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Controlled Document

Quest CCS Project

Basic Design & Engineering Package

Project Quest CCS Project

Document Title Basic Design & Engineering Package

Document Number 07-1-AA-7739-0001

Document Revision 04

Document Status Approved

Document Type AA7739-Project Specification

Control ID 238

Owner / Author Steve Peplinski

Issue Date 2011-09-09

Expiry Date None

ECCN EAR 99

Security Classification Restricted

Disclosure None

Revision History shown on next page

07-1-AA-7739-0001 Restricted

Basic Design & Engineering Package 04

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Revision History

REVISION STATUS APPROVAL

Rev. Date Description Originator Reviewer Approver

01 2010-11-10 Draft for Review Manoj Dharwadkar Steve Peplinski Anita Spence

02 2010-11-24 Issued for DG3 Manoj Dharwadkar Steve Peplinski Anita Spence

03 2011-05-29 Limited Updates for

ITR4 Manoj Dharwadkar Steve Peplinski

04 2011-09-13 Issued for VAR4 Manoj Dharwadkar Steve Peplinski Anita Spence

04 2011-10-04 Approved Manoj Dharwadkar Steve Peplinski Anita Spence

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

Signatures for this revision

Date Role Name Signature or electronic reference (email)

Originator Manoj

Dharwadkar

2011-10-04 Reviewer Steve Peplinski Email and in Assai

2011-10-04 Approver Anita Spence Email and in Assai

Summary

Basic Design & Engineering Package for Quest CCS Project

Keywords

Quest, CCS, Basic Design & Engineering Package, Capture, Pipeline, Wells, DG4, VAR4, ITR4



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Table of Contents

1. PROJECT OVERVIEW .................................................................................... 111.1. General ................................................................................................... 111.2. Overall Quest CCS Project Drivers for Design ............................................... 111.3. Scope of BDEP ........................................................................................ 121.4. Design Case Definition .............................................................................. 121.5. Contributors ............................................................................................ 131.6. Key Reference Documents ......................................................................... 13

2. GENERAL DESIGN CONSIDERATIONS ........................................................ 142.1. Process Unit Capacities .............................................................................. 142.2. Feedstock Specifications............................................................................. 152.3. Product Specifications ............................................................................... 152.4. CO2 Specific Design Philosophy / Guidelines for Quest .................................. 16

2.4.1. Venting and Relief of CO2 Vapour ....................................................... 162.4.2. Supercritical CO2 Venting .................................................................. 162.4.3. High Pressure CO2 Equipment ............................................................ 172.4.4. CO2 BLEVE............................................................................... 172.4.5. Metallurgy ..................................................................................... 17

2.5. Sparing Philosophy ................................................................................... 182.6. Cooling Philosophy ................................................................................... 18

2.6.1. HMU 1, 2 and 3 (Brownfield) ............................................................. 182.6.2. Amine Regeneration and CO2 Compression (Greenfield) ................................ 182.6.3. Air Cooling ................................................................................... 19

2.7. Operating Philosophy ................................................................................ 192.7.1. Hydrogen Manufacturing and CO2 Capture .............................................. 192.7.2. Amine Regeneration, CO2 Compression and Transport ................................. 20

2.8. Unit Availability ........................................................................................ 212.9. Turndown Requirements ............................................................................ 212.10. Interface with Existing Facilities .................................................................. 212.11. Meteorological and Site Data ....................................................................... 232.12. Units of Measurement ............................................................................... 252.13. Instrumentation and Control Philosophy ....................................................... 252.14. Project Design Standards and Codes ............................................................. 272.15. Engineering Documents and Unit Numbering Standards .................................. 292.16. Class of Facilities ...................................................................................... 302.17. Modularization Approach ........................................................................... 30

3. HEALTH, SAFETY, ENVIRONMENT AND SUSTAINABLE

DEVELOPMENT ........................................................................................... 323.1. Overview ................................................................................................ 32



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3.2. Technical HSE Work done in FEED Phase ................................................... 323.3. Key HSE Hazards & Issues ........................................................................ 323.4. Technical HSE Work planned for Execute Phase ............................................ 333.5. Human Factors Engineering Plans (HFE) ...................................................... 33

3.5.1. Purpose ........................................................................................ 333.5.2. Scope ........................................................................................... 34

3.6. Energy Management and Greenhouse Gases .................................................. 353.7. Waste Minimization................................................................................... 353.7.1 General ................................................................................................... 363.7.2 Scope ...................................................................................................... 37

4. ITEMS TO BE RESOLVED IN EXECUTE PHASE ............................................ 39

5. OVERALL UTILITY SUMMARIES & BATTERY LIMIT TABLE .......................... 435.1. Overall Utility Summaries ........................................................................... 435.2. Battery Limit Table ................................................................................... 43

6. CAPTURE LOCATION AND SITE PLAN ......................................................... 44

7. CAPTURE PLOT PLAN ................................................................................... 467.1. Amine Regeneration, CO2 Compression and CO2 Dehydration Area ................. 467.2. HMU 1 & 2 Capture Area (Amine Absorbers and wash water

equipment) .............................................................................................. 487.3. HMU 3 Capture Area (Amine Absorbers and wash water equipment) ................. 497.4. Interconnection to existing units .................................................................. 497.5. Client Plot Plan Review including HFE and Constructability ............................. 51

8. OPERATING MODE CASE STUDIES .............................................................. 53

9. HIGH LEVEL RAM STUDY ............................................................................ 61

10. PROJECT INTEGRATION .............................................................................. 62

11. INSTRUMENTATION AND CONTROL .......................................................... 6511.1. Lean Amine Distribution ............................................................................ 6511.2. Amine Stripper Reboiler Controls ................................................................ 6511.3. Hydrogen Manufacturing Units (HMU 1/2/3) ............................................... 6511.4. CO2 Compressor Controls ......................................................................... 6611.5. Third Generation Modularization ................................................................. 66

12. ELECTRICAL ................................................................................................. 6812.1. Electrical Design ....................................................................................... 6812.2. Power Supply and Distribution .................................................................... 6812.3. Electrical Modularization ............................................................................ 7012.4. General Electrical Layout ........................................................................... 7012.5. Electrical Loads ........................................................................................ 70



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12.6. Power Routing Layouts .............................................................................. 7112.7. Area Classification .................................................................................... 7112.8. Equipment List ........................................................................................ 71

13. CIVIL ............................................................................................................. 7213.1. General ................................................................................................... 7213.2. Civil, Paving & Roads ................................................................................ 7213.3. Geotechnical Investigation.......................................................................... 7213.4. Piles & Foundations .................................................................................. 7313.5. Structural Steel ......................................................................................... 7413.6. Buildings ................................................................................................. 7413.7. Painting & Fireproofing ............................................................................. 75

14. MECHANICAL ............................................................................................... 7614.1. General ................................................................................................... 7614.2. Equipment Specifics .................................................................................. 7614.3. Material Selection ...................................................................................... 7614.4. Sized Equipment List................................................................................. 7714.5. Modularization ......................................................................................... 77

15. CO2 CAPTURE AND AMINE REGENERATION .............................................. 7815.1. Unit Overview ......................................................................................... 7815.2. SGSI Licensor Reports .............................................................................. 7815.3. Unit Specific Design Basis .......................................................................... 78

15.3.1. Specific Feedstock Rate and Specifications ................................................. 7915.3.2. Product and Process Specifications .......................................................... 7915.3.3. On-Stream Factor ............................................................................ 8115.3.4. Turndown ..................................................................................... 8115.3.5. Run Lengths .................................................................................. 8115.3.6. Maintainability Philosophy .................................................................. 81

15.4. Process Description .................................................................................. 8115.5. Key Operating Parameters .......................................................................... 8415.6. Process Flow Diagrams .............................................................................. 8415.7. Heat and Material Balances in Appendices ..................................................... 8515.8. Sized Equipment List................................................................................. 8515.9. Utility Summary and Conditions .................................................................. 8515.10. Battery Limit Stream Summary .................................................................... 8515.11. Relief Load Summary ................................................................................ 8515.12. Special Process Engineering Considerations ................................................... 8715.13. Chemicals ................................................................................................ 87

16. COMPRESSOR AND DEHYDRATION (UNIT 247/248) ..................................... 89



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16.1. Unit Overview ......................................................................................... 8916.2. Vendor Package ........................................................................................ 8916.3. Unit Specific Design Basis .......................................................................... 89

16.3.1. Specific Feedstock Rate and Specifications ................................................. 8916.3.2. Product and Process Specifications .......................................................... 9016.3.3. On-Stream Factor ............................................................................ 9116.3.4. Turndown ..................................................................................... 9116.3.5. Run Lengths .................................................................................. 9116.3.6. Maintainability Philosophy .................................................................. 91

16.4. Process Description .................................................................................. 9116.4.1. Compression ................................................................................... 9116.4.2. Dehydration ................................................................................... 92

16.5. Key Operating Parameters .......................................................................... 9316.6. Process Flow Diagrams .............................................................................. 9316.7. Heat and Material Balances ......................................................................... 9316.8. Sized Equipment List................................................................................. 9416.9. Utility Summary and Conditions .................................................................. 9416.10. Battery Limit Stream Summary .................................................................... 9416.11. Relief Load Summary ................................................................................ 9416.12. Special Process Engineering Considerations ................................................... 9516.13. Chemicals ................................................................................................ 95

17. REVAMP OF HYDROGEN MANUFACTURING UNITS (UNITS 241,

242 & 441) ....................................................................................................... 9617.1. Unit Overview ......................................................................................... 9617.2. Vendor (Uhde) Package ............................................................................. 9717.3. Unit Specific Design Basis .......................................................................... 97

17.3.1. Specific Feedstock Rate and Specifications ............................................... 10017.3.2. Product and Process Specifications ........................................................ 10017.3.3. On-Stream Factor .......................................................................... 10117.3.4. Turndown ................................................................................... 10117.3.5. Run Lengths ................................................................................ 10117.3.6. Maintainability Philosophy ................................................................ 101

17.4. Process Description ................................................................................ 10117.5. Yield Estimates and Key Operating Parameters (if applicable) ......................... 10217.6. Process Flow Diagrams ............................................................................ 10217.7. Revised Heat and Material Balances ............................................................ 10317.8. Sized Equipment List............................................................................... 10417.9. Utility Summary and Conditions ................................................................ 10417.10. Revised Catalyst and Chemical Summary ..................................................... 105



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17.11. Relief Load Summary .............................................................................. 10517.12. Safeguarding Review ................................................................................ 10517.13. Special Process Engineering Considerations (if required) ................................ 10517.14. Revised Plot Plan .................................................................................... 105

18. TIE-INS AND INTERCONNECTING LINES .................................................. 10618.1. Piping Tie-in List .................................................................................... 10618.2. Electrical Tie-In List ................................................................................ 10618.3. Instrumentation Tie-in List ....................................................................... 107

19. REVAMP OF UTILITIES & OFFSITE FACILITIES .......................................... 11219.1. Greenfield Utility Requirements ................................................................. 11219.2. Brownfield Utility Requirements ................................................................ 11319.3. Unit Overview ....................................................................................... 11319.4. Objectives and Results of Value Improvement and Scoping Studies .................. 11319.5. System Specific Design Philosophy ............................................................ 115

19.5.1. Utilities and Offsites Specifications ....................................................... 11519.5.2. Turndown ................................................................................... 11819.5.3. On-Stream Factor .......................................................................... 11819.5.4. Maintainability Philosophy ................................................................ 11819.5.5. Reliability and Flexibility ................................................................. 118

19.6. Utility System Requirements ..................................................................... 11919.6.1. Steam / BFW / Condensate ............................................................. 11919.6.2. Cooling Water .............................................................................. 11919.6.3. Demineralised Water ....................................................................... 11919.6.4. Instrument and Utility Air ................................................................ 12019.6.5. Nitrogen ..................................................................................... 12019.6.6. Utility Water ............................................................................... 12019.6.7. Potable Water .............................................................................. 12119.6.8. Waste Water ................................................................................ 121

19.7. Offsites Changes by System ...................................................................... 12119.7.1. Stormwater Collection ...................................................................... 12119.7.2. Firewater .................................................................................... 12119.7.3. Tankage Changes .......................................................................... 12119.7.4. Waste Water Treatment ................................................................... 12219.7.5. Flare ......................................................................................... 12219.7.6. Buildings .................................................................................... 12219.7.7. Interconnecting Piperacks and Piping ..................................................... 122

19.8. Key Operating Parameters ........................................................................ 12319.9. New and Revised PFDs ........................................................................... 12319.10. Sized New Equipment List ....................................................................... 123



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20. PIPELINE .................................................................................................... 12420.1. Introduction .......................................................................................... 124

20.1.1. System description .......................................................................... 12420.1.2. Facilities ..................................................................................... 124

20.2. Design Data ........................................................................................... 12420.2.1. Design Standards and Legislation Requirements ........................................ 12420.2.2. Industry Guidelines ......................................................................... 12520.2.3. Client Specifications ........................................................................ 12520.2.4. Fluid Composition .......................................................................... 12520.2.5. CO2 Purity Specification Requirements .................................................. 12620.2.6. Pipeline Operating Pressure................................................................ 12820.2.7. Pipeline Operating Temperature ........................................................... 12820.2.8. Flow Rates .................................................................................. 12920.2.9. Flow Rate Requirements ................................................................... 12920.2.10. Water Content and CO2 Phase Change Management ................................. 12920.2.11. Design Life .................................................................................. 12920.2.12. Pipeline Steel Grade ........................................................................ 13020.2.13. Right of Way Geotechnical Data ......................................................... 13020.2.14. HDD Crossing Geotechnical Data ....................................................... 130

20.3. General Design Basis ............................................................................... 13120.3.1. Routing ...................................................................................... 13120.3.2. Pipeline Location Class .................................................................... 13320.3.3. Pipeline Battery Limits .................................................................... 13320.3.4. Thermal Hydraulic Design Guidelines ................................................... 13420.3.5. Mechanical Design Guidelines ............................................................ 13520.3.6. Line Break valves .......................................................................... 13520.3.7. External Corrosion Protection ............................................................ 13620.3.8. Field Joint Coating System ................................................................ 13620.3.9. Internal Corrosion Protection .............................................................. 13620.3.10. Pipeline Leak Detection System........................................................... 13720.3.11. Integrity Management ...................................................................... 13720.3.12. Internal Corrosion Mitigation ............................................................. 13820.3.13. Cathodic Protection ......................................................................... 13820.3.14. Monitoring .................................................................................. 13820.3.15. Inspection .................................................................................... 13820.3.16. Material Selection .......................................................................... 139

20.4. Pipeline Construction & Installation ........................................................... 13920.4.1. Pipeline Spreads ............................................................................ 13920.4.2. Pre-Construction Survey ................................................................... 139



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20.4.3. Pipe Bends .................................................................................. 14020.4.4. Induction Bends ............................................................................. 14020.4.5. Cold Field Bends ........................................................................... 14020.4.6. Crossings – Road & River ................................................................ 14020.4.7. Major Rail and Road Crossings .......................................................... 14120.4.8. Minor Gravel ............................................................................... 14120.4.9. Crossing of Buried Services and 3rd Party Pipelines .................................... 14120.4.10. Commitments ............................................................................... 141

20.5. Special Crossings .................................................................................... 14220.5.1. Horizontal Directional Drill Construction Methodology ............................... 14220.5.2. Pipe Installation ............................................................................ 142

20.6. Pig Trap System...................................................................................... 14220.7. Relief Philosophy & Pipeline Depressurization Facilities ................................. 14320.8. Pipeline Electrical Philosophy ................................................................... 14320.9. Pipeline Instrumentation and Control Philosophy ......................................... 14320.10. Pre-commissioning, Commissioning and Start up .......................................... 144

20.10.1. Hydrotesting, Cleaning, and Drying ...................................................... 14420.10.2. Preservation ................................................................................. 14420.10.3. Initial Fill ................................................................................... 145

20.11. Operation and Maintenance ...................................................................... 14520.11.1. Operation and Staff ........................................................................ 14520.11.2. Control Room and Offices ................................................................. 14520.11.3. Reliability ................................................................................... 14520.11.4. Emergency Response Planning ............................................................. 14520.12. Future Expansion ...................................................................... 146

20.13. Health, Safety, Security, and Environment (HSSE) ........................................ 14620.13.1. General Philosophy ......................................................................... 14620.13.2. Isolation Philosophy ........................................................................ 14720.13.3. Simultaneous Operations (SIMOPS) .................................................... 14720.13.4. Emergency Planning ........................................................................ 14720.13.5. Safety Equipment .......................................................................... 147

21. SUBSURFACE SCOPE OF WORK .................................................................. 14821.1. Overview .............................................................................................. 14821.2. Integrated Production System.................................................................... 149

21.2.1. Compression & Pipeline Requirements .................................................. 14921.2.2. System Operating Envelope ................................................................ 15021.2.3. System Operational Philosophy ............................................................ 15121.2.4. Integrated Production System Controls ................................................... 151

21.3. Flow assurance ....................................................................................... 153



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21.3.1. Flow Assurance Scope for the Project ..................................................... 15321.3.2. Flow Assurance Strategy................................................................... 155

22. PROJECT APPROACH TO NOVELTY ........................................................... 161

23. APPENDICES .............................................................................................. 163



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1. PROJECT OVERVIEW

1.1. General

The Basic Design & Engineering Package (BDEP) provides basic design data to confirm the configuration of the CO2 Capture, Pipeline and Wells facilities and to define the integration with the existing Scotford Base Plant Expansion 1 Upgraders.

The CO2 capture facility produces CO2 for sequestration in a geological formation to reduce the green house gas emissions from the Scotford Upgrader. The CO2 capture facility is designed to remove CO2 from the process gas streams of the Hydrogen Manufacturing Units (HMUs) using Amine technology and to dehydrate and compress the captured CO2 to a supercritical state to allow for efficient pipeline transportation to the subsurface storage site. The CO2 capture scope includes three HMUs: two identical existing HMU trains in the Base Plant Upgrader, and one being constructed as part of the Upgrader Expansion 1 project, which is planned for operation in 2011.

1.2. Overall Quest CCS Project Drivers for Design

The following are the project drivers in order of importance:

§ Cost – The cost driver arises from the fact that the project does not have a “standalone” business case and strictly maintaining project costs are required for theproject to meet its goal of being NPV =0.

§ Quality - The quality driver arises from the fact that this project must achieve itsagreed process performance as described in the government funding agreementswhile

§ Schedule – The strategy by this project is to achieve sustained operations in May2015. However, if the execution schedule starts to slip, money may not be spent tomaintain the schedule.



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1.3. Scope of BDEP

In summary, the BDEP covers the following Quest design scope:

· Modifications on the two existing HMUs and the new Expansion 1 HMU

· Modifications on the two existing PSAs and the new Expansion 1 PSA

· Three amine absorption units located at each of the HMUs

· A single common CO2 amine regeneration unit (Amine Stripper)

· A CO2 vent stack

· A CO2 compression unit

· A TEG dehydration unit

· Scotford Utilities and Offsites Integration

· CO2 Main Pipeline, Laterals, and Surface Equipment

· Subsurface Wells Scope of Work

1.4. Design Case Definition

The three HMUs at the Scotford site together generate about 1.5 million tons per year of CO2 as a by-product of the synthesis gas reaction. Based on the analysis done in the earlier project phases it is economical from capital efficiency point of view to recover up to 80% of the total CO2 produced. That adds up to a total on-stream capacity of 1.2 million tons per year at 90% plant availability a total of 1.08 million tons per year of CO2 is captured for sequestration on a calendar year basis.

The project will only capture CO2 from the process streams of the three existing Scotford Upgrader hydrogen manufacturing units (HMUs). The capture infrastructure will capture CO2 using an ADIP-X technology, an activated amine process, Licensed by Shell Global Solutions International (SGSI). The captured CO2 stream will normally be about 99% CO2. The remaining portion will comprise of hydrogen, methane, carbon monoxide and nitrogen.

The CO2 thus captured is compressed to a super critical condition for transportation to well sites. Compressed CO2 will be transported via a new pipeline from the capture infrastructure to a storage area located approximately 81 km north of the capture infrastructure site. The pipeline will be 305 mm (12 inches) in diameter, and will transport a dense-phase CO2.

Injection wells will be designed for injection of CO2 into the Basal Cambrian Sands (BCS), at a depth of approximately 2 km below surface, and will include a



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measurement, monitoring and verification (MMV) plan. Based on the current results, it is expected that approximately 5 injection wells, with an uncertainty ranging from 3 to 8, will be drilled into the BCS storage formation to inject the CO2. Three deep observation wells will be required while three shallow groundwater wells per injector are currently part of the MMV plan. Confirmation of the number of wells, their location and their phasing is contained in the Storage Development Plan (07-0-AA-

5726-0001)

1.5. Contributors

Contributors to this BDEP document include:

· Fluor (Capture EPC Contractor)

· TriOcean (Pipeline engineering Contractor)

· Shell Quest project team (integration and subsurface)

1.6. Key Reference Documents

Contributors to this BDEP document include:



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2. GENERAL DESIGN CONSIDERATIONS

The purpose of the Quest CCS Project is to capture, compress and store about 1.08 million tonnes of CO2 per year from the Athabasca Oilsands Project (AOSP) Scotford Upgrader.

Shell Canada currently operates two Hydrogen Manufacturing Units (HMU1 and HMU2) and is in the process of starting up a third HMU (HMU3) at the Scotford Upgrader. The production of hydrogen represents a significant source of CO2 generated in the Upgrader, which is released from the reformer furnace stack. A significant portion of the CO2 generated is a by-product of the steam reforming and shift conversion reactions. The CO2 in the syngas stream from the HT-Shift Converter is cooled at high pressure, which presents an energy efficient source for CO2 recovery, due to its high partial pressure

An amine absorption and regeneration system is used to capture and recover about 80% of the total CO2 from the three HMU PSA feed gas streams. The absorption process used is the ADIP-X process, which is an accelerated MDEA-based process licensed by Shell Global Solutions International (SGSI). The CO2 Rich Amine streams from each individual Absorber is combined and stripped in the Amine Stripper to recover CO2 with about 95% purity.

The recovered CO2 is compressed in an eight stage integrally geared centrifugal compressor with an electric motor drive. In the first 5 stages, free water is separated out through compression and cooling. The CO2 from the 6th stage of compression is processed through a TEG dehydration unit to reduce the water content to a maximum of 6 lb per MMSCF. In the final two stages, the CO2 stream is compressed to an operating discharge pressure in the range of 8, 000-11,000 kPag resulting in a dense phase fluid (supercritical). The CO2 Compressor is able to provide a discharge pressure as high as 14,790 kPa at a reduced flow for start-up and other operating scenarios. This dense phase CO2 is transported by pipeline from the Scotford Upgrader to the injection locations which are located up to approximately 64 kilometres from the Upgrader.

2.1. Process Unit Capacities

To achieve the required 1.08 million tons per year of CO2 sequestration on a calendar year basis, the nameplate capacity is 1.2 million tons per year of CO2 on a stream day basis (90% availability). A listing of the main process unit capacities is provided in Table 2.1, as defined by the Shell Canada.

Table 2.1: Plant Capacities Unit Capacity Hydrogen Manufacturing Units:

· HMU1

· HMU2

136,487 Std. m³/h (116 MMSCFD) H2 production 136,487 Std. m³/h (116 MMSCFD) H2 production



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· HMU3 159,444 Std. m³/h (135 MMSCFD) H2 production

Amine Absorbers

· HMU1 Amine Absorber



168,031 Std. m³/h raw H2 gas (feed) 168,031 Std. m³/h raw H2 gas (feed) 244,556 Std. m³/h raw H2 gas (feed)

Amine Regeneration 1481 m³/h lean amine circulation (Note 2) CO2 Compression and Dehydration

3,564 tonnes/day CO2 Production (>95% CO2)

Notes: 1. Standard conditions are 15.6 °C (60 °F) and 101.325 kPaa (1 atm).2. Lean Amine composition is 40 wt% MDEA, 5 wt% DEDA, and 55 wt% H2O.

2.2. Feedstock Specifications

The feedstock to the Quest CCS project is Raw Hydrogen Gas from the HMU Process Condensate Separators, upstream of the PSA Units. This gas has a relatively high CO2 content at high pressure, which makes it suitable for absorption using the ADIP-X process. The gas quality is provided in Table 2.2.

Table 2.2: Feedstock Quality HMU1 HMU2 HMU3

Temperature °C 35 35 35 Pressure kPag 2964 2964 3004

Composition H2O Mol% 0.2 0.2 0.2 CO2 Mol% 16.5 16.5 17.1 CO Mol% 2.4 2.4 2.9 N2 Mol% 0.3 0.3 0.3 H2 Mol% 74.8 74.8 72.4 CH4 Mol% 5.8 5.8 7.2

2.3. Product Specifications

The Quest CCS Project produces two primary products: H2 Raw Gas (CO2 lean) and compressed CO2. The specifications for these products are identified in Tables 2.3 and 2.4.

Table 2.3: H2 Raw Gas Specifications Temperature (°C) 35 °C (maximum, operating) CO2 Capture Pressure drop 70 kPa (maximum) Amine Carry-Over 1 ppmw (maximum) CO2 Removal 80%

1481 m³/h lean amine circulation (Note 2)

2. Lean Amine composition is 40 wt% MDEA, 5 wt% DEDA, and 55 wt% H2O.2. Lean Amine composition is 40 wt% MDEA, 5 wt% DEDA, and 55 wt% H2O.2. Lean Amine composition is 40 wt% MDEA, 5 wt% DEDA, and 55 wt% H2O.



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Table 2.4: CO2 Specifications CO2 Concentration 95 vol% (minimum) H2O Content 6 lb / MMSCF (maximum, Note 1) Hydrocarbon Content 5 vol% (maximum)

Note 1: Water content specification is a maximum of 6 lb per MMSCF during the summer months and a maximum of 4 lb per MMSCF during the required periods of the remaining seasons with ambient temperatures up to approximately 20°C. .

2.4. CO2 Specific Design Philosophy / Guidelines for Quest

The Quest CCS Project introduces new HSE complexities into the Shell Scotford Upgrader. In a typical Upgrader setting, CO2 is primarily released from fired heater stacks in a diluted form as a combustion product. Concentrated CO2 presents toxic and asphyxiation risks. Therefore, CO2 specific guidelines have been developed for the Quest CCS Project.

2.4.1. Venting and Relief of CO2 Vapour

Concentrated CO2 streams, like those found in the Quest CCS Project, can snuff out a flare and are not appropriate for discharging into the Upgrader flare system. Therefore, releasing concentrated CO2 streams separately at a safe location, for proper dispersion, is the disposal method of choice. Upset CO2 venting is routed to the vent stack which shall be designed with sufficient height for proper dispersion. Detailed dispersion modelling indicated that a vent stack tip located 50 m above ground is sufficient to not expose individuals to IDLH concentrations of CO2 at all areas that may be occupied, on the ground and on vessel platforms (see A6GT-R-1034_B.pdf).

2.4.2. Supercritical CO2 Venting

Supercritical CO2 venting under normal circumstances is avoided by process design. When depressuring, supercritical CO2 auto-refrigerates, potentially forming both liquid and dry-ice. To avoid the liquid and solid phases, high temperature (enthalpy) supercritical CO2 can be depressured. The compression system spills back high enthalpy supercritical CO2 to lower pressure stages, allowing for safer low pressure venting.

A pipeline backflow protection system isolates the low enthalpy high pressure supercritical CO2 in the pipeline, in the event of any process interruption. The pipeline remains bottled-in during any emergency situations until it can be vented manually in a controlled manner by the pipeline venting system.

A manual low temperature supercritical vent is provided for planned pipeline venting scenarios, for maintenance or decommissioning. The pipeline venting rate is limited by



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installing a 4” restriction orifice to avoid exceeding MDMT limits of the pipeline. Normally closed isolation valves are provided to prevent inadvertent opening of the pipeline venting.

2.4.3. High Pressure CO2 Equipment

High pressure CO2 equipment has been minimized. Only the compressor aftercooler and pig launcher are in cold supercritical service at the Capture unit.

Additionally, air cooling was selected as the preferred cooling medium for all high pressure streams (>4000 kPag), to mitigate potential CO2 contamination of the cooling water system.

2.4.4. CO2 BLEVE

During a catastrophic failure of a CO2 vessel in liquid or supercritical service, it is theorized that:

“(…) shock waves can form from a short time formation of superheated liquid to a spinodal state, followed by a homogeneous nucleation, known as Boiling Liquid Expanding Vapour Explosion (BLEVE). Initial catastrophic failure of the vessel must occur for a BLEVE. This could be:

· Mechanical damage caused, for example, by corrosion or collision;

· Overfilling and no relief valve;

· Overheating with an inoperative relief valve;

· Mechanical failure;

· Exposure to fire.”

- Source: Det Norske Veritas, “Mapping of potential HSE Issues related to large-scale capture, transport and storage of CO2” (2008), Page 60.

This phenomenon is known as a cold CO2 BLEVE.

The project does not consider a CO2 BLEVE a credible HSE risk, as there are no supercritical CO2 storage vessels within the Quest facilities. However, since there is supercritical CO2 volume within the piping and equipment, the following measures have been undertaken to mitigate the risk of a BLEVE:

· Minimized the volume of CO2 and equipment items that operate in the potentialoperating range (between the Compressor 7th Stage discharge and the Aftercooler).

· Performed Consequence Model for ALARP Decision Register, document numberA6GT-R-1014. The BLEVE model found no unacceptable safety consequences fornormally occupied buildings local to the facility. During future design developmentof the project, if a BLEVE scenario emerges, building designs will be revisited.

2.4.5. Metallurgy



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Wet CO2 presents a risk of carbonic acid corrosion of carbon and low alloy steels. Stainless steel piping and equipment has been specified for streams that contain CO2 and water, such as:

· Rich amine

· Wet CO2 from Amine Stripper (upstream of the TEG dehydration unit).

· CO2 Vent Lines

· Condensed water streams (wash water, purge water, compressor KO water, etc.)

Material Selection Diagrams (MSD) have been prepared to define the details and basis for material selection for the capture, compression and dehydration facilities. The Material Selection Report (07-1-MX-8241-0001) is located on the Livelink site:

https://knowledge.shell.ca/livelink/livelink.exe/open/55802109

2.5. Sparing Philosophy

Sparing philosophy has been identified in the Reliability section of the Class of Facilities Quality Overview; document number A6GT-R-1016 Attachment 2. Refer to Section 2.16 for further details.

2.6. Cooling Philosophy

The cooling philosophy is to leverage the Upgrader cooling water system and demineralised water system to the greatest extent feasible. The existing Base Plant cooling water system has additional duty available to accommodate the Quest cooling demands.

2.6.1. HMU 1, 2 and 3 (Brownfield)

The modest cooling duty requirements in HMU 1, 2 and 3 are met by new heat exchangers in parallel to their respective cooling water circuits. Licensor requirements for Water Wash Circulation cooling utilize a conservative design premise to ensure there is sufficient treated gas cooling in the event of high CO2 absorption exotherms.

2.6.2. Amine Regeneration and CO2 Compression (Greenfield)

The more substantial duty requirements for amine regeneration and compression necessitate a new cooling water circuit. New cooling water booster pumps (2 x 50%) are required and are located in the Quest Capture facility. Cooling water supply at 25°C is taken from the Upgrader supply (CWS) header near the Base Plant Cogen / Utility Plant. The CWS tie-ins are upstream of the Cogen steam condensers which are under-utilized when Quest is online.



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Warmed cooling water is returned to the Cogen Plant such that overall cooling water interruptions are minimized. In the event that Cogen power demands increase substantially (such as a power grid demand spike), then Quest will ramp-down and/or shutdown to shift cooling water duty back to Cogen.

2.6.3. Air Cooling

The design air temperature for critical process services is 28°C and for non-critical process services is 21°C.

Air cooling is limited to services where process (CO2) heat exchange with cooling water poses HSE risks. Specifically, air coolers are specified where CO2 is in supercritical condition such as the compressor aftercooler and high pressure CO2 services such as the interstage cooler upstream of the dehydration unit.

The compressor 5th stage cooler is categorized as critical service as its performance impacts the water content of the CO2 going to the pipe line. The compressor aftercooler is also categorized as critical service to maintain the CO2 product temperature at pipeline specification.

2.7. Operating Philosophy

The Quest CCS Project is divided into two primary operating systems:

1. Hydrogen Manufacturing and CO2 Capture2. Amine Regeneration, CO2 Compression ,Transport and Injection

The individual amine absorbers and wash columns are located inside the battery limits of the associated HMU, and are controlled and maintained by their respective plant operations group.

The common systems, including the Amine Regeneration, CO2 Compression and Dehydration, and the CO2 pipeline are controlled and maintained by the Scotford Base Plant, due to its geographic location in the Upgrader. To facilitate understanding of the integrated operation of Compressor, Pipeline and Wells, a drawing (246.0001.000.040.005) is developed that shows process parameters for the key operating modes.

2.7.1. Hydrogen Manufacturing and CO2 Capture

With the introduction of Quest, the HMUs will have two main operating modes: with Quest and without Quest. While Quest is offline, the absorbers are bypassed and the HMU operates with a CO2 rich feed into the PSA. When Quest is online, the CO2 in the H2 Raw Gas is removed in the Amine Absorbers and resulting CO2 Lean syngas is routed to the



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PSAs. As a result the PSA tailgas has lower CO2 content and the Flue Gas Recirculation system is employed to reduce NOx production in the Reformer furnace.

Based on the SGSI H&MB, the hydrogen production remains unaffected but for a loss of about 0.3 Mol% H2 when Quest is on full load. The reduced hydrogen production is not significant and does not interfere with the operation of the Scotford Upgrader process units.

The CO2 Capture facilities operate continuously, matching the normal operation of the HMUs. The entire Raw H2 Gas from the existing Process Condensate Separators enters the bottom section of the Amine Absorber and is contacted with lean amine where nominally 80% of the CO2 is removed. A water wash system cools the treated gas and also limits the amine carry-over to a maximum of 1 ppmw, to ensure optimal operation of the downstream PSAs.

The HMUs are revamped to accommodate the reduction in the CO2 content in the PSA tail gas, which is ultimately sent to the Steam Reformer Furnace as fuel gas. A Flue Gas Recycle system (FGR) and low NOX burners are added to reduce the NOX emissions. Each absorber/wash system has a Raw H2 Gas bypass to allow the HMU to operate with CO2 Capture offline. Therefore, the modifications to flue gas recirculation controls and burners of the Steam Reformer permit the HMU to switch operation during CO2 rich (current operation) and lean (Quest normal operation) PSA feed gas operation. Refer to Section 8 for further details regarding operating modes.

2.7.2. Amine Regeneration, CO2 Compression and Transport

Rich Amine from the Base Plant and Expansion HMUs is routed to a common Amine Regeneration facility. The Amine Regeneration system is designed to recover the CO2 from the rich amine in an Amine Stripper provided with LP steam reboiling. The Amine Regeneration design turndown of 30% allows continuous operation during a shutdown of any two of the three HMUs.

Contamination of the amine system is prevented by an amine filtration system. In the event that foaming occurs in the Amine Stripper, or in the Amine Absorbers, a common Anti-Foam injection system is provided within the Amine Regeneration Battery Limits. The anti-foam is injected into the lean amine lines to each Absorber, individually, or the rich amine line to the Amine Stripper.

The compressor operation mirrors that of the Amine Regeneration system. The compressor also has a turndown of 30% by employing a recycle mode of operation. The compressor can also be operated if a loss of a CO2 injection well occurs (planned or unplanned shutdown). Venting of CO2 from the compressor suction occurs due to an accumulation of CO2, and signals for the compressor to default to spillback mode. The CO2 Vent Stack is provided for start-up, shutdown and for other safeguarding purposes.



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The CO2 pipeline and injection systems are operated by the Scotford Base Plant. Therefore, pipeline/well shutdowns is managed from the Scotford site where determination of corrective actions such as a compressor turndown/shutdown (temporary venting), or shutdown of the Amine Facilities can be made.

