October 1, 2011 

Minor NSR Permitting Coordinator 

US EPA Region 8 

1595 Wynkoop Avenue, 8P-AR 

Denver, CO 80202-1129 

RE: Enerplus Resources (USA) Corporation Application for New Construction 

 Sitka/Yellowbird Facility

To Whom It May Concern; 

Enclosed please find the application for new construction for the Enerplus Resources (USA) Corporation 

Sitka/Yellowbird facility. Included in the application for new construction is a synthetic minor limit 

request for the facility requesting federally-enforceable limitations on the facility’s potential to emit. 

An environmental assessment, including an evaluation of endangered species and an archeological 

survey, has been completed for this facility and the final report has been submitted to the attention of 

Mr. Mark Herman of the United States Department of the Interior, Bureau of Indian Affairs in the Great 

Plains Region Office located in Aberdeen, South Dakota. 

As requested, the application contains backup calculations for the various input parameters used in 

calculating the potential to emit for the facility; however, the finalized summary developed by the North 

Dakota Bakken Task Force for the calculation the applicable tank flash emission factor (97.91 standard 

cubic feet per barrel) has not been included in this application at this time as the Task Force has not 

released their final document. Upon release, Enerplus Resources (USA) Corporation will make available 

to the EPA the finalized summary under separate cover. 

If you should have any questions or concerns, please don’t hesitate to contact the undersigned.

Respectfully, 

Tony Lucero 

Enerplus Resources (USA) Operations 

Environment, Health & Safety Coordinator 
Application for New Construction

Sitka/Yellowbird Facility

Prepared For: 

Enerplus Resources (USA) Corporation 

US Bank Tower, 950 17th Street 

Denver, CO 80202 

October 1, 2011 

Prepared By: 

3700 East 41st Avenue 

Denver, CO 80216-6504 

303-289-7520 (Office) 

303-289-7521 (Fax)
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

ii

Table of Contents 

General Facility Information ................................................................................................................................................... 1

Previous Permit Actions.......................................................................................................................................................... 2

Contact Information................................................................................................................................................................ 3

Facility Process Description .................................................................................................................................................... 4

Operating Schedule................................................................................................................................................................. 5

Process Flow Diagram (typ.) ................................................................................................................................................... 6

Type and Quantity of Fuels..................................................................................................................................................... 7

Attachments

Attachment A  Emission Units and Air PollutionͲGenerating Activities

Attachment B  Proposed Emission Controls, Control Efficiencies and Manufacturer Guarantees

Attachment C  Criteria Pollutant Emission Estimates

Attachment D  Criteria Pollutant Emission Supporting Documentation

Attachment E  Qualitative Air Quality Analysis

Attachment F  Synthetic Minor Limit Request

Attachment G  Equipment Specifications and Guarantees
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

1

General Facility Information

1. (a) Company Name

Enerplus Resources (USA) Corporation

(b) Operator Name

Enerplus Resources (USA) Corporation

2. Facility Information

Sitka/Yellowbird

3. Type of Operation

Oil and Gas Production

4.

5.

Portable Source

Temporary Source

Yes

Yes

_No

_No

6. NAICS Code

21111

7. SIC Code

1311

8. Physical Address (home base for portable sources)

North of BIA Road 12 and East of Highway 28.

9. Reservation

Ft. Berthold Reservation

10. County

Dunn County

11. (a) Latitude

TBD

11. (b) Longitude

TBD

12. (a) Quarter Quarter

NE / NW

12. (b) Section

6

12. (c) Township

149N

12. (d) Range

93W

 
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

2

Previous Permit Actions

Provide information for each permit that has been issued to this facility.

Facility Name on the Permit

No previous permit actions for this facility as specified in the EPA Region 8 Application for New Construction, Section B.

Permit Number

Date of the Permit Action

Facility Name on the Permit

N/A

Permit Number

Date of the Permit Action

Facility Name on the Permit

N/A

Permit Number

Date of the Permit Action

 
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

3

Contact Information

Company Contact

Tony Lucero

Title

HSE Coordinator

Mailing Address

US Bank Tower, Suite 220, 950 – 17th Street, Denver, CO 80202Ͳ2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279Ͳ5500

Facsimile Number

(720) 279Ͳ5550

Operator Contact (if different from above)

Same as above.

Title

Mailing Address

Email Address

Telephone Number Facsimile Number

Facility Contact

Lynn Sundby

Title

Senior Foreman

Mailing Address

3911 University Ave., Williston, ND 58801

Email Address

LSundby@enerplus.com

Telephone Number

(406) 774Ͳ3010

Facsimile Number

(720) 279Ͳ5550

Compliance Contact

Tony Lucero

Title

HSE Coordinator

Mailing Address

US Bank Tower, Suite 220, 950 – 17th Street, Denver, CO 80202Ͳ2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279Ͳ5500

Facsimile Number

(720) 279Ͳ5550
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

4

Facility Process Description

Generally, a crude oil reservoir contains not only the oil itself, but saline water and also a dissolved form of natural gas

due to the high pressures of the underground reservoir. Because fluids from a reservoir are under a higher pressure

below ground than at the ground surface, recovery of fluids is initially driven by rock and fluid expansion from reservoir

conditions to surface conditions.After time this pressure source becomes depleted and the well will no longer flow to

surface and an artificial lift, usually in the form of a pump, must be installed to continue production.

Fluids produced at the wellhead(s) are transferred via an underground flowline(s) to various processing units utilized to

separate the fluids into three phases; oil, natural gas, and water. The separator and heater/treater processing units

separate the fluids into the three different process streams. The different fluid densities are used to separate the fluids

and heat is used to make the process more efficient.Descriptions of the elements involved in the crude oil recovery

process are described below:

HighͲPressure Natural Gas

Dissolved natural gas entrained in the wellhead fluids evolves out of solution as the pressure of the fluid decreases.

Additionally, as the wellhead fluid(s) is heated, the natural gas components offͲgas more readily than the heavier oil

and water counterparts. Recovered natural gas is either used as fuel for onsite equipment or transferred to the

natural gas sales line for conveyance to a gas plant for sale.

Crude Oil

Recovered crude oil is separated from the saline water component of the recovered fluids in the heater/treater

processing units and is transferred via underground flowlines to aboveground oil storage tanks. Crude oil is

temporarily stored in these onͲsite containers prior to being transferred to the lease automatic custody transfer

(LACT) unit for conveyance to a refining process plant.

Saline Water

Recovered saline water is similarly separated from the crude oil component of the recovered fluids in

heater/treater processing units and is transferred via an underground flowline(s) to an aboveground storage

tank(s). Recovered water is temporarily stored onͲsite prior to being loaded into tanker trucks for transport and

disposal.

LowͲPressure Natural Gas

In addition to the natural gas recovered from the wellhead fluids as described above, natural gas is also collected

and recovered from offͲgassing that occurs from the crude oil stored in the onͲsite oil storage tanks. This natural

gas is collected in what is called a vent line from the oil storage tanks and water storage tank(s) at the facility. This

additional, lowͲpressure, natural gas is routed to an enclosed combustion device capable of a minimum destruction

removal efficiency of 98%.

Recycle Pump Process

This facility also has a recycle pump(s) that is used to return fluid from the above ground oil and water storage

tanks to the heater/treater in the event the oil or water does not meet quality standards and needs additional

processing.

Upset Conditions

Although a sales line for both the natural gas and crude oil are present at the facility, a condition known as an

“upset” may occur in which the produced and recoverable natural gas cannot be transferred to the natural gas

sales line. In these instances, the highͲpressure natural gas will be routed to a ground pit flare capable of 90%

destruction removal efficiency.
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

5

Operating Schedule

This facility is designed to operate 24 hours a day, 7 days a week for 52 weeks a year.
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

6

Water

Tank Vapors

Produced

Gas

[UPSET]

Separator &

Heater/Treater Oil Tank Oil Tank Oil Tank Water Tank

Recycle

Pump

Oil/Water Recycle

Separator &

Heater/Treater

Oil

Water

Recycle

Pump

Oil Tank Oil Tank Oil Tank Water Tank

Oil/Water Recycle

Lease

Automatic

Custody

Transfer

Unit

Tank

Vapors

Two Well Facility – Pipeline with No VRU

98% LowͲPressure Gas

Combustion Device

90% Destruction Removal

Efficient Pit Flare

Sales Gas Pipeline

Tank

Vapors

Facility Perimeter

Wellhead Pumpjack

Oil/Gas/Water

Oil/Gas/Water

Pumpjack Wellhead

Process Flow Diagram (typ.)
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

7

Type and Quantity of Fuels

The table below details the type and quantity of fuels for each individual piece of equipment, including sulfur content,

that are proposed to be used on a daily, annual and maximum hourly basis.

Equipment Fuel Type Sulfur

Content Max. Hourly Daily Annual

Heater Treater Burner Natural Gas N/A 490 scf/hour 11.76 Mscf/day 4.29MMscf/year

Heater Treater Burner Natural Gas N/A 490 scf/hour 11.76 Mscf/day 4.29 MMscf/year

Recycle Pump Gasoline 30 ppm 0.8 gallons/hour 1.6 gallons/day 20 gallons/year

Recycle Pump Gasoline 30 ppm 0.8 gallons/hour 1.6 gallons/day 20 gallons/year

145 kW Generator Natural Gas N/A 485scf/hour 11.64Mscf/day 4.25 MMscf/year

145 kW Generator Natural Gas N/A 485 scf/hour 11.64 Mscf/day 4.25 MMscf/year

The heater treater burner fuel consumption was calculated using the equipment capacity of 500,000 British thermal

units (Btu), with an assumption of continuous operation using natural gas fuel and an average gross heating value of

approximately 1,020 British thermal units per standard cubic foot (Btu/scf) (APͲ42, Vol. I, Ch 1.4: Natural Gas

Combustion).

The recycle pump fuel consumption was calculated using the actual fuel tank size of 1.6 gallons with an assumed use of

one tank per month.



The generator(s) fuel consumption was calculated by converting the generator size in kilowatts (kW)into Btu per hour,

with an assumption of continuous operation using natural gas fuel and an average gross heating value of approximately

1,020 Btu/scf (APͲ42, Vol. I, Ch 1.4: Natural Gas Combustion).

Engines listed above will meet the applicable emission standards in accordance with published regulatory standards. EPA

emission standard certification(s) of conformity and emission warranties for proposed engines are included in

Attachment G.
Attachment A

Emission Units and Air PollutionͲGenerating Activities

 
Facility Name Hawaii/Maui Facility

Emitting Unit: Emitting Unit:

Unit Type: Unit Type:

Max Rated Design Capacity/Throughput: Max Rated Design Capacity/Throughput:

Emitting Unit: Emitting Unit:

Unit Type: Unit Type:

Max Rated Design Capacity/Throughput: Max Rated Design Capacity/Throughput:

Emitting Unit: Emitting Unit:

Unit Type: Unit Type:

Max Rated Design Capacity/Throughput: Max Rated Design Capacity/Throughput: 145 kW (194HP)/each

Recycle Pump (x2)

Honda Brand or Equivalent

8 HP/each

Sivallis Brand or Equivalent

Generator (x2)

Newage UCI274G or Equivalent

400 bbl/each

Truck Loading

500,000 Btu/each 25 HP

Kohler Brand or Equivalent

See LACT emitting unit description

LACT Pump (Electric - Generator)

N/A - sent through LACT 

Oil/Condensate Tanks (x10)

Welded Steel

Heater Treater Burner(x2)
Attachment B

Proposed Emission Controls, Control Efficiencies, Emission Limits and Monitoring

 
Facility Name Sitka/Yellowbird Facility

Emission Control Type Emission Control Type

Efficiency: Efficiency:

Max Rated Design Capacity/Throughput: Max Rated Design Capacity/Throughput:

Size: Size:

Monitoring: Monitoring:

Note: Manufacturer specifications and guarantees are appended to this permit.

Continuous Pilot Flame N/A

98% 100%

Enclosed Smokeless Combustor Connected to Sales Line

148 mscf/d to 296 mscf/d N/A

Size of combustor will be selected 

based on volume of actual throughtput. N/A
Attachment C

Criteria Pollutant and GHG Emission Estimates

 
Facility:

Sitka/Yellowbird Facility

PTE SYN PTE SYN PTE SYN PTE SYN

Oil/Condensate Tanks 575.07 11.50 5.34 0.11 2.40 2.40 13.05 13.05 N/A N/A N/A N/A N/ATreater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 N/A 0.00 N/A N/ATreater Burner 0.02 0.02 N/A N/A 0.30 0.30 0.26 0.26 N/A N/A N/A 0.02 N/ARICE Engine 2.62 2.62 N/A N/A 3.75 3.75 7.49 7.49 N/A N/A N/A N/A N/ATruck Loading 0.00 0.00 N/A N/APneumatic Pump 0.00 0.00 0.00 0.00Pneumatic Controllers 0.00 0.00 0.00 0.00Glycol Dehydrator 0.00 0.00 0.00 0.00Totals (TPY) 577.71 14.14 5.34 0.11 6.45 6.45 20.80 20.80 0.00 0.00 0.00 0.02 0.00

PTE SYN PTE SYN PTE SYN PTE SYN

Oil/Condensate Tanks 25.59 4,407.47 357.53 7.15 0.12 0.00 8,284.55 4,572.65Treater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Treater Burner 365.25 365.25 0.03 0.03 0.01 0.01 367.63 367.63RICE Engine 1,911.08 1,911.08 0.00 0.00 0.00 0.00 1,911.08 1,911.08Totals (TPY) 2,301.93 6,683.81 357.56 7.18 0.13 0.01 10,563.27 6,851.37

PTE SYN PTE SYN PTE SYN PTE SYN

Oil/Condensate Tanks 2.59 0.05 1.22 0.02 1.01 0.02 0.00 0.00Treater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Totals (TPY) 2.59 0.05 1.22 0.02 1.01 0.02 0.00 0.00

Notes:

aPb, HFCs, PFCs, and SF6 are not created from standard O&G production operations. b No sulfur has been detected in Enerplus wells at this time.

N O2 CO2e

 Green House Gases PTE (TPY)

Emission Summary

Enerplus Resources (USA) Corporation

*PTE column reflects emissions without controls. SYN column reflects post-control emission limits requested under this synthetic minor permit.

Emission Source PTE (TPY)

VOC HAP CO NOx bH2S bH2SO4 bSO2 PM 10 PM 2.5

Emission Source

CO2 CH4

Emission Source

HAP Breakdown

Benzene Toluene Xylenes 2,2,4 Trimethylpentane
Attachment D

Criteria Pollutant and GHG Emission Supporting Documentation
GREEN = Requires input

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

Facility Information

Line 1 Sitka/Yellowbird Facility Name of the facility and the well number.

Line 2 10/1/2011 Submittal Date.

Production Data Description

Line 3 BOPD 3,024 Average daily production in barrels of oil per day (BOPD).

Line 4 Mscfd 2,280 Average daily production of gas in Mscf per day.Line 5 Decline Factor 0.46

Expected decline factor for the first year of operation. Decline factor calculated from Enerplus wells operating in the Bakken formation with greater than 1 year 

of production data - see criteria pollutant emission supporting documentation.

Line 6 Adjusted BOPD 1391.058 This is the calculated BOPD expected to be produced using the above entered decline factor.

Line 7 Adjusted Treater Gas (Mscfd) 1048.8 This is the calculated mcfd of gas the well is expected to produce using the above entered decline factor.

Oil/Condensate Tank Data Description

Line 8 1 EF scf/bbl calculation method.

Line 9 EF scf/bbl 97.91

The scf/bbl from direct measurement or representative sample. EF value of 97.91 scf/bbl calculated by the Bakken VOC task force - see criteria pollutant 

emission supporting documentation.

Line 10 Estimated Tank Vapors (scfd) 136198.5 This is the estimated scfd of tank vapors based on the following: adjusted BOPD multiplied by the scf/bbl entered on Line 9.

Line 11 Lower Heating Value 1,418.50 Lower heating value (Btu/scf) of tank vapors. Estimated from E&P Tank V2 Emission Summary. 

Line 12 Molecular Weight 26.03 Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole). Estimated from E&P Tank V2 Emission Summary.Line 13 VOC% 33.69% VOC weight fraction of the tank vapor gas (C3+). Estimated from E&P Tank V2 Emission Summary.Line 14 HAP% 0.31% HAP weight fraction of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.Line 15 CO %2 0.45% CO2 mole fraction of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.Line 16 CH %4 33.99% CH4 weight fraction of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.Line 17 H2S weight % 0.000% H2S weight percent of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary. Line 18 H2S mole % 0.000% H2S mole percent of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary. Line 19 3 Use the drop down menu to choose the appropriate emission control type.

Line 20 Control Destruction Efficiency 98% Control efficiency of applied control technology.

Treater Gas Data Description

Line 21 Btu/scf 1,473.10 Btu/scf of well stream gas. 

Line 22 Molecular Weight 26.97 Average molecular weight of the well stream gas in lb/lb-mole.Line 23 Specific Gravity 0.931 If necessary to convert specific gravity to molecular weight, enter the specific gravity of the well stream gas.

Line 24 Calculated Molecular Weight 26.97 This is the calculated molecular weight based on the specific gravity entered above. Please enter this number on Line 24.Line 25 VOC% 37.77%

VOC weight fraction of the well stream gas (Note: Weight%, not Mole%). Value from lab gas analysis report - see criteria pollutant emission supporting documentation.

Line 26 HAP% 4.49%

HAP weight fraction of the well stream gas. (Note: Weight%, not Mole%). Value from lab gas analysis report - see criteria pollutant emission supporting documentation.

Line 27 H2S weight % 0.000% H2S weight percent of the well stream gas. Value from lab gas analysis report - see criteria pollutant emission supporting documentation. Line 28 H2S mole % 0.000% H2S mole percent of the well stream gas. Value from lab gas analysis report - see criteria pollutant emission supporting documentation.Line 29 4 Use the drop down menu to choose the appropriate emission control type.

Line 30 Control Destruction Efficiency 100% Control efficiency of applied control technology.

Default Bakken EF

Utility Flare or Other 98% DRE DeviceConnected to Sales Line
GREEN = Requires input

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

Facility Information

Line 1 Sitka/Yellowbird Facility Name of the facility and the well number.

Line 2 10/1/2011 Submittal Date.

Treater Burner(s) Description

Line 32 Total Btu/hr 1,000,000 Total burner rating for the heater treater burner(s) in btu/hr. If there are multiple burners, add the total heat input together.

Line 33 Hours of Operation 8,760 The burner(s) is/are assumed to operate 8,760 hours per year.

Truck Loading Description

Line 34 2 1 Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a LACT, no input values are required in Lines 35-40.

Line 35 2 0 Use the drop down list to choose the appropriate mode of operation. The saturation factor will automatically be selected based on mode of operation.

Line 36 Molecular Weight 0.00 Molecular weight of tank vapors in lb/lb-mole. From AP-42 refer to Table 2 on the Truck Loading tab.

Line 37 Vapor Pressure 0.00 True vapor pressure of liquid loaded, pounds per square inch absolute (psia). From AP-42, please refer to Table 2 on the Truck Loading tab.Line 38 Temperature 0.00 Temperature of bulk liquid loaded in Fahrenheit. Estimated average annual temperature.Line 39 Load Rate (bbl/hr) 0 Load rate of liquid loaded in barrels per hour.

Line 40 Load Time (hrs) 0.00 The time it takes to loadout one load (hrs).

Pneumatic Pumps Description

Line 41 Number of Pneumatic Pumps 0 Number of pneumatic pumps at facility.

Line 42 Hours of Operation 8,760 Hours the pump is in operation annually. Line 43 scf/min 0.50 Pneumatic source consumption rate as per manufacturer data (scf/min).

Line 44 1 Use the drop down menu to choose the appropriate emission control type.Line 45 Control Efficiency 100% Control efficiency of applied control technology.

Pneumatic Controllers Description

Line 46 Number of Pneumatic Controllers 0 Number of pneumatic controllers at facility.

Line 47 Bleed rate (scf/hr) 0.00 Average bleed rate of device (scf/hr).

Glycol Dehydrator Description

Line 48 VOC (TPY) 0.00 VOC emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0). Not applicable to this facility.Line 49 HAP (TPY) 0.00 HAP emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0). Not applicable to this facility.

Oil is sold through LACTSubmerged loading of a clean cargo tankRouted exhaust back into closed loop system
scf/day

Btu/scflb/lb-mole

HAP wt Fraction

CO2 mole Fraction

CH4 wt Fraction

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

VOC: 5,675 scf/hr x 0.002638522 lb-mole/scf x 26.03 lb/lb-mole x 33.69% = 131.29 lb/hr

131.29 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 575.07 TPY

HAP: 5,675 scf/hr x 0.002638522 lb-mole/scf x 26.03 lb/lb-mole x 0.31% = 1.22 lb/hr

1.22 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 5.34 TPY

AP-42 Table 13.5-1a

NOx: 5,675 scf/hr x 1,419 Btu/scf x 1E-06 MMBtu/ Btu x 0.068 = 0.55 lb/hr

0.55 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 2.40 TPY

Sitka/Yellowbird Facility

Oil/Condensate Tanks

Flare Gas Volume 136,199

Lower Heating Value 1418.5

Molecular Weight 26.03

VOC wt Fraction 33.69%

0.31%

98%

0.45%

33.99%
AP-42 

Table 13.5-1a

CO: 5,675 scf/hr x 1,419 Btu/scf x 1E-06 MMBtu/ Btu x 0.370 = 2.98 lb/hr

2.98 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 13.05 TPY

E&P TankV2 Em.Summaryb ∑(Yj * Rj)

cCO2: 5,675 scf/hr x 0.451% + 0.98 x 5,675 scf/hr x 1.55 = 8665.70 scf/hr

8665.70 scf/hr x 0.0026 lb-mole/scf x 44.01 lb/lb-mole = 1006.27 lb/hr

1006.27 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 4407.47 TPY

E&P TankV2 Em.Summaryb

CH4: 5,675 scf/hr x 0.002638522 lb-mole/scf x 16.04 lb/lb-mole x 33.99% = 81.63 lb/hr

81.63 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 357.53 TPY

N O: 2 5,675 scf/hr x 2.2 lb/MMscf x 1E-06 Mmscf/ scf = 0.01 lb/hr

0.01 kg/hr x 2.2046 lbs/kg x 8,760 hr/yr x 0.0005 ton/lb = 0.12 TPY

Notes:aNOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.

575.07 VOC TPY

c CO2 calculated from Subpart W, Eq. W-20 and W-21.

11.50 VOC TPY Controlled

5.34 HAP TPY Uncontrolled0.11 HAP TPY Controlled2.40 NOx TPY

13.05 CO TPY25.59 CO2 TPY Uncontrolled

4,407.47 CO2 TPY Controlled

357.53 CH4 TPY Uncontrolled

7.15 CH4 TPY Controlled0.12 N2O TPY Uncontrolled0.00 N2O TPY

Uncontrolled

Controlled

bCO2 and CH4 percent weight are from E&P Tank V2 Emission Summary.

TOTALS

AP-42 Table 1.4-2
HAP: 5,675 scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.31% = 1.22 lb/hr

1.22 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 5.34 TPY

Benzene: 5,675 scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.15% = 0.59 lb/hr

0.59 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 2.59 TPY

Toluene: 5,675 scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.07% = 0.28 lb/hr

0.28 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 1.22 TPY

Xylenes: 5,675 scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.06% = 0.23 lb/hr

0.23 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 1.01 TPY

2,2,4 Trimethylpentane: 5,675 scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.00% = 0.00 lb/hr

0.00 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 0.00 TPY

Benzene 2.59 TPY UncontrolledBenzene 0.05 TPY Controlled

Toluene 1.22 TPY UncontrolledToluene 0.02 TPY Controlled

Xylenes 1.01 TPY UncontrolledXylenes 0.02 TPY Controlled

2,2,4 Trimethylpentane 0.00 TPY Uncontrolled2,2,4 Trimethylpentane 0.00 TPY Controlled

TOTALS

Sitka/Yellowbird Facility

Oil/Condensate Tanks 

HAP Emission Breakdown
scfd

Btu/scflb/lb-mole

HAP wt fraction

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

VOC: 43,700 scf/hr x 0.002638522 lb-mole/scf x 26.965884 lb/lb-mole x 37.77% = 1174.44 lb/hr

1174.44 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 5144.03 TPY Uncontrolled

HAP 43,700 scf/hr x 0.002638522 lb-mole/scf x 26.965884 lb/lb-mole x 4.49% = 139.64 lb/hr

139.64 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 611.61 TPY Uncontrolled

H2S 43,700 scf/hr x 0.002638522 lb-mole/scf x 26.965884 lb/lb-mole x 0.00% = 0.00 lb/hr

0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 TPY Uncontrolled

SO2 43,700 scf/hr x 0.002638522 lb-mole/scf x 26.97 lb/lb-mole x 0.00% = 0.00 lb/hr

0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 TPY Uncontrolled

AP-42 Table

 13.5-1a

NOx: 43,700 scf/hr x 1,473 Btu/scf x 0.000001 Mmbtu/ Btu x 0.068 lb/MMBtu = 4.38 lb/hr

4.38 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 19.17 TPY

Avg. Molecular Weight 26.97

VOC wt fraction 37.77%

4.49%

100%

Sitka/Yellowbird Facility

Treater Flare

Flare Gas Volume 1,048,800

Lower Heating Value 1473.1
AP-42 Table

 13.5-1a

CO: 43,700 scf/hr x 1,473 Btu/scf x 0.000001 Mmbtu/ Btu x 0.370 lb/MMBtu = 23.82 lb/hr

23.82 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 104.33 TPY

TreaterGas AnalysisSummaryb ∑(Yj * Rj)

dCO2: 43,700 scf/hr x 0.440% + 0.98 x 43,700 scf/hr x 1.56 = 67012.40 scf/hr

43,700 scf/hr x 0.0026385 scf/lb-mole x 44.01 lb/lb-mole = 5074.50 lb/hr

5074.50 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 22226.33 TPY

CH4: 43,700 scf/hr x 1473.1 Btu/scf x 0.000001 Mmbtu/ Btu x 0.0009 kg/MMBtu = 0.06 kg/hr

0.06 kg/hr x 2.2046 lbs/kg x 8760 hr/yr x 0.0005 ton/lb = 0.56 TPY

N O: 2 43,700 scf/hr x 1473.1 Btu/scf x 0.000001 Mmbtu/ Btu x 0.0001 kg/MMBtu = 0.01 lb/hr

0.01 kg/hr x 2.2046 lbs/kg x 8760 hr/yr x 0.0005 ton/lb = 0.06 TPY

Notes:

H2S and SO2 emissions are not typical for wells in the Bakken formation and are NOTE: No emissions because source is routed directly to sales line. therefore not calculated herein. 0.00 VOC TPY

aNOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.

