Quest Carbon Capture and Storage Project ANNUAL SUMMARY REPORT - ALBERTA DEPARTMENT OF ENERGY: 2013

Transcription

1 Quest Carbon Capture and Storage Project ANNUAL SUMMARY REPORT - ALBERTA DEPARTMENT OF ENERGY: 2013 March 2013

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3 Quest Carbon Capture and Storage Project Executive Summary Executive Summary This annual report summarizes the progress and status of the Quest Carbon Capture and Storage (CCS) Project (the Project) as it pertains to the initial full project proposal submitted in March 2009 to the Alberta Department of Energy by Shell Canada Limited. That submission was for funding from the Alberta CCS Fund and as a requirement for CCS Funding Agreement Quest Project that was signed on June 24, The purpose of the Project is to deploy technology to capture CO 2 produced at the Scotford Upgrader and to transport, compress and inject the CO 2 for permanent storage in a saline formation near Thorhild, Alberta. Up to 1.2 Mt/a of CO 2 will be captured, representing greater than 35% capture of the CO 2 produced from the Scotford Upgrader. The Project is a part of the Athabasca Oil Sands Project (AOSP), an oil sands joint venture operated by Shell and owned by Shell Canada, Chevron Canada and Marathon Oil. According to Shell s Opportunity Realization Manual (ORM) process, the Project has completed the Define phase whereby the Project scope is finalized and the Front End Engineering and Design (FEED) is completed. The project now moves into the Execute Phase. With the completion of FEED, the process design is finalized. The CO 2 will be captured from three existing steam methane reformers used to generate hydrogen at the Scotford Upgrader. A commercially-proven activated amine process will be used in which the CO 2 is absorbed (captured) into the amine solution and then regenerated to produce at least 95% CO 2 purity. The CO 2 will then be compressed by an electrical drive compressor to a maximum dense-phase pressure of approximately 14 MPa. At this pressure, the CO 2 will be transported through a 12-inch diameter pipeline to a location approximately 80 kilometers north of the Scotford Upgrader. No further compression or pumping is required to transport the CO 2 into the storage area by means of three injection wells. By means of three injection wells, CO 2 will be injected approximately 2 km underground into the Basal Cambrian Sands (BCS) geological formation. The BCS formation is situated below layers of impermeable, continuous and thick cap rock, which will keep CO 2 isolated within the formation and will prevent any upward migration. The CO 2 will be trapped within the pore spaces of the rock formation in the same way that geological formations have naturally contained large reservoirs of oil and gas for millions of years. Storage properties of the BCS complex have been validated through analysis of the data obtained from drilling a test well into the BCS formation. Risks of CO 2 containment loss are comprehensively detailed along with mitigation activities. A detailed measurement, monitoring and verification (MMV) Plan has been developed and will be implemented by Shell to monitor the storage of CO 2 and to protect public health and safety. The MMV Plan will be integrated with the GHG reporting system in place at the Scotford Upgrader. Final regulatory approvals for the Project were received by August 2012, following a public hearing held in March of that year. Subsequent to that, a public announcement was held on September 5, 2012 whereby the joint venture owners and representatives of the Governments of Canada and Alberta announced that Shell had been given final approval to proceed with the Project. Shell Canada Limited March 2013 Page i

4 Executive Summary Quest Carbon Capture and Storage Project Work is underway at the Shell Scotford capture unit site to construct and install the below grade facilities such as sumps, underground lines and pilings prior to main construction. Long-lead major equipment such as the amine vessels and large CO 2 compressor are being fabricated. The module contract has been awarded and the module fabrication shop, located near Edmonton, has begun work to be ready to receive steel and begin fabrication of the modules in The drilling program is largely completed with all deep wells drilled. Field work began in mid-2012 to gather benchmark data to quantify the hydrosphere, biosphere and subsurface properties prior to injection. The operations team has begun to be assembled and has started to prepare the necessary operating and maintenance procedures required to run the Project. Shell conducted a series of open houses for local communities in November 2012 to continue to update the public on the Project s progress, including the news that the Project is proceeding. County and Town Council Project updates were given twice in 2012 to councils in Thorhild, Strathcona, Lamont, Bruderheim, Fort Saskatchewan, and Strathcona and Sturgeon County. Additionally, local community events were attended in the summer of 2012 to continue to provide opportunities to residents to receive information about the Project. The current estimate of capital costs is about $875 million, which will be spent from 2012 to The current estimate of operating costs is about $41 million per year. Project revenues will be zero during construction and will be $30 million per year during operations from the sale of carbon credits at 2013 carbon prices. The Project is proceeding on the expected timeline with completion of construction in 2015 and startup immediately thereafter. The only milestone change has been to change the startup point from Q to Q4 2015, resulting from the delay in the regulatory approval and subsequent FID from March 2012 point to August The Project has experienced a number of successes in the past reporting period, including: receiving regulatory approvals and FID announcement holding the capital costs in line, with a resultant forecast of slightly lower than past reporting period completing the major engineering work beginning of the module fabrication process completing the deep drilling activities commencing the MMV program with the benchmark data gathering maintaining local support through the extensive stakeholder engagement activities meeting the Government of Alberta funding milestones March 2013 Page ii Shell Canada Limited

5 Quest Carbon Capture and Storage Project Executive Summary Project challenges included: acquiring land leases for the wells and pipelines conducting the initial site construction through the winter months as opposed to the planned summer period managing the Project overall schedule within the bounds of the delay in receiving regulatory approvals These challenges have been successfully managed with the result that the Project remains on track for a 2015 startup. Within the next reporting period, construction at the site and the module yard will continue. Pipeline construction will begin later in 2013 and major equipment will begin to be delivered to the site. Operations readiness will be a focal point as will finalizing the remaining regulatory permits. Stakeholder engagement activities will be continuing to enable local residents to maintain their awareness of Project progress. Ongoing reporting will be done to the governments of Alberta and Canada to keep them apprised of the Project s progress. Shell Canada Limited March 2013 Page iii

6 Executive Summary Quest Carbon Capture and Storage Project March 2013 Page iv Shell Canada Limited

7 Quest Carbon Capture and Storage Project Table of Contents Table of Contents 1 Overall Facility Design Design Concept Design Scope ORM Design Framework and Project Maturity Facility Locations and Plot Plans Process Design Modularization Approach Facility Construction Schedule Geological Formation Selection Storage Area Selection Geological Framework Risk to Containment Estimate of Storage Potential Initial Injectivity Assessment Facility Operations Capture Facilities Operations Activities Next Steps Facility Operations - Transportation Pipeline Design Pipeline Safeguarding Considerations Facility Operations - Storage and Monitoring MMV Plan Facility Operations - Maintenance and Repairs Regulatory Approvals Regulatory Overview Regulatory Hurdles Regulatory Filings Status Next Regulatory Steps Public Engagement Background Shell s Stakeholder Engagement Strategy First Nations and Métis Groups Issues Identified Issue Management Costs and Revenues Capex Costs Opex Costs Revenues Funding Status Project Timeline Shell Canada Limited March 2013 Page v

8 Table of Contents Quest Carbon Capture and Storage Project 12 General Project Assessment Project Successes Project Challenges Indirect Albertan and Canadian Economic Benefits Next Steps List of Tables Table 3-1 Assessment of the BCS for Safety and Security of CO 2 Storage Table 3-2 BCS Pore Volume Range within the ASLB Table 3-3 Injectivity Estimates for Redwater Well and Radway Well 8-19 Water Injection Tests Table 5-1 Pipeline Design and Operating Conditions Table 5-2 Pipeline Fluid Composition Table 6-1 MMV Commitments Table 6-2 Summary of the Monitoring Plan for the Geosphere, Hydrosphere, Biosphere and Table 6-3 Atmosphere Summary of the Monitoring Plan for Deep Observation Wells and CO 2 Injection Wells Table 8-1 Regulatory Approval Status Table 10-1 Anticipated Project Capital Costs (2012 Estimate) Table 10-2 Anticipated Project Operating Costs (2011 Estimate) Table 10-3 Anticipated Project Revenue Table 11-1 Project Timeline Table Project Milestones List of Figures Figure 1-1 ORM Phases with current Project Maturity Figure 1-2 Project Facility Locations Figure 1-3 Capture Unit Location Schematic Figure 1-4 BCS Storage Complex within the Regional Stratigraph Figure 1-5 Project Components and Approved Sequestration Lease Boundary Figure 1-6 Capture and Compression Process Design Figure 2-1 Project Construction Schedule Figure 3-1 Stratigraphy and Hydrostratigraphy of Southern and Central Alberta Figure 3-2 Cross-Section of the WCSB Showing the BCS Storage Complex Figure 3-3 Pressure Distribution after 25 Years of Injection in the Mid- Property/Mid- Connectivity Case with an Analytical Aquifer Extension Figure 3-4 Actual Well Test Injectivity versus Full Project Injection Requirements Figure 6-1 CO 2 Containment Loss Risk and Mitigation Diagram Figure 6-2 MMV Plan Schedule March 2013 Page vi Shell Canada Limited

