dafa

Title: Subsea Pipeline Design Basis

Document No : BD1-00-L-A-0001 Date : 20-May-10 Page : 2 of 67 Rev : D2

TABLE OF CONTENTS 1.

2.

3.

INTRODUCTION INTRODUCTION ........................................................................................ .................................................................................................................................. .......................................... 5

1.1

General Project Description .................................................................................................. .................................................................................................... .. 5

1.2

Objective............................................................................................................................... Objective.................................................................................................................................. ... 6

1.3

System of Units .......................................................................................... ....................................................................................................................... ............................. 6

1.4

Sources of Data.......................................................................................... Data ....................................................................................................................... ............................. 6

1.5

Pipeline System Description.................................................................................................... 6

1.6

Pipeline Battery Limit............................................................................................................... 8

1.7

Scope Exclusion / Limitation ................................................................................................... 8

1.8

Definition of Classes................................................................................................................ 9

1.9

Acronym................................................................................................................................... Acronym................................................................................... ................................................ 9

1.10

References ........................................................................... ............................................................................................................................ ................................................. 10

REGULATIONS, CODES AND STANDARDS STANDA RDS ................................................................................. ................................................................................... 12

2.1

Vietnam Petroleum Regulation Act ....................................................................................... 12

2.2

International Codes and Standards....................................................................................... Standards ....................................................................................... 12

DESIGN DATA AND CRITERIA ...................................................................................... ........................................................................................................ .................. 14

3.1

Design Life............................................................................................................................. 14

3.2

Geodetic Parameters............................................................................................................. Parameters............................................................................................................. 14

3.3

Key Location Coordinates ..................................................................................... ..................................................................................................... ................ 15

3.4

Pipeline Data ............................................................................... ......................................................................................................................... .......................................... 16

3.5

Steel Pipeline Material Data .................................................................................................. 18

3.6

Flexible Pipeline, Subsea Cable and Umbilical Data ............................................................ 18

3.7

Pipeline External Coating Data ............................................................................................. 19

3.8

Pipeline Design Pressures and Temperatures...................................................................... 21

3.9

Pipeline Fluid Density ........................................................................... ............................................................................................................ ................................. 22

3.10

Splash Zone .............................................................................................. .......................................................................................................................... ............................ 22

3.11

Platform Displacement ................................................................................................... .......................................................................................................... ....... 22

3.12

Environmental Data ............................................................................................... ............................................................................................................... ................ 23 3.12.1 Tidal Characteristic………………………………………………………………………...23 3.12.2 Seawater Properties………………………………………………………………………. 23 3.12.3 Wave and Current Data………………………………………………………………… 24 3.12.4 Hydrodynamics Coefficients………………………………………………………………28 3.12.5 Marine Growth……………………………………………………………………………...28

This document is the property of BD POC. Any unauthorised attempt attempt to reproduce it, in any form, is strictly prohibited.



TABLE OF CONTENTS 1.

2.

3.

INTRODUCTION INTRODUCTION ........................................................................................ .................................................................................................................................. .......................................... 5

1.1

General Project Description .................................................................................................. .................................................................................................... .. 5

1.2

Objective............................................................................................................................... Objective.................................................................................................................................. ... 6

1.3

System of Units .......................................................................................... ....................................................................................................................... ............................. 6

1.4

Sources of Data.......................................................................................... Data ....................................................................................................................... ............................. 6

1.5

Pipeline System Description.................................................................................................... 6

1.6

Pipeline Battery Limit............................................................................................................... 8

1.7

Scope Exclusion / Limitation ................................................................................................... 8

1.8

Definition of Classes................................................................................................................ 9

1.9

Acronym................................................................................................................................... Acronym................................................................................... ................................................ 9

1.10

References ........................................................................... ............................................................................................................................ ................................................. 10

REGULATIONS, CODES AND STANDARDS STANDA RDS ................................................................................. ................................................................................... 12

2.1

Vietnam Petroleum Regulation Act ....................................................................................... 12

2.2

International Codes and Standards....................................................................................... Standards ....................................................................................... 12

DESIGN DATA AND CRITERIA ...................................................................................... ........................................................................................................ .................. 14

3.1

Design Life............................................................................................................................. 14

3.2

Geodetic Parameters............................................................................................................. Parameters............................................................................................................. 14