0.00 VOC TPY Controlled

d CO2 calculated from Subpart W, Eq. W-20 and W-21. 0.00 HAP TPY Uncontrolled

0.00 HAP TPY Controlled0.00 H2S TPY Uncontrolled0.00 H2S TPY Controlled0.00 SO2 TPY Uncontrolled0.00 NOx TPY0.00 CO TPY0.00 CO2 TPY Uncontrolled0.00 CO2 TPY Controlled0.00 CH4 TPY Uncontrolled0.00 CH4 TPY Controlled0.00 N2O TPY Uncontrolled0.00 N2O TPY Controlled

Subpart WcSubpart Wc

cCH4 and N O emission factors are from Subpart W, Table C-3. 2

TOTALS

Uncontrolled

bCO2 percent weight is from Treater Gas Analysis.
HAP 43,700 scf/hr x 0.002638522 lb-mole/scf x 26.97 lb/lb-mole x 4.49% = 139.64 lb/hr

139.64 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 611.61 TPY Uncontrolled

Benzene: 43,700 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.27% = 39.46 lb/hr

39.46 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 172.83 TPY

Toluene: 43,700 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.50% = 46.55 lb/hr

46.55 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 203.87 TPY

Xylenes: 43,700 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.72% = 53.63 lb/hr

53.63 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 234.91 TPY

2,2,4 Trimethylpentane: 43,700 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 0.00% = 0.00 lb/hr

0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 TPY

TOTALS Benzene 0.00 TPY Uncontrolled

Benzene 0.00 TPY Controlled

Toluene 0.00 TPY UncontrolledToluene 0.00 TPY Controlled

Xylenes 0.00 TPY UncontrolledXylenes 0.00 TPY Controlled

2,2,4 Trimethylpentane 0.00 TPY Uncontrolled2,2,4 Trimethylpentane 0.00 TPY Controlled

Treater Flare

HAP Emission Breakdown

Sitka/Yellowbird Facility
1,000,000 Btu/hr

AP-42 Table 

1.4-1

EFa

(lb/MMscf)

Avg. Gas Heating Value (Btu/scf)

Avg. Gas Heating Value (Btu/scf)

Sample Gas Heating Value (Btu/scf)

NOx: 1.000 MMBtu/hr x 100.00 / 1020.00 x 1020.00 / 1439.00 = 0.07 lb/hr

0.07 lb/hr x 0.0005 ton/lb x 8760 hr/yr = 0.30 TPY

AP-42 Table 

1.4-1

EFa

(lb/MMscf)

Avg. Gas 

Heating 

Value 

(Btu/scf)

Avg. Gas 

Heating Value 

(Btu/scf)

Sample Gas 

Heating 

Value 

(Btu/scf)

CO: 1.000 MMBtu/hr x 84.00 / 1020.00 x 1020.00 / 1439.00 = 0.06 lb/hr

0.06 lb/hr x 0.0005 ton/lb x 8760 hr/yr = 0.26 TPY

AP-42 Table 

1.4-1

EFa

(lb/MMscf)

Avg. Gas 

Heating 

Value 

(Btu/scf)

Avg. Gas 

Heating Value 

(Btu/scf)

Sample Gas 

Heating 

Value 

(Btu/scf)

VOC: 1.000 MMBtu/hr x 5.50 / 1020.00 x 1020.00 / 1439.00 = 0.00 lb/hr

0.00 lb/hr x 0.0005 ton/lb x 8760 hr/yr = 0.02 TPY

AP-42 Table 

1.4-1

EFa

(lb/MMscf)

Avg. Gas 

Heating 

Value 

(Btu/scf)

Avg. Gas 

Heating Value 

(Btu/scf)

Sample Gas 

Heating 

Value 

(Btu/scf)

PM 10: 1.000 MMBtu/hr x 7.60 / 1020.00 x 1020.00 / 1439.00 = 0.01 lb/hr

0.01 lb/hr x 0.0005 ton/lb x 8760 hr/yr = 0.02 TPY

Burner Rating

Heater Treater Burner

Sitka/Yellowbird Facility
Heater Treater Burner

Sitka/Yellowbird Facility

AP-42 Table 

1.4-2

EFb

(lb/MMscf)

Avg. Gas 

Heating 

Value 

(Btu/scf)

Avg. Gas 

Heating Value 

(Btu/scf)

Sample Gas 

Heating 

Value 

(Btu/scf)

CO2: 1.000 MMBtu/hr x 120,000 / 1020.00 x 1020.00 / 1439.00 = 83.39 lb/hr

83.39 lb/hr x 0.0005 ton/lb x 8760 hr/yr = 365.25 TPY

Subpart Wc

(kg/MMBtu)

CH4: 1.000 MMBtu/hr x 0.003 = 0.00 kg/hr

lb/kg

0.00 kg/hr x 2.205 x 0.0005 ton/lb x 8760 hr/yr = 0.03 TPY

Subpart Wc

(kg/MMBtu)

N O: 2 1.000 MMBtu/hr x 0.0006 = 0.00 kg/hr

lb/kg

0.00 kg/hr x 2.205 x 0.0005 ton/lb x 8760 hr/yr = 0.01 TPY

Notes:aNOx, CO, VOC, PM10 emission factors are from AP-42 Table 1.4-1,Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion.bCO2 emission factor from AP-42 Table 1.4-2, Emission Factors for criteria Pollutant and Greenhouse Gases from Natural Gas Combustion.cCH4 and N O emission factors are from Subpart W, Table C-3. 2

0.02 VOC TPY0.30 NOx TPY0.26 CO TPY

365.25 CO2 TPY

0.03 CH4 TPY0.01 N O TPY 2

TOTALS
Saturation Vapor Molecular Temp + Load Loss

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

12.46 x 0.00 x 0.00 x 0.00 / 460.00 = 0.00

LL Truck Load Load Time

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

0.00 x 0.00 / 0.00 x 42.00 = 0.00

LL Annual Emissions

lb/1,000 gal bbl/yr gal/bbl lb/ton TPY VOC C3+ VOC

0.00 x 507736.32 x 42.00 / 2000.00 = 0.00 0.00

VOC

Emissions

Uncontrolled Control % TPY

0.00 100.00% 0.00 0.00

S Factor

Petroleum Vapor MW

Liquid at 60F

Mv(lb/lb-mole)

40 50 60 70 80 90 100

Crude Oil

RVP 5

Tank Trucks and Rail Tank Cars Submerged loading of a clean cargo tank 0.50

Sitka/Yellowbird Facility

Truck Loadout Emission Calculation

(EPA AP-42 Values) Table 1 below is required to supply the saturation factor variable in the above equation.

Cargo Carrier Mode of Operation

Condensed Liquid

Vapor Density Density True Vapor Pressure, Pva (psi) at various temperatures in F

at 60F at 60F

Submerged loading: dedicated normal service 0.60

Submerged loading: dedicated vapor balance service 1.00

(EPA AP-42 Values) Table 2 below may be used to provide the vapor pressure and molecular weight values for the above equation.

Wvc(lb/gal W1(lb/gal)

50 4.5 7.1 1.8 2.3 2.8 3.4 4 4.8 5.7
Where:

PSCR = Pneumatic Source Consumption Rate (scf/min), as per manufacturers literature

Gas MW = Supply Gas Average Molecular Weight (lb/lb-mole)

Supply Gas MW VOC wt fraction

0.50 scfm/min x 60 min/hr x 0.003 scf/lb-mole x 26.97 x 37.77% = 0.81 lb/hr VOC Uncontrolled

lbs/hr Hours lbs/ton

0.81 x 8760 x 2000 = 0.00 TPY VOC Uncontrolled 

Supply Gas MW HAP wt fraction

0.50 scfm/min x 60 min/hr x 0.003 scf/lb-mole x 26.97 x 4.49% = 0.10 lb/hr HAP Uncontrolled

lbs/hr Hours lbs/ton

0.10 x 8760 x 2000 = 0.00 TPY HAP Uncontrolled

100%

0

0.00 TPY VOC

0.00 TPY HAP

TOTALS

Control Efficiency

Number of Pumps

Sitka/Yellowbird Facility

Emissions from Pneumatic Pumps

Emissions (lb/hr) = PSCR (scf/min) x (60 min/1hr) x (1/379 scf/lb-mole) x (VOC wt. Fraction)

Emissions (TPY) = (lb/hr VOC) x (8760 hr/yr) x (1 ton/2000)
Where:

PSCR = Pneumatic Source Consumption Rate (scf/min), as per manufacturers literature

Gas MW = Supply Gas Average Molecular Weight (lb/lb-mole)

Supply Gas MW VOC wt fraction

0.00 scf/hr x 60 min/hr x 0.002638522 scf/lb-mole x 26.97 x 37.77% = 0.00 lb/hr VOC

lbs/hr Hours lbs/ton

0.00 x 8760 x 2000 = 0.00 TPY VOC

Supply Gas MW HAP wt fraction

0.00 scf/hr x 60 min/hr x 0.002638522 scf/lb-mole x 26.97 x 4.49% = 0.00 lb/hr HAP

lbs/hr Hours lbs/ton

0.00 x 8760 x 2000 = 0.0 TPY HAP

0.00 TPY VOC

0.00 TPY HAP

TOTALS

Sitka/Yellowbird Facility

Emissions from Pneumatic Controllers

Emissions (lb/hr) = PSCR (scf/hr) x (1/379 scf/lb-mole) x (VOC wt. Fraction)

Emissions (TPY) = (lb/hr VOC) x (8760 hr/yr) x (1 ton/2000)
Line 1 Number of Engines 4

RICE Engine #1

Line 2 Hours of Operation 8,760Line 3 Maximum HP Rating 194Line 4 NOx g/hp-hr 1Line 5 CO g/hp-hr 2Line 6 VOC g/hp-hr 0.7Line 7 N O g/hp-hr 2 0.0006Line 8 CO2 g/hp-hr 1.08Line 9 CH4 g/hp-hr 0.003Line 10 NOx Control Efficiency 0%Line 11 CO Control Efficiency 0%Line 12 VOC Control Efficiency 0%

RICE Engine #2

Line 13 Hours of Operation 8,760Line 14 Maximum HP Rating 8Line 15 NOx g/hp-hr 0.011Line 16 CO g/hp-hr 0.00696Line 17 VOC g/hp-hr 0.015Line 18 N O g/hp-hr 2 0.0006Line 19 CO2 g/hp-hr 1.08Line 20 CH4 g/hp-hr 0.003Line 21 NOx Control Efficiency 0%Line 22 CO Control Efficiency 0%Line 23 VOC Control Efficiency 0%

RICE Engine #3

Line 24 Hours of Operation 8,760Line 25 Maximum HP Rating 8Line 26 NOx g/hp-hr 0.011Line 27 CO g/hp-hr 0.007Line 28 VOC g/hp-hr 0.015Line 29 N O g/hp-hr 2 0.0006Line 30 CO2 g/hp-hr 1.08Line 31 CH4 g/hp-hr 0.003Line 32 NOx Control Efficiency 0%Line 33 CO Control Efficiency 0%Line 34 VOC Control Efficiency 0%

Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N O. 2Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N O. 2Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test resManufacturer's maximum hp rating.

ults.

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

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxideManufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).

s (NOx).

Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N O. 2

RICE Input Data

Enter the number of engines that will be installed at the production facility.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.

2.

Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.
RICE Input Data

RICE Engine #4

Line 35 Hours of Operation 8,760Line 36 Maximum HP Rating 194Line 37 NOx g/hp-hr 1Line 38 CO g/hp-hr 2Line 39 VOC g/hp-hr 0.7Line 40 N O g/hp-hr 2 0.0006Line 41 CO2 g/hp-hr 1.08Line 42 CH4 g/hp-hr 0.003Line 43 NOx Control Efficiency 0%Line 44 CO Control Efficiency 0%Line 45 VOC Control Efficiency 0%

RICE Engine #5

Line 46 Hours of Operation 0Line 47 Maximum HP Rating 100Line 48 NOx g/hp-hr 10Line 49 CO g/hp-hr 5Line 50 VOC g/hp-hr 4Line 51 N O g/hp-hr 2 0.0006Line 52 CO2 g/hp-hr 1.08Line 53 CH4 g/hp-hr 0.003Line 54 NOx Control Efficiency 0%Line 55 CO Control Efficiency 0%Line 56 VOC Control Efficiency 0%

Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N O. 2Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N O. 2Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.

Description

Engine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxideManufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).

s (NOx).

Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).
ENGINE #1

194 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE

NOx: 1.00 g/HP-HR 194 HP x 0.002204586 lb / grams = 0.43 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 1.87 NOx TPY Uncontrolled

1.87 NOx TPY Controlled

CO: 2.00 g/HP-HR 194 HP x 0.002204586 lb / grams = 0.86 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 3.75 CO TPY Uncontrolled

3.75 CO TPY Controlled

VOC: 0.70 g/HP-HR 194 HP x 0.002204586 lb / grams = 0.30 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 1.31 VOC TPY Uncontrolled

1.31 VOC TPY Controlled

N O: 2 6.00E-04 kg/mmBtu 3.9E-07 x 194 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 N O TPY Uncontrolled 2

CO2: 1.08 lb/HP-HR 194 HP = 209.52 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 917.70 CO2 TPY Uncontrolled

CH4: 3.00E-03 kg/mmBtu 3.9E-07 x 194 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 CH4 TPY Uncontrolled

ENGINE #2

8 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE

NOx: 0.01 b/HP-HR 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 NOx TPY Uncontrolled

0.00 NOx TPY Controlled

CO: 0.01 lb/HP-HR 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 CO TPY Uncontrolled

0.00 CO TPY Controlled

VOC: 0.02 lb/HP-HR 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 VOC TPY Uncontrolled

0.00 VOC TPY Controlled

N O: 2 6.00E-04 kg/mmBtu 3.9E-07 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 N O TPY Uncontrolled 2

CO2: 1.08 lb/HP-HR 8 HP = 8.64 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 37.84 CO2 TPY Uncontrolled

CH4: 3.00E-03 kg/mmBtu 3.9E-07 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 CH4 TPY Uncontrolled

AP-42, Table 3.3-1aAP-42, Table 3.3-1a

Sitka/Yellowbird Facility

Reciprocating Engine Emissions 

xxxxxxxx

g-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hr

Subpart W, Table C-3bSubpart W, Table C-3b

xxxx

g-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hr

Subpart W, Table C-3bSubpart W, Table C-3b
Sitka/Yellowbird Facility

Reciprocating Engine Emissions 

ENGINE #3

8 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE

NOx: 0.01 lb/HP-HR 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 NOx TPY Uncontrolled

0.00 NOx TPY Controlled

CO: 0.01 lb/HP-HR 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 CO TPY Uncontrolled

0.00 CO TPY Controlled

VOC: 0.02 lb/HP-HR 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 VOC TPY Uncontrolled

0.00 VOC TPY Controlled

N O: 2 6.00E-04 kg/mmBtu 3.9E-07 8 HP x 0.002204586 lb / grams = 4.16E-12 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 N O TPY Uncontrolled 2

CO2: 1.08 lb/HP-HR 8 HP = 8.64 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 37.84 CO2 TPY Uncontrolled

CH4: 3.00E-03 kg/mmBtu 3.9E-07 8 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 CH4 TPY Uncontrolled

ENGINE #4

194 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE

NOx: 1.00 lb/HP-HR 194 HP x 0.002204586 lb / grams = 0.43 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 1.87 NOx TPY Uncontrolled

1.87 NOx TPY Controlled

CO: 2.00 lb/HP-HR 194 HP x 0.002204586 lb / grams = 0.86 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 3.75 CO TPY Uncontrolled

3.75 CO TPY Controlled

VOC: 0.70 lb/HP-HR 194 HP x 0.002204586 lb / grams = 0.30 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 1.31 VOC TPY Uncontrolled

1.31 VOC TPY Controlled

N O: 2 6.00E-04 kg/mmBtu 3.9E-07 194 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 N O TPY Uncontrolled 2

CO2: 1.08 lb/HP-HR 194 HP = 209.52 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 917.70 CO2 TPY Uncontrolled

CH4: 3.00E-03 kg/mmBtu 3.9E-07 194 HP x 0.002204586 lb / grams = 0.00 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 CH4 TPY Uncontrolled

AP-42, Table 3.3-1aAP-42, Table 3.3-1a

xxxxxxxx

Subpart W, Table C-3bSubpart W, Table C-3b g-mmBtu/kg-hp-hr

g-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hr

xxxx

g-mmBtu/kg-hp-hr

Subpart W, Table C-3bSubpart W, Table C-3b
Sitka/Yellowbird Facility

Reciprocating Engine Emissions 

ENGINE #5

100 MAX HP 0% NOx DRE 0% CO DRE 0% VOC DRE

NOx: 10.00 lb/HP-HR 100 HP x 0.002204586 lb / grams = 2.20 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 NOx TPY Uncontrolled

0.00 NOx TPY Controlled

CO: 5.00 lb/HP-HR 100 HP x 0.002204586 lb / grams = 1.10 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 CO TPY Uncontrolled

0.00 CO TPY Controlled

VOC: 4.00 lb/HP-HR 100 HP x 0.002204586 lb / grams = 0.88 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 VOC TPY Uncontrolled

0.00 VOC TPY Controlled

N O: 2 6.00E-04 kg/mmBtu 3.9E-07 100 HP x 0.002204586 lb / grams = 0.00 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 N O TPY Uncontrolled 2

CO2: 1.08 lb/HP-HR 100 HP = 108.00 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 CO2 TPY Uncontrolled

CH4: 3.00E-03 kg/mmBtu 3.9E-07 100 HP x 0.002204586 lb / grams = 0.00 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 CH4 TPY Uncontrolled

Notes:aCO2 Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines (lb/hp-hr) from AP-42 Table 3.3-1, Gasoline Fuel.

b CH4 and N2O Subpart W, Table C-3 of Subpart C - Default CH4 and N2O Emission Factors for Various Types of Fuel.

3.75 NOx TPY Uncontrolled3.75 NOx TPY Controlled7.49 CO TPY Uncontrolled7.49 CO TPY Controlled2.62 VOC TPY Uncontrolled2.62 VOC TPY Controlled0.00 N O TPY 2

1911.08 CO2 TPY

0.00 CH4 TPY

TOTALS

AP-42, Table 3.3-1a

xxxxxx

g-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hr

Subpart W, Table C-3bSubpart W, Table C-3b
Gas Analysis

Mole 

Percent1

Mole 

Fraction

Molecular 

Weight

MW 

Component Wt Fraction

VOC 

Component 

MW

HAP 

Component 

MW

Oxygen 0.000 0.000 32 0 0Nitrogen 6.829 0.068 28.01 1.9128029 0.070549836Carbon Dioxide 0.440 0.004 44.01 0.193644 0.007142164H2S 0.000 0.000 34.08 0 0Methane 53.554 0.536 16.04 8.5900616 0.316826913Ethane 20.536 0.205 30.07 6.1751752 0.227758751Propane 10.970 0.110 44.097 4.8374409 0.178419148 0.863092082i-Butane 1.305 0.013 58.12 0.758466 0.027974472 0.021217686n-Butane 2.392 0.024 58.12 1.3902304 0.051275815 0.071285196i-Pentane 0.524 0.005 72.15 0.378066 0.013944194 0.005271826n-Pentane 1.688 0.017 72.15 1.217892 0.044919464 0.054707056Hexanes+ 0.441 0.004 100.2 0.441381 0.016279439 0.007185435Benzene2 0.441 0.004 78.11 0.34407455 0.012690488 0.004366474 0.004366474Toluene2 0.441 0.004 92.14 0.4058767 0.014969935 0.006075948 0.006075948Xylenes2 0.441 0.004 106.17 0.46767885 0.017249381 0.008067171 0.0080671712,2,4 Trimethylpentane 0.000 0.000 114.23 0 0 0 0Total 100.00 1.00 27.11 1.04 0.02VOC Weight Fraction 0.38HAP Weight Fraction 0.04VOC Weight % 3.84HAP Weight % 0.07

Notes: Bold Items are considered VOCs.1 Mole Percent averaged from three attached Stock Tank Gas Samples.2Averaged mole % from Hexanes+, no extended gas analysis available at this time.

 Treater Gas Analysis Worksheet

Gas Analysis

Mole 

Percent1

Mole 

Fraction

Molecular 

Weight

MW 

Component Wt Fraction VOC Wt. Fraction HAP Wt. Fraction

VOC Component 

MW

HAP Component 

MW

Oxygen 0.000 0.000 32 0 0Nitrogen 7.081 0.071 28.01 1.98324805 0.075900023Carbon Dioxide 0.451 0.005 44.01 0.1984851 0.007596137H2S 0.000 0.000 34.08 0 0Methane 55.367 0.554 16.04 8.8807866 0.339872719Ethane 20.835 0.208 30.07 6.26520478 0.239772926Propane 10.532 0.105 44.097 4.644119652 0.177733082 0.177733082 0.8254137i-Butane 1.114 0.011 58.12 0.64722432 0.02476964 0.02476964 0.016031514n-Butane 1.897 0.019 58.12 1.1025364 0.042194691 0.042194691 0.046521182i-Pentane 0.294 0.003 72.15 0.2118324 0.008106946 0.008106946 0.001717314n-Pentane 0.813 0.008 72.15 0.5862909 0.022437684 0.022437684 0.01315501Hexanes+ 1.525 0.015 100.2 1.5283506 0.058490841 0.058490841 0.089394511Benzene 0.051 0.001 78.11 0.03960177 0.001515582 0.001515582 0.001515582 6.00197E-05 6.00197E-05Toluene 0.020 0.000 92.14 0.01870442 0.000715829 0.000715829 0.000715829 1.33892E-05 1.33892E-05Ethylbenzene 0.0074 0.000 106.17 0.00785658 0.000300676 0.000300676 0.000300676 2.36228E-06 2.36228E-06Xylenes 0.0146 0.000 106.17 0.01550082 0.000593225 0.000593225 0.000593225 9.19548E-06 9.19548E-06224 Trimethylpentane 0.0000 0.000Total 100.00 1.00 26.13 0.34 0.00 0.99 0.00VOC Weight % 3.80HAP Weight % 0.00

Notes: Bold Items are considered VOCs.1 Mole Percent averaged from three attached Stock Tank Gas Samples.

E&P Gas Analysis Worksheet
file:///Q|/Customer%20Records/Enerplus%20-%202390/Consulting/Envir...deral/NSR%20Permit%20Application/Template/Agave-Birdbear%20E&P.txt

******************************************************************************************

* Project Setup Information *

******************************************************************************************

Project File : Q:\Customer Records\Enerplus - 2390\Consulting\Enviro\Air\Federal\NSR Permit Application\Template\Ehtan Hall E&P.ept

Flowsheet Selection : Oil Tank with Separator

Calculation Method : RVP Distillation

Control Efficiency : 98.0%

Known Separator Stream : Low Pressure Oil

Entering Air Composition : No

Date : 2011.09.15

******************************************************************************************

* Data Input *

******************************************************************************************

Separator Pressure : 70.00[psig]

Separator Temperature : 100.00[F]

Ambient Pressure : 14.70[psia]

Ambient Temperature : 70.00[F]

C10+ SG : 0.8100

C10+ MW : 245.66

-- Low Pressure Oil ----------------------------------------------------------------------

 No. Component mol %

 1 H2S 0.0000

 2 O2 0.0000

 3 CO2 0.4400

 4 N2 6.8290

 5 C1 53.5540

 6 C2 20.5360

 7 C3 10.9700

 8 i-C4 1.3050

 9 n-C4 2.3920

 10 i-C5 0.5240

 11 n-C5 1.6880

 12 C6 1.7620

 13 C7 7.7170

 14 C8 8.0790

 15 C9 5.0500

 16 C10+ 43.4390

 17 Benzene 0.3200

 18 Toluene 0.4240

 19 E-Benzene 0.4700

 20 Xylenes 1.0810

 21 n-C6 2.4160

 22 224Trimethylp 0.0000

-- Sales Oil -----------------------------------------------------------------------------

Production Rate : 3024[bbl/day]

Days of Annual Operation : 365 [days/year]

API Gravity : 42.3

Reid Vapor Pressure : 12.10[psia]

******************************************************************************************

* Calculation Results *

******************************************************************************************

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-- Emission Summary ----------------------------------------------------------------------

Item Uncontrolled Uncontrolled Controlled Controlled

 [ton/yr] [lb/hr] [ton/yr] [lb/hr]

Total HAPs 455.060 103.895 9.101 2.078

Total HC 26128.656 5965.447 522.573 119.309

VOCs, C2+ 16397.605 3743.745 327.952 74.875

Page 1---------------------------------------------------------------- E&P TANK

VOCs, C3+ 9533.850 2176.678 190.677 43.534

Uncontrolled Recovery Info.

