DAKOTA-3 F.&P COMPANY. LLC

a slIbsidial')' ofWiliiallls 1001 17'" Street, Suite 1200 Denver, CO 80202 303/527·3900


### September 30, 2011

Ms, Kathleen Paser Minor NSR Permitting Coordinator U.S. EPA, Region 8 1595 Wynkoop Avenue, 8P-AR Denver, CO 80202-1 129 Duplicate submittal provided via e-mail to: paser.kathleen@epa.gov

Re: Synthetic Minor Source Permit Application for the George Evans 11-2H 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 George Evansll-2H Pad. This application is being submitted in accordance with the requirements of the August 29, 20 II Consent Agreement, regarding compl iance with the Federal Minor New Source 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 COlllpauy, 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** George Evans 11-2H 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* Mountrail 11a. Latitude* 47.82055 11b. Longitude* 102.41529

12a. Quarter Quarter Section 

### * SWSE 12b. Section* 11 12c. Township* T150N 12d. Range* R92W

## B. PREVIOUS PERMIT ACTIONS (Provide information in this format for each permit that has b een 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 t he process flow diagram to be submitted with this application.

 P rocess 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.

 T ype 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

o rganic 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

c alculations 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

r equired 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 P M 10 

### - Particulate Matter less th an 10 microns in size PM 2.5 

### - Particulate Matter less th an 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 T RS - Total Reduced Sulfur RSC - Reduced Sulfur Compounds **PM** 

## 0.46 **0 .63** 

**PM 10**  

## 0.46 **0 .63** 

**PM 2.5**  

## 0.46 **0 .63** 

**SO x**  

## 0.03 **0 .03** 

**NO x**  

## 30.16 **3 3.84** 

**CO** 

## 99.05 **1 19.06** 

**VOC** 

## 1978.94 **8 5.64** 

**Pb** 

## Negligible **N egligible** 

**Fluorides** 

## Negligible **N egligible** 

**H 2**  

### SO **4** 

## Negligible **N egligible** 

**H 2**  

### S 

## Negligible **N egligible** 

**TRS** 

## Negligible **N egligible** 

**RSC** 

## Negligible **N egligible** 

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 P M 2.5 

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

### - Ammonia F luorides - Gaseous and particulates H 2 

### SO 4 

### - Sulfuric Acid Mist H 2 

### S - Hydrogen Sulfide T RS - Total Reduced Sulfur RSC - Reduced Sulfur CompoundsP age 7 of 15 

# Instructions

**Us e 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.



## • 4 0 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.P age 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).P age 9 of 15 

# B. Current Permit Information

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

Th is 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.

 **F ORM 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

w ith 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.P age 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

m inimum, 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

o f material and product.

 T ype 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. I nclude manufacturer specifications and guarantees for each control device.P age 11 of 15 

# Criteria Pollutant Emissions **Estimates**

 Estimates of Current Actual Emissions, Current Allowable Emissions, Post-Change Uncontrolled Em issions, 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

o rganic compound (VOC), lead (Pb) and lead compounds, ammonia (NH 3 

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

## SO 4 

## ), hydrogen sulfide (H 2 

## S), total reduced sulfur (TRS) and

r educed 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. F or 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 anyP age 12 of 15 

## e missions unit are calculated considering any emissions limitations that are enforceable as a practical matter on the unit’s PTE.

2. For an **e xisting 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. F or 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 p otential to emit of each unit.

• 

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

r eplaced, 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 t he 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.P age 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

a bove, please contact EPA Region 8’s Modeling Lead:

Gail Tonnesen Region 8 Modeling Lead Tonnesen.gail@epa.gov 303-312- 6113P age 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 f urther modeling is necessary.
**Significant Impact Levels Pollutant Averaging Period Class II Area SIL**  **(ug/m 3**  

## ) **C lass 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.P age 15 of 15 

## 5

. Sources that cannot demonstrate protection of air quality using a screening technique should continue to the modeling requirements in **Step 3** through **Step 6** . Modeling in Steps 3 through 6 should be performed based an approved protocol.

6. Applicants are encouraged to contact the EPA Region 8 Modeling Lead prior to conducting any refined modeling analysis (Step 3 through Step 6) to obtain an approved protocol.


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

1. Approved Modeling Protocol
In order to expedite the permitting process, it is recommended that you include a protocol that has already been approved. An application will not be deemed complete until the protocol has been approved.

2. Modeling Results
In all cases, the modeling results should include the name of the model used, all input parameters, and the resulting output. Electronic copies of the modeling input/output files should be provided to EPA Region 8.



#  **ESA**

The Endangered Species Act requires us, in consultation with the U.S. Fish and Wildlife Service and/or the NOAA Fisheries Service, to ensure that actions we authorize are not likely to jeopardize the continued existence of any listed species or result in the destruction or adverse modification of designated critical habitat of such species.

To expedite the approval of your proposed construction, we encourage you to identify any listed species that you may be readily aware of that could be affected by your proposal. The following website has been provided to assist you:
http://www.fws.gov/endangered/
Simply enter the State and County in which you propose to construct to obtain a general listing.



#  **NHPA**

Th e 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 a treghome
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**  D akota-3 E&P Company, LLC **Facility Name** George Evan 11-2H 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:**

 **I tem 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.P age 2 of 4 

# I **n structions** 

**Us e 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 thatP age 3 of 4 

## c ase, 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

s pecifications). 

## ( 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 G HG emissions by at least 75,000 tpy CO 2 

## e and minor sources that increase GHG emissions by at least 1 00,000 tpy CO 2 

## e and 100 or 250 tpy on a mass basis are subject to PSD permitting requirements, even i f 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 GHGP age 4 of 4 

## a djusted 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 

# G **EORGE EVANS 11-2H PAD ATTACHMENTS:**
Attachment A: Application Report

A ttachment 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 

# A **TTACHMENT A: APPLICATION REPORT**

# APPLICATION FOR AN NSR **SYNTHETIC MINOR AIR QUALITY PERMIT**  **GEORGE EVANS 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, 2011George Evans 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 .................................................. 23George Evans Pad 09/30/11 pg. iii NSR Synthetic Minor Permit Application Project #: WEP211324 

# FIGURES

Figure 1: Example of Maximum PTE from aSeven Well Pad .................................... 6 Figure 2: Example of Actual Production from a Seven Well Pad .............................. 7



# 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 SummaryGeorge Evans 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 George Evans 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 George Evans Pad is proposed to be located in the southwest 1⁄4 of the southeast 1⁄4

Section 11, Township 150 North, Range 92 West, Mountrail County, on the FBIR in North Dakota.



# 1.3. **Site Description**
At the proposed George Evans Pad there will be six oil and gas wells that are 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 Mountrail County, North Dakota. The surrounding area is mainly used for agriculture and livestock grazing. The proposed pad’s associated well names are:
1. George Evans 11-2HC 2. George Evans 11-2HD 3. George Evans 11-2HZ 4. George Evans 11-2D 5. George Evans 11-2DGeorge Evans Pad 09/30/11 pg. 2 NSR Synthetic Minor Permit Application Project #: WEP211324 

## 6. George Evans 11-2D

The names of the wells may be subject to change due to landowner requirements, drilling location changes, timing of well leases, etc. The Agency will be notified if the names change.George Evans Pad 09/30/11 pg. 3 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 George Evans Pad. For purposes of estimating emissions from this facility, the combined first twelve-month potential production from the six proposed wells at this facility was used. These production rates can be found in Attachment B, Emission Inventory.
The production rates used in this application are grossly overestimated when compared to the actual predicted production rates in the first and subsequent years. The wells that will be producing to this facility do not begin producing at the same time. In reality, there will be up to six or more years’ difference in when the initial production from wells begin to when the final wells are constructed and begin to produce. It is not physically possible for all of the wells to be simultaneously drilled and begin initial production. However, to allow for reasonable flexibility and to be conservative, this application has considered a maximum potential production case from the pad. Due to ever-changing drilling schedules, completion schedules, economics, etc., the wells will begin actual production at different times.
The entire pad facility will consist of the following primary production equipment and capabilities.
6 - Heater Treater/Separators 6 - Line-Heaters (0.75 MMBtu/hr max) 30 - Oil Production Tanks 1 - Gasoline Recycling Pump 12 - Produced Water Tanks 6 - Electric Lifting Units 6 - Oil and Gas Producing Wells 1 - Truck Loading Rack 1 - Manufactured Produced Gas Flare 6 - Diesel Engines 1 - Manufactured Enclosed Tank Vapor Combustor


