...

~~

- . BISON

ENGINEERING, INC.

September 29, 2011

Ms. Kathleen Paser

EPA Region 8 Tribal Air Coordinator

U.S. EPA, Region 8

1595 Wynkoop Avenue, 8P-AR

Denver, CO 80202-1129

140011''' AVENUE' HELENA, MT 59601 • 406-442-5768

FAX: 406-449-6653 • E-MAil: bison@bison-eng.com • www,bison-eng.com

Duplicate submittal provided via

e-mail to: paser.kathleen@epa.gov

RE: Synthetic Minor Permit Application for the FBIR Smith Pad

Dear Ms. Paser:

Bison Engineering, Inc. (Bison), as contracted by XTO Energy, Inc. (XTO), is submitting

a Synthetic Minor Permit Application for the Smith Pad. This application is being

submitted in accordance with the requirements of the August 29, 2011 Consent

Agreement, regarding compliance with the Federal Minor New Source Review Rule.

If the Agency has any questions or concerns, please contact me (406.442.5768 or

bret@bison-eng.com). I will be pleased to assist you.

Sincerely,

BISON ENGINEERING, INC.

Bret Gallo

Project Engineer

Attachment

cc: John McMichael, XTO Energy, Inc.

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

Town, NO 58763-9404

Tex hall,- Chairman Three Affiliated Tribes, 404Frontage Road, New Town, NO

58763-9404

(Letter Only)

Bison File XT0211339

An Employee Owned Company
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 

 Proposed Construction of New Equipment at an Existing Facility 

 Proposed Modification of an Existing Facility 

 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 

 XTO Energy, Inc. 

 (b) Operator Name 

 XTO Energy, Inc 

2. Facility Name

 FBIR Smith 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: 

 810 Houston St. Ft Worth, TX 76102 (main office) 

9. Reservation* 

 FBIR 

10. County* 

 Dunn 

11a. Latitude* 

 47° 44' 43.192" N 

11b. Longitude* 

 102° 26' 49.25" W 

12a. Quarter Quarter Section* 

 NWNW 

12b. Section* 

 10 

12c. Township* 

 149N 

12d. Range* 

 92W 
B. PREVIOUS PERMIT ACTIONS (Provide information in this format for each permit that has 

been issued to this facility. Provide as an attachment if additional space is necessary) 

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

no previous permit actions have been taken. 

Facility Name on the Permit N/A 

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

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

Company Contact: John McMichael Title: 

Environmental Engineer 

Mailing Address: 810 Houston St. Ft Worth, TX 76102

Email Address: John_McMichael@xtoenergy.com 

Telephone Number: (817) 885-3782 Facsimile Number: (817) 885-2683

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

Mailing Address

Email Address 

Telephone Number Facsimile Number

Facility Contact: Ray Kordonowy Title: Sr. Production Foreman 

Mailing Address: 35399 HWY 23 Sidney, MT 59270

Email Address 

Telephone Number: 406-48206802 Facsimile Number

Compliance Contact: John McMichael Title: Environmental Engineer 

Mailing Address: 810 Houston St. Ft Worth, TX 76102

Email Address: John_McMichael@xtoenergy.com 

Telephone Number: (817) 885-3782 Facsimile Number: (817) 885-2683
D. ATTACHMENTS 

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

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

being requested. 

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

the process flow diagram to be submitted with this application. 

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

equipment. 

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

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

maximum hourly basis. 

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

maximum hourly basis. 

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

weeks per year. 

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

for each emission unit and air pollution generating activity. 

 Criteria Pollutant Emissions - Estimates of Current Actual Emissions, Current Allowable Emissions, PostChange Uncontrolled Emissions, and Post-Change Allowable Emissions for the following air pollutants: 

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

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

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

calculations for the estimates. 

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

total. 

 Modeling – Air Quality Impact Analysis (AQIA) 

 ESA (Endangered Species Act) 

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

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

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

E(i) – Proposed New Facility

Pollutant Potential Emissions 

 (tpy) 

Proposed Allowable 

Emissions 

 (tpy) 

PM - Particulate Matter 

PM10 - Particulate Matter less 

than 10 microns in size 

PM2.5 - Particulate Matter less 

than 2.5 microns in size 

SOx - Sulfur Oxides 

NOx - Nitrogen Oxides 

CO - Carbon Monoxide 

VOC - Volatile Organic 

Compound 

Pb - Lead and lead compounds 

Fluorides - Gaseous and 

particulates 

H2SO4 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur 

Compounds

PM 5.59 5.84 

PM10 5.59 5.84 

PM 2.5 5.59 5.84 

SOx 0.01 0.01 

NOx 87.68 92.13 

CO 189.44 213.61 

VOC 10200.51 177.40 

Pb Negligible Negligible 

Fluorides Negligible Negligible 

H2SO4 Negligible Negligible 

H2S Negligible Negligible 

TRS Negligible Negligible 

RSC Negligible Negligible 

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

sources, pursuant to CAA Section 302(j): 

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

(b) Kraft pulp mills; 

(c) Portland cement plants; 

(d) Primary zinc smelters; 

(e) Iron and steel mills; 

(f) Primary aluminum ore reduction plants; 

(g) Primary copper smelters; 

(h) Municipal incinerators capable of charging more than 

250 tons of refuse per day; 

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

(j) Petroleum refineries; 

(k) Lime plants; 

(l) Phosphate rock processing plants; 

(m) Coke oven batteries; 

(n) Sulfur recovery plants; 

(o) Carbon black plants (furnace process); 

(p) Primary lead smelters; 

(q) Fuel conversion plants; 

(r) Sintering plants; 

(s) Secondary metal production plants; 

(t) Chemical process plants 

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

more than 250 million British thermal units per hour 

heat input; 

(v) Petroleum storage and transfer units with a total 

storage capacity exceeding 300,000 barrels; 

(w) Taconite ore processing plants; 

(x) Glass fiber processing plants; 

(y) Charcoal production plants; 

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

250 million British thermal units per hour heat input, 

and 

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

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

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

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

Pollutant Current 

Actual 

Emissions 

(tpy) 

Current 

Allowable 

Emissions 

(tpy) 

Post-Change 

Potential 

Emissions 

(tpy) 

Post-Change 

Allowable 

Emissions 

(tpy) 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

PM - Particulate Matter 

PM10 - Particulate Matter less than 10 microns in size 

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

SOx - Sulfur Oxides 

NOx - Nitrogen Oxides 

CO - Carbon Monoxide 

VOC - Volatile Organic Compound 

Pb - Lead and lead compounds 

NH3 - Ammonia 

Fluorides - Gaseous and particulates 

H2SO4 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur Compounds 
Page 7 of 15 

Instructions 

Use of This Form 

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

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

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

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

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

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

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

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

The following exemptions apply: 

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

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

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

other permit condition that is enforceable as a practical matter. 

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

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

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

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

unit’s potential to emit. 

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

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

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

stringent of the following: 

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

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

compliance date; or 

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

a future compliance date. 

 
Page 8 of 15 

A. General Facility Information 

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

corporations, include divisions or subsidiary name, if any. 

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

contain one or more air pollution emitting units. 

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

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

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

include asphalt batch plants and concrete batch plants. 

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

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

 

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

found at the following link  North American Industry Classification System

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

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

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

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

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

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

Include the State and the ZIP Code. 

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

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

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

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

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

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

B. Current Permit Information 

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

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

permit number must be included with each permit identified. 

C. Contact Information 

Please provide the information requested in full.

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

contact. 

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

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

information. 

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

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

D. Attachments 

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

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

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

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

 FORM SYNMIN

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

SYNMIN be included with this application. 

 Narrative description of the proposed production processes. 

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

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

proposed facility and how it will be operated. For example: 

What are the raw materials? 

What are the properties of the raw materials? 

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

How will the raw materials be affected by this process? 

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

Etc.... 

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

and weeks per year. 

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

material should be described in enough detail to indicate its basic chemical 

components. 
Page 10 of 15 

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

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

narrative description requested above. 

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

minimum, provide the following: 

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

production process, and activity. 

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

equipment. 

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

of material in the storage units. 

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

throughput of material and product. 

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

of material and product.

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

maximum hourly basis. 

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

and maximum hourly basis. 

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

weeks per year. 

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

monitoring for each emission unit and air pollution generating activity. 

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

Criteria Pollutant Emissions Estimates 

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

Emissions, and Post-Change Allowable Emissions for the following air pollutants: particulate 

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

organic compound (VOC), lead (Pb) and lead compounds, ammonia (NH3), fluorides (gaseous and 

particulate), sulfuric acid mist (H2SO4), hydrogen sulfide (H2S), total reduced sulfur (TRS) and 

reduced sulfur compounds, including all calculations for the estimates. 

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

to total emissions. 

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

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

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

as well as annual (tons per year) units. 

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

using currently accepted engineering criteria. The following procedures are generally 

acceptable for estimating emissions from air pollution sources: 

• Source-specific emission tests; 

• Mass balance calculations; 

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

specifications) 

• Other engineering calculations; or 

• Other procedures to estimate emissions specifically approved by the Regional 

Administrator. 

4. Guidance for estimating emissions can be found at 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

number of pounds in a ton). 

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

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

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

practical matter on the unit’s PTE. 

