Heavy Oil
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
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Revision History
Rev.
REVISION STATUS
Date
Description
Originator
APPROVAL
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
Manoj Dharwadkar
Steve Peplinski
04
04
2011-09-13
2011-10-04
Manoj Dharwadkar
Manoj Dharwadkar
Steve Peplinski
Steve Peplinski
·
Limited Updates for
ITR4
Issued for VAR4
Approved
Anita Spence
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
2011-10-04
2011-10-04
Signature or electronic reference
(email)
Role
Name
Originator
Manoj
Dharwadkar
Reviewer
Steve Peplinski
Email and in Assai
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 .................................................................................... 11
1.1. General ................................................................................................... 11
1.2. Overall Quest CCS Project Drivers for Design ............................................... 11
1.3. Scope of BDEP ........................................................................................ 12
1.4. Design Case Definition .............................................................................. 12
1.5. Contributors ............................................................................................ 13
1.6. Key Reference Documents ......................................................................... 13
2.
GENERAL DESIGN CONSIDERATIONS ........................................................ 14
2.1. Process Unit Capacities .............................................................................. 14
2.2. Feedstock Specifications............................................................................. 15
2.3. Product Specifications ............................................................................... 15
2.4. CO2 Specific Design Philosophy / Guidelines for Quest .................................. 16
2.4.1. Venting and Relief of CO2 Vapour ....................................................... 16
2.4.2. Supercritical CO2 Venting .................................................................. 16
2.4.3. High Pressure CO2 Equipment ............................................................ 17
2.4.4. CO2 BLEVE............................................................................... 17
2.4.5. Metallurgy ..................................................................................... 17
2.5. Sparing Philosophy ................................................................................... 18
2.6. Cooling Philosophy ................................................................................... 18
2.6.1. HMU 1, 2 and 3 (Brownfield) ............................................................. 18
2.6.2. Amine Regeneration and CO2 Compression (Greenfield) ................................ 18
2.6.3. Air Cooling ................................................................................... 19
2.7. Operating Philosophy ................................................................................ 19
2.7.1. Hydrogen Manufacturing and CO2 Capture .............................................. 19
2.7.2. Amine Regeneration, CO2 Compression and Transport ................................. 20
2.8. Unit Availability........................................................................................ 21
2.9. Turndown Requirements ............................................................................ 21
2.10. Interface with Existing Facilities .................................................................. 21
2.11. Meteorological and Site Data ....................................................................... 23
2.12. Units of Measurement ............................................................................... 25
2.13. Instrumentation and Control Philosophy ....................................................... 25
2.14. Project Design Standards and Codes ............................................................. 27
2.15. Engineering Documents and Unit Numbering Standards .................................. 29
2.16. Class of Facilities ...................................................................................... 30
2.17. Modularization Approach ........................................................................... 30
HEALTH, SAFETY, ENVIRONMENT AND SUSTAINABLE
DEVELOPMENT ........................................................................................... 32
3.1. Overview ................................................................................................ 32
3.
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3.2.
3.3.
3.4.
3.5.
3.6.
3.7.
3.7.1
3.7.2
Restricted
Technical HSE Work done in FEED Phase ................................................... 32
Key HSE Hazards & Issues ........................................................................ 32
Technical HSE Work planned for Execute Phase ............................................ 33
Human Factors Engineering Plans (HFE) ...................................................... 33
3.5.1. Purpose ........................................................................................ 33
3.5.2. Scope ........................................................................................... 34
Energy Management and Greenhouse Gases .................................................. 35
Waste Minimization................................................................................... 35
General ................................................................................................... 36
Scope ...................................................................................................... 37
4.
ITEMS TO BE RESOLVED IN EXECUTE PHASE ............................................ 39
5.
OVERALL UTILITY SUMMARIES & BATTERY LIMIT TABLE .......................... 43
5.1. Overall Utility Summaries ........................................................................... 43
5.2. Battery Limit Table ................................................................................... 43
6.
CAPTURE LOCATION AND SITE PLAN ......................................................... 44
7.
CAPTURE PLOT PLAN ................................................................................... 46
7.1. Amine Regeneration, CO2 Compression and CO2 Dehydration Area ................. 46
7.2. HMU 1 & 2 Capture Area (Amine Absorbers and wash water
equipment) .............................................................................................. 48
7.3. HMU 3 Capture Area (Amine Absorbers and wash water equipment) ................. 49
7.4. Interconnection to existing units .................................................................. 49
7.5. 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 .......................................................... 65
11.1. Lean Amine Distribution ............................................................................ 65
11.2. Amine Stripper Reboiler Controls ................................................................ 65
11.3. Hydrogen Manufacturing Units (HMU 1/2/3) ............................................... 65
11.4. CO2 Compressor Controls ......................................................................... 66
11.5. Third Generation Modularization................................................................. 66
12.
ELECTRICAL ................................................................................................. 68
12.1. Electrical Design....................................................................................... 68
12.2. Power Supply and Distribution .................................................................... 68
12.3. Electrical Modularization ............................................................................ 70
12.4. General Electrical Layout ........................................................................... 70
12.5. Electrical Loads ........................................................................................ 70
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12.6. Power Routing Layouts .............................................................................. 71
12.7. Area Classification .................................................................................... 71
12.8. Equipment List ........................................................................................ 71
13.
CIVIL............................................................................................................. 72
13.1. General ................................................................................................... 72
13.2. Civil, Paving & Roads ................................................................................ 72
13.3. Geotechnical Investigation.......................................................................... 72
13.4. Piles & Foundations .................................................................................. 73
13.5. Structural Steel ......................................................................................... 74
13.6. Buildings ................................................................................................. 74
13.7. Painting & Fireproofing ............................................................................. 75
14.
MECHANICAL ............................................................................................... 76
14.1. General ................................................................................................... 76
14.2. Equipment Specifics .................................................................................. 76
14.3. Material Selection...................................................................................... 76
14.4. Sized Equipment List................................................................................. 77
14.5. Modularization ......................................................................................... 77
15.
CO2 CAPTURE AND AMINE REGENERATION .............................................. 78
15.1. Unit Overview ......................................................................................... 78
15.2. SGSI Licensor Reports .............................................................................. 78
15.3. Unit Specific Design Basis .......................................................................... 78
15.3.1. Specific Feedstock Rate and Specifications ................................................. 79
15.3.2. Product and Process Specifications .......................................................... 79
15.3.3. On-Stream Factor ............................................................................ 81
15.3.4. Turndown ..................................................................................... 81
15.3.5. Run Lengths .................................................................................. 81
15.3.6. Maintainability Philosophy .................................................................. 81
15.4. Process Description .................................................................................. 81
15.5. Key Operating Parameters .......................................................................... 84
15.6. Process Flow Diagrams .............................................................................. 84
15.7. Heat and Material Balances in Appendices ..................................................... 85
15.8. Sized Equipment List................................................................................. 85
15.9. Utility Summary and Conditions .................................................................. 85
15.10. Battery Limit Stream Summary .................................................................... 85
15.11. Relief Load Summary ................................................................................ 85
15.12. Special Process Engineering Considerations ................................................... 87
15.13. Chemicals ................................................................................................ 87
16.
COMPRESSOR AND DEHYDRATION (UNIT 247/248)..................................... 89
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16.1. Unit Overview ......................................................................................... 89
16.2. Vendor Package........................................................................................ 89
16.3. Unit Specific Design Basis .......................................................................... 89
16.3.1. Specific Feedstock Rate and Specifications ................................................. 89
16.3.2. Product and Process Specifications .......................................................... 90
16.3.3. On-Stream Factor ............................................................................ 91
16.3.4. Turndown ..................................................................................... 91
16.3.5. Run Lengths .................................................................................. 91
16.3.6. Maintainability Philosophy .................................................................. 91
16.4. Process Description .................................................................................. 91
16.4.1. Compression ................................................................................... 91
16.4.2. Dehydration ................................................................................... 92
16.5. Key Operating Parameters .......................................................................... 93
16.6. Process Flow Diagrams .............................................................................. 93
16.7. Heat and Material Balances ......................................................................... 93
16.8. Sized Equipment List................................................................................. 94
16.9. Utility Summary and Conditions .................................................................. 94
16.10. Battery Limit Stream Summary .................................................................... 94
16.11. Relief Load Summary ................................................................................ 94
16.12. Special Process Engineering Considerations ................................................... 95
16.13. Chemicals ................................................................................................ 95
REVAMP OF HYDROGEN MANUFACTURING UNITS (UNITS 241,
242 & 441)....................................................................................................... 96
17.1. Unit Overview ......................................................................................... 96
17.2. Vendor (Uhde) Package ............................................................................. 97
17.3. Unit Specific Design Basis .......................................................................... 97
17.3.1. Specific Feedstock Rate and Specifications ............................................... 100
17.3.2. Product and Process Specifications ........................................................ 100
17.3.3. On-Stream Factor .......................................................................... 101
17.3.4. Turndown ................................................................................... 101
17.3.5. Run Lengths ................................................................................ 101
17.3.6. Maintainability Philosophy ................................................................ 101
17.4. Process Description ................................................................................ 101
17.5. Yield Estimates and Key Operating Parameters (if applicable) ......................... 102
17.6. Process Flow Diagrams ............................................................................ 102
17.7. Revised Heat and Material Balances ............................................................ 103
17.8. Sized Equipment List............................................................................... 104
17.9. Utility Summary and Conditions ................................................................ 104
17.10. Revised Catalyst and Chemical Summary ..................................................... 105
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17.11. Relief Load Summary .............................................................................. 105
17.12. Safeguarding Review................................................................................ 105
17.13. Special Process Engineering Considerations (if required) ................................ 105
17.14. Revised Plot Plan .................................................................................... 105
18.
TIE-INS AND INTERCONNECTING LINES.................................................. 106
18.1. Piping Tie-in List .................................................................................... 106
18.2. Electrical Tie-In List ................................................................................ 106
18.3. Instrumentation Tie-in List ....................................................................... 107
19.