## The oil/gas/water emulsion being produced from the wells is transported up each wellbore using an electric lifting unit. The emulsion from the wells producing to this site is transported in a closed system to individual two-phased separators and then to the three-phase separators (heater treaters). 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 treaters then reduce the pressure closer to ambient pressure and heat 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 separators 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 combustionGeorge Evans Pad 09/30/11 pg. 4 NSR Synthetic Minor Permit Application Project #: WEP211324 

## device. The stored oil is transported for sale via the truck loadout. 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. Onsite diesel genset engines will provide electricity until transmission lines are installed.
A process flow diagram and plot plan of the site is shown in Attachment H.George Evans Pad 09/30/11 pg. 5 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 each 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.
As noted in Section 2.0 above, determination of potential emissions from the proposed George Evans Pad has been approached in a very conservative fashion. The combined production rate for the pad assumes all of the wells start production simultaneously (represented in example Figure 1). With this assumption, the initial 30- day production from each well is summed to estimate a potential total production rate from the pad. Operating practice is that the wells will be drilled over time, often months or even years apart. Further, after each well is drilled and brought into production, the initial production rate generally decreases greatly before the next well is drilled. Therefore, this potential to emit (PTE) estimate is meant only to define an outer envelope of emissions for permitting applicability purposes. Furthermore, the allowable emissions estimates presented in Section 4 are also very conservative compared to anticipated actual emissions that could be emitted at the facility during any given 12- month rolling average. An example demonstrating the predicted production of a theoretical multiple well pad over an extended period of time is presented in Figure 2. This example does not represent predicted production from the well pad being permitted in this application; however, it does serve to demonstrate typical operations for this type of facility.George Evans Pad 09/30/11 pg. 6 NSR Synthetic Minor Permit Application Project #: WEP211324 

# Figure 1: Example of Maximum PTE from a Seven Well PadGeorge Evans Pad 09/30/11 pg. 7 NSR Synthetic Minor Permit Application Project #: WEP211324 

# Figure 2: Example of Actual Production from a Seven Well Pad

1st well begins production 2nd well begins production 3rd and 4th wells begin production

5th well begins production 6th and 7th wells begin production

0 500 1,000 1,500 2,000 2,500 3,000 3,500

0 5 10 15 20 25 30 35 40Monthly Average BOPD



### Month 

# Example of Actual Production From a Seven-Well Well Pad

Total Production from Seven Wells on Pad
12-Month Rolling Average Oil Production 12-Month Rolling Average Oil Production LimitGeorge Evans Pad 09/30/11 pg. 8 NSR Synthetic Minor Permit Application Project #: WEP211324

## Potential emissions from this facility originate primarily from the heater treater lineheaters 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 engines and natural gas-fired external combustion units, 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 Gensets) 4. Natural Gas External Combustion Units (Heater Treater Line-Heaters); 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 pipelineGeorge Evans Pad 09/30/11 pg. 9 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 Engines
Diesel engines connected to generators provide the facility with electricity. The potential emissions from the engines 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 units at the facility are the heater treater lineheaters. Each 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
Oil sales and water pipelines are planned for this facility in the future; however, since the pipeline infrastructure has not yet been constructed, the facility is not anticipated to be hooked to the oil sales pipeline in the near future, and the produced oil and water will be trucked from the facility. The emissions associated with the truck loading operations will be estimated using daily production, AP-42 factors, and submerged fill loading without any control.


# 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.George Evans Pad 09/30/11 pg. 10 NSR Synthetic Minor Permit Application Project #: WEP211324 

# 4.0 EMISSIONS AND OPERATIONAL LIMITS REQUESTS

Datoka-3 is requesting emissions and operational limits at the George Evans 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: 85.64 tons per year of VOCs and 1.02 tons per year of HAPs.


# 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.George Evans Pad 09/30/11 pg. 11 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 units (0.5-0.75 MMBtu/hr heater treater line-heaters) at the facility; therefore, the emissions estimate is equal to the uncontrolled potential to emit.George Evans Pad 09/30/11 pg. 12 NSR Synthetic Minor Permit Application Project #: WEP211324 

# 5.5 Truck Loading Emissions

No limits have been requested for the truck loading operations at the facility; therefore, the emissions estimate is equal to the uncontrolled potential to emit.


# 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 gensets. 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.George Evans Pad 09/30/11 pg. 13 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.George Evans Pad 09/30/11 pg. 14 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.George Evans Pad 09/30/11 pg. 15 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.George Evans Pad 09/30/11 pg. 16 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.George Evans Pad 09/30/11 pg. 17 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-heaters, no monitoring or recordkeeping requirements are being proposed by Dakota-3.George Evans Pad 09/30/11 pg. 18 NSR Synthetic Minor Permit Application Project #: WEP211324 

# 6.6 Truck Loading
The truck loading rack is designed for submerged filling of the tank trucks. This is standard operating procedure.
Monitoring Requirements:
The monitoring requirements for truck loading will be estimating the monthly VOC, total HAP, and any single HAP emissions from the loadout operations using input parameters, equations, and emission factors from AP-42, Fifth Edition, Volume I, Chapter 5.
Recordkeeping Requirements:
Total VOC, total HAP, and any single HAP emissions, in tons, from loading operations 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 all input parameters and calculations used to determine the monthly emissions.


# 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 theGeorge Evans Pad 09/30/11 pg. 19 NSR Synthetic Minor Permit Application Project #: WEP211324 

## leak is detected. Dakota-3 will minimize leaks of volatile organics from each piece of equipment in hydrocarbon service at this facility.
Monitoring Requirements:
a. Dakota-3 will conduct leak detection monitoring on an annual basis. If no instrument reading of 10,000 ppm or greater is measured for two consecutive quarterly monitoring periods, the required monitoring frequency will change from quarterly to semi-annual. If no instrument reading of 10,000 ppm or greater is measured for two consecutive semi-annual monitoring periods, the required monitoring frequency will change from semi-annual to annual. If any single instrument reading of 10,000 ppm or greater is measured, the required monitoring frequency will change back to quarterly. b. Dakota-3 will use one of the following methods to conduct leak detection of the equipment: i. Method 21 a) Use the equipment leak detection methods in 40 CFR Part 60, Appendix A–7, Method 21; and b) If an instrument reading of 10,000 ppm or greater is measured, a leak 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.George Evans Pad 09/30/11 pg. 20 NSR Synthetic Minor Permit Application Project #: WEP211324 

## Recordkeeping Requirements:
a. Dakota-3 will document and maintain a record of each leak detection inspection and repairs. b. All leak detection inspection records will include, at a minimum, the following information: i. Date of the inspection; ii. All documentation and/or images produced in the inspection; iii. Findings of the inspection; iv. Any corrective action taken; and v. Inspector's name and signature.


# 6.8 General Recordkeeping Requirements
Total VOC (or VOC, total HAP, and any single HAP) emissions, in tons, from each piece of equipment will be calculated and recorded at the end of each month, beginning with the first full calendar month after operations commenced. Prior to twelve full months of operation, Dakota-3 will, at the end of each month, add the emissions for that month to 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.George Evans Pad 09/30/11 pg. 21 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 facility’s actual emissions are modest in nature (i.e., below typical permitting thresholds) as demonstrated in Figure 2; therefore, additional ambient impact analysis is not warranted.George Evans Pad 09/30/11 pg. 22 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.George Evans Pad 09/30/11 pg. 23 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 

# A **TTACHMENT B: EMISSION INVENTORY**Facility Information George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11- 2D Name of the facility and the well number. Not Producing Yet Approximate first date of production or the date of m odification of the facility. 9/30/2011 Date application packet is submitted to the EPA Regio n 8.
Production Data Description BOPD 5891.5858 Average daily production in barrels of oil per day (BOPD), based on the predicted first 30 days of production. Mscfd 4 094.6521 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 2 975.419 This is the calculated BOPD expected to be produced using the above entered decline factor. Adjusted Produced Gas (Mscfd) 2 067.9162 This is the calculated mcfd of gas the well is expected to produce using the above entered decline factor.

