Offset Project Plan Hays Gas Plant Enhanced Oil Recovery ......This project plan for Hays Gas Plant...

Environment & Geoscience

June 22, 2017

Internal Ref: 647087

Offset Project Plan

Hays Gas Plant Enhanced Oil Recovery Project

Canadian Natural Resources Limited

Offset Project Plan

Notice to Reader This report has been prepared and the work referred to in this report has been undertaken by SNC-Lavalin Inc. (SNC-Lavalin), for the exclusive use of Canadian Natural Resources Limited (the Client), who has been party to the development of the scope of work and understands its limitations. The methodology, findings, conclusions and recommendations in this report are based solely upon the scope of work and subject to the time and budgetary considerations described in the proposal and/or contract pursuant to which this report was issued. Any use, reliance on, or decision made by a third party based on this report is the sole responsibility of such third party. SNC-Lavalin accepts no liability or responsibility for any damages that may be suffered or incurred by any third party as a result of the use of, reliance on, or any decision made based on this report.

The findings, conclusions and recommendations in this report (i) have been developed in a manner consistent with the level of skill normally exercised by professionals currently practicing under similar conditions in the area, and (ii) reflect SNC-Lavalin’s best judgment based on information available at the time of preparation of this report. No other warranties, either expressed or implied, are made with respect to the professional services provided to the Client or the findings, conclusions and recommendations contained in this report. The findings and conclusions contained in this report are valid only as of the date of this report and may be based, in part, upon information provided by others. If any of the information is inaccurate, new information is discovered or project parameters change, modifications to this report may be necessary.

This report must be read as a whole, as sections taken out of context may be misleading. If discrepancies occur between the preliminary (draft) and final version of this report, it is the final version that takes precedence. Nothing in this report is intended to constitute or provide a legal opinion.

SNC-Lavalin disclaims any liability to third parties in respect of the use of (publication, reference, quoting, or distribution), any decision made based on, or reliance on this report or any of its contents.

Canadian Natural Resources Ltd.

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Table of Contents 1. Introduction 1

2. Project Scope and Site Description: 2

3. Contact Information 5

4. Other Project Information 6

Description of how the project will achieve GHG emission reductions/removals .... 6 4.1

Conditions prior to project initiation ........................................................................ 7 4.2

Project eligibility ..................................................................................................... 9 4.3 Deviation from the Protocol ........................................................................... 9 4.3.1 Flexibility Mechanism .................................................................................. 10 4.3.2

Project technologies, products, services and the expected level of activity .......... 10 4.4

Identification of risks ............................................................................................ 11 4.5

5. Identification of the Baseline and Project Conditions 13

Baseline condition ................................................................................................ 13 5.1

Project condition .................................................................................................. 13 5.2

6. Inventory of Sources and Sinks 14

7. Quantification Plan 19

Fuel Receipts and Usage ..................................................................................... 19 7.1 Fuel Gas ..................................................................................................... 19 7.1.1 Purchased Gas ........................................................................................... 19 7.1.2 Sampling Procedures and Frequency ......................................................... 20 7.1.3

Incremental Solution Gas Compression (P12a Transportation Emissions) ........... 20 7.2 Emission Calculations, Equations, Emission Factors .................................. 20 7.2.1

Fugitive Emissions from Additional Equipment (P17 Fugitive at Injection Site + P13 7.3Fugitive Transportation + P12b Venting During the Compressor Start-ups) .................. 21

Equipment fugitive emissions (P17 Fugitive at Injection Site) ...................... 21 7.3.1 Pipeline fugitive emissions (P13 Fugitive Transportation) ........................... 21 7.3.2


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Compressor start gas vent (P12b Venting During the Compressor 7.3.3Start-ups) .................................................................................................... 22

CO2 Injected into the Reservoir (P14 Injection Unit Operation) ............................ 22 7.4 Sampling Procedures and Frequency ......................................................... 23 7.4.1 Activity Data ................................................................................................ 23 7.4.2 Emission Calculations, Equations, Emission Factors .................................. 23 7.4.3

Re-processed CO2 in the Solution Gas (P19 Recycled Injection Gas) ................. 24 7.5

8. Monitoring Plan 25

Calibration and Proving ........................................................................................ 25 8.1

Averaging ............................................................................................................ 27 8.2

9. Data Management System and Records 28

Data Flow ............................................................................................................ 28 9.1

Quality Assurance / Quality Control Procedures .................................................. 29 9.2

Data Retention Procedures .................................................................................. 30 9.3

Version Control .................................................................................................... 30 9.4

Equipment and information Management Systems .............................................. 30 9.5

10. Project Developer Signature 31


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1. Introduction This project plan for Hays Gas Plant Enhanced Oil Recovery has originally been created by Anadarko in 2005 and Anadarko has claimed 6,148 serialized Registered Emission Reductions (RERs) for this project for 2004 vintage year. Anadarko’s successor, Canadian Natural Resources Limited (CNRL), would like to continue with this offset project and would like to claim credits dating back to 2012 and any future offsets to 2019. This project plan is an update to the original project plan to satisfy the current regulatory requirements of the Alberta Environment and Parks (AEP).

From 2004 until 2012, CO2 was injected by the facility but it was not accounted for under the Specified Gas Emitters Regulation (SGER) until 2012. On January 29, 2014, the AEP issued a decision that CO2 sent off-site would be included in the total annual emissions in the source category it would have otherwise been reported in if it had not been sent off-site. This decision applied for 2012 and future SGER compliance report (CR) submissions. Those CO2 emissions were deemed to be vented emissions in the Hays Gas Plant CR as CO2 is not combustible and as such would simply flow through the incinerator unchanged.

CNRL requested permission to use the Quantification Protocol for Enhanced Oil Recovery for the Hays sour gas plant offsets from the Climate Change Office (CCO). CCO granted that request in a letter dated September 7, 2016.


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Offset Project Plan for Hays Gas Plant Enhanced Oil Recovery Project

Project Developer: Canadian Natural Resources Limited (CNRL) Suite 2500, 855 2nd Street SW T2P 4J8 Calgary, Alberta, Canada Date: June 21, 2017

2. Project Scope and Site Description: Project Title: Offset Project Plan for Hays Gas Plant Enhanced Oil Recovery Project

Project Purpose and Objectives:

The opportunity for generating carbon offsets with this project arises from the direct and indirect reductions of greenhouse gas (GHG) emissions resulting from the geological storage of waste gas streams containing GHG as part of enhanced oil recover (EOR) schemes.

Project Start Date: Initiation of the commercial injection of acid gas for EOR was September of 2004.

Credit Start Date: The credit start date was January 1, 2012.

Credit Duration Period: The project credit duration will be for 8 years starting January 1, 2012 and ending December 31, 2019.

Expected Lifetime of the Project:

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

Estimated Emission Reduction/Removals:

The total project emission reductions as a result of this project since January 1, 2012 (the project credit start date) are: 2012: 14,190 tonnes of CO2e/year 2013: 16,557 tonnes of CO2e/year 2014: 15,421 tonnes of CO2e/year 2015: 14,385 tonnes of CO2e/year 2016: 12,235 tonnes of CO2e/year Using the average reduction of the previous years and applying it to the future years: 2017: 14,558 tonnes of CO2e/year 2018: 14,558 tonnes of CO2e/year 2019: 14,558 tonnes of CO2e/year To the total: 116,461 tonnes CO2e/year

Actual Emission Reduction/Removals:

The actual emission reductions from this project, covering the period from January 1, 2012 – December 31, 2016, are calculated to be 72,788 tonnes of CO2e.

Applicable Quantification Protocol(s):

The quantification protocol used is the Quantification Protocol for Enhanced Oil Recovery (v1, October 2007) (the Protocol) protocol published by AEP.



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Project Title: Offset Project Plan for Hays Gas Plant Enhanced Oil Recovery Project

Protocol(s) Justification:

The protocol is applicable to this project as prior to EOR, the carbon dioxide (CO2) produced as a by-product of the natural gas processing would otherwise have been emitted to the atmosphere.

Other Environmental Attributes: None.

Legal Land Description of the Project and/or Other Unique Site Description:

The EOR is project involves the Enchant Arcs reservoir through the 10-22-013-15W4 and 14-22-014-16W4 injection wells. The processing components of the project (CO2 separation and compression) are location at the Hays gas plant (11-31-13-14W4M), therefore the plant’s location is used for the project. Latitude: 50.1294 N Longitude : 111.9075 W

Ownership:

Canadian Natural Resources Limited is the operator and majority owner of the Hays gas plant. There are three other companies that have a working interest in the plant through joint venture (JV) arrangements. Each party is entitled to their share of offset credits according to the average of their working interest in the two functional units that generate the offset credits (namely, the sulphur recovery unit and the CO2 compressor). Due to the low working interests of the three other parties, they will be paid for their proportionate share of the credits at the prevailing carbon price, resulting in Canadian Natural Resources Limited having 100% ownership of the offset credits.

Reporting and Verification Details:

This project is claiming historic credits from January 1, 2012 – December 31, 2016. Subsequent reporting will occur annually. The verifier will be an independent third-party verifier that meets the requirements outlined in the SGER. An acceptable verification standard (e.g. ISO14064-3) will be used and the verifier will be vetted to ensure technical competence with this project type.



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Project Title: Offset Project Plan for Hays Gas Plant Enhanced Oil Recovery Project

Project Activity:

The project is an EOR project in southeast Alberta and meets the Offset Eligibility Criterion as listed in the section 3.1 of the Technical Guidance for Offset Project Developers (v4, February 2013) published by AEP. Specifically:

1. The project occurs in Alberta: the location is in southern Alberta; 2. The project results from actions not otherwise required by law and

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

3. The project results from actions taken on or after January 1, 2002: as outlined above the project start date was September of 2004; the project start date is demonstrated by the commissioning of the acid gas injection system and the commencement of EOR monitoring/reporting by CNRL.

4. The project reductions/removals are real, demonstrable, quantifiable and verifiable: the project is creating real reductions that are not a result of shutdown, cessation of activity or drop in production levels.

5. The project has clearly established ownership: CNRL is the owner and operator of the Hays Gas Plan and the EOR scheme. Credits created from the specified reduction activity have not been created, recorded or registered in more than one trading registry for the same time period.

6. The project will be counted once for compliance purposes: The project credits will be registered with the Alberta Emissions Offset Registry (AEOR) which tracks the creation, sale and retirement of credits. Credits created from the specified reduction activity have not been, and will not be, created, recorded or registered in more than one trading registry for the same time period. There have been 6,148 serialized RERs for this project that have been registered for 2004 vintage year.

Project Registration: Project Registered with the following project identifier: C-AAA-0048. Other: None.



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3. Contact Information

Project Developer Contact Information:

Andrew Higgins Supervisor Environmental Operations Canadian Natural Resources Limited Suite 2500, 855 2nd Street SW T2P 4J8 Calgary, Alberta, Canada Work: (403) 514-7565 Fax: (403) 514-7677 Cell: (403) 998-4616

Authorized Project Contact: None



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4. Other Project Information Description of how the project will achieve GHG 4.1

emission reductions/removals The Hays oil field, located in Southern Alberta, is operated by Canadian Natural Resources Limited (CNRL). The field began production in the mid-1980’s as a conventional oil field. From 1992 to approximately 2003, enhanced oil recovery (EOR) by waterflooding of the field was used to improve production. EOR by injecting carbon dioxide (CO2) into the pool commenced operation in September 2004. CO2 injection is expected to increase the life of the pool by 20 to 30 years, while maintaining production levels. GHG emission reductions began at the start of the CO2 flood and are expected to continue as long as the CO2 continues to be injected. If the CO2 injection EOR was to be terminated, the waterflooding would continue as the waterflooding operates separately from the CO2 EOR. Thus the waterflooding operations are outside of the scope of this plan and have not been included in the emissions or offsets assessments.

Initially, CO2 was injected into the Enchant Arcs A&B pool with subsequent expansion of the project to the Enchant Arcs E&F pool. The CO2 for the project is supplied by the nearby Hays sour gas processing plant, also operated by CNRL. Figure 1, below outlines the project boundary with its major components: the gas plant and the two CO2 injection wells for the two pools.

Figure 1 Project Boundary with its Major Components



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CO2 and hydrogen sulphide (H2S) (collectively called acid gas) are stripped from the raw gas at the Hays plant using a regenerative amine process. This acid gas stream is further processed by the Flexsorb unit to separate most of the H2S from the CO2. The H2S rich stream is fed through a sulphur recovery plant to convert virtually all of the H2S to elemental sulphur. Under normal operation, the CO2 rich stream is dehydrated and compressed for injection, and the sulphur recovery plan tail-gas stream is disposed of by incineration. The CO2 rich stream consists of approximately 99 percent CO2, 0.5 percent methane (CH4), and trace quantities of other hydrocarbons, H2S and inerts.

The CO2 rich stream is compressed from near atmospheric pressure to 15 500 kPa in order to transport it to the oil field by a pipeline for the EOR injection. A Coriolis meter (FIT 8321), located at the plant, continuously measures the mass flow rate of CO2 sent to the field. Gas analysis of the injected stream and of the streams entering the facility are completed on a monthly basis and help to increase the precision of the offset calculations.

In the field, the CO2 is injected into the Enchant Arcs reservoir through the 10-22-013-15W4 and 14-22-014-16W4 injection wells. CO2 expands in a reservoir and pushes additional oil to a production wellbore, by dissolving in the oil and lower its viscosity and improving its flow rate. By this process much of the injected gas stays in the reservoir. As the oil is produced, the solution gas is separated at the battery and transported back to the Hays gas plant by pipeline for processing, and subsequently returned to the field to be re-injected.

Tracking the quantity of re-produced CO2 is a key element in determining the net reduction of GHG emissions. A baseline quantity of CO2 in the solution gas is compared to the amount of CO2 produced after implementation of the EOR project. The difference represents the amount of re-produced CO2, and this quantity will be subtracted from the total amount of injected CO2 to arrive at the net quantity of CO2 stored.

Conditions prior to project initiation 4.2The emission baseline is the quantity of GHGs prior to the start-up or expansion of the injection operation. For this project, baseline emissions are those that would have occurred had the EOR project not been implemented. Specifically, they are the vented CO2 emissions from the incinerator at the Hays gas processing plant. The baseline changes from year to year depending on activity levels in the field and physical characteristics of the production. Setting an accurate emission baseline is the critical first step in the determination of GHG emission reductions, as it provides the benchmark against which emission reductions are measured. This section provides an overview of the elements that are the framework for the baseline.

