October 19, 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 Nishu/Sanish Facility

To Whom It May Concern;

Enclosed please find the application for new construction for the Enerplus Resources (USA) Corporation Nishu/Sanish facility. In cluded 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.

At this time, this facility has not had an environmental assessment completed and submitted to the,

United States Department of the Interior, Bureau of I ndian Affairs Great Plains Regional office. The

environmental assessment is currently ongoing and will be submitted upon completion.

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 Bakke n 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 su mmary 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 Nishu/Sanish Facility

Prepared For:



## Enerplus Resources (USA) Corporation US Bank Tower, 950 17 th 

## Street Denver, CO 80202

October 19, 2011

Prepared By:

3700 East 41 st Avenue Denver, CO 80216-6504

303-289-7520 (Office)

303-289-7521 (Fax )Enerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

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 Pollution

‐ Generating 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 Equi pment Specifications and GuaranteesEnerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

1 

## General Facility Information

1. (a) Company Name Enerplus Resources (USA) Corporation

(b) Operator Name Enerplus Resources (USA) Corporation 2. Facility Information Nishu/Sanish

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)

West of State Highway 22. North of State Highway 73.

9. Reservation

Ft. Berthold Reservation 10. County
McKenzie County 11. (a) Latitude

TBD 11. (b) Longitude

TBD

12. (a) Quarter Quarter

NW / NE 12. (b) Section

6 12. (c) Township

150N 12. (d) Range
94WEnerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

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 ActionEnerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

3 

## Contact Information

Company Contact Tony Lucero Title

EHS Coordinator

Mailing Address

US Bank Tower, Suite 220, 950

– 17 th Street, Denver, CO 80202

‐ 2805

Email Address tlucero@enerplus.com

Telephone Number (720) 279

‐ 5500 Facsimile Number (720) 279

‐ 5550

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) 774

‐ 3010 Facsimile Number (720) 279

‐ 5550

Compliance Contact Tony Lucero Title

EHS Coordinator

Mailing Address

US Bank Tower, Suite 220, 950

– 17 th Street, Denver, CO 80202

‐ 2805

Email Address tlucero@enerplus.com

Telephone Number (720) 279

‐ 5500 Facsimile Number (720) 279

‐ 5550Enerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

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 reservoi r 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 well head(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 hea t is used to make the process more efficient. Descriptions of the elements involved in the crude oil recovery

process are described below:

High

‐ Pressure 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 na tural gas components off

‐ gas 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 wa ter 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 on

‐ site containers prior to being transferred to the lease automatic custody transfer (LACT) unit for conveyance to a refi ning 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 on

‐ site prior to being loaded into tanker trucks for tran sport and disposal.

Low

‐ Pressure Natural Gas

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

‐ gassing that occurs from the crude oil stored in the on

‐ site oil storage tanks. This natural

gas is collected in what is called a vent line from the oil storage tanks and wa ter storage tank(s) at the facility. This additional, low

‐ pressure, 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 pu mp(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 facili ty, 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 high

‐ pressure natural gas will be routed to a ground pit flare capable of a 90%
destruction removal effici ency.Enerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

5 

## Operating Schedule

This facility is designed to operate 24 hours a day, 7 days a week for 52 weeks a year.EnerplusResources(USA)CorporationApplicationforNewConstructionFacility:Nishu/Sanish6ProcessFlowDiagram(typ.)Enerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

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 4.29 MMscf/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 485 scf/hour 11.64 Mscf/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) (AP

‐ 42, Vol. I, Ch 1.4: Natural Gas Combustion).

The re cycle 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 co ntinuous operation using natural gas fuel and an average gross heating value of approximately 1,020 Btu/scf (AP

‐ 42, 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 pro posed engines are included in

Attachment G.

# Attachment A

Emission Units and Air Pollution

‐ Generating ActivitiesFacility Name Nishu/Sanish

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: Generator (x2) Newage UCI274G or Equivalent 400 bbl/each

145 kW (194 HP)/each Recycle Pump (x2) Honda Brand or Equivalent
8 HP/each Sivallis Brand or Equivalent 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 MonitoringFacility Name Nishu/Sanish

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. Enclosed Smokeless Combustor Connected to Sales Line

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

Continuous Pilot Flame N/A

98% 100%

Size of combustor will be selected based on volume of actual throughput. N/A

# Attachment C

Criteria Pollutant and GHG Emission EstimatesFacility: Nishu/Sanish

PTE SYN PTE SYN PTE SYN PTE SYN
Oil/Condensate Tanks 4,442.97 88.86 7.77 0.16 9.74 9.74 53.00 53.00 N/A N/A N/A N/A N/A

Treater 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/A

Treater 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/A RICE 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/A Truck Loading 0.00 0.00 N/A N/A Pneumatic Pump 0.00 0.00 0.00 0.00
Pneumatic Controllers 0.00 0.00 0.00 0.00 Glycol Dehydrator 0.00 0.00 0.00 0.00

Totals (TPY) 4,445.62 91.50 7.77 0.16 13.79 13.79 60.75 60.75 0.00 0.00 0.00 0.02 0.00

PTE SYN PTE SYN PTE SYN PTE SYN
Oil/Condensate Tanks 90.71 19,104.01 223.72 4.47 0.32 0.01 5,330.63 19,208.81
Treater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Treater Burner 365.25 365.25 0.03 0.03 0.01 0.01 367.63 367.63 RICE Engine 1,911.08 1,911.08 0.00 0.00 0.00 0.00 1,911.08 1,911.08

Totals (TPY) 2,367.04 21,380.35 223.75 4.50 0.32 0.01 7,609.34 21,487.53

PTE SYN PTE SYN PTE SYN PTE SYN
Oil/Condensate Tanks 4.18 0.08 1.67 0.03 1.28 0.03 0.00 0.00
Treater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Totals (TPY) 4.18 0.08 1.67 0.03 1.28 0.03 0.00 0.00

Notes:

a Pb, 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. 2,2,4 Trimethylpentane Emission Source HAP Breakdown

Benzene Toluene Xylenes N 2 O CO 2 CH 4 Emission Source CO 2 e 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)

PM 2.5 NOx b H 2 SO 4 b SO 2 PM 10 b H 2 S VOC HAP CO

# Attachment D

Criteria Pollutant and GHG Emission Supporting DocumentationGREEN = Requires input

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

Line 1 Nishu/Sanish Name of the facility and the well number.

Line 2 11/1/2011 Submittal Date.

Production Data Description

Line 3 BOPD 8,000 Average daily production in barrels of oil per day (BOPD).

Line 4 Mscfd 5,992 Average daily production of gas in Mscf per day. Estimated gas production based on actual Bakken gas production from existing Enerplus facilities.

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 3680 This is the calculated BOPD expected to be produced using the above entered decline factor.

Line 7 Adjusted Treater Gas (Mscfd) 2756.32 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) 360308.8 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 2,178.25 Lower heating value (Btu/scf) of tank vapors. Estimated from E&P Tank V2 Emission Summary.

Line 12 Molecular Weight 38.18 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% 67.07% VOC weight fraction of the tank vapor gas (C3+). Estimated from E&P Tank V2 Emission Summary.

Line 14 HAP% 0.12% HAP weight fraction of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.

Line 15 CO 2 % 0.60% CO 2 mole fraction of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.

Line 16 CH 4 % 8.04% CH 4 weight fraction of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.

Line 17 H 2 S weight % 0.000% H 2 S weight percent of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.

Line 18 H 2 S mole % 0.000% H 2 S mole percent of the tank vapor gas. Estimated from E&P Tank V2 Emission Summary.

Line 19 2 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 H 2 S weight % 0.000% H 2 S weight percent of the well stream gas. Value from lab gas analysis report - see criteria pollutant emission supporting documentation.

Line 28 H 2 S mole % 0.000% H 2 S 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.

Enclosed Smokeless Combustor

Connected to Sales Line Default Bakken EFGREEN = Requires input

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

Line 1 Nishu/Sanish Name of the facility and the well number.

Line 2 11/1/2011 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 LACT

Submerged loading of a clean cargo tank

Routed exhaust back into closed loop systemscf/day

Btu/scf

lb/lb-mole

HAP wt Fraction

CO 2 mole Fraction

CH 4 wt Fraction

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

VOC: 15,013 scf/hr x 0.002638522 lb-mole/scf x 38.18 lb/lb-mole x 67.07% = 1014.38 lb/hr

1014.38 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 4442.97 TPY

HAP: 15,013 scf/hr x 0.002638522 lb-mole/scf x 38.18 lb/lb-mole x 0.12% = 1.77 lb/hr

1.77 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 7.77 TPY

AP-42
Table 13.5-

1 a

NOx: 15,013 scf/hr x 2,178 Btu/scf x 1E-06 MMBtu/ Btu x 0.068 = 2.22 lb/hr

2.22 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 9.74 TPY 98% 0.60%

8.04% Lower Heating Value 2178.25

VOC wt Fraction 67.07%

0.12% Nishu/Sanish

Oil/Condensate Tanks

Flare Gas Volume 360,309

Molecular Weight 38.18AP-42
Table 13.5-

1 a

CO: 15,013 scf/hr x 2,178 Btu/scf x 1E-06 MMBtu/ Btu x 0.370 = 12.10 lb/hr

12.10 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 53.00 TPY

E&P Tank

V2 Em. Summary b ∑ (Y j * R j )

c CO 2 : 15,013 scf/hr x 0.604% + 0.98 x 15,013 scf/hr x 2.55 = 37561.11 scf/hr

37561.11 scf/hr x 0.0026 lb-mole/scf x 44.01 lb/lb-mole = 4361.65 lb/hr

4361.65 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 19104.01 TPY

E&P Tank

V2 Em.
Summary b

CH 4 : 15,013 scf/hr x 0.002638522 lb-mole/scf x 16.04 lb/lb-mole x 8.04% = 51.08 lb/hr

51.08 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 223.72 TPY

N 2 O: 15,013 scf/hr x 2.2 lb/MMscf x 1E-06 Mmscf/ scf = 0.03 lb/hr

0.03 kg/hr x 2.2046 lbs/kg x 8,760 hr/yr x 0.0005 ton/lb = 0.32 TPY

Notes:

a NOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.
4,442.97 VOC TPY

c CO 2 calculated from Subpart W, Eq. W-20 and W-21.