REVAMP OF UTILITIES & OFFSITE FACILITIES .......................................... 112
19.1. Greenfield Utility Requirements ................................................................. 112
19.2. Brownfield Utility Requirements ................................................................ 113
19.3. Unit Overview ....................................................................................... 113
19.4. Objectives and Results of Value Improvement and Scoping Studies .................. 113
19.5. System Specific Design Philosophy ............................................................ 115
19.5.1. Utilities and Offsites Specifications ....................................................... 115
19.5.2. Turndown ................................................................................... 118
19.5.3. On-Stream Factor .......................................................................... 118
19.5.4. Maintainability Philosophy ................................................................ 118
19.5.5. Reliability and Flexibility ................................................................. 118
19.6. Utility System Requirements ..................................................................... 119
19.6.1. Steam / BFW / Condensate ............................................................. 119
19.6.2. Cooling Water .............................................................................. 119
19.6.3. Demineralised Water....................................................................... 119
19.6.4. Instrument and Utility Air ................................................................ 120
19.6.5. Nitrogen ..................................................................................... 120
19.6.6. Utility Water ............................................................................... 120
19.6.7. Potable Water .............................................................................. 121
19.6.8. Waste Water................................................................................ 121
19.7. Offsites Changes by System ...................................................................... 121
19.7.1. Stormwater Collection ...................................................................... 121
19.7.2. Firewater .................................................................................... 121
19.7.3. Tankage Changes .......................................................................... 121
19.7.4. Waste Water Treatment ................................................................... 122
19.7.5. Flare ......................................................................................... 122
19.7.6. Buildings .................................................................................... 122
19.7.7. Interconnecting Piperacks and Piping ..................................................... 122
19.8. Key Operating Parameters ........................................................................ 123
19.9. New and Revised PFDs ........................................................................... 123
19.10. Sized New Equipment List ....................................................................... 123
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PIPELINE .................................................................................................... 124
20.1. Introduction .......................................................................................... 124
20.1.1. System description .......................................................................... 124
20.1.2. Facilities ..................................................................................... 124
20.2. Design Data........................................................................................... 124
20.2.1. Design Standards and Legislation Requirements ........................................ 124
20.2.2. Industry Guidelines......................................................................... 125
20.2.3. Client Specifications ........................................................................ 125
20.2.4. Fluid Composition.......................................................................... 125
20.2.5. CO2 Purity Specification Requirements .................................................. 126
20.2.6. Pipeline Operating Pressure................................................................ 128
20.2.7. Pipeline Operating Temperature........................................................... 128
20.2.8. Flow Rates .................................................................................. 129
20.2.9. Flow Rate Requirements ................................................................... 129
20.2.10. Water Content and CO2 Phase Change Management ................................. 129
20.2.11. Design Life .................................................................................. 129
20.2.12. Pipeline Steel Grade ........................................................................ 130
20.2.13. Right of Way Geotechnical Data ......................................................... 130
20.2.14. HDD Crossing Geotechnical Data ....................................................... 130
20.3. General Design Basis ............................................................................... 131
20.3.1. Routing ...................................................................................... 131
20.3.2. Pipeline Location Class .................................................................... 133
20.3.3. Pipeline Battery Limits .................................................................... 133
20.3.4. Thermal Hydraulic Design Guidelines ................................................... 134
20.3.5. Mechanical Design Guidelines ............................................................ 135
20.3.6. Line Break valves .......................................................................... 135
20.3.7. External Corrosion Protection ............................................................ 136
20.3.8. Field Joint Coating System ................................................................ 136
20.3.9. Internal Corrosion Protection .............................................................. 136
20.3.10. Pipeline Leak Detection System........................................................... 137
20.3.11. Integrity Management ...................................................................... 137
20.3.12. Internal Corrosion Mitigation ............................................................. 138
20.3.13. Cathodic Protection ......................................................................... 138
20.3.14. Monitoring .................................................................................. 138
20.3.15. Inspection .................................................................................... 138
20.3.16. Material Selection .......................................................................... 139
20.4. Pipeline Construction & Installation ........................................................... 139
20.4.1. Pipeline Spreads ............................................................................ 139
20.4.2. Pre-Construction Survey ................................................................... 139
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20.4.3. Pipe Bends .................................................................................. 140
20.4.4. Induction Bends ............................................................................. 140
20.4.5. Cold Field Bends ........................................................................... 140
20.4.6. Crossings – Road & River ................................................................ 140
20.4.7. Major Rail and Road Crossings .......................................................... 141
20.4.8. Minor Gravel ............................................................................... 141
20.4.9. Crossing of Buried Services and 3rd Party Pipelines .................................... 141
20.4.10. Commitments ............................................................................... 141
20.5. Special Crossings .................................................................................... 142
20.5.1. Horizontal Directional Drill Construction Methodology ............................... 142
20.5.2. Pipe Installation ............................................................................ 142
20.6. Pig Trap System...................................................................................... 142
20.7. Relief Philosophy & Pipeline Depressurization Facilities ................................. 143
20.8. Pipeline Electrical Philosophy ................................................................... 143
20.9. Pipeline Instrumentation and Control Philosophy ......................................... 143
20.10. Pre-commissioning, Commissioning and Start up .......................................... 144
20.10.1. Hydrotesting, Cleaning, and Drying ...................................................... 144
20.10.2. Preservation ................................................................................. 144
20.10.3. Initial Fill ................................................................................... 145
20.11. Operation and Maintenance ...................................................................... 145
20.11.1. Operation and Staff ........................................................................ 145
20.11.2. Control Room and Offices ................................................................. 145
20.11.3. Reliability ................................................................................... 145
20.11.4. Emergency Response Planning............................................................. 145
20.12. Future Expansion ...................................................................... 146
20.13. Health, Safety, Security, and Environment (HSSE) ........................................ 146
20.13.1. General Philosophy ......................................................................... 146
20.13.2. Isolation Philosophy ........................................................................ 147
20.13.3. Simultaneous Operations (SIMOPS) .................................................... 147
20.13.4. Emergency Planning ........................................................................ 147
20.13.5. Safety Equipment .......................................................................... 147
21.
SUBSURFACE SCOPE OF WORK .................................................................. 148
21.1. Overview .............................................................................................. 148
21.2. Integrated Production System.................................................................... 149
21.2.1. Compression & Pipeline Requirements .................................................. 149
21.2.2. System Operating Envelope ................................................................ 150
21.2.3. System Operational Philosophy............................................................ 151
21.2.4. Integrated Production System Controls ................................................... 151
21.3. Flow assurance ....................................................................................... 153
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21.3.1.
21.3.2.
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Flow Assurance Scope for the Project ..................................................... 153
Flow Assurance Strategy................................................................... 155
22.
PROJECT APPROACH TO NOVELTY ........................................................... 161
23.
APPENDICES .............................................................................................. 163
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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 “stand
alone” business case and strictly maintaining project costs are required for the
project to meet its goal of being NPV =0.
Quality - The quality driver arises from the fact that this project must achieve its
agreed process performance as described in the government funding agreements
while
Schedule – The strategy by this project is to achieve sustained operations in May
2015. However, if the execution schedule starts to slip, money may not be spent to
maintain 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-AA5726-0001)
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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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:
136,487 Std. m³/h (116 MMSCFD) H2 production
· HMU1
136,487 Std. m³/h (116 MMSCFD) H2 production
· HMU2
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159,444 Std. m³/h (135 MMSCFD) H2 production
· HMU3
Amine Absorbers
168,031 Std. m³/h raw H2 gas (feed)
· HMU1 Amine Absorber
168,031 Std. m³/h raw H2 gas (feed)
· HMU2 Amine Absorber
244,556 Std. m³/h raw H2 gas (feed)
· HMU3 Amine Absorber
Amine Regeneration
1481 m³/h lean amine circulation (Note 2)
CO2 Compression and
3,564 tonnes/day CO2 Production (>95% CO2)
Dehydration
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.
Temperature
Pressure
°C
kPag
Composition
H2O
CO2
CO
N2
H2
CH4
Mol%
Mol%
Mol%
Mol%
Mol%
Mol%
Table 2.2: Feedstock Quality
HMU1
HMU2
35
35
2964
2964
0.2
16.5
2.4
0.3
74.8
5.8
0.2
16.5
2.4
0.3
74.8
5.8
HMU3
35
3004
0.2
17.1
2.9
0.3
72.4
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%
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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 bottledin 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 largescale 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 potential
operating range (between the Compressor 7th Stage discharge and the Aftercooler).
· Performed Consequence Model for ALARP Decision Register, document number
A6GT-R-1014. The BLEVE model found no unacceptable safety consequences for
normally occupied buildings local to the facility. During future design development
of 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 Capture
2. 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 AntiFoam injection system is provided within the Amine Regeneration Battery Limits. The antifoam 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 CO2
recovery
o High interstage temperature in the compressor, leading to compressor
trip
o High amine temperature, resulting in loss of absorption efficiency.
·
Loss of LP steam results in loss of amine stripping, resulting in no CO2
production.
·
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 off
specification 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
· DCS and SIS integration
· 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
· DCS and SIS integration
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 vacuum
is based on standard barometric pressure at sea level, 101.325 kPa (abs). That is, design for full
vacuum is design for 101.325 kPa external pressure. Design for ½ vacuum is design for 50.663
kPa 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 tip
barometric pressure, etc.
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Ambient Temperature
Restricted
°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
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
For critical service as per A6GT-DN-1037
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
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.
Frost Protection
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 Safety
System for Quest. (Note that the existing Base Plant Safety System is implemented in
a GE-Fanuc based system.) Quest CCS Project units that employ this control system
are:
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. The
Quest 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 and
guidelines. Reference to voluntary documents in the site approvals gives them
force of law.
·
Shell Canada Energy Minimum Health, Safety, Environment and Sustainable
Development 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 50/1998per 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 AdministrationRegulations, 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 remove
them from the project list
·
Maintain alignment with Shell Enterprise Frame Agreements (for example on
centrifugal pumps)
During FEED, the specifications were reviewed in detail to:
·
generate project specific deviations to align project specifications with the Quest
Design Class Report requirements
·
generate Project specific deviations to align project specifications with
specifications included in procurement Global Framework Agreement used on the
project
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 the
RCDU plot area but not in HMU1,2 and HMU3 areas
·
Modules would be elevated above grade not embedded at Grade
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HEALTH, SAFETY, ENVIRONMENT AND SUSTAINABLE
DEVELOPMENT
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-5700001). 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 phase
action 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 of
containment. Planned mitigation includes rigorous compliance to Shell’s Asset
Integrity standards, engagement of Shell’s and industry’s experts to model releases
and conduct QRA to understand the effects.
