Re: Advantage Glacier Acid Gas Injection Offset Project Response

This document is intended for the sole use of the party to whom it is addressed and may contain information that is privileged and/or confidential. If you have received this in error, please notify us immediately.

® RWDI name and logo are registered trademarks in Canada and the United States of America

Reputation Resources Results Canada | USA | UK | India | China www.rwdiair.com

Tel: 403-232-6771 Fax: 403-232-6762 RWDI AIR Inc. #1000, 736-8

th Avenue S.W.

Calgary, Alberta, Canada T2P 1H4 Email: [email protected]

March 20, 2013

Advantage Oil & Gas Ltd. Canterra Tower, Suite 700 400 – 3

rd Avenue S.W.

Calgary, Alberta Canada T2P 4H2 Re: Advantage Glacier Acid Gas Injection Offset Project

Response to Alberta Emissions Offset Registry Comments on the Verification Report RWDI AIR Project: 1301032

Email: [email protected]

Dear Mr. Tarala,

RWDI AIR Inc. (RWDI) was retained by Advantage Oil & Gas Ltd. (Advantage) through its offset project

developer, Blue Source Canada (Blue Source), to provide third party verification to a reasonable level of

assurance of the 2012 Advantage Glacier Acid Gas Inject Offset Project Report. As documented in the

verification report dated February 25, 2013, RWDI completed the verification with a positive finding. The

February 25, 2013 verification report was submitted to the Alberta Emissions Offset Registry (AEOR) as

part of the documentation required to serialize the claimed offset credits on the AEOR. Subsequent to the

submission of this documentation, RWDI received a request for clarification of certain items in the

verification report from AEOR reviewers. In response to this request, the following changes were made to

the verification report, which has been re-issued and dated March 20, 2013:

Update to Verification Report Section or Page #

Modified the verification objective to reference the Specified Gas Emitters Regulation

Table 1 on Page 1

Modified the location of the project relative to Grande Prairie. Page 2

Added section heading to identify the Sampling Plan and added explanatory text to clarify the relationship of the Sampling Plan with the Final Verification Procedures.

Page 8

Modified references to Alberta Environment and Sustainable Resource Development’s Technical Guidance for Project Developers to consistently refer to Version 4.0 - February, 2013.

Throughout

Clarified the roles and responsibilities of the verification team members. Table 8 on Pages 29-30

Modified the Verification Statement in Appendix B to be addressed to Alberta Environment and Sustainable Resource Development rather than AEOR.

Appendix B

Changed report date from February 25, 2013 to March 20, 2013 Throughout


Todd Tarala, Advantage Oil & Gas Ltd. Response to AEOR Comments on Advantage Glacier AGI Offset Project Verification Report RWDI#1301032 March 20, 2013

Page 2

The changes to the verification report summarized above did not affect the positive finding of this

verification. The updated report has been attached for recirculation to the appropriate parties. We trust

that the information provided in this report meets your needs with respect to third party verification under

AESRD’s Specified Gas Emitters Regulation. Should you have any questions, or if we can be of further

assistance, do not hesitate to contact me.

Yours very truly,

RWDI AIR Inc.

Trevor Cavanaugh, P.Eng. Project Manager, Designated Signing Authority Attach.

This document is intended for the sole use of the party to whom it is addressed and may contain information that is privileged and/or confidential. If you have received this in error, please notify us immediately.

® RWDI name and logo are registered trademarks in Canada and the United States of America


Tel: 403-232-6771 Fax: 403-232-6762 RWDI AIR Inc. #1000, 736-8

th Avenue S.W.

Calgary, Alberta, Canada T2P 1H4 Email: [email protected]

March 20, 2013

Advantage Oil & Gas Ltd.

Canterra Tower, Suite 700

400 – 3rd

Avenue S.W.

Calgary, Alberta

Canada T2P 4H2

Attention: Todd Tarala, Environmental Coordinator Re: Reasonable-level Assurance Verification of Partial-year 2012

Advantage Oil & Gas Ltd. Offset Project Greenhouse Gas Assertion Advantage Glacier Acid Gas Injection Offset Project

RWDI AIR Project: 1301032 Email: [email protected]

OFFSET PROJECT REPORT VERIFICATION SUMMARY

RWDI AIR Inc. (RWDI) has completed a third-party verification of the greenhouse gas emissions

reductions claimed for the Advantage Oil & Gas Ltd., Glacier Acid Gas Injection (AGI) Offset Project for

the partial-year, 2012. A summary of important information pertaining to the verification is provided in

Table 1.

Table 1: Offset Project Verification Summary

Project Identification Advantage Glacier Acid Gas Injection Offset Project Advantage Oil & Gas Ltd.

Project Contact

Advantage Oil & Gas Ltd.

Suite 700, 400 – 3rd

Avenue S.W., Calgary, Alberta T2P 4H2 Canada

Todd Tarala, [email protected] , 403-718-8144

Verification Objective

Ensure the partial-year 2012 (July 1 to December 31, 2012) Offset Project Report and corresponding GHG Assertion are credible and of sufficient quality to register in the Alberta Emissions Offset Registry under the Specified Gas Emitters Regulation.

Verification Summary

We have found the Advantage Glacier Acid Gas Injection Offset Project’s partial-year 2012 GHG Offset Project Report and corresponding GHG Assertion to be reliable, complete and in compliance with the requirements of the Specified Gas Emitters Regulation.

RWDI Verification Team Members

Mike Kennedy (Lead Verifier), Russ Lewis (Peer Reviewer), Dave Horrocks (Field Verifier), Jyotsna Kashyap (Verifier), Alena Saprykina (Verifier) and Trevor Cavanaugh (Project Manager)

Verification Report Date March 20, 2013

mailto:[email protected]



Todd Tarala Advantage Oil & Gas Ltd. RWDI#1301032 March 20, 2013

Page 2

INTRODUCTION

The Advantage Oil & Gas Ltd. (Advantage) Glacier Acid Gas Injection (AGI) Offset Project is located

northwest of Grande Prairie near the British Columbia-Alberta border in the Province of Alberta.

Advantage is the sole owner, operator and offset project proponent of this offset project. On October 27th,

2011, the Glacier AGI Offset Project was commissioned to replace the pre-existing incinerator unit; the

plant was de-grandfathered and re-licensed accordingly.

The Alberta Government has developed a carbon compliance system as part of its commitment to taking

action on climate change. Emission offset generation is one of several compliance options outlined by

Alberta Environment and Sustainable Resource Development (AESRD) Climate Change and Emissions

Management Act (2007) and Specified Gas Emitters Regulation (Alberta Regulation 139/2007). Based on

the AESRD Technical Guidance for Offset Project Developers Document (Version 4.0, February 2013),

the following requirements must be met in order to qualify for project-based emission reductions or

removals:

the specified gas emissions reduction must occur in Alberta;

the emissions reductions must be from an action taken that is not otherwise required by law at the

time the action is initiated;

the reductions must result from actions taken on or after January 1, 2002;

the reductions must be real, quantifiable and demonstrable;

the project must have clearly established ownership; and

the emissions reductions must be quantifiable and measurable, directly or by accurate estimation

using replicable techniques.

The opportunity for generating carbon offsets arises from the direct and indirect reductions of greenhouse

gas (GHG) emissions resulting from the geological sequestration of acid gas streams containing

greenhouse gases as part of raw natural gas processing. Advantage retained Blue Source Canada (Blue

Source) to quantify their carbon offsets and prepare an Offset Project Plan (OPP) and Offset Project

Report (OPR) in accordance with the Alberta Environment and Sustainable Resource Development

(AESRD) Technical Guidance for Offset Project Developers (Version 4.0, 2013) and the Quantification

Protocol for Acid Gas Injection (Version 1, 2008). Advantage intends to register their carbon offsets for

partial-year 2012 (July 1 to December 31, 2012) with the Alberta Emissions Offset Registry.

The AESRD Specified Gas Emitters Regulation requires that the GHG assertion be third-party verified to

a reasonable-level of assurance. Advantage has retained RWDI AIR Inc. (RWDI) through Blue Source to

complete the verification. This document is RWDI’s report regarding the verification of the partial-year

2012 (July 1 to December 31, 2012) Advantage Glacier AGI Offset Project submission as provided by

Advantage. RWDI’s verification report follows AESRD’s February 3, 2011, Alberta Offset System

Template: Offset Project Verification Report guidance document.



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PROJECT IDENTIFICATION

Table 2: Project Identification Details

Category Description

The project title Advantage Glacier Acid Gas Injection Offset Project

Verification objective

In accordance with the principles of ISO 14064 Part 3, Specification with Guidance for the Validation and Verification of Greenhouse Gas Assertions, Section A.2.3.2 (Level of Assurance), the objective of the reasonable-level assurance verification is to ensure offset project submissions are materially correct and of sufficient quality to determine the Project's emissions reductions.

In addition, the GHG Offset Project Report and corresponding GHG Assertion should conform to the requirements and principles of ISO 14064 Part 2, Specification with Guidance at the Project Level for Quantification, Monitoring and Reporting of Greenhouse Gas Emission Reductions or Removal Enhancements. More specifically, this is done by ensuring that the submission is complete, accurate, consistent, transparent, and without material discrepancies. This includes confirming data, controls and processes that support the emissions reduction calculations presented in the Offset Project Plan.

