• 

APPLICATION FOR 

PSD/TITLE V SYNTHE ~MIjNffj~-:­

AIR QUALITY PERMIT 

NORTH SEGMENT 6-7H 

PAD OIL & GAS 

;~i_ODUCTI FA ~'--"f\~~:'f ~;-~, -/-.;:~_ :'­ ':;'" 

1400 11th Avenue 

--­ --­

-­

~-­

-

Bison Engineering, Inc. 
• 


~~©~~~~~ [;EC 28 2011 

8P-AR 

Decembel' 28,2011 

DAKOTA-J E&P COMPANY, LLC 

8 subsidiary ofWlllillms 

1001 ttl' Street, Suite 1200 

Denver, CO 80202 

303/527·3900 

Ms. Kathleen Pasel' Duplicate submittal provided via e-mail to: 

Minor NSR Permitting Coordinator r8airpermitting@epa.gov

• U.S. EPA, Region 8 


1595 Wynkoop Avenue. 8P-AR 


Denver, CO 80202-1129 

Re: Synthetic Minor Source Permit Application for the North Segment 6-7H Pad 

Dear Ms. Paser: 

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

Source Permit Application for the North Segment 6-7H Pad. This application is being submitted in 

accordance with the requirements of Federal Minor New Source Review Rule. 

Do not hesitate to contact me with any questions either by phone at 303-606-4056, 01' bye-mail at 

JoDell.Mizoue@Williams.com. 

Sincerely, 

Williams 


Dakota-3 E&P CompallY, LLC 


• 

Staff 

t.~1f Environmental Specialist 

Attachment 

cc: 	 File 

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

New Town, NO 58763-9404 

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

(letter Only) 

• 

T 

• 

C. CONTACT INFORMATION 


• 


Company Contact: JoDell Mizoue ITitle: 

, Staff Environmental 

! Specialist 

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

Email Address: JoDell.Mizoue@Williams.com 

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

I 

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

Mailing Address 

Email Address 

Telephone Number Facsimile Number 

Facility Contact: Same as above Title 

Mailing Address 

Email Address 

Telephone Number Facsimile Number 

Compliance Contact: Same as above Title 

Mailing Address 

Email Address 

Telephone Number Facsimile Number 

• 

• 

D. ATTACHMENTS 


Include all ofthe fo])owing information (see the attached instructions) 

./ 	FORM SYNMIN - New Source Review Synthetic Minor Limit Request Fonn, 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 ofdays 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, PM1O, 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 (H2S04), 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 ofthis form, as appropriate for the use specified at the top ofthe form. 

E(i) - Proposed New Facility 

• 

Pollutant Potential Emissions 

(tpy) 

Proposed Allowable 

Emissions 

(tpy) 

PM - Particulate Matter 

PM 10 - Particulate Matter less 

than 10 microns in size 

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 

H2S04 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur 

Compounds 

PM 0.51 0.63 

PMu) 0.51 0.63 

PM 2.5 0.51 0.63 

SOx 0.14 0.14 

NO. 31.40 34.06 

CO 63.06 77.56 

VOC 1448.50 76.21 

Pb Negligible Negligible 

Fluorides Negligible Negligible 

H2SO4 Negligible Negligible 

HIS 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 ofrefuse per day; 

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

til Petroleum refineries; 

(k) Lime plants; 

(I) Phosphate rock processing plants; 

(m) Coke oven batteries; 

(n) Sulfur recovery plants; 

(0) 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 III or 

Il2 ofthe Act. 

• 

• 

E(ii) Proposed New Construction at an Existing Facility or Modification of an Existing Facility 

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

Pollutant Current 

Actual 

Emissions 

Jtpy) 

Current 

Allowable 

Emissions 

(tpy) 

Post-Change 

Potential 

Emissions 

(tpy) 

Post-Change 

Allowable 

Emissions 

(tpy) 

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

PMIG N/A N/A N/A N/A 

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

SO, N/A N/A N/A N/A 

NO, 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 

H1S04 N/A N/A N/A N/A 

H1S N/A N/A N/A N/A 

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

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

• 

PM - PartIculate Matter 

PM IO - 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 

H2S04 - Sulfuric Acid Mist 

H2S - Hydrogen Sulfide 

TRS - Total Reduced Sulfur 

RSC - Reduced Sulfur Compounds 

• 

• 
• Instructions 

Use of This Form 

• 	 Proposed new construction or modifications should first be evaluated to determine ifthe 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). Ifthe proposed construction does not qualify as a major under 

that test, then it may be subject to the requirements ofthe 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. J 52(d) - Modification means any physical or operational change at a source that would 

cause an increase in the allowable emissions ofthe 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: 

(l) 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.J52(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. 

