October 1, 2011

Minor NSR Permitting Coordinator

US EPA Region 8

1595 Wynkoop Avenue, 8P-AR

Denver, CO 80202-1129

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

Hilo/Kona Facility

To Whom It May Concern;

Enclosed please find the application for new constr uction for the Enerplus Re sources (USA) Corporation

Hilo/Kona facility. Included in the application for new construction is a synthetic minor limit request for

the facility requesting federally-enforceabl e limitations on the facility’s potential to emit.

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

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

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

Plains Region Office located in Aberdeen, South Dakota.

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

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

Dakota Bakken Task Force for the calc ulation 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, Enerplu s Resources (USA) Corporation will make available

to the EPA the finalized summary under separate cover.

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

Respectfully,

Tony Lucero

Enerplus Resources (USA) Operations

Environment, Health & Safety Coordinator

# Application for New Construction

Hilo/Kona Facility

Prepared For:



## Enerplus Resources (USA) Corporation

US Bank Tower, 950 17 th 

## Street

Denver, CO 80202

October 1, 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: Hilo/Kona

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

Ͳ 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  Equipment Specifications and GuaranteesEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

1 

## General Facility Information

1. (a) Company Name

Enerplus Resources (USA) Corporation

(b) Operator Name

Enerplus Resources (USA) Corporation 2. Facility Information

Hilo/Kona

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)

South of BIA Road 14 and West of Highway 17.

9. Reservation

Ft. Berthold Reservation 10. County

Dunn County 11. (a) Latitude

TBD 11. (b) Longitude

TBD

12. (a) Quarter Quarter NE / NW 12. (b) Section

23 12. (c) Township

148N 12. (d) Range

94W Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

2 

## Previous Permit Actions

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

Facility Name on the Permit

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

Permit Number

Date of the Permit Action

Facility Name on the Permit

N/A

Permit Number

Date of the Permit Action

Facility Name on the Permit

N/A

Permit Number

Date of the Permit Action Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

3 

## Contact Information

Company Contact

Tony Lucero Title

HSE Coordinator

Mailing Address

US Bank Tower, Suite 220, 950

– 17 th Street, Denver, CO 80202

Ͳ 2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279

Ͳ 5500 Facsimile Number

(720) 279

Ͳ 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

Ͳ 3010 Facsimile Number

(720) 279

Ͳ 5550

Compliance Contact

Tony Lucero Title

HSE Coordinator

Mailing Address

US Bank Tower, Suite 220, 950

– 17 th Street, Denver, CO 80202

Ͳ 2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279

Ͳ 5500 Facsimile Number

(720) 279

Ͳ 5550Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

4 

## Facility Process Description

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

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

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

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

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

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

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

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

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

process are described below:

High

Ͳ 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 natural gas components off

Ͳ 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 water component of the recovered fluids in the heater/treater

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

temporarily stored in these on

Ͳ site containers prior to being transferred to the lease automatic custody transfer

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

Saline Water

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

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

tank(s). Recovered water is temporarily stored on

Ͳ site prior to being loaded into tanker trucks for transport and

disposal.

Low

Ͳ 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

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

Ͳ site oil storage tanks. This natural

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

additional, low

Ͳ 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 pump(s) that is used to return fluid from the above ground oil and water storage

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

processing.

Upset Conditions

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

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

sales line. In these instances, the high

Ͳ pressure natural gas will be routed to a ground pit flare capable of 90%

destruction removal efficiency.Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

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:Hilo/Kona6WaterTankVaporsProducedGas[UPSET]Separator&Heater/TreaterOilTankOilTankOilTankWaterTankRecyclePumpOil/WaterRecycleSeparator&Heater/TreaterOilWaterRecyclePumpOilTankOilTankOilTankWaterTankOil/WaterRecycleLeaseAutomaticCustodyTransferUnitTankVaporsTwoWellFacility–PipelinewithNoVRU98%LowͲPressureGasCombustionDevice90% DestructionRemovalEfficientPitFlareSalesGasPipeline

Tank VaporsFacilityPerimeterWellheadPumpjackOil/Gas/Water Oil/Gas/WaterPumpjackWellheadProcessFlowDiagram(typ.)Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

7 

## Type and Quantity of Fuels

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

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

Equipment Fuel Type Sulfur

Content Max. Hourly Daily Annual

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

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

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

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

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

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

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

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

approximately 1,020 British thermal units per standard cubic foot (Btu/scf) (AP

Ͳ 42, Vol. I, Ch 1.4: Natural Gas

Combustion).

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

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

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

1,020 Btu/scf (AP

Ͳ 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 proposed engines are included in

Attachment G.

# Attachment A

Emission Units and Air Pollution

Ͳ Generating Activities Facility Name Hawaii/Maui FacilityEmitting Unit:Emitting Unit:Unit Type:Unit Type:Max Rated Design Capacity/Throughput: MaxRated Design Capacity/Throughput:Emitting Unit:Emitting Unit:Unit Type:Unit Type:Max Rated Design Capacity/Throughput: MaxRated Design Capacity/Throughput:Emitting Unit:Emitting Unit:Unit Type:Unit Type:Max Rated Design Capacity/Throughput: MaxRated Design Capacity/Throughput:145 kW (194HP)/eachRecycle Pump (x2)Honda Brand or Equivalent8 HP/eachSivallis Brand or EquivalentGenerator (x2)Newage UCI274G or Equivalent400 bbl/eachTruck Loading500,000 Btu/each25 HPKohler Brand or EquivalentSee LACT emittingunit descriptionLACT Pump (Electric - Generator)N/A - sent through LACTOil/Condensate Tanks (x10)Welded SteelHeater Treater Burner(x2)

# Attachment B

Proposed Emission Controls, Control Efficiencies, Emission Limits and Monitoring Facility Name Hilo/Kona FacilityEmission Control Type Emission Control TypeEfficiency:Efficiency:Max Rated Design Capacity/Throughput: MaxRated Design Capacity/Throughput:Size:Size:Monitoring:Monitoring:Note: Manufacturer specifications and guarantees are appended to this permit.Continuous Pilot FlameN/A98%100%Enclosed Smokeless CombustorConnected to Sales Line148 mscf/d to 296 mscf/dN/ASize of combustor will be selectedbased on volume of actual throughtput.N/A

# Attachment C

Criteria Pollutant and GHG Emission Estimates Facility:Hilo/Kona FacilityPTE SYN PTE SYN PTE SYN PTE SYNOil/Condensate Tanks 575.07 11.50 5.34 0.11 2.40 2.40 13.05 13.05 N/A N/A N/A N/A N/ATreater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 N/A 0.00 N/A N/ATreater Burner 0.02 0.02 N/A N/A 0.30 0.30 0.26 0.26 N/A N/A N/A 0.02 N/ARICE Engine 2.62 2.62 N/A N/A 3.75 3.75 7.49 7.49 N/A N/A N/A N/A N/ATruck Loading 0.00 0.00 N/A N/APneumatic Pump 0.00 0.00 0.00 0.00Pneumatic Controllers 0.00 0.00 0.00 0.00Glycol Dehydrator 0.00 0.00 0.00 0.00Totals (TPY)577.71 14.14 5.34 0.11 6.45 6.45 20.80 20.80 0.00 0.00 0.00 0.02 0.00PTE SYN PTE SYN PTE SYN PTE SYNOil/Condensate Tanks 25.59 4,407.47 357.53 7.15 0.12 0.00 8,284.55 4,572.65Treater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Treater Burner 365.25 365.25 0.03 0.03 0.01 0.01 367.63 367.63RICE Engine 1,911.08 1,911.08 0.00 0.00 0.00 0.00 1,911.08 1,911.08Totals (TPY)2,301.93 6,683.81 357.56 7.18 0.13 0.01 10,563.27 6,851.37PTE SYN PTE SYN PTE SYN PTE SYNOil/Condensate Tanks 2.59 0.05 1.22 0.02 1.01 0.02 0.00 0.00Treater Flare 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Totals (TPY)2.59 0.05 1.22 0.02 1.01 0.02 0.00 0.00Notes:aPb, HFCs, PFCs, and SF6 are not created from standard O&G production operations.bNo sulfur has been detected in Enerplus wells at this time.N2OCO2eGreen House Gases PTE (TPY)Emission SummaryEnerplus Resources (USA) Corporation*PTE column reflects emissions without controls. SYN column reflects post-control emission limits requested under this synthetic minor permit.Emission SourcePTE (TPY)VOCHAPCONOxbH2SbH2SO4bSO2PM 10PM 2.5Emission SourceCO2CH4Emission SourceHAP BreakdownBenzeneTolueneXylenes2,2,4 Trimethylpentane