Key project dates, credit duration and reported period

• Project start date: October 27, 2011

• Credit start date: October 27, 2011

• Credit duration: 8 years starting on October 27, 2011 and ending on October 26, 2019

• Reporting period: July 1 to December 31, 2012

Expected lifetime of the project According to the Offset Project Plan, the AGI Offset Project is expected to replace the acid gas incinerator at the Glacier Sour Gas Plant for the remainder of the lifetime of facility operations.

Type of greenhouse gas emission reduction or removal project

Acid Gas Injection Offset Project

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

The Advantage Glacier AGI Offset Project location is as follows:

• Legal land description: 05-02-076-12W6 (Plant), 02/03-12-076-12W6 (Injection well)

• Latitude: 55.554089°N (Plant), 55.564862°N (Injection well)

• Longitude: 119.755366°W (Plant), 119.87171°W (Injection well)



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Category Description

Reporting, monitoring and verification details

The Advantage Glacier Acid Gas Injection Offset Project is claiming offsets from July 1 to December 31, 2012. Subsequent reporting will occur annually.

RWDI AIR Inc. was retained as the verifier and is an independent third-party. RWDI meets the requirements outlined in the AESRD Specified Gas Emitters Regulation. The RWDI verification plan uses the methodology and standards as set out in ISO 14064 Part 3, Specification with Guidance for the Validation and Verification of Greenhouse Gas Assertions (April, 2006).

Verification criteria

Criteria used in this verification were as set out in the AESRD Specified Gas Emitters Regulation (Alberta Regulation 139/2007). Specifically, the verification criteria include:

• The offset project submission satisfies the requirements of the regulation;

• The offset project submission is substantiated by sufficient and appropriate evidence;

• The methodology is reasonable and follows best practices for GHG emissions and offset estimations; and

• Any errors, omissions or misrepresentation identified during the verification are corrected.

In addition, criteria as set out in the AESRD Technical Guidance for Offset Project Developers (Version 4.0, February 2013) and the Quantification Protocol for Acid Gas Injection (May, 2008) were also used in this verification.

Verification standard used

Standards used in this verification include:

• ISO 14064-2 Specification with guidance at the project level for quantification, monitoring and reporting of greenhouse gases emission reductions or removal enhancements; and

• ISO 14064-3 Specification with guidance for the validation and verification of greenhouse gas assertions

Level of assurance Reasonable-level assurance

Materiality threshold A standard materiality threshold of 5% was used for this verification.



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PROJECT CONTACT INFORMATION

Roles of the parties involved in the Advantage Glacier Acid Gas Inject Offset Project and their contact information are provided in Table 3.

Table 3: Offset Project Roles and Contact Details

Role Contact Details

Project Developer

Project Company Name: Advantage Oil & Gas Ltd. Suite 700, 400 – 3

rd Avenue S.W.

Calgary, Alberta T2P 4H2 Canada Website: www.advantageog.com

Contact Name: Todd Tarala Environmental Coordinator Phone: 403-718-8144 Fax: 403-718-8300 Email: [email protected]

Project quantifier contact information

Quantifier Company Name: Blue Source Canada 717 – 7

th Avenue SW

Calgary, AB T2P 0Z3 Canada Website: www.bluesourcecan.com

Contact Name: Helen La Carbon Services Project Analyst Phone: 403-262-3026 ext 234 Fax: 403-269-3024 Email: [email protected]

RWDI verification team members details

Verifier Company Name: RWDI AIR Inc. 1000 – 736 8

th Avenue SW

Calgary, Alberta, T2P 1H4 Canada Website: www.rwdi.com

Lead Verifier: Mike Kennedy, P.Eng., GHG-V Phone: 519-823-1311 ext 2083 Fax: 519-823-1316 Email: [email protected]

Verifier: Jyotsna Kashyap Phone: 403-232-6771 ext 6263 Fax: 403-232-6762 Email: [email protected]

http://www.advantageog.com/


http://www.bluesourcecan.com/


http://www.rwdi.com/





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PROJECT GHG ASSERTION

The GHG Assertion for the Advantage Glacier AGI Offset Project is presented in Table 4.

Table 4: Project GHG Assertion

Period Total Quantity of Emission Reduction Offsets Claimed

(tonnes CO2e)

July 1 to December 31, 2012 14,834

RISK ASSESSMENT

One of the initial steps of the verification process involves an assessment of risks that could lead to errors,

omissions, or misstatements in the Offset Project Report or GHG assertion. The risk assessment informs

the development of the sampling plan in order to focus verification activities on areas of higher risk.

The types of risk assessed include inherent, control and detection risks. Inherent risks are associated

with the complexity of the GHG project, the proponent’s capacity to run the project as planned, and the

quantifier’s capacity to develop a high quality GHG inventory system. Control risk is the risk that the

project’s GHG inventory system controls will not prevent or detect discrepancies. Detection risk is the risk

that the verifier will not detect discrepancies that have not been corrected by the controls of the GHG

inventory system. Table 5 summarizes the findings of the risk analysis.

Verifier: Alena Saprykina Phone: 403-232-6771 ext 6273 Fax: 403-232-6762 Email: [email protected]

Field Verifier: Dave Horrocks Phone: 403-232-6771 Fax: 403-232-6762 Email: [email protected]

Project Manager and Designated Signing Authority: Trevor Cavanaugh, P.Eng. Phone: 403-232-6771 ext 6233 Fax: 403-232-6762 Email: [email protected]

Peer Reviewer: Russ Lewis, P.Eng. Phone: 403-232-6771 ext 6241 Fax: 403-232-6762 Email: [email protected]







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Table 5: Risk Assessment Results

Risk Type Risk Categories Relevant Example Level of Risk

Inherent Risks

Quality of Offset Project Report and Offset Project Plan

Offset Project Report and Offset Project Plan were found to be detailed and well written.

Low

Completeness or consistency of GHG inventory documentation

Not an issue. Low to

Medium

Multiple sites to be verified Single site only. Low

Complexity of technology or process

The AGI Offset Project process was not found to be complex.

Low

Control Risks

Communication amongst offset project team

No communication issues were found within the Project.

Low

Design of data management system

The on-site data capture system relies heavily on manual data transfers. However, QA checks exist in the Advantage Production Accounting Department and there are data checks implemented by Blue Source.

Low to Medium

Complexity of project’s organizational structure

Project’s organizational structure is not an issue.

Low

Many people are responsible for the project submission

Not an issue. Low

Staff turnover rate Not an issue. Low

Responsible staff appear too confident

Not an issue. Low

Detection Risks

Multiple sites to be verified Single site only. Low

Data collection and management varies by site

Not applicable. Low

Remote locations Not an issue. The Project was easily accessed for the site visit.

Low

Attitude to the Verification Body

Advantage and Blue Source staff members were cooperative.

Low

As shown in Table 5, there are no high levels of risks associated with the Advantage Glacier AGI Offset

Project. An area of potential low to medium risk (control risk) was identified for manual data transfers. The

sampling plan was adjusted to focus additional attention to the issue of manual data transfers. A second

area of potential low to medium risk (inherent risk) was identified pertaining to the completeness and

consistency of the GHG inventory documentation. The sampling plan was adjusted to focus additional

attention to identify any errors, material or immaterial, that may exist in the Offset Project Report.



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FINAL VERIFICATION PLAN

The verification plan establishes and outlines the terms of engagement, level of assurance, objective,

criteria, scope, and materiality threshold. It also describes the range of potential procedures that may be

applied to ensure the verification objective is met. The RWDI verification plan uses the methodology and

standards as set out in ISO 14064 Part 3, Specification with Guidance for the Validation and Verification

of Greenhouse Gas Assertions (April, 2006).

Procedures and methodologies include the general steps listed below. Where an area of concern was

found (for example, where the resolution of the data or the existence or quality of records was

questionable), additional checking was done to further test these items. Such testing can be quantitative

or qualitative and include spot checking, document reviews, comparison to prior years, field trips, phone

interviews and e-mail questionnaires. The additional testing/checking contributes to the sampling plan.

General

Check for independence between RWDI and Advantage (including Advantage’s contracted quantifier, Blue Source);

Check that the Project’s physical process is adequately defined in the Offset Project Plan;

Review the physical and temporal scope of the offset project submission;

Review Project boundaries to assess transparency around ownership of the offset credits associated with the Project;

Review the overall clarity and transparency of the offset project submission and supporting documentation;

Evaluate areas of inherent, control and detection risk that could potentially lead to errors, omissions or misstatements in the net emissions reductions calculations.

Sampling Plan

The Sampling Plan for this verification was split into the three main categories listed below. The

Sampling Plan was developed based on RWDI’s standard verification process, but was customized to

take into consideration the risks discussed above. Note that the Sampling Plan was adjusted as needed

throughout the verification process as issues were uncovered. Further details of the execution of the

sampling plan are provided in the Final Verification Procedures section below.