• 	 52.2J(b)(J6) - Allowable emissions means the emissions rate ofa stationary source calculated 

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

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

stringent ofthe 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 7 of 15 

• 
• 

A. General Facility Information 

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

found at the following link ~ North American Industry Classification System 

(bup://www.census.gov/epcdlnaics/nsic2ndx.htm#SI ). 

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

Classification System (NAICS) has replaced the SIC codes, much ofthe 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. 

lla & lIb. 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 114 SectioniSection/Township/Range. 


(e.g., SW 14, NE 114 /S36/T lONIR21 E). 


• 

Page 8 of 15 

• 
• 

B. Current Permit Information 

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

Minor New Source Review (MNSR), Prevention ofSignificant 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 ofhours per day, days per week, 

and weeks per year. 

3. 	 A list ofthe 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 9 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. 

,f 	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 


ofmaterial 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 •

ofmaterial 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. 

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

• 

Page 10 of 15 

• 
• 


• 


A. GENERAL FACILITY INFORMATION 

1. 	 (a) Company Name 

Dakota-3 E&P Company, LLC 

(b) Operator Name

• Dakota-3 E&P Company, LLC 

3. 	Type of Operation 

Oil and Gas Production 

6. NAlCS Code 


213111 


UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Region 8 Air Program 

FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY 

Check List - Application for New Construction 

(FonnNEW) 

Please check all that apply to show how you are using this form 

• Proposed Construction of a New Facility 

o Proposed Construction of New Equipment at an Existing Facility 

o Proposed Modification of an Existing Facility 

o Other ­ Please Explain 

Use of tbls InformatioD 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 ofapplication forms for 

this program is currently under Office ofManagement 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: 

Ifyou 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 

2. Facility Name 

North Segment 6-7H Pad 

4. Portable Source? o Yes 

5. Temporary Source? 0 Yes 

~ No 

~ No 

7. SIC Code 

1311 

8. Physical Address: 1001 1th Street, Suite 1200 Denver, CO 80202 

9. 	Reservation* 110. County* , 11 a. Latitude* 11 b. Longitude* 

FBIR Mountrail 	 47.84584 -102.38335

I 

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

NWNW 6 : TI50N 	 R91W 

I I 

. 

• 

• 

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 ofthe 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 

I Date of the Permit Action N/A 

• 

• 

• 
• Criteria Pollutant Emissions Estimates 

./ 	Estimates ofCurrent Actual Emissions, Current Allowable Emissions, Post-Change Uncontrolled 

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

matter, PMJO, 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 (H2S04), hydrogen sulfide (H2S), total reduced sulfur (TRS) and 

reduced sulfur compounds, including all calculations for the estimates. 

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

to total emissions. 

• 

2. The information should include all ofthe 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/ttnichiefJefuac/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 

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

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

• I. 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 cornbusted 

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 ofhours in a year) and dividing by 2,000 (which is the 

number ofpounds 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 I I ofl5 
• 

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 ofa 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 hOUTS (which is the number ofhoUTS in a year) and 

dividing by 2,000 (which is the number ofpounds 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 

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

is the number ofpounds 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 ofeach 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 ofthe 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. Ifthe allowable emissions ofan 
 •

emissions unit would be reduced as a result ofthe 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 ofthe 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. Ifthe 


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


replacement, use zero in the calculation. 


Page 12 of 15 

• 
• 

./ Modeling Analysis 

I 

f 

Do I need to do a mode1ing analysis? 

The Federal Minor New Source Review Regulations at 40 CFR 49. 1 S9(d) requires that a modeling 

analysis (AQIA) ofproposed 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 ofSignificant Deterioration (PSD) increment violation. 

In addition, ifthe 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 ofthe NAAQS and PSD Increment, EPA Region 8 requests that those 

proposed activities that meet the following criteria perform an AQIA: • 	 

I. 	 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 ofthe environmental impact ofthe activities proposed. I 

2. 	 Modeling ofproposed 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 ofapplicable ambient air quality standards or increments in 

circumstances such as: 

(a) A substantial portion ofthe 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 13 of IS 

• 
• 

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: 

Step 4: 

Step 5: 

Step 6: 

Preliminary Modeling Analysis (refined modeling) 

Full Impact Modeling Analysis (refined modeling) 

PSD Increment and NAAQS Analysis 

Additional Impact Analysis 

2. Step 1: Qualitative Air Quality Assessment 

Narrative description ofthe 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. 

Ifa 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 ofair 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/scramldispersionscreening.htm. A pre-approved modeling protocol is 

not necessary prior to conducting a Screening Analysis. 

4. 	 lfthe proposed new or modified emission increases do not increase ambient concentrations ofa 

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

further modeling is necessary. 