The most important step in determining net emission reductions from a GHG emission reduction project is establishing an appropriate project boundary. The boundary must be sufficiently large to capture all significant emission sources, while excluding sources that do not influence net emission reductions from the project, see Figure 1. The process flow presented in Figure 2 provides a detailed schematic of items considered for the offset project within the Hays gas plant such as fuel sources, key meters, sampling points, fuel / production receipts and the disposition point.



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Figure 2 Hays Gas Plant Simplified Process Diagram



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The boundaries include the portion of the Hays gas processing plant associated with extraction of the CO2 stream, CO2 compression and metering. In the field, sources within the project boundaries include: the CO2 pipeline and injection equipment. Existing gas/oil separation equipment and vapour recovery systems in the field are not included within the boundaries. GHG emissions from these systems are anticipated to remain relatively constant or decline slightly with the depletion of the reservoir. In addition, as the ratio of CO2 to CH4 of the solution gas changes with the CO2 injection operations, bearing in mind that the GWP for CH4 is 25 compared to 1 for CO2, the total carbon dioxide equivalent (CO2eq) emissions from fugitive equipment leaks would decrease.

All sources of GHG emissions within the project boundaries, both direct and indirect, are considered and include natural gas fuel consumption, venting and fugitive emission sources such as equipment leaks, etc.

Injected CO2 refers to only “new” CO2 injection and does not include CO2 that is re-produced, re-processed and re-injected. This distinction ensures that there is no double counting of avoided CO2 emissions. That is, the CO2 is only counted the first time it is injected.

Project eligibility 4.3This project meets the requirements for offset eligibility as outlined in section 3.1 of the Technical Guidance for Offset Project Developers (version 2.0, January 2011), see Section 2: Project Scope and Site Description of this plan. Permission to use the Quantification Protocol for Enhanced Oil Recovery dated September 7, 2016 is also attached to support project eligibility. Please refer to Attachment 1.

The project has obtained approvals from the Alberta Energy Regulator (AER) and meets the requirements outlined under Directive 051: Injection and disposal Wells – Well Classifications, Completions, Logging and Testing Requirements. The Approval No. 10523H Arcs F&G and 9839E Arcs A&B are attached in Attachments 2 and 3.

Deviation from the Protocol 4.3.1Hays Gas Plant reports under the SGER and has several sources reporting under the SGER which are being counted as an offset project emissions. A reduction target (T) is reported through the SGER program, thus the offset project would need any emissions reported by the SGER facility sources to be backed out through this EOR offset project calculations. A “deviation from the EOR protocol” will be requested as per the attached email dated January 23, 2017 which will justify why only portion of the CO2 compressor emissions are accounted for under this plan. The “deviation from the EOR protocol” document is attached in Attachment 4.



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Flexibility Mechanism 4.3.2The quantification of GHG emission reductions from the Hays Gas Plant EOR Injection Offset Project utilizes one flexibility mechanism as per the Protocol, specifically the use of site specific CO2 emission factors and N2O and CH4 emission factors, consistent with and accepted as part of the facility’s SGER CR report. The flexibility mechanism permits site specific emission factors to be substituted for the generic emission factors provided that the methodology for the generation of these emission factors is sufficiently robust to ensure reasonable accuracy. In this project the default Environment Canada CO2 emission factor for natural gas combustion was replaced with a site specific emission factor calculated according to the specific composition of the fuel gas used at the site. The use of annual third party lab analyses to calculate the carbon content of the fuel gas improves the accuracy of the quantification since the fuel gas used at the site is considerably richer than sales gas purchased from a pipeline, which rarely occurs. The methodology for the calculation of the fuel gas emission factor was sourced from best practice guidance from the Canadian Association of Petroleum Producers (CAPP), Calculating Greenhouse Gas Emissions (CAPP and Altus Environmental Engineering Ltd, 2003) and increases the conservativeness of the GHG reduction estimate.

Project technologies, products, services and the 4.4expected level of activity

This EOR project eliminates the direct GHG emissions to the atmosphere through the permanent geologic storage of CO2 that would otherwise have been vented to the atmosphere. The source of injected CO2 is an important consideration, as net CO2 emission reductions occur only if the stream of CO2 to be injected had previously been vented to the atmosphere. In most EOR applications, CO2 used for injection comes from wells that were developed specifically for the purpose of producing CO2 to be injected into an oil field. In such cases, had the EOR project not been implemented, the CO2 would have simply remained in the geologic formation and there would be no basis for claims of GHG emission reductions.

In contrast, where CO2 that had previously been vented to the atmosphere is used for EOR, net reductions in CO2 emissions can occur. A common source of carbon dioxide is “formation CO2” extracted from raw natural gas at processing plants in order to attain the CO2 pipeline specification in the sales gas. This formation CO2 is typically vented either through flares or incinerators, depending on regulations for the disposal of other contaminants, such as H2S being removed along with the CO2. The CO2, being non-combustible, is ultimately released to the atmosphere.

When CO2 injection is used for EOR, some of the CO2 returns to the surface with the produced oil and gas. As part of the project, solution gas containing the re-produced CO2 is conserved and transported to the Hays gas processing plant. There, the CO2 is separated and then returned to the field for re-injection.

Details of the systems included in the project are provided in the sections below. Please note there is no electrically operating equipment as part of the CO2 injection process.

Compressor The compressor, Waukesha L5774LT, 1250 hp, is a gas-driven compressor. The CO2 gas is compressed to a pressure of up to 15,500 kPa and is transported by pipeline for injection into the reservoir. Canadian Natural Resources Ltd.


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Pipeline The 88.9 mm diameter pipeline runs approximately 6.5 km to the injection well located at 10-22-013-15W4.

Injection and monitoring infrastructure The compressed CO2 gas is transported by pipeline to a well that will result in essentially permanent geological storage. The IPCC estimates that, provided that geological reservoirs are appropriately selected and managed, the CO2 fraction retained underground is (IPCC, 2005): very likely to exceed 99% over 100 years (with a probability greater than 90%); and likely to exceed 99% over 1 000 years (with a probability higher than 66%). Regular pressure surveys are and will be conducted to ensure that the injected gas is being contained within the target reservoir as dictated by the AER Approvals: 10523H Arcs F&G and 9839E Arcs A&B. CNRL currently monitors reservoir pressures and reports them to AER. Monitoring requirements for future (after CO2 injection ceases) will be determined by AER. Issuance of the operational permits from the AER provides assurance that the required measurement and monitoring programs are in place to ensure long-term storage of all components of the acid gas stream. In particular, a complete geological assessment of the injection reservoir with respect to permanence of storage, an assessment of any potential leakage and contemplation of the leakage mitigation and management strategies that CNRL has implemented was included in the review completed by the AER during the EOR permitting.

Identification of risks 4.5Geologic storage of GHGs inevitably raises concerns about whether the injected gases will remain permanently stored in the geologic formation. These concerns may include sudden large releases to the surface; slow, likely unnoticeable releases, to the surface; migration of the fluid within the geological formation; and seismic activities. Potential releases to the atmosphere and risks associated are mitigated by the proper implementation of pressure monitoring protocols, as required by AER, during the course of operations. Technological measures are planned to ensure that this is the case. Formations typically selected for CO2 injection are ones that have contained hydrocarbons (and often CO2) over geologic time periods and are presumed to be able to contain the injected CO2. The CO2 will, however, reach wells that have been drilled into the geologic formation in which the CO2 has been injected. To ensure that CO2 moves only into producing or monitoring wells, inactive wells in the injection area were inspected prior to the commencement of injection to ensure that they have been properly plugged and abandoned, thus eliminating this potential migration route to the surface.

Once active wells used in the EOR process are no longer needed, they will be plugged and abandoned following current provincial regulations to ensure that migration of hydrocarbons and CO2 to the surface does not occur. Procedures for plugging and abandoning wells to avoid future releases are well established and activities are directed by AER.



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Operational failure (e.g. leakage) of the injected gas from the pipelines and other equipment may occur due to activities related to improper excavation as well as corrosion and potential over-pressurization (e.g. due to bad engineering practices). These events are mitigated by the employment of automated shutdown valves and other safety measures that limit the amount of CO2 discharged to the atmosphere. Additionally, ensuring that the injection wellhead is situated in well-ventilated areas allows for the quick diffusion of CO2 into the atmosphere. CO2 detection is present in the buildings at injection wells and pressure transmitters have been installed on tubing and casing of wellheads with alarms and low pressure shutdowns on the tubing side. The system alarms if there is a pressure increase on the casing side. Also, there is a low pressure shutdown on the compressor itself. In the event that the injection equipment, monitoring equipment, or safety devices fail, injection activities will be suspended, and the CO2 stream will be rerouted to the incinerator or flare. To further clarify, normal upset flow would be to the incinerator. If the incinerator is off line then it would go to the flare. Fuel gas will be used to supplement the gas stream to ensure efficient combustion.

Additional project specific monitoring requirements, as per AER Approvals, are adhered to in order to fully implement safety considerations.



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5. Identification of the Baseline and Project Conditions Based on the Protocol, the baseline and project conditions include Source Type A gases as the venting or flaring of the GHG contained within waste gas streams either at the capture point or as part of processing, and where applicable, the operation of the oil production system without injection and geological storage. The Source Type A is applicable to oil and gas production project where solution gas capture and processing, venting or flare are part of the normal operating practice for the facility, and the EOR project has been implemented to utilize the CO2 portion of the captured solution gas.

The project and baseline are functionally equivalent, except for the project-specific sources, as they provide the same function and quality of products, as outlined in the inventory of the sources and sinks, sections below.

Baseline condition 5.1The baseline condition for a project is a reasonable representation of conditions that would likely have occurred during the offset credit period had the offset project not been implemented. In other words, the baseline represents “business as usual” and the project represents a change from this practice. Please see the baseline condition description found in the Protocol. The baseline emissions for the Hays EOR project include:

› Pre-project emissions from incinerator and flare fuel gas consumption; › Baseline quantity of CO2 in the Enchant Arcs solution gas, for these wells, it ranges from

10-20% of the gas; › Pre-project venting and fugitives; and › Baseline combustion of fuel gas used in the stationary fuel combustion (SFC).

Project condition 5.2The project condition is a specific action targeted at reducing or removing GHG emissions, and the project description, ie geological storage of CO2 is outlined in the previous sections. In addition to the emission reductions that will be achieved from the CO2 injection, there are a number of GHG emission sources that will be created, in addition to the baseline ones, in the implementation of the Hays EOR project:

› Natural gas-fueled CO2 compressor assisting in transportation of the CO2 gas from the gas plant to the injection site (combustion emissions of CO2, CH4 and N2O),

› CO2 pipeline (fugitive emissions of CO2 and CH4), and › Venting and fugitive emissions from the additional equipment and meters used for the project

(emissions of CO2 and CH4).

The net emission reduction calculation must account for the project emission reductions as well as these incremental emission increases.



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6. Inventory of Sources and Sinks Each of the SS’s from the project and baseline conditions were compared and evaluated as to their relevance as mandated by the protocol. The SS’s were identified using protocol’s scheme, refer to Attachment 5.

1. Identified SS 2. Baseline 3. Project 4. Include or Exclude from Quantification 5. Justification for Exclusion

Upstream SS's during project operation P1a Capture Site Emissions Related Exclude Excluded as these SS's are functionally

equivalent under the project and baseline conditions. B1a Capture Site Emissions Related Exclude

P2a Flaring Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B2a Flaring Related Exclude

P3a Venting Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B3a Venting Related Exclude

P4a Fugitive Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B4a Fugitive Related Exclude

P5a Transportation Emissions Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B5a Transportation Emissions Related Exclude


P7a Processing Emissions Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B7a Processing Emissions Related Exclude

P8a Flaring Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B8a Flaring Related Exclude

P9a Venting Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B9a Venting Related Exclude



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P11a Sealable Components Transport and Use Related Exclude Excluded as these SS's are functionally

equivalent under the project and baseline conditions. B11a Sealable Components

Transport and Use Related Exclude

P12a Injection Gas Transportation Emissions

no Related Include The gas is carried via pipeline run by a CO2 compressor. The CO2 compressor emissions are accounted for under the SGER requirements. Only the amount of emissions in excess of the SGER reduction target will be accounted for the injection project. For example, if the SGER reduction target is 15%, then 85% of the compressor emissions would be accounted for in the injection project.

P12b Venting During the Compressor Start-ups

no Related Include Part of the CO2 compressor operations.

P13 Fugitive Transportation no Related Include Only fugitive transportation emissions are applicable as the gas is carried via pipeline.

P20 Electricity Usage Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B15 Electricity Usage Related Exclude

P21 Fuel Extraction/Processing Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B13 Fuel Extraction/Processing Related Exclude

P22 Fuel Delivery Related Exclude Excluded as these SS's are functionally equivalent under the project and baseline conditions. B14 Fuel Delivery Related Exclude

On-site SS's during project operation P14 Injection Unit Operation no Controlled Include The amount of CO2 being injected. P15 Flaring no Controlled Exclude No flaring on the injection site. P16 Venting no Controlled Exclude No venting on the injection site.



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P17 Fugitive at Injection Site no Related Include Only fugitive emissions are applicable to the injecting site as the rest of the equipment is located in the upstream part of the project.

Downstream SS's during project operation P18 Fuel Production, Distribution and Usage Emissions Related Exclude Excluded as these SS's are functionally

equivalent under the project and baseline conditions. B12 Fuel Production, Distribution

and Usage Emissions Related Exclude

P19 Recycled Injection Gas Related Include Recycled CO2 that has been injected. Downstream SS's before project operation P23 Development of Site Related Exclude Emissions from the site development are

not material given the minimal site development typically required. B16 Development of Site Related Exclude

P24 Building Equipment Related Exclude Emissions from the site development are not material given the minimal site development typically required. B17 Building Equipment Related Exclude

P25 Transportation of Equipment Related Exclude Emissions from the site development are not material given the minimal site development typically required. B18 Transportation of Equipment Related Exclude

P26 Construction on Site Related Exclude Emissions from the site development are not material given the minimal site development typically required. B19 Construction on Site Related Exclude

P27 Testing of Equipment Related Exclude Emissions from the site development are not material given the minimal site development typically required. B20 Testing of Equipment Related Exclude

Downstream SS's after project P28 Site Decommissioning Related Exclude Emissions from the site development are

not material given the minimal site decommissioning typically required. B21 Site Decommissioning Related Exclude



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The basis for claiming GHG emission reductions from the Hays EOR project hinges on the permanent storage of the injected CO2. The net emission reduction is the difference between the project emissions and the baseline. The sources and sinks (SSs) that are excluded from the project are excluded by setting their input variables to zeros because they do not exist within the project and baseline boundaries. The CO2 injected into the reservoir is not included in the baseline since this activity is not present in the baseline case.

