a. For the Cross-section from ITR-2 Project Team Presentation, Oct 2009, see Figure Regional Aquifer Flow and Potential CO 2 Receptors

Transcription

1 3. Part A Quest Carbon Capture and Storage Project a. For the Cross-section from ITR-2 Project Team Presentation, Oct 2009, see Figure Figure 43-1 NOTE: This graphic remains accurate as to Project design. Regional Aquifer Flow and Potential CO 2 Receptors July 2011 Page 3-86 Shell Canada Limited

2 Quest Carbon Capture and Storage Project 3. Part A b. For the Integrated CCS CO2 Storage, see Figure Figure 43-2 NOTE: This graphic remains accurate as to Project design. Integrated CCS Project CO 2 Storage Shell Canada Limited July 2011 Page 3-87

3 3. Part A Quest Carbon Capture and Storage Project c. For the BCS Thickness Map from Well Control, see Figure Figure 43-3 NOTE: This graphic is updated to reflect the Generation3 maps submitted in the D65 Application. Basal Cambrian Sands Thickness Map from Well Control July 2011 Page 3-88 Shell Canada Limited

4 Quest Carbon Capture and Storage Project 3. Part A d. For the Base Map of Log and Core Data for BCS, see Figure Legend High Log Quality Reasonable Log Quality Limited Log Data Wel l s Penetrati ng Precambri an Scotford Upgrader Proposed Pipeline Route July 13,2010 Existing 3D Seismic Exploration Tenure AOI Generation 3 Static Model Outline Generation 3 Dynamic Model Outline CO2 Plume Generation 3 Dynamic Model Outline Pressure Cities Cambrian Core NOTE: This graphic is updated to incorporate the latest extent of the 3D seismic shown in pink hatch fill. Figure 43-4 Base Map of Log and Core Data for the Basal Cambrian Sands Shell Canada Limited July 2011 Page 3-89

5 3. Part A Quest Carbon Capture and Storage Project e. For the Appraisal Data Overview, see Figure Exploration Tenure AOI Gen3 Pressure Model HRAM Outline 3D Outline 30x13.6 Km 2D Seismic Data Shell Appraisal Wells Basement Penetrations Redwater 3D 5x7 Km Figure 43-5 NOTE: This graphic is updated to reflect the latest total 3D seismic acquisition 30 x 13.6 km and the Generation3 Pressure Model Outline. Appraisal Data Overview July 2011 Page 3-90 Shell Canada Limited

6 Quest Carbon Capture and Storage Project 3. Part A f. For the 3D Seismic Through the Radway 8-19 Well, see Figure NOTE: This graphic remains accurate as to Project design. Figure D Seismic View Through Radway Well 8-19 Shell Canada Limited July 2011 Page 3-91

7 3. Part A Quest Carbon Capture and Storage Project g. For the 2D seismic Through Pop-Ups to NE of AOI, see Figure Figure 43-7 NOTE: This graphic is updated to remove the 2D seismic line because it is third-party seismic data that Shell does not have the legal right to share publicly. The vertically exaggerated schematic interpretation of the seismic line is shown on the bottom figure. The corresponding seismic line 1 is indicated in the top left figure. Schematics of Seismic Line Northeast of Area of Interest July 2011 Page 3-92 Shell Canada Limited

8 Quest Carbon Capture and Storage Project 3. Part A h. For the Aeromagnetic Data Including HRAM Data, see Figure Figure 43-8 NOTE: This graphic remains accurate as to Project design. Aeromagnetic Data including High-Resolution Airborne Magnetic Data Shell Canada Limited July 2011 Page 3-93

9 3. Part A Quest Carbon Capture and Storage Project i. For the Quest CO 2 Pipeline & Storage with figure of casing and perforations, see Figure Figure 43-9 NOTE: This graphic remains accurate as to Project design. CO 2 Pipeline and Storage, Casing and Perforations July 2011 Page 3-94 Shell Canada Limited

10 Quest Carbon Capture and Storage Project 3. Part A j. For the Quest well schematic for injection test well, see Figure NOTE: This graphic is updated to reflect the actual well schematic for Well W4. Figure Well Schematic for Injection Test Well 8-19 Shell Canada Limited July 2011 Page 3-95

11 3. Part A Quest Carbon Capture and Storage Project k. For the MMV Strategy Framework, see Figure NOTE: This graphic remains accurate as to Project design. Figure Measurement, Monitoring and Verification Strategy Framework July 2011 Page 3-96 Shell Canada Limited

12 Quest Carbon Capture and Storage Project 3. Part A l. For the Subsurface Risk and Uncertainty Framework, see Figure NOTE: This graphic remains accurate as to Project design. Figure Subsurface Risk and Uncertainty Management Framework Shell Canada Limited July 2011 Page 3-97

13 3. Part A Quest Carbon Capture and Storage Project m. For the Containment Monitoring Tasks below Upper Lotsberg Salt, see Figure NOTE: This graphic remains accurate as to Project design. Figure Containment Monitoring Tasks, and Well and Reservoir Management Decisions below Upper Lotsberg Salt July 2011 Page 3-98 Shell Canada Limited

14 Quest Carbon Capture and Storage Project 3. Part A n. For the Containment Monitoring Tasks above Upper Lotsberg Salt, see Figure NOTE: This graphic remains accurate as to Project design. Figure Containment Monitoring Tasks, and Well and Reservoir Management Decisions above Upper Lotsberg Salt Shell Canada Limited July 2011 Page 3-99

15 3. Part A Quest Carbon Capture and Storage Project o. For the Framework for Tolerability of Risk, see Figure NOTE: This graphic remains accurate as to Project design. Figure Framework for Tolerability of Risk July 2011 Page Shell Canada Limited

16 Quest Carbon Capture and Storage Project 3. Part A Question 44: Drilling System for the Injection Wells Volume 1, Section , Page 2-31 Shell states...a shale inhibitive drilling fluid system suitable for maintaining wellbore integrity, supporting data acquisition and minimizing formation damage. Current design is an oil-basedmud system although other compatible mud systems may still be used in future wells. a. Confirm a non-toxic system will be used above the base of groundwater protection surface hole in future wells and was used to drill the surface hole in the existing 8-19 well. Response 44 a. Yes. Shell confirms that a non-toxic system will be used above the base of groundwater protection surface hole in future wells and was used to drill the surface hole in the existing Well In addition, the surface casing will be set deep enough to cover the base of groundwater protection BGWP in accordance with ERCB Directive 008 Surface Casing Depth Requirements Released: December 14, 2010 Directive 8 for setting surface casing. The mud system is a water-based mud commonly referred to as a gel chemical system, which consists mostly of clays, similar to those found in surface formations. The remaining additives are used for mud formulation, which are of very low concentration. Shell uses the Microtox Basic test to screen the mud mixtures for aquatic toxicity, which is suitable for surface waters, effluents, pore water and sediment extracts. Such testing was used in well 100/ W4 Well 8-19 and a similar mud system will be used in subsequent wells to drill a surface hole to protect aquifers above the BGWP. The Microtox Basic test is approved by ERCB and is done by independent laboratory, which follows provisional standards and is certified legally to do the test. Question 45: Cement for the Injection Wells Volume 1, Section , Page 2-31 Shell states...three casing strings, each cemented to surface to maximize borehole stability. Surface hole casing will be set below the BGWP zone. Intermediate casing setting depth will be located below the first seal MCS inside the LMS layer. This will effectively isolate all the three main seals behind intermediate casing before the main hole is drilled and cased. The type of cement used in the 8-19 well or the type of cement to be used in future wells is not described. a. What type of cement will be used for the 8-19 well and future wells? b. Describe the impacts of CO 2 injection on the cement. Shell Canada Limited July 2011 Page 3-101

17 3. Part A Quest Carbon Capture and Storage Project Response 45 a. Well 8-19 was designed and drilled to give optimum protection to the groundwater and shallow horizons. The three-casing design and cementing program provides this optimum protection as follows: The surface casing covering aquifers above the base of groundwater protection and the intermediate casing covering the three seals of the BCS storage complex are cemented to the surface with Class G cement formulation including additives for tight fluid loss and better rheology. For the main casing, covering the CO 2 injection zone, a special formulation of cement was used based on a modified Portland cement blend for CO 2 specific application. The cement blend is supported by Shell in-house expertise and work, and consists of Class G cement with reduced amounts of cement by volume, addition of silica, metakaolin, silica fume and fly ash. Polymeric additives have also been used to reduce matrix permeability. This is fundamental to the durability and ductility of the cement; therefore, the same cement formulation will be used for subsequent wells. Future wells will use a similar cement recipe and follow the same design and completion procedures as used for Well b. Cement is a key element to ensuring the integrity of the well and the storage complex. The cement is subjected to two main potential degradation mechanisms, chemical and mechanical. CHEMICAL The cement reacts with CO 2 but its impact is less pronounced if the CO 2 is dry as is the case with the Project. Dry CO 2 is not acidic and once the formation fluid is pushed away from the well bore at the start of injection, the cement is exposed to dry CO 2. In addition, an analysis on the performance of oil well cement with 30 years of CO 2 exposure in West Texas from Carey et al suggests that CO 2 reaction with cement could be beneficial, i.e., when carbonation takes place, reaction products that precipitate out may reduce cement permeability creating a buffer between the injected CO 2 and the cement. MECHANICAL Mechanical degradation occurs when a well is exposed to significant stress and strain. This is not expected to be the case with the Project because injection will be under matrix conditions not fracture injection and limited formation strain at the well less than 1% is expected during the Project life. The critical element for cement and well integrity is the placement and quality of the cement. To achieve integrity, the best drilling practices will be used to ensure an in-gauge hole and July 2011 Page Shell Canada Limited

18 Quest Carbon Capture and Storage Project 3. Part A Shell s best cementing practices will be used to place the cement behind the casing, as demonstrated in Well 8-19 by cement bond logging and hydraulic pressure testing. The same drilling and cementing practices will be used for subsequent wells. CONCLUSION In their study, Carey et al support the conclusion that even normal Portland cement is sufficient for the containment of CO 2. The cement used in a CO 2 flooding operation was retrieved after years of service and no appreciable degradation was observed. In addition, a study conducted by OXAND an independent consultant recognized as an expert in cement degradation on the proposed Shell well design confirmed the effect of CO 2 on cement would not lead to a loss of well integrity OXAND REFERENCES Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner, M.A. Raines, G.D. Guthrie Jr Analysis and performance of oil well cement with 30 years of CO 2 exposure from the SACROC Unit, West Texas, USA. International Journal of Greenhouse Gas Control 1: OXAND Canada Inc Final Report Well Integrity Study of the Quest Project Proposed Appraisal Well #3 - Phase 1: Design Review, Long Term Integrity Performance and Gaps Analysis with Practical Risk-based recommendations. Question 46: Cementing the Injection Wells Volume 1, Section Figure 2-12, Page 2-32 The figure shows a production casing cement top that is approximately 300 metres from surface. a. Why is cement not being brought to surface? b. Discuss whether corrosion of the upper 300 metres of uncemented production casing could occur. c. Figure 2-12 does not include information on the tubing or packer types, or inhibited fluid in the tubing casing annulus. Provide this information. Shell Canada Limited July 2011 Page 3-103

19 3. Part A Quest Carbon Capture and Storage Project Response 46 a. The cement will not be brought completely to the surface behind the main casing in order to provide space for the casing alignment and to prevent damage to the fibre optic string behind the casing. Therefore, it was decided not to cement the casing to the surface but to leave a small uncemented interval. Having cement all the way to the surface behind the main casing is not a critical requirement, as the well has multiple casing strings, as follows: The surface casing protects the groundwater and is cemented to the surface. The intermediate casing covers all overlaying formations and the three seals of the storage complex the Upper Lotsberg, the Lower Lotsberg and the Middle Cambrian Shales, and is also cemented to the surface. The main casing, which is not cemented to the surface, and is only exposed to the Basal Cambrian Sands BCS, the injection target zone, and the Lower Marine Sands LMS, i.e., the zone immediately above the injection zone. It is below all three major seals of the storage complex. The intermediate casing cement bond logs show effective cementation across all three seals, confirming good hydraulic isolation. Additionally, the intermediate casing is set at 1,983 m and the top of cement in the main casing is at 300 m depth. Therefore, the overlap of cement in the main casing is sufficient. b. Corrosion of the 300 m uncemented section is highly unlikely because: it will not be exposed to either formation fluids or any other corrosive fluids the uncemented section is filled with an inhibited cement pre-flush fluid c. The final well completion under Base-Case design is 4½-inch tubing, preferably L-80 grade. The packer could be a hydraulic set mechanical packer with all flow-wetted areas internally coated for CO 2 service and to prevent corrosion. The setting depth of the packer will be according to the current regulations and will be no more than 15 m above the top of injection zone. Also all the equipment below the packer will be coated internally for corrosion prevention and rated for CO 2 service. The annulus will be filled with inhibitive fluid e.g., Norrcorr 500. Question 47: Clarification on Raising BCS Brine Volume 1, Appendix A, Section , Page 5-11 Shell states The selected site allows for injection of CO 2 no closer than 21 km to any legacy well penetrating the BCS.... After 25 years of injection, the expected rise in pore fluid pressure around these seven legacy wells will likely be insufficient to raise BCS brine into the groundwater protection zone Attachment E. July 2011 Page Shell Canada Limited

