Measurement, Monitoring and Verification (MMV) Plan...The injected CO2 will be stored at a depth of...

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Controlled Document

Quest CCS Project

Measurement, Monitoring and Verification Plan

Project Quest CCS Project

Document Title Measurement, Monitoring and Verification Plan

Document Number 07-0-AA-5726-0002

Document Revision 01

Document Status Approved

Document Type AA5726 -Field Development Plan

Owner / Author Stephen Bourne

Issue Date 2011-08-15

Expiry Date None

ECCN EAR 99

Security Classification

Disclosure None

Revision History shown on next page

AA5726 -Field Development Plan Page 1 of 196 Rev. 01

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Revision History REVISION STATUS APPROVAL

Rev. Date Description Originator Reviewer Approver 01 2011-08-15 Issued for Review Stephen Bourne Max Prins Syrie Crouch

All signed originals will be retained by the UA Document Control Center and an electronic copy will be stored in Livelink

Signatures for this revision Date Role Name Signature or electronic reference (email)

Originator Stephen Bourne

Reviewer Ian Silk

Reviewer Kathy Penney

Reviewer Anita Spence

Reviewer Max Prins

Reviewer James Clark

Approver Syrie Crouch

Summary

This document defines the Measurement, Monitoring and Verification Plan for the Quest Carbon Capture and Storage Project.

Keywords

Quest, CCS, MMV

DCAF Authorities Date Role Name Signature or electronic reference (email)

Max Prins Actual signature


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Executive Summary

The Quest Carbon Capture and Storage Project (Quest CCS Project) will make a material early contribution to reducing CO2 emissions generated by upgrading bitumen from the Alberta oil sands. The climate benefits and societal acceptability of this Project both require long-term secure storage of the 1.08 million tonnes of CO2 captured per annum within the Basal Cambrian Sands (BCS) storage complex.

The Quest CCS Project will ensure secure storage through selection of a site with ideal storage characteristics, a comprehensive data gathering and characterisation of the site and a state of the art program for Measurement, Monitoring and Verification (MMV). Confidence in the oil and gas industry’s ability to select an appropriate site and safely manage the injection and monitoring programs is based on many years of experience:

More than 100 years of experience of managing reservoirs and wells; More than 100 years experience of storing natural gas, including in Fort

Saskatchewan and Bruderheim; Acid gas has been injected for 20 years in Alberta; 12 years of direct experience in ongoing small and large-scale CCS projects.

Site Selection This previous experience helped select the Quest site which is an ideal site for CO2 injection and storage. Bachu et al.1 identified the most promising opportunities for CCS across Canada by matching the location of large localized CO2 emissions with geological formations well-suited for CO2 storage. This systematic screening concluded the top ranking opportunities were located within the Alberta Basin. The Quest storage site is located within the Alberta Basin.

Site Characterisation The injected CO2 will be stored at a depth of 2 km where there are three extensive natural geological seals to trap the CO2. This site avoids legacy wells that might compromise the integrity of these seals. Wells for CO2 injection will be purpose built for this site and based on existing CO2 injection technologies.

Measurement, Monitoring and Verification The Quest Project has a responsibility to carefully monitor activity within the storage area and to confirm everything is as it should be. To that end, world-leading monitoring systems have been developed to operate even at the deepest levels of the storage site. The monitoring results will be transparent and publically available to demonstrate that the Quest storage site is inherently safe. This MMV Plan is designed according to a systematic risk assessment to achieve two distinct objectives:

Ensure Conformance to indicate the long-term effectiveness of CO2 storage by demonstrating actual storage performance is consistent with expectations about injectivity, capacity and CO2 behaviour inside the storage complex;


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Ensure Containment to demonstrate the security of CO2 storage and to protect human health, groundwater resources, hydrocarbon resources, and the environment.

MMV will achieve this in two ways. First, by verifying the expected effectiveness of existing safeguards created by site selection, site characterization and engineering designs. Second, by creating additional safeguards using the same monitoring systems to provide an early warning to trigger timely control measures designed to reduce the likelihood or the consequence of any leakage from the storage site. These control measures include re-distribution of injection rates, drilling additional injectors and, if necessary, stopping injection and deploying groundwater remediation systems. For example, transfer of long-term liability, in accordance with the Closure Plan2, is supported by MMV activities designed to verify that the observed storage performance conforms to model-based forecasts and that these forecasts are consistent with permanent secure storage at an acceptable risk. These same monitoring systems will also provide early warning of any potential for loss of conformance to allow timely updates to subsurface models or updates to the Storage Development Plan to maintain conformance and ensure timely site closure and transfer of long-term liability to the crown. The selected monitoring plans for conformance and containment are subject to different value drivers. Conformance risks affect project value so conformance monitoring plans were selected according to their value of information. Containment risks affect project safety so containment monitoring plans were selected to ensure these risks are as low as reasonably practicable. Some commitments for monitoring already exist for each of the major environmental domains based on responses provided to Requests for Supplemental Information following the submission of the Conceptual MMV Plan3 to regulatory authorities in November 2010 (Table 1). The estimated cost of this updated MMV Plan depends on the number of injectors required according to the phased storage development plan:

3 injectors: 4.0 CAD per tonne of CO2; 4 injectors: 4.4 CAD per tonne of CO2; 5 injectors: 4.8 CAD per tonne of CO2.


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Table 1: MMV commitments made in June 2010 in response to Supplemental Information Requests.

MMV and Closure Plan Updates 1. Updates to be submitted to regulators before commencing baseline monitoring in 2012, and then every 3 years Wells 2. Distributed temperature sensing system outside the production casing on all injectors to verify well integrity 3. Deep monitoring wells (3), drilled from injection well pads to monitor pressure in the Winnipegosis Formation Geosphere 4. Time-lapse seismic: First 3D VSP then 3D surface seismic designed to monitor the CO2 plume from each injector 5. Remote sensing: Monthly InSAR monitoring designed to monitor pressure build-up inside the storage complex Hydrosphere 6. Groundwater monitoring wells (3 per injector): Water electrical conductivity and water chemistry Biosphere 7. Remote sensing: Annual multi-spectral imaging designed to detect environmental changes Atmosphere 8. Line-of-sight CO2 flux monitoring field trial at Radway 8-19 starting Q3 2011 to measure any CO2 emissions


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TABLE OF CONTENTS ABBREVIATIONS ....................................................................................................... 9

1. PROJECT DESCRIPTION ................................................................................... 11

2. THE PURPOSES OF MMV ................................................................................ 11

2.1. Area of Review ....................................................................................... 14

2.2. Domains of Review .................................................................................. 14

2.3. Timeframe of Review ............................................................................... 14

2.4. Timeframe of Updates .............................................................................. 15

2.5. WRM Standards ..................................................................................... 15

3. MMV DESIGN ................................................................................................ 20

3.1. MMV Design Principles ............................................................................ 20

3.2. MMV Design Process ............................................................................... 20

3.3. Influences on MMV Design ....................................................................... 22

4. STORAGE RISKS BEFORE MMV ....................................................................... 23

4.1. Storage Site Description ........................................................................... 23

4.2. Initial Conformance Risks ......................................................................... 28

4.2.1. Loss of Conformance Definition .................................................... 28

4.2.2. Potential Consequences Due to a Loss of Conformance ................... 28

4.2.3. Potential Threats to Conformance ................................................. 28

4.2.4. Initial Safeguards to Ensure Conformance ..................................... 28

4.3. Initial Containment Risks .......................................................................... 30

4.3.1. Loss of Containment Definition ..................................................... 30

4.3.2. Potential Consequences Due to a Loss of Containment .................... 30

4.3.3. Potential Threats to Containment ................................................... 30

4.3.4. Initial Safeguards to Ensure Containment ...................................... 31

5. MONITORING TECHNOLOGY SELECTION ...................................................... 34

5.1. Monitoring Performance Targets ............................................................... 34

5.2. Monitoring Tasks ..................................................................................... 34

5.3. Monitoring Technologies .......................................................................... 35

6. MONITORING PLAN ....................................................................................... 37

6.1. Monitoring Schedule ............................................................................... 37

6.2. Monitoring Coverage .............................................................................. 40

6.2.1. Observation Wells within the Basal Cambrian Sands Formation ...... 40

6.2.2. Observation Wells within the Winnipegosis Formation ................... 41

6.2.3. Project Groundwater Wells .......................................................... 41

6.2.4. Landowner Groundwater Wells .................................................... 43

7. MONITORING PERFORMANCE TARGETS ........................................................ 49

7.1. Performance Targets for Conformance Monitoring ..................................... 49


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7.1.1. Monitoring CO2 Plume Development ............................................ 49

7.1.2. Monitoring Pressure Development ................................................. 50

7.2. Performance Targets for Containment Monitoring ...................................... 50

7.2.1. Monitoring Legacy Well Integrity .................................................. 51

7.2.2. Monitoring Injection Well Integrity ................................................ 51

7.2.3. Monitoring Geological Seal Integrity............................................. 52

7.2.4. Monitoring the Hydrosphere ........................................................ 55

7.2.5. Monitoring the Biosphere ............................................................. 56

7.2.6. Monitoring the Atmosphere.......................................................... 57

7.3. Modeling ................................................................................................ 59

7.4. Key Performance Indicators ...................................................................... 60

8. CONTINGENCY MONITORING PLANS ........................................................... 63

8.1. InSAR ..................................................................................................... 63

8.2. Time-Lapse Seismic .................................................................................. 64

8.3. Microseismic Monitoring .......................................................................... 65

8.4. Pressure Monitoring ................................................................................. 66

9. STORAGE RISKS AFTER MMV .......................................................................... 67

9.1. Additional Safeguards to Ensure Conformance .......................................... 67

9.2. Additional Safeguards to Ensure Containment ........................................... 69

10. OPERATING PROCEDURES.............................................................................. 73

10.1. Monitoring Procedures under Normal Operating Conditions ....................... 73

10.2. Operating Procedures in Response to Monitoring Alarms ........................... 75

11. REPORTING .................................................................................................... 78

11.1. Scotford Upgrader Current Reporting Requirements ................................... 78

11.2. Anticipated Additional Reporting Requirements ......................................... 78

11.3. Communication Venues ........................................................................... 79

11.4. Multi-stakeholder Groups ......................................................................... 79

REFERENCES .......................................................................................................... 80

APPENDIX 1. EMERGING MMV GUIDELINES ................................................... 85

A1.1. Future Regulatory Expectations ..................................................... 85

A1.2. International Authorities ............................................................... 86

A1.3. Government Authorities ............................................................... 86

A1.4. Industry Authorities ..................................................................... 87

APPENDIX 2. RISK MANAGEMENT USING THE BOWTIE METHOD ................... 89

APPENDIX 3. INITIAL EVALUATION OF CONFORMANCE RISKS ...................... 91

A3.1. Potential Consequences Due to a Loss of Conformance ................... 91

A3.2. Potential Threats to Conformance ................................................. 91

A3.3. Initial Safeguards to Ensure Conformance ..................................... 91

APPENDIX 4. INITIAL EVALUATION OF CONTAINMENT RISKS ......................... 94


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A4.1. Potential Consequences Due to a Loss of Containment .................... 94

A4.2. Potential Threats to Containment ................................................... 94

A4.3. Initial Safeguards to Ensure Containment ...................................... 97

A4.3.1. Preventative Measures ................................................................. 97

A4.3.2. Corrective Measures .................................................................. 102

A4.4. Evaluation of Safeguards ........................................................... 104

A4.5. Risks Deemed Insignificant ......................................................... 104

APPENDIX 5. EVALUATION OF MONITORING TECHNOLOGIES ..................... 114

A5.1. Method of Evaluation ................................................................ 114

A5.2. Identification of Monitoring Tasks ............................................... 114

A5.3. Identification of Monitoring Technologies .................................... 115

A5.4. Screening of Technologies ......................................................... 116

A5.5. Evaluation of Technologies ......................................................... 116

A5.5.1. Ranking of Technologies ............................................................ 117

A5.5.2. Ranking Benefits ....................................................................... 117

A5.5.3. Ranking Costs ........................................................................... 117

APPENDIX 6. EVALUATION OF CONTROL MEASURES ................................... 146

A6.1. Active Safeguards ..................................................................... 146

A6.1.1. Preventative Control Responses .................................................. 146

A6.1.2. Corrective Control Responses ..................................................... 147

A6.2. Additional Safeguards to Ensure Conformance ............................ 148

A6.3. Additional Safeguards to Ensure Containment ............................. 148

APPENDIX 7. MONITORING FEASIBILITY ASSESSMENTS ................................ 157

A7.1. Injection Well Integrity Monitoring .............................................. 157

A7.2. Geosphere Monitoring .............................................................. 157

A7.3. Hydrosphere Monitoring ............................................................ 158

A7.4. Biosphere Monitoring ................................................................ 159

A7.5. Atmosphere Monitoring ............................................................. 158

APPENDIX 8. RELIABLE DETECTION OF RARE EVENTS .................................... 160

A8.1. Threat Detection ........................................................................ 160

A8.2. Deciding if a Threat Exists .......................................................... 160

A8.3. False Alarms or Missed Alarms .................................................. 162

A8.4. Rare Threats ............................................................................. 163

A8.5. Expected Alarm Rates ................................................................ 163

A8.6. Switch Off by False Alarms ........................................................ 165

A8.7. Performance Requirements ......................................................... 165

APPENDIX 9. TOWARDS A QUANTIFIED RISK ASSESSMENT .......................... 168

A9.1. Probability Model of Containment Risk ........................................ 168

A9.2. Model Inputs ............................................................................. 169


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A9.2.1. Threat Initiation Rates ................................................................ 169

A9.2.2. Consequence Weights ............................................................... 170

A9.2.3. Effectiveness of safeguards ........................................................ 171

A9.3. Computed Risks ........................................................................ 171

APPENDIX 10. KNOWLEDGE TRANSFER BETWEEN CCS PROJECTS .................. 173

A10.1. Existing Large-Scale CCS Projects ............................................... 173

A10.1.1. Sleipner ........................................................................... 173

A10.1.2. In Salah ........................................................................... 173

A10.1.3. Snøhvit ............................................................................ 173

A10.1.4. Rangely ........................................................................... 174

A10.1.5. Weyburn‐Midale .............................................................. 174

A10.2. Joint Industry Project for Knowledge Transfer ............................... 174

A10.3. Independent Project Reviews ...................................................... 175

APPENDIX 11. STATUS OF EXISTING WELLS .................................................... 176

APPENDIX 12. PRESSURE REQUIRED TO LIFT BCS BRINE ................................... 180

APPENDIX 13. KEY PERFORMANCE INDICATOR REGRETS ............................... 181

APPENDIX 14. DATA MANAGEMENT FOR MMV ............................................. 182

APPENDIX 15. RESPONSIBILITIES AND ACCOUNTABILITIES FOR MMV ............. 187

APPENDIX 16. MMV COST ESTIMATES ............................................................ 189


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Abbreviations

AEC ..................................................................... atmospheric eddy correlation ALARP ............................................................. as low as reasonably practicable AOI ............................................ Exploration Tenure Area of Interest for the Project AOR ............................................. area of review of MMV activities for the Project APM ....................................................................... annulus pressure monitoring ARC .......................................................................... Alberta Research Council BCS............................................................................. basal Cambrian Sands BGWP .............................................................. Base of Groundwater Protection BGS .......................................................................... British Geological Survey CBL .................................................................................... cement bond logs CCS ...................................................................... carbon capture and storage CDM ................................................................ Clean Development Mechanism CO2 ....................................................................................... carbon dioxide CSA ............................................................... Canadian Standards Association DAS .......................................................... fibre-optic distributed acoustic sensing DHMS .......................................................... down-hole microseismic monitoring DHPT ....................................................... down-hole pressure-temperature gauge DNV .................................................................................. Det Norske Veritas DTS ...................................................... fibre-optic distributed temperature sensing EPA ................................................................. Environmental Protection Agency ERCB ........................................................ Energy Resources Conservation Board ESS ..................................................................................... ecosystem studies GHG ..................................................................................... greenhouse gas GPS........................................................................... global positioning system GPZ ..................................................................... groundwater protection zone HIA ........................................... satellite or airborne hyper-spectral image analysis HSE ................................................. United Kingdom Health and Safety Executive HSSE ...................................................... Health Safety Security and Environment HUD ......................................................................................... hold-up depth IEA ........................................................................ International Energy Agency INJ .......................................................................................... injection wells InSAR ...................................................... Interferometric Synthetic Aperture Radar IPAC ................................................. International Performance Assessment Centre IPAC-CO2 .............................. International Performance Assessment Centre for CO2 IPCC................................................. Intergovernmental Panel on Climate Change IRM .............................................................. injection rate metering at wellhead KPI .......................................................................... key performance indicator LOSCO2 .............................................................. line-of-sight gas flux monitoring MCS .......................................................................... Middle Cambrian Shale MIA ............................................. satellite or airborne multi-spectral image analysis MMV .................................................... measurement, monitoring and verification MNA .................................................................. Monitored Natural Attenuation


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MWIT ................................................... mechanical well integrity pressure testing NETL ...................................................... National Energy Technology Laboratory OBW ................................................ observation wells in Winnipegosis (WPGS) PTRC ........................................................ Petroleum Technology Research Centre Quest CCS project ...............................Quest Carbon Capture and Storage Project RIA ....................................................... satellite or airborne radar image analysis SC-SSSV ................................................ surface controlled subsurface safety value SEIS2D ................................................................. time-lapse surface 2D seismic SEIS3D ................................................................. time-lapse surface 3D seismic Shell ............................................................................... Shell Canada Limited SPH ........................................................................................ soil pH surveys SSAL .................................................................................. soil salinity surveys TNO ................................ Netherlands Organisation for Applied Scientific Research UK .............................. United Kingdom Department of Energy and Climate Change UNSED ...................... United Nations Conference on Environment and Development USIT ........................................................... time-lapse ultrasonic casing imaging VSP .............................................................................vertical seismic profiling VSP3D ...................................................... time-lapse 3D vertical seismic profiling WEC ................................................. down-hole electrical conductivity monitoring WHCO2 ..................................................................... wellhead CO2 detectors WHPT ........................................................ wellhead pressure-temperature gauge WPGS ..................................................................................... Winnipegosis WPH ........................................................................ down-hole pH monitoring WRI ........................................................................... World Resources Institute WRM ............................................................... well and reservoir management


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1. PROJECT DESCRIPTION

Shell Canada Limited, which will hold all necessary regulatory approvals in respect of the Project, is the managing partner of Shell Canada Energy. Shell Canada Energy will operate the Project, on behalf of the Athabasca Oil Sands Project (“AOSP”), which is a joint venture between Shell Canada Energy (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). . The goal of the Quest CCS Project is to separate, capture and permanently store CO2, thereby reducing greenhouse gas emissions from the existing Scotford Upgrader. The Scotford Upgrader is located about 5 km northeast of Fort Saskatchewan, Alberta, within Alberta’s Industrial Heartland, which is zoned for heavy industrial development. The three components of the Quest CCS Project are:

CO2 capture infrastructure, which will be connected to the Scotford Upgrader. The method of capture is based on a licensed Shell amine system called ADIP-X.

a CO2 pipeline, which will transport the CO2 from the Scotford Upgrader to the injection wells, about 50 km north of the upgrader. The CO2 injection well locations are in the located in the center of the storage site.

a storage scheme consisting of 3 to 8 injection wells, which will inject the CO2 into the Basal Cambrian Sands (BCS), a deep underground formation, for permanent storage at a depth of about 2 km below ground level. The security of storage will be ensured through a program of Measurement, Monitoring and Verification (MMV).

The injection policy consists in injecting 1.08 million tonnes of CO2 per annum for 25 years using 3 to 8 vertical wells with a typical spacing of 5 km. The maximum injection pressure will not exceed the measured fracture pressure of the injection formation. The distribution of injection between this well will be manages to satisfy this pressure constraint and minimise the plume size in each well in accordance with the Directive 65 application. This project does not include additional wells for production and disposal of brine for pressure management.

2. THE PURPOSES OF MMV

The selected storage site is believed to be inherently safe, however it is responsible to manage the residual storage risks no matter how small. MMV is central to the framework for storage risk management (Figure 1). There are two independent storage risks, loss of conformance and loss of containment and these are reflected in the two primary objectives of MMV for the Quest CCS Project.

Ensure Conformance to indicate the long-term security of CO2 storage, i.e. Show pressure and CO2 development inside the storage complex are

consistent with models and, if necessary, calibrate and update these models.


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Evaluate and, if necessary, adapt injection and monitoring to optimize storage performance.

Provide the monitoring data necessary to support CO2 inventory reporting. Ensure Containment to demonstrate the current security of CO2 storage, i.e.

Verify containment, well integrity, and the absence of any environmental effects outside the storage complex.

Detect early warning signs of any unexpected loss of containment. If necessary, activate additional safeguards to prevent or remediate any

significant environmental impacts as defined by the Environmental Assessment3.

Well-established industry practices for Well and Reservoir Management and Environmental Monitoring provide the key capabilities necessary to fulfill these requirements.


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Figure 1: Framework for storage risk management.

Establish Monitoring Requirements

Select Monitoring Plans

Establish Performance Targets

Identify Contingency Monitoring

Identify Control Measures

Evaluate theseAdditional Safeguards

Storage Risks Acceptable?

Evaluate Storage Feasibility

Select Storage Site

Assess Site-Specific Storage Risks

Characterise Geological Safeguards

Select Engineered Safeguards

Evaluate theseInitial Safeguards

Storage RisksSuitable?

Evaluate Monitoring Performance

Monitoring Performance Acceptable?

Adapt Monitoring Plans

Evaluate Storage Performance

Storage Performance Acceptable?

Implement Control Measures

MMV PlanPerformance Review

& Site ClosureSite Characterisation

yesno

Communication and Consultation

noyes

noyes

Site Closure

continue

continue

yes final

yes final

yesno


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2.1. Area of Review

MMV will operate within an Area of Review (AOR) which has sufficient extent to include the area of influence where there is potential for impacts due to CO2 storage including the displacement of brine. The initial AOR is equal to the initial Sequestration Lease Area (see Figure 2). Observed storage performance will be used to verify the size and shape of the AOR and, if necessary, the AOR will be updated as part of a revised MMV Plan submitted to regulatory agencies every 3 years.

2.2. Domains of Review

MMV will span four distinct environmental domains (see Figure 3). Geosphere: The subsurface domain below the base of the groundwater protection

zone including the BCS storage complex. The geological storage complex comprises a primary storage formation (Basal Cambrian Sands, BCS), a first seal (Middle Cambrian Shale, MCS), a second seal (Lower Lotsberg Salt), and an ultimate seal (Upper Lotsberg Salt). Above the storage complex, the geosphere also contains two addition deep saline aquifers, the Winnipegosis and the Cooking Lake, that provide potential opportunities for MMV. Proven oil resources exist within the Leduc, Nisku and Wabamun formations and proven gas resources within the Nisku, Mannville Group and Colorado Group.

Hydrosphere: The subsurface domain within the groundwater protection zone where water salinity measured as the concentration of total dissolved solids is less than 4,000 milligrams per litre. The Alberta Environment (AENV) Water Act defines saline groundwater as that containing greater than 4000 milligrams per litre (mg/L) total dissolved solids.

Biosphere: The domain containing ecosystems where living organisms exist. Atmosphere: The local air mass where any changes to air quality matter and the

global air mass where any changes influencing climate matter. The sequestration lease tenure for the Quest Project extends from the top of the Elk Point Group located just above the Prairie Evaporite to the basement.

2.3. Timeframe of Review

MMV activities will be adapted through time to meet the different requirements during five distinct phases of the Project lifecycle:

Pre-Injection Phase: Monitoring tasks are identified, monitoring solutions evaluated and selected, risks are characterized, and baseline monitoring data are acquired.

Injection Phase: Monitoring activities are undertaken to manage conformance and containment risks, and, if necessary, are adapted through time to ensure their continuing effectiveness.


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Closure Phase: In accordance with the Closure Plan2, some monitoring activities will continue during this phase to manage containment risk and to demonstrate storage performance is consistent with expectations for long-term secure storage. The duration of the closure phase before transfer of liability will be determined according to the strength of evidence obtained from the monitoring program that actual storage performance conforms to the predicted performance. Site closure activities will be executed including facilities decommissioning, pipeline abandonment and reclamation, and wells abandonment and reclamation (Figure 4).

Site Closure: Shell will apply for a Site Closure Certificate following the execution of site closure activities. Shell anticipates receipt of a Site Closure Certificate 10 years post injection cessation, provided there are no significant issues that arise from Project operations and that storage performance and CO2 and brine containment in the BCS storage complex are demonstrated to the satisfaction of the Crown in accordance with agreed criteria.

Post-Closure Phase: Closure certificate is acquired and liability transferred from Shell to Crown. The Crown may elect to continue some monitoring activities for reasons such as scientific research to understand long-term storage mechanisms for CO2 within the BCS formation.

2.4. Timeframe of Updates

The MMV Plan will be subject to annual performance reporting to the ERCB by the Quest Venture Regulatory Team with technical content prepared by the Quest Venture Subsurface Team, the Shell Canada Surveillance and Environmental Teamsi. If necessary, the MMV Plan will be adapted by the Quest Venture Subsurface Team in response to new information gained from:

Site-specific technical feasibility assessments Baseline measurements during the pre-injection period Monitoring during the injection and closure periods

Shell will provide an annual report on MMV performance and submit a revised MMV Plan to regulatory agencies every three years, coincident with the required submission of the Closure Plan2 to Alberta Energy.

2.5. WRM Standards

The MMV plan is to be considered as Quest CCS project-specific control, covering the global project control Well and Reservoir Management (WRM) Plan. WRM is designed to include all components of the asset, including capture facilities, pipelines, wells, and reservoir. Table

i APPENDIX 15 describes these accountabilities in detail.


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2 describes the mapping between mandatory elements of a WRM Plan and the MMV Plan. The capture facility and pipeline components are documented elsewhere4.

Table 2: Mapping between a WRM Plan and the MMV Plan.

WRM Mandatory Element MMV Plan Philosophy and approach Purpose of MMV (Section 2) Relevant regulatory, statutory and contractual/partner requirements MMV Design (Section 3) The key value drivers for life cycle asset value Purpose of MMV (Section 2) The key development decisions to be taken Contingency MMV plan and Residual Risks (Sections 8 and 9) The key uncertainties and opportunities to be managed Contingency MMV plan and Residual Risks

(Sections 8 and 9) The modeling and mapping strategy selected for the reservoir, wells and facilities and the integrated Asset

Updates of MMV plan and closure plan and Monitoring Performance Targets (Section 7)

The injection policy Project Description (Section 1) Data acquisition requirements Monitoring plan (Section 6) The technical/operational resources and capabilities required to carry out the WRM plan

Appendix 14

The testing, metering, sensing and control equipment considered critical to WRM

Monitoring Performance Targets (Section 7)

An estimate of the annual WRM budget, including operational budgets to carry out intervention and data acquisition activities

MMV Costs (Appendix 15)

The Planned WRM organisation and resources Appendix 14 The WRM processes that will be used. Which review will be done at what frequencies. Who will be responsible and accountable and who will contribute. This should be based on WRM practice table.

Appendix 14

The WRM KPIs that will be used for the Asset Table 10 The information and Data Management practices that will be used Appendix 13


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Figure 2: Location map of the Quest storage site.

15-29-60-21W4

7-11-59-20W4

SCL Radway 8-19-59-20W4

12-14-60-21W4

10-6-60-20W4

Imperial PLC Redwater 7-17

15-16-60-21W4

5-35-59-21W4

15-1-59-21W4

SCL Redwater 3-4

Imp. Eastgate No. 1-34

Imp. Egremont W 6-36

Imp. Clyde No. 1

SCLRedwater 11-32

Category 1: Does not penetrate through a major seal

Category 2: Penetrates through 1 or more major seals

Category 3: Penetrates through all 3 major seals

Scotford Upgrader

Approved Sequestration Lease AOI

Proposed Pipeline Route

Existing 3D Seismic

Lake

River

City/Town

Legacy Wells in BCS storage complex

Quest Proposed Project WellsAppraisal Wells – Penetrate all 3 seals but not legacy wells

Candidate Injection Well – drilled and penetrates all seals

Candidate Injection Wells – not drilled will penetrate all seals

Imp. Darling No. 1

Line of Section through 3D Petrel Model

SW

NE


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Figure 3: Cross section through the BCS storage complex and overlying geological formations. Figure 2 shows the location of this cross-section.

GEO

SPH

ERE

HYD

RO

SPH

ERE

(Not present in section)

Cretaceous Unconformity

SW NEATM

OSP

HER

E

Groundwater Protection Zone

Lea Park

Colorado Shale

Elevation amsl (m)

Stratigraphy

Vertical Exaggeration: x20


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Figure 4: Proposed timeline for site closure activities.


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3. MMV DESIGN

3.1. MMV Design Principles

The MMV Plan is designed according to the following principles that build on guidelines published by DNV5:

Regulatory-Compliance: The MMV Plan will comply with regulatory requirements as they mature.

Risk-Based: Monitoring tasks are identified through a systematic risk evaluation based on the collective expert judgment and validated independent experts. The scope and frequency of monitoring tasks depend on the outcome of this risk assessment. Project safeguards are implemented to reduce storage risks to as low as reasonably practicable.

Site-Specific: Monitoring technologies are selected for each monitoring task based on the outcome of site-specific feasibility assessments and then custom-designed to ensure optimal monitoring performance under local conditions particular to the storage site.

Adaptive: The performance of the storage site and the monitoring systems are continuously evaluated. Contingency Plans exist with clear trigger points for implementing control measures to ensure effective responses to any unexpected events.

3.2. MMV Design Process

MMV is central to the framework developed for storage risk management (Figure 1). There are three principle parts to this framework.

Site Characterisation: This is the initial risk assessment and implementation of initial safeguards through site selection, site appraisal, and engineering concept selections. The Directive 65 regulatory application2 describes the outcome of this process.

MMV: This provides an additional layer of risk assessment and implements additional safeguards through monitoring to verify the expected storage performance and, if necessary, trigger appropriate control measures.

Performance Reviews & Site Closure: Annual performance reviews provide a continuation of the risk management process during the injection and closure phases of the project to support site closure and transfer of long-term liability. The Closure Plan2 , Appendix E of the Directive 65 application describes this process in detail.

The MMV design process works within this risk management framework and starts after site selection by evaluating site-specific storage risks before proceeding to implement additional safeguards supported by monitoring in the following stepwise approach.


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1. Assess site-specific storage risks: Establish definitions for loss of conformance and loss of containment. Identify potential threatsi and consequencesii associated with these risk events.

2. Characterise geological safeguards: Identify and appraise the integrity of each geological seal within and above the storage complex.

3. Select engineered safeguards: Identify and assess the engineering concept selections that provide safeguards against unexpected loss of well integrity.

4. Evaluate these initial safeguards: Evaluate the expected efficacy of these initial safeguards in relation to the identified conformance and containment threats, and their potential consequences.

5. Establish monitoring requirements: Define monitoring tasks to verify the performance of these initial safeguards and, if necessary, trigger timely control measures.

6. Select monitoring plans: Select monitoring technologies according to a cost-benefit ranking where benefits are judged according to how effective each technology is at each task. This includes baseline monitoring as well as monitoring during the injection and closure phases.

7. Establish performance targets: Evaluate the expected monitoring capabilities. 8. Identify contingency monitoring: Develop alternative monitoring plans to replace any

under-performing monitoring system and establish clear criteria for when to implement these contingencies.

9. Identify control measures: Design interventions designed to reduce the likelihood or the consequence of any unexpected loss of conformance or containment. These include operational controls and updates to model-based predictions.

10. Evaluate these additional safeguards: Systematic evidence-based evaluation of the expected efficacy of the additional safeguards and demonstrate that storage risks are as low as reasonably practicable.

The structure of this document reflects these steps: Chapter 4 reviews storage risks before MMV (steps 1 to 4), Chapters 5 identifies the monitoring tasks (step 5), Chapter 6 describes the monitoring plans (step 6), Chapter 0 evaluates the monitoring performance targets (step 7), Chapter 8 provides contingency monitoring plans (step 8) and Chapter 9 identifies control measure and evaluates storage risk after MMV (steps 9 and 10).

i Possible mechanisms that could cause the occurrence of an unwanted event.

ii Possible adverse outcomes due to the occurrence of an unwanted event.


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3.3. Influences on MMV Design

Standards for MMV are still developing for Carbon Capture and Storage projects. The main influences on the MMV program for the Quest CCS Project are:

the existing regulatory environment a review of the existing global guidelines (see APPENDIX 1) knowledge-sharing with existing and developing projects (see APPENDIX 10)

Alberta’s existing regulations for the permitting and oversight of Acid Gas Disposal projects have proved effective for more than 40 schemes involving CO2 over the last 20 years. The ERCB intends to use the same processes for regulating any CCS projects in Alberta6,7, and these may be updated by the ongoing Regulatory Framework Assessment (RFA). Therefore, the Quest CCS Project MMV plan will use these existing standards as a minimum requirement and will comply with any additional requirements that may follow from the RFA process. There are many different directives applicable to Acid Gas Disposal in Alberta. The following directives are particularly relevant for MMV as they specify requirements for measurements and monitoring.

Directives 7 & 17: Specify requirements for measuring and reporting the amounts of acid gas injected.

Directive 20: Specifies minimum requirements for well abandonment, testing to detect leakage and mitigation measures in the event of detecting leakage.

Directive 51: Classifies injection and disposal wells according to the injected or disposed fluid and specifies design, operating, and monitoring requirements for each class of wells.

Directive 65: Addresses enhanced hydrocarbon recovery, natural gas storage and acid gas disposal. For acid gas disposal projects, this directive specifies requirements to ensure confinement of the disposed fluid and its isolation. This directive also requires the applicant to prove that disposal will not affect hydrocarbon recovery.

In addition, two existing CCS projects in Canada create important precedents for MMV: the Weyburn-Midale CO2 enhanced oil recovery project in Saskatchewan8 and Pembina Cardium CO2 enhanced oil recovery (EOR) project in Alberta9. Although injected volumes are substantially smaller, numerous Acid Gas Disposal projects in Alberta also provide important experience10. Outside Canada, there are four notable examples of commercial-scale CO2 injection projects with ongoing MMV activities: Sleipner and Snøhvit in Norway, In Salah in Algeria11, Rangely in the United States. See APPENDIX 10 for further details. Other commercial-scale CCS projects under development with more mature MMV plans include Gorgon in Australia and Goldeneye in the UK.


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4. STORAGE RISKS BEFORE MMV

This section reviews the assessment of storage risks after site selection and site characterisation but before the implementation of a MMV Plan. The scope of this risk assessment includes both conformance and containment risks. The method of this risk assessment relies on an evidence-based evaluation of the potential threats and consequences and the effectiveness of safeguards in-place. To provide the necessary context for these risk assessments, we begin by describing the storage site in more detail.

4.1. Storage Site Description

The Quest storage site is bounded laterally by the approved pore space AOI (Figure 2) and extends from the Precambrian basement to the surface (Figure 3) including the following key components.

The BCS Storage Complex: In ascending stratigraphic order, the BCS storage complex comprises the following formations (see also Table 3).

Precambrian basement: Basal bounding formation

BCS: CO2 injection zone

LMS: Baffle

MCS: The first major seal

Upper Marine Sand: Baffle

Lower Lotsberg Salt: The second major seal

Upper Lotsberg Salt: The third major (ultimate) seal

Geosphere: Above the BCS storage complex, the geosphere also contains numerous additional permeable formations and seals including, in ascending stratigraphic order, the following (see also Table 3 and Table 4).

Winnipegosis: Auxiliary storage

Prairie Evaporite: Major regional seal

Cooking Lake: Auxiliary storage

Leduc: Contains proven oil resources

Ireton: Major regional seal

Nisku and Wabamun Formations: Contains proven oil resources

Nisku, Mannville Group and Colorado Group: Contains proven gas resources

Hydrosphere: In ascending stratigraphic order, the following units each contain locally important aquifers above the base of groundwater protection3.

Foremost Formation of the Belly River Group: About 1,584 wells inside AOI

Oldman Formation of the Belly River Group: About 1,576 wells inside AOI

Surficial Deposits: About 2,165 wells inside AOI


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Biosphere: Land use in the area is primarily agricultural with some industrial and transportation corridors and small areas of natural vegetation.

Injection Wells: The Storage Development Plan12 allows for the phased development of between 3 and 8 injectors. The base case development plan includes 5 injectors with an opportunity to reduce to 3 injectors.

Exploration and Appraisal Wells: The Project drilled two exploration wells and one appraisal well:

Redwater 11-32: Exploration well located just outside the AOI,

Redwater 3-4: Exploration well located just inside the AOI

Radway 8-19: Appraisal well located close to the center of the AOI. This well is proposed to be used as a CO2 injector.

Legacy Wells: Figure 2 and Table 32 describe the legacy wells within the AOI.

BCS wells: Four abandoned wells penetrate the BCS inside the AOI.

Lotsberg wells: There are no legacy wells that penetrated the entire Lotsberg Salt inside the AOI other than the BCS legacy wells described above.

Winnipegosis wells: Two abandoned wells penetrate down to the Winnipegosis Formation inside the AOI with partial penetrations of the Upper Lotsberg Formation.

Viking wells: More than 3000 active and abandoned wells penetrate down to the Viking Formation inside the AOI.

Groundwater wells: Available records indicate there are more than 5300 wells drilled and completed within the groundwater protection zone.


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Table 3: Geological description of the BCS storage complex and the overlying Winnipegosis complex.

Formation Quest Name Type Composition and Depositional Environment

WPG

S C

ompl

ex

Elk

Poin

t Gro

up

Watt Mountain Seal

Top of the Elk Point Group represented by a thin (10m to 40m) green/greyish shale with thinly inter-bedded limestone units that overlie the sub-watt mountain unconformity. It is absent to the west and North of the study area because it is commonly mapped as part of the Muskeg Fm. which is equivalent to the Prairie Evaporite.

Prairie Evaporite

Ultimate Seal WPGS Complex

Regional Seal for the WPGS complex. The Prairie Evaporite is predominantly halite with thin anhydrite layers in middle and at base. There is a marked increase in dolomite and shale laminae near the base of the Formation. Within the AOI, the Prairie Evaporite increases in thickness from 80m to 145m towards the NE and acts as a regional aquiclude. There are no known hydrocarbons below this point within the AOI.

Winnipegosis Regional Aquifer

Fossiliferous carbonates decreasing in thickness towards the SE grading into the silty/sandy dolostone of the underlying Contact Rapids. The Winnipegosis-Contact Rapids regional aquifer is the first reliable aquifer above the BCS storage complex that can potentially be used for MMV purposes.

Contact Rapids

Contact Rapids/ Lower Winni-pegosis

Regional Aquifer / Baffle

Correlation between the Contact Rapids and overlying Winnipegoiss is poorly defined within the region and are therefore treated as one Regional aquifer. Within the heart of the AOI Contact Rapids is characterized by porous dolostone that transitions towards the basin edges to a grey to green, argillaceous dolomite and dolomitic shale, and towards the base of the section it grades to red shale. The porous intervals are referred to here as the Lower Winnipegosis. In the AOI there is good porosity within this zone as it is predominantly dolomite.