The CO2 gas vented through the incinerator/flare comprises of the three streams for which composition and flow data are not accurately known. In contrast, the volume of the CO2 rich stream injected is continuously measured with a custody transfer quality meter and monthly composition data are collected. This results in a high quality quantification of the avoided GHG emissions.

For the project case, CO2 injection stops during the non-routine events such as emergency. Such gas is sent to be vented through the incinerator/flare as in the baseline operations and is not metered by the CO2 injection meter. However, this gas is considered to be a formation CO2 vent GHG emission and is captured by a Hays Gas Plant’s SGER reporting. In summary:

CO2 Venting (Baseline) = CO2 Injected into the Reservoir + CO2 Venting (Project)

Or

CO2 Injected into the Reservoir = CO2 Venting (Baseline) - CO2 Venting (Project) The net GHG emission reduction may be summarized by the following equations:

Net GHG Emission Reduction = EB - EEOR

Where: EB = Baseline Emissions

= Incinerator and Flare Fuel Gas Consumption (B8a Flaring)

+ CO2 Venting (B9a Venting)

+ Other Facility Venting (B9b Venting) and Fugitive (B10a Fugitive)

+ Fuel Gas SFC Consumption (B7a Processing Emissions)

EEOR = EOR Project Emissions

= Incinerator and Flare Fuel Gas Consumption (P8a Flaring)

+ CO2 Venting (P9a Venting)

+ Other Facility Venting (P9b Venting) and Fugitive (P10a Fugitive)

+ Fuel Gas SFC Consumption (P7a Processing Emissions)

+ Fugitive Emissions from Additional Equipment (P17 Fugitive at Injection Site + P13 Fugitive Transportation + P12b Venting during the compressor start-ups)

+ Re-processed CO2 in the Solution Gas (P19 Recycled Injection Gas)

+ Incremental Solution Gas Compression (P12a Transportation Emissions)



Offset Project Plan

Several of the emission sources remain unchanged between the baseline and project cases, those sources cancel out by being on the opposite sides of the Net GHG Emission Reduction equation. The sources that have the same emissions for the baseline and project scenarios at the facility level are:

B8a Flaring = P8a Flaring

B9b Other Facility Venting = P9b Other Facility Venting

B10a Fugitive = P10a Fugitive

B7a Processing Emissions = P7a Processing Emissions Combining the baseline and EOR emissions into one equation:

Net GHG Emission Reduction = CO2 Venting (B9a Venting)

- CO2 Venting (P9a Venting)

- Fugitive Emissions from Additional Equipment (P17 Fugitive at Injection Site+ P13 Fugitive Transportation+ P12b Venting during the compressor start-ups)

- Re-processed CO2 in the Solution Gas (P19 Recycled Injection Gas)

- Incremental Solution Gas Compression (P12a Transportation Emissions)

However,

CO2 Venting (Baseline) - CO2 Venting (Project) = CO2 Injected into the Reservoir Using the amount of CO2 injected into the reservoir in the project calculations:

Net GHG Emission Reduction = CO2 Injected into the Reservoir (P14 Injection Unit Operation)

- Fugitive Emissions from Additional Equipment (P17 Fugitive at Injection Site+ P13 Fugitive Transportation+ P12b Venting during the compressor start-ups)

- Re-processed CO2 in the Solution Gas (P19 Recycled Injection Gas)

- Incremental Solution Gas Compression (P12a Transportation Emissions)



Offset Project Plan

7. Quantification Plan Net GHG emission reductions from the Hays CO2 injection project may be represented by the equation presented in the section above. GHG emissions associated with each term in the equations are delineated in the sections that follow. The calculations presented in this quantification plan are based on the SGER Hays Gas Plant compliance report calculations since the project is part of the plant’s operations which need to be reported under the SGER.

Fuel Receipts and Usage 7.1The CO2 compressor, as the rest of the Hays gas plant is powered by the natural gas. The Hays facility has two fuel sources:

1. Fuel gas processed by the Hays gas plant; and 2. Purchased gas from TransCanada Pipeline (TCPL) (also known as buyback gas).

Table 1, below, summarizes how the fuel is received on site, where it is used and how the final use is determined.

Table 1 Fuel Receipt Points

Fuel Receipt Point Volume Inputs Determined By

Final Fuel Usage Determined By

Fuel gas Plant Direct Measurement Usage TCPL purchased gas Meter station Invoice Usage

For the purpose of the GHG offset quantifications there is no difference in the usage of the two types of the gasses.

Fuel Gas 7.1.1Compressors and other external combustion sources such as utility boilers and line heaters burn fuel gas in the form of processed gas that is the sales gas product from the Hays plant. Wells are owned by CNRL as well as other owners. Fuel gas is also used for the dehydrators and as blanket gas. Fuel gas is metered by FE-3232 for the whole plant.

PETROLEUM REGISTRY PLANT FUEL = FE3232

Purchased Gas 7.1.2CNRL purchases natural gas from TCPL when there is insufficient fuel gas to run the plant. The purchased gas is used for all of the same equipment that fuel gas is used for. Purchased gas is metered by TCPL at their delivery point. The volumetric data is provided to the CNRL accounting department and is manually entered into EC.

PETROLEUM REGISTRY SALES GAS = TCPL CUSTODY METER



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Sampling Procedures and Frequency 7.1.3Purchased gas samples are provided by TCPL on a monthly basis, through their website, for months where CNRL has purchased gas using the monthly sales meter report.

Solution gas is sampled and analyzed twice per year by Maxxam Analytics (measured data). The gas compositions are posted on the lab’s website and available to CNRL electronically. The lab report is available for viewing on the website, or as an export to Excel with the breakdown of the hydrocarbons. For the purposes of the yearly SGER reporting, the Excel versions have been downloaded and copied into the Master Calculation spreadsheet. The same gas analyses were used for the CO2 compressor GHG emissions calculations. Fuel gas volumes are received from the daily meter readings. Sample points are as follows:

The sampling point for solution gas is FUEL GAS just after meter FE-3232

The sampling point for sour gas is SOUR GAS INLET just after meter FE-3225

Incremental Solution Gas Compression (P12a 7.2Transportation Emissions)

The major equipment type which emits GHG emissions for the project is the CO2 compressor. Table 2, below, lists the compressor equipment unit number as found in the Detechtion Technologies database, a third party providing management services for compressors, the tag number used in the data management system at the plant and the type of service the compressor is in.

Table 2 CO2 Compressor Details

Equipment Type Equipment Number (Detechtion) Tag Number Service

Compressor 6728 K810 CO2

Emission Calculations, Equations, Emission Factors 7.2.1CO2 compressor combustion emissions were calculated by the following equation:

SFC EMISSIONS = INPUT FUEL VOLUME X EMISSION FACTOR

From 2012 to 2015, the consumed fuel volumes were based on Hays Plant Fuel Gas Allocation worksheets provided by Property Accountant which split the total fuel consumed by reciprocating engine / heater and incinerator.

Starting in 2016 for calculation purposes, CNRL started using the data as provided from Detechtion which is based on actual horsepower load and actual run hours. Using the higher heating value (HHV) from the fuel gas composition volume of the burned fuel can be estimated:

FUEL USED BY CO2 COMPRESSOR = FUEL USED (MMBTU) * 1.055056/HHV (MJ/M3)



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The CO2 emission factor is based on the semi-annual fuel gas analysis for the plant. The equation is as follows:

CO2 FUEL GAS EMISSION FACTOR = ((VOLUME WEIGHTED % OF CO2 AND HYDROCARBON COMPONENT IN THE SAMPLE * NUMBER OF CARBON ATOMS IN THE MOLECULE) * MOLECULAR WEIGHT CO2) / VOLUME OF KMOLE

The CH4 and N2O emission factors are based on the CAPP 2003 Guide, Table 1-6, for natural gas drivers for lean burning reciprocating engines.

Fugitive Emissions from Additional Equipment (P17 7.3Fugitive at Injection Site + P13 Fugitive Transportation + P12b Venting During the Compressor Start-ups)

Fugitive emissions from the additional equipment include equipment, pipeline and pig removals fugitive emissions and the vented start gas from the K810 compressor. Instruments and controllers run using instrument air, not instrument gas, and are therefore not a source of fugitive emissions. Fugitive volumes were estimated according to the equations listed for each source, below.

Equipment fugitive emissions (P17 Fugitive at Injection Site) 7.3.1Fugitive emissions were calculated based on the Generic Fitting Count (GFC) Method described in Section 1.8 of the CAPP 2003 guide. For the injection system, the CO2 injected gas was used as a representative composition. Once the equivalent seal or fitting count was determined it was multiplied by the generic emission factor to yield the tonnes of gas per year emitted. This value was then multiplied by the corresponding gas analysis to reflect the actual methane content in the emissions.

EMISSIONS = NUMBER OF COMPRESSOR SEALS OR FITTINGS X EMISSION FACTORS

7.3.1.1 Pig removals fugitive emissions Volume of CO2 fugitive emissions was calculated based on the size of a pig receiver at the injection site and that was multiplied by how many pigs were received in a year. An injection gas CO2 emission factor was used to estimate mass of CO2 emissions released to the air.

Pipeline fugitive emissions (P13 Fugitive Transportation) 7.3.2Fugitive emissions were calculated based on the length of pipeline and applying an IPCC default medium emission factor of 0.0014 kt CO2/km of pipeline length per year.



Offset Project Plan

Compressor start gas vent (P12b Venting During the 7.3.3Compressor Start-ups)

The amount of gas required to start the compressors has been estimated based on the number of compressors in service, start gas rate, duration, and frequency of starts, as provided by the Assistant Foreman. The number of starts is based on the number of oil changes and maintenance periods for each compressor. The methane composition of the start gas was calculated based on the annual fuel gas composition. K-810 is a lean-burn compressor. Compressor start gas emissions are calculated as follows:

START GAS VOLUME = STARTER FLOWRATE * NUMBER OF STARTS PER YEAR * START DURATION

EMISSIONS = VENT VOLUME * CH4 CONTENT (MOL FRACTION) OF THE FUEL GAS

CO2 Injected into the Reservoir (P14 Injection Unit 7.4Operation)

At the Hays gas plant, stripped formation CO2 is sent to injection wells off site to be used for EOR. The stripped CO2 gas comprises of the three streams (solution flash gas, Flexsorb CO2 and tail gas CO2) for which composition and flow data are not accurately known. In contrast, the volume of the CO2 rich stream injected is continuously measured with a custody transfer quality meter and monthly composition data are collected. This results in a high quality quantification of the avoided GHG emissions.

In the event that it is not possible to transfer the Flexsorb contactor off-gas offsite (e.g., if the CO2 injection compressor is not operating, or there were problems with the injection well), then the Flexsorb contactor off-gas stream would be directed to the incinerator/flare, with volumes metered through meter FE 3230. To further clarify, normal upset flow would be to the incinerator. If the incinerator is off line then it would go to the flare. Note, the Flexsorb contactor off-gas volumes dropped off significantly after September 2004 due to the commencement of CO2 injection for EOR. As a result of CO2 injection, less fuel gas was needed in the incinerator to meet the stack top temperature requirements.

As per Section 5.3 of AEP’s “Technical Guidance for Completing Specified Gas Compliance Reports, Version 6.0” (February 2013), the Hays plant began reporting CO2 volumes that were captured on-site and transferred off-site, ie injected, in the “Formation CO2” category, effective for the 2012 compliance year and onwards.



Offset Project Plan

The volumes of the streams are metered as follows:

Table 3 Meter Id's and associated Production Management System Tags

Meter ID Description Production Management System Tag

FE 3228 Solution amine flash drum off gas Sol Flash Incin or Flash Gas CO2 (sweet)

FE 3750 Flexsorb Contactor gas to the incinerator

Flex Cont Incin or Flexsorb CO2

FE 3230 proxy for FQI 955, sulphur Plant Tail Gas

Tail Gas CO2 or S2 tail gas Or Flex Reflx – SP (Sour)

FIT 8321 CO2 gas, to off-site injection CO2 Dehy Off Contactor

Sampling Procedures and Frequency 7.4.1The CO2 dehy off-gas stream is sampled and analyzed numerous times per year by Maxxam Analytics (measured data) since this is the injected CO2. The gas compositions are posted on the lab’s website and available to CNRL electronically. The lab report is available for viewing on the website, or as an export to Excel with the breakdown of the hydrocarbons. The sampling point for the CO2 dehy off-gas stream is between the 3rd and 4th stages of the CO2 compressor. The sampling points for the Sulphur Recovery Units, used as a back-up analysis, are:

SOLUTION AMINE FLASH OFF GAS just after meter FE-3228

FLEXSORB CONTACTOR OFF GAS just after meter FE-3750

FLEXSORB REFLUX ACCUM. OFF GAS just after meter FE-3230

Activity Data 7.4.2The Solution flash gas volume and vented CO2 raw gas volumes that did not enter the injection stream are obtained from the daily meter readings, provided by the Assistant Foreman. However, the volume of gas sent to the injection well is obtained from the daily meter reading for FIT 8321, and entered into accounting system by personnel at the Hays plant.

Emission Calculations, Equations, Emission Factors 7.4.3The CO2 gas that is captured and transferred offsite for use in EOR, was calculated as the stream volume flown through meter FIT 8321 multiplied by the mol fraction of CO2 in the stream, and then converted to a mass basis. A sample calculation for the determination of the emission factor for the Formation CO2 (captured and transferred offsite) follows.

