basis of design

ENFIELD SUBSEA EPICRisers and Flowlines Basis of Design

Doc. No: JA004847-JSD-3500-0001 Revision: 2 Page: 2 of 66

Property of Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV). Copyright Technip Oceania Subsea 7 Enfield Joint Venture (TSEJV).All rights reserved

JA004847-JSD-3500-0001 Rev 2.doc

RECORD OF AMENDMENT

It is certified that the amendments listed below have been incorporated in this copy of the publication.

AMDTNO

AMENDEDSECTION

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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HOLD'S STATUS SHEET

This revision has the following HOLD's

SECTION PARA NO

DESCRIPTION OF HOLD




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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




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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




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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........................................................................ 647.17 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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1.0 EXECUTIVE SUMMARY

1.1 Field Overview

WEL is developing the Enfield oilfield, located in permit WA 27 1P, off Australias 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).




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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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2.0 SCOPE

2.1 Field Location and Layout

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 Easting (m) Northing (m) Water Depth LAT (m) FPSO 189 966 7 621 597 396 E-DC1 188 003 7 621 533 516 E-DC2 188 361 7 623 334 495 E-DC3 186 564 7 620 853 551 E-DC4 185 450 7 619 350 552

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 Item No

Flexible Service Riser / Flowline

NominalInternal

Diameter(Inches)

NominalLength

(m)Proposed

Configuration

1 & 2 R2 & R5 Production Riser 9 2 x 830 Hybrid Lazy Wave

3 R4 Production/Test Riser 8 830 Hybrid Lazy Wave

4 R3 Gas Lift Riser 6 830 Hybrid Lazy Wave

5 R1 Gas Injection Riser 6 820 Hybrid Lazy Wave

6 R7 Water Injection Riser 10 815 Hybrid Lazy Wave

7 & 8 B & D Production Flowline 9 2060 + 1913 N/A

9 C Production/Test Flowline 8 1911 N/A

10 E Gas Lift Flowline 6 1853 N/A

11 G Gas Injection Flowline 6 4974 N/A

12 & 13 F & K Water Injection Flowline 10 3051 + 3521 N/A

14 R6 EHU Riser - 815 Hybrid Lazy Wave15 A EHU Flowline - 2202 N/A

16 - 18 L, M & N EHU Flowline - 2212, 1753, 2013 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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3.0 ABBREVIATIONS AND DEFINITIONS

3.1 Abbreviations

API American Petroleum Institute ASB Above Sea Bed CAD Computer Aided Design DAF Dynamic Amplification Factor DnV Det Norske Veritas DP Design Pressure EHU Electro-Hydraulic Umbilical EPIC Engineering, Procurement, Installation and Commissioning FAT Factory Acceptance Test FOP Full of Product FOW Full of Water FPSO Floating, Production, Storage and Off-Loading Facility GRV Gas Release Valve HAT Highest Astronomical Tide Hmax Maximum Single Wave Height Hs Significant Wave Height ID Internal Diameter LAT Lowest Astronomical Tide MBR Minimum Bending Radius MFOP Maximum Flowing Operating Pressure MODU Mobile Offshore Drilling Unit MOP Maximum Operating Pressure MSL Mean Sea Level NRV Non Return Valve OST Offshore Strength Test OTC Offshore Technology Conference PLEM Pipeline End Manifold Poff Offshore Strength Test Pressure QS Quasi-static RAO Response Amplitude Operator RECE Reverse End Cap Effect RP Recommended Practice Rp Return Period RTM Riser Turret Mooring SBM Single Buoy Moorings TBA To Be Advised TDS Technical Data Sheet THmax Period of Maximum Wave Tm Spectral Mean Wave Period TOPL Technip Oceania Pty Ltd Tp Spectral Peak Period TSEJV Technip Oceania Subsea 7 Enfield Joint Venture Tz Average Zero-Crossing Wave Period UF Utilisation Factor VLS Vertical Lay System WEL Woodside Energy Ltd




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3.2 Definitions Touch Down Point Location where the flexible riser touches down onto the seabed. Sag Bend 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).

Hog Bend Highest section of flexible riser supported by the buoyancy modules.

A sketch identifying the locations defined above is included below.

Sketch 3.2.1 Flexible Riser Configuration Definitions

Hog Bend Touch Down Point

Sag Bend

Riser Column

Riser Subsea End fitting including hold back anchor

Bend Stiffener and BSC




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4.0 REFERENCES

4.1 TSEJV References

[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 [A18] JA004847/TSEJV/WEL-TQ009




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Selection of vessel draft / RAOs set resulting in highest vertical motions for dynamic and fatigue analysis

[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

4.2 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 [B7] Anchoring Anchorlegs General Arrangement Drawing No: K 4060 D S 001 0001, Revision C




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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



[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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[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 and Chemical Injection (Updated)

[B35] Correspondence WELS/ TSEJV/155 Riser Condition for Disconnection

4.3 Codes and Standards

The following is a list of design codes and standards used in addition to Technips internal design rules for the design of the flexible pipes and associated equipment.

RefNo.

Code No. Title

S1 API RP 17B 3rd Edition, March 2002

Recommended Practice for Flexible Pipe

S2 API 17J 2nd Edition, Effective December 2002

Specification for Unbonded Flexible Pipe Second Edition

S3 DnV RP B401 Recommended Practice for Cathodic Protection Design

S4 DnV RP E305 Recommended Practice for On-Bottom Stability of Pipelines

S5 DnV OS-F101 Submarine Pipeline Systems, January 2000

Table 4.3.1 Codes and Standards used for the Flexible Risers and Flowlines Design




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5.0 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 WEL ItemNo