Utilities are provided to the Quest CCS common facilities from the main common base plant utility systems, with the exception of cooling water as outlined in Section 2.6.2. Loss of utilities will force the Quest CCS Project common facilities to trip:

· Loss of Cooling Water Booster pumps results in:

o Loss of condensation in the stripper overhead, leading to loss of CO2recovery

o High interstage temperature in the compressor, leading to compressortrip

o High amine temperature, resulting in loss of absorption efficiency.

· Loss of LP steam results in loss of amine stripping, resulting in no CO2production.

· Loss of power results in loss of pumping and compression capabilities

· Loss of instrument air results in all valving switching to fail safe positions

· Loss of saturated HP steam or nitrogen for TEG stripping (potentially offspecification CO2, which could result in a shutdown of the pipeline)

Trips to the Quest CCS common facilities will be mitigated and designed so that no impacts occur in other Upgrader process units.

2.8. Unit Availability

In order to achieve an annual CO2 sequestration of 1.08 million tonnes per year, the availability of the Quest CCS Project is 90%, compared to the nameplate capacity of 1.2 million tonnes per year. The availability of raw hydrogen gas feed is historically 93% in accordance with the Upgrader availability. The Quest reliability during periods when feed is available (between shutdowns) must be roughly 96.8%. This minimum reliability has been verified by RAM modelling which is highlighted in Section 9.

2.9. Turndown Requirements

The turndown ability of the Quest CCS Project Facilities is 30% of the design capacity. Refer to the Class of Facilities, Section 2.16 for further details.

2.10. Interface with Existing Facilities



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The Quest CCS Project interfaces with the Upgrader Base Plant and Expansion to feed the CO2 Capture facilities and provide new utility connections to new equipment items. Six main interface points have been identified:

1. Base Plant HMUs (HMU 1/2 and common facilities)

· Raw H2 Gas Supply / Return

· Cooling Water for Absorber 1/2 Circulating Water Coolers (supply and return)

· Flare connection for pressure control vents and relief valves

· Utility Air

· Instrument Air

· Nitrogen

· Utility Water

· LP Steam for Utility Stations

· Steam Condensate

· Power

· DCS and SIS integration

· Fire Water

· Flue gas and combustion air ducting

2. Expansion HMU3 and common facilities

· Raw H2 Gas Supply / Return

· Cooling Water for Absorber 3 Circulating Water and Make-up Water Coolers(supply and return)

· Boiler feed water for make-up water

· Purge Water to Process Condensate blowdown system

· Flare connection for pressure control vents and relief valves

· Utility Air

· Instrument Air

· Nitrogen

· Utility Water

· LP Steam for Utility Stations

· Steam Condensate

· Power


· Fire Water

· Flue gas and combustion air ducting

3. Utility (Unit 251) tie-ins

· Cooling Water Return to Cogen

· Recovered Clean Condensate



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· Demin Water Return to the Deaerator

4. Cooling Water Tower (Unit 252)

· Cooling Water Supply

5. Underground Utilities (Units 258 / 282)

· Fire Water to Quest Greenfield area

6. Base Plant Piperack (Unit 285)

· LP Steam from Cogen

· Steam Condensate

· Demin Water Supply to Quest for heat recovery

· Waste Water

· Low Temperature HP Steam

· Instrument Air for Quest Greenfield area

· Utility Air

· Nitrogen

· Utility Water

· Power


The lean and rich amine systems require additional interfaces between the Base Plant and Expansion units. The amine flow control and antifoam systems require instrumentation interfaces between the Base Plant Foxboro control system and Honeywell Experion control system.

2.11. Meteorological and Site Data

Meteorological and Site Data listed below provided by Shell Canada.

Table 2.5: Meteorological and Site Data

Normal Atmospheric Pressure kPa 93.5

1. For the purposes of mechanical design where design for full vacuum is required: full vacuumis based on standard barometric pressure at sea level, 101.325 kPa (abs). That is, design for fullvacuum is design for 101.325 kPa external pressure. Design for ½ vacuum is design for 50.663kPa external pressure.

2. For the purposes of process design: use barometric pressure of 93.5 kPa (abs). For example:suction pressure for air compressors, fans and blowers with atmospheric air suction; flare tipbarometric pressure, etc.



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Ambient Temperature °C Max Min Mean Daily

Normal Maximum Minimum

Hottest month +33.9 +2.8 +15.6 +22.3 +10.8

Coldest month +10.0 -43 -13.4 -9.0 -17.9

Design

Minimum -43

Summer wet bulb +19

Summer dry bulb (July) +28

Air cooled exchanger: (dry bulb temperature)

+28 For critical service as per A6GT-DN-1037

Design for motors +40

Design for pipe expansion +40 / -43

Design for freeze protection -43

Design for material selection -43

Instrument air dew point max. -60

Relative Humidity Max Min

Summer 75% @ 28°C

Winter - <1 %

Precipitation

Average annual mm 430

15 minute max mm 20

24 hour max mm 88

Wind q1/10 = 0.31 kPa

q1/50 = 0.43 kPa

Snow

(1/50)

SS = 1.6 kPa

SR = 0.1 kPa

Seismic

Site response – Site Class D

Spectral accelerations (2% in 50 year probability)

Sa (0.2) = 0.116



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Sa (1.0) = 0.023

Design factor R, as per table 4.1.8.9 of ABC 2006.

Elevation m 623.5

Frost Protection

Design depth -foundations m 2.7

Soil Conditions Refer to geotechnical reports (file 19-90-83 by Thurber Engineering); “CCS Quest Project Shell Scotford Complex Supplemental Geotechnical Investigation”, dated Dec 2010.

2.12. Units of Measurement

The units of measure utilized by the Quest CCS Project have been defined by the Shell DEP 00.00.20.10-SCAN: The Use of SI Quantities and Units (September 2005). A general list of quantities and units is available in Appendix B of the DEP.

2.13. Instrumentation and Control Philosophy

The implementation of control and safeguarding for the Quest CCS Project spans two separate existing facilities , Base Plant and Expansion, where each plant (facility) has a different vendor for the basic process control system (BPCS) and Pipeline / Wells (Greenfield areas) controlled by SCADA PLC/RTU’s interfaced with Base plant Foxboro DCS system.. All equipment within the physical boundary of a plant is controlled and maintained by independent control room of that plant.

· Base Plant: Invensys Foxboro based BPCS with a new Honeywell based SafetySystem for Quest. (Note that the existing Base Plant Safety System is implemented ina GE-Fanuc based system.) Quest CCS Project units that employ this control systemare:

o HMU1/2 modifications, including new CO2 Absorber units (Units 241 /242)

o Amine Regeneration (Unit 246)o CO2 Compression (Unit 247)o CO2 Dehydration (Unit 248)o CO2 Pipeline LBV’s and Wellsites (SCADA system interface)

· Expansion: Honeywell Experion BPCS with a Honeywell based Safety System. TheQuest CCS Project unit that employs this control system is:

o HMU3 modifications, including a new CO2 Absorber unit (Unit 441)

The Quest CCS Project instrumentation and control design premise is to define each process unit as a stand-alone unit in terms of safeguarding and control. Therefore, the Expansion 1



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amine supply and demand control is independent of the amine supply to the base plant absorbers. Both plants appear as "customers" to the Amine Regeneration unit; the lean amine supply from the Amine Regeneration unit is capable of dealing with any demand changes from either customers.

To prevent potential disruptions to the hydrogen supply, the CO2 Capture Project does not impact the availability of the HMU units. Given the changes to the CO2 content of the raw hydrogen gas to the PSA, which is used for hydrogen supply to the Upgrader, control systems will be validated by the PSA licensors during the Execute Phase to ensure that the hydrogen recovery is not adversely impacted. Furthermore, modifications to the HMU steam reformer combustion controls and flue gas recirculation systems will be evaluated during Execute phase.

Critical analytical measurements on the compressed CO2 stream are CO2 purity, H2 in CO2 content and Moisture. Moisture analysis is used to prevent potential hydrate formation and corrosion concerns in the pipeline. H2 and CO2 measurements are used to keep CO2 in supercritical phase and prevent compressor surge. The compressor operates on suction pressure control. The maximum compressor delivery pressure will be managed by the antisurge spillback pressure control system. This is fully automated via the antisurge logic controller, and operates independently of other system controllers. The compressor antisurge spillback control system has the primary purpose of ensuring that the mass flow through the compressor itself is always above the surge flow minimum, which is a complex calculation based on all compressor conditions. It will open in response to low turndown operation of QUEST CCS, generally if below 75% of rated flow. This arises for example if any one HMU is shut down. In addition, if the compressor discharge pressure approaches design maximum (~14 MPa), then it will also start to open the spillback. It is not a pipeline system pressure controller. Pipeline pressure can float between this upper safeguarding limit, and the lower process single phase limit setpoint (~8.5 MPa). There is no direct process control link between injection wellheads and the compressor. Refer to diagram 246.0001.000.040.005 for high level details on the process control scheme.

The compressor is designed to operate at zero net outflow, on 100% spillback. It is

confirmed that it can manage the initial start-up duties, achieved by bleeding CO2 into

pipeline via a special bypass valves on LBVs. As line demand increases, the Capture

operation will be adjusted accordingly, with surplus CO2 venting to stack. CO2 capture is

controlled by adjusting the HMU Absorbers operation.

Other important measurements include CO2 content in the raw hydrogen gas stream and O2 in the HMU steam reformer flue gas stream. Additionally there is a requirement for point and open path CO2 gas detectors.



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For onsite CO2 leak detection Tuneable Laser Diode (TDL) IR technology for CO2 stream measurements and environmental detection is the basis to begin the Execute Phase, as agreed to by the Shell Technical Authorities. Detector locations and numbers will be confirmed in Execute phase.

2.14. Project Design Standards and Codes

As a minimum, the Quest CCS Project shall adhere to all statutory and code requirements as well as any environmental requirements identified in permits, licenses, etc. In addition each portion of the Quest CCS Project shall adhere to the Technical Standards applicable to that business.

The order of precedence for Codes and Standards applicable to the Quest CCS Project will be:

· Canadian Federal, Provincial and municipal laws and regulatory requirements

· Existing site approvals. These documents refer to a variety of standards andguidelines. Reference to voluntary documents in the site approvals gives themforce of law.

· Shell Canada Energy Minimum Health, Safety, Environment and SustainableDevelopment Expectations

· Shell HSSE Control Framework Standards and Guideline Manuals

· Shell ESTG (Engineering Standards Technical Guidelines) and DEP (Design &Engineering Practices)

· International Codes and Standards (e.g. ISO, ASME, API)

The following table lists the applicable regulations and approval authorities having jurisdiction for the Registration of Design documents in Alberta under the Safety Codes Act of Alberta.

Table 2.6: Regulations and Approval Authorities

Item Regulations Approval Authority

Fire: Fire Code Regulation, AR 52/1998-per Alberta Building Code

Safety Codes Act.

Buildings Building Code Regulation, AR 50/1998-per Alberta Building Code

Safety Codes Act.

Electrical Electrical Code Regulation, AR 208/99 Safety Codes Act.



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Elevators Elevating Devices Codes Regulations, AR 216/97 consolidated up to AR 276/98 Also, Elevating Devices Administration-Regulations, AR72/2001

Alberta Elevating Devices and Amusement Ride Safety Association (AEDARSA)

Gas Installation

Gas Installation:

Gas Code Regulation, AR 67/2001

Safety Codes Act.

Plumbing: Plumbing Code Regulation, AR 219/97 Safety Codes Act.

Pressure Equipment & Pressure Piping:

Design, Construction and Installation of Boilers and Pressure Vessel Regulations, AR 227/75, consolidated AR 159/97

Alberta Boilers Safety Association (ABSA)

Below is a list of common codes and standards used on the project. Additional Specific Codes and standards applicable to only one or two engineering disciplines are listed in the individual discipline's References and Standards section of the Scope of Services:

ABC Alberta Building Code

AFC Alberta Fire Code

AGMA American Gear Manufacturers Association

ASHRAE American Society of Heating, Refrigerating and Air Conditioning Engineers.

ANSI American National Standards Institute

API American Petroleum Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing Material

AWS American Welding Society

CEC Canadian Electrical Code

CISC Canadian Institute of Steel Construction

CSA Canadian Standards Association

EEMAC Electrical Equipment Manufacturer's Association of Canada

IEEE Institute of Electrical and Electronics Engineers



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ISA Instrument Society of America

NACE National Association of Corrosion Engineers

NBCC National Building Code of Canada

NEMA National Electrical Manufacturers Association

NFC National Fire Code of Canada

NFPA National Fire Protection Association

OSHA Occupational Safety and Health Administration

OHS Occupational Health & Safety Code

SPE 2000 Guide for Electrical Equipment for Installation and Use in Canada

TEMA Tubular Exchanger Manufacturers Association

ULC Underwriter's Laboratories Canada Inc.

The Quest Specific list of Shell Design Engineering Practices and specifications is used as the basis of FEED and Execute Phases. The list is based on AOSP - OSG Master List of Project Technical Standards Rev 3, Apr 2009 provided as part of the BOD. This issue was based on SCAN's standards update February 2009 and DEP version 28, February 2009. The list provided in the BOD has been updated to:

· identify mandatory specification requirements of DEM1 Rev 6, 2010

· identify which specifications are not applicable to Shell Quest Scope and removethem from the project list

· Maintain alignment with Shell Enterprise Frame Agreements (for example oncentrifugal pumps)

During FEED, the specifications were reviewed in detail to:

· generate project specific deviations to align project specifications with the QuestDesign Class Report requirements

· generate Project specific deviations to align project specifications withspecifications included in procurement Global Framework Agreement used on theproject

2.15. Engineering Documents and Unit Numbering Standards



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Engineering documents and unit numbering standards is in accordance with existing Scotford Upgrader procedures and is documented in the Quest Information Handover Guide (iHOG).

2.16. Class of Facilities

A Design Class review workshop was initially completed at the beginning of Select in 2006. A review of the Design Class was done in Sept 2009 and updated with the Capture project team in March 2010.

During Pre-FEED the Design Class framework for the project was updated and discipline specific design class reviews were held to define the design class in more detail. The Fluor standard for determining design class was used as it is very similar to Shell’s at a high level but the more detailed discipline level design classes from the Fluor procedure were felt to be more relevant and useful for EPC engineers than the standard Shell PG08c Design Class Value Improving Practice. The detailed discipline level design class tables were completed in a series of workshops with input from Shell and Fluor discipline engineers with a focus on reducing project costs and reflecting high level design class decisions agree to with project leadership. Final discipline level tables were also reviewed and agreed to by operations representatives.

To help the project achieve its overall goal of being NPV neutral, the Capture unit will be designed with no provisions for expandability, no ability to exceed nameplate capacity and limited provisions for online maintenance. These high level decisions were reviewed and confirmed by the project DRB. No changes to the class of facilities were undertaken in the FEED phase; however a PEER review was completed to verify the FEED design was in compliance with the design class decisions made in Pre-FEED. The output of this PEER review and its action items is captured in Fluor conference note CN-505.

2.17. Modularization Approach

The modularization approach for the Quest CCS Project is to use Fluor Third Generation ModularSM design practices. The plant is designed with a maximum module size of 7.3 m wide x 7.6m high x 36m long modules that are assembled in the Alberta area and transported by road to the Scotford site via the Alberta Heavy Haul corridor.

Third Generation Modular execution is a modular design and construction execution method which is different than the traditional truckable modular construction execution methods, as limitations exist to the number of components that are be installed onto the truckable modules. The 3rd Generation Modules are transported and interconnected into a complete processing facility at a remote location including all mechanical, piping, electrical



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and control system equipment. The use of specialized design practices and installation details are required to produce this type of design.

The Capture team developed the plot using the 3rd Generation Design Guideline, document A6GT-200-1065, to model all equipment, the large bore piping, the major electrical equipment and selected critical inline instruments during FEED.

These 3rd Generation Modules models were reviewed with Shell Operation and Maintenance personnel from the project and the Scotford project in a series of model reviews during FEED. The purpose of these meetings was to allow operation, maintenance and HFE to identify issues around the 3rd Generation ModuleSM concept and to obtain buy-in from Scotford Site that this concept was acceptable to the site. The outcome of these meeting was that the Site O&M team accepted the 3rd Generation ModuleSM as an acceptable design.

Knowledge sharing session on Modularization was held between key Shell and Fluor project personnel and members of the Shell MARS B project to share elements of offshore design techniques and best practices for operations and maintenance that were applicable to the Quest application of 3rd Generation Modularizations.

A plot and module design PEER review was conducted with input from the Shell Offshore Design Specialist and Modularization Technical authorities to assess the readiness of the project plot plan and modularization program. This meeting was held near the end of FEED and involved a review of the plot plans, the model and the work process around weight control and module design. The result was that the project plot plan and Modularization Program were adequately developed to support the beginning of the Execute Phase (Fluor conference note #505).

Also during FEED several technical decisions were made regarding the implementation of 3rd Generation Modularization based on items of concern Operations and Maintenance had identified during Pre-FEED. These included the following key decisions

· Cable Connectors would not be used on the Quest CCS Project.

· Distributed Electrical Substation and FARs would be used on the project in theRCDU plot area but not in HMU1,2 and HMU3 areas

· Modules would be elevated above grade not embedded at Grade



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3. HEALTH, SAFETY, ENVIRONMENT AND SUSTAINABLEDEVELOPMENT

3.1. Overview

Health, Safety, Environment and Sustainable Development is achieved through a systematic approach to all relevant aspects of HSE & SD using the HSE Activity Plan (07-0-HX-570-0001). The Plan provides a list of documents and studies to be completed during each phase of the project to ensure that risks have been identified, eliminated or reduced to As Low As Reasonably Pracicable (ALARP), and tracks their progress. The following is an overview of the documents and studies produced to date to ensure that project design risks are ALARP; (see section 19.16 of this document for the Pipeline HSE & SD segment)

3.2. Technical HSE Work done in FEED Phase

HSE work in the FEED phase (from BoD data to the development of this document) has been focused on supporting the evolving scope of the Quest CCS Project in general and the CO2 Capture facilities in particular. The work includes:

· PHA II and III for the entire venture (tie-in to injection wells)

· Progressing items in the HSE Action Item tracker, and closeout of select phaseaction items

· QRA on occupied buildings

· HSE Plot Plan review

· HSE input to CO2 Capture layout & modularization reviews

· Dispersion modelling and vent stack height determination

3.3. Key HSE Hazards & Issues

The HSE hazards and issues are described in the HAZID reports for Quest and CO2 Capture. These include recommended actions for mitigation, which form part 3333of the requirements of this BDEP. The Major Accident Hazards (Shell RAM Red and Yellow 5A or 5B) identified in the HAZIDs included the following:

· Asphyxiation by CO2, released by planned or unplanned venting or by loss ofcontainment. Planned mitigation includes rigorous compliance to Shell’s AssetIntegrity standards, engagement of Shell’s and industry’s experts to model releasesand conduct QRA to understand the effects.



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· Loss of containment of high pressure CO2 piping due to corrosion. Mitigated byaddition of TEG dehydration to the scope and material selection.

· Contribution to an increased likelihood of incidents of (a) the novelty of designingfor and handling dense phase CO2 and (b) the lack of Shell and industry standardsfor materials and equipment to handle dense phase CO2. Incidents could result inloss of reputation and compromising Shell’s global ability to implement additionalCCS projects. Planned mitigation includes engagement of Shell’s and industry’sexperts.

· Integration of CO2 absorption, regeneration, and compression with the HMU’s mayimpair the overall reliability of hydrogen production, and thus of production fromthe Scotford Upgraders. Planned mitigation includes focused design effort on theprocess controls and safeguards to ensure that robust hydrogen production is notimpaired by integration with the CO2 Capture facilities.

· CO2 Capture construction workers may be exposed to a toxic gas (H2S) releasefrom the Scotford operating process units, with the potential for multiple fatalities.Planned mitigation includes adoption of procedures used at the base plant Upgraderand for Expansion 1 construction, as well as QRA of the risk from a H2S releaseduring construction.

3.4. Technical HSE Work planned for Execute Phase

Project Guide 01 provides the basis for the HSE assessment approach that is required throughout design and execution phases to ensure that the project meets its HSE objectives. During the Execute process, several risk assessments, both qualitative and quantitative will be undertaken. The studies required for the Execute Phase are detailed in the HSE Activity Plan (see Project Execution Strategy).

The approach to HSE governance for the CO2 Project are centered on the building of Health, Safety and Environmental (HSE) cases that demonstrate that the project’s HSE risks are tolerable and ALARP. During FEED the Design HSE case was prepared and issued for approval – the document will continue to be developed & updated in Execute. A construction HSE Case shall be developed and issued prior to construction and an Operations HSE Case shall be developed and issued prior to start-up (during Execute phase).

3.5. Human Factors Engineering Plans (HFE)

3.5.1. Purpose



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HFE is applied to the design of work systems, workplaces and products, with the following aims:

· To enhance operational performance, while reducing risk to health, safety and theenvironment

· To eliminate, reduce the likelihood, or mitigate the consequences of human error

· To improve human efficiency and productivity

· To improve user acceptance of new facilities

3.5.2. Scope

The key requirement in the HSSE Control Framework is that projects conduct an HFE Screening, and to have the screening approved by an HFE Authorized SME. Based on the screening, projects are required to prepare a strategy for managing HFE issues or risks identified. The screening for Quest was completed in Pre-FEED using Bert Simmons as the facilitator and is documented in Report number 07-0-HX-6854-001.

During the FEED phase the specific activities identified in the Scotford Quest CCS Project HFE Strategy (doc. Ref.07-0-HX6854-001) have been executed in parallel with the Constructability program. Planned HFE design reviews were combined with constructability reviews to preserve alignment of purpose. The following bullets represent the HFE strategy implementation status;

· A valve criticality analysis (VCA) has been completed in accordance with theScotford Quest CCS Project HFE Strategy. The results of the meeting (ref.conference note CN-376) are captured on a highlighted set of AFE P&IDs, whereeach valve is color coded to its designated class. A preliminary assessment of “class”compliance has been performed; however the “purchased” design data must bevalidated prior to final valve location acceptance.

· A “first-pass” of a material handling matrix has been populated for each process areaduring the FEED phase. All equipment modules utilizing “monorails” formechanical lifting have been through preliminary “Materials Handling Reviews”.Reviews will be listed on the “Project HFE Plan” and will be scheduled when theProcess and Mechanical prerequisite design data permits.

· A preliminary HFE (Human Factors in Engineering) “Building layout review” hasbeen performed for the compressor building. This review is listed on the “ProjectHFE Plan” and will be scheduled when the Process and Mechanical prerequisitedesign data permits.

· All existing fire suppression equipment has been through a preliminary evaluation inareas where new facilities (i.e. HMU-1, 2 & 3) may impede the “expected



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performance” of these systems. Preliminary reviews have provided a basis that has been included within the Type 3 Estimate.

3.6. Energy Management and Greenhouse Gases

In the Capture facility, Steam and power are the main sources of the GHG. Special attention is being given to minimize their GHG footprint. For Quest new steam generation system (boiler) is not being installed. Existing ATCO Cogen system will be the source of LP Steam required for Amine Regeneration.

Also, the existing Cooling Water (CW) system is being used by reconfiguring the CW supply to the Cogen unit.

The Lean Only configuration decided during the Select phase helped reduce the power requirement by about 10%. Quest GHG performance is documented in PCAP deliverable 07-0-AA-5878-0001 Rev. 01 GHG (Greenhouse Gas) and Energy Efficiency Report.

3.7. Waste Minimization

The HSE premise of the Quest CCS Project is to limit HSE risks to As Low As Reasonably Practicable (ALARP). The efficient use of chemicals, materials, natural resources and energy sources is required by conserving resource and minimizing waste discharges. In addition to the reduction of GHG emissions outlined in Section 3.2, a number of strategies have been employed to accomplish this objective:

· Hydrogen Management

o Minimizing H2 losses to the amine

o Maintaining H2 recovery in the PSA

· Water Management

o Re-using purge water and compressor knockout water as make-up waterto the amine system

o Circulating wash water to minimize the use of clean condensate forwashing carry-over amine from the H2 Raw Gas.

o Subcooling recovered steam condensate, from the reboilers, to preventsteam releases to atmosphere.

· Waste Heat Recovery

o Demin water is employed to cool condensate from the Amine StripperReboiler.



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· Chemical Management

o Amine losses minimized by recycling purge water from the water washsystem, which contains entrained amine, to be used as water make-up.

o Prevention of Amine contamination with TEG, by segregating KO waterwhich may be contaminated.

o TEG is continuously recycled

o TEG reboiling temperature remains below the thermal degradationtemperature.

o Anti-foam used only as required.

3.7.1 General

The process isolation philosophy (Process Bulletin PB-003 Rev 0) is developed with guidance from Shell Canada based on the requirements of the Alberta OHS Code, DEP 31.38.01.11-Gen, and best isolation practices at the Scotford Upgrader.

The purpose of an isolation philosophy is to ensure that Quest equipment and piping can be serviced without exposing personnel to the unexpected release of energy that could cause injury, and to prevent or reduce the potential consequences of such releases. The Quest CCS Project does not carry hydrocarbons, therefore inventory sectionalisation usually required to prevent escalation of an event is not necessary.

In situations where redundant equipment is installed, and the requirement is to replace an unserviceable item whilst continuing to run the plant. Double isolation valves are required each side of equipment plus a pressure letdown arrangement.

All equipment and piping is capable of being physically separated from energy sources, of being de-energized, and of being tested to verify that it has been de-energized.

Positive isolation shall be provided when:

• Entry by personnel is required, or

• Hot work is to be done, or

• Equipment is to be hydrostatically tested or pneumatically tested, or

• Equipment is to be opened or removed whilst the remainder of the unit is stillin operation.

• Long duration isolations, e.g., more than one per shift.

• Where equipment is to be mothballed



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• For harmful substances

Note: abandoned equipment and piping is not included in the above list as it is to be removed. Abandoned connections to the process are to be positively isolated, but this may include permanent means such as welded end caps or blinds

3.7.2 Scope

The philosophy covers all Quest facilities including the process units, utilities and Offsites and pipeline installations. It will address process isolation, i.e., the mechanical isolation of fluid systems. It excludes isolation of electrical equipment and systems.

The basis for preparing the philosophy is consistency with legislation, the project engineering standards, and operating site isolation best practices. Specifically, these included:

· Alberta OHS Code (2006). Key points:

- minimize the need for isolation methods for equipment access other thanDouble Block & Bleed, blinding or blanking, and therefore for isolationsrequiring individual approval by a Professional Engineer

- All isolations must include means for verification that the equipment hasbeen de-energized

· Scotford Upgrader Safe Work Plans and Maintenance Practices related to Isolation:

- G304 – Safe Blinding/ Isolation Practices (latest revision)

- G304I – Upgrader Isolation (latest revision)

- G304U – Safe Blinding Practices Upgrader (latest revision)

· Scotford Upgrader isolation best practices, Black Oil Isolation guidance

· Quest CCS Project Standards’ guidance on isolation:

- DEP 31.38.01.11-SCAN

- DEP 80.47.10.30-SCAN

· Incorporation of relevant Lessons Learned from the Base Plant Upgrader, Upgrader

Expansion 1, and the Base Plant Upgrader Turnaround

Double block and bleed isolation is not used everywhere for the following reasons:

· Every additional flange and valve is an additional leak source

· Increased capital cost

· Operational efficiency (more valves require more time to operate and maintain)



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· The design intent of the system is that isolation is provided elsewhere (such as at a

unit level) to de-energize and safe the system in order to safely access particular

equipment piping or instrument items.

Additional Shell basis included incorporation of Shell Learning from Incidents on isolations (Incidents Involving Single Valve Isolation, Alert 200709, and June 2007).

Refer to PB-003 for further details.



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4. ITEMS TO BE RESOLVED IN EXECUTE PHASE

The following is a list of items that require consideration during Execute Phase, as well as the implementation plan to complete the item.

Title Unit Details

Steam Balance Site wide The Scotford steam balance is affected by the addition of the Quest CCS Project to the Upgrader operation. During Execute Phase, a greater understanding of the following items is required:

· Site Steam balance (as relevant to Quest)once HMU3 and Expansion Upgrader isoperational. Preliminary overall balances withand without Quest operation to becompleted early in Execute Phase.

· Need to determine whether the condensaterecovery and additional demin waterrequirements (to offset the condensate lossdue to water wash make-up) can beaccommodated with the existing integrationfacilities.

PSA Modifications 241, 242, 441

PSA vendors have been approached to undertake a study to identify modifications to the PSAs. Air Products (HMU1/2) and UOP (HMU3) will complete a study during Execute Phase to finalize the adsorbent requirements and determine if further modifications are required to meet the Design Basis (2010)

Steam Reformer Burner Management

241, 242, 441

A Shell study is underway to determine how recertification / compliance of current burner management system can be achieved (by modifications or by variance) under CSA B-149.3

Amine Initial Fill Logistics

246 The procedure for the initial fill of amine has not been finalized. Tanker trucks are assumed as the method of transport.

3rd Generation Modularization

General Module center of gravity will be evaluated during the Execute Phase.

Dispersion Model 246 Update/Finalize the dispersion model to include any



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Title Unit Details

vendor modifications arising from compressor or vent stack vendors

Dispersion Model 246 Complete ALARP decision on use and acceptance criteria for any CO2 PSV discharges which vent locally. Complete dispersion modelling if required.

Cooling Water Booster Pumps

246 Finalize pump type (API vs. ANSI) during detailed engineering.

Model Reviews General Confirm with pipeline, exact sizing and orientation of pig launcher so that any concrete barriers, if required, are be included in Capture unit design.

E&I Building 283 HSE reviews to be conducted to ensure that the location for the new E&I Building is appropriate (by SPG).

E&I Building General Execution Quest Undergrounds (Natural Gas, Firewater, electrical cables) and MOC 6890 E&I utilidor building project coordination.

Electrical / Instrumentation

General Electrical and Instrumentation cable routing to be optimized given the final plot plan.

Consider using surplus electrical material (i.e. cables and transformers) from the Expansion 1 Project.

Civil / Structural General Review the selection for the types of piles that have been selected for the revamp areas, specifically the piperack between the control building and the ATCO Co-Gen Building.

Coating requirements for the sewer pipes needs to be confirmed.

Compressor Casing 246 Confirm toughness suitability for Quest service for vendor recommended compressor casing material

Amine Dosing 246 Confirm is amine dosing is required for Quest waste water stream to ensure compatibility with existing Scotford Waste Water treatment facility

Gas Composition Analysis

247 Confirm requirements for gas composition gas chromatograph (GC) at compressor discharge versus CO2 analyser currently in FEED estimate. GC can measure CH4 (for potentially more GHG credits) as



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Title Unit Details

well as CO2 and H20 content.

H2 Analyzer Location 247 H2 analyzer or H2 measurement from Composition Analyser (GC) will be used to adjust compressor antisurge programming; exact location of H2 analyzer within Quest piping system needs to be finalized to simplify installation and maintenance while providing acceptable response time.

Location for Proposed GC which will measure all the compositions within CO2 Stream needs to be finalised in next phase.

Pipeline H2O Shutdown

247 Confirm alarm settings, allowable operator response times and automated executive action (Pipeline line block valve shutdown) upon detecting CO2 water content above 6 lbs/masc. Current design provides alarm at 6 lbs/mmscf, time delay for operator response at 7 lbs/mmscf and pipeline S/D at 8lbs/mmscf with time delay of Approximate 5 min (to be finalised in next phase of Project.)

Injector Well Count General Second and Third Injector wells are planned to be drilled and tested in Q2/Q3 2012. With knowledge obtained from these wells the pipeline and storage development plan will be finalized for the final number of wells (current premise is 5 wells).

Line Block Valves Enclosures

249 Design detailed of enclosures present at Line Block valve stations need to be confirmed that they will be naturally ventilated to eliminate confined space needs while still providing heated protection for any electronics if required

Instrumentation General Finalize criticality matrix

Shell SME’s from P&T to approve magnetic flow meters that were selected for Amine service.

Selection of which instruments will be wireless (i.e. Indicating Transmitters with no Control or safeguarding action).

Piping General Piping DEP requirements for minimum flow lines on pumps that operate in parallel need to be reviewed versus current design to confirm requirements.



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Title Unit Details

Process 241,242,441 Modifications to existing and new H2 FEED piping to HMU 1,2,3 need to be reviewed to confirm 70 kPa pressure drop criteria is met

Mechanical 241,242,441 Determine if API560 versus API673 will be used for FGR fans.

Dispersion model 249 Develop dispersion model at LBVs stations and Well pads once final location is selected



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5. OVERALL UTILITY SUMMARIES & BATTERY LIMIT TABLE

5.1. Overall Utility Summaries

Utility summary tables for the normal operation of the new units and the absorber additions to the HMUs (1, 2 & 3) can be found in Appendix A1.7.

5.2. Battery Limit Table

Battery Limit Interface Tables for the new units and the interfaces between the new absorbers and their respective HMUs (1 & 2 or 3) can be found in Appendix A1.8.



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6. CAPTURE LOCATION AND SITE PLAN

Prior to commencing Pre-FEED, the Shell Quest CCS Project team undertook a comparative assessment of five site locations for the proposed Scotford CO2 capture and compression facilities within the Scotford plot. The main objective was to demonstrate that HSE risks are reduced to ‘as low as reasonably practicable’ (ALARP) during construction SIMOPs and normal operations. Several internal stakeholders were consulted including Scotford Operations, the Venture HSE Advisor and Shell Groups’ Toxicologist.

Preliminary engineering carried out during IDENTIFY and ASSESS concluded the absorber towers must be located close to the Hydrogen Manufacturing Units to overcome pressure drop limitations, and maximize energy efficiency. The design is premised on siting the absorber towers on the plots for HMU 1 & 2 and HMU 3, with the regeneration and compression facilities located to the east of the Base Plant HMUs. The design premise for siting the plant was questioned during an External Technical Review in December 2009 resulting in a recommendation that the Project Team demonstrate that risks had been reduced to ALARP. The current site plan is the result of this process.

The Quest CCS Capture related Facilities are physically located in four geographic areas within the Scotford complex, which can be described as follows;

· HMU1/2 CO2 Capture Area (Amine Absorbers and wash water equipment)

· HMU3 CO2 Capture Area (Amine Absorbers and wash water equipment)

· Amine Regeneration, CO2 Compression and CO2 Dehydration Area, the Pipeline piglauncher (designed and fabricated by TriOcean), is located on the same plot.

· Interconnection to existing units

The Site Plan is presently shown on the following drawing (Appendix A4):

Document No. Title Revision Rev No

000-0311-000-SK-001Unit 285 Interconnecting Piperack

Additions For CCS Expansion IFE C1



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For the Quest Pipeline numerous routing options were evaluated in 2009 with a final decision being taken in late 2009 to follow the East route generally along the Enbridge pipeline right of way as the preferred route.

During 2010 a detailed route selection process was undertaken with the objective to:

· Limit the potential for line strikes and infrastructure crossings

· Align with the proposed CO2 disposal area

· Use existing pipeline rights-of-way and other linear disturbances, where possible, tolimit physical disturbance

· Limit the length of the pipeline to reduce the total area of disturbance

· Avoid protected areas and using appropriate timing windows

· Avoid wetlands and limiting the number of watercourse crossings

· Accommodate landowner and government concerns to the extent possible andpractical.

As well Quest undertook an extensive Participant Involvement Program and thus far, Shell has not received any objections from potentially directly affected stakeholders.

The proposed route contained in the regulatory application extends east from the Scotford Upgrader at Shell Scotford through Alberta’s Industrial Heartland, then northwest across the North Saskatchewan River to the pipeline terminus, approximately 8 km north of the County of Thorhild, Alberta.

A Site Integration request (SI Ref. # SI-069) has been prepared in accordance with the interface procedure (OSG-P10.03) to reserve right of way (ROW) for a buried 12” CO2 pipeline that will run from the Quest Compressor area to the fence line at the East side of Scotford. This pipeline will start at the pig launcher and run East until the existing so called “ATCO” trailer, them it will turn South until the so called “Training center” trailer, where it will turn East passing between the Selenium area and the North side of the so called “rented equipment parking” area, after which it will go East ward to the fence line. Pipeline will be buried at 1.5m depth.



