Basis of Design

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

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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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 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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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

JA004847-JSD-3500-0001 Rev 2.doc



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


JA004847-JSD-3500-0001 Rev 2.doc

ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 1.0

EXECUTIVE SUMMARY

1.1

Field Overview


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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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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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 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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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


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


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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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” 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]


[B21]


[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


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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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)


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


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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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


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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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 <0.5 11000 430 390 1300 8 <2 20000 <1 140 <1 2700 n/a

Table 5.9.1 Enfield-2 Produced Water Composition The pH of the produced water is between 4.5 and 5.5 (reference /B6/ item 325). 5.10

Insulation Requirements The insulation requirements, based on internal diameter with flooded insulation annulus conditions (for the flowlines), for the Production risers and flowlines are as detailed below in table 5.10.1 (reference /A28/). Service 9” Production Risers 8” Production / Test Riser 9” Production Flowlines 8” Production / Test Flowlines

U Value (W/m2/ C) 7.05 7.35 6.3 6.6

Table 5.10.1 Insulation Requirements 5.11

Sand Production The sand production rate for the production risers and flowlines is as follows (reference /B1/ data sheet 0206 revision 5): Design life = 20 years 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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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 <0.2% vol. assuming 100,000 bbl/d liquids production.


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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design 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 V(z) V(d) d

= = = =

elevation of interest above seabed, (m). current speed at elevation z, (m/s). near-bottom current speed, (m/s). corresponds to the elevation ASB at which the nearbottom 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 Enfield FPSO Production Manifold E-DC1 Water Injection PLEM E-DC2 Water Injection PLEM E-DC3 Gas Injection Drill Centre E-DC4

LAT Water Depth (m) 396 516 495 551 552

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 MSL

2.1 m 1.0 m

The surge values are given as follows (reference /B5/): 100 year cyclonic high tide 100 year cyclonic low tide 5.14.2

+0.86 m -0.34 m

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 Surface Seabed

Seawater Temperature ( C) Extreme Minimum Extreme Maximum 24 30 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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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 Significant Wave Height – Hs (m) Spectral Peak Wave Period – Tp (s) Spectral Mean Wave Period – Tm (s) Average Zero-Crossing Wave Period – Tz (s) Maximum Single Wave Height – Hmax (m) Period of Maximum Single Wave – THmax (s) Philips Parameter – Peakedness Parameter – Sigma A – a Sigma B – b

1 year 4.7 11.7 7.5 6.8 8.5 8.6 0.0064 0.8206 0.1140 0.1129

10 year 5.7 12.9 8.3 7.5 10.3 9.5 0.0064 0.8204 0.1140 0.1129

50 year 6.5 13.8 8.8 8.1 11.7 10.2 0.0064 0.8203 0.1140 0.1129

Table 5.14.4.1 Infield Non-cyclonic Wave Data for 1, 10 and 50 year Return Period Return Period 565m ASB (-15m MSL) – V-15 (m/s) 515m ASB (-65m MSL) – V-65 (m/s) 455m ASB (-125m MSL) – V-125 (m/s) 335m ASB (-245m MSL) – V-245 (m/s) 95m ASB (-485m MSL) – V-485 (m/s) 5m ASB (-575m MSL) – V-575 (m/s)

1 year 1.07 0.90 0.94 0.61 0.45 0.43

10 year 1.22 0.94 1.03 0.67 0.54 0.50

50 year 1.30 0.96 1.08 0.70 0.60 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 Significant Wave Height – Hs (m) Spectral Peak Wave Period – Tp (s) Spectral Mean Wave Period – Tm (s) Average Zero-Crossing Wave Period – Tz (s) Maximum Single Wave Height – Hmax (m) Period of Maximum Single Wave – THmax (s) Philips Parameter – Peakedness Parameter – Sigma A – a Sigma B – b

1 year 4.7 11.7 7.5 6.8 8.5 8.6 0.0064 0.8206 0.1140 0.1129

10 year 5.7 12.9 8.3 7.5 10.3 9.5 0.0064 0.8204 0.1140 0.1129

50 year 6.5 13.8 8.8 8.1 11.7 10.2 0.0064 0.8203 0.1140 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 390m ASB (-10m MSL) – V-10 (m/s) 340m ASB (-60m MSL) – V-60 (m/s) 280m ASB (-120m MSL) – V-120 (m/s) 160m ASB (-240m MSL) – V-240 (m/s) 65m ASB (-335m MSL) – V-335 (m/s) 5m ASB (-395m MSL) – V-395 (m/s)

1 year 1.06 0.91 0.94 0.69 0.67 0.57

10 year 1.16 0.96 1.01 0.77 0.73 0.62

50 year 1.22 0.98 1.04 0.81 0.76 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) Steady Current at 2m ASB (m/s)

N 0.45

NE 0.45

E 0.45

SE 0.85

S 0.45

SW 0.45

W 0.45

NW 0.68

OMNI 0.85

NW 1.6

OMNI 2.02

Table 5.14.6.1 Infield 1 Year Soliton Steady Current Direction (To) Steady Current at 2m ASB (m/s)

N 1.0

NE 1.0

E 1.0

SE 2.0

S 1.0

SW 1.0

W 1.0

Table 5.14.6.2 Infield 50 Year Soliton Steady Current Notes: 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 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 Current Reference height ASB Seabed friction 5.14.7

0.0003 m 2.0 m 0.37

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 Current Reference height ASB Seabed friction

5.14.8

0.0003 m 2.0 m 0.5

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) Significant Wave Height – Hs (m) Spectral Peak Wave Period – Tp (s) Spectral Mean Wave Period – Tm (s) Average ZeroCrossing Wave Period – Tz (s) Maximum Single Wave Height – Hmax (m) Period of Maximum Single Wave – THmax (s) Philips Parameter – Peakedness Parameter – Sigma A – a Sigma B – b

N 5.48

NE 5.60

E 6.82

SE 10.35

S 11.81

SW 11.14

W 7.89

NW 5.80

OMNI 12.12

10.26

10.34

11.12

13.11

13.85

13.52

11.76

10.48

14.00

8.10

8.16

8.78

10.35

10.93

10.67

9.28

8.27

11.05

7.59

7.65

8.23

9.70

10.24

10.00

8.70

7.75

10.36

9.54

9.74

11.87

18.02

20.56

19.39

13.73

10.10

21.09

9.32

9.39

10.10

11.90

12.57

12.27

10.67

9.51

12.71

0.0114 1.73

0.0115 1.75

0.0124 1.92

0.0140 2.24

0.0144 2.33

0.0142 2.29

0.0130 2.04

0.0117 1.78

0.0145 2.35

0.086 0.098

0.086 0.098

0.083 0.096

0.078 0.094

0.077 0.093

0.078 0.093

0.081 0.095

0.085 0.098

0.077 0.093

NW 0.22 0.24 0.20 0.27 0.25 0.48 0.75 0.85 0.94 1.04

OMNI 0.82 1.32 1.48 1.43 1.43 1.59 1.83 1.94 2.07 2.28

Table 5.14.8.1 Extreme 100 Year Cyclonic Wave Data Direction (To) 276m below MSL – V-276 (m/s) 209m below MSL – V-209 (m/s) 163m below MSL – V-163 (m/s) 121m below MSL – V-121 (m/s) 83m below MSL – V-83 (m/s) 59m below MSL – V-59 (m/s) 36m below MSL – V-36 (m/s) 26m below MSL – V-26 (m/s) 15m below MSL – V-15 (m/s) 5m below MSL – V-5 (m/s)

N 0.08 0.18 0.26 0.31 0.30 0.48 0.70 0.80 0.94 1.05

NE 0.38 0.39 0.40 0.42 0.50 0.59 0.87 0.99 1.10 1.19

E 0.49 0.42 0.35 0.38 0.41 0.54 0.79 0.88 0.99 1.10

SE 0.48 0.36 0.32 0.29 0.33 0.67 1.02 1.15 1.28 1.46

S 0.61 0.67 0.71 0.60 0.80 1.17 1.55 1.70 1.86 2.06

SW 0.80 1.30 1.48 1.43 1.43 1.59 1.81 1.90 2.03 2.23

W 0.69 1.12 1.27 0.96 0.73 0.89 1.17 1.26 1.40 1.62

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 Zone 1 Carbonate Sand Zone 2 Carbonate Mud

Tide & Drift 0.5 0.4

Soliton 0.5 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 Depth MSL to -5m -5m to -70m -70m to -100m -100m to -150m -150m to -600m

5

10 15 20 Hard Thickness (mm) 38 75 113 150 45 45 68 90 15 26 39 53 1 1 2 2 0 0 0 0

