Basis of Design
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basis of design...
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
Doc. No: JA004847-JSD-3500-0001 Revision: 2 Page: 2 of 66
RECORD OF AMENDMENT It is certified that the amendments listed below have been incorporated in this copy of the publication.
AMDT NO
AMENDED SECTION
PARA NO
DESCRIPTION OF CHANGES
1
5.17.3
1
Typing error corrected
2
5.17.3
5
RAO axis system definition corrected
3
T 5.18.3
-
Typing error corrected
4
7.10.5
1
Wave period sensitivity clarified
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
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HOLD'S STATUS SHEET This revision has the following HOLD's
SECTION
PARA NO
DESCRIPTION OF HOLD
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
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TABLE OF CONTENTS 1.0
EXECUTIVE SUMMARY ........................................................................................... 7
1.1
Field Overview ........................................................................................................... 7
1.2
Purpose...................................................................................................................... 8
1.3
Applicability ................................................................................................................ 8
2.0
SCOPE....................................................................................................................... 9
2.1
Field Location and Layout .......................................................................................... 9
2.2
Flexible Riser and Flowline System Scope ................................................................ 9
3.0
ABBREVIATIONS AND DEFINITIONS ................................................................... 10
3.1
Abbreviations ........................................................................................................... 10
3.2
Definitions ................................................................................................................ 11
4.0
REFERENCES......................................................................................................... 12
4.1
TSEJV References................................................................................................... 12
4.2
WEL References ...................................................................................................... 13
4.3
Codes and Standards .............................................................................................. 15
5.0
DESIGN DATA AND ASSUMPTIONS .................................................................... 16
5.1
Flexible Pipe Sizes................................................................................................... 16
5.2
Internal Pressure...................................................................................................... 16
5.3
Accidental Over Pressurisation ................................................................................ 18
5.4
Test Pressures ......................................................................................................... 18
5.5
Internal Temperature................................................................................................ 19
5.6
Internal Fluid Density ............................................................................................... 20
5.7
Fluid Composition .................................................................................................... 20
5.8
Slug Loading ............................................................................................................ 22
5.9
Produced Water Composition .................................................................................. 22
5.10
Insulation Requirements .......................................................................................... 22
5.11
Sand Production....................................................................................................... 22
5.12
Chemical Injection.................................................................................................... 23 Property of Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). Copyright Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). All rights reserved
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
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5.13
Design Life ............................................................................................................... 24
5.14
Environmental Data.................................................................................................. 24
5.15
Geotechnical Data.................................................................................................... 29
5.16
Marine Growth.......................................................................................................... 30
5.17
Vessel Data.............................................................................................................. 30
5.18
Mooring Line Data.................................................................................................... 34
5.19
Fatigue Wave Data .................................................................................................. 37
5.20
Fatigue Currents ...................................................................................................... 37
5.21
Fatigue Offsets......................................................................................................... 37
5.22
Hydrodynamic Coefficients ...................................................................................... 38
6.0
INTERFACES .......................................................................................................... 40
6.1
Riser Entry Configuration Data ................................................................................ 40
6.2
Riser Interface Connection Specifications ............................................................... 40
6.3
Flowline Tie-In Data ................................................................................................. 41
6.4
Flowline Interface Connection Specifications........................................................... 41
6.5
Ancillary Equipment ................................................................................................. 44
6.6
Installation Tolerances ............................................................................................. 44
7.0
METHODOLOGY..................................................................................................... 45
7.1
Determination of Flexible Pipe Components ............................................................ 45
7.2
Material Selection for the Flexible Pipe Components .............................................. 45
7.3
Pressure and Tension Resistance of the Flexible Pipe............................................ 45
7.4
Hydrostatic Collapse of the Flexible Pipe................................................................. 47