Cold Lake Seal Thin halite interval represented in the far eastern portion of the Quest AOI. Where it exists, it acts as an additional seal. In central Alberta it grades westward into red, dolomitic shale overlying the Ernestina Lake Formation which for this study were included in the Contact Rapids Formation.

Red Beds Devonian Red Beds 1

Baffle Devonian Red Beds confined to the Central Alberta Sub-Basin characterized by a thin 10m red dolomitic shale that merges at the basin margins with the other Devonian Reb Beds. Commonly stratigraphically described as the part of the Cold Lake Salts.

Ernestina Lake Baffle Anhydrite, light grey at top, underlain by light grey-brown, crypto-to-micro-grained limestone, locally anhydritic with salt plugged porosity.


Baffle Devonian Red Beds confined to the Central Alberta Sub-Basin characterized by a thin, maximum 11m red dolomitic shale that merges at the basin margins with the other Devonian Reb Beds. Only occurs in the lows of the underlying Lotsberg Salt. Equivalent to Elk Point Group, Member 6 in the CSPG Western Canadian Lexicon.

BCS

Stor

age

Com

plex

Lotsberg Upper Lotsberg Salt

Ultimate Seal

Almost pure halite that acts as an aquiclude, ranging in thickness from 53m to 94m across the AOI and thickening to 150m up-dip, NE of the AOI in the Central Alberta Sub-Basin.


Baffle

Devonian Basal Red Beds confined to the Central Alberta Sub-Basin. Basal Red Bed intervals exist between and below the Lotsberg Salts, merging at the basin margins together with the Devonian Red beds above. Brick red dolomitic or calcareous silty shale that grade downwards through to red sandy shale into greenish fine to coarse grained quartzose sandstone.

Lotsberg Lower Lotsberg Salt

2nd Major Seal

Almost pure halite that acts as an aquiclude, ranging in thickness from 9m to 41 across the AOI and thickening to 60m up-dip, NE of the AOI in the Central Alberta Sub-Basin.


Baffle

Devonian Basal Red Beds confined to the Central Alberta Sub-Basin. Basal Red Bed intervals exist between and below the Lotsberg Salts, merging at the basin margins together with the Devonian Red beds above. Brick red dolomitic or calcareous silty shale that grade downwards through to red sandy shale into greenish fine to coarse grained quartzose sandstone. This is the base of the Elk Point Group.

Upper Deadwood Upper Marine Silts

Baffle Flow baffle composed of greenish shale and minor silty and sandy interludes deposited in the offshore shelf in response to either an increase in sediment supply or a relative sea level fall. Absent in the Eastern part of the AOI due to the Pre-Cretaceous unconformity.

Lower Deadwood Middle Cambrian Shale

1st Major Seal

The first major seal composed of shale deposited in an offshore shelf environment associated with continued flooding of the basin. Present across the entire AOI ranging in thickness from 21m to 75m. The MCS is absent due the Pre-Cretaceous unconformity just to the NE of the AOI.

Earlie Lower Marine Sands

Baffle Regional flow baffle created by these transgressive, heterogeneous subtidal clastics representative of transition from marginal marine sediments of the BCS to the more distal environment of the MCS above. Present across the entire AOI.

Basal Sandstone Basal Cambrian Sands

CO2 injection zone

The BCS is transgressive sheet sand, deposited in a tide dominated bay margin, that acts as a basin-scale saline aquifer. Existing data internal and external to Shell indicates the BCS saline aquifer has suitable injectivity, capacity, and containment for CO2. The BCS is the primary target for the potential CO2 storage operation.

Precambrian Basement

Basal Bounding Formation

Cratonic basement on which the BCS unconformably lies on top of. Considered an aquiclude.


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Table 4: Geological description of the formations above Winnipegosis complex.

Formation Quest Name Type Composition and Depositional Environment

Hyd

ro-sp

here

Quaternary

Gro

undw

ater

Pro

tect

ion

Zone

Aquifer Pre-glacial channel fill deposits, glacial drift and other glacially derived sediments deposited above the bedrock surface.

Belly

Riv

er G

roup

Oldman Aquifer Belly River Group forms the uppermost bedrock in the region, and hosts aquifers above Base Ground Water Protection (BGWP). The Oldman Formation is composed of continental deposits of inter-bedded sandstone, siltstone, shale and coal. It sub-crops beneath the AOI.

Foremost Aquifer Marine and continental shale, with sandstone members forming regionally extensive aquifers. Distinctive coal-bearing zones also present (i.e. McKay and Taber coals). The Foremost sub-crops beneath portions of the NE and central areas of the AOI.

Geo

sphe

re A

bove

the

Win

nipe

gosis

Com

plex

Lea Park Seal

Medium to dark grey shale with minor amounts of silt deposited during a marine transgression. Based on estimated depth from Top Colorado to BGWP as specified by the Alberta Government in Deep Rights Reversion, the thickness ranges from 92m to 170m thinning towards the NE.

Col

orad

o G

roup

Colorado

Seal Thick, grey regional marine shale present across entire AOI with an average thickness of 134m.

2nd White Specks

Gas Reservoir & Seal

Calcareous mudstone deposited in a marine setting. The uppermost ~5m of the Second White specks is represented by a thin sandstone layer that is a gas reservoir in the central part of the AOI reaching porosities of up to 8%. The average thickness in the AOI is 67m.

Base Fish Scales Seal Abundant fish remains within finely laminated, generally non-bioturbated sandstone, siltstone

and shale. Within the AOI it is predominantly shale averaging 50m.

Viking

Oil and Gas Reservoir

Derived from Cordilleran erosion in the West. In the western portion of the AOI it is shallow shelf deposits with dominantly sandstone to the West and shale dominating towards the East. There is Viking Production in the AOI (Oil in the SW corner only) in a thin 2m sandstone at top of section that reaches porosities of 20%. Viking thickness averages 14m.

Joli Fou Seal Dark grey, non-calcareous marine shale with minor inter-bedded fine to medium grained sandstone deposited unconformably on top of the Upper Mannville. Major flooding surface that covered most of WCSB averaging a thickness of 21m.

Upp

er M

annv

ille Upper

Mannville

Man

nville

Gro

up

Baffle

Upper Mannville is predominantly shale with grey silt inter-bedded with fine-grained, moderately sorted, silty , sandstone with local coal seams deposited as part of a prograding deltaic sequence with sediment transport towards the N-NE transitioning upward to be more fluvial in nature. There is porosity within the sandstones portion of this heterogeneous interval. Exists across the entire AOI.

Glauconitic Sandstone

Gas Reservoir

Inter-bedded shale, siltstone, and fine-grained sandstones. The sandstones range from glauconitic to salt-and-pepper. Absent in the very N-NE of the AOI as the Wainwright Highlands were finally covered. Gas Production in the AOI, predominantly to the SW half of the AOI.

Low

er M

annv

ille

Ostracod Zone Baffle

Inter-bedded fine clastics and limestone. Predominantly composed of shale, siltstones and lenticular sandstones with locally occurring limestone representing deposition in a low-energy, brackish, subaqueous environment. Minor patchy porosity associated with sand lenses. Absent towards the NE of the AOI along the Wainwright Highlands (Devonian).

Ellerslie Gas Reservoir

Fluvial deposit of fine to medium grained quartz with chert sandstone with fairly good porosity deposited in the Edmonton Valley likely under brackish water conditions. Sediment transport towards the N-NW. Gas Production in AOI. Absent towards the NE of the AOI along the Wainwright Highlands (Devonian). Thickness of the Ellerslie inside the AOI reaches a maximum of 90m. depending on the unconformity and the presence of channel sands.

Win

terb

urn

Gro

up

Wabamun Gas Bearing

Characterized by Dolomite, brown, finely crystalline, porous in part; with subsidiary inter-beds of brown, micritic, pelloidal limestone. Only exists in the W-NW half of the AOI due to erosion by the sub-cretaceous unconformity. However, there is some gas production within the AOI. Thickness ranges from 0m to 100m.

Graminia Baffle A silt unit at the top of the Winterburn. Exists predominantly in the W-NW of the AOI. Thin and patchy across the rest of the AOI due to irregularities in the Pre-Cretaceous unconformity.


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Blueridge Gas Bearing

Last widespread carbonate cycle in Western Canada. Exists predominantly in the W-NW of the AOI. Exists predominantly in the W-NW of the AOI. Thin and patchy across the rest of the AOI due to irregularities in the Pre-Cretaceous unconformity. Has some minor porosity within the AOI. Production in the Eastern part of the AOI commonly mislabeled as Wabamun Production.

Calmar Baffle Predominantly silts and clays likely the result of reworking of the underlying lowstand Nisku siliciclastics. Exists predominantly in the W-NW of the AOI. Thin and patchy across the rest of the AOI due to irregularities in the Pre-Cretaceous unconformity.

Nisku Oil and Gas Reservoir

A mixed carbonate-siliciclastic deposited during a lowstand. Within the AOI the Nisku is a porous light brown to light grey crystalline dolomite with lesser amounts of brownish grey dolomitic siltstones, green shales and anhydrite. It is commonly truncated by the pre-Cretaceous unconformity. Within the AOl oil production is only above and to the West of the Redwater reef, some minor gas exists in the NE portion of the AOI. The Nisku has a relatively constant thickness of the AOI at 57m.

Woo

dben

d G

roup

Ireton

Ireto

n /

Gro

smon

t I&

II

Seal

Only the Lower Ireton exists in the AOI represented by a cyclic succession of basin filling shales considered to be a regional aquitard. The Lower Ireton is thin on top of the Leduc Reefs (~10m) and thickens to an average of 160m away from the reef. Grosmont Carbonates begin to appear within the Upper part of the Ireton to the East of the AOI.

Duvernay

Seal

Grades from a bituminous rich shale to a shale to a dolomite towards the NE of the Basin. Within the AOI represented by dark brown shale and limestones to the west and as you move towards 8-19 it is predominantly tight argillaceous limestone with shale interbeds. Relatively uniform thickness across basin (~160m) except it is absent over the Leduc Reefs.

Leduc

Oil Reservoir

Within the AOI is the Redwater Reef and the Morinville Reef trend associated with the Rimbey-Arc. The Morinville reef trend is a tight dolomitic structure except for a localized field just west of the Redwater reef called the fairydell-Bon Accord Field. In contrast, the Redwater pinnacle reef, is a major oil producing limestone and the focus for this study.

Majeau Lake Seal

In the AOI only the Lower Majeau Lake is present. Characterized by greenish grey and dark brown shale that are time equivalent to the Cooking Lake (West of and underlying the reef chain). Only exists to the West of the AOI.

Cooking Lake

Inter-mediate Aquifer

Major regional aquifer made up of extensive sheet like shelf carbonates and a equivalent basin-fill shale (Majeau Lake). Consists of peloidal and skeletal limestones (bracs, crinoids, stromatoporoids, bryzoans). Unlike most younger Woodbend carbonates it is predominantly undolomitized (except directly under the Leduc-Homeglen-Rimbey-Meadowbrook reef chain). The AOI is at the intersection of all three facies. There is a sharp edge to the West of the reef chain where the Cooking lake is non-existent, replaced by Majeau Lake, it is thickest under the reefs and then thins to the NE.

Beav

erhi

ll La

ke G

roup

Waterways

Mildred Baffle

The Firebug, Calmut, Christina, Moberly and Mildred Members make up the Waterways Formation deposited during a regressive basin fill phase of the Waterways Basin. Composed of a series of shallowing upwards shale-carbonate clinothem cycles deposited in a basin slope depositional setting. Each cycle is composed of a shale base that grades vertically to argillaceous carbonate. The Waterways and Slave Point are combined to form the Beaverhill Lake Group Aquifer System.

Moberly Inter-mediate Aquifer

Christina Baffle

Calmut Inter-mediate Aquifer

Firebag Baffle

Slave Point Slave Point Baffle

The Slave Point Fm. is a distinct, non-contemporaneous event from the Waterways Fm. above, deposited in a transgressive "reefal" phase dominated by restricted to open-marine carbonates. In the AOI Slave Point is a thin, limestone unit that contains some minor porosity. Although represented here as a baffle, on a regional scale it is included in the Beaverhill Lake Group Aquifer System.


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4.2. Initial Conformance Risks

4.2.1. Loss of Conformance Definition

A loss of conformance exists if: The observed distribution of CO2 and pressure build-up inside the storage complex

does not agree with model-based predictions within the range of uncertainty; or Knowledge of the actual storage performance is insufficient to distinguish between

two classes of possible future performance: those that result in permanent stable storage of the target mass of CO2 inside the BCS storage complex, and those that do not.

These criteria are taken from the agreed Closure Plan2.

4.2.2. Potential Consequences Due to a Loss of Conformance

A loss of conformance is not expected but if it does occur it may result in some of the following negative consequences:

Cost of additional monitoring activities required to re-establish conformance

Delay in site closure until long-term storage risks are understood to be acceptable

Loss of storage efficiency if CO2 plumes spread further than expected

4.2.3. Potential Threats to Conformance

There are two potential threats that may cause a loss of conformance: The original models are wrong due to unexpected geological heterogeneities, or incorrect

representation of the physical or chemical processes governing fluid transport, or insufficient

analysis of uncertainties within the models

The monitoring is wrong due to an unrecognised bias in either the acquisition, processing or

interpretation of monitoring data.

4.2.4. Initial Safeguards to Ensure Conformance

Prior to implementing MMV, several safeguards are already in-place to reduce the likelihood or consequence of any unexpected loss of conformance. These safeguards include:

Basin-scale screening studies ranked the top opportunities for geological storage of CO2 in

Canada. Selecting a site within the top-ranked region minimises the risk of complex geology

causing unpredictable storage behaviour.

Site selection was based on a feasibility study of the pre-existing appraisal data to reduce the

likelihood of insufficient injectivity, capacity or containment.

Site characterisation based on a dedicated and comprehensive appraisal program including 2D

and 3D seismic and an appraisal well at the center substantially improved the reliability of a


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broad range of subsurface models. These models will be updated in response to data acquired

from each development well.

The residual risk associated with the possibility of all these independent safeguards failing is judged to be low (see Table 5). For a more detailed description of conformance risk management please see APPENDIX 3.

Table 5: Classifications for describing the likelihood of an event.

Very Low Low Medium High Very High

0-5%

Occurs in almost no

projects (extremely unlikely)

5-20%

Occurs in some projects

(low but not impossible)

20-50%

Occurs in projects

(fairly likely)

50-80%

Occurs in most projects

(more likely than not)

80-100%

Expected to occur in every

project (almost certain)


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4.3. Initial Containment Risks

4.3.1. Loss of Containment Definition

Containment means that the injected CO2 and the native BCS brine remain inside the storage complex. Consequently a loss of containment is defined as:

A migration of CO2 or BCS brine into environmental domains above the Upper Lotsberg Salt that is the ultimate seal of the BCS storage complex.

This is a natural choice as it represents the top of the BCS storage complex. Prior to this event, the migrating fluids remain inside the intended geological formations. After this event, consequences due to loss of containment may arise if fluid migration continues upwards uncontrolled. Therefore, the MMV plan focuses on providing verification of containment and an early detection of any loss of containment.

4.3.2. Potential Consequences Due to a Loss of Containment

A loss of containment is not expected but it still represents a risk because if it does occur it may result in some of the following negative consequences:

Hydrocarbon resources affected due to a slight increase in the salinity or acidity of the

produced fluids

Groundwater impacts if sufficient quantities of CO2 or BCS brine migrate above the base of

groundwater protection to reduce groundwater quality.

Soil contamination if sufficient quantities of CO2 or BCS brine migrate into the soil to reduce soil

quality.

CO2 emissions into the atmosphere will reduce the effectiveness the Project’s contribution to

climate change mitigation.

4.3.3. Potential Threats to Containment

There are nine potential threats to containment identified. Each are considered unlikely but are, in principle, capable of allowing CO2 or BCS brine to migrate upwards out of the BCS storage complex:

Migration along a legacy well: Due to an insufficient number, thickness and depth of cement

plugs placed during abandonment or their subsequent degradation through time

Migration along an injector due to a poor or subsequently degraded cement bond or corrosion

of the casing and completion

Migration along an observation well: Any such wells drilled into the BCS storage complex pose a

threat similar to the injectors

Migration along a rock matrix pathway due to unexpected changes in the depositional

environment or erosional processes

Migration along a fault that extends out of the BCS storage complex and provides a permeable

pathway


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Induced stress reactivates a fault creating a new permeable pathway out of the BCS storage

complex

Induced stress opens fractures: Increased pressures and decreased temperatures may initiate

fractures that propagate vertically to create a new permeable pathway out of the BCS storage

complex

Acidic fluids erode geological seals: Injected CO2 will acidify formation fluids which may react in

contact with geological seals to locally enhance permeability within the seal

Third Party Activities may induce environmental changes that cannot be distinguished from the

potential impacts of CO2 storage that might trigger a perceived loss of containment from the

BCS storage complex

4.3.4. Initial Safeguards to Ensure Containment

Following extensive site characterisation, there are no known migration pathways for fluids to escape upwards out of the BCS storage complex. Prior to implementing MMV, several safeguards are already in-place to reduce the risk of any unexpected loss of containment due to an unknown migration pathway. There are two distinct types of safeguards: preventative measures that reduce the likelihood and corrective measures that avoid, mitigate or remediate the potential consequence of any loss of containment The preventative measures in-place include:

The first seal, the Middle Cambrian Shale provides a 20 to 55 m thick seal over the entire AOI.

The second seal, the Lower Lotsberg Salt provides a 10 to 35 m thick seal over the entire AOI.

The ultimate seal, the Upper Lotsberg Salt provides a 55 to 90 m thick seal over the entire AOI.

Geochemistry of the BCS brine is distinct from the brine found within shallower formations

providing strong evidence of no long-term fluid migration in or out of the storage complex.

Lateral separation of injectors from BCS legacy wells significantly reduces the chance of CO2 or

sufficient BCS pressure reaching these wells.

Multiple cement plugs seal the abandoned BCS legacy wells.

Multiple casing strings within the injectors provide three barriers against corrosion.

Chrome casing over the injection intervals provides additional corrosion resistance.

Cement placement along the entire wellbore of each injector creates the largest possible

cement barrier to fluids migrating upwards outside the casing.

Injection pressures will never exceed the measured pressure required to open fractures.

Mechanical barriers to vertical fracture propagation are provided by multiple clay-rich layers

within the LMS and larger compressive stresses within the first seal.

No faults across any of these geological seals are detectable on the 3D and 2D seismic data.

No recorded earthquakes indicates there is no current tectonic activity that might re-activate an

unknown fault.

Limited shear stress is induced inside the storage complex during injection which reduces the

likelihood of re-activating an unknown fault.


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Ductile creep within the Lotsberg Salts are likely to reseal any fault or fracture unexpectedly

induced by CO2 storage.

Acidic fluids cannot erode either Lotsberg Salt Formation which are made of pure halite that

does not react with CO2 saturated brine.

The corrective measures in-place include: The Winnipegosis provides a major auxiliary storage formation able to dissipate pressures

and store CO2 or BCS brine.

The Prairie Evaporite is a major regional seal, 100 to 150 m thick over the entire AOI.

The Beaver Hill Lake Group provides multiple baffles to inhibit vertical migration of fluids.

The Cooking Lake provides another major auxiliary storage formation, able to dissipate

pressures and store CO2 or BCS brine. This is the most likely auxiliary storage formation

because it already has some pressure depletion due to nearby production.

The Ireton seals the Redwater Reef Oil field, is about 10 m thick above the reef, and about

90 m thick elsewhere within the AOI including above the injection zones.

The Mannville Group offers auxiliary storage capacity within multiple producing clastics

reservoirs

The Colorado Group is a proven seal for the hydrocarbon accumulations

The Lea Park is a marine shale with a lateral extent greater than the AOI and a thickness of

about 120 m at Radway 8-19.

The residual likelihood of all these multiple independent safeguards failing is judged to be very low (see Table 5). Figure 5 provides a summary of the relationship between all these threats safeguards and consequences. For a more detailed description of containment risk management please see APPENDIX 4.


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Figure 5: Summary of the safeguards in place to reduce the likelihood (left side) and consequence (right side) of any unexpected loss of containment. The additional

active safeguards are supported by the monitoring plan (Section 6) and control measures (Section 9).

LegendPassive safeguards; these are always present

Active safeguards, these are only present when a decision to

intervene is made triggered by monitoring information


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5. MONITORING TECHNOLOGY SELECTION

Monitoring technologies are selected for inclusion in the MMV Plan according to a cost-benefit analysis. Monitoring costs are estimated according to current unit costs and a monitoring frequency appropriate for each individual technology. Monitoring benefits are estimated according to the expected effectiveness of each monitoring technology at each monitoring task. The identified monitoring tasks are risk-based and designed to verify the effectiveness of the passive safeguards described previously and if necessary to trigger the timely deployment of active control measures, such as reducing or stopping injection, to reduce the risk of a loss of conformance or containment.

5.1. Monitoring Performance Targets

In accordance with the Closure Plan2, the monitoring performance targets are defined as follows.

CO2 Inventory Accuracy Target

The accuracy of the reported CO2 stored will comply with regulations and protocols.

Conformance Monitoring Targets

Observed storage performance conforms to predicted storage performance within the

range of uncertainty.

Knowledge of actual storage performance is sufficient to distinguish between two

classes of possible future performance: those that result in permanent stable storage of

the target mass of CO2 inside the BCS storage complex, and those that do not.

Containment Monitoring Targets

Measurements of any changes within the hydrosphere, biosphere, and atmosphere

caused by CO2 injection are sufficient to demonstrate the absence of any significant

impacts as defined in the Environmental Assessment3.

Measurements of any changes within the geosphere, hydrosphere, biosphere, and

atmosphere caused by CO2 injection are sufficient to trigger effective control measures

to protect human health and the environment.

5.2. Monitoring Tasks

The monitoring tasks identified to fulfil these monitoring targets are: Monitor CO2 plume development inside the storage complex

Monitor pressure development inside the storage complex

Monitor legacy well integrity

Monitor injection well integrity

Monitor geological seal integrity

Monitor for any hydrosphere impacts

Monitor for any biosphere impacts


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Monitor for any CO2 emissions into the atmosphere

This list does not include monitoring to determine the contribution of individual storage mechanisms such as structural, capillary, solution, and mineralisation trapping. This is not part of the conformance monitoring target because there is no evidence that any one mechanism is any less secure than another within the BCS storage complex. The relative contribution of these trapping mechanisms should not impact the transfer of liability which depends on a demonstration of containment and conformance.

5.3. Monitoring Technologies

More than 50 candidate technologies are considered including many geophysical, geochemical, in-well and surface monitoring methods. The expected effectiveness of each monitoring technology at each monitoring task is evaluated using a systematic evidenced-based logic approach that relies on collective expert judgement. The outcome of this evaluation is summarised in a cost-benefit ranking (Figure 6). Following this ranking, the notable regrets from the base-case monitoring plan are:

Multiple BCS observation wells: Time-lapse seismic and InSAR are more effective at

conformance monitoring.

Surface gravity monitoring due to insufficient sensitivity to monitor conformance or

containment monitoring.

Surface microseismic monitoring due to insufficient sensitivity to monitor containment.

Surface electromagnetic monitoring methods due to insufficient sensitivity for

conformance or containment monitoring.

GPS for surface displacement monitoring as InSAR is equally effective and lower cost.

Several actions are ongoing to reduce key uncertainties about the expected performance of key monitoring technologies included in the base-case plan.

Time-lapse seismic repeatability is expected to be sufficient to monitor the CO2 plumes,

but uncertainty remains due to the site-specific sources of noise that might limit

repeatability. Seismic repeatability tests are ongoing around the Radway 8-19 well and

preliminary results are in-line with expected feasibility of time-lapse seismic monitoring.

InSAR monitoring of surface displacements depends on the number, distribution, and

reliability of features in the landscape able to scatter InSAR signals back to the InSAR

satellite. Ongoing data acquisition and feasibility studies are encouraging.

Line-of-sight CO2 gas flux monitoring is a novel application of existing technology. A field

trial is being prepared for deployment on the Radway 8-19 well pad before the end of 2011.

For a more detailed description of the evaluation of monitoring technologies please see APPENDIX 5 and APPENDIX 7.


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Figure 6: Ranking of monitoring technology options according to expected benefits and costs. Colours denote the difference between the benefit and cost rankings as an

indicator of value.


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6. MONITORING PLAN

This section describes the type, frequency and coverage of monitoring activities included in the base-case monitoring plan for the wells and the storage complex. Subsequent chapters describe the expected performance of these monitoring technologies (Chapter 0) and the contingency plans (Chapter 8) in case these are not realised.

6.1. Monitoring Schedule

The monitoring schedule allows for multiple independent monitoring systems with comprehensive coverage through time and across the AOR within each of the environmental domains (Table 6, Table 7, Figure 7). The diversity of monitoring technologies mitigates the risk of any one technology failing.

Table 6: Summary of the monitoring plan for the geosphere, hydrosphere, biosphere and atmosphere.

Monitoring Coverage Pre-Injection Injection Closure

Atmosphere

Line-of-sight CO2 gas flux monitoring a Within 6 km of every injector Continuous Continuous Continuous

Biosphere

Remote Sensing a Entire AOR Twice a year Twice a year

Twice a year

Soil monitoring Discrete locations across the AOR Every year Every year Every 2 years

Natural BCS brine tracer monitoring Discrete locations across the AOR Every year Every year Every 2 years

Artificial tracer monitoring Discrete locations across the AOR Every year Every year Every 2 years

Hydrosphere

Down-hole pH monitoring a Project groundwater wells Continuous Continuous Continuous

Down-hole electrical conductivity monitoring a Project groundwater wells Continuous Continuous Continuous

Natural tracer monitoring a Project and Private groundwater wells At least every year Every year Every 2 years

Artificial tracer monitoring Project and Private groundwater wells At least every year Every year Every 2 years

Geosphere

Time-lapse 3D vertical seismic profiling a, b Within 600 m of every injector 2013 2016 2018

None

Time-lapse 3D surface seismic a Each entire CO2 plume 2010 2022 2029 2039

2048

Interferometric Synthetic Aperture Radar a Entire AOR Monthly Monthly Monthly

a A commitment made in response to Supplement Request for Information. b Baseline data will be acquired using conventional down-hole geophones and the DAS system, subsequent surveys will

be acquired with the DAS system only.


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Table 7: Summary of the monitoring plan for deep observation wells and CO2 injectors.

Monitoring Pre-Injection Injection Closure

WPGS Observation Wells

Down-hole pressure-temperature monitoring c None Continuous Continuous

Down-hole microseismic monitoring (8-19 well pad only) None Continuous None

Cement bond log Once None None

BCS Observation Well

Down-hole pressure-temperature monitoring None Continuous Continuous

Cement bond log Once None None

Injectors

Well-head pressure-temperature monitoring b None Continuous Continuous

Time-lapse ultrasonic casing imaging Once Every 5 years Every 10 years

Time-lapse electromagnetic casing imaging Once Every 5 years Every 10 years

Time-lapse casing calliper logs Once Every 5 years Every 10 years

Mechanical well integrity testing (packer isolation test)a and tubing calliper log

Once Every year Every 3 years

Injection rate monitoring b None Continuous None

Distributed temperature sensing c None Continuous Continuous

Down-hole pressure-temperature monitoring None Continuous Continuous

Distributed acoustic sensing None Continuous Continuous

Cement bond log Oncea Every 5 yearsb Every 5 years

Annulus pressure monitoring b None Continuous Continuous

Artificial tracer injection None Quarterly None

Routine well maintenance d Every 6 months Every 6 months Every 6 months

a A D51current regulatory commitment for Class III wells. b A possible future D51 regulatory commitment for Class III wells (current requirement for Class I wells). c A commitment made in response to Supplement Request for Information. d A maintenance task related to the wells, included in this table for completeness.


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Figure 7: This diversified monitoring program eliminates dependence on any single monitoring technology. For a more detailed version please see APPENDIX 16.

Pre-Injection Injection Closure Post-ClosureAtmosphere Line-of -Sight CO2 Flux Monitoring

Biosphere Remote sensing, Brine & CO2 Tracer Monitoring

HydrosphereGroundwater Monitoring Wells: Water Electrical Conductivity, pH, Brine & CO2 Tracer Monitoring

Landowner Water Wells: Brine & CO2 Tracer Monitoring

Wells: Monitors

WPGS Observation Wells: Down-Hole Pressure & Temperature

WPGS Observation Wells: Down-Hole Microseismic Monitoring

BCS Observation Well: Down-Hole Pressure & Temperature

Wells: Injectors

Injection Rate Metering, Tracer Injection

CBL, USIT

GeosphereINSAR

Time-Lapse 3D VSP

Time-Lapse 3D Surface Seismic

Down-Hole Pressure & Temperature, Distributed Temperature Sensing, Distributed Acoustic

Sensing, Annulus Pressure Monitoring, Wellhead Pressure & Temperature,

Wellhead CO2 sensor, Mechanical Well Integrity Testing, Operational Integrity Assurance


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6.2. Monitoring Coverage

The coverage of most monitoring systems is centered on, or confined to, one of the several different types of Project wells (Table 6, Table 7). The number and location of these Project wells (Table 8, Figure 8) depends on the number of injectors required according to the phased Storage Development Plan12. The coverage expected from each monitoring system varies considerably – some cover the entire AOI, whilst others cover regions of varying distance from each injector (Figure 9, Figure 11).

6.2.1. Observation Wells within the Basal Cambrian Sands Formation

The existing appraisal well, Redwater 3-4, located towards the southern boundary of the AOI, is proposed to be the only direct observation point within the BCS besides the injectors. The reason for this choice is that additional BCS observation wells provide insufficient benefits to justify the incremental costs and containment risks relative to alternative monitoring methods such as time-lapse seismic and InSAR. The perceived benefits are limited because BCS observation wells have no ability to verify containmenti and are ineffective at conformance monitoring unless used in large numbers. Moreover, drilling a BCS observation well to measure geochemical reactions and calibrate the trapping mechanism is of limited value because these are expected to be negligible within the BCS and, if necessary, may be measured by logging injection wells during the closure period. For example, one BCS observation well per injector would be insufficient to map the CO2 plume geometry as it will only provide information about the CO2 front at one time in one location. To provide conformance information comparable to time-lapse seismic requires several BCS observation wells per plume. The option of locating one or more BCS observation wells within a single CO2 plume to validate and calibrate the time-lapse seismic response was also rejected due to the expectation of insufficient benefits to justify the incremental costs and containment risk. Time-lapse seismic is expected to image the CO2 plume geometry with a lateral resolution of 25 to 50 m. This is difficult to calibrate with an observation well because in-well logging techniques are not sensitive to saturation distributions on this scale and narrow sand bodies may channel the CO2 towards or around the well. Moreover, time-lapse seismic is routinely used for Well and Reservoir Management without the need for calibration by observation wells because the failure case is easily recognised as an image dominated by incoherent noise. The benefits of multiple BCS observation wells located outside the expected CO2 plumes to monitor pressure conformance are also limited compared to the value of information expected from InSAR that provides low-cost coverage of the entire AOR and will be calibrated by BCS pressure measurements within every injector and the existing Redwater 3-4 well. i Monitoring inside the storage complex provides no ability to detect fluids migrating outside the complex.


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The option to drill BCS observation wells is retained under contingency plans (section 8) in case time-lapse seismic or InSAR monitoring performance falls short of requirements.

6.2.2. Observation Wells within the Winnipegosis Formation

The prime role of the three WPGS observation wells is to support pressure monitoring to verify containment. The phased Storage Development Plan provides for drilling 3, 4 or 5 injectors prior to start-up in order to ensure sufficient injectivity. In the case of:

3 injectors, one WPGS observation well will be located on each injection well pad. 4 injectors, these 3 WPGS observation wells will be located on the well pads of the

3 injectors expected to have the smallest injectivity according to existing appraisal data. This is a risk-based choice as these three locations are expected to develop greater BCS pressures. This initial choice is based on the expectation that all injectors will achieve the same cement bond quality. If cement bond logs show this not to be the case, then this choice will be revised to include injection wells judged to be at slightly higher risk due to pressure and cement bond quality.

5 injectors, these 3 WPGS observation wells will be located on the well pads of the central 3 injectors. Again, this is a risk-based choice as these injectors are expected to develop greater BCS pressures due to pressure support from their many neighbouring injectors. Furthermore, this choice may be revised in response to unexpected differences in cement bond quality between these 5 injectors.

In addition to the pressure monitoring, one of these WPGS observation wells will be instrumented with a conventional permanent down-hole geophone array to support microseismic monitoring up to 600 m away. This again is a risk-based choice. The selected well, depends on the number of injectors to ensure it will monitor that part of the BCS storage complex expected to develop some of the greatest pressures. Contingency plans exist to revise this selection based on the results of water injectivity tests for each injector that will be completed prior to drilling the WPGS observation wells. The base-case monitoring plan does not include a WPGS observation well for every injector because the network of three observation wells described above is judged to be sufficient to verify containment. Contingency plans exist to increase the number of WPGS observation wells and microseismic monitoring systems, in the unexpected event that pressure or microseismic monitoring indicates the appearance of an increased threat to containment (Chapter 8).

6.2.3. Project Groundwater Wells

Three Project groundwater wells will be drilled per injector. One of these Project groundwater wells will be located within 50 m of each injector and each abandoned BCS


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legacy well inside the AOI. This is a risk-based choice as these are all the known locations of potential migration pathways from the BCS storage complex within the AOR. However, due to the presence of multiple independent safeguards the likelihood of fluids migrating out of the BCS storage complex along any these pathways is very low. The proximity of these groundwater wells to unlikely but potential leak paths will provide monitoring to verify containment and, in the event of an unexpected migration of fluids along one of these pathways, will provide an early warning to trigger effective control measures. The remaining Project groundwater wells will be located elsewhere within the AOI following consultation with the local municipal authorities during Q3-Q4 2011. The lateral offset of these groundwater wells from the injectors or BCS legacy wells is sufficiently small to ensure effective groundwater monitoring regardless of the direction of local groundwater flow. These wells will be drilled down to 140 m below the surface and will be screened for monitoring within the most permeable zone that possesses a competent basal shale and is located above the base of groundwater protection.

Table 8: The number and location of Project wells that support the MMV plan depend on the development scenario.

3 Injectors 4 Injectors 5 Injectors 8 Injectors

Injectors 8-19-59-20W4

7-11-59-20W4

5-35-59-21W4

8-19-59-20W4

7-11-59-20W4

5-35-59-21W4

15-16-60-21W4

8-19-59-20W4

7-11-59-20W4

5-35-59-21W4

15-16-60-21W4

10-6-60-20W4

8-19-59-20W4

7-11-59-20W4

5-35-59-21W4

15-16-60-21W4

10-6-60-20W4

15-1-59-21W4

15-29-60-21W4

12-14-60-21W4

BCS Observation Wells Redwater 3-4 Redwater 3-4 Redwater 3-4 Redwater 3-4

WPGS Observation Wells 1 well on each of these 3 well pads:

8-19-59-20W4*

7-11-59-20W4

5-35-59-21W4

1 well on each of these 3 well pads:

8-19-59-20W4

5-35-59-21W4*

15-16-60-21W4


8-19-59-20W4

5-35-59-21W4*

10-6-60-20W4


8-19-59-20W4

5-35-59-21W4*

15-16-60-21W4

Project Groundwater Wells 9 wells in total

3 next to injectors

4 next to legacy wells

2 inside AOI

12 wells in total

4 next to injectors


4 inside AOI

15 wells in total

5 next to injectors


6 inside AOI

24 wells in total

8 next to injectors


12 inside AOI

*Denotes the single WPGS observation well equipped with down-hole geophones for microseismic monitoring.


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Three distinct types of injection well pads are required to support the MMV Plan. These are characterised by the different wells present on each type of well pad:

Type 1: Includes: Injection well Project groundwater well

Type 2: As Type 1, but also includes: WPGS observation well with down-hole pressure monitoring

Type 3: As type 2, but also includes: Down-hole microseismic monitoring within the WPGS observation well

Table 9 describes the allocation of these injection well pad types under the different development scenarios. In addition to these, the Redwater 3-4 well pad requires conversion from an exploration well to a BCS observation well with support for continuous pressure monitoring.

Table 9: The type of well pad required at each injector location depends on the development scenario.

Development Scenarios

3 Injectors 4 Injectors 5 Injectors 8 Injectors

Type 3 Type 2 Type 2 Type 2 8-19-59-20W4

Injection Well Pads



Type 2 Type 1 Type 2 15-16-60-21W4

Type 2 Type 1 10-6-60-20W4

Type 1 15-1-59-21W4

Type 1 15-29-60-21W4

Type 1 12-14-60-21W4

6.2.4. Landowner Groundwater Wells

Access to landowner groundwater wells will greatly increase the coverage of the groundwater well monitoring network. However, this is contingent on permission from the landowner and the condition of the well. The landowner groundwater wells proposed for inclusion in the monitoring program include every landowner groundwater well within 3.2km (2 miles) of each injector and abandoned BCS legacy well inside the AOI. Additional landowner groundwater wells are also proposed elsewhere to ensure a minimum of one within each township inside the AOI (Figure 12).


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Figure 8: Maps showing the location of observation wells for the different development scenarios. Coordinates show

kilometres in the NAD27 UTM Zone 12N datum.


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Figure 9: Maps showing the coverage of different monitoring methods for the base-case scenario. Coordinates show meters in the NAD27 UTM Zone 12N datum.

Legend DHPT – Down-hole pressure-temperature monitoring within a deep observation well MIA – Remote sensing Multi-Spectral Image Analysis OBG – Project groundwater observation wells VSP3D – Time-lapse 3D Vertical Seismic Profile surveys DHMS – Down-hole microseismic monitoring within a deep observation well INSAR – InSAR measurements of surface displacements to monitor BCS pressure changes LOSCO2 – Line-of-sight CO2 flux monitoring SEIS3D – Time-lapse 3D surface seismic monitor surveys; transparent green box denotes baseline CO2 – Expected maximum CO2 plume radius after 25 years injection OBB – BCS observation well Legacy wells – Abandoned wells that penetrate the BCS OBL – Landowner groundwater wells


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Figure 10: As Figure 9, but focused on the coverage of monitoring around each injector.


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Figure 11: Schematic cross-section showing the expected coverage of different monitoring methods for the base case development scenario of 5 injectors. See Figure 9 for the location of this cross-section and an explanation of the legend.


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Figure 12: Distribution of landowner water wells proposed for inclusion in the groundwater monitoring network.

<<Update AOI polygon>>


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7. MONITORING PERFORMANCE TARGETS

This section describes the expected capabilities of each selected monitoring technology and sets monitoring performance targets based on the outcome of technical feasibility assessments. For more details about these assessments, please see APPENDIX 7.