88.86 VOC TPY Controlled

7.77 HAP TPY Uncontrolled

0.16 HAP TPY Controlled

9.74 NOx TPY

53.00 CO TPY

90.71 CO 2 TPY Uncontrolled

19,104.01 CO 2 TPY Controlled

223.72 CH 4 TPY Uncontrolled

4.47 CH 4 TPY Controlled

0.32 N 2 O TPY Uncontrolled

0.01 N 2 O TPY Controlled

Uncontrolled

TOTALS AP-42 Table 1.4-2

b CO 2 and CH 4 percent weight are from E&P Tank V2 Emission Summary.HAP: 15,013 scf/hr x 0.002638522 scf/lb-mole x 38.18 lb/lb-mole x 0.12% = 1.77 lb/hr

1.77 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 7.77 TPY

Benzene: 15,013 scf/hr x 0.002638522 scf/lb-mole x 38.18 lb/lb-mole x 0.06% = 0.95 lb/hr

0.95 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 4.18 TPY

Toluene: 15,013 scf/hr x 0.002638522 scf/lb-mole x 38.18 lb/lb-mole x 0.03% = 0.38 lb/hr

0.38 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 1.67 TPY

Xylenes: 15,013 scf/hr x 0.002638522 scf/lb-mole x 38.18 lb/lb-mole x 0.02% = 0.29 lb/hr

0.29 lb/hr x 8,760 hr/yr x 0.0005 ton/lb = 1.28 TPY

2,2,4 Trimethylpentane: 15,013 scf/hr x 0.002638522 scf/lb-mole x 38.18 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 4.18 TPY Uncontrolled

Benzene 0.08 TPY Controlled

Toluene 1.67 TPY Uncontrolled

Toluene 0.03 TPY Controlled

Xylenes 1.28 TPY Uncontrolled

Xylenes 0.03 TPY Controlled

2,2,4 Trimethylpentane 0.00 TPY Uncontrolled

2,2,4 Trimethylpentane 0.00 TPY Controlled TOTALS Nishu/Sanish

Oil/Condensate Tanks
HAP Emission Breakdownscfd

Btu/scf

lb/lb-mole

HAP wt fraction

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

VOC: 114,847 scf/hr x 0.002638522 lb-mole/scf x 26.965884 lb/lb-mole x 37.77% = 3086.50 lb/hr

3086.50 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 13518.88 TPY Uncontrolled

HAP 114,847 scf/hr x 0.002638522 lb-mole/scf x 26.965884 lb/lb-mole x 4.49% = 366.97 lb/hr

366.97 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 1607.35 TPY Uncontrolled

H 2 S 114,847 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

SO 2 114,847 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

13.5-1 a

NOx: 114,847 scf/hr x 1,473 Btu/scf x 0.000001 Mmbtu/ Btu x 0.068 lb/MMBtu = 11.50 lb/hr

11.50 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 50.39 TPY VOC wt fraction Nishu/Sanish

Treater Flare

Flare Gas Volume 2,756,320

37.77%

4.49% Lower Heating Value 1473.1

100% Avg. Molecular Weight 26.97AP-42 Table

13.5-1 a

CO: 114,847 scf/hr x 1,473 Btu/scf x 0.000001 Mmbtu/ Btu x 0.370 lb/MMBtu = 62.60 lb/hr

62.60 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 274.17 TPY

Treater Gas Analysis Summary b ∑ (Y j * R j )

d CO 2 : 114,847 scf/hr x 0.440% + 0.98 x 114,847 scf/hr x 1.56 = 176113.30 scf/hr

114,847 scf/hr x 0.0026385 scf/lb-mole x 44.01 lb/lb-mole = 13336.15 lb/hr

13336.15 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 58412.35 TPY

CH 4 : 114,847 scf/hr x 1473.1 Btu/scf x 0.000001 Mmbtu/ Btu x 0.0009 kg/MMBtu = 0.15 kg/hr

0.15 kg/hr x 2.2046 lbs/kg x 8760 hr/yr x 0.0005 ton/lb = 1.47 TPY

N 2 O: 114,847 scf/hr x 1473.1 Btu/scf x 0.000001 Mmbtu/ Btu x 0.0001 kg/MMBtu = 0.02 lb/hr

0.02 kg/hr x 2.2046 lbs/kg x 8760 hr/yr x 0.0005 ton/lb = 0.16 TPY

Notes:

H 2 S and SO 2 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

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

0.00 VOC TPY Controlled

d CO 2 calculated from Subpart W, Eq. W-20 and W-21. 0.00 HAP TPY Uncontrolled

0.00 HAP TPY Controlled

0.00 H 2 S TPY Uncontrolled

0.00 H 2 S TPY Controlled

0.00 SO 2 TPY Uncontrolled

0.00 NOx TPY

0.00 CO TPY

0.00 CO 2 TPY Uncontrolled

0.00 CO 2 TPY Controlled

0.00 CH 4 TPY Uncontrolled

0.00 CH 4 TPY Controlled

0.00 N 2 O TPY Uncontrolled

0.00 N 2 O TPY Controlled Subpart W c

c CH 4 and N 2 O emission factors are from Subpart W, Table C-3. Uncontrolled Subpart W c

TOTALS b CO 2 percent weight is from Treater Gas Analysis.HAP 114,847 scf/hr x 0.002638522 lb-mole/scf x 26.97 lb/lb-mole x 4.49% = 366.97 lb/hr

366.97 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 1607.35 TPY Uncontrolled

Benzene: 114,847 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.27% = 103.70 lb/hr

103.70 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 454.20 TPY

Toluene: 114,847 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.50% = 122.32 lb/hr

122.32 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 535.78 TPY

Xylenes: 114,847 scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.72% = 140.95 lb/hr

140.95 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 617.36 TPY

2,2,4 Trimethylpentane: 114,847 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

Benzene 0.00 TPY Uncontrolled

Benzene 0.00 TPY Controlled

Toluene 0.00 TPY Uncontrolled

Toluene 0.00 TPY Controlled

Xylenes 0.00 TPY Uncontrolled

Xylenes 0.00 TPY Controlled

2,2,4 Trimethylpentane 0.00 TPY Uncontrolled

2,2,4 Trimethylpentane 0.00 TPY Controlled Treater Flare HAP Emission Breakdown

Nishu/Sanish

TOTALS1,000,000 Btu/hr

AP-42 Table
1.4-1

EF a (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

EF a (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

EF a (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

EF a (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 Nishu/Sanish

### Heater Treater Burner Nishu/Sanish

AP-42 Table
1.4-2

EF b (lb/MMscf) Avg. Gas Heating
Value (Btu/scf) Avg. Gas Heating Value (Btu/scf) Sample Gas Heating
Value (Btu/scf)

CO 2 : 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 W c (kg/MMBtu)

CH 4 : 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 W c (kg/MMBtu)

N 2 O: 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:

a NOx, CO, VOC, PM 10 emission factors are from AP-42 Table 1.4-1,Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion.

b CO 2 emission factor from AP-42 Table 1.4-2, Emission Factors for criteria Pollutant and Greenhouse Gases from Natural Gas Combustion.

c CH 4 and N 2 O emission factors are from Subpart W, Table C-3.

0.02 VOC TPY

0.30 NOx TPY

0.26 CO TPY

365.25 CO 2 TPY

0.03 CH 4 TPY

0.01 N 2 O TPY TOTALSSaturation 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 1343200.00 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 3.4 4 4.8 50 4.5 7.1 (EPA AP-42 Values) Table 2 below may be used to provide the vapor pressure and molecular weight values for the above equation.

True Vapor Pressure, Pva (psi) at various temperatures in F Submerged loading: dedicated normal service

5.7 1.8 0.50

Condensed Liquid

2.3 2.8 Vapor Density Density

Wvc(lb/gal W1(lb/gal) at 60F at 60F 1.00



### Nishu/Sanish



## 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

0.60

Submerged loading: dedicated vapor balance service Tank Trucks and Rail Tank Cars Submerged loading of a clean cargo tankWhere: 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 Nishu/Sanish



### 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 Nishu/Sanish



### 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 8,760

Line 3 Maximum HP Rating 194

Line 4 NOx g/hp-hr 1

Line 5 CO g/hp-hr 2

Line 6 VOC g/hp-hr 0.7

Line 7 N 2 O g/hp-hr 0.0006

Line 8 CO 2 g/hp-hr 1.08

Line 9 CH 4 g/hp-hr 0.003

Line 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 8,760

Line 14 Maximum HP Rating 8

Line 15 NOx g/hp-hr 0.011

Line 16 CO g/hp-hr 0.00696

Line 17 VOC g/hp-hr 0.015

Line 18 N 2 O g/hp-hr 0.0006

Line 19 CO 2 g/hp-hr 1.08

Line 20 CH 4 g/hp-hr 0.003

Line 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 8,760

Line 25 Maximum HP Rating 8

Line 26 NOx g/hp-hr 0.011

Line 27 CO g/hp-hr 0.007

Line 28 VOC g/hp-hr 0.015

Line 29 N 2 O g/hp-hr 0.0006

Line 30 CO 2 g/hp-hr 1.08

Line 31 CH 4 g/hp-hr 0.003

Line 32 NOx Control Efficiency 0%

Line 33 CO Control Efficiency 0%

Line 34 VOC Control Efficiency 0% CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.
VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results. Manufacturer's emission factor, actual test results or AP-42 factor in 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. Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N 2 O.

Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO 2 . Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH 4 . 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 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 CO 2 . Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH 4 .

Manufacturer's maximum hp rating. 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 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).

Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N 2 O.

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

RICE Input Data

Manufacturer's maximum hp rating.

Description

Manufacturer's maximum hp rating. 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 emission factor, actual test results or AP-42 factor in lb/hp-hr for CO 2 . Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH 4 . 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.

Engine is assumed to operate 8,760 hours per year. 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 2 O.RICE Input Data

RICE Engine #4

Line 35 Hours of Operation 8,760

Line 36 Maximum HP Rating 194

Line 37 NOx g/hp-hr 1

Line 38 CO g/hp-hr 2

Line 39 VOC g/hp-hr 0.7

Line 40 N 2 O g/hp-hr 0.0006

Line 41 CO 2 g/hp-hr 1.08

Line 42 CH 4 g/hp-hr 0.003

Line 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 0

Line 47 Maximum HP Rating 100

Line 48 NOx g/hp-hr 10

Line 49 CO g/hp-hr 5

Line 50 VOC g/hp-hr 4

Line 51 N 2 O g/hp-hr 0.0006

Line 52 CO 2 g/hp-hr 1.08

Line 53 CH 4 g/hp-hr 0.003

Line 54 NOx Control Efficiency 0%

Line 55 CO Control Efficiency 0%

Line 56 VOC Control Efficiency 0% 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

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 CH 4 . Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N 2 O.

Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO 2 . 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. 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).

Engine is assumed to operate 8,760 hours per year.
Manufacturer's maximum hp rating. Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH 4 . Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N 2 O. Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).

Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO 2 . Description

Engine is assumed to operate 8,760 hours per year.
Manufacturer's maximum hp rating.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 2 O: 6.00E-04 kg/mmBtu 3.9E-07 x 194 HP x 0.002204586 lb / grams = 1.01E-10 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 N 2 O TPY Uncontrolled

CO 2 : 1.08 lb/HP-HR 194 HP = 209.52 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 917.70 CO 2 TPY Uncontrolled

CH 4 : 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 CH 4 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 2 O: 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 2 O TPY Uncontrolled

CO 2 : 1.08 lb/HP-HR 8 HP = 8.64 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 37.84 CO 2 TPY Uncontrolled

CH 4 : 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 CH 4 TPY Uncontrolled

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

AP-42, Table 3.3-1 a x

x

x

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

g-mmBtu/kg-hp-hr

x x

x

x Nishu/Sanish

Reciprocating Engine Emissions

x

Subpart W, Table C-3 b x

x

Subpart W, Table C-3 b AP-42, Table 3.3-1 a

g-mmBtu/kg-hp-hr x

xNishu/Sanish

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 2 O: 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 2 O TPY Uncontrolled

CO 2 : 1.08 lb/HP-HR 8 HP = 8.64 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 37.84 CO 2 TPY Uncontrolled

CH 4 : 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 CH 4 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 2 O: 6.00E-04 kg/mmBtu 3.9E-07 194 HP x 0.002204586 lb / grams = 1.01E-10 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 0.00 N 2 O TPY Uncontrolled

CO 2 : 1.08 lb/HP-HR 194 HP = 209.52 lb/hr x 8760 hr/yr x 0.0005 ton/lb = 917.70 CO 2 TPY Uncontrolled

CH 4 : 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 CH 4 TPY Uncontrolled

Subpart W, Table C-3 b

Subpart W, Table C-3 b

Subpart W, Table C-3 b

x x

x x

x

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

x g-mmBtu/kg-hp-hr AP-42, Table 3.3-1 a

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

x

x

x g-mmBtu/kg-hp-hr Subpart W, Table C-3 bNishu/Sanish

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 2 O: 6.00E-04 kg/mmBtu 3.9E-07 100 HP x 0.002204586 lb / grams = 5.2E-11 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 N 2 O TPY Uncontrolled

CO 2 : 1.08 lb/HP-HR 100 HP = 108.00 lb/hr x 0 hr/yr x 0.0005 ton/lb = 0.00 CO 2 TPY Uncontrolled

CH 4 : 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 CH 4 TPY Uncontrolled

Notes:

a CO 2 Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines (lb/hp-hr) from AP-42 Table 3.3-1, Gasoline Fuel.

b CH 4 and N 2 O Subpart W, Table C-3 of Subpart C - Default CH 4 and N 2 O Emission Factors for Various Types of Fuel.

3.75 NOx TPY Uncontrolled

3.75 NOx TPY Controlled

7.49 CO TPY Uncontrolled

7.49 CO TPY Controlled

2.62 VOC TPY Uncontrolled

2.62 VOC TPY Controlled

0.00 N 2 O TPY

1911.08 CO 2 TPY

0.00 CH 4 TPY AP-42, Table 3.3-1 a Subpart W, Table C-3 b

Subpart W, Table C-3 b

TOTALS x

x x

g-mmBtu/kg-hp-hr x x

g-mmBtu/kg-hp-hr xGas Analysis Mole

Percent 1 Mole

Fraction Molecular

Weight MW

Component Wt Fraction VOC Wt. Fraction HAP Wt. Fraction VOC Component

MW HAP Component

MW
Oxygen 0.0000 0.000 32 0 0 Nitrogen 0.4169 0.004 28.01 0.11677369 0.003042659
Carbon Dioxide 0.5269 0.005 44.01 0.23188869 0.0060421

H2S 0.0000 0.000 34.08 0 0
Methane 19.2347 0.192 16.04 3.08524588 0.080389272
Ethane 30.6072 0.306 30.07 9.20358504 0.239808927 Propane 30.0923 0.301 44.097 13.26980153 0.345758403 0.345758403 4.588145383

i-Butane 3.4974 0.035 58.12 2.03268888 0.052963811 0.052963811 0.10765895

n-Butane 9.7930 0.098 58.12 5.6916916 0.148302911 0.148302911 0.844094433

i-Pentane 1.7106 0.017 72.15 1.2341979 0.032158303 0.032158303 0.03968971

n-Pentane 2.1712 0.022 72.15 1.5665208 0.04081732 0.04081732 0.06394118

Hexanes+ 1.8976 0.019 100.2 1.9013952 0.049542818 0.049542818 0.094200477

Benzene 0.0310 0.000 78.11 0.0242141 0.000630923 0.000630923 0.000630923 1.52772E-05 1.52772E-05
Toluene 0.0105 0.000 92.14 0.0096747 0.000252084 0.000252084 0.000252084 2.43884E-06 2.43884E-06 Ethylbenzene 0.0035 0.000 106.17 0.00371595 9.68229E-05 9.68229E-05 9.68229E-05 3.59789E-07 3.59789E-07 Xylenes 0.0070 0.000 106.17 0.0074319 0.000193646 0.000193646 0.000193646 1.43916E-06 1.43916E-06 224 Trimethylpentane 0.0000 0.000
Total 100.00 1.00 38.38 0.67 0.00 5.74 0.00 VOC Weight % 14.95 HAP Weight % 0.00

Notes:

Bold items are considered volatile organic compounds (VOCs).

Pressure input for E&P Tank for the flash valve option is based on a corresponding elevation of 2,170 ft. above mean sea level.

Temperature input for E&P Tank for the flash valve option is based on an average temperature of 54 O F for the month of May corresponding to the date the oil separator sample was collected referenced below

(Reference: http://www.weatherreports.com/United_States/ND/Mandaree).

Mole percentages input in E&P Tank are based on the oil separator analysis from the Leghorn Melodee facility collected on 05/30/2007, as analyzed by PENCOR of Broussard, Louisiana. 

## E&P Gas Analysis WorksheetGas Analysis Mole

Percent 1 Mole

Fraction Molecular

Weight MW

Component Wt Fraction VOC Component

MW HAP

Component

MW
Oxygen 0.000 0.000 32 0 0 Nitrogen 6.829 0.068 28.01 1.9128029 0.070549836
Carbon Dioxide 0.440 0.004 44.01 0.193644 0.007142164

H2S 0.000 0.000 34.08 0 0
Methane 53.554 0.536 16.04 8.5900616 0.316826913
Ethane 20.536 0.205 30.07 6.1751752 0.227758751 Propane 10.970 0.110 44.097 4.8374409 0.178419148 0.863092082

i-Butane 1.305 0.013 58.12 0.758466 0.027974472 0.021217686

n-Butane 2.392 0.024 58.12 1.3902304 0.051275815 0.071285196

i-Pentane 0.524 0.005 72.15 0.378066 0.013944194 0.005271826

n-Pentane 1.688 0.017 72.15 1.217892 0.044919464 0.054707056

Hexanes+ 0.441 0.004 100.2 0.441381 0.016279439 0.007185435

Benzene 2 0.441 0.004 78.11 0.34407455 0.012690488 0.004366474 0.004366474

Toluene 2 0.441 0.004 92.14 0.4058767 0.014969935 0.006075948 0.006075948
Xylenes 2 0.441 0.004 106.17 0.46767885 0.017249381 0.008067171 0.008067171 2,2,4 Trimethylpentane 0.000 0.000 114.23 0 0 0 0
Total 100.00 1.00 27.11 1.04 0.02

VOC Weight Fraction 0.38 HAP Weight Fraction 0.04 VOC Weight % 3.84 HAP Weight % 0.07

Notes:

Bold items are considered volatile organic compounds (VOCs).

Mole percentages are based on the gas analysis report from the Ethan Hall 6B-31-30-1H facility, dated 02/14/2011, as analyzed by Sathe Analytical Laboratory, Inc. of

of Williston, North Dakota.

1 Mole percentages for Hexanes+, benzene, toluene and xylenes are of equal value based on a Hexanes+ result of 1.762 as no extended gas analys is available.



# Treater Gas Analysis Worksheet

## 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 sta tistical 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

repres ented by the level line in BOX 4 after the first 30

‐ day 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 usin g 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 = (1 ‐ 12th Month of Production) / (1st Month of Production)

Decline Factor (facility

‐ specific) = 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 Fa ctor for

the Formation= 0.459026

Burr
Prod_Month BOPD

Mar

‐ 09 6238 Apr

‐ 09 4092 May

‐ 09 4104

Jun

‐ 09 3552
Jul

‐ 09 3324 Aug

‐ 09 2854 Sep

‐ 09 2593

Oct

‐ 09 2414

Nov

‐ 09 2162

Dec

‐ 09 2151

Jan

‐ 10 2053
Feb

‐ 10 1775

Decline over the first 12

‐ months 0.715454

First Month's Production 6238

Last Month's Production 1775

Average BOPD 3109.333
Decline factor 0.49845

Four Bears

Dec

‐ 08 7473

Jan

‐ 09 3645
Feb

‐ 09 3873

Mar

‐ 09 4167 Apr

‐ 09 3148 May

‐ 09 3490

Jun

‐ 09 2820
Jul

‐ 09 2737 Aug

‐ 09 2444 Sep

‐ 09 2291

Oct

‐ 09 1778

Nov

‐ 09 2495

Decline over the first 12

‐ months 0.666131

First Month's Production 7473

Last Month's Production 2495

Average BOPD 3363.417
Decline factor 0.450076

Fredericks 5

Oct

‐ 08 11838

Nov

‐ 08 4545

Dec

‐ 08 5793

Jan

‐ 09 5012
Feb

‐ 09 3909

Mar

‐ 09 3706 Apr

‐ 09 3573 May

‐ 09 3334

Jun

‐ 09 3042
Jul

‐ 09 2886 Aug

‐ 09 2762 Sep

‐ 09 2465

Decline over the first 12

‐ months 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 product ion 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

Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10

0 1000 2000 3000 4000 5000 6000 7000 8000

Sep

‐ 08 Dec

‐ 08 Mar

‐ 09 Jul

‐ 09 Oct

‐ 09 Jan

‐ 10

0 2000 4000 6000 8000 10000 12000 14000

Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09Enerplus Resources (USA) Corporation
Decline Factor Calculation