Service Route Direction Internal Diameter

1 R2 Production 2 F/L D to FPSO 9 (228.6mm)

2 R5 Production 1 F/L B to FPSO 9 (228.6mm)

3 R4 Production / Test F/L C to FPSO 8 (203.2mm)

4 R3 Gas Lift FPSO to F/L E 6 (152.4mm)

5 R1 Gas Injection FPSO to F/L G 6 (152.4mm)

6 R7 Water Injection FPSO to F/L F 10 (254.0mm)

7 B Production 1 E-DC1 to R5 9 (228.6mm)

8 D Production 2 E-DC1 to R2 9 (228.6mm)

9 C Production / Test E-DC1 to R4 8 (203.2mm)

10 E Gas Lift R3 to E-DC1 6 (152.4mm)

11 G Gas Injection R1 to E-DC4 6 (152.4mm)

12 F Water Injection R7 to E-DC2 10 (254.0mm)

13 K Water Injection E-DC2 to E-DC3 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 WEL Item No

Service Max Differential Pressure (Barg)

Max Internal Pressure (Barg)

1 & 2 R2 & R5 Production 238 260 3 R4 Production / Test 238 260 4 R3 Gas Lift 237 243 5 R1 Gas Injection 280 287 6 R7 Water Injection 258 296

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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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 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 riser is for the base case of a smooth bore flowline and rough bore riser.

Item WEL Item No

Service Max Differential Pressure (Barg)

Max Internal Pressure (Barg)

7 & 8 B & D Production 223 270 9 C Production / Test 223 270 10 E Gas Lift 203 245 11 G Gas Injection 248 291

12 & 13 F & K Water Injection 258 314

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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Item WEL Item No Service MOP Differential Pressure (Barg)

MFOP Differential Pressure (Barg)

1 & 2 R2 & R5 Production 226 63 3 R4 Production / Test 226 63 4 R3 Gas Lift 225 208 5 R1 Gas Injection 265 240 6 R7 Water Injection 241 223

7 & 8 B & D Production 211 26 9 C Production / Test 211 26 10 E Gas Lift 191 174 11 G Gas Injection 233 208

12 & 13 F & K Water Injection 241 223

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.




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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).

Design Temperature (oC)

Item WEL Item No

Service

Min Max

MaximumOperating

Temperature (oC)1 & 2 R2&R5 Production 0a) 70 65

3 R4 Production/Test 0 a) 70 65 4 R3 Gas Lift 0 65 60 5 R1 Gas Injection 0 a) 65a) 60 6 R7 Water Injection 0 65 60

7 & 8 B & D Production 0 a) 70 65 9 C Production/Test 0 a) 70 65 10 E Gas Lift 0 65 60 11 G Gas Injection 0 a) 65a) 60

12 & 13 F & K Water Injection 0 65 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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5.6 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)

Fluid Density at Riser

Seabed End (kg/m3)

Fluid Density at Top of Riser

(kg/m3)1 R2 Production 2 N/A 315 - 461 135 205

2 R5 Production 1 N/A 287 - 379 123 164

3 R4 Production/Test N/A 380 - 562 173 260

4 R3 Gas Lift N/A 165 163 5 R1 Gas Injection N/A 189 184 6 R7 Water Injection N/A 1026 1026 7 B Production 1 371 - 488 287 - 379 N/A 8 D Production 2 391 545 315 - 461 N/A

9 C Production/Test 476 - 631 380 - 562 N/A 10 E Gas Lift 177 165 N/A 11 G Gas Injection 205 189 N/A 12 F Water Injection 1026 1026 N/A 13 K Water Injection 1026 1026 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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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 Seawater mg/L

Iron, Fe (soluble)




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Initial startup of wells: 10-200 lbs of gravel pack and formation sand will be flowed back during the clean up of individual wells and will be controlled by bean up procedures. Sand particle size from 0-1200 micron (max size based on gravel size). Steady state production: 0.5 lbs/1000 bpd with sand size less than 45 micron Subsequent start up of wells: 1 lbs/1000 bpd with sand size less than 45 micron

During gas injection well back flowing operations sand production rate is 1lb/MMscfpd. Velocity data as follows (reference /B6/ item 263, data included in Appendix H):

27m/s at riser top 24m/s at 12m radius location in J tube 12m/s at hog bend 10.5m/s on seabed

Maximum flowrates as follows (reference /B6/ item 263, data included in Appendix H):

50640 BPD for the 9 risers and flowlines

36405 BPD for the 8 risers and flowlines

5.12 Chemical Injection See below for details of chemical injection for each riser and flowline (reference /B34/). Additional details for chemicals injection are included Appendix J (reference /B34/). All of these chemicals will be checked for compatibility with the respective risers and flowlines. TSEJV is to approve all chemicals to be introduced into the risers and flowlines.

5.12.1 Production Flowlines and Risers

Demulsifier is FX2499 or 2500 from Ondeo Nalco. Continuous injection at a rate of 50ppm.

Scale Inhibitor is Nalco EC 6330A. Continuous injection at a rate of 10ppm max (water production independent).

No corrosion inhibitors will be used. Methanol (MeOH) injection will be required for hydrate management during production

start-up as follows:o Cold Start Up (duration > 8hours)

Life of Field Total Cold Start-Ups = 104. MeOH injection rate = 5m3/hr. MeOH per flowline for 3 hours = 15m3 total per flowline. MeOH is injected into each of the three main wells, one lined up to each flowline. MeOH concentration is approx. 0.8% vol. assuming 100,000 bbl/d liquids production.

o Warm Start Up (duration < 8hours)Life of Field Total Warm Start-Ups = 325. MeOH injection rate = 1.1m3/hr. MeOH for 1 hour = 1.1m3 total. MeOH is injected into all 5 wells at




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5.12.2 Gas Injection Flowlines and Risers No corrosion inhibitors will be used. MeOH injection is nominally required for hydrate management during gas injection

backflow as follows:o Cold Start Up

Life of Field Total Cold Start-Ups = 104. MeOH injection rate = 0.07m3/hr for gas backflow for 8 hours nominal (Gas flowrate = 10MMscfd).

o Gas Injection Well Clean-Up (annual) Life of Field Total G.I. Well Clean-Ups = 20 per G.I. well. MeOH injection rate = 0.28m3/hr for gas backflow for 24 hours nominal per G.I. well (Gas flowrate = 40MMscfd).