Oil/Condensate Tank Data D escription Flash Gas Method: Process Simulator Use the drop down menu to choose the appropriate flash gas method. Process Simulator Estimated scf/bbl 4 1.57 The scf/bbl from direct measurement or representative sample. B ased on representative E&P Tank Emission Summary Out put. Estimated Tank Vapors (scfd) 1 23688.17 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 2 395.38 Lower heating value (Btu/scf) of tank vapors. B ased on representative E&P Tank Emission Summary Out put. Molecular Weight 4 1.99 Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole). B ased on representative E&P Tank Emission Summary Out put. VOC% 7 6.5678 VOC weight fraction of the tank vapor gas (C3+). B ased on representative E&P Tank Emission Summary Out put. VOC TPY/BOPD Emission Factor 0 .6493 Based on representative E&P Tank Emission Summary Output. (Summary Output creates a linear relationship between TPY and BOPD) HAP% 0 .7175 HAP weight fraction of the tank vapor gas. B ased on representative E&P Tank Emission Summary Out put. HAP TPY/BOPD Emission Factor 0 .0060 Based on representative E&P Tank Emission Summary Output. (Summary Output creates a linear relationship between TPY and BOPD) CO2% 0 .23% CO2 weight fraction of the tank vapor gas. Based on representative E&P Tank Emission Summary Ou tput. CH4% 1 .59% CH4 weight fraction of the tank vapor gas. B ased on representative E&P Tank Emission Summary Out put. H 2 S weight % 0 .16% H 2 S weight percent of the tank vapor gas. B ased on representative E&P Tank Emission Summary Out put.
H 2 S mole % 0 .20% H 2 S mole percent of the tank vapor gas. B ased on representative E&P Tank Emission Summary Out put. Enclosed Smokeless Combustor Use the drop down menu to choose the appropriate emission control type. Control Destruction Efficiency 9 8% 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 George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11- 2D 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 1480 Btu/scf of wellstream gas. ( From representative field gas analysis) Molecular Weight 2 6.296606 Average molecular weight of the wellstream gas in lb/lb-mole. ( From representative field gas analysis) Specific Gravity 0 .9078931 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 2 6.30 This is the calculated molecular weight based on the specific gravity entered above. Please enter this number on Line 21. VOC% 3 6.87% VOC weight fraction of the wellstream gas (Note: Weight%, not Mole%). ( From representative field gas analysis) HAP% 0 .72% HAP weight fraction of the wellstream gas. (Note: Weight%, not Mole%). ( From representative field gas analysis) CO2% 0 .720% CO2 weight fraction of the wellstream gas. (Note: Weight%, not Mole%). ( From representative field gas analysis) CH4% 3 2.882% 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 1 00% 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) D escription Total Btu/hr 4500000 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 D escription Oil is hauled by truck Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a LACT, no input values are required 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 4 1.99 Molecular weight of tank vapors in lb/lb-mole. A ssumed same molecular weight as flashing emissions f rom 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 5 0.00 Temperature of bulk liquid loaded in Fahrenheit. If no site specific data is available, use an estimated average annual temperature. Load Rate (bbl/hr) 1 80 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:
George Evans Pad Associated Wells: George Evans 11-2HC, 11- 2HD, 11-2HZ, 11-2D, 11-2D, 11-2D

VOC H AP NOx PM PM10 PM2.5 CO H 2 S SO 2 HCHO Oil/Condensate Tanks 1931.94 17.94 N/A N/A N/A N/A N/A N/A N/A Negligible Casing Head Gas 19.31 0.38 3.80 0.29 0.29 0.29 20.67 NA 0.00 0.00 Treater Burner 0.11 0.04 1.93 0.15 0.15 0.15 1.62 N/A 0.01 Negligible RICE Engine 2.78 1.70E-02 24.43 0.03 0.03 0.03 76.76 N/A 2.08E-02 0.02 Truck Loading 24.80 0.23 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) 1978.94 18.61 30.16 0.46 0.46 0.46 99.05 0.00 0.03 0.02

VOC HAP NOx PM PM10 PM2.5 CO H 2 S SO 2 HCHO Oil/Condensate Tanks 38.64 0.36 3.68 0.17 0.17 0.17 20.01 N/A N/A Negligible Casing Head Gas 19.31 0.38 3.80 0.29 0.29 0.29 20.67 0.00 0.00 0.00 Treater Burner 0.11 0.04 1.93 0.15 0.15 0.15 1.62 N/A 0.01 Negligible RICE Engine 2.78 1.70E-02 24.43 0.03 0.03 0.03 76.76 N/A 2.08E-02 0.02 Truck Loading 24.80 0.23 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) 85.64 1.02 33.84 0.63 0.63 0.63 119.06 0.00 0.03 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

C riteria Pollutants a 

# Dakota-3 E&P Company, LLC

Allowable Potential to Emit 

## Emission Summary

Uncontrolled Potential to EmitFacility:
George Evans Pad Associated Wells: George Evans 11-2HC, 11- 2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# 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 39.79 N/A 2714.54 0.00 0.05 Casing Head Gas 4547.58 17.22 0.00 4547.58 17.22 0.00 Treater Burner 2318.82 0.13 0.03 2318.82 0.13 0.03 RICE Engine 3.79E+01 0.34 0.07 3.79E+01 0.34 0.07 Truck Loading 0.07 0.52 N/A 0.07 0.52 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) 6904.36 57.99 0.10 9618.90 18.20 0.15

GHG Mass Emissions (tpy): 6962.45 GHG Mass Emissions (tpy): 9637.25 CO2e (tpy): 8152.59 CO2e (tpy): 10047.64 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 G reenhouse Gases b Potential To Emit Gr eenhouse 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. 0.0186%

0 .0018% 0.0132%

0.6143% 0.0109%

0.0587%

CH4 wt Fraction 0.006

Controlled emissions are calculated based on a 0.23%

1 .59% CO2 wt Fraction 

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D


# Tanks

Flare Gas Volume 1 23,688 Oil Production 2975

0.649 Lower Heating Value 2395.38

Molecular Weight 41.99

VOC wt Fraction 76.57%

VOC Emission Factor

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D


# Tanks

Uncontrolled VOCs (PTE): DRE Using E&P Tanks Run: 0.649 x 2975.42 x 0% = 1931.94 TPY



### Controlled VOCs (Allowable): DRE Using E&P Tanks Run: 0.649 x 2975.42 x 98% = 38.64 TPY



### Uncontrolled HAPs (PTE): Using E&P Tanks Run: wt% DRE TPY Benzene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.02% x 0% = 0.11 lb/hr 0.47 E-Benzene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.00% x 0% = 0.01 lb/hr 0.05

Toluene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.01% x 0% = 0.08 lb/hr 0.33 n-Hexane 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.61% x 0% = 3.51 lb/hr 15.36

Xylene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.01% x 0% = 0.06 lb/hr 0.27 2,2,4-Trimethylpentane 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.06% x 0% = 0.34 lb/hr 1.47

Uncontrolled TOTAL HAPS (TPY) 17.94



### Controlled HAPs (Allowable):
Benzene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.01 E-Benzene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01 n-Hexane 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.61% x 98% = 0.07 lb/hr 0.31

Xylene 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01 2,2,4-Trimethylpentane 5,154 scf/hr x x 1/379 scf/lb-mole x 41.99 lb/lb-mol x 0.06% x 98% = 0.01 lb/hr 0.03

Controlled TOTAL HAPS (TPY) 0.36 BOPD

TPY VOC/BOPD TPY VOC/BOPD 

# CRITERIA POLLUTANT EMISSIONS a

BOPD

= =

=

=

=

=

=

=

= =

= =

=

=

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D


# Tanks

Uncontrolled NOx:

NOx: 0 scf/hr x 2,395 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: 5,154 scf/hr x 2,395 Btu/scf x x 0.068 lb/MMBtu = 0.84 lb/hr

0.84 lb/hr x x 3.68 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: 5,154 scf/hr x 7.6 lb/1,000,000 scf = 0.04 lb/hr