5 0 45 41 4 2

10 15 20 Soft Thickness (mm) 0 0 0 104 104 104 60 60 60 10 10 10 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 tanker’s bow by a special reinforced section of the ship’s 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 Riser Draught Disconnected Riser Draught Loaded Riser Draught Ballasted Riser Draught Intermediate

Units m m m m

Value 74.8 67.8 61.3 65.0

Table 5.17.1.1 Riser Column Data The FPSO drafts are detailed below (reference /B3/ and /B22/): Vessel Ballasted Draught Vessel Fully Loaded Draught Vessel Intermediate Draught 5.17.2

11m 17.5m 14.7m

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 Excursion Elevation Angle

QS Max QS Min Max QS Max

Ballasted Draft In-Between SW / SE Bundle 38.4 m 50.0 m -57.8 m -52.0 m -66.0 m 16.1 deg 22.5 deg

Fully Loaded Draft In-Line with SW Bundle 26.2 m 35.5 m -63.0 m -57.0 m -69.5 m 19.0 deg 25.5 deg

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


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Motion Excursion Elevation Angle


In-Plane Loading Note a) In-Line with In-Between SW SW Bundle / SE Bundle 23.1 m 35.2 m 34.7 m 43.7 m -56.5 m -57.2 m -52.2 m -53.0 m -63.7 m -64.1 m 19.1 deg 17.6 deg 21.9 deg 20.0 deg


Transverse Loading Note b) In-Line with In-Between SW SW Bundle / SE Bundle 29.4 m 23.0 m -57.4 m -57.4 m 17.3 deg 17.4 deg -

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


QS QS QS

In-Plane Loading Note a) In-Line with In-Between SW SW Bundle / SE Bundle 17.3 m 28.5 m -59.2 m -59.5 m 12.6 deg 11.8 deg

Transverse Loading Note b) In-Line with In-Between SW SW Bundle / SE Bundle 27.5 m 19.0 m -58.9 m -57.4 m 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 Excursion Elevation Angle


Intact Mooring 43.5 m 55.0 m -75.4 m -71.0 m -79.0 m 8.5 deg 20.0 deg

Damaged Mooring 53.5 m 65.0 m -75.4 m -71.0 m -79.0 m 11.5 deg 25.0 deg

Table 5.17.2.4 Riser Entry Disconnected Extreme Motions – 100 year Cyclonic


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In-Line with SW Bundle 7.5 m 13.5 m -74.7 m -74.0 m -76.0 m 3.3 deg 8.7 deg


In-Between SW / SE Bundle 9.5 m 13.0 m -74.6 m -73.8 m -75.9 m 3.5 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 inline 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 Vessel connected, ballasted Vessel connected, fully loaded Vessel Connected, Intermediate Vessel disconnected

Riser Bend Stiffener Distance below MSL (m) 61.3 67.8 65.0 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 3 degrees.

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

Component Type Diameter Diameter w/sheathing Nominal Length N bundle leg1 Nominal Length N bundle leg2 Nominal Length N bundle leg3 Nominal Length (SE bundle) Nominal Length SW bundle leg7 Nominal Length SW bundle leg8 Nominal Length SW bundle leg9 Weight in Air Weight in Water Axial Stiffness (EA)

mm mm m m m m m m m kg/m kg/m MN

Segment 1 Seabed

Segment 2 Middle

Segment 3 Fairlead

Stud less R3

Sheathed Spiral Strand 68 88

Stud less R3

354

85

346

85

360

85

25.3 19.1 409

142.5 124 645

110 N/A 498 496 495 505 494 496 498 244 213 953

84 N/A

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 Radius between top chain connection and turret centre line Height of top chain connection point above riser column keel Nominal anchoring radius from fairlead N Bundle leg 1 Nominal anchoring radius from fairlead N Bundle leg 2 Nominal anchoring radius from fairlead N Bundle leg 3 Nominal anchoring radius from fairlead SE Bundle leg 4 Nominal anchoring radius from fairlead SE Bundle leg 5 Nominal anchoring radius from fairlead SE Bundle leg 6 Nominal anchoring radius from fairlead SW Bundle leg 7 Nominal anchoring radius from fairlead SW Bundle leg 8 Nominal anchoring radius from fairlead SW Bundle leg 9

Value 8.53 m 41.5 m 842 m 842 m 844 m 856 m 856 m 856 m 837 m 837 m 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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Loading Condition

Bundle

Horizontal Tension (kN)

Vertical Tension (kN)

Total Tension (kN)

Ballast FPSO Connected

1 2 3 4 5 6 7 8 9

404 405 405 404 404 405 404 403 404

537 533 527 508 509 509 544 546 549

672 669 665 649 650 651 678 679 682

Angle to horizontal ( ) 53.0 52.8 52.5 51.5 51.5 51.5 53.4 53.6 53.7

Table 5.18.3 Mooring Line Static Tensions – Connected & Ballast FPSO Loading Condition

Bundle



Total Tension (kN)

1 2 3 4 5 6 7 8 9

354 354 353 353 354 355 353 352 353

491 486 480 465 465 466 496 498 501

605 602 596 583 584 585 609 610 613

Fully Loaded FPSO Connected


Table 5.18.4 Mooring Line Static Tensions – Connected & Fully Loaded FPSO Loading Condition

Bundle



Total Tension (kN)

1 2 3 4 5 6 7 8 9

305 303 301 302 303 304 301 302 303

444 439 432 420 421 421 446 448 452

538 533 526 517 518 519 538 540 544

FPSO Disconnected


Table 5.18.5 Mooring Line Static Tensions – Disconnected FPSO


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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. Wave Class 1 2 3 4 5 6 7 8 9 10

Hmax (m) 1 2 3 4 5 6 7 8 9 10

THmax (s) 6.6 6.7 7.0 7.4 7.7 8.0 8.2 8.3 8.3 8.3

Number of Cycles for 20 years 40,453,303 41,855,472 13,574,131 2,941,801 550,481 96,990 16,953 3,070 574 107

Corresponding Return Period 1 year 1 year 1 year 1 year 1 year 1 year 1 year 1 year 10 year 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 1 2 3 4 5 6 14

WEL Item No R2 R5 R4 R3 R1 R7 R6

Flexible Service

Directional Split for Number of Cycles

Production 2 Production 1 Production/Test Gas Lift Gas Injection Water Injection EHU

90% transverse 10% far 100% transverse 100% transverse 100% transverse 100% far 100% near 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. 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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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 28.5 m -59.5 m 11.8 deg

Riser Entry QS Excursion Riser Entry QS Elevation Riser Entry QS Inclination

10 year Non-Cyclonic 35.2 m -57.2 m 17.6 deg

Table 5.21.1 In Line Riser Fatigue Offsets Riser Entry QS Excursion Riser Entry QS Elevation Riser Entry QS Inclination



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.

Normal Drag Coefficient, CDN Normal Inertia Coefficient, CMN Axial Drag Coefficient, CDA Axial Inertia Coefficient, CMA

Riser without Marine Growth (Post Installation Cases) 0.70 2.00 0.00 0.00

Riser with Marine Growth (Operation Cases) 1.00 1.80 0.10 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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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, Inertia Force Coefficient, Drag Force Coefficient, Reynolds Number 3 x 105, Reynolds Number < 3 x 105,

CL = 0.9 CI = 3.29 CD = 0.7 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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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

1 2 3 4 5 6 14

Production Production Production / Test Gas Lift Gas Injection Water Injection EHU

Riser Attachment Point Elevation below FPSO Keel (m) 50.3 50.3 50.3 50.3 50.3 50.3 50.3

Horizontal Distance from C/L of Riser Column (m) 3.335 3.335 3.335 3.335 3.335 3.335 3.335

Nominal Built-in Angle to Vertical (Deg) 10 10 10 10 10 10 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 1&2 3 4 5 6


Riser / Flowline Interface Termination Type a) Grayloc Hub Grayloc Hub Grayloc Hub Grayloc Hub Grayloc Hub

Topside Connection Termination Type b) Grayloc Hub 12M91 Grayloc Hub 8GR72 Grayloc Hub 8GR62 Grayloc Hub 8GR62 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 GRV’s 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 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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which are plugged (reference /B10/). The maximum allowable back pressure to the GRV’s will be determined during detailed design (reference /B6/ item 76). Bolt details are to be confirmed during detailed design. Loads from the topside piping to the riser end fittings are included in Appendix Q. The riser mating piping ID’s are included below in table 6.2.2. Item 1&2 3 4 5 6


Mating Line ID 230.2 182.6 124.4 139.8 230.2

Table 6.2.2 Riser Mating Piping ID Notes: a) Any differences in internal diameter between flexible pipe and adjacent hard piping shall be met by the tapering of the flexible pipe end fitting bore (reference /B10/). b) The taper for the gas lift and gas injection risers will be taken in the mating hubs to allow a common end fitting to be used for both (reference /A26/). 6.3

Flowline Tie-In Data The production and gas lift flowlines will connect into the Production Manifold, E-DC1. The water injection flowlines will connect into the Water Injection Manifolds, E-DC2 and E-DC3. The gas injection flowline will connect into the Gas Injection Flow Base, E-DC4. The height of the connections is approximately 3m for all lines except for the Gas Injection line which is approximately 2m (reference /B6/, item 3) with an installation tolerance to be determined during detailed design. For the umbilicals the height is approximately either 3m or 2m depending on the location and to be determined during detailed design. The connections are 15 degrees downwards with an installation tolerance on inclination of 5 degrees (see section 6.6).

