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 of the 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 Staff Environmental 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 17 th 

### 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 17 th 

### 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, PM 10 

### , PM 2.5 

### , sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO), volatile organic compound (VOC), lead (Pb) and lead compounds, fluorides (gaseous and particulate), sulfuric acid mist (H 2 

### SO 4 

### ), hydrogen sulfide (H 2 

### S), total reduced sulfur (TRS) and reduced sulfur compounds, including all calculations for the estimates.

 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 PM 10 

### - Particulate Matter less than 10 microns in size PM 2.5 

### - Particulate Matter less than 2.5 microns in size SOx - Sulfur Oxides NOx - Nitrogen Oxides CO - Carbon Monoxide VOC - Volatile Organic Compound Pb - Lead and lead compounds Fluorides - Gaseous and particulates H 2 

### SO 4 

### - Sulfuric Acid Mist H 2 

### S - Hydrogen Sulfide TRS - Total Reduced Sulfur RSC - Reduced Sulfur Compounds **PM** 

## 0.09 **0.11**

**PM 10**  

## 0.09 **0.11**

**PM 2.5**  

## 0.09 **0.11**

**SO x**  

## 0.02 **0.02**

**NO x**  

## 5.49 **5.97**

**CO** 

## 45.38 **48.00**

**VOC** 

## 250.11 **9.14**

**Pb** 

## Negligible **Negligible**

**Fluorides** 

## Negligible **Negligible**

**H 2**  

### SO **4** 

## Negligible **Negligible**

**H 2**  

### S 

## 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**

**PM 10**  

## N/A **N/A N/A**  **N/A**

**PM 2.5**  

## N/A **N/A N/A**  **N/A**

**SO x**  

## N/A **N/A N/A**  **N/A**

**NO x**  

## 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**
**NH 3**  

## N/A **N/A N/A**  **N/A**
**Fluorides** 

## N/A **N/A N/A**  **N/A**

**H 2**  

### SO **4** 

## N/A **N/A N/A**  **N/A**

**H 2**  

### S 

## 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 PM 10 

### - Particulate Matter less than 10 microns in size PM 2.5 

### - Particulate Matter less than 2.5 microns in size SOx - Sulfur Oxides NOx - Nitrogen Oxides CO - Carbon Monoxide VOC - Volatile Organic Compound Pb - Lead and lead compounds NH 3 

### - Ammonia Fluorides - Gaseous and particulates H 2 

### SO 4 

### - Sulfuric Acid Mist H 2 

### S - Hydrogen Sulfide TRS - Total Reduced Sulfur RSC - Reduced Sulfur CompoundsPage 7 of 15 

# Instructions

**U se 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 FederalMinor 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.



##  L 

## ist 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**

 E stimates of Current Actual Emissions, Current Allowable Emissions, Post-Change Uncontrolled Emissions, and Post-Change Allowable Emissions for the following air pollutants: particulate matter, PM 10 

## , PM 2.5 

## , sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO), volatile organic compound (VOC), lead (Pb) and lead compounds, ammonia (NH 3 

## ), fluorides (gaseous and particulate), sulfuric acid mist (H 2 

## SO 4 

## ), hydrogen sulfide (H 2 

## S), total reduced sulfur (TRS) and reduced sulfur compounds, including all calculations for the estimates.

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 anyPage 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 4 th 

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

Gail Tonnesen Region 8 Modeling Lead Tonnesen.gail@epa.gov 303-312- 6113Page 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.ht m . 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/m 3**  

## ) **Class I Area SIL (ug/m**  **3** 

## )

SO 2 

### 1 hr 3 ppb or 7.8 ug/m 3 

### (interim) ---- 3 hr 25 1.0 24 hr 5 0.2 Annual 1 0.08


## PM 2.5 

### 24 hr 0.07 1.2 Annual 0.06 0.3


## PM 10 

### 24 hr 5 0.2 Annual 1 0.08 

## NO 2 

### 1 hr 4 ppb or 7.5 ug/m 3 

### (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.



#  **E SA** 

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.

T o 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.



