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Controlled Document

Quest CCS Project

Containment Risk and Uncertainty Review

Project Quest CCS Project

Document Title Containment Risk and Uncertainty Review

Document Number 07-3-AA-6619-0004

Document Revision 02

Document Status Issued for Approval

Document Type AA6619-Risk, Opportunity Register

Owner / Author Hein de Groot

Issue Date 2011-06-29

Expiry Date 2015-12-31

ECCN EAR 99

Security Classification

Disclosure None

Revision History shown on next page

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Revision History REVISION STATUS APPROVAL

Rev. Date Description Originator Reviewer Approver

01 2010-09-17 Issued for Approval Hein de Groot Sean McFadden Syrie Crouch 02 2011-06-29 Issued for Approval Hein de Groot Sean McFadden 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 Hein de Groot

Reviewer Doreen Becker

Reviewer Sean McFadden

Approver Syrie Crouch

Summary

Shell has a mature risk management process which is applied to all projects and provides a rigorous assessment/management of risk that feeds into project decisions. This process has been applied to the QUEST project with the addition of: - A more formal approach to uncertainty management for the subsurface (Italian Flags

/TESLA) - Project Specific Risk Assessment Matrix (RAM) (See Appendix 1) - Application of the Bow Tie process to assess barriers that reduce containment risk to ALARP

(As Low As Reasonably Practicable) - a key process in the development of a risk based, site specific MMV plan (Only applicable to risks with HSE impact, i.e. Containment).

This document summarizes all loss of containment related risks and uncertainties for the Quest integrated Capture and Sequestration project identified up to Q2 2011 and includes updates made to incorporate feedback from the Oct 2010 DNV led Independent Project Review, the drilling and testing of well Radway 8-19 and information gathered from 3D seismic campaigns in 2010. This document is an ever green document that will be updated when new data comes available.

Keywords

Quest, CCS, Containment, MMV, Risks, Uncertainty, TESLA, EasyRisk, bow-tie

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TABLE OF CONTENTS

1. CONTAINMENT – TESLA SUMMARY ................................................................... 5

2. CONTAINMENT – BOW-TIES ............................................................................... 8

3. CONTAINMENT – EASYRISK SUMMARY............................................................ 11

4. FEEDBACK FROM THE OCT 2010 EXTERNAL PERFORMANCE REVIEW .............. 13

5. CHANGES IMPLEMENTED FROM REV. 01 .......................................................... 17

6. ALL CONTAINMENT RISKS IN EASYRISK AND TESLA DATABASES .................... 24

Risk 4339: Timely Demonstration of Storage Feasibility .................................................. 25

7. FAULTS / FRACTURING – EASYRISK SUBGROUP ............................................... 27

Risk 4157: Migration along a fault pathway .................................................................. 28

TESLA - LOCATIONS of all significant faults & fractures in the containment complex are known and mapped ............................................................................................ 30

TESLA - REGIONAL stress measurements are available, are of sufficient quality and are supportive of containment .................................................................................... 31

TESLA - CURRENT DISTRIBUTION OF FLUIDS in the play support fault sealing in the containment complex - including an assessment of natural seismicity ...................... 32

Risk 4177: Injection induced stress reactivates a fault ..................................................... 33

TESLA - FAULT REACTIVATION pressures are calculated and with choice and control of BHP are supportive of containment ....................................................................... 35

TESLA - FAULT VALVING pressures are calculated and with choice and control of BHP are supportive of containment .............................................................................. 36

Risk 4154: Injection induced stress fractures geological seals .......................................... 37

TESLA - FRACTURE PROPAGATION pressures are measured and modeling and choice of BHP supports containment .................................................................................... 39

8. SEALS – EASYRISK SUBGROUP .......................................................................... 41

Risk 4168: Migration along a stratigraphic pathway ...................................................... 42

TESLA - PROVEN PRIMARY SEAL, the primary seal is proven (in a play sense) to hold pressures & fluids and this proof is representative of the CO2 area ........................ 44

TESLA - PROVEN ULTIMATE SEAL: Shallowest seal which defines the upper limit of the container complex ............................................................................................... 46

Risk 4167: Acidic fluids erode geological seals (Geochemical degradation) .................... 47

TESLA - REACTIVE FLUIDS; interaction between reactive fluids and cap-rock are understood and supportive of sustained sealing..................................................... 49

9. WELLS – EASYRISK SUBGROUP ......................................................................... 50

Risk 4520: Migration along Legacy wells ....................................................................... 51

TESLA - EXISTENCE: all well locations are known ........................................................... 53

TESLA - STATUS/CONDITION: status of all known wells is known and supports non-leakage in the subsurface ..................................................................................... 54

Risk 4132: Migration along a QUEST well - Compromised casing integrity...................... 55

Risk: QUEST: Migration along a QUEST well - Compromised cement integrity ................. 57

Risk 4159: Migration along a QUEST well - Compromised completion or wellhead integrity .............................................................................................................. 59

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Risk 4522: Migration along a QUEST well - Compromised abandonment ....................... 61

Risk: QUEST: Migration along a QUEST well as a result of well intervention..................... 63

TESLA - FUTURE well bores will avoid creating leak paths or minimise the risk thereof ...... 65

Risk 4149: Requirement for MMV wells in the BCS (eg. ineffective non-invasive MMV) threatens Containment ......................................................................................... 66

Risk 4524: Third party induced migration ...................................................................... 68

APPENDIX 1 QUEST RISK ASSESSMENT MATRIX (RAM) .................................... 70

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1. Containment – TESLA Summary The containment hypothesis is illustrated below for the QUEST project and the evolution of the Italian flag for this hypothesis over the 3 workshops.

CONTAINMENT HYPOTHESIS Injected, reactive fluids will not leak SIGNIFICANTLY from the containment complex

Italian Flag History

Nov 2008 0.35 0.05

March 2009 0.41 0.15

Sept 2009 0.48 0.25

Sept 2010 0.7 0.10 A new TESLA evaluation was not prepared for this Rev.02 issue of the Containment risk and uncertainty document and the first paragraph in this section is maintained as a commentary on the September 2010 TESLA score and its history. September 2010 commentary on TESLA score The evidence for the containment hypothesis has increased significantly as uncertainty has been reduced. It is understandable that this number started at a reasonably high level of 0.35 as the site would not have been selected unless there was reasonable evidence for containment. The key evidence for containment can be summarized below:

• The BCS storage complex has been defined to include the first seal MCS and all intervals above up to the top of the Upper Lotsberg salt.

• There are three key seals within the BCS storage complex: the MCS (Middle Cambrian Shales), The Lower Lotsberg salts and the Upper Lotsberg Salts

• The seals compensationally stack so that as the MCS is eroded by the Devonian unconformity the Lotsberg Salts thicken into the resulting basin.

• The MCS is a marine shale composed predominantly of illite and kaolinite, which is eroded by the Devonian unconformity to the north of the AOI

• The Lower and Upper Lotsberg Salts predominantly consist of halite with minor shale laminae and are thick and extensive (extending for more than 300 km updip towards the NE) and covers the area where the MCS may be thinning out.

• The total package above the BCS injection target is ~350m thick including the three seals described above and the intervening baffling formations.

The small negative evidence from the hypothesis is related to the primary seal (MCS): PROVEN PRIMARY SEAL, the primary seal is proven (in a play sense) to hold pressures & fluids and this proof is representative of the CO2 area Although the MCS is believed to be thick and extensive there are still some outstanding minor issues:

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- Petrophysical analysis has shown the MCS to contain silty streaks (with horizontal perm.) at the top and centre parts.

- The MCS is eroded by the Devonian unconformity to the NE outside of our AOI. - BCS is absent over Precambrian highs east of the AOI and potentially absent in the bald

highs in the northern portion of the AOI as interpreted from 2D seismic. Legacy Wells The negative evidence from previous updates was influenced by the hypothesis related to well integrity: • FUTURE well bores will avoid creating leak paths or minimise the risk thereof • STATUS/CONDITION: status of all known wells is known and supports non-leakage in the

subsurface The status and condition of existing wells penetrating the BCS has now been studied and is known. As there are no known issues with legacy well integrity other than the uncertainty that arises from lack of pressure testing on cement plugs this negative evidence has also been removed. Also the probability of legacy wells being intersected by the plume or higher pressures which are deemed to be significant is very low as most of them are outside the AOI with only four penetrations through the MCS seal inside but towards the boundaries of the AOI away from the central injection area. The biggest remaining uncertainty is around the status of Legacy well Imperial Darling as this well is inside the AOI but was not cemented across the seals of the BCS storage complex. The legacy well study was extended to all wells penetrating the Upper and Lower Lotsberg salts to evaluate the risk of a leak path above the BCS storage complex. The extended search added one well, Imperial Gibbons that TD’ed in the Lower Lotsberg, but is located to the SW outside of the AOI. Project Wells Incorporation of learnings from drilling the first two appraisal wells (11-32 and 3-4), regional drilling experience, and wellbore stability and mud testing led to the third well, and first injection well (8-19), being drilled, cased and cemented with hydraulic isolation over all three seals. Therefore negative evidence associated with poor cement and hole condition in the first two appraisal wells (11-32 and 3-4) was removed. Continuity of seals and absence of faults The 3D seismic data now covers approximately 415 km2 or about 11% of the AOI and the latest processed data, available since April 2011, indicate increased frequency content of the data (up to 100Hz) which for the first time allows for an interpretation of an event near the top BCS. The absence of interpreted faults continuing from top Precambrian interval to top of BCS on the 3D seismic dataset has reduced the probability of the presence of faults across the BCS reservoir or any of the seals that could act as migration paths out of the BCS storage complex.

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Seal Integrity and Fracture gradients Sufficient fracture gradient information has been obtained in the Redwater 11-32 and Radway 8-19 wells to show that there is low probability, with the current compressor design capacity, of exceeding the fracture initiation or propagation pressure for the BCS. Since there are no known faults across the seals the uncertainty around fault reactivation is not seen to be an issue. One area where some residual uncertainty exists in relation to containment is the fracture gradient and how this may be impacted by reservoir cooling through injection of cold CO2. Containment versus Conformance Although there are uncertainties in reservoir architecture and structural dip, the impact on CO2 flow across the range of uncertainties will not result in a loss of containment of CO2 migration outside the BCS storage complex. However, these uncertainties are discussed in detail in relation to conformance.

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2. Containment – Bow-ties The application of the Bow Tie process to assess barriers that reduce containment risk to ALARP (As Low As Reasonably Practicable) is a key process in the development of a risk based, site specific MMV plan. The containment Bow Tie that describes the threats and consequences of a Loss of Containment event is provided in Figure 1 on the next page. The top event in this bow-tie is defined as “Migration of CO2 or BCS brine above the Upper Lotsberg Salt” (Ultimate seal for the BCS storage complex). All threats on the left side of the bow-tie are captured in the Quest EasyRisk database and are aligned with Risk hypotheses in TESLA. The bow-tie is an integral part of the Quest risk management framework and is used to support the MMV objectives around ensuring containment. This subset of overall MMV objectives focuses on:

- Detect early warning signs for any loss of containment - Activate safeguards to reduce containment risks to ALARP - Demonstrate effectiveness of any control measures deployed The Risk based Management Approach to MMV comprises:

- An iterative evaluation cycle to Identify-Monitor-Decide-Respond to each Risk Outcome - The use of a Bowtie for safety critical risk: Containment - Selection of MMV options based on technical feasibility & Value of Information - An adaptive MMV plan to manage lifecycle risks

The threat of migration along a Quest well was broken down further to the various elements and failure mechanisms in the well that could result in loss of containment. The wells bow tie is provided in Figure 2 and applies equally to Quest injection and MMV wells if they would be required to penetrate the seals of the BCS storage complex. The five threats on the left hand side of the wells bow-tie were also entered into the Quest risk database and complement the 8 threats from the containment bow tie on the previous page.

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Fig. 1 Containment Bow-tie for the Quest Project

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Fig. 2

Wells Bow

-tie, subset of the Containment Bow

-tie for the Quest Project

Threats

Barriers

Migration of CO2

or BCS brine

above the Upper

Lotsberg

Salt

HC resource

affected

Groundwater

Impacted

Soil

impacted

CO2 releases

in atmosphere

Monitoring& RM1

Monitoring& RM2

Monitoring& RM3

Winnipegosis

PrarieEvaporite

BeaverHill Lake

CookingLake

Ireton

Mannville

Colorado

Lea Park

Monitoring& RM1

Monitoring& RM6

Monitoring& RM16

Monitoring& RM8

Winnipegosis

PrarieEvaporite

BeaverHill Lake

CookingLake

Ireton

Winterburn

Mannville

Colorado

Monitoring& RM1

Monitoring& RM4

Monitoring& RM9

Monitoring& RM17

Winnipegosis

PrarieEvaporite

BeaverHill Lake

CookingLake

Ireton

Winterburn

Mannville

Colorado

Lea Park

Monitoring& RM1

Monitoring& RM2

Monitoring& RM3

Monitoring& RM4

Mitigations

Consequences

Migration due to

Compromised cem

ent

Migration due to

Compromised casing

WellTD

CementSelection

CementPlacement

OperatingProcedures

Legend

PrarieEvaporite

BeaverHill Lake

Monitoring& RM5

Migration due to

Compromised

Completion/wellhead

Migration due to

Well intervention

Migration due to

Compromised

abandonm

ent

For MMV wells only

Design barriers

Operational barriers

Already mentioned in Containment Bowtie, applicable for wells

WellTD

BCS notperforated

WellTD

WellTD

MMV

CasingSelection

CasingPlacement

OperatingProcedures

MMV

Compl./WHSelection

Compl./WHPlacement

OperatingProcedures

MMV

Procedures design

Crew Competences

AppropriateEquipment

CO2 blowout

SC-SSSV

Wellkill

E.R.P.

Design &PhasedStrategy

CementPlacement

MMV

In c

ase

of c

om

pro

mis

ed w

ellh

ead

inte

grity

CasingIntegrity

CementIntegrity

CementIntegrity

CasingIntegrity

CementIntegrity

CasingIntegrity

CementSelection

AppropriateOnsite HSSE

IC4WI1, WI3

IC4WI1, WI3

IC4WI2, WI3

WellheadIntegrity

WellheadIntegrity

WellheadIntegrity

MMV

Top

Even

t

SiteSelection

WellDesign

MinimizeWell Interv.

WellTD

Few absorbedcontaminants

Bufferingreactions

High initialWater pH

Mixing, dilutionin groundwater

WellDesign

WellDesign

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3. Containment – EasyRisk Summary Fourteen risks are captured in the EasyRisk database in the Containment category.

The project and HSE Risk Assessment Matrix (RAM) and its definitions are provided in Appendix 1.