6.4

Flowline Interface Connection Specifications The proposed flowline end terminations types are detailed below in Table 6.4.1. The full bore and face of all of the flowline end fittings and terminations are to be clad with Inconel 625 weld overlay (reference /B10/). All external surfaces are to be Nikaflex treated as per Technip standard procedure.


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Item

Service

7&8 9 10 11 12 & 13

Production Production / Test Gas Lift Gas Injection Water Injection

Flowline End Termination Type at Riser End Grayloc Hub Grayloc Hub Grayloc Hub Grayloc Hub Grayloc Hub

Flowline Termination Type at Midline Connection (if required) Grayloc Hub Grayloc Hub Grayloc Hub Grayloc Hub Grayloc Hub

Flowline End Termination Type at Manifold or Drill Centre Ends Destec flange Destec flange Destec flange Destec flange Destec flange

Table 6.4.1 Flowline End Fitting Termination Schedule Notes: a) Hub types and flange sizes to be confirmed during detailed design (reference /A9/). Each flowline end fitting will be supplied with 2 GRV’s (reference /B10/). The maximum allowable back pressure to the GRV’s will be determined during detailed design (reference /B6/ item 76). Bolting will be uncoated grade B7 carbon steel and nuts will be uncoated grade 2H carbon steel, with hardness less than 350HV. This is subject to verification of suitability during detailed design. The flowline mating Destec flange ID’s are included below in table 6.4.2 (reference /B19/, /B20/ and /B21/). Item 1&2 3 4 5 6


Destec Flange ID 215.8 182.5 131.7 131.7 215.8

Table 6.4.2 Flowline Mating Piping ID Notes: a) Any differences in internal diameter between flexible pipe and adjacent Destec flange shall be met by the tapering of the flexible pipe end fitting bore (reference /B10/). The maximum permissible loads for the flowlines connection to the Subsea equipment at EDC1, E-DC2, E-DC3 and E-DC4 are included below in tables 6.4.3, 6.4.4 and 6.4.5 (reference /B11/). Note that the loads are indicative as they are the maximums for this combination only. Actual values obtained must be checked for acceptability during detailed design.


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Maximum operation load from flexible flowlines (345 bar) Maximum operation load from flexible flowlines (345 bar) Maximum operation load from flexible flowlines (345 bar) Maximum operation load from flexible flowlines (345 bar)

Loads Acting On Flowline Hub 10” ID (9” production) Flowline Hub 6” ID (6” gas lift) Flowline Hub 8” ID (8” production / test) Flowline Hub 10” ID (9” production)

Forces (kN) FV FT

FL


Moments (kNm) ML MV MT

-100

-70

40

15

180

+100

-100

-60

20

30

80

+50

-100

-70

40

15

180

+100

-100

-70

40

15

180

+100

Table 6.4.3 Permissible Loads from Flowlines for E-DC1 Notes: a) Loads give small contributions for global design of structure, and are therefore neglected. b) For location of forces and moments acting on Hubs see Appendix I. c) Hubs tilted 15 degrees downwards from horizontal.

Loads Acting On Maximum operation Flowline Hub load from flexible 10” ID (10” flowlines (345 bar) water injection)

FL

Forces (kN) FV FT

-100

-70

40

Moments (kNm) ML MV MT 15

180

+100

Table 6.4.4 Permissible Loads from Flowlines for E-DC2 & E-DC3 Notes: a) Loads give small contributions for global design of structure, and are therefore neglected. b) For location of forces and moments acting on Hubs see Appendix I. c) Hubs tilted 15 degrees downwards from horizontal.

Loads Acting On Maximum operation Flowline Hub load from flexible 6” ID (6” gas flowlines (345 bar) injection)

FL

Forces (kN) FV

FT

-100

-60

20

Moments (kNm) ML MV MT 30

80

Table 6.4.5 Permissible Loads from Flowlines for E-DC4


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+50



Notes: a) Loads give small contributions for global design of structure, and are therefore neglected. b) For location of forces and moments acting on Hubs see Appendix I. c) Hubs tilted 15 degrees downwards from horizontal. 6.5

Ancillary Equipment The flexible riser engineering scope also includes the requirement to provide information to enable the design of related ancillary equipment. The ancillary equipment will be designed in accordance with the requirements of reference /B10/ where applicable. This equipment includes: Anodes and cathodic protection system Pull / test heads Sliding bend stiffeners Bend stiffener connectors Bend restrictors (if required for the in-place tie-in connection) Buoyancy modules including clamps Uraduct (if required for weight or protection) Hold back clamp (if required) Sliding stopper for stiffener per riser (for installation phase) if required Dummy end fittings See Document Responsibility Assignment Matrix (DRAM), JA004847-REG-7011-0001 for document numbers for the above items.

6.6

Installation Tolerances The tolerances to be used for the design of the flexible riser system are as follows: +/-3m for the FPSO location. +/-3m for the riser / flowline connection location. The flowline connections to the manifolds and drill centres are 15 degrees downwards, but an inclination of 5 degrees is to be considered for installation tolerances (reference B14/).


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METHODOLOGY

7.1

Determination of Flexible Pipe Components


The dynamic flexible risers will be designed and shall be verified in accordance to Technip internal design rules (reference /A1/ and /A2/). API 17J acceptance criteria will be applied throughout. 7.2

Material Selection for the Flexible Pipe Components The dimensions and materials of each layer are determined in accordance with reference /A2/. Materials will be selected accounting for fluid compatibility, structural capacity and manufacturing feasibility. The material selection will be based upon existing testing and qualification data which is in accordance with reference /A2/. Full consideration will be given to the affect of the pressure and armour wire materials chosen with respect to corrosion fatigue.

7.3

Pressure and Tension Resistance of the Flexible Pipe The flexible risers will be checked for resistance to internal and external pressure and applied tension.

7.3.1

Design Method The response of the flexible pipe structure to applied tension and pressure is determined using STRUCTURE / EFLEX® program (reference /A10/) which determines stress levels within each layer.

7.3.2

Design Cases The design cases detailed below in table 7.3.2.1 will be checked for each riser:

Case

Type

1

Recurrent Operations Extreme / Abnormal Operations Installation (Functional) PostInstallation (Pressure Test) FAT

2

3 4

5

Internal Pressure MOP Design Pressure d) Ambient Offshore Strength Test Pressure Note a) FAT Pressure Note a)

External Pressure Zero Note b) Zero Note b)

Tension Maximum reported by dynamic analysis load cases for recurrent operation Maximum reported by dynamic analysis load cases for extreme and abnormal operations

Zero Note b) Zero Note b)

Maximum tension estimated for installation Note c) Maximum reported by dynamic analysis load cases for offshore strength test

Zero

Zero

Table 7.3.2.1 Riser Pressure and Tension Design Cases


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Notes: a) FAT and offshore test pressures shall be as per Section 5.4 with 5% over pressurisation added. b) Zero external pressure is a conservative assumption. c) The maximum installation tension for each riser will be estimated as follows and compared to actual installation analysis results (reference /A21/) when these are known: Weight of the riser (full or empty – to be determined during detailed design) in the water column (maximum water depth along riser route) and an additional 10m length from the water level to the VLS. Multiplication coefficient of 1.2 for estimation of the length in the installation catenary shape. Dynamic Amplification Factor (DAF) of 1.5 to estimate the vessel motions during installation. d) The design pressure is to include the 10% or 16% over pressure as detailed in section 5.3. The design cases detailed below in table 7.3.2.2 will be checked for each flowline: Case

Type

1

Recurrent Operations Extreme / Abnormal Operations Installation (Functional) PostInstallation (Pressure Test) FAT

2

3 4

5

Internal Pressure MOP Design Pressure d) Ambient Offshore Strength Test Pressure Note a) FAT Pressure Note a)

External Pressure Zero Note b) Zero Note b)

Tension Maximum reported by tie in and on bottom stability analysis (reference /A15/) Maximum reported by tie in and on bottom stability analysis (reference /A15/)


Maximum tension estimated for installation Note c) Maximum reported by tie in and on bottom stability analysis (reference /A15/)

Zero

Zero

Table 7.3.2.2 Flowline Pressure and Tension Design Cases Notes: a) FAT and offshore test pressures shall be as per Section 5.4 with 5% over pressurisation added. b) Zero external pressure is a conservative assumption. c) The maximum installation tension for each flowline will be estimated as follows and compared to actual installation analysis results (reference /A21/) when these are known: Weight of the flowline (full or empty – to be determined during detailed design) in the water column (maximum water depth along flowline route) and an additional 10m length from the water level to the VLS. Multiplication coefficient of 1.2 for estimation of the length in the installation catenary shape. Dynamic Amplification Factor (DAF) of 1.5 to estimate the vessel motions during installation.