# Attachment D

Criteria Pollutant and GHG Emission Supporting DocumentationGREEN= Requires inputRED= No input required. Thisis a calculated value.Facility InformationLine 1Hilo/Kona FacilityName of the facility and the well number.Line 210/1/2011Submittal Date.Production Data DescriptionLine 3BOPD3,024Average daily production in barrels of oil per day (BOPD).Line 4Mscfd2,280Average daily production of gas in Mscf per day.Line 5Decline Factor0.46Expected decline factor for the first year of operation.Decline factor calculated from Enerplus wells operating in the Bakken formation with greater than 1 yearof production data - see criteria pollutant emission supporting documentation.Line 6Adjusted BOPD1391.058This is the calculated BOPD expected to be produced using the above entered decline factor.Line 7Adjusted Treater Gas (Mscfd)1048.8This is the calculated mcfd of gas the well is expected to produce using the above entered decline factor.Oil/Condensate Tank Data DescriptionLine 81EF scf/bbl calculation method.Line 9EF scf/bbl97.91The scf/bbl from direct measurement or representative sample.EF value of 97.91 scf/bbl calculated by the Bakken VOC task force - see criteria pollutantemission supporting documentation.Line 10Estimated Tank Vapors (scfd)136198.5This is the estimated scfd of tank vapors based on the following: adjusted BOPD multiplied by the scf/bbl entered on Line 9.Line 11Lower Heating Value1,418.50Lower heating value (Btu/scf) of tank vapors.Estimated from E&P Tank V2 Emission Summary.Line 12Molecular Weight26.03Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole).Estimated from E&P Tank V2 Emission Summary.Line 13VOC%33.69%VOC weight fraction of the tank vapor gas (C3+).Estimated from E&P Tank V2 Emission Summary.Line 14HAP%0.31%HAP weight fraction of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 15CO2%0.45%CO2mole fraction of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 16CH4%33.99%CH4weight fraction of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 17H2S weight %0.000%H2S weight percent of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 18H2S mole %0.000%H2S mole percent of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 193Use the drop down menu to choose the appropriate emission control type.Line 20Control Destruction Efficiency98%Control efficiency of applied control technology.Treater Gas Data DescriptionLine 21Btu/scf1,473.10Btu/scf of well stream gas.Line 22Molecular Weight26.97Average molecular weight of the well stream gas in lb/lb-mole.Line 23Specific Gravity0.931If necessary to convert specific gravity to molecular weight, enter the specific gravity of the well stream gas.Line 24Calculated Molecular Weight26.97This is the calculated molecular weight based on the specificgravity entered above. Please enter this number on Line 24.Line 25VOC%37.77%VOC weight fraction of the well stream gas (Note: Weight%, not Mole%).Value from lab gas analysis report - see criteria pollutant emission supportingdocumentation.Line 26HAP%4.49%HAP weight fraction of the well stream gas. (Note: Weight%, not Mole%).Value from lab gas analysis report - see criteria pollutant emission supportingdocumentation.Line 27H2S weight %0.000%H2S weight percent of the well stream gas.Value from lab gas analysis report - see criteria pollutant emission supporting documentation.Line 28H2S mole %0.000%H2S mole percent of the well stream gas.Value from lab gas analysis report - see criteria pollutant emission supporting documentation.Line 294Use the drop down menu to choose the appropriate emission control type.Line 30Control Destruction Efficiency100%Control efficiency of applied control technology.Utility Flare or Other 98% DRE DeviceConnected to Sales LineDefault Bakken EFGREEN= Requires inputRED= No input required. Thisis a calculated value.Facility InformationLine 1Hilo/Kona FacilityName of the facility and the well number.Line 210/1/2011Submittal Date.Treater Burner(s) DescriptionLine 32Total Btu/hr1,000,000Total burner rating for the heater treater burner(s) in btu/hr. If there are multiple burners,add the total heat input together.Line 33Hours of Operation8,760The burner(s) is/are assumed to operate 8,760 hours per year.Truck Loading DescriptionLine 3421Use the drop down menu to choose the appropriate oil sales method. If oil is sold through a LACT, no input values are requiredin Lines 35-40.Line 35 20Use the drop down list to choose the appropriate mode of operation.The saturation factor will automatically be selected basedon mode of operation.Line 36Molecular Weight0.00Molecular weight of tank vapors in lb/lb-mole.From AP-42 refer to Table 2 on the Truck Loading tab.Line 37Vapor Pressure0.00True 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 38Temperature0.00Temperature of bulk liquid loaded in Fahrenheit.Estimated average annual temperature.Line 39Load Rate (bbl/hr)0Load rate of liquid loaded in barrels per hour.Line 40Load Time (hrs)0.00The time it takes to loadout one load (hrs).Pneumatic Pumps DescriptionLine 41Number of Pneumatic Pumps0Number of pneumatic pumps at facility.Line 42Hours of Operation8,760Hours the pump is in operation annually.Line 43scf/min0.50Pneumatic source consumption rateas per manufacturer data (scf/min).Line 44 1Use the drop down menu to choose the appropriate emission control type.Line 45Control Efficiency100%Control efficiency of applied control technology.Pneumatic Controllers DescriptionLine 46Number of Pneumatic Controllers0Number of pneumatic controllers at facility.Line 47Bleed rate (scf/hr)0.00Average bleed rate of device (scf/hr).Glycol Dehydrator DescriptionLine 48VOC (TPY)0.00VOC emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).Not applicable to this facility.Line 49HAP (TPY)0.00HAP emissions calculated in GRI-GLYCalc software (if no glycol dehydrator enter 0).Not applicable to this facility.Oil is sold through LACTSubmerged loading of a clean cargo tankRouted exhaust back into closed loop systemscf/dayBtu/scflb/lb-moleHAP wt FractionCO2mole FractionCH4wt FractionControlled emissions are calculated based on a destruction efficiency of the VOC gas.VOC: 5,675scf/hr x 0.002638522 lb-mole/scf x 26.03 lb/lb-mole x 33.69% =131.29lb/hr131.29lb/hr x 8,760 hr/yr x 0.0005 ton/lb =575.07TPYHAP: 5,675scf/hr x 0.002638522 lb-mole/scf x 26.03 lb/lb-mole x 0.31% =1.22lb/hr1.22lb/hr x 8,760 hr/yr x 0.0005 ton/lb =5.34TPYAP-42Table 13.5-1aNOx: 5,675scf/hr x1,419Btu/scfx1E-06 MMBtu/ Btux 0.068 =0.55lb/hr0.55lb/hrx 8,760 hr/yr x 0.0005 ton/lb =2.40TPYHilo/Kona FacilityOil/Condensate TanksFlare Gas Volume136,199Lower Heating Value1418.5Molecular Weight26.03VOC wt Fraction33.69%0.31%98%0.45%33.99%AP-42Table 13.5-1aCO: 5,675scf/hr x1,419Btu/scfx1E-06 MMBtu/ Btux 0.370 =2.98lb/hr2.98lb/hrx 8,760 hr/yr x 0.0005 ton/lb =13.05TPYE&P TankV2 Em.Summaryb∑(Yj* Rj)cCO2:5,675scf/hr x 0.451% +0.98x5,675scf/hr x1.55 = 8665.70scf/hr8665.70scf/hr x 0.0026 lb-mole/scf x 44.01 lb/lb-mole =1006.27lb/hr1006.27lb/hrx 8,760 hr/yr x 0.0005 ton/lb =4407.47TPYE&P TankV2 Em.SummarybCH4:5,675scf/hr x 0.002638522 lb-mole/scf x 16.04 lb/lb-mole x 33.99% =81.63lb/hr81.63lb/hrx 8,760 hr/yr x 0.0005 ton/lb =357.53TPYN2O:5,675scf/hr x 2.2 lb/MMscf x1E-06 Mmscf/ scf=0.01lb/hr0.01kg/hrx 2.2046 lbs/kg x 8,760 hr/yr x 0.0005 ton/lb =0.12TPYNotes:aNOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.575.07VOC TPYcCO2calculated from Subpart W, Eq. W-20 and W-21.11.50VOC TPYControlled5.34 HAP TPY Uncontrolled0.11 HAP TPY Controlled2.40NOx TPY13.05 CO TPY25.59CO2TPYUncontrolled4,407.47CO2TPYControlled357.53CH4TPYUncontrolled7.15CH4TPYControlled0.12N2OTPYUncontrolled0.00N2OTPYControlledUncontrolledbCO2and CH4percent weight are from E&P Tank V2 Emission Summary.TOTALSAP-42 Table 1.4-2HAP: 5,675scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.31% =1.22lb/hr1.22lb/hr x 8,760 hr/yr x 0.0005 ton/lb =5.34TPYBenzene: 5,675scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.15% =0.59lb/hr0.59lb/hr x 8,760 hr/yr x 0.0005 ton/lb =2.59TPYToluene: 5,675scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.07% =0.28lb/hr0.28lb/hr x 8,760 hr/yr x 0.0005 ton/lb =1.22TPYXylenes: 5,675scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.06% =0.23lb/hr0.23lb/hr x 8,760 hr/yr x 0.0005 ton/lb =1.01TPY2,2,4 Trimethylpentane: 5,675scf/hr x 0.002638522 scf/lb-mole x 26.03 lb/lb-mole x 0.00% =0.00lb/hr0.00lb/hr x 8,760 hr/yr x 0.0005 ton/lb =0.00TPYBenzene 2.59 TPY UncontrolledBenzene 0.05 TPY ControlledToluene 1.22 TPY UncontrolledToluene 0.02 TPY ControlledXylenes 1.01 TPY UncontrolledXylenes 0.02 TPY Controlled2,2,4 Trimethylpentane 0.00 TPY Uncontrolled2,2,4 Trimethylpentane 0.00 TPY ControlledTOTALSHilo/Kona FacilityOil/Condensate TanksHAP Emission BreakdownscfdBtu/scflb/lb-moleHAP wt fractionControlled emissions are calculated based on a destruction efficiency of the VOC gas.VOC: 43,700scf/hrx 0.002638522 lb-mole/scf x 26.965884lb/lb-molex 37.77% =1174.44lb/hr1174.44lb/hr x8760hr/yrx 0.0005 ton/lb =5144.03TPY UncontrolledHAP 43,700scf/hrx 0.002638522 lb-mole/scf x 26.965884lb/lb-molex 4.49% =139.64lb/hr139.64lb/hr x8760hr/yrx 0.0005 ton/lb =611.61TPY UncontrolledH2S43,700scf/hrx 0.002638522 lb-mole/scf x 26.965884lb/lb-molex 0.00% =0.00lb/hr0.00lb/hr x8760hr/yrx 0.0005 ton/lb =0.00TPY UncontrolledSO243,700scf/hrx 0.002638522 lb-mole/scf x 26.97lb/lb-molex0.00%=0.00lb/hr0.00lb/hr x8760hr/yrx 0.0005 ton/lb =0.00TPY UncontrolledAP-42 Table13.5-1aNOx: 43,700scf/hrx1,473Btu/scf x0.000001 Mmbtu/ Btux 0.068lb/MMBtu=4.38lb/hr4.38lb/hrx8760hr/yrx 0.0005 ton/lb =19.17TPYAvg. Molecular Weight26.97VOC wt fraction37.77%4.49%100%Hilo/Kona FacilityTreater FlareFlare Gas Volume1,048,800Lower Heating Value1473.1AP-42 Table13.5-1aCO: 43,700scf/hrx1,473Btu/scf x0.000001 Mmbtu/ Btux 0.370lb/MMBtu=23.82lb/hr23.82lb/hrx8760hr/yrx 0.0005 ton/lb =104.33TPYTreaterGas AnalysisSummaryb∑(Yj* Rj)dCO2:43,700scf/hr x 0.440% +0.98x43,700scf/hr x1.56 = 67012.40scf/hr43,700scf/hr x 0.0026385 scf/lb-mole x 44.01 lb/lb-mole =5074.50lb/hr5074.50lb/hrx 8760 hr/yr x 0.0005 ton/lb =22226.33TPYCH4:43,700scf/hr x 1473.1 Btu/scf x0.000001 Mmbtu/ Btux 0.0009kg/MMBtu=0.06kg/hr0.06kg/hrx 2.2046 lbs/kg x 8760 hr/yr x 0.0005 ton/lb =0.56TPYN2O:43,700scf/hr x 1473.1 Btu/scf x0.000001 Mmbtu/ Btux 0.0001kg/MMBtu=0.01lb/hr0.01kg/hrx 2.2046 lbs/kg x 8760 hr/yr x 0.0005 ton/lb =0.06TPYNotes:H2S and SO2emissions are not typical for wells in the Bakken formation and areNOTE: No emissions because source is routed directly to sales line.therefore not calculated herein.0.00VOC TPYaNOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.0.00VOC TPYControlleddCO2calculated from Subpart W, Eq. W-20 and W-21.0.00 HAP TPY Uncontrolled0.00 HAP TPY Controlled0.00H2STPY Uncontrolled0.00H2STPY Controlled0.00SO2TPY Uncontrolled0.00NOx TPY0.00CO TPY0.00CO2TPYUncontrolled0.00CO2TPYControlled0.00CH4TPY Uncontrolled0.00CH4TPY Controlled0.00N2OTPY Uncontrolled0.00N2OTPY ControlledSubpart WcSubpart WccCH4and N2O emission factors are from Subpart W, Table C-3.TOTALSUncontrolledbCO2percent weight is from Treater Gas Analysis.HAP 43,700scf/hrx 0.002638522 lb-mole/scf x 26.97lb/lb-molex 4.49% =139.64lb/hr139.64lb/hr x8760hr/yrx 0.0005 ton/lb =611.61TPY UncontrolledBenzene: 43,700scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.27% =39.46lb/hr39.46lb/hr x 8760 hr/yr x 0.0005 ton/lb =172.83TPYToluene: 43,700scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.50% =46.55lb/hr46.55lb/hr x 8760 hr/yr x 0.0005 ton/lb =203.87TPYXylenes: 43,700scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 1.72% =53.63lb/hr53.63lb/hr x 8760 hr/yr x 0.0005 ton/lb =234.91TPY2,2,4 Trimethylpentane: 43,700scf/hr x 0.002638522 scf/lb-mole x 26.97 lb/lb-mole x 0.00% =0.00lb/hr0.00lb/hr x 8760 hr/yr x 0.0005 ton/lb =0.00TPYTOTALS Benzene 0.00 TPY UncontrolledBenzene 0.00 TPY ControlledToluene 0.00 TPY UncontrolledToluene 0.00 TPY ControlledXylenes 0.00 TPY UncontrolledXylenes 0.00 TPY Controlled2,2,4 Trimethylpentane 0.00 TPY Uncontrolled2,2,4 Trimethylpentane 0.00 TPY ControlledTreater FlareHAP Emission BreakdownHilo/Kona Facility1,000,000Btu/hrAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeating Value(Btu/scf)Sample GasHeatingValue(Btu/scf)NOx:1.000 MMBtu/hr x 100.00 / 1020.00 x 1020.00 / 1439.00 =0.07lb/hr0.07 lb/hr x 0.0005 ton/lb x 8760 hr/yr =0.30TPYAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeating Value(Btu/scf)Sample GasHeatingValue(Btu/scf)CO:1.000 MMBtu/hr x 84.00 / 1020.00 x 1020.00 / 1439.00 =0.06lb/hr0.06 lb/hr x 0.0005 ton/lb x 8760 hr/yr =0.26TPYAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeating Value(Btu/scf)Sample GasHeatingValue(Btu/scf)VOC:1.000 MMBtu/hr x 5.50 / 1020.00 x 1020.00 / 1439.00 =0.00lb/hr0.00 lb/hr x 0.0005 ton/lb x 8760 hr/yr =0.02TPYAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeating Value(Btu/scf)Sample GasHeatingValue(Btu/scf)PM 10:1.000 MMBtu/hr x 7.60 / 1020.00 x 1020.00 / 1439.00 =0.01lb/hr0.01 lb/hr x 0.0005 ton/lb x 8760 hr/yr =0.02TPYBurner RatingHeater Treater BurnerHilo/Kona FacilityHeater Treater BurnerHilo/Kona FacilityAP-42 Table1.4-2EFb(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeating Value(Btu/scf)Sample GasHeatingValue(Btu/scf)CO2:1.000 MMBtu/hr x 120,000 / 1020.00x1020.00 / 1439.00 =83.39lb/hr83.39 lb/hr x 0.0005 ton/lb x 8760 hr/yr =365.25TPYSubpart Wc(kg/MMBtu)CH4:1.000 MMBtu/hr x 0.003 =0.00kg/hrlb/kg0.00 kg/hr x 2.205 x 0.0005 ton/lb x 8760 hr/yr =0.03TPYSubpart Wc(kg/MMBtu)N2O:1.000 MMBtu/hr x 0.0006 =0.00kg/hrlb/kg0.00 kg/hr x 2.205 x 0.0005 ton/lb x 8760 hr/yr =0.01TPYNotes:aNOx, CO, VOC, PM10emission factors are from AP-42 Table 1.4-1,Emission Factors for Criteria Pollutants and Greenhouse Gases from Natural Gas Combustion.bCO2emission factor from AP-42 Table 1.4-2, Emission Factors forcriteria Pollutant and Greenhouse Gases from Natural Gas Combustion.cCH4and N2O emission factors are from Subpart W, Table C-3.0.02VOC TPY0.30NOx TPY0.26CO TPY365.25CO2TPY0.03CH4TPY0.01N2O TPYTOTALSSaturation Vapor Molecular Temp + Load Loss