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

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

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

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

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

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

emissions. 

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

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

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

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

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

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

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

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

is the number of pounds in a ton). 

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

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

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

emissions may be proposed. 

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

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

proposed change would be the sum of following: 

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

potential to emit of each unit. 

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

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

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

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

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

calculation.

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

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

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

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

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

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

 Modeling Analysis 

Do I need to do a modeling analysis? 

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

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

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

Prevention of Significant Deterioration (PSD) increment violation. 

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

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

issued. 

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

proposed activities that meet the following criteria perform an AQIA: 

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

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

accurate assessment of the environmental impact of the activities proposed. 

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

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

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

circumstances such as: 

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

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

proximity to ambient air at the site boundary; 

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

height in close proximity to the source); or 

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

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

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

Gail Tonnesen 

Region 8 Modeling Lead 

Tonnesen.gail@epa.gov

303-312- 6113 
Page 14 of 15 

What Kind of Air Quality Modeling Analysis Is Needed? 

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

follows: 

Step 1: Qualitative Air Quality Assessment 

Step 2: Screening Modeling Analysis 

Step 3: Preliminary Modeling Analysis (refined modeling) 

Step 4: Full Impact Modeling Analysis (refined modeling) 

Step 5: PSD Increment and NAAQS Analysis

Step 6: Additional Impact Analysis 

2. Step 1: Qualitative Air Quality Assessment 

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

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

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

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

expected, a screening analysis should next be performed. 

3. Step 2: Screening Analysis 

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

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

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

download at the EPA SCRAM website: 

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

not necessary prior to conducting a Screening Analysis. 

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

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

further modeling is necessary. 

Significant Impact Levels 

Pollutant Averaging Period Class II Area SIL 

(ug/m3) 

Class I Area SIL 

(ug/m3) 

SO2

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

3 hr 25 1.0 

24 hr 5 0.2 

Annual 1 0.08 

PM2.5

24 hr 0.07 1.2 

Annual 0.06 0.3 

PM10

24 hr 5 0.2 

Annual 1 0.08 

NO2

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

Annual 1 0.08 

CO 1 hr 2,000 ppb 

8 hr 500 ppb 

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

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

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

6 should be performed based an approved protocol.

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

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

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

1. Approved Modeling Protocol 

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

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

been approved. 

2. Modeling Results 

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

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

be provided to EPA Region 8. 

 ESA 

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

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

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

designated critical habitat of such species. 

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

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

website has been provided to assist you: 

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

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

 NHPA 

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

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

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

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

website has been provided to assist you: 

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

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

Region 8 Air Program 

FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY 

Checklist - Synthetic Minor Limit Request 

(Form SYNMIN) 

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

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

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

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

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

completed. 

Please submit information to following two entities: 

Federal Minor NSR Permit Coordinator 

U.S. EPA, Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

The Tribal Environmental Contact for the specific reservation: 

If you need assistance in identifying the appropriate Tribal 

Environmental Contact and address, please contact the EPA 

Region 8 Tribal Air Coordinator: 

Alexis North, EPA Region 8 Tribal Air Coordinator 

303-312-7005 

north.alexis@epa.gov

A. GENERAL INFORMATION 

Company Name 

XTO Energy, Inc. 

Facility Name 

FBIR Smith Pad 

Company Contact or Owner Name 

John McMichael 

Title 

Environmental Engineer 

Mailing Address 

810 Houston St. Ft Worth, TX 76102

Email Address 

John_McMichael@xtoenergy.com 

Telephone Number 

(817) 885-3782

Facsimile Number 

(817) 885-2683 

B. ATTACHMENTS 

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

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

emit. 

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

and assure compliance with the proposed limitation.

 Item 3 - A description of estimated efficiency of air pollution control equipment under present or anticipated 

operating conditions, including documentation of the manufacturer specifications and guarantees. 

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

limitation, including all calculations for the estimates. 

 Item 5 – Estimates of the potential emissions of Greenhouse Gas (GHG) pollutants before and after proposed 

emission controls. 
Page 2 of 4 

Instructions 

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

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

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

Tribal lands. 

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

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

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

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

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

does not affect how the rule applies. 

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

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

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

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

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

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

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

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

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

requirements. 

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

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

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

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

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

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

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

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

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

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

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

standards that would otherwise apply to the source. 

3. Section B. ATTACHMENTS 

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

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

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

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

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

be addressed by this section of the application form. 

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

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

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

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

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

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

effect. 

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

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

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

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

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

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

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

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

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

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

guarantees for each control device. 

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

using currently accepted engineering criteria. The following procedures are generally 

acceptable for estimating emissions from air pollution sources: 

(i) Source-specific emission tests; 

(ii) Mass balance calculations; 

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

specifications). 

(iv) Other engineering calculations; or 

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

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

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

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

the number of pounds in a ton). 

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

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

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

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

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

avoid PSD must take into account greenhouse gases. 

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

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

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

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

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

1. Carbon dioxide (CO2) 

2. Methane (CH4) and its CO2e 

3. Nitrous oxide (N2O) and its CO2e 

4. Hydrofluorocarbons (HFCs) and its CO2e 

5. Perfluorocarbons (PFCs) and its CO2e 

6. Sulfur hexafluoride (SF6) and its CO2e 
XTO Energy, Inc.

NSR Synthetic Minor Permit Application 

XTO211339 

FBIR SMITH PAD ATTACHMENTS: 

Attachment A: Application Report 

Attachment B: Emission Inventory Spreadsheets 

Attachment C: Representative Gas Analysis 

Attachment D: Engine Manufacturer’s Specs 

Attachment E: NSCR Control Manufacturer’s Specs 

Attachment F: Enclosed Combustor Manufacturer’s Specs 

Attachment G: Process Flow Diagram of Facility 

Attachment H: Production Decline Curve Calculations (Confidential) 

Attachment I: Diesel Tank EPA TANKS 4.09d Emissions Summary 
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT A: APPLICATION REPORT 
APPLICATION FOR AN NSR 

SYNTHETIC MINOR 

AIR QUALITY PERMIT 

FBIR SMITH PAD 

OIL & GAS 

PRODUCTION FACILITY 

Prepared for: 

XTO Energy, Inc. 

810 Houston Street 

Fort Worth, TX 76102 

Prepared by: 

Bison Engineering, Inc. 

1400 11th Avenue 

Helena, MT 59601 

(406) 442-5768 

www.bison-eng.com 

September 29, 2011
FBIR Smith Pad 09/29/11 pg. ii 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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 Wellhead Gas Emissions ............................................... 9 

 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 Produced Casing Wellhead Gas .............................................................. 10 

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

5.0 ALLOWABLE EMISSIONS ................................................................................. 12 

 5.1 Storage Tank Emissions .......................................................................... 12 

 5.2 Produced Casing Head Gas Emissions ................................................... 12 

 5.3 RICE Engine Emissions ........................................................................... 12 

 5.4 Natural Gas External Combustion Unit Emissions ................................... 12 

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

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

 5.7 Diesel Storage Tank Emissions ............................................................... 13 

6.0 PROPOSED MONITORING AND RECORDKEEPING ...................................... 14

 6.1 Production Storage Tanks ....................................................................... 14 

 6.2 Production Storage Tank Emissions Control Device ............................... 15 

 6.3 Produced Casing Head Gas Emergency Utility Flare .............................. 17 

 6.4 RICE Engines .......................................................................................... 18 

 6.5 Natural Gas-Fired External Combustion Units ......................................... 18 

 6.6 Truck Loading .......................................................................................... 19 

 6.7 Fugitive Equipment Leaks ........................................................................ 19 

 6.8 General Recordkeeping Requirements .................................................... 21 

7.0 QUALITATIVE AIR QUALITY ASSESSMENT .................................................... 22 

8.0 ENDANGERED SPECIES ACT .......................................................................... 23 

9.0 NATIONAL HISTORIC PRESERVATION ACT .................................................. 24 
FBIR Smith Pad 09/29/11 pg. iii 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

FIGURES 

Figure 1: Example of Maximum PTE from a Six Well Pad ........................................ 6 

Figure 2: Example of Actual Production from a Six Well Pad ................................... 7 

ATTACHMENTS 

Attachment A: Application Report 

Attachment B: Emission Inventory Spreadsheets 

Attachment C: Representative Gas Analysis 

Attachment D: Engine Manufacturer’s Specs 

Attachment E: NSCR Control Manufacturer’s Specs 

Attachment F: Enclosed Combustor Manufacturer’s Specs 

Attachment G: Process Flow Diagram of Facility 

Attachment H: Production Decline Curve Calculations (CONFIDENTIAL) 

Attachment I: Diesel Tank EPA TANKS 4.09d Emissions Summary 
FBIR Smith Pad 09/29/11 pg. 1 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

1.0 INTRODUCTION 

1.1. Summary 

XTO Energy, Inc. (XTO) 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. XTO executed 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 August 30, 2011, implementation date did not feasibly allow time for 

preparation, review and processing of applications and permits. 

Under the Consent Agreement, XTO 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). 

XTO is proposing to construct and operate the FBIR Smith 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 FBIR Smith Pad is proposed to be located in the northwest 1⁄4 of the northwest 1⁄4

Section 10 Township 149 North, Range 92 West, Dunn County, North Dakota. 