EFCO2 = MOLE FRACTION CO2 * MOLAR MASS OF CARBON DIOXIDE / VOLUME OF GAS1

= MOLE FRACTION CO2 *44.01/23.64

The resulting emission factor was used in the emission equations below.

1 The calculation refers to the volume (in m3) occupied by 1 kmole of gas at 15ºC and 101.325 kPa.



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EMISSIONS = VOLUME SENT TO INJECTION WELL (E3M3) X EMISSION FACTOR

Re-processed CO2 in the Solution Gas (P19 Recycled 7.5Injection Gas)

The quantity of CO2 re-produced from the Enchant Arcs pool after CO2 injection commences must be calculated to ensure that injected CO2 is only accounted for the first time it is injected. The CO2 recycle calculation is based on the amount of CO2 produced by the wells in the two pools that have had CO2 injection that is above the natural CO2 levels. For each well, a baseline CO2 in the gas analysis prior to any CO2 injection has been determined and it ranges from 20-25% of the gas.

In addition, gas coming back to the surface has been sampled on a regular basis since CO2 injection has started. From these a fraction of CO2 in the gas at a point in time to the baseline amount can be compared. If the gas analysis shows the same or lower than baseline CO2 concentration it is assumed to be natural CO2 in the formation to be flowing back. Anything above the baseline amount is assumed to be produced back from the CO2 injection. For each month of gas production, the most recent gas analysis relative to that month is used for the calculations. If there are more than one gas analysis in that month, then the average is used. The quantity of produced CO2 is calculated using the following equation:

MONTHLY GAS PRODUCTION * (MONTHLY – BASELINE MOLE FRACTION CO2) = CO2 RECYCLED

The CO2 recycled is calculated for an individual well, and then all of the CO2 Recycled volumes are added up for a total CO2 Recycled volume.



Offset Project Plan

8. Monitoring Plan Calibration and Proving 8.1

Table 4, Meter Calibration Tags and Dates, below for calibration schedules of meters used at the facility. Meters are calibrated per the manufacturer’s specifications. All meters are accurate to +/- 10%. Meters are checked for issues at the time of calibration. As well, operators perform routine meter checks on a weekly basis at a minimum.

Table 4 Meter Calibration Tags and Dates

Meter # Description Meter Calibration Frequency

Meter Type

FE-2110 Grand Forks Fuel Gas Semi-annual Rosemount FE-3225 Non-associated sour inlet Semi-annual Rosemount FE-3228 Solution Amine flash drum off gas Semi-annual Rosemount FE-3750 Flexsorb Contactor gas to the incinerator Semi-annual Rosemount FE-3230 Gas off flexsorb reflux accumulator to sulfur plant Semi-annual Rosemount FE-3232 Fuel gas Semi-annual Rosemount FIT-8321 CO2 dehy off gas stream Annual Micro Motion Table 5 Monitoring Plan for CO2 Injected into the Reservoir Source/Sink Identifier and Name

CO2 Injected Into The Reservoir (Negative Quantity) (P14 Injection Unit Operation)

Data parameter Volume of CO2 gas injected Estimation, modeling, measurement or calculation approaches

Monitored Gas analysis

Data unit m3 mole fractions

Sources/Origin Direct metering of gas injected. Converted to STP conditions.

Direct gas sampling by a third party

Monitoring frequency Continuous Monthly

Description and justification of monitoring method

This is the most accurate method of measuring this parameter assuming that staff are correctly trained and equipment is correctly maintained.


Uncertainty +/- 10% N/A Provide the details for any deviations from protocol(s) including the justification and rationale.

N/A N/A



Offset Project Plan

Table 6 Monitoring Plan for Fugitive Emissions from Additional Equipment

Source/sink Identifier and Name Fugitive Emissions from Additional Equipment (P17 Fugitive at Injection Site+ P13 Fugitive Transportation)

Data parameter Volume of CO2 gas released to the air Estimation, modeling, measurement or calculation approaches

Estimated using component count and emission factors Gas analysis


Sources/Origin Published Emission Factors and Component Counts (Site Specific and Industry Averages)


Monitoring frequency N/A Monthly


This is the most practical method for determining this parameter as


Uncertainty N/A N/A Provide the details for any deviations from protocol(s) including the justification and rationale.

N/A N/A

Table 7 Monitoring Plan for Re-processed CO2 in the Solution Gas

Source/sink Identifier and Name Re-processed CO2 in the Solution Gas (P19 Recycled Injection Gas)

Data parameter Volume of recycled CO2 gas Estimation, modeling, measurement or calculation approaches

Monthly production is monitored Gas analysis of the produced gas


Sources/Origin Direct metering of gas injected. Converted to STP conditions.







N/A N/A



Offset Project Plan

Table 8 Incremental Solution Gas Compression

Source/sink Identifier and Name Incremental Solution Gas Compression (P12 Transportation Emissions)

Data parameter Volume of CO2 gas produced by burning fuel Estimation, modeling, measurement or calculation approaches

Metered volume of fuel consumed Gas analysis


Sources/Origin Direct metering of gas consumed. Converted to STP conditions.




This is the most accurate method of measuring this parameter assuming that staff are correctly trained and equipment is correctly maintained



N/A N/A

Averaging 8.2The following calculations use yearly averaging:

› Fuel gas analysis used for the reciprocating engine for CO2 emission factor; › Fuel gas analysis used for the heater and incinerator for CO2 emission factor; › Fuel gas analysis used for the flare CO2 and CH4 emission factors; › Fuel gas analysis used for the CH4 vent emissions from the compressor starts and the

condensate tank blanket; and › Solution amine flash off gas hydrocarbon emission factors are average to calculate the CO2

emission factor from incinerating the solution amine flash off gas.



Offset Project Plan

9. Data Management System and Records This protocol describes the GHG emission sources and sinks associated with the Hays EOR CO2 injection project. The general approach is to ensure that the emission estimates are as accurate as possible without being unduly complex to implement. In general, the presented methods will yield a conservative estimate of net GHG emission reductions. That is, baseline values will tend towards lower emission levels and estimated incremental GHG emission increases will tend to be higher, as per SGER the true up rule.

The critical element in assessing the net GHG emissions is an accurate measurement of CO2 injected. The mass flow of CO2 is continuously measured at the plant and a meter is installed at the injection point as a means of confirming the total flow of CO2 injected. Another important factor in determining net CO2 injected, is accounting for CO2 re-produced from the reservoir. Since the produced solution gas currently contains 15 to 20 percent CO2, (compared to the baseline amount of 10-20% before EOR commenced) simply assuming all CO2 contained in the solution gas comes from injected CO2 would grossly underestimate the net GHG emission reduction. Instead, the CO2 concentration prior to commencing CO2 injection is used as the baseline case. The produced solution gas flow and CO2 concentration is tracked monthly. Furthermore, tracking these data allows detection of the point when re-production of injected CO2 first occurs.

Data records available to support quantification calculations are: calibration records, production records, gas analysis and gas volumes, pipeline lengths, equipment information such as compressor starts and power, and various approvals.

Data Flow 9.1Accounting data flows through the system as follows (note that the data system transitioned from the Production Volume Reporting (PVR) system to the Energy Components (EC) system in February 2014 and from the EC system to the Production Volume Reporting (PVR5) system in March 2016):

› Production data for the Hays Gas Plant is saved in the Production Tracking software system. It is entered by the operators at the plant.

› The Property accountant takes the plant production data from the Production Tracking software’s Plant Monthly Report and inputs the data into the Prism/PAS production accounting system. (Note that production accounting system converted from PRISM to PAS in the April 2015 production month, so both systems are referenced here).

› Data is then uploaded from Prism/PAS into the Petroleum Registry to fulfill the production accounting reporting requirements.

This accounting method was audited by the AER in 2008 which included reviewing all the metering. Also, CNRL provides an annual progress report to the AER. The flow of production data is shown in Figure 3, below.



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Figure 3 Production Data Flow

Quality Assurance / Quality Control Procedures 9.2QA/QC procedures involved in the calculations and Production Accounting data include the following:

› Production accounting data obtained from the Petroleum Registry, or from internal sources, is subject to the quality requirements of EUB Directive 7 (Production Accounting Handbook)

› Laboratory data (e.g., gas analysis) are generated by accredited labs and is subject to the QA/QC requirements of the lab.

› Internal calculations are checked for computational and other errors as part of the development of the baseline.

› The operator entering data at the plant, into EC, can correct keying errors within the current month because they are responsible for the integrity of the data. At the end of each period, as part of the month end process, the EC data is locked. Changes to a locked period in EC require involvement of the Property Accountant and sign off by a supervisor.

› A similar process to the above occurs for natural gas sales; however some variation is allowed. The Registry will allow a 5% – 20% discrepancy to be entered. If this situation arises CNRL prepares internal documents which explain the reason for the discrepancy and indicate that the value recorded in the Registry is correct. The difference between the Sales Gas receiver and CNRL is entered in the Registry as an imbalance and coded as “IMBAL”.

Monthly Shipping Statements submitted from service providers to Property Accountant on sales gas, sulphur and natural gas liquids

Monthly data submitted from plant’s Production Tracking software to Property Accountant

Property Accountant compares Monthly service provider Shipping Statements to plant estimates in Production Tracking software

Property Accountant enters data into Petroleum Registry and explains any imbalances in an internal document to Management

Data Requested from Production Accounting / Plant Assistant Foreman

Data received from Production Accounting / Plant Assistant Foreman

Data used in GHG Calculations



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› If there is greater than a 10% discrepancy between the purchased gas sales meter and the

CNRL meters, then the Production accountant contacts the plant assistant foreman to reconcile it. Periodically, the meter calibration company reviews its meters and provides calibration reports. No discrepancies >10% were experienced from 2012 to 2016.

› As with all data entry there are internal checks that occur to ensure that no mistyped values are entered and that numbers entered are accurate. Shipping statements are compared to estimates and production tracking software as well as truck tickets. The Monthly Plant Balance spreadsheet is updated and reviewed every month. Once the Production Accountant is sure that the values are correct she enters the information in the Registry where it undergoes the check outlined in the two previous bullets.

Data Retention Procedures 9.3Data is retained indefinitely in the DCS. Data is backed up nightly and retained by the Information Systems Department (IS). Data will be and is retained for at least 7 years in EC after the end of the project credit duration period. It is backed up nightly and stored by IS. Spreadsheets are retained indefinitely on the CNRL network. They are backed up nightly and stored by IS. The responsibility for records retention and records management processes is shared by the software administrators of the various applications and IS.

Version Control 9.4When the vendor provides updates to EC, these are implemented in a test environment before being implemented as a live product. Hard copies of reports are controlled by storage in steel filing cabinets at the plant office. Supervisors are responsible to check the hard copy reports and sign off monthly. Electronic production reports are sent monthly to the Production Accountants and are stored on the network. They are backed up nightly by IS, as above. Other electronic reports gathered from the Field (e.g. equipment counts) are received by the Greenhouse Gas Advisor, stored on the network, and backed up by IS. The Registry data is stored on the Registry’s website. Schematic diagrams are updated when facility changes are made. These are stored at the plant office as well as in AutoCAD on the Calgary computer network.

Equipment and information Management Systems 9.5The 'Estimating Missing Data' procedure was not used in from 2012 to 2016 because there were sufficient fuel samples available (two samples per year). The average annual CO2 concentration in the captured CO2 was based on averaging the number of monthly samples available for the given calendar year. This ranged from three monthly samples (in 2013) to twelve monthly samples (in 2016). No data filling was done – CNRL would simply average the available analyses. For the metered volumes (fuel gas and captured CO2), no daily data points were missing from the metered data.

EC is a third party application. The vendor manages the modifications. CNRL does not modify the software programming code.



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10. Project Developer Signature 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 plan 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(s) 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.

The project developer has executed this offset project plan as of the 4th day of August, 2017.

Project Title: Hays Gas Plant Enhanced Oil Recovery Project

Signature:

Date:

August 4, 2017

Name: Andrew Higgins

Title: Supervisor Environmental Operations



Attachment 1

Permission to use the Quantification Protocol for Enhanced Oil Recovery

Attachment 2

The Approval No. 10523H Arcs F&G

MADE at the City of Calgary, in the Province of Alberta, on

ALBERTA ENERGY REGULATOR

(1) Proceeding No. 1826241 Approval No. 10523H Page 1 of 4

ENHANCED OIL RECOVERY Approval No. 10523H

The Alberta Energy Regulator (AER) pursuant to the Oil and Gas Conservation Act, chapter O-6

of the Revised Statutes of Alberta, 2000, orders as follows:

1) The scheme of Canadian Natural Resources Limited for enhanced recovery of oil by miscible

displacement using carbon dioxide and water injection in that part of the Enchant Arcs F

Pool and Arcs G Pool outlined in Appendix A of the approval, that is part of the Enchant

Commingled Pool 005, as described in

a) Application No. 911326,

b) Application No. 930036,

c) Application No. 1006351,

d) Proceeding No. 1067938,

e) Application No. 1437175,

f) Application No. 1502866,

g) Proceeding No. 1510354,

h) Application No. 1524759,

i) Proceeding No. 1621347,

j) Application No. 1710000,

k) Application No. 1783324,

l) Proceeding No. 1821430,

m) Proceeding No. 1826241,

is approved, subject to the terms and conditions herein contained.

2) For the purpose of this approval “miscible fluid” means a mixture of carbon dioxide, nitrogen,

hydrogen sulphide and hydrocarbons, with the carbon dioxide component being not less than

98 mole per cent.

3) Miscible fluid and water may be injected into the subject pool through the well(s) with the

following unique identifier(s):

Previously approved injection wells:

Class II

00/07-27-014-16W4/2 {15 030}

02/13-22-014-16W4/0 {15 030}

00/16-22-014-16W4/0 {15 030}

Class II & III

00/14-22-014-16W4/01 {15 030} [17 176]

The class of injection fluid is described in Directive 051.

31st day of March 2015.

Approval No. 10523H Page 2 of 4

Bracketed value denotes the maximum wellhead injection pressure {kilopascals gauge} for

the specified well(s) for {water injection} & [miscible fluid].

4) The injection of water may commence in the well(s) referred to in clause 2 once the AER has

confirmed in writing that Directive 051 requirements have been met.

5) The miscible fluid volume to be injected shall not be less than 45 percent of the hydrocarbon

pore volume on a pattern basis at the end of the project life.

