DAKOTA-3 E&P CO;\IPANY, LLC

a subsidiary of Williams

1001 17'" Street, Suite 1200

Denver, CO 80202

303/527-3900

September 30,20 II

Ms. Kathleen Paser

Minor NSR Permitting Coordinator

U.S. EPA, Region 8

1595 Wynkoop Avenue, 8P-AR

Denver, CO 80202-1129

Duplicate submittal provided via e-mail to:

paser.kathleen@epa.gov

Re: Synthetic Minor Source Permit Application for the North John Elk 28-27HC Pad

Dear Ms. Paser:

Dakota-3 E&P Company, LLC (Dakota-3) a subsidiary of Williams is submitting this Synthetic Minor

Source Permit Application for the North John Elk 28-27HC Pad. This application is being submitted in

accordance with the requirements ofthe August 29, 2011 Consent Agreement, regarding compliance with

the Federal Minor New SOlll'ce Review Rule.

Do not hesitate to contact me with any questions either by phone at 303-606-4056, or bye-mail at

JoDell.Mizoue@Williams.com.

Sincerely,

Williams

Dakota-3 E&P Company, LLC

JoDell Mizoue, P.E

StaffEnvironmental Specialist

Attachment

cc: file

Joe Gillies Jr. Environmental Director, Environmental Division, 204 W. Main,

New Town, ND 58763-9404

Tex Hall, Chairman Three Affiliated Tribes, 404 Frontage Road, New Town, ND 58763-9404

(letter Only)
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 a New Facility 

o Proposed Construction of New Equipment at an Existing Facility 

o Proposed Modification of an Existing Facility 

o Other – Please Explain 

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

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

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

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

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

replaced/updated after that review is completed. 

Please submit information to 

following two entities: 

Minor NSR Permitting Coordinator 

U.S. EPA, Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

The Tribal Environmental Contact for the specific reservation: 

If you need assistance in identifying the appropriate Tribal 

Environmental Contact and address, please contact the EPA 

Region 8 Tribal Air Coordinator: 

Alexis North, EPA Region 8 Tribal Air Coordinator 

303-312-7005 

north.alexis@epa.gov

A. GENERAL FACILITY INFORMATION 

1. (a) Company Name 

 Dakota-3 E&P Company, LLC 

 (b) Operator Name 

 Dakota-3 E&P Company, LLC 

2. Facility Name

 North John Elk 28-27HC Pad 

3. Type of Operation 

 Oil and Gas Production 

4. Portable Source? Yes No 

5. Temporary Source? Yes No 

6. NAICS Code 

 213111 

7. SIC Code 

 1311 

8. Physical Address: 1001 17th Street, Suite 1200 Denver, CO 80202

9. Reservation* 

 FBIR 

10. County* 

 Dunn 

11a. Latitude* 

47.78070 

11b. Longitude* 

102.59182 

12a. Quarter Quarter Section* 

NESW 

12b. Section* 

 28 

12c. Township* 

 T150N 

12d. Range* 

 R93W 
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) 

This section of the permit application is not applicable. This application is for a new facility for which 

no previous permit actions have been taken. 

Facility Name on the Permit N/A 

Permit Number (xx-xxx-xxxxx-xxxx.xx) N/A 

Date of the Permit Action N/A
C. CONTACT INFORMATION 

Company Contact: JoDell Mizoue Title: 

Staff Environmental 

Specialist 

Mailing Address: 1001 17th Street, Suite 1200 Denver, CO 80202

Email Address: JoDell.Mizoue@Williams.com 

Telephone Number: (303) 606-4056 Facsimile Number: (303) 692-8285

Operator Contact (if different from company contact): Same as above Title 

Mailing Address

Email Address 

Telephone Number Facsimile Number

Facility Contact: Same as above Title 

Mailing Address

Email Address 

Telephone Number Facsimile Number

Compliance Contact: Same as above Title 

Mailing Address

Email Address 

Telephone Number Facsimile Number
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 descriptions 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 operating 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 Pollutant Emissions - Estimates of Current Actual Emissions, Current Allowable Emissions, PostChange Uncontrolled Emissions, and Post-Change Allowable Emissions for the following air pollutants: 

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

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

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

calculations for the estimates. 

 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 D of this form, as appropriate for the use specified at the top of the form. 

E(i) – Proposed New Facility

Pollutant Potential Emissions 

 (tpy) 

Proposed Allowable 

Emissions 

 (tpy) 

PM - Particulate Matter 

PM10 - Particulate Matter less 

than 10 microns in size 

PM2.5 - Particulate Matter less 

than 2.5 microns in size 

SOx - Sulfur Oxides 

NOx - Nitrogen Oxides 

CO - Carbon Monoxide 

VOC - Volatile Organic 

Compound 

Pb - Lead and lead compounds 

Fluorides - Gaseous and 

particulates 

H2SO4 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur 

Compounds

PM 0.09 0.11 

PM10 0.09 0.11 

PM 2.5 0.09 0.11 

SOx 0.02 0.02 

NOx 5.49 5.97 

CO 45.38 48.00 

VOC 250.11 9.14 

Pb Negligible Negligible 

Fluorides Negligible Negligible 

H2SO4 Negligible Negligible 

H2S Negligible Negligible 

TRS Negligible Negligible 

RSC Negligible Negligible 

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

sources, pursuant to CAA Section 302(j): 

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

(b) Kraft pulp mills; 

(c) Portland cement plants; 

(d) Primary zinc smelters; 

(e) Iron and steel mills; 

(f) Primary aluminum ore reduction plants; 

(g) Primary copper smelters; 

(h) Municipal incinerators capable of charging more than 

250 tons of refuse per day; 

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

(j) Petroleum refineries; 

(k) Lime plants; 

(l) Phosphate rock processing plants; 

(m) Coke oven batteries; 

(n) Sulfur recovery plants; 

(o) Carbon black plants (furnace process); 

(p) Primary lead smelters; 

(q) Fuel conversion plants; 

(r) Sintering plants; 

(s) Secondary metal production plants; 

(t) Chemical process plants 

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

more than 250 million British thermal units per hour 

heat input; 

(v) Petroleum storage and transfer units with a total 

storage capacity exceeding 300,000 barrels; 

(w) Taconite ore processing plants; 

(x) Glass fiber processing plants; 

(y) Charcoal production plants; 

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

250 million British thermal units per hour heat input, 

and 

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

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

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

This section of the application is not applicable. The application is for a new facility only. 

Pollutant Current 

Actual 

Emissions 

(tpy) 

Current 

Allowable 

Emissions 

(tpy) 

Post-Change 

Potential 

Emissions 

(tpy) 

Post-Change 

Allowable 

Emissions 

(tpy) 

PM N/A N/A N/A N/A 

PM10 N/A N/A N/A N/A 

PM 2.5 N/A N/A N/A N/A 

SOx N/A N/A N/A N/A 

NOx N/A N/A N/A N/A 

CO N/A N/A N/A N/A 

VOC N/A N/A N/A N/A 

Pb N/A N/A N/A N/A 

NH3 N/A N/A N/A N/A 

Fluorides N/A N/A N/A N/A 

H2SO4 N/A N/A N/A N/A 

H2S N/A N/A N/A N/A 

TRS N/A N/A N/A N/A 

RSC N/A N/A N/A N/A 

PM - Particulate Matter 

PM10 - Particulate Matter less than 10 microns in size 

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

SOx - Sulfur Oxides 

NOx - Nitrogen Oxides 

CO - Carbon Monoxide 

VOC - Volatile Organic Compound 

Pb - Lead and lead compounds 

NH3 - Ammonia 

Fluorides - Gaseous and particulates 

H2SO4 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur Compounds 
Page 7 of 15 

Instructions 

Use of This Form 

• Proposed new construction or modifications should first be evaluated to determine if the change is 

major under the major NSR program using the procedures at 40 CFR 52.21 (i.e., baseline actual to 

projected actual applicability test). If the proposed construction does not qualify as a major under 

that test, then it may be subject to the requirements of the minor NSR rule at 40 CFR 49.151. 

Helpful Definitions from the Federal Minor NSR Rule (40 CFR 49) – This is not a comprehensive list. 

• 40 CFR 49.152(d) - Modification means any physical or operational change at a source that would 

cause an increase in the allowable emissions of the affected emissions units for any regulated NSR 

pollutant or that would cause the emission of any regulated NSR pollutant not previously emitted. 

The following exemptions apply: 

(1) A physical or operational change does not include routine maintenance, repair, or replacement. 

(2) An increase in the hours of operation or in the production rate is not considered an operational 

change unless such increase is prohibited under any federally-enforceable permit condition or 

other permit condition that is enforceable as a practical matter. 

(3) A change in ownership at a source is not considered a modification.

• 40 CFR 49.152(d) - Allowable emissions means ‘‘allowable emissions’’ as defined in 

§52.21(b)(16), except that the allowable emissions for any emissions unit are calculated 

considering any emission limitations that are enforceable as a practical matter on the emissions 

unit’s potential to emit. 

• 52.21(b)(16) - Allowable emissions means the emissions rate of a stationary source calculated 

using the maximum rated capacity of the source (unless the source is subject to federally 

enforceable limits which restrict the operating rate, or hours of operation, or both) and the most 

stringent of the following: 

(i) The applicable standards as set forth in 40 CFR parts 60 and 61; 

(ii) The applicable State Implementation Plan emissions limitation, including those with a future 

compliance date; or 

(iii) The emissions rate specified as a federally enforceable permit condition, including those with 

a future compliance date. 

 
Page 8 of 15 

A. General Facility Information 

1. Company Name & Operator Name (if different): Provide the complete company and operator names. For 

corporations, include divisions or subsidiary name, if any. 

2. Facility Name: Provide the facility name. Please note that a facility is a site, place, location, etc... that may 

contain one or more air pollution emitting units. 

3. Type of Operation: Indicate the generally accepted name for the operation (i.e., asphalt plant, gas station, dry 

cleaner, sand & gravel mining, oil and gas wellsite, tank battery, etc.). 

4. Portable Source: Does the facility operate in more than one location? Some examples of portable sources 

include asphalt batch plants and concrete batch plants. 

5. Temporary Source: A temporary source, in general, would have emissions that are expected last less than 2 

years. Do you expect to cease operations within the next 2 years? 

 

6. NAICS Code: North American Industry Classification System. The NAICS Code for your facility can be 

found at the following link  North American Industry Classification System

(http://www.census.gov/epcd/naics/nsic2ndx.htm#S1). 

7. SIC Code: Standard Industrial Classification Code. Although the new North American Industry 

Classification System (NAICS) has replaced the SIC codes, much of the Clean Air Act permitting processes 

continue to use these codes. The SIC Code for your facility can be found at the following link  Standard 

Industrial Classification Code (http://www.osha.gov/pls/imis/sic_manual.html). 

8. Physical Address: Provide the actual address of where the facility is operating, not the mailing address. 

Include the State and the ZIP Code. 

9. Reservation: Provide the name of the Indian reservation within which the facility is operating. 

10. County: Provide the County within which the facility is operating. 

11a & 11b. Latitude & Longitude: These are GPS (global positioning system) coordinates. This information 

can be provided in decimal format or degree-minute-second format. 

12a – 12d. Section-Township-Range: Please provide these coordinates in 1/4 Section/Section/Township/Range. 

(e.g., SW 1⁄4, NE 1⁄4 /S36/T10N/R21E). 
Page 9 of 15 

B. Current Permit Information 

Provide a list of all permits that have been issued to your facility. This should include any Federal 

Minor New Source Review (MNSR), Prevention of Significant Deterioration (PSD) or NonAttainment New Source Review (NA NSR) permits, in addition to the most recent Part 71 permit. The 

permit number must be included with each permit identified. 

C. Contact Information 

Please provide the information requested in full.

1. Company Contact: List the full name (last, middle initial, first) of the owners of the facility or the company 

contact. 

2. Operator Contact: Provide the name of the operator of the facility if it is different from the company contact. 

3. Facility Contact: The facility contact must be the local contact authorized to receive requests for data and 

information. 

4. Compliance Contact: The compliance contact must be the local contact responsible for the facility’s 

compliance with this rule. If this is the same as the Facility Contact please note this on the form. 

D. Attachments 

This section lists the information needed to complete the requested approval. This 

information should be accompanied by the supporting information listed on the form and 

described below. The information should be presented in enough detail to document how the 

facility is currently operating and/or how it is proposed to operate. 

 FORM SYNMIN

If synthetic minor limits are being requested, we recommend that the information from checklist tiled Form 

SYNMIN be included with this application. 

 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. For example: 

What are the raw materials? 

What are the properties of the raw materials? 

Does the production process include heating, drying, the application of chemicals, etc? 

How will the raw materials be affected by this process? 

What are the out puts from each step of the process (i.e., crushed ore, dry gas, water, etc...)? 

Etc.... 

2. The proposed operating schedule presented in terms of hours per day, days per week, 

and weeks per year. 

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. 
Page 10 of 15 

 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. 

 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. 

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

equipment. 

3. The capacity for storage units and the hourly, daily and annual maximum throughput 

of material in the storage units. 

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

throughput of material and product. 

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

of material and product.

 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 operating 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. 

1. Include manufacturer specifications and guarantees for each control device.
Page 11 of 15 

Criteria Pollutant Emissions Estimates 

 Estimates of Current Actual Emissions, Current Allowable Emissions, Post-Change 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), hydrogen sulfide (H2S), total reduced sulfur (TRS) and 

reduced sulfur compounds, including all calculations for the estimates. 

1. These estimates are to be made for each emission unit, emission generating activity, in addition 

to total emissions. 

2. The information should include all of the supporting calculations, assumptions and 

references. Emission estimates must address all emission units and pollutants proposed 

and/or affected by the limitation and be presented in short term (e.g. pounds per hour) 

as well as annual (tons per year) units. 

3. Any emission estimates submitted to the Regional Administrator must be verifiable 

using currently accepted engineering criteria. The following procedures are generally 

acceptable for estimating emissions from air pollution sources: 

• Source-specific emission tests; 

• Mass balance calculations; 

• Published, verifiable emission factors that are applicable to the source. (i.e. manufacturer 

specifications) 

• Other engineering calculations; or 

• Other procedures to estimate emissions specifically approved by the Regional 

Administrator. 

4. Guidance for estimating emissions can be found at 

http://www.epa.gov/ttn/chief/efpac/index.html. 

Current Actual Emissions: Current actual emissions for a pollutant is expressed in tpy and 

generally is calculated by multiplying the actual hourly emissions rate in pounds per hour 

(lbs/hr) times actual hours operated (which is the number of hours in a year) and dividing 

by 2,000 (which is the number of pounds in a ton). 

1. For an existing air pollution source (permitted and unpermitted) that operated prior to the 

application submittal, the current actual emissions are the actual rate of emissions for the 

preceding calendar year and must be calculated using the actual operating hours, production 

rates, in-place control equipment, and types of materials processed, stored, or combusted 

during the preceding calendar year. The emission estimates must be based upon actual test data 

or, in the absence of such data, upon procedures acceptable to the Regional Administrator. 

Current Allowable Emissions: Current allowable emissions for a pollutant is expressed in tpy and 

generally is calculated by multiplying the allowed hourly emissions rate in pounds per hour (lbs/hr) 

times allowed hours (which is the number of hours in a year) and dividing by 2,000 (which is the 

number of pounds in a ton). 

1. “Allowed” means the source is restricted by permit conditions that limit its emissions and are 

enforceable as a practical matter (i.e., allowable emissions). The allowable emissions for any 
Page 12 of 15 

emissions unit are calculated considering any emissions limitations that are enforceable as a 

practical matter on the unit’s PTE. 

2. For an existing permitted air pollution source that operated prior to the application submittal, the 

current allowable emissions are the allowable rate of emissions for the preceding calendar year and must 

be calculated using the permitted operating hours, production rates, in-place control equipment, and 

types of materials processed, stored, or combusted during the preceding calendar year. 

3. For an existing air pollution source that does not have an established allowable 

emissions level prior to the modification must report the pre-change uncontrolled 

emissions. 

Post-Change Potential Emissions (Potential uncontrolled emissions from proposed project): This is 

the maximum capacity of a source to emit a pollutant under its physical and operational design. 

This is expressed in tpy and generally is calculated by multiplying the maximum hourly emissions 

rate in pounds per hour (lbs/hr) times 8,760 hours (which is the number of hours in a year) and 

dividing by 2,000 (which is the number of pounds in a ton). 

Post-Change Allowable Emissions: A source’s allowable emissions for a pollutant is expressed in 

tpy and generally is calculated by multiplying the allowed hourly emissions rate in pounds per hour 

(lbs/hr) times allowed hours (which is the number of hours in a year) and dividing by 2,000 (which 

is the number of pounds in a ton). 

1. Unless the source is restricted by permit conditions or other requirements that are enforceable 

as a practical matter, the post-change allowable emissions would be equivalent to post-change 

uncontrolled emissions. For the post-change allowable emissions a lower level of allowable 

emissions may be proposed. 

2. For physical or operational changes at minor sources and for minor physical or operational 

changes at major sources, the total increase in allowable emissions resulting from your 

proposed change would be the sum of following: 

• For each new emissions unit that is to be added, the emissions increase would be the 

potential to emit of each unit. 

• For each emissions unit with an allowable emissions limit that is to be changed or 

replaced, the emissions increase would be the allowable emissions of the emissions unit 

after the change or replacement minus the allowable emissions prior to the change or 

replacement. However, this may not be a negative value. If the allowable emissions of an 

emissions unit would be reduced as a result of the change or replacement, use zero in the 

calculation.

• For each unpermitted emissions unit (i.e., a unit without any emissions limitations before 

the change) that is to be changed or replaced, the emissions increase would be the 

allowable emissions of the unit after the change or replacement minus the potential to emit 

prior to the change or replacement. However, this may not be a negative value. If the 

allowable emissions of an emissions unit would be reduced as a result of the change or 

replacement, use zero in the calculation.
Page 13 of 15 

 Modeling Analysis 

Do I need to do a modeling analysis? 

The Federal Minor New Source Review Regulations at 40 CFR 49.159(d) requires that a modeling 

analysis (AQIA) of proposed emissions be performed if there is reason to be concerned that new 

construction would cause or contribute to a National Ambient Air Quality Standard (NAAQS) or 

Prevention of Significant Deterioration (PSD) increment violation. 