S'19m'fileantImpact Leve s 

Pollutant Averaging Period Class II Area SIL Class I Area SIL 

(uwm3

) 

I (uwm3

) 

I hr 3 ppb or 7.8 ug/m~ (interim) ..--­ 3 hr 25 1.0 S02 24 hr 5 0.2 

Annual I 0.08 

24 hr 0.07 1.2 PM2.5 Annual 0.06 0.3 I 

24hr 5 0.2 PM10 Annual I 0.08 

1 hr 4 ppb or 7.5 ug/m~ (interim) ---... N02 Annual 1 0.08 

1 hr 2,OOOppb CO 8 hr 500ppb 

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

Page 14 of 15 

• 

• 

• 

i 
• 5. Sources that cannot demonstrate protection ofair 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 

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

What Should I Include In My Application IfModeling 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 ofthe model used, all input f parameters, and the resulting output. Electronic copies ofthe modeling input/output files should 

be provided to EPA Region 8. t 

./ ESA 	 I 

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 ofany listed species or result in the destruction or adverse modification of 

designated critical habitat ofsuch species. 

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

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

website has been provided to assist you: 

http://www.fws.gov/endangeredl 

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 ofthat 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. 

Page 15 of 15 

• 
• 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 


Region 8 Air Program 

&EPA FEDERAL MINOR NEW SOURCE REVIEW PROGRAM IN INDIAN COUNTRY 

Checklist - Synthetic Minor Limit Request 

(Fonn SYNMIN) 

Use ofthis 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 ofManagement and Budget review and these information request forms will be replaced/updated after that review is 

completed. 

Please submit information to following two entities: 

The Tribal Environmental Contact for the specific reservation: 

Ifyou need assistance in identifying the appropriate Tribal 

Environmental Contact and address, please contact the EPA 

Region 8 Tribal Air Coordinator: 

• Federal Minor NSR Permit Coordinator 

U.S. EPA, Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

Alexis North, EPA Region 8 Tribal Air Coordinator 

303 -312-7005 

north.alexis@epa.gov 

A. GENERAL INFORMATION 

• 

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: 

B. ATTACHMENTS 

./' 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 ofthe 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 ofGreenhouse Gas (GHG) pollutants before and after proposed 

emission controls. 

• 

Company Name Facility Name 

Dakota-3 E&P Company, LLC North Segment 6-7H Pad 

Company Contact or Owner Name Title 

JoDell Mizoue StaffEnvironmental 

Specialist 

Mailing Address 

1001 17th Street, Suite 1200 Denver, CO 80202 

Email Address 

JoDell.Mizoue@Williams.com 

Telephone Number Facsimile Number 

(303) 606-4056 (303) 692-8285 
• 
 i 

t 

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 ofAmerica 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 ofthe 

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

Emission or operational limits can also be taken into consideration as maximums ifthey 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 offederal Clean Air Act programs that use PTE to determine whether they apply are 

(I) the Prevention ofSignificant 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 ofthe 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 ofa new source or expansion ofan 

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. AITACHMENTS 

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 ofmany federal Clean Air Act requirements (such as 

Title V, PSD and MACT) is often based on facility-wide emission levels ofspecific pollutants. In that 

• 

Page 2 of4 
• 

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

be addressed by this section ofthe 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 wi1llimit the source's actual or potential 

emissions as a legal and practical matter and, ifapplicable, 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 ofair 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 

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

the number ofpounds in a ton). 

Item 5 - JI:lew construction projects that have the potential to emit GHG emissions ofat least 100,000 

tpy C02e and 100 or 250 tpy on a mass basis, modifications at existing PSD facilities that increase 

GHG emissions by at least 75,000 tpy C02e and minor sources that increase GHG emissions by at least 

100,000 tpy C02e and 100 or 250 tpy on a mass basis are subject to PSD permitting requirements, even 

ifthey 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 ofthe potential emissions ofthe 

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

permitting and how to calculate CO2 equivalents (C02e), the mass emissions of each individual GHG 

• 

• 

•

Page 3 01'4 
• adjusted for its Global Warming Potential (GWP) can be found at: 

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

1. Carbon dioxide (C02) 

2. Methane (C~) and its C02e 

3. Nitrous oxide (N20) and its C02e 

4. Hydrofluorocarbons (HFCs) and its COze 

5. Perfluorocarbons (PFCs) and its C02e 

6. Sulfur hexafluoride (SF6) and its COze 

• 

• 

• Page 4 of4 
• 

NORTH SEGMENT 6-7H PAD ATTACHMENTS: 

• 

Attachment A: Application Report 

Attachment B: Emission Inventory 

Attachment C: Flashing Emissions Calculations 

Attachment D: Representative Low Pressure Oil Analytical Data 

Attachment E: Representative Gas Analysis 

Attachment F: Engine Manufacturer's Specs 

Attachment G: Emission Control Device Manufacturer's Specs 

Attachment H: Process Flow Diagram of Facility 

Attachment I: Production Decline Curve Calculations 

Attachment J: Diesel Tank EPA TANKS 4.09d Emission Summary 

• 


Dakota-3 E&P Company. LLC. 