Emissions Data and Base Quantity Information for the Baseline Condition

Assess whether the appropriate baseline condition was selected for the submission;

Assess the completeness of the GHG inventory in terms of the sources, sinks and reservoirs identified and included in the inventory under the baseline scenario;

Assess whether appropriate emission factors were used in the GHG emission calculations;

Review the GHG emission factors for year-to-year consistency and/or consistency across the industry;



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Review the GHG emission calculations for correctness and year-to-year consistency and/or consistency across the industry;

Where appropriate, check the reasonableness of emissions or base quantity data by:

- Testing the data for extreme high/low values, spurious values, systematic abnormalities, and values recorded during periods of sensor malfunction or downtime; and,

- Investigating trends and outliers in the data.

Assess whether emissions calculations are consistent with the methodology presented in the AESRD Quantification Protocol for Acid Gas Injection (May, 2008).

Emissions Data and Base Quantity Information for the Project Condition

Assess whether the project scope is clearly defined for the purpose of quantifying GHG emissions reductions;

Check that the project conforms to ISO 14064-2;

Assess the completeness of the GHG inventory in terms of the sources, sinks and reservoirs identified and included in the inventory under the project scenario;

Assess whether appropriate emission factors were used in the GHG emission calculations;

Review the GHG emission factors for year-to-year consistency and/or consistency across the industry;

Review the GHG emission calculations for correctness and year-to-year consistency and/or consistency across the industry;

Where appropriate, check the reasonableness of emissions or base quantity data by:

- Testing the data for extreme high/low values, spurious values, systematic abnormalities, and values recorded during periods of sensor malfunction or downtime; and,

- Investigating trends and outliers in the data.

Assess whether emissions calculations are consistent with the methodology presented in the AESRD Quantification Protocol for Acid Gas Injection (May, 2008).

Data and Information Systems and Controls

Assess the data/information management system for transparency and organization;

Review the flow of data and information and check if it is validated, version controlled and backed-up;

Assess whether monitoring instrumentation used to produce data for emissions reductions estimates is maintained and calibrated to an appropriate standard;

Evaluate the appropriateness of these standards and procedures implemented by Advantage and their ability to ensure the accuracy of the information provided;

Review Advantage’s data control quality assurance documents (i.e., the Quality Assurance Plan); and,

Assess whether required data or information is retained for an appropriate number of years and that there is access to historical data.



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Partial-Year 2012 Offset Project Report Submission

Assess the appropriateness and accuracy of the partial-year 2012 GHG Assertion in accordance with the AESRD Specified Gas Emitters Regulation requirements and the AESRD Technical Guidance for Offset Project Developers (Version 4.0, February 2013);

Check that the Offset Project Plan and Report conform to the ISO 14064-2 standard; and,

Check that the Offset Project Report and accompanying Offset Project Plan clearly specify the project’s GHG reductions/removals.

VERIFICATION SCHEDULE

Verification activities proceeded as shown in Table 6.

Table 6: Schedule of Verification Activities

Date Activity

January 16, 2013 Conflict of interest checked.

January 21, 2013 Site visit request communicated to Advantage.

January 31, 2013 Draft Offset Project Plan and supporting documents received from Blue Source for July 1 to December 31, 2012 reporting period.

February 1, 2013 Verification plan established. Sampling plan developed.

February 4, 2013 Site visit.

February 4 – 7, 2013 Reviewed emission data, base quantity information and draft net emissions reductions calculations for partial-year 2012. Communicated questions and requests for clarifications.

February 8, 2013 Additional information received.

February 11 – 13, 2013 Reviewed additional information received, communicated additional questions and requests for clarifications.

February 13, 2013 Working papers and sampling plan completed.

February 19 – 20, 2013 Verification report written.

February 22, 2013 Draft verification report submitted and reviewed.

February 25, 2013 Final verification report submitted.

March 20, 2013 Response to AEOR comments



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FINAL VERIFICATION PROCEDURES

As indicated in the Final Verification Plan section, verification procedures included a number of

quantitative and qualitative checks of the GHG inventory system and its controls. Desktop document

reviews were complemented with a comprehensive site visit that was conducted on February 4, 2013

(See Appendix A for site visit notes). Key portions of the sampling and testing procedures specific to this

verification are discussed below and detailed working papers are available upon request.

Document Review

Although many documents and sources of information were consulted, the assurance effort focused on

the documents listed in Table 7. The first two documents in the table are the Offset Project Plan and

Offset Project Report submissions as provided to RWDI and the remaining documents were provided by

Advantage or Blue Source as supporting documentation.

Table 7: Summary of Documents Received for the Verification

Document Type Description Name

Offset Project Report and Offset Project Plan

Offset Project Report that provides project details, including site description and calculation methodologies of net emissions reductions for the partial-year 2012 period and includes the GHG Assertion.

‘Advantage AGI Offset Project Report_v3_February 20, 2013.pdf, ‘Advantage AGI Offset ProjectPlan_ Final_August 29, 2012_Signed.pdf’

Emission Reduction calculation spreadsheet

Calculation spreadsheet created by Blue Source to calculate the net emissions reductions for the Advantage Glacier AGI Offset Project.

‘Advantage AGI Offset Calculator_v2_February 19,2013.xlsx-1.xlsx’

Acid Gas Analysis Files

Third-party acid gas analysis data provided as part of the Offset Project submission. Sampling occurred every month and multiple times for some months.

‘Combined Acid Gas - Q2 Samples.pdf’

Fuel Gas Analysis File Third-party fuel gas analysis data emailed to Blue Source by Advantage for the purpose of calculating GHG emissions.

‘Glacier_Sales_Gas_Analysis.xlsx’

SRU Simulation Report for Split-Flow Claus Unit

SRU Simulation report for Split-Flow Claus Unit prepared by Sulphur Experts Western Research (August 2012)

‘SRU_Simulation_Report_Aug_2012_photocopy.pdf’

Loading of Acid Gas Compressor and Stage 1 & 2 intercoolers Documentation

Acid gas ARIEL compressor Multi-run curve which indicates the kW rating of the compressor and the maximum throughput

‘05-02 Acid Gas Comp Curves - Pd at 5500 to 9000kPa1.pdf’

Acid Gas Compressor Documentation

Requested document to confirm kW rating of the Acid gas compressor

‘G10040 002 Acid Gas DBM for HAZOP’



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Document Type Description Name

Stage 1 & 2 intercoolers Documentation

Requested document to confirm kW rating of the Stage 1 and 2 intercoolers

‘Stage 1 and 2 Cooler (EFX Drawing).pdf’

Stage 3 & 4 intercoolers Documentation

Requested document to confirm kW rating of the Stage 3 and 4 intercoolers and the maximum throughput

‘Stage 3 and 4 Cooler (ACE Specs).pdf’

Inlet & Outlet Temperatures, Intercooler Documentation

HMI screenshots ‘Glacier HMI Pages - May 2012.pdf’

Acid Gas Flow Rate from Flash Tank Documentation

Documentation for the glycol flash tank ‘Glacier_Flash_Vapour_TEG.pdf’

Glycol Generator Fuel gas consumption Documentation

Documentation for the glycol regenerator ‘Glacier Hysis Simulation.pdf’

Generator Efficiency Documentation

Manufacturer’s Specification Sheet ‘Cummins_Generator_Data_Sheet.pdf’

Calibration Certificate Documents

Calibration Certificates (Advantage Oil and Gas Ltd. Meter Run Inspection Reports obtained on site visit)

‘Advantage Meter Run Inspection Reports.pdf’

Meter Data Meter Data Spreadsheet obtained on site visit ‘GlacierDB-20130204.xlsx’

Alberta Environment and Sustainable Resource Development Approvals

AESRD Approval documents for Advantage Glacier AGI Offset Project

‘AESRD Approval_00262479-00-00.pdf’, ‘AESRD Approval_00262479-00-01.pdf’, ‘AESRD Approval_00262479-00-02.pdf’ and ‘AESRD Approval_00262479-00-03.pdf’

Energy Resources Conservation Board Approvals

ERCB Approval documents for Advantage Glacier AGI Offset Project

‘Gas Plant Approval ERCB - Acid Gas.pdf’, ‘Gas_Plant_ Approval_ ERCB-Amendment_November_15_2011 .pdf’, ‘Glacier Acid Gas Disposal Approval No. 11628.pdf’

The physical scope of the assessment of the Advantage Glacier AGI Offset Project is as described in the

Alberta Environment and Sustainable Resource Development Approvals (i.e., ‘AESRD

Approval_00262479-00-00.pdf’) and Energy Resource Conservation Board (ERCB) Document Approvals

(eg. ‘Gas Plant Approval ERCB - Acid Gas.pdf’). The temporal scope includes the partial-year 2012 (July

1 to December 31, 2012). Advantage engaged Blue Source to assist with the quantification of the offsets

for their Glacier AGI Offset Project. Blue Source provided an Offset Project Report along with all



Page 13

supporting documentation, which was used to determine the Project’s emission reductions for partial-year

2012, on behalf of Advantage.

Blue Source defined the Project and Baseline conditions in their Offset Project Plan ‘Advantage AGI

Offset ProjectPlan_ Final_August 29, 2012_Signed.pdf’. Advantage generated carbon offsets from the

reductions of greenhouse gas emissions resulting from the geological sequestration of acid gas

containing greenhouse gases as part of the natural gas processing.