Probability pre mitigation Low (5-20% occurs in some projects, low but not impossible)

4339 – Timely Demonstration of Storage Feasibility (L/VH → VL/H) 4177 – Injection induced stress reactivates a fault (L/VH → VL/VH) 4132 – Migration along a QUEST well - Compromised Casing Integrity (L/H → VL/H) 4133 – Migration along a QUEST well – Compromised Cement Integrity (L/H →VL/H) 4149 – Requirement for MMV wells in BCS threatens containment (L/H → VL/H) 4154 – Injection induced stress fractures geological seals (L/H → VL/H) 4157 – Migration along a fault pathway (L/H → VL/H) 4159 – Migration along a QUEST well - Compromised Completion Integrity (L/H → VL/H) 4168 – Migration along stratigraphic pathway (L/H → VL/H) 4520 – Migration along legacy wells (L/H → VL/H) 4523 – Migration along a QUEST well as a result of Well Intervention (L/H → VL/H) 4524 – Third-party induced CO2 migration (L/M → VL/M) 4522 – Migration along a QUEST well – Compromised Abandonment (L/L → VL/L)

Probability pre mitigation Very Low (0-5% occurs in almost no projects, extremely unlikely)

4167– Acidic Erosion of geological seals (VL/VH → VL/VH)

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Alignment of EasyRisk with TESLA Hypotheses:

Faults and Fracturing R-4157 Migration along a fault pathway - LOCATIONS of all significant faults & fractures in the containment complex are known and mapped. - REGIONAL stress measurements are available, are of sufficient quality and are supportive of containment. - CURRENT DISTRIBUTION OF FLUIDS in the play support fault sealing in the containment complex - including an assessment of natural seismicity.

R-4177 Injection induced stress reactivates a fault - FAULT REACTIVATION pressures are calculated and with choice and control of BHP are supportive of containment

- FAULT VALVING pressures are calculated and with choice and control of BHP are supportive of containment R-4154 Injection induced stress fractures geological seals - FRACTURE PROPAGATION pressures are measured and modeling and choice of BHP supports containment. Geological Seals R-4168 Migration along a stratigraphic pathway - PROVEN PRIMARY SEAL, the primary seal is proven (in a play sense) to hold pressures & fluids and this proof is representative of the CO2 area

- PROVEN ULTIMATE SEAL: Shallowest seal which defines the upper limit of the container complex R-4167 Acidic fluids erode geological seals (geochemical degradation) - REACTIVE FLUIDS; interaction between reactive fluids and cap-rock are understood and supportive of sustained sealing

Wells R-4520 Migration along legacy wells - TESLA - EXISTENCE: all well locations are known - TESLA - STATUS/CONDITION: status of all known wells is known and supports non-leakage in the subsurface R-4132 Migration along a Quest well – Compromised Casing Integrity R-4133 Migration along a Quest well – Compromised Cement Integrity R-4159 Migration along a Quest well – Compromised Completion Integrity R-4522 Migration along a Quest well – Compromised Abandonment Integrity R-4523 Migration along a Quest well as a result of well intervention - TESLA - FUTURE well bores will avoid creating leak paths or minimise the risk thereof R-4149 Requirement for MMV wells in the BCS (eg. Ineffective non-invasive MMV) threatens containment R-4524 Third party induced migration

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4. Feedback from the Oct 2010 External Performance Review The below paragraph is quoted from the final close out report of the DNV facilitated Independent Project Review [07-3-AA-0706-0001, Nov. 2010] QUOTE: The Panel agrees that ample evidence has been provided at this stage of the project to demonstrate that leakage of CO2 out of the storage complex will be extremely unlikely if the storage site is managed according to indicated plans, contingent upon implementation of a designated risk-based MMV plan and implementation of identified actions to mitigate containment risk. Thus, the Panel has very strong confidence in the top-level containment hypothesis: Injected reactive fluids will not leak significantly from the containment complex. The panel recommends, however, that the word “significantly” is carefully defined or removed from the formulation of this hypothesis.

The Panel further agrees that the containment risks are generally accurately assessed, but has the following additional remarks and/or recommendations for modifications:

- Timely demonstration of containment. Description should be reworded to “Timely

prediction of containment for regulatory approval” (See discussion in paragraph below). The QUEST subsurface team is urged to review this wording and confirm the focus for the risk issue. Post-mitigation probability should be raised from “Extremely unlikely” to “Low, but not impossible” or higher. The subsurface team is also advised to carefully review assessed post-mitigation impacts.

- Injection induced stress reactivates a fault. Probability should be raised from “Extremely unlikely” to “Low, but not impossible”.

- Injection induced stress fractures geological seals. Proceed carefully with work-packages identified for thermal effects during CO2 injection. Consider subdividing risk into the following two elements: “Injection fractures BCS” and “Injection fractures geological seals”.

- Migration along a stratigraphic pathway. Additional work packages should be identified to support or defend the assessed reduction in probability post mitigation (from “Extremely unlikely” to “Low, but not impossible”). Potential for brine migration should be considered separately.

- Acidic erosion of geological seals. Further numerical analysis studies should be performed to validate the conclusions. Although reactions between the Lotsberg salts and the near salt saturated BCS formation water will be minimal, this must be documented. Potential reactions between the MCS and a CO2 charged BCS formation water should be described and documented.

- Migration along legacy wells. Probability might need to be raised from “Extremely unlikely” to “Low, but not impossible”. More work needs to be done, quantitatively evaluating the mechanisms of up-hole migration of pressure and fluids, to support conclusion.

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- Requirement for MMV wells in the BCS. There is an inconsistency between assessment of risks related to injectors and MMV wells that should be more clearly resolved in ongoing work packages.

The risk “Timely demonstration of containment” was introduced to ensure that the cumulative effect of all identified technical containment risks are properly captured and aggregated. This risk does not represent a technical failure mechanism, but is intended to ensure adequate visibility of containment risks to support the need for early and adequate appraisal and to provide a tool to communicate containment risk in general. In the risk register the assessed risk post-mitigation was based on the residual level of risk after regulatory approval of the QUEST project is granted. The Panel is of the opinion that this risk is really about the ability to build sufficiently strong confidence in containment to support a successful application for regulatory approval. This alternative definition of this “umbrella risk” would recognize the potential influence of perceived risks among regulators, stakeholders and the general public, as well as the time needed by ERCB and AUB to absorb the technical documentation provided supporting the regulatory submission. UNQUOTE Actions and Comments on IPR feedback from Quest Storage Team TESLA Hypothesis The structure of the TESLA containment tree including the definitions of the Containment hypotheses is currently under review by the Shell global CCS team. Quest will review whether to align with this new TESLA structure or at least partially adapt to this new standard. It is expected that the new phrasing of the overall containment hypothesis will not include the word “significantly”. Risk 4339: Timely Demonstration of Storage Feasibility This risk was re-phrased from “Timely demonstration of Containment” to “Timely demonstration of Storage Feasibility” and additional description was added to clarify that this risk is intended to capture pre-FID risks of not being able to demonstrate storage feasibility (Containment, Injectivity & Capacity) internally or, to Regulatory board and address Government and public concerns. Risk 4177: Injection induced stress reactivates a fault The post mitigation probability of this risk was reviewed but not changed, in view of the additional information from the 3D seismic that supports the absence of evidence for faults intersecting either the BCS or any of the seals in the BCS storage complex. In the absence of faults the probability for fault reactivation remains very low. Risk 4154: Injection induced stress fractures geological seals Considerably more work was carried out on thermal well and reservoir models to quantify the degree and extent of reservoir cooling that could be expected from injecting cold CO2. Pipeline and wellbore modelling suggests that flowing bottom hole temperatures could be as low as 15

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degC, some 45 degC below initial reservoir temperature. Injecting CO2 with a constant temperature of 20 degc for 10 and 25 years would result in a cooling zone of 130-230m and 160-350m respectively. Due to conduction effects cooling is expected to take place in a fairly homogenous cylinder, relatively independent from CO2 plume development. Special core analysis to quantify the effect of cooling on formation stress and fracture gradients is still ongoing and expected to be reported out by Q3 2011. The suggestion to split fracturing of the BCS out of this risk, separate from the risk of fracturing the seals was considered but eventually not incorporated. The risk description was extensively reviewed and eight passive and active barriers to fracture propagation were identified and incorporated in the risk description. Ultimately the introduction of a new risk called “Injection fractures BCS” was rejected as this risk would have no consequences that are not already captured in existing containment of conformance risks. Risk 4168: Migration along a stratigraphic pathway Further review of BCS and Winnipegosis water composition data appears to provide further evidence of geological separation of these intervals and hence the absence of a stratigraphic migration path between these formations. Seismic data further suggest the continuity of all three seals of the BCS storage complex within the AOI and considerable distances beyond the AOI boundary whilst dynamic reservoir modeling has indicated that plumes will be contained well within the AOI, with pressures at the AOI boundary being very unlikely sufficient to lift BCS brine to surface in the presence of a leakpath. The post mitigation probability for this risk is still considered “Extremely unlikely” and was not increased to “Low, but not impossible”. Risk 4167: Acidic fluids erode geological seals (Geochemical degradation) Further geochemical studies were carried out to support the assessed probability and consequences but documentation is still in progress. Risk 4520: Migration along Legacy wells A radial well model was constructed for the Imperial Darling Legacy well in the NE of the AOI to test potential impacts of elevated BCS pressures on the overburden in the presence of a migration path along the abandoned wellbore. Ingress of saline BCS brine was noticed in some of the more permeable overlying formations (most notably the Winnipegosis and Cooking Lake formations) over a distance up to 100m away from the legacy well bore. Pressures were seen to increase much faster and over a longer distance and could be observed more than 500m away from the legacy well bore. If the low Cooking Lake reservoir pressure, measured in Radway 8-19, is present throughout the AOI, BCS brine may never be able to reach either the surface or the base of the groundwater protection zone. The Cooking Lake would act in this scenario as a sink to BCS formation water as well as shallow groundwater, should these formations be in communication through a poorly abandoned legacy wellbore. The status of the legacy wells has meanwhile been further clarified, with many of them containing multiple long cement plugs, and further Gen-4 pressure modeling is also suggesting a reduced likelihood of reaching threshold pressures at the AOI boundary as the risk of

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compartmentalization is much reduced following interpretation of the new 3D seismic. The post mitigation probability was maintained at Very Low (Extremely unlikely). Risk 4149: Requirement for MMV wells in the BCS (eg. ineffective non-invasive MMV) threatens Containment The pre-mitigation probability of Loss of Containment in an MMV well was aligned with the probability of Loss of Containment in the Injection wells and reduced from Medium to Low.

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5. Changes implemented from Rev. 01 Risk 4339: Timely Demonstration of Storage Feasibility This pre-mitigation probability of this risk was reduced from High to Low after the completion of the 2010 Appraisal program for the following reasons:

1) A Carbon Sequestration Lease for the project was received on 27 May 2011 2) Landowners have been consulted wrt to all 8 proposed D65 injection well locations and

most of the Pipeline ROW. Landowner consent has been gained for the original 5 wells and discussions are ongoing for the 3 additional wells

3) Outcome of 2010 appraisal activities (3D seismic, Radway 8-19) providing strong evidence for containment (absence of faults intersecting BCS, continuity of seals, consistency in frac gradients) and encouraging injectivity and storage capacity results (Radway 8-19 injectivity of 380 m3/d/MPa sufficient to meet Project requirements, average porosity up from 15 to 16%, no indications of compartmentalisation from seismic)

4) Positive outcome of the DNV facilitated Independent Project Review (Oct'10), VAR3 (Dec'10), JV partner review (Feb'11), ITR4 (June '11)

5) Good progression on regulatory approval process (Applications submitted on 30 Nov 2010, draft SIR's received and preparation of responses nearing completion, in time for Regulatory hearing in Q4 2011)

Timely completion of 2010 appraisal activities (3D surface seismic, Radway 8-19 drilling and testing) has confirmed or reduced the range of uncertainty in reservoir properties and improved the base case reservoir description

Risk 4157: Migration along a fault pathway The 3D seismic data now covers approximately 415 km2 or about 11% of the AOI and the latest processed data, available since April 2011, indicate increased frequency content of the data (up to 100Hz) which for the first time allows for an interpretation of an event near the top BCS. The absence of interpreted faults continuing from top Precambrian interval to top of BCS on the 3D seismic dataset has reduced the probability of the presence of faults across the BCS reservoir or any of the seals that could act as migration paths out of the BCS storage complex.

The following mitigations in place were added to the risk description: 1) Faults are picked on the Pre-Cambrian granite seismic interval. 2) Evidence of no faults with throws greater than 15 m crossing the seal complex from 2D

and 3D seismic covering the full AOI. The 2D seismic spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic is available over the central development area.

3) There is a period of ~1.5 billion years between the granite and the deposition of the BCS. Therefore it is unlikely that any Pre-Cambrian faults were active in the BCS time of deposition.

4) 3D seismic will help place injection wells away from features that may represent faults at the Precambrian basement level.

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5) The Lotsberg salts are ductile and expected to creep and reseal any unexpected small faults.

Risk 4177: Injection induced stress reactivates a fault In line with the reduced likelihood of the presence of faults intersecting either the BCS or any of the seals in the storage complex, there is a reduced likelihood of fault reactivation.

The following mitigations in place were added to the risk description: 1) The Quest AOI is not an area of active natural seismicity. There is a regional seismic

monitoring network in place for more than 80 years with a capability of detecting a magnitude 3 event within our AOI. None were detected over this period (Reference: AGS Tectonic activity map for Alberta).

2) No faults offsetting the MCS or Lotsberg seals were mapped in the AOI using 2D seismic that spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic over the development area.



5) Compressor discharge pressure is limited to 14.5 MPa (900# pipe class) 6) Down hole gauges will be deployed to ensure that wells stay within pressure constraints

using well head chokes to control pressure. 7) Under normal operating conditions injection will be distributed over n wells. The system

will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells.

8) Downhole microseismic monitoring will detect any fault reactivation within 600m of the injector to motivate a reduction in injection pressure (to be included in the final MMV plan).

Risk 4154: Injection induced stress fractures geological seals The new data acquired to support the definition of this risk is the Radway 8-19 minifrac. This data suggests good alignment of the BCS fracture extension pressure (FEP) between these wells that are 36km apart. Redwater 11-32 measured a BCS FEP gradient of 20.7 kPa/m, whilst the Radway 8-19 FEP gradient came in at 20.6 kPa/m. The maximum bottom hole pressure constraint however is set by the LMS FEP gradient measured in Redwater 11-32 measured at 17.4 kPa/m and no new minifrac data was acquired on the LMS in Radway 8-19. However, a casing shoe leak-off test for the intermediate casing set at the top of the LMS suggested confirmation of this 17.4 kPa/m FEP gradient.