1.3. Site Description 

At the proposed FBIR Smith 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 Dunn County, North 

Dakota. The surrounding area is mainly used for agriculture and livestock grazing. The 

proposed pad’s associated well names are: 

1. FBIR Smith 11X-10-1 

2. FBIR Smith 11X-10-2 

3. FBIR Smith 11X-10-3 

4. FBIR Smith 11X-10-4 

5. FBIR Smith 11X-10-5 

6. FBIR Smith 11X-10-6 
FBIR Smith Pad 09/29/11 pg. 2 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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. 
FBIR Smith Pad 09/29/11 pg. 3 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

2.0 NARRATIVE DESCRIPTION 

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

FBIR Smith 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. 

One must note that the production rates used in this application are grossly 

overestimated when compared to the predicted production actual 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 could be up to several years’ difference in when the 

initial production from some of the wells begin. 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 likely begin 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 (0.5 MMBtu/hr each) 

24 - Oil Production Tanks 1 - Electric 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 - LACT Units 

3 - Manufactured Enclosed Tank Vapor Combustors 3 - Diesel Engines 

The oil/gas/water emulsion being produced from the wells is transported up each 

wellbore using an electric lifting unit, when required. 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 twophase 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 lineheater 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 vapors from the tanks may be recovered using a vapor recovery unit (VRU) and 

sent to the gas sales pipeline if the capacity of the sales line is large enough to take the 

vapors. However, there are three enclosed combustors to combust the tank vapors as 

backup to the VRU. If it is not feasible for a VRU to be installed and operated, the 

combustors serve as the primary tank vapor control.
FBIR Smith Pad 09/29/11 pg. 4 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

The produced casing head gas is transferred from the heater treaters and two-phase 

separators to the sales gas pipeline. An onsite utility flare serves as an emergency 

backup. The oil and water production tank’s working, standing, breathing, and flashing 

vapors are routed to an enclosed combustion device. The stored oil is typically 

transported for sale via the Lease Automated Custody Transfer (LACT) unit, with the 

truck loadout serving as an emergency backup if there was a malfunction with the oil 

pipeline. Produced water is stored in the onsite water storage tank until it is transported 

offsite using the water pipeline. 

At the facility, there is a small electric 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. The facility is completely electrified when 

possible; 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. 
FBIR Smith Pad 09/29/11 pg. 5 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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 H of the application. 

As noted in Section 2.0 above, determination of potential emissions from the proposed 

FBIR Smith 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 the actual 

emissions that could ever be emitted at the facility during any given twelve-month rolling 

average (represented in example Figure 2). 
FBIR Smith Pad 09/29/11 pg. 6 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

Figure 1: Example of Maximum PTE from a Six Well Pad 
FBIR Smith Pad 09/29/11 pg. 7 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

Figure 2: Example of Actual Production from a Six Well Pad 
FBIR Smith Pad 09/29/11 pg. 8 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

Potential emissions from this facility originate primarily from the heater treater’s 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), the default Bakken Pool emission factors were used from the 

North Dakota Department of Health’s (NDDoH) “Bakken Pool Oil and Gas Production 

Facilities Air Pollution Control Permitting & Compliance Guidance 

(http://www.ndhealth.gov/AQ/OilAndGasWells_files/New%20Guidance%20O&G%20Fil

es/20110502Oil%20%20Gas%20Permitting%20Guidance.pdf). As stated on page 6 of 

the guidance document: 

“Use of the Bakken default values to calculate VOC emissions is expected to result 

in a conservatively high estimate of VOC emissions..........In the vast majority of 

cases, the use of site-specific data instead of the Bakken default values is 

expected to result in lower calculated VOC emissions.”

XTO is aware of the likelihood of overestimating the emissions associated with the 

facility due to using the Bakken Pool emission factors. However; due to the short 

timeframe to submit the synthetic minor permit application for the facility, XTO feels this 

approach will conservatively overestimate the facility emissions until site-specific or 

representative data can be sampled and analyzed to estimate emissions. All applicable 

uncontrolled and controlled emissions from the storage tanks calculations are included 

in Attachment B.
FBIR Smith Pad 09/29/11 pg. 9 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

3.2 Produced Casing Wellhead Gas Emissions 

The casing head gas at this facility is sent to the gas sales pipeline; however, due to 

pipeline capacity issues, XTO is conservatively estimating the PTE assuming ALL of the 

produced gas is being sent to their onsite high capacity utility flare. Because the facility 

is connected to the gas sales pipeline, XTO is not required to estimate the PTE 

assuming the produced head gas emissions are being vented to the atmosphere. To 

calculate the flared combustions emissions, AP-42 factors for a representative field gas 

analysis were used. The utility flare will meet the requirements of 40 CFR 60.18; 

therefore, to estimate the potential to emit, XTO is allowed to assume 98% destruction 

efficiency. Again, this estimate is still very conservative because XTO will be selling 

much of their produced gas, even though all of it is assumed to be routed to the flare. 

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. 

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 500,000 Btu/hr. The emissions 

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

3.5 Truck Loading Emissions 

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

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

emergency or malfunction situations. 

3.6 Fugitive Emissions: Dust and Equipment Leaks 

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

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

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

to track 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. 
FBIR Smith Pad 09/29/11 pg. 10 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

4.0 EMISSIONS AND OPERATIONAL LIMITS REQUESTS 

XTO is requesting emissions and operational limits at the FBIR Smith Pad in order to 

obtain a synthetic minor status with regard to the NSR permitting programs. The 

federally enforceable permit conditions will allow XTO 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, XTO will 

limit the storage tank VOC and HAP emissions by installing an enclosed smokeless 

combustion device that meets the requirements of 40 CFR 60.18. The control device 

XTO is installing at this facility has a guaranteed 99% control efficiency; therefore, XTO 

is allowed to apply 99%, rather than 98%, to the uncontrolled PTE. On this basis, the 

requested emission limit from the storage tanks is: 177.40 tons per year of VOCs and 

4.92 tons per year of HAPs. 

4.2 Produced Casing Wellhead Gas 

Although XTO is connected to the gas sales pipeline, XTO is assuming that all 

emissions associated with the produced casing wellhead gas are being flared to the 

utility flare. Only under emergency or malfunction situations with the pipeline would all of 

the produced gas be sent to the utility flare. Furthermore, as previously stated, the 

application assumes all six of the wells are put into production simultaneously, which is 

not realistic. Due to these two factors, the actual gas production at the facility would 

most likely not reach the estimated conservative amount routed to the utility flare. XTO 

would like to note that, although CO emissions associated with the combustion of the 

overestimated flared gas are estimated to be ~173 tons per year, this level is unlikely to 

be reached. As more capacity in the sales pipeline occurs, more produced gas will be 

sold, ultimately achieving 100% sales, unless there is a pipeline malfunction. Therefore, 

no emission limit is being requested from the produced casing wellhead gas emissions. 

4.3 Reciprocating Internal Combustion or Compression Ignition Engines 

XTO 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 ZZZZ or 40 CFR 60 Subparts IIII and 

JJJJ. XTO will be installing one genset per two wells at this facility for a total of three 

gensets. The engines are certified to meet the Tier 3 emission standards; however, 

XTO is also installing nonselective catalytic reduction (NSCR) systems on the engines 

that will reduce the CO emissions by approximately 70%. The NSCRs reduce the CO 
FBIR Smith Pad 09/29/11 pg. 11 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

emissions from the engines to 15.36 tons per year of CO. This reduction reduces the 

limits of the total allowable emissions for the facility to ~213 tons per year. In order to 

take credit for the reduction in emissions associated with the catalyst, XTO is requesting 

a permit condition requiring the use of the catalyst. In addition to the requirement for 

the catalyst, XTO will follow the manufacturer’s recommended maintenance schedule 

and follow the recordkeeping and recording requirements proposed in Section 6.4 of 

this report. 
FBIR Smith Pad 09/29/11 pg. 12 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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 99% control efficiency 

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

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

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

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

pollutant and greenhouse gas components from a representative gas analysis. 

5.2 Produced Casing Head Gas Emissions 

No limits have been requested for the casing wellhead gas utility flare emissions at the 

facility; therefore, the emissions estimate is equal to the uncontrolled potential to emit. 

5.3 RICE Engine Emissions 

No limits have been requested for the RICE at the facility. XTO 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 unless otherwise specified by rule or regulation. 

5.4 Natural Gas External Combustion Unit Emissions 

No limits have been requested for the natural gas external combustion units at the 

facility; therefore, the emissions estimate is equal to the uncontrolled potential to emit. 

5.5 Truck Loading Emissions 

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

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

emergency or malfunction situations if the oil pipeline is not operational. 

5.6 Fugitive Emissions: Dust and Equipment Leaks 

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

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

emissions will be estimated after a final permit is issued in order to track the twelve-
FBIR Smith Pad 09/29/11 pg. 13 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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 on the location. 