7.5
Crushing Capacity of the Flexible Pipe .................................................................... 48
7.6
Erosion of the Flexible Pipe ..................................................................................... 49
7.7
Annulus Calculations of the Flexible Pipe ................................................................ 49
7.8
Reverse End Cap Effect of the Flexible Pipe ........................................................... 51
7.9
Cathodic Protection of the Flexible Pipe .................................................................. 52
7.10
Riser Configuration Analysis .................................................................................... 53 Property of Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). Copyright Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). All rights reserved
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
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7.11
Interference Analysis................................................................................................ 58
7.12
Fatigue Analysis ....................................................................................................... 58
7.13
In-Place Tie-In Connection Analysis ........................................................................ 60
7.14
End Fitting Design.................................................................................................... 61
7.15
Bend Stiffener Design .............................................................................................. 63
7.16
Dropped Objects Impact Resistance........................................................................ 64
7.17
On-Bottom Stability .................................................................................................. 64
APPENDICES Appendix A
Drawings
Appendix B
FPSO RAOs data
Appendix C
Fatigue Wave Data
Appendix D
Dynamic Analysis Load Case Matrix
Appendix E
Description of Dynamic Analysis Load Cases Titles Signification
Appendix F
Pressure Conversion Calculations
Appendix G
Gas Injection Back Flow Fluid Composition
Appendix H
Sand Erosion Data
Appendix I
Location of Forces on Manifold /PLEM Hubs
Appendix J
Additional Chemical Injection Details
Appendix K
Design Data Sheet for On Bottom Stability
Appendix L
Extreme Riser Connected Motion Details
Appendix M
Riser Fatigue Analysis Methodology
Appendix N
Production Flowrate Details
Appendix O
Riser Column Motions During Disconnection
Appendix P
Referenced Correspondence
Appendix Q
Topside Piping Loads
Appendix R
Slugging Data
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 1.0
EXECUTIVE SUMMARY
1.1
Field Overview
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WEL is developing the Enfield oilfield, located in permit WA 27 1P, off Australia’s North West Cape, using an FPSO and subsea wells. A ship shaped, double hulled, Suezmax size, disconnectably moored FPSO will be located approximately 3km to the east of Enfield in approximately 400m water depth, with processing facilities to handle 100,000 bopd and 140,000 bpd total liquids. These facilities are sized to accommodate later tie-in of a Notional Field in the vicinity. The Enfield reservoir will be developed with 5 subsea gas-lifted single leg production wells (4 horizontal, 1 vertical) and 6 subsea single leg vertical water injection wells. The area is subject to severe cyclone activity and it has been decided that the FPSO will use a disconnectable mooring system. The system will comprise an external riser turret mooring connected to a bow-mounted rigid arm. Gas produced from the reservoir not needed for fuel will be re-injected into the Enfield reservoir via two clustered gas injection wells. Crude oil will be exported via a floating hose into non-dedicated offtake tankers, which will moor in tandem off the stern of the FPSO. The development area is close to the Ningaloo Marine Park, which is an area of high environmental significance. The flexible pipes in question are to operate as production, gas lift, gas injection and water injection lines. A hybrid Lazy Wave type configuration is the base case for the risers at the FPSO. Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV) has been selected for the supply of the flexible risers, flowlines and umbilicals system which is comprised of but not limited to the following items: 2 No. 9” Production flexible risers with end fittings. 1 No. 8” Production / Test flexible riser with end fittings. 1 No. 6” Gas Lift flexible riser with end fittings. 1 No. 6” Gas Injection flexible riser with end fittings. 1 No. 10” Water Injection flexible riser with end fittings. 2 No. 9” Production flexible flowlines with end fittings. 1 No. 8” Production / Test flexible flowline with end fittings. 1 No. 6” Gas Lift flexible flowline with end fittings. 1 No. 6” Gas Injection flexible flowline with end fittings. 2 No. 10” Water Injection flexible flowlines with end fittings. 1 No. Dynamic / static EHU 3 No. Infield EHUs 1 No. Sliding bend stiffener per riser (including EHU) for the FPSO end. 1 No. Bend stiffener connector per riser (including EHU) for the hang-off location on the riser column. Bend stiffener connector housing and ROV removable caps as appropriate. 1 No. Set of buoyancy modules (including clamps) per riser and EHU. 1 No. Set of bracelet anodes per riser located at the seabed end fitting. 1 No. Set of bracelet anodes per flowline at each end fitting. Uraduct for all risers except water injection riser and EHU (as required). Property of Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). Copyright Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). All rights reserved
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
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Hold back clamp for each riser / flowline connection and EHU static / dynamic transition (as required). Dummy end fitting for each riser top connection. 1 No. Sliding stopper for the bend stiffener on each riser (for installation phase) if required, to be confirmed during detailed design. 2 No. Test/pulling heads per riser and flowline. 1 No. Abandonment cable per riser, flowline and EHU (as required). 1 No. Set of standard packing rigging per riser, flowline and EHU. 1 No. Set of bend restrictor assembly (as required) for each of the following flowline / EHU ends: - Flowlines B, C, D and E and EHUs L and M: at E-DC1 connection. - Flowlines F and K and EHU L : at E-DC2 connection. - Flowline G and EHU N: at E-DC4 connection. - Flowline K and EHUs M and N: at E-DC3 connection. A field layout drawing is included in Appendix A. 1.2
Purpose The purpose of this document is to present the engineering design data, methods and acceptance criteria for the design of the FPSO flexible risers, flowlines and associated TSEJV supplied equipment for the Enfield Area Development Project. This document shall be used to highlight any required data that is outstanding and any assumptions made in lieu of missing data. Data specific to the EHUs is included in reference /A23/.