Based on the methodology outlined in the AESRD Quantification Protocol for Acid Gas Injection (May,

2008), emission reductions are calculated from a theoretical baseline of emissions that would have been

emitted from the incineration of acid gas and the operation of Liquid Redox Process, Multi-Stage Claus

unit or other equivalent type of sulphur recovery unit, had the acid gas not been stored geologically and

the emissions avoided.

Blue Source described the baseline scenario in detail in their Offset Project Plan as a Split-Flow Claus

process rather than the normal straight-through Multi-Stage Claus Process. The emission sources in the

baseline consider the energy imports necessary to operate the Split-Flow Claus and the energy exports

(e.g. via waste heat recovery) to secondary processes. The baseline condition identified by Blue Source

was determined to be appropriate for the Advantage AGI Offset Project.

According to the AESRD guidance document Quantification Protocol for Acid Gas Injection, the following

sources and sinks may be included:

Baseline sources and sinks

Fuel Extraction and Processing (B9).

Liquide Redox Process Emissions (B5a);

Gas Processing – Multi-Stage Claus Unit (B5b);

Incineration Emissions – Fuel Gas (B6a); and,

Incineration Emissions – Tail Gas (B6b).

Project sources and sinks

Fuel Extraction and Processing Emissions (P12);

Acid Gas Dehydration and Compression Emissions (P6);

Upset Flaring Emissions (P8);

Injection Unit Operation Emissions (P9); and,

Recycled Gas Emissions (P10).

Emissions reduction calculations for partial-year 2012 are performed in the following spreadsheet:

‘Advantage AGI Offset Calculator_v2_February 19,2013.xlsx-1.xlsx’.



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The Calculation Spreadsheet correctly follows the applicable AESRD guidance documents for emission

reduction calculations. The emission reductions calculation spreadsheet is set up so that each baseline

and project category (i.e., ‘Fuel Extraction and Processing’ or ‘Upset Flaring Emissions’, etc.) has its own

worksheet, in which related emissions are calculated. Final emission reductions are calculated in the

‘Offset_Summary’ worksheet of the calculation spreadsheet. Blue Source significantly improved the

calculation spreadsheet for the partial-year 2012 emission reduction calculations, making it more

transparent, better organized, with improved references to data sources and equations. The spreadsheet

is now easier to follow and review.

Baseline Condition Emissions

Fuel Extraction and Processing Emissions: Emissions from this baseline source include the emissions

that would have occurred from fuel extraction and processing in the absence of the AGI Offset Project.

Monthly fuel gas volumes were used in the calculation from the sources: baseline fuel gas flaring and

baseline fuel used in furnace air blower and hot oil pump, which are components of the Split Flow Claus

Unit. Other components of the Split-Flow Claus unit, which include Acid Gas Preheater, Air Preheater and

Reheaters #1 and #2 were not included under this source because, as stated in the OPR, they require

energy import form the hot oil system (SRU Simulation report for Split-Flow Claus Unit prepared by

Sulphur Experts Western Research). In turn, the hot oil system captures energy from the waste heat

exchanger of the Split-Flow Claus. Therefore, the Acid Gas Preheater, the Air Preheater and Reheaters

#1 and #2 would have been operated on recovered energy, not fuel gas. Exclusion of these sources was

found to be acceptable. Emissions were calculated using generic natural gas extraction and processing

emission factors in the ‘B9 Fuel Extractn and Processing’ tab of the calculation spreadsheet.

Baseline Flaring Fuel Gas Volume

The amount of fuel gas flared was calculated using the metered project-level acid gas flared volume, in

addition to the project-level acid gas disposal volume, since this is the total amount of acid gas that would

have been present in the baseline case. These were multiplied by a calculated fuel gas to acid gas ratio.

The acid gas flared volume used in the calculation was referenced to meters FQI-4700C and FQI-4710C,

the total acid gas produced at the two Amine Plant Buildings onsite, as per the Offset Project Plan. The

acid gas disposal volume was referenced to meter FQI-7957D. Daily metered volumes were included in

the ‘HMI_Raw_Data’ worksheet of the calculation spreadsheet. It was confirmed during the site visit that

these were the correct meters to use for the calculation. Several relevant calibration reports and

maintenance notes were provided as part of the Offset Project Report submission. A copy of a meter data

spreadsheet that is the output from an automatic data capture system was obtained on the site visit.

Metered data in this spreadsheet (‘GlacierDB-20130204.xlsx’) was compared to the data used in the

calculation spreadsheet created by Blue Source. A number of days of data was missing from the

spreadsheet obtained at the site visit, but the data that were included did match the numbers that Blue

Source used.

The fuel gas to acid gas ratio calculated for this reporting period is 2.39. The calculation is based on an

energy balance equation and is consistent with the approach used in the previous submission for partial



Page 15

year 2011 and partial-year (January 1 to June 30) 2012. The equation uses the LHV of the tail gas (acid

gas that has already been processed by the SRU), which is being flared in this scenario; and the LHV of

the fuel gas that would be added to the tail gas in order to reach the LHV of 25 MJ/m3

required by the

AESRD Approval No. 262479-00-00.

The tail gas LHV is obtained using the tail gas composition based on the ADA (Anthraquinone Disulfonic

Acid) Outlet Wet Composition taken from the SULSIM report

(‘SRU_Simulation_Report_Aug_2012_photocopy.pdf’), and LHV values (at 15 °C and 101.325 kPa) for

each of the compounds in the composition, referenced to Gas Processors Association (GPA), 2008. GPA

Standard 2145-09: Table of Physical Properties for Hydrocarbons and Other Compounds of Interest to

the Natural Gas Industry.

The LHV of the fuel gas was calculated using time-weighted average molar fractions of each fuel gas

compound and corresponding LHV values (at 15 °C and 101.325 kPa) from GPA, 2008. Fuel gas

compositions were obtained from the ‘Ref_Sales_Gas’ worksheet in the calculation spreadsheet, which

includes pasted raw data from the ‘Bear River West Meter: Sales Gas to TCPL’. RWDI requested the

original file from which these data were taken (‘Glacier_Sales_Gas_Analysis.xlsx’), and confirmed that

they were transferred correctly. Although fuel gas composition documentation obtained during the site

visit did not match the compositions that were included in this worksheet, Blue Source clarified the

discrepancy between the two sources. The Senior Engineer, Facility Construction at Advantage

confirmed that the Sales Gas Analysis taken at the TransCanada meter station represents an average

over an entire month, while the third-party Sales Gas Analyses (analyzed by Maxxam Labs) obtained at

the site visit represent samples analyzed once per month. The engineer indicated that either gas analysis

could be used, but he recommended using the TCPL meter analysis, as the revenue generated by the

sales gas produced at Advantage is based on this analysis. The calculations for fuel gas to acid gas ratio

and the amount of fuel gas addition to flared gas were found to be correct.

Air Blower and Hot Oil Pump Fuel Gas Volume

As per the OPR, both these units are powered by electricity generated by an on-site natural gas fired

generator. The fuel gas volume-equivalence is calculated according to the following equation:

Here is the electrical efficiency of the on-site generator at 75% load. Blue Source referenced

the Cummins Power Generation data sheet (‘Cummins_Generator_Data_Sheet.pdf’) for this value, which

was found to be correct. corresponds to output power rating of the air blower and hot oil

pump. is the total number of hours the acid gas injection compressor was running in

partial-year 2012. Since the gas would be processed by the SRU in the absence of the acid gas

compressor, the run times for both these units are the same. Run time hours are referenced to the

‘HMI_Raw_Data’ worksheet in the calculation spreadsheet. They are automatically tracked by computers

on site. The run time hours were included in the ‘GlacierDB-20130204.xlsx’ document that was obtained



Page 16

on the site visit; the two sets of data were the same, apart from the few days that were missing from the

site visit spreadsheet.

All input parameters used for the fuel usage calculation, such as the output rating, run time hours, and

fuel LHV, for both the air blower and hot oil pump, were found to be correct and appropriately referenced

and/or calculated. However, RWDI believes that the equation for total fuel usage should also take into

account thermal efficiency since the furnace air blower and hot oil pump are operated by a generator that

runs on fuel gas. RWDI calculated the change in the emissions reduction corresponding to this error, and

found it to be less than 1%.

Emission Factors

Generic CO2, CH4 and N2O emission factors associated with natural gas extraction and processing were

used and correctly referenced to AESRD’s Quantification Protocol for Acid Gas Injection (May, 2008).

Final GHG Emissions Calculations

Calculation methods, including conversion factors and references, were found to be consistent for the

partial-year 2012 period. The final GHG emissions based on the baseline source ‘Fuel Extraction and

Processing (Baseline)’ were calculated correctly in the emissions reductions calculation spreadsheet.

Split-Flow Claus Unit Emissions: Emissions from this baseline source include the emissions that would

have occurred from a hypothetical Split-Flow Claus Unit operation and associated fuel usage in the

absence of the AGI Offset Project. Monthly fuel gas volumes to operate a Split-Flow Claus were

calculated based on the fuel consumption of the Split-Flow equipment minus the fuel saved due to the

process energy recovery. Emissions were calculated in the ‘B5b Split_Flow’ tab of the calculation

spreadsheet based on site-specific CO2 and generic CH4 and N2O emission factors.