5.12.3 Gas Lift Flowlines and Risers

No corrosion inhibitors will be used. Methanol injection is not required.

5.12.4 Water Injection Flowlines and Risers Refer to Appendix J for additional chemical injection details. Methanol injection is not required.

5.13 Design Life

The design life of the flexible riser system is 20 years (reference /B1/ data sheet 0204 revision 1).

5.14 Environmental Data

The 1-year, 10-year, 50-year and 100-year storm conditions shall be used for design of the riser and flowline systems. Additional directional Metocean data is available and included in reference /A27/.

The environmental data has been provided in reference /B5/ for the infield location (water depths of approximately 580m) and for the FPSO location (water depths of approximately 400m). For the risers only the data for the FPSO location will be used. For the flowlines the most severe data will be used.

Not all the provided environmental data is included in this document. There is a significant amount of additional data which will be used if required (references /A27/ and /B28/). The near seabed current will be determined using the 1/7th power law:

V(z) = V(d) * (z/d)1/7

where:z = elevation of interest above seabed, (m).

V(z) = current speed at elevation z, (m/s). V(d) = near-bottom current speed, (m/s). d = corresponds to the elevation ASB at which the near-

bottom current speed is taken.




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Notes:a) See section 5.14.6 for the boundary layer effect for soliton currents.

5.14.1 Water Depth, Tides & Surge

The water depth at the Enfield location is in the range of 400 to 600m (reference /B5/). The LAT water depths at each location are included below in table 5.14.1.1 (reference /B23/).

Location LAT Water Depth (m) Enfield FPSO 396 Production Manifold E-DC1 516 Water Injection PLEM E-DC2 495 Water Injection PLEM E-DC3 551 Gas Injection Drill Centre E-DC4 552

Table 5.14.1.1 Enfield Location LAT Water Depths

Tide levels are predicted as follows for the Enfield location relative to LAT (reference /B5/):

HAT 2.1 m MSL 1.0 m

The surge values are given as follows (reference /B5/):

100 year cyclonic high tide +0.86 m 100 year cyclonic low tide -0.34 m

5.14.2 Seawater Data

The seawater density is 1026 kg/m3 (reference /B1/ data sheet 0302 revision 2). The seawater temperature data is included below in table 5.14.2.1 (reference /B1/ data sheet 0205 revision 3).

Location Seawater Temperature ( C) Extreme Minimum Extreme Maximum Surface 24 30 Seabed 6 9

Table 5.14.2.1 Seawater Temperature Data

5.14.3 Air Temperature

Maximum air temperature = 31 C (reference /B1/ data sheet 0205 revision 3). Minimum air temperature = 17 C (reference /B1/ data sheet 0205 revision 3).




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5.14.4 Infield Non-Cyclonic Environmental Data

The omni-directional non-cyclonic wave and current data for the 1 year, 10 year and 50 year conditions are included below in tables 5.14.4.1 and 5.14.4.2 (reference /B5/). Note that the currents provided are extreme values and do not occur at the same time. The 1 year, 10 year and 50 year non-cyclonic directional data may be required for the dynamic analysis.

Return Period 1 year 10 year 50 year Significant Wave Height Hs (m) 4.7 5.7 6.5

Spectral Peak Wave Period Tp (s) 11.7 12.9 13.8

Spectral Mean Wave Period Tm (s) 7.5 8.3 8.8

Average Zero-Crossing Wave Period Tz (s) 6.8 7.5 8.1

Maximum Single Wave Height Hmax (m) 8.5 10.3 11.7

Period of Maximum Single Wave THmax (s) 8.6 9.5 10.2

Philips Parameter 0.0064 0.0064 0.0064 Peakedness Parameter 0.8206 0.8204 0.8203 Sigma A a 0.1140 0.1140 0.1140 Sigma B b 0.1129 0.1129 0.1129

Table 5.14.4.1 Infield Non-cyclonic Wave Data for 1, 10 and 50 year Return Period

Return Period 1 year 10 year 50 year 565m ASB (-15m MSL) V

-15 (m/s) 1.07 1.22 1.30 515m ASB (-65m MSL) V

-65 (m/s) 0.90 0.94 0.96 455m ASB (-125m MSL) V

-125 (m/s) 0.94 1.03 1.08 335m ASB (-245m MSL) V

-245 (m/s) 0.61 0.67 0.70 95m ASB (-485m MSL) V

-485 (m/s) 0.45 0.54 0.60 5m ASB (-575m MSL) V

-575 (m/s) 0.43 0.50 0.53

Table 5.14.4.2 Infield Non-cyclonic Current Data for 1, 10 and 50 year Return Period

5.14.5 FPSO Non-Cyclonic Environmental Data

The omni-directional non-cyclonic wave and current data for the 1 year, 10 year and 50 year conditions are included below in tables 5.14.5.1 and 5.14.5.2 (reference /B5/). Note that the currents provided are extreme values and do not occur at the same time. The 1 year, 10 year and 50 year non-cyclonic directional data may be required for the dynamic analysis.