NSR Synthetic Minor Application 

WEP211324 

• 
• 

ATTACHMENT A: APPLICATION REPORT 

• 


• 


Dakota-3 E&P Company. LLC. 

NSR Synthetic Minor Application 

WEP211324 

~. 

t 

• 

• 


APPLICATION FOR AN NSR 


PSD/TITLE V SYNTHETIC MINOR 


AIR QUALITY PERMIT 


NORTH SEGMENT 6-7H 


PAD OIL & GAS 


PRODUCTION FACILITY 


Prepared for: 

Dakota-3 E&P Company, LLC 

100117th Street, Suite 1200 

Denver, CO 80202 

Prepared by: 

Bison Engineering, Inc. 

1400 11th Avenue 

I 

Helena, MT 59601 I • 

(406) 442-5768 

www.bison-eng.com 

I 

! 

I 

i 

~ 

~ 

~ 

I 

December 28, 2011 
• 

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 ................................................................................ 2 


3.0 POTENTIAL TO EMIT ESTIMATE ....................................................................... 4 


3.1 Production Storage Tank VOC Emissions ................................................. 7 


3.2 Produced Casing Head Gas Emissions ..................................................... 7 


• 
 3.3 ReCiprocating Internal Combustion or Compression Ignition Engines ....... 8 


3.4 Natural Gas External Combustion Unit Emissions ..................................... 8 


3.5 Truck Loading Emissions ........................................................................... 8 


3.6 Fugitive Emissions: Dust and Equipment Leaks ....................................... 8 


4.0 EMISSIONS AND OPERATIONAL LIMITS REQUESTS ..................................... 9 


4.1 Production Storage Tank Emissions .......................................................... 9 


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


5.0 ALLOWABLE EMISSIONS ................................................................................. 10 


5.1 Storage Tank Emissions .......................................................................... 10 


5.2 Produced Casing Head Gas Emissions ................................................... 10 


5.3 Rice Engine Emissions ............................................................................ 10 


5.4 Natural Gas External Combustion Unit Emissions ................................... 10 


5.5 Truck Loading Emissions ......................................................................... 11 


5.6 Fugitive Emissions: Dust and Equipment Leaks ..................................... 11 


5.7 Diesel Storage Tank Emissions ............................................................... 11 


6.0 PROPOSED MONITORING AND RECORDKEEPING ...................................... 12 


6.1 Production Storage Tanks ....................................................................... 12 


6.2 Production Storage Tank Emissions Control Device ............................... 13 


6.3 Produced Casing Head Gas Emergency Utility Flare .............................. 15 


• 
 6.4 Rice Engines ............................................................................................ 16 


6.5 Natural Gas-Fired External Combustion Units ......................................... 16 


6.6 Truck Loading .......................................................................................... 17 


6.7 Fugitive Emissions: Dust and EqUipment Leaks ..................................... 17 


6.8 General Recordkeeping Requirements .................................................... 19 


7.0 QUALITATIVE AIR QUALITY ASSESSMENT .................................................... 20 


8.0 ENDANGERED SPECIES ACT .......................................................................... 21 


9.0 NATIONAL HISTORIC PRESERVATION ACT .................................................. 22 


North Segment 6-7H Pad 12/28/11 pg. ii 


NSR Synthetic Minor Permit Application 


Project #: WEP211324 


• 
• 

FIGURES 


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


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


ATTACHMENTS 

Attachment A: 

Attachment B: 

Attachment C: 

Attachment D: 

Attachment E: 

Attachment F: 

Attachment G: 

Attachment H: 

Attachment I: 

Attachment J: 

Application Report 

Emission Inventory Spreadsheets 

E&P Tank V2 Emission Summary Output 

Representative Low Pressure Oil Analytical Data 

Representative Gas Analysis •

Engine Manufacturer's Specs 

Emission Control Device Manufacturer's Specs 

Process Flow Diagram of F acUity 

Production Dedine Curve Calculations 

Diesel Tank EPA TANKS 4.09d Emissions Summary 

• 

North Segment 6·7H Pad 12/28111 pg. iii 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 


1.0 INTRODUCTION 


1.1. Summary 

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

of Significant Deterioration (PSD) and/or Part 71 Title V (Title V) synthetic minor permit 

to the Environmental Protection Agency (Agency) in accordance with the Federal Minor 

New Source Review (NSR) Rule (40 CFR 49) adopted pursuant to the Federal Clean 

Air Act. 