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7. CAPTURE PLOT PLAN

The Plot Plans are currently shown on the following drawings (Appendix A4):

Document No. Revision Rev No

246.0000.000.044.001 Plot Plan CO2 Capture (RCDU)

Unit 246, 247, 248, 249 IFD 0

240.0000.000.044.001 Hydrogen Manufacturing Unit

Overall Plot Plan IFD 6

440.0000.000.044.001 Plot Plan Hydrogen Manufacturing

Unit 440, 441 & 443 IFD 2

The overall siting philosophy is further described in Section 6.0 of this document.

The Nov 2009 BOD plot layouts were based on traditional “stick built” construction, with minimum modularization incorporated. At the start of the Pre-FEED phase a “3rd Generation Modular ExecutionSM” approach was utilized to redevelop the Select Phase plot plans and maximize the use of Alberta Corridor Truckable modules for the CO2 Capture facilities, which is reflected in the latest plot plans listed above. The Modularization Approach is further described in Section 2.17 of this document.

During FEED, module sizes and weights have been confirmed through the project design review process. A PEER Review by Shell on the Plot Plan and Modularization (July 12 – 14/2011) confirmed the viability of the current design basis (conference note ref. # CN-505).

7.1. Amine Regeneration, CO2 Compression and CO2 Dehydration Area

The Amine Regeneration, Compression, Dehydration unit is located at the Scotford facility on a brown field East of the existing HMU1 and HMU2 facilities.

Ongoing process studies were incorporated as a result of P&ID reviews, PHA II and various model design reviews.

A fact finding site visit to a CO2 Compressor installation in North Dakota was used as the basis for early layout of the CO2 Compressor. This was the same size compressor as Quest although the North Dakota process produces dry CO2 reducing the need for water knockout equipment for pipeline transport.



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The extent of the CO2 Compressor area modularization has been extensively reviewed and is defined as shown on the “RCDU module index drawing” (Appendix A4). The Compressor and associated piping layouts have been developed during the FEED phase with vendor input and have dictated the IFD plot plan Compressor Building sizing basis.

Key Considerations in setting the Quest plot plan;

· The CO2 vent stack has been confirmed to be located in an ALARP location froman HSE perspective (document ref. A6GT-R-1034, CO2 VENT STACK DESIGNDETAILS ALARP REVIEW). It will remain outside the 100 meter radius from theSecurity Building.

· General plant process flow, to locate equipment in optimal locations to minimizepiping lengths.

· The Pig Launching Module has been located to best suit a pipeline corridor exitingthe Scotford Facility to the east. HSE concerns for the pig launcher moduleregarding depressurization during operation will need further consideration tomitigate any risks, potentially a deflection wall or earth berm may be considered onthe loading end of the launcher. Also the pig launcher has been located as far aspossible from the main security building to the south.

· The Amine Makeup Tanks (TK-24601 and TK-24602) are located to minimize trucktraffic within the existing plant road network.

· Temporary / rental amine storage tanks are anticipated to be placed on an unpaved,uncurbed area beside the Amine Storage facility in accordance with the design class.

· Logical access for Operations and Maintenance activities, including access forexchanger bundle pulls, air cooler maintenance, and filter element access.

· Facilitate plant constructability, in particular crane access to set modules and dressedvessels.

· Based on the fact HMU1/2 new absorbers are within the HMU1/2 battery limit towest, location of new CO2 compression unit took into account the most direct routeto minimize piping, steel and electrical cabling to tie the two facilities together.

· The CO2 compressor will be located in a fully enclosed equipment shelter building.Details may be found Decision Note A6GT-DN-1020 and the respective ALARPstudy, but the primary reason is noise. If the compressor is outside or semi-enclosed,it will not likely be possible to meet the 50 dB noise impact criterion required in theShell Quest HSE premises at the Security building. Some toxic release scenarios aremodified slightly by the presence of a building. Operability and maintainability aresignificantly improved.

· A process isolation philosophy has been reviewed during the development of theP&IDs and battery limit valves have been added where required. The locations ofthe battery limit valving were reviewed during the FEED phase model reviews formaintainability and operability.

· Stormwater Containment & Drainage Philosophy requirements are defined within theapproved Decision Note A6GT-DN-1062. The basis is to provide concrete paving



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with curbing, underground piping and catch basins/manholes to capture rainfall and potential spills during operation and maintenance activities. Direct the collected water to the POSWS. Secondary containment requirements for aboveground storage tanks are covered in a separate decision note (A6GT-DN-1047).

· Decision Note A6GT-DN-1049 (Above Ground vs. Buried Modules) has beenapproved. Aboveground modules will be used. Both the above ground andembedded options are technically acceptable and can be used for 3rd Gen ModularExecutionSM, however, above ground modules provide a lower TIC.

Key Plot Plan Constraints

· The plant has been located south of the existing east-west underground O2 (5 m)right of way that runs directly south of 9th Ave.

· The layouts are in accordance with Shell’s design guidelines and practices related toPlant Layout: DEP - 80.00.10.11-SCAN - Layout of Onshore Facilities, as well asShell’s Human Factors Engineering in Workplace Design (OSG-P9.15 Green Book2008).

· Process requirements such as hydraulics dictating equipment locations relative to oneanother, pressure drop constraints, maintaining short pump suction lines, equipmentelevations to satisfy free draining requirements.

· The Class of Facilities defines NO allowance for future expansion.

· The Plot Plans have been developed based on using truckable modules transportedto site using the Alberta Heavy Haul Corridor.

·

7.2. HMU 1 & 2 Capture Area (Amine Absorbers and wash water equipment)

The new amine absorbers, wash towers and associated equipment for the HMU1 & 2 units will be installed upstream of the PSA units in the existing units as brown field work. Amine lines from the HMU1 & 2 units will be connected to the new CO2 Capture Unit on a new pipe rack.

Key Considerations

· Maintain the shortest distance possible, for the raw H2 gas line to the new AmineAbsorbers due to pressure drop limitations.

· Minimizing associated utility interconnecting pipelines to tie-in locations within theHMU unit and avoids using utilities from the CO2 compression facility.

· Facilitate plant constructability, in particular crane access to set modules and dressedvessels.

· The process isolation philosophy has been defined, reviewed and incorporated.

· Stormwater Containment & Drainage Philosophy requirements are defined within theapproved Decision Note A6GT-DN-1062.

· Decision Note A6GT-DN-1049 (Above Ground vs. Buried Modules) has beenapproved. Aboveground modules will be used. Both the above ground and



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embedded options are technically acceptable and can be used for 3rd Gen Modular ExecutionSM, however, above ground modules provide a lower TIC.

Key Constraints

· Allow for maintenance access into and around existing HMU equipment.

· Locate new equipment to minimize existing underground demolition and relocation.

· All existing fire suppression equipment will need to be re-evaluated in areas wherenew facilities may impede the “expected performance” of these systems. Preliminaryreviews have provided a basis that has been included within the Type 3 Estimate.

7.3. HMU 3 Capture Area (Amine Absorbers and wash water equipment)

The new amine absorbers, wash towers and associated equipment for the HMU3 units will be installed upstream of the PSA units in the existing units as brown field work.

Within HMU3, Lean and Rich Amine pipelines back to the CO2 Capture Unit are presently routed on the north side of HMU3, north of the PSA absorbers running east to a new sleeperway running south to the existing eastside sleeperway.

Key Considerations

· Maintain the shortest distance possible for the raw H2 gas line to the new amineabsorber due to pressure drop limitations.

· Constructability, in particular crane access to set modules and dressed vessels.

· The process isolation philosophy has been defined, reviewed and incorporated.

· Stormwater Containment & Drainage Philosophy requirements are defined within theapproved Decision Note A6GT-DN-1062.

· Decision Note A6GT-DN-1049 (Above Ground vs. Buried Modules) has beenapproved. Aboveground modules will be used. Both the above ground andembedded options are technically acceptable and can be used for 3rd Gen ModularExecutionSM, however, above ground modules provide a lower TIC.

Key Constraints

· Allow for maintenance access into and around existing HMU equipment.

· Locate new equipment to minimize existing underground demolition and relocation.

· All existing fire suppression equipment will need to be re-evaluated in areas wherenew facilities may impede the “expected performance” of these systems. Preliminaryreviews have provided a basis that has been included within the Type 3 Estimate.

7.4. Interconnection to existing units



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A new interconnecting Piperack has been located to run from the CO2 Capture area to the existing 285 Piperack at the intersection of G Street and 10th Ave. The envisioned routing will run on the north side of 9th Ave, to G Street then north on the eastside of G Street to the 285 Piperack where the utility tie-ins are located.

A Site Integration request (SI Ref. # SI-052) has been prepared in accordance with the interface procedure (OSG-P10.03) for the addition of a combination of new piperack and the use of existing piperack to accommodate the routing of various utilities from tie-in locations to the Quest Capture plot; also to accommodate the routing of amine lines from the Quest Capture plot to HMU3. This request was approved in October 2010.

In the intervening months it has been determined that the amine lines – initially shown on the east side of H Street between 10th Avenue and HMU3 – must cross H street to avoid encroaching upon the 138 kV right-of-way. The cross must occur immediately south of 13th Avenue. The bridge height will be equal to other bridges on H Street (5.3m). On the west side of H street, the pipeline will travel through a small portion of ATCO earmarked land, past the expansion cooling tower, and the PSA absorber vessels, and finally into the HMU3 component of the Quest scope.

A model review of this routing was conducted in April 2011 by the Quest CCS Project team and representatives from the Scotford site.

A separate Site Integration request (SI Ref. # SI-054) has been prepared for Quest’s Cooling Water Routing. Most of the utilities needed for Quest CCS will be routed on a new modular piperack which extends south from 10th Ave to 9th Ave along G Street, then East to the Quest CCS plot. However, cooling water demand is quite large, and the pipe required is > 24” in diameter. Regarding constructability, construction resources have informed the team that it will be easier for the cooling water to follow a different route to the Quest plot, than to follow the same path as the new modular piperack.

The Cooling Water tie-ins will be made in Units 250/251 and in Unit 252. The line from Unit 250/251 will extend east along the existing piperack on 10th Avenue. The line from Unit 252 will extend south along the existing piperack on H Street. Where 10th Avenue and H Street intersect, both lines will continue east along the existing rack, to the east side of Unit 284 (Main Substation). There the lines will go underground, and extend south to the Quest plot south of 9th Avenue.

Key Considerations

· Approximately 15 piping tie-ins are to be located in the existing 285 piperack nearintersection of G Street and 10th Ave. Thus the new piperack is located in an optimallocation with respect to overall length.



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· Quest has VALIDATED the access requirements for operations and maintenanceon the west and south side of Cogeneration and Utility building relative to theproposed location of the interconnecting piperack.

· Location of the new piperack to minimize underground demolition and relocationof existing facilities.

· The following Integration Requests for proposed Quest facilities have been preparedand submitted to Scotford for approval;1. Ref. SI-052 - Quest Pipe Routing for Amine & Utilities - approved2. Ref. SI-054 - Quest Cooling Water Routing – approved3. Ref. SI-069 - Quest Pipeline ROW ISBL route – submitted

Key Constraints

· Constructability due to the 138 kV right-of-way.

· The 36” Steam line tie-in and interconnecting piping has been studied in detail dueto the large line size, to allow the tie-in to be located and orientated to best suit thenew piperack location. The tie-in (TP285-7) location has been finalized and theisometric drawing issued IFC.

· 30” Cooling Water tie-in locations have been finalized, however the locations mayhave a temporary impact on existing operations. The tie-in (TP251-6 and TP252-1)locations have been finalized and the isometric drawings issued IFC.

7.5. Client Plot Plan Review including HFE and Constructability

During the FEED Phase, a series of model reviews were performed for each process area, to review the preliminary layouts to get Owner, Operations, Maintenance, HFE, HSE, Construction and inter-discipline stakeholders to arrive at an agreement with the proposed design. These were not intended to be “line by line” reviews, the intent was to “freeze” the 3rd Generation Modularization equipment layouts and module boundaries to determine the number of modules, and establish the general elevation of the working floor for modules, as well as to obtain agreement on electrical and instrumentation distribution networks, in order to support the engineering input baseline for the TYPE 3 Estimate and the subsequent issue of the IFD plot plans.

The preliminary model reviews were performed for each process area, starting with the O&M, HFE and Constructability reviews, and finishing with the Plot Plan Reviews. These reviews were intended to solicit/capture Shell feedback during the preliminary stages of module design in order to minimize design recycle during the development process. The internal and joint reviews addressed the following criteria;

· Confirm all equipment (configuration) optimization opportunities have been identified

· Process requirements (performance) relative to equipment location

· Review module large bore piping (visual stress 10"> complete) layout

· Preliminary configuration of electrical trays



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· Confirm preliminary column, beam and bracing locations

· Review configuration of Inline instrumentation in piping

· Confirm all critical space reservations have been identified, including general O&MHFE access envelopes

· Constructability review, includes Construction, Operations, maintenance, HFE Repand Construction Safety

· Review access to instrumentation and remote IO boxes at a conceptual level



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8. OPERATING MODE CASE STUDIES

Overall integration of operating modes and key process control loops has been developed in drawings 246.0001.000.040.005 and .006. These drawings have been used to verify integrated operating modes across Capture/Pipeline and wells scope.

8.1. Start Up of the CO2 Plant

1- Preliminary steps preceding an actual start up of the CO2 Plant involve ensuring thatall vessels and piping are clean, properly preserved, and “ O2 freed” by purging themwith nitrogen. All process and utilities tie-ins are complete such as cooling water, lowpressure steam, high pressure steam, electricity, instrument air, utility air, nitrogen,flare, boiler feed water, return clean condensate, waste water, and fire water systemsand are ready for service prior to start up. Only one HMU train is lined up for theinitial pipeline commissioning and well start up.

2- The next step is to inventory the ADIP-X amine solution (40% MDEA, 5% DEDA,55% water) into the Amine Stripper in order to build working levels and to startcirculation to the Absorption System. The anti-foam system needs to be ready forservice and the anti-foam tank must be full of the correct anti-foam chemical, pumpsmust be primed and tested before the amine circulation begins.

3- Circulation from the Amine Stripper via the Lean Amine Pumps, Lean/Rich AmineExchanger, Lean Amine Cooler, Lean Amine Filter, Lean Amine Carbon Filter, LeanAmine Post Filter, and Lean Amine Charge Pumps is established to the Absorbers.

4- Sufficient nitrogen pressure is necessary at the Absorbers to pressurize the aminefrom the bottoms of the Absorbers back to the Amine Stripper to complete thecirculation loops. The use of nitrogen is limited to start up and shut down periods tominimize their losses and also to prevent any contamination of the CO2 to theinjection well head.

5- Samples need to be taken at the outlet of the Post Amine Filters to verify amineconcentrations and to ensure that the amine is in clean condition.

6- Low Pressure steam is slowly opened up into the tube sides of the Amine Reboilers atthe Amine Stripper, in order to warm up the vessels and establish the amine flowsthrough the shell sides of the Amine Reboilers. This slow warm up of the aminesystem is done to prevent stresses on the system due to uneven temperatures, ensure

X amine solution (40% MDEA, 5% DEDA,% MDEA, 5% DEDA,55% water) into the Amine Stripper in order to build working levels and to start



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that there are no leaks in the system, and to make sure that the amine system is ready for service. A small portion of the Return Clean Condensate (RCC) from the Stripper Reboilers is to be routed back to the Absorber Wash Water Vessels, and excess RCC is routed to the base plant RCC Storage Tank. The temperature of the lean amine flows to the absorbers is also closely monitored to make sure that the lean/rich heat exchangers are working properly and that the correct amount of cooling is taking place at the exchangers.

7- All instrumentation, including flow, level, temperature, and pressure transmitters ofthe various pumps and heat exchangers need to be commissioned and function testedfor proper operation.

8- The CO2 Compressor must be purged with nitrogen and be ready to start. The CO2Compressor surge testing and run-in test must be completed before CO2 is madeavailable to the compressor. The CO2 Vent Stack shall be commissioned and readyfor service. The CO2 will be initially vented until all components in the amine unit arestable, and beyond the minimum turndown to ensure that when we start up thecompressor that enough CO2 is available to go through the surge point quickly.

9- The TEG system charge pumps, Regenerator Stripping Column, Absorption Tower,Flash Drum, Lean/ Rich Heat Exchangers, and Knock out Drum circuits must becommissioned and ready to dehydrate the wet CO2 gas stream when it is available.High Pressure Steam is required to regenerate the rich TEG and must be available.The RCC line will also be placed in service.

10- The CO2 sequestration well will be checked that it is lined up and ready for service.All instrumentation and shutdowns need to be tested prior to being put in service.Note that the pipeline must be commissioned by this time, and all hydrostatic testwater is removed by running a pig through the pipeline. The pipeline must bemoisture freed to ensure all traces of moisture have been removed. The B/L custodytransfer meter must also be tested and ready for service.

11- At this time the HMU’s will be in steady state service and ready to supply feed gas tothe CO2 Plant. The amine circulation rates to the Absorbers will be monitored andthen the feed gas supply will be put in service. The flows to the Absorber(s), and theoverhead gas via the Absorber Water Wash Drum to the PSA will be slowly openedup.

12- The CO2 Absorption System is now in service and is removing the CO2 from theinlet feed gas to the Absorbers. Rich amine will be pressurized back to the AmineStripper for regeneration and reuse. Care must be taken to slowly increase the flow



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rates of the feed gas to the Absorption System without adversely affecting the PSA and SMR units by pressure spikes or amine carry-over from the Absorber Wash Water Vessel to the Pressure Swing Absorbers (PSA). Once the CO2 has been captured in the CO2 Plant the PSA Feed as well as off gas will be reduced in volume. Extra fuel gas will be needed in the SMR furnace, and will also require more combustion air to the reformer. The PSA absorption cycle times will have to be adjusted based on the plant load. The SMR firebox High and Low Pressure trips must be carefully watched when the combustion air is increased and the PSA Unit is in the lean mode of operation. The CO2 will be routed to the vent stack until sufficient CO2 is available to start the CO2 compressor. The Dehydration System is now started and drying of the CO2 gas will begin. The compressed CO2 will now be pressurized into the pipeline and down into the well reservoir.

Loadings of the amine will need to be done to verify correct absorption of the CO2; and all flows, temperatures, and pressures of the CO2 Plant taken to ensure correct operation.

8.2. Normal Operation of the CO2 Plant

The following items are the main specifications and issues, while the CO2 Plant is in normal operation:

1- CO2 Recovery is normally at 80% but can be varied by adjusting the percentage ofamine flow. An inline CO2 analyser will be installed on the outlet line of the WashWater Vessels to the PSA to monitor CO2 concentration in the feed gas to the PSA.

2- The use of the Flue Gas Recirculation (FGR) will be used for NOX control of theSMR flue gases. The burners will be changed to a newer type of Ultra low NOxburner to assist in NOx reduction.

3- The additional delta pressure drop added to each HMU is expected to beapproximately 70 kPa across each absorber and wash water vessel system.

4- The maximum amount of tolerable amine carryover from the Absorber Water WashVessels to the PSA Units is 1 ppm. Amine carryover will coat the adsorbent media inthe PSA Units and reduce their efficiencies. This would ultimately lead to higherdelta pressure drops across the beds, reduced throughputs, lower quality hydrogenproduction, premature change outs of the absorbent media, and higher operatingcosts. Water wash in the absorber overheads is designed to remove the aminecarryover, and demister pads designed to remove 99% of liquid droplets in theAbsorber overhead.

5- The CO2 Plant should not affect the temperature of the PSA feed gas. Thetemperature of the PSA inlet gas shall not exceed 35°C. Shell and tube exchangers



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using cooling water as the cooling medium will be used to cool the make-up water to the Absorber Wash Water Vessel. The Wash Water Vessels have demister pads on their outlets to remove amine from the PSA Unit feed gas.

6- Foaming in the Amine Absorption System and Regeneration System is caused bydegradation products (i.e. iron compounds, acids and particulates) that are insolution with the amine. The foaming can cause carryover of liquids from theAbsorbers and Regeneration System vessels, and will reduce throughputs andproduct qualities. A portion of the lean amine is routed through the Lean AmineFilter, which contains cartridges to remove the degradation products. This isfollowed by the Carbon Filter and the Post Amine Filter, which also containscartridge filters, to purify the lean amine streams upstream of the Absorbers. Thetotal amount of the amine being filtered is approximately 25%, with 5 % of the total amine flow being filtered in the Carbon Filter. Anti-foam chemical may also be periodically pumped into the amine system to reduce foaming in the Absorbers and Amine Stripper.

7- The amine system is expected to lose some water due to small amounts ofentrainment to the PSA Units, and from the Regeneration System to the CO2 Plant.Water makeup to the amine system is from the HMU 1 and 2 purge water system aswell as the RCC system. Water makeup can be added to the unit through aconnection provided on the make-up water circulating loop. This allows for themaintenance of the amine-water balance. The makeup water is to be added underflow control. Amine addition is from the pure amine tank and is pumped slowly intothe amine system. Tests for amine concentration need to be done to keep the aminepercentage correct (ie.40% MDEA, 5% DEDA, and 55% water).

8- Only one Absorber Unit will be brought on line at a time. This is done to minimizethe adverse impact on the HMU trains, and to prevent upsets in the CO2 Plant. Thisis because there is only one Amine Regeneration Unit for the three Amine AbsorberUnits. Once one Absorber has been brought into service and is lined out, a secondAbsorber Unit can be brought on line, and then a third Absorber Unit is started.Follow the steps outlined in Section D- Start up Procedure for Amine Unit andHMU. The lean amine flows to the Absorbers will be on flow control, with the richamine in the Absorbers being on level control. The feed gas to the Absorbers will beat 35 degrees C. and 3,000 KPag, and the overhead gas is at approximately the sametemperature and pressure when it is routed to the PSA Unit. The Absorbers haveinstrumentation for flow, level, pressure, and temperature. A pressure differentialindicator and alarm is required across the trays within the Absorbers. The importantfunction of the pressure differential indicator is to detect increases or fluctuations indifferential pressure that are warnings of tower foaming. The Absorbers areoperated with flows of lean amine at a fixed rate and the operator will manually

25%, with 5 % of the total %, with 5 % of the total

percentage correct (ie.40% MDEA, 5% DEDA, and 55% water).% MDEA, 5% DEDA, and 55% water).% MDEA, 5% DEDA, and 55% water).



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adjust the amine flows when significant changes in gas flows are expected for extended periods of time.

10- The Capture unit impact on the HMUs must as little as possible.

8.3. Shutdown of the CO2 Plant

These general steps will be taken to shut down the CO2 Plant:

1- Slowly reduce the feed to the CO2 Plant absorbers by means of the feed gas bypassarrangement. The feed to the PSA units will change from “lean” to “rich” when theCO2 Plant is taken off line. Once the CO2 Plant is totally bypassed and off line, itcan be blocked in by closing the isolation valves on the inlet to the Absorbers.Adjust the PSA sequencing/cycle times to the CO2 rich operation.

2- The impact to the PSA Unit and HMU is expected to be minimal. Shortly after thefeed to the PSA Units changes from lean to rich, the loading on the PSA Units willincrease. This also changes the composition of the off gas from the PSA Unit to theSMR and the requirement for FGR. The increased flow of the off gas to the SMRwill mean that the quantity of combustion air will be decreased. The steam reformertube wall temperatures must be kept within acceptable values in order to protect theintegrity of the tubes.

3- Continue to circulate lean amine to the Absorbers at a constant rate. Reduce theintake of feed gas until the inlet feed is completely bypassed. In this way there is onlyone parameter to control and doing this will not affect the HMU. It may also help tospeed up the removal of the CO2 from the amine. Check valves or non returnvalves, and manual isolation valves, may be needed on the feed gas inlet to eachAbsorber to minimize the loss of rich amine from the Absorbers. Once the leanamine streams do not contain CO2 the circulation of amine to the absorbers can bestopped by shutting down the amine circulation pumps and blocking them in.

4- Once the amine is CO2 free, reduce the LPS to the Amine Reboilers gradually andthen block in the LPS block valve to the inlets of the reboilers.

5- Build levels in the Amine Stripper to working levels, and then stop the aminecirculation by shutting down the Lean Amine Pumps, Lean Amine Charge Pumps.Care must be taken to ensure that the levels in the columns do not get high enoughto flood the towers once the amine circulation has been stopped. The amine storagetank can also be used to store additional Amine during an outage.



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6- Stop the CO2 Compressor once the Amine Unit is shutdown. After the CO2compressor has been stopped the remaining CO2 in the overhead line will be ventedto the CO2 Vent Stack. The pipeline must be ready to be blocked in once thecompressor is out of service.

7- Stop the CO2 Dehydration Unit and block in the HPS to the TEG Regenerator.

8- Block in the CO2 pipeline and wellheads. .

9- Open up nitrogen to the unit to keep pressure on the unit and prevent air fromentering it.

10- Close control valves on the Absorbers amine feed lines, overhead line, and richamine line. Close block valves at these locations also.

11- Isolate the Regeneration System by closing control valves and block valves on theAmine Stripper and amine pumps.

12- Depending upon the operations needs, additional steps will need to be undertaken.These would include shutting down the CO2 Plant for a planned Turn Around andwill include the following :

- Draining of lean amine to temporary storage tanks

- Blinding the vessels and opening them up for maintenance, inspection, andcleaning.

- The nitrogen blanketing gas will need to be closed prior to any confinedspace entries to the vessels.

- All utilities that are not required would be blocked in until they are requiredat a later date.

- PSVs that require servicing would be removed, tested, and reinstalled

- any repairs to prime movers and stationary equipment would be done

13- Note: Individual Absorbers may need to be taken off line in cases where the HMUtrain is taken down for Turn Around. The feed gas will be slowly closed to theabsorber and then amine circulation will continue until the amine is CO2 free. TheAbsorber will be blocked in, drained, steamed out, and blinded prior to any confinedspace entry to it.



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8.4. Trips and Emergency Shut Down of the CO2 Plant

A CO2 Plant emergency shutdown or trip is to be designed to have no impact on the operation of the rest of the facility (i.e. HMUs). The overall design of the control system shall be based on Shell’s operating philosophy for a manned 24/7 operation and associated Shell DEP and design standards. The CO2 Plant is to be a standalone unit with all the required emergency isolation valves installed inside of the plant battery limits. The control system for the CO2 Plant will be fully integrated with the Base Plant DCS. The control valves on the feed gas bypass arrangement at the Absorber feed gas inlets will be fully automated instruments, so that they can react quickly to flow and pressure surges to the PSU Units when the changes from lean to rich conditions occur. Shortly after a shutdown of the CO2 Plant (i.e. one cycle or 5-10 minutes in duration) the composition of the feed gas to the PSA Unit and the offgas to the SMR will greatly change. This has the potential of changing the product hydrogen from the PSA and will also affect the operation of the SMR. The quantity of air from the combustion air fans will be decreased due to the increase in off gas flow. Consideration must be also be given for the steam reformer tube wall temperatures to be within acceptable values, in order to achieve acceptable tube service life.



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8.5. Amine Draining

An Amine Drain Drum is provided to collect amine drained from piping, equipment and instruments located in Unit 246. Any amine that cannot be pumped directly to the amine storage tank prior to maintenance activities will be either gravity drained or pressured with nitrogen to the Amine Drain Drum. Amine collected in the drum is pumped through a particulate filter before being sent to either the Amine Stripper (during normal operation) or the Amine Storage Tank (prior to maintenance).

The amine draining philosophy is as follows: 1. Amine Absorber Draining: Current basis is to pressurize amine from the HMU

Absorbers to the Stripper down to the LLL (Proper evaluation of LL set value willbe done) using the pressure in the absorbers. The isolation valves downstream ofthe level control valve would be closed, and any amine remaining in the systemwould be withdrawn by vacuum truck (4” drain connection provided). Theremaining volume of amine is approximately 8 m3 for HMU1/2 and 15 m3 forHMU3. There will be no other amine drain facilities provided in the HMUs. Adetailed Amine draining Procedure will be generated as part of shut down procedureby Operations.

2. Prior to shutdown of the Amine Stripper the bulk of the amine would be transferredto the Amine Absorbers in the HMUs as well as the Amine Storage Tank. Theremainder of the amine can be gravity drained to the Amine Drain Drum. Since thiswill be done during total Quest shutdown, it is assumed at this stage that transferringamine to absorbers will not need over filling of vessels beyond high level.

3. Intent is to leave the main line from absorbers to strippers packed with amine. ForHMU3 in particular, this represents a substantial volume. If maintenance is requiredon these lines, temporary storage tanks would be needed to hold the volume ofamine. It is assumed that the amine can be pressured from the line to the tank usingnitrogen and existing vent and drain connections. A temporary amine storage spacewill be allocated in plot plan and necessary flange or spool piece connections will beprovided to facilitate temporary draining.

4. The amine drain system in Area 246 gravity drains to the Amine Drain Drum, andrequires drain pipe routed below grade in a trench. This trench will also collectrainwater from potentially contaminated amine area runoff which could otherwisecontaminate groundwater. A local collection basin will be considered separate fromthe amine vessel sump to collect this water runoff and pump it to wastewatertreatment.

A nitrogen blanketing system is provided on the drum to maintain an inert atmosphere in the drum, which will prevent degradation of the amine due to oxygen exposure. The drum will be vented to atmosphere.



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9. HIGH LEVEL RAM STUDY

Shell Global Solutions has performed an update to the reliability study for the CO2 capture, compression, and storage facility that has been proposed for the Scotford Upgrader. The study was used to determine the availability of the facility, identify key equipment that contributes to the downtime of the system, and then use sensitivity analysis to quantify the impact of alternative design configurations. Reliability data was taken from previous studies performed for Shell Canada and other refineries.

For the Base Case, the average Quest production efficiency was predicted to be 97.6%. When the availability of the Scotford Baseplant and Expansion Upgraders were considered this resulted in an overall CO2 injection availability of 90%, meeting the premises set out in the GOA funding requirements.

Figure 8 – Overall Quest RAM Block Model

The compression section contributed the majority of the losses. Several other scenarios were simulated to include the impact of the pipeline and well injection facilities, and to investigate the sparing of pumps and compressors. A full report of RAM work undertaken in SELECT is contained in Quest CCS Project RAM Study – Final Report GS.10.52419.

Although the compressor is the major influence on Quest reliability, economic analysis completed in Pre-FEED indicated that 2@100% or 2@50% compressors are not economically justified.



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10. PROJECT INTEGRATION

An interface management process has been established that will facilitate the timely identification and resolution of project interfaces. Effective interface management is a key element of sound project management and is a critical success factor to ensure cost, schedule, safety and quality targets are met. The key aim is to provide a consistent cross-project method by which interfaces can be identified, developed, mutually agreed, managed, tracked, controlled and closed out.

The Interface Management Plan (IMP) provides:

1. A consistent approach for achieving technical alignment between work areas

2. A process for initiating information requests

3. An auditable trail for interface transfers

4. A process for resolving difficulties or disputes

5. A process for managing changes arising that affect project activities

The Interface Map and focal points are shown in the diagram below:



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The process description of the Interface Management Plan is as follows:

1. Focal point (FP) generates an Interface Data Sheet “IDS” request.



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2. IDS request goes to Document Control; Document Controls routes it to FP’s andrequired recipient(s).

3. IDS acquires unique number cover sheet from Document Control.

4. FP’s resolve directly and close out.

5. If dispute arrives elevate to interface lead.

6. The IDS revs up under the unique cover.

The full interface management plan is available as document 07-0-AA-5800-0003 Interface Management Plan



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11. INSTRUMENTATION AND CONTROL

The implementation of control and safeguarding on a process system spans two different plants where each plant has a different vendor for the control system. All equipment within the physical boundary of a plant is controlled and maintained by that plant. The Base Plant has an Invensys Foxboro based control system with a Honeywell based Safety System (note: the existing GE Fanuc Safety System is being replaced on the Base Plant) whereas the Expansion 1 Plant has a Honeywell Experion control system with a Honeywell based Safety System. In addition, the Invensys Foxboro control system at the Base Plant is being upgraded to the latest offering; the Quest CCS Project will need to interface to the final control system design.

Detailed accounts of the control systems and the implementation plans for integrating the Quest CCS Project into the existing frameworks are available in the “Control and Automation Philosophy and System Architecture”, document number A6GT-R-1023. Specific instrumentation and control considerations are highlighted in the following sections.

11.1. Lean Amine Distribution

The Quest CCS Project instrumentation and control design premise is to define each process unit as a stand-alone unit in terms of safeguarding and control. Therefore, the Expansion 1 amine supply and demand control is independent of the amine supply to the base plant absorbers. Both plants appear as "customers" to the amine regeneration unit; the lean amine supply from the Amine Regeneration Unit is capable of dealing with any demand changes from either customers.

Independent lean amine flow control valves are located inside each HMU CO2 Capture area, and are controlled by the unit operators. The individual flow controllers are overridden by the level control signal from the Amine Sump, in the event of a high or low liquid level.

11.2. Amine Stripper Reboiler Controls

SGSI, the licensor for the ADIP-X Process, has outlined the reboiler control systems in Section 5 of the “QUEST CO2 CAPTURE PROJECT AMINE UNIT Basic Design Package”, SGSi document number SR.11.10343

11.3. Hydrogen Manufacturing Units (HMU 1/2/3)

By extracting the CO2 from the raw hydrogen gas stream, composition of the PSA feed gas is changed significantly. PSA licensors (Air Products for HMU1/2 and UOP for HMU3) have been approached to determine whether modifications are required to the PSA vessels and control schemes. UOP has indicated that the PSA system can adequately respond to the



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reduced CO2 content in feed gas stream, for HMU3; Air Products will provide recommendations during the Execute Phase.

The tail gas from the PSA, which is used for fuel in the Steam Reformer, sees significantly less CO2 with the implementation of the Quest CCS Project. CO2 inside the furnace is used as to reduce the NOx produced, and affords the ability to recover heat via feed preheat and steam generation. To compensate for the loss of heat absorption, a Flue Gas Recycle (FGR) system is implemented (refer to Section 17 for further details). To prevent disruptions to the Upgrader hydrogen supply, due to loss or start-up of the CO2 Capture Units, the FGR system is required to switch from CO2 rich to CO2 lean tail gas operation (and vice versa).

Control options have been identified in the “Control and Automation Philosophy and System Architecture”.

11.4. CO2 Compressor Controls

The requirements for CO2 compressor control, performance control and machine monitoring will be finalized during the Execute Phase of the Quest CCS Project. The direction is to utilize the compressor vendor’s standard surge and performance control system and interface this system with the Base Plant DCS and Safeguarding Systems. Existing Base Plant machine-monitoring standards are used for compressor protection.

There are significant analytical measurement & gas detection requirements for the Quest CCS Project:

· Moisture measurement in the CO2 flow post compression; in order to protect thecarbon steel pipeline from corrosion and potential hydrate formation at chokevalve . The required redundancy on this measurement will be reviewed during theExecute Phase. At this stage a redundant analyzer configuration has beenassumed.

· CO2 content in the raw hydrogen gas stream for each of the three HMU plantsfor combustion control

· CO2 point and area gas detection for personnel safety

· H2 analysis (from GC) to adjust compressor antisurge controls (if required)

· CO2 vent stack monitoring for potential regulatory requirements

The metering technology recommendations from the pre-FEED phase are detailed in sections 9 and 11.3 of the “Control and Automation Philosophy and System Architecture”.

11.5. Third Generation Modularization

Fluor 3rd Generation Modularization is the construction methodology accepted for the Quest CCS Project. The main implication for controls is that instrumentation (i.e.



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transmitters and end devices) is fully installed and wired in road transportable modules by the use of remote I/O and digital networks. Together with a distributed electrical system, this construction method minimizes the controls and electrical installation effort at site. Design details for this construction methodology were finalized and presented for Shell comment and approval during the Execute phase.



