### February 9, 2012

Minor NSR Permitti ng Coordinator

US EPA Region 8

1595 Wynkoop Avenue, 8P-AR

Denver, CO 80202-1129

RE: Enerplus Resources (USA) Corporation

Revised Construction Permit Application

To Whom It May Concern:

Enerplus is resubmitting the enclosed applica tion for the construction of the synthetic

minor air emission source named “Hans.” T he application has been revised to reflect

the approved Motion to Amend the August 29 th 

### , 2011 Administrative Complaint and

Consent Agreement (Consent Agreement ) under Docket No. CAA-08-2011-0021. The

revisions are limited to changing the name and location (Towns hip, Range, etc.) of the

original application. The Moti on to Amend was approved on January 13 th 

### , 2012, and is

included with this submittal for your reference.

Thank you for your assistance with this matte r. Please don’t hesitate to contact me at

(720) 279-5542 if I can be of any further assistance.

Respectfully,

Tony Lucero

Enerplus Resources (USA) Operations

Environment, Health & Safety Coordinator

Enclosure: Approved Joint Motion to Amend, Administrative Complaint and Consent

Agreement

# Application for New Construction

Hans Facility

Prepared For:



## Enerplus Resources (USA) Corporation

US Bank Tower, 950 17 th 

## Street

Denver, CO 80202

Revised Submittal: February 9, 2012

Initial Submittal: October 19, 2011

Prepared By:

3700 East 41 st Avenue

Denver, CO 80216-6504

303-289-7520 (Office)

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

Application for New Construction

Facility: Hans

ii 

### Table of Contents

General Facility Information

................................................................................................................................................... 1

Previous Permit Actions

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

Contact Information

................................................................................................................................................................ 3

Facility Process Description

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

Operating Schedule

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

Process Flow Diagram (typ.)

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

Type and Quantity of Fuels

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

Attachments

Attachment A Emission Units and Air Pollution

‐ Generating Activities

Attachment B Proposed Emission Controls, Control Efficiencies and Manufacturer Guarantees

Attachment C Criteria Pollutant Emission Estimates

Attachment D Criteria Pollutant Emission Supporting Documentation

Attachment E Qualitative Air Quality Analysis

Attachment F Synthetic Minor Limit Request

Attachment G Equi pment Specifications and GuaranteesEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

1 

## General Facility Information

1. (a) Company Name

Enerplus Resources (USA) Corporation

(b) Operator Name

Enerplus Resources (USA) Corporation 2. Facility Information

Hans

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)

Southeast of BIA Road 14.

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

20 12. (c) Township

148N 12. (d) Range

93WEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans



## Previous Permit Actions

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

Facility Name on the Permit

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

Permit Number

Date of the Permit Action

Facility Name on the Permit

N/A

Permit Number

Date of the Permit Action

Facility Name on the Permit

N/A

Permit Number

Date of the Permit ActionEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans



## Contact Information

Company Contact

Tony Lucero Title

EHS Coordinator

Mailing Address

US Bank Tower, Suite 2200, 950

– 17 th Street, Denver, CO 80202

‐ 2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279

‐ 5500 Facsimile Number

(720) 279

‐ 5550

Operator Contact (if different from above)

Same as above. Title

Mailing Address

Email Address

Telephone Number Facsimile Number

Facility Contact

Lynn Sundby Title

Senior Foreman

Mailing Address

3911 University Ave., Williston, ND 58801

Email Address

LSundby@enerplus.com

Telephone Number

(406) 774

‐ 3010 Facsimile Number

(720) 279

‐ 5550

Compliance Contact

Tony Lucero Title

EHS Coordinator

Mailing Address

US Bank Tower, Suite 2200, 950

– 17 th Street, Denver, CO 80202

‐ 2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279

‐ 5500 Facsimile Number

(720) 279

‐ 5550Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans



## Facility Process Description

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

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

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

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

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

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

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

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

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

process are described below:

High

‐ Pressure Natural Gas

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

Additionally, as the wellhead fluid(s) is heated, the na tural gas components off

‐ gas more readily than the heavier oil

and water counterparts. Recovered natural gas is either used as fuel for onsite equipment or routed to an enclosed

combustion device capable of a minimum destruction removal efficiency of 98%.

Crude Oil

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

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

temporarily stored in these on

‐ site containers prior to being loaded into tanker trucks for transport to a refining

process plant for sale.

Saline Water

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

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

tank(s). Recovered water is temporarily stored on

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

disposal.

Low

‐ Pr essure Natural Gas

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

and recovered from off

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

‐ site oil storage tanks. This natural

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

additional, low

‐ pressure, natural gas is routed to an enclosed combustion device capable of a minimum destruction

removal efficiency of 98%.

Recycle Pump Process

This facility also has a recycle 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 qual ity standards and needs additional

processing.



## Operating Schedule

This facility is designed to operate 24 hours a day, 7 days a week for 52 weeks a year.EnerplusResources(USA)CorporationApplicationforNewConstructionFacility:Hans5ProcessFlowDiagram(typ.)Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

6 

## Type and Quantity of Fuels

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

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

Equipment Fuel Type Sulfur

Content Max. Hourly Daily Annual

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

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

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

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

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

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

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

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

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

‐ 42, Vol. I, Ch 1.4: Natural Gas

Combustion).

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

one tank per month.

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

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

1,020 Btu/scf (AP

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

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

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

Attachment G.

# Attachment A

Emission Units and Air Pollution

‐ Generating ActivitiesFacility NameHansEmitting Unit:Emitting Unit:Unit Type:Unit Type:Max Rated Design Capacity/Throughput:Max Rated Design Capacity/Throughput:Emitting Unit:Emitting Unit:Unit Type:Unit Type:Max Rated Design Capacity/Throughput:Max Rated Design Capacity/Throughput:Emitting Unit:Emitting Unit:Unit Type:Unit Type:Max Rated Design Capacity/Throughput:Max Rated Design Capacity/Throughput:400 bbl/eachRecycle Pump (x2)Honda Brand or Equivalent8 HP/eachSivallis Brand or EquivalentTruck Loading500,000 Btu/each145 kW (194 HP)/eachNewage UCI274G or Equivalent0.6Generator (x2)Submerged loading: dedicated normal serviceOil/Condensate Tanks (x10)Welded SteelHeater Treater Burner(x2)

# Attachment B

Proposed Emission Controls, Control Efficiencies, Emission Limits and MonitoringFacility NameHansEmission Control TypeEmission Control TypeEfficiency:Efficiency:Max Rated Design Capacity/Throughput:Max Rated Design Capacity/Throughput:Size:Size:Monitoring:Monitoring:Note: Manufacturer specifications and guarantees are appended to this permit.Enclosed Smokeless CombustorEnclosed Smokeless Combustor148 mscf/d to 296 mscf/d148 mscf/d to 296 mscf/dContinuous Pilot FlameContinuous Pilot Flame98%98%Size of combustor will be selectedbased on volume of actual throughput.Size of combustor will be selected basedon volume of actual throughput.

# Attachment C

Criteria Pollutant and GHG Emission EstimatesFacility:HansPTE SYN PTE SYN PTE SYNPTE SYNOil/Condensate Tanks1,010.86 20.22 1.77 0.04 2.22 2.2212.06 12.06N/AN/A N/AN/AN/ATreater Flare3,075.54 61.51 365.67 7.31 11.46 11.46 62.37 62.370.00N/A 0.00N/AN/ATreater Burner0.02 0.02 N/A N/A 0.30 0.300.26 0.26N/AN/A N/A0.02N/ARICE Engine2.62 2.62 N/A N/A 3.75 3.757.49 7.49N/AN/A N/AN/AN/ATruck Loading7.27 7.27 N/A N/APneumatic Pump0.00 0.00 0.00 0.00Pneumatic Controllers0.00 0.00 0.00 0.00Glycol Dehydrator0.00 0.00 0.00 0.00Totals (TPY)4,096.32 91.64 367.44 7.35 17.73 17.73 82.18 82.180.00 0.00 0.000.020.00PTE SYN PTE SYN PTE SYNPTE SYNOil/Condensate Tanks20.64 4,346.16 50.90 1.02 0.07 0.00 1,212.72 4,370.00Treater Flare114.96 20,377.92 0.33 0.01 0.04 0.00 133.66 20,378.29Treater Burner365.25 365.25 0.03 0.03 0.01 0.01 367.63 367.63RICE Engine1,911.08 1,911.08 0.00 0.00 0.00 0.00 1,911.08 1,911.08Totals (TPY)2,411.93 27,000.42 51.26 1.05 0.12 0.01 3,625.09 27,027.01PTE SYN PTE SYN PTE SYNPTE SYNOil/Condensate Tanks0.95 0.02 0.38 0.01 0.29 0.010.00 0.00Treater Flare103.33 2.07 121.89 2.44 140.45 2.810.00 0.00Totals(TPY)104.28 2.09 122.27 2.45 140.74 2.810.00 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.2,2,4 TrimethylpentaneEmission SourceHAP BreakdownBenzene Toluene XylenesN2OCO2CH4Emission SourceCO2eGreen 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)PM 2.5NOxbH2SO4bSO2PM 10bH2SVOC HAP CO

# Attachment D

Criteria Pollutant and GHG Emission Supporting DocumentationGREEN= Requires inputRED= No input required. This is a calculated value.Facility InformationLine 1HansName of the facility and the well number.Line 211/1/2011Submittal Date.Production DataDescriptionLine 3BOPD1,820Average daily production in barrels of oil per day (BOPD).Line 4Mscfd1,363Average daily production of gas in Mscf per day.Estimated gas production based on actual Bakken gas production from existing Enerplus facilities.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 1year of production data - see criteria pollutant emission supporting documentation.Line 6Adjusted BOPD837.2This is the calculated BOPD expected to be produced using the above entered decline factor.Line 7Adjusted Treater Gas (Mscfd)627.0628This is the calculated mcfd of gas the well is expectedto produce using the above entered decline factor.Oil/Condensate Tank DataDescriptionLine 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)81970.252This 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 Value2,178.25Lower heating value (Btu/scf) of tank vapors.Estimated from E&P Tank V2 Emission Summary.Line 12Molecular Weight38.18Molecular weight of the tank vapors in pounds per pound-mole (lb/lb-mole).Estimated from E&P Tank V2 Emission Summary.Line 13VOC%67.07%VOC weight fraction of the tank vapor gas (C3+).Estimated from E&P Tank V2 Emission Summary.Line 14HAP%0.12%HAP weight fraction of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 15CO2%0.60%CO2mole fraction of the tank vapor gas.Estimated from E&P Tank V2 Emission Summary.Line 16CH4%8.04%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 192Use the drop down menu to choose the appropriate emission control type.Line 20Control Destruction Efficiency98%Control efficiency of applied control technology.Treater Gas DataDescriptionLine 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 specific gravity entered above. Please enter this number on Line 24.Line 25VOC%37.77%VOC weight fraction of the well streamgas (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 291Use the drop down menu to choose the appropriate emission control type.Line 30Control Destruction Efficiency98%Control efficiency of applied control technology.GREEN= Requires inputRED= No input required. This is a calculated value.Facility InformationLine 1HansName of the facility and the well number.Line 211/1/2011Submittal 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 LoadingDescriptionLine 3410Use 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 30.6Use the drop down list to choose the appropriate mode of operation. The saturation factor will automatically be selected basedon mode of operation.Line 36Molecular Weight50.00Molecular weight of tank vapors in lb/lb-mole.From AP-42 refer to Table 2 on the Truck Loading tab.Line 37Vapor Pressure2.30True 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 38Temperature50.00Temperature of bulk liquid loaded in Fahrenheit.Estimated average annual temperature.Line 39Load Rate (bbl/hr)180Load rate of liquid loaded in barrels per hour.Line 40Load Time (hrs)1.00The time it takes to loadout one load (hrs).Pneumatic PumpsDescriptionLine 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 rate as 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 ControllersDescriptionLine 46Number of Pneumatic Controllers0Number of pneumatic controllers at facility.Line 47Bleed rate (scf/hr)0.00Average bleed rate of device (scf/hr).Glycol DehydratorDescriptionLine 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.scf/dayBtu/scflb/lb‐moleHAP wt FractionCO2moleFractionCH4wtFractionControlled emissions are calculated based on adestruction efficiency of the VOC gas.VOC: 3,415scf/hr x 0.002638522 lb‐mole/scfx 38.183 lb/lb‐mole x 67.07% =230.79lb/hr230.79lb/hr x 8,760 hr/yr x 0.0005 ton/lb=1010.86TPYHAP: 3,415scf/hr x 0.002638522 lb‐mole/scfx 38.183 lb/lb‐mole x 0.12% =0.40lb/hr0.40lb/hr x 8,760 hr/yr x 0.0005 ton/lb=1.77TPYAP‐42Table13.5‐1aNOx: 3,415scf/hr x2,178Btu/scfx1E-06 MMBtu/ Btux 0.068 =0.51lb/hr0.51lb/hrx 8,760 hr/yr x 0.0005 ton/lb=2.22TPY98%0.60%8.04%Lower Heating Value2178.25VOC wt Fraction67.07%0.12%HansOil/Condensate TanksFlareGasVolume81,970Molecular Weight38.18AP‐42Table13.5‐1aCO: 3,415scf/hr x2,178Btu/scfx1E-06 MMBtu/ Btux 0.370 =2.75lb/hr2.75lb/hrx 8,760 hr/yr x 0.0005 ton/lb=12.06TPYE&PTankV2Em.Summaryb∑(Yj*Rj)cCO2:3,415scf/hr x 0.604%+0.98x3,415scf/hrx2.55 = 8545.15scf/hr8545.15scf/hr x 0.0026 lb‐mole/scf x 44.01 lb/lb‐mole=992.27lb/hr992.27lb/hrx 8,760 hr/yr x 0.0005 ton/lb=4346.16TPYE&PTankV2Em.SummarybCH4:3,415scf/hr x 0.002638522 lb‐mole/scf x 16.04 lb/lb‐mole x 8.04% =11.62lb/hr11.62lb/hrx 8,760 hr/yr x 0.0005 ton/lb=50.90TPYN2O:3,415scf/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=0.07TPYNotes:aNOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.1,010.86VOC TPYcCO2calculated from Subpart W, Eq. W-20 and W-21.20.22VOC TPYControlled1.77 HAP TPY Uncontrolled0.04 HAP TPY Controlled2.22NOx TPY12.06 CO TPY20.64CO2TPYUncontrolled4,346.16CO2TPYControlled50.90CH4TPYUncontrolled1.02CH4TPYControlled0.07N2OTPYUncontrolled0.00N2OTPYControlledUncontrolledTOTALSAP‐42Table1.4‐2bCO2and CH4percent weight are from E&P Tank V2 Emission Summary.HAP: 3,415scf/hr x 0.002638522 scf/lb‐mole x 38.18 lb/lb‐mole x 0.12% =0.40lb/hr0.40lb/hr x 8,760 hr/yr x 0.0005 ton/lb=1.77TPYBenzene: 3,415scf/hr x 0.002638522 scf/lb‐mole x 38.18 lb/lb‐mole x 0.06% =0.22lb/hr0.22lb/hr x 8,760 hr/yr x 0.0005 ton/lb=0.95TPYToluene: 3,415scf/hr x 0.002638522 scf/lb‐mole x 38.18 lb/lb‐mole x 0.03% =0.09lb/hr0.09lb/hr x 8,760 hr/yr x 0.0005 ton/lb=0.38TPYXylenes: 3,415scf/hr x 0.002638522 scf/lb‐mole x 38.18 lb/lb‐mole x 0.02% =0.07lb/hr0.07lb/hr x 8,760 hr/yr x 0.0005 ton/lb=0.29TPY2,2,4 Trimethylpentane: 3,415scf/hr x 0.002638522 scf/lb‐mole x 38.18 lb/lb‐mole x 0.00% =0.00lb/hr0.00lb/hr x 8,760 hr/yr x 0.0005 ton/lb=0.00TPYBenzene 0.95 TPYUncontrolledBenzene 0.02 TPYControlledToluene 0.38 TPYUncontrolledToluene 0.01 TPYControlledXylenes 0.29 TPYUncontrolledXylenes 0.01 TPYControlled2,2,4Trimethylpentane 0.00 TPYUncontrolled2,2,4Trimethylpentane 0.00 TPYControlledTOTALSHansOil/Condensate TanksHAP Emission BreakdownscfdBtu/scflb/lb‐moleHAP wt fractionControlled emissions are calculated based on a destruction efficiency of the VOC gas.VOC: 26,128scf/hrx 0.002638522 lb‐mole/scfx 26.965884lb/lb-molex37.77%=702.18lb/hr702.18lb/hr x8760hr/yrx0.0005 ton/lb =3075.54TPY UncontrolledHAP 26,128scf/hrx 0.002638522 lb‐mole/scfx 26.965884lb/lb-molex4.49%=83.49lb/hr83.49lb/hr x8760hr/yrx0.0005 ton/lb =365.67TPY UncontrolledH2S 26,128scf/hrx 0.002638522 lb‐mole/scfx 26.965884lb/lb-molex0.00%=0.00lb/hr0.00lb/hr x8760hr/yrx0.0005 ton/lb =0.00TPY UncontrolledSO226,128scf/hrx 0.002638522 lb‐mole/scfx 26.97lb/lb-molex0.00%=0.00lb/hr0.00lb/hr x8760hr/yrx0.0005 ton/lb =0.00TPY UncontrolledAP‐42Table13.5‐1aNOx: 26,128scf/hrx1,473Btu/scfx0.000001 Mmbtu/ Btux0.068lb/MMBtu=2.62lb/hr2.62lb/hrx8760hr/yrx0.0005 ton/lb =11.46TPYHansTreater FlareFlareGasVolume627,06337.77%4.49%Lower Heating Value1473.198%Avg. Molecular Weight26.97VOCwtfractionAP‐42Table13.5‐1aCO: 26,128scf/hrx1,473Btu/scfx0.000001 Mmbtu/ Btux0.370lb/MMBtu=14.24lb/hr14.24lb/hrx8760hr/yrx0.0005 ton/lb =62.37TPYTreaterGasAnalysisSummaryb∑(Yj*Rj)dCO2: 26,128scf/hr x 0.440%+0.98x26,128scf/hr x1.56 =40,066scf/hr40,066scf/hr x 0.0026385 scf/lb‐mole x 44.01 lb/lb‐mole =4,652lb/hr4,652lb/hrx 8760 hr/yr x0.0005 ton/lb =20,378TPYCH4: 26,128scf/hr x 1473.1 Btu/scfx0.000001 Mmbtu/ Btux0.0009kg/MMBtu=0.03kg/hr0.03kg/hrx 2.2046 lbs/kg x 8760 hr/yr x0.0005 ton/lb =0.33TPYN2O: 26,128scf/hr x 1473.1 Btu/scfx0.000001 Mmbtu/ Btux0.0001kg/MMBtu=0.00lb/hr0.00kg/hrx 2.2046 lbs/kg x 8760 hr/yr x0.0005 ton/lb =0.04TPYNotes:H2SandSO2emissionsarenottypicalforwellsintheBakkenformationandareNOTE:Noemissionsbecausesourceisrouteddirectlytosalesline.thereforenotcalculatedherein.3075.54VOC TPYaNOx & CO emission factors are from AP-42 Table 13.5-1, Emission Factors for Flare Operations.61.51VOC TPYControlleddCO2calculated from Subpart W, Eq. W-20 and W-21.365.67 HAP TPYUncontrolled7.31 HAP TPYControlled0.00 H2S TPYUncontrolled0.00 H2S TPYControlled0.00 SO2TPYUncontrolled11.46NOx TPY62.37CO TPY114.96 CO2TPYUncontrolled20377.92 CO2TPYControlled0.33CH4TPYUncontrolled0.01CH4TPYControlled0.04N2OTPY Uncontrolled0.00N2OTPY ControlledSubpartWccCH4and N2O emission factors are from Subpart W, Table C-3.UncontrolledSubpartWcTOTALSbCO2percent weight is from Treater Gas Analysis.HAP 26,128scf/hrx 0.002638522 lb‐mole/scfx 26.97lb/lb-molex4.49%=83.49lb/hr83.49lb/hr x8760hr/yrx0.0005 ton/lb =365.67TPY UncontrolledBenzene: 26,128scf/hr x 0.002638522 scf/lb‐mole x 26.97 lb/lb‐mole x 1.27% =23.59lb/hr23.59lb/hr x 8760 hr/yr x0.0005 ton/lb =103.33TPYToluene: 26,128scf/hr x 0.002638522 scf/lb‐mole x 26.97 lb/lb‐mole x 1.50% =27.83lb/hr27.83lb/hr x 8760 hr/yr x0.0005 ton/lb =121.89TPYXylenes: 26,128scf/hr x 0.002638522 scf/lb‐mole x 26.97 lb/lb‐mole x 1.72% =32.07lb/hr32.07lb/hr x 8760 hr/yr x0.0005 ton/lb =140.45TPY2,2,4 Trimethylpentane: 26,128scf/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 x0.0005 ton/lb =0.00TPYTOTALSBenzene 103.33 TPY UncontrolledBenzene 2.07 TPY ControlledToluene 121.89 TPY UncontrolledToluene 2.44 TPY ControlledXylenes 140.45 TPY UncontrolledXylenes 2.81 TPY Controlled2,2,4Trimethylpentane 0.00 TPY Uncontrolled2,2,4Trimethylpentane 0.00 TPY ControlledTreater FlareHAP Emission BreakdownHans1,000,000Btu/hrAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeatingValue(Btu/scf)SampleGasHeatingValue(Btu/scf)NOx:1.000 MMBtu/hrx100.00/1020.00x1020.00/1439.00 =0.07lb/hr0.07 lb/hrx0.0005 ton/lbx8760 hr/yr =0.30TPYAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeatingValue(Btu/scf)SampleGasHeatingValue(Btu/scf)CO:1.000 MMBtu/hrx84.00/1020.00x1020.00/1439.00 =0.06lb/hr0.06 lb/hrx0.0005 ton/lbx8760 hr/yr =0.26TPYAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeatingValue(Btu/scf)SampleGasHeatingValue(Btu/scf)VOC:1.000 MMBtu/hrx5.50/1020.00x1020.00/1439.00 =0.00lb/hr0.00 lb/hrx0.0005 ton/lbx8760 hr/yr =0.02TPYAP-42 Table1.4-1EFa(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeatingValue(Btu/scf)SampleGasHeatingValue(Btu/scf)PM 10:1.000 MMBtu/hrx7.60/1020.00x1020.00/1439.00 =0.01lb/hr0.01 lb/hrx0.0005 ton/lbx8760 hr/yr =0.02TPYBurner RatingHeater Treater BurnerHansHeater Treater BurnerHansAP-42 Table1.4-2EFb(lb/MMscf)Avg. GasHeatingValue(Btu/scf)Avg. GasHeatingValue(Btu/scf)SampleGasHeatingValue(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 for criteria 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) Weight (MW) 460 lb/1000 gal

