APACHE ZAMA BATTERY 12 ENHANCED OIL RECOVERY PROJECT

APACHE ZAMA BATTERY 12

ENHANCED OIL RECOVERY PROJECT

Greenhouse Gas Emissions Reduction

Offset Project Report

For the Period January 1, 2012 – December 31, 2012

Version 3.0

23 February, 2013

Prepared by: Blue Source Canada ULC (Authorized Project Contact) Suite 700, 717-7

th Avenue SW

Calgary, Alberta T2P 3R5 T: (403) 262-3026 F: (403) 269-3024 www.bluesourceCAN.com

Prepared for: Apache Canada Ltd (Project Proponent) 421 7

th Avenue SW, Suite 2800

Calgary , Alberta T2P 2S5 T: (403) 261-1200 F: (403) 266-5987

www.apachecorp.com

http://www.bluesourcecan.com/

http://www.apachecorp.com/

Page 2

Prepared by: Blue Source Canada ULC 700, 717 7

th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024

Contents Contents ........................................................................................................................................................ 2

List of Tables ................................................................................................................................................. 2

List of Figures ................................................................................................................................................ 2

List of Abbreviations ..................................................................................................................................... 3

1 PROJECT SCOPE AND PROJECT DESCRIPTION ....................................................................................... 4

2 PROJECT CONTACT INFORMATION ....................................................................................................... 6

3 PROJECT DESCRIPTION AND LOCATION ................................................................................................ 7

4 PROJECT IMPLEMENTATION AND VARIANCES ..................................................................................... 8

5 REPORTING PERIOD ............................................................................................................................ 10

6 GREENHOUSE GAS CALCULATIONS ..................................................................................................... 10

7 GREENHOUSE GAS ASSERTION ........................................................................................................... 17

8 OFFSET PROJECT PERFORMANCE ....................................................................................................... 18

9 PROJECT DEVELOPER SIGNATURES ..................................................................................................... 20

10 STATEMENT OF SENIOR REVIEW .................................................................................................... 21

11 REFERENCES .................................................................................................................................... 22

APPENDIX A – CONFIRMATION OF CREDITING EXTENSION APPROVAL ..................................................... 23

List of Tables TABLE 1 - EMISSION FACTORS USED FOR THE PROJECT .............................................................................................. 16

TABLE 2 - OFFSET TONNES CREATED BY VINTAGE YEAR AND GHG ............................................................................. 17

List of Figures FIGURE 1 - LOCATION OF ZAMA EOR PROJECT.............................................................................................................. 7

FIGURE 2 - CREDITS CREATED BY PROJECT, BY VINTAGE YEAR ................................................................................... 18

FIGURE 3 - RELATIONSHIP BETWEEN ACID GAS INJECTION VOLUMES AND OCS CREATED ........................................ 19

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List of Abbreviations AEOR Alberta Emissions Offset Registry

AENV Alberta Environment (now Alberta Environment & Sustainable Resource Development)

AESRD Alberta Environment & Sustainable Resource Development (previously Alberta Environment)

AGI Acid Gas Injection

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide equivalent

e3m3 Thousand cubic meters

EOR Enhanced Oil Recovery

ERCB Energy Resources Conservation Board

ft foot/feet

GHG Greenhouse gas

Hrs hour/s

H2S Hydrogen sulphide

HFC Hydrofluorocarbon/s

HP Horsepower

kg Kilogram

km Kilometre

kPa Kilopascal

kW Kilowatt

LHV Lower Heating Value

m3 Cubic metres/s

MJ Megajoule

MWh Megawatt-hour

N/A Not applicable

N2O Nitrous Oxide

PFC Perfluorocarbon/s

QA/QC Quality assurance and quality control

SF6 Sulphur Hexafluoride

SO2 Sulphur Dioxide

SSs Sources and sinks

VRU Vapour Recovery Unit

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1 PROJECT SCOPE AND PROJECT DESCRIPTION The project title is: Apache Zama Battery 12 Enhanced Oil Recovery Project

The project’s purpose(s) and objective(s) are:

The opportunity for generating carbon offsets with this project arises from the direct and indirect reductions of greenhouse gas (GHG) emissions resulting from the geological storage of carbon dioxide contained in acid gas as part of an enhanced oil recovery (EOR) scheme.

Date when the project began:

Initiation of the commercial injection of acid gas for EOR was December 1, 2004.

Expected lifetime of the project:

It is anticipated that this EOR project will continue until it becomes economically unviable for oil production in the field.

Credit start date: The credit start date was December 1, 2004.

Credit duration period: The initial project credit duration is for 8 years starting December 1, 2004 and ending November 30, 2012. Alberta Environment and Sustainable Resource Development has granted, in a letter dated February 12, 2013 (see Appendix A), a 5 year Crediting Extension Period, to run from December 1, 2012 – November 30, 2017.

Reporting period: January 1, 2012 – December 31, 2012

Actual emissions reductions:

Previously registered and calculated project emission reductions from this project are, per vintage year, shown below in tonnes CO2e: 2004: 17,150, of which December 1 – December 20, 2004: 11,065* December 21 – December 31, 2004: 6,085* 2005: 203,923 2006: 157,951 2007: 88,077 2008: 79,589 2009: 61,409 2010: 41,811 2011: 16,145 2012: 3,776

Total – 669,831 tonnes CO2e *Note that there were 20 days at the beginning of the project period where the project was licensed as an acid has injection (AGI) rather than an EOR project. Although the project was still avoiding GHG emissions via the geological sequestration of carbon dioxide, no oil was being recovered. The appropriate protocol for this period was the AGI protocol, which was used in the calculations. This use of two protocols for one project was discussed with and approved by Alberta Environment.

Applicable Quantification Protocol(s):

The quantification protocol used is for this reporting period is the Quantification Protocol for Enhanced Oil Recovery – Streamlined (v1, October 2007) as published by Alberta Environment.

Protocol(s) Justification: The project is an enhanced oil recovery (EOR) project in northwest Alberta, therefore the use of the EOR protocol for the project is appropriate. Prior to EOR, carbon dioxide contained in acid gas associated with the produced gas

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was processed through sulphur recovery and incineration and the formation CO2 was vented to the atmosphere. Note that there were 20 days at the beginning of the project period where the project was licensed as an acid has injection (AGI) rather than an EOR project. Although the project was still avoiding GHG emissions via the geological sequestration of carbon dioxide, no oil was being recovered. The appropriate protocol for this period was the AGI protocol, which has been used in the calculations. This use of two protocols for one project has been discussed with and approved by Alberta Environment.

Other Environmental Attributes:

There are no other environmental attributes (e.g. RECs, etc) being claimed by this project.

Legal land description of the project or the unique latitude and longitude:

The project is located in Alberta. The nearest settlement is Zama City. EOR is ongoing in multiple pools within the oil reservoir, but the recovered oil flows to the oil battery (00/14-12-116-6W6), therefore the battery location is used for this project. Latitude: 59° 03' 57" N Longitude : 118° 52' 16" W

Ownership: Apache Canada Ltd. is the sole owner of the assets and project in the Zama oil field.

Reporting details: This project has already claimed historic credits from December 1, 2004 – December 31, 2011. As outlined in the OPP, this report covers the remainder of the initial crediting period (i.e. January 1, 2012 – November 30, 2012) as well as the first month of the crediting period extension (December, 2012). It is anticipated that subsequent reporting will occur annually.

Verification details: The verifier, RWDI Air Inc, is an independent third-party that meets the requirements outlined in the Specified Gas Emitters Regulation (SGER). An acceptable verification standard (e.g. ISO14064-3) has been used and the verifier has been vetted to ensure technical competence with this project type. This is the 2nd consecutive verification carried out by the verifier for this project.

Project activity: This project meets the requirements for offset eligibility as outlined in section 3.1. Of the Technical Guidance for Offset Project Developers (version 3.0, February 2012). In particular: 1. The project occurs in AB: as outlined above;

2. The project results from actions not otherwise required by law and

beyond business as usual and sector common practices: Offsets being claimed under this project originate from a voluntary action. The project activity (i.e. enhanced oil recovery) occurs at a non-regulated facility and is not required by law. The protocol uses a government approved quantification protocol, which indicates that the activity is undertaken by less than 40% of the industry and is therefore not considered to be

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sector common practice; 3. The project results from actions taken on or after January 1, 2002: as

outlined above; 4. The project reductions/removals are real, demonstrable, quantifiable

and verifiable: the project is creating real reductions that are not a result of shutdown, cessation of activity or drop in production levels. The emission reductions are demonstrable, quantifiable and verifiable as outlined in the remainder of this plan.

5. The project has clearly established ownership: Apache Canada Ltd is the

owner and operator of the Zama Battery 12 facility and EOR scheme. Credits created from the specified reduction activity have not been created, recorded or registered in more than one trading registry for the same time period.

6. The project will be counted once for compliance purposes: The project credits will be registered with the Alberta Emissions Offset Registry (AEOR) which tracks the creation, sale and retirement of credits. Credits created from the specified reduction activity have not been, and will not be, created, recorded or registered in more than one trading registry for the same time period.

2 PROJECT CONTACT INFORMATION Project Developer Contact Information

Apache Canada Ltd. John Hawkins Director, EH&S Phone: 403-817-5074 Fax: 403-261-1373 [email protected]

421 7th Avenue SW Calgary Alberta T2P 2S5 Canada www.apachecorp.com

Authorized Project Contact

Blue Source Canada Graham Harris Vice President, Technical Services Phone: 403-262-3026 x234 Fax: 403-269-3024 [email protected]

717 7th Avenue SW Calgary Alberta T2P 0Z3 Canada www.bluesourcecan.com

Verifier

RWDI Air Inc. Trevor Cavanaugh Project Manager Phone: 403-232-6771 x 6233 Fax: 403-232-6762

Suite 1000, 736-8th Avenue SW Calgary Alberta T2P 1H4 Canada

mailto:[email protected]

http://www.apachecorp.com/


http://www.bluesourcecan.com/

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[email protected] www.rwdiair.com

3 PROJECT DESCRIPTION AND LOCATION The Zama Battery 12 Enhanced Oil Recovery Project (‘the Project’) is located in the north-western corner

of the province of Alberta, approximately 875 km (550 miles) northwest of Edmonton, as shown in

Figure 1 (overleaf). The nearest settlement is Zama City. The owner, operator and project proponent of

the Project is Apache Canada Ltd (‘the Proponent’). The acid gas, containing primarily CO2 and hydrogen

sulphide (H2S), is compressed and dehydrated, then injected into a well-characterized producing

reservoir called the Zama oil field.

Figure 1 - Location of Zama EOR Project

The Zama-Virgo oilfields in the Middle Devonian Keg River Pinnacles are the primary oil producers in the

area. The area was discovered in 1967 and the Zama sour gas plant (‘the Plant’) first produced gas in

1974. The Plant operated a modified three-stage Claus sulphur recovery unit to treat the acid gas

separated from the raw gas during the gas sweetening operations. The sulphur recovery unit converted

the H2S in the acid gas stream into elemental sulphur, which was then stored on-site until market

conditions would allow its sale. The remaining CO2 was vented to the atmosphere during these plant

operations.

The Plant historically generated approximately 210,000 m3/day of acid gas consisting of 20% to 40% H2S

and 60% to 80% CO2.

In 2004, as both gas and oil productions in the area were in significant decline, the Proponent made an

application to the EUB (now ERCB) to conduct an acid gas miscible flood for EOR. The decision to inject

acid gas for EOR permitted the shutdown of the Claus unit and associated tail gas incinerator, and the


http://www.rwdiair.com/

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Plant was reconfigured to inject the entire acid gas stream into the Keg River EOR pools. Acid gas

injection began on 1 December, 2004 and continued for 20 days during which no oil was recovered. The

operation was licensed by the EUB during this time for Acid Gas Injection (AGI) under license #18372.

On 21 December, 2004 the operation received EUB approval to begin Enhanced Oil Recovery (EOR)

(Approval #10161).

Under both conditions – i.e. AGI and EOR – the Project directly reduces greenhouse gas emissions

compared to the prior sulphur recovery operations by geologically storing carbon dioxide contained in

the acid gas stream and by reducing fossil fuel consumption normally required for sulphur recovery

operations, including fuel gas required for tail gas incineration. The total capital cost of the Project to-

date has been roughly $25.45 million CAD.

Once the acid gas enters the system, it is designed not to leave the field. There will be associated gas

produced during the enhanced oil recovery, however this recovered gas enters the oil battery into a

separator and is subsequently recycled back into this closed loop system – this occurs separately to the

metering of the acid gas injection so does not affect the Project. Any flaring will be for emergencies and

periodic shut-down and maintenance of the vapour recovery unit (VRU) at the battery.

It is anticipated that the Project will continue until it becomes economically unviable for oil production

in the field.

4 PROJECT IMPLEMENTATION AND VARIANCES The following changes to the Project have been made for this reporting period, as compared to the

Offset Project Plan, dated 8 January 2013:

1. Addition of volumes from the 9-33 well: due to declining throughput of acid gas at the Plant,

volumes of acid gas available for injection at Battery 12 have declined. The Proponent therefore

decided to tie-in the acid gas disposal well at 00/09-33-115-06W6/2 (the ‘9-33 well’) to the

Project to increase oil recovery rates. As this acid gas was previously injected for disposal –

instead of being sent to the SRU/incinerator – this volume is not resulting in GHG reductions,

and must not be included in the total acid gas injection volume.

However, in the project, the metered volume of acid gas diverted from the Plant to the Project

is used for the injection volume. This volume is metered before the tie-in point of the 9-33 well,

and so does not include this additional volume. As such, no change needs to be made to the

calculator. This change has no impact on the volumes of credits from the project;

2. Flaring at Battery 12: There is increased flaring at Battery 12 between the months of January

and August 2012. This was due to an equipment failure (the igniter was burned-out during a

liquid carry over) in January 2012. Rather than shut the battery down and do the repair, Apache

scheduled this equipment maintenance for the turnaround at the battery in May 2012. For

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safety purposes, to ensure that the flare stayed lit during this period, Apache made an

operational decision to increase the fuel gas purge to the flare. The battery turnaround was

subsequently postponed to September 2012, and so flare volumes at the battery between

January and August are substantially higher than in previous years.

During January to August, most of the gas being flared at Battery 12 was therefore fuel gas

rather than vent gas. However, this fuel gas stream is not metered (fuel to the battery is

metered as a whole, not to individual pieces of equipment).

An engineering estimate of the volume of vent gas being flared was provided to the third-party

verifier, based on the following:

Flare records from January 2005 – December 2011, when the flare igniter was working

properly, give an indication of the historic norm of vent gas being flared at Battery 12. The

historic median flare volume from this time period was 98.83 e3m3/month. As the vent gas

has a heating value above 20 MJ/m3, no additional fuel gas was being added to ensure

combustion. This volume therefore represents normal upset conditions at Battery 12;

Since the flare igniter stopped working in January 2012, flare volumes increased

substantially to an average of 340 e3m3/month – substantially surpassing any historic norms

(the maximum for any prior month from 2004 – 2011 was only 231 e3m3);

The total flare gas volume was assumed to therefore be 98.83 e3m3/month of vent gas,

with the remainder being fuel gas. As, once the igniter issue was fixed, flare volumes fell

back to an average of 30 e3m3/month – much lower than historic medians (and, during

October – December 2012, the lowest levels ever recorded at Battery 2012) the value of

98.83 e3m3/month is both reasonable and conservative. It almost certainly overstates the

portion of flared gas that was vent gas, which has a much higher emission factor than the

fuel gas does. This therefore conservatively increases project level emissions.

In addition, compressor flare volumes have been added to the project condition, which

increases the accuracy of the quantification. These volumes had previously been omitted from

the quantification as they were immaterial; however, given the reduced size of the project (due

to declining production) this flare source has become more material and so has been added into

the quantification for this and future years. The total impact has been to increase project

emissions and therefore decrease emission reductions from the project. Note that as the

compressor flare combust solution gas, which has a low heating value, additional fuel gas

required for combustion was simulated as per the Protocol.

3. Plant 2 compressor K-645: this compressor engine was moved from Plant 2 to Battery 12, to be

used to compress solution gas from the recovery operation. It was moved September 5, 2012

and is not currently operational.

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The engine did not run in 2012 at all. This has been reflected in the calculator. This change

reduces the project-level emissions associated with running this engine.

4. Plant 2 compressors K-620 and K-640: these two compressor engines did not run in 2012. This

has been reflected in the calculator. This change reduces the project-level emissions associated

with running these engines.

In addition, as the reporting period also includes one month of the crediting extension period (i.e.

December 2012) the Offset Project Plan has been updated to reflect these changes and a new Offset

Project Plan (version 2, dated 23 February, 2013) has been uploaded to the AEOR.

5 REPORTING PERIOD For the purposes of this project report, the carbon dioxide equivalent emission reduction credits are

claimed for activities from 1 January, 2012 to 31 December, 2012.

6 GREENHOUSE GAS CALCULATIONS As per the Offset Project Plan, GHG emission reductions were calculated following the Quantification

Protocol for Acid Gas Injection (v1, May 2008) (AENV, 2008) and the Quantification Protocol for

Enhanced Oil Recovery – Streamlined (v1, October 2007) (AENV, 2007). The activities and procedures

outlined in the Offset Project Plan provide a detailed description of the project’s adherence to the

requirements of the quantification protocol. The formulas used to quantify greenhouse gas offset by the

project are listed below.

Emission Reduction = Emissions Baseline – Emissions Project

Emissions Baseline = sum of the emissions under the baseline condition, which is made up of:

Emissions Flaring = emissions under SS (B2a) Flaring at Capture Site

Emissions Venting = emissions under SS (B3a) Venting at Capture Site

Emissions Fuel Extraction and Processing = emissions under SS (B13) Fuel Extraction / Processing

Emissions Project = sum of the emissions under the project condition, which is made up of:

Emissions Inj Transport = emissions under SS (P12) Injection Gas Transportation

Emissions Compression = emissions under SS (P14) Injection Unit Operation

Emissions Flaring = emissions under SS (P15) Flaring at Injection Site

Emissions Fuel Extraction and Processing = emissions under SS (P21) Fuel Extraction / Processing

Emissions Flaring & Emissions Venting = emissions under SS (B2a) Venting at Capture Site and

emissions under SS (B3a) Flaring at Capture Site

Emissions Flaring & Venting = CO2FV + CH4FV + N2OFV

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CO2FV = CO2 emissions from Flaring & Venting (kg CO2e)

CH4FV = CH4 emissions from Flaring & Venting (kg CO2e)

N2OFV = N2O emissions from Flaring & Venting (kg CO2e)

Where (using CO2FV as an example; CH4FV and N2OFV are calculated in the same way, but with the

additional step of converting into CO2e by multiplying the end result by the Global Warming

Potential of CH4 (21) and N2O (310), respectively):

CO2FV = CO2TG + CO2FG

= (TGINCIN * TGCO2EF) + (FGINCIN * NGCO2EF)

= [(AGSRU * AG:TG) * TGCO2EF] + [(TGINCIN * FG:TG) * NGCO2EF]

CO2TG = CO2 Emissions from Tail Gas Combustion (kg CO2)

CO2FG = CO2 Emissions from Fuel Gas Combustion (kg CO2)

TGINCIN= Total Tail Gas that would have been sent to incinerator (e3m3)

TGCO2EF = Tail Gas combustion CO2 emission factor (kg/m3)

FGINCIN = Fuel gas consumed at incinerator (e3m3)

NGCO2EF = Natural Gas combustion CO2 emission factor (kg/m3)

AGSRU = Total Acid Gas Injected that would have gone to SRU (e3m3)

AG:TG= Volume Proportion of Acid Gas Sent to Tail Gas Incinerator (%)

FG:TG = Ratio of fuel gas to tail gas

Where:

FG:TG = (LHVC - LHVTG) / (LHVFG - LHVC)

LHVC = LHV combined gas stream (MJ/m3)

LHVTG = LHV tail gas (MJ/m3)

LHVFG = LHV fuel gas (MJ/m3)

AG:TG = Volume of Tail Gas to Incinerator (e3m3) - Volume of Acid Gas (e3m3)

= Volume of Tail Gas to Incinerator (e3m3) – (Volume of Acid Gas (e3m3) – Shrinkage of

Acid Gas (e3m3))

= Volume of Tail Gas to Incinerator (e3m3) – [Volume of Acid Gas (e3m3) – (Volume of H2S

(e3m3)* Sulphur Recovery Efficiency (%))]

Where:

Volume of H2S = Mass of H2S (tonnes) / Density of H2S (tonnes/e3m3)

Where:

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Mass of H2S (tonnes) = (Mol Weight of H2S (kg/kmol) * Volume of Acid

Gas (e3m3) * Mol% of H2S in Acid Gas) / 23.645

Emissions Fuel Extraction and Processing = emissions under SS (B13) Fuel Extraction / Processing

Emissions Fuel Extraction and Processing = CO2NXP + CH4NXP + N2ONXP

CO2NXP = CO2 emissions from Fuel Extraction and Processing (kg CO2e)

CH4NXP = CH4 emissions from Fuel Extraction and Processing (kg CO2e)

N2ONXP = N2O emissions from Fuel Extraction and Processing (kg CO2e)

Where (using CO2NXP as an example; CH4NXP and N2ONXP are calculated in the same way, but with

the additional step of converting into CO2e by multiplying the end result by the Global Warming


CO2NXP = FGINCIN * NXPCO2EF

FGINCIN = Fuel gas consumed at incinerator (e3m3)

NXPCO2EF = Natural Gas extraction and processing CO2 emission factor (kg/m3)

Emissions Fuel Extraction and Processing = emissions under SS (P21) Fuel Extraction / Processing

Emissions Fuel Extraction and Processing = CO2NXP + CH4NXP + N2ONXP

CO2NXP = CO2 emissions from Fuel Extraction and Processing (kg CO2e)



Where (using CO2NXP as an example; CH4NXP and N2ONXP are calculated in the same way, but with

the additional step of converting into CO2e by multiplying the end result by the Global Warming


CO2NXP = (FGCOMP + FGFlares )* NXPCO2EF

FGCOMP = Fuel gas consumed by compressors (e3m3)

FGFlares = Fuel gas consumed by the HP, LP and Compressor Gas Flares (see P15 for

equations)

Where:

FGCOMP = FGCOMP (P12) + FGCOMP (P14)

FGCOMP(P12) = Fuel gas consumed by compressors (e3m3) under SS P12

FGCOMP(P14) = Fuel gas consumed by compressors (e3m3) under SS P14

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Emissions Injection Gas Transportation = emissions under SS (P12) Injection Gas Transportation OR

Emissions Injection Unit Operation = emissions under SS (P14) Acid Gas Injection System Operation

Emissions = CO2FG + CH4FG + N2OFG + CO2ELEC

CO2FG = CO2 emissions from Fuel Gas Combustion (kg CO2e)



CO2ELEC = CO2-equivalent emissions from Electricity Consumption (kg CO2e)

Where (using CO2FG as an example; CH4FG and N2OFG are calculated in the same way, but with the



CO2FG = FGCOMP * NGCO2EF

FGCOMP = Fuel gas consumed by compressors (e3m3)

NXPCO2EF = Natural Gas combustion CO2 emission factor (kg/m3)

Where:

FGCOMP = [(kW x Hrs)/ Eff (%)] x 3.6 / LHVNG

kW = Power rating of compressor engine (kW)

Hrs = Annual runtime (from January 1 – December 31, 2012) (hours)

Eff = Thermal efficiency of compressor engine (%)

3.6 = conversion from MJ to kWh

LHVNG = Lower heating value of natural gas (MJ/m3)

And where, if electric compressors are also used:

COELEC = ECOMP * ECCO2EF

ECOMP = Electricity consumed by compressors (kWh)

ECCO2EF = Electricity consumption CO2-equivalent emission factor (kg/m3)

Where:

ECOMP = kW * Hrs

kW = Power rating of compressor engine (kW)

Hrs = Annual runtime (from January 1 – December 30, 2012) (hours)

Emissions Flaring = emissions under SS (P15) Flaring at Injection Site

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Emissions Flaring = CO2F + CH4F + N2OF

CO2F = CO2 emissions from Flaring (kg CO2e)

CH4F = CH4 emissions from Flaring (kg CO2e)

N2OF = N2O emissions from Flaring (kg CO2e)

Where (using CO2F as an example; CH4F and N2OF are calculated in the same way, but with the



CO2F = CO2HPLP + CO2FG-HPLP + CO2EOR + CO2FG-EOR

= (FlareHPLPVG * VGCO2EF) + (FlareHPLPFuel * NGCO2EF) + (FlareEORSG * SGCO2EF) + (FlareEORFuel *

NGCO2EF)

Where:

CO2HPLP = CO2 Emissions from Vent Gas combusted in High Pressure and Low

Pressure Flare (kg CO2)

CO2FG-HPLP = CO2 Emissions from Fuel Gas combusted in High Pressure and Low

Pressure Flare (kg CO2) due to flare igniter issue (see Section 4)

CO2EOR= CO2 Emissions from Solution Gas combusted in Compressor Flare

FlareHPLPVG = Volume of Vent Gas combusted in High Pressure and Low Pressure

Flare (e3m3)

FlareHPLPFuel = Volume of Fuel Gas combusted in High Pressure and Low Pressure

Flare (e3m3) due to flare igniter issue

FlareEORSG = Volume of Solution Gas combusted in Compressor Flare (e3m3)

FlareEORFuel = Volume of Fuel Gas combusted in Compressor Flare (e3m3)

CO2FG-EOR = CO2 Emissions from Fuel Gas combusted in Compressor Flare

VGCO2EF = Vent gas combustion CO2 emission factor (kg/m3)

NGCO2EF = Natural Gas combustion CO2 emission factor (kg/m3)

SGCO2EF = Solution Gas combustion CO2 emission factor (kg/m3)

And:

FlareHPLPFuel = FlareHPLP - FlareHPLPVG

FlareEORSG = FlareEOR * (1-FG:SG)

FlareEORFuel = FlareEOR * FG:SG

Where:

FG:SG = Ratio of fuel gas to solution gas

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And:

FG:SG = (LHVC – LHVSG) / (LHVFG - LHVC)

Where:

LHVC = LHV combined gas stream (MJ/m3)

LHVSG = LHV solution gas (MJ/m3)

LHVFG = LHV fuel gas (MJ/m3)

Table 1 provides the emission factors used for the project.

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Table 1 - Emission factors used for the Project

Parameter Relevant

SS

CO2 Emission

Factor

CO2

Emission

Factor

Source

CH4

Emission

Factor

CH4 Emission

Factor

Source

N2O

Emission

Factor

N2O

Emission

Factor

Source

CO2e

Emission

Factor

CO2e Emission

Factor Source

Natural gas

combustion

B2a,

P12,

P14, P15

2.1406 kg/m3

Site specific,

calculated

annually

0.000037

kg/m3

Environment

Canada

(2012),

"National

Inventory

Report 1990-

2010", Table

A8-2,

'Industrial'

0.000033

kg/m3

Environment

Canada

(2012),

"National

Inventory

Report 1990-

2010", Table

A8-2,

'Industrial'

n/a n/a

Tail gas

combustion B2a 1.8680 kg/m3

Vent gas

combustion P15 2.6435 kg/m3

Solution gas

combustion P15 1.8852 kg/m3

Natural gas

extraction &

processing

B13, P21 0.133 kg/m3

Acid Gas

Injection

Protocol

0.0026

kg/m3

Acid Gas

Injection

Protocol

0.000007

kg/m3

Acid Gas

Injection

Protocol

Electricity

consumption P12 n/a n/a n/a n/a n/a n/a 0.88

Government of

Alberta.

December 20,

2011

Memorandum

Page 17



7 GREENHOUSE GAS ASSERTION The greenhouse gas assertion is a statement of the number of offset tonnes achieved during the

reporting period. The assertion identifies emissions reductions per vintage year and includes a breakout

of individual greenhouse gas types (CO2, CH4, N2O, SF6, HFCs, and PFCs) applicable to the project and

total emissions reported as CO2e. The total in units of tonnes of carbon dioxide equivalent (CO2e) is

calculated using the global warming potentials (GWPs) referenced in the SGER.

Table 2 identifies the greenhouse gas assertion, containing the calculated number of offset tonnes

achieved, separated by each unique vintage year and GHG released. As shown, the Project has created

3,776 tonnes of GHG reductions.

Table 2 - Offset tonnes created by vintage year and GHG1

2012 Greenhouse Gas (GHG) in tonnes CO2e

CO2 CH4 N2O PFCs HFCs SF6 CO2e Total

Baseline 23,817 319 130 - - - - 24,266

Project 19,965 419 105 - - - - 20,490

Reductions 3,852 -101 27 - - - - 3,776

1 Note that figures have been rounded, and may not calculate out exactly. The total reduction shown is accurate,

however.

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8 OFFSET PROJECT PERFORMANCE The Project has created credits in eight previous vintage years (2004 was a partial year). Figure 2 shows

the credits created by the Project between 2004 and 2012.

Figure 2 - Credits Created by Project, by Vintage Year

The project has shown a steady, year-on-year decline in the number of Offset Credits from 2005

onwards (2004 was a partial year, representing only 1 month of production). This is to be expected,

given the declining volumes of acid gas being sent to the EOR well for injection. As the regression

analysis in Figure 3 shows, the volume of acid gas injected explains over 99% of the Offset Credits

created in any given year. 2012 was a particularly low year due to the increase in flaring at the site (as

noted in Section 4).

0

50,000

100,000

150,000

200,000

250,000

2004 2005 2006 2007 2008 2009 2010 2011 2012

Cre

dit

s C

reat

ed

Vintage Year

Page 19



Figure 3 - Relationship between Acid Gas Injection volumes and OCs created

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10 STATEMENT OF SENIOR REVIEW This offset project report was prepared by Graham Harris, VP, Technical Services, Blue Source Canada

and senior reviewed by Warren Brooke, Carbon Services Project Manager, Blue Source Canada.

Although care has been taken in preparing this document, it cannot be guaranteed to be free of errors

or omissions.

Prepared by:

Senior reviewed by:

Warren Brooke

Graham Harris Warren Brooke 23/02/2013 23/02/2013

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11 REFERENCES Alberta Environment, 2012, Technical Guidance for Offset Project Developers, Version 3.0, February

2012.

Alberta Environment, 2008, Quantification Protocol for Acid Gas Injection, Version 1.0, May 2008.

Alberta Environment, 2007, Quantification Protocol for Enhanced Oil Recovery – Streamlined, Version

1.0, October 2007.

Canadian Association of Petroleum Producers, 2003, Calculating Greenhouse Gas Emissions,

http://membernet.capp.ca/raw.asp?x=1&dt=PDF&dn=55904

Canadian Association of Petroleum Producers, 2007, A Recommended Approach to Completing the

National Pollutant Release Inventory (NPRI) for the Upstream Oil and Gas Industry.

Energy Resources Conservation Board, 1994, Directive 051: Injection and disposal wells – well

classifications, completions, logging, and testing requirements,

www.ercb.ca/docs/documents/directives/Directive051.pdf.

Energy Resources Conservation Board, 2008, Directive 071: Emergency preparedness and response

requirements for the petroleum industry, www.ercb.ca/docs/documents/directives/Directive071.pdf.

Energy Resources Conservation Board, 2009, Directive 065: Resources applications for conventional oil

and gas reservoirs, www.ercb.ca/docs/documents/directives/Directive065.pdf.

Environment Canada (2012) National Inventory Report 1990-2010: Greenhouse Gas Sources and Sinks in

Canada. Environment Canada, Ottawa.

Gas Processors Association (2009) GPA Standard 2145-09: Table of Physical Properties for Hydrocarbons

and Other Compounds of Interest to the Natural Gas Industry. GPA, Tulsa.

http://membernet.capp.ca/raw.asp?x=1&dt=PDF&dn=55904

http://www.ercb.ca/docs/documents/directives/Directive051.pdf



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APPENDIX A – CONFIRMATION OF CREDITING EXTENSION APPROVAL

Documents

APACHE ZAMA BATTERY 12 ENHANCED OIL RECOVERY PROJECT