6) Volumes of miscible fluid and water may be injected at the 00/14-22-014-16W4/0 well

a) in slugs alternating at least every 1000 days at a water to miscible fluid ratio not to

exceed 3.0 at reservoir conditions, for any injection cycle.

7) Upon commencement of miscible fluid and water injection,

a) production shall not be taken from any well in that part of the subject pool outlined in

Appendix A wherein the reservoir pressure is less than 10 500 kilopascals (gauge),

corrected to the mid-point of perforations or the mid-point of the open hole completion of

the well, unless the AER, upon application, permits otherwise. Furthermore, if a pressure

test is conducted and is found to be below the minimum operating pressure (MOP), the

wellbore shall remain shut-in; however, the other wells in the pattern may produce for a

further two-month period. If the pressure at the tested location is not restored above the

MOP within this two-month period, the remaining wells in the pattern shall be shut-in

and all wells will remain shut-in until the pressure is restored above the MOP, and

b) the average reservoir pressure must not exceed 16 000 kPa (gauge) at any time.

8) Upon commencement of miscible fluid injection into the subject pools, the approval holder

shall implement a program of sampling and analysis in accordance with the following rules:

a) The composition of the injected miscible fluid shall be determined annually.

b) The approval holder shall monitor each well’s producing gas-oil ratio to determine when

miscible fluid breakthrough occurs.

c) The approval holder shall implement the appropriate corrosion protection.

9) The approval holder shall submit and present annual progress reports to the AER Resource

Compliance Group in the Environment and Operations Branch on an annual basis,

commencing January 1, 2015. These reports shall include the following information, in

metric units:

a) A discussion of the overall performance of the scheme, including the incremental oil

recovery, the volume of incremental oil produced as a result of chase gas, solvent and

water injection.

b) The volume of hydrocarbon solvent recovered due to miscible fluid injection, and when

breakthrough has occurred, the volume of injected miscible fluid remaining in the


reservoir, at reservoir and surface conditions, based on the difference between the volume

of miscible fluid injected and the volume produced back to surface.

c) A discussion on the changes in the performance of the scheme including, but not limited

to, identification of problems, remedial action taken, and results of remedial action on

scheme performance during the reporting period.

d) The results and evaluation of all monitoring done during the reporting period including

but not limited to: pressure surveys, corrosion protection, fluid analyses, logs and any

measurements, observations, tests, or laboratory investigations which are pertinent to the

interpretation of the scheme operations.

e) Verification that all conditions of this approval had been met during the reporting period;

all non-compliance events should be summarized and should be voluntarily self-disclosed

as soon as they occur to the AER Resource Compliance Group in the Environment and

Operations Branch in accordance with Section 6 of Directive 019: Compliance Assurance.

f) A table(s) showing the following injection data for each month of the reporting period:

i) volume of chase gas, solvent and water injected at standard conditions;

ii) cumulative volume of chase gas, solvent and water injected at standard conditions;

iii) representative mole fraction of hydrogen sulphide and carbon dioxide in the injected

solvent;

iv) representative formation volume factors of the injected chase gas and solvent;

v) maximum daily injection rate at standard conditions;

vi) average daily injection rate at standard conditions; and

vii) maximum wellhead injection pressure.

g) A table(s) showing the following production data for each month of the reporting period:

i) volume of gas, oil, and water produced at each producing well at standard

conditions; and

ii) representative mole fraction of hydrogen sulphide and carbon dioxide at each

producing well.

10) The approval holder shall conduct operations in such a way that there is no significant

atmospheric, land, ground or surface water pollution.

11) Approval No. 10523H rescinds Approval No. 10523G.

END OF DOCUMENT


ENCHANT ARCS F POOL AND ARCS G POOL

APPENDIX A TO APPROVAL NO. 10523H

Added

Deleted

Area(s) of Change

Attachment 3

The Approval No. 9839E Arcs A&B

MADE at the City of Calgary, in the Province of Alberta, on

ALBERTA ENERGY REGULATOR

(1) Proceeding No. 1811361 Approval No. 9839E Page 1 of 4

ENHANCED OIL RECOVERY Approval No. 9839E

The Alberta Energy Regulator (AER) pursuant to the Oil and Gas Conservation Act, chapter O-6

of the Revised Statutes of Alberta, 2000, orders as follows:

1) The scheme of Canadian Natural Resources Limited for enhanced recovery of oil by miscible

displacement using carbon dioxide and water injection in that part of the Enchant Arcs A

Pool and Arcs B Pool as outlined in Appendix A of the approval, that is part of the Enchant

Commingled Pool 017, as described in

a) Application No. 920955,

b) Proceeding No. 1067938,

c) Application No. 1325799,

d) Application No. 1515641,

e) Application No. 1599923,

f) Application No. 1614986,

g) Application No. 1783323,

h) Proceeding No. 1811361,

is approved, subject to the terms and conditions herein contained.

2) For the purposes of this approval “miscible fluid” means a mixture of carbon dioxide,

nitrogen, hydrogen sulphide and hydrocarbons, with the carbon dioxide component being not

less than 98 mole per cent.

3) Class II water and Class III miscible fluid, as identified in Directive 051, may be injected in

the subject pools through the wells with the following unique identifiers:

Previously approved injection wells:

00/10-22-013-15W4/01 {14 300/15 600}

02/10-22-013-15W4/01 {10 800/12 226}

The class of injection fluid is described in Directive 051.

Bracketed values denote the maximum wellhead injection pressure for water and CO2

respectively in {kilopascals gauge} for the specified well.

4) (1) The miscible fluid volume to be injected shall not be less than 45 percent of the

hydrocarbon pore volume at the end of the project life.

(2) The average reservoir pressure must not exceed 16 000 kPa (gauge) at any time.

5) Volumes of miscible fluid and water may be injected in slugs alternating at least every 1000

days at water to miscible fluid ratio at reservoir conditions not to exceed 3.0 for any injection

cycle.

23rd day of October 2014.

Approval No. 9839E Page 2 of 4

6) Upon commencement of miscible fluid injection in accordance with clause 4, production

shall not be taken from any well in the scheme wherein the reservoir pressure is less than

11 100 kilopascals (gauge), corrected to the mid-point of perforations or the mid-point of the

open hole completion of the well.

7) The approval holder shall submit and present annual progress reports to the AER

Enforcement and Surveillance Section on an annual basis, commencing January 1, 2015.

These reports shall include the following information, in metric units:

a) A discussion of the overall performance of the scheme, including the incremental oil

recovery, the volume of incremental oil produced as a result of chase gas, solvents and

water injection.

b) The volume of hydrocarbon solvents recovered due to miscible fluid injection, and when

breakthrough has occurred, the volume of injected miscible fluid remaining in the

reservoir, at reservoir and surface conditions, based on the difference between the volume

of miscible fluid injected and the volume produced back to surface.

c) A discussion on the changes in the performance of the scheme including, but not limited

to, identification of problems, remedial action taken, and results of remedial action on

scheme performance during the reporting period.

d) The results and evaluation of all monitoring done during the reporting period including

but not limited to: pressure surveys, corrosion protection, fluid analyses, logs and any

measurements, observations, tests, or laboratory investigations which are pertinent to the

interpretation of the scheme operations.

e) Verification that all conditions of this approval had been met during the reporting period;

all non-compliance events should be summarized and should be voluntarily self-disclosed

as soon as they occur to the Enforcement and Surveillance Section of the AER Resources

Applications Group in accordance with Section 6 of Directive 019: Compliance

Assurance.

f) A table(s) showing the following injection data for each month of the reporting period

i) volume of chase gas, solvents and water injected at standard conditions,

ii) cumulative volume of chase gas, solvents and water injected at standard conditions,

iii) representative mole fraction of hydrogen sulphide and carbon dioxide in the

injected solvents

iv) representative formation volume factors of the injected chase gas and solvents

v) maximum daily injection rate at standard conditions,

vi) average daily injection rate at standard conditions, and

vii) maximum wellhead injection pressure.

g) A table(s) showing the following production data for each month of the reporting period

i) volume of gas, oil, and water produced at each producing well at standard

conditions, and

ii) representative mole fraction of hydrogen sulphide and carbon dioxide at each

producing well.


8) Approval No. 9839E rescinds Approval No. 9839D.

END OF DOCUMENT


ENCHANT ARCS A POOL AND ARCS B POOL APPENDIX A TO APPROVAL NO. 9839E

Added

Deleted

Area(s) of Change

Attachment 4

Deviation from the EOR Protocol

1. Deviation from the EOR Protocol We are preparing a project plant for a facility that has several sources reporting under the SGER as well as being counted as an offset project emissions. Under SGER, large final emitter facilities only need to account for the reduction target (T) in their compliance reporting, thus the offset project would need any emission reported by the SGER facility to be backed out.

Specifically, the CO2 compressor emissions will deviate from the protocol, as detailed below. The CO2 compressor (Waukesha L5774LT, 1250 hp) is a gas-driven compressor and its emissions are included in the SGER reporting, thus for the offset calculation purposes only 1-T multiplier has been used for the estimation of the compressors emissions as described below.

1.1 Calculations CO2 compressor combustion emissions were calculated by the following equation:

Fuel used by CO2 Compressor = Fuel Used (MMBtu) * 1.055056/HHV (MJ/m3)

CO2 Compressor Emissions = Fuel used by CO2 Compressor x Emission Factor

Total CO2 Compressor Emissions = CO2 Emissions + CH4 Emissions + N2O Emissions

SGER CO2 Compressor Emissions = Total CO2 Compressor Emissions * T

Offset CO2 Compressor Emissions = Total CO2 Compressor Emissions * (1-T)

T = 12% for 2015 and pre-2015, 15% for 2016 and 20% for 2017

Attachment 5

Quantification Protocol for Enhanced Oil Recovery

EOR Protocol

SPECIFIED GAS EMITTERS REGULATION

Page i

QQUUAANNTTIIFFIICCAATTIIOONN PPRROOTTOOCCOOLL FFOORR EENNHHAANNCCEEDD OOIILL RREECCOOVVEERRYY

OCTOBER 2007 Version 1

EOR Protocol

Disclaimer: The information provided in this document is intended as guidance only and is subject to revisions as learnings and new information comes forward as part of a commitment to continuous improvement. This document is not a substitute for the law. Please consult the Specified Gas Emitters Regulation and the legislation for all purposes of interpreting and applying the law. In the event that there is a difference between this document and the Specified Gas Emitters Regulation or legislation, the Specified Gas Emitters Regulation or the legislation prevail. Acknowledgements: This protocol is largely based on the CO2-EOR Offset Quantification Protocol dated September, 2006. This document was prepared by EnergyINet Inc. and the Alberta Research Council Inc. for submission to Alberta Environment. This document represents an abridged, re-formatted and amended version of the referenced work. Therefore, the seed document remains as a source of additional detail on any of the technical elements of the protocol. Note To Enhanced Oil Recovery Project Developers: There are two protocols covering enhanced oil recovery projects. This document represents the full scope protocol document. A streamlined version is also available for projects which meet the limited scope described therein. Any comments, questions, or suggestions regarding the content of this document may be directed to:

Environmental Assurance Alberta Environment 10th Floor, Oxbridge Place 9820 - 106th Street Edmonton, Alberta, T5K 2J6E-mail: [email protected]

ISBN: 978-0-7785-7230-5 (Printed) ISBN: 978-0-7785-7231-2 (On-line) Copyright in this publication, regardless of format, belongs to Her Majesty the Queen in right of the Province of Alberta. Reproduction of this publication, in whole or in part, regardless of purpose, requires the prior written permission of Alberta Environment.

© Her Majesty the Queen in right of the Province of Alberta, 2007

Page ii

EOR Protocol

Table of Contents 1.0 Project and Methodology Scope and Description...................................................... 1

1.1 Protocol Scope and Description............................................................................. 1 1.2 Glossary of New Terms ......................................................................................... 5

2.0 Quantification Development and Justification ...................................................... 6

2.1 Identification of Sources and Sinks (SS’s) for the Project .................................... 6 2.2 Identification of Baseline..................................................................................... 11 2.3 Identification of SS’s for the Baseline................................................................. 11 2.4 Selection of Relevant Project and Baseline SS’s................................................. 17 2.5 Quantification of Reductions, Removals and Reversals of Relevant SS’s.......... 22

2.5.1 Quantification Approaches .......................................................................... 22 2.5.2. Contingent Data Approaches ....................................................................... 36

2.6 Management of Data Quality............................................................................... 36 2.6.1 Record Keeping ........................................................................................... 36 2.6.2 Quality Assurance/Quality Control (QA/QC) ............................................. 36

List of Figures FIGURE 1.1 Process Flow Diagram for Project Condition 2 FIGURE 1.2 Process Flow Diagram for Baseline Condition 3 FIGURE 2.1 Project Element Life Cycle Chart 8 FIGURE 2.2 Baseline Element Life Cycle Chart 13

List of Tables TABLE 2.1 Project SS’s 9 TABLE 2.2 Baseline SS’s 14 TABLE 2.3 Comparison of SS’s 18 TABLE 2.4 Quantification Procedures 23 TABLE 2.5 Contingent Data Collection Procedures 37

Page iii

EOR Protocol

Page 1

1.0 Project and Methodology Scope and Description This quantification protocol is written for the EOR system operator or EOR project developer. Some familiarity with, or general understanding of, the operation of an oil production and EOR system is assumed. 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 (EOR) schemes. 1.1 Protocol Scope and Description This protocol quantifies emission reductions created by the capture, processing, transport, injection, recirculation and geological storage of waste gases from oil and gas production processes or other industrial processes. FIGURE 1.1 offers a process flow diagram for a typical project. Protocol Approach: This protocol applies to projects where the injected gases are from industrial sources and would otherwise have been emitted to atmosphere. Carbon dioxide produced as a by-product of natural gas or oil production that would otherwise have been vented to atmosphere may also be included. This protocol serves as a generic ‘recipe’ for project developers to follow in order to meet the measurement, monitoring and GHG quantification requirements. The baseline condition has been identified as the venting or flaring of the greenhouse gases contained within waste gas streams either at the capture point or as part of processing, and where applicable, the operation of the oil production system without injection and geological storage. The baseline condition could include an oil production system using water-flood for enhanced oil recovery. For illustration purposes, the process flow diagrams FIGURES 1.1 and 1.2 for the baseline and project condition include two types of source gases: • Source Type A - applicable to oil and gas production projects where solution gas

capture and processing, venting or flaring are part of the normal operating practice for the facility, and the EOR project has been implemented to utilize the CO2 portion of the captured solution gas. This source type is anticipated to apply to solution gas capture and processing in the oil and gas production industries.