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ENFIELD SUBSEA EPIC Risers and Flowlines Basis of Design d)

7.3.3


The design pressure is to include the 10% or 16% over pressure as detailed in section 5.3.

Acceptance Criteria The utilisation factors within each layer are defined by API 17J, according to the type of operation. Case

Type

1 2 3 4 5

Recurrent Operations Extreme / Abnormal Operations Installation (Functional) Post-Installation (Pressure Test) FAT

API 17J Allowable Utilisation Factors Pressure Wires 0.55 0.85 0.67 0.91 0.91

API 17J Allowable Utilisation Factors Tensile Wires 0.67 0.85 0.67 0.91 0.91

Table 7.3.3.1 Pressure and Tension Design Cases Allowable Utilisation Factors 7.4

Hydrostatic Collapse of the Flexible Pipe

7.4.1

Design Method The ultimate hydrostatic collapse capacity of the flexible pipe is determined using the STRUCTURE and COLLAPSE programs (reference /A10/). The COLLAPSE program is a Technip in-house program that is able to calculate the collapse pressure of a straight or curved flexible pipe. The hydrostatic collapse pressure for the pipe considered in a straight line is reported on the flexible pipe TDS. In addition, the “bent” collapse pressure corresponding to the riser bent to its minimum operational MBR is calculated by the COLLAPSE program. The calculation assumes the external sheath is breached and that the hydrostatic pressure acts directly on the pressure sheath. This is a conservative assumption. Note that for the insulated production and production / test risers and flowlines the calculation assumes that the hydrostatic pressure acts directly on the intermediate sheath.

7.4.2

Design Parameters The design parameters are the maximum hydrostatic pressure due to the water column (inclusive of wave crest) as stated in section 5.14. The pipe will be conservatively assumed to be empty with atmospheric pressure in the bore in the first instance. In the event that the required utilisation factors are not met (see section 7.4.3) then the analysis will consider the minimum product density for operational / disconnected purposes and either partial or full flooding for installation purposes (see reference /A21/).

7.4.3

Acceptance Criteria The allowable hydrostatic pressure to which the flexible pipe may be exposed is calculated by applying an appropriate factor of safety as specified by reference /S2/ on the ultimate collapse capacity of the pipe. The reference /S2/ utilisation factor is calculated for the rough bore structures as follows:

UF

D max 300 600

0.18 0.67


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Where Dmax is the maximum water depth including tidal and wave effects. This will be calculated for each individual flowline and riser during detailed design (references /A14/ and /A15/). This calculated value is also to be used for the “bent” collapse condition when the riser or flowline is bent to a radius appropriate to the operational or installation conditions (reference /B6/ item 77). For smooth bore structures the utilisation factor will be as per table 6 of reference /S2/ (dependent on type of operation) for pressure armours (reference /B6/ item 198). 7.5

Crushing Capacity of the Flexible Pipe The flexible risers will be analysed for crushing capacity during normal installation and recovery installation. Normal installation is a functional activity and recovery installation is an accidental activity as defined by API 17J.

7.5.1

Design Method The crushing capacity of the flexible line is determined using Technip internal software PARABAQ (reference /A10/), a customised module of the finite element package ABAQUS. This software can calculate the stresses induced by a gutter radius and/or tensioners associated with axial tensile load induced during installation. The limiting value is the most conservative value of: a) b)

Plastification of carcass: When the yield stress is reached in the carcass material or the pressure vault material (failure is deemed to occur). Ovalisation: When 2% permanent ovalisation has been reached in the inner diameter of the carcass.

Whichever of these occurs first determines the maximum allowable tension for the flexible pipe when installed over an arch or drum of specified radius or driven through a specific tensioner. 7.5.2

Design Parameters The flexible risers will be considered for installation using a vertical lay system. Details of the system and resulting loadings will be confirmed during installation analysis and used to analyse the flexible pipes (see reference /A21/).

7.5.3

Acceptance Criteria Crushing capacity calculations are performed for installation purposes. The appropriate API 17J safety factors for the recovery (i.e. 0.85) and installation (i.e. 0.67) phases will be applied to the ultimate crushing capacity of the pipe to calculate the allowable tension in the pipe, which will be reported.


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Erosion of the Flexible Pipe There is no production and entrainment of solids specified in the following risers and flowlines and thus no requirement for an erosion analysis: Gas Lift Gas Injection (see note below) Water Injection As the production lines contain solids an erosion analysis of the carcass is required for the Production risers and flowlines. The data included in section 5.11 for the initial start up of the wells is not considered as it is not a normal operational condition and as such will generate negligible erosion. Note: There is sand in the gas injection risers and flowlines but only for the back flow operations. This case will not be analysed as it is considered a short term event and as such will generate negligible erosion.

7.6.1

Design Method TOPL in-house spreadsheet EROSION (reference /A10/) is used to evaluate the erosion rate of the carcass layer of the pipe and determine the characteristic of the eroded carcass strip. The spreadsheet is based on the methodology presented in OTC publication 4485 modified for flexible pipes. Then the COLLAPSE program (reference /A10/) is used to calculate the new collapse pressure of the flexible structure when the carcass is eroded.

7.6.2

Design Parameters The design parameters to consider are the sand production data described in Section 5.11.

7.6.3

Acceptance Criteria The acceptance criterion is that the hydrostatic collapse pressure of the flexible riser with the eroded carcass should remain below the allowable limits as defined in Section 7.4.3.

7.7

Annulus Calculations of the Flexible Pipe The steel layers of the flexible pipes (armour and pressure wires) become surrounded by the gases which diffuse through the pressure sheath or inner tube. It is important to determine the composition of this gaseous environment to ensure that the steel layers are not compromised by the presence of CO2, H2S and water in the annulus. Note that this does not indicate that the pipe can be operated with a damaged external sheath for the field life. Wire dimensions after corrosion will be assessed to ensure wire stresses do not exceed the allowable stresses under extreme conditions as specified in API 17J. Gas diffusion and CO2 corrosion calculations will be performed to ensure the structure materials are suitable for annulus conditions. The results of the gas diffusion calculations are also used to determine the annulus composition for the assessment of corrosion fatigue.


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Gas Diffusion Calculations The rate of diffusion of the different gases through the pressure sheath is dependent on the gas composition in the bore of the flexible pipe, the physical properties of the flexible pipe layers and the ambient and operating temperatures and pressures. Temperatures in the flexible pipe layers are computed using the Technip program THERM (reference /A10/). Gas diffusion calculations are performed using Technip internal program MOLDITM (reference /A10/). The inputs detailed below in Table 7.7.1.1 will be used for these calculations (reference /B1/ data sheets 0206 revision 5, 0207 revision 1 and 0614 revision 4).

Item

Service

Maximum Operating Pressure c)

1&2 3 4 5 6 7&8 9 10 11 12 & 13

Production Production/Test Gas Lift Gas Injection Water Injection Production Production/Test Gas Lift Gas Injection Water Injection

MFOP MFOP MFOP MFOP MFOP MFOP MFOP MFOP MFOP MFOP

Operating Temperature ( C) 65 65 60 60 60 65 65 60 60 60

Maximum CO2 Content in Gas Phase (Mol%) 5 5 6.5 6.5 5 a) 5 5 6.5 6.5 5 a)

Maximum H2S Content in Gas Phase (ppmv) 25 25 25 25 25 b) 25 25 25 25 25 b)

Water Cut (%) 0-95 0-95 0 0 N/A 0-95 0-95 0 0 N/A

CH4+C2+ C3 Content in Gas Phase (Mol%) 66.7 e) 66.7 e) 93.5 d) 93.5 d) 58.5 d) 66.7 e) 66.7 e) 93.5 d) 93.5 d) 58.5 d)

Table 7.7.1.1 Gas Diffusion Calculations Input Notes: a) The design composition of CO2 is 5% mol at 0.8 barg in the de-gasser unit at standard conditions (reference /B6/, item 52 and /B13/, item 4). b) The design composition of H2S is to be taken as 25ppm at 0.8 barg in the de-gasser unit at standard conditions (reference /B6/, item 52 and /B13/, item 4). c) The MFOP is as per section 5.2. d) Unless otherwise stated CO2 and H2S content in gas phase is at standard conditions. e) At operating temperature and pressure. The results of the gas diffusion are inputs for the Technip in-house program PH (reference /A10/) to determine the pH of the annulus composition and allow the selection of the adequate SN curve for the corrosion fatigue assessment (see Section 7.12). The maximum allowable flow rate of gas through the pressure sheath over the entire length of flexible must remain below 6 litres / minute per GRV and 90 litres / minute per NRV. 7.7.2

CO2 Corrosion The net corrosion rate of steel layers of the flexible pipe due to the diffused CO2 combining with Iron (Fe) and water will be assessed using TOPL internal spreadsheet CORROS1 (reference /A10/). It will be demonstrated that this loss is not sufficient to compromise the integrity of the steel layers when submitted to the loads they are expected to encounter during the design life of the flexible risers. The design cases to be considered are as detailed below in table 7.7.2.1.