 Vapor 2.2800 x1E3 [MSCFD]

 HC Vapor 2.1000 x1E3 [MSCFD]

 GOR 753.97 [SCF/bbl]

-- Emission Composition ------------------------------------------------------------------

No Component Uncontrolled Uncontrolled Controlled Controlled

 [ton/yr] [lb/hr] [ton/yr] [lb/hr]

1 H2S 0.000 0.000 0.000 0.000

2 O2 0.000 0.000 0.000 0.000

3 CO2 217.449 49.646 217.449 49.646

4 N2 2172.966 496.111 2172.966 496.111

5 C1 9731.052 2221.701 194.621 44.434

6 C2 6863.754 1567.067 137.275 31.341

7 C3 5087.797 1161.597 101.756 23.232

8 i-C4 709.107 161.897 14.182 3.238

9 n-C4 1207.952 275.788 24.159 5.516

10 i-C5 232.101 52.991 4.642 1.060

11 n-C5 642.338 146.653 12.847 2.933

12 C6 321.585 73.421 6.432 1.468

13 C7 597.310 136.372 11.946 2.727

14 C8 227.434 51.926 4.549 1.039

15 C9 53.069 12.116 1.061 0.242

16 C10+ 0.093 0.021 0.002 0.000

17 Benzene 43.372 9.902 0.867 0.198

18 Toluene 20.492 4.679 0.410 0.094

19 E-Benzene 8.558 1.954 0.171 0.039

20 Xylenes 17.011 3.884 0.340 0.078

21 n-C6 365.630 83.477 7.313 1.670

22 224Trimethylp 0.000 0.000 0.000 0.000

 Total 28519.070 6511.203 570.381 130.224

-- Stream Data ---------------------------------------------------------------------------

No. Component MW LP Oil Flash Oil Sale Oil Flash Gas W&S Gas Total Emissions

 mol % mol % mol % mol % mol % mol %

1 H2S 34.80 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

2 O2 32.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

3 CO2 44.01 0.4400 0.0077 0.0077 0.4510 0.0000 0.4510

4 N2 28.01 6.8290 0.0121 0.0121 7.0805 0.0000 7.0805

5 C1 16.04 53.5540 0.3073 0.3073 55.3665 0.0000 55.3665

6 C2 30.07 20.5360 0.6422 0.6422 20.8354 0.0000 20.8354

7 C3 44.10 10.9700 1.1361 1.1361 10.5316 0.0000 10.5316

8 i-C4 58.12 1.3050 0.3197 0.3197 1.1136 0.0000 1.1136

9 n-C4 58.12 2.3920 0.7771 0.7771 1.8970 0.0000 1.8970

10 i-C5 72.15 0.5240 0.3318 0.3318 0.2936 0.0000 0.2936

11 n-C5 72.15 1.6880 1.2456 1.2456 0.8126 0.0000 0.8126

12 C6 86.16 1.7620 1.9614 1.9614 0.3495 0.0000 0.3495

13 C7 100.20 7.7170 9.8738 9.8738 0.5621 0.0000 0.5621

14 C8 114.23 8.0790 10.8690 10.8690 0.1870 0.0000 0.1870

15 C9 128.28 5.0500 6.8967 6.8967 0.0394 0.0000 0.0394

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16 C10+ 245.66 43.4390 59.7733 59.7733 0.0000 0.0000 0.0000

17 Benzene 78.11 0.3200 0.3731 0.3731 0.0507 0.0000 0.0507

18 Toluene 92.13 0.4240 0.5565 0.5565 0.0203 0.0000 0.0203

19 E-Benzene 106.17 0.4700 0.6370 0.6370 0.0074 0.0000 0.0074

20 Xylenes 106.17 1.0810 1.4681 1.4681 0.0146 0.0000 0.0146

21 n-C6 86.18 2.4160 2.8112 2.8112 0.3873 0.0000 0.3873

22 224Trimethylp 114.24 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

 MW 95.17 186.80 186.80 26.03 0.00 26.03

 Stream Mole Ratio 1.0000 0.4300 0.4300 0.5700 0.0000 0.5700

 Heating Value [BTU/SCF] 1418.50 0.00 1418.50

 Gas Gravity [Gas/Air] 0.90 0.00 0.90

 Bubble Pt. @ 100F [psia] 1999.61 18.91 18.91

 RVP @ 100F [psia] 259.26 5.69 5.69

 Spec. Gravity @ 100F 0.636 0.695 0.695

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Decline Factor Supporting Documentation
The Basis for the 0.6 Factor and How it Relates to 80% Decline in Production for the First Year

The first year daily production rates are represented by the jagged line in BOX 1. The area under the line

represents the total actual production volume for the first year. It is difficult to calculate the total volume

under the jagged line so it is smoothed out in BOX 2 using statistical methods.

BOX 1 BOX 2

 

BOX 3 BOX 4 

The smoothed curve is straightened out in BOX 3, and then leveled out in BOX 4.Now the production for the

first year is represented by the area under the line in BOX 4 which is easily calculated.Production curves from

a large sampling of wells indicate the average well declines by 80% during the first year.That 80% decline is

represented by the level line in BOX 4 after the first 30Ͳday average production rate is multiplied by 0.6.

Example:For the first month the well makes an average 3.333 MMCFD.With 80% decline during the first

year, the well will make 0.667 MMCFD at the end of the first year (3.333 – 0.8(3.333) = 0.667).  Then the

average daily production rate over 365 days is (3.33 + 0.667)/2 = 2.0 MMCFD which is the same as 3.333 x 0.6

= 2.0 MMCFD.

Start Up  365 Days

MMCFD

Actual production during the first year is

represented by the area under the jagged line

which ultimately turns out to be ~730 MMCF.

Start Up  365 Days

The jagged line representing daily production is

“smoothed” out using statistical methods.

Start Up  365 Days Start Up  365 Days

2 MMCFD

Leveled” out, projected daily gas production

rate vs. time

Total projected production for the first year is

represented by the area under the straight line

2 MMCFD x 365 days = 730 MMCF

The “smoothed” curve in BOX 2 is “straightened” out

using mathematical methods.
Decline Over First 12 Months = (1Ͳ12th Month of Production) / (1st Month of Production)

Decline Factor (facilityͲspecific) = Average Production Over 12 Month Period / 1st Month of Production

5. Average the decline factors from each specific facility to obtain a representative decline factor for the formation.

Representative Decline Factor for

the Formation= 0.459026

Burr

Prod_Month BOPD

MarͲ09 6238

AprͲ09 4092

MayͲ09 4104

JunͲ09 3552

JulͲ09 3324

AugͲ09 2854

SepͲ09 2593

OctͲ09 2414

NovͲ09 2162

DecͲ09 2151

JanͲ10 2053

FebͲ10 1775

Decline over the first 12Ͳmonths 0.715454

First Month's Production 6238

Last Month's Production 1775

Average BOPD 3109.333

Decline factor 0.49845

Four Bears

DecͲ08 7473

JanͲ09 3645

FebͲ09 3873

MarͲ09 4167

AprͲ09 3148

MayͲ09 3490

JunͲ09 2820

JulͲ09 2737

AugͲ09 2444

SepͲ09 2291

OctͲ09 1778

NovͲ09 2495

Decline over the first 12Ͳmonths 0.666131

First Month's Production 7473

Last Month's Production 2495

Average BOPD 3363.417

Decline factor 0.450076

Fredericks 5

OctͲ08 11838

NovͲ08 4545

DecͲ08 5793

JanͲ09 5012

FebͲ09 3909

MarͲ09 3706

AprͲ09 3573

MayͲ09 3334

JunͲ09 3042

JulͲ09 2886

AugͲ09 2762

SepͲ09 2465

Decline over the first 12Ͳmonths 0.791772

First Month's Production 11838

Last Month's Production 2465

Average BOPD 4405.417

Decline factor 0.372142

The decline factor was determined by following the method described in Appendix E of the North Dakota Air Pollution Control Permitting

& Compliance Guidance. The following steps outline the calculations used to determine the decline factor:

1. For each month of the first 12 months of production, sum the production data to calculate a monthly total.

2. Calculate a decline in production over the first 12 months by applying the following formula:

SUMMARY

3. Calculate an average of the production data over the 12 month period.

4. Calculate the decline factor for that facility by applying the following formula:

Enerplus Resources (USA) Corporation

Decline Factor Calculation

0

1000

2000

3000

4000

5000

6000

7000

FebͲ09 MarͲ09 MayͲ09 JulͲ09 AugͲ09 OctͲ09 DecͲ09 JanͲ10

0

1000

2000

3000

4000

5000

6000

7000

8000

SepͲ08 DecͲ08 MarͲ09 JulͲ09 OctͲ09 JanͲ10

0

2000

4000

6000

8000

10000

12000

14000

SepͲ08 OctͲ08 DecͲ08 FebͲ09 MarͲ09 MayͲ09 JulͲ09 AugͲ09 OctͲ09
Enerplus Resources (USA) Corporation

Decline Factor Calculation

Fredericks 6

MarͲ09 6852.7

AprͲ09 4388

MayͲ09 5106

JunͲ09 4388

JulͲ09 3549

AugͲ09 3073

SepͲ09 2812

OctͲ09 2570

NovͲ09 2318

DecͲ09 1735

JanͲ10 2307

FebͲ10 1739

Decline over the first 12Ͳmonths 0.746231

First Month's Production 6852.7

Last Month's Production 1739

Average BOPD 3403.142

Decline factor 0.496613

Tekakwitha

MayͲ08 12498

JunͲ08 6761

JulͲ08 6635

AugͲ08 7139

SepͲ08 5283

OctͲ08 4743

NovͲ08 3854

DecͲ08 4039

JanͲ09 3649

FebͲ09 2938

MarͲ09 3614

AprͲ09 2964

Decline over the first 12Ͳmonths 0.762842

First Month's Production 12498

Last Month's Production 2964

Average BOPD 5343.083

Decline factor 0.427515

Voigt 11

AugͲ08 8107.6

SepͲ08 4929

OctͲ08 3423

NovͲ08 6889

DecͲ08 4670

JanͲ09 3979

FebͲ09 3129

MarͲ09 3220

AprͲ09 2823

MayͲ09 2857

JunͲ09 2562

JulͲ09 2464

Decline over the first 12Ͳmonths 0.696088

First Month's Production 8107.6

Last Month's Production 2464

Average BOPD 4087.717

Decline factor 0.504183

Voigt 21

JulͲ08 16424

AugͲ08 4804

SepͲ08 8111

OctͲ08 7384

NovͲ08 5169

DecͲ08 5160

JanͲ09 4610

FebͲ09 3619

MarͲ09 3903

AprͲ09 3336

MayͲ09 3419

JunͲ09 3120

Decline over the first 12Ͳmonths 0.810034

First Month's Production 16424

Last Month's Production 3120

Average BOPD 5754.917

Decline factor 0.350397

0

1000

2000

3000

4000

5000

6000

7000

8000

FebͲ09 MarͲ09 MayͲ09 JulͲ09 AugͲ09 OctͲ09 DecͲ09 JanͲ10 MarͲ10

0

2000

4000

6000

8000

10000

12000

14000

AprͲ08 JunͲ08 JulͲ08 SepͲ08 OctͲ08 DecͲ08 FebͲ09 MarͲ09 MayͲ09

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

JunͲ08 JulͲ08 SepͲ08 OctͲ08 DecͲ08 FebͲ09 MarͲ09 MayͲ09 JulͲ09 AugͲ09

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

JunͲ08 JulͲ08 SepͲ08 OctͲ08 DecͲ08 FebͲ09 MarͲ09 MayͲ09 JulͲ09
Enerplus Resources (USA) Corporation

Decline Factor Calculation

Woman Creek

MayͲ09 6123

JunͲ09 4204

JulͲ09 4558

AugͲ09 3452

SepͲ09 3379

OctͲ09 3092

NovͲ09 2572

DecͲ09 2494

JanͲ10 2296

FebͲ10 1949

MarͲ10 2030

AprͲ10 1810

Decline over the first 12Ͳmonths 0.704393

First Month's Production 6123

Last Month's Production 1810

Average BOPD 3163.25

Decline factor 0.516618

TSB

JulͲ09 17132.67

AugͲ09 13068.9

SepͲ09 10498.9

OctͲ09 7647.33

NovͲ09 9522.55

DecͲ09 7606.9

JanͲ10 4596.83

FebͲ10 8671.98

MarͲ10 7834.86

AprͲ10 6425.9

MayͲ10 6638.86

JunͲ10 6283.47

Decline over the first 12Ͳmonths 0.633246

First Month's Production 17132.67

Last Month's Production 6283.47

Average BOPD 8827.429

Decline factor 0.51524

0

1000

2000

3000

4000

5000

6000

7000

MarͲ09 MayͲ09 JulͲ09 AugͲ09 OctͲ09 DecͲ09 JanͲ10 MarͲ10 MayͲ10

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

MayͲ09 JulͲ09 AugͲ09 OctͲ09 DecͲ09 JanͲ10 MarͲ10 MayͲ10 JunͲ10
Enerplus Resources (USA) Emission Calculator Supporting Documentation
i

Table of Contents 

Introduction .................................................................................................................................................. 1

Unique Issues with Bakken Pool VOCs.......................................................................................................... 1

Potential to Emit ...........................................................................................................................................1

Emission Factors ...........................................................................................................................................1

Regulated Air Pollutant Sources ................................................................................................................... 2

Emission Calculation .....................................................................................................................................2

Emission Calculation Procedure.................................................................................................................... 2

Production Data ........................................................................................................................................2

Decline Factor Calculation Steps........................................................................................................... 3

Oil/Condensate Tank Data ........................................................................................................................ 3

Treater Gas Data .......................................................................................................................................4

Treater Burner(s) Data .............................................................................................................................. 5

Smokeless Combustion Devices (Flares)................................................................................................... 6

Truck Loading Data ...................................................................................................................................7

Pneumatic Pumps Data............................................................................................................................. 9

Pneumatic Pump Controls .................................................................................................................... 9

Pneumatic Controllers Data.................................................................................................................. 9

Glycol Dehydrator Data............................................................................................................................. 9

Calculating Glycol Dehydrator Emissions.............................................................................................. 9

Glycol Dehydrator Control Threshold ................................................................................................. 10

Glycol Dehydrator Controls................................................................................................................. 10

Glycol Dehydrator Federal Regulations.............................................................................................. 10

RICE Data Input .......................................................................................................................................10

Federal Regulations for RICE............................................................................................................... 11

Gas Analysis Worksheet Input ................................................................................................................ 11

E&P Tanks v2.0 Input .............................................................................................................................. 12
ii

Acronyms and Abbreviations 

APͲ42   EPA Publication APͲ42, Compilation of Air Pollutant  

 Emission Factors (5th Edition)

bbl    barrel

BOPD    barrels of oil per day

BTEX    benzene/toluene/ethylͲbenzene/xylenes

Btu    British thermal unit

Btu/hr    Btu per hour

CO    carbon monoxide

DRE    destruction and removal efficiency

EF    emission factor

Enerplus  Enerplus Resources (USA) Corporation

EPA    Environmental Protection Agency

gpm    gallons per minute

H2S    hydrogen sulfide

HAP    hazardous air pollutants

hp    horsepower

lb    pound

lb/lbͲmole   pound per pound mole

LACT    Lease Automatic Custody Transfer

MMBtu   one million Btu

MMscf   one million standard cubic feet (scf × 106)

MMscfd 1,000,000 scf per day

Mscf    one thousand standard cubic feet (scf × 1000)

Mscfd   1000 scf per day

NDDoH   North Dakota Department of Health

NESHAP   National Emission Standards for Hazardous Air Pollutants

NOx    nitrogen oxides

NSCR    NonͲSelective Catalytic Reduction
iii

NSPS    New Source Performance Standards

O&G    Oil and Gas

PSD    Prevention of Significant Deterioration

psig    pounds per square inch gauge

psia    pounds per square inch absolute

PTE    potential to emit

RICE    reciprocating internal combustion engine

scf    standard cubic foot

scf/bbl   standard cubic foot per barrel

SO2    sulfur dioxide

S/W/B    standing/working/breathing losses

TEG   triͲethylene glycol

Title V    Title V of the Clean Air Act Amendments of 1990

TOC    total organic compounds

TPY    tons per year

VOC    volatile organic compounds
1

Introduction

The following pages explain the emission calculation methods applied to Oil and Gas (O&G) production facilities on the

Ft. Berthold Indian Reservation that fall into one of the following categories:

a) Existing, unpermitted (Part 49) facilities seeking synthetic minor limits; or 

b) The construction of a new facility.

The permitting official should note that emissions associated with the exploration and production of O&G resources

cannot be predicted with any degree of precision or accuracy until after it is determined the oil or gas well will actually

produce and site specific production data are collected and known. Therefore, unlike other stationary sources for which

projected emissions upon startup can be estimated in advance for purposes of preͲconstruction air permitting,

emissions from O&G exploration and production facilities are only known postͲconstruction and completion. This

situation is unique to O&G exploration and production facilities and, therefore, requires a practical regulatory response.

To accommodate the need for registration preͲconstruction Enerplus Resources (USA) Corporation (Enerplus) has taken

a conservative approach to emission calculations for the startͲup of new exploration and production facilities, and the

modification of existing facilities.

Applied control technologies have been referenced within this document for tank emissions and emissions from treater

flares. Emissions from other sources such as vehicle miles traveled, fugitive equipment leaks, truck loading, etc. are also

included in the calculations.

Unique Issues with Bakken Pool VOCs

The composition of crude oil from the Bakken Pool (defined as wells in the Bakken, Sanish and Three Forks formations)

typically contains a high amount of lighter end components which have the potential to produce increased volumes of

flash emissions. The North Dakota Department of Health (NDDoH)ͲBakken VOC Task Force and industry have created

Bakken default values based on Bakken production wells which have been utilized in instances where siteͲspecific data is

unavailable.

Potential to Emit

The federal regulations define "potential to emit" as:

“The maximum capacity of a stationary source to emit a pollutant under its physical and operational

design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including

air pollution control equipment and restrictions on hours of operation or on the type or amount of fuel

combusted, stored or processed, shall be treated as part of its design if the limitation or the effect it

would have on emissions is federally enforceable.”

The PTE of VOCs, HAPs and other pollutants associated with oil and gas production have been calculated preͲcontrol for

determining source status. Post control emissions are also included to prove source ability to meet synthetic minor limit.

Emission Factors

Emission factors relate the quantity of a pollutant released to an activity or production associated with the release of the

pollutant. Emission factors for engine emitting units have been obtained from the manufacturer documents. Additional

emission factors were taken from the U. S. Environmental Protection Agency’s (EPA) Office of Air Quality Planning and

Standards (OAQPS) APͲ42 emission factors. The APͲ42 is maintained by the Emission Factor and Inventory Group (EFIG)

and can be found online at the EPA’s Clearinghouse for Inventories & Emissions Factors (CHIEF):

http://www.epa.gov/ttn/chief/ap42/index.html.
2

The EPA’s CHIEF website (http://www.epa.gov/ttn/chief/index.html) contains information on and links for emissions

inventories, emissions factors, emissions modeling, and emissions monitoring.

Regulated Air Pollutant Sources

When calculating facility emissions, each potential emitting unit located on the facility was considered to determine

source potential to emit.Generally, the following are the most common emission sources and the type of regulated air

pollutants they may emit at a typical O&G production facility:

a) Oil/Condensate Tanks – VOC, HAP, H2S (NOx, CO, SO2 when controlled)

b) Treater Flares – VOC, HAP, NOx, CO, H2S, SO2

c) Heaters/Burners – VOC, HAP, NOx, CO, SO2

d) Truck Loading – VOC, HAP

e) RICE Engines – VOC, HAP, NOx, CO

f) Pneumatic Pumps – VOC, HAP

g) Pneumatic Controllers – VOC, HAP

Emission Calculation

A facility’s emissions are calculated in an Excel workbook. The spreadsheet will serve two functions in that it will provide

a simple way of calculating facilityͲwide emissions, as well as insuring that emissions are calculated in a manner similar

to those currently applied in states bordering the facility locations.

The Enerplus Emission Calculations Workbook contains the following 10 tabs:

a) Input – The necessary data to perform calculations applied throughout the workbook shall be entered on this

tab.

b) RICE Input – The necessary data to perform the required calculations for RICE shall be entered on this tab.

c) Emission Summary – The calculated emissions are summarized by source and pollutant on this tab.

1) Oil/Condensate Tanks – The tank vapor emissions are calculated here.

2) Equipment Leaks – Connector, flange, and valve leaks are calculated here.

3) Treater Flare – The treater flare emissions are calculated here.

4) Treater Burner – The treater burner emissions are calculated here.

5) Truck Loading – The truck loading emissions are calculated here.

6) RICE – The RICE emissions are calculated here.

7) Pneumatic Pump – The pneumatic pump emissions are calculated here.

8) Pneumatic Controllers –The pneumatic controller emissions are calculated here.

Emission Calculation Procedure

The calculation workbook was completed per the detailed process below:

Production Data

Line 3: New wells: the average daily production for a facility that has not been producing shall be calculated by applying

a conservative estimation based on an average from owner/operator wells that have production data for a year or more.

Existing wells: the average daily production in BOPD shall be calculated based on the most recent year of production.
3

Line 4: New wells: the average daily production for a facility that has not been producing shall be calculated of gas in

Mscf per day, based on an average from owner/operator wells that have been in production for a year or more. Existing

wells: enter the average daily production in Mscf, based on the most recent year of production.

Line 5: New wells: enter 0.46 on this line (See calculation in Appendix D). Existing wells that have produced for more

than 18 months shall use a decline factor of 1.

Decline Factor Calculation Steps

1) For each month of the first 12 months of production, sum the production data to calculate a monthly total.

2) Calculate a decline in production over the first 12 months by applying the following formula:

Decline Over First 12 Months = (1Ͳ12th Month of Production)/ (1st Month of Production)

3) Calculate an average of the production data over the 12 month period.

4) Calculate the decline factor for that facility by applying the following formula:

Decline Factor (facilityͲspecific) = Average Production Over 12 Month Period/ 1st Month of Production

5) Average the decline factors from each specific facility to obtain a representative decline factor for the

formation.

For further detail on decline factor calculation see Appendix D.2.

Line 6: The predetermined first year average daily oil production rate (BOPD) which is calculated by multiplying the

average daily rate entered on Line 3 by the decline factor entered on Line 5.

Line 7: The predetermined first year average daily gas production rate (Mscfd) which is calculated by multiplying the

average daily rate entered on Line 4, by the decline factor entered on Line 5.

Oil/Condensate Tank Data

Emissions from storage tanks that store crude oil (or other process condensate) include flashing losses, working losses,

and breathing losses. Vapors containing regulated pollutants are released from solution in hydrocarbon liquids as the

liquids are transferred from higher pressure vessel (separator) to lower pressure vessel (storage tank). These vapors are

called flashing losses. Vapors escaping from hydrocarbon liquids while they are stored in atmospheric tanks are called

standing/working/breathing (S/W/B) losses. Standing losses are essentially evaporation losses. Working losses are those

caused by decreased/increased tank vapor space occurring as the tank is filled/emptied. Breathing losses are those

promoted by daily ambient changes in air temperature and barometric pressure. Flashing losses are normally greater

than the working and breathing vapor losses. Oil/Condensate Tank emissions include all S/W/B losses and flashing

emissions.

The workbook calculates the tank emissions by using either an actual direct measurement (scf/bbl), a representative

average or by using the Bakken Pool emission factor of 97.91 scf/bbl. In addition to the scf/bbl value, the workbook uses

the molecular weight, lower heating value of the fuel and the VOC, HAP, CH4, and CO2 weight fractions of the tank

vapors to calculate the tank vapor emissions.

Line 8: The appropriate flash gas method is selected using the drop down box, determining the applicable tank vapor

emission factor (scf/bbl).

1) Default Bakken EF.

2) Site Specific Direct Measurement.

3) Representative Average.
4

Line 9: Enter the scf/bbl EF based on the method chosen on Line 8.

1) Default NDDoH Bakken EF: If site specific data is not available, the default Bakken EF of 97.91 scf/bbl shall be

applied.

2) Direct Measurement: If site specific direct measurements have been taken, the measured scf/bbl EF determined

from direct measurement is applied.

3) Representative average: The representative average scf/bbl.

Line 10: This value is calculated by multiplying the adjusted BOPD value on Line 6, by the scf/bbl entered in Line 9.

Line 11: The lower heating value (Btu/scf) of site tank vapors. Taken from E&P Tank V2 Emission Summary.

Line 12: Enter the molecular weight of the tank vapors in pounds per poundͲmole (lb/lbͲmole), taken from E&P Tank V2

Emission Summary.

Line 13: The tank vapor gas (C3+) VOC weight fraction. Taken from E&P Tank V2 Emission Summary.

Line 14: The tank vapor gas HAP weight fraction. Taken from E&P Tank V2 Emission Summary.

Line 15: The tank vapor gas CO2 weight fraction. Taken from E&P Tank V2 Emission Summary.

Line 16: The tank vapor gas CH4 weight fraction. Taken from E&P Tank V2 Emission Summary.

Line 17: The H2S weight percent of the tank vapors. Taken from E&P Tank V2 Emission Summary.

Line 18: The H2S mole percent of the tank vapors. Taken from E&P Tank V2 Emission Summary.

Line 19: The drop down menu is used to select the technology applied to destruct tank vapors, the options are:

1) Vapor Recovery Unit or Oil Stabilizer

2) Enclosed Smokeless Combustor

3) Utility Flare or Other 98% DRE Device

4) Ground Pit Flare or other 90% DRE device

Line 20: Destruction efficiency is based on the control type selected on Line 19.