Dakota-3 is proposing to construct and operate the North Segment 6-7H Pad 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 and/or Title 

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

1.2. Site Location 

The North Segment 6-7H Pad is proposed to be located in the northwest ~ of the 

northwest ~ Section 6, Township 150 North, Range 91 West, Mountrail County, on the 

FBIR in North Dakota. 

1.3. Site Description 

At the proposed North Segment 6-7H Pad there will be six oil and gas wells that are 

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

acre site, with an elevation of approximately 2,000 feet (mean sea level), in Mountrail 

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

grazing. The proposed pad's associated well names are: 

1. North Segment 6-7HA 

2. North Segment 6-7HB 

3. North Segment 6-7HC 

• 4. North Segment 6-7HX 

5. North Segment 6-7HW 

6. North Segment 6-7HY 

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. 

North Segment 6·7H Pad pg. 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 

2.0 NARRATIVE DESCRIPTION 


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

North Segment 6-7H Pad. For purposes of estimating emissions from this facility, the 

combined first twelve-month potential production from the six proposed wells at this 

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

Inventory. 

The production rates used in this application are grossly overestimated when compared 

to the actual predicted production rates in the first and subsequent years. The wells that 

will be producing to this facility do not begin producing at the same time. In reality, there 

will be up to six or more years' difference in when the initial production from wells begin 

to when the final wells are constructed and begin to produce. It is not physically possible 

for all of the wells to be simultaneously drilled and begin initial production. However, to 

•

allow for reasonable flexibility and to be conservative, this application has considered a 

maximum potential production case from the pad. Due to ever-changing drilling 

schedules, completion schedules, economics, etc., the wells will begin actual production 

at different times. 

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

capabilities. 

6 - Heater Treater/Separators 6 - Line-Heaters (0.75 MMBtu/hr max) 

30 - Oil Production Tanks 1 - Gasoline Recycling Pump 

12 - Produced Water Tanks 6 - Electric Lifting Units 

6 - Oil and Gas Producing Wells 1 - Truck Loading Rack 

1 - Manufactured Produced Gas Flare 6 - Diesel Engines 

1 - Manufactured Enclosed Tank Vapor Combustor 

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

wellbore using an electric lifting unit. The emulsion from the wells producing to this site 

is transported in a closed system to individual two-phased separators and then to the 

three-phase separators (heater treaters). The initial two-phase separator reduces the 

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

water. The heater treaters then reduce the pressure closer to ambient pressure and 

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

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

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

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

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

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

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

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

that the gas cannot be placed into the sales line. The oil and water production tank's 

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

North Segment 6-7H Pad pg.2 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 


device. The stored oil is transported for sale via the truck loadout. Produced water is 

stored in the onsite water storage tank until it is transported offsite using the water 

pipeline. 

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

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

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

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

however, the electricity lines have not yet been installed at the facility. Onsile 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. 

• i 

I 

• 

North Segment 6·7H Pad 12/28111 pg. 3 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 

3.0 POTENTIAL TO EMIT ESTIMATE 


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

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

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

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

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

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

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

included in Attachment I of the application. 

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

facility has been approached in a very conservative fashion. The combined production 

rate for the pad assumes all of the wells start production simultaneously (represented in 

example Figure 1). With this assumption, the initial 30-day production from each well is 

summed to estimate a potential total production rate from the pad. Operating practice is 

that the wells will be drilled over time, often months or even years apart. Further, after 

each well is drilled and brought into production, the initial production rate generally 

decreases greatly before the next well is drilled. Therefore, this potential to emit (PTE) 

estimate is meant only to define an outer envelope of emissions for permitting 

applicability purposes. Furthermore, the allowable emissions estimates presented in 

Section 4 are also very conservative compared to anticipated actual emissions that 

could be emitted at the facility during any given 12-month rolling average. An example 

demonstrating the predicted production of a theoretical multiple well pad over an 

extended period of time is presented in Figure 2. This example does not represent 

predicted production from the well pad being permitted in this application; however, it 

does serve to demonstrate typical operations for this type of facility. 

• 

• 

• 

North Segment 6-7H Pad 12/28111 pg.4 

NSR SynthetiC Minor Permit Application 

Project #: WEP211324 
• • • 

•••••••••••••••••••••• 

• ,",.~_.,._. ~_.~,..~~..~~ .. ,".~~, ..,.

....~_.·.,"".~w~._.,,_,~_.~_.,~~~_.. 