1.3
Applicability This document is to be used as the input for the design and analysis of the flexible riser and flowline system to be supplied by TSEJV to the ENFIELD AREA DEVELOPMENT SUBSEA EPIC, TSEJV Job No. JA004847, Contract No. 00000148.
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 2.0
SCOPE
2.1
Field Location and Layout
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The route layout of the flexible risers, flowlines and EHUs in relation to the FPSO and wellheads is shown in the drawings included in Appendix A. The locations of main items on the field are detailed below in Table 2.1.1 (reference /B23/). Location FPSO E-DC1 E-DC2 E-DC3 E-DC4
Easting (m) 189 966 188 003 188 361 186 564 185 450
Northing (m) 7 621 597 7 621 533 7 623 334 7 620 853 7 619 350
Water Depth LAT (m) 396 516 495 551 552
Table 2.1.1 Enfield Field Layout Details Notes: a) All coordinates based on GDA 94. 2.2
Flexible Riser and Flowline System Scope The scope of supply for the flexible risers, flowlines and EHUs is summarised below in Table 2.2.1 (reference /B1/ data sheet 0201 revision 3). The full scope of supply for the project is presented in Section 1.1. Item
WEL Flexible Service Riser / Nominal Nominal Item No Flowline Internal Length Diameter (m) (Inches) 1 & 2 R2 & R5 Production Riser 9” 2 x 830 3 R4 Production/Test Riser 8” 830 4 R3 Gas Lift Riser 6” 830 5 R1 Gas Injection Riser 6” 820 6 R7 Water Injection Riser 10” 815 7&8 B&D Production Flowline 9” 2060 + 1913 9 C Production/Test Flowline 8” 1911 10 E Gas Lift Flowline 6” 1853 11 G Gas Injection Flowline 6” 4974 12 & 13 F & K Water Injection Flowline 10” 3051 + 3521 14 R6 EHU Riser 815 15 A EHU Flowline 2202 16 - 18 L, M & N EHU 2212, 1753, Flowline 2013
Proposed Configuration
Hybrid Lazy Wave Hybrid Lazy Wave Hybrid Lazy Wave Hybrid Lazy Wave Hybrid Lazy Wave N/A N/A N/A N/A N/A Hybrid Lazy Wave N/A N/A
Table 2.2.1 Flexible Riser, Flowline and EHU Scope Notes: b) Flexible and EHU lengths and configuration presented above are preliminary and subject to change during detailed design. c) All risers and flowlines will be rough bore type structures except for the water injection flowlines which will be smooth bore type structures.
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 3.0
ABBREVIATIONS AND DEFINITIONS
3.1
Abbreviations API ASB CAD DAF DnV DP EHU EPIC FAT FOP FOW FPSO GRV HAT Hmax Hs ID LAT MBR MFOP MODU MOP MSL NRV OST OTC PLEM Poff QS RAO RECE RP Rp RTM SBM TBA TDS THmax Tm TOPL Tp TSEJV Tz UF VLS WEL
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American Petroleum Institute Above Sea Bed Computer Aided Design Dynamic Amplification Factor Det Norske Veritas Design Pressure Electro-Hydraulic Umbilical Engineering, Procurement, Installation and Commissioning Factory Acceptance Test Full of Product Full of Water Floating, Production, Storage and Off-Loading Facility Gas Release Valve Highest Astronomical Tide Maximum Single Wave Height Significant Wave Height Internal Diameter Lowest Astronomical Tide Minimum Bending Radius Maximum Flowing Operating Pressure Mobile Offshore Drilling Unit Maximum Operating Pressure Mean Sea Level Non Return Valve Offshore Strength Test Offshore Technology Conference Pipeline End Manifold Offshore Strength Test Pressure Quasi-static Response Amplitude Operator Reverse End Cap Effect Recommended Practice Return Period Riser Turret Mooring Single Buoy Moorings To Be Advised Technical Data Sheet Period of Maximum Wave Spectral Mean Wave Period Technip Oceania Pty Ltd Spectral Peak Period Technip Oceania Subsea 7 Enfield Joint Venture Average Zero-Crossing Wave Period Utilisation Factor Vertical Lay System Woodside Energy Ltd
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3.2
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Definitions Touch Down Point Sag Bend
Hog Bend
Location where the flexible riser touches down onto the seabed. Section of catenary of the flexible riser located around the lowest vertical point of the catenary shape (i.e. the closest point to the seabed). Highest section of flexible riser supported by the buoyancy modules.