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·
Loss of containment of high pressure CO2 piping due to corrosion. Mitigated by
addition of TEG dehydration to the scope and material selection.
·
Contribution to an increased likelihood of incidents of (a) the novelty of designing
for and handling dense phase CO2 and (b) the lack of Shell and industry standards
for materials and equipment to handle dense phase CO2. Incidents could result in
loss of reputation and compromising Shell’s global ability to implement additional
CCS projects. Planned mitigation includes engagement of Shell’s and industry’s
experts.
·
Integration of CO2 absorption, regeneration, and compression with the HMU’s may
impair the overall reliability of hydrogen production, and thus of production from
the Scotford Upgraders. Planned mitigation includes focused design effort on the
process controls and safeguards to ensure that robust hydrogen production is not
impaired by integration with the CO2 Capture facilities.
·
CO2 Capture construction workers may be exposed to a toxic gas (H2S) release
from the Scotford operating process units, with the potential for multiple fatalities.
Planned mitigation includes adoption of procedures used at the base plant Upgrader
and for Expansion 1 construction, as well as QRA of the risk from a H2S release
during 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 the
environment
·
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 the
Scotford 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, where
each valve is color coded to its designated class. A preliminary assessment of “class”
compliance has been performed; however the “purchased” design data must be
validated prior to final valve location acceptance.
A “first-pass” of a material handling matrix has been populated for each process area
during the FEED phase. All equipment modules utilizing “monorails” for
mechanical lifting have been through preliminary “Materials Handling Reviews”.
Reviews will be listed on the “Project HFE Plan” and will be scheduled when the
Process and Mechanical prerequisite design data permits.
A preliminary HFE (Human Factors in Engineering) “Building layout review” has
been performed for the compressor building. This review is listed on the “Project
HFE Plan” and will be scheduled when the Process and Mechanical prerequisite
design data permits.
All existing fire suppression equipment has been through a preliminary evaluation in
areas 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 water
to the amine system
o Circulating wash water to minimize the use of clean condensate for
washing carry-over amine from the H2 Raw Gas.
o Subcooling recovered steam condensate, from the reboilers, to prevent
steam releases to atmosphere.
·
Waste Heat Recovery
o Demin water is employed to cool condensate from the Amine Stripper
Reboiler.
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Chemical Management
o Amine losses minimized by recycling purge water from the water wash
system, which contains entrained amine, to be used as water make-up.
o Prevention of Amine contamination with TEG, by segregating KO water
which may be contaminated.
o TEG is continuously recycled
o TEG reboiling temperature remains below the thermal degradation
temperature.
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 still
in 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 than
Double Block & Bleed, blinding or blanking, and therefore for isolations
requiring individual approval by a Professional Engineer
- All isolations must include means for verification that the equipment has
been 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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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 is
operational. Preliminary overall balances with
and without Quest operation to be
completed early in Execute Phase.
·
Need to determine whether the condensate
recovery and additional demin water
requirements (to offset the condensate loss
due to water wash make-up) can be
accommodated with the existing integration
facilities.
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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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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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 pig
launcher (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
000-0311-000-SK-001
Unit 285 Interconnecting Piperack
Additions For CCS Expansion
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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, to
limit physical disturbance
·
Limit the length of the pipeline to reduce the total area of disturbance
·
Avoid protected areas and using appropriate timing windows
·
Avoid wetlands and limiting the number of watercourse crossings
·
Accommodate landowner and government concerns to the extent possible and
practical.
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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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. # CN505).
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 from
an HSE perspective (document ref. A6GT-R-1034, CO2 VENT STACK DESIGN
DETAILS ALARP REVIEW). It will remain outside the 100 meter radius from the
Security Building.
· General plant process flow, to locate equipment in optimal locations to minimize
piping lengths.
· The Pig Launching Module has been located to best suit a pipeline corridor exiting
the Scotford Facility to the east. HSE concerns for the pig launcher module
regarding depressurization during operation will need further consideration to
mitigate any risks, potentially a deflection wall or earth berm may be considered on
the loading end of the launcher. Also the pig launcher has been located as far as
possible from the main security building to the south.
· The Amine Makeup Tanks (TK-24601 and TK-24602) are located to minimize truck
traffic 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 for
exchanger bundle pulls, air cooler maintenance, and filter element access.
· Facilitate plant constructability, in particular crane access to set modules and dressed
vessels.
· Based on the fact HMU1/2 new absorbers are within the HMU1/2 battery limit to
west, location of new CO2 compression unit took into account the most direct route
to 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 ALARP
study, 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 the
Shell Quest HSE premises at the Security building. Some toxic release scenarios are
modified slightly by the presence of a building. Operability and maintainability are
significantly improved.
· A process isolation philosophy has been reviewed during the development of the
P&IDs and battery limit valves have been added where required. The locations of
the battery limit valving were reviewed during the FEED phase model reviews for
maintainability and operability.
· Stormwater Containment & Drainage Philosophy requirements are defined within the
approved 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 been
approved. Aboveground modules will be used. Both the above ground and
embedded options are technically acceptable and can be used for 3rd Gen Modular
ExecutionSM, 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 to
Plant Layout: DEP - 80.00.10.11-SCAN - Layout of Onshore Facilities, as well as
Shell’s Human Factors Engineering in Workplace Design (OSG-P9.15 Green Book
2008).
· Process requirements such as hydraulics dictating equipment locations relative to one
another, pressure drop constraints, maintaining short pump suction lines, equipment
elevations 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 transported
to 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 Amine
Absorbers due to pressure drop limitations.
· Minimizing associated utility interconnecting pipelines to tie-in locations within the
HMU unit and avoids using utilities from the CO2 compression facility.
· Facilitate plant 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 the
approved Decision Note A6GT-DN-1062.
· Decision Note A6GT-DN-1049 (Above Ground vs. Buried Modules) has been
approved. 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 where
new facilities may impede the “expected performance” of these systems. Preliminary
reviews 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 amine
absorber 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 the
approved Decision Note A6GT-DN-1062.
· Decision Note A6GT-DN-1049 (Above Ground vs. Buried Modules) has been
approved. Aboveground modules will be used. Both the above ground and
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 where
new facilities may impede the “expected performance” of these systems. Preliminary
reviews 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 near
intersection of G Street and 10th Ave. Thus the new piperack is located in an optimal
location with respect to overall length.
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Quest has VALIDATED the access requirements for operations and maintenance
on the west and south side of Cogeneration and Utility building relative to the
proposed location of the interconnecting piperack.
Location of the new piperack to minimize underground demolition and relocation
of existing facilities.
The following Integration Requests for proposed Quest facilities have been prepared
and submitted to Scotford for approval;
1. Ref. SI-052 - Quest Pipe Routing for Amine & Utilities - approved
2. Ref. SI-054 - Quest Cooling Water Routing – approved
3. 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 due
to the large line size, to allow the tie-in to be located and orientated to best suit the
new piperack location. The tie-in (TP285-7) location has been finalized and the
isometric drawing issued IFC.
30” Cooling Water tie-in locations have been finalized, however the locations may
have 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&M
HFE access envelopes
· Constructability review, includes Construction, Operations, maintenance, HFE Rep
and Construction Safety
· Review access to instrumentation and remote IO boxes at a conceptual level
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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 that
all vessels and piping are clean, properly preserved, and “ O2 freed” by purging them
with nitrogen. All process and utilities tie-ins are complete such as cooling water, low
pressure steam, high pressure steam, electricity, instrument air, utility air, nitrogen,
flare, boiler feed water, return clean condensate, waste water, and fire water systems
and are ready for service prior to start up. Only one HMU train is lined up for the
initial pipeline commissioning and well start up.
2- The next step is to inventory the ADIP-X
X amine solution (40%
% MDEA, 5% DEDA,
55% water) into the Amine Stripper in order to build working levels and to start
circulation to the Absorption System. The anti-foam system needs to be ready for
service and the anti-foam tank must be full of the correct anti-foam chemical, pumps
must be primed and tested before the amine circulation begins.
3- Circulation from the Amine Stripper via the Lean Amine Pumps, Lean/Rich Amine
Exchanger, Lean Amine Cooler, Lean Amine Filter, Lean Amine Carbon Filter, Lean
Amine Post Filter, and Lean Amine Charge Pumps is established to the Absorbers.
4- Sufficient nitrogen pressure is necessary at the Absorbers to pressurize the amine
from the bottoms of the Absorbers back to the Amine Stripper to complete the
circulation loops. The use of nitrogen is limited to start up and shut down periods to
minimize their losses and also to prevent any contamination of the CO2 to the
injection well head.
5- Samples need to be taken at the outlet of the Post Amine Filters to verify amine
concentrations 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 at
the Amine Stripper, in order to warm up the vessels and establish the amine flows
through the shell sides of the Amine Reboilers. This slow warm up of the amine
system is done to prevent stresses on the system due to uneven temperatures, ensure
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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 of
the various pumps and heat exchangers need to be commissioned and function tested
for proper operation.
8- The CO2 Compressor must be purged with nitrogen and be ready to start. The CO2
Compressor surge testing and run-in test must be completed before CO2 is made
available to the compressor. The CO2 Vent Stack shall be commissioned and ready
for service. The CO2 will be initially vented until all components in the amine unit are
stable, and beyond the minimum turndown to ensure that when we start up the
compressor 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 be
commissioned 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 test
water is removed by running a pig through the pipeline. The pipeline must be
moisture freed to ensure all traces of moisture have been removed. The B/L custody
transfer 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 to
the CO2 Plant. The amine circulation rates to the Absorbers will be monitored and
then the feed gas supply will be put in service. The flows to the Absorber(s), and the
overhead gas via the Absorber Water Wash Drum to the PSA will be slowly opened
up.
12- The CO2 Absorption System is now in service and is removing the CO2 from the
inlet feed gas to the Absorbers. Rich amine will be pressurized back to the Amine
Stripper 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 of
amine flow. An inline CO2 analyser will be installed on the outlet line of the Wash
Water 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 the
SMR flue gases. The burners will be changed to a newer type of Ultra low NOx
burner to assist in NOx reduction.