A 4 MPa safety margin is still being carried for the initial period of injection to allow for the reduction of FEP gradient that could be the result of reservoir cooling due to injecting cold CO2. Thermal wellbore and reservoir modeling suggest that a cool area with a radius up to 350m could develop over a period of 25 years by injecting CO2 with a flowing bottom hole temperature of approximately 20 degC. Based on internal research at BTC, and given the

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uncertainty in the thermal expansion and poro-elastic parameters the minimum reduction we would expect to see is about 1.4 MPa and the maximum would be about 7.9 MPa. The thermal expansion is still being measured on BCS core material and is expected to confirm where we are in this range and whether a 4 MPa is indeed an appropriate allowance. The MMV plan will also target the monitoring of fracture initiation through a standard micro seismic array as an objective for at least one deep observation well, this will be used to calibrate the potential for DAS microseismic in all wells (for more detail see Seal Integrity report [Ref. 07-3-ZG-7180-0012]). The following mitigations in place were added to the risk description:

1) A 14 MPa safety margin between BCS Fracture pressure and maximum injection pressure is applied through the following incremental constraints:

a. Reduce the maximum injection pressure to 10% below the fracture extension pressure as per D51 regulatory requirement (~4 MPa).

b. Further reduce the maximum injection pressure by 16% based on the lower LMS Fracture Extension Pressure rather than BCS FEP (~6 MPa).

c. Furthermore, an additional 4 MPa safety margin will be applied to 90% of LMS FEP to allow for a safety margin against thermal stress

2) The presence of three extensive geological seals, (MCS, Lower Lotsberg, Upper Lotsberg) with vertical separation that will dissipate pressure and temperature effects.

3) The Lotsberg salts (Upper and Lower) are expected to be ductile so they are likely to anneal and arrest fracture propagation.

4) The presence of a highly laminated LMS between BCS and MCS is expected to arrest vertical fracture growth, as weak interfaces are likely to slip and arrest vertical fracture propagation.

5) The stress contrast between MCS and BCS is 1.5. Anything over 1.1 is expected to be an effective barrier to fracture propagation.

6) The compressor discharge pressure is limited to 14.5 MPa (900# pipe class) ~32 MPA max FBHP

7) Down hole gauges will be deployed to ensure that wells stay within pressure constraints using well head chokes to control pressure.

8) Under normal operating conditions injection will be distributed over n wells. The system will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells.

Risk 4168: Migration along a stratigraphic pathway This risk has been substantially reduced by proving the continuity of all three seals of the BCS storage complex through 3D and 2D seismic and a central well penetration in the AOI (Radway 8-19).

The following mitigations in place were added to the risk description: 1) 2D seismic covers the entire AOI with a spacing of 2-3km and shows continuity of seals 2) Every well in the AOI has confirmed the presence of all three seals. 3) Lotsberg seal thickness LL 9-36m and UL 53-91m suggest low likelihood of local gaps

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4) Tortuosity of leak path as seal breaches are unlikely to align 5) Buffering effects of long leak path 6) BCS and WPGS water chemistry differences suggest long term isolation of these aquifers

from each other 7) The cleanest shales are at the bottom of the MCS section and will erode last by the

Devonian unconformity towards the NE Risk 4167: Acidic fluids erode geological seals (Geochemical degradation) Shell has taken the opportunity to further understand the geomechanical and reservoir properties of the Ultimate seal – The Upper Lotsberg Salt. Shell was granted permission from ATCO Gas and Pipelines LTD. in March 2011, to take 9 plugs from their Upper Lotsberg core located in 100-07-34-055-21W400 (located on the southern border of the AOI) for SCAL analysis. A SCAL Program comprising the following elements in ongoing:

1) High Resolution photos of the core and the salt plugs. Including proper depth marking. 2) Thin section and petrography to determine the salt composition. 3) Salt porosity & permeability measurements to prove that the Lotsberg Salt is a competent

seal. 4) Salt creep test for geomechanics (This is now unlikely due damage during cutting of the

core plugs).

In addition, Shell will take a representative core of the Upper Lotsberg Salt in the Second CO2 injection well (100-07-11-059-20W400) to confirm that the samples used for SCAL were reasonable analogues (for more detail see Seal Integrity report [Ref. 07-3-ZG-7180-0012]). The following mitigations in place were added to the risk description:

1) The secondary and ultimate seals, the Upper and Lower Lotsberg salts respecitively, are comprised of greater than 90% pure halite. Salt is not known to be affected by the acidity of the formation brine. The BCS brine is already salt saturated and unable to dissolve significant volumes of salt.

2) Thickness of seals and baffles that need to be eroded are 350m from top perfs to top ultimate seal

3) Buffering materials (mostly clay minerals) in the seals and baffles between the salt seals and the top perfs are abundant. CO2 leaking into the seals/baffles will lose moisture and acidity

4) Seal integrity relies on stresses and may not be affected by seal embrittlement (need to check effect of salt exposure to CO2 with GuoXiang Zhang)

Risk 4520: Migration along Legacy wells Westcoast et al Newbrook 100-09-31-062-19W40 (Westcoast 9-31), was reclassified as a legacy well that penetrates through all three major seals of the BCS storage complex, since the issuing of the Rev.01 version of this document. The well had previously been identified but was not recognized initially to penetrate the seals of the BCS storage complex. This triggered a

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second independent search of publicly available databases to ensure no other legacy wells penetrating the BCS storage complex had been missed. The initial search was using Accumap, a system provided with data by IHS, the second independent search carried out was on Geovista, a system that acquire its data from Divestco. No additional wells were found and the Carbon Sequestration Lease, approved on 27 May 2011, now contains four third-party legacy wells within its boundaries: (Egremont 6-36, Eastgate 1-34, Darling No.1 and Westcoast 9-31). The PLC Redwater 7-17 well, an abandoned salt cavern, is no longer part of the AOI as the 24 most southwesterly sections (Sections 1-24 in Township 56-21W4) submitted in the Sequestration Lease Application were excluded by the ERCB in the approved Carbon Sequestration Lease Tenure. Abandonment reports are available for all third-party legacy wells in the AOI that penetrate one or more of the Major regional seals in the BCS storage complex, as well as for the following third party legacy well penetrations in the vicinity of the AOI boundary that penetrate through one or more seals in the BCS storage complex:

• Imperial Baysel Riverdale • Imperial Clyde • Imperial Gibbons • Imperial PLC Redwater • Four salt cavern wells: Provident 12, 14, 15 and 16

Theoretical threshold pressures were calculated for each of the third-party Legacy wells that drill through the MCS seal in the AOI to see at what BCS pressure there could be a risk of lifting BCS brine into the base of the groundwater protection zone (BGWP).

Table 1 Pressure Increase Required to Lift BCS Brine to BGWP

Well Name

Surface elevation (mBSL)

BGP depth

(mBSL)

BGP depth

(mBGL)

Hydrostatic pressure at BGP

(kPaa)

Extrapolated BCS pressure at BGP

(kPaa) Delta P (kPa)

Imperial Eastgate No. 1-34 -641.3 -401 240 2,456 -1,356 3,452

Imperial Egremont W 6-36 -627.9 -408 220 2,259 -1,435 3,334

Imperial Darling No. 1 -704.4 -469 235 2,406 -2,168 4,201

Westcoast 9-31 -699 -471 228 2,338 -1,808 4,146

NOTE:

mBSL – metres below sea level

mBGL – metres below ground level

A conceptual leak path model was built for Imperial Darling No. 1 as this well has the shallowest abandonment plug and is the only legacy well in the AOI that does not have cement across the seals of the BCS storage complex. This type of modeling confirms findings from hydrogeological contamination modeling in the groundwater, suggesting the radius of contamination with saline brine is limited to <100m. The pressure signal, in the event of brine migration through the abandoned well bore, responds faster and has a larger radius of penetration, easily exceeding 500m (assuming reservoir continuity). Both the Winnipegosis and

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the Cooking Lake appear to be suitable candidates for pressure monitoring if reservoir continuity for these reservoirs can be confirmed.

There is potential that brine contamination would never reach the groundwater due to the Cooking Lake acting as a pressure sink as it has the lowest formation pressure gradient in the entire sequence from BCS to surface.

The following mitigations in place were added to the risk description: Site selection has minimized this risk:

1) through offset to legacy wells (21 km Radway to Egremont) . 2) selection of AOI with few BCS penetrations

The following barriers are in place in the known legacy wells: 1) multiple cement plugs of significant length at various intervals 2) open hole abandonment across the salt allows for the opportunity for hole closure by

salt creep 3) impermeable plugs may have formed through settlement of solids out of drilling mud

in well bore An adaptive MMV plan may provide additional options for early warning through pressure monitoring (e.g. InSAR, Redwater 3-4, MMV wells near higher risk legacy well locations, etc). The possibility of new 3rd party wells is mitigated through a drilling ban into the BCS storage complex within the AOI and a Carbon Sequestration Lease for the project was received on 27 May 2011 granting Shell the subsurface rights from the top of the Prairie Evaporite to the Basement. A request was issued separately to stop the creation of new Lotsberg salt caverns within the AOI.

Well Risks: The well risks were not reviewed in the integrated subsurface team since the wells bow-tie was restructured in September 2010. However, the actions supporting mitigations of well related containment risks have been progressed and the well risks were reviewed and found to be still up to date by the wells coordinator. The following well risks have seen limited change since the Rev.01 report: Risk 4132: Compromised Casing Integrity Risk 4133: Compromised Cement Integrity Risk 4159: Compromised Completion Integrity Risk 4523: Well intervention Risk 4522: Compromised Abandonment Risk 4149: Observation wells in the BCS may threaten Containment The risk name was shortened from “Requirement for MMV wells in the BCS (eg. ineffective non-invasive MMV) threatens Containment” to “Observation wells in the BCS may threaten Containment” and the risk description was updated to focus on the containment risks rather than the risks of failing MMV technologies or not being able to track CO2 which are captured in our Conformance risk category.

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It is still not clear whether the regulator will accept an MMV plan without BCS observation wells and not all non-invasive monitoring techniques have proven feasibility. However, with the exception of converting the existing Redwater 3-4 penetration into a BCS pressure observation well, the Project has no plans to drill observation wells into the BCS for direct CO2 monitoring or otherwise. The following mitigations in place were added to the risk description:

1) The initial base case MMV Plan does not include BCS observation wells 2) The use of Redwater 3-4 as a BCS pressure observation well 3) Well sparing philosophy allows for regular sequence of annual fall-off tests in injection

wells (to be included in the operating guidelines) 4) All BCS injectors will be used as BCS observation wells during start-up & closure periods 5) InSAR, VSP and seismic are part of the initial base case MMV Plan 6) InSAR will be calibrated to BCS pressure measurements from the Redwater 3-4 BCS

observation well The pre-mitigation probability of Loss of Containment in an MMV well was aligned with the probability of Loss of Containment in the Injection wells and reduced from Medium to Low, in line with feedback received from the external panel. Risk 4524: Third Party Induced Migration The risk description was clarified with some minor edits, separating the drilling of new wells and pressurizing of the BCS as separate causes that could lead in loss of containment. The first one has now been minimized as the Carbon Sequestration Lease was granted to Quest on 27 May 2011 and prohibits the drilling by third-parties below the Prairie Evaporite within the AOI. The second cause (pressurization resulting in increased legacy well risk) is also much reduced through the size of the approved Carbon Sequestration Lease AOI providing a minimum 25km offset from the development area to the AOI boundary.

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6. All Containment Risks in Easyrisk and Tesla Databases

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Risk 4339: Timely Demonstration of Storage Feasibility This risk was created as a roll-up of all technical containment risks to ensure adequate visibility of these risks at project level and to support the need for early and adequate appraisal. This risk does not represent any technical failure mechanism that could lead to loss of containment but is used as a tool to communicate containment risk in general to decision makers.

ID R-4339

Name QUEST: Timely Demonstration of Storage Feasibility

Description CAUSE: Fast track appraisal & subsurface studies, early definition CCS project description with immature subsurface understanding RISK EVENT: Unable to demonstrate storage feasibility (Containment, Injectivity & Capacity) internally or, to Regulatory board and address Government and public concerns. Inappropriate porespace and injection site selection. CONSEQUENCE: Inability to convince stakeholders of the long-term performance of the storage system could result in the following consequences: 1. Inaccurate media reports or misinterpreted information 2. Delays in; i) Regulatory approval, ii) FID and iii) achieving sustained injection capacity 3. Severe public opposition, 4. Government refusal to accept long term liability of CO2 at project completion if containment can not be demonstrated (also captured in R4342 "Inability to Demsontrate Conformance"), 5. Project costs increase as alternate storage site is selected post injection.

Notes 30 May '11 (HdG): Pre-mitigation probability of this risk is dropped from Hi to Lo for the following reasons: 1) Pore space tenure for the project was received on 27 May 2011 2) Landowners have been consulted wrt to all 8 proposed D65 injection well locations and most of the Pipeline ROW. Landowner consent has been gained for the original 5 wells and discussions are ongoing for the 3 additional wells 3) Outcome of 2010 appraisal activities (3D seismic, Radway 8-19) providing strong evidence for containment (absence of faults intersecting BCS, continuity of seals, consistency in frac gradients) and encouraging injectivity and storage capacity results (Radway 8-19 injectivity of 380 m3/d/MPa sufficient to meet Project requirements, average porosity up from 15 to 16%, no indications of compartmentalisation from seismic) 4) Positive outcome of the DNV facilitated Independent Project Review (Oct'10), VAR3 (Dec'10), JV partner review (Feb'11), on track for preparations for ITR4 in June '11 5) Good progression on regulatory approval process (Applications submitted on 30 Nov 2010, draft SIR's received and preparation of responses nearing completion, in time for Regulatory hearing in Q4 2011) 18 April '11 (HdG): Planned finish date moved from end Mar '11 to end Mar '12 (FID) after discussion with SVC and SMcF Alternative risk description: Stakeholders of the project (external) expect to see demonstration of feasibility (C, I, C) before project is approved and funded => technical and/ or political difficulties to demo containment => additional activities required that impact pre-FID schedule. CO2 containment is a key public concern and, ultimately, regulatory requirement and corporate liability. Whilst much debate focuses on storage performance in view of the time dimensions (1000 years and more), all components of the CCS system must provide containment during their functional life.

Mitigations Assumed or In Place

1. Continued technical appraisal pre-FID to validate containment. 2. Identify critical stakeholders and develop stakeholder engagement strategies. 3. Get early input from external reviewers on our assessment of technical risks (DNV IPR) and non-technical risks (Blue Rubicon) and embed feedback into Project Execution Plan. 4. Acceleration of MMV base-lining and drilling of next two injection wells into 2012

Owner Crouch, Syrie

(Sub)Project Containment (Quest)

Status In Progress

Review Date 2011-05-30

Planned Finish 2012-03-30

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Before actions Probability: Low Timely completion of 2010 appraisal activities (3D

surface seismic, Radway 8-19 drilling and testing) has confirmed or reduced the range of uncertainty in reservoir properties and improved the base case reservoir description

Cost/Benefit [C&B] Very High Cost impact could be very high if the selected site proves to be inappropriate for CO2 sequestration. Potentially CDN100 mln appraisal cost of a new site.

HSSE [HSSE] No impact Reputation [REP] High Inability to demonstrate containment to the

appropriate regulatory bodies and stakeholders could have considerable (national) impact on Shell's reputation as a CCS Operator.

System Capacity (QUEST) No impact Schedule to FID (QUEST) Very High The schedule impact could be very high (> 5

months) if appraisal shows that the selected site is inappropriate for CO2 sequestration. Selection and appraisal of a new sequestration site would take in excess of 1 year.

Schedule FID to SO (QUEST) No impact, risk has been eliminated post FID once regulatory approval has been received.

After actions Probability: Very Low The appraisal campaign should confirm suitability of selected site for CO2 sequestration (absence of large faults, continuity of seals, confirmation of reservoir quality and injectivity). Some uncertainty remains on reliability of performance predictions.

