Marathon

Oil Company

3172 Highway 22 North

Dickinson, ND 58601

Telephone 701.456.7500

Facsimile 701.456.7525

September 30, 2011

SENT VIA OVERNIGHT MAIL

Minor NSR Permitting Coordinator

U.S. EPA, Region 8

1595 Wynkoop Avenue, 8P-AR

Denver, CO 80202-1129

RE: Oil and Gas Production Facility Application for New Construction 

Dear Ms. Paser:

Enclosed, for your review, is a completed Oil and Gas Production Facility Application for New 

Construction (Form NEW and Form SYNMIN), with attachments, for the Marathon Oil 

Company facility listed below. 

NDIC Permit Numbers Facility Name

 

TBD Maggie Old Dog USA 24-19H

Should you have any questions or if you need additional information, please contact me via 

telephone at 701-456-7515 or via email at jajehn@marathonoil.com .

Sincerely, MARATHON OIL COMPANY

John A. Jehn P.G.

Senior HES Professional

Bakken Asset, North American Production Operations

Cc: Joe Gillies Jr., Environmental Director

Environmental Division

204 W. Main

New Town, ND 58763-9404

Cc: Tex Hall, Chairman Three Affiliated Tribes

404 Frontage Road

New Town, ND 58763-9404






 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 9 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

 request approval and providing the information requested my 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 The Tribal Environmental Contact for the specific reservation:

 U.S. EPA, Region 8

 1595 Wynkoop Avenue, 8P-AR If you need assistance in identifying the appropriate Tribal

 Denver, CO 80202-1129 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 FACILTY INFORMATION

 1. (a) Company Name 2. Facility Name

 (b) Operator Name

 3. Type of Operation 4. Portable Source? Yes No

 5. Temporary Source? Yes No

 6. NAICS Code 7. SIC Code

 8. Physical Address (home base for portable sources)

 9. Reservation* 10. County* 11a. Latitude* 11b. Longitude*

 12a. Quarter Quarter Section * 12b. Section * 12c. Township* 12d. Range*

 *Provide all proposed locations of operation for portable sources

 Proposed Construction of a New Facility

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

 Proposed Construction of New Equipment at an Existing Facility

 Proposed Modification of an Existing Facility

Marathon Oil Company

Marathon Oil Company

Maggie Old Dog USA 24-19H

Oil and Gas Extraction

211111 1311

 3172 Hwy 22, Dickinson, North Dakota 58061

Fort Berthold McKenzie 47.791275 -102.632886

 18 or 19 150 93
 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

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

 Date of the Permit Action

 Facility Name on the Permit

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

 Date of the Permit Action

 Facility Name on the Permit

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

 Date of the Permit Action

 Facility Name on the Permit

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

 Date of the Permit Action

 Facility Name on the Permit

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

 Date of the Permit Action
 C. CONTACT INFORMATION

 Company Contact Title

 Mailing Address

 Email Address

 Telephone Number Facsimile Number

 Operator Contact (if different from company contact) Title

 Mailing Address

 Email Address

 Telephone Number Facsimile Number

 Facility Contact Title

 Mailing Address

 Email Address

 Telephone Number Facsimile Number

 Compliance Contact Title

 Mailing Address

 Email Address

 Telephone Number Facsimile Number

(701) 456-7500 (701) 456-7525

Curtis Ryland Operations Manager

 3172 Hwy 22, Dickinson, North Dakota 58061

cryland@marathonoil.com

Curtis Ryland Operations Manager

 3172 Hwy 22, Dickinson, North Dakota 58061

cryland@marathonoil.com

(701) 456-7500 (701) 456-7525

John Jehn Senior HES Professional

 3172 Hwy 22, Dickinson, North Dakota 58061

jajehn@marathonoil.com

(701) 456-7515 (701) 456-7525
 D. ATTACHMENTS

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

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

being requested.

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

process flow diagram to be submitted with this application.

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

equipment.

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

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

maximum hourly basis.

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

maximum hourly basis.

Proposed operationg schedule, including number of hours per day, number of days per week and number of weeks

per year.

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

each emission unit and air pollution generating activity.

Criteria Polluant Emissions - Estimates of Current Acutal 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, ammonia (NH3), fluorides (gaseous and particulate), 

sulfuric acid mist (H2SO4), hydrogran sulfide (H2S), total reduced sulfur (TRS) and reduced sulfur compounds,

including all calculations for the estimates.

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

Modeling - Air Quality Impact Analysis (AQIA)

ESA (Endangered Species Act)

NHPA (National Historic Preservation Act)
 E. TABLE OF ESTIMATED EMISSIONS

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

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

D(i) - Proposed New Facility

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); (r) Sintering plants;

(b) Kraft pulp mills; (s) Secondary metal production plants;

(c) Portland cement plants; (t) Chemical process plants;

(d) Primary zinc smelters; (u) Fossil-fuel boilers (or combination thereof) totaling

(e) Iron and steel mills; more than 250 million British thermal units per hour

(f) Primary aluminum ore reduction plants; heat input;

(g) Primary copper smelters; (v) Petroleum storage and transfer units with a total

(h) Municipal incinerators capable of charging more than storage capacity exceeding 300,000 barrels;

 250 tons of refuse per day; (w) Taconite ore processing plants;

(i) Hydrofluoric, sulfuric, or nitric acid plants; (x) Glass fiber processing plants;

(j) Petroleum refineries; (y) Charcoal production plants;

(k) Lime plants; (z) Fossil fuel-fired steam electric plants of more than

(l) Phosphate rock processing plants; 250 million British thermal units per hour heat input,

(m) Coke oven batteries; and

(n) Sulfur recovery plants; (aa) Any other stationary source category which, as of

(o) Carbon black plants (furnace process); August 7, 1980, is being regulated under section 111 or

(p) Primary lead smelters; 112 of the Act.

(q) Fuel conversion plants;

H2SO4

H2S

TRS

0.00

PM2.5

SOx

0.02

0.002

32.12

173.35

230*

0.00

0.00

0.00

0.00

0.00

0.002

32.12

173.35

0.00

0.00 0.00

0.00

0.00

10,219.14

0.00

0.00

RSC 0.00

 

 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 - Hydrogren Sulfide

 TRS - Total Reduced Sulfur

 RSC - Reduced Sulfur

 Compounds

0.02 0.02

0.02

0.02

NOx

CO

VOC

Pb

NH3

Fluorides

(tpy)

Proposed Allowable

Emissions

(tpy)

PM

PM10 0.02

Pollutant Potential Emissions

* Marathon Oil Company is requesting a facility-wide permit limit of 230 tpy for VOCs in this permit application. This limit will be 

demonstrated by initially limiting production to 1,400 barrels of oil per day, on an annualized daily average, until a gas sales line is installed and 

functional. At that time Marathon will notify EPA of the gas sales line availability, that routine treater gas flaring has ceased, and the 1,400 bopd 

production limit will no longer apply. With gas sales the facility PTE will most likely be below Title V limits. With gas sales, oil production 

rates will be kept below 2,200 bopd, on an annualized average. VOC emissions at those rates will remain below the 230 tpy permit limits as 

shown on the attached calculations.
D(ii) - Proposed New Construction at an Existing Facility or Modification of an Existing Facility

 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 - Hydrogren Sulfide

 TRS - Total Reduced Sulfur

 RSC - Reduced Sulfur Compounds

Post-Change

Actual Allowable Potential

Pollutant Current Current Post-Change

Allowable

Emissions Emissions Emissions Emissions

(tpy) (tpy) (tpy) (tpy)

H2S

TRS

RSC

SOx

NOx

CO

VOC

Pb

NH3

PM

PM10

PM2.5

Fluorides

H2SO4
FORM NEW Maggie Old Dog USA 24-19H

D. Attachments September 30, 2011

 FORM SYNMIN

See the attached form and associated attachments (Form SYNMIN).

 Narrative description of the proposed production processes.

1. The narrative description should follow the flow of the process flow diagram to be submitted with 

this application. This needs to be as comprehensive as possible to help in understanding the 

proposed facility and how it will be operated.

Maggie Old Dog USA 24-19H will be owned and operated by Marathon Oil Company and is located 

within McKenzie County, North Dakota. The facility will be an oil and gas production facility 

consisting of multiple wells, each well equipped with its dedicated heater treater, produced oil and 

produced water storage tanks, treater utility flare and an enclosed combustor for the tank vents. 

Produced natural gas at the site is believed to be sweet but historically could contain up to 14 parts per 

million of hydrogen sulfide (H2S). The process flow diagram for each individual well that makes up 

this facility is provided in Attachment 1 and is described as follows:

1. Emulsion (comprised of produced oil, natural gas, and produced water) produced from the 

production well casinghead (WELL HEAD) enters the 350,000 btu/hr Heater Treater 

(HEATER TREATER) for separation. The heater treater is equipped with a heater treater 

burner that is fueled by natural (field) gas to separate the produced water, produced oil and 

natural (field) gas.

2. Natural gas from the heater treater is either routed to the heater treater burner, or to an 

external flare (UPSET CONDITION GAS DESTRUCTION DEVICE) with an estimated 

destruction efficiency of 98% with a continuous automatic igniter is temporary. This flare is 

currently visually monitored. This flare also meets the flare velocity and gas btu requirements 

of 40 CFR 60.18.

3. Treater gas will only be flared temporarily until sales line installation is complete. Once the 

sale line installation is complete, natural gas from the heater treater will be routed directly to 

the sales line with 100% efficiency. The heater treater flare will remain in place, but will only 

be used in the event of an emergency upset condition. Attachment 3 to this application will 

include the revised maximum production rate for this facility upon connection of the sales line 

as a result of reduced admissions.

4. Produced oil from the heater treater is routed to approximately four (4) 400-barrel 

aboveground vertical fixed-roof produced oil storage tanks (OIL TANK), where it is stored 

prior to tanker truck loadout via submerged fill. The total number of tanks will vary and is 

dependent upon capacity required for each well. Emissions from working/breathing/flash 

losses from the produced oil tanks are routed to a combustor (GAS DESTRUCTION DEVICE) 

with an estimated efficiency of 98% with a continuous automatic igniter. The combustor is 

equipped with an internal thermocouple to detect the presence of a flame, control operating 

temperature, and to protect the combustor from potential overheating. In the event of 

overheating leading to a high temperature emergency shutdown, the tank vent gas is routed 

automatically to the treater utility flare until the combustor cools and is restarted. Emergency 

shutdowns and run times are communicated to the Marathon main office via a telemetry 

system.
FORM NEW Maggie Old Dog USA 24-19H

D. Attachments September 30, 2011

5. If additional separation is necessary to further treat the produced oil in storage to meet buyer 

specifications, one (1) electric 8-horsepower recirculation engine pump, with one (1) 8-

hoursepower re-circulating internal combustion engine (RICE) is used to re-circulate the 

produced oil from the tanks back to the heater treater. This engine does not have any emission 

control devices at this time, but good operating practices are utilized to minimize any excess 

emissions.

6. Produced water from the heater treater is routed to the one (1) 400-barrel aboveground vertical 

fixed-roof produced water storage tank (WATER TANK), where it is stored prior to tanker 

truck loadout. Emissions from the produced water tank are routed to the same combustor noted 

above.

2. The proposed operating schedule present in terms of hours per day, days per week, and weeks per 

year.

The proposed production facility will operate 24 hours per day, 7 days per week, 52 weeks per year for 

a total of 8,760 hours per year. Exceptions to this operating schedule may include, but are not limited 

to, emergency shutdowns due to weather conditions, scheduled maintenance, operation updates, and 

temporary shut-in if required.

3. A list of the type and quantity of fuels and/or raw materials used. Each fuel and raw material 

should be described in enough detail to indicate its basic chemical components.

Table 1 – Fuels and/or Raw Materials Used on Site

Fuel and/or Raw Material Site Use

Produced Oil

This site produces produced oil which is stored in the aforementioned 

storage tanks prior to being taken off site via tanker truck. Production 

volumes are shown on the attached calculation sheets.

Natural Gas

Natural gas that is produced with the oil is separated and flared. A 

portion of the gas (field gas) is used to fuel the burner for the heater 

treater; composition of field gas is included in analytical results of 

casinghead gas sampling included with this registration packet. 

Production volumes are shown on the attached calculation sheets.

Produced Water

Produced water associated with the production of oil and gas at this 

facility is separated from the hydrocarbon streams in the heater treater 

and routed to storage tanks prior to removal by tank truck.

 A process flow chart identifying all proposed processing, combustion, handling, storage, and 

emission control equipment (include the unit identification # or code). This flow chart should 

illustrate the detailed narrative description requested above.

See the attached process flow diagram (Attachment 1). The following-codes represent major pieces of 

equipment in the proposed facility:

Table 2 – Facility Equipment Codes and Descriptions

Process Flow Diagram 

Code Facility Equipment Description

WELL HEAD Location of the oil and gas well.
FORM NEW Maggie Old Dog USA 24-19H

D. Attachments September 30, 2011

HEATER TREATER Heater treater and 350,000 btu/hr heater treater burner.

OIL TANK Four (4) 400-bbl aboveground oil storage tank with a vertical fixed roof.*

WATER TANK One (1) 400-bbl aboveground water storage tank with a vertical fixed roof.

RICE One (1) 8-horsepower recirculation engine pump.

UPSET CONDITION 

GAS DESTRUCTION 

DEVICE

Heater treater utility flare.

GAS DESTRUCTION 

DEVICE

Produced oil and produced water storage tank combustor.

*See the narrative description above 

 List and describe all proposed units, emission units and air pollution-generating activities. At a 

minimum, provide the following:

1. The hourly, daily and annual maximum operating rates for each operating unit, production 

process, and activity.

Table 3 – Hourly, Daily and Annual Maximum Operating Rates for Each Operating Unit

Operating Unit Maximum Annual 

Operating Hours

Produced Oil and Water Tank Combustor 8,760

Recirculation Engine Pump (RICE) 120

Heater Treater Burner 8,760

Heater Treater Flare 8,760

The projected average production at this facility is 1,400 barrels of oil per day (BOPD) and 1,400 Mscf 

of natural gas per day. Upon completion of the sales line, as described in the narrative above, the 

projected average is 2,200 BOPD and 2,200 Mscf of natural gas per day (Attachment 3). The projected 

maximum production at this facility is 803,000 barrels of oil per year and 803,000 Mscf per year of 

natural gas.

2. The hourly, daily and annual maximum firing rates for each fuel and combustion equipment.

Table 4 – Hourly, Daily and Annual Maximum Firing Rates for Oil and Gas Materials for each 

Combustion Equipment

Combustion Equipment Maximum Firing 

Rates (in btu/hr)

Maximum Annual 

Operating Hours

Produced Oil and Water Tank Combustors 3.7 x 106

(average btu/hr)*

8,760

Recirculation Engine Pumps (RICE) 8** 120

Heater Treater Burners 350,000 8,760

Heater Treater Utility Flares 37.5 x 106 

(average btu/hr)*

8,760

* These values were calculated in the calculation spreadsheet, which is based on multiplying the dry 

heating input value and the scf/day value (see Attachment 2).

** 8-horsepower engine
FORM NEW Maggie Old Dog USA 24-19H

D. Attachments September 30, 2011

3. The capacity for storage units and the hourly, daily and maximum throughput of material in the 

storage units. 

The maximum capacity of each produced oil and produced water storage tanks on site is 400 barrels. 

Each produced oil tank is an aboveground steel tank with a fixed roof. The produced water tanks are 

also aboveground and are fiberglass tanks that have fixed roofs. All tanks have vents to collect 

working, breathing and flash emissions which are collected and conveyed to the combustor.

Table 5 – Hourly, Daily and Annual Maximum Throughput of Materials to the Storage Tanks

Material

Average Daily 

Throughput 

(in bbl/day)

Annual Maximum 

Throughput 

(in bbl/year)

Produced Oil 1,400** 511,000

Produced Water 82.14* 29,981.1*

* Produced water is based on barrels of water per day (BWPD) and can vary significantly, depending 

on timing of completion, days or years of production, etc. This value is based on 10 facilities within the 

same prospect and was the highest of the facility produced water rates.

**See the narrative description above regarding sales line connection. If connected to sales, the 

average daily production will be approximately 2,200 bbl/day and annual maximum throughput of 

803,000 bbl/year. 

4. Material and product handling equipment and the hourly, daily and annual maximum throughput 

of material and product. 

See information provided from questions 1 through 3 above. In addition, refer to the facility narrative 

description above and the associated process flow diagram (Attachment 1).

5. Tank designs, tank storage capacities, hourly, daily and annual maximum throughput of material 

and product. 

See information provided from question 3 above.

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

annual and maximum hourly basis.

The proposed annual usage of field gas at this location is estimated at a maximum of 511,000 Mscf per 

year. The anticipated hydrogen sulfide (H2S) content of this field gas (which fuels the treater burner 

and is otherwise combusted in the treater flare) and tank emissions (which are combusted in the tank 

combustor) are included in the analytical data in this registration packet. Actual H2S concentrations 

data for gas produced at this facility is not yet available. However, based on projections, the gas is 

potentially projected to have a H2S concentration of approximately 14 ppm.

 Type and quantity of raw materials used or final product produced proposed to be used on a 

daily, annual and maximum hourly basis.

See information regarding produced oil and natural gas production as provided in question 1.
FORM NEW Maggie Old Dog USA 24-19H

D. Attachments September 30, 2011

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

number of weeks per year.

See information provided in question 2 above.

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

monitoring for each emission unit and air pollution generating activity.

Table 6 – Controls, Efficiencies, Limits and Monitoring for Each Emission Source/Activity

Emission Source Emission Controls Control 

Efficiency

Emission 

Limit (in tpy) Monitoring Type

Produced 

Oil/Produced Water 

Storage Tanks

Combustor 98% See Note 1

Visual 

combustor flame 

presence

Heater Treater 

Produced Natural 

Gas

Utility Flare 98% See Note 1 Visual flare 

flame presence

Heater Treater 

Burner

Programmable Logic 

Controller (PLC)

0% 

(uncontrolled) See Note 1 See Note 2

RICE Engine None (uncontrolled) 0% 

(uncontrolled) See Note 1 See Note 2

Truck Loadout 

(Produced oil and 

produced water)

Submerged Fill 0% 

(uncontrolled) See Note 1

Wellview 

Program oil 

production rates

Pneumatic Pump None (uncontrolled) 0% 

(uncontrolled) See Note 1 See Note 2

Pneumatic 

Controllers None (uncontrolled) 0% (uncontrolled) See Note 1 See Note 2

Note 1: See the attached calculation sheet for the emission limits in tons per year (Attachment 2).

Note 2: This emission source has negligible emissions; visual monitoring can be conducted to check 

for leaks and changes.

1. Include manufacturer specifications and guarantees for each control device.

Manufacturer’s specifications for each pollution control device (combustor for control of tank 

emissions and utility flare for produced gas combustion) are included in the attached materials 

(Attachment 4). The utility flare used to control produced gas emissions from the heater treater is a 

shop-built flare device, and is designed to meet the flare velocity and gas btu requirements of 40 CFR 

60.18.

 Criteria Pollutant Emissions Estimates

See the calculation spreadsheet attached (Attachment 2).

 Modeling – Air Quality Impact Analysis (AQIA)

There is no evidence at this time that this new construction would cause or contribute to a deterioration 

of air quality.

 ESA (Endangered Species Act)
FORM NEW Maggie Old Dog USA 24-19H

D. Attachments September 30, 2011

North Dakota Industrial Commission (NDIC) Oil and Gas Division rules require an Environmental 

Assessment (EA) as a prerequisite to obtaining an oil drilling permit. Such assessments include or will 

include best management practices and proposed action plans to mitigate any potential impacts to 

protected species/habitats.

 NHPA (National Historic Preservation Act)

Within the exterior boundaries of the Ft Berthold Indian Reservation (FBIR), and specifically for this 

project, MOC has contracted a 3rd party professional archeologist in consultation with the Tribal 

Historic Preservation Office (THPO), to conduct a Class III Cultural Resource Inventory Survey of the 

lands affected by the proposed facility. In addition, as a precursor to this survey and under the 

direction of this professional archeologist, a search of the State Historical Society of North Dakota’s 

site and manuscript files to ensure no previously recorded cultural resources are located within the 

project area. In general, should discovery of any culturally important resources occur during the 

initial Class III survey, the project site is moved or abandoned to ensure there will be no impact to any 

of these resources.

Consultation and clearance is required by NEPA for wells that lie atop of federal surface lands or for 

wells on fee simple surface lands that will cut federal minerals. This project has been approved by 

either the BIA and/or the BLM with THPO concurrence prior to issuance of any permits and right of 

ways for the project. In addition, MOC by way of an agreement with the Three Affiliated Tribes (TAT)

and THPO, has agreed to undertake the same methods and cultural resource surveys when 

conducting operations on fee simple lands (within the exterior boundaries of FBIR), where there are 

no other federal actions necessary to obtain a permit to drill (APD).
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 The Tribal Environmental Contact for the specific reservation:

 U.S. EPA, Region 8

 1595 Wynkoop Avenue, 8P-AR If you need assistance in identifying the appropriate Tribal

 Denver, CO 80202-1129 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 FACILTY INFORMATION

 Company Name Facility Name

 Company Contact or Owner Name Title

 Mailing Address

 Email Address

 Telephone Number Facsimile Number

 B. ATTACHMENTS

 For each criteria air pollutant, hazardous air pollutant and for all emission units and air pollutant-

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

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

 assure compliance with the proposed limitation.

 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.

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

 limitation, including all calculations for the estimates.

 Item 5 - Estimates of the potential emissions of Greenhuose Gas (GHG) pollutants before and after proposed 

 emission controls

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Region 8 Air Program

 FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY

Check List - Synthetic Minor Limit Request

(Form SYNMIN)

Marathon Oil Company Maggie Old Dog USA 24-19H

 generating activities to be covered by a limitation, include the following:

John A. Jehn Senior HES Professional

3172 Highway 22 North, Dickinson, ND 58601

jajehn@marathonoil.com

701-456-7515 701-456-7525
FORM SYNMIN Maggie Old Dog USA 24-19H

B. Attachments September 30, 2011

Item 1 – The proposed limitation and a description of its effect on current actual, allowable and the 

potential to emit.

This facility does not have a current permit that dictates the Current Actual Emissions or the Current 

Allowable Emissions. For the Potential to Emit (PTE), see the attached calculation spreadsheet 

(Attachment 2).

Item 2 – The proposed testing, monitoring, recordkeeping, and reporting requirements to be used to 

demonstrate and assure compliance with the proposed limitation.

According to 40 CFR §49.155(Minor NSR Rule), the following table identifies the testing, monitoring, 

recordkeeping and reporting requirements for the facility:

Table 1 – Testing, Monitoring, Recordkeeping and Reporting Requirements

Facility 

Equipment

Testing 

Requirements

Monitoring 

Requirements

Recordkeeping 

Requirements

Reporting 

Requirements

Heater treater 

burner N/A N/A Maintain records of burner rating N/A

Treater flare Initial sample gas 

composition N/A

Maintain records 

according to

40 CFR 

§49.155(4)(i)

Initial Submission

Treater flare N/A Monitor for flame 

presence

Maintain records 

when flare is not 

operating

Annual

Treater flare N/A

Visually monitor 

for smoke 

quarterly

Maintain records 

according to

40 CFR 

§49.155(4)(i)

Annual

Tank vent 

combustor

Initial sample gas 

composition N/A

Maintain records 

according to

40 CFR 

§49.155(4)(i)

Initial Submission

Tank vent 

combustor N/A Monitor for flame presence

Maintain records 

when flare is not 

operating

Annual

Tank vent 

combustor N/A

Visually monitor 

for smoke 

quarterly

Maintain records 

according to

40 CFR 

§49.155(4)(i)

Annual

Produced Oil 

Storage Tanks N/A N/A Maintain records of oil production

Report average 

daily throughput 

annually

8 hp recycle 

engine N/A N/A N/A N/A

Item 3 – The type and quantity of fuels and/or raw materials used.