0.04 lb/hr x 8760 hr/yr x 0.17 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

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D


# Tanks

Uncontrolled CO:

CO: 0 scf/hr x 2,395 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: 5,154 scf/hr x 2,395 Btu/scf x x 0.370 lb/MMBtu = 4.57 lb/hr

4.57 lb/hr x x 20.01 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: 5,154 scf/hr x x 41.99 lb/lb-mole 0.23% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY



### CO2 Created by Combustion (Actual)

CO2: 5,154 scf/hr x 120,000.0 lb/1,000,000 scf = lb/hr

618.44 lb/hr x 8760 hr/yr x = 2708.77 TPY 1 ton/2000 lb x 1/379 scf/lb-mole

1 ton/2000 lb 1.32

5.77

618.44 

# REGULATED GREENHOUSE GAS EMISSIONS b = 1 MMBtu/1,000,000 Btu

8760 hr/yr 1 ton/2000 lb

1.32 1 MMBtu/1,000,000 Btu

8760 hr/yr 1 ton/2000 lb =

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D


# Tanks

Uncontrolled CH4:

wt DRE CH4: 5,154 scf/hr x x 41.99 lb/lb-mole 1.59% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY



### Controlled CH4: (Actual)

wt% DRE CH4: 5,154 scf/hr x x 41.99 lb/lb-mole 1.59% x 98% = lb/hr

lb/hr x 8760 hr/yr x = TPY



### Uncontrolled N2O:

wt% DRE CH4: 5,154 scf/hr x x 41.99 lb/lb-mole 0.00% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY



### N2O Created by Combustion:

CH4: 5,154 scf/hr x 2.3 lb/1,000,000 scf = lb/hr

0.01 lb/hr x 8760 hr/yr x = 0.05 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

0.01

1 ton/2000 lb

x 0.00 0.18

0.18 0.80 1/379 scf/lb-mole

1/379 scf/lb-mole

1 ton/2000 lb 1 ton/2000 lb x 9.08

9.08 39.79 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 

## George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

Flare Gas Volume 8, 616

Lower Heating Value 1480

Avg. Molecular Weight 26.30

VOC wt fraction 36.87%

0.72% 0.02% 0.00% 0.01% 0.61% 0.01%

0.06%

0.72%

32.88%

98%

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

Controlled VOCs (PTE):
wt% Control % VOC: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 lb/lb-mole 36.87% x 98% = lb/hr

4.41 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY



### Controlled VOCs (Allowable):
wt% Control % VOC: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 lb/lb-mole 36.87% x 98% = lb/hr

4.41 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY 19.31

4.41

19.31 x 

# CRITERIA POLLUTANT EMISSIONS a

x 4.41

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

Controlled HAPs (PTE):

Using E&P Tanks Run: wt% Control % TPY Benzene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.01 E-Benzene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01 n-Hexane 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.61% x 98% = 0.07 lb/hr 0.32

Xylene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01 2,2,4-Trimethylpentane 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.06% x 98% = 0.01 lb/hr 0.03 Formaldehyde 8,616 scf/hr 7.50E-02 lb/MMscf = 0.00 lb/hr 0.00

` 0.09 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY



### Controlled HAPs (Allowable):

Using E&P Tanks Run: wt% Control % TPY Benzene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.02% x 98% = 0.00 lb/hr 0.01 E-Benzene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01 n-Hexane 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.61% x 98% = 0.07 lb/hr 0.32

Xylene 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01 2,2,4-Trimethylpentane 8,616 scf/hr x x 1/379 scf/lb-mole x 26.29661 lb/lb-mol x 0.06% x 98% = 0.01 lb/hr 0.03 Formaldehyde 8,616 scf/hr x 7.50E-02 lb/MMscf x 1000000 scf/MMscf = 0.00 lb/hr 0.00

` 0.09 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY =

=

=

= 0.38 =

= =

=

= =

=

=

=

=

0.38

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

Uncontrolled NOx (PTE):

NOx: 8,616 scf/hr x 1,480 Btu/scf x x 0.068 lb/MMBtu = 0.87 lb/hr

0.87 lb/hr x 8760 hr/yr x 3.80 TPY



### NOx Created by Combustion (Actual):

NOx: 8,616 scf/hr x 1,480 Btu/scf x x 0.068 lb/MMBtu = 0.87 lb/hr

0.87 lb/hr x 8760 hr/yr x 3.80 TPY



### Controlled H2S (PTE):
wt% Control % H 2 S: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 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: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 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

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

SO2 Created by Combustion (PTE):
wt% Control % SO 2 8,616 s cf/hr x 1/379 scf/lb-mole x 26.29661 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 8,616 s cf/hr x 1/379 scf/lb-mole x 26.29661 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: 8,616 scf/hr x 1,480 Btu/scf x x 0.370 lb/MMBtu = 4.72 lb/hr

4.72 lb/hr x 8760 hr/yr x 20.67 TPY



### CO Created by Combustion (Actual):

CO: 8,616 scf/hr x 1,480 Btu/scf x x 0.370 lb/MMBtu = 4.72 lb/hr

4.72 lb/hr x 8760 hr/yr x 20.67 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

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

PM Created by Combustion (PTE):

PM: 8,616 scf/hr x 7.6 = 0.07 lb/hr

0.07 lb/hr x 8760 hr/yr x 0.29 TPY



### PM Created by Combustion (Actual):

PM: 8,616 scf/hr x 7.6 = 0.07 lb/hr

0.07 lb/hr x 8760 hr/yr x 0.29 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

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

CO2 (PTE):

CO2 Entrained in the Produced Gas:
Control % CO2: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 lb/lb-mole 0.72% x 98% = lb/hr

4.30 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 18.84 TPY 

### CO2 Created by Combustion:

CO2: 8,616 scf/hr x 120,000.0 = 1033.96 lb/hr

` 1033.96 lb/hr x 8760 hr/yr x 4528.74 TPY

4547.58 TPY



### CO2 (Actual):

CO2 Entrained in the Produced Gas: wt% Control % CO2: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 lb/lb-mole 0.72% x 98% = lb/hr

4.30 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 18.84 TPY 

### CO2 Created by Combustion: `

CO2: 8,616 scf/hr x 120,000.0 = 1033.96 lb/hr

` 1033.96 lb/hr x 8760 hr/yr x 4528.74 TPY

4547.58 TPY 

# REGULATED GREENHOUSE GAS EMISSIONS b

1 ton/2000 lb = x 4. 30

Total CO2 Emitted (Allowable): 1 ton/2000 lb = lb/1,000,000 scf

lb/1,000,000 scf Total CO2 Emitted (PTE):

x 4.30

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Casing Head Gas

Controlled CH4 (PTE):

wt% Control % CH4: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 lb/lb-mole 32.88% x 98% = lb/hr

3.93 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY



### Controlled CH4 (Actual):

wt% Control % CH4: 8,616 scf/hr x 1/379 scf/lb-mole x 26.29661 lb/lb-mole 32.88% x 98% = lb/hr

3.93 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY



### N2O Created by Combustion (PTE):

N2O: 8,616 scf/hr x 2.2 = 1.90E-02 lb/hr

1.90E-02 lb/hr x 8760 hr/yr x 4.74E-03 TPY



### N2O Created by Combustion (Actual):

N2O: 8,616 scf/hr x 2.2 = 1.90E-02 lb/hr

1.90E-02 lb/hr x 8760 hr/yr x 4.74E-03 TPY

(Emission Factors for Natural Gas Combustion). x 3.93

17.22

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 = 3.93

17.22 x4,500,000 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 4.50 MMBtu/hr = 0.441 lb/hr