1) Vapor Recovery Unit or Oil Stabilizer = 99% DRE

2) Enclosed Smokeless Combustor = 98% DRE

3) Utility Flare or Other 98% DRE Device = 98% DRE

4) Ground Pit Flare or other 90% DRE device = 90% DRE

Treater Gas Data

The treater flare emissions are calculated within the Enerplus Emission Calculation Workbook using the following:

1) The projected first year average daily gas production rate. This is calculated by multiplying the average daily rate

entered on Line 4, by the decline factor entered on Line 5.

2) VOC, HAP, CH4, and CO2 weight fraction of the treater gas.

3) H2S mole percent of the treater gas.

4) Lower heating value of the treater gas.

5) Average molecular weight of the treater gas
5

6) NOx & CO emissions are based on APͲ42 emission factors for industrial flares.

Treater gas shall be routed to a gas gathering pipeline as soon as practicable. When a pipeline is not available, treater

gas shall be routed to a control system or device.

Line 21: Enter the site specific Btu/scf of the well stream gas.

Line 22: Enter the average molecular weight of the well stream gas in lb/lbͲmole.

Line 23: If it is necessary to convert specific gravity to molecular weight, enter the specific gravity of the well stream gas.

Line 24: This is the calculated molecular weight of the well stream gas based on the specific gravity entered on Line 23.

Enter this value on Line 22.

Line 25: Enter the VOC weight fraction of the well stream gas (C3+). Note that this is the weight percent, not the mole

percent of the gas.

Line 26: Enter the HAP weight fraction of the well stream gas. Note that this is the weight percent, not the mole percent

of the gas. A complete list of HAPs is located at http://www.epa.gov/ttn/atw/orig189.html.

Line 27: Enter the H2S weight percent of the well stream gas.

Line 28: Enter the H2S mole percent of the well stream gas.

Line 29: Use the drop down menu to select the type of device used to destruct the well stream gas from the following

options:

1) Enclosed Smokeless Combustor

2) Utility Flare or other 98% DRE Device

3) Ground Pit Flare or other 90% DRE device

4) Connected to Sales Line

Line 30: No input required. This is a fixed destruction efficiency based on the control type selected on Line 29.

1) Enclosed Smokeless Combustor = 98% DRE

2) Utility Flare or Other 98% DRE Device = 98% DRE

3) Ground Pit Flare or other 90% DRE device = 90% DRE

4) Connected to Sales Line = 100% DRE

Treater Burner(s) Data

Lines 31Ͳ32: Emission estimates for natural gas burners, such as those found on heater/treaters or some flares, are

typically calculated using APͲ42 emission factors. The APͲ42 factors can be found at

http://www.epa.gov/ttn/chief/ap42/ch01/index.html in Section 1.4, Natural Gas Combustion.

Natural gas burner emissions can be estimated using the following equation:

  ̧

1

·  ̈

©

§  u u

u u u

u u u 100

100

10 2000

100

10 Pr

6

6 DRE

HV

HV

HV

B

EF BR HO E

Avg

od

Avg

EFF

X

X  

where:
6

EX = emissions for pollutant X (tpy);

EFX = emission factor for pollutant X (lb/MMscf);

BR = burner rating (MMBtu/hr);

BEff = burner efficiency (%);

HO = annual hours of operation (hr/yr);

HVAvg = average gas heating value (Btu/scf);

HVProd = produced gas heating value (Btu/scf);

DRE = destruction and removal efficiency (%);

1Ͳton = 2000Ͳlb;

1ͲMMBtu = 106

ͲBtu; and

1ͲMMscf = 106

Ͳscf.

Potential emissions must be calculated based on 8,760Ͳhrs/yr and using the manufacturer's maximum rated design

capacity of the burner. If the burner efficiency in not known, a value no greater than 80% may be assumed. For

uncontrolled emissions, the DRE is zero.

Some of the byproducts of natural gas combustion in process heaters, boilers, burners, etc. are regulated air pollutants.

NOx, CO, VOC, HAP & SO2 emissions from process unit heaters are calculated within the Oil & Gas Facility Emission

Calculation Workbook using the emission factors (EF) below from EPA APͲ42, Tables 1.4Ͳ1, 1.4Ͳ2 and 1.4Ͳ3:

Table 1.4Ͳ1 Emission Factors from Natural Gas Combustion (Excerpt from APͲ42, Tables 1.4Ͳ1, 1.4Ͳ2 and 1.4Ͳ3)

Pollutant Natural Gas EF*

NOx 100 lb/MMscf

CO 84 lb/MMscf

VOC 5.5 lb/MMscf

HAPS 1.89 lb/MMscf

*Based on an average heating value of 1020 Btu/scf of natural gas.

Line 31: Enter the total burner rating for the treater burner(s) in Btu/hr. If there are multiple burners at the facility,

enter the total heat input of all burners.

Line 32: The burner(s) is/are assumed to operate 8,760 hours per year.

Smokeless Combustion Devices (Flares)

Emissions from a smokeless combustion device (e.g., flare) can be estimated using the following methods. Emission

factors for estimating NOX, CO, and total organic compounds (TOC) emissions can be found in APͲ42 Chapter 13.5:

Miscellaneous Sources – Industrial Flares (see http://www.epa.gov/ttn/chief/ap42/ch13/index.html).

If the flared gas composition is not known, VOC emissions may be estimated using the TOC emission factor in the above

table. Calculations must be performed assuming TOC concentration is equivalent to total VOC concentration. NOX, CO,

and VOC flare emissions can be estimated using the following equation:
7

2000

EF FC HV E X

X

u u  

where:

EX = emissions for pollutant X (tpy);

EFX = emission factor for pollutant X (lb/MMBtu);

FC = fuel consumption (MMscf/yr);

HV = fuel heating value (Btu/scf); and

1Ͳton = 2000Ͳlb.

The fuel consumption (FC) can be calculated using the equation:

24

DPR HO FC GAS u  

where:

FC = fuel consumption (MMscf/yr);

DPRGAS = maximum daily gas production rate (MMscf/day);

HO = annual hours of operation (hr/yr); and

1Ͳday = 24Ͳhours.

The produced gas flare emissions must be estimated using uncontrolled emissions calculations based on venting the

maximum daily production capacity for 8760Ͳhrs/yr. 

Truck Loading Data

Lines 32Ͳ38: Loading losses occur as hydrocarbon vapors in the empty tank are displaced to the atmosphere as the

stored oil is loaded into the tank. Methods and emission factors for estimating tank loading losses may be found in APͲ

42 Chapter 5.2 – Transportation and Marketing of Petroleum Liquids (see

http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf). The oil production rate used to calculate potential truck

loading loss emissions should be a daily maximum production rate not expected to be exceeded during normal

operation. The equation for estimating loading loss is:

460

12.46



u u u

T

S P M LL  

where:

LL = loading loss per 1000 gallons of liquid loaded (lb/1000Ͳgal);

S = saturation factor (unitless) (APͲ42, Table 5.2Ͳ1);

P = true vapor pressure of liquid loaded (psia) (APͲ42, Table 7.1Ͳ2);

M = molecular weight of tank vapors (lb/lbͲmole) (APͲ42 Table 7.1Ͳ2); and
8

T = temperature of bulk liquid loaded (°F) (oR = oF + 460).

VOC emissions resulting from truck loading losses can be estimated using the following equation:

2000

u u 365u 42 L OIL

X

L DPR E  

where:

EX = emissions for pollutant X (tpy);

LL = loading loss per 1000 gallons of liquid loaded (lb/1000Ͳgal);

DPROIL = maximum daily oil production rate (bbl/day);

1Ͳyear = 365Ͳdays;

1Ͳbbl = 42Ͳgallons; and

1Ͳton = 2000Ͳlb.

Table 5.2Ͳ1 Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses (Excerpt from APͲ42, Table 5.2Ͳ1)

Tank Truck: Mode of Operation* S Factor

Submerged loading of a clean cargo tank 0.50

Submerged loading: dedicated normal service 0.60

Submerged loading: dedicated vapor balance service 1.00

Table 7.1Ͳ2 Properties of Selected Petroleum Liquids (Excerpt from APͲ42, Table 7.1Ͳ2)

Petroleum

Liquid

Crude Oil

RVP 5

Vapor MW at 60 F

MV(lb/lbͲmole)

50

Condensed Vapor Density

at 60F WVC(lb/gal)

4.5

Liquid Density at

60F WL(lb/gal)

7.1

True Vapor Pressure, Pva (psi)

at various temperatures in F

40 50 60 70 80 90 100

1.8 2.3 2.8 3.4 4.0 4.8 5.7

O&G production facilities are not required to route emissions displaced from truck loading activities to a control system

or device due to safety concerns.

Line 33: Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a Lease Automatic

Custody Transfer, no input values are required in Lines 34Ͳ39.

Line 34: Use the drop down list to choose the appropriate mode of operation. The saturation factor will automatically be

selected based on mode of operation.

Line 35: Enter the molecular weight of tank vapors, lb/lbͲmole. If no site specific data is available, please refer to Table 2

on the Truck Loading tab.

Line 36: Enter the true vapor pressure of liquid loaded, pounds per square inch absolute (psia). If no site specific data is

available, please refer to Table 2 on the Truck Loading tab.

Line 37: Temperature of bulk liquid loaded in degrees Fahrenheit. If no site specific data is available, use an estimated

average annual temperature.

Line 38: Enter the load rate of liquid loaded in barrels per hour.

Line 39: Enter the time (in hours) it takes to load out one load.
9

Pneumatic Pumps Data

If a pneumatic pump uses natural gas as the fuel gas, the pump will release VOC and HAP emissions each time it strokes

since all motive gas is vented by the pump. The Workbook calculates emissions from the pump based on the following:

a) Manufacturer’s information regarding gas usage (scf/hr)

b) The VOC & HAP weight fraction of the motive gas

c) Molecular weight of motive gas

d) Hours of operation

Pneumatic Pump Controls

Owner/operator of O&G production facilities shall control pneumatic pumps that use natural gas as the motive gas, if

the PTE of VOCs from the pneumatic pump is >5 TPY per pump.

Line 40: Enter the number of pneumatic pumps at the facility.

Line 41: Enter the hours each pump is in operation annually. For winter months only, enter 4380 hours.

Line 42: Enter the pneumatic source consumption rate from manufacturer’s data (scf/min).

Line 43: Use the drop down menu to choose the appropriate emission control type.

Line 44: No input required. Control efficiency is automatically calculated based on control type selected on Line 43.

Pneumatic Controllers Data

Lines 45Ͳ46: If a pneumatic controller uses natural gas as the motor fuel, VOC and HAP emissions shall be released

during device operation. The Workbook calculates emissions from the pump based on the following:

a) Manufacturer’s information regarding gas usage (scf/hr)

b) The VOC & HAP weight fraction of the fuel gas

c) Molecular weight of fuel gas

d) Hours of operation

Bakken Pool O&G production facilities are not required to install addͲon controls for emissions from these types of

devices.

Line 45: Enter the number of pneumatic controllers at facility.

Line 46: Enter the average bleed rate of device (scf/hr).

Glycol Dehydrator Data

Lines 47Ͳ48: Glycol, usually triͲethylene glycol (TEG), is used in dehydration units to absorb water from wet produced

gas. “Lean” TEG contacts the wet gas and absorbs water. The TEG is then considered “rich.” As the rich TEG is passed

through a reboiler and a flash separator (if installed) for regeneration, steam containing hydrocarbon vapors are

released. These are then vented from the dehydration unit flash separator and/or reboiler still vent.

Calculating Glycol Dehydrator Emissions

GRIͲGLYCalc V4.0 or higher shall be used to determine potential uncontrolled VOC and HAP emissions from the

process vents of the dehydration unit associated with the projected (decline factor applied) first year average daily

gas production rate. A copy of the run report shall be included with the Emission Calculation Workbook when

applicable. The estimated VOC and HAP emission values shall be entered on Line 59 & Line 60 on the Input Tab of

the Emission Calculation Workbook.
10

Glycol Dehydrator Control Threshold

Emissions that meet or exceed the following thresholds require the still vent vapors be routed to a control device:ш

5.0 TPY of any combination of HAPs, orш15.0 TPY any combination of VOCs.

Glycol Dehydrator Controls

The following control systems or devices shall be applied for glycol dehydrator emissions:

An enclosed, smokeless combustion device or flare that is designed and operated to reduce the mass content of

VOC and total HAP emissions in the vapors vented to the device by at least 98% by weight.

Any other control device (e.g. condenser or ground pit flare) or configuration that can be demonstrated to reduce

the mass content of total HAP and VOC in the process gases vented to the device or configuration by at least 90% by

weight.

Glycol dehydrator emission controls may be removed after one year of operation provided emissions have declined

to <15 TPY VOC and <5 TPY HAP. An updated GRIͲGLYCalc run with new calculations shall be submitted with a

request for control removal to regulating agency. No controls shall be removed prior to obtaining agency approval.

Glycol Dehydrator Federal Regulations

40 CFR 63, Subpart HH may be applicable to glycol dehydrators located at Bakken Pool O&G production facilities.

Line 47: Enter the TPY of VOC emissions calculated in GRIͲGLYCalc V4 software. (If no glycol dehydrator is installed, enter

0).

Line 48: Enter the TPY of HAP emissions calculated in GRIͲGLYCalc V4 software. (If no glycol dehydrator is installed, enter

0).

RICE Data Input

Lines 1Ͳ9: Emission estimates for internal combustion engines were calculated using manufacturer emission factors.

Internal combustion engine emissions were estimated using the following equation:

  ̧

1

·  ̈

©

§  u

u u 100

100

2000

EF ER HO DRE E X

X  

where:

EX = emissions for pollutant X (tpy);

EFX = emission factor for pollutant X (lb/hpͲhr or lb/MMBtu);

ER = engine rating (hp or MMBtu/hr);

HO = annual hours of operation (hr/yr);

DRE = destruction and removal efficiency (%); and

1Ͳton = 2000Ͳlb.

Potential emissions were calculated based on 8760Ͳhours per year (hrs/yr) and using the manufacturer's guaranteed

maximum rated design capacity (horsepower). The horsepower (hp) rating was not adjusted for elevation and

temperature. For uncontrolled emissions, the destruction and removal efficiency (DRE) is zero.
11

Line 1: Enter the number of engines to be installed at the production facility.

RICE Engine #1: Lines 2Ͳ12

Line 2: Engine is assumed to operate 8,760 hours per year.

Line 3: Enter the manufacturer’s maximum hp rating.

Line 4: Enter the manufacturer's emission factor or actual test results for nitrogen oxides (NOx).

Line 5: Enter the manufacturer's emission factor or actual test results for carbon monoxide (CO).

Line 6: Enter the manufacturer's emission factor or actual test results for volatile organic compounds (VOC).

Line 7: Enter the manufacturer’s emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.

Line 8: Enter the manufacturer’s emission factor, actual test results or ApͲ42 factor in lb/hpͲhr for CO2.

Line 9: Enter the manufacturer’s emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.

Line 10: Enter the NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc.) obtained from

manufacturer data or actual test results.

Line 11: Enter the CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc.) obtained from

manufacturer data or actual test results.

Line 12: Enter the VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc.) obtained from

manufacturer data or actual test results.

Repeat the above input instructions for Line 2 through Line 12 for each additional engine at the facility. 

Federal Regulations for RICE

There are several Federal regulations that may be applicable to RICE located at O&G production facilities. Listed below is

a brief summary of the Federal regulations that may be applicable. These regulations can be found at the following:

http://ecfr.gpoaccess.gov.

40 CFR 60, Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combustion Engines:

Applies to any compressionͲignition internal combustion engine where construction is commenced after July 11, 2005

and the engine is manufactured after April 1, 2006.

40 CFR 60, Subpart JJJJ – Standards of Performance for Stationary Spark Ignition Internal Combustion Engines: Applies to

any sparkͲignition internal combustion engine where construction is commenced after June 12, 2006 and the engine is

manufactured:

1) After July 1, 2007 for engines > 500 hp

2) After January 1, 2008 for leanͲburn engines 500 < hp < 1350

3) After July 1, 2008 for engines < 500 hp

4) After January 1, 2009 for emergency engines

40 CFR 63, Subpart ZZZZ – National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal

Combustion Engines: Applies to any (new, existing, modified and reconstructed) RICE located at a major source or an

area source of HAPs.

Gas Analysis Worksheet Input

Input mole percentages for gas component breakdown from representative treater gas analysis report.
12

E&P Tanks v2.0 Input

Input mole percentages from the Emission Summary: Stream Data: Total Emissions.
Attachment E

Qualitative Air Quality Analysis
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

EͲ1

Qualitative Air Quality Impact Analysis

This permit application does not include an air quality impact analysis as the effects on air emissions from this source are

not anticipated to impact air quality in the region. A qualitative approach to modeling the air quality impact was

performed based on the following items:

x Natural gas is being used to fuel equipment on the facility and typical emissions from utilizing this type of fuel

are insignificant.

x The region for which the source is operating is classified as an attainment area; therefore, there are no

significant air quality issues in the region for which this source would impact.

Due to the above factors, the proposed emissions under this permit are not anticipated to impact air quality in the

region.
Attachment F

Synthetic Minor Limit Request
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

FͲ1

SYNTHETIC MINOR LIMIT REQUEST GENERAL INFORMATION

Company Name

Enerplus Resources (USA) Corporation

Facility Name

Sitka/Yellowbird

Company Contact or Owner Name

Tony Lucero

Title

HSE Coordinator

Mailing Address

US Bank Tower, Suite 2200

950Ͳ17th Street

Denver, CO 80202Ͳ2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279Ͳ5500

Facsimile Number

(720) 279Ͳ5550

 
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

FͲ2

PROPOSED LIMITATION AND EFFECT ON THE POTENTIAL TO EMIT

Based on this facility’s maximum annual operational potential to emit (PTE) calculations presented in

Attachment C of the Application for New Construction, this facility will require a federallyͲenforceable

limitation on emissions to avoid an otherwise applicable federal Clean Air Act program, rule or

requirement, including Prevention of Significant Deterioration (PSD) and an applicable Title V Operating

Permit.

Requested Limitation. To limit this facility’s PTE, Enerplus is requesting mandated installation, operation

and maintenance of 98% destruction removal efficiency emission control equipment.

Combustor size(s) and quantity needed are likely to change as:

x Drill schedules change (i.e. all planned wells at a pad are not drilled at the same time; therefore

affecting the cumulative production rates and combustion unit sizing);

x Actual production rates are determined (i.e. actual production rate is lower than the

conservative average herein); and

x Combustion unit availability closer to the time of well construction.

As such, vendor guarantees are included in Attachment G for the selected combustion units from which

Enerplus will utilize based on actual well production values of natural gas. These combustion unit(s) are

guaranteed to ensure 98% removal of VOC and HAPs; therefore, the most appropriate unit of this

selection will be installed as actual well construction/drilling commences. If an alternate combustion

unit(s) is selected, Enerplus will provide the EPA with the guarantee to ensure 98% removal of VOC and

HAPs for approval prior to installation.

Effect on Emissions. Estimates of the facility’s anticipated emissions with and without the above

requested limitations are provided in the emission summary in Appendix C.

Emission of hydrofluorocarbons (HFC), perfluorocompound (PFC), sulfur hexafluoride (SF6), ammonia

and lead are not typical of oil and gas production, and are therefore not anticipate to be emitted from

this facility.

 
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

FͲ3

MONITORING, RECORDKEEPING AND REPORTING

FacilityͲWide Emissions

Monitoring. FacilityͲwide emissions will be calculated and recorded at the end of each month,

beginning with the first full calendar month after productions commenced. During the first year

of production, the emissions will be calculated using the first year projected average daily

hydrocarbon production rates specific to the facility. Thereafter, the monthly emissions will be

based upon actual average daily hydrocarbon production rates for this facility each month.

Testing. Within One (1) year of the first date of production, an extended laboratory analysis for

the oil and natural gas produced at this facility will be analyzed to confirm emission estimates

provided herein.

Recordkeeping. The following records will be kept for this facility:

1) Actual rolling monthly facilityͲwide emissions;

2) Each month’s daily average hydrocarbon production rate for the facility;

3) Extended laboratory analysis conducted on the hydrocarbon streams used to calculate

emissions at the facility;

4) Hydrocarbon production records for the life of the facility;

5) Process units and emission control devices used; and

6) Input parameters and calculations used to calculate monthly emissions.

Control Device for VOC and HAP Emissions

Monitoring. Facility operations will be inspected periodically to confirm proper operation as

follows:

1) Periodic check of continuous parameter monitoring system to confirm proper operation;

2) Minimum quarterly visual confirmation of smokeless operation;

Recordkeeping. The following records will be maintained for the facility:

1) SiteͲspecific design input parameters provided for the independent engineering analysis

or as provided to the manufacturer/vendor used to properly size the enclosed

combustor(s) and/or utility flare(s) to assure 98% destruction removal efficiency.

2) Instances in which a control device was bypassed or down each calendar month, the

reason for the incident, its duration, and the corrective actions taken or the

preventative measures adopted to avoid such bypasses or downtime.

3) Exceedances of the operating parameters specified in the manufacturer/vendor

guarantee or engineering analysis and selected for the device.
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

FͲ4

4) Instances in which the pilot flame is not present in the enclosed combustor(s) or utility

flare(s).

5) Instances in which the thermocouple (or other heat sensing monitoring device) installed

to detect the presence of a flame in the enclosed combustor(s) or utility flare(s) is not

operational.

6) Visible emissions.

Recordkeeping documentation shall be maintained onsite or at a central field office and

maintained as a permanent business record for a minimum of five years. Inspection records shall

include the following information:

1) The date, place, and time of observation, sampling or measurements;

2) The date(s) analyses were performed;

3) The companies or entities that performed observations and analyses;

4) The analytical techniques or methods used;

5) The results of such analyses or measurements; and

6) The operating conditions at the time of the sampling or measurement.

Hydrocarbon Storage Vessels and Pressurized Hydrocarbon Vessels

Monitoring. Calculate total VOC and HAP emissions from each storage and pressurized

hydrocarbon vessel.

Recordkeeping.

Records will be kept of all input parameters and calculations, including the input and output

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

Natural Gas Fired External Combustion Units

Recordkeeping. The following records will be kept for the facility’s natural gas fired external

combustion units:

1) The maximum rated heat input to the burning chambers of each external combustion

unit installed at the facility per the manufacturer’s specifications or nameplate on the

equipment;

2) The actual heat input to the burning chambers of each external combustion unit

installed at the facility;

3) The actual monthly fuel consumption for each external combustion unit at the facility;

4) The number of hours of operation for each external combustion unit at the facility;

5) The monthly emission calculations for each external combustion unit at the facility; and

6) Maintenance procedures performed on each external combustion unit at the facility.
Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Sitka/Yellowbird

FͲ5

Natural Gas Fired Engines

Monitoring. The following monitoring parameters will be followed for natural gas fired engines:

1) Quarterly measurement of VOC emissions from each engine;

2) Daily measurement of the exhaust temperature at the inlet to each catalyst; and

3) Monthly measurement of the pressure drop across each catalyst.

Recordkeeping. The following records will be kept for the facility’s natural gas fired engines:

1) Input parameters and calculations used to determine monthly emissions;

2) Manufacturer specifications for each temperatureͲsensing device, pressureͲmeasuring

device, and oxidation catalyst;

3) Calibration and maintenance conducted in accordance with the manufacturer

recommendations for each temperatureͲsensing device, pressureͲmeasuring device or

engine catalyst;

4) Measurements of exhaust temperature at the inlet to each catalyst and corrective

actions taken;

5) Measurements of pressure drop across each catalyst and corrective actions taken;

6) Quality of fuel used to operate natural gas fired engines;

7) Catalyst replacements, engine overhauls and engine replacements; and

8) Each overhauled or replaced engines “breakͲin” period.

Recordkeeping documentation shall be maintained onsite or at a central field office and

maintained as a permanent business record for a minimum of five years. Inspection records shall

include the following information:

1) The date, place, and time of observation, sampling or measurements;

2) The date(s) analyses were performed;

3) The companies or entities that performed observations and analyses;

4) The analytical techniques or methods used;

5) The results of such analyses or measurements; and

6) The operating conditions at the time of the sampling or measurement.
Attachment G

Equipment Specifications and Guarantees
Emission Control System Warranty

Your new Honda Power Equipment engine complies with the U.S. EPA, Environment Canada, and State of California emission regulations (models 

certified for sale in California only). American Honda Motor Co., Inc. provides the emission warranty coverage for engines in the United States and its 

territories. Honda Canada Inc. provides the emission warranty for engines in the 13 provinces and territories of Canada. In the remainder of this Emission 

Control System Warranty, American Honda Motor Company Inc. and Honda Canada Inc. will be referred to as Honda.

YOUR WARRANTY RIGHTS AND OBLIGATIONS:

California 

The California Air Resources Board and Honda are pleased to explain the emission control system warranty on your Honda Power Equipment engine. 

In California, new spark-ignited small off-road equipment engines must be designed, built, and equipped to meet the State's stringent anti-smog 

standards.

Other States, U.S. territories, and Canada

In other areas of the United States and in Canada, your engine must be designed, built, and equipped to meet the U.S. EPA and Environment Canada 

emission standards for spark-ignited engines at or below 19 kilowatts. Specific Honda products that do not meet the California emissions regulations 

can be identified by a “Not for sale in California” decal.

All of the United States and Canada

Honda must warrant the emission control system on your power equipment engine for the period of time listed below, provided there has been no abuse, 

neglect, or improper maintenance of your power equipment engine. Where a warrantable condition exists, Honda will repair your power equipment 

engine at no cost to you including diagnosis, parts, and labor.

Your emission control system may include such parts as the carburetor or fuel injection system, the ignition system, and catalytic converter. Also 

included may be hoses, connectors, and other emission-related assemblies (see page 2 for additional covered parts).