Cost/Benefit [C&B] Low Pore space selection is now confirmed, scope for cost overruns as result of appraisal surprises is now limited to one appraisal well or several well tests CDN 5-10 mln.

HSSE [HSSE] No impact Reputation [REP] High Inability to demonstrate containment to the

appropriate regulatory bodies and stakeholders could have considerable (national) impact on Shell's reputation as a CCS Operator.

System Capacity (QUEST) No impact Schedule to FID (QUEST) Medium If data acquisition campaign is successful and the

D65 submission complete then minimal iterations with the regulator should have to occur and approval process should not be delayed by more than 3 months.

Schedule FID to SO (QUEST) No impact, risk has been eliminated post FID once regulatory approval has been received.

Associated actions: ID Name Status Owner Start Date Planned Finish

A-2703 QUEST: Capture learnings from partner projects. In Progress Crouch, Syrie

2010-12-01 2011-08-31

A-2952 QUEST: Fast Track Technical Appraisal & Study work

Closed Crouch, Syrie

2010-01-01 2011-01-25

A-2956 QUEST: Apply CCS Industry and Owner's Learnings to Quest

In Progress McFadden, Sean

2010-05-17 2012-08-31

A-3099 QUEST: FA timeline conditional to 3rd well results

Closed Heckel, Len 2010-06-01 2010-06-30

A-3103 QUEST: Engage independent external CSS experts to support public acceptance of project

In Progress McFadden, Sean

2010-08-15 2012-03-30

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7. FAULTS / FRACTURING – EasyRisk subgroup



4177: Injection induced stress reactivates a fault (L/VH T VL/VH) 4154: Injection induced stress fractures geological seals (L/H T VL/H) 4157: Migration along a fault pathway (L/H T VL/H)

Alignment of EasyRisk with TESLA Hypotheses on Faults and Fracturing:

R-4157 Migration along a fault pathway - LOCATIONS of all significant faults & fractures in the containment complex are known and mapped. - REGIONAL stress measurements are available, are of sufficient quality and are supportive of containment. - CURRENT DISTRIBUTION OF FLUIDS in the play support fault sealing in the containment complex - including an assessment of natural seismicity.

R-4177 Injection induced stress reactivates a fault - FAULT REACTIVATION pressures are calculated and with choice and control of BHP are supportive of containment

- FAULT VALVING pressures are calculated and with choice and control of BHP are supportive of containment R-4154 Injection induced stress fractures geological seals - FRACTURE PROPAGATION pressures are measured and modeling and choice of BHP supports containment.

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Risk 4157: Migration along a fault pathway ID R-4157

Name QUEST: Migration along a fault pathway

Description CAUSE: Existence of permeable fault systems that act as conduits to shallow strata. RISK EVENT: Pressure/CO2 migration through primary (MCS) and ultimate seals (Lotsberg salts) resulting in loss of containment. CONSEQUENCE: More extensive MMV measures may be required, injection may need to be cut back or redistributed over potentially additional wells and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and national reputation loss.

Notes 4/Mar/'11 (HdG) mitigations assumed in place discussed in weekly risk meeting 8/Jul/'10 (HdG) actions/probability and consequences reviewed in weekly risk review 9/Mar/'10 (HdG) Cleaned up risk description, aligned with risk in subsurface bow-tie


1) Faults are picked on the Pre-Cambrian granite seismic interval. 2) Evidence of no faults with throws greater than 15 m crossing the seal complex from 2D and 3D seismic covering the full AOI. The 2D seismic spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic is available over the central development area. 3) There is a period of ~1.5 billion years between the granite and the deposition of the BCS. Therefore it is unlikely that any Pre-Cambrian faults were active in the BCS time of deposition. 4) 3D seismic will help place injection wells away from features that may represent faults at the Precambrian basement level. 5) The Lotsberg salts are ductile and expected to creep and reseal any unexpected small faults.

Owner Crouch, Syrie


Status In Progress



Before actions Probability: Low No faults have been identified that run across the

full height of the seals. Lotsberg salts are ductile and would seal any small faults if present. The confining stress at target depth causes cataclaysis that would destroy perm along subseismic faults.

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Cost/Benefit [C&B] High Redistribution of CO2 injection (incl. possible new wells), increased MMV around possible leak paths and potential clean up of contaminated aquifers could cost between CDN 25-50 mln.

HSSE [HSSE] High Environmental impact could be high, health and safety effect could be high too as the leak is likely to contain CO2 (migration along faults is likely to occur where pressure is high due to presence of CO2).

Reputation [REP] High Loss of containment through known (or unmapped) faults could have considerable (regional) impact on Shell's reputation as a prudent Operator

System Capacity (QUEST) High In case of a permeable fault across the seals, system capacity would likely have to be reduced significantly for at least a year until adequate alternatives have been identified and agreed by regulators.

Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact, this will only manifest itself after a

period of sustained injection, if at all.

After actions Probability: Very Low MMV will help monitor CO2 and brine movement so that injection can be redistributed away from fault prone areas, if any.

Cost/Benefit [C&B] High MMV is expected to lower the consequence through early detection of migration beyond ultimate seal. However, remediation required after detection is expected to keep the cost consequence high.


Reputation [REP] High Loss of containment through known (or unmapped) faults could have considerable (national) impact on Shell's reputation as a prudent Operator

System Capacity (QUEST) High Current mitigations do not address consequences Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact, this will only manifest itself after a


Action Party Sequestration Team Prefix - risk number

Associated actions: ID Name Status Owner Start Date Planned

Finish

A-2624 QUEST: Acquire additional seismic in the commercial area.

Closed Bourne, Stephen

2009-12-01 2010-12-24

A-2628 QUEST: Map faults using seismic In Progress Bourne, Stephen

2010-01-01 2011-06-30

A-2629 QUEST: Develop adaptive MMV plan In Progress Bourne, Stephen

2010-01-01 2011-07-29

A-2682 QUEST: Evaluate Seal strength/fracture pressure

In Progress Winkler, Mario

2010-01-01 2011-05-20

A-2691 QUEST: 2D Reprocessing (PSTM) Closed Bourne, Stephen

2009-09-01 2010-04-01

A-2696 QUEST: Regional evaluation of in-situ stresses

In Progress Smith, Mauri

2010-03-01 2011-07-29

A-2704 QUEST: Conduct and Evaluate Well Test on Radway 8-19

Proposed Closed

De Groot, Hein

2010-09-01 2011-06-02

A-3140 QUEST: Water Chemistry and Pressure study to support containment

In Progress Pierpont, Robert

2010-01-01 2011-06-30

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TESLA - LOCATIONS of all significant faults & fractures in the containment complex are known and mapped

Root Hypothesis -Impact Rank


Nov 2008 0.3

March 2009 0.3 0.2

Sept 2009 0.3 0.2

Sept 2010 0.7

Evidence FOR 1) Evidence of no faults with throws greater than 15 m crossing the seal complex

from 2D and 3D seismic covering the full AOI. The 2D seismic spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic is available over the central development area.



4) The Lotsberg salts are ductile and expected to creep and reseal any unexpected small faults. During drilling Radway 8-19 well tight spots over the Lotsberg salts were encountered.

5) No evidence of natural fractures present in the LMS or BCS from FMI logs. Evidence AGAINST

None Uncertainties:

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TESLA - REGIONAL stress measurements are available, are of sufficient quality and are supportive of containment



Nov 2008 0.1

March 2009 0.1

Sept. 2009 0.3

Sept. 2010 0.4

NOTE: Suggest to edit Hypothesis from regional to in-situ

Evidence FOR 1) The interpreted difference between max. and min. compressive stress from well

logs is small (min. horizontal compressive stress is 0.8-0.9 of the vertical stress) and calibrated against minifrac results. This is consistent with regional stress data that indicates little in-situ shear stress (world stress map).

Evidence AGAINST

None Uncertainties:

1) Expect geological heterogeneity, concentrate stress, diminish strength (in-situ stress data available but not sufficiently well sampled)

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TESLA - CURRENT DISTRIBUTION OF FLUIDS in the play support fault sealing in the containment complex - including an assessment of natural seismicity



Nov 2008 0.6

March 2009 0.6

Sept. 2009 0.6

Sept. 2010 0.7

Mar. 2011 0.7

NOTE: TESLA branch to be moved out of Faults &Fractures as isolated branch

Evidence FOR 1) Differences in the chemical signature (e.g. Halogen ratios) between the

Winnipegosis and BCS support hydraulic isolation between these intervals. The BCS fluids are dominated by NaCl dissolution brines (high Cl/Br ratios) whereas the WPGS is dominated by evaporitic brine (distinctly lower Cl/Br ratios). In house analysis of public data is consistent with external publications.

2) MDT data from Radway 8-19 indicates that the Winnipegosis has a pressure that is 326 kPa higher than the extrapolated BCS in-situ pressure gradient. This supports hydraulic isolation between the BCS and the WPGS.

3) Flow mechanisms and direction vary between shallow formations (Upper Devonian to surface) and WPGS/Cambrian. WPGS&BCS are topographic drive associated with upper Laromide orogeny (ENE) while all aquifers above the Prairie Evap. appear to flow via gravity (WSW). Opposite flow directions point towards the absence of a connection of the WPGS and BCS from shallower aquifers.

a. The dynamic pressure gradient on a regional scale in the Upper Devonian is lower (subhydrostatic) than seen in the WPGS and BCS

b. Differences in the chemical signature (e.g. Halogen ratios) between the Winnipegosis and the Cooking Lake and above support hydraulic isolation between these intervals.

Evidence AGAINST

None Uncertainties:

1) Limited Fluid Chemistry data for the WPGS in the AOIs and quality of fluid sample data in the public database.

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Risk 4177: Injection induced stress reactivates a fault ID R-4177

Name QUEST: Injection induced stress reactivates a fault

Description CAUSE: Existing faults are reactivated as reservoir pressure or thermal stresses may exceed fault strength RISK EVENT: Pressure/CO2 migration through primary (MCS) and ultimate seals (Lotsberg salts) resulting in loss of containment. CONSEQUENCE: More extensive MMV measures may be required, injection may need to be cut back or redistributed over potentially additional wells and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and national reputation loss.

Notes 4/Mar/'11 (HdG) mitigations assumed in place discussed in weekly risk meeting July 2010 comment on surface deformation moved to R-4164 on surface heave 9/Mar/'10 (HdG) Cleaned up risk description, aligned with risk in subsurface bow-tie.


1) The Quest AOI is not an area of active natural seismicity. There is a regional seismic monitoring network in place for more than 80 years with a capability of detecting a magnitude 3 event within our AOI. None were detected over this period (Reference: AGS Tectonic activity map for Alberta). 2) No faults offsetting the MCS or Lotsberg seals were mapped in the AOI using 2D seismic that spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic over the development area. 3) 3D seismic will help place injection wells away from features that may represent faults at the Precambrian basement level. 4) The Lotsberg salts are ductile and expected to creep and reseal any unexpected small faults. 5) Compressor discharge pressure is limited to 14.5 MPa (900# pipe class) 6) Down hole gauges will be deployed to ensure that wells stay within pressure constraints using well head chokes to control pressure. 7) Under normal operating conditions injection will be distributed over n wells. The system will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells. 8) Downhole microseismic monitoring will detect any fault reactivation within 600m of the injector to motivate a reduction in injection pressure (to be included in the final MMV plan).

Owner Crouch, Syrie


Status In Progress



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Before actions Probability: Low The three seals of the storage complex provide redundancy in case the first seal (MCS) fails. No faults intersecting the three seals can be seen on seismic. The AOI is in a tectonically quiet region.

Cost/Benefit [C&B] Very High If brine or CO2 migrate along reactivated faults across three seals it is likely that the entire pore space AOI is sterilised for further CCS and the scheme will need to be relocated or terminated.


Reputation [REP] High Loss of containment through reactivated faults could have considerable (national) impact on Shell's reputation as a prudent Operator.

System Capacity (QUEST) High In case of fault leakpath across the seals, system capacity would have to be reduced significantly for at least a year until remediation has been identified and agreed by regulators. Fault reactivation will not occur until some time into 10yr contract.

Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact

After actions Probability: Very Low Further geomechanical studies and implementation of pressure control and risk based MMV plan will reduce the likelihood of this event further.

Cost/Benefit [C&B] Very High If brine or CO2 migrate along reactivated faults across three seals it is likely that the entire pore space AOI is sterilised for further CCS and the scheme will need to be relocated or terminated.


Reputation [REP] High Loss of containment through reactivated faults could have considerable (national) impact on Shell's reputation as a prudent Operator.

System Capacity (QUEST) High Current mitigations do not address consequences Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact


Finish

A-2599 QUEST: Review pressure monitoring and control requirements

In Progress Hugonet, Vincent

2010-01-01 2011-07-29

A-2623 QUEST: Drill and test a third appraisal well within the commercial area.


2010-01-01 2010-12-04



2009-12-01 2010-12-24

A-2628 QUEST: Map faults using seismic In Progress Bourne, Stephen

2010-01-01 2011-06-30


2010-01-01 2011-07-29

A-2632 QUEST: Define well based monitoring (MMV) requirements


2010-04-01 2011-06-30



2010-01-01 2011-05-20

A-2691 QUEST: 2D Reprocessing (PSTM) Closed Bourne, Stephen

2009-09-01 2010-04-01



2010-03-01 2011-07-29

A-2697 QUEST: Investigate/understand available data on pre-existing Salt Caverns

Closed Smith, Mauri

2010-04-30 2011-05-20

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TESLA - FAULT REACTIVATION pressures are calculated and with choice and control of BHP are supportive of containment



Nov 2008 0.3

March 2009 0.3

Sept. 2009 0.3

Sept. 2010 0.6

Evidence FOR 1) The Quest AOI is not an area of active natural seismicity. There is a regional seismic

monitoring network in place for more than 80 years with a capability of detecting a magnitude 3 event within our AOI. None were detected over this period (Reference: AGS Tectonic activity map for Alberta).

2) No faults offsetting the MCS or Lotsberg seals were mapped in the AOI using 2D seismic that spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic over the development area.




6) Compressor discharge pressure is limited to 14.5 MPa (900# pipe class) 7) Down hole gauges will be deployed to ensure that wells stay within pressure constraints

using well head chokes to control pressure. 8) Under normal operating conditions injection will be distributed over n wells. The system

will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells.

9) Downhole microseismic monitoring will detect any fault reactivation within 600m of the injector to motivate a reduction in injection pressure (to be included in the final MMV plan).

Evidence AGAINST None

Uncertainties: 1) Presence of subseismic faults 2) Intrinsic uncertainties remain on fault re-activation pressures

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TESLA - FAULT VALVING pressures are calculated and with choice and control of BHP are supportive of containment



Nov 2008 0.3

March 2009 0.3

Sept. 2009 0.3

Sept. 2010 0.6

Note: candidate for simplification of TESLA tree, to be amalgamated with fault reactivation ?

Evidence FOR 1) No faults seen on seismic that cut through seals. 2) Tectonically very quiet 3) The Quest AOI is not an area of active natural seismicity. 4) No faults offsetting the MCS or Lotsberg seals were mapped in the AOI using 2D

seismic that spans the entire AOI with ~3 km spacing and 415 km2 of 3D seismic over the development area.