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

12.46 x 0.00 x 0.00 x 0.00 / 460.00

= 0.00

LL Truck Load Load Time

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

0.00 x 0.00 / 0.00 x 42.00

= 0.00

LL Annual Emissions

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

0.00 x 507736.32 x 42.00 / 2000.00

= 0.00 0.00

VOC

Emissions

Uncontrolled Control % TPY

0.00 100.00% 0.00 0.00

S Factor

Petroleum Vapor MW

Liquid at 60F

Mv(lb/lb-mole)

40 50 60 70 80 90 100

Crude Oil

RVP 5 Tank Trucks and Rail Tank Cars Submerged loading of a clean cargo tank 0.50 

### Hilo/Kona Facility



## Truck Loadout Emission Calculation

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

Cargo Carrier Mode of Operation

Condensed Liquid

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

at 60F at 60F Submerged loading: dedicated normal service 0.60

Submerged loading: dedicated vapor balance service 1.00

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

Wvc(lb/gal W1(lb/gal)

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

PSCR = Pneumatic Source Consum ption Rate (scf/min), as per manufacture rs 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 Hilo/Kona Facility



### Emissions from Pneumatic Pumps

Emissions (lb/hr) = PSCR (scf/min) x (60 min/1hr) x (1/3 79 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 Hilo/Kona Facility