Return Period 1 year 10 year 50 year Significant Wave Height Hs (m) 4.7 5.7 6.5

Spectral Peak Wave Period Tp (s) 11.7 12.9 13.8

Spectral Mean Wave Period Tm (s) 7.5 8.3 8.8

Average Zero-Crossing Wave Period Tz (s) 6.8 7.5 8.1

Maximum Single Wave Height Hmax (m) 8.5 10.3 11.7

Period of Maximum Single Wave THmax (s) 8.6 9.5 10.2

Philips Parameter 0.0064 0.0064 0.0064 Peakedness Parameter 0.8206 0.8204 0.8203 Sigma A a 0.1140 0.1140 0.1140 Sigma B b 0.1129 0.1129 0.1129

Table 5.14.5.1 FPSO Non-cyclonic Wave Data for 1, 10 and 50 year Return Period




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Return Period 1 year 10 year 50 year 390m ASB (-10m MSL) V

-10 (m/s) 1.06 1.16 1.22 340m ASB (-60m MSL) V

-60 (m/s) 0.91 0.96 0.98 280m ASB (-120m MSL) V

-120 (m/s) 0.94 1.01 1.04 160m ASB (-240m MSL) V

-240 (m/s) 0.69 0.77 0.81 65m ASB (-335m MSL) V

-335 (m/s) 0.67 0.73 0.76 5m ASB (-395m MSL) V

-395 (m/s) 0.57 0.62 0.66

Table 5.14.5.2 FPSO Non-cyclonic Current Data for 1, 10 and 50 year Return Period

5.14.6 Infield Internal Wave / High Frequency Current (Soliton) Environmental Data The Enfield location is subject to internal wave / high frequency current also known as solitons. It is understood from reference /B5/ that such phenomenon is not coincident with cyclonic conditions and is therefore to be analysed in combination with non-cyclonic wave conditions.

Two types of high frequency events have been identified as being active at the Enfield location. They include solitons which evolve from the internal tide and propagate generally across the regional bathymetry and high frequency alongslope currents which emanate from breaking solitons. High near seabed current velocities are generated from the breaking solitons and these are significant in terms of on-bottom stability of the flowlines, umbilicals and on-seabed sections of the risers.

The 100 year return period high frequency along slope currents are not constant but are time varying events that can be defined in terms of timescale (lengthscale in the direction of propogation) and crestlength (width of event). The current velocities produced during these events vary over both the lengthscale and crestlength and therefore are a 3 dimensional event. For the Enfield location the current velocity distribution along the lengthscale and crestlength to be used for the 3D stability analysis shall take on a hyperbolic secant squared shape (reference /B5/). An example of this distribution is included in reference /A13/. The duration, crestlength and peak velocity of the 100 year high frequency soliton event are:

Lengthscale (timescale) = 4 minutes (reference /B5/ Appendix T, Scope C) Crestlength = 500m (reference /B5/ Appendix T, Scope C) Omni Directional 100 Year return period high frequency current @ 2m above seabed

= 2.02m/s (reference /B5/ Appendix T, Scope A)

Directional soliton currents are included below in tables 5.14.6.1 and 5.14.6.2 for the 1 year and 50 year conditions respectively (reference /B5/). Direction (To) N NE E SE S SW W NW OMNI Steady Current at 2m ASB (m/s) 0.45 0.45 0.45 0.85 0.45 0.45 0.45 0.68 0.85

Table 5.14.6.1 Infield 1 Year Soliton Steady Current

Direction (To) N NE E SE S SW W NW OMNI Steady Current at 2m ASB (m/s) 1.0 1.0 1.0 2.0 1.0 1.0 1.0 1.6 2.02

Table 5.14.6.2 Infield 50 Year Soliton Steady Current

Notes:




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a) The data given in table 5.14.6.2 is actually the 100 year soliton data. However, this is also to be used for the 50 year conditions (reference /B16/).

Omnidirectional soliton steady currents through the water column are to be taken as 0.2m/s for the 1 year and 50 year conditions respectively (reference /B16/). This is the value to be used in conjunction with the soliton current. It is assumed that the soliton current reduces linearly to 0.2m/s between 2m and 5m ASB.

To account for the boundary layer effect the average current velocity acting on the pipe shall be calculated in accordance with Appendix A, Section A.2 of DnV RP E305 (reference /S4/).The boundary layer properties associated with the near seabed soliton data is detailed below (reference /B5/):

Bottom Roughness 0.0003 m Current Reference height ASB 2.0 m Seabed friction 0.37

5.14.7 FPSO Internal Wave / High Frequency Current (Soliton) Environmental Data The Enfield location is subject to internal wave / high frequency current also known as solitons. It is understood from reference /B5/ that such phenomenon is not coincident with cyclonic conditions and is therefore to be analysed in combination with non-cyclonic conditions.

Directional near seabed high frequency soliton steady currents are as per section 5.14.6.

The boundary layer properties associated with the near seabed soliton data is detailed below (reference /B5/):

Bottom Roughness 0.0003 m Current Reference height ASB 2.0 m Seabed friction 0.5

5.14.8 FPSO Cyclonic Environmental Data

Cyclonic conditions are not to be considered for the flowlines due to the water depths at the Enfield location as the cyclonic currents are not expected to reach through the complete water column (reference /B5/). Therefore only the FPSO cyclonic environmental data is provided.

Independent (i.e. extreme values) wave and current data for the 100 year cyclonic conditions are included below in tables 5.14.8.1 and 5.14.8.2 for the wave and current respectively (reference /B5/). In order to reduce the amount of load cases to study, the independent data will be used for the design of the riser system as they are more stringent. However, if the independent data proves to be too conservative, TSEJV will revert to the peak wave and peak current data provided in Appendix V of reference /B5/ (i.e. joint occurrence data).




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Direction (To) N NE E SE S SW W NW OMNI Significant Wave Height Hs (m)

5.48 5.60 6.82 10.35 11.81 11.14 7.89 5.80 12.12

Spectral Peak Wave Period Tp (s)

10.26 10.34 11.12 13.11 13.85 13.52 11.76 10.48 14.00

Spectral Mean Wave Period Tm (s)

8.10 8.16 8.78 10.35 10.93 10.67 9.28 8.27 11.05

Average Zero-Crossing Wave Period Tz (s)

7.59 7.65 8.23 9.70 10.24 10.00 8.70 7.75 10.36

Maximum Single Wave Height Hmax (m)

9.54 9.74 11.87 18.02 20.56 19.39 13.73 10.10 21.09

Period of Maximum Single Wave THmax (s)

9.32 9.39 10.10 11.90 12.57 12.27 10.67 9.51 12.71

Philips Parameter 0.0114 0.0115 0.0124 0.0140 0.0144 0.0142 0.0130 0.0117 0.0145 PeakednessParameter