7) Compressor discharge pressure is limited to 14.5 MPa (900# pipe class) 8) Down hole gauges will be deployed to ensure that wells stay within pressure

constraints using well head chokes to control pressure. 9) Under normal operating conditions injection will be distributed over n wells. The

system will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells.


Uncertainties:

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Risk 4154: Injection induced stress fractures geological seals ID R-4154

Name QUEST: Injection induced stress fractures geological seals

Description CAUSE: Injection induced hydraulic and thermal stress (cold CO2) exceeds fracture stress of the geological seals, due to operational error or uncertainties on actual fracture pressure for MCS and lower and Upper Lotsberg. RISK EVENT: Pressure/CO2 migration through primary (MCS) and ultimate seals (Lotsberg salts) resulting in loss of containment. CONSEQUENCE: More extensive MMV measures may be required, injection may need to be cut back or redistributed over potentially additional wells and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and national reputation loss.

Notes 4/Mar/'11 (HdG) Mitigations discussed in weekly risk discussion, pre-mitigation probability rephrased to address external panel feedback but left at Low 25/Mar/'10 (HdG) Thermal fracturing now included. 9/Mar/'10 (HdG) Cleaned up risk description, aligned with risk in subsurface bow-tie.


1) A 14 MPa safety margin between BCS Fracture pressure and maximum injection pressure is applied through the following incremental constraints: 1a. Reduce the maximum injection pressure to 10% below the fracture extension pressure as per D51 regulatory requirement (~4 MPa). 1b. Further reduce the maximum injection pressure by 16% based on the lower LMS Fracture Extension Pressure rather than BCS FEP (~6 MPa). 1c. Furthermore, an additional 4 MPa safety margin will be applied to 90% of LMS FEP to allow for a safety margin against thermal stress 2) The presence of three extensive geological seals, (MCS, Lower Lotsberg, Upper Lotsberg) with vertical separation that will dissipate pressure and temperature effects. 3) The Lotsberg salts (Upper and Lower) are expected to be ductile so they are likely to anneal and arrest fracture propagation. 4) The presence of a highly laminated LMS between BCS and MCS is expected to arrest vertical fracture growth, as weak interfaces are likely to slip and arrest vertical fracture propagation. 5) The stress contrast between MCS and BCS is 1.5. Anything over 1.1 is expected to be an effective barrier to fracture propagation. 6) The compressor discharge pressure is limited to 14.5 MPa (900# pipe class) ~32 MPA max FBHP 7) Down hole gauges will be deployed to ensure that wells stay within pressure constraints using well head chokes to control pressure. 8) Under normal operating conditions injection will be distributed over n wells. The system will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells.

Owner Crouch, Syrie


Status In Progress



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Before actions Probability: Low Any unexpected fracturing within the BCS storage complex is unlikely to result in loss of containment, due to the presence of multiple geological barriers and a conservative injection pressure constraint.


HSSE [HSSE] High Environmental impact could be high, health and safety effect could be high too as the leak is likely to contain CO2 (fractures likely to occur where pressure is high due to presence of CO2).

Reputation [REP] High Loss of containment due to Operator error (exceed frac pressure constraint) would have serious (National) impact on Shell's reputation as a prudent Operator

System Capacity (QUEST) Medium In case of a fractured seal leak path system capacity would likely have to be reduced significantly for some time but reduction of pressures should close fractures and allow for continuation of redistributed injection.

Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact, this will only manifest itself after a


After actions Probability: Very Low Pressure control, MMV plan, operating guidelines and further geomechanical studies to ensure safe operating envelope will reduce likelihood to very low


HSSE [HSSE] High Environmental impact could be high, health and safety effect could be high too as the leak is likely to contain CO2 (fractures likely to occur where pressure is high due to presence of CO2).

Reputation [REP] High Loss of containment due to Operator error (exceed frac pressure constraint) would have serious (National) impact on Shell's reputation as a prudent Operator

System Capacity (QUEST) Medium Current mitigations do not address consequences Schedule to FID (QUEST) no impact Schedule FID to SO (QUEST) no impact


Finish

A-2599 QUEST: Review pressure monitoring and control requirements


2010-01-01 2011-07-29

A-2620 QUEST: Evaluate possible temperature change that wellbore could experience

In Progress Clark, Christa

2010-04-01 2011-06-30


2010-01-01 2011-07-29



2010-04-01 2011-06-30



2010-01-01 2011-05-20



2010-03-01 2011-07-29

A-2697 QUEST: Investigate/understand available data on pre-existing Salt Caverns

Closed Smith, Mauri

2010-04-30 2011-05-20

A-2716 QUEST: Dynamic Fracture Modeling In Progress Clark, Christa

2010-01-01 2011-06-30

A-3274 QUEST: Evaluate geomechanical properties of MCS cores


2010-08-23 2011-07-29

A-3591 QUEST: Quantify the radius of cooling around an injector

In Progress Huang, Hongmei

2011-01-05 2011-06-30

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TESLA - FRACTURE PROPAGATION pressures are measured and modeling and choice of BHP supports containment Root Hypothesis -Impact Rank


Nov 2008 0.3

March 2009 0.6

Sept. 2009 0.6

June 2010 0.6

Mar 2011

0.8

Footnote: Radway 8-19 minifrac data and increased definition on MMV plan and inherent mitigations support moving the score to 0.8

Evidence FOR 1) A 14 MPa safety margin between BCS Fracture pressure and maximum injection

pressure is applied through the following incremental constraints: a. Reduce the maximum injection pressure to 10% below the fracture extension

pressure as per D51 regulatory requirement (~4 MPa). b. Further reduce the maximum injection pressure by 16% based on the lower

LMS Fracture Extension Pressure rather than BCS FEP (~6 MPa). c. Furthermore, an additional 4 MPa safety margin will be applied to 90% of

LMS FEP to allow for a safety margin against thermal stress 2) The presence of three extensive geological seals, (MCS, Lower Lotsberg, Upper

Lotsberg) with vertical separation that will dissipate pressure and temperature effects.

3) The Lotsberg salts (Upper and Lower) are expected to be ductile so they are likely to anneal and arrest fracture propagation.

4) The presence of a highly laminated LMS between BCS and MCS is expected to arrest vertical fracture growth, as weak interfaces are likely to slip and arrest vertical fracture propagation.

5) The stress contrast between MCS and BCS is 1.5. Anything over 1.1 is expected to be an effective barrier to fracture propagation.

6) The compressor discharge pressure is limited to 14.5 MPa (900# pipe class) ~32 MPA max FBHP

7) Down hole gauges will be deployed to ensure that wells stay within pressure constraints using well head chokes to control pressure.

8) Under normal operating conditions injection will be distributed over n wells. The system will be designed to stay below the maximum injection pressure constraint for n-1 wells, resulting in pressures below the maximum constraint for most of the time using n wells.

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Evidence CONSIDERED 1) The stiffness contrast (Young’s modulus) between the MCS and the BCS/LMS is just

under 3, which is likely to be insufficient to arrest vertical fracture propagation (required to be between 3 and 5).

2) The bulk shale at the base of the MCS appears to be brittle rather than ductile. However, the loss of containment risk is minimized by constraining BHP on the fracture propagation pressure that is based on in-situ stress and does not rely on additional tensile strength of the seal.

Uncertainties: 1) Thermal expansion coefficient is not known and when measured on a single core

plug may not be representative for entire AOI. Simple calculations suggest that fracture pressure may drop 1.4-7.9 MPa, depending on assumptions on thermal expansion coefficient.

2) Maxwell time constant for Lotsberg salts is unknown. 3) Increased Pore Pressure can impact fracture pressure but is not expected to be a

large effect (lateral gradients of pore volume changes are small).

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8. SEALS – EasyRisk subgroup



4168: Migration along stratigraphic pathway (L/H T VL/H)

Probability pre mitigation Very Low (0-5% occurs in almost no projects, extremely unlikely)

4167: Acidic Erosion of geological seals (VL/VH T VL/VH)

Alignment of EasyRisk with TESLA Hypotheses on Geological Seals:

R-4168 Migration along a stratigraphic pathway - PROVEN PRIMARY SEAL, the primary seal is proven (in a play sense) to hold pressures & fluids and this proof is representative of the CO2 area

- PROVEN ULTIMATE SEAL: Shallowest seal which defines the upper limit of the container complex R-4167 Acidic fluids erode geological seals (geochemical degradation) - REACTIVE FLUIDS; interaction between reactive fluids and cap-rock are understood and supportive of sustained sealing

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Risk 4168: Migration along a stratigraphic pathway ID R-4168

Name QUEST: Migration along a stratigraphic pathway

Description CAUSE: As a result of the MCS pinching out just beyond the Northeast edge of the AOI and possible existence of local gaps in the lower and upper Lotsberg salts, a stratigraphic pathway may exist for brine or CO2 migration out of the primary containment complex. RISK EVENT: Brine/CO2 migration around primary (MCS) and ultimate seals (Lotsberg salts) resulting in loss of containment. CONSEQUENCE: More extensive MMV measures may be required, injection may need to be cut back or redistributed over potentially additional wells and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and considerable reputation loss.

Notes 9/Mar/'10 (HdG) Cleaned up risk description, aligned with risk in subsurface bow-tie. Risks around the performance of the Upper Lotsberg seal removed, they are captured through the failure mechanisms in the remaining risks (faults, fractures, wells and stratigraphic pinch-outs)


- 2D seismic covers the entire AOI with a spacing of 2-3km and shows continuity of seals - Every well in the AOI has penetrated all three seals.

- Lotsberg seal thickness LL 9-36m and UL 53-91m suggest low likelihood of local gaps - Tortuosity of leak path as seal breaches are unlikely to align - Buffering effects of long leak path - BCS and WPGS water chemistry differences (e.g. Halogen ratios) suggest long term isolation

of these aquifers from each other. The BCS fluids are dominated by NaCl dissolution brines (high Cl/Br ratios) whereas the WPGS is dominated by evaporitic brine (distinctly lower Cl/Br ratios). - The cleanest shales are at the bottom of the MCS section and will erode last by the Devonian

unconformity towards the NE

Owner Crouch, Syrie


Status In Progress

Review Date 2011-03-25 Planned Finish 2050-01-01

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Heavy Oil

Before actions Probability: Low Due to the length and tortuosity of a potential stratigraphic leak path, this event will be slow to occur (if at all) and the long leakpath will buffer any potential impacts as CO2 will get adsorbed along the way.


HSSE [HSSE] Low Environmental impact is expected to be low as the long tortuous flow path of a stratigraphic leak path will adsorb most CO2 and dissipate most of the pressure required to push heavy brine into shallow aquifers and/or to surface.

Reputation [REP] Medium Loss of containment through a long stratigraphic migration path could have medium (Provincial) impact on Shell's reputation. Lower impact is aligned with the lower environmental impact.

System Capacity (QUEST) Low Migration along a stratigr. leakpath is a slow process that is not expected to result in loss of containment in the 10 yr contractual period. However, once it occurs sequestration on this site may have to be terminated and relocated to a new site.


After actions Probability: Very Low Implementation of an adaptive MMV plan, mapping of seals over the AOI and leak path modelling will reduce the probability of this event further to very low.


HSSE [HSSE] Low Environmental impact is expected to be low as the long tortuous flow path of a stratigraphic leak path will adsorb most CO2 and dissipate most of the pressure required to push heavy brine into shallow aquifers and/or to surface.

Reputation [REP] Medium Loss of containment through a long stratigraphic migration path could have medium (Provincial) impact on Shell's reputation. Lower impact is aligned with the lower environmental impact.

System Capacity (QUEST) Low Migration along a stratigr. leakpath is a slow process that is not expected to result in loss of containment in the 10 yr contractual period. However, once it occurs sequestration on this site may have to be terminated and relocated to a new site.

Schedule to FID (QUEST) No Impact Schedule FID to SO (QUEST) No Impact

Associated actions: ID Name Status Owner Start Date Planned Finish

A-2595 QUEST: Build a framework geological model to base Prairie evaporites (Gen-3)

Closed Abernethy, Ross 2010-01-01 2010-11-23


Closed Crouch, Syrie 2010-01-01 2010-12-04


Closed Bourne, Stephen 2009-12-01 2010-12-24

A-2629 QUEST: Develop adaptive MMV plan In Progress Bourne, Stephen 2010-01-01 2011-07-29

A-2691 QUEST: 2D Reprocessing (PSTM) Closed Bourne, Stephen 2009-09-01 2010-04-01

A-2709 QUEST: Evaluation of Upper Marine Siltstones and Base Devonian Red Beds

In Progress Winkler, Mario 2009-02-01 2011-06-30

A-3140 QUEST: Water Chemistry and Pressure study to support containment

In Progress Pierpont, Robert 2010-01-01 2011-06-30

A-3742 QUEST: Build a framework leakpath model from Precambrian basement to base Lea Park

In Progress Smith, Mauri 2011-02-01 2011-06-30

A-3743 QUEST: Identify, select, core and analyse plugs from UL Salt

In Progress Smith, Mauri 2011-03-01 2011-07-29

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TESLA - PROVEN PRIMARY SEAL, the primary seal is proven (in a play sense) to hold pressures & fluids and this proof is representative of the CO2 area



Nov 2008 0.35

March 2009 0.35

Sept. 2009 0.35

Sept. 2010 0.6 0.1

Review Hypo and align with Easyrisk by removing fracturing already captured elsewhere

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Evidence FOR 1) The Middle Cambrian Shale, the primary seal is extensive covering the entire AOI

with a thickness ranging from 22-90m: a. 67m at Redwater location, 46m at Radway well. b. The MCS is now interpreted to be present in the Imperial Darling well

(22m) based on isochron data and tied to Canstrat data. 2) Mini Frac in LMS shows higher fracture closure pressure than in BCS. The

expectation is that the MCS since it is a clean shale will a have higher fracture closure pressure

3) The sonic and density logs indicate a minimum horizontal stress consistent with the BCS and LMS Mini frac results in the Scotford well and also supports a higher minimum horizontal stress in the MCS

4) The cleanest shales are at the bottom of the MCS section and will erode last by the Devonian unconformity towards the NE (Based on Scotford and Redwater wells). The clean shales at base MCS correlate well between the three Quest appraisal well locations.

5) Differences in the chemical signature (e.g. Halogen ratios) between the Winnipegosis and BCS support hydraulic isolation between these intervals. The BCS fluids are dominated by NaCl dissolution brines (high Cl/Br ratios) whereas the WPGS is dominated by evaporitic brine (distinctly lower Cl/Br ratios). In house analysis of public data is consistent with external publications.

Evidence AGAINST (Note both points reflect evidence outside the AOI) 1) NE outside of our AOI the MCS is eroded by the Devonian unconformity 2) MCS is thin (BCS absent) over Precambrian highs east of the AOI (well

Westminster hairy 2-13-55-13W4)

Uncertainties: 1) Petrophysical analysis has shown the MCS to contain silty streaks (with horizontal

perm.) at the top and centre parts. The seal property distribution of the MCS away from well control is unknown (e.g. distribution of silty streaks, both laterally and vertically within the BCS).