EOR Protcol

FIGURE 1.1: Process Flow Diagram for Project Condition

P20 Electricity Usage

P23 Development

of Site

P26 Construction on

Site

P28 Site Decommissioning

P24 Building Equipment

P27 Testing of Equipment

P25 Transportation of

Equipment

P14 Injection Unit Operation

P1b Source Type B Gas Capture

P7b Source Type B Gas Processing

P4b Fugitive Emissions at Capture Site

P5b Source Type B Gas

Transportation

P2b Flaring at Capture Site

P11b Saleable Component Transport

and Use

P3b Venting at Capture Site

P19 Recycled Injection Gas

P18 Fuel Production, Distribution and

Usage

P21 Fuel Extraction / Processing

P22 Fuel Delivery

P6b Fugitive Emissions in

Transportation

P10b Fugitive Emissions at

Processing Site

P8b Flaring at Processing Site

P9b Venting at Processing Site

P12 Injection Gas

Transportation

P13 Fugitive Emissions in

Transportation

P17 Fugitive Emissions at Injection Site

P15 Flaring at Injection Site

P16 Venting at Injection Site

P11a Saleable Component Transport

and Use

P5a Source Type A Gas

Transportation

P7a Source Type A Gas

Processing

P1a Source Type A Gas Capture

P4a Fugitive Emissions at Capture Site

P2a Flaring at Capture Site

P3a Venting at Capture Site

P6a Fugitive Emissions in

Transportation

P8a Flaring at Processing Site

P9a Venting at Processing Site

P10a Fugitive Emissions at

Processing Site

Page 2

EOR Protcol

Page 3

FIGURE 1.2: Process Flow Diagram for Baseline Condition

B12 Fuel Production, Distribution and

Usage

B13 Fuel Extraction / Processing

B14 Fuel Delivery

B16 Development

of Site

B17 Building Equipment

B18 Transportation of

Equipment

B19 Construction on

Site

B20 Testing of Equipment


B2a Flaring at Capture Site

B3a Venting at Capture Site

B4a Fugitive Emissions at Capture Site

B6 Fugitive Emissions in

Transportation

B8 Flaring at Processing Site

B9 Venting at Processing Site

B10 Fugitive Emissions at

Processing Site

B11 Saleable Component Transport

and Use

B2b Flaring at Capture Site

B3b Venting at Capture Site

B4b Fugitive Emissions at Capture Site

B1b Source Type B Gas Capture

B15 Electricity Usage

B7 Source Type A Gas

Processing


Transportation

B1a Source Type A Gas Capture

EOR Protocol

• Source Type B - applicable to projects where gas capture and processing are not normally undertaken (and thus are not described in the baseline process flow diagram), but are added to the system in order to utilize waste gases for EOR. Source Type B is anticipated to apply to industrial processes outside of the fossil fuel production industry.

For Source Type B emissions, the capture point is defined at the site where capture systems would be implemented under the project condition, and processing downstream under a baseline condition would not exist as part of the normal site operations. FIGURE 1.2 offers a process flow diagram for a typical baseline configuration. For EOR projects that use more than one source of CO2, the project proponent must identify the type of each source and perform the applicable quantification calculations for each source. Protocol Applicability: To demonstrate that a project meets the requirements under this protocol, the project developer must provide evidence 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.

Protocol Flexibility: Flexibility in applying the quantification protocol is provided to project developers in three ways:

1. Not all parameters are applicable to all EOR systems. Those sources and sinks (SS’s) that are not applicable will be excluded as their input variables will be zeros.

Page 4

EOR Protocol

As such, the project developer can exclude sources and sinks that are not applicable to their project with reasonable justification; and

2. 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.

If applicable, the developer must indicate and justify why flexibility provisions have been used. 1.2 Glossary of New Terms Functional Equivalence The Project and the Baseline should provide the same

function and quality of products or services. This type of comparison requires a common metric or unit of measurement (such as the barrels of oil produced) for comparison between the Project and Baseline activity (refer to the Project Guidance Document for the Alberta Offset System)

Enhanced Oil Recovery: Oil recovery over and above what is obtained using

the natural pressure of the reservoir. For the purposes of this protocol, this is obtained through carbon dioxide and/or acid gas injection.

Capture Site: The point in the process where gas containing GHGs

that would otherwise be vented or flared is captured for eventual injection as part of an EOR project.

Leakage: Escape of the injected gas into adjacent wells or

underground formations. Migration: Lateral movement of the injected gas within the

reservoir. Seepage: Escape of the injected gas to the biosphere, including

non-saline water and atmospheric environment.

Page 5

EOR Protocol

Page 6

2.0 Quantification Development and Justification The following sections outline the quantification development and justification. 2.1 Identification of Sources and Sinks (SS’s) for the Project SS’s were identified for the project by reviewing the seed documents and relevant process flow diagram developed by the Alberta Research Council. This process confirmed that the SS’s in the process flow diagrams covered the full scope of eligible project activities under the protocol. Based on the process flow diagrams provided in FIGURE 1.1, the project SS’s were organized into life cycle categories in FIGURE 2.1. Descriptions of each of the SS’s and their classification as controlled, related or affected are provided in TABLE 2.1.

EOR Protocol

FIGURE 2.1: Project Element Life Cycle Chart

Upstream SS’s During Project

P1a/b Source Type A/B Gas

Capture

P4a/b Fugitive Emissions at Capture Site

P5a/b Source Type A/B Gas Transportation

P6a/b Fugitive Emissions in

Transportation

P7a/b Source Type A/B Gas

Processing

P2a/b Flaring at Capture Site

P3a/b Venting at Capture Site

P8a/b Flaring at Processing Site

P10a/b Fugitive Emissions at

Processing Site

P11a/b Saleable Component

Processing and Transport

P12 Injection Gas

Transportation

P13 Fugitive Emissions in

Transportation

P21 Fuel Extraction / Processing

P9a/b Venting at Processing Site

P20 Electricity Usage

P22 Fuel Delivery

Downstream SS’s Downstream SS’s On Site SS’s During Project Before Project After Project

P23 Development

of Site






P28 Site Decommissioning P25

Transportation of Equipment

P26 Construction on

Site


Downstream SS’s During Project

P18 Fuel Production and

Distribution


Page 7

EOR Protocol

TABLE 2.1: Project SS’s 3. Controlled, Related or Affected 1. SS 2. Description

Upstream SS’s during Project Operation P1a/b Source Gas Capture

Source Type A or 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. Related

Source Type A or 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.

P2a/b Flaring at Capture Site Related

P3a/b Venting at Capture Site

Source Type A or Source Type 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 vented would need to be tracked. Related

P4a/b Fugitive Emissions at Capture Site

Fugitive emissions may occur from equipment used to capture Source Type A or Source Type B gas. The quantity of fugitive emissions would need to be tracked. Related

Source Type A or 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.

P5a/b Source Type A and Source Type B Gas Transportation

Related

P6a/b Fugitive Emissions in Transportation

Fugitive emissions may occur from equipment and facilities used to transport Source Type A or Source Type B gas. The quantity of fugitive emissions would need to be tracked. Related

Source Type A or 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.

P7a/b Source Type A and Source Type B Gas Processing

Related

P8a/b Flaring at Processing Site

Source Type A or 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 flared would need to be tracked. Related

P9a/b Venting at Processing Site

Source Type A or Source Type B gas may be vented at the processing site as a result of emergency shut-down, maintenance or other operational conditions. The quantity of gas vented would need to be tracked. Related

P10a/b Fugitive Emissions at Processing Site

Fugitive emissions may occur from equipment used at the processing site. The quantity of fugitive emissions would need to be tracked. Related

P11a/b Saleable Component Processing and Transport

Saleable components of the Source Type A or Source Type B gas may require further processing and transportation to end users, resulting in emissions of greenhouse gases. The parameters characterizing the emissions would need to be tracked.

Related

Page 8

EOR Protocol

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.

P12 Injection Gas Transportation Related

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. Related

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. P20 Electricity Usage Related

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.

P21 Fuel Extraction and Processing Related

Each of the fuels used throughout the project may need to be transported to the site. This may include shipments by tanker or by pipeline, resulting in the emissions of greenhouse gases. It is reasonable to exclude fuel sourced by taking equipment to an existing commercial fuelling station as the fuel used to take the equipment to the sites is captured under other SS’s and there is no other delivery.

Related P22 Fuel Delivery

Onsite SS’s during Project 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.

P14 Injection Unit Operation Controlled

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.

P15 Flaring at Injection Site Controlled


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. Controlled


Fugitive emissions will occur from equipment used at the injection site. The quantity of fugitive emissions would need to be tracked. Related

Downstream SS’s during Project Operation 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. Related

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.

P19 Recycled Injection Gas Related

Page 9

EOR Protocol

Page 10

Other

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.

Related


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.

Related

P25 Transportation of Equipment

Equipment built off-site and the materials to build equipment on-site, 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.

Related

P26 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.

Related


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.

Related


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.

Related

EOR Protocol

2.2 Identification of Baseline The baseline condition for projects applying this protocol is defined as the operating condition prior to the start-up or expansion of the injection operation. The baseline is project-specific but would be anticipated to include the venting or flaring of the greenhouse gases contained within source gas streams either at the capture point or as part of processing, and where applicable, the operation of the oil production system without injection and geological storage, or using a water-flood enhanced recovery scheme. For Source Type B emissions, the capture point is defined at the site where capture systems would be implemented under the project condition. The approach to quantifying the baseline will be calculation based as there are suitable data available for the applicable baseline condition that can provide reasonable certainty. The volume of CO2 injected under the project condition is assumed to have been vented to atmosphere under the baseline condition. The baseline scenario for this protocol is dynamic as the volume of gas injected would be expected to change materially from project to project. The baseline condition is defined, including the relevant SS’s and processes, as shown in FIGURE 1.2. More detail on each of these SS’s is provided in Section 2.3, below. 2.3 Identification of SS’s for the Baseline Based on the process flow diagrams provided in FIGURE 1.2, the project SS’s were organized into life cycle categories in FIGURE 2.2. Descriptions of each of the SS’s and their classification as either ‘controlled’, ‘related’ or ‘affected’ is provided in TABLE 2.2.

Page 11

EOR Protocol

Page 12

EOR Protocol

FIGURE 2.2: Baseline Element Life Cycle Chart Upstream SS’s During Baseline

B1a/b Source Type A/B Gas

Capture

B4a/b Fugitive Emissions at Capture Site


Transportation

B6 Fugitive Emissions in

Transportation

B2a/b Flaring at Capture Site

B3a/b Venting at Capture Site


Processing

On Site SS’s During Baseline

Downstream SS’s During Baseline

Downstream SS’s Before Baseline

Downstream SS’s After Baseline

B11 Saleable Component

Processing and Transport

B10 Fugitive Emissions at

Processing Site

B8 Flaring at Processing Site


B12 Fuel Production and

Distribution

B13 Fuel Extraction / Processing

B14 Fuel Delivery

B16 Development

of Site

B17 Building Equipment

B18 Transportation of

Equipment

B19 Construction on

Site

B20 Testing of Equipment

B21 Site Decommissioning

B15 Electricity Usage

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EOR Protocol

TABLE 2.2: Baseline SS’s 3. Controlled, Related or Affected 1. SS 2. Description

Upstream SS’s during Baseline Operation Source Type A/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.

B1a/b Source Type A/B Gas Capture Related

B2a/b Flaring at Capture Site

From time to time Source Type A/B gas may be flared 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. Related

B3a/b Venting at Capture Site

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. Related

B4a/b Fugitive Emissions at Capture Site

Fugitive emissions may occur from equipment used to capture Source Type A gas or Source Type B gas. The quantity of fugitive emissions would need to be tracked. Related

Source Type A 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. 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.

B5 Source Type A Gas Transportation Related

B6 Fugitive Emissions In Transportation

Fugitive emissions may occur from equipment used to transport Source Type A gas. The quantity of fugitive emissions would need to be tracked. Related

Source Type A 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.

B7 Source Type A Gas Processing Related

B8a/b Flaring at Processing Site

Source Type A/B gas may be flared at the processing site as a result of emergency shut-down, maintenance or other operational condition. The quantity of gas flared would need to be tracked. Related


Processed gas may be vented at the processing site as a result of emergency shut-down, maintenance or other operational condition. The quantity of gas flared would need to be tracked. Related

B10 Fugitive Emissions at Processing Site

Fugitive emissions may occur from equipment used to process Source Type A gas. The quantity of fugitive emissions would need to be tracked. Related

B11a/b Saleable Component Processing and Transport

Saleable components of the Source Type A/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.

Related

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EOR Protocol

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.

B13 Fuel Extraction/ Processing Related

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. It is reasonable to exclude fuel sourced by taking equipment to an existing commercial fuelling station as the fuel used to take the equipment to the sites is captured under other SS’s and there is no other delivery.

Related B14 Fuel Delivery

Electricity may be required to power equipment throughout the capture and processing processes. The quantity of power consumed and the source of electricity would need to be tracked. Related B15 Electricity Usage

Downstream SS’s during Baseline Operation 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.

B12 Fuel Production and Distribution Related

Other 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.

B16 Development of Site Related

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.

B17 Building Equipment Related

Equipment built off-site and the materials to build equipment on-site, 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.

B18 Transportation of Equipment Related

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.

B19 Construction on Site Related

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.

B20 Testing of Equipment Related

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Related

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.

B21 Site Decommissioning

EOR

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Page 17

2.4 Selection of Relevant Project and Baseline SS’s Each of the SS’s from the project and baseline condition were compared and evaluated as to their relevancy using the guidance provided in Annex VI of the “Guide to Quantification Methodologies and Protocols: Draft”, dated March 2006 (Environment Canada). The justification for the exclusion or conditions upon which SS’s may be excluded is provided in TABLE 2.3 below. All other SS’s listed previously are included.