3.3

Key Location Coordinates ..................................................................................... ..................................................................................................... ................ 15

3.4

Pipeline Data ............................................................................... ......................................................................................................................... .......................................... 16

3.5

Steel Pipeline Material Data .................................................................................................. 18

3.6

Flexible Pipeline, Subsea Cable and Umbilical Data ............................................................ 18

3.7

Pipeline External Coating Data ............................................................................................. 19

3.8

Pipeline Design Pressures and Temperatures...................................................................... 21

3.9

Pipeline Fluid Density ........................................................................... ............................................................................................................ ................................. 22

3.10

Splash Zone .............................................................................................. .......................................................................................................................... ............................ 22

3.11

Platform Displacement ................................................................................................... .......................................................................................................... ....... 22

3.12

Environmental Data ............................................................................................... ............................................................................................................... ................ 23 3.12.1 Tidal Characteristic………………………………………………………………………...23 3.12.2 Seawater Properties………………………………………………………………………. 23 3.12.3 Wave and Current Data………………………………………………………………… 24 3.12.4 Hydrodynamics Coefficients………………………………………………………………28 3.12.5 Marine Growth……………………………………………………………………………...28



3.13


Site Survey Data.................................................................................................................... Data.................................................................................................................... 29 3.13.1 WHP-MT1 to WHP-HT1………………………………………………………………….. 29 3.13.2 WHP-HT1 to HT FSO……………………………………………………………… FSO…………………………………………………………………….. …….. 29 3.13.3 WHP-HT1 to NCSP Wye Tie-In…………………………………………………………..30

3.14

Soil Survey Data............................................................................................ Data .................................................................................................................... ........................ 30 3.14.1 WHP-MT1 to WHP-HT1 Pipeline Route…………………………………………………30 3.14.2 WHP-HT1 to FSO Pipeline Route……………………………………………………….. 31 3.14.3 WHP-HT1 to NCSP Wye Tie-In Pipeline Route………………………………………...32 3.14.4 Soil Friction Coefficient…………………………………………………………………… 33

3.15

Corrosion Allowance Philosophy ........................................................................................... 33

3.16

Fluid Classification......................................................................................................... Classification................................................................................................................. ........ 33

3.17

Safety Classes....................................................................................................................... Classes....................................................................................................................... 34

3.18

Design Factors ............................................................................................ ...................................................................................................................... .......................... 34

4.

PIPELINE / CAB LE ROUTE SELECTION ........................................................................................ 35

5.

MATERIAL SELECTION AND PROCUREMENT PROCUREMENT PHILOSOPHY .................................................... 36

6.

WALL WAL L THICKNESS .................................................................................................. ........................................................................................................................... ......................... 39

7.

8.

9.

6.1

Pressure Containment (Bursting) .......................................................................................... 39

6.2

Local Buckling ...................................................................................... ....................................................................................................................... ................................. 39

6.3

Propagation Buckling............................................................................................. Buckling............................................................................................................. ................ 40

BUCKLE BUCK LE ARRESTOR DESIGN................................................... DESIGN......................................................................................................... ...................................................... 41

7.1

External Hydrostatic Pressure............................................................................................... Pressure ............................................................................................... 41

7.2

Propagation Pressure............................................................................................................ 41

7.3

Crossover Pressure..................................................................................... Pressure ............................................................................................................... .......................... 42

COATING SELECTION ........................................................................................... ..................................................................................................................... .......................... 43

8.1

Pipeline / Riser Corrosion Coating ........................................................................................ 43

8.2

Insulation Coating...................................................................................... Coating .................................................................................................................. ............................ 43

8.3

Pipeline / Riser Riser Field Joint Coating ....................................................................................... 44

8.4

Pipeline Field Joint Infill ....................................................................................... ......................................................................................................... .................. 44

8.5

Splash Zone Coating ................................................................................................ ............................................................................................................. ............. 44

ON BOTTOM STAB ILITY ..................................................................................... .................................................................................................................. ............................. 45

9.1

Design Criteria (Lateral Stability)........................................................................................... Stability)........................................................................................... 45

9.2

Hydrodynamic Force Computation ........................................................................................ 45

9.3

Method of Analysis ...................................................................................... ................................................................................................................ .......................... 46



10.

11.

12.

13.

14.

15.