7.1. Performance Targets for Conformance Monitoring

7.1.1. Monitoring CO2 Plume Development

Time-lapse seismic (VSP3D, SEIS3D) will be used to monitor the development of the CO2 plume inside the BCS storage complex. Repeat seismic surveys are expected to yield an image of the CO2 plume geometry around each CO2 injector. CO2 entering the pore space within the Basal Cambrian Sandstones will replace some of the brine. Because the injected CO2 is much more compressible than brine, the speed of seismic p-waves traveling through the BCS will be reduced in those places containing CO2 and will remain unchanged elsewhere. Differences in seismic images of the BCS obtained before and during CO2 injection will arise due to the presence of CO2 in two characteristics ways:

Travel-time across the BCS will become longer (c. 8%) due to the slower p-wave velocity inside the BCS. Reflections from the base of the BCS will become stronger (c. 8%) as the impedance contrast with the underlying granite basement increased. The contribution of bulk density changes is negligible.

Increases in CO2 saturation of up to 5 or 10% of the pore-space cause significant velocity reductions (c. 8%) but thereafter additional CO2 within the same pore-space causes very little additional velocity change. Consequently, time-lapse seismic is expected to monitor the shape of the CO2 front but not the distribution of CO2 saturation inside the plume. Evaluation of seismic data acquired during the appraisal period and site-specific feasibility studies indicated CO2 will be detectable in those places where CO2 fills at least 5% of the pore-space and the thickness of a contiguous CO2 plume exceeds 5 m. The expected lateral and vertical resolution of the CO2 plume geometry are 25 m and 10 m respectively. This expected sensitivity and resolution is based on a typical amount of non-repeatable noise being present within the two land seismic images. Observed monitoring performance during the injection period will be used to validate and, if necessary, update these values. New borehole seismic recording technology using distributed acoustic sensing along a permanent fibre optic system inside each injector provides an opportunity to acquire time-lapse VSP data on demand without the cost or risk associated with well interventions to deploy a conventional temporary geophone array. Based on successful field trial results at Radway 8-1913 this technology is included in the base-case monitoring plan and conventional VSP surveys are retained in the contingency monitoring plans.


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7.1.2. Monitoring Pressure Development

Down-hole pressure gauges (DHPT) will be used to ensure down-hole injection pressures do not exceed their agreed maximum values. This is a mature industry standard technology and any failed gauge will be replaced during a scheduled well work-over.

Down-hole pressure gauges and InSAR (DHPT, INSAR) will be used to monitor the development of fluid pressure inside the BCS storage complex at and away from the injectors. Continuous pressure measurements will be made inside the BCS within every injector and a dedicated observation well, Redwater 3-4, located just inside the southern edge of the sequestration lease area. These gauges will provide accurate direct measurements of pressure changes at these discrete locations. InSAR will provide monthly measurements to indicate the areal distribution of BCS pressure changes between the gauge locations and across the entire sequestration lease area.

InSAR is a satellite remote sensing method designed to map even the smallest displacements of the Earth’s surface. Pressure increases expected inside the BCS storage complex will cause the BCS and LMS to increase in thickness by 1 to 10 mm per MPa. This small deformation at depth results in a smaller and smoothly distributed displacement of the Earth’s surface. These displacements are so small that they can only be detected by very sensitive instruments specifically designed for this purpose. The moment CO2 injection stops, pressures inside the BCS will begin to relax and surface displacements will begin to reverse. Evaluation of data acquired during the appraisal period and site-specific feasibility studies indicate InSAR will measure surface displacements with a precision of 1-2 mm/yr. This allows temporal pressure changes of 0.1 to 1 MPa to be detected and spatial pressure changes to be mapped with a lateral resolution of 1 to 3 km. This is sufficient to delineate the region subject to a pressure increase sufficient to lift brine above the base of groundwater protection (c. 3 MPa). Observed monitoring performance during the injection period will be used to validate or update these values.

7.2. Performance Targets for Containment Monitoring

The containment monitoring system is designed to: Verify the continuing containment of fluids inside the BCS storage complex Verify the absence of any adverse environmental effects due to CO2 storage Provide early warning should fluids migrate out of the BCS storage complex

To ensure the necessary reliability this monitoring capability is provided by many independent technologies intended to detect change above the BCS storage complex.


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7.2.1. Monitoring Legacy Well Integrity

Down-hole pressure gauges and InSAR (DHPT, INSAR) will monitor the lateral extent of pressure changes inside the BCS14 to indicate that any pressure increase at the location of abandoned BCS legacy wells remains insufficient to lift BCS brine above the base of groundwater protection even if the legacy well unexpectedly provides a permeable pathway out of the storage complex.

7.2.2. Monitoring Injection Well Integrity

Mechanical Well Integrity Testing, which consists in annually pressure testing the packer for 10 minutes at a minimum pressure of 7 MPa (as per Directive 51 for Class I wells, which is the most conservative. Class III wells only required 1.4 MPa). In addition to this regulatory requirement, it is proposed to add a calliper survey to measure any potential corrosion of the tubing.

Corrosion coupons at the injection skid to confirm the dehydration specs are being adhered to and corrosion is not occurring in the pipeline and wellbore completion.

Routine well maintenance, which consists in regular (every 6 months) maintenance of the wellhead valves(not a regulatory requirement but a standard Shell practice) and the measurement of the pressure on the different casing annuli.

Cement Bond Logs, Ultrasonic Casing Logs and Electromagnetic Casing Logs (CBL, MWIT, USIT, EMIT) will verify the initial integrity of the cement bond and well completion along the entire length of each injector. These will be re-acquired every 5 years during the injection period to verify continuing cement bond, casing and tubing integrity. Although it is not currently a regulatory requirement for Class III injection well, hydraulic isolation logging every 5 years could be required by the authorities in the future (as per Directive 51 Class I wells).

Hold Up Depths (HUD) should be measured at every wire-line entry in a well, and every 5 years before the CBL/MWIT/USIT/EMIT logs are run, to ensure no plugging exists across the perforation interval.

Distributed Temperature Sensing (DTS) along an optical fibre permanently deployed from the surface down to the first seal on the outside of the intermediate casing will provide a continuous means on verifying cement bond integrity and the absence of CO2 outside the casing. In the unexpected event of a loss of cement bond integrity, any upward migration of CO2 outside the casing will lower the temperature on the adjacent portion of the DTS fibre due to increased thermal insulation from the in-situ formation temperature provided by the out-of-place CO2. Evaluation of data acquired at Radway 8-19 during the appraisal period and a site-specific feasibility study15 indicate DTS will detect temperature changes with a precision of 0.1 degrees Celsius and a vertical resolution of 1 m. This allows detection a CO2 flux of at least 10 kg/day through a micro-annulus within the


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external cement bond. Observed monitoring performance during the injection period will be used to validate or update these values. A static blanket of CO2 cannot be directly distinguished from a flux of CO2 outside the casing. However, a flux may be inferred in the case the temperature anomaly extends upwards to but not beyond a permeable formation.

Distributed Acoustic Sensing (DAS) along an optical fibre deployed alongside the DTS fibre will provide continuous independent means of verifying cement bond integrity and the absence of fluid flow outside the casing. In the unexpected event of a loss of cement bond integrity, any upward migration of fluids outside the casing will generate acoustic noise that reaches the adjacent portion of the DAS fibre. Evaluation of data acquired at Radway 8-19 during the appraisal period and site-specific feasibility studies indicate DAS will detect changes in the magnitude of acoustic noise with a vertical resolution of 1 to 5 m. This should allow detection of a fluid flux through a conduit within the external cement bond. Observed monitoring performance during the injection period will be used to validate or update these values. Acoustic noise due to flow through a micro-annulus is readily distinguished from microseismic events as the former is continuous and ubiquitous along the affect portion of the well whilst the latter are episodic with distinct p- and s-wave arrivals that travel along the fibre.

7.2.3. Monitoring Geological Seal Integrity

Deep observation wells will be drilled from 3 of the injection well pads and completed within the first major permeable zone above the BCS storage complex.

Continuous pressure measurements (DHPT) within the deep observation wells will provide a means of detecting any unexpected migration of injected CO2 or brine out of the BCS storage complex. Within the Winnipegosis Formation, just 6 kg/day of fluid migration into this deep formation will likely cause a detectable sustained pressure rise16. The time to detection depends on the distance through the permeable formation between the fluid entry point and the pressure gauge. A fluid entry point will likely be detected within 5-20 days if located within 1 km of the pressure gauge, and 100-300 days for 3.5 km. These monitoring wells will be drilled from 3 injection well pads (Table 8) selected, based on risk, according to which injectors are expected to develop the greatest pressures inside the BCS. The target monitoring zone is the Winnipegosis Formation (1800 m deep) which is expected to transmit pressure changes over sufficient distances and to experience no other sources of notable pressure change. However, should the Winnipegosis Formation prove insufficient for pressure monitoring, the Cooking Lake Formation (1200 m deep) may provide a suitable alternative; although there are potential complications due to the gaining the necessary regulatory permissions and the ongoing regional pressure depletion.


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Time-lapse seismic (VSP3D, SEIS3D) will be used to verify the absence of CO2 above the ultimate seal of the BCS storage complex. Any CO2 unexpectedly entering the Winnipegosis Formation, or other overlying permeable formation, will affect the seismic image due to the same physical effects previously described for CO2 entering the BCS (Section 7.1.1). Due to different formation properties and different in-situ temperature and pressure conditions that affect the properties of CO2, the magnitude of anticipated time-lapse seismic changes in the unexpected event of CO2 entering these formations varies. CO2 saturation exceeding 5 to 10% is expected to reduce the velocity of seismic p-waves by c. 6% within the Winnipegosis Formation and 3% within the Cooking Lake Formation. The expected acoustic impendence changes by c. 7% and c. 4% within these two formations respectively. Seismic modeling studies indicate this velocity reduction will likely be detectable within time-lapse seismic images for a contiguous CO2 plume of at least:

Winnipegosis Formation: 10 m thick and a lateral extent of at least 100-200 m Cooking Lake Formation: 10 m thick and a lateral extent of at least 100-200 m

For an assumed average CO2 saturation of 20-40% within such a CO2 plume, this corresponds to an expected detection limit of 100,000 to 60,000 tonnes of CO2. This expected sensitivity is based on a typical amount of non-repeatable noise being present within the two land seismic images. Additional information about formation properties gained by logging each injection well and reconciliation of observed and predicted monitoring performance will be used to validate or update these values.

Microseismic (DHMS) monitoring using a conventional down-hole array with 8 levels of three-component geophones spaced 10 m apart that is permanently deployed within one of the deep observation wells (Table 8) will verify the absence of any induced microseismic activity within the vicinity of this injector. Induced microseismicity results from fracture propagation or fault slippage. The microseismic monitoring performance of a conventional down-hole geophone array is well-established through observed field performance elsewhere. In the unexpected case of induced microseismicity, the anticipated event size is up to a moment magnitude of –2 and 0 for induced fracturing and fault-slip respectively. These are detectable out to a distance of 800-3000 m from the geophone array17. Observed monitoring performance during the injection period will be used to validate or update these values. Similar down-hole geophone arrays have operated now elsewhere for more than 10 years without failure. The opportunity to provide down-hole microseismic monitoring in all injectors using the DAS fibre will be evaluated based on the results of trial data acquired at Radway 8-19 during perforation shots within the adjacent deep observation well.


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Injection pressure and rate monitoring (IRM, WHPT) are well and reservoir WRM critical equipment and will provide a continuous means to verify the absence of injection induced fracturing within the BCS

o The flow rate at Scotford and on well sites will be measured with a coriolis mass flow meter with an minimum accuracy of +/-0.5% of reading (typical ±0.1%).

o The pressure will be measured with meters with +/-0.5% minimum accuracy. o The temperature will be measured with meters with +/-0.25 degrees Celsius minimum

accuracy.

These are conservative estimates based on the technical specifications of the flow rate, pressure, and temperature monitoring systems. These performance targets will be updated based on the selected meter performance and will ensure regulatory compliance.

InSAR will provide monthly measurements of temporal and areal changes in surface displacements to verify the absence of any induced deformations above the storage complex that indicate a loss of containment. InSAR provides coverage across the whole sequestration lease with two distinct detection capabilities for containment verification:

Escaped fluids: Unexpected migration of brine or CO2 upwards from the BCS storage complex will cause volume changes within any overlying permeable formations that receive these fluids. Any such volume changes above the ultimate seal will result in surface displacements additional to those expected due to pressure development inside the BCS storage complex. These additional surface displacements will be more localized in lateral extent. A feasibility study14 indicates migration of more than 250,000 tonnes of fluid from the BCS into the Mannville Group or Cooking Lake Formation are likely detectable. Due to the limited depth resolution achievable from surface displacement data, any unexpected volume changes inside the Winnipegosis Formation are too close in depth to be distinguished from the expected volume changes inside the BCS and LMS. However, any volume changes inside the shallower Cooking Lake Formation are likely to be detectable. Because, the Cooking Lake is under-pressured relative to the BCS pressure gradient, any leakage reaching this depth is likely to preferential move into this formation. Fault slippage: Unexpected induced fault slippage will cause shear distortion within the subsurface resulting in a characteristic pattern of surface displacements distinct from those induced by subsurface volume changes. Evaluation of appraisal data and feasibility studies indicate fault slippage of at least 1 m over a fault length of 200 m that extends from the BCS to above the Lotsberg Salt will be likely detectable.


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Alberta is a potentially challenging environment for InSAR due to extended periods of snow cover, but these potential difficulties should be readily overcome by deploying a limited number of artificial corner reflectors and GPS receivers across the AOI. Acquisition of InSAR data over the AOI started in 2010 to evaluate the number of reliable monitoring targets within the existing landscape.

The observed performance of geological seal integrity monitoring during the injection period will be used to validate or update these performance values; APPENDIX 15 indicates the accountable organisations for this process.

7.2.4. Monitoring the Hydrosphere

Project groundwater monitoring wells will include one located on each injection well pad. Additional groundwater monitoring wells are proposed to be located close to each of the 4 abandoned wells that penetrate the BCS inside the sequestration lease (Imperial Darling No.1, Imperial Eastgate No.1-34, Imperial Egrement W6-36, and Westcoast 9-31). Additional project groundwater monitoring wells will be located elsewhere within the sequestration lease to bring the total number to 3 times the number of injectors. These additional locations will be determined following consultation with the local municipal authorities before the end of 2011. The total number of these wells is 9 to 24 groundwater monitoring wells with a base case of 15.

Landowner groundwater wells within the sequestration lease provide opportunities for monitoring groundwater quality throughout the sequestration lease. Access to these wells for collecting water samples for analysis depends on landowner permission.

Continuous water electrical conductivity monitoring (WEC) within each Project groundwater monitoring well will verify the absence of high salinity water, such as BCS brine, at these locations. These sensors will detect a change in conductivity of at least 0.1S/cm corresponding to an increase in salinity of at least 0.1 mg/kg. Observed monitoring performance during the baseline period will be used to validate or update these monitoring performance values. These data will also provide the basis to establish a trigger value for any sustained conductivity increase that requires further investigation. For any anomalous conductivity increase, fluid and gas samples will be collected from that well and analyzed to determine the presence or absence of tracers uniquely associated with the BCS brine and the injected CO2.

Continuous water pH monitoring (WPH) within each Project groundwater monitoring well will indicate the absence of any anomalous pH reduction potentially associated with increased levels of dissolved CO2 within the groundwater. These sensors will detect pH changes as small as 0.1; the concentration of dissolved CO2 in the


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groundwater required to induce this change depends on the degree of buffering provided by the local aquifer composition . Continuous pH monitoring typically may prove unreliable due to increasing measurement error through time which necessitate frequent recalibration and creates the potential for frequent false alarms. Observed monitoring performance during the baseline period will be used to validate or update these monitoring performance values, or if necessary justify the cessation of continuous pH monitoring. These data will also provide the basis to establish a trigger value for any sustained pH reduction that requires further investigation. For any anomalous pH reduction, fluid and gas samples will be collected from that well and analyzed to determine the presence or absence of tracers uniquely associated with the BCS brine and the injected CO2.

Fluid sampling and analysis (NTM, ATM) within each Project groundwater monitoring well and a statistically representative selection of accessible landowner groundwater wells will verify the absence of BCS brine and injected CO2 within the groundwater at these locations on an annual basis.

BCS tracers: Between 50 parts per million and 3 parts per thousand of BCS brine unexpectedly appearing within a groundwater sample will be detected using a combination of chemical and isotopic indicators uniquely associated with BCS brine and not initially present within the groundwater or indeed other aquifers above the BCS storage complex. CO2 tracer: Just 1 part per thousand of injected CO2 unexpectedly appearing within a groundwater sample will be detected using an artificial tracer injected with the CO2.

Evidence for the absence of these tracers within groundwater fluid samples is the most reliable and sensitive method available for demonstrating groundwater quality remains unaffected by CO2 injection into the BCS storage complex. Observed monitoring performance during the baseline and injection periods will be used to validate or update these monitoring performance values.

7.2.5. Monitoring the Biosphere

Remote sensing using radar image analysis (RIA) and multi-spectral image analysis (MIA) methods will help track any annual changes across the entire sequestration lease to help indicate the absence of BCS brine and Project CO2 within the near surface soil and vegetation. Local changes in the dielectic constant of the soil due to increased salinity or moisture content will affect the back-scattered amplitude and polarisation of radar data even during periods of snow cover. The same monthly data acquired for InSAR monitoring of surface displacements can also be used for this purpose. Optical methods based on multi-spectral image data, such as the normalised difference vegetation index (NDVI), may indicate vegetation stress due to


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soil salinization or acidification. However the potential for confounding effects is not insignificant especially due to extensive agricultural activities across the AOR. These remote sensing techniques offer the potential for affordable wide-area coverage but they may prove insufficiently reliable for environmental change detection. The performance of these methods will be evaluated and calibrated using ground based soil and vegetation survey techniques at a representative set of discrete locations across the AOR.

Soil surveys to measure near surface electrical conductivity using EM38 at a sufficient number of discrete locations to calibrate the ability of radar image analysis to measure soil salinity variations. Any indications of anomalous change from remote sensing will be subject to ground-based verification using EM38 and, if necessary, soil samples will be analysed to determine the presence or absence of BCS brine tracers.

Vegetation surveys to measure any indications of vegetation stress at a sufficient number of discrete locations to calibrate the ability of multi-spectral image analysis to measure vegetation stress. Any indications of anomalous change from remote sensing will be subject to ground-based verification and, if necessary, soil samples will be analysed to determine the presence or absence of BCS brine tracers and the artificial PFC tracer injected with the CO2.

7.2.6. Monitoring the Atmosphere

Line-of-sight CO2 gas flux monitoring (LOSCO2) based on LIDAR technology will provide a method to verify the absence of any unexpected atmospheric CO2 emissions potentially originating from the BCS storage complex. One monitoring system will operate continuously on each injection well pad and is expected to detect and map CO2 emissions up to 6 km from each injector. This is more than 1 km beyond the largest anticipated radius of a CO2 plume developed around each injector at the end of the injection period. The expected sensitivity and resolution of CO2 emission mapping depends on distance from the sensor system:

2 km: At least 250 kg/hour (0.9 kilo-tonnes/year) of CO2 from a point source will be

detected within days and mapped with a resolution of 100 m.

6 km: At least 600 kg/hour (5 kilo-tonnes/year) of CO2 from a point source will be

detected within days and mapped with a lateral resolution of 200 m.

For any anomalous CO2 emissions detected, samples of soil gas will be collected from that location and analyzed to determine the presence or absence of the artificial tracer uniquely associated with the injected CO2. Observed monitoring performance during the baseline periods and controlled CO2 release tests will be used to validate or update these monitoring performance values.


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The selected monitoring technologies provide complementary capabilities in terms of detection sensitivity, detection time and detection range (Figure 13). The most sensitive technologies, technologies typically provide limited coverage whereas technologies with broader coverage are typically less sensitive. The diverse monitoring plan combines these systems to provide an integrated capability that spans all these monitoring requirements. Table 11 summarises the preliminary expectations of monitoring performance and proposed alarm levels that would trigger further investigation to determine the need, if any, for implementing corrective measures as described in Chapter 9 and APPENDIX 6.

Figure 13: A comparison, where possible, of the expected detection time, detection sensitivity and detection range for a

range of different monitoring technologies.

Legend: LOSCO2 – Line-of-sight CO2 flux monitoring, DTS – Distributed Temperature Sensing, DHPT WPGS – Down-hole pressure-temperature monitoring within the Winnipegosis SEIS3D – Time-lapse surface 3D seismic VSP3D – Time-lapse 3D vertical seismic profiles SGRAV – Time-lapse surface gravity (regretted due to insufficient sensitivity and detection time)


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7.3. Modeling

A list of models already in use for the Quest CCS project, and expected to be required during the project’s lifecycle, is shown below, in addition to the accountable discipline.

Model Accountable Discipline

Static Reservoir Model (3D) and Maps (2D) Production Geosciences

Dynamic Reservoir Model Reservoir Engineering

Well Models, including inflow and vertical lift Production Technologist

Integrated Production System Model Production Technologist

See the Closure Plan for more details.


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7.4. Key Performance Indicators

Key Performance Indicators (KPI) are an important standard means of evaluating and improving Well and Reservoir Monitoring Plans18 – this is also applicable to MMV. Table 10 describes the project-specific KPIs proposed for Quest MMV; these are modified from the standard KPIs for WRM due to the unique aspects of this CCS project and MMV Plan. Deviation from the standard KPI are described in APPENDIX 13.

Table 10: Key Performance Indicators for Quest MMV.

KPI 1 Permanent sensors for continuous monitoring are functional and calibrated Intent To monitor the operational conditions of the MMV tools and bring focus on ensuring all

tools are functional. Definition Fraction of permanent sensors required for continuous monitoring that are functional and

calibrated. Target 0.8 Frequency Quarterly KPI 2 Planned monitoring activities are completed on time Intent To ensure the approved monitoring activities are executed. Definition Fraction of subsurface surveillance activities achieved compared to plan. Target 1 Frequency Quarterly KPI 3 CO2 reconciliation factor Intent To monitor the quality of the CO2 Injection Allocation process. Definition Monthly CO2 Reconciliation Factor (RF) between Scotford meter and individual well pad

meters. Target 5% - this may be revised depending on the outcome of the regulatory assessment

framework Frequency Monthly KPI 4 Injection performance Intent To track compliance with injection targets to optimise storage including conformance. Definition Fraction of wells meeting injection targets. Target 0.8 - based on 1 spare injector out of a total of 5 injectors Frequency Monthly KPI 5 Well stock review Intent To ensure that all active and closed-in wells have technical reviews conducted at least

once a year. Includes injectors, deep observation wells and groundwater observation wells; but excludes abandoned wells.

Definition Fraction of total number of injection and observation wells with complete and documented reviews, executed according to the Annual Well Review guidelines.

Target 1 Frequency Annual KPI 7 Injector operating envelopes Intent To ensure that all wells have (optimum) operating guidelines – agreed and documented

between Petroleum Engineering, Reservoir Engineers and Production functions. Definition Fraction of injectors with reviewed and, if necessary, revised operating envelopes and

well and reservoir models.


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Target 1 Frequency Annual KPI 8 Additional regulatory requirements Intent To track confidence of authorities in the MMV Plan and Closure Plan to ensure timely

transfer of long-term liability to the crown. Definition Number of additional regulatory requirements in response to regulatory review of the

updated MMV and Closure Plans Target 0 Frequency Every three years


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Table 11: Preliminary alarm thresholds to trigger control responses designed to safeguard containment. Baseline data will be used to verify, and if necessary, updated these values. Please see APPENDIX 8 for an explanation of the basis for selecting alarm levels to ensure reliable detection of rare events.

Technology Indicator Frequency Baseline Sensor Error Threshold Alarm Units [mean] [std] [std] [mean] [std] [value]

LOSCO2 2x2 CO2 Emission Mass Rate Every day 0 0 631 25000i 0 23500 tonnes/year

LOSCO2 6x6 CO2 Emission Mass Rate Every day 0 0 5256 25000i 0 23500 tonnes/year

SPH Soil pH Every year 8 0 0.10 7.47 0.00 7.51 pH units

SSAL Soil Salinity Change Every year 0 0 0.10 0.53 0.00 0.49 ppm

WPH Water pH Every day 8 0 0.10 6.3 0.00 6.4 pH units

WEC Water Salinity Every day 4000 0 0.10ii 4001.67iii 0.00 4001.57 ppm

VSP3D CO2 Mass above Ultimate Seal Every 2 years 0 0 40.0 190.5 0.0 89.5 kilo-tonnes

SEIS3D CO2 Mass above Ultimate Seal Every 5 years 0 0 80.0 296.3 0.0 118.5 kilo-tonnes

DHMS Microseismic Depth Decrease Every day 0 0 10.0 170 0.0 160 m

DHPT WPGS Fluid Mass Rate into WPGS Every day 0 0 2.2 37 0.0 34 tonnes/year

INSAR Fluid Mass increase above ? Every month 0 0 83 617 0.0 444 kilo-tonnes

DTS CO2 Mass Rate outside Casing Every day 0 0 3.5 58 0.0 55 tonnes/year

Notes i Threshold based on maximum IPCC emission limits range of 100-1000 ppm/year for 27 Mt CO2 stored. ii WEC sensor error based on Aqua Troll sensitivity specification for conductivity measurements, Schlumberger regression with salinity, and ignoring need to distinguish natural changes. iii Salinity threshold of 2 ppm increases corresponds to 7 ppm of BCS brine at the base of groundwater protection.


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8. CONTINGENCY MONITORING PLANS

This section describes how the monitoring plan will be adapted in response to an range of unexpected but possible scenarios for under-performance of the monitoring systems. The monitoring plan comprises many diverse monitoring technologies. Each was selected on the basis of site-specific technical feasibility evaluations that indicate its likely suitability for the task. Because containment monitoring is a safety-critical task, multiple independent monitoring systems are designed to fulfill each containment monitoring task. This multiple-redundancy is designed to mitigate the risk of unexpected under-performance of an individual monitoring system – this form of contingency is built into the base-case plan. The same approach is not required for conformance monitoring systems as any unexpected under-performance in this domain is not immediately safety-critical. This means the risk of failed conformance monitoring may be mitigated by developing alternative monitoring systems that are ready to be deployed only in the unexpected event that they are required. The following sections describe these contingency plans for conformance monitoring and for selected containment monitoring systems that require adaptation or replacement should they under-perform.

8.1. InSAR

Insufficient population of reliable monitoring targets Reason: Too few objects within the landscape, such as buildings, act as

reliable monitoring targets for surface displacement monitoring using this space-borne remote sensing technique. This means the gaps between reliable monitoring targets at the surface are so large that they create blind-spots within the measured distribution of volume changes inside the BCS storage complex due to increased fluid pressures within the BCS and LMS.

Indicator: Less than one reliable surface monitoring target exists every 4 square kilometres inside the AOR based on the appraisal data (2010-2011) and the baseline data (2012-2014).

Mitigation: Deploy the minimum number of corner reflectors required to eliminate the gap in monitoring coverage. Corner reflectors are compact passive metal objects (less than 0.5 m across) mounted on a stable foundation in the ground and designed to provide a reliable InSAR monitoring target. Consider the value of information gained by supplementing these corner reflectors with a limited number of GPS stations.

Response time: The time required to gain land access and deploy corner reflectors is expected to be less than 6 months.

Surface displacements are too small to support reliable imaging of volume changes inside the BCS storage complex


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Reason: Volumes changes inside the BCS storage complex are smaller than expected due to smaller than expected pressure increases or larger than expected bulk stiffness of the BCS or LMS.

Indicator: The observed maximum rate of surface displacement is less than 1mm/year.

Mitigation: Evaluate the value of information associated with drilling additional BCS observation wells designed to monitor the areal distribution of pressure changes inside the AOR. Consider placing one such observation well close to the most vulnerable BCS legacy well. Note if pressure increases are expected to remain below 3.3 MPa at the injectors then these observation wells may not be required as they would never be sufficient pressure to lift BCS brine above the base of groundwater protection.

Response time: 12 months are likely required to agree land access, gain well licenses and to drill and complete these wells.

Note: Although GPS and optical levelling methods provide alternatives means of monitoring surface displacements, neither are able to detect surface displacement rates less than 1mm/year.

8.2. Time-Lapse Seismic

Time-lapse repeatability of VSP data acquired using the DAS system is insufficient Reason: DAS fibre performance is less than expected based on initial field

trials at the Radway 8-19 well. Indicator: The relative repeatability ratio (RRR) of DAS data exceeds 0.4. Mitigation: Acquire additional repeat VSP surface using a temporarily-

deployed conventional down-hole geophone array. Response time: 3-9 months are likely required to identify the problem and

mobilize a conventional geophone array for a repeat survey. Time-lapse repeatability of conventional VSP data acquired is insufficient

Reason: Environmental non-repeatable noise sources are larger than expected based on initial field trials at the Radway 8-19 well.

Indicator: The ratio of relative repeatability (RRR) of conventional geophone data exceeds 0.4.

Mitigation: Evaluate the value of information associated with drilling additional BCS observation wells designed to monitor the future areal extent of the CO2 plumes.

Response time: 12-18 months are likely required to select locations, agree land access, gain well licenses and to drill and complete these wells.

Time-lapse seismic changes are too small to image the CO2 plume


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Reason: The reduction in seismic velocity of the BCS due to the presence of CO2 is smaller than expected.

Indicator: The ratio of relative repeatability (RRR) is less than 0.4 but time-lapse changes observed around the injector are indistinguishable from time-lapse noise observed away from the injector.

Mitigation: As above. The rate of CO2 plume growth is different than expected

Reason: Uncertainty about reservoir properties such as relative permeability result in a CO2 plume growing at a rate substantially different from the median predicted rate.

Indicator: According to the observed plume size, VSP coverage is expected to be insufficient to image at least half of the CO2 front at the time of the next scheduled VSP survey.

Mitigation: Switch from VSP to surface seismic for monitoring the CO2 plume.

8.3. Microseismic Monitoring

The selected microseismic monitoring well provides insufficient coverage Reason: Observed BCS pressure build-up around an injector not covered by

microseismic monitoring has the potential to induce microseismicity. Indicator: Down-hole pressure at an injector not covered by microseismic

monitoring are consistently limited to the maximum injection pressure. Mitigation: Deploy recording systems to monitor microseismic activity using the

DAS fibre within the identified injector. This does not affect DAS monitoring for well integrity.

Response time: 3-6 months are likely required to deploy these recording systems on a single injection well pad.

A single microseismic monitoring system provides insufficient coverage Reason: Microseismic events are unexpectedly observed by the single

conventional down-hole geophone array. This means there is the reasonable possibility of undetected microseismic events associated with the other CO2 injectors.

Indicator: Sustained microseismic activity located within and above the Lower Lotsberg Salt.

Mitigation: Deploy recording systems to monitor microseismic activity using the DAS fibre within every injector.

Response time: 6-12 months are likely required to deploy these recording systems on every injection well pad.


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8.4. Pressure Monitoring

Permeability within the Winnipegosis Formation is insufficient to support pressure monitoring to verify containment

Reason: The Winnipegosis is a carbonate formation and the observation wells might encounter zones of locally limited permeability.

Indicator: The measured permeability is less than 5 mD. Mitigation: Consider well stimulation or drilling a side-track. If this does not

succeed then abandon upwards and re-complete within the Cooking Lake Formation.

Response time: This mitigation could be implemented before any CO2 injection but requires regulatory approval.

The number of pressure gauges within the Winnipegosis Formation is insufficient to support pressure monitoring to verify containment

Reason: Only three injectors have Winnipegosis observation wells located directly on their well pads. In the base-case development of 5 injectors, the closest deep observation wells to the other two injectors are 5 km away.

Indicator: Down-hole injection pressure is sufficient to fracture the BCS at an injector that does not have a Winnipegosis observation well located on its well pad.

Mitigation: Drill and complete a deep observation well with a down-hole pressure gauge from the identified well pad.

Gauge malfunction prevents down-hole pressure monitoring Reason: DHPG’s can stop working with time due to various reasons, usually

later in life (>10 years). Indicator: Continuous pressure recordings become sporadic, and eventually

stop recording. Mitigation: The Surveillance Team should be calibrating the bottom-hole

pressure with the wellhead pressure while the DHPG is working. After a DHPG failure, the operator could decide to install a memory DHPG in a down-hole nipple that could be retrieved every quarter to ensure wellhead pressures are still calibrated to bottom-hole pressures. This should continue until the failed gauge is replaced.


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9. STORAGE RISKS AFTER MMV

Initial storage risk reductions are achieved through multiple independent safeguards implemented through site selection, site characterisation and engineering concept selections. These initial passive safeguards are sufficient on their own to make the loss of containment extremely unlikely (Table 5). The monitoring plan provides a comprehensive and reliable means to verify the effectiveness of these initial passive safeguards. In the extremely unlikely case that this monitoring indicates a potential loss of containment then a wide range of control measures can be deployed in a timely fashion to effectively prevent, mitigate, or remediate any actual loss of containment. These additional active safeguards must be triggered by monitoring and are designed to be sufficiently numerous and diverse to yield significant additional storage risks reductions. This section summarises the number, type and expected effectiveness of these additional active safeguards. APPENDIX 15 states which organisation is accountable for operating these monitoring systems, deciding on the need for intervention and implementing the appropriate control response.

9.1. Additional Safeguards to Ensure Conformance

The following monitoring-supported safeguards are planned to prevent or correct a situation where the lateral extent of the CO2 plumes or pressure build-up exceeds their model-based predictions. For a more detailed description of these active safeguards please see APPENDIX 6, Section A6.2.

CO2 plume development Monitoring: Time-lapse seismic. Intervention Indicator: The observed CO2 plume is larger than the largest

predicted plume size documented in the Closure Plan2, or there is a clear temporal trend towards this state.

Control Options: Update models, and if necessary increase the areal extent of the baseline 3D seismic survey. Consider re-distributing injection across existing wells or drilling additional injectors to regain conformance.

Response Time: 3-6 months for model updates or additional seismic surveys. Re-distribution of injection between existing wells is available on demand. Drilling additional injectors will take12-18 months.

Pressure development Monitoring: BCS pressure gauges and InSAR. Intervention Indicator: The observed lateral extent of pressure rise sufficient to

lift BCS brine above the base of groundwater protection is larger than the largest predicted size documented in the Closure Plan2, or there is a clear


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temporal trend towards this state. Or there is rapid and localised pressure build-up around an injector due to unexpected compartmentalisation.

Control Options: Update models, and if necessary increase the areal extent of the InSAR data acquisition. Consider re-distributing injection across existing wells or drilling additional injectors to regain conformance.

Response Time: 3-6 months for model updates. 1-3 months to schedule additional InSAR data acquisition. Re-distribution of injection between existing wells is available on demand. Drilling additional injectors will take12-18 months.

The following additional safeguards are planned to ensure accurate CO2 inventory measurements are available and that the target CO2 inventory is achieved. Injected mass of CO2

Monitoring: Wellhead injection rate metering on each injector and rate metering at the compressor outlet in Scotford, minimum technical accuracy of 0.5%

Intervention Indicator: Based on existing acid gas disposal regulations, a difference greater than 5% between the sum of monthly CO2 injection volumes for all injectors and the Scotford fence-line meter. This is subjected to revision as the regulatory framework assessment is ongoing.

Control Options: Recalibrate or, if necessary, replace meters or revise the performance target.

Response Time: 1-3 months. Emitted mass of CO2

Monitoring: Line-of-sight CO2 flux metering Intervention Indicator: Annual controlled release tests of 250 kg/hour at 2 km

and 600 kg/hour at 4 km are not detected. Control Options: Recalibrate or, if necessary, replace meters. Response Time: 1-3 months.

Target inventory of CO2 Monitoring: Down-hole pressure monitoring for each injector. Intervention Indicator: The rate of pressure increase on each injector is large

enough to reach the maximum down-hole injection pressure (28 MPa) before the end of the injection period.

Control Options: Consider increasing the maximum down-hole injection pressure to ERCB D65 limit (32 MPa) or drilling additional injectors.

Response Time: 6-12 months are likely required to drill an additional injector in one of the remaining pre-selected locations.


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Each aspect of conformance is managed by a single monitoring system designed to trigger one of several possible control measures. This collection of control measures is expected to be effective at ensuring conformance provided the monitoring systems perform as expected. The possibility of unexpected poor monitoring performance is mitigated by contingency monitoring plans that will provide timely alternative systems to monitor conformance (Chapter 8). The likelihood of an unexpected loss of conformance despite the control measures in-place is judged to be low (see Table 5).

9.2. Additional Safeguards to Ensure Containment

The following monitoring supported safeguards are planned to prevent or correct any potential loss of containment. For a more detailed description of these active safeguards please see APPENDIX 6, Section A6.3.

Safeguards supported by legacy well integrity monitoring Monitoring: BCS pressure gauges and InSAR. Intervention Indicator: BCS pressure increase at a legacy well is sufficient to lift

brine above BGP or there is a clear temporal trend towards this state. Control Options: Re-distributing injection across existing wells, increase

frequency of groundwater fluid sampling and analysis next to the legacy well, consider drilling a BCS observation well at this location, consider well intervention to plug and re-abandon the legacy well.

Response Time: Injection rates can be re-distributed immediately. Additional groundwater fluid samples can be acquired within 1 week. The time to execute any well intervention depends on the third-parties.

Safeguards supported by injection well integrity monitoring Monitoring: Cement bond logging, tubing-casing annulus pressure

monitoring, casings annuli pressure monitoring, mechanical well integrity monitoring, corrosion coupons, distributed temperature sensing, distributed acoustic sensing, WPGS pressure monitoring, time-lapse seismic

Intervention Indicators: Poor cement bond, sustained annulus pressure, failed well integrity test, sustained temperature or noise anomaly outside casing, sustained WPGS pressure, or a time-lapse seismic anomaly around the injector within the WPGS.

Control Options: Re-distribute injection away from this well, repair the well by changing the failed completion component(s) or re-plugging with cement, or plug and abandon an injector that cannot be repaired, and drill a replacement well.

Response Time: Continuous pressure monitoring supports an automated instant control response to re-distribute injection (see Section 10.2). 1-3 months are


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likely required to plan and execute a well intervention. 6-12 months are likely required to drill an additional injector in one of the remaining pre-selected locations.

Safeguards supported by geological seal integrity monitoring Monitoring: BCS pressure monitoring, WPGS pressure monitoring, time-lapse

seismic, InSAR, down-hole microseismic Intervention Indicator: BCS injector pressure exceed agreed limits, sustained

WPGS pressure, WPGS time-lapse seismic anomaly, InSAR anomaly due to volume changes above the ultimate seal, sustained microseismic activity located above the first seal.

Control Options: Re-distribute injection across existing wells, drill an additional injector, or stop injection. Consider reservoir fluid extraction to reduce pressures inside the BCS storage complex.

Response Time: Continuous pressure monitoring supports an automated instant control response to re-distribute injection (see Section 10.2). Microseismic monitoring requires 1 month for processing and interpretation. Time-lapse seismic and InSAR monitoring requires 2-4 months for processing and interpretation. 6-12 months are likely required to drill an additional injector in one of the remaining pre-selected locations. Implementing a scheme for reservoir fluid extraction and re-disposal will take at least 24 months.