20 Quest Carbon Capture and Storage Project 3. Part A a. Discuss how Shell can confirm this is true for wells that penetrate the Pre-Cambrian? b. Would the pressure be great enough to raise BCS brine into the groundwater protection zone, at the injector sites or within some distance of the injector sites? Response 47 Shell wishes to provide additional clarification on i the legacy well definition, ii offset distances of legacy wells and iii the reservoirs the legacy wells penetrate. The responses to Questions 47a and b are provided immediately after these clarifications. i. Legacy well definitions For further clarification on the number, location and nature of legacy wells, see Response 127. ii. Offset distances Shell will keep the CO 2 injection wells as far away as possible from the legacy wells penetrating the BCS storage complex to minimize risk to containment. However, the 21 km offset refers to the distance between legacy wells that drilled through all three major seals, and Well It is not a commitment for minimum offset to these legacy wells. In particular, the 21 km offset refers to the distance between legacy well Egremont 6-36 and the recently drilled Project appraisal well, Radway Well 8-19, which is intended to be the first injection well for the Project. The offset distances from the original five candidate injection well locations to the Egremont 6-36 legacy well range from 21 to 23 km. The location of three additional candidate injection wells for the Project has been identified and their offset distances to the Egremont 6-36 legacy well range from 18 to 20 km. There is no requirement that injection well locations should be no closer than 21 km to any legacy well penetrating the BCS storage complex. Injection wells will be sited based on a range of selection criteria, one of which is the offset to existing legacy wells in the BCS. iii. Reservoir penetrations The Precambrian is unlikely to be pressurized during the life of the Project due to the tight reservoir properties associated with the basement granite. The pressurization resulting from CO 2 injection is expected to be contained within the BCS. The BCS is the storage formation and is overlain by three seals the Middle Cambrian Shale [MCS] first seal, the Lower Lotsberg second seal and the Upper Lotsberg ultimate seal forming the BCS storage complex. Shell Canada Limited July 2011 Page 3-105

21 3. Part A Quest Carbon Capture and Storage Project The responses to Questions 47 a and b follow: a. Based on the modelling work on CO 2 plume distribution and pressure front modelling done to date see Response 116 for further details, after 25 years of injection the pore fluid pressure is unlikely to be sufficient to raise BCS brine into the groundwater protection zone at the four third-party legacy wells Egremont 6-36, Eastgate 1-34, Darling and Westcoast 9-31 that penetrate the BCS reservoir within the AOI. One additional third-party legacy well Imperial PLC Redwater W400 penetrates the BCS storage complex within the AOI. However, this well penetrates neither the BCS reservoir nor the bottom two seals MCS and Lower Lotsberg of the storage complex. Any elevated BCS pressure at this location does not represent an increased risk of loss of containment through the Imperial PLC Redwater legacy well. The two other of the seven wells that penetrate the BCS storage complex within the AOI, Redwater Well 3-4 and Radway Well 8-19, are part of the Project. Both these wells have been designed, drilled and completed to eliminate loss of containment risks. These wells have not been abandoned. The methods that will allow Shell to confirm that BCS pressures are insufficient to raise BCS brine into the groundwater protection zone during Project operations are: continuous pressure measurements at the injection wells numerical reservoir modelling of the pressure distribution around these wells An iterative modelling strategy will be used by Shell, which will allow performance predictions for a range of expected pressure distributions in the BCS, based on dynamic simulation models. During operations, the models will be validated and updated using continuous down-hole pressure data acquired from down-hole gauges in the injection wells. Flowing bottom-hole pressure BHP as well as annual fall-off tests for closed-in injection wells will help to reduce the range of uncertainty on predictions for BHP development around the injection wells. The MMV Plan allows for validation of the pressure distribution in the BCS through interferometric synthetic aperture radar InSAR and for Redwater Well 3-4 to potentially be converted to a BCS pressure observation well currently under review. b. A direct flow path is not anticipated between the BCS penetrations and aquifers above the base of groundwater protection at or near the injection wells. This is because the injection wells and completions are designed and will be executed to reduce the risk of leak paths from the BCS storage complex to overlying formations. Hydraulic isolation will be demonstrated through adherence to existing ERCB regulations e.g., Directive 051: Injection and Disposal Wells - Well Classifications, Completions, Logging, and Testing Requirements [March 1994]. July 2011 Page Shell Canada Limited

22 Quest Carbon Capture and Storage Project 3. Part A In the absence of a direct flow path, fluids will be contained in the BCS storage complex and not migrate into the groundwater protection zone. However, in theory, if a direct flow path existed between the BCS and the base of groundwater protection zone, which as described above is not anticipated, then the BCS pressure at the injection wells would be sufficiently high to lift BCS brine into the groundwater protection zone. Question 48: Clarification on Legacy Wells and BCS Brine Volume 1, Appendix A, Section , Page 5-11 Shell states Wells represent a deliberate breach of the geologic seals and as such pose the greatest risk to containment and legacy wells are likely the most vulnerable given uncertainty about their current and future integrity...the selected site allows for injection of CO 2 no closer than 21 km to any legacy well penetrating the BCS. And Volume 2A, Appendix 7A, Figure 7A -37, Page 7A-87, shows a large number of wells drilled to various depths shallower than the Pre-Cambrian in the Area of interest. a. Confirm Shell s definition of legacy wells refers only to wells that penetrate the CO 2 complex. b. List the wells drilled shallower than the CO 2 complex in close proximity to the injector wells. c. Discuss potential impacts to non-saline groundwater resources if CO 2, BCS brine or CO 2 saturated brine were to reach a formation penetrated by these shallower wells. Response 48 For clarification, Shell will keep the CO 2 injection wells as far away as possible from the legacy wells that penetrate through one or more seals in the BCS storage complex to minimize risk to containment. However, the 21 km offset is a reference distance between Well 8-19 and the legacy wells that were drilled through all three major seals. The distance of 21 km is not a commitment for a minimum offset to legacy wells. a. No, legacy wells do not only include those that penetrate the CO 2 storage complex. A legacy well is defined as any pre-existing, ERCB licensed well deeper than 150 m that: is located within the Project AOI was drilled before the Application was submitted was not drilled as part of the Project Shell Canada Limited July 2011 Page 3-107

23 3. Part A Quest Carbon Capture and Storage Project The legacy wells, referred to in the above statement as posing the greatest risk to containment and 21 km to any legacy well penetrating the BCS, refer to a category of legacy wells that penetrate through one or more seals in the BCS storage complex. In contrast, the large number of legacy wells drilled to various depths shown in the Application, Volume 2A, Appendix 7A, Figure 7A-37 reproduced here, includes shallow legacy wells that do not penetrate through one or more seals in the BCS storage complex. As these shallow legacy wells pose a very low risk to containment, they were not reviewed in detail. See Response 127 for further details on legacy wells. b. For the list of all ERCB licensed wells close within 1.6 km to the planned CO 2 injection wells, see Table 48-1 and Figure The 1.6 km distance the distance of one section is taken from the Resources Applications Notification Guidelines Table 2 of ERCB Directive 065, Resource Applications for Oil and Gas Reservoirs revised edition, August 2010 Directive 65. All of these wells have a total depth TD that is shallower than the top of the BCS storage complex. July 2011 Page Shell Canada Limited

24 Oil and Gas Wells* Formation ^ Belly River Cardium SS Second White Speck SS Viking Mannville ± Wabamun Leduc Cooking Lake Precambrian Completed Appraisal Well Candidate Injection Well AOI County Boundaries Pipeline Route ^ Kilometres * Legacy Oil and Gas Well Data where more than one completion formation is reported at one location, only the deepest completion formation is indicated on the map Shell Scotford ^ AB BC Area of Interest USA XXX REVX QUEST CARBON CAPTURE AND STORAGE PROJECT SK Location of Legacy Oil and Gas Wells Acknowledgements: Original Drawing by Stantec Pipeline: Sunstone Engineering August 11, 2010, Basedata: Altalis 1 Million ^ PREPARED BY PREPARED FOR FIGURE NO. 7A-37

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26 Quest Carbon Capture and Storage Project 3. Part A Table 48-1 Wells Close to the First Eight Candidate CO 2 Injection Wells UWI TD m UWI TD m UWI TDm UWI TDm 1 100/ W * 2 100/ W400 Precambrian 3 100/ W400 Precambrian 4 100/ W400 Precambrian S0/ W / W / W / W / W / W / W / W / W / W / W / W F1/ W W0/ W / W / W / W / W / W / W W0/ W W0/ W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W W0/ W / W / W / W W0/ W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W UWI TD m UWI TDm UWI TDm 100/ W / W400 Precambrian 6 100/ W400 Precambrian 7 100/ W400 Precambrian 100/ W / W / W / W / W / W / W / W / W / W / W / W UWI TDm 100/ W / W / W / W400 Precambrian 100/ W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W S0/ W / W / W / W / W / W / W / W / W / W / W / W W0/ W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W / W Legend: Bold Wells - Proposed CO 2 injection well candidates 1 through 8 The list of wells below each candidate CO 2 injection well represents all the ERCB licensed wells located within a one section offset from that candidate CO 2 injection well. This distance is equal to or slightly greater than 1.6 km. See Figure 48-1 for schematic explanation. TD = total well depth Precambrian = well with TD in Precambrian basement. * Injection well already drilled Shell Canada Limited July 2011 Page 3-111

27 3. Part A Quest Carbon Capture and Storage Project All ERCB licensed wells >150m deep located within this boundary are listed for each CO 2 injection well. Section containing planned CO 2 injection well from Table Example: 100/ W km One section offset from planned CO 2 injection well km Figure 48-1 Schematic of Area Considered to be Close to a CO 2 Injection Well c. The Application, Volume 2A, Part 2, Section presents a characterization of several potential migration pathways that fluids from the BCS storage complex could follow to aquifers above the BGWP and provides a summary of the assessment of potential effects on groundwater. The characterization discusses potential pathways associated with legacy wells penetrating the BCS storage complex, CO 2 injection wells, and MMV observation wells. The characterization does not specifically identify migration along shallower legacy oil and gas wells because the potential pathways along these wells exist for essentially the same reasons as for deeper legacy oil and gas wells that penetrate the BCS storage complex. However, migration along the shallow wells is less likely because of the shallower depth and the absence of a connection with the BCS storage complex. Moreover, for BCS fluids to reach shallow legacy wells completed above the BCS storage complex, they would first need to migrate through many intervening geological seals and aquifers, which would tend to further attenuate the concentration of the fluids reaching the shallow legacy well bores. Thus, the risks associated with these shallower legacy wells are lower than for the deep legacy wells that penetrate the BCS storage complex. July 2011 Page Shell Canada Limited

28 Quest Carbon Capture and Storage Project 3. Part A From the Application Volume 2A, Part 2, Section : Summary and Significance The following provides a summary of the assessment of potential effects on groundwater, and a significance conclusion. A release of injected CO 2, BCS brine, or CO 2 saturated brine from the BCS storage complex and subsequent upward migration of these fluids into an aquifer above the BGWP would cause changes in groundwater quality. A lowering of ph in the aquifer and the resulting geochemical reactions could potentially mobilize trace elements present in the aquifer minerals. Dissolved metals already present within the BCS brine could also contribute to elevated concentrations of these parameters. Salinity parameters within the aquifer, including electrical conductivity and sodium and chloride concentrations, could also increase. The combined effects of these changes could potentially increase concentrations of groundwater parameters above their respective guideline values, indicating the potential for increased risks to ecological or human receptors. It should be noted that under baseline conditions, several groundwater quality parameters see Volume 2A, Appendix 7A including TDS, iron, manganese, and sodium already exceed their respective guidelines. The magnitude of the changes to groundwater quality parameters would be influenced by the volume of the release, the rate of release, brine:co 2 mix ratio, temperature/pressure conditions in the aquifer at the release location, the mineralogy of the aquifer at the release location, hydraulic parameters of the aquifer at the release location, local groundwater gradients and flow velocities, presence of minerals with free adsorption sites, and other site specific factors. The duration of a release is expected to be brief due to the implementation of the MMV Plan. Changes in groundwater quality would also be local in scale due to slow groundwater flow velocities in the assessment area and attenuating reactive transport or adsorption mechanisms. The confidence level is moderate based on the above discussion and in consideration of collective industry experience with other resource projects involving the injection of fluids that result in incremental pressurization of various subsurface geologic units. Numerous projects such as acid gas injection schemes, enhanced oil recovery EOR projects and deep well disposal operations involving subsurface injection of fluids have been operating in Alberta for extended periods of time in the order of decades. Shell Canada Limited July 2011 Page 3-113