Split-Flow Claus Unit Fuel Gas Volumes

The fuel consumption of the Split-flow Claus unit was calculated using the following equation:

The parameter ‘Fuel Usage’ in the above equation refers to the fuel required to generate power output of

the Split-Flow Claus equipment components, which include acid gas preheater, air preheater, reheaters

#1 and #2, furnace air blower and hot oil pump. As described in the baseline ‘Fuel Extraction and

Processing Emissions’ section, the fuel usage for the furnace air blower and hot oil pump was found to be

correctly calculated. Acid gas preheater, air preheater, reheaters #1 and #2 were excluded from the

baseline ‘Fuel Extraction and Processing Emissions’ calculations because they require energy import

from the hot oil system, which operates on exothermic energy recovered in the Split-Flow Claus. However,

these sources need to be included into calculations of the Split-flow Claus total fuel usage, as they

represent energy import components into Multi-Stage Claus (fuel usage in the above equation). Energy



Page 17

output from the Split-Flow Claus unit (i.e. exothermic energy recovered to support operation of the hot oil

system) in the above formula is included in the subtrahend. Therefore, total fuel usage is fuel associated

with energy required to operate Split-Flow Claus unit minus the fuel saved that is associated with

exothermic energy recovered in Split-Flow Claus unit.

Acid Gas Preheater, Air Preheater and Reheaters #1 and #2 Fuel Gas Volumes

Total fuel consumption by the acid gas preheater, air preheater and reheaters #1 and #2 were calculated

by the equation shown below:

The output ratings for all units were found to be correct and referenced to the SRU Simulation Report

prepared by Sulphur Experts (‘SRU_Simulation_Report_Aug_2012.pdf’). The run time hours are tracked

on-site based on the operating hours of the acid gas compressor. Run time hourly data were referenced

to the ‘HMI_Raw_Data’ worksheet. Thermal efficiency for each unit was correctly calculated based on the

inlet and outlet temperatures included in the SRU Simulation Report. As per the OPR, Thermal efficiency

was determined based on taking the median bulk temperature of 10 different potential heat transfer

liquids (including Shell Thermia, Therminal, and Downtherm) as the hot oil inlet temperature. This was

done as the baseline SRU unit is simulated only, and the exact design of that unit cannot be known. The

Lower Heating Value of fuel gas was calculated using a time-weighted average for the fuel gas

composition and was found to be correct. The last parameter of the fuel usage equation is referred to as

‘ ’ by Blue Source. This is the fuel energy efficiency of direct-fired heater, which utilizes the

exothermic energy recovered by Split-Flow Claus. In this reporting period, was adjusted from the

fuel energy of a small gas utility boiler (used previously) to a direct-fired heater, in order to take into

account the hot oil system as identified in the SULSIM report. The calculated fuel usage of the acid gas

preheater, air preheater and reheaters #1 and #2 was found to be correct based on all referenced

parameters.

Energy Process Recovery

The parameter ‘Eclaus x ηHeat’ refers to the useful process energy recovered from the Multi Stage Claus

Unit in MJ after ηHeat, heat transfer efficiency from Multi Stage Claus Unit to the secondary process is

taken into account. This was calculated using the following equation:

The sum of energy exports refers to the power ratings (kW) of the waste heat exchanger and condensors

1 to 3, which were correctly referenced to the Sulphur Experts SRU Simulation Report. Utilization

corresponds to run time hours of the acid gas injection compressor as explained in the baseline ‘Fuel

Extraction and Processing Emissions’ section discussing the furnace air blower and hot oil pump. This

was correctly referenced to the ‘HMI_Raw_Data’ worksheet and the final calculation for the ‘Eclaus x



Page 18

ηHeat’ parameter was found to be correct. As mentioned in the baseline ‘Fuel Extraction and Processing

Emissions’ section, data transferred to this worksheet were compared against the meter data

spreadsheet obtained on the site visit (‘GlacierDB-20130204.xlsx’) and found to be consistent, apart from

the few days that were missing from the site visit spreadsheet.

To obtain the saved fuel associated with exothermic energy process recovery, this is divided by ‘ηEnergy’

and the LHV fuel gas value. Here ‘ηEnergy’ is the thermal efficiency of a direct-fired heater already

mentioned above. Finally, the LHV fuel value, also discussed previously in the baseline ‘Fuel Extraction

and Processing Emissions’ section, was correctly calculated using a time-weighted average fuel gas

composition.

The ‘Total Fuel Usage’ calculation for the Split-Flow Claus unit was found to be correct with all

parameters referenced and/or calculated properly.

Emission Factors

A site-specific CO2 emission factor was used in the calculations, while generic CH4 and N2O emission

factors were applied.

For the CO2 emission factor, the CAPP Calculating Greenhouse Gas Emissions (April, 2003) guidance

document (CAPP, 2003) was used to calculate site specific values based on the time-weighted average

fuel gas analysis. Fuel gas compositions were included in the calculation spreadsheet within the

'Ref_Sales_Gas' worksheet. As mentioned previously in the baseline ‘Fuel Extraction and Processing

Emissions’ section, this was obtained from a TransCanada meter data spreadsheet

(‘Glacier_Sales_Gas_Analysis.xlsx’). From July until December, 2012, there were six fuel gas analyses.

The time-weighted average composition was calculated by multiplying the composition values by the

number of days each composition was sampled for, divided by the total number of sampling days for all

gas analyses. This time-weighted average composition was calculated correctly, as was the site specific

CO2 emission factor.

Generic CH4 and N2O emission factors for industrial natural gas combustion were used in the calculations

and referenced to the Environment Canada National Inventory Report (1990 – 2010), Part 2, Annex 8. All

of the emission factors were found to be correct.



partial-year 2012 period. The final GHG emissions based on the baseline source ‘Split-Flow Claus

Emissions’ were calculated correctly in the emissions reductions calculation spreadsheet. It should be

noted that the final GHG emissions associated with this source is a negative number. This is because the

Multi-Flow Claus unit is a net energy exporter, i.e., emissions from the fuel gas consumed in the unit are

lower than the emissions avoided due to the utilization of the exothermal recovered heat from this unit.



Page 19

Incineration Emissions – Fuel Gas: Emissions from this baseline source include emissions that would

have occurred from the flaring of fuel gas to supplement acid gas flaring in the absence of the AGI project.

Emissions were calculated in the ‘B6a Incineration (Fuel Gas)’ tab of the calculation spreadsheet using

site-specific CO2 and generic CH4 and N2O emission factors.

Fuel Gas Volumes

Monthly fuel gas volume, or baseline fuel gas flaring volume, was calculated based on project-level acid

gas flaring volume and project-level acid gas disposal volume. These metered volumes were multiplied by

the calculated baseline fuel gas to acid gas ratio to obtain the baseline fuel gas flaring volume. These

calculations were previously reviewed for the ‘Fuel Extraction and Processing’ baseline source and found

to be correct.

Emission Factors

A site-specific CO2 emission factor was calculated using the CAPP Calculating Greenhouse Gas

Emissions (April, 2003) guidance document (CAPP, 2003) based on a time-weighted average fuel gas

composition. This calculated emission factor was reviewed and found to be correct, as previously

described in the ‘Split-Flow Claus Unit Emissions’ section of this report.

Generic CH4 and N2O emission factors for industrial natural gas combustion were used in the calculations

and referenced to the Environment Canada National Inventory Report (1990 – 2010), Part 2, Annex 8. All

of the emission factors were found to be correct.



partial-year 2012 period. The final GHG emissions based on the baseline source ‘Incineration Emissions

(Fuel Gas)’ were calculated correctly in the emissions reductions calculation spreadsheet.

Incineration Emissions – Tail Gas: This baseline source considers emissions that would have occurred

from the flaring of tail gas in the absence of the AGI project. For CO2 emissions, monthly tail gas volumes

were multiplied by the %CO2 in the tail gas analysis and the density of CO2. A similar calculation was

completed for CH4 emissions that took into account the amount of CO2 which would have been generated

in combustion of CH4 by taking the molecular weight ratio of CO2 to CH4. Emissions associated with

combustion of C2H6, C3H8, iC4H10, C4H10 and C7H16 were calculated using the same calculation method as

for CH4 emissions and also taking into account the molecular weight ratio of CO2 to CxH2x+2 and the

number of moles in the combustion reaction. Emissions were calculated in the ‘B6b Incineration (Tail

Gas)’ tab of the calculation spreadsheet.



Page 20

Tail Gas Volumes

Monthly tail gas volumes included two sources: acid gas disposal volumes and upset flaring acid gas

volumes. These sources have been discussed previously in the baseline ‘Fuel Extraction and Processing

Emissions’ section.

Tail Gas Composition

As mentioned in the baseline ‘Fuel Extraction and Processing Emissions’ section, the tail gas composition

was referenced to the 'SULSIM_Tail_Gas' worksheet in the calculation spreadsheet. The original

composition data, in units of kmol per hour, were manually transferred from the Sulphur Experts SRU

Simulation Report (‘SRU_Simulation_Report_Aug_2012_photocopy.pdf’) and converted based on total

utilization (total run time hours) to kmol. The original spreadsheet received from Blue Source incorrectly

used the utilization hours from the previous reporting period in this calculation. This was an immaterial

error, causing no numerical difference to the offset emissions, which was addressed by Blue Source

before the final version. From the composition in units of kmol, the final tail gas composition was correctly

converted to units of mol% by taking each component and dividing by the total number of moles in the

gas composition. Composition data were correctly transferred from the Sulphur Experts reference file and

the final tail gas composition conversion to mole % was also found to be correct.