Table 2 – Fuels and/or Raw Materials Used on Site
FORM SYNMIN Maggie Old Dog USA 24-19H

B. Attachments September 30, 2011

Fuel and/or Raw Material Site Use

Crude Oil

This site produces crude oil which is stored in the aforementioned 

storage tanks prior to being taken off site via tanker truck. Production 

volumes are shown on the attached calculation sheets.

Natural Gas

Natural gas that is produced with the oil is separated and flared or sold 

via a gas pipeline. A portion of the gas (field gas) is used to fuel the 

burner for the heater-treater; composition of field gas is included in 

analytical results of casinghead gas sampling included with this 

registration packet. Production volumes are shown on the attached 

calculation sheets.

Produced Water

Produced water associated with the production of oil and gas at this 

facility is separated from the hydrocarbon streams and routed to storage 

tanks prior to removal by tank truck.

Item 4 – A description of estimated efficiency of air pollution control equipment under present or 

anticipated operating conditions, including documentation of the manufacturer specifications and 

guarantees.

Historically a flare has been considered to meet the 98% control efficiency by demonstrating that the 

40 CFR 60.18 allowable tip velocity is not exceeded. 40 CFF 60.18(c)(4)(ii) allows non-assisted flare 

tip velocities from 60 to 400 feet per second if the net heating value exceeds 1,000 Btu/std. cubic foot. 

As shown on the attached gas analyses, the Btu content of both the treater gas (~1,500 Btu/scf) and the 

tank vent gas (~2,200 Btu/scf) are well in excess of the 1,000 Btu/scf minimum requirement for a flare 

tip velocity of up to 400 ft/sec.

Using a minimum treater flare tip diameter of 3 inches (0.049 ft2

) and a treater flare gas rate of 

1,400,000 scf/day (16.2 scf/sec), the flare tip velocity can be calculated by from the gas volume in cubic 

feet and the tip diameter in square feet. For this scenario, 16.2 scf/sec divided by the tip area of 0.049 

ft2 calculates to a flare velocity of 330 feet per second. Since this velocity is below the allowable 400 

ft/sec, we believe demonstrates a 98% efficiency for the flare. Please note that while this 

demonstration is for a three inch flare tip, it is possible the installed flare will have a larger tip

diameter that will further reduce velocities.

Item 5 – Estimates of the Current Actual Emissions, Current Allowable Emissions including all 

calculations for the estimates, where applicable.

This facility does not have a current permit that dictates the Current Actual Emissions or the Current 

Allowable Emissions. The potential to emit (PTE) value, as calculated in the attached calculation 

spreadsheet (Attachment 2) is 223.24 tons per year of VOCs. 

Item 6 – Estimates of the Post-Change Allowable Emissions that would result from compliance with the 

proposed limitation, including all calculations for the estimates.

Similar to Item 5, this facility does not have a current permit that dictates Current Actual Emissions or 

the Current Allowable Emissions, so Post-Change Allowable Emissions cannot be calculated at this 

time.

Item 7 – Estimates of the potential emissions of Greenhouse Gas (GHG) pollutants:

1. Carbon Dioxide (CO2)
FORM SYNMIN Maggie Old Dog USA 24-19H

B. Attachments September 30, 2011

2. Methane (CH4) and its CO2e

3. Nitrous Oxide (N2O) and its CO2e

4. Hydrofluorocarbons (HFCs) and its CO2e

5. Perfluorocarbons (PFCs) and its CO2e

6. Sulfur hexafluoride (SF6) and its CO2e

Based on the estimated parameters for an oil and gas production facility in the state of North Dakota, 

see the attached calculation spreadsheet (Attachment 2).
Attachment 1 – Typical Process Flow Diagram

Attachment 2 – Current Calculations for EPA Registration
GREEN = Requires input

RED = No input required. This is a calculated value.

Facility InformationMaggie Old Dog USA 24-19H Name of the facility, with well numbers (if known).

TBD First date of production or the date of modification of the facility.9/30/2011 Date registration packet is submitted to the NDDoH.Production Data DescriptionAnnual Avg BOPD 1400 This is the projected facility average BOPD on an annualized basisAnticipated GOR, scf/bbl 1000 Expected produced oil GORAnnual Avg Treater Gas (Mscfd) 1400 This is the calculated annual average mscfd of gas for the facility.Oil/Condensate Tank Data DescriptionFlash Gas Method: Default Bakken EF Use the drop down menu to choose the appropriate flash gas method.Bakken EF scf/bbl 97.91 The scf/bbl from direct measurement or representative sample. If specific data is not available, use the Bakken default of 97.91.Estimated Tank Vapors (scfd) 137074 This is the estimated scfd of tank vapors based on the following: adjusted BOPD multiplied by the scf/bbl entered under the Production Data Lower Heating Value 2231 Lower heating value (Btu/scf) of tank vapors. If site specific data is not available, use the Bakken default value of 2000.Molecular Weight 44.11 Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole). If site specific data is not available, use the Bakken default value VOC% 77.41% VOC weight fraction of the tank vapor gas (C3+). If site specific data is not available, use the Bakken default value of 79.8%.HAP% 2.37% HAP weight fraction of the tank vapor gas. If site specific data is not available, use the Bakken default value of 2.26%.H2S weight % 0.000% H2S weight percent of the tank vapor gas.H2S mole % 0.000% H2S mole percent of the tank vapor gas.Enclosed Smokeless Combustor Use the drop down menu to choose the appropriate emission control type.Control Destruction Efficiency 98% Control efficiency of any applicable controls. This is a fixed number based on control type.Treater Gas Data DescriptionBtu/scf 1,612 Btu/scf of wellstream gas. Molecular Weight 28.46 Average molecular weight of the wellstream gas in lb/lb-mole.Specific Gravity 1 If necessary to convert specific gravity to molecular weight, enter the specific gravity of the wellstream gas.Calculated Molecular Weight 28.96 This is the calculated molecular weight based on the specific gravity entered above.VOC% 41.42% VOC weight fraction of the wellstream gas (Note: Weight%, not Mole%). HAP% 3.50% HAP weight fraction of the wellstream gas. (Note: Weight%, not Mole%). H2S weight % 0.000% H2S weight percent of the wellstream gasH2S mole % 0.000% H2S mole percent of the wellstream gasUtility Flare or Other 98% DRE Device Use the drop down menu to choose the appropriate emission control type.Control Destruction Efficiency (DE 1) 98% Control efficiency of any applicable controls (combustor, pit flare, utility flare, etc).Hours of Operation 8760 Hours of Operation at Destruction Efficiency 1

Input Data

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Input 1 of 36 
Input Data

Treater Burner(s) DescriptionTotal Btu/hr 700,000 Total burner rating for the heater treater burner(s) in btu/hr. If there are multiple burners, add the total heat input together.Hours of Operation 8,760 The burner(s) is/are assumed to operate 8,760 hours per year.Truck Loading DescriptionOil is hauled by truck Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a LACT, no input values are required for the TrucSubmerged loading: dedicated normal service 0.6 Use the drop down list to choose the appropriate mode of operation. The saturation factor will automatically be selected based on mode of oMolecular Weight 44.11 Molecular weight of tank vapors in lb/lb-mole. If no site specific data is available, please refer to Table 2 on the Truck Loading tab.Vapor Pressure 1.90 True vapor pressure of liquid loaded, pounds per square inch absolute (psia) If no site specific data is available, please refer to Table 2 on thTemperature 41.33 Temperature of bulk liquid loaded in Fahrenheit. If no site specific data is available, use an estimated average annual temperature.Load Rate (bbl/hr) 200 Load rate of liquid loaded in barrels per hour.Load Time (hrs) 1.00 The time it takes to loadout one load (hrs).Pneumatic Pumps DescriptionNumber of Pneumatic Pumps 2 Number of pneumatic pumps at facility.Hours of Operation 4380 Hours the pump is in operation annually. For winter months only, please enter 4380 hours.scf/min 0.50 Pneumatic source consumption rate as per manufacturer data (scf/min).Vented to atmosphere Use the drop down menu to choose the appropriate emission control type.Control Efficiency 0% Control efficiency of any applicable controls (combustor, routing exhaust to fuel supply, VRU, etc).Pneumatic Controllers DescriptionNumber of Pneumatic Controllers 4 Number of pneumatic controllers at facility.Bleed rate (scf/hr) 17.40 Average bleed rate of device (scf/hr).Glycol Dehydrator DescriptionVOC (TPY) 0.00 VOC emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).HAP (TPY) 0.00 HAP emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Input 2 of 36 
Number of Engines 2

RICE Engine #1Hours of Operation 120Maximum HP Rating 8NOx g/hp-hr 4.99CO g/hp-hr 3.16VOC g/hp-hr 6.8NOx Control Efficiency 0%CO Control Efficiency 0%VOC Control Efficiency 0%RICE Engine #2Hours of Operation 120Maximum HP Rating 8NOx g/hp-hr 4.99CO g/hp-hr 3.16VOC g/hp-hr 6.8NOx Control Efficiency 0%CO Control Efficiency 0%VOC Control Efficiency 0%RICE Engine #3Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%

RICE Input Data

Enter the number of engines that will be installed at the production facility.

Description

Recycle pump engine operates less than 10 hours per month.Manufacturer's maximum hp rating.

Description

Recycle pump engine operates less than 10 hours per month.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Rice Input 3 of 36 
RICE Input Data

RICE Engine #4Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #5Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #6Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #7Hours of Operation 0

NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TO

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Rice Input 4 of 36 
RICE Input Data

Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #8Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #9Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #10Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4

Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daManufacturer's maximum hp rating.NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TO

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Rice Input 5 of 36 
RICE Input Data

NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #11Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #12Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%

Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TO

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Rice Input 6 of 36 
GREEN = Requires input

RED = No input required. This is a calculated value.

Facility InformationMaggie Old Dog USA 24-19H Name of the facility and the well number.TBD First date of production or the date of modification of the facility.9/30/2011 Date registration packet is submitted to the NDDoH.Natural Gas Pneumatic Device Venting DescriptionCount - Total Number of Continuous High Bleed Natural Gas Pneumatic Devices 2Count - Total Number of Continuous Low Bleed Natural Gas Pneumatic Devices 0Count - Total Number of Intermittent Bleed Natural Gas Pneumatic Devices 0Concentration in Produced Natural Gas - CH4 47% Concentration of CH4 in produced natural gas. For facilities in 98.230(a)(3)-(a)(8), GHGi = 1Concentration in Produced Natural Gas - CO2 1% Concentration of CO2, in produced natural gas. For facilities in 98.230(a)(3)-(a)(8), GHGi = 1Associated Gas Venting and Flaring DescriptionGas to Oil Ratio (GOR) 1000 Gas to Oil ratio in cubic feet of gas per barrel of oil. Oil refers to hydrocarbon liquids produced of all API gVolume of Oil Produced (barrels/year) 511000 Volume of oil produced in barrels in the calendar year during which associated gas was vented or flaredVolumetric Emissions - Gas Venting & Flaring DescriptionTemperature at standard conditions (°F) 60 Temperature at standard conditions (°F) - TsTemperature at actual emission conditions (°F) 60 Temperature at actual emission conditions (°F) - TaAbsolute pressure at standard conditions (psia) 14.7 Absolute pressure at standard conditions (psia) - PsAbsolute pressure at actual conditions (psia) 13.6 Absolute pressure at actual conditions (psia) - PaMole Fraction in Natural Gas - CH4 0.47

Mole Fraction in Natural Gas - CO2 0.01115

Gas Venting and Flare Stack Emissions DescriptionField Gas or Process Vent Gas Use the drop down menu to choose the appropriate type of fuel vented.

High Heat Value (HHV) 1.235E-03 Default High Heat Value based on 40 CFR 98 Table C-1 or 40 CFR 98.233(z)(6)(ii)Percent of Gas Flared 100% Percent of gas sent to flare in cubic feet, during the yearFraction of Gas Combusted by Burning Flare 98% Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, n is zeroMole Fraction of Methane 0.47 Mole fraction of gas hydrocarbon constituentsMole Fraction of Ethane 0.26 Mole fraction of gas hydrocarbon constituentsMole Fraction of Propane 0.15 Mole fraction of gas hydrocarbon constituentsMole Fraction of Butane 0.0534 Mole fraction of gas hydrocarbon constituentsMole Fraction of Pentanes-Plus 0.03 Mole fraction of gas hydrocarbon constituents

GHG Calculations Input Data

1st Calendar Year - Count the total of each type, or count any percentage number of each type plus an engi2nd Calendar Year - Count the total of each type, or count any percentage number of each type plus an eng3rd Calendar Year - Complete the count of all pneumatic devices, including any changes to equipment counFollowing Years - Update the total count of pneumatic devices and adjust accordingly to reflect any modificMole fraction of GHGi in the natural gas. 98.233(u)(2) - Annual average mole fraction for each facility as speGHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities. If ythese values for determining the mole fraction. If you do not have a continuous gas composition analyzer, of the field.

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG Calculations Input 7 of 36 
VOC NOx CO SO2 PM PM10 PM2.5

Oil/Condensate Tanks 45.08 3.80 20.65 -- -- -- --Treater Flare 158.92 28.02 152.44 0.00 -- -- --Treater Burner 0.02 0.30 0.25 0.002 0.02 0.02 0.02RICE Engine 0.01 0.01 0.01 0.00 0.00 0.00 0.00Truck Loading 10.38 -- -- -- -- -- --Pneumatic Pump 4.09 -- -- -- -- -- --Pneumatic Controllers 4.74 -- -- -- -- -- --Glycol Dehydrator 0.00 -- -- -- -- -- --Totals (TPY) 223.24 32.12 173.35 0.00 0.02 0.02 0.02PSD Threshold* 250 250 250 250 250 250 250Is Threshold Exceeded? No No No No No No NoPSD Modification Threshold* 40 40 100 40 25 15 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 100 100 100 100 100 100Is Threshold Exceeded? Yes No Yes No No No NoMinor NSR Rule Threshold*** 5 10 10 10 10 5 3Is Threshold Exceeded? Yes Yes Yes No No No No

Pb NH3 Fluorides H2SO4 H2S TRS RSC

Oil/Condensate Tanks -- -- -- -- -- -- --Treater Flare -- -- -- -- 0.00 -- --Treater Burner -- -- -- -- -- -- --RICE Engine -- -- -- -- -- -- --Truck Loading -- -- -- -- -- -- --Pneumatic Pump -- -- -- -- -- -- --Pneumatic Controllers -- -- -- -- -- -- --Glycol Dehydrator -- -- -- -- -- -- --Totals (TPY) 0.00 0.00 0.00 0.00 0.00 0.00 0.00PSD Threshold* 250 - 250 250 250 250 250Is Threshold Exceeded? No No No No No No NoPSD Modification Threshold* 0.6 - 3 7 10 10 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 - 100 100 100 100 100Is Threshold Exceeded? No No No No No No NoMinor NSR Rule Threshold*** 0.1 - 1 2222Is Threshold Exceeded? No No No No No No No

Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements**Title V Thresholds taken from the Major Source definition contained in 40 CFR 70.2***Minor NSR Rule Thresholds are found in Table 1 to 40 CFR 49.153, Minor NSR Thresholds (Attainment Areas)

*PSD Threshold taken from 40 CFR 52.21(b)(1)(i)(b), oil and gas well facilities are not 1 of the 28 designated source categories listed in 40 CFR 52.21(b)(1)(i)(a) thus the applicability threshold is 250 tpy. PSD Modification Thresholds taken from 40 CFR 52.21(b)(23)(i).

Controlled Criteria Air Pollutants Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Emission Source

REGULATED CRITERIA AIR POLLUTANTS PTE (TPY) - Controlled

REGULATED AIR POLLUTANTS (TPY) - Controlled

Emission Source

Marathon Oil Company

Maggie Old Dog USA 24-19H

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Emission Summary - Controlled 
VOC NOx CO SO2 PM PM10 PM2.5

Oil/Condensate Tanks 2253.87 3.80 20.65 -- -- -- --Treater Flare 7946.03 28.02 152.44 0.00 -- -- --Treater Burner 0.02 0.30 0.25 0.002 0.02 0.02 0.02RICE Engine 0.01 0.01 0.01 0.00 0.00 0.00 0.00Truck Loading 10.38 -- -- -- -- -- --Pneumatic Pump 4.09 -- -- -- -- -- --Pneumatic Controllers 4.74 -- -- -- -- -- --Glycol Dehydrator 0.00 -- -- -- -- -- --Totals (TPY) 10219.14 32.12 173.35 0.002 0.02 0.02 0.02PSD Threshold* 250 250 250 250 250 250 250Is Threshold Exceeded? Yes No No No No No NoPSD Modification Threshold* 40 40 100 40 25 15 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 100 100 100 100 100 100Is Threshold Exceeded? Yes No Yes No No No NoMinor NSR Rule Threshold*** 5 10 10 10 10 5 3Is Threshold Exceeded? Yes Yes Yes No No No No

Pb NH3 Fluorides H2SO4 H2S TRS RSC

Oil/Condensate Tanks -- -- -- -- -- -- --Treater Flare -- -- -- -- 0.00 -- --Treater Burner -- -- -- -- -- -- --RICE Engine -- -- -- -- -- -- --Truck Loading -- -- -- -- -- -- --Pneumatic Pump -- -- -- -- -- -- --Pneumatic Controllers -- -- -- -- -- -- --Glycol Dehydrator -- -- -- -- -- -- --Totals (TPY) 0.00 0.00 0.00 0.00 0.00 0.00 0.00PSD Threshold* 250 - 250 250 250 250 250Is Threshold Exceeded? No No No No No No NoPSD Modification Threshold* 0.6 - 3 7 10 10 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 - 100 100 100 100 100Is Threshold Exceeded? No No No No No No NoMinor NSR Rule Threshold*** 0.1 - 1 2222Is Threshold Exceeded? No No No No No No No

Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements**Title V Thresholds taken from the Major Source definition contained in 40 CFR 70.2***Minor NSR Rule Thresholds are found in Table 1 to 40 CFR 49.153, Minor NSR Thresholds (Attainment Areas)

*PSD Threshold taken from 40 CFR 52.21(b)(1)(i)(b), oil and gas well facilities are not 1 of the 28 designated source categories listed in 40 CFR 52.21(b)(1)(i)(a) thus the applicability threshold is 250 tpy. PSD Modification Thresholds taken from 40 CFR 52.21(b)(23)(i).

REGULATED CRITERIA AIR POLLUTANTS PTE (TPY) - Uncontrolled

Emission Source

Maggie Old Dog USA 24-19H

REGULATED AIR POLLUTANTS (TPY) - Uncontrolled

Emission Source

Uncontrolled Criteria Air Pollutants Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Emission Summary - Uncontrolled 
CO2e CO2 CH4 N2O

Oil/Condensate Tanks & Fugitive Equipment Leaks**** Negligible Negligible Negligible --Gas Venting (Flared) 5.80E+04 5.60E+04 9.60E+01 --Gas Venting (Unflared) 0.00E+00 0.00E+00 0.00E+00 --Treater Burner 325.44 325.12 0.13 0.19RICE Engine 1.04 1.04 -- --Truck Loading -- -- -- --Pneumatic Pump 45.27 0.14 2.15 --Pneumatic Controllers 163.72 0.50 7.77 --Glycol Dehydrator -- -- -- --Totals (metric tons/year) 58,555 56,330 106 0.19GHG Reporting Threshold* 25,000 -- -- --Note: Subpart W requires reporting these emissions as part of the larger basin reporting.

CO2e CO2 CH4 N2O

Oil/Condensate Tanks & Fugitive Equipment Leaks**** Negligible Negligible Negligible --Gas Venting (Flared) 63955.80 6.17E+04 1.06E+02 --Gas Venting (Unflared) 0.00E+00 0.00E+00 0.00E+00Treater Burner 358.73 358.38 0.14 0.21RICE Engine 1.04 1.04 -- --Truck Loading -- -- -- --Pneumatic Pump 49.90 0.15 2.37 --Pneumatic Controllers 180.47 0.56 8.57 --Glycol Dehydrator -- -- -- --Totals (tpy) 64,545.94 62,093.36 116.91 0.21Title V Threshold** 100,000 -- -- --Is Threshold Exceeded? No -- -- --PSD Threshold*** 100,000 -- -- --Is Threshold Exceeded? No -- -- --

Maggie Old Dog USA 24-19H

GREENHOUSE GAS EMISSIONS PTE (metric tons/year)

Emission Source

***PSD Threshold for GHG taken from PSD and Title V Permitting Guidance for Greenhouse Gases prepared by the US EPA Office of Air Quality Planning and Standards in March 2011. PSD applicability threshold is 75,000 tpy CO2e for 

modifications at existing PSD sources, 100,000 tpy CO2e for new sources and 100/250 tpy mass basis.

**Title V Threshold for GHG taken from PSD and Title V Permitting Guidance for Greenhouse Gases prepared by the US EPA Office of Air Quality Planning and Standards in March 2011.Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.*GHG Reporting Threshold taken from 40 CFR 98.2(3)(iii).

GREENHOUSE GAS EMISSIONS PTE (tpy)

Greenhouse Gas Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

Emission Source

****Due to the nature of these types of emissions sources (i.e., oil/condensate tanks and fugitive equipment leaks) potential emissions of regulated GHG emissions have been assumed to be negligible.

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG Emission Summary 
Total HAPs Benzene Toluene Hexane Ac

Oil/Condensate Tanks 1.38 -- -- -- Treater Flare 13.42 -- -- -- Treater Burner 5.67E-03 6.31E-06 1.02E-05 5.41E-03 RICE Engine -- -- -- -- Truck Loading -- -- -- -- Pneumatic Pump 0.35 -- -- -- Pneumatic Controllers 0.40 -- -- -- Glycol Dehydrator -- -- -- -- Totals (TPY) 15.55 (no individual HAP exceeds 10 tpy)Title V Threshold* 25 10 10 10 Is Threshold Exceeded? No Yes No No 

Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requiremen

Treater flare HAPs conservatively calculated assuming all C6+ components are HAPs, as an extended analysis was not available

*HAP thresholds of 10 tpy of an individual regulated HAP and 25 tpy aggregate are taken from the Major Source definition coCFR 70.2. The thresholds of 10/25 tpy also represent what constitutes a major stationary source.

REGULATED HAZARDOUS AIR POLLUTANTS PTE (TPY)

Emission Source

Maggie Old Dog USA 24-19H

HAP Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

6Attachment 2 - Calculations for EPA Air Registration.xlsx, HAP Emission Summary 
Oil/Condensate Tanks Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Flare Gas Volume 

(scf/day)

Lower Heating 

Value (Btu/scf)

Molecular 

Weight 

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt 

Fraction (%)

Destruction 

Efficiency (%)

NOx Emission 

Factor

(lb/MMBtu)

CO Emission 

Factor

(lb/MMBtu)

137074.00 2231.38 44.11 77.41% 2.37% 98% 0.068 0.37

Pollutant Flare Gas Volume

(scf/hr)

scf/lb-mole

Molecular 

Weight 

(lb/lb-mole)

wt Fraction 

(%)

Heating Value

(Btu/scf)

Destruction 

Efficiency (%)

Potential 

Uncontrolled 

Emissions

(lbs/hr)

Potential 

Uncontrolled 

Emissions

(tons/year)

Potential 

Controlled 

Emissions

(lbs/hr)

Potential 

Controlled 

Emissions

(tons/year)

VOC 5711.42 0.0026 44.11 77.41% -- 98% 514.58 2253.87 10.29 45.08

HAP 5,711.42 0.0026 44.11 2.37% -- 98% 15.79 69.14 0.32 1.38

NOx 5,711.42 -- -- -- 2231.38 -- 0.87 3.796 0.87 3.796

CO 5,711.42 -- -- -- 2231.38 -- 4.72 20.65 4.72 20.65

Notes: NOx & CO emission factors are from AP-42 Table 13.5-1 - Emission Factors for Flare Operations.

Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirementsEmission estimates reflect combustion related air pollutants. If flare equipped with a pilot burner, heat input of burner should be evaluated.

Example Calculations

VOC and HAPS EmissionsPotential Controlled Emissions (lbs/hr) = (Flare Gas Volume (scf/hr) * scf/lb-mole * Molecular Weight (lb/lb-mole) * wt Fraction (%)) * 1 - Destruction Efficiency (%)Potential Controlled Emissions (tons/yr) = Potential Controlled Emissions (lbs/hr) * 8760 hrs/yr * 1/2000NOx and CO EmissionsPotential Controlled Emissions (lbs/hr) = Flare Gas Volume (scf/hr) * Heating Value (Btu/scf) * 1/1,000,000 * Emission Factor (lbs/MMBtu)Potential Controlled Emissions (tons/yr) = Potential Emissions (lbs/hr) * 8760 hrs/yr * 1/2000

6Attachment 2 - Calculations for EPA Air Registration.xlsx, OilCondensate Tanks 
Treater Flare Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Flare Gas 

Volume (scf/day)

Lower Heating 

Value (Btu/scf)

Molecular 

Weight 

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt 

Fraction (%)

NOx Emission 

Factor

(lb/MMBtu)*

CO Emission 

Factor

(lb/MMBtu)*

Destruction 

Efficiency 1 

(%)**

Hours of 

Operation at DE 1 

(hours)

Destruction 

Efficiency 2 (%)**

Hours of 

Operation at DE 2 

(hours)

1,400,000.00 1612.49 28.46 41.42% 3.50% 0.068 0.37 98% 8760 100% 0

Pollutant Flare Gas Volume (scf/hr) scf/lb-mole Molecular Weight (lb/lb-mole) wt Fraction (%) Heating Value (Btu/scf) Potential Uncontrolled Emissions (lbs/hr) Potential Uncontrolled Emissions (tons/year) Potential Controlled Emissions 1 (lbs) Potential Controlled Emissions 1 (tons) Potential Controlled Emissions 2 (lbs) Potential Controlled Emissions 2 (tons) Potential Total Controlled Emissions (lbs/hr) Potential Total Controlled Emissions (tons/year)

VOC 58,333.33 0.0026 28.46 41.42% -- 1814.16 7946.03 36.28 158.92 0.00 0.00 36.28 158.92

HAP 58,333.33 0.0026 28.46 3.50% -- 153.20 671.00 3.06 13.42 0.00 0.00 3.06 13.42

H2S 58,333.33 0.0026 28.46 0.00% -- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

SO2 58,333.33 0.0026 64.00 0.00% -- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NOx 58,333.33 -- -- -- 1612.49 6.40 28.02 -- -- -- -- 6.40 28.02

CO 58,333.33 -- -- -- 1612.49 34.80 152.44 -- -- -- -- 34.80 152.44

Notes: *NOx & CO emission factors are from AP-42 Table 13.5-1 - Emission Factors for Flare Operations.

**100% destruction efficiency means that the treater gas is routed and connected to the sales line (gas gathering pipeline).Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Example Calculations

VOC and HAPS EmissionsPotential Controlled Emissions (lbs/hr) = (Flare Gas Volume (scf/hr) * scf/lb-mole * Molecular Weight (lb/lb-mole) * wt Fraction (%)) * 1 - Destruction Efficiency (%)Potential Controlled Emissions (tons/yr) = Potential Controlled Emissions (lbs/hr) * Hours of Operation * 1/2000NOx and CO EmissionsPotential Controlled Emissions (lbs/hr) = Flare Gas Volume (scf/hr) * Heating Value (Btu/scf) * 1/1,000,000 * Emission Factor (lbs/MMBtu)Potential Emissions (tons/yr) = Potential Emissions (lbs/hr) * 8760 hrs/yr * 1/2000

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Treater Flare 
Treater Burner Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Burner Rating

(Btu/hr)

Burner Rating

(MMBtu/hr)

Average Natural 

Gas Higher 

Heating Value 

(Btu/scf)

NOx Emission 

Factor

(lb/106 scf)

CO Emission 

Factor

(lb/106 scf)

PM (Total) 

Emission Factor

(lb/106 scf)

PM 

(Condensable) 

Emission Factor

(lb/106 scf)

PM (Filterable) 

Emission Factor

(lb/106 scf)

SO2 Emission 

Factor

(lb/106 scf)

VOC Emission 

Factor

(lb/106 scf)

HAP Emission 

Factor

(lb/106 scf)

700,000.00 0.70 1,020 100 84 7.6 5.7 1.9 0.6 5.5 1.9

Pollutant Emission Factor (lb/MMBtu) Burner Rating (MMBtu/hr) Potential Emissions (lbs/hr) Potential Emissions (tons/year)

NOx 0.10 0.70 0.07 0.30

CO 0.08 0.70 0.06 0.25

PM (Total) 0.007 0.70 0.005 0.02

PM (Condensable) 0.006 0.70 0.004 0.02

PM (Filterable) 0.002 0.70 0.001 0.006

SO2 0.001 0.70 0.0004 0.002

VOC 0.005 0.70 0.004 0.02

HAPs 0.002 0.70 0.001 0.006

Notes: NOx, CO, PM, HAP, SO2 & VOC Emission Factors are from AP-42, Section 1.4 - Natural Gas Combustion, Tables 1.4-1, 1.4-2, and 1.4-3.Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Example Calculations

Potential Emissions (lbs/hr) = Emission Factor (lbs/MMBtu) * Burner Rating (MMBtu/hr)Potential Emissions (tons/yr) = Potential Emissions (lbs/hr) * 8760 hrs/yr * 1/2000

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Treater Burner 
Treater Burner - Regulated HAPs Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Formaldehyde Yes 7.35E-05 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 5.15E-05 2.25E-2-Methylnaphthalene Yes 2.35E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.65E-08 7.21E-3-Methylchloranthrene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-7,12-Dimethylbenz(a)anthracene Yes 1.57E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.10E-08 4.81E-Acenaphthene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Acenaphthylene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Anthracene Yes 2.35E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.65E-09 7.21E-Arsenic Yes 1.96E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.37E-07 6.01E-Benz(a)anthracene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Benz(a)pyrene Yes 1.18E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-10 3.61E-Benzene Yes 2.06E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.44E-06 6.31E-Benzo(b)fluoranthene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Benzo(g,h,i)perylene Yes 1.18E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-10 3.61E-Benzo(k)fluoranthene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Beryllium Yes 1.18E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 8.24E-09 3.61E-Cadmium Yes 1.08E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 7.55E-07 3.31E-Chromium Yes 1.37E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 9.61E-07 4.21E-Chrysene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Cobalt Yes 8.24E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 5.76E-08 2.52E-Dibenzo(a,h)anthracene Yes 1.18E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-10 3.61E-Dichlorobenzene Yes 1.18E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-07 3.61E-Fluoranthene Yes 2.94E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 2.06E-09 9.02E-Fluorene Yes 2.75E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.92E-09 8.42E-Hexane Yes 1.76E-03 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-03 5.41E-Indeno(1,2,3-cd)pyrene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Manganese Yes 3.73E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 2.61E-07 1.14E-Mercury Yes 2.55E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.78E-07 7.82E-

Naphthalene Yes 5.98E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 4.19E-07 1.83E-Nickel Yes 2.06E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.44E-06 6.31E-Phenanathrene Yes 1.67E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.17E-08 5.11E-Pyrene Yes 4.90E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 3.43E-09 1.50E-Selenium Yes 2.35E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.65E-08 7.21E-Toluene Yes 3.33E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 2.33E-06 1.02E-

Total (TPY)= 0.00

Equipment Heat Input (MMBtu/hr) Hours of Operation (hrs/yr)

Treater Burner 0.7 8760

TOTAL 0.7

Notes:

*Regulated under Section 112(b) for Clean Air Act.Example Calculation Estimated Uncontrolled Emissions (lbs/hr) = Emission Factor (lbs/MMBtu) x Heat Input Rate (MMBtu/hr)Estimated Uncontrolled Emissions (tons/yr) = Estimated Uncontrolled Emissions (lbs/hr) x Hours of Operation / 2000

Estimated Uncontr

(tons/

**Emission factors taken from AP-42, Chapter 1 - External Combustion Sources, Table 1.4-3 - Emission Factors for Speciated Organic Compounds from Natural Gas Combustion and Table 1.4-4 - Emission Factors for Metals from Natural Gas Combustion.

Pollutant HAP

*

Yes/No

Emission Factor

(lb/MMBtu)** Emission Factor Source Estimated Uncontrolled Emissions (lb/hr)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Treater Burner - HAPs 
Truck Loading Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Cargo Carrier Mode of Operation S Factor

Submerged loading of a clean cargo 

tank 0.50

Submerged loading: dedicated 

normal service 0.60

Submerged loading: dedicated vapor 

balance service 1.00

Table 2 - Vapor Pressure and Molecular Weight Values

40 50 60 70 80 90 100

Crude Oil RVP 5 50 4.5 7.1 1.8 2.3 2.8 3.4 4.0 4.8 5.7

Values based on AP-42, Chapter 7 - Liquid Storage Tanks, Table 7.1-2 - Properties (M v, PVA, WL) of Selected Petroleum Liquids.

Constant Saturation Factor (S) Vapor Pressure (P) (psi) Molecular Weight (M) (lb/lb-mole) Temperature (T) (°R) Loading Loss (lb/1,000 gal)

12.46 0.60 1.90 44.11 501 1.25

Loading Loss

(lb/1,000 gal) Truck Load Rate (bbl/hr) Truck Load Time (hrs) gal/bbl Annual bbl/yr

Potential 

Uncontrolled VOC 

Emissions 

(lbs/hr)

Potential 

Uncontrolled VOC 

Emissions 

(tons/yr)

Potential 

Uncontrolled C3+ 

VOC Emissions*

(tons/yr)

1.25 200.00 1.00 42.00 511000.00 10.50 13.41 10.38

Notes:*VOC weight fraction of the tank vapor gas (C3+). If site specific data is not available, use the Bakken default value of 79.8%.

Uncontrolled 

Potential VOC 

Emissions

(tons/yr)

Control (%) 1 - Control (%)

Controlled 

Potential VOC 

Emissions

(tons/yr)

10.38 0.00 1.00 10.38

Notes: Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirementsExample Calculations

Loading Loss (lb/1,000 gal) = Constant * Saturation Factor * Vapor Pressure * (Molecular Weight / Temperature)Potential Emissions (lbs/hr) = Loading Loss / 1000 * (Truck Load Rate / Truck Load Time) * gal/bblUncontrolled Potential Emissions (tons/yr) = (Loading Loss / 1000) * Annual bbl/yr * gal/bbl / 2000Controlled Potential Emissions (tons/yr) = Uncontrolled Emissions * 1 - Control Efficiency

AP-42 Equation

LL = 12.46 x (S x P x M)/TLL = Loading loss, pound per 1,000 gallons of liquid loaded (lb/1000 gal)S = Saturation factor (AP-42 Table 5.2-1)P = True vapor pressure of liquid loaded (psia) (AP-42 Table 7.1-2)M = Molecular weight of tank vapors (lb/lb-mol) (AP-42 Table 7.1-2)T = Temperature of bulk liquid loaded (°R) (°R = °F + 460)

Table 1 - Saturation Factor Variable

Tank Trucks and Rail 

Tank Cars

Factors based on AP-42, Section 5.2 - Transportation and Marketing of Petroleum Liquids, Table 5.2-1 - Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses.

True Vapor Pressure

Petroleum Liquid (psi) at various temperatures in °F Vapor MW at 60°F (lb/lb-mole) Condensed Vapor Density at 60°F (lb/gal) Liquid Density at 60°F (lb/gal)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Truck Loading 
Reciprocating Internal Combustion Gasoline Engines (RICE) Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Engine # Maximum HP Hours of Operation*** NOx DRE (%)** NOx Emission Factor (g/HP-HR)* CO DRE (%)** CO Emission Factor (g/HP-HR)* VOC DRE (%)** VOC Emission Factor (g/HP-HR)*

PM10 Emission 

Factor 

(g/HP-HR)*

SO2 Emission 

Factor 

(g/HP-HR)*

CO2 Emission 

Factor 

(g/HP-HR)*

Engine #1 8.00 120.00 0% 4.99 0% 3.16 0% 6.80 0.33 0.27 489.89Engine #2 8.00 120.00 0% 4.99 0% 3.16 0% 6.80 0.33 0.27 489.89Engine #3 100.00 0 90% 10.00 75% 5.00 70% 4.00 0.33 0.27 489.89Engine #4 100.00 0 90% 10.00 75% 5.00 70% 4.00 0.33 0.27 489.89

Notes:**Control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.***Engine is assumed to operate 8,760 hours per year.Uncontrolled Emissions

Pollutant Engine #1 Potential Emissions (lbs/hr) Engine #1 Potential Emissions (tons/yr) Engine #2 Potential Emissions (lbs/hr) Engine #2 Potential Emissions (tons/yr) Engine #3 Potential Emissions (lbs/hr) Engine #3 Potential Emissions (tons/yr) Engine #4 Potential Emissions (lbs/hr) Engine #4 Potential Emissions (tons/yr) Total Potential Uncontrolled Emissions (lbs/hr) Total Potential Uncontrolled Emissions (tons/yr)

NOx 0.09 0.01 0.09 0.01 2.20 0.00 2.20 0.00 4.59 0.01

CO 0.06 0.00 0.06 0.00 1.10 0.00 1.10 0.00 2.32 0.01

VOC 0.12 0.01 0.12 0.01 0.88 0.00 0.88 0.00 2.00 0.01

PM10 0.01 0.00 0.01 0.00 0.07 0.00 0.07 0.00 0.16 0.00

SO2 0.005 0.00 0.00 0.00 0.06 0.00 0.06 0.00 0.13 0.00

CO2 8.64 0.52 8.64 0.52 108.00 0.00 108.00 0.00 233.28 1.04

Controlled Emissions

Pollutant Engine #1 Potential Emissions (lbs/hr) Engine #1 Potential Emissions (tons/yr) Engine #2 Potential Emissions (lbs/hr) Engine #2 Potential Emissions (tons/yr) Engine #3 Potential Emissions (lbs/hr) Engine #3 Potential Emissions (tons/yr) Engine #4 Potential Emissions (lbs/hr) Engine #4 Potential Emissions (tons/yr) Total Potential Controlled Emissions (lbs/hr) Total Potential Controlled Emissions (tons/yr)

NOx 0.09 0.01 0.09 0.01 0.22 0.00 0.22 0.00 0.62 0.01

CO 0.06 0.00 0.06 0.00 0.28 0.00 0.28 0.00 0.66 0.01

VOC 0.12 0.01 0.12 0.01 0.26 0.00 0.26 0.00 0.77 0.01

PM10 0.01 0.00 0.01 0.00 0.07 0.00 0.07 0.00 0.16 0.00

SO2 0.005 0.00 0.00 0.00 0.06 0.00 0.06 0.00 0.13 0.00

CO2 8.640 0.52 8.64 0.52 108.00 0.00 108.00 0.00 233.28 1.04

Notes: Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Total Combined HP: 216.00

Total Hours of Operation: 240.00Example Calculations

Potential Controlled Emissions (lbs/hr) = HP x Emission Factor (g/HP-hr) / Conversion Factor x 1 - Control EfficiencyPotential Controlled Emissions (tons/yr) = Potential Emissions (lbs/hr) * Hours of Operation / 2000*Emission factors for NOx, CO and VOC are based on Manufacturer's emission factor, actual test results, or AP-42 factor in grams per horsepower hour (g/hp-hr). 

Emission factors for PM10, SO2, and CO2 are taken from AP-42, Table 3.3-1 - Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines. Factors are converted to g/hp-hr from lb/hphr.

6Attachment 2 - Calculations for EPA Air Registration.xlsx, RICE Engines 
Pneumatic Pumps Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Pneumatic Source 

Consumption 

Rate* (scf/min)

Supply Gas 

Molecular 

Weight**

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt Fraction 

(%)

Hours of 

Operation***

(hrs/yr)

Control 

Efficiency (%)

Number of 

Pumps 

Potential 

Uncontrolled 

VOC Emissions

(lbs/hr)

Potential 

Uncontrolled VOC 

Emissions

(tons/yr)

Potential 

Controlled VOC 

Emissions

(tons/yr)

Potential 

Uncontrolled 

HAP Emissions

(lbs/hr)

Potential 

Uncontrolled HAP 

Emissions

(tons/yr)

0.50 28.46 41.42% 3.50% 4380 1.00 2.0 0.93 4.1 4.1 0.08 0.3 

Notes:*PSCR = Pneumatic Source Consumption Rate (scf/min), as per manufacturers literature.**Gas MW = Supply Gas Average Molecular Weight (lb/lb-mole).***Hours the pump is in operation annually. For winter months only, please enter 4380 hours.Example Calculations

Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Potential Controlled Emissions (lb/hr) = PSCR (scf/min) x (60 min/1hr) x (1/379 scf/lb-mole) x Supply Gas MW x VOC wt. Fraction x Control EfficiencyPotential Controlled Emissions (tons/yr) = lb/hr VOC x Hours of Operation x 1 ton/2000 x Number of Pumps

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Pneumatic Pump 
Pneumatic Controllers Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Pneumatic Source 

Consumption 

Rate* (scf/hr)

Supply Gas 

Molecular 

Weight**

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt Fraction 

(%)

Hours of 

Operation***

(hrs/yr)

Number of 

Controllers 

Potential VOC 

Emissions

(lbs/hr)

Potential VOC 

Emissions

(tons/yr)

Potential HAP 

Emissions

(lbs/hr)

Potential HAP 

Emissions

(tons/yr)

17.40 28.46 41.42% 3.50% 4380 4.0 0.54 4.7 0.05 0.4

Notes:*PSCR = Pneumatic Source Consumption Rate (scf/min), as per manufacturers literature.**Gas MW = Supply Gas Average Molecular Weight (lb/lb-mole).***Hours the pump is in operation annually. For winter months only, please enter 4380 hours.Example Calculations

Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.

Potential Emissions (lb/hr) = PSCR (scf/min) x (60 min/1hr) x (1/379 scf/lb-mole) x Supply Gas MW x VOC wt. FractionPotential Emissions (tons/yr) = lb/hr VOC x Hours of Operation x 1 ton/2000 x Number of Pumps

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Pneumatic Controller 
Tank Flare Combustion - Greenhouse Gases Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

Maggie Old Dog USA 24-19H

CO2 from

Component "I"

Gas Burned

(scf)

Gas Mol

Fraction

of "I"

Mol

Factor

of "I"

Conversion

Factor

@100% 

Tonnes 

CO2

Flare @ 98%, 

tonnes

CH4 50,032,010 0.07242 1 0.0000526 190.6 187

C2H6 50,032,010 0.24148 2 0.0000526 1271.0 1,246

C3H8 50,032,010 0.33425 3 0.0000526 2638.9 2,586

Iso-C4H10 50,032,010 0.04619 4 0.0000526 486.2 477

Nor-C4H10 50,032,010 0.15573 4 0.0000526 1639.3 1,607

Iso-C5H12 50,032,010 0.02605 5 0.0000526 342.8 336

Nor-C5H12 50,032,010 0.03643 5 0.0000526 479.4 470

C6 and + 50,032,010 0.03406 6 0.0000526 537.8 527

CO2 50,032,010 0.00285 1 0.0000526 7.5 8

0.94946 tonnes CO2 from combustion 7,442

uncombusted methane as CO2e 29

total tankflare GHG as CO2e, tonnes 7,471

tpy 8,237

Tank Flare Gas GHG Emissions
Natural Gas Combustion (Treater Burner) - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HEmission Factor Table

value custom default units value custom default units value custom default units 

Natural Gas Fossil-gaseous 0.001028 1.028E-03 MMBtu/scf 53.02 53.02 kg/MMBtu 0.001 1.0E-03 kg/MMBtu 

Notes:a) Default values for natural gas were obtained from the EPA Greenhouse Gas Reporting Rule (10/30/2009) Tables C-1 and C-2.b) Please convert any custom values to the specified default units.Annual GHG Calculation (By GHG Rule Eq. C-2a and C-2b)

Fuel Use

(MMBtu/hr)

Fuel Use

(MMBtu/yr) Calculation Tier(a)

0.70 6,132 Tier 1

CO2 CH4 N2O TOTAL

53.02 0.001 0.0001 --

325 0.006 0.0006 --

1 21 310 --

325 0.13 0.19 325358 0.14 0.21 359

Notes:Color Key:

Required DataOptional Data (Provide if Available)

CH4 Emission Factor 

Estimated GHG Emissions (tons CO2e)

b) Emission factors (EF) for natural gas were obtained from Tables C-1 and C-2 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).c) Global warming potentials (GWP) were obtained from Table A-1 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).

Fuel Fuel Classification Higher Heating Value CO2 Emission Factor

ParameterEF(b) (kg/MMBtu)

Estimated GHG Emissions (metric tons)GWP(c) (kg CO2e/kg)

Estimated GHG Emissions (metric tons CO2e)

a) The default HHV value from Table C-1 of the EPA Greenhouse Gas Reporting Rule is substituted when no actual HHV data from fuel sampling is available. Use of the default HHV value constitutes the Tier 1 calculation method while use of HHV values obtained from fuel sampling constitutes Tier 2.

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Natural Gas 
Natural Gas Pneumatic Device Venting - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HEmission Factor Table*

Population 

Emission Factors - 

All Components, 

Gas Service

Valve Connector Open-Ended Line Pressure Relief Valve

Low Continuous Bleed 

Pneumatic Device 

Vents**

High Continuous Bleed 

Pneumatic Device 

Vents**

Intermittent Bleed 

Pneumatic Device 

Vents**

Pneumatic Pumps**

Emission Factor 

(scf/hour/

component)

0.123 0.017 0.032 0.196 1.8 48.1 17.4 13.3

Notes:*Default values were obtained from the EPA Greenhouse Gas Reporting Rule Table W-1A - Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production (Western U.S.)