9 Quest Carbon Capture and Storage Project Abbreviations Abbreviations 2D... 2-Dimensional 3D... 3-Dimensional 4D... 4-Dimensional AEW... Alberta Environment and Water AFN... Alexander First Nation AOI... Area of Interest AOSP... Athabasca Oil Sands Project ARC... Alberta Research Council ASRD... Alberta Sustainable Resources Development BCS... Basal Cambrian Sands BHP... bottom-hole pressure BLCN... Beaver Lake Cree Nation CCS... carbon capture and storage CEAA... Canadian Environmental Assessment Act CRC... Calgary Research Center D51... Directive 51 application D56... Directive 56 application D65... Directive 65 application DEDA... piperazine ERCB... Energy Resources Conservation Board FEED... Front End Engineering and Design FEP... fracture extension pressure FID... Final Investment Decision GHG... greenhouse gases HMUs... hydrogen manufacturing units HVP... high vapor pressure InSAR... Interferometric synthetic aperture radar LBV... line break valve LMS... Lower Marine Sand LRDF... long running ductile fracture MCS... Middle Cambrian Shale MMV... measurement, monitoring and verification ORM... Opportunity Realization Manual OSCA... Oil Sands Conservation Act PSA... pressure swing adsorber RFA... Regulatory Framework Assurance ROW... right-of way ASLB... approved sequestration lease boundary SLCN... Saddle Lake Cree Nation TEG... triethylene glycol UMS... Upper Marine Siltstone VSP... vertical seismic profile WCSB... Western Canada Sedimentary Basin WIIP... water initially in place Shell Canada Limited March 2013 Page vii

10 Abbreviations Quest Carbon Capture and Storage Project March 2013 Page viii Shell Canada Limited

11 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design 1 Overall Facility Design Facility design at this point has reached the 90% complete detailed design with an expected 100% completion by the end of June Early works construction effort has begun with the underground piping and piling underway. 1.1 Design Concept The Athabasca Oil Sands Project (AOSP) is an oil sands joint venture that operates the Scotford Upgrader located at Shell Scotford, located in the Alberta Industrial Heartland, northeast of Edmonton. The design concept for the Project is to remove CO 2 from the process gas streams of the three hydrogen manufacturing units (HMUs), which are a part of the Scotford Upgrader infrastructure, by using amine technology and to dehydrate and compress the captured CO 2 to a dense-phase state for efficient pipeline transportation to the subsurface storage area. The three HMU s comprise two identical existing HMU trains in the base plant Scotford Upgrader and third one constructed as part of the Scotford Upgrader Expansion 1 Project, which has been operational since May Design Scope The design scope for the facilities includes: modifications on the three existing HMUs modifications on the three existing pressure swing adsorbers (PSAs) three amine absorption units located at each of the HMUs a single common CO 2 amine regeneration unit (amine stripper) a CO 2 vent stack a CO 2 compression unit a triethylene glycol (TEG) dehydration unit Shell Scotford utilities and offsite integration CO 2 pipeline, laterals, and surface equipment three to eight injection wells 1.3 ORM Design Framework and Project Maturity The design framework followed by the Project is the standard Shell approach in project design, called the Opportunity Realization Manual (ORM). The ORM process manages a project as it matures through its lifecycle from initial concept to remediation following closure. ORM divides this lifecycle into stages as shown in Figure 1-1. Each phase has required deliverables that are reviewed to ensure proper quality of these deliverables before proceeding to the next phase. Shell Canada Limited March 2013 Page 1-1

12 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project Quest Status March 2013 IDENTIFY ASSESS SELECT DEFINE EXECUTE OPERATE Decision Gates Figure 1-1 ORM Phases with current Project Maturity The Project technical activities in the past year correspond with the Execute Phase. This includes the detailed engineering work required to deliver the approved-for-construction drawings, technical specification for the procurement of all equipment and materials and the management of any changes to the Define Phase deliverables. In December 2011, Shell made a risk-based decision to proceed into the Execute Phase before final regulatory approval in order to hold to the Project schedule. The Shell Executive Committee, followed by the Joint Venture partners, approved the FID of the Project in the summer of 2012 after the ERCB Decision Report on the hearing was received. This approval was announced in early September after formal receipt of the various regulatory approvals. In June of 2012, Shell conducted the required Project Execution Review (PER) of the Project progress at that time. The PER examined the status of the Project, including the Execute Phase deliverables completed at that time as well as reviewing the output of the early works construction readiness review and concluded that the Project was proceeding according to plan and ready to start early works construction upon execution of the contracts and receipt of the regulatory approvals. The Execute Phase concludes with the completion of the facilities construction and subsequent handover to Shell Scotford operations for startup and operation. This is planned to occur in mid Facility Locations and Plot Plans The Project facility locations are shown in Figure 1-2. The capture facility is situated within the Scotford Upgrader. The pipeline routing is shown as the dotted line in Figure 1-2, while the stars indicate the location of the potential maximum number of eight wells. The actual number of wells drilled may be less and will be dependent on the actual injectivity and porosity characteristics of the formation. Three injection wells are planned initially and additional ones drilled only as they are required to store the CO 2 into the Basal Cambrian Sands (BCS) formation (see Section 3). The capture unit is located adjacent to two of the Scotford Upgrader HMU s. See Figure 1-3 for a schematic view of the capture unit location. March 2013 Page 1-2 Shell Canada Limited

13 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design Figure 1-2 Project Facility Locations Shell Canada Limited March 2013 Page 1-3

14 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project A North Saskatchewan River Expansion 1 Bitumen Processing Train Hydrogen Manufacturing Unit Shell Chemical Plant 215A N Legend Proposed CO2 Capture Infrastructure Existing Scotford Upgrader Facilities Scotford Expansion 1 Upgrader Facilities Not to scale 1 Tank Farm x Flare 2 A & V Unit RHC-IHT Unit Water and Discharge Ponds Sulphur Recovery Hydrogen Manufacturing Unit Scotford Refinery No Existing Scotford Upgrader Facilities CO2 Pipeline Description Storm water ponds Dilbit and diluent metering and pumping Water treatment Cooling tower Central Control Building Utilities and Cogeneration Figure 1-3 Capture Unit Location Schematic Extensive work was done during the Define Phase to validate the BCS formation CO 2 storage properties and to establish the optimum storage location. Figure 1-4 shows the BCS storage complex. Figure 1-5 shows the approved sequestration lease boundary (ASLB, formerly called the area of interest [AOI], which had a different boundary) for the storage area. Criteria for this selection included validating the BCS properties within the location, minimizing the number of legacy wells into the BCS storage complex (to reduce risk of potential leak paths), and avoiding proximity to densely populated areas (to minimize the number of landowner consents for the pipeline and injection wells). Section 3 contains additional details on the selection and properties of the BCS formation. March 2013 Page 1-4 Shell Canada Limited

15 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design Figure 1-4 BCS Storage Complex within the Regional Stratigraph Shell Canada Limited March 2013 Page 1-5

16 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project Figure 1-5 Project Components and Approved Sequestration Lease Boundary March 2013 Page 1-6 Shell Canada Limited

17 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design A critical requirement of the Project was that the storage area be available for use and not be impeded by other future CCS projects. To that end, pore space tenure was applied for by Shell to the Province of Alberta immediately after CCS pore space regulations were passed. This tenure granted in May 2011 for the exclusive use by Shell of the BCS formation for the Project within the ASLB depicted in Figure 1-5. This exclusive use allows Shell to store the design volumes of CO 2 into the formation without the risk of another CCS operator storing CO 2 in proximity to the ASLB (this would raise the required injection pressures and threaten the storage area viability). 1.5 Process Design The process flow scheme for the Project is shown in Figure 1-6. Figure 1-6 Capture and Compression Process Design Shell Canada Limited March 2013 Page 1-7