CO2 Emissions

The total monthly tail gas volume was multiplied by the percent of CO2 in the tail gas analysis and the

density of CO2 to determine the total CO2 emissions.

The percent of CO2 was correctly referenced to the tail gas composition. The density of CO2 was correctly

referenced to the Gas Processors Association, 2008. GPA Standard 2145-09: Table of Physical

Properties for Hydrocarbons and Other Compounds of Interest to the Natural Gas Industry. The

calculated CO2 emissions were found to be correct.

CO2 emissions associated with CH4, C2H6, C3H8, iC4H10, C4H10 and C7H16 Combustion

As with CO2 emissions, the total monthly tail gas volume was multiplied by the percent of each compound

(CH4, C2H6, C3H8, iC4H10, C4H10 and C7H16) in the tail gas analysis, and the compound density. This value

was then multiplied by the number of carbons in the molecular formula (x), which represents the ratio of

CO2 to CxH2x+2 number of moles in the combustion reaction, and the ratio of CO2 molecular weight to the

relevant CxH2x+2 compound molecular weight, resulting in the total CO2e emissions. This calculation is

illustrated in the equation below:

The densities of CH4, C2H6, C3H8, iC4H10, C4H10 and C7H16 were referenced to the Gas Processors

Association, 2008. GPA Standard 2145-09: Table of Physical Properties for Hydrocarbons and Other



Page 21

Compounds of Interest to the Natural Gas Industry. All parameters used in the calculations including the

percent of compound in the tail gas analysis, compound density, number of carbons and molecular

weights, were found to be correct; hence, the calculated CO2e emissions were found to be correct.


Calculation methods, including conversion factors and references, were found to be satisfactory for the

partial-year 2012 period. The final GHG emissions based on the baseline source ‘Incineration Emissions

(Tail Gas)’ were calculated correctly in the emissions reductions calculation spreadsheet.

Project Condition Emissions

Fuel Extraction and Processing Emissions: Emissions from the ‘Fuel Extraction and Processing

(Project)’ include the extraction and processing emissions from fuels used throughout the project. Monthly

fuel gas volumes were used in the calculation from several sources: dilution gas upset flaring, and fuel

gas consumed by the acid gas compressor, intercooler fans stages 1 and 2 discharge, intercooler fans

stages 3 and 4 discharge, glycol flash tank and glycol regenerator. Emissions were calculated using

generic natural gas fuel extraction and processing emission factors in the ‘P12 Fuel Extractn and

Processin’ tab of the calculation spreadsheet.

Dilution Gas for Upset Flaring Fuel Gas Volumes

The dilution gas volume for upset flaring was referenced to meters FQI-4701 and FQI-4711, the total

dilution gas produced at the two Amine Plant Buildings onsite as per the Offset Project Plan. The data for

these meters was included in the ‘GlacierDB-20130204.xlsx’ document obtained on the site visit, and the

two sets of data were the same, apart from the few days that were missing from the site visit spreadsheet.

The data for these meters were also included in hard copy documents of hand-written Plant Logs

obtained at the site visit. Spot checks confirmed that the values matched the site visit meter data

spreadsheet, as well as the data used by Blue Source in the calculations. It was confirmed during the site

visit that the correct meters were used for the calculation. Several relevant calibration reports and

maintenance notes were provided as part of the Offset Project Report submission.

Acid Gas Compressors and Intercoolers Fuel Gas Volumes

The Canadian Association of Petroleum Producers (CAPP) Calculating Greenhouse Gas Emissions

(2003) guidance document was used to calculate monthly consumption for the acid gas compressor and

intercoolers. The following equation was used:

The ‘ηGenerator’ parameter refers to the electrical efficiency of a generator at 75% load and was found to

be correctly referenced to the ‘Cummins_Generator_Data_Sheet.pdf’ supporting file.



Page 22

Acid Gas Compressor: The output rating for the acid gas compressor was correctly referenced to the

Gemini supporting document ‘Glacier Acid Gas Injection Design Basis Memorandum, Revision F

(‘G10040 002 Acid Gas DBM for HAZOP.pdf’).The utilization of the acid gas compressor was referenced

to the run time hour data in the ‘HMI_Raw_data' worksheet. These data were correctly summed. The

equipment monthly load (%) was calculated based on the monthly average of the daily acid gas disposal

volumes, divided by the maximum daily volume capacity of the acid gas compressor. The maximum daily

volume was referenced to the ‘05-02 Acid Gas Comp Curves - Pd at 5500 to 9000 kPa1.pdf’ (Ariel

Compressor Multi-Run) document and estimated to be 27 e3m

3/day.

Blue Source used a thermal efficiency of 28% for the natural gas fired generator which feeds the electrical

acid gas compressor engine. The thermal efficiency is referenced to the CAPP guidance document A

Recommended Approach to Completing the National Pollutant Release Inventory (NPRI) for the

Upstream Oil and Gas Industry. This assumption was determined appropriate.

The site specific Lower Heating Value of fuel gas was calculated based on the time weighted average fuel

gas analysis data and found to be correct.

All parameters used in the fuel gas volume calculation for the acid gas compressor were found to be

correct; therefore, the volume calculated was also found to be correct.

Intercoolers (1st and 2

nd stage discharge; 3

rd and 4

th stage discharge): The output rating for the 1

st and 2

nd

stage intercooler was correctly referenced to the file ‘Stage 1 and 2 Cooler (EFX Drawing).pdf’. The 3rd

and 4th stage intercooler output rating was correctly referenced to the ‘Stage 3 and 4 Cooler (ACE

Specs).pdf’ file. The utilization of the intercoolers was assumed to be the same as the acid gas

compressor and was referenced to the run-time hour data in the 'HMI_Raw_data' worksheet. This

assumption and output power ratings for all intercoolers were confirmed to be correct during the site visit.

The equipment load (%) was calculated based on average acid disposal gas volume for the month,

divided by the maximum volume. The maximum daily volume for the 1st and 2

nd stage discharge

intercooler was referenced to the ‘05-02 Acid Gas Comp Curves - Pd at 5500 to 9000 kPa1.pdf’ file and

estimated to be 27 e3m

3/day. The maximum daily volume for the 3

rd and 4

th stage discharge intercooler

was correctly referenced to the ‘Stage 3 and 4 Cooler (ACE Specs).pdf’ file. The monthly equipment load

was found to be correctly calculated for both units.

The thermal efficiency (%) of the intercoolers was calculated based on respective inlet and outlet

temperatures, including the ambient temperature of Grand Prairie. This approach was found to be correct.

Inlet and outlet temperatures for the intercoolers were taken from HMI screenshots captured at the facility

‘Glacier HMI Pages - May 2012.pdf’, provided by Blue Source among the supporting documents. The

ambient temperature of Grand Prairie was obtained from the online Environment Canada database. All

the values used were checked and found to be correct.

The same site specific LHV of fuel gas (reviewed previously) was used in the consumption calculations

for the intercoolers and found to be correct.



Page 23

All parameters used in the fuel gas volume calculation for the intercoolers for stages 1 and 2 discharge

and 3 and 4 discharge were found to be correct; therefore, the respective volume calculated was also

found to be correct.

Glycol Flash Tank Fuel Gas Volumes

Fuel usage by the glycol flash tank was calculated based on the following equation:

The glycol flash tank utilization was calculated by subtracting the run time hours of the acid gas

compressor from the total hours of operation in each month. During the regeneration of glycol, acid gas is

flashed from the glycol tank and recycled to first stage compression. However, during system

maintenance, acid gas is directed from the glycol flash tank to the flare stack. Therefore, it was assumed

that while the plant operates 24 hours a day, 7 days a week, the system maintenance time, which

corresponds to the flash tank utilization, is the time when the acid gas compressor is not running. The

original spreadsheet received from Blue Source had an error in the calculation of total hours, but this has

been addressed in the current spreadsheet. The acid gas flare rate was correctly referenced to the

‘Glacier_Flash_Vapour_TEG.pdf’ supporting document. The Project-level Fuel Gas to Acid Gas ratio was

calculated to be 3.05. The calculation is similar to the ratio calculated for the baseline case, discussed in

detail in the baseline ‘Fuel Extraction and Processing Emissions’ section. This calculated ratio takes into

account the required 28 MJ/m3 Lower Heating Value (LHV) required by the revised AESRD Approval no.

262479-00-02. Since this calculated ratio is applicable only in the project case, it has followed the

requirements of the updated approval (while the baseline calculation for fuel gas to acid gas ratio used

the required 25MJ/m3 LHV in AESRD Approval No. 262479-00-00).

All parameters used in the fuel gas volume calculation for the glycol flash tank were found to be correct;

therefore, the respective volume calculated was also found to be correct.

Glycol Regenerator Fuel Gas Volumes

Fuel usage by the glycol regenerator was calculated based on the following equation:

The utilization of the glycol regenerator was referenced to the run time hour data in the 'HMI_Raw_data'

worksheet. The fuel gas flow rate was correctly referenced to the ‘Glacier Hysis Simulation.pdf’ file

produced by the Gemini Corporation. During the verification process, RWDI identified an error associated

with unit conversions for the fuel gas flow rate, but this has been addressed in the final spreadsheet.

