apache zama battery 12 enhanced oil recovery project
TRANSCRIPT
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
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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
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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
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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
Potential of CH4 (21) and N2O (310), respectively):
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)
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
Potential of CH4 (21) and N2O (310), respectively):
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)
CH4NXP = CH4 emissions from Fuel Extraction and Processing (kg CO2e)
N2ONXP = N2O emissions from Fuel Extraction and Processing (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
additional step of converting into CO2e by multiplying the end result by the Global Warming
Potential of CH4 (21) and N2O (310), respectively):
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
additional step of converting into CO2e by multiplying the end result by the Global Warming
Potential of CH4 (21) and N2O (310), respectively):
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
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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
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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.
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APPENDIX A – CONFIRMATION OF CREDITING EXTENSION APPROVAL