Joffre Viking CO 2 Injection Project. Offset Project Report. March 2012 Alberta Offset System

Transcription

1 Joffre Viking CO 2 Injection Project Offset Project Report March 2012 Alberta Offset System

2 Offset Project Report for Joffre Viking CO 2 Injection Project P R O J E C T D O C U M E N T I N F O R M A T I O N Enter title of offset project report: Joffre Viking CO 2 Injection Project Enter the date and reporting period covered in the report: March 30 th 2012, reporting period is January December P R O J E C T S C O P E A N D P R O J E C T D E S C R I P T I O N The project title is The project s purpose(s) and objective(s) are: Joffre Viking CO 2 Injection Project The purpose is to reduce GHG emissions through forced, high pressure injection of CO 2 that would have otherwise been vented to atmosphere. Date when the project began: The project began in August 2003, this is after January 1, Expected lifetime of the project Credit start date Credit duration period The facility lifetime is expected to be much longer than that of the offset crediting period. The Joffre Viking Tertiary Oil Unit (JVTOU) commenced CO 2 injection in 1984 and has operated continuously since that date. The project credit start date is January Credit duration period in this report is 8 years from January 1 st 2004 to December 31 st There will be no further claims from this project. Actual emissions reductions Year Actual Emission Reductions (tco 2 e) , , , , ,494

3 2010 4, ,358 Total 39,566 Quantification Protocol Protocol Justification Legal land description of the project or the unique latitude and longitude Quantification Protocol for Enhanced Oil Recovery, Version 1, October 2007 The project is applicable because it is a CO 2 Injection for Enhanced Oil Recovery Scheme and emission reductions are achieved through the injection of CO 2 into hydrocarbon formations. The project meets all aspects of the project applicability. Had the project not occurred, the CO 2 would have been vented to atmosphere. The Joffre Oil Battery acts as the only facility for all injection activities covered under the scope of this project and is located at W4M. Three new patterns began injection in the Joffre Viking Pool as part of the miscible flood phase 3 expansion injection program. The three injectors that were initiated for phase 3 injection are located in sections: 4-12 (pattern 16 at 100/ W4), 4-34 (pattern 21 at 100/ W4), and (pattern 23 at 102/ W4). Ownership Reporting and verification details The emission reductions benefits generated by the Joffre Battery CO 2 Injection Project are owned by PennWest and Nova through a contractual agreement whereby benefits arising out of injection are shared. PennWest and Nova have agreed the ownership of credits is to be developed by PennWest and that commercial compensation will be shared between PennWest to Nova. This is the first offset report for this project. There will be no future claims for the Joffre expansion patterns listed in this report. The verification was conducted by an independent, qualified, non-conflicted 3 rd party. Chris Caners from ICF Marbek was the lead verifier and has provided an assurance statement verifying that this project meets the requirements of the Alberta Offset System and that the assertions made are fairly represented in all material respects. Project activity Criteria Start Date after Jan 1, 2002 Credit Duration Period How this Project Meets Requirement The Joffre Viking CO 2 Injection Project phase 3 expansions began in August, 2003 and the facility continues to inject. The project proponent intends to claim offsets

4 for a period of 8 years, from January 1st, 2004, to December 31st, Real, Demonstrable, and Quantifiable Not Required By Law Clearly Established Ownership Counted Once for Compliance Purposes Verified by a Third Party Have occurred in Alberta Project Specific This project was developed using the Quantification Protocol for Enhanced Oil Recovery, issued by Alberta Environment and results in real emission reductions as determined through the use of methods described in this protocol. Carbon dioxide is captured from waste gas streams of acid gas processing. These would otherwise be vented to atmosphere through direct incineration or sulphur recovery and are not required by regulation or law. Ownership of the emission reductions has been established. The emission reduction benefits generated by the Joffre Viking CO 2 Injection Project are owned by PennWest and Nova through a contractual agreement whereby the benefits arising out of the project is shared. PennWest and Nova have agreed the ownership of credits are to be developed by PennWest and that commercial compensation will be shared between PennWest to Nova. Offsets created from the reduction activity have not been created, recorded or registered under any other offset system or offsets registry for the same time period. The Nova facility is a large final emitter under the Specified Gas Emitters Regulation. Nova reports the volume of CO 2 captured and transferred to PennWest as an industrial process emissions, hence any emission reductions claimed through this quantification of injection activities are counted once. This project will be verified by a Verifier meeting the requirements of the Alberta Specified Gas Emitters Regulation. CO 2 is captured from an Alberta facility and injected in an Alberta oil field. All activities of the project occur in Alberta. ERCB Directive 65 Approval

5 Approvals Other The project has no foreseeable limit on lifetime. The Joffre Viking CO 2 injection activities have been in operation since 1984, and will likely operate for many more years. The CO 2 injection will continue for the foreseeable future up until it is uneconomic for production to continue and the reservoir is shut in. P R O J E C T C O N T A C T I N F O R M A T I O N Project Developer Contact Information Primary Contact Ian Bryden Consultant, CO2 Enhanced Oil Recovery Suite 200, PennWest Plaza 207 9th Avenue SW, Calgary Ph: ian.bryden@pennwest.com Secondary Contact Jennifer Clee Senior Exploitation Engineer Suite 200, PennWest Plaza 207 9th Avenue SW, Calgary Ph: jennifer.clee@pennwest.com Authorized Project Contact (This is a contact that has been given the authority to act on behalf of the project developer.) Verifier Ian Kuwahara Project Manager The Prasino Group / Leading Carbon # th Ave S.W. Calgary, Alberta, T2R 0A5 Ph: (403) ikuwahara@prasinogroup.com ICF Marbek Chris Caners Manager, Energy & Carbon Markets 277 Wellington Street West, Suite 808: Toronto, Ontario, M5V 3E4 Ph: (416) CCaners@icfi.com marbek.ca Hannah Simmons Project Analyst The Prasino Group / Leading Carbon # th Ave S.W. Calgary, Alberta, T2R 0A5 Ph: (403) hsimmons@prasinogroup.com P R O J E C T D E S C R I P T I O N A N D L O C A T I O N This project is concerned with the quantification of emission reductions for only the Joffre Viking Tertiary Oil Unit. In 2001, PennWest acquired the Joffre project the only commercial CO 2 miscible flood in Alberta, and the first in Canada. With secondary production completely shut-in during the 1970s, Joffre s response to CO 2 miscible flooding has been very positive, with production climbing from zero in 1983 to 900 barrels per day in A dormant field with essentially zero value became a growth play with the application of tertiary recovery technology. The incentive for the project was to expand the CO 2 miscible flood into phase 3 for enhanced oil recovery (EOR), due to a significant volume of unrecovered oil that was contained in the Joffre Viking Pool.

6 The CO 2 rich stream from the NOVA Chemicals Ethylene Plant, which was historically emitted to the atmosphere, was captured and sold as a product to PennWest for EOR activities. This offset project has been quantified using the approved Quantification Protocol for Enhanced Oil Recovery, October 2007 ( the Protocol ). The opportunity for generating carbon offsets with this protocol arises from the direct and indirect reductions of greenhouse gas (GHG) emissions resulting from the geological storage of waste gas streams containing greenhouse gases as part of enhanced oil recovery activities. The Joffre Viking Tertiary Oil Unit injection program, which began in 1984, expanded to include additional capacity in Three new patterns began injection in the Joffre Viking Pool as part of the miscible flood phase 3 expansion injection program. The three injectors that were initiated for phase 3 injection are located in sections: 4-12 (pattern 16 at 100/ W4), 4-34 (pattern 21 at 100/ W4), and (pattern 23 at 102/ W4). Pattern 16 began injection in August 2003, while pattern 21 commenced in January 2007 and 23 began injection in March This quantification project is concerned with quantifying the injection activities in expansion patterns described above. The project site boundaries consist of the producing wells, receiving facilities, measurement, processing and logistical equipment, piping, compressors and injection wells. The Joffre Oil Battery is owned and operated by PennWest and is located at W4M. The Joffre Oil Battery acts as the only facility for all injection activities covered under the scope of this project plan. The PennWest Joffre facility consists of various components for dealing with the injection of CO 2. Three main process elements summarize the project activities: 1) External CO 2 gas from NOVA 2) Recycled CO 2 gas 3) CO 2 injection P R O J E C T D E T A I L S No deviations from the project plan have occurred. R E P O R T I N G P E R I O D The reporting period of the project is January December G R E E N H O U S E G A S C A L C U L A T I O N S For a complete explanation of the calculations used in this project, please refer to the offset project plan. The following three equations will be used to quantify the emission reductions from the comparison of the baseline and project conditions: Emission Reduction = Emissions Baseline Emissions Project

7 Emissions Baseline = Emissions Flaring at Capture Site Emissions Project = Emissions Source Gas B Capture + Emissions Fuel Extraction /Processing + Emissions Injection Unit Operation + Emissions Flaring at Injection Site Where: Emissions Baseline = sum of the emissions under the baseline condition Emissions Flaring at Capture Site = emissions under SS B2b Flaring at Capture Site Emissions Project = sum of the emissions under the project condition Emissions Source Gas B Capture = emissions under SS P1b Source Gas B Capture Emissions Fuel Extraction / Processing = emissions under SS P21 Fuel Extraction and Processing Emissions Injection Unit Operation = emissions under SS P14 Injection Unit Operation Emissions Flaring at Injection Site = emissions under SS P15 Flaring at Injection Site The quantification calculation details of the parameters used in the above equations are outlined in the Enhanced Oil Recovery Protocol. Quantification of the emission reductions generated by the project will be conducted using a customized excel Quantification Calculator, developed by Leading Carbon according to the Enhanced Oil Recovery Protocol. The general methods of quantification for the required data listed above are as follows: B2b Flaring at Capture Site Volume of CO 2 incinerated (flared) in the baseline condition The volume of CO 2 that would have been incinerated in the baseline condition is measured by calculating the volume of new CO 2 that was injected in the project condition. The volume of injected CO 2 is determined based on the amount of injected CO 2 attributed to the three new injectors. Due to the fact that Joffre has multiple injectors that inject CO 2 prior to the project, and that the facility re-injects produced CO 2, a number of steps went into this calculation: a) To determine the proportion of new CO 2 (from NOVA) that is injected versus the amount of recycled CO 2 that is injected, the following calculation is performed on a monthly basis: Where, % CO 2 NEW = the percentage of new CO 2 that is injected CO 2 NOVA = the total volume of CO 2 supplied by NOVA Gas Tot. Inj = the total (un-prorated) volume of injected gas by all injector wells The reported numbers from the Production Accounting reports account for the concentration of the CO 2 in the supplied gas stream from Nova.