9.3.1

Lateral Stability……………………………………………………………………………. 46

9.3.2

Vertical Stability…………………………………………………………………………….47

PIPELINE EXPANSION ..................................................................................................................... 48

10.1

Pipeline End Expansion......................................................................................................... 48

10.2

Initial Lateral Buckling Assessment....................................................................................... 49

FREE SPAN ASSESSMENT ............................................................................................................. 51

11.1

Dynamic Screening Analysis................................................................................................. 51

11.2

Static Analysis (ULS)............................................................................................................. 52

OFFSHORE CROSSING DESIGN..................................................................................................... 53

12.1

Design Criteria....................................................................................................................... 53

12.2

Design Cases ........................................................................................................................ 53

12.3

Analysis Methodology............................................................................................................ 54

CATHODIC PROTECTION ANALYSIS............................................................................................. 55

13.1

Current Demand Calculation ................................................................................................. 55

13.2

Anodes Mass Calculation ...................................................................................................... 56

RISERS AND TIE-IN SPOOL DESIGN ............................................................................................. 57

14.1

Riser Spans Assessment ...................................................................................................... 57

14.2

Riser Stress Analysis............................................................................................................. 58

14.3

Riser Hanger Flange and Subsea Flange Design................................................................. 59

PIPELINE, FLEXIBLE PIPELINE AND SUBSEA CABL E INSTALLA TION .................................... 60

15.1

Installation Analysis ............................................................................................................... 60

15.2

Strain Based Analysis............................................................................................................ 60

15.3

Flexible Pipeline and Subsea Cable Pull Analysis ................................................................ 62

16.

PIPELINE PIGGING PHILOSOPHY .................................................................................................. 63

17.

HYDROTEST, PRESERVATION AND PRE-COMMISSIONING OF PIPELINES ............................ 64

ATTACHMENT ATTACHMENT 1

PLATFORM DISPLACEMENT

This document is the property of BD POC. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited.


1.

INTRODUCTION

1.1

General Project Descript ion


The Bien Dong 1 (BD1) Project involves offshore development of the Hai Thach and Moc Tinh gas/condensate Fields in Blocks 05.2 and 05.3 approximately 340km south of the coast of Vietnam. The fields lie approximately 20km apart. Field locations and existing facilities are indicated in Figure 1.1. The project includes:

•

A Wellhead platform in Moc Tinh (WHP-MT1)

•

A Wellhead platform in Hai Thach (WHP-HT1)

•

A Production and Quarter Platform in Hai Thach (PQP-HT)

•

A Floating Storage and Offloading (FSO) vessel in Hai Thach

•

An interfield pipeline from the WHP-MT1 to WHP-HT1

•

A gas export pipeline form WHP-HT1 to tie-in to the existing Nam Con Son pipeline (NCSP)

•

A dual flexible condensate pipelines and a flexible fuel gas pipeline from WHP-HT1 to the FSO

•

A Subsea Composite Fiber Optic / Power Cable from WHP-HT1 to the WHP-MT1

•

A Subsea Hydro-Electric Umbilical from PQP-HT to SSIV

The FSO design will be conducted under a separate contract.

FIGURE 1.1 : FIELD LAYOUT



1.2


Objective

The objective of this document is to provide the basic design parameters and basis of design that will be used to perform the Front End Engineering Design (FEED) of the BD1 pipeline systems. Details of the pipeline system involved in the proposed BD1 development can be found in Section 1.5.

1.3

System of Units

The System International of Units (SI units) shall be used in all design, engineering document and drawings. Where standard equipment is supplied with Imperial Units, the Imperial Units shall be shown on the drawings with Metric equivalent in brackets.

1.4

Sources of Data

Unless noted otherwise, all data contained in this document are obtained from references in Section 1.10.

1.5

Pipeline System Descript ion

The pipeline systems for BD1 include:

•

12 inch Well Fluid Pipeline (PL-BD1) from WHP-MT1 to WHP-HT1, approximate length is 19.7km.