Fredericks 6

Mar

‐ 09 6852.7 Apr

‐ 09 4388 May

‐ 09 5106

Jun

‐ 09 4388
Jul

‐ 09 3549 Aug

‐ 09 3073 Sep

‐ 09 2812

Oct

‐ 09 2570

Nov

‐ 09 2318

Dec

‐ 09 1735

Jan

‐ 10 2307
Feb

‐ 10 1739

Decline over the first 12

‐ months 0.746231

First Month's Production 6852.7

Last Month's Production 1739

Average BOPD 3403.142
Decline factor 0.496613

Tekakwitha

May

‐ 08 12498

Jun

‐ 08 6761
Jul

‐ 08 6635 Aug

‐ 08 7139 Sep

‐ 08 5283

Oct

‐ 08 4743

Nov

‐ 08 3854

Dec

‐ 08 4039

Jan

‐ 09 3649
Feb

‐ 09 2938

Mar

‐ 09 3614 Apr

‐ 09 2964

Decline over the first 12

‐ months 0.762842

First Month's Production 12498

Last Month's Production 2964

Average BOPD 5343.083
Decline factor 0.427515

Voigt 11

Aug

‐ 08 8107.6 Sep

‐ 08 4929

Oct

‐ 08 3423

Nov

‐ 08 6889

Dec

‐ 08 4670

Jan

‐ 09 3979
Feb

‐ 09 3129

Mar

‐ 09 3220 Apr

‐ 09 2823 May

‐ 09 2857

Jun

‐ 09 2562
Jul

‐ 09 2464

Decline over the first 12

‐ months 0.696088

First Month's Production 8107.6

Last Month's Production 2464

Average BOPD 4087.717
Decline factor 0.504183

Voigt 21

Jul

‐ 08 16424 Aug

‐ 08 4804 Sep

‐ 08 8111

Oct

‐ 08 7384

Nov

‐ 08 5169

Dec

‐ 08 5160

Jan

‐ 09 4610
Feb

‐ 09 3619

Mar

‐ 09 3903 Apr

‐ 09 3336 May

‐ 09 3419

Jun

‐ 09 3120

Decline over the first 12

‐ months 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

Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10 Mar

‐ 10

0 2000 4000 6000 8000 10000 12000 14000

Apr

‐ 08 Jun

‐ 08 Jul

‐ 08 Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Jun

‐ 08 Jul

‐ 08 Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

Jun

‐ 08 Jul

‐ 08 Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09Enerplus Resources (USA) Corporation
Decline Factor Calculation

Woman Creek

May

‐ 09 6123

Jun

‐ 09 4204
Jul

‐ 09 4558 Aug

‐ 09 3452 Sep

‐ 09 3379

Oct

‐ 09 3092

Nov

‐ 09 2572

Dec

‐ 09 2494

Jan

‐ 10 2296
Feb

‐ 10 1949

Mar

‐ 10 2030 Apr

‐ 10 1810

Decline over the first 12

‐ months 0.704393

First Month's Production 6123

Last Month's Production 1810

Average BOPD 3163.25 Decline factor 0.516618

TSB

Jul

‐ 09 17132.67 Aug

‐ 09 13068.9 Sep

‐ 09 10498.9

Oct

‐ 09 7647.33

Nov

‐ 09 9522.55

Dec

‐ 09 7606.9

Jan

‐ 10 4596.83
Feb

‐ 10 8671.98

Mar

‐ 10 7834.86 Apr

‐ 10 6425.9 May

‐ 10 6638.86

Jun

‐ 10 6283.47

Decline over the first 12

‐ months 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

Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10 Mar

‐ 10 May

‐ 10

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10 Mar

‐ 10 May

‐ 10 Jun

‐ 10

## Enerplus Resources (USA) Emission Calculator Supporting Documentationi 

### 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 Da ta

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

Glyco l 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

.............................................................................................................................. 11ii 

### Acronyms and Abbreviations

AP

‐ 42 EPA Publication AP

‐ 42, Compilation of Air Pollutant

Emission Factors (5th Edition)

bbl barrel

BOPD barrels of oil per day

BTEX benzene/toluene/ethyl

‐ benzene/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

H 2 S hydrogen sulfide

HAP hazardous air pollutants

hp horsepower

lb pound

lb/lb

‐ mole 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 Non

‐ Selective Catalytic Reductioniii 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

SO 2 sulfur dioxide

S/W/B standing/working/breathing losses

TEG tri

‐ ethylene glycol

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

TOC total organic compounds

TPY tons per year

VOC volatile organic compounds1 

## 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 th at 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 esti mated in advance for purposes of pre

‐ construction air permitting,
emissions from O&G exploration and production facilities are only known post

‐ construction and completion. This

situation is unique to O&G exploration and production facilities and, therefore, requires a practical regulatory response.
To accommodate th e need for registration pre

‐ construction Enerplus Resources (USA) Corporation (Enerplus) has taken

a conservative approach to emission calculations for the start

‐ up 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 e quipment 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) ‐ Bakken VOC Task Force and i ndustry have created
Bakken default values based on Bakken production wells which have been utilized in instances where site

‐ specific 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, st ored 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 calc ulated pre

‐ control 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) AP

‐ 42 emission factors. The AP

‐ 42 is maintained by th e 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/c hief/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, NO x, 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 facility

‐ wide emissions, as well as insuring that emissions are calculated in a manner similar

to those currently applied in states bordering the facility locations.

The Ener plus 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

– Th e 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

– Th e 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 th e 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 li ne (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 prod uction 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 = (1

‐ 12 th Month of Production)/ (1 st 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 (facility

‐ specific) = Average Production Over 12 Month Period/ 1 st 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 fa ctor 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 fr om 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 tem perature 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 a ddition to the scf/bbl value, the workbook uses
the molecular weight, lower heating value of the fuel and the VOC, HAP, CH 4 , and CO 2 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 det ermined

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 Tan k V2 Emission Summary.

Line 12: Enter the molecular weight of the tank vapors in pounds per pound

‐ mole (lb/lb

‐ mole), 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 ga s 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 H 2 S weight percent of the tank vapors. Taken from E&P Tank V2 Emission Summary.

Line 18: The H 2 S 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 Fl are 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 Fl are 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, CH 4 , and CO 2 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 gas5 6) NOx & CO emissions are based on AP

‐ 42 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 spe cific Btu/scf of the well stream gas.

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

‐ mole.

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 calc ulated 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: En ter 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 H 2 S weight percent of the well stream gas.

Line 28: Enter the H 2 S 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 devi ce 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 devi ce = 90% DRE 4) Connected to Sales Line = 100% DRE



### Treater Burner(s) Data

Lines 31

‐ 32: Emission estimates for natural gas burners, such as those found on heater/treaters or some flares, are typically calculated using AP

‐ 42 emission factors. The AP

‐ 42 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:


##        

 





 100 100

200010 100 10 Pr

6 6 

### DRE

HV HV

HV B HO BREF E

Avg od

Avg EFF X
X

where:6 E X = emissions for pollutant X (tpy);

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

BR = burner rating (MMBtu/hr);

B Eff = burner efficiency (%);

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

HV Avg = average gas heating value (Btu/scf);

HV Prod = produced gas heating value (Btu/scf);

DRE = destruction and removal efficiency (%);

1

‐ ton = 2000

‐ lb;

1

‐ MMBtu = 10 6

‐ Btu; and

1

‐ MMscf = 10 6

‐ scf.

Potential emissions must be calculated based on 8,760

‐ hrs/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 heat ers, boilers, burners, etc. are regulated air pollutants. NOx, CO, VOC, HAP & SO 2 emissions from process unit heaters are calculated within the Oil & Gas Facility Emission
Calculation Workbook using the emission factors (EF) below from EPA AP

‐ 42, Tables 1.4

‐ 1, 1.4

‐ 2 and 1.4

‐ 3:

Table 1.4

‐ 1 Emission Factors from Natural Gas Combustion (Excerpt from AP

‐ 42, Tables 1.4

‐ 1, 1.4

‐ 2 and 1.4

‐ 3)

Poll utant 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 NO X , CO, and total organic compounds (TOC) emissions can be found in AP

‐ 42 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. NO X , CO,

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

### 2000 HVFCEF E X

X 

### 



where:

E X = emissions for pollutant X (tpy);

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

FC = fuel consumption (MMscf/yr);

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

1

‐ ton = 2000

‐ lb.

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



### 24 HO DPR FC GAS 

### 



where:

FC = fuel consumption (MMscf/yr);

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

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

1

‐ day = 24

‐ hours.

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

maximum daily production capacity for 8760

‐ hrs/yr.



### Truck Loading Data

Lines 32

‐ 38: 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 AP

‐ 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 46.12
   T MPS L L

where:

L L = loading loss per 1000 gallons of liquid loaded (lb/1000

‐ gal);

S = saturation factor (unitless) (AP

‐ 42, Table 5.2

‐ 1);

P = true vapor pressure of liquid loaded (psia) (AP

‐ 42, Table 7.1

‐ 2);

M = molecular weight of tank vapors (lb/lb

‐ mole) (AP

‐ 42 Table 7.1

‐ 2); and8 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 42365 

 OIL L
X 

### DPRL E

where:

E X = emissions for pollutant X (tpy);

L L = loading loss per 1000 gallons of liquid loaded (lb/1000

‐ gal);

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

1

‐ year = 365

‐ days;

1

‐ bbl = 42

‐ gallons; and

1

‐ ton = 2000

‐ lb.

Table 5.2

‐ 1 Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses (Excerpt from AP

‐ 42, Table 5.2

‐ 1)

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 7.1

‐ 2 Properties of Selected Petroleum Liquids (Excerpt from AP

‐ 42, Table 7.1

‐ 2)

Petroleum Liquid
Crude Oil

RVP 5 Vapor MW at 60 F MV(lb/lb

‐ mole)

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 34

‐ 39.

Line 34: Use the drop down list to choo se 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/lb

‐ mole. If no site specific data is available, please refer to Table 2

on the Tru ck 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 degre es 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 VO C & 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 pu mp.

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 me nu 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 45

‐ 46 : If a pneumatic controller uses natural gas as the motor fuel, VOC and HAP emissions shall be released during devi ce 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 instal l add

‐ on 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 47

‐ 48 : Glycol, usually tri

‐ ethylene 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 regenerati on, 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

GRI

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

process vents of the dehydration unit as sociated 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: ≥

5.0 TPY of any combination of HAPs, or ≥ 15.0 TPY any combination of VOCs.

Glycol Dehydrator Controls

The following control systems or devices shall be applied for gly col 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 dem onstrated 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 TP Y HAP. An updated GRI

‐ GLYCalc 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 Bakke n Pool O&G production facilities.

Line 47: Enter the TPY of VOC emissions calculated in GRI

‐ GLYCalc V4 software. (If no glycol dehydrator is installed, enter 0).

Line 48: Enter the TPY of HAP emissions calculated in GRI

‐ GLYCalc V4 software. (If no glycol dehydrator is installed, enter 0).



### RICE Data Input

Lines 1

‐ 9: Emission estimates for internal combustion engines were calculated using manufacturer emission factors.

Internal combustion engine emissions were estimated using the following equation: 

##        

  

 100 100

2000 DRE HOEREF E X

X

where:

E X = emissions for pollutant X (tpy);

EF X = emission factor for pollutant X (lb/hp

‐ hr or lb/MMBtu);

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

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

DRE = destruction and removal efficiency (%); and

1

‐ ton = 2000

‐ lb.

Potential emissions were calculated based on 8760

‐ hours per year (hrs/yr) and using the manufactur er'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.

Line 1: Enter the number of engines to be installed at the production facility.11 RICE Engine #1: Lines 2

‐ 12

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 res ults 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 N 2 O.