A sketch identifying the locations defined above is included below.
Riser Column Bend Stiffener and BSC
Hog Bend Touch Down Point Riser Subsea End fitting including hold back anchor
Sag Bend
Sketch 3.2.1 Flexible Riser Configuration Definitions
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 4.0
REFERENCES
4.1
TSEJV References
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[A1]
Technip Detailed Procedure 04 DTF T 001 Rev 6 “Flexible Pipe Design, Selection of Type of Flexible Pipe Structure”
[A2]
Technip Detailed Procedure 04 DTF 002 Rev 11 “Flexible Pipe Design, Determination of Pipe Components”
[A3]
Technip Detailed Procedure 04 PES T 428 Rev 1 "Stress Analysis in Flexible Pipes”
[A4]
Technip Detailed Procedure 04 PES T 417 Rev 1 "Guidelines for Design and Analysis of Dynamic Riser Systems”
[A5]
Technip Detailed Procedure 04 DIE T 211 Rev 2 "Design of Stiffeners, Design Rules"
[A6]
Technip Detailed Procedure 04 DIE T 111 Rev 1 "End-Fitting Material Selection"
[A7]
TSEJV Document JA004847-CN-3532-0002 “Water Ingress Management Plan”
[A8]
TSEJV Document JA004847-CN-3561-0001 “Flexible Riser End Fitting Design Report”
[A9]
TSEJV Document JA004847-REP-3535-0005 “Flexible Flowline End Fitting Design Report”
[A10]
TSEJV Document JA004847-CN-3552-0001 “Flexible Pipe Design Software Description”
[A11]
TSEJV Document JA004847-CN-3554-0002 “Flexible Riser Dynamic Analysis Report”
[A12]
JA004847/TSEJV/WEL-TQ017 “Loss of Buoyancy Module”
[A13]
TSEJV Document JA004847-CN-3533-0004 “On Bottom 3D Stability Methodology”
[A14]
TSEJV Document JA004847-CN-3553-0001 “Flexible Riser Design Report”
[A15]
TSEJV Document JA004847-REP-3535-0003 “Flexible Flowline Design Report”
[A16]
JA004847/TSEJV/WEL-TQ010 “Missing data: Maximum Flowing Operating Pressures”
[A17]
JA004847/TSEJV/WEL-TQ019 “Produced Fluid Composition with Gas Lift” JA004847/TSEJV/WEL-TQ009
[A18]
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“Selection of vessel draft / RAOs set resulting in highest vertical motions for dynamic and fatigue analysis”
4.2
[A19]
JA004847/TSEJV/WEL-TQ023 “Revised Load Case Matrix for Dynamic Analysis (revB)”
[A20]
TSEJV Document JA004847-CN-3532-0001 “Riser Configuration Assessment Technical Note”
[A21]
TSEJV Document JA004847-CN-8002-0001 “Flexible Riser Installation Analysis”
[A22]
JA004847/TSEJV/WEL-TQ033 “Hydrodynamic Coefficients for Riser Dynamic Analysis”
[A23]
DUCO Document 04-06-1836 “EHU Basis of Design”
[A24]
Interface Agreement TS-SB-010-055 “Vessel Fatigue Offset”
[A25]
TSEJV Document JA004847-CN-8002-0003 “Flexible Flowline Installation Analysis”
[A26]
JA004847/TSEJV/WEL-TQ035 “End Fitting Taper for 6” Risers”
[A27]
JA004847/TSEJV/WEL-TQ013 “Description of the “independent” load cases for dynamic analysis” (Note that this includes the non-cyclonic joint occurrence Metocean data).