### Emissions from Pneumatic Controllers

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

Emissions (TPY) = (lb/hr VOC) x (8760 hr/yr) x (1 ton/2000)Line1Number of Engines4RICE Engine #1Line 2Hours of Operation8,760Line 3Maximum HP Rating194Line 4NOx g/hp-hr1Line 5CO g/hp-hr2Line 6VOC g/hp-hr0.7Line 7N2O g/hp-hr0.0006Line 8CO2g/hp-hr1.08Line 9CH4g/hp-hr0.003Line 10NOx Control Efficiency0%Line 11CO Control Efficiency0%Line 12VOC Control Efficiency0%RICE Engine #2Line 13Hours of Operation8,760Line 14Maximum HP Rating8Line 15NOx g/hp-hr0.011Line 16CO g/hp-hr0.00696Line 17VOC g/hp-hr0.015Line 18N2O g/hp-hr0.0006Line 19CO2g/hp-hr1.08Line 20CH4g/hp-hr0.003Line 21NOx Control Efficiency0%Line 22CO Control Efficiency0%Line 23VOC Control Efficiency0%RICE Engine #3Line 24Hours of Operation8,760Line 25Maximum HP Rating8Line 26NOx g/hp-hr0.011Line 27CO g/hp-hr0.007Line 28VOC g/hp-hr0.015Line 29N2O g/hp-hr0.0006Line 30CO2g/hp-hr1.08Line 31CH4g/hp-hr0.003Line 32NOx Control Efficiency0%Line 33CO Control Efficiency0%Line 34VOC Control Efficiency0%RICE Input DataManufacturer's maximum hp rating.DescriptionEngine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Enter the number of engines that will be installed at the production facility.DescriptionEngine 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 CO2.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or 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 AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst,AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.VOC control efficiency of any applicable controls (NSCR catalyst,AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst,AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.VOC control efficiency of any applicable controls (NSCR catalyst,AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.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.DescriptionEngine is assumed to operate 8,760 hours per year.RICE Input DataRICE Engine #4Line 35Hours of Operation8,760Line 36Maximum HP Rating194Line 37NOx g/hp-hr1Line 38CO g/hp-hr2Line 39VOC g/hp-hr0.7Line 40N2O g/hp-hr0.0006Line 41CO2g/hp-hr1.08Line 42CH4g/hp-hr0.003Line 43NOx Control Efficiency0%Line 44CO Control Efficiency0%Line 45VOC Control Efficiency0%RICE Engine #5Line 46Hours of Operation0Line 47Maximum HP Rating100Line 48NOx g/hp-hr10Line 49CO g/hp-hr5Line 50VOC g/hp-hr4Line 51N2O g/hp-hr0.0006Line 52CO2g/hp-hr1.08Line 53CH4g/hp-hr0.003Line 54NOx Control Efficiency0%Line 55CO Control Efficiency0%Line 56VOC Control Efficiency0%Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).DescriptionEngine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).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.DescriptionEngine is assumed to operate 8,760 hours per year.Manufacturer's maximum hp rating.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.ENGINE #1194 MAX HP0%NOx DRE0%CO DRE0%VOC DRENOx:1.00g/HP-HR194HP x 0.002204586 lb / grams =0.43lb/hr x8760hr/yr x 0.0005 ton/lb = 1.87 NOx TPY Uncontrolled1.87 NOx TPY ControlledCO:2.00g/HP-HR194HP x 0.002204586 lb / grams =0.86lb/hr x8760hr/yr x 0.0005 ton/lb = 3.75 CO TPY Uncontrolled3.75 CO TPY ControlledVOC:0.70g/HP-HR194HP x 0.002204586 lb / grams=0.30lb/hr x8760hr/yr x 0.0005 ton/lb = 1.31 VOC TPY Uncontrolled1.31 VOC TPY ControlledN2O:6.00E-04kg/mmBtu 3.9E-07 x194HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00N2O TPY UncontrolledCO2:1.08lb/HP-HR194HP =209.52lb/hr x8760hr/yr x 0.0005 ton/lb = 917.70CO2TPY UncontrolledCH4:3.00E-03kg/mmBtu 3.9E-07 x194HP x 0.002204586 lb / grams=0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00CH4TPY UncontrolledENGINE #28 MAX HP0%NOx DRE0%CO DRE0%VOC DRENOx:0.01b/HP-HR8HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00 NOx TPY Uncontrolled0.00 NOx TPY ControlledCO:0.01lb/HP-HR8HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00 CO TPY Uncontrolled0.00 CO TPY ControlledVOC:0.02lb/HP-HR8HP x 0.002204586 lb / grams=0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00 VOC TPY Uncontrolled0.00 VOC TPY ControlledN2O:6.00E-04kg/mmBtu 3.9E-078HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00N2O TPY UncontrolledCO2:1.08lb/HP-HR8HP =8.64lb/hr x8760hr/yr x 0.0005 ton/lb = 37.84CO2TPY UncontrolledCH4:3.00E-03kg/mmBtu 3.9E-078HP x 0.002204586 lb / grams=0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00CH4TPY UncontrolledSubpart W, Table C-3bSubpart W, Table C-3bxxxxg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrxxxxxxxg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrSubpart W, Table C-3bSubpart W, Table C-3bHilo/Kona FacilityReciprocating Engine EmissionsxAP-42, Table 3.3-1aAP-42, Table 3.3-1aHilo/Kona FacilityReciprocating Engine EmissionsENGINE #38 MAX HP0%NOx DRE0%CO DRE0%VOC DRENOx:0.01lb/HP-HR8HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00 NOx TPY Uncontrolled0.00 NOx TPY ControlledCO:0.01lb/HP-HR8HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00 CO TPY Uncontrolled0.00 CO TPY ControlledVOC:0.02lb/HP-HR8HP x 0.002204586 lb / grams=0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00 VOC TPY Uncontrolled0.00 VOC TPY ControlledN2O:6.00E-04kg/mmBtu 3.9E-078HP x 0.002204586 lb / grams =4.16E-12lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00N2O TPY UncontrolledCO2:1.08lb/HP-HR8HP =8.64lb/hr x8760hr/yr x 0.0005 ton/lb = 37.84CO2TPY UncontrolledCH4:3.00E-03kg/mmBtu 3.9E-078HP x 0.002204586 lb / grams=0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00CH4TPY UncontrolledENGINE #4194 MAX HP0% NOx DRE0%CO DRE0%VOC DRENOx:1.00lb/HP-HR194HP x 0.002204586 lb / grams =0.43lb/hr x8760hr/yr x 0.0005 ton/lb = 1.87 NOx TPY Uncontrolled1.87 NOx TPY ControlledCO:2.00lb/HP-HR194HP x 0.002204586 lb / grams =0.86lb/hr x8760hr/yr x 0.0005 ton/lb = 3.75 CO TPY Uncontrolled3.75 CO TPY ControlledVOC:0.70lb/HP-HR194HP x 0.002204586 lb / grams=0.30lb/hr x8760hr/yr x 0.0005 ton/lb = 1.31 VOC TPY Uncontrolled1.31 VOC TPY ControlledN2O:6.00E-04kg/mmBtu 3.9E-07194HP x 0.002204586 lb / grams =0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00N2O TPY UncontrolledCO2:1.08lb/HP-HR194HP =209.52lb/hr x8760hr/yr x 0.0005 ton/lb = 917.70CO2TPY UncontrolledCH4:3.00E-03kg/mmBtu 3.9E-07194HP x 0.002204586 lb / grams=0.00lb/hr x8760hr/yr x 0.0005 ton/lb = 0.00CH4TPY UncontrolledSubpart W, Table C-3bSubpart W, Table C-3bg-mmBtu/kg-hp-hrxxxxg-mmBtu/kg-hp-hrxxxxxxSubpart W, Table C-3bSubpart W, Table C-3bg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrAP-42, Table 3.3-1aAP-42, Table 3.3-1axxHilo/Kona FacilityReciprocating Engine EmissionsENGINE #5100 MAX HP0%NOx DRE0%CO DRE0%VOC DRENOx:10.00lb/HP-HR100HP x 0.002204586 lb / grams =2.20lb/hr x0hr/yr x 0.0005 ton/lb = 0.00 NOx TPY Uncontrolled0.00 NOx TPY ControlledCO:5.00lb/HP-HR100HP x 0.002204586 lb / grams =1.10lb/hr x0hr/yr x 0.0005 ton/lb = 0.00 CO TPY Uncontrolled0.00 CO TPY ControlledVOC:4.00lb/HP-HR100HP x 0.002204586 lb / grams=0.88lb/hr x0hr/yr x 0.0005 ton/lb = 0.00 VOC TPY Uncontrolled0.00 VOC TPY ControlledN2O:6.00E-04kg/mmBtu 3.9E-07100HP x 0.002204586 lb / grams =0.00lb/hr x0hr/yr x 0.0005 ton/lb = 0.00N2O TPY UncontrolledCO2:1.08lb/HP-HR100HP =108.00lb/hr x0hr/yr x 0.0005 ton/lb = 0.00CO2TPY UncontrolledCH4:3.00E-03kg/mmBtu 3.9E-07100HP x 0.002204586 lb / grams=0.00lb/hr x0hr/yr x 0.0005 ton/lb = 0.00CH4TPY UncontrolledNotes:aCO2Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines (lb/hp-hr) from AP-42 Table 3.3-1, Gasoline Fuel.bCH4and N2O Subpart W, Table C-3 of Subpart C - Default CH4and N2O Emission Factors for Various Types of Fuel.3.75 NOx TPY Uncontrolled3.75NOx TPY Controlled7.49 CO TPY Uncontrolled7.49 CO TPY Controlled2.62 VOC TPY Uncontrolled2.62 VOC TPY Controlled0.00N2O TPY1911.08CO2TPY0.00CH4TPYSubpart W, Table C-3bSubpart W, Table C-3bg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrTOTALSAP-42, Table 3.3-1axxxxxxGas AnalysisMolePercent1MoleFractionMolecularWeightMWComponentWt FractionVOCComponentMWHAPComponentMWOxygen 0.000 0.000 32 0 0Nitrogen 6.829 0.068 28.01 1.9128029 0.070549836Carbon Dioxide 0.440 0.004 44.01 0.193644 0.007142164H2S 0.000 0.000 34.08 0 0Methane 53.554 0.536 16.04 8.5900616 0.316826913Ethane 20.536 0.205 30.07 6.1751752 0.227758751Propane10.970 0.110 44.097 4.8374409 0.178419148 0.863092082i-Butane1.305 0.013 58.12 0.758466 0.027974472 0.021217686n-Butane2.392 0.024 58.12 1.3902304 0.051275815 0.071285196i-Pentane0.524 0.005 72.15 0.378066 0.013944194 0.005271826n-Pentane1.688 0.017 72.15 1.217892 0.044919464 0.054707056Hexanes+0.441 0.004 100.2 0.441381 0.016279439 0.007185435Benzene20.441 0.004 78.11 0.344074550.012690488 0.004366474 0.004366474Toluene20.441 0.004 92.14 0.40587670.014969935 0.006075948 0.006075948Xylenes20.441 0.004 106.17 0.467678850.017249381 0.008067171 0.0080671712,2,4 Trimethylpentane0.000 0.000 114.23 0 0 0 0Total100.00 1.0027.11 1.04 0.02VOC Weight Fraction 0.38HAP Weight Fraction 0.04VOC Weight %3.84HAP Weight %0.07Notes:Bold Items are considered VOCs.1Mole Percent averaged from three attached Stock Tank Gas Samples.2Averaged mole % from Hexanes+, no extended gas analysis available at this time.Treater Gas Analysis WorksheetGas AnalysisMolePercent1MoleFractionMolecularWeightMWComponentWt Fraction VOC Wt. Fraction HAP Wt. FractionVOC ComponentMWHAP ComponentMWOxygen 0.000 0.000 32 0 0Nitrogen 7.081 0.071 28.01 1.98324805 0.075900023Carbon Dioxide 0.451 0.005 44.01 0.1984851 0.007596137H2S 0.000 0.000 34.08 0 0Methane 55.367 0.554 16.04 8.8807866 0.339872719Ethane 20.835 0.208 30.07 6.26520478 0.239772926Propane10.532 0.105 44.097 4.644119652 0.177733082 0.177733082 0.8254137i-Butane1.114 0.011 58.12 0.64722432 0.02476964 0.02476964 0.016031514n-Butane1.897 0.019 58.12 1.1025364 0.042194691 0.042194691 0.046521182i-Pentane0.294 0.003 72.15 0.2118324 0.008106946 0.008106946 0.001717314n-Pentane0.813 0.008 72.15 0.5862909 0.022437684 0.022437684 0.01315501Hexanes+1.525 0.015 100.2 1.5283506 0.058490841 0.058490841 0.089394511Benzene0.051 0.001 78.11 0.03960177 0.001515582 0.001515582 0.001515582 6.00197E-05 6.00197E-05Toluene0.020 0.000 92.14 0.01870442 0.000715829 0.000715829 0.000715829 1.33892E-05 1.33892E-05Ethylbenzene0.0074 0.000 106.17 0.00785658 0.000300676 0.000300676 0.000300676 2.36228E-06 2.36228E-06Xylenes0.0146 0.000 106.17 0.01550082 0.000593225 0.000593225 0.000593225 9.19548E-06 9.19548E-06224 Trimethylpentane0.0000 0.000Total100.00 1.0026.13 0.34 0.00 0.99 0.00VOC Weight %3.80HAP Weight %0.00Notes:Bold Items are considered VOCs.1Mole Percent averaged from three attached Stock Tank Gas Samples.E&P Gas Analysis Worksheetfile:///Q|/Customer%20Records/Enerplus%20-%202390/Consulting/Envir...deral/NSR%20Permit%20Application/Template/Agave-Birdbear%2 0E&P.txt