12.46 x 0.60 x 2.30 x 50.00 / 510.00 = 1.69

LL Truck Load Load Time

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

1.69 x 180.00 / 1.00 x 42.00 = 0.00

LL Annual Emissions

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

1.69 x 305578.00 x 42.00 / 2000.00 = 10.84 7.27

VOC

Emissions

Uncontrolled Control % TPY

7.27 0.00% 1.00 7.27

S Factor

Petroleum Vapor MW

Liquid at 60F

Mv(lb/lb-mole)

40 50 60 70 80 90 100

Crude Oil

RVP 5 3.4 4 4.8 50 4.5 7.1 (EPA AP-42 Values) Table 2 below may be used to provide the vapor pressure and molecular we ight values fo r the above equation.

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

5.7 1.8 0.50

Condensed Liquid

2.3 2.8 Vapor Density Density

Wvc(lb/gal W1(lb/gal)

at 60F at 60F 1.00 

### Hans



## Truck Loadout Emission Calculation

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

Cargo Carrier Mode of Operation

0.60

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

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

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

Supply Gas MW VOC wt fraction

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

lbs/hr Hours lbs/ton

0.81 x 8760 x 2000 = 0.00 TPY VOC Uncontrolled

Supply Gas MW HAP wt fraction

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

lbs/hr Hours lbs/ton

0.10 x 8760 x 2000 = 0.00 TPY HAP Uncontrolled

100%

0

0.00 TPY VOC

0.00 TPY HAP TOTALS Control Efficiency

Number of Pumps Hans



## Emissions from Pneumatic Pumps

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

Emissions (TPY)

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

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

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

Supply Gas MW VOC wt fraction

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

lbs/hr Hours lbs/ton

0.00 x 8760 x 2000 = 0.00 TPY VOC

Supply Gas MW HAP wt fraction

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

lbs/hr Hours lbs/ton

0.00 x 8760 x 2000 = 0.0 TPY HAP

0.00 TPY VOC

0.00 TPY HAP TOTALS Hans



### 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%CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.VOC control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for 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.CO control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for CH4.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 8,760hours peryear.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).Manufacturer's emission factor, actual test results or Subpart W factor in kg/mmBtu for N2O.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).RICE Input DataManufacturer's maximum hp rating.DescriptionManufacturer's maximum hp rating.Enter the number of engines that will be installed at the production facility.DescriptionEngine is assumed to operate 8,760hours peryear.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).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Engine is assumed to operate 8,760hours peryear.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.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%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.DescriptionCO 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 AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for total organic compounds (TOC or THC).NOx control efficiency of any applicable controls (NSCR catalyst, AFRC, etc) obtained from manufacturer data or actual test results.Manufacturer's emission factor, actual test results or AP-42 factor in pounds per horsepower hour (lb/hp-hr) for nitrogen oxides (NOx).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for carbon monoxide (CO).Engine is assumed to operate 8,760hours peryear.Manufacturer's maximum hp rating.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 total organic compounds (TOC or THC).Manufacturer's emission factor, actual test results or AP-42 factor in lb/hp-hr for CO2.DescriptionEngine is assumed to operate 8,760hours peryear.Manufacturer's maximum hp rating.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 Uncontrolled0.00VOC 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 #3Subpart W, Table C-3bSubpart W, Table C-3bAP-42, Table 3.3-1axxxg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrxxxxHansReciprocating Engine EmissionsxSubpart W, Table C-3bxxSubpart W, Table C-3bAP-42, Table 3.3-1ag-mmBtu/kg-hp-hrxxHansReciprocating Engine Emissions8 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 Uncontrolled0.00VOC 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%NOxDRE0%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 Uncontrolled1.31VOC 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-3bSubpart W, Table C-3bxxxxxg-mmBtu/kg-hp-hrg-mmBtu/kg-hp-hrxg-mmBtu/kg-hp-hrAP-42, Table 3.3-1aAP-42, Table 3.3-1axxxxxxg-mmBtu/kg-hp-hrSubpart W, Table C-3bHansReciprocating 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.bCH4andN2OSubpartW,TableC‐3ofSubpartC‐DefaultCH4andN2OEmissionFactorsforVariousTypesofFuel.3.75 NOx TPY Uncontrolled3.75 NOx TPY Controlled7.49 CO TPY Uncontrolled7.49 CO TPY Controlled2.62 VOC TPY Uncontrolled2.62 VOC TPY Controlled0.00N2O TPY1911.08CO2TPY0.00CH4TPYAP-42, Table 3.3-1aSubpart W, Table C-3bSubpart W, Table C-3bTOTALSxxxg-mmBtu/kg-hp-hrxxg-mmBtu/kg-hp-hrxGasAnalysisMolePercentMoleFractionMolecularWeightMWComponent WtFractionVOCWt.FractionHAPWt.FractionVOCComponentMWHAPComponentMWOxygen 0.0000 0.000 32 0 0Nitrogen 0.4169 0.004 28.01 0.11677369 0.003042659CarbonDioxide 0.5269 0.005 44.01 0.23188869 0.0060421H2S 0.0000 0.000 34.08 0 0Methane 19.2347 0.192 16.04 3.08524588 0.080389272Ethane 30.6072 0.306 30.07 9.20358504 0.239808927Propane30.0923 0.301 44.097 13.26980153 0.345758403 0.345758403 4.588145383i‐Butane3.4974 0.035 58.12 2.03268888 0.052963811 0.052963811 0.10765895n‐Butane9.7930 0.098 58.12 5.6916916 0.148302911 0.148302911 0.844094433i‐Pentane1.7106 0.017 72.15 1.2341979 0.032158303 0.032158303 0.03968971n‐Pentane2.1712 0.022 72.15 1.5665208 0.04081732 0.04081732 0.06394118Hexanes+1.8976 0.019 100.2 1.9013952 0.049542818 0.049542818 0.094200477Benzene0.0310 0.000 78.11 0.0242141 0.000630923 0.000630923 0.000630923 1.52772E‐05 1.52772E‐05Toluene0.0105 0.000 92.14 0.0096747 0.000252084 0.000252084 0.000252084 2.43884E‐06 2.43884E‐06Ethylbenzene0.0035 0.000 106.17 0.00371595 9.68229E‐05 9.68229E‐05 9.68229E‐05 3.59789E‐07 3.59789E‐07Xylenes0.0070 0.000 106.17 0.0074319 0.000193646 0.000193646 0.000193646 1.43916E‐06 1.43916E‐06224Trimethylpentane0.0000 0.000Total100.00 1.0038.38 0.67 0.00 5.74 0.00VOCWeight%14.95HAPWeight%0.00Notes:Bolditemsareconsideredvolatileorganiccompounds(VOCs).PressureinputforE&PTankfortheflashvalveoptionisbasedonacorrespondingelevationof2,170ft.abovemeansealevel.TemperatureinputforE&PTankfortheflashvalveoptionisbasedonanaveragetemperatureof54OFforthemonthofMaycorrespondingtothedatetheoilseparatorsamplewascollectedreferencedbelow(Reference:http://www.weatherreports.com/United_States/ND/Mandaree).MolepercentagesinputinE&PTankarebasedontheoilseparatoranalysisfromtheLeghornMelodeefacilitycollectedon05/30/2007,asanalyzedbyPENCORofBroussard,Louisiana.E&PGasAnalysisWorksheetGasAnalysisMolePercentMoleFractionMolecularWeightMWComponent WtFractionVOCComponentMWHAPComponentMWOxygen0.000 0.000 3200Nitrogen6.829 0.068 28.01 1.9128029 0.070549836CarbonDioxide0.440 0.004 44.01 0.193644 0.007142164H2S0.000 0.000 34.08 00Methane53.554 0.536 16.04 8.5900616 0.316826913Ethane20.536 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+10.441 0.004 100.2 0.441381 0.016279439 0.007185435Benzene10.441 0.004 78.11 0.34407455 0.012690488 0.004366474 0.004366474Toluene10.441 0.004 92.14 0.4058767 0.014969935 0.006075948 0.006075948Xylenes10.441 0.004 106.17 0.46767885 0.017249381 0.008067171 0.0080671712,2,4Trimethylpentane0.000 0.000 114.23 0 0 0 0Total100.00 1.0027.11 1.04 0.02VOCWeightFraction 0.38HAPWeightFraction 0.04VOCWeight%3.84HAPWeight%0.07Notes:Bolditemsareconsideredvolatileorganiccompounds(VOCs).MolepercentagesarebasedonthegasanalysisreportfromtheEthanHall6B‐31‐30‐1Hfacility,dated02/14/2011,asanalyzedbySatheAnalyticalLaboratory,Inc.ofofWilliston,NorthDakota.1MolepercentagesforHexanes+,benzene,tolueneandxylenesareofequalvaluebasedonaHexanes+resultof1.762asnoextendedgasanalysisavailable.TreaterGasAnalysisWorksheet

## Decline Factor Supporting DocumentationDecline Over First 12 Months

= (1

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

Decline Factor (facility

‐ specific)

= Average Production Over 12 Month Period / 1st Month of Production

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

Representative Decline Fa ctor for

the Formation= 0.459026

Burr

Prod_Month BOPD

Mar

‐ 09 6238

Apr

‐ 09 4092

May

‐ 09 4104

Jun

‐ 09 3552

Jul

‐ 09 3324

Aug

‐ 09 2854

Sep

‐ 09 2593

Oct

‐ 09 2414

Nov

‐ 09 2162

Dec

‐ 09 2151

Jan

‐ 10 2053

Feb

‐ 10 1775

Decline over the first 12

‐ months 0.715454

First Month's Production 6238

Last Month's Production 1775

Average BOPD 3109.333

Decline factor 0.49845

Four Bears

Dec

‐ 08 7473

Jan

‐ 09 3645

Feb

‐ 09 3873

Mar

‐ 09 4167

Apr

‐ 09 3148

May

‐ 09 3490

Jun

‐ 09 2820

Jul

‐ 09 2737

Aug

‐ 09 2444

Sep

‐ 09 2291

Oct

‐ 09 1778

Nov

‐ 09 2495

Decline over the first 12

‐ months 0.666131

First Month's Production 7473

Last Month's Production 2495

Average BOPD 3363.417

Decline factor 0.450076

Fredericks 5

Oct

‐ 08 11838

Nov

‐ 08 4545

Dec

‐ 08 5793

Jan

‐ 09 5012

Feb

‐ 09 3909

Mar

‐ 09 3706

Apr

‐ 09 3573

May

‐ 09 3334

Jun

‐ 09 3042

Jul

‐ 09 2886

Aug

‐ 09 2762

Sep

‐ 09 2465

Decline over the first 12

‐ months 0.791772

First Month's Production 11838

Last Month's Production 2465

Average BOPD 4405.417

Decline factor 0.372142 The decline factor was determined by following the method described in Appendix E of the North Dakota Air Pollution Control Permitting

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

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

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

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

4. Calculate the decline factor for that facility by applying the following formula: Enerplus Resources (USA) Corporation

Decline Factor Calculation

0 1000 2000 3000 4000 5000 6000 7000

Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10

0 1000 2000 3000 4000 5000 6000 7000 8000

Sep

‐ 08 Dec

‐ 08 Mar

‐ 09 Jul

‐ 09 Oct

‐ 09 Jan

‐ 10

0 2000 4000 6000 8000 10000 12000 14000

Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09Enerplus Resources (USA) Corporation

Decline Factor Calculation

Fredericks 6

Mar

‐ 09 6852.7

Apr

‐ 09 4388

May

‐ 09 5106

Jun

‐ 09 4388

Jul

‐ 09 3549

Aug

‐ 09 3073

Sep

‐ 09 2812

Oct

‐ 09 2570

Nov

‐ 09 2318

Dec

‐ 09 1735

Jan

‐ 10 2307

Feb

‐ 10 1739

Decline over the first 12

‐ months 0.746231

First Month's Production 6852.7

Last Month's Production 1739

Average BOPD 3403.142

Decline factor 0.496613

Tekakwitha

May

‐ 08 12498

Jun

‐ 08 6761

Jul

‐ 08 6635

Aug

‐ 08 7139

Sep

‐ 08 5283

Oct

‐ 08 4743

Nov

‐ 08 3854

Dec

‐ 08 4039

Jan

‐ 09 3649

Feb

‐ 09 2938

Mar

‐ 09 3614

Apr

‐ 09 2964

Decline over the first 12

‐ months 0.762842

First Month's Production 12498

Last Month's Production 2964

Average BOPD 5343.083

Decline factor 0.427515

Voigt 11

Aug

‐ 08 8107.6

Sep

‐ 08 4929

Oct

‐ 08 3423

Nov

‐ 08 6889

Dec

‐ 08 4670

Jan

‐ 09 3979

Feb

‐ 09 3129

Mar

‐ 09 3220

Apr

‐ 09 2823

May

‐ 09 2857

Jun

‐ 09 2562

Jul

‐ 09 2464

Decline over the first 12

‐ months 0.696088

First Month's Production 8107.6

Last Month's Production 2464

Average BOPD 4087.717

Decline factor 0.504183

Voigt 21

Jul

‐ 08 16424

Aug

‐ 08 4804

Sep

‐ 08 8111

Oct

‐ 08 7384

Nov

‐ 08 5169

Dec

‐ 08 5160

Jan

‐ 09 4610

Feb

‐ 09 3619

Mar

‐ 09 3903

Apr

‐ 09 3336

May

‐ 09 3419

Jun

‐ 09 3120

Decline over the first 12

‐ months 0.810034

First Month's Production 16424

Last Month's Production 3120

Average BOPD 5754.917

Decline factor 0.350397 0 1000 2000 3000 4000 5000 6000 7000 8000

Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10 Mar

‐ 10

0 2000 4000 6000 8000 10000 12000 14000

Apr

‐ 08 Jun

‐ 08 Jul

‐ 08 Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Jun

‐ 08 Jul

‐ 08 Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

Jun

‐ 08 Jul

‐ 08 Sep

‐ 08 Oct

‐ 08 Dec

‐ 08 Feb

‐ 09 Mar

‐ 09 May

‐ 09 Jul

‐ 09Enerplus Resources (USA) Corporation

Decline Factor Calculation

Woman Creek

May

‐ 09 6123

Jun

‐ 09 4204

Jul

‐ 09 4558

Aug

‐ 09 3452

Sep

‐ 09 3379

Oct

‐ 09 3092

Nov

‐ 09 2572

Dec

‐ 09 2494

Jan

‐ 10 2296

Feb

‐ 10 1949

Mar

‐ 10 2030

Apr

‐ 10 1810

Decline over the first 12

‐ months 0.704393

First Month's Production 6123

Last Month's Production 1810

Average BOPD 3163.25

Decline factor 0.516618

TSB

Jul

‐ 09 17132.67

Aug

‐ 09 13068.9

Sep

‐ 09 10498.9

Oct

‐ 09 7647.33

Nov

‐ 09 9522.55

Dec

‐ 09 7606.9

Jan

‐ 10 4596.83

Feb

‐ 10 8671.98

Mar

‐ 10 7834.86

Apr

‐ 10 6425.9

May

‐ 10 6638.86

Jun

‐ 10 6283.47

Decline over the first 12

‐ months 0.633246

First Month's Production 17132.67

Last Month's Production 6283.47

Average BOPD 8827.429

Decline factor 0.51524 0 1000 2000 3000 4000 5000 6000 7000

Mar

‐ 09 May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10 Mar

‐ 10 May

‐ 10

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

May

‐ 09 Jul

‐ 09 Aug

‐ 09 Oct

‐ 09 Dec

‐ 09 Jan

‐ 10 Mar

‐ 10 May

‐ 10 Jun

‐ 10

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

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

. The area under the line

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

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

BOX 1 BOX 2

BOX 3 BOX 4

The smoothed curve is straightened out in BOX 3

, and then leveled out in BOX 4

. Now the production for the

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

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

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

‐ day average production rate is multiplied by 0.6.

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

year, the well will make 0.667 MMCFD at the end of the first year (3.333

– 0.8(3.333)

= 0.667). Then the

average daily production rate over 365 days is (3.33 + 0.667)/2

= 2.0 MMCFD which is the same as 3.333 x 0.6

= 2.0 MMCFD. Start Up 365 Days

MMCFD

Actual production during the first year is

represented by the area under the jagged line

which ultimately turns out to be ~730 MMCF. Start Up 365 Days

The jagged line representing daily production is

“smoothed” out usin g statistical methods.

Start Up 365 Days Start Up 365 Days

2 MMCFD

Leveled” out, projected daily gas production

rate vs. time

Total projected production for the first year is

represented by the area under the straight line

2 MMCFD x 365 days = 730 MMCF The “smoothed” curve in BOX 2 is “straightened” out

using mathematical methods.

