APACHE ZAMA BATTERY 12 ENHANCED OIL RECOVERY PROJECT
Greenhouse Gas Emissions Reduction
Offset Project Report
For the Period January 1, 2013 – December 31, 2013
FINAL REPORT, Version 3.0
19 February, 2014
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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 ...... 7 3 PROJECT DESCRIPTION AND LOCATION ...... 8 4 PROJECT IMPLEMENTATION AND VARIANCES ...... 9 5 REPORTING PERIOD ...... 11 6 GREENHOUSE GAS CALCULATIONS ...... 11 7 GREENHOUSE GAS ASSERTION ...... 17 8 OFFSET PROJECT PERFORMANCE ...... 18 9 PROJECT DEVELOPER SIGNATURES ...... 20 10 STATEMENT OF SENIOR REVIEW ...... 21 11 REFERENCES ...... 22
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...... 8 FIGURE 2 - CREDITS CREATED BY THE 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 Blue Source Blue Source Canada ULC
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 SGER Specified Gas Emitters Regulation SRU Sulphur Recovery Unit
SO2 Sulphur Dioxide SSs Sources and sinks SULSIM Sulphur Recovery Unit Simulation 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 (herein referred to as ‘the Project’) The project’s purpose(s) The opportunity for generating carbon offsets with this project arises from and objective(s) are: 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 Initiation of the commercial injection of acid gas for EOR was December 1, began: 2004. Expected lifetime of the It is anticipated that this EOR project will continue until it becomes project: 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 have granted, in a letter dated February 12, 2013, a 5 year Crediting Extension Period, to run from December 1, 2012 – November 30, 2017. Reporting period: January 1, 2013 – December 31, 2013 Actual emissions Previously registered and calculated project emission reductions from this reductions: 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 2013: 24,633
Total – 694,464 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 The quantification protocol used is for this reporting period is the Quantification Quantification Protocol for Enhanced Oil Recovery – Streamlined (v1, October Protocol(s): 2007) as published by Alberta Environment. Protocol(s) Justification: The Project is an enhanced oil recovery (EOR) project in northwest Alberta,
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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 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 gas 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 There are no other environmental attributes (e.g. RECs, etc) being claimed by Attributes: this project. Legal land description of The Project is located in Alberta. The nearest settlement is Zama City. EOR is the project or the ongoing in multiple pools within the oil reservoir, but the recovered oil flows unique latitude and to the oil battery (00/14-12-116-6W6), therefore the battery location is used longitude: for this project.
Latitude: 59° 03' 57" N Longitude : 118° 52' 16" W Ownership: Apache Canada Ltd. (herein referred to as ‘the Proponent’) 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, 2012. This report covers the period January 1, 2013 – December 31, 2013. 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 3rd 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 4.0, February 2013). 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
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less than 40% of the industry and is therefore not considered to be 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.
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2 PROJECT CONTACT INFORMATION Project Developer Apache Canada Ltd. 421 7th Avenue SW Contact Information Erin Hutchinson Calgary Environmental Engineer Alberta T2P 2S5 Phone: 403-817-5089 Canada Fax: 403-261-1373 [email protected] www.apachecorp.com Authorized Project Blue Source Canada 717 7th Avenue SW Contact Tooraj Moulai Calgary Engineer, Carbon Services Alberta T2P 0Z3 Phone: 403-262-3026 x259 Canada Fax: 403-269-3024 [email protected] www.bluesourcecan.com Verifier RWDI Air Inc. Suite 1000, 736-8th Avenue SW Trevor Cavanaugh Calgary Project Manager Alberta T2P 1H4 Phone: 403-232-6771 x 6233 Canada Fax: 403-232-6762 [email protected] www.rwdiair.com
Verifications Conducted: This is the 3rd consecutive verification carried out by this verifier for this project
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3 PROJECT DESCRIPTION AND LOCATION The Apache 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 two-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.
3 The Plant historically generated approximately 210,000 m /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 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
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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:
(i) SS B3a Flaring at Capture Site a. A methodology revision has been made to the calculation of baseline Tail Gas Volumes leaving the SRU and being sent to the flare. This revision has been made to increase the accuracy of the calculation, in line with the principles of ISO 14064-2. This method is based on the results of a simulation produced by Sulphur Experts (“SULSIM”), a third- party simulator. The simulation models the function of a hypothetical SRU using project specific acid gas composition and volumes produced. The SULSIM indicates a change in the molar flow within the SRU, such that the tail gas volume is higher than the acid gas volume being processed.
As modeled by the SULSIM, the multi-stage Claus unit consists of a thermal reaction
furnace where H2S is converted to SO2 via the oxidation reaction:
H2S + 3/2O2 → SO2 + H2O
The addition of air to supply enough oxygen for the reaction to tend to completion results in a large increase in the molar volume of the acid gas mixture. The SULSIM model captures this increase in the material balance of the acid gas inlet stream
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(AG2013) and the tail gas stream to the incinerator (ADA Outlet). Prior to the process,
the inlet stream is comprised mainly of CO2, H2S and H2O. Following the SRU, the tail gas 1 components are CO2, N2, and H2O; with a molar flow rate approximately 1.78 times that of the inlet stream due to the introduction of nitrogen and oxygen. As the acid gas stream is assumed to follow ideal gas behaviour at standard temperature and pressure, any changes to the number of moles in the gas will see an equal change in the spatial volume occupied by that gas, regardless of the different composition.
Therefore, to obtain an accurate volume representation of the baseline tail gas sent to incineration the inlet volume of acid gas will need to be multiplied by the ratio of the molar flow rate of ADA Outlet, n2, to the molar flow rate of the acid gas inlet stream, AG2013, n1.
With an increase in the tail gas volumes going into the incinerator the incinerator fuel gas requirements also increase to meet the minimum LHV value for combustion. As a result the emissions from incineration of fuel gas are higher. This methodological change is a more accurate estimation of the tail gas volumes produced in the baseline.
b. Emissions from tail gas combustion are calculated using the same method as outlined in the Offset Project Plan (i.e. multiplying the tail gas volumes with the tail gas emission
factor). However, the tail gas composition used in calculating the tail gas CO2 emission factor and the lower heating value of the tail gas is based on the SULSIM produced by Sulphur Experts. Use of the simulated tail gas composition is more accurate than using the acid gas composition, which was previously done. This increased the accuracy of emissions from tail gas combustion and in determining the baseline fuel gas requirements using the tail gas heating value.
(ii) Change in Compressor Utilization One of the natural gas powered compressors at Plant-3 (K-630) experienced equipment failure and was not fully operational in 2013. Repairs have been postponed until it is cost- effective. As a workaround to maintain compression capacity the two electric compressors that had been unused in 2012 were operated in 2013. Use of grid electricity in the operation of the electric compressors is more emissions intensive2 than natural gas for the gas powered compressors. As a result, there was an increase in the project emissions due to the use of the electric compressors.
1 Sulphur Experts (December, 2013), “Apache Zama Lake SRU Simulation Report” 2 Alberta’s Grid is powered mainly by coal, a highly emissions intensive energy source.
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5 REPORTING PERIOD For the purposes of this project report, the carbon dioxide equivalent emission reduction credits are claimed for activities from 1 January, 2013 to 31 December, 2013.
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
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)
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= [(AGSRU * TG:AG) * TGCO2EF] + [(TGINCIN * FG:TG) * NGCO2EF]
CO2TG = CO2 Emissions from Tail Gas Combustion (kg CO2)
CO2FG = CO2 Emissions from Fuel Gas Combustion (kg CO2) 3 3 TGINCIN= Total Tail Gas that would have been sent to incinerator (e m ) 3 TGCO2EF = Tail Gas combustion CO2 emission factor (kg/m ) 3 3 FGINCIN = Fuel gas consumed at incinerator (e m ) 3 NGCO2EF = Natural Gas combustion CO2 emission factor (kg/m ) 3 3 AGSRU = Total Acid Gas Injected that would have gone to SRU (e m ) TG :AG = Ratio of tail gas to acid gas processed by SRU FG:TG = Ratio of fuel gas to tail gas Where:
FG:TG = (LHVC - LHVTG) / (LHVFG - LHVC)
3 LHVC = LHV combined gas stream (MJ/m ) 3 LHVTG = LHV tail gas (MJ/m ) 3 LHVFG = LHV fuel gas (MJ/m )
TG:AG = ADAoutlet / AG2013
Where:
ADAoutlet = molar flow of acid gas streaming into the sulphur recovery unit as simulated by Sulphur Experts and presented in the SULSIM.
AG2013 = molar flow output (tail gas) of sulphur recovery unit as simulated by Sulphur Experts and reported in the SULSIM.
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
3 3 FGINCIN = Fuel gas consumed at incinerator (e m ) 3 NXPCO2EF = Natural Gas extraction and processing CO2 emission factor (kg/m )
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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
3 3 FGCOMP = Fuel gas consumed by compressors (e m )
FGFlares = Fuel gas consumed by the EOR Compressor Gas Flare (see P15 for equations) Where:
FGCOMP = FGCOMP (P12) + FGCOMP (P14)
3 3 FGCOMP(P12) = Fuel gas consumed by compressors (e m ) under SS P12 3 3 FGCOMP(P14) = Fuel gas consumed by compressors (e m ) under SS P14
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
3 3 FGCOMP = Fuel gas consumed by compressors (e m ) 3 NXPCO2EF = Natural Gas combustion CO2 emission factor (kg/m )
Where:
FGCOMP = [(kW x Hrs)/ Eff (%)] x 3.6 / LHVNG
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kW = Power rating of compressor engine (kW) Hrs = Annual runtime (from January 1 – December 31, 2013) (hours) Eff = Thermal efficiency of compressor engine (%) 3.6 = conversion from MJ to kWh 3 LHVNG = Lower heating value of natural gas (MJ/m )
And where, if electric compressors are also used:
CO2ELEC = ECOMP * ECCO2EF
ECOMP = Electricity consumed by compressors (kWh) 3 ECCO2EF = Electricity consumption CO2-equivalent emission factor (kg/m )
Where:
ECOMP = kW * Hrs
kW = Power rating of compressor engine (kW) Hrs = Annual runtime (from January 1 – December 30, 2013) (hours)
Emissions Flaring = emissions under SS (P15) Flaring at Injection Site
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 + CO2EOR + CO2FG-EOR
= (FlareHPLP * VGCO2EF) + (FlareEORSG * SGCO2EF) + (FlareEORFuel * NGCO2EF)
Where:
CO2HPLP = CO2 Emissions from Vent Gas combusted in High Pressure and Low
Pressure Flare (kg CO2)
CO2EOR= CO2 Emissions from Solution Gas combusted in Compressor Flare
FlareHPLP = Volume of Gas combusted in High Pressure and Low Pressure Flare (e3m3) 3 3 FlareEORSG = Volume of Solution Gas combusted in Compressor Flare (e m )
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3 3 FlareEORFuel = Volume of Fuel Gas combusted in Compressor Flare (e m )
CO2FG-EOR = CO2 Emissions from Fuel Gas combusted in Compressor Flare 3 VGCO2EF = Vent gas combustion CO2 emission factor (kg/m ) 3 NGCO2EF = Natural Gas combustion CO2 emission factor (kg/m ) 3 SGCO2EF = Solution Gas combustion CO2 emission factor (kg/m )
And:
FlareEORSG = FlareEOR * (1-FG:SG)
FlareEORFuel = FlareEOR * FG:SG
Where: FG:SG = Ratio of fuel gas to solution gas And:
FG:SG = (LHVC – LHVSG) / (LHVFG - LHVC)
Where: 3 LHVC = LHV combined gas stream (MJ/m ) 3 LHVSG = LHV solution gas (MJ/m ) 3 LHVFG = LHV fuel gas (MJ/m )
Table 1 provides the emission factors used for the project.
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Table 1 - Emission factors used for the Project
CO N O 2 CH CH Emission N O 2 CO e Relevant CO Emission Emission 4 4 2 Emission 2 CO e Emission Parameter 2 Emission Factor Emission Emission 2 SS Factor Factor Factor Factor Source Factor Source Factor Factor Source Source Natural gas B2a, P12, 2.1022 kg/m3 Environment Environment combustion P14, P15 Canada Canada Tail gas (2013), (2013), 3 B2a 0.7467 kg/m Site specific, "National "National combustion 0.000037 0.000033 calculated Inventory Inventory kg/m3 kg/m3 Vent gas annually Report 1990- Report 1990- P15 2.6629 kg/m3 combustion 2011", Table 2011", Table n/a n/a A8-2, A8-2, Solution gas P15 1.8852 kg/m3 'Industrial' 'Industrial' combustion Natural gas Acid Gas Acid Gas Acid Gas 0.0026 0.000007 extraction & B13, P21 0.133 kg/m3 Injection Injection Injection kg/m3 kg/m3 processing Protocol Protocol Protocol Government of Alberta. Electricity 0.88 P12 n/a n/a n/a n/a n/a n/a December 20, consumption t/MWh 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 24,633 tonnes of GHG reductions.
Table 2 - Offset tonnes created by vintage year and GHG3
Greenhouse Gas (GHG) in tonnes CO2e 2013
CO2 CH4 N2O PFCs HFCs SF6 CO2e Total
Baseline 40,514 787 299 - - - - 41,600
Project 12,555 297 69 - - - 4,046 16,966
Reductions 27,959 491 230 - - - -4,046 24,633
3 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 2013.
250,000
200,000
150,000
100,000 CreditsCreated
50,000
0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Vintage Year
Figure 2 - Credits Created by the 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 Offset Credits created in any given year is strongly correlated to the volume of acid gas injected.
However, there was a substantial increase in credits between 2013 (24,633 tCO2e) and 2012 (3,776 tCO2e) and this is partly due to the increase in flaring at the site in 2012, which raised project emissions in that year (and hence greatly reduced emission reductions from the project during 2012). Flaring during the 2013 year was at normal levels. In addition, the methodological change in quantification (i.e. determining the volumes of tail gas produced in the baseline using the molar flow ratio obtained from the SULSIM) also contributed to higher emissions reductions in 2013. The methodological change and the updated formulas used in the calculations are described in detail in the above sections of the report and were required in order to meet the principle of accuracy as described in ISO 14064-2.
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70,000 y = 0.305x + 4304. R² = 0.991 60,000
50,000
/yr)
3
m 3 40,000
30,000
Acid Gas Gas Acid Injected (e 20,000
10,000 6,860
0 0 50,000 100,000 150,000 200,000 250,000 Offset Credits Created (tonnes CO e) 2 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 Tooraj Moulai, Engineer Carbon Services , Blue Source Canada and senior reviewed by Graham Harris, VP, Technical Services, 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: Prepared by:
Tooraj Moulai Graham Harris 19/02/2014 19/02/2014
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11 REFERENCES Alberta Environment and Sustainable Resource Development, 2013, Technical Guidance for Offset Project Developers - Version 4.0, February 2013.
Alberta Environment and Sustainable Resource Development, 2008, Quantification Protocol for Acid Gas Injection, 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
Alberta Energy Regulator, March 1994, Directive 051: Injection and disposal wells – well classifications, completions, logging, and testing requirements, www.aer.ca/documents/directives/Directive051.pdf.
Alberta Energy Regulator, November 2009, Directive 071: Emergency preparedness and response requirements for the petroleum industry, http://www.aer.ca/documents/directives/Directive071-with- 2009-errata.pdf.
Alberta Energy Regulator, 2009, Directive 065: Resources applications for conventional oil and gas reservoirs, http://www.aer.ca/documents/directives/Directive065.pdf Canadian Association of
Petroleum Producers, 2007, A Recommended Approach to Completing the National Pollutant Release Inventory (NPRI) for the Upstream Oil and Gas Industry.
Environment Canada (2013) National Inventory Report 1990-2011: 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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