### Via e

- mail to: r8airpermitting@epa.gov

December 29

, 2011

US Environmental P rotection 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 : 1 2

- 4E 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 above

referenced facility.

This facility is listed in A dministrative C omplaint and C onsent A greem ent (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. QEP E 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.

Sin cerely,


# Daniel Ryan

Daniel Ryan Sr. Environmental Engineer

Cc: Randy Judge

M att 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 ENVIRONMEN TAL PROTECTION AGENCY Region 8 Air Program

FEDERAL MINOR NEW SOURCE REVI EW PROGRAM IN INDIAN COUNTRY



## Check List – Application for New Construction (Form NEW)
Please check all that apply to sh ow 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 Ma nagement 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 unde r 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



## 12-4E

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*


## 47.75083 11b. Longitude*


## -102.34121

12a. Quarter Quarter Section 

### *


## NWNW 12b. Section*


## 4 12c. Township*


## 149N 12d. Range*


## 91W

*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 shoul d 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 emissi on 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 produc t produced proposed to be used on a daily, annual and maximum hourly basis.

9 Proposed operating schedule, including number of hours pe r 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, PM 10 

### , PM 2.5 

### , 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 (H 2 

### SO 4 

### ), hydrogen sulfide (H 2 

### S), 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 Compan y Facility Name: 12-4E



## 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.

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

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 CO2 e
but greater than 250 TPY on a mass basis.

Prepared for: Prepared by:

QEP Energy Company Lesair Environmental, Inc.

www.Lesair.com

### UNITED STATES ENVIRONMEN TAL PROTECTION AGENCY Region 8 Air Program

FEDERAL MINOR NEW SOURCE REVI EW 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 Ma nagement 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. W hile submittal of this form is not required, it does offer details on the information we will use to complete your requested approva l 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/u pdated 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


## 12-4E

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, ha zardous 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 th e manufacturer specifications and guarantees.

9 Item 4 - Estimates of the Post-Change Allowable Emissions th at 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 Compan y Facility Name: 12-4E



# Attachment D.1 Part B

Additional Compliance Information

### 1 

## Attachment D.1.B to Application for Facility: _12-4E :

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

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 hour s 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 pe riod 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 s hall 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 th e 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 demons trate 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 S t o r a ge T a nk s

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 oper ate 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 emissi on for each emission source type (tanks, process devices, etc.) using the ratio of: actual production th roughput, operating hours, or other appropriate parameter, divided by the appropria te production parameter value used to calculate the estimated monthly emissions in the permit application. The emission ra tio 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 in itial 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 Clarifi cations” in a letter from the North Dakota Petroleum
Council to Mr. Jim Martin, EPA, dated December 7, 2011.

### Company Name: QEP Energy Compan y Facility Name: 12-4E



# 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.comQEP Energy Company

Fort Berthold

12-4E 

### Process Description

This is a multi-well facility t hat will separate producti on from four (4) proposed oil and natural gas exploration and production wells dr illed at this location. Each we ll 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, condens ate and produced water) flows

from each well. The well fluids flow to its res pective 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 (condensat e) and produced water flow to their respective storage

tanks.

The natural gas stream fr om the vertical heater treater is expected to be metered into a natural gas sales pipeline. If t he pipeline is not immediat ely available or if it becomes unavailable the natural gas will go to a utility flare.

From the condensate storage tan ks, 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 divert ed to one of the "divert" tanks wh ere it will be tr eated 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 pi pelines 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 pi ping 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 natu ral 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 moto r driven pumping unit, and other facility power

needs.

## N 12-4E Topographic Map

Questar Exploration & Production CO. Dunn County, North Dakota

Latitude: 47.7508N Longitude: -102.3412W

Drawn by: CAD

Date: November 2011 12-4E

### Company Name: QEP Energy Compan y Facility Name: 12-4E



# Attachment D.3

Proposed Equipment and Esitmated Emissions Summar y

Prepared for: Prepared by:

QEP Energy Company Lesair Environmental, Inc.