**Emission Factor is in units of scf/hour/device or scf/hour/pumpAnnual GHG Calculation

Count - Continuous 

High Bleed

EF - Continuous High 

Bleed

(scf/hour/device)

Count - Continuous 

Low Bleed

EF - Continuous Low 

Bleed

(scf/hour/device)

Count - Intermittent 

Bleed

EF - Intermittent 

Bleed

(scf/hour/device)

Concentration of CH4 in 

Produced Natural Gas

(GHGi)

Concentration of CO2 in 

Produced Natural Gas

(GHGi)

Conversion (Convi) 

from standard cubic 

feet CH4 to 

metric tons CO2e 

Co

fro

m

2.0 48.1 0.0 1.8 0.0 17.4 47% 1% 0.000410 

Emissions in Metric Tons CO2e (GHG Rule Eq. W-1)

Continuous 

High Bleed - 

CH4 Emissions 

(metric tons CO2e)

Continuous 

High Bleed - 

CO2 Emissions 

(metric tons CO2e)

Continuous 

Low Bleed - 

CH4 Emissions (metric 

tons CO2e)

Continuous 

Low Bleed - 

CO2 Emissions (metric 

tons CO2e)

Intermittent Bleed - 

CH4 Emissions 

(metric tons CO2e)

Intermittent Bleed - 

CO2 Emissions (metric 

tons CO2e)

Total

CH4 Emissions 

(metric tons CO2e)

Total

CO2 Emissions 

(metric tons CO2e)

Total 

GHG Emissions 

(metric tons CO2e)

163.22 0.50 0.00 0.00 0.00 0.00 163.22 0.50 163.72

Emissions in Metric Tons CH4

Continuous 

High Bleed 

(metric tons CH4)

Continuous 

Low Bleed - 

(metric tons CH4)

Intermittent Bleed - 

(metric tons CH4)

Total

CH4 Emissions (metric 

tons CH4)

7.77 0.00 0.00 7.77

Notes:a) Calculation for Natural Gas Pneumatic Device Venting found in 98.233(a) Equation W-1 -Masss,I = Count * EF * GHGi * Convi * 24 *365Masss,I = Annual total mass GHG emissions in metric tons CO2e

Count = Total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each typeEF = Population emission factorsGHGi = Concentration of GHGi, CH4 or CO2 in produced natural gas (For facilities in 98.230(a)(3)-(a)(8), GHGi = 1)

Convi = Conversion from scf to metric tons CO2e, 0.000410 for CH4 or 0.00005357 for CO2

b) Global warming potentials (GWP) were obtained from Table A-1 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Pneumatic Device Venting 
Natural Gas Pneumatic Pumps - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HEmission Factor Table*

Population 

Emission Factors - 

All Components, 

Gas Service

Pneumatic Pumps**

Emission Factor 

(scf/hour/

component)

13.3

Notes:*Default values were obtained from the EPA Greenhouse Gas Reporting Rule Table W-1A - Default Whole Gas Emission Factors for Onshore Petroleum and Natural 

**Emission Factor is in units of scf/hour/device or scf/hour/pumpAnnual GHG Calculation

Count - Pneumatic 

Pumps

EF - Pneumatic 

Pumps

(scf/hour/device)

Concentration of CH4 

in Produced Natural 

Gas

(GHGi)

Concentration of CO2 

in Produced Natural 

Gas

(GHGi)

Conversion (Convi) 

from standard cubic 

feet CH4 to 

metric tons CO2e 

Conversion (Convi) 

from standard cubic 

feet CO2 to 

metric tons CO2e 

Global Warming 

Potential (GWP) - CH4

(kg CO2e/kg)

2.0 13.3 47.2% 1.115% 0.000410 0.00005357 21

Emissions in Metric Tons CO2e (GHG Rule Eq. W-1)

Pneumatic Pumps

CH4 Emissions 

(metric tons CH4)

Pneumatic Pumps

CH4 Emissions 

(metric tons CO2e)

Pneumatic Pumps

CO2 Emissions (metric 

tons CO2e)

Total 

GHG Emissions 

(metric tons CO2e)

2.15 45.13 0.14 45.27

Notes:a) Calculation for Natural Gas Pneumatic Device Venting found in 98.233(a) Equation W-2 -Masss,I = Count * EF * GHGi * Convi * 24 *365Masss,I = Annual total mass GHG emissions in metric tons CO2e

Count = Total number of natural gas pneumatic pumpsEF = Population emission factorsGHGi = Concentration of GHGi, CH4 or CO2 in produced natural gas (For facilities in 98.230(a)(3)-(a)(8), GHGi = 1)

Convi = Conversion from scf to metric tons CO2e, 0.000410 for CH4 or 0.00005357 for CO2

b) Global warming potentials (GWP) were obtained from Table A-1 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Pneumatic Pumps 
Gas Production (Western U.S.).

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Pneumatic Pumps 
Associated Gas Venting and Flaring - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HAnnual Volumetric Natural Gas Emissions (cubic feet) (GHG Rule Eq. W-18)

Gas to Oil Ratio (GOR)

(cubic feet of 

gas/barrel of oil)

Volume of Oil Produced 

(V)

(barrels/year)

Annual Volumetric 

Natural Gas Emissions

(Ea,n) (cubic feet)

Percent of Annual 

Volumetric Natural 

Gas Not Flared (%)

Annual Volumetric 

Natural Gas Emissions -

Not Flared (cubic feet)

1,000.00 511,000.00 511,000,000.00 0% 0.00

Calculation for Venting Emissions found in 98.233(m) Equation W-18Ea,n = GOR * V

Natural Gas Volumetric Emissions - Standard Conditions (GHG Rule Eq. W-33)

Natural Gas Volumetric 

Emissions at Actual 

Conditions (Ea,n) (cubic 

feet)

Temperature at 

Standard Conditions (T s) 

(°F)

Temperature at Actual 

Emission Conditions 

(Ta) (°F)

Absolute Pressure at 

Standard Conditions 

(Ps) (psia)

Absolute Pressure at 

Actual Conditions 

(Pa) (psia)

Natural Gas Volumetric 

Emissions at STP 

(Es,n) (cubic feet)

0.00 60.00 60.00 14.70 13.60 0.00

Calculation for Natural Gas Volumetric Emissions - Standard Conditions found in 98.233(t) Equation W-33GHG Volumetric Emissions (cubic feet) (GHG Rule Eq. W-35)

Natural Gas Volumetric 

Emissions at Actual 

Conditions (Es,n) (cubic 

feet)

Mole Fraction (Mi) - CH4 Mole Fraction (Mi) - CO2 CH4 Volumetric Emissions at STP (Es,i) (cubic feet) CO2 Volumetric Emissions at STP (Es,i) (cubic feet)

0.00 0.47 0.01 0.00 0.00

Calculation for GHG Volumetric Emissions found in 98.233(u) Equation W-35Es,i = Es,n * Mi

GHG Mass Emissions (metric tons CO2e) (GHG Rule Eq. W-36)

CH4 Volumetric 

Emissions at STP (Es,i)

(cubic feet)

CO2 Volumetric 

Emissions at STP (Es,i)

(cubic feet)

Density (Pi) of CO2 Density (Pi) of CH4

Global Warming 

Potential (GWP) of CO2

(kg CO2e/kg)

Global Warming Potential 

(GWP) of CH4

(kg CO2e/kg)

Mass Emissions at 

Standard Conditions 

(Massi) - CO2

(metric tons CO2e)

Mass Emissions at 

Standard Conditions 

(Massi) - CH4

(metric tons CO2e)

Mass Emissions at Standard 

Conditions (Massi) - Total

(metric tons CO2e)

Mass Emissio

Standard Con

(Massi) - C

(metric tons 

0.00 0.00 0.0538 0.0196 1 21 0.00E+00 0.00E+00 0.00E+00 0.00E+0

Calculate GHG mass emissions in CO2e at standard conditions by converting the GHG volumetric emissions into mass emissions

Calculation for GHG Mass Emissions found in 98.233(v) Equation W-36Masss,i = Es,i * Pi * GWP * 10-3

*Density was assumed to be at standard conditions, 68°F and 14.7 psia.Es,i = GHGi (either CH4 or CO2) volumetric emissions at standard conditions in cubic feetEs,n = Natural gas volumetric emissions at standard conditions in cubic feetMi = Mole fraction of GHGi in the natural gas. 98.233(u)(2) - Annual average mole fraction for each facility as specified in 98.233(u)(2)(i) - GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities. If you have a continuous gas composition analyzer for produced natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use your most recent gas composition based on available sample analysis of the field.Masss,i = GHGi (either CH4 or CO2) mass emissions at standard conditions in metric tons CO2e

Es,i = GHGi (either CH4 or CO2) volumetric emissions at standard conditions in cubic feet

Pi = Density of GHGi. Use 0.0538 kg/ft3 for CO2 and N2O, and 0.0196 kg/ft3 for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O, and 0.0193 kg/ft3 

for CH4 at 60°F and 14.7 psia.

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O

Ea,n = Annual volumetric natural gas emissions from associated gas venting, in cubic feet

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravitiesV = Volume of oil produced in barrels in the calendar year during which associated gas was vented or flaredEs,n = Ea,n * (459.67 + Ts) * Pa

 (459.67 + T a) * PsEs,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet

Ea,n = Natural Gas Volumetric Emissions at Actual Conditions in Cubic Feet

Ts = Temperature at standard conditions (°F)

Ta = Temperature at actual emission conditions (°F)

Ps = Absolute pressure at standard conditions (psia)

Pa = Absolute pressure at actual conditions (psia)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Gas Venting (Unflared) 
Flare Stack Emissions - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HGHG Volumetric Emissions at Actual Conditions (cubic feet)Annual Un-Combusted CH4 Emissions (cubic feet) (GHG Rule Eq. W-19)

Volume of Gas Flared 

(Va)

(cubic feet/yr)

Fraction of Gas 

Combusted by 

Burning Flare (n) (%)

Mole Fraction of CH4 in 

Flared Gas (XCH4)

Annual 

Un-Combusted CH4 

Emissions (Ea,CH4) 

(cubic feet)

511,000,000.00 98% 0.47 4,827,846.2400

Calculation for Flare Stack Emissions - Annual Un-Combusted CH4 Emissions found in 98.233(n) Equation W-19Ea,CH4 (un-combusted) = Va * (1 - n) * XCH4

Annual Un-Combusted CO2 Emissions (cubic feet) (GHG Rule Eq. W-20)

Volume of Gas Flared 

(Va)

(cubic feet/yr)

Mole Fraction of CO2 

in Flared Gas (XCO2)

Annual 

Un-Combusted CO2 

Emissions (Ea,CO2) 

(cubic feet)

511,000,000.00 0.01 5,699,694.00

Calculation for Flare Stack Emissions - Annual Un-Combusted CO2 Emissions found in 98.233(n) Equation W-20

Ea,CO2 (un-combusted) = Va * XCO2Annual Combusted CO2 Emissions (cubic feet) (GHG Rule Eq. W-21)

Volume of Gas Flared 

(Va)

(cubic feet/yr)

Fraction of Gas 

Combusted by 

Burning Flare (n)(%)

Annual 

Combusted CO2 

Emissions (Ea,CO2)

(cubic feet)

511,000,000.00 98% 896,934,538.50

Calculation for Flare Stack Emissions - Annual Combusted CO2 Emissions found in 98.233(n) Equation W-21

Ea,CO2 (combusted) = ∑j n * Va * Yj * RjEa,CH4 (un-combusted) = Contribution of annual un-combusted CH4 emissions from flare stack in cubic feet, under actual conditions

Va = Volume of gas sent to flare in cubic feet, during the year

n = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, n is zeroXCH4 = Mole fraction of CH4 in gas to the flare

Ea,CO2 (un-combusted) = Contribution of annual un-combusted CO2 emissions from flare stack in cubic feet, under actual conditions

Va = Volume of gas sent to flare in cubic feet, during the year

XCO2 = Mole fraction of CO2 in gas to the flare

Ea,CO2 (combusted) = Contribution of annual combusted CO2 emissions from flare stack in cubic feet, under actual conditions

Va = Volume of gas sent to flare in cubic feet, during the year

n = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, n is zeroYj = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus)

Rj = Number of carbon atoms in the gas hydrocarbon constituents j: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentane plus

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Flare Stacks 
Flare Stack Emissions - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HNatural Gas Volumetric Emissions - Standard Conditions (GHG Rule Eq. W-33)

Natural Gas Volumetric 

Emissions at Actual 

Conditions (Ea,n) (cubic 

feet)

Temperature at 

Standard Conditions 

(Ts) (°F)

Temperature at Actual 

Emission Conditions (Ta) 

(°F)

Absolute Pressure at 

Standard Conditions (Ps) 

(psia)

Absolute Pressure at 

Actual Conditions (Pa) 

(psia)

Natural Gas Volumetric 

Emissions at STP (Es,n)

(cubic feet)

511,000,000.00 60.00 60.00 14.70 13.60 472,761,904.76

Calculation for Natural Gas Volumetric Emissions - Standard Conditions found in 98.233(t) Equation W-33

GHG Mass Emissions (metric tons CO2e) (GHG Rule Eq. W-36)

CH4 Volumetric 

Emissions at STP (Es,i)

(cubic feet)

CO2 Volumetric 

Emissions at STP (Es,i) 

(cubic feet)

Density (Pi) of CO2 Density (Pi) of CH4

Global Warming Potential 

(GWP) of CO2

(kg CO2e/kg)

Global Warming Potential 

(GWP) of CH4

(kg CO2e/kg)

Mass Emissions at Standard 

Conditions (Massi) - CO2

(metric tons CO2e)

Mass Emissions at Standard 

Conditions (Massi) - CH4

(metric tons CO2e)

Mass 

Con

4,827,846.24 902,634,232.50 0.0538 0.0196 1 21 4.86E+04 1.99E+03 

Calculate GHG mass emissions in CO2e at standard conditions by converting the GHG volumetric emissions into mass emissions

Calculation for GHG Mass Emissions found in 98.233(v) Equation W-36Masss,i = Es,i * Pi * GWP * 10-3

*Potential N2O emissions from fuel combustion in the flare are assumed to be negligible.

**Density was assumed to be at standard conditions, 68°F and 14.7 psia.

Subpart W Equation W-40 Treater Flare Negligibility Check

HHV, mmBtu/scf (eq. W-40) 1.235E-03

EF, kg N2O/mmBtu 1.00E-04

convert kg to metric tons 1.00E-03

combusted gas volume, scf/yr 511,000,000

N2O, metric tons 6.3E-02N2O emissions are negligibleEs,n = Ea,n * (459.67 + Ts) * Pa

 (459.67 + Ta) * PsEs,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet

Ea,n = Natural Gas Volumetric Emissions at Actual Conditions in Cubic Feet

Ts = Temperature at standard conditions (°F)

Ta = Temperature at actual emission conditions (°F)

Ps = Absolute pressure at standard conditions (psia)

Pa = Absolute pressure at actual conditions (psia)

Masss,i = GHGi (either CH4 or CO2) mass emissions at standard conditions in metric tons CO2e

Es,i = GHGi (either CH4 or CO2) volumetric emissions at standard conditions in cubic feet

Pi = Density of GHGi. Use 0.0538 kg/ft3 for CO2 and N2O, and 0.0196 kg/ft3 for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O, 

and 0.0193 kg/ft3 for CH4 at 60°F and 14.7 psia.

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O

6Attachment 2 - Calculations for EPA Air Registration.xlsx, GHG - Flare Stacks 
Bakken Pool Oil and Gas Production Facilities

Air Pollution Control Permitting & Compliance Guidance - May 2, 2011North Dakota Department of Health - Division of Air QualityDefault FactorsOil/Condensate Tank Data

Vapor Recovery Unit 

or Oil Stabilizer

Enclosed Smokeless 

Combustor

Utility Flare or Other 98% DRE 

Device G

97.91 2000 45.19 79.8 2.26 99 98 98 

Control Requirements

If first date of production occurred after June 1, 2011, tank emissions must be controlled by a ground it flare or other control device that achieves at least 90% DRE for VOCs upon startup of the facility.Facilities must calculate VOC PTE within 90 days after the first day of production.If PTE for VOC emissions is < 20 tpy, then a minimum of a ground pit flare (90% DRE) is required.If PTE for VOC emissions is > 20 tpy, then a control device that achieves at least 98% DRE must be installed and operated.

Treater Gas Data

Enclosed Smokeless 

Combustor

Utility Flare or Other 98% 

DRE Device

Ground Pit Flare or Other 

90% DRE Device Connected to Sales Line

98 98 90 100

Control Requirements

Treater gas must be routed to a gas gathering pipeline as soon as practicable in accordance with North Dakota Industrial Commission Requirements.When a pipeline is not available, treater gas is required to be routed to a control system or device (appropriate devices are included in the table above).

Treater Burner Data

NOx CO VOC HAPS

8,760 100 84 5.5 1.89

*Taken from AP-42, Tables 1.4-1, 1.4-2 and 1.4-3 - Emission Factors from Natural Gas Consumption. Based on average heating value of 1020 Btu/scf of natural gas.

Truck Loading Data

Submerged Loading of a 

Clean Cargo Tank

Submerged Loading: 

Dedicated Normal Service

Submerged Loading: 

Dedicated Vapor 

Balance Service

Oil is Hauled by Truck Oil is Sold through LACT 0.5 0.6 1 Refer to Table 2 on Truck Loading tab Refer to Table 2 on Truck Loading tab If no specific data, use estimated average annual temperature

Emissions calculated using formula provided in AP-42.Saturation factors taken from AP-42, Table 5.2-1 - Saturation (S) Factors for Calculating Petroleum Liquid Loading Loss.P and M values taken from Table 7.1-2 - Properties of Selected Petroleum Liquids.Control Requirements

Bakken Pool O&G production facilities are not required to route emissions displaced from truck loading activities to a control system or device due to safety concerns.However, the owner/operator shall follow any operating and/or construction requirements established in Chapters 33-15-07 and 33-15-20 of the North Dakota Air Pollution Control Rules.

Destruction Devices and Efficiency (%) Default Bakken EF 

(scf/bbl)

Lower Heating Value of 

Tank Vapors

(Btu/scf)

Molecular Weight of Tank 

Vapors

(lb/lb-mole)

VOC Weight Fraction of 

Tank Vapor Gas (C3+) (%)

HAP Weight Fraction 

of Tank Vapor Gas (%)

Destruction Devices and Efficiency (%)

Sales Method

Mode of Operation and Appropriate Saturation Factor Molecular Weight of 

Tank Vapors 

(lb/lb-mole)

Vapor Pressure of 

Liquid Loaded

(psia)

Temperature of Bulk Liquid 

Loaded (°F)

Hours of Operation Natural Gas Emission Factors* (lb/MMscf)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, NDDoH Default Factors 28 of 36 
Bakken Pool Oil and Gas Production Facilities

Air Pollution Control Permitting & Compliance Guidance - May 2, 2011North Dakota Department of Health - Division of Air QualityDefault FactorsPneumatic Pumps Data

Routed Exhaust Back into 

Closed Loop System

Routed Exhaust to a 

Combustion Device

4,380 100 98

Control Requirements

Bakken Pool O&G production facilities are required to control pneumatic pumps that use natural gas as the motive gas, if the PTE of VOCs from the pneumatic pump is > 5 tpy per pump.

Pneumatic Controllers Data

There are not default factors for pneumatic controllers. Emissions are calculated based on the following: number of controllers, gas usage or bleed rate (scf/hr), VOC/HAP weight fraction, molecular weight and hours of operationControl RequirementsBakken Pool O&G production facilities are not required to install add-on controls for emissions from these types of devices.

Glycol Dehydrator Data

VOC Emissions (tpy) HAP Emissions (tpy)

0 0

Use emissions calculated in GRI-GLYCalc V4 software; if no Glycol Dehydrator is installed, enter 0.

RICE Engines Data

Hours of Operation

NOx AP-42 

Emissions Factor

(g/hp-hr)

CO AP-42 

Emissions Factor

(g/hp-hr)

VOC AP-42 

Emissions Factor

(g/hp-hr)

NOx Control Efficiency CO Control Efficiency VOC Control Efficiency

8,760

Manufacturer data, actual 

test results or 

AP-42 emission factors

Manufacturer data, actual 

test results or 

AP-42 emission factors

Manufacturer data, actual 

test results or 

AP-42 emission factors

Manufacturer data or 

actual test results

Manufacturer data or 

actual test results

Manufacturer data or 

actual test results

While emission factors from actual stack testing, manufacturer's engine data, and AP-42 are acceptable, actual test data is usually the most accurate and preferred method.Control Requirements

NDDoH does not require any specific air pollution control equipment; however, the RICE must be in compliance with all State and Federal Rules and Regulations.See the Federal Rules and Regulations tab for specifics regarding applicable Federal Rules.

Annual Hours of Operation - 

Winter Months Only

Control Devices and Efficiency (%)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, NDDoH Default Factors 29 of 36 
US EPA

AP 42, Compilation of Air Pollutant Emission FactorsApplicable TablesOil/Condensate Tank and Treater Flare

13.5-1 - Emission Factors for Flare Operations

Total Hydrocarbonsb 0.14

Carbon Monoxide 0.37

Nitrogen Oxides 0.068

Sootc 0 - 274

b Measured as methane equivalent.

Treater Burner Data

Table 1.4-1 - Emission Factors for Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from Natural Gas Combustion

Combustor Type

(MMBtu/hr Heat Input)

NOx Emission Factor

(lb/106 scf)

CO Emission Factor

(lb/106 scf)

Uncontrolled (Pre-NSPS) 280 84

Uncontrolled (Post-NSPS) 190 84

Controlled - Low NOx Burners 140 84

Controlled - Flue Gas Recirculation 100 84

Uncontrolled 100 84

Controlled - Low NOx Burners 50 84

Controlled - Low NOx Burner / 

Flue Gas Recirculation

32 84

Uncontrolled 170 24

Controlled - Flue Gas Recirculation 76 98

Uncontrolled 94 40

Units are in lb/MMscf of natural gas fired. To convert from lb/106 scf to lb/MMBtu, divide by 1,020.

Component Emission Factor

(lb/106 Btu)

c Soot in concentration values: nonsmoking flares, 0 micrograms per liter (ug/l); lightly 

smoking flares, 40 mg/l; average smoking flares, 177 ug/l; and heavy smoking flares, 274 ug/l.Large Wall-Fired Boilers (>100)Small Boilers (< 100)Tangential-Fired Boilers (All Sizes)Residential Furnaces (< 0.3)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, AP-42 Tables 30 of 36 
US EPA

AP 42, Compilation of Air Pollutant Emission FactorsApplicable Tables

Table 1.4-2 - Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion

Pollutant 

Emission Factor

(lb/106 scf)

CO2 120,000

Lead 0.0005

N2O (Uncontrolled) 2.2

N2O (Controlled - Low NOx Burner) 0.64

PM (Total) 7.6

PM (Condensable) 5.7

PM (Filterable) 1.9

SO2 0.6

TOC 11

Methane 2.3

VOC 5.5

PM is assumed to be less than 1.0 micrometer in diameter. Therefore, the PM emission factors may be used to estimate PM10 and PM2.5.

SO2 is based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content is natural gas of 2,000 grains/106 scf.

Table 1.4-3 - Emission Factors for Speciated Organic Compounds from Natural Gas Combustion

Emission factors are included in the Natural Gas Combustion calculations.