0 .4412 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 1.932 TPY

C O: 0.08 lb/MMBtu x 4.50 MMBtu/hr = 0.371 lb/hr

0 .37 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 1.623 TPY

SO 2: 5.88E-04 lb/MMBtu x 4.50 MMBtu/hr = 0.003 lb/hr

2 .65E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.012 TPY

PM : 0.01 lb/MMBtu x 4.50 MMBtu/hr = 0.034 lb/hr

0 .03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.147 TPY

VO C: 0.01 lb/MMBtu x 4.50 MMBtu/hr = 0.024 lb/hr

0 .02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.106 TPY

H AP: 0.002 lb/MMBtu x 4.50 MMBtu/hr = 0.008 lb/hr

8 .34E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.037 TPY

C O2 117.647 lb/MMBtu x 4.50 MMBtu/hr = 529.412 lb/hr

5 .29E+02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 2,318.824 TPY

C H4: 0.007 lb/MMBtu x 4.50 MMBtu/hr = 0.030 lb/hr

2 .98E-02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.130 TPY

N 2O: 0.001 lb/MMBtu x 4.50 MMBtu/hr = 0.006 lb/hr

5 .95E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.026 TPY

N Ox TPY

CO TPY

SO2 TPY

PM TPY

VOC TPY

HAP TPY

CO2 TPY

CH4 TPY

N2O TPY 

## Dakota-3 E&P Company, LLC

2318.82

0 .13

0.03 1.62

0.11

0.04 0.01

0.15 George Evans Pad A s sociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D


### Heater Treater Burner a

a NOx, CO, CO2, & VOC Emission Factors are from AP-42 T able 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

1.93Saturation Vapor Molecular Temp + Load Loss Factor (S) Pressure (P) Weight (MW) 460 lb/1000 gal 12.46 x 0.60 x 2.30 x 41.99 / 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 1086027.92 x 42.00 / 2000.00 = 32.39 24.80

VOC Emissions Uncontrolled Control % TPY 24.80 0% 1.00 24.80

LL Annual Emissions lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 1.42 x 1086027.92 x 42.00 / 2000.00 = 32.39 0.23

HAPs Emissions Uncontrolled Control % TPY 0.23 0% 1.00 0.23

LL Annual Emissions lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 1.42 x 1086027.92 x 42.00 / 2000.00 = 32.39 0.07

CO2 Emissions Uncontrolled Control % TPY 0.07 0% 1.00 0.07

LL Annual Emissions lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 1.42 x 1086027.92 x 42.00 / 2000.00 = 32.39 0.52

CH4 Emissions Uncontrolled Control % TPY 0.52 0% 1.00 0.52 

# Dakota-3 E&P Company, LLC

George Evans Pad Associated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D



# 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 1650 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 o urs 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

1650 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 1650 HP x 1 lb / 453.6 grams = 5.43E+00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.38E+01 NOx TPY

CO: 2.61E+00 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 9.50E+00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 4.16E+01 CO TPY

SO2: 4.52E-06 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 1.64E-05 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 7.20E-05 SO2 TPY

PM: 4.85E-06 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 1.76E-05 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 7.73E-05 PM TPY

VOC: 1.42E-01 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 5.16E-01 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.26E+00 VOC TPY

HAP: 1.02E-06 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 3.71E-06 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.63E-05 HCHO TPY

CO2: 2.54E-03 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 9.22E-03 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 4.04E-02 CO2

CH4: 2.10E-02 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 7.64E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 3.35E-01 CH4

N2O: 4.20E-03 g/HP-HR 1650 HP x 1 lb / 453.6 grams = 1.53E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 6.69E-02 N2O 

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Reciprocating Engine Emissions

x

x x

x

x x

x x

x

# Dakota-3 E&P Company, LLC

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# 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

George Evans Pad A ssociated Wells: George Evans 11-2HC, 11-2HD, 11-2HZ, 11-2D, 11-2D, 11-2D 

# Reciprocating Engine Emissions

2.44E+01

7.68E+01

2.08E-02

2.53E-02
2.78E+00

1.70E-02

3.79E+01

3.36E-01

6.72E-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 

# A **TTACHMENT C: FLASHING EMISSIONS CALCULATIONS**

• E&P Tanks Emission Summary

• E&P Tanks Linear Relationship (Emission Factor)Van Hook Field 1000 BOPD wt%

****************************************************************************************** * Project Setup Information *
****************************************************************************************** Project File : Y:\Projects\Williams Exploration & Production WEP\WEP211324 Ft. Berthold IR Well Work\E&P Tanks\Van Hook 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 : Van Hook Well Name : Pennington 16-15H and Van Hook 16-14H Averages Permit Number : Dakota-3 E&P Company, LLC Date : 2010.09.24

****************************************************************************************** * Data Input *
****************************************************************************************** Separator Pressure : 52.00[psig] Separator Temperature : 90.00[F] Ambient Pressure : 13.70[psia] Ambient Temperature : 50.00[F] C10+ SG : 0.7970 C10+ MW : 233.494
-- Low Pressure Oil ---------------------------------------------------------------------- No. Component wt % 1 H2S 0.0027 2 O2 0.0000 3 CO2 0.0038 4 N2 0.0008 5 C1 0.0261 6 C2 0.3417 7 C3 1.3723 8 i-C4 0.3662 9 n-C4 1.6928 10 i-C5 0.6858 11 n-C5 1.2496 12 C6 1.4712 13 C7 7.9550 14 C8 19.2940 15 C9 13.4810 16 C10+ 49.4241 17 Benzene 0.0470 18 Toluene 0.1281 19 E-Benzene 0.0586 20 Xylenes 0.3912 21 n-C6 1.5420 22 224Trimethylp 0.4660
-- Sales Oil ----------------------------------------------------------------------------- Production Rate : 1000[bbl/day] Days of Annual Operation : 365 [days/year] API Gravity : 41.5 Reid Vapor Pressure : 6.20[psia]

****************************************************************************************** * Calculation Results *
****************************************************************************************** -- Emission Summary ---------------------------------------------------------------------- Item Uncontrolled Uncontrolled [ton/yr] [lb/hr] Page 1---------------------------------------------------------------- E&P TANK
Total HAPs 6.040 1.379 Total HC 836.657 191.018 VOCs, C2+ 823.270 187.961 VOCs, C3+ 649.305 148.243 Page 1Van Hook Field 1000 BOPD wt% Uncontrolled Recovery Info. Vapor 41.5700 [MSCFD] HC Vapor 41.3600 [MSCFD] GOR 41.57 [SCF/bbl] -- Emission Composition ------------------------------------------------------------------ No Component Uncontrolled Uncontrolled [ton/yr] [lb/hr] 1 H2S 1.343 0.307 2 O2 0.000 0.000 3 CO2 1.941 0.443 4 N2 0.412 0.094 5 C1 13.387 3.056 6 C2 173.965 39.718 7 C3 448.169 102.322 8 i-C4 34.294 7.830 9 n-C4 102.418 23.383 10 i-C5 13.956 3.186 11 n-C5 18.394 4.200 12 C6 6.270 1.432 13 C7 10.476 2.392 14 C8 7.517 1.716 15 C9 1.774 0.405 16 C10+ 0.002 0.000 17 Benzene 0.156 0.036 18 Toluene 0.111 0.025 19 E-Benzene 0.016 0.004 20 Xylenes 0.090 0.021 21 n-C6 5.168 1.180 22 224Trimethylp 0.493 0.113 Total 840.352 191.861

-- 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 0.0027 0.0024 0.0001 0.1791 0.1609 0.1631 2 O2 32.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 3 CO2 44.01 0.0038 0.0026 0.0000 0.5796 0.1818 0.2307 4 N2 28.01 0.0008 0.0001 0.0000 0.3282 0.0099 0.0490 5 C1 16.04 0.0261 0.0112 0.0000 7.4009 0.7777 1.5911 6 C2 30.07 0.3417 0.2811 0.0024 30.3262 19.3302 20.6806 7 C3 44.10 1.3723 1.3000 0.5065 37.1767 55.5360 53.2811 8 i-C4 58.12 0.3662 0.3594 0.3044 3.7640 4.1203 4.0766 9 n-C4 58.12 1.6928 1.6719 1.5180 12.0581 12.1907 12.1744 10 i-C5 72.15 0.6858 0.6836 0.6696 1.7610 1.6447 1.6590 11 n-C5 72.15 1.2496 1.2474 1.2340 2.3296 2.1666 2.1866 12 C6 86.16 1.4712 1.4725 1.4830 0.8134 0.7577 0.7645 13 C7 100.20 7.9550 7.9683 8.0662 1.3546 1.2768 1.2865 14 C8 114.23 19.2940 19.3310 19.6004 0.9553 0.9145 0.9195 15 C9 128.28 13.4810 13.5078 13.7022 0.2134 0.2208 0.2201 16 C10+ 233.49 49.4241 49.5238 50.2483 0.0000 0.0000 0.0000 17 Benzene 78.11 0.0470 0.0471 0.0475 0.0197 0.0184 0.0186 18 Toluene 92.13 0.1281 0.1283 0.1300 0.0137 0.0131 0.0132 19 E-Benzene 106.17 0.0586 0.0587 0.0596 0.0020 0.0020 0.0018 20 Xylenes 106.17 0.3912 0.3920 0.3976 0.0109 0.0106 0.0109 21 n-C6 86.18 1.5420 1.5438 1.5575 0.6517 0.6091 0.6143 22 224Trimethylp 114.24 0.4660 0.4668 0.4728 0.0617 0.0581 0.0587