3- The additional delta pressure drop added to each HMU is expected to be
approximately 70 kPa across each absorber and wash water vessel system.
4- The maximum amount of tolerable amine carryover from the Absorber Water Wash
Vessels to the PSA Units is 1 ppm. Amine carryover will coat the adsorbent media in
the PSA Units and reduce their efficiencies. This would ultimately lead to higher
delta pressure drops across the beds, reduced throughputs, lower quality hydrogen
production, premature change outs of the absorbent media, and higher operating
costs. Water wash in the absorber overheads is designed to remove the amine
carryover, and demister pads designed to remove 99% of liquid droplets in the
Absorber overhead.
5- The CO2 Plant should not affect the temperature of the PSA feed gas. The
temperature 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 by
degradation products (i.e. iron compounds, acids and particulates) that are in
solution with the amine. The foaming can cause carryover of liquids from the
Absorbers and Regeneration System vessels, and will reduce throughputs and
product qualities. A portion of the lean amine is routed through the Lean Amine
Filter, which contains cartridges to remove the degradation products. This is
followed by the Carbon Filter and the Post Amine Filter, which also contains
cartridge filters, to purify the lean amine streams upstream of the Absorbers. The
%, with 5 % of the total
total amount of the amine being filtered is approximately 25%,
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 of
entrainment 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 as
well as the RCC system. Water makeup can be added to the unit through a
connection provided on the make-up water circulating loop. This allows for the
maintenance of the amine-water balance. The makeup water is to be added under
flow control. Amine addition is from the pure amine tank and is pumped slowly into
the amine system. Tests for amine concentration need to be done to keep the amine
percentage 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 minimize
the adverse impact on the HMU trains, and to prevent upsets in the CO2 Plant. This
is because there is only one Amine Regeneration Unit for the three Amine Absorber
Units. Once one Absorber has been brought into service and is lined out, a second
Absorber 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 and
HMU. The lean amine flows to the Absorbers will be on flow control, with the rich
amine in the Absorbers being on level control. The feed gas to the Absorbers will be
at 35 degrees C. and 3,000 KPag, and the overhead gas is at approximately the same
temperature and pressure when it is routed to the PSA Unit. The Absorbers have
instrumentation for flow, level, pressure, and temperature. A pressure differential
indicator and alarm is required across the trays within the Absorbers. The important
function of the pressure differential indicator is to detect increases or fluctuations in
differential pressure that are warnings of tower foaming. The Absorbers are
operated with flows of lean amine at a fixed rate and the operator will manually
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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 bypass
arrangement. The feed to the PSA units will change from “lean” to “rich” when the
CO2 Plant is taken off line. Once the CO2 Plant is totally bypassed and off line, it
can 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 the
feed to the PSA Units changes from lean to rich, the loading on the PSA Units will
increase. This also changes the composition of the off gas from the PSA Unit to the
SMR and the requirement for FGR. The increased flow of the off gas to the SMR
will mean that the quantity of combustion air will be decreased. The steam reformer
tube wall temperatures must be kept within acceptable values in order to protect the
integrity of the tubes.
3- Continue to circulate lean amine to the Absorbers at a constant rate. Reduce the
intake of feed gas until the inlet feed is completely bypassed. In this way there is only
one parameter to control and doing this will not affect the HMU. It may also help to
speed up the removal of the CO2 from the amine. Check valves or non return
valves, and manual isolation valves, may be needed on the feed gas inlet to each
Absorber to minimize the loss of rich amine from the Absorbers. Once the lean
amine streams do not contain CO2 the circulation of amine to the absorbers can be
stopped 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 and
then 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 amine
circulation 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 enough
to flood the towers once the amine circulation has been stopped. The amine storage
tank 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 CO2
compressor has been stopped the remaining CO2 in the overhead line will be vented
to the CO2 Vent Stack. The pipeline must be ready to be blocked in once the
compressor 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 from
entering it.
10- Close control valves on the Absorbers amine feed lines, overhead line, and rich
amine line. Close block valves at these locations also.
11- Isolate the Regeneration System by closing control valves and block valves on the
Amine 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 and
will include the following :
-
Draining of lean amine to temporary storage tanks
Blinding the vessels and opening them up for maintenance, inspection, and
cleaning.
The nitrogen blanketing gas will need to be closed prior to any confined
space entries to the vessels.
All utilities that are not required would be blocked in until they are required
at 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 HMU
train is taken down for Turn Around. The feed gas will be slowly closed to the
absorber and then amine circulation will continue until the amine is CO2 free. The
Absorber will be blocked in, drained, steamed out, and blinded prior to any confined
space 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 will
be done) using the pressure in the absorbers. The isolation valves downstream of
the level control valve would be closed, and any amine remaining in the system
would be withdrawn by vacuum truck (4” drain connection provided). The
remaining volume of amine is approximately 8 m3 for HMU1/2 and 15 m3 for
HMU3. There will be no other amine drain facilities provided in the HMUs. A
detailed Amine draining Procedure will be generated as part of shut down procedure
by Operations.
2. Prior to shutdown of the Amine Stripper the bulk of the amine would be transferred
to the Amine Absorbers in the HMUs as well as the Amine Storage Tank. The
remainder of the amine can be gravity drained to the Amine Drain Drum. Since this
will be done during total Quest shutdown, it is assumed at this stage that transferring
amine 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. For
HMU3 in particular, this represents a substantial volume. If maintenance is required
on these lines, temporary storage tanks would be needed to hold the volume of
amine. It is assumed that the amine can be pressured from the line to the tank using
nitrogen and existing vent and drain connections. A temporary amine storage space
will be allocated in plot plan and necessary flange or spool piece connections will be
provided to facilitate temporary draining.
4. The amine drain system in Area 246 gravity drains to the Amine Drain Drum, and
requires drain pipe routed below grade in a trench. This trench will also collect
rainwater from potentially contaminated amine area runoff which could otherwise
contaminate groundwater. A local collection basin will be considered separate from
the amine vessel sump to collect this water runoff and pump it to wastewater
treatment.
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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Restricted
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 crossproject 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 and
required 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 the
carbon steel pipeline from corrosion and potential hydrate formation at choke
valve . The required redundancy on this measurement will be reviewed during the
Execute Phase. At this stage a redundant analyzer configuration has been
assumed.
·
CO2 content in the raw hydrogen gas stream for each of the three HMU plants
for 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 each
MCC.
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 electrical
devices, 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.
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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
Stream Number
Stream
Description
HMU 1
Absorber
#1
HMU 2
Absorber
#2
HMU 3
Absorber
#3
1A
1B
1C
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
10.50
10.50
11.05
Molecular Weight
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
Cool Treated Gas from Wash
Vessels
Stream Description
CO2 to
Compression
HMU 1
Absorber
#1
HMU 2
Absorbe
r #2
HMU 3
Absorber
#3
Amine
Regeneration
3A
3B
3C
9
°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
5.25
5.25
5.68
42.60
System
Stream Number
Temperature
Molecular Weight
Total Stream Composition
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
Notes:
1. Standard conditions are 15.6°C (60°F) and 101.325 kPaa (1 atm).
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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 through
intimate contact with a lean amine (ADIP-X)
X) solution consisting of 40% MDEA, 5 %
Piperazine
zine (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.
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Warm treated gas exits the top of the absorbers and enters the 99-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 crossexchange 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 feedforward 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
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
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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 antifoam. 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 preformulated 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
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.
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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
35°C
< 1 ppmw
70 kPa
0.6 mol CO2/mol Amine
Treated Hydrogen Raw Gas temperature
Amine content of Treated Hydrogen Raw Gas
Maximum allowable system pressure drop
Target Rich Amine loading
Amine Regeneration Section
Lean Amine supply temperature
Lean Amine loading
CO2 Gas to Compression temperature
30°C
0.03 mol CO2/mol Amine
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
241.0001.000.040.005 Rev 0B
Drawing Name
HMU 1 Absorber
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242.0001.000.040.006 Rev 0B
441.0001.000.040.005 Rev 0B
246.0001.000.040.001 Rev 0B
246.0001.000.040.002 Rev 0B
246.0001.000.040.003 Rev 0B
HMU 2 Absorber
HMU 3 Absorber
Amine Stripper System
Amine Filtration
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 Name
Heat and Material Balance
Drawing Number
245.0001.000.046.001 Rev 0B
15.8. Sized Equipment List
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,
Fire
Raw H2 Gas
Flare
Fire
Raw H2 Gas
Flare
Fire
Raw H2 Gas
Flare
Vapour Outlet
RV-441023
Absorber #3 V-44118,
Vapour Outlet
RV-441023
Absorber #3 V-44118,
Vapour Outlet
Table 15.4: Relief Scenarios for Amine Regeneration Area
Relief
Valve
Equipment
Relief Case
Type of
Release
Destination
RV-246001
Lean / Rich Amine Exchanger
Control Valve
Rich Amine
Amine Stripper inlet
E-24602A/B Cold side outlet
Failure
(liquid)
device (downstream of
(Rich Amine)
RV-246002
Lean Amine Cooling Train
PV-246010A/B)
Fire
H2O + Amine
Amine Drain Drum
Fire
H2O + Amine
Amine Drain Drum
Amine Stripper, V-24601,
Cooling Water
CO2 + H2O
To atmosphere at a safe
Vapour outlet
Failure, power
“A”, E-24602A, E-246004A,
E-246005A
RV-246003
Lean Amine Cooling Train
“B”, E-24602B, E-246004B,
E-246005B
RV-246005
location
failure (partial
and full), blocked
vapour outlet,
CO2+H2+CH4
fire,
Vapour
breakthrough
RV-246011
Stripper Reboiler Condensate
Fire
Steam
Pot, V-24603B
RV-246013
Stripper Reflux Drum, V-
To atmosphere at a safe
location
Vapour
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Equipment
Relief Case
Type of
Release
Destination
24602
Breakthrough,
H2O + CO2
location
H2O + Lean
To Amine Drain Drum
Fire
RV-246020
Lean Amine Filter, V-24604
Fire
Amine
RV-246021
Lean Amine Carbon Filter, V-
Fire
Amine
To Amine Drain Drum
Vapour
Nitrogen
To atmosphere at a safe
24608
RV-246025
Amine Drain Drum, V-24606
breakthrough
RV-246026
Drained Amine Filter, V-
Fire
24605
RV-246031
RV-246033
RV-246034
location
H2O + Lean
Amine
Demin Water Supply Pump
Blocked
Discharge, P-24610A/B
discharge
Condensate Flash Drum, V-
Vapour
24507
Breakthrough
Amine Drain Nitrogen, V-
PCV Failure
Demin Water
To grade
HP Steam
To atmosphere at a safe
Nitrogen
Nitrogen
24606
RV-246046
Amine Make-up Tank, Tk-
To Amine Drain Drum
location
To atmosphere at a safe
location
PCV Failure
Nitrogen
Amine Make-Up Tank, Tk-
Fire, blocked
Nitrogen, water
To atmosphere at a safe
24601
vapour outlet,
or amine
location
24601
PVSV-246047
Steam failure,
tube rupture
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 offsite 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.