OWNER'S WARRANTY RESPONSIBILITY: 

As the power equipment engine owner, you are responsible for the performance of the required maintenance listed in your owner's manual. Honda 

recommends that you retain all receipts covering maintenance on your power equipment engine, but Honda cannot deny warranty coverage solely for 

the lack of receipts or for your failure to ensure the performance of all scheduled maintenance.

As the power equipment engine owner, you should however be aware Honda may deny you warranty coverage if your power equipment engine or a 

part has failed due to abuse, neglect, improper maintenance, or unapproved modifications.

You are responsible for presenting your power equipment engine to a Honda Power Equipment dealer as soon as a problem exists. The emission related 

warranty repairs should be completed in a reasonable amount of time, not to exceed 30 days.

If you have any questions regarding your emission warranty rights and responsibilities, you should contact the Honda office in your region:

WARRANTY COVERAGE: 

Honda power equipment engines sold in the United States and Canada are covered by this warranty for a period of two years from the date of delivery 

to the original retail purchaser or the length of the Honda Distributor’s Limited Warranty, whichever is longer. This warranty is transferable to each 

subsequent purchaser for the duration of the warranty period.

If any emission-related part on your engine is defective, the part will be repaired or replaced by Honda without charge for diagnosis, parts, or labor. All 

defective parts replaced under this warranty become the property of Honda. A list of warranted parts is on the reverse side of this warranty statement. 

Normal maintenance items, such as spark plugs and filters, that are on the warranted parts list are warranted up to their required replacement interval 

only.

Honda will also replace other engine components damaged by a failure of any warranted part during the warranty period. 

Only Honda approved replacement parts may be used in the performance of any warranty repairs and must be provided without charge to the owner. 

The use of replacement parts not equivalent to the original parts may impair the effectiveness of your engine emission control system. If such a 

replacement part is used in the repair or maintenance of your engine, and an authorized Honda dealer determines it is defective or causes a failure of a 

warranted part, your claim for repair of your engine may be denied. If the part in question is not related to the reason your engine requires repair, your 

claim will not be denied.

American Honda Motor Co., Inc. - Honda Canada Inc.

October 2009

Page 1 of 2

American Honda Motor Co., Inc.

Power Equipment Customer Relations 

4900 Marconi Drive

Alpharetta, Georgia 30005-8847

Telephone: (888) 888-3139

Email: powerequipmentemissions@ahm.honda.com

or

Honda Canada Inc.

Power Equipment Customer Relations

Visit www.honda.ca 

for contact information.

Telephone: (888) 946-6329

00X51-ZG0-6110 TO961 PWL50975-M
Emission Control System Warranty 

TO OBTAIN WARRANTY SERVICE: 

You must, at your own expense, take your Honda Power Equipment engine or the product on which it is installed, along with your sales registration card 

or other proof of original purchase date, to any Honda Power Equipment dealer who is authorized by Honda to sell and service that Honda product during 

his normal business hours. Claims for repair or adjustment found to be caused solely by defects in material or workmanship will not be denied because the 

engine was not properly maintained and used.

If you are unable to obtain emission warranty service or are dissatisfied with the warranty service you received, contact the owner of the dealership 

involved. Normally this should resolve your problem. However, if you require further assistance, contact the Honda office in your region:

EXCLUSIONS: 

Failures other than those resulting from defects in material or workmanship are not covered by this warranty. This warranty does not extend to emission 

control systems or parts that are affected or damaged by owner abuse, neglect, improper maintenance, misuse, misfueling, improper storage, collision, the 

incorporation of, or use of, unsuitable attachments, or the unauthorized alteration of any part.

This warranty does not cover replacement of expendable maintenance items made in connection with required maintenance service after the item’s first 

scheduled replacement as listed in the maintenance section of the product owner’s manual, such as: spark plugs and filters.

Disclaimer of Consequential Damage and Limitation of Implied Warranties: 

American Honda Motor Co., Inc. and Honda Canada Inc. disclaim any responsibility for incidental or consequential damages such as loss of time or the 

use of the power equipment, or any commercial loss due to the failure of the equipment; and any implied warranties are limited to the duration of this 

written warranty. This warranty is applicable only where the California, U.S. EPA, or Environment Canada emission control system warranty regulation 

is in effect.

EMISSION CONTROL SYSTEM WARRANTY PARTS:

American Honda Motor Co., Inc. - Honda Canada Inc.

October 2009

Page 2 of 2

American Honda Motor Co., Inc.

Power Equipment Customer Relations 

4900 Marconi Drive

Alpharetta, Georgia 30005-8847

Telephone: (888) 888-3139

Email: powerequipmentemissions@ahm.honda.com

or

Honda Canada Inc.

Power Equipment Customer Relations

Visit www.honda.ca 

for contact information.

Telephone: (888) 946-6329

SYSTEMS COVERED

BY THIS WARRANTY:

PARTS

DESCRIPTION:

Fuel Metering Carburetor assembly (includes starting enrichment system), 

Engine temperature sensor, Engine control module, Fuel regulator, Intake manifold

Evaporative Fuel tank, Fuel cap, Fuel hoses, Vapor hoses, Carbon canister, Canister mounting brackets, 

Fuel strainer, Fuel cock, Fuel pump, Fuel hose joint, Canister purge hose joint

Exhaust Catalyst, Exhaust manifold

Air Induction Air filter housing, Air filter element*

Ignition Flywheel magneto, Ignition pulse generator, Crankshaft position sensor, 

Power coil, Ignition coil assembly, Ignition control module, Spark plug cap, Spark plug*

Crankcase Emission Control Crankcase breather tube, Oil filler cap

Miscellaneous Parts Tubing, fittings, seals, gaskets, and clamps associated with these listed systems.

Note: This list applies to parts supplied by Honda and does not cover parts supplied by the equipment manufacturer. Please see the original equipment 

manufacturer’s emissions warranty for non-Honda parts.

* Covered up to the first required replacement only. See the Maintenance Schedule in the owner’s manual.

PWL50975-M
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

2011 MODEL YEAR

CERTIFICATE OF CONFORMITY

WITH THE CLEAN AIR ACT OF 1990

OFFICE OF TRANSPORTATION

AND AIR QUALITY

ANN ARBOR, MICHIGAN 48105

Certificate Issued To: Power Solutions International

(U.S. Manufacturer or Importer)

Certificate Number: BPWRB11.1NGP-002

Effective Date:

01/03/2011

Expiration Date:

12/31/2011

_________________________

Karl J. Simon, Director

Compliance and Innovative Strategies Division

Issue Date:

01/03/2011

Revision Date:

N/A

Manufacturer: Power Solutions InternationalEngine Family: BPWRB11.1NGPCertificate Number: BPWRB11.1NGP-002Certification Type: Mobile and StationaryFuel : LPG/Propane Natural Gas (CNG/LNG)Emission Standards : NMHC + NOx ( g/kW-hr ) : 2.7 CO ( g/kW-hr ) : 4.4 HC + NOx ( g/kW-hr ) : 2.7CO ( g/Hp-hr ) : 2 VOC ( g/Hp-hr ) : 0.7 NOx ( g/Hp-hr ) : 1Emergency Use Only : N

Pursuant to Section 213 of the Clean Air Act (42 U.S.C. section 7547) and 40 CFR Part 1048, 40 CFR Part 60, 1065, 1068, and 60 ( stationary only and combined stationary and mobile ) and subject to theterms and conditions prescribed in those provisions, this certificate of conformity is hereby issued with respect to the test engines which have been found to conform to applicable requirements and whichrepresent the following nonroad engines, by engine family, more fully described in the documentation required by 40 CFR Part 1048, 40 CFR Part 60 and produced in the stated model year.This certificate of conformity covers only those new nonroad spark-ignition engines which conform in all material respects to the design specifications that applied to those engines described in thedocumentation required by 40 CFR Part 1048, 40 CFR Part 60 and which are produced during the model year stated on this certificate of the said manufacturer, as defined in 40 CFR Part 1048, 40 CFR Part60. This certificate of conformity does not cover nonroad engines imported prior to the effective date of the certificate.It is a term of this certificate that the manufacturer shall consent to all inspections described in 40 CFR 1068.20 and authorized in a warrant or court order. Failure to comply with the requirements of such awarrant or court order may lead to revocation or suspension of this certificate for reasons specified in 40 CFR Part 1048, 40 CFR Part 60. It is also a term of this certificate that this certificate may be revokedor suspended or rendered void ab initio for other reasons specified in 40 CFR Part 1048, 40 CFR Part 60.This certificate does not cover large nonroad engines sold, offered for sale, or introduced, or delivered for introduction, into commerce in the U.S. prior to the effective date of the certificate.
Source Emissions Test Report 

Cimarron Energy, Inc. 

Flare Stack 

Inlet and Outlet NMOC Emissions 

Parshall, North Dakota 

Report prepared for: Report prepared by: 

Cimarron Energy, Inc. 

1012 24th Avenue, Suite 100 

Norman, Oklahoma 73069 

 Marcus Manning 

Portable Division Director 

Test Date:

June 14 - 15, 2011 

APT Project: CIM1122 
Table of Contents 

1. Introduction..................................................................................... 1

2. Methods.......................................................................................... 1

3. Test Program Summary....................................................... 2

4. Test Method Details............................................................. 3

5. Test Results Summary......................................................... 4 

Tables 

Table 1.1 : Contact Personnel....................................................... 1 

Table 3.1 : Sampling and Analytical Methods............................ 3 

Table 5.1 : Test Results Summary, Flare Outlet, 1 oz. Flow........ 5 

Table 5.2 : Test Results Summary, Flare Outlet, 4 oz. Flow........ 5 

Table 5.3 : Test Results Summary, Flare Outlet, 10 oz. Flow...... 6 

Table 5.4 : Test Results Summary, DRE Calculations............... 6 

Appendices 

Test Parameters................................................................ Appendix 1 

Field and Laboratory Data................................................... Appendix 2 

Calibration Information........................................................ Appendix 3 

Schematics.......................................................................... Appendix 4 
APT Project: CIM1122 

Test Report – Cimarron Energy Parshall Flare 

page 1 

1. Introduction 

Air Pollution Testing, Inc. (APT) was contracted by Cimarron Energy, Inc. to conduct 

source emission testing services at a facility near Parshall, North Dakota. 

The purpose of the test program was to determine the concentrations and mass 

emission rates of oxygen (O2), carbon dioxide (CO2), carbon monoxide (CO), methane 

(CH4) and non-methane organic compounds (NMOC) at both the inlet and outlet 

sampling locations of an enclosed flare stack. The unit is fed with off gas from various 

facility processes. Concurrent inlet gas velocity measurements, as well as pilot light 

data, were collected for the determination of total inlet emissions. All of the above data 

were combined to determine the overall destruction removal efficiency (DRE) of the unit. 

The emissions testing was conducted under three different operating conditions; 1 oz., 4 

oz. and 10 oz. inlet feed pressures. 

Table 1.1 provides contact information for key personnel involved in the test program. 

Cimarron Energy, Inc.: Parshall Flare 

Testing Program Contact Personnel 

Name, Title Company Address Phone, FAX, email 

Mr. Michael John, 

Process Engineer 

Cimarron Energy, Inc. 

1012 24th Ave NW, Suite 100 

Norman, Oklahoma 73069 

405-928-7373 ext. 111, 

405-928-7379 

mjohn@cimarron.com

Mr. Dave Maiers, 

Operations Director 

Air Pollution Testing, Inc. 

5530 Marshall Street 

Arvada, Colorado 80003 

303-420-5949, 

303-420-5920, 

dmaiers@airtest.net 

Table 1.1: Testing Program Contact Personnel 

2. Methods 

All testing was conducted in accordance with the following source emissions test 

methods referenced in 40 CFR Part 60, Appendix A. 

Method 1 – Sample and Velocity Traverses for Stationary Sources 

Method 2 – Determination of Stack Gas Velocity and Volumetric Flow Rate (Type S 

Pitot Tube) 

Method 3A – Gas Analysis for the Determination of Emission Rate Correction Factor or 

Excess Air 

Method 4 – Determination of Moisture Content in Stack Gases 
APT Project: CIM1122 

Test Report – Cimarron Energy Parshall Flare 

page 2 

Method 10 – Determination of Carbon Monoxide Emissions from Stationary Sources 

Method 18 – Measurement of Gaseous Organic Compound Emissions by Gas 

Chromatography 

Method 25A – Determination of Total Gaseous Organic Concentration Using a Flame 

Ionization Analyzer 

3. Test Program Summary

APT provided all necessary equipment and labor for the determination of all emission 

parameters detailed in Table 3.1 on the following page. 

Three, 1-hour sampling runs were conducted at 1 oz., 4 oz. and 10 oz. inlet feed 

pressure from the flare exhaust to determine pollutant concentrations. Concentration 

data were combined with concurrently collected oxygen (O2), carbon dioxide (CO2), 

moisture (H2O) and gas velocity data to determine pollutant mass emission rates. 

Integrated samples were collected from both the pilot light and the waste gas inlet, 

concurrent with each sample run, for off-site analysis to determine the total hydrocarbon 

and NMOC content of the two streams for comparison with the exhaust stack levels. 

Cimarron Energy, Inc. – Parshall Flare 

Sampling and Analytical Methods

Gas Parameter EPA Method Analytical Method Laboratory 

Enclosed Flare Exhaust Measurements 

gas flow Methods 1, 2 draft gauge, thermocouple, pitot tube 

O2, CO2 Method 3A paramagnetic and non-dispersive infrared 

analyzers 

H2O Method 4 gravimetric 

CO Method 10 gas filter correlation, infrared analyzer 

NMOC Method 25A flame ionization detector with methane 

separation – Thermo Model 55 

APT, 

on-site 

C2H6 Method 18 gas chromatography APT, Arvada, CO 

Condensate Tank Waste Gas Measurements (Flare Inlet)

gas flow Methods 1, 2 draft gauge, thermocouple, pitot tube APT, 

on-site

VOC, NMOC ASTM D1945/1946 

gas chromatography / flame ionization 

detector / thermal conductivity detector 

Empact Analytical, 

Brighton, CO 

Flare Pilot / Assist Gas Measurements (Flare Inlet) 

gas flow Orifice Manufacturer provided constant value APT, 

on-site

VOC, NMOC ASTM D1945/1946 

gas chromatography / flame ionization 

detector / thermal conductivity detector 

Empact Analytical, 

Brighton, CO 

Table 3.1: Sampling and Analytical Methods
APT Project: CIM1122 

Test Report – Cimarron Energy Parshall Flare 

page 3 

4. Test Method Details 

4.1. Stack Gas Velocity, Volumetric Flow Rate and Moisture

Stack gas velocity, volumetric flow rate and moisture (H2O) content were measured in 

accordance with EPA Methods 1, 2 and 4. 

Each sampling period consisted of conducting a temperature and differential pressure 

traverse of the stack using a K-type thermocouple and an S-type pitot tube. Concurrent 

with each traverse, a sample of gas for moisture determination was extracted from the 

stack at a constant flow rate of no more than 0.75 cubic feet per minute (cfm). The gas 

sample passed through a stainless steel probe, through a series of four (4) chilled glass 

impingers, and through a calibrated dry gas meter. See Appendix 4 – Schematics for a 

diagram of the EPA Methods 1, 2 and 4 sampling train. 

Prior to sampling, the first two impingers were each seeded with 100 milliliters of water. 

The third impinger was empty. The fourth impinger was seeded with 250 grams of dried 

silica gel. Following sampling, the moisture gain in the impingers was measured 

gravimetrically to determine the moisture content of the gas. 

All of the above data were combined with concurrently collected diluent (O2 and CO2) 

data to calculate the stack gas velocity and volumetric flow rate in units of feet per 

second (ft/sec), actual cubic feet per minute (acfm), dry standard (1 atmosphere and 

68°F) cubic feet per minute (dscfm), and pounds per hour (lb/hr). 

4.2. Diluent, Carbon Monoxide and Non-methane Hydrocarbons – Flare Exhaust

O2, CO2, CO and NMOC emission concentrations were measured in accordance with 

EPA Methods 3A (O2 and CO2), 10 (CO) and 25A (NMOC). 

Each sampling period consisted of extracting a gas sample from the stack at a constant 

flow rate of approximately three liters per minute (lpm). The sample passed through a 

refrigeration-type gas conditioner to remove moisture and into the sampling port of a 

TECO Model 48H gas filter correlation infrared CO analyzer, a Servomex Series 1400 

paramagnetic O2 / non-dispersive infrared CO2 analyzer and a Thermo Model 55 flame 

ionization analyzer equipped with a methane separator. The gas conditioner was 

bypassed for the NMOC analyzer. The gas concentrations were displayed on the 

analyzer front panels in units of either parts per million, dry volume basis (ppmvd – CO), 

percent, dry volume basis (%vd – O2 and CO2), or parts per million, wet volume basis as 

propane (ppmvw as C3H8 – NMOC) and logged to a computerized data acquisition 

system (CDAS). Please see Appendix 4 – Schematics for a diagram of the EPA 

Methods 3A, 10 and 25A sampling train. 

Before and after each sampling period, the analyzers were challenged with calibration 

gases to calibrate the instruments, to verify linearity of response, and to quantify zero 
APT Project: CIM1122 

Test Report – Cimarron Energy Parshall Flare 

page 4 

and span drift for the previous sampling period. The calibration gases were prepared 

and certified in accordance with EPA Protocol 1. To ensure no system bias, the 

analyzer calibrations were conducted by introducing all gases to the analyzers at the 

sampling probe tip at stack pressure. 

Following sampling, the CDAS data were averaged in one-minute increments, corrected 

for instrumental drift, and reported as average emission concentrations for each 

sampling period. 

4.3. Total Hydrocarbon / NMOC – Flare Inlets

Methane and NMOC concentrations were measured in accordance with ASTM D-1945 

and 1946, which are industry standard analytical methods for analysis of fuel gas type 

samples. Samples were collected from each inlet in Tedlar bags for off-site 

GC/FID/TCD analysis for C1 – C6+ hydrocarbons, oxygen, carbon dioxide and nitrogen. 

The concentration data were combined with the pitot traverse data (condensate waste 

gas) or manufacturer data (pilot light) to calculate flare inlet NMOC mass flow to 

determine the control efficiency for NMOC. 

Laboratory analysis of the waste gas sample indicated high oxygen and nitrogen from 

likely sample leakage. The hydrocarbon and carbon dioxide concentrations were 

normalized to remove the leakage. DRE was calculated on both a mass flow in/out 

basis and by carbon balance. 

5. Test Results Summary 

The results of the testing are summarized in Tables 5.1 – 5.3. Any emission 

parameters not found in the tables may be found in Appendix 1 – Test Parameters. The 

following terms are used in the tables: 

• %vd – diluent concentration, dry volume percent 

• %vw – moisture content, wet volume percent 

• dscfm – stack gas flow rate, dry standard (one atmosphere, 68°F) cubic feet per 

minute 

•  ̊F – temperature, in degrees Fahrenheit 

• lb/hr – pollutant mass emission rate, pounds per hour 

• ppmvd – parts per million, dry volume basis 

• as C3H8 – as propane 

• DRE – destruction removal efficiency 
APT Project: CIM1122 

Test Report – Cimarron Energy Parshall Flare 

page 5 

Cimarron Energy, Inc. – Parshall Flare 

Flare Test Results Summary (06/15/2011) – 1 oz. Inlet Pressure 

Run #1 Run #2 Run #3

Start Time 12:34 14:12 15:30 

Stop Time 13:34 15:12 16:30 

Average 

Stack Temp ( ̊F) 936 811 889 879 

Stack Flow (MDSCFD) 2,105.3 3,924.0 4,059.4 3,362.4 

O2 (%vd) 18.5 18.3 18.2 18.3 

CO2 (%vd) 1.5 1.7 1.8 1.6 

H2O (%vw) 4.6 3.9 4.1 4.2 

Emission Data

CO (lb/hr) 0.7 1.1 1.0 0.9 

CO (tons/year) 3.0 4.6 4.4 4.0 

NMOC (ppmvd as C3H8) 46.0 69.8 46.0 53.9 

NMOC (lb/hr as C3H8) 0.46 1.30 0.89 0.89 

Table 5.1: Test Results Summary, Flare Outlet, 1 oz. Flow 

Cimarron Energy, Inc. – Parshall Flare 

Flare Test Results Summary (06/14/2011) – 4 oz. Inlet Pressure 

Run #1 Run #2 Run #3

Start Time 10:48 12:55 14:14 

Stop Time 11:48 13:55 15:14 

Average 

Stack Temp ( ̊F) 1,320 1,321 1,327 1,323 

Stack Flow (MDSCFD) 3,840.5 3,762.7 3,703.7 3,768.5 

O2 (%vd) 16.5 16.6 16.6 16.6 

CO2 (%vd) 2.9 2.8 2.8 2.8 

H2O (%vw) 4.4 6.2 4.9 5.2 

Emission Data

CO (lb/hr) 0.6 0.6 0.6 0.6 

CO (tons/year) 2.7 2.7 2.5 2.6 

NMOC (ppmvd as C3H8) 0.0 2.0 0.4 0.8 

NMOC (lb/hr as C3H8) 0.00 0.04 0.01 0.01 

Table 5.2: Test Results Summary, Flare Outlet, 4 oz. Flow 
APT Project: CIM1122 

Test Report – Cimarron Energy Parshall Flare 

page 6 

Cimarron Energy, Inc. – Parshall Flare 

Flare Test Results Summary (06/14-15/2011) – 10 oz. Inlet Pressure 

Run #1 Run #2 Run #3

Start Time 15:31 16:48 08:45 

Stop Time 16:31 17:48 09:45 

Average 

Stack Temp ( ̊F) 1,973 1,992 1,992 1,986 

Stack Flow (MDSCFD) 3,386.9 3,373.9 3,607.2 3,456.0 

O2 (%vd) 14.8 14.9 15.1 14.9 

CO2 (%vd) 3.9 3.8 3.8 3.8 

H2O (%vw) 8.4 5.9 6.8 7.0 

Emission Data

CO (lb/hr) 0.2 0.2 0.2 0.2 

CO (tons/year) 0.7 0.9 0.7 0.8 

NMOC (ppmvd as C3H8) 0.3 0.7 0.1 0.4 

NMOC (lb/hr as C3H8) 0.01 0.01 0.00 0.01 

Table 5.3: Test Results Summary, Flare Outlet, 10 oz. Flow 

Cimarron Energy, Inc. – Parshall Flare 

Flare Test Results Summary (06/14-15/2011) – DRE Summary 

1 oz. Flow 4 oz. Flow 10 oz. Flow

Waste Gas Inlet

Waste Gas Specific Gravity 1.46 1.44 1.45 

Waste Gas Heat Content (BTU) 2,273 2,252 2,308 

Waste Gas Flow (MCFD) 41.8 70.6 131.0 

Waste Gas Flow (MDSCFD) 37.4 64.8 119.5 

NMOC (lb/hr as C3H8) 150.6 260.0 489.2 

Pilot Inlet

Pilot Light Flow (MCFD) 0.3 0.3 0.3 

Pilot Light NMOC (lb/hr as C3H8) 0.5 0.5 0.5 

Total Inlet NMOC (lb/hr as C3H8) 151.0 260.5 489.7 

 

Total Outlet NMOC (lb/hr as C3H8) 0.9 0.01 0.01 

% DRE(mass flow in/out basis) 99.41 99.99 100.00 

% DRE(carbon balance) 98.94 99.99 100.00 

Table 5.4: Test Results Summary, DRE Calculations 
 $SSHQGL[2QH7HVW3DUDPHWHUV
1 oz. Inlet Pressure 
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

6/15/2011

1 oz.

Run # 7 8 9 Average

Start Time 12:42 14:20 15:41

Stop Time 13:08 14:40 16:06

hrs Hours of Operation / Year 8760 8760 8760 8760

DS Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0

√ΔPAVG Inlet Average (Delta P)

1⁄2 (" H2O)1⁄2 0.1150 0.0940 0.1026 0.1039

CP Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84

TS Inlet Stack Temperature (°F) 73 74 73 73

Pbar Barometric Pressure (mbar) 936 936 936 936

Pbar Barometric Pressure (" Hg) 27.64 27.64 27.64 27.64

Ps Inlet Stack Pressure ('' H2O) 1.0 1.0 1.0 1.0

Carbon Dioxide (%vd) 0.3 0.3 0.3 0.3

Methane (%vd) 16.1 14.0 14.8 14.9

Ethane (%vd) 20.4 19.2 19.8 19.8

Propane (%vd) 33.0 32.1 32.9 32.7

Butanes (%vd) 18.9 18.7 19.1 18.9

Pentanes (%vd) 5.3 5.2 5.3 5.3

Hexanes+ (%vd) 2.7 2.5 2.7 2.6

Heat Content (Btu/scf) 2,304 2,224 2,290 2,273

Carbon Dioxide (%vd) 0.5 0.5 0.5 0.5

Methane (%vd) 47.5 47.5 47.5 47.5

Ethane (%vd) 19.2 19.2 19.2 19.2

Propane (%vd) 15.4 15.4 15.4 15.4

Butanes (%vd) 6.1 6.1 6.1 6.1

Pentanes (%vd) 1.5 1.5 1.5 1.5

Hexanes+ (%vd) 0.8 0.8 0.8 0.8

Heat Content (Btu/scf) 1,479 1,479 1,479 1,479

FACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18

FDSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17

dry Pilot Light NMOC (ppmvd as C3H8) 402,167 402,167 402,167 402,167

lb/hr Pilot Light NMOC (lb/hr as C3H8) 0.47 0.47 0.47 0.47

Run # 7 8 9 Average

Bws Inlet Moisture Content (%/100) - saturated 0.029 0.030 0.029 0.030

MD Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54

MA Inlet Molecular Weight Wet (lb/lb-mole) 35.03 35.01 35.03 35.02

VS Inlet Gas Velocity (ft/sec) 6.1 5.0 5.5 5.5

FACFM Inlet Gas Flow (acfm) 32 26 29 29

FDSCFM Inlet Gas Flow (dscfm) 29 23 25 26

dry NMOC (ppmvd as C3H8) 858,433 835,967 858,533 850,978

lb/hr NMOC (lb/hr as C3H8) 168 134 150 151

tpy NMOC (tons/year as C3H8) 739 587 659 661

Field Reference Method Data

Waste Gas Data

Reference Method Calculations

Pilot Light Data 
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

6/15/2011

1 oz.