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

* Project Setup Information *

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

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

Flowsheet Selection : Oil Tank with Separator

Calculation Method : RVP Distillation

Control Efficiency : 98.0%

Known Separator Stream : Low Pressure Oil

Entering Air Composition : No

Date : 2011.09.15

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

* Data Input *

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

Separator Pressure : 70.00[psig]

Separator Temperature : 100.00[F]

Ambient Pressure : 14.70[psia]

Ambient Temperature : 70.00[F]

C10+ SG : 0.8100

C10+ MW : 245.66

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

No. Component mol %

1 H2S 0.0000

2 O2 0.0000

3 CO2 0.4400

4 N2 6.8290

5 C1 53.5540

6 C2 20.5360

7 C3 10.9700

8 i-C4 1.3050

9 n-C4 2.3920

10 i-C5 0.5240

11 n-C5 1.6880

12 C6 1.7620

13 C7 7.7170

14 C8 8.0790

15 C9 5.0500

16 C10+ 43.4390

17 Benzene 0.3200

18 Toluene 0.4240

19 E-Benzene 0.4700

20 Xylenes 1.0810

21 n-C6 2.4160

22 224Trimethylp 0.0000

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

Production Rate : 3024[bbl/day]

Days of Annual Operation : 365 [days/year]

API Gravity : 42.3

Reid Vapor Pressure : 12.10[psia]

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

* Calculation Results *

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

file:///Q|/Customer%20Records/Enerplus%20-%202390/Con...ermit%20Application/Template/Agave-Birdbear%20E&P.txt (1 of 3)9/27/2011 8:00:37 AMfile:///Q|/Customer%20Records/Enerplus%20-%202390/Consulting/Envir...deral/NSR%20Permit%20Application/Template/Agave-Birdbear%2 0E&P.txt

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

Item Uncontrolled Uncontrolled Controlled Controlled

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

Total HAPs 455.060 103.895 9.101 2.078

Total HC 26128.656 5965.447 522.573 119.309

VOCs, C2+ 16397.605 3743.745 327.952 74.875

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

VOCs, C3+ 9533.850 2176.678 190.677 43.534

Uncontrolled Recovery Info.

Vapor 2.2800 x1E3 [MSCFD]

HC Vapor 2.1000 x1E3 [MSCFD]

GOR 753.97 [SCF/bbl]

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

No Component Uncontrolled Uncontrolled Controlled Controlled

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

1 H2S 0.000 0.000 0.000 0.000

2 O2 0.000 0.000 0.000 0.000

3 CO2 217.449 49.646 217.449 49.646

4 N2 2172.966 496.111 2172.966 496.111

5 C1 9731.052 2221.701 194.621 44.434

6 C2 6863.754 1567.067 137.275 31.341

7 C3 5087.797 1161.597 101.756 23.232

8 i-C4 709.107 161.897 14.182 3.238

9 n-C4 1207.952 275.788 24.159 5.516

10 i-C5 232.101 52.991 4.642 1.060

11 n-C5 642.338 146.653 12.847 2.933

12 C6 321.585 73.421 6.432 1.468

13 C7 597.310 136.372 11.946 2.727

14 C8 227.434 51.926 4.549 1.039

15 C9 53.069 12.116 1.061 0.242

16 C10+ 0.093 0.021 0.002 0.000

17 Benzene 43.372 9.902 0.867 0.198

18 Toluene 20.492 4.679 0.410 0.094

19 E-Benzene 8.558 1.954 0.171 0.039

20 Xylenes 17.011 3.884 0.340 0.078

21 n-C6 365.630 83.477 7.313 1.670

22 224Trimethylp 0.000 0.000 0.000 0.000

Total 28519.070 6511.203 570.381 130.224

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

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

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

1 H2S 34.80 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

2 O2 32.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

3 CO2 44.01 0.4400 0.0077 0.0077 0.4510 0.0000 0.4510

4 N2 28.01 6.8290 0.0121 0.0121 7.0805 0.0000 7.0805

5 C1 16.04 53.5540 0.3073 0.3073 55.3665 0.0000 55.3665

6 C2 30.07 20.5360 0.6422 0.6422 20.8354 0.0000 20.8354

7 C3 44.10 10.9700 1.1361 1.1361 10.5316 0.0000 10.5316

8 i-C4 58.12 1.3050 0.3197 0.3197 1.1136 0.0000 1.1136

9 n-C4 58.12 2.3920 0.7771 0.7771 1.8970 0.0000 1.8970

10 i-C5 72.15 0.5240 0.3318 0.3318 0.2936 0.0000 0.2936

11 n-C5 72.15 1.6880 1.2456 1.2456 0.8126 0.0000 0.8126

12 C6 86.16 1.7620 1.9614 1.9614 0.3495 0.0000 0.3495

13 C7 100.20 7.7170 9.8738 9.8738 0.5621 0.0000 0.5621

14 C8 114.23 8.0790 10.8690 10.8690 0.1870 0.0000 0.1870

15 C9 128.28 5.0500 6.8967 6.8967 0.0394 0.0000 0.0394

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16 C10+ 245.66 43.4390 59.7733 59.7733 0.0000 0.0000 0.0000

17 Benzene 78.11 0.3200 0.3731 0.3731 0.0507 0.0000 0.0507

18 Toluene 92.13 0.4240 0.5565 0.5565 0.0203 0.0000 0.0203

19 E-Benzene 106.17 0.4700 0.6370 0.6370 0.0074 0.0000 0.0074

20 Xylenes 106.17 1.0810 1.4681 1.4681 0.0146 0.0000 0.0146

21 n-C6 86.18 2.4160 2.8112 2.8112 0.3873 0.0000 0.3873

22 224Trimethylp 114.24 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

MW 95.17 186.80 186.80 26.03 0.00 26.03

Stream Mole Ratio 1.0000 0.4300 0.4300 0.5700 0.0000 0.5700

Heating Value [BTU/SCF] 1418.50 0.00 1418.50

Gas Gravity [Gas/Air] 0.90 0.00 0.90

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

RVP @ 100F [psia] 259.26 5.69 5.69

Spec. Gravity @ 100F 0.636 0.695 0.695

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## Decline Factor Supporting Documentation

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

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

.  The area under the line

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

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

BOX 1  BOX 2 

BOX 3  BOX 4 

The smoothed curve is straightened out in BOX 3

, and then leveled out in BOX 4

. Now the production for the

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

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

represented by the level line in BOX 4 after the first 30

Ͳ 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

Ͳ 12th Month of Production) / (1st Month of Production)

Decline Factor (facility

Ͳ 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 Factor for

the Formation= 0.459026

Burr

Prod_Month BOPD

Mar

Ͳ 09 6238

Apr

Ͳ 09 4092

May

Ͳ 09 4104

Jun

Ͳ 09 3552

Jul

Ͳ 09 3324

Aug

Ͳ 09 2854

Sep

Ͳ 09 2593

Oct

Ͳ 09 2414

Nov

Ͳ 09 2162

Dec

Ͳ 09 2151

Jan

Ͳ 10 2053

Feb

Ͳ 10 1775

Decline over the first 12

Ͳ months 0.715454

First Month's Production 6238

Last Month's Production 1775

Average BOPD 3109.333

Decline factor 0.49845

Four Bears

Dec

Ͳ 08 7473

Jan

Ͳ 09 3645

Feb

Ͳ 09 3873

Mar

Ͳ 09 4167

Apr

Ͳ 09 3148

May

Ͳ 09 3490

Jun

Ͳ 09 2820

Jul

Ͳ 09 2737

Aug

Ͳ 09 2444

Sep

Ͳ 09 2291

Oct

Ͳ 09 1778

Nov

Ͳ 09 2495

Decline over the first 12

Ͳ months 0.666131

First Month's Production 7473

Last Month's Production 2495

Average BOPD 3363.417

Decline factor 0.450076

Fredericks 5

Oct

Ͳ 08 11838

Nov

Ͳ 08 4545

Dec

Ͳ 08 5793

Jan

Ͳ 09 5012

Feb

Ͳ 09 3909

Mar

Ͳ 09 3706

Apr

Ͳ 09 3573

May

Ͳ 09 3334

Jun

Ͳ 09 3042

Jul

Ͳ 09 2886

Aug

Ͳ 09 2762

Sep

Ͳ 09 2465

Decline over the first 12

Ͳ 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 production data to calculate a monthly total. 2. Calculate a decline in production over the first 12 months by applying the following formula: SUMMARY 3. Calculate an average of the production data over the 12 month period. 4. Calculate the decline factor for that facility by applying the following formula: Enerplus Resources (USA) Corporation