16.3. Unit Specific Design Basis
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.
16.3.1.
Specific Feedstock Rate and Specifications
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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Product and Process Specifications
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
Temperature
56
°C
43
kPag
9000
Molar Rate
kmol/h
3397
Mass Rate
kg/h
148496
m3/hr
80330
Pressure
Standard Volume Rate
Molecular Weight
43.71
Total Stream Composition
H2O
mol%
0.01 %
CO2
mol%
99.23 %
CO
mol%
0.02 %
N2
mol%
0.00 %
H2
mol%
0.65 %
CH4
mol%
0.09 %
Notes:
1. Standard conditions are 15.6°C (60°F) and 101.325 kPaa (1 atm).
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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 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.
16.3.6.
Maintainability Philosophy
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. Process Description
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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16.5. Key Operating Parameters
The following are key operating parameters for the CO2 Compression and Dehydration
Units.
CO2 Compression
Compressor Discharge Pressure:
Cooler Outlet Temperatures:
Pipeline CO2 Temperature:
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.
42°C (water cooled services)
36°C (air cooled services)
43°C
CO2 Dehydration
Product CO2 H2O Content
CO2 Inlet Pressure
Lean TEG Loading
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.
3800 to 5200 kPag
>99 wt% TEG
16.6. Process Flow Diagrams
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
247.0001.000.040.001 Rev 0B
247.0001.000.040.002 Rev 0B
247.0001.000.040.003 Rev 0B
248.0001.000.040.001 Rev 0B
Drawing Name
CO2 Compression
CO2 Compression
CO2 Metering Station and Pig Launcher
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
245.0001.000.046.001 Rev 0B
Drawing Name
Heat and Material Balance
16.8. Sized Equipment List
The sized equipment list is located in Appendix A1.4.
16.9. Utility Summary and Conditions
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.
16.11. Relief Load Summary
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 Case
Type of
Release
Relief Valve
Equipment
RV-247004
3rd Stage Compressor KO
Fire
H2O, CO2
Drum, V-24703
RV-247006
Destination
(Magnitude of
release)
To atmosphere at a safe
location
4th Stage Compressor KO
Vapour
Drum, V-24704
Breakthrough,
H2O, CO2
To atmosphere at a safe
location
Fire
RV-247008
5th Stage Compressor KO
Fire
H2O, CO2
Drum, V-24705
RV-247010
6th Stage Compressor KO
location
Fire
H2O, CO2
Drum, V-24706
RV-247011
7th Stage Compressor KO
To atmosphere at a safe
To atmosphere at a safe
location
Fire
Drum, V-24708
H2O, CO2
To atmosphere at a safe
location
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Relief Valve
Equipment
Relief Case
Type of
Release
Destination
(Magnitude of
release)
RV-248003/5
Lean TEG Pumps, P-
Blocked outlet
TEG
Grade
Blocked outlet
TEG
Grade
Fire
H2O
To atmosphere at a safe
24601A/B
RV-248006
Make-Up TEG Pumps, P24602
RV-248007
Lean TEG Filter, V-248004A
location
RV-248008
Lean TEG Filter, V-248004B
Fire
H2O
To atmosphere at a safe
location
RV-248009
Lean TEG Carbon Filter, V-
Fire
H2O
248007
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 (Induced
Draft) fans, C-24102 and C-24202, to the FGR fan suction.
·
Install new ducting to connect the discharge of FGR Fan with the combustion air
fan discharge.
·
Replace all burners in the Steam Methane Reformers, H-24101 and H-24201, with
Lanemark Low NOX burners.
·
Replace the adsorbent in the Pressure Swing Adsorbers (PSAs) - 10 Vessels in
each of the PSA units.
·
Modifications to the Base Plant PSA control logic.
·
Modify the tail gas control and combustion air controls to account for operation
and switching between lean / rich CO2 taking into account: the effects of CO2
capture on the composition of the PSA offgas and the addition of flue gas
recirculation.
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 (Induced
Draft) 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 combustion
air fan discharge.
·
Replace all burners in the Steam Methane Reformer, H-44101 with Lanemark Low
NOX 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 and
switching between lean / rich CO2 taking into account: the effects of CO2
capture on the composition of the PSA offgas and the addition of flue gas
recirculation.
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-VTEC-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.
17.3. Unit Specific Design Basis
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 in
the reformer flue gas onto the flow of combustion air
·
The FGR fans motor speed is controlled by a VFD based on control of the total
reformer convection section flow for a given load.
·
To mitigate the transient effects due to changes in Quest operation a feedforward
signal 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.
17.3.1.
Specific Feedstock Rate and Specifications
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.
17.3.2.
Product and Process Specifications
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.
17.3.3.
On-Stream Factor
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.
17.3.6.
Maintainability Philosophy
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.
17.4. Process Description
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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.
17.6. Process Flow Diagrams
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
240.0001.000.040.001 Rev. 2B
Chemical Feed Compression
240.0001.000.040.003 Rev. 2A
Steam and Condensate
240.0001.000.040.004 Rev. 2A
Cooling Water Supply / Return
241.0001.000.040.001 Rev. 2B
Description
Updated H&MBs
Updated H&MBs
Added steam and condensate tie-ins for the amine
absorbers
Added cooling water supply and return tie-ins for
amine absorbers
Updated H&MBs
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Drawing Number / Title
Feed Gas Desulphurization
241.0001.000.040.002 Rev. 2B
Steam Reforming
241.0001.000.040.003 Rev. 2B
Co-Conversion Cooling Train
242.0001.000.040.001 Rev. 2B
Feed Gas Desulphurization
242.0001.000.040.002 Rev. 2B
Steam Reforming
242.0001.000.040.003 Rev. 3B
Co-Conversion Cooling Train
243.0001.000.040.001 Rev. 2B
H2 Purification
244.0001.000.040.001 Rev. 3B
H2 Purification
440.0001.000.040.001 Rev. 3B
Feed Intake
440.0001.000.040.002 Rev. 3B
Steam and Condensate
440.0001.000.040.004 Rev 2
Relief and Depressuring Flow
Diagram
440.0001.000.040.011 Rev. 2B
Steam/Condensate/BFW
441.0001.000.040.001 Rev. 3B
Feed Gas Desulphurization
441.0001.000.040.002 Rev. 3B
Steam Reforming
441.0001.000.040.003 Rev. 3B
Steam Reforming
441.0001.000.040.004 Rev. 3B
Co-Conversion Cooling Train
443.0001.000.040.001 Rev. 3B
HMU – H2 Purification
Restricted
Description
Updated H&MBs
Add flue gas recirculation
Updated H&MBs
Add hydrogen raw gas tie-ins for supply and return
to the amine absorber
Updated H&MBs
Updated H&MBs
Add flue gas recirculation
Updated H&MBs
Add hydrogen raw gas tie-ins for supply and return
to the amine absorber
Updated H&MBs
Added notes regarding modifications to PSA unit
Updated H&MBs
Added notes regarding modifications to PSA unit
Updated H&MBs
Updated H&MBs
Added Quest pressure control vent and relief valve
lines to drawing.
Added steam and condensate tie-ins for the amine
absorbers
Updated H&MBs
Updated H&MBs
Added note for burner modification
Updated H&MBs
Add flue gas recirculation
Updated H&MBs
Add hydrogen raw gas tie-ins for supply and return
to the amine absorber
Updated H&MBs
Added notes regarding modifications to PSA unit
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
Case 2
Case 24 w/FGR
Case 24 w/FGR 75% TD
Case 24 w/FGR 50% TD
Case 24 w/FGR 30% TD
Check Case V rev 2
Case 21 w/FGR
Case 21 w/FGR 75% TD
Case 21 w/FGR 50% TD
Case 21 w/FGR 30% TD
HMU
1/2
1/2
1/2
1/2
1/2
No
Yes
Yes
Yes
Yes
CO2Removal
Online
No
Yes
Yes
Yes
Yes
No
Yes
Yes
Yes
Yes
FGR
Online
No
Yes
Yes
Yes
Yes
Yes
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.
17.8. Sized Equipment List
The sized equipment list is attached in Appendix A1.7.
17.9. Utility Summary and Conditions
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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.
17.11. Relief Load Summary
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 (RV241/241375A/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 pressure
drop study of the HMU convection section because of the addition of FGR. They
will also complete pressure analysis of the HMUs to support development of the
control 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.
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Anti-Surge Control System
QUEST SCADA system interface
Base Plant Control Room space requirements
4
5
6
6.1
5.1
4.1
3.1
04
Foxboro DCS & Control room
Foxboro DCS & existing SCADA System
Foxboro DCS
Bentley-Nevada System 1 interfaces.