All parameters, including unit conversions, used in the fuel gas volume calculation for the glycol

regenerator were found to be correct; therefore, the respective volume calculated was also found to be

correct.



Page 24

Emission Factors

Generic CO2, CH4 and N2O emission factors associated with natural gas extraction and processing were

used and correctly referenced to AESRD’s Quantification Protocol for Acid Gas Injection (May, 2008).



partial-year 2012 period. The final GHG emissions based on the project source ‘Fuel Extraction and

Processing (Project)’ were calculated correctly in the emissions reductions calculation spreadsheet.

Acid Gas Dehydration and Compression Emissions: This project source includes emissions from the

operation of the acid gas dehydration and compression system (including the acid gas compressor, fans

and intercoolers, and the glycol dehydration unit components, which include the glycol flash tank and

glycol regenerator) at the Glacier AGI Offset Project. Emissions from the last two sources are associated

with the acid gas dehydration process and are included as per the AESRD guidance document,

Quantification Protocol for Acid Gas Injection. Emissions were calculated using site specific CO2 and

generic CH4 and N2O emission factors in the ‘P6 AG Dehyd & Compression’ tab of the calculation

spreadsheet.

Fuel Gas Volumes

Monthly fuel gas volumes were calculated using the CAPP Calculating Greenhouse Gas Emissions (2003)

guidance document for several sources: the acid gas compressor, 1st and 2

nd stage discharge intercooler

and 3rd

and 4th stage intercooler. Fuel gas volumes were also calculated for the glycol flash tank and

glycol regenerator. The monthly consumption for all of these sources were reviewed and documented in

the previous project category ‘Fuel Extraction and Processing Emissions’ and found to be correct.

Emission Factors

A site specific CO2 emission factor was used in the emissions calculations. This CO2 emission factor was

reviewed for the ‘Split-Flow Claus Unit Emissions’ baseline source and found to be correct. Generic CH4

and N2O emission factors for industrial natural gas combustion were used in the calculations and

referenced to the Environment Canada National Inventory Report (1990 – 2010), Part 2, Annex 8. All of

the emission factors were found to be correct.



partial-year 2012 period. The final GHG emissions based on the project source ‘Acid Gas Dehydration

and Compression’ were calculated correctly in the emissions reductions calculation spreadsheet.

Upset Flaring Emissions – Fuel Gas: The ‘Upset Flaring Emissions – Fuel Gas’ project source includes

emissions from the flaring of fuel gas to supplement acid gas flaring that occur as part of the Glacier AGI



Page 25

Offset Project operation. Emissions were calculated using site-specific and generic emission factors in the

‘P8a (Fuel Gas) Upset Flaring’ tab of the calculation spreadsheet.

Fuel Gas Volumes

Monthly fuel gas volumes were referenced to dilution gas for upset flaring data captured by the FQI-4701

and FQI-4711 meters and included in the ‘HMI_Raw_Data’ worksheet. As stated in the project category

‘Fuel Extraction and Processing Emissions’ section, these values were found to be correct.

Emission Factors

A site specific CO2 emission factor was used in the emissions calculations. This CO2 emission factor was

previously reviewed in the baseline ‘Split-Flow Claus Unit Emissions’ section of the report and found to be

correct. Generic CH4 and N2O emission factors for industrial natural gas combustion were used in the

calculations and referenced to the Environment Canada National Inventory Report (1990 – 2010), Part 2,

Annex 8. All of the emission factors were found to be correct.



partial-year 2012 period. The final GHG emissions based on the project source ‘Upset Flaring Emissions

– Fuel Gas’ were calculated correctly in the emissions reductions calculation spreadsheet.

Upset Flaring Emissions – Acid Gas: The ‘Upset Flaring Emissions – Acid Gas’ project source includes

acid gas flaring emissions that occur as part of the Glacier AGI Offset Project operation. CO2e emissions

were calculated in the ‘P8b (Acid Gas) Upset Flaring’ tab of the calculation spreadsheet based on emitted

CO2, CH4, C2H6, C3H8, iC4H10, C4H10 , iC5H12, C5H12, C6H14 and C7H16 from upset flaring.

Acid Gas Volumes

Total monthly flared acid gas volume was correctly referenced to the 'HMI_Raw_Data' worksheet with

data captured by the FQI4700C and FQI4710C meters. As stated in the baseline ‘Fuel Extraction and

Processing Emissions’ section of the report, these values were found to be correct.

Acid Gas Composition

Average acid gas compositions were calculated for each month, based on third party acid gas analysis

files from July until December, 2012. Blue Source provided RWDI all of the gas analysis files (‘Combined

Acid Gas - Q2 Samples.pdf’); the data were confirmed to be correctly transferred to the calculation

spreadsheet from the supporting documents. Average monthly compositions were seen to be correctly

calculated. Although acid gas analysis files obtained on the site visit did not match the analyses that Blue

Source used in their calculations, Blue Source clarified the discrepancy between the two sources. The

Senior Engineer, Facility Construction at Advantage indicated that the facility operators sample acid gas

periodically for diagnostic purposes from two different acid gas trains on site, and in some months either



Page 26

one or the other train is missing. The combined stream is more relevant for the purposes of calculating

offset emission reductions, and this is what was used in the calculator.

CO2 Emissions

CO2 emissions were calculated by the total monthly acid gas (upset flared) volume multiplied by the

percent of CO2 in the acid gas analysis, and the density of CO2. The employed methodology is the same

as that used in the baseline section ‘Incineration Emissions – Tail Gas: CO2 Emissions’ of the report.

The percent of CO2 was correctly referenced to the acid gas composition The calculated CO2 emissions

and methodology used were found to be correct.

CO2 emissions associated with CH4, C2H6, C3H8, iC4H10, C4H10, iC5H12, C5H12, C6H14 and C7H16

Combustion

The employed methodology to calculate emissions associated with CH4, C2H6, C3H8, iC4H10, C4H10, iC5H12,

C5H12, C6H14 and C7H16 combustion in acid gas flared is the same as that used in the baseline section

‘Incineration Emissions – Tail Gas: CO2 emissions associated with CH4, C2H6, C3H8, iC4H10, C4H10 and

C7H16 Combustion’ of the report. The calculated CO2 emissions and methodology used were found to be

correct.



partial-year 2012 period. The final GHG emissions based on the project source ‘Upset Flaring Emissions

– Acid Gas’ were calculated correctly in the emissions reductions calculation spreadsheet.

Excluded Emissions

Liquid Redox Process Emissions: This source was excluded from the quantification as Blue Source

selected the Split-Flow Claus unit as the baseline condition. The Split-Flow Process was determined to be

more appropriate than a Multi-Stage Claus unit for sulphur recovery as the acid gas processed at the

Advantage Glacier Sour Gas Plant is relatively lean and would prevent a normal straight-through Multi-

Stage Claus unit from functioning properly.

Injection Unit Operation Emissions: According to the OPP, injection unit operation emissions were

excluded because the acid gas injection system at the Advantage Glacier Sour Gas Plant consists of an

acid gas dehydration unit and compression unit and no other equipment. This was confirmed by RWDI

during the site visit.

Recycled Gas Emissions: According to the OPP, recycled gas emissions were excluded because

producing wells and injection well are distinct entities and therefore recycling of acid gas does not occur.

This was confirmed by RWDI during the site visit.



Page 27

Final Emissions Reductions Calculation

The final net emissions reductions were calculated in the ‘Offset_Summary’ worksheet in partial-year

2012 of the calculation spreadsheet. These reductions were correctly calculated according to the AESRD

guidance document, Quantification Protocol for Acid Gas Injection.

Net emissions reductions (tonnes CO2e) for the partial-year were calculated by subtracting the Project

emissions from the Baseline emissions. The Project and Baseline CO2, N2O and CH4 emissions were

correctly referenced to the appropriate worksheets for each category. The Project and Baseline GHG

emissions in each category were correctly converted to CO2e using the appropriate Global Warming

Potential (GWP) values.

The partial-year 2012 (July 1 to December 31, 2012) net emission reductions were correctly calculated.

Calculations and Methodologies: All emission factors, methodologies and emission reduction

calculations were checked for accuracy and/or appropriateness and compared to the applicable

ISO 14064-2 and AESRD guidance documents. All calculations were found to be correct.

Offset Project Report Submission: The Advantage Offset Project Report, ‘Advantage AGI Offset

Project Report_v3_February 20, 2013.pdf’ and accompanying Offset Project Plan, ’ Advantage AGI Offset

ProjectPlan_ Final_August 29, 2012_Signed.pdf’, were reviewed and found to be detailed and well written.

All protocol deviations were thoroughly explained; necessary supporting documentation was provided.

The GHG assertion presented in the Offset Project Report is consistent with partial-year 2012 (July 1 to

December 31, 2012) emissions reduction Calculation Spreadsheet.

The Offset Project Report and accompanying Offset Project Plan conform to the guidelines presented in

the AESRD Alberta Offset System Template: Offset Project Report and the Alberta Offset System

Template: Offset Project Plan documents, respectively, as well as ISO 14064-2.