Run # 1 2 3 Average

Start Time 12:34 14:12 15:30

Stop Time 13:34 15:12 16:30

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

DS Stack Diameter (inches) 42.6 42.6 42.6 42.6

√ΔPAVG Average (Delta P)

1⁄2 (" H2O)1⁄2 0.0780 0.1380 0.1475 0.1212

CP Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83

TS Stack Temperature (°F) 936 811 889 879

Pbar Barometric Pressure (mbar) 936 936 936 936

Pbar Barometric Pressure (" Hg) 27.64 27.64 27.64 27.64

Ps Stack Pressure ('' H2O) 0.00 0.00 0.00 0.00

Yd Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780

Tm Meter Temperature (°F) 74 78 79 77

Vm Sample Volume (ft3

) 37.560 38.015 37.022 37.532

ΔH Orifice Pressure Delta H (" H2O) 1.0 1.0 1.0 1.0

Vlc Moisture (g) 34.0 28.7 30.1 30.9

O2%vd O2 (%vd) 18.5 18.3 18.2 18.3

CO2%vd CO2 (%vd) 1.5 1.7 1.8 1.6

N2%vd N2 (%vd) 80.0 80.0 80.0 80.0

dry CO (ppmvd) 107.2 89.1 81.4 92.6

wet CH4 (ppmvw) 18.3 18.0 9.6 15.3

wet NMOC (ppmvw as C3H8) 43.9 67.1 44.1 51.7

Run # 1 2 3 Average

Vmstd Sample Volume (dscf) 33.629 33.763 32.850 33.414

Vwstd Moisture Volume (scf) 1.60 1.35 1.42 1.46

Bws Moisture Content (%/100) 0.046 0.039 0.041 0.042

MD Molecular Weight Dry (lb/lb-mole) 28.98 29.00 29.02 29.00

MA Molecular Weight Wet (lb/lb-mole) 28.48 28.58 28.56 28.54

VS Gas Velocity (ft/sec) 7.4 12.4 13.7 11.2

FACFM Gas Flow (acfm) 4,382 7,386 8,135 6,635

FDSCFM Gas Flow (dscfm) 1,462 2,725 2,819 2,335

lb/hr Gas Flow (lb/hr) 6,791 12,611 13,080 10,827

Fo Fo (unitless) 1.640 1.551 1.499 1.564

lb/hr CO (lb/hr) 0.7 1.1 1.0 0.9

tpy CO (tons/year) 3.0 4.6 4.4 4.0

dry CH4 (ppmvd) 19.2 17.4 9.2 15.3

lb/hr CH4 (lb/hr) 0.1 0.1 0.1 0.1

tpy CH4 (tons/year) 0.3 79.0 42.3 40.5

dry NMOC (ppmvd as C3H8) 46.0 69.8 46.0 53.9

lb/hr NMOC (lb/hr as C3H8) 0.461 1.3042 0.8903 0.885

tpy NMOC (tons/year as C3H8) 2.019 5.712 3.900 3.877

DRE TVOC DRE (%) - carbon balance 98.96% 98.67% 99.19% 98.94%

Field Reference Method Data

Reference Method Calculations
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

O2 CO2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 100.0

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

Linearity Bias (Zero) 0.0 0.0 -0.2 1.9 0.0

Linearity Bias (Span) 10.0 2.5 77.0 295.4 31.1

% % (ppm) (ppm) (ppm)

0.00 0.00 0.0 0.0 0.0

10.00 2.48 79.1 300.0 30.2

21.10 5.00 182.0 750.0 50.1

1490.0 85.5

0.0 0.0 -0.2 1.9 0.0

10.0 2.5 77.0 295.4 31.1

21.1 5.0 179.0 749.6 50.5

1500.0 85.2

0.0 0.0 0.2 1.9 0.0

0.0 0.0 2.1 4.6 0.9

0.0 0.0 3.0 0.4 0.4

0.0 0.0 0.0 10.0 0.3

0.00% 0.00% 0.77% 0.13% 1.00%

0.47% 0.40% 0.49% 0.65% 0.30%

0.00% 0.20% 1.65% 0.67% 0.90%

Linearity Information

Gas

Span Gas Value/Range

Bias Gas Value

Gas Concentration

1

2

3

4

Difference

1

4

Response

1

2

Span Bias 

Max Calibration Error

Bias Check (Zero)

Bias Check (Span)

2

3

4

Results

3

Zero Bias
Cimarron Energy Run 1

Liberty Oil Well

Parshall, ND Start Time 12:34

Flare Run Length 60

06/15/11 Stop Time 13:34

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 100

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

0.0% 0.0% 0.8% 0.1% 0.0%

0.5% 0.4% 0.5% 0.7% 0.9%

0.0% 0.0% 0.0% 0.0% 0.0%

0.0% 0.0% 0.0% 0.0% 0.0%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

18.5 1.5 107.2 18.3 43.9

Run Length 

(Minutes) Time Uncorrected 

O2 %

Uncorrected 

CO2 %

Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

18.7 1.5 105.1 18.6 43.9

1 12:34 18.7 1.5 100.1 18.5 41.3

2 12:35 18.1 1.9 78.6 12.0 54.6

3 12:36 18.7 1.5 71.9 7.4 29.7

4 12:37 19.0 1.2 115.5 5.8 18.0

5 12:38 19.1 1.2 113.1 8.1 12.3

6 12:39 19.2 1.1 160.0 13.4 20.2

7 12:40 18.9 1.3 144.9 16.0 29.8

8 12:41 18.5 1.6 76.2 33.4 37.7

9 12:42 18.6 1.6 73.5 17.6 87.1

10 12:43 18.4 1.7 73.2 5.3 28.6

11 12:44 18.3 1.7 70.4 4.2 12.0

12 12:45 18.5 1.7 72.2 4.9 10.4

13 12:46 18.4 1.7 73.0 5.0 11.1

14 12:47 18.7 1.5 85.3 5.6 12.1

15 12:48 18.8 1.3 110.1 7.5 12.0

16 12:49 19.1 1.2 150.5 11.3 16.0

17 12:50 19.0 1.2 150.8 17.0 22.7

18 12:51 19.1 1.1 154.8 22.6 31.0

19 12:52 19.2 1.1 171.1 23.5 46.9

20 12:53 19.3 1.0 199.4 25.8 47.9

21 12:54 19.3 1.1 199.3 34.3 58.4

22 12:55 18.9 1.3 162.4 111.0 108.2

23 12:56 18.9 1.3 117.2 44.3 261.1

24 12:57 19.2 1.1 171.9 19.1 72.6

25 12:58 19.4 1.0 220.1 19.6 38.0

26 12:59 19.3 1.0 201.5 38.1 53.9

27 13:00 19.2 1.1 209.7 121.7 125.6

28 13:01 18.8 1.4 190.0 75.8 303.3

29 13:02 18.3 1.7 80.8 82.3 160.9

30 13:03 18.3 1.7 73.6 90.3 234.2

31 13:04 18.3 1.7 71.3 6.9 180.2

32 13:05 18.4 1.6 75.3 4.9 15.6

33 13:06 18.4 1.7 72.8 5.7 12.1

34 13:07 18.4 1.7 70.5 5.6 13.9

35 13:08 18.5 1.6 71.4 5.0 13.0

36 13:09 18.4 1.6 70.9 5.0 11.7

37 13:10 18.4 1.7 71.9 5.0 11.2

38 13:11 18.5 1.6 71.8 4.3 12.1

39 13:12 18.4 1.6 72.5 4.4 10.5

40 13:13 18.4 1.6 73.0 5.0 10.7

41 13:14 18.4 1.7 71.8 5.0 11.4

42 13:15 18.3 1.7 71.9 5.0 12.1

43 13:16 18.5 1.6 73.3 5.0 11.1

44 13:17 18.5 1.5 78.6 5.1 11.1

45 13:18 18.6 1.5 80.8 5.0 12.3

46 13:19 18.6 1.5 81.2 6.0 13.8

47 13:20 18.6 1.5 88.5 5.1 16.0

48 13:21 18.2 1.8 80.2 6.0 14.1

49 13:22 18.6 1.5 82.5 6.3 17.0

50 13:23 18.8 1.4 97.8 5.2 15.1

51 13:24 18.6 1.6 78.1 11.0 14.4

52 13:25 18.9 1.4 96.5 7.0 22.1

53 13:26 18.3 1.7 95.2 22.5 13.4

54 13:27 18.7 1.5 76.0 28.4 46.8

55 13:28 18.7 1.5 104.3 5.0 37.1

56 13:29 18.8 1.4 101.9 11.0 11.9

57 13:30 18.3 1.8 86.8 8.8 23.0

58 13:31 18.6 1.6 76.3 5.6 19.3

59 13:32 18.7 1.5 111.1 3.8 11.6

60 13:33 18.4 1.7 81.2 6.0 11.0

Calibration 

Pretest Calibration

Absolute Bias (Zero)

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Zero%

Span%

Calibration Information

Instrument Range

Span Gas Value

Gas

Zero%

Span%

Results

Post Test Calibration
Cimarron Energy Run 2

Liberty Oil Well

Parshall, ND Start Time 14:12

Flare Run Length 60

06/15/11 Stop Time 15:12

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 100

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

0.0 0.0 1.2 0.2

10.0 2.5 77.7 284.0 30.0

0.0% 0.0% 0.8% 0.1% 0.2%

0.0% 0.2% 0.4% 0.8% 1.1%

0.0% 0.0% 0.0% 0.0% 0.2%

0.5% 0.6% 0.1% 1.4% 0.2%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

18.3 1.7 89.1 18.0 67.1

Run Length 

(Minutes) Time Uncorrected 

O2 %

Uncorrected 

CO2 %

Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

18.4 1.7 87.5 17.7 66.7

1 14:12 18.6 1.6 84.2 12.7 43.4

2 14:13 18.9 1.3 123.5 8.9 40.7

3 14:14 18.7 1.5 138.5 17.7 36.4

4 14:15 18.5 1.6 91.7 20.9 63.2

5 14:16 18.3 1.8 83.7 16.3 84.1

6 14:17 18.5 1.7 80.0 9.4 56.2

7 14:18 18.9 1.3 114.7 7.0 34.2

8 14:19 18.4 1.7 114.6 12.7 28.3

9 14:20 18.7 1.4 97.9 17.9 47.1

10 14:21 18.6 1.5 109.6 19.1 68.7

11 14:22 18.5 1.6 85.7 16.6 70.9

12 14:23 18.2 1.8 77.6 10.0 59.5

13 14:24 18.2 1.8 73.7 9.0 39.8

14 14:25 18.3 1.8 75.1 7.0 36.1

15 14:26 17.7 2.1 71.6 6.7 25.2

16 14:27 17.8 2.1 67.5 7.5 27.0

17 14:28 18.1 1.9 72.2 5.0 24.7

18 14:29 18.2 1.9 73.3 7.6 13.6

19 14:30 18.3 1.8 74.1 8.0 24.1

20 14:31 18.5 1.6 76.4 7.6 25.6

21 14:32 18.4 1.7 78.6 7.1 25.6

22 14:33 18.4 1.7 77.2 8.0 26.6

23 14:34 17.9 2.0 73.9 8.0 30.2

24 14:35 18.2 1.8 71.5 6.8 29.1

25 14:36 18.4 1.7 76.7 6.9 23.1

26 14:37 18.3 1.7 78.4 9.0 25.5

27 14:38 18.1 1.9 72.6 9.0 30.2

28 14:39 18.3 1.8 71.1 7.4 30.1

29 14:40 18.3 1.8 72.5 6.9 25.2

30 14:41 18.7 1.5 83.7 6.6 25.1

31 14:42 18.9 1.3 135.2 6.1 23.6

32 14:43 18.1 1.8 101.1 18.0 30.8

33 14:44 17.9 2.0 70.7 12.0 66.1

34 14:45 18.5 1.6 76.0 6.9 41.4

35 14:46 18.4 1.7 83.8 6.2 23.6

36 14:47 18.4 1.7 74.4 12.9 27.3

37 14:48 17.9 2.0 71.0 10.1 41.6

38 14:49 18.4 1.7 76.3 7.1 34.0

39 14:50 18.2 1.8 81.1 7.9 20.5

40 14:51 18.1 2.0 72.3 9.6 28.8

41 14:52 18.7 1.5 88.5 7.9 31.0

42 14:53 18.5 1.6 100.7 8.1 26.2

43 14:54 18.5 1.6 79.7 12.0 27.0

44 14:55 18.1 1.9 81.6 12.7 45.3

45 14:56 18.4 1.6 75.9 10.2 40.3

46 14:57 18.4 1.7 82.8 6.0 30.0

47 14:58 18.2 1.8 76.4 13.2 23.5

48 14:59 18.3 1.7 74.6 11.4 50.2

49 15:00 18.6 1.5 84.0 9.3 37.5

50 15:01 18.7 1.5 98.9 8.7 31.2

51 15:02 18.9 1.3 126.9 13.1 32.9

52 15:03 18.6 1.5 108.9 164.8 80.1

53 15:04 18.5 1.6 88.7 180.2 782.4

54 15:05 18.6 1.5 92.0 118.2 720.1

55 15:06 18.7 1.5 109.6 12.3 349.6

56 15:07 18.5 1.6 97.7 16.1 43.4

57 15:08 18.5 1.6 92.2 12.6 54.8

58 15:09 18.6 1.6 105.8 13.1 41.1

59 15:10 18.5 1.6 102.9 15.2 45.7

60 15:11 18.4 1.7 97.0 17.7 55.6

Gas

Instrument Range

Post Test Calibration

Zero%

Span Gas Value

Calibration 

Pretest Calibration

Zero%

Calibration Information

Results

Absolute Bias (Zero)

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Span%

Span%
Cimarron Energy Run 3

Liberty Oil Well

Parshall, ND Start Time 15:30

Flare Run Length 60

06/15/11 Stop Time 16:30

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 100

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.2

10.0 2.5 77.7 284.0 30.0

0.0 0.0 0.0 0.0 0.0

10.0 2.5 76.6 305.8 28.1

0.0% 0.0% 0.1% 0.1% 0.0%

0.0% 0.6% 0.2% 0.7% 3.0%

0.0% 0.0% 0.7% 0.0% 0.2%

0.0% 0.8% 0.6% 1.5% 1.9%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

18.2 1.8 81.4 9.6 44.1

Run Length 

(Minutes) Time Uncorrected 

O2 %

Uncorrected 

CO2 %

Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

18.2 1.8 79.4 9.5 42.4

1 15:30 18.6 1.5 129.2 23.8 94.5

2 15:31 18.2 1.8 103.9 23.8 110.9

3 15:32 18.2 1.8 80.8 15.9 104.4

4 15:33 18.0 1.9 79.3 9.2 74.6

5 15:34 18.0 2.0 72.1 7.7 40.1

6 15:35 17.9 2.0 72.9 6.9 32.1

7 15:36 18.1 1.9 74.4 6.5 28.5

8 15:37 18.0 2.0 74.2 8.4 28.6

9 15:38 18.2 1.8 75.3 7.5 32.0

10 15:39 18.1 1.9 80.5 7.9 28.9

11 15:40 18.3 1.8 74.2 8.7 33.7

12 15:41 18.2 1.8 76.3 9.3 37.2

13 15:42 18.1 1.9 76.1 7.3 37.5

14 15:43 18.1 1.9 75.1 9.9 32.9

15 15:44 18.4 1.7 84.5 9.3 44.9

16 15:45 18.2 1.8 81.5 9.4 37.8

17 15:46 18.0 1.9 89.0 11.3 43.1

18 15:47 18.3 1.8 82.3 6.3 47.1

19 15:48 18.3 1.7 86.2 7.9 29.2

20 15:49 17.9 2.0 76.7 12.2 36.7

21 15:50 18.4 1.7 80.6 13.4 63.7

22 15:51 18.3 1.7 89.4 6.3 54.8

23 15:52 18.1 1.9 76.6 15.8 35.4

24 15:53 18.2 1.8 77.0 9.5 72.2

25 15:54 18.2 1.8 80.6 8.2 36.5

26 15:55 18.1 1.9 78.4 9.9 39.5

27 15:56 18.3 1.8 75.0 11.5 45.9

28 15:57 18.3 1.7 79.2 8.5 47.7

29 15:58 18.2 1.8 85.1 7.7 33.1

30 15:59 17.9 2.0 72.2 7.7 31.4

31 16:00 18.4 1.7 73.7 7.7 34.1

32 16:01 18.3 1.7 86.2 5.3 31.2

33 16:02 18.3 1.7 76.2 13.0 25.5

34 16:03 18.4 1.7 78.4 9.5 56.1

35 16:04 18.0 1.9 75.0 8.3 35.3

36 16:05 18.4 1.7 73.2 8.8 37.0

37 16:06 18.5 1.6 86.6 4.1 34.1

38 16:07 18.3 1.7 81.1 12.6 21.6

39 16:08 18.3 1.8 80.2 11.7 58.1

40 16:09 18.2 1.8 89.3 11.6 50.1

41 16:10 18.1 1.9 76.0 13.1 56.1

42 16:11 17.9 2.0 71.1 8.5 55.8

43 16:12 18.1 1.9 71.8 7.5 37.1

44 16:13 18.4 1.6 83.6 7.3 33.2

45 16:14 18.2 1.8 84.9 9.1 30.1

46 16:15 18.4 1.7 76.5 12.2 41.6

47 16:16 18.4 1.7 80.8 6.3 47.3

48 16:17 18.3 1.7 75.5 9.6 27.1

49 16:18 18.4 1.7 79.6 9.4 47.8

50 16:19 18.3 1.7 78.9 8.7 38.8

51 16:20 18.1 1.9 72.8 9.4 38.4

52 16:21 17.9 2.0 69.9 7.4 40.4

53 16:22 18.1 1.9 70.6 6.6 33.1

54 16:23 18.0 1.9 73.8 6.3 24.6

55 16:24 18.2 1.7 75.2 6.7 25.4

56 16:25 18.2 1.7 77.9 8.3 28.2

57 16:26 18.2 1.8 73.7 10.4 33.2

58 16:27 18.4 1.6 77.6 7.4 44.2

59 16:28 18.2 1.8 80.5 7.3 30.5

60 16:29 18.4 1.7 76.2 7.9 33.6

Zero%

Calibration Information

Span Gas Value

Calibration 

Pretest Calibration

Gas

Instrument Range

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Results

Absolute Bias (Zero)

Span%

Span%

Post Test Calibration

Zero%
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

6/15/2011

Outlet NMOC (lb/hr as C3H8) 0.89

Waste Gas Inlet NMOC (lb/hr as C3H8) 150.6

Pilot Inlet NMOC (lb/hr as C3H8) 0.5

Sum of Inlets NMOC (lb/hr as C3H8) 151.0

% DRE (mass flow in/out basis) 99.4%

% DRE (carbon balance) 98.9%

%DRE Calculations
4 oz. Inlet Pressure 
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

4 oz.

Run # 4 5 6 Average

Start Time 10:56 13:15 14:28

Stop Time 11:02 13:21 14:36

hrs Hours of Operation / Year 8760 8760 8760 8760

DS Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0

√ΔPAVG Inlet Average (Delta P)

1⁄2 (" H2O)1⁄2 0.1793 0.1769 0.1798 0.1787

CP Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84

TS Inlet Stack Temperature (°F) 61 63 67 64

Pbar Barometric Pressure (mbar) 938 938 938 938

Pbar Barometric Pressure (" Hg) 27.70 27.70 27.70 27.70

Ps Inlet Stack Pressure ('' H2O) 6.2 6.2 6.2 6.2

Carbon Dioxide (%vd) 0.4 0.3 0.3 0.4

Methane (%vd) 15.4 16.7 17.5 16.5

Ethane (%vd) 20.2 20.5 20.4 20.4

Propane (%vd) 31.5 32.2 32.1 31.9

Butanes (%vd) 18.1 17.9 18.6 18.2

Pentanes (%vd) 5.1 4.9 5.2 5.0

Hexanes+ (%vd) 2.8 2.4 3.0 2.7

Heat Content (Btu/scf) 2,227 2,229 2,299 2,252

Carbon Dioxide (%vd) 0.5 0.5 0.5 0.5

Methane (%vd) 46.3 46.3 46.3 46.3

Ethane (%vd) 19.9 19.9 19.9 19.9

Propane (%vd) 15.8 15.8 15.8 15.8

Butanes (%vd) 6.3 6.3 6.3 6.3

Pentanes (%vd) 1.5 1.5 1.5 1.5

Hexanes+ (%vd) 0.7 0.7 0.7 0.7

Heat Content (Btu/scf) 1,496 1,496 1,496 1,496

FACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18

FDSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17

dry Pilot Light NMOC (ppmvd as C3H8) 413,300 413,300 413,300 413,300

lb/hr Pilot Light NMOC (lb/hr as C3H8) 0.49 0.49 0.49 0.49

Run # 4 5 6 Average

Bws Inlet Moisture Content (%/100) - saturated 0.019 0.021 0.024 0.021

MD Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54

MA Inlet Molecular Weight Wet (lb/lb-mole) 35.20 35.18 35.12 35.17

VS Inlet Gas Velocity (ft/sec) 9.3 9.2 9.4 9.3

FACFM Inlet Gas Flow (acfm) 49 48 49 49

FDSCFM Inlet Gas Flow (dscfm) 46 45 45 45

dry NMOC (ppmvd as C3H8) 830,533 826,400 850,367 835,767

lb/hr NMOC (lb/hr as C3H8) 260 255 265 260

tpy NMOC (tons/year as C3H8) 1142 1119 1162 1141

Field Reference Method Data

Waste Gas Data

Reference Method Calculations

Pilot Light Data 
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

4 oz.