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Item

Service

Load Case

Internal Pressure (bar)

Tension (kN)

CO2 Flowrate (l/m/s)

1&2

Production Risers Production/Test Riser Gas Lift Riser

Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations Recurrent Operations Extreme / Abnormal Operations

Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b) Note a) Note b)

Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d) Note c) Note d)

Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e) Note e)

3 4 5 6 7&8 9 10 11 12 & 13

Gas Injection Riser Water Injection Riser Production Flowlines Production/Test Flowline Gas Lift Flowline Gas Injection Flowline Water Injection Flowlines

Table 7.7.2.1 Design Parameters for CO2 Corrosion Notes: a) For recurrent operations, the internal pressure corresponds to the MFOP as specified in Section 5.2. b) For extreme/abnormal operations, the internal pressure corresponds to the maximum differential design pressure as specified in Section 5.2. c) For recurrent operations, the tension to consider for the risers is the maximum design tension retained for recurrent operations load cases as defined in reference /A11/. For the flowlines the maximum tie-in tension is used as defined in reference /A15/. d) For extreme/abnormal operations, the tension to consider for the risers is the maximum design tension retained for extreme/abnormal operations load cases as defined in reference /A11/. For the flowlines the maximum tie-in tension is used as defined in reference /A15/. e) The CO2 flowrate to consider is the stabilised flowrate of CO2 through the pressure sheath for a damaged external sheath as defined in reference /A14/ and /A15/ for the risers and flowlines respectively. The acceptance criteria is that the flexible risers shall remain compliant with API 17J design requirement in their “end of field life” condition, after considering the maximum potential thickness loss to the armour wires due to CO2 corrosion. 7.8

Reverse End Cap Effect of the Flexible Pipe

7.8.1

Design Method The combination of hydrostatic pressure causing compression on the ends of the pipe and flooding of the annulus resulting from a damaged outer sheath creates the potential for bird caging of the wires due to reverse end cap effect (RECE). Torsion applied to the pipe can


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have similar bird caging effects on the outer armour layer. Design for RECE due to both compression and torsion of Technip flexible pipes is covered in reference /A3/. For the Enfield risers and flowlines, RECE will be assessed for compression during operation and by torsion during installation. 7.8.2

Design Parameters The design parameters for RECE for operational and installation cases are as detailed below in Table 7.8.2.1. Case

Description

1

Installation

2

Operation (Shut Down)

Internal Pressure Zero (conservative assumption) Zero (conservative assumption)

External Pressure Hydrostatic pressure Note a) Hydrostatic pressure Note c)

Compression

Twist

Nil

Allowable torsion to be calculated Nil

Note b) Allowable compression to be calculated

Table 7.8.2.1 RECE Design Parameters Notes: a) Hydrostatic pressure corresponding to the maximum instantaneous water level for the 1-year Rp conditions (see section 5.14). b) Flexible riser shall be installed under tension. c) Hydrostatic pressure corresponding to the maximum instantaneous water level for the 100-year Rp conditions (see section 5.14). d) If necessary, pressure corresponding to fluid at minimum density shall be used. 7.8.3

Acceptance Criteria Allowable compression and torsion of the flexible risers and flowlines shall be determined to satisfy RECE criteria defined in reference /A3/, as follows: The cumulative radial gap cannot exceed 50% of the thickness of the thinnest armour layer. (Note that for water depths greater than 500m this criterion is reduced to 30%). Tension in each tape must be lower than 30% of the tape breaking strength. Tension in armour wires does not exceed the allowable for the appropriate condition.

7.9

Cathodic Protection of the Flexible Pipe

7.9.1

Design Method Half-shell bracelet anodes will be electrically connected to the end fittings and steel armours of the flexible risers and flowlines. The anodes cathodically protect the flexibles in the event of damage to the external sheath resulting in exposure of armour wires to seawater or in the event of damage to the Nikaflex® corrosion coating on the end fitting. The anode requirements are calculated using Technip in-house program PROCAT (reference /A10/) in accordance with DEP 30.10.73.32 (reference /B12/). The anodes will be installed offshore during installation.


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Design Parameters Design data and assumptions are detailed below in Table 7.9.2.1. Parameter Anode material Design life Resistivity of seawater Average annual maximum seawater temperature at seabed Anode potential in seawater Steel protective potential Current Initial density Mean (Unburied) Final End fitting coating breakdown Damaged area of external sheath Anode utilisation factor Internal fluid temperature Temperature correction

Data Aluminium-Zinc-Indium alloy As per section 5.13 0.27 Ohm.m (reference /S3/ assuming 35% salinity) As per Section 5.14.2 -1050 mV (wrt Ag/AgCl/Sea Water) (reference /S3/) -800 mV (wrt Ag/AgCl/Sea Water) (reference /S3/) 130 mA/m2 (reference /S3/) 60 mA/m2 (reference /B12/) 80 mA/m2 (reference /B12/) 100% (reference /B10/) 0.3% - Note a) (reference /B10/) 0.8 (reference /S3/) Operating temperature (Section 5.5) 1mA/m2/ C above 25 C operating temperature (reference /S3/)

Table 7.9.2.1 Cathodic Protection Design Parameters Notes: a) The analysis assumes that the external sheath is completely removed over 0.3% of the riser and flowline length. The analysis output shall be the weight and number of anodes required at each location for protecting the flexible risers and flowlines for the design life stated accounting for the flexibles and end fittings. 7.9.3

Acceptance Criteria Design shall be accordance with reference /B12/, and the system will be designed for the 20 years field life.

7.10

Riser Configuration Analysis

7.10.1

General A hybrid lazy wave system has been chosen as the configuration for the Enfield risers. This system is very similar to a traditional lazy wave system in that the flexible riser has distributed buoyancy modules and a section of the riser is lying on the seabed. See sketch included in section 3.2. The difference between the traditional lazy wave system and the hybrid lazy wave system is that the height of the hog bend is reduced which results in higher tensions at the riser / flowline connection. These tensions are taken out of the system by the use of a hold back clamp at the riser / flowline end fitting location, which prevents the transfer of loads into the flowline. This is detailed further in reference /A20/. The EHU is also included in the dynamic analysis model.


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Design Method Finite element analysis will be performed in accordance to reference /B9/ to determine the following: The most effective riser configuration. The interface loads under different conditions. To assess the performance of the risers. To study the risers motions and excursions. To determine the relevant data for the design of ancillary equipment. To demonstrate that the full responses of the riser system are within allowable limits under all loading conditions.

7.10.3

Design Parameters and Analysis Matrices The dynamic analysis will be carried out to satisfy the matrix included in Appendix D (reference /A19/) for FAR, NEAR and TRANSVERSE cases defined as follows: FAR case NEAR case TRANSVERSE case

The environmental conditions push the riser top connection away from the subsea end fitting. The environmental conditions push the riser top connection towards the subsea end fitting. The environmental conditions push the riser top connection in a 90 degree direction to the subsea end fitting. Two directions are considered for the transverse case (Trans 1 and Trans 2), which are 180 degrees from each other.