Figure 1: Example of Maximum PTE from a Seven Well Pad 

Example of Maximum PTE from a Seven Well Pad 

6,000 

• 	 All seven wells begin 


production
 5,000 simuRaneou:sf\{ 

R'OOO 	 • 

liD •

'" looo •• 

• Total Production from Seven 

f • We'Is on Pad 

i 	 ••• 

2,000 . 	 • .... 

1,000 

o 

o 	 10 20 30 40 

Month 

North Segment 6-7H Pad 12128111 pg.5 

NSR Synthetic Minor Pennit Application 

Project #: WEP211324 
• • • • 

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

Example of Actual Production From a Seven-Well Well Pad 


3,500 


Lt' 6th and 7th wells begin 


production 


3,000 

2,500 

Q 

c.. 

g 

G/ 2,000 

If 

G/ 

5th well begi ns production 

2nd well begins production 

1st well begi ns producti on 

-+-Total Production from Seven Wells on Pad 

~ ---12-Month Rolling Average Oil Production 2:­

..s 1,500 

i -12-Month Rolling Average Oil Production limit 

1,000 

500 

o 

o 5 10 15 20 25 30 35 40 

Month 

North Segment 6-7H Pad 12128111 pg.6 

NSR Synthetic Minor Permit Application 

Project#: WEP211324 
• 


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

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

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

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

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

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

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

for this proposed pad. 

• 

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

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

categories (i.e., emitting units) . 

1. 	 Production Storage Tanks (Oil and Water); 

2. 	 Casing Head Gas (Produced Gas); 

3. 	 Reciprocating Internal Combustion Engines (Recycle Pump Engine and 

Diesel Gensets) 

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

5. 	 Truck Loading 

6. 	 Miscellaneous Fugitive Emissions (Fugitives); 

3.1 Production Storage Tank VOC Emissions 

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

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

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

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

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

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

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

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

such as VOCs, HAPs. GHGs, etc. 

• 

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

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

attachments. 

3.2 Produced Casing Head Gas Emissions 

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

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

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

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

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

residual gas is routed to the onsite utility flare. Furthermore, if the gas sales pipeline 

North Segment 6-7H Pad 12128111 pg. 7 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 

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

as an emergency backup. 

3.3 Reciprocating Internal Combustion or Compression Ignition Engines 

Diesel engines connected to generators provide the facility with electricity. The potential 

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

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

60 Subparts 1111 and ZZZZ emission limits as applicable. 

3.4 Natural Gas External Combustion Unit Emissions 

The natural gas external combustion units at the facility are the heater treater line­

•

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

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

3.5 Truck Loading Emissions 

Oil sales and water pipelines are planned for this facility in the future; however, since 

the pipeline infrastructure has not yet been constructed, the facility is not anticipated to 

be hooked to the oil sales pipeline in the near future, and the produced oil and water will 

be trucked from the facility. The emissions associated with the truck loading operations 

will be estimated using daily production, AP-42 factors, and submerged fill loading 

without any control. 

3.6 Fugitive Emissions: Dust and Equipment Leaks 

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

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

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

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

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

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

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

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

traffic at the location. 

North Segment 6-7H Pad 12/28111 pg.8 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 


4.0 EMISSIONS AND OPERATIONAL LIMITS REQUESTS 


Oatoka-3 is requesting emissions and operational limits at the~~~~ rrtrPad.(i~~7Ier to 

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

federally enforceable permit conditions will allow Oakota-3 to operate the facility while 

emitting less than the PSOlTitle V major source thresholds of 250/100 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, Oakota-3 

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

smokeless combustion device that has been independently tested and certified to 

exceed the requirements of 40 CFR 60.18 at 98% destruction efficiency (ORE). I Although this control device is certified to meet 99% ORE, Oakota-3 will assume the 

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

emissions. This control device will allow Oakota-3 to apply a 98% control effiCiency to 

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

is: 28.01 tons per year of vacs and 0.26 tons per year of HAPs. 

4.2 Reciprocating Internal Combustion or Compression Ignition Engines 

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

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

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

1111 and ZZZZ, as applicable. 

• 

North Segment 6-7H Pad 12/28/11 pg.9 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 

5.0 ALLOWABLE EMISSIONS 


• 

• 

• 

• 

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

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

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

Table E(i) - Proposed New Facility. 

5.1 Storage Tank Emissions 

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

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

emissions are reduced by the smokeless combustion device, CO, NOx, PM, PM1O. PM2.5 

and N20 emissions are created by the combustion process. These emissions estimates 

are calculated using Ap·42 factors and applying the weight percentages of the criteria 

pollutant and greenhouse gas components from a representative gas analysis. 