In addition, if the AQIA reveals that the new construction could cause or contribute to a NAAQS or 

PSD increment violation; such impacts must be reduced before a pre-construction permit can be 

issued. 

To facilitate the protection of the NAAQS and PSD Increment, EPA Region 8 requests that those 

proposed activities that meet the following criteria perform an AQIA: 

1. The proposed activity has air emissions that EPA Region 8 determines have the potential to 

cause adverse air quality effects for which an air quality impact analysis is necessary for an 

accurate assessment of the environmental impact of the activities proposed. 

2. Modeling of proposed emissions is usually warranted, even though the proposed activity does 

not meet the modeling requirements, above, if it is reasonable to believe the new activity may 

cause or contribute to a violation of applicable ambient air quality standards or increments in 

circumstances such as: 

(a) A substantial portion of the new or modified emissions have poor dispersion characteristics 

(e.g., rain caps, horizontal stacks, fugitive releases, or building downwash) in close 

proximity to ambient air at the site boundary; 

(b) The new or modified emissions are located in complex terrain (e.g., terrain above stack 

height in close proximity to the source); or 

(c) The new or modified emissions are located in areas with existing air quality concerns. 

(d) If you have questions about whether modeling may be necessary based on the 4th criteria 

above, please contact EPA Region 8’s Modeling Lead: 

Gail Tonnesen 

Region 8 Modeling Lead 

Tonnesen.gail@epa.gov

303-312- 6113 
Page 14 of 15 

What Kind of Air Quality Modeling Analysis Is Needed? 

1. EPA Region 8 considers a stepped or phased approach to modeling to be appropriate, as 

follows: 

Step 1: Qualitative Air Quality Assessment 

Step 2: Screening Modeling Analysis 

Step 3: Preliminary Modeling Analysis (refined modeling) 

Step 4: Full Impact Modeling Analysis (refined modeling) 

Step 5: PSD Increment and NAAQS Analysis

Step 6: Additional Impact Analysis 

2. Step 1: Qualitative Air Quality Assessment 

Narrative description of the current air quality conditions and the expected impact the permitted 

source would have on that air quality. Some suggested factors to consider in the qualitative 

discussion could include meteorology, terrain, distance to ambient air, expected emissions, etc. 

If a convincing case cannot be made qualitatively that no impacts to air quality would be 

expected, a screening analysis should next be performed. 

3. Step 2: Screening Analysis 

For proposed new or modified sources that meet the modeling requirement criteria identified 

above, protection of air quality from proposed emissions may be shown by using a simple 

screening technique (e.g., SCREEN3 or AERSCREEN). Screening models are available for 

download at the EPA SCRAM website: 

http://www.epa.gov/ttn/scram/dispersion_screening.htm. A pre-approved modeling protocol is 

not necessary prior to conducting a Screening Analysis. 

4. If the proposed new or modified emission increases do not increase ambient concentrations of a 

pollutant by more than the significant impact levels, as compared to the SILs identified below, no 

further modeling is necessary. 

Significant Impact Levels 

Pollutant Averaging Period Class II Area SIL 

(ug/m3) 

Class I Area SIL 

(ug/m3) 

SO2

1 hr 3 ppb or 7.8 ug/m3 (interim) ---- 

3 hr 25 1.0 

24 hr 5 0.2 

Annual 1 0.08 

PM2.5

24 hr 0.07 1.2 

Annual 0.06 0.3 

PM10

24 hr 5 0.2 

Annual 1 0.08 

NO2

1 hr 4 ppb or 7.5 ug/m3 (interim) ---- 

Annual 1 0.08 

CO 1 hr 2,000 ppb 

8 hr 500 ppb 

Note: The Class I area SILs are provided as guidance and have not been formalized by EPA. 
Page 15 of 15 

5. Sources that cannot demonstrate protection of air quality using a screening technique should 

continue to the modeling requirements in Step 3 through Step 6. Modeling in Steps 3 through 

6 should be performed based an approved protocol.

6. Applicants are encouraged to contact the EPA Region 8 Modeling Lead prior to conducting any 

refined modeling analysis (Step 3 through Step 6) to obtain an approved protocol. 

What Should I Include In My Application If Modeling Is Necessary?

1. Approved Modeling Protocol 

In order to expedite the permitting process, it is recommended that you include a protocol that 

has already been approved. An application will not be deemed complete until the protocol has 

been approved. 

2. Modeling Results 

In all cases, the modeling results should include the name of the model used, all input 

parameters, and the resulting output. Electronic copies of the modeling input/output files should 

be provided to EPA Region 8. 

 ESA 

The Endangered Species Act requires us, in consultation with the U.S. Fish and Wildlife Service 

and/or the NOAA Fisheries Service, to ensure that actions we authorize are not likely to jeopardize the 

continued existence of any listed species or result in the destruction or adverse modification of 

designated critical habitat of such species. 

To expedite the approval of your proposed construction, we encourage you to identify any listed 

species that you may be readily aware of that could be affected by your proposal. The following 

website has been provided to assist you: 

http://www.fws.gov/endangered/

Simply enter the State and County in which you propose to construct to obtain a general listing. 

 NHPA 

The National Historic Preservation Act requires us, in consultation with State and/or Tribal Historic 

Preservation Officers to ensure that actions we authorize are not likely to affect cultural resources. 

To expedite the approval of your proposed construction, we encourage you to identify any cultural 

resources that you may be readily aware of that could be affected by your proposal. The following 

website has been provided to assist you: 

http://nrhp.focus.nps.gov/natreghome.do?searchtype=natreghome

Simply enter the State and County in which you propose to construct to obtain a general listing. 
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Region 8 Air Program 

FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY 

Checklist - Synthetic Minor Limit Request 

(Form SYNMIN) 

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

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

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

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

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

completed. 

Please submit information to following two entities: 

Federal Minor NSR Permit Coordinator 

U.S. EPA, Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

The Tribal Environmental Contact for the specific reservation: 

If you need assistance in identifying the appropriate Tribal 

Environmental Contact and address, please contact the EPA 

Region 8 Tribal Air Coordinator: 

Alexis North, EPA Region 8 Tribal Air Coordinator 

303-312-7005 

north.alexis@epa.gov

A. GENERAL INFORMATION 

Company Name 

Dakota-3 E&P Company, LLC 

Facility Name 

North John Elk 28-27 HC Pad 

Company Contact or Owner Name 

JoDell Mizoue 

Title

Staff Environmental 

Specialist 

Mailing Address 

1001 17th Street, Suite 1200 Denver, CO 80202

Email Address 

JoDell.Mizoue@Williams.com 

Telephone Number 

(303) 606-4056

Facsimile Number 

(303) 692-8285

B. ATTACHMENTS 

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

 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 Greenhouse Gas (GHG) pollutants before and after proposed 

emission controls. 
Page 2 of 4 

Instructions 

Use this form to provide general and summary information about the synthetic minor NSR 

source (facility or plant) on Tribal lands and to indicate the emissions limitations requested. 

Submit this form once, in addition to FORM NEW, for each synthetic minor NSR source on 

Tribal lands. 

1. Who Can Request Federally-Enforceable Limitations Under the Tribal NSR Authority? 

The Tribal NSR Rule applies only to sources located within the exterior boundaries of an Indian 

reservation in the United States of America or other lands as specified in 40 CFR part 49, collectively 

referred to as “Indian country”. So, to use the authority in the Tribal NSR Rule to create federallyenforceable limitations, a facility must be located within Indian country. Land ownership status (for 

example, whether the land is owned by a Tribal member or whether the land is owned in fee or in trust) 

does not affect how the rule applies. 

2. Who Might Want to Request Federally-Enforceable Limitations? 

The primary reason for requesting federally-enforceable limitations is to avoid an otherwise applicable 

federal Clean Air Act program, rule or requirement. Many federal Clean Air Act programs use a 

source’s “potential to emit” (PTE) air pollution to determine which rules or requirements apply. A 

facility’s PTE is based on the maximum annual operational (production, throughput, etc) rate of the 

facility taking into consideration the capacity and configuration of the equipment and operations. 

Emission or operational limits can also be taken into consideration as maximums if they are federally 

enforceable. So, using a synthetic minor NSR permit to establish federally enforceable limitations can 

lower a facility’s PTE and possibly allow the facility to avoid certain federal Clean Air Act 

requirements. 

Three examples of federal Clean Air Act programs that use PTE to determine whether they apply are 

(1) the Prevention of Significant Deterioration (PSD) construction permitting program, (2) the Title V 

operating permit program, and (3) the Maximum Achievable Control Technology (MACT) program. 

For example, existing sources that are considered “major” for Title V (meaning they have the potential 

to emit air pollution at levels defined in that rule as “major”) must apply for a Title V operating permit. 

If a source accepts a federally-enforceable limitation through a synthetic minor NSR permit that 

reduces their PTE to below the “major” threshold, and the source does not meet any of the other 

requirements that would trigger applicability to the part 71 program, then the source no longer needs a 

Title V operating permit. When planning for the construction of a new source or expansion of an 

existing source, a source can also accept limitations on PTE (using a synthetic minor NSR permit) that 

allow the source to avoid PSD. Limitations on PTE can similarly help a source to avoid new MACT 

standards that would otherwise apply to the source. 

3. Section B. ATTACHMENTS 

This section lists the information that must be attached to the application form for each requested 

limitation. The requested limitation(s) must be described for each affected emissions unit (or pollutantgenerating activity) and pollutant and must be accompanied by the supporting information listed on the 

form and described below. Note that applicability of many federal Clean Air Act requirements (such as 

Title V, PSD and MACT) is often based on facility-wide emission levels of specific pollutants. In that 
Page 3 of 4 

case, all emissions units at a facility and all pollutants regulated by that given rule or regulation must 

be addressed by this section of the application form. 

Item 1 – The requested limitation and its effect on actual emissions or potential to emit must be 

presented in enough detail to document how the limitation will limit the source’s actual or potential 

emissions as a legal and practical matter and, if applicable, will allow the source to avoid an otherwise 

applicable requirement. The information presented must clearly explain how the limitation affects each 

emission unit and each air pollutant from that emission unit. Use the information provided in response 

to Item 4 below to explain how the limitation affects emissions before and after the limitation is in 

effect. 

Item 2 – For each requested limitation, the application must include proposed testing, monitoring, 

recordkeeping and reporting that will be used to demonstrate and assure compliance with the 

limitation. Testing approaches should incorporate and reference appropriate EPA reference methods 

where applicable. Monitoring should describe the emission, control or process parameters that will be 

relied on and should address frequency, methods, and quality assurance. 

Item 3 – The application must include a description and estimated efficiency of air pollution control 

equipment under present or anticipated operating conditions. For control equipment that is not 

proposed to be modified to meet the requested limit, simply note that fact; however, for equipment that 

is proposed to be modified (e.g. improved efficiency) or newly installed to meet the proposed limit, 

address both current and future descriptions and efficiencies. Include manufacturer specifications and 

guarantees for each control device. 

Items 4 – Any emission estimates submitted to the Regional Administrator must be verifiable 

using currently accepted engineering criteria. The following procedures are generally 

acceptable for estimating emissions from air pollution sources: 

(i) Source-specific emission tests; 

(ii) Mass balance calculations; 

(iii) Published, verifiable emission factors that are applicable to the source. (i.e., manufacturer 

specifications). 

(iv) Other engineering calculations; or 

(v) Other procedures to estimate emissions specifically approved by the Regional Administrator. 

Post-Change Allowable Emissions: A source’s allowable emissions for a pollutant is expressed in tpy 

and generally is calculated by multiplying the allowed hourly emissions rate in pounds per hour 

(lbs/hr) times allowed hours (which is the number of hours in a year) and dividing by 2,000 (which is 

the number of pounds in a ton). 

Item 5 - New construction projects that have the potential to emit GHG emissions of at least 100,000 

tpy CO2e and 100 or 250 tpy on a mass basis, modifications at existing PSD facilities that increase 

GHG emissions by at least 75,000 tpy CO2e and minor sources that increase GHG emissions by at least 

100,000 tpy CO2e and 100 or 250 tpy on a mass basis are subject to PSD permitting requirements, even 

if they do not significantly increase emissions of any other pollutant. As such, any requested limits to 

avoid PSD must take into account greenhouse gases. 

Therefore, please include in your permit application estimates of the potential emissions of the 

following pollutants before and after proposed emission controls. More information about GHG 

permitting and how to calculate CO2 equivalents (CO2e), the mass emissions of each individual GHG 
Page 4 of 4 

adjusted for its Global Warming Potential (GWP) can be found at: 

http://epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf 

1. Carbon dioxide (CO2) 

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 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

NORTH JOHN ELK 28-27 HC PAD ATTACHMENTS: 

Attachment A: Application Report 

Attachment B: Emission Inventory 

Attachment C: Flashing Emissions Calculations 

Attachment D: Representative Low Pressure Oil Analytical Data 

Attachment E: Representative Gas Analysis 

Attachment F: Engine Manufacturer’s Specs 

Attachment G: Emission Control Device Manufacturer’s Specs 

Attachment H: Process Flow Diagram of Facility 

Attachment I: Production Decline Curve Calculations 

Attachment J: Diesel Tank EPA TANKS 4.09d Emission Summary 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT A: APPLICATION REPORT 
APPLICATION FOR AN NSR 

SYNTHETIC MINOR 

AIR QUALITY PERMIT 

NORTH JOHN ELK 28-27HC 

PAD OIL & GAS 

PRODUCTION FACILITY 

Prepared for: 

Dakota-3 E&P Company, LLC 

1001 17th Street, Suite 1200 

Denver, CO 80202 

Prepared by: 

Bison Engineering, Inc. 

1400 11th Avenue 

Helena, MT 59601 

(406) 442-5768 

www.bison-eng.com 

September 30, 2011
North John Elk 28-27HC Pad 09/30/11 pg. ii 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

TABLE OF CONTENTS 

1.0 INTRODUCTION .................................................................................................. 1 

 1.1 Summary ................................................................................................... 1 

 1.2 Site Location .............................................................................................. 1 

 1.3 Site Description .......................................................................................... 1 

2.0 NARRATIVE DESCRIPTION................................................................................ 3 

3.0 POTENTIAL TO EMIT ESTIMATE ....................................................................... 5 

 3.1 Production Storage Tank VOC Emissions ................................................. 8 

 3.2 Produced Casing Head Gas Emissions ..................................................... 8 

 3.3 Reciprocating Internal Combustion or Compression Ignition Engines ....... 9 

 3.4 Natural Gas External Combustion Unit Emissions ..................................... 9 

 3.5 Truck Loading Emissions ........................................................................... 9 

 3.6 Fugitive Emissions: Dust and Equipment Leaks ....................................... 9 

 

4.0 EMISSIONS AND OPERATIONAL LIMITS REQUESTS ................................... 10 

 4.1 Production Storage Tank Emissions ........................................................ 10 

 4.2 Reciprocating Internal Combustion or Compression Ignition Engines ..... 10 

5.0 ALLOWABLE EMISSIONS ................................................................................. 11 

 5.1 Storage Tank Emissions .......................................................................... 11 

 5.2 Produced Casing Head Gas Emissions ................................................... 11 

 5.3 Rice Engine Emissions ............................................................................ 11 

 5.4 Natural Gas External Combustion Unit Emissions ................................... 11 

 5.5 Truck Loading Emissions ......................................................................... 12 

 5.6 Fugitive Emissions: Dust and Equipment Leaks ..................................... 12 

 5.7 Diesel Storage Tank Emissions ............................................................... 12 

6.0 PROPOSED MONITORING AND RECORDKEEPING ...................................... 13

 6.1 Production Storage Tanks ....................................................................... 13 

 6.2 Production Storage Tank Emissions Control Device ............................... 14 

 6.3 Produced Casing Head Gas Emergency Utility Flare .............................. 16 

 6.4 Rice Engines ............................................................................................ 17 

 6.5 Natural Gas-Fired External Combustion Units ......................................... 17 

 6.6 Truck Loading .......................................................................................... 18 

 6.7 Fugitive Emissions: Dust and Equipment Leaks ..................................... 18 

 6.8 General Recordkeeping Requirements .................................................... 20 

7.0 QUALITATIVE AIR QUALITY ASSESSMENT .................................................... 21 

8.0 ENDANGERED SPECIES ACT .......................................................................... 22 

9.0 NATIONAL HISTORIC PRESERVATION ACT .................................................. 23 
North John Elk 28-27HC Pad 09/30/11 pg. iii 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

ATTACHMENTS 

Attachment A: Application Report 

Attachment B: Emission Inventory Spreadsheets 

Attachment C: E&P Tank V2 Emission Summary Output 

Attachment D: Representative Low Pressure Oil Analytical Data 

Attachment E: Representative Gas Analysis 

Attachment F: Engine Manufacturer’s Specs 

Attachment G: Emission Control Device Manufacturer’s Specs 

Attachment H: Process Flow Diagram of Facility 

Attachment I: Production Decline Curve Calculations 

Attachment J: Diesel Tank EPA TANKS 4.09d Emissions Summary 
North John Elk 28-27HC Pad 09/30/11 pg. 1 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

1.0 INTRODUCTION 

1.1. Summary 

Dakota-3 E&P Company, LLC (Dakota-3) is submitting this application for a Prevention 

of Significant Deterioration (PSD) synthetic minor permit to the Environmental 

Protection Agency (Agency) in accordance with the requirements of the Consent 

Agreement dated August 29, 2011, regarding compliance with the Federal Minor New 

Source Review (NSR) Rule (40 CFR 49) adopted pursuant to the Federal Clean Air Act. 

Dakota-3 signed the Consent Agreement to address the unique situation where a 

synthetic minor source permit could not be obtained prior to commencing construction 

because the new Tribal Minor NSR Rule’s August 30, 2011, implementation date did not 

feasibly allow time for preparation, review and processing of applications and permits. 

Under the Consent Agreement, Dakota-3 is required to submit, by October 1, 2011, 

synthetic minor preconstruction permit applications for all oil and gas production 

facilities within the Fort Berthold Indian Reservation (FBIR) in North Dakota. These 

applications are for facilities that are anticipated to commence construction between 

August 31, 2011, and December 31, 2011 (Table A-2 of the Consent Agreement). 