18 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project Process Description CO 2 Absorption Section Amine absorbers located within HMU 1 (Unit 241), HMU 2 (Unit 242) and HMU 3 (Unit 441) treat hydrogen raw gas at high pressure and low temperature to remove CO 2 through close contact with a lean amine (ADIP-X) solution consisting of 40% MDEA, 5% piperazine (DEDA) and 55% water. The hydrogen raw gas enters the 25-tray absorbers below tray 1 of the column at a temperature of 35 C and pressure of approximately 3,000 kpa(g). Lean amine solution enters at the top of the column on flow control at a temperature of 30 C. The CO 2 absorption reaction is exothermic, resulting in the treated gas leaving the top of the absorber at 39 C. The bulk of the heat generated within the absorber is removed through the bottom of the column by the rich amine, which has a temperature of 64 C. Rich amine from the three absorbers is collected into a common header and sent to the amine regeneration section. Warm treated gas exits the top of the absorbers and enters the 9-tray water wash vessels below Tray 1, where a circulating water system is used to cool the treated gas to a temperature of 35 C. Pumps draw warm water from the bottom of the vessel and cool it to 33 C in shell and tube exchangers using cooling water as the cooling medium. The cooled circulating water is returned to the water wash vessel above Tray 6 to achieve the treated gas temperature specification. A continuous supply of wash water is supplied to the top of the water wash vessel in the polishing section. The purpose of the water wash is to remove entrained amine to less than 1 ppmw; thereby, the downstream PSA unit adsorbent is protected from contamination. A continuous purge of circulating water, approximately equal to the wash water flow, is sent from HMU 1 and HMU 2 to the reflux drum in the amine regeneration section for use as makeup water to the amine system. The purge of circulating water from HMU 3 is sent to the existing process steam condensate separator, V Amine Regeneration Section Rich amine from the three absorbers is heated in the lean/rich exchangers by crossexchange with hot, lean amine from the bottom of the amine stripper. The lean/rich exchangers are Compabloc design to reduce plot requirements. The hot, lean amine is maintained at high pressure through the lean/rich exchangers by a back pressure controller, which reduces two-phase flow in the line. The pressure is let down across the 2 x 50% back-pressure control valves and fed to the amine stripper. The two-phase feed to the amine stripper enters the column through two Schoepentoeter inlet devices, which facilitate the initial separation of vapour from liquid. As the lean/rich amine flows down the trays of the stripper, it comes into contact with hot, stripping steam, which causes desorption of the CO 2 from the amine. The amine stripper is equipped with 2 x 50% kettle reboilers that supply the heat required for desorption of CO 2 and produce the stripping steam required to reduce the CO 2 partial pressure. The low-pressure steam supplied to the reboilers is controlled by a feed-forward flow signal from the rich amine stream entering the stripper and is trim-controlled by a temperature signal from the overhead vapour leaving the stripper. March 2013 Page 1-8 Shell Canada Limited

19 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design The CO 2 stripped from the amine solution leaves the top of the amine stripper saturated with water vapour at a pressure of 54 kpa(g). This stream is then cooled by the overhead condenser to a temperature of 36 C. The two-phase stream leaving the condenser enters the reflux drum, where separation of CO 2 vapour from liquid occurs. In addition to the vapour liquid stream from the overhead condenser, the reflux drum also receives purge water from the HMU 1 and HMU 2 water wash vessels, as well as knockout water from the CO 2 compression area. The reflux pumps draw water from the drum and provide reflux to the stripper for cooling and wash of entrained amine from the vapour. Column reflux is on flow control, with drum level control managed by purging excess water to wastewater treatment. CO 2 is stripped from the rich amine to produce lean amine to a specification of 0.03 (mol CO 2 )/(mol amine) by kettle-type reboilers and collected in the bottom of the amine stripper. Hot, lean amine from the bottom of the stripper is pumped by the lean amine pumps to the lean/rich exchanger, where it is cooled by cross-exchange with the incoming rich amine feed from the HMU absorbers. The lean amine is further cooled to 50 C by the lean amine coolers, which use 25 C cooling water in shell and tube exchangers. The lean amine is cooled to the final temperature of 30 C by the lean amine trim coolers, which are plate and frame exchangers using cooling water supplied at 25 C. A slipstream of 25% of the cooled lean amine flow is filtered to remove particulates from the amine. A second slipstream of 5% of the filtered amine is then further filtered through a carbon bed to remove degradation products. A final particulate filter is used for polishing of the amine and removing carbon fines from the carbon-bed filter. The filtered amine is then pumped by the lean amine charge pumps to the three amine absorbers in HMU 1, HMU 2, and HMU 3. Anti-Foam Injection An anti-foam injection package is provided to supply anti-foam to the amine absorbers and amine stripper. Because there are minimal hydrocarbons present in the system and the service is considered clean, it is anticipated that foaming issues should be minimal. Should the need arise, anti-foam can be injected into the lean amine lines going to each of the absorbers, as well as the rich amine line supplying the amine stripper. The anti-foam chemical currently identified for use in this system is polyglycol-based anti-foam. The actual anti-foam injection chemical required cannot be confirmed until the facility is operating. Amine Storage Two amine storage tanks, along with an amine make-up pump, supply pre-formulated concentrated amine as make-up to the system during normal operation. The concentrated amine will be blended off-site and provided by an amine supplier. The amine concentration for the initial fill at start-up will be based on 40% wt MDEA and 5% wt DEDA. During normal operation, losses of DEDA will exceed losses of MDEA; therefore, the makeup amine concentration will be slightly different in order to maintain the overall concentrations at the design values. The amine storage tanks will also be used for storage of lean amine solution during maintenance outages. The size of the amine storage tanks provides sufficient volume for Shell Canada Limited March 2013 Page 1-9

20 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project the amine stripper contents during an unplanned outage. Permanent amine solution storage is not provided for the entire amine inventory, which would require supplemental temporary storage. During major turnarounds, when the entire system needs to be deinventoried, a temporary tank will be required for the duration of the turnaround. The amine system can be recharged with the lean amine solution using the amine inventory pump. This pump will also be used to charge the system during start-up. The amine storage tanks are equipped with a steam coil to maintain the tank contents at 40 C. A nitrogen blanketing system maintains an inert atmosphere in the tank, which prevents degradation of the amine. The storage tanks will have ventilation to the atmosphere. Compression The CO 2 from amine regeneration is routed to the compressor suction by the compressor suction KO drum to remove free water. The CO 2 compressor is an eight-stage, integrally geared centrifugal machine. Further details of compressor performance will be developed through collaboration with the selected vendor and integrated with the control requirements of the pipeline system. Increase in H 2 impurity from 0.67% to 5% in the CO 2 increases the minimum discharge pressure required (to keep CO 2 in a dense-phase state) to about 8,500 kpa(g). Though the compressor design is still under development, H 2 impurity greater than 5% may lead to potential surge situations. To avoid this situation, it is proposed to put compressor in recycle mode when the H 2 content reaches 2.5%. Cooling and separation facilities are provided on the discharge of the first five compressor stages. The condensed water streams from the interstage KO drums are routed back to the stripper reflux drum to be degassed and recycled as make up water to the amine system. The condensed water from the compressor fifth and sixth stage KO drums and the TEG inlet scrubber are routed to the compressor fourth stage KO drum. This routing reduces the potential of a high pressure vapour breakthrough on the stripper reflux drum and reduces the resulting pressure drops. The seventh stage KO drum liquids are routed to the TEG flash drum due to the likely presence of TEG in the stream. The saturated water content of CO 2 at 36 C approaches a minimum at approximately 5,000 kpa(a). Consequently, an interstage pressure in the 5,000 kpa(a) range is specified for the compressor. This pressure is expected to be obtained at the compressor sixth stage discharge. At this pressure, the wet CO 2 is air cooled to 36 C and dehydrated by triethylene glycol (TEG) in a packed bed contactor. The dehydrated CO 2 is compressed to a discharge pressure in the range of 8,000 kpa(g) to 11,000 kpa(g), resulting in a dense-phase fluid. The CO 2 compressor is able to provide a discharge pressure as high as 14,790 kpa at a reduced flow for start-up and other operating scenarios. The dense-phase CO 2 is cooled in the compressor, after the cooler, to 43 C, and routed to the CO 2 pipeline. This dense-phase CO 2 is transported by pipeline from the Scotford Upgrader to the injection wells. March 2013 Page 1-10 Shell Canada Limited

21 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design Dehydration A lean triethylene glycol (TEG) stream at a concentration greater than 99% wt TEG contacts the wet CO 2 stream in an absorption column to absorb water from the CO 2 stream. The water-rich TEG from the contactor is heated and letdown to a flash drum that operates at approximately 270 kpa(g). This pressure allows the flashed portion of dissolved CO 2 from the rich TEG to be recycled to the compressor suction KO drum. The flashed TEG is further preheated and the water is stripped in the TEG stripper. The column employs a combination of reboiling, by a stab-in reboiler using low temperature HP steam, and nitrogen stripping gas to purify the TEG stream. Nitrogen stripping gas is required to achieve the TEG purity required for the desired CO 2 dehydration because the maximum TEG temperature is limited to 204 C to prevent TEG decomposition. Stripped water, nitrogen and degassed CO 2 are vented to atmosphere at a safe location above the TEG stripper. Though the system is designed to minimize TEG carryover, it is estimated that 27 ppmw of TEG will escape with CO 2. The dehydrated CO 2 is analyzed for moisture and composition at the outlet of TEG unit. The lean TEG is cooled in a lean/rich TEG exchanger. The lean TEG is then pumped and further cooled to 39 C in the lean TEG cooler with cooling water and returned to the TEG absorber. Pipeline The pipeline design is a 12-inch high vapor pressure (HVP) pipeline for transporting the dehydrated, compressed, and dense-phase CO 2 from the capture facility to the injection wells. Also included are pigging facilities, line break valves, and monitoring and control facilities. The line is buried to a depth of 1.5 m with the exception of the line break valve locations, which are located a maximum of 15 km apart. In the Select Phase of the Project, a detailed route selection process was undertaken with the objective to: limit the potential for line strikes and infrastructure crossings align with the CO 2 storage area use existing pipeline rights-of-way and other linear disturbances, where possible, to limit physical disturbance limit the length of the pipeline to reduce the total area of disturbance avoid protected areas and using appropriate timing windows avoid wetlands and limit the number of watercourse crossings accommodate landowner and government concerns to the extent possible and practical Shell Canada Limited March 2013 Page 1-11