5.7 Diesel Storage Tank Emissions 

There will be three onsite storage tanks at this facility to store diesel fuel that will be 

utilized in the diesel gensets. These tanks will be either horizontal or vertical 1,000 

gallon tanks. Emissions for these tanks 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 I. 
FBIR Smith Pad 09/29/11 pg. 14 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

6.0 PROPOSED MONITORING AND RECORDKEEPING 

According to the Application for Synthetic Minor Limit Request (Form SYNMIN), Page 1 

(B), ATTACHMENTS, Item, 2, XTO is proposing 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. In the 

alternative an emissions control device that achieves a minimum of 99% destruction 

efficiency may be used. XTO will follow the tank manufacturer’s recommended 

maintenance schedule and procedures to ensure optimum performance. Furthermore, 

XTO 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 to an emissions control device; and 

c. Quarterly observations 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: 

XTO 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. 
FBIR Smith Pad 09/29/11 pg. 15 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

Recordkeeping Requirements: 

Total VOC, total HAP, and any single HAP emissions 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, 

XTO 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, XTO 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. 

XTO 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 by 

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%. 

For each enclosed combustion device and utility flare, XTO will follow 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 the 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. 
FBIR Smith Pad 09/29/11 pg. 16 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

Monitoring Requirements: 

XTO has identified a manufacturer or vendor that guarantees the enclosed combustor 

will meet, at minimum, the 98.0% reduction requirement. XTO 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. A check of the chart recorder to ensure proper operation will be done whenever 

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

c. A check 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 provided for in 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 

through the independent engineering analysis or from the manufacturer or 

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

assure the, at minimum, 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 exceedances 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; 
FBIR Smith Pad 09/29/11 pg. 17 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

g. Records will be kept of any time periods in which visible emissions from an 

enclosed combustor or utility flare are observed; 

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 a chart recorder that indicates 

the continuous ignition of the pilot flame; 

j. A check of the chart recorder 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 provided for in 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. 

For each enclosed combustion device and utility flare, XTO will follow 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 

XTO 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, XTO will record the volume of gas sent to the emergency utility flare. 

During an emergency or malfunction XTO 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%. 

XTO will follow 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. 

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. 
FBIR Smith Pad 09/29/11 pg. 18 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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

efficiency for the 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, XTO is required to meet the 

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

ZZZZ. XTO will properly operate and maintain the engines per the manufacturer’s 

specifications to ensure compliance with the above standards. If the engines emissions 

are not certified to meet the required standards, XTO will have performance tests 

performed on the engines as required by the applicable subparts. XTO will also operate 

and maintain the NSCRs to the manufacturer’s specification to ensure maximum 

performance of the control devices. 

6.5 Natural Gas-Fired External Combustion Units 

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

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

proposed by XTO. Furthermore, XTO would like to point out that the emissions 

associated with the line-heaters were estimated based on 8,760 hours of operation per 

year when, in reality, the heaters are not used that often due to the high temperature of 

the emulsion from the wells. 
FBIR Smith Pad 09/29/11 pg. 19 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

6.6 Truck Loading 

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

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

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

trucks will be loaded using submerged fill. 

6.7 Fugitive Equipment Leaks 

XTO 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, XTO 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. XTO 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 or inaccessible due to weather conditions. 

Such equipment will be repaired before the end of the first facility shutdown, after 

the leak is initially detected. XTO will make the first attempt to repair any leaking 

equipment within five days after the leak is detected. XTO will minimize leaks of 

volatile organics from each piece of equipment in hydrocarbon service at this 

facility. 

Monitoring Requirements: 

a. XTO will conduct leak detection monitoring on an quarterly 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. XTO 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 
FBIR Smith Pad 09/29/11 pg. 20 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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. 

Recordkeeping Requirements: 

a. XTO 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. 
FBIR Smith Pad 09/29/11 pg. 21 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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, XTO 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, XTO 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. 

XTO, 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 set-points, 

temperature monitoring, alarm notification, data logging, flowmeter monitoring, etc. 
FBIR Smith Pad 09/29/11 pg. 22 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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. 
FBIR Smith Pad 09/29/11 pg. 23 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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.
FBIR Smith Pad 09/29/11 pg. 24 

NSR Synthetic Minor Permit Application 

Project #: XTO211339

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. 

 
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT B: EMISSION INVENTORY 

SPREADSHEETS 
GREEN = Requires input

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

Facility Information

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-

3, 11X-10-4,11X-10-5, 11X-10-6 Name of the facility and the well number.

Unknown Approximate first date of production or the date of modification of the facility.

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

Production Data Description

BOPD 3354 Average daily production in barrels of oil per day (BOPD), based on the predicted first 30 days of production.

Mscfd 3354 Average daily production of gas in Mscf per day, based on the predicted first 30 days of production.

Decline Factor 0.545 Expected decline factor for the first year of operation. Based on data from previsously producing wells in the same field and formation.

Adjusted BOPD 1827.93 This is the calculated BOPD expected to be produced using the above entered decline factor.

Adjusted Produced Gas (Mscfd) 1827.93 This is the calculated mcfd of gas the well is expected to produce using the above entered decline factor.

Oil/Condensate Tank Data Description

Flash Gas Method: Default Bakken EF Use the drop down menu to choose the appropriate flash gas method.

Bakken EF scf/bbl 97.91 The scf/bbl from direct measurement or representative sample. If specific data is not available, use the Bakken default of 97.91.

Estimated Tank Vapors (scfd) 178973 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 2000 Lower heating value (Btu/scf) of tank vapors. If site specific data is not available, use the Bakken default value of 2000.

Molecular Weight 45.19 Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole). If site specific data is not available, use the Bakken default value of 45.19.

VOC% 79.80% VOC weight fraction of the tank vapor gas (C3+). If site specific data is not available, use the Bakken default value of 79.8%.

HAP% 2.26% HAP weight fraction of the tank vapor gas. If site specific data is not available, use the Bakken default value of 2.26%.

CO2% 1.02% CO2 weight fraction of the tank vapor gas. (Assumed to be equal to the field gas data.)

CH4% 16.92% CH4 weight fraction of the tank vapor gas. (100%-VOC wt% -CO2 wt%)

H2S weight % 0.00% H2S weight percent of the tank vapor gas.

H2S mole % 0.00% H2S mole percent of the tank vapor gas.

Utility Flare or Other 98% DRE Device Use the drop down menu to choose the appropriate emission control type.

Control Destruction Efficiency 99% Control efficiency of any applicable controls. This is a fixed number based on control type. (Vendor Guarantee.)

XTO Energy, Inc.

Input Data
GREEN = Requires input

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

XTO Energy, Inc.

Input Data

Treater Gas Data Description

Btu/scf 1401.5 Btu/scf of wellstream gas. (From representative field gas analysis)

Molecular Weight 24.49 Average molecular weight of the wellstream gas in lb/lb-mole. (From representative field gas analysis)

Specific Gravity 0.8476 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 24.55 This is the calculated molecular weight based on the specific gravity entered above. Please enter this number on Line 21.

VOC% 32.88% VOC weight fraction of the wellstream gas (Note: Weight%, not Mole%). (From representative field gas analysis)

HAP% 0.02% HAP weight fraction of the wellstream gas. (Note: Weight%, not Mole%). (From representative field gas analysis)

CO2% 1.022% CO2 weight fraction of the wellstream gas. (Note: Weight%, not Mole%). (From representative field gas analysis)

CH4% 43.112% CH4 weight fraction of the wellstream gas. (Note: Weight%, not Mole%). (From representative field gas analysis)

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

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

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

Treater Burner(s) Description

Total Btu/hr 3000000 Total burner rating for the heater treater burner(s) in btu/hr. If there are multiple burners, add the total heat input together.

Hours of Operation 8,760 The burner(s) is/are assumed to operate 8,760 hours per year.

Truck Loading Description

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

Submerged loading: dedicated normal service 0.6 Use the drop down list to choose the appropriate mode of operation. The saturation factor will automatically be selected based on mode of operation.

Molecular Weight 45.19 Molecular weight of tank vapors in lb/lb-mole. Assumed same molecular weight as flashing emissions from representative E&P Tanks data.

Vapor Pressure 2.30 True vapor pressure of liquid loaded, pounds per square inch absolute (psia) If no site specific data is available, please refer to Table 2 on the Truck Loading tab.

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

Load Rate (bbl/hr) 180 Load rate of liquid loaded in barrels per hour.

Load Time (hrs) 1.00 The time it takes to loadout one load (hrs).

Pneumatic Pumps Description

Number of Pneumatic Pumps 0 Number of pneumatic pumps at facility.

Hours of Operation 0 Hours the pump is in operation annually. For winter months only, please enter 4380 hours.

scf/min 0.00 Pneumatic source consumption rate as per manufacturer data (scf/min).

Routed exhaust back into closed loop system Use the drop down menu to choose the appropriate emission control type.

Control Efficiency 100% Control efficiency of any applicable controls (combustor, routing exhaust to fuel supply, VRU, etc).

Pneumatic Controllers Description

Number of Pneumatic Controllers 0 Number of pneumatic controllers at facility.

Bleed rate (scf/hr) 0.00 Average bleed rate of device (scf/hr).

Glycol Dehydrator Description

VOC (TPY) 0.00 VOC emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).