29 3. Part A Quest Carbon Capture and Storage Project While these projects may differ regarding the overall objective of their operations, they are appropriate analogues to the Project regarding successful success and integrity of subsurface containment. These other Projects indicate that with proper design and operation, fluids injected into the subsurface are not likely to affect groundwater. Any potential effects will further be limited by the implementation of Shell s ERP and MMV Plan. In conclusion, for residual effects, magnitude is moderate, geographical extent is local, duration is short-term, reversibility is reversible and prediction confidence is moderate. Potential effects on groundwater are, therefore, not significant. The risks associated with the shallower legacy wells are considered to be much lower than described above for the deep legacy wells that penetrate the BCS storage complex, due to: the absence of a direct connection with the BCS storage complex the further attenuation of the concentration of the fluids reaching the shallow legacy well bores through dissolution and residual trapping in the many intervening geological seals and aquifers between the BCS and the shallow legacy wells Therefore, there is even greater confidence that the likelihood of a release occurring is low with respect to shallower legacy wells, and the magnitude of potential effects is considered to be negligible. Question 49: Cement Types and Risk of Loss of Containment Volume 2B, Section , Page 17-6 This section discusses loss of containment, and describes the potential pathways for fluids to migrate from the CO 2 storage complex to receptors above the complex, including along legacy wells, injection wells, or monitoring wells. Although these pathways are acknowledged, there does not appear to be information in the application related to reducing this risk by ensuring cement integrity, i.e., cement types and cementing practices, cement integrity monitoring... a. What cement types, cementing practices and cement integrity monitoring... will be used? Provide and discuss this information. b. Identify the closest wells to the injectors. Could these wells be impacted if containment were lost at an injector due to cement issues, and fluids migrated up-hole. c. Does Shell plan to incorporate the wells in 7b into its MMV plan? July 2011 Page Shell Canada Limited

30 Quest Carbon Capture and Storage Project 3. Part A Response 49 a. Following is a description of cement processes for the two types of wells. INJECTION WELLS The design and construction of the Project injection wells maximizes protection of the ground water and shallow horizons. The three-casing design provides multiple layers of protection. The surface casing will cover the ground water source. The intermediate casing will cover all three geological seals within the BCS storage complex, thereby ensuring a good cement bond and hydraulic isolation before the main injection zone is drilled. The main casing will be exposed only to the injection zone and the immediate zone above. To achieve a good cement bond and hydraulic isolation, good drilling practices are necessary to achieve an in-gauge hole. The use of oil-based mud over the intermediate hole section, followed by a pre-flush treatment to remove mud filtrate for effective cement placement, as implemented in Radway Well 8-19, will be considered in the cementing program. The surface and intermediate casing are both cemented to surface with Class G cement formulation including additives for tight fluid loss and better rheology. For the main casing, covering the CO 2 injection zone, a special formulation of cement was used based on a modified Portland cement blend for CO 2 -specific application. The cement blend is supported by Shell in-house expertise and work and consists of Class G cement with a reduced amount of cement by volume, addition of silica, metakaolin, silica fume and fly ash. Polymeric additives will also be used to reduce matrix permeability. This is fundamental to the durability and ductility of the cement. A good cement bond and hydraulic isolation across the three geological seals and across the ground water zone was confirmed in Radway Well 8-19 by running a cement bond log and performing a pressure test of the casing. This has confirmed the effectiveness of the drilling and cementing practices. The same approach will be used in drilling subsequent wells. VERIFICATION WELLS Frequent cement bond logs and pressure testing over the Project life will be run to demonstrate the integrity of cement bond and temperature and spinner logs will be used to demonstrate the conformance of injection fluid with the desired injection zone. b. The closest well to each injection well will be a Project groundwater observation well located on the well pad. Any unexpected loss of containment at an injection well due to cement issues is unlikely to affect these wells because continuous monitoring systems within each injection well are designed to provide timely detection of such an event to enable effective control measures that prevent any farther up-hole migration of fluids. The Project groundwater Shell Canada Limited July 2011 Page 3-115

31 3. Part A Quest Carbon Capture and Storage Project monitoring wells located on these well pads are intended to verify the absence of any effects on groundwater. In the unlikely event of loss of containment at an injection well, the groundwater monitoring well is designed to give an early indication of any effects on groundwater. c. Yes, the Project groundwater monitoring wells described in Response 49b will be designed and drilled as part of the MMV Plan. Question 50: Groundwater Monitoring Wells Volume 2B, Section , Page 18-5 This section indicates Shell plans to install groundwater monitoring wells; however, no detail is provided. a. Describe the groundwater monitoring program, including potential zones/depths to be monitored and potential monitoring sites based on risk and sampling frequency. Response 50 a. The groundwater monitoring program will include three groundwater monitoring wells for each injection well, of which at least one groundwater monitoring well will be located on each injection well pad. These groundwater monitoring wells will be equipped to perform continuous measurement of water electrical conductivity. In addition, fluid samples will be collected annually from each groundwater monitoring well for laboratory analysis to determine the presence or absence of tracers uniquely associated with the Project. The potential zones/depths to be monitored will be above the base of groundwater protection. Ongoing technical feasibility studies will inform the specification of these groundwater monitoring wells. An updated MMV Plan, that specifies the initial Base-Case groundwater monitoring plan, will be submitted for review before commencing baseline measurements two years prior to sustained CO 2 injection and then every three years coincident with the required submission of the Closure Plan to Alberta Energy. The details of the groundwater monitoring plan depend on the outcome of ongoing feasibility studies that will be documented as part of the Field Development Plan, which will include such elements as: capacity and injectivity estimates static and dynamic models predicted long-term evolution of the storage site July 2011 Page Shell Canada Limited

32 Quest Carbon Capture and Storage Project 3. Part A well locations, design, and construction or status changes uncertainty and risk assessment The Application, Volume 1, Appendix A, Section describes the conceptual groundwater monitoring plan: Groundwater monitoring wells completed at least two years prior to CO 2 injection support continuous electrical conductivity WEC and ph WPH monitoring of the groundwater to establish a baseline and to verify the absence of significant impacts to groundwater quality throughout the injection and closure periods. Fluid sampling and laboratory analysis of water chemistry start with annual measurements two years prior to CO 2 injection and continue with measurements every two years throughout the closure period. Analyzing these same fluids samples for natural and potentially artificial tracers follows the same schedule with the exception that artificial tracers do not require any baseline data Aquatics Question 51: Trenched Crossing of the North Saskatchewan River Volume 1, Appendix I, Attachment C, Section C.3.6, Page C-8 Shell states If the preferred crossing method fails or if the crossing method changes, an alternative method may be implemented if approved by Shell and the Regulatory Agencies. a. Any other crossing method for the North Saskatchewan River besides a trenchless technique will likely result in the harmful alteration, disruption, or destruction HADD of fish habitat. In order to identify the potential impacts of the contingency method, provide an environmental effects assessment and mitigation plan specific to a trenched method crossing of the North Saskatchewan River. Response 51 a. Shell proposes to cross the North Saskatchewan River using horizontal directional drilling HDD. It is unlikely that a wet trenched crossing method will be used and would only occur if the HDD is unsuccessful, or Shell decides, due to unforeseen circumstances, that HDD is no longer feasible. A discussion of the expected environmental effects and Shell s proposed mitigation plan for a trenched crossing of the North Saskatchewan River is provided below. Shell will employ sediment control measures until all disturbed ground has been permanently stabilized, so that suspended soil particles in the river and surface runoff water are limited or trapped to reduce turbidity in the aquatic environment. Shell Canada Limited July 2011 Page 3-117

33 3. Part A Quest Carbon Capture and Storage Project Erosion and sediment control during construction and after the reclamation of the crossing will be achieved through a combination of physical, operational and scheduling measures, including isolation of the trench during construction through use of sheet pile, coarse material i.e., rip-rap, aquadams, and large bulk-fill sand bags. A monitoring plan will be implemented to measure total suspended solids TSS during construction. Before construction starts, the correlation between TSS concentration and turbidity in the North Saskatchewan River will be established. Sediments suspended during construction and subsequently deposited downstream will be redistributed by natural bedload movement. The length of time required for the river bed to recover fully is the cause of the uncertainty. Most movement of smaller particles will occur during ramping of flows related to standard operation of the upstream hydroelectric facilities. Coarser materials may also be redistributed by ramping flows, but their redistribution could be delayed until June and July high flows. Under the best-case conditions, recovery would occur in less than six months. Under worst-case conditions, recovery along the trench could take two peak flow periods for elimination of visual evidence i.e., approximately 20 months. Any adverse effects from a trenched crossing are anticipated to be not significant. Based on previous studies, it is expected that the open cut crossing of the North Saskatchewan River will result in a temporary disruption of fish habitat at the crossing location. This constitutes a harmful alteration, disruption or destruction HADD and will require an Authorization under Section 352 of the Fisheries Act. Application of appropriate mitigation measures will result in any residual environmental effects to fish and fish habitat being not significant. Compensation will be provided as per Fisheries and Oceans Canada DFO policy to result in no net loss and to offset adverse residual environmental effects. Shell is committed to providing to DFO and Transport Canada TC a contingency plan for the crossing of the North Saskatchewan River using a trenched crossing. The contingency plan will include the assessment of effects, mitigation measures and methodology summary provided above. The contingency plan will be submitted to DFO in Q and to TC before construction or clearing activities on the bed and banks of the North Saskatchewan River. Question 52: Maintenance along Watercourse Crossings Volume 2A, Section 8.2.2, Page 8-6 Shell states...other than access for routine maintenance along the pipeline, watercourses will not be affected. a. Describe in detail the routine maintenance required and how it may affect the watercourses and Fording of watercourses during operation for maintenance activities. July 2011 Page Shell Canada Limited

34 Quest Carbon Capture and Storage Project 3. Part A Response 52 a. Routine maintenance activities along the pipeline right-of-way ROW include mowing, aerial surveillance, and routine instrument calibration at the line block valve LBV location. Routine maintenance of the pipeline will not be required at, or near, watercourse crossings during operations. Fording of watercourses may be required but will be undertaken according to the DFO Operational Statement for Temporary Stream Crossings DFO A one-time ford is not considered to have a harmful effect on a watercourse, providing it is completed outside the restricted activity period RAP. Shell will, where required, adhere to the RAP for all watercourses where fording is required. REFERENCE Fisheries and Oceans Canada DFO Operational Statement for Temporary Stream Crossings. Available at: Question 53: Lower Namepi Creek Crossing Volume 2A, Section 8.4, Table 8-5, Page 8-11 The proposed pipeline crossing method for Lower Namepi Creek is an open cut when dry or frozen as per the Operational Statement and trenchless if the creek is flowing. Shell s aquatic resources baseline identified this reach of the Lower Namepi as good spawning habitat for sucker species. As per the Operational Statement for Isolated or Dry Open-cut Stream Crossings Shell may proceed with the crossing only if it meets certain conditions, including that the site does not occur at a stream location involving known fish spawning habitat. Based on the baseline aquatic assessment, DFO has determined that the crossing of Lower Namepi Creek does not meet the Operational Statement for Isolated or Dry Open-cut Stream Crossings conditions. a. What is the possibility of using a trenchless technique regardless of flow conditions? If it is not possible, what potential mitigation measures will Shell apply to minimize the potential impacts of this crossing? Shell Canada Limited July 2011 Page 3-119

35 3. Part A Quest Carbon Capture and Storage Project Response 53 a. The baseline aquatics assessment indicates that spawning habitat within the LAA is considered good for coarse and forage fish species. However, this is a general comment referring to the entire LAA for the Lower Namepi Creek crossing. For the crossing of Lower Namepi Creek, Shell will follow the terms of the applicable operational statement. Within the zone of influence for the crossing the PDA plus the area where 90% of the sediment generated during construction is expected to be deposited, there is a predominantly fine substrate 80% fines that would not be suitable for spawning by either sucker or sport fish species. Therefore, Shell s view is that the open cut crossing of the Lower Namepi Creek, even if water is flowing, will meet the conditions contained in the applicable operating statement. The crossing location was dry or frozen to the bottom during the winter survey in Therefore, it is highly likely that at the time of construction, this crossing will meet the requirements of the operational statement, which means that it will not result in a HADD. During winter construction, the top layer of substrate will be removed and stockpiled separately, to be used as the final layer of backfill, to reduce the potential effects of the crossing and restore the channel to the pre-construction condition. Conditions are expected to be amendable to an open cut crossing that complies with the DFO operational statements, but, if they are not, a trenchless technique will be considered. Question 54: Temporary Crossings Volume 2A, Section 8.2.2, Page 8-12 Volume 2A, Section , Page 8-12 Shell states that as a mitigation measure If culverts are used for temporary crossings, they will be removed before the restricted activity period, unless otherwise agreed with DFO and Construction of the pipeline will require temporary crossings over, and instream works in, most of the watercourses along route. a. Describe in detail the temporary crossings that will be used, include in the description the location and method of crossing. b. Clarify if the temporary crossings described in Section are included in the original 18 crossings identified in Section 8.4. If not, explain if any of these temporary crossings are identified under the Minor Works and Water Order or will require Navigable Water Protection Act approvals. July 2011 Page Shell Canada Limited