22 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project The outcome of this process is the routing shown in Figure 1-2. The pipeline route extends east from Shell Scotford along existing pipeline rights of way through Alberta s Industrial Heartland and then north of Bruderheim to the North Saskatchewan River. The route crosses the North Saskatchewan River and continues north along an existing pipeline corridor for approximately 10 km, where the route angles to the northwest to the endpoint well, approximately 8 km north of the County of Thorhild, Alberta. The total pipeline length is about 80 km. This pipeline crosses the counties of Strathcona, Sturgeon, Lamont and Thorhild. There are 256 crossings by the pipeline: 40 road crossings 4 railroad crossings 18 watercourse crossings 73 pipeline crossings 121 utility crossings CO 2 Storage The storage facilities design and construction activities consist of: the drilling and completion of three to eight injection wells equipped with fibre optic monitoring systems a skid-mounted module on each injection well site to provide control, measurement and communication for both injection and MMV equipment the drilling and completion of a minimum of three deep observation wells the conversion of Redwater Well 3-4 to a deep BCS pressure monitoring well the drilling of three groundwater wells per injection well (although not all will be located on the well pads) a field trial of the line-of-sight CO 2 gas flux monitoring technology with an option to include this at each injection well site location 1.6 Modularization Approach A key feature of the FEED work for the Project was the decision to use a modularization approach for the CO 2 capture infrastructure for the benefit to scheduling and cost. The modularization approach for the Project is to use Fluor Third Generation Modular SM design practices. The Project is designed with a maximum module size of 7.3 m (wide) x 7.6 m (high) x 36 m (long) modules that are assembled in the Alberta area and transported by road to the Shell Scotford site by the Alberta Heavy Haul corridor. March 2013 Page 1-12 Shell Canada Limited

23 Quest Carbon Capture and Storage Project Section 1: Overall Facility Design Third Generation Modular SM execution is a modular design and construction execution method that is different from the traditional truckable modular construction execution methods because limitations exist to the number of components that are to be installed onto the truckable modules. The modules are transported and interconnected into a complete processing facility at a remote location including all mechanical, piping, electrical and control system equipment. The module s boundaries were reflected in the 3 dimensional model and matured through 30%, 60% and 90% model reviews of multi-disciplinary teams as well as safety, operability and maintainability reviews. The weight and dimensions of each model were accurately tracked through the process to ensure compliance with the maximum weight and size restrictions for the heavy load corridor. The structural steel manufacturing and fabrication for the modules was bid, awarded and manufacture of the steel commenced in In August of 2012, a request for proposal went out to five pre-qualified module yard contractors on the heavy load corridor. Proposals were received in October and evaluated thereafter. Award recommendations were made to Shell s contract board in mid-january 2013 followed by approval by the Joint Venture Executive Committee late in January The contract was signed in February. Fabrications of the structural steel for the modules started in early February and in mid-february, kick off meetings were held in the module yard to start the preparation work to start module pipe fabrication and module construction. Shell Canada Limited March 2013 Page 1-13

24 Section 1: Overall Facility Design Quest Carbon Capture and Storage Project March 2013 Page 1-14 Shell Canada Limited

25 Quest Carbon Capture and Storage Project Section 2: Facility Construction Schedule 2 Facility Construction Schedule As of March 2013, the early works construction activities including the installation of the amine sump, underground cooling water, firewater, oily water and inside battery limits of the CO 2 pipelines, underground electrical and installation of all the piles are in various stages of completion. The foundation work is the last part of the early works and is due to start in late April or early May The current manpower on site is approximately 150 people. Module fabrication, capture main construction and pipeline construction readiness activities have commenced as detailed engineering is completed in the near future. See Figure 2-1 for the overall construction schedule. Upon award of the module contract, kickoff meetings were held to establish expectations and start the planning processes required to start the actual fabrication. Engineering and equipment and material deliveries are on track to meet the module fabrication schedule. Two injection wells, three deep monitoring wells and four groundwater monitoring wells have been drilled, completed and tested. A plant turnaround is planned for April and May 2013 in the second train of the base plant allowing the tie-ins as well as the burner upgrades, installation of the flue gas recycle and the pressure swing absorber are completed. The flue gas recycle will be commissioned and started up when HMU #2 comes back on stream after the turnaround. The main construction activities will commence after the turnaround in June with firewater and cooling water modification as well as foundation and steel work in preparation for module construction. Structural steel fabrication has already commenced and pipe spooling will start in the May to support the module completion schedule. The modules will start to arrive in mid-august of 2013 with the last module scheduled to arrive at site in mid April Construction will start on the compressor building in August of 2013 with the compressor arriving in October. The three absorber towers and the stripper will be dressed at site starting with HMU #3 absorber in late September HMU #3 turnaround is planned for the spring of Workforce is expected to ramp up during 2013 and peak in early 2014 around between 450 and 600 workers. Pipeline construction is scheduled to begin in mid-2013 kicking off with the horizontal drill under the North Saskatchewan River and some of the major rail and road crossings. Pipeline construction will be completed prior to spring break up in 2014, with well site leases and line block valve installation later that spring. The pipeline workforce is expected to peak between 200 and 300 workers. Mechanical completion is scheduled for late September in HMU #3 and the main capture facility. This will allow commissioning and start up to begin in those areas. The spring 2015 turnaround of HMU #1 area and the base plant common facilities will be required to complete the final tie-ins and modification to that HMU. All construction activities are phased to meet the planned startup in Q Shell Canada Limited March 2013 Page 2-1

26 Section 2: Facility Construction Schedule Quest Carbon Capture and Storage Project At January Quest Project MC ( P50 ): 3rd Gen. Modules Model P50Reviews Module Fab. & Assembly Module Delivery Capture Construction: Early Works Start Module Fab. Start Pipe Fab. Start Mod Assly.. Deliver last CO2 Mod Current Deterministic Plan P10 P90 Current Deterministic Plan F/C Critical Milestone Contingency Duration U/G Piping/Elect. FGR - Piling/Mech./E&I Capture Field Major Const. Piling and Foundations Steel and Bldg Erection Module Setting Mechanical & Piping Electrical & Instrumentation Wells Commissioning SO (Sustained Ops) Well # 2, 3 & Deep M & Water Wells HMU-2 T/A & Elect. Tie ins HMU 2 FGR Piling Complete Fdtn. Start Compr. Bldg Compr Bldg. shell erection ISBL P/L HDD Fdtn. Comp. P/R Module HMU Modules Set Compressor Stripper Main P/L Constr. HMU 3 Absorber HMU T/A Last Module Precomm Final Grade HMU1&2 MC HMU3 & Capture MC Well # 1 S/up HMU T/A & Flare Tie ins MC Well # 1 Monitoring S/Up Well # 2 & HMU s S/up SO March 2013 Page 2-2 Shell Canada Limited

27 Quest Carbon Capture and Storage Project Section 2: Facility Construction Schedule Figure 2-1 Project Construction Schedule Shell Canada Limited March 2013 Page 2-3

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29 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection 3 Geological Formation Selection 3.1 Storage Area Selection A screening process resulted in a preferred storage area that was initially selected for further appraisal and studies in 2010 and 2011 by submitting an exploration tenure request with the regulator on December 16, The subsequent process of storage area characterization comprised a period of intensive data acquisition, resulting in storage area endorsement prior to submitting the regulatory applications on November 30, 2010 and culminating in the award of a Carbon Sequestration Leases by Alberta Energy on May 27, Storage area selection was mainly based on data, analyses and modeling of the two CO 2 appraisal wells with supplemental data from legacy wells, seismic and study reports. Storage area selection criteria for CCS projects are still in the process of being developed by CCS authorities at international, national and provincial levels. One set of criteria has been developed by the Alberta Research Council (ARC) and the properties of the Basal Cambrian Sands (BCS) are compared with those criteria in Table 3-1. The approved sequestration lease boundary (ASLB), as defined by the approved Carbon Sequestration Leases and pursuant to Section 116 of the Mines and Minerals Act, was granted to Shell, on behalf of the ASOP Joint Venture, by the Alberta Department of Energy. Shell Canada Limited March 2013 Page 3-1