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12. ELECTRICAL

12.1. Electrical Design

The power design shall be based on the latest revisions of Shell Standard 15-1.01 and its amendment. The design approach and equipment selection for the CO2 capture plant is standardized and integrated with the overall facility.

The design and construction of the electrical system shall be in accordance with the applicable codes and standards of the Canadian Electrical Code CSA C22.1 &C22.2 and other requirements of the provincial and local electrical inspection authorities having jurisdiction.

A Decision Notice has been approved in the Pre-FEED phase to allow the project to use the Objective Based Industrial Electrical Code. An OBIEC specific electrical Quality Management Plan was developed during FEED upon reflect at the end of the FEED phase and in consideration of available procurement activities it was decided to stop implementation of OBIEC on Quest. The completed OBIEC documentation will be filed for potential use on other Shell projects.

12.2. Power Supply and Distribution

The majority of process equipment of Quest CCS Project is located at the Upgrader Base plant and a small portion of process equipment will be located adjacent to HMU3 at Expansion 1 plant.

The power supply for the Amine Regeneration, CO2 Compression and Dehydration areas at the Upgrader base plant will be obtained through two new 34.5 kV breakers at the 34.5 kV switchgear line-up 284-SG-3501 located in the U&O area. A new breaker on the B bus section will supply a captive transformer 34.5kV/13.8 kV, 40 MVA feeding the 16.5 MW CO2 compressor motor.

The second breaker on the A bus section will supply the distribution step-down transformer 34.5kV/ 4.16 kV, 7.5 MVA, which will feed an assembly of 4.16 kV switchgear/motor controllers to supply some of the pumps, air cooler fans, area lighting, and heat tracing.

The power distribution within the CO2 capture facility will be through the 4.16 kV arc resistance type switchgear / motor controller assembly, the 600 V MCC for process equipment, building power, instrumentation & control system and lighting. In general, area



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power distribution system for this project will follow the same philosophy as being used in Base Plant & Expansion 1 areas. The Quest power distribution system will be radial only and not secondary selective.

Shell produced preliminary SKM Load Flow, short Circuit and 16.5 MW CO2 Compressor’s motor starting studies. The purpose of these studies is to analyze and evaluate the impact to the existing distribution system, and confirms the feasibility to supply the Quest CCS Project from the main 34.5kV switchgear. The study results show that the existing power system is robust enough to supply Quest CCS Project under normal operation, and the 16.5 MW compressor could be started from the 34.5 kV switchgear using a captive transformer 34.5/13.8 kV, 40 MVA with 5% impedance. The voltage dip at 34.5kV lineups is less than the permitted 15% of the normal bus voltage. Also, it is noted that the CO2 Compressor motor should not be started under Islanded operation mode, when only GTG &STG are running without power supply from the grid. In the detailed phase of the project, more detailed electrical studies shall be performed using the SKM program models executed by Shell and documented by the EPC.

The critical services feeder will be powered from the UPS as there is no spare capacity on the Utility Critical Service MCC. The critical load list and required power source will be verified during the detailed stage.

CO2 Capture electrical loads in the HMU3 of Expansion 1 area will be supplied from Low Voltage of the Unit 440 HMU3 substation. There are two 600 V MCCs, 440-MCC-401A and 440-MCC-401B. Two new sections of 600V MCC have to be added, one section for eachMCC.

Preliminary cable schedules have been issued during the FEED phase of the project and will be updated during the design phase.

Preliminary low voltage MCC schedules have been issued during the FEED phase of the project and will be updated during the design phase.

During the FEED phase, it was determined that all the major electrical equipment would be supplied be the existing equipment venders and would be identical where ever possible.

Schematics for major equipment and new motors will be identical to the existing presently used at site except that the MCC interface I/O will be located in the MCCs instead of remotely.



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Protection relay settings will be finalized during detailed design. Settings will mimic those of the existing facilities where ever possible.

The new power system will be high resistance grounded.

12.3. Electrical Modularization

The facilities will be designed and installed as a 3rd Generation modularized project. The design will incorporate changes in the location of the electrical equipment such as substations in order to maximize the content of the module shop work and minimize the onsite work. A process module substation will be provided in each process module complex. On site construction duration will be shortened accordingly. It is recognized that extra engineering effort will be required.

12.4. General Electrical Layout

All electrical cables shall be installed in aluminum cable tray system over the pipe rack. Aluminum conductors may be used for power circuits, where economical. Area lighting shall be provided as per operational requirements to a level for night safety. Building interior lighting shall be provided to illuminate the equipment and instrumentation read outs as per the Shell standards.

The main ground grid shall be designed and installed to match the existing plant. All cable trays shall carry ground wire and be bonded as per Shell STD 15.1.01. All equipment shall be connected to the ground grid as per Shell STDs’ and industry practice requirement.

12.5. Electrical Loads

A new electrical load list was provided during FEED and will be updated during detailed design.



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12.6. Power Routing Layouts

The primary power distribution up to the new substations will be 34.5kV level. 4160 volt and 600 volt buses will be provided as necessary. See the Single line Diagram. Detailed power routing layouts and right of ways were developed in the FEED phase of project. During the detailed phase of the project, the design will be embellished with final details

12.7. Area Classification

All areas within the scope of this project shall be classified as per Shell STD 15-1.02 and the API RP 500& 505 for the degree and the extent of hazard from flammable materials. A preliminary assessment of the Capture facility at Upgrader Base Plant has been done. Most of the CO2 Capture plot plan is Unclassified. A portion of the facility that will be adjacent to the Hydrogen unit 240 and in the Expansion area will be classified Zone 2, Group IIC. A final Area Classification drawing will be produced towards the end of detailed design.

12.8. Equipment List

All new main electrical equipment in accordance to the Canadian Shell Standards and from Approved Vendor List (AVL) will consist of the following:

· One 34.5kV/13.8kV, 40 MVA Captive Transformer

· One 34.5kV /4.16 kV ,7.5MVA Power Transformer

· Two 4.16kV/600V Power Transformers

· 4.16 kV Medium Voltage Switchgear, Arc resistance type

· 4.16kV Medium Voltage Motor Control Center, Arc resistance type.

· 600V Low Voltage Motor Control Center

· 120-volt UPS power supply system

All major electrical equipment will be identical to the equipment already on site.



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13. CIVIL

13.1. General

Piles, foundations, structures and buildings will be designed to meet the technical requirements of the specifications and standards noted in Section 2.14 and all applicable codes and standards.

The following general design considerations are to be used for the Civil and Structural design.

13.2. Civil, Paving & Roads

New facilities for the existing HMU plants and the interconnecting rack areas will be designed based on the existing grade elevations and therefore will require little or no grading other than local grading required for construction activities.

The CO2 Capture plot will be covered by a combination of concrete paving and gravel. Concrete paving will be used in areas where there is potential for amine and glycol spills resulting in contaminants in the runoff. Areas requiring concrete paving were determined by Shell and Fluor personnel and are documented in Project Decision Note A6GT-R-1062 Stormwater Containment & Drainage Philosophy. Gravel surfacing will be provided for all other areas.

Concrete paved areas will have surface drainage to a series of interconnected catch basins and manholes which will be discharged into the Potentially Oily Storm Water Sewer. Gravel areas will be graded to provide surface drainage to perimeter ditches which drain into the existing stormwater collection system (combination of ditches and sewers) for the plant. Secondary containment will be required for the amine makeup tank (a concrete bund wall with a geotextile liner) and the closed amine collection drum (a concrete sump lined with steel plate).

New OSBL roads (asphalt paved to match existing site roads) will be required East and South of the new CO2 Capture plot. New ISBL roads (gravel) will be required in the existing HMU plants and the new CO2 Capture plot.

13.3. Geotechnical Investigation

A geotechnical investigation was completed in FEED which involved new boreholes and Seismic Cone Penetration Tests (SCPTs) in the CO2 Capture Plot. The geotechnical report provides the design parameters required for all areas based on the new boreholes & SCPTs in the CO2 Capture Plot area and on existing geotechnical reports for existing plant areas. Existing geotechnical reports for the site referenced in the Quest CCS Project geotechnical investigation provide design criteria such as road design, frost depth, etc.



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Although geotechnical reports are available for the existing site and provide design criteria such as road design, frost depth, etc., the new geotechnical report completed as part of the Quest CCS Project provides dynamic foundation design parameters and limit state design parameters for all areas of the plant where new facilities will be installed as part of the Quest CCS Project.

Vibration of the compressor foundation is of particular concern based on the results of past dynamic analysis for vibrating equipment at site. Therefore, good delineation of the soil stratigraphy and confirmation of the soil dynamic properties for the CO2 Capture Plot are required for the compressor foundation design. Further, once a preliminary design has been completed for the compressor foundation, additional consultation with the geotechnical contractor may be required to complete the design.

13.4. Piles & Foundations

Driven steel piles (H-piles or pipe piles as appropriate) will be used for most foundations (vessels, equipment, steel structures, etc.) as they are judged to be more economical than concrete piles. Where sufficient load capacity cannot be provided with driven steel piles or for foundations with significant dynamic loading (compressor foundation and large pump foundations), bored & cased cast-in-place concrete or Continuous Flight Auger (CFA) piles will be used. Concrete piles may also be required in lieu of driven steel piles in areas where vibration resulting from pile driving operations have the potential to cause excessive vibration of equipment (e.g. foundations for pipe racks adjacent to the ATCO Gas Co-Gen building, foundations for new HMU fans, etc.).

Screw piles may be considered for non-settlement sensitive foundations (e.g. supports for amine lines to HMU3) but may not be economical compared with driven steel piles depending on the number of supports and the construction timing relative to other foundation installations. Note that the use of screw piles would require the engagement of a screw pile contractor to complete the engineering and design of the foundations. Pile caps will be steel plates for small foundations and concrete for large foundations requiring multiple piles such as foundations for large modules, vertical vessels, large equipment and the compressor.

Void form will be utilized below pile caps and grade beams to prevent frost heave where these items lie above the seasonal frost line. This includes pile caps for large pumps located outside of buildings. Void form will not be used for the compressor foundation as it will be inside the compressor building and therefore will not be subject to frost effects. The amine makeup tank will be supported on a piled foundation (to eliminate differential settlement relative to adjacent structures).

The based of the amine drain drum sump will act as a spread footing to support the vessel and the sump thereby eliminating the need for piles for the sump.



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13.5. Structural Steel

Structural steel will be designed with the objective of minimizing stick-built steel and maximizing modularization and pre-fabrication. In general, stick-built construction is anticipated for items such as revamp scope and small off-module miscellaneous supports (e.g. supports for amine lines to HMU3, duct support structures, supports in existing HMU piperacks between absorber areas and tie-in locations, etc.), the compressor building, and supports for piperack modules. A module design concept will be used for formally identified modules on the module index including stair towers, equipment and piperack modules. Refer to Section 2.17 Modularization Approach for more details. Pre-fabrication will be considered for small structures that are not modularized such as small platforms that can be shop assembled, caged ladders, stair stringers with treads, etc.

It is intended that structural steel connections will be designed by Fluor with input from the structural steel fabricator. IFC drawings would identify the type of connection to be used but actual steel detailing would be completed by the structural steel fabricator. In order to maximize the benefit to the project of this approach, early engagement of the structural steel fabricator is required.

13.6. Buildings

The compressor building structural steel (rigid frames, girts & purlins) will be designed by Fluor as a stick-built structure, purchased as part of the project structural steel PO, and erected by Fluor Constructors. Acoustic design of the wall profile and construction details for cladding & associated items (e.g. doors, openings, vents, etc.) will be completed by the building contractor. Supply and installation of the cladding and associated items will be by the building contractor.

The antifoam injection shelter will be designed integrally with the 3rd Generation Modules (i.e. structural steel and secondary framing including grits and purloins will be fabricated as part of the module) with cladding attached directly to the module steel. The module steel will be purchased as part of the project structural steel PO and free-issued to the module assembly contractor. Design and construction details for cladding & associated items (e.g. doors, openings, vents, etc.) will be by the module contractor. Supply and installation of the cladding and associated items will be by the building contractor.

Remote MCC/IO shelters will be designed integrally with the 3rd Generation Modules as self-framing structures supported on the modules. Structural steel supports and flooring will be designed and fabricated as part of the module. Design, construction details, supply and installation of all shelter components will be by the module contractor.

Analyzer shelters in the HMU plants will be purchased as fabricated skid-mounted shelters that are installed on the module as complete items (similar to other equipment items. Design,



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construction details, supply and assembly of the analyzer shelters will be by a separate vendor. Installation of the shelters on the modules will be by the module contractor One MCC/substation shelter will be required on the new CO2 Capture Plot for the compressor area. This will be an elevated skid-mounted structure. Design, construction details, supply and assembly of the shelter will be by the module contractor.

13.7. Painting & Fireproofing

Structural steel will be unpainted to be consistent with the remainder of the site.

No fireproofing will be provided due to the very limited quantities of liquid hydrocarbons in the new construction areas.



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14. MECHANICAL

14.1. General

Mechanical Equipment Design is based on applicable Codes and Standards and Shell Specifications updated for the Quest CCS Project. Mechanical Design and engineering is based on the Process Data Sheet for each equipment service. Based on the current information available for equipment, all of the equipment is anticipated to be shop fabricated. No field fabrication of equipment is envisaged.

14.2. Equipment Specifics

Based on the Process Equipment identified for the Quest CCS Project, Process equipment can be summarized as follows:

· (20) services of Heat Exchangers covering 31 tags

· (17) services of pumps covering 28 tags

· (1) service of integrally geared type compressor

· (8) services of columns

· (15) services of vessels

· (11) services of packaged equipment

Total seventy four (74) Services of Equipment covering 98 equipment tags. In addition to the list above, there with HVAC equipment for compressor building, Sub-Station and Control Systems building.

Based on the scope defined in the Basic Design Engineering Package Process section, revamp work in HMU areas will be detailed during the EPC phase.

Integrally Geared Compressor is sole sourced from Man Turbo considering the complexity and Man Turbo’s previous experience in manufacturing and supply of such machines for the intended service.

Lean Amine Rich Exchanger being a Compabloc type (i.e. welded Plate and Frame), is single sourced from Alfa Laval. All other equipment is either sourced through Shell Enterprise Frame Agreements or competitively bid.

14.3. Material Selection



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Materials for Quest CCS Project are mainly carbon steel and 304 stainless steel. Material Selection Diagrams define the details and basis for material selection of the capture, regeneration, compression and dehydration facilities. The Material Selection Report is PCAP ID 07-1-MX-8241-0001 Materials Selection Report.

14.4. Sized Equipment List

For Equipment List, refer to the Equipment Lists attached in the Appendices 3A1.3 and A2.3.

14.5. Modularization

In order to support third generation modularization, the following equipment considerations are used:

· Vertical in-line pumps are utilized preferentially

· Vessels are dressed, and pre-installing internals at the shop

· Sizing of heat exchangers to fit within the module transportation envelop

· Packaged equipment is supplied complete with all equipment, piping and electricaldevices, control system hardware, wiring, MCCs, lighting and HVAC (if required).



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15. CO2 CAPTURE AND AMINE REGENERATION

15.1. Unit Overview

CO2 Capture is comprised of a CO2 Absorption section and an Amine Regeneration section.

The CO2 Absorption section consists of three CO2 absorber systems that are located within the Base Plant (HMU 1 and HMU 2) and Expansion 1 (HMU 3) areas. Each absorber system consists of an amine absorber, water wash vessel, water wash pumps and circulating water cooler. The HMU 1 and HMU 2 absorber systems are identical. These absorber systems use lean amine to remove approximately 82% of the CO2 from the raw hydrogen feed gas stream, which is taken from upstream of the PSA units. The absorption process used is the ADIP-X process, which is an MDEA-based process licensed by Shell Global Solutions Inc. (SGSI) that uses piperazine as an accelerant to enhance CO2 absorption at high pressure and low temperature.

The Amine Regeneration section removes the CO2 from rich amine produced in the CO2 Absorption section by applying heat in a low pressure Amine Stripper. Stripped vapour is sent overhead and cooled to remove water, and the CO2 rich vapour is then sent to the CO2 Compression area for compression and further removal of water (see Section 16.0). Lean amine from the bottom of the Amine Stripper is cooled before being sent back to the Amine Absorbers.

15.2. SGSI Licensor Reports

The Basic Design & Engineering Package for the CO2 Absorption and Amine Regeneration systems was prepared by SGSI and is located in Appendix A1.5.

15.3. Unit Specific Design Basis

The design of the CO2 Absorption section is based on achieving a CO2 removal rate from the hydrogen raw gas of 80%. Margin employed by the Licensor sets the unit Heat and Material Balance at a removal rate of 82%. The allowable pressure drop through the CO2 Absorption system, including the absorbers and water wash vessels, is 70 kPa.

The maximum outlet temperature from the water wash vessels of the treated hydrogen raw gas is 35°C. The amine content in the treated gas leaving the water wash vessels must be below 1 ppmw. Rich amine leaving the absorbers has a maximum loading of 0.60 mol CO2/mol amine.

The design of the Amine Regeneration section is based on lean amine provided to the absorbers at a maximum temperature of 30°C and lean loading of 0.03 mol CO2/mol amine. Recovered CO2 gas is sent to CO2 Compression at a temperature of 36°C. absorbers at a maximum temperature of 30°C and lean loading of 0.03 mol CO2/mol amine.absorbers at a maximum temperature of 30°C and lean loading of 0.03 mol CO2/mol amine.

below 1 ppmw. Rich amine leaving the absorbers has a maximum loading of 0.60 mol



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15.3.1. Specific Feedstock Rate and Specifications

The specifications for feedstock to the HMU 1, HMU 2 and HMU 3 absorbers are defined in the following table.

Table 15.1: Feedstock Specifications

Hydrogen Raw Gas to Absorbers

HMU 1 Absorber

#1

HMU 2 Absorber

#2

HMU 3 Absorber

#3

Stream Number 1A 1B 1C

Stream Description

Feed Gas Feed Gas Feed Gas

Temperature °C 35 35 35

Pressure kPa 3057 3057 3097

Molar Rate kmol/h 7106.4 7106.4 10342.8

Mass Rate kg/h 74599 74599 114312

Std. Vol. Rate (1) m3/h 168029.8 168029.8 244554.0

Molecular Weight 10.50 10.50 11.05

Total Stream Composition

H2O mol% 0.18 0.18 0.18

CO2 mol% 16.51 16.51 17.08

CO mol% 2.41 2.41 2.92

N2 mol% 0.30 0.30 0.27

H2 mol% 74.79 74.79 72.38

C1 mol% 5.81 5.81 7.17

Notes: 1. Standard conditions are 15.6°C (60°F) and 101.325 kPaa (1 atm).

15.3.2. Product and Process Specifications

The specifications for the cool treated gas from each of the absorber wash water vessels are defined in the following table.



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Table 15.2: Product Specifications

Stream Description Cool Treated Gas from Wash

Vessels CO2 to

Compression

System

HMU 1 Absorber

#1

HMU 2 Absorbe

r #2

HMU 3 Absorber

#3 Amine

Regeneration

Stream Number 3A 3B 3C 9

Temperature °C 35 35 35 36

Pressure kPag 2894 2894 2934 46

Molar Rate kmol/h

6,136 6,136 8,882 3,551

Mass Rate kg/h 32,206 32,206 50,485 151,293

Std. Vol. Rate (1) m3/h 145,092 145,092 210,010 83,954

Molecular Weight 5.25 5.25 5.68 42.60


H2O mol% 0.20 0.20 0.20 4.30

CO2 mol% 3.44 3.43 3.57 94.97

CO mol% 2.79 2.79 3.40 0.02

N2 mol% 0.35 0.35 0.31 0.00

H2 mol% 86.51 86.51 84.18 0.62

C1 mol% 6.72 6.72 8.33 0.08

DEDA mol% 0.00 0.00 0.00 0.00

MDEA mol% 0.00 0.00 0.00 0.00

Water (as free liquid)

kg/h 0.90 0.90 1.30 7.24

Total Amine ppm

w < 1 < 1 < 1 < 1




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15.3.3. On-Stream Factor

The target overall availability is 90%. Considering the availability of the Upgrader (which is historically about 93%), the reliability required between turnarounds must be greater than 96.8%. The capture and compression reliability has been shown to exceed this number by RAM modelling.

15.3.4. Turndown

The design turndown rate for the CO2 Absorption and Amine Regeneration section is 30%.

15.3.5. Run Lengths

The CO2 Absorption and Amine Regeneration sections are not designed for a specific run length. Amine quality is maintained online so as not to be limiting. Run lengths will generally correspond to the Upgrader run length and applicable inspection and corrosion monitoring requirements.

15.3.6. Maintainability Philosophy

The maintainability philosophy for the CO2 Capture and Amine Regeneration sections is as defined in the Project Class of Facilities Value Improvement Practice Report, Document Number A6GT-R-1016 Rev A. Attachment 2 – Class of Facilities Quality Overview Rev B defines the HMU Area as Class 3, and the CAP Area as Class 1. Refer to Section 2.16 for further details about Class of Facilities and definitions of the HMU and Capture Areas.

15.4. Process Description

CO2 Absorption Section

Amine absorbers located within HMU 1 (Unit 241), HMU 2 (Unit 242) and HMU 3 (Unit 441) treat hydrogen raw gas at high pressure and low temperature to remove CO2 throughintimate contact with a lean amine (ADIP-X) solution consisting of 40% MDEA, 5 %Piperazine (DEDA) and 55% water.

The hydrogen raw gas enters the 25-tray absorbers below tray 1 of the column at a temperature of 35°C and pressure of ~3000 kPag. Lean amine solution enters at the top of the column on flow control at a temperature of 30°C.

The CO2 absorption reaction is exothermic, resulting in the treated gas leaving the top of the absorber at 39°C. The bulk of the heat generated within the absorber is removed through the bottom of the column by the rich amine, which has a temperature of 64°C. Rich Amine from the three absorbers is collected into a common header and sent to the Amine Regeneration section.

X) solution consisting of 40% MDEA, 5 %X) solution consisting of 40% MDEA, 5 %zine (DEDA) and 55% water.

The hydrogen raw gas enters the 25-tray absorbers

the column on flow control at a temperature of 30°C.

the absorber at 39°C. The bulk of the heat generated within the absorber is removed through the bottom of the column by the rich amine, which has a temperature of 64°C.



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Warm treated gas exits the top of the absorbers and enters the 9-tray water wash vessels below tray 1, where a circulating water system is used to cool the treated gas to a temperature of 35°C. Pumps draw warm water from the bottom of the vessel and cool it to 33°C in shell and tube exchangers using cooling water as the cooling medium. The cooled circulating water is returned to the water wash vessel above tray 6 to achieve the treated gas temperature specification. A continuous supply of wash water is supplied to the top of the water wash vessel in the polishing section. The purpose of the water wash is to remove entrained amine to less than 1 ppmw, and thus protect the downstream PSA unit adsorbent from contamination.

A continuous purge of circulating water, approximately equal to the wash water flow, is sent from HMU 1 and HMU 2 to the reflux drum in the Amine Regeneration section for use as makeup water to the amine system. The purge of circulating water from HMU 3 is sent to the existing Process Steam Condensate Separator, V-44111.

Amine Regeneration Section

Rich amine from the three absorbers is heated in the Lean/Rich Exchangers by cross-exchange with hot lean amine from the bottom of the Amine Stripper. The Lean/Rich Exchangers are Compabloc design to minimize plot requirements. The hot rich amine is maintained at high pressure through the lean/rich exchangers by a back pressure controller, which minimizes two-phase flow in the line. The pressure is let down across the2 x 50% back pressure control valves and fed to the Amine Stripper.

The two-phase feed to the Amine Stripper enters the column through two Schoepentoeter inlet devices, which facilitate the initial separation of vapour from liquid. As the rich amine flows down the trays of the Stripper, it comes into contact with hot stripping steam, which causes desorption of the CO2 from the amine.

The Amine Stripper is equipped with 2 x 50% kettle reboilers that supply the heat required for desorption of CO2, as well as producing the stripping steam required to reduce the CO2 partial pressure. The low pressure steam supplied to the reboilers is controlled by a feed-forward flow signal from the rich amine stream entering the stripper, and is trim-controlled by a temperature signal from the overhead vapour leaving the stripper.

The CO2 stripped from the amine solution leaves the top of the Amine Stripper saturated with water vapour at a pressure of 54 kPag. This stream is then cooled by the Overhead Condenser to a temperature of 36°C. The two-phase stream leaving the condenser enters the Reflux Drum, where separation of CO2 vapour from liquid occurs.

In addition to the vapour/liquid stream from the Overhead Condenser, the Reflux Drum also receives purge water from the HMU 1 and HMU 2 Water Wash Vessels, as well as knockout water from the CO2 Compression area. The Reflux Pumps draw water from the

Warm treated gas exits the top of the absorbers and enters the 9-

two Schoepentoeter

temperature of 35°C. Pumps draw warm water from the bottom of the vessel and cool it to33°C in

Condenser to a temperature of 36°C. The two



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drum and provide reflux to the Stripper for cooling and wash of entrained amine from the vapour. Column reflux is on flow control, with drum level control managed by purging excess water to wastewater treatment.

CO2 is stripped from the rich amine to produce lean amine to a specification of 0.03 mol CO2/mol amine by kettle-type reboilers and collected in the bottom of the Amine Stripper. Hot lean amine from the bottom of the Stripper is pumped by the Lean Amine Pumps to the Lean/Rich Exchanger, where it is cooled by cross-exchange with the incoming rich amine feed from the HMU Absorbers. The lean amine is then further cooled to 50°C by the Lean Amine Coolers, which use 25°C cooling water in shell and tube exchangers. The lean amine is then cooled to the final temperature of 30°C by the Lean Amine Trim Coolers, which are Plate and Frame exchangers using cooling water supplied at 25°C.

A slipstream of 25% of the cooled lean amine flow is filtered to remove particulates from the amine. A second slipstream of 5% of the filtered amine is then further filtered through a carbon bed to remove degradation products. A final particulate filter is used for polishing of the amine and removal of any carbon fines from the carbon bed filter.

The filtered amine is then pumped by the Lean Amine Charge Pumps to the three Amine Absorbers in HMU 1, HMU 2 and HMU 3.

Anti-Foam Injection

An anti-foam injection package is provided to supply anti-foam to the Amine Absorbers and Amine Stripper. Since there are no hydrocarbons present in the system and the service is considered clean, it is anticipated that foaming issues should be minimal. Should the need arise, anti-foam can be injected into the lean amine lines going to each of the Absorbers, as well as the rich amine line supplying the Amine Stripper.

The anti-foam chemical currently identified for use in this system is Polyglycol-based anti-foam. The actual anti-foam injection chemical required cannot be confirmed until the facility is operating.

Amine Storage

Two amine storage Tanks along with an Amine Make-up Pump are provided to supply pre-formulated concentrated amine as make-up to the system during normal operation. The concentrated amine will be blended off-site and provided by an amine supplier. The amine concentration for the initial fill at start-up will be based on 40 wt% MDEA and 5 wt% DEDA. During normal operation, losses of DEDA will exceed losses of MDEA, so the makeup amine concentration will be slightly different in order to maintain the overall concentrations at the design values. Refer to the chemical the summary in appendix A1.9 for the annual make up rate.

to a specification of 0.03 mol

A slipstream of 25% of the cooled lean amine flow isthe amine. A second slipstream of 5% of the filtered amine is then further filtered through a

up will be based on 40 wt% MDEA and 5 wt%up will be based on 40 wt% MDEA and 5 wt%

50°C by the

amine is then cooled to the final temperature of 30°C by the Lean Amine Trim Coolers,



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The Amine Storage Tanks will also be used for storage of lean amine solution during maintenance outages. The Amine Storage Tanks sizing basis is to provide storage volume for the Amine Stripper contents during an unplanned outage. Permanent amine solution storage is not provided for the entire amine inventory, which would require supplemental temporary storage. For major T/A, when the entire system needs to be deinventoried a temporary tank will be required for the duration of the T/A. The amine system can be recharged with the lean amine solution using the Amine Inventory Pump. This pump will also be used to charge the system during start-up.

The Amine Storage Tanks are equipped with a steam coil to maintain the tank contents at 40°C. A nitrogen blanketing system is provided to maintain an inert atmosphere in the tank, which will prevent degradation of the amine. The storage tanks will be vented to atmosphere.

15.5. Key Operating Parameters

The following are key operating parameters for the CO2 Absorption Section and Amine Regeneration Section.

CO2 Absorption Section

ADIP-X Amine Solution Composition: 40 wt% MDEA 5 wt % DEDA (Piperazine)

55 wt% Water Treated Hydrogen Raw Gas temperature 35°C Amine content of Treated Hydrogen Raw Gas < 1 ppmw Maximum allowable system pressure drop 70 kPa Target Rich Amine loading 0.6 mol CO2/mol Amine

Amine Regeneration Section

Lean Amine supply temperature 30°C Lean Amine loading 0.03 mol CO2/mol Amine CO2 Gas to Compression temperature 36°C

15.6. Process Flow Diagrams

Process Flow Diagrams for the CO2 Capture and Amine Regeneration sections are located in Appendix A1.1. The following list identifies the relevant PFDs.

Drawing Number Drawing Name 241.0001.000.040.005 Rev 0B HMU 1 Absorber

40 wt% MDEA5 wt % DEDA (Piperazine)

55 wt% Water

0.6 mol

0.03 mol CO2/mol Amine30°C



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242.0001.000.040.006 Rev 0B HMU 2 Absorber 441.0001.000.040.005 Rev 0B HMU 3 Absorber 246.0001.000.040.001 Rev 0B Amine Stripper System 246.0001.000.040.002 Rev 0B Amine Filtration 246.0001.000.040.003 Rev 0B Amine Storage and Drain Collection

15.7. Heat and Material Balances in Appendices

The Heat and Material Balance for the CO2 Capture and Amine Regeneration sections is located in Appendix A1.3.

Drawing Number Drawing Name 245.0001.000.046.001 Rev 0B Heat and Material Balance


The sized equipment list is located in Appendix A1.4.

15.9. Utility Summary and Conditions

The Utility Summary for the CO2 Capture and Amine Regeneration sections is located in Appendix A1.7, Overall Utility Summaries.

15.10. Battery Limit Stream Summary

The Battery Limit Stream Summary for the CO2 Capture and Amine Regeneration sections is located in Appendix A1.8.

15.11. Relief Load Summary

Preliminary safeguarding evaluations identified the potential relief scenarios and evaluate the general magnitude of the potential release. The results of the evaluation are summarized below of the CO2 Capture and Amine Regeneration areas. Refer to the preliminary Safeguarding Manual, document number 246.0008.000.026.001, for the relief load summary.



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Table 15.3: Relief Scenarios for CO2 Capture Area

Relief Valve

Equipment Relief Case Type of Release

Destination

RV-241023 Absorber #1 V-24118,

Vapour Outlet Fire Raw H2 Gas Flare

RV-441023 Absorber #3 V-44118,


RV-441023 Absorber #3 V-44118,


Table 15.4: Relief Scenarios for Amine Regeneration Area

Relief Valve


Destination

RV-246001 Lean / Rich Amine Exchanger

E-24602A/B Cold side outlet

(Rich Amine)

Control Valve

Failure Rich Amine

(liquid)

Amine Stripper inlet

device (downstream of

PV-246010A/B)

RV-246002 Lean Amine Cooling Train

“A”, E-24602A, E-246004A,

E-246005A

Fire H2O + Amine Amine Drain Drum

RV-246003 Lean Amine Cooling Train

“B”, E-24602B, E-246004B,

E-246005B

Fire H2O + Amine Amine Drain Drum

RV-246005 Amine Stripper, V-24601,

Vapour outlet Cooling Water

Failure, power

failure (partial

and full), blocked

vapour outlet,

fire,

Vapour

breakthrough

CO2 + H2O

CO2+H2+CH4

To atmosphere at a safe

location

RV-246011 Stripper Reboiler Condensate

Pot, V-24603B Fire Steam To atmosphere at a safe

location

RV-246013 Stripper Reflux Drum, V- Vapour CO2+H2+CH4 To atmosphere at a safe



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Relief Valve


Destination

24602 Breakthrough,

Fire

H2O + CO2 location

RV-246020 Lean Amine Filter, V-24604 Fire H2O + Lean

Amine To Amine Drain Drum

RV-246021 Lean Amine Carbon Filter, V-

24608 Fire Amine To Amine Drain Drum

RV-246025 Amine Drain Drum, V-24606 Vapour

breakthrough Nitrogen To atmosphere at a safe

location

RV-246026 Drained Amine Filter, V-

24605 Fire H2O + Lean

Amine To Amine Drain Drum

RV-246031 Demin Water Supply Pump

Discharge, P-24610A/B

Blocked

discharge

Demin Water To grade

RV-246033 Condensate Flash Drum, V-

24507

Vapour

Breakthrough HP Steam

Nitrogen


location

RV-246034 Amine Drain Nitrogen, V-

24606

PCV Failure Nitrogen To atmosphere at a safe

location

RV-246046 Amine Make-up Tank, Tk-

24601

PCV Failure Nitrogen

PVSV-246047 Amine Make-Up Tank, Tk-

24601

Fire, blocked

vapour outlet,

Steam failure,

tube rupture

Nitrogen, water

or amine


location

15.12. Special Process Engineering Considerations

Special process engineering considerations in the CO2 Capture and Amine Regeneration areas relate primarily to changes that have been made to the SGSI licensor Basis Design Package. These changes have been previously discussed in Section 15.2.

15.13. Chemicals

The chemicals used in the CO2 Capture and Amine Regeneration sections of the facility are MDEA, DEDA, Polyglycol anti-foam agent and activated carbon. Material Safety Datasheets for these chemicals can be found in Appendix A1.5 in the SGSI Basis Design



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Package document. A chemical summary identifying quantities of these chemicals is included in Appendix A1.9.



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16. COMPRESSOR AND DEHYDRATION (UNIT 247/248)

16.1. Unit Overview

The purified CO2 stream from the Stripper Reflux Drum is compressed to a supercritical state, at 14,790 kPag with an electric driven integrally geared (IG) centrifugal compressor. Water is removed from the CO2 in a triethylene glycol (TEG) based Dehydration Unit. The supercritical CO2 from the compressor discharge is cooled and transported via pipeline off-site to the sequestration wells.

16.2. Vendor Package

The compressor basic design information is based on information provided by Man Diesel & Turbo (MDT) and Siemens.

The project has elected to design the TEG Dehydration Unit by Fluor with the guidance of Shell gas dehydration expertise and standards. The TEG Regeneration Package comprising of the TEG stripper, reboiler, condenser, and surge drum is to be vendor furnished with the required performance guarantees to achieve product spec.


The design of the CO2 Compressor is based on compressing the CO2 recovered from the CO2 Capture and Amine Regeneration sections from 38 kPag to 14,790 kPag. The discharge pressure is set in accordance with the pipeline and well requirements at initial start-up and for future operation, and is at the functional operating limits of the 900# carbon steel pipeline (at 60°C). During normal operation, after the wells are conditioned, the operating pressure will be reduced to 12,000 kPag, to reduce power consumption. Based on an average interstage compression ratio of approximately 2, it is anticipated that an 8-stage IG centrifugal compression system is required. The power requirement is approximately 16.5 MW for the compressor.

The design of the Dehydration Unit is to reduce the presence of water in the CO2 to 6 lb / MMSCF using TEG. The water-rich TEG is regenerated using a combination of reboiler with low temperature high pressure steam as the heating medium and nitrogen stripping to restore the TEG concentration to above 99 wt%. The dehydration unit is installed after the 6th stage of compression to take advantage of the natural water saturation properties of CO2 at 5000 kPaa.


Refer to Table 15.2 in Section 15.3.2 for the flow rates and properties of the CO2 from the Amine Regeneration unit.



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The specifications for the supercritical CO2 are identified in Tables 16.1 and 16.2.