[A28]
JA004847/TSEJV/WEL-TQ057 “Production Riser OHTC”
WEL References [B1]
Project Basis of Design Document No: B2500SG7, Revision 9
[B2]
Basis of Design for On-Bottom Stability of Flowlines and Umbilicals Document No: K2040RX0008, Revision 0
[B3]
RTM Motion Analysis Report Document No: K4000RG0007, Revision 2
[B4]
Turret and Mooring System Information and Requirements for Subsea Tender Document No: K4000RG2, Revision 2
[B5]
Final Metocean Design Criteria for the Vincent/Enfield/Laverda Development Document No: R1119, Revision 4
[B6]
Log of Tenderers Qualifications - Technical VEPROD-23879-V12-Subsea, Revision M Anchoring Anchorlegs General Arrangement Drawing No: K 4060 D S 001 0001, Revision C
[B7]
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[B8]
Riser Column Riser Column General Arrangement Drawing No: K 4101 D G 001 0001, Revision C
[B9]
Specification for Riser System Analysis Document No: K2040SX11, Revision 2
[B10]
Specification for Flexible Pipe Design, Manufacture and Installation Document No: K2040SX12, Revision 2
[B11]
Permissible Loads KC4-10 Hubs & Structure Document No: IDS-0000021124, Version 01
[B12]
Design of Cathodic Protection Systems for Offshore Pipelines (Amendments/Supplements to DnV RP B401) Document No: DEP 30.10.73.32-Gen, July 1996
[B13]
Minutes of meeting 15/04/04 Document No: 29774V2
[B14]
Minutes of meeting 23/03/04 Document No: 29522v1
[B15]
Email dated 13/04/2004 from Steve Buchan – included in Appendix P Document No: N/A
[B16]
Meeting held with Metocean (WNI) on 07/04/04
[B17]
Anchorlegs Length and Anchor Design Loads Calculation Document No: K4060CS0001, Revision 0
[B18]
Minutes of meeting 20/04/04 Document No: 30132v1
[B19]
Term Head KC4-10, IP, ID10, 10” SPO, R1 Document No: XD-0001005404
[B20]
Term Head KC4-10, IP, ID10, 8” SPO, R1 Document No: XD-0001005722
[B21]
Term Head KC4-10, IP, ID6, 6” SPO, R1 Document No: XD-0001005631
[B22]
Interface item number TS-SB-004-041
[B23]
FPSO East subsea Facilities Layout Drawing No: SK1580, Revision C
[B24]
Interface item number SB-TS-004-074
[B25]
Minutes of meeting 26/05/04 Document No: 31434
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design [B26]
Email dated 28/06/04 from WEL Reference No: WELS/TSEJV/067: Production and Production Test Line Gas Density
[B27]
Email dated 6/09/04 from WEL Reference No: WELS/TSEJV/102: Flexible Riser & Flowline Design Review – Close Out Actions
[B28]
Email dated 28/06/04 from WEL Reference No: WELS/TSEJV/065: Additional Metocean Items 1 & 2 (Internal Wave)
[B29]
Email dated 19/07/04 from SBM Riser Entry Timehistories
[B30]
Email dated 19/07/04 from SBM Timehistory for Case 1
[B31]
Email dated 19/07/04 from SBM Timehistory for Case 4 and not Case 3
[B32]
Email dated 21/07/04 from SBM Case 2 Timehistories
[B33]
Email dated 21/07/04 from SBM Case 3 Timehistories
[B34]
Correspondence WELS/ TSEJV/154 “WEL Comments on Riser and Flowline BOD Rev.0: Shutdowns Injection (Updated)”
[B35]
4.3
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and
Chemical
Correspondence WELS/ TSEJV/155 “Riser Condition for Disconnection”
Codes and Standards The following is a list of design codes and standards used in addition to Technip’s internal design rules for the design of the flexible pipes and associated equipment. Ref No. S1
Code No.
Title
S3
API RP 17B 3rd Edition, March 2002 API 17J 2nd Edition, Effective December 2002 DnV RP B401
S4
DnV RP E305
S5
DnV OS-F101
S2
Recommended Practice for Flexible Pipe Specification for Unbonded Flexible Pipe Second Edition Recommended Practice for Cathodic Protection Design Recommended Practice for On-Bottom Stability of Pipelines Submarine Pipeline Systems, January 2000
Table 4.3.1 Codes and Standards used for the Flexible Risers and Flowlines Design
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 5.0
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DESIGN DATA AND ASSUMPTIONS This section presents the design data to be used in the engineering of the flexible riser and flowline system. Data extracted from a reference has been noted whereas data which has been assumed, interpolated or is missing has been highlighted.