5.2 Produced Casing Head Gas Emissions 

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

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

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

pressure increases to the point at which the produced casing head gas from the two· 

phased separator cannot be sold or the gas pipeline has a malfunction, the flare serves 

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

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

to emit. 

5.3 RICE Engine Emissions 

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

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

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

emit. 

5.4 Natural Gas External Combustion Unit Emissions 

No limits have been requested for the natural gas external combustion units (0.5·0.75 

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

equal to the uncontrolled potential to emit. 

North Segment 6-7H Pad 12128/11 pg. 10 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
• 


5.5 Truck Loading Emissions 

No limits have been requested for the truck loading operations at the facility; therefore, 

the emissions estimate is equal to the uncontrolled potential to emit. 

5.6 Fugitive Emissions: Dust and Equipment Leaks 

• 

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

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

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

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

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

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

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

5.7 Diesel Storage Tank Emissions 

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

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

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

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

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

summary output is in Attachment J. 

• 


North Segment 6-7H Pad 12/28/11 pg. 11 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
• 

6.0 PROPOSED MONITORING AND RECORDKEEPING 


As per the Application for Synthetic Minor Limit Request (Form SYNMIN), Page 1 (8), 

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

record keeping, and reporting requirements that will be used to demonstrate and assure 

compliance with the proposed allowable emissions. 

6.1 Production Storage Tanks 

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

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

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

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

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

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

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

requested proposed device(s): 

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

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

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

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

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

or an emissions control device; and 

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

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

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

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

Monitoring Requirements: 

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

one of the following methods: 

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

analysis; 

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

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

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

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

4.0.9d to calculate standing/working/breathing losses; 

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

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

f. 	 Other methods approved by EPA. 

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North Segment 6-7H Pad 12/28/11 pg.12 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
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Recordkeeping Requirements: 

In order to demonstrate compliance with the 12-month rOiling emission limits for the oil 

production tanks, Dakota-3 will track facility oil production rates for each month, 

beginning with the first full calendar month after operations commenced. The monthly 

totals will be summed to create a production rate for the prior twelve month rolling 

operating period. As demonstrated in Attachment C of this application, the total VOC, 

total HAP, and any single HAP emissions in tons per year are directly proportional to the 

production rate of oil at the facility. Based upon this relationship, compliance with the 

requested limits in this application will have been maintained if the production rate 

during any twelve month rolling period is less than the production rate used to establish 

the emission limits. 

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

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

6.2 Production Storage Tank Emissions Control Device 

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

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

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

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

the device by at least 98%. 

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

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

ensure good air pollution control practices for minimizing emissions. 

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

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

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

Each enclosed combustion device will be: 

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

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

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

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

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

in °C, or ±2.5 °C; 

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

document the presence of a flame; 

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

alarm and remote notification system if the pilot flame fails; 

f. 	 Maintained in a leak-free condition; and 

g. 	 Operated in a smokeless mode. 

North Segment 6-7H Pad 12/28111 pg.13 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
• 

Monitoring Requirements: 

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

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

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

operations to confirm proper operation as follows: 

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

the continuous ignition of the pilot flame; 

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

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

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

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

d. 	 Measure one other parameter determined during the independent engineering • 

analysis or provide a manufacturer or vendor guarantee; and 

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

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

quarterly. 

Recordkeeping Requirements: 

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

independent engineering analysis or provided to the manufacturer or vendor and 

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

98% reduction requirements. 

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

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

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

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

bypasses or downtimes. 

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

specified in the manufacturer or vendor guarantee or engineering analysis and 

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

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

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

exceeded, and the corrective actions taken or the preventative measures 

adopted to operate the facility within that operating parameter. 

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

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

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

increase the operating time of the pilot flame. 

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

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

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

it was not operational, and the corrective measures taken. 

North Segment 6-7H Pad 12/28111 pg.14 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
• 


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

emanating from an enclosed combustor or utility flare. 

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

include the following: 

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

ii. 	 Date(s) analyses were performed; 

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

iv. Analytical techniques or methods used; 

v. 	 Results of such analyses or measurements; and 

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

• 

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

means that indicates the continuous ignition of the pilot flame; 

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

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

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

operator is on site; at a minimum, quarterly; 

I. 	 Measure one other parameter determined during the independent engineering 

analysis or provide a manufacturer or vendor guarantee; and 

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

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

quarterly. 

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

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

ensure good air pollution control practices for minimizing emissions. 

6.3 Produced Casing Head Gas Emergency Utility Flare 

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

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

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

flare. 

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

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

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

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

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

practices for minimizing emissions. 

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

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

maintained and operated during any time the facility is operating. 

North Segment 6-7H Pad 12/28/11 pg. 15 

NSR Synthetic Minor Permit Application 

PrOject #: WEP211324 

• 
• 

The emergency utility flare will be: 

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

and 40 CFR 63.11. 