8 b) The volume of CO 2 that would have been incinerated in the baseline condition is measured by calculating the volume of new CO 2 that is injected in the project condition. To determine the amount of new CO 2 injected per injector (4-12, 4-34, 11-33) the following calculation is performed on a monthly basis: Where, Vol Source Type B Gas Flare = the total volume of new CO 2 injected by expansion injector wells % CO 2 NEW = the percentage of new CO 2 that is injected Gas Inj. Well = the total volume of gas that is injected by each injector well Vol Source Type B Gas Flare is then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for B2b Flaring at Capture Site P1b Source Type B Capture Amount of electricity consumed for CO 2 capture in the project condition The amount of electricity used at the NOVA ethylene production plant to compress and cool the CO 2 rich gas results in indirect greenhouse gas emissions through electricity consumption. The amount of kilowatt hours consumed to operate the above pieces of equipment is estimated based on the following equation: Where, Vol. Elec = Volume of electricity consumed by Nova to supply CO 2 each month Max Power = the maximum power consumption for cooling and compression equipment at Nova supply facility, as estimated by Nova is 509.1kW. % Gas Inj. Well = the gas that was injected by each injector well 4-12, 4-34, as a percentage of the total gas injection (see P15) 24 = hours / day 365 = days per year 12 = months per year The respective volumes of electricity are then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for P1b Source Type B Capture P14 Injection Unit Operation Volume of fuel gas consumed for injection unit operation in the project condition The volume of fuel gas used at the Joffre Battery for dehydration, heating and operating maintenance trucks results in greenhouse gas emissions. The volume of gasoline, propane and nature gas consumed to perform the above operations is estimated based on the following equations: Total volume of gasoline used =

9 The volume of gasoline has been estimated based on the following parameters: a. Distance The distance an operator travels from the Joffre battery to the injection well and back has been estimated. This is a conservative estimate as the operator usually does a loop while driving and doesn t always return to the battery before travelling to the next injection site. To calculate the distance from the Joffre Battery to each injection well, an online LSD mapping tool, BaseLoc DLS by GPS Police ( is used. Where, Dist. MT = the total distance a maintenance truck travels in a day in km Dist = the distance from the Joffre Battery to the 4-12 injection well Dist = the distance from the Joffre Battery to the 4-34 injection well Dist = the distance from the Joffre Battery to the injection well 2 - factor to account for the round trip to the injection well b. Fuel efficiency The maintenance trucks used at the Joffre Battery are Chevrolet Silverado 2500 HD trucks with a 5.3L Gas engine. The fuel efficiency, measured in kilometers per liter, is estimated based on Natural Resources Canada's 2011 Fuel Consumption Guide. c. Litres of gasoline The estimate is based on an operator traveling once a day to each injection well from the Joffre Battery. This is a conservative estimate because operators do not visit every injection well once a day. Where, Gas Total = the total litres of gasoline that a maintenance truck consumes in a month Dist. Total = the total distance a maintenance truck travels in a day in hundreds of kilometers Fuel Efficiency = the fuel rating of a Chevrolet Silverado in L/100km 365 = the number of days in a year 12 = months in a year Total volume of propane used = The volume of propane has been estimated based on the type of heater and the length of heating. a. Fuel Rating A Cata-Dyne WX Series Explosion-Proof Infrared Gas Catalytic Heaters is used at each injection well. The size of the heater is 12 by 24 and utilizes propane for 6 months of the year. The fuel rating was taken from a catalogue found on the Cata-Dyne website. /12

10 b. Liters of Propane Where, Prop. Total = the total volume of propane consumed to heat the injection wells in liters Fuel Rating = the fuel rating of the Cata-Dyne heater for propane in BTU/hr 3 is the number of injection wells (4-12, 4-34, 11-33) 744 is the number of hours in one month Total volume of natural gas used = The volume of natural gas has been estimated based on the type equipment and the length of heating. a. Fuel Rating A 30 by 15 reboiler runs a glycol reconcentrator unit, which is involved with the dehydration process. The reboiler has a fuel rating of 750,000BTU/hr., which was taken from a PennWest Joffre Battery Appraisal done by Jedex. It is assumed that the reboiler runs 24/7. The total emissions resulting from the reboiler will then be proportioned out per well, so as to only account for the expansion patterns (4-12, 4-34, 11-33). b. Volume of Natural Gas Where, Prop. Total = the total volume of propane consumed to heat the injection wells in liters Fuel Rating = the fuel rating of the reboiler for natural gas in BTU/hr. 744 is the number of hours in one month Amount of electricity consumed for injection unit operation in the project condition The amount of electricity used at the Joffre Battery for compression and injection activities results in greenhouse gas emissions. The amount of electricity consumed for injection activities at the 3 expansion wells (4-12, 4-34, and 11-33) is prorated from the Battery consumption based on the following equation: Where, Elec. 4-12,4-34,11-33 = the total amount of electricity consumed at each expansion injector well % Gas Inj.Well = the percentage of gas that was injected by each expansion injector well Elec = the total amount of electricity consumed at the Joffre Battery The respective volumes of fuel are then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for P14 Injection Unit Operation.

11 Rod-Packing Emissions from the Compressor and VRU Under normal operating conditions, the compressor and VRU vent a small amount of emissions to the atmosphere. This emission source has not been included into the calculation as it is negligible and immaterial to the project P15 Flaring at Injection Site Volume of Gas flared in the project condition Flaring of gas is required during upset conditions or during system maintenance. Direct greenhouse gas emissions result from the release of the carbon dioxide contained in the gas stream. The total volume of flared gas is prorated to determine the amount of flared gas attributable to each injector. a) To determine the percentage of the total gas injected by the three new injectors, the following calculation is performed: Where, % Gas Inj. Well = the CO 2 that was injected by each injector well 4-12, 4-34, as a percentage of the total CO 2 injection Gas Inj. Well = the total volume of gas that is injected by each injector well 4-12, 4-34, Gas Tot. Inj = the total volume of injected gas by all injector wells b) To determine the volume of gas flared per injector (4-12, 4-34, 11-33), the following calculation is performed: Where, Vol Injection Gas Flared = the total volume of new gas flared by expansion injector wells % Gas Inj. Well = the percentage of CO 2 that was injected by each expansion injector well Gas Tot. Flared = the total volume of flared gas Composition of flared gas The composition of flared gas is measured from the injection gas stream as is permitted in the protocol. The balance of gas composition is assumed to methane as methane is known to be present. The actual flare gas stream will be a mixture of purge gas (98% CO 2 ) and injection gas (typically around 82% CO 2 ) and will therefore have less methane than the balance of injection gas (typically lower than 18% methane). The flare ignition system constantly tries to ignite the flare on 15 second intervals, meaning if the flare gas is combustible, it will be ignited within 15 seconds and likely burn at a high efficiency. The assumption that the balance of injection gas composition is un-combusted methane is therefore conservative.

12 Where, %CH 4 = the calculated concentration of methane in the flare gas % CO 2 = the percentage of CO 2 in the flare gas Volume of fuel gas consumed to supplement flaring in the project condition Flaring of gas is required during upset conditions or during system maintenance. From all flare volumes are calculated based on an engineering estimate and directly inputted into PVR (Production Volume Reporting) by the field operators. From volumes of flared gas is estimated using Flarecheck, an engineered estimation program which determines gas volumes sent to the flare based on pipe volumes, and inline conditions during the event. Purge gas is used to ensure that flare flow remains positive (no back flow) and that no flame arrestor is required. Purge gas is composed of CO 2 from Nova and is included in Flarecheck estimates. There is no fuel gas consumed for the flare. The respective emissions are then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for P15 Flaring at Injection Site P21 Fuel Extraction / Processing There are no calculation procedures required to determine the emissions under this SS beyond that which is listed in the protocol calculation methods. Please refer to the protocol, Section for all necessary calculation procedures for this SS. G R E E N H O U S E G A S A S S E R T I O N CO 2 CH 4 N 2 0 CO 2 e Total (kg CO 2 e) (kg CO 2 e) (kg CO 2 e) (kg CO 2 e) (t CO 2 e) ,493, ,488,973 1, ,425, ,421,765 1, , , ,475, ,469,144 11, ,405, ,399,016 9, ,501, ,494,580 6, ,169, ,164,407 4, ,363, ,358,168 4,358

13 TOTAL 39,566

14 P R O J E C T D E V E L O P E R S I G N A T U R E S I am a duly authorized corporate officer of the project developer mentioned above and have personally examined and am familiar with the information submitted in this Offset Project Report including the accompanying Greenhouse Gas Assertion on which it is based. Based upon reasonable investigation, including my inquiry of those individuals responsible for obtaining the information, I hereby warrant that the submitted information is true, accurate and complete to the best of my knowledge and belief, and that all matters affecting the validity of the emission reduction claim or the protocol upon which it is based have been fully disclosed. I understand that any false statement made in the submitted information may result in de-registration of credits and may be punishable as a criminal offence in accordance with provincial or federal statutes. PennWest has executed this Offset Project Report as of the 30 th day of March, 2012.

15 Appendix A Offset Project Plan

16 LEADING CARBON LTD. Consulting and Project Development Providing leadership in a carbon constrained economy Offset Project Plan Joffre Viking CO 2 Injection Project MARCH PREPARED FOR: PENNWEST EXPLORATION

17 Table of Contents Introduction Project Scope and Site Description Project Applicability Conditions Prior to Project Initiation Removal Of Emissions Project Approval Flexibility Mechanisms Ownership of Emissions Offset Eligibility Requirements Project Stakeholders Project Scope Project Description Identification of Risks Technical Risk Market Risk Political Risks Inventory of Sources and Sinks Quantification of Estimated GHG Emissions/Removals Estimate of GHG Emission Reductions/Removals Enhancements Attributable for the Project Identification of Baseline Quantification Plan Quantification Approach Data Sources Quantification Method B2b Flaring at Capture Site P1b Source Type B Capture P14 Injection Unit Operation P15 Flaring at Injection Site P21 Fuel Extraction / Processing Sample Calculations B2b Flaring at Capture Site P1b Source Type B Capture P14 Injection Unit Operation P15 Flaring at Injection Site Monitoring Plan Measured Parameters B2B Flaring at Capture Site P14 Injection Unit Operation Estimated Parameters B2b Flaring at Capture Site P1b Source Type B Gas Capture P14 Injection Unit Operation P15 Flaring at Injection Site Data Information Management System and Data Controls Measurement Quality Control B2b Flaring at Capture Site P14 Injection Unit Operation...47

18 6.2 Data System Maintenance and Data Controls Record Keeping Deviations from the Protocol Incremental Emissions Reversals Project Developer Signatures...52