•

20 inch Gas Export Pipeline (PL-BD2) from WHP-HT1 to Existing NCSP Wye tie-in, approximate length is 44.3km. One SSIV will be installed approximate 500m from WHP-HT1

•

Umbilical (UMB-BD1) from PQP-HT to SSIV, approximate length is 0.4km

•

Dual 7 inch ID Flexible Condensate Pipelines (PL-BD3 / PL-BD4) from WHP-HT1 to tie-in location of Dynamic Flexible Riser (DFR), approximate length is 2.0km

•

3 inch ID Flexible Fuel Gas Pipeline (PL-BD5) from WHP-HT1 to DFR tie-in, approximate length is 2.0km

•

Subsea Cable (CAB-BD1) from WHP-HT1 to WHP-MT1, approximate length is 19.7km

In the beginning of the project, the following options have been considered for BD1 pipelines:

•

26 inch Nominal OD CS Pipe Option for Gas Export Pipeline (PL-BD2)

•

Dual 8 inch Nominal OD Clad Pipe Option for Flexible Condensate Pipelines (PL-BD3 / PL-BD4)

•

Dual 6 inch Nominal OD CS Pipe Option for Flexible Condensate Pipelines (PL-BD3 / PL-BD4)

•

6 inch Nominal OD CS Pipe Option for Flexible Fuel Gas Pipeline (PL-BD5)




These options are reflected in several FEED reports such as Material Selections, External Coating Selections, Wall Thickness Calculations and On Bottom Stability Report. However, based on design instruction, No. DI-BD1-015 [Ref. 20], flexible pipes have been selected for Condensate and Fuel Gas Pipelines (PL-BD3 / PL-BD4 / PL-BD5) and 20 inch nominal OD has been selected for Gas Export Pipeline (PL-BD2). The wall thickness of rigid pipeline (Well Fluid and Gas Export Pipelines) is determined based on constant ID philosophy. The flexible pipelines, subsea cable and umbilical shall be post trenched and buried with minimum 1m cover depth for stability purposes. The exposed section on seabed shall be protected with uraduct / concrete mattress. The boundary between the buried and exposed section shall be determined by Installation Contractor. The Bien Dong pipelines layout is as illustrated in the figure below.

FIGURE 1.2 : PIPELINE LAYOUT



1.6


Pipeline Battery Limi t

The battery limit for pipeline scope of work is as follows:

•

WHP-MT1 ESDV ESDV bottom flange to WHP-HT1 ESDV bottom flange for Well Fluid Pipeline (PL-BD1)

•

WHP-HT1 ESDV bottom flange to Existing NCSP Wye tie-in for Gas Export Pipeline Pipeline (PL-BD2)

•

End termination connection (hang off assembly) at WHP-HT1 to DFR tie-in for Flexible Condensate Pipelines (PL-BD3 / PL-BD4)

•

End termination connection (hang off assembly) at WHP-HT1 WHP-HT1 to DFR tie-in for Flexible Fuel Gas Pipeline (PL-BD5)

•

End termination connection (hang off assembly) at PQP-HT to SSIV for Umbilical (UMB-BD1)

For the Well Fluid Pipeline (PL-BD1) and Gas Export Pipeline (PL-BD2), the whole pipeline system, from pig trap to pig trap shall be designed to DNV OS F101. Refer Figure 5.1 of Section 5.0 for pipeline design code break for these two pipelines. The flexible pipelines for the Dual Flexible Condensate Pipelines (PL-BD3 / PL-BD4) and Fuel Gas Pipeline (PL-BD5) shall be designed by the flexible pipe manufacturer as per ISO 13628-11 and the topside section from hang off assembly up to and including pig trap shall be designed by piping discipline as per ASME B31.3. The Umbilical (UMB-BD1) for SSIV shall be designed by the manufacturer as per ISO 13628-5, and meet the requirement of project specifications. For the Subsea Cable (CAB-BD1), the scope of work is only for routing design and cable installation study analysis.

1.7 1.7

Scope Exclusion / Limitation

The followings are excluded from the pipeline discipline scope.

•

Riser hanger and riser guide clamps design– by Structural

•

J-Tube and J-Tube clamps design – by Structural

•

Subsea Cable design– By Electrical

•

Dropped Object Study – by Safety

•

Flow Assurance Analysis – by Process

•

Material Selection – by Material

•

Buckle Trigger Analysis and Design – by Others

•

Dynamic Flexible Riser (for flexible pipelines) – by Others



1.8


Definiti on of Classes

Class 2 – The part of the pipeline/riser in the near platform area or in areas with frequent human activity, i.e. the rigid riser section to 500m from the base of platform (including subsea tiein spool) and within 500m from the PLEM / DFR Tiie-In (including subsea tie-in spool). Class 1 – Remaining of the pipeline.