2) MCS thickness is potentially reduced over bald highs in the N of the AOI along the edge of the Rimbey block, as interpreted from 2D seismic

3) Radway 8-19 pressure in the WPGS is 300 kPa above the gradient in the BCS and it is not clear whether this is sufficient to support hydraulic isolation.

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TESLA - PROVEN ULTIMATE SEAL: Shallowest seal which defines the upper limit of the container complex



Nov 2008 0..7

March 2009 0.7

Sept. 2009 0.8

Sept. 2010 0.9

Evidence FOR 1) The ultimate seal is the Upper Lotsberg which is a clean Halite. 2) The Upper Lotsberg ranges in thickness from 53 - 91m over the AOI (84m @ the

Radway well) and extends more than 300 km up dip towards the NE. 3) 2D & 3D seismic supports continuity of the Upper Lotsberg and the absence of

large faults offsetting the ultimate seal. 4) The Lotsberg salts are a proven seal for natural gas storage. 5) Engineered Gas storage salt caverns do not penetrate the base of the ultimate seal

and are outside our AOI. 6) The Lotsberg salts thicken up dip in a NE direction. At least one penetration known

greater than 150m thick. : 8-10-62-11W4 7) Differences in the chemical signature (e.g. Halogen ratios) between the

Winnipegosis and BCS support hydraulic isolation between these intervals. The BCS fluids are dominated by NaCl dissolution brines (high Cl/Br ratios) whereas the WPGS is dominated by evaporitic brine (distinctly lower Cl/Br ratios). In house analysis of public data is consistent with external publications.

Evidence AGAINST

None Uncertainties:

1) 2-3 km spacing of 2D lines leaves some limited uncertainty about continuity between lines

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Risk 4167: Acidic fluids erode geological seals (Geochemical degradation) ID R-4167

Name QUEST: Acidic fluids erode geological seals (Geochemical degradation)

Description CAUSE: Gradual geochemical alteration of seals through acidification of in-situ formation waters or exposure to CO2 RISK EVENT: Brine/CO2 migration through primary (MCS) and ultimate seals (Lotsberg salts) resulting in loss of containment. CONSEQUENCE: More extensive MMV measures may be required, injection may need to be cut back or redistributed over potentially additional wells and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and national reputation loss.

Notes The primary seal contains small quantities of dolomite and K-feldspar. The dissolution of these minerals in a low pH CO2 environment could be offset by the creation of clays in this reaction, resulting in a net loss of permeability, although there is uncertainty about the timing of precipitation (10 days to 10 years).


- The secondary and ultimate seals are Lotsberg salts, comprised of clean halites. Salt is not known to be affected by the acidity of the formation brine. The BCS brine is already salt saturated and unable to dissolve significant volumes of salt.

- Thickness of seals and baffles that need to be eroded are 350m from top perfs to top ultimate seal

- Buffering materials (mostly clay minerals) in the seals and baffles between the salt seals and the top perfs are abundant. CO2 leaking into the seals/baffles will lose moisture and acidity.

- Seal integrity relies on stresses and may not be affected by seal embrittlement (need to check effect of salt exposure to CO2, GXZ)

Owner Crouch, Syrie


Status In Progress


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Before actions Probability: Very Low This is a very low likelihood event as the seals are not known to contain any elements that are subject to geochemical degradation and if so, there is over 100m of seal complex to act as buffer.

Cost/Benefit [C&B] Very High Erosion of seals due to geochemical degradation would be on a scale so large that remediation cost would easily exceed CDN 50 mln and Sequestration would have to be terminated or relocated to a new site.

HSSE [HSSE] High Erosion of seals due to geochemical degradation would be on a scale so large that it would present major HSE hazards and major environmental impact.

Reputation [REP] High Loss of containment at this scale would have major (National) impact on Shell's reputation as a prudent Operator.

System Capacity (QUEST) Very Low Degradation of seals is a very slow process that is not expected to result in a breach of the seals in the 10 yr contractual period. However, once it occurs it would be on a scale too large for remediation. Injection would be stopped on this site.

Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact, as would only become apparent

several years into operation

After actions Probability: Cost/Benefit [C&B] Erosion of seals due to geochemical degradation

would be on a scale so large that remediation cost would easily exceed CDN 50 mln and Sequestration would have to be terminated or relocated to a new site.

HSSE [HSSE] Erosion of seals due to geochemical degradation would be on a scale so large that it would present major HSE hazards and major environmental impact.

Reputation [REP] Loss of containment at this scale would have major (National) impact on Shell's reputation as a prudent Operator.

System Capacity (QUEST) Degradation of seals is a very slow process that is not expected to result in a breach of the seals in the 10 yr contractual period. However, once it occurs it would be on a scale too large for remediation. Injection would be stopped on this site.

Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact, as would only become apparent

several years into operation Action Party Sequestration Team

Prefix - risk number


Finish



2010-01-01 2010-12-04


2010-01-01 2011-07-29

A-2701 QUEST: Model Rock-Fluid interactions (BCS and seal Geochemistry/halite precipitation)


2010-01-01 2011-06-30

A-3109 QUEST: Tap into ongoing PT research initiatives on CO2 impacting seal integrity

In Progress Crouch, Syrie

2010-06-10 2011-08-26

A-3274 QUEST: Evaluate geomechanical properties of MCS cores


2010-08-23 2011-07-29

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TESLA - REACTIVE FLUIDS; interaction between reactive fluids and cap-rock are understood and supportive of sustained sealing



Nov. 2008

March 2009

Sept. 2009

Aug. 2010 0.8

Evidence FOR 1) Shale contains minute volumes of Dolomite and K Feldspar. Interaction with CO2

lowers pH to 4.0. Lower pH causes dissolution of Dolomite and K Feldspar leading to formation of clays. Dissolution enhances permeability, clay formation reduces permeability and dominates.

2) Total thickness of seal complex 350m from top perforation to top ultimate seal, creating a buffer to any reactive fluids.

3) There is no known history of salts affected by CO2 or acidic brines 4) Acid gas injection history in Alberta and CO2 injection (global EOR projects) have

not indicated issues with loss of seal integrity (review facts).

Evidence AGAINST Uncertainties:

1) Timescale of formation after dissolution of dolomites and K-feldspar. This could be somewhere between 10 days to 10 years.

2) Acidic fluids in the BCS are expected to be long-lived (1000+ years) due to lack of buffering reactions (mineral trapping) and the impact at this timescale is unknown.

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9. WELLS – EasyRisk subgroup


Probability pre mitigation Medium (20-50% occurs in projects, fairly likely)

4149 – Requirement for MMV wells in BCS threatens containment (M/H T VL/H)


4132 – Migration along a QUEST well - Compromised Casing Integrity (L/H T VL/H) 4133 – Migration along a QUEST well – Compromised Cement Integrity (L/H T VL/H) 4159 – Migration along a QUEST well - Compromised Completion or Wellhead Integrity (L/H T VL/H) 4520 – Migration along legacy wells (L/H T VL/H) 4523 – Migration along a QUEST well as a result of Well Intervention (L/H T VL/H) 4524 – Third-party induced CO2 migration (L/M T VL/M) 4522 – Migration along a QUEST well – Compromised Abandonment (L/L T VL/L) Alignment of EasyRisk with TESLA Hypotheses on Wells: R-4520 Migration along legacy wells - TESLA - EXISTENCE: all well locations are known - TESLA - STATUS/CONDITION: status of all known wells is known and supports non-leakage in the subsurface R-4132 Migration along a Quest well – Compromised Casing Integrity R-4133 Migration along a Quest well – Compromised Cement Integrity R-4159 Migration along a Quest well – Compromised Completion Integrity R-4522 Migration along a Quest well – Compromised Abandonment Integrity R-4523 Migration along a Quest well as a result of well intervention - TESLA - FUTURE well bores will avoid creating leak paths or minimise the risk thereof R-4149 Requirement for MMV wells in the BCS (eg. Ineffective non-invasive MMV) threatens containment R-4524 Third party induced migration

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Risk 4520: Migration along Legacy wells ID R-4520

Name QUEST: Migration along Legacy wells

Description CAUSE: Inadequate integrity of the 3rd party pre-existing legacy wells, because of the way they were drilled, completed and abandoned could provide a migration path across the seals of the BCS storage complex. RISK EVENT: BCS brine or CO2 to leak to either shallower horizons or ultimately to surface if the pressure front induces fluid migration uphole or CO2 plume intersects these wells. CONSEQUENCE: Additional cost towards remedial action on wells with poor integrity, requirement to redirect plume away from offending well, More extensive MMV measures may be required and CO2 credits could be lost as leaked volumes would incur penalties. If breach remains undetected eventually contamination of potable water zones and leak to surface may result which could trigger Litigation, HSSE issues and national reputation loss.

Notes Migration of CO2 is seen to be much less likely than the migration of brine due to the offset distance resulting from site selection. Also, the original owner of the well remains liable for abandoned wells. Additional remediation costs for 3rd party legacy wells are not included in the base case cost estimate (wells are assumed to be abandoned to the existing standards at the time). Four 3rd party legacy wells penetrate the BCS in the AOI (Darling, Westcoast, Eastgate and Egremont). The 5th legacy well is PLC Redwater, an abandoned salt cavern that penetrates only the upper Lotsberg within the AOI. There are currently two project wells, Redwater 3-4 and Radway 8-19, penetrating the BCS within the AOI resulting in a total of 7 penetrations of the BCS complex within the AOI. The only other relevant 3rd party legacy wells in AOI are Thorhild 16-9 and 16-22, penetrating the Prairie Evaporites but not the BCS storage complex. Outside of the AOI but within 1 township of the AOI boundary, the following penetrations have been identified: BCS: Clyde and Redwater 11-32, Lower Lotsberg: Gibbons, Upper Lotsberg: Provident #12, #14, #15, #16 Reference documentation: 07-3-ZG-7180-0001 3rd Party Legacy Well Status Report issued October 2010 07-3-ZW-7180-0002 Quest Legacy Wells Analysis Rev.03 issued March 2011


Site selection has minimized this risk: - through offset to legacy wells (21 km Radway to Egremont) . - selection of AOI with few BCS penetrations The following barriers are in place in the known legacy wells: - multiple cement plugs of significant length at various intervals - open hole abandonment across the salt allows for the opportunity for hole closure by salt creep - impermeable plugs may have formed through settlement of solids out of drilling mud in well bore An adaptive MMV plan may provide additional options for early warning through pressure monitoring (e.g. InSAR, Redwater 3-4, MMV wells near high risk legacy locations, etc). The possibility of new 3rd party wells is mitigated through a drilling ban into the BCS storage complex within the AOI. A request was issued separately to stop the creation of new Lotsberg salt caverns within the AOI.

Owner Crouch, Syrie


Status In Progress



Before actions Probability: Low Site selection has already mitigated this risk

through large offset distances to known legacy wells. CO2 is not envisaged to reach known legacy wells but the pressure front may cause brine to migrate up poorly abandoned well bores.

Cost/Benefit [C&B] High Re-abandonment, increased MMV around the offending well and potential clean-up of contaminated aquifers could cost between CDN

07-3-AA-6619-0004


Heavy Oil

25-50 mln. HSSE [HSSE] High Environmental impact could be high, health and

safety effect is expected to be medium as the leak is likely to be brine, not CO2.

Reputation [REP] High Loss of containment on this demonstration project could have high (National) impact on Shell's reputation as a CCS Operator.

System Capacity (QUEST) Medium Loss of containment at the edge of the pore space could result in injectors having to be shut-in, but will not occur until at least several years of injection have pushed the pressure front out to the nearest legacy well.


After actions Probability: Very Low Further review is assumed to increase confidence that all legacy wells have been identified and abandonment reports reviewed.

Cost/Benefit [C&B] High Current mitigations do not address consequences HSSE [HSSE] High Current mitigations do not address consequences Reputation [REP] High Current mitigations do not address consequences System Capacity (QUEST) Medium Current mitigations do not address consequences Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact

Likelihood

Cost Estimate

Schedule Estimate

Production Estimate

Action Party Sequestration Team



Finish

A-2611 QUEST: Investigate the limit of liability for legacy wells.


2010-01-01 2011-10-14


2010-01-01 2011-07-29

A-2635 QUEST: Model multiple subsurface realizations dynamically for pressure response.


2009-01-01 2011-06-30

A-3028 QUEST: Study all legacy well penetrations of the BCS in the Quest AOI

Closed Hugonet, Vincent

2009-04-01 2010-03-31

A-3029 QUEST: Develop a emergency response plan for legacy wells


2010-09-01 2011-06-30

A-3062 QUEST: Emergency Response Plan for Wells and Pipeline to keep Scotford Site-Specific ERP's from Scope

In Progress Jepp, Jon-Paul

2010-06-01 2011-11-01

A-3104 QUEST: Study all legacy well penetrations of the three seals in the Quest AOI


2010-06-10 2011-03-08

A-3105 QUEST: Review the Funding agreement for protection against liability on 3rd party wells


2010-03-01 2011-03-09

A-3106 QUEST: Review whether a survey for legacy wells is required around injector locations.


2010-01-01 2011-05-04

A-3120 QUEST: Use radial well models to review the monitoring requirements (if any) on legacy wells

In Progress De Groot, Hein

2011-04-01 2011-06-30

07-3-AA-6619-0004


Heavy Oil

TESLA - EXISTENCE: all well locations are known



Nov 2008 0.8

March 2009 0.8

Sept. 2009 0.8

Sept 2010 0.8

April 2011 0.7

Note: An additional well was found Westcoast 9-31. The well had previously been identified but was not recognized initially to penetrate the seals of the BCS storage complex. As a result the uncertainty of this hypothesis was changed from 0.2 to 0.3. There continues to be no evidence for additional legacy wells in the BCS storage complex in the AOI.

Evidence FOR 1) A data base exists and is available to the project team with petroleum/natural gas

well locations. 2) All BCS penetrations in AOI in the public database are known for pore space

application. 3) Two legacy well database searches have been completed:

a. The initial search was using Accumap, a system provided with data by IHS, b. The second independent search carried out was on Geovista, a system that

acquire its data from Divestco. c. No additional wells were found and the Carbon Sequestration Lease,

approved on 27 May 2011, now contains four third-party legacy wells within its boundaries: (Egremont 6-36, Eastgate 1-34, Darling No.1 and Westcoast 9-31).

Evidence AGAINST None Uncertainties:

1) Survey for legacy wells as part of well 8-19 planning could find no surface expression for some legacy wells

2) Records are not complete - anomaly existed for Darling well, for example where Shell did not pick up the full information

3) Formation at TD recorded for each well may not be a good record of TD formation.

07-3-AA-6619-0004


Heavy Oil

TESLA - STATUS/CONDITION: status of all known wells is known and supports non-leakage in the subsurface



Nov 2008 0.2

March 2009 0.2

Sept. 2009 0.2 0.1

Sept. 2010 0.6

Note: leakage in the subsurface requires clarification, risks out of the BCS storage complex are higher than risks to BGP zone.