1.73 1.75 1.92 2.24 2.33 2.29 2.04 1.78 2.35

Sigma A a 0.086 0.086 0.083 0.078 0.077 0.078 0.081 0.085 0.077 Sigma B b 0.098 0.098 0.096 0.094 0.093 0.093 0.095 0.098 0.093

Table 5.14.8.1 Extreme 100 Year Cyclonic Wave Data

Direction (To) N NE E SE S SW W NW OMNI 276m below MSL V

-276 (m/s) 0.08 0.38 0.49 0.48 0.61 0.80 0.69 0.22 0.82 209m below MSL V

-209 (m/s) 0.18 0.39 0.42 0.36 0.67 1.30 1.12 0.24 1.32 163m below MSL V

-163 (m/s) 0.26 0.40 0.35 0.32 0.71 1.48 1.27 0.20 1.48 121m below MSL V

-121 (m/s) 0.31 0.42 0.38 0.29 0.60 1.43 0.96 0.27 1.43 83m below MSL V

-83 (m/s) 0.30 0.50 0.41 0.33 0.80 1.43 0.73 0.25 1.43 59m below MSL V

-59 (m/s) 0.48 0.59 0.54 0.67 1.17 1.59 0.89 0.48 1.59 36m below MSL V

-36 (m/s) 0.70 0.87 0.79 1.02 1.55 1.81 1.17 0.75 1.83 26m below MSL V

-26 (m/s) 0.80 0.99 0.88 1.15 1.70 1.90 1.26 0.85 1.94 15m below MSL V

-15 (m/s) 0.94 1.10 0.99 1.28 1.86 2.03 1.40 0.94 2.07 5m below MSL V

-5 (m/s) 1.05 1.19 1.10 1.46 2.06 2.23 1.62 1.04 2.28

Table 5.14.8.2 Extreme 100 Year Cyclonic Current Data

Notes:a) For water depths greater than 276m below MSL the 50% excedence measured current

will be used (reference /B15/). From Appendix J of reference /B5/ the current speed is conservatively estimated as 0.2m/s below 276m.

5.15 Geotechnical Data

The seabed soil properties are defined as carbonate muds and carbonate sands to the west and east of the central scarp feature respectively. The properties between the riser and seabed for steady currents are included below in table 5.15.1 (reference /B2/).

Soil Tide & Drift Soliton Zone 1 Carbonate Sand 0.5 0.5 Zone 2 Carbonate Mud 0.4 0.37

Table 5.15.1 Friction factors for Steady Current




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The seabed roughness parameter shall be taken as 0.0003 m reflecting a generally soft granular seabed (reference /B2/). There are two general soil types prevalent as follows (reference /B2/):

Carbonate muds to the west of the central scarp feature Carbonate sands to the east of the central scarp feature

It can be seen from the drawings included in Appendix A that the risers are in zone 1 as defined in table 5.15.1 and the flowlines are in both zones 1 and 2.

5.16 Marine Growth

The marine growth profiles are included below in table 5.16.1. The submerged weight of hard marine growth is 120 kg/m3. Soft marine growth is neutrally buoyant and has a compressibility factor of 0.5 (reference /B1/ data sheet 0205 revision 3).

Years 5 10 15 20 5 10 15 20 Depth Hard Thickness (mm) Soft Thickness (mm) MSL to -5m 38 75 113 150 0 0 0 0 -5m to -70m 45 45 68 90 45 104 104 104 -70m to -100m 15 26 39 53 41 60 60 60 -100m to -150m 1 1 2 2 4 10 10 10 -150m to -600m 0 0 0 0 2 4 6 8

Table 5.16.1 Marine Growth Profiles

5.17 Vessel Data

5.17.1 Vessel Characteristics

A bow mounted Disconnectable Riser Turret Mooring (RTM) system has been selected as the turret / mooring system for the Enfield FPSO. The RTM system consists of two main components a rigid arm structure permanently mounted at the vessel bow, and a riser column structure which is anchored to the seabed by means of 9 anchor legs comprised of chain and wire rope. The lower end of each anchor leg is connected to an anchor embedded into the seabed. The rigid arm structure is integrated into the tankers bow by a special reinforced section of the ships structure. The general arrangement of and naming convention for the RTM system is included in the drawings in Appendix A.

When the FPSO is connected, the riser column is suspended from the rigid arm structure via a structural connector. Relative motion between the riser column and the rigid arm is allowed through a universal joint (for pitch and roll), and a main roller bearing (for weathervaning).Disconnection of the riser column is achieved by activating the structural connector which is incorporated in the mooing system just below the universal joint. After disconnection, the riser column will float with a freeboard of approximately 6m (reference /B4/). The riser column is a welded tubular steel column stiffened by internal circumferential ring frames. The total length of the riser column is approximately 86.5 m (reference /B4). There is also a central shaft present for storage of the reconnection chain. The central shaft is assumed to be a maximum of 6m long (reference /B18/, item 12) with a diameter of 0.61m.




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J-tubes for the risers and umbilicals will be run through the riser column to the riser column top deck.

The riser entry point draughts are included below in table 5.17.1.1 (reference /B3/ and /B22/).

Designation Units Value Riser Draught Disconnected m 74.8 Riser Draught Loaded m 67.8 Riser Draught Ballasted m 61.3 Riser Draught Intermediate m 65.0

Table 5.17.1.1 Riser Column Data

The FPSO drafts are detailed below (reference /B3/ and /B22/):

Vessel Ballasted Draught 11m Vessel Fully Loaded Draught 17.5m Vessel Intermediate Draught 14.7m

5.17.2 Offsets / Excursions

In the connected case, the 50 year non-cyclonic event is the governing environment in terms of maximum riser motions. The maximum quasi-static (QS) and dynamic (assumed to include mean offsets, slow drift motion and wave induced offsets) excursions are detailed below in table 5.17.2.1 (reference /B3/). The riser entry elevations from MSL and riser column pitch angle are also included. All excursions are given for the intact mooring system. To account for the damaged mooring system and additional 10m must be added. Additionally, installation tolerances will be added to the offsets. Sketches from reference /B3/ which detail the extreme riser connected motions are included in Appendix L. The extreme motions for the 10 year and 1 year conditions are included in tables 5.17.2.2 and 5.17.2.3 respectively.