Decline Factor Calculation

0 1000 2000 3000 4000 5000 6000 7000

Feb

Ͳ 09 Mar

Ͳ 09 May

Ͳ 09 Jul

Ͳ 09 Aug

Ͳ 09 Oct

Ͳ 09 Dec

Ͳ 09 Jan

Ͳ 10

0 1000 2000 3000 4000 5000 6000 7000 8000

Sep

Ͳ 08 Dec

Ͳ 08 Mar

Ͳ 09 Jul

Ͳ 09 Oct

Ͳ 09 Jan

Ͳ 10

0 2000 4000 6000 8000 10000 12000 14000

Sep

Ͳ 08 Oct

Ͳ 08 Dec

Ͳ 08 Feb

Ͳ 09 Mar

Ͳ 09 May

Ͳ 09 Jul

Ͳ 09 Aug

Ͳ 09 Oct

Ͳ 09Enerplus Resources (USA) Corporation

Decline Factor Calculation

Fredericks 6

Mar

Ͳ 09 6852.7

Apr

Ͳ 09 4388

May

Ͳ 09 5106

Jun

Ͳ 09 4388

Jul

Ͳ 09 3549

Aug

Ͳ 09 3073

Sep

Ͳ 09 2812

Oct

Ͳ 09 2570

Nov

Ͳ 09 2318

Dec

Ͳ 09 1735

Jan

Ͳ 10 2307

Feb

Ͳ 10 1739

Decline over the first 12

Ͳ months 0.746231

First Month's Production 6852.7

Last Month's Production 1739

Average BOPD 3403.142

Decline factor 0.496613

Tekakwitha

May

Ͳ 08 12498

Jun

Ͳ 08 6761

Jul

Ͳ 08 6635

Aug

Ͳ 08 7139

Sep

Ͳ 08 5283

Oct

Ͳ 08 4743

Nov

Ͳ 08 3854

Dec

Ͳ 08 4039

Jan

Ͳ 09 3649

Feb

Ͳ 09 2938

Mar

Ͳ 09 3614

Apr

Ͳ 09 2964

Decline over the first 12

Ͳ months 0.762842

First Month's Production 12498

Last Month's Production 2964

Average BOPD 5343.083

Decline factor 0.427515

Voigt 11

Aug

Ͳ 08 8107.6

Sep

Ͳ 08 4929

Oct

Ͳ 08 3423

Nov

Ͳ 08 6889

Dec

Ͳ 08 4670

Jan

Ͳ 09 3979

Feb

Ͳ 09 3129

Mar

Ͳ 09 3220

Apr

Ͳ 09 2823

May

Ͳ 09 2857

Jun

Ͳ 09 2562

Jul

Ͳ 09 2464

Decline over the first 12

Ͳ 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

Ͳ 08 16424

Aug

Ͳ 08 4804

Sep

Ͳ 08 8111

Oct

Ͳ 08 7384

Nov

Ͳ 08 5169

Dec

Ͳ 08 5160

Jan

Ͳ 09 4610

Feb

Ͳ 09 3619

Mar

Ͳ 09 3903

Apr

Ͳ 09 3336

May

Ͳ 09 3419

Jun

Ͳ 09 3120

Decline over the first 12

Ͳ 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

Ͳ 09 Mar

Ͳ 09 May

Ͳ 09 Jul

Ͳ 09 Aug

Ͳ 09 Oct

Ͳ 09 Dec

Ͳ 09 Jan

Ͳ 10 Mar

Ͳ 10

0 2000 4000 6000 8000 10000 12000 14000

Apr

Ͳ 08 Jun

Ͳ 08 Jul

Ͳ 08 Sep

Ͳ 08 Oct

Ͳ 08 Dec

Ͳ 08 Feb

Ͳ 09 Mar

Ͳ 09 May

Ͳ 09

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Jun

Ͳ 08 Jul

Ͳ 08 Sep

Ͳ 08 Oct

Ͳ 08 Dec

Ͳ 08 Feb

Ͳ 09 Mar

Ͳ 09 May

Ͳ 09 Jul

Ͳ 09 Aug

Ͳ 09

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

Jun

Ͳ 08 Jul

Ͳ 08 Sep

Ͳ 08 Oct

Ͳ 08 Dec

Ͳ 08 Feb

Ͳ 09 Mar

Ͳ 09 May

Ͳ 09 Jul

Ͳ 09Enerplus Resources (USA) Corporation

Decline Factor Calculation

Woman Creek

May

Ͳ 09 6123

Jun

Ͳ 09 4204

Jul

Ͳ 09 4558

Aug

Ͳ 09 3452

Sep

Ͳ 09 3379

Oct

Ͳ 09 3092

Nov

Ͳ 09 2572

Dec

Ͳ 09 2494

Jan

Ͳ 10 2296

Feb

Ͳ 10 1949

Mar

Ͳ 10 2030

Apr

Ͳ 10 1810

Decline over the first 12

Ͳ months 0.704393

First Month's Production 6123

Last Month's Production 1810

Average BOPD 3163.25

Decline factor 0.516618

TSB

Jul

Ͳ 09 17132.67

Aug

Ͳ 09 13068.9

Sep

Ͳ 09 10498.9

Oct

Ͳ 09 7647.33

Nov

Ͳ 09 9522.55

Dec

Ͳ 09 7606.9

Jan

Ͳ 10 4596.83

Feb

Ͳ 10 8671.98

Mar

Ͳ 10 7834.86

Apr

Ͳ 10 6425.9

May

Ͳ 10 6638.86

Jun

Ͳ 10 6283.47

Decline over the first 12

Ͳ 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

Ͳ 09 May

Ͳ 09 Jul

Ͳ 09 Aug

Ͳ 09 Oct

Ͳ 09 Dec

Ͳ 09 Jan

Ͳ 10 Mar

Ͳ 10 May

Ͳ 10

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

May

Ͳ 09 Jul

Ͳ 09 Aug

Ͳ 09 Oct

Ͳ 09 Dec

Ͳ 09 Jan

Ͳ 10 Mar

Ͳ 10 May

Ͳ 10 Jun

Ͳ 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 Data

............................................................................................................................... ........ 4

Treater Burner(s) Data

.............................................................................................................................. 5

Smokeless Combustion Devices (Flares)

................................................................................................... 6

Truck Loading Data

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

Pneumatic Pumps Data

............................................................................................................................. 9

Pneumatic Pump Controls

.................................................................................................................... 9

Pneumatic Controllers Data

.................................................................................................................. 9

Glycol Dehydrator Data

............................................................................................................................. 9

Calculating Glycol Dehydrator Emissions

.............................................................................................. 9

Glycol Dehydrator Control Threshold

................................................................................................. 10

Glycol Dehydrator Controls

................................................................................................................. 10

Glycol Dehydrator Federal Regulations

.............................................................................................. 10

RICE Data Input

............................................................................................................................... ........ 10

Federal Regulations for RICE

............................................................................................................... 11

Gas Analysis Worksheet Input

................................................................................................................ 11

E&P Tanks v2.0 Input

.............................................................................................................................. 12ii 

### Acronyms and Abbreviations

AP

Ͳ 42   EPA Publication AP

Ͳ 42, Compilation of Air Pollutant   Emission Factors (5th Edition)

bbl    barrel

BOPD    barrels of oil per day

BTEX    benzene/toluene/ethyl

Ͳ 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

Ͳ 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

Ͳ 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

Ͳ 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 that emissions associated with the exploration and production of O&G resources

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

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

projected emissions upon startup can be estimated in advance for purposes of pre

Ͳ construction air permitting,

emissions from O&G exploration and production facilities are only known post

Ͳ construction and completion. This

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

To accommodate the need for registration pre

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

a conservative approach to emission calculations for the start

Ͳ 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 equipment leaks, truck loading, etc. are also

included in the calculations.



## Unique Issues with Bakken Pool VOCs

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

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

flash emissions. The North Dakota Department of Health (NDDoH)

Ͳ Bakken VOC Task Force and industry have created

Bakken default values based on Bakken production wells which have been utilized in instances where site

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

would have on emissions is federally enforceable.”

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

Ͳ 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

Ͳ 42 emission factors. The AP

Ͳ 42 is maintained by the Emission Factor and Inventory Group (EFIG)

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

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

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

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



## Regulated Air Pollutant Sources

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

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

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

a) Oil/Condensate Tanks

– VOC, HAP, H2S (NOx, CO, SO2 when controlled)

b) Treater Flares

– VOC, HAP, NOx, CO, H2S, SO2

c) Heaters/Burners

– VOC, HAP, NOx, CO, SO2

d) Truck Loading

– VOC, HAP

e) RICE Engines

– VOC, HAP, NOx, CO

f) Pneumatic Pumps

– VOC, HAP

g) Pneumatic Controllers

– VOC, HAP



## Emission Calculation

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

a simple way of calculating facility

Ͳ 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 Enerplus Emission Calculations Workbook contains the following 10 tabs:

a) Input

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

tab.

b) RICE Input

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

c) Emission Summary

– The calculated emissions are summarized by source and pollutant on this tab.

1) Oil/Condensate Tanks

– The tank vapor emissions are calculated here.

2) Equipment Leaks

– Connector, flange, and valve leaks are calculated here.

3) Treater Flare

– The treater flare emissions are calculated here.

4) Treater Burner

– The treater burner emissions are calculated here.

5) Truck Loading

– The truck loading emissions are calculated here.

6) RICE

– The RICE emissions are calculated here.

7) Pneumatic Pump

– The pneumatic pump emissions are calculated here.

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



## Emission Calculation Procedure

The calculation workbook was completed per the detailed process below:



### Production Data

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

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

Existing wells: the average daily production in BOPD shall be calculated based on the most recent year of production.3 Line 4: New wells: the average daily production for a facility that has not been producing shall be calculated of gas in

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

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

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

than 18 months shall use a decline factor of 1.