Dakota-3 is proposing to construct and operate the North John Elk 28-27HC Oil and 

Gas (O&G) production facility on the FBIR. Included in this application for a synthetic 

minor permit are allowable emissions specified by requested federally enforceable 

permit conditions that limit the emissions from the facility to below the PSD major 

source thresholds. These limits can be found in Section 4.0 of the application. 

1.2. Site Location 

The North John Elk 28-27HC Pad is proposed to be located in the northeast 1⁄4 of the 

southwest 1⁄4 Section 28, Township 150 North, Range 93 West, Dunn County, on the 

FBIR in North Dakota. 

1.3. Site Description 

 

At the proposed North John Elk 28-27HC Pad there will be one oil and gas well that is 

currently proposed to produce to the facility. The facility will be situated on an 

approximately ten acre site, with an elevation of approximately 2,000 feet (mean sea 

level), in Dunn County, North Dakota. The surrounding area is mainly used for 

agriculture and livestock grazing. The proposed pad’s associated well name is: 

1. North John Elk 28-27HC 

The name of the well may be subject to change due to landowner requirements, drilling 

location changes, timing of well leases, etc. The Agency will be notified if the name 

changes. 
North John Elk 28-27HC Pad 09/30/11 pg. 2 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

2.0 NARRATIVE DESCRIPTION 

This section of the application provides a detailed description of the operations at the 

North John Elk 28-27HC Pad. For purposes of estimating emissions from this facility, 

the first twelve-month potential production from the proposed well at this facility was 

used. These production rates can be found in Attachment B, Emission Inventory. 

The entire pad facility will consist of the following primary production equipment and 

capabilities. 

1 - Heater Treater/Separator 1 - Line-Heater (0.75 MMBtu/hr max) 

4 - Oil Production Tanks 1 - Gasoline Recycling Pump 

1 - Produced Water Tank 1 - Electric Lifting Unit 

1 - Oil and Gas Producing Well 1 - Truck Loading Rack 

1 - Manufactured Produced Gas Flare 1 - Diesel Engine 

1 - Manufactured Enclosed Tank Vapor Combustor 1 - LACT Unit 

The oil/gas/water emulsion being produced from the well is transported up the wellbore 

using an electric lifting unit. The emulsion from the well producing to this site is 

transported in a closed system to individual two-phased separator and then to the threephase separator (heater treater). The initial two-phase separator reduces the pressure 

of the oil/gas/water emulsion to allow the gas to separate from the oil and water. The 

heater treater then reduces the pressure closer to ambient pressure and heats the 

leftover emulsion using a flame-arrested line-heater. The combination of higher 

temperatures and low pressures allow for additional separation of the gas/oil/water 

phases from each other because of differences in densities. The line-heater is fueled by 

onsite produced casing head gas that is routed to the heater’s combustion chamber. 

Propane may also be used as an alternative fuel if necessary. Following the heater 

treater the oil and water are routed to their separate storage tanks. 

The produced casing head gas is transferred from the two-phase separator to the sales 

gas pipeline. An onsite utility flare serves as an emergency backup in the event that the 

gas cannot be placed into the sales line. The oil and water production tank’s working, 

standing, breathing, and flashing vapors are routed to an enclosed combustion device. 

The stored oil is typically transported for sale via the Lease Automated Custody 

Transfer (LACT) unit, with the truck loadout serving as an emergency backup if there 

was a malfunction with the oil pipeline. Produced water is stored in the onsite water 

storage tank until it is transported offsite using the water pipeline. 

At the facility, there is a small gasoline fueled pump located near the production storage 

tanks. This pump is commonly known as a “transfer” or “recycle.” The pump is used to 

periodically recycle the liquids (oil/water) in the bottom of the production tanks back into 

the heater treater for further separation. Otherwise, the facility is completely electrified; 

however, the electricity lines have not yet been installed at the facility. An onsite diesel 

genset engine will provide electricity until transmission lines are installed. 
North John Elk 28-27HC Pad 09/30/11 pg. 3 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

A process flow diagram and plot plan of the site is shown in Attachment H. 
North John Elk 28-27HC Pad 09/30/11 pg. 4 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

3.0 POTENTIAL TO EMIT ESTIMATE 

In estimating the average production for the first twelve months, a decline curve was 

developed. The decline curve takes into account the fact that the initial production of the 

well will greatly decline over the initial twelve months of production. Assuming that the 

well’s production would be equivalent to the initial production will grossly overestimate 

production and is not realistic for how an oil and gas well operates. The decline curve 

calculated for this facility was developed using existing well data from wells previously 

drilled and producing in the same region. The confidential decline curve estimations are 

included in Attachment I of the application. 
North John Elk 28-27HC Pad 09/30/11 pg. 5 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

Potential emissions from this facility originate primarily from the heater treater lineheater emissions, the production storage tank uncontrolled emissions, truck loading 

emissions, diesel genset emissions, and fugitive emissions (e.g., truck loading, 

equipment leaks and road dust). The maximum design capacity of the engine and 

natural gas-fired external combustion unit, in conjunction with maximum annual 

anticipated oil and gas production rates of this facility, were used in determining the 

facility’s potential to emit (PTE). The oil, gas, and water production rates were estimated 

by using data from recently drilled wells in the same region and extrapolating the rates 

for this proposed pad. 

The potential emissions are stated in the Application for New Construction (Form NEW), 

Table E(i) – Proposed New Facility. The emissions from the facility fall into the following 

categories (i.e., emitting units). 

1. Production Storage Tanks (Oil and Water); 

2. Casing Head Gas (Produced Gas); 

3. Reciprocating Internal Combustion Engines (Recycle Pump Engine and 

Diesel Genset) 

4. Natural Gas External Combustion Unit (Heater Treater Line-Heater); 

5. Truck Loading 

6. Miscellaneous Fugitive Emissions (Fugitives); 

3.1 Production Storage Tank VOC Emissions 

To estimate the uncontrolled PTE of the production tank’s vapors (working, breathing, 

standing, and flashing), extended BTEX low pressure oil analyses were taken from 

representative wells producing out of the same geological region. E&P Tanks V2 was 

used to calculate the production tank’s vapors using the anticipated maximum 

production rates, area-specific ambient pressure/temperature data, representative 

process operating conditions, and sampled analytical data. The E&P Tanks output 

summary includes all of the needed input data in the emission inventory, such as the 

vapor rate that is produced from the tanks (scf/bbl), the mol% of the vapor components, 

such as VOCs, HAPs, GHGs, etc. 

All applicable uncontrolled emissions from the storage tanks calculations, low pressure 

analytical data, and E&P TANKS program inputs and outputs are provided in the 

attachments.

3.2 Produced Casing Head Gas Emissions 

At the two-phase separator, +90% of all of the initial casing head gas is separated and 

sent to the gas sales pipeline. After the initial separation occurs, the leftover emulsified 

oil/gas/water is transferred to the three-phase heater treater. The heater treater then 

separates the residual gas from the oil and water. Due to the reduced pressure of the 

heater treater, the sales pipeline pressure is too high to overcome; therefore, the 

residual gas is routed to the onsite utility flare. Furthermore, if the gas sales pipeline 
North John Elk 28-27HC Pad 09/30/11 pg. 6 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

pressure increases to the point at which the produced casing head gas from the twophased separator cannot be sold or the gas pipeline has a malfunction, the flare serves 

as an emergency backup. 

3.3 Reciprocating Internal Combustion or Compression Ignition Engine 

Diesel engine connected to generator provide the facility with electricity. The potential 

emissions from the engine are estimated by assuming the engine is operating 8,760 

hours per year and applying the federally required 40 CFR 63 Subpart JJJJ or 40 CFR 

60 Subparts IIII and ZZZZ emission limits as applicable. 

3.4 Natural Gas External Combustion Unit Emissions 

The natural gas external combustion unit at the facility is the heater treater line-heater. 

The heater is rated to a maximum capacity of 750,000 Btu/hr. The emissions are based 

on AP-42 factors and assume the heater is running 8,760 hours per year. 

3.5 Truck Loading Emissions 

The facility is connected to the oil pipeline via the LACT unit; therefore, no emissions 

are associated with truck loading. The only time truck loading would occur is under 

emergency or malfunction situations. 

3.6 Fugitive Emissions: Dust and Equipment Leaks 

Fugitive emissions from equipment leaks and dust are not required to be estimated for 

purposes of potential to emit within the NSR permitting program. However, the fugitive 

emissions will be estimated after a final permit is issued and production begins in order 

to track to the twelve-month rolling average actual emissions. The fugitive leak 

emissions primarily consist of leaks from connectors, open-ended lines, valves, pumps, 

etc. These emissions will be estimated using EPA’s average emissions factors for total 

hydrocarbon emissions from O&G production operations. The fugitive dust emissions 

will be estimated using AP-42 factors to capture the emissions associated with vehicle 

traffic at the location. 
North John Elk 28-27HC Pad 09/30/11 pg. 7 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

4.0 EMISSIONS AND OPERATIONAL LIMITS REQUESTS 

Datoka-3 is requesting emissions and operational limits at the North John Elk 28-27HC 

Pad in order to obtain a synthetic minor status with regard to the NSR permitting 

programs. The federally enforceable permit conditions will allow Dakota-3 to operate the 

facility while emitting less than the PSD major source thresholds of 250 tons per year of 

a regulated criteria pollutant, 10 tons per year of an individual HAP, and 25 tons per 

year of all emitted HAPs. 

4.1 Production Storage Tank Emissions 

The majority of emissions associated with the facility occur from the working, breathing, 

standing, and flashing vapors from the production storage tanks. Therefore, Dakota-3 

will control the storage tank VOC and HAP emissions by installing an enclosed 

smokeless combustion device that has been independently tested and certified to 

exceed the requirements of 40 CFR 60.18 at 98% destruction efficiency (DRE). 

Although this control device is certified to meet 99% DRE, Dakota-3 will assume the 

minimum required 98% DRE for purposes of calculating the controlled tank vapor 

emissions. This control device will allow Dakota-3 to apply a 98% control efficiency to 

the uncontrolled PTE. On this basis, the requested emission limit from the storage tanks 

is: 4.92 tons per year of VOCs. 

4.2 Reciprocating Internal Combustion or Compression Ignition Engines 

Dakota-3 will be required to limit the emissions from any reciprocating internal 

combustion or compression ignition engine being operated at the facility due to the 

federally enforceable requirements of 40 CFR 63 Subpart JJJJ or 40 CFR 60 Subparts 

IIII and ZZZZ, as applicable. 
North John Elk 28-27HC Pad 09/30/11 pg. 8 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

5.0 ALLOWABLE EMISSIONS 

The allowable emissions are the new estimated controlled potential to emit based on 

the federally enforceable controls and limits requested in Section 4. The allowable 

emissions are also presented in the Application for New Construction (Form NEW), 

Table E(i) – Proposed New Facility. 

5.1 Storage Tank Emissions 

The storage tank controlled emissions are estimated by applying 98% control efficiency 

to the uncontrolled VOC, HAP, and CH4 emissions. Although the VOC, HAP, and CH4

emissions are reduced by the smokeless combustion device, CO, NOx, PM, PM10, PM2.5 

and N2O emissions are created by the combustion process. These emissions estimates 

are calculated using AP-42 factors and applying the weight percentages of the criteria 

pollutant and greenhouse gas components from a representative gas analysis. 

5.2 Produced Casing Head Gas Emissions 

As stated in Section 3, the produced casing head gas is transferred to the gas sales 

pipeline. However, the residual gas released from the oil/gas/water emulsion in the 

heater treater will be sent to the onsite utility flare. Furthermore, if the gas sales pipeline 

pressure increases to the point at which the produced casing head gas from the twophased separator cannot be sold or the gas pipeline has a malfunction, the flare serves 

as an emergency backup. No limits have been requested for the produced casing head 

gas emissions at the facility; therefore, the emissions estimate is equal to the potential 

to emit. 

5.3 RICE Engine Emissions 

No limits have been requested for the RICE at the facility. Dakota-3 is required to meet 

the federally enforceable emission standards depending on the size (hp) and date of 

manufacture; therefore, the emissions estimate is equal to the uncontrolled potential to 

emit. 

5.4 Natural Gas External Combustion Unit Emissions 

No limits have been requested for the natural gas external combustion unit (0.5-0.75 

MMBtu/hr heater treater line-heater) at the facility; therefore, the emissions estimate is 

equal to the uncontrolled potential to emit. 
North John Elk 28-27HC Pad 09/30/11 pg. 9 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

5.5 Truck Loading Emissions 

The facility is connected to the oil pipeline via the LACT unit; therefore, no emissions 

are associated with truck loading. The only time truck loading would occur is under 

emergency or malfunction situations with the oil pipeline; therefore, there are no 

emissions associated with truck loading. 

5.6 Fugitive Emissions: Dust and Equipment Leaks 

Fugitive emissions from equipment leaks and dust are not required to be estimated for 

purposes of potential to emit within the NSR permitting program. However, the fugitive 

emissions will be estimated after a final permit is issued in order to track the twelvemonth rolling average actual emissions. The fugitive leak emissions primarily consist of 

leaks from connectors, open-ended lines, valves, pumps, etc. These emissions will be 

estimated using EPA’s average emissions factors for total hydrocarbon emissions from 

O&G production operations. The fugitive dust emissions will be estimated using AP-42 

factors to capture the emissions associated with vehicle traffic on the location. 

5.7 Diesel Storage Tank Emissions 

There will be an onsite storage tank at this facility to store diesel fuel that will be utilized 

in the diesel genset. This tank will be either a horizontal or vertical 1,000 gallon tank. 

Emissions for this tank were estimated using EPA TANKS 4.09d and determined to be 

less than 0.01 tpy. Because of the low level of emissions from this equipment, it has 

been determined to have insignificant emissions. The EPA TANKS 4.09d emissions 

summary output is in Attachment J. 
North John Elk 28-27HC Pad 09/30/11 pg. 10 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

6.0 PROPOSED MONITORING AND RECORDKEEPING 

As per the Application for Synthetic Minor Limit Request (Form SYNMIN), Page 1 (B), 

ATTACHMENTS, Item, 2, Datoka-3 is required to propose testing, monitoring, 

recordkeeping, and reporting requirements that will be used to demonstrate and assure 

compliance with the proposed allowable emissions. 

6.1 Production Storage Tanks 

The production storage tanks will have their flashing and standing/working/breathing 

vapors routed by a closed-vent system to equipment designed to capture the VOC and 

total HAP emissions generated at the facility for sale or other beneficial purposes, or an 

emissions control device that achieves a minimum of 98% destruction efficiency. 

Dakota-3 will follow the tank manufacturer’s recommended maintenance schedule and 

procedures to ensure optimum performance. Furthermore, Dakota-3 will employ the 

following methods to ensure the tank vapors are efficiently being routed to the 

requested proposed device(s): 

a. Thief hatch covers will be weighted and properly seated; 

b. Pressure relief valves (PRV) will be set to release at a pressure that will ensure 

flashing, and standing/working/breathing losses are routed through a closed-vent 

system to equipment designed to capture the VOC and total HAP vapors. The 

vapors will be routed to equipment designed for sale or other beneficial purpose, 

or an emissions control device; and 

c. Periodic measurements of the peak pressure and vacuum values in the vapor 

recovery and control systems will be conducted to ensure that the pressure and 

vacuum relief set-points are not being exceeded (e.g., due to fouling or increased 

activity levels) resulting in venting and possible damage to equipment. 

Monitoring Requirements: 

Dakota-3 will estimate the emissions from the production storage tanks by performing 

one of the following methods: 

a. Direct measurement of standing/working/breathing losses by sampling and lab 

analysis; 

b. EPA TANKS 4.0.9d to calculate standing/working/breathing losses; 

c. Direct measurement of flashing emissions by sampling and lab analysis; 

d. Process simulator such as PROMAX, HYSIM, HSYS using site-specific sampling 

and lab analysis to calculate flashing emissions in conjunction with EPA TANKS 

4.0.9d to calculate standing/working/breathing losses; 

e. API E&P TANKS Software V2.0 using representative sampling and lab analysis 

to calculate standing/working/breathing losses and flashing emissions; or 

f. Other methods approved by EPA. 
North John Elk 28-27HC Pad 09/30/11 pg. 11 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

Recordkeeping Requirements: 

Total VOC, total HAP, and any single HAP emissions, in tons, from production storage 

tanks will be calculated and recorded at the end of each month, beginning with the first 

full calendar month after operations commenced. Prior to twelve full months of 

operation, Dakota-3 will, at the end of each month, add the emissions for that month to 

the calculated emissions for all previous months since operations commenced, where 

applicable, and record the total. Thereafter, Dakota-3 will, at the end of each month, 

add the emissions for that month to the calculated emissions for the preceding eleven 

months and record a new twelve-month total. 

Dakota-3 will keep records of all input parameters and calculations, including the input 

and output reports for the models, used to determine the monthly emissions. 

6.2 Production Storage Tank Emissions Control Device 

The limits requested on the emissions from the storage tanks are directly dependent on 

the production throughput in the tanks. All emissions at the facility will be controlled in 

one or more enclosed combustors and/or utility flares that are designed and operated to 

reduce the mass content of VOC (or VOC and HAP) emissions in the vapors vented to 

the device by at least 98%. 

Dakota-3 will follow, for each enclosed combustion device and utility flare, the 

manufacturer’s written operating instructions, procedures and maintenance schedule to 

ensure good air pollution control practices for minimizing emissions. 

All vent lines, connections, fittings, valves, relief valves, or any other appurtenance 

employed to contain and collect vapors and transport them to the enclosed combustor, 

or utility flare will be maintained and operated during any time the facility is operating. 