Truck Loading 

Table 5.2-1 - Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses

Cargo Carrier Mode of Operation S Factor

Submerged loading of a 

clean cargo tank 0.50

Submerged loading: 

dedicated normal service 0.60

Submerged loading: 

dedicated vapor balance 

service

1.00

Splash loading of a clean 

cargo tank 1.45

Splash loading: dedicated 

normal service 1.45

Splash loading: dedicated 

vapor balance service 1.00

Tank Trucks and Rail Tank Cars

6Attachment 2 - Calculations for EPA Air Registration.xlsx, AP-42 Tables 31 of 36 
US EPA

AP 42, Compilation of Air Pollutant Emission FactorsApplicable Tables

Table 7.1-2 - Properties (MV, PVA, WL) of Selected Petroleum Liquids

40°F 50°F 60°F 70°F 80°F 90

Crude Oil RVP 5 50 7.1 1.8 2.3 2.8 3.4 4 4

Distillate Fuel Oil No. 2 130 7.1 0.0031 0.0045 0.0065 0.0090 0.012 0.0

Gasoline RVP 7 68 5.6 2.3 2.9 3.5 4.3 5.2 6

Gasoline RVP 7.8 68 5.6 2.5929 3.2079 3.9363 4.793 5.7937 6.9Gasoline RVP 8.3 68 5.6 2.7888 3.444 4.2188 5.1284 6.1891 7.4

Gasoline RVP 10 66 5.6 3.4 4.2 5.2 6.2 7.4 8

Gasoline RVP 11.5 65 5.6 4.087 4.9997 6.069 7.3132 8.7519 10.4

Gasoline RVP 13 62 5.6 4.7 5.7 6.9 8.3 9.9 11

Gasoline RVP 13.5 62 5.6 4.932 6.0054 7.2573 8.7076 10.3774 12.2Gasoline RVP 15.0 60 5.6 5.5802 6.774 8.1621 9.7656 11.6067 13.7

Jet Kerosene 130 7.0 0.0041 0.0060 0.0085 0.011 0.015 0.0

Jet Naphtha (JP-4) 80 6.4 0.8 1 1.3 1.6 1.9 2

Residual Oil No. 6 190 7.9 0.00002 0.00003 0.00004 0.00006 0.00009 0.00

RICE Engines Data

Table 3.3-1 - Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines

lb/hp-hr

(Power Output)

lb/MMBtu

(Fuel Input)

lb/hp-hr

(Power Output)

lb/MMBtu

(Fuel Input)

NOx 0.011 1.63 0.031 4.41

CO 6.96E-03 0.99 6.68E-03 0.95

SOx 5.91E-04 0.084 2.05E-03 0.29

PM10 7.21E-04 0.1 2.20E-03 0.32

CO2 1.08 154 1.15 64

Aldehydes 4.85E-04 0.07 4.63E-04 0.07

TOC - Exhaust 0.015 2.1 2.47E-03 0.35

TOC - Evaporative 6.61E-04 0.09 0.00 0.00

TOC - Crankcase 4.85E-03 0.69 4.41E-05 0.01

TOC - Refueling 1.08E-03 0.15 0.00 0.00

Table 3.3-2 - Speciated Organic Compound Emission Factors for Uncontrolled Diesel Engines

Emission factors are included in the RICE calculations.

True Vapor Pressure, PVA (psi)

Pollutant

Gasoline Fuel

Emission Factors

Diesel Fuel

Emission Factors

Petroleum Liquid Vapor Molecular Weight @ 60°F, MV (lb/lb-mole) Liquid Density @ 60°F, WL (lb/gal)

6Attachment 2 - Calculations for EPA Air Registration.xlsx, AP-42 Tables 32 of 36 
Federal Rules and Regulations Applicable to the Oil and Gas Industry

This regulation document is provided by the North Dakota Department of Health for information purposes only.Please reference the rule for complete applicability and full details.40 CFR Part 60 - New Source Performance Standards (NSPS)

Subpart Applicability and Description Subpart Reviewed for Applicability

Subpart IIII - Stationary Compression Ignition 

Internal Combustion Engines

Applies to any compression ignition internal combustion engine where construction is commenced after July 11, 2005 where the engine is manufactured after April 1, 2006 NA

Subpart JJJJ - Stationary Spark Ignition Internal 

Combustion Engines

Applies to any spark ignition internal combustion engine where construction is commenced after June 12, 2006 where the engine is manufactured:- After July 1, 2007 for engines > 500 hp- After July 1, 2008 for lean-burn engines 500 < hp < 1350- After July 1, 2008 for engines < 500 hp- After January 1, 2009 for emergency engines

only 8 hp gasoline engine on site

Subpart GG - Stationary Gas Turbines

Applies to all stationary gas turbines with a heat input ≥ 10 MMBtu/hr based on the lower heating value of the fuel where construction is commenced after October 3, 1997 but before February 18, 2005

NA

Subpart KKKK - Stationary Combustion Turbines

Applies to stationary gas turbines with a heat input ≥ 10 MMBtu/hr based on the higher 

heating value of the fuel where construction, modification or reconstruction is commenced after February 18, 2005

NA

Subpart Kb - Volatile Organic Liquid (VOL) Storage 

Vessels (Including Petroleum Liquid Storage 

Vessels) for which Construction, Reconstruction 

or Modification Commenced after July 23, 1984

Applies to each storage vessel with a capacity of ≥ 75 m3 that is used to store VOL for which 

construction, reconstruction, or modification commenced after July 23, 1984. Common exceptions to this rule include:- Does not apply to storage vessels with a capacity > 151 m3 storing a liquid with a maximum 

true vapor pressure less than 3.5 kilopascals (kPa)- Does not apply to vessels with a capacity of 75 ≥ m3 < 151 storing a liquid with a maximum 

true vapor pressure less than 15.0 kPa- Does not apply to vessels with a design capacity < 1,589.874 m3 used for petroleum or 

condensate stored, processed or treated prior to custody transfer

NA - prior to custody transfer

Subpart Dc - Small Industrial - Commercial - 

Institutional Steam Generating Units

Applies to all steam generating units for which construction, modification or reconstruction is commenced after June 9, 1989 and that has a maximum design capacity of 10 ≥ MMBtu/hr < 

100

NA

Subpart KKK - Equipment Leaks of VOC from 

Onshore Natural Gas Processing Plants Applies to affected facilities at onshore natural gas processing plants NA

Subpart LLL - Onshore Natural Gas Processing: 

SO2 Emissions

Applies to each sweetening unit and each sweetening unit followed by a sulfur recovery unit at facilities that process natural gas NA

Existing NSPS covers only natural gas processing 

plants and the proposal would cover additional 

emission points including: well completions (and 

re-completions), compressors, pneumatic 

controllers, storage vessels (condensate and 

crude oil tanks.

EPA is under a consent decree deadline to take 

final action on these rules by February 28, 2012

- Would limit VOC emissions from gas wells as they are being prepared for production, a process called "well completion".- Would apply to all hydraulically fractured (fracked) wells, both new wells and existing wells that are fracked or refracked to get more gas out of a well. - Would require combination of green completion and flaring for most fractured wells. Achieve 95% VOC reduction and 90% recovery of salable natural gas. Require flaring in situations not meeting criteria for reduced emissions completion where flaring is not a hazard.- Would require VOC reductions from other operations in the oil and gas sector including: - Compressors, which help move natural gas along a pipeline. Centrifugal and reciprocating compressors would be required to reduce VOC emissions. - Pneumatic Controllers, which regulate pressure, flow and temperature. Cover units 

located at gas processing plants and compressor stations. - Storage Tanks, located at wells and other production facilities. Reduce VOC emissions by 95%. - Onshore Natural Gas Processing Plants. Strengthen leak detection and repair 

requirements of existing NSPS.

NA - stil proposed

EnginesTurbinesTanksHeatersNatural Gas Processing Plants**Based on the EPA document "Addressing Air Emissions from the Oil and Natural Gas Industry - Overview of EPA's Proposed New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants".EPA Review - Natural Gas Processing Plants*

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Federal Rules 33 of 36 
Federal Rules and Regulations Applicable to the Oil and Gas Industry

This regulation document is provided by the North Dakota Department of Health for information purposes only.Please reference the rule for complete applicability and full details.40 CFR Part 63 - National Emission Standards for Hazardous Air Pollutants (MACT)

Subpart Applicability and Description Subpart Reviewed for Applicability

Subpart ZZZZ - Stationary Reciprocating Internal 

Combustion Engines

Applies to any (new, existing, modified and reconstructed) reciprocating internal combustion engines located at a major source or area source of hazardous air pollutants (HAPs). only 8 hp gasoline engine on site

Subpart HH - Oil and Gas Production Facilities

Applies to all oil and gas production facilities that are major and area sources of HAPs with the

following exceptions:- A facility that exclusively processes, stores or transfers black oil- A major source prior to the point of custody transfer with a facility-wide annual average natural gas throughput < 18.4 thousand cubic meters/day and a facility-wide annual hydrocarbon liquid throughput < 37,700 liters/day.

The facility will be a synthetic minor 

source

Subpart HHH - Natural Gas Transmission and 

Storage Facilities 

Applies to owners and operators of natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end user and that are major sources of HAP emissions.

NA

Proposal for Air Toxics - Oil and Gas Production 

Facilities and Natural Gas Transmission and 

Storage Facilities*

EPA is under a consent decree deadline to take 

final action on these rules by February 28, 2012

Technology Review

- No available cost-effective technologies for controlled glycol dehydrators and storage tanks that could achieve greater reductions that current standards.- Standard for equipment leaks has been made more stringent.Review identified unregulated emission points, and proposal includes provisions to reduce emissions- Glycol Dehydrators - Establish limits for small dehydrators at major sources.- Storage Tanks (Oil and Gas Production Only) - Regulate all crude oil and condensate tanks at major sources. Remove throughput, API gravity and gas/oil ratio criteria.Risk Review- Rule proposes to reduce amount of air toxics allowed to be emitted. - Eliminate the 1 tpy benzene compliance option for glycol dehydrators at major sources (Oil and Gas Production and Natural Gas Transmission/Storage).

NA - stil proposed

EnginesProposal for Air Toxics - Oil and Gas Production Facilities and Natural Gas Transmission and Storage Facilities*

*Based on the EPA document "Addressing Air Emissions from the Oil and Natural Gas Industry - Overview of EPA's Proposed New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants".Oil and Gas Production FacilitiesNatural Gas Transmission and Storage Facilities

6Attachment 2 - Calculations for EPA Air Registration.xlsx, Federal Rules 34 of 36 
Average Casinghead Gas Analysis Data

Compou

MW Wt Gross 

lb/lb-mole lb Btu/sc

oxygen n 0.000% 32.00 0.0000 0.00% 0 nitrogen n 2.717% 28.013 0.7611 2.67% 0 H2S n 0.000% 34.076 0.0000 0.00% 637.1 

CO2 n 1.115% 44.01 0.4909 1.73% 0 

C1 / CH4 n 47.239% 16.043 7.5786 26.63% 1010.0 C2 n 26.069% 30.07 7.8389 27.55% 1796.6 C3 y 14.617% 44.10 6.4455 22.65% 2516.1 C4, iso y 1.569% 58.12 0.9122 3.21% 3251.9 C4, n y 3.766% 58.12 2.1888 7.69% 3262.3 C5, iso y 0.594% 72.15 0.4289 1.51% 4000.9 C5, n y 1.131% 72.15 0.8162 2.87% 4008.9 C6+ y 1.182% 84.18 0.9953 3.50% 4755.9 

Totals 100.00% 28.46 100.00% 

weight % VOC: 41.42%

Heat

Component VOC Mole2 % Wt%
(If speciated by lab, enter HAPs at bottom of sheet, not lumped with carbon numbers)

(enter composition in %, not mole fraction)

Gas Source: Average from 4 existing locations collected by Comm Engineering

Sample Date: 05/28/09-06/05/09

Compound Gas

Correction Mole % Net LHV

Mole % Calculations w/o air Mole Wt Wt Wt% Btu/scf Btu/scf

oxygen 0.000% 0.000% 0.000% 32.00 0.0000 0.00% 0 0.0

nitrogen 5.055% 5.055% 5.055% 28.01 1.4161 3.21% 0 0.0

hydrogen sulfide 0.000% 0.000% 0.000% 34.08 0.0000 0.00% 586.8 0.0

carbon dioxide 0.285% 0.285% 0.285% 44.01 0.1254 0.28% 0 0.0

methane 7.242% 7.242% 7.242% 16.04 1.1618 2.63% 909.4 65.9

ethane 24.148% 24.148% 24.148% 30.07 7.2613 16.46% 1618.7 390.9

propane 33.425% 33.425% 33.425% 44.10 14.7394 33.41% 2314.9 773.8

isobutane 4.619% 4.619% 4.619% 58.12 2.6847 6.09% 3000.4 138.6

n-butane 15.573% 15.573% 15.573% 58.12 9.0515 20.52% 3010.8 468.9

isopentane 2.605% 2.605% 2.605% 72.15 1.8795 4.26% 3699.0 96.4

n-pentane 3.643% 3.643% 3.643% 72.15 2.6284 5.96% 3706.9 135.0

n-hexane 0.736% 0.736% 0.736% 86.18 0.6343 1.44% 4403.8 32.4

hexanes, other 1.222% 1.222% 1.222% 84.18 1.0287 2.33% 4403.8 53.8

heptanes 0.987% 0.987% 0.987% 100.21 0.9891 2.24% 5100.0 50.3

octanes 0.035% 0.035% 0.035% 114.23 0.0400 0.09% 5796.1 2.0

nonanes 0.043% 0.043% 0.043% 128.26 0.0552 0.13% 6493.2 2.8

decanes plus 0.002% 0.002% 0.002% 142.29 0.0028 0.01% 7189.6 0.1

benzene 0.047% 0.047% 0.047% 78.11 0.0367 0.08% 3590.9 1.7

toluene 0.019% 0.019% 0.019% 92.14 0.0175 0.04% 4273.6 0.8

ethylbenzene 0.004% 0.004% 0.004% 106.17 0.0042 0.01% 4970.5 0.2

xylenes 0.006% 0.006% 0.006% 106.17 0.0064 0.01% 4957 0.3

2,2,4-trimethylpentane 0.305% 0.305% 0.305% 114.23 0.3484 0.79% 5738 17.5

(should total 100%) 100.00% 100.00% 100.00% 44.11 100.00% 2231.4

gas gravity 1.5229

gas rate, mscfd weight % VOC (C3+) 77.41% weight % HAPS 2.37%

mole % VOC 63.27%

TANK VENT EMISSION CALCULATION

Marathon Oil Company
Attachment 3 – Revised Maximum Production Rate with Gas Sales Calculation Sheet
GREEN = Requires input

RED = No input required. This is a calculated value.

Facility InformationMaggie Old Dog USA 24-19H Name of the facility, with well numbers (if known).

TBD First date of production or the date of modification of the facility.9/30/2011 Date registration packet is submitted to the NDDoH.Production Data DescriptionAnnual Avg BOPD 2200 This is the projected facility average BOPD on an annualized basisAnticipated GOR, scf/bbl 1000 Expected produced oil GORAnnual Avg Treater Gas (Mscfd) 2200 This is the calculated annual average mscfd of gas for the facility.Oil/Condensate Tank Data DescriptionFlash Gas Method: Default Bakken EF Use the drop down menu to choose the appropriate flash gas method.Bakken EF scf/bbl 97.91 The scf/bbl from direct measurement or representative sample. If specific data is not available, use the Bakken default of 97.91.Estimated Tank Vapors (scfd) 215402 This is the estimated scfd of tank vapors based on the following: adjusted BOPD multiplied by the scf/bbl entered under the Production Data Lower Heating Value 2231 Lower heating value (Btu/scf) of tank vapors. If site specific data is not available, use the Bakken default value of 2000.Molecular Weight 44.11 Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole). If site specific data is not available, use the Bakken default value VOC% 77.41% VOC weight fraction of the tank vapor gas (C3+). If site specific data is not available, use the Bakken default value of 79.8%.HAP% 2.37% HAP weight fraction of the tank vapor gas. If site specific data is not available, use the Bakken default value of 2.26%.H2S weight % 0.000% H2S weight percent of the tank vapor gas.H2S mole % 0.000% H2S mole percent of the tank vapor gas.Enclosed Smokeless Combustor Use the drop down menu to choose the appropriate emission control type.Control Destruction Efficiency 98% Control efficiency of any applicable controls. This is a fixed number based on control type.Treater Gas Data DescriptionBtu/scf 1,612 Btu/scf of wellstream gas. Molecular Weight 28.46 Average molecular weight of the wellstream gas in lb/lb-mole.Specific Gravity 1 If necessary to convert specific gravity to molecular weight, enter the specific gravity of the wellstream gas.Calculated Molecular Weight 28.96 This is the calculated molecular weight based on the specific gravity entered above.VOC% 41.42% VOC weight fraction of the wellstream gas (Note: Weight%, not Mole%). HAP% 3.50% HAP weight fraction of the wellstream gas. (Note: Weight%, not Mole%). H2S weight % 0.000% H2S weight percent of the wellstream gasH2S mole % 0.000% H2S mole percent of the wellstream gasConnected to sales line Use the drop down menu to choose the appropriate emission control type.Control Destruction Efficiency (DE 1) 100% Control efficiency of any applicable controls (combustor, pit flare, utility flare, etc).Hours of Operation 8760 Hours of Operation at Destruction Efficiency 1

Input Data

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Input 1 of 36 
Input Data

Treater Burner(s) DescriptionTotal Btu/hr 700,000 Total burner rating for the heater treater burner(s) in btu/hr. If there are multiple burners, add the total heat input together.Hours of Operation 8,760 The burner(s) is/are assumed to operate 8,760 hours per year.Truck Loading DescriptionOil is hauled by truck Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a LACT, no input values are required for the TrucSubmerged loading: dedicated normal service 0.6 Use the drop down list to choose the appropriate mode of operation. The saturation factor will automatically be selected based on mode of oMolecular Weight 44.11 Molecular weight of tank vapors in lb/lb-mole. If no site specific data is available, please refer to Table 2 on the Truck Loading tab.Vapor Pressure 1.90 True vapor pressure of liquid loaded, pounds per square inch absolute (psia) If no site specific data is available, please refer to Table 2 on thTemperature 41.33 Temperature of bulk liquid loaded in Fahrenheit. If no site specific data is available, use an estimated average annual temperature.Load Rate (bbl/hr) 200 Load rate of liquid loaded in barrels per hour.Load Time (hrs) 1.00 The time it takes to loadout one load (hrs).Pneumatic Pumps DescriptionNumber of Pneumatic Pumps 2 Number of pneumatic pumps at facility.Hours of Operation 4380 Hours the pump is in operation annually. For winter months only, please enter 4380 hours.scf/min 0.50 Pneumatic source consumption rate as per manufacturer data (scf/min).Vented to atmosphere Use the drop down menu to choose the appropriate emission control type.Control Efficiency 0% Control efficiency of any applicable controls (combustor, routing exhaust to fuel supply, VRU, etc).Pneumatic Controllers DescriptionNumber of Pneumatic Controllers 4 Number of pneumatic controllers at facility.Bleed rate (scf/hr) 17.40 Average bleed rate of device (scf/hr).Glycol Dehydrator DescriptionVOC (TPY) 0.00 VOC emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).HAP (TPY) 0.00 HAP emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Input 2 of 36 
Number of Engines 2

RICE Engine #1Hours of Operation 120Maximum HP Rating 8NOx g/hp-hr 4.99CO g/hp-hr 3.16VOC g/hp-hr 6.8NOx Control Efficiency 0%CO Control Efficiency 0%VOC Control Efficiency 0%RICE Engine #2Hours of Operation 120Maximum HP Rating 8NOx g/hp-hr 4.99CO g/hp-hr 3.16VOC g/hp-hr 6.8NOx Control Efficiency 0%CO Control Efficiency 0%VOC Control Efficiency 0%RICE Engine #3Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%

Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

RICE Input Data

Enter the number of engines that will be installed at the production facility.

Description

Recycle pump engine operates less than 10 hours per month.Manufacturer's maximum hp rating.

Description

Recycle pump engine operates less than 10 hours per month.Manufacturer's maximum hp rating.

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Rice Input 3 of 36 
RICE Input Data

RICE Engine #4Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #5Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #6Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #7Hours of Operation 0

NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TO

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Rice Input 4 of 36 
RICE Input Data

Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #8Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #9Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #10Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daManufacturer's maximum hp rating.

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Rice Input 5 of 36 
RICE Input Data

NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #11Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%RICE Engine #12Hours of Operation 0Maximum HP Rating 100NOx g/hp-hr 10CO g/hp-hr 5VOC g/hp-hr 4NOx Control Efficiency 90%CO Control Efficiency 75%VOC Control Efficiency 70%

NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOManufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) foManufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TONOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer daNOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer datCO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer da

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Rice Input 6 of 36 
GREEN = Requires input

RED = No input required. This is a calculated value.

Facility InformationMaggie Old Dog USA 24-19H Name of the facility and the well number.TBD First date of production or the date of modification of the facility.9/30/2011 Date registration packet is submitted to the NDDoH.Natural Gas Pneumatic Device Venting DescriptionCount - Total Number of Continuous High Bleed Natural Gas Pneumatic Devices 2Count - Total Number of Continuous Low Bleed Natural Gas Pneumatic Devices 0Count - Total Number of Intermittent Bleed Natural Gas Pneumatic Devices 0Concentration in Produced Natural Gas - CH4 47% Concentration of CH4 in produced natural gas. For facilities in 98.230(a)(3)-(a)(8), GHGi = 1Concentration in Produced Natural Gas - CO2 1% Concentration of CO2, in produced natural gas. For facilities in 98.230(a)(3)-(a)(8), GHGi = 1Associated Gas Venting and Flaring DescriptionGas to Oil Ratio (GOR) 1000 Gas to Oil ratio in cubic feet of gas per barrel of oil. Oil refers to hydrocarbon liquids produced of all API gVolume of Oil Produced (barrels/year) 803000 Volume of oil produced in barrels in the calendar year during which associated gas was vented or flaredVolumetric Emissions - Gas Venting & Flaring DescriptionTemperature at standard conditions (°F) 60 Temperature at standard conditions (°F) - TsTemperature at actual emission conditions (°F) 60 Temperature at actual emission conditions (°F) - TaAbsolute pressure at standard conditions (psia) 14.7 Absolute pressure at standard conditions (psia) - PsAbsolute pressure at actual conditions (psia) 13.6 Absolute pressure at actual conditions (psia) - PaMole Fraction in Natural Gas - CH4 0.47

Mole Fraction in Natural Gas - CO2 0.01115

Gas Venting and Flare Stack Emissions DescriptionField Gas or Process Vent Gas Use the drop down menu to choose the appropriate type of fuel vented.

High Heat Value (HHV) 1.235E-03 Default High Heat Value based on 40 CFR 98 Table C-1 or 40 CFR 98.233(z)(6)(ii)Percent of Gas Flared 100% Percent of gas sent to flare in cubic feet, during the yearFraction of Gas Combusted by Burning Flare 100% Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, n is zeroMole Fraction of Methane 0.47 Mole fraction of gas hydrocarbon constituentsMole Fraction of Ethane 0.26 Mole fraction of gas hydrocarbon constituentsMole Fraction of Propane 0.15 Mole fraction of gas hydrocarbon constituentsMole Fraction of Butane 0.0534 Mole fraction of gas hydrocarbon constituentsMole Fraction of Pentanes-Plus 0.03 Mole fraction of gas hydrocarbon constituents

GHG Calculations Input Data

1st Calendar Year - Count the total of each type, or count any percentage number of each type plus an engi2nd Calendar Year - Count the total of each type, or count any percentage number of each type plus an eng3rd Calendar Year - Complete the count of all pneumatic devices, including any changes to equipment counFollowing Years - Update the total count of pneumatic devices and adjust accordingly to reflect any modificMole fraction of GHGi in the natural gas. 98.233(u)(2) - Annual average mole fraction for each facility as speGHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities. If ythese values for determining the mole fraction. If you do not have a continuous gas composition analyzer, of the field.