Motion Ballasted Draft In-Between SW / SE Bundle Fully Loaded Draft In-Line

with SW Bundle QS 38.4 m 26.2 m Excursion Max 50.0 m 35.5 m QS -57.8 m -63.0 m Min -52.0 m -57.0 m ElevationMax -66.0 m -69.5 m QS 16.1 deg 19.0 deg Angle Max 22.5 deg 25.5 deg

Table 5.17.2.1 Riser Entry Connected Extreme Motions 50 yr Non-Cyclonic Intact Mooring




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In-Plane Loading Note a) Transverse Loading Note b) Motion In-Line with

SW Bundle In-Between SW

/ SE Bundle In-Line with SW Bundle

In-Between SW / SE Bundle

QS 23.1 m 35.2 m 29.4 m 23.0 m Excursion Max 34.7 m 43.7 m - - QS -56.5 m -57.2 m -57.4 m -57.4 m Min -52.2 m -53.0 m - - ElevationMax -63.7 m -64.1 m - - QS 19.1 deg 17.6 deg 17.3 deg 17.4 deg Angle Max 21.9 deg 20.0 deg - -

Table 5.17.2.2 Riser Entry Connected Extreme Motions 10 yr Non-Cyclonic Ballasted Draft - Intact Mooring

In-Plane Loading Note a) Transverse Loading Note b) Motion In-Line with

SW Bundle In-Between SW

/ SE Bundle In-Line with SW Bundle

In-Between SW / SE Bundle

Excursion QS 17.3 m 28.5 m 27.5 m 19.0 m Elevation QS -59.2 m -59.5 m -58.9 m -57.4 m Angle QS 12.6 deg 11.8 deg 13.6 deg 17.3 deg

Table 5.17.2.3 Riser Entry Connected Extreme Motions 1 yr Non-Cyclonic Ballasted Draft - Intact Mooring

Notes:a) In-Plane loading: Swell, current and wind are collinear b) Transverse loading: Current @90 degrees from swell, wind @ 30 degrees from swell When the riser column is disconnected due to a cyclonic event approaching (see section 7.10.3 for disconnection conditions), the system reaches a new equilibrium position with a freeboard of approximately 6m. Maximum riser entry motions for the 100 year cyclonic conditions are included below in table 5.17.2.4 (reference /B3/). The maximum excursions are assumed to include mean offsets, slow drift motion and wave induced offsets. Sketches from reference /B3/ which detail the extreme riser disconnected motions are included in Appendix L. Extreme riser motions are included in table 5.17.2.5 for the 1 year disconnected conditions.

Motion Intact Mooring Damaged Mooring QS 43.5 m 53.5 m Excursion Max 55.0 m 65.0 m QS -75.4 m -75.4 m Min -71.0 m -71.0 m ElevationMax -79.0 m -79.0 m QS 8.5 deg 11.5 deg Angle Max 20.0 deg 25.0 deg

Table 5.17.2.4 Riser Entry Disconnected Extreme Motions 100 year Cyclonic




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Motion In-Line with SW Bundle In-Between SW / SE BundleQS 7.5 m 9.5 m Excursion Max 13.5 m 13.0 m QS -74.7 m -74.6 m Min -74.0 m -73.8 m ElevationMax -76.0 m -75.9 m QS 3.3 deg 3.5 deg Angle Max 8.7 deg 8.6 deg

Table 5.17.2.5 Riser Entry Disconnected Extreme Motions 1 year Non-Cyclonic

Notes:a) In addition, an extra 6m vertical static excursion has to be accounted for in case of

accidental flooding of 1 or 2 compartments. b) Additional offsets may be required for less severe storm conditions for both the

connected and disconnected riser column. c) Installation tolerances will be added to the offset.

5.17.3 Wave Induced Motions

The RAOs are given at the riser entry point to the riser column. The riser entry RAOs are derived from a fully coupled Orcaflex model which includes the riser column connected to the FPSO via a universal joint. The wave motions of the FPSO are transmitted to the riser column and motions at the riser entry are extracted in the global coordinate system of Orcaflex. The system layout in the Orcaflex models is rotated such that the swell direction is always collinear to the X-axis of Orcaflex (see diagram included in Appendix B). The RAOs to be used for the design of the flexible risers are included in Appendix B for the ballasted and disconnected conditions of the FPSO for storm conditions (reference /B3/) and for the ballast draft for the fatigue conditions (reference /A18/). See section 7.12.4 for further details on the RAOs to be used for fatigue analysis.

The worst case RAOs have been used throughout the analysis whether corresponding to in-line or in-between mooring conditions (i.e. environment in line with a mooring or in between 2 moorings). Where RAOs were similar for the two conditions, those corresponding to the greatest excursions have been supplied (reference /B25/). The effect of the universal joint is to limit the riser column sway, yaw and roll motions.

All phase angles reported are positive for phase lag, i.e. the response lags the wave, which is inconsistent with the Deeplines convention which requires a phase lead input. To account for this all the phase angles are multiplied by -1.

The coordinate system used by the RAO calculation program is the right handed system with heave positive upwards, surge positive forwards and sway positive to port. This is consistent with the Deeplines convention.

Timetrace data has also been provided by SBM which eliminates the need for RAOs. Instead the position of the riser entry is defined at each given time and this defines the motions of the riser top (references /B29/ t0 /B33/).

5.17.4 Riser Connection to Riser Column

The flexible risers are guided through J-tubes inside the riser column to production piping situated on the top deck of the riser column, and are supported axially at this elevation.




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The riser bend stiffener connection locations are detailed below in table 5.17.4.1 for all considered conditions (reference /B3/).