19 INTRODUCTION PennWest Exploration is one of the largest conventional oil and natural gas producers in Canada. PennWest operates a significant portfolio of opportunities with a dominant position in light oil in Canada. Based in Calgary, Alberta, PennWest operates throughout western Canada on a land base encompassing over six million acres. PennWest has been an industry leader in enhanced oil recovery (EOR) since 1984, with innovative pilots and project expansions established in Alberta since PennWest has operated three carbon dioxide (CO 2 ) injection sites and hired Leading Carbon, the parent company of the Prasino Group, as the lead project developer to quantify the emission reductions associated with the following EOR projects: Pembina A Lease CO2 Injection Pilot PennWest initiated a vertical well CO2 Pilot in the Pembina Cardium Pool in The pilot was centered in sections 11 and W5M and consisted of two vertical CO2 injectors. In 2007, the pilot was expanded to include two additional horizontal injectors in section W5M, with injection terminating in CO2 for this pilot was purchased from Ferus Limited Partnership and delivered by truck to the injection site. South Swan Hills Unit CO2 Injection Pilot The South Swan Hills Unit CO2 Pilot was initiated in The pilot consisted of two injection wells located in section19 and W5M. Injection continued until CO2 for the SSHU Pilot was purchased from Air Liquide Canada Inc. Joffre Viking Tertiary Oil Unit (JVTOU) The JVTOU commenced CO2 injection in 1984 and has operated continuously since that date. CO2 is purchased from Nova Chemical Corporation and injected into the Joffre Viking Oil Pool. The flood was expanded in 2003 and injection commenced in Pattern 16 in August of 2003, in Pattern 21 in January, 2007 and in Pattern 23 in March of

20 Figure 1: Enhanced Oil Recovery Using CO2 Miscible Flooding Technology Emission reductions are achieved through the forced, high pressure injection of CO 2 that would have otherwise been vented to atmosphere. The CO 2 was injected into underground geological formations that were selected based on 1) their suitability for long term retention of the CO 2 and 2) the advantageous impacts the injected CO 2 has on the oil production capabilities of the associated production wells. 5

21 1 PROJECT SCOPE AND SITE DESCRIPTION Project Title: Joffre Viking CO 2 Injection Project Project Purpose: The purpose of this offset project plan is to quantify emission reductions generated under the Alberta Offset System from the PennWest Joffre Viking CO 2 Injection Project for Enhanced Oil Recovery (herein the Project ). The project itself was created with the objective of improving oil recovery in Joffre Viking field while reducing direct greenhouse gas emissions to the atmosphere. The opportunity for generating carbon offsets with this project arises from the direct greenhouse gas emission reductions resulting from the geological sequestration of CO 2 rich waste gas streams, produced during ethanol production at NOVA. Start Date: August Expected Lifetime: The project has no foreseeable limit on lifetime. The Joffre Viking CO 2 injection activities have been in operation since 1984, and will likely operate for many more years. The CO 2 injection will continue for the foreseeable future up until it is uneconomic for production to continue and the reservoir is shut in. Credit Start Date: January Credit Duration Period: 8 years (Jan 1 st 2004 December 31 st 2011) Estimated Emission Reduction: Approximately 40,000 tco 2 e Protocol: Quantification Protocol for Enhance Oil Recovery, Version 1, October Protocol Justification: This project is applicable to use the protocol because PennWest is injecting CO 2 rich waste gas streams into the Joffre Viking reservoir for enhanced oil recovery activities. This protocol is the appropriate method for quantifying emission reduction benefits. The Quantification Protocol Enhanced Oil Recovery (herein the Protocol ) is intended for projects which inject and store waste gas streams in geological formations. According to the Protocol, the process of compression, transportation, and sequestration of waste gas reduces GHG emissions released to the atmosphere as injection activities are less energy intensive than the baseline processes (the venting of CO 2 rich waste gas to atmosphere). Location: The Joffre Viking Pool is located near Joffre, Alberta, which is west of Red Deer (see Figure 2). All aspects of the project occurred in Alberta. 6

22 Figure 2: Location of the Joffre Facility 1.1 PROJECT APPLICABILITY The applicability criteria, identification of sources and sinks, and quantification methodologies for this project have been determined in accordance with the Alberta Offset System Quantification Protocol for Enhanced Oil Recovery (October 2007). As outline in the protocol, the project must conform to the following applicability criteria. This Offset Project Plan must demonstrate that: 1. The storage project results in removal of emissions that would otherwise have been released to the atmosphere as indicated by an affirmation from the project developer and project schematics; 2. The emissions captured under the protocol are reported as emitted at the source facility such that the emission reductions are not double counted; 3. The enhanced recovery scheme has obtained approval from the Alberta Energy and Utilities Board (AEUB) and meets the requirements outlined under Directive 051: Injection and Disposal Wells Well Classifications, Completions, Logging and Testing Requirements and Directive 065 Resources Applications for Conventional Oil and Gas Reservoirs. 4. Metering of injected gas volumes takes place as close to the injection point as is reasonable to address the potential for fugitive emissions as demonstrated by a project schematics; 5. The quantification of reductions achieved by the project is based on actual measurement and monitoring (except where indicated in this protocol) as indicated by the proper application of this protocol; and 6. The project must meet the requirements for offset eligibility as specified in the applicable regulation and guidance documents for the Alberta Offset System. Demonstration that the Project complies with the applicability criteria outlined above is provided in the following sections. 7

23 1.1.1 CONDITIONS PRIOR TO PROJECT INITIATION Prior to the CO 2 capture and injection activities initiated by PennWest, the CO 2 generated by the NOVA Chemicals Ethylene Plant was incinerated and vented to the atmosphere. As part of a miscible flood program initiated in the 1980 s, the Joffre Viking Pool produced oil and injected CO 2 prior to the 2007 phase 3 expansion projects. The pre-project injection activities are not quantified in this project plan REMOVAL OF EMISSIONS In the absence of the enhanced oil recovery activity, NOVA Chemicals would have continued to operate business as usual and incinerated the CO 2 rich waste gas stream resulting from the sweetening process of ethylene production. This is demonstrated by the continued reporting of these emissions under the SGER as being emitted PROJECT APPROVAL This project obtained Directive 051 approval for Injection and Disposal Wells Well Classifications, Completions, Logging and Testing Requirements. This project obtained Directive 065 approval for Resources Applications for Conventional Oil and Gas Reservoirs FLEXIBILITY MECHANISMS The Joffre Viking Injection project exercises the use of the second flexibility mechanism of the protocol, which states that: This protocol may be applied to projects where an existing injection program is being expanded to include additional capacity. In the case of a project expansion, the proponent may consider the additional capacity as a new project. Alternatively, the project developer may include the previous operations as the operating condition under the baseline. As such, the SS s considered under the baseline condition may be amended to include SS s as defined for the project condition that are applicable under the baseline condition. PennWest and predecessor companies have been injecting into the Joffre Viking Pool since 1984 as part of their CO 2 miscible flood program to increase oil recovery rates from the oil producing formation. In 2003 a decision was made to expand the injection program to include additional capacity. Three new patterns (16, 21 and 23) were added as well as three new injectors (4-12, 4-34 and 11-33, see Section 1.4). The expansion to the original Joffre injection program occurs at specific injectors in new injection patterns beyond that which the original injection program included. The expanded capacity is considered to be the project, the originally existing injection activities are considered to be equivalent under the baseline and project condition. The baseline condition does not consider pre-project operations in the calculation method. All emissions and injections associated with the facility operations prior to the project injection activities are not part of this quantification plan and do not make the baseline condition. They are equivalent from the baseline to the project and therefore irrelevant to the quantification OWNERSHIP OF EMISSIONS Ownership of the emission reductions has been established. The emission reductions benefits generated by the Joffre Battery CO 2 Injection Project are owned by PennWest and Nova through a contractual agreement whereby benefits arising out of injection is shared. PennWest and Nova have agreed the ownership of credits are to be developed by PennWest and that commercial compensation will be shared between PennWest to Nova. 8

24 1.1.6 OFFSET ELIGIBILITY REQUIREMENTS This project meets the requirement for offset eligibility as specified in the applicable regulation and guidance documents for the Alberta Offset System. In particular: Criteria How this Project Meets Requirement Start Date after Jan 1, 2002 The Joffre Battery CO 2 Injection Project phase 3 expansions began in August, 2003 and the facility continues to inject. Credit Duration Period Real, Demonstrable, and Quantifiable Not Required By Law Clearly Established Ownership Counted Once for Compliance Purposes Verified by a Third Party Project Specific Approvals Have occurred in Alberta The project proponent intends to claim offsets for a period of 8 years, from January 1 st, 2004, to December 31 st, The Joffre Viking Injection Expansion Project results in real GHG reductions that are not the result of a shutdown or cessation of an activity. The emissions reductions are related to the facility s operations and are quantifiable using the government approved protocol based on metered and measured data. The greenhouse gas emission reductions created as a result of the enhanced oil recovery project at the Joffre Viking facility are surplus to any regulation. Ownership of the emission reductions has been established. The emission reduction benefits generated by the Joffre Battery CO 2 Injection Project are owned by PennWest and Nova through a contractual agreement whereby benefits arising out of injection is shared. PennWest and Nova have agreed the ownership of credits are to be developed by PennWest and that commercial compensation will be shared between PennWest to Nova. Offsets created from the reduction activity have not been created, recorded or registered under any other offset system or offsets registry for the same time period. The Nova facility is a large final emitter under the Specified Gas Emitters Regulation. Nova reports the volume of CO 2 captured and transferred to PennWest as an industrial process emissions, hence any emission reductions claimed through this quantification of injection activities are counted once. This project will be verified by a Verifier meeting the requirements of the Alberta Specified Gas Emitters Regulation. ERCB Directive 65 Approval ERCB Directive 51 Approval CO 2 is captured from an Alberta facility and injected in an Alberta oil field. All activities of the project occur in 9