HAP (TPY) 0.00 HAP emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).
Facility:

FBIR Smith Pad

Associated Wells: Smith 

11X-10-1, 11X-10-2, 11X-10-

3, 11X-10-4,11X-10-5, 11X10-6

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

Oil/Condensate Tanks 3107.82 37.23 N/A N/A N/A N/A N/A N/A N/A Negligible

Casing Head Gas 7088.13 206.08 31.79 2.54 2.54 2.54 172.99 NA 0.00 0.03

Treater Burner 0.07 0.02 1.29 0.10 0.10 0.10 1.08 N/A 0.01 Negligible

RICE Engine 4.49 2.01E-05 54.60 2.95 2.95 2.95 15.36 N/A 8.90E-05 0.00

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

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) 10200.51 243.33 87.68 5.59 5.59 5.59 189.44 0.00 0.01 0.03

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

Oil/Condensate Tanks 31.08 0.74 4.44 0.25 0.25 0.25 24.17 N/A N/A Negligible

Casing Head Gas 141.76 4.15 31.79 2.54 2.54 2.54 172.99 0.00 0.00 0.03

Treater Burner 0.07 0.02 1.29 0.10 0.10 0.10 1.08 N/A 0.01 Negligible

RICE Engine 4.49 2.01E-05 54.60 2.95 2.95 2.95 15.36 N/A 8.90E-05 0.00

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

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) 177.40 4.92 92.13 5.84 5.84 5.84 213.61 0.00 0.01 0.03

Allowable Potential to Emit

XTO Energy, Inc.

Emission Summary

Uncontrolled Potential to Emit

Criteria Pollutants

Criteria Pollutantsa
Facility:

FBIR Smith Pad

Associated Wells: Smith 

11X-10-1, 11X-10-2, 11X-10-

3, 11X-10-4,11X-10-5, 11X10-6

XTO Energy, Inc.

a

Emissions of lead and lead compounds, flourides, sulfuric acid mist, total reduced sulfur and reduced sulfur compounds have been determined to be negligable

CO2 CH4 N2O CO2 CH4 N2O

Oil/Condensate Tanks N/A 658.88 N/A 3959.30 0.00 0.08

Casing Head Gas 40251.95 9293.26 0.04 40251.95 185.87 0.04

Treater Burner 1545.88 0.09 0.02 1545.88 0.09 0.02

RICE Engine 4.99E-02 0.41 0.08 4.99E-02 0.41 0.08

Truck Loading 0.00 0.00 N/A 0.00 0.00 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) 41797.88 9952.64 0.14 45757.18 186.37 0.22

GHG Mass Emissions (tpy): 51750.66 GHG Mass Emissions (tpy): 45943.76

CO2e (tpy): 250847.32 CO2e (tpy): 49738.17

Applicable to the Tailoring Rule?: No

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

Actual

Greenhouse Gasesb

Potential To Emit

Greenhouse Gasesb
BOPD

scf/day

Btu/scf

lb/lb-mole

HAPs:

Benzene wt Fraction (Assumed to be equal to gas sales wt fraction.)

Toluene wt Fraction (Assumed to be equal to gas sales wt fraction.)

E-Benzene wt Fraction (Assumed to be equal to gas sales wt fraction.)

Xylene wt Fraction (Assumed to be equal to gas sales wt fraction.)

n-Hexane wt Fraction (Assumed to be equal to gas sales wt fraction.)

2,2,4-Trimethylpentane

wt Fraction (Assumed to be equal to gas sales wt fraction.)

Controlled emissions are calculated based on a 99% destruction efficiency of the VOC gas.

XTO Energy, Inc.

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Tanks

Flare Gas Volume 178,973

Oil Production 1828

Lower Heating Value 2000

Molecular Weight 45.19

VOC wt Fraction 79.80%

0.0763%

0.0031%

0.0337%

0.7394%

0.0126%

0.0908%

CH4 wt Fraction

1.02%

16.92%

CO2 wt Fraction
XTO Energy, Inc.

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Tanks

Uncontrolled VOCs (PTE):

DRE

VOC: 7,457 scf/hr x x 45.19 lb/lb-mole x 79.80% x 0% = lb/hr

709.55 lb/hr x x = TPY

Controlled VOCs (Allowable):

DRE

VOC: 7,457 scf/hr x x 45.19 lb/lb-mole x 79.80% x 99% = lb/hr

7.10 lb/hr x x x TPY

Uncontrolled HAPs (PTE):

Using E&P Tanks Run: wt% DRE TPY

Benzene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.08% x 0% = 0.68 lb/hr 2.97

E-Benzene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.00% x 0% = 0.03 lb/hr 0.12

Toluene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.03% x 0% = 0.30 lb/hr 1.31

n-Hexane 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.74% x 0% = 6.57 lb/hr 28.80

Xylene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.01% x 0% = 0.11 lb/hr 0.49

2,2,4-Trimethylpentane 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.09% x 0% = 0.81 lb/hr 3.54

Uncontrolled TOTAL HAPS (TPY) 37.23

Controlled HAPs (Allowable):

Benzene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.08% x 98% = 0.01 lb/hr 0.06

E-Benzene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.00

Toluene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.03% x 98% = 0.01 lb/hr 0.03

n-Hexane 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.74% x 98% = 0.13 lb/hr 0.58

Xylene 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.01% x 98% = 0.00 lb/hr 0.01

2,2,4-Trimethylpentane 7,457 scf/hr x x 1/379 scf/lb-mole x 45.19 lb/lb-mol x 0.09% x 98% = 0.02 lb/hr 0.07

Controlled TOTAL HAPS (TPY) 0.74

709.55

8760 hr/yr 3107.82

7.10

31.08

=

=

=

=

=

=

=

=

=

=

=

=

=

=

1/379 scf/lb-mole

1/379 scf/lb-mole

1 ton/2000 lb

1 ton/2000 lb

8760 hr/yr

CRITERIA POLLUTANT EMISSIONSa
XTO Energy, Inc.

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Tanks

Uncontrolled NOx:

NOx: 0 scf/hr x 2,000 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: 7,457 scf/hr x 2,000 Btu/scf x x 0.068 lb/MMBtu = 1.01 lb/hr

1.01 lb/hr x x 4.44 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: 7,457 scf/hr x 7.6 lb/1,000,000 scf = 0.06 lb/hr

0.06 lb/hr x 8760 hr/yr x 0.25 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
XTO Energy, Inc.

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Tanks

Uncontrolled CO:

CO: 0 scf/hr x 2,000 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: 7,457 scf/hr x 2,000 Btu/scf x x 0.370 lb/MMBtu = 5.52 lb/hr

5.52 lb/hr x x 24.17 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: 7,457 scf/hr x x 45.19 lb/lb-mole 1.02% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY

CO2 Created by Combustion (Actual)

CO2: 7,457 scf/hr x 120,000.0 lb/1,000,000 scf = lb/hr

894.86 lb/hr x 8760 hr/yr x = 3919.50 TPY

REGULATED GREENHOUSE GAS EMISSIONSb

=

1 MMBtu/1,000,000 Btu

8760 hr/yr 1 ton/2000 lb

9.09

1 MMBtu/1,000,000 Btu

8760 hr/yr 1 ton/2000 lb =

1 ton/2000 lb

1/379 scf/lb-mole x

1 ton/2000 lb

9.09

39.80

894.86
XTO Energy, Inc.

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Tanks

Uncontrolled CH4:

wt DRE

CH4: 7,457 scf/hr x x 45.19 lb/lb-mole 16.92% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY

Controlled CH4: (Actual)

wt% DRE

CH4: 7,457 scf/hr x x 45.19 lb/lb-mole 16.92% x 99% = lb/hr

lb/hr x 8760 hr/yr x = TPY

Uncontrolled N2O:

wt% DRE

CH4: 7,457 scf/hr x x 45.19 lb/lb-mole 0.00% x 0% = lb/hr

lb/hr x 8760 hr/yr x = TPY

N2O Created by Combustion:

CH4: 7,457 scf/hr x 2.3 lb/1,000,000 scf = lb/hr

0.02 lb/hr x 8760 hr/yr x = 0.08 TPY

b

CO2 and N2O emission factors are from AP-42 Table 1.4-2

(Emission Factors for Natural Gas Combustion).

x 150.43

150.43 658.88

1/379 scf/lb-mole

1 ton/2000 lb

x

0.00 0.00

0.02

1 ton/2000 lb

x 0.00

1.50

1.50 6.59

1/379 scf/lb-mole

1/379 scf/lb-mole

1 ton/2000 lb

1 ton/2000 lb
scfd

Btu/scf

lb/lb-mole

HAP wt fractions

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

DRE

0.08%

0.00%

0.03%

0.74%

0.01%

0.09%

1.02%

43.11%

98%

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

Flare Gas Volume 1,827,930

Lower Heating Value 1401.5

Avg. Molecular Weight 24.49

VOC wt fraction 32.88%

XTO Energy, Inc.