Additionally a case will be studied for the disconnection of the riser column using the data included in Appendix O. The vessel draft which gives the most onerous vertical displacements (combination of vessel draft and motion) is to be used for the dynamic analysis (reference /B6/, item 57). Therefore the following combination of RAOs and vessel drafts will be used (reference /A18/): Disconnected load cases: Survival disconnected RAOs associated with the disconnected or flooded riser column as appropriate. (Note that the riser column will be disconnected during installation and for any conditions worse than the 50 year non cyclonic). Connected load cases: Survival connected / ballasted draft RAOs associated with the ballasted draft. Two tidal condition levels will be considered: Low water level for the NEAR cases. High water level for the FAR and TRANSVERSE cases. The water levels are as follows (see Section 5.14.1):


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High water level ASB Low water level ASB

100 yr Rp 398.1 m (including storm surge variation) 395.66 m (including storm surge variation)


50 yr Rp 398.1 m

10 yr Rp 398.1 m

1 yr Rp 398.1 m

396 m

396 m

396 m

Table 7.10.3.1 Water Levels The seabed is assumed to be flat for the analysis, however the depth will vary for each riser as detailed below in table 7.10.3.2. Item 1 2 3 4 5 6 14

WEL Item Number R2 R5 R4 R3 R1 R7 R6

Service Production 2 Production 1 Production/Test Gas Lift Gas Injection Water Injection EHU

Seabed Depth 415 415 415 415 405 396 415

Table 7.10.3.2 Depth for Riser Analysis The risers will be analysed with the following conditions: Full marine growth attached (as per Section 5.16) for load cases 1 to 16 and 25 to 28. However, a sensitivity study assuming no marine growth (see section 7.10.5) will be performed on the most critical cases identified in the Riser Dynamic Analysis Report (reference /A11/). No marine growth attached for load cases 17 to 24 as these cases refer to a postinstallation condition (see Appendix D). Internal fluid to be considered is included in Appendix D. The load cases for which the risers are to be considered FOP will be analysed for the maximum fluid density (as per Section 5.6). However, a sensitivity study assuming minimum product density as per section 5.6 (see section 7.10.5) will also be performed on the most critical cases identified in the Riser Dynamic Analysis Report (reference /A11/). See note a) below. Minimum (end of life) buoyancy for load cases 1 to 16 and 25 to 28 with a sensitivity study assuming intermediate (short term) buoyancy (see section 7.10.5) to be performed on the most critical cases identified in the Riser Dynamic Analysis Report (reference /A11/). Maximum (initial) buoyancy for load cases 17 to 20 as these cases refer to a post installation hook up condition. Intermediate (short term) buoyancy for load cases 21 to 24 as these cases refer to a post installation hydrotest condition. Note that the hydrotest will be performed after initial hook up and buoyancy modules lose some of their initial buoyancy upon immersion and during the first 24 hours after immersion, reaching the intermediate buoyancy condition.


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Notes: a) When the riser column is disconnected 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 the gas lift minimum depressurised density which is 1.3 kg/m3 (reference /B26/). However, the maximum density will still be used as this is conservative and also a real case to be considered. b) The gas lift and gas injection lines will remain pressurised at operating pressure. A description of the load cases titles signification is included in Appendix E. 7.10.4

Riser Modelling The configuration analysis will be performed using the Deeplines software (reference /A10/). This has the capability to model beams, bar and cable elements, rigid bodies, seabeds, hydrodynamic, inertia and environmental effects, and to perform simulations in static, quasistatic and dynamic modes. The risers will be modelled using beam and cable elements. The riser physical and mechanical properties are determined using STRUCTURE program (reference /A10/). The top connection of the riser is modelled as a pinned connection (free to rotate) for the global analysis. Detailed analysis of the bend stiffener will be carried out as described in Section 7.15. The output of the dynamic analysis shall provide configurations, lengths as well as angles at the ends of the risers and curvature along the lines. Resultant maximum tensions will be used to construct the load cases for stress analysis of the flexible pipes (see Section 7.3.2). All of the load cases will be analysed using regular wave analysis. Wave heights and periods are defined in Section 5.14. Time domain simulation will cover at least 5 wave periods including a ramp up period during which the wave-induced loads are applied linearly. Note that critical cases may be subjected to irregular wave analysis if deemed appropriate. In this case, a simulation period of 120s will be used, centred on the occurrence of the maximum wave height in a 3-hour storm. The Jonswap parameters defined in Section 5.14 will be used.

7.10.5

Sensitivity Analysis A number of critical load cases will be selected and subjected to a sensitivity study for various parameters. The following parameters will be considered: 1.

Wave period - a number of critical load cases will be selected and subjected to a sensitivity study on the wave period account for wave period variations. For this study, the wave periods used initially will be modified by 20%.

2.

No marine growth – a number of critical load cases will be selected and subjected to a sensitivity study assuming no marine growth on the risers.

3.

Loss of buoyancy modules – a number of critical load cases will be selected and subjected to a sensitivity study assuming the loss of 1 or 10% of buoyancy modules (reference /B6/, item 348). The lost buoyancy module location will be considered as follows: 1st module


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Middle module Last module Additionally for the worst riser the loss of buoyancy modules in between these locations are to be considered (reference /A12/). 4.

Intermediate buoyancy – a number of critical load cases will be selected and subjected to a sensitivity study assuming the intermediate net buoyancy of the modules. This is to cover the condition of the buoyancy modules immediately after installation.

5.

Hydrodynamic coefficients – a number of critical load cases will be selected and subjected to a sensitivity study on the hydrodynamic coefficients. The riser and buoyancy module normal drag coefficient will be increased by 5%.

6.

Product density – a number of critical load cases will be selected and subjected to a sensitivity study assuming the minimum product density. For the production and production / test risers the minimum product density for each riser will still be taken as per see note a) of section 7.10.3.

7.

Vessel out of plane to wave – a number of critical load cases will be selected and subjected to a sensitivity study to account for modified RAOs due to the vessel being out of plane with the offset, current and wave i.e. no longer head seas. The 0.5m/s cross current RAOs will be used (RAOs included in Appendix B). Note that if it is evident by inspection that the out of plane RAOs are less severe than the in line RAOs already provided then this sensitivity analysis will not be carried out.

8.

Out of plane wave and current – a number of critical load cases will be selected and subjected to a sensitivity study to account for the current coming from a different direction to the wave. The near maximum offset will be considered for the wave in line with the offset and the current at 90 degrees and 180 degrees to the wave direction. It will be assumed that the offset direction will be determined by the wave direction and only the current direction will be modified.

9.

Discrete modelling of buoyancy modules – if the MBR in the region of the buoyancy modules (hog bend as per section 3.2) is near the allowable then a number of critical load cases will be selected and subjected to a sensitivity study considering discrete buoyancy modules in the dynamic analysis model.

10.

Zero offset RAO – a number of critical load cases will be subjected to a sensitivity study considering the RAOs provided for the zero offset case.


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Results and Acceptance Criteria Dynamic analysis results are used as an input to the design of various items as follows: Riser structural capacity (maximum tension and curvature). Top end connection interface (tensions). Bend stiffener (tensions and angles). Bend stiffener connectors (shear forces and bending moments) Flexible flowline interface (tensions). Shear forces and bending moments are calculated during the in-place tie-in connection analysis (see Section 7.13). Design of hold back clamp (tensions, shear forces and bending moments). Acceptance criteria are imposed by API 17J and are summarised as follows: Allowable bend radius (depending on the appropriate safety factor for each condition) is not compromised at any location along the riser. Allowable Compression in the riser is not compromised (see section 7.8.2). Allowable tension and pressure loading (depending on the appropriate safety factor for each condition) in the riser is not compromised.

7.11

Interference Analysis The following interferences will be checked during the riser interference analysis using a number of load cases appropriately selected from the dynamic analysis load case matrix included in Appendix D. Note that each riser and umbilical will be considered with adjacent risers and / or umbilicals on both sides. Riser / riser Riser / umbilical Riser / keel Riser or umbilical / riser column (including central shaft) Riser / mooring lines Riser or umbilical sag bend / seabed If possible interference will be eliminated by modifying the configurations. If this is not possible then it will be demonstrated that the risers can sustain the clashing without compromising the technical integrity. If required, some means of external protection will be applied.

7.12

Fatigue Analysis In order to calculate the fatigue life of dynamic flexible risers, it is necessary to perform dynamic analysis to evaluate the variations of both tension and curvature for the fatigue conditions. The results from these dynamic analyses are used to calculate the service life. The fatigue analysis will be carried out under fatigue wave conditions (see Section 5.19). The tension and curvature results from the analysis will be used to evaluate the stresses in the steel layers. If the stresses in the steel layers of the flexible pipe are in the fatigue domain, then SN curves will be used to predict the service life of the risers. The SN curves will be selected according to the material considered and the riser annulus conditions (see Section 7.7).


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The fatigue life of riser ancillary equipment will be at least 200 years (i.e. cumulative damage less than 0.1). 7.12.1

Fatigue Analysis Conditions Fatigue analysis shall be performed for the following conditions for all risers: 1. 2. 3.