Safeguards supported by hydrosphere monitoring Monitoring: Project groundwater wells with continuous water electrical

conductivity and pH measurements, annual groundwater sampling and analysis for natural BCS brine tracers and an artificial tracer injected with the CO2 within all project groundwater wells and a representative selection of private groundwater wells.

Intervention Indicator: Sustained increase in water electrical conductivity, sustained decrease in pH, presence of Project-specific tracers within groundwater samples.

Control Options: Conduct groundwater investigations, implement exposure controls and remediation measures (see APPENDIX 6). Stop injection at all wells suspected to be the source of these impacts.

Response Time: 1-3 months are likely required to conduct these investigations and deploy the appropriate controls measures.

Safeguards supported by biosphere monitoring Monitoring: Remote sensing, line-of-sight CO2 flux monitoring, soil sampling

and tracer analysis at locations of potential change indicated by remote sensing and line-of-sight CO2 flux monitoring.


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Intervention Indicator: Project-specific tracers measured at concentrations above established detection limits from samples collected at locations indicated by remote sensing or line-of-sight CO2 flux monitoring.

Control Options: Conduct soil investigations, implement exposure controls and remediation measures (see APPENDIX 6). Stop injection at all wells suspected to be the source of these impacts.


Safeguards supported by atmosphere monitoring Monitoring: Line-of-sight CO2 gas flux monitoring Intervention Indicator: Sustained localised increase in CO2 flux confidently

exceeds background levels established during baseline monitoring. Control Options: Conduct soil and groundwater investigations at the site of the

indicated anomaly. Implement exposure controls. Stop injection at all wells suspected to be the source of these emissions.


Figure 5 illustrates these additional active safeguards and their relationship to the identified threats and consequences. The diversity of monitoring within the injectors and inside the BCS storage complex provides multiple means to trigger many different preventative controls without relying on any single monitoring system. This is expected to provide a significant additional containment risk reduction. Furthermore, the multiple monitoring systems designed to verify the absence of environmental impacts provide additional triggers, if necessary, to deploy timely mitigation or remediation of potential effects within the hydrosphere and biosphere. This is expected to provide a further additional containment risk reduction. The reduction in containment risk achieved by additional active safeguards is judged to be commensurate with the risk reduction already achieved through initial passive safeguards (Figure 14). Moreover, the trend of diminishing risk reductions achieved for each additional safeguard provides a clear indication that efforts to implement additional safeguards are not expected to result in any appreciable further risk reductioni. For more information of the method of this risk assessment, please see APPENDIX 9.

i This is one possible means of demonstrating storage risk is reduced to as low as reasonably practicable.


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Figure 14: Representation of the expected containment risk reductions achieved through implementation of passive and

active safeguards. Passive safeguards depend on site selection and engineering concept selections. Active safeguards are control measures trigger by monitoring for unexpected storage behaviour. This risk assessment is a systematic evidence-based process reliant on collective expert judgement. Uncertainty in this assessment is represented by the multiple lines showing the range of possible scenarios. Note that vertical scale is logarithmic.

Unacceptable

Tolerable

Broadly

Acceptable

1 in 104 per year

1 in 106 per yearRis

k M

etr

ic

Number of Safeguards

Passive safeguards

Active safeguards


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10. OPERATING PROCEDURES

10.1. Monitoring Procedures under Normal Operating Conditions

This section describes the procedures for acquiring monitoring data under normal operating conditions. The Storage Development Plan12 describes procedures for operating the wells under normal operating conditions. APPENDIX 13 on Data Management describes the procedures for data transfer and storage. For more details the allocation of accountabilities and responsibilities for the execution of the MMV Plan see APPENDIX 15.

Geosphere Monitoring Procedures Time-lapse seismic: Shell Canada Geophysical Operations are accountable

for down-hole and surface seismic acquisitions under the MMV Plan. These surveys will be acquired according to the established Shell Group and Shell Canada procedures for seismic acquisition. The Quest Venture Subsurface Team are accountable for selecting the timing of these surveys based on previously observed storage and monitoring performance.

InSAR: An approved third-party service provider will be responsible for the acquisition and processing of these remote sensing data. The Quest Venture Subsurface Team are accountable for the interpretation of these data to support verification of conformance and containment. Shell Canada Geophysical Operations are accountable for the deployment of any InSAR corner reflectors on the ground, if necessary.

Microseismic: Shell Canada Geophysical Operations are accountable for microseismic data acquisition. Deployment and maintenance of this permanent monitoring system will be executed according to established procedures within Shell Canada.

In-Well Monitoring Procedures Injection pressure, temperature, rate, annulus pressure, down-hole pressure,

down-hole temperature monitoring: These will be continuously monitored, with the data sent via SCADA to Scotford and made available in PI for Calgary to view.

Distributed Temperature Sensing and Distributed Acoustic Sensing: Continuous monitoring will be provided using one light box for each system permanently deployed on each injection well pad. This hardware will be housed inside climate controlled cabinets mounted on the side of the injection skid. The


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operating procedures for this will be determined based on the outcome of an ongoing field trial at Radway 8-19.

Cement Bond Logging: CBL runs will be supervised by C&WI. The procedure consists in running the CBL tool from top to bottom of the well, following the same configuration as for the baseline (following well drilling). The CBL requires the tubing to be pulled out of hole and the well to be filled with liquid.

USIT: These logging runs will be supervised by C&WI. The procedure consists in running the USIT tool from top to bottom of the well, following the same configuration as for the baseline. The USIT requires the tubing to be pulled out of hole and the well to be filled with liquid.

EMIT: These logging runs will be supervised by C&WI. The procedure consists in running the EMIT tool from top to bottom of the well, following the same configuration as for the baseline. The USIT requires the tubing to be pulled out of hole and the well to be filled with liquid. (TBC)

Hold-up depth (HUD) measurement procedure is to run a dummy on wire-line to tag the bottom of the well every time the well is intervened. For instance, for the planned CBL/USIT/EMIT run, HUD run should be done prior to setting the isolation plug in the packer tail.

In-Well Maintenance Procedures Well Mechanical Integrity Testing: this task consists in pressurising the tubing-

casing annulus at 7MPa during 10 minutes and running a calliper survey in the tubing (from surface to bottom). If a deviation is observed, SCAN surveillance team should be contacted and the relevant remediation plan should be triggered.

Routine Well Maintenance: The well routine maintenance consists in wellhead valves maintenance and measurement of all casings annular pressures. If a deviation is observed, SCAN surveillance team should be contacted and the relevant remediation plan should be triggered.

Hydrosphere Monitoring Procedures Continuous water electrical conductivity and pH monitoring: An approved

third-party service provider will deploy and maintenance of these monitoring systems according to established industry procedures.

Fluid sampling and analysis will be conducted by an approved third-party service provider according to established industry procedures.

Biosphere Monitoring Procedures


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Remote sensing: Radar and multi-spectral image acquisition and processing will be conducted by an approved third-party service provider according to established industry procedures.

Soil and vegetation sampling and analysis: will be conducted by an approved third-party service provider according to established industry procedures.

Atmosphere Monitoring Procedures Line-of-sight CO2 flux monitoring: An approved third-party service provider

will deploy and maintenance of these systems.

10.2. Operating Procedures in Response to Monitoring Alarms

Several continuous monitoring systems on each injection well may trigger automated alarms in the Scotford Control Room. The operating procedures to immediately response to these alarms are as follows.

Wellhead pressure and temperature gauge alarm Case 1:

Alarm indicates: Injection pressure exceeds maximum injection pressure. Alarm response: The well-choke will automatically starts to close until the

injection pressure is below the maximum injection pressure. Case 2:

Alarm indicates: wellhead pressure is below minimum allowable wellhead pressure

Alarm response: alarm goes off at Scotford and SC-SSSV closes automatically Down-hole pressure and temperature gauge alarm

Alarm indicates: down-hole injection pressure exceeds maximum injection pressure.

Alarm response: Alarm goes off at Scotford, operator to check wellhead pressure for consistency and contact SCAN Surveillance team. Check correlation too.

Annulus pressure gauge alarm Alarm indicates: sustained annulus pressure above defined threshold. Alarm response: Alarm goes off at Scotford, operator to check gauge on

location for consistency and contact SCAN Surveillance team. Note: this applies to the tubing annulus gauge (in the base plan) but also to

any annular gauges installed in case a casing shoe is tested leaking below 15 MPa.

Pressure drop across filter alarm


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Alarm indicates: pressure drop across filter above maximum allowable value Alarm response: Alarm goes off at Scotford. Scotford to check on location

status of the filter and plan for maintenance. Surface controlled subsurface safety value (SC-SSSV) status alarm

Alarm indicates: SC-SSSV closed. Alarm response: Scotford to check other well pad variables (e.g. wellhead

pressure) and check on location to confirm SC-SSSV status. Emergency shut-down (ESD) valve status alarm

Alarm indicates: ESD is closed. Alarm response: Alarm goes off at Scotford to confirm closed status of ESD.

Chemical injection alarm Alarm indicates: Chemical injection is off. Alarm response: Scotford operations to investigate and restore tracer

injection. Uninterruptible Power Supply (UPS) status alarm

Alarm indicates: UPS is down. Alarm response: Scotford to investigate and restore UPS on location.

Other continuous monitoring systems may trigger automated alarms in Calgary that require an initial prompt response from the Surveillance Team.

Line-of-sight CO2 gas flux monitoring alarm Alarm indicates: Localised CO2 flux exceeds threshold established after

baseline monitoring from 2012 to 2014 is completed. Alarm response: Environmental Team will investigate this location, collect

samples suitable for BCS and CO2 tracer analysis. Water electrical conductivity monitoring alarm

Alarm indicates: Water electrical conductivity exceeds threshold established after baseline monitoring from 2012 to 2014 is completed.

Alarm response: Environmental Team will investigate this location, collect samples suitable for BCS and CO2 tracer analysis.

Water pH monitoring alarm Alarm indicates: Water pH exceeds threshold established after baseline

monitoring from 2012 to 2014 is completed. Alarm response: Environmental Team will investigate this location, collect

samples suitable for BCS and CO2 tracer analysis. Distributed temperature sensing alarm


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Alarm indicates: Sustained low temperature anomaly migrating upwards above the first seal.

Alarm response: Stop injection at this well. The Surveillance Team will investigate and, if necessary plan an appropriate well work-over, before re-starting injection.

Distributed acoustic sensing alarm Alarm indicates: Sustained acoustic noise anomaly migrating upwards above

the first seal. Alarm response: Stop injection at this well. The Surveillance Team will

investigate and, if necessary plan an appropriate well work-over, before re-starting injection.

Down-hole microseismic monitoring alarm Alarm indicates: Within a 10-day period, more than 10 microseismic events

occur that are located above the base of the Lower Lotsberg Salt with a confidence estimate of greater than 95%.

Alarm response: Stop injection at the adjacent injector. The Surveillance Team will investigate and, if appropriate re-start injection at lower rates and only increasing injection rates when no further microseismic activity is detected above the base of the Lower Lotsberg Salt.

The remaining periodic monitoring systems may also trigger control responses should the interpreted results provide the necessary indicator as described in APPENDIX 6.


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11. REPORTING

Quest will integrate within existing operations. As such, much of the environmental monitoring data and operational performance will be reported and communicated through existing mechanisms. Shell expects that Quest will also require additional reporting not currently completed at the Scotford Upgrader.

11.1. Scotford Upgrader Current Reporting Requirements

The following is a list of current reporting requirements for the Scotford Upgrader that will likely be expanded to include the performance and emissions of Quest:

Monthly and Annual Air report, AENV

Annual Operations Report and meeting, ERCB

Annual GHG reporting, SGER, AENV

Annual GHG reporting, CEPA, Environment Canada

NPRI, Environment Canada

Annual Groundwater Report, AENV

Annual and monthly production reporting, ERCB

11.2. Anticipated Additional Reporting Requirements

It is expected that Quest will also require additional reporting including but not limited to the following:

An annual progress report similar to that in accordance with ERCB Directives 7 and 17 and a

monthly report of volumes injected to the Petroleum Registry of Alberta.

This shall be shall be published within 6 months of the expiration of each calendar

year. This report shall include but is not limited to, the following:

A table of the injected volume of gas on a monthly, annual and cumulative basis, since

start-up

A table and plot of the net volume of gas stored on a monthly basis

A table and plot showing the monthly injection rates

A plot of both bottom hole reservoir pressures and wellhead injection pressures,

along with a summary of any pressure test data obtained and the results and

evaluations of all bottom-hole pressure surveys conducted, during the reporting

period

A gas analysis representative of the composition of the gas injected during the

reporting period

A discussion of the volume of gas injected into the storage site

A summary of any change or modification in the operation of the Project, including

well work-overs, recompletions and suspensions, or any surface facility operations

during the reporting period

Results and evaluation of all monitoring done during the reporting period


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Annual performance reporting to NRCAN and Alberta Department of Energy. The format and

content of this report will be determined as discussions with both of these agencies continue.

An annual report summarizing the results of the MMV program including detection of leaks

(chronic and acute). There are many possible formats for communicating this information

including using a third party auditor and, or external review panel, as an example. The final

program, format to be presented publically, audience and frequency of publication will be

developed as the project and associated consultation progresses.

Updates to the MMV Plan and the Closure Plan will be reported every three years during the

injection and site closure periods.

11.3. Communication Venues

The Scotford Complex has a number of mechanism and forums in which Shell communicates with the public giving and receiving information pertaining to the performance. This includes:

Community Newsletter- once per quarter

Community Meeting- once per year

Report to the community- once every 2 years

Information on the performance of Quest will be integrated into these reporting venues. Scotford also has an Emergency Response Plan that is activated in the event of an emergency. The Project is developing a stand-alone ERP for wells and pipeline, and will append emergency response plans for the capture infrastructure to the existing Scotford site ERP, prior to operations. In the event there is a release of CO2, the appropriate plans will be activated.

11.4. Multi-stakeholder Groups

Shell Canada Energy as operators of the Scotford Upgrader, participates in a number of regional groups including, but not limited to:

The Fort Air Partnership which monitors ambient air quality,

The NCIA which is conducting a regional groundwater study and has constructed a regional noise

model and the

Northeast Region Community Awareness and Emergency Response (NRCAER) Hotline for

posting operational information of interest to community members

Shell will investigate the feasibility and appropriateness of expanding its involvement in these groups to include the Quest project.


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REFERENCES

1. Bachu, S. et al. Suitability of the Alberta Subsurface for Carbon-Dioxide Sequestration in

Geological Media. Earth Sciences Report (Alberta Energy and Utilities Board. Alberta

Geological Survey, Edmonton, alberta, Canada: 2000).

2. Shell Canada Limited Update to Directive 65: Application for a CO2 Acid Gas Storage

Scheme. (Quest CCS Project, Heavy Oil Development, Shell Canada Limited, 2011).

3. Shell Canada Limited Quest Carbon Capture and Storage Project: Environmental

Assessment. (2010).

4. Lacrampe, M. Operation and Maintenance Philosophy. (Heavy Oil Controlled Document

Shell Canada Limited, 2011).doi:07-0-OA-5522-0001

5. DNV CO2QUALSTORE Report: Guideline for Selection, Characterization and

Qualification of Sites and Projects for Geological Storage of CO2. 79(Det Norske Veritas

AS, Oslo, Norway: 2010).at

<http://www.dnv.com/binaries/CO2QUALSTORE_guideline_tcm4-412142.pdf>

6. Zeidouni, M., Moore, M. & Keith, D. Guidelines for a Regulatory Framework to

Accommodate Geological Storage of CO2 in Alberta. SPE 121000 (2009).

7. ERCB ERCB Processes Related to Carbon Capture and Storage (CCS) Projects. 22,

(2010).

8. PTRC IEA GHG Weyburn CO2 Monitoring & Storage Project Summary Report 2000-

2004. (From the proceedings of the 7th International Conference on Greenhouse Gas

Control Technologies. Vancouver, Canada, September 5-9: 2004).

9. ARC Cardium CO2 Monitoring Pilot: A CO2-EOR Project, Alberta, Canada. (Alberta

Research Council (ARC), Geoscience Publishing, Canada: 2009).

10. Bachu, S. & Gunter, W.D. Overview of Acid Gas Injection Operations in Western

Canada. (2005).at <http://uregina.ca/ghgt7/PDF/papers/peer/588.pdf>

11. Mathieson, A. et al. CO2 sequestration monitoring and verification technologies applied at

Krechba, Algeria. The Leading Edge 503, (2010).

12. Shell Canada Limited Storage Development Plan. (Heavy Oil Development Controlled

Document, Shell Canada Limited, 2011).doi:07-0-AA-5726-0001

13. Mestayer, J. et al. Field Trials of Distributed Acoustic Sensing for Geophysical

Monitoring. Society of Exploration Geophysics (2011).


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14. Bourne, S. Quest CCs Project: Technical Feasibility of InSAR for CO2 Storage

Monitoring and Leak Detection. Change (Heavy Oil Controlled Document Shell Canada

Limited, 2011).doi:07-3-ZG-7180-0016

15. Hugonet, V. Quest CCS Project: Feasibility of Distributed Temperature Sensing for CO2

Leak Detection. Design 1-24(Heavy Oil Controlled Document Shell Canada Limited,

2011).doi:07-3-AA-8211-0003

16. Bourne, S. Quest CCS Project: Technical Feasibility of Pressure Monitoring for Leak

Detection. (Heavy Oil Controlled Document Shell Canada Limited, 2011).doi:07-3-ZG-

7180-0013

17. Bourne, S. Quest CCS Project: Technical Feasibility of Microseismic Monitoring. (Heavy

Oil Controlled Document Shell Canada Limited, 2011).doi:07-3-ZG-7180-0014

18. Hertog, R. den WRM Performance Management. (Shell Note-to-File, 2009).at

<https://sww-knowledge-epe.shell.com/teamsiep/livelink.exe/open/47144188>

19. Kyoto Protocol Kyoto Protocol to the United Nations Framework Convention on Climate

Change. (1998).at <http://unfccc.int/resource/docs/convkp/kpeng.pdf>

20. IEA Carbon Capture and Storage in the CDM. (Environmental Directorate, International

Energy Agency: 2007).

21. IPCC IPCC Special Report on Carbon Dioxide Capture and Storage. 442(Prepared by

Working Group III of the Intergovernmental Panel on Climate Change. Cambridge

University Press, Cambridge, United Kingdom and New York, NY, USA: 2005).

22. IPCC IPCC Guidelines for National Greenhouse Gas Inventories: Chapter 5 Carbon

Dioxide Transport, Injection and Geological Storage. (2006).

23. Hepple, R.P. & Benson, S.M. Geologic storage of carbon dioxide as a climate change

mitigation strategy: performance requirements and the implications of surface seepage.

Environmental Geology 47, 576-585(2004).

24. Shaffer, G. Long-term effectiveness and consequences of carbon dioxide sequestration.

Nature Geoscience 3, 464-467(2010).

25. Quintessa A Generic FEP Database for the Assessment of Long-Term Performance and

Safety of the Geological Storage of CO 2. 73(Greenhouse Gas R&D Programme,

International Energy Agency: 2004).at <www.ieaghg.org/docs/QuintessaReportIEA.pdf>

26. IEA Monitoring Selection Tool. IEA Greenhouse Gas R&D Programme (2006).at

<http://www.co2captureandstorage.info/co2tool_v2.1beta/index.php>


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27. DNV CO2QUALSTORE Workbook with examples of applications. (Det Norske Veritas

AS, Oslo, Norway: 2010).at

<http://www.dnv.com/binaries/CO2QUALSTORE_Workbook_tcm4-436659.pdf>

28. WRI CCS Guidelines: Guidelines for Carbon Dioxide Capture, Transport, and Storage.

(World Resources Institute (WRI): Washington, DC, USA, 2008).

29. CSA Worlds first standard for deep-earth storage of industrial carbon emissions to be

developed by CSA Standards and IPAC-CO2 Research. (2010).at

<http://www.csa.ca/cm/ca/en/news/article/deep-earth-storage-industrial-carbon-

emissions>

30. OSPAR OSPAR Convention for the Protection of the Marine Environment of the Noerth-

East Atlantic: OSPAR Guidelines for Risk Assessment and Management of Storage of C)2

Streams in Geological Formations. Framework 1, (2007).

31. EC Directive of the European Parliment and of The Council on the geological storage of

carbon dioxide and amending Council Directive 85/337/EEC, Directives 2000/60/EC,

2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No 1013/2006.

(Eurpoean Union: 2009).at

<http://ec.europa.eu/environment/climat/ccs/pdf/st03739_en08.pdf>

32. UK A consultation on the proposed offshore carbon dioxide storage licensing regime.

29(UK Department of Energy and Climate Change: 2009).

33. UK Towards Carbon Capture and Storage : Government Response to Consultation.

96(UK Department of Energy & Climate Change: 2009).at

<www.berr.gov.uk/files/file46810.pdf>

34. BGS Measurement, Monitoring & Verification of CO2 Storage: UK Requirements Study -

Final Report : Vol 1 (Draft). 1, 295(British Geological Survey Commercial Report: 2010).

35. BGS Measurement, Monitoring & Verification of CO2 Storage: UK Requirements Study -

Final Report : Vol 2 (Draft). 2, 135(British Geological Survey Commercial Report: 2010).

36. EPA Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide.

Environmental Protection 85(U.S. Environmental Protection Agency. EPA430-R-08-009.

July 10: 2008).

37. NETL Monitoring, Verification and Accounting of CO2 Stored in Deep Geologic

Formations. 132(National Energy Technology Laboratory (NETL), U.S. Department of

Energy: 2009).at <www.netl.doe.gov>


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38. IEA Review of gaps in knowledge from the IPCC special report on CO2 capture and

storage. (IEA Greenhouse Gas R&D Programme: 2006).at

<http://www.cslforum.org/publications/documents/Final_Report_MMV_Task_Force.pdf>

39. EPA Federal Requirements Under the Underground Injection Control (UIC) Program for

Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells. 1-51(U.S. Environmental

Protection Agency, Federal Register, Vol. 73, No. 144, July 25: 2008).

40. Chadwick, R.A. et al. Best practice for the storage of CO2 in saline aquifers -

observations and guidelines from the SACS and CO2STORE projects. 267(British

Geological Survey Occasional Publication No. 14., Nottingham, UK: 2008).

41. Pearce, J. et al. Quest CCS Project: Potential Applications of the Real-Time Compaction

Imager for Monitoring Carbon Capture Sequestration and Acid Gas Injection Wells.

Carbon (Heavy Oil Controlled Document Shell Canada Limited, ).doi:07-3-AA-8211-

0004

42. Bourne, S. Quest CCS Project: Feasibility of Gravity Surveys for CO2 Storage

Monitoring and Leak Detection. (Heavy Oil Controlled Document Shell Canada Limited,

2011).doi:07-3-AA-8211-0002

43. Ostermeier, R.M., Skelton, W.K. & Grae, A.D. Identifying and Quantifying Well Logging

Technologies for Monitoring the Quest ScotFord Upgrader CCS Project. Personnel

(Heavy Oil Controlled Document Shell Canada Limited, 2008).doi:07-3-ZG-7180-0015

44. Zhang, G. Quest Geochemical Study – Radway Well Calibration and Shallow Horizons.

(Heavy Oil Development Controlled Document, Shell Canada Limited, 2011).doi:07-3-

ZG-7180-0026

45. Inan, E. Chemical CO2 Tracer Deployment for the MMV Program at the Quest CCS

Project. (Heavy Oil Development Controlled Document, Shell Canada Limited,

2011).doi:07-3-ZG-7180-0031

46. Pierpont, R.M. Quest CCS Project: Feasibility of Uniquely Identifying Basal Cambrian

Sand Formation Fluid in Shallow Groundwater. (Heavy Oil Controlled Document Shell

Canada Limited, 2011).doi:07-3-ZG-7180-0027

47. Stantec Quest Carbon Capture and Storage Project: Recommended Environmental

Monitoring Plan. (2011).

48. Jonathan, P., with B. Hirst A method for remotely measuring surface gas fluxes above an

onshore CO2 sequestration project. EP 2010-5293 (2010).


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49. HSE Failure rates for underground gas storage: Significance for land use planning

assessments. Health (San Francisco) (UK Health and Safety Executive: 2008).

50. IEA Carbon Capture and Storage: Progress and Next Steps. 44(International Energy

Agency: 2010).

51. Hugonet, V. Quest Legacy Wells Analysis. (Heavy Oil Controlled Document Shell Canada

Limited, 2011).doi:07-3-ZW-7180-0002


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APPENDIX 1. EMERGING MMV GUIDELINES

According to the Kyoto Protocol19 and the Copenhagen Accord, project activities under the Clean Development Mechanism (CDM) must result in emission reductions that are “real, measurable and long-term”. CCS offers one route towards achieving such emissions reductions20. The Intergovernmental Panel on Climate Change21 found that existing technologies are sufficient to meet these requirements for monitoring and verification of underground geological storage of CO2. The Greenhouse Gas Inventory Guidelines22 consider underground storage sites to be a source of CO2 emissions. This means the difference between the amount of injected and emitted CO2 is a measure of the inventory of stored CO2. For potential CCS CDM projects to be an effective mitigation for climate change, annual CO2 emissions rates should be less than 0.01% of the mass of CO2 stored underground23, or perhaps less than 0.001%24. The IPCC22 evaluated a wide range of feasible monitoring methods for detecting emissions from an underground storage site and concluded the performance of each individual method will be site specific. The IEA Greenhouse Gas Research and Development Program supported the development of guidelines in three key areas related to monitoring for verification of geological storage of CO2:

Risk assessment25,

Monitoring tool selection26

Site selection, characterization and qualification5,27

The latter, developed by a joint industry project (JIP) including Shell and led by Det Norske Veritas (DNV), represent the most comprehensive guidelines and examples yet for safe and sustainable geological storage of CO2. This JIP advocates a site-specific risk-based approach. Independently, the World Resource Institute issued general guidelines28 for CCS operators and regulators, including recommendations for monitoring and verifications plans to follow a site-specific risk assessment that allows flexibility to select appropriate monitoring methods adapted through time to suit the different risk profiles at each stage of the project.

A1.1. Future Regulatory Expectations

The volume and time-scale of CO2 storage required for CCS to be an effective mitigation for climate change greatly exceeds the existing experience acquired through Acid Gas Disposal projects. This necessitates the development of new standards for CCS projects. The Canadian Standards Association (CSA) and the International Performance Assessment Centre for Geologic Storage of Carbon Dioxide (IPAC-CO2) recently announced a joint agreement to develop Canada’s first carbon capture and storage standard for the geologic storage of industrial emissions29. International and other national authorities, industry and


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environmental non-governmental organizations will most likely influence the development of these standards.

A1.2. International Authorities

Several international authorities published guiding principles for CCS developments to aid the harmonization of standards between jurisdictions5,21,22,28,30. These are likely to influence future regulations.

A1.3. Government Authorities

Many governments are developing country-specific frameworks for CCS regulations: Australia, Brazil, Canada, China, European Union, Germany, Indonesia, Norway, Poland, Qatar, South Africa, The Netherlands, UK, and USA. Some of this initial work adds to the existing guidance from international authorities. European Union: The European Council Directive on permanent underground CO2 storage31 develops the OSPAR30 principles for monitoring to state the following six objectives for monitoring.

Demonstrate CO2 behaves as expected.

Detect any migration or leakage.

Measure any environmental or health damage.

Determine effectiveness of CO2 storage as GHG mitigation.

In case of leakage, assess effectiveness of corrective measures.

Update risk assessment and monitoring plan based on performance of the storage site.

Further monitoring requirements arise because the transfer of liability to the authorities after site closure is contingent on demonstrating the permanence of CO2 storage according to three criteria.

Actual CO2 behaviour conforms to modeled behaviour within range of uncertainty.

Absence of any detectable leaks.

Storage site is evolving towards long-term stability.

The European Council Monitoring and Reporting Guidelines (MRG), a draft amendment to the Emissions Trading Scheme (ETS), also stipulate additional monitoring requirements beyond the 2009 EC Directive in the instance of detecting actual emissions from the storage site to quantify the emissions and the efficacy any remediation activities. United Kingdom: Government response to consultation on CCS32,33 accepts four key clarifications of the monitoring requirements for CCS.

Monitoring should cover the volume affected by CO2 storage rather than just the volume

occupied by the CO2 plume itself.


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The post-closure period before transfer of liability will be determined individually for each

project depending on the behaviour of the storage site during operation based on evidence

from the monitoring program.

The duration and type of post-transfer monitoring will be decided based on evidence from the

monitoring program and will determine the ‘transfer fee’.

Site closure includes removal of infrastructure and sealing of wells before handover to the

authorities with the possible exception of some wells that may be maintained for monitoring

purposes.

A subsequent study commissioned by the UK34,35 identified technologies and methodologies judged suitable for MMV in the UK. USA: Environmental Protection Agency (EPA) consultation on Federal requirements for geological storage of CO2 (EPA 2008) proposes a broadly similar monitoring requirements to elsewhere.

The Area of Review (AOR) for monitoring is considered to include the pressure front defined as

the region of elevated pressures sufficient to cause movement of formation fluids into the

protected groundwater zone.

Determination of the AOR is initially based on predictive models and should be re-determined in

the event of any significant discrepancy between predicted and actual performance or within 10

years of the last determination, whichever is the sooner.

Monitoring the CO2 plume and pressure front may be achieved with a combination of direct and

in-direct techniques selected according to site-specific requirements.

Continuous monitoring of injection with automatic alarms and shut-off equipment is

recommended as an important safety consideration. The EPA proposes to require down-hole

safety shut-off value.

Duration of the site closure period is not specified but anticipated to be determined according to

demonstrated performance of the storage site.

EPA36 proposes a quantitative risk assessment methodology as a high-level approach towards determining the suitability of sites for geological storage of CO2. The US Department of Energy’s National Energy Technology Laboratory (NETL) provide guidance for MMV37, including a classification of monitoring technologies according to their readiness for monitoring CO2 storage sites.

A1.4. Industry Authorities

Advocacy by industries and companies with relevant expertise may influence future regulations.

CO2QUALSTORE: A joint industry project (JIP) led by Det Norske Veritas (DNV) includes partners

from a number of sectors; oil and gas companies (BP, BG Group, Petrobras, Shell and Statoil);

energy companies (DONG Energy, RWE Dea and Vattenfall); technical consultancy and service


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providers (Schlumberger and Arup); the IEA Greenhouse Gas Reseearch and Development

Programme; and two Norwegian public enterprises (Gassnova/Climit and Gassco). This JIP draws

together experience and good practises to generate guidelines and recommendations for

geological storage of CO2 including MMV5,27.

Shell advocates that the IPCC GHG inventory guidelines22, the World Resource Institute

guidelines28 and the DNV guidelines5 form the basis for any MMV program.


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APPENDIX 2. RISK MANAGEMENT USING THE BOWTIE METHOD

The Bowtie Method5 provides a framework for a systematic risk assessment of events with the potential to affect storage performance. Figure 15 illustrates a highly simplified bowtie risk analysis. The bowtie represents the relationship between the five key elements that describe how a risk might arise and how safeguards can provide effective protection against the risk and its associated consequences.

Top Event: This is the unwanted event, placed in the centre of the bowtie.

Threats: These possible mechanisms can lead to the top event.

Consequences: These are the possible adverse outcomes due to the occurrence of the top

event.

Preventative safeguards: These decrease the likelihood of a threat leading to the top event.

Corrective safeguards: These decrease the likelihood of significant consequences due to a top

event.

The Bowtie Method is a proven and effective method for analysing and communicating risks.

Figure 15: Schematic Diagram of the Bowtie Method.

Within the context of this MMV Plan both preventative and corrective safeguards take one of two distinct forms:

Passive safeguards: These safeguards are always present from the start of injection and do not

need to be activated at the appropriate moment. These passive safeguards exist in two forms:

Geological barriers identified during site characterization;

Engineered barriers identified during engineering concept selections.

Active safeguards: These are engineered safeguards, brought into service in response to some

indication of a potential upset condition in order to make the site safe. Each active safeguard

requires three key components in order to operate effectively:

Top Event

Thre

ats

Co

nseq

uen

ces

Preventative

Safeguards

Corrective

Safeguards

Bar

rier

Barrier

Barrier

Barrier

Barrier

Barrier

Bar

rier

Bar

rier

Bar

rier

Hazard

Scenario

Escalation

Scenario


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A sensor capable of detecting changes with sufficient sensitivity and reliability to provide

an early indication that some form of intervention is required;

Some decision logic to interpret the sensor data and select the most appropriate form of

intervention;

A control response capable of effective intervention to ensure continuing storage

performance or to control the effects of any potential loss of storage performance.

This combination of a sensor, decision logic and a control response is the central mechanism for risk management within the MMV Plan.


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APPENDIX 3. INITIAL EVALUATION OF CONFORMANCE RISKS

Conformance means that the storage complex is behaving in a predictable manner, consistent with the subsurface modeling.

A3.1. Potential Consequences Due to a Loss of Conformance

An unexpected loss of conformance may result in one or more of the following consequences:

Containment risks change: Additional MMV activities may be required if sufficiently elevated pressures contact potential migration pathways outside the initial AOR that were not part of the base MMV plan.

Site closure delayed: Additional MMV activities and an extended Closure Phase may be required to re-calibrate and verify model-based predictions of storage performance if monitoring indicates unexpected CO2 or pressure development.

Storage efficiency changes: Additional injectors may be required to maintain injectivity if unexpected rapid pressure build-up occurs, or to limit the ultimate size of a CO2 plume if unexpected rapid CO2 migration occurs which increases the containment risk.

A3.2. Potential Threats to Conformance

In order to avoid these unwanted consequences we start by evaluating the possible threats to conformance:

Unexpected modeling errors: Model-based predictions about pressure or CO2 development inside the BCS storage complex may cause a loss of conformance because:

the properties of the storage formations or fluids are incorrect, the equations representing fluid transport are incorrect, the analysis of uncertainties in the results are incomplete.

Unexpected monitoring errors: Observations of actual storage performance may cause a perceived loss of conformance because:

the acquisition of monitoring data includes unknown biases, the processing of monitoring data creates unknown artefacts, the interpretation of monitoring data is incorrect.

A3.3. Initial Safeguards to Ensure Conformance

Next we evaluate the multiple independent safeguards in-place to control these threats and prevent or mitigate their consequences.


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Basin-scale screening: A systematic screening process concluded the top ranking opportunities for geological storage of CO2 in Canada are located within the central Alberta Basin due to the presence of deep permeable saline aquifers overlain by multiple extensive geological seals1. Avoiding complex geology helps to mitigate the threat of misrepresenting the distribution of properties within the storage complex.

Feasibility study and site selection: Evaluation of pre-existing appraisal data concluded there is evidence of sufficient capacity, injectivity, and containment within the BCS storage complex to support the proposed storage project and de-risk site selection. Avoiding less suitable sites within the Alberta Basin helps to mitigate the threat of incomplete uncertainty analysis.

Appraisal and site characterization: The comprehensive appraisal program included 3D seismic, 2D seismic, high resolution aeromagnetic data and the Radway 8-19 appraisal well. These new appraisal data demonstrate with a high degree of confidence the quality, thickness, and continuity of the BCS and the numerous geological seals within and above the BCS storage complex. These data also provide good evidence for the absence of faults within these formations. The quality of these data significantly limited the scope for incorrect model inputs.

High-resolution aeromagnetic survey: Acquisition, processing and interpretation of

these data indicate variations in the depth to the top of the Precambrian Basement and

potentially the location of small faults (offsets less than 100 m) within the basement.

Although the sensitivity and resolution of these data to basement structures is

substantially less than seismic data, its areal coverage (8,500 km2) is substantially

greater than the combined coverage of all available seismic data across the storage site

and spans the entire AOR.

2D seismic surveys: Reprocessing and interpretation of legacy 2D seismic data provides

coverage over the entire storage site. The seismic lines are orientated north-south or

east-west with a typical spacing of 2 to 3 km. These data demonstrate the presence and

continuity of the geological seals over the entire storage site as well as the absence of

any large faults crossing these seals. Within the basement, many small faults (offsets

less than 20 m) and occasional larger faults (offsets of about 100 m) exist. The larger

faults within the basement are located close to the north-west boundary of the storage

site, and coincide with major terrain boundaries in the basement identified from

aeromagnetic data. At these locations the BCS is interpreted as being locally absent but

the primary seal, although thinner, remains intact, while the secondary and ultimate

seals (Lower and Upper Lotsberg Salts) are unaffected. Where seismic lines pass close to

existing wells, the data from these two independent sources are consistent.

3D seismic survey: Acquisition, processing and interpretation of new 3D seismic data

over the central area (176 km2) of the storage site provide a detailed continuous image

of the storage complex and overlying formations. Local variations in the structure of the

BCS storage complex are resolved with a lateral resolution of 25 m and are consistent

with 2D seismic data. The BCS is present throughout the 3D seismic image with an


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average dip direction consistent with the regional trend revealed by well data. Many

small faults (offsets less than 20 m) exist within the basement, but no faults are

detected crossing any of the seals within the BCS storage complex. These small faults

control local variations in the depth to the basement, which in turn control the small

variations (plus or minus 20 m) in the thickness of the BCS. Due to the small nature of

these deep faults on the seismic image, there remains a small possibility that they

extend just into the BCS, due perhaps to the process of differential compaction. If these

faults do extent into the BCS, they are not likely to be sealing due to sand-on-sand

contacts across the faults. If the faults are sealing, due perhaps to cataclysis, their

mapped locations and orientations make it unlikely that they connect together

sufficiently to limit injectivity. It is also unlikely that they compartmentalize the aquifer

and limit storage capacity. Although these three conditions are each unlikely, there

remains no guarantee that small faults cannot affect storage performance. Placement of

the Radway 8-19 appraisal well, guided by this seismic image, close to a representative

distribution of small faults affords an early opportunity to test the hydraulic properties

of these faults.

Radway 8-19 appraisal well: This is currently the only well penetrating the center of the

BCS storage complex. Log and test data from this well confirm the expected depth,

thickness and properties of all the geological formations within the storage complex.

Residual likelihood of a loss of conformance due to failure of these initial safeguards is judged to be low (Table 5).


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APPENDIX 4. INITIAL EVALUATION OF CONTAINMENT RISKS

The Project is designed for permanent secure containment of CO2 and brine within the BCS storage complex. However, it is prudent to consider unlikely threats that may still occur with potential consequences. The following analysis of both the threats and potential consequences represents collective expert opinions and draws on existing risks descriptions provided by IPCC21, WRI28, EPA36, and NETL37 as well as Acid Gas Disposal Projects in Alberta. Some of these risks are insignificant for this Project (A4.5) Containment focuses on the fact that the injected fluid should remain in the geological interval intended for long-term storage. Containment is a safety-critical risk, therefore a full containment Bowtie has been developed (Figure 5). APPENDIX 2 provides a brief description of risk management using the Bowtie method.