FIGURE 1.3 : CLASS DEMARCATION FIGURE

1.9

Acronym

ASME

American Society of Mechanical Engineers

BDPOC

Bien Dong Petroleum Operating Company

BTS

Buckle Trigger Structure

CA

Corrosion Allowance

CP

Cathodic Protection

CS

Carbon Steel

CRA

Corrosion Resistant Alloy

DNV

Det Norske Veritas

DFR

Dynamic Flexible Riser

ESDV

Emergency Shut Down Valve

FEED

Front End Engineering and Design

FSO-HT

Hai Thach Floating Storage and Offloading Vessel

HAT

Highest Astronomical Tide

ID

Internal Diameter

KP

Kilometre Point

LAT

Lowest Astronomical Tide

LSZ

Lower Splash Zone

MSL

Mean Sea Level



1.10

NCSP

Nam Con Son Pipeline

NEM

North East Monsoon

PQP-HT

Hai Thach Production and Quarters Platform

PLEM

Pipeline End Manifold

SMYS

Specific Minimum Yield Stress

SMTS

Specific Minimum Tensile Stress

SOR

Statement of Requirements

SSIV

Subsea Isolation Valve

SWM

South West Monsoon

TAD

Tender Assisted Drilling

TS

Tropical Storm

USZ

Upper Splash Zone

WHP-HT1

Hai Thach Wellhead Platform

WHP-MT1

Moc Tinh Wellhead Platform

WP

WorleyParsons Ltd


References

1. 5256-1000-AG-0001, Integrated Statement of Requirement (FEED Phase), Bien Dong Petroleum Operating Company, Rev. A7 July 2009 2. 5253-1000-RP-1900, Pipeline Preliminary Design, Rev. A1 Nov. 2006 3. 5256-1000-RG-0003, Metocean Criteria, Nam Con Son Blocks 05.2, 05.3 & 06.1, Southern Vietnam, Oceanmetrix, Rev. 1.0 Jan. 2009 4. 5253-1000-RB-0006, HT-MT Pipeline Route Survey, TL Geohydrographics Pte Ltd, Rev. 1.0 Oct. 2008 5. 5253-1000-RB-0002, HT-NCSP Pipeline Route Survey, TL Geohydrographics Pte Ltd, Rev. 1.0 Oct. 2008 6. 5253-1000-RB-0003, MT Marine Site survey, TL Geohydrographics Pte Ltd, Rev. 1.0 Oct. 2008 7. 5253-1000-RB-0004, HT Marine Site Survey, TL Geohydrographics Pte Ltd, Rev. 1.0 Oct. 2008 8. 5253-1000-RB-1012, Flowline-Pipeline Final Factual Report, Fugro Singapore, Rev. 2 Feb. 2009 9. In-Service Buckling of Heated Pipelines, Roger E Hobbs 10. BD1-00-S-A-0001, Structural Design Basis, Rev. B1 Aug. 2009 11. BD1-00-R-T-0021, Condensate Pipeline Flow Assurance 12. BD1-00-R-T-0022, Gas Export Pipeline Flow Assurance 13. BD1-00-R-T-0024, Moc Tinh Pipeline Flow Assurance




14. BD1-00-R-T-0025, WHP-HT1 Fuel Gas Pipeline to FSO Flow Assurance 15. Roark’s Formulas for Stress & Strain 7th Edition, Warren C Young 16. Carl G.Langner, “Buckle Arrestors for Deepwater Pipelines” OTC 10711, Offshore Technology Conference 1999 17. BD1-00-G-N-L-R-0004, Subsea Pipeline Material Selection Report 18. BR02050/SAFEBUCK/B, Safe Design of Pipelines with Lateral Buckling Design Guidelines, Aug. 2004 19. DI-BD1-0012, Topsides Piping, Launcher / Receiver – Design to Pipeline Code & Tech Requisitions Allocation 20. DI-BD1-0015, Flexible Pipelines from WHP-HT1-FSO 21. DI-BD1-0003, Pipeline / Piping Code Break and Intelligent Pig Launcher / Receiver 22. 4211281-MOM-PL-006, MOM for Scope Demarcation for Pipeline and Topside Piping 23. PL-BD1-L-A-0001, Lateral Buckling Design Basis



2.