Table 16.1: CO2 Specifications CO2 Concentration 95 vol% (minimum) H2O Content 6 lb / MMSCF

(maximum, Note 1) Hydrocarbon Content 5 vol% (maximum)

Note 1: Water content specification is a maximum of 6 lb per MMSCF during the summer months and a maximum of 4 lb per MMSCF during the required periods of the remaining seasons with ambient temperatures up to approximately 20°C. .

Table 16.2: CO2 Properties

Stream Description CO2 to Pipeline

Stream Number 56

Temperature °C 43

Pressure kPag 9000

Molar Rate kmol/h 3397

Mass Rate kg/h 148496

Standard Volume Rate m3/hr 80330

Molecular Weight 43.71


H2O mol% 0.01 %

CO2 mol% 99.23 %

CO mol% 0.02 %

N2 mol% 0.00 %

H2 mol% 0.65 %

CH4 mol% 0.09 %




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The target overall availability is 90%. Considering the availability of the Upgrader (which is historically about 93%), the reliability required between turnarounds must be greater than 96.8%. The compression reliability has been shown to exceed this number by RAM modelling.

16.3.4. Turndown

The design turndown rate for the CO2 Compressor and Dehydration Units is 30%.

16.3.5. Run Lengths

The CO2 Compression and Dehydration Units are not designed for a specific run length. Run lengths will generally correspond to the Upgrader utility run length and applicable inspection and corrosion monitoring requirements.


The maintainability philosophy for the CO2 Capture Facilities, including Compression and Dehydration, is as defined in the Project Class of Facilities Value Improvement Practice Report, Document Number A6GT-R-1016 Rev A. Attachment 2 – Class of Facilities Quality Overview Rev B defines the Compressor and Dehydration Units as Class 1. Refer to Section 2.16 for further details about Class of Facilities and definitions of the HMU and CAP Areas.


16.4.1. Compression

The CO2 from Amine Regeneration is routed to the compressor suction, via the Compressor Suction KO Drum to remove any free water. The CO2 Compressor is an eight stage integrally geared centrifugal machine. Further details of compressor performance will be developed through collaboration with the selected vendor and integrated with the control requirements of the pipeline system. Increase in H2 impurity from 0.67% to 5% in CO2 increases the minimum discharge pressure required (to keep CO2 in supercritical condition) to about 8500 kpag. Though, the compressor design is still under development, per current information available from the compressor vendors, H2 impurity >5% may, lead to potential surge situations. In view of this to avoid this situation it is proposed to put compressor in recycle mode when the H2 goes upto 2.5%. Cooling and separation facilities are provided on the discharge of the first five compressor stages. The condensed water streams from the interstage KO drums are routed back to the Stripper Reflux Drum to be degassed and recycled as make up water to the amine system. The condensed water from the Compressor 5th and 6th Stage KO Drums and the TEG Inlet



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Scrubber are routed to the Compressor 4th stage KO Drum. This routing reduces the potential of a high pressure vapour breakthrough on the Stripper Reflux Drum and minimizes the resulting pressure drops. The 7th Stage KO Drum liquids are routed to the TEG Flash Drum due to the likely presence of TEG in the stream.

The saturated water content of CO2 at 36°C approaches a minimum at approximately 5000 kPaa. Consequently, an interstage pressure in the 5000 kPaa range is specified for the compressor. This pressure is expected to be obtained at the compressor 6th Stage Discharge. At this pressure, the wet CO2 is air cooled to 36°C and dehydrated by triethylene glycol (TEG) in a packed bed contactor.

The dehydrated CO2 is compressed to a discharge pressure in the range of 8, 000-11,000 kPag resulting in a dense phase fluid (supercritical). The CO2 Compressor is able to provide a discharge pressure as high as 14,790 kPa at a reduced flow for start-up and other operating scenarios. The supercritical CO2 is cooled in the Compressor Aftercooler to 43°C, and routed to the CO2 Pipeline. This dense phase CO2 is transported by pipeline from the Scotford Upgrader to the injection locations which are located up to approximately 81 kilometres from the Upgrader.

16.4.2. Dehydration

A lean triethylene glycol (TEG) stream at a concentration greater than 99 wt% TEG contacts the wet CO2 stream in an absorption column to absorb water from the CO2 stream. The water rich TEG from the contactor is heated and letdown to a flash drum which operates at approximately 270 kPag. This pressure allows the flashed portion of dissolved CO2 from the rich TEG to be recycled to the Compressor Suction KO Drum.

The flashed TEG is further preheated and the water is stripped in the TEG Stripper. The column employs a combination of reboiling, via a stab-in reboiler using low temperature HP Steam, and nitrogen stripping gas to purify the TEG stream. Nitrogen stripping gas is required to achieve the TEG purity required for the desired CO2 dehydration, as the maximum TEG temperature is limited to 204°C to prevent TEG decomposition. Stripped water, nitrogen and degassed CO2 are vented to atmosphere at a safe location above the TEG Stripper.

Though, the system is designed to minimize TEG carryover, it is estimated that 27 PPMW of TEG will escape with CO2. The dehydrated CO2 is analysed for moisture and composition at the outlet of TEG unit.

The lean TEG is cooled in a Lean / Rich TEG Exchanger. The lean TEG is then pumped and further cooled to 39 °C in the Lean TEG Cooler with cooling water and returned to the TEG Absorber.



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The following are key operating parameters for the CO2 Compression and Dehydration Units.

CO2 Compression

Compressor Discharge Pressure: 8,000 - 11,000 kPag (Note 1) Note 1: The CO2 Compressor is able to provide a discharge pressure as high as 14,790 kPa at a reduced flow for start-up and other operating scenarios.

Cooler Outlet Temperatures: 42°C (water cooled services) 36°C (air cooled services)

Pipeline CO2 Temperature: 43°C

CO2 Dehydration

Product CO2 H2O Content 6 lb / MMSCF (Note 2)

Note 2: Water content specification is a maximum of 6 lb per MMSCF during the summer months and a maximum of 4 lb per MMSCF during the required periods of the remaining seasons with ambient temperatures up to approximately 20°C.

CO2 Inlet Pressure 3800 to 5200 kPag Lean TEG Loading >99 wt% TEG


Process Flow Diagrams for the CO2 Compressor and Dehydration Units are located in Appendix A1.1. The following list identifies the relevant PFDs.

Drawing Number Drawing Name 247.0001.000.040.001 Rev 0B CO2 Compression 247.0001.000.040.002 Rev 0B CO2 Compression 247.0001.000.040.003 Rev 0B CO2 Metering Station and Pig Launcher 248.0001.000.040.001 Rev 0B CO2 Dehydration

16.7. Heat and Material Balances

The Heat and Material Balance for the CO2 Compressor and Dehydration Units is located in Appendix A1.3.



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Drawing Number Drawing Name 245.0001.000.046.001 Rev 0B Heat and Material Balance


The sized equipment list is located in Appendix A1.4.


The Utility Summary for the CO2 Compressor and Dehydration Units is located in Appendix A1.7, Overall Utility Summaries.

16.10. Battery Limit Stream Summary

The Battery Limit Stream Summary for the CO2 Compressor and Dehydration Units is located in Appendix A1.8.


A preliminary safeguarding evaluation was undertaken to identify the potential relief scenarios and evaluate the general magnitude of the potential release. The results of the evaluation are summarized below for the CO2 Compressor Units. Refer to the preliminary Safeguarding Manual, document number 246.0008.000.026.001, for the relief load summary.

Table 16.3: CO2 Properties

Relief Valve Equipment Relief Case Type of Release

Destination

(Magnitude of release)

RV-247004 3rd Stage Compressor KO

Drum, V-24703 Fire H2O, CO2 To atmosphere at a safe

location

RV-247006 4th Stage Compressor KO

Drum, V-24704 Vapour

Breakthrough,

Fire

H2O, CO2 To atmosphere at a safe

location



location



location



location



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Relief Valve Equipment Relief Case Type of Release

Destination

(Magnitude of release)

RV-248003/5 Lean TEG Pumps, P-

24601A/B Blocked outlet TEG Grade

RV-248006 Make-Up TEG Pumps, P-

24602 Blocked outlet TEG Grade

RV-248007 Lean TEG Filter, V-248004A Fire H2O To atmosphere at a safe

location

RV-248008 Lean TEG Filter, V-248004B Fire H2O To atmosphere at a safe

location

RV-248009 Lean TEG Carbon Filter, V-

248007 Fire H2O To atmosphere at a safe

location

16.12. Special Process Engineering Considerations

Section 2.4, CO2 Specific Design Philosophy / Guidelines for Quest details various design considerations that apply for the CO2 Compressor Unit, including Venting and Relief of CO2 Vapour, Supercritical CO2 Venting, High Pressure CO2 Equipment, and CO2 BLEVE as well as low temperature due to CO2 flashing.

In addition, compressor anti-surge protection through spill-back control is necessary to protect the compressor. This system, in addition to the guide vanes, can be used to achieve greater turndowns; however, the system will need to account for auto-refrigeration of CO2. To prevent dry-ice formation, dense phase CO2 is letdown at high enthalpy. The spill-back details will be further developed with the vendor during Execute Phases of the project.

Properties for the CO2 streams have been modeled using Peng-Robinson correlations for the compressor and TEG absorption. The final CO2 properties used for design will be coordinated with the compressor vendor and pipeline to ensure consistency and agreement for CO2 properties in the final design.

16.13. Chemicals

The chemical used to dehydrate the CO2 is Triethylene Glycol (TEG). A chemical summary identifying quantities of these chemicals is included in Appendix A1.9



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17. REVAMP OF HYDROGEN MANUFACTURING UNITS(UNITS 241, 242 & 441)

17.1. Unit Overview

Shell Canada currently operates two identical steam methane reforming based Hydrogen Manufacturing Units (HMU), HMU 1 and 2 (Unit 241 and 242), and is currently in the process of commissioning a third HMU (HMU3 -Unit 441) which is part of the Scotford Upgrader Expansion Project. As part of the Quest CCS Project, raw hydrogen gas from the process condensate separators is sent to the new amine absorbers (refer to Section 16) which are designed to remove 80% of the CO2 from the stream. The treated gas is returned to the existing HMUs upstream of the PSA Units.

As a result of CO2 capture, the composition of the PSA tail gas, which is used as fuel in the Steam Reformer furnace, changes significantly. The CO2 in the tail gas acts as a heat carrier in the convection section of the reformer. Flue gas recirculation (FGR) is implemented to reduce the NOX formation in the reformer furnace with the fuel composition.

Major changes to HMU 1 and 2 as a result of implementing CO2 capture include:

· Install new FGR Fan, C-24103 and C-24203, and control.

· Install new ducting and damper to connect the discharge of the Flue Gas (InducedDraft) fans, C-24102 and C-24202, to the FGR fan suction.

· Install new ducting to connect the discharge of FGR Fan with the combustion airfan discharge.

· Replace all burners in the Steam Methane Reformers, H-24101 and H-24201, withLanemark Low NOX burners.

· Replace the adsorbent in the Pressure Swing Adsorbers (PSAs) - 10 Vessels ineach of the PSA units.

· Modifications to the Base Plant PSA control logic.

· Modify the tail gas control and combustion air controls to account for operationand switching between lean / rich CO2 taking into account: the effects of CO2capture on the composition of the PSA offgas and the addition of flue gasrecirculation.

Major changes to HMU 3 as a result of implementing CO2 capture include:

· Install new FGR Fan, C-44105, and control.

· Install new ducting and damper to connect the discharge of the Flue Gas (InducedDraft) fan, C-44102 to the FGR fan suction.



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· Install new ducting to connect the discharge of the FGR Fan with the combustionair fan discharge.

· Replace all burners in the Steam Methane Reformer, H-44101 with Lanemark LowNOX burners.

· Modifications to PSA control logic to be determined by UOP (PSA licensor).

· Modify tail gas control and combustion air controls to account for operation andswitching between lean / rich CO2 taking into account: the effects of CO2capture on the composition of the PSA offgas and the addition of flue gasrecirculation.

17.2. Vendor (Uhde) Package

The design basis for the revamps to the HMUs is the following Uhde documents:

· Basis of Design (2008)

· CO2-Capture Study 2009

· Basis of Design 2010 “Flue gas recycle and CO2 removal” – UD-VT-EC-00012

· Detailed Pressure Drop Study for Flue Gas Recycle and CO2 Removal – UD-VT-EC-00013 Rev 1.

· Update heat and material balances and fan specifications in August 2011.

Each of the subsequent documents builds on the 2008 Basis of Design and does not supersede the prior documents. The write-up below is to summarize the basis of design for the modifications to HMUs 1 and 2 as part of the Quest CCS Project.

The Uhde documents are attached in Appendix A2.4.


Operating Modes

In order to prevent shutdowns to the Upgrader due to an upset within the Quest units, the HMUs must be capable of switching between CO2 rich (Case 2 for HMU 1 & 2, Check Case V rev 2 for HMU 3) and CO2 lean operation (Case 24 for HMU 1 & 2, Case 21 for HMU 3), and visa versa, without interruption to the hydrogen supply or quality from the HMU. Refer to Section 9 in the Basis of Design (2008). The HMUs must also be able to continue to operate through transients caused by a trip of the new FGR Fan.

Process Tie in Location



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The process supply and return for the amine absorbers is located downstream of the process condensate separator (V-241/24206, V-44106). Specifically, they are located downstream of the PSA shutdown valve (XV-241/242379, XV-441379) and upstream of the PSA isolation valves. A vent to flare is included in the design of the CO2 Capture area, which allows purging of the system during start up. Therefore, the preferred tie-in location is downstream of the vent to flare to prevent the RVs on the Process Condensate Separators from lifting in the event of valve misalignment to/from the amine absorbers.

The tie-in location is a deviation from the licensor package, which located the tie-in connection upstream of the nitrogen circulation return branch, subsequently, the tie-in would have been located upstream of the vent to flare. Due to the new vent line to flare in the CO2 Capture area, the tie-ins do not have to be upstream of the nitrogen recirculation connection.

Flue Gas Recycle

Flue Gas Recycle is employed to offset the loss of CO2 in the PSA tail gas. The CO2 contained in the tail gas, acts as a heat absorbent in the reformer furnace, and helps reduce the NOx production by reducing the temperature in the firebox.

UHDE, the HMU licensor, had proposed recycling a portion of the flue gas from the outlet of the existing Induced Draft Flue Gas (ID) Fan to the inlet of the Forced Draft Combustion Air (CA) Fan (refer to Section 4 in the Design Basis 2010 for further details regarding the implementation of FGR). However, this option increased the flow of gas through the CA Fan, and resulted in modifications to the fan motor and rotor (HMU1/2 required a complete modification to the CA fan). Additionally, the air intake structures needed to be relocated to provide adequate spacing for the FGR tie-in in HMU 1/2.

These modifications resulted in construction schedule risks which could extend the turnaround schedule. As a means to mitigate risk, a new FGR fan is employed to blow the flue gas into the combustion air stream, downstream of the FD Fan discharge (refer to project decision note A6GT-DN-1057).

FGR Fan

Due to the implementation of flue gas recycle, a new fan is required to blow the recycled flue gas into the combustion air downstream of the combustion air fans (FD) discharge.

For HMUs 1 and 2 the FGR fan discharge ties into the combustion air fan discharge upstream of the preheater (E-24117, E-24217); for HMU 3, the FGR fan discharge ties into the combustion air duct downstream of Combustion Air Heater I, E-44117.

Flue Gas Recycle and Combustion Control Modifications



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The control scheme developed in FEED phase is significantly different from the preliminary control scheme by Shell and issued as back-up to DN-CO2 Capture-GEN-0028. The control scheme is based on the following:

· Combustion air automatically controlled by cascade control of excess oxygen inthe reformer flue gas onto the flow of combustion air

· The FGR fans motor speed is controlled by a VFD based on control of the totalreformer convection section flow for a given load.

· To mitigate the transient effects due to changes in Quest operation a feedforwardsignal will be sent to the FGR fan VFD based on the amount of CO2 captured.

The scheme for FGR and combustion control will be further developed and tested using transient and dynamic analysis during Execute Phase.

NOX Control

The removal of the CO2 from the PSA tailgas results in higher temperatures in the combustion zone with the existing configuration, which in turn results in higher NOX

emissions. FGR provides a means to absorb heat, thus reducing the combustion zone temperature. Other means of reducing NOX are burner modifications and selective reduction reactions.

Burner Modifications

As part of the NOX mitigation measures, the existing Lanemark burners in the HMUs are being replaced with low NOX burners. Based on burner test results, the existing burners will be replaced with new Low NOx Lanemark burners.

Refer to Section 4.2 of the Design basis 2010.

SCR and SNCR

Both selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) were investigated; refer to Section 4.6 of the Design Basis 2010. SCR is not feasible because of the temperature profile and tube configuration of the reformer furnace, which is not compatible with the temperature and spacing requirements for SCR.

With the implementation of FGR and low NOX burners, NOX emission targets can be met without SNCR. Refer to Project Decision Note DN-CO2 Capture-GEN-0028 for further details.

PSA Modifications



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Air products, the PSA licensor for HMU1/2, was approached during the 2008 Design Basis to determine the limitations of the PSAs with respect to the implementation of the CO2 Capture Project. As a result of the modified composition of the H2 Raw Gas from the CO2 Capture Unit, Air Products recommends that the absorbent in the PSA beds be changed. Refer to Section 7.6 of the Design Basis 2008 for further details. Air Products will complete a study during Execute Phase to finalize the adsorbent requirements and determine if further modifications are required to meet the Design Basis (2010).

UOP, the PSA licensor for HMU3, was approached during the 2008 and 2009 Design Basis phases to determine the limitations of the HMU3 PSA with respect to the implementation of the CO2 Capture facilities. UOP confirmed that no modifications to the absorbent in the PSA beds and the valve skid are required as a result of the modified feed composition to the PSA unit. Refer to Section 4.5 in the Design Basis 2010 for further details.


There is no impact to the primary feedstock to the reformer section of the HMUs as a result of Quest. For HMU 1 and 2, the feedstock for Case 24 is defined Section 1.1 of the Basis of Design (2008) and differs from the base case (Case 2); however, this in not as a result of the Quest CCS Project. For HMU 3, the feedstock for Case 21 is defined Section 1.2 of the Basis of Design (2008) and is consistent with the base case (Check Case V rev 2).

The Quest CCS Project removes the CO2 from the Raw Hydrogen Gas and feeds the PSA. The specifications for this product are identified in Tables 2.3 and 2.4. This closely matches with Stream 19 and 56 for HMUs 1/2 and HMU 3 respectively) in the Uhde heat and material balance, supplied in August 2011.

Table 17.1: H2 Raw Gas Specifications Temperature (°C) 35 °C (maximum, operating) CO2 Capture Pressure drop 70 kPa (maximum) Amine Carry-Over 1 ppmw (maximum)

The hydrogen raw gas return from the amine absorber is shown in Section 15.3.2 and closely matches with Steam 19a and 19 (for HMUs 1/2 and HMU 3 respectively) in the Uhde heat and material balance, supplied in August 2011.


The hydrogen product specification remains the constant during both CO2 rich and CO2 Lean operation; refer to Section 2.5.1.1 in the CO2-Capture Study 2009.

The hydrogen production rate and quality for both operating scenarios remain the same as represented in the Design Basis 2010 heat and material balances.



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The HP steam export specification remains the same whether or not the CO2 absorber is operating; refer to Section 2.5.2.2 in the CO2-Capture Study 2009. There is a net increase in steam consumption of 7 t/h in HMU 1 and 2 and net increase of 3 t/h in HMU 3. The net steam consumption takes into account the IP steam import and the HP steam export from each of the HMUs.

The properties of the hydrogen raw gas from the Process Condensate Separator are displayed in Table 15.1. The stream information matches closely with stream 19 and 56 (for HMUs 1/2 and HMU 3 respectively) in the Design Basis 2010 heat and material balance.


The implementation of CO2 capture must not affect the availability of the HMUs; therefore, on-stream factor of the HMUs is not be affected by the Quest CCS Project. A bypass valve allows bypassing of the amine absorber if it is offline.

17.3.4. Turndown

The turndown of HMUs 1, 2 and 3 are 30% and are unaffected by the Quest CCS Project. CO2 capture is intended to operate while the HMU is in turndown mode and may remove up to 100% of the CO2 when limited hydrogen raw gas is available. Refer to Section 2.4.1 of the 2009 study for additional details.

Air Products has confirmed the PSA will operate at 30% turndown, but will complete a study in the Execute Phase to assess any impacts. The PSA is expected to operate at 30% turndown but the recovery may be impacted.

UOP has confirmed the PSA will operate at 30% turndown without any modifications, but the hydrogen recovery will be reduced (See Section 4.5 in Design Basis 2010).

17.3.5. Run Lengths

The run lengths of the HMUs will not be affected by the Quest CCS Project.


The maintainability philosophy for the CO2 Capture Facilities, including Compression and Dehydration, is as defined in the Project Class of Facilities Value Improvement Practice Report, Document Number A6GT-R-1016 Rev A. Attachment 2 – Class of Facilities Quality Overview Rev B defines the HMU Area as Class 3. Refer to Section 2.18 for further details about Class of Facilities and definitions of the HMU and CAP Areas.




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The process description is limited to the changes that are being made as a result of the CO2 Capture project.

A description of the general impact of CO2 removal on a HMU is provided in Section 3.1 of the Design Basis 2010.

Section 3 in the CO2-Capture Study 2009 contains a description of flue gas recirculation.

17.5. Yield Estimates and Key Operating Parameters (if applicable)

There is a minor effect on the yield of the HMUs as a result of the Quest CCS Project. When the absorbers are operating, approximately 0.3% of the hydrogen is absorbed with the CO2. Additionally, the hydrogen recovery from the PSAs during CO2 capture operation may be affected and will be confirmed by Air Products during Execute phase. For HMU 3, UOP has confirmed that there is no effect on hydrogen recovery in the PSA, when it is operating above 50% turndown.

Overall hydrogen capacity of the existing HMUs will be reduced by about 2%, but the Reformer capacity is increased by 1%. No change in the PSA is envisioned to maintain the ability to switch between CO2 lean and CO2 rich operations apart from a control signal to adjust the sequencing/cycle times of the PSAs according to the operating mode. Also, superheated high pressure steam export from HMU 1&2 will be reduced by approximately 5 tons per hour; however Expansion #1 HMU HPS export will remain the same. NOX levels are expected to increase to 140-160 ppmv from the original design of 35 ppmv due to the higher flame temperature but the N2O increase will be minimal. However, Flue Gas Recirculation (FGR) is expected to bring the NOX levels down to their original values. Any loss of CO2 will have to be made up with extra combustion air and an increased forced draft fan capacity.


Process Flow Diagrams for HMU 1/2/3 are located in Appendix A2.1. The following lists identify the relevant PFDs with a brief description of the modifications that have been made as part of the Quest CCS Project.

Drawing Number / Title Description 240.0001.000.040.001 Rev. 2B Chemical Feed Compression

Updated H&MBs

240.0001.000.040.003 Rev. 2A Steam and Condensate

Updated H&MBs Added steam and condensate tie-ins for the amine absorbers

240.0001.000.040.004 Rev. 2A Cooling Water Supply / Return

Added cooling water supply and return tie-ins for amine absorbers

241.0001.000.040.001 Rev. 2B Updated H&MBs



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Drawing Number / Title Description Feed Gas Desulphurization 241.0001.000.040.002 Rev. 2B Steam Reforming

Updated H&MBs Add flue gas recirculation

241.0001.000.040.003 Rev. 2B Co-Conversion Cooling Train

Updated H&MBs Add hydrogen raw gas tie-ins for supply and return to the amine absorber

242.0001.000.040.001 Rev. 2B Feed Gas Desulphurization

Updated H&MBs

242.0001.000.040.002 Rev. 2B Steam Reforming




243.0001.000.040.001 Rev. 2B H2 Purification

Updated H&MBs Added notes regarding modifications to PSA unit

244.0001.000.040.001 Rev. 3B H2 Purification


440.0001.000.040.001 Rev. 3B Feed Intake

Updated H&MBs

440.0001.000.040.002 Rev. 3B Steam and Condensate

Updated H&MBs

440.0001.000.040.004 Rev 2 Relief and Depressuring Flow Diagram

Added Quest pressure control vent and relief valve lines to drawing.

440.0001.000.040.011 Rev. 2B Steam/Condensate/BFW

Added steam and condensate tie-ins for the amine absorbers

441.0001.000.040.001 Rev. 3B Feed Gas Desulphurization

Updated H&MBs


Updated H&MBs Added note for burner modification





443.0001.000.040.001 Rev. 3B HMU – H2 Purification


17.7. Revised Heat and Material Balances

The heat and material balances have been updated by Uhde in August 2011 and are attached in Appendix A2.3. A summary is compiled in the following table:



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Table 17.2: H&MB Summary H&MB Case Description HMU CO2-

Removal Online

FGR Online

Case 2 1/2 No No Case 24 w/FGR 1/2 Yes Yes Case 24 w/FGR 75% TD 1/2 Yes Yes Case 24 w/FGR 50% TD 1/2 Yes Yes Case 24 w/FGR 30% TD 1/2 Yes Yes Check Case V rev 2 No No Case 21 w/FGR Yes Yes Yes Case 21 w/FGR 75% TD Yes Yes Yes Case 21 w/FGR 50% TD Yes Yes Yes Case 21 w/FGR 30% TD Yes Yes Yes

Case 2 represents the original 100% normal operating case for designing HMU 1 and 2. There is no CO2 capture, hydrogen production with additional chemical feed and Dow gas. FGR is offline, and the CO2 rich hydrogen raw gas stream is sent to the PSA.

Case 24 represents the design case for HMU 1 and 2 for CO2 capture. CO2 capture is online, hydrogen production with additional chemical feed and Dow gas. FGR is online, and the CO2 lean hydrogen raw gas stream is sent to the PSA.

The pressure profile is based on the data from the plant survey in 2008 and includes a 70 kPa pressure drop for the amine absorber and wash water vessel. Additional constraints for Case 24 are detailed in section 3.2.2 in the Design Basis 2010.

Check Case V rev 2 represents the original 100% normal operating case for designing HMU 3. There is no CO2 capture, hydrogen production with chemical feed and HP natural gas.FGR is offline, and the CO2 rich hydrogen raw gas stream is sent to the PSA.

Case 21 represents the design case for HMU 3 for CO2 capture. CO2 capture is online, hydrogen production with chemical feed and HP natural gas. FGR is online, and the CO2 lean hydrogen raw gas stream is sent to the PSA. Additional constraints for Case 21 are detailed in section 3.2.1 in the Design Basis 2010.


The sized equipment list is attached in Appendix A1.7.




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The Utility Summary for the HMUs is included in the Overall Utility Summary, Appendix A1.7.

17.10. Revised Catalyst and Chemical Summary

The absorbent in the PSAs for HMU 1 and 2 will be changed. The changes will be defined by Air Products early in the Execute Phase.

There is no change to the catalyst or chemicals in HMU 3 as a result of the Quest CCS Project.


The controlling relief loads of the HMUs are not affected by the Quest CCS Project. The relief loads associated with the amine absorbers will tie-into the existing HMU flare system. The relief valves and scenarios are detailed in Section 15.11.

17.12. Safeguarding Review

The process tie-ins for the hydrogen raw gas to and from the absorbers are located downstream of the process condensate separators (V-241/24206, V-44106), which means that the system is protected by the PSVs on the condensate separators (RV-241/241375A/B, RV-441375A/B). During preliminary reviews of the changes to the HMUs, the relief loads are not expected to change.

There are safeguarding concerns regarding combustion control, specifically maintaining sufficient excess air in the flue gas, due to the implementation of FGR. These concerns will be addressed during the development of the combustion and flue gas control scheme in the Execute Phase.

17.13. Special Process Engineering Considerations (if required)

· HMU Convection Zone pressure study - Uhde is completing a detailed pressuredrop study of the HMU convection section because of the addition of FGR. Theywill also complete pressure analysis of the HMUs to support development of thecontrol scheme and check operating scenarios. (Completed: Refer to Detailed Pressure

Drop Study for Flue Gas Recycle and CO2 Removal – UD-VT-EC-00013)

17.14. Revised Plot Plan

The revised plot plans for HMUs are included in Section 7.



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18. TIE-INS AND INTERCONNECTING LINES

18.1. Piping Tie-in List

The Piping Tie-In List is located in Appendix A3.3 and P&IDs showing Tie-Ins and Quest’s integration with existing plants in the Upgraders are located in Appendix 3.2.

Tie-In scope was provided to Scotford Projects Group (SPG) through the IDS process. SPG developed all of the MOC packages so that construction work packages, material, and installation procedures would be available to the Turnaround and Commissioning group (TAC) for execution. Timing for completion of tie-ins is the responsibility of TAC, and follows the following timing:

· HMU2 tie-ins in 2013 mini turnaround,

· HMU3 and 285 piperack tie-ins in 2014 Expansion 1 turnaround,

· HMU 1 and HMU 1&2 Utility tie-ins in 2015 Upgrader turnaround.

18.2. Electrical Tie-In List

The main electrical tie-ins will be at the main sub 284. Two feeders will be tied in on the B side of the 34.5 kV bus. One feeder will feed the captive transformer and compressor, and the other feeder will feed the balance of the new sequestration plant loads. Tie-ins will also be made at the 600 volt level at the HMU3 electrical substation to feed the loads in the new facilities located there. A tie in to the 600 volt bus in HMU1, HMU2, and HMU3 will be made for the new Blowers being added in each HMU. Details of the above tie ins will be developed early in detailed design to support the schedule.

Numerous other minor tie-ins will be made to existing lighting and heat tracing panels in existing areas where required.

07-1

-AA

-773

9-0

001

R

estr

icte

d

Bas

ic D

esig

n &

En

gin

eeri

ng

Pac

kage

04

Hea

vy O

il

18.3

. In

stru

men

tati

on

Tie

-in

Lis

t

Item

Nu

mb

er

Bri

ef D

escr

ipti

on

of

inte

rface

T

ype

of

syst

em i

nte

rface

D

etail

s o

f in

terf

ace

D

o w

e n

eed

S/

D t

o i

mp

lem

ent

this

tie

in

1

Mo

dif

icat

ion

s to

HM

U 1

/2/

3 fo

r im

ple

men

tin

g n

ew c

on

tro

l sc

hem

e

1.1

F

oxb

oro

DC

S

1)Q

ues

t C

CS P

roje

ct h

as a

num

ber

of

inte

rfac

es w

ith

Sco

tfo

rd U

tilit

ies

syst

em. A

t p

rese

nt

this

is b

ein

g co

ntr

olle

d v

ia F

oxb

oro

DC

S. Q

ues

t C

CS P

roje

ct t

eam

exp

ect

to r

euse

an

d a

dd

ext

ra h

ard

war

e an

d lo

gic

into

exi

stin

g F

oxb

oro

DC

S s

yste

m.

2)Q

ues

t C

CS P

roje

ct e

xpec

t to

ad

d a

lmo

st 1

000

har

d I

/O

's a

nd

500

so

ft I

/O

's in

to e

xist

ing

syst

em lo

adin

g an

d n

ew h

ardw

are

nee

ds

to b

e in

tegr

ated

wit

h e

xist

ing

Fo

xbo

ro s

yste

m.

No

1.2

G

E S

afet

y Sys

tem

T

he

add

itio

n o

f a

Flu

e G

as R

ecir

cula

tio

n F

an in

to t

he

refo

rmer

co

mb

ust

ion

air

sys

tem

will

req

uir

e th

e sh

utd

ow

n f

un

ctio

ns

for

this

equip

men

t to

be

inte

grat

ed in

to t

he

exis

tin

g G

E S

afet

y Sys

tem

to

geth

er w

ith

th

e ex

isti

ng

com

bust

ion

air

an

d f

orc

ed d

raft

fan

s.

Yes

1.3

H

on

eyw

ell D

CS

Ques

t C

CS P

roje

ct w

ill h

ave

num

ber

of

inte

rfac

es w

ith

Exp

ansi

on

1 H

on

eyw

ell D

CS t

o t

ake

adva

nta

ge o

f ex

isti

ng

con

tro

l sc

hem

e

and

mo

dif

y th

em f

or

Ques

t C

CS P

roje

ct n

eed

s. A

s a

resu

lt, th

e Q

ues

t C

CS P

roje

ct e

xpec

ts t

o a

dd

alm

ost

200

har

d I

/O

's a

nd

so

ft

I/O

's in

to e

xist

ing

syst

em lo

adin

g. N

ew h

ard

war

e an

d s

oft

war

e n

eed

s to

in

tegr

ated

wit

h e

xist

ing

Ho

ney

wel

l D

CS s

yste

m

No

1.4

Saf

ety

Man

ager

Saf

ety

Sys

tem

Q

ues

t C

CS P

roje

ct h

as t

he

nee

d f

or

a Saf

ety

Sh

utd

ow

n s

yste

m. A

t th

is s

tage

, th

e p

roje

ct h

as e

stim

ated

fo

r an

in

dep

end

ent

S/

D

syst

em f

or

Ques

t. A

s d

irec

ted

by

Sh

ell,

the

pre

ferr

ed v

end

or

for

the

Ques

t S/

D s

yste

m is

Ho

ney

wel

l.

No

2

Fuel

Gas

Rec

ycle

Co

ntr

ol

2.

1

Fo

xbo

ro D

CS

Q

ues

t C

CS P

roje

ct w

ill h

ave

to m

eet

the

NO

x ta

rget

s an

d e

ffo

rts

are

bee

n p

ut

into

fin

aliz

atio

n o

f F

GR

Co

ntr

ol sc

hem

e an

d

iden

tifi

cati

on

of

typ

e of

Burn

ers.

An

y ch

ange

s w

ill b

e im

ple

men

ted

in

th

e F

oxb

oro

sys

tem

. N

o

2.2

H

MU

Burn

er M

anag

emen

t Sys

tem

At

this

sta

ge, th

e sc

op

e is

no

t ye

t fi

nal

ized

. T

he

FG

R F

an w

ill r

equir

e in

tegr

atio

n in

to t

he

BM

S s

yste

m. H

ow

ever

, th

e sc

op

e w

ith

rega

rd t

o r

e-ce

rtif

icat

ion

of

the

BM

S t

o m

eet

the

requir

emen

ts o

f C

SA

B14

9.3

is u

nkn

ow

n p

end

ing

the

acce

pta

nce

of

reques

ted

cod

e va

riat

ion

s b

y th

e au

tho

rity

hav

ing

juri

sdic

tio

n.

Yes

3

Inte

rfac

e o

f C

o2

com

pre

sso

r vi

bra

tio

n m

on

ito

rin

g sy

stem

3.

1

Ben

tley

-Nev

ada

Sys

tem

1 in

terf

aces

.

Ques

t C

CS P

roje

ct w

ill h

ave

an 8

sta

ge c

om

pre

sso

r an

d m

ach

ine

con

dit

ion

par

amet

ers

(i.e

. V

ibra

tio

ns,

Tem

per

ature

s, k

eyp

has

ors

)

to b

e m

on

ito

red

via

a B

entl

ey-N

evad

a st

and

alo

ne

syst

em. T

his

sys

tem

nee

ds

to b

e in

tegr

ated

wit

h B

ase

pla

nt

B-N

Sys

tem

1 f

or

sin

gle

po

int

mo

nit

ori

ng.

Co

nfi

gura

tio

n o

f Sys

tem

1 is

on

a M

od

bus

Net

wo

rk.

No

4

An

ti-S

urg

e C

on

tro

l Sys

tem

4.

1

Fo

xbo

ro D

CS

Q

ues

t C

CS P

roje

ct w

ill h

ave

anti

-surg

e an

d p

erfo

rman

ce c

on

tro

llers

fo

r co

mp

ress

or

pro

tect

ion

. T

his

will

req

uir

e in

tegr

atio

n in

to

the

Fo

xbo

ro D

CS f

or

info

rmat

ion

exc

han

ge a

nd

co

ntr

ol o

pti

miz

atio

n.

No

5

QU

EST

SC

AD

A s

yste

m in

terf

ace

5.