www.Lesair.comCompany Name:QEP Energy CompanyFacility Name:12-4ENOx CO SO2 ParticulatesVOC Total HAPsRef No. Equipment Note lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY001 (8) 400 bbl. Condensate Storage Tanks a 0.00 0.000.00 0.00 0.00 0.00 0.000.00 409.14 1792.05 4.01 17.55002 (4) 400 bbl. Divert Tanks b 0.00 0.00 0.000.00 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 0.00004 (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 0.580.88 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 0.00Total 4.37 19.13 2.41 10.54 0.82 3.60 0.14 0.62 1157.675103.62 21.39 94.26NOTES: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 notan emission source but the small amount of condensate thatcarries 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 gasburners (July 1998), the worst case assumptionthat 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 ProgramUncontrolled Production Equipment Emissionsh - 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.comCompany Name:QEP Energy CompanyFacility Name:12-4EEPA Region 8 Minor Source Permitting ProgramNOx CO SO2 ParticulatesVOC Total HAPsRef No. Equipment Note lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY001 (8) 400 bbl. Condensate Storage Tanks a 0.00 0.000.00 0.00 0.00 0.00 0.000.00 0.00 0.00 0.00 0.00002 (4) 400 bbl. Divert Tanks b 0.00 0.00 0.000.00 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 0.00004 (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 0.580.88 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 0.00009 Enclosed Flare or UtilityFlare i 5.41 23.69 10.80 47.30 0.000.00 0.00 0.00 23.14 101.37 0.43 1.88Total 9.78 42.82 13.21 57.84 0.82 3.60 0.14 0.62 24.56 140.61 0.43 2.44NOTES: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 condensatetank vent system and go to flare, these controlled emissionsare accounted for at source (010) "EnclosedFlare 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 gasburners (July 1998), the worst case assumptionthat 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 atsource (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 EmissionsGeneratorengineemissionsareestimatedusing400HpdieselfueledtierIIengineemissionfactors.Theseenginesaretrailermountedandareexpectedtobeportable.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: 12-4E

Methane CO2e f NO

x CO2e f 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 2369.93

002 (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 0.00

003 (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 0.00

004 (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 20886.07

005 (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 20886.07

006 (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 7757.04

008 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: 12-4E


# EPA Region 8 Minor Source Permitting Program

Methane CO2e f NO

x CO2e f 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 0.00

002 (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 0.00

003 (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 0.00

004 (1) 0.5 MMBtu/hr Heater Treater d 0.00 0.00 0.00 0.00 0.07 0.30 21.45 93.97 83.04 363.74 104.50 457.70

005 (1) 0.5 MMBtu/hr Heater Treater d 0.00 0.00 0.00 0.00 0.07 0.30 21.45 93.97 83.04 363.74 104.50 457.70

006 (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 7757.04

008 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

009 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 Compan y Facility Name: 12-4E



# 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: 12-4E



## Condensate Storage Tank Emissions Calculations

V OC, Benzene & n-Hexane Emissions

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

Production While Controls Operational: 301,730 Control Efficienc y : 98%

Production forecasts are based on the first year of production for similar wells in the area. Production decline was built int o 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 fac ilities pr oduction 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/ y r ) Total HAP ( TPY ) n-Hexane ( TPY ) Flash Gas ( MMBtu/ y r ) 1,792.0 17.6 15.8 82,709

VOC (ton/yr) Total HAP (TPY) n-Hexane (TPY) NOx (ton/yr) CO (ton/yr) Controlled Emissions Uncontrolled Emissions

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

35.8 0.4 0.3 5.71 11.39
*N

- h exane i s t h e l argest HAP

, i t i s use d to i n di cate potent i a l f or Ti t l e V app li ca bili ty.

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 fac ilities. (ton/yr)

⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

= ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

bbl lb Factor Emission
yr bbl Throughput ed Uncontroll Annual

yr lb Emissions ed Uncontroll



## ( )

⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

+ − ⋅ ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

= ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

bbl lb Factor Emission
yr bbl Throughput ed Uncontroll Annual Effciency Control bbl lb Factor Emission
yr bbl Throughput Controlled Annual

yr lb Emissions Controlled 1

⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

⋅ ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

= ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

lb ton

yr MMBtu Gas Flash MMBtu lb Factor Emission

yr ton CO NOx 2000 1 & ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

− ⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

⋅ ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛ =

⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

Btu MMBtu

SCF Btu Content Heat VOC mol lb Gas SCF

MW Gas ton lb

yr ton VOC ed Uncontroll yr MMBtu Gas Flash

6 10 1

% 1 41

. 379 1 000

, 2 ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

⋅ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

= ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

lb ton

yr lb Emissions
yr tons Emissions VOC 000

, 2 1



### Lesair Environmental, Inc.

www.lesair.com

### Company Name: QEP Energy Compan y Facility Name: 12-4E

Flash Gas Flash Gas (lb/h) (lb/bbl)