25 Alberta. 1.2 PROJECT STAKEHOLDERS Project Proponent PennWest Petroleum Ltd. ( PennWest ) Suite 200, 207-9th Avenue SW Calgary, Alberta T2P 1K3 Telephone: (403) Primary Contact Ian Bryden Consultant, CO 2 Enhanced Oil Recovery Suite 200, PennWest Plaza th Avenue SW, Calgary Ph: ian.bryden@pennwest.com Secondary Contact Jennifer Clee Senior Exploitation Engineer Suite 200, PennWest Plaza th Avenue SW, Calgary Ph: jennifer.clee@pennwest.com 1.3 PROJECT SCOPE This project plan is concerned with the quantification of emission reductions for only the Joffre Viking Tertiary Oil Unit. In 2001, PennWest acquired the Joffre project the only commercial CO 2 miscible flood in Alberta, and the first in Canada. With secondary production completely shut-in during the 1970s, Joffre s response to CO 2 miscible flooding has been very positive, with production climbing from zero in 1983 to 900 barrels per day in A dormant field with essentially zero value became a growth play with the application of tertiary recovery technology. The incentive for the project was to expand the CO 2 miscible flood into phase 3 for enhanced oil recovery (EOR), due to a significant volume of unrecovered oil that was contained in the Joffre Viking Pool. The CO 2 rich stream from the NOVA Chemicals Ethylene Plant, which was historically emitted to the atmosphere, was captured and sold as a product to PennWest for EOR activities. This offset project has been quantified using the approved Quantification Protocol for Enhanced Oil Recovery, October 2007 ( the Protocol ). The opportunity for generating carbon offsets with this protocol arises from the direct and indirect reductions of greenhouse gas (GHG) emissions resulting from the geological storage of waste gas streams containing greenhouse gases as part of enhanced oil recovery activities. 1.4 PROJECT DESCRIPTION The Joffre Viking Tertiary Oil Unit injection program, which began in 1984, expanded to include additional capacity in Three new patterns began injection in the Joffre Viking Pool as part of the miscible flood phase 3 expansion injection program. The three injectors that were initiated for phase 3 injection are located in sections: 4-12 (pattern 16 at 100/ W4), 4-34 (pattern 21 at 100/ W4), and (pattern 23 at 102/ W4). Pattern 16 began injection in August 2003, while pattern 21 commenced in January 2007 and 23 began injection in March This quantification project is concerned with quantifying the injection activities in expansion patterns described above and depicted in Figure 3. 10

26 Figure 3: Location of Three Expansion Injection Projects Pattern 23 Pattern 21 Pattern 16 The project site boundaries consist of the producing wells, receiving facilities, measurement, processing and logistical equipment, piping, compressors and injection wells. The Joffre Oil Battery is owned and operated by PennWest and is located at W4M. The Joffre Oil Battery acts as the only facility for all injection activities covered under the scope of this project plan. The PennWest Joffre facility consists of various components for dealing with the injection of CO 2 (see Figure 4 for the process flow diagram). Three main process elements summarize the project activities: 1) External CO 2 gas from NOVA 2) Recycled CO 2 gas 3) CO 2 injection 11

27 Figure 4: Process Flow Diagram for the Joffre Battery 1) External liquid CO 2 CO 2 gas was transported from the NOVA Chemicals Ethylene Plant to the Joffre Oil Battery via pipeline. The distance the CO 2 travelled in the pipeline is approximately 1000 meters. The incremental greenhouse gas emissions that resulted from transportation in the project condition, such as compression, will be accounted for in the quantification methodology. Figure 5 highlights the process elements concerned with capturing CO 2 at the Nova facility. NOVA Chemicals Joffre manufacturing facility lies just east of Red Deer, Alberta and is one the largest ethylene and polyethylene production complexes in the world, capable of generating 2.6 megatonnes annually. Carbon dioxide is produced as a result of ethylene and polyethylene production, and would have been incinerated to atmosphere in the baseline condition. In the project condition, the CO 2 is captured through an amine process and sold to PennWest. The CO 2 supplied from NOVA meets the definition of a Source Type B gas in the protocol. 12

28 Figure 5: Nova CO 2 Capture Process 2) Recycled CO 2 The effluent of producing wells contains a proportion of CO 2 gas, which is re-injected back to the reservoir. All produced effluent goes through a 2-phase separation technique to separate out the CO 2 gas, which gets compressed and re-injected with the new stream of CO 2 from NOVA. This recycling is discounted against total injections in the quantification method to ensure proper accounting. 3) CO 2 Injection The recycled stream of CO 2 and the external source of CO 2 from NOVA are mixed, compressed and subsequently injected into several injection patterns alternating with water injection. This project however is only concerned with three new injection patterns: 16 at 4-12, 23 at and 21 at IDENTIFICATION OF RISKS Risks associated with the planning and execution of this project does not exist since this project occurred in the past. The crediting period has been successfully completed. Risks associated with the quantification of emission reduction benefits achieved by this project are listed in the following sections TECHNICAL RISK Technical risks include all risks associated with the operation and functionality of equipment or processes on or off-site related to the project. The most significant risks and their mitigation are given below: 13

29 - Metering error this risk is reporting error from the meters responsible for determining the activity level of the various processes in injection. Regular calibration and maintenance throughout the project period is the main mitigation strategy for this risk. - Data risk - this risk is the loss, mis-management or degradation of data collected by meters for the baseline and project activity level. The project relies heavily on digital data and therefore has low risk for degradation or loss. Data management is done through several redundant systems that have local storage both on and offsite providing for robust data as processes and personnel change through time. - Personnel risk this risk is due to personnel changing and knowledge transfer between different human resources. The injection activities were implemented several years ago and much of the soft information that the individuals performing the project would have had at the beginning that may be relevant to the quantification could be lost. The mitigation strategy here is to ensure that broad contact throughout the company is made and that all potential resources for knowledge in the company has been accessed. - Reversal risk this risk is due to the potential for sequestered carbon dioxide to seep or leak from the storage reservoir to other geological formations or to the surface. This risk is mitigated by the continuous well monitoring program in place at Joffre MARKET RISK Market risks include all risks associated with the financial and market related aspects of the quantification project. The most significant risks and their mitigation is given below: - Verification availability The quantification project requires a qualified verifier review and sign-off on all assertions made. The availability of a verifier in early 2012 will be a market risk to the success of the quantification project POLITICAL RISKS Political risks include all risks associated with the governing policies and regulations of the quantification project. The most significant risks and their mitigation are given below: - Historical credit deadline risk The quantification project must be verified by March 31, This is a risk due to the time it typically would take to do the quantification and verification. 2 INVENTORY OF SOURCES AND SINKS Sources and sinks of emissions for the baseline and project were assessed based on Guidance from ISO , Alberta Environment and Environment Canada and are classified as follows: Controlled: The behaviour or operation of a controlled source and/or sink is under the direction and influence of a Project Developer through financial, policy, management, or other instruments. Related: A related source and/or sink has material and/or energy flows into, out of, or within a project but is not under the reasonable control of the project developer. 14

30 Affected: An affected source and/or sink is influenced by the project activity through changes in market demand or supply for projects or services associated with the project. Figure 6 below shows the process flow diagram for the baseline condition, while Figure 7 categorizes these elements into the above listed classifications. 15

31 Figure 6: Process Flow Diagram for the Baseline Condition 16

32 Figure 7: Process Flow Diagram for the Project Condition 17

33 The following table lists all included and excluded emission sources or sinks and how they differ from protocol requirements (if applicable), and justifies with project specifics. Only sources and sinks relevant to Source Type B gas (industrial process emissions) are listed here as this is the gas type relevant to this project. Table 1: Identification of Sources and Sinks Sources/Sinks B1b Source Type B Gas Capture B2b Flaring at Capture Site B3b Venting at Capture Site B4b Fugitive Emissions at Capture Site B8b Flaring at Processing Site Description Baseline Source Type B gas streams produced may be captured at the project site for eventual venting, flaring or processing. Energy in the form of fossil fuels or electricity may be required during the capture process. The types and quantities of fuel or electricity consumed would need to be tracked This is the baseline condition. All CO 2 that is injected for EOR activities would have been incinerated/flared to the atmosphere at the NOVA Ethylene Plant in the absence of the project. This dynamic, projection based baseline is calculated by metering the amount of CO 2 injected at the wellhead. From time to time Source Type A/B gas may be vented at the capture site as a result of emergency shut-down, maintenance or other operational condition. The quantity of gas flared would need to be tracked. Fugitive emissions may occur from equipment used to capture Source Type B gas. The quantity of fugitive emissions would need to be tracked. Source Type B gas may be flared at the processing site as a result of emergency shut-down, maintenance or other operational conditions. The quantity of gas would need to be tracked. Include/ Exclude Exclude Include Exclude Exclude Exclude Justification for inclusion/exclusion This emission is equivalent under the project and baseline scenario. It is excluded in this project for its irrelevance, and it is conservative to exclude baseline emissions. As per protocol, injected volumes in the project condition displace emissions under this SS, making this SS relevant. This emission is equivalent under the project and baseline scenario. It is excluded in this project for its irrelevance, and it is conservative to exclude baseline emissions. As per protocol. It is conservative to exclude baseline emissions. As per protocol. It is conservative to exclude baseline emissions. 18

34 B11b Saleable Component Processing and Transport B12 Fuel Production and Distribution B13 Fuel Extraction/ Processing Saleable components of the Source Type B gas may then be transported to end users, resulting in emissions from the end-use combustion of sales gas. The types and quantities of gas sold would need to be tracked. Oil, natural gas and / or coal bed methane would have to be produced to offset that which may be produced under the injection processes under the project condition. The quantity of oil produced and transported for processing would need to be tracked. Each of the fuels used throughout the project will need to sourced and processed. This will allow for the calculation of the greenhouse gas emissions from the various processes involved in the production, refinement and storage of the fuels. The total volumes of fuel for each of the SS s are considered under this SS. Volumes and types of fuels are the important characteristics to be tracked. B14 Fuel Delivery Each of the fuels used throughout the project will need to be transported to the site. This may include shipments by tanker or by pipeline, resulting in the emissions of greenhouse gases. B15 Electricity Usage Electricity may be required to power equipment throughout the capture, processing and injection processes. The quantity of power consumed and the source of electricity would need to be tracked. Exclude Exclude Exclude Exclude Exclude As per protocol. It is conservative to exclude baseline emissions. As per protocol. It is conservative to exclude baseline emissions. The fuel use prior to the project is equivalent between the baseline and project condition. It is excluded in this project for its irrelevance, and it is conservative to exclude baseline emissions. As per protocol. It is conservative to exclude baseline emissions. As per protocol. It is conservative to exclude baseline emissions. 19

35 B16 Development of Site The site may need to be developed. This could include civil infrastructure such as access to electricity, gas and water supply, as well as sewer etc. This may also include clearing, grading, building access roads, etc. There will also need to be some building of structures for the facility such as storage areas, storm water drainage, offices, vent stacks, firefighting water storage lagoons, etc., as well as structures to enclose, support and house the equipment. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels and electricity used to power equipment required to develop the site such as graders, backhoes, trenching machines, etc. Exclude As per protocol. It is conservative to exclude baseline emissions. B17 Building Equipment Equipment may need to be built either on-site or off-site. This includes all of the components of the storage, handling, processing, combustion, air quality control, system control and safety systems. These may be sourced as pre-made standard equipment or custom built to specification. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels and electricity used to power equipment for the extraction of the raw materials, processing, fabricating and assembly Exclude As per protocol. Emissions from building equipment are not material for the baseline condition given the minimal building equipment typically required. It is conservative to exclude baseline emissions. B18 Transportation of Equipment Equipment built off-site and the materials to build equipment onsite, will all need to be delivered to the site. Transportation may be completed by train, truck, by some combination, or even by courier. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels to power the equipment delivering the equipment to the site Exclude As per protocol. Emissions from building equipment are not material for the baseline condition given the minimal building equipment typically required. It is conservative to exclude baseline emissions. B19 Construction on Site The process of construction at the site will require a variety of heavy equipment, smaller power tools, cranes and generators. The operation of this equipment will have associated greenhouse gas emission from the use of fossil fuels and electricity. Exclude As per protocol. Emissions from building equipment are not material for the baseline condition given the minimal building equipment typically required. It is conservative to exclude baseline emissions. 20