1

Fo

xbo

ro D

CS

& e

xist

ing

SC

AD

A S

yste

m

Dat

a co

llect

ed b

y re

mo

te R

TU

s at

LB

V s

ites

an

d W

ell h

eads

will

be

tran

sfer

red

bac

k to

Fo

xbo

ro D

CS

via

SC

AD

A. It

was

iden

tifi

ed t

hat

Bas

e P

lan

t R

iver

Wat

er P

um

ps

are

con

tro

lled v

ia S

CA

DA

sys

tem

an

d Q

ues

t C

CS P

roje

ct w

ould

lik

e to

tak

e

adva

nta

ge o

f th

e ex

isti

ng

SC

AD

A s

yste

m in

terf

ace

and

ad

d a

dd

itio

nal

I/

O's

of

alm

ost

500

to

th

is s

yste

m.

To

be

Co

nfi

rmed

6

Bas

e P

lan

t C

on

tro

l R

oo

m s

pac

e re

quir

emen

ts

6.1

F

oxb

oro

DC

S &

Co

ntr

ol ro

om

It is

pla

nn

ed t

hat

tw

o (

add

itio

nal

) F

oxb

oro

DC

S o

per

ato

r st

atio

ns

will

be

inst

alle

d in

to t

he

Bas

e p

lan

t C

on

tro

l R

oo

m d

uri

ng

Ques

t

CC

S P

roje

ct s

tart

-up

. T

hes

e st

atio

ns

will

wo

rk in

dep

end

ent

of

exis

tin

g co

nso

les

to m

inim

ize

imp

act

to o

per

atio

ns.

On

ce Q

ues

t is

com

mis

sio

ned

, O

p's

tea

m w

ill in

tegr

ate

Ques

t in

to t

he

exis

tin

g H

MU

co

nso

le. C

om

mis

sio

nin

g co

nso

le m

ay a

lso

be

loca

ted

in

th

e

No

07-1

-AA

-773

9-0

001

R

estr

icte

d

Bas

ic D

esig

n &

En

gin

eeri

ng

Pac

kage

04

Hea

vy O

il

Item

Nu

mb

er

Bri

ef D

escr

ipti

on

of

inte

rface

T

ype

of

syst

em i

nte

rface

D

etail

s o

f in

terf

ace

D

o w

e n

eed

S/

D t

o i

mp

lem

ent

this

tie

in

HM

U o

per

atio

ns/

per

mit

cen

tre

at B

ase

Pla

nt.

6.2

IT

& R

adio

nee

ds

D

uri

ng

con

stru

ctio

n, P

re-c

om

an

d s

tart

-up

, th

ere

is a

nee

d f

or

add

itio

nal

IT

in

fras

truct

ure

an

d R

adio

s, it

is e

xpec

ted

th

at e

xist

ing

infr

astr

uct

ure

has

suff

icie

nt

spar

e ca

pac

ity

and

Ques

t C

CS P

roje

ct is

no

t ad

din

g an

yth

ing

new

.

No

7

Inte

rfac

e w

ith

Bas

e P

lan

t D

evic

eNet

, E

HT

sys

tem

& H

V M

ult

ilin

Mo

db

us

7.

1

Dev

iceN

et N

etw

ork

Dis

trib

ute

d M

CC

’s w

ill b

e im

ple

men

ted

in

th

e B

ase

Pla

nt

Ques

t ar

eas

(HM

U 1

&2

Ab

sorb

ers,

Am

ine

Reg

ener

atio

n, C

O2

Co

mp

ress

ion

, D

ehyd

rati

on

) an

d D

evic

eNet

net

wo

rks

asso

ciat

ed w

ith

th

em w

ill b

e in

tegr

ated

in

to t

he

rem

ote

Fo

xbo

ro I

/O

cab

inet

s lo

cate

d n

ear

the

MC

C’s

in a

co

mm

on

build

ing.

In H

MU

#3,

new

mo

tor

load

s w

ill b

e ad

ded

into

th

e ex

isti

ng

MC

C e

lect

rica

l n

etw

ork

fo

r E

lect

rica

l si

gnal

in

terf

aces

. Sam

e n

etw

ork

inte

rfac

es w

ill b

e use

d f

or

Op

erat

or

inte

rfac

e p

urp

ose

. D

esig

n w

ill f

ollo

w s

tan

dar

ds

for

each

pla

nt

(e.g

. HM

U#

3 w

ill f

ollo

w

Exp

ansi

on

1).

No

7.2

E

HT

sys

tem

Ques

t C

CS P

roje

ct w

ill h

ave

som

e h

eat

trac

ing

requir

emen

ts; e

xist

ing

EH

T n

etw

ork

at

bas

e p

lan

t an

d a

t E

xpan

sio

n 1

will

be

exte

nd

ed f

or

add

itio

nal

Ques

t sc

op

e. D

esig

n w

ill f

ollo

w s

tan

dar

ds

for

each

pla

nt

(e.g

. HM

U#

3 w

ill f

ollo

w E

xpan

sio

n 1

). I

t sh

ould

be

no

ted

th

at E

HT

co

nfi

gura

tio

n is

dif

fere

nt

bet

wee

n B

ase

Pla

nt

and

Exp

ansi

on

1.

No

7.3

M

ult

ilin

Mo

db

us

Sys

tem

New

HV

ele

ctri

cal sw

itch

gear

in

stal

led

in

Bas

e P

lan

t Q

ues

t ar

eas

(i.e

. A

min

e R

egen

erat

ion

) w

ill b

e in

tegr

ated

in

to t

he

rem

ote

Fo

xbo

ro I

/O

cab

inet

s lo

cate

d n

ear

the

elec

tric

al e

quip

men

t in

a c

om

mo

n b

uild

ing.

HV

un

its

add

ed in

to e

xist

ing

sub

stat

ion

s w

ill u

se t

he

exis

tin

g n

etw

ork

fo

r E

lect

rica

l si

gnal

in

terf

aces

. Sam

e n

etw

ork

in

terf

aces

will

be

use

d f

or

Op

erat

or

inte

rfac

e p

urp

ose

. D

esig

n w

ill f

ollo

w s

tan

dar

ds

for

each

pla

nt

(e.g

. HM

U#

3 w

ill f

ollo

w E

xpan

sio

n 1

).

No

8

Pip

elin

e L

eak

Det

ecti

on

sys

tem

in

terf

ace

8.

1

At

this

sta

ge, s

cop

e is

un

clea

r

Wit

h c

urr

ent

thin

kin

g, lo

oks

like

we

will

hav

e p

ress

ure

mo

nit

ori

ng

at m

ult

iple

lo

cati

on

s fo

r p

ipel

ine

leak

det

ecti

on

an

d s

imp

le

algo

rith

m w

ill b

e ex

ecute

d w

ith

in t

he

Fo

xbo

ro D

CS s

yste

m f

or

leak

det

ecti

on

cal

cula

tio

ns.

If

abo

ve s

cop

e ch

ange

s d

ue

to

stan

dal

on

e le

ak d

etec

tio

n s

yste

m, th

en t

hat

sys

tem

will

be

inte

rfac

ed w

ith

Fo

xbo

ro D

CS

as 3

rd p

arty

in

tegr

atio

n.

No

9

Pip

elin

e L

ine

Blo

ck V

alve

s (L

BV

) C

on

tro

l

9.1

Sco

pe

is in

dev

elo

pm

ent

Pip

elin

e P

FD

s an

d P

&ID

s ar

e n

ot

avai

lab

le a

t th

e ti

me

of

wri

tin

g, b

ut

it is

exp

ecte

d t

o h

ave

Hyd

raulic

typ

e o

f L

BV

s at

15

KM

dis

tan

ce. E

ach

LB

V s

ite

will

hav

e p

ress

ure

& t

emp

mo

nit

ori

ng

alo

ng

wit

h p

rovi

sio

n t

o d

epre

ssuri

ze t

hat

sec

tio

n o

f th

e p

ipel

ine.

All

the

LB

V s

ites

will

be

po

wer

ed b

y so

lar

pan

els

and

rem

ote

ly c

on

nec

ted

to

co

ntr

ol ro

om

via

a S

CA

DA

sys

tem

.

No

10

Wel

l H

ead M

on

ito

rin

g &

Co

ntr

ol

10

.1

Sco

pe

is in

dev

elo

pm

ent

At

this

sta

ge n

um

ber

of

wel

l h

ead

s is

no

t co

nfi

rmed

. At

each

wel

l h

ead

, p

ress

ure

, fl

ow

an

d t

emp

erat

ure

mo

nit

ori

ng

will

be

do

ne.

Th

ere

is is

ola

tio

n v

alve

at

each

wel

l h

ead

an

d a

ll d

ata

fro

m w

ell h

ead

will

be

sen

t to

co

ntr

ol ro

om

via

SC

AD

A s

yste

m. T

his

sys

tem

will

be

inte

rfac

ed w

ith

th

e F

oxb

oro

DC

S sy

stem

.

No

11

Pip

elin

e de-

pre

ssuri

zati

on

11

.1

Sco

pe

is in

dev

elo

pm

ent

se

e se

ctio

n 9

07-1

-AA

-773

9-0

001

R

estr

icte

d

Bas

ic D

esig

n &

En

gin

eeri

ng

Pac

kage

04

Hea

vy O

il

Item

Nu

mb

er

Bri

ef D

escr

ipti

on

of

inte

rface

T

ype

of

syst

em i

nte

rface

D

etail

s o

f in

terf

ace

D

o w

e n

eed

S/

D t

o i

mp

lem

ent

this

tie

in

12

InT

oo

ls D

atab

ase

Inte

rfac

es

12.1

B

ase

Pla

nt

Into

ols

Tie

in

Sin

ce B

ase

pla

nt

mai

nta

ins

an in

dep

end

ent

dat

abas

e, a

sn

ap s

ho

t o

f th

is d

atab

ase

will

be

take

n f

or

Ques

t C

CS P

roje

ct. A

n

ind

epen

den

t U

nit

will

be

add

ed in

to e

xist

ing

Pla

nt,

are

a U

nit

arc

hit

ectu

re a

nd

sit

e te

am w

ill b

e th

e ad

min

istr

ato

r fo

r th

e d

atab

ase.

On

ce E

PC

M f

inis

hes

th

e w

ork

, th

is d

atab

ase

will

be

han

ded

ove

r to

op

erat

ion

s, it

is e

xpec

ted

th

at O

per

atio

ns

will

per

form

th

e

mer

ge a

t la

ter

stag

e. A

ny

mo

dif

icat

ion

s/up

grad

es t

o t

he

HM

U s

team

ref

orm

ers

and

/o

r P

SA

un

it c

on

tro

ls w

ould

nee

d t

o b

e d

on

e

usi

ng

the

exis

tin

g In

too

ls d

atab

ases

sin

ce e

xist

ing

jun

ctio

n b

oxe

s, h

om

e ru

n c

ablin

g, c

on

tro

llers

, mar

shal

ling,

etc

are

bei

ng

uti

lized

(i.e

. n

ot

wir

ed u

p t

o t

he

new

Ques

t sy

stem

s).

No

12.2

E

xpan

sio

n 1

In

too

ls T

ie in

Sin

ce E

xpan

sio

n 1

dat

abas

e h

as n

ot

yet

bee

n h

and

ed o

ver

to o

per

atio

ns,

a s

nap

sh

ot

of

this

dat

abas

e w

ill b

e ta

ken

fo

r Q

ues

t C

CS

Pro

ject

. A

n in

dep

end

ent

Un

it w

ill b

e ad

ded

in

to e

xist

ing

Pla

nt,

are

a U

nit

arc

hit

ectu

re a

nd

sit

e te

am w

ill b

e th

e ad

min

istr

ato

r fo

r

the

dat

abas

e. O

nce

EP

CM

fin

ish

es t

he

wo

rk, th

is d

atab

ase

will

be

han

ded

ove

r to

op

erat

ion

s, it

is e

xpec

ted

th

at O

per

atio

ns

wil

l

per

form

th

e m

erge

at

late

r st

age.

An

y m

od

ific

atio

ns/

up

grad

es t

o t

he

HM

U s

team

ref

orm

ers

and

/o

r P

SA

un

it c

on

tro

ls w

ould

nee

d

to b

e d

on

e usi

ng

the

exis

tin

g In

too

ls d

atab

ases

sin

ce e

xist

ing

jun

ctio

n b

oxe

s, h

om

e ru

n c

ablin

g, c

on

tro

llers

, mar

shal

ling,

etc

are

bei

ng

uti

lized

(i.e

. n

ot

wir

ed u

p t

o t

he

new

Ques

t sy

stem

s).

No

13

Fir

e &

Gas

Det

ecti

on

sys

tem

in

terf

aces

13

.1

Inte

rfac

e to

Fo

xbo

ro D

CS

Bas

e p

lan

t has

imp

lem

ente

d t

he

exis

tin

g F

&G

wit

hin

Fo

xbo

ro D

CS s

yste

m.

New

F&

G in

th

e B

ase

Pla

nt

Ques

t ar

eas

(HM

U 1

&2

Ab

sorb

ers,

Am

ine

Reg

ener

atio

n, C

O2

Co

mp

ress

ion

, an

d D

ehyd

rati

on

)) w

ill b

e im

ple

men

ted

in

th

e n

ew H

on

eyw

ell Saf

ety

Sys

tem

wit

h in

terf

aces

to

th

e F

oxb

oro

DC

S, u

sin

g th

e sa

me

ph

iloso

ph

y as

Exp

ansi

on

1.

No

13.2

In

terf

ace

to E

xpan

sio

n 1

DC

S/

SIS

E

xpan

sio

n 1

F&

G a

rch

itec

ture

id

enti

fies

th

at in

puts

to

be

wir

ed t

o D

CS &

SIS

, sa

me

ph

iloso

ph

y w

ill b

e fo

llow

ed f

or

HM

U 3

are

a

inte

rfac

e F

&G

sys

tem

.

Yes

. New

I/

O c

has

sis

to b

e in

stal

led

in

exi

stin

g

FG

S c

abin

et.

13.3

P

ipel

ine

& W

ell F

&G

sco

pe

is u

ncl

ear

If

th

ere

is a

ny

sco

pe

in t

hes

e ar

eas,

it

will

fo

llow

th

e B

ase

Pla

nt

F&

G s

yste

m A

rch

itec

ture

.

14

Pla

nt

Eva

cuat

ion

sys

tem

in

terf

aces

14

.1

Bas

e P

lan

t E

vac

syst

em in

terf

ace

In

ord

er t

o a

void

co

nfu

sio

n, Q

ues

t C

CS P

roje

ct a

reas

ass

oci

ated

wit

h H

MU

1/

2 w

ill t

ie b

ack

to b

ase

pla

nt

evac

sys

tem

. N

eed

s to

be

con

firm

ed d

uri

ng

the

Exe

cute

Ph

ase.

T

o b

e C

on

firm

ed

14.2

E

x 1

Eva

c sy

stem

in

terf

ace

In

ord

er t

o a

void

co

nfu

sio

n, Q

ues

t C

CS P

roje

ct a

reas

ass

oci

ated

wit

h H

MU

3 w

ill t

ie b

ack t

o b

ase

pla

nt

evac

sys

tem

. N

eed

s to

be

con

firm

ed d

uri

ng

the

Exe

cute

Ph

ase.

T

o b

e C

on

firm

ed

15

Nee

d f

or

Del

uge

sys

tem

an

d s

afet

y sh

ow

er s

yste

m

15.1

A

t th

is s

tage

, th

ere

is n

o d

eluge

sys

tem

sco

pe.

16

Lo

adin

g o

f Q

UE

ST d

ata

into

PI

syst

em

16.1

F

oxb

oro

DC

S

On

ce Q

ues

t is

in

tegr

ated

wit

hin

th

e D

CS s

yste

m, Q

ues

t ta

gs n

eed

to

be

add

ed in

to t

he

PI

ho

me

no

de,

Pro

ject

will

pro

vid

e al

l th

e

nec

essa

ry in

puts

to

PI

team

at

Sco

tfo

rd f

or

them

to

up

dat

e th

e P

I se

rver

as

per

exi

stin

g si

te p

ract

ices

.

No

16.2

H

on

eyw

ell D

CS

On

ce Q

ues

t is

in

tegr

ated

wit

hin

th

e D

CS s

yste

m, Q

ues

t ta

gs n

eed

s to

be

add

ed in

to t

he

PI

ho

me

no

de,

Pro

ject

will

pro

vid

e al

l th

e

nec

essa

ry in

puts

to

PI

team

at

Sco

tfo

rd f

or

them

to

up

dat

e th

e P

I se

rver

as

per

exi

stin

g si

te p

ract

ices

.

No

07-1

-AA

-773

9-0

001

R

estr

icte

d

Bas

ic D

esig

n &

En

gin

eeri

ng

Pac

kage

04

Hea

vy O

il

Item

Nu

mb

er

Bri

ef D

escr

ipti

on

of

inte

rface

T

ype

of

syst

em i

nte

rface

D

etail

s o

f in

terf

ace

D

o w

e n

eed

S/

D t

o i

mp

lem

ent

this

tie

in

17

Pro

vide

inp

uts

to

succ

essf

ul im

ple

men

tati

on

of

GA

ME

17

.1

Inte

rfac

es w

ith

GA

ME

@ B

ase

Pla

nt

O

per

atio

ns

has

pro

vid

ed a

ll n

eces

sary

in

put

requir

emen

ts t

o Q

ues

t C

CS P

roje

ct t

eam

, n

eces

sary

dat

a fi

eld

s w

ill b

e up

dat

ed in

th

e

give

n s

pre

ad s

hee

t to

op

erat

ion

s fo

r su

cces

sful G

AM

E im

ple

men

tati

on

(in

clud

ing

Sh

ell E

SP a

nd

IP

F r

equir

emen

ts)

N

o

17.2

In

terf

aces

wit

h G

AM

E @

Exp

ansi

on

1

Op

erat

ion

s h

as p

rovi

ded

all

nec

essa

ry in

put

requir

emen

ts t

o Q

ues

t C

CS P

roje

ct t

eam

, n

eces

sary

dat

a fi

eld

s w

ill b

e up

dat

ed in

th

e

give

n s

pre

ad s

hee

t to

op

erat

ion

s fo

r su

cces

sful G

AM

E im

ple

men

tati

on

.

No

18

Inve

stig

ate

and im

ple

men

t F

oxb

oro

-Ho

ney

wel

l G

atew

ay P

LC

dat

a tr

ansf

er n

eeds

18

.1

Fo

xbo

ro &

Ho

ney

wel

l D

CS s

yste

ms

At

pre

sen

t, a

Quan

tum

gat

eway

PL

C p

rovi

des

nec

essa

ry d

ata

map

to

shar

e in

form

atio

n b

etw

een

Bas

e P

lan

t an

d E

xpan

sio

n 1

con

tro

l ro

om

s. T

o m

inim

ize

the

imp

act

to O

per

atio

ns,

Ques

t w

ill a

dd

a n

ew P

LC

an

d r

edun

dan

t F

oxb

oro

co

mm

un

icat

ion

gat

eway

mo

dule

s. Q

ues

t C

CS P

roje

ct t

eam

nee

ds

to u

nd

erst

and

sp

are

cap

acit

y an

d u

tiliz

e af

ter

app

rova

l fr

om

th

e si

te O

per

atio

ns

team

(in

clud

ing

fib

er o

pti

c b

ackb

on

e, c

abin

et s

pac

e an

d s

wit

ch r

equir

emen

ts).

To

be

Co

nfi

rmed

19

Mo

dif

icat

ion

of

Ho

ney

wel

l &

Fo

xbo

ro n

ativ

e H

isto

rian

19

.1

Fo

xbo

ro D

CS

Q

ues

t C

CS P

roje

ct n

eed

s to

up

dat

e F

oxb

oro

DC

S s

yste

ms

nat

ive

His

tori

an f

or

Ques

t ta

gs a

nd

nec

essa

ry p

oin

t p

aram

eter

s w

ill b

e

his

tori

zed

bas

ed o

n e

xist

ing

site

pra

ctic

es.

N

o

19.2

H

on

eyw

ell D

CS

Ques

t C

CS P

roje

ct n

eed

s to

up

dat

e H

on

eyw

ell D

CS s

yste

ms

nat

ive

His

tori

an f

or

Ques

t ta

gs a

nd

nec

essa

ry p

oin

t p

aram

eter

s w

ill

be

his

tori

zed

bas

ed o

n e

xist

ing

site

pra

ctic

es.

N

o

20

Mo

dif

icat

ion

s o

f H

on

eyw

ell an

d F

oxb

oro

DC

S g

rap

hic

s

20.1

F

oxb

oro

DC

S

Th

e Q

ues

t C

CS P

roje

ct n

eed

s to

cre

ate

add

itio

nal

pro

cess

gra

ph

ics

for

Hum

an in

terf

ace.

All

Bas

e P

lan

t si

te p

ract

ices

will

be

follo

wed

to

en

sure

gra

ph

ics

and

co

ntr

ol sc

hem

es a

re s

eam

less

.

No

20.2

H

on

eyw

ell D

CS

Th

e Q

ues

t C

CS P

roje

ct n

eed

s to

cre

ate

add

itio

nal

pro

cess

gra

ph

ics

for

Hum

an in

terf

ace.

All

Ex

1 si

te p

ract

ices

will

be

follo

wed

to

ensu

re g

rap

hic

s an

d c

on

tro

l sc

hem

es a

re s

eam

less

.

No

21

Inte

rfac

e o

f fl

ow

met

erin

g sy

stem

wit

h n

ativ

e D

CS/P

I/P

rism

21

.1

Sco

pe

is in

dev

elo

pm

ent

Q

ues

t C

CS P

roje

ct w

ell h

ead

dat

a n

eed

to

be

avai

lab

le f

or

acco

un

tin

g p

urp

ose

s in

Sh

ell C

entr

e. O

nce

SC

AD

A d

ata

is h

isto

rize

d

wit

hin

DC

S a

nd

PI,

wh

ich

nee

ds

to b

e in

tegr

ated

wit

h P

rism

sys

tem

at

Sh

ell C

entr

e.

No

22

Use

of

FB

M 2

28 in

stea

d o

f F

BM

221

& its

in

terf

ace

wit

h F

oxb

oro

DC

S

22.1

U

se o

f n

ew m

od

ule

F

BM

228

is

stro

ngl

y re

com

men

ded

by

the

tech

nic

al t

eam

an

d t

his

nee

ds

to b

e co

nsi

der

ed d

uri

ng

har

dw

are

ord

erin

g an

d s

yste

m

inte

grat

ion

.

No

23

Iden

tifi

cati

on

of

Pro

ject

in

terf

aces

an

d its

im

pac

t o

n D

AC

A

23.1

Sco

pe

is in

dev

elo

pm

ent

A

t th

is t

ime

3rd

par

ty in

terf

ace

sco

pe

is u

ncl

ear

and

its

im

pac

t o

n D

AC

A a

rch

itec

ture

will

be

stud

ied

at

late

r st

age.

N

o

24

PSA

Co

ntr

ol M

odif

icat

ion

s

24.1

Sco

pe

is in

dev

elo

pm

ent

for

HM

U#

1 &

2

Bas

e P

lan

t P

SA

Un

it is

con

tro

lled

via

th

e m

ain

In

ven

sys

DC

S. In

terf

ace

and c

on

figu

rati

on

ch

ange

s b

y SP

G.

Yes

24.2

Sco

pe

is in

dev

elo

pm

ent

for

HM

U#

3

Exp

ansi

on

1 P

SA

Un

it is

con

tro

lled

via

lic

enso

r su

pp

lied

pac

kage

PL

C. In

terf

ace

and

co

nfi

gura

tio

n c

han

ges

by

UO

P.

Yes

07-1

-AA

-773

9-0

001

R

estr

icte

d

Bas

ic D

esig

n &

En

gin

eeri

ng

Pac

kage

04

Hea

vy O

il

Item

Nu

mb

er

Bri

ef D

escr

ipti

on

of

inte

rface

T

ype

of

syst

em i

nte

rface

D

etail

s o

f in

terf

ace

D

o w

e n

eed

S/

D t

o i

mp

lem

ent

this

tie

in

25

Dem

in P

lan

t (P

lan

t 25

1) C

on

tro

l

25.1

Sco

pe

to b

e d

eter

min

ed in

th

e E

xecu

te P

has

e In

terf

ace

and c

on

figu

rati

on

ch

ange

s b

y SP

G.

No

26

Lab

ora

tory

In

form

atio

n S

yste

m

26.1

N

o k

no

wn s

cop

e.

To

be

Co

nfi

rmed

T

o b

e C

on

firm

ed



Heavy Oil

19. REVAMP OF UTILITIES & OFFSITE FACILITIES

Upgrader utilities will be extended to provide services to the Quest greenfield and brownfield units. No new or additional utility facilities are required within the Upgrader’s Utility plant, Raw Water plant, Waste Water Treatment plant or Cooling Tower to satisfy Quest’s utility demands. Design of piping systems to the Quest unit are used to satisfy the expansion of services that Quest requires. Increases in utility system throughputs to meet Quest’s requirements are deemed to be within the operational windows of each of the respective utilities.

19.1. Greenfield Utility Requirements

The Quest Amine Regeneration and CO2 Compression / Dehydration areas require the following utilities:

· Utility Air

· Instrument Air

· Utility Water

· Nitrogen

· Demin Water

· Cooling Water

· LP Steam

· HP (low temp) Steam

· Steam Condensate Recovery and Handling

· Waste Water

· Firewater

· Stormwater

· Power

These are supplied from tie-ins to utility pipelines in the interconnecting piperacks, Cooling Tower and in the Utility Plant. One tie-in is at HMU 1&2 for storm water removal from the Quest area.

Utility systems need tie-ins complete and piping operational to facilitate initial Quest operation on HMU3 feed. Specific hot tap applications have been identified scope found in Section 18 by SPG. It is expected all of these systems will be available as of the completion of the 2014 turnaround for the Expansion 1 facilities.

The CW return tie-in at the Utility / CoGen CW Supply header requires the upstream butterfly block valve to be trimmed to approximately 40% closure, to ensure Utility / CoGen unit does not receive excessive cooling water supply from the main header. This pipeline valve will be initially fitted with an actuator for the initial start-up in 2014, but will be replaced with a new instrument control valve in 2015 when the Base Upgrader is in turnaround.



Heavy Oil

Instrument Air supply for Quest utilizes a tie-in to the Expansion 1 Instrument Air pipeline between the Base Upgrader and Expansion 1 Upgrader. This line will be isolated and de-energized in the 2014 turnaround to complete the tie-in.

19.2. Brownfield Utility Requirements

The CO2 Absorber areas of the HMUs, both Base Upgrader and Expansion 1, require the following utilities:

· Utility Air

· Instrument Air (CO2 Absorbers and FGR Fans & Louvers)

· Utility Water

· Nitrogen

· Cooling Water

· HP Boiler Feed Water (HMU3 only)

· Waste Water (HMU3 only)

· LP Steam

· Steam Condensate Recovery

· Flare

· Firewater

· Power

These will be supplied by tie-ins to the common utility headers within the respective Base Upgrader or Expansion 1 facilities.

HMU2 will have a unit shutdown in 2013, but this will not allow for utility tie-ins to be completed. The 2015 Base Upgrader turnaround will be used to complete all of the utility and flare tie-ins required for HMU 1&2 since that complex will be shutdown.

HMU3 will be shutdown in 2014 in the Expansion 1 turnaround and all utility tie-ins for HMU3 will be completed in that timeframe. HMU3 is expected to be the first unit to be serviced by the Quest Capture process after the Expansion 1 turnaround is complete.

19.3. Unit Overview

Utility delivery within the Quest unit and the CO2 Absorbers installed in the HMUs are integrated with existing utility conditions and in accordance with existing Upgrader standards and details.

19.4. Objectives and Results of Value Improvement and Scoping Studies

Two key utility systems for the successful operation of the Quest greenfield units are the delivery of LP Steam and fresh cooling water.



Heavy Oil

A study was undertaken during Pre-FEED to select between a semi-lean and lean only process configuration. The overall demand for LP Steam increases significantly with the incorporation of the lean only amine concept for absorption and regeneration design. Scotford has established that the Upgraders have sufficient capacity to deliver the additional LP Steam. The advantages of this case have been documented in Project Decision Note A6GT-DN-1035.

The cooling water system in the Base Upgrader is hydraulically limited but is under-utilized with respect to duty. A significant amount of under-utilized duty is available from the Cogen plant which normally is used to condense steam. With the extraction and transfer of LP steam to the Quest unit, the normal Cogen plant cooling water duty is further unloaded. Therefore, the Quest design basis is to transfer the Cogen plant cooling water flow and duty to Quest. The Quest design provides for a cooling water supply header originating at Cooling Tower unit and cooling water return header connecting to the cooling water supply header at the Cogen / Utility Plant. This will allow Quest to utilize a portion of this available cooling water to provide cooling of the amine regeneration area and CO2 compression area. This is a significant capital savings as large air cooler bays can be replaced by smaller water coolers.

Demin water is used to provide cooling and retention of 100% of the LP Condensate generated by the amine regeneration reboilers. Typical condensate collection systems have an atmospheric flash drum where 10 – 12% of the LP Condensate can be lost to atmospheric flash steam. By recovering this heat using demin water, venting atmospheric flashed steam is prevented and the steam requirements at the BFW Deaerator are reduced.



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19.5. System Specific Design Philosophy

Utility consumptions for the operation of the Quest greenfield and brownfield units have been discussed with the Upgraders and Project Integration to ensure the site has the ability to provide each utility. The Quest SIF request requires the Upgrader utility systems to deliver:

Temp Press

ACT m³/h S m³/h kg/h ACT m³/h S m³/h kg/h °C kPag

HMU 1 & 2

Unit 240 (Units 241 & 242)LP Steam (Utility Station) SL NNF NNF NNF 958 2,000 160 355

Instrument Air AI 5 36 44 6 45 55 45 700

Utility Air AU NNF NNF NNF 29 204 250 45 700

Nitrogen GI NNF NNF NNF 23 211 250 40 900

Utility Water WU NNF NNF NNF 11 11 10,992 25 425

Potable Water WO NNF NNF NNF NNF NNF NNF 25 425

Cooling Water Supply CWS 75 75 74,448 78 78 78,170 25 425

Cooling Water Return CWR (75) (75) (74,448) (79) (78) (78,170) 30 250

Consumption is +ve, Return or Production is (-ve)

Quest CO2 (Amine Regeneration, CO2 Compression etc)

Units 246, 247 & 248 ACT m³/h S m³/h kg/h ACT m³/h S m³/h kg/h °C kPag

LP Steam SL 77,655 162,125 81,582 170,325 145 355

LT HP Steam SH 20 450 36 800 257 4370

Rec'd Clean Condensate RCC (157) (154) (153,557) (175) (171) (170,704) 74 600



Nitrogen GI 3 33 39 32 314 372 15 900


Potable Water WO NNF NNF NNF 15 15 14,990 5 525

Waste Water (Purge Water) (12) (12) (11,792) (12) (12) (11,792) 35 500

Demin Water (Supply) WD 185 185 184,893 195 194 194,138 22 700

Demin Water (Return) WD (190) (185) (184,893) (200) (194) (194,138) 79 650

Cooling Water Supply CWS 5,755 5,743 5,739,182 6,249 6,236 6,231,855 25 510

Cooling Water Return CWR (5,787) (5,743) (5,739,182) (6,284) (6,236) (6,231,855) 41.9 503


HMU 3

Unit 440 (Unit 441)ACT m³/h S m³/h kg/h ACT m³/h S m³/h kg/h °C kPag

LP Steam (Utility Station) SL NNF NNF NNF 958 2,000 160 355

Boiler Feed Water BFW 7 7 6,527 7 7 6,853 121 5250



Nitrogen GI NNF NNF NNF 22 211 250 15 900


Potable Water WO NNF NNF NNF NNF NNF NNF 23 525

Waste Water (7) (7) (6,503) (7) (7) (6,828) 35 2900

Cooling Water Supply CWS 113 113 112,920 113 113 112,920 25 425

Cooling Water Return CWR (113) (113) (112,920) (113) (113) (112,920) 32.7 355


Utility

Unit 251 ACT m³/h S m³/h kg/h ACT m³/h S m³/h kg/h °C kPag

Rec'd Clean Condensate RCC 157 154 153,557 175 171 170,704 74 470


Waste Water (Cont RCC) NNF NNF NNF (175) (171) (170,704) 74 470


Design allowances for piping design, which are not additive to

Unit demand for SL, WU, AU, GI. CW is part of hydraulic study

Normal

Normal Flow Design Flow

Design allowances for piping design, which are not additive to

Unit demand for SL, WU, AU, GI. CW is part of hydraulic study

19.5.1. Utilities and Offsites Specifications

Utilities are supplied to the Quest greenfield unit primarily from existing utility headers in Unit 285, and these commodities are available according to the Basic Utility Design Data as shown in Table 19.1. Utilities are supplied to the new Absorbers in the HMU areas from unit utility headers in their respective HMU plots.

Table 19.1 Basic Utility Design Data

77,655 162,125 81,582 170,325



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UTILITY

NO

TE

S

PIP

ING

DE

SIG

N

At Source or Producer at

Battery Limit

Plant Supply Header

Note

No.

NOTES & LEGEND

OPERATING OPERATING

MAX NORM MIN MAX NORM MIN Darker cell shading indicates data from Base Upgrader Project

1.0 STEAM

Care must be taken when units have large steam producers such as

boilers, h.p. turbines or letdown facilities, as this may have a great

impact on local conditions within the battery limits

General Notes 1.1, 1.2 1.1

HP (SH, 600# flange rating) kPag 1.3 5170 4550 4500 4370 4480 4350 4300

°C 415 405 400 395 405 400 380

IP (SAT, 600# flange rating) kPag 4850 4410 4220 4170 4340 4150 4100

Users of steam should design for pressure drop of 70, 70, 35 and 35

kPa respectively for HP, IP, SHMP and LP steam headers if they are

located in the current plant area

°C 290 262 455 sat 262 255 sat 1.2

SHMP (SH, 150# flange rating) kPag 1100 950 885 835 915 850 800

°C 260 250 240 230 250 220 200

HP Steam turbine drivers shall be designed for a min. inlet pressure

of 3800 kPag @ 270°C

LP (SH, 150# flange rating) kPag 500 385 370 355 350 335 320 1.3

°C 250 240 160 sat 240 160 sat

2.0 BOILER FEEDWATER

High Pressure kPag 2.1, 2.3 9060 8200 7700 7000 7700 7000 6500 2.1 Max. conditions to be verified once pump shut-off head is established

°C 2.2 150 140 130 121 126 121 116 2.2 Assume no temp. drop between users and producers

Low Pressure kPag 2.1, 2.4 1500 1320 1000 900 1070 750 650 2.3 Assume 500 kPa pressure drop (750 m @ 67.5 kPa/100 m)

°C 2.2 150 140 130 121 126 121 116 2.4 Assume 250 kPa pressure drop (375 m @ 67.5 kPa/100 m)

3.0 CONDENSATE

STG HP condensate (600#) kPag 3.1 9060 7850 6600 6500 3.1

All condensate returned to the Utility plant will be considered

potentially contaminated and must flashed and pumped back to the

Utility plant.