Methane 0.071 0.172

Ethane 0.732 1.756

Pro p ane 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-Dimeth y lbutane 0.001 0.001

2-3-Dimeth y lbutane 0.013 0.032

2-Meth y l p entane 0.042 0.100

3-Meth y l p entane 0.027 0.065

n-Hexane 0.044 0.104

n-He p tane 0.055 0.131

n-Octane 0.021 0.050

n-Nonane 0.003 0.008

n-Decane 0.008 0.018

Nitro g en 0.001 0.003

Carbon Dioxide 0.015 0.036

Benzene 0.001 0.003

Toluene 0.002 0.004

Eth y lbenzene 0.001 0.002

m-X y lene 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 CompanyFacility Name:12-4EWellNo.1 WellNo.2 WellNo.3 WellNo.4 TotalPadProductionMonth# Oil(bbl) Gas(mcf) Oil(bbl) Gas(mcf) Oil(bbl) Gas(mcf) Oil(bbl) Gas(mcf) Oil(bbl) Gas(mcf)113,8058,28313,8058,28313,8058,28313,8058,28355,22133,13329,5055,7039,5055,7039,5055,7039,5055,70338,02022,81237,7264,6367,7264,6367,7264,6367,7264,63630,90418,54246,6814,0086,6814,0086,6814,0086,6814,00826,72216,03355,9713,5835,9713,5835,9713,5835,9713,58323,88414,33065,4493,2695,4493,2695,4493,2695,4493,26921,79513,07775,0433,0265,0433,0265,0433,0265,0433,02620,17312,10484,7172,8304,7172,8304,7172,8304,7172,83018,86811,32194,4472,6684,4472,6684,4472,6684,4472,66817,78710,672104,2182,5314,2182,5314,2182,5314,2182,53116,87310,124114,0222,4134,0222,4134,0222,4134,0222,41316,0879,652123,8502,3103,8502,3103,8502,3103,8502,31015,4019,241Total75,43375,43375,43375,433301,733181,040BOPD 206.67206.67206.67206.67Estimate Annual ProductionCompany Name:QEP Energy CompanyFacility Name:12-4EEnclosed 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 theCombustion ChamberVapor Volume(MSCFD)VaporHeatingValue(Btu/scf)H2SContent(%)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 Gas496 1438 04.10 17.96 8.19 35.9 0.00 0.00 14.94 65.45 0.35 1.52Condensate Tank Vapors93 2443 01.30 5.71 2.60 11.4 0.00 0.00 8.18 35.84 0.08 0.35Pilot Gas0.6 1438 00.00 0.02 0.01 0.0 0.00 0.00 0.02 0.08 0.00 0.00Total 5895.41 23.69 10.80 47.30 0.00 0.00 23.14 101.37 0.43 1.88NOTES: 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 assumedto be high-Btu (> 1,000 Btu/scf).PilotGas(SCF/hr)(hrs/day)PilotGas(SCFD)25 24600Lesair Environmental, Inc.www.lesair.comCompany Name: QEP Energy Compan y Facility Name: 12-4E



### 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

A nnual Fuel

I.D. Quantity Engine Equipment 1 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 SO 2 PM TOC 2 VOC 3 CO 2 (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 A P-42 Tier II Tier II Tier II A P-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 Stan dards.