## Enerplus Resources (USA) Emission Calculator Supporting Documentationi 

### Table of Contents

Introduction

.................................................................................................................................................. 1

Unique Issues with Bakken Pool VOCs

.......................................................................................................... 1

Potential to Emit

........................................................................................................................................... 1

Emission Factors

........................................................................................................................................... 1

Regulated Air Pollutant Sources

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

Emission Calculation

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

Emission Calculation Procedure

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

Production Data

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

Decline Factor Calculation Steps

........................................................................................................... 3

Oil/Condensate Tank Data

........................................................................................................................ 3

Treater Gas Da ta

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

Treater Burner(s) Data

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

Smokeless Combustion Devices (Flares)

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

Truck Loading Data

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

Pneumatic Pumps Data

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

Pneumatic Pump Controls

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

Pneumatic Controllers Data

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

Glycol Dehydrator Data

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

Calculating Glycol Dehydrator Emissions

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

Glycol Dehydrator Control Threshold

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

Glyco l Dehydrator Controls

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

Glycol Dehydrator Federal Regulations

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

RICE Data Input

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

Federal Regulations for RICE

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

Gas Analysis Worksheet Input

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

E&P Tanks v2.0 Input

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

### Acronyms and Abbreviations

AP

‐ 42 EPA Publication AP

‐ 42, Compilation of Air Pollutant

Emission Factors (5th Edition)

bbl barrel

BOPD barrels of oil per day

BTEX benzene/toluene/ethyl

‐ benzene/xylenes

Btu British thermal unit

Btu/hr Btu per hour

CO carbon monoxide

DRE destruction and removal efficiency

EF emission factor

Enerplus Enerplus Resources (USA) Corporation

EPA Environmental Protection Agency

gpm gallons per minute

H 2 S hydrogen sulfide

HAP hazardous air pollutants

hp horsepower

lb pound

lb/lb

‐ mole pound per pound mole

LACT Lease Automatic Custody Transfer

MMBtu one million Btu

MMscf one million standard cubic feet (scf × 106)

MMscfd 1,000,000 scf per day

Mscf one thousand standard cubic feet (scf × 1000)

Mscfd 1000 scf per day

NDDoH North Dakota Department of Health

NESHAP National Emission Standards for Hazardous Air Pollutants

NOx nitrogen oxides

NSCR Non

‐ Selective Catalytic Reductioniii NSPS New Source Performance Standards

O&G Oil and Gas

PSD Prevention of Significant Deterioration

psig pounds per square inch gauge

psia pounds per square inch absolute

PTE potential to emit

RICE reciprocating internal combustion engine

scf standard cubic foot

scf/bbl standard cubic foot per barrel

SO 2 sulfur dioxide

S/W/B standing/working/breathing losses

TEG tri

‐ ethylene glycol

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

TOC total organic compounds

TPY tons per year

VOC volatile organic compounds1 

## Introduction

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

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

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

b) The construction of a new facility.

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

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

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

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

‐ construction air permitting,

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

‐ construction and completion. This

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

To accommodate th e need for registration pre

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

a conservative approach to emission calculations for the start

‐ up of new exploration and production facilities, and the

modification of existing facilities.

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

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

included in the calculations.



## Unique Issues with Bakken Pool VOCs

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

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

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

‐ Bakken VOC Task Force and i ndustry have created

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

‐ specific data is

unavailable.



## Potential to Emit

The federal regulations define "potential to emit" as:

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

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

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

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

would have on emissions is federally enforceable.”

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

‐ control for

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



## Emission Factors

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

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

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

Standards (OAQPS) AP

‐ 42 emission factors. The AP

‐ 42 is maintained by th e Emission Factor and Inventory Group (EFIG)

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

http://www.epa.gov/ttn/c hief/ap42/index.html

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

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



## Regulated Air Pollutant Sources

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

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

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

a) Oil/Condensate Tanks

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

b) Treater Flares

– VOC, HAP, NO x, CO, H2S, SO2

c) Heaters/Burners

– VOC, HAP, NOx, CO, SO2

d) Truck Loading

– VOC, HAP

e) RICE Engines

– VOC, HAP, NOx, CO

f) Pneumatic Pumps

– VOC, HAP

g) Pneumatic Controllers

– VOC, HAP



## Emission Calculation

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

a simple way of calculating facility

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

to those currently applied in states bordering the facility locations.

The Ener plus Emission Calculations Workbook contains the following 10 tabs:

a) Input

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

tab.

b) RICE Input

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

c) Emission Summary

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

1) Oil/Condensate Tanks

– The tank vapor emissions are calculated here.

2) Equipment Leaks

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

3) Treater Flare

– The treater flare emissions are calculated here.

4) Treater Burner

– Th e treater burner emissions are calculated here.

5) Truck Loading

– The truck loading emissions are calculated here.

6) RICE

– The RICE emissions are calculated here.

7) Pneumatic Pump

– The pneumatic pump emissions are calculated here.

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



## Emission Calculation Procedure

The calculation workbook was completed per the detailed process below:



### Production Data

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

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

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

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

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

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

than 18 months shall use a decline factor of 1.

Decline Factor Calculation Steps

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

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

Decline Over First 12 Months

= (1

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

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

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

Decline Factor (facility

‐ specific)

= Average Production Over 12 Month Period/ 1 st Month of Production

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

formation.

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

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

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

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

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



### Oil/Condensate Tank Data

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

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

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

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

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

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

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

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

emissions.

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

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

the molecular weight, lower heating value of the fuel and the VOC, HAP, CH 4 , and CO 2 weight fractions of the tank

vapors to calculate the tank vapor emissions.

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

emission factor (scf/bbl).

1) Default Bakken EF

. 2) Site Specific Direct Measurement.

3) Representative Average.4 Line 9: Enter the scf/bbl EF based on the method chosen on Line 8.

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

applied.

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

from direct measurement is applied.

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

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

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

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

‐ mole (lb/lb

‐ mole), taken from E&P Tank V2

Emission Summary.

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

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

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

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

Line 17: The H 2 S weight percent of the tank vapors. Taken from E&P Tank V2 Emission Summary.

Line 18: The H 2 S mole percent of the tank vapors. Taken from E&P Tank V2 Emission Summary.

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

1) Vapor Recovery Unit or Oil Stabilizer

2) Enclosed Smokeless Combustor

3) Utility Flare or Other 98% DRE Device

4) Ground Pit Fl are or other 90% DRE device

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

1) Vapor Recovery Unit or Oil Stabilizer

= 99% DRE

2) Enclosed Smokeless Combustor

= 98% DRE

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

4) Ground Pit Fl are or other 90% DRE device

= 90% DRE



### Treater Gas Data

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

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

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

2) VOC, HAP, CH 4 , and CO 2 weight fraction of the treater gas.

3) H2S mole percent of the treater gas.

4) Lower heating value of the treater gas.

5) Average molecular weight of the treater gas5 6) NOx & CO emissions are based on AP

‐ 42 emission factors for industrial flares.

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

gas shall be routed to a control system or device.

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

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

‐ mole.

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

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

Enter this value on Line 22.

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

percent of the gas.

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

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

.

Line 27: Enter the H 2 S weight percent of the well stream gas.

Line 28: Enter the H 2 S mole percent of the well stream gas.

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

options:

1) Enclosed Smokeless Combustor

2) Utility Flare or other 98% DRE Device

3) Ground Pit Flare or other 90% DRE devi ce

4) Connected to Sales Line

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

1) Enclosed Smokeless Combustor

= 98% DRE

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

3) Ground Pit Flare or other 90% DRE devi ce = 90% DRE

4) Connected to Sales Line = 100% DRE



### Treater Burner(s) Data

Lines 31

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

typically calculated using AP

‐ 42 emission factors. The AP

‐ 42 factors can be found at

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

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



##        

 





 100 100

200010

100 10

Pr

6 6 

### DRE

HV HV

HV B HO BREF

E

Avg od

Avg EFF X

X

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

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

BR = burner rating (MMBtu/hr);

B Eff = burner efficiency (%);

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

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

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

DRE = destruction and removal efficiency (%);

1

‐ ton = 2000

‐ lb;

1

‐ MMBtu = 10 6

‐ Btu; and

1

‐ MMscf

= 10 6

‐ scf.

Potential emissions must be calculated based on 8,760

‐ hrs/yr and using the manufacturer's maximum rated design

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

uncontrolled emissions, the DRE is zero.

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

NOx, CO, VOC, HAP & SO 2 emissions from process unit heaters are calculated within the Oil & Gas Facility Emission

Calculation Workbook using the emission factors (EF) below from EPA AP

‐ 42, Tables 1.4

‐ 1, 1.4

‐ 2 and 1.4

‐ 3:

Table 1.4

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

‐ 42, Tables 1.4

‐ 1, 1.4

‐ 2 and 1.4

‐ 3)

Poll utant Natural Gas EF*

NOx 100 lb/MMscf

CO 84 lb/MMscf

VOC 5.5 lb/MMscf

HAPS 1.89 lb/MMscf

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

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

enter the total heat input of all burners.

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



### Smokeless Combustion Devices (Flares)

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

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

‐ 42 Chapter 13.5:

Miscellaneous Sources

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

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

table. Calculations must be performed assuming TOC concentration is equivalent to total VOC concentration. NO X , CO,

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

### 2000 HVFCEF

E X

X 

### 



where:

E X = emissions for pollutant X (tpy);

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

FC = fuel consumption (MMscf/yr);

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

1

‐ ton = 2000

‐ lb.

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



### 24 HO DPR FC GAS 

### 



where:

FC = fuel consumption (MMscf/yr);

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

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

1

‐ day

= 24

‐ hours.

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

maximum daily production capacity for 8760

‐ hrs/yr.



### Truck Loading Data

Lines 32

‐ 38: Loading losses occur as hydrocarbon vapors in the empty tank are displaced to the atmosphere as the

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

‐

42 Chapter 5.2

– Transportation and Marketing of Petroleum Liquids (see

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

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

operation. The equation for estimating loading loss is:



### 460 46.12

 

 T MPS L

L

where:

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

‐ gal);

S = saturation factor (unitless) (AP

‐ 42, Table 5.2

‐ 1);

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

‐ 42, Table 7.1

‐ 2);

M = molecular weight of tank vapors (lb/lb

‐ mole) (AP

‐ 42 Table 7.1

‐ 2); and8 T = temperature of bulk liquid loaded (°F) (oR

= oF + 460).

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



### 2000 42365 

 OIL L

X 

### DPRL E

where:

E X = emissions for pollutant X (tpy);

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

‐ gal);

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

1

‐ year = 365

‐ days;

1

‐ bbl

= 42

‐ gallons; and

1

‐ ton = 2000

‐ lb.

Table 5.2

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

‐ 42, Table 5.2

‐ 1)

Tank Truck: Mode of Operation* S Factor

Submerged loading of a clean cargo tank 0.50

Submerged loading: dedicated normal service 0.60

Submerged loading: dedicated vapor balance service 1.00

Table 7.1

‐ 2 Properties of Selected Petroleum Liquids (Excerpt from AP

‐ 42, Table 7.1

‐ 2)

Petroleum

Liquid

Crude Oil

RVP 5 Vapor MW at 60 F

MV(lb/lb

‐ mole)

50 Condensed Vapor Density

at 60F WVC(lb/gal)

4.5 Liquid Density at

60F WL(lb/gal)

7.1 True Vapor Pressure, Pva (psi)

at various temperatures in F

40 50 60 70 80 90 100

1.8 2.3 2.8 3.4 4.0 4.8 5.7

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

or device due to safety concerns.

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

Custody Transfer, no input values are required in Lines 34

‐ 39.

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

selected based on mode of operation.

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

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

on the Tru ck Loading tab.

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

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

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

average annual temperature.

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

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

### Pneumatic Pumps Data

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

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

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

b) The VO C & HAP weight fraction of the motive gas

c) Molecular weight of motive gas

d) Hours of operation

Pneumatic Pump Controls

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

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

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

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

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

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

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

Pneumatic Controllers Data

Lines 45

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

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

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

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

c) Molecular weight of fuel gas

d) Hours of operation

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

‐ on controls for emissions from these types of

devices.

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

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



### Glycol Dehydrator Data

Lines 47

‐ 48 : Glycol, usually tri

‐ ethylene glycol (TEG), is used in dehydration units to absorb water from wet produced

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

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

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

Calculating Glycol Dehydrator Emissions

GRI

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

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

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

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

the Emission Calculation Workbook.10 Glycol Dehydrator Control Threshold

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

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

Glycol Dehydrator Controls

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

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

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

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

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

weight.

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

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

‐ GLYCalc run with new calculations shall be submitted with a

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

Glycol Dehydrator Federal Regulations

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

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

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

0).

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

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

0).



### RICE Data Input

Lines 1

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

Internal combustion engine emissions were estimated using the following equation:



##        

  

 100 100

2000 DRE HOEREF

E X

X

where:

E X = emissions for pollutant X (tpy);

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

‐ hr or lb/MMBtu);

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

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

DRE = destruction and removal efficiency (%); and

1

‐ ton = 2000

‐ lb.

Potential emissions were calculated based on 8760

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

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

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

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

‐ 12

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

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

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

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

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

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

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

‐ 42 factor in lb/hp

‐ hr for CO 2

.

Line 9: Enter the manufacturer’s emission factor, actual test results or Subpart W factor in kg/mmBtu for CH 4

.

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

manufacturer data or actual test results.

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

manufacturer data or actual test results.

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

manufacturer data or actual test results.

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

### cility.

Federal Regulations for RICE

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

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

http://ecfr.gpoaccess.gov

.

40 CFR 60, Subpart IIII

– Standards of P erformance for Stationary Compression Ignition Internal Combustion Engines :

Applies to any compression

‐ ignition internal combustion engine where construction is commenced after July 11, 2005

and the engine is manufactured after April 1, 2006.

40 CFR 60, Subpart JJJJ

– Standards of Performance for Stationary Spark Ignition Internal Combustion Engines: Applies to

any spark

‐ ignition internal combustion e ngine where construction is commenced after June 12, 2006 and the engine is

manufactured:

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

2) After January 1, 2008 for lean

‐ burn engines 500 < hp < 1350

3) After July 1, 2008 for engin es < 500 hp

4) After January 1, 2009 for emergency engines

40 CFR 63, Subpart ZZZZ

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

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

area source of HAPs.



### Gas Analysis Worksheet Input

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



### E&P Tanks v2.0 Input

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

# Attachment E

Qualitative Air Quality AnalysisEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

E

‐ 1 

## Qualitative Air Quality Impact Analysis

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

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

performed based on the following items:

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

are insignificant.

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

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

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

region.

# Attachment F

Synthetic Minor Limit RequestEnerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

F

‐ 1 

## S YNTHETIC 

## M INOR 

## L IMIT 

## R EQUEST 

## G ENERAL 

## I NFORMATION

Company Name

Enerplus Resources (USA) Corporation Facility Name

Hans

Company Contact or Owner Name

Tony Lucero Title

EHS Coordinator

Mailing Address

US Bank Tower, Suite 2200

950

‐ 17th Street

Denver, CO 80202

‐ 2805

Email Address

tlucero@enerplus.com

Telephone Number

(720) 279

‐ 5500 Facsimile Number

(720) 279

‐ 5550Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

F

‐ 2 

## P ROPOSED 

## L IMITATION AND 

## E FFECT ON THE 

## P OTENTIAL TO 

## E MIT

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

‐

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

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

Operating Permit.

Requested Limitation. To limit this facility’s potential to emi t, Enerplus is requesting the following:

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

emission control equipment; and

2) A production limit of 1,820 BOPD.

Selection of a control device will occur nearer to the time the facility commences construction as

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

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

affecting the cumulative production rates and combustion unit sizing);

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

conservative average herein); and

 Combustion unit availability closer to the ti me of well construction.

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

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

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

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

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

HAPs for approval prior to installation.

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

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

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

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

this facility.Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

F

‐ 3 

## M ONITORING



## , R ECORDKEEPING AND 

## R EPORTING



### Facility

‐ Wide Emissions

Monitoring. Facility

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

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

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

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

1) Actual rolling monthly fac ility

‐ wide hydrocarbon production rate; and

2) Process units and emission control devices used.



### Control Device for VOC and HAP Emissions

Monitoring. Control device operations will be inspected periodically to confirm proper

operation as follows:

1) Continuous monitoring of the flame using a thermocouple and a data acquisition device

indicating continuous ignition of the flame;

2) Periodic check of the chart recorder to insure proper operation, at a minimum

performed quarterly;

3) Periodic chec k of the flame to insure proper operation, at a minimum performed

quarterly; and

4) Visual confirmation of smokeless operation of any enclosed combustor process or

temporary/emergency flare, at a minimum performed quarterly.

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

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

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

preventative measures adopted to avoid such bypasses or downtime.

2) Instances in which visible emissions are observed emanating from an enclosed

combustor process or temporary/emergency flare.

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

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

include the following information:

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

2) The results of such analyses or measurements.Enerplus Resources (USA) Corporation

Application for New Construction

Facility: Hans

F

‐ 4 

### Natural Gas Fired External Combustion Units

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

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

stabilizers, tank heaters, etc.

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

combustion units:

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

installed at the facility; and

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

# Attachment G

Equipment Specifications and Guarantees

# Emission Control System Warranty

Your new Honda Power Equipment e ngine complies with the U.S. EP A, Environment Canada , and State of Califo rnia emission regulati ons (models

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

territories. Honda Cana da Inc. provides the emission warra nty for engines in the 13 provinces and territories of Canada. In the remainder of this Emission

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

YOUR WARRANTY RIGHTS AND OBLIGATIONS:

California

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

In California, new spark-ignited small off-ro ad equipment engines must be designed, bui lt, and equipped to meet the State's str ingent anti-smog

standards.

Other States, U.S. territories, and Canada

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

emission standards for spark-ignited engine s at or below 19 kilowatts. Specific Ho nda products that do not meet the California emissions regulations

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

All of the United States and Canada

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

neglect, or improper main tenance of your power equipment engi ne. Where a warrantable condition ex ists, Honda will repair your p ower equipment

engine at no cost to you includi ng diagnosis, pa rts, and labor.

Your emission control system may include su ch parts as the carburetor or fuel inje ction system, the igni tion system, and cataly tic converter. Also

included may be hoses, connecto rs, and other emission-related assemblies (see page 2 fo r additional covered parts).

OWNER'S WARRANTY RESPONSIBILITY:

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

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

the lack of receipts or for your failure to ensu re the performance of al l scheduled maintenance.

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

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

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

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

If you have any questions regarding your emission warranty rights and res ponsibilities, you s hould contact the Honda office in your region:

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

to the original retail purchaser or the leng th of the Honda Distributor’s Limited Warra nty, whichever is longer. This warranty is transferable to each

subsequent purchaser for the duration of the warranty period.

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

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

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

only.

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

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

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

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

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

claim will not be denied.

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

October 2009

Page 1 of 2 American Honda Motor Co., Inc.

Power Equipment Cu stomer Relations

4900 Marconi Drive

Alpharetta, Georgia 30005-8847

Telephone: (888) 888-3139

Email: powerequipmente missions@ahm.honda.com or Honda Canada Inc.

Power Equipment Cu stomer Relations

Visit www.honda.ca

for contact information.

Telephone: (888) 946-6329



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

# Emission Control System Warranty

TO OBTAIN WARRANTY SERVICE:

You must, at your own expe nse, take your Honda Power Equipm ent engine or the product on which it is installed, along with your sales registration card

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

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

engine was not properly maintained and used.

If you are unable to obtain emission warranty se rvice or are dissatisfied with the warranty service you received, contact the o wner of the dealership

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

EXCLUSIONS:

Failures other than those resulting from defe cts in material or workmanship are not co vered by this warranty. This warranty doe s not extend to emission

control systems or parts that are affected or damaged by owner abuse, neglect, improper maintenance, misuse, misf ueling, improp er storage, collision, the

incorporation of, or use of, unsui table attachments, or the unaut horized alteration of any part.

This warranty does not cover repl acement of expendable maintenance items made in connection with required maintenance service a fter the item’s first

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

Disclaimer of Consequential Damage a nd Limitation of Im plied Warranties:

American Honda Motor Co., Inc. and Honda Canada Inc. disclaim any responsibility for in cidental or conseque ntial damages such a s loss of time or the

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

written warranty. This warranty is applicable only where the Calif ornia, U.S. EPA, or Environment Canada em ission control syste m warranty regulation

is in effect.