Each enclosed combustion device will be: 

a. Designed to have sufficient capacity to achieve at least a 98% destruction 

efficiency for hydrocarbon volumetric flow and BTU content routed to the device; 

b. Operated with a liquid knock-out system to condense any condensable vapors; 

c. Equipped with a thermocouple to detect the presence of a pilot flame with a 

minimum accuracy of ±2 percent of the temperature being monitored expressed 

in °C, or ±2.5 °C; 

d. Equipped with a recording device, such as a chart recorder or similar device, to 

document the presence of a flame; 

e. Equipped with an electronically controlled ignition system with a malfunction 

alarm and remote notification system if the pilot flame fails; 

f. Maintained in a leak-free condition; and 

g. Operated in a smokeless mode. 
North John Elk 28-27HC Pad 09/30/11 pg. 12 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

Monitoring Requirements: 

Dakota-3 will identify, via an independent engineering analysis or a manufacturer or 

vendor guarantee, each control device’s operating parameters within which they will 

meet the 98.0% reduction requirement. Dakota-3 will monitor the control device 

operations to confirm proper operation as follows: 

a. Monitor the pilot flame using a thermocouple and a chart recorder that indicates 

the continuous ignition of the pilot flame; 

b. An inspection of the chart recorder to ensure proper operation will be done 

whenever an operator is on site; at a minimum, quarterly; 

c. A visual inspection of the pilot flame to ensure proper operation will be done 

whenever an operator is on site; at a minimum, quarterly; 

d. Measure one other parameter determined during the independent engineering 

analysis or provide a manufacturer or vendor guarantee; and 

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

combustor or utility flare whenever an operator is on site; at a minimum, 

quarterly. 

Recordkeeping Requirements: 

a. Records will be kept of the site-specific design input parameters provided for the 

independent engineering analysis or provided to the manufacturer or vendor and 

used to properly size the enclosed combustors and utility flares to assure the 

98% reduction requirements. 

b. Records will be kept of all required monitoring of the control device operations. 

c. Records will be kept of any instances in which any control device was bypassed 

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

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

bypasses or downtimes. 

d. Records will be kept of the any exceedance of the operating parameters 

specified in the manufacturer or vendor guarantee or engineering analysis and 

selected for the required monitoring. The records will include the enclosed 

combustor’s total operating time during the calendar month in which the 

exceedance occurred, the date, time and length of time that the parameters were 

exceeded, and the corrective actions taken or the preventative measures 

adopted to operate the facility within that operating parameter. 

e. Records will be kept of any instances in which the pilot flame is not present in the 

enclosed combustor or the utility flare, the date and times that the pilot was not 

present and the corrective actions taken or the preventative measures adopted to 

increase the operating time of the pilot flame. 

f. Records will be kept of any instances in which the thermocouple (or other heat 

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

enclosed combustor or utility flare is not operational, the time period during which 

it was not operational, and the corrective measures taken. 
North John Elk 28-27HC Pad 09/30/11 pg. 13 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

g. Records will be kept of any time periods in which visible emissions are observed 

emanating from an enclosed combustor or utility flare. 

h. Records will be kept of all required testing and monitoring. The records will 

include the following: 

i. Date, place, and time of observations, sampling or measurements; 

ii. Date(s) analyses were performed; 

iii. Companies or entities that performed observations and the analyses; 

iv. Analytical techniques or methods used; 

v. Results of such analyses or measurements; and 

vi. Operating conditions as existing at the time of sampling or measurement. 

i. Monitor the pilot flame using a thermocouple, and/or a chart recorder or other 

means that indicates the continuous ignition of the pilot flame; 

j. A check of the chart recorder or other monitoring device to ensure proper 

operation will be done whenever an operator is on site; at a minimum, quarterly; 

k. A check of the pilot flame to ensure proper operation will be done whenever an 

operator is on site; at a minimum, quarterly; 

l. Measure one other parameter determined during the independent engineering 

analysis or provide a manufacturer or vendor guarantee; and 

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

combustor or utility flare whenever an operator is on site; at a minimum, 

quarterly. 

Dakota-3 will follow, for each enclosed combustion device and utility flare, the 

manufacturer’s written operating instructions, procedures and maintenance schedule to 

ensure good air pollution control practices for minimizing emissions. 

6.3 Produced Casing Head Gas Emergency Utility Flare 

Dakota-3 is not requesting any limits from the produced casing head gas because it is 

being sent to the gas sales pipeline. If a malfunction from the pipeline occurs and the 

gas cannot be sold, Dakota-3 will record the volume of gas sent to the emergency utility 

flare. 

During an emergency or malfunction Dakota-3 will route the produced casing head gas 

to the onsite utility flare that will be designed and operated to reduce the mass content 

of VOC (or VOC and HAP) emissions in the vapors vented to the device by at least 

98%. Dakota-3 will follow, for the utility flare, the manufacturer’s written operating 

instructions, procedures and maintenance schedule to ensure good air pollution control 

practices for minimizing emissions. 

All vent lines, connections, fittings, valves, relief valves, or any other appurtenance 

employed to contain and collect vapors and transport them to the utility flare will be 

maintained and operated during any time the facility is operating. 
North John Elk 28-27HC Pad 09/30/11 pg. 14 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

The emergency utility flare will be: 

a. Designed and operated in accordance with the requirements of 40 CFR 60.18 

and 40 CFR 63.11. 

b. Designed to have sufficient capacity to achieve at least a 98% destruction 

efficiency for hydrocarbon volumetric flow and BTU content routed to the device; 

c. Operated with a liquid knock-out system to condense any condensable vapors; 

d. Equipped with a thermocouple to detect the presence of a pilot flame with a 

minimum accuracy of ±2 percent of the temperature being monitored expressed 

in °C, or ±2.5 °C; 

e. Equipped with a recording device, such as a chart recorder or similar device, to 

document the presence of a flame; 

f. Equipped with an electronically controlled ignition system with a malfunction 

alarm and remote notification system if the pilot flame fails; 

g. Maintained in a leak-free condition; and 

h. Operated in a smokeless mode. 

Monitoring Requirements: 

The monitoring requirements for the emergency utility flare will be the same as 

described above for the production storage tanks control device as specified in Section 

6.2. 

Recordkeeping Requirements: 

The recordkeeping requirements for the emergency utility flare will be the same as 

described above for the production storage tanks control device as specified in Section 

6.2. 

6.4 RICE Engines 

Depending on the size (hp) and date of manufacture, Dakota-3 is required to meet the 

emission standards set forth in 40 CFR 63 Subpart JJJJ or 40 CFR 60 Subparts IIII and 

ZZZZ, as applicable. Dakota-3 will properly operate and maintain the engines as per the 

manufacturer’s specifications to ensure compliance with the above standards. If the 

engines emissions are not certified to meet the required standards, Dakota-3 will have 

performance tests conducted on the engines as required by the applicable subparts. 

6.5 Natural Gas-Fired External Combustion Units 

Due to the insignificant emissions associated with the 0.5 to 0.75 MMBtu/hr natural gas 

(or propane) fired line-heater, no monitoring or recordkeeping requirements are being 

proposed by Dakota-3. 
North John Elk 28-27HC Pad 09/30/11 pg. 15 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

6.6 Truck Loading 

LACT units are utilized to transport the oil and water at this facility into their respective 

pipelines. However, there is a truck loading rack at the facility in case of a malfunction. If 

the truck loading rack must be used in an emergency or malfunction situation, the tank 

trucks will be loaded using submerged fill. 

6.7 Fugitive Emissions: Equipment Leaks 

Dakota-3 will minimize leaks of volatile organics from each piece of equipment in 

hydrocarbon service at this facility. 

Work Practice and Operational Requirements: 

a. At a minimum, Dakota-3 will detect and repair leaks at each tank thief hatch, 

centrifugal compressor vent, reciprocating compressor vent, instrument, meter, 

diaphragm, pressure relief device, dump arm, open-ended valve or line, vent line, 

flange, connection, fitting, or any other appurtenance employed to contain and 

collect vapors and transport them. 

b. Dakota-3 will make the first attempt to repair any leaking equipment within five 

days after the leak is detected. 

c. Any leaking equipment will be repaired as soon as practicable, but no later than 

15 days after the leak is initially detected, unless the repair is technically 

infeasible without a facility shutdown. Such equipment will be repaired before the 

end of the first facility shutdown, after the leak is initially detected. Dakota-3 will 

make the first attempt to repair any leaking equipment within five days after the 

leak is detected. Dakota-3 will minimize leaks of volatile organics from each 

piece of equipment in hydrocarbon service at this facility. 

Monitoring Requirements: 

a. Dakota-3 will conduct leak detection monitoring on an annual basis. If no 

instrument reading of 10,000 ppm or greater is measured for two consecutive 

quarterly monitoring periods, the required monitoring frequency will change from 

quarterly to semi-annual. If no instrument reading of 10,000 ppm or greater is 

measured for two consecutive semi-annual monitoring periods, the required 

monitoring frequency will change from semi-annual to annual. If any single 

instrument reading of 10,000 ppm or greater is measured, the required 

monitoring frequency will change back to quarterly. 

b. Dakota-3 will use one of the following methods to conduct leak detection of the 

equipment: 

i. Method 21 

a) Use the equipment leak detection methods in 40 CFR Part 60, 

Appendix A–7, Method 21; and 

b) If an instrument reading of 10,000 ppm or greater is measured, a leak 
North John Elk 28-27HC Pad 09/30/11 pg. 16 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

is detected. 

ii. Optical Gas Imaging Instrument 

a) Use an optical gas imaging instrument for equipment leak detection in 

accordance with 40 CFR Part 60, Subpart A, §60.18(i)(1) and (2) of the 

Alternative work practice for monitoring equipment leaks; 

b) Any emissions detected by the optical gas imaging instrument are a 

leak unless screened with Method 21 (40 CFR Part 60, Appendix A–7) 

monitoring, in which case 10,000 ppm or greater is designated a leak; 

c) The optical gas image will include an image of the equipment in 

addition to any observed leaks; and 

d) The optical gas imaging instrument will be operated in accordance with 

the instrument manufacturer’s operating parameters. 

iii. Operator Developed Inspection Protocol - Best Management Practices 

a) Develop and use a written inspection protocol approved by EPA, 

based on best management practices, for leak detection; 

b) Any emissions detected by the protocol are a leak unless screened 

with Method 21 (40 CFR Part 60, Appendix A–7) monitoring, in which 

case 10,000 ppm or greater is designated a leak; 

c) The protocol will include the following: 

I. A detailed description of the best management practice to be 

used for leak detection; 

II. A requirement to use a log book that contains a list, summary 

description, or diagram showing the location of all equipment in 

hydrocarbon service at the facility, and the required 

recordkeeping for equipment leaks; and 

III. A requirement that the log book be signed by the inspector at the 

completion of each inspection. 

Recordkeeping Requirements: 

a. Dakota-3 will document and maintain a record of each leak detection inspection 

and repairs. 

b. All leak detection inspection records will include, at a minimum, the following 

information: 

i. Date of the inspection; 

ii. All documentation and/or images produced in the inspection; 

iii. Findings of the inspection; 

iv. Any corrective action taken; and 

v. Inspector's name and signature. 

6.8 General Recordkeeping Requirements 

Total VOC (or VOC, total HAP, and any single HAP) emissions, in tons, from each piece 

of equipment will be calculated and recorded at the end of each month, beginning with 

the first full calendar month after operations commenced. Prior to twelve full months of 

operation, Dakota-3 will, at the end of each month, add the emissions for that month to 
North John Elk 28-27HC Pad 09/30/11 pg. 17 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

the calculated emissions for all previous months since operations commenced, where 

applicable, and record the total. Thereafter, Dakota-3 will, at the end of each month, 

add the emissions for that month to the calculated emissions for the preceding eleven 

months and record a new twelve-month total. 

Dakota-3, when feasible, may use a Supervisory Control and Data Acquisition (SCADA) 

system to monitor and record the needed data. SCADA consists of computer systems 

that monitor and control industrial, infrastructure, or facility-based processes. The 

system may include, but is not limited to, production monitoring, electronic pressure 

indicating transmitters, pilot flame status monitoring, valve position setpoints, 

temperature monitoring, alarm notification, data logging, flowmeter monitoring, etc. 
North John Elk 28-27HC Pad 09/30/11 pg. 18 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

7.0 QUALITATIVE AIR QUALITY ASSESSMENT 

The climatology and air quality of the area of interest is dominated by continental air 

masses with only minor terrain features (from a synoptic point of view) of interest. The 

area has excellent ventilation since large air mass movement is not limited by any 

significant geologic features. This is in stark contrast to other areas in Region 8 that 

may have limited atmospheric mixing due to mountain valleys or large mountain ranges 

that can minimize the effect of air mass movement. 

Ambient air quality data has been gathered in and near the reservation for many years. 

The results of that ambient monitoring network indicate ambient concentrations of all 

pollutants well below the National Ambient Air Quality Standards (40 CFR 50). Those 

measured values include the impact of substantial oil and gas development that has 

occurred in the region including development near the proposed facility. In fact, much of 

the monitoring data yields background values despite the presence of current industrial 

activity and general anthropogenic sources. The reported data shows that the values 

are the same or nearly the same as one would find in a rural location devoid of any 

industrial activity (although industrial activity is clearly nearby). 

A typical single well pad facility’s actual emissions are modest in nature (i.e., below 

typical permitting thresholds); therefore, additional ambient impact analysis is not 

warranted. 
North John Elk 28-27HC Pad 09/30/11 pg. 19 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

8.0 ENDANGERED SPECIES ACT 

The Endangered Species Act (ESA) requires EPA, in consultation with the U.S. Fish 

and Wildlife Service (USFWS) and/or the NOAA Fisheries Service, to ensure that 

actions EPA authorizes are not likely to jeopardize the continued existence of any listed 

threatened or endangered species (TES) or result in the destruction or adverse 

modification of designated critical habitat of such species. 

TES are considered to be those species recognized by the USFWS as listed or 

proposed species, and those designated as candidate TES under the ESA. Whether 

critical habitat for TES exists near the facility will first be assessed by consulting the 

USFWS North Dakota Ecological Service Field Office website 

(http://www.fws.gov/northdakotafieldoffice/index.htm) and noting the potential 

occurrence of each TES by county. Once the potential presence of a species is 

assessed, a look at whether any critical habitat exists in the vicinity of the facility will 

help determine the possibility of any impacts from the facility on TES. EPA will conduct 

an evaluation of the potential for TES impacts from the facility and consult, as 

appropriate, with USFWS regarding identification and mitigation of any impacts.
North John Elk 28-27HC Pad 09/30/11 pg. 20 

NSR Synthetic Minor Permit Application 

Project #: WEP211324

9.0 NATIONAL HISTORIC PRESERVATION ACT 

The National Historic Preservation Act requires EPA, in consultation with State and/or 

Tribal Historic Preservation Officers, to ensure that actions authorized are not likely to 

affect cultural resources. 

The potential for cultural resources in the vicinity of the facility will be assessed by 

consulting with the North Dakota State Historic Preservation Office (NDSHPO) and the 

Tribal Historic Preservation Officer(s), and conducting a literature review of available 

information from the area immediately surrounding the facility 

(http://history.nd.gov/hp/siclass1.html). If the review finds a need for more intensive 

analysis of the immediate area of the facility, a Class II or III cultural resources inventory 

may be performed as required. EPA will conduct the consultation with NDSHPO and 

Tribal officials to identify any cultural resources that could be impacted by the facility 

and any needed mitigation measures for those impacts. 

 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT B: EMISSION INVENTORY 
Facility Information

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC Name of the facility and the well number.

Not Producing Yet Approximate first date of production or the date of modification of the facility.

9/30/2011 Date application packet is submitted to the EPA Region 8.

Production Data Description

BOPD 794.80327 Average daily production in barrels of oil per day (BOPD), based on the predicted first 30 days of production.

Mscfd 552.38828 Average daily production of gas in Mscf per day, based on the predicted first 30 days of production.

Decline Factor 0.505 Expected decline factor for the first year of operation. Based on data from previously producing wells in the same field and formation.

Adjusted BOPD 401.39834 This is the calculated BOPD expected to be produced using the above entered decline factor.

Adjusted Produced Gas (Mscfd) 278.97185 This is the calculated mcfd of gas the well is expected to produce using the above entered decline factor.

Oil/Condensate Tank Data Description

Flash Gas Method: Process Simulator Use the drop down menu to choose the appropriate flash gas method.

Process Simulator Estimated scf/bbl 40.23 The scf/bbl from direct measurement or representative sample. Based on representative E&P Tank Emission Summary Output.

Estimated Tank Vapors (scfd) 16148.255 This is the estimated scfd of tank vapors based on the following: adjusted BOPD multiplied by the scf/bbl entered on Line 9.

Lower Heating Value 2401.97 Lower heating value (Btu/scf) of tank vapors. Based on representative E&P Tank Emission Summary Output.

Molecular Weight 42.14 Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole). Based on representative E&P Tank Emission Summary Output.

VOC% 74.0256 VOC weight fraction of the tank vapor gas (C3+). Based on representative E&P Tank Emission Summary Output.

VOC TPY/BOPD Emission Factor 0.6126 Based on representative E&P Tank Emission Summary Output. (Summary Output creates a linear relationship between TPY and BOPD) 

HAP% 1.0459 HAP weight fraction of the tank vapor gas. Based on representative E&P Tank Emission Summary Output.

HAP TPY/BOPD Emission Factor 0.0085 Based on representative E&P Tank Emission Summary Output. (Summary Output creates a linear relationship between TPY and BOPD) 

CO2% 0.26% CO2 weight fraction of the tank vapor gas. Based on representative E&P Tank Emission Summary Output.

CH4% 1.99% CH4 weight fraction of the tank vapor gas. Based on representative E&P Tank Emission Summary Output.

H2S weight % 0.09% H2S weight percent of the tank vapor gas. Based on representative E&P Tank Emission Summary Output.

H2S mole % 0.10% H2S mole percent of the tank vapor gas. Based on representative E&P Tank Emission Summary Output.

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.

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

Input Data

Dakota-3 E&P Company, LLC

GREEN = Requires input
Facility Information

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC Name of the facility and the well number.

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

Input Data

Dakota-3 E&P Company, LLC

GREEN = Requires input

Treater Gas Data Description

Btu/scf 1606.12 Btu/scf of wellstream gas. (From representative field gas analysis)

Molecular Weight 28.068816 Average molecular weight of the wellstream gas in lb/lb-mole. (From representative field gas analysis)

Specific Gravity 0.9690788 If necessary to convert specific gravity to molecular weight, enter the specific gravity of the wellstream gas. (From representative field gas analysis)

Calculated Molecular Weight 28.07 This is the calculated molecular weight based on the specific gravity entered above. Please enter this number on Line 21.