Normal operating conditions (dry annulus or diffused water environment) Abnormal or accidental sea water ingress (without oxygen renewal) Abnormal or accidental sea water ingress (with oxygen renewal)

Annulus conditions will be calculated defined in section 7.7. 7.12.2

Fatigue Analysis Locations Fatigue analysis shall determine the adequacy of pressure and tensile wires for the critical fatigue locations as shown below (see section 3.2 for definitions): Bend stiffener Hog bend Sag bend Touch down point In the particular case of the diffused water environment, calculations will be performed to determine the maximum amount of water that can be diffused into the annulus (see section 7.7) and also to determine if condensation will occur. If condensation does occur, then fatigue corrosion calculations will be performed at the sag bend and touchdown locations only. For the bend stiffener and hog bend locations there will be no water present as it will move away from these areas due to the effect of gravity. For the hog bend location the effect of the buoyancy module clamps will be considered as the movement of the armour wires will be restrained in this region.

7.12.3

Fatigue Waves The fatigue scatter diagram extracted from reference /B5/ and included in Appendix C has been condensed into 10 individual wave classes in line with standard procedure for fatigue analysis of flexible risers. 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 method used to condense the data is contained in Appendix M. The scatter diagram gives the probability of occurrence of the significant wave heights and significant period ranges. From this data, the method consists in determining the maximum wave heights and associated period of each wave class. Note that in this case the input is given as Hs and Tz. Tz has been converted to Tp by multiplying by a factor of 1.41 (reference /B5/, Appendix D). Fatigue analysis shall be conducted using the LIFE and SLPM programs (reference /A10/). The input to the fatigue analysis shall be taken from the dynamic analysis of the relevant sea states.

7.12.4

Design Cases NEAR, FAR and TRANSVERSE cases will be analysed and factored according to their proportional occurrence as given in Section 5.19. Riser entry excursions as described in


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Section 5.21 and an intact mooring system shall be used. Wave class distribution shown in Section 5.19 will be used. The risers are assumed to be full of product (FOP) at maximum density and the appropriate product density will be applied to the weight of the pipe. The fatigue analysis will be performed using the ballasted water level and associated RAOs (reference /A18/). The worst case RAOs will be used throughout the analysis whether corresponding to in-line or out-of-plane environmental effects. Based on the results of the riser dynamic analysis, TSEJV will decide which RAOs are to be used (reference /B25/). Fatigue RAOs are included in Appendix B. 7.12.5

Method of Analysis A series of regular wave analyses will be performed using the maximum wave height and associated period for each wave class. Tension and curvature variations will be extracted for each wave class, for each fatigue sensitive location as detailed in section 7.12.2. One or more of these locations may be eliminated from further analysis by inspection if it is evident that they are not critical. For the identified fatigue sensitive locations, the pressure and tensile armour wires fatigue will be studied with reference to the properties of the wire material, using the SLPM and LIFE computer programs (reference /A10/). The internal fluid pressure is the maximum flowing operating pressure from Table 5.2.3. To account for the fact that it is not possible to guarantee no welds in the armour wires at the bend stiffener locations, all fatigue calculations will be performed assuming a reduction in the number of armour wires. It is proposed to consider one armour wire removed from each layer, but this approach may be modified depending on the actual welds obtained during manufacture. This will account for the fact that there may be a weld in this location that has broken (reference /B6/ item 80). Wear is not considered, as all the risers will include anti-wear layers. Results from the fatigue analysis (i.e. tension and curvature variations) will be provided to the EHU supplier for input to their dynamic analysis software.

7.12.6

Acceptance Criteria In accordance with API 17J requirements, for the normal operating conditions (case 1 as per section 7.12.1) the risers shall have a predicted fatigue life of at least 10 times the design service life specified in Section 5.13. For the abnormal or accidental sea water ingress conditions (case 2 and 3 as per section 7.12.1) the fatigue life will be predicted and this value used as input to the Water Ingress Management Plan (reference /A7/).

7.13

In-Place Tie-In Connection Analysis

7.13.1

Design Method The purpose of the in-place tie-in connection analysis is to check the integrity of the flexible pipe in the in place geometry between the seabed and the connection flange at the Manifolds and Drill Centres under the design environmental and operating load conditions. The pull-in loads will be assessed during the flowline installation analysis (reference /A25/).


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The requirement for bend restrictors for each flowline tie-in will be assessed. The riser / flowline and flowline midline connections will not require bend restrictors if they are on the seabed. If the connection is above the seabed then the requirement for bend restrictors will be checked. A regular wave analysis combined with current shall be performed to determine the following for the selected cases: Interface loads. Catenary geometry (eg span length). Pipe curvature. 7.13.2

Design Parameters The following design parameters also considered for the in-place tie-in connection analysis: Tie-in height and declination at the Manifolds and Drill Centres shall be as per Section 6.3 with a tolerance on elevation of the flange. Hydrodynamic coefficients shall be as specified in Section 5.22.2. The bending stiffness in the short term (no creep) and long term creep condition is to be considered. The weight of anodes on the flexible flowlines will be accounted for to calculate the loads at the tie-in flange connection.

7.13.3

Acceptance Criteria The tie-in geometry minimum bend radius shall be compliant with design criteria of API 17J. If however this criteria is not achieved, then mechanical restraint of the bending must be applied (eg use of bend restrictor). Reactions at the tie-in location shall be used to confirm flange ratings and provided as an interface to Manifolds and Drill Centres design contractor.

7.14

End Fitting Design

7.14.1

Design Method Each end fitting is designed to withstand an internal pressure equal to the bursting pressure of the flexible pipe to which it is attached. Materials for the end fitting are chosen with full consideration of the composition and temperature of the product to be transported (reference /A6/). Each end fitting is designed according to Technip field proven design techniques utilising Technip CAD systems and the internal program EFNA2 (reference /A10/). Stress calculations are performed by EFNA2 for the most highly stressed location of the end fitting when subjected to pressure and mechanical loading. The pressure containing components shall be checked against API 17J in terms of permissible utilization factors. End fitting fatigue will not be considered as all end fittings are effectively static with variations in tension only.

7.14.2

Design Parameters Design parameters to be used for the design of the end fittings are as follows:


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Case

Type

Internal Pressure

External Pressure

1

Recurrent Operations

MOP

Zero Note b)

2

Extreme / Abnormal Operations

Design Pressure d)

Zero Note b)

3

Installation (Functional) PostInstallation (Pressure Test) FAT

Ambient


4

5

Offshore Strength Test Pressure Note a) FAT Pressure Note a)

Zero


Loading (Tension, Bending Moment and Shear Force) Maximum reported by dynamic analysis load cases for recurrent operation for risers (reference /A11/) or tie-in analysis for flowlines (reference /A15/) Maximum reported by dynamic analysis load cases for extreme and abnormal operations for risers (reference /A11/) or tie-in analysis for flowlines (reference /A15/) Maximum loads estimated for installation Note c) Maximum reported by dynamic analysis load cases for offshore strength test for risers (reference /A11/) or tie-in analysis for flowlines (reference /A15/) Zero

Table 7.14.2.1 End Fitting Design Cases Notes: a) FAT and offshore test pressures shall be as per Section 5.4 with 5% over pressurisation added. b) Zero external pressure is a conservative assumption. c) The maximum installation tension for each riser will be estimated as follows and compared to actual installation analysis results (reference /A21/) when these are known: Weight of the pipe (full or empty – to be determined during detailed design) in the water column (maximum water depth along flowline route) and an additional 10m length from the water level to the VLS. Multiplication coefficient of 1.2 for estimation of the length in the installation catenary shape. Dynamic Amplification Factor (DAF) of 1.5 to estimate the vessel motions during installation. d) The design pressure is to include the 10% or 16% over pressure as detailed in section 5.3.


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Acceptance Criteria The utilisation factors for the pressure containing components are defined by API 17J according to the type of operation. Case

Type

1 2 3 4 5

Recurrent Operations Extreme / Abnormal Operations Installation (Functional) Post-Installation (Pressure Test) FAT

API 17J Allowable Utilisation Factors 0.55 0.85 0.67 0.91 0.91

Table 7.14.3.1 End Fitting Design Cases Allowable Utilisation Factors 7.15

Bend Stiffener Design The riser / riser column interface requires a bend stiffener to avoid over bending of the riser at the bottom of the riser column.

7.15.1

Design Cases The design cases shall be selected in order to cover all of the most critical cases identified in the Riser Dynamic Analysis Report (reference /A11/) and listed in Appendix D.