36 B20 Testing of Equipment Equipment may need to be tested to ensure that it is operational. This may result in running the equipment using test anaerobic digestion fuels or fossil fuels in order to ensure that the equipment runs properly. These activities will result in greenhouse gas emissions associated with the combustion of fossil fuels and the use of electricity. Exclude As per protocol. Emissions from building equipment are not material for the baseline condition given the minimal building equipment typically required. It is conservative to exclude baseline emissions. B21 Site Decommissioning Once the facility is no longer operational, the site may need to be decommissioned. This may involve the disassembly of the equipment, demolition of on-site structures, disposal of some materials, environmental restoration, re-grading, planting or seeding, and transportation of materials off-site. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels and electricity used to power equipment required to decommission the site. Exclude As per protocol. Emissions from building equipment are not material for the baseline condition given the minimal building equipment typically required. It is conservative to exclude baseline emissions. Project P1b Source Gas Capture Source Type B gas streams may be captured. Energy in the form of fossil fuels may be required during the capture process. The types and quantities of fuel consumed would need to be tracked. Include As per protocol, this SS is relevant to the project. This SS will include P5b and P7b due to measurement constraints in this project. P2b Flaring at Capture Site Source Type B gas may be flared at the capture site as a result of emergency shut-down, maintenance or other operational conditions. The quantity of gas flared and any supplemental fuel would need to be tracked. Exclude This SS is irrelevant to the project as all flaring at the capture site under the project condition is functionally equivalent to flaring that would have occurred under the baseline condition P3b Venting at Capture Site Source Type B gas may be vented at the capture site as a result of emergency shutdown, maintenance or other operational condition. The quantity of gas vented would need to be tracked. Exclude This SS is not relevant to this project because all gas stream venting releases in the project condition would be functionally equivalent to venting in the baseline condition. 21

37 P5b Source Type B Gas Transportation Source Type B gas transportation systems may require compressors and other equipment for the gathering and transport of the gas from the capture site to the processing site by pipeline. This equipment may be fuelled by diesel, gasoline or natural gas, resulting in GHG emissions. Other fuels may also be used in some rare cases. Gas may also be transported by truck or tanker, which would require fuel consumption resulting in GHG emissions. Quantities and types for each of the energy inputs may need to be tracked. Include As per protocol, this SS is relevant to the project, however is bundled to P1b due to measurement constraints in this project. P6b Fugitive Emissions in Transportation Fugitive emissions may occur from equipment and facilities used to transport Source Type B gas. The quantity of fugitive emissions would need to be tracked. Exclude As per protocol, fugitive emissions in transportation are upstream of measurement points and are functionally equivalent to emissions in baseline. P7b Source Type B Gas Processing Source Type B gas may be separated into component gases using chemical and physical processing equipment. This equipment would be fuelled by diesel, gasoline or natural gas, resulting in GHG emissions. Other fuels may also be used in some rare cases. Quantities and types for each of the energy inputs may need to be tracked Include As per protocol, this SS is relevant to the project, however is bundled to P1b due to measurement constraints in this project. P12 Injection Gas Transportation Injection gas transportation systems may require compressors and other equipment for the gathering and transport of the gas from the capture site to the injection site by pipeline. This equipment may be fuelled by diesel, gasoline or natural gas, resulting in GHG emissions. Other fuels may also be used in some rare cases. Gas may also be transported by truck or tanker, which would require fuel consumption resulting in GHG emissions. Quantities and types for each of the energy inputs may need to be tracked. Include As per protocol, this SS is relevant to the project, however is bundled to P14 due to measurement constraints in this project. P13 Fugitive Emissions in Transportation Fugitive emissions may occur from equipment used to transport injection gas. The quantity of fugitive emissions would need to be tracked. Exclude As per protocol, fugitive emissions in transportation are upstream of measurement points and are functionally equivalent to emissions in baseline. 22

38 P14 Injection Unit Operation Operation of the injection unit may require the use of pumps and pressure equipment. Mechanical equipment may be required to treat the Source Type A gas in order meet the required specifications for injection. This may require several energy inputs such as electricity, natural gas and diesel. Quantities and types for each of the energy inputs would be tracked. Include As per protocol, this SS is relevant to the project. This SS is bundled with P12 and P20 due to measurement constraints in this project. P15 Flaring at Injection Site From time to time injection gas may be flared at the injection site as a result of emergency shut-down, maintenance or other operational condition. Emissions of greenhouse gases would be contributed from the combustion of the injection gas as well as from any natural gas used in flaring to ensure more complete combustion. Quantities of injection gas being flared and the quantities of natural gas would need to be tracked. Include As per protocol, this SS is relevant to the project. This SS is bundled with P19 due to measurement constraints in this project. P16 Venting at Injection Site From time to time injection gas may be vented at the injection site as a result of emergency shut-down, maintenance or other operational condition. The quantity of gas vented would need to be tracked. Exclude This SS is not relevant to this project condition because all gas stream releases are incinerated through the flare and captured under P15 Flaring at Injection Site. P17 Fugitive Emissions at Injection Site Fugitive emissions will occur from equipment used at the injection site. The quantity of fugitive emissions would need to be tracked. Exclude As per protocol, fugitive emissions at injection site are likely upstream of measurement points therefore are functionally equivalent to emissions in baseline, and are likely to be negligible. P18 Fuel Production and Distribution Oil, natural gas and / or coal bed methane may be produced as a result of the injection process. The additional quantity of fossil fuels produced and transported for processing would need to be tracked. Exclude As per protocol this SS is likely equivalent under project and baseline condition P19 Recycled Injection Gases Injected gas may be re-circulated through production wells in the area. The re-circulated gas may be re-injected or released (vented or flared). Emissions due to recirculation of gas that is not re-injected would need to be tracked. Include As per protocol, this SS is relevant to the project, however is bundled to P15 due to measurement constraints in this project. 23

39 P20 Electricity Usage Electricity may be required to power equipment throughout the capture, processing and injection processes. The quantity of power consumed and the source of electricity would need to be tracked. Include This SS is relevant to the project condition as there are incremental emissions associated with the use of electricity in the project condition. This SS is bundled to P14 due to measurement constraints in this project. P21 Fuel Extraction and Processing Each of the fuels used throughout the project may need to sourced and processed. This will allow for the calculation of the greenhouse gas emissions from the various processes involved in the production, refinement and storage of the fuels. The total volumes of fuel for each of the SS s are considered under this SS. Volumes and types of fuels are the important characteristics to be tracked Include As per protocol, this SS is relevant to the project. P23 Development of Site The site may need to be developed. This could include civil infrastructure such as access to electricity, gas and water supply, as well as sewer etc. This may also include clearing, grading, building access roads, etc. There will also need to be some building of structures for the facility such as storage areas, storm water drainage, offices, vent stacks, firefighting water storage lagoons, etc., as well as structures to enclose, support and house the equipment. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels and electricity used to power equipment required to develop the site such as graders, backhoes, trenching machines, etc. Exclude As per protocol. Emissions from building equipment are not material for the project condition given the minimal building equipment typically required. P24 Building Equipment Equipment may need to be built either on-site or off-site. This includes all of the components of the storage, handling, processing, combustion, air quality control, system control and safety systems. These may be sourced as pre-made standard equipment or custom built to specification. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels and electricity used to power equipment for the extraction of the raw materials, processing, fabricating and assembly. Exclude As per protocol. Emissions from building equipment are not material for the project condition given the minimal building equipment typically required. 24

40 P25 Transportation of Equipment Equipment built off-site and the materials to build equipment onsite, will all need to be delivered to the site. Transportation may be completed by train, truck, by some combination, or even by courier. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels to power the equipment delivering the equipment to the site. Exclude As per protocol. Emissions from building equipment are not material for the project condition given the minimal building equipment typically required. P26 Construction of Site The process of construction at the site will require a variety of heavy equipment, smaller power tools, cranes and generators. The operation of this equipment will have associated greenhouse gas emission from the use of fossil fuels and electricity. Exclude As per protocol. Emissions from building equipment are not material for the project condition given the minimal building equipment typically required. P27 Testing of Equipment Equipment may need to be tested to ensure that it is operational. This may result in running the equipment using test anaerobic digestion fuels or fossil fuels in order to ensure that the equipment runs properly. These activities will result in greenhouse gas emissions associated with the combustion of fossil fuels and the use of electricity. Exclude As per protocol. Emissions from building equipment are not material for the project condition given the minimal building equipment typically required. P28 Site Decommissioning Once the facility is no longer operational, the site may need to be decommissioned. This may involve the disassembly of the equipment, demolition of on-site structures, disposal of some materials, environmental restoration, re-grading, planting or seeding, and transportation of materials off-site. Greenhouse gas emissions would be primarily attributed to the use of fossil fuels and electricity used to power equipment required to decommission the sit Exclude As per protocol. Emissions from building equipment are not material for the project condition given the minimal building equipment typically required. 2.1 QUANTIFICATION OF ESTIMATED GHG EMISSIONS/REMOVALS Project specific details on the implementation of the quantification protocol are provided in Section 4. Information on the measurement and estimation procedures for each parameter is provided in Section 5, as well as the information on the data quality management procedures for the project. 2.2 ESTIMATE OF GHG EMISSION REDUCTIONS/REMOVALS ENHANCEMENTS ATTRIBUTABLE FOR THE PROJECT The project specific formula for the quantification of emission reductions is provided in Section 4. The estimate of total greenhouse gas emission reductions for the project is approximately 40,000 tco 2e. 25