Site Visit

A site visit was conducted by the RWDI Field Verifier on February 4, 2013. A Project overview was

provided along with a discussion regarding the inputs and output and description of the plant processes.

An Advantage Plant Operator facilitated the site visit, arranged the site tour and organized additional

meetings with other Advantage department staff. Checks were made during the interviews to verify that

data transfer was properly performed. A spreadsheet containing metered data that was captured

automatically from the HMI system was provided as a supporting document for the verification process.

Meter inspection reports, process flow diagrams and a plant log with hand written entries of different

metered values, were also provided. The RWDI Field Verifier was able to confirm consumption data

based on the meter numbers referenced in the Calculation Spreadsheet. The site visit demonstrated that

personnel performing specific tasks in the plant have the required education, training, experience and

skills to operate the Project.



Page 28

Data flow is transparent. In general, data handling procedures are simple and staff members require

minimal instructions to complete data handling. Data is checked for Quality Assurance on site. Data

checks are also made by production accountants in Red Deer, Alberta and Weyburn, Saskatchewan after

being transferred to the Production Volume Reporting (PVR) system.

Field notes regarding the site visit are attached as Appendix A.

Verification Records

The necessary records obtained and/or created during the verification will be maintained for a minimum of

five years.

VERIFICATION FINDINGS

RWDI has found the Advantage Glacier Acid Gas Injection Offset Project’s partial-year 2012 (July 1 to

December 31, 2012) GHG Offset Project Report and corresponding GHG Assertion to be reliable,

complete and in compliance with the requirements of the AESRD Specified Gas Emitters Regulation.

Furthermore, the quantification, monitoring and reporting of greenhouse gas emission reductions

associated with the Project were found to conform to the requirements and principles of ISO 14064-2.

During the verification, one quantitative issue was identified in the emissions reductions calculations. As

discussed in the baseline ‘Fuel Extraction and Processing Emissions’ section of this report, RWDI

identified an error associated with neglecting to include thermal efficiency in calculations for fuel gas

volume-equivalence of the furnace air blower and hot oil pump, which are operated by a generator that

runs on fuel gas. However, the error in emission reductions associated with this omission is less than 1%.

Since this is only quantitative error found in the verification, the absolute value of the sum of the total

errors is immaterial.

From a qualitative perspective, Advantage carries out its operational activities in a manner adequate to

ensure the proper performance of its equipment and collection of required data. While much of the base

data collected by Advantage and provided to Blue Source for calculations originates from an automated

data capture system, some base data are obtained from written logs or subject to manual transcription. It

was found that base data collection, transcription and reporting were subject to limited QA/QC procedures

on site at Advantage; however, QA checks are implemented by the Production Accounting Department

(located in Red Deer, Alberta). In addition, QA procedures are implemented at Blue Source during the

preparation of the emissions reductions calculations, the OPP and the OPR.

The partial-year 2012 Offset Project Report submission, including the supporting documents and Offset

Project Plan, was presented in a reasonably clear and transparent manner. There were no significant

challenges in following the assertion through to its conclusion. Questions regarding calculations and

methods were answered thoroughly by Advantage and Blue Source staff members; requests for

additional documentation were promptly addressed. All GHG emission factors, emissions calculations



Page 29

and emissions reductions were documented, and found to be correct and consistent with the Offset

Project Plan. All the changes applicable for the partial-year 2012 were listed in the Offset Project report

under section 4.0, Project Implementation and Variances, and were found to be acceptable and clearly

explained. Advantage and Blue Source staff members were well prepared for the audit, accommodating

and open regarding all aspects of their emissions reductions calculations and reporting.

Based on the verification activities described in this report, we have found to a reasonable-level of

assurance, that the Advantage Glacier AGI Offset Project’s partial-year 2012 GHG Offset Project Report

and corresponding GHG Assertion are reliable, complete and in compliance with the requirements of the

AESRD Specified Gas Emitters Regulation.

RWDI’s Statement of Verification, Conflict of Interest Checklist, and Statement of Qualification can be

found in Appendices B to D, respectively.

VERIFICATION TEAM

The verification team and their roles and responsibilities are listed in Table 8.

Table 8: Verification Team Roles and Responsibilities

Team Member Role Responsibilities

Mike Kennedy, P.Eng,

GHG-V

Lead Verifier

Leadership of the verification team

Coordination of the verification process

Ensuring appropriate expertise is available to review all aspects of the GHG assertion

Development of verification strategy and verification plan (including sampling plan)

Execution of most of the sampling plan and verification procedures

Jyotsna Kashyap Verifier Assistance with development of sampling plan

Execution of most of the sampling plan and verification procedures

Alena Saprykina Verifier

Dave Horrocks Field Verifier Participation in the site visit

Execution of those aspects of the sampling plan and verification procedures that took place during the site visit

Trevor Cavanaugh, P.Eng. Project Manager,

Designated Signing

Authority

Binding authority for RWDI

Statement of Verification

Conflict of Interest Checklist

Statement of Qualification

Overall project planning

Client Communication



Page 30

Russ Lewis, M.Eng.,

P.Eng.

Peer Reviewer Independent review of verification process and procedures

Overall quality of deliverables

CLOSURE

We trust that the information provided in this report meets your requirements for the purposes of the

AESRD Specified Gas Emitters Regulation. Should you have any questions or if we can be of further

assistance, please contact me directly by telephone at (403) 232-6771 (extension 6233) or by email at

[email protected].

Yours very truly,

RWDI AIR Inc.

Trevor Cavanaugh, P.Eng. Russ Lewis, M.Eng., P.Eng.

Project Manager, Designated Signing Authority Peer Reviewer

Attachments


APPENDIX A

Advantage Glacier Acid Gas Injection Offset Project Verification – Site Visit Notes

February 4, 2013

Present: Dave Horrocks (RWDI)

1. Site tour. Checked all facility components / emission sources. Requested an overview of the

plant process. Asked if any changes were made to the facility during the period July to

December 2012. No significant changes to facility over the period in question. Was asked to

take a picture of the injection point, if possible. Brought back photos of injection point and other

equipment on site.

2. Confirmed list of all emission sources listed in the AENV Approval 262479-00-03:

- five 1767 kW compressor engine exhaust stacks;

- 858 kW compressor engine exhaust stack;

- 3585 kW compressor engine exhaust stack; - 1400 kW natural gas electric generator engine exhaust

stack - 420 kW emergency diesel electric generator engine

exhaust stack; - two 475 kW emergency natural gas electric generator

engine exhaust stacks;

- three 1538 kW dehydrator reboiler exhaust stacks;

- four 1903 kW amine reboiler exhaust stacks;

- 673 kW heat medium reboiler exhaust stack;

- acid gas dehydrator reboiler exhaust stack;

- acid gas flare stack;

- emergency flare stack;

- low pressure flare stack;

- glycol still vent vapor incinerator stack;

- space ventilation exhaust vents;

- space heater exhaust stacks;

- compressor starter gas vents;

The 858 kW compressor is not normally running. It is run only briefly once or twice per year.

3. Baseline Source B9 Fuel Extraction and Processing. Confirmed what the meters read. Data

is automatically sent to a spreadsheet. Brought back meter data spreadsheet

GlacierDB-20130204.xlsx. Confirmed that data is QA’ed on site by Darren Wegel. Confirmed

that the fuel gas to acid gas ratio has been changed from 1.25:1 to 3:1 since June, 2012, and

that it is an automatic process to change the ratio.

4. Baseline Source B5b Split Flow Claus. Asked operator, if acid gas injection were not

occurring at Advantage, what would have occurred? Would they have flared everything, or install

a Split-Flow Claus unit? The basic attitude was that it may help, but it was not really needed at

this facility.

5. Baseline Source B6a Incineration (Fuel Gas). Confirmed that gas analyses are now entered

by PVR support, people in Red Deer Alberta and Weyburn Saskatchewan.

6. Project Source P8b Upset Flaring (Acid Gas). Confirmed that gas analysis was performed by

a third party, Maxxam. Confirmed that the sampling point of the combined acid gas stream was

before the flare stack. Confirmed that acid gas is sampled once per month.

7. Project Source P6 AG Dehydration and Compression. Confirmed that nothing has changed

at the site, so previous output kw ratings for AG compressor, intercoolers would still be valid.

Took photos of some name plates. Asked about run time hours for AG compressor and

intercoolers. Tech wasn’t sure where they get this information from. His assumption was that

they used a 24 hour day and subtracted downtime. He did confirm that the AG compressor and

intercoolers are either all running at the same time, or not running.

8. Data handling and controls. There is a custom HMI by Rockwell. Data flow is transparent. All

data is automatically collected. All data is stored in the HMI database. Backed up by Calgary.

Calculation spreadsheet is not done on site, so nobody there has access. Regular calibrations

are done. Data is retained permanently.

9. Calibration records for the period July to December, 2012. Calibration records requested for

meters FQI-4700C, FQI-4710C, FQI-4701, FQI-4711 and FQI-7957D. Records received for all

meters except FQI-7957D. This meter is not calibration capable and they are researching what

is to be done with it, since it is relatively new.

APPENDIX B

APPENDIX C

APPENDIX D

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