MW 137.41 138.18 142.90 36.81 42.83 41.99 Stream Mole Ratio 1.0000 0.9924 0.9456 0.0076 0.0468 0.0544 Heating Value [BTU/SCF] 2105.43 2442.60 2395.38 Gas Gravity [Gas/Air] 1.27 1.48 1.45 Bubble Pt. @ 100F [psia] 29.55 23.39 7.57 Page 2---------------------------------------------------------------- E&P TANK RVP @ 100F [psia] 15.49 13.82 6.27 Spec. Gravity @ 100F 0.673 0.674 0.677

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 Van Hook Field Dakota-3 Wells Separator: 52 psig, 90 degF Flash Valve: 13.7 psia, 50 degF Sales Oil: API Gravity 41.5, Reid Vapor Pressure 6.2 psia, 365 days/year
Outputs: Oil Production Rates (bbl/day) (P) 0 50 100 300 1000 Emission (tons/yr) Total HC 0 41.83255 83.6651 250.9953 836.651 VOCs, C3+ 0 32.46485 64.9297 194.7891 649.297 Total HAPs 0 0.302 0.604 1.812 6.04
VOC (C3+) Emission Factor: 0.6493 tpy/BOPD HAP Emission Factor: 0.00604 tpy/BOPD Oil Storage Tank Flashing Emissions Calculation Methodology E&P Tanks Linear Relation between Production (bbls/day) and Emissions (tons/yr)

y = 0.00604x R 2 = 1.00000 y = 0.6493x R 2 = 1

-100 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 5 Date Sampled

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

Ͳ 15

Ͳ 2010 Date Tested............. 7

Ͳ 23

Ͳ 2010

S l Id tifi ti VAN HOOK 16 14 H CRUDE OIL 

## EXTENDED HYDROCARBON (GLYCALC) LIQUID STUDY

Samp l e I d enti f ication

.................... V AN H OO K 16-14 H C RUDE O IL



### Sample Location .......... MONTANA. Sample Pressure ......... 28 PSIG Sample Temperature.... 80 F Type Sample ............... SPOT County...................... MONTRAIL Test method ................ 

### GPA

Ͳ 2286 Sampling Method........ YZ PISTON

Components Mole % Weight % Liq. Vol. % Hydrogen Sulfide

.......... 0.009 0.002 0.002 

### Oxygen

...................... 0.000 0.000 0.000 

### Carbon Dioxide

............ 0.010 0.003 0.003 

### Nitrogen

..................... 0.003 0.001 0.001 

### Methane 0 184 0 021 0 051



### ..................... . . . 

### Ethane

....................... 1.152 0.241 0.501 

### Propane

..................... 3.568 1.096 1.600 

### iso

Ͳ Butane

.................. 0.778 0.315 0.414



### n

Ͳ Butane

.................... 3.694 1.496 1.896 

### iso

Ͳ Pentane

................ 1.242 0.624 0.739



### n

Ͳ Pentane

................... 2.270 1.141 1.339 

### H 2 276 1 367 1 523 

### exanes

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

### Heptanes

.................... 10.418 7.274 7.823 

### Octanes

..................... 24.125 19.203 20.117 

### Nonanes

..................... 16.003 14.302 14.658 

### Decanes+

................... 30.668 50.576 46.892 

### Benzene...................... 0.090 0.049 0.041 

### Toluene....................... 0.183 0.117 0.100 

### Ethylbenzene............... 0.047 0.035 0.030 

### Xylenes....................... 0.455 0.337 0.288



### n

Ͳ Hexane

.................... 2.304 1.384 1.542 

### 2,2,4

Ͳ Trimethylpentane... 0.521 0.415 0.441 

### TOTALS

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



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

### 1.293 0.777 0.866 3-Methylpentane 

### 0 983 0 590 0 658 3

- Methylpentane



### . . . n-Hexane 

### 2.304 1.384 1.542 2,2,4-Trimethylpentane 

### 0.521 0.415 0.441
Benzene 

### 0.090 0.049 0.041
Toluene 

### 0.183 0.117 0.100 Ethylbenzene 

### 0.047 0.035 0.030 m-Xylene 

### 0.056 0.041 0.035 p-Xylene 

### 0.291 0.216 0.184 o-Xylene 

### 0.108 0.080 0.068

API GRAVITY AT 60/60 F, calculated........................................................................ 59.7 SPECIFIC GRAVITY AT 60/60 F, calculated.............................................................. 0.7402 RELATIVE SPECIFIC GRAVITY OF DECANES+ (C10+) FRACTION ............................... 0.7983 AVERAGE MOLECULAR WEIGHT .......................................................................... 143.505 AVERAGE MOLECULAR WEIGHT OF DECANES+ (C10+) FRACTION .......................... 236.660 TRUE VAPOR PRESSURE AT 100 F PSIA calculated 28 847 TRUE VAPOR PRESSURE AT 100 F
, PSIA
, calculated

................................................ . AVERAGE BOILING POINT, F, ................................................................................ 308.034 CUBIC FEET OF GAS / GALLON OF LIQUID, as Ideal Gas .......................................... 18.973 BTU / GALLON OF LIQUID AT 14.73 PSIA, calculated ................................................. 122702.719 LBS / GALLON OF LIQUID, calculated ...................................................................... 6.171

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-5B Date Sampled............. 7-15-2010 Date Tested.............. 7-22-2010

Sample Identification................ VAN HOOK 16-14 H CRUDE OIL

Sample Location......... MONTANA. Sample Pressure.......... N/A Sample Temperature.... N/A
Flowrate................... N/A County..................... MONTRAIL

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.............. 4.6 PSIG



### TOTAL SULFUR CONTENT (ASTM D-5453), PPMW.................. 1,562.18 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 VanHook 16-14 C:\GCsolution\DRO\DRO Data\08-2010\08-01-2010\VanHook 16-14.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 / 1.307 / 1.405 / 1.552 / 1.669 / 1.729 / 1.901 / 2.038 / 2.108 / 2.280 / 2.361 / 2.417 / 2.564 / 2.666 / 2.854 / 2.948 / 3.034 / 3.135 /

3.210 / 3.301 / 3.420 / 3.538 / 3.638 / 3.772 / 3.857 / 3.966 / 4.069 / 4.147 / 4.333 / 4.508 / 4.582 / 4.693 / 4.899 / 5.021 /

5.165 / 5.364 / 5.509 / 5.608 / Decane (C10) 5.816 / 5.947 / 6.069 / 6.190 / 6.289 / 6.392 / 6.510 /

6.562 / 6.657 / 6.713 / 6.778 / 6.903 / 7.082 / 7.220 / 7.323 / 7.381 / 7.455 / 7.559 / 7.632 / 7.745 / 7.831 / 7.906 /

7.967 / 8.056 / 8.184 / 8.269 / 8.326 / 8.451 / 8.540 / 8.632 / 8.744 / 8.807 / 8.998 / 9.127 /

9.270 / 9.380 / 9.467 / 9.526 /

9.595 / 9.724 / 9.861 / 9.939 / 10.055 / 10.125 / 10.256 / 10.332 / 10.425 /

10.487 / 10.569 / 10.639 / 10.828 / 10.912 /

11.054 / 11.219 /

11.470 / 11.614 / 11.785 / 12.031 / 12.130 / 12.183 / 12.301 / 12.412 / 12.607 / 12.705 / 12.822 / 13.004 / 13.087 / 13.300 / 13.367 / 13.454 / 13.582 / 13.672 / 13.726 / 13.925 / 14.089 / 14.146 / 14.315 / 14.446 /