41 3 IDENTIFICATION OF BASELINE The project uses a dynamic projection-based baseline condition. This is most appropriate and provides the highest degree of accuracy when quantifying emission reductions. Measurements taken during the project condition provide an accurate and dynamic representation of emissions that would have occurred in the baseline condition. In the absence of the expansion project, the Nova facility would have captured a smaller volume of CO 2 from its process emissions, and a larger volume of CO 2 would have been emitted to atmosphere. Joffre would have sequestered less CO 2 in the absence of the project. Nova would have produced a similar amount of ethylene in the baseline condition and therefore the project and baseline condition are functionally equivalent. The baseline condition for the Joffre Viking Injection Project is determined through direct measurement of the volume of CO 2 injected at the expansion patterns at Joffre which would have been released to the atmosphere from industrial process emissions arising from ethylene production at NOVA s ethylene plant. Baseline emissions are quantified using direct measurements of the quantity of CO 2 that has been captured and injected in the project condition. The baseline condition is dynamic in approach as the quantity of CO 2 captured and injected will vary from year to year based on PennWests need for CO 2 to maintain their enhanced oil recovery activities. The net quantity of CO 2 injected at the three patterns was metered at the injection and production wellhead to determine net sequestration, and provides a high level of accuracy for calculating the baseline condition. 4 QUANTIFICATION PLAN Quantification of the reductions, removals and reversals of relevant sources and sinks of emissions for each of the greenhouse gases was completed using the methodologies outlined in Section 2.5 of the Enhanced Oil Recovery Protocol. 4.1 QUANTIFICATION APPROACH The following three equations will be used to quantify the emission reductions from the comparison of the baseline and project conditions: Emission Reduction = Emissions Baseline Emissions Project Emissions Baseline = Emissions Flaring at Capture Site Emissions Project = Emissions Source Gas B Capture + Emissions Fuel Extraction /Processing + Emissions Injection Unit Operation + Emissions Flaring at Injection Site Where: Emissions Baseline = sum of the emissions under the baseline condition Emissions Flaring at Capture Site = emissions under SS B2b Flaring at Capture Site Emissions Project = sum of the emissions under the project condition Emissions Source Gas B Capture = emissions under SS P1b Source Gas B Capture Emissions Fuel Extraction / Processing = emissions under SS P21 Fuel Extraction and Processing 26

42 Emissions Injection Unit Operation = emissions under SS P14 Injection Unit Operation Emissions Flaring at Injection Site = emissions under SS P15 Flaring at Injection Site The quantification calculation details of the parameters used in the above equations are outlined in the Enhanced Oil Recovery Protocol and discussed in Section 5 of this report. 4.2 DATA SOURCES The data required for the above calculation of emission reductions generated by the Project consists of the following: Volume of CO 2 that would have been incinerated (flared) in the baseline condition Composition of injected CO 2 (% CO 2 ) Volume of CO 2 gas flared in the project condition Composition of flared CO 2 (% CO 2 ) Volume of fuel gas consumed to supplement flaring in the project condition Amount of electricity consumed for CO 2 capture in the project condition Volume of fuel gas consumed for CO 2 capture in the project condition Volume of fuel gas consumed for injection unit operation in the project condition Amount of electricity consumed for injection unit operation in the project condition The specific methods of quantification for the above data sources are presented in the following section. 4.3 QUANTIFICATION METHOD Quantification of the emission reductions generated by the project will be conducted using a customized excel Quantification Calculator, developed by Leading Carbon / Prasino Group according to the Enhanced Oil Recovery Protocol. The general methods of quantification for the required data listed above are as follows: B2B FLARING AT CAPTURE SITE Volume of CO 2 incinerated (flared) in the baseline condition The volume of CO 2 that would have been incinerated in the baseline condition is measured by calculating the volume of new CO 2 that was injected in the project condition. The volume of injected CO 2 is determined based on the amount of injected CO 2 attributed to the three new injectors. Due to the fact that Joffre has multiple injectors that inject CO 2 prior to the project, and that the facility re-injects produced CO 2, a number of steps went into this calculation: a) To determine the proportion of new CO 2 (from NOVA) that is injected versus the amount of recycled CO 2 that is injected, the following calculation is performed on a monthly basis: 27

43 Where, % CO 2 NEW = the percentage of new CO 2 that is injected CO 2 NOVA = the total volume of CO 2 supplied by NOVA Gas Tot. Inj = the total (un-prorated) volume of injected gas by all injector wells The reported numbers from the Production Accounting reports account for the concentration of the CO 2 in the supplied gas stream from Nova. b) The volume of CO 2 that would have been incinerated in the baseline condition is measured by calculating the volume of new CO 2 that is injected in the project condition. To determine the amount of new CO 2 injected per injector (4-12, 4-34, 11-33) the following calculation is performed on a monthly basis: Where, Vol Source Type B Gas Flare = the total volume of new CO 2 injected by expansion injector wells % CO 2 NEW = the percentage of new CO 2 that is injected Gas Inj. Well = the total volume of gas that is injected by each injector well Vol Source Type B Gas Flare is then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for B2b Flaring at Capture Site P1B SOURCE TYPE B CAPTURE Amount of electricity consumed for CO 2 capture in the project condition The amount of electricity used at the NOVA ethylene production plant to compress and cool the CO 2 rich gas results in indirect greenhouse gas emissions through electricity consumption. The amount of kilowatt hours consumed to operate the above pieces of equipment is estimated based on the following equation: Where, Vol. Elec = Volume of electricity consumed by Nova to supply CO 2 each month Max Power = the maximum power consumption for cooling and compression equipment at Nova supply facility, as estimated by Nova 1 is 509.1kW. % Gas Inj. Well = the gas that was injected by each injector well 4-12, 4-34, as a percentage of the total gas injection (see P15) 24 = hours / day 1 Nova provided a document to PennWest titled Summary of significant equipment used by NOVA Chemicals in the capture, compression and transport of CO 2 to PennWest which provides details on how the above Max Power parameter was calculated. 28

44 365 = days per year 12 = months per year The respective volumes of electricity are then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for P1b Source Type B Capture P14 INJECTION UNIT OPERATION Volume of fuel gas consumed for injection unit operation in the project condition The volume of fuel gas used at the Joffre Battery for dehydration, heating and operating maintenance trucks results in greenhouse gas emissions. The volume of gasoline, propane and nature gas consumed to perform the above operations is estimated based on the following equations: Total volume of gasoline used = The volume of gasoline has been estimated based on the following parameters: a. Distance The distance an operator travels from the Joffre battery to the injection well and back has been estimated. This is a conservative estimate as the operator usually does a loop while driving and doesn t always return to the battery before travelling to the next injection site. To calculate the distance from the Joffre Battery to each injection well, an online LSD mapping tool, BaseLoc DLS by GPS Police ( is used. Where, Dist. MT = the total distance a maintenance truck travels in a day in km Dist = the distance from the Joffre Battery to the 4-12 injection well Dist = the distance from the Joffre Battery to the 4-34 injection well Dist = the distance from the Joffre Battery to the injection well 2 - factor to account for the round trip to the injection well b. Fuel efficiency The maintenance trucks used at the Joffre Battery are Chevrolet Silverado 2500 HD trucks with a 5.3L Gas engine. The fuel efficiency, measured in kilometers per liter, is estimated based on Natural Resources Canada's 2011 Fuel Consumption Guide 2. c. Litres of gasoline The estimate is based on an operator traveling once a day to each injection well from the Joffre Battery. This is a conservative estimate because operators do not visit every injection well once a day. 2 Natural Resources Canada's 2011 Fuel Consumption Guide 29

45 /12 Where, Gas Total = the total litres of gasoline that a maintenance truck consumes in a month Dist. Total = the total distance a maintenance truck travels in a day in hundreds of kilometers Fuel Efficiency = the fuel rating of a Chevrolet Silverado in L/100km 365 = the number of days in a year 12 = months in a year Total volume of propane used = The volume of propane has been estimated based on the type of heater and the length of heating. a. Fuel Rating A Cata-Dyne WX Series Explosion-Proof Infrared Gas Catalytic Heaters is used at each injection well. The size of the heater is 12 by 24 and utilizes propane for 6 months of the year. The fuel rating was taken from a catalogue found on the Cata-Dyne website 3. b. Liters of Propane Where, Prop. Total = the total volume of propane consumed to heat the injection wells in liters Fuel Rating = the fuel rating of the Cata-Dyne heater for propane in BTU/hr 3 is the number of injection wells (4-12, 4-34, 11-33) 744 is the number of hours in one month Total volume of natural gas used = The volume of natural gas has been estimated based on the type equipment and the length of heating. a. Fuel Rating A 30 by 15 reboiler runs a glycol reconcentrator unit, which is involved with the dehydration process. The reboiler has a fuel rating of 750,000BTU/hr., which was taken from a PennWest Joffre Battery Appraisal done by Jedex. It is assumed that the reboiler runs 24/7. The total emissions resulting from the reboiler will then be proportioned out per well, so as to only account for the expansion patterns (4-12, 4-34, 11-33). b. Volume of Natural Gas Where, Prop. Total = the total volume of propane consumed to heat the injection wells in liters 3 CCI Thermal Technologies Inc. Heating and Filtration Solutoins 30

46 Fuel Rating = the fuel rating of the reboiler for natural gas in BTU/hr. 744 is the number of hours in one month Amount of electricity consumed for injection unit operation in the project condition The amount of electricity used at the Joffre Battery for compression and injection activities results in greenhouse gas emissions. The amount of electricity consumed for injection activities at the 3 expansion wells (4-12, 4-34, and 11-33) is prorated from the Battery consumption based on the following equation: Where, Elec. 4-12,4-34,11-33 = the total amount of electricity consumed at each expansion injector well % Gas Inj.Well = the percentage of gas that was injected by each expansion injector well Elec = the total amount of electricity consumed at the Joffre Battery The respective volumes of fuel are then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for P14 Injection Unit Operation. Rod-Packing Emissions from the Compressor and VRU Under normal operating conditions, the compressor and VRU vent a small amount of emissions to the atmosphere. This emission source has not been included into the calculation as it is negligible and immaterial to the project P15 FLARING AT INJECTION SITE Volume of Gas flared in the project condition Flaring of gas is required during upset conditions or during system maintenance. Direct greenhouse gas emissions result from the release of the carbon dioxide contained in the gas stream. The total volume of flared gas is prorated to determine the amount of flared gas attributable to each injector. a) To determine the percentage of the total gas injected by the three new injectors, the following calculation is performed: Where, % Gas Inj. Well = the CO 2 that was injected by each injector well 4-12, 4-34, as a percentage of the total CO 2 injection Gas Inj. Well = the total volume of gas that is injected by each injector well 4-12, 4-34, Gas Tot. Inj = the total volume of injected gas by all injector wells b) To determine the volume of gas flared per injector (4-12, 4-34, 11-33), the following calculation is performed: 31