HMU Burner Management System
Safety Manager Safety System
1.4
2.2
Honeywell DCS
1.3
Foxboro DCS
GE Safety System
1.2
2.1
Foxboro DCS
1.1
Type of system interface
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Interface of Co2 compressor vibration monitoring system
3
Basic Design & Engineering Package
Fuel Gas Recycle Control
Modifications to HMU 1/2/3 for implementing new control scheme
Brief Description of interface
2
1
Item Number
18.3. Instrumentation Tie-in List
07-1-AA-7739-0001
commissioned, Op's team will integrate Quest into the existing HMU console. Commissioning console may also be located in the
CCS Project start-up. These stations will work independent of existing consoles to minimize impact to operations. Once Quest is
It is planned that two (additional) Foxboro DCS operator stations will be installed into the Base plant Control Room during Quest
advantage of the existing SCADA system interface and add additional I/O's of almost 500 to this system.
identified that Base Plant River Water Pumps are controlled via SCADA system and Quest CCS Project would like to take
Data collected by remote RTUs at LBV sites and Well heads will be transferred back to Foxboro DCS via SCADA. It was
the Foxboro DCS for information exchange and control optimization.
Quest CCS Project will have anti-surge and performance controllers for compressor protection. This will require integration into
single point monitoring. Configuration of System 1 is on a Modbus Network.
to be monitored via a Bentley-Nevada standalone system. This system needs to be integrated with Base plant B-N System 1 for
Quest CCS Project will have an 8 stage compressor and machine condition parameters (i.e. Vibrations, Temperatures, keyphasors)
code variations by the authority having jurisdiction.
regard to re-certification of the BMS to meet the requirements of CSA B149.3 is unknown pending the acceptance of requested
At this stage, the scope is not yet finalized. The FGR Fan will require integration into the BMS system. However, the scope with
identification of type of Burners. Any changes will be implemented in the Foxboro system.
Quest CCS Project will have to meet the NOx targets and efforts are been put into finalization of FGR Control scheme and
system for Quest. As directed by Shell, the preferred vendor for the Quest S/D system is Honeywell.
Quest CCS Project has the need for a Safety Shutdown system. At this stage, the project has estimated for an independent S/D
I/O's into existing system loading. New hardware and software needs to integrated with existing Honeywell DCS system
and modify them for Quest CCS Project needs. As a result, the Quest CCS Project expects to add almost 200 hard I/O's and soft
Quest CCS Project will have number of interfaces with Expansion 1 Honeywell DCS to take advantage of existing control scheme
equipment to be integrated into the existing GE Safety System together with the existing combustion air and forced draft fans.
The addition of a Flue Gas Recirculation Fan into the reformer combustion air system will require the shutdown functions for this
needs to be integrated with existing Foxboro system.
2) Quest CCS Project expect to add almost 1000 hard I/O's and 500 soft I/O's into existing system loading and new hardware
DCS. Quest CCS Project team expect to reuse and add extra hardware and logic into existing Foxboro DCS system.
1) Quest CCS Project has a number of interfaces with Scotford Utilities system. At present this is being controlled via Foxboro
Details of interface
No
To be Confirmed
No
No
Yes
No
No
No
Yes
No
Do we need S/D to implement this tie in
Pipeline Line Block Valves (LBV) Control
Well Head Monitoring & Control
Pipeline de-pressurization
9
10
11
Multilin Modbus System
7.3
11.1
10.1
9.1
04
Scope is in development
Scope is in development
Scope is in development
At this stage, scope is unclear
EHT system
7.2
8.1
DeviceNet Network
IT & Radio needs
7.1
6.2
Type of system interface
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Pipeline Leak Detection system interface
8
Basic Design & Engineering Package
Interface with Base Plant DeviceNet, EHT system & HV Multilin Modbus
Brief Description of interface
7
Item Number
07-1-AA-7739-0001
see section 9
will be interfaced with the Foxboro DCS system.
There is isolation valve at each well head and all data from well head will be sent to control room via SCADA system. This system
At this stage number of well heads is not confirmed. At each well head, pressure, flow and temperature monitoring will be done.
All the LBV sites will be powered by solar panels and remotely connected to control room via a SCADA system.
distance. Each LBV site will have pressure & temp monitoring along with provision to depressurize that section of the pipeline.
Pipeline PFDs and P&IDs are not available at the time of writing, but it is expected to have Hydraulic type of LBVs at 15 KM
standalone leak detection system, then that system will be interfaced with Foxboro DCS as 3rd party integration.
algorithm will be executed within the Foxboro DCS system for leak detection calculations. If above scope changes due to
With current thinking, looks like we will have pressure monitoring at multiple locations for pipeline leak detection and simple
be used for Operator interface purpose. Design will follow standards for each plant (e.g. HMU#3 will follow Expansion 1).
HV units added into existing substations will use the existing network for Electrical signal interfaces. Same network interfaces will
Foxboro I/O cabinets located near the electrical equipment in a common building.
New HV electrical switchgear installed in Base Plant Quest areas (i.e. Amine Regeneration) will be integrated into the remote
be noted that EHT configuration is different between Base Plant and Expansion 1.
extended for additional Quest scope. Design will follow standards for each plant (e.g. HMU#3 will follow Expansion 1). It should
Quest CCS Project will have some heat tracing requirements; existing EHT network at base plant and at Expansion 1 will be
Expansion 1).
interfaces will be used for Operator interface purpose. Design will follow standards for each plant (e.g. HMU#3 will follow
In HMU#3, new motor loads will be added into the existing MCC electrical network for Electrical signal interfaces. Same network
cabinets located near the MCC’s in a common building.
Compression, Dehydration) and DeviceNet networks associated with them will be integrated into the remote Foxboro I/O
Distributed MCC’s will be implemented in the Base Plant Quest areas (HMU 1&2 Absorbers, Amine Regeneration, CO2
infrastructure has sufficient spare capacity and Quest CCS Project is not adding anything new.
During construction, Pre-com and start-up, there is a need for additional IT infrastructure and Radios, it is expected that existing
HMU operations/permit centre at Base Plant.
Details of interface
No
No
No
No
No
No
No
Do we need S/D to implement this tie in
Fire & Gas Detection system interfaces
Plant Evacuation system interfaces
Need for Deluge system and safety shower system
Loading of QUEST data into PI system
13
14
15
16
Honeywell DCS
16.2
04
Foxboro DCS
At this stage, there is no deluge system scope.
16.1
15.1
Ex 1 Evac system interface
14.2
Pipeline & Well F&G scope is unclear
13.3
Base Plant Evac system interface
Interface to Expansion 1 DCS/SIS
13.2
14.1
Interface to Foxboro DCS
Expansion 1 Intools Tie in
12.2
13.1
Base Plant Intools Tie in
12.1
Type of system interface
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InTools Database Interfaces
12
Basic Design & Engineering Package
Brief Description of interface
Item Number
07-1-AA-7739-0001
necessary inputs to PI team at Scotford for them to update the PI server as per existing site practices.
Once Quest is integrated within the DCS system, Quest tags needs to be added into the PI home node, Project will provide all the
necessary inputs to PI team at Scotford for them to update the PI server as per existing site practices.
Once Quest is integrated within the DCS system, Quest tags need to be added into the PI home node, Project will provide all the
confirmed during the Execute Phase.
In order to avoid confusion, Quest CCS Project areas associated with HMU 3 will tie back to base plant evac system. Needs to be
be confirmed during the Execute Phase.
In order to avoid confusion, Quest CCS Project areas associated with HMU 1/2 will tie back to base plant evac system. Needs to
If there is any scope in these areas, it will follow the Base Plant F&G system Architecture.
interface F&G system.
Expansion 1 F&G architecture identifies that inputs to be wired to DCS & SIS, same philosophy will be followed for HMU 3 area
with interfaces to the Foxboro DCS, using the same philosophy as Expansion 1.
Absorbers, Amine Regeneration, CO2 Compression, and Dehydration)) will be implemented in the new Honeywell Safety System
Base plant has implemented the existing F&G within Foxboro DCS system. New F&G in the Base Plant Quest areas (HMU 1&2
being utilized (i.e. not wired up to the new Quest systems).
to be done using the existing Intools databases since existing junction boxes, home run cabling, controllers, marshalling, etc are
perform the merge at later stage. Any modifications/upgrades to the HMU steam reformers and/or PSA unit controls would need
the database. Once EPCM finishes the work, this database will be handed over to operations, it is expected that Operations will
Project. An independent Unit will be added into existing Plant, area Unit architecture and site team will be the administrator for
Since Expansion 1 database has not yet been handed over to operations, a snap shot of this database will be taken for Quest CCS
(i.e. not wired up to the new Quest systems).
using the existing Intools databases since existing junction boxes, home run cabling, controllers, marshalling, etc are being utilized
merge at later stage. Any modifications/upgrades to the HMU steam reformers and/or PSA unit controls would need to be done
Once EPCM finishes the work, this database will be handed over to operations, it is expected that Operations will perform the
independent Unit will be added into existing Plant, area Unit architecture and site team will be the administrator for the database.
Since Base plant maintains an independent database, a snap shot of this database will be taken for Quest CCS Project. An
Details of interface
No
No
To be Confirmed
To be Confirmed
FGS cabinet.
Yes. New I/O chassis to be installed in existing
No
No
No
Do we need S/D to implement this tie in
Modification of Honeywell & Foxboro native Historian
Modifications of Honeywell and Foxboro DCS graphics
Interface of flow metering system with native DCS/PI/Prism
Use of FBM 228 instead of FBM 221 & its interface with Foxboro DCS
Identification of Project interfaces and its impact on DACA
PSA Control Modifications
19
20
21
22
23
24
Scope is in development for HMU#3
04
Scope is in development for HMU#1 & 2
24.1
Scope is in development
Use of new module
24.2
23.1
22.1
Scope is in development
Honeywell DCS
20.2
21.1
Foxboro DCS
Honeywell DCS
19.2
20.1
Foxboro DCS
19.1
Foxboro & Honeywell DCS systems
Interfaces with GAME @ Expansion 1
17.2
18.1
Interfaces with GAME @ Base Plant
17.1
Type of system interface
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Investigate and implement Foxboro-Honeywell Gateway PLC data transfer needs
18
Basic Design & Engineering Package
Provide inputs to successful implementation of GAME
Brief Description of interface
17
Item Number
07-1-AA-7739-0001
Expansion 1 PSA Unit is controlled via licensor supplied package PLC. Interface and configuration changes by UOP.
Base Plant PSA Unit is controlled via the main Invensys DCS. Interface and configuration changes by SPG.
At this time 3rd party interface scope is unclear and its impact on DACA architecture will be studied at later stage.
integration.