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

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

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

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

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

in °C, or ±2.5 °C; 

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

document the presence of a flame; 

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

alarm and remote notification system if the pilot flame fails; • 

g. 	 Maintained in a leak-free condition; and 

h. 	 Operated in a smokeless mode. 

Monitoring Requirements: 

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

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

6.2. 

Recordkeeping Requirements: 

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

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

6.2. 

6.4 RICE Engines 

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

emission standards set forth in 40 CFR 63 Subpart JJJJ or 40 CFR 60 Subparts 1111 and 

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

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

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

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

6.5 Natural Gas-Fired External Combustion Units 

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

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

proposed by Dakota-3. 

North Segment 6-7H Pad 12/28/11 pg.16 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
• 
 I 

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6.6 Truck Loading 

The truck loading rack is designed for submerged filling of the tank trucks. This is 

standard operating procedure. 

Monitoring Requirements: 

The monitoring requirements for truck loading will be estimating the monthly VOC, total 

HAP, and any single HAP emissions from the loadout operations using input 

parameters, equations, and emission factors from AP-42, Fifth Edition, Volume I, 

Chapter 5. 

• Recordkeeping Requirements: 

Total VOC, total HAP, and any single HAP emissions, in tons, from loading operations 

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

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

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

calculated emissions for all previous months since operations commenced, where 

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

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

months and record a new twelve-month total. 

Dakota-3 will keep all input parameters and calculations used to determine the monthly 

emissions. 

6.7 Fugitive Emissions: Equipment Leaks 

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

hydrocarbon service at this facility. 

Work Practice and Operational Requirements: 

• 

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

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

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

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

collect vapors and transport them. 

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

days after the leak is detected. 

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

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

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

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

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

North Segment 6-7H Pad 12/28/11 pg.17 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 I 

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

piece of equipment in hydrocarbon service at this facility. 

Monitoring Requirements: 

a. 	 Dakota-3 will conduct leak detection monitoring on a semi-annual basis. 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 semiannual. 

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

equipment: 

i. Method 21 • 

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

Appendix A-7, Method 21; and 

b) 	If an instrument reading of 10,000 ppm or greater is measured, a leak 

is detected. 

ii. 	 Optical Gas Imaging Instrument 

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

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

Alternative work practice for monitoring equipment leaks; 

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

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

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

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

addition to any observed leaks; and 

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

the instrument manufacturer's operating parameters. 

iii. 	 Operator Developed Inspection Protocol - Best Management Practices 

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

based on best management practices, for leak detection; 

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

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

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

c) 	 The protocol will include the following: 

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

used for leak detection; 

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

description, or diagram showing the location of all equipment in 

hydrocarbon service at the facility, and the required 

recordkeeping for equipment leaks; and 

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

completion of each inspection. 

North Segment 6-7H Pad 12/28/11 pg. 18 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
• 


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Recordkeeping Requirements: 

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

and repairs. 

b. 	 All leak detection inspection records wi" indude. at a minimum, the following 

information: 

i. 	 Date of the inspection; 

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

iii. Findings of the inspection; 

iv. Any corrective action taken; and 

v. 	 Inspector's name and signature. 

6.8 General Recordkeeping Requirements 

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

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

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

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

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

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

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

months and record a new twelve-month total. 

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

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

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

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

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

temperature monitoring, alarm notification, data logging, flowmeter monitoring, etc . 

• 


North Segment 6-7H Pad 12128111 pg.19 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
7.0 QUALITATIVE AIR QUALITY ASSESSMENT 


• 

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.' 

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 (Le., below typical permitting 

thresholds) as demonstrated in Figure 2; therefore, additional ambient impact analysis 

is not warranted. 

North Segment 6-7H Pad 12/28/11 pg.20 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
8.0 ENDANGERED SPECIES ACT 


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• 


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/northdakotafieldotfice/index.htm) and noting the potential 

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

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

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

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

appropriate, with USFWS regarding identification and mitigation of any impacts . 

• 


North Segment 6-7H Pad 12/28/11 pg.21 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 

• 
9.0 NATIONAL HISTORIC PRESERVATION ACT 


• 

• 

• 

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

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

affect cultural resources. 

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

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

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

information from the area immediately surrounding the facility 

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

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

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

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

and any needed mitigation measures for those impacts. 

North Segment 6-7H Pad 12128111 pg.22 

NSR Synthetic Minor Permit Application 

Project #: WEP211324 
• 

ATTACHMENT B: EMISSION INVENTORY 

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Dakota-3 E&P Company. LLC. 

NSR Synthetic Minor Application 

WEP211324 

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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.