A4.1. Potential Consequences Due to a Loss of Containment

An unexpected loss of containment may result in one or more of the following consequences: Hydrocarbon resources affected: Proven oil resources exist within the Leduc, Nisku

and Wabamun formations and proven gas resources within the Nisku, Mannville Group and Colorado Group (see Table 4). Migration of CO2 or BCS brine into a producing fields might result in a slight increase in salinity or acidity of the produced fluids, although the lateral and vertical offset of the producing fields makes this unlikely. The closest hydrocarbon resources are more than 10km laterally and 1000m vertically offset from the injection points.

Groundwater impacts: The Groundwater Protection Zone extends 100 to 400 m below the surface throughout the AOR and supports extensive domestic, agricultural and commercial use. The potential consequences to the groundwater are discussed in the Environmental Assessment3.

Soil contamination: Migration of CO2 into the soil may increase soil acidity and introduce contaminants mobilized and transported by the passage of CO2 through the subsurface. Changes in soil quality may be sufficient to stress the flora and fauna.

CO2 release to the atmosphere: Any release of CO2 from the BCS storage complex into the atmosphere constitutes a potential threat to people and will reduce the effectiveness of the Project’s contribution to climate change mitigation.

A4.2. Potential Threats to Containment

To understand how to avoid these unwanted consequences we start by evaluating the identified possible threats to containment:

Migration along a legacy well: Four abandoned BCS legacy wells exist inside the AOR. These wells date from 1940 to 1960 so abandonment standards, execution, documentation and aging all contribute to uncertainty about well integrity (APPENDIX


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11). Insufficient number, incorrect placement relative to the seals or quality of cement plugs placed inside the abandoned wellbore, or deterioration of cement quality through time may affect the integrity of these legacy wells. The Quest CCS Project has been sited such that in all the current subsurface simulations the CO2 plume does not reach these wells and the pressure increase at these locations does not exceed the threshold to lift BCS brine above the base of groundwater protection.

Migration along an injection well: Any well injecting CO2 into the storage complex creates a threat to containment as it punctures the geological seals directly above the CO2 plume. Any loss of external or internal well integrity will potentially allow migration of CO2 and BCS brine out of the storage complex. This threat may arise for any of the following five reasons.

1. Compromised cement: Initial cement bond, or deterioration of the cement bond through time due to stress cycling, or chemical alteration may allow upward fluid migration outside the casing.

2. Compromised casing: Casing corrosion through time due to oxygen ingress, or contact with saline or acidic fluids may allow upward fluid migration inside or outside the casing.

3. Compromised completion or wellhead: Loss of integrity of the completion or wellhead due to undetected flaws in the initial design or execution or subsequent degradation due to corrosion, or deterioration of seals in the presence of CO2 may allow fluids to escape through the wellbore.

4. Well interventions: During the course of normal operations, routine well interventions may result in loss of well control.

5. Compromised abandonment: Injection and observation wells will be properly abandoned prior to site-closure. Undetected flaws in the design or execution of well abandonment or subsequent degradation of materials may allow upwards migration of fluids.

Migration along an observation well: One method of monitoring conformance inside the BCS storage complex is direct measurement of pressure and saturation changes within observation wells. Any such observation wells constitute a threat for the same reasons as the injectors. Legacy, injector and observation wells each represent a different type of threat: legacy wells are avoidable, injectors are essential; however, observation wells are optional.

Migration along a matrix pathway: Sedimentary processes often generate extensive thick impermeable geological seals that retain fluids under pressure for millions of years. The Alberta Basin contains many such seals, and careful site selection process for the Quest AOR has been used to optimize the use of these natural barriers. Nonetheless, permeable pathways may exist up through the geological seals due to the occasional juxtaposition of different sedimentary formations. For instance, a seal


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may truncate against a local basement high or a channel filled with sand may erode down through a seal.

Migration along a fault: Faults exist as discontinuities over a range of length-scales in many rock formations. However, large faults that transect regional scale geological seals within the Alberta Basin are rare (more than 100 km separates the Snowbird Tectonic Zone from the Hay River Shear Zone to the north). Even when present, many faults are sealing and retain fluids under pressure over geological time-scales. Mechanisms associated with fault slip, such as clay smear and cataclysis, reduce permeability within the fault zone. Other mechanisms, such as dilation and fracturing may enhance fault permeability. Although unlikely, it remains a credible possibility that permeable fault pathways exist somewhere within the AOR. No faults are identified in the AOR that cut through the BCS storage complex.

Induced stress reactivates a fault: Any pre-existing sealing faults may re-activate due to stress changes induced by CO2 injection. Effective normal stresses will decrease inside the BCS and may de-stabilize any pre-existing weak fault. Shear stress loading these faults will also change and may de-stabilize then fault depending on the fault orientation and the sense of residual shear stress held on the fault due to friction. Renewed fault slip might increase local permeability due to dilation or fracturing within the fault damage zone and perhaps allow the fault to propagate upwards. Equally likely is a reduction of permeability due to clay smear or cataclysis along the fault surface. No faults are identified in the AOR that cut across any of the seals in the BCS container.

Induced stress opens a fracture: CO2 injection may induce open fractures due to pore fluid pressure increase and temperature decrease inside the aquifer close to the well. Occurrence of any such fracturing does not constitute a threat to containment unless these fractures propagate upwards sufficiently to transect the geological seals and remains at least partially open to provide an enduring permeable pathway.

Acidic fluids erode geological seals: Injected CO2 will acidify formation fluids in contact with geological seals. Depending on the mineralogy of the seals there is potential for many different chemical reactions to occur. Many of these reactions yield products that occupy a greater volume and therefore most likely reduce permeability; however the converse is also possible. For acidic fluids to erode geological seals, minerals must be present that react and these reactions must increase not decrease permeability.

Migration due to third-party activities: Any nearby third-party CCS projects may induce migration of CO2 or brine into the AOR causing environmental impacts. Existing activities, such as mining, agriculture, or landfill inside the AOR may also cause environmental impacts. Inability to identify the true source of these impacts might trigger a perceived loss of containment from the Quest BCS storage complex.


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A4.3. Initial Safeguards to Ensure Containment

This section identifies and evaluates two distinct types of safeguards to reduce containment risks: preventative measures and corrective measures.

A4.3.1. Preventative Measures

To reduce the likelihood of any loss containment the following safeguards are in place to prevent BCS brine or CO2 migrating out of the BCS storage complex.

Safeguards for legacy wells: Four abandoned BCS legacy wells exist within the AOR. The likelihood of loss of containment via one of these wells is judged to be very low due to the following safeguards.

Lateral separation of these wells from the CO2 injectors is expected to eliminate their potential threat to containment. The closest distance between an abandoned BCS legacy well and a proposed CO2 injector is 21 km. All model realizations indicate a maximum CO2 plume extent substantially less than this distance and the expectation that BCS pressure increases will be insufficient to lift BCS brine above the base of groundwater protection (APPENDIX 12).

Vertical separation between the injection formation and the base of groundwater protection is more than 1500 m. This increases the BCS pressure rise required to lift BCS brine above the base of groundwater protection compared to shallower potential storage.

Multiple large cement plugs placed in the well bore at the time of abandonment (Table 32) were designed to ensure the long-term integrity of the well but may have unexpected degraded over the 60 years since abandonment. The Imperial Darling BCS legacy well does not have a cement plug below the Lotsberg Salts.

Lotsberg salts are expected to creep and have completely bridged the open borehole sections through these seals over the 60 years since drilling.

A thick impermeable plug over the BCS is expected to have formed from the settlement of drilling mud within these wells over the last 60 years.

Cooking Lake under pressure of 600 kPa means any fluids migrating up a legacy well are more likely to enter this formation rather than continue migrating upwards towards the base of groundwater protection.

The residual likelihood of this system of safeguards failing is very low but exists to some small extent due to the small possibility of larger than expected BCS pressure increases at these well locations, the absence of documented positive pressure tests at the time of abandonment to confirm the initial


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integrity of the cement plugs, and the possibility of cement degradation through time.

Safeguards for injection wells: Injectors designed, drilled, completed and operated for the dedicated purpose of CO2 injection allow for a wide range of engineered safeguards. This results in a very low likelihood of any loss of containment via the injectors.

Multiple casing strings provide three independent layers of protection against corrosion through the groundwater protection zone and two layers of protection along the entire well bore with the exception of the BCS.

Chrome casing over the injection interval provides additional corrosion resistance over the interval expected to encounter CO2 saturated BCS brine.

Cement placement along the entire well bore provides the largest possible cement barrier to safeguard well integrity outside each casing string.

CO2 tolerant cement is used to ensure enduring cement bond integrity even in the presence of CO2.

Corrosion inhibitor within the annulus fluid between the main casing and the injection tubing will help avoid casing corrosion in the unexpected case of CO2 entering this annulus.

Logging and pressure testing will verify initial well integrity The residual likelihood of a loss in well integrity is very low due to their tailor-

made design for CO2 service as demonstrated by many mature CO2 EOR projects worldwide.

Safeguards for observation wells: Observation wells drilled into the BCS pose a somewhat similar threat to containment as injectors. However, this risk can be eliminated by not drilling them into the storage complex. The benefits of accepting this avoidable additional containment risk are small as direct measurements within the BCS at a limited number of locations provides very little information about the distribution of pressure and CO2 development necessary to assess conformance. In-direct non-invasive conformance measurements, such as time-lapse seismic, should be feasible and sufficient. The following safeguard eliminates this risk:

Observation well depth will be limited so as not to penetrate the Upper Lotsberg Salt Formation.

The residual likelihood of migration along an observation well is zero. The existing Redwater 3-4 well will be converted into a BCS observation well

but the offset distance from this to the injectors is sufficient to ensure it will only experience a small pressure rise. Down-hole pressure monitoring will verify this expectation.


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Safeguards against any matrix pathways: The BCS storage complex contains three major regional geological seals (see Figure 3). Appraisal and Site Characterization provides the following safeguards indicating that the likelihood of fluid migration along a matrix pathways is very low.

The LMS is a baffle that will inhibit vertical migration of fluids out of the BCS. The first seal, the Middle Cambrian Shale, is approximately 20 to 55 m thick

over the entire AOI; the thinnest zones within the AOR occurs over occasional basement highs identified within 5 km of the north-west boundary of the AOR.

The UMS is a second baffle that will inhibit vertical migration of fluids. The second seal, the Lower Lotsberg Salt, is typically approximately 10 to

35 m thick within the AOI and thins towards the west terminating just beyond the western boundary of the AOR.

The Devonian Red Beds provide a third baffle to inhibit vertical migration. The ultimate seal, the Upper Lotsberg Salt, is approximately 55 to 90 m thick

over the entire AOI and extends beyond the AOR boundary in all directions. Geochemistry of the BCS brine is fundamentally distinct from the brine found

within shallower formations within the geosphere and the ground water. This is strong evidence for long-term regional hydraulic isolation of the BCS formation from the other formations.

The tortuous path that is necessary for any potential matrix pathway to find an unexpected route around multiple geological seals provides large exposure to secondary storage due to capillary trapping within the matrix pathway.

The residual likelihood of migration along a matrix pathway is very low as each of the three major regional seals seal on its own is expected to be sufficient to ensure permanent secure storage of the injected CO2.

Safeguards against any fault pathways: The following group of safeguards indicate the likelihood of fluid migration along a fault pathway is very low.

Site characterization informed by extensive 2D seismic across the entire AOR and 3D seismic over the entire area of expected CO2 plume development provides strong evidence for the absence of faulting within the BCS storage complex and overlying formations.

Cataclysis and clay smear are two mechanisms expected to reduce permeability associated with any undetected faults within the MCS and other formations below the Lotsberg Salt Formations.

Lotsberg Salts provide thick ductile formations expected to either prevent brittle fault formation or to creep and seal any fault that unexpectedly transects these formations. Core material recovered from the Basal Red Beds formation


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(Redwater 11-32) directly below the Lower Lotsberg Salt contains open fractures completely sealed with salt fill.

Residual uncertainty is very low as even in the extremely unlikely event of unexpected faults possessing unexpected permeability for fluids to escape the storage complex, the maximum flux will likely still be less than any unexpected migration of fluids along a well that provide a direct flow path from the storage complex to the surface34,35.

Safeguards against fault reactivation: The following safeguards together indicate the containment risk due to fault reactivation is very low.

The absence of faults within the BCS storage complex and overlying formations indicate an absence of structures susceptible to fault reactivation due to CO2 storage.

The absence of recorded earthquakes within the storage site provides evidence for the absence of any current tectonic activity that might de-stabilize or re-activate any unknown faults.

Limited initial shear stress exists within the BCS storage complex. Borehole fracture pressure measurements within the Project appraisal wells indicate the minimum compressive stress is within 90% of the vertical compressive stress. This implies any unexpected faults within the BCS storage complex experience little shear loading initially and are therefore more likely to remain stable.

Limited induced shear stresses are expected within the BCS storage complex during the injection period and these will decline again during the closure period. All model realizations indicate the lateral extent of BCS pressure increases is much larger than the BCS depth, induced aquifer dilation is almost entirely accommodated by uplift of the Earth’s surface rather than deformation of the overburden. Consequently, all geomechanical model realizations indicate induced incremental shear stress smaller than the initial shear stress.

Ductile creep within the thick Lower and Upper Lotsberg Salt Formations will likely seal any unexpected fault that unexpectedly reactivates and unexpectedly forms a permeable pathway through the first seal.

Residual uncertainty is very low due to the absence of faults and the absence of stresses required to reactivate these faults and the presence of major seals within the BCS storage complex to prevent the formation of a permeable pathway even in the unexpected event of fault reactivation.

Safeguards against fractures opening: Any induced fractures cannot threaten containment unless they propagate more than 330 m upwards through the ultimate seal. Several safeguards exist to make this likelihood very low.


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The maximum injection pressure at Radway 8-19 will never exceed 32 MPa relative to an initial measured pore fluid pressure of 20 MPa and fracture closure pressure of 42 MPa. According to the measured rock properties of core material obtained from Radway 8-19, thermal stresses associated with cooling around the injectors is expected to reduce the fracture closure pressure by 4 to 9 MPai. Aquifer dilation in response to increased fluid pressures is expected to increase the fracture closure pressure by 2 to 10 MPaii. This means the fracture closure pressure may decrease by 7 MPa or increase by 6 MPa depending on the balance between these two competing effects. Consequently, injection pressure is expected to remain 3 to 16 MPa below the fracture closure pressure making fracture initiation within the BCS unlikely. Injection pressure constraints on other injectors will be established in an equivalent manner, but the absolute value will vary according on depth.

The LMS contains many clay-rich layers likely to act as weak interfaces that would slide in response to an approaching fracture that unexpectedly initiated within the BCS, causing the fracture to arrest at this interface.

The MCS minimum horizontal stress is 10% greater than the BCS and is therefore likely to arrest the vertical growth of any unexpected fracture initiation within the BCS that manages to propagates across numerous weak interfaces within the LMS. This stress contrast means any vertical fracture will take the route of least resistance and preferentially propagate horizontally within the BCS rather than vertically through the MCS.

The Devonian Red Beds provide four permeable formations able to arrest vertical fracture growth as the rate of fluid leak-off into the formation leaves insufficient pressure to propagate the fracture any further.

The Lotsberg Salt Formations are sufficiently ductile and thick to arrest any unexpected fractures that unexpectedly reach the base of these formations.

Pressure decline within the BCS during the Closure Period means the risk of fracture opening disappears with time after the end of CO2 injection.

Residual uncertainty is very low as the maximum injection pressure is designed to avoid fracture initiation and several effective mechanical barriers exist to prevent any unexpected fracture breaching all three major seals of the BCS storage complex.

i Thermal compressive stress reduction, , based on a linear coefficient of thermal expansivity, = 5x10

-5 to 10

-6

K-1

, Young’s modulus, E = 18 MPa, Poisson’s ratio, = 0.2, and a temperature change, T = -40 K, is

= ET/(1--4 to -9 MPa. ii Poro-elastic compressive stress increase, , based on a horizontal stress-arching factor, h = 0.2 to 0.8 and a pore

fluid pressure increase, P = 12 MPa, is = hP = 2 to 10 MPa


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Safeguards against acidic fluids: The likelihood of all geological seals within the BCS storage complex undergoing chemical reactions with CO2 saturated brine that create permeable pathways is very low due to the following safeguards.

Mineralogy of the first seal, the MCS, favours the eventual reduction of permeability due to reactions with acidified brine. The bulk of the minerals within the shale remain un-reactive in contact with this acidified brine.

The Lotsberg Salt Formations are made of pure halite that does not react with acidified brine. Salt creep would most likely fill any voids created by dissolution of currently unidentified reactive minerals before any permeable pathways transect the seals.

Residual uncertainty is very low due to the thickness and quality of the un-reactive Lotsberg Salt Formations.

Safeguards against third-party activities: The likelihood of third-party activities contributing to an actual loss of containment is extremely low. However, the likelihood of a perceived loss of containment due to third-party activities is moderate due to existing agricultural and industrial activities within the AOR that might influence groundwater or soil quality. The following safeguards are in place to prevent this threat.

Pore space tenure eliminates the threat of any third-party drilling into the BCS storage complex and its areal extent substantially reduces the likelihood of any future adjacent CCS project inducing additional increased BCS pressure inside the AOR sufficient to lift BCS brine above the base of groundwater protection.

Residual uncertainty remains moderate due to the absence of pre-MMV safeguards against the perceived loss of containment.

Safeguards against potential combination pathways: Although unlikely, there is the possibility of a single leak pathway exploiting multiple threats. For instance, fracturing of the MCS might connect to a poor injection well cement bond above the MCS. The presence of multiple independent safeguards against each independent threat means the likelihood of a single leak path by-passing all safeguards is extremely unlikely.

A4.3.2. Corrective Measures

In the extremely unlikely event of BCS brine or CO2 migrating out of the BCS storage complex the following safeguards are in place to control these fluids and prevent or mitigate any unwanted consequences.

Safeguards for hydrocarbon resources: The safeguards present to avoid or mitigate any potential impacts to hydrocarbon resources are:


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Physical separation between the closest producing hydrocarbon field of more than 10 km laterally and 1000 m vertically.

The Winnipegosis provides a major auxiliary storage formation expected to dissipate pressures and store CO2 or BCS brine in the unlikely event that these fluids escape the BCS storage complex.

The Prairie Evaporite is a major regional seal, 100 to 150 m thick within the AOI. Water chemistry differences between underlying and overlying aquifers indicate this is an effective regional seal.

The Beaver Hill Lake Group is an aquitard expected to provide multiple baffles to inhibit any vertical migration of fluids.

Safeguards for groundwater: These include all the geological formations previously described as safeguards for hydrocarbon resources with the additional following safeguards:

The Cooking Lake provides another major auxiliary storage formation. Fluid pressures within this formation are 600Kpa below the BCS pressure gradient due to production from the Redwater Reef Oil Field. This under-pressure means the Cooking Lake is expected to provide a preferential route for fluids unexpectedly migrating upwards from the BCS storage complex.

The Ireton seals the Redwater Reef Oil Field and is about 10 m thick above the reef and about 90 m thick elsewhere within the AOI. Most well penetration through this seal are more than 10 km away from the proposed injection sites.

The Mannville Group offers auxiliary storage capacity within multiple clastic reservoirs and producing wells inside the AOI. Any CO2 reaching this formation will no longer be in dense phase.

The Colorado Group is a proven seal for the hydrocarbon accumulations within the Mannville Group. However it does contain more than 1000 well penetrations within the AOI.

The Lea Park is a marine shale with a lateral extent greater than the AOI and a thickness of about 120 m at the Radway 8-19 well.

Mixing & dilution within groundwater. High initial groundwater pH of 7.5 to 8.8. Few adsorbed in-situ contaminants within the groundwater host rock available

for mobilisation. Buffering reactions delay acidification such as CO2 reacting with calcite.

Safeguards for soil: These include all the geological formations previously described as safeguards for hydrocarbon resources and groundwater.


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Safeguards against CO2 release into the atmosphere: These include all the geological formations previously described as safeguards for hydrocarbon resources, groundwater and soil with the additional following safeguard:

CO2 dilution by natural atmospheric mixing.

A4.4. Evaluation of Safeguards

The evaluation of these safeguards follows a systematic evidence-based approach based on collective expert judgement. The evidence derives from appraisal data, site characterisation studies, regional data and analogues. Scores are assigned using a system of three-value logic to represent:

The strength of evidence for the barrier being effective, EF

The strength of evidence against the barrier being effective, EA

Uncertainty in the evidence about the effectiveness of the barrier, 1-EF-EA

Table 12 summarises the evidenced-based evaluation of safeguards in-place to prevent any loss of containment from the BCS storage complex. Table 13 summarises the evidenced-based evaluation of safeguards in-place to mitigate or remediate any unexpected loss of containment from the BCS storage complex. To improve confidence in the process, the evidence and scores were also subject to independent expert review.

A4.5. Risks Deemed Insignificant

This risk analysis excludes many other possible threats as not credible or not having the potential to cause a significant impact. The five examples described below illustrate some of the justification for excluding these threats.

Surface Uplift: During injection, the distribution of increased pore fluid pressure inside the

storage complex will induce an increase in bulk volume due to poro-elastic effects. This in turn

induces deformations of the surrounding rock mass and the overburden will experience uplift

and some associated strains. Geomechanical calculations based on mechanical rock properties

gained from appraisal data and dynamic simulations of the pressure distributions induced by

CO2 injection yield results showing insignificant surface uplift (c. 60 mm maximum) and

subsurface strain (c. 10-5 maximum). Surface uplift already observed above the In Salah CCS

project in Algeria show similar deformation rates induced by similar rates of CO2 injection into a

formation at a similar depth (Rutqvista et al. 2008). Lateral Migration within the Storage Complex: Lateral migration of the injected CO2 or

displaced brine is not a containment risk. Unexpected lateral migration poses no direct threat to

containment. To escape the BCS storage complex, fluids must eventually migrate upwards.

Lateral migration only creates an indirect risk to containment because it may bring fluids

towards potential pathways for upwards fluid migration. Any safeguards in place against these

direct containment risks will also be effective against the indirect risks.


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Molecular Diffusion through Geological Seals: CO2 will diffuse across geological seals at the

molecular level even in the absence of any connected pore networks. However, this physical

process takes millions of years due to the thickness and extremely low rates of diffusion of

geological seals within the BCS storage complex.

Capillary Migration through Geological Seals: Injection pressure must exceed the capillary entry

pressure and sufficient time must pass for fluid front to permeate through an almost

impermeable and thick seal. Salinity differences between the BCS and Winnipegosis brines

indicate long-term isolation between these two aquifers. Injection pressure will never exceed

the MCS capillary entry pressure. The MCS permeability and thickness mean that even if

injection exceeds the capillary entry pressure, flow through the restricted pore network will take

hundreds of years and then only result in an insignificant flux. Stratigraphic heterogeneities that

may provide localized permeable pathways through geological seals pose a substantially greater

threat.


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Table 12: Evidence-based evaluation of the effectiveness of geological and engineered safeguards against containment threats.

Threat Safeguard Evidence For Evidence Against EF EA T1 Migration along a

legacy well B1.1 Injectors located away from

legacy wells 1. IHS database identifies legacy wells 2. Shortest offset distance is 21km

1. IHS database may not be complete 2. IHS database may be inaccurate 0.8 0.05

B1.2 Drilling mud forms impermeable plug

1. Weighted drilling fluid used 2. Settlement creates low K filtrate plug 3. Plug forms at bottom hole over several meters

1. Plug may not cover first seal 0.4 0.2

B1.3 Lotsberg salt creep seals borehole 1. Open-hole over Lotsberg salts 2. Documented shrinkage in LPG caverns 3. Small hole (<10 in) – long time (50 yr) 4. Thick salt layers (55-127 m) 5. Greater than 90% halite

1. None

0.7 0

B1.4 Cement plugs 1. Well abandonment and drilling reports 2. Three abandoned BCS wells inside AOI 3. Multiple cement plugs in each well 4. Large size of cement plugs

1. No positive pressure test results reported 2. Cement may degrade over c. 50 years 3. Darling lacks plugs in storage complex

0.4 0.4

T2 Migration along a MMV well

B2.1 MMV wells located away from injectors

1. MMV wells outside expected CO2 plume 1. MMV wells inside pressure front 2. Unexpected CO2 migration possible

0.2 0.5

B2.2 Reduce number of MMV wells 1. Just one MMV well per injector 1. Cannot eliminate all MMV wells 0.5 0.5

B2.3 Reduce depth of MMV wells 1. No new observation wells drilled into BCS 1. Redwater 3-4 retained for BCS monitoring 0.8 0.1

B2.4 Cement bond 1. Cementing standards & past performance 2. No sensors outside casing 3. Cement bond log

1. Washouts expected within MCS 2. Cement bond may degrade with time 0.7 0.2

B2.5 Completions design & material selection

1. Chrome casing over BCS 2. Multiple casing strings 3. Corrosion inhibitor within annulus fluid 4. Long-term integrity study

1. Acidic fluids may accelerate corrosion

0.7 0.1

T3 Migration along an injector

B3.1 Cement bond 1. Cementing standards & past performance 2. No sensors outside casing 3. Cement bond log

1. Washouts expected within MCS 2. Cement bond may degrade with time 0.7 0.2

B3.2 Completions design & material selection

1. Chrome casing over BCS 2. Three casing strings 3. Corrosion inhibitor within annulus fluid 4. Long-term integrity study

1. Acidic fluids may accelerate corrosion 2. Acidified brines may accelerate corrosion 0.6 0.2


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Table 12 continued.


matrix pathway B4.1 LMS – Baffle 1. Lateral extent greater than AOI

2. Expected thickness is 50-75 m over AOI 3. Vertical permeability is micro Darcy or less 4. Net-to-gross is 0.33 to 0.57

1. Net-to-gross increases up-dip outside AOI

0.3 0.05

B4.2 MCS – First seal 1. Lateral extent greater than AOI 2. Expected thickness is 21 to 75 m over AOI 3. Vertical permeability is micro Darcy or less

1. Pinches out to the north outside AOI 0.6 0.1

B4.3 UMS – Baffle 1. Expected thickness is 60 to 0 m over AOI 2. Vertical permeability is 1 milli-Darcy or less 3. Predominantly shale with silt & sand lenses

1. UMS absent over NE half of AOI 0.2 0.5

B4.4 Lower Lotsberg – Secondary seal 1. Lateral extent greater than AOI 2. Expected thickness is 9 to 41 m over AOI 3. Vertical permeability is nano-Darcy or less

1. Pinches out just beyond SW edge of AOI 0.8 0.1

B4.5 Devonian Red Beds – Baffle 1. Lateral extent greater than AOI 2. Combined thickness is 68-121 m over AOI 3. Vertical permeability is 1 milli-Darcy or less 4. Predominantly shale with silt & sand lenses

1. None

0.3 0

B4.6 Upper Lotsberg – Ultimate seal 1. Lateral extent greater than AOI 2. Expected thickness is 53-94 m 3. Vertical permeability is nano-Dacy or less 4. Water chemistry differences indicate isolation

1. None

0.9 0

B4.7 Tortuous path length – Capillary trapping

1. Geological pathways are typically tortuous 2. Top seal is 350 m above BCS perforations 3. Residual CO2 trapping along pathway

1. None 0.8 0


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Table 12 continued.


fault pathway B5.1 Select site away from potential

pathways 1. No faults through seals on 2D/3D seismic 1. Not all faults (offsets<20m) identified

0.8 0.1

B5.2 Catalysis & clay smear reduce permeability

1. Large confining stress favours k reduction 2. Clay smear likely in LMS; MCS; UMS

1. None 0.2 0.2

B5.3 Lower Lotsberg – Secondary seal 1. Salt creep re-seals fault after slippage 2. Expected salt thickness is 2-36 m

1. Pinches out beyond SW edge of AOI 0.8 0.1

B5.4 Upper Lotsberg – Ultimate seal 1. Salt creep re-seals fault after slippage 2. Expected salt thickness is 53-91 m 3. WPGS water distinct from BCS water

1. None 0.9 0

T6 Induced stress re-activates a fault

B6.1 Select site with no natural seismicity

1. No recorded seismicity within AOR 2. Central Alberta is tectonically stable 3. No faults seen in overburden 4. Faults not critically stressed before injection

1. Past may not indicate future seismicity

0.6 0.2

B6.2 Select site away from known faults

1. No faults through seals on 2D/3D seismic 1. Not all faults (offsets<20m) identified 2. Widespread basement faults; offsets<20m 3. Reactivated fault may grow upwards

0.3 0.3

B6.3 Select max injection pressure using geomechanics

1. Inject at >14Mpa below BCS fracture pressure 2. Fault-normal stresses remain compressive 3. Compressor & pipeline rated to 14.5Mpa

1. Injection induces shear stress on faults 0.6 0.2

B6.4 Lower Lotsberg – Reseals fault 1. Salt creep re-seals fault after slippage 2. Expected salt thickness is 2-36 m

1. Pinches out beyond the SW edge of AOI 2. Salt creep may take years to re-seal fault

0.6 0.2

B6.5 Upper Lotsberg – Reseals fault 1. Salt creep re-seals fault after slippage 2. Expected salt thickness is 53-91 m

1. Salt creep may take years to re-seal fault 0.7 0.2


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Table 12 continued.

Threat Safeguard Evidence For Evidence Against EF EA T7 Induced stress opens

fractures B7.1 Select injection pressure using

geomechanics to avoid initiating fractures

1. Inject at >14Mpa below BCS fracture pressure 2. Compressor & pipeline rated to 14.5Mpa 3. No fractures seen in BHI/core over BCS

1. Heterogeneities enhance induced stresses 2. Heterogeneities reduce fracture strengths 0.6 0.2

B7.2 LMS+MCS – Stops vertical fracture growth

1. Fractures cannot cross weak interfaces 2. LMS contains many weak interfaces 3. Fractures cannot bridge thick ductile units 4. LMS is 70m thick at Redwater 3-4 & 11-32 5. MCS is 22-90m thick over AOI 6. Pressure dissipation within LMS

1. Some heterogeneities are more brittle

0.7 0.1

B7.3 Lower Lotsberg – Stops vertical fracture growth

1. Fractures cannot bridge thick ductile units (2-36m) 2. Top is c. 250 m above BCS perforations 3. Salt creep seals open fractures

1. Salt creep may take years to seal fracture 0.6 0.2

B7.4 Upper Lotsberg – Stops vertical fracture growth

1. Fractures cannot bridge thick ductile units (>50m) 2. Salt creep seals open fracture 3. Top is c. 350 m above BCS perforations

1. Salt creep may take years to seal fracture 0.7 0.2

T8 Acidic fluids erode geological seals

B8.1 MCS - resists acid erosion 1. MCS: quartz; k-feldspar; clay; dolomite 2. Exposure to CO2 lowers brine pH to 4.0 3. Lower pH causes the k-feldspar to dissolve 4. Dissolved k-feldspar forms clays 5. These clays lower MCS permeability slightly 6. Offsets any effects due to dissolution 7. MCS is 22-90m thick over AOI

1. Rate of clay formation is slow

0.7 0.1

B8.2 Lower Lotsberg salt - resists acid erosion

1. Salt does not react with CO2 2. Salt does not react with acidified brine 3. Salt cannot dissolved in BCS brine 4. Thickness 2-36 m

1. None

0.8 0

B8.3 Upper Lotsberg salt - resists acid erosion

1. Salt does not react with CO2 2. Salt does not react with acidified brine 3. Salt cannot dissolved in BCS brine 4. Thickness 53-91 m

1. None

0.9 0


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Table 12 continued.

Threat Safeguard Evidence For Evidence Against EF EA T9 Third –party CO2

migration B9.1 Maintain offset from third party

activities 1. Requested pore space tenure 1. Many additional CCS projects expected

0.8 0.1


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Table 13: Evidence-based evaluation of the effectiveness of geological and engineered safeguards against potential consequences of an unexpected loss of containment.

Consequence Safeguard Evidence For Evidence Against EF EA C1 Hydrocarbon

resources impacted M1.1 Offset distances 1. 10km lateral offset to Redwater Field

2. 1000 m vertical offset to Redwater Field 3. BCS brine or CO2 unlikely to migrate this far

1. None 0.5 0

M1.2 Lower WPGS/Contact Rapids – Auxiliary storage

1. Lateral extent greater than AOI 2. Expected thickness is 54-76m across AOI 3. Mean porosity 7% (Radway 8-19) 4. DST demonstrate permeability 5. Regional aquifer 6. Dissolution creates permeable pathways 7. Carbon storage via mineralisation

1. Carbonates are typically heterogeneous 2. Low perm detected in some places 3. 300kPa overpressure wrt BCS gradient 4. Re-mineralization plugs porosity 0.5 0.1

M1.3 Prairie Evaporite – Seal 1. Lateral extent greater than AOI 2. Expected thickness is 100-150m across AOI 3. Composition: >40% halite 4. Vertical permeability is negligible 5. Water chem. differences indicate seal integrity

1. None

0.9 0

M1.4 Beaver Hill Lake Group – Aquitard

1. Multiple baffles to flow. 1. Water chem. similar to Cooking Lake 0.3 0.2

C2 Groundwater impacted


As for M1.2 As for M1.2 0.5 0

M2.2 Prairie Evaporite – Seal As for M1.3 As for M1.3 0.9 0

M2.3 Beaver Hill Lake Group – Aquitard

1. Multiple baffles to flow

1. Water chem. similar to Cooking Lake 0.3 0.2

M2.4 Cooking Lake – Auxiliary storage

1. Lateral extent greater than AOI 2. Expected thickness is 44-92m across AOI 3. Porosity is 3 to 12%, mean of 7% 4. Logs demonstrate permeability 5. Production effects show regional connectivity 6. 660kPa under-pressure wrt BCS gradient 7. Dissolution creates permeable pathways 8. Carbon storage via mineralization

1. Carbonates are heterogeneous 2. Down-dip connection to Leduc Reef 3. Possibility of Leduc injection within AOI 4. Re-mineralization plugs porosity 0.6 0.2


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Table 13 continued.

Consequence Safeguard Evidence For Evidence Against EF EA M2.5 Ireton – Aquitard 1. Seals Redwater Reef Oil Field

2. Lateral extent greater than AOI 3. Expected thickness above reef is 10m 4. Expected thickness off reef is 90m 5. Composition: deep marine shale 6. Most well penetrations >10km from injectors

1. Basin-scale pressure comm. across seal 2. Seal maybe absent over reefs outside AOI 3. >100 well penetrations within AOI 0.6 0.3

M2.6 Mannville Group – Auxiliary storage

1. Multiple producing clastic reservoirs 2. Group extends over entire AOI 3. Group thickness is 127-247 m across AOI 4. Porosity is 3-12 %, mean of 7% 5. 660kPa under-pressure wrt BCS gradient

1. CO2 no longer in dense phase

0.4 0.2

M2.7 Colorado Group - Aquitard

1. Seals Mannville Group HC fields 2. Lateral extent greater than AOI 3. Colorado shale thickness is110-168m 4. Composition: deep marine shale 5. Water chem. differences indicate seal integrity 6. Contains Viking hydrocarbons

1. >1000 well penetrations

0.6 0.2

M2.8 Lea Park – Aquitard 1. Lateral extent greater than AOI 2. Expected thickness is 92-170m, mean of 120m 3. Composition: marine shale 4. Water chem. differences indicate seal integrity

1. >1000 well penetrations

0.4 0.3

M2.9 Mixing & dilution within groundwater

1. Median water well spacing is 500 m 2. Allows time & volume for mixing & dilution

1. Not all potential sources points identified 2. Source maybe too close to receptor 3. Not effective for larger leak volumes

0.3 0.3

M2.10 Few adsorbed in-situ contaminants

1. XRD indicates low levels of contaminants 1. Ineffective against BCS brine contaminants 2. Limited areal sampling of mineralogy 0.3 0.3

M2.11 Buffering reactions 1. CO2 reacts with calcite; delays acidification 1. Ineffective against BCS brine contaminants 2. Limited areal sampling of mineralogy 0.3 0.3

Table 13 continued.


Heavy Oil

Consequence Safeguard Evidence For Evidence Against EF EA

C3 Soil impacted M3.1 Lower WPGS/Contact Rapids – Auxiliary storage



M3.3 Beaver Hill Lake Group – Aquitard As for M1.4 As for M1.4 0.3 0.2

M3.4 Cooking Lake – Auxiliary storage As for M2.4 As for M2.4 0.6 0.2

M3.5 Ireton – Aquitard As for M2.5 As for M2.5 0.6 0.3

M3.6 Mannville Group – Auxiliary storage As for M2.6 As for M2.6 0.4 0.2

M3.7 Colorado Group – Aquitard As for M2.7 As for M2.7 0.6 0.3

M3.8 Lea Park – Aquitard As for M2.8 As for M2.8 0.4 0.3

C4 CO2 released into

the atmosphere




M4.3 Beaver Hill Lake Group – Aquitard As for M1.4 As for M1.4 0.3 0.2

M4.4 Cooking Lake – Auxiliary storage As for M2.4 As for M2.4 0.6 0.2

M4.5 Ireton – Aquitard As for M2.5 As for M2.5 0.6 0.3

M4.6 Mannville Group – Auxiliary storage As for M2.6 As for M2.6 0.4 0.2

M4.7 Colorado Group – Aquitard As for M2.7 As for M2.7 0.6 0.3

M4.8 Lea Park – Aquitard As for M2.8 As for M2.8 0.4 0.3

M4.9 CO2 dilution by natural atmospheric mixing

1. Average wind speed is 15 km/hour 2. Few wind breaks present in landscape

1. Reduced mitigation of climate change 2. CO2 may collect in natural hollows 0.4 0.4


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APPENDIX 5. EVALUATION OF MONITORING TECHNOLOGIES

A5.1. Method of Evaluation

The method adopted for evaluating monitoring technologies is as follows. 1. Define the monitoring tasks required to support the identified active safeguards.

2. Identify candidate monitoring technologies with potential to fulfill at least one monitoring

task.

3. Screen the candidate technologies against the tasks assuming the information gained is both

free and perfect, and then regret any still judged incapable of the task.

4. Evaluate the effectiveness of technologies against the tasks using expert opinions. Document

this process by recording and scoring evidence for and against including any uncertainty.

5. Estimate the lifecycle monitoring costs of each technology.

6. Estimate the lifecycle benefits generated by each technology in terms of risk reduction.

7. Rank technologies according to their overall benefits and costs to the Project.

8. Evaluate the effectiveness of the identified active safeguards triggered by high-ranking

monitoring technologies.

A5.2. Identification of Monitoring Tasks

Table 14 lists the monitoring tasks required to support each active safeguard identified to protect conformance and containment. These tasks divide into four distinct groups:

Containment monitoring tasks below the Upper Lotsberg Salt: In the unlikely event of an

increased likelihood of a loss of containment, this monitoring will be designed to:

Trigger preventative controls to prevent or reduce the likelihood of fluids migrating

above the BCS storage complex.

Containment monitoring tasks above the Upper Lotsberg Salt: In the unlikely event of any loss

of containment, this monitoring will be designed to:

Trigger corrective controls to avoid or reduce the likelihood of significant environmental

impacts.