5.1
Flexible Pipe Sizes The flexible pipe sizes are presented in Table 5.1.1 below (reference /B23/): Item
1 2 3 4 5 6 7 8 9 10 11 12 13
WEL Item No R2 R5 R4 R3 R1 R7 B D C E G F K
Service
Route Direction
Internal Diameter
Production 2 Production 1 Production / Test Gas Lift Gas Injection Water Injection Production 1 Production 2 Production / Test Gas Lift Gas Injection Water Injection Water Injection
F/L D to FPSO F/L B to FPSO F/L C to FPSO FPSO to F/L E FPSO to F/L G FPSO to F/L F E-DC1 to R5 E-DC1 to R2 E-DC1 to R4 R3 to E-DC1 R1 to E-DC4 R7 to E-DC2 E-DC2 to E-DC3
9” (228.6mm) 9” (228.6mm) 8” (203.2mm) 6” (152.4mm) 6” (152.4mm) 10” (254.0mm) 9” (228.6mm) 9” (228.6mm) 8” (203.2mm) 6” (152.4mm) 6” (152.4mm) 10” (254.0mm) 10” (254.0mm)
Table 5.1.1 Flexible Riser and Flowline Sizes Notes: a) Where F/L means flowline. 5.2
Internal Pressure The internal pressure requirements for the flexible risers and flowlines are detailed below in tables 5.2.1, 5.2.2 and 5.2.3 (derived from reference /B1/ data sheet 0614 revision 4, and reference /A16/). Item 1&2 3 4 5 6
WEL Item No R2 & R5 R4 R3 R1 R7
Service Production Production / Test Gas Lift Gas Injection Water Injection
Max Differential Pressure (Barg) 238 238 237 280 258
Max Internal Pressure (Barg) 260 260 243 287 296
Table 5.2.1 Risers Design Pressures Notes: a) The pressures presented above were calculated from the data specified by WEL in full accordance with reference /S5/. The conversion calculations are included in Appendix F.
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design b)
c)
d)
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The maximum differential pressure presented above corresponds to the maximum differential pressure along the pipe accounting for external hydrostatic pressure, internal head of fluid at maximum density and maximum wave effect. This is the pressure used to design the flexible pipe except for the pressure sheath / inner tube (see note c below). The maximum internal pressure presented above corresponds to the maximum absolute design pressure that will be seen along the pipe accounting for internal head of fluid at maximum density. This pressure is the design pressure used for the design of the pressure sheath / inner tube only. The pressures presented for the water injection riser is for the base case of a smooth bore flowline and rough bore riser. Item
7&8 9 10 11 12 & 13
WEL Item No B&D C E G F&K
Service Production Production / Test Gas Lift Gas Injection Water Injection
Max Differential Pressure (Barg) 223 223 203 248 258
Max Internal Pressure (Barg) 270 270 245 291 314
Table 5.2.2 Flowlines Design Pressures Notes: a) The pressures presented above were calculated from the data specified by WEL in full accordance with reference /S5/. The conversion calculations are included in Appendix F. b) The maximum differential pressure presented above corresponds to the maximum differential pressure along the pipe accounting for external hydrostatic pressure, internal head of fluid at maximum density and maximum wave effect. This is the design pressure used to design the flexible pipe except for the pressure sheath / inner tube (see note c below). c) The maximum internal pressure presented above corresponds to the maximum absolute design pressure that will be seen along the pipe accounting for internal head of fluid at maximum density. This pressure is the design pressure used for the design of the pressure sheath / inner tube only. d) The pressures presented for the water injection flowlines is for the base case of a smooth bore flowline and rough bore riser.