30 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project Table 3-1 Assessment of the BCS for Safety and Security of CO 2 Storage Criterion Level No Criterion Unfavourable Preferred or Favourable BCS Storage Complex Critical 1 Reservoir-seal pairs; extensive and competent barrier to vertical flow Poor, discontinuous, faulted and/or breached 2 Pressure regime Overpressured pressure gradients >14 kpa/m Intermediate and excellent; many pairs (multi-layered system) Pressure gradients less than 12 kpa/m 3 Monitoring potential Absent Present Present 4 Affecting protected groundwater quality Yes No No Essential 5 Seismicity High Moderate Low 6 Faulting and fracturing intensity 7 Hydrogeology Short flow systems, or compaction flow, Saline aquifers in communication with protected groundwater aquifers Three major seals (Middle Cambrian Shale [MCS], Lower Lotsberg and Upper Lotsberg Salts) continuous over the entire ASLB. Salt aquicludes thicken up dip to the northeast. Normally pressured <12 kpa/m Extensive Limited to moderate Limited. No faults penetrating major seal observed on 2D or 3D seismic. Intermediate and regional-scale flow Desirable 8 Depth < m > 800 m > 2,000 m 9 Located within fold belts Yes No No 10 Adverse diagenesis Significant Low Low 11 Geothermal regime Gradients 35 C/km and low surface temperature Gradients <35 C/km and low surface temperature 12 Temperature <35 C 35 C 60 C 13 Pressure <7.5 MPa 7.5 MPa MPa 14 Thickness <20 m 20 m >35 m 15 Porosity <10% 10% 16% Intermediate and regional-scale flow-saline aquifer not in communication with groundwater Gradients <35 C/km and low surface temperature March 2013 Page 3-2 Shell Canada Limited

31 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection Table 3-1 Assessment of the BCS for Safety and Security of CO 2 Storage (cont d) Criterion Level No Criterion Unfavourable Preferred or Favourable BCS Storage Complex Desirable (cont d) 16 Permeability <20 md 20 md Average over the ASLB md 17 Caprock thickness <10 m 10 m Three caprocks MCS 21 m to 75 m L. Lotsberg Salt 9 m to 41 m U. Lotsberg Salt 53 m to 94 m 18 Well density High Low to moderate Low SOURCE: CCS Site Selection and Characterization Criteria Review and Synthesis: Alberta Research Council, Draft submission to IEA GHG R&D Program June 2009: Shell Canada Limited March 2013 Page 3-3

32 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project 3.2 Geological Framework The BCS is at the base of the central portion of the Western Canada Sedimentary Basin (WCSB), directly on top of the Precambrian basement. The BCS storage complex is defined herein as the series of intervals and associated formations from the top of the Precambrian basement to the top of the Upper Lotsberg Salt (see Figure 3-1). The BCS storage complex includes, in ascending stratigraphic order: Precambrian granite basement unconformably underlying the Basal Cambrian Sands Basal Cambrian Sands (BCS) of the Basal Sandstone Formation the CO 2 injection storage area Lower Marine Sand (LMS) of the Earlie Formation a transitional heterogeneous clastic interval between the BCS and overlying Middle Cambrian Shale Middle Cambrian Shale (MCS)of the Deadwood Formation thick shale representing the first major regional seal above the BCS Upper Marine Siltstone (UMS) likely Upper Deadwood Formation progradational package of siliciclastic material made up of predominantly green shale with minor silts and sands Devonian Red Beds fine-grained siliciclastics predominantly composed of shale Lotsberg Salts Lower and Upper Lotsberg Salts represent the second and third (ultimate) seals, respectively, and aquiclude to the BCS storage complex. These salt packages are predominantly composed of 100% halite with minor shale laminae. They are separated from each other by 50 m of additional Devonian Red Beds. March 2013 Page 3-4 Shell Canada Limited

33 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection Figure 3-1 Stratigraphy and Hydrostratigraphy of Southern and Central Alberta Shell Canada Limited March 2013 Page 3-5

34 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project The rocks that comprise the BCS storage complex were deposited during the Middle Cambrian to Early Devonian directly atop the Precambrian basement. The erosional unconformity between the Cambrian sequence and the Precambrian represents approximately 1.5 billion years of Earth history. Erosion of the Precambrian surface during this interval likely resulted in a relatively smooth but occasionally rugose gently southwest dipping (<1 degree) top Precambrian surface. Within the ASLB, the Cambrian clastic packages pinch out towards the northeast, while the Devonian salt seals thicken towards the northeast. For a cross-section of the WCSB showing the regionally connected BCS storage complex in relation to regional baffles and sealing overburden, see Figure 3-2 (the AOI is the former name for the ASLB). The ASLB is within a tectonically quiet area; no faults crosscutting the regional seals were identified in 2D or 3D seismic data. Figure 3-2 Cross-Section of the WCSB Showing the BCS Storage Complex March 2013 Page 3-6 Shell Canada Limited

35 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection 3.3 Risk to Containment This section describes the various potential conduits that could permit migration of fluids out of the BCS storage complex. Mitigation measures are included, where applicable, for each risk. Migration along a Legacy Well The status and condition of existing wells penetrating the BCS has been reviewed from multiple data sources. There are no known issues with legacy well integrity other than the uncertainty that arises from the age of the cement plugs and the inability to pressure test old cement plugs. The following mitigation measures were implemented during storage area selection to reduce this risk: selection of an AOI (now replaced by the ASLB, which is a different boundary) with few BCS penetrations selection of an injection site to maximize the offset to legacy wells (21 km from the Shell Radway Well to the Egremont Well down-dip and 31 km from the Shell Radway Well to the Imperial Darling Well up-dip). 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 the well bore The probability of legacy wells being intersected by the CO 2 plume or brine pressures high enough to lift brine into the groundwater is very low. Detailed CO 2 plume migration modeling of a three-injection well scheme concluded that the most likely case results in a CO 2 plume length of only 4,100 m at the end of 25 years of injection. The dynamic model results indicate that the pressure build up in the BCS is expected to be less than 2 MPa of delta pressure at the perforations of the injection wells while flowing at the end of 25 years. A map of the pressure distribution for the Gen-4 expectation case with an analytic aquifer, infinitely acting on the southwest boundary is included in Figure 3-3. The MMV Plan described in Section 6 provides additional options for early warning through pressure monitoring, such as interferometric synthetic aperture radar (InSAR), with a BCS pressure calibration point at Redwater Well 3-4. Shell Canada Limited March 2013 Page 3-7

36 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project Delta P (MPa) Figure 3-3 Pressure Distribution after 25 Years of Injection in the Mid- Property/Mid-Connectivity Case with an Analytical Aquifer Extension Migration along an MMV Well The Storage Development Plan, a standard Project document deliverable that outlines the plan for categorizing and developing the anticipated storage area, does not include the addition of dedicated BCS MMV observation well penetrations for the following reasons: The selected MMV technologies of 4D seismic and InSAR are expected to provide conformance information with much better aerial coverage than any single well penetration can provide and without the additional risk of having to penetrate the seals of the BCS storage complex. The perceived benefits of additional BCS observation wells are limited because they have no ability to verify containment and are ineffective at conformance monitoring unless used in large numbers. March 2013 Page 3-8 Shell Canada Limited

37 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection The following factors reduce this risk: the use of Redwater Well 3-4 as a BCS pressure observation well all injection wells will be used as BCS observation wells pressure build up and interference will be monitored during the start-up period the well sparing philosophy allows for regular sequence of annual fall-off tests in injection wells (to be included in the operating guidelines) bottom-hole pressure (BHP) will be monitored during the closure period and sampling and logging are also possible InSAR, vertical seismic profile (VSP) and seismic are part of the initial Base Case MMV Plan InSAR will be calibrated to BCS pressure measurements from Redwater Well 3-4 BCS observation well Migration along an Injection Well Interpretation of data from drilling the first two appraisal wells (Well and Well 3-4), regional drilling experience, and wellbore stability and mud testing led to Well 8-19 being drilled, cased and cemented with hydraulic isolation over all three seals. Drilling a gauge hole has proved critical to achieving good cement integrity over the seals of the BCS storage complex and using oil-based mud, combined with an intermediate casing setting depth just below the base of the MCS. This practice was applied to the second and third injection wells drilled in The seals have been analyzed from the resultant well data and they exhibit a high integrity. 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 ASLB (Radway Well 8-19). The following factors reduce this risk: 2D seismic covers (with a spacing of 2 km to 3 km) the entire ASLB and shows continuity of the geological seals. Every legacy well in the ASLB has confirmed the presence of all three seals. Lotsberg seal thickness LL 9-41 m and UL m suggest low likelihood of local gaps. Tortuosity of leak path shows that seal breaches are unlikely to align. Buffering effects of a long leak path reduce the risk. BCS and WPGS water chemistry differences suggest long term isolation of these aquifers from each other. The cleanest shales are at the bottom of the MCS section and will erode last, by the Devonian unconformity towards the northeast. Shell Canada Limited March 2013 Page 3-9