36 Quest Carbon Capture and Storage Project 3. Part A Response 54 a. For the proposed method of temporary crossing for defined watercourses, see the Application, Volume 1, Table 2-1 reproduced below. Table 2-1 Fish-Bearing Watercourse Crossings for the CO 2 Pipeline Watercourse Name Channel Width m Quarter Section COP Class 1 Restricted Activity Period Astotin Creek 7.5 NE C April 16 to June 30 Beaverhill Creek 12 NW C April 16 to June 30 North Saskatchewan River 300+ NW C April 16 to July 31 Lower Namepi Creek 1 16 SW C April 16 to June 30 Upper Namepi Creek NE C April 16 to July 31 NOTE: 1 Source: Alberta Sustainable Resource Development ASRD 2006a, 2006b. Proposed Vehicle Crossing Method Ford when dry or frozen. Temporary single-span bridge if flowing water Ford when dry or frozen. Temporary single-span bridge if flowing water No vehicle crossing permitted Ford when dry or frozen. Temporary single-span bridge if flowing water Ford when dry or frozen. Temporary single-span bridge if flowing water Pipeline Crossing Method Open cut when dry or frozen as per the Operational Statement. Trenchless technique if flowing. Open cut when dry or frozen as per the Operational Statement. Trenchless technique if flowing, as a contingency. Primary method is HDD. Contingency method is a two-stage coffer dam constructed in the fall. Open cut when dry or frozen as per the Operational Statement. Trenchless technique if flowing. Open cut when dry or frozen as per the Operational Statement. Trenchless technique if flowing. Shell Canada Limited July 2011 Page 3-121

37 3. Part A Quest Carbon Capture and Storage Project For temporary crossings, watercourses will be forded only if dry or frozen. Culverts will only be used on watercourses identified as not supporting fish habitat see Table If flowing water is present in an area identified as supporting fish habitat, then a temporary, single-span bridge will be used. Table 54-1 CO 2 Pipeline Non Fish-Bearing Watercourse Crossings Crossing Watercourse UTM Location ID Location Watercourse Name Class Easting Northing 3 SE W4 Unnamed tributary to NSR 1 D SE W4 Unnamed tributary to NSR 2 C NW W4 Unnamed tributary to NSR 3 D SE W4 Drainage 1 D NW W4 Unnamed tributary to NSR 4 D SW W4 Unnamed tributary to NSR 5 C NW W4 Unnamed tributary to C Namepi Creek 1 11 NW W4 Unnamed tributary to C Namepi Creek 2 13 NE W4 Drainage 2 C SE W4 Unnamed intermittent water D body 16 NW W4 Drainage 3 D SE W4 Drainage 4 D NE W4 Drainage 5 D NOTES: NSR North Saskatchewan River UTM Universal Transverse Mercator 1 Drainage had no defined bed or banks and was assigned to watercourse Class D. 2 The North Saskatchewan River is considered Class C within the assessment area. There are Class A sections of habitat associated with known lake sturgeon overwintering habitat located in the North Saskatchewan River. The closest downstream Class A habitat is approximately 42 km from the proposed HDD crossing. b. Temporary crossings referred to in the Application, Volume 2A, Section 8.2.2, are included in the original 18 crossings identified in Volume 2A, Section 8.4. Based on the methods described above, Shell applied for and received approval under Sections 51 and 3 of the Navigable Waters Protection Act for all applicable permanent and temporary crossings associated with the CO 2 pipeline. July 2011 Page Shell Canada Limited

38 Quest Carbon Capture and Storage Project 3. Part A Question 55: Mitigation for Channel Restoration Volume 2A, Section , Page 8-13 Shell states Construction during the fall or winter when the watercourse is dry or frozen will reduce the vegetation damage and allow the bed and banks to be easily restored to preconstruction conditions to limit changes to fish habitat. a. Describe what specific mitigation measures are in place for channel restoration i.e., will original substrate, including any aquatic vegetation, be returned to the bed?. Response 55 Aquatic vegetation is expected to be minimal and will not be restored following construction. The following mitigation measures specific to channel restoration associated with a trenched crossing are provided in the Application, Volume 1, Appendix I, Table 7-1: Item 58: When implementing a trenched isolated ditch or open-cut see Attachment A, Figure A-9, A-8 and A-7 pipeline installation method, gravel or cobble substrates located in the watercourse will be salvaged and stockpiled separately from excavated ditch spoil. These coarse substrates will be used to cap the in-stream portion of the trench line upon completion of back fill. Silt or sandy substrates will be backfilled with clean, coarse substrate to avoid sedimentation of downstream areas. Item 57: Salvage the upper 0.5 m minimum of clean granular material, if present, and stockpile separately from the remainder of the trench spoil. Following construction, cap the upper 0.5 m minimum of the trench with the salvaged granular material. Question 56: Beaver Dams Volume 2A, Section , Page 8-14 Beaver dams are often removed prior to crossing a watercourse resulting in a release of anoxic water and a change in oxygen levels downstream. a. Confirm if any beaver dams will be removed prior to or during the construction of the watercourse crossing. b. If beaver dams will be removed describe any plans to test pond water and downstream dissolved oxygen levels prior to removal and proposed mitigation measures to ensure anoxic water is not released downstream where fish may be present. Shell Canada Limited July 2011 Page 3-123

39 3. Part A Quest Carbon Capture and Storage Project Response 56 a. At the time of the baseline assessment, no beaver dams were found within the ROW at any of the crossing locations. Therefore, no plans exist to remove beaver dams before construction. If beaver ponds are encountered on the ROW during construction, Shell will test the dissolved oxygen level to determine whether the release of water from the pond is an issue, as identified in the DFO Operational Statement for Beaver Dam Removal. Test results will be discussed with DFO and ASRD before water is released. b. See Response 56a. Question 57: Monitoring During HDD in the North Saskatchewan River Volume 1, Appendix I, Attachment C, Section C.3.3, Table C-2, Page C-6. The Aquatic Monitoring section describes a general plan for monitoring at horizontal directional drilling crossings, the North Saskatchewan River crossing being the most sensitive of these. a. Confirm if there is a specific monitoring plan for the North Saskatchewan River crossing, if so provide. b. Table C-2 identifies 4 transects with sampling occurring every 30 minutes at the first transect downstream of the drill. Explain why a data logger is not being placed at this location to ensure a quicker spill detection and response. The emergency procedures described may not be applicable or possible for the North Saskatchewan River crossing because of its size, provide a more specific plan to efficiently manage a frac-out at the North Saskatchewan River and quantify the amount of drilling fluid that may be deposited downstream and the habitat impacts of the deposit. Response 57 a. Water quality monitoring will occur during HDD activities at the North Saskatchewan River. A monitoring plan will be submitted to DFO for review before construction. The plan will include the use of environmental monitors in addition to construction personnel, to monitor both onshore and channel portions of the drill path. Monitoring measures will be in place during nighttime hours for adequate coverage. This may include walking the drill path only where safe to do so and when procedures are in place, and at a minimum will include increased diligence in monitoring drilling pressures. Water quality measurement by auto dataloggers installed during daylight hours will be used for nighttime monitoring. Water quality July 2011 Page Shell Canada Limited

40 Quest Carbon Capture and Storage Project 3. Part A data collected using auto data-loggers will be correlated with water quality measurements obtained by environmental monitors, where possible. b. Water quality data loggers are fixed in place and, in a large river, such as the North Saskatchewan River, a large number of loggers would be required to detect potential plumes quickly. Patrolling the area for a plume combined with periodically sampling and monitoring drilling fluids during HDD operations will result in a more reliable method for quick spill detection and response. An emergency response plan will be provided to DFO for review as part of the contingency plan for the proposed crossing of the North Saskatchewan River. It will address the items identified under the Operational Statement for High-Pressure Directional Drilling, including measures to stop work, contain the drilling mud and prevent its further migration into the watercourse should a frac-out occur. Spill response materials and equipment will be maintained onsite for the duration of the drilling, and personnel will be trained in their use and in the appropriate response protocols for incidents and emergencies. A frac-out is more likely to occur during boring of the pilot hole when pressure is higher, but the borehole diameter and circulation of drilling fluid would be smaller. For a pilot hole of about 5 inches, the potential release of drilling fluid would be approximately 4 to 7 m 3 in a worst-case scenario. If a loss of drilling fluid is suspected, the operation will be suspended until the source of the loss can be determined. In addition, the following measures will be implemented to monitor for drilling fluid entering the environment: Qualified personnel will monitor both onshore and channel portions water quality along the drill path and surrounding area i.e., upstream and downstream. Water quality monitoring personnel will ensure that industry-accepted monitoring equipment, procedures and methodologies are used. Monitoring locations, including alterations from the minimum requirements, to suit sitespecific conditions will be determined by qualified personnel. Site conditions may change i.e., higher water, ice conditions if approvals are delayed during drilling activities, which may preclude or alter water quality monitoring at predetermined locations. Monitoring personnel will have communication with drilling personnel at all times during daylight monitoring. Daily communication and interaction with the Shell environmental inspectors, including submitting daily reports, is required. Monitoring measures will be in place during nighttime hours, so that adequate coverage occurs. This may include walking the drill path only where safe to do so and when Shell Canada Limited July 2011 Page 3-125

41 3. Part A Quest Carbon Capture and Storage Project procedures are in place and, at a minimum, will include increased diligence in monitoring drilling pressures. Water quality measurement by auto data-loggers installed during daylight hours will be used for nighttime monitoring. Water quality data collected using auto data-loggers will be correlated with water quality measurements obtained by environmental monitors, where possible. Nighttime monitoring will not occur where it is deemed unsafe and hazards cannot be addressed by proper controls. The sampling frequency will be increased if monitoring drilling mud returns indicates that a release may have occurred. Depending on the timing of construction, a plan will be developed to address monitoring in the late fall to early winter, during the transition between ice-free conditions and icecover conditions, when it is safe to access the river monitoring locations Monitoring, Measurement and Verification Question 58: MMV Design Framework Volume 1, Appendix A, Section 2.1, Page 2-1 In January 2011 a Geochemical Soil Gas Survey conducted by Petro-Find Geochem Ltd was released indicating that CO 2 from the Weyburn-Midale CO 2 enhanced oil recovery project in Saskatchewan may be migrating in a manner that was not originally predicted for the site, and reaching the surface. The Weyburn-Midale Measurement, Monitoring and Verification MMV plan is mentioned as an important precedent for MMV in 2.1. a. Given the information presented in the study by Petro-Find Geochem Ltd., will Shell have to adjust any of the components presented in the MMV Design Framework or proposing any additional mitigation measures to ensure Containment and Verify Storage Performance? If not, explain why and if so, provide a description of any proposed changes. Response 58 a. The MMV design framework for the Project does not require any amendment because it already includes provision for an appropriate Project-specific baseline and monitoring program that will identify any anomalous changes in soil quality. The adaptive nature of the proposed MMV program allows Shell to investigate such anomalies further and decide whether they are attributable to the Project. July 2011 Page Shell Canada Limited

42 Quest Carbon Capture and Storage Project 3. Part A The results of the CO 2 soil gas survey reported by Petro-Find Geochem Ltd. are consistent with natural background variations. The International Energy Agency IEA does not believe that this provides evidence of CO 2 migration from the Weyburn-Midale CO 2 enhanced oil recovery project Petroleum Technology Research Centre, no date. REFERENCE Petroleum Technology Research Centre PTRC. No date. IEA-GHG Weyburn-Midale CO 2 Monitoring & Storage Project Response to the Petro-Find Geochem Ltd. Study. Available at: Question 59: Geographic Area of the MMV Program Volume 1, Appendix A While NRCan understands that much of this information was discussed during meetings in the fall of 2010 it is important that it also be addressed in the EIS to ensure that all relevant information is available to the public and other stakeholders. a. Provide a map, if possible, showing the geographic area that will be included in the MMV program and explain if this area will overlap with study areas proposed for any other Carbon Capture and Storage CCS projects. Response 59 a. The Application, Volume 1, Appendix A, Section 2.3 describes the geographical area of review AOR for the MMV activities. The AOR is expected to coincide with the subsurface area of interest AOI for the initial period of operations see Figure The Heartland Area Redwater Project HARP is the only other CCS project known to have been proposed for the area northeast of Edmonton. The HARP Project is proposing operations in the Redwater Leduc Reef. Figure 59-1 shows the location of the HARP Project relative to the proposed injection well locations and the AOI for the Quest CCS Project. The HARP Project is separated from the nearest Quest CCS Project injection well by more than 10 km laterally, and is proposed for horizons approximately 1,000 m above the Quest CCS Project. Shell Canada Limited July 2011 Page 3-127

43 3. Part A Quest Carbon Capture and Storage Project Figure 59-1 Exploration Tenure Area of Interest, Equivalent to the Initial MMV Area of Review July 2011 Page Shell Canada Limited

44 Quest Carbon Capture and Storage Project 3. Part A Question 60: Verifying the Source of a CO 2 Leak Volume 1, Appendix A While NRCan understands that much of this information was discussed during meetings in the fall of 2010 it is important that it also be addressed in the EIS to ensure that all relevant information is available to the public and other stakeholders. a. There are other proposals for CCS projects in the area i.e. HARP. If an accidental release of Basal Cambrian Sands BCS brine or CO 2 were to occur in the vicinity of the project explain if and how the source of the CO 2 will be verified. If the source can not be confirmed discuss how Shell will mitigate the issue collectively with other CCS projects in the area. Response 60 a. The Application, Volume 1, Appendix A, Section describes the principle safeguards designed to avoid uncertainty about the origin of an accidental release of BCS brine or injected CO 2. From The Application, Volume 1, Appendix A, Section : Provision of exclusive pore space tenure is the prime safeguard against threats from any third-party CCS projects. The possibility of competing or indistinguishable environmental impacts from adjacent CCS projects is avoidable if the tenure region is sufficiently large to encompass the zone of elevated pore fluid pressures capable of lifting BCS brine above the base of the groundwater protection zone. Physical separation from any future CCS projects is provided by the size of the pore-space tenure region 40 townships, which is sufficient to avoid an interaction between CO 2 plumes from different operators. Physical separation from the potential HARP Project is provided by a lateral up-dip offset of more than 10 km and a vertical offset of 1,000 m between the location of Project CO 2 injection wells and the Redwater reef. This is sufficient to avoid an interaction between CO 2 plumes from the two different operators. Chemical analysis of groundwater samples from a network of monitoring wells may determine the presence or absence of tracers uniquely associated with injected CO 2 or BCS brine displaced by the injected CO 2. Shell continues to evaluate the feasibility of using tracers. Tracers naturally present within the BCS brine should uniquely distinguish this brine from that of any other aquifer near the storage complex. Initial assessments are ongoing to determine the technical and operational feasibility of both artificial and natural tracers for the injected CO 2 and BCS brine. The outcome of these Shell Canada Limited July 2011 Page 3-129

