified at the top of the form. 

E(i) – Proposed New Facility 

Pollutant Potential Emissions 

 (tpy) 

Proposed Allowable 

Emissions 

 (tpy) 

PM - Particulate Matter 

PM10 - Particulate Matter less 

than 10 microns in size 

PM2.5 - Particulate Matter less 

than 2.5 microns in size 

SOx - Sulfur Oxides 

NOx - Nitrogen Oxides 

CO - Carbon Monoxide 

VOC - Volatile Organic 

Compound 

Pb - Lead and lead compounds 

Fluorides - Gaseous and 

particulates 

H2SO4 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur 

Compounds

PM 0.62 0.62 

PM10 0.62 0.62 

PM 2.5 0.62 0.62 

SOx 3.60 3.60 

NOx 19.13 42.82 

CO 10.54 57.84 

VOC 5103.3 140.29 

Pb 0.0 0.0 

Fluorides 0.0 0.0 

H2SO4 0.0 0.0 

H2S 0.0 0.0 

TRS 0.0 0.0 

RSC 0.0 0.0 

Emissions calculations must include fugitive emissions if the source is one the following listed 

sources, pursuant to CAA Section 302(j): 

(a) Coal cleaning plants (with thermal dryers); 

(b) Kraft pulp mills; 

(c) Portland cement plants; 

(d) Primary zinc smelters; 

(e) Iron and steel mills; 

(f) Primary aluminum ore reduction plants; 

(g) Primary copper smelters; 

(h) Municipal incinerators capable of charging more than 

250 tons of refuse per day; 

(i) Hydrofluoric, sulfuric, or nitric acid plants; 

(j) Petroleum refineries; 

(k) Lime plants; 

(l) Phosphate rock processing plants; 

(m) Coke oven batteries; 

(n) Sulfur recovery plants; 

(o) Carbon black plants (furnace process); 

(p) Primary lead smelters; 

(q) Fuel conversion plants; 

(r) Sintering plants; 

(s) Secondary metal production plants; 

(t) Chemical process plants 

(u) Fossil-fuel boilers (or combination thereof) totaling 

more than 250 million British thermal units per hour 

heat input; 

(v) Petroleum storage and transfer units with a total 

storage capacity exceeding 300,000 barrels; 

(w) Taconite ore processing plants; 

(x) Glass fiber processing plants; 

(y) Charcoal production plants; 

(z) Fossil fuel-fired steam electric plants of more that 

250 million British thermal units per hour heat input, 

and 

(aa) Any other stationary source category which, as of 

August 7, 1980, is being regulated under section 111 or 

112 of the Act.
E(ii) – Proposed New Construction at an Existing Facility or Modification of an Existing Facility 

Pollutant Current 

Actual 

Emissions 

(tpy) 

Current 

Allowable 

Emissions 

(tpy) 

Post-Change 

Potential 

Emissions 

(tpy) 

Post-Change 

Allowable 

Emissions 

(tpy) 

PM 

PM10 

PM 2.5 

SOx 

NOx

CO 

VOC 

Pb 

NH3

Fluorides 

H2SO4

H2S 

TRS 

RSC 

PM - Particulate Matter 

PM10 - Particulate Matter less than 10 microns in size 

PM2.5 - Particulate Matter less than 2.5 microns in size 

SOx - Sulfur Oxides 

NOx - Nitrogen Oxides 

CO - Carbon Monoxide 

VOC - Volatile Organic Compound 

Pb - Lead and lead compounds 

NH3 - Ammonia 

Fluorides - Gaseous and particulates 

H2SO4 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur Compounds 
End of Facility 13-24G Application