Evidence FOR 1) Well study - report issued on the completions in 13 wells penetrating the BCS

storage complex in or in close proximity of the AOI (4 wells are in the final AOI). 2) All 3rd party legacy wells documented were found to have multiple cement plugs,

although not all of them cover the seals of the BCS storage complex. 3) Quest project wells will either be part of the development or appropriately

abandoned in accordance to the prevailing regulatory requirements

Evidence AGAINST 1) Two 3rd party legacy wells, one inside the AOI (Darling) one just outside the AOI

(Clyde) do not have deep cement plugs over the seals of the BCS storage complex Uncertainties:

1) The integrity of known cement plugs has not been tested (through pressure tests). 2) Historically competent cement jobs have been an issue resulting in casing failures. 3) Legacy wells are old and cement integrity may have degraded with time.

07-3-AA-6619-0004


Heavy Oil

Risk 4132: Migration along a QUEST well - Compromised casing integrity ID R-4132

Name QUEST: Migration along a QUEST well - Compromised casing integrity

Description CAUSE: Inadequate casing design and execution, casing degradation or corrosion could result in compromised casing integrity with respect to assumed operating envelope. RISK EVENT: Loss of containment could result in a CO2 leak outside the storage complex and in extreme case a blowout i.e. uncontrolled leak to atmosphere. Injection may need to be cut back or redistributed over potentially additional wells, more extensive MMV measures may be required and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and national reputation loss.

Notes 17Jun 2010 (HdG) reformulated risk to align with draft wells bow-tie by Ben Wallace. Previously this risk was called "oxygen ingress into tubing-casing and csg-csg annuli" 27 Aug 2010 (HdG) reformulated after review by SM, VH, SB and HdG, risk previously called "External corrosion" Oxygen ingress into tubing-casing and casing-casing annuli could occur, due vacuum created by temperature change of wellbore from shut-down to operating condition. CO2 injection will likely result in wellbore cooling from the normal geothermal gradient; fluid contraction could/will create vacuum in annuli. Operations personnel could (usually will) open valves to eliminate vacuum, if they notice this. This potential corrosion could create well integrity concern. Tubing leak may turn the packer fluid acidic resulting in casing corrosion leading in compromised casing integrity. Wet CO2, well shut-in/system shut down resulting in reservoir fluid flowing back into wellbore and introduction of well kill fluids could all lead to internal corrosion


-Include sufficient corrosion allowance in casing design. - Appropriate material selection - Packer placement immediately above the injection zone thereby protecting the casing -Operation intervention upon detection of excursion of design premise -Install TEG unit at capture & compression facilities to dry CO2 before it enters pipeline -Monitor CO2 quality by metering it before it enters the pipeline -Design the well to provide integrity in a corrosive environment (multiple casings, etc.) -Inhibitor fluid in the well annulus or cement to surface -Monitor annulus pressures and fluid pH

Owner Crouch, Syrie


Status In Progress



07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low Cost/Benefit [C&B] High Remediation of a leak on the outside of one or

more injectors wells and associated environmental clean-up costs and additional MMV burden could well cost ~ CDN$ 25-50 mln

HSSE [HSSE] High A slow leak outside of the casing that remains undetected for a long period could cause significant environmental damage to hydro- and biosphere

Reputation [REP] High Closely aligned with environmental impact System Capacity (QUEST) Low If a leak on the outside of an injector's casing is

detected this well is likely to be shut-in resulting in loss of capacity until well is remedied or replaced => loss of 10-15% system capacity

Schedule to FID (QUEST) no impact Schedule FID to SO (QUEST) no impact

After actions Probability: Very Low Cost/Benefit [C&B] High Remediation of a leak on the outside of one or



Reputation [REP] High Closely aligned with environmental impact System Capacity (QUEST) Very Low Contingency in number development wells

drilled(i.e. sparing) will reduce the capacity impact of this risk

Schedule to FID (QUEST) no impact Schedule FID to SO (QUEST) no impact




Finish

A-2600 QUEST: Deliver consistent CO2 purity Closed Leontowich, Jeffrey

2009-10-01 2011-01-25

A-2603 QUEST: Ensure robust well design (incl. material selection, cement quality, completion)


2009-07-01 2011-06-30

A-2622 QUEST: Develop Operating guidelines In Progress Hugonet, Vincent

2010-04-01 2011-06-30



2010-04-01 2011-06-30

A-2713 QUEST: Model CO2 open flow potential for dispersion models.

Closed Clark, Christa

2010-02-01 2010-12-01

A-2717 QUEST: Casing and cement integrity modeling.


2009-07-01 2011-10-01

A-3030 QUEST: Develop a bow-tie for leakage risks via the wellbore to surface


2010-04-01 2010-09-15

A-3062 QUEST: Emergency Response Plan for Wells and Pipeline to keep Scotford Site-specific ERP's from Scope


2010-06-01 2011-11-01

A-3107 QUEST: Risk assessment of the well design through OXAND


2010-06-14 2010-08-31

A-3111 QUEST: Define Well intervention strategy


2010-06-10 2011-06-30

07-3-AA-6619-0004


Heavy Oil

Risk: QUEST: Migration along a QUEST well - Compromised cement integrity ID R-4133

Name QUEST: Migration along a QUEST well - Compromised cement integrity

Description CAUSE: Inadequate cement design, cement placement or cement degradation through ageing or induced stresses (press. & temp.) could result in compromised cement integrity within the assumed operating envelope. RISK EVENT: Migration of CO2 or BCS brine outside of storage complex. CONSEQUENCE: Loss of containment could result in a CO2 leak outside the storage complex and in extreme case a blowout i.e uncontrolled leak to atmosphere. Injection may need to be cut back or redistributed over potentially additional wells, more extensive MMV measures may be required and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and national reputation loss.

Notes 17 Jun 2010 (HdG) reformulated risk to align with "low temperatures" risk in draft wells bow-tie by Ben Wallace, this risk was previously called "Cement degradation through Thermal cycling 27 Aug 2010 (HdG) reformulated after review by SM, VH, SB and HdG, risk previously called "Thermal cycling" Temperature change of wellbore, from shut-down to operating conditions during CO2 injection, could cause cement degradation (small cracks), creation of micro-annuli, and potential pipe and seal integrity issues. In the extreme case, well aging could lead to more severe sustained casing pressures and loss of tubing-casing annulus fluid volume/level.


PT: Consider potential modeling that could be done to evaluate possible temperature change that wellbore could experience, from operating to shut-in conditions. Engage subject-matter experts in material designs. WE: Well design should address possible mitigations, in terms of cement selection. Lab testing to validate cement design. Operations: Start up and operating guidelines.- Include instructions for minimizing opening/closing of well to minimize thermal cycling. From Bow-tie - Mechanical and process design to provide integrity for low temperatures - Instrumentation safeguarding system to prevent low temperatures - Operations intervention on indication of low temperature - D51 regulatory requirement for cement bond logging every 5 years

Owner Crouch, Syrie


Status In Progress


07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low Cost/Benefit [C&B] High Remediation of a leak on the outside of one or



Reputation [REP] High Closely aligned with environmental impact System Capacity (QUEST) Low If a leak on the outside of an injector's casing is

detected this well is likely to be shut-in resulting in loss of capacity until well is remedied or replaced => loss of 10-15% system capacity


After actions Probability: Very Low Cost/Benefit [C&B] High Remediation of a leak on the outside of one or



Reputation [REP] High Closely aligned with environmental impact System Capacity (QUEST) Very Low Contingency in number development wells

drilled(i.e. sparing) will reduce the capacity impact of this risk


Likelihood

Cost Estimate

Schedule Estimate Production Estimate




Finish



2009-07-01 2011-06-30

A-2620 QUEST: Evaluate possible temperature change that wellbore could experience

In Progress Clark, Christa

2010-04-01 2011-06-30


2010-04-01 2011-06-30



2010-04-01 2011-06-30

A-2716 QUEST: Dynamic Fracture Modeling In Progress Clark, Christa

2010-01-01 2011-06-30

A-2717 QUEST: Casing and cement integrity modeling.


2009-07-01 2011-10-01



2010-04-01 2010-09-15

A-3062 QUEST: Emergency Response Plan for Wells and Pipeline to keep Scotford Site-Specific ERP's from Scope


2010-06-01 2011-11-01



2010-06-14 2010-08-31

A-3298 QUEST: Document existing knowledge on cement-CO2 interactions


2010-09-01 2011-06-30

07-3-AA-6619-0004


Heavy Oil

Risk 4159: Migration along a QUEST well - Compromised completion or wellhead integrity ID R-4159

Name QUEST: Migration along a QUEST well - Compromised completion or wellhead integrity

Description CAUSE: Inadequate completion design and execution, failure through degradation of materials used (in completion and wellhead) or external damage to the wellhead could result in compromised well integrity with respect to assumed operating envelope RISK EVENT: Migration of CO2 or BCS brine outside of storage complex predominantly to atmosphere. CONSEQUENCE: Loss of containment could result in a blow-out or if leak is smaller injection may need to be cut back or redistributed over potentially additional wells, more extensive MMV measures may be required, CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and considerable reputation loss.

Notes 22Jun2010 (HdG) reformulated to align with Equipment failure risk in draft Wells bow-tie by Ben Wallace, previously called "Inappropriate wellhead design" 27 Aug 2010 (HdG) reformulated after review by SM, VH, SB and HdG, risk previously called "Equipment failure" Usage of inappropriate materials for CO2 service (either metallurgy, elastomers or cement recipe) in any of the well components, including wellhead and annulus valve bodies, gates and seats, stem packings, hanger seals, and sealant injection check valves, will increase leakage risks. External impact from vehicles, mobile equipment, dropped objects from platform, sabotage or surface explosions could cause damage to the well head.


Adequate well design and material selection. Operations intervention upon excursions outside the design premises Adherence to Dir -51 directive of annual packer isolation test Wellhead damage mitigations: -Offset spacing (100m from public road), barrier on access road -Ditch, railing, concrete barriers around well head to avoid potential well head collisions -Crane safety equipment, design well for impact resistance to small dropped objects -Consider fencing and surveillance camera's to restrict access to site -Site selection, spacing and avoidance of presence of combustibles on site should minimise fire/explosion risks - CW&I well intervention procedures - Start up and operating guidelines - Operators competency development

Owner Crouch, Syrie


Status In Progress


07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low Cost/Benefit [C&B] Medium Leak path is likely to be contained inside casing

and can be remedied with little environmental damage or additional MMV requirements. At worst the affected wells would need to be redrilled =>cost CDN$ 10-25 mln

HSSE [HSSE] High Well control (blow-out) issues give high safety impact. Environmental risk is medium as leak is likely to be contained within the casing

Reputation [REP] Medium Aligned with medium environmental impact, loss of well control will be a temporary event

System Capacity (QUEST) Low If a leak of the injector's completion is detected this well is likely to be shut-in resulting in loss of capacity until well is remedied or replaced => loss of 10-15% system capacity


After actions Probability: Very Low Cost/Benefit [C&B] Medium Leak path is likely to be contained inside casing




System Capacity (QUEST) Very Low Contingency in number development wells drilled(i.e. sparing) will reduce the capacity impact of this risk





Finish



2009-07-01 2011-06-30

A-2612 QUEST: Consider the use of SSSV – SCSSSV


2010-04-01 2011-10-14


2010-04-01 2011-06-30



2010-04-01 2011-06-30



2010-04-01 2010-09-15



2010-06-01 2011-11-01



2010-06-14 2010-08-31



2010-06-10 2011-06-30

A-3296 QUEST: Mitigate risk of external wellhead damage (site design and selection)


2010-04-01 2011-06-30

A-3297 QUEST: Develop well kill plans and procedures


2010-04-01 2011-06-30

07-3-AA-6619-0004


Heavy Oil

Risk 4522: Migration along a QUEST well - Compromised abandonment ID R-4522

Name QUEST: Migration along a QUEST well - Compromised abandonment

Description CAUSE: Inadequate abandonment design or execution (ineffective placement), or degradation of plugs through ageing could result in compromised abandonment integrity of QUEST wells post abandonment. RISK EVENT: Migration of CO2 or BCS brine outside of storage complex to shallower horizons or to surface. CONSEQUENCE: Loss of containment could result in a CO2 leak outside the storage complex and in extreme case a blowout i.e. uncontrolled leak to atmosphere. Injection may need to be cut back or redistributed over potentially additional wells, more extensive MMV measures may be required, CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and limited reputation loss.

Notes 22June2010 (HdG) Re-used a duplicate risk on LOC from injectors to capture five separate wellhead risks identified in the draft wells bow-tie issued by Ben Wallace. 27/Aug/10 (HdG) renamed after meeting with SM, VH, SB and HdG, risk previously called "External damage to wellhead" now incorporated in R-4159 on well completion risk. Abandonment risk of QUEST wells (post closure of AOI) were not previously captured specifically


-Abandonment strategy -Incorporate abandonment requirements in initial well design - MMV requirements for abandoned wells - Operating strategy and guidelines

Owner Crouch, Syrie


Status In Progress



07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low Cost/Benefit [C&B] Low Costs related to remediation of well abandonment

and deferred handover of liability (additional late life operating costs). NPV effect may be small due to late timing => CAD 5-10 mln

HSSE [HSSE] Low Post injection pressures will stabilize and safety impact of poor abandonment is expected to be minimal. Environmental impact rated as minor, assuming leak is contained within casing and thus easily detectable and possible to remedy

Reputation [REP] Low Aligned with minor environmental impact System Capacity (QUEST) Post injection so no impact on capacity Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact

After actions Probability: Very Low Cost/Benefit [C&B] Low Costs related to remediation of well abandonment

and deferred handover of liability (additional late life operating costs). NPV effect may be small due to late timing => CAD 5-10 mln

HSSE [HSSE] Low Post injection pressures will stabilize and safety impact of poor abandonment is expected to be minimal. Environmental impact rated as minor, assuming leak is contained within casing and thus easily detectable and possible to remedy

Reputation [REP] Low Aligned with minor environmental impact

System Capacity (QUEST) Post injection so no impact on capacity Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact

Likelihood

Cost Estimate

Schedule Estimate

Production Estimate Action Party Sequestration Team



Finish

A-2596 QUEST: Create Abandonment plan that ensures long term integrity


2010-01-01 2011-07-29



2009-07-01 2011-06-30


2010-04-01 2011-06-30



2010-04-01 2011-06-30

07-3-AA-6619-0004


Heavy Oil

Risk: QUEST: Migration along a QUEST well as a result of well intervention ID R-4523

Name QUEST: Migration along a QUEST well as a result of well intervention

Description CAUSE: Loss of containment from well due to well intervention activity in well bore (eg. wirelining, coiled tubing, service rig, HP pumping or nitrogen lifting operations, workover etc.) RISK EVENT: Migration of CO2 or BCS brine outside of storage complex- predominantly to atmosphere. CONSEQUENCE: Loss of containment could result in a blow-out or if leak is smaller injection may need to be cut back or redistributed over potentially additional wells, more extensive MMV measures may be required and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected, though unlikely in well intervention case, contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and considerable reputation loss.