EOR Protocol

TABLE 2.3: Comparison of SS’s 4. Include or Exclude from Quantification

2. Baseline (C, R, A)

3. Project (C, R, A) 5. Justification for Exclusion 1. Identified SS

Upstream SS’s P1a Source Type A Gas Capture N/A Related Exclude

B1a Source Type A Gas Capture Related N/A Exclude

Excluded as these SS’s are functionally equivalent under the project and baseline conditions.

P1b Source Type B Gas Capture N/A Related Include N/A

B1b Source Type B Gas Capture Related N/A Include N/A

P2a Flaring at Capture Site N/A Related Exclude

B2a Flaring at Capture Site Related N/A Exclude


P2b Flaring at Capture Site N/A Related Include N/A

B2b Flaring at Capture Site Related N/A Include N/A

P3a Venting at Capture Site N/A Related Exclude

B3a Venting at Capture Site Related N/A Exclude


P3b Venting at Capture Site N/A Related Include N/A

B3b Venting at Capture Site Related N/A Include N/A

P4a/b Fugitive Emissions at Capture Site N/A Related Exclude

B4a/b Fugitive Emissions at Capture Site Related N/A Exclude

Excluded as the fugitive emissions are likely negligible in comparison to other emissions.

P5a Source Type A Gas Transportation N/A Related Exclude

B5 Source Type A Gas Transportation Related N/A Exclude


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EOR Protocol

P5b Source Type B Gas Transportation N/A Related Include N/A

P6a/b Fugitive Emissions In Transportation N/A Related Exclude

B6 Fugitive Emissions In Transportation Related N/A Exclude


P7a Source Type A Gas Processing N/A Related Exclude

B7 Source Type A Gas Processing Related N/A Exclude


P7b Source Type B Gas Processing N/A Related Include N/A

P8a/b Flaring at Processing Site N/A Related Exclude

B8 Flaring at Processing Site Related N/A Exclude

Excluded as these SS’s are not relevant to the project as the emissions from these practises are covered under proposed greenhouse gas regulations.

P9a/b Venting at Processing Site N/A Related Exclude

B9 Venting at Processing Site Related N/A Exclude

Excluded as these SS’s are not relevant to the project as the emissions from these practises are covered under proposed greenhouse gas regulations.

P10a/b Fugitive Emissions at Processing Site

N/A Related Exclude

B10 Fugitive Emissions at Processing Site Related N/A Exclude


P11a/b Saleable Component Transport and Use

N/A Related Exclude

B11 Saleable Component Transport and Use Related N/A Exclude

Excluded as these SS’s are functionally equivalent in the project and baseline conditions.

P12 Injection Gas Transportation N/A Related Include N/A

P13 Fugitive Emissions in Transportation N/A Related Exclude Excluded as the fugitive emissions are likely negligible in

comparison to other emissions. P20 Electricity Usage N/A Related Exclude Excluded as these SS’s are not relevant to the project as the

emissions from these practises are covered under proposed greenhouse gas regulations. B15 Electricity Usage N/A Related Exclude

P21 Fuel Extraction and Processing N/A Related Include N/A

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EOR Protocol

B13 Fuel Extraction and Processing Related N/A Include N/A

P22 Fuel Delivery N/A Related Exclude Excluded as the emissions from transportation are negligible and likely greater under the baseline condition. B14 Fuel Delivery Related N/A Exclude

Onsite SS’s P14 Injection Unit Operation N/A Controlled Include N/A

P15 Flaring at Injection Site N/A Controlled Include N/A

P16 Venting at Injection Site N/A Controlled Include N/A

P17 Fugitive Emissions at Injection Site N/A Related Exclude Excluded as the fugitive emissions are likely negligible in

comparison to other emissions. Downstream SS’s P18 Fuel Production and Distribution N/A Related Exclude

B12 Fuel Production and Distribution Related N/A Exclude


P19 Recycled Injection Gas N/A Related Include N/A

Other Emissions from site development are not material given the long project life, and the minimal site development typically required.

P23 Development of Site N/A Related Exclude

Emissions from site development are not material for the baseline condition given the minimal site development typically required.

B16 Development of Site Related N/A Exclude

Emissions from building equipment are not material given the long project life, and the minimal building equipment typically required.

P24 Building Equipment N/A Related Exclude

Emissions from building equipment are not material for the baseline condition given the minimal building equipment typically required.

B17 Building Equipment Related N/A Exclude

P25 Transportation of Equipment N/A Related Exclude

Emissions from transportation of equipment are not material given the long project life, and the minimal transportation of equipment typically required.

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Page 21

B18 Transportation of Equipment Related N/A Exclude

Emissions from transportation of equipment are not material for the baseline condition given the minimal transportation of equipment typically required.

P26 Construction on Site N/A Related Exclude Emissions from construction on site are not material given the long project life, and the minimal construction on site typically required.

B19 Construction on Site Related N/A Exclude Emissions from construction on site are not material for the baseline condition given the minimal construction on site typically required.

P27 Testing of Equipment N/A Related Exclude Emissions from testing of equipment are not material given the long project life, and the minimal testing of equipment typically required.

B20 Testing of Equipment Related N/A Exclude Emissions from testing of equipment are not material for the baseline condition given the minimal testing of equipment typically required.

P28 Site Decommissioning N/A Related Exclude

Emissions from decommissioning are not material given the long project life, and the minimal decommissioning typically required.

Exclude Emissions from decommissioning are not material for the baseline condition given the minimal decommissioning typically required.

Related N/A B21 Site Decommissioning

EOR

EOR Protocol

Page 22

Where:

2.5 Quantification of Reductions, Removals and Reversals of Relevant SS’s 2.5.1 Quantification Approaches Quantification of the reductions, removals and reversals of relevant SS’s for each of the greenhouse gases will be completed using the methodologies outlined in TABLE 2.4, below. A listing of relevant emission factors is provided in Appendix A. These calculation methodologies serve to complete the following three equations for calculating the emission reductions from the comparison of the baseline and project conditions.

Emissions Project = Emis Capture + Emissions Capture Flare + Em ransport + Emissions Process + Em + Emissions Inj Flare + E

Emissions Baseline = Emi Capture + Emissions Capture Flare + E

Emissions

Emissions Baseline = sum of the emissions under the baseline condition.

Emissions Fuel Extraction / Processing = emissions under SS B13 Fuel Extraction and Processing Emissions Capture = emissions under SS B1b Source Type B Gas Capture Emissions Capture Flare = emissions under SS B2b Flaring at Capture Site Emissions Capture Vent = emissions under SS B3b Venting at Capture Site

Project = sum of the emissions under the project condition. Emissions Fuel Extraction / Processing = emissions under SS P20 Fuel Extraction and Processing Emissions Capture = emissions under SS P1b Source Type B Gas Capture Emissions Capture Flare = emissions under SS P2b Flaring at Capture Site Emissions Capture Vent = emissions under SS P3b Venting at Capture Site Emissions PG Transport = emissions under SS P5b Source Type B

Transportation Emissions Process = emissions under SS P7b Source Type B Gas Processing Emissions Inj Transport = emissions under SS P12 Injection Gas Transportation Emissions Injection = emissions under SS P14 Injection System Operation Emissions Inj FlareEmissions

= emissions under SS P15 Flaring at Injection Site Inj Vent

Emissions

Emission Reduction = Emissions Baseline – Emissions Project

sions Fuel Extraction / Processing + Emissions issions Capture Vent + Emissions PG Tissions Inj Transport + Emissions Injection

missions Inj Vent + Emissions Recirculation

ssions Fuel Extraction / Processing + Emissions missions Capture Vent + Emissions PG Tr

Recirculation

= emissions under SS P16 Venting at Injection Site = emissions under SS P19 Recycled Injection Gas

ansport + Emissions Process

EOR Protocol

TABLE 2.4: Quantification Procedures 1.0 Project/ Baseline SS

2. Parameter / Variable

4. Measured / Estimated

7. Justify measurement or estimation and frequency 3. Unit 5. Method 6. Frequency

Project SS’s Emissions Capture = ∑ (Vol. Fuel i * EF Fuel ) ; ∑ (Vol. Fuel i CO2 i * EF Fuel ) ; ∑ (Vol. Fuel i CH4 i * EF Fuel ) i N2O

kg of CO2 ; CH4 ; N N/A N/A N/A Quantity being calculated. Emissions Capture

2O Both methods are standard practice. Frequency of metering is highest level possible. Frequency of reconciliation provides for reasonable diligence.

Direct metering or reconciliation of volume in storage (including volumes received).

Continuous metering or

monthly reconciliation.

Volume of Each Type of Fuel Used/ Vol. Fuel

L / m3 / other Measured i

Reference values adjusted annually as part of Environment Canada reporting on Canada's emissions inventory.

CO2 Emissions Factor for Each Type of Fuel / EF Fuel

From Environment Canada reference documents. i

CO2

kg CO2 per L / m3 / other Estimated Annual



CH4 Emissions Factor for Each Type of Fuel / EF Fuel


CH4

kg CH4 per L / m3 / other Estimated Annual


N20 Emissions Factor for Each Type of Fuel / EF Fuel


N2O

kg N2O per L / m3 / other Estimated Annual

Emissions Capture Flare = ∑ (Vol. Type B Gas Flared * % CO2 * ρ ) ; ∑ (Vol. CO2 Type B Gas Flared * % CH4 * EF Source Type B Gas ) ; CO2∑ (Vol. Source Type B Gas Flared * % CH4 * EF Source Type B Gas CH4) ; ∑ (Vol. Source Type B Gas Flared * % CH4 * EF Source Type B Gas N2O) ; ∑

(Vol. Fuel i *EF Fuel i CO2) ; ∑ (Vol. Fuel i *EF Fuel i CH4) ; ∑ (Vol. Fuel i * EF Fuel i N2O)

P2b Flaring at Capture Site

kg of CO2 ; CH4 ; N N/A N/A N/A Quantity being calculated. Emissions Capture Flare

2O Direct metering of volume of Source Type B gas being flared, converted to STP conditions.

Direct metering is standard practice. Frequency of metering is highest level possible.

Volume of Source Type B Gas Flared / Vol.

Continuous metering m3 Measured

Type B Gas Flared

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EOR Protocol

Composition may vary throughout the injection Source Type B. Quarterly gas composition measurement is reasonable for operation of an injection facility.

CO2 Composition in Source Type B Gas Stream (Volumetric Basis) / % CO2

% Measured Direct measurement.

Daily sampling averaged

monthly on a volumetric basis

Constant value of 1.98 kg/m³ at STP. Density of CO2/ ρ kg/m3 Estimated N/A Accepted value. CO2


Methane Composition in Source Type B Gas Stream (Volumetric Basis) / % CH4




CO2 Emissions Factor for Source Type B Gas Flared / EF Source Type B Gas


From Environment Canada reference documents.

CO2

kg CO2 per m3 Estimated Annual

CH4 Emissions Factor for Source Type B Gas Flared / EF Source Type B Gas



CH4

kg CH4 per m3 Estimated Annual

N20 Emissions Factor for Source Type B Gas Flared / EF Source Type B Gas



N2O

kg N2O per m3 Estimated Annual

Both methods are standard practice. Frequency of metering is highest level possible. Frequency of reconciliation provides for reasonable diligence.






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EOR Protocol




i CO2





i CH4





i N2O


Emissions Capture Vent = ∑ (Vol. Source Type B Gas Vented * % CO2 * ρCO2) ; ∑ (Vol. Source Type B Gas Vented * % CH4 * ρCH4)

Emissions Capture Vent kg of CO2 ; CH4 N/A N/A N/A Quantity being calculated.

P3b Venting at Capture Site

Direct metering of volume of Source Type B gas being vented, converted to STP conditions.


Volume of Source Type B Gas Vented / Vol.


Source Type B Gas

VentedComposition may vary throughout the injection Source Type B. Quarterly gas composition measurement is reasonable for operation of an injection facility.





Constant value of 1.98 kg/m³ at STP.

Density of CO2 / ρCO2

kg/m3 N/A Accepted value. Estimated


Methane Composition in Source Type B Gas Stream (Volumetric Basis) / % CH




4

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EOR Protocol

Constant value of 0.717 kg/mDensity of CH4/ ρ kg/m3 Estimated N/A Accepted value. 3CH4 at STP.

Emissions = ∑ (Vol. Fuel PG Transport i * EF Fuel ) ; ∑ (Vol. Fuel i CO2 i * EF Fuel ) ; ∑ (Vol. Fuel i CH4 i * EF Fuel ) i N2Okg of CO2 ; CH4 ;

N N/A N/A N/A Quantity being calculated. Emissions PG Transport2O







CO2 Emissions Factor for Each Type of Fuel / EF Fuel i CO2

kg CO2 per L / m3 / other Estimated


Annual


P5b Source Type B Gas Transportation




CH4





N2O


Emissions Process = ∑ (Vol. Fuel i * EF Fuel i CO2) ; ∑ (Vol. Fuel i * EF Fuel i CH4) ; ∑ (Vol. Fuel i * EF Fuel i N2O)

Emissions Processkg of CO2 ; CH4 ;

N2O N/A N/A N/A Quantity being calculated.








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EOR Protocol




CO2





CH4





N2O


Emissions Inj Transport = ∑ (Vol. Fuel i * EF Fuel i CO2) ; ∑ (Vol. Fuel i * EF Fuel i CH4) ; ∑ (Vol. Fuel i * EF Fuel i N2O)

Emissions Inj Transport kg of CO2 ; CH4 ;

N2O N/A N/A N/A

Quantity being calculated in aggregate form as fuel and electricity use on site is likely aggregated for each of these SS’s.

P12 Injection Gas Transportation










CO2





CH4


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EOR Protocol




N2O


Emissions Injection = ∑ (Vol. Fuel i * EF Fuel ) ; ∑ (Vol. Fuel i CO2 i * EF Fuel ) ; ∑ (Vol. Fuel i CH4 i * EF Fuel ) i N2O

Emissions Injection kg of CO2 ; CH4 ;

N2O N/A N/A N/A

Quantity being calculated in aggregate form as fuel and electricity use on site is likely aggregated for each of these SS’s. Both methods are standard practice. Frequency of metering is highest level possible. Frequency of reconciliation provides for reasonable diligence.