VOC% 43.74% VOC weight fraction of the wellstream gas (Note: Weight%, not Mole%). (From representative field gas analysis)

HAP% 1.05% HAP weight fraction of the wellstream gas. (Note: Weight%, not Mole%). (From representative field gas analysis)

CO2% 0.956% CO2 weight fraction of the wellstream gas. (Note: Weight%, not Mole%). (From representative field gas analysis)

CH4% 29.680% CH4 weight fraction of the wellstream gas. (Note: Weight%, not Mole%). (From representative field gas analysis)

H2S weight % 0.000% H2S weight percent of the wellstream gas. (From representative field gas analysis)

H2S mole % 0.000% H2S mole percent of the wellstream gas. (From representative field gas analysis)

Connected to sales line Use the drop down menu to choose the appropriate emission control type.

Control/Capture Efficiency 100% If routed to pipeline, assumed 100% capture of gas. If flared, control efficiency of any applicable controls (combustor, pit flare, utility flare, etc).

Treater Burner(s) Description

Total Btu/hr 750000 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 Description

Oil is sold through LACT Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a LACT, no input values are required in Lines 30-35.

Submerged 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 operation.

Molecular Weight 42.14 Molecular weight of tank vapors in lb/lb-mole. Assumed same molecular weight as flashing emissions from representative E&P Tanks data.

Vapor Pressure 2.30 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 Truck Loading tab.

Temperature 50.00 Temperature of bulk liquid loaded in Fahrenheit. If no site specific data is available, use an estimated average annual temperature.

Load Rate (bbl/hr) 180 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 and Contollers (None) Description

Glycol Dehydrator (None) Description
Facility:

North John Elk 28-27HC 

Pad

Associated Well:

North John Elk 28-27HC

VOC HAP NOx PM PM10 PM2.5 CO H2S SO2 HCHO

Oil/Condensate Tanks 245.90 3.43 N/A N/A N/A N/A N/A N/A N/A Negligible

Casing Head Gas 3.30 0.08 0.56 0.04 0.04 0.04 3.03 NA 0.00 0.00

Treater Burner 0.02 0.01 0.32 0.02 0.02 0.02 0.27 N/A 0.00 Negligible

RICE Engine 0.90 1.70E-02 4.61 0.03 0.03 0.03 42.08 N/A 2.07E-02 0.02

Truck Loading N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Fuel Storage Tank Negligible Negligible N/A N/A N/A N/A N/A N/A N/A N/A

Pneumatic Pump N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Pneumatic Controllers N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Glycol Dehydrator N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Totals (TPY) 250.11 3.53 5.49 0.09 0.09 0.09 45.38 0.00 0.02 0.02

VOC HAP NOx PM PM10 PM2.5 CO H2S SO2 HCHO

Oil/Condensate Tanks 4.92 0.07 0.48 0.02 0.02 0.02 2.62 N/A N/A Negligible

Casing Head Gas 3.30 0.08 0.56 0.04 0.04 0.04 3.03 0.00 0.00 0.00

Treater Burner 0.02 0.01 0.32 0.02 0.02 0.02 0.27 N/A 0.00 Negligible

RICE Engine 0.90 1.70E-02 4.61 0.03 0.03 0.03 42.08 N/A 2.07E-02 0.02

Truck Loading N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Fuel Storage Tank Negligible Negligible N/A N/A N/A N/A N/A N/A N/A N/A

Pneumatic Pump N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Pneumatic Controllers N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Glycol Dehydrator N/A N/A N/A N/A N/A N/A N/A N/A N/A Negligible

Totals (TPY) 9.14 0.17 5.97 0.11 0.11 0.11 48.00 0.00 0.02 0.02

a

Emissions of lead and lead compounds, fluorides, sulfuric acid mist, total reduced sulfur, and reduced sulfur compounds are assumed to be negiligable for upstream oil & gas operations on the FBIR.

Criteria Pollutants

Criteria Pollutantsa

Dakota-3 E&P Company, LLC

Allowable Potential to Emit

Emission Summary

Uncontrolled Potential to Emit
Facility:

North John Elk 28-27HC 

Pad

Associated Well:

North John Elk 28-27HC

Dakota-3 E&P Company, LLC

CO2 CH4 N2O CO2 CH4 N2O

Oil/Condensate Tanks N/A 6.52 N/A 354.51 0.00 0.01

Casing Head Gas 614.55 2.24 0.00 614.55 2.24 0.00

Treater Burner 386.47 0.02 0.00 386.47 0.02 0.00

RICE Engine 3.78E+01 0.06 0.01 3.78E+01 0.06 0.01

Truck Loading 0.00 0.00 N/A 0.00 0.00 N/A

Fuel Storage Tank N/A N/A N/A N/A N/A N/A

Pneumatic Pump N/A N/A N/A N/A N/A N/A

Pneumatic Controllers N/A N/A N/A N/A N/A N/A

Glycol Dehydrator N/A N/A N/A N/A N/A N/A

Totals (TPY) 1038.87 8.84 0.02 1393.39 2.32 0.02

GHG Mass Emissions (tpy): 1047.73 GHG Mass Emissions (tpy): 1395.73

CO2e (tpy): 1229.52 CO2e (tpy): 1449.26

Applicable to the Tailoring Rule?: No

b Hydrofluorocarbons (HFCs), Perfluorocarbons (PFCs), and Sulfur Hexafluorides (SF6) emissions are not created from O&G production operations.

Actual

Greenhouse Gasesb

Potential To Emit

Greenhouse Gasesb
BOPD

scf/day

Btu/scf

lb/lb-mole

tpy/bopd

HAPs:

Benzene wt Fraction

Toluene wt Fraction

E-Benzene wt Fraction

Xylene wt Fraction

n-Hexane wt Fraction

2,2,4-Trimethylpentane

wt Fraction

HAP Emission Factor tpy/bopd

98% destruction efficiency of the VOC gas.

0.0285%

0.0033%

0.0166%

0.9045%

0.0191%

0.0739%

CH4 wt Fraction

0.009

Controlled emissions are calculated based on a 

0.26%

1.99%

CO2 wt Fraction

Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Tanks

Flare Gas Volume 16,148

Oil Production 401

0.613

Lower Heating Value 2401.97

Molecular Weight 42.14

VOC wt Fraction 74.03%

VOC Emission Factor
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Tanks

Uncontrolled VOCs (PTE):

DRE

Using E&P Tanks Run: 0.613 x 401.398 x 0% = 245.90 TPY

Controlled VOCs (Allowable):

DRE

Using E&P Tanks Run: 0.613 x 401.398 x 98% = 4.92 TPY

Uncontrolled HAPs (PTE):

Using E&P Tanks Run: wt% DRE TPY

Benzene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.03% x 0% = 0.02 lb/hr 0.09

E-Benzene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.00% x 0% = 0.00 lb/hr 0.01

Toluene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.02% x 0% = 0.01 lb/hr 0.05

n-Hexane 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.90% x 0% = 0.68 lb/hr 2.96

Xylene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.02% x 0% = 0.01 lb/hr 0.06

2,2,4-Trimethylpentane 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.07% x 0% = 0.06 lb/hr 0.24

Uncontrolled TOTAL HAPS (TPY) 3.43

Controlled HAPs (Allowable):

Benzene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.03% x 98% = 0.00 lb/hr 0.00

E-Benzene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.00

n-Hexane 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.90% x 98% = 0.01 lb/hr 0.06

Xylene 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.00

2,2,4-Trimethylpentane 673 scf/hr x x 1/379 scf/lb-mole x 42.14 lb/lb-mol x 0.07% x 98% = 0.00 lb/hr 0.00

Controlled TOTAL HAPS (TPY) 0.07

BOPD

TPY VOC/BOPD

TPY VOC/BOPD

CRITERIA POLLUTANT EMISSIONSa

BOPD

=

=

=

=

=

=

=

=

=

=

=

=

=

=
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Tanks

Uncontrolled NOx:

NOx: 0 scf/hr x 2,402 Btu/scf x x 0.068 lb/MMBtu = 0.00 lb/hr

0.00 lb/hr x x 0.00 TPY

NOx Created by Combustion (Actual)

NOx: 673 scf/hr x 2,402 Btu/scf x x 0.068 lb/MMBtu = 0.11 lb/hr

0.11 lb/hr x x 0.48 TPY

Uncontrolled PM:

PM: 0 scf/hr x 7.6 lb/1,000,000 scf = 0.00 lb/hr

0.00 lb/hr x 8760 hr/yr x 0.00 TPY

PM Created by Combustion (Actual)

PM: 673 scf/hr x 7.6 lb/1,000,000 scf = 0.01 lb/hr

0.01 lb/hr x 8760 hr/yr x 0.02 TPY

1 MMBtu/1,000,000 Btu

8760 hr/yr

1 ton/2000 lb =

=

1 ton/2000 lb =

1 ton/2000 lb =

1 ton/2000 lb

1 MMBtu/1,000,000 Btu

8760 hr/yr
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Tanks

Uncontrolled CO:

CO: 0 scf/hr x 2,402 Btu/scf x x 0.370 lb/MMBtu = 0.00 lb/hr

0.00 lb/hr x x 0.00 TPY

CO Created by Combustion (Actual)

CO: 673 scf/hr x 2,402 Btu/scf x x 0.370 lb/MMBtu = 0.60 lb/hr

0.60 lb/hr x x 2.62 TPY

a

NOx, SO2, and CO emission factors are from AP-42 Table 13.5-1

(Emission Factors for Flare Operations).

Uncombusted CO2:

wt DRE

CO2: 673 scf/hr x x 42.14 lb/lb-mole 0.26% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY

CO2 Created by Combustion (Actual)

CO2: 673 scf/hr x 120,000.0 lb/1,000,000 scf = lb/hr

80.74 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 353.65 TPY

1/379 scf/lb-mole x

1 ton/2000 lb

0.20

0.87

80.74

REGULATED GREENHOUSE GAS EMISSIONSb

=

1 MMBtu/1,000,000 Btu

8760 hr/yr 1 ton/2000 lb

0.20

1 MMBtu/1,000,000 Btu

8760 hr/yr 1 ton/2000 lb =
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Tanks

Uncontrolled CH4:

wt DRE

CH4: 673 scf/hr x x 42.14 lb/lb-mole 1.99% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY

Controlled CH4: (Actual)

wt% DRE

CH4: 673 scf/hr x x 42.14 lb/lb-mole 1.99% x 98% = lb/hr

lb/hr x 8760 hr/yr x = TPY

Uncontrolled N2O:

wt% DRE

CH4: 673 scf/hr x x 42.14 lb/lb-mole 0.00% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY

N2O Created by Combustion:

CH4: 673 scf/hr x 2.3 lb/1,000,000 scf = lb/hr

0.00 lb/hr x 8760 hr/yr x = 0.01 TPY

b

CO2 and N2O emission factors are from AP-42 Table 1.4-2

(Emission Factors for Natural Gas Combustion).

x

0.00 0.00

0.00

1 ton/2000 lb

x 0.00

0.03

0.03 0.13

1/379 scf/lb-mole

1/379 scf/lb-mole

1 ton/2000 lb

1 ton/2000 lb

x 1.49

1.49 6.52

1/379 scf/lb-mole

1 ton/2000 lb
scf/hr (Takes into account the 10% of the total

produced gas volume that is not being sold.)

Btu/scf

lb/lb-mole

HAP wt fraction

Benzene wt fraction

E-Benzene wt fraction

Toluene wt fraction

n-Hexane wt fraction

Xylene wt fraction

2,2,4-Trimethylpentane

wt fraction

CO2 wt fraction

CH4 wt fraction

hours/yr

DRE

Dakota-3 E&P Company, LLC

8760 Hours of Flaring for 

PTE:

Control Effiiciency

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

Flare Gas Volume 1,162

Lower Heating Value 1606.12

Avg. Molecular Weight 28.07

VOC wt fraction 43.74%

1.05%

0.03%

0.00%

0.02%

0.90%

0.02%

0.07%

0.96%

29.68%

98%
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

Controlled VOCs (PTE):

wt% Control %

VOC: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 43.74% x 98% = lb/hr

0.75 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

Controlled VOCs (Allowable):

wt% Control %

VOC: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 43.74% x 98% = lb/hr

0.75 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

3.30

0.75

3.30

x

CRITERIA POLLUTANT EMISSIONSa

x 0.75
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

Controlled HAPs (PTE):

Using E&P Tanks Run: wt% Control % TPY

Benzene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.03% x 98% = 0.00 lb/hr 0.00

E-Benzene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.00

n-Hexane 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.90% x 98% = 0.02 lb/hr 0.07

Xylene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.00

2,2,4-Trimethylpentane 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.07% x 98% = 0.00 lb/hr 0.01

Formaldehyde 1,162 scf/hr 7.50E-02 lb/MMscf = 0.00 lb/hr 0.00

` 0.02 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

Controlled HAPs (Allowable):

Using E&P Tanks Run: wt% Control % TPY

Benzene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.03% x 98% = 0.00 lb/hr 0.00

E-Benzene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.00

n-Hexane 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.90% x 98% = 0.02 lb/hr 0.07

Xylene 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.00

2,2,4-Trimethylpentane 1,162 scf/hr x x 1/379 scf/lb-mole x 28.06882 lb/lb-mol x 0.07% x 98% = 0.00 lb/hr 0.01

Formaldehyde 1,162 scf/hr x 7.50E-02 lb/MMscf x 1000000 scf/MMscf = 0.00 lb/hr 0.00

` 0.02 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

=

=

=

=

0.08

=

=

=

=

=

=

=

=

=

=

0.08
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

Uncontrolled NOx (PTE):

NOx: 1,162 scf/hr x 1,606 Btu/scf x x 0.068 lb/MMBtu = 0.13 lb/hr

0.13 lb/hr x 8760 hr/yr x 0.56 TPY

NOx Created by Combustion (Actual):

NOx: 1,162 scf/hr x 1,606 Btu/scf x x 0.068 lb/MMBtu = 0.13 lb/hr

0.13 lb/hr x 8760 hr/yr x 0.56 TPY

Controlled H2S (PTE):

wt% Control %

H2S: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 0.00% x 98% = lb/hr

0.00 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

Controlled H2S (Actual):

wt% Control %

H2S: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 0.00% x 98% = lb/hr

0.00 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

x

0.00

=

1 Mmbtu/1,000,000 Btu

1 ton/2000 lb =

x 0.00

0.00

1 ton/2000 lb

1 Mmbtu/1,000,000 Btu

0.00
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

SO2 Created by Combustion (PTE):

wt% Control %

SO2 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 0.00% x 98% = lb/hr

0.00 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

SO2 Created by Combustion (Actual):

wt% Control %

SO2 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 0.00% x 98% = lb/hr

0.00 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

CO Created by Combustion (PTE):

CO: 1,162 scf/hr x 1,606 Btu/scf x x 0.370 lb/MMBtu = 0.69 lb/hr

0.69 lb/hr x 8760 hr/yr x 3.03 TPY

CO Created by Combustion (Actual):

CO: 1,162 scf/hr x 1,606 Btu/scf x x 0.370 lb/MMBtu = 0.69 lb/hr

0.69 lb/hr x 8760 hr/yr x 3.03 TPY

0.00

0.00

0.00

=

0.00

=

1 ton/2000 lb

x

1 Mmbtu/1,000,000 Btu

1 ton/2000 lb

x

1 Mmbtu/1,000,000 Btu
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

PM Created by Combustion (PTE):

PM: 1,162 scf/hr x 7.6 = 0.01 lb/hr

0.01 lb/hr x 8760 hr/yr x 0.04 TPY

PM Created by Combustion (Actual):

PM: 1,162 scf/hr x 7.6 = 0.01 lb/hr

0.01 lb/hr x 8760 hr/yr x 0.04 TPY

=

 lb/1,000,000 scf

(Emission Factors for Flare Operations and Natural Gas Combustion).

 lb/1,000,000 scf

1 ton/2000 lb =

1 ton/2000 lb

a

NOx, SO2, PM, & CO emission factors are from AP-42 Table 13.5-1 and Table 1.4-2
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

CO2 (PTE):

CO2 Entrained in the Produced Gas:

Control %

CO2: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 0.96% x 98% = lb/hr

0.82 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 3.61 TPY

CO2 Created by Combustion:

CO2: 1,162 scf/hr x 120,000.0 = 139.49 lb/hr

`

139.49 lb/hr x 8760 hr/yr x 610.95 TPY

614.55 TPY

CO2 (Actual):

CO2 Entrained in the Produced Gas:

wt% Control %

CO2: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 0.96% x 98% = lb/hr

0.82 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 3.61 TPY

CO2 Created by Combustion: `

CO2: 1,162 scf/hr x 120,000.0 = 139.49 lb/hr

`

139.49 lb/hr x 8760 hr/yr x 610.95 TPY

614.55 TPY

REGULATED GREENHOUSE GAS EMISSIONSb

1 ton/2000 lb =

x 0.82

Total CO2 Emitted (Allowable):

1 ton/2000 lb =

 lb/1,000,000 scf

 lb/1,000,000 scf

Total CO2 Emitted (PTE):

x 0.82
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Casing Head Gas

Controlled CH4 (PTE):

wt% Control %

CH4: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 29.68% x 98% = lb/hr

0.51 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

Controlled CH4 (Actual):

wt% Control %

CH4: 1,162 scf/hr x 1/379 scf/lb-mole x 28.06882 lb/lb-mole 29.68% x 98% = lb/hr

0.51 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

N2O Created by Combustion (PTE):

N2O: 1,162 scf/hr x 2.2 = 2.56E-03 lb/hr

2.56E-03 lb/hr x 8760 hr/yr x 6.39E-04 TPY

N2O Created by Combustion (Actual):

N2O: 1,162 scf/hr x 2.2 = 2.56E-03 lb/hr

2.56E-03 lb/hr x 8760 hr/yr x 6.39E-04 TPY

(Emission Factors for Natural Gas Combustion).

x 0.51

2.24

1 ton/2000 lb =

 lb/1,000,000 scf

 lb/1,000,000 scf

b

CO2 and N2O emission factors are from AP-42 Table 1.4-2

1 ton/2000 lb =

0.51

2.24

x
750,000 Btu/hr This burner rating reflects the combined size of all of the proposed heater treater burners at the facility.