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG Calculations Input 7 of 36 
VOC NOx CO SO2 PM PM10 PM2.5

Oil/Condensate Tanks 70.84 5.96 32.46 -- -- -- --Treater Flare 0.00 0.00 0.00 0.00 -- -- --Treater Burner 0.02 0.30 0.25 0.002 0.02 0.02 0.02RICE Engine 0.01 0.01 0.01 0.00 0.00 0.00 0.00Truck Loading 16.31 -- -- -- -- -- --Pneumatic Pump 4.09 -- -- -- -- -- --Pneumatic Controllers 4.74 -- -- -- -- -- --Glycol Dehydrator 0.00 -- -- -- -- -- --Totals (TPY) 96.01 6.28 32.71 0.00 0.02 0.02 0.02PSD Threshold* 250 250 250 250 250 250 250Is Threshold Exceeded? No No No No No No NoPSD Modification Threshold* 40 40 100 40 25 15 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 100 100 100 100 100 100Is Threshold Exceeded? No No No No No No NoMinor NSR Rule Threshold*** 5 10 10 10 10 5 3Is Threshold Exceeded? Yes No Yes No No No No

Pb NH3 Fluorides H2SO4 H2S TRS RSC

Oil/Condensate Tanks -- -- -- -- -- -- --Treater Flare -- -- -- -- 0.00 -- --Treater Burner -- -- -- -- -- -- --RICE Engine -- -- -- -- -- -- --Truck Loading -- -- -- -- -- -- --Pneumatic Pump -- -- -- -- -- -- --Pneumatic Controllers -- -- -- -- -- -- --Glycol Dehydrator -- -- -- -- -- -- --Totals (TPY) 0.00 0.00 0.00 0.00 0.00 0.00 0.00PSD Threshold* 250 - 250 250 250 250 250Is Threshold Exceeded? No No No No No No NoPSD Modification Threshold* 0.6 - 3 7 10 10 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 - 100 100 100 100 100Is Threshold Exceeded? No No No No No No NoMinor NSR Rule Threshold*** 0.1 - 1 2222Is Threshold Exceeded? No No No No No No No

Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements**Title V Thresholds taken from the Major Source definition contained in 40 CFR 70.2***Minor NSR Rule Thresholds are found in Table 1 to 40 CFR 49.153, Minor NSR Thresholds (Attainment Areas)

*PSD Threshold taken from 40 CFR 52.21(b)(1)(i)(b), oil and gas well facilities are not 1 of the 28 designated source categories listed in 40 CFR 52.21(b)(1)(i)(a) thus the applicability threshold is 250 tpy. PSD Modification Thresholds taken from 40 CFR 52.21(b)(23)(i).

Controlled Criteria Air Pollutants Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Emission Source

REGULATED CRITERIA AIR POLLUTANTS PTE (TPY) - Controlled

REGULATED AIR POLLUTANTS (TPY) - Controlled

Emission Source

Marathon Oil Company

Maggie Old Dog USA 24-19H

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Emission Summary - Controlled 
VOC NOx CO SO2 PM PM10 PM2.5

Oil/Condensate Tanks 3541.80 5.96 32.46 -- -- -- --Treater Flare 12486.62 44.02 239.54 0.00 -- -- --Treater Burner 0.02 0.30 0.25 0.002 0.02 0.02 0.02RICE Engine 0.01 0.01 0.01 0.00 0.00 0.00 0.00Truck Loading 16.31 -- -- -- -- -- --Pneumatic Pump 4.09 -- -- -- -- -- --Pneumatic Controllers 4.74 -- -- -- -- -- --Glycol Dehydrator 0.00 -- -- -- -- -- --Totals (TPY) 16053.59 50.30 272.26 0.002 0.02 0.02 0.02PSD Threshold* 250 250 250 250 250 250 250Is Threshold Exceeded? Yes No Yes No No No NoPSD Modification Threshold* 40 40 100 40 25 15 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 100 100 100 100 100 100Is Threshold Exceeded? Yes No Yes No No No NoMinor NSR Rule Threshold*** 5 10 10 10 10 5 3Is Threshold Exceeded? Yes Yes Yes No No No No

Pb NH3 Fluorides H2SO4 H2S TRS RSC

Oil/Condensate Tanks -- -- -- -- -- -- --Treater Flare -- -- -- -- 0.00 -- --Treater Burner -- -- -- -- -- -- --RICE Engine -- -- -- -- -- -- --Truck Loading -- -- -- -- -- -- --Pneumatic Pump -- -- -- -- -- -- --Pneumatic Controllers -- -- -- -- -- -- --Glycol Dehydrator -- -- -- -- -- -- --Totals (TPY) 0.00 0.00 0.00 0.00 0.00 0.00 0.00PSD Threshold* 250 - 250 250 250 250 250Is Threshold Exceeded? No No No No No No NoPSD Modification Threshold* 0.6 - 3 7 10 10 10Is Threshold Exceeded? N/A N/A N/A N/A N/A N/A N/ATitle V Threshold** 100 - 100 100 100 100 100Is Threshold Exceeded? No No No No No No NoMinor NSR Rule Threshold*** 0.1 - 1 2222Is Threshold Exceeded? No No No No No No No

Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements**Title V Thresholds taken from the Major Source definition contained in 40 CFR 70.2***Minor NSR Rule Thresholds are found in Table 1 to 40 CFR 49.153, Minor NSR Thresholds (Attainment Areas)

Uncontrolled Criteria Air Pollutants Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

Maggie Old Dog USA 24-19H

REGULATED AIR POLLUTANTS (TPY) - Uncontrolled

Emission Source

*PSD Threshold taken from 40 CFR 52.21(b)(1)(i)(b), oil and gas well facilities are not 1 of the 28 designated source categories listed in 40 CFR 52.21(b)(1)(i)(a) thus the applicability threshold is 250 tpy. PSD Modification Thresholds taken from 40 CFR 52.21(b)(23)(i).

REGULATED CRITERIA AIR POLLUTANTS PTE (TPY) - Uncontrolled

Emission Source

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Emission Summary - Uncontrolled 
CO2e CO2 CH4 N2O

Oil/Condensate Tanks & Fugitive Equipment Leaks**** Negligible Negligible Negligible --Gas Venting (Flared) 8.96E+04 8.96E+04 2.18E+00 --Gas Venting (Unflared) 0.00E+00 0.00E+00 0.00E+00 --Treater Burner 325.44 325.12 0.13 0.19RICE Engine 1.04 1.04 -- --Truck Loading -- -- -- --Pneumatic Pump 45.27 0.14 2.15 --Pneumatic Controllers 163.72 0.50 7.77 --Glycol Dehydrator -- -- -- --Totals (metric tons/year) 90,134 89,880 12 0.19GHG Reporting Threshold* 25,000 -- -- --Note: Subpart W requires reporting these emissions as part of the larger basin reporting.

CO2e CO2 CH4 N2O

Oil/Condensate Tanks & Fugitive Equipment Leaks**** Negligible Negligible Negligible --Gas Venting (Flared) 98765.70 9.87E+04 2.40E+00 --Gas Venting (Unflared) 0.00E+00 0.00E+00 0.00E+00Treater Burner 358.73 358.38 0.14 0.21RICE Engine 1.04 1.04 -- --Truck Loading -- -- -- --Pneumatic Pump 49.90 0.15 2.37 --Pneumatic Controllers 180.47 0.56 8.57 --Glycol Dehydrator -- -- -- --Totals (tpy) 99,355.85 99,075.36 13.48 0.21Title V Threshold** 100,000 -- -- --Is Threshold Exceeded? No -- -- --PSD Threshold*** 100,000 -- -- --Is Threshold Exceeded? No -- -- --

 Due to the nature of these types of emissions sources (i.e., oil/condensate tanks and fugitive equipment leaks) potential emissions of regulated GHG emissions have been assumed to be negligible.

Greenhouse Gas Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

Maggie Old Dog USA 24-19H

GREENHOUSE GAS EMISSIONS PTE (metric tons/year)

Emission Source

** *PSD Threshold for GHG taken from PSD and Title V Permitting Guidance for Greenhouse Gases prepared by the US EPA Office of Air Quality Planning and Standards in March 2011. PSD applicability threshold is 75,000 tpy CO2e for 

modifications at existing PSD sources, 100,000 tpy CO2e for new sources and 100/250 tpy mass basis.

**Title V Threshold for GHG taken from PSD and Title V Permitting Guidance for Greenhouse Gases prepared by the US EPA Office of Air Quality Planning and Standards in March 2011.Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.*GHG Reporting Threshold taken from 40 CFR 98.2(3)(iii).

GREENHOUSE GAS EMISSIONS PTE (tpy)

Emission Source

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG Emission Summary 
Total HAPs Benzene Toluene Hexane Ac

Oil/Condensate Tanks 2.17 -- -- -- Treater Flare 0.00 -- -- -- Treater Burner 5.67E-03 6.31E-06 1.02E-05 5.41E-03 RICE Engine -- -- -- -- Truck Loading -- -- -- -- Pneumatic Pump 0.35 -- -- -- Pneumatic Controllers 0.40 -- -- -- Glycol Dehydrator -- -- -- -- Totals (TPY) 2.92 (no individual HAP exceeds 10 tpy)Title V Threshold* 25 10 10 10 Is Threshold Exceeded? No Yes No No 

Notes: Spreadsheets based on forms provided by North Dakota Department of Health and updated to reflect EPA requiremen

Treater flare HAPs conservatively calculated assuming all C6+ components are HAPs, as an extended analysis was not available

HAP Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

*HAP thresholds of 10 tpy of an individual regulated HAP and 25 tpy aggregate are taken from the Major Source definition coCFR 70.2. The thresholds of 10/25 tpy also represent what constitutes a major stationary source.

REGULATED HAZARDOUS AIR POLLUTANTS PTE (TPY)

Emission Source

Maggie Old Dog USA 24-19H

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, HAP Emission Summary 
Oil/Condensate Tanks Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Flare Gas Volume 

(scf/day)

Lower Heating 

Value (Btu/scf)

Molecular 

Weight 

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt 

Fraction (%)

Destruction 

Efficiency (%)

NOx Emission 

Factor

(lb/MMBtu)

CO Emission 

Factor

(lb/MMBtu)

215402.00 2231.38 44.11 77.41% 2.37% 98% 0.068 0.37

Pollutant Flare Gas Volume

(scf/hr)

scf/lb-mole

Molecular 

Weight 

(lb/lb-mole)

wt Fraction 

(%)

Heating Value

(Btu/scf)

Destruction 

Efficiency (%)

Potential 

Uncontrolled 

Emissions

(lbs/hr)

Potential 

Uncontrolled 

Emissions

(tons/year)

Potential 

Controlled 

Emissions

(lbs/hr)

Potential 

Controlled 

Emissions

(tons/year)

VOC 8975.08 0.0026 44.11 77.41% -- 98% 808.63 3541.80 16.17 70.84

HAP 8,975.08 0.0026 44.11 2.37% -- 98% 24.81 108.65 0.50 2.17

NOx 8,975.08 -- -- -- 2231.38 -- 1.36 5.965 1.36 5.965

CO 8,975.08 -- -- -- 2231.38 -- 7.41 32.46 7.41 32.46

Notes: NOx & CO emission factors are from AP-42 Table 13.5-1 - Emission Factors for Flare Operations.

Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirementsEmission estimates reflect combustion related air pollutants. If flare equipped with a pilot burner, heat input of burner should be evaluated.

Example Calculations

VOC and HAPS EmissionsPotential Controlled Emissions (lbs/hr) = (Flare Gas Volume (scf/hr) * scf/lb-mole * Molecular Weight (lb/lb-mole) * wt Fraction (%)) * 1 - Destruction Efficiency (%)Potential Controlled Emissions (tons/yr) = Potential Controlled Emissions (lbs/hr) * 8760 hrs/yr * 1/2000NOx and CO EmissionsPotential Controlled Emissions (lbs/hr) = Flare Gas Volume (scf/hr) * Heating Value (Btu/scf) * 1/1,000,000 * Emission Factor (lbs/MMBtu)Potential Controlled Emissions (tons/yr) = Potential Emissions (lbs/hr) * 8760 hrs/yr * 1/2000

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, OilCondensate Tanks 
Treater Flare Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Flare Gas 

Volume (scf/day)

Lower Heating 

Value (Btu/scf)

Molecular 

Weight 

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt 

Fraction (%)

NOx Emission 

Factor

(lb/MMBtu)*

CO Emission 

Factor

(lb/MMBtu)*

Destruction 

Efficiency 1 

(%)**

Hours of 

Operation at DE 1 

(hours)

Destruction 

Efficiency 2 (%)**

Hours of 

Operation at DE 2 

(hours)

2,200,000.00 1612.49 28.46 41.42% 3.50% 0.068 0.37 100% 8760 100% 0

Pollutant Flare Gas Volume (scf/hr) scf/lb-mole Molecular Weight (lb/lb-mole) wt Fraction (%) Heating Value (Btu/scf) Potential Uncontrolled Emissions (lbs/hr) Potential Uncontrolled Emissions (tons/year) Potential Controlled Emissions 1 (lbs) Potential Controlled Emissions 1 (tons) Potential Controlled Emissions 2 (lbs) Potential Controlled Emissions 2 (tons) Potential Total Controlled Emissions (lbs/hr) Potential Total Controlled Emissions (tons/year)

VOC 91,666.67 0.0026 28.46 41.42% -- 2850.83 12486.62 0.00 0.00 0.00 0.00 0.00 0.00

HAP 91,666.67 0.0026 28.46 3.50% -- 240.74 1054.43 0.00 0.00 0.00 0.00 0.00 0.00

H2S 91,666.67 0.0026 28.46 0.00% -- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

SO2 91,666.67 0.0026 64.00 0.00% -- 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NOx 91,666.67 -- -- -- 1612.49 10.05 44.02 -- -- -- -- 0.00 0.00

CO 91,666.67 -- -- -- 1612.49 54.69 239.54 -- -- -- -- 0.00 0.00

Notes: *NOx & CO emission factors are from AP-42 Table 13.5-1 - Emission Factors for Flare Operations.

**100% destruction efficiency means that the treater gas is routed and connected to the sales line (gas gathering pipeline).Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Example Calculations

VOC and HAPS EmissionsPotential Controlled Emissions (lbs/hr) = (Flare Gas Volume (scf/hr) * scf/lb-mole * Molecular Weight (lb/lb-mole) * wt Fraction (%)) * 1 - Destruction Efficiency (%)Potential Controlled Emissions (tons/yr) = Potential Controlled Emissions (lbs/hr) * Hours of Operation * 1/2000NOx and CO EmissionsPotential Controlled Emissions (lbs/hr) = Flare Gas Volume (scf/hr) * Heating Value (Btu/scf) * 1/1,000,000 * Emission Factor (lbs/MMBtu)Potential Emissions (tons/yr) = Potential Emissions (lbs/hr) * 8760 hrs/yr * 1/2000

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Treater Flare 
Treater Burner Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Burner Rating

(Btu/hr)

Burner Rating

(MMBtu/hr)

Average Natural 

Gas Higher 

Heating Value 

(Btu/scf)

NOx Emission 

Factor

(lb/106 scf)

CO Emission 

Factor

(lb/106 scf)

PM (Total) 

Emission Factor

(lb/106 scf)

PM 

(Condensable) 

Emission Factor

(lb/106 scf)

PM (Filterable) 

Emission Factor

(lb/106 scf)

SO2 Emission 

Factor

(lb/106 scf)

VOC Emission 

Factor

(lb/106 scf)

HAP Emission 

Factor

(lb/106 scf)

700,000.00 0.70 1,020 100 84 7.6 5.7 1.9 0.6 5.5 1.9

Pollutant Emission Factor (lb/MMBtu) Burner Rating (MMBtu/hr) Potential Emissions (lbs/hr) Potential Emissions (tons/year)

NOx 0.10 0.70 0.07 0.30

CO 0.08 0.70 0.06 0.25

PM (Total) 0.007 0.70 0.005 0.02

PM (Condensable) 0.006 0.70 0.004 0.02

PM (Filterable) 0.002 0.70 0.001 0.006

SO2 0.001 0.70 0.0004 0.002

VOC 0.005 0.70 0.004 0.02

HAPs 0.002 0.70 0.001 0.006

Notes: NOx, CO, PM, HAP, SO2 & VOC Emission Factors are from AP-42, Section 1.4 - Natural Gas Combustion, Tables 1.4-1, 1.4-2, and 1.4-3.Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Example Calculations

Potential Emissions (lbs/hr) = Emission Factor (lbs/MMBtu) * Burner Rating (MMBtu/hr)Potential Emissions (tons/yr) = Potential Emissions (lbs/hr) * 8760 hrs/yr * 1/2000

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Treater Burner 
Treater Burner - Regulated HAPs Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Formaldehyde Yes 7.35E-05 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 5.15E-05 2.25E-2-Methylnaphthalene Yes 2.35E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.65E-08 7.21E-3-Methylchloranthrene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-7,12-Dimethylbenz(a)anthracene Yes 1.57E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.10E-08 4.81E-Acenaphthene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Acenaphthylene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Anthracene Yes 2.35E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.65E-09 7.21E-Arsenic Yes 1.96E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.37E-07 6.01E-Benz(a)anthracene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Benz(a)pyrene Yes 1.18E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-10 3.61E-Benzene Yes 2.06E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.44E-06 6.31E-Benzo(b)fluoranthene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Benzo(g,h,i)perylene Yes 1.18E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-10 3.61E-Benzo(k)fluoranthene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Beryllium Yes 1.18E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 8.24E-09 3.61E-Cadmium Yes 1.08E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 7.55E-07 3.31E-Chromium Yes 1.37E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 9.61E-07 4.21E-Chrysene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Cobalt Yes 8.24E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 5.76E-08 2.52E-Dibenzo(a,h)anthracene Yes 1.18E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-10 3.61E-Dichlorobenzene Yes 1.18E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 8.24E-07 3.61E-Fluoranthene Yes 2.94E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 2.06E-09 9.02E-Fluorene Yes 2.75E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.92E-09 8.42E-Hexane Yes 1.76E-03 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-03 5.41E-Indeno(1,2,3-cd)pyrene Yes 1.76E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.24E-09 5.41E-Manganese Yes 3.73E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 2.61E-07 1.14E-Mercury Yes 2.55E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.78E-07 7.82E-

Naphthalene Yes 5.98E-07 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 4.19E-07 1.83E-Nickel Yes 2.06E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.44E-06 6.31E-Phenanathrene Yes 1.67E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 1.17E-08 5.11E-Pyrene Yes 4.90E-09 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 3.43E-09 1.50E-Selenium Yes 2.35E-08 AP-42 Nat. Gas Comb. (7/98), Table 1.4-4 1.65E-08 7.21E-Toluene Yes 3.33E-06 AP-42 Nat. Gas Comb. (7/98), Table 1.4-3 2.33E-06 1.02E-

Total (TPY)= 0.00

Equipment Heat Input (MMBtu/hr) Hours of Operation (hrs/yr)

Treater Burner 0.7 8760

TOTAL 0.7

Notes:

*Regulated under Section 112(b) for Clean Air Act.Example Calculation Estimated Uncontrolled Emissions (lbs/hr) = Emission Factor (lbs/MMBtu) x Heat Input Rate (MMBtu/hr)Estimated Uncontrolled Emissions (tons/yr) = Estimated Uncontrolled Emissions (lbs/hr) x Hours of Operation / 2000

Estimated Uncontr

(tons/

**Emission factors taken from AP-42, Chapter 1 - External Combustion Sources, Table 1.4-3 - Emission Factors for Speciated Organic Compounds from Natural Gas Combustion and Table 1.4-4 - Emission Factors for Metals from Natural Gas Combustion.

Pollutant HAP

*

Yes/No

Emission Factor

(lb/MMBtu)** Emission Factor Source Estimated Uncontrolled Emissions (lb/hr)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Treater Burner - HAPs 
Truck Loading Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Cargo Carrier Mode of Operation S Factor

Submerged loading of a clean cargo 

tank 0.50

Submerged loading: dedicated 

normal service 0.60

Submerged loading: dedicated vapor 

balance service 1.00

Table 2 - Vapor Pressure and Molecular Weight Values

40 50 60 70 80 90 100

Crude Oil RVP 5 50 4.5 7.1 1.8 2.3 2.8 3.4 4.0 4.8 5.7

Values based on AP-42, Chapter 7 - Liquid Storage Tanks, Table 7.1-2 - Properties (M v, PVA, WL) of Selected Petroleum Liquids.

Constant Saturation Factor (S) Vapor Pressure (P) (psi) Molecular Weight (M) (lb/lb-mole) Temperature (T) (°R) Loading Loss (lb/1,000 gal)

12.46 0.60 1.90 44.11 501 1.25

Loading Loss

(lb/1,000 gal) Truck Load Rate (bbl/hr) Truck Load Time (hrs) gal/bbl Annual bbl/yr

Potential 

Uncontrolled VOC 

Emissions 

(lbs/hr)

Potential 

Uncontrolled VOC 

Emissions 

(tons/yr)

Potential 

Uncontrolled C3+ 

VOC Emissions*

(tons/yr)

1.25 200.00 1.00 42.00 803000.00 10.50 21.08 16.31

Notes:*VOC weight fraction of the tank vapor gas (C3+). If site specific data is not available, use the Bakken default value of 79.8%.

Uncontrolled 

Potential VOC 

Emissions

(tons/yr)

Control (%) 1 - Control (%)

Controlled 

Potential VOC 

Emissions

(tons/yr)

16.31 0.00 1.00 16.31

Notes: Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirementsExample Calculations

Loading Loss (lb/1,000 gal) = Constant * Saturation Factor * Vapor Pressure * (Molecular Weight / Temperature)Potential Emissions (lbs/hr) = Loading Loss / 1000 * (Truck Load Rate / Truck Load Time) * gal/bblUncontrolled Potential Emissions (tons/yr) = (Loading Loss / 1000) * Annual bbl/yr * gal/bbl / 2000Controlled Potential Emissions (tons/yr) = Uncontrolled Emissions * 1 - Control Efficiency

AP-42 Equation

LL = 12.46 x (S x P x M)/TLL = Loading loss, pound per 1,000 gallons of liquid loaded (lb/1000 gal)S = Saturation factor (AP-42 Table 5.2-1)P = True vapor pressure of liquid loaded (psia) (AP-42 Table 7.1-2)M = Molecular weight of tank vapors (lb/lb-mol) (AP-42 Table 7.1-2)T = Temperature of bulk liquid loaded (°R) (°R = °F + 460)

Table 1 - Saturation Factor Variable

Tank Trucks and Rail 

Tank Cars

Factors based on AP-42, Section 5.2 - Transportation and Marketing of Petroleum Liquids, Table 5.2-1 - Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses.