°C 150 53 34 27

STG LP condensate (150#) kPag 3.1 1400 800 750 700

°C 150 53 34 27

RCC (150#) kPag 1400 800 750 50

°C 130 98 95

4.0 FIREWATER

Firewater (150#) kPag 1100 950 900 900

°C 27 5



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5.0 INSTRUMENT / UTILITY AIR

Instrument Air (150#) kPag

5.1, 5.2, 5.3

1200 860 700 350 5.1 Oil Free

°C 70 50 45 -43 5.2 Pressure dew point -40°C

Utility Air (150#) kPag

5.1, 5.2, 5.3

1200 860 700 300 5.3 Users will see 70 kPa pressure drop from producer per line space

°C 70 50 45 -43

6.0 POTABLE / UTILITY WATER / RAW WATER

Potable Water (150#) kPag 880 625 525 -

°C 23 - 5 -

Utility Water (150#) kPag 900 750 525 525

°C 33 23 5 1

Raw Water (150#) kPag 1120 200 190 190

°C 33 23 5 1

Clarified water to CT (150#) kPag 500 470 270 140

°C 33 23 5 1

WWTU effluent to CT (150#) kPag 420 320 240 140

°C 45 35 35 30

Demin (150#) kPag 750 750 415 415

°C 45 35 25 5

7.0 COOLING WATER

Cooling Water Supply (150#) kPag 800 550 420 420 7.1 Max temperature for MVGO cooling only

°C 7.1, 7.2 58 25 25 18 7.2 Wintertime minimum to prevent icing

Cooling Water Return (150#) kPag 800 420 240 240

°C 58 48 45 45

8.0 NITROGEN

Nitrogen (150#) kPag 1500 1100 900 800

°C 70 50 5 – 45 -43

9.0 FUEL / NATURAL GAS

Fuel Gas (150#) kPag 800 545 520 350

°C 70 45 40 15



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HP Natural Gas (600#) kPag 5600 5600 5200 4890 5000 4800 4600

°C 70 27 5 0 30 5 -30

LP Natural Gas (150#) kPag 1350 1200 1000 950 1100 950 800

°C 70 27 15 -10 30 15 -30

10.0 BOILER BLOWDOWN

Boiler Blowdown (150#) kPag 650 500 450 0

°C 122 98 98 -

19.5.2. Turndown

Control systems in the delivery of utilities will facilitate the operational flexibility of the Quest CCS Project.


Utility systems availability is based on the overall availability of the Upgrader and will not adversely affect the On Stream Factor of the Quest CCS Project.


Utility systems within the Quest greenfield will meet the needs and requirements of a unit designed to meet “Class of Facilities Level 1” as defined in the Project Class of Facilities Value Improvement Practice Report, Document Number A6GT-R-1016 Rev A. Attachment 2 – Class of Facilities Quality Overview.

In the Amine Regeneration unit, the Demin Water Booster and Cooling Water Booster pumps are designed as 2 x 50%. This allows operation of the Quest facilities, albeit in a limited fashion, when one pump needs to be serviced.

Pumps in the “Class of Facilities Level 3” areas, which service the Wash Water Circulation systems of the CO2 Absorbers, are designed as 2 x 100%. If one of these pumps requires maintenance, there is a standby spare.

19.5.5. Reliability and Flexibility

The Quest Greenfield units are dedicated facilities to extract CO2 from three process streams, and purify / compress the CO2 for pipeline discharge. The utility systems within the greenfield units will meet the flexibility and reliability requirements of the unit as a whole.



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19.6. Utility System Requirements

19.6.1. Steam / BFW / Condensate

The Amine Stripper Reboilers are the largest consumer of LP Steam in the Quest unit. At design rates the reboilers require 162 t/h LP Steam.

LP Condensate from the reboilers is cooled by exchanging heat with Demin Water and routed into a nitrogen blanketed Condensate Flash Drum, to be combined with HP Condensate from the Dehydration TEG unit. The combined, cooled condensate is moderately subcooled to prevent flashing, which conserves condensate for return to the utility plant or water make-up for HMU 1&2 water wash systems or amine dilution.

Condensate is returned to the Base Upgrader as RCC for delivery to the RCC Tank Tk-25101 and has the same analysis and bypass system to POC as existing RCC streams.

HP (Low Temp) Steam is supplied to the Dehydration unit for regeneration purposes and the resulting condensate sent to the Condensate Flash Drum.

Boiler feed water is required in HMU3 as wash water make-up. The BFW will be sourced from the header inside the HMU3 battery limits.

Building and space heating has not been defined and may affect steam consumption in winter.

19.6.2. Cooling Water

Cooling water (CW) is supplied to the Quest greenfield units from a Cooling Tower tie-in on the CWS header to the Utility Plant / Cogen Unit 250/251. A booster pump is utilized to supply CW to users in the Amine Regeneration and CO2 Compression areas. Warm CW is returned to a Utility Plant tie-in on the Utility Plant / Cogen Unit 250/251 CWS header. To prevent operational disruptions in the Cogen Unit associated with a loss of Quest CW pumps, a bypass valve has been added between the Quest CW supply and return headers to divert CW directly to the Cogen Unit.

The Water Wash vessels, downstream of the absorbers, require cooling water to maintain the temperature of the treated raw hydrogen gas to 35°C. This increases overall CW demand in each of the HMU blocks of the Upgraders. There is an additional cooling load in HMU3 for cooling BFW for make-up water supply.

19.6.3. Demineralised Water

Demineralised water (DW) is used to recover heat from Quest’s LP Condensate system, as described in Section 19.6.1. Demin water is supplied from a tie-in on the DW header on the existing Unit 285 piperack. A booster pump is used in the Quest unit to overcome hydraulic losses associated with the LP Condensate / Demin Water exchanger and the supply and return



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piping. The hot DW is returned to a tie-in located in the Utility Plant (Unit 251) downstream of FV-251001.

Returning hot DW to the Base Plant Upgrader Deaerator recovers waste heat from the Quest unit and reduces LP Steam requirements at the Deaerator.

Quest extracts and returns DW to essentially the same supply line, and does not consume DW in its process configuration. In the event that DW flow stops within Quest, the Base Upgrader utility systems experiences the following affects:

· Flow is maintained through the existing deaerator level control system.

· an increase in atmospheric steam flash losses at Quest,

· a reduction in condensate recovery from Quest,

· an increase in LP Steam consumption at the Deaerator.

19.6.4. Instrument and Utility Air

Instrument air is required to operate the control valves in the CO2 Capture, Amine Regeneration, CO2 Compression and Dehydration areas. Utility air is provided to all new utility stations.

Tie-ins to existing distribution systems are used to supply Instrument and Utility Air to the Quest unit as well as to the new Absorber units and Flue Gas re-circulation skids in the HMUs.

Utility air is required for the utility stations. An intermittent consumption of approximately 322 Nm3/h is estimated, based on two utility stations in use at any given time.

19.6.5. Nitrogen

Nitrogen is normally used as a stripping gas in the TEG Unit and a blanket gas in the Amine Make-up tanks, Amine Drain Drum and the LP Condensate Flash Drum. Nitrogen, supplied from utility stations, is also used for purging of vessels and equipment for maintenance.

Utility stations within the CO2 Capture areas of the HMUs have nitrogen supplied as part of the extension of utilities within the HMU areas to service the new Amine Absorbers.

19.6.6. Utility Water

Utility water is required for the utility stations. An intermittent consumption of 11 Sm³/h has been estimated in the Quest unit and is based on two utility stations in use at any given time.

Utility water for the Absorbers will be obtained from within their respective HMUs and it is expected that no more than two utility stations might be in use in an HMU area. The new utility station loads are not expected to be coincident with existing loads in the HMUs.



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19.6.7. Potable Water

Two safety showers have been assumed in the Amine Regeneration area. Safety showers and eye wash stations will be stand alone systems (i.e. do not require connections to the potable water distribution system.

19.6.8. Waste Water

The Quest unit generates a waste water stream combined from excess Amine Stripper reflux water, recovered water from CO2 compression and HMU 1&2 Purge Water. This water is routed to the Potentially Oily Condensate (POC) line on the interconnecting piperack for treatment in the Waste Water Treatment plant.

HMU3 Purge water is routed to the existing Process Condensate Steam Receiver, V-44111.

The net waste water generation adds approximately 16 tonnes/h of waste water to the treatment requirements of the combined Waste Water Treatment plants (Units 271 / 471).

19.7. Offsites Changes by System

19.7.1. Stormwater Collection

The overall paved area of the Base Plant Upgrader is increased by the addition of the Quest unit which moderately affects the stormwater collected. The stormwater drainage areas of the HMUs changes marginally with the addition of the CO2 Capture facilities, as these are constructed within the existing HMU paved areas.

There are curbed areas within the new facilities which are isolated from the stormwater catchment basins, and require a new storm water pump to remove collected rainwater from the local sumps connected to the curbed areas. The stormwater collected in the Quest area will be pumped to the HMU 1&2 Absorber area sump, which is connected to the POS sewer system in HMU 1&2.

19.7.2. Firewater

The Base Plant Upgrader firewater (FW) distribution network is to be modified so that monitors and hydrants can be installed around the new Quest greenfield plot area.

In both HMU plot areas, the internal FW distribution systems are modified to accommodate the addition of the CO2 Capture facilities. These modifications shall be completed prior to placement of new equipment in these plot areas to assure continued fire fighting coverage in the operating areas of the HMUs during Quest construction and new HMU module erection.

19.7.3. Tankage Changes



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Quest area requirements for liquid storage will be met by facilities installed within the Quest plot area. These are:

· Amine Make-up and Inventory Storage Tank (2 shop fabricated tanks).

· A small TEG make-up tank (tote) in the Dehydration area.

Recovered Clean Condensate (RCC) from the Quest CSS Project will be sent directly to the RCC Tank Tk-25101. This will ensure Quest’s RCC flow does not bottleneck the existing RCC rundown system.

19.7.4. Waste Water Treatment

The Waste Water Treatment plant receives two waste water streams from the Quest units.

The combined excess reflux stream (predominately water, with traces of CO2 and amine) from Quest will be discharged into the base Upgrader Potentially Oily Condensate line, that runs from the Utility Plant to the Waste Water Treatment Plant. Normally this line has no flow while the RCC system operates normally and is contaminant free.

HMU3 Purge Water stream will discharge into the HMU3 DO system via the Process Condensate Steam Receiver / Cooler (V-44111 / E-44120) for treatment in the Unit 471 Waste Water facility.

19.7.5. Flare

The Regeneration, Compression and common areas have their own CO2 Vent Stack, and do not require connections to the main hydrocarbon flare system.

The HMU absorber areas have pressure control vents and new relief valves that are connected through tie-ins to their respective HMU flare collection headers.

19.7.6. Buildings

No new utility buildings are required. Specific purpose shelters will be provided as part of Electrical, Instrumentation and compression design of the Quest unit.

19.7.7. Interconnecting Piperacks and Piping

New interconnecting piperacks are provided in Unit 285 Interconnecting Piping:

· To connect the Quest greenfield units to the HMU 1&2 CO2 Capture facilities. Thispiperack provides lean and rich amine; make-up wash water and purge water returnlines as well as power cables and the stormwater return line.

· To connect the Quest greenfield units with the main interconnecting piperack runningEast-West along 10th Ave in the Base Upgrader.



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· To connect lean and rich amine lines running from HMU3 (East side) down to theUnit 285 / 485 piping sleeper that is east of the Raw Water pond. The lean and richamine lines continue on the existing piping sleeper and piperacks to the new piperackrunning to the Quest greenfield units.


Utility design conditions are outlined in Section 19.5.1.

19.9. New and Revised PFDs

New utility PFDs for the Quest CCS Project, are found in Appendix A1.1, and marked-up PFDs, showing the integration of most utilities with the Base Upgrader are found in Appendix A3.1

Utility flow rates are shown on the Heat and Material Balances as found in Appendix A1.3.

Table 19.2 is a listing of new and marked-up PFDs that are utilized in the Quest utility design. These drawings can be found in Appendix A1.1 and A3.1.

Table 19.2 Utility Process Flow Diagrams Drawing Number Revision Title 246.0001.000.040.003 0B Process Flow Diagram – Quest –

Amine Storage and Drain Collection 246.0001.000.040.004 0B Utility Flow Diagram – Quest –

Utilities System 251.0001.000.040.001 4B Process Flow Diagram Recovered

Condensate Treatment / BFW Treatment System

251.0001.000.040.007 4B Utility Flow Diagram Upgrader Operation – HP, IP, SHMP & LP Steam Distribution

251.0001.000.040.008 4B Utility Flow Diagram Upgrader Operation – Condensate Collection

252.0001.000.040.002 3B Utility Flow Diagram Cooling Water Distribution

253.0001.000.040.002 4B Utility Flow Diagram Utility & Instrument Air Distribution

440.0001.000.040.011 2B Utility Flow Diagram AOSP Downstream Expansion – HMU3 – Steam / Condensate / BFW

19.10. Sized New Equipment List

The Equipment List for the Quest Capture unit, as found in Appendix A1.4 includes all of the Utilities and Offsites equipment required.



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20. PIPELINE

20.1. Introduction

20.1.1. System description

Tri Ocean Engineering scope of work consists of a buried high vapor pressure (HVP) pipeline that will transport dehydrated, compressed, and dense phase CO2. This CO2 will originate from the CO2 capture facility that will be added to the Scotford Upgrader and will be delivered, via pipeline, to injection wells in the CO2 storage area near Radway and Thorhild, Alberta.

Also included are pigging facilities, line break valves, and monitoring and control facilities.

The well pad scope includes: subsurface safety valve control panel; Measurement, Monitoring and Verification (MMV) interconnection; and utilities.

20.1.2. Facilities

The CO2 capture facility will contain a metering skid and pig launching facilities, which will be a part of this project’s scope. The CO2 delivery to the injection wells will consist of:

a) provision for future pig receiving facility for catching pipeline pigs,

b) a meter skid to measure the flowrate of CO2 into the injection well. This flow meter isused as an integral part of the leak detection on the pipeline system.

c) a particulate filter is incorporated upstream of the flow meter. These filters will removeany debris from the pipeline. Primarily, the filters are to prevent millscale fromreaching the formation face. Quality sampling of the CO2 stream will take place atScotford to ensure it meets minimum pipeline specifications. Quality sampling willimpact pipeline operation, but will not be part of this scope, and will be completed byFluor.

d) A Supervisory Control and Data Acquisition (SCADA) system will collect and transmitdata from the pipeline and well sites back to the Capture Facility Control Room andwill centrally control and monitor the Line Break Valves.

20.2. Design Data

20.2.1. Design Standards and Legislation Requirements

This project will follow applicable Shell standards, government acts, regulations, and industry codes and practices, a summary of which is provided in Appendix L of this document.

This pipeline project will comply with CSA Standard Z662, latest edition. Adherence to CSA Z662 requires specification of a ‘location factor’ used in determination of LBV spacing and in determination of the relationship between design wall thickness and design pressure.



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Other applicable Regulations include:

− Alberta Pipeline Act and Regulations

− ERCB Directive 56 (Requirements and Procedures for Pipelines)

− ERCB Directive 066 (Energy Development Application Code)

− ERCB Directive 71 (Emergency Response for Upstream Petroleum Industry)

Water crossings will comply with all Alberta Environment, DFO and Navigable Waters requirements.

20.2.2. Industry Guidelines

This project will follow all relevant and applicable industry standards, in particular:

− CSA Z662 Oil and Gas Pipeline Systems

− CSA Z245.1 Steel Line Pipe

− CSA Z245.11 Steel Fittings

− CSA Z245.12 Steel Flanges

− CSA Z245.15 Steel Valves

− ASME B31.3 Chemical Plant and Petroleum Refinery Piping

− TC E-10 Railway Crossings

An industry guideline developed by a Joint Industry Project (JIP), CO2 PIPETRANS contains best practices for CO2 pipelines. This was used as a reference during the Define phase. The guideline is contained in Appendix N of the Pipeline Conceptual Design report Revision 1 dated November 22, 2010 (document number 07-2-LA-7180-0002).

20.2.3. Client Specifications

The specifications applicable to this project are a combination of generic Shell Canada standards, Shell DEP – General and Project Specific standards developed to meet the regulatory requirements, CSA Z662 design code and Shell DEM1 requirements for Process Safety.

20.2.4. Fluid Composition

The CO2 composition is described in Table 19.2.4. The amount of water shall be controlled to 4 lb/MMSCF in the winter and to 6 lb/MMSCF in the summer.

Table 19.2.4 Feed Composition

Component Normal Composition Upset Composition

CO2 99.23 95.00



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H2 0.65 4.27

CH4 0.09 0.57

CO 0.02 0.15

N2 0.00 0.01

Total 100.00 100.00

20.2.5. CO2 Purity Specification Requirements

The Capture CO2 delivery specification states a minimum 95% purity is required. The minimum CO2 purity value has been provided in the regulatory applications. Its purpose was to assure the approving agencies that the project sequestering basis is not compromised by delivering a low purity product, as the financial arrangements are based on pure CO2 actually sequestered underground.

The following describes the interventions that would be made if purity drops.

• Normal CO2 purity is 99.2Vol%. This is the design basis of the Capture amineabsorption facility.

• Contaminants normally present would be up to 27 ppmw glycol (TEG); from 4 to 6lbs H2O per MMSCF; plus residual H2/CH4 from the Stripper.

• The primary indication of CO2 purity will be from the compressor CO2 DeliveryAnalyser.

• There would not be any direct indication at the pipeline, as the CO2 is acompressible fluid in which liquid/vapour hammer is extremely unlikely. Howeverpressure drop would increase if a two-phase flow regime did develop.

• No safety hazard could be identified should this happen.

• The intervention proposed is to respond to 97.5% CO2 purity with reduction ofthrottle valve openings at the wellhead, to increase line pressure to >10 MPa. Thiswould ensure pipeline flow remains single phase down to 95% purity, or nominallyup to 5% hydrogen content. Capture operations would commence sourceinvestigation based on the downward trend, regardless of the other processindications listed above.

• If CO2 purity drops to 97.5V%, and if an immediate resolution is not possible, thenthe compressor would be placed into spillback mode, and pipeline delivery would beclosed at the Scotford battery limit.



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• There is the possibility of operating the pipeline below 9 MPa to save energy cost.This would be acceptable at normal CO2 purity. This is an optimisation availableduring operation, and does not alter design basis. Actual pipeline pressure is expectedto range between 8 – 13 MPa, determined by flow rate and well requirements.

• The pressure drop across the choke valves is in the range of 3 – 5 MPA, thus flashingwill occur with significant impurities are present. Well bottom pressure isapproximately 14 MPa above the choke pressure due to static head. Thus gasseswould re-dissolve en route.

• The upper compressor discharge pressure of 14 MPa is confirmed as design basis,noting however that this was a risk-based decision based on expected well start-uprequirements. At this pressure point on the compressor curve, the flow rate would be93% of design. Full flow is delivered at 12.3 MPag.



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Table 20.2.5 Pressure, Temperature and Flow Rates

20.2.6. Pipeline Operating Pressure

Pipeline Design Pressure 14.79 MPa @ 60°C

Maximum Operation Pressure 14.0 MPa

Minimum Operation Pressure (10% higher than Critical Pressure) 8.5 MPa

CO2 Critical Pressure 7.4 MPa

20.2.7. Pipeline Operating Temperature

The temperature of the CO2 leaving the Scotford Upgrader will be approximately 43°C. As the CO2 travels down the pipeline, heat is transferred to the soil. At approximately 20 km



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from Scotford, the CO2 will be at ground temperature. For the basis of design, a ground temperature of 4°C was assumed during summer and 0°C during winter .

Due to the fact that the CO2 is cooled throughout the pipeline length, it is deemed unnecessary to provide for thermal relief.

20.2.8. Flow Rates

The actual volume of CO2 injected will be determined by the operation of the CO2 Compressor at Scotford. The CO2 will be injected into 5 Injection Wells. All wells will be operating on Flow Control during normal operation. To maintain pipeline pressure to minimum value, low pressure override to flow controller will be provided and choke valve will close and maintain the pipeline pressure. In the event of higher pressure from well, a algorithm will be developed to calculate the amount of override signal requirements in relation to surface temperature at the well, will decide Choke valve opening which will prevent over pressurisation of the wells. .

20.2.9. Flow Rate Requirements

The basic requirement of the project is to store 10.8 million tonnes of CO2 over the span of 10 years of operation or the end of 2025, whichever comes first. Design capacity of the pipeline throughput is to be 1.2 million tonnes per annum. The CO2 pipeline is designed so that it could receive and transport up to an additional 2.2 Mtpa of CO2, in excess of the 1.2 Mtpa of CO2 that would be captured and sequestered as part of the Quest CCS Project.

20.2.10. Water Content and CO2 Phase Change Management

The CO2 will be dehydrated to a water content of 6 lb/MMSCF during summer and 4 lb/MMSCF during winter within the Capture facilities. A moisture analyser will be installed between the 6th and 7th stages of the Compressor. There will be a sampling procedure to cross check and to confirm the moisture analyser measurement. When the moisture content is above the set point, operator action is to take corrective action in the TEG Dehydration Unit and ultimately shutdown the stream to the pipeline and put the Compressor in recycle mode.

Based on discussions in the Operating Integration Meeting (of 1st and 2nd Aug, 2011) the general consensus was to (incorporate full compressor recycle and) stop forwarding CO2 to pipeline when moisture content in dehydrated CO2 increases to 8lbs/MMSCF. (Consider alarm at 7lbs/MMSCF.)

20.2.11. Design Life

Design life for the pipeline and associated surface facilities is 25 years.



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20.2.12. Pipeline Steel Grade

The linepipe steel grade is limited by fracture toughness for CO2 service. For the pipeline to be resistant to long running ductile failure, stringent material requirements around Charpy v-notch testing will be employed.

Initial requirements as tested by Shell Calgary Research Center indicate the main line pipe will be:

• Grade 386, Cat II, -45°C MDMT with Charpy impact results of greater than 60 Jouleswith a minimum 85% shear area.

Crossings and bends have not been evaluated; however, they may be a thicker wall pipe of similar material, or the next higher grade to account for thinning of bends or increased thickness requirements due to location. Appendix D shows the Line Pipe Specifications.

20.2.13. Right of Way Geotechnical Data

Right of Way Geotechnical Data and the AMEC Geotechnical Report can be found in Appendix G of the PDP/Pipeline Conceptual Design Report.

Soil samples have been taken for the entire pipeline right of way. As the pipeline is routed primarily through agricultural areas, there is not expected to be requirements for blasting (confirmed by a walk-through of the right of way during Define phase). Cobble is likely to be encountered, based upon landowner comments (included on Alignment Sheets). A soil report has been completed by Stantec, and is attached in Appendix M.

20.2.14. HDD Crossing Geotechnical Data

The project identified a need to cross the North Saskatchewan River (NSR) via Horizontal Directional Drilling (HDD), as recommended by the Department of Fisheries and Oceans (DFO) for an expedited approval process. The majority of the North Saskatchewan River near Scotford lies within the Beverly Channel. This is a paleo-valley in the location of the present day NSR. The Beverly Channel is substantially wider and deeper than the present day NSR, and is filled with unconsolidated sand and gravel glacial deposits. As such, the majority of the river near Scotford is not suitable for HDD crossing.

A tabletop geotechnical review was made on the area using hydrogeology maps available from the Alberta Geological Survey website. This identified a location that appeared suitable for an HDD and open cut methodology as a backup. Geotechnical fieldwork by AMEC has confirmed the site as suitable for HDD.

Entec has designed the HDD as an uncased crossing based upon the geotechnical study provided by AMEC. No further geotechnical studies are required.



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20.3. General Design Basis

20.3.1. Routing

The proposed pipeline route extends east from Shell Scotford along existing pipeline rights of way through Alberta’s Industrial Heartland and then north of Bruderheim to the North Saskatchewan River. The route then crosses the North Saskatchewan River and continues north along an existing Enbridge pipeline corridor for approximately 10 km and then travels northwest to the endpoint well, approximately 8 km north of the County of Thorhild, Alberta. The total pipeline length is about 81 km.

Each wellsite metering facility will include a regulating valve and coriolis flow meter. This meter will be used for leak detection and allocation. Production accounting will be done at the Scotford as part of the Capture facilities.

This pipeline will be located in the counties of Strathcona, Sturgeon, Lamont and Thorhild.

There are approximately 256 crossings to be performed on the Quest Pipeline. Of these, there are:

• 40 Road crossings

• 4 Railroad crossings

• 18 Watercourse crossings

• 73 Pipeline crossings

• 121 Utility Crossings



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Figure 1 – Quest CO2 Pipeline Routing



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20.3.2. Pipeline Location Class

The pipeline will use a Pipeline Location Class 2 as defined by CSA Z662 (latest version). This was chosen by Shell based upon commitments to landowners to install a robust pipeline based on a conservative design. Designing to Location Class 2 typically requires a greater wall thickness for general pipeline installation and emergency valves at a spacing interval of 15km max.

20.3.3. Pipeline Battery Limits

The total Quest project is broken into three parts: Capture, Pipeline, and Wells, which are handled separately by Fluor, Tri Ocean, and Shell, respectively. Because of the separation of responsibilities between these entities, interface management will be required for total project success.

Design interfaces are as follows:

• Fluor is responsible for the Capture and Compression facilities

• Tri Ocean is responsible for the pipelines and wellsite facilities.

• Shell is responsible for the wells and reservoir.

The break between Capture and the Pipeline is nominally at the first flange preceding the first pig launching facility. The pig launcher is to be fabricated as a module designed by Tri Ocean and delivered to site to be constructed by Fluor’s construction contractor. The delineation point for the construction contractors will be the bored crossing of the 138kV overhead power lines crossing south-north at the east side of the SWMF Disposal Well, which will be handled by the pipeline contractor.

The spec break from B31.3 to CSA Z662 will occur on the pigging package provided by and designed by Tri Ocean. This spec break will be upstream of the pig launcher and pig launcher kicker line.

Tri Ocean is responsible for the design up to the wing valve on the wellhead. An item of note is that connecting the down hole monitoring equipment and the sub surface safety valve panel is also included in Tri Ocean’s scope of work, although the down hole equipment and sub-surface safety valve will be installed by the Shell Wells group.

These limits can be seen on the Process and Instrumentation Diagrams attached in Appendix C.

Other interfaces will include Supervisory Control and Data Acquisition (SCADA) communications, where Tri Ocean’s design will have to interface with the design of the DCS at Scotford, designed by Fluor.



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20.3.4. Thermal Hydraulic Design Guidelines

A thermal-hydraulic design has been completed during Define phase.. The results of the flow assurance study have been incorporated into the progression of the system design. The design basis is to keep the CO2 in the pipeline in dense phase when operating at steady state conditions. The main flow assurance issues expected are due to hydrates and cold temperatures. In both cases, these issues can be mitigated by chemicals injection and/or operating procedures.

A flowline vent of 4” or smaller is recommended to keep temperature in main CO2 line above the minimum design metal temperature. Venting from both ends of any section of the pipeline is also recommended to avoid reaching extremely low temperatures.

Details of the hydraulic design can be found in the Flow Assurance and Operability report No. 07-2-LA-5507-0003.



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20.3.5. Mechanical Design Guidelines

20.3.6. Line Break valves

As per Class 2 requirements for CSA Z662, Line Break Valves will be spaced at no longer than 15km intervals. Based upon preliminary routing and access, the LBV sites chosen for this project, pending landowner approval, are located as per below.

• LBV #1 – 12-13-56-21 W4M,

• LBV #2 – 02-02-57-20 W4M,

• LBV #3 – 02-25-57-20 W4M,

• LBV #4 – 02-02-58-20 W4M,

• LBV #5 – 16-03-59-20 W4M,

• LBV #6 – 12-31-59-20 W4M, and

• LBV #7 – 02-21-60-21 W4M.

Table 5.5-1 Mechanical Design Data

General Units Value

Pipeline Material - CSA Z245.1 Gr. 386 Cat II

Material Toughness 60J @ -60°C, min. 85% shear area

Pipeline Location Class

(CSA Z662-2007)

2

LBV Sites # 7

Launching Facilities # 2 launchers, 3 provisions (laterals)

Receiving Facilities # 2 receivers, 3 provisions (laterals)

Main Flow Line Data:

Length km ~80.4

Size in NPS 12

Wall Thickness mm 12.7 (11.4 + 1.3 CA)

ASME Class - 900#

Laterals Data:

Number - 5

Length 50 - 4,200 (variable)

Size in NPS 6

Wall Thickness mm 7.9 (6.6 + 1.3 CA)

ASME Class - 900#



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The line break valves will be placed in areas near secondary roads, which allows for ease of access by operations and maintenance personnel. As these LBVs are located in populated areas, they will be fenced for security. Currently, the fencing is envisioned to be 5 foot chain link with three barbed wires on top to discourage unauthorized entry.

The LBV stations are expected to be enclosed in a cabinet style enclosure for weather protection. The cabinets shall be designed to keep the valve elevations at a working height from the ground surface.

In the event of a line break valve closure, the line break valve computer will send a signal to all line break valves to signal a close, thus minimizing loss of containment. The rate of closure should take 30 seconds from the open position to the fully closed position. This slow rate of closure will minimize the pressure surge (caused by the kinetic energy of the fluid) at the LBV.

After emergency shutdown due to a pipeline leak or rupture, the depressurized section will be brought up to temperature and pressure again slowly via the line break bypass valves, which also serve as temperature-controlled vents in the case of emergency.

Line break valves are expected to be actuated by hydraulic accumulators, and controlled via solar-powered RTU.

20.3.7. External Corrosion Protection

External corrosion protection will be provided by two complementary methods:

• Protective coating system (fusion bonded epoxy) applied on the outside surface ofthe pipeline, and

• Cathodic protection to protect any exposed steel surfaces.

20.3.8. Field Joint Coating System

Field joint coating systems are currently being evaluated for suitability. There are two methods that are candidates for use in Quest. The first method is brush applied epoxy, which is the traditional method of field coating FBE coated pipelines. The second method is a spray epoxy, which is more similar to the primary coating in thickness and application.

See 07-2-LA-7880-0005 for details on external coating and field joint coating systems.

20.3.9. Internal Corrosion Protection

The pipeline will have no internal coating. Internal corrosion protection will be provided by:

• The carbon dioxide stream will be dehydrated to 4#/MMSCF in the winter and6#/MMSCF in the summer.

• Isolation Valves designed with stainless steel trim



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The Integrity Reference Plan will be completed during the Execute phase. It is envisioned to contain:

• Pigging, dewatering and drying the line

• Batch chemical inhibition, if required,

• Preservation for period between mechanical completion and start-up

• Post start-up maintenance and inspection procedures.

20.3.10. Pipeline Leak Detection System

Leak detection is to be based upon the principles laid out in CSA Z662 Annex E as pertaining to HVP lines. Basically, the leak detection is based on material balance. Mass flow meter considered for this application at the Scotford battery limit and at the well head will be of custody transfer accuracy Coriolis type flow meter.

Both automated and manual emergency shut down systems will be utilized. Automated shutdown will be initiated when pressure transmitters indicate operating parameters outside of acceptable limits. Both (not just a single PIT) pressure transmitters at each LBV, must vote for a low pressure trip to confirm a line break incident.

Emergency shut downs can be initiated manually from each of the well sites or from Scotford when pressure, temperature, and flow transmitters indicate upset conditions such as leak or rupture.

During previous phase of project fibre optic leak detection system was evaluated and determined that it will not be further discussed mainly due to cost associated with that option.

20.3.11. Integrity Management

The design pressure of the pipeline system is 14.79 MPa @ 60°C, which exceeds the maximum discharge pressure of the Compressor. Therefore, supplemental over¬pressure devices such as PSV’s are not required for the pipeline.

Thermal relief valves are included on the filter vessels as required by B31.3. No thermal relief valves have been included on the pipeline, as the pipeline will not see thermal swings over 99.9% of the length due to burial depth. The pressure increases at the above ground sections will not be blocked in, and will have communication to the belowground pipeline which will absorb the pressure swings while remaining significantly below the design pressure of the pipeline.

Pipeline Corrosion Mitigation Program and Pipeline Integrity Plan



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As noted above, the site specific corrosion mitigation, monitoring and inspection program (Integrity Reference Plan) for the pipeline includes tasks associated with protecting and maintaining the pipeline integrity and includes the following requirements.

20.3.12. Internal Corrosion Mitigation

The compressed CO2 will be dehydrated prior to entering the pipeline. Under normal operating conditions, the water content is 4#/MMSCF in winter and 6#/MMSCF in the summer. This amount of water is absorbed in the CO2 stream and does not exist as “free water”. Without free water, the CO2 is not corrosive to carbon steel.

Water from hydrostatic testing or from in-line inspection (smart pigging) will be thoroughly removed by dry air to a dew point of -40°C or lower

20.3.13. Cathodic Protection

As per regulatory requirements and the project Pipeline Integrity Management Plan, cathodic protection will be installed for the Quest pipeline. It is currently envisioned to be an impressed current system for the entire line.

During the construction of the first segment of line, which will be installed by Fluor earlier in the project, temporary cathodic protection via sacrificial anode should be considered.

20.3.14. Monitoring

Continuous moisture monitoring will be maintained to ensure no moisture enters with the product into the pipeline.

Corrosion monitoring devices (corrosion coupons) in the pipeline will verify the corrosion rate.

Other routine monitoring activities will include:

• Product stream testing to confirm fluid compositions and process changes over thelife of the project

• Flow rates and pressures will verify pipeline superficial velocities

• Maximum operating temperature to confirm that temperatures do not exceed thedesign limits for the external protective coating systems

20.3.15. Inspection

An in-line inspection tool (smart pig) run of the Quest Pipeline is to be performed within the first year from startup to verify pipeline integrity. Frequency of repeat inspections will be based on results from this inspection, other surface inspections, and ongoing monitoring results on this pipeline.

Other inspection activities will include:

• Non-destructive Examination (ultrasonic thickness test) on above ground piping toidentify possible corrosion of the pipeline



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• During routine maintenance activities when parts of the surface facilities will beaccessible, perform internal visual examination of open piping and equipment to assess forany evidence of internal corrosion.

• Pipeline right-of way (ROW) surveillance including: aerial flights to check ROWcondition for ground or soil disturbances, 3rd Party activity in the area, etc.

20.3.16. Material Selection

Items that have been identified as a possible concern for CO2 pipelines include long running ductile fracture (LRDF) and explosive decompression of elastomers.

Shell Global Solutions, through Shell’s Calgary Research Center (CRC), has performed material testing in order to determine the appropriate elastomers to minimize explosive decompression and the appropriate grade of steel with sufficient toughness to resist LRDF.

Elastomer candidates from the explosive decompression program include FFK, HNBR and Viton. Further details of this testing can be found in Appendix D of the PDP/Pipeline Conceptual Design Report.

Results from the LRDF testing show that the toughness requirements for the line pipe are quite achievable in commercially available steel grades, as verified by past history. Specifically, CSA Z245.1 Gr. 386 Cat II pipe would need a minimum wall thickness of 11.4 mm plus corrosion allowance (1.3 mm), and a minimum toughness of 60J at –45°C.

This information has been included as a basis for the material selection diagrams.

20.4. Pipeline Construction & Installation

20.4.1. Pipeline Spreads

Pipeline construction is expected to occur starting September 1st 2013, with the commencement of the HDD of the North Saskatchewan River. Once the crossing is completed, the mainline pipeline construction will begin. The pipeline construction is expected to occur over the winter season of 2013/2014.

20.4.2. Pre-Construction Survey

A preliminary survey has been completed via desktop and Lidar information. This survey has been used for basic design and estimate purposes.

A physical field survey will occur after FID in the 1st half of 2012. This survey will be used for construction.

Prior to commencement of any construction activities, a Pre-Construction Survey shall be carried out to identify the pipeline centerline and to define the Right-of-Way (ROW) boundaries.



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During the survey and the establishment of the exact route of the pipelines, the following points will be considered:

• Location of Line Break Valve Stations

• Minimize the requirements for bending operations

• Minimize the requirements for dozing of ROW

• Determine the most appropriate techniques for crossings of roads, railways,highways, and confirm the crossing technique of watercourses

• Determine the crossing points of overhead power lines and telephone cables and thenecessity for any local re-alignments

• Additional lay down areas for special crossings

• Areas for temporary pipe dumps

While performing the route and profile of the ROW, the Surveyor will establish and confirm locations of all underground and aboveground obstacles and existing services, and establish a schedule of crossings to be marked up with appropriate safety warning signage and height restrictors.

20.4.3. Pipe Bends

As far as possible, the installation Contractor will provide the changes of vertical and horizontal alignment by elastic flexing of the pipeline within tolerances.

Shop cold bending is not be used and all shop bends will be by induction bending.