47 Where, Vol Injection Gas Flared = the total volume of new gas flared by expansion injector wells % Gas Inj. Well = the percentage of CO 2 that was injected by each expansion injector well Gas Tot. Flared = the total volume of flared gas Composition of flared gas The composition of flared gas is measured from the injection gas stream as is permitted in the protocol. The balance of gas composition is assumed to methane as methane is known to be present. The actual flare gas stream will be a mixture of purge gas (98% CO 2 ) and injection gas (typically around 82% CO 2 ) and will therefore have less methane than the balance of injection gas (typically lower than 18% methane). The flare ignition system constantly tries to ignite the flare on 15 second intervals, meaning if the flare gas is combustible, it will be ignited within 15 seconds and likely burn at a high efficiency. The assumption that the balance of injection gas composition is un-combusted methane is therefore conservative. Where, %CH 4 = the calculated concentration of methane in the flare gas % CO 2 = the percentage of CO 2 in the flare gas Volume of fuel gas consumed to supplement flaring in the project condition Flaring of gas is required during upset conditions or during system maintenance. From all flare volumes are calculated based on an engineering estimate and directly inputted into PVR (Production Volume Reporting) by the field operators. From volumes of flared gas is estimated using Flarecheck, an engineered estimation program which determines gas volumes sent to the flare based on pipe volumes, and inline conditions during the event. Purge gas is used to ensure that flare flow remains positive (no back flow) and that no flame arrestor is required. Purge gas is composed of CO 2 from Nova and is included in Flarecheck estimates. There is no fuel gas consumed for the flare. The respective emissions are then inputted into the quantification calculator as per the instructions found in Appendix A of the protocol for P15 Flaring at Injection Site P21 FUEL EXTRACTION / PROCESSING There are no calculation procedures required to determine the emissions under this SS beyond that which is listed in the protocol calculation methods. Please refer to the protocol, Section for all necessary calculation procedures for this SS. 32

48 4.4 SAMPLE CALCULATIONS The following sample calculation is provided to demonstrate how the above quantification methodology was applied to the data for January, Emission Reduction = Emissions Baseline Emissions Project Emissions Baseline = Emissions Flaring at Capture Site Emissions Project = Emissions Source Gas B Capture + Emissions Fuel Extraction /Processing + Emissions Injection Unit B2B FLARING AT CAPTURE SITE Operation + Emissions Flaring at Injection Site Volume of CO 2 incinerated (flared) in the baseline condition Gas NOVA = e 3 m 3 Gas Tot. Inj. = 4740 e 3 m 3 Gas Tot. Inj = 406 e 3 m 3 Gas Tot. Inj = 245 e 3 m 3 Gas Tot. Inj = 1,059 e 3 m P1B SOURCE TYPE B CAPTURE Amount of electricity consumed for CO 2 capture in the project condition The amount of electricity used at the NOVA ethylene production plant for compressing and cooling the CO 2 rich gas results in indirect emission of greenhouse gases. The amount of kilowatt hours consumed to operate the above pieces of equipment is estimated. Max Power = 509.1kW Vol elec. = (509.1) (24) (365) / (12) * ( ) = 134,056kWh 33

49 Emissions Source Type B Capture Grid Emission Factor = 0.88 kg CO P14 INJECTION UNIT OPERATION Volume of fuel gas consumed for injection unit operation in the project condition The volume of fuel gas used at the Joffre Battery for dehydration, heating and operating maintenance trucks results in greenhouse gas emissions. The volume of gasoline, propane and nature gas consumed to perform the above operations is estimated based on the following equations: Total volume of gasoline used = a. Distance Distance from 4-12 to = 14.5km/day Distance from 4-34 to = 9.5km/day Distance from to = 13km/day km b. Fuel efficiency = 9.5L/100km c. Litres of gasoline Distance Maintenance Truck = 75km/day Fuel efficiency = 9.5L/100km Total volume of propane used = a. Type of heater PennWest uses Cata-Dyne WX Series Explosion-Proof Infrared Gas Catalytic Heaters at each injection well. The size of the heater is 12 by 24 and utilizes propane for 6 months of the year. The fuel rating was taken from a catalogue found on the Cata-Dyne website 3. Fuel Rating = 10,000BTU/hr MJ per 10,000 BTU Energy content of propane = 46.44MJ/kg 34

50 Density of liquid propane = 581.2kg/m 3 c. Liters of Propane Fuel Rating = L/hr 3 = the number of injection wells = L/hr Total volume of natural gas used = a. Fuel Rating A 30 by 15 reboiler runs a glycol reconcentrator unit, which is involved with the dehydration process. The reboiler has a fuel rating of 750,000BTU/hr., which was taken from a PennWest Joffre Battery Appraisal done by Jedex. It is assumed that the reboiler runs 24/7. Fuel Rating = 750,000BTU/hr MJ per 750,000BTU Energy content of natural gas = 38.3MJ/m 3 b. Volume of Natural Gas Fuel Rating = 20.66m 3 /hr = 20.66m 3 /hr Vol Natural Gas. = 15,371.3 * ( ) = m 3 Amount of electricity consumed for injection unit operation in the project condition 35

51 4.4.4 P15 FLARING AT INJECTION SITE Volume of gas flared in the project condition Composition of flared gas Flared gas CO 2 composition is assumed to be equivalent to injection gas composition. It is conservative to assume this with the balance of gas composition being methane. The methane composition is therefore calculated as: 5 MONITORING PLAN 5.1 MEASURED PARAMETERS Based on the requirements set forth in Quantification Plan (Section 4), the following parameters are to be monitored during project execution B2B FLARING AT CAPTURE SITE SS B2b Flaring at Capture Site Data Parameter Gas Volume CO 2 NEW (from Nova) Estimated, modelled, measured, or calculation approaches Measured Data unit m 3 Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for Direct metering of volume transferred from Nova to Joffre at inline conditions Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration 36

52 any deviations from protocol SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol B2b Flaring at Capture Site Gas Temperature CO 2 NEW (from Nova) Measured C Direct metering of gas temperature transferred from Nova to Joffre at inline conditions Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol B2b Flaring at Capture Site Gas Pressure CO 2 NEW (from Nova) Measured kpag Direct metering of gas pressure transferred from Nova to Joffre at inline conditions Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration SS B2b Flaring at Capture Site Data Parameter Gas Volume CO 2 Injection (all wells) Estimated, modelled, measured, or calculation approaches Measured Data unit m 3 Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol Common output header from injection compressors Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration 37

53 SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol B2b Flaring at Capture Site Gas Temperature CO 2 Injection (all wells) Measured C Common output header from injection compressors Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol B2b Flaring at Capture Site Gas Pressure CO 2 Injection (all wells) Measured kpag Common output header from injection compressors Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration SS B2b Flaring at Capture Site Data Parameter Gas Composition CO 2 Injection (all wells) Estimated, modelled, measured, or calculation approaches Sampled by 3 rd party, reported to PennWest Data unit % Source / origin Direct metering of gas composition at inline conditions at output of compressors Monitoring Frequency Monthly Description and Justification of Monitoring Method Monthly sampling as per protocol Variations due to upsets and transient conditions in daily operations increase Uncertainty uncertainty however the impact on reduction estimates are minimal due to short term nature Provide detail, rationale and justification for any deviations from protocol of these events. Gas composition is not expected to vary highly from month to month 38

54 SS B2b Flaring at Capture Site Data Parameter Gas Volume CO 2 Injection (injection wells 4-12, 4-34, 11-33) Estimated, modelled, measured, or calculation approaches Measured Data unit m 3 Source / origin Injection well head Monitoring Frequency Continuous, recorded weekly, aggregated monthly Description and Justification of Monitoring Method Continuous metering is the most accurate method Uncertainty Limited to meter uncertainty and calibration Provide detail, rationale and justification for any deviations from protocol SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol B2b Flaring at Capture Site Gas Temperature CO 2 Injection (injection wells 4-12, 4-34, 11-33) Measured C Injection well head Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol B2b Flaring at Capture Site Gas Pressure CO 2 Injection (injection wells 4-12, 4-34, 11-33) Measured kpag Injection well head Continuous, recorded weekly, aggregated monthly Continuous metering is the most accurate method Limited to meter uncertainty and calibration P14 INJECTION UNIT OPERATION SS P14 Injection Unit Operation 39

55 Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol Electricity Consumption Measured kwh Metered by utility and invoiced Continuous, aggregated to invoicing schedule Continuous metering is the most accurate method Limited to meter uncertainty and calibration Prorated based on total battery injection and expansion wells injection rate on a monthly basis 5.2 ESTIMATED PARAMETERS Based on the requirements set forth in Quantification Plan (Section 4), the following parameters are estimated. Estimated parameters are used directly in the GHG Reporting Tool as preparation for the GHG Quantification Tool B2B FLARING AT CAPTURE SITE SS B2b Flaring at Capture Site Data Parameter Gas Composition CO 2 NEW (from Nova) Estimated, modelled, measured, or calculation Estimated by Nova, reported to PennWest approaches Data unit % Direct metering of gas composition transferred from Nova to Joffre at inline conditions is Source / origin unavailable, however Nova comfirms that contractual obligations are met Monitoring Frequency N/A Description and Justification of Monitoring Nova is contractually bound to maintain 98% Method CO 2 or greater at all times Variations due to upsets and transient conditions in daily operations increase Uncertainty uncertainty however the impact on reduction estimates are minimal due to short term nature of these events. Provide detail, rationale and justification for Gas composition is not expected to vary highly any deviations from protocol from month to month P1B SOURCE TYPE B GAS CAPTURE SS P1b Source Type B Gas Capture Data Parameter Electricity Consumption Estimated, modelled, measured, or calculation approaches Estimated Data unit kwh Source / origin Nova Monitoring Frequency Estimated monthly. Description and Justification of Monitoring Estimates from Nova based on process 40

56 Method Uncertainty Provide detail, rationale and justification for any deviations from protocol requirements for capture facilities are the only feasible data sources for this parameter. PennWest does not have control over this data and must rely on external support from Nova. Moderate, with minimal impact on project yield It is impractical to directly measure the incremental capture electricity use due to the increase in capture rate for the new injection patterns relevant to the project. A prorated value based on injected volumes to each pattern is most accurate based on the maximum possible power consumption provided by Nova P14 INJECTION UNIT OPERATION SS P14 Injection Unit Operation Data Parameter Propane Fuel Consumption Estimated, modelled, measured, or calculation approaches Estimated Data unit m 3 Source / origin Estimated Monitoring Frequency Estimated monthly, per injection well activity Injection heater propane use is not metered Description and Justification of Monitoring and can be accurately estimated based on Method conservative assumptions for heater capacity Uncertainty Provide detail, rationale and justification for any deviations from protocol Moderate, with minimal impact on project yield It is impractical to directly measure the incremental fuel use due to the increase in fuel use for the new injection patterns relevant to the project. An estimate based on site personnel interviews is most reasonable based on required operational activities. SS Data Parameter Estimated, modelled, measured, or calculation approaches Data unit Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol P14 Injection Unit Operation Diesel Fuel Consumption Estimated L Estimated Estimated monthly, per injection well activity Truck fuel use can be conservatively estimated based on operational requirements Moderate, with minimal impact on project yield It is impractical to directly measure the incremental fuel use due to the increase in fuel use for the new injection patterns relevant to the project. An estimate based on site personnel interviews is most reasonable 41