Riser Column Condition Riser Bend Stiffener Distance below MSL (m) Vessel connected, ballasted 61.3 Vessel connected, fully loaded 67.8 Vessel Connected, Intermediate 65.0Vessel disconnected 74.8

Table 5.17.4.1 Riser Bend Stiffener Connection Location Details

5.17.5 Riser Column Motions During Disconnection

The drawings included in Appendix O show the riser column motions during disconnection. Details are included for disconnection in still water and also under the 50 year non-cyclonic conditions (reference /B3/). For disconnection in still water the keel reaches a maximum of -76.2m below mean water level when the riser column is oscillating from a ballasted position to a still position. This is only around 1.5m below the free-floating equilibrium position in still water.

For disconnection under the 50 year non-cyclonic conditions the maximum depth reached by the keel is -75.1m when the riser column disconnects from a fully loaded extreme position to a free-floating condition. The pitch of the column is also decreasing from +25 degrees (static angle caused by the FPSO excursion) to -18 degrees (wave and current action onto the riser column and risers combined with the inertia of the riser column) and then the pitch is fluctuating around a mean position of -5 degrees with an amplitude of 3degrees.

5.18 Mooring Line Data

The mooring line data has been extracted from reference /B17/. The mooring system is comprised of 9 legs in 3 groups of three with 120 spacing between each group of lines and 5 spacing between each leg within a group. This leaves large open sectors for the risers and it also allows good load sharing between the lines in the one line broken condition.

The anchor leg composition is given below in table 5.18.1 (reference /B17/).




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Mooring Line Properties Unit Segment 1 Seabed

Segment 2 Middle

Segment 3 Fairlead

Component Type Stud less R3 Sheathed Spiral Strand

Stud less R3

Diameter mm 110 68 84 Diameter w/sheathing mm N/A 88 N/A Nominal Length N bundle leg1 m 498 Nominal Length N bundle leg2 m 496 Nominal Length N bundle leg3 m 495

354 85

Nominal Length (SE bundle) m 505 346 85 Nominal Length SW bundle leg7 m 494 Nominal Length SW bundle leg8 m 496 Nominal Length SW bundle leg9 m 498

360 85

Weight in Air kg/m 244 25.3 142.5 Weight in Water kg/m 213 19.1 124 Axial Stiffness (EA) MN 953 409 645

Table 5.18.1 Anchor Leg Composition

Notes:a) The nominal length of segment 1 excludes the buried chain length. The mooring line tie-in configuration parameters at the riser column are given below in Table 5.18.2. Data has been extracted from references /B7/ and /B8/ which are included in Appendix A.

Description Value Radius between top chain connection and turret centre line 8.53 mHeight of top chain connection point above riser column keel 41.5 m Nominal anchoring radius from fairlead N Bundle leg 1 842 m Nominal anchoring radius from fairlead N Bundle leg 2 842 m Nominal anchoring radius from fairlead N Bundle leg 3 844 m Nominal anchoring radius from fairlead SE Bundle leg 4 856 m Nominal anchoring radius from fairlead SE Bundle leg 5 856 m Nominal anchoring radius from fairlead SE Bundle leg 6 856 m Nominal anchoring radius from fairlead SW Bundle leg 7 837 m Nominal anchoring radius from fairlead SW Bundle leg 8 837 m Nominal anchoring radius from fairlead SW Bundle leg 9 838 m

Table 5.18.2 Mooring Line Tie-in Configuration Parameters

The mooring line static tensions are given below in tables 5.18.3 to 5.18.5 (reference /B17/).




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LoadingCondition

Bundle Horizontal Tension (kN)

VerticalTension (kN)

TotalTension (kN)

Angle to horizontal

( )1 404 537 672 53.0 2 405 533 669 52.8 3 405 527 665 52.5 4 404 508 649 51.5 5 404 509 650 51.5 6 405 509 651 51.5 7 404 544 678 53.4 8 403 546 679 53.6

BallastFPSOConnected

9 404 549 682 53.7

Table 5.18.3 Mooring Line Static Tensions Connected & Ballast FPSO

LoadingCondition



TotalTension (kN)

Angle to horizontal

( )1 354 491 605 54.2 2 354 486 602 54.0 3 353 480 596 53.7 4 353 465 583 52.8 5 354 465 584 52.8 6 355 466 585 52.7 7 353 496 609 54.6 8 352 498 610 54.7

Fully Loaded FPSOConnected

9 353 501 613 54.8

Table 5.18.4 Mooring Line Static Tensions Connected & Fully Loaded FPSO

LoadingCondition



TotalTension (kN)

Angle to horizontal

( )1 305 444 538 55.5 2 303 439 533 55.4 3 301 432 526 55.2 4 302 420 517 54.3 5 303 421 518 54.2 6 304 421 519 54.2 7 301 446 538 55.9 8 302 448 540 56.1

FPSODisconnected

9 303 452 544 56.2

Table 5.18.5 Mooring Line Static Tensions Disconnected FPSO




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5.19 Fatigue Wave Data

The fatigue wave data extracted from reference /B5/ and included in Appendix C has been condensed to 10 individual wave classes in line with Technip standard procedure for fatigue analysis of flexible risers. The methodology for this is included in Appendix M. The method used to condense the data is conservative and may be refined at a later date if reported fatigue lives for the risers prove to be unacceptable. The scatter diagram gives the probability of occurrence of the significant wave heights and significant period ranges. From this data, the method consists of determining the maximum wave heights and associated period of each wave class.

The proposed fatigue wave class split is detailed below in table 5.19.1.

WaveClass

Hmax(m)

THmax(s)

Number of Cycles for 20 years Corresponding Return Period

1 1 6.6 40,453,303 1 year 2 2 6.7 41,855,472 1 year 3 3 7.0 13,574,131 1 year 4 4 7.4 2,941,801 1 year 5 5 7.7 550,481 1 year 6 6 8.0 96,990 1 year 7 7 8.2 16,953 1 year 8 8 8.3 3,070 1 year 9 9 8.3 574 10 year 10 10 8.3 107 10 year

Table 5.19.1 Riser Fatigue Wave Data

Table 2 included in Appendix C demonstrates that the wave direction is predominantly from the south west. Based on this table the directional split on the number of cycles detailed below in table 5.19.2 will be considered for each riser.