14.518 / 14.594 / 14.691 / 14.776 / 14.896 / 15.041 / 15.130 / 15.242 / 15.297 /

15.369 / 15.430 / 15.565 / 15.626 / 15.792 /

15.884 / 15.948 / o-terphenyl 16.062 / 16.183 / 16.346 / 16.458 / 16.570 / 16.667 / 16.813 / 16.896 / 16.987 / 17.134 / 17.231 / 17.310 /

17.450 / 17.528 / 17.642 / 17.765 / 17.957 / 18.048 / 18.140 / 18.222 / 18.289 / 18.436 / 18.589 /

18.722 / 18.914 / 18.981 / 19.082 / 19.197 / 19.332 / 19.465 / 19.623 / 19.673 / 19.783 / 19.850 / 19.928 / 19.997 / 20.067 / 20.181 / 20.252 / 20.368 / 20.446 / 20.500 / 20.633 / 20.762 / 20.792 / 20.873 / 21.032 / 21.137 / 21.213 / 21.310 / 21.411 / 21.473 / 21.528 / 21.626 / 21.725 / 21.801 / 21.880 / 21.970 / 22.051 / 22.098 / 22.215 / 22.368 / 22.429 / 22.605 / Octacosane (C28) 22.722 / 22.823 / 22.885 / 22.945 / 22.995 / 23.073 /

23.221 / 23.292 / 23.353 / 23.417 / 23.532 / 23.600 / 23.660 /

23.821 / 23.896 / 23.952 / 24.047 / 24.180 / 24.301 /

24.406 / 24.591 / 24.643 / 24.750 / 24.810 / 24.881 / 24.977 / 25.158 / 25.337 / 25.421 / 25.573 / 25.745 / 25.809 / 25.959 / 26.054 / 26.221 / 26.392 / 26.509 / 26.605 / 26.710 / 26.802 / 26.946 / 27.105 / 27.178 / 27.281 / 27.449 / 27.533 / 27.670 / 27.787 / 28.002 / 28.136 / 28.277 / 28.724 / 29.009 / 29.145 / 29.457 / 29.673 / 29.860 /

### Company

.................... ZENERGY 

### Lab Number

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

Ͳ 10330 Study Number.............. CR

Ͳ 4 Date Sampled

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

Ͳ 15

Ͳ 2010 Date Tested................. 7

Ͳ 23

Ͳ 2010

S l Id tifi ti PENNINGTON 16 15 H CRUDE OIL 

## EXTENDED HYDROCARBON (GLYCALC) LIQUID STUDY

Samp l e I d enti f ication

.................... PENNIN G T O N 16-15 H C RUDE O IL



### Sample Location .......... MONTANA. Sample Pressure ......... 75 PSIG Sample Temperature...... 100 F Type Sample ............... SPOT County........................ MONTRAIL Test method ................ 

### GPA

Ͳ 2286 Sampling Method........ YZ PISTON

Components Mole % Weight % Liq. Vol. % Hydrogen Sulfide

.......... 0.012 0.003 0.003 

### Oxygen

...................... 0.000 0.000 0.000 

### Carbon Dioxide

............ 0.013 0.004 0.004 

### Nitrogen

..................... 0.004 0.001 0.001 

### Methane 0 270 0 032 0 078



### ..................... . . . 

### Ethane

....................... 2.018 0.448 0.920 

### Propane

..................... 5.113 1.663 2.400 

### iso

Ͳ Butane

.................. 0.980 0.420 0.546



### n

Ͳ Butane

.................... 4.432 1.900 2.381 

### iso

Ͳ Pentane

................ 1.409 0.750 0.878



### n

Ͳ Pentane

................... 2.562 1.364 1.582 

### H 2 488 1 582 1 743 

### exanes

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

### Heptanes

.................... 11.732 8.673 9.222 

### Octanes

..................... 22.998 19.381 20.074 

### Nonanes

..................... 13.316 12.600 12.767 

### Decanes+

................... 28.387 48.236 44.369 

### Benzene...................... 0.078 0.045 0.037 

### Toluene....................... 0.204 0.139 0.116 

### Ethylbenzene............... 0.107 0.084 0.070 

### Xylenes....................... 0.573 0.449 0.379



### n

Ͳ Hexane

.................... 2.688 1.709 1.883 

### 2,2,4

Ͳ Trimethylpentane... 0.616 0.519 0.545 

### TOTALS

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



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

### 1.398 0.889 0.979 3-Methylpentane 

### 1 090 0 693 0 764 3

- Methylpentane



### . . . n-Hexane 

### 2.688 1.709 1.883 2,2,4-Trimethylpentane 

### 0.616 0.519 0.545
Benzene 

### 0.078 0.045 0.037
Toluene 

### 0.204 0.139 0.116 Ethylbenzene 

### 0.107 0.084 0.070 m-Xylene 

### 0.067 0.053 0.045 p-Xylene 

### 0.386 0.302 0.255 o-Xylene 

### 0.120 0.094 0.079

API GRAVITY AT 60/60 F, calculated........................................................................ 61.9 SPECIFIC GRAVITY AT 60/60 F, calculated.............................................................. 0.7318 RELATIVE SPECIFIC GRAVITY OF DECANES+ (C10+) FRACTION ............................... 0.7956 AVERAGE MOLECULAR WEIGHT .......................................................................... 135.548 AVERAGE MOLECULAR WEIGHT OF DECANES+ (C10+) FRACTION .......................... 230.327 TRUE VAPOR PRESSURE AT 100 F PSIA calculated 43 649 TRUE VAPOR PRESSURE AT 100 F
, PSIA
, calculated

................................................ . AVERAGE BOILING POINT, F, ................................................................................ 283.928 CUBIC FEET OF GAS / GALLON OF LIQUID, as Ideal Gas .......................................... 19.480 BTU / GALLON OF LIQUID AT 14.73 PSIA, calculated ................................................. 121815.044 LBS / GALLON OF LIQUID, calculated ...................................................................... 6.102

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-4B Date Sampled............. 7-15-2010 Date Tested.............. 7-22-2010

Sample Identification................ PENNINGTON 16-15 H CRUDE OIL

Sample Location......... MONTANA. Sample Pressure.......... N/A Sample Temperature.... N/A
Flowrate................... N/A County..................... MONTRAIL

Test Method.............. VARIOUS Sample Container........ 1-QUART BOTTLE

TEST PERFORMED RESULTS

A PI GRAVITY AT 60/60 F (ASTM D-287), observed...................... 41.8 

### / ( ),

SPECIFIC GRAVITY AT 60/60 F (ASTM D-1657), calculated.......... 0.8165



### REID VAPOR PRESSURE (ASTM D-323), PSIG AT 100 F.............. 7.8 PSIG



### TOTAL SULFUR CONTENT (ASTM D-5453), PPMW.................. 1,435.60 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).