FBM 228 is strongly recommended by the technical team and this needs to be considered during hardware ordering and system
within DCS and PI, which needs to be integrated with Prism system at Shell Centre.
Quest CCS Project well head data need to be available for accounting purposes in Shell Centre. Once SCADA data is historized
ensure graphics and control schemes are seamless.
The Quest CCS Project needs to create additional process graphics for Human interface. All Ex 1 site practices will be followed to
followed to ensure graphics and control schemes are seamless.
The Quest CCS Project needs to create additional process graphics for Human interface. All Base Plant site practices will be
be historized based on existing site practices.
Quest CCS Project needs to update Honeywell DCS systems native Historian for Quest tags and necessary point parameters will
historized based on existing site practices.
Quest CCS Project needs to update Foxboro DCS systems native Historian for Quest tags and necessary point parameters will be
(including fiber optic backbone, cabinet space and switch requirements).
modules. Quest CCS Project team needs to understand spare capacity and utilize after approval from the site Operations team
control rooms. To minimize the impact to Operations, Quest will add a new PLC and redundant Foxboro communication gateway
At present, a Quantum gateway PLC provides necessary data map to share information between Base Plant and Expansion 1
given spread sheet to operations for successful GAME implementation.
Operations has provided all necessary input requirements to Quest CCS Project team, necessary data fields will be updated in the
given spread sheet to operations for successful GAME implementation (including Shell ESP and IPF requirements)
Operations has provided all necessary input requirements to Quest CCS Project team, necessary data fields will be updated in the
Details of interface
Yes
Yes
No
No
No
No
No
No
No
To be Confirmed
No
No
Do we need S/D to implement this tie in
Laboratory Information System
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26.1
25.1
04
No known scope.
Scope to be determined in the Execute Phase
Type of system interface
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Basic Design & Engineering Package
Demin Plant (Plant 251) Control
Brief Description of interface
25
Item Number
07-1-AA-7739-0001
To be Confirmed
Interface and configuration changes by SPG.
Details of interface
To be Confirmed
No
Do we need S/D to implement this tie in
Restricted
07-1-AA-7739-0001
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.
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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 deenergized 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.
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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:
ACT m³/h
Normal Flow
S m³/h
kg/h
HMU 1 & 2
Unit 240 (Units 241 & 242)
LP Steam (Utility Station)
Instrument Air
Utility Air
Nitrogen
Utility Water
Potable Water
Cooling Water Supply
Cooling Water Return
ACT m³/h
SL
NNF
NNF
NNF
AI
5
36
44
AU
NNF
NNF
NNF
GI
NNF
NNF
NNF
WU
NNF
NNF
NNF
WO
NNF
NNF
NNF
CWS
75
75
74,448
(75)
(75)
(74,448)
CWR
Consumption is +ve, Return or Production is (-ve)
958
6
29
23
11
NNF
78
(79)
LP Steam
SL
77,655
162,125
81,582
LT HP Steam
SH
20
450
36
(157)
(154)
(153,557)
(175)
Rec'd Clean Condensate
RCC
Instrument Air
AI
15
107
131
19
Utility Air
AU
NNF
NNF
NNF
29
Nitrogen
GI
3
33
39
32
Utility Water
WU
NNF
NNF
NNF
11
Potable Water
WO
NNF
NNF
NNF
15
Waste Water (Purge Water)
(12)
(12)
(11,792)
(12)
Demin Water (Supply)
WD
185
185
184,893
195
Demin Water (Return)
WD
(190)
(185)
(184,893)
(200)
Cooling Water Supply
CWS
5,755
5,743
5,739,182
6,249
(5,787)
(5,743)
(5,739,182)
(6,284)
Cooling Water Return
CWR
Consumption is +ve, Return or Production is (-ve)
HMU 3
Unit 440 (Unit 441)
ACT m³/h
19.5.1.
S m³/h
kg/h
NNF
NNF
NNF
7
7
6,527
3
18
23
NNF
NNF
NNF
NNF
NNF
NNF
NNF
NNF
NNF
NNF
NNF
NNF
(7)
(7)
(6,503)
CWS
113
113
112,920
(113)
(113)
(112,920)
CWR
Consumption is +ve, Return or Production is (-ve)
ACT m³/h
Rec'd Clean Condensate
Instrument Air
Waste Water (Cont RCC)
Temp
°C
Normal
Press
kPag
45
204
211
11
NNF
78
(78)
2,000
55
250
250
10,992
NNF
78,170
(78,170)
160
45
45
40
25
25
25
30
355
700
700
900
425
425
425
250
S m³/h
kg/h
°C
kPag
(171)
134
204
314
11
15
(12)
194
(194)
6,236
(6,236)
170,325
800
(170,704)
164
250
372
10,993
14,990
(11,792)
194,138
(194,138)
6,231,855
(6,231,855)
145
257
74
45
45
15
5
5
35
22
79
25
41.9
355
4370
600
700
700
900
525
525
500
700
650
510
503
Design allowances for piping design, which are not additive to
Unit demand for SL, WU, AU, GI. CW is part of hydraulic study
SL
BFW
AI
AU
GI
WU
WO
Utility
Unit 251
kg/h
Design allowances for piping design, which are not additive to
Unit demand for SL, WU, AU, GI. CW is part of hydraulic study
Quest CO2 (Amine Regeneration, CO2 Compression etc)
ACT m³/h
S m³/h
kg/h
ACT m³/h
Units 246, 247 & 248
LP Steam (Utility Station)
Boiler Feed Water
Instrument Air
Utility Air
Nitrogen
Utility Water
Potable Water
Waste Water
Cooling Water Supply
Cooling Water Return
Design Flow
S m³/h
S m³/h
kg/h
RCC
AI
157
154
153,557
1
6
7
NNF
NNF
NNF
Consumption is +ve, Return or Production is (-ve)
ACT m³/h
S m³/h
kg/h
°C
kPag
958
7
3
29
22
11
NNF
(7)
113
(113)
7
24
204
211
11
NNF
(7)
113
(113)
2,000
6,853
29
250
250
10,993
NNF
(6,828)
112,920
(112,920)
160
121
45
45
15
5
23
35
25
32.7
355
5250
700
700
900
525
525
2900
425
355
ACT m³/h
S m³/h
kg/h
°C
kPag
175
1
(175)
171
10
(171)
170,704
13
(170,704)
74
45
74
470
700
470
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
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PIPING
UTILITY
Plant Supply Header
Battery Limit
DESIGN
NOTES
At Source or Producer at
NOTES & LEGEND
Note
OPERATING
MAX
NORM
No.
OPERATING
MIN
MAX
NORM
MIN
Darker cell shading indicates data from Base Upgrader Project
1.0 STEAM
General Notes
1.1
1.1, 1.2
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
HP (SH, 600# flange rating)
IP (SAT, 600# flange rating)
kPag
5170
4550
4500
4370
4480
4350
4300
°C
415
405
400
395
405
400
380
kPag
4850
4410
4220
4170
4340
4150
4100
°C
290
262
455
sat
262
255
sat
kPag
1100
950
885
835
915
850
800
°C
260
250
240
230
250
220
200
kPag
500
385
370
355
350
335
320
°C
250
240
160
sat
240
160
sat
1.3
impact on local conditions within the battery limits
Users of steam should design for pressure drop of 70, 70, 35 and 35
1.2
kPa respectively for HP, IP, SHMP and LP steam headers if they are
located in the current plant area
SHMP (SH, 150# flange rating)
HP Steam turbine drivers shall be designed for a min. inlet pressure
LP (SH, 150# flange rating)
1.3
of 3800 kPag @ 270°C
2.0 BOILER FEEDWATER
High Pressure
Low 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
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)
kPag
3.1
9060
7850
6600
6500
3.1
150
53
34
27
1400
800
750
700
°C
150
53
34
27
kPag
1400
800
750
50
°C
130
98
95
kPag
1100
950
900
°C
27
3.0 CONDENSATE
STG HP condensate (600#)
All condensate returned to the Utility plant will be considered
°C
potentially contaminated and must flashed and pumped back to the
Utility plant.
STG LP condensate (150#)
RCC (150#)
kPag
3.1
4.0 FIREWATER
Firewater (150#)
900
5
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5.0 INSTRUMENT / UTILITY AIR
Instrument Air (150#)
kPag
1200
860
700
350
5.1
Oil Free
70
50
45
-43
5.2
Pressure dew point -40°C
1200
860
700
300
5.3
Users will see 70 kPa pressure drop from producer per line space
70
50
45
-43
kPag
880
625
525
-
°C
23
-
5
-
kPag
900
750
525
525
°C
33
23
5
1
kPag
1120
200
190
190
°C
33
23
5
1
kPag
500
470
270
140
°C
33
23
5
1
kPag
420
320
240
140
°C
45
35
35
30
kPag
750
750
415
415
°C
45
35
25
5
kPag
800
550
420
420
7.1
Max temperature for MVGO cooling only
58
25
25
18
7.2
Wintertime minimum to prevent icing
kPag
800
420
240
240
°C
58
48
45
45
kPag
1500
1100
900
800
°C
70
50
5 – 45
-43
kPag
800
545
520
350
°C
70
45
40
15
5.1, 5.2, 5.3
°C
Utility Air (150#)
kPag
5.1, 5.2, 5.3
°C
6.0 POTABLE / UTILITY WATER / RAW WATER
Potable Water (150#)
Utility Water (150#)
Raw Water (150#)
Clarified water to CT (150#)
WWTU effluent to CT (150#)
Demin (150#)
7.0 COOLING WATER
Cooling Water Supply (150#)
°C
Cooling Water Return (150#)
7.1, 7.2
8.0 NITROGEN
Nitrogen (150#)
9.0 FUEL / NATURAL GAS
Fuel Gas (150#)
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HP Natural Gas (600#)
LP Natural Gas (150#)
kPag
5600
5600
5200
4890
5000
4800
4600
°C
70
27
5
0
30
5
-30
kPag
1350
1200
1000
950
1100
950
800
°C
70
27
15
-10
30
15
-30
kPag
650
500
450
0
°C
122
98
98
-
10.0 BOILER BLOWDOWN
Boiler Blowdown (150#)
19.5.2.