REGULATIONS, CODES AND STANDARDS The submarine pipelines shall be designed primarily to meet the requirements of the Vietnam Petroleum Regulation Act and the latest edition of Offshore Standard DNV OS F101 Submarine Pipeline Systems. However, should DNV OS F101 does not cover any specific criterion; other applicable design codes may be employed. In case of any conflict between applicable codes and standards, the design criteria detailed in this document followed by requirements of client specifications shall govern. The applicable codes and standards for the pipeline/riser design are listed below.

2.1

Vietnam Petroleum Regulation Act

Guidelines on Risk and Emergency Response Management in the Petroleum Activities Oil and Gas Production Regulations Regulations on Environmental Protection Safety Management Regulations in Petroleum Activities

2.2

Internation al Codes and Standards

Det Norske Veritas (DNV) DNV OS F101 Submarine Pipeline Systems, 2007 DNV OS F201 Offshore Standard for Dynamic Risers, 2001 DNV RP F105 Free Spanning Pipelines, 2006 DNV RP E305 On-Bottom Stability of Submarine Pipelines, 1988 DNV RP F103 Cathodic Protection of Pipeline Submarine Pipelines By Galvanic Anodes, 2003 DNV RP F106 Factory Applied External Pipeline Coatings for Corrosion Control, 2003 DNV RP F107 Risk Assessment of Pipeline Protection, 2001 DNV RP F110 Global Buckling of Submarine Pipelines, 2007

American Petroleum Institute API 5LD

Specification for CRA Clad or Lined Steel Pipe, 2009

API 17J / ISO 13628-2 Specification for Unbonded Flexible Pipe, 2009 API 17B / ISO 13628-11 Recommended Practice for Flexible Pipe, 2008




American Society of Mechanical Engineers (ASME) ASME B16.5

Pipe Flanges and Flanged Fittings, 2003

ASME B16.20 Metallic Gaskets for Pipe Flanges, 1998 ASME B16.47 Large Diameter Steel Flanges, 2006 ASME VIII Div.1 Rules for Construction of Pressure Vessel, 2008

American Society for Testing Materials (ASTM) ASTM A193

Standard Specification for Alloy Steel and Stainless Steel Bolting Materials for High Temperature and High Pressure Service

ASTM A194

Standard Specification for Carbon and Alloy Steel Nuts for Bolts for High Pressure or High Temperature Service, or Both

ASTM A694

Specification for Carbon and Alloy Steel Forgings for Pipe Flanges, Fittings, Valves and Parts for High Pressure Transmission Service, 2000

International Organization for Standardization (ISO) ISO 3183

Petroleum and Natural Gas Industries – Steel Pipe for Pipeline Transportation Systems, 2007

ISO 14723

Petroleum and Natural Gas Industries – Pipeline Transportation Systems – Subsea pipeline valves, 2002

ISO 15589-2

Petroleum and Natural Gas Industries Cathodic Protection Transportation Systems — Part 2: Offshore pipelines, 2004

ISO 15590-1

Petroleum and Natural Gas Industries – Induction Bends, Fittings and Flanges for Pipeline Transportation Systems – Part 1: Induction Bends, 2001

ISO 15590-2

Petroleum and Natural Gas Industries – Induction Bends, Fittings and Flanges for Pipeline Transportation Systems – Part 1: Fittings, 2003

ISO 15590-3

Petroleum and Natural Gas Industries – Induction Bends, Fittings and Flanges for Pipeline Transportation Systems – Part 3: Flanges, 2004

ISO 13628-5

Subsea Umbilicals

ISO 13628-8

Remotely Operated Vehicle (ROV) interfaces on subsea production systems


of

Pipeline


3.


DESIGN DATA AND CRITERIA The design data is extracted from the Project Statement of Requirement (SOR) [Ref. 1] unless stated otherwise.

3.1

Design Life

The pipeline system and associated facilities shall be designed for a 25 years design life.