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
Item
WEL Item No
Service
1&2 3 4 5 6 7&8 9 10 11 12 & 13
R2 & R5 R4 R3 R1 R7 B&D C E G F&K
Production Production / Test Gas Lift Gas Injection Water Injection Production Production / Test Gas Lift Gas Injection Water Injection
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MOP Differential Pressure (Barg) 226 226 225 265 241 211 211 191 233 241
MFOP Differential Pressure (Barg) 63 63 208 240 223 26 26 174 208 223
Table 5.2.3 Risers and Flowlines Operating Pressures Notes: a) The maximum differential pressures presented above correspond to the maximum differential pressure along the pipe accounting for external hydrostatic pressure, internal head of fluid at maximum density and maximum wave effect. b) The pressures presented for the water injection risers and flowlines is for the base case of a smooth bore flowline and rough bore riser. c) As defined in reference /S5/, MOP values include for shut-in pressures. For specific aspects of the design such as the fatigue assessment of the risers, the MFOP values are used. d) Differential pressures included above are maximum differential pressures. 5.3
Accidental Over Pressurisation An accidental internal over pressurisation of all flowlines and risers can occur of between 10% and 16% of design pressure for a duration of 15 minutes. The probability of such an occurrence is 10-2 or less (reference /B1/ data sheet 0614 revision 4). The pressures to be considered during structure design are different for the overall structure itself and the pressure sheath thickness. The pressure sheath thickness is determined using the maximum internal pressure without the 16% overpressure as this is a short term event only and the sheath thickness is governed by creep which is a long term event. All other structure design parameters will consider the 16% overpressure to be the design pressure.
5.4
Test Pressures For the risers the nominal factory acceptance test (FAT) pressure shall be 1.5 times the design pressure specified (reference /S2/). For the flowlines the nominal factory acceptance test (FAT) pressure shall be a minimum of 1.3 times the design pressure specified (reference /S2/) and shall ensure the flowlines have been tested to a pressure above that seen during an offshore strength test. Nominal offshore leak test pressure shall be 1.1 times design pressure specified for all risers and flowlines. Property of Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). Copyright Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). All rights reserved
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To allow for the event of damage to the pipe during offshore installation where it is considered that the structural integrity of the pipe may have been compromised, the pipe shall be designed to withstand a nominal offshore strength test pressure of 1.25 times the design pressure specified for all risers and flowlines. An over pressurisation allowance of 5% shall be applied to the nominal test pressure for FAT and for offshore tests. This is for calculation purposes only to allow for the fact that during stabilisation of the required pressures, there may be up to 5% over pressure. See Appendix F for the test pressures (excluding the 5% over pressurisation) to be considered for each riser and flowline. 5.5
Internal Temperature
5.5.1
General The flexible pipes will be subjected to the internal design and operating temperatures detailed below in Table 5.5.1.1 (reference /B1/ data sheet 0614 revision 4). Item
WEL Item No
1 & 2 R2&R5 3 R4 4 R3 5 R1 6 R7 7&8 B&D 9 C 10 E 11 G 12 & 13 F & K
Design Temperature (oC) Min Max
Service
Production Production/Test Gas Lift Gas Injection Water Injection Production Production/Test Gas Lift Gas Injection Water Injection
0a) 0 a) 0 0 a) 0 0 a) 0 a) 0 0 a) 0
70 70 65 65a) 65 70 70 65 65a) 65
Maximum Operating Temperature (oC) 65 65 60 60 60 65 65 60 60 60
Table 5.5.1.1 Design and Operating Temperatures Notes: a) See below in sections 5.5.2 and 5.5.3 additional temperature requirements for the production and gas injection risers and flowlines. 5.5.2
Production Risers and Flowlines At production start up into a depressurised flowline, the inner wall temperature of the flowline may be as low as -26 C rising to 0 C after approximately 1 hour (reason for low temperature is initial gas production). Winter temperature profiles (assuming fully flooded insulation) for the production and test risers and flowlines are included in Appendix N.
5.5.3
Gas Injection Risers and Flowlines During gas injection backflow into a depressurised flowline, the inner wall temperature of the flowline may be as low as -17 C increasing to 0 C after approximately 10 seconds. The maximum temperature during gas injection backflow shall be 55 C (reference /B1/ data sheet 0614 revision 4).