38 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project Migration along an Open Fault Pathway The 3D seismic data now covers approximately 415 km 2, which is about 11% of the ASLB. The latest processed data, available since April 2011, indicate increased frequency content of the data (up to 100 Hz) that for the first time allows for an interpretation of whether a migration event near the top BCS could occur. The absence of interpreted faults continuing from the top Precambrian interval to the top of BCS on the 3D seismic dataset reduces the probability of the presence of migration path faults across the BCS reservoir or any of the seals. The following factors reduce this risk: Faults are absent on the Precambrian granite seismic interval. There is no evidence of no faults with throws greater than 15 m crossing the seal complex from 2D and 3D seismic covering the full ASLB. The 2D seismic spans the entire ASLB with an approximate 3 km spacing and 415 km 2 of 3D seismic is available over the central portion of the ASLB. There is a period of approximately 1.5 billion years between the granite and the deposition of the BCS. Therefore, it is unlikely that any Precambrian faults were active in the BCS time of deposition. 3D seismic was used to select injection well locations away from features that may represent faults at the Precambrian basement level. The Lotsberg salts are ductile and expected to creep and reseal any unexpected small faults. Induced Stress Reactivates a Fault In line with the very low likelihood of the presence of faults intersecting either the BCS or any of the seals in the storage complex, there is a very low likelihood of fault reactivation. The following factors reduce this risk: The ASLB is not an area of active natural seismicity. There has been a regional seismic monitoring network in place for more than 80 years with a capability of detecting a magnitude 3 event within the ASLB. None were detected over this period as indicated by the AGS Tectonic activity map for Alberta: No faults offsetting the MCS or Lotsberg seals were mapped in the ASLB using 2D seismic, which spans the entire ASLB with an approximate 3 km spacing and 415 km 2 of 3D seismic. 3D seismic will help place injection wells away from features that may represent faults at the Precambrian basement level. The Lotsberg salts are ductile and expected to creep and reseal any unexpected small faults. Compressor discharge pressure is limited to 14.5 MPa (900# pipe class). March 2013 Page 3-10 Shell Canada Limited

39 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection Down-hole gauges will be deployed to ensure that injection wells stay within pressure constraints using well head chokes to control pressure. Under normal operating conditions, injection will be distributed over the final number of injection wells. The system will be designed to stay below the maximum injection pressure constraint for one injection well less than the total number of injection wells, resulting in pressures below the maximum constraint for most of the time at the injection wells. Down-hole microseismic monitoring will detect any fault reactivation within 600 m of an injection well; injection pressure can be reduced if any reactivation is detected. Induced Stress Opens Fractures Minifrac data from Redwater Well and Radway Well 8-19 suggest good alignment of the BCS fracture extension pressure (FEP) between these wells, which are 36 km apart. A conservative approach has been taken by setting the BHP limitation at 28 MPa, based on the weaker LMS fracture gradient and including a 4 MPa safety margin to account for the reduction in fracture gradient due to the thermal impact of CO 2 injection. Mitigating actions to address this risk include: Compressor discharge pressure is limited to 14.5 MPa (900# pipe class). Down-hole gauges will be deployed to ensure that injection wells stay within pressure constraints using well head chokes to control pressure. Under normal operating conditions, and assuming the three injection well scenario, the injection will be distributed over the three wells. The system will be designed in this case to stay below the maximum injection pressure constraint for two injection wells, resulting in pressures below the maximum constraint for most of the time at the injection wells. Acidic Fluid Erodes Seals Several MCS cores were acquired in the first few injection wells. The first seal (MCS) contains small quantities of dolomite and K-feldspar. The dissolution of these minerals in a low-ph CO 2 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). Absence of experimental data does not allow this uncertainty in time range to be reduced. Shell was granted permission from ATCO Gas and Pipelines Ltd. in March 2011, to take nine plugs from their Upper Lotsberg core at W400 for SCAL analysis. A SCAL program comprising the following elements is ongoing: high resolution photos of the core and the salt plugs, including proper depth marking thin section and petrography to determine salt composition Shell Canada Limited March 2013 Page 3-11

40 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project The following factors reduce the risk: Thickness of seals and baffles that need to be eroded are 350 m from top perfs to the top ultimate seal. Buffering materials (mostly clay minerals) in the seals and baffles between the salt seals and the top perfs are abundant. CO 2 leaking into the seals/baffles will lose moisture and acidity. The secondary and ultimate seals, the Upper and Lower Lotsberg salts respectively, comprise 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. Seal integrity relies on stresses and may not be affected by seal embrittlement. Third Party Induced Migration This risk includes the drilling of new wells and pressurizing of the BCS as separate causes, both of which could lead to loss of containment. The risk of third-party drilling into the ASLB has been eliminated because the Carbon Sequestration Leases, granted to Shell on May 27, 2011, prohibits the drilling by third-parties below the Prairie Evaporite within the ASLB. The risk of pressurization of the BCS resulting in increased legacy well risk is also much reduced through the size of the approved Carbon Sequestration Leases, which provides a minimum 25 km offset from the development area to the ASLB boundary. 3.4 Estimate of Storage Potential The uncertainty in the capacity of the storage area, the BCS storage complex, has been reduced considerably over time due to appraisal data gathering (three appraisal wells, 2D seismic, 3D seismic and the ongoing reservoir modeling and feasibility studies). There is continued strong evidence for the BCS having the capacity to store the required volume for 25 years of injection. The residual uncertainty in pore volume is unlikely to decrease much further until several years of injection performance can be used to calibrate the existing reservoir models. The latest full-field static reservoir models describe the range of subsurface uncertainty in terms of reservoir quality and reservoir connectivity, both being key uncertainties that influence the maximum achievable injection rates into the reservoir (i.e., k*h), the plateau length of that injection rate and the total amount of CO 2 that can be injected. The range of uncertainty in BCS pore volume equates to water initially in place (WIIP), given 100% water saturation. The range is presented in Table 3-2 and can be related to three main variables: the presence of a depositional trend affects reservoir quality the thickness of the BCS unit risk of systematic error in the measurement of porosity from well logs March 2013 Page 3-12 Shell Canada Limited

41 Quest Carbon Capture and Storage Project Section 3: Geological Formation Selection Table 3-2 BCS Pore Volume Range within the ASLB Case Reservoir Connectivity Reservoir Quality Sum Pore Volume in the ASLB (m 3 ) P90 High High 1.62E+10 P50 Mid Mid 1.43E+10 P10 Low Low 1.08E+10 Using a material balance calculation: Using the mid-case properties: G CO2 = A h g f tot r (c p + c w ) (p-p 0 ) Pres = 20 Mpa, Pmax = of 28 MPa, Temp = 60 C, Cp = 1.45 E-7, Cw = 2.78 E-7, r = 814 kg/m 3 A base case pore volume of 14.3 billion m 3 within the ASLB could store 27 Mt of CO 2 at just under 70% potential storage capacity. This is an extremely conservative calculation because displacement of water outside the ASLB relieves all of the pressure over time. Detailed pressure modeling indicates that this 27 Mt of CO 2 can be injected while bringing the reservoir pressure up to 24 MPa (compared to the BHP limitation of 28 MPa). This pressure disperses after shut-in. 3.5 Initial Injectivity Assessment Two water injection tests were conducted during exploration and appraisal. Injectivity was estimated using average pressures and flow rates for the last stable flow period of the Redwater Well water injection test and the fifth and final Radway Well 8-19 water injection test. A summary of these results is provided in Table 3-3. Additional injectivity results will be available later in 2013 after testing is complete on the second and third injection wells. Table 3-3 Injectivity Estimates for Redwater Well and Radway Well 8-19 Water Injection Tests Well Rate [m 3 /d] DeltaP [kpa] Injectivity [m 3 /d/mpa] Redwater Well Radway Well Shell Canada Limited March 2013 Page 3-13

42 Section 3: Geological Formation Selection Quest Carbon Capture and Storage Project Injectivities can be used to extrapolate estimated water injection rates to the pressure differential associated with normal operating conditions. In this case, operating conditions were assumed to correspond to a flowing bottom-hole pressure of approximately 26 MPa, about 6 MPa above initial reservoir pressure at top of the BCS in Radway Well Water injection rates are converted to CO 2 injection rates by making assumptions on the fluid property differences between the injected water and the CO 2 (i.e., viscosity) and the CO 2 /brine displacement model (relative permeabilities). Taking these factors into account, CO 2 is expected to inject at rates that are a ratio of 1.5 to 3 times higher than water injection rates (expressed in reservoir volume). Figure 3-4 illustrates the several steps required to compare well test rates to estimate injection requirements. Figure 3-4 illustrates that Radway Well 8-19 is expected to provide sufficient initial injectivity to take the full CO 2 volume into a single well. Figure 3-4 Actual Well Test Injectivity versus Full Project Injection Requirements March 2013 Page 3-14 Shell Canada Limited