Run # 4 5 6 Average

Start Time 10:48 12:55 14:14

Stop Time 11:48 13:55 15:14

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

DS Stack Diameter (inches) 42.6 42.6 42.6 42.6

√ΔPAVG Average (Delta P)1⁄2 (" H2O)1⁄2 0.1607 0.1599 0.1560 0.1589

CP Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83

TS Stack Temperature (°F) 1320 1321 1327 1323

Pbar Barometric Pressure (mbar) 938 938 938 938

Pbar Barometric Pressure (" Hg) 27.70 27.70 27.70 27.70

Ps Stack Pressure ('' H2O) 0.00 0.00 0.00 0.00

Yd Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780

Tm Meter Temperature (°F) 57 65 69 64

Vm Sample Volume (ft3

) 36.340 36.409 37.287 36.679

ΔH Orifice Pressure Delta H (" H2O) 1.0 1.0 1.0 1.0

Vlc Moisture (g) 32.7 46.2 37.2 38.7

O2%vd O2 (%vd) 16.5 16.6 16.6 16.6

CO2%vd CO2 (%vd) 2.9 2.8 2.8 2.8

N2%vd N2 (%vd) 80.6 80.6 80.6 80.6

dry CO (ppmvd) 52.6 54.0 51.5 52.7

wet CH4 (ppmvw) 0.0 0.7 0.0 0.2

wet NMOC (ppmvw as C3H8) 0.0 1.9 0.4 0.7

Run # 4 5 6 Average

Vmstd Sample Volume (dscf) 33.662 33.213 33.775 33.550

Vwstd Moisture Volume (scf) 1.54 2.18 1.75 1.82

Bws Moisture Content (%/100) 0.044 0.062 0.049 0.052

MD Molecular Weight Dry (lb/lb-mole) 29.12 29.11 29.10 29.11

MA Molecular Weight Wet (lb/lb-mole) 28.63 28.43 28.56 28.54

VS Gas Velocity (ft/sec) 17.1 17.1 16.6 16.9

FACFM Gas Flow (acfm) 10,158 10,145 9,894 10,065

FDSCFM Gas Flow (dscfm) 2,667 2,613 2,572 2,617

lb/hr Gas Flow (lb/hr) 12,435 12,327 12,031 12,265

Fo Fo (unitless) 1.523 1.547 1.562 1.544

lb/hr CO (lb/hr) 0.6 0.6 0.6 0.6

tpy CO (tons/year) 2.7 2.7 2.5 2.6

dry CH4 (ppmvd) 0.0 0.7 0.0 0.2

lb/hr CH4 (lb/hr) 0.0 0.0 0.0 0.0

tpy CH4 (tons/year) 0.0 3.1 0.1 1.0

dry NMOC (ppmvd as C3H8) 0.0 2.0 0.4 0.8

lb/hr NMOC (lb/hr as C3H8) 0.000 0.0354 0.0068 0.014

tpy NMOC (tons/year as C3H8) 0.000 0.155 0.030 0.062

DRE TVOC DRE (%) - carbon balance 100.00% 99.98% 100.00% 99.99%

Field Reference Method Data

Reference Method Calculations
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

06/14/11

O2 CO2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 10.0

10.00 2.48 79.1 300.0 3.0

0.0 0.0 1.2 1.0 0.1

10.0 2.5 79.5 300.9 3.0

Linearity Bias (Zero) 0.0 0.0 1.2 1.0 0.1

Linearity Bias (Span) 10.0 2.5 78.8 309.1 2.9

% % (ppm) (ppm) (ppm)

0.00 0.00 0.0 0.0 0.0

10.00 2.48 79.1 300.0 3.0

21.10 5.00 182.0 750.0 5.0

1490.0 8.5

0.0 0.0 1.2 1.0 0.1

10.0 2.5 78.8 309.1 2.9

21.1 5.0 180.1 758.9 5.0

1505.2 8.4

0.0 0.0 1.2 1.0 0.1

0.0 0.0 0.3 9.1 0.1

0.0 0.0 1.9 8.9 0.0

0.0 0.0 0.0 15.2 0.0

0.00% 0.00% 0.00% 0.00% 0.00%

0.14% 0.00% 0.38% 0.55% 0.50%

0.14% 0.60% 1.04% 1.02% 1.00%

Linearity Information

Gas

Span Gas Value/Range

Bias Gas Value

Gas Concentration

1

2

3

4

Difference

1

4

Response

1

2

Span Bias 

Max Calibration Error

Bias Check (Zero)

Bias Check (Span)

2

3

4

Results

3

Zero Bias
Cimarron Energy Run 4

Liberty Oil Well

Parshall ND Start Time 10:48:13

Flare Run Length 60

06/14/11 Stop Time 11:48

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

0.0 0.0 1.2 1.0 0.1

10.0 2.5 79.5 300.9 3.0

-0.1 0.0 5.2 0.0 0.1

10.0 2.5 81.1 305.9 3.0

0.5% 0.0% 2.2% 0.1% 0.0%

0.1% 0.2% 1.3% 0.2% 1.0%

0.5% 0.0% 2.2% 0.1% 0.0%

0.0% 0.2% 0.9% 0.3% 0.5%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

16.5 2.9 52.6 -0.5 -0.1

Run Length 

(Minutes) Time Uncorrected 

O2 %

 Uncorrected 

CO2 %

 Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

16.6 2.9 54.5 0.0 0.0

1 10:48 16.5 2.9 56.2 0.3 0.0

2 10:49 16.4 2.9 55.1 0.0 0.0

3 10:50 16.4 2.9 55.8 0.7 0.0

4 10:51 16.3 3.0 54.4 -0.2 0.0

5 10:52 16.8 2.7 57.5 0.1 0.0

6 10:53 16.8 2.7 59.0 -0.4 0.0

7 10:54 16.6 2.8 57.3 1.4 0.0

8 10:55 16.3 3.0 55.0 0.5 0.0

9 10:56 16.6 2.9 56.1 0.7 0.0

10 10:57 16.7 2.8 59.5 0.3 0.0

11 10:58 16.4 3.0 56.3 0.1 0.0

12 10:59 16.5 2.9 56.3 1.3 0.0

13 11:00 16.5 2.9 56.3 0.2 0.0

14 11:01 16.4 3.0 54.0 -0.1 0.0

15 11:02 16.3 3.0 53.5 -0.6 0.0

16 11:03 16.4 2.9 52.8 0.2 0.0

17 11:04 16.5 2.9 54.3 -0.5 0.0

18 11:05 16.4 3.0 53.0 -0.6 0.0

19 11:06 16.7 2.8 54.7 0.1 0.0

20 11:07 16.6 2.8 55.4 -0.2 0.0

21 11:08 16.4 3.0 53.1 -0.3 0.0

22 11:09 16.5 2.9 54.4 0.2 0.0

23 11:10 16.5 2.9 54.3 -0.4 0.0

24 11:11 16.4 3.0 53.5 -0.4 0.0

25 11:12 16.6 2.8 54.5 -0.5 0.0

26 11:13 16.5 3.0 54.2 0.3 0.0

27 11:14 16.8 2.8 56.0 -0.2 0.0

28 11:15 16.7 2.8 56.8 0.0 0.0

29 11:16 16.4 3.0 52.5 0.4 0.0

30 11:17 16.6 2.9 52.0 1.1 0.0

31 11:18 16.6 2.9 55.2 0.5 0.0

32 11:19 16.5 2.9 53.1 0.1 0.0

33 11:20 16.6 2.9 55.5 -0.2 0.0

34 11:21 16.4 2.9 53.4 0.0 0.0

35 11:22 16.5 3.0 52.1 0.1 0.0

36 11:23 16.7 2.9 54.6 -0.4 0.0

37 11:24 16.7 2.8 55.2 -0.2 0.0

38 11:25 16.8 2.8 57.3 -0.4 0.0

39 11:26 16.7 2.9 55.4 -0.3 0.0

40 11:27 16.8 2.8 55.3 0.8 0.0

41 11:28 16.5 2.9 53.1 -0.2 0.0

42 11:29 16.8 2.8 52.4 -0.3 0.0

43 11:30 16.9 2.7 55.3 0.0 0.0

44 11:31 16.8 2.8 54.7 0.1 0.0

45 11:32 16.7 2.8 54.8 0.2 0.0

46 11:33 16.9 2.7 55.3 -0.2 0.0

47 11:34 16.7 2.8 55.5 0.0 0.0

48 11:35 16.6 2.9 53.4 -0.1 0.0

49 11:36 16.6 2.9 52.8 0.6 0.0

50 11:37 16.7 2.8 54.6 -0.2 0.0

51 11:38 16.7 2.8 53.1 -0.8 0.0

52 11:39 16.7 2.8 54.1 0.4 0.0

53 11:40 16.7 2.8 52.4 -0.7 0.0

54 11:41 16.4 3.0 52.7 -0.4 0.0

55 11:42 16.3 3.0 50.3 0.2 0.0

56 11:43 16.7 2.8 51.5 -0.4 0.0

57 11:44 16.6 2.9 53.6 -0.1 0.0

58 11:45 16.7 2.8 51.7 -0.2 0.0

59 11:46 16.7 2.8 54.3 0.0 0.0

60 11:47 16.5 2.9 52.2 -0.1 0.0

Calibration 

Pretest Calibration

Absolute Bias (Zero)

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Zero%

Span%

Calibration Information

Instrument Range

Span Gas Value

Gas

Zero%

Span%

Results

Post Test Calibration
Cimarron Energy Run 5

Liberty Oil Well

Parshall ND Start Time 12:55:23

Flare Run Length 60

06/14/11 Stop Time 13:55

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

-0.1 0.0 5.2 0.0 0.1

10.0 2.5 81.1 305.9 3.0

0.0 0.0 0.6 0.0 0.1

10.0 2.5 79.7 301.9 3.0

0.0% 0.0% 0.3% 0.1% 0.0%

0.1% 0.2% 0.5% 0.5% 0.1%

0.5% 0.0% 2.5% 0.0% 0.0%

0.0% 0.4% 0.8% 0.3% 0.9%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

16.6 2.8 54.0 0.7 1.9

Run Length 

(Minutes) Time Uncorrected 

O2 %

 Uncorrected 

CO2 %

 Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

16.6 2.8 55.8 0.7 1.9

1 12:55:23 16.4 2.9 61.7 1.0 0.2

2 12:56:23 16.6 2.8 53.9 0.9 0.2

3 12:57:23 16.6 2.8 57.9 0.1 0.1

4 12:58:23 16.5 2.9 58.3 0.7 0.9

5 12:59:23 16.4 2.9 52.1 0.4 1.0

6 13:00:23 16.6 2.8 56.6 0.0 0.4

7 13:01:23 16.5 2.8 54.9 0.0 0.0

8 13:02:23 16.5 2.9 54.2 0.0 -0.1

9 13:03:23 16.7 2.7 58.5 -0.1 0.3

10 13:04:23 16.7 2.8 57.3 0.4 0.0

11 13:05:23 16.4 2.9 56.8 0.9 1.1

12 13:06:23 16.6 2.8 53.6 1.0 1.7

13 13:07:23 16.4 2.9 54.9 0.1 1.0

14 13:08:23 16.7 2.7 56.2 0.0 -0.1

15 13:09:23 17.2 2.5 60.2 0.4 0.1

16 13:10:23 17.0 2.6 82.1 2.1 0.6

17 13:11:23 16.7 2.7 63.6 15.1 15.1

18 13:12:23 16.8 2.7 61.6 4.1 53.2

19 13:13:23 16.8 2.7 61.1 1.4 5.1

20 13:14:23 16.6 2.8 55.5 1.0 3.1

21 13:15:23 16.6 2.9 54.8 0.8 2.3

22 13:16:23 16.8 2.7 55.8 0.0 1.8

23 13:17:23 16.7 2.7 56.5 -0.1 0.8

24 13:18:23 16.9 2.7 58.2 0.4 0.7

25 13:19:23 17.0 2.6 56.9 1.1 1.6

26 13:20:23 16.8 2.7 57.5 1.0 1.9

27 13:21:23 16.7 2.7 54.8 1.0 1.8

28 13:22:23 16.7 2.7 53.6 1.1 2.3

29 13:23:23 16.9 2.6 58.9 0.9 1.7

30 13:24:23 16.9 2.6 60.0 1.2 1.4

31 13:25:23 17.0 2.6 63.2 2.0 2.0

32 13:26:23 16.5 2.9 58.3 1.9 3.4

33 13:27:23 16.6 2.8 51.9 1.3 5.5

34 13:28:23 16.6 2.8 56.2 0.5 1.8

35 13:29:23 16.3 3.0 52.5 0.0 0.4

36 13:30:23 16.5 2.9 50.6 -0.1 0.0

37 13:31:23 16.5 2.9 56.4 0.0 0.2

38 13:32:23 16.4 2.9 51.7 0.0 -0.4

39 13:33:23 16.4 2.9 53.2 0.0 0.4

40 13:34:23 16.5 2.9 54.2 -0.1 0.0

41 13:35:23 16.4 2.9 52.6 0.0 -0.2

42 13:36:23 16.4 2.9 52.7 0.0 -0.1

43 13:37:23 16.5 2.9 51.8 0.0 0.1

44 13:38:23 16.4 2.9 52.5 0.0 -0.3

45 13:39:23 16.3 3.0 51.6 0.0 -0.3

46 13:40:23 16.6 2.8 53.2 0.1 0.0

47 13:41:23 16.4 2.9 53.4 0.1 0.8

48 13:42:23 16.6 2.8 53.6 0.0 -0.3

49 13:43:23 16.5 2.9 51.3 -0.1 -0.3

50 13:44:23 16.3 3.0 52.9 0.0 -0.2

51 13:45:23 16.4 2.9 51.1 0.0 -0.1

52 13:46:23 16.6 2.8 52.2 0.0 0.0

53 13:47:23 16.6 2.8 57.2 -0.1 0.7

54 13:48:23 16.7 2.8 53.7 0.1 0.0

55 13:49:23 16.4 2.9 55.3 0.0 0.0

56 13:50:23 16.4 3.0 53.7 0.0 0.4

57 13:51:23 16.6 2.8 53.2 0.0 0.7

58 13:52:23 16.5 2.8 55.9 0.0 -0.3

59 13:53:23 16.4 2.9 53.4 0.1 -0.1

60 13:54:23 16.6 2.8 52.7 0.0 -0.1

Gas

Instrument Range

Post Test Calibration

Zero%

Span Gas Value

Calibration 

Pretest Calibration

Zero%

Calibration Information

Results

Absolute Bias (Zero)

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Span%

Span%
Cimarron Energy Run 6

Liberty Oil Well

Parshall ND Start Time 14:14:23

Flare Run Length 60

06/14/11 Stop Time 15:14

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

0.0 0.0 0.6 0.0 0.1

10.0 2.5 79.7 301.9 3.0

-0.1 0.0 0.2 0.0 0.1

10.0 2.5 81.8 307.4 3.0

0.5% 0.0% 0.5% 0.1% 0.0%

0.1% 0.6% 1.6% 0.1% 0.4%

0.5% 0.0% 0.2% 0.0% 0.0%

0.0% 0.8% 1.2% 0.4% 0.3%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

16.6 2.8 51.5 0.0 0.4

Run Length 

(Minutes) Time Uncorrected 

O2 %

 Uncorrected 

CO2 %

 Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

16.6 2.8 52.7 0.0 0.4

1 14:14 16.6 2.8 52.0 0.0 1.5

2 14:15 16.6 2.8 52.1 0.0 -0.1

3 14:16 16.7 2.7 50.0 0.0 -0.1

4 14:17 16.7 2.7 52.5 0.0 -0.1

5 14:18 16.7 2.7 51.7 -0.1 -0.2

6 14:19 16.6 2.8 52.5 -0.1 -0.2

7 14:20 16.7 2.8 53.9 -0.1 -0.1

8 14:21 16.7 2.7 53.9 -0.1 0.1

9 14:22 16.6 2.8 52.8 0.0 0.3

10 14:23 16.6 2.8 51.2 -0.1 0.3

11 14:24 16.6 2.8 52.7 -0.1 0.5

12 14:25 16.6 2.8 53.3 -0.1 1.6

13 14:26 16.5 2.9 51.4 -0.1 0.1

14 14:27 16.8 2.7 54.6 0.1 0.1

15 14:28 16.7 2.7 53.9 0.0 0.1

16 14:29 16.6 2.8 51.1 -0.1 -0.2

17 14:30 16.7 2.8 52.8 -0.1 0.5

18 14:31 16.8 2.7 52.7 -0.1 -0.1

19 14:32 16.6 2.8 56.0 0.0 0.1

20 14:33 16.7 2.8 49.2 -0.1 0.5

21 14:34 16.8 2.7 53.1 0.0 0.6

22 14:35 16.8 2.7 54.2 0.0 -0.4

23 14:36 16.6 2.8 50.1 0.0 0.6

24 14:37 16.5 2.9 52.0 0.0 0.7

25 14:38 16.8 2.7 48.7 -0.1 0.8

26 14:39 16.8 2.7 50.3 0.0 1.3

27 14:40 16.7 2.7 50.6 -0.1 1.2

28 14:41 16.8 2.7 52.4 -0.1 0.2

29 14:42 16.6 2.8 52.1 0.0 -0.2

30 14:43 16.7 2.7 51.1 0.0 -0.1

31 14:44 16.7 2.7 52.5 0.0 0.5

32 14:45 16.6 2.8 53.0 0.0 1.3

33 14:46 16.5 2.8 50.6 0.0 0.7

34 14:47 16.7 2.8 49.4 -0.1 0.1

35 14:48 16.8 2.7 56.2 0.0 -0.1

36 14:49 16.6 2.8 52.3 0.0 1.2

37 14:50 16.6 2.7 53.1 0.0 0.8

38 14:51 16.7 2.7 55.3 0.0 0.6

39 14:52 16.5 2.8 51.6 0.0 0.6

40 14:53 16.5 2.8 51.1 0.0 0.7

41 14:54 16.5 2.8 53.7 0.1 0.7

42 14:55 16.6 2.8 52.5 0.0 -0.1

43 14:56 16.5 2.8 54.7 0.1 0.2

44 14:57 16.6 2.8 53.2 0.1 0.6

45 14:58 16.7 2.7 53.5 -0.1 0.7

46 14:59 16.6 2.8 54.8 0.0 0.2

47 15:00 16.7 2.7 52.1 0.0 0.4

48 15:01 16.7 2.7 56.6 0.1 0.5

49 15:02 16.6 2.8 54.8 0.9 0.8

50 15:03 16.7 2.8 52.8 0.1 1.7

51 15:04 16.5 2.9 54.3 0.0 0.5

52 15:05 16.6 2.8 51.8 -0.1 0.7

53 15:06 16.8 2.7 52.9 -0.1 0.7

54 15:07 16.6 2.8 55.6 0.0 0.5

55 15:08 16.5 2.8 52.2 0.8 0.3

56 15:09 16.6 2.8 52.8 0.3 1.9

57 15:10 16.7 2.7 55.6 0.1 0.6

58 15:11 16.6 2.7 51.9 -0.1 0.2

59 15:12 16.6 2.8 51.5 0.0 0.3

60 15:13 16.6 2.7 54.6 0.0 0.7

Zero%

Calibration Information

Span Gas Value

Calibration 

Pretest Calibration

Gas

Instrument Range

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Results

Absolute Bias (Zero)

Span%

Span%

Post Test Calibration

Zero%
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

4 oz.

Outlet NMOC (lb/hr as C3H8) 0.01

Waste Gas Inlet NMOC (lb/hr as C3H8) 260.0

Pilot Inlet NMOC (lb/hr as C3H8) 0.5

Sum of Inlets NMOC (lb/hr as C3H8) 260.5

% DRE (mass flow in/out basis) 99.99%

% DRE (carbon balance) 99.99%

%DRE Calculations
10 oz. Inlet Pressure 
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

10 oz.

Run # 7 8 9 Average

Start Time 15:37 16:56 8:56

Stop Time 15:44 17:08 9:03

hrs Hours of Operation / Year 8760 8760 8760 8760

DS Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0

√ΔPAVG Inlet Average (Delta P)

1⁄2 (" H2O)1⁄2 0.3290 0.3314 0.3338 0.3314

CP Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84

TS Inlet Stack Temperature (°F) 68 73 74 72

Pbar Barometric Pressure (mbar) 938 938 936 937

Pbar Barometric Pressure (" Hg) 27.70 27.70 27.64 27.68

Ps Inlet Stack Pressure ('' H2O) 9.5 9.5 9.5 9.5

Carbon Dioxide (%vd) 0.3 0.3 0.3 0.3

Methane (%vd) 16.5 17.9 17.6 17.3

Ethane (%vd) 20.5 20.5 21.3 20.8

Propane (%vd) 33.0 32.0 32.9 32.6

Butanes (%vd) 19.0 18.5 18.1 18.6

Pentanes (%vd) 5.3 5.2 5.0 5.2

Hexanes+ (%vd) 2.8 3.0 2.6 2.8

Heat Content (Btu/scf) 2,325 2,305 2,295 2,308

Carbon Dioxide (%vd) 0.5 0.5 0.5 0.5

Methane (%vd) 46.1 46.1 46.1 46.1

Ethane (%vd) 19.9 19.9 19.9 19.9

Propane (%vd) 15.9 15.9 15.9 15.9

Butanes (%vd) 6.4 6.4 6.4 6.4

Pentanes (%vd) 1.6 1.6 1.6 1.6

Hexanes+ (%vd) 0.9 0.9 0.9 0.9

Heat Content (Btu/scf) 1,514 1,514 1,514 1,514

FACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18

FDSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17

dry Pilot Light NMOC (ppmvd as C3H8) 421,267 421,267 421,267 421,267

lb/hr Pilot Light NMOC (lb/hr as C3H8) 0.50 0.50 0.50 0.50

Run # 7 8 9 Average

Bws Inlet Moisture Content (%/100) - saturated 0.024 0.029 0.029 0.028

MD Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54

MA Inlet Molecular Weight Wet (lb/lb-mole) 35.11 35.03 35.02 35.06

VS Inlet Gas Velocity (ft/sec) 17.2 17.4 17.6 17.4

FACFM Inlet Gas Flow (acfm) 90 91 92 91

FDSCFM Inlet Gas Flow (dscfm) 83 83 84 83

dry NMOC (ppmvd as C3H8) 864,867 851,467 848,100 854,811

lb/hr NMOC (lb/hr as C3H8) 494 486 487 489

tpy NMOC (tons/year as C3H8) 2168 2131 2135 2145

Field Reference Method Data

Waste Gas Lab Data

Reference Method Calculations

Pilot Light Data 
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

10 oz.

Run # 7 8 9 Average

Start Time 15:31 16:48 8:45

Stop Time 16:31 17:48 9:45

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

DS Stack Diameter (inches) 42.6 42.6 42.6 42.6

√ΔPAVG Average (Delta P)1⁄2 (" H2O)1⁄2 0.1719 0.1681 0.1813 0.1738

CP Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83

TS Stack Temperature (°F) 1973 1992 1992 1986

Pbar Barometric Pressure (mbar) 938 938 936 937

Pbar Barometric Pressure (" Hg) 27.70 27.70 27.64 27.68

Ps Stack Pressure ('' H2O) 0.00 0.00 0.00 0.00

Yd Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780

Tm Meter Temperature (°F) 74 79 62 72

Vm Sample Volume (ft3

) 37.385 37.148 37.088 37.207

ΔH Orifice Pressure Delta H (" H2O) 1.0 1.0 1.0 1.0

Vlc Moisture (g) 65.2 43.7 52.2 53.7

O2%vd O2 (%vd) 14.8 14.9 15.1 14.9

CO2%vd CO2 (%vd) 3.9 3.8 3.8 3.8

N2%vd N2 (%vd) 81.3 81.3 81.1 81.2

dry CO (ppmvd) 15.5 21.0 15.4 17.3

wet CH4 (ppmvw) 0.0 0.0 0.0 0.0

wet NMOC (ppmvw as C3H8) 0.3 0.6 0.1 0.3

Run # 7 8 9 Average

Vmstd Sample Volume (dscf) 33.536 33.037 33.984 33.519

Vwstd Moisture Volume (scf) 3.07 2.06 2.46 2.53

Bws Moisture Content (%/100) 0.084 0.059 0.068 0.070

MD Molecular Weight Dry (lb/lb-mole) 29.22 29.21 29.21 29.21

MA Molecular Weight Wet (lb/lb-mole) 28.28 28.55 28.45 28.43

VS Gas Velocity (ft/sec) 21.5 21.0 22.7 21.7

FACFM Gas Flow (acfm) 12,780 12,486 13,507 12,925

FDSCFM Gas Flow (dscfm) 2,352 2,343 2,505 2,400

lb/hr Gas Flow (lb/hr) 11,304 11,069 11,903 11,425

Fo Fo (unitless) 1.562 1.565 1.537 1.555

lb/hr CO (lb/hr) 0.2 0.2 0.2 0.2

tpy CO (tons/year) 0.7 0.9 0.7 0.8

dry CH4 (ppmvd) 0.0 0.0 0.0 0.0

lb/hr CH4 (lb/hr) 0.0 0.0 0.0 0.0

tpy CH4 (tons/year) 0.0 0.0 0.0 0.0

dry NMOC (ppmvd as C3H8) 0.3 0.7 0.1 0.4

lb/hr NMOC (lb/hr as C3H8) 0.005 0.0107 0.0013 0.006

tpy NMOC (tons/year as C3H8) 0.022 0.047 0.006 0.025

DRE TVOC DRE (%) - carbon balance 100.00% 99.99% 100.00% 100.00%

Field Reference Method Data

Reference Method Calculations
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

06/14/11

O2 CO2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 10.0

10.00 2.48 79.1 300.0 3.0

-0.1 0.0 1.1 0.0 0.1

10.0 2.5 78.0 294.2 3.0

Linearity Bias (Zero) 0.0 0.0 -0.2 1.9 0.0

Linearity Bias (Span) 10.0 2.5 77.0 295.4 3.0

% % (ppm) (ppm) (ppm)

0.00 0.00 0.0 0.0 0.0

10.00 2.48 79.1 300.0 3.0

21.10 5.00 182.0 750.0 5.0

1490.0 8.5

0.0 0.0 -0.2 1.9 0.0

10.0 2.5 77.0 295.4 3.0

21.1 5.0 179.0 749.6 5.0

1500.0 8.4

0.0 0.0 0.2 1.9 0.0

0.0 0.0 2.1 4.6 0.0

0.0 0.0 3.0 0.4 0.0

0.0 0.0 0.0 10.0 0.0

0.47% 0.00% 0.71% 0.13% 1.00%

0.00% 0.00% 0.55% 0.08% 0.20%

0.00% 0.20% 1.65% 0.67% 0.40%

Span Bias 

Max Calibration Error

Bias Check (Zero)

Bias Check (Span)

2

3

4

Results

3

Zero Bias

4

Difference

1

4

Response

1

2

Gas Concentration

1

2

3

Linearity Information

Gas

Span Gas Value/Range

Bias Gas Value
Cimarron Energy Run 7

Liberty Oil Well

Parshall ND Start Time 15:31:23

Flare Run Length 60

06/14/11 Stop Time 16:31

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

-0.1 0.0 0.2 0.0 0.1

10.0 2.5 81.8 307.4 3.0

0.0 0.0 1.4 0.0 0.1

10.0 2.5 80.2 305.0 3.0

0.0% 0.0% 0.1% 0.1% 0.0%

0.1% 0.2% 0.8% 0.3% 0.6%

0.5% 0.0% 0.7% 0.0% 0.0%

0.0% 0.4% 0.9% 0.2% 0.2%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

14.8 3.9 15.5 0.0 0.3

Run Length 

(Minutes) Time Uncorrected 

O2 %

 Uncorrected 

CO2 %

 Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

14.8 3.9 16.5 0.0 0.4

1 15:31 14.7 4.0 17.1 0.1 0.9

2 15:32 14.9 3.9 17.2 0.0 0.8

3 15:33 14.9 3.9 15.5 0.1 0.8

4 15:34 14.8 3.9 18.4 0.0 0.8

5 15:35 14.9 3.9 14.5 -0.1 0.8

6 15:36 14.8 4.0 14.0 0.0 0.8

7 15:37 14.9 3.9 15.2 -0.1 0.8

8 15:38 14.8 4.0 15.8 0.0 0.8

9 15:39 14.7 4.0 13.9 0.0 0.8

10 15:40 15.0 3.9 15.8 0.0 0.2

11 15:41 14.8 3.9 13.6 0.0 -0.3

12 15:42 15.0 3.8 22.7 -0.1 0.5

13 15:43 15.1 3.8 17.4 0.0 0.6

14 15:44 14.9 3.9 17.4 -0.1 0.5

15 15:45 14.8 4.0 14.1 0.0 0.3

16 15:46 14.9 3.9 15.4 0.0 0.0

17 15:47 14.8 4.0 30.7 -0.1 0.5

18 15:48 14.8 4.0 15.9 0.0 0.2

19 15:49 15.2 3.7 23.0 0.0 0.4

20 15:50 14.5 4.1 21.8 -0.1 0.4

21 15:51 14.9 3.9 11.6 0.0 0.2

22 15:52 14.7 4.0 16.3 -0.1 0.5

23 15:53 14.8 4.0 13.1 -0.1 0.5

24 15:54 15.1 3.8 16.2 0.0 0.5

25 15:55 14.9 3.8 16.6 0.0 0.5

26 15:56 14.9 3.9 15.8 0.0 0.5

27 15:57 15.2 3.7 20.7 0.0 0.9

28 15:58 15.0 3.8 22.7 -0.1 0.6

29 15:59 15.0 3.8 21.9 0.0 0.2

30 16:00 14.9 3.9 23.2 0.0 0.1

31 16:01 14.8 4.0 14.1 0.0 0.5

32 16:02 14.9 3.9 17.5 0.0 0.6

33 16:03 14.8 4.0 13.2 0.0 0.1

34 16:04 14.9 3.9 18.2 0.1 0.2

35 16:05 14.8 4.0 15.4 0.0 0.3

36 16:06 14.8 4.0 14.0 -0.1 -0.5

37 16:07 14.8 4.0 14.6 -0.1 0.4

38 16:08 14.8 4.0 13.9 -0.1 0.6

39 16:09 14.4 4.2 16.7 0.0 0.6

40 16:10 15.0 3.8 12.0 -0.1 0.5

41 16:11 15.0 3.8 24.2 0.0 0.6

42 16:12 15.1 3.8 30.0 -0.1 0.8

43 16:13 14.9 3.9 14.9 0.0 0.7

44 16:14 14.9 3.9 19.4 -0.1 0.6

45 16:15 14.7 4.0 12.9 -0.1 0.4

46 16:16 14.7 4.0 17.8 -0.1 -0.2

47 16:17 14.6 4.1 19.6 0.0 0.4

48 16:18 15.0 3.9 15.7 0.0 0.2

49 16:19 14.8 4.0 17.2 0.0 0.2

50 16:20 15.1 3.8 15.9 0.0 0.6

51 16:21 14.7 4.0 17.6 0.1 1.0

52 16:22 14.4 4.2 10.5 0.0 0.6

53 16:23 14.6 4.1 11.3 0.0 -0.2

54 16:24 14.6 4.0 13.7 0.0 -0.5

55 16:25 14.6 4.1 11.3 0.0 -0.1

56 16:26 14.8 3.9 13.9 -0.1 -0.8

57 16:27 14.6 4.1 11.1 0.1 -0.3

58 16:28 14.5 4.2 11.8 0.0 0.1

59 16:29 14.6 4.1 14.5 0.0 0.4

60 16:30 14.7 4.0 11.0 -0.1 0.6

Results

Absolute Bias (Zero)