#  **N HPA** 

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=n atreghome
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 17 th 

### 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 pollutant**  **generating 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 

# I **nstructions**

**U se 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, collectivelyreferred 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 requestedlimitation. 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 thatPage 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 CO 2 

## e and 100 or 250 tpy on a mass basis, modifications at existing PSD facilities that increase GHG emissions by at least 75,000 tpy CO 2 

## e and minor sources that increase GHG emissions by at least 100,000 tpy CO 2 

## e 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 CO 2 

## equivalents (CO 2 

## e), the mass emissions of each individual GHGPage 4 of 4 

## adjusted for its Global Warming Potential (GWP) can be found at: http://epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf

1. Carbon dioxide (CO 2 

## ) 2. Methane (CH 4 

## ) and its CO 2 

## e 3. Nitrous oxide (N 2 

## O) and its CO 2 

## e 4. Hydrofluorocarbons (HFCs) and its CO 2 

## e 5. Perfluorocarbons (PFCs) and its CO 2 

## e 6. Sulfur hexafluoride (SF 6 

## ) and its CO 2 

## eDakota-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 SummaryDakota-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 17 th**  

# Street, Suite 1200 **Denver, CO 80202**

Prepared by:


# Bison Engineering, Inc. **1400 11 th**  

# Avenue **Helena, MT 59601 (406) 442-5768**  **www.bison-eng.com**



# September 30, 2011North 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 .................................................. 23North 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 SummaryNorth John Elk 28-27HC Pad 09/30/11 pg. 1 NSR Synthetic Minor Permit Application Project #: WEP211324 

# 1.0 **I NTRODUCTION** 

**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 istransported 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 pipelineNorth 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 CH 4 

## emissions. Although the VOC, HAP, and CH 4 

## emissions are reduced by the smokeless combustion device, CO, NO x 

## , PM, PM 10 

## , PM 2.5 

## and N 2 

## O 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 pipelinepressure 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 fugitiveemissions 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 leakNorth 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 toNorth 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 INVENTORYFacility 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. H 2 S weight % 0.09% H 2 S weight percent of the tank vapor gas. Based on representative E&P Tank Emission Summary Output.
H 2 S mole % 0.10% H 2 S 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 inputFacility 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) H 2 S weight % 0.000% H 2 S weight percent of the wellstream gas. (From representative field gas analysis)
H 2 S mole % 0.000% H 2 S 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) DescriptionFacility:

North John Elk 28-27HC Pad Associated Well: North John Elk 28-27HC

VOC HAP NOx PM PM10 PM2.5 CO H 2 S SO 2 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 H 2 S SO 2 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 Pollutants a 

# Dakota-3 E&P Company, LLC

Allowable Potential to Emit 

## Emission Summary

Uncontrolled Potential to EmitFacility:

North John Elk 28-27HC Pad Associated Well: North John Elk 28-27HC 

# Dakota-3 E&P Company, LLC

CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O 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 Gases b Potential To Emit G reenhouse Gases bBOPD

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 EMISSIONS a

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 = 353.65 TPY 1 ton/2000 lb x 1/379 scf/lb-mole

1 ton/2000 lb 0.20

0.87

80.74 

# REGULATED GREENHOUSE GAS EMISSIONS b = 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 lbscf/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 EMISSIONS a

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 % H 2 S: 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 % H 2 S: 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 % SO 2 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 % SO 2 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 EMISSIONS b

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 x750,000 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 A ssociated Well: North John Elk 28-27HC


### Heater Treater Burner a

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

0.32Saturation 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 H ours 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 TPYDakota-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 1Mandaree 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 R 2 = 1.00000 y = 0.6126x R 2 = 1

0 100 200 300 400 500 600 700

0 500 1000 1500tons/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

................ CR

Ͳ 10330 Study Number.......... CR

Ͳ 2 Date Sampled

.............. 7

Ͳ 15

Ͳ 2010 Date Tested............. 7

Ͳ 23

Ͳ 2010

S l Id tifi ti CROSS 2 13 H CRUDE OIL 

## EXTENDED HYDROCARBON (GLYCALC) LIQUID STUDY

Samp l e I d enti f ication

.................... C R OSS 2-13 H C RUDE O IL



### Sample Location .......... MONTANA. Sample Pressure ......... 22 PSIG Sample Temperature.... 95 F Type Sample ............... SPOT County...................... DUNN Test method ................ 

### GPA

Ͳ 2286 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 

### iso

Ͳ Butane

.................. 0.855 0.353 0.463



### n

Ͳ Butane

.................... 3.974 1.640 2.072 

### iso

Ͳ Pentane

................ 1.378 0.706 0.833



### n

Ͳ Pentane

................... 2.569 1.316 1.540 

### H 2 510 1 536 1 707 

### exanes

..................... . . . 