Decline Factor Calculation Steps

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

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

Decline Over First 12 Months

= (1

Ͳ 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

Ͳ 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 factor entered on Line 5.

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

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



### Oil/Condensate Tank Data

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

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

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

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

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

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

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

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

emissions.

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

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

the molecular weight, lower heating value of the fuel and the VOC, HAP, 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 determined

from direct measurement is applied. 3) Representative average: The representative average scf/bbl.

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

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

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

Ͳ mole (lb/lb

Ͳ 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 gas HAP weight fraction. Taken from E&P Tank V2 Emission Summary.

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

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

Line 17: The 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 Flare or other 90% DRE device

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

1) Vapor Recovery Unit or Oil Stabilizer

= 99% DRE

2) Enclosed Smokeless Combustor

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

= 98% DRE 4) Ground Pit Flare or other 90% DRE device

= 90% DRE



### Treater Gas Data

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

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

entered on Line 4, by the decline factor entered on Line 5. 2) VOC, HAP, 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

Ͳ 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 specific Btu/scf of the well stream gas.

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

Ͳ 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 calculated molecular weight of the well stream gas based on the specific gravity entered on Line 23.

Enter this value on Line 22.

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

percent of the gas.

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

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

.

Line 27: Enter the 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 device 4) Connected to Sales Line

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

1) Enclosed Smokeless Combustor

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

= 98% DRE 3) Ground Pit Flare or other 90% DRE device

= 90% DRE 4) Connected to Sales Line

= 100% DRE



### Treater Burner(s) Data

Lines 31

Ͳ 32: Emission estimates for natural gas burners, such as those found on heater/treaters or some flares, are

typically calculated using AP

Ͳ 42 emission factors. The AP

Ͳ 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:



###  ̧ 1 ·  ̈ © §

 u u

u u u u u u

100 100

2000 10

100 10

Pr

6 6 

### DRE

HV HV

HV B HO BR EF

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

Ͳ ton

= 2000

Ͳ lb;

1

Ͳ MMBtu

= 10 6

Ͳ Btu; and

1

Ͳ MMscf

= 10 6

Ͳ scf.

Potential emissions must be calculated based on 8,760

Ͳ 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 heaters, 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

Ͳ 42, Tables 1.4

Ͳ 1, 1.4

Ͳ 2 and 1.4

Ͳ 3:

Table 1.4

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

Ͳ 42, Tables 1.4

Ͳ 1, 1.4

Ͳ 2 and 1.4

Ͳ 3)

Pollutant Natural Gas EF*

NOx 100 lb/MMscf CO 84 lb/MMscf VOC 5.5 lb/MMscf HAPS 1.89 lb/MMscf

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

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

enter the total heat input of all burners.

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



### Smokeless Combustion Devices (Flares)

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

factors for estimating NO X , CO, and total organic compounds (TOC) emissions can be found in AP

Ͳ 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 HV

FC EF

E X

X 

### u u 

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

Ͳ ton

= 2000

Ͳ lb.

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



### 24 HO DPR FC GAS 

### u 

where:

FC

= fuel consumption (MMscf/yr);

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

HO

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

1

Ͳ day

= 24

Ͳ hours.

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

maximum daily production capacity for 8760

Ͳ hrs/yr. 



### Truck Loading Data

Lines 32

Ͳ 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

Ͳ

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

 u u

u T M P S L

L 

where:

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

Ͳ gal);

S

= saturation factor (unitless) (AP

Ͳ 42, Table 5.2

Ͳ 1);

P

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

Ͳ 42, Table 7.1

Ͳ 2);

M

= molecular weight of tank vapors (lb/lb

Ͳ mole) (AP

Ͳ 42 Table 7.1

Ͳ 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 42 365 u u u OIL L

X 

### DPR L E 

where:

E X = emissions for pollutant X (tpy);

L

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

Ͳ gal);

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

1

Ͳ year = 365

Ͳ days;

1

Ͳ bbl

= 42

Ͳ gallons; and

1

Ͳ ton

= 2000

Ͳ lb.

Table 5.2

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

Ͳ 42, Table 5.2

Ͳ 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

Ͳ 2 Properties of Selected Petroleum Liquids (Excerpt from AP

Ͳ 42, Table 7.1

Ͳ 2)

Petroleum

Liquid

Crude Oil

RVP 5 Vapor MW at 60 F

MV(lb/lb

Ͳ 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

Ͳ 39.

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

selected based on mode of operation.

Line 35: Enter the molecular weight of tank vapors, lb/lb

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

on the Truck Loading tab.

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

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

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

average annual temperature.

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

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

### Pneumatic Pumps Data

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

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

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

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

c) Molecular weight of motive gas

d) Hours of operation

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

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

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

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

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

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

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

Pneumatic Controllers Data

Lines 45

Ͳ 46 : If a pneumatic controller uses natural gas as the motor fuel, VOC and HAP emissions shall be released

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

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

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

c) Molecular weight of fuel gas

d) Hours of operation

Bakken Pool O&G production facilities are not required to install add

Ͳ 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

Ͳ 48 : Glycol, usually tri

Ͳ 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 regeneration, steam containing hydrocarbon vapors are

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

Calculating Glycol Dehydrator Emissions GRI

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

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

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

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

the Emission Calculation Workbook.10 Glycol Dehydrator Control Threshold Emissions that meet or exceed the following thresholds require the still vent vapors be routed to a control device: ш

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

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

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

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

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

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

weight.

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

to <15 TPY VOC and <5 TPY HAP. An updated GRI

Ͳ 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 Bakken Pool O&G production facilities.

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

Ͳ GLYCalc V4 software. (If no glycol dehydrator is installed, enter

0).

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

Ͳ GLYCalc V4 software. (If no glycol dehydrator is installed, enter

0).



### RICE Data Input

Lines 1

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

Internal combustion engine emissions were estimated using the following equation:



###  ̧ 1 ·  ̈ © §

 u u u

100 100

2000 DRE HO ER EF

E X

X 

where:

E X = emissions for pollutant X (tpy);

EF

X = emission factor for pollutant X (lb/hp

Ͳ 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

Ͳ ton

= 2000

Ͳ lb.

Potential emissions were calculated based on 8760

Ͳ hours per year (hrs/yr) and using the manufacturer's guaranteed

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

temperature. For uncontrolled emissions, the destruction and removal efficiency (DRE) is zero.11 Line 1: Enter the number of engines to be installed at the production facility.

RICE Engine #1: Lines 2

Ͳ 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 results for carbon monoxide (CO).

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

Line 7 : Enter the manufacturer’s emission factor, actual test results or Subpart W factor in kg/mmBtu for N 2 O.

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

Ͳ 42 factor in lb/hp

Ͳ 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 efficiency of any applicable controls (NSCR catalyst, AFRC, etc.) obtained from

manufacturer data or actual test results.

Repeat the above input instructions for Line 2 through Line 12 for each additional engine at the 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 Performance for Stationary Compression Ignition Internal Combustion Engines :

Applies to any compression

Ͳ 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

Ͳ ignition internal combustion engine where construction is commenced after June 12, 2006 and the engine is

manufactured:

1) After July 1, 2007 for engines > 500 hp 2) After January 1, 2008 for lean

Ͳ burn engines 500 < hp < 1350

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

4) After January 1, 2009 for emergency engines

40 CFR 63, Subpart ZZZZ

– National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal

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

area source of HAPs.



### Gas Analysis Worksheet Input

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

### E&P Tanks v2.0 Input

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

# Attachment E

Qualitative Air Quality AnalysisEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

E

Ͳ 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:

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

are insignificant.

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

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

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

region.

# Attachment F

Synthetic Minor Limit RequestEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

F

Ͳ 1 

## S

YNTHETIC 

## M INOR 

## L IMIT 

## R EQUEST 

## G ENERAL 

## I NFORMATION

Company Name

Enerplus Resources (USA) Corporation Facility Name

Hilo/Kona

Company Contact or Owner Name

Tony Lucero Title

HSE Coordinator

Mailing Address

US Bank Tower, Suite 2200

950

Ͳ 17th Street

Denver, CO 80202

Ͳ 2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279

Ͳ 5500 Facsimile Number

(720) 279

Ͳ 5550 Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

F

Ͳ 2 

## P ROPOSED 

## L IMITATION AND 

## E FFECT ON THE 

## P OTENTIAL TO 

## E MIT

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

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

Ͳ 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 PTE, Enerplus is requesting mandated installation, operation

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

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

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

affecting the cumulative production rates and combustion unit sizing);

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

conservative average herein); and

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

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

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

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

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

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

HAPs for approval prior to installation.

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

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

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

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

this facility. Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hilo/Kona

F

Ͳ 3 

## M ONITORING



## , R ECORDKEEPING AND 

## R EPORTING



### Facility

Ͳ Wide Emissions

Monitoring. Facility

Ͳ wide emissions will be calculated and recorded at the end of each month,

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

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

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

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

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

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

provided herein.

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

1) Actual rolling monthly facility

Ͳ wide emissions;

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

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

emissions at the facility;

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

5) Process units and emission control devices used; and

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



### Control Device for VOC and HAP Emissions

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

follows:

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

2) Minimum quarterly visual confirmation of smokeless operation;

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

1) Site

Ͳ specific design input parameters provided for the independent engineering analysis

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

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

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

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

preventative measures adopted to avoid such bypasses or downtime.

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

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

Application for New Construction

Facility: Hilo/Kona

F

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

flare(s).

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

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

operational.

6) Visible emissions.

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

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

include the following information:

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

2) The date(s) analyses were performed;

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

4) The analytical techniques or methods used;

5) The results of such analyses or measurements; and

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



### Hydrocarbon Storage Vessels and Pressurized Hydrocarbon Vessels

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

hydrocarbon vessel.

Recordkeeping.