Span%

Span%

Post Test Calibration

Zero%

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Zero%

Calibration Information

Span Gas Value

Calibration 

Pretest Calibration

Gas

Instrument Range
Cimarron Energy Run 8

Liberty Oil Well

Parshall ND Start Time 16:48:23

Flare Run Length 60

06/14/11 Stop Time 17:48

O2 CO2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

0.0 0.0 1.4 0.0 0.1

10.0 2.5 80.2 305.0 3.0

-0.1 0.0 0.2 0.0 0.1

10.0 2.5 81.3 299.1 3.1

0.3% 0.0% 0.5% 0.1% 0.0%

0.1% 0.2% 1.4% 0.7% 1.2%

0.3% 0.0% 0.7% 0.0% 0.0%

0.0% 0.0% 0.6% 0.4% 0.6%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

14.9 3.8 21.0 0.0 0.6

Run Length 

(Minutes) Time Uncorrected 

O2 %

 Uncorrected 

CO2 %

 Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

14.9 3.8 22.0 0.0 0.7

1 16:48 14.7 4.0 17.2 -0.1 2.4

2 16:49 15.2 3.6 22.6 0.0 1.4

3 16:50 14.9 3.8 24.1 -0.1 1.4

4 16:51 14.6 4.1 19.9 -0.1 1.2

5 16:52 14.7 4.0 14.8 0.0 1.3

6 16:53 14.6 4.0 13.2 0.0 1.3

7 16:54 14.5 4.2 14.0 -0.1 1.2

8 16:55 14.7 4.0 13.0 0.0 1.4

9 16:56 15.1 3.8 15.6 0.1 1.4

10 16:57 15.1 3.7 22.6 0.1 1.4

11 16:58 14.8 3.9 20.1 0.0 1.4

12 16:59 14.8 3.9 16.4 0.1 1.4

13 17:00 14.6 4.1 13.2 0.0 1.2

14 17:01 14.7 4.0 13.7 -0.1 1.2

15 17:02 14.9 3.9 14.1 0.0 1.2

16 17:03 14.7 4.0 13.0 -0.2 1.2

17 17:04 14.6 4.0 17.6 0.0 1.2

18 17:05 14.8 3.9 11.7 0.1 0.2

19 17:06 14.8 3.9 14.5 -0.1 -0.5

20 17:07 14.6 4.0 13.4 0.0 -0.4

21 17:08 14.6 4.1 14.8 -0.1 0.3

22 17:09 14.8 4.0 14.8 -0.1 0.3

23 17:10 15.0 3.8 20.3 0.0 0.9

24 17:11 14.8 4.0 18.5 0.0 1.0

25 17:12 15.1 3.7 21.2 -0.1 1.0

26 17:13 15.0 3.8 20.2 -0.1 1.0

27 17:14 15.1 3.7 20.0 0.1 0.5

28 17:15 15.0 3.8 18.7 0.1 -0.6

29 17:16 15.2 3.7 19.3 -0.1 -0.2

30 17:17 15.3 3.6 31.2 -0.1 0.5

31 17:18 15.1 3.7 24.2 -0.1 1.0

32 17:19 15.1 3.8 21.0 -0.1 1.2

33 17:20 15.0 3.9 19.8 -0.1 0.8

34 17:21 15.1 3.7 20.4 -0.1 0.8

35 17:22 15.0 3.7 22.1 0.0 1.1

36 17:23 15.0 3.8 18.9 0.0 1.2

37 17:24 15.2 3.7 22.7 0.0 -0.4

38 17:25 15.1 3.7 23.3 -0.1 -0.1

39 17:26 14.9 3.8 18.2 -0.2 0.5

40 17:27 15.0 3.8 19.8 0.0 0.7

41 17:28 15.1 3.7 22.9 -0.1 -0.4

42 17:29 15.3 3.6 138.2 -0.1 0.9

43 17:30 15.3 3.7 90.9 0.0 0.4

44 17:31 15.0 3.8 32.2 -0.1 -0.2

45 17:32 15.1 3.7 47.7 -0.1 -0.5

46 17:33 15.0 3.9 18.3 -0.1 0.3

47 17:34 14.9 3.8 14.7 -0.1 1.1

48 17:35 14.9 3.8 18.0 0.0 1.2

49 17:36 14.9 3.8 15.8 0.1 0.6

50 17:37 15.2 3.7 20.5 0.0 -0.3

51 17:38 15.0 3.8 20.9 -0.1 1.0

52 17:39 14.9 3.9 13.3 0.0 1.2

53 17:40 15.3 3.6 24.7 -0.1 1.2

54 17:41 14.8 3.9 18.7 0.0 1.0

55 17:42 14.7 4.0 14.4 -0.1 0.5

56 17:43 14.7 4.0 15.9 -0.1 0.3

57 17:44 14.8 3.9 12.4 0.0 0.2

58 17:45 14.9 3.8 18.2 -0.1 0.1

59 17:46 14.9 3.9 14.6 -0.1 0.2

60 17:47 14.8 3.9 14.8 0.1 0.3

Zero%

Calibration Information

Span Gas Value

Calibration 

Pretest Calibration

Gas

Instrument Range

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Results

Absolute Bias (Zero)

Span%

Span%

Post Test Calibration

Zero%
Cimarron Energy Run 9

Liberty Oil Well

Parshall ND Start Time 8:45:06

Flare Run Length 60

06/14/11 Stop Time 9:45

O2 CO2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 10.0

10.0 2.5 79.1 300.0 3.0

-0.1 0.0 1.1 0.0 0.1

10.0 2.5 78.0 294.2 3.0

0.0 0.0 1.1 0.1 0.0

10.0 2.5 77.1 301.4 3.0

0.0% 0.0% 0.1% 0.1% 1.0%

0.1% 0.4% 0.9% 0.5% 1.0%

0.5% 0.0% 0.0% 0.0% 1.0%

0.0% 0.2% 0.5% 0.5% 0.4%

 Corrected O2 

%

 Corrected 

CO2 %

 Corrected CO 

ppm

 Corrected 

CH4 ppmvw

 Corrected 

TVOC ppm

15.1 3.8 15.4 -0.1 0.1

Run Length 

(Minutes) Time Uncorrected 

O2 %

 Uncorrected 

CO2 %

 Uncorrected 

CO ppm

 Uncorrected 

CH4 ppmvw

 Uncorrected 

TVOC ppm

15.1 3.8 16.0 0.0 0.1

1 6/15/11 8:45 15.2 3.7 16.8 0.0 0.4

2 6/15/11 8:46 15.0 3.8 15.4 0.0 0.3

3 6/15/11 8:47 15.1 3.8 15.0 -0.1 0.3

4 6/15/11 8:48 15.1 3.8 14.2 0.0 0.3

5 6/15/11 8:49 15.1 3.8 13.9 0.0 0.3

6 6/15/11 8:50 15.2 3.7 14.68 -0.1 0.3

7 6/15/11 8:51 14.9 3.9 15.0 0.0 0.3

8 6/15/11 8:52 15.1 3.7 14.9 0.0 0.3

9 6/15/11 8:53 15.1 3.8 14.0 0.0 0.4

10 6/15/11 8:54 15.0 3.8 15.2 0.0 0.3

11 6/15/11 8:55 15.0 3.9 14.4 -0.1 0.0

12 6/15/11 8:56 15.1 3.8 13.8 -0.1 0.4

13 6/15/11 8:57 15.2 3.8 15.0 0.0 0.8

14 6/15/11 8:58 15.0 3.8 16.2 -0.1 0.7

15 6/15/11 8:59 15.0 3.9 13.1 0.0 0.3

16 6/15/11 9:00 15.1 3.8 14.2 -0.1 0.1

17 6/15/11 9:01 15.0 3.9 14.8 -0.1 0.1

18 6/15/11 9:02 15.2 3.8 15.5 0.0 0.2

19 6/15/11 9:03 15.0 3.9 14.8 0.0 0.1

20 6/15/11 9:04 15.0 3.8 14.2 0.0 0.0

21 6/15/11 9:05 14.9 3.9 13.16 0.0 0.1

22 6/15/11 9:06 15.0 3.9 13.9 0.0 0.1

23 6/15/11 9:07 15.0 3.9 13.2 -0.1 0.1

24 6/15/11 9:08 15.0 3.9 13.1 0.0 0.2

25 6/15/11 9:09 15.1 3.8 15.2 0.0 0.3

26 6/15/11 9:10 14.8 4.0 12.0 0.0 0.2

27 6/15/11 9:11 15.2 3.7 16.0 0.0 0.3

28 6/15/11 9:12 15.0 3.8 14.7 -0.1 0.2

29 6/15/11 9:13 15.1 3.8 14.0 0.1 0.0

30 6/15/11 9:14 14.8 4.0 14.0 0.0 -0.4

31 6/15/11 9:15 15.0 3.8 13.1 -0.1 0.1

32 6/15/11 9:16 14.7 4.1 13.4 -0.1 0.0

33 6/15/11 9:17 14.9 4.0 11.8 -0.1 0.0

34 6/15/11 9:18 14.9 4.0 13.7 0.0 0.0

35 6/15/11 9:19 15.1 3.8 13.5 -0.1 0.1

36 6/15/11 9:20 15.5 3.6 17.4 -0.1 0.0

37 6/15/11 9:21 15.2 3.7 23.0 0.1 0.0

38 6/15/11 9:22 14.9 4.0 15.2 0.1 0.1

39 6/15/11 9:23 15.5 3.6 18.2 0.0 0.2

40 6/15/11 9:24 15.5 3.6 22.6 0.0 0.0

41 6/15/11 9:25 15.5 3.5 26.7 0.0 0.0

42 6/15/11 9:26 15.2 3.8 17.7 0.0 0.0

43 6/15/11 9:27 15.5 3.6 17.3 0.1 0.0

44 6/15/11 9:28 15.7 3.5 26.1 0.0 0.0

45 6/15/11 9:29 15.7 3.4 29.9 0.0 0.0

46 6/15/11 9:30 15.3 3.7 23.4 -0.1 0.0

47 6/15/11 9:31 15.0 3.9 15.1 0.0 0.1

48 6/15/11 9:32 15.4 3.7 17.4 0.1 0.1

49 6/15/11 9:33 15.2 3.7 19.0 -0.1 0.0

50 6/15/11 9:34 15.0 3.9 14.0 0.1 -0.1

51 6/15/11 9:35 15.0 3.9 14.0 0.0 0.0

52 6/15/11 9:36 15.3 3.7 15.8 0.0 0.0

53 6/15/11 9:37 15.1 3.8 16.9 0.1 0.0

54 6/15/11 9:38 15.1 3.8 16.3 0.0 0.0

55 6/15/11 9:39 15.1 3.8 15.5 0.0 0.0

56 6/15/11 9:40 15.3 3.8 15.6 0.2 -0.1

57 6/15/11 9:41 15.4 3.8 18.8 0.0 0.0

58 6/15/11 9:42 15.1 3.9 15.2 0.0 0.0

59 6/15/11 9:43 15.2 3.9 14.8 -0.1 -0.1

60 6/15/11 9:44 15.1 4.0 13.8 0.0 -0.1

Results

Absolute Bias (Zero)

Span%

Span%

Post Test Calibration

Zero%

Absolute Bias (Span)

 Absolute Drift (Zero)

Absolute Drift (Span)

Zero%

Calibration Information

Span Gas Value

Calibration 

Pretest Calibration

Gas

Instrument Range
Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

10 oz. 

Outlet NMOC (lb/hr as C3H8) 0.01

Waste Gas Inlet NMOC (lb/hr as C3H8) 489.2

Pilot Inlet NMOC (lb/hr as C3H8) 0.5

Sum of Inlets NMOC (lb/hr as C3H8) 489.7

% DRE (mass flow in/out basis) 100.00%

% DRE (carbon balance) 100.00%

%DRE Calculations
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Methods 1-4: Determination of Stack Gas Velocity and Volumetric Flow Rate

Sample Calculations

sample volume (scf) = 17.64 * VM * YD * {PB + ǻH/13.6}

TM + 460

= 17.64 * 37.56 * 0.978 * { 27.64 + 1.0 / 13.6}

74 460

= 33.629

moisture volume (scf) = 0.04715 * VLC

= 0.04715 * 34

= 1.603

moisture content (% / 100) = VW(STD)

(VM(STD) + VW(STD))

= 1.603

( 33.629 + 1.603 )

= 0.046

molecular weight, dry (grams/mol) = (0.440) * (%CO2) + (0.320) * (%O2) + (0.280) * (%N2 + %CO)

= (0.440) * 1.5 + (0.320) + 18.5 + (0.280) * ( 80 + 0.0)

= 28.98

molecular weight, actual (grams/mol) = MD * (1 - BWS) + (18.0) * BWS

= 28.98 * (1 - 0.046 ) + (18 * 0.046 )

= 28.48

+
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Methods 1-4: Determination of Stack Gas Velocity and Volumetric Flow Rate

Sample Calculations (continued)

gas velocity (ft/sec) = 85.49 * CP * ¥ǻPAVG *

[PB + PS / 13.6] * MA

= (85.49) * 0.83 * 0.078 * 936 +

27.64 + 0.00 * 28.48

13.6

= 7.4

ʌ * (DS / 12)2

gas flow (acfm) = 60 * 4 * VS

ʌ * ( 42.63 / 12)2

= 60 * 4 * 7.4

= 4,382

ʌ * (DS / 12)2 TSTD * [PB + PS / 13.6]

gas flow (dscfm) = 60 * VS * (1 - BWS) * 4 * (TS + 460) * PSTD

ʌ * ( /12)2 528 * [ 27.64 + 0.00 / 13.6 ]

= 60 * ) * * ( 936 + 460) * 29.92

= 1,462

7.4

TS + 460

42.6

* (1 - 0.046 4

[ ]

460
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Methods 1-4: Determination of Stack Gas Velocity and Volumetric Flow Rate

Variables and Abbreviations

BWS - moisture content of the gas (wet volume percent/100)

%CO - carbon monoxide content of the gas (dry volume percent)

%CO2 - carbon dioxide content of the gas (dry volume percent)

CP - pitot tube constant (unitless)

DS - diameter of the stack (inches)

ǻH - pressure differential at dry gas meter exit orifice (inches water)

MD - molecular weight of the dry gas (grams per mol)

MA - molecular weight of the wet gas (grams per mol)

%N2 - nitrogen content of the gas (dry volume percent)

%O2 - oxygen content of the gas (dry volume percent)

PAVG - average square root of the stack gas pitot differential pressure (inches water)

PB - barometric pressure (inches mercury)

PS - stack pressure relative to barometric presure (inches water)

PSTD - standard pressure (29.92 inches mercury)

TM - average dry gas meter temperature (oF)

TS - average stack temperature (oF)

TSTD - standard temperature (528 oR)

VLC - volume of moisture collected as a liquid (milliliters)

VM - volume indicated on dry gas meter (uncorrected actual cubic feet)

VMSTD - volume of gas through dry gas meter (corrected dry standard cubic feet)

VS - stack gas velocity (feet per second)

VWSTD - volume of moisture collected as a gas at standard conditions (standard cubic feet)

YD - dry gas meter calibration factor (unitless)
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Method 3A: Determination of O2 / CO2 Concentrations in Emissions from Stationary 

Sources (Instrumental Analyzer Procedure )

Sample Calculations

CO2 conc, drift cal (%vd) = (%FSSTACK - %FS0) * [Span Gas Conc (%vd)]

(%FSSPAN-%FS0)

= ( 1.5 - 0 ) * ( 2.48 )

( 2.5 ) - ( 0 )

= 2.5

O2 conc, drift cal (%vd) = (%FSSTACK - %FS0) * [Span Gas Conc (%vd)]

(%FSSPAN-%FS0)

= ( 18.7 - 0.0 ) * ( 10 )

( 10.1 ) - ( 0.0 )

= 18.5

Variables and Abbreviations

cal - calibrated

conc - concentration

CO2 - Carbon Dioxide

O2 - Oxygen

%FSSPAN - average analyzer reading for span gas (percent of full scale)

%FSSTACK - average analyzer reading for stack gas (percent of full scale)

%FS0 - average analyzer reading for zero gas (percent of full scale)

%vd- dry volume percent
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Method 10: Determination of Carbon Monoxide Emissions from Stationary 

Sources (Instrumental Analyzer Procedure )

Sample Calculations

CO conc, drift cal (ppmvd) = (%FSSTACK - %FS0) * [Span Gas Conc (ppmvd)]

(%FSSPAN-%FS0)

= ( 105.1 - 1.2 ) * ( 79.1 )

( 77.9 ) - ( 1.2 )

= 107.2

CO emissions (lb/hr) = [CO (ppmvd)]*(FDSCFM)*(1.556 X 10 E-7)*(46.01)

= ( 107.2 )* 1,462 * (1.556 X 10E-7) * (46.01)

= 0.70

Variables and Abbreviations

cal - calibrated

conc - concentration

FDSCFM - gas flow (dry standard cubic feet per minute, where standard = 29.92 inches Hg and 68oF)

%FSSPAN - average analyzer reading for span gas at probe tip (percent of full scale)

%FSSTACK - average analyzer reading for stack gas (percent of full scale)

%FS0 - average analyzer reading for zero gas at probe tip (percent of full scale)

lb/hr - pounds per hour

ppmvd - parts per million, dry volume basis

g/bhp-hr - grams per brake horsepower-hour
Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Method 25A: Determination of Total Gaseous Organic Concentrations Using a Flame Ionization Analyzer

Sample Calculations

NMOC conc, drift cal (ppmvd as C3H8) = (%FSSTACK - %FS0) * [Span Gas Conc (ppmvd)]

(%FSSPAN-%FS0)

= ( 43.9 - 0.0 ) * ( 30.2 )

( 30.2 ) - ( 0.0 )

= 43.9

NMOC emissions (lb/hr as C3H8) [NMOC (ppmvd)]*(FDSCFM)*(1.556 X 10 E-7)*(44.09)

= ( 43.9 ) * ( 1,462 ) * (1.556 X 10 E-7) * 44.09

= 0.46

Variables and Abbreviations

as C3H8 - as propane or C3

BWS - moisture content of the gas (wet volume percent/100)

cal - calibrated

conc - concentration

FDSCFM - gas flow (dry standard cubic feet per minute, where standard = 29.92 inches Hg and 68oF)

%FSSPAN - average analyzer reading for span gas at probe tip (percent of full scale)

%FSSTACK - average analyzer reading for stack gas (percent of full scale)

%FS0 - average analyzer reading for zero gas at probe tip (percent of full scale)

lb/hr - pounds per hour

tpy - tons per year

ppmvw - parts per million, wet volume basis

g/bhp-hr - grams per brake horsepower-hour

=
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sample probe

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PROJECT #98-19895

INCINERATOR EFFICIENCY SURVEY 

QUESTOR TECHNOLOGIES INC. 

MOBIL LONE PINE 06-03-030-27-W4M 

INCINERATOR EXHAUST STACK 

November 5, 1998

Prepared by: 

MAXXAM ANALYTICS INC. 

9331 - 48th Street 

Edmonton, Alberta 

T6B 2R4 

Submitted to: 

QUESTOR TECNOLOGIES INC. 

Suite 500, 665-8 Street SW 

Calgary, Alberta 

T2P 3K7 
 Questor Technologies Inc. 

 Mobil Lone Pine Creek (06-03) - November 1998 

 Project #98-19895

 

-iSUMMARY

On November 5, 1998, the Edmonton office of Maxxam Analytics Inc. conducted a source emission survey and efficiency 

test on the Incinerator Exhaust Stack that was operating on a Mobil well site (06-03-030-27-W4M) near the Mobil Lone 

Pine Creek Gas Plant. Sampling was carried out on the separator inlet to determine concentrations of organic compounds 

and water content. Sampling was carried out on the separator outlet to determine concentrations of organic compounds, 

total reduced sulphur compounds and water content. Sampling was carried out on the incinerator exhaust stack to 

determine concentrations of sulphur dioxide, oxides of nitrogen, carbon monoxide, total reduced sulphur compounds 

and organic compounds. Furthermore, destruction efficiencies were determined for total reduced sulphur compounds 

and organic compounds. 

The summary of results is as follows: 

 RUN: SEP. INLET SEP. OUTLET STACK AVERAGE

 DATE: Nov. 5, 1998 Nov. 5, 1998 Nov. 5, 1998 

 TIME: 12:06 - 13:06 12:06 - 13:06 12:06 - 13:06 

WATER CONTENT 

(lb. water/million ft3 of wet gas) 6.4 4.3 - - 

SULPHUR DIOXIDE 

(ppmv wet) - - 547 - 

(ppmv dry) - - 610 - 

(kg/hr) - - - - 

OXIDES OF NITROGEN (as NO2) 

(ppmv wet) - - 67 - 

(ppmv dry) - - 75 - 

(kg/hr) - - - - 

CARBON MONOXIDE 

(ppmv wet) - - 226 - 

(ppmv dry) - - 252 - 

(kg/hr) - - - - 
 Questor Technologies Inc. 

 Mobil Lone Pine Creek (06-03) - November 1998 

 Project #98-19895

 

-ii-

 TOTAL REDUCED SULPHUR COMPOUNDS 

Hydrogen Sulphide (H2S) (ppmv wet) - - <0.9 - 

 (ppmv dry) - 10400 <1.0 - 

(g/hr) - - - - 

 

Carbonyl Sulphide (COS) (ppmv wet) - - <0.9 - 

 (ppmv dry) - 6 <1.0 - 

(g/hr) - - - - 

 Carbon Disulphide (CS2) (ppmv wet) - - <0.4 - 

 (ppmv dry) - <0.5 <0.5 - 

(g/hr) - - - - 

 ORGANIC COMPOUNDS 

Methane (CH4) (ppmv wet) - - <0.9 - 

 (ppmv dry) 825000 816900 <1.0 - 

(g/hr) - - - - 

 

 Ethane (C2H6) (ppmv wet) - - <0.9 - 

 (ppmv dry) 44100 44800 <1.0 - 

(g/hr) - - - - 

 

Propane (C3H8) (ppmv wet) - - <0.9 - 

 (ppmv dry) 13700 14800 <1.0 - 

(g/hr) - - - - 

 Butane (C4H10) (ppmv wet) - - <0.9 - 

 (ppmv dry) 7040 9420 <1.0 - 

(g/hr) - - - - 

 

Pentane (C5H12) (ppmv wet) - - <0.9 - 

 (ppmv dry) 3520 5880 <1.0 - 

(g/hr) - - - - 

 Hexane (C6H14) (ppmv wet) - - <0.9 - 

 (ppmv dry) 1960 3510 <1.0 - 

(g/hr) - - - - 
Questor Technologies Inc. 

 Mobil Lone Pine Creek (06-03) - November 1998 

 Project #98-19895

-iii-

 

Heptane + (C7H16) (ppmv wet) - - <0.9 - 

 (ppmv dry) 4680 3690 <1.0 - 

(g/hr) - - - - 

Components heavier than heptane are presented in Appendix II of this report 

DESTRUCTION EFFICIENCIES – TRS (as Sulphur) 

(total in – ppmv as Sulphur) 10420 - - - 

(total out – ppmv as Sulphur) 1.50 - - - 

(% efficiency) >99.99 - - - 

DESTRUCTION EFFICIENCIES – GASEOUS ORGANICS (as CH4) 

(total in – ppmv as Methane) 851328 - - - 

(total out – ppmv as Methane) 1.37 - - - 

(% efficiency) >99.99 - - - 

(% efficiency) >99.99

(% efficiency) >99.99