True Vapor Pressure

Petroleum Liquid (psi) at various temperatures in °F Vapor MW at 60°F (lb/lb-mole) Condensed Vapor Density at 60°F (lb/gal) Liquid Density at 60°F (lb/gal)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Truck Loading 
Reciprocating Internal Combustion Gasoline Engines (RICE) Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Engine # Maximum HP Hours of Operation*** NOx DRE (%)** NOx Emission Factor (g/HP-HR)* CO DRE (%)** CO Emission Factor (g/HP-HR)* VOC DRE (%)** VOC Emission Factor (g/HP-HR)*

PM10 Emission 

Factor 

(g/HP-HR)*

SO2 Emission 

Factor 

(g/HP-HR)*

CO2 Emission 

Factor 

(g/HP-HR)*

Engine #1 8.00 120.00 0% 4.99 0% 3.16 0% 6.80 0.33 0.27 489.89Engine #2 8.00 120.00 0% 4.99 0% 3.16 0% 6.80 0.33 0.27 489.89Engine #3 100.00 0 90% 10.00 75% 5.00 70% 4.00 0.33 0.27 489.89Engine #4 100.00 0 90% 10.00 75% 5.00 70% 4.00 0.33 0.27 489.89

Notes:**Control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.***Engine is assumed to operate 8,760 hours per year.Uncontrolled Emissions

Pollutant Engine #1 Potential Emissions (lbs/hr) Engine #1 Potential Emissions (tons/yr) Engine #2 Potential Emissions (lbs/hr) Engine #2 Potential Emissions (tons/yr) Engine #3 Potential Emissions (lbs/hr) Engine #3 Potential Emissions (tons/yr) Engine #4 Potential Emissions (lbs/hr) Engine #4 Potential Emissions (tons/yr) Total Potential Uncontrolled Emissions (lbs/hr) Total Potential Uncontrolled Emissions (tons/yr)

NOx 0.09 0.01 0.09 0.01 2.20 0.00 2.20 0.00 4.59 0.01

CO 0.06 0.00 0.06 0.00 1.10 0.00 1.10 0.00 2.32 0.01

VOC 0.12 0.01 0.12 0.01 0.88 0.00 0.88 0.00 2.00 0.01

PM10 0.01 0.00 0.01 0.00 0.07 0.00 0.07 0.00 0.16 0.00

SO2 0.005 0.00 0.00 0.00 0.06 0.00 0.06 0.00 0.13 0.00

CO2 8.64 0.52 8.64 0.52 108.00 0.00 108.00 0.00 233.28 1.04

Controlled Emissions

Pollutant Engine #1 Potential Emissions (lbs/hr) Engine #1 Potential Emissions (tons/yr) Engine #2 Potential Emissions (lbs/hr) Engine #2 Potential Emissions (tons/yr) Engine #3 Potential Emissions (lbs/hr) Engine #3 Potential Emissions (tons/yr) Engine #4 Potential Emissions (lbs/hr) Engine #4 Potential Emissions (tons/yr) Total Potential Controlled Emissions (lbs/hr) Total Potential Controlled Emissions (tons/yr)

NOx 0.09 0.01 0.09 0.01 0.22 0.00 0.22 0.00 0.62 0.01

CO 0.06 0.00 0.06 0.00 0.28 0.00 0.28 0.00 0.66 0.01

VOC 0.12 0.01 0.12 0.01 0.26 0.00 0.26 0.00 0.77 0.01

PM10 0.01 0.00 0.01 0.00 0.07 0.00 0.07 0.00 0.16 0.00

SO2 0.005 0.00 0.00 0.00 0.06 0.00 0.06 0.00 0.13 0.00

CO2 8.640 0.52 8.64 0.52 108.00 0.00 108.00 0.00 233.28 1.04

Notes: Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Total Combined HP: 216.00

Total Hours of Operation: 240.00Example Calculations

Potential Controlled Emissions (lbs/hr) = HP x Emission Factor (g/HP-hr) / Conversion Factor x 1 - Control EfficiencyPotential Controlled Emissions (tons/yr) = Potential Emissions (lbs/hr) * Hours of Operation / 2000*Emission factors for NOx, CO and VOC are based on Manufacturer's emission factor, actual test results, or AP-42 factor in grams per horsepower hour (g/hp-hr). 

Emission factors for PM10, SO2, and CO2 are taken from AP-42, Table 3.3-1 - Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines. Factors are converted to g/hp-hr from lb/hphr.

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, RICE Engines 
Pneumatic Pumps Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Pneumatic Source 

Consumption 

Rate* (scf/min)

Supply Gas 

Molecular 

Weight**

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt Fraction 

(%)

Hours of 

Operation***

(hrs/yr)

Control 

Efficiency (%)

Number of 

Pumps 

Potential 

Uncontrolled 

VOC Emissions

(lbs/hr)

Potential 

Uncontrolled VOC 

Emissions

(tons/yr)

Potential 

Controlled VOC 

Emissions

(tons/yr)

Potential 

Uncontrolled 

HAP Emissions

(lbs/hr)

Potential 

Uncontrolled HAP 

Emissions

(tons/yr)

0.50 28.46 41.42% 3.50% 4380 1.00 2.0 0.93 4.1 4.1 0.08 0.3 

Notes:*PSCR = Pneumatic Source Consumption Rate (scf/min), as per manufacturers literature.**Gas MW = Supply Gas Average Molecular Weight (lb/lb-mole).***Hours the pump is in operation annually. For winter months only, please enter 4380 hours.Example Calculations

Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.Potential Controlled Emissions (lb/hr) = PSCR (scf/min) x (60 min/1hr) x (1/379 scf/lb-mole) x Supply Gas MW x VOC wt. Fraction x Control EfficiencyPotential Controlled Emissions (tons/yr) = lb/hr VOC x Hours of Operation x 1 ton/2000 x Number of Pumps

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Pneumatic Pump 
Pneumatic Controllers Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19H

Pneumatic Source 

Consumption 

Rate* (scf/hr)

Supply Gas 

Molecular 

Weight**

(lb/lb-mole)

VOC wt Fraction 

(%)

HAP wt Fraction 

(%)

Hours of 

Operation***

(hrs/yr)

Number of 

Controllers 

Potential VOC 

Emissions

(lbs/hr)

Potential VOC 

Emissions

(tons/yr)

Potential HAP 

Emissions

(lbs/hr)

Potential HAP 

Emissions

(tons/yr)

17.40 28.46 41.42% 3.50% 4380 4.0 0.54 4.7 0.05 0.4

Notes:*PSCR = Pneumatic Source Consumption Rate (scf/min), as per manufacturers literature.**Gas MW = Supply Gas Average Molecular Weight (lb/lb-mole).***Hours the pump is in operation annually. For winter months only, please enter 4380 hours.Example Calculations

Calculations based on forms provided by North Dakota Department of Health and updated to reflect EPA requirements.

Potential Emissions (lb/hr) = PSCR (scf/min) x (60 min/1hr) x (1/379 scf/lb-mole) x Supply Gas MW x VOC wt. FractionPotential Emissions (tons/yr) = lb/hr VOC x Hours of Operation x 1 ton/2000 x Number of Pumps

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Pneumatic Controller 
Tank Flare Combustion - Greenhouse Gases Emission Summary

US EPA - Region 8 Air Program

Federal New Source Review Program in Indian Country

Marathon Oil Company

Maggie Old Dog USA 24-19H

CO2 from

Component "I"

Gas Burned

(scf)

Gas Mol

Fraction

of "I"

Mol

Factor

of "I"

Conversion

Factor

@100% 

Tonnes 

CO2

Flare @ 98%, 

tonnes

CH4 78,621,730 0.07242 1 0.0000526 299.5 294

C2H6 78,621,730 0.24148 2 0.0000526 1997.3 1,957

C3H8 78,621,730 0.33425 3 0.0000526 4146.9 4,064

Iso-C4H10 78,621,730 0.04619 4 0.0000526 764.1 749

Nor-C4H10 78,621,730 0.15573 4 0.0000526 2576.1 2,525

Iso-C5H12 78,621,730 0.02605 5 0.0000526 538.6 528

Nor-C5H12 78,621,730 0.03643 5 0.0000526 753.3 738

C6 and + 78,621,730 0.03406 6 0.0000526 845.1 828

CO2 78,621,730 0.00285 1 0.0000526 11.8 12

0.94946 tonnes CO2 from combustion 11,694

uncombusted methane as CO2e 46

total tankflare GHG as CO2e, tonnes 11,740

tpy 12,943

Tank Flare Gas GHG Emissions
Natural Gas Combustion (Treater Burner) - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HEmission Factor Table

value custom default units value custom default units value custom default units 

Natural Gas Fossil-gaseous 0.001028 1.028E-03 MMBtu/scf 53.02 53.02 kg/MMBtu 0.001 1.0E-03 kg/MMBtu 

Notes:a) Default values for natural gas were obtained from the EPA Greenhouse Gas Reporting Rule (10/30/2009) Tables C-1 and C-2.b) Please convert any custom values to the specified default units.Annual GHG Calculation (By GHG Rule Eq. C-2a and C-2b)

Fuel Use

(MMBtu/hr)

Fuel Use

(MMBtu/yr) Calculation Tier(a)

0.70 6,132 Tier 1

CO2 CH4 N2O TOTAL

53.02 0.001 0.0001 --

325 0.006 0.0006 --

1 21 310 --

325 0.13 0.19 325358 0.14 0.21 359

Notes:Color Key:

Required DataOptional Data (Provide if Available)

CH4 Emission Factor 

Estimated GHG Emissions (tons CO2e)

b) Emission factors (EF) for natural gas were obtained from Tables C-1 and C-2 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).c) Global warming potentials (GWP) were obtained from Table A-1 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).

Fuel Fuel Classification Higher Heating Value CO2 Emission Factor

ParameterEF(b) (kg/MMBtu)

Estimated GHG Emissions (metric tons)GWP(c) (kg CO2e/kg)

Estimated GHG Emissions (metric tons CO2e)

a) The default HHV value from Table C-1 of the EPA Greenhouse Gas Reporting Rule is substituted when no actual HHV data from fuel sampling is available. Use of the default HHV value constitutes the Tier 1 calculation method while use of HHV values obtained from fuel sampling constitutes Tier 2.

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Natural Gas 
Natural Gas Pneumatic Device Venting - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HEmission Factor Table*

Population 

Emission Factors - 

All Components, 

Gas Service

Valve Connector Open-Ended Line Pressure Relief Valve

Low Continuous Bleed 

Pneumatic Device 

Vents**

High Continuous Bleed 

Pneumatic Device 

Vents**

Intermittent Bleed 

Pneumatic Device 

Vents**

Pneumatic Pumps**

Emission Factor 

(scf/hour/

component)

0.123 0.017 0.032 0.196 1.8 48.1 17.4 13.3

Notes:*Default values were obtained from the EPA Greenhouse Gas Reporting Rule Table W-1A - Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production (Western U.S.)

**Emission Factor is in units of scf/hour/device or scf/hour/pumpAnnual GHG Calculation

Count - Continuous 

High Bleed

EF - Continuous High 

Bleed

(scf/hour/device)

Count - Continuous 

Low Bleed

EF - Continuous Low 

Bleed

(scf/hour/device)

Count - Intermittent 

Bleed

EF - Intermittent 

Bleed

(scf/hour/device)

Concentration of CH4 in 

Produced Natural Gas

(GHGi)

Concentration of CO2 in 

Produced Natural Gas

(GHGi)

Conversion (Convi) 

from standard cubic 

feet CH4 to 

metric tons CO2e 

Co

fro

m

2.0 48.1 0.0 1.8 0.0 17.4 47% 1% 0.000410 

Emissions in Metric Tons CO2e (GHG Rule Eq. W-1)

Continuous 

High Bleed - 

CH4 Emissions 

(metric tons CO2e)

Continuous 

High Bleed - 

CO2 Emissions 

(metric tons CO2e)

Continuous 

Low Bleed - 

CH4 Emissions (metric 

tons CO2e)

Continuous 

Low Bleed - 

CO2 Emissions (metric 

tons CO2e)

Intermittent Bleed - 

CH4 Emissions 

(metric tons CO2e)

Intermittent Bleed - 

CO2 Emissions (metric 

tons CO2e)

Total

CH4 Emissions 

(metric tons CO2e)

Total

CO2 Emissions 

(metric tons CO2e)

Total 

GHG Emissions 

(metric tons CO2e)

163.22 0.50 0.00 0.00 0.00 0.00 163.22 0.50 163.72

Emissions in Metric Tons CH4

Continuous 

High Bleed 

(metric tons CH4)

Continuous 

Low Bleed - 

(metric tons CH4)

Intermittent Bleed - 

(metric tons CH4)

Total

CH4 Emissions (metric 

tons CH4)

7.77 0.00 0.00 7.77

Notes:a) Calculation for Natural Gas Pneumatic Device Venting found in 98.233(a) Equation W-1 -Masss,I = Count * EF * GHGi * Convi * 24 *365Masss,I = Annual total mass GHG emissions in metric tons CO2e

Count = Total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas pneumatic devices of each typeEF = Population emission factorsGHGi = Concentration of GHGi, CH4 or CO2 in produced natural gas (For facilities in 98.230(a)(3)-(a)(8), GHGi = 1)

Convi = Conversion from scf to metric tons CO2e, 0.000410 for CH4 or 0.00005357 for CO2

b) Global warming potentials (GWP) were obtained from Table A-1 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Pneumatic Device Venting 
Natural Gas Pneumatic Pumps - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HEmission Factor Table*

Population 

Emission Factors - 

All Components, 

Gas Service

Pneumatic Pumps**

Emission Factor 

(scf/hour/

component)

13.3

Notes:*Default values were obtained from the EPA Greenhouse Gas Reporting Rule Table W-1A - Default Whole Gas Emission Factors for Onshore Petroleum and Natural 

**Emission Factor is in units of scf/hour/device or scf/hour/pumpAnnual GHG Calculation

Count - Pneumatic 

Pumps

EF - Pneumatic 

Pumps

(scf/hour/device)

Concentration of CH4 

in Produced Natural 

Gas

(GHGi)

Concentration of CO2 

in Produced Natural 

Gas

(GHGi)

Conversion (Convi) 

from standard cubic 

feet CH4 to 

metric tons CO2e 

Conversion (Convi) 

from standard cubic 

feet CO2 to 

metric tons CO2e 

Global Warming 

Potential (GWP) - CH4

(kg CO2e/kg)

2.0 13.3 47.2% 1.115% 0.000410 0.00005357 21

Emissions in Metric Tons CO2e (GHG Rule Eq. W-1)

Pneumatic Pumps

CH4 Emissions 

(metric tons CH4)

Pneumatic Pumps

CH4 Emissions 

(metric tons CO2e)

Pneumatic Pumps

CO2 Emissions (metric 

tons CO2e)

Total 

GHG Emissions 

(metric tons CO2e)

2.15 45.13 0.14 45.27

Notes:a) Calculation for Natural Gas Pneumatic Device Venting found in 98.233(a) Equation W-2 -Masss,I = Count * EF * GHGi * Convi * 24 *365Masss,I = Annual total mass GHG emissions in metric tons CO2e

Count = Total number of natural gas pneumatic pumpsEF = Population emission factorsGHGi = Concentration of GHGi, CH4 or CO2 in produced natural gas (For facilities in 98.230(a)(3)-(a)(8), GHGi = 1)

Convi = Conversion from scf to metric tons CO2e, 0.000410 for CH4 or 0.00005357 for CO2

b) Global warming potentials (GWP) were obtained from Table A-1 of the EPA Greenhouse Gas Reporting Rule (40 CFR 98).

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Pneumatic Pumps 
Gas Production (Western U.S.).

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Pneumatic Pumps 
Associated Gas Venting and Flaring - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HAnnual Volumetric Natural Gas Emissions (cubic feet) (GHG Rule Eq. W-18)

Gas to Oil Ratio (GOR)

(cubic feet of 

gas/barrel of oil)

Volume of Oil Produced 

(V)

(barrels/year)

Annual Volumetric 

Natural Gas Emissions

(Ea,n) (cubic feet)

Percent of Annual 

Volumetric Natural 

Gas Not Flared (%)

Annual Volumetric 

Natural Gas Emissions -

Not Flared (cubic feet)

1,000.00 803,000.00 803,000,000.00 0% 0.00

Calculation for Venting Emissions found in 98.233(m) Equation W-18Ea,n = GOR * V

Natural Gas Volumetric Emissions - Standard Conditions (GHG Rule Eq. W-33)

Natural Gas Volumetric 

Emissions at Actual 

Conditions (Ea,n) (cubic 

feet)

Temperature at 

Standard Conditions (T s) 

(°F)

Temperature at Actual 

Emission Conditions 

(Ta) (°F)

Absolute Pressure at 

Standard Conditions 

(Ps) (psia)

Absolute Pressure at 

Actual Conditions 

(Pa) (psia)

Natural Gas Volumetric 

Emissions at STP 

(Es,n) (cubic feet)

0.00 60.00 60.00 14.70 13.60 0.00

Calculation for Natural Gas Volumetric Emissions - Standard Conditions found in 98.233(t) Equation W-33GHG Volumetric Emissions (cubic feet) (GHG Rule Eq. W-35)

Natural Gas Volumetric 

Emissions at Actual 

Conditions (Es,n) (cubic 

feet)

Mole Fraction (Mi) - CH4 Mole Fraction (Mi) - CO2 CH4 Volumetric Emissions at STP (Es,i) (cubic feet) CO2 Volumetric Emissions at STP (Es,i) (cubic feet)

0.00 0.47 0.01 0.00 0.00

Calculation for GHG Volumetric Emissions found in 98.233(u) Equation W-35Es,i = Es,n * Mi

GHG Mass Emissions (metric tons CO2e) (GHG Rule Eq. W-36)

CH4 Volumetric 

Emissions at STP (Es,i)

(cubic feet)

CO2 Volumetric 

Emissions at STP (Es,i)

(cubic feet)

Density (Pi) of CO2 Density (Pi) of CH4

Global Warming 

Potential (GWP) of CO2

(kg CO2e/kg)

Global Warming Potential 

(GWP) of CH4

(kg CO2e/kg)

Mass Emissions at 

Standard Conditions 

(Massi) - CO2

(metric tons CO2e)

Mass Emissions at 

Standard Conditions 

(Massi) - CH4

(metric tons CO2e)

Mass Emissions at Standard 

Conditions (Massi) - Total

(metric tons CO2e)

Mass Emissio

Standard Con

(Massi) - C

(metric tons 

0.00 0.00 0.0538 0.0196 1 21 0.00E+00 0.00E+00 0.00E+00 0.00E+0

Calculate GHG mass emissions in CO2e at standard conditions by converting the GHG volumetric emissions into mass emissions

Calculation for GHG Mass Emissions found in 98.233(v) Equation W-36Masss,i = Es,i * Pi * GWP * 10-3

*Density was assumed to be at standard conditions, 68°F and 14.7 psia.Es,i = GHGi (either CH4 or CO2) volumetric emissions at standard conditions in cubic feetEs,n = Natural gas volumetric emissions at standard conditions in cubic feetMi = Mole fraction of GHGi in the natural gas. 98.233(u)(2) - Annual average mole fraction for each facility as specified in 98.233(u)(2)(i) - GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities. If you have a continuous gas composition analyzer for produced natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use your most recent gas composition based on available sample analysis of the field.Masss,i = GHGi (either CH4 or CO2) mass emissions at standard conditions in metric tons CO2e

Es,i = GHGi (either CH4 or CO2) volumetric emissions at standard conditions in cubic feet

Pi = Density of GHGi. Use 0.0538 kg/ft3 for CO2 and N2O, and 0.0196 kg/ft3 for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O, and 0.0193 kg/ft3 

for CH4 at 60°F and 14.7 psia.

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O

Ea,n = Annual volumetric natural gas emissions from associated gas venting, in cubic feet

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravitiesV = Volume of oil produced in barrels in the calendar year during which associated gas was vented or flaredEs,n = Ea,n * (459.67 + Ts) * Pa

 (459.67 + T a) * PsEs,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet

Ea,n = Natural Gas Volumetric Emissions at Actual Conditions in Cubic Feet

Ts = Temperature at standard conditions (°F)

Ta = Temperature at actual emission conditions (°F)

Ps = Absolute pressure at standard conditions (psia)

Pa = Absolute pressure at actual conditions (psia)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Gas Venting (Unflared) 
Flare Stack Emissions - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HGHG Volumetric Emissions at Actual Conditions (cubic feet)Annual Un-Combusted CH4 Emissions (cubic feet) (GHG Rule Eq. W-19)

Volume of Gas Flared 

(Va)

(cubic feet/yr)

Fraction of Gas 

Combusted by 

Burning Flare (n) (%)

Mole Fraction of CH4 in 

Flared Gas (XCH4)

Annual 

Un-Combusted CH4 

Emissions (Ea,CH4) 

(cubic feet)

803,000,000.00 100% 0.47 0.0000

Calculation for Flare Stack Emissions - Annual Un-Combusted CH4 Emissions found in 98.233(n) Equation W-19Ea,CH4 (un-combusted) = Va * (1 - n) * XCH4

Annual Un-Combusted CO2 Emissions (cubic feet) (GHG Rule Eq. W-20)

Volume of Gas Flared 

(Va)

(cubic feet/yr)

Mole Fraction of CO2 

in Flared Gas (XCO2)

Annual 

Un-Combusted CO2 

Emissions (Ea,CO2) 

(cubic feet)

803,000,000.00 0.01 8,956,662.00

Calculation for Flare Stack Emissions - Annual Un-Combusted CO2 Emissions found in 98.233(n) Equation W-20

Ea,CO2 (un-combusted) = Va * XCO2Annual Combusted CO2 Emissions (cubic feet) (GHG Rule Eq. W-21)

Volume of Gas Flared 

(Va)

(cubic feet/yr)

Fraction of Gas 

Combusted by 

Burning Flare (n)(%)

Annual 

Combusted CO2 

Emissions (Ea,CO2)

(cubic feet)

803,000,000.00 100% 1,438,233,225.00

Calculation for Flare Stack Emissions - Annual Combusted CO2 Emissions found in 98.233(n) Equation W-21

Ea,CO2 (combusted) = ∑j n * Va * Yj * RjEa,CH4 (un-combusted) = Contribution of annual un-combusted CH4 emissions from flare stack in cubic feet, under actual conditions

Va = Volume of gas sent to flare in cubic feet, during the year

n = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, n is zeroXCH4 = Mole fraction of CH4 in gas to the flare

Ea,CO2 (un-combusted) = Contribution of annual un-combusted CO2 emissions from flare stack in cubic feet, under actual conditions

Va = Volume of gas sent to flare in cubic feet, during the year

XCO2 = Mole fraction of CO2 in gas to the flare

Ea,CO2 (combusted) = Contribution of annual combusted CO2 emissions from flare stack in cubic feet, under actual conditions

Va = Volume of gas sent to flare in cubic feet, during the year

n = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, n is zeroYj = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanes-plus)

Rj = Number of carbon atoms in the gas hydrocarbon constituents j: 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentane plus

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Flare Stacks 
Flare Stack Emissions - Greenhouse Gases Emission Summary

US EPA - Region 8 Air ProgramFederal New Source Review Program in Indian CountryMarathon Oil CompanyMaggie Old Dog USA 24-19HNatural Gas Volumetric Emissions - Standard Conditions (GHG Rule Eq. W-33)

Natural Gas Volumetric 

Emissions at Actual 

Conditions (Ea,n) (cubic 

feet)

Temperature at 

Standard Conditions 

(Ts) (°F)

Temperature at Actual 

Emission Conditions (Ta) 

(°F)

Absolute Pressure at 

Standard Conditions (Ps) 

(psia)

Absolute Pressure at 

Actual Conditions (Pa) 

(psia)

Natural Gas Volumetric 

Emissions at STP (Es,n)

(cubic feet)

803,000,000.00 60.00 60.00 14.70 13.60 742,911,564.63

Calculation for Natural Gas Volumetric Emissions - Standard Conditions found in 98.233(t) Equation W-33

GHG Mass Emissions (metric tons CO2e) (GHG Rule Eq. W-36)

CH4 Volumetric 

Emissions at STP (Es,i)

(cubic feet)

CO2 Volumetric 

Emissions at STP (Es,i) 

(cubic feet)

Density (Pi) of CO2 Density (Pi) of CH4

Global Warming Potential 

(GWP) of CO2

(kg CO2e/kg)

Global Warming Potential 

(GWP) of CH4

(kg CO2e/kg)

Mass Emissions at Standard 

Conditions (Massi) - CO2

(metric tons CO2e)

Mass Emissions at Standard 

Conditions (Massi) - CH4

(metric tons CO2e)

Mass 

Con

0.00 1,447,189,887.00 0.0538 0.0196 1 21 7.79E+04 0.00E+00 

Calculate GHG mass emissions in CO2e at standard conditions by converting the GHG volumetric emissions into mass emissions

Calculation for GHG Mass Emissions found in 98.233(v) Equation W-36Masss,i = Es,i * Pi * GWP * 10-3

*Potential N2O emissions from fuel combustion in the flare are assumed to be negligible.