20.4.4. Induction Bends

Shop bends will be performed by induction bending, as the geometry of the pipe is critical to maintaining control on long running ductile failure. Pipeline induction bends shall be designed to accommodate any type of internal inspection tools in the pipelines, bends in the pipelines shall be minimum 20D radius.

20.4.5. Cold Field Bends

Field bends are permitted as per CSA guidelines.

Cold bends will be produced using a built-for-purpose pipe bending machine with smooth formers and mandrels that will not damage the external surfaces of the pipe as it is bent to preserve the cross-sectional shape of the pipe. Under no circumstances will heat be used for the purpose of the bending the pipe.

20.4.6. Crossings – Road & River

The preferred method for crossing is the trenchless method. The open trench method should be avoided and only considered when there is no alternative method.



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Uncased crossings are preferred. Any cased crossings will require electrical insulation, end seals, and cathodic protection for the carrier pipe.

Minimum vertical separation of 0.5 m should be kept between the pipeline and any other buried structures, e.g. existing pipelines, cables, foundations, etc.

The crossing of existing pipelines, cables, power lines, roads, railways and waterways should be at an angle between 60° and 90°, and in no case shall the angle be less than 45°.

20.4.7. Major Rail and Road Crossings

All rail and road crossings shall be cased.

Along the pipeline right of way, there are 3-4 rail crossings with an additional area where future railroad tracks are planned. These areas will need to have detailed crossing drawings as set by government regulation, Transport Canada E-10.

There are approximately 5 numbered highways along the right of way. These crossings will require agreements and details as set forth by Alberta Transportation guidelines.

20.4.8. Minor Gravel

Also along the right of way are numerous high grade township and range road crossings which will be required to have crossing agreements and details as per Alberta Transportation guidelines.

20.4.9. Crossing of Buried Services and 3rd Party Pipelines

It is anticipated that there are buried services in the area, as it is sparsely, but regularly populated. Buried services may include natural gas, cable, water and power lines. These items will be located in the surveys later in the project.

Lastly, there are a large number (over 100) of third party pipelines which will require crossing agreements with the third party owners.

20.4.10. Commitments

Commitments made during the initial public consultations include a burial depth of the pipeline to a minimum of 1.5 meters to top of pipe.

The counties of Lamont, Strathcona and Sturgeon have been identified to have occurrences of clubroot. As the majority of the pipeline crosses private agricultural land, there is a requirement to have a clubroot mitigation program in place. Shell has elected to follow the guidelines set forth by the Canadian Association of Petroleum Producers (CAPP) in conjunction with landowner requests.



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20.5. Special Crossings

20.5.1. Horizontal Directional Drill Construction Methodology

The North Saskatchewan River (NSR) crossing is expected to be completed by Horizontal Directional Drill. This is expected to commence on September 1st, 2013, after the Restricted Activity Period (RAP) on the North Saskatchewan River closes. The RAP for the NSR is April 15th to the 31st of August.

This crossing design will be awarded by competitive bid. The design and inspection will nominally be completed by the same company. Construction of the crossing will be completed by a company different from the design and inspection company, also selected through competitive bid.

Engineering design of the crossing has been completed by Entec, and the report is located within the Tri Ocean Vendor Documentation files.

20.5.2. Pipe Installation

Pipe installation will occur as per normal HDD operations.

There is an opportunity, however, as Enbridge is installing a pipeline directly adjacent and north of the Quest line in May 2013. If the Enbridge bore fails, they will install the linepipe via open cut commencing September 2013. If they are installing their pipe in this manner, they have tentatively agreed to install the Quest line concurrently. In this instance, consideration should be given to installing a spare line.

20.6. Pig Trap System

Pigging facilities will be included as part of the scope of work. These facilities will be used for maintenance and for post hydrotest dewatering/drying of the line.

Mainline pigging facilities will be installed at Scotford (launcher), just before the North Saskatchewan River (receiver and launcher) and the end point well (receiver).

Provisions for pigging facilities will be included for the lateral wells, however the launchers themselves will not be provided. It is not expected that IPCIT will be run on the laterals, as the laterals will be sistered to the mainline.

Pigging facilities will be designed for smart pigging.

The installation of pig traps should follow these guidelines:

• Pig traps should be located at least 15 m from any type of equipment, other thanadjacent pig traps.

• Pig trap systems should generally be located adjacent to each other for ease ofpigging operations.



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• Pig trap systems shall be fenced (either separately or as part of adjoining facilities)and access should normally be provided for light trucks and lifting cranes, subject tohazardous area classification constraints.

• A pig trap shall not point towards hydrocarbon containing equipment, safety criticalequipment, buildings, etc. to prevent these items from damage by a pig which might bereleased in case of a pig tap door failure.

20.7. Relief Philosophy & Pipeline Depressurization Facilities

Bottling in shall be the primary method of ceasing operations at all times. Venting is only to be considered if bottling in is not an option.

Provisions have been made to vent the pipeline at Scotford by back flowing through the main process line to a controlled vent line header which is connected to the main vent at Scotford.

Other forms of venting, i.e. maintenance venting and emergency venting of pipeline segments will be achieved through local venting. Local vent stacks will be required at all surface locations. Currently these are envisioned to be based upon the H-Stack design detailed in DNV JIP CO2 PIPETRANS.

Venting at the H-Stack must be done under the continuous supervision of Shell personnel. The wind direction must be monitored to ensure the CO2 plume does not threaten a nearby resident or his livestock. It is also advisable to install portable Air Quality Monitoring equipment at the resident’s yard prior to the venting operation.

Dispersion characteristics will require modeling and verification. This is expected to occur once the final locations of the Line Break Valves are set through the pipeline right of way acquisitions, and the issue of the Field Development Plan for the well sites.

It is estimated that blowdown will take approximately 1 hour per kilometer of mainline pipe.

20.8. Pipeline Electrical Philosophy

The Line Break Valves are expected to have a small load (less than 500W) and are envisioned to be powered by Solar panels. Design of the solar panels will occur in the Execute phase of the project.

The wellsites are intended to have grid power for a load of 4kW.

The locations of LBVs and Wellsites to be finalized in Execute phase. A preliminary location of LBV’s is provided in Section 5.6.

20.9. Pipeline Instrumentation and Control Philosophy



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Tri Ocean Engineering scope of work consists of the following:

• Design and installation of a new pipeline and wellsite SCADA system that includes alocal RTU at each well site and all the associated site instrumentation (see instrument index)for monitoring, control and shutdown. This system function is to include the collection andtransmission of data from the pipeline and well sites back to the capture facility (Scotford)control room.

• The CO2 capture facility, constructed within the Scotford Plant battery limit, will beexecuted by others. This facility will require both hardwired and a communication interfacewith the master SCADA PLC. These interfaces will transfer process data from the capturefacility (i.e. the local metering skid, the moisture analyzer, etc.) for control and shutdown ofthe pipeline. The metering skid will be used as an integral part of the leak detection on thepipeline system.

• The wellhead choke valve will operate with a flow control set point along with lowpressure pipeline (to maintain pipeline in supercritical state) override and high pressurewellhead override (to avoid exceed subsurface fracture pressure).

Details of the control philosophy can be found in Appendix G Control Narrative and Appendix H Cause and Effect Diagrams (Shutdown Key).

20.10. Pre-commissioning, Commissioning and Start up

20.10.1. Hydrotesting, Cleaning, and Drying

As part of the design and installation requirements for the pipeline, to mitigate the potential for corrodents, additional measures including the following will be incorporated:

• Measures such as pigging and drying to a dew point of at least -40°C to removeliquids following hydrostatic pressure testing

• Application of a batch corrosion inhibitor prior to going into service

• The pipeline should also be free of debris to mitigate against loss of injectivity.

A guideline for dewatering, cleaning, drying and the pipeline has been written for the pipeline and will be provided to the pipeline contractor for estimating and implementation.

20.10.2. Preservation

Once the pipeline has been hydrotested, it will be cleaned, dewatered, and dried to a dew point of -45°C. When this is completed the entire system will be placed in suspension with a dry nitrogen blanket at 175 kPag.



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A guideline for dewatering, cleaning, drying and the pipeline has been written for the pipeline and will be provided to the pipeline contractor for estimating and implementation.

20.10.3. Initial Fill

Filling and pressurization with CO2 will be done at a very slow rate with dry CO2.so that the minimum temperature (-45°C) is not reached.

Alternatively, the pipeline can be pre-filled with dry nitrogen up to 1000 kPa (150 psig) prior to CO2 pressurization process to avoid pipeline cooling to very low temperatures during filling.

20.11. Operation and Maintenance

Operation and Maintenance of the pipeline will be assumed by Scotford Upgrader Operations.

20.11.1. Operation and Staff

The pipeline and surface facilities of the CO2 pipeline must operate locally, with remote monitoring, control and shutdown functionality from Scotford as well. All sites are to be designed for unattended operation.

Control of remote operations is new to Scotford, and this project will be integrating a field facility into what is essentially an oil refinery. As such, special consideration must be made when developing or determining operating procedures.

20.11.2. Control Room and Offices

The existing control room at Scotford Upgrader will be used to control the pipeline operations.

20.11.3. Reliability

The pipeline has a reliability factor close to 100%. Thus, the pipeline and wells were found not to contribute significantly to downtime of the CO2 capture system. Reference is made to report GS.10.52419 Quest CCS Project RAM Study – Final Report.

20.11.4. Emergency Response Planning



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An emergency response plan has been developed for the pipeline and well sites. This ERP will be integrated into the Scotford emergency response system.

It is noted that this ERP is not required by the regulatory body within Alberta (ERCB), but will be completed by Shell as normal operating practice.

20.12. Future Expansion

The CO2 pipeline is designed so that it could receive and transport up to an additional 2.2 Mtpa of CO2, in excess of the 1.2 Mtpa of CO2 that would be captured and compressed as part of the Quest CCS Project.

There are plans to have facilities to supply third parties consumers such as EOR operators, for this purpose, Quest pipeline will be fitted with a 12” -900# valve blinded off tie-in connection.

The tie-in connection for EOR operators will be located in the raiser of LBV-1, right upstream of LBV-1. The location was selected taking into account the following:

· Third party does not need to access Scotford plant

· Area close to route of EOR operators pipelines heading to their EOR fields

· LBV raiser is fitted with communication via SCADA system

· No need for a specific raiser for tie-in

· There are venting facilities at this location

Meter station for EOR’s operator supply will be provided and installed by EOR operator. Flow, pressure and temperature indication to be sent to Scotford whenever third party supply is implemented via Quest Pipeline SCADA.

20.13. Health, Safety, Security, and Environment (HSSE)

20.13.1. General Philosophy

The Hazard Identification (HAZID) study and Coarse Hazard and Operability (HAZOP) study have been performed on this project. The Coarse HAZOP results can be found in Appendix K of the PDP/Pipeline Conceptual Design Report.

Further safeguarding will be required, with a minimum requirement for a detailed HAZOP and a Safety Integrity Level (SIL) Evaluation of the pipeline. If required due to project changes, a HAZID or Coarse HAZOP can be revisited.



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20.13.2. Isolation Philosophy

Double block and bleed will be used to isolate systems within the pipeline and wellsites. The systems are:

System 1 – Pig Launcher at Scotford to the Pig Receiver at LBV 3

System 2 – Pig Launcher at LBV #3 to the wellsties, including lateral lines

Systems 3-7 – Individual wellsites, from the pigging provisions to the wellhead

Double block and bleed will also be used to isolate the pigging facilities for use, as well as the vent stacks at the line break valves. Line break valves will not have DB&B isolation, save for at the system boundaries.

Meter prover taps at the wellsite will have DB&B capability.

20.13.3. Simultaneous Operations (SIMOPS)

While no instances of SIMOPS are envisioned for the pipeline and wellsite portion of Quest at this point, items that may require observation include:

• Pipeline Installation and North Saskatchewan River crossing – SIMOPS potential withEnbridge 30” and 24” pipelines (currently May 2013)

• Wellsite Facilities – SIMOPS potential with Wells Pipeline construction in Scotford willbe completed by Fluor, who will mitigate the SIMOPS potential inside battery limits(ISBL).

20.13.4. Emergency Planning

Unplanned venting of the pipeline system has been studied with a Quantitative Risk Analysis (QRA). The draft version of the final QRA can be found in Appendix J of the PDP/Pipeline Conceptual Design Report. Additional information regarding Emergency Planning for the Quest Project can be found as a subset of the Key Design Challenges section of the PDP/Pipeline Conceptual Design Report.

20.13.5. Safety Equipment

The Quest CCS wellsite filters will be equipped with thermal pressure relief valves in order to relieve pressure buildup in the case of unexpected, substantial increases in CO2 temperatures. These TRVs will release to a safe location on lease.



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21. SUBSURFACE SCOPE OF WORK

21.1. Overview

The Quest project will require 3 to 8 wells to inject the CO2 into the BCS for storage . The wells will be connected to the main 12” pipeline by 6” laterals, all assumed to be less than 15 km long. The BCS is overlaid by a number of formations which provide containment for the CO2. The base case considers a 5 well development although the results of the Radway 8-19 appraisal well drilled Q3 2010 has highlighted an opportunity to reduce the well count to 3 going forward. This has been built into the project planning and is reflected in the phasing of the drilling and staged pipeline purchase and development. This means that in 2012 after drilling development wells 2 and 3 there is a major decision to be made in terms of final number of wells and therefore an update to this document required.

The storage components are accompanied by a detailed Measurement, Monitoring and Verification program [ref. 21.2] designed to prove containment and conformance both of which are key criteria to support the final site closure and hand-over of liability to the Crown at the end of project life. Some elements of the MMV scope are tightly tied to the final number of injection wells such as the number of groundwater and deep monitoring wells and will also need to be revisited in 2012.

The storage facilities involve constructing:

· The drilling and completion of three to eight injection wells equipped with opticfiber monitoring system

· A skid mounted module on each injection well site to provide control,measurement and communication for both injection and MMV equipment.

· The drilling and completion of a minimum of three deep observation wells

· The conversion of Redwater 3-4 to a deep BCS pressure monitoring well

· The drilling of three groundwater wells per injection well (although not all will belocated on the well pads).

· A field trial of the line-of-sight CO2 gas flux monitoring technology in Q4 2011with option to include this at each injection well site location

The full description of the Quest Subsurface Scope is contained in the Storage Development Plan (SDP) [ref. 21.1]. It describes:

· Storage site selection and evaluation,

· Containment, storage capacity, injectivity and conformance

· Well engineering and production technology

· Measurement, Monitoring and Verification (MMV) plan

· Asset management

· Subsurface project execution plan

· Subsurface start-up and commissioning



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· Closure, post closure, decommissioning and abandonment

Rather than repeat the extensive information contained in the SDP, this Basic Design Package will only described the key interface between Quest Capture Pipeline and Wells Scope with is Flow Assurance aspects .

21.2. Integrated Production System

21.2.1. Compression & Pipeline Requirements

The integrated production system was first modeled to evaluate the operating envelope of the system and size the compressor and pipeline. The General Allocation Package (GAP) within the Petroleum Experts Integrated Production Modeling (IPM) toolkit was used to confirm a compressor with a 14.5 MPa discharge pressure is sufficient to provide the necessary wellhead and bottom hole pressures to inject the minimum 1.2 MT/yr CO2 required for the Quest CCS project under the conditions studied (100% up-time of facilities and injection).

Quest’s integrated injection modeling system includes the integration of the surface network with the well model, as shown on Figure 21-1: Example of Quest GAP network connecting surface components and

wells.

Figure 21-1: Example of Quest GAP network connecting surface components and wells

GAP was used to model the pressure and temperature losses across the pipelines from the compressor (i.e. Injection Manifold) to the wellheads (red triangles). This wellhead pressure and



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temperature was then used by a Prosper well model to model the bottom hole pressure and temperature at the top perforation.

21.2.2. System Operating Envelope

The changes in pressure and temperature throughout this injection process are illustrated in the CO2 phase envelope below Figure 21-2: Quest CO2 pressure and temperature conditions from surface compressor

outlet to injector bottom hole conditions, which shows CO2 remaining in the liquid or supercritical phase at all times. The arrows in the phase envelope indicate the direction of flow from the compressor, through the pipelines to the wellheads, down the wellbore and into the reservoir.

Figure 21-2: Quest CO2 pressure and temperature conditions from surface compressor outlet to injector bottom hole conditions

The following scenario’s were evaluated to ensure that a 14.5 MPa compressor could deliver sufficient injection pressures in each of these surface scenarios, for the low case reservoir permeability of 20-50 mD:

· A four and five well count scenario was compared against a 10, 12, and 16 inchnominal pipeline size.

· A seven well count scenario with a 10 inch NPS pipeline was compared against 3.5”and 4.5” tubing.



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· A winter and summer scenario for a 31°C and 60°C compressor discharge temperaturewere modelled to capture the range of realistic temperature losses attainable from thecompressor to the wellhead.

GAP modelling shows a 14.5 MPa compressor discharge pressure is more than adequate to provide the necessary wellhead and bottomhole pressures to inject the minimum 1.2 mtpa CO2 required for the Quest CCS project for all the surface scenarios modelled.

Whilst a 10 inch pipeline would provide adequate capacity, the decision was made to move forward with a 12 inch pipeline in the base case. This permits additional capacity to be added to the system at a later date should the opportunity arise.

The detailed results of this study can be found in the “Quest IPSM Compressor Design Modelling Results” [ref. 21.3].

21.2.3. System Operational Philosophy

The operational philosophy for the wells is as follows:

o The wells will be operated by flowrate setpoints to spread injection over the different wells,with built-in automated overrides

o The flowrate will be measured at each wellsite and at the pipeline inlet

o If the pipeline pressure decreases below 8.5 MPa, the well chokes will start to close tomaintain the minimum pipeline pressure. If the wellhead pressure increases above the maximumallowable injection pressure (10 to 12 MPa depending on wellhead temperature), the well chokeswill start to close to decrease wellhead injection pressure

o If the wellhead pressure drops below 1 MPa (proposed value) the SC-SSSV will beautomatically closed

o If the water content goes above specifications (proposed threshold is 8ppm), thecompressor will automatically go in recycle mode.

o If the Hydrogen content goes above specifications (proposed threshold is 2.5%), thecompressor will automatically go in recycle mode.

The injection policy is based on a 1-spare well capacity so that sufficient injection can be ensured even if one well is shut-in (e.g. for workover) and is constrained by a maximum downhole injection pressure of 28 MPa.

21.2.4. Integrated Production System Controls

The table 21.1 below summarises the integrated system operating envelope, and the different automated alarms and controls attached to it. This is the base design premise across all aspects of the Quest Project.

Measurement Measurement

point

Minimum

Operating

Maximum

Operating

Alarms* Control



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value value

Pipeline

Pressure

Pipeline inlet 8.5 MPa 13.9 MPa High: 14* MPa High: Spillback of compressor starts in

order to reduce pipeline pressure below

maximum setpoint.

This alarm overrides any other control

as it is safety critical.

Pipeline outlet

(upstream of

well choke)

8.5 MPa 12.9 MPa Low level 1: 8.5*

MPa

Low level 2: 8* MPa

Level 1: well choke start closing to reduce

injection rate.

Level 2: in case well chokes fail to

maintain pipeline pressure above

minimum, the well ESD valve will close at

the well pad where the low pressure alarm

goes off.

LBVs 8.5 MPa 13.9 MPa 7* MPa In case the pipeline pressure drops below

normal minimum pressure (even with the

ESD valves closed), the LBVs will close

automatically (pipeline leak detection).



Pipeline Inlet

Temperature

Pipeline inlet 43 degC 60 degC Level 1: 49* degC

Level 2: 60* degC

Level 1: alarm in Scotford control room

to investigate abnormal performance of

the cooling system.

Level 2: shutdown to protect pipeline.

Pipeline

flowrate

Pipeline inlet 0 Mtpa 1.2 Mtpa No alarm required Pipeline flowrate is controlled by the wells

flowrate operator setpoints.

Wellhead

Pressure

Downstream

of well choke

3.5 MPa 12 MPa Low alarm: 1* MPa

High alarm: 10*-12*

MPa (will depend

on wellhead

temperature, to

ensure bottomhole

pressure does not

exceed 28 MPa)

Low alarm: Alarm in Scotford and closing

of the SC-SSSV (blowout detection).

High alarm: Well choke will automatically

start to close until wellhead pressure is

below maximum allowable value.



Downhole

Well Pressure

Bottom of

completion

20 MPa 28 MPa 27* MPa Alarm in Scotford control room to

investigate high well pressure (consistency

with wellhead pressure).

Wellhead

temperature

Downstream

of well choke

-10 degC 26 degC No alarm required Wellhead temperature controlled by

choke and CO2 pipeline outlet



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temperature.

Downhole

temperature

Bottom of

completion

15 degC 60 degC No alarm required Downhole temperature controlled by well

flowrate and wellhead temperature.

Well flowrate Upstream of

well choke

0 Mtpa 0.6 Mtpa No alarm required The flowrate is an operator setpoint. The

choke will automatically open or close to

meet the set point, within the allowable

pressure envelope.

H2 content Pipeline inlet 2.5% 0.67%

(normal)

Level 1: 1.5%*

Level 2: 2.5%*


to investigate abnormal CO2 purity, well

chokes are manually adjusted to raise

pipeline pressure to 9* MPa to maintain

single phase flow.

Level 2: compressor enters automatically

recycling mode to protect pipeline and

wells, and ESD closes after a delay.

Water content TEG unit

outlet

4

lbs/MMscf

6

lbs/MMscf

Level 1: 7*

lbs/MMscf

Level 2: 8*

lbs/MMscf


to investigate abnormal water content.

Level 2: compressor enters automatically

recycling mode to protect pipeline and

wells, and ESD closes after a delay.

* Note: these values will be confirmed in the next phase of the project

Table 21.1: Integrated System Operating Envelope and Controls

The table above describes the main signals and controls related to pipeline and wells operations. More details on well pads measurements and controls are given in the SDP [ref. 21.1].

21.3. Flow assurance

This section covers at a high-level the Flow Assurance aspects related to the pipeline and the wells, that consisted of several studies and simulations performed to identify, quantify and mitigate any potential flow assurance issues.

21.3.1. Flow Assurance Scope for the Project

The following items were studied by the flow assurance team:

· System Designo Pipeline

§ Thermal-hydraulic performance§ Pipeline sizing§ Maximum system capacity



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§ Insulation requirements§ Vent-valve design§ Requirements for above-ground sections

o Wells§ Pressure-temperature in the wellbore with varying flow rate and

injection temperature§ Cooling at the well choke§ SC-SSSV location

· Solid Deposition Risko Hydrate risk and mitigation in pipeline and wellso Dehydratation limitso Solids in the injection streamo Impact of carryovers

· Multiphase Flowo Two-phase flow in pipeline and wellboreo Slugging screening

· Operabilityo Normal operationso Low flow eventso Emergency pipeline leak / blowdowno Emergency wellbore blowouto System start-upo Vent line operabilityo Liquid hammer screeningo Low water content operability

· Modelingo Impact of impuritieso Applicability of simulators

Each of these elements can be found in the different Flow Assurance presentations and reports issued as part of this project [Ref. 21.4, 21.5, 21.6, 21.7, 21.8, 21.9, 21.10]. A specific note on the pipeline hydrate risk was also issued [Ref. 21.11].

The first part of the Flow Assurance study was to support the sizing of the system (pipeline and wells) and confirm the performance of the pipeline following the design based on the IPM toolkit.

The second part of the Flow Assurance study was to simulate all operational scenarios using OLGA® (steady-state injection, start-up, low flow injection, shut-in, leak,...) and identify the potential issues, safety critical or operational, and recommend mitigation measures.

The strategy related to the main flow assurance risks are developed in the next section.



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21.3.2. Flow Assurance Strategy

21.3.2.1. System Design

21.3.2.1.1. Maximum system capacity

For a given operating pressure, there is an operability envelope for each well depending on the well injectivity. Practically, this means that there are a minimum and maximum number of injection wells that can be operated at a given time. Figure 21-3 shows the operability envelope developed for well 1. The figure includes the operating lines for both the well (for a given reservoir injectivity) and the pipeline over the range of operating pressures. The intersection of the well and pipeline operating curves defines the maximum injection rate into the well. An additional constraint given by the maximum bottomhole pressure is also shown. With this information, the maximum injection rate into a well can be determined and hence the total number of wells required.

Figure 21-3: Operating line for Well 1 with the normal composition

21.3.2.1.2. SC-SSSV depth setting

Simulations were completed to identify the closing depth of the SC-SSSV based on a single phase and a hydrate stability criteria. Basis this, a depth of 1,000 m was recommended to ensure that the valves is in the single phase, liquid region during a blowout and that the temperatures at this location are sufficiently high to avoid hydrate formation. In this scenario, it was envisaged that the SC-SSSV only closes in the event of a well blowout. Figure 21-1 shows the predicted liquid level and hydrate formation level as a function of time. Given than hydrate formation with free water will not occur until a significant time into the blowout process (>10 minutes), the liquid level in the well defines the required depth setting of the SC-SSSV.



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Figure 21-1: Safety valve setting based on single phase and hydrate criteria

21.3.2.1.3. Solids Deposition Risk

21.3.2.1.4. Hydrates mitigation

A key flow assurance risk is related to the hydrate formation in the injection stream. Figure 21-5 defines the hydrate stability boundary for the base composition. Note that two sets of curves are shown to illustrate the uncertainty in the hydrate prediction for this fluid at high pressure (i.e. single phase region). The hydrate strategy is based on the more conservative approach which requires a more stringent dehydrate requirement of the injected fluid.

Pipeline: the risk of hydrate formation in the pipeline during steady-state, low flow and shut-in conditions was studied and the dehydration requirements to mitigate hydrate formation was determined and implemented (6 lbs/MMscf in summer to 4 lbs/MMscf in winter)

Well: despite the large pressure drop across the well choke that generates significant cooling, simulations have shown that over the operating envelope of the integrated system, the well choke should always be outside of the hydrate formation zone, considering the dehydration requirements mentioned above. Temporary methanol injection upstream of the well choke is an additional mitigation strategy that was included in the well surface kit design.



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Figure 21-5 Predicted hydrate curve for composition during normal operation and uncertainty in predicted values

21.3.2.2. Multiphase Flow

21.3.2.2.1. Single-phase requirement

The first main element of the flow assurance study was to investigate the impact of two-phase CO2 in the pipeline and wells. It was concluded that one-phase CO2 was a requirement in the pipeline for the following reasons:

· Two-phase CO2 can induce slugging which can give pressure and temperatureinstability in the system, in particular at the well choke

· One-phase CO2 maximise fluid density and minimize fluid viscosity, thereforeoptimising pipeline transportability

· The metering system on each wellpad loses accuracy to +/-20% which isunacceptable because of the metering requirement and the fact that unlike mostprojects the meter at the wellhead is the custody transfer meter for a CCS project ascredits are issued at the point of storage.

· Single phase liquid CO2 will prevent hydrates from forming at any temperature

With the inclusion of online CO2 analysers within the Capture scope assuring CO2 purity, the minimum operating pressure of the pipeline is 8.5 MPa.

21.3.2.3. Operability

21.3.2.3.1. System Startup

The last main element of the flow assurance study was to look into pipeline pressurisation and controlled blowdown of parts of the system to ensure that the resulting cooling did not induce safety risks related to the minimum temperature rating of the equipment.



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As per the model it will take some 96 hrs to pressurize the pipeline to reach the minimum operating pressure, it is not an intuitive process, for the first 20 hours, the pipeline pressurizes until reaching the 2-phase region. Then, for the next 40 hours, the pressure and temperature both rise. What is happening is that the CO2 in the pipeline must condense and thus releasing heat. This heat is absorbed by the CO2 causing the temperature to rise even above the compressor temperature at the inlet. For about 16 hours, the pressure plateaus. The condensation at this point is complete and the liquid in the pipeline starts to cool. Due to the strong density dependence with temperature, the inflow is only compensating for the reduction in volume due to cooling. Finally, at about 96 hours, the pressure starts to quickly rise.

21.3.2.3.2. Vent Line Operability

During venting as consequence of J-T effect, the pipeline could reach extremely low temperature if the venting rate is not controlled. To prevent reaching temperatures lower than -45degC , it was determined that vent’s valve size orifice must not exceed 4inches diameter. Topography also has its effect on venting, as CO2 in dense and liquid phase tent to accumulate at the low points of the line, it is recommended to vent any segment of the line from both ends to allow a more uniform temperature gradient along the segment.

21.3.2.3.3. Fluid Hammer

In general, pressure surges exceeding design values are not observed when closing the LBVs, wellhead choke, or SC-SSSV. One issue that was observed occur when the wellhead choke is suddenly closed during the injection of the full design rate of 1.2 Mtpa into a single well while the system is operating at the maximum design pressure of 140 bar. Figure 21-6 shows the expected rise in pressure upon for the highest risk case when the wellhead choke is suddenly closed. When used with Figure 21-3 to get the wellhead pressure, the absolute pressure at the wellhead can be determined. This effect can easily be mitigated by operating the system at lower pressure, so that any rise in flowline pressure is below the pipeline design pressure.



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Figure 21-6: Pressure increase in well branch upon closing well choke at maximum injection rate of 1.2 Mtpa

21.4. Well pads layout

Figure 21.4 presents the typical pad layout for Quest, with all the potential MMV equipment that could be installed.

130m

13

0m

Injection well

Deep MMV well

Water MMV well

Line of Sight

Power/Data line

Data/ControlsSC-SSSV: Subsurface SV

GP: geophones

P/T: Pressure&Temperature

HT: Heat tracing

DL: Datalogger (on battery)

DTS/DAS

CP: Cathodic protection

AP: Annular pressure

FM: Flow meter

WC: Well chok

ESD: Emergency shutdown

DAS

DTS

P/T x 2

CP

AP

SC-SSSV

HT

P/T x 2 + dP

FM + WC

ESD

Filter

DL

DL

DL

GP

DAS

DTS

AP

CP

40m

minimum

40

m

min

imu

m

40m

minimum

40

m

min

imu

m

Enclosed skid with

climate control and

communication systems

Ga

te



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Figure 21-4: Well pad layout

Each injection well pad will include: 1 injection well, at least 1 groundwater MMV well and possibly 1 deep MMV well. The injection well pad will have a connection to the power grid and an enclosed skid to house computers for operating MMV instruments. SCADA communication system will be installed for the operational and safety critical elements (e.g. ESD) and an independent communication system will continuously transmit the large volume of MMV data to Scotford and Calgary centre.

Depending on the number of injection wells at start-up, the well pads will have the following configuration:

3 Injectors 4 Injectors 5 Injectors 8 Injectors Locations

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

Injectio

n W

ell Pad

s



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

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

Type 1 15-1-59-21W4

Type 1 15-29-60-21W4

Type 1 12-14-60-21W4

Where:

· Type 1 includes:- Injection well- Project groundwater well

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

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

More details on the MMV plan and requirements are available in the MMV Plan [ref. 21.2].

21.5. References

[21.1]: Quest Storage Development Plan, S. Crouch, 07-0-AA-5726-0001, August 2011 [21.2]: Quest Measurement, Monitoring and Verification Plan, S. Bourne, 07-0-AA-5726-

0002, August 2011



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[21.3]: Quest IPM Compressor Design Modeling Results, C. Clark, 07-3-ZG-7180-0004, October 2010

[21.4]: Quest CCS Project: Flow Assurance, Concept Design & Operability, September 2009 (Presentation), L. Dykhno & S. Anderson

[21.5]: Quest Update: Flow Assurance Transient Studies, January 2010 (Presentation), L. Dykhno & R. Lacy

[21.6]: Quest CCS Prospect: Flow Assurance for System Selection, November 11, 2010 (Presentation), R. Lacy, L. Dykhno, D. Peters & U. Andresen

[21.7]: Quest CCs Prospect: Flow Assurance for System Selection, March 10, 2011 (VAR 3 Report) R. Lacy, L. Dykhno, D. Peters & U. Andresen

[21.8] Quest CCS Prospect: Flow Assurance Evaluation of Low Flow Events, February 2011 (Intermediate Report) D. Peters, R. Lacy & L. Dykhno, 07-2-LA-7180-0004

[21.9]: Quest Update: Determination of Vent Line Size & Update to Hydrate Risk, May 3,2011 (Presentation) D. Peters, R. Lacy & L. Dykhno

[21.10]: Quest project Fluid Flow and Flow Assurance Report - SR.11.12758, D. Peters, R.Lacy, N. Seunsom & L. Dykhno, August 2011

[21.11]: PT Note for File - Hydrate assessment, V. Hugonet, April 2011

22. PROJECT APPROACH TO NOVELTY

As part of the overall project quality plan the Flawless Startup initiative will be employed on all three components of the project. Flawless Start-up Initiative (FSI) is aimed at enhancing the capability of the project to deliver the facilities for successful first-time-right start-up. It encompasses a systematic approach to ensure successful commissioning & start-up (CSU) and first cycle operation of a facility. The Flawless initiative incorporates 10 focus areas (10 Qs) to address project areas with a history of affecting successful start-up. With respect to FSI, novelty is Q06.

Novelty is defined in this context as any new process, prototype equipment or novel application with which there is no operating experience yet. In a broader sense this also includes new man-machines interfaces, new ways of working and new staff not experienced with the particular operation or equipment.

The policy with respect to novelty is to have an open mind for it and the benefits that it can bring and to manage carefully the risks and uncertainties that are an intricate part of novel features. It is realized that the management of novelty has its own methods and requires precautions commensurate to the risks. The policy is not to avoid novelty.

The process to manage novel features in plants consists of four preparation and one execution stage:

-identification-classification



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-generation of proven alternatives-mitigation measures to manage the novel aspects-monitoring of initial performance.

The overall goal of the Novelty Q in the Select phase is to identify novelties on Quest so that operations can prepare an adequate operating philosophy as the project matures through, Feed, Execute and Operation phases. Novelty workshop assists in defining technical needs for areas of the project where uncertainty still exists (subsurface, pipeline operation etc.). During the Select Phase workshop the project team achieved the following w.r.t novelty:

· Expanded initial list of novelties using brainstorming type exercise with workshopparticipants particularly novelty created by interdependence of Capture, Pipeline andsubsurface design or operation

· Identified owners for novelty items

· Frame mitigations for high impact or “most novel” items

During the novelty workshop sessions conducted in September 2010, the project team and external participants were consulted to document any novel aspects of the project scope including Capture Pipeline & subsurface scope.



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23. APPENDICES

A1 CO2 Capture, Compression and Dehydration (Unit 246, 247)

A1.1 PFDs

A1.2 P&IDs

A1.3 Heat and Material Balances

A1.4 Sized Equipment List

A1.5 Licensor Reports with Datasheets Provided

A1.6 Cause and Effect Diagrams

A1.7 Overall Utility Summaries

A1.7 Battery Limit Stream Summary

A1.8 Chemical Summary

A2 HMU 1/2/3 Revamp

A2.1 Revised PFDs

A2.2 P&IDs

A2.3 Revised Heat and Material Balances

A2.4 Revamp Equipment List

A2.5 Preliminary MTO’s

A2.6 Licensor Reports with Datasheets Provided

A3 Tie-ins and Interconnecting Lines

A3.1 PFDs

A3.2 Marked-up P&IDs

A3.3 Battery Limit Table (Tie-Ins)

A4 Site and Plot Plans

A5 Technical Decision Notes

Pipeline Appendix A Acronyms and Abbreviations

Pipeline Appendix B Process Flow Scheme

Pipeline Appendix C Process and Instrumentation Diagrams (P&IDs)

Pipeline Appendix D Line Pipe Specifications



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Pipeline Appendix E Piping Material Specifications

Pipeline Appendix F Coating Specifications

Pipeline Appendix G Control Narrative

Pipeline Appendix H Cause and Effect Diagrams (Shutdown Key)

Pipeline Appendix I Instrument Index

Pipeline Appendix J Alignment Sheets and Crossing Drawings

Pipeline Appendix K Line List

Pipeline Appendix L Regulations, Codes and Standards

Pipeline Appendix M Stantec’s Soil Report

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