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Internal Fluid Density The internal fluid densities during operation for the flexible risers and flowlines are detailed below in Table 5.6.1 (reference /B6/, item 262). Water density is taken conservatively as 1026 kg/m3 (reference /B1/ data sheet 0302 revision 2). Note that the internal fluid for the risers and flowlines for installation (i.e. flooded or empty) will be determined during detailed installation analysis. If they are installed empty, after installation the risers and flowlines will be flooded for the offshore pressure testing. Item
WEL Item No
Service
Fluid Density at Manifold / Well (kg/m3)
1 2 3 4 5 6 7 8 9 10 11 12 13
R2 R5 R4 R3 R1 R7 B D C E G F K
Production 2 Production 1 Production/Test Gas Lift Gas Injection Water Injection Production 1 Production 2 Production/Test Gas Lift Gas Injection Water Injection Water Injection
N/A N/A N/A N/A N/A N/A 371 - 488 391 – 545 476 - 631 177 205 1026 1026
Fluid Density at Riser Seabed End (kg/m3) 315 - 461 287 - 379 380 - 562 165 189 1026 287 - 379 315 - 461 380 - 562 165 189 1026 1026
Fluid Density at Top of Riser (kg/m3) 135 – 205 123 – 164 173 – 260 163 184 1026 N/A N/A N/A N/A N/A N/A N/A
Table 5.6.1 Internal Fluid Densities Notes: a) See section 7.17.3 for internal fluid details for on bottom stability analysis. b) See Appendix D for internal fluid details for the dynamic analysis. c) When the riser column is disconnected for any conditions worse than the 50 year non-cyclonic, the production and production / test risers and flowlines will be depressurised and the contents will quickly settle out, leaving the upper section gas filled. The density of the inner fluid at this time will be 1.3 kg/m3 (reference /B26/). All other risers and flowlines will remain pressurised except for maintenance or in an emergency (reference / B35/). 5.7
Fluid Composition
5.7.1
Production Fluid Data as follows (reference /B1/ data sheet 0206 revision 5): The design composition of CO2 is 5% mol in the gas phase at standard conditions. The design composition of H2S is to be taken as 25ppm in the gas phase at standard conditions. Produced water will occur from year 1. Maximum produced water content 95% (see data included in Appendix N). See section 5.9 for details of the produced water pH.
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See Appendix N for details of the production flowrate and temperature (reference /B6/, item 323 and 325).The temperature is to be extrapolated between the years and the temperatures given for 2020 are to continue to the end of field life (reference /B13/, item 1). 5.7.2
Gas Injection Data as follows (reference /B1/ data sheets 0206 revision 5 and 0302 revision 2): The design composition of CO2 is 6.5% mol in the gas phase at standard conditions. The design composition of H2S is to be taken as 25ppm in the gas phase at standard conditions. The gas is dry, except for the backflow scenario which is detailed below (reference /B1/ data sheets 0206 revision 5 and 0302 revision 2): Nominal 4 occurrences per year back flowing at 10 MMscf/d with choke fully open (flow for approx 8 hours) Nominal 1 occurrence per year back flowing at 10 MMscf/d using choke to pressurise the flowline and then ramp fully open (charge up time 10 minutes, flow back 8 hours) Nominal 1 occurrence per year back flowing at 40 MMscf/d with choke fully open (flow approx 24 hrs) For fluid composition during back flow, see detail of Enfield 5 exploration well included in Appendix G. Wet gas density during backflow is as follows (reference /B27/): 173 kg/m3 at riser top 144 kg/m3 at riser base
5.7.3
Gas Lift Data as follows (reference /B1/ data sheet 0206 revision 5): The design composition of CO2 is 6.5% mol in the gas phase at standard conditions. The design composition of H2S is to be taken as 25ppm in the gas phase at standard conditions. The gas is dry.
5.7.4
Water Injection The design composition of CO2 is 5% mol at 0.8 barg in the de-gasser unit (reference /B6/, item 52 and /B13/, item 4). The design composition of H2S is to be taken as 25ppm at 0.8 barg in the de-gasser unit (reference /B6/, item 52 and /B13/, item 4). The operating pressure of the de-gasser unit will be 0.8 barg for 90% of the time and 1.2 barg for 10% of the time (reference /B13/, item 4). The water injection fluid shall be considered to contain 50 ppb of oxygen for 90% of the time and 200 ppb of oxygen for 10% of the time. The oxygen content is from the seawater only, as there is no oxygen in the produced water (reference /B13/, item 9).
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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design
The water injection risers are always full of water during operation apart from an accidental emptying case during a shut in of the water injection system. This condition may result in a vacuum in the top section of the riser (reference /B13/, item 7). 5.8
Slug Loading Slugging loading will be assessed for the production and production / test flowlines and risers. Slugging data is included in Appendix R.
5.9
Produced Water Composition The produced water composition is as detailed below in table 5.9.1 (reference /B1/ data sheet 0302 revision 2). Note that the seawater composition is to be used for waterflood operations design. Dissolved Constituent Iron, Fe (soluble) Sodium Potassium Calcium Magnesium Strontium Barium Chloride Carbonate Bicarbonate Hydroxide Sulphate Nitrate
Seawater mg/L
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