Item WEL Item No

Flexible Service Directional Split for Number of Cycles

1 R2 Production 2 90% transverse 10% far 2 R5 Production 1 100% transverse 3 R4 Production/Test 100% transverse 4 R3 Gas Lift 100% transverse 5 R1 Gas Injection 100% far 6 R7 Water Injection 100% near 14 R6 EHU 90% transverse, 10% near

Table 5.19.2 Directional Split for Number of Cycles

5.20 Fatigue Currents

The currents to be used for the fatigue analysis are the corresponding 1 year or 10 year non-cyclonic currents included in section 5.14.5 depending on the return period of the wave class as shown in table 5.19.1. Directional data is available for use if required.

5.21 Fatigue Offsets

The offsets to be used for the fatigue analysis are the corresponding 1 year or 10 year riser column offsets depending on the return period of the wave class as shown in table 5.19.1.




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The 1 year and 10 year offsets are detailed below in tables 5.21.1 and 5.21.2 for the ballasted connected vessel (reference /A24/) for the in line and out of plane conditions respectively.

1 year Non-Cyclonic 10 year Non-Cyclonic Riser Entry QS Excursion 28.5 m 35.2 m Riser Entry QS Elevation -59.5 m -57.2 m Riser Entry QS Inclination 11.8 deg 17.6 deg

Table 5.21.1 In Line Riser Fatigue Offsets

1 year Non-Cyclonic 10 year Non-Cyclonic Riser Entry QS Excursion 23.7 m 29.4 m Riser Entry QS Elevation -58.9 m -57.4 m Riser Entry QS Inclination 13.6 deg 17.3 deg

Table 5.21.2 Out of Plane Riser Fatigue Offsets

5.22 Hydrodynamic Coefficients

5.22.1 Riser Hydrodynamic Coefficients

The proposed drag and inertia coefficients to be used for the risers are detailed below in Table 5.22.1.1 and are as per reference /A22/ except for the axial drag coefficient with marine growth. This value has been reduced following discussions with WEL and other industry sources, and as it is still considered conservative there will be no sensitivity on the axial drag value. The inertia coefficient is defined as 1+ Added Mass.

Riser without Marine Growth

(Post Installation Cases) Riser with Marine

Growth (Operation Cases)

Normal Drag Coefficient, CDN 0.70 1.00 Normal Inertia Coefficient, CMN 2.00 1.80 Axial Drag Coefficient, CDA 0.00 0.10 Axial Inertia Coefficient, CMA 0.00 0.00

Table 5.22.1.1 Riser Drag and Inertia Coefficients

The hydrodynamic coefficients for the buoyancy modules are to be calculated during detailed design (reference /A11/) as these are dependent on the buoyancy module dimensions and method of analysis.

As per section 7.10.4, a sensitivity analysis will be conducted on critical load cases identified during the riser dynamic analysis which will consider an increase in normal drag coefficients of 5%.




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5.22.2 Flowline Hydrodynamic Coefficients

The hydrodynamic coefficients to be used for the flowlines are presented below and are in accordance with reference /S4/:

Lift Force Coefficient, CL = 0.9 Inertia Force Coefficient, CI = 3.29 Drag Force Coefficient,

Reynolds Number 3 x 105, CD = 0.7 Reynolds Number < 3 x 105, CD = 1.2

The Reynolds Number shall be calculated based on the pipe OD using the average velocity across the pipe to account for the boundary layer effect in accordance with reference /S4/.




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6.0 INTERFACES

6.1 Riser Entry Configuration Data

The risers enter the J-tubes at the bottom of the riser column where the bend stiffeners are attached. The risers are then guided through J-tubes to the top of the riser column where the tie-in is located. The riser sequence and arrangement on the riser column provided in drawings included in Appendix A.

The tie-in configuration parameters at the riser entry point to the riser column are included below in Table 6.1.1 (reference /B3/). A drawing showing the layout is included in Appendix A.

Item Service Riser Attachment Point Elevation

below FPSO Keel (m)

HorizontalDistance from C/L of Riser Column

(m)

NominalBuilt-in Angle

to Vertical (Deg)

1 Production 50.3 3.335 10 2 Production 50.3 3.335 10 3 Production / Test 50.3 3.335 10 4 Gas Lift 50.3 3.335 10 5 Gas Injection 50.3 3.335 10 6 Water Injection 50.3 3.335 10 14 EHU 50.3 3.335 10

Table 6.1.1 Tie-In Configuration Data Riser Column

The bending moment and shear force at the base of the bend stiffener functional cone are transferred to the riser column via bend stiffener connectors.

6.2 Riser Interface Connection Specifications

The proposed riser end termination types are detailed below in Table 6.2.1.

The internal surfaces of all of the riser end fittings are to be clad with Inconel 625 weld overlay (reference /B10/). All external surfaces are to be Nikaflex treated as per Technip standard procedure.

Item Service Riser / Flowline Interface Termination Type a)

Topside Connection Termination Type b)

1 & 2 Production Grayloc Hub Grayloc Hub 12M91 3 Production / Test Grayloc Hub Grayloc Hub 8GR72 4 Gas Lift Grayloc Hub Grayloc Hub 8GR62 5 Gas Injection Grayloc Hub Grayloc Hub 8GR62 6 Water Injection Grayloc Hub Grayloc Hub 12M91

Table 6.2.1 Riser End Fitting Termination Schedule

Notes:a) Hub types to be confirmed during detailed design (reference /A8/). b) Reference /B24/. Riser topside end fittings will be supplied with 2 GRVs each and will be compatible for tie-in into the vent pipework. Riser subsea end fittings will each be supplied with 3 gas vent ports



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