NOx: 0.10 lb/MMBtu x 0.75 MMBtu/hr = 0.074 lb/hr

0.0735 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.322 TPY

CO: 0.08 lb/MMBtu x 0.75 MMBtu/hr = 0.062 lb/hr

0.06 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.271 TPY

SO2: 5.88E-04 lb/MMBtu x 0.75 MMBtu/hr = 0.000 lb/hr

4.41E-04 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.002 TPY

PM: 0.01 lb/MMBtu x 0.75 MMBtu/hr = 0.006 lb/hr

0.01 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.024 TPY

VOC: 0.01 lb/MMBtu x 0.75 MMBtu/hr = 0.004 lb/hr

0.00 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.018 TPY

HAP: 0.002 lb/MMBtu x 0.75 MMBtu/hr = 0.001 lb/hr

1.39E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.006 TPY

CO2 117.647 lb/MMBtu x 0.75 MMBtu/hr = 88.235 lb/hr

8.82E+01 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 386.471 TPY

CH4: 0.007 lb/MMBtu x 0.75 MMBtu/hr = 0.005 lb/hr

4.96E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.022 TPY

N2O: 0.001 lb/MMBtu x 0.75 MMBtu/hr = 0.001 lb/hr

9.92E-04 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.004 TPY

NOx TPY

CO TPY

SO2 TPY

PM TPY

VOC TPY

HAP TPY

CO2 TPY

CH4 TPY

N2O TPY

Dakota-3 E&P Company, LLC

386.47

0.02

0.00

0.27

0.02

0.01

0.00

0.02

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Heater Treater Burnera

a

NOx, CO, CO2, & VOC Emission Factors are from AP-42 Table 1.4-1 and 1.4-2 (Emission Factors for

Nitrogen Oxides (N2O) and Methane come from Table C-1 of Subpart W).

Burner Rating

0.32
Saturation Vapor Molecular Temp + Load Loss

Factor (S) Pressure (P) Weight (MW) 460 lb/1000 gal

12.46 x 0.60 x 2.30 x 42.14 / 510.00 = 1.42

LL Truck Load Load Time

lb/1,000 gal Rate bbl/hr hrs gal/bbl

1.42 x 180.00 / 1.00 x 42.00 = 10.74

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.42 x 146510.39 x 42.00 / 2000.00 = 4.37 3.23

VOC

Emissions

Uncontrolled Control % TPY

3.23 100% 0.00 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.42 x 146510.39 x 42.00 / 2000.00 = 4.37 0.05

HAPs

Emissions

Uncontrolled Control % TPY

0.05 100% 0.00 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.42 x 146510.39 x 42.00 / 2000.00 = 4.37 0.01

CO2

Emissions

Uncontrolled Control % TPY

0.01 100% 0.00 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.42 x 146510.39 x 42.00 / 2000.00 = 4.37 0.09

CH4

Emissions

Uncontrolled Control % TPY

0.09 100% 0.00 0.00

Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Truck Loadout Emission Calculation

Total Gas 

Emissions lb/hr

Uncontrolled 

C3+ VOC tpy

Uncontrolled 

HAPs tpy

Uncontrolled 

CO2 tpy

Uncontrolled 

CH4 tpy
Combined Diesel Engines

Hours of Operation 8760

Maximum HP Rating 275

NOx g/hp-hr 1.49E+00

CO g/hp-hr 2.61E+00

SO2 g/hp-hr 4.52E-06

PM g/hp-hr 4.85E-06

VOC g/hp-hr 1.42E-01

HAP g/bh-hr 1.02E-06

CO2 g/bh-hr 2.54E-03

CH4 g/bh-hr 2.10E-02

N2O g/hp-hr 4.20E-03

Recycle Pump

Hours of Operation 8760

Maximum HP Rating 8

NOx g/hp-hr 8.43E+00

CO g/hp-hr 4.55E+02

SO2 g/hp-hr 2.68E-01

PM g/hp-hr 3.27E-01

VOC g/hp-hr 6.80E+00

HAP g/hp-hr 2.20E-01

CO2 g/bh-hr 4.90E+02

CH4 g/hp-hr 2.10E-02

N2O g/hp-hr 4.20E-03

Description

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

Manufacturer's maximum hp rating.

AP-42 Table 3.3-1

AP-42 Table 3.3-1

AP-42 Table 3.3-1

AP-42 Table 3.3-1

AP-42 Table 3.3-1

40 CFR 98 Subpart C, Table C-2

40 CFR 98 Subpart C, Table C-2

AP-42 Table 3.3-1

AP-42 Table 3.3-1

AP-42 Table 3.3-1

AP-42 Table 3.3-1

Manufacturer Guarantee (40 CFR 63 Subpart IIII requirements), see Attachment F

AP-42 Table 3.3-1

AP-42 Table 3.3-1

40 CFR 98 Subpart C, Table C-2

40 CFR 98 Subpart C, Table C-2

Dakota-3 E&P Company, LLC

RICE Input Data

Description

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

Manufacturer's maximum hp rating.

Manufacturer Guarantee (40 CFR 63 Subpart IIII requirements), see Attachment F

Manufacturer Guarantee (40 CFR 63 Subpart IIII requirements), see Attachment F
ENGINE #1

275 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE 0% SO2 DRE 0% HAP DRE 0% PM DRE

##### #### ##### #### ### 100.00%

NOx: 1.49E+00 g/HP-HR 275 HP x 1 lb / 453.6 grams = 9.05E-01 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 3.96E+00 NOx TPY 

CO: 2.61E+00 g/HP-HR 275 HP x 1 lb / 453.6 grams = 1.58E+00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 6.94E+00 CO TPY 

SO2: 4.52E-06 g/HP-HR 275 HP x 1 lb / 453.6 grams = 2.74E-06 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.20E-05 SO2 TPY 

PM: 4.85E-06 g/HP-HR 275 HP x 1 lb / 453.6 grams = 2.94E-06 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.29E-05 PM TPY 

VOC: 1.42E-01 g/HP-HR 275 HP x 1 lb / 453.6 grams = 8.60E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 3.77E-01 VOC TPY 

HAP: 1.02E-06 g/HP-HR 275 HP x 1 lb / 453.6 grams = 6.19E-07 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.71E-06 HCHO TPY 

CO2: 2.54E-03 g/HP-HR 275 HP x 1 lb / 453.6 grams = 1.54E-03 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 6.73E-03 CO2

CH4: 2.10E-02 g/HP-HR 275 HP x 1 lb / 453.6 grams = 1.27E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 5.58E-02 CH4

N2O: 4.20E-03 g/HP-HR 275 HP x 1 lb / 453.6 grams = 2.55E-03 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.12E-02 N2O

Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Reciprocating Engine Emissions 

x

x

x

x

x

x

x

x

x
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Reciprocating Engine Emissions 

8 MAX HP 0% CO DRE 0% VOC DRE 0% SO2 DRE 0% HAP DRE 0% PM DRE

##### #### ##### #### ### 100.00%

NOx: 8.43E+00 g/HP-HR 8 HP x 1 lb / 453.6 grams x 0.15 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 6.51E-01 NOx TPY 

CO: 4.55E+02 g/HP-HR 8 HP x 1 lb / 453.6 grams x 8.02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 3.51E+01 CO TPY 

SO2: 2.68E-01 g/HP-HR 8 HP x 1 lb / 453.6 grams = 4.73E-03 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.07E-02 SO2 TPY 

PM: 3.27E-01 g/HP-HR 8 HP x 1 lb / 453.6 grams = 5.77E-03 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.53E-02 PM TPY 

VOC: 6.80E+00 g/HP-HR 8 HP x 1 lb / 453.6 grams x 0.12 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 5.26E-01 VOC TPY

HAP: 2.20E-01 g/HP-HR 8 HP x 1 lb / 453.6 grams = 0.00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.70E-02 HAP TPY 

CO2: 4.90E+02 g/HP-HR 8 HP x 1 lb / 453.6 grams = 8.64E+00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 3.78E+01 CO2 TPY 

CH4: 2.10E-02 g/HP-HR 8 HP x 1 lb / 453.6 grams = 3.70E-04 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.62E-03 CH4 TPY

N2O: 4.20E-03 g/HP-HR 8 HP x 1 lb / 453.6 grams = 7.41E-05 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 3.24E-04 N2O TPY

ENGINE #2

x

x

x

x

NOx DRE

x

x

x

x

x
Dakota-3 E&P Company, LLC

North John Elk 28-27HC Pad

Associated Well:

North John Elk 28-27HC

Reciprocating Engine Emissions 

4.61E+00

4.21E+01

2.07E-02

2.53E-02

9.02E-01

1.70E-02

3.78E+01

5.74E-02

1.15E-02

SO2 TPY 

CO2 TPY 

CH4 TPY

N2O TPY

TOTALS

NOx TPY 

CO TPY 

VOC TPY 

PM TPY 

HAP TPY 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT C: FLASHING EMISSIONS CALCULATIONS 

• E&P Tanks Emission Summary

• E&P Tanks Linear Relationship (Emission Factor) 
Mandaree Field 1000 BOPD wt%

******************************************************************************************

* Project Setup Information *

******************************************************************************************

Project File : Y:\Projects\Williams Exploration & Production WEP\WEP211324 Ft. Berthold

IR Well Work\E&P Tanks\Mandaree Field 1000 BOPD.ept

Flowsheet Selection : Oil Tank with Separator

Calculation Method : RVP Distillation

Control Efficiency : 100.0%

Known Separator Stream : Low Pressure Oil

Entering Air Composition : No

Filed Name : Mandaree

Well Name : Cross 2-13H and Patricia Charging 4-15H Averages

Permit Number : Dakota-3 E&P Company, LLC

Date : 9/24/2010

******************************************************************************************

* Data Input *

******************************************************************************************

Separator Pressure : 51.00[psig]

Separator Temperature : 82.50[F]

Ambient Pressure : 14.70[psia]

Ambient Temperature : 70.00[F]

C10+ SG : 0.8000

C10+ MW : 235.14

-- Low Pressure Oil ----------------------------------------------------------------------

 No. Component wt %

 1 H2S 0.0014

 2 O2 0.0000

 3 CO2 0.0042

 4 N2 0.0015

 5 C1 0.0320

 6 C2 0.3654

 7 C3 1.2089

 8 i-C4 0.3443

 9 n-C4 1.5191

 10 i-C5 0.6508

 11 n-C5 1.2185

 12 C6 1.3933

 13 C7 6.7524

 14 C8 15.9338

 15 C9 14.3170

 16 C10+ 53.7971

 17 Benzene 0.0479

 18 Toluene 0.0997

 19 E-Benzene 0.0600

 20 Xylenes 0.3998

 21 n-C6 1.4864

 22 224Trimethylp 0.3663

-- Sales Oil -----------------------------------------------------------------------------

Production Rate : 1000[bbl/day]

Days of Annual Operation : 365 [days/year]

API Gravity : 41.85

Reid Vapor Pressure : 5.90[psia]

******************************************************************************************

* Calculation Results *

******************************************************************************************

-- Emission Summary ----------------------------------------------------------------------

Item Uncontrolled Uncontrolled 

 [ton/yr] [lb/hr] 

Page 1---------------------------------------------------------------- E&P TANK 

Total HAPs 8.550 1.952 

Total HC 812.744 185.558 

VOCs, C2+ 796.480 181.845 

VOCs, C3+ 612.595 139.862 

Page 1
Mandaree Field 1000 BOPD wt%

 

Uncontrolled Recovery Info. 

 Vapor 40.2300 [MSCFD] 

 HC Vapor 40.0300 [MSCFD] 

 GOR 40.23 [SCF/bbl] 

-- Emission Composition ------------------------------------------------------------------

No Component Uncontrolled Uncontrolled 

 [ton/yr] [lb/hr] 

1 H2S 0.689 0.157 

2 O2 0.000 0.000 

3 CO2 2.160 0.493 

4 N2 0.786 0.179 

5 C1 16.264 3.713 

6 C2 183.886 41.983 

7 C3 375.375 85.702 

8 i-C4 37.149 8.482 

9 n-C4 112.787 25.750 

10 i-C5 17.863 4.078 

11 n-C5 24.862 5.676 

12 C6 8.648 1.974 

13 C7 13.803 3.151 

14 C8 10.281 2.347 

15 C9 3.270 0.747 

16 C10+ 0.004 0.001 

17 Benzene 0.234 0.053 

18 Toluene 0.136 0.031 

19 E-Benzene 0.027 0.006 

20 Xylenes 0.156 0.036 

21 n-C6 7.394 1.688 

22 224Trimethylp 0.604 0.138 

 Total 816.378 186.388 

-- Stream Data ---------------------------------------------------------------------------

No. Component MW LP Oil Flash Oil Sale Oil Flash Gas W&S Gas Total Emissions

 wt % wt % wt % wt % wt % wt % 

1 H2S 34.80 0.0014 0.0010 0.0000 0.0873 0.0856 0.0861 

2 O2 32.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 

3 CO2 44.01 0.0042 0.0020 0.0000 0.4818 0.1765 0.2642 

4 N2 28.01 0.0015 0.0001 0.0000 0.3044 0.0123 0.0962 

5 C1 16.04 0.0320 0.0079 0.0000 5.2226 0.6866 1.9891 

6 C2 30.07 0.3654 0.2356 0.0039 28.3624 20.1288 22.4930 

7 C3 44.10 1.2089 1.0468 0.4786 36.1613 49.8497 45.9192 

8 i-C4 58.12 0.3443 0.3257 0.2757 4.3503 4.6218 4.5438 

9 n-C4 58.12 1.5191 1.4623 1.3185 13.7647 13.8076 13.7953 

10 i-C5 72.15 0.6508 0.6432 0.6257 2.2771 2.1480 2.1850 

11 n-C5 72.15 1.2185 1.2094 1.1888 3.1795 2.9854 3.0410 

12 C6 86.16 1.3933 1.3945 1.3984 1.1369 1.0640 1.0850 

13 C7 100.20 6.7524 6.7753 6.8342 1.8207 1.7133 1.7442 

14 C8 114.23 15.9338 16.0015 16.1730 1.3430 1.2744 1.2941 

15 C9 128.28 14.3170 14.3815 14.5440 0.4133 0.4189 0.4174 

16 C10+ 235.14 53.7971 54.0465 54.6758 0.0006 0.0005 0.0006 

17 Benzene 78.11 0.0479 0.0480 0.0483 0.0298 0.0281 0.0285 

18 Toluene 92.13 0.0997 0.1001 0.1011 0.0174 0.0165 0.0166 

19 E-Benzene 106.17 0.0600 0.0603 0.0610 0.0035 0.0032 0.0033 

20 Xylenes 106.17 0.3998 0.4016 0.4059 0.0196 0.0187 0.0191 

21 n-C6 86.18 1.4864 1.4889 1.4959 0.9466 0.8874 0.9045 

22 224Trimethylp 114.24 0.3663 0.3677 0.3711 0.0772 0.0726 0.0739 

 

 MW 143.08 144.90 148.98 39.02 43.55 42.14 

 Stream Mole Ratio 1.0000 0.9829 0.9448 0.0171 0.0381 0.0552 

 Heating Value [BTU/SCF] 2225.52 2481.29 2401.97 

 Gas Gravity [Gas/Air] 1.35 1.50 1.45 

 Bubble Pt. @ 100F [psia] 32.28 20.39 7.37 

Page 2---------------------------------------------------------------- E&P TANK 

 RVP @ 100F [psia] 15.35 12.04 6.01 

 Spec. Gravity @ 100F 0.677 0.678 0.680 

Page 2
Emission estimates are based on using the E&P TANK V2.0 Model, RVP Distillation Column

As shown below, the E&P Tanks summary output has a linear relationship with the production rate

of the oil with the given inputs listed below.

Inputs:

Low pressure oil from average of 2 representative Mandaree Field Dakota-3 Wells

Separator: 51 psig, 83 degF

Flash Valve: 13.7 psia, 50 degF

Sales Oil: API Gravity 41.9, Reid Vapor Pressure 5.90 psia, 365 days/year

Outputs:

Oil Production Rates (bbl/day) (P) 0 50 100 300 1000

Emission (tons/yr)

Total HC 0 40.6372 81.2744 243.8232 812.744

VOCs, C3+ 0 30.62975 61.2595 183.7785 612.595

Total HAPs 0 0.4275 0.855 2.565 8.55

VOC (C3+) Emission Factor: 0.6126 tpy/BOPD

HAP Emission Factor: 0.00855 tpy/BOPD

Oil Storage Tank Flashing Emissions Calculation Methodology

E&P Tanks Linear Relation between Production (bbls/day) and Emissions (tons/yr)

y = 0.00855x

R2 = 1.00000

y = 0.6126x

R2 = 1

0

100

200

300

400

500

600

700

0 500 1000 1500

tons/year

bbl/day

Tank Emissions by Production Rate

Total HAPs

VOCs, C3+

Linear (Total HAPs)

Linear (VOCs, C3+)
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT D: REPRESENTATIVE LOW PRESSURE OIL 

ANALYTICAL DATA 
Company .................... ZENERGY

Lab Number ................ CRͲ10330 Study Number.......... CRͲ2

Date Sampled .............. 7Ͳ15Ͳ2010 Date Tested............. 7Ͳ23Ͳ2010

S l Id tifi ti CROSS 2 13 H CRUDE OIL

 EXTENDED HYDROCARBON (GLYCALC) LIQUID STUDY

Sample Identification .................... CROSS 2-13 H CRUDE OIL

Sample Location .......... MONTANA.

Sample Pressure ......... 22 PSIG Sample Temperature.... 95 F

Type Sample ............... SPOT County...................... DUNN

Test method ................ GPAͲ2286 Sampling Method........ YZ PISTON

 Components Mole % Weight % Liq. Vol. %

Hydrogen Sulfide .......... 0.003 0.001 0.001

Oxygen ...................... 0.000 0.000 0.000

Carbon Dioxide ............ 0.013 0.004 0.004

Nitrogen ..................... 0.007 0.001 0.001

Methane ..................... 0 180 . 0 021 . 0 050 .

Ethane ....................... 1.602 0.342 0.709

Propane ..................... 4.036 1.264 1.839

isoͲButane .................. 0.855 0.353 0.463

nͲButane .................... 3.974 1.640 2.072

isoͲPentane ................ 1.378 0.706 0.833

nͲPentane ................... 2.569 1.316 1.540

Hexanes ..................... 2 510. 1 536. 1 707.