Turndown
Control systems in the delivery of utilities will facilitate the operational flexibility of the Quest
CCS Project.
19.5.3.
On-Stream Factor
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.
19.5.4.
Maintainability Philosophy
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:
·
·
·
·
19.6.4.
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.
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. This
piperack provides lean and rich amine; make-up wash water and purge water return
lines as well as power cables and the stormwater return line.
To connect the Quest greenfield units with the main interconnecting piperack running
East-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 the
Unit 285 / 485 piping sleeper that is east of the Raw Water pond. The lean and rich
amine lines continue on the existing piping sleeper and piperacks to the new piperack
running to the Quest greenfield units.
19.8. Key Operating Parameters
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 is
used 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 remove
any debris from the pipeline. Primarily, the filters are to prevent millscale from
reaching the formation face. Quality sampling of the CO2 stream will take place at
Scotford to ensure it meets minimum pipeline specifications. Quality sampling will
impact pipeline operation, but will not be part of this scope, and will be completed by
Fluor.
d) A Supervisory Control and Data Acquisition (SCADA) system will collect and transmit
data from the pipeline and well sites back to the Capture Facility Control Room and
will 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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20.2.5.
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
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 amine
absorption facility.
•
Contaminants normally present would be up to 27 ppmw glycol (TEG); from 4 to 6
lbs H2O per MMSCF; plus residual H2/CH4 from the Stripper.
•
The primary indication of CO2 purity will be from the compressor CO2 Delivery
Analyser.
•
There would not be any direct indication at the pipeline, as the CO2 is a
compressible fluid in which liquid/vapour hammer is extremely unlikely. However
pressure 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 of
throttle valve openings at the wellhead, to increase line pressure to >10 MPa. This
would ensure pipeline flow remains single phase down to 95% purity, or nominally
up to 5% hydrogen content. Capture operations would commence source
investigation based on the downward trend, regardless of the other process
indications listed above.
•
If CO2 purity drops to 97.5V%, and if an immediate resolution is not possible, then
the compressor would be placed into spillback mode, and pipeline delivery would be
closed 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 available
during operation, and does not alter design basis. Actual pipeline pressure is expected
to 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 flashing
will occur with significant impurities are present. Well bottom pressure is
approximately 14 MPa above the choke pressure due to static head. Thus gasses
would 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-up
requirements. At this pressure point on the compressor curve, the flow rate would be
93% 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
Maximum Operation Pressure
Minimum Operation Pressure (10% higher than Critical Pressure)
CO2 Critical Pressure
14.79 MPa @ 60°C
14.0 MPa
8.5 MPa
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 Joules
with 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
Table 5.5-1 Mechanical Design Data
General
Pipeline Material
Material Toughness
Pipeline Location Class
(CSA Z662-2007)
LBV Sites
Launching Facilities
Receiving Facilities
Main Flow Line Data:
Length
Size
Wall Thickness
ASME Class
Laterals Data:
Number
Length
Size
Wall Thickness
ASME Class
Units
Value
-
CSA Z245.1 Gr. 386 Cat II
60J @ -60°C, min. 85% shear area
2
#
#
#
7
2 launchers, 3 provisions (laterals)
2 receivers, 3 provisions (laterals)
km
in NPS
mm
-
~80.4
12
12.7 (11.4 + 1.3 CA)
900#
-
5
50 - 4,200 (variable)
6
7.9 (6.6 + 1.3 CA)
900#
in NPS
mm
-
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.
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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 of
the 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 and
6#/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 the
life of the project
•
Flow rates and pressures will verify pipeline superficial velocities
•
Maximum operating temperature to confirm that temperatures do not exceed the
design 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 to
identify possible corrosion of the pipeline
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•
During routine maintenance activities when parts of the surface facilities will be
accessible, perform internal visual examination of open piping and equipment to assess for
any evidence of internal corrosion.
•
Pipeline right-of way (ROW) surveillance including: aerial flights to check ROW
condition 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 the
necessity 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 than
adjacent pig traps.
•
Pig trap systems should generally be located adjacent to each other for ease of
pigging 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 to
hazardous area classification constraints.
•
A pig trap shall not point towards hydrocarbon containing equipment, safety critical
equipment, buildings, etc. to prevent these items from damage by a pig which might be
released in case of a pig tap door failure.
20.7.
20.8.
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.
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 a
local 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 and
transmission 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 be
executed by others. This facility will require both hardwired and a communication interface
with the master SCADA PLC. These interfaces will transfer process data from the capture
facility (i.e. the local metering skid, the moisture analyzer, etc.) for control and shutdown of
the pipeline. The metering skid will be used as an integral part of the leak detection on the
pipeline system.
• The wellhead choke valve will operate with a flow control set point along with low
pressure pipeline (to maintain pipeline in supercritical state) override and high pressure
wellhead 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 remove
liquids 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 with
Enbridge 30” and 24” pipelines (currently May 2013)
• Wellsite Facilities – SIMOPS potential with Wells Pipeline construction in Scotford will
be 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 optic
fiber 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 be
located on the well pads).
A field trial of the line-of-sight CO2 gas flux monitoring technology in Q4 2011
with 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 inch
nominal 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 temperature
were modelled to capture the range of realistic temperature losses attainable from the
compressor 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 to
maintain the minimum pipeline pressure. If the wellhead pressure increases above the maximum
allowable injection pressure (10 to 12 MPa depending on wellhead temperature), the well chokes
will start to close to decrease wellhead injection pressure
o
If the wellhead pressure drops below 1 MPa (proposed value) the SC-SSSV will be
automatically closed
o
If the water content goes above specifications (proposed threshold is 8ppm), the
compressor will automatically go in recycle mode.
o
If the Hydrogen content goes above specifications (proposed threshold is 2.5%), the
compressor 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
Maximum
Operating
Operating
Alarms*
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Pipeline
Pressure
Pipeline inlet
value
value
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
LBVs
8.5 MPa
12.9 MPa
13.9 MPa
Low level 1: 8.5*
MPa
Level 1: well choke start closing to reduce
injection rate.
Low level 2: 8* MPa
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.
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).
This alarm overrides any other control
as it is safety critical.
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
Low alarm: Alarm in Scotford and closing
of the SC-SSSV (blowout detection).
Downhole
Well Pressure
Wellhead
temperature
High alarm: 10*-12*
MPa (will depend
on wellhead
temperature, to
ensure bottomhole
pressure does not
exceed 28 MPa)
High alarm: Well choke will automatically
start to close until wellhead pressure is
below maximum allowable value.
This alarm overrides any other control
as it is safety critical.
Bottom of
completion
20 MPa
28 MPa
27* MPa
Alarm in Scotford control room to
investigate high well pressure (consistency
with wellhead pressure).
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%
Level 1: 1.5%*
(normal)
Level 2: 2.5%*
Level 1: alarm in Scotford control room
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 1: alarm in Scotford control room
to investigate abnormal water content.
Level 2: 8*
lbs/MMscf
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 Design
o Pipeline
§ Thermal-hydraulic performance
§ Pipeline sizing
§ Maximum system capacity
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§
§
§
o Wells
§
·
·
·
·
Insulation requirements
Vent-valve design
Requirements for above-ground sections
Pressure-temperature in the wellbore with varying flow rate and
injection temperature
§ Cooling at the well choke
§ SC-SSSV location
Solid Deposition Risk
o Hydrate risk and mitigation in pipeline and wells
o Dehydratation limits
o Solids in the injection stream
o Impact of carryovers
Multiphase Flow
o Two-phase flow in pipeline and wellbore
o Slugging screening
Operability
o Normal operations
o Low flow events
o Emergency pipeline leak / blowdown
o Emergency wellbore blowout
o System start-up
o Vent line operability
o Liquid hammer screening
o Low water content operability
Modeling
o Impact of impurities
o 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 temperature
instability in the system, in particular at the well choke
· One-phase CO2 maximise fluid density and minimize fluid viscosity, therefore
optimising pipeline transportability
· The metering system on each wellpad loses accuracy to +/-20% which is
unacceptable because of the metering requirement and the fact that unlike most
projects the meter at the wellhead is the custody transfer meter for a CCS project as
credits 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.
HT
P/T x 2 + dP
FM + WC
ESD
Filter
Injection well
Deep MMV well
DL
Water MMV well
40m
minimum
130m
40m
minimum
DL
Line of Sight
Power/Data line
Enclosed skid with
climate control and
communication systems
40m
minimum
GP
DAS
DTS
AP
CP
Gate
DL
DAS
DTS
P/T x 2
CP
AP
SC-SSSV
40m
minimum
130m
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Data/Controls
SC-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
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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:
4 Injectors
5 Injectors
8 Injectors
Locations
Type 3
Type 2
Type 2
Type 2
8-19-59-20W4
Type 2
Type 1
Type 1
Type 1
7-11-59-20W4
Type 2
Type 3
Type 3
Type 3
5-35-59-21W4
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
Injection Well Pads
3 Injectors
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-57260002, August 2011
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[21.3]:
[21.4]:
[21.5]:
[21.6]:
[21.7]:
[21.8]
[21.9]:
[21.10]:
[21.11]:
Quest IPM Compressor Design Modeling Results, C. Clark, 07-3-ZG-7180-0004,
October 2010
Quest CCS Project: Flow Assurance, Concept Design & Operability, September 2009
(Presentation), L. Dykhno & S. Anderson
Quest Update: Flow Assurance Transient Studies, January 2010 (Presentation), L.
Dykhno & R. Lacy
Quest CCS Prospect: Flow Assurance for System Selection, November 11, 2010
(Presentation), R. Lacy, L. Dykhno, D. Peters & U. Andresen
Quest CCs Prospect: Flow Assurance for System Selection, March 10, 2011 (VAR 3
Report) R. Lacy, L. Dykhno, D. Peters & U. Andresen
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
Quest Update: Determination of Vent Line Size & Update to Hydrate Risk, May 3,
2011 (Presentation) D. Peters, R. Lacy & L. Dykhno
Quest project Fluid Flow and Flow Assurance Report - SR.11.12758, D. Peters, R.
Lacy, N. Seunsom & L. Dykhno, August 2011
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 workshop
participants particularly novelty created by interdependence of Capture, Pipeline and
subsurface 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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