43 Quest Carbon Capture and Storage Project Section 4: Facility Operations Capture Facilities 4 Facility Operations Capture Facilities 4.1 Operations Activities Operations activities for the past reporting period focused on several key areas. One of them is providing design input to the engineering model reviews for the capture facilities. Members of the operations, maintenance, and engineering disciplines have been very active in these reviews and supporting the Project and construction teams. As the construction began, the operations team also was involved in activities related to interface management between Shell Scotford and the construction team. This includes such activities to clarity responsibilities around site access, permitting, and HSE interface. Another key activity for operations readiness is implementing a program called Flawless that helps with achieving a smooth commissioning and start-up of the Project. This activity identifies lessons learned from other projects and common issues during start-up and embeds the elements of the program to manage these risks. The Flawless work is ramping up and integrating the program into the various procurement and construction activities. Preparing the site for the future operation of the capture facility, pipeline, and wells is a key role. To do this, Shell is ensuring that all the key management system aspects that Shell Scotford currently utilizes are covered. Maintenance planning and execution activity preparation is ongoing and a key activity that has been completed is the identification of the preventative maintenance activities required for the capture facility. Preparation activities are underway for the commissioning of the flue gas recycle facility on one of the HMUs. This facility is required to help manage the NO X emissions once CO 2 is removed from the fuel gas system. This is a new application to the hydrogen reformer process although it has been successfully used in boilers in other processes. More detailed commissioning and startup planning continues and the final operations organization chart has been completed. There will be an additional 14 team members hired in 2013 to provide 29 Project operations team members. Shell Canada Limited March 2013 Page 4-1

44 Section 4: Facility Operations Capture Facilities Quest Carbon Capture and Storage Project 4.2 Next Steps Key operations activities for 2013 and early 2014 include the following: Flue Gas Recycle - Preparation for and commissioning of the flue gas recycle system. Turnaround Scope - Execution of the turnaround work required for one of the HMUs at Shell Scotford that includes burner modifications, pipe connections, adsorbent change out, and flue gas recycle work. Hiring and Onboarding - Hiring of operations, maintenance, and engineering personnel to support the commissioning and start-up (CSU) of the Project facilities. Utilize external networks to strengthen skills and competencies with pipeline, subsurface, and CO 2 operations. Activity Base CSU Plan - Detailed CSU planning that identifies all resources required at the various stages of the commissioning and start-up. Pre-Start-Up Safety Reviews on Engineering and Design Continue Operations Management System alignment work with Shell Scotford Project to Asset Transition Plan Implement the transition plan so that all key aspects of deliverables from the Project are transitioned to Shell Scotford. This includes such things as materials, documents, and drawings. March 2013 Page 4-2 Shell Canada Limited

45 Quest Carbon Capture and Storage Project Section 5: Facility Operations - Transportation 5 Facility Operations - Transportation 5.1 Pipeline Design The pipeline has the general design conditions as outlined in Table 5-1. Discussion of the design specifications follow. Table 5-1 Pipeline Design and Operating Conditions Characteristic Specification Units Value General Pressure Normal MPa 8.5 to 14 pending flow assurance study results and well results At inlet Design minimum 8 MPa Design maximum Estimated Delta P to well site Temperature (@ Comp Discharge) Deg C Normal (Winter) 43 Normal (Summer) 43 Upset condition Flow rates Normal Mt/a 1.2 Design minimum MPa 0.4 (for three-well scenario) 60 (max summer, cooling unit down) Main Flow Line Data Length ~80 Size In NPS 12 Wall thickness mm 12.7 ( CA) Laterals Data Length Variable Size In NPS 6 Wall thickness mm 7.9 ( CA) Reservoir pressure MPa Reservoir temperature Deg C 63 Well bore tubing diameters NPS/ID mm 4.5/99.06 Well depth m 2,070 Shell Canada Limited March 2013 Page 5-1

46 Section 5: Facility Operations - Transportation Quest Carbon Capture and Storage Project Pipeline Fluid Composition The composition is described in Table 5-2. Table 5-2 Pipeline Fluid Composition Component Normal Composition Upset Composition CO H CH CO N Total Pipeline Pressure Data Pipeline Design Pressure C Maximum Operation Pressure Minimum Operation Pressure (10% higher than Critical Pressure) CO 2 Critical Pressure Pipeline Operating Temperature 14.0 MPa 8.5 MPa 7.4 MPa The temperature of the CO 2 leaving the Scotford Upgrader will be approximately 43 C. As the CO 2 travels in the pipeline, heat is transferred to the soil. At approximately 20 km from Shell Scotford, the CO 2 will be at ground temperature. For the basis of design, a ground temperature of 4 C was assumed during summer and 0 C during winter. Due to the CO 2 being cooled throughout the pipeline length, it is deemed unnecessary to provide for thermal relief. Flow Rate Requirements Design capacity of the pipeline throughput is to be 1.2 Mt/a. The CO 2 pipeline is designed so that it could receive and transport up to an additional 2.2 Mt/a of CO 2, in excess of the 1.2 Mt/a of CO 2 that would be captured and stored, should there be a commercial option to receive additional CO 2 from a third party. Water Content and CO 2 Phase Change Management The CO 2 will be dehydrated to a water content of 6 lb/mmscf during summer and 4 lb/mmscf during winter within the capture facilities. A moisture analyzer will be installed between the sixth and seventh stages of the compressor. There will be a sampling procedure to confirm the moisture analyzer measurement. Design Life Design life for the pipeline and associated surface facilities is for the remaining life of the Scotford Upgrader, approximately 25 years. March 2013 Page 5-2 Shell Canada Limited

47 Quest Carbon Capture and Storage Project Section 5: Facility Operations - Transportation Pipeline Steel Grade Items that have been identified as a possible concern for CO 2 pipelines include long running ductile fracture (LRDF) and explosive decompression of elastomers. Shell Global Solutions, through Shell s Calgary Research Center (CRC), has performed material testing in order to determine the appropriate elastomers to minimize explosive decompression and the appropriate grade of steel with sufficient toughness to resist LRDF. Results from the LRDF testing show that the toughness requirements for the line pipe are quite achievable in commercially available steel grades, as verified by past history. Specifically, CSA Z245.1 Gr. 386 Cat II pipe would need a minimum wall thickness of 11.4 mm plus corrosion allowance (1.3 mm), and a minimum toughness of 60J at 45 C. 5.2 Pipeline Safeguarding Considerations Line Break Valves As per Class 2 requirements for CSA Z662, line break valves (LBVs) will be spaced at no greater than 15 km intervals. The line break valves will be placed in areas near secondary roads, which allows for ease of access by operations and maintenance personnel. Because the LBVs are located in populated areas, they will be fenced for security. Currently, the fencing is planned to be 5-foot chain link with three barbed wires on top to discourage unauthorized entry. The LBV stations are expected to be enclosed in a cabinet style enclosure for weather protection. The cabinets will be designed to keep the valve elevations at a working height from the ground surface. In the event of a line break valve closure, the line break valve computer will send a signal to all line break valves to close, thus minimizing loss of containment. The rate of closure should take 30 seconds from the open position to the fully closed position. This slow rate of closure will minimize the pressure surge (caused by the kinetic energy of the fluid) at an LBV. After emergency shutdown due to a pipeline leak or rupture, the depressurized section would be brought up to temperature and pressurized again, slowly, by the line break bypass valves, which also serve as temperature-controlled vents in the case of emergency. Flow Meters Leak detection will be based upon the principles laid out in CSA Z662 Annex E as pertaining to HVP lines. Leak detection is based on material balance. The mass flow meter being considered at the Shell Scotford boundary limit and at the well head will be of custody transfer accuracy, typically a Coriolis-type flow meter. Both automated and manual emergency shutdown systems will be installed. Automated shutdown will be initiated when pressure transmitters indicate operating parameters outside of acceptable limits. Both (not just a single PIT) pressure transmitters at each LBV, must indicate a low pressure trip in order to confirm a line break incident. Emergency shutdowns can be initiated manually from each of the well sites or from Shell Scotford when pressure, temperature, and flow transmitters indicate upset conditions. Shell Canada Limited March 2013 Page 5-3

48 Section 5: Facility Operations - Transportation Quest Carbon Capture and Storage Project Corrosion Protection Following regulatory requirements and the Pipeline Integrity Management Plan, cathodic protection will be installed for the pipeline; it is planned to be an impressed current system for the entire line. Inspection An in-line inspection tool (smart pig) run of the pipeline will be performed within the first year from startup to verify pipeline integrity. Frequency of repeat inspections will be based on results from this inspection, other surface inspections, and ongoing monitoring results. Other inspection activities will include: non-destructive examination (ultrasonic thickness test) on above ground piping to identify possible corrosion of the pipeline internal visual examination of open piping and equipment evaluated for evidence of internal corrosion; this will be done during routine maintenance activities when parts of the surface facilities will be accessible pipeline right-of way (ROW) surveillance including, for example, aerial flights to check ROW condition for ground or soil disturbances and third party activity in the area March 2013 Page 5-4 Shell Canada Limited