Flare Combustion 

Efficiency:
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

Controlled VOCs (PTE):

wt% DRE

VOC: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 32.88% x 0% = lb/hr

1618.30 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

Controlled VOCs (Allowable):

wt% DRE

VOC: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 32.88% x 98% = lb/hr

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

32.37

141.76

x

CRITERIA POLLUTANT EMISSIONSa

x 1618.30

7088.13
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

Controlled HAPs (PTE):

Using E&P Tanks Run: wt% DRE TPY

Benzene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.08% x 0% = 3.76 lb/hr 16.45

E-Benzene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.00% x 0% = 0.15 lb/hr 0.67

Toluene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.03% x 0% = 1.66 lb/hr 7.26

n-Hexane 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.74% x 0% = 36.39 lb/hr 159.39

Xylene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.01% x 0% = 0.62 lb/hr 2.72

2,2,4-Trimethylpentane 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.09% x 0% = 4.47 lb/hr 19.57

Formaldehyde 76,164 scf/hr 7.50E-02 lb/MMscf = 0.01 lb/hr 0.03

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

Controlled HAPs (Allowable):

Using E&P Tanks Run: wt% DRE TPY

Benzene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.08% x 98% = 0.08 lb/hr 0.33

E-Benzene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.00% x 98% = 0.00 lb/hr 0.01

Toluene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.03% x 98% = 0.03 lb/hr 0.15

n-Hexane 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.74% x 98% = 0.73 lb/hr 3.19

Xylene 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.01% x 98% = 0.01 lb/hr 0.05

2,2,4-Trimethylpentane 76,164 scf/hr x x 1/379 scf/lb-mole x 24.49 lb/lb-mol x 0.09% x 98% = 0.09 lb/hr 0.39

Formaldehyde 76,164 scf/hr x 7.50E-02 lb/MMscf / 1000000 scf/MMscf = 0.01 lb/hr 0.03

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

=

=

4.15

=

=

=

=

=

=

=

=

206.08

=

=

=

=
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

Uncontrolled Nox (PTE):

NOx: 76,164 scf/hr x 1,402 Btu/scf x x 0.068 lb/MMBtu = 7.26 lb/hr

7.26 lb/hr x 8760 hr/yr x 31.79 TPY

NOx Created by Combustion (Actual):

NOx: 76,164 scf/hr x 1,402 Btu/scf x x 0.068 lb/MMBtu = 7.26 lb/hr

7.26 lb/hr x 8760 hr/yr x 31.79 TPY

Controlled H2S (PTE):

wt% DRE

H2S: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 0.00% x 0% = lb/hr

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

Controlled H2S (Actual):

wt% DRE

H2S: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 0.00% x 98% = lb/hr

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

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

x

0.00
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

SO2 Created by Combustion (PTE):

wt% DRE

SO2 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 0.00% x 0% = lb/hr

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

SO2 Created by Combustion (Actual):

wt% DRE

SO2 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 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: 76,164 scf/hr x 1,402 Btu/scf x x 0.370 lb/MMBtu = 39.50 lb/hr

39.50 lb/hr x 8760 hr/yr x 172.99 TPY

CO Created by Combustion (Actual):

CO: 76,164 scf/hr x 1,402 Btu/scf x x 0.370 lb/MMBtu = 39.50 lb/hr

39.50 lb/hr x 8760 hr/yr x 172.99 TPY

1 Mmbtu/1,000,000 Btu

0.00

=

1 ton/2000 lb

x

1 Mmbtu/1,000,000 Btu

1 ton/2000 lb

x

=

0.00

0.00

0.00
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

PM Created by Combustion (PTE):

PM: 76,164 scf/hr x 7.6 = 0.58 lb/hr

0.58 lb/hr x 8760 hr/yr x 2.54 TPY

PM Created by Combustion (Actual):

PM: 76,164 scf/hr x 7.6 = 0.58 lb/hr

0.58 lb/hr x 8760 hr/yr x 2.54 TPY

1 ton/2000 lb

a

NOx, SO2, PM, & CO emission factors are from AP-42 Table 13.5-1 and Table 1.4-2

(Emission Factors for Flare Operations and Natural Gas Combustion).

 lb/1,000,000 scf

1 ton/2000 lb =

=

 lb/1,000,000 scf
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

CO2 (PTE):

CO2 Entrained in the Produced Gas:

DRE

CO2: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 1.02% x 0% = lb/hr

50.29 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 220.28 TPY

CO2 Created by Combustion:

CO2: 76,164 scf/hr x 120,000.0 = 9139.65 lb/hr

`

9139.65 lb/hr x 8760 hr/yr x 40031.67 TPY

40251.95 TPY

CO2 (Actual):

CO2 Entrained in the Produced Gas:

wt% DRE

CO2: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 1.02% x 0% = lb/hr

50.29 lb/hr x 8760 hr/yr x 1 ton/2000 lb = 220.28 TPY

CO2 Created by Combustion: `

CO2: 76,164 scf/hr x 120,000.0 = 9139.65 lb/hr

`

9139.65 lb/hr x 8760 hr/yr x 40031.67 TPY

40251.95 TPY

50.29

1 ton/2000 lb =

x 50.29

Total CO2 Emitted (Allowable):

1 ton/2000 lb =

 lb/1,000,000 scf

 lb/1,000,000 scf

Total CO2 Emitted (PTE):

x

REGULATED GREENHOUSE GAS EMISSIONSb
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

Controlled CH4 (PTE):

wt% DRE

CH4: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 43.11% x 0% = lb/hr

2121.75 lb/hr x 8760 hr/yr x 1 ton/2000 lb = TPY

Controlled CH4 (Actual):

wt% DRE

CH4: 76,164 scf/hr x 1/379 scf/lb-mole x 24.49 lb/lb-mole 43.11% x 98% = lb/hr

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

2121.75

9293.26

x

x 42.43

185.87
FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Treater Flare

XTO Energy, Inc.

N2O Created by Combustion (PTE):

N2O: 76,164 scf/hr x 2.2 = 0.17 lb/hr

0.17 lb/hr x 8760 hr/yr x 0.04 TPY

N2O Created by Combustion (Actual):

N2O: 76,164 scf/hr x 2.2 = 0.17 lb/hr

0.17 lb/hr x 8760 hr/yr x 0.04 TPY

b

CO2 and N2O emission factors are from AP-42 Table 1.4-2

1 ton/2000 lb =

(Emission Factors for Natural Gas Combustion).

1 ton/2000 lb =

 lb/1,000,000 scf

 lb/1,000,000 scf
3,000,000 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 3.00 MMBtu/hr = 0.294 lb/hr

0.2941 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 1.288 TPY

CO: 0.08 lb/MMBtu x 3.00 MMBtu/hr = 0.247 lb/hr

0.25 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 1.082 TPY

SO2: 5.88E-04 lb/MMBtu x 3.00 MMBtu/hr = 0.002 lb/hr

1.76E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.008 TPY

PM: 0.01 lb/MMBtu x 3.00 MMBtu/hr = 0.022 lb/hr

0.02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.098 TPY

VOC: 0.01 lb/MMBtu x 3.00 MMBtu/hr = 0.016 lb/hr

0.02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.071 TPY

HAP: 0.002 lb/MMBtu x 3.00 MMBtu/hr = 0.006 lb/hr

5.56E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.024 TPY

CO2 117.647 lb/MMBtu x 3.00 MMBtu/hr = 352.941 lb/hr

3.53E+02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 1,545.882 TPY

CH4: 0.007 lb/MMBtu x 3.00 MMBtu/hr = 0.020 lb/hr

1.98E-02 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.087 TPY

N2O: 0.001 lb/MMBtu x 3.00 MMBtu/hr = 0.004 lb/hr

3.97E-03 lb/hr x 8,760 hr/yr x 1 ton / 2000 lb = 0.017 TPY

NOx TPY

CO TPY

SO2 TPY

PM TPY

VOC TPY

HAP TPY

CO2 TPY

CH4 TPY

N2O TPY

XTO Energy, Inc.

1545.88

0.09

0.02

1.08

0.07

0.02

0.01

0.10

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Heater Treater Burnera

a

NOx, CO, CO2, & VOC Emission Factors are from AP-42 Table 1.4-1 and 1.4-2 (Emission Factors for

Nitrogen Oxides (N2O) and Methane come from Table C-1 of Subpart W).

Burner Rating

1.29
Saturation Vapor Molecular Temp + Load Loss

Factor (S) Pressure (P) Weight (MW) 460 lb/1000 gal

12.46 x 0.60 x 2.30 x 45.19 / 510.00 = 1.52

LL Truck Load Load Time

lb/1,000 gal Rate bbl/hr hrs gal/bbl

1.52 x 180.00 / 1.00 x 42.00 = 11.49

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.52 x 667194.45 x 42.00 / 2000.00 = 21.30 0.17

VOC

Emissions

Uncontrolled Control % TPY

0.17 100% 0.00 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.52 x 667194.45 x 42.00 / 2000.00 = 21.30 0.00

HAPs

Emissions

Uncontrolled Control % TPY

0.00 100% 0.00 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.52 x 667194.45 x 42.00 / 2000.00 = 21.30 0.22

CO2

Emissions

Uncontrolled Control % TPY

0.22 100% 0.00 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY 

1.52 x 667194.45 x 42.00 / 2000.00 = 21.30 3.60

CH4

Emissions

Uncontrolled Control % TPY

3.60 100% 0.00 0.00

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-

4,11X-10-5, 11X-10-6

Truck Loadout Emission Calculation

Total Gas 

Emissions lb/hr

Uncontrolled 

C3+ VOC tpy

Uncontrolled 

HAPs tpy

Uncontrolled 

CO2 tpy

Uncontrolled 

CH4 tpy

XTO Energy, Inc.
Combined Diesel Engines

Hours of Operation 8760

Maximum HP Rating 2040

NOx g/hp-hr 2.77E+00

CO g/hp-hr 7.80E-01

SO2 g/hp-hr 4.52E-06

PM g/hp-hr 1.50E-01

VOC g/hp-hr 2.28E-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

NOx Control Efficiency 0%

CO Control Efficiency 0%

SO2 Control Efficiency 0%

PM Control Efficiency 0%

VOC Control Efficiency 0%

HAP Control Efficiency 0%

CO2 Control Efficiency 0%

CH4 Control Efficiency 0%

N2O Control Efficiency 0%

Description

RICE Input Data

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

Manufacturer's maximum hp rating.