### 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



### n

Ͳ Hexane

.................... 2.798 1.712 1.903 

### 2,2,4

Ͳ Trimethylpentane... 0.542 0.440 0.466 

### TOTALS

..................... 100.000 100.000 100.000ADDITIONAL BETX DATA



### Components Mole % Weight % Liq. Vol. % 2-Methylpentane 

### 1.486 0.910 1.011 3-Methylpentane 

### 1 024 0 627 0 696 3

- Methylpentane



### . . . 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 33 400 TRUE VAPOR PRESSURE AT 100 F
, PSIA

, calculated

................................................ . 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 b CR 10330 St d N b a umer............. CR-10330 Study Number............ 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

A PI 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.................. 658.98 PPMW



### 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 1min 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 / 20.182 / 20.222 / 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

................ CR

Ͳ 10330 Study Number.......... CR

Ͳ 3 Date Sampled

.............. 7

Ͳ 15

Ͳ 2010 Date Tested............. 7

Ͳ 23

Ͳ 2010

S l Id tifi ti PATRICIA CHARGING 4 15 H CRUDE OIL 

## EXTENDED HYDROCARBON (GLYCALC) LIQUID STUDY

Samp l e I d enti f ication

.................... PATRI C IA C HAR G IN G 4-15 H C RUDE O IL



### Sample Location .......... MONTANA. Sample Pressure ......... 80 PSIG Sample Temperature.... 70 F Type Sample ............... SPOT County...................... DUNN Test method ................ 

### GPA

Ͳ 2286 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 

### iso

Ͳ Butane

.................. 0.862 0.335 0.445



### n

Ͳ Butane

.................... 3.606 1.403 1.795 

### iso

Ͳ Pentane

................ 1.238 0.598 0.715



### n

Ͳ Pentane

................... 2.329 1.125 1.333 

### H 2 180 1 257 1 415 

### exanes

..................... . . . 

### 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



### n

Ͳ Hexane

.................... 2.204 1.271 1.431 

### 2,2,4

Ͳ Trimethylpentane... 0.387 0.296 0.317 

### TOTALS

..................... 100.000 100.000 100.000ADDITIONAL BETX DATA



### Components Mole % Weight % Liq. Vol. % 2-Methylpentane 

### 1.272 0.734 0.826 3-Methylpentane 

### 0 908 0 524 0 590 3

- Methylpentane



### . . . 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 46 319 TRUE VAPOR PRESSURE AT 100 F
, PSIA

, calculated

................................................ . 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 b CR 10330 St d N b a umer............. CR-10330 Study Number............ 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

A PI 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.................. 940.25 PPMW



### 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 1min 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 / 15.621 / 15.658 / 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

• UL 142 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 UL 142 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, UL 142,1803046/1,1808528, 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.

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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 

### 6Dakota-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" DlA 

### x 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 

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# , "'"Dakota-3 E&P Company, LLC. NSR Synthetic Minor Application WEP211324 

# ATTACHMENT H: PROCESS FLOW DIAGRAM OF **F ACILITY** 

### 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 F lare **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 LineDakota-3 E&P Company, LLC. NSR Synthetic Minor Application WEP211324 

# ATTACHMENT I: PRODUCTION DECLINE CURVE **C ALCULATIONS** Dakota-3 E&P Company, LLC. NSR Synthetic Minor Application WEP211324 

# ATTACHMENT J: DIESEL TANK EPA TANKS 4.09D **E MISSIONS 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) 

## Page 1 of 6 TANKS 4.0 Report

9/29/2011 file://C:\Program Files\Tanks409d\summarydisplay.htm

### 1000 gallon diesel tank - Horizontal Tank Williston, North Dakota 

## T ANKS 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 

## Page 2 of 6 TANKS 4.0 Report

9/29/2011 file://C:\Program Files\Tanks409d\summarydisplay.htm

### 1000 gallon diesel tank - Horizontal Tank Williston, North Dakota 

## T ANKS 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 

## Page 3 of 6 TANKS 4.0 Report

9/29/2011 file://C:\Program Files\Tanks409d\summarydisplay.htmAnnual Turnovers: 2,244.3120 Turnover Factor: 0.1800 Tank Diameter (ft): 4.1600 Working Loss Product Factor: 1.0000

Total Losses (lb): 5.9375 

## Page 4 of 6 TANKS 4.0 Report

9/29/2011 file://C:\Program Files\Tanks409d\summarydisplay.htm

## Emissions Report for: Annual

1000 gallon diesel tank - Horizontal Tank Williston, North Dakota 

## T ANKS 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 

## Page 5 of 6 TANKS 4.0 Report

9/29/2011 file://C:\Program Files\Tanks409d\summarydisplay.htm

## Page 6 of 6 TANKS 4.0 Report

9/29/2011 file://C:\Program Files\Tanks409d\summarydisplay.htm