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

CO 2 EF Source



### Source Emissions

NOx CO SO 2 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.comCompany Name: QEP Energy Company Facility Name: 12-4E



### Emission Calculation for External Combustion Sources

A P-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. QT Y Rating Equipment Op Time Type V alue 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 fr om the fuel gas analysis (MW VOC /MW TOTAL )



### Emission Factors

Reference Burner

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

(MMBtu/Hr) (Lb/MMFt 3 ) (Lb/MMFt 3 ) (Lb/MMFt 3 ) (Lb/MMFt 3 ) (Lb/MMFt 3 ) (Lb/MMFt 3 ) (Lb/MMFt 3 )

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

A P-42 A P-42 A P-42 A P-42 A P-42 Estimate A P-42

2- Total Organic Compunds (TOC)
3 - VOC emission factor determined by taking TOC fa ctor 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/MM btu

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 SO 2 PM VOC Source Emissions 

### Source Emissions

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.comCompany Name: QEP Energy Compan y Facility Name: 12-4E 

### Fugitives Emission Calculation

Equipment Service Category
Component Type Gas Heavy Oil 3 Light Oil Water/Light Oil 2

(<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 Other 1 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 Categor y 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 esti mates of counts at similar facilitie Equipment Leak Emission Estimates fo r 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)

Sample Calculation:

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

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

Equipment Service Categor y 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)

F iti 4651 39 2 33 308 28 0 15 Source VOC Total HAPs Lesair Environmental, Inc.

www.lesair.com

F u giti ves 4651

. 39 2

. 33 308

. 28 0

. 15Company Name: QEP Energy Compan y Facility Name: 12-4E

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/y r or 826.66 bbl/day

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

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 duratio n

Truck Loadout Emissions = 43.78 lb/hr of VOC

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)) 

## PTE Volatile Organic Compound Emission Calculation for Truck Loading

Lesair Environmental, Inc.

www.lesair.com 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 Benzen e

Truck Loadout Emissions = 1012.37 lb/yr of n-Hexan e

Lesair Environmental, Inc.

www.lesair.comCompany Name:QEP Energy CompanyFacility Name:12-4EGas Analysis Calculation SheetBased on:Rupple 1-4 H-150-90LHVHHVBTU Content BTU ContentComponent Mole % Mole Frac.Lb/Lb moleMWVOC HAP Btu/scfBtu/scf*Mole FracBtu/scfBtu/scf*Mole FracHelium0.0000.0000 4.00 0.00 0.0 0.00 0.0 0.00Nitrogen8.5300.0853 28.02 2.39 0.0 0.00 0.0 0.00Other Inerts0.0030.0000 30.00 0.00 0.0 0.00 0.0 0.00Carbon Dioxide0.0900.0009 44.01 0.04 0.0 0.00 0.0 0.00Methane46.4080.4641 16.04 7.44 909.4 422.04 1010.0 468.72Ethane19.2300.1923 30.07 5.78 1618.7 311.28 1769.6 340.30Propane15.3870.1539 44.09 6.78 6.78 2314.9 356.18 2516.1 387.14Isobutane1.8050.0180 58.12 1.05 1.05 3000.4 54.15 3251.9 58.68n-butane5.1150.0512 58.12 2.97 2.97 3010.8 154.01 3262.3 166.87Isopentane0.9650.0097 72.15 0.70 0.70 3699.0 35.70 4000.9 38.61n-pentane1.2100.0121 72.15 0.87 0.87 3706.9 44.86 4008.9 48.51Cyclopentane0.0000.0000 70.08 0.00 0.00 3512.2 0.00 3763.4 0.00n-Hexane0 2480 002586 180 210 210 214404 110 944750 211 80n Hexane0.2480.002586.180.210.210.214404.110.944750.211.80Cyclohexane0.0270.0003 84.18 0.02 0.02 4179.9 1.11 4481.2 1.19Other Hexanes0.4640.0046 86.18 0.40 0.40 4392.7 20.40 4744.5 22.03Heptanes0.3150.0032 100.21 0.32 0.32 5100.3 16.08 5500.4 17.34Methylcyclohexane0.0260.0003 98.19 0.03 0.03 4863.9 1.25 5215.7 1.342,2,4 Trimethylpentane0.0700.0007 114.22 0.08 0.08 0.08 5779.1 4.05 6231.5 4.37Benzene0.0110.0001 78.11 0.01 0.01 0.01 3591.1 0.39 3741.5 0.40Toluene0.0110.0001 92.14 0.01 0.01 0.01 4273.7 0.48 4474.5 0.51Ethylbenzene0.0020.0000 106.17 0.00 0.00 0.00 4970.7 0.09 5221.7 0.10Xylenes0.0040.0000 106.17 0.00 0.00 0.00 4957.4 0.19 5208.4 0.20C8+ Heavies0.0820.0008 315.00 0.26 0.26 5796.3 4.75 5794.1 4.75Totals 100.00 1.0000 29.3727 13.7158 0.3191 1437.94 1572.86Fraction 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: 0.0000Fraction of Vapors that are Xylenes: 0.0000Fraction of Vapors that are n-Hexane: 0.0004Lesair 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