Manufacturer's emission factor, actual test results or AP-42 factor in grams per horsepower hour (g/hp-hr) for nitrogen oxides (NOx).

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for carbon monoxide (CO).

HAP control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (HAPs).

SO2 control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for sulfure dioxide (SO2).

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (TOC or THC).

NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for sulfure dioxide (PM).

PM control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (CO2).

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (CH4).

CO2 control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

Manufacturer's emission factor, actual test results or AP-42 factor in g/hp-hr for total organic compounds (N2O).

N2O control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

XTO Energy, Inc.

CH4 control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.
ENGINES

2040 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE 0% SO2 DRE 0% HAP DRE 0% PM DRE

##### #### ##### #### ### 100.00%

NOx: 2.77E+00 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 1.25E+01 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 5.46E+01 NOx TPY 

CO: 7.80E-01 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 3.51E+00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 1.54E+01 CO TPY 

SO2: 4.52E-06 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 2.03E-05 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 8.90E-05 SO2 TPY 

PM: 1.50E-01 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 6.75E-01 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.95E+00 PM TPY 

VOC: 2.28E-01 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 1.03E+00 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 4.49E+00 VOC TPY 

HAP: 1.02E-06 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 4.59E-06 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 2.01E-05 HCHO TPY 

CO2: 2.54E-03 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 1.14E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 4.99E-02 CO2

CH4: 2.10E-02 g/HP-HR 2040 HP x 1 lb / 453.6 grams = 9.44E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 4.14E-01 CH4

N2O: 4.20E-03 g/HP-HR x 2040 HP x 1 lb / 453.6 grams = 1.89E-02 lb/hr x 8760 hr/yr x 1 ton / 2000lb = 8.27E-02 N2O

x

x

x

x

x

XTO Energy, Inc.

FBIR Smith Pad

Associated Wells: Smith 11X-10-1, 11X-10-2, 11X-10-3, 11X-10-4,11X-10-5, 11X-10-6

Reciprocating Engine Emissions 

x

x

x
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT C: REPRESENTATIVE GAS ANALYSIS 
 QUESTAR APPLIED TECHNOLOGY

1210 D. Street, Rock Springs, Wyoming 82901

(307) 352-7292

LIMS ID: N/A Description: Jane 11x-20

Analysis Date/Time: 8/30/2011 1:00 PM Field: Lostbridge

Analyst Initials: AST ML#: XTO

Instrument ID: Instrument 1 GC Method: Quesbtex

Data File: QPC73.D

Date Sampled: 8/24/2011

Component Mol% Wt% LV%

Methane 65.8105 43.1118 54.9906

Ethane 14.7115 18.0637 19.4481

Propane 8.4823 15.2736 11.5292

Isobutane 1.1052 2.6230 1.7833

n-Butane 3.4281 8.1362 5.3312

Neopentane 0.0052 0.0152 0.0097

Isopentane 0.6395 1.8841 1.1547

n-Pentane 0.9259 2.7278 1.6541

2,2-Dimethylbutane 0.0048 0.0169 0.0099

2,3-Dimethylbutane 0.0447 0.1571 0.0902

2-Methylpentane 0.1557 0.5477 0.3186

3-Methylpentane 0.0847 0.2979 0.1704

n-Hexane 0.2101 0.7394 0.4261

Heptanes 0.3050 1.1676 0.6006

Octanes 0.0396 0.1837 0.0965

Nonanes 0.0125 0.0618 0.0313

Decanes plus 0.0012 0.0071 0.0037

Nitrogen 3.4649 3.9635 1.8738

Carbon Dioxide 0.5686 1.0219 0.4780

Oxygen 0.0000 0.0000 0.0000

Hydrogen Sulfide 0.0000 0.0000 0.0000

Total 100.0000 100.0000 100.0000

Global Properties Units

Gross BTU/Real CF 1401.5 BTU/SCF at 60°F and14.73 psia

Sat.Gross BTU/Real CF 1378.5 BTU/SCF at 60°F and14.73 psia

Gas Compressibility (Z) 0.9952

Specific Gravity 0.8476 air=1

Avg Molecular Weight 24.490 gm/mole

Propane GPM 2.324682 gal/MCF

Butane GPM 1.438725 gal/MCF

Gasoline GPM 0.892199 gal/MCF

26# Gasoline GPM 1.971372 gal/MCF

Total GPM 4.656794 gal/MCF

Base Mol% 99.883 %v/v

Sample Temperature: 74 °F

Sample Pressure: 34 psig

H2SLength of Stain Tube N/A ppm
Component Mol% Wt% LV%

Benzene 0.0239 0.0763 0.0330

Toluene 0.0090 0.0337 0.0148

Ethylbenzene 0.0007 0.0031 0.0014

M&P Xylene 0.0024 0.0102 0.0045

O-Xylene 0.0006 0.0024 0.0010

2,2,4-Trimethylpentane 0.0195 0.0908 0.0483

Cyclopentane 0.0000 0.0000 0.0000

Cyclohexane 0.0382 0.1314 0.0642

Methylcyclohexane 0.0378 0.1515 0.0749

Description: Jane 11x-20

GRI GlyCalc Information

Component Mol% Wt% LV%

Carbon Dioxide 0.5686 1.0219 0.4780

Hydrogen Sulfide 0.0000 0.0000 0.0000

Nitrogen 3.4649 3.9635 1.8738

Methane 65.8105 43.1118 54.9906

Ethane 14.7115 18.0637 19.4481

Propane 8.4823 15.2736 11.5292

Isobutane 1.1052 2.6230 1.7833

n-Butane 3.4281 8.1362 5.3312

Isopentane 0.6447 1.8993 1.1644

n-Pentane 0.9259 2.7278 1.6541

Cyclopentane 0.0000 0.0000 0.0000

n-Hexane 0.2101 0.7394 0.4261

Cyclohexane 0.0382 0.1314 0.0642

Other Hexanes 0.2899 1.0196 0.5891

Heptanes 0.1766 0.6839 0.3654

Methylcyclohexane 0.0378 0.1515 0.0749

2,2,4 Trimethylpentane 0.0195 0.0908 0.0483

Benzene 0.0239 0.0763 0.0330

Toluene 0.0090 0.0337 0.0148

Ethylbenzene 0.0007 0.0031 0.0014

Xylenes 0.0030 0.0126 0.0055

C8+ Heavies 0.0496 0.2369 0.1246

Subtotal 100.0000 100.0000 100.0000

Oxygen 0.0000 0.0000 0.0000

Total 100.0000 100.0000 100.0000
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT D: 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. 
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT E: NSCR CONTROL MANUFACTURER’S 

SPECS 
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT F: ENCLOSED COMBUSTOR 

MANUFACTURER’S SPECS 
CIMARRON ENERGY INC.

Home Office: 1-(580) 338-5496 FAX 1-(580) 338-0885 P.O. Box 1406, Guymon, Oklahoma 73942 

Administrative Office: 1-(405) 928-7373 FAX 1-(405) 928-7380 P.O. Box 722110, Norman, Oklahoma 73070 

EMISSION CONTROL DEVICES (ECD) 

Cimarron Energy Tank VOC Emission Control Devices are enclosed combustors 

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. 
Specifications 

24”D x 8’.5”L ECD 30”D x 8’.5”L ECD 

Capacity: 8 mcf/d @ 10 oz. Capacity: 11mcf/d @ 10oz. 

MAWP: Atmospheric MAWP: Atmospheric 

MMBTU/hr: .7 MMBTU/hr. MMBTU/hr: 1 MMBTU/hr. 

Number of Jets: 64 Number of Jets: 88 

Flame Cell: 24” Flame Cell: 30” 

Burner: 16” Burner: 25” 

Backdraft: 2” or 3” Inline Wenco Backdraft: 2” or 3” Inline Wenco 

Inlet Connection: 3” NPT Inlet Connection: 3” NPT 

48”D x 12’L ECD 60”D x 13’L ECD 

Capacity: 26 mcf/d @ 10 oz. Capacity: 60 mcf/d @ 10 oz. 

MAWP: Atmospheric MAWP: Atmospheric 

MMBTU/hr: 2 MMBTU/hr. MMBTU/hr: 5 MMBTU/hr. 

Number of Jets: 210 Number of Jets: 440 

Flame Cell: 48” Flame Cell: 60” 

Burner: 34” Burner: 42” 

Backdraft: 2” or 3” Inline Wenco Backdraft: 3” Inline Wenco 

Inlet Connection: 3” NPT Inlet Connection: 3” NPT 

48”D x 25’L HV ECD 

Capacity: 130 mcf/d @ 10 oz. 