45 3. Part A Quest Carbon Capture and Storage Project assessments will be included in an update to the MMV Plan, which will be submitted for review before baseline measurements start, two years before sustained CO 2 injection. Further updates will then be submitted every three years, coincident with the required submission of the Closure Plan to Alberta Energy. In the unexpected event that the Project cannot be reasonably excluded as the source of an accidental release, Shell proposes to work cooperatively with other CCS operators to implement control measures appropriate to the particular circumstances of the release to protect the groundwater see the Application, Volume 1, Appendix A, Section and the soil see the Application, Volume 1, Appendix A, Section Question 61: Additional Details on MMV Systems Volume 1, Appendix A Appendix A documents how Shell will approach the development of a monitoring plan, but no detail is given a. Provide specific details related to the types of measuring, monitoring and verification systems Shell has selected. Types, locations, and rationale should be provided, and as well a discussion of how the information will be used. Response 61 a. Table 61-1 describes the components that are now sufficiently matured to be included in the current MMV Plan. The MMV Plan will be implemented by a process of continuous site-specific adaptations in response to monitoring data. The MMV Plan in the Application see Volume 1, Appendix A is conceptual, because the initial selection of monitoring systems depends on the outcome of ongoing site-specific feasibility assessments and future baseline measurements. An updated MMV Plan, which specifies the initial monitoring plan including details such as locations, will be submitted for review before baseline measurements start, two years before sustained CO 2 injection. Shell will also provide an annual report on MMV performance and submit a revised MMV Plan to regulatory agencies every three years, coincident with the required submission of the Closure Plan to Alberta Energy. July 2011 Page Shell Canada Limited

46 Quest Carbon Capture and Storage Project 3. Part A Table 61-1 Item Components Sufficiently Matured to be included in the Monitoring, Measurement and Verification Plan 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. Distributed temperature sensing Shell will install a distributed temperature sensing system outside the production casing in all injection wells. 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 each injection well pad; the remaining groundwater wells may be located elsewhere. 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 already. 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. Interferometric synthetic aperture radar InSAR Shell will acquire InSAR data designed to monitor surface heave induced by CO 2 storage. Remote sensing Shell will acquire remote sensing data designed to detect environmental change. This will include multi-spectral image analysis. Line of sight CO 2 gas flux monitoring A field trial of the line-of-sight CO 2 gas flux monitoring technology will be 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. BCS water tracers 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. Shell Canada Limited July 2011 Page 3-131

47 3. Part A Quest Carbon Capture and Storage Project The MMV Plan contains: the risk-based rationale for monitoring the performance requirements for monitoring the assessment and ranking of many diverse monitoring technologies, with specifics about the expected costs and benefits for each type of MMV system available a conceptual monitoring schedule see the Application, Volume 1, Appendix A, Figure 6-4; reproduced here as Figure 61-1, revised to include notes and a legend. This schedule provides the starting point for adapting the MMV Plan in response to new information from ongoing feasibility assessments, future baseline measurements and future operational monitoring. the contingency monitoring options available to respond to unexpected events the use of monitoring information for safe permanent storage of CO 2 within the BCS storage complex July 2011 Page Shell Canada Limited

48 Quest Carbon Capture and Storage Project 3. Part A NOTES: Continuous lines denote continuous monitoring activities. Squares denote discrete monitoring activities. Numbers denote the number of monitoring systems active. Cement bond logs CBLs denote the timing of well construction. In this example, there are five injection wells, five observation wells in the Winnipegosis Formation and 15 observation wells in the hydrosphere. All wells are drilled before injection starts, except for two Winnipegosis observation wells, which are drilled some years later so their locations may be adapted according to the first VSP results. All groundwater wells are drilled two years before first injection to support baseline data acquisition. The first injection well, the Radway 8-19 appraisal well, was drilled in See the legend for the full monitoring technology names. Figure 61-1 Schedule of Measurement, Monitoring and Verification Activities Shell Canada Limited July 2011 Page 3-133

49 3. Part A Quest Carbon Capture and Storage Project AEC Atmospheric eddy correlation MWIT Mechanical well integrity pressure testing AFNL Time-lapse annular flow noise logging NSEM Magnetotelluric - natural source EM AIRGA Airborne infra-red laser gas analysis NTM Natural isotope tracer monitoring APM Annulus pressure monitoring OIA Operational Integrity Assurance System ATM Artificial tracer monitoring PFOT Pressure fall-off test CAL Time-lapse multi-finger calliper PIT Pressure interference testing CBL Cement bond logs RTCI Real time casing imager CSEM Time-lapse surface controlled source EM SATL Time-lapse saturation logging CSEMX Time-lapse cross-well controlled source EM SEIS2D Time-lapse surface 2D seismic DAS Fibre-optic distributed acoustic sensing SEIS3D Time-lapse surface 3D seismic DENL Time-lapse density logging SEISX Time-lapse cross-well seismic DHGRAV Time-lapse down-hole microgravity SGC Soil CO2 gas concentration surveys DHMS Down-hole microseismic monitoring SGF Soil CO2 gas flux surveys DHPT Down-hole pressure-temperature gauge SGRAV Time-lapse surface microgravity DHTLT Down-hole tiltmeters SMS Surface microseismic monitoring DIAL DIAL - Differential absorption LIDAR SONIC Time-lapse sonic logging DPS Fibre-optic distributed pressure sensing SPH Soil ph surveys DTS Fibre-optic distributed temperature sensing SSAL Soil salinity surveys EMIT Time-lapse EM casing imaging STLT Surface tiltmeters ESS Ecosystem studies TMPL Time-lapse temperature logging GPS GPS - Global Positioning System TRL Tracer injection & gamma logging GWG Ground water gas analysis USIT Time-lapse ultrasonic casing imaging HIA Satellite or airborne hyperspectral image analysis UTUBE U-tube fluid sampling HIRGA Hand-held infra-red gas analysers VSP3D Time-lapse 3D vertical seismic profiling INSAR InSAR - Interferometric Synthetic Aperture Radar WC Water chemistry monitoring IRM Injection rate metering at wellhead WEC Down-hole electrical conductivity monitoring ITUBE Isotube fluid sampling WHCO2 Well-head CO2 detectors LOSCO2 Line-of-sight gas flux monitoring WHPT Wellhead pressure-temperature gauge WPH Downhole ph monitoring Figure 61-1 Schedule of Measurement, Monitoring and Verification Activities cont d July 2011 Page Shell Canada Limited

50 Quest Carbon Capture and Storage Project 3. Part A Question 62: Identifying Potential Leaks Volume 1 Appendix A, Section a. Outline proposals for identifying potential CO 2 leaks from pipelines, wells into air, soils or groundwater using carbon/oxygen isotopes and artificial tracers mercaptans, etc.. b. Outline methods to determine viable baseline signatures for CO 2 in soil and groundwater and thresholds for investigation of anomalous values identified during MMV. c. Discuss limitations and options for the use of natural isotopes and artificial tracers in the MMV plan. Response 62 a. Monitoring plans will be included in an update to the MMV Plan, which will be submitted two years before sustained CO 2 injection. Intended MMV commitments specific for air, soils and groundwater monitoring are as follows see Response 61 for additional commitments: An artificial tracer may be co-injected with the CO 2 at each wellhead, specifically to mark any CO 2 leaks as originating from the Project. These leaks could be released into the air, soil or groundwater. Use of this option will depend on the outcome of ongoing assessments of its technical and operational feasibility. Carbon:oxygen isotope ratios are not expected to be a reliable tracer, as these ratios are unlikely to distinguish injected CO 2 from biogenic CO 2. Any anomalous flux of CO 2 from the soil into the atmosphere is expected to be detected by the line-of-sight CO 2 gas flux monitoring technology. Otherwise, CO 2 soil gas concentration and flux surveys should provide a viable alternative. For groundwater, there will be a network of groundwater monitoring wells see Table 61-1 in Response 61a for details. For monitoring pipeline leaks, the supervisory control and data acquisition SCADA system will monitor pressure and mass balance to determine whether the CO 2 is being injected, or a potential leak is occurring. When there is a mass imbalance, the line block valves will be closed and pressure will be reported by section. The leaking section will have a lower pressure than the other non-leaking sections. In addition, aerial pipeline surveys will be conducted as part of the Pipeline Integrity Management Plan. Escaping gases will create a temperature drop that will be detectable using thermal imagery. b. In principle, baseline measurements for a CO 2 tracer are not required because, by design, this compound will not initially be present near the storage area. Feasibility studies for artificial CO 2 tracers are currently ongoing and a final decision is outstanding. The threshold for detecting an anomalous concentration of the artificial tracer depends on the particular tracer Shell Canada Limited July 2011 Page 3-135

51 3. Part A Quest Carbon Capture and Storage Project selected and the sensitivity of laboratory measurements to detect its presence within soil, water or gas samples. The outcome of these feasibility studies will be provided in an update to the MMV Plan. c. Tracers provide opportunities to identify uniquely the injected CO 2 or any displaced BCS brine. Artificial tracers are not an option for the BCS brine, but several natural tracer options, including natural stable isotopes, are under evaluation. The option to include artificial tracers for injected CO 2 remains under evaluation for operational feasibility. The outcome of these feasibility studies will be provided in an update to the MMV Plan. Question 63: Base-Case Monitoring Volume 1, Appendix A This section provides the principles, framework and concepts of the Measurement, Monitoring and Verification MMV Plan. The review of monitoring technology must be completed and decided on prior to initiating Base-Case monitoring to ensure the appropriate baseline information is collected. a. When will Shell Quest provide the details of the plan for Base-Case monitoring to take place? Response 63 a. For details about the Base-Case monitoring plan, see Response 61. An updated MMV Plan, which will specify the initial monitoring plan including further details, such as locations, will be submitted for review before baseline measurements start, two years before sustained CO 2 injection. Shell will also provide an annual report on MMV performance and submit a revised MMV Plan to regulatory agencies every three years, coincident with the required submission of the Closure Plan to Alberta Energy. Question 64: Soil ph and Soil Salinity Surveys Volume 1, Appendix A, Section This section describes Shell s Biosphere Monitoring Plan. a. Provide the basis for deciding on soil ph and soil salinity surveys as the means for effective monitoring of potential impacts to the biosphere from the unlikely event of compromised containment of injected CO 2 and explain why Soil CO 2 gas fluxes and concentration surveys were not included. July 2011 Page Shell Canada Limited

52 Quest Carbon Capture and Storage Project 3. Part A Response 64 a. Soil ph, soil salinity, soil CO 2 gas flux and soil gas CO 2 concentration surveys soil CO 2 gas fluxes have not yet been included or excluded from the initial Base-Case monitoring plan. For a description of a conceptual Biosphere Monitoring Plan, which remains subject to change, see Figure 61-1, in Response 61, and the Application, Volume 1, Appendix A, Section From the Application, Volume 1, Appendix A, Section 6.5.4: Ecosystem studies ESS, hyper-spectral image analysis HIA, and soil ph SPH and salinity SSAL annual monitoring for two years prior to CO2 injection will establish a sufficient baseline. Monitoring during injection generates the information necessary to verify the absence of any significant impacts to the biosphere or to trigger corrective controls measures if necessary. During the closure period, bi-annual monitoring is sufficient as average pressures inside the storage complex will decrease and the forces driving migration of the CO2 plume and BCS brine become much smaller. The basis for deciding on particular monitoring methods will be the outcome of ongoing sitespecific technical feasibility studies. The outcome of these studies will be provided in an update to the MMV Plan, which will be submitted for review before baseline measurements start, two years before sustained CO 2 injection. Further updates will then be submitted every three years, coincident with the required submission of the Closure Plan to Alberta Energy. The MMV Plan will be implemented by a process of continuous verification and, if necessary, adaptation in response to new information gained from: ongoing site-specific technical feasibility assessments baseline measurements monitoring during the injection and closure periods Question 65: Soil ph Surveys to Detect Changes Volume 1, Appendix A a. How well will soil ph surveys of soils of the AOI, generally regarded as having a relatively high buffering capacity, detect changes to soil ph from uncontained injected CO 2? Response 65 a. Evaluation of specific components of the Base-Case monitoring plan is still underway see Response 64. Shell Canada Limited July 2011 Page 3-137