EMISSION CONTROL SYSTEM WARRANTY PARTS:

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

October 2009

Page 2 of 2 American Honda Motor Co., Inc.

Power Equipment Customer Relations

4900 Marconi Drive

Alpharetta, Georgia 30005-8847

Telephone: (888) 888-3139

Email: powerequipmente missions@ahm.honda.com or Honda Canada Inc.

Power Equipment Cu stomer Relations

Visit www.honda.ca

for contact information.

Telephone: (888) 946-6329

SYSTEMS COVERED

BY THIS WARRANTY: PARTS

DESCRIPTION:

Fuel Metering Carburetor assembly (includes starting en richment system),

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

Evaporative Fuel tank, Fuel cap, Fu el hoses, Vapor hoses, Carbon ca nister, Canister mounting brackets,

Fuel strainer, Fuel cock, Fuel pump, Fu el hose joint, Canist er purge hose joint

Exhaust Catalyst, Exhaust manifold

Air Induction Air filter hous ing, Air filter element*

Ignition Flywheel magneto, Ignition pulse gene rator, Crankshaft position sensor,

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

Crankcase Emission Cont rol Crankcase breather tube, Oil filler cap

Miscellaneous Pa rts Tubing, fittings, seals, ga skets, and clamps associated with these listed systems.

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

manufacturer’s emissions wa rranty for non-Honda parts.

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

PWL50975-MUNITED STATES ENVIRONMENTAL PROTECTION AGENCY2011 MODEL YEARCERTIFICATE OF CONFORMITYWITH THE CLEAN AIR ACT OF 1990OFFICE OF TRANSPORTATIONAND AIR QUALITYANN ARBOR, MICHIGAN 48105Certificate Issued To: Power Solutions International(U.S. Manufacturer or Importer)Certificate Number: BPWRB11.1NGP-002Effective Date:01/03/2011Expiration Date:12/31/2011_________________________Karl J. Simon, DirectorCompliance and Innovative Strategies DivisionIssue Date:01/03/2011Revision Date:N/AManufacturer:Power Solutions InternationalEngine Family:BPWRB11.1NGPCertificate Number:BPWRB11.1NGP-002Certification Type:Mobile and StationaryFuel :LPG/PropaneNatural Gas (CNG/LNG)Emission Standards :NMHC + NOx ( g/kW-hr ) : 2.7CO ( g/kW-hr ) : 4.4HC + NOx ( g/kW-hr ) : 2.7CO ( g/Hp-hr ) : 2VOC ( g/Hp-hr ) : 0.7NOx ( g/Hp-hr ) : 1Emergency Use Only :NPursuant to Section 213 of the Clean Air Act (42 U.S.C. section 7547) and 40 CFR Part 1048, 40 CFR Part 60, 1065, 1068, and 60 ( stationary only and combined stationary and mobile ) and subject to theterms and conditions prescribed in those provisions, this certificate of conformity is hereby issued with respect to the test engines which have been found to conform to applicable requirements and whichrepresent the following nonroad engines, by engine family, more fully described in the documentation required by 40 CFR Part 1048, 40 CFR Part 60 and produced in the stated model year.This certificate of conformity covers only those new nonroad spark-ignition engines which conform in all material respects to the design specifications that applied to those engines described in thedocumentation required by 40 CFR Part 1048, 40 CFR Part 60 and which are produced during the model year stated on this certificate of the said manufacturer, as defined in 40 CFR Part 1048, 40 CFR Part60. This certificate of conformity does not cover nonroad engines imported prior to the effective date of the certificate.It is a term of this certificate that the manufacturer shall consent to all inspections described in 40 CFR 1068.20 and authorized in a warrant or court order. Failure to comply with the requirements of such awarrant or court order may lead to revocation or suspension of this certificate for reasons specified in 40 CFR Part 1048, 40 CFR Part 60. It is also a term of this certificate that this certificate may be revokedor suspended or rendered voidab initiofor other reasons specified in 40 CFR Part 1048, 40 CFR Part 60.This certificate does not cover large nonroad engines sold, offered for sale, or introduced, or delivered for introduction, into commerce in the U.S. prior to the effective date of the certificate.

### Source Emissions Test Report

Cimarron Energy, Inc.

Flare Stack

Inlet and Outlet NMOC Emissions

Parshall, North Dakota

Report prepared for: Report prepared by:

Cimarron Energy, Inc.

1012 24 th 

### Avenue, Suite 100

Norman, Oklahoma 73069

Marcus Manning

Portable Division Director

Test Date:

June 14 - 15, 2011

APT Project: CIM1122

## T able of Contents

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

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

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

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

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

Tables

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

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

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

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

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

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

Appendices

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

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

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

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

Test Report – Cimarron Energy Parshall Flare



### page 1 1. Introduction

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

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

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

emission rates of oxygen (O 2 

### ), carbon dioxide (CO 2 

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

(CH 4 

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

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

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

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

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

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

oz. and 10 oz. inlet feed pressures.

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

Cimarron Energy, Inc.: Parshall Flare

Testing Program Contact Personnel

Name, Title Company Address Phone, FAX, email

Mr. Michael John,

Process Engineer Cimarron Energy, Inc.

1012 24 th Ave NW, Suite 100

Norman, Oklahoma 73069 405-928-7373 ext. 111,

405-928-7379

mjohn@cimarron.com

Mr. Dave Maiers,

Operations Director Air Pollution Testing, Inc.

5530 Marshall Street

Arvada, Colorado 80003 303-420-5949,

303-420-5920,

dmaiers@airtest.net



### Table 1.1: Testing Program Contact Personnel

2. Methods

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

methods referenced in 40 CFR Part 60, Appendix A

.

Method 1 – Sample and Velocity Traverses for Stationary Sources

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

Pitot Tube)

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

Excess Air

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

Test Report – Cimarron Energy Parshall Flare



### page 2 Method 10 – Determination of Carbon Monoxide Emissions from Stationary Sources

Method 18 – Measurement of Gaseous Organic Compound Emissions by Gas

Chromatography

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

Ionization Analyzer

3. Test Program Summary

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

parameters detailed in Table 3.1 on the following page.

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

pressure from the flare exhaust to determine pollutant concentrations. Concentration

data were combined with concurrently collected oxygen (O 2 

### ), carbon dioxide (CO 2 

### ),

moisture (H 2 

### O) and gas velocity data to determine pollutant mass emission rates.

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

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

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

Cimarron Energy, Inc. – Parshall Flare

Sampling and Analytical Methods

Gas Parameter EPA Method Analytical Method Laboratory

Enclosed Flare Exhaust Measurements

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

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

analyzers

H 2 O Method 4 gravimetric

CO Method 10 gas filter correlation, infrared analyzer

NMOC Method 25A flame ionization detector with methane

separation – Thermo Model 55 APT,

on-site

C 2 H 6 Method 18 gas chromatography APT, Arvada, CO

Condensate Tank Waste Gas Measurements (Flare Inlet)

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

on-site

VOC, NMOC ASTM D1945/1946 gas chromatography / flame ionization

detector / thermal conductivity detector Empact Analytical,

Brighton, CO

Flare Pilot / Assist Gas Measurements (Flare Inlet)

gas flow Orifice Manufacturer provided constant value APT,

on-site

VOC, NMOC ASTM D1945/1946 gas chromatography / flame ionization

detector / thermal conductivity detector Empact Analytical,

Brighton, CO



### Table 3.1: Sampling and Analytical MethodsAPT Project: CIM1122

Test Report – Cimarron Energy Parshall Flare



### page 3 4. Test Method Details

4.1. Stack Gas Velocity, Volumetric Flow Rate and Moisture

Stack gas velocity, volumetric flow rate and moisture (H 2 

### O) content were measured in

accordance with EPA Methods 1, 2 and 4.

Each sampling period consisted of conducting a temperature and differential pressure

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

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

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

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

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

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

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

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

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

gravimetrically to determine the moisture content of the gas.

All of the above data were combined with concurrently collected diluent (O 2 

### and CO 2 

### )

data to calculate the stack gas velocity and volumetric flow rate in units of feet per

second (ft/sec), actual cubic feet per minute (acfm), dry standard (1 atmosphere and

68°F) cubic feet per minute (dscfm), and pounds per hour (lb/hr).

4.2. Diluent, Carbon Monoxide and Non-methane Hydrocarbons – Flare Exhaust

O 2 

### , CO 2 

### , CO and NMOC emission concentrations were measured in accordance with

EPA Methods 3A (O 2 

### and CO 2 

### ), 10 (CO) and 25A (NMOC).

Each sampling period consisted of extracting a gas sample from the stack at a constant

flow rate of approximately three liters per minute (lpm). The sample passed through a

refrigeration-type gas conditioner to remove moisture and into the sampling port of a

TECO Model 48H gas filter correlation infrared CO analyzer, a Servomex Series 1400

paramagnetic O 2 

### / non-dispersive infrared CO 2 

### analyzer and a Thermo Model 55 flame

ionization analyzer equipped with a methane separator. The gas conditioner was

bypassed for the NMOC analyzer. The gas concentrations were displayed on the

analyzer front panels in units of either parts per million, dry volume basis (ppmvd – CO),

percent, dry volume basis (%vd – O 2 

### and CO 2 

### ), or parts per million, wet volume basis as

propane (ppmvw as C 3 

### H 8 

### – NMOC) and logged to a computerized data acquisition

system (CDAS). Please see Appendix 4 – Schematics for a diagram of the EPA

Methods 3A, 10 and 25A sampling train.

Before and after each sampling period, the analyzers were challenged with calibration

gases to calibrate the instruments, to verify linearity of response, and to quantify zeroAPT Project: CIM1122

Test Report – Cimarron Energy Parshall Flare



### page 4 and span drift for the previous sampling period. The calibration gases were prepared

and certified in accordance with EPA Protocol 1. To ensure no system bias, the

analyzer calibrations were conducted by introducing all gases to the analyzers at the

sampling probe tip at stack pressure.

Following sampling, the CDAS data were averaged in one-minute increments, corrected

for instrumental drift, and reported as average emission concentrations for each

sampling period.

4.3. Total Hydrocarbon / NMOC – Flare Inlets

Methane and NMOC concentrations were measured in accordance with ASTM D-1945

and 1946, which are industry standard analytical methods for analysis of fuel gas type

samples. Samples were collected from each inlet in Tedlar bags for off-site

GC/FID/TCD analysis for C1 – C6+ hydrocarbons, oxygen, carbon dioxide and nitrogen.

The concentration data were combined with the pitot traverse data (condensate waste

gas) or manufacturer data (pilot light) to calculate flare inlet NMOC mass flow to

determine the control efficiency for NMOC.

Laboratory analysis of the waste gas sample indicated high oxygen and nitrogen from

likely sample leakage. The hydrocarbon and carbon dioxide concentrations were

normalized to remove the leakage. DRE was calculated on both a mass flow in/out

basis and by carbon balance.

5. Test Results Summary

The results of the testing are summarized in Tables 5.1 – 5.3. Any emission

parameters not found in the tables may be found in Appendix 1 – Test Parameters . The

following terms are used in the tables:

• %vd – diluent concentration, dry volume percent

• %vw – moisture content, wet volume percent

• dscfm – stack gas flow rate, dry standard (one atmosphere, 68°F) cubic feet per

minute

•  ̊F – temperature, in degrees Fahrenheit

• lb/hr – pollutant mass emission rate, pounds per hour

• ppmvd – parts per million, dry volume basis

• as C 3 

### H 8 

### – as propane

• DRE – destruction removal efficiencyAPT Project: CIM1122

Test Report – Cimarron Energy Parshall Flare



### page 5 Cimarron Energy, Inc. – Parshall Flare

Flare Test Results Summary (06/15/2011) – 1 oz. Inlet Pressure

Run #1 Run #2 Run #3

Start Time 12:34 14:12 15:30

Stop Time 13:34 15:12 16:30 Average

Stack Temp ( ̊F) 936 811 889 879

Stack Flow (MDSCFD) 2,105.3 3,924.0 4,059.4 3,362.4

O 2 (%vd) 18.5 18.3 18.2 18.3

CO 2 (%vd) 1.5 1.7 1.8 1.6

H 2 O (%vw) 4.6 3.9 4.1 4.2

Emission Data

CO (lb/hr) 0.7 1.1 1.0 0.9

CO (tons/year) 3.0 4.6 4.4 4.0

NMOC (ppmvd as C 3 H 8 ) 46.0 69.8 46.0 53.9

NMOC (lb/hr as C 3 H 8 ) 0.46 1.30 0.89 0.89



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

Cimarron Energy, Inc. – Parshall Flare

Flare Test Results Summary (06/14/2011) – 4 oz. Inlet Pressure

Run #1 Run #2 Run #3

Start Time 10:48 12:55 14:14

Stop Time 11:48 13:55 15:14 Average

Stack Temp ( ̊F) 1,320 1,321 1,327 1,323

Stack Flow (MDSCFD) 3,840.5 3,762.7 3,703.7 3,768.5

O 2 (%vd) 16.5 16.6 16.6 16.6

CO 2 (%vd) 2.9 2.8 2.8 2.8

H 2 O (%vw) 4.4 6.2 4.9 5.2

Emission Data

CO (lb/hr) 0.6 0.6 0.6 0.6

CO (tons/year) 2.7 2.7 2.5 2.6

NMOC (ppmvd as C 3 H 8 ) 0.0 2.0 0.4 0.8

NMOC (lb/hr as C 3 H 8 ) 0.00 0.04 0.01 0.01



### Table 5.2: Test Results Summary, Flare Outlet, 4 oz. FlowAPT Project: CIM1122

Test Report – Cimarron Energy Parshall Flare



### page 6 Cimarron Energy, Inc. – Parshall Flare

Flare Test Results Summary (06/14-15/2011) – 10 oz. Inlet Pressure

Run #1 Run #2

Run #3

Start Time 15:31 16:48 08:45

Stop Time 16:31 17:48 09:45 Average

Stack Temp ( ̊F) 1,973 1,992 1,992 1,986

Stack Flow (MDSCFD) 3,386.9 3,373.9 3,607.2 3,456.0

O 2 (%vd) 14.8 14.9 15.1 14.9

CO 2 (%vd) 3.9 3.8 3.8 3.8

H 2 O (%vw) 8.4 5.9 6.8 7.0

Emission Data

CO (lb/hr) 0.2 0.2 0.2 0.2

CO (tons/year) 0.7 0.9 0.7 0.8

NMOC (ppmvd as C 3 H 8 ) 0.3 0.7 0.1 0.4

NMOC (lb/hr as C 3 H 8 ) 0.01 0.01 0.00 0.01



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

Cimarron Energy, Inc. – Parshall Flare

Flare Test Results Summary (06/14-15/2011) – DRE Summary

1 oz. Flow

4 oz. Flow 10 oz. Flow

Waste Gas Inlet

Waste Gas Specific Gravity 1.46 1.44 1.45

Waste Gas Heat Content (BTU) 2,273 2,252 2,308

Waste Gas Flow (MCFD) 41.8 70.6 131.0

Waste Gas Flow (MDSCFD) 37.4 64.8 119.5

NMOC (lb/hr as C 3 H 8 ) 150.6 260.0 489.2

Pilot Inlet

Pilot Light Flow (MCFD) 0.3 0.3 0.3

Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.5 0.5 0.5

Total Inlet NMOC (lb/hr as C 3 H 8 ) 151.0 260.5 489.7

Total Outlet NMOC (lb/hr as C 3 H 8 ) 0.9 0.01 0.01

% DRE(mass flow in/out basis) 99.41 99.99 100.00

% DRE(carbon balance) 98.94 99.99 100.00



### Table 5.4: Test Results Summary, DRE Calculations

# Appendix One : Test Parameters

### 1 oz. Inlet PressureCimarron Energy

Liberty Oil Well

Parshall, ND

Flare

6/15/2011

1 oz.

Run # 7 8 9 Average

Start Time 12:42 14:20 15:41

Stop Time 13:08 14:40 16:06

hrs Hours of Operation / Year 8760 8760 8760 8760

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

√∆ P AVG Inlet Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1150 0.0940 0.1026 0.1039

C P Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84

T S Inlet Stack Temperature (°F) 73 74 73 73

P bar Barometric Pressure (mbar) 936 936 936 936

P bar Barometric Pressure (" Hg) 27.64 27.64 27.64 27.64

Ps Inlet Stack Pressure ('' H 2 O) 1.0 1.0 1.0 1.0

Carbon Dioxide (%vd) 0.3 0.3 0.3 0.3

Methane (%vd) 16.1 14.0 14.8 14.9

Ethane (%vd) 20.4 19.2 19.8 19.8

Propane (%vd) 33.0 32.1 32.9 32.7

Butanes (%vd) 18.9 18.7 19.1 18.9

Pentanes (%vd) 5.3 5.2 5.3 5.3

Hexanes+ (%vd) 2.7 2.5 2.7 2.6

Heat Content (Btu/scf) 2,304 2,224 2,290 2,273

Carbon Dioxide (%vd) 0.5 0.5 0.5 0.5

Methane (%vd) 47.5 47.5 47.5 47.5

Ethane (%vd) 19.2 19.2 19.2 19.2

Propane (%vd) 15.4 15.4 15.4 15.4

Butanes (%vd) 6.1 6.1 6.1 6.1

Pentanes (%vd) 1.5 1.5 1.5 1.5

Hexanes+ (%vd) 0.8 0.8 0.8 0.8

Heat Content (Btu/scf) 1,479 1,479 1,479 1,479

F ACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18

F DSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17

dry Pilot Light NMOC (ppmvd as C 3 H 8 ) 402,167 402,167 402,167 402,167

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

Run # 7 8 9 Average

B

ws Inlet Moisture Content (%/100) - saturated 0.029 0.030 0.029 0.030

M D Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54

M A Inlet Molecular Weight Wet (lb/lb-mole) 35.03 35.01 35.03 35.02

V S Inlet Gas Velocity (ft/sec) 6.1 5.0 5.5 5.5

F ACFM Inlet Gas Flow (acfm) 32 26 29 29

F DSCFM Inlet Gas Flow (dscfm) 29 23 25 26

dry NMOC (ppmvd as C 3 H 8 ) 858,433 835,967 858,533 850,978

lb/hr NMOC (lb/hr as C 3 H 8 ) 168 134 150 151

tpy NMOC (tons/year as C 3 H 8 ) 739 587 659 661 Field Reference Method Data

Waste Gas Data

Reference Method Calculations Pilot Light DataCimarron Energy

Liberty Oil Well

Parshall, ND

Flare

6/15/2011

1 oz.

Run # 1 2 3 Average

Start Time 12:34 14:12 15:30

Stop Time 13:34 15:12 16:30

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Stack Diameter (inches) 42.6 42.6 42.6 42.6

√∆ P AVG Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.0780 0.1380 0.1475 0.1212

C P Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83

T S Stack Temperature (°F) 936 811 889 879

P bar Barometric Pressure (mbar) 936 936 936 936

P bar Barometric Pressure (" Hg) 27.64 27.64 27.64 27.64

Ps Stack Pressure ('' H 2 O) 0.00 0.00 0.00 0.00

Y d Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780

T

m Meter Temperature (°F) 74 78 79 77

V

m Sample Volume (ft 3 ) 37.560 38.015 37.022 37.532

∆ H Orifice Pressure Delta H (" H 2 O) 1.0 1.0 1.0 1.0

V lc Moisture (g) 34.0 28.7 30.1 30.9

O 2 %vd O 2 (%vd) 18.5 18.3 18.2 18.3

CO 2 %vd CO 2 (%vd) 1.5 1.7 1.8 1.6

N 2 %vd N 2 (%vd) 80.0 80.0 80.0 80.0

dry CO (ppmvd) 107.2 89.1 81.4 92.6

wet CH 4 (ppmvw) 18.3 18.0 9.6 15.3

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

Run # 1 2 3 Average

V mstd Sample Volume (dscf) 33.629 33.763 32.850 33.414

V wstd Moisture Volume (scf) 1.60 1.35 1.42 1.46

B

ws Moisture Content (%/100) 0.046 0.039 0.041 0.042

M D Molecular Weight Dry (lb/lb-mole) 28.98 29.00 29.02 29.00

M A Molecular Weight Wet (lb/lb-mole) 28.48 28.58 28.56 28.54

V S Gas Velocity (ft/sec) 7.4 12.4 13.7 11.2

F ACFM Gas Flow (acfm) 4,382 7,386 8,135 6,635

F DSCFM Gas Flow (dscfm) 1,462 2,725 2,819 2,335

lb/hr Gas Flow (lb/hr) 6,791 12,611 13,080 10,827

F

o F

o (unitless) 1.640 1.551 1.499 1.564

lb/hr CO (lb/hr) 0.7 1.1 1.0 0.9

tpy CO (tons/year) 3.0 4.6 4.4 4.0

dry CH 4 (ppmvd) 19.2 17.4 9.2 15.3

lb/hr CH 4 (lb/hr) 0.1 0.1 0.1 0.1

tpy CH 4 (tons/year) 0.3 79.0 42.3 40.5

dry NMOC (ppmvd as C 3 H 8 ) 46.0 69.8 46.0 53.9

lb/hr NMOC (lb/hr as C 3 H 8 ) 0.461 1.3042 0.8903 0.885

tpy NMOC (tons/year as C 3 H 8 ) 2.019 5.712 3.900 3.877

DRE TVOC DRE (%) - carbon balance 98.96% 98.67% 99.19% 98.94% Field Reference Method Data

Reference Method CalculationsCimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 100.0

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

Linearity Bias (Zero) 0.0 0.0 -0.2 1.9 0.0

Linearity Bias (Span) 10.0 2.5 77.0 295.4 31.1

% % (ppm) (ppm) (ppm)

0.00 0.00 0.0 0.0 0.0

10.00 2.48 79.1 300.0 30.2

21.10 5.00 182.0 750.0 50.1

1490.0 85.5

0.0 0.0 -0.2 1.9 0.0

10.0 2.5 77.0 295.4 31.1

21.1 5.0 179.0 749.6 50.5

1500.0 85.2

0.0 0.0 0.2 1.9 0.0

0.0 0.0 2.1 4.6 0.9

0.0 0.0 3.0 0.4 0.4

0.0 0.0 0.0 10.0 0.3

0.00% 0.00% 0.77% 0.13% 1.00%

0.47% 0.40% 0.49% 0.65% 0.30%

0.00% 0.20% 1.65% 0.67% 0.90% Linearity Information

Gas

Span Gas Value/Range

Bias Gas Value

Gas Concentration

1

2

3

4

Difference

1

4

Response

1

2

Span Bias

Max Calibration Error Bias Check (Zero)

Bias Check (Span)

2

3

4

Results 3

Zero BiasCimarron Energy Run 1

Liberty Oil Well

Parshall, ND Start Time 12:34

Flare Run Length 60

06/15/11 Stop Time 13:34

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 100

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

0.0% 0.0% 0.8% 0.1% 0.0%

0.5% 0.4% 0.5% 0.7% 0.9%

0.0% 0.0% 0.0% 0.0% 0.0%

0.0% 0.0% 0.0% 0.0% 0.0%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

18.5 1.5 107.2 18.3 43.9

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

18.7 1.5 105.1 18.6 43.9

1 12:34 18.7 1.5 100.1 18.5 41.3

2 12:35 18.1 1.9 78.6 12.0 54.6

3 12:36 18.7 1.5 71.9 7.4 29.7

4 12:37 19.0 1.2 115.5 5.8 18.0

5 12:38 19.1 1.2 113.1 8.1 12.3

6 12:39 19.2 1.1 160.0 13.4 20.2

7 12:40 18.9 1.3 144.9 16.0 29.8

8 12:41 18.5 1.6 76.2 33.4 37.7

9 12:42 18.6 1.6 73.5 17.6 87.1

10 12:43 18.4 1.7 73.2 5.3 28.6

11 12:44 18.3 1.7 70.4 4.2 12.0

12 12:45 18.5 1.7 72.2 4.9 10.4

13 12:46 18.4 1.7 73.0 5.0 11.1

14 12:47 18.7 1.5 85.3 5.6 12.1

15 12:48 18.8 1.3 110.1 7.5 12.0

16 12:49 19.1 1.2 150.5 11.3 16.0

17 12:50 19.0 1.2 150.8 17.0 22.7

18 12:51 19.1 1.1 154.8 22.6 31.0

19 12:52 19.2 1.1 171.1 23.5 46.9

20 12:53 19.3 1.0 199.4 25.8 47.9

21 12:54 19.3 1.1 199.3 34.3 58.4

22 12:55 18.9 1.3 162.4 111.0 108.2

23 12:56 18.9 1.3 117.2 44.3 261.1

24 12:57 19.2 1.1 171.9 19.1 72.6

25 12:58 19.4 1.0 220.1 19.6 38.0

26 12:59 19.3 1.0 201.5 38.1 53.9

27 13:00 19.2 1.1 209.7 121.7 125.6

28 13:01 18.8 1.4 190.0 75.8 303.3

29 13:02 18.3 1.7 80.8 82.3 160.9

30 13:03 18.3 1.7 73.6 90.3 234.2

31 13:04 18.3 1.7 71.3 6.9 180.2

32 13:05 18.4 1.6 75.3 4.9 15.6

33 13:06 18.4 1.7 72.8 5.7 12.1

34 13:07 18.4 1.7 70.5 5.6 13.9

35 13:08 18.5 1.6 71.4 5.0 13.0

36 13:09 18.4 1.6 70.9 5.0 11.7

37 13:10 18.4 1.7 71.9 5.0 11.2

38 13:11 18.5 1.6 71.8 4.3 12.1

39 13:12 18.4 1.6 72.5 4.4 10.5

40 13:13 18.4 1.6 73.0 5.0 10.7

41 13:14 18.4 1.7 71.8 5.0 11.4

42 13:15 18.3 1.7 71.9 5.0 12.1

43 13:16 18.5 1.6 73.3 5.0 11.1

44 13:17 18.5 1.5 78.6 5.1 11.1

45 13:18 18.6 1.5 80.8 5.0 12.3

46 13:19 18.6 1.5 81.2 6.0 13.8

47 13:20 18.6 1.5 88.5 5.1 16.0

48 13:21 18.2 1.8 80.2 6.0 14.1

49 13:22 18.6 1.5 82.5 6.3 17.0

50 13:23 18.8 1.4 97.8 5.2 15.1

51 13:24 18.6 1.6 78.1 11.0 14.4

52 13:25 18.9 1.4 96.5 7.0 22.1

53 13:26 18.3 1.7 95.2 22.5 13.4

54 13:27 18.7 1.5 76.0 28.4 46.8

55 13:28 18.7 1.5 104.3 5.0 37.1

56 13:29 18.8 1.4 101.9 11.0 11.9

57 13:30 18.3 1.8 86.8 8.8 23.0

58 13:31 18.6 1.6 76.3 5.6 19.3

59 13:32 18.7 1.5 111.1 3.8 11.6

60 13:33 18.4 1.7 81.2 6.0 11.0 Calibration

Pretest Calibration

Absolute Bias (Zero)

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span)

Zero%

Span% Calibration Information

Instrument Range

Span Gas Value Gas

Zero%

Span%

Results Post Test CalibrationCimarron Energy Run 2

Liberty Oil Well

Parshall, ND Start Time 14:12

Flare Run Length 60

06/15/11 Stop Time 15:12

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 100

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.0

10.1 2.5 77.9 305.1 30.2

0.0 0.0 1.2 0.2

10.0 2.5 77.7 284.0 30.0

0.0% 0.0% 0.8% 0.1% 0.2%

0.0% 0.2% 0.4% 0.8% 1.1%

0.0% 0.0% 0.0% 0.0% 0.2%

0.5% 0.6% 0.1% 1.4% 0.2%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

18.3 1.7 89.1 18.0 67.1

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

18.4 1.7 87.5 17.7 66.7

1 14:12 18.6 1.6 84.2 12.7 43.4

2 14:13 18.9 1.3 123.5 8.9 40.7

3 14:14 18.7 1.5 138.5 17.7 36.4

4 14:15 18.5 1.6 91.7 20.9 63.2

5 14:16 18.3 1.8 83.7 16.3 84.1

6 14:17 18.5 1.7 80.0 9.4 56.2

7 14:18 18.9 1.3 114.7 7.0 34.2

8 14:19 18.4 1.7 114.6 12.7 28.3

9 14:20 18.7 1.4 97.9 17.9 47.1

10 14:21 18.6 1.5 109.6 19.1 68.7

11 14:22 18.5 1.6 85.7 16.6 70.9

12 14:23 18.2 1.8 77.6 10.0 59.5

13 14:24 18.2 1.8 73.7 9.0 39.8

14 14:25 18.3 1.8 75.1 7.0 36.1

15 14:26 17.7 2.1 71.6 6.7 25.2

16 14:27 17.8 2.1 67.5 7.5 27.0

17 14:28 18.1 1.9 72.2 5.0 24.7

18 14:29 18.2 1.9 73.3 7.6 13.6

19 14:30 18.3 1.8 74.1 8.0 24.1

20 14:31 18.5 1.6 76.4 7.6 25.6

21 14:32 18.4 1.7 78.6 7.1 25.6

22 14:33 18.4 1.7 77.2 8.0 26.6

23 14:34 17.9 2.0 73.9 8.0 30.2

24 14:35 18.2 1.8 71.5 6.8 29.1

25 14:36 18.4 1.7 76.7 6.9 23.1

26 14:37 18.3 1.7 78.4 9.0 25.5

27 14:38 18.1 1.9 72.6 9.0 30.2

28 14:39 18.3 1.8 71.1 7.4 30.1

29 14:40 18.3 1.8 72.5 6.9 25.2

30 14:41 18.7 1.5 83.7 6.6 25.1

31 14:42 18.9 1.3 135.2 6.1 23.6

32 14:43 18.1 1.8 101.1 18.0 30.8

33 14:44 17.9 2.0 70.7 12.0 66.1

34 14:45 18.5 1.6 76.0 6.9 41.4

35 14:46 18.4 1.7 83.8 6.2 23.6

36 14:47 18.4 1.7 74.4 12.9 27.3

37 14:48 17.9 2.0 71.0 10.1 41.6

38 14:49 18.4 1.7 76.3 7.1 34.0

39 14:50 18.2 1.8 81.1 7.9 20.5

40 14:51 18.1 2.0 72.3 9.6 28.8

41 14:52 18.7 1.5 88.5 7.9 31.0

42 14:53 18.5 1.6 100.7 8.1 26.2

43 14:54 18.5 1.6 79.7 12.0 27.0

44 14:55 18.1 1.9 81.6 12.7 45.3

45 14:56 18.4 1.6 75.9 10.2 40.3

46 14:57 18.4 1.7 82.8 6.0 30.0

47 14:58 18.2 1.8 76.4 13.2 23.5

48 14:59 18.3 1.7 74.6 11.4 50.2

49 15:00 18.6 1.5 84.0 9.3 37.5

50 15:01 18.7 1.5 98.9 8.7 31.2

51 15:02 18.9 1.3 126.9 13.1 32.9

52 15:03 18.6 1.5 108.9 164.8 80.1

53 15:04 18.5 1.6 88.7 180.2 782.4

54 15:05 18.6 1.5 92.0 118.2 720.1

55 15:06 18.7 1.5 109.6 12.3 349.6

56 15:07 18.5 1.6 97.7 16.1 43.4

57 15:08 18.5 1.6 92.2 12.6 54.8

58 15:09 18.6 1.6 105.8 13.1 41.1

59 15:10 18.5 1.6 102.9 15.2 45.7

60 15:11 18.4 1.7 97.0 17.7 55.6 Gas

Instrument Range

Post Test Calibration

Zero% Span Gas Value

Calibration

Pretest Calibration

Zero% Calibration Information

Results

Absolute Bias (Zero)

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span)

Span%

Span%Cimarron Energy Run 3

Liberty Oil Well

Parshall, ND Start Time 15:30

Flare Run Length 60

06/15/11 Stop Time 16:30

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 100

10.00 2.48 79.1 300.0 30.2

0.0 0.0 1.2 0.0 0.2

10.0 2.5 77.7 284.0 30.0

0.0 0.0 0.0 0.0 0.0

10.0 2.5 76.6 305.8 28.1

0.0% 0.0% 0.1% 0.1% 0.0%

0.0% 0.6% 0.2% 0.7% 3.0%

0.0% 0.0% 0.7% 0.0% 0.2%

0.0% 0.8% 0.6% 1.5% 1.9%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

18.2 1.8 81.4 9.6 44.1

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

18.2 1.8 79.4 9.5 42.4

1 15:30 18.6 1.5 129.2 23.8 94.5

2 15:31 18.2 1.8 103.9 23.8 110.9

3 15:32 18.2 1.8 80.8 15.9 104.4

4 15:33 18.0 1.9 79.3 9.2 74.6

5 15:34 18.0 2.0 72.1 7.7 40.1

6 15:35 17.9 2.0 72.9 6.9 32.1

7 15:36 18.1 1.9 74.4 6.5 28.5

8 15:37 18.0 2.0 74.2 8.4 28.6

9 15:38 18.2 1.8 75.3 7.5 32.0

10 15:39 18.1 1.9 80.5 7.9 28.9

11 15:40 18.3 1.8 74.2 8.7 33.7

12 15:41 18.2 1.8 76.3 9.3 37.2

13 15:42 18.1 1.9 76.1 7.3 37.5

14 15:43 18.1 1.9 75.1 9.9 32.9

15 15:44 18.4 1.7 84.5 9.3 44.9

16 15:45 18.2 1.8 81.5 9.4 37.8

17 15:46 18.0 1.9 89.0 11.3 43.1

18 15:47 18.3 1.8 82.3 6.3 47.1

19 15:48 18.3 1.7 86.2 7.9 29.2

20 15:49 17.9 2.0 76.7 12.2 36.7

21 15:50 18.4 1.7 80.6 13.4 63.7

22 15:51 18.3 1.7 89.4 6.3 54.8

23 15:52 18.1 1.9 76.6 15.8 35.4

24 15:53 18.2 1.8 77.0 9.5 72.2

25 15:54 18.2 1.8 80.6 8.2 36.5

26 15:55 18.1 1.9 78.4 9.9 39.5

27 15:56 18.3 1.8 75.0 11.5 45.9

28 15:57 18.3 1.7 79.2 8.5 47.7

29 15:58 18.2 1.8 85.1 7.7 33.1

30 15:59 17.9 2.0 72.2 7.7 31.4

31 16:00 18.4 1.7 73.7 7.7 34.1

32 16:01 18.3 1.7 86.2 5.3 31.2

33 16:02 18.3 1.7 76.2 13.0 25.5

34 16:03 18.4 1.7 78.4 9.5 56.1

35 16:04 18.0 1.9 75.0 8.3 35.3

36 16:05 18.4 1.7 73.2 8.8 37.0

37 16:06 18.5 1.6 86.6 4.1 34.1

38 16:07 18.3 1.7 81.1 12.6 21.6

39 16:08 18.3 1.8 80.2 11.7 58.1

40 16:09 18.2 1.8 89.3 11.6 50.1

41 16:10 18.1 1.9 76.0 13.1 56.1

42 16:11 17.9 2.0 71.1 8.5 55.8

43 16:12 18.1 1.9 71.8 7.5 37.1

44 16:13 18.4 1.6 83.6 7.3 33.2

45 16:14 18.2 1.8 84.9 9.1 30.1

46 16:15 18.4 1.7 76.5 12.2 41.6

47 16:16 18.4 1.7 80.8 6.3 47.3

48 16:17 18.3 1.7 75.5 9.6 27.1

49 16:18 18.4 1.7 79.6 9.4 47.8

50 16:19 18.3 1.7 78.9 8.7 38.8

51 16:20 18.1 1.9 72.8 9.4 38.4

52 16:21 17.9 2.0 69.9 7.4 40.4

53 16:22 18.1 1.9 70.6 6.6 33.1

54 16:23 18.0 1.9 73.8 6.3 24.6

55 16:24 18.2 1.7 75.2 6.7 25.4

56 16:25 18.2 1.7 77.9 8.3 28.2

57 16:26 18.2 1.8 73.7 10.4 33.2

58 16:27 18.4 1.6 77.6 7.4 44.2

59 16:28 18.2 1.8 80.5 7.3 30.5

60 16:29 18.4 1.7 76.2 7.9 33.6

Zero% Calibration Information

Span Gas Value

Calibration

Pretest Calibration Gas

Instrument Range

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span) Results

Absolute Bias (Zero)

Span%

Span% Post Test Calibration

Zero%Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

6/15/2011

Outlet NMOC (lb/hr as C 3 H 8 ) 0.89

Waste Gas Inlet NMOC (lb/hr as C 3 H 8 ) 150.6

Pilot Inlet NMOC (lb/hr as C 3 H 8 ) 0.5

Sum of Inlets NMOC (lb/hr as C 3 H 8 ) 151.0

% DRE (mass flow in/out basis) 99.4%

% DRE (carbon balance) 98.9%

%DRE Calculations

### 4 oz. Inlet PressureCimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

4 oz.

Run # 4 5 6 Average

Start Time 10:56 13:15 14:28

Stop Time 11:02 13:21 14:36

hrs Hours of Operation / Year 8760 8760 8760 8760

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

√∆ P AVG Inlet Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1793 0.1769 0.1798 0.1787

C P Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84

T S Inlet Stack Temperature (°F) 61 63 67 64

P bar Barometric Pressure (mbar) 938 938 938 938

P bar Barometric Pressure (" Hg) 27.70 27.70 27.70 27.70

Ps Inlet Stack Pressure ('' H 2 O) 6.2 6.2 6.2 6.2

Carbon Dioxide (%vd) 0.4 0.3 0.3 0.4

Methane (%vd) 15.4 16.7 17.5 16.5

Ethane (%vd) 20.2 20.5 20.4 20.4

Propane (%vd) 31.5 32.2 32.1 31.9

Butanes (%vd) 18.1 17.9 18.6 18.2

Pentanes (%vd) 5.1 4.9 5.2 5.0

Hexanes+ (%vd) 2.8 2.4 3.0 2.7

Heat Content (Btu/scf) 2,227 2,229 2,299 2,252

Carbon Dioxide (%vd) 0.5 0.5 0.5 0.5

Methane (%vd) 46.3 46.3 46.3 46.3

Ethane (%vd) 19.9 19.9 19.9 19.9

Propane (%vd) 15.8 15.8 15.8 15.8

Butanes (%vd) 6.3 6.3 6.3 6.3

Pentanes (%vd) 1.5 1.5 1.5 1.5

Hexanes+ (%vd) 0.7 0.7 0.7 0.7

Heat Content (Btu/scf) 1,496 1,496 1,496 1,496

F ACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18

F DSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17

dry Pilot Light NMOC (ppmvd as C 3 H 8 ) 413,300 413,300 413,300 413,300

lb/hr Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.49 0.49 0.49 0.49

Run # 4 5 6 Average

B

ws Inlet Moisture Content (%/100) - saturated 0.019 0.021 0.024 0.021

M D Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54

M A Inlet Molecular Weight Wet (lb/lb-mole) 35.20 35.18 35.12 35.17

V S Inlet Gas Velocity (ft/sec) 9.3 9.2 9.4 9.3

F ACFM Inlet Gas Flow (acfm) 49 48 49 49

F DSCFM Inlet Gas Flow (dscfm) 46 45 45 45

dry NMOC (ppmvd as C 3 H 8 ) 830,533 826,400 850,367 835,767

lb/hr NMOC (lb/hr as C 3 H 8 ) 260 255 265 260

tpy NMOC (tons/year as C 3 H 8 ) 1142 1119 1162 1141 Field Reference Method Data

Waste Gas Data

Reference Method Calculations Pilot Light DataCimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

4 oz.

Run # 4 5 6 Average

Start Time 10:48 12:55 14:14

Stop Time 11:48 13:55 15:14

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Stack Diameter (inches) 42.6 42.6 42.6 42.6

√∆ P AVG Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1607 0.1599 0.1560 0.1589

C P Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83

T S Stack Temperature (°F) 1320 1321 1327 1323

P bar Barometric Pressure (mbar) 938 938 938 938

P bar Barometric Pressure (" Hg) 27.70 27.70 27.70 27.70

Ps Stack Pressure ('' H 2 O) 0.00 0.00 0.00 0.00

Y d Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780

T

m Meter Temperature (°F) 57 65 69 64

V

m Sample Volume (ft 3 ) 36.340 36.409 37.287 36.679

∆ H Orifice Pressure Delta H (" H 2 O) 1.0 1.0 1.0 1.0

V lc Moisture (g) 32.7 46.2 37.2 38.7

O 2 %vd O 2 (%vd) 16.5 16.6 16.6 16.6

CO 2 %vd CO 2 (%vd) 2.9 2.8 2.8 2.8

N 2 %vd N 2 (%vd) 80.6 80.6 80.6 80.6

dry CO (ppmvd) 52.6 54.0 51.5 52.7

wet CH 4 (ppmvw) 0.0 0.7 0.0 0.2

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

Run # 4 5 6 Average

V mstd Sample Volume (dscf) 33.662 33.213 33.775 33.550

V wstd Moisture Volume (scf) 1.54 2.18 1.75 1.82

B

ws Moisture Content (%/100) 0.044 0.062 0.049 0.052

M D Molecular Weight Dry (lb/lb-mole) 29.12 29.11 29.10 29.11

M A Molecular Weight Wet (lb/lb-mole) 28.63 28.43 28.56 28.54

V S Gas Velocity (ft/sec) 17.1 17.1 16.6 16.9

F ACFM Gas Flow (acfm) 10,158 10,145 9,894 10,065

F DSCFM Gas Flow (dscfm) 2,667 2,613 2,572 2,617

lb/hr Gas Flow (lb/hr) 12,435 12,327 12,031 12,265

F

o F

o (unitless) 1.523 1.547 1.562 1.544

lb/hr CO (lb/hr) 0.6 0.6 0.6 0.6

tpy CO (tons/year) 2.7 2.7 2.5 2.6

dry CH 4 (ppmvd) 0.0 0.7 0.0 0.2

lb/hr CH 4 (lb/hr) 0.0 0.0 0.0 0.0

tpy CH 4 (tons/year) 0.0 3.1 0.1 1.0

dry NMOC (ppmvd as C 3 H 8 ) 0.0 2.0 0.4 0.8

lb/hr NMOC (lb/hr as C 3 H 8 ) 0.000 0.0354 0.0068 0.014

tpy NMOC (tons/year as C 3 H 8 ) 0.000 0.155 0.030 0.062

DRE TVOC DRE (%) - carbon balance 100.00% 99.98% 100.00% 99.99% Field Reference Method Data

Reference Method CalculationsCimarron Energy

Liberty Oil Well

Parshall ND

Flare

06/14/11

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 10.0

10.00 2.48 79.1 300.0 3.0

0.0 0.0 1.2 1.0 0.1

10.0 2.5 79.5 300.9 3.0

Linearity Bias (Zero) 0.0 0.0 1.2 1.0 0.1

Linearity Bias (Span) 10.0 2.5 78.8 309.1 2.9

% % (ppm) (ppm) (ppm)

0.00 0.00 0.0 0.0 0.0

10.00 2.48 79.1 300.0 3.0

21.10 5.00 182.0 750.0 5.0

1490.0 8.5

0.0 0.0 1.2 1.0 0.1

10.0 2.5 78.8 309.1 2.9

21.1 5.0 180.1 758.9 5.0

1505.2 8.4

0.0 0.0 1.2 1.0 0.1

0.0 0.0 0.3 9.1 0.1

0.0 0.0 1.9 8.9 0.0

0.0 0.0 0.0 15.2 0.0

0.00% 0.00% 0.00% 0.00% 0.00%

0.14% 0.00% 0.38% 0.55% 0.50%

0.14% 0.60% 1.04% 1.02% 1.00% Linearity Information

Gas

Span Gas Value/Range

Bias Gas Value

Gas Concentration

1

2

3

4

Difference

1

4

Response

1

2

Span Bias

Max Calibration Error Bias Check (Zero)

Bias Check (Span)

2

3

4

Results 3

Zero BiasCimarron Energy Run 4

Liberty Oil Well

Parshall ND Start Time 10:48:13

Flare Run Length 60

06/14/11 Stop Time 11:48

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

0.0 0.0 1.2 1.0 0.1

10.0 2.5 79.5 300.9 3.0

-0.1 0.0 5.2 0.0 0.1

10.0 2.5 81.1 305.9 3.0

0.5% 0.0% 2.2% 0.1% 0.0%

0.1% 0.2% 1.3% 0.2% 1.0%

0.5% 0.0% 2.2% 0.1% 0.0%

0.0% 0.2% 0.9% 0.3% 0.5%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

16.5 2.9 52.6 -0.5 -0.1

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

16.6 2.9 54.5 0.0 0.0

1 10:48 16.5 2.9 56.2 0.3 0.0

2 10:49 16.4 2.9 55.1 0.0 0.0

3 10:50 16.4 2.9 55.8 0.7 0.0

4 10:51 16.3 3.0 54.4 -0.2 0.0

5 10:52 16.8 2.7 57.5 0.1 0.0

6 10:53 16.8 2.7 59.0 -0.4 0.0

7 10:54 16.6 2.8 57.3 1.4 0.0

8 10:55 16.3 3.0 55.0 0.5 0.0

9 10:56 16.6 2.9 56.1 0.7 0.0

10 10:57 16.7 2.8 59.5 0.3 0.0

11 10:58 16.4 3.0 56.3 0.1 0.0

12 10:59 16.5 2.9 56.3 1.3 0.0

13 11:00 16.5 2.9 56.3 0.2 0.0

14 11:01 16.4 3.0 54.0 -0.1 0.0

15 11:02 16.3 3.0 53.5 -0.6 0.0

16 11:03 16.4 2.9 52.8 0.2 0.0

17 11:04 16.5 2.9 54.3 -0.5 0.0

18 11:05 16.4 3.0 53.0 -0.6 0.0

19 11:06 16.7 2.8 54.7 0.1 0.0

20 11:07 16.6 2.8 55.4 -0.2 0.0

21 11:08 16.4 3.0 53.1 -0.3 0.0

22 11:09 16.5 2.9 54.4 0.2 0.0

23 11:10 16.5 2.9 54.3 -0.4 0.0

24 11:11 16.4 3.0 53.5 -0.4 0.0

25 11:12 16.6 2.8 54.5 -0.5 0.0

26 11:13 16.5 3.0 54.2 0.3 0.0

27 11:14 16.8 2.8 56.0 -0.2 0.0

28 11:15 16.7 2.8 56.8 0.0 0.0

29 11:16 16.4 3.0 52.5 0.4 0.0

30 11:17 16.6 2.9 52.0 1.1 0.0

31 11:18 16.6 2.9 55.2 0.5 0.0

32 11:19 16.5 2.9 53.1 0.1 0.0

33 11:20 16.6 2.9 55.5 -0.2 0.0

34 11:21 16.4 2.9 53.4 0.0 0.0

35 11:22 16.5 3.0 52.1 0.1 0.0

36 11:23 16.7 2.9 54.6 -0.4 0.0

37 11:24 16.7 2.8 55.2 -0.2 0.0

38 11:25 16.8 2.8 57.3 -0.4 0.0

39 11:26 16.7 2.9 55.4 -0.3 0.0

40 11:27 16.8 2.8 55.3 0.8 0.0

41 11:28 16.5 2.9 53.1 -0.2 0.0

42 11:29 16.8 2.8 52.4 -0.3 0.0

43 11:30 16.9 2.7 55.3 0.0 0.0

44 11:31 16.8 2.8 54.7 0.1 0.0

45 11:32 16.7 2.8 54.8 0.2 0.0

46 11:33 16.9 2.7 55.3 -0.2 0.0

47 11:34 16.7 2.8 55.5 0.0 0.0

48 11:35 16.6 2.9 53.4 -0.1 0.0

49 11:36 16.6 2.9 52.8 0.6 0.0

50 11:37 16.7 2.8 54.6 -0.2 0.0

51 11:38 16.7 2.8 53.1 -0.8 0.0

52 11:39 16.7 2.8 54.1 0.4 0.0

53 11:40 16.7 2.8 52.4 -0.7 0.0

54 11:41 16.4 3.0 52.7 -0.4 0.0

55 11:42 16.3 3.0 50.3 0.2 0.0

56 11:43 16.7 2.8 51.5 -0.4 0.0

57 11:44 16.6 2.9 53.6 -0.1 0.0

58 11:45 16.7 2.8 51.7 -0.2 0.0

59 11:46 16.7 2.8 54.3 0.0 0.0

60 11:47 16.5 2.9 52.2 -0.1 0.0 Calibration

Pretest Calibration

Absolute Bias (Zero)

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span)

Zero%

Span% Calibration Information

Instrument Range

Span Gas Value Gas

Zero%

Span%

Results Post Test CalibrationCimarron Energy Run 5

Liberty Oil Well

Parshall ND Start Time 12:55:23

Flare Run Length 60

06/14/11 Stop Time 13:55

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

-0.1 0.0 5.2 0.0 0.1

10.0 2.5 81.1 305.9 3.0

0.0 0.0 0.6 0.0 0.1

10.0 2.5 79.7 301.9 3.0

0.0% 0.0% 0.3% 0.1% 0.0%

0.1% 0.2% 0.5% 0.5% 0.1%

0.5% 0.0% 2.5% 0.0% 0.0%

0.0% 0.4% 0.8% 0.3% 0.9%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

16.6 2.8 54.0 0.7 1.9

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

16.6 2.8 55.8 0.7 1.9

1 12:55:23 16.4 2.9 61.7 1.0 0.2

2 12:56:23 16.6 2.8 53.9 0.9 0.2

3 12:57:23 16.6 2.8 57.9 0.1 0.1

4 12:58:23 16.5 2.9 58.3 0.7 0.9

5 12:59:23 16.4 2.9 52.1 0.4 1.0

6 13:00:23 16.6 2.8 56.6 0.0 0.4

7 13:01:23 16.5 2.8 54.9 0.0 0.0

8 13:02:23 16.5 2.9 54.2 0.0 -0.1

9 13:03:23 16.7 2.7 58.5 -0.1 0.3

10 13:04:23 16.7 2.8 57.3 0.4 0.0

11 13:05:23 16.4 2.9 56.8 0.9 1.1

12 13:06:23 16.6 2.8 53.6 1.0 1.7

13 13:07:23 16.4 2.9 54.9 0.1 1.0

14 13:08:23 16.7 2.7 56.2 0.0 -0.1

15 13:09:23 17.2 2.5 60.2 0.4 0.1

16 13:10:23 17.0 2.6 82.1 2.1 0.6

17 13:11:23 16.7 2.7 63.6 15.1 15.1

18 13:12:23 16.8 2.7 61.6 4.1 53.2

19 13:13:23 16.8 2.7 61.1 1.4 5.1

20 13:14:23 16.6 2.8 55.5 1.0 3.1

21 13:15:23 16.6 2.9 54.8 0.8 2.3

22 13:16:23 16.8 2.7 55.8 0.0 1.8

23 13:17:23 16.7 2.7 56.5 -0.1 0.8

24 13:18:23 16.9 2.7 58.2 0.4 0.7

25 13:19:23 17.0 2.6 56.9 1.1 1.6

26 13:20:23 16.8 2.7 57.5 1.0 1.9

27 13:21:23 16.7 2.7 54.8 1.0 1.8

28 13:22:23 16.7 2.7 53.6 1.1 2.3

29 13:23:23 16.9 2.6 58.9 0.9 1.7

30 13:24:23 16.9 2.6 60.0 1.2 1.4

31 13:25:23 17.0 2.6 63.2 2.0 2.0

32 13:26:23 16.5 2.9 58.3 1.9 3.4

33 13:27:23 16.6 2.8 51.9 1.3 5.5

34 13:28:23 16.6 2.8 56.2 0.5 1.8

35 13:29:23 16.3 3.0 52.5 0.0 0.4

36 13:30:23 16.5 2.9 50.6 -0.1 0.0

37 13:31:23 16.5 2.9 56.4 0.0 0.2

38 13:32:23 16.4 2.9 51.7 0.0 -0.4

39 13:33:23 16.4 2.9 53.2 0.0 0.4

40 13:34:23 16.5 2.9 54.2 -0.1 0.0

41 13:35:23 16.4 2.9 52.6 0.0 -0.2

42 13:36:23 16.4 2.9 52.7 0.0 -0.1

43 13:37:23 16.5 2.9 51.8 0.0 0.1

44 13:38:23 16.4 2.9 52.5 0.0 -0.3

45 13:39:23 16.3 3.0 51.6 0.0 -0.3

46 13:40:23 16.6 2.8 53.2 0.1 0.0

47 13:41:23 16.4 2.9 53.4 0.1 0.8

48 13:42:23 16.6 2.8 53.6 0.0 -0.3

49 13:43:23 16.5 2.9 51.3 -0.1 -0.3

50 13:44:23 16.3 3.0 52.9 0.0 -0.2

51 13:45:23 16.4 2.9 51.1 0.0 -0.1

52 13:46:23 16.6 2.8 52.2 0.0 0.0

53 13:47:23 16.6 2.8 57.2 -0.1 0.7

54 13:48:23 16.7 2.8 53.7 0.1 0.0

55 13:49:23 16.4 2.9 55.3 0.0 0.0

56 13:50:23 16.4 3.0 53.7 0.0 0.4

57 13:51:23 16.6 2.8 53.2 0.0 0.7

58 13:52:23 16.5 2.8 55.9 0.0 -0.3

59 13:53:23 16.4 2.9 53.4 0.1 -0.1

60 13:54:23 16.6 2.8 52.7 0.0 -0.1 Gas

Instrument Range

Post Test Calibration

Zero% Span Gas Value

Calibration

Pretest Calibration

Zero% Calibration Information

Results

Absolute Bias (Zero)

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span)

Span%

Span%Cimarron Energy Run 6

Liberty Oil Well

Parshall ND Start Time 14:14:23

Flare Run Length 60

06/14/11 Stop Time 15:14

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

0.0 0.0 0.6 0.0 0.1

10.0 2.5 79.7 301.9 3.0

-0.1 0.0 0.2 0.0 0.1

10.0 2.5 81.8 307.4 3.0

0.5% 0.0% 0.5% 0.1% 0.0%

0.1% 0.6% 1.6% 0.1% 0.4%

0.5% 0.0% 0.2% 0.0% 0.0%

0.0% 0.8% 1.2% 0.4% 0.3%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

16.6 2.8 51.5 0.0 0.4

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

16.6 2.8 52.7 0.0 0.4

1 14:14 16.6 2.8 52.0 0.0 1.5

2 14:15 16.6 2.8 52.1 0.0 -0.1

3 14:16 16.7 2.7 50.0 0.0 -0.1

4 14:17 16.7 2.7 52.5 0.0 -0.1

5 14:18 16.7 2.7 51.7 -0.1 -0.2

6 14:19 16.6 2.8 52.5 -0.1 -0.2

7 14:20 16.7 2.8 53.9 -0.1 -0.1

8 14:21 16.7 2.7 53.9 -0.1 0.1

9 14:22 16.6 2.8 52.8 0.0 0.3

10 14:23 16.6 2.8 51.2 -0.1 0.3

11 14:24 16.6 2.8 52.7 -0.1 0.5

12 14:25 16.6 2.8 53.3 -0.1 1.6

13 14:26 16.5 2.9 51.4 -0.1 0.1

14 14:27 16.8 2.7 54.6 0.1 0.1

15 14:28 16.7 2.7 53.9 0.0 0.1

16 14:29 16.6 2.8 51.1 -0.1 -0.2

17 14:30 16.7 2.8 52.8 -0.1 0.5

18 14:31 16.8 2.7 52.7 -0.1 -0.1

19 14:32 16.6 2.8 56.0 0.0 0.1

20 14:33 16.7 2.8 49.2 -0.1 0.5

21 14:34 16.8 2.7 53.1 0.0 0.6

22 14:35 16.8 2.7 54.2 0.0 -0.4

23 14:36 16.6 2.8 50.1 0.0 0.6

24 14:37 16.5 2.9 52.0 0.0 0.7

25 14:38 16.8 2.7 48.7 -0.1 0.8

26 14:39 16.8 2.7 50.3 0.0 1.3

27 14:40 16.7 2.7 50.6 -0.1 1.2

28 14:41 16.8 2.7 52.4 -0.1 0.2

29 14:42 16.6 2.8 52.1 0.0 -0.2

30 14:43 16.7 2.7 51.1 0.0 -0.1

31 14:44 16.7 2.7 52.5 0.0 0.5

32 14:45 16.6 2.8 53.0 0.0 1.3

33 14:46 16.5 2.8 50.6 0.0 0.7

34 14:47 16.7 2.8 49.4 -0.1 0.1

35 14:48 16.8 2.7 56.2 0.0 -0.1

36 14:49 16.6 2.8 52.3 0.0 1.2

37 14:50 16.6 2.7 53.1 0.0 0.8

38 14:51 16.7 2.7 55.3 0.0 0.6

39 14:52 16.5 2.8 51.6 0.0 0.6

40 14:53 16.5 2.8 51.1 0.0 0.7

41 14:54 16.5 2.8 53.7 0.1 0.7

42 14:55 16.6 2.8 52.5 0.0 -0.1

43 14:56 16.5 2.8 54.7 0.1 0.2

44 14:57 16.6 2.8 53.2 0.1 0.6

45 14:58 16.7 2.7 53.5 -0.1 0.7

46 14:59 16.6 2.8 54.8 0.0 0.2

47 15:00 16.7 2.7 52.1 0.0 0.4

48 15:01 16.7 2.7 56.6 0.1 0.5

49 15:02 16.6 2.8 54.8 0.9 0.8

50 15:03 16.7 2.8 52.8 0.1 1.7

51 15:04 16.5 2.9 54.3 0.0 0.5

52 15:05 16.6 2.8 51.8 -0.1 0.7

53 15:06 16.8 2.7 52.9 -0.1 0.7

54 15:07 16.6 2.8 55.6 0.0 0.5

55 15:08 16.5 2.8 52.2 0.8 0.3

56 15:09 16.6 2.8 52.8 0.3 1.9

57 15:10 16.7 2.7 55.6 0.1 0.6

58 15:11 16.6 2.7 51.9 -0.1 0.2

59 15:12 16.6 2.8 51.5 0.0 0.3

60 15:13 16.6 2.7 54.6 0.0 0.7

Zero% Calibration Information

Span Gas Value

Calibration

Pretest Calibration Gas

Instrument Range

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span) Results

Absolute Bias (Zero)

Span%

Span% Post Test Calibration

Zero%Cimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

4 oz.

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

Waste Gas Inlet NMOC (lb/hr as C 3 H 8 ) 260.0

Pilot Inlet NMOC (lb/hr as C 3 H 8 ) 0.5

Sum of Inlets NMOC (lb/hr as C 3 H 8 ) 260.5

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

% DRE (carbon balance) 99.99%

%DRE Calculations

### 10 oz. Inlet PressureCimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

10 oz.

Run # 7 8 9 Average

Start Time 15:37 16:56 8:56

Stop Time 15:44 17:08 9:03

hrs Hours of Operation / Year 8760 8760 8760 8760

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

√∆ P AVG Inlet Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.3290 0.3314 0.3338 0.3314

C P Inlet Pitot Tube Constant (unitless) 0.84 0.84 0.84 0.84

T S Inlet Stack Temperature (°F) 68 73 74 72

P bar Barometric Pressure (mbar) 938 938 936 937

P bar Barometric Pressure (" Hg) 27.70 27.70 27.64 27.68

Ps Inlet Stack Pressure ('' H 2 O) 9.5 9.5 9.5 9.5

Carbon Dioxide (%vd) 0.3 0.3 0.3 0.3

Methane (%vd) 16.5 17.9 17.6 17.3

Ethane (%vd) 20.5 20.5 21.3 20.8

Propane (%vd) 33.0 32.0 32.9 32.6

Butanes (%vd) 19.0 18.5 18.1 18.6

Pentanes (%vd) 5.3 5.2 5.0 5.2

Hexanes+ (%vd) 2.8 3.0 2.6 2.8

Heat Content (Btu/scf) 2,325 2,305 2,295 2,308

Carbon Dioxide (%vd) 0.5 0.5 0.5 0.5

Methane (%vd) 46.1 46.1 46.1 46.1

Ethane (%vd) 19.9 19.9 19.9 19.9

Propane (%vd) 15.9 15.9 15.9 15.9

Butanes (%vd) 6.4 6.4 6.4 6.4

Pentanes (%vd) 1.6 1.6 1.6 1.6

Hexanes+ (%vd) 0.9 0.9 0.9 0.9

Heat Content (Btu/scf) 1,514 1,514 1,514 1,514

F ACFM Pilot Light Flow (acfm) 0.18 0.18 0.18 0.18

F DSCFM Pilot Light Flow (dscfm) 0.17 0.17 0.17 0.17

dry Pilot Light NMOC (ppmvd as C 3 H 8 ) 421,267 421,267 421,267 421,267

lb/hr Pilot Light NMOC (lb/hr as C 3 H 8 ) 0.50 0.50 0.50 0.50

Run # 7 8 9 Average

B

ws Inlet Moisture Content (%/100) - saturated 0.024 0.029 0.029 0.028

M D Inlet Molecular Weight Dry (lb/lb-mole) 35.54 35.54 35.54 35.54

M A Inlet Molecular Weight Wet (lb/lb-mole) 35.11 35.03 35.02 35.06

V S Inlet Gas Velocity (ft/sec) 17.2 17.4 17.6 17.4

F ACFM Inlet Gas Flow (acfm) 90 91 92 91

F DSCFM Inlet Gas Flow (dscfm) 83 83 84 83

dry NMOC (ppmvd as C 3 H 8 ) 864,867 851,467 848,100 854,811

lb/hr NMOC (lb/hr as C 3 H 8 ) 494 486 487 489

tpy NMOC (tons/year as C 3 H 8 ) 2168 2131 2135 2145 Field Reference Method Data

Waste Gas Lab Data

Reference Method Calculations Pilot Light DataCimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

10 oz.

Run # 7 8 9 Average

Start Time 15:31 16:48 8:45

Stop Time 16:31 17:48 9:45

Sample Duration (minutes) 60 60 60

hrs Hours of Operation / Year 8760 8760 8760 8760

D S Stack Diameter (inches) 42.6 42.6 42.6 42.6

√∆ P AVG Average (Delta P) 1⁄2 (" H 2 O) 1⁄2 0.1719 0.1681 0.1813 0.1738

C P Pitot Tube Constant (unitless) 0.83 0.83 0.83 0.83

T S Stack Temperature (°F) 1973 1992 1992 1986

P bar Barometric Pressure (mbar) 938 938 936 937

P bar Barometric Pressure (" Hg) 27.70 27.70 27.64 27.68

Ps Stack Pressure ('' H 2 O) 0.00 0.00 0.00 0.00

Y d Meter Y Factor (unitless) 0.9780 0.9780 0.9780 0.9780

T

m Meter Temperature (°F) 74 79 62 72

V

m Sample Volume (ft 3 ) 37.385 37.148 37.088 37.207

∆ H Orifice Pressure Delta H (" H 2 O) 1.0 1.0 1.0 1.0

V lc Moisture (g) 65.2 43.7 52.2 53.7

O 2 %vd O 2 (%vd) 14.8 14.9 15.1 14.9

CO 2 %vd CO 2 (%vd) 3.9 3.8 3.8 3.8

N 2 %vd N 2 (%vd) 81.3 81.3 81.1 81.2

dry CO (ppmvd) 15.5 21.0 15.4 17.3

wet CH 4 (ppmvw) 0.0 0.0 0.0 0.0

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

Run # 7 8 9 Average

V mstd Sample Volume (dscf) 33.536 33.037 33.984 33.519

V wstd Moisture Volume (scf) 3.07 2.06 2.46 2.53

B

ws Moisture Content (%/100) 0.084 0.059 0.068 0.070

M D Molecular Weight Dry (lb/lb-mole) 29.22 29.21 29.21 29.21

M A Molecular Weight Wet (lb/lb-mole) 28.28 28.55 28.45 28.43

V S Gas Velocity (ft/sec) 21.5 21.0 22.7 21.7

F ACFM Gas Flow (acfm) 12,780 12,486 13,507 12,925

F DSCFM Gas Flow (dscfm) 2,352 2,343 2,505 2,400

lb/hr Gas Flow (lb/hr) 11,304 11,069 11,903 11,425

F

o F

o (unitless) 1.562 1.565 1.537 1.555

lb/hr CO (lb/hr) 0.2 0.2 0.2 0.2

tpy CO (tons/year) 0.7 0.9 0.7 0.8

dry CH 4 (ppmvd) 0.0 0.0 0.0 0.0

lb/hr CH 4 (lb/hr) 0.0 0.0 0.0 0.0

tpy CH 4 (tons/year) 0.0 0.0 0.0 0.0

dry NMOC (ppmvd as C 3 H 8 ) 0.3 0.7 0.1 0.4

lb/hr NMOC (lb/hr as C 3 H 8 ) 0.005 0.0107 0.0013 0.006

tpy NMOC (tons/year as C 3 H 8 ) 0.022 0.047 0.006 0.025

DRE TVOC DRE (%) - carbon balance 100.00% 99.99% 100.00% 100.00% Field Reference Method Data

Reference Method CalculationsCimarron Energy

Liberty Oil Well

Parshall ND

Flare

06/14/11

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 10.0

10.00 2.48 79.1 300.0 3.0

-0.1 0.0 1.1 0.0 0.1

10.0 2.5 78.0 294.2 3.0

Linearity Bias (Zero) 0.0 0.0 -0.2 1.9 0.0

Linearity Bias (Span) 10.0 2.5 77.0 295.4 3.0

% % (ppm) (ppm) (ppm)

0.00 0.00 0.0 0.0 0.0

10.00 2.48 79.1 300.0 3.0

21.10 5.00 182.0 750.0 5.0

1490.0 8.5

0.0 0.0 -0.2 1.9 0.0

10.0 2.5 77.0 295.4 3.0

21.1 5.0 179.0 749.6 5.0

1500.0 8.4

0.0 0.0 0.2 1.9 0.0

0.0 0.0 2.1 4.6 0.0

0.0 0.0 3.0 0.4 0.0

0.0 0.0 0.0 10.0 0.0

0.47% 0.00% 0.71% 0.13% 1.00%

0.00% 0.00% 0.55% 0.08% 0.20%

0.00% 0.20% 1.65% 0.67% 0.40% Span Bias

Max Calibration Error Bias Check (Zero)

Bias Check (Span)

2

3

4

Results 3

Zero Bias 4

Difference

1

4

Response

1

2 Gas Concentration

1

2

3 Linearity Information

Gas

Span Gas Value/Range

Bias Gas ValueCimarron Energy Run 7

Liberty Oil Well

Parshall ND Start Time 15:31:23

Flare Run Length 60

06/14/11 Stop Time 16:31

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

-0.1 0.0 0.2 0.0 0.1

10.0 2.5 81.8 307.4 3.0

0.0 0.0 1.4 0.0 0.1

10.0 2.5 80.2 305.0 3.0

0.0% 0.0% 0.1% 0.1% 0.0%

0.1% 0.2% 0.8% 0.3% 0.6%

0.5% 0.0% 0.7% 0.0% 0.0%

0.0% 0.4% 0.9% 0.2% 0.2%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

14.8 3.9 15.5 0.0 0.3

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

14.8 3.9 16.5 0.0 0.4

1 15:31 14.7 4.0 17.1 0.1 0.9

2 15:32 14.9 3.9 17.2 0.0 0.8

3 15:33 14.9 3.9 15.5 0.1 0.8

4 15:34 14.8 3.9 18.4 0.0 0.8

5 15:35 14.9 3.9 14.5 -0.1 0.8

6 15:36 14.8 4.0 14.0 0.0 0.8

7 15:37 14.9 3.9 15.2 -0.1 0.8

8 15:38 14.8 4.0 15.8 0.0 0.8

9 15:39 14.7 4.0 13.9 0.0 0.8

10 15:40 15.0 3.9 15.8 0.0 0.2

11 15:41 14.8 3.9 13.6 0.0 -0.3

12 15:42 15.0 3.8 22.7 -0.1 0.5

13 15:43 15.1 3.8 17.4 0.0 0.6

14 15:44 14.9 3.9 17.4 -0.1 0.5

15 15:45 14.8 4.0 14.1 0.0 0.3

16 15:46 14.9 3.9 15.4 0.0 0.0

17 15:47 14.8 4.0 30.7 -0.1 0.5

18 15:48 14.8 4.0 15.9 0.0 0.2

19 15:49 15.2 3.7 23.0 0.0 0.4

20 15:50 14.5 4.1 21.8 -0.1 0.4

21 15:51 14.9 3.9 11.6 0.0 0.2

22 15:52 14.7 4.0 16.3 -0.1 0.5

23 15:53 14.8 4.0 13.1 -0.1 0.5

24 15:54 15.1 3.8 16.2 0.0 0.5

25 15:55 14.9 3.8 16.6 0.0 0.5

26 15:56 14.9 3.9 15.8 0.0 0.5

27 15:57 15.2 3.7 20.7 0.0 0.9

28 15:58 15.0 3.8 22.7 -0.1 0.6

29 15:59 15.0 3.8 21.9 0.0 0.2

30 16:00 14.9 3.9 23.2 0.0 0.1

31 16:01 14.8 4.0 14.1 0.0 0.5

32 16:02 14.9 3.9 17.5 0.0 0.6

33 16:03 14.8 4.0 13.2 0.0 0.1

34 16:04 14.9 3.9 18.2 0.1 0.2

35 16:05 14.8 4.0 15.4 0.0 0.3

36 16:06 14.8 4.0 14.0 -0.1 -0.5

37 16:07 14.8 4.0 14.6 -0.1 0.4

38 16:08 14.8 4.0 13.9 -0.1 0.6

39 16:09 14.4 4.2 16.7 0.0 0.6

40 16:10 15.0 3.8 12.0 -0.1 0.5

41 16:11 15.0 3.8 24.2 0.0 0.6

42 16:12 15.1 3.8 30.0 -0.1 0.8

43 16:13 14.9 3.9 14.9 0.0 0.7

44 16:14 14.9 3.9 19.4 -0.1 0.6

45 16:15 14.7 4.0 12.9 -0.1 0.4

46 16:16 14.7 4.0 17.8 -0.1 -0.2

47 16:17 14.6 4.1 19.6 0.0 0.4

48 16:18 15.0 3.9 15.7 0.0 0.2

49 16:19 14.8 4.0 17.2 0.0 0.2

50 16:20 15.1 3.8 15.9 0.0 0.6

51 16:21 14.7 4.0 17.6 0.1 1.0

52 16:22 14.4 4.2 10.5 0.0 0.6

53 16:23 14.6 4.1 11.3 0.0 -0.2

54 16:24 14.6 4.0 13.7 0.0 -0.5

55 16:25 14.6 4.1 11.3 0.0 -0.1

56 16:26 14.8 3.9 13.9 -0.1 -0.8

57 16:27 14.6 4.1 11.1 0.1 -0.3

58 16:28 14.5 4.2 11.8 0.0 0.1

59 16:29 14.6 4.1 14.5 0.0 0.4

60 16:30 14.7 4.0 11.0 -0.1 0.6 Results

Absolute Bias (Zero)

Span%

Span% Post Test Calibration

Zero%

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span)

Zero% Calibration Information

Span Gas Value

Calibration

Pretest Calibration Gas

Instrument RangeCimarron Energy Run 8

Liberty Oil Well

Parshall ND Start Time 16:48:23

Flare Run Length 60

06/14/11 Stop Time 17:48

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182 1490 10

10.00 2.48 79.1 300.0 3.0

0.0 0.0 1.4 0.0 0.1

10.0 2.5 80.2 305.0 3.0

-0.1 0.0 0.2 0.0 0.1

10.0 2.5 81.3 299.1 3.1

0.3% 0.0% 0.5% 0.1% 0.0%

0.1% 0.2% 1.4% 0.7% 1.2%

0.3% 0.0% 0.7% 0.0% 0.0%

0.0% 0.0% 0.6% 0.4% 0.6%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

14.9 3.8 21.0 0.0 0.6

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

14.9 3.8 22.0 0.0 0.7

1 16:48 14.7 4.0 17.2 -0.1 2.4

2 16:49 15.2 3.6 22.6 0.0 1.4

3 16:50 14.9 3.8 24.1 -0.1 1.4

4 16:51 14.6 4.1 19.9 -0.1 1.2

5 16:52 14.7 4.0 14.8 0.0 1.3

6 16:53 14.6 4.0 13.2 0.0 1.3

7 16:54 14.5 4.2 14.0 -0.1 1.2

8 16:55 14.7 4.0 13.0 0.0 1.4

9 16:56 15.1 3.8 15.6 0.1 1.4

10 16:57 15.1 3.7 22.6 0.1 1.4

11 16:58 14.8 3.9 20.1 0.0 1.4

12 16:59 14.8 3.9 16.4 0.1 1.4

13 17:00 14.6 4.1 13.2 0.0 1.2

14 17:01 14.7 4.0 13.7 -0.1 1.2

15 17:02 14.9 3.9 14.1 0.0 1.2

16 17:03 14.7 4.0 13.0 -0.2 1.2

17 17:04 14.6 4.0 17.6 0.0 1.2

18 17:05 14.8 3.9 11.7 0.1 0.2

19 17:06 14.8 3.9 14.5 -0.1 -0.5

20 17:07 14.6 4.0 13.4 0.0 -0.4

21 17:08 14.6 4.1 14.8 -0.1 0.3

22 17:09 14.8 4.0 14.8 -0.1 0.3

23 17:10 15.0 3.8 20.3 0.0 0.9

24 17:11 14.8 4.0 18.5 0.0 1.0

25 17:12 15.1 3.7 21.2 -0.1 1.0

26 17:13 15.0 3.8 20.2 -0.1 1.0

27 17:14 15.1 3.7 20.0 0.1 0.5

28 17:15 15.0 3.8 18.7 0.1 -0.6

29 17:16 15.2 3.7 19.3 -0.1 -0.2

30 17:17 15.3 3.6 31.2 -0.1 0.5

31 17:18 15.1 3.7 24.2 -0.1 1.0

32 17:19 15.1 3.8 21.0 -0.1 1.2

33 17:20 15.0 3.9 19.8 -0.1 0.8

34 17:21 15.1 3.7 20.4 -0.1 0.8

35 17:22 15.0 3.7 22.1 0.0 1.1

36 17:23 15.0 3.8 18.9 0.0 1.2

37 17:24 15.2 3.7 22.7 0.0 -0.4

38 17:25 15.1 3.7 23.3 -0.1 -0.1

39 17:26 14.9 3.8 18.2 -0.2 0.5

40 17:27 15.0 3.8 19.8 0.0 0.7

41 17:28 15.1 3.7 22.9 -0.1 -0.4

42 17:29 15.3 3.6 138.2 -0.1 0.9

43 17:30 15.3 3.7 90.9 0.0 0.4

44 17:31 15.0 3.8 32.2 -0.1 -0.2

45 17:32 15.1 3.7 47.7 -0.1 -0.5

46 17:33 15.0 3.9 18.3 -0.1 0.3

47 17:34 14.9 3.8 14.7 -0.1 1.1

48 17:35 14.9 3.8 18.0 0.0 1.2

49 17:36 14.9 3.8 15.8 0.1 0.6

50 17:37 15.2 3.7 20.5 0.0 -0.3

51 17:38 15.0 3.8 20.9 -0.1 1.0

52 17:39 14.9 3.9 13.3 0.0 1.2

53 17:40 15.3 3.6 24.7 -0.1 1.2

54 17:41 14.8 3.9 18.7 0.0 1.0

55 17:42 14.7 4.0 14.4 -0.1 0.5

56 17:43 14.7 4.0 15.9 -0.1 0.3

57 17:44 14.8 3.9 12.4 0.0 0.2

58 17:45 14.9 3.8 18.2 -0.1 0.1

59 17:46 14.9 3.9 14.6 -0.1 0.2

60 17:47 14.8 3.9 14.8 0.1 0.3

Zero% Calibration Information

Span Gas Value

Calibration

Pretest Calibration Gas

Instrument Range

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span) Results

Absolute Bias (Zero)

Span%

Span% Post Test Calibration

Zero%Cimarron Energy Run 9

Liberty Oil Well

Parshall ND Start Time 8:45:06

Flare Run Length 60

06/14/11 Stop Time 9:45

O 2 CO 2 CO CH4 NMHC

21.1 5.0 182.0 1490.0 10.0

10.0 2.5 79.1 300.0 3.0

-0.1 0.0 1.1 0.0 0.1

10.0 2.5 78.0 294.2 3.0

0.0 0.0 1.1 0.1 0.0

10.0 2.5 77.1 301.4 3.0

0.0% 0.0% 0.1% 0.1% 1.0%

0.1% 0.4% 0.9% 0.5% 1.0%

0.5% 0.0% 0.0% 0.0% 1.0%

0.0% 0.2% 0.5% 0.5% 0.4%

Corrected O 2

% Corrected

CO 2 % Corrected CO

ppm Corrected

CH4 ppmvw Corrected

TVOC ppm

15.1 3.8 15.4 -0.1 0.1

Run Length

(Minutes) Time Uncorrected

O 2 % Uncorrected

CO 2 % Uncorrected

CO ppm Uncorrected

CH4 ppmvw Uncorrected

TVOC ppm

15.1 3.8 16.0 0.0 0.1

1 6/15/11 8:45 15.2 3.7 16.8 0.0 0.4

2 6/15/11 8:46 15.0 3.8 15.4 0.0 0.3

3 6/15/11 8:47 15.1 3.8 15.0 -0.1 0.3

4 6/15/11 8:48 15.1 3.8 14.2 0.0 0.3

5 6/15/11 8:49 15.1 3.8 13.9 0.0 0.3

6 6/15/11 8:50 15.2 3.7 14.68 -0.1 0.3

7 6/15/11 8:51 14.9 3.9 15.0 0.0 0.3

8 6/15/11 8:52 15.1 3.7 14.9 0.0 0.3

9 6/15/11 8:53 15.1 3.8 14.0 0.0 0.4

10 6/15/11 8:54 15.0 3.8 15.2 0.0 0.3

11 6/15/11 8:55 15.0 3.9 14.4 -0.1 0.0

12 6/15/11 8:56 15.1 3.8 13.8 -0.1 0.4

13 6/15/11 8:57 15.2 3.8 15.0 0.0 0.8

14 6/15/11 8:58 15.0 3.8 16.2 -0.1 0.7

15 6/15/11 8:59 15.0 3.9 13.1 0.0 0.3

16 6/15/11 9:00 15.1 3.8 14.2 -0.1 0.1

17 6/15/11 9:01 15.0 3.9 14.8 -0.1 0.1

18 6/15/11 9:02 15.2 3.8 15.5 0.0 0.2

19 6/15/11 9:03 15.0 3.9 14.8 0.0 0.1

20 6/15/11 9:04 15.0 3.8 14.2 0.0 0.0

21 6/15/11 9:05 14.9 3.9 13.16 0.0 0.1

22 6/15/11 9:06 15.0 3.9 13.9 0.0 0.1

23 6/15/11 9:07 15.0 3.9 13.2 -0.1 0.1

24 6/15/11 9:08 15.0 3.9 13.1 0.0 0.2

25 6/15/11 9:09 15.1 3.8 15.2 0.0 0.3

26 6/15/11 9:10 14.8 4.0 12.0 0.0 0.2

27 6/15/11 9:11 15.2 3.7 16.0 0.0 0.3

28 6/15/11 9:12 15.0 3.8 14.7 -0.1 0.2

29 6/15/11 9:13 15.1 3.8 14.0 0.1 0.0

30 6/15/11 9:14 14.8 4.0 14.0 0.0 -0.4

31 6/15/11 9:15 15.0 3.8 13.1 -0.1 0.1

32 6/15/11 9:16 14.7 4.1 13.4 -0.1 0.0

33 6/15/11 9:17 14.9 4.0 11.8 -0.1 0.0

34 6/15/11 9:18 14.9 4.0 13.7 0.0 0.0

35 6/15/11 9:19 15.1 3.8 13.5 -0.1 0.1

36 6/15/11 9:20 15.5 3.6 17.4 -0.1 0.0

37 6/15/11 9:21 15.2 3.7 23.0 0.1 0.0

38 6/15/11 9:22 14.9 4.0 15.2 0.1 0.1

39 6/15/11 9:23 15.5 3.6 18.2 0.0 0.2

40 6/15/11 9:24 15.5 3.6 22.6 0.0 0.0

41 6/15/11 9:25 15.5 3.5 26.7 0.0 0.0

42 6/15/11 9:26 15.2 3.8 17.7 0.0 0.0

43 6/15/11 9:27 15.5 3.6 17.3 0.1 0.0

44 6/15/11 9:28 15.7 3.5 26.1 0.0 0.0

45 6/15/11 9:29 15.7 3.4 29.9 0.0 0.0

46 6/15/11 9:30 15.3 3.7 23.4 -0.1 0.0

47 6/15/11 9:31 15.0 3.9 15.1 0.0 0.1

48 6/15/11 9:32 15.4 3.7 17.4 0.1 0.1

49 6/15/11 9:33 15.2 3.7 19.0 -0.1 0.0

50 6/15/11 9:34 15.0 3.9 14.0 0.1 -0.1

51 6/15/11 9:35 15.0 3.9 14.0 0.0 0.0

52 6/15/11 9:36 15.3 3.7 15.8 0.0 0.0

53 6/15/11 9:37 15.1 3.8 16.9 0.1 0.0

54 6/15/11 9:38 15.1 3.8 16.3 0.0 0.0

55 6/15/11 9:39 15.1 3.8 15.5 0.0 0.0

56 6/15/11 9:40 15.3 3.8 15.6 0.2 -0.1

57 6/15/11 9:41 15.4 3.8 18.8 0.0 0.0

58 6/15/11 9:42 15.1 3.9 15.2 0.0 0.0

59 6/15/11 9:43 15.2 3.9 14.8 -0.1 -0.1

60 6/15/11 9:44 15.1 4.0 13.8 0.0 -0.1 Results

Absolute Bias (Zero)

Span%

Span% Post Test Calibration

Zero%

Absolute Bias (Span)

Absolute Drift (Zero)

Absolute Drift (Span)

Zero% Calibration Information

Span Gas Value

Calibration

Pretest Calibration Gas

Instrument RangeCimarron Energy

Liberty Oil Well

Parshall ND

Flare

6/14/2011

10 oz.

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

Waste Gas Inlet NMOC (lb/hr as C 3 H 8 ) 489.2

Pilot Inlet NMOC (lb/hr as C 3 H 8 ) 0.5

Sum of Inlets NMOC (lb/hr as C 3 H 8 ) 489.7

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

% DRE (carbon balance) 100.00%

%DRE CalculationsCimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Methods 1-4: Determination of Stack Gas Velocity and Volumetric Flow Rate

Sample Calculations

sample volume (scf) = 17.64 * V M * Y D * {P B + **∆** H/13.6}

T M + 460

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

74 460

= 33.629

moisture volume (scf) = 0.04715 * V LC

= 0.04715 * 34

= 1.603

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

(V M(STD) + V W(STD) )

= 1.603

( 33.629 + 1.603 )

= 0.046

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

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

= 28.98

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

= 28.98 * (1 - 0.046 ) + (18 * 0.046 )

= 28.48 +Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Methods 1-4: Determination of Stack Gas Velocity and Volumetric Flow Rate

Sample Calculations (continued)

gas velocity (ft/sec) = 85.49 * C P * **√∆** P AVG *

[P B + P S / 13.6] * M A

= (85.49) * 0.83 * 0.078 * 936 +

27.64 + 0.00 * 28.48

13.6

= 7.4

**π** * (D S / 12) 2

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

**π** * ( 42.63 / 12) 2

= 60 * 4 * 7.4

= 4,382

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

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

**π** * ( /12) 2 528 * [ 27.64 + 0.00 / 13.6 ]

= 60 * ) * * ( 936 + 460) * 29.92

= 1,462 7.4 T S + 460

42.6

4 0.046 * (1 - 

# [ ] 460Cimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Methods 1-4: Determination of Stack Gas Velocity and Volumetric Flow Rate

Variables and Abbreviations

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

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

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

C P - pitot tube constant (unitless)

D S - diameter of the stack (inches)

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

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

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

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

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

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

P B - barometric pressure (inches mercury)

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

P STD - standard pressure (29.92 inches mercury)

T M - average dry gas meter temperature (oF)

T S - average stack temperature (oF)

T STD - standard temperature (528 oR)

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

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

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

V S - stack gas velocity (feet per second)

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

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

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Method 3A: Determination of O 2 / CO 2 Concentrations in Emissions from Stationary

Sources ( Instrumental Analyzer Procedure )

Sample Calculations

CO 2 conc, drift cal (%vd)

= (%FS STACK - %FS 0 ) * [Span Gas Conc (%vd)]

(%FS SPAN -%FS 0 )

= ( 1.5 - 0 ) * ( 2.48 )

( 2.5 ) - ( 0 )

= 2.5

O 2 conc, drift cal (%vd)

= (%FS STACK - %FS 0 ) * [Span Gas Conc (%vd)]

(%FS SPAN -%FS 0 )

= ( 18.7 - 0.0 ) * ( 10 )

( 10.1 ) - ( 0.0 )

= 18.5

Variables and Abbreviations

cal - calibrated

conc - concentration

CO 2 - Carbon Dioxide

O 2 - Oxygen

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

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

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

%vd- dry volume percentCimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Method 10: Determination of Carbon Monoxide Emissions from Stationary

Sources ( Instrumental Analyzer Procedure )

Sample Calculations

CO conc, drift cal (ppmvd)

= (%FS STACK - %FS 0 ) * [Span Gas Conc (ppmvd)]

(%FS SPAN -%FS 0 )

= ( 105.1 - 1.2 ) * ( 79.1 )

( 77.9 ) - ( 1.2 )

= 107.2

CO emissions (lb/hr)

= [CO (ppmvd)]*(F DSCFM )*(1.556 X 10 E-7)*(46.01)

= ( 107.2 )* 1,462 * (1.556 X 10E-7) * (46.01)

= 0.70

Variables and Abbreviations

cal - calibrated

conc - concentration

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

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

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

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

lb/hr - pounds per hour

ppmvd - parts per million, dry volume basis

g/bhp-hr - grams per brake horsepower-hourCimarron Energy

Liberty Oil Well

Parshall, ND

Flare

06/15/11

EPA Method 25A: Determination of Total Gaseous Organic Concentrations Using a Flame Ionization Analyzer

Sample Calculations

NMOC conc, drift cal (ppmvd as C 3 H 8 )

= ( %FS STACK - %FS 0 ) * [Span Gas Conc (ppmvd)]

( %FS SPAN -%FS 0 )

= ( 43.9 - 0.0 ) * ( 30.2 )

( 30.2 ) - ( 0.0 )

= 43.9

NMOC emissions (lb/hr as C 3 H 8 ) [NMOC (ppmvd)]*(F DSCFM )*(1.556 X 10 E-7)*(44.09)

= ( 43.9 ) * ( 1,462 ) * (1.556 X 10 E-7) * 44.09

= 0.46

Variables and Abbreviations

as C 3 H 8 - as propane or C3

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

cal - calibrated

conc - concentration

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

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

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

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

lb/hr - pounds per hour

tpy - tons per year

ppmvw - parts per million, wet volume basis

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

# Appendix Two : Field and Laboratory Data

### 1 oz. Inlet Pressure

### 4 oz. Inlet Pressure

### 10 oz. Inlet Pressure

# Appendix Three : Calibration Data

# Appendix Four : SchematicsF F

ft 3

“Hg orifice

manometer dry gas

meter air-tight

pump vacuum

gauge main valve bypass

valve thermocouples sample probe

S-type pitot

with

thermocouple

100 mL H

2 0 250g Silica gel

empty

100 mL H

2 0 stack wall

chilled impinger train

sample line pitot lines



### EPA Methods 1,2, & 4

sampling train schematic

### EPA Methods 3A, 10, 18 & 25A

sampling train schematic CO

CO

2 O

2 CDAS stack wall

sample probe

with

in-stack filter moisture removal

system with pump

calibration gas

manifold pressure

regulator and pressure

gauge sample transport lines

heated sample lines calibration valve

sample control valve

with bypass

flowmeter

sample control

valve Servomex Series 1400

TECO Model 48H

JUM Model VE-7 FID pump

VOC Tedlar bag for

subsequent GC

analysis

### PROJECT #98-19895



## INCINERATOR EFFICIENCY SURVEY

**QUESTOR TECHNOLOGIES INC.**

**MOBIL LONE PINE 06-03-030-27-W4M**

**INCINERATOR EXHAUST STACK**

**November 5, 1998**

**Prepared by:**

MAXXAM ANALYTICS INC.

9331 - 48th Street

Edmonton, Alberta

T6B 2R4

**Submitted to:**

QUESTOR TECNOLOGIES INC.

Suite 500, 665-8 Street SW

Calgary, Alberta

T2P 3K7Questor Technologies Inc.

Mobil Lone Pine Creek (06-03) - November 1998

Project #98-19895

-i

## SUMMARY

On November 5, 1998, the Edmonton office of Maxxam Analytics Inc. conducted a source emission survey and efficiency

test on the Incinerator Exhaust Stack that was operating on a Mobil well site (06-03-030-27-W4M) near the Mobil Lone

Pine Creek Gas Plant. Sampling was carried out on the separator inlet to determine concentrations of organic compounds

and water content. Sampling was carried out on the separator outlet to determine concentrations of organic compounds,

total reduced sulphur compounds and water content. Sampling was carried out on the incinerator exhaust stack to

determine concentrations of sulphur dioxide, oxides of nitrogen, carbon monoxide, total reduced sulphur compounds

and organic compounds. Furthermore, destruction efficiencies were determined for total reduced sulphur compounds

and organic compounds.

The summary of results is as follows:

**RUN: SEP. INLET**  **SEP. OUTLET STACK**  **AVERAGE**

**DATE:** Nov. 5, 1998 Nov. 5, 1998 Nov. 5, 1998

**TIME:** 12:06 - 13:06 12:06 - 13:06 12:06 - 13:06

WATER CONTENT

(lb. water/million ft 3 of wet gas) 6.4 4.3

- -

SULPHUR DIOXIDE

(ppmv wet)

- - 547

-

(ppmv dry) - - 610 -

(kg/hr)

- - - -

OXIDES OF NITROGEN (as NO 2 )

(ppmv wet) - - 67 -

(ppmv dry) - - 75 -

(kg/hr)

- - - -

CARBON MONOXIDE

(ppmv wet) - - 226 -

(ppmv dry) - - 252 -

(kg/hr)

- - - -Questor Technologies Inc.

Mobil Lone Pine Creek (06-03) - November 1998

Project #98-19895

-ii- TOTAL REDUCED SULPHUR COMPOUNDS

Hydrogen Sulphide (H 2 S) (ppmv wet) - - <0.9 -

(ppmv dry) - 10400 <1.0 -

(g/hr)

- - - -

Carbonyl Sulphide (COS) (ppmv wet) - - <0.9 -

(ppmv dry) - 6 <1.0 -

(g/hr)

- - - -

Carbon Disulphide (CS 2 ) (ppmv wet) - - <0.4 -

(ppmv dry) - <0.5 <0.5 -

(g/hr)

- - - -

ORGANIC COMPOUNDS

Methane (CH 4 ) (ppmv wet) - - <0.9 -

(ppmv dry) 825000 816900 <1.0 -

(g/hr)

- - - -

Ethane (C 2 H 6 ) (ppmv wet) - - <0.9 -

(ppmv dry) 44100 44800 <1.0 -

(g/hr)

- - - -

Propane (C 3 H 8 ) (ppmv wet) - - <0.9 -

(ppmv dry) 13700 14800 <1.0 -

(g/hr)

- - - -

Butane (C 4 H

10

) (ppmv wet) - - <0.9 -

(ppmv dry) 7040 9420 <1.0 -

(g/hr)

- - - -

Pentane (C 5 H

12 ) (ppmv wet) - - <0.9 -

(ppmv dry) 3520 5880 <1.0 -

(g/hr)

- - - -

Hexane (C 6 H 14

) (ppmv wet) - - <0.9 -

(ppmv dry) 1960 3510 <1.0 -

(g/hr)

- - - -Questor Technologies Inc.

Mobil Lone Pine Creek (06-03) - November 1998

Project #98-19895

-iii- Heptane + (C 7 H

16

) (ppmv wet) - - <0.9 -

(ppmv dry) 4680 3690 <1.0 -

(g/hr)

- - - -

Components heavier than heptane are presented in Appendix II of this report

DESTRUCTION EFFICIENCIES – TRS (as Sulphur)

(total in – ppmv as Sulphur) 10420 - - -

(total out – ppmv as Sulphur) 1.50 - - -

(% efficiency) >99.99 - - -

DESTRUCTION EFFICIENCIES – GASEOUS ORGANICS (as CH 4 )

(total in – ppmv as Methane) 851328 - - -

(total out – ppmv as Methane) 1.37 - - -

(% efficiency) >99.99 - - -Mr. Kim Eastlick

Facilities Division



### EnvironmentSafety & 

### Technical Services

AlbertaEliergy ai1dUtilities Board

Regarding: Portable Incinerator Test

Shell 29 Limestone 14-2-33-10W5m

Jan 25, 2000/03/04 

### Shell Canada Limited

400-4th Avenue S.W.

P.O. Box 100. Station M

Calgary, Alberta, T2P2H5

20 March, 2000

Attached are the findings of the Portable incinerator test conducted by Shell Canada Limited in

conjunction with Norward Energy Services, the owner of the incinerator, and Questor

Technologies, the manufacturer of the incinerator.

Yours truly,



# .. tt£

.. ..•.•.•...**~~ R.L~**  Nels()n.

qrillingand Production EngineE!ring Advisor

Copies

Robert Knowles

Divisi.onManager

Norwa;rdEnergy Limited

DanierMotyka

President/CpO

Questor Technology Inc

CAPPWellTestFlaring Comrnitteemembers & CAPP Well Construction Committee Chairman

CAPP Environmental Committee Chairman·

File: Incinertatornote to EUB.DOCpage 1



## Conducted on Jan 

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



# Portable 

# Well "'Fest Incinerator Test Results

Shell 

# 29 Limestone 14-2-33-10W5M

2-2-33-10W5 surface 

# location

## Maxxam Analytics Inc.



# Summary of Inlet 

# and 

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

Attachment 3



## And



# Air 

# /Fuel Calculations200

200 833

833

333

333 933

933

3500

3500 13933

13933 10.39

103900

766300

766300 AVERAGE

Shell Canada Limited

Limestone 29

- "l1luary 2000

Project #00-20310

9.98

99800



## msoo

772500 

## a

JiUl.25, 2000

19:04

- 20:04

":

.. 

## -

... - .:

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

106900

764200

764200 

### 4

JiUl.25,2000

18:00 -19:00

10.51

105100 1

JiUl.25,20oo

16:53 -17:53

(pp,nvwet) 762200

(ppmv dry) 762200

(ppm» ioet) 14400 14000 13400

(ppmv dTY) 14-100 14000 13400

(ppmv tuet) 1000 700 800

(ppmvdry) 1000 700 800

(ppmv.loet) 900 900 1000

(ppmvdry) 900 900 1000

(ppmv wet) 400 200 400

(ppm» dry) 400 200 400

(ppmvwet) 200 200 200

(ppmvdry) 200 200 200

(ppmv wet) 4800 3800 1900

(ppmvdry) 4800 3800 1900 1;2.4 

### -(3 

## o

INCINERATOR INLET 

## (126 E3m3/ day)

RUN:

DATE:

TIME:

HYDROGEN SULPHIDE

Mole %

ppmv(dTY)

ORGANICCOMPOUNDS

Metltalle

.**(CH~)**

Etlzalle(CJlJ

Propane(CPJ

Blltane (C.,H.,,)

Pentane (C,lfJ:)

Hexane (CJlIJ 

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

I

# fi,141~~~~



# _

··1·



# I

-iv-

. - 

### ..... "-

'-' .. " ..

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

### _ 

## -_

, 

### .. Limestone 29

- January 2000

Project #00-20310

851

960 27.3

30.6 6597

7415 AVERAGE

47

53 28.7

32.2 6510

7316

,1



### Jan. 25, 2000

19:04.; 20:04

32

36 33.4 64-l0

37.4 i212



### Z



### Jan. 25,2000

18:00- 19:00

22.3 19.7 6842

7718

2473

2790

1



### Jari. 25, 2000

16:53- 17:53 RUN:

DATE:

,TIME: !;la-f)u



## INCINERATOR EXHAUST STACK (126 

## E3rn3lday)

SULPHUR DIOXIDE

OXIDESOFNITRQGEN (as N02)

(ppmvlvet)

(ppmvdry)

(ppmvtl1et)

(pplnvdry) (ppmtrtuet)

(ppmvtiry)

·CARBONMONOXIDE

# ~I 

# r

I 

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

I

iii.· •• ••· ••

# ·l?.....-~ '.

·

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

# --------~

__ ---------'



# \ 1

I

'i

II

I

I

I

I

. ','

-

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

CarbollylSrtlplridll (COS) (pprnv uret} <0.9

(ppm» dry) <1.0 .'

.-

... -

.... ,

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

(ppmv dry) <1.0 

# I

I'

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

(ppm» dry) <1.0 <0.9 <0.9 <0.9

<1.0 <1.0 <1.0

<0.9 <0.9 <0.9

<1.0 <1.0 <1.0

<0.9 <0.9 <0.9

<1.0 <1.0 <1.0

2.7 24.5 9.3

3.0 27.5 10.5

<0.9 <0.9 <0.9

<1.0 <-LO d.O

4.5 23.1 10.7

5.0· 26.0 '12.0 4.4

5.0 <0.9

<1.0

(ppmvwet) <0.9

(ppmu dry) <1.0

(ppmv wet)

(ppmvdry) Ethane. (CzHJ ORGANIC.CQMPOUNDS

Methani!(CHJ (pp"ivlvet)

(ppm» dry) \ I"--o

....

## ~~~

_

I

I

i,

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

_.**~..:** • - ." "-

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

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

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

(ppm» tuet) 0.9 0.9 16.9 6.2

(ppm» dry) 1.0 1.0 19.0 7.0

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

(pprnvdry) <1.0 <1.0 <LO <LO

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

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

(ppmvwet) <0.9 <0.9 <0.9 <0.9

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

### (CPuJ



# I 

# 1

Hexane (CJ{.J

II

. 

# II

Heptane + (C,HIJ

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

_



# I

I

103900

<4.0

>99.9962

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

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

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



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

(total iII-pprnvas 

### Methane) 828102 821376 818214

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

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

<86.9

>99.9894



### -vi-

.... 

### ----- 

## ------

- ".- ..•... -: "._

..... .-- ".;

. •• ..;....o¥iT.;., .: •.

, ."

. "'-.' ,- " •• 

### .. :

..... '

.. - 

### ... ".