Heptanes .................... 10.694 7.610 8.159

Octanes ..................... 19.351 15.699 16.394

Nonanes ..................... 17.072 15.551 15.886

Decanes+ ................... 31.435 51.099 47.376

Benzene...................... 0.093 0.052 0.043

Toluene....................... 0.166 0.109 0.092

Ethylbenzene............... 0.104 0.078 0.066

Xylenes....................... 0.618 0.466 0.397

nͲHexane .................... 2.798 1.712 1.903

2,2,4ͲTrimethylpentane... 0.542 0.440 0.466

TOTALS ..................... 100.000 100.000 100.000
ADDITIONAL BETX DATA

 Components Mole % Weight % Liq. Vol. %

2-Methylpentane 1.486 0.910 1.011

3-Methylpentane 3-Methylpentane 1 024 . 0 627 . 0 696 .

n-Hexane 2.798 1.712 1.903

2,2,4-Trimethylpentane 0.542 0.440 0.466

Benzene 0.093 0.052 0.043

Toluene 0.166 0.109 0.092

Ethylbenzene 0.104 0.078 0.066

m-Xylene 0.066 0.050 0.042

p-Xylene 0.436 0.329 0.280

o-Xylene 0.116 0.087 0.074

API GRAVITY AT 60/60 F, calculated........................................................................ 60.3

SPECIFIC GRAVITY AT 60/60 F, calculated.............................................................. 0.7378

RELATIVE SPECIFIC GRAVITY OF DECANES+ (C10+) FRACTION ............................... 0.7958

AVERAGE MOLECULAR WEIGHT .......................................................................... 140.803

AVERAGE MOLECULAR WEIGHT OF DECANES+ (C10+) FRACTION .......................... 228.881

TRUE VAPOR PRESSURE AT 100 F PSIA calculated TRUE VAPOR PRESSURE AT 100 F, PSIA, calculated................................................ 33 400 .

AVERAGE BOILING POINT, F, ................................................................................ 299.063

CUBIC FEET OF GAS / GALLON OF LIQUID, as Ideal Gas .......................................... 19.106

BTU / GALLON OF LIQUID AT 14.73 PSIA, calculated ................................................. 122456.887

LBS / GALLON OF LIQUID, calculated ...................................................................... 6.152

NOTATION: ALL CALCULATIONS PERFORMED USING PHYSICAL CONSTANTS FROM GPA 2145-09, THE TABLES

 OF PHYSICAL CONSTANTS FOR HYDROCARBONS AND OTHER COMPOUNDS OF INTEREST

 TO THE NATURAL GAS INDUSTRY.
 EXTENDED HYDROCARBON LIQUID STUDIES

 CERTIFICATE OF ANALYSIS

Company................ PRECISION ANALYSIS

L bN ba umer............. CR-10330 CR 10330 Study Number............ St d N b CR-2B 

Date Sampled............. 7-15-2010 Date Tested.............. 7-22-2010

Sample Identification................ ZENERGY - CROSS 2-13 H CRUDE OIL

Sample Location......... MONTANA.

Sample Pressure.......... N/A Sample Temperature.... N/A

Flowrate................... N/A County..................... DUNN

Test Method.............. VARIOUS Sample Container........

1-QUART 

BOTTLE

TEST PERFORMED RESULTS

API GRAVITY AT 60/60 F (ASTM D-287), observed...................... / ( ), 42.5

SPECIFIC GRAVITY AT 60/60 F (ASTM D-1657), calculated.......... 0.8132

REID VAPOR PRESSURE (ASTM D-323), PSIG AT 100 F.............. 5.2 PSIG

TOTAL SULFUR CONTENT (ASTM D-5453), PPMW.................. PPMW 658.98

TRUE VAPOR PRESSURE (ASTM D-2889), PSIA AT 100 F ........... N/A

BASIC SEDIMENT AND WATER CONTENT, % BY VOLUME.... N/A

COPPER STRIP CORROSION (ASTM D-130), 1 HOUR AT 100 F........... N/A

FREE WATER, observed......................................................... N/A

NOTATION : ALL TESTING PROVIDED ABOVE WAS PERFORMED IN ACCORDANCE TO METHODOLOGY

 OUTLINED BY THE AMERICAN SOCIETY FOR TESTING AND MATERIALS (ASTM).
5HSRUW5HSRUW(GLWRU

Chromatogram Cross 2-13H C:\GCsolution\DRO\DRO Data\08-2010\08-01-2010\Cross 2-13H.gcd - Channel 1

min

Intensity 0.0

2.5

5.0

7.5

10.0

12.5

15.0

17.5

20.0

22.5

25.0

27.5

30.0

0 50000 100000 150000 200000 250000

 1.055 / 1.137 / 1.306 / 1.405 / 1.552 / 1.668 / 

 1.729 / 1.901 / 1.979 / 2.039 / 2.109 / 2.280 / 2.417 / 2.565 / 2.667 / 2.854 / 2.949 / 3.034 / 3.092 / 3.213 / 3.342 / 3.420 / 3.539 / 3.632 / 3.773 / 3.862 / 3.965 / 4.069 / 4.148 / 4.335 / 4.448 / 4.508 / 4.583 / 4.692 / 4.751 / 4.901 / 5.021 / 5.164 / 5.365 / 5.508 / 5.608 / Decane (C10) 5.816 / 5.947 / 6.069 / 6.188 / 6.286 / 6.393 / 6.509 / 6.569 / 6.657 / 6.714 / 6.777 / 6.896 / 7.083 / 7.220 / 7.323 / 7.381 / 7.455 / 7.559 / 7.632 / 7.703 / 7.769 / 7.836 / 7.907 / 7.967 / 8.056 / 8.184 / 8.268 / 8.329 / 8.452 / 8.540 / 8.633 / 8.744 / 8.808 / 8.998 / 9.128 / 9.270 / 9.380 / 9.467 / 9.526 / 9.596 / 9.724 / 9.862 / 9.939 / 10.055 / 10.150 / 10.257 / 10.332 / 10.427 / 10.487 / 10.568 / 10.638 / 10.766 / 10.828 / 10.911 / 11.051 / 11.216 / 11.469 / 11.613 / 11.706 / 11.785 / 12.031 / 12.128 / 12.182 / 12.302 / 12.409 / 12.463 / 12.536 / 12.607 / 12.700 / 12.822 / 13.004 / 13.088 / 13.203 / 13.305 / 13.372 / 13.447 / 13.582 / 13.674 / 13.803 / 13.929 / 14.089 / 14.146 / 14.316 / 14.427 / 14.515 / 14.592 / 14.691 / 14.773 / 14.896 / 15.041 / 15.129 / 15.249 / 15.300 / 15.369 / 15.430 / 15.566 / 15.620 / 15.691 / 15.787 / 15.947 / o-terphenyl 16.113 / 16.187 / 16.339 / 16.456 / 16.570 / 16.661 / 16.813 / 16.894 / 16.979 / 17.143 / 17.306 / 17.449 / 17.519 / 17.642 / 17.787 / 17.954 / 18.052 / 18.153 / 18.222 / 18.292 / 18.434 / 18.549 / 18.723 / 18.887 / 18.991 / 19.197 / 19.331 / 19.474 / 19.663 / 19.724 / 19.785 / 19.850 / 19.927 / 19.995 / 20.077 / 20.222 / 20.182 / 20.345 / 20.443 / 20.634 / 20.789 / 20.871 / 20.945 / 21.059 / 21.134 / 21.205 / 21.310 / 21.542 / 21.695 / 21.795 / 21.855 / 21.905 / 21.966 / 22.073 / 22.181 / 22.367 / 22.425 / 22.599 / Octacosane (C28) 22.737 / 22.808 / 22.879 / 23.003 / 23.058 / 23.117 / 23.217 / 23.351 / 23.418 / 

 23.678 / 23.816 / 23.905 / 24.027 / 24.086 / 24.202 / 24.264 / 24.400 / 24.521 / 24.587 / 24.651 / 24.765 / 24.809 / 24.874 / 24.981 / 25.069 / 25.142 / 25.201 / 25.273 / 25.334 / 25.401 / 25.462 / 25.568 / 25.705 / 25.765 / 25.966 / 26.056 / 26.229 / 26.397 / 26.487 / 26.575 / 26.665 / 26.758 / 26.958 / 27.073 / 27.191 / 27.327 / 27.441 / 27.561 / 27.668 / 27.798 / 27.952 / 28.073 / 28.297 / 28.467 / 28.689 / 28.833 / 28.995 / 29.193 / 29.393 / 29.601 / 
Company .................... ZENERGY

Lab Number ................ CRͲ10330 Study Number.......... CRͲ3

Date Sampled .............. 7Ͳ15Ͳ2010 Date Tested............. 7Ͳ23Ͳ2010

S l Id tifi ti PATRICIA CHARGING 4 15 H CRUDE OIL

 EXTENDED HYDROCARBON (GLYCALC) LIQUID STUDY

Sample Identification .................... PATRICIA CHARGING 4-15 H CRUDE OIL

Sample Location .......... MONTANA.

Sample Pressure ......... 80 PSIG Sample Temperature.... 70 F

Type Sample ............... SPOT County...................... DUNN

Test method ................ GPAͲ2286 Sampling Method........ YZ PISTON

 Components Mole % Weight % Liq. Vol. %

Hydrogen Sulfide .......... 0.008 0.002 0.002

Oxygen ...................... 0.000 0.000 0.000

Carbon Dioxide ............ 0.014 0.004 0.004

Nitrogen ..................... 0.008 0.001 0.001

Methane ..................... 0 398 . 0 043 . 0 107 .

Ethane ....................... 1.921 0.387 0.811

Propane ..................... 3.914 1.155 1.702

isoͲButane .................. 0.862 0.335 0.445

nͲButane .................... 3.606 1.403 1.795

isoͲPentane ................ 1.238 0.598 0.715

nͲPentane ................... 2.329 1.125 1.333

Hexanes ..................... 2 180. 1 257. 1 415.

Heptanes .................... 8.849 5.934 6.445

Octanes ..................... 21.103 16.133 17.068

Nonanes ..................... 15.296 13.130 13.589

Decanes+ ................... 34.917 56.412 52.378

Benzene...................... 0.085 0.044 0.038

Toluene....................... 0.148 0.091 0.078

Ethylbenzene............... 0.060 0.043 0.037

Xylenes....................... 0.473 0.336 0.290

nͲHexane .................... 2.204 1.271 1.431

2,2,4ͲTrimethylpentane... 0.387 0.296 0.317

TOTALS ..................... 100.000 100.000 100.000
ADDITIONAL BETX DATA

 Components Mole % Weight % Liq. Vol. %

2-Methylpentane 1.272 0.734 0.826

3-Methylpentane 3-Methylpentane 0 908 . 0 524 . 0 590 .

n-Hexane 2.204 1.271 1.431

2,2,4-Trimethylpentane 0.387 0.296 0.317

Benzene 0.085 0.044 0.038

Toluene 0.148 0.091 0.078

Ethylbenzene 0.060 0.043 0.037

m-Xylene 0.058 0.041 0.036

p-Xylene 0.298 0.212 0.183

o-Xylene 0.117 0.083 0.072

API GRAVITY AT 60/60 F, calculated........................................................................ 57.8

SPECIFIC GRAVITY AT 60/60 F, calculated.............................................................. 0.7475

RELATIVE SPECIFIC GRAVITY OF DECANES+ (C10+) FRACTION ............................... 0.8050

AVERAGE MOLECULAR WEIGHT .......................................................................... 149.417

AVERAGE MOLECULAR WEIGHT OF DECANES+ (C10+) FRACTION .......................... 241.399

TRUE VAPOR PRESSURE AT 100 F PSIA calculated TRUE VAPOR PRESSURE AT 100 F, PSIA, calculated................................................ 46 319 .

AVERAGE BOILING POINT, F, ................................................................................ 314.836

CUBIC FEET OF GAS / GALLON OF LIQUID, as Ideal Gas .......................................... 18.857

BTU / GALLON OF LIQUID AT 14.73 PSIA, calculated ................................................. 122700.693

LBS / GALLON OF LIQUID, calculated ...................................................................... 6.232

NOTATION: ALL CALCULATIONS PERFORMED USING PHYSICAL CONSTANTS FROM GPA 2145-09, THE TABLES

 OF PHYSICAL CONSTANTS FOR HYDROCARBONS AND OTHER COMPOUNDS OF INTEREST

 TO THE NATURAL GAS INDUSTRY.
 EXTENDED HYDROCARBON LIQUID STUDIES

 CERTIFICATE OF ANALYSIS

Company................ ZENERGY

L bN ba umer............. CR-10330 CR 10330 Study Number............ St d N b CR-3B 

Date Sampled............. 7-15-2010 Date Tested.............. 7-22-2010

Sample Identification................ PATRICIA CHARGING 4-15 H CRUDE OIL

Sample Location......... MONTANA.

Sample Pressure.......... N/A Sample Temperature.... N/A

Flowrate................... N/A County..................... DUNN

Test Method.............. VARIOUS Sample Container........

1-QUART 

BOTTLE

TEST PERFORMED RESULTS

API GRAVITY AT 60/60 F (ASTM D-287), observed...................... / ( ), 41.2

SPECIFIC GRAVITY AT 60/60 F (ASTM D-1657), calculated.......... 0.8193

REID VAPOR PRESSURE (ASTM D-323), PSIG AT 100 F.............. 6.6 PSIG

TOTAL SULFUR CONTENT (ASTM D-5453), PPMW.................. PPMW 940.25

TRUE VAPOR PRESSURE (ASTM D-2889), PSIA AT 100 F ........... N/A

BASIC SEDIMENT AND WATER CONTENT, % BY VOLUME.... N/A

COPPER STRIP CORROSION (ASTM D-130), 1 HOUR AT 100 F........... N/A

FREE WATER, observed......................................................... N/A

NOTATION : ALL TESTING PROVIDED ABOVE WAS PERFORMED IN ACCORDANCE TO METHODOLOGY

 OUTLINED BY THE AMERICAN SOCIETY FOR TESTING AND MATERIALS (ASTM).
5HSRUW5HSRUW(GLWRU

Chromatogram PC 4-15 1-100 C:\GCsolution\DRO\DRO Data\08-2010\08-01-2010\PC 4-15 1-100.gcd - Channel 1

min

Intensity 0.0

2.5

5.0

7.5

10.0

12.5

15.0

17.5

20.0

22.5

25.0

27.5

30.0

0 50000 100000 150000 200000 250000

 1.054 / 1.137 / 1.407 / 1.593 / 1.670 / 

 1.730 / 1.902 / 2.040 / 2.109 / 2.280 / 2.363 / 2.418 / 2.566 / 2.667 / 2.855 / 2.950 / 3.035 / 3.136 / 3.214 / 3.343 / 3.421 / 3.540 / 3.635 / 3.773 / 3.863 / 3.967 / 4.070 / 4.149 / 4.335 / 4.509 / 4.584 / 4.694 / 4.750 / 4.901 / 5.022 / 5.166 / 5.366 / 5.510 / 5.610 / Decane (C10) 5.818 / 5.949 / 6.070 / 6.190 / 6.288 / 6.397 / 6.512 / 6.564 / 6.660 / 6.714 / 6.780 / 6.901 / 7.016 / 7.084 / 7.156 / 7.221 / 7.326 / 7.384 / 7.457 / 7.561 / 7.634 / 7.747 / 7.836 / 7.908 / 7.969 / 8.059 / 8.184 / 8.270 / 8.331 / 8.453 / 8.542 / 8.634 / 8.745 / 8.812 / 9.000 / 9.129 / 9.271 / 9.381 / 9.469 / 9.529 / 9.597 / 9.725 / 9.863 / 9.942 / 10.057 / 10.149 / 10.260 / 10.334 / 10.429 / 10.488 / 10.570 / 10.640 / 10.768 / 10.830 / 10.913 / 11.059 / 11.220 / 11.472 / 11.615 / 11.787 / 12.031 / 12.130 / 12.184 / 12.318 / 12.414 / 12.470 / 12.541 / 12.606 / 12.706 / 12.826 / 13.005 / 13.088 / 13.306 / 13.376 / 13.450 / 13.583 / 13.673 / 13.728 / 13.934 / 14.091 / 14.148 / 14.319 / 14.445 / 14.516 / 14.595 / 14.692 / 14.779 / 14.896 / 15.042 / 15.130 / 15.246 / 15.373 / 15.431 / 15.568 / 15.658 / 15.621 / 15.775 / 15.883 / 15.950 / o-terphenyl 16.056 / 16.118 / 16.191 / 16.341 / 16.460 / 16.573 / 16.667 / 16.814 / 16.894 / 16.987 / 17.144 / 17.313 / 17.452 / 17.528 / 17.644 / 17.796 / 17.963 / 18.087 / 18.144 / 18.226 / 18.292 / 18.436 / 18.558 / 18.723 / 18.924 / 18.986 / 19.083 / 19.198 / 19.272 / 19.329 / 19.473 / 19.627 / 19.786 / 19.849 / 19.928 / 20.077 / 20.180 / 20.244 / 20.372 / 20.431 / 20.488 / 20.634 / 20.798 / 20.870 / 20.952 / 21.027 / 21.131 / 21.218 / 21.313 / 21.422 / 21.538 / 21.594 / 21.705 / 21.795 / 21.845 / 21.966 / 22.068 / 22.188 / 22.368 / 22.426 / 22.604 / Octacosane (C28) 22.717 / 22.799 / 22.997 / 23.054 / 23.217 / 23.347 / 23.408 / 23.605 / 23.663 / 23.817 / 24.040 / 24.163 / 24.292 / 24.402 / 24.498 / 24.572 / 24.634 / 24.695 / 24.758 / 24.836 / 24.977 / 25.088 / 25.178 / 

 25.438 / 25.504 / 25.571 / 25.721 / 25.797 / 26.044 / 26.117 / 26.208 / 26.366 / 26.438 / 26.526 / 26.626 / 26.733 / 26.830 / 26.947 / 27.166 / 

 27.448 / 27.552 / 27.669 / 27.776 / 27.974 / 

 28.293 / 28.432 / 28.616 / 28.720 / 28.944 / 29.074 / 

 29.336 / 

 29.688 / 29 920 /
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT E: REPRESENTATIVE GAS ANALYSIS 
This section of the document has been redacted because it 

contains copyrighted information. The redacted information 

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

available at the EPA Region 8 Office upon request. 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT F: ENGINE MANUFACTURER’S SPECS 
This section of the document has been redacted because it 

contains copyrighted information. The redacted information 

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

available at the EPA Region 8 Office upon request. 
RENTAL C~TERPILLAR@

•

XQ230

SOUND ATTENUATED

DUAL VOLTAGE

50/60 Hz

Arrangement shown

with optional trailer

FEATURES

EMISSIONS

• EPA Tier 3 and CARS Emissions Certified for

non-road mobile applications at all 60 Hz and

50 Hz ratings

CAT C9 ATAAC DIESEL ENGINE

• Utilizes ACERT® Technology

• Reliable, rugged, durable design

• Field-proven in multiple applications

worldwide

• Four-stroke-cycle diesel engine combines

durability with minimum weight while

providing dependability and economy

• 50/60 Hz convertibility

CAT SR4B GENERATOR

• Designed to match performance and output

characteristics of diesel engines

• Permanent magnet excitation

• Segregated AC/DC, low voltage accessory box

provides single point access to accessory

connections

ENCLOSURE

• Made with 12-gauge steel

• Single point lifting eye

• Sound attenuated

• Convenient hand holds and steps for safe

operation

• Two coat polyester powder-coated finish

LEHE5329-03

ENVIRONMENTALLY FRIENDLY DESIGN

• Sound attenuated for low noise operation

• OSHA compliant safe design

• 110% spill containment for coolant and oil

• UL142 certified dual wall fuel tank

MULTI-VOLTAGE DISTRIBUTION PANEL

• Simultaneous dual voltage

• Load door safety switch

• Rust-free hinges on all doors

• Adequate space for line and plug connection

without interference

• Remote start and stop contacts

SINGLE-SOURCE SUPPLIER

• Complete systems designed at Caterpillar

ISO 9001 :2000 certified facilities

• Certified Prototype Tested with torsional

analysis

WORLDWIDE PRODUCT SUPPORT

• Worldwide parts availability through the

Caterpillar dealer network

• With over 1,875 dealer outlets operating in

200 countries, you're never far from the

Caterpillar part you need.