### Report(Report Editor)

Chromatogram Pennington 16-15H C:\GCsolution\DRO\DRO Data\08-2010\08-01-2010\Pennington 16-15H.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

1.054 / 1.137 / 1.405 /

1.552 / 1.669 / 1.730 / 1.901 / 2.039 / 2.109 / 2.281 / 2.362 / 2.418 / 2.564 / 2.667 / 2.854 / 2.949 / 3.035 / 3.135 /

3.210 / 3.301 / 3.421 / 3.539 / 3.637 / 3.740 / 3.857 / 3.967 / 4.069 / 4.148 / 4.334 / 4.509 / 4.583 / 4.693 / 4.901 / 5.022 / 5.166 / 5.365 / 5.512 / 5.609 / Decane (C10) 5.819 / 5.949 / 6.070 / 6.136 / 6.191 / 6.292 / 6.395 / 6.466 / 6.659 / 6.714 / 6.779 / 6.905 / 7.083 / 7.154 /

7.221 /

7.325 / 7.457 / 7.560 / 7.634 / 7.745 / 7.833 / 7.907 /

7.967 / 8.057 / 8.184 / 8.270 / 8.327 / 8.452 / 8.541 / 8.633 / 8.743 / 8.809 / 8.999 / 9.128 /

9.270 / 9.380 / 9.467 / 9.529 /

9.595 / 9.724 / 9.863 / 9.941 / 10.053 / 10.147 / 10.259 / 10.331 / 10.427 /

10.487 / 10.570 / 10.638 / 10.768 /

10.828 / 10.912 / 11.059 / 11.222 / 11.265 / 11.470 / 11.614 / 11.786 / 12.030 / 12.130 / 12.186 / 12.300 / 12.416 / 12.469 / 12.604 / 12.703 / 12.823 / 13.006 / 13.087 / 13.304 / 13.372 / 13.447 / 13.583 / 13.673 / 13.730 / 13.932 / 14.090 / 14.147 / 14.322 / 14.440 /

14.518 / 14.594 / 14.692 / 14.776 / 14.903 / 15.041 / 15.131 / 15.243 / 15.302 /

15.370 / 15.432 / 15.570 / 15.626 / 15.788 /

15.885 / 15.948 / o-terphenyl 16.044 / 16.183 / 16.344 / 16.460 / 16.573 / 16.674 / 16.814 / 16.895 / 16.970 / 17.137 / 17.329 /

17.446 / 17.535 / 17.643 / 17.802 / 17.961 / 18.057 / 18.128 / 18.224 / 18.286 / 18.435 / 18.595 / 18.722 / 18.918 / 18.983 / 19.078 / 19.197 / 19.331 / 19.480 / 19.598 / 19.651 / 19.702 / 19.783 / 19.851 / 19.927 / 20.074 / 20.181 / 20.361 / 20.440 / 20.517 / 20.634 / 20.795 / 20.874 / 21.027 / 21.136 / 21.309 / 21.400 / 21.541 / 21.724 / 21.789 / 21.888 / 21.969 / 22.076 / 22.183 / 22.375 / 22.436 /

22.605 / Octacosane (C28) 22.719 / 22.799 / 22.998 / 23.056 / 23.106 /

23.220 / 23.422 / 23.502 / 23.624 / 23.677 /

23.815 / 23.917 / 23.968 / 24.038 / 24.175 / 24.300 /

24.404 / 24.615 / 24.704 / 24.762 / 24.824 / 24.896 / 24.973 / 25.070 / 25.139 / 25.197 / 25.259 / 25.329 / 25.454 / 25.573 / 25.720 / 25.795 / 25.869 / 25.956 / 26.069 / 26.222 / 26.421 / 26.547 / 26.638 / 26.744 / 26.842 / 26.947 / 27.166 / 27.295 / 27.437 / 27.581 / 27.764 / 27.902 / 28.049 / 28.197 / 28.360 / 28.528 /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.

i 

## i



# -. @

1
r j

..**---Q~-,--** ------------

LEHE5329-03 

### 5 Wiring Descriptions 1. 800 amp main breaker 240V with 24V shunt trip 2. 400 amp main 480V with 24V shunt trip 3. 50 amp 240V branch breaker 4. 20 amp 240V branch breaker 5. 20 amp 120V branch breaker 6. 15 amp 120V branch breaker 7. 50 amp 240V twistlock receptacle 8. 20 amp 240V twistlock receptacle 9. 20 amp 120V twistlock receptacle (2x) 10. 20 amp 120V ground fault interrupter, (2x) 11. 15 amp 120V ground fault interrupter, duplex receptacle (2x) 12. 30 amp 120V battery charger/generator space heater receptacle 13. 30 amp 120V JWH receptacle 14. Remote start/stop contacts 15. 12.7 mm ('WI) 

### ground stud 16. Dual voltage load connection bus board [6.35 mm 

## x 101.6 mm 

## x 101.6 mm (%" 

## x 4" x 4") bus bars]

# RENTAL

CONTAINER DIMENSIONS

- TOP VIEW

. 901.3 [35.49] 272.8 [10.74]-+----t---1

2540.0 [100.00]

# C~TERPILLAR@

1-----------6239.7 [245.66]-------------l



## CONTAINER DIMENSIONS

- RIGHT SIDE VIEW

1---------6239.7 [245.66]----------1

J-------4675.6 [184.08)----- 1386.7 [54.60)

J------4361.6 [171.72)------i

12383.7 [93.84]

2240.4**2303.8[88.20~** 825.0 2865.1901.70) [71.85] [112.81]**t-I-hrJ:."...l~===n==!~:--T"ir-+:~~~** "'''---LL.-k'/

415.4 [16.35]

Overall Dimensions Package With Trailer Length 4597.4 mm 181 in 6248.3 mm 246 in Width 1498.6 mm 59in 2540.0 mm 100in Height 2387.6 mm 94in 2882.8 mm 113.5 in

LEHE5329-03 

### 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.

Hom.Oltil;:e: H5801338·S41i18 FAX 1-(5801 331-allaS P.O. BOll U08.**Gt.I~",on,** OkJahom. 73942 Admllll.lt.U

.... Office: 1-(405) 928-7313 FAX '.(405) i2a·1S110 P.O. 81)Jl 722110. Norman, Oklahoma 73070

# • 

# \ , 48" DIA 

### x 302 

### SI8'" HEIGHT, 88 ORIFICES EMISSION CONTROL DEVICE

• >98% TVOC ORE, CERTIAED lJS8>A 40 

# em 60, APPENDIX 

### A. SOURCE EMMISIONS TEST METHODS REfERENCED. MEETS ALl. EPA & 

### IDPHE REGUlATIONS.

.. DESTROYS OIL/CONDENSATE PRODUCTION TANK VAPOO$ WI NO VISIBlE R..AME •

• EXCELLENT OPAOTY AND SMOKElESS 

### OPERATION

.

.. RELlABlf AND CUSTOMIZABtE IGNITION

.

.. VERY lO'N CAPITAl AND OPERATING COST.

• EASV TO OPERATE AND MAlNTAIN.

• Will DESTROY UP TO ISO MCFD@ 100llIn' 

# o**~-,** 

# - _k CIMARRON**~-,** 

# -

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...... I 

# BL-__

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

# A **TTACHMENT H: PROCESS FLOW DIAGRAM OF F**  **A CILITY** 

### TYPICAL VAN HOOK AREA **SIX WELL PAD FACILITY PLOT PLAN Dakota-3 E&P Company, LLC**  **FBIR, North Dakota**

**NOT TO SCALE**

12’d x 20’h 400 bbl Prod. H2O **Recycle Pump**  **Chemicals**

**(6)Wellheads**

**Tank Vent line**

Utility Flare **Gas to sales Gas Meter** 

12’d x 20’h 400 bbl Prod. H2O 12’d x 20’h 400 bbl Prod. H2O 12’d x 20’h 400 bbl Prod. H2O 12’d x 20’h 400 bbl Prod. H2O 12’d x 20’h 400 bbl Prod. H2O Enclosed Combustor

**Recycle Pump**  **Recycle Pump**  **Recycle Pump** 

**Recycle Pump**  12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil **Valve Valve** 

**Valve**

**Valve Valve** 

**Valve**

**Recycle Line** 6’d x 20’h vertical treater Separator 30” d by 10’ h

6’d x 20’h vertical treater Separator 30” d b y 10’ h

6’d x 20’h vertical treater Separator 30” d b y 10’ h

6’d x 20’h vertical treater Separator 30” d b y 10’ h

6’d x 20’h vertical treater Separator 30” d b y 10’ h

6’d x 20’h vertical treater Separator 30” d b y 10’ h Gas Meter **(6) Gensets Genset** 

12’d x 20’h 400 bbl oil
12’d x 20’h 400 bbl oil
12’d x 20’h 400 bbl oil
12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil

12’d x 20’h 400 bbl oil 12’d x 20’h 400 bbl oil 24 bbl Diesel

**Oil Getty Box**

**Water Getty Box Recycle**  **Pump** 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 

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

# A **TTACHMENT J: DIESEL TANK EPA TANKS 4.09D E**  **M ISSIONS 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 

## TA NKS 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 

## TA NKS 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 

## TA NKS 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