49 Quest Carbon Capture and Storage Project Section 6: Facility Operations - Storage and Monitoring 6 Facility Operations - Storage and Monitoring 6.1 MMV Plan As of March 31, 2013, no storage volumes have been injected. Data collection for the purposes of gaining benchmarking information has been occurring. The list of recent activities associated with the MMV Plan includes: PFC tracer feasibility studies ongoing results expected January 2014 Submission of the pre-baseline MMV plan to ERCB on Oct. 15, 2012 and the response to the associated deficiency letter dated January 9, 2012 Completion of the InSAR feasibility study in association with Special Report #2 submitted January 31, This activity included an external feasibility study performed by TRE. The study indicates that there is a sufficiently large population of reliable natural InSAR targets to characterize the displacement field without the installation of corner reflectors near the injection wells. Drilling deep monitoring wells, located on injection well pads, to assess the potential aquifers used for future pressure monitoring. Initial results indicate that the Cooking Lake formation is the most likely monitoring interval. Completion and initial review of draft documentation of the first field season activities associated with the Hydrosphere Biosphere Monitoring Plan (HBMP). The 2012 field program was carried out by Golder Associates Ltd. during the weeks of Sept and Nov. 6 Dec. 21 in order to attain baseline data for calibration with remote sensing and hydrosphere monitoring respectively. The MMV Plan is designed according to a systematic risk assessment to achieve two distinct objectives: Ensure Conformance to indicate the long-term effectiveness of CO 2 storage by demonstrating actual storage performance is consistent with expectations about injectivity, capacity and CO 2 behaviour inside the storage complex Ensure Containment to demonstrate the security of CO 2 storage and to protect human health, groundwater resources, hydrocarbon resources, and the environment. MMV will achieve this in two ways. First, the expected effectiveness of existing safeguards created by site selection, site characterization and engineering designs will be verified. Second, additional safeguards will be implemented, which will use the same monitoring systems to trigger control measures for reducing the likelihood or the consequence of any leakage from the BCS storage complex. These control measures include re-distribution of injection rates, drilling additional injection wells and, if necessary, stopping injection and deploying groundwater remediation systems. Transfer of long-term liability, in accordance with the Closure Plan, is supported by MMV activities designed to verify that the observed storage performance conforms to model-based forecasts and that these forecasts are consistent with permanent secure storage at an acceptable risk. These same monitoring systems would also provide early warning of any potential for loss of conformance and allow for timely updates to Shell Canada Limited March 2013 Page 6-1

50 Geosphere Wells Section 6: Facility Operations - Storage and Monitoring Quest Carbon Capture and Storage Project subsurface models or updates to the Storage Development Plan. These activities will maintain conformance and ensure timely site closure and transfer of long-term liability to the Crown. Containment risks affect Project safety and economic value, so containment monitoring plans were selected to ensure these risks are as low as reasonably practicable. The selected monitoring plans for conformance and containment measure a variety of regions and time periods and this breadth provides assurance that a full spectrum of potential conformance issues are being monitored. Some commitments for monitoring already exist for each of the major environmental domains as shown in Table 6-1. Table 6-1 MMV Commitments Item Description MMV Plan updates The MMV Plan will be site-specific and adaptive; this means it remains subject to change in response to new information from: technical feasibility studies baseline measurements monitoring during the injection and closure periods An update to the MMV Plan will be submitted for review before commencing baseline measurements, and thereafter every three years, coincident with the required submission of the updated Closure Plan to Alberta Energy. Deep monitoring wells Shell proposes to drill a minimum of three deep monitoring wells. The planned target is the Winnipegosis Formation. The suitability of this formation will be verified by logging and testing these deep monitoring wells. Monitoring within these wells will include continuous pressure measurements. One of these wells will also include a down-hole, microseismic monitoring system. Distributed temperature sensing Shell will install a distributed temperature sensing system outside the production casing in all injection wells. Time-lapse seismic Shell will acquire time-lapse seismic surveys designed to monitor the CO 2 plume. A 3D surface seismic baseline survey has been acquired. Repeat 3D vertical seismic profile (VSP) surveys designed to monitor the CO 2 plume will be acquired until the CO 2 plume exceeds the radius of investigation for a VSP seismic survey. Thereafter, at least one repeat 3D surface seismic survey will be acquired. InSAR Shell will acquire InSAR data designed to monitor surface heave induced by CO 2 storage. March 2013 Page 6-2 Shell Canada Limited

51 Hydrosphere Quest Carbon Capture and Storage Project Section 6: Facility Operations - Storage and Monitoring Table 6-1 MMV Commitments (cont d) Item Description Project groundwater monitoring wells Shell proposes to drill three groundwater monitoring wells for each injection well. Each of these groundwater monitoring wells will include a continuous water electrical conductivity measurement system. Annual fluid sampling and analysis will be performed. At least one of these groundwater wells will be located on the injection well pad; the remaining groundwater wells may be located elsewhere. Landowner groundwater monitoring wells Subject to landowner consent, a network of landowner groundwater wells will also be used for monitoring groundwater quality. These will include: All existing landowner wells within 3.2 km of the injection wells. Existing landowner wells within close proximity to the BCS legacy wells. A regional network of existing landowner wells sparsely distributed across the remaining AOR at a density of approximately one per township. Tracers for BCS brine and CO 2 Water geochemistry appraisal work has identified that the BCS brine has a unique formation fluid chemistry. In the unlikely event of a potential loss of containment, water geochemistry analysis is expected to verify the presence or absence of BCS brine within protected groundwater resources. An artificial tracer will be co-injected with the CO 2 contingent on a satisfactory conclusion to ongoing technical and operational feasibility evaluations. Groundwater sampling and analysis Shell proposes a tiered approach to monitoring groundwater quality within the Project and landowner groundwater monitoring wells. Tier 0 Continuous monitoring of water electrical conductivity within the Project groundwater monitoring wells. Tier 1 Groundwater sample collection from Project and landowner groundwater monitoring wells and standard water quality analysis for bulk parameters, major ions, nutrients and halogens as tracers for BCS brine. Headspace gas sample collection, where possible, from the same wells and analysis for standard gas composition and the presence of artificial tracer co-injected with the CO 2. Tier 2 Repeat the Tier 1 sample collection and analysis. Additional alternative analysis for halogens, and standard analysis for dissolved metals Tier 3 Repeat the Tier 2 sample collection and analysis. Additional analysis for standard isotopes, such as strontium, oxygen, hydrogen, carbon, halogen isotope ratios. Tier 4 In the event of Tiers 0, 1, 2 and 3 indicating a change in water quality potentially attributable to the Project, a variety of sitespecific measurements will be acquired to delineate the contaminant plume delineation and support risk management activities. Shell Canada Limited March 2013 Page 6-3

52 Atmosphere Biosphere Section 6: Facility Operations - Storage and Monitoring Quest Carbon Capture and Storage Project Table 6-1 MMV Commitments (cont d) Item Groundwater sampling and analysis (cont d) Description Tiers 1, 2 and 3 will be measured at regular intervals and no less frequently than once every 2 years. Each tier constitutes an independent set of water quality measurements and so provides successively increasing levels of confidence. Remote sensing Shell will acquire remote sensing data designed to detect environmental change. This will include multi-spectral optical images. Sample plots Sample plots will be utilized to calibrate the remote sensing data designed to detect environmental changes Line of sight CO 2 gas flux monitoring A field trial of the line-of-sight CO 2 gas flux monitoring technology has been deployed in Q It will verify the technical capability of this technology for continuous detection and mapping and any CO 2 emissions from the BCS storage complex into the atmosphere. SOURCE: based on responses provided as a response to Intervenor Submisisons, ERCB Hearing. Response dated February 28, 2012, Exhibit (Tab B). The MMV Plan is a key component of the risk mitigation strategy regarding CO 2 storage containment. Figure 6-1 summarizes these risks and mitigation measures. March 2013 Page 6-4 Shell Canada Limited

53 Quest Carbon Capture and Storage Project Section 6: Facility Operations - Storage and Monitoring Legend Passive safeguards; these are always present Active safeguards, these are only present when a decision to intervene is made triggered by monitoring information Figure 6-1 CO 2 Containment Loss Risk and Mitigation Diagram The dark and light boxes indicate the safeguards in place to reduce the likelihood (left side) and consequence (right side) of any unexpected loss of containment. The additional active safeguards are supported by the monitoring plan and control measures. Shell Canada Limited March 2013 Page 6-5