Contingencies must also exist to allow for additional monitoring in the event of any

detected loss of containment to characterize the impact and verify the efficacy of any

correction measures applied.

Conformance monitoring tasks within the BCS storage complex: To verify that the build-up and

migration of pore fluid pressures and CO2 through time remains consistent with the range of

published forecasts and provide the necessary information to revise and narrow the range of

these forecasts whenever appropriate.

CO2 inventory measurement tasks: To report the rate and volume of CO2 injected into the storage complex and potentially emitted from the storage complex into the atmosphere.


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Table 14: The monitoring tasks identified based on an assessment of site-specific containment and conformance risks.

Monitoring Tasks Containment Monitoring Tasks Below the Upper Lotsberg Salt T1 Detect migration of CO2 or brine along a legacy well T2 Detect migration of CO2 or brine along a MMV well T3 Detect migration of CO2 or brine along an injector T4 Detect migration of CO2 or brine along matrix pathways T5 Detect migration of CO2 or brine along a fault pathway T6 Detect fault reactivation T7 Detect induced fractures opening T8 Detect fluid migration through pathways created by acidic fluids T9 Third –party activities induce CO2 or brine migration Containment Monitoring Tasks Above the Upper Lotsberg Salt C1 Detect CO2 entering hydrocarbon resources C2 Detect and characterise any contamination of protected groundwater C3 Detect and characterise any contamination of surface soils C4 Detect and quantify any CO2 releases into the atmosphere Conformance Monitoring Tasks within the BCS S1 Detect migration of CO2 within the BCS S2 Detect migration of pressure within the BCS CO2 Inventory Measurement Tasks I1 Measure injection volume per well I2 Measure any CO2 emissions from the storage site into the atmosphere

A5.3. Identification of Monitoring Technologies

The 56 identified monitoring technologies were drawn from a range of authoritative sources proposing technologies suitable for MMV22,34,35,37-40 and supplemented by expert knowledge available within the Shell Group. The identified technologies may be classified into 4 distinct groups:

In-Well Monitoring: These are direct measurements of down-hole changes made either by

permanent sensors incorporated into the well design, or by occasional petrophysical logging or

well integrity testing activities that require well intervention. This group of technologies

provides detailed information about changes within the well and the near-well environment

(e.g. within 5 m), but provides no information about changes further afield.

Geochemical Monitoring: These are the methods of monitoring chemical changes throughout

the subsurface using geochemical measurements within observation wells. These

measurements are made either by permanent sensors incorporated into the well design, or

through the occasional collection of fluid samples from the well for laboratory analysis. This

group of technologies may provide detailed information about the transport and reaction of

chemical species above the storage complex indicative of any loss of containment and its

potential impacts.

Geophysical Monitoring: These are the methods of monitoring physical changes throughout the

subsurface using remote-sensing techniques. This group of technologies may provide detailed

images of the spatial distribution of CO2 and increased pore fluid pressures within or above the

storage complex.


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Near-Surface Monitoring: These are the methods of monitoring near-surface changes within the

biosphere or atmosphere.

Many technologies within the first three categories depend on sensors within wells. There are four different types of wells that may support these kinds of monitoring:

CO2 injection wells in the BCS: The measurements maybe taken either during the injection

period and/or in the post-injection but pre-abandonment phase.

Observation wells in the BCS: To provide additional direct monitoring opportunities inside the

storage complex.

Observation wells in the Winnipegosis: To provide direct monitoring opportunities within the

first permeable formation above the ultimate seal.

Observation wells in the Protected Groundwater Zone: To provide direct monitoring

opportunities to verify the absence of any adverse impacts to groundwater quality or provide

early warning of the need for corrective measures to protect groundwater quality.

Together, all the identified monitoring technologies possess a wide range of complimentary and overlapping capabilities (Table 15) with varying degrees of sensitivity, resolution, reliability and cost.

A5.4. Screening of Technologies

Table 17 summarises the screening of candidate monitoring technologies according to their applicability to the identified monitoring tasks. This first step eliminates or reduces the scope of applicability for most technologies and significantly reduced the effort required to complete the next step.

A5.5. Evaluation of Technologies

Evaluation of conformance and containment monitoring technologies is an evidence-based expert judgement according to these criteria:

Is it fast enough? Meaning that the expected detection delay is acceptable, as it still allows

sufficient time for intervention to prevent or mitigate any adverse environmental effects.

Is it precise enough? Meaning that the measurements are sufficiently reliable and sensitive to

trigger effective control measures.

Is it big enough? Meaning that the monitored region is large enough to include the area where

unexpected migration of BCS brine has the potential to cause adverse environmental effects.

Tables 18-20 summarise the evidenced-based evaluation of conformance and containment monitoring technologies. For each monitoring task, there is a wide range of partially effective monitoring technologies (Figure 16). No monitoring technology is perfect – but the combination of multiple technologies with different capabilities provides a highly effective integrated monitoring system.


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A5.5.1. Ranking of Technologies

Monitoring for containment is a safety-critical task and takes precedence over conformance monitoring. Therefore, technology ranking considers only the benefits and costs of each technology in relation to the containment monitoring tasks. Figure 6 shows the ranking of each monitoring option according to a combined evaluation of benefits and costs. This cost-benefit assessment is the basis for selecting technologies to perform the containment monitoring tasks. Many of these monitoring technologies will also support the conformance monitoring tasks at the same time for no additional cost. Should, however, some additional monitoring be required to satisfy all the conformance monitoring tasks then these must be justified by a value of information assessment on a case-by-case basis.

A5.5.2. Ranking Benefits

Individual monitoring systems may be applicable to multiple tasks. For instance, time-lapse seismic methods might be highly effective at monitoring the conformance of CO2 inside the BCS and partially effective at a range of different containment monitoring tasks. The metric used for estimating the total benefit of each technology is simply the number of monitoring tasks weighted by their expected likelihood of success. This is a simple measure useful only for comparing the relative benefits of each technology assuming all monitoring tasks are equally important. This ranking is sufficient to support the matching of monitoring technologies with the active safeguards.

A5.5.3. Ranking Costs

The estimated lifecycle costs for each monitoring technology depends on the notional acquisition schedule shown in Table 16. Estimates of any initial capital costs and the subsequent operating costs relied on current local market conditions. These estimates are not final and remain subject to change. Figure 6 shows a good distribution of costs and benefits. Not all high-benefit technologies are also high cost and several high-cost technologies deliver little benefit. Some care is required when interpreting this 5-by-5 matrix as differences of less than 20% may not be apparent. The criteria for selecting monitoring technologies cannot translate to a dividing line on this matrix with everything above the line in and everything else out. The prime reason for this is that not all technologies are independent, for instance if time-lapse VSP fails then so will 2D and 3D surface seismic. Moreover, if time-lapse 3D surface seismic succeeds then 2D surface seismic provides no new information. Allowance for these inter-dependencies is essential and once again relies on expert judgement.


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Table 15: Summary of the technical capabilities of each identified monitoring technology.

Monitoring System Information Gained Availability Coverage

In-Well Monitoring Cement bond logs CBL Initial quality of cement bond Once, during well completion Entire well length

Time-lapse ultrasonic casing imaging USIT Casing corrosion detection During well intervention Injection and monitoring wells

Time-lapse EM casing imaging EMIT Casing corrosion detection During well intervention Injection and monitoring wells

Time-lapse multi-finger calliper CAL Tubing corrosion detection On demand Injection wells

Annulus pressure monitoring APM Pressure leak detection Continuously Injection and monitoring wells

Injection rate metering at wellhead IRM Rate and volume of CO2 injected Continuously Injection wells

Wellhead pressure-temperature gauge WHPT Injection pressure, temperature Continuously Injection wells

Down-hole pressure-temperature gauge DHPT Down-hole pressure, temperature Continuously Injection and monitoring wells

Mechanical well integrity pressure testing MWIT Leak detection On demand Injection and monitoring wells

Well-head CO2 detectors WHCO2 CO2 leak detection Continuously Injection and monitoring wells

Tracer injection & gamma logging TRL Leak detection & CO2 conformance Continuously / On demand Injection and monitoring wells

Time-lapse saturation logging SATL Leak detection & injection profile During well intervention Injection and monitoring wells

Time-lapse temperature logging TMPL Leak detection outside casing During well intervention Injection and monitoring wells

Time-lapse annular flow noise logging AFNL Leak detection outside casing During well intervention Entire borehole

Time-lapse density logging DENL Leak detection outside casing During well intervention Entire borehole

Time-lapse sonic logging SONIC Leak detection outside casing During well intervention Entire borehole

Fibre-optic distributed temperature sensing DTS Leak detection outside casing Continuously Entire length of FO down-hole

Fibre-optic distributed pressure sensing DPS Leak detection outside casing Continuously Many discrete locations down-hole

Real time casing imager RTCI Leak detection outside casing Continuously Region of wrapped FO down-hole

Fibre-optic distributed acoustic sensing DAS Leak detection outside casing Continuously Entire length of FO down-hole

Pressure interference testing PIT Fraction of path containing CO2 On demand Injection and monitoring wells

Pressure fall-off test PFOT Storage capacity On demand Injection wells


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Geochemical Monitoring Water chemistry monitoring WC Leak detection, storage mechanisms On demand Monitoring wells

Down-hole electrical conductivity monitoring WEC Brine leak detection & impact assessment Continuously Monitoring wells

Down-hole pH monitoring WPH CO2 leak detection & impact assessment Continuously Monitoring wells

Artificial tracer monitoring ATM Leak detection & impact assessment On demand Monitoring wells

Natural isotope tracer monitoring NTM Leak detection & impact assessment on demand Monitoring wells

U-tube fluid sampling UTUBE Leak detection, storage mechanisms Continuous, or on-demand Monitoring wells

Isotube fluid sampling ITUBE Leak detection, storage mechanisms Continuous, or on-demand Monitoring wells

Ground water gas analysis GWG Leak detection & impact assessment On demand Discrete locations across AOR

Soil CO2 gas flux surveys SGF CO2 leak detection & impact assessment On demand Discrete locations across AOR

Soil CO2 gas concentration surveys SGC CO2 leak detection & impact assessment On demand Discrete locations across AOR

Soil pH surveys SPH CO2 leak detection & impact assessment On demand Discrete locations across AOR

Soil salinity surveys SSAL Brine leak detection & impact assessment On demand Discrete locations across AOR


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Geophysical Monitoring Time-lapse 3D vertical seismic profiling VSP3D 3D distribution of CO2 plume On demand, winter only Within 1km of the wellbore

Time-lapse surface 3D seismic SEIS3D 3D distribution of CO2 plume On demand, winter only Entire CO2 plume

Time-lapse surface 2D seismic SEIS2D 2D distribution of CO2 plume On demand, winter only Entire CO2 plume

Surface microseismic monitoring SMS Microseismic catalogue Continuously, or on demand Underneath geophone array

Down-hole microseismic monitoring DHMS Microseismic catalogue Continuously, or on demand <600m of monitoring well geophones

Time-lapse surface microgravity SGRAV Areal distribution of CO2 plume On demand Entire CO2 plume

Time-lapse down-hole microgravity DHGRAV Detection of CO2 plume near borehole On demand Monitoring wells

Time-lapse surface controlled source EM CSEM Spatial distribution of CO2 plume On demand, winter only Entire CO2 plume

Time-lapse cross-well controlled source EM CSEMX Cross-well distribution of CO2 plume On demand Section between wells within c. 500m

Time-lapse cross-well seismic SEISX 2D distribution of CO2 plume On demand Section between wells within c. 500m

Magnetotelluric – natural source EM NSEM Spatial distribution of CO2 plume On demand, winter only Entire CO2 plume

InSAR – Interferometric Synthetic Aperture Radar INSAR Pressure front & fault re-activation Monthly Entire region of elevated pressure

GPS – Global Positioning System GPS Pressure front & fault re-activation Continuously or on demand Entire region of elevated pressure

Surface tilt-meters STLT Pressure front & fault re-activation Continuously Entire region of elevated pressure

Down-hole tilt-meters DHTLT Vertical distribution of pressure changes Continuously Monitoring wells

Surface Monitoring DIAL – Differential absorption LIDAR DIAL CO2 leakage rate to atmosphere On demand Areal coverage over parts of AOR

Line-of-sight gas flux monitoring LOSCO2 CO2 leakage rate to atmosphere Continuously or on demand Areal coverage over parts of AOR

Atmospheric eddy correlation AEC CO2 leakage rate to atmosphere On demand Discrete locations across AOR

Airborne infra-red laser gas analysis AIRGA CO2 leakage rate to atmosphere On demand Areal coverage of entire AOR

Hand-held infra-red gas analysers HIRGA Leak detection & impact assessment On demand Discrete locations across AOR

Satellite or airborne multi-spectral image analysis MIA Leak detection & impact assessment Monthly Entire AOR and beyond

Ecosystem studies ESS Leak detection & impact assessment On demand Discrete locations across AOR


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Table 16: Summary of monitoring frequencies and quantities assumed to estimate costs for each technology.

Monitoring Systems

Quantity Baseline Injection Closure In-Well Monitoring

Cement bond logs CBL 10 Once - -

Time-lapse ultrasonic casing imaging USIT 10 Once Every 5 years Every 10 years

Time-lapse EM casing imaging EMIT 10 Once Every 5 years Every 10 years

Time-lapse multi-finger casing calliper CAL 10 Once Every 5 years Every 10 years

Annulus pressure monitoring APM 10 Continuous Continuous Continuous

Injection rate metering IRM 5 - Continuous -

Wellhead pressure-temperature gauge WHPT 5 - Continuous Continuous

Down-hole pressure-temperature gauge DHPT 10 - Continuous Continuous

Mechanical well integrity pressure testing MWIT 5 Once Every year Every year

Well-head CO2 detectors WHCO2 10 - Continuous Continuous

Tracer injection / wire line logging TRL 1 - Every 5 years Every 10 years

Time-lapse saturation logging SATL 10 - Every 5 years Every 10 years

Time-lapse temperature logging TMPL 10 - Every 5 years Every 10 years

Time-lapse annular flow noise logging AFNL 10 - Every 5 years Every 10 years

Time-lapse density logging DENL 10 - Every 5 years Every 10 years

Time-lapse sonic logging SONIC 10 - Every 5 years Every 10 years

Fibre-optic distributed temperature sensing DTS 10 Continuous Continuous Continuous

Fiber-optic distributed pressure sensing DPS 10 Continuous Continuous Continuous

Real time casing imager RTCI 10 Continuous Continuous Continuous

Fibre-optic distributed acoustic sensing DAS 10 Continuous Continuous Continuous

Pressure interference testing PIT 5 - Every year Every year

Pressure fall-off test PFOT 5 - Every year Every year Geochemical Monitoring

Water chemistry monitoring WC 15 Every year Every year Every 2 years

Down-hole electrical conductivity monitoring WEC 15 Continuous Continuous Continuous

Down-hole pH monitoring WPH 15 Continuous Continuous Continuous

Artificial tracer monitoring ATM 1 Every year Every year Every 2 years

Natural isotope tracer monitoring NTM 15 Every year Every year Every 2 years

U-tube fluid sampling UTUBE 5 Every year Every year Every 2 years

Isotube fluid sampling ITUBE 5 Every year Every year Every 2 years

Ground water gas monitoring GWG 15 Every year Every year Every 2 years

Soil gas flux monitoring SGF 1 Every year Every year Every 2 years

Soil gas concentration monitoring SGC 1 Every year Every year Every 2 years

Soil pH surveys SPH 1 Every year Every year Every 2 years

Soil salinity surveys SSAL 1 Every year Every year Every 2 years Geophysical Monitoring

Time-lapse 3D vertical seismic profiling VSP3D 5 Once 7 times -

Time-lapse surface 3D seismic SEIS3D 5 Once Every 5 years Once

Time-lapse surface 2D seismic SEIS2D 5 Once Every 5 years Once


Heavy Oil

Time-lapse cross-well seismic SEISX 5 Once Every 5 years Once

Surface microseismic monitoring SMS 5 - Continuously -

Down-hole microseismic monitoring DHMS 5 - Continuously -

Time-lapse surface microgravity SGRAV 5 Once Every 5 years Once

Time-lapse down-hole microgravity DHGRAV 5 Once Every 5 years Once

Time-lapse surface controlled source EM CSEM 5 Once Every 5 years Once

Time-lapse cross-well controlled source EM CSEMX 5 Once Every 5 years Once

Magnetotelluric – natural source EM NSEM 5 Once Every 5 years Once

InSAR – Interferometric Synthetic Aperture Radar INSAR 1 Monthly Monthly Monthly

GPS – Global Positioning System GPS 1 Continuous Continuous Continuous

Surface tilt meters STLT 1 Continuous Continuous Continuous

Down-hole tilt meters DHTLT 5 Continuous Continuous Continuous Surface Monitoring

DIAL – Differential absorption LIDAR DIAL 5 Continuous Continuous Continuous

Line-of-sight gas flux monitoring LOSCO2 5 Continuous Continuous Continuous

Atmospheric eddy correlation AEC 1 Continuous Continuous Continuous

Airborne infra-red laser gas analysis AIRGA 1 Once Every year Every 2 years

Hand-held infra-red gas analysers HIRGA 1 Every year Every year Every 2 years

Satellite or airborne hyper-spectral image analysis HIA 1 Every year Every year Every 2 years

Ecosystem studies ESS 1 Every year Every year Every 2 years


Heavy Oil

Table 17: Screening candidate monitoring systems against the identified monitoring tasks.

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Detect migration of CO2 or brine along a legacy well 1

Detect migration of CO2 or brine along a MMV well 2

Detect migration of CO2 or brine along an injector 3

Detect migration of CO2 or brine via matrix pathways 4

Detect migration of CO2 or brine along fault pathways 5

Detect fault reactivation 6

Detect induced fractures opening 7

Third-party activities induce CO2 or brine migration 8

Detect CO2 entering HC resources 9

Detect & characterise groundwater contamination 10

Detect & characterise surface soils contamination 11

Measure any CO2 releases into the atmosphere 12

Detect migration of CO2 within the BCS 13

Detect migration of pressure within the BCS 14

Monitor injection pressure per well 15

Monitor injection rate per well 16

Monitor injection volume per well 17

Monitor total injection volume 18

INJ

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Legend

Screened Out

Screened In

Candidate Monitoring Systems

SurfaceGeophysicalGeochemical

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Monitoring Tasks


Heavy Oil

Figure 16: Monitoring technologies ranked according to their expected effectiveness for each containment monitoring

task described in Table 14 demonstrate a wide range of viable options exists. The height of each blue bar denotes the expected success rate from 0 to 100%.


Heavy Oil

Table 18: Evaluation of technologies for conformance monitoring. This is an evidenced-based evaluation of the candidate technologies according to their expected effectiveness at the identified tasks. EF and EA denote the scores assigned, based on expert judgement, to represent the strength of evidence for and evidence against the candidate technology being effective at the task. The degree of uncertainty in this evaluation is denoted by 1 – EF – EA, where 0<EF<1 and 0<EA<1.

Task Technology Indicator Evidence For Evidence Against EF EA

S1 Detect migration of CO2 within the BCS SEIS3D Time-lapse surface 3D

seismic Amplitude increase inside the BCS is consistent with the predicted plume

1. Areal coverage over entire CO2 plume 2. Expect to image areal conformance of CO2 3. Lateral resolution c. 25 m

1. Acquisition noise may mask indicator 2. No resolution of vertical conformance 3. Cannot quantify CO2 saturation 4. No pilot – so technical feasibility not proven

0.8 0.1

VSP3D Time-lapse 3D vertical seismic profiling

Amplitude increase inside the BCS is consistent with the predicted plume

1. Areal coverage within c. 750m of well 2. Expect to image areal conformance of CO2 3. Lateral resolution c. 50 m

1. Acquisition noise may mask indicator 2. Removing tubing threatens well integrity 3. May not image entire plume after 2-14 years 4. No resolution of vertical conformance 5. Cannot quantify CO2 saturation 6. No pilot – so technical feasibility not proven

0.7 0.2

DHGRAV Time-lapse down-hole microgravity in a WPGS observation well

Bulk density decrease inside the BCS consistent with the predicted plume

1. Partial sampling of areal conformance 2. Well not required to penetrate ultimate seal 3. Greater sensitivity than surface microgravity

1. Limited areal sampling – may be insufficient 2. Displaced brine mass masks CO2 signal 3. Potentially insensitive to changes inside BCS 4. Feasibility study results pending

0.3 0.2

SEIS2D Time-lapse surface 2D seismic

Amplitude increase inside the BCS is consistent with the predicted plume

1. Parital sampling of areal conformance 2. Expect to image areal conformance of CO2 3. In-line lateral resolution c. 25 m

1. Limited areal sampling – may be insufficient 2. Acquisition noise may mask indicator 3. No resolution of vertical conformance 4. Cannot quantify CO2 saturation 5. No pilot – so technical feasibility not proven

0.4 0.4

PIT Pressure interference testing between injector and a BCS observation well

Pressure transient travel-time from injector to observation well is consistent with the predicted plume

1. Indicates average lateral extent of plume 2. Frequent measurements possible

1. Well penetrates all seals – containment risk 2. Limited areal sampling – may be insufficient

0.2 0.7

SATL Time-lapse saturation logging in a BCS observation well

CO2 saturation profiles inside BCS consistent with predicted plume

1. Direct measure of vertical conformance 2. Partial sampling of areal conformance

1. Well penetrates all seals – containment risk 2. Limited surveys – miss breakthrough time 3. Limited areal sampling – may be insufficient

0.1 0.7


Heavy Oil

DENL Time-lapse density logging in a BCS observation well

Density profiles inside the BCS consistent with the predicted plume



0.1 0.7

SONIC Time-lapse sonic logging in a BCS observation well

P-wave and S-wave velocity profiles inside BCS consistent with predicted plume



0.1 0.7

NSEM Magnetotelluric – natural source EM

Conductivity decrease inside the BCS is consistent with the predicted plume

1. Areal coverage over entire CO2 plume 2. Lateral resolution c. 2 km

1. Resistive salts mask CO2 signal 2. Resistive basement masks CO2 signal 3. Insufficient sensitivity to changes inside BCS

0 0.9

CSEM Time-lapse surface controlled source EM

Conductivity decrease inside the BCS is consistent with the predicted plume


1. Resistive salts mask CO2 signal 2. Resistive basement masks CO2 signal 3. Insufficient sensitivity to changes inside BCS

0 0.9

SGRAV Time-lapse surface microgravity

Bulk density decrease inside the BCS is consistent with the predicted plume


1. Displaced brine mass masks CO2 signal 2. Insufficient sensitivity to changes inside BCS

0.1 0.9

S2 Detect migration of pressure within the BCS INSAR InSAR – Interferometric

Synthetic Aperture Radar Surface uplift is consistent with predicted BCS pressure distribution

1. Detects dilation of any shallow formation 2. Sensitive to uplifts >1mm/year 3. Monthly monitoring over entire AOR

1. Natural monitoring targets maybe limited 2. Maybe cannot monitor through snow cover

0.6 0.2

DPS Fibre-optic distributed pressure sensing in a BCS observation well

Changes in pressure profiles through the BCS are consistent with the predicted pressure distribution

1. Direct measurement 2. Monitors several discrete points 3. Continuous monitoring 4. Measures pressure profile through BCS


0.3 0.5

RTCI Real time casing imager in a BCS observation well

Changes in pressure profiles through the BCS are consistent with the predicted pressure distribution

1. Direct measurement 2. Continuous monitoring 3. Distributed monitoring over entire BCS 3. Measures pressure profile through BCS


0.3 0.5

DHPT Down-hole pressure-temperature gauge in a BCS observation well

Pressure changes inside the BCS are consistent with predicted pressure distribution

1. Direct measurement 2. Continuous monitoring


0.3 0.5

PFOT Pressure fall-off test in an injector

Changes in average BCS pressure are consistent with the predicted pressure distribution

1. Direct measurement 1. No areal sampling of pressure distribution 0.1 0.7


Velocity decrease inside BCS consistent with predicted pressure distribution

1. None 1. Insufficient sensitivity to pressure changes 0 0.9


Heavy Oil







DHMS Down-hole microseismic monitoring in a WPGS observation well

Pattern of microseismic events inside the BCS is consistent with the predicted pressure distribution

1. None 1. Detect magnitude -3 events up to 600m away 2. Insufficient areal coverage 3. Geological heterogeneity affects pattern

0 0.9

SMS Surface microseismic monitoring

Pattern of microseismic events inside the BCS is consistent with the predicted pressure distribution

1. None 1. Insufficient sensitivity to detect BCS events 2. Geological heterogeneity affects pattern

0 1


Heavy Oil

Table 19: Evaluation of technologies for monitoring to prevent any loss of containment. This is a evidenced-based evaluation of the candidate technologies according to their expected effectiveness at the identified tasks. EF and EA denote the scores assigned, based on expert judgement, to represent the strength of evidence for and evidence against the candidate technology being effective at the task. The degree of uncertainty in this evaluation is denoted by 1 – EF – EA, where 0<EF<1 and 0<EA<1.

Task Monitoring System Indicator Evidence For Evidence Against EF EA

T1 Detect migration of CO2 or brine along a legacy well

DHPT Down-hole pressure-temperature gauge in a WPGS observation well

Sustained Winnipegosis pressure increase

1. Continuous monitoring 2. Early warning before brine or CO2 arrives 2. Sensitive to low flux rates (1 ppm) 3. Detection within 1-6 months

1. Gauge drift may mask indicator 2. Natural changes may mask indicator 3. WPGS pressure barriers may mask indicator 4. WPGS permeability may be insufficient

0.8 0.1

INSAR InSAR – Interferometric Synthetic Aperture Radar

Surface uplift indicates a sufficient BCS pressure rise to lift brine above BGP is expected to reach a legacy well

1. Maps BCS dilation due to pressure rise 2. Sensitive to uplifts >1mm/year 3. Monthly monitoring over entire AOR

1. Natural monitoring targets maybe limited 2. Cannot monitor through snow cover

0.6 0.2

RIA Satellite or airborne radar image analysis

Change in radar reflectivity at well location indicates soil salinity increase

1. Brine increases radar reflectivity 2. Covers entire AOR

1. Monthly monitoring only 2. Natural changes may mask indicator 3. Not an early indicator 4. Some potential for false or missed alarms

0.4 0.3

MIA Satellite or airborne multi-spectral image analysis

Change in vegetation patterns at well location indicate vegetation stress due to brine or CO2

1. Brine or CO2 induces vegetation changes 2. Covers entire AOR

1. Annual monitoring only 2. Changes may take several years to appear 3. Natural changes may mask indicator 4. Not an early indicator 5. High potential for false or missed alarms

0.3 0.3

LOSCO2 Line-of-sight gas flux monitoring Sustained CO2 flux above background levels

1. Validate no CO2 migration along wells 1. Sensitivity threshold may be insufficient 2. Not sensitive to brine migration 3. Unable to detect migration at depth 4. Not an early indicator

0.2 0.5

WHCO2 Well-head CO2 detectors CO2 concentrations exceed background levels

1. Continuous monitoring at well-heads 1. Low flux rates may not be detected 2. Dispersion may limit sensitivity 3. Wellheads removed 4. Not an early indicator

0.4 0.6


Heavy Oil

T2 Detect migration of CO2 or brine along a BCS observation well DHPT Down-hole pressure-

temperature gauge in a WPGS observation well


1. Continuous monitoring 2. Early warning before brine or CO2 arrives 2. Sensitive to low flux rates (1 ppm) 3. Detection within 1-6 months


0.8 0.1

CBL Cement bond logs Poor cement bond quality 1. Industry standard technology 2. Validates cement bond quality

1. Small conduits may not be detected 2. Cement bond quality may degrade with time

0.8 0.2

DAS Fibre-optic distributed acoustic sensing

Sustained flow noise migrating upwards above the first seal

1. Continuous monitoring 2. Coverage along entire wellbore 3. Based on proven annular flow noise logging

1. Noise undetectable for low flux rates 2. Less sensitive if fibre install behind casing 3. Impairs cement bond if fibre outside casing 4. Emerging technology – development ongoing

0.6 0.1


Surface uplift indicates a sufficient BCS pressure rise to lift brine above BGP is expected to reach the well



0.4 0.2


1. Continuous monitoring at well-heads 1. Low flux rates may not be detected 2. Dispersion may limit sensitivity

0.4 0.3

MWIT Mechanical well integrity pressure testing

Inability to sustain applied pressure within the zone of the straddle packer

1. Industry standard technology 2. Coverage along the entire wellbore 3. Identifies depth interval of leak path

1. Leak may go undetected for years 2. Pump leaks may mask casing leaks

0.5 0.4

USIT Time-lapse ultrasonic casing imaging

Reduction of metal thickness due to corrosion

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years 3. Will not detect pinhole corrosion

0.5 0.4

EMIT Time-lapse EM casing imaging

Reduction of casing & tubing thickness

1. Industry standard technology 2. Distinguishes tubing & casing corrosion

1. Only monitor every few years 2. Leak may go undetected for years 3. Will not detect pinhole corrosion

0.5 0.4

APM Annulus pressure monitoring

Sustained annular pressure increase

1. Continuous monitoring 2. Well-established technology 3. Sensitive to migration inside the casing

1. Insensitive to migration outside casing 0.5 0.5

RIA Satellite or airborne radar image analysis

Change in radar reflectivity at well location indicates soil salinity increase

1. Brine increases radar reflectivity 2. Covers entire AOR

1. Monthly monitoring only 2. Natural changes may mask indicator 3. Not an early indicator 4. Some potential for false or missed alarms

0.4 0.3




1. Annual monitoring only 2. Changes may take several years to appear 3. Natural changes may mask indicator

0.3 0.3


Heavy Oil


Appearance of an amplitude anomaly above the first seal around the well

1. Areal coverage over entire CO2 plume 2. Expect to image the CO2 plume 3. Lateral resolution c. 25 m 4. Vertical resolution c. 10 m

1. No sensitivity expected to brine migration 2. Acquisition noise may mask indicator 3. Only monitor every few years 4. Leak may go undetected for years 5. Unable to detect CO2 leaks <10-60 ktonnes

0.3 0.3



1. Areal coverage within c. 750m of well 2. Expect to image the CO2 plume 3. Lateral resolution c. 50 m 4. Vertical resolution c. 5 m

1. No sensitivity expected to brine migration 2. Acquisition noise may mask indicator 3. Only monitor every few years 4. Leak may go undetected for years 5. Unable to detect CO2 leaks <10-60 ktonnes 6. Removing tubing threatens well integrity

0.3 0.3

CAL Time-lapse multi-finger casing calliper

Increase in the internal casing diameter

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years

0.4 0.4

LOSCO2 Line-of-sight gas flux monitoring

Sustained CO2 flux above background levels

1. Validate no CO2 migration along wells 1. Sensitivity threshold may be insufficient 2. Not sensitive to brine migration 3. Only monitor every few years 4. Leak may go undetected for years

0.2 0.5

AIRGA Airborne infra-red laser gas analysis

Increase in CO2 concentration around well

1. Areal coverage over entire CO2 plume 1. Likely insufficient sensitivity 0.2 0.6

SONIC Time-lapse sonic logging Reduction in sonic velocity above the first seal

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years 3. May not detect small flux rates 4. Less sensitive to brine migration

0.2 0.7

AFNL Time-lapse annular flow noise logging

Flow noise above the first seal outside the casing

1. Established technology 1. Only monitor every few years 2. Leak may go undetected for years 3. May not detect small flux rates 4. Less sensitive to brine migration

0.2 0.7

SATL Time-lapse saturation logging

Increase in CO2 or brine saturation outside casing


0.2 0.7

DENL Time-lapse density logging Reduction in density above first seal

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years 3. May not detect small flux rates 4. Insensitive to brine migration

0.2 0.7


Heavy Oil



1. Expect to image the CO2 plume 2. In-line lateral resolution c. 25 m 3. Vertical resolution c. 10 m

1. Limited areal sampling – may miss anomaly 2. No sensitivity expected to brine migration 3. Acquisition noise may mask indicator 4. Only monitor every few years 5. Leak may go undetected for years 6. Unable to detect CO2 leaks <10-60 ktonnes

0.1 0.7

RTCI Real time casing imager Sustained pressure increase outside casing migrating upwards above the first seal

1. Continuous monitoring 2. Contiguous coverage over the first seal 3. Detects pressure changes of >0.3 Mpa

1. Untested application of RTCI 2. May not detect low flux rates

0.2 0.8

DTS Fibre-optic distributed temperature sensing

Sustained low temperature anomaly migrating upwards above the first seal

1. Continuous monitoring 2. Coverage along entire wellbore

1. CO2 likely in thermal equilibrium with formation 2. Likely not sensitive to CO2 3. Not sensitive to brine migration

0.1 0.8

DPS Fibre-optic distributed pressure sensing

Sustained pressure increase outside casing migrating upwards above the first seal

1. Continuous monitoring 2. Coverage over the seals 3. Provides early indication

1. Requires observation well to penetrate seals 2. Creates additional threat to containment

0.1 0.8

TMPL Time-lapse temperature logging

Low temperature anomaly above first seal

1. Industry standard technology 2. Coverage along entire wellbore

1. CO2 likely in thermal equilibrium with formation 2. Likely not sensitive to CO2 3. Not sensitive to brine migration

0.1 0.9


Appearance of a negative gravity anomaly around the well

1. Areal coverage over entire CO2 plume 1. Displaced brine mass masks CO2 signal 2. Smallest detectable leak: 5-25 Mtonnes CO2 3. No sensitivity to BCS brine movements

0.1 0.9

WC Water chemistry monitoring

Change in Redbeds water chemistry indicates mixing with BCS brine or injected CO2

1. Sensitive to small changes in water chemistry 1. Requires observation well to penetrate seals 2. Creates additional threat to containment 3. Unlikely to provide early warning

0.1 0.9


Conductivity reduction anomaly above the first seal around the well

1. Areal coverage over entire CO2 plume 1. Insufficient sensitivity to changes below salt 2. Insufficient depth resolution

0 0.9




0 0.9


Heavy Oil

T3 Detect migration of CO2 or brine along an injector CBL Cement bond logs Poor cement bond quality 1. Well-established technique 1. Small conduits may not be detected

2. Cement bond quality may degrade with time 0.8 0.2

DTS Fibre-optic distributed temperature sensing

Sustained low temperature anomaly migrating upwards

1. Continuous monitoring 2. Coverage along entire wellbore 3. Injected CO2 25C cooler than brine 4. Detect CO2 migration outside casing 5. CO2 reduces heat transfer from the formation

1. Cooling undetectable for low flux rates 2. Variable injection rates may mask indicator 3. Not sensitive to brine migration

0.6 0.2

OIA Operational Integrity Assurance system

Exception triggered by pre-defined criteria for continuously recorded well monitoring data

1. Combines all continuous well data 2. Automated diagnostics – avoids human error 3.Detects leaks within days

1. Trigger criteria may not be correct 2. Correct trigger criteria may change with time

0.6 0.2

DAS Fibre-optic distributed acoustic sensing

Sustained increased flow noise anomaly migrating upwards

1. Continuous monitoring 2. Coverage along entire wellbore 3. Based on proven annular flow noise logging

1. Noise undetectable for low flux rates 2. Less sensitive if fibre install behind casing 3. Impairs cement bond if fibre outside casing 4. Emerging technology

0.6 0.3


Short spatial wavelength surface uplift anomaly around well



0.4 0.2


1. Continuous monitoring at well-heads 1. Low flux rates may not be detected 2. Dispersion may limit sensitivity

0.4 0.3

APM Annulus pressure monitoring

Sustained annular pressure increase

1. Continuous monitoring 2. Well-established technology

1. Insensitive to migration outside casing 0.5 0.5




1. Annual monitoring only 2. Changes may take several years to appear 3. Natural changes may mask indicator 4. Not an early indicator

0.3 0.3





0.3 0.3


Heavy Oil





0.3 0.3

TMPL Time-lapse temperature logging

Low temperature anomaly above first seal

1. Industry standard technology 2. Coverage along entire wellbore 3. Injected CO2 25C cooler than brine 4. Joule-Thomsen effect enhances cooling 5. Detect migration outside casing

1. Only monitor every few years 2. Leak may go undetected for years 3. May not detect small flux rates 4. Less sensitive to brine migration

0.3 0.4

LOSCO2 Line-of-sight gas flux monitoring

Sustained CO2 flux above background levels

1. Validate no CO2 migration along wells 1. Sensitivity threshold may be insufficient 2. Not sensitive to brine migration 3. Only monitor every few years 4. Leak may go undetected for years

0.4 0.4





0.1 0.7


Increase in CO2 concentration around well

1. Large areal coverage 1. Likely insufficient sensitivity 0.2 0.6

EMIT Time-lapse EM casing imaging

Reduction of casing & tubing thickness

1. Industry standard technology 2. Distinguishes tubing & casing corrosion

1. Only monitor every few years 2. Leak may go undetected for years 3. Will not detect pinhole corrosion

0.3 0.7

CAL Time-lapse multi-finger casing calliper

Increase in the internal casing diameter

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years

0.3 0.7

AFNL Time-lapse annular flow noise logging

Flow noise above the first seal outside the casing


0.2 0.7


Heavy Oil

SONIC Time-lapse sonic logging Reduction in sonic velocity above the first seal

1. Industry standard technology 1. Must stop injection 2. Need to remove tubing impairs well integrity 3. Only monitor every few years 4. Leak may go undetected for years 5. May not detect small flux rates 6. Less sensitive to brine migration

0.2 0.7

SATL Time-lapse saturation logging

Increase in CO2 or brine saturation outside casing


0.2 0.7

MWIT Mechanical well integrity pressure testing


1. Industry standard technology 2. Coverage along the entire wellbore 3. Identifies depth interval of leak path 4. Can be triggered by annulus pressure change

1. Must stop injection 2. Need to remove tubing impairs well integrity 3. Leak may go undetected for years 4. Pump leaks may mask casing leaks

0.2 0.7

DENL Time-lapse density logging Reduction in density above first seal

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years 3. May not detect small flux rates 4. Insensitive to brine migration

0.2 0.7

TRL Tracer injection & gamma logging

Increased gamma ray reading above first seal

1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years 3. May not detect small flux rates

0.2 0.7

RTCI Real time casing imager Sustained pressure increase outside casing migrating upwards above the first seal

1. Continuous monitoring 2. Contiguous coverage over the first seal 3. Detects pressure changes of >0.3 Mpa

1. Untested application of RTCI 2. May not detect low flux rates

0.2 0.8

USIT Time-lapse ultrasonic casing imaging

Reduction of metal thickness 1. Industry standard technology 1. Only monitor every few years 2. Leak may go undetected for years 3. Will not detect pinhole corrosion

0.2 0.8

DPS Fibre–optic distributed pressure sensing

Sustained pressure increase outside casing migrating upwards above the first seal

1. Continuous monitoring 2. Coverage over the seals 3. Provides early indication

1. Requires observation well to penetrate seals 2. Creates additional threat to containment

0.1 0.8




0 0.9




0 0.9


Heavy Oil


Appearance of a negative gravity anomaly around the well


0.1 0.9

DHPT Down-hole pressure-temperature gauge

Down hole pressure drops despite steady injection rates

1. Industry standard technology 2. Detects major leaks instantly

1. Only detects major leaks 0.1 0.9

WHPT Wellhead pressure-temperature gauge

Wellhead pressure drops despite steady injection rates

1. Industry standard technology 2. Detects major leaks instantly

1. Only detects major leaks 0.1 0.9

T4 Detect migration of CO2 or brine via matrix pathways DHPT Down-hole pressure-


Sustained Winnipegosis pressure increase detected by down hole pressure gauge

1. Industry standard technology 2. Continuous monitoring 3. Early warning before brine or CO2 arrives 4. Sensitive to low flux rates (1 ppm) 5. Detection within 1-6 months


0.8 0.1


Short spatial wavelength surface uplift anomaly away from deep wells



0.6 0.2


Appearance of an amplitude anomaly above the first seal away from deep wells



0.3 0.3





0.3 0.3





0.1 0.7


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Conductivity reduction anomaly above the first seal away from deep wells


0 0.9


Conductivity reduction anomaly above the first seal away from deep wells


0 0.9


Appearance of a negative gravity anomaly away from deep wells


0.1 0.9

T5 Detect migration of CO2 or brine along a fault pathway DHPT Down-hole pressure-





0.8 0.1


Short spatial wavelength surface uplift anomaly around a potential fault



0.6 0.2


Appearance of an amplitude anomaly above the first seal around a potential fault



0.3 0.3





0.3 0.3





0.1 0.7


Heavy Oil


Conductivity reduction anomaly above the first seal around a potential fault


0 0.9




0 0.9


Appearance of a negative gravity anomaly around a potential fault


0.1 0.9

T6 Detect fault reactivation DHPT Down-hole pressure-





0.8 0.1

DHMS Down-hole microseismic monitoring

A sustained cluster of microseismic events located above the first seal that migrates upwards with time

1. Industry standard technology 2. Continuous monitoring 3. Detect magnitude -3 events up to 600m away 4. Event location error c. 10-20 m

1. Not all fault slip creates microseismic events 2. Not all microseismic events are detectable

0.7 0.2


Short spatial wavelength surface uplift anomaly around a potential fault



0.6 0.2





0.3 0.3





0.3 0.3


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1. Continuous monitoring 2. Detect magnitude -3 events up to 600m away 3. Lateral event location error c. 10-20 m 4. Depth location error c. 100 m


0.3 0.3





0.1 0.7




0 0.9




0 0.9


Appearance of a negative gravity anomaly around a potential fault


0.1 0.9

T7 Detect induced fractures opening DHPT Down-hole pressure-





0.8 0.1

DHMS Down-hole microseismic monitoring


1. Continuous monitoring 2. Detect magnitude -3 events up to 600m away 3. Event location error c. 10-20 m


0.7 0.2


Short spatial wavelength surface uplift anomaly



0.6 0.2


Heavy Oil


Appearance of an amplitude anomaly above the first seal



0.3 0.3





0.3 0.3



1. Continuous monitoring 2. Detect magnitude -3 events up to 600m away 3. Lateral event location error c. 10-20 m 4. Depth location error c. 100 m


0.3 0.3





0.1 0.5


Conductivity reduction anomaly above the first seal


0 0.9


Conductivity reduction anomaly above the first seal


0 0.9


Appearance of a negative gravity anomaly


0.1 0.9

T8 Detect acidic fluids eroding geological seals DHPT Down-hole pressure-



1. Industry standard technology 2. Continuous monitoring 3. Early warning before brine or CO2 arrives 4. Sensitive to low flux rates (1 ppm)


0.8 0.1


Heavy Oil


Short spatial wavelength surface uplift anomaly consistent with volume increases within the Winnipegosis



0.6 0.2


Appearance of an amplitude anomaly above the first or secondary or ultimate seals


1. No sensitivity expected to brine migration 2. Acquisition noise may mask indicator 3. Only monitor every few years 4. Migration may go undetected for years 5. Unable to detect CO2 leaks <10-60 ktonnes

0.3 0.3





0.3 0.3





0.1 0.7

T9 Detect CO2 or brine migration due to third party activities DHPT Down-hole pressure-


Sustained Winnipegosis pressure increase detected by down-hole pressure gauge on the boundary but not elsewhere within the AOR



0.8 0.1


Short spatial wavelength surface uplift anomaly extends into AOR from neighbouring project



0.6 0.2


Appearance of an amplitude anomaly above the ultimate seal on the boundary but not elsewhere within the survey



0.3 0.3


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Appearance of an amplitude anomaly above the ultimate seal on the boundary but not elsewhere within the survey



0.3 0.3


Conductivity reduction anomaly above the ultimate seal on the boundary but not elsewhere within the survey


0 0.9


Conductivity reduction anomaly above the ultimate seal on the boundary but not elsewhere within the survey


0 0.9


Appearance of a negative gravity anomaly on the boundary but not elsewhere within the survey


0.1 0.9


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Table 20: Evaluation of technologies for monitoring to mitigate any unexpected loss of containment. This is an evidenced-based evaluation of the candidate technologies according to their expected effectiveness at the identified tasks. EF and EA denote the scores assigned, based on expert judgement, to represent the strength of evidence for and evidence against the candidate technology being effective at the task. The degree of uncertainty in this evaluation is denoted by 1 – EF – EA, where 0<EF<1 and 0<EA<1.