• 99.7% of parts orders filled within 48 hours.

The best product support record in the industry.

• Caterpillar dealer service technicians are

trained to service every aspect of your electric

power generation system.
RENTAL C~TERPILLAR®

FACTORY INSTALLED STANDARD AND OPTIONAL EQUIPMENT

STANDARD FEATURES

Air Inlet System Air cleaner, dual element

Turbocharger

Charging System Battery charger

Heavy duty charging alternator

Control Panel Generator controls and monitoring

Fuel tank monitoring

Engine controls and monitoring

Digital displays

Cooling System Fan and belt guards

Base mounted radiator

Air to air aftercooling

Distribution Panel Lockable doors

Load door safety switch, (trips breaker

upon door opening)

Individual bus bar connections

Circuit breaker with 24 VDC shunt trip

Remote start/stop contacts

Shore power connections

Enclosure Sound attenuated

12-gauge steel

Lockable doors

Separate vented battery compartment

Single point lifting

Exterior oil and water drains with interior valves

Hidden exterior fuel drain

Hand holds and steps

Powder coated finish

Fuel System Primary fuel filter/water separator

UL142 dual wall fUel tank 1667 L (440 gal)

Radiator-mounted fuel cooler

Generator Brushless, permanent magnet

Coastal corrosion protection

Shock mounted VR6 voltage regulator

Space heater

UL approved

Simultaneous three-phase 480/277 and

240/139 voltage

Mounting System Generator soft mounted to base

Base contains integral fuel tank

Skiddable structural steel design

110% oil and coolant spill containment

Starting System Electric starting motor

Battery set with disconnect switch

Jacket water heater with thermostat,

shut-off valves

OPTIONAL FEATURES

Trailer Full frame support

Independent tandem axle trailer frame

with tongue

Electric actuated hydraulic brakes

with rechargeable battery backup

breakaway system.

Overcenter mechanical parking brake

Full length fenders

Non-skid surface on steps

Heavy duty safety chains and

grab hooks

Reinforced 4540 kg (10,000 Ib) top

wind drop jack

LEHE5329-03 2
RENTAL

SPECIFICATIONS

CAT SR4B GENERATOR

Frame size 449

Type Permanent magnet brush less

Construction Single bearing, close coupled

Three-phase , 12 lead reconnectable

Insulation Class H with coastal insulation protection

IP rating 22

Alignment Pilot shaft

Voltage regulator 3-phase sensing with Volts-per-Hertz

Voltage regulation ± Yz% steady state/± Yz%

no load to full load

TIF Less than 50

THD Less than 5%

TECHNICAL DATA

C~TERPILLAR®

ENGINE

C9 ATAAC, 4-stroke-cycle watercooled diesel

Bore - mm (in) 112 (4.41)

Stroke - mm (in) 149 (5.87)

Displacement - L (cu in) , 8.8 (537)

Compression ratio , 16.1:1

Aspiration Turbocharged AA charge cooled

Engine control , ADEMTM A4

CAT CONTROL PANEL - EMCP 3.2

24 Volt DC Control

NEMA 1, IP22 enclosure

Lockable hinged door

Enclosure mounted

Single location customer connector point

16 light alarm module with alarm horn

Electric fuel level gauge

Consult your Caterpillar dealer for available voltages.

X0230

Power Rating Standby TMIRef. Prime TMI Ref.

60 Hz ekW 230 DM8502 210 DM8512

50 Hz kVA 275 DM8504

Engine and Container Information

Engine model C9

Container dimensions see chart on page 6

Shipping Weight (Dry)

Unit with trailer kg (Ib) 6210 (13,690)

Unit without trailer kg (Ib) 4980 (10,980)

Maximum Fuel Capacity Weight

Unit with trailer kg (Ib) 7506 (16,550)

Unit without trailer kg (lb) 6278 (13,840)

Engine Lubricating Oil Capacity L(gal) 40 (10.55)

Engine Coolant Capacity with Radiator L(gal) 36 (9.5)

Fuel Tank Capacity L (gal) 1516 (400)

Fuel Consumption LJhr (gal/hr) 69.2 (18.3) 64.7 (17.1)

Fuel Consumption (75% Prime) LJhr (gal/hr) 50.6 (13,4)

Running lime @ 75% Prime hours 28

Sound Level

Standby dB(A) 74.72

No load @ 7 m (23 ft) dB(A) 70.20

Prime dB(A) 73.49

Ambient Capability Deg C (Deg F) 43 (109.4)

LEHE5329-03 3
RENTAL

RATING DEFINITIONS AND CONDITIONS

Meets or Exceeds International Specifications:

• NEMA MG1-32, IEC 60034, C8A, 98/37/EEC, 72/23/EEC,

UL 508, UL142,1803046/1,1808528, 89/336/EEC

Standby - Output available with varying load for the

duration of the interruption of the normal source power.

8tandby power in accordance with 1808528. Fuel stop power

in accordance with 1803046/1, A82789, DIN6271, and 885514.

Prime - Output available with varying load for an unlimited

time. Prime power in accordance with 1808528. 10% overload

power in accordance with 1803046/1, A82789, DIN6271, and

885514 available on request.

LEHE5329-03 4

C~TERPILLAR@

Ratings are based on 8AE J1349 standard conditions.

These ratings also apply at 1803046/1, DIN6271, and 885514

standard conditions.

Fuel rates are based on fuel oil of 35° API [@ 16° C (60° F)]

gravity having an LHV of 42780 kJ/kg (18,390 8tullb) when used

at 29° C (85° F) and weighing 838.9 g/liter (7.001 Ib/U.8. gal).

Additional ratings may be available for specific customer

requirements. Consult your Caterpillar representative for details.
RENTAL

DISTRIBUTION PANEL

C~TERPILLAR®

• CATERPILLAR.

i i

@-.

1

r

j

.. ---Q~-,-- ------------

LEHE5329-03 5

Wiring Descriptions

1. 800 amp main breaker 240V with 24V shunt trip

2. 400 amp main 480V with 24V shunt trip

3. 50 amp 240V branch breaker

4. 20 amp 240V branch breaker

5. 20 amp 120V branch breaker

6. 15 amp 120V branch breaker

7. 50 amp 240V twistlock receptacle

8. 20 amp 240V twistlock receptacle

9. 20 amp 120V twistlock receptacle (2x)

10. 20 amp 120V ground fault interrupter, (2x)

11. 15 amp 120V ground fault interrupter,

duplex receptacle (2x)

12. 30 amp 120V battery charger/generator

space heater receptacle

13. 30 amp 120V JWH receptacle

14. Remote start/stop contacts

15. 12.7 mm ('WI) ground stud

16. Dual voltage load connection bus board

[6.35 mm x 101.6 mm x 101.6 mm

(%" x 4" x 4") bus bars]
RENTAL

CONTAINER DIMENSIONS - TOP VIEW

. 901.3 [35.49]

272.8 [10.74]-+----t---1

2540.0 [100.00]

C~TERPILLAR@

1-----------6239.7[245.66]-------------l

CONTAINER DIMENSIONS - RIGHT SIDE VIEW

1---------6239.7[245.66]----------1

J-------4675.6[184.08)----- 1386.7 [54.60)

J------4361.6[171.72)------i

12383.7[93.84]

2240.4

2303.8[88.20~ 825.0

2865.1901.70) [71.85]

[112.81]

t-I-hrJ:."...l~===n==!~:--T"ir-+:~~~ "'''---LL.-k'/

415.4 [16.35]

Overall Dimensions

Package With Trailer

Length 4597.4 mm 181 in 6248.3 mm 246 in

Width 1498.6 mm 59in 2540.0 mm 100in

Height 2387.6 mm 94in 2882.8 mm 113.5 in

LEHE5329-03 6
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT G: EMISSION CONTROL DEVICE 

MANUFACTURER’S SPECS 
CIiAaRaON

CIMARRON ENERGY INC.

EMISSION CONTROL DEVICES (ECD)

Cimarron Energy Tank VOC Emission Control Devices are enclosed flares that are

low maintenance with safe reliable operation, user friendly, easy to install, and

highly efficient. These units are engineered to capture and combust VOC

emissions from the Oil/Condensate Production Tanks with clean efficient

destruction. Cimarron ECDs have been independently tested and certified to

exceed the strict EPA requirements with a 99% destruction rate.

Specifications on the next page.

Auto Ignition systems also available.

H~m. Ol1lel: '·{5801 338-S"9S FAX 1·(5801 338-0835 P.O. BOll 1401$, Gu~mon, Oklahoma 739-42

Admlni.lr.ll.... OWel: 1-(<405) 928-7313 FAX 1-(405) 828·7380 P.O. SOl< 122110. Non",n, OI<Jaholt'la 73010
•

\

,

48" DlAx 302 SI~ HBGKT, 88 ORIFICES

EMISSION COHTROL DEVICE

.. >98% lVOC ORE, CERTIFIED USCPA <10 CFR

60, APPENDIX A, SOURCE EMMrsJONS TEST

METHODS REfERENCED. MEETS AI.l EPA&

CDPHE RfGUlATIONS. • DESTROYS OIIJCONDENSATE PRODUCTION

TANK VAPORS WI NO VISIBlE R.AME•

• EXCELLENT OPACITY AND SMOKELESS

OPfAATION. * RELIABlE AND CUSTOMIZABlf IGNITION. • VERY lOYi CAPITAl AND OPERATING COST. • EASY TO OPERATE AND MAlNTAIN. * WIll DESTROY UP TO 150 MCFD@l100Z/1rl

J

o

•

W1I1MUlll.I_JY:ltl!i'IIEY· 1_100.,_ ;

-- CIMARRON

""-.,

-....._A$>UOXII, -=n:lII1'IIl Off1

K:L-_I'I 1lO1~

~j;o • •

.........._....

.,

:..-.:0.''''

....fJl;

.xr us JOOl ... _oP ..-....-

~.- =::;:r IllIlIl[;

I we llIL:I SIftT:I GO,

__Il'fa.D

L_aJ..-

l.CUI.--- MOm J.DDIIIlf-.l

.........-_- ._- .-

Nm\iflli.

.~- .. I'UM 1ISloWII""'" ~-

--

--

IOlI'Dtlf IlOIIUS

M_-

1"1 rr.. ~')11 " H- i "'"

'\Jt>l._I

of tr~o~T•

-

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Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT H: PROCESS FLOW DIAGRAM OF 

FACILITY 
TYPICAL MANDAREE AREA 

ONE WELL PAD FACILITY PLOT PLAN 

Dakota-3 E&P Company, LLC 

FBIR, North Dakota 

NOT TO SCALE 

Recycle Line 

Chemicals 

(1)Wellhead 

Tank Vent line 

Utility 

Flare

Gas to sales

Gas Meter

12’d x 20’h 

400 bbl oil 

12’d x 20’h 

400 bbl oil 

12’d x 20’h 

400 bbl oil 

Enclosed 

Combustor

Recycle 

Pump 

LACT 

Unit 

12’d x 20’h 

400 bbl 

H2O 

12’d x 20’h 

400 bbl oil 

Valve

6’d x 20’h 

vertical treater 

Separator 30” d by 

10’ h 

Gas Meter 

(1) Genset 

Genset

Oil Pipeline 

Water 

Pipeline 

24 bbl 

Diesel 

Gas Meter 

Legend 

Berms 

Water Line 

Crude Line 

Flowline 

Buried Recycle Lines 

Gas Sales Line 

Tank Vapor Line 

Flared Gas Line 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT I: PRODUCTION DECLINE CURVE 

CALCULATIONS 
Dakota-3 E&P Company, LLC. 

NSR Synthetic Minor Application 

WEP211324 

ATTACHMENT J: DIESEL TANK EPA TANKS 4.09D 

EMISSIONS SUMMARY 
TANKS 4.0.9d

Emissions Report - Detail Format 

Tank Indentification and Physical Characteristics

Identification

 User Identification: 1000 gallon diesel tank

 City: Williston

 State: North Dakota

 Company: Williams E&P, LLC

 Type of Tank: Horizontal Tank

 Description: 1,000 gallon diesel tank to fuel onsite diesel generators. Tank throughput is based on engine fuel consumption.

Tank Dimensions

 Shell Length (ft): 10.00

 Diameter (ft): 4.16

 Volume (gallons): 1,000.00

 Turnovers: 2,244.31

 Net Throughput(gal/yr): 2,244,312.00

 Is Tank Heated (y/n): N

 Is Tank Underground (y/n): N

Paint Characteristics

 Shell Color/Shade: Gray/Medium

 Shell Condition Good

Breather Vent Settings

 Vacuum Settings (psig): -0.03

 Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Bismarck, North Dakota (Avg Atmospheric Pressure = 13.86 psia)

TANKS 4.0 Report Page 1 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
1000 gallon diesel tank - Horizontal Tank

Williston, North Dakota 

TANKS 4.0.9d

Emissions Report - Detail Format 

Liquid Contents of Storage Tank

Daily Liquid Surf. 

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol. 

Liquid

Mass 

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Distillate fuel oil no. 2 All 50.18 39.72 60.64 44.68 0.0045 0.0031 0.0067 130.0000 188.00 Option 1: VP50 = .0045 VP60 = .0065

TANKS 4.0 Report Page 2 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
1000 gallon diesel tank - Horizontal Tank

Williston, North Dakota 

TANKS 4.0.9d

Emissions Report - Detail Format 

Detail Calculations (AP-42)

Annual Emission Calcaulations

Standing Losses (lb): 0.2654

 Vapor Space Volume (cu ft): 86.5719

 Vapor Density (lb/cu ft): 0.0001

 Vapor Space Expansion Factor: 0.0780

 Vented Vapor Saturation Factor: 0.9995

Tank Vapor Space Volume:

 Vapor Space Volume (cu ft): 86.5719

 Tank Diameter (ft): 4.1600

 Effective Diameter (ft): 7.2797

 Vapor Space Outage (ft): 2.0800

 Tank Shell Length (ft): 10.0000

Vapor Density

 Vapor Density (lb/cu ft): 0.0001

 Vapor Molecular Weight (lb/lb-mole): 130.0000

 Vapor Pressure at Daily Average Liquid

 Surface Temperature (psia): 0.0045

 Daily Avg. Liquid Surface Temp. (deg. R): 509.8466

 Daily Average Ambient Temp. (deg. F): 41.5958

 Ideal Gas Constant R

 (psia cuft / (lb-mol-deg R)): 10.731

 Liquid Bulk Temperature (deg. R): 504.3458

 Tank Paint Solar Absorptance (Shell): 0.6800

 Daily Total Solar Insulation

 Factor (Btu/sqft day): 1,276.2450

Vapor Space Expansion Factor

 Vapor Space Expansion Factor: 0.0780

 Daily Vapor Temperature Range (deg. R): 41.8377

 Daily Vapor Pressure Range (psia): 0.0036

 Breather Vent Press. Setting Range(psia): 0.0600

 Vapor Pressure at Daily Average Liquid

 Surface Temperature (psia): 0.0045

 Vapor Pressure at Daily Minimum Liquid

 Surface Temperature (psia): 0.0031

 Vapor Pressure at Daily Maximum Liquid

 Surface Temperature (psia): 0.0067

 Daily Avg. Liquid Surface Temp. (deg R): 509.8466

 Daily Min. Liquid Surface Temp. (deg R): 499.3872

 Daily Max. Liquid Surface Temp. (deg R): 520.3060

 Daily Ambient Temp. Range (deg. R): 24.3583

Vented Vapor Saturation Factor

 Vented Vapor Saturation Factor: 0.9995

 Vapor Pressure at Daily Average Liquid:

 Surface Temperature (psia): 0.0045

 Vapor Space Outage (ft): 2.0800

Working Losses (lb): 5.6720

 Vapor Molecular Weight (lb/lb-mole): 130.0000

 Vapor Pressure at Daily Average Liquid

 Surface Temperature (psia): 0.0045

 Annual Net Throughput (gal/yr.): 2,244,312.0000

TANKS 4.0 Report Page 3 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
 Annual Turnovers: 2,244.3120

 Turnover Factor: 0.1800

 Tank Diameter (ft): 4.1600

 Working Loss Product Factor: 1.0000

Total Losses (lb): 5.9375

TANKS 4.0 Report Page 4 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
Emissions Report for: Annual 

1000 gallon diesel tank - Horizontal Tank

Williston, North Dakota 

TANKS 4.0.9d

Emissions Report - Detail Format 

Individual Tank Emission Totals

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Distillate fuel oil no. 2 5.67 0.27 5.94

TANKS 4.0 Report Page 5 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
TANKS 4.0 Report Page 6 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011