53 3. Part A Quest Carbon Capture and Storage Project Question 66: Salinity and ph of Soil Volume 1, Figure 6-4 and Section This section briefly describe biosphere monitoring. a. Explain the method that could be employed to monitor soil ph and salinity in a spatial context and how the method would account for wide range of naturally occurring variability both spatial and temporal. b. Discuss whether airborne geophysics been considered as a method to assess soil salinity over a large area such as the AOI. Response 66 a. Soil ph and soil salinity may be monitored through a combination of direct measurements, using site sampling and measurement techniques, and indirect methods, using remote sensing techniques. Measurement of ph and salinity in soil within the AOI before CO 2 injection and at reference sites outside the AOI during CO 2 injection should provide evidence of natural spatial and temporal variability. The method for spatial monitoring has not yet been selected. The basis for deciding on a particular monitoring method will be the outcome of ongoing sitespecific technical feasibility studies that take into account the wide range of naturally occurring spatial and temporal variability. The results of these studies will be provided in an update to the MMV Plan, which will be submitted for review two years before sustained CO 2 injection and then every three years, coincident with the required submission of the Closure Plan to Alberta Energy. b. Airborne geophysics, including electromagnetic survey methods, offers opportunities for wide-coverage soil salinity mapping, and is under consideration for inclusion in the MMV Plan. Question 67: InSAR Technology and Surface Displacement Volume 1, Appendix A, Section Shell provides a description of Notable Technologies and describes InSAR as potentially an effective way of monitoring surface displacements as a result of CO 2 injection. a. How does InSAR technology compensate for surface displacement caused by other activities such as agriculture? July 2011 Page Shell Canada Limited

54 Quest Carbon Capture and Storage Project 3. Part A Response 67 a. InSAR is a space-borne satellite technology for monitoring displacements of the Earth s surface by measuring the travel time of electro-magnetic signals transmitted by the satellite, scattered by the Earth s surface and received again by the satellite. Activities, such as agricultural activities, may induce surface displacements that could mask the effects of CO 2 injection. A correction for this masking is obtained by remote monitoring of nearby permanent and persistent structures, as a baseline against which displacement changes in the landscape can be measured. Question 68: Isotope Characterization Volume 1, Appendix A. a. Provide a discussion on whether isotope characterization of source CO 2 will be conducted as part of the MMV as a means to differentiate from naturally occurring CO 2 found in the geoshere, biosphere and atmosphere? Response 68 a. Initial assessments are ongoing to determine the technical and operational feasibility of CO 2 tracers, including isotope characterization of the source CO 2. The outcome of these assessments will be included in an update to the MMV Plan, which will be submitted two years before sustained CO 2 injection and then every three years, coincident with the required submission of the Closure Plan to Alberta Energy. Also, see Response Terrestrial Question 69: Topsoil Replacement Upland, Wetland, Wildlife Volume 1, Section , Page 2-6 to 2-7 Shell states Topsoil and subsoil will not be mixed during trench backfilling. Backfilling activities will be confined to the construction ROW and will proceed immediately after lowering the pipe in,....salvaged soil materials will be placed in the reverse order of excavation, or lower subsoil returned first and upper subsoil second. a. When will Shell replace topsoil to the ROW trench? b. Provide additional details on timing of topsoil replacement in both upland and wetland sites. Shell Canada Limited July 2011 Page 3-139

55 3. Part A Quest Carbon Capture and Storage Project c. If topsoil will be replaced during the spring, describe how potential conflicts with wildlife will be mitigated? Response 69 ERRATA In the Environmental Protection Plan see the Application, Volume 1, Appendix I incorrect information was provided with regard to topsoil replacement. The correct wording follows incorrect text indicated by strikeout, correct text indicated by bold text. In the Application, Volume 1, Appendix I, Table 4-2, Item 20 should read: Final cleanup and topsoil replacement will take place during suitably dry, non-frozen conditions in the fall. If the schedule does not allow the completion of the topsoil replacement before the soils freeze, then final cleanup will be scheduled for suitably dry non-frozen conditions in the late spring/early summer the following year. late spring or early summer after construction. If construction takes place during non-frozen conditions, topsoil will be replaced during suitably dry, non-frozen conditions as soon as construction, testing and backfilling are complete. In the Application, Volume 1, Appendix I, Table 8-1, Items 1 and 2 should read: 1. Rough cleanup will follow completion of construction operations as soon as practical. Final cleanup will occur during suitably dry non-frozen conditions after the roach has settled and the trench re-contoured to alleviate any subsidence that may have occurred during thawing of the subsoil. Seeding after October 1 is acceptable since seeds will normally remain dormant until spring, additional measures might need to be employed in areas that are exposed to high winds or water movement. 2. If schedule changes require Final cleanup will be completed in spring once the frost comes out of the soils; the priority will be on cultivated lands first to avoid conflicts with agricultural land use. On excessively wet soils, postpone work will be postponed until ground conditions are dry and trafficable. Seeding will be undertaken between May 1 and July 31. a. Final cleanup and topsoil replacement will take place during suitably dry, non-frozen conditions in the late spring or early summer following construction observing any pertinent restricted activity periods as discussed in Response 69c. b. For a description of the preferred timing window for upland topsoil replacement, see Response 69a. The standard procedure for wetland construction, where an open trench crossing method is used, is to replace the mineral subsoil then the overlying organics as soon as possible after lowering-in and hydrostatic testing have taken place. If possible, doing this July 2011 Page Shell Canada Limited

56 Quest Carbon Capture and Storage Project 3. Part A under frozen conditions is preferable, to limit additional surface disturbance that is likely once thawing has occurred. c. Project construction planning will take into consideration timing windows and setback distances for species at risk and other species of wildlife protected under the Migratory Birds Convention Act and the Wildlife Act of Alberta. For a list of the restricted activity dates for protecting the species at risk selected for the environmental assessment, see Table The topsoil replacement will occur within the recommended timing windows for many wildlife species. However, the magnitude of the disturbances and barriers to wildlife is predicted to be low and can be reduced further through mitigation. Due to the removal of habitat and the ground disturbance associated with pipeline installation, few species of wildlife are expected to return to the area of Project construction between the end of winter construction and when the topsoil is replaced. Thus, the activities associated with topsoil replacement are predicted to affect few animals. Potential conflicts with the few species of wildlife that may occur in the area of Project construction in the spring or summer after pipeline installation will be mitigated by the following strategies: Pre-disturbance nest searches will be conducted so that no nests are disturbed or destroyed as per the Migratory Birds Convention Act and the Wildlife Act of Alberta see Table If active nests are found, the setback distances recommended by Alberta Sustainable Resource Development ASRD will be used, so that nests and their contents are protected. The possibility of small wildlife, such as western toads, being buried under soil piles will be mitigated by following Alberta s best practice guidelines produced for the oil and gas industry ASRD 2004, which are as follows: Limit the duration and amount of activity along the ROW approximately 24 hours and 1 km at a time. Check areas adjacent to soil piles at least twice daily for wildlife. Prohibit pets, firearms or recreational use of all-terrain vehicles on the ROW. Do not harass or feed wildlife. Record all wildlife observed within the construction or topsoil replacement sites for submission to ASRD. Shell Canada Limited July 2011 Page 3-141

57 3. Part A Quest Carbon Capture and Storage Project Table 69-1 Restricted Activity Dates Timing Windows and Setback Distances by Species or Species Groups Species at Risk Western toad, Yellow Rail, Rusty Blackbird Sensitive Habitat Wetlands and riparian habitat Additional Species or Species Groups Affected Canadian toad, breeding birds protected under the Migratory Birds Convention Act and the Wildlife Act of Alberta Horned Grebe Nesting sites Breeding birds protected under the Migratory Birds Convention Act and the Wildlife Act of Alberta Western toad Forested and shrubby Hibernating mammals wetlands, coniferous forests and wet shrub habitat within 2 km of a wetland Short-Eared Owl Active nest Nests of owls and diurnal raptors in any habitat type Sprague's Pipit, Canada Warbler, Olive-Sided Flycatcher, Loggerhead Shrike, Bobolink Common Nighthawk, Short- Eared Owl Upland, effective habitat that may contain active nests forest, shrub, pasture Roadside roosting, nesting and foraging sites Breeding birds protected under the Migratory Birds Convention Act and the Wildlife Act of Alberta Timing Window Year round 1 April 15 July 31 1 October March April 1 July 31 2 April 15 July 31 2 Nocturnal foraging wildlife April 1 August 3 1 Recommended Policy Use a setback of 100 m for all activities 1 Use a setback of 500 m from nest sites 1 Do not clear during timing window Use a setback of 200 m during construction or soil replacement activities 2 Do not clear during timing window. Conduct a predisturbance survey if clearing is required during timing window 2 Reduce driving speeds on gravel access roads at night NOTES: 1. Government of Alberta The guiding principles for the timing windows and setback requirements are based on those listed by ASRD REFERENCES Alberta Sustainable Resource Development ASRD Recommended Wildlife Procedures for Pipelines in Alberta. Alberta Fish and Wildlife, Edmonton, AB. Alberta Sustainable Resource Development ASRD Recommended Land Use Guidelines for Protection of Selected Wildlife Species and Habitat within Grassland and Parkland Natural Regions in Alberta. Fish and Wildlife Branch, Sustainable Resource Development, Government of Alberta. Edmonton, AB. Government of Alberta Upstream Oil and Gas Best Management Guidelines for the Enhanced Approval Process. Government of Alberta. Edmonton, AB. July 2011 Page Shell Canada Limited

58 Quest Carbon Capture and Storage Project 3. Part A Question 70: Contingency Crossing of the North Saskatchewan River Volume 2A, Section 8.4, Page 8-11 Shell has elected to cross the North Saskatchewan River using horizontal directional drilling HDD. In the event this crossing method cannot be used, an isolated trench using a two-stage coffer-dam will be used. a. Describe the ecological effects of this crossing method on the aquatic environment and mitigations that will be utilized to minimize effects. b. Will this method require Fisheries and Oceans Canada DFO authorization? If yes, describe discussions Shell has had with DFO to permit this crossing method? c. Will this crossing method be consistent with the Alberta Code of Practice for Pipelines and Telecommunication Lines? Response 70 a. For details on the ecological effects of the contingency crossing method on the North Saskatchewan River, see Response 51. b. The contingency crossing method for the North Saskatchewan River will require DFO authorization. Shell will discuss the contingency crossing method with DFO before starting the crossing by HDD. Shell will also submit a contingency plan for this crossing method to DFO for review. Shell will not perform any clearing or construction before DFO reviews the contingency plan. c. The contingency crossing method for the North Saskatchewan River is consistent with the Alberta Code of Practice for Pipelines and Telecommunication Lines. Question 71: Transplanting Rare Plants Volume 2B, Section 10A.3.3, Page 10A-12 Volume 2B, Section , Page 18-7 Shell states To manage Project and cumulative effects on vegetation, Shell plans the following programs;....rare plant transplantation and subsequent success monitoring for three years. Shell discovered during field surveys rare plant, leather leaf grape fern Botrychium multifidum var. intermedium, as occurring in the project area and thus potentially a transplant candidate. a. Has Shell discussed transplanting of this species and or other potential mitigations with the Alberta Conservation Information Management System formerly ANHIC? Discuss. b. Describe Shell s follow-up mitigation for an unsuccessful transplant. Shell Canada Limited July 2011 Page 3-143

59 3. Part A Quest Carbon Capture and Storage Project Response 71 a. Yes, Shell has discussed transplanting of this species and other potential mitigation strategies with personnel at Alberta Conservation Information Management System ACIMS formerly Alberta Natural Heritage Information Centre [ANHIC]. Avoidance is the preferred scenario for all rare plants. Shell has located the pipeline route adjacent to an existing pipeline, to limit overall disturbance as a result of the Project. However, avoidance of the leather grape fern is not practical, and transplantation was the recommended mitigation strategy included in the Application. ACIMS personnel suggested that transplants should be monitored, preferably for longer than one season Allen 2011, pers. comm.. Shell proposes to monitor transplants of leather grape fern for three years, over a five-year period: at years one, three and five after transplanting. b. Before transplanting and construction, Shell proposes to search for other individuals of this species in the quarter section NW W4M, where the known population of leather grape fern was found on an area that will be physically disturbed as a result of the Project. Knowledge of other individuals within the quarter section, but outside the area that will be physically disturbed as a result of the Project, will ease concerns about loss of the population if transplanting is done. As individuals of leather grape fern are known to go dormant for one to three years at a time Mesipuu et al. 2009, it is possible that not all individuals present along the ROW will be transplanted. If successful, transplanting individuals of the population will reduce cumulative environmental effects, which were considered not significant see the Application, Volume 2B, Section REFERENCES Mesipuu, M., R.P. Shefferson and T. Kull Weather and herbivores influence fertility in the endangered fern Botrycium multifidum S.G.Gmel. Rupr. Plant Ecology 203: PERSONAL COMMUNICATION Allen, Lorna Coordinator, Alberta Conservation Information Management System ACIMS. Government of Alberta. March 15, July 2011 Page Shell Canada Limited