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

A nalyst Initials: PRP ML#: QEP / 8654
Instrument ID: Instrument 1 GC Method: Quesbte x 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-Methylpentan e 0.2398 0.7081 0.4581 3-Methylpentan e 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 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 Sulfid e 0.0000 0.0000 0.0000

Total 100 0000 100 0000 100 0000 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 Gravit y 1.0095 air=1

A vg 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 ppmComponent Mol% Wt% LV%

Benzene 0.0108 0.0290 0.0139

Toluene 0.0113 0.0358 0.0175 Ethylbenzen e 0.0019 0.0070 0.0034 M&P Xylen e 0.0033 0.0122 0.0060 O-Xylene 0.0006 0.0022 0.0010 2,2,4-Trimethylpentane 0.0701 0.2743 0.1621 Cyclopentan e 0.0000 0.0000 0.0000 Cyclohexan e 0.0265 0.0763 0.0415 Methylcyclohexan e 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 Sulfid e 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 Cyclopentan e 0 0.0000 0.0000

n-Hexane 0.2484 0.7335 0.4701 Cyclohexan e 0.0265 0.0763 0.0415

Other Hexanes 0.4644 1.3711 0.8805 Heptanes 0.3152 1.0054 0.5869

Meth y lc y clohexan e 0.0257 0.0863 0.0475 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 Ethylbenzen e 0.0019 0.0070 0.0034 Xylene s 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 Compan y Facility Name: 12-4E



# 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 Compan y Facility Name: 12-4E



# Attachment D.6

Evaluation of ESA and NHP A

## ATTACHMENT D.6

Endangered Species Act/EA/NHPA Information for

Permit Application 12

‐ 4E

Permission to survey the site has been requested from the allottees and BIA and the required NEPA/EA Process has commenced. Survey permission is anticipated to be granted during May 2012.

As soon as permission is granted, environmental on

‐ site surveys will be performed (BIA, Site survey, Biology, Archeology, Tribal historic preservation, Company Rep.) for AVOID, MOVE, and MITIGATE

consideration.

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 will submit 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. After 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 comment period for the FONSI begins.

If no unresolved issues are raised during the 30

‐ day public comment 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 of the site or construction of the

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

is transmitted to the permittee, and all related approvals are obtained from BLM/BIA.

/S1

### Company Name: QEP Energy Compan y Facility Name: 12-4E



# Attachment E

Facility Emission Summar y

### 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

PM 10 - Particulate Matter less

than 10 microns in size

PM 2.5 - 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

H 2 SO 4 - Sulfuric Acid Mist

H 2 S - Hydrogen Sulfide

TRS - Total Reduced Sulfur

RSC - Reduced Sulfur Compounds PM 

## 0.62 0.62

PM 10 

## 0.62 0.62

PM 2.5 

## 0.62 0.62

SO

x 

## 3.60 3.60

NO

x 

## 19.13 42.82

CO 

## 10.54 57.84

VOC 

## 5103.62 140.61

Pb 

## 0.0 0.0

Fluorides 

## 0.0 0.0

H 2 SO 4 

## 0.0 0.0

H 2 S 

## 0.0 0.0

TRS 

## 0.0 0.0

RSC 

## 0.0 0.0

Emissions calculations must include fugitive em issions 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 capa ble 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 plan ts (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 tr ansfer units with a total storage capacity exceed ing 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

PM 10

PM 2.5

SO

x

NO

x

CO

VOC

Pb

NH 3

Fluorides

H 2 SO 4

H 2 S

TRS

RSC

PM - Particulate Matter

PM 10 - Particulate Matter less than 10 microns in size

PM 2.5 - 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

NH 3 - Ammonia Fluorides - Gaseous and particulates

H 2 SO 4 - Sulfuric Acid Mist

H 2 S - Hydrogen Sulfide

TRS - Total Reduced Sulfur RSC - Reduced Sulfur Compounds

# End of Facility 1 2

- 4E Application