3.2

Geodetic Parameters

The following geodetic parameters were based on the survey report. All positions quoted in reports and charts related to the survey information refer to the WGS72BE DMA spheroid and datum. Local Datum

Geodetic Datum

:

Spheroid

WGS 72 BE DMA WGS 72

Semi-major axis

:

6 378 135.00 meters

Semi-minor axis

:

6 356 750.53 meters

Inverse flattening (1/f)

:

298.2600

Eccentricity Squared (e2)

:

0.00660431778

Positioning Systems

:

Veripos Ultra PPB

Transformation method

:

Transverse Mercator

Projection Zone

:

UTM Zone 49 North

Latitude of natural origin

:

0° N

Central Meridian

:

111° E

Scale Factor at natural origin

:

0.9996

False Easting

:

500 000 metres

False Northing

:

0 metres

Unit of Measure

:

International Metres

Projection Transformation Parameters

Co-ordinate system transformation parameters from WGS 84 to WGS 72 BE DMA to be used are (position vector rotation convention):

dX = 0.00m

dY = 0.00m

dZ = -1.90m

rX = 0.000” Scale = 0.38ppm

rY = 0.000”

rZ = -0.814”



3.3


Key Locati on Coordin ates

The table below presents the key locations coordinates and water depths [Refs. 6 and 7]. TABLE 3.1 : KEY LOCATION Descript ion

Easting (m)

Northi ng (m)

Water Depth (m)

New WHP-MT1

256 520

877 038

115.1

New WHP-HT1

271 615

889 619

132.8

New PQP-HT

271 605

889 756

132.7

New FSO-HT Turret

269 473

890 484

130.4

Existing NCSP Wye Tie-In (POVO PLEM)

230 173

904 364

100.0

Dynamic Flexible Riser Tie-in

269 712

890 388

130.4

SSIV

271 353

890 038

132.8

Notes: 1. Water Depths are referred to CD/LAT.


(1)


3.4

Document No Date Page Rev

: BD1-00-L-A-0001 : 26-Mar-10 : 16 of 67 : D1

Pipeli ne Data

The pipeline design data is as presented in tables below. TABLE 3.2 : PIPELINE DATA Pipelines

Class

Material Grade

(1)

Size

Product

Flange Rating

12 inch (1) (297.3mm ID)

Well Fluid

900#

0.0

Gas

1500#

1.0

CA

(1)

(mm)

Class 1

DNV OS F101 grade 450 + AISI 316L CRA (LSAW) (3)

Class 2

DNV OS F101 grade 450 + Inconel 625 CRA (LSAW) (3)

Class 1

DNV OS F101 grade 450 (HFW)

Class 2

DNV OS F101 grade 450 (LSAW)

20 inch (1) (479.4mm ID)

Flexible Condensate Pipeline (PL-BD3 / PL-BD4)

-

API 17J (Flexible Pipe)

7 inch ID (2)

Condensate

600#

-

Flexible Fuel Gas Pipeline (PLBD5)

-

API 17J (Flexible Pipe)

3 inch ID (2)

Fuel Gas

600#

-

Well Fluid Pipeline (PL-BD1)

Gas Export Pipeline (PL-BD2)

Notes: 1. Data is refers to [Ref. 17]. 2. Data is refers to [Ref. 19]. 3. Topside piping material for CRA Clad pipeline shall be DNV OS F101 Grade 22Cr D (SAW).




: BD1-00-L-A-0001 : 26-Mar-10 : 17 of 67 : D1

TABLE 3.3 : PIPELINE DATA FOR OPTIONAL CASES Product

Flange Rating

26 inch (625.0mm ID)

Gas

1500#

1.0

8 inch (199.1mmID)

Condensate

600#

0.0

DNV OS F101 grade 450 (Seamless)

6 inch (146.3mm ID)

Condensate

600#

6.0


6 inch (149.3mm ID)

Fuel Gas

600#

1.0

(1)

Pipelines

Class

Gas Export Pipeline (PL-BD2) – 26 inch Option

Class 1


Class 2


Class 1


Class 2


Condensate Pipeline (Pl-BD3 / PL-BD4) - Clad Option

Condensate Pipeline (Pl-BD3 / PL-BD4) - CS Option

Class 1

Fuel Gas Pipeline (PL-BD5) CS Option

Class 1

Class 2

Class 2

Material Grade

Size

(1)

Notes: 1. Data is refers to [Ref. 17]. 2. Topside piping material for CRA pipeline shall be DNV OS F101 Grade 22Cr D (SAW).


CA

(