60 Quest Carbon Capture and Storage Project 3. Part A 3.9. Health Question 72: Make-up Amine Required Volume 2B, Section , Page a. Discuss the quantity of make-up amine required and the ultimate disposition of the amine. Response 72 a. The amine make-up quantity is 36 kg/h or about 25 m 3 per month. In the pre-combustion capture configuration used in the Project, amine losses are primarily to the water treatment plant, with very small losses to the furnaces for combustion. Amine losses are primarily due to amine carryover with wash water from the three wash water columns and also with the purge water from the reflux drum. These water streams are diverted to the waste water treatment facility at the Scotford Upgrader, where the amine content is consumed by the bio-mass. A very small quantity of amine, up to 1 ppmw, flows through the capture unit, proceeding to the pressure swing adsorber PSA. The PSA produces a rich hydrogen stream that is used in the Upgrader and an off-gas stream that is recycled back to the HMU furnace as part of fuel gas. The amine is carried with the off-gas to the furnace for combustion. Question 73: Disturbance from Construction Noise Volume 2A, Section 6, Pages 6-1 to 6-36 a. Provide an estimate of the project noise-related change in the percentage highly annoyed %HA at each representative receptor from either construction or operational noise. Shell can do this by using Annex D, equation D1, of ISO , where the %HA is estimated with the following equation: HA = 100 / [1 + exp10,4 0,132* RL] % where RL is a rating level, which is an adjustment to any measured or calculated sound level. Shell can use Annex A in ISO for guidance on what the applicable adjustments are. As noted in this standard, an adjustment of up to +10dBA may also be applicable in quiet rural areas where there is a greater expectation for and value placed on peace and quiet. The receptors in this area seem to be located in what would be characterised as quiet rural areas. Shell Canada Limited July 2011 Page 3-145

61 3. Part A Quest Carbon Capture and Storage Project b. Provide the estimated complaints and/or change in %HA from construction noise. The equation provided in part a above should only be used for construction noise that has a total exposure duration at any given receptor that is greater than 1 year. For construction noise lasting less than one year, an estimate of widespread complaints may be appropriate using EPA Levels 1974, which is based on a normalized day-night equivalent noise levels Ldn value. A normalized Ldn is a calculated day-night sound level that is used to determine the potential for widespread complaints. The normalized Ldn is obtained from the measured value and the addition of various corrections in dba EPA These adjustments are similar, but not identical to those outline in ISO for estimating community annoyance. c. Provide the thresholds for sleep disturbance. Shell should be aware of the noise thresholds for sleep disturbance as outlined in the WHO Community Noise Guidelines Sleep disturbance starts to occur when continuous sound levels inside the bedroom exceed 30dBA i.e. 45dBA outside, assuming a 15dBA transmission loss with windows partially opened. The WHO also recommends that noise events exceeding 45dBA Lmax be limited to during sleeping hours in order to avoid adverse impacts on sleep. Response 73 a. The Project is not predicted to result in any noise annoyance and sleep disturbance. The Project will operate in compliance with ERCB Directive 38 during both the construction and operations phase. However, for an estimate of the percentage of highly annoyed %HA individuals during Project operation, using procedures described in Annex D, Equation D1, of ISO , see Table The percentage of highly annoyed individuals at the residences ranges from 2.2 to 3.6% during operations, which is less than the 6.5% limit recommended by Health Canada. July 2011 Page Shell Canada Limited

62 Quest Carbon Capture and Storage Project 3. Part A Table 73-1 Predicted Percentage of Highly Annoyed Individuals During Operation Column 1 Column 2 Column 3 Column 4 Column 5 Column 6 Column 7 Residence No. Predicted Base Case CSL dba L eq 9 Predicted Sound Level Contribution from the CO 2 Capture Infrastructure dba L eq 9 Predicted Application Case Nighttime CSL Columns 2+3 dba L eq 9 Predicted Application Case Daytime CSL a dba L eq 15 Predicted Day-Night Average Sound Level dba Ldn Predicted Percentage Highly Annoyed Individuals %HA b c c NOTE: a Daytime CSL assumes a 10 db daytime adjustment per ERCB Directive 38. b Residence 33 is located within the fenceline of the planned TOTAL upgrader. It is no longer occupied and is included in the assessment for information only. c Residence 81 is located approximately 5.3 km north of the Project while Residence 72 is 2.2 km southwest of the Project. %HA percentage highly annoyed CSL comprehensive sound level b. The NIA was conducted in accordance with the requirements of ERCB Directive 38. Directive 38 requires that reasonable measures be taken to mitigate construction noise, where possible. Shell is committed to minimizing noise levels during construction activities. Noisy construction activities will be scheduled to daytime hours 07:00 to 20:00. In accordance with Directive 38, Shell will also provide advance notice by letter to nearby residents of upcoming construction activities involving noise. c. Shell is aware of the noise thresholds for sleep disturbance as outlined in the World Health Organization WHO Community Noise Guidelines published in 1999, and agrees that sleep disturbance starts to occur when continuous sound levels inside the bedroom exceed 30 dba i.e., 45 dba outside. The predicted outdoor noise levels during both day and night from the Project range from 20 to 32 dba at the residential locations. This is less than the 45 dba outdoor levels specified in WHO guidelines. In addition, Project construction will take place during day time hours only and will therefore not likely result in sleep disturbance. Shell Canada Limited July 2011 Page 3-147

63 3. Part A Quest Carbon Capture and Storage Project Question 74: Potentially Affected Drinking Water Sources Volume 2B, Section , Pages to Shell indicates that an accidental release of CO 2, Basal Cambrian Sands BCS brine, or CO 2 saturated brine from the storage complex or from an injection well could impact groundwater sources. An increase in dissolved CO 2 in groundwater would result in a decrease in ph which could then react with alkaline materials in the sediments, resulting in the mobilization of trace elements which may include heavy metals such as antimony, arsenic, barium, cadmium, lead, mercury, nickel, selenium, uranium, and zinc; an increase in CO 2 saturated BCS brine would have a similar impact. An increase in BCS brine in groundwater would elevate the total dissolved solids TDS concentrations as well as potentially mobilize metals present in the aquifer minerals due to its low ph. If this were to happen in a community or private well groundwater source, impacts on human health as well as on the drinking water treatment process itself could occur. Information on whether any groundwater drinking water sources could be impacted by the project was not given. Shell indicates that the communities of Fort Saskatchewan, Bon Accord, Bruderheim, Gibbons, Josephburg, Lamont, Thorhild and Redwater are found near the project as well as a few public use areas Bruderheim Natural Area, Astotin Natural Area, Fort Saskatchewan Natural Area, Redwater Natural Area and Wayside campsite, however, Shell does not indicate the type of drinking water source for these communities/public use areas and whether these drinking water sources could be impacted by any accidental releases of CO 2, BCS brine, or CO 2 saturated brine from the storage complex or from an injection well. Additionally, no information on private well owners whom could be potentially impacted by the project was given. a. In order to assess any human health impacts of the project via drinking water, provide information on potentially impacted drinking water sources communities and private well owners as well as information on any drinking water treatment processes currently being used. b. In the event of adverse impacts on source water surface water or groundwater quality from the project i.e. accidental release of CO 2, BCS brine, or CO 2 saturated brine from the storage complex or from an injection well, confirm if Shell s emergency response plans will include instructions to communicate immediately with potentially impacted drinking water treatment facilities and residents whose drinking water comes from a source other than a drinking water treatment facility. July 2011 Page Shell Canada Limited

64 Quest Carbon Capture and Storage Project 3. Part A Response 74 a. The location and details for potential groundwater-derived drinking water sources and domestic use water wells in the AOI were determined by reviewing: AENV groundwater diversion licences AENV Water Well Information Database Prairie Farm Rehabilitation Administration PFRA regional groundwater assessment reports To identify potential groundwater-derived drinking water sources, the AENV groundwater diversion licences were querried for licences with Municipal or Recreational activity types see Table 74-1, as those descriptors encompass activities that could include drinking water use. Within the AOI are 18 such licences and by extension, potential licensed drinking water sources. Specific activities associated with these licences include Recreational, Cooperative, Urban, Subdivision and Camps. For the location of the 18 licences in the AOI, see Figure 74-1, with symbology reflecting the specific activity of the particular licence. Within the AOI are groundwater diversion licences for three urban water supplies: Village of Warspite licences and Hamlet of Newbrook licences 32946, 32947, and Hamlet of Egremont licence Details regarding treatment system process for these three urban water supplies are not included in the licences. Shell obtained the locations and details of potential domestic use water wells in the AOI from the PFRA regional groundwater assessment reports and the AENV Water Well Information Database. These wells include those that may not currently be in use and those that are used for purposes other than human consumption. The locations of these wells are presented in the groundwater resources baseline in the Application see Volume 2A, Section 7, Appendix 7A, Figure 7A-24, replicated here with minor updates. The domestic well locations are presented in Figure 7A-24 to illustrate the distribution of potential groundwater users in the AOI. The AOI has 5,598 water wells, which represent potential unlicensed drinking water sources domestic and traditional agricultural uses are generally exempt from licensing requirements. Interactions between the Project and shallow groundwater resources are not expected under normal operating conditions. Recent communication with AENV Curran 2011 indicates that all municipal water supply systems within the AOI, except for the hamlet of Warspite, are now connected to the regional water distribution system operated by EPCOR Utilities Inc. EPCOR. This regional system Shell Canada Limited July 2011 Page 3-149

65 3. Part A Quest Carbon Capture and Storage Project distributes treated, potable water from water treatment plants located in the City of Edmonton E.L. Smith and Rossdale plants. The source water for these plants is the North Saskatchewan River at Edmonton. The hamlet of Warspite currently uses a reverse osmosis process to treat a split stream of groundwater, followed by blending and chlorination before distribution. Current plans are for the hamlet of Warspite also to be connected to EPCOR s regional water distribution network in fall b. In the event of any confirmed or suspected adverse environmental effect from the Project on source water quality surface water or groundwater, Shell will communicate the issue with: potentially affected drinking water treatment facilities potentially affected residents whose drinking water comes from a source other than a drinking water treatment facility In the Emergency Response Plan for the Project, Shell will include a special procedure guideline for adverse effect on source water. REFERENCE PERSONAL COMMUNICATION Curran, David Municipal Engineer, Alberta Environment. July 20, July 2011 Page Shell Canada Limited

66 Quest Carbon Capture and Storage Project 3. Part A Table 74-1 Nonsaline Groundwater Diversion Licences - Municipal and Recreational Approval ID Licensee Status Status Date Effective Date Expiry Date Activity Type Specific Activity SOURCE Total Quantity m 3 /a Maximum Diversion Rate m 3 /d Priority Number Latitude Longitude Tawatinaw Valley Ski Club Active 29-OCT OCT-1992 Recreational Recreational Unnamed Aquifer - Unclassified 74,010 1, County of Thorhild No. 7 Active 03-JUN JUN-1985 Municipal Cooperative Unnamed Aquifer - Unclassified 1, County of Thorhild No. 7 Active 24-NOV NOV-1995 Municipal Urban Unnamed Aquifer - Unclassified 12, County of Thorhild No. 7 Active 24-NOV NOV-1995 Municipal Urban Unnamed Aquifer - Unclassified 9, County of Thorhild No. 7 Active 24-NOV NOV-1995 Municipal Urban Unnamed Aquifer - Unclassified County of Thorhild No. 7 Active 27-JAN JAN-1986 Municipal Urban Unnamed Aquifer - Unclassified 7, County of Thorhild No. 7 Active 31-AUG AUG-2010 Municipal Urban Unnamed Aquifer - Unclassified 4, County of Thorhild No. 7 Active 31-AUG AUG-2010 Municipal Urban Unnamed Aquifer - Unclassified County of Thorhild No. 7 Active 27-JAN JAN-1986 Municipal Urban Unnamed Aquifer - Unclassified 1, County of Thorhild No. 7 Active 27-JAN JAN-1986 Municipal Urban Unnamed Aquifer - Unclassified Half Moon Lake Water Co-Op Active 02-NOV NOV-1990 Municipal Subdivision Unnamed Aquifer - Unclassified Village of Clyde Active 07-APR APR-1986 Municipal Urban Unnamed Aquifer - Unclassified 88, Smoky Lake County Active 10-AUG AUG-1995 Municipal Urban Unnamed Aquifer - Unclassified 18, Smoky Lake County Active 13-JUL JUL-1983 Municipal Urban Unnamed Aquifer - Unclassified Smoky Lake County Active 13-JUL JUL-1983 Municipal Urban Unnamed Aquifer - Unclassified 4, Shiloh Youth Ranch Active 07-APR APR APR-2028 Recreational Recreational Unnamed Aquifer - Potable Shiloh Youth Ranch Active 07-APR APR APR-2028 Recreational Recreational Unnamed Aquifer - Potable 1, Access Pipeline Inc. Active 22-SEP SEP SEP-2019 Municipal Camps Unnamed Aquifer - Potable Shell Canada Limited July 2011 Page 3-151

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68 ± Nonsaline Groundwater Diversions Use Type COLINTON [ t Camps / Cooperative [ k Recreational & Subdivision % & Urban MEANOOK Quest Project Wells Completed Appraisal Well Candidate Injection Well* AOI ELLSCOTT County Boundaries Pipeline Route Shell Scotford PERRYVALE Town/Village/Hamlet LONG LAKE 6 Kilometres *note that well 8-19 has also been completed as an appraisal well % & NESTOW ABEE % & THORHILD [ k NEWBROOK & TAWATINAW ROCHESTER 8-19 RADWAY WARSPITE 7-11 % & & % EGREMONT / TOWN OF LEGAL OPAL TOWN OF REDWATER 3-4 [ k TOWN OF GIBBONS CARDIFF [ t STAR TOWN OF BRUDERHEIM CARBONDALE TOWN OF LAMONT NAMAO AB BC Area of Interest USA QUEST CARBON CAPTURE AND STORAGE PROJECT SK ST. MICHAEL TOWN OF BON ACCORD Location of Licensed Municipal and Recreational Use Nonsaline Groundwater Diversions Acknowledgements: Original Drawing by Stantec Pipeline: Sunstone Engineering August 11, 2010, Basedata: Altalis 1 Million PREPARED BY PREPARED FOR FIGURE NO. 74-1