7.15.2

Method of Analysis The dynamic analysis output graphs of tension versus time and theoretical top angle versus time are compared for each design case by the RCN program. RCN is a post processing module within Deeplines (reference /A10/). RCN provides the combination of tension and angle for the maximum and minimum tension, maximum and minimum angle and the combination of tension and angle which give the maximum and minimum pseudo curvature. The angles provided are relative to the built in angle at the riser entry to the riser column thus taking into account vessel motions. The RCN outputs are then input to the Technip stiffener design program Bending (reference /A10/) which applies the Technip design rules for bend stiffeners (reference /A5/). This takes into account the variation of riser bending stiffness with temperature and the variation in stiffener material modulus due to manufacturing tolerances. Alternatively, in order to reduce the number of load cases to analyse, adequately selected sets of tension and angle that cover all of the RCN outputs could also be used as input to Bending. Output from the bend stiffener design including axial, shear and bending reactions at the back of the bend stiffener are input to the design of the bend stiffener connector. The bend stiffener design for the EHUs will be carried out by the EHU supplier. Loads will be provided by TSEJV for this design.

7.15.3

Acceptance Criteria The allowable bending radius in the pipe is defined by API17J according to the type of operation.


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Dropped Objects Impact Resistance The linear impact resistance of the flexible risers to dropped objects will be determined using Technip internal software PARABAQ (reference /A10/), a customised module of the finite element package ABAQUS. This software allows calculation of stresses induced by a crushing load. This method can be used to determine the maximum energy that the pipe can absorb by unit length. The acceptance criterion used to calculate the maximum allowable impact energy is that the flexible riser shall resist the maximum linear impact energy that will induce a 5% maximum deformation in the vault or provide a stress beyond the allowable. The maximum allowable impact energy will be calculated for each structure design and compared to 2kJ over an area of 100mm x 100mm (reference /B10/ and /B6/ items 70 and 345).

7.17

On-Bottom Stability

7.17.1

Cases for Consideration Three load cases are to be considered: Installation case Operating case (riser column connected) Operating case (riser column disconnected) Additionally, two environmental scenarios are to be considered for the operating load cases: 1. 2.

Cyclonic, including surface wave and associated steady current effects (riser column disconnected) Non-cyclonic, ignoring effect of surface waves and associated currents with cases as shown below: 100 year steady current (from tide and drift - riser column disconnected) 100 year soliton current (riser column connected)

Note that installation conditions are considered to be the 1 year RP wave and current. 7.17.2

Design Method The flowlines will be analysed for on-bottom stability in accordance with the following: The methodology to be used for analysis of the cyclonic environmental scenario (item 1 as per section 7.17.1) is DnV RP E305 (reference /S4/) Simplified Method using Technip in-house software Stabil (reference /A10/). The methodology to be used for analysis of the non-cyclonic environmental scenario (item 2 as per section 7.17.1) is the force balance method in accordance with reference /S5/. 3D stability analysis is to be performed for any flowlines found to be unstable using the force balance methodology described above. This methodology will be submitted for approval prior to use (reference /A13/).


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Linear (Airy) wave theory shall be used with the simplified method in accordance with DnV RP E305 (reference /S4/). As no waves are applicable to the force balance methodology, no wave theory is required for this. 7.17.3

Design Parameters The hydrodynamic coefficients used will be in accordance with DnV RP E305 (reference /S4/) sections 5.3.8 and 5.3.12, with due consideration of the Reynolds Number and other dimensionless parameters. This is applicable for both the simplified and force balance methodologies. For all flowlines except the production and production/test the flowline contents shall be product at minimum density for the 100yr non-cyclonic (including soliton) conditions, and the 100yr cyclonic conditions (operation cases as per section 7.17.1). For the production and production/test flowlines the flowline contents shall be as follows: Product at minimum density for the riser column connected case. When the riser column is disconnected the production and production / test flowlines will be depressurised and the contents will quickly settle out, leaving the density of the inner fluid the same as the gas lift minimum density as given in note a) of section 7.10.3. The flowline contents shall be empty for the 1yr non-cyclonic conditions and 1yr internal wave conditions (installation case as per section 7.17.1). Environmental data shall be as per section 5.14, with the directionality of the current accounted for by applying the component of the current perpendicular to the pipe axis. No marine growth is to be included for on bottom stability analysis (reference /B2/). For cyclonic conditions (item 1 as per section 7.17.1) to be carried out using the simplified method as per DnV RP E305 (reference /S4/), a lateral friction coefficient of 0.7 will be used (reference /B2/). For non-cyclonic conditions (item 2 as per section 7.17.2) to be carried out using the force balance methodology, a lateral friction coefficient as per section 5.15 will be used (reference /B2/). Seabed roughness is as per section 5.15. No self embedment is to be considered. See design data sheet for on bottom stability included in Appendix K.

7.17.4

Acceptance Criteria The minimum submerged weight of the pipe must exceed the maximum required weight for stability calculated using DnV RP E305 (reference /S4/) simplified method or force balance method. Note that DnV RP E305 (reference /S4/) allows lateral pipeline displacements of up to 20m under certain circumstances. Alternatively, if 3D dynamic stability is carried out then the following is to apply (reference /B2/):


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Flowline lateral displacement due to environmental loading is prohibited in the locations where the flowlines cross the exposed escarpment feature. Flowline lateral displacement in other locations (including drill centres and riser / flowline interface) will be considered acceptable pending acceptable loadings and curvatures. Lateral displacement onto MODU anchor exclusion zones is not acceptable.


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APPENDIX A Drawings FPSO East Subsea Facilities Layout Drawing No: SK1580, Rev C FPSO Flexible Flowline & EHU Approach General Arrangement Drawing No: K2000DX002.0001, Rev 3 Anchoring Anchorlegs General Arrangement Drawing No: K 4060 D S 001 0001, Rev C Riser Column Riser Column General Arrangement Drawing No: K 4101 D G 001 0001, Rev C Riser Column “J” Tubes Layout Drawing No: K 4101 D S 007 0001, Rev D RTM Mooring System General Arrangement Drawing No: K 4101 D S 010 0001, Rev A Top of Column General Arrangement Drawing No: SB 81327 DCM97024, Rev C1 Riser Column Compartmental Arrangement Drawing No: SB 81327 DCM97022, Rev C1 Riser Column Central Shaft Structural Details Drawing No: K 4101 D S 003 0001, Rev 1 E-DC1 Flexible Flowline & EHU Approach (Rigid Xmas Tree Tie-in Spools) General Arrangement Drawing No: K2000DX003.0001, Rev 2 E-DC2 Flexible Flowline & EHU Approach (Rigid Xmas Tree Tie-in Spools) General Arrangement Drawing No: K2000DX004.0001, Rev 2 E-DC3 Flexible Flowline & EHU Approach (Rigid Xmas Tree Tie-in Spools) General Arrangement Drawing No: K2000DX006.0001, Rev 2 E-DC4 Flexible Flowline & EHU Approach (Rigid Xmas Tree Tie-in Spools) General Arrangement Drawing No: K2000DX007.0001, Rev 2 Anchoring Anchorlegs Details Sheet 1 Drawing No: K 4060 D S 002 0001, Rev A Anchoring Anchorlegs Details Sheet 2 Drawing No: K 4060 D S 002 0002, Rev 0 Anchoring Anchorlegs Details Sheet 3 Drawing No: K 4060 D S 002 0003, Rev 0 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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APPENDIX B FPSO RAOs Data


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APPENDIX C Fatigue Wave Data


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APPENDIX D Dynamic Analysis Load Case Matrix


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APPENDIX E Description of Dynamic Analysis Load Cases Titles Signification


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The description of the dynamic analysis load cases titles signification is as follows: XX_YYY_www_O Where: 1. XX is the load case number as per the load case matrix included in Appendix D. 2. YYY is the riser being considered: Pd9 for the 9” production risers Pd8 for the 8” production / test riser Gi6 for the 6” gas injection riser Gl6 for the 6” gas lift riser Wi10 for the 10” water injection riser 3. www is the analysis type: nom for nominal load case sen1 for sensitivity study 1 sen2 for sensitivity study 2 etc with the sensitivity numbered as per section 7.10.5. 4. O is an unused parameter at this stage.


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APPENDIX F Pressure Conversion Calculations


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APPENDIX G Gas Injection Back Flow Fluid Composition


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APPENDIX H Sand Erosion Data


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APPENDIX I Location of Forces on Manifold / PLEM Hubs


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APPENDIX J Additional Chemical Injection Details


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APPENDIX K Design Data Sheet for On Bottom Stability


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APPENDIX L Extreme Riser Connected Motion Details


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APPENDIX M Riser Fatigue Analysis Methodology


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APPENDIX N Production Flowrate Details


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APPENDIX O Riser Column Motions During Disconnection


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APPENDIX P Referenced Correspondence


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APPENDIX Q Topside Piping Loads


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APPENDIX R Slugging Data


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Basis of Design

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