**Density was assumed to be at standard conditions, 68°F and 14.7 psia.

Subpart W Equation W-40 Treater Flare Negligibility Check

HHV, mmBtu/scf (eq. W-40) 1.235E-03

EF, kg N2O/mmBtu 1.00E-04

convert kg to metric tons 1.00E-03

combusted gas volume, scf/yr 803,000,000

N2O, metric tons 9.9E-02N2O emissions are negligibleEs,n = Ea,n * (459.67 + Ts) * Pa

 (459.67 + Ta) * PsEs,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet

Ea,n = Natural Gas Volumetric Emissions at Actual Conditions in Cubic Feet

Ts = Temperature at standard conditions (°F)

Ta = Temperature at actual emission conditions (°F)

Ps = Absolute pressure at standard conditions (psia)

Pa = Absolute pressure at actual conditions (psia)

Masss,i = GHGi (either CH4 or CO2) mass emissions at standard conditions in metric tons CO2e

Es,i = GHGi (either CH4 or CO2) volumetric emissions at standard conditions in cubic feet

Pi = Density of GHGi. Use 0.0538 kg/ft3 for CO2 and N2O, and 0.0196 kg/ft3 for CH4 at 68°F and 14.7 psia or 0.0530 kg/ft3 for CO2 and N2O, 

and 0.0193 kg/ft3 for CH4 at 60°F and 14.7 psia.

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, GHG - Flare Stacks 
Bakken Pool Oil and Gas Production Facilities

Air Pollution Control Permitting & Compliance Guidance - May 2, 2011North Dakota Department of Health - Division of Air QualityDefault FactorsOil/Condensate Tank Data

Vapor Recovery Unit 

or Oil Stabilizer

Enclosed Smokeless 

Combustor

Utility Flare or Other 98% DRE 

Device G

97.91 2000 45.19 79.8 2.26 99 98 98 

Control Requirements

If first date of production occurred after June 1, 2011, tank emissions must be controlled by a ground it flare or other control device that achieves at least 90% DRE for VOCs upon startup of the facility.Facilities must calculate VOC PTE within 90 days after the first day of production.If PTE for VOC emissions is < 20 tpy, then a minimum of a ground pit flare (90% DRE) is required.If PTE for VOC emissions is > 20 tpy, then a control device that achieves at least 98% DRE must be installed and operated.

Treater Gas Data

Enclosed Smokeless 

Combustor

Utility Flare or Other 98% 

DRE Device

Ground Pit Flare or Other 

90% DRE Device Connected to Sales Line

98 98 90 100

Control Requirements

Treater gas must be routed to a gas gathering pipeline as soon as practicable in accordance with North Dakota Industrial Commission Requirements.When a pipeline is not available, treater gas is required to be routed to a control system or device (appropriate devices are included in the table above).

Treater Burner Data

NOx CO VOC HAPS

8,760 100 84 5.5 1.89

*Taken from AP-42, Tables 1.4-1, 1.4-2 and 1.4-3 - Emission Factors from Natural Gas Consumption. Based on average heating value of 1020 Btu/scf of natural gas.

Truck Loading Data

Submerged Loading of a 

Clean Cargo Tank

Submerged Loading: 

Dedicated Normal Service

Submerged Loading: 

Dedicated Vapor 

Balance Service

Oil is Hauled by Truck Oil is Sold through LACT 0.5 0.6 1 Refer to Table 2 on Truck Loading tab Refer to Table 2 on Truck Loading tab If no specific data, use estimated average annual temperature

Emissions calculated using formula provided in AP-42.Saturation factors taken from AP-42, Table 5.2-1 - Saturation (S) Factors for Calculating Petroleum Liquid Loading Loss.P and M values taken from Table 7.1-2 - Properties of Selected Petroleum Liquids.Control Requirements

Bakken Pool O&G production facilities are not required to route emissions displaced from truck loading activities to a control system or device due to safety concerns.However, the owner/operator shall follow any operating and/or construction requirements established in Chapters 33-15-07 and 33-15-20 of the North Dakota Air Pollution Control Rules.

Temperature of Bulk Liquid 

Loaded (°F)

Hours of Operation Natural Gas Emission Factors* (lb/MMscf)

Destruction Devices and Efficiency (%)

Sales Method

Mode of Operation and Appropriate Saturation Factor Molecular Weight of 

Tank Vapors 

(lb/lb-mole)

Vapor Pressure of 

Liquid Loaded

(psia)

Destruction Devices and Efficiency (%) Default Bakken EF 

(scf/bbl)

Lower Heating Value of 

Tank Vapors

(Btu/scf)

Molecular Weight of Tank 

Vapors

(lb/lb-mole)

VOC Weight Fraction of 

Tank Vapor Gas (C3+) (%)

HAP Weight Fraction 

of Tank Vapor Gas (%)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, NDDoH Default Factors 28 of 36 
Bakken Pool Oil and Gas Production Facilities

Air Pollution Control Permitting & Compliance Guidance - May 2, 2011North Dakota Department of Health - Division of Air QualityDefault FactorsPneumatic Pumps Data

Routed Exhaust Back into 

Closed Loop System

Routed Exhaust to a 

Combustion Device

4,380 100 98

Control Requirements

Bakken Pool O&G production facilities are required to control pneumatic pumps that use natural gas as the motive gas, if the PTE of VOCs from the pneumatic pump is > 5 tpy per pump.

Pneumatic Controllers Data

There are not default factors for pneumatic controllers. Emissions are calculated based on the following: number of controllers, gas usage or bleed rate (scf/hr), VOC/HAP weight fraction, molecular weight and hours of operationControl RequirementsBakken Pool O&G production facilities are not required to install add-on controls for emissions from these types of devices.

Glycol Dehydrator Data

VOC Emissions (tpy) HAP Emissions (tpy)

0 0

Use emissions calculated in GRI-GLYCalc V4 software; if no Glycol Dehydrator is installed, enter 0.

RICE Engines Data

Hours of Operation

NOx AP-42 

Emissions Factor

(g/hp-hr)

CO AP-42 

Emissions Factor

(g/hp-hr)

VOC AP-42 

Emissions Factor

(g/hp-hr)

NOx Control Efficiency CO Control Efficiency VOC Control Efficiency

8,760

Manufacturer data, actual 

test results or 

AP-42 emission factors

Manufacturer data, actual 

test results or 

AP-42 emission factors

Manufacturer data, actual 

test results or 

AP-42 emission factors

Manufacturer data or 

actual test results

Manufacturer data or 

actual test results

Manufacturer data or 

actual test results

While emission factors from actual stack testing, manufacturer's engine data, and AP-42 are acceptable, actual test data is usually the most accurate and preferred method.Control Requirements

NDDoH does not require any specific air pollution control equipment; however, the RICE must be in compliance with all State and Federal Rules and Regulations.See the Federal Rules and Regulations tab for specifics regarding applicable Federal Rules.

Annual Hours of Operation - 

Winter Months Only

Control Devices and Efficiency (%)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, NDDoH Default Factors 29 of 36 
US EPA

AP 42, Compilation of Air Pollutant Emission FactorsApplicable TablesOil/Condensate Tank and Treater Flare

13.5-1 - Emission Factors for Flare Operations

Total Hydrocarbonsb 0.14

Carbon Monoxide 0.37

Nitrogen Oxides 0.068

Sootc 0 - 274

b Measured as methane equivalent.

Treater Burner Data

Table 1.4-1 - Emission Factors for Nitrogen Oxides (NOx) and Carbon Monoxide (CO) from Natural Gas Combustion

Combustor Type

(MMBtu/hr Heat Input)

NOx Emission Factor

(lb/106 scf)

CO Emission Factor

(lb/106 scf)

Uncontrolled (Pre-NSPS) 280 84

Uncontrolled (Post-NSPS) 190 84

Controlled - Low NOx Burners 140 84

Controlled - Flue Gas Recirculation 100 84

Uncontrolled 100 84

Controlled - Low NOx Burners 50 84

Controlled - Low NOx Burner / 

Flue Gas Recirculation

32 84

Uncontrolled 170 24

Controlled - Flue Gas Recirculation 76 98

Uncontrolled 94 40

Units are in lb/MMscf of natural gas fired. To convert from lb/106 scf to lb/MMBtu, divide by 1,020.

Tangential-Fired Boilers (All Sizes)Residential Furnaces (< 0.3)

Component Emission Factor

(lb/106 Btu)

c Soot in concentration values: nonsmoking flares, 0 micrograms per liter (ug/l); lightly 

smoking flares, 40 mg/l; average smoking flares, 177 ug/l; and heavy smoking flares, 274 ug/l.Large Wall-Fired Boilers (>100)Small Boilers (< 100)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, AP-42 Tables 30 of 36 
US EPA

AP 42, Compilation of Air Pollutant Emission FactorsApplicable Tables

Table 1.4-2 - Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion

Pollutant 

Emission Factor

(lb/106 scf)

CO2 120,000

Lead 0.0005

N2O (Uncontrolled) 2.2

N2O (Controlled - Low NOx Burner) 0.64

PM (Total) 7.6

PM (Condensable) 5.7

PM (Filterable) 1.9

SO2 0.6

TOC 11

Methane 2.3

VOC 5.5

PM is assumed to be less than 1.0 micrometer in diameter. Therefore, the PM emission factors may be used to estimate PM10 and PM2.5.

SO2 is based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content is natural gas of 2,000 grains/106 scf.

Table 1.4-3 - Emission Factors for Speciated Organic Compounds from Natural Gas Combustion

Emission factors are included in the Natural Gas Combustion calculations.

Truck Loading 

Table 5.2-1 - Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses

Cargo Carrier Mode of Operation S Factor

Submerged loading of a 

clean cargo tank 0.50

Submerged loading: 

dedicated normal service 0.60

Submerged loading: 

dedicated vapor balance 

service

1.00

Splash loading of a clean 

cargo tank 1.45

Splash loading: dedicated 

normal service 1.45

Splash loading: dedicated 

vapor balance service 1.00

Tank Trucks and Rail Tank Cars

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, AP-42 Tables 31 of 36 
US EPA

AP 42, Compilation of Air Pollutant Emission FactorsApplicable Tables

Table 7.1-2 - Properties (MV, PVA, WL) of Selected Petroleum Liquids

40°F 50°F 60°F 70°F 80°F 90

Crude Oil RVP 5 50 7.1 1.8 2.3 2.8 3.4 4 4

Distillate Fuel Oil No. 2 130 7.1 0.0031 0.0045 0.0065 0.0090 0.012 0.0

Gasoline RVP 7 68 5.6 2.3 2.9 3.5 4.3 5.2 6

Gasoline RVP 7.8 68 5.6 2.5929 3.2079 3.9363 4.793 5.7937 6.9Gasoline RVP 8.3 68 5.6 2.7888 3.444 4.2188 5.1284 6.1891 7.4

Gasoline RVP 10 66 5.6 3.4 4.2 5.2 6.2 7.4 8

Gasoline RVP 11.5 65 5.6 4.087 4.9997 6.069 7.3132 8.7519 10.4

Gasoline RVP 13 62 5.6 4.7 5.7 6.9 8.3 9.9 11

Gasoline RVP 13.5 62 5.6 4.932 6.0054 7.2573 8.7076 10.3774 12.2Gasoline RVP 15.0 60 5.6 5.5802 6.774 8.1621 9.7656 11.6067 13.7

Jet Kerosene 130 7.0 0.0041 0.0060 0.0085 0.011 0.015 0.0

Jet Naphtha (JP-4) 80 6.4 0.8 1 1.3 1.6 1.9 2

Residual Oil No. 6 190 7.9 0.00002 0.00003 0.00004 0.00006 0.00009 0.00

RICE Engines Data

Table 3.3-1 - Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines

lb/hp-hr

(Power Output)

lb/MMBtu

(Fuel Input)

lb/hp-hr

(Power Output)

lb/MMBtu

(Fuel Input)

NOx 0.011 1.63 0.031 4.41

CO 6.96E-03 0.99 6.68E-03 0.95

SOx 5.91E-04 0.084 2.05E-03 0.29

PM10 7.21E-04 0.1 2.20E-03 0.32

CO2 1.08 154 1.15 64

Aldehydes 4.85E-04 0.07 4.63E-04 0.07

TOC - Exhaust 0.015 2.1 2.47E-03 0.35

TOC - Evaporative 6.61E-04 0.09 0.00 0.00

TOC - Crankcase 4.85E-03 0.69 4.41E-05 0.01

TOC - Refueling 1.08E-03 0.15 0.00 0.00

Table 3.3-2 - Speciated Organic Compound Emission Factors for Uncontrolled Diesel Engines

Emission factors are included in the RICE calculations.

True Vapor Pressure, PVA (psi)

Pollutant

Gasoline Fuel

Emission Factors

Diesel Fuel

Emission Factors

Petroleum Liquid Vapor Molecular Weight @ 60°F, MV (lb/lb-mole) Liquid Density @ 60°F, WL (lb/gal)

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, AP-42 Tables 32 of 36 
Federal Rules and Regulations Applicable to the Oil and Gas Industry

This regulation document is provided by the North Dakota Department of Health for information purposes only.Please reference the rule for complete applicability and full details.40 CFR Part 60 - New Source Performance Standards (NSPS)

Subpart Applicability and Description Subpart Reviewed for Applicability

Subpart IIII - Stationary Compression Ignition 

Internal Combustion Engines

Applies to any compression ignition internal combustion engine where construction is commenced after July 11, 2005 where the engine is manufactured after April 1, 2006 NA

Subpart JJJJ - Stationary Spark Ignition Internal 

Combustion Engines

Applies to any spark ignition internal combustion engine where construction is commenced after June 12, 2006 where the engine is manufactured:- After July 1, 2007 for engines > 500 hp- After July 1, 2008 for lean-burn engines 500 < hp < 1350- After July 1, 2008 for engines < 500 hp- After January 1, 2009 for emergency engines

only 8 hp gasoline engine on site

Subpart GG - Stationary Gas Turbines

Applies to all stationary gas turbines with a heat input ≥ 10 MMBtu/hr based on the lower heating value of the fuel where construction is commenced after October 3, 1997 but before February 18, 2005

NA

Subpart KKKK - Stationary Combustion Turbines

Applies to stationary gas turbines with a heat input ≥ 10 MMBtu/hr based on the higher 

heating value of the fuel where construction, modification or reconstruction is commenced after February 18, 2005

NA

Subpart Kb - Volatile Organic Liquid (VOL) Storage 

Vessels (Including Petroleum Liquid Storage 

Vessels) for which Construction, Reconstruction 

or Modification Commenced after July 23, 1984

Applies to each storage vessel with a capacity of ≥ 75 m3 that is used to store VOL for which 

construction, reconstruction, or modification commenced after July 23, 1984. Common exceptions to this rule include:- Does not apply to storage vessels with a capacity > 151 m3 storing a liquid with a maximum 

true vapor pressure less than 3.5 kilopascals (kPa)- Does not apply to vessels with a capacity of 75 ≥ m3 < 151 storing a liquid with a maximum 

true vapor pressure less than 15.0 kPa- Does not apply to vessels with a design capacity < 1,589.874 m3 used for petroleum or 

condensate stored, processed or treated prior to custody transfer

NA - prior to custody transfer

Subpart Dc - Small Industrial - Commercial - 

Institutional Steam Generating Units

Applies to all steam generating units for which construction, modification or reconstruction is commenced after June 9, 1989 and that has a maximum design capacity of 10 ≥ MMBtu/hr < 

100

NA

Subpart KKK - Equipment Leaks of VOC from 

Onshore Natural Gas Processing Plants Applies to affected facilities at onshore natural gas processing plants NA

Subpart LLL - Onshore Natural Gas Processing: 

SO2 Emissions

Applies to each sweetening unit and each sweetening unit followed by a sulfur recovery unit at facilities that process natural gas NA

Existing NSPS covers only natural gas processing 

plants and the proposal would cover additional 

emission points including: well completions (and 

re-completions), compressors, pneumatic 

controllers, storage vessels (condensate and 

crude oil tanks.

EPA is under a consent decree deadline to take 

final action on these rules by February 28, 2012

- Would limit VOC emissions from gas wells as they are being prepared for production, a process called "well completion".- Would apply to all hydraulically fractured (fracked) wells, both new wells and existing wells that are fracked or refracked to get more gas out of a well. - Would require combination of green completion and flaring for most fractured wells. Achieve 95% VOC reduction and 90% recovery of salable natural gas. Require flaring in situations not meeting criteria for reduced emissions completion where flaring is not a hazard.- Would require VOC reductions from other operations in the oil and gas sector including: - Compressors, which help move natural gas along a pipeline. Centrifugal and reciprocating compressors would be required to reduce VOC emissions. - Pneumatic Controllers, which regulate pressure, flow and temperature. Cover units 

located at gas processing plants and compressor stations. - Storage Tanks, located at wells and other production facilities. Reduce VOC emissions by 95%. - Onshore Natural Gas Processing Plants. Strengthen leak detection and repair 

requirements of existing NSPS.

NA - stil proposed

*Based on the EPA document "Addressing Air Emissions from the Oil and Natural Gas Industry - Overview of EPA's Proposed New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants".EPA Review - Natural Gas Processing Plants*EnginesTurbinesTanksHeatersNatural Gas Processing Plants*

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Federal Rules 33 of 36 
Federal Rules and Regulations Applicable to the Oil and Gas Industry

This regulation document is provided by the North Dakota Department of Health for information purposes only.Please reference the rule for complete applicability and full details.40 CFR Part 63 - National Emission Standards for Hazardous Air Pollutants (MACT)

Subpart Applicability and Description Subpart Reviewed for Applicability

Subpart ZZZZ - Stationary Reciprocating Internal 

Combustion Engines

Applies to any (new, existing, modified and reconstructed) reciprocating internal combustion engines located at a major source or area source of hazardous air pollutants (HAPs). only 8 hp gasoline engine on site

Subpart HH - Oil and Gas Production Facilities

Applies to all oil and gas production facilities that are major and area sources of HAPs with the

following exceptions:- A facility that exclusively processes, stores or transfers black oil- A major source prior to the point of custody transfer with a facility-wide annual average natural gas throughput < 18.4 thousand cubic meters/day and a facility-wide annual hydrocarbon liquid throughput < 37,700 liters/day.

The facility will be a synthetic minor 

source

Subpart HHH - Natural Gas Transmission and 

Storage Facilities 

Applies to owners and operators of natural gas transmission and storage facilities that transport or store natural gas prior to entering the pipeline to a local distribution company or to a final end user and that are major sources of HAP emissions.

NA

Proposal for Air Toxics - Oil and Gas Production 

Facilities and Natural Gas Transmission and 

Storage Facilities*

EPA is under a consent decree deadline to take 

final action on these rules by February 28, 2012

Technology Review

- No available cost-effective technologies for controlled glycol dehydrators and storage tanks that could achieve greater reductions that current standards.- Standard for equipment leaks has been made more stringent.Review identified unregulated emission points, and proposal includes provisions to reduce emissions- Glycol Dehydrators - Establish limits for small dehydrators at major sources.- Storage Tanks (Oil and Gas Production Only) - Regulate all crude oil and condensate tanks at major sources. Remove throughput, API gravity and gas/oil ratio criteria.Risk Review- Rule proposes to reduce amount of air toxics allowed to be emitted. - Eliminate the 1 tpy benzene compliance option for glycol dehydrators at major sources (Oil and Gas Production and Natural Gas Transmission/Storage).

NA - stil proposed

EnginesProposal for Air Toxics - Oil and Gas Production Facilities and Natural Gas Transmission and Storage Facilities*

*Based on the EPA document "Addressing Air Emissions from the Oil and Natural Gas Industry - Overview of EPA's Proposed New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants".Oil and Gas Production FacilitiesNatural Gas Transmission and Storage Facilities

8Attachment 3 - Revised Maximum Production Rate with Gas Sales Calculation Sheet.xlsx, Federal Rules 34 of 36 
Average Casinghead Gas Analysis Data

Compou

MW Wt Gross 

lb/lb-mole lb Btu/sc

oxygen n 0.000% 32.00 0.0000 0.00% 0 nitrogen n 2.717% 28.013 0.7611 2.67% 0 H2S n 0.000% 34.076 0.0000 0.00% 637.1 

CO2 n 1.115% 44.01 0.4909 1.73% 0 

C1 / CH4 n 47.239% 16.043 7.5786 26.63% 1010.0 C2 n 26.069% 30.07 7.8389 27.55% 1796.6 C3 y 14.617% 44.10 6.4455 22.65% 2516.1 C4, iso y 1.569% 58.12 0.9122 3.21% 3251.9 C4, n y 3.766% 58.12 2.1888 7.69% 3262.3 C5, iso y 0.594% 72.15 0.4289 1.51% 4000.9 C5, n y 1.131% 72.15 0.8162 2.87% 4008.9 C6+ y 1.182% 84.18 0.9953 3.50% 4755.9 

Totals 100.00% 28.46 100.00% 

weight % VOC: 41.42%

Heat

Component VOC Mole2 % Wt%
(If speciated by lab, enter HAPs at bottom of sheet, not lumped with carbon numbers)

(enter composition in %, not mole fraction)

Gas Source: Average from 4 existing locations collected by Comm Engineering

Sample Date: 05/28/09-06/05/09

Compound Gas

Correction Mole % Net LHV

Mole % Calculations w/o air Mole Wt Wt Wt% Btu/scf Btu/scf

oxygen 0.000% 0.000% 0.000% 32.00 0.0000 0.00% 0 0.0

nitrogen 5.055% 5.055% 5.055% 28.01 1.4161 3.21% 0 0.0

hydrogen sulfide 0.000% 0.000% 0.000% 34.08 0.0000 0.00% 586.8 0.0

carbon dioxide 0.285% 0.285% 0.285% 44.01 0.1254 0.28% 0 0.0

methane 7.242% 7.242% 7.242% 16.04 1.1618 2.63% 909.4 65.9

ethane 24.148% 24.148% 24.148% 30.07 7.2613 16.46% 1618.7 390.9

propane 33.425% 33.425% 33.425% 44.10 14.7394 33.41% 2314.9 773.8

isobutane 4.619% 4.619% 4.619% 58.12 2.6847 6.09% 3000.4 138.6

n-butane 15.573% 15.573% 15.573% 58.12 9.0515 20.52% 3010.8 468.9

isopentane 2.605% 2.605% 2.605% 72.15 1.8795 4.26% 3699.0 96.4

n-pentane 3.643% 3.643% 3.643% 72.15 2.6284 5.96% 3706.9 135.0

n-hexane 0.736% 0.736% 0.736% 86.18 0.6343 1.44% 4403.8 32.4

hexanes, other 1.222% 1.222% 1.222% 84.18 1.0287 2.33% 4403.8 53.8

heptanes 0.987% 0.987% 0.987% 100.21 0.9891 2.24% 5100.0 50.3

octanes 0.035% 0.035% 0.035% 114.23 0.0400 0.09% 5796.1 2.0

nonanes 0.043% 0.043% 0.043% 128.26 0.0552 0.13% 6493.2 2.8

decanes plus 0.002% 0.002% 0.002% 142.29 0.0028 0.01% 7189.6 0.1

benzene 0.047% 0.047% 0.047% 78.11 0.0367 0.08% 3590.9 1.7

toluene 0.019% 0.019% 0.019% 92.14 0.0175 0.04% 4273.6 0.8

ethylbenzene 0.004% 0.004% 0.004% 106.17 0.0042 0.01% 4970.5 0.2

xylenes 0.006% 0.006% 0.006% 106.17 0.0064 0.01% 4957 0.3

2,2,4-trimethylpentane 0.305% 0.305% 0.305% 114.23 0.3484 0.79% 5738 17.5

(should total 100%) 100.00% 100.00% 100.00% 44.11 100.00% 2231.4

gas gravity 1.5229

gas rate, mscfd weight % VOC (C3+) 77.41% weight % HAPS 2.37%

mole % VOC 63.27%

TANK VENT EMISSION CALCULATION

Marathon Oil Company
Attachment 4 – Manufacturer Specifications