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70 ± Groundwater Well* Completed Appraisal Well Candidate Injection Well** AOI County Boundaries Pipeline Route Major Road Railway Watercourse Waterbody Urban Area Kilometres *AENV Water Well Database Records **note that well 8-19 has also been completed as an appraisal well AB BC Area of Interest USA XXX REVX QUEST CARBON CAPTURE AND STORAGE PROJECT SK Groundwater Wells in the Assessment Area Acknowledgements: Original Drawing by Stantec Pipeline: Sunstone Engineering August 11, 2010, Basedata: Altalis 1 Million PREPARED BY PREPARED FOR FIGURE NO. 7A-24

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72 Quest Carbon Capture and Storage Project 3. Part A Question 75: Potential Additional Contaminants Volume 2B, Appendix 5A Table 5A-2, Page 5A-9 Chemicals evaluated in the air quality assessment are: NOx; SO 2 ; PM 2.5; and VOC total. VOC emissions appear to be evaluated as total VOCs rather than individual chemicals. The following chemicals and chemical groups have been associated with natural gas fueled compressors US EPA, 1995; IPCC, 2005: Methane Carbon monoxide Halogenated aliphatics and aromatics Monoaromatic hydrocarbons i.e. BTEX Polycyclic aromatic hydrocarbons PAH Aliphatic hydrocarbons Acrolein Biphenyl Aldehydes Methanol a. Provide an assessment of the potential for the project to contribute to these or other relevant VOC chemicals individually and the potential of these results to change the conclusions of the HHRA. b. If additional exposure pathways are relevant based on the inclusion of individual VOCs, include an assessment of the potential health risks for these chemicals in the HHRA. There is evidence that ammonia NH 3 emissions may occur in carbon capture and storage CCS facilities due to the degradation of the amine solvent used during CO 2 capture van Horssen et al., c. Discuss the rationale for excluding NH 3 emissions in the air modelling study. d. Discuss the potential human health implications of NH 3 emissions. e. Provide a rationale for excluding metals as COPC. Response 75 a. As volatile organic compound VOC emissions will not change as a result of the Project, they are not included in this assessment. No new combustion sources or new types of fuel are being used in existing combustion sources associated with the Project. The compressors will be electrically driven. Direct emissions from the Project are only from modifications of the existing HMUs, resulting in increased temperatures and subsequent increased emissions of nitrogen oxide gases NO X. Shell Canada Limited July 2011 Page 3-157

73 3. Part A Quest Carbon Capture and Storage Project b. A comprehensive assessment of VOC emissions associated with the Scotford Upgrader 2 Project, and other sources in the area, was completed in 2007 Shell A comprehensive assessment was also completed in 2005 for the Scotford Upgrader Expansion Project. The Human Health Risk Assessment HHRA of the most recent Shell upgrader application Shell 2007 assessed a comprehensive list of emissions e.g., VOCs and polycyclic aromatic hydrocarbons [PAHs] for all relevant pathways of exposure. As no changes in VOC or PAH concentrations are anticipated in relation to the Quest CCS Project, an update to the 2007 results is not necessary. c. The Project s CO 2 capture infrastructure captures CO 2 from the synthesis gas process stream pre-combustion at the outlet of the HMUs and not from the post-combustion flue gas stream. The concern expressed in the report by Van Horssen et al refers to postcombustion capture. Ammonia emissions for the selected process for the Project are not a concern. d. Because the Project is not expected to be a source of ammonia emissions, a health risk assessment focusing on ammonia was not undertaken. e. No new combustion sources or new types of fuel are being used in existing combustion sources associated with the Project. Project changes are limited to modifications of the existing HMUs, resulting in increased temperatures and subsequent increased NO X emissions. Metals are not included in this assessment because the metal emissions from the Scotford Upgrader are not expected to change due to the Project. REFERENCE Shell Canada Ltd Application for Approval of the Scotford Upgrader 2 Project: Environmental Impact Assessment. July van Horssen, A., T. Kuramochi, M. Jozicka, J. Koornneef, T. van Harmelen, A.R. Ramírez The impacts of CO 2 capture technologies in power generation and industry on greenhouse gases emissions and air pollutants in the Netherlands. Dutch Policy Research Programme on Air and Climate / Beleidergericht Onderzoeksprogramma Lucht en Klimaat BOLK, Netherlands. Available at: July 2011 Page Shell Canada Limited

74 Quest Carbon Capture and Storage Project 3. Part A Question 76: Maximum Point of Impingement for COPCs Volume 2B, Section , Figure 14-2 Page 14-9 a. Provide a figure identifying the locations of the maximum point of impingement MPOI for each COPC. b. Do the receptor locations modeled correspond to the MPOI for each COPC? If not, provide modelling results for a hypothetical receptor located at each MPOI and discuss the human health implications. Response 76 a. In the HHRA, two chemicals of potential concern COPCs are discussed: NO 2 and PM 2.5. Project NO X emissions are anticipated to increase only from the three existing HMUs due to increased combustion temperature. Therefore, the COPCs of concern are limited to NO 2 and PM 2.5 because NO X emissions are a precursor to secondary PM 2.5 formation. Air quality modelling was undertaken to determine the spatial patterns of NO 2 and PM 2.5 concentrations. To determine spatial variability, the air quality assessment see the Application, Volume 2A, Section 5 provided maximum concentrations along the Shell Scotford fenceline and outside the fenceline, but inside the 50 km by 50 km LAA. The results are presented as a series of concentration maps and as tables see Tables 5-15, 5-16 and 5-17 [for NO 2 ] and Tables 5-22, 5-23 and 5-24 [for PM 2.5 ], reproduced here. In addition, Table 76-1 provides the 8 th highest 1-hour concentrations in a day and Table 76-2 the 8 th highest 24-hour PM 2.5 concentrations. Table 76-1 is compatible with the new form of the US Environmental Protection Agency EPA air quality standard for NO 2, and Table 76-2 is compatible with the Canadian Council of Ministers of the Environment CCME Canadawide standard CWS for PM 2.5. In addition, the following figures are presented: Figures 76-1, 76-2 and 76-3 provide the 9 th highest predicted 1-hour average NO 2 concentrations for the Base, Application and Planned Development Cases, respectively. The only difference between these figures and Figures 5-4, 5-5 and 5-6 in the Application see Volume 2A, Section 5 is that the maximum point of impingement MPOI within the LAA is identified explicitly. Figures 76-4, 76-5 and 76-6 provide the 2 nd highest predicted 24-hour average NO 2 concentrations for the Base, Application and Planned Development Cases, respectively. The only difference between these figures and Figures 5-7, 5-8 and 5-9 in the Application Volume 2A, Section 5 is that the MPOI within the LAA is identified explicitly. Shell Canada Limited July 2011 Page 3-159

75 3. Part A Quest Carbon Capture and Storage Project Figures 76-7, 76-8 and 76-9 provide the predicted maximum annual NO 2 concentrations for the Base, Application and Planned Development Cases, respectively. The only difference between these figures and Figures 5-10, 5-11 and 5-12 in the Application Volume 2A, Section 5 is that the MPOI within the LAA is identified explicitly. Figures 76-10, and provide the 9 th highest predicted 1-hour average PM 2.5 concentrations for the Base, Application and Planned Development Cases, respectively. The only difference between these figures and Figures 5-13, 5-14 and 5-15 in the Application Volume 2A, Section 5 is that the MPOI within the LAA is identified explicitly. Figures 76-13, and provide the 2 nd highest predicted 24-hour average PM 2.5 concentrations for the Base, Application and Planned Development Cases, respectively. The only difference between these figures and Figures 5-16, 5-17 and 5-18 in the Application Volume 2A, Section 5 is that the MPOI within the LAA is identified explicitly. Figures 76-16, and provide the predicted maximum annual PM 2.5 concentrations for the Base, Application and Planned Development Cases, respectively. The only difference between these figures and Figures 5-19, 5-20 and 5-21 in the Application Volume 2A, Section 5 is that the MPOI within the LAA is identified explicitly. The figures indicate that the MPOI in the LAA occurs in northwest Edmonton, or within existing or planned industrial facilities other than Shell Scotford. For these locations, the Project emissions are not predicted to have any contributions to these MPOI in the LAA. For this reason, the discrete receptors that are closer to the Project see the Application, Volume 2A, Appendix 5D, Figure 5D-2, reproduced here at the end of Response 76a are viewed as providing a better basis for evaluating risk to human health than the MPOI, which is not influenced by Project emissions. July 2011 Page Shell Canada Limited

76 Quest Carbon Capture and Storage Project 3. Part A Table hour 9 th Highest NO 2 Concentrations 1-hour 9th Highest NO 2 Concentration µg/m 3 Planned Base Case Application Case Development Case Location Year µg/m 3 µg/m 3 % change µg/m 3 % change Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial AAAQO NOTES: The cell entry represents the maximum from each simulation year. The % change is with respect to the Base Case. AAAQOs are not applicable within an industrial fenceline. Shell Canada Limited July 2011 Page 3-161

77 3. Part A Quest Carbon Capture and Storage Project Table hour 2 nd Highest NO 2 Concentrations 24-hour 2 nd Highest NO 2 Concentration µg/m 3 Planned Base Case Application Case Development Case Location Year µg/m 3 µg/m 3 % change µg/m 3 % change Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial AAAQO NOTES: The cell entry represents the maximum from each simulation year. The % change is with respect to the Base Case. AAAQOs are not applicable within an industrial fenceline. July 2011 Page Shell Canada Limited

78 Quest Carbon Capture and Storage Project 3. Part A Table 5-17 Annual NO 2 Concentrations Annual NO 2 Concentration µg/m 3 Base Case Application Case Planned Development Case Location Year µg/m 3 µg/m 3 % change µg/m 3 % change Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial AAAQO NOTES: The cell entry represents the maximum from each simulation year. The % change is with respect to the Base Case. AAAQOs are not applicable within an industrial fenceline. AAAQO exceedances are shown in bold and are attributable to urban emissions, such as vehicles Shell Canada Limited July 2011 Page 3-163

79 3. Part A Quest Carbon Capture and Storage Project Table hour 9 th Highest PM hour 9 th Highest PM 2.5 Concentration µg/m 3 Planned Base Case Application Case Development Case Location Year µg/m 3 µg/m 3 % change µg/m 3 % change Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial AAAQG NOTES: The cell entry represents the maximum from each simulation year. The % change is with respect to the Base Case. AAAQG = Alberta Ambient Air Quality Guideline. AAAQGs are not applicable within an industrial fenceline. AAAQG exceedances are shown in bold. July 2011 Page Shell Canada Limited

80 Quest Carbon Capture and Storage Project 3. Part A Table hour 2 nd Highest PM 2.5 Concentrations Base Case 24-hour 2 nd Highest PM 2.5 Concentration µg/m 3 Application Case % change µg/m 3 Planned Development Case % change Location Year µg/m 3 µg/m 3 Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial AAAQO NOTES: The cell entry represents the maximum from each simulation year. The % change is with respect to the Base Case. AAAQOs are not applicable within an industrial fenceline. AAAQO exceedances are shown in bold. Shell Canada Limited July 2011 Page 3-165

81 3. Part A Quest Carbon Capture and Storage Project Table 5-24 Annual PM 2.5 Concentrations Base Case Annual PM 2.5 Concentration µg/m 3 Planned Application Case Development Case Location Year µg/m 3 µg/m 3 % change µg/m 3 % change Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial AAAQO NOTES: The cell entry represents the maximum from each simulation year. The % change is with respect to the Base Case. Alberta does not have an AAAQO for PM2.5. July 2011 Page Shell Canada Limited

82 Quest Carbon Capture and Storage Project 3. Part A Table hour 8 th Highest in One Day NO 2 Concentrations Along Shell Scotford fenceline Outside Shell Scotford fenceline Base Case Application Case Future Case 8 th Highest 3-year Rolling Average 8 th Highest 3-year Rolling Average 8 th Highest 3-year Rolling Average Discrete Receptor Agricultural/ Residential Residential/ Community Public Access Area Commercial/ Industrial US EPA Standard Shell Canada Limited July 2011 Page 3-167

83 3. Part A Quest Carbon Capture and Storage Project Table th Highest 24-hour PM 2.5 Concentrations Base Case 24-hour 8 th Highest PM 2.5 Concentration µg/m 3 Application Case Planned Development Case Location Year µg/m 3 µg/m 3 % change µg/m 3 % change Along Shell Scotford fenceline Outside Shell Scotford fenceline Discrete Locations 0 0 Agricultural/Residential Residential/Community Public Access Area Commercial/Industrial CWS NOTES: The cell entry represents the average from three rolling simulation years. The % change is with respect to the Base Case. AAAQOs are not applicable within an industrial fenceline. CWS Canada-wide standard July 2011 Page Shell Canada Limited

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