Annual





CH4





N2O


Emissions Inj Flare = ∑ (Vol. Injection Gas Flared * % CO2 * ρ ) ; ∑ (Vol. CO2 Injection Gas Flared * % CH4 * EF Injection Gas ) ; CO2∑ (Vol. Injection Gas Flared * % CH4 * EF Injection Gas CH4) ; ∑ (Vol. Injection Gas Flared * % CH4 * EF Injection Gas N2O) ;

∑ (Vol. Fuel i *EF Fuel i CO2) ; ∑ (Vol. Fuel i *EF Fuel i CH4) ; ∑ (Vol. Fuel i * EF Fuel i N2O)


kg of CO2 ; CH4 ; N N/A N/A N/A Quantity being calculated. Emissions Inj Flare

2O

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EOR Protocol

Direct metering of volume of injection gas being flared, converted to STP conditions.


Volume of Injection Gas Flared / Vol. Continuous

metering m3 Measured Injection Gas Flared

Composition may vary throughout the injection process. Quarterly gas composition measurement is reasonable for operation of an injection facility.

CO2 Composition in Injection Gas Stream (Volumetric Basis) / % CO2



monthly on a volumetric

basis

Constant value of 1.98 kg/m³ at STP. Density of CO2 / ρ kg/m3 Estimated N/A Accepted value. CO2


Methane Composition in Injection Gas Stream (Volumetric Basis) / % CH4




basis


CO2 Emissions Factor for Injection Gas Flared / EF Injection Gas


CO2



CH4 Emissions Factor for Injection Gas Flared / EF Injection Gas


CH4



N20 Emissions Factor for Injection Gas Flared / EF Injection Gas


N2O








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EOR Protocol




kg CO2 per L / m Estimated Annual 3 / other

i CO2




kg CH4 per L / m Estimated Annual 3 / other

i CH4




kg N2O per L / m Estimated Annual 3 / other

i N2O

Emissions Inj Vent = ∑ (Vol. Injection Gas Vented * % CO2 * ρ ) ; ∑ (Vol. CO2 Injection Gas Vented * % CH * ρ ) 4 CH4

Emissions kg of COInj Vent 2 ; CH4 N/A N/A N/A Quantity being calculated.

Direct metering of volume of injection gas being vented, converted to STP conditions.


Volume of Injection Gas Vented / Vol. Continuous

metering m3 Measured Injection Gas Vented







kg/m3 Estimated Constant value of 1.98 kg/m³ at STP. N/A Accepted value.



Methane Composition in Injection Gas Stream (Volumetric Basis) / % CH




4

Constant value of 0.717 kg/mDensity of CH4/ ρ kg/m3 Estimated N/A Accepted value. 3CH4 at STP.

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EOR Protocol

Emissions Recirculation = ∑ (Vol. Injected Gas Recycled * % CO2 * ρ ) CO

Emissions kg of CORecirculation 2 ; CH4 N/A N/A N/A Quantity being calculated. Direct metering of volume of injected gas produced at adjacent locations over the reporting period, converted to STP conditions. Volume should include only the gas that is not re-injected.


Volume of Injected Gas Produced at Adjacent Locations / Vol.


Injected Gas Recycled P19 Recycled Injection Gas

CO2 Composition in Injection Gas / % CO2




basis


Constant value of 1.98 kg/m³ at STP. Density of CO2 / ρ kg/m3 Estimated N/A Accepted value. CO2

Emissions Fuel Extraction / Processing = ∑ (Vol. Fuel i * EF Fuel i CO2) ; ∑ (Vol. Fuel i * EF Fuel i CH4) ; ∑ (Vol. Fuel I * EF Fuel i N2O)

Emissions Fuel Extraction /

Processingkg of CO2e N/A N/A N/A


P21 Fuel Extraction and Processing


Volume of Fossil Fuel Combusted for P1, P2, P5, P7, P8, P12, P14 and P15 / Vol. Fuel

Direct metering or reconciliation of volume

in storage (including volumes received).



L/ m3/ Other Measured


CO2 Emissions Factor for Fuel Including Production and Processing / EF Fuel

From Environment Canada reference

documents.

kg CO2 per L / m Estimated Annual 3 / other

CO2CH4 Emissions Factor for Fuel Including Production and Processing / EF Fuel



documents.

kg CH4 per L / m Estimated Annual 3 / other

CH4

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EOR Protocol

N20 Emissions Factor for Fuel Including Production and Processing / EF Fuel



documents.

kg N2O per L / m Estimated Annual 3 / other

N2OBaseline SS’s

Emissions Capture = ∑ (Vol. Fuel i * EF Fuel ) ; ∑ (Vol. Fuel i CO2 i * EF Fuel ) ; ∑ (Vol. Fuel i CH4 i * EF Fuel ) i N2O

kg of CO2 ; CH4 ; N N/A N/A N/A Quantity being calculated. Emissions Capture

2O











CH4 Emissions Factor for Each Type of Fuel / EF Fuel i CH4

kg CH4 per L / m3 / other Estimated


Annual


B1b Source Type B Gas Capture




N2O





CO2 Composition in Source Type A Gas / % CO

mole % Measured Direct measurement. 2

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EOR Protocol

Emissions Capture Flare = ∑ (Vol. Source Type B Gas Flared * % CO2 * ρ ) ; ∑ (Vol. CO2 Source Type B Gas Flared * % CH4 * EF Source Type B Gas ) ; CO2∑ (Vol. Source Type B Gas Flared * % CH4 * EF Source Type B Gas CH4) ; ∑ (Vol. Source Type B Gas Flared * % CH4 * EF Source Type B Gas N2O) ; ∑

(Vol. Fuel i *EF Fuel i CO2) ; ∑ (Vol. Fuel i *EF Fuel i CH4) ; ∑ (Vol. Fuel i * EF Fuel i N2O)

B2b Flaring at Capture Site

kg of CO2 ; CH4 ; N N/A N/A N/A Quantity being calculated. Emissions Capture Flare

2O Direct metering of volume of Source Type A gas being flared, converted to STP conditions.


Volume of Source Type B Gas Flared / Vol.


Source Type B Gas

Flared






Constant value of 1.98 kg/m³ at STP. Density of CO2/ ρCO2 kg/m3 N/A Accepted value. Estimated






CO2 Emissions Factor for Source Type B Gas Flared / EF Source Type B Gas



CO2


CH4 Emissions Factor for Source Type B Gas Flared / EF Source Type B Gas



CH4


N20 Emissions Factor for Source Type B Gas Flared / EF Source Type B Gas



N2O


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EOR Protocol










i CO2





i CH4





i N2O


Emissions Capture Vent = ∑ (Vol. Source Type B Gas Vented * % CO2 * ρCO2) ; ∑ (Vol. Source Type B Gas Vented * % CH4 * ρCH4) Emissions Capture Vent kg of CO2 ; CH4 N/A N/A N/A Quantity being calculated.

B3b Venting at Capture Site

Direct metering of volume of Source Type B gas being vented, converted to STP conditions.


Volume of Source Type B Gas Vented / Vol.


Source Type B Gas

Vented






Constant value of 1.98 kg/m³ at STP.


kg/m3 N/A Accepted value. Estimated

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Page 35






Density of CH4/ ρCH4 kg/m3 Estimated Constant value of 0.717 kg/m3 at STP. N/A Accepted value.

Emissions Fuel Extraction / Processing = ∑ (Vol. Fuel i * EF Fuel i CO2) ; ∑ (Vol. Fuel i * EF Fuel i CH4) ; ∑ (Vol. Fuel i * EF Fuel i N2O)

Emissions Fuel Extraction /

Processingkg of CO2e N/A N/A N/A


Volume of Fossil Fuel Combusted for B1b, B2b, B3b and B8 / Vol. Fuel

L/ m3/ Other Measured

Direct metering or reconciliation of volume

in storage (including volumes received).




CO2 Emissions Factor for Fuel Including Production and Processing / EF Fuel CO2



documents. Annual

Reference values adjusted annually as part of Environment Canada reporting on Canada's emissions inventory. Reference values adjusted annually as part of Environment Canada reporting on Canada's emissions inventory.

CH4 Emissions Factor for Fuel Including Production and Processing / EF Fuel CH4

kg CH4 per L / m3 / other Estimated


documents. Annual


Annual From Environment Canada reference

documents. Estimated

B13 Fuel Extraction and Processing

N20 Emissions Factor for Fuel Including Production and Processing / EF Fuel N2O

kg N2O per L / m3 / other

EOR

EOR Protocol

Page 36

2.5.2. Contingent Data Approaches Contingent means for calculating or estimating the required data for the equations outlined in section 2.5.1 are summarized in TABLE 2.5, below. 2.6 Management of Data Quality In general, data quality management must include sufficient data capture such that the mass and energy balances may be easily performed with the need for minimal assumptions and use of contingency procedures. The data should be of sufficient quality to fulfill the quantification requirements and be substantiated by company records for the purpose of verification. The project proponent shall establish and apply quality management procedures to manage data and information. Written procedures should be established for each measurement task outlining responsibility, timing and record location requirements. The greater the rigour of the management system for the data, the more easily an audit will be to conduct for the project. 2.6.1 Record Keeping Record keeping practises should include:

a. Electronic recording of values of logged primary parameters for each measurement interval;

b. Printing of monthly back-up hard copies of all logged data; c. Written logs of operations and maintenance of the project system including

notation of all shut-downs, start-ups and process adjustments; d. Retention of copies of logs and all logged data for a period of 7 years; and e. Keeping all records available for review by a verification body.

2.6.2 Quality Assurance/Quality Control (QA/QC) QA/QC can also be applied to add confidence that all measurements and calculations have been made correctly. These include, but are not limited to:

a Protecting monitoring equipment (sealed meters and data loggers); b Protecting records of monitored data (hard copy and electronic storage); c Checking data integrity on a regular and periodic basis (manual assessment,

comparing redundant metered data, and detection of outstanding data/records);

d Comparing current estimates with previous estimates as a ‘reality check’; e Provide sufficient training to operators to perform maintenance and

calibration of monitoring devices; f Establish minimum experience and requirements for operators in charge of

project and monitoring; and g Performing recalculations to make sure no mathematical errors have been

made.

EOR Protocol

TABLE 2.5: Contingent Data Collection Procedures 1.0 Project/ Baseline SS

2. Parameter / Variable

4. Measured / Estimated

7. Justify measurement or estimation and frequency 3. Unit 5. Method 6. Frequency

Project SS’s Provides reasonable estimate of the parameter, when the more accurate and precise method cannot be used.

Reconciliation of volume of fuel purchased within given time period.


Volume of Each Type of Fuel Used/ Vol. Fuel i

L / m3 Monthly / other Estimated

Reconciliation of volume of fuel consumed within given time period based on equipment efficiency specifications and average flow rates.

Provides reasonable estimate of the parameter, when the more accurate and precise method cannot be used.

Volume of Source Type B Gas Flared / Vol. Source Type B Gas

Flared

m3 Estimated Monthly P2b Flaring at Capture Site

Source Type B gas composition should remain relatively stable during steady-state operation. Interpolating gas composition provides a reasonable estimate when the more accurate and precise method cannot be used.

CO2 Composition in Source Type B Gas (Volumetric Basis) / % CO2

% Measured

Interpolation of previous and following measurements taken.

Daily averaged monthly on a

volumetric basis

Source Type B gas composition should remain relatively stable during steady-state operation. Monthly gas composition analysis provides a reasonable estimate when the more accurate and precise method cannot be used.

Methane Composition in Source Type B Gas (Volumetric Basis) / % CH4

% Measured



volumetric basis

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EOR Protocol





Reconciliation of volume of Source Type B gas relative to length of venting event and average flow rates.


Volume of Source Type B Gas Vented / Vol. Source Type B Gas

Vented

m3 Monthly Estimated



% Measured



volumetric basis P3b Venting at Capture Site



% Measured



volumetric basis



P5b Source Type B Gas Transportation







L / m3 / other Estimated Monthly i

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EOR Protocol



P12 Injection Gas Transportation







i




Volume of Injection Gas Flared / Vol. Injection Gas Flared


Injection gas composition should remain relatively stable during steady-state operation. Interpolating gas composition provides a reasonable estimate when the more accurate and precise method cannot be used.


% Measured



volumetric basis P15 Flaring at Injection Site

Injection gas composition should remain relatively stable during steady-state operation. Monthly gas composition analysis provides a reasonable estimate when the more accurate and precise method cannot be used.


% Measured



volumetric basis

Provides reasonable estimate of the parameter, when the more accurate and precise method cannot be




Page 39

EOR Protocol

used. Reconciliation of volume of Source Type B gas relative to length of venting event and average flow rates.


Volume of Injection Gas Vented / Vol. m3 Estimated Monthly Injection Gas Vented

Injection gas composition should remain relatively stable during steady-state operation. Interpolating gas composition provides a reasonable estimate when the more accurate and precise method cannot be used.


% Measured



volumetric basis P16 Venting at Injection Site

Injection gas composition should remain relatively stable during steady-state operation. Monthly gas composition analysis provides a reasonable estimate when the more accurate and precise method cannot be used.


% Measured



volumetric basis

Gas production should remain relatively stable during steady-state operation. Interpolating gas composition provides a reasonable estimate when the more accurate and precise method cannot be used.


Volume of Injected Gas Produced at Adjacent Locations / Vol.


volumetric basis m3 Estimated

Injected Gas Recycled


Injection gas composition should remain relatively stable during steady-state operation. Interpolating gas composition provides a reasonable estimate when the more accurate and

CO2 Composition in Injection Gas / % CO2

% Measured



volumetric basis

Page 40

EOR Protocol

precise method cannot be used.

Baseline SS’s Provides reasonable estimate of the parameter, when the more accurate and precise method cannot be used.


B1b Source Type A Gas Capture





Volume of Source Type B Gas Flared / Vol. Source Type B Gas

Flared

m3 Estimated Monthly B2b Flaring at Capture Site



% Measured



volumetric basis



% Measured



volumetric basis

Page 41

EOR Protocol




i


Reconciliation of volume of Source Type B gas relative to length of venting event and average flow rates.


Volume of Source Type B Gas Vented / Vol. Source Type B Gas

Vented




% Measured



volumetric basis B3b Venting at Capture Site



% Measured



volumetric basis

Page 42

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Calgary, Alberta, Canada T2P 3G4 403.253.4333

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