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

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



### Natural Gas Fired External Combustion Units

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

combustion units:

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

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

equipment;

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

installed at the facility;

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

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

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

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

Application for New Construction

Facility: Hilo/Kona

F

Ͳ 5 

### Natural Gas Fired Engines

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

1) Quarterly measurement of VOC emissions from each engine;

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

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

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

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

2) Manufacturer specifications for each temperature

Ͳ sensing device, pressure

Ͳ measuring

device, and oxidation catalyst;

3) Calibration and maintenance conducted in accordance with the manufacturer

recommendations for each temperature

Ͳ sensing device, pressure

Ͳ measuring device or

engine catalyst;

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

actions taken;

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

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

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

8) Each overhauled or replaced engines “break

Ͳ in” period.

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

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

include the following information:

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

2) The date(s) analyses were performed;

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

4) The analytical techniques or methods used;

5) The results of such analyses or measurements; and

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

# Attachment G

Equipment Specifications and Guarantees

# Emission Control System Warranty

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

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

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

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

YOUR WARRANTY RIGHTS AND OBLIGATIONS:

California

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

In California, new spark-ignited small off-road equipment engines must be designed, built, 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 engines at or below 19 kilowatts. Specific Honda products that do not meet the California emissions regulations

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

All of the United States and Canada

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

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

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

Your emission control system may include such parts as the ca rburetor or fuel injection system, the ignition system, and cataly tic converter. Also

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

OWNER'S WARRANTY RESPONSIBILITY:

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

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

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

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

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

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

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

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

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

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

subsequent purchaser for the duration of the warranty period.

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

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

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

only.

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

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

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

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

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

4900 Marconi Drive

Alpharetta, Georgia 30005-8847

Telephone: (888) 888-3139

Email: powerequipmentemissions@ahm.honda.com or Honda Canada Inc.

Power Equipment Customer Relations

Visit www.honda.ca

for contact information.

Telephone: (888) 946-6329



### 00X51-ZG0-6110 TO961 PWL50975-M

# Emission Control System Warranty

TO OBTAIN WARRANTY SERVICE:

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

or other proof of original purchase date, to any Honda Power Equipment dealer who is authorized by Honda to sell and service 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 service 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 the Honda office in yo ur region:

EXCLUSIONS:

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

control systems or parts that ar e affected or damaged by owner abuse, neglect, improper maintenance, misuse, misfueling, improp er storage, collision, the

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

This warranty does not cover replacement of expendable maintenan ce 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 Implied Warranties:

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

use of the power equipment, or any commercial loss due to the fail ure of the equipment; and a ny implied warrantie s are limited to the duration of this

written warranty. This warranty is applicable only where the California, U.S. EPA, or Environmen t Canada emission 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: powerequipmentemissions@ahm.honda.com or Honda Canada Inc.

Power Equipment Customer Relations

Visit www.honda.ca

for contact information.

Telephone: (888) 946-6329

SYSTEMS COVERED

BY THIS WARRANTY: PARTS

DESCRIPTION:

Fuel Metering Carburetor assembly (includes starting enrichment system),

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

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

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

Exhaust Catalyst, Exhaust manifold

Air Induction Air filter housing, Air filter element*

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

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

Crankcase Emission Control Crankcase breather tube, Oil filler cap

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

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

manufacturer’s emissions warranty for non-Honda parts.

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

PWL50975-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

## Table of Contents

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

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

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

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

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

**Tables**

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

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

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

Table 5.2 : Test Results Summar y, 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, Volu metric 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

# $SSHQGL[2QH7HV W 3DUDPHWHUV

### 1 oz. Inlet Pressure**Cimarron Energy**

**Liberty Oil Well**

**Parshall, ND**

**Flare**

**6/15/2011**

**1 oz.**

**Run # 7 8 9 Average**

Start Time 12:42 14:20 15:41

Stop Time 13:08 14:40 16:06

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0

√Δ P AVG Inlet Avera g e ( 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 Data** **Cimarron Energy**

**Liberty Oil Well**

**Parshall, ND**

**Flare**

**6/15/2011**

**1 oz.**

**Run # 1 2 3 Average**

Start Time 12:34 14:12 15:30

Stop Time 13:34 15:12 16:30

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Stack Diameter (inches) 42.6 42.6 42.6 42.6

√Δ P AVG Avera g e ( 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 Sam p le Volume ( ft 3 ) 37.560 38.015 37.022 37.532

Δ 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 Calculations Cimarron Energ**  **y**

**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 Bias**Cimarron Energy Run 1**

**Liberty Oil Well**

**Parshall, ND Start Time** 12:34

**Flare Run Length** 60

**06/15/11 Stop Time** 13:34

**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 Calibration**Cimarron Energy Run 2**

**Liberty Oil Well**

**Parshall, ND Start Time** 14:12

**Flare Run Length** 60

**06/15/11 Stop Time** 15:12

**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 Pressure**Cimarron Energy**

**Liberty Oil Well**

**Parshall ND**

**Flare**

**6/14/2011**

**4 oz.**

**Run # 4 5 6 Average**

Start Time 10:56 13:15 14:28

Stop Time 11:02 13:21 14:36

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0

√Δ P AVG Inlet Avera g e ( 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 Pil o t Li g ht NMOC (lb/h r 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 Data** **Cimarron Energy**

**Liberty Oil Well**

**Parshall ND**

**Flare**

**6/14/2011**

**4 oz.**

**Run # 4 5 6 Average**

Start Time 10:48 12:55 14:14

Stop Time 11:48 13:55 15:14

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Stack Diameter (inches) 42.6 42.6 42.6 42.6

√Δ 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 Sam p le Volume ( ft 3 ) 36.340 36.409 37.287 36.679

Δ 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 Calculations Cimarron Ener**  **gy**

**Libert y**  **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 Bias**Cimarron Energy Run 4**

**Liberty Oil Well**

**Parshall ND Start Time** 10:48:13

**Flare Run Length** 60

**06/14/11 Stop Time** 11:48

**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 Calibration**Cimarron Energy Run 5**

**Liberty Oil Well**

**Parshall ND Start Time** 12:55:23

**Flare Run Length** 60

**06/14/11 Stop Time** 13:55

**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 Pressure**Cimarron Energy**

**Liberty Oil Well**

**Parshall ND**

**Flare**

**6/14/2011**

**10 oz.**

**Run # 7 8 9 Average**

Start Time 15:37 16:56 8:56

Stop Time 15:44 17:08 9:03

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Inlet Duct Diameter (inches) 4.0 4.0 4.0 4.0

√Δ P AVG Inlet Avera g e ( 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 Pil o t Li g ht NMOC (lb/h r 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 Data** **Cimarron Energy**

**Liberty Oil Well**

**Parshall ND**

**Flare**

**6/14/2011**

**10 oz.**

**Run # 7 8 9 Average**

Start Time 15:31 16:48 8:45

Stop Time 16:31 17:48 9:45

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Stack Diameter (inches) 42.6 42.6 42.6 42.6

√Δ 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 Sam p le Volume ( ft 3 ) 37.385 37.148 37.088 37.207

Δ 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 Calculations Cimarron Ener**  **gy**

**Libert y**  **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 Value**Cimarron Energy Run 7**

**Liberty Oil Well**

**Parshall ND Start Time** 15:31:23

**Flare Run Length** 60

**06/14/11 Stop Time** 16:31

**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 Range**Cimarron Energy Run 8**

**Liberty Oil Well**

**Parshall ND Start Time** 16:48:23

**Flare Run Length** 60

**06/14/11 Stop Time** 17:48

**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 Range**Cimarron 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 Calculations** **Cimarron Energy**

**Liberty Oil Well**

**Parshall, ND**

**Flare**

**06/15/11**

**EPA Methods 1-4: Determin ation of Stack Gas Velocity**  **and Volumetric Flow Rate**

**Sam p**  **le Calculation s** 

sample volume (scf) = 17.64 * V M * Y D * {P B + ǻ 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 Energ y** 

**Liberty Oil Well**

**Parshall, ND**

**Flare**

**06/15/11**

**EPA Methods 1-4: Determin ation of Stack Gas Velocity**  **and Volumetric Flow Rate**

**Sample Calculations (continued)**

gas velocity (ft/sec) = 85.49 * C P * ¥ǻ 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

ʌ * (D S / 12) 2

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

ʌ * ( 42.63 / 12) 2

= 60 * 4 * 7.4

= 4,382

ʌ * (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

ʌ * ( /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 - 

# [ ] 460**Cimarron Energ y** 

**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)

ǻ 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 Anal**  **y**

**zer Procedur e**  **)**

**Sam p**  **le Calculation s** 

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 Abbreviation s** 

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 percent**Cimarron Energy**

**Liberty Oil Well**

**Parshall, ND**

**Flare**

**06/15/11**

**EPA Method 10: Determination of Carbon Monoxide Emissions from Stationary**

**Sources ( Instrumental Anal**  **y**

**zer Procedur e**  **)**

**Sam p**  **le Calculation s** 

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 Abbreviation s** 

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-hour**Cimarron Energy**

**Liberty Oil Well**

**Parshall, ND**

**Flare**

**06/15/11**

**EPA Method 25A: Determination of Total Gaseous Orga nic Concentrations Using a Flame Ionization Analyzer** 

**Sam p**  **le Calculation s** 

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 Abbreviation s** 

as C 3 H 8 - as propane or C3

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

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

tpy - tons per year

ppmvw - parts per million, wet volume basis

g/bhp-hr - grams per brake horsepower-hour =

# $SSHQGL[7ZR)LHOGDQG/DERUDWRU\'DWD

### 1 oz. Inlet Pressure

### 4 oz. Inlet Pressure

### 10 oz. Inlet Pressure

# $SSHQGL[7KUHH&DOLEUDWLRQ'DWD

# $SSHQGL[)RXU6FKHPDWLFVF 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 op erating 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 ou t on the separator outlet to determin e concentrations of organic compounds,

total reduced sulphur compounds and water content. Samplin g 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 - - - ( % e ff

iciency) > 99

. 99

( % e ff

iciency) > 99

. 99