Notes 22June2010 (HdG) aligned with the "re-entry risk" in draft wells bow-tie issued by Ben Wallace, risk was previously called "Wells Execution (MMV & Injectors). 27/Aug/10 (HdG) renamed after meeting with SM, VH, SB and HdG, risk previously called "Re-entry operations". This risk now specifically focuses on catastrophic loss of well control (blow out). External impact from vehicles, mobile equipment, dropped objects from platform, sabotage or surface explosions could cause damage to well head.


-CW&I guidelines and procedures -Mechanical design to provide integrity of temporary equipment (ensure CO2 compatible equipment) -Minimize well interventions -Develop well kill procedures and ensure contractor capability -Operating strategy and guidelines - Operator competencies

Owner Crouch, Syrie


Status In Progress



07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low Cost/Benefit [C&B] Medium Leak path is likely to be contained inside casing




System Capacity (QUEST) Low If a leak occurs due to a well intervention this well is likely to be shut-in resulting in loss of capacity until well is remedied or replaced => loss of 10-15% system capacity


After actions Probability: Very Low Cost/Benefit [C&B] Medium Leak path is likely to be contained inside casing




System Capacity (QUEST) Very Low Contingency in number development wells drilled(i.e. sparing) will reduce the capacity impact of this risk





Finish



2009-07-01 2011-06-30

A-2610 QUEST: SIMOPS planning In Progress Hugonet, Vincent

2010-01-01 2014-01-31

A-2612 QUEST: Consider the use of SSSV – SCSSSV


2010-04-01 2011-10-14


2010-04-01 2011-06-30



2010-04-01 2010-09-15



2010-06-01 2011-11-01



2010-06-10 2011-06-30

A-3296 QUEST: Mitigate risk of external wellhead damage (site design and selection)


2010-04-01 2011-06-30

A-3297 QUEST: Develop well kill plans and procedures


2010-04-01 2011-06-30

A-3304 QUEST: Ensure relevant staff have mapped and developed the necessary competencies to operate an integrated CCS scheme.

Proposed Crouch, Syrie

2012-01-01 2014-01-01

07-3-AA-6619-0004


Heavy Oil

TESLA - FUTURE well bores will avoid creating leak paths or minimise the risk thereof



Nov 2008 0.3 0.05

March 2009 0.4 0.1

Sept. 2009 0.7 0.1

Aug 2010 0.7

Evidence FOR 1) There are existing standards in Alberta with regard to well construction regarding

injection activities. To date, corporate standards do not exist for CO2 sequestration. It is not expected that AG disposal standards will differ markedly from those of CO2 disposal wells. Factors affecting success of CO2 service wellbores is understood in Shell.

2) There is a low likelihood of other operators penetrating the BCS for HC appraisal purposes.

3) AAR report from 2 appraisal wells issued. RCFA undertaken. New cement rheology proposed for well #3. Lookback on wells 1&2 undertaken. Borehole stability - issues better understood (effectiveness of oil based mud still to be confirmed, intermediate casing setting depth improved, well design changed (hole size), better understanding of pore pressure).

4) We have preliminary approval from the Alberta Government that limits 3rd party drilling below the Upper Lotsberg over ~75% of the AOI.

5) External studies (Bachu /Sch) show that the likelihood of well leakage is low. 6) Future Well design and abandonment design have been assessed externally

(OXAND) and show no leakage above the ultimate seal. 7) Third well was successfully drilled, cased and cemented with good hydraulic

isolation across the seals. Evidence AGAINST

1) Washouts in mid and upper Cambrian shale sections during SC and RW wells. CBL & USIT logs run and interpreted. Logs demonstrate intervals with good bonding and intervals with poor bonding (no longer relevant due to incorporation of learning and performance on the third well).

Uncertainties:

07-3-AA-6619-0004


Heavy Oil

Risk 4149: Requirement for MMV wells in the BCS (eg. ineffective non-invasive MMV) threatens Containment ID R-4149

Name QUEST: Observation wells in the BCS may threaten Containment

Description CAUSE: Failure of non-invasive technologies to remotely track the migration of CO2 and/or pressure distribution inside the storage complex or ERCB requirements. RISK EVENT: Loss of containment caused by additional BCS well penetrations required to track the migration of CO2 and/or pressure distribution inside the storage complex CONSEQUENCE: Monitoring wells that penetrate all seals of the storage complex could add to project cost, increase HSE impact (surface footprint) and contribute to loss of containment risks through creation of additional potential leakpaths. Consequences of loss of containment could be the requirement for more extensive MMV measures, reduction or redistribution of injection volumes over potentially additional wells and CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and considerable reputation loss.

Notes 28/Apr/'11 (HdG) Risk renamed from "Requirement for MMV wells in the BCS (eg. ineffective non-invasive MMV) threatens Containment" to "Observation wells in the BCS may threaten Containment". Mitigations assumed in place updated and aligned with passive barriers in bowtie. It is not sure whether the regulator will accept an MMV plan without BCS observation wells and not all non-invasive monitoring techniques have proven feasibility. 2 Sep 2010 (HdG) Risk reformulated from "Inability to use surface seismic for MMV" to a more generic risk around having to penetrate the seals of the BCS storage complex if remote non-invasive monitoring (eg. seismic, INSAR, etc.) fails or proves to be inadequate. This risk aligns with a risk from Ch7 of the June 2010 draft MMV plan. Risk is now moved from Conformance (previously called MMV) to Containment Old description captured for future reference: CAUSE: Inherent geologic complexities prohibit acquisition of good quality seismic data. RISK EVENT: Unable to use surface seismic for MMV CONSEQUENCE: Required to resort to other MMV activities (potentially more expensive like more observation wells)


1) The initial base case MMV Plan does not include BCS observation wells 2) The use of Redwater 3-4 as a BCS pressure observation well 3) Well sparing philosophy allows for regular sequence of annual fall-off tests in injection wells (to be included in the operating guidelines) 4) All BCS injectors will be used as BCS observation wells during start-up & closure periods 5) InSAR, VSP and seismic are part of the initial base case MMV Plan 6) InSAR will be calibrated to BCS pressure measurements from the Redwater 3-4 BCS observation well

Owner Crouch, Syrie


Status In Progress


07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low The low probability reflects the pre-mitigated chance of loss of containment through an MMV well, not the chance that these have to penetrate the BCS. Shell has high standards in place for well design (incl. material selection) and execution.


HSSE [HSSE] High Environmental impact could be high, health and safety effect could be more moderate as the leak is not likely to contain CO2 but brine (depending on location and perforation strategy of MMV vs injectors)

Reputation [REP] High Loss of containment through Quest MMV wells could have national impact on Shell's reputation as a prudent Operator

System Capacity (QUEST) Very Low Nearest injector to MMV well with leak may have to be temporarily shut-in or suspended.


After actions Probability: Very Low The MMV plan aims to eliminate any MMV wells penetrating the seals of the storage complex. Best in class well design, material selection and cementing practices will mitigate in the event that regulators require additional BCS observation wells.

Cost/Benefit [C&B] Medium Reduction of BCS penetrations for MMV purposes reduces the cost impact of this risk to between CDN 10-25 mln with scope for total elimination of risk.

HSSE [HSSE] Low Elimination of MMV wells will reduce impact. If still required limiting numbers of MMV wells and maintaining offset to injectors will also reduce impact

Reputation [REP] High Loss of containment through Quest MMV wells could have national impact on Shell's reputation as a prudent Operator

System Capacity (QUEST) Very Low Impact can be reduced if MMV wells are not open to BCS and eliminated if they do not penetrate seals



Finish

A-2619 QUEST: Evaluate need for a 'spare' well In Progress Hugonet, Vincent

2009-03-02 2011-07-29


2010-01-01 2011-07-29

A-2693 QUEST: 4D Seismic Feasibility In Progress Bourne, Stephen

2009-06-01 2011-06-30

A-2705 QUEST: 3D Vertical Seismic Profiling (VSP) Feasibility.

In Progress Bourne, Stephen

2009-06-01 2011-06-30

A-3289 QUEST: INSAR feasibility study In Progress Bourne, Stephen

2010-01-01 2011-08-12

A-3299 QUEST: Feasibility study on Microgravity surveys


2010-02-01 2011-05-30

A-3555 QUEST: Evaluate feasibility of converting Redwater 3-4 into MMV observation well


2010-11-25 2011-06-30

A-3556 QUEST: Develop Start-up guidelines that address early data acquisition requirements


2011-01-28 2011-06-30

A-3785 QUEST: ERCB advocacy on future MMV guidelines

Proposed Crouch, Syrie

2011-04-28 2012-05-31

07-3-AA-6619-0004


Heavy Oil

Risk 4524: Third party induced migration ID R-4524

Name QUEST: Third party induced migration

Description Third party activity (drilling and/or injection in the BCS storage complex) induces brine/CO2 migration out of the BCS storage complex. CAUSE: 1) Inadequate integrity of future 3rd party wells to be drilled within or in close proximity to our AOI could provide a migration path across the ultimate seal of the Upper Lotsberg. 2) Disposal into the BCS by a nearby injection scheme could increase BCS pressure sufficient to breach the seals of the BCS storage complex (Legacy wells, fractures, faults). RISK EVENT: Brine/CO2 migration out of the BCS storage complex resulting in loss of containment. Increased BCS pressure would result in reduced storage capacity and injectivity. CONSEQUENCE: More extensive MMV measures may be required, injection may need to be cut back or redistributed over potentially additional wells. Additional wells may be required to compensate for loss of injectivity and storage and abandonment pressure could be effected by 3rd party schemes. CO2 credits could be lost as uncontained volumes of CO2 would incur penalties. If loss of containment remains undetected contamination of potable water zones and leak to surface may eventually result which could endanger public health and safety, cause environmental damage, legal action, and considerable reputation loss.

Notes 28/Apr/'11 (HdG) The following text was previously captured as imitigation assumed in place: We have preliminary approval from the Alberta Government that limits drilling below the Upper Lotsberg over ~75% of the AOI. The status of these approvals need to be verified and referenced 26/Mar/'10 (HdG) Risk expanded to include all 3rd party activity that could result in LOC, i.e. wells AND competing disposal schemes. Risk also moved from Wells to Containment as there will be no Well Engineering actions by Shell on 3rd party schemes, in other words this is a LOC not a Well's risk.


-Site selection away from active salt caverns and HC plays -Lateral extent (40 townships) and vertical extent (top Prairie evaporite to PC basement) of the sequestration lease (AOI), which should prevent future drilling or mining in the AOI below the Prairie Evaporite.

Owner Crouch, Syrie


Status In Progress



07-3-AA-6619-0004


Heavy Oil

Before actions Probability: Low The Exploration Tenure request has mitigated this risk by guiding the AOI sizing on the extent of the pressure front after 25 yrs of injection. A ban on 3rd party drilling through the seals of the BCS storage complex in the AOI was requested.

Cost/Benefit [C&B] Medium Redistribution of injection (1 extra well to increase offset to 3rd party) and increased MMV could cost between CDN 10-25 mln.

HSSE [HSSE] Medium Environmental and Health and Safety effects from a 3rd party caused loss of containment could be high, but are rated medium here as the 3rd party would carry primary liability, with medium contribution from the Quest pressure front (no CO2 due to offsets)

Reputation [REP] Medium Even though loss of containment in this scenario is caused by a 3rd party it could have repercussions (regional) on Shell's reputation as a prudent CCS operator.

System Capacity (QUEST) Medium Loss of containment due to 3rd party activity could result in injectors having to be shut-in, but will not occur until at least several years into the 10yr contract period due to Quest’s leading position in the area.


After actions Probability: Very Low Active engagement with regulators and potential other CCS operators should further minimize the probability of this event occurring.

Cost/Benefit [C&B] Medium Current mitigations do not address consequences HSSE [HSSE] Medium Current mitigations do not address consequences Reputation [REP] Medium Current mitigations do not address consequences System Capacity (QUEST) Medium Current mitigations do not address consequences Schedule to FID (QUEST) No impact Schedule FID to SO (QUEST) No impact

Likelihood

Cost Estimate

Schedule Estimate Production Estimate



Associated actions:

ID Name Status Owner Start Date Planned Finish


2010-01-01 2011-07-29

A-2954 QUEST: Secure sufficient subsurface tenure to support regulatory application

Closed Penney Kathy

2009-12-16 2011-06-30

A-3108 QUEST: Engage regulator on urban planning to secure 3rd party buffer zones

In Progress Crouch, Syrie

2010-03-01 2011-09-30

A-3554 QUEST: Assess and document storage capacity estimates for the Quest AOI

In Progress De Groot, Hein

2011-01-28 2011-06-30

A-3599 QUEST: Evaluate impact of concurrent CCS schemes adjacent to Quest AOI


2009-04-29 2011-06-30

07-3-AA-6619-0004


Heavy Oil

APPENDIX 1 Quest Risk Assessment Matrix (RAM)

1) Cost/ Benefit in Operations is measured by cumulative impact during project Funding Period (first 10 years of operation) 2) Schedule delay to Final Investment Decision (between now and ~Q1 2012) 3) Schedule delay to Sustained Operations (incremental delay from FID to meeting contractual disposal requirement 4) System Capacity refers to the cumulative impact on the combined Capture, PL and Sequestration capacity during project Funding

Period (first 10 years of operation) 5) The Risk Assessment matrix is project specific, with the exception of HSE where a global RAM is applied

Shell Global HSE Risk Matrix

Las t Update : A pri l 22, 2010

1 2 3 4 5

VLO LO MED HI VHI

Co

st/B

en

efit

in C

DN

$ 1

Sch

ed

ule

dela

y to

FID

2

Sch

ed

ule

de

lay to

SO

3

Syste

m

Cap

acity 4

HS

E 5

Re

puta

tio

n

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)

Score

As

ses

sm

ent

> 50 mln > 6 mos > 6 mos >25% downtimeInternational

impact5 10 15 20 25 5 VHI

25-50 mln 3 - 6 mos 3 - 6 mos20% - 25%

downtimeNational impact 4 8 12 16 20 4 HI

10-25 mln 1 - 3 mos 1 - 3 mos15% - 20%

downtime

Considerable

(Regional)

impact

3 6 9 12 15 3 MED

5-10 mln 0.5 - 1 mos 0.5 - 1 mos10% - 15%

downtime

Limited impact

(public concern/

local media)

2 4 6 8 10 2 LO

< 5 mln < 0.5 mos < 0.5 mos < 10% downtime

Slight impact

(some public

awareness)

1 2 3 4 5 1 VLO

Risk CategoryScore

Assessment

IM

PA

CT

→

PROBABILITY →

Refe

r to

HS

E R

AM

IM

PA

CT

→

Last Update: M arch 3rd, 2010

A B C D E

People EnvironmentNever Heard

of in Industry

Heard of in

Industry

Has

happened in

Organization

or >1/yr in

Industry

Has

happened in

Location

or >1/yr in

Organization

Has

happened

>1 /yr in

Location

Score

No injury

or health

affect

No effect 0

Slight

injury or

health

effect

Slight effect 1

Minor

injury or

health

effect

Minor effect 2

Major

injury or

health

effect

Moderate

effect3

PTD* or up

to 3

fatalities

Major effect 4

More than

3 fatalities

Massive

effect5

PROBABILITY →Score

←

IMP

AC

T

Category

←

IMP

AC

T

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