MAWP: Atmospheric 

Number of orfices: 88 

Flame Cell: 4) 36” 

Inlet Connection: 3” NPT 

Backdraft: 2” or 3” Inline Wenco 
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT G: PROCESS FLOW DIAGRAM OF 

FACILITY 
Gas & Liquids

2-Phase Production Separator(s) 

(Up to 6 Separators Site Wide, 

one Separator for each Well)

Liquids (Oil & Produced Water)

0.5 MMBTU/HR Heater Treater(s) 

(Up to 6 Heater Treaters Site 

Wide, One for each well)

Oil

Produced Water

*Gas Gas

Well Head(s) & Pumping Unit(s)

 (Up to 6 Well Heads & 6 

Pumping Units Site Wide, One 

for each well)

400 bbl Oil Tank(s)

 (Up to 24 Tanks Site Wide, 

Four Tanks for each well)

400 bbl Produced Water Tank(s) 

(Up to 12 Tanks Site Wide, Two 

Tanks for each well)

L.A.C.T. Unit(s)

(Pipeline Sales)

Sales Oil

Water Pump(s) 

(Up to 12 Water Pumps Site Wide, one 

for each Tank) / Pipeline to Disposal

Tank Vapors

Produced Water

Enclosed Combustor(s)

(99% DRE of VOC)

(Up to 3 Combustors, site 

wide total)

Utility Flare

(98% DRE of VOC) Sales Gas

Gas Meter

(Pipeline Sales)

*Gas from Separator(s) will either be sent to pipeline

 sales, or will be flared if we cannot tie into a sales 

pipeline or shut in by third party

3 – GENSETS

500KW (680 hp)

Diesel Engines (Supplies 

Electric Power Pumping Unit, 

Water Transfer Pumps, 

Recycle Pumps, and L.A.C.T 

Units

XTO Energy, Inc. 

Fort Berthold Indian Reservation

Process Flow Diagram – Six (6) Well Pad Design

3 – 1000 Gallon 

Diesel Storage 

Tanks

Fuel
Gas & Liquids

2-Phase Production Separator(s) 

(Up to 6 Separators Site Wide, 

one Separator for each Well)

Liquids (Oil & Produced Water)

0.5 MMBTU/HR Heater Treater(s) 

(Up to 6 Heater Treaters Site 

Wide, One for each well)

Oil

Produced Water

*Gas Gas

Well Head(s) & Pumping Unit(s)

 (Up to 6 Well Heads & 6 

Pumping Units Site Wide, One 

for each well)

400 bbl Oil Tank(s)

 (Up to 24 Tanks Site Wide, 

Four Tanks for each well)

400 bbl Produced Water Tank(s) 

(Up to 12 Tanks Site Wide, Two 

Tanks for each well)

L.A.C.T. Unit(s)

(Pipeline Sales)

Sales Oil

Water Transfer Pump(s) 

(Up to 12 Water Transfer Pumps Site 

Wide, One for each Tank) / Pipeline to 

Disposal

Tank Vapors

Produced Water

Enclosed Combustor(s)

(99% DRE of VOC)

(Up to 3 Combustors, Site 

wide total)

Utility Flare

(98% DRE of VOC)

Sales Gas Gas Meter

(Pipeline Sales)

*Gas from the Separator(s) will either be sent to pipeline

 sales, or will be flared if we cannot tie into a sales 

pipeline or shut in by third party

**When VRU is down or being by passed, Tank Vapors 

are controlled by the Enclosed Combustor(s)

VRT

(Vapor Recovery Tower)

Up to 6 VRTs Site Wide, 

One for each well.

Stable Oil

VRU

(Vapor Recovery Unit)

Gas

Gas Meter

(Pipeline Sales) Gas

3 – GENSETS

500KW (680hp) Diesel Engines

(Supplies Electric Power for the 

VRU, Pumping Units, Water 

Transfer Pumps, Recycle 

Pumps, and L.A.C.T. Units

3 -1000 gal 

Diesel Fuel 

Tanks

Fuel

XTO Energy, Inc.

Fort Berthold Indian Reservation

Process Flow Diagram – Six (6) Well Pad
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT H: PRODUCTION DECLINE CURVE 

CALCULATIONS (CONFIDENTIAL) 
XTO Energy, Inc. 

NSR Synthetic Minor Permit Application 

XTO211339 

ATTACHMENT I: DIESEL TANK EPA TANKS 4.09D 

EMISSIONS SUMMARY 
TANKS 4.0.9d

Emissions Report - Detail Format 

Tank Indentification and Physical Characteristics

Identification

 User Identification: 1000 gallon diesel tank

 City: Williston

 State: North Dakota

 Company: XTO Energy

 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: 314.48

 Net Throughput(gal/yr): 314,484.00

 Is Tank Heated (y/n): N

 Is Tank Underground (y/n): N

Paint Characteristics

 Shell Color/Shade: Gray/Medium

 Shell Condition Good

Breather Vent Settings

 Vacuum Settings (psig): -0.03

 Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Bismarck, North Dakota (Avg Atmospheric Pressure = 13.86 psia)

TANKS 4.0 Report Page 1 of 6

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1000 gallon diesel tank - Horizontal Tank

Williston, North Dakota 

TANKS 4.0.9d

Emissions Report - Detail Format 

Liquid Contents of Storage Tank

Daily Liquid Surf. 

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol. 

Liquid

Mass 

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Distillate fuel oil no. 2 All 50.18 39.72 60.64 44.68 0.0045 0.0031 0.0067 130.0000 188.00 Option 1: VP50 = .0045 VP60 = .0065

TANKS 4.0 Report Page 2 of 6

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1000 gallon diesel tank - Horizontal Tank

Williston, North Dakota 

TANKS 4.0.9d

Emissions Report - Detail Format 

Detail Calculations (AP-42)

Annual Emission Calcaulations

Standing Losses (lb): 0.2654

 Vapor Space Volume (cu ft): 86.5719

 Vapor Density (lb/cu ft): 0.0001

 Vapor Space Expansion Factor: 0.0780

 Vented Vapor Saturation Factor: 0.9995

Tank Vapor Space Volume:

 Vapor Space Volume (cu ft): 86.5719

 Tank Diameter (ft): 4.1600

 Effective Diameter (ft): 7.2797

 Vapor Space Outage (ft): 2.0800

 Tank Shell Length (ft): 10.0000

Vapor Density

 Vapor Density (lb/cu ft): 0.0001

 Vapor Molecular Weight (lb/lb-mole): 130.0000

 Vapor Pressure at Daily Average Liquid

 Surface Temperature (psia): 0.0045

 Daily Avg. Liquid Surface Temp. (deg. R): 509.8466

 Daily Average Ambient Temp. (deg. F): 41.5958

 Ideal Gas Constant R

 (psia cuft / (lb-mol-deg R)): 10.731

 Liquid Bulk Temperature (deg. R): 504.3458

 Tank Paint Solar Absorptance (Shell): 0.6800

 Daily Total Solar Insulation

 Factor (Btu/sqft day): 1,276.2450

Vapor Space Expansion Factor

 Vapor Space Expansion Factor: 0.0780

 Daily Vapor Temperature Range (deg. R): 41.8377

 Daily Vapor Pressure Range (psia): 0.0036

 Breather Vent Press. Setting Range(psia): 0.0600

 Vapor Pressure at Daily Average Liquid 

 Surface Temperature (psia): 0.0045

 Vapor Pressure at Daily Minimum Liquid 

 Surface Temperature (psia): 0.0031

 Vapor Pressure at Daily Maximum Liquid

 Surface Temperature (psia): 0.0067

 Daily Avg. Liquid Surface Temp. (deg R): 509.8466

 Daily Min. Liquid Surface Temp. (deg R): 499.3872

 Daily Max. Liquid Surface Temp. (deg R): 520.3060

 Daily Ambient Temp. Range (deg. R): 24.3583

Vented Vapor Saturation Factor

 Vented Vapor Saturation Factor: 0.9995

 Vapor Pressure at Daily Average Liquid: 

 Surface Temperature (psia): 0.0045

 Vapor Space Outage (ft): 2.0800

Working Losses (lb): 1.1569

 Vapor Molecular Weight (lb/lb-mole): 130.0000

 Vapor Pressure at Daily Average Liquid 

 Surface Temperature (psia): 0.0045

 Annual Net Throughput (gal/yr.): 314,484.0000

TANKS 4.0 Report Page 3 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
 Annual Turnovers: 314.4840

 Turnover Factor: 0.2621

 Tank Diameter (ft): 4.1600

 Working Loss Product Factor: 1.0000

Total Losses (lb): 1.4223

TANKS 4.0 Report Page 4 of 6

file://C:\Program Files\Tanks409d\summarydisplay.htm 9/29/2011
Emissions Report for: Annual 

1000 gallon diesel tank - Horizontal Tank

Williston, North Dakota 

TANKS 4.0.9d

Emissions Report - Detail Format 

Individual Tank Emission Totals

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Distillate fuel oil no. 2 1.16 0.27 1.42

TANKS 4.0 Report Page 5 of 6

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TANKS 4.0 Report Page 6 of 6

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