Task Technology Indicator Evidence For Evidence Against EF EA

C1 Detect CO2 or BCS brine entering hydrocarbon resources DHPT Down-hole pressure-





0.8 0.1


Short spatial wavelength surface uplift anomaly consistent with volume changes above the ultimate seal



0.6 0.2


Appearance of an amplitude anomaly within the Winnipegosis



0.3 0.3





0.3 0.3





0.1 0.7


Appearance of a negative gravity anomaly within the Winnipegosis


0.1 0.9


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Conductivity reduction anomaly within the Winnipegosis


0 0.9


Conductivity reduction anomaly within the Winnipegosis


0 0.9

C2 Detect and characterise any contamination of protected groundwater

NTM Natural brine tracer analysis of fluid samples from a groundwater well

Tracer unique to BCS brine is detected within groundwater samples

1. Detects unique chemical signature of BCS brine 2. Multiple independent natural tracers exist 3. No ambiguity about source of leak

1. Unable to detect CO2 leak 2. Annual sampling delay detections 3. Tracer may appear from alternative sources

0.7 0.2

ATM Artificial isotope tracer analysis of fluid samples from a groundwater well

Artificial tracer injected with the CO2 is detected within groundwater

1. Artificial tracer is unique 2. No ambiguity about the source of the leak

1. Unable to detect BCS brine leaks 2. Limited areal sampling – may miss anomaly 3. Tracer handling errors may cause false alarms

0.6 0.2

WEC Down-hole electrical conductivity sensor in a groundwater well

Sustained increase of water salinity above the established limit

1. Industry standard technology 2. Continuous monitoring 3. Sensitive to small volumes of BCS brine

1. Limited areal sampling – may miss anomaly 2. Natural changes may mask indicator 3. Cannot determine source of contamination 4. Unlikely to detect CO2 only BCS brine

0.6 0.3

WPH Down-hole pH sensor in a groundwater well

Sustained reduction of pH below the established limit

1. Industry standard technology 2. Sensitive to small changes 3. Unambiguous direct measurement

1. Limited areal sampling – may miss anomaly 2. Annual sampling delays detection 3. Natural changes may mask indicator 4. Cannot determine source of contamination 5. Probe likely requires frequent recalibration

0.4 0.3

WC Water chemistry monitoring in a groundwater well

Sustained increase in concentration of one of a range of identified chemical species exceeds its established limit

1. Industry standard technology 2. Sensitive to small changes 3. Unambiguous direct measurement

1. Limited areal sampling – may miss anomaly 2. Annual sampling delays detection 3. Natural changes may mask indicator 4. Cannot determine source of contamination

0.4 0.3


Appearance of an amplitude anomaly within the protected groundwater zone



0.3 0.6





0.3 0.6


Areal distribution of conductivity anomaly indicative of CO2

1. Areal coverage over entire CO2 plume 2. Potential to detect CO2 or BCS brine leaks

1. Unlikely to be sufficiently sensitive 2. Only monitor every few years

0.2 0.6


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within GPZ 3. Leak may go undetected for years


Areal distribution of conductivity anomaly indicative of CO2 within GPZ

1. Areal coverage over entire CO2 plume 2. Potential to detect CO2 or BCS brine leaks

1. Unlikely to be sufficiently sensitive 2. Only monitor every few years 3. Leak may go undetected for years

0.2 0.6

DHPT Down-hole pressure-temperature gauge in a groundwater well

Sustained increase in groundwater pressure above the established limit

1. Industry standard technology 2. Continuous monitoring 3. Sensitive to small changes

1. Natural fluctuations likely to mask indicator 2. Insensitive to contamination

0.2 0.7





0.1 0.7

GWG Ground water gas monitoring

Sustained increase in CO2 concentration exceeding established background variability

1. Demonstrated technology 2. Direct measurement of CO2

1. Limited areal sampling – may miss anomaly 2. Annual sampling delays detections 3. No sensitivity to brine 4. Large natural variations may mask indicator 5. Other influences may cause false indications

0.1 0.8

C3 Detect and characterise any contamination of surface soils ATM Artificial tracer

monitoring in soil gas samples

Artificial tracer injected with the CO2 is detected within soil gas samples

1. Artificial tracer is unique 2. No ambiguity about the source of the leak

1. Unable to detect BCS brine leaks 2. Limited areal sampling – may miss anomaly

0.6 0.3

NTM Natural tracer monitoring in soil gas samples

Tracer unique to BCS brine is detected within soil samples

1. Detects carbon from the injected CO2 2. Not triggered by biogenic carbon

1. Annual sampling delay detections 2. Tracer may appear from alternative sources 3. Unable to detect CO2 leaks

0.6 0.3

RIA Satellite radar image analysis

Time-lapse image attributes indicate sustained localised increase in soil salinity

1. Radar reflectivity increases due to brine in soil 2. Areal coverage over the entire AOR 3. Potential to detect BCS brine leaks

1. Attributes may be unreliable due to land use 2. Other influences may cause false indications

0.6 0.3

ESS Ecosystem studies Sustained decline in the population of species identified as intolerant to BCS brine or CO2

1. Established methodology 2. Verification of no environmental impact 3. Sensitive to CO2 and BCS brine 4. Isotopic analysis may indicate source

1. Provides no early warning on impacts 2. Natural variations may mask indicator 3. Limited areal sampling – may miss impacts 4. Labour intensive

0.5 0.3

MIA Satellite multi-spectral image analysis

Time-lapse image attributes indicate sustained localised loss of vegetation cover

1. CO2 or brine in soil causes plant stress 2. Image attributes indicate plant stress 3. Areal coverage over the entire AOR 4. Potential to detect CO2 or BCS brine leaks

1. Attributes may be unreliable due to land use 2. Other influences may cause false indications

0.4 0.3


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SGF Soil CO2 gas flux monitoring

Sustained localised increase in CO2 flux exceeding established background variability

1. Demonstrated technology 2. Potential sensitivity of 0.5 mg/m2/hour 3. Natural variations follow soil temperature

1. Large natural variations may mask indicator 2. Other influences may cause false indications 3. Limited areal sampling – may miss anomaly 4. Labour intensive – scope of human error

0.3 0.4

SGC Soil CO2 gas concentration monitoring

Sustained localised increase in CO2 concentration exceeding established background variability

1. Demonstrated technology 2. Natural variations follow soil temperature

1. Large natural variations may mask indicator 2. Other influences may cause false indications 3. Limited areal sampling – may miss anomaly 4. Labour intensive – scope of human error

0.3 0.4

SPH Soil pH surveys Sustained pH reduction exceeding established background variability

1. Established methodology 2. Verification of no environmental impact 3. Direct measurement of any acidification

1. Insensitive to BCS brine 2. Provides no early warning of impacts 3. Natural variations may mask indictor 4. Limited areal sampling – may miss impacts 5. Annual sampling delays detection

0.2 0.5

SSAL Soil salinity surveys Sustained salinity increase exceeding established background variability

1. Established methodology 2. Verification of no environmental impact 3. Sensitive to BCS brine

1. Insensitive to BCS brine 2. Provides no early warning of impacts 3. Natural variations may mask indictor 4. Limited areal sampling – may miss impacts 5. Annual sampling delays detection

0.2 0.5

C4 Measure any CO2 releases into the atmosphere LOSCO2 Line-of-sight gas flux

monitoring Sustained localised increase in CO2 flux exceeding established background variability

1. Scope for continuous measurements 2. Continuous areal sampling 3. Potential sensitivity of 250kg/hour

1. Limited areal coverage 2. Leaks in unexpected areas may go undetected 3. Cannot determine the subsurface source

0.6 0.2

AEC Atmospheric eddy correlation

Sustained localised increase in CO2 flux exceeding established background variability by

1. Demonstrated technology 2. Continuous measurements 3. Potential sensitivity of 0.5 mg/m2/hour

1. Site selection may limit sensitivity 2. Atmospheric conditions may limit sensitivity 3. Large natural variations may mask indicator 4. Limited areal sampling – may miss anomaly 5. Cannot locate surface source of CO2

0.2 0.7

HIRGA Hand-held infra-red gas analysers

Localised increase in CO2 concentration exceeding established background variability

1. Standard technology 1. Does not measure CO2 flux 2. Discrete areal & temporal sampling 3. Likely insufficient sensitivity 4. Difficult to locate surface source

0.1 0.6



1. Areal coverage over the entire AOR 1. Unlikely to be sufficiently sensitive 2. Only monitor every one or few years 3. Leak may go undetected for years

0.1 0.8

DIAL DIAL – Differential absorption LIDAR


1. Proven technology for HC gas fluxes 2. Continuous areal sampling

1. Unlikely to be sufficiently sensitive for CO2 2. Requires frequent specialist maintenance 3. Leaks in unexpected areas may go undetected 4. Cannot determine the subsurface source

0.1 0.8


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APPENDIX 6. EVALUATION OF CONTROL MEASURES

MMV provides monitoring information to verify the expected storage or to trigger interventions designed to improve storage performance. This section describes the requirements for such an active safeguard to be effective and then proceeds to evaluate the active safeguards planned to manage conformance and containment risks

A6.1. Active Safeguards

Each active safeguards requires three key components to be effective: 1. A sensor capable of detecting changes with sufficient sensitivity and reliability to provide an

early indication that some form of intervention is required.

2. Decision logic to interpret the sensor data and select the most appropriate form of intervention.

3. A control response capable of effective intervention to ensure continuing containment or to

control the effects of any potential loss of containment.

As before, a single barrier may be effective against multiple threats. However, for multiple active barriers to be effective against a single threat none can share the same detector, or decision logic, or control response. Otherwise, a single point failure would disable the entire group of barriers. There is an important distinction between prevention and correction measures. From a precautionary standpoint, deep monitoring that prompts early intervention to avoid any loss of containment is preferred. However, these monitoring techniques might be less effective and more expensive than shallow monitoring alternatives. In this case, a proper balance between prevention and correction will achieve better outcomes from the same finite resource. The following discussion addresses control responses for containment risk management.

A6.1.1. Preventative Control Responses

Table 21 summarizes the control response options for preventing any loss of containment. There are two categories.

Injection controls to change the manner of CO2 injection into the storage complex. These

include re-distributing injections rates across existing wells, drilling additional injectors, drilling

producers and re-injectors to manage reservoir pressures, and stopping injection.

Well interventions to restore well integrity. These include repairing the cement bond, replacing

the completion, or abandoning a well that cannot be repaired.


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A6.1.2. Corrective Control Responses

Table 22 summarize the corrective control response options for avoiding, limiting, or recovering from any significant impacts in the unlikely event of CO2 or displaced BCS brine migrating above the Upper Lotsberg Salt. There are three categories.

Well interventions to restore well integrity. These include repairing the cement bond, replacing

the completion, or abandoning a well that cannot be repaired. These are different to the

preventative well interventions. Preventative and corrective well interventions aim to restore

well integrity below and above the ultimate seal respectively.

Exposure controls to prevent contaminants reaching sensitive environmental domains where

significant impacts might occur such as the protected groundwater zone. Remediation measures to recover from any significant impacts in the unlikely event of an

uncorrected loss of containment.

Table 21: Control response options to prevent any unexpected migration of fluids out of the BCS storage complex.

Injection Controls

IC1 Re-distribute injection across existing wells

IC2 Drill new vertical or horizontal injectors

IC3 Extract reservoir fluids to reduce pressure

IC4 Stop injection

Well Interventions WI1 Repair leaking well by re-plugging with cement

WI2 Repair leaking injector by replacing completion

WI3 Plug and abandon leaking wells that cannot be repaired


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Table 22: Control response options to correct any unexpected migration of fluids out of the BCS storage complex.

Well Interventions RM1 Repair leaking well by re-plugging with cement

RM2 Repair leaking injector by replacing completion

RM3 Plug and abandon leaking wells that cannot be repaired

Exposure Controls RM4 Inject fluids to increase pressure above leak

RM5 Inject chemical sealant to block leak

RM6 Contain contaminated groundwater with hydraulic barriers

RM7 Replacement of potable water supplies

Remediation Measures RM8 Pump and Treat

RM9 Air Sparging or Vapour Extraction

RM10 Multi-phase Extraction

RM11 Chemical Oxidation

RM12 Bioremediation

RM13 Electrokinetic Remediation

RM14 Phytoremediation

RM15 Monitored Natural Attenuation

RM16 Permeable Reactive Barriers

RM17 Treat acidified soils with alkaline supplements

A6.2. Additional Safeguards to Ensure Conformance

Table 23 describes the additional active safeguards planned to ensure conformance. Table 24 describes the additional active safeguards planned to ensure accurate CO2 inventory measurements are available.

A6.3. Additional Safeguards to Ensure Containment

Table 25 describes the additional active safeguards planned to prevent any loss of containment. Table 26 describes the additional active safeguards planned to avoid, mitigate or remediate any consequences of an unexpected loss of containment. Table 27 provides a summary of the evidence-based evaluation of available groundwater remediation methods.


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Table 23: Conformance monitoring inside the BCS storage complex to trigger controls designed to prevent or correct any loss of conformance.

Monitoring Task

Monitoring System Indicator Control Options

S1 Detect migration of CO2 within the BCS

S1.1 Time-lapse seismic The observed CO2 plume is larger than the largest predicted plume size, or there is a clear temporal trend towards this state

IC1, IC2, update models, increase the areal extent of the baseline 3D seismic survey

S2 Detect migration of pressure within the BCS

S2.1 InSAR & BCS pressure gauges within each injector & the BCS observation well

The observed lateral extent of pressure rise sufficient to lift BCS brine above the BGP is larger than the largest predicted size, or there is a clear temporal trend towards this state

IC1, IC2, update models, increase the areal extent of InSAR monitoring

Table 24: Measurements and control options designed to ensure accurate CO2 inventory reporting.

Monitoring Task

Monitoring System Indicator Control Options

I1 Measure monthly volume of CO2 injected per well

I1.1 Wellhead injection rate metering and Scotford fence-line metering

Greater than 5% difference between the sum of monthly CO2 injection volumes for all injectors and the Scotford fence-line meter. Subject to change once regulatory framework assessment concludes.

Recalibrate or, if necessary, replace meters

I2 Measure monthly volume of any unexpected CO2 emissions from the BCS storage complex into the atmosphere

I2.1 Line-of-sight CO2 flux metering

Annual controlled release tests of 250 kg/hour at 2 km and 600 kg/hour at 4 km are not detected

Recalibrate or, if necessary, replace sensors


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Table 25 continues on the next page.

Monitoring Task

Monitoring System Indicator

Control Options

T1 Detect migration of CO2 or brine along a legacy well

B1.5 InSAR & BCS pressure gauges within each injector & the BCS observation well

Surface displacements through time satisfy the following criteria: -inconsistent with the range of model scenarios that predict pressure increase at an observation well will never exceed the threshold for lifting BCS brine above BGP -consistent with a revised model scenarios that predict pressure increase at an observation well will exceed the threshold for lifting BCS brine above BGP

IC1

T2 Detect migration of CO2 or brine along a BCS observation well

B2.6 Down-hole pressure gauge within the BCS observation well

Sustained pressure increase at the observation well exceeds the threshold for lifting BCS brine above BGP

IC1, IC2, IC4

B2.7 Cement Bond Logging Poor cement bond quality across major seals within the BCS storage complex

WI1

B2.8 Annulus Pressure Monitoring

Sustained annular pressure increase WI1, WI2, WI3

B2.9 InSAR Surface displacements through time satisfy the following criteria: -consistent with the range of modelled scenarios that predict pressure increase at an observation well will exceed the threshold for lifting BCS brine above BGP -inconsistent with the range of modelled scenarios that predict pressure increase at an observation well will never exceed the threshold for lifting BCS brine above BGP

IC1

T3 Detect migration of CO2 or brine along an injector

B3.3 Cement Bond Logging Poor cement bond quality across major seals within the BCS storage complex

WI1, WI3

B3.4 Annulus Pressure Monitoring

Sustained annular pressure increase WI1, WI2, WI3

B3.5 Mechanical Well Integrity Testing


WI1, WI2, WI3

B3.6 Distributed Temperature Sensing

Sustained low temperature anomaly migrating upwards above the first seal

IC1, IC2, IC4, WI1, WI3

B3.7 Distributed Acoustic Sensing

Sustained flow noise migrating upwards above the first seal IC1, IC2, IC4, WI1, WI3

B3.8 Down-hole pressure gauges within Winnipegosis observation wells

Appearance of a sustained pressure increase at one well relative to the other wells that increases by more than XX kPa per month over XX consecutive months


B3.9 Time-Lapse Seismic Appearance of a reliable amplitude anomaly that satisfies the following criteria: -consistent with velocity changes expected due to the presence of CO2 inside the Winnipegosis -located around the CO2 injector



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Table 25 continues on the next page.

Monitoring Task


Control Options

T4 Detect migration of CO2 or brine along matrix pathways


As for B3.8 IC1, IC2, IC4

B4.9 Time-lapse seismic Appearance of a reliable amplitude anomaly that satisfies the following criteria: -consistent with velocity changes expected due to the presence of CO2 inside the Winnipegosis -located away from the CO2 injector

IC1, IC2, IC4

B4.10 InSAR Appearance of a short spatial wavelength surface uplift anomaly that satisfies the following criteria: -consistent with volume changes occurring within the Winnipegosis Formation -located away from all injectors and BCS legacy wells

IC1, IC2, IC4

T5 Detect migration of CO2 or brine along a fault pathway


As for B3.8 IC1, IC2, IC4

B5.6 Time-lapse seismic As for B4.9 IC1, IC2, IC4

B5.7 InSAR As for B4.10 IC1, IC2, IC4

T6 Detect fault reactivation

B6.6 Down-hole microseismic monitoring within one Winnipegosis observation well

Within a 10-day period, more than 10 microseismic events occur that are located above the base of the Lower Lotsberg Salt with a confidence estimate of greater than 95%.

IC1, IC2, IC3, IC4


As for B3.8 IC1, IC2, IC3, IC4

B6.8 Time-lapse seismic As for B4.9 IC1, IC2, IC3, IC4

B6.9 InSAR Appearance of a short spatial wavelength surface displacement anomaly that satisfies the following criteria: -consistent with slip a fault segment extending from the BCS to the Lower Lotsberg Formation -inconsistent with any distribution of volume changes inside the BCS storage complex

IC1, IC2, IC3, IC4

T7 Detect induced fractures opening

B7.5 Down-hole microseismic monitoring within one Winnipegosis observation well




B7.7 Time-lapse seismic As for B4.9 IC1, IC2, IC3, IC4

B7.8 InSAR Appearance of a short spatial wavelength surface displacement anomaly that satisfies the following criteria: -consistent with the opening of a fracture zone extending from the BCS to the Lower Lotsberg Formation -inconsistent with any distribution of volume changes inside the BCS storage complex

IC1, IC2, IC3, IC4

T8 Detect fluid migration through pathways created by acidic fluids


As for B3.8 IC1, IC4

B8.5 Time-lapse seismic As for B4.9 IC1, IC4


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Table 25: Containment monitoring designed to trigger controls to prevent CO2 or brine migrating above the BCS storage complex and the Winnipegosis monitoring complex.

Monitoring Task


Control Options

T9 Third –party activities induce CO2 or brine migration

B9.2 InSAR & BCS pressure gauges within each injector & the BCS observation well

Surface displacements close to the edge of the AOI indicate pressure increases sufficient to lift brine above the BGP inside the AOI due to third-party injection outside the AOI

IC1

B9.3 Time-lapse seismic Appearance of a reliable amplitude anomaly on the edge of a repeat 3D surface not associated with Quest injectors

IC4


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Table 26: Containment monitoring to trigger controls designed to mitigate or remediate the effects of any unexpected migration of CO2 or brine above the BCS storage complex and the Winnipegosis monitoring complex.

Monitoring Task


Control Options

C1 Detect and characterise CO2 entering hydrocarbon resources

M1.5 Time-lapse seismic Appearance of an amplitude anomaly consistent with a CO2 plume entering hydrocarbon resources above the Beaver Hill Lake Group

RM2, RM3, RM15

M1.6 InSAR Appearance of an localised uplift anomaly consistent with pressure build-up within hydrocarbon resources above the Beaver Hill Lake Group

RM2, RM3, RM15

C2 Detect and characterise any contamination of protected groundwater

M2.14 Continuous water electrical conductivity monitoring within Project groundwater monitoring wells

Increase in water electrical conductivity of more than X sustained over a 90-day period where X is to be determined from the baseline monitoring results

RM1-3, RM6-16

M2.15 Continuous water pH monitoring within Project groundwater monitoring wells

Decrease in water pH of more than X sustained over a 90-day period where X is to be determined from the baseline monitoring results

RM1-3, RM6-16

M2.16 Measurements for the presence of BCS tracers within fluid samples from Project groundwater and landowner water wells

All BCS brine tracer metrics indicate more than X ppm of BCS brine contained within groundwater samples where X is to be determined from the baseline monitoring results

RM1-3, RM6-16

M2.17 Measurements for the presence of the CO2 tracer within fluid samples from Project groundwater and landowner water wells

The measured concentration of CO2 tracer indicates more than X ppm of injected CO2 is contained within the groundwater sample where X is to be determined from the baseline monitoring results

RM1-3, RM6-16

C3 Detect and characterise any contamination of surface soils

M3.9 Line-of-sight CO2 flux monitoring Indicator to be determined from baseline monitoring data RM1-3, RM12,15,17

M3.10 Remote sensing: Multi-spectral image analysis?

Indicator to be determined from baseline monitoring data RM1-3, RM12,15,17

M3.11 Remote sensing: SAR Indicator to be determined from baseline monitoring data RM1-3, RM12,15,17

M3.12 Soil samples & tracer analysis Indicator to be determined from baseline monitoring data RM1-3, RM12,15,17

M3.13 Soil salinity surveys Indicator to be determined from baseline monitoring data RM1-3, RM12,15,17

M3.14 Vegetation surveys Indicator to be determined from baseline monitoring data RM1-3, RM12,15,17

C4 Detect and quantify any CO2 releases into the atmosphere

M4.10 Line-of-sight CO2 flux monitoring Detection of a localised CO2 flux greater than X kg/m2/hour triggers the ERP, where X is determined from baseline monitoring results. The appearance of a smaller sustained localised CO2 flux triggers a Control Response if the following criteria are satisfied: -CO2 flux greater than X kg/m2/hour located within 2 km of the sensor or greater than Y kg/m2/hour located within 4 km of the sensor where X and Y are to be determined from the baseline monitoring results -CO2 tracer measurements on samples collected from the

RM1-3


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identified site indicate the presence of Project CO2

M4.11 Wellhead CO2 concentration sensors

CO2 concentrations exceeding X trigger the ERP where X is to be determined from the baseline monitoring results. CO2 concentrations exceeding Y trigger a Control Response where Y is to be determined from the baseline monitoring results

RM1-3


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Table 27: Evaluation of remediation methods.

Remediation Method Type Evidence For Evidence Against RM8 Pump and Treat Active,

Physical, Ex-Situ

1. Can remove contaminants from shallow to deep depths 2. Relatively insensitive to the nature of contaminants 3. Can be quick where hydraulic characteristics are good 4. Uses conventional wastewater treatment processes 5. Effluent quality can be easily monitored

1. Can be problematic if hydraulic characteristics are unfavourable 2. Requires ongoing source of power 3. Relatively high capital cost 4. Requires operational maintenance of equipment 5. Necessitates handling of produced water 6. Can be challenging in winter environments

RM9 Air Sparging or Vapour Extraction

Active, Physical, Ex-Situ

1. Remediation of gaseous and dissolved contaminants 2. Can be used as a means of exposure control

1. Can be problematic if hydraulic characteristics are unfavourable 2. Generally limited to volatile contaminants 3. Limited to contaminants near the vadose zone 4. Requires ongoing source of power 5. Relatively high capital cost 6. Requires operational maintenance of equipment 7. Necessitates scrubbing of effluent 8. Diminishing returns as contaminants become less concentrated 9. Can be challenging in winter environments

RM10 Multi-phase Extraction Active, Physical, Ex-Situ

1. Removes gaseous, free liquid and dissolved contaminants 2. Relatively quick removal of concentrated contamination 3. Relatively insensitive to nature of contaminants

1. Can be problematic if hydraulic characteristics are unfavourable 2. Requires ongoing source of power 3. Relatively high capital cost. 4. Requires operational maintenance of equipment 5. Limited to contamination near the water table 6. Necessitates handling of produced fluids. 7. Diminishing returns as contaminants become less concentrated. 8. Can be challenging in winter environments

RM11 Chemical Oxidation Active, Chemical, In-Situ

1. Removes contaminants from shallow & intermediate depths 2. Relatively low surface disturbance 3. Relatively quick degradation of organic contaminants 4. Able to treat high concentrations of contaminants 5. Does not require handling of produced groundwater

1. Can be problematic if hydraulic characteristics are unfavourable 2. Requires operational maintenance of equipment 3. Can be corrosive for other underground infrastructure 4. Potential for Health and Safety Issues

RM12 Bioremediation Active or Passive, Biological, In-Situ

1. Relatively low surface disturbance 2. Does not require handling of produced groundwater 3. Relatively low capital cost

1. Generally limited to organic contaminants 2. May not be suitable for highly concentrated or toxic contaminants 3. Requires operational maintenance of equipment 4. Can be challenging in winter environments


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RM13 Electrokinetic Remediation Active, Physical and Chemical, In-Situ

1. Treats inorganic contaminants not easily treated otherwise 2. Can be used in areas of low permeability

1. Requires source of power 2. Requires eventual groundwater extraction to remove contaminants that have not been immobilized 3. Relatively immature technology

RM14 Phytoremediation Passive, Biological, In-Situ

1. Relatively passive method of remediation requiring little operational maintenance 2. Relatively low capital cost 3. Treats inorganic contaminants not easily treated otherwise

1. Limited to very shallow contamination 2. Requires periodic removal and disposal of plants 3. May not be suitable for contaminants with high toxicity or concentration 4. Requires a high level of ongoing monitoring 5. Generally long term remedial method 6. Can be challenging in winter environments

RM15 Monitored Natural Attenuation

Passive, Physical and Chemical and Biological, In-Situ

1. Requires little operational maintenance 2. Relatively low cost in the short to medium term. 3. Relatively low surface disturbance

1. Requires a high level of subsurface assessment 2. Requires a high level of ongoing monitoring 3. Generally a long term remedial method 4. May not be acceptable to all stakeholders

RM16 Permeable Reactive Barriers Passive, Chemical, In-Situ

1. Requires little operational maintenance 2. Treats inorganic contaminants not easily treated otherwise

1. Limited to shallow to intermediate depths of contamination 2. Requires a high level of ongoing monitoring 3. Capital costs increase markedly with depth 4. Barriers may need replacing


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APPENDIX 7. MONITORING FEASIBILITY ASSESSMENTS

The following lists provide references to the technical feasibility reports that informed the development of the Quest MMV Plan.

A7.1. Injection Well Integrity Monitoring

Distributed temperature sensing15 using an optic fibre on the production casing provides a means of a detecting an unexpected micro-annulus of CO2 outside the casing. This is based on the thermal insulation properties of CO2 altering the dynamic equilibrium between the extent to which injected CO2 cools the casing and the heat flux from the formation.

Distributed acoustic sensing using an optic fibre on the production casing is expected to detect any sustain annular flow noise associated with unexpected fluid movements outside the casing.

Real-time casing imager41 requires on optic fibre wrapped in a helical form on the production casing. This measures both radial and longitudinal casing strain. Radial strains arise due to differences in fluid pressure inside and outside the casing to provide a means of detecting any sustained pressure rise outside the casing due to a loss of external well integrity. This expected sensitivity of this technology is sufficient for leak detection but it is regretted due to cost and compatibility concerns with distributed temperature and acoustic sensing systems.

A7.2. Geosphere Monitoring

Down-hole pressure16 monitoring within observation wells completed either in the Winnipegosis or Cooking Lake Formations are judged to be an effective means of sensitive and early leak detection.

Time-lapse seismic is expected to image the CO2 plumes inside the BCS and detect any out-of-place CO2 above the BCS storage complex. The expected pressure changes inside the BCS are too small for this method to detect, nor will it detect any out-of-place BCS brine above the BCS storage complex.

Vertical seismic profiles acquired inside an injector are expected to image the CO2 plume up to a distance of 600 m away from the injector.

Microseismic17 monitoring is expected to detect any microseismic activity associated with unexpected fracturing or fault slip inside the BCS storage complex up to a distance of 800 m away from the observation well and with sufficient resolution to


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distinguish microseismic events occurring inside the BCS versus events occurring above the first seal.

InSAR monitoring of surface displacements induced by pressure build-up inside the BCS and LMS are expected to provide an effective low-cost means of monitoring pressure conformance. InSAR monitoring is also expected to detect any unexpected fault slip across the seals of the BCS storage complex and any out-of-place volume increases within the Cooking Lake aquifer due to any unexpected migration of CO2 or brine out of the BCS storage complex.

Gravity42: Surface gravity monitoring is potentially a low-cost means of monitoring CO2 plume conformance and containment. This was regretted due to insufficient sensitivity to detect CO2 inside the storage complex because the signal due to the lower density of CO2 relative to the brine is in part offset by the additional mass injected into the aquifer.

Electromagnetic: Surface electromagnetic monitoring is potentially another low-cost means of monitoring CO2 plume conformance and containment. This was regretted due to insufficient sensitivity due to the resistive basement directly below the BCS masking the signal of resistive CO2 displacing the more conductive BCS brine. Resistive layers above the BCS, such as the Lotsberg salts and the Prairie Evaporite also limited the strength of EM signals expected to reach the BCS.

Logging43: Time-lapse logging to detect CO2 saturation changes inside the BCS is technically feasible using Neutron Porosity Logging, Thermal Neutron Capture Logging, or Induction Conductivity Logging.

A7.3. Hydrosphere Monitoring

Potential groundwater impacts44: Controlled water and core samples were collected from 4 Project groundwater wells drilled from the Radway 8-19 well pad, the deepest of which was cored down to 200m below the surface. The base of groundwater protection at this location is about 200m below surface. Based on these data, geochemical modelling of the potential effects of an unexpected point-source release of BCS brine or injected CO2 above the base of groundwater protection indicates the radius (less than c. 100m) and nature of a contaminant plume.

CO2 tracers45: Injection of a PFC tracer into the CO2 stream at Scotford is a technically feasible means of uniquely determining the unexpected presence of Project CO2 within the hydrosphere, biosphere or atmosphere. The measured absence of this tracer within groundwater, soil or vegetation samples is expected to be sufficient


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evidence for the absence of unexpected Project CO2 within these environments. A wide range of different artificial tracers were evaluated before identifying PFC as the technically-preferred option.

Brine tracers46: Detailed chemical and isotopic analysis was completed on BCS brine samples collected from the Radway 8-19 and Redwater 11-32 Project BCS wells and groundwater samples collected from the Project groundwater wells located on the Radway 8-19 well pad and 16 landowner groundwater wells location inside the 3D seismic survey area. These results indicate the technical feasibility of multiple independent natural tracers uniquely associated with the BCS brine that are detectable in trace amounts should they unexpectedly appear within groundwater or soil samples.

A7.4. Biosphere Monitoring

Remote sensing47: The application of radar and optical remote sensing methods to indicate potential locations of soil salinity increases and vegetation stress are promising but require careful calibration with ground-based measurements.

Soil and vegetation surveys47: These are standard component of environmental monitoring programs in Alberta.

A7.5. Atmosphere Monitoring

Line-of-sight CO2 flux monitoring48: This technology is expected to be capable of detecting and mapping the location of any localised CO2 emissions from the CO2 storage complex into the atmosphere. A field trial is planned at the Radway 8-19 well pad to demonstrate these capabilities.


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APPENDIX 8. RELIABLE DETECTION OF RARE EVENTS

A8.1. Threat Detection

The task of monitoring CO2 storage performance is really about indicating if any observed change is within appropriate limits or not. Changes within these limits should not constitute any threat of an adverse environmental impact. Changes that exceed these limits require prompt corrective actions to avoid any threat of an adverse environmental impact. In practice, measurements of change and knowledge of these limits are both imperfect. These uncertainties create four possible outcomes when trying to decide if the actual change remained within appropriate limits or not. The effectiveness of a detection system then depends on the likelihood of each of these four outcomes.

Table 28: Possible alarm outcomes.

Measured Change No Threat Threat

Act

ual C

hang

e

No

Thre

at

TV TRUE

VERIFICATION

FA FALSE

ALARM

Thre

at MA

MISSED ALARM

TA TRUE

ALARM

A8.2. Deciding if a Threat Exists

Consider some property whose actual value, varies through time, , and only causes a threat to occur if it exceeds a threshold value, . Expressing this in terms of changes from an initial baseline value, a threat exists if:

(1)

where , and .


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Knowledge of the actual change and threat threshold will however be uncertain. Therefore, consider a detector that periodically measures the property value, , with a random error, , so the probability that the actual change, , exceeds the measured change, , is given by the Cumulative Normal Probability Distribution function, , such that

, (2)

where and are the mean and standard deviation of the distribution respectively.

Likewise, our knowledge of the actual threat threshold, , will be limited to some estimate, , subject to a standard error, . Therefore, the probability that an actual threat threshold, , exceeds the estimated threat threshold, , is given by the Cumulative Normal Probability Distribution function, , such that

, (3)

where and are the mean and standard deviation of the distribution respectively.

Figure 17: Deciding if the observed change exceeds the threat threshold is an uncertain business.

Consequently, the probability of an actual threat existing, , given a measured change, , and an estimated threshold, , is

, (4)


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where and are the mean and the standard deviation of the probability density distribution respectively and

is the standard error for threat detection. An

example of such a distribution is given below.

Figure 18: Threat probability given a Measured Change.

For any given measured change, the red region indicates the likelihood of a threat existing. In the absence of uncertainty the interface between the threat and no threat domains is vertical. Uncertainty about the existence of a threat arises in practice due to measurement error, , and incomplete knowledge about the actual threat threshold, .

A8.3. False Alarms or Missed Alarms

In the presence of such uncertainty the choice of alarm level must be made carefully. Lowering the alarm level will reduce the likelihood of Missed Alarms but increase the likelihood of False Alarms and vice versa as indicated in the figure below.

Figure 19: The probability of False Alarms and Missed Alarms for a given Measured Change depends on the Alarm

Level.


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A8.4. Rare Threats

The probability distribution of actual changes to a system property, , that only rarely triggers a threat may be represented by the Exponential Probability Density Function , f, and the Cumulative Probability Function, F, such that

(5)

(6)

A key property of this distribution is that small changes occur frequently and large changes occur rarely. Figure 20 shows an example of this distribution where the scale parameter, , was selected to ensure the probability of any change exceeding the threat threshold is 1 in 10,000.

Figure 20: An Exponential Cumulative Probability Function to represent the likelihood of changes that only rarely

trigger a threat. In this example there is a 1 in 10,000 chance of a threat occurring.

A8.5. Expected Alarm Rates

Regardless of the Alarm Level, the expected rate of True Alarms, , or Missed Alarms, , must equal the expected rate of threat occurrence, .

(7)

Equally, the expected rate of True Verifications, , or False Alarms, , must equal the rate of measurement, , less the expected rate of threat occurrence.

(8)

Subject to these constraints, the expected rate of True Alarms for an actual change, , above some Alarm Level, , is the product of the probability of this change occurring,


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, and the probability that this change indicates a threat, The total expected rate of True Alarms is then the integral of this product for all changes above the Alarm Level, normalized to match the constraint stated above. The expected rates of each alarm may be similarly obtained as follows:

Expected Rate of True Alarms:

(9)

Expected Rate of Missed Alarms:

(10)

Expected Rate of True Verifications:

(11)

Expected Rate of False Alarms:

(12)

and the normalization constants, and are

, (13)

. (14)

Figure 21 shows an example of how these expected alarm rates depend on the selected alarm level.


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Figure 21: Expected Alarm Rates depend strongly on the Alarm Level selected. This example shows results for threat

rate (TR) of 1 in 10,000 per annum and a monitoring system with a measurement rate (MR) of

once per annum and a 20% fractional detection error ( ).

A8.6. Switch Off by False Alarms

The problem of False Alarms is potentially acute when monitoring to detect the occurrence of a rare event. Unless the Alarm Level is set sufficiently high, the rate of False Alarms will be intolerable (Figure 21). More than one or two False Alarms that trigger major investigations to determine the absence of a threat will likely be sufficient for such a loss of confidence in the monitoring system that it is discontinued. For a monitoring system to be effective at detecting rare events it must continue to maintain the confidence of the operators by avoiding False Alarms and still be likely to identify the occurrence the rare event should it ever occur.

A8.7. Performance Requirements

The quality of an alarm system may be characterized in terms of Missed Alarms and False Alarms. The rate of False Alarms and Missed Alarms must both be acceptably small. This may only be achieved through sufficiently small errors in the process of measuring change and estimating the threat threshold. Figure 22 shows how the expected the expected alarm performance depends on both the alarm level and the measurement uncertainty. More frequent monitoring necessarily requires better sensors with less measurement uncertainty, otherwise the rate of False Alarms will quickly become unacceptable. Figure 23 shows the annual rate of False Alarms expected as a function of measurement uncertainty for a range of measurement frequencies.


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Figure 22: Expected alarm performance as a function of alarm level and measurement uncertainty. Coloured labels

denote these Alarm Levels expressed as a fraction of the incremental threat threshold ( ). Alarm performance is controlled by the choice of Alarm Level and the uncertainty in measuring

change relative to the threat threshold ( ). Improving the detection error by a factor of 10 typically reduces the False Alarm rate by a factor of 1000 as shown by the difference between red and dark green curves.

Figure 23: More frequent monitoring requires better sensors. This example shows the expected rate of False Alarms as

a function of Detection Error for an Alarm Level selected so that the probability of a Missed Alarm is 0.1. For reference the dashed line indicates one False Alarm over a 35-year monitoring period.


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Given a suitable alarm performance criteria, that specifies acceptable rates of Missed and False Alarms, and knowledge of the threat threshold, this model provides an indication of the maximum tolerable measurement error and the appropriate Alarm Level as a function measurement rate. Alternatively, for the same alarm performance criteria and knowledge of the measurement error, this model provides an indication of the minimum Threat Threshold that the monitoring system is able to reliably detect. This approach is expected to help avoid selecting monitoring systems with unacceptably large measurement errors, or selecting an Alarm Level that is either too high or too low. Understanding the relationship between these competing effects helps to avoid setting monitoring targets that cannot be achieved whilst maintaining confidence in the capability to detect rare events reliably. Adopting an alarm performance criteria of no more than 1 False Alarm over a 35 year monitoring period (25 years injection, 10 years site closure) and no worse than a 1 in 10 chance of a Missed Alarm leads to the required detection errors and recommended alarm levels for monitoring systems (Table 29). These recommendations provide the logical framework for the preliminary alarms levels proposed at the conclusion of Chapter 0 on Monitoring Performance Targets (see Table 11).

Table 29: Detection error requirements and recommended alarm levels for a range of monitoring frequencies. These are based on an assumed performance requirement stated in Figure 23. These are expressed as fractions of the interval from the initial baseline value to the recognised threat threshold.

Monitoring Rate Alarm Level Detection Error Every 5 years 40% 28%

Every year 54% 19% Every month 72% 14% Every day 94% 7% Every hour 100% 2%


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APPENDIX 9. TOWARDS A QUANTIFIED RISK ASSESSMENT

This section describes a means of computing risk using the bowtie framework for risk assessment. This provides a measure of the successive risk reductions achieved through implementing increasing numbers of safeguards to prevent threats or avoid consequences. Application of this method to the bowtie assessment of containment risks for the BCS storage complex reveals a means of demonstrating the residual risk after implementing safeguards through Site Characterisation and MMV is as low a reasonably practicable. This method is characterised as a quantified rather than a quantitative risk assessment in an attempt to draw an important distinction between this approach that necessarily relies on expert judgement to assess the relative risks and quantitative methods based on empirical data about the previous performance of very many comparable systems to assess the absolute risks.

A9.1. Probability Model of Containment Risk

Building on the Bowtie Method of assessing risk (APPENDIX 2), we proceed to interpret the connection between threats, safeguard and consequences as a probability network; where each threat initiates at a given rate, each safeguard fails at a given rate, and each consequences has a given significance weighting. The probability of a significant consequence occurring despite the safeguards in-place may then be computed using simple Probability Theory. Consider a set of n threats and m consequences. Let the ith threat initiate with a probability of Ti where i is an index that takes integer values from 1 to n, and let the jth consequence have a significance weight of Cj where j is an index from 1 to m. Furthermore, let the kth safeguard, on the left of the bowtie to prevent the ith threat causing the top event, fail with a probability Lik where k is an index from 1 to ni. Likewise, let the lth safeguard, in place on the right of the bowtie to prevent the top event causing the jth consequence, fail with a probability Rjl where l is an index from 1 to mj Now, it follows that the probability of the ith threat causing the top event, , is simply the probability that the threat initiates and every subsequent safeguard fails, i.e.

(15)

The probability that the top event occurs, pt, is easily understood in terms of the probability that the top event fails to occur, 1-pt, which is equal to the probability that every threat fails to cause the top event:


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(16)

Moving to the right of the bowtie, the probability of the jth consequence occurring, pj, is simply the probability the top event occurs and every subsequent safeguard fails, i.e.

(17)

Finally, the total risk represented by the bowtie associated with the possible occurrence of every consequence may be expressed as

(18)

A9.2. Model Inputs

A9.2.1. Threat Initiation Rates

A review of malfunctions of underground gas storage sites worldwide49 demonstrates the historical rate of storage well failures is less than 1 in 120,000 per well year. Assuming each underground storage site typically implements risk mitigation measures with a combined failure rate of 1 in 1000 this implies a threat initiation rate for well failures of 1 in 120 per well year. This provides a basis for assigning threat initiation rates to the population of wells inside the BCS storage complex (Table 30). The initiation rates for the other threats were estimated by selecting a rate factor to represent the expected rate relative to legacy wells. This rate factor was selected according to expert judgment informed by the appraisal data and site characterization. All these other threats are judged equally unlikely to initiate as the appraisal data provides no direct evidence for the existence of any of these threats within the storage site. There are two exceptions. First, natural analogues suggest acidic erosion is much less likely than the other geological processes. Second, third parties are assumed to operate their own additional safeguards.


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Table 30: Estimates for containment threat initiation rates for the BCS storage complex.

Well Threats Number Initiating Rate

Migration along a legacy well T1 4 1 in 30 per annum

Migration along a MMV well T2 1 1 in 120 per annum

Migration along an injector well T3 5 1 in 24 per annum

Other Threats Rate Factor Initiating Rate

Migration along a matrix pathway T4 0.1 1 in 300 per annum

Migration along an existing fault T5 0.1 1 in 300 per annum

Induced stress re-activates a fault T6 0.1 1 in 300 per annum

Induced stress opens fractures T7 0.1 1 in 300 per annum

Acidic fluids erode geological seals T8 0.01 1 in 3000 per annum

Migration induced by third party T9 0.01 1 in 3000 per annum

A9.2.2. Consequence Weights

Assigning weights to the different consequences is simply a recognition that the potential impact of each identified consequence is not equal. Table 31 shows estimates for these weights based on four categories of potential impacts if all safeguards unexpectedly fail. Each category is assigned a score, s, on a 5-point scale using collective expert judgement against a clearly established criteria in the corporate Risk Assessment Matrix. Each point on this scale represent 10 times greater potential impact than the previous point. The weights, C, are therefore computed as

(19)

and then normalised so that the largest weight is equal to 1.


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Table 31: Estimates for containment consequence weights for the BCS storage complex.

Assessment of Potential Impact if Uncontrolled

Consequence

People Environment Asset Reputation Weights

Hydrocarbons impacted C1 No Effect (0) No Effect (0) Major (4) Minor (2) 0.01

Groundwater impacted C2 Major (3) Major (4) Massive (5) Major (4) 1.00

Soil impacted C3 No Effect (0) Moderate (3) Major (4) Moderate (3) 0.10

CO2 emissions C4 Minor (2) Minor (2) Major (4) Major (4) 0.20

A9.2.3. Effectiveness of safeguards

The failure rate of each safeguard is taken from the tables that identify evidence for and against each safeguard being effective (Table 12, Table 13, Table 18, Table 19). These provide an estimated failure rate for each individual safeguard and an uncertainty range for this rate based on an acknowledgement of uncertainty in the evidence.

A9.3. Computed Risks

Figure 24 shows the results of these computed risks. The risk was calculated iteratively to demonstrate the incremental risk reduction of each passive safeguard and of each active safeguard. The sequence of these safeguards was selected to maximise the incremental risk reduction each time. These results are useful to assess the relative risk reduction achieved with each additional safeguard; however the absolute values obtained are only as good as the absolute estimates of threat initiation and safeguard failure rates. Due to the limited empirical data available on the historical frequency of CO2 storage risk events, caution is necessary in interpreting risk estimates in any absolute sense.


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Figure 24: Reduction in risk computed for increasing number of passive and active safeguards. Each line represents

one realisation of the anticipated failure rates for each safeguard selected at random from the recognised range of potential failure rates for each safeguard. The 100 realisations shown indicate impact of these uncertainties on risk management. The Risk Metric is shown on a logarithmic scale.

Ris

k M

etr

ic

Number of Safeguards

Passive safeguards

Active safeguards


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APPENDIX 10. KNOWLEDGE TRANSFER BETWEEN CCS PROJECTS

A10.1. Existing Large-Scale CCS Projects

Five fully-integrated, large scale CCS projects are in commercial operation today storing more than 0.5 million tonnes CO2 per year. Four projects – Sleipner, In Salah, Snøhvit and Rangely – inject CO2 from a natural gas production facility where it is separated from the natural gas sent to market. In the first three cases, the CO2 is injected into saline aquifers, while in the fourth it is used for EOR. A fifth project captures CO2 at the Great Plains Synfuels Plant and transports it for EOR to the Weyburn-Midale project. All five are contributing to the knowledge base needed for widespread CCS use. The following summary of these projects was adapted from IEA50.

A10.1.1. Sleipner

The Sleipner project began in 1996 when Norway’s Statoil began injecting more than 1 million tonnes a year of CO2 under the North Sea. This CO2 was extracted with natural gas from the offshore Sleipner gas field. In order to avoid a government‐imposed carbon tax equivalent to about USD 55/tonne, Statoil built a special offshore platform to separate CO2 from other gases. The CO2 is re-injected about 1 000 metres below the sea floor into the Utsira saline formation located near the natural gas field. The formation is estimated to have a capacity of about 600 billion tonnes of CO2, and is expected to continue receiving CO2 long after natural gas extraction at Sleipner has ended.

A10.1.2. In Salah

In August 2004, Sonatrach, the Algerian national oil and gas company, with partners BP and Statoil, began injecting about 1 million tonnes per year of CO2 into the Krechba geologic formation near their natural gas extraction site in the Sahara Desert. The Krechba formation lies 1 800 metres below ground and is expected to receive 17 million tonnes of CO2 over the life of the project.

A10.1.3. Snøhvit

Europe’s first liquefied natural gas (LNG) plant also captures CO2 for injection and storage. Statoil extracts natural gas and CO2 from the offshore Snøhvit gas field in the Barents Sea. It pipes the mixture 160 kilometres to shore for processing at its LNG plant near Hammerfest, Europe’s northernmost town. Separating the CO2 is necessary to produce LNG and the Snøhvit project captures about 700 000 tonnes a year of CO2. Starting in 2008, the captured CO2 is piped back to the offshore platform and injected in the Tubåsen sandstone formation 2,600 metres under the seabed and below the geologic formation from which natural gas is produced.


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A10.1.4. Rangely

The Rangely CO2 Project has been using CO2 for enhanced oil recovery since 1986. The Rangely Weber Sand Unit is the largest oilfield in the Rocky Mountain region and was discovered in 1933. Gas is separated and reinjected with CO2 from the LaBarge field in Wyoming. Since 1986, approximately 23-25 million tonnes of CO2 have been stored in the reservoir. Computer modeling suggests nearly all of it is dissolved in the formation water as aqueous CO2 and bicarbonate. Though Rangely uses CO2 for EOR, it is considered a CCS project based on the assessed viability of long-term storage of CO2.

A10.1.5. Weyburn‐Midale

About 2.8 million tonnes per year of CO2 are captured at the Great Plains Synfuels Plant in the US State of North Dakota, a coal gasification plant that produces synthetic natural gas and various chemicals. The CO2 is transported by pipeline 320 kilometres (200 miles) across the international border into Saskatchewan, Canada and injected into depleting oil fields where it is used for EOR. Although it is a commercial project, researchers from around the world have been monitoring the injected CO2. The IEA Greenhouse Gas R&D Programme’s Weyburn-Midale CO2 Monitoring and Storage Project was the first project to scientifically study and monitor the underground behaviour of CO28. Canada’s Petroleum Technologies Research Centre manages the monitoring effort. This effort is now in the second and final phase (2007‐2011), of building the necessary framework to encourage global implementation of CO2 geological storage. The project will produce a best‐practices manual for carbon injection and storage.

A10.2. Joint Industry Project for Knowledge Transfer

The CO2QUALSTORE joint industry project (JIP) led by Det Norske Veritas (DNV) recently compiled a workbook of examples for underground storage of CO2 including MMV plans (DNV 2010b). The JIP includes the following partners from a number of sectors; oil and gas companies (BP, BG Group, Petrobras, Shell and Statoil); energy companies (DONG Energy, RWE Dea and Vattenfall); technical consultancy and service providers (Schlumberger and Arup); the IEA Greenhouse Gas R&D Programme; and two Norwegian public enterprises (Gassnova/Climit and Gassco). This workbook provides guidance on how site-specific performance targets can be defined and includes practical examples of how to follow the guidance and its various steps. This workbook represents the most recent collection of shared experience and good practises applicable to MMV. This guidance and the good practises illustrated through the examples are central to the approach taken by Shell to all current CCS development projects including Quest. The key lessons learned applicable to the protection of groundwater resources and users and incorporated by Shell into the Project are:


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• site-specific selection of monitoring methods designed to verify containment • risk-based selection of monitoring methods and monitoring schedules designed to verify containment and to provide early warning in the unlikely event of a potential loss of containment • adaptive updates to the MMV Plan in response to new information obtained about the performance of the storage complex and the monitoring technologies

A10.3. Independent Project Reviews

Shell also incorporated lessons learned from other CCS projects through an Independent Project Review process conducted by a panel of CCS experts selected by DNV. This panel included individuals with particular expertise in groundwater monitoring and protection and lead scientists within the Weyburn CO2 Monitoring and Storage Project run by the International Energy Agency Greenhouse Gas Research and Development Program.


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APPENDIX 11. STATUS OF EXISTING WELLS

The status of existing wells that penetrate the BCS storage complex was analysed based on available documentation51. A review of existing documentation for all abandoned BCS legacy wells within and close to the Pore Space Tenure AOI indicates they all contain multiple thick cement plugs (Table 32). The deepest cement plug is below the Upper Lotsbeg Salt Formation in all cases except Imperial Darling No. 1. Table 33 describes the current status of Project appraisal wells. Table 34 provides the offset distances between proposed injectors and the closest hydrocarbon production well. Figure 25 shows the location of these wells in relation to the AOI and the stratigraphy.

Table 32: Status of BCS legacy wells.

Well name and UWI History and Distance from pipeline

Seals drilled through Casings, holes and BGWP

Cement plugs

Imperial Eastgate 100-01-34-057-22W400

- Drilled and abandoned in 1955 - 21 km from pipeline

- Upper Lotsberg - Lower Lotsberg - MCS

- 9 5/8” casing to 277m - 9” openhole to 2205m (TD) - BGWP at 240m bgl

#1: 265 – 289 m #2: 644 – 710m #3: 887 – 981m #4: 1016 – 1048m #5: 1256 – 1292m #6: 2125 – 2205m

Imperial Egremont 100-06-36-058-23W400



- 13 3/8” casing to 186m - 9” openhole to 2242.3m - BGWP at 220m bgl

#1: 172 – 195m #2: 624 – 670m #3: 844 – 875m #4: 969 – 1003m #5: 1178 – 1218m #6: 2140 – 2242m

Imperial Darling #1 100-16-19-062-19W400



- 13 3/8” casing to 183m - 9” (supposed) openhole to 2013m - BGWP at 235m bgl

#1: 168 – 198m #2: 525 – 587m #3: 708 – 740m #4: 762 – 792m

Westcoast et al Newbrook 100-09-31-062-19W40

- Drilled in and abandoned in 1978 28 km from pipeline


- 9 5/8” casing to 230m - 7” (supposed) openhole to TD at 1923m - BGWP at 228m

#1: 183 – 366m #2: 518 – 701m #3: 838 – 960m #4: 1082 – 1204m #5: 1280 – 1402m #6: 1524 – 1615m #7: 1707 – 1923m

Imperial Clyde #1 100-09-29-059-24W400

- Drilled and abandoned in 1948 - 43.5 km from pipeline (outside AOI)


- 13 3/8” casing to 135m - 9” openhole to 2295m (TD) - BGWP at 232.5m bgl

#1: 128 – 195m #2: 781 – 945m

Imperial Gibbons #1 100-02-16-056-22W400

- Drilled and abandoned in 1949 - 25 km from pipeline (outside AOI)

- Upper Lotsberg - Lower Lotsberg

- 13 3/8” casing to 180m - 9” openhole to 2024m (TD) - BGWP at 258.1m bgl

#1: 695 – 754m #2: 893 – 983m #3: 1052 – 1113m

Imperial PLC Redwater LPGS 100-07-17-056-21W400

- Drilled in 1974 – Converted to LPG reproducer in 1975 - Abandoned in 2007 - 18.5 km from pipeline

- Upper Lotsberg - 13 3/8”casing to 188.4m - 9 5/8” casing to 1778.2m - 7” casing to 1836m - TD at 1861m - BGWP at 216m bgl

#1: 0 – 500m #2: 1435 – 1760m #3: 1760 – 1861m


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Table 33: Status of the Project appraisal wells.

Well Name and UWI Inside AOI TD Status

SCL Redwater

102-11-32-55-21-W4M

No 2269m Well cased and cemented to TD. BCS abandoned and well converted to

a water disposal well into the shallower Nisku formation.

SCL-Redwater

03-04-57-20W4M

Yes 2190m Well cased and cemented to TD. Well suspended with 19 joints of

drillpipe and liner running tool cemented in hole. Top of cement at

1696.5m with top of fish at 1672m

SCL-Radway

8-19-59-20W4

Yes 2132m Well cased and cemented to TD. Well suspended awaiting D51 and D65

approval before recompletion as a potential commercial CO2 injection

well


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Figure 25: Summary of existing well locations.

1

2

3

5

13

12

68

9

10

BCS

LMS

MCS

Upper Lostberg

Winnipegosis

BC

S S

tora

ge c

om

ple

x

Upper Cambrian

Prairie Evaporite

Lower Lostberg

Devonian Red Beds

PreCambrian

Cooking Lake

Seal

CO2 storage

Aquifer

Permeable formation

Simplified stratigraphy

1: Imperial Eastgate2: Imperial Egremont3: Imperial Darling #1

4: Westcoast 9-315: Imperial Clyde #16: Imperial Gibbons #17: Imperial PLC Redwater8: Redwater 11-32

9: Redwater 3-410: Radway 8-1911: Provident #12, #14, #15, #1612: BP Amoco Thorhild 16-913: Mosaic Gulf Thorhild 16-22

Questwells

7

11

Legend

Basement

4


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Table 34: Distances to closest offset hydrocarbon producers.

Formation

Closest offset well

Inside AOI

Average depth to top reservoir in AOI

[m]

Distance from 8-19-059-20W4

[km] Comments

Viking 100/09-31-059-20W4/00 Yes 590 3.4

Joli Fou 100/08-36-059-20W4/00 Yes 615 8.7

Mannville 100/15-20-059-20W4/00 Yes 623 1.2 Includes Ellerslie, Glaucontic Sands

Wabamun 100/14-29-059-20W4/00 Yes 750 8.2

Nisku 100/09-06-058-21W4/00 Yes 850 15 Leduc Reef

Ireton 103/06-07-058-21W4/00 Yes 900 15 Leduc Reef

Leduc 100/03-08-058-21W4/0 Yes 1000 15 Leduc Reef

Winnipegosis - No 1600 - Saline Aquifer

BCS - No 2000 - Saline Aquifer


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APPENDIX 12. PRESSURE REQUIRED TO LIFT BCS BRINE

Table 35 gives the pressure increase required to lift BCS brine above the BGWP zone at third-party legacy well locations for wells that penetrate through all three major seals in the BCS storage complex (BCS legacy wells) in the AOI. However, BCS brine can only by lifted to the BGWP zone if these legacy wells provide an open conduit from the BCS to surface and this is unlikely because all BCS legacy wells have been abandoned with multiple large cement plugs. Other third-party legacy wells in the area either do not penetrate the BCS reservoir or are located outside the AOI and would have lower pressures in the BCS than the wells quoted in Table 117-1. To manage the containment risks associated with legacy wells, it will suffice to focus the modelling and monitoring efforts on the selected BCS legacy wells.

Table 35: Pressure increase required to lift BCS above the base of groundwater protection.

Well Name

Surface Elevation [mbsl]

BGWP Depth [mbsl]

Delta PA [kPa]

Imperial Eastgate 1-34 -641 -401 3,452

Imperial Egremont 6-36 -628 -408 3,334

Imperial Clyde No. 1B -629 -397 3,327

Imperial Darling No. 1 -704 -469 4,201

Westcoast 9-31C -699 -471 4,146

NOTES: mbsl denotes metres below sea level A Delta P is incremental BCS pressure required to lift BCS brine to BGWP B Imperial Clyde No. 1 is not located in the AOI. C Westcoast et al Newbrook 100-09-31-062-19W40 (Westcoast 9-31) was reclassified as a legacy well

that penetrates all three major seals in the BCS storage complex, since submission of the Application.


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APPENDIX 13. KEY PERFORMANCE INDICATOR REGRETS

Table 36: Standard Leading Operational Key Performance Indicators not considered for Quest MMV.

KPI 2 Well Test Compliance Definition Number of wells with a validated well test to the total number of wells Intent To ensure that well tests are carried out in accordance with the agreed injection

allocation requirements Rationale Discarded as each well will be equipped with a fiscal-class meter. Metering maintenance

is covered by KPI 1 of Table 10 so that the Well Test Compliance will be continuous for the Quest project

KPI 5b Operating Envelopes (Facility) Definition Percentage of facilities with up-to-date operating envelopes compared to total number of

active facilities. Intent To ensure that all facilities have (optimum) operating guidelines – agreed and

documented between Process Engineering and Production functions. Rationale Not included in the MMV plan but included in the Capture Operations and

Maintenance Plan4

KPI 7 Well Stock Covered by IPSM models Definition Percentage of wells covered with active and calibrated IPSM models compared to total

number of active (production/injection) and closed-in wells. Intent To monitor the build and maintenance of IPSM models as a key tool for production system

optimisation. Includes producer and injector wells; but excludes abandoned wells. Rationale Included in KPI 7 of Table 10.

KPI 8 IAP Compliance Definition Scheduling compliance for the Short Term IAP as defined in the IAP Process Guideline.

(The percentage of completed well intervention activities compared to the total number of activities scheduled for execution of the (frozen) first month of the short-term (90 day) plan.

Intent To monitor the efficiency of the planning and execution delivery. Rationale Included in KPI 2 of Table 10. Since the MMV activities are planned on year basis, KPI 2

is sufficient to track the quality of execution of the MMV activities.


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APPENDIX 14. DATA MANAGEMENT FOR MMV

Monitoring activities required under the MMV Plan will generate large amounts of data from many different source. Table 37 summarises the data management plan for these activities. All reference documents, such as updates to the MMV Plan and the Closure Plan, will be stored in LiveLink. Final location and structure of this to be agreed upon by the Quest Venture Subsurface and Surveillance teams. Web-based data portals will provide access to these monitoring data stored in secure databases (Figure 26).


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Table 37: Summary of the Data Managament Plan for MMV.

Legend: ET – SCAN Environmental Team; GR – Government Regulators; KS – Knowledge Sharing; SCR – Scotford Control Room; SP – SCAN Seismic Processing; ST – SCAN Surveillance Team; OPS – Operations; TBD – To be decided.

Technology

Data Source Data Transfer Data Storage

Users

Alarm & Type Location Volumes Frequency Mechanism Database Location Location

LOSCO2 – Line-of-Sight CO2 Gas Flux Monitoring

CO2 flux, time stamp, beam id (ASCII)

Project injection well pads <1 Mb/day

Daily Cellular network, via SCR, to Calgary

TBD (Novel, maybe PI)

Calgary ST, GR, ET, KS

Yes, in Calgary

MIA – Multi-Spectral Image Analysis

Geotiff images Satellite <1 Gb/year

<4 times per year FTP from Spatial Energy direct to Calgary

Arc Spatial Data Engine


No

ATM – Artifical Tracer Monitoring NTM – Natural Tracer Monitoring WC – Water Chemistry Monitoring

Chemical species concentrations (ASCII)

1. Project groundwater wells 2. Landowner wwater wells N.B. Not all on injection well pads

< 100 Mb/year

Annually FTP from Service Provider direct to Calgary

TBD (Check with NW)


No

CBL – Cement Bond Logs USIT – USIT Logs

LAS files (ASCII) 1. Project injection wells 2. Project deep observation wells 3. Project groundwater wells

<10 Mb/survey

1. Once at time of well construction 2. Every 5 years for injectors

FTP from Service Provider direct to Calgary

Openworks Calgary ST, GR, ET, KS

No

WEC – Water Electrical Conductivity Monitoring WPH – Water pH Monitoring

Attribute, time, well id (ASCII)

1. Project groundwater wells N.B. Not all on injection well pads

< 1Mb/day


PI (Check with NW)

Scotford ST, GR, ET, KS

Yes, in Calgary

INSAR – Surface Uplift Monitoring

Displacement, time, location (ASCII)

Satellite < 1Gb/year

Quarterly FTP from Service Provider direct to Calgary

Arc Spatial Data Engine (Check with Geomatics)


No

SEIS3D – 3D Surface Seismic VSP3D – 3D Vertical Seismic Profile

SEGY (Binary) Seismic surveys around injectors <10 Gb per survey

Every 1-10 years FTP from Service Provider direct to Calgary

Openworks Calgary ST, GR, ET, KS, SP

No

DTS - Distributed Temperature Sensing

Temperature, depth, time,

Project injection wells <10 Mb/day

Daily Cellular network, via SCR, to

DTS database

Calgary ST, GR, ET, KS,

Yes, in Calgary


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well id (ASCII) Calgary SP

DAS - Distributed Acoustic Sensing

Noise, depth, time, well id (ASCII)

Project injection wells <10 Mb/day


TBD (TDS database)

Calgary ST, GR, ET, KS, SP

Yes, in Calgary

DHMS - Down-hole Microseismic Monitoring

1. SEGY (Binary) 2. Event catalogue (ASCII)

Project deep observation wells on injection well pads

<10 Mb/day

Daily Cellular network or local internet connection, via SCR, to Calgary

TBD Calgary ST, GR, ET, KS, SP

Yes, in Calgary

Well-head pressure and temperature gauge

Pressure & temp Injector wellhead <1 Mb/day

real time SCADA PI Calgary via Scotford

ST, GR, KS, SCR

Down-hole pressure and temperature gauge

Pressure & temp Injector down-hole <1 Mb/day


ST, GR, KS, SCR

Yes, Scotford

Annulus pressure gauge Pressure Injector annulus <1 Mb/day


ST, GR, KS, SCR

Yes. Scotford

Injection rate metering mass flow rate Injector well pad <1 Mb/day


ST, GR, KS, SCR

Choke position % opening Injector well pad <1 Mb/day


ST, GR, KS, SCR

Pressure drop across choke

Pressure drop Injector well pad <1 Mb/day


ST, GR, KS, SCR

Temperature downstream of the choke

Temp. drop Injector well pad <1 Mb/day


ST, GR, KS, SCR

Pressure drop across filter Pressure drop Injector well pad <1 Mb/day


ST, GR, KS, SCR

Yes. Scotford

Surface controlled subsurface safety value status (SCSSV)

Open/close Injector well pad <1 Mb/day


ST, GR, KS, SCR

Yes. Scotford

Emergency shut-down valve status

Open/close Injector well pad <1 Mb/day


ST, GR, KS, SCR

Yes. Scotford


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Skid cabinet climate control status

Current status Injector well pad <1 Mb/day


ST, GR, KS, OPS

Yes. Scotford

Cathodic protection status Current status Injector well pad <1 Mb/day


ST, GR, KS, OPS

Chemical Injection mass flow rate Injector well pad <1 Mb/day


ST, GR, KS, OPS

Yes. Scotford

Well-head CO2 concentration gauge

Leak detector Injector well pad <1 Mb/day


ST, GR, KS, OPS

Yes. Scotford

UPS power supply status Strength Injector well pad <1 Mb/day


ST, GR, KS, OPS

Yes. Scotford


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Figure 26: Schematic illustration of the flow of data from sources to databases.


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APPENDIX 15. RESPONSIBILITIES AND ACCOUNTABILITIES FOR MMV

Table 38 lists the responsibilities and accountabilities for executing the MMV Plan.

Table 38: Allocation of single-point accountability and responsibilities for executing the MMV Plan.

R – Responsible

A – Accountable

C – Consulted

I – Informed

Sc

otfo

rd C

ontro

l Roo

m

SCA

N S

urve

illan

ce T

eam

SCA

N E

nviro

nmen

tal T

eam

Que

st Ve

ntur

e Su

bsur

face

Tea

m

Que

st Ve

ntur

e Re

gula

tory

Tea

m

SCA

N G

eoph

ysic

al O

pera

tions

SCA

N S

eism

ic P

roce

ssin

g

P&T

Geo

phys

ics

P&T

Rem

ote

Sens

ing

Com

plet

ions

and

Wel

l Int

erve

ntio

ns

Team

W

ell E

ngin

eerin

g

Third

-Par

ty S

ervi

ce P

rovi

der

Gov

ernm

ent R

egul

ator

s

Know

ledg

e Sh

arin

g

Reviews Daily surveillance by exception C A

Monthly surveillance reviews C A C Quarterly surveillance reviews I R C A C I I I I I

Annual MMV reviews I C C A C I I I I I I

Reporting

Monthly injection volume reporting C R A C I Annual performance reporting C C C R A C I

MMV Plan update C C C R A C I Closure Plan update C C C R A C I

In-Well Monitoring

Respond to SCR alarm A I I Respond to Calgary alarm C A R C Respond to Calgary alarm C A C Planned well maintenance A C C I

Well interventions C A C I R

Geosphere Monitoring

VSP acquisition I I A R C C I VSP processing I A C R R I

VSP interpretation C A C C C I VSP performance review C A I C C C I

Surface seismic acquisition I I A R C C I Surface seismic processing I A C R R I

Surface seismic interpretation C A C C C I Surface seismic performance review C A I C C C I

Microseismic acquisition A C C R I Microseismic processing A C R I

Microseismic interpretation A C R I


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Microseismic performance review A C I R I InSAR acquisition I A C R I InSAR processing I A R I

InSAR interpretation C A I InSAR performance review C A I I

Deploy InSAR corner reflectors I C A C R Verify or update reservoir models I C A I I

Hydrosphere Monitoring

Groundwater fluid sampling C C A C C R Groundwater fluid analysis C A C C R I

Groundwater WEC & PH acquisition A C C R I Interpretation of monitoring data C A I R I Monitoring performance review C A I R I

Biosphere Monitoring

Remote sensing acquisition I A C C R I Remote sensing processing I A C C R I

Remote sensing interpretation I C A C I C R I Remote sensing performance review I C A C I C R I

Soil & vegetation sampling C A C C R Soil & vegetation analysis I A C I R I

Soil & vegetation performance review I A C I R I

Atmosphere Monitoring

LOSCO2 acquisition C C A C C C R I LOSCO2 processing I A I R I

LOSCO2 interpretation I C A C I R I LOSCO2 performance review I C A C I R I

Scotford Control Room

SCA

N Surveillance Team

SCA

N Environm

ental Team

Quest Venture Subsurface Team

Quest Venture Regulatory Team

SCA

N G

eophysical Operations

SCA

N Seism

ic Processing

P&T Seismic Processing

P&T Remote Sensing

Com

pletions and Well Interventions Team

Well Engineering

Third-Party Service Provider

Governm

ent Regulators

Knowledge Sharing

The Resourcing requirements for each team listed above will be developed during the execute phase of the development.


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APPENDIX 16. MMV COST ESTIMATES

Due to the phased storage development concept12, the total estimated lifecycle cost of MMV depends on the number of injectors required at start-up:

3 injectors: 4.0 CAD per tonne CO2 injected; 4 injectors: 4.4 CAD per tonne CO2 injected; 5 injectors: 4.8 CAD per tonne CO2 injected.

These estimates were calculated according to unit cost estimates (Table 39), and the frequency (Table 6, Table 7, Figure 27) and quantity (Table 8) of monitoring activities through time. No adjustments were made for changes in unit costs or the value-of money through time. Time-lapse surface seismic within geosphere monitoring accounts for the greater part of these costs (Figure 28, Figure 29).

Table 39: Summary of estimates for initial costs and unit repeat costs for data acquisition and processing.

Legend: PTI – Shell Projects, Technology and Innovation, WE – Well engineering, CWI – Completions and Well Interventions, GO – Geophysical Operations, VE – Vendor estimate, SE – Screening Estimate, WB – Wells budget already covers these costs

Technology Initial Acquisition Processing Unit Source

[CAD] [CAD] [CAD]

Atmosphere

Line-of-sight CO2 gas flux monitoring 200000 20000 0 Per system (year) VE

Biosphere

Soil salinity monitoring 0 200000 0 Per survey SE

Soil pH monitoring 0 200000 0 Per survey SE

Multi-spectral image analysis – WorldView II 0 145000 21000 Per image VE

Multi-spectral image analysis - RapidEye 0 4300 3600 Per image VE

Hydrosphere

Water chemistry monitoring 0 200 100 Per well sample SE

Down-hole pH monitoring 13000 2000 0 Per well (year) VE

Down-hole electrical conductivity monitoring 13000 2000 0 VE

Water chemistry monitoring 0 200 100 SE

Natural tracer monitoring 0 0 20000 Per year SE

Artificial tracer monitoring 0 0 20000 Per year SE

Observation wells in GPZ 200000i 0 0 Per well WE

Geosphere

Time-lapse 3D vertical seismic profiling 0 500000 150000 Per well survey GO

i Includes 40% contingency


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Time-lapse 3D surface seismic 0 33000 1600 Km2 GO

Interferometric Synthetic Aperture Radar 0 5000 5000 Per month VE

Wells: Monitors

Down-hole pressure-temperature monitoring 100000 2000 0 Per year CWI

Down-hole microseismic monitoring 400000 100000 0 Per system (year) GO

Cement bond Log 0 20000 0 Per log CWI

Observation wells in WPGS 2250000i 10000ii 0 Per well WE

Observation wells in WPGS (for DHMS) 2625000I 10000i 0 Per well WE

Recomplete observation well in BCS 560000 0 0 Redwater 3-4 CWI

Wells: Injectors

Well-head pressure-temperature monitoring 0 0 0 Per well (year) WB

Well-head CO2 monitoring 5000 2000 0 Per well (year) SE

Time-lapse ultrasonic casing imaging 0 20000 0 Per log SE

Time-lapse electromagnetic imaging 0 20000 0 Per log SE

Mechanical Well Integrity Testing and Routine Well Maintenance ii 0 0 0 Per test WB

Injection rate monitoring 0 0 0 Per well (year) WB

Distributed temperature sensing (fibre + box) 500000 5000 0 Per well (year) SE

Down-hole pressure-temperature monitoring 100000 2000 0 Per well (year) WB

Distributed acoustic sensing (box) 300000 5000 0 Per well (year) SE

Cement bond Log 0 20000 0 Per log CWI

Annulus pressure monitoring 0 0 0 Per well (year) WB

Artificial tracer injection 0 0.1 0 Per tonne CO2 VE

Injection wells 0 0 0 Per well WB Note: The cost injection well construction and routine maintenance of these wells is carried by the wells budget.

i Includes 25% contingency

ii Annual cost of well maintenance is 10kCAD


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Figure 27: Schedule of monitoring activities through time for the base case development scenario of 5 injectors.


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Figure 28: Estimated cumulative MMV costs through time.


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Figure 29: Estimated cumulative MMV costs through time for geosphere and hydrosphere.


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Figure 30: Estimated cumulative MMV costs through time for monitoring within injectors and deep observation wells.


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Figure 31: Estimated cumulative MMV costs through time for biosphere and atmosphere monitoring.

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