Line 8: Enter the manufacturer’s emission factor, actual test results or Ap

‐ 42 factor in lb/hp

‐ hr for CO 2 .
Line 9: Enter the manufacturer’s emission factor, actual test results or Subpart W factor in kg/mmBtu for CH 4 .
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 effi ciency 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 fa 

### cility.

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 P erformance for Stationary Compression Ignition Internal Combustion Engines : Applies to any compression

‐ ignition 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 spark

‐ ignition internal combustion e ngine 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 lean

‐ burn engines 500 < hp < 1350 3) After July 1, 2008 for engin es < 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.



### E&P Tanks v2.0 Input
Input mole percentages from the Emission Summary: Stream Data: Total Emissions.

# Attachment E

Qualitative Air Quality AnalysisEnerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

E

‐ 1 

## 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:

 Natural gas is being use d to fuel equipment on the facility and typical emissions from utilizing this type of fuel

are insignificant.

 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 un der this permit are not anticipated to impact air quality in the region.

# Attachment F

Synthetic Minor Limit RequestEnerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

F

‐ 1 

## S YNTHETIC 

## M INOR 

## L IMIT 

## R EQUEST 

## G ENERAL 

## I NFORMATION
Company Name Enerplus Resources (USA) Corporation Facility Name Nishu/Sanish

Company Contact or Owner Name Tony Lucero Title

EHS Coordinator

Mailing Address

US Bank Tower, Suite 2200

950 ‐ 17th Street Denver, CO 80202

‐ 2805

Email Address tlucero@enerplus.com

Telephone Number (720) 279

‐ 5500 Facsimile Number (720) 279

‐ 5550Enerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

F

‐ 2 

## P ROPOSED 

## L IMITATION AND 

## E FFECT ON THE 

## P OTENTIAL TO 

## E MIT

Based on this facility’s maximum annual hydrocarbon production, this facility will require a federally

‐ enforceable 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 potential to emi t, Enerplus is requesting the following:

1) Mandated installation, operation and maintenance of 98% destruction removal efficiency

emission control equipment; and 2) A production limit of 8,000 BOPD.

Selection of a control device will occur nearer to the time the facility commences construction as
combustor size(s) and quantity are likely to change as:

 Drill schedule s 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);

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

conservative average herein); and

 Combustion unit availability closer to the ti me 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 constructi on/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 antici pated 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: Nishu/Sanish

F

‐ 3 

## M ONITORING 

## , R ECORDKEEPING AND 

## R EPORTING



### Facility

‐ Wide Emissions

Monitoring. Facility

‐ wide hydrocarbon production will be maintained and recorded at the end

of each month, beginning with the first full calendar month after production commences to

compare with the production rate used to calculate emissions for this application.

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

1) Actual rolling monthly fac ility

‐ wide hydrocarbon production rate; and 2) Process units and emission control devices used.



### Control Device for VOC and HAP Emissions

Monitoring. Control device operations will be inspected periodically to confirm proper operation as follows:

1) Continuous monitoring of the flame using a thermocouple and a data acquisition device indicating continuous ignition of the flame; 2) Periodic check of the chart recorder to insure proper operation, at a minimum performed quarterly; 3) Periodic chec k of the flame to insure proper operation, at a minimum performed quarterly; and 4) Visual confirmation of smokeless operation of any enclosed combustor process or temporary/emergency flare, at a minimum performed quarterly.

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

1) Instances in which a control device was bypassed or down each calen dar month, the

reason for the incident, its duration, and the corrective actions taken or the
preventative measures adopted to avoid such bypasses or downtime. 2) Instances in which visible emissions are observed emanating from an enclosed

combustor process or temporary/emergency flare.

Recordkeeping documentation shall be maintai ned 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; and 2) The results of such analyses or measurements.Enerplus Resources (USA) Corporation Application for New Construction Facility: Nishu/Sanish

F

‐ 4 

### Natural Gas Fired External Combustion Units

This section applies to combustion emissions from external combustion units other than control

devices (i.e. flares and enclosed combustors) such as process heaters, trace line heaters, oil
stabilizers, tank heaters, etc.

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

combustion units:

1) The actual heat input to the burning chamb ers of each external combustion unit

installed at the facility; and 2) The number of hours of operation for each external combustion unit at the facility.

# Attachment G

Equipment Specifications and Guarantees

# Emission Control System Warranty

Your new Honda Power Equipment e ngine complies with the U.S. EP A, Environment Canada , and State of Califo rnia emission regulati ons (models certified for sale in California only). Amer ican Honda Motor Co., Inc. provides the emission warranty coverage for engines in t he United States and its territories. Honda Cana da Inc. provides the emission warra nty 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 cont rol system warranty on your Honda Power Eq uipment engine. In California, new spark-ignited small off-ro ad equipment engines must be designed, bui lt, and equipped to meet the State's str ingent 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 E nvironment Canada emission standards for spark-ignited engine s at or below 19 kilowatts. Specific Ho nda 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 syst em on your power equipment engine for the period of time listed below, provided the re has been no abuse, neglect, or improper main tenance of your power equipment engi ne. Where a warrantable condition ex ists, Honda will repair your p ower equipment engine at no cost to you includi ng diagnosis, pa rts, and labor.

Your emission control system may include su ch parts as the carburetor or fuel inje ction system, the igni tion system, and cataly tic converter. Also included may be hoses, connecto rs, and other emission-related assemblies (see page 2 fo r additional covered parts).

OWNER'S WARRANTY RESPONSIBILITY: As the power equipment engine ow ner, 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 cov erage solely for the lack of receipts or for your failure to ensu re the performance of al l scheduled maintenance.

As the power equipment engine ow ner, you should however be aware Honda may deny you warranty coverage if your power equipment e ngine or a part has failed due to abuse, neglect, improper maintenanc e, or unapproved modifications.

You are responsible for presenting your power equipment engine to a Honda Power Equipmen t dealer as soon as a problem exists. The emission related warranty repairs should be comp leted in a reasonable amount of time, not to exceed 30 days. If you have any questions regarding your emission warranty rights and res ponsibilities, you s hould 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 leng th of the Honda Distributor’s Limited Warra nty, 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, th e part will be repaired or replaced by Honda without charge for dia gnosis, parts, or labor. All defective parts replaced under th is warranty become the property of Honda. A list of warranted pa rts 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 requi red replacement interval only.

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

Only Honda approved replacem ent 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 th e effectiveness of your engine emission control system. If such a replacement part is used in the repair or maintenance of your engi ne, 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 qu estion is not related to the reason your e ngine 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 Cu stomer Relations 4900 Marconi Drive Alpharetta, Georgia 30005-8847

Telephone: (888) 888-3139 Email: powerequipmente missions@ahm.honda.com or Honda Canada Inc. Power Equipment Cu stomer 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 expe nse, take your Honda Power Equipm ent 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 th at 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 se rvice or are dissatisfied with the warranty service you received, contact the o wner of the dealership involved. Normally this should resolve your problem. However, if you require further assistance, contact th e Honda office in yo ur region:

EXCLUSIONS:
Failures other than those resulting from defe cts in material or workmanship are not co vered by this warranty. This warranty doe s not extend to emission control systems or parts that are affected or damaged by owner abuse, neglect, improper maintenance, misuse, misf ueling, improp er storage, collision, the incorporation of, or use of, unsui table attachments, or the unaut horized alteration of any part. This warranty does not cover repl acement of expendable maintenance items made in connection with required maintenance service a fter 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 a nd Limitation of Im plied Warranties: American Honda Motor Co., Inc. and Honda Canada Inc. disclaim any responsibility for in cidental or conseque ntial damages such a s 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 Calif ornia, U.S. EPA, or Environment Canada em ission control syste m 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: powerequipmente missions@ahm.honda.com or Honda Canada Inc. Power Equipment Cu stomer 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 en richment system), Engine temperature sensor, Engine control module, Fuel regulator, Intake manifold
Evaporative Fuel tank, Fuel cap, Fu el hoses, Vapor hoses, Carbon ca nister, Canister mounting brackets, Fuel strainer, Fuel cock, Fuel pump, Fu el hose joint, Canist er purge hose joint
Exhaust Catalyst, Exhaust manifold

Air Induction Air filter hous ing, Air filter element*

Ignition Flywheel magneto, Ignition pulse gene rator, Crankshaft position sensor, Power coil, Ignition coil assembly, Ignition control module, Spark plug cap, Spark plug*

Crankcase Emission Cont rol Crankcase breather tube, Oil filler cap

Miscellaneous Pa rts Tubing, fittings, seals, ga skets, and clamps associated with these listed systems.
Note: This list applies to pa rts supplied by Honda and does not cover parts supplied by the equi pment manufacturer. Please see the original equipment
manufacturer’s emissions wa rranty for non-Honda parts. * Covered up to the first required replacement only. See the Maintenance Schedul e in the owner’s manual.

PWL50975-MUNITED STATES ENVIRONMENTAL PROTECTION AGENCY2011 MODEL YEARCERTIFICATE OF CONFORMITYWITH THE CLEAN AIR ACT OF 1990OFFICE OF TRANSPORTATIONAND AIR QUALITYANN ARBOR, MICHIGAN 48105Certificate Issued To: Power Solutions International(U.S. Manufacturer or Importer)Certificate Number: BPWRB11.1NGP-002Effective Date:01/03/2011Expiration Date:12/31/2011_________________________Karl J. Simon, DirectorCompliance and Innovative Strategies DivisionIssue Date:01/03/2011Revision Date:N/AManufacturer:Power Solutions InternationalEngine Family:BPWRB11.1NGPCertificate Number:BPWRB11.1NGP-002Certification Type:Mobile and StationaryFuel :LPG/PropaneNatural Gas (CNG/LNG)Emission Standards :NMHC + NOx ( g/kW-hr ) : 2.7CO ( g/kW-hr ) : 4.4HC + NOx ( g/kW-hr ) : 2.7CO ( g/Hp-hr ) : 2VOC ( g/Hp-hr ) : 0.7NOx ( g/Hp-hr ) : 1Emergency Use Only :NPursuant 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 voidab initiofor 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 24 th 

### Avenue, Suite 100 Norman, Oklahoma 73069 Marcus Manning Portable Division Director

Test Date: June 14 - 15, 2011

APT Project: CIM1122

## T able 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 4APT 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 (O 2 

### ), carbon dioxide (CO 2 

### ), carbon monoxide (CO), methane (CH 4 

### ) 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 24 th 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 GasesAPT 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 (O 2 

### ), carbon dioxide (CO 2 

### ), moisture (H 2 

### O) 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

O 2 , CO 2 Method 3A paramagnetic and non-dispersive infrared analyzers

H 2 O 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

C 2 H 6 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 MethodsAPT 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 (H 2 

### O) 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 (O 2 

### and CO 2 

### ) 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

O 2 

### , CO 2 

### , CO and NMOC emission concentrations were measured in accordance with EPA Methods 3A (O 2 

### and CO 2 

### ), 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 O 2 

### / non-dispersive infrared CO 2 

### 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 – O 2 

### and CO 2 

### ), or parts per million, wet volume basis as propane (ppmvw as C 3 

### H 8 

### – 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 zeroAPT 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 C 3 

### H 8 

### – as propane

• DRE – destruction removal efficiencyAPT 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

O 2 (%vd) 18.5 18.3 18.2 18.3

CO 2 (%vd) 1.5 1.7 1.8 1.6

H 2 O (%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 C 3 H 8 ) 46.0 69.8 46.0 53.9
NMOC (lb/hr as C 3 H 8 ) 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

O 2 (%vd) 16.5 16.6 16.6 16.6

CO 2 (%vd) 2.9 2.8 2.8 2.8

H 2 O (%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 C 3 H 8 ) 0.0 2.0 0.4 0.8
NMOC (lb/hr as C 3 H 8 ) 0.00 0.04 0.01 0.01 

### Table 5.2: Test Results Summary, Flare Outlet, 4 oz. FlowAPT 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

O 2 (%vd) 14.8 14.9 15.1 14.9

CO 2 (%vd) 3.9 3.8 3.8 3.8

H 2 O (%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 C 3 H 8 ) 0.3 0.7 0.1 0.4
NMOC (lb/hr as C 3 H 8 ) 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 C 3 H 8 ) 150.6 260.0 489.2

Pilot Inlet Pilot Light Flow (MCFD) 0.3 0.3 0.3
Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.5 0.5 0.5
Total Inlet NMOC (lb/hr as C 3 H 8 ) 151.0 260.5 489.7

Total Outlet NMOC (lb/hr as C 3 H 8 ) 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

# Appendix One : Test Parameters

### 1 oz. Inlet PressureCimarron 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
D S Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0 √∆ P AVG Inlet Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1150 0.0940 0.1026 0.1039 C P Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84
T S Inlet Stack Temperature (°F) 73 74 73 73
P bar Barometric Pressure (mbar) 936 936 936 936
P bar Barometric Pressure (" Hg) 27.64 27.64 27.64 27.64
Ps Inlet Stack Pressure ('' H 2 O) 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 F ACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18
F DSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17 dry Pilot Light NMOC (ppmvd as C 3 H 8 ) 402,167 402,167 402,167 402,167

lb/hr Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.47 0.47 0.47 0.47

Run # 7 8 9 Average

B ws Inlet Moisture Content (%/100) - saturated 0.029 0.030 0.029 0.030
M D Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54
M A Inlet Molecular Weight Wet (lb/lb-mole) 35.03 35.01 35.03 35.02
V S Inlet Gas Velocity (ft/sec) 6.1 5.0 5.5 5.5
F ACFM Inlet Gas Flow (acfm) 32 26 29 29
F DSCFM Inlet Gas Flow (dscfm) 29 23 25 26 dry NMOC (ppmvd as C 3 H 8 ) 858,433 835,967 858,533 850,978
lb/hr NMOC (lb/hr as C 3 H 8 ) 168 134 150 151 tpy NMOC (tons/year as C 3 H 8 ) 739 587 659 661 Field Reference Method Data

Waste Gas Data

Reference Method Calculations Pilot Light DataCimarron 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
D S Stack Diameter (inches) 42.6 42.6 42.6 42.6 √∆ P AVG Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.0780 0.1380 0.1475 0.1212 C P Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83
T S Stack Temperature (°F) 936 811 889 879
P bar Barometric Pressure (mbar) 936 936 936 936
P bar Barometric Pressure (" Hg) 27.64 27.64 27.64 27.64
Ps Stack Pressure ('' H 2 O) 0.00 0.00 0.00 0.00
Y d Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780
T m Meter Temperature (°F) 74 78 79 77
V m Sample Volume (ft 3 ) 37.560 38.015 37.022 37.532

∆ H Orifice Pressure Delta H (" H 2 O) 1.0 1.0 1.0 1.0
V lc Moisture (g) 34.0 28.7 30.1 30.9 O 2 %vd O 2 (%vd) 18.5 18.3 18.2 18.3 CO 2 %vd CO 2 (%vd) 1.5 1.7 1.8 1.6
N 2 %vd N 2 (%vd) 80.0 80.0 80.0 80.0 dry CO (ppmvd) 107.2 89.1 81.4 92.6

wet CH 4 (ppmvw) 18.3 18.0 9.6 15.3

wet NMOC (ppmvw as C 3 H 8 ) 43.9 67.1 44.1 51.7

Run # 1 2 3 Average
V mstd Sample Volume (dscf) 33.629 33.763 32.850 33.414
V wstd Moisture Volume (scf) 1.60 1.35 1.42 1.46
B ws Moisture Content (%/100) 0.046 0.039 0.041 0.042
M D Molecular Weight Dry (lb/lb-mole) 28.98 29.00 29.02 29.00
M A Molecular Weight Wet (lb/lb-mole) 28.48 28.58 28.56 28.54
V S Gas Velocity (ft/sec) 7.4 12.4 13.7 11.2
F ACFM Gas Flow (acfm) 4,382 7,386 8,135 6,635
F DSCFM 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
F o F o (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 CH 4 (ppmvd) 19.2 17.4 9.2 15.3
lb/hr CH 4 (lb/hr) 0.1 0.1 0.1 0.1 tpy CH 4 (tons/year) 0.3 79.0 42.3 40.5 dry NMOC (ppmvd as C 3 H 8 ) 46.0 69.8 46.0 53.9
lb/hr NMOC (lb/hr as C 3 H 8 ) 0.461 1.3042 0.8903 0.885 tpy NMOC (tons/year as C 3 H 8 ) 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 CalculationsCimarron Energy Liberty Oil Well Parshall, ND
Flare
06/15/11

O 2 CO 2 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 BiasCimarron Energy Run 1 Liberty Oil Well Parshall, ND Start Time 12:34
Flare Run Length 60
06/15/11 Stop Time 13:34

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

18.5 1.5 107.2 18.3 43.9
Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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 CalibrationCimarron Energy Run 2 Liberty Oil Well Parshall, ND Start Time 14:12
Flare Run Length 60
06/15/11 Stop Time 15:12

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

18.3 1.7 89.1 18.0 67.1
Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

18.2 1.8 81.4 9.6 44.1 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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 C 3 H 8 ) 0.89

Waste Gas Inlet NMOC (lb/hr as C 3 H 8 ) 150.6 Pilot Inlet NMOC (lb/hr as C 3 H 8 ) 0.5 Sum of Inlets NMOC (lb/hr as C 3 H 8 ) 151.0

% DRE (mass flow in/out basis) 99.4% % DRE (carbon balance) 98.9%

%DRE Calculations

### 4 oz. Inlet PressureCimarron 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
D S Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0 √∆ P AVG Inlet Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1793 0.1769 0.1798 0.1787 C P Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84
T S Inlet Stack Temperature (°F) 61 63 67 64
P bar Barometric Pressure (mbar) 938 938 938 938
P bar Barometric Pressure (" Hg) 27.70 27.70 27.70 27.70
Ps Inlet Stack Pressure ('' H 2 O) 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 F ACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18
F DSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17 dry Pilot Light NMOC (ppmvd as C 3 H 8 ) 413,300 413,300 413,300 413,300
lb/hr Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.49 0.49 0.49 0.49

Run # 4 5 6 Average

B ws Inlet Moisture Content (%/100) - saturated 0.019 0.021 0.024 0.021
M D Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54
M A Inlet Molecular Weight Wet (lb/lb-mole) 35.20 35.18 35.12 35.17
V S Inlet Gas Velocity (ft/sec) 9.3 9.2 9.4 9.3
F ACFM Inlet Gas Flow (acfm) 49 48 49 49
F DSCFM Inlet Gas Flow (dscfm) 46 45 45 45 dry NMOC (ppmvd as C 3 H 8 ) 830,533 826,400 850,367 835,767
lb/hr NMOC (lb/hr as C 3 H 8 ) 260 255 265 260 tpy NMOC (tons/year as C 3 H 8 ) 1142 1119 1162 1141 Field Reference Method Data

Waste Gas Data

Reference Method Calculations Pilot Light DataCimarron 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
D S Stack Diameter (inches) 42.6 42.6 42.6 42.6 √∆ P AVG Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1607 0.1599 0.1560 0.1589 C P Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83
T S Stack Temperature (°F) 1320 1321 1327 1323
P bar Barometric Pressure (mbar) 938 938 938 938
P bar Barometric Pressure (" Hg) 27.70 27.70 27.70 27.70
Ps Stack Pressure ('' H 2 O) 0.00 0.00 0.00 0.00
Y d Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780
T m Meter Temperature (°F) 57 65 69 64
V m Sample Volume (ft 3 ) 36.340 36.409 37.287 36.679

∆ H Orifice Pressure Delta H (" H 2 O) 1.0 1.0 1.0 1.0
V lc Moisture (g) 32.7 46.2 37.2 38.7 O 2 %vd O 2 (%vd) 16.5 16.6 16.6 16.6 CO 2 %vd CO 2 (%vd) 2.9 2.8 2.8 2.8
N 2 %vd N 2 (%vd) 80.6 80.6 80.6 80.6 dry CO (ppmvd) 52.6 54.0 51.5 52.7

wet CH 4 (ppmvw) 0.0 0.7 0.0 0.2

wet NMOC (ppmvw as C 3 H 8 ) 0.0 1.9 0.4 0.7

Run # 4 5 6 Average
V mstd Sample Volume (dscf) 33.662 33.213 33.775 33.550
V wstd Moisture Volume (scf) 1.54 2.18 1.75 1.82
B ws Moisture Content (%/100) 0.044 0.062 0.049 0.052
M D Molecular Weight Dry (lb/lb-mole) 29.12 29.11 29.10 29.11
M A Molecular Weight Wet (lb/lb-mole) 28.63 28.43 28.56 28.54
V S Gas Velocity (ft/sec) 17.1 17.1 16.6 16.9
F ACFM Gas Flow (acfm) 10,158 10,145 9,894 10,065
F DSCFM 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
F o F o (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 CH 4 (ppmvd) 0.0 0.7 0.0 0.2
lb/hr CH 4 (lb/hr) 0.0 0.0 0.0 0.0 tpy CH 4 (tons/year) 0.0 3.1 0.1 1.0 dry NMOC (ppmvd as C 3 H 8 ) 0.0 2.0 0.4 0.8
lb/hr NMOC (lb/hr as C 3 H 8 ) 0.000 0.0354 0.0068 0.014 tpy NMOC (tons/year as C 3 H 8 ) 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 CalculationsCimarron Energy Liberty Oil Well
Parshall ND Flare
06/14/11

O 2 CO 2 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 BiasCimarron Energy Run 4 Liberty Oil Well
Parshall ND Start Time 10:48:13
Flare Run Length 60
06/14/11 Stop Time 11:48

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

16.5 2.9 52.6 -0.5 -0.1 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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 CalibrationCimarron Energy Run 5 Liberty Oil Well
Parshall ND Start Time 12:55:23
Flare Run Length 60
06/14/11 Stop Time 13:55

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

16.6 2.8 54.0 0.7 1.9 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

16.6 2.8 51.5 0.0 0.4 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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 C 3 H 8 ) 0.01

Waste Gas Inlet NMOC (lb/hr as C 3 H 8 ) 260.0 Pilot Inlet NMOC (lb/hr as C 3 H 8 ) 0.5 Sum of Inlets NMOC (lb/hr as C 3 H 8 ) 260.5

% DRE (mass flow in/out basis) 99.99% % DRE (carbon balance) 99.99%

%DRE Calculations

### 10 oz. Inlet PressureCimarron 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
D S Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0 √∆ P AVG Inlet Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.3290 0.3314 0.3338 0.3314 C P Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84
T S Inlet Stack Temperature (°F) 68 73 74 72
P bar Barometric Pressure (mbar) 938 938 936 937
P bar Barometric Pressure (" Hg) 27.70 27.70 27.64 27.68
Ps Inlet Stack Pressure ('' H 2 O) 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 F ACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18
F DSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17 dry Pilot Light NMOC (ppmvd as C 3 H 8 ) 421,267 421,267 421,267 421,267
lb/hr Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.50 0.50 0.50 0.50

Run # 7 8 9 Average

B ws Inlet Moisture Content (%/100) - saturated 0.024 0.029 0.029 0.028
M D Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54
M A Inlet Molecular Weight Wet (lb/lb-mole) 35.11 35.03 35.02 35.06
V S Inlet Gas Velocity (ft/sec) 17.2 17.4 17.6 17.4
F ACFM Inlet Gas Flow (acfm) 90 91 92 91
F DSCFM Inlet Gas Flow (dscfm) 83 83 84 83 dry NMOC (ppmvd as C 3 H 8 ) 864,867 851,467 848,100 854,811
lb/hr NMOC (lb/hr as C 3 H 8 ) 494 486 487 489 tpy NMOC (tons/year as C 3 H 8 ) 2168 2131 2135 2145 Field Reference Method Data

Waste Gas Lab Data

Reference Method Calculations Pilot Light DataCimarron 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
D S Stack Diameter (inches) 42.6 42.6 42.6 42.6 √∆ P AVG Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1719 0.1681 0.1813 0.1738 C P Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83
T S Stack Temperature (°F) 1973 1992 1992 1986
P bar Barometric Pressure (mbar) 938 938 936 937
P bar Barometric Pressure (" Hg) 27.70 27.70 27.64 27.68
Ps Stack Pressure ('' H 2 O) 0.00 0.00 0.00 0.00
Y d Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780
T m Meter Temperature (°F) 74 79 62 72
V m Sample Volume (ft 3 ) 37.385 37.148 37.088 37.207

∆ H Orifice Pressure Delta H (" H 2 O) 1.0 1.0 1.0 1.0
V lc Moisture (g) 65.2 43.7 52.2 53.7 O 2 %vd O 2 (%vd) 14.8 14.9 15.1 14.9 CO 2 %vd CO 2 (%vd) 3.9 3.8 3.8 3.8
N 2 %vd N 2 (%vd) 81.3 81.3 81.1 81.2 dry CO (ppmvd) 15.5 21.0 15.4 17.3

wet CH 4 (ppmvw) 0.0 0.0 0.0 0.0

wet NMOC (ppmvw as C 3 H 8 ) 0.3 0.6 0.1 0.3

Run # 7 8 9 Average
V mstd Sample Volume (dscf) 33.536 33.037 33.984 33.519
V wstd Moisture Volume (scf) 3.07 2.06 2.46 2.53
B ws Moisture Content (%/100) 0.084 0.059 0.068 0.070
M D Molecular Weight Dry (lb/lb-mole) 29.22 29.21 29.21 29.21
M A Molecular Weight Wet (lb/lb-mole) 28.28 28.55 28.45 28.43
V S Gas Velocity (ft/sec) 21.5 21.0 22.7 21.7
F ACFM Gas Flow (acfm) 12,780 12,486 13,507 12,925
F DSCFM 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
F o F o (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 CH 4 (ppmvd) 0.0 0.0 0.0 0.0
lb/hr CH 4 (lb/hr) 0.0 0.0 0.0 0.0 tpy CH 4 (tons/year) 0.0 0.0 0.0 0.0 dry NMOC (ppmvd as C 3 H 8 ) 0.3 0.7 0.1 0.4
lb/hr NMOC (lb/hr as C 3 H 8 ) 0.005 0.0107 0.0013 0.006 tpy NMOC (tons/year as C 3 H 8 ) 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 CalculationsCimarron Energy Liberty Oil Well
Parshall ND Flare
06/14/11

O 2 CO 2 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 ValueCimarron Energy Run 7 Liberty Oil Well
Parshall ND Start Time 15:31:23
Flare Run Length 60
06/14/11 Stop Time 16:31

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

14.8 3.9 15.5 0.0 0.3 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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 RangeCimarron Energy Run 8 Liberty Oil Well
Parshall ND Start Time 16:48:23
Flare Run Length 60
06/14/11 Stop Time 17:48

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

14.9 3.8 21.0 0.0 0.6 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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

O 2 CO 2 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 O 2 % Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

15.1 3.8 15.4 -0.1 0.1 Run Length (Minutes) Time Uncorrected
O 2 % Uncorrected

CO 2 % 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 RangeCimarron Energy Liberty Oil Well
Parshall ND Flare
6/14/2011

10 oz. Outlet NMOC (lb/hr as C 3 H 8 ) 0.01

Waste Gas Inlet NMOC (lb/hr as C 3 H 8 ) 489.2 Pilot Inlet NMOC (lb/hr as C 3 H 8 ) 0.5 Sum of Inlets NMOC (lb/hr as C 3 H 8 ) 489.7

% DRE (mass flow in/out basis) 100.00% % DRE (carbon balance) 100.00%

%DRE CalculationsCimarron 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 * V M * Y D * {P B + **∆** H/13.6}

T M + 460

= 17.64 * 37.56 * 0.978 * { 27.64 + 1.0 / 13.6}
74 460

= 33.629

moisture volume (scf) = 0.04715 * V LC

= 0.04715 * 34

= 1.603

moisture content (% / 100) = V W(STD) (V M(STD) + V W(STD) )

= 1.603 ( 33.629 + 1.603 )

= 0.046

molecular weight, dry (grams/mol) = (0.440) * (%CO 2 ) + (0.320) * (%O 2 ) + (0.280) * (%N 2 + %CO)

= (0.440) * 1.5 + (0.320) + 18.5 + (0.280) * ( 80 + 0.0)

= 28.98

molecular weight, actual (grams/mol) = M D * (1 - B WS ) + (18.0) * B WS

= 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 * C P * **√∆** P AVG * [P B + P S / 13.6] * M A

= (85.49) * 0.83 * 0.078 * 936 +
27.64 + 0.00 * 28.48

13.6

= 7.4

**π** * (D S / 12) 2

gas flow (acfm) = 60 * 4 * V S

**π** * ( 42.63 / 12) 2

= 60 * 4 * 7.4

= 4,382

**π** * (D S / 12) 2 T STD * [P B + P S / 13.6]

gas flow (dscfm) = 60 * V S * (1 - B WS ) * 4 * (T S + 460) * P STD

**π** * ( /12) 2 528 * [ 27.64 + 0.00 / 13.6 ]
= 60 * ) * * ( 936 + 460) * 29.92

= 1,462 7.4 T S + 460

42.6
4 0.046 * (1 - 

# [ ] 460Cimarron 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

B WS - moisture content of the gas (wet volume percent/100)

%CO - carbon monoxide content of the gas (dry volume percent)

%CO 2 - carbon dioxide content of the gas (dry volume percent)

C P - pitot tube constant (unitless)

D S - diameter of the stack (inches)

**∆** H - pressure differential at dry gas meter exit orifice (inches water)

M D - molecular weight of the dry gas (grams per mol)

M A - molecular weight of the wet gas (grams per mol)

%N 2 - nitrogen content of the gas (dry volume percent)

%O 2 - oxygen content of the gas (dry volume percent)

P AVG - average square root of the stack gas pitot differential pressure (inches water)

P B - barometric pressure (inches mercury)

P S - stack pressure relative to barometric presure (inches water)

P STD - standard pressure (29.92 inches mercury)

T M - average dry gas meter temperature (oF)

T S - average stack temperature (oF)

T STD - standard temperature (528 oR)

V LC - volume of moisture collected as a liquid (milliliters)

V M - volume indicated on dry gas meter (uncorrected actual cubic feet)

V MSTD - volume of gas through dry gas meter (corrected dry standard cubic feet)

V S - stack gas velocity (feet per second)

V WSTD - volume of moisture collected as a gas at standard conditions (standard cubic feet)

Y D - dry gas meter calibration factor (unitless)Cimarron Energy

Liberty Oil Well Parshall, ND Flare
06/15/11

EPA Method 3A: Determination of O 2 / CO 2 Concentrations in Emissions from Stationary Sources ( Instrumental Analyzer Procedure )

Sample Calculations

CO 2 conc, drift cal (%vd) = (%FS STACK - %FS 0 ) * [Span Gas Conc (%vd)] (%FS SPAN -%FS 0 )

= ( 1.5 - 0 ) * ( 2.48 )

( 2.5 ) - ( 0 )

= 2.5

O 2 conc, drift cal (%vd) = (%FS STACK - %FS 0 ) * [Span Gas Conc (%vd)] (%FS SPAN -%FS 0 )

= ( 18.7 - 0.0 ) * ( 10 )

( 10.1 ) - ( 0.0 )

= 18.5

Variables and Abbreviations

cal - calibrated

conc - concentration

CO 2 - Carbon Dioxide

O 2 - Oxygen

%FS SPAN - average analyzer reading for span gas (percent of full scale)

%FS STACK - average analyzer reading for stack gas (percent of full scale)

%FS 0 - average analyzer reading for zero gas (percent of full scale)

%vd- dry volume percentCimarron 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) = (%FS STACK - %FS 0 ) * [Span Gas Conc (ppmvd)] (%FS SPAN -%FS 0 )

= ( 105.1 - 1.2 ) * ( 79.1 ) ( 77.9 ) - ( 1.2 )

= 107.2

CO emissions (lb/hr) = [CO (ppmvd)]*(F DSCFM )*(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

F DSCFM - gas flow (dry standard cubic feet per minute, where standard = 29.92 inches Hg and 68oF)

%FS SPAN - average analyzer reading for span gas at probe tip (percent of full scale)

%FS STACK - average analyzer reading for stack gas (percent of full scale)

%FS 0 - 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-hourCimarron 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 C 3 H 8 ) = ( %FS STACK - %FS 0 ) * [Span Gas Conc (ppmvd)] ( %FS SPAN -%FS 0 )

= ( 43.9 - 0.0 ) * ( 30.2 ) ( 30.2 ) - ( 0.0 )

= 43.9

NMOC emissions (lb/hr as C 3 H 8 ) [NMOC (ppmvd)]*(F DSCFM )*(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 C 3 H 8 - as propane or C3

B WS - moisture content of the gas (wet volume percent/1 00)

cal - calibrated

conc - concentration

F DSCFM - gas flow (dry standard cubic feet per minute, whe re standard = 29.92 inches Hg and 68oF)

%FS SPAN - average analyzer reading for span gas at probe ti p (percent of full scale)

%FS STACK - average analyzer reading for stack gas (percent o f full scale)

%FS 0 - average analyzer reading for zero gas at probe ti p (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 =

# Appendix Two : Field and Laboratory Data

### 1 oz. Inlet Pressure

### 4 oz. Inlet Pressure

### 10 oz. Inlet Pressure

# Appendix Three : Calibration Data

# Appendix Four : SchematicsF F

ft 3

“Hg orifice

manometer dry gas

meter air-tight

pump vacuum

gauge main valve bypass

valve thermocouples sample probe

S-type pitot

with thermocouple

100 mL H 2 0 250g Silica gel

empty

100 mL H 2 0 stack wall

chilled impinger train

sample line pitot lines



### EPA Methods 1,2, & 4 sampling train schematic

### EPA Methods 3A, 10, 18 & 25A sampling train schematic CO

CO 2 O 2 CDAS stack wall

sample probe
with in-stack filter moisture removal system with pump

calibration gas

manifold pressure regulator and pressure
gauge sample transport lines

heated sample lines calibration valve

sample control valve with bypass flowmeter

sample control valve Servomex Series 1400

TECO Model 48H

JUM Model VE-7 FID pump

VOC Tedlar bag for subsequent GC analysis

### 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 3K7Questor Technologies Inc. Mobil Lone Pine Creek (06-03) - November 1998 Project #98-19895

-i

## SUMMARY

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 ft 3 of wet gas) 6.4 4.3

- -

SULPHUR DIOXIDE

(ppmv wet)

- - 547 - (ppmv dry) - - 610 -
(kg/hr)
- - - -

OXIDES OF NITROGEN (as NO 2 )

(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 (H 2 S) (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 (CS 2 ) (ppmv wet) - - <0.4 -
(ppmv dry) - <0.5 <0.5 -
(g/hr)
- - - -

ORGANIC COMPOUNDS

Methane (CH 4 ) (ppmv wet) - - <0.9 -
(ppmv dry) 825000 816900 <1.0 -
(g/hr)
- - - -

Ethane (C 2 H 6 ) (ppmv wet) - - <0.9 -
(ppmv dry) 44100 44800 <1.0 -
(g/hr)
- - - -

Propane (C 3 H 8 ) (ppmv wet) - - <0.9 -
(ppmv dry) 13700 14800 <1.0 -
(g/hr)
- - - -

Butane (C 4 H

10

) (ppmv wet) - - <0.9 -
(ppmv dry) 7040 9420 <1.0 -
(g/hr)
- - - -

Pentane (C 5 H

12 ) (ppmv wet) - - <0.9 -
(ppmv dry) 3520 5880 <1.0 -
(g/hr)
- - - -

Hexane (C 6 H 14

) (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 + (C 7 H

16

) (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 CH 4 )
(total in – ppmv as Methane) 851328 - - -
(total out – ppmv as Methane) 1.37 - - -
(% efficiency) >99.99 - - -Mr. Kim Eastlick Facilities Division 

### EnvironmentSafety & 

### Technical Services AlbertaEliergy ai1dUtilities Board

Regarding: Portable Incinerator Test Shell 29 Limestone 14-2-33-10W5m Jan 25, 2000/03/04 

### Shell Canada Limited

400-4th Avenue S.W. P.O. Box 100. Station M Calgary, Alberta, T2P2H5

20 March, 2000

Attached are the findings of the Portable incinerator test conducted by Shell Canada Limited in conjunction with Norward Energy Services, the owner of the incinerator, and Questor Technologies, the manufacturer of the incinerator.

Yours truly,



# .. tt£

.. ..•.•.•...**~~ R.L~**  Nels()n. qrillingand Production EngineE!ring Advisor

Copies
Robert Knowles Divisi.onManager Norwa;rdEnergy Limited

DanierMotyka President/CpO Questor Technology Inc

CAPPWellTestFlaring Comrnitteemembers & CAPP Well Construction Committee Chairman

CAPP Environmental Committee Chairman·

File: Incinertatornote to EUB.DOCpage 1



## Conducted on Jan 

## 25, 2;000 Incinerator test on Shell 29 Limestone 14-2-33-10 W5M



# Portable 

# Well "'Fest Incinerator Test Results

Shell 

# 29 Limestone 14-2-33-10W5M

2-2-33-10W5 surface 

# location

## Maxxam Analytics Inc.



# Summary of Inlet 

# and 

# Exhaust Gas Analysis Incineratbrtest on Shell 29 Limestone 14-2-33-10 W5M page 11

Attachment 3



## And



# Air 

# /Fuel Calculations200

200 833

833

333

333 933

933

3500

3500 13933

13933 10.39

103900

766300

766300 AVERAGE

Shell Canada Limited Limestone 29

- "l1luary 2000 Project #00-20310

9.98

99800



## msoo

772500 

## a JiUl.25, 2000 19:04

- 20:04

":

.. 

## -

... - .:

-**';~-** -." 10.69

106900

764200

764200 

### 4 JiUl.25,2000 18:00 -19:00

10.51

105100 1 JiUl.25,20oo 16:53 -17:53

(pp,nvwet) 762200

(ppmv dry) 762200

(ppm» ioet) 14400 14000 13400

(ppmv dTY) 14-100 14000 13400

(ppmv tuet) 1000 700 800

(ppmvdry) 1000 700 800

(ppmv.loet) 900 900 1000

(ppmvdry) 900 900 1000

(ppmv wet) 400 200 400

(ppm» dry) 400 200 400

(ppmvwet) 200 200 200

(ppmvdry) 200 200 200

(ppmv wet) 4800 3800 1900

(ppmvdry) 4800 3800 1900 1;2.4 

### -(3 

## o INCINERATOR INLET 

## (126 E3m3/ day)

RUN: DATE:

TIME:

HYDROGEN SULPHIDE

Mole %

ppmv(dTY)

ORGANICCOMPOUNDS

Metltalle

.**(CH~)**

Etlzalle(CJlJ

Propane(CPJ

Blltane (C.,H.,,)

Pentane (C,lfJ:)

Hexane (CJlIJ 

# I**lill,"""--~";,;,,;,,,,;;,---~--------**

I

# fi,141~~~~ 

# _

··1·



# I

-iv-

. - 

### ..... "-

'-' .. " ..

- ."**~~~** -.

### _ 

## -_ , 

### .. Limestone 29

- January 2000 Project #00-20310

851

960 27.3

30.6 6597

7415 AVERAGE

47

53 28.7

32.2 6510

7316

,1 

### Jan. 25, 2000 19:04.; 20:04

32

36 33.4 64-l0

37.4 i212



### Z 

### Jan. 25,2000
18:00- 19:00

22.3 19.7 6842

7718

2473

2790

1 

### Jari. 25, 2000
16:53- 17:53 RUN:
DATE: ,TIME: !;la-f)u 

## INCINERATOR EXHAUST STACK (126 

## E3rn3lday)

SULPHUR DIOXIDE

OXIDESOFNITRQGEN (as N02)

(ppmvlvet)

(ppmvdry)

(ppmvtl1et)
(pplnvdry) (ppmtrtuet)

(ppmvtiry)

·CARBONMONOXIDE

# ~I 

# r

I 

# I**?I~........-------.,.-- ~----**  '[I

I

iii.· •• ••· ••

# ·l?.....-~ '.

·

... .....-... --.;......----.....;.--------------------------------: \' .: ,,1=-.,·

# --------~ __ ---------'


# \ 1

I

'i

II

I I
I I

. ','
-

.. ,' ...... , "TcrTAL REDUCED SULPHUR COMPOUNDS

CarbollylSrtlplridll (COS) (pprnv uret} <0.9

(ppm» dry) <1.0 .'

.-

... -

.... ,

. Hydrogensulpl,ide·(H2s) (ppmv wet) <0.9

(ppmv dry) <1.0 

# I

I'

CarbotJ,.VisulpJiide.(CSJ (ppmv wet) <0.9

(ppm» dry) <1.0 <0.9 <0.9 <0.9

<1.0 <1.0 <1.0

<0.9 <0.9 <0.9

<1.0 <1.0 <1.0

<0.9 <0.9 <0.9

<1.0 <1.0 <1.0

2.7 24.5 9.3

3.0 27.5 10.5

<0.9 <0.9 <0.9

<1.0 <-LO d.O

4.5 23.1 10.7

5.0· 26.0 '12.0 4.4

5.0 <0.9

<1.0

(ppmvwet) <0.9

(ppmu dry) <1.0

(ppmv wet)

(ppmvdry) Ethane. (CzHJ ORGANIC.CQMPOUNDS

Methani!(CHJ (pp"ivlvet)

(ppm» dry) \ I"--o

....

## ~~~ _ I I

i,

-v-**-~.** .'!:.'.:

_.**~..:** • - ." "-

- =.,.-.-.'.:.-.-

..... ':.-::::---:'

.. "Limestone 29 - January 2000 Projf!ct 1100-20310

(ppm» tuet) 0.9 0.9 16.9 6.2

(ppm» dry) 1.0 1.0 19.0 7.0

(pp111V wet) <0.9 <0.9 .<0.9 <0.9

(pprnvdry) <1.0 <1.0 <LO <LO

(ppmv wet) <0.9 <0.9 <0.9 <0.9

(ppmt: dry) <1.0 <1.0 <1.0 <1.0

(ppmvwet) <0.9 <0.9 <0.9 <0.9

(ppm» dry) <1.0 <1.0 <1.0 <1.0 Pe1ltane( CsHrJ Butane 

### (CPuJ



# I 

# 1

Hexane (CJ{.J

II

. 

# II Heptane + (C,HIJ

## 1'_~".**i;;V}\:~** _



# I
I

103900

<4.0

>99.9962

GASEOUS.ORGANICS DESTRUC110NE:{FICIENCIES (as CH,) @ 126 E3m3/d (total in- pplrrv as S"lpll",) 105100 106900 99800

. (totalouf-pprnvas S"lpl,ur) <4.0 <4.0 <4.0

(%e!ficiency) >99.9962 >99.9963 >99.9960 

### T;i:- i'I.:fuocro.-t f"'it;.i;, Qlr**J~/oJT;.h- 1if~'!**  9'1,P 99R

(total iII-pprnvas 

### Methane) 828102 821376 818214

(total out -ppmv as Met/'ane) <36.4 <38.4 <185.8

(% l!fficie"cy) >99.9956 ;>99.9953 >99.9773 822564

<86.9

>99.9894



### -vi-

.... 

### ----- 

## ------

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..... .-- ".;

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. "'-.' ,- " •• 

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