57 based on required operational activities P15 FLARING AT INJECTION SITE SS P15 Flaring at Injection Site Data Parameter Gas Volume Estimated, modelled, measured, or calculation approaches Estimated Data unit m 3 Source / origin Monitoring Frequency Description and Justification of Monitoring Method Uncertainty Provide detail, rationale and justification for any deviations from protocol Direct metering of volume transferred from Nova to Joffre at inline conditions Estimated for each flare event, aggregated monthly Engineering estimates through Flarecheck based on pipe volume and conditions of each flare event is most reasonable and accurate Moderate with minimal impact on yield It is impractical and inaccurate to directly measure the highly transient flare events during project operations. Flarecheck is used to provide detailed engineering estimates for each flare event based on real time conditions and pipe volumes. SS P15 Flaring at Injection Site Data Parameter Gas Composition Estimated, modelled, measured, or calculation Estimated approaches Data unit % Taken as inlet gas composition at Joffre Source / origin battery Monitoring Frequency Monthly sampling for estimate Monthly sampling by external lab is an accurate and cost effective way to determine Description and Justification of Monitoring gas composition. Estimation by assuming inlet Method gas composition is that of the flare is allowed by protocol. Variations due to upsets and transient conditions in daily operations increase Uncertainty uncertainty however the impact on reduction estimates are minimal due to short term nature Provide detail, rationale and justification for any deviations from protocol of these events. Gas composition is not expected to vary highly from month to month, hence monthly samples are sufficient. 42

58 6 DATA INFORMATION MANAGEMENT SYSTEM AND DATA CONTROLS In general, the data control process employed for this Project consists of manual or electronic data capture and reporting, and manual entry of monthly total or average values into a customized Quantification Calculator developed by Leading Carbon / Prasino Group. For monitoring and quality assurance purposes, it is assumed that the quantification methods and formulas used in the Quantification Calculator are accurate and have been reviewed on behalf of the Project proponent. There are two data streams involved in this project: Electronic data captured and reported by the continuous metering systems; and Manual data entry of all other parameters. Some data streams combine both electronic data capture and processing as well as manual transfer of information. The specifics of the Monitoring and QAQC plan are discussed in the following sections. 6.1 MEASUREMENT QUALITY CONTROL B2B FLARING AT CAPTURE SITE The quantification of emission reductions achieved by this project for this SS are based on direct measurement. Figure 8 shows the schematic for where metering occurs in the process at the Joffre site. There are two metering points in the process for this SS and are labelled in the figure below as such. Figure 8: Schematic Locations of Meters On-site at Joffre As described in Section 4, prorating the total injection of all injection patterns by the amount of new CO 2 received from Nova requires measurement of total injection volumes and measurement of receipt volumes from Nova on a continuous basis. The first meter point (Meter 1) occurs at the outlet from Nova to PennWest and represents the new CO 2 that is received from Nova. This meter is therefore necessary to determine the B2b 43

59 Flaring at Capture Site volume for quantification. If this meter is not working or deemed unreliable for any data points, there is no contingency and no offsets are generated for those time stamps. The second meter point (Meter 2) occurs at the injection well head for each injection pattern relevant to the expansion project. This meter is therefore necessary to determine the B2b Flaring at Capture Site volume for quantification for each well. If this meter is not working or deemed unreliable for any data points, no offsets are generated for those time stamps for that injection well, however injection measurement at the remain injection patterns may continue and generate offsets. The third meter point (Meter 3) occurs at the outlet of the compression train. This meter is necessary to determine the B2b Flaring at Capture Site volume for quantification for each well. If this meter is not working or deemed unreliable for any data points, no offsets are generated for those time stamps for all injection wells. Gas concentration data is outsourced to 3 rd party labs. Sample gas is taken on monthly intervals and reported through PennWest s gas analysis tracking system (PROTREND). This information is later correlated to relevant injection volume data and stored at PennWest offices in Production Reports. The table below lists the meters shown in the figure above and provides quality control details for each meter onsite. Table 2: Meter description and details # Description Meter Tag Meter Type / SN Maint. Schedule 1 Gas flow meter - deliveries from Nova Reference W4M G04M Bailey Fischer and Porter - Vortex Meter Annual Calibration Schedule Annual Accuracy Rating (Reference only) Gas flow meter - injection for pattern W4M Dynamic Flow ECHART V-Cone / Annual Annual +/-0.075% of cal. range 2 Gas flow meter - injection for pattern Injector W4M G01M Dri Flo II 25FS Orifice Meter / FR2018 Annual Annual +/-0.5% of full scale Gas flow meter - injection for pattern Injector W4M G01M Dri Flo II 25FS Orifice Meter / 202E-C Annual Annual +/-0.5% of full scale 3 Gas flow meter compressor output Phase 1 wells Gas flow meter compressor output Phase 2 wells W4M G08M W4M G09M Micromotion Flow Meter - Coriolis Micromotion Flow Meter - Coriolis Annual Annual +/-0.5% Annual Annual +/-0.5% 2 Pressure gauge injection W4M Dynamic Flow ECHART V-Cone Annual Annual +/-0.075% of cal. range 44

60 G01M Pressure gauge injection W4M G01M Dri Flo II 25FS Annual Annual +/-1% of full scale Pressure gauge injection W4M G01M Dri Flo II 25FS Annual Annual +/-1% of full scale 3 Gas pressure meter compressor output Phase 1 wells Gas pressure meter compressor output Phase 2 wells W4M G08M W4M G09M Integrated to Micromotion Flow Meter - Coriolis Integrated to Micromotion Flow Meter - Coriolis Annual Annual +/-0.5% Annual Annual +/-0.5% Temperature probe injection W4M G01M Dynamic Flow ECHART V-Cone Annual Annual +/-0.075% of cal. range 2 Temperature probe injection W4M G01M Dri Flo II 25FS Annual Annual +/-1% of full scale Temperature probe injection W4M G01M Dri Flo II 25FS Annual Annual +/-1% of full scale 3 Gas temperature meter compressor output Phase 1 wells Gas temperature meter compressor output Phase 2 wells W4M G08M W4M G09M Integrated to Micromotion Flow Meter - Coriolis Integrated to Micromotion Flow Meter - Coriolis Annual Annual +/-0.5% Annual Annual +/-0.5% Production Reporting accuracy and checks are performed on a monthly basis by the Production Accounting team. Any discrepancies between production records, invoiced volumes and sales volumes is reviewed. Utility information is first measured by utility meters, cross referenced by PennWest metering and settled on a monthly basis. The settling process for utility energy use therefore involves three data points, but effectively results in one data point that has redundant metering. Data is stored in PVR and at PennWest offices for the relevant data management systems. Only PennWest employees have access to the information and require employee logins and password authentication. The following figure depicts the data information management system for this SS. 45

61 Figure 9: Monitoring Plan for B2b Flaring Data Automated data flow in the figure above depicts the transfer of digital information from one computerized system to another. This may occur in one of two forms: 1. Both computer systems have purpose designed-and-built software dedicated to handling the data transfer. The transfer may be initiated manually or may be automated, however human intervention/error/tampering is not possible during the actual transfer of information. Information transfers within PVR are examples of this. 2. One computer system has a purpose built reporting tool that outputs digital data into a form that is easily transposable to a second computerized system that is not purpose built (ie Excel) but serves to manage the data as needed. Human intervention/error/tampering is possible however not likely unless malicious in intent. Information transfer from PVR or Protrend to Production Tracking Reports are examples of this. Manual data flow in the figure above depicts manual transfer of digital information from one computer system to another. This implies manual copying/pasting of values on a month-bymonth or well-by-well basis (ie in Excel). Human intervention/error/tampering is possible. Inputting into PVR and transferring from Production Tracking Reports to GHG Reporting tools are examples of this. 46

62 GHG assertions generated from the GHG Quantification tool and the GHG Reporting Tool will be retained by 3 rd party consultants and stored as part of the data management system in electronic form P14 INJECTION UNIT OPERATION The injection battery site uses both fuel and electricity. The injection site uses electricity as well (remote pad) for injection activities and production activities. Electricity and fuel use for the facility is prorated by injection to account for other wells injecting which are not considered part of this project. The fourth meter point (Meter Util ) occurs at the utility meter points at the PennWest battery and represents the volume of natural gas or electricity used by the various facilities relevant to the injection activities in this project plan. If these meters are not working or deemed unreliable for any data points, a settlement process is initiated whereby PennWest and the utility company agree on the billed amount on a monthly basis. Table 3: Meter description and details Description Meter Tag Meter Type / SN Util Gas flow meter Co-op gas (15-20) Util Electricity meter Fortis (15-20) Util Electricity meter Fortis (11-33) N/A (Co-op 1617) N/A (Fortis ) N/A (Fortis ) Dresser Rotary / Elster Electric Landis +Gyr Electric Maint. Schedule Calibration Schedule Utility Utility - Utility Utility - Utility Utility - Accuracy Rating 47

63 Production Reporting accuracy and checks are performed on a monthly basis by the Production Accounting team. Any discrepancies between production records, invoiced volumes and sales volumes is reviewed. Utility information is first measured by utility meters, cross referenced by PennWest metering and settled on a monthly basis. The settling process for utility energy use therefore involves two data points, but effectively results in one data point that has redundant metering. Data is encrypted at PennWest offices for the relevant data management systems (Qbyte). Only PennWest employees have access to the information and require employee logins and password authentication. The following figure depicts the monitoring plan for data for this SS. Figure 10: Monitoring Plan for P14 Injection Unit Operation Automated data flow in the figure above depicts the transfer of information from one system to another. This may occur in one of two forms: 1. Both computer systems have purpose designed-and-built software dedicated to handling the data transfer. The transfer may be initiated manually or may be automated, however human intervention/error/tampering is not possible during the actual transfer of information. Information transfers within PVR are examples of this. 2. One computer system has a purpose built reporting tool that outputs digital data into a form that is easily transposable to a second computerized system that is not purpose built (ie Excel) but serves to manage the data as needed. Human intervention/error/tampering is possible however not likely unless malicious in intent. Information transfer from PVR or Protrend to Production Tracking Reports are examples of this. Manual data flow in the figure above depicts manual transfer of digital information from one computer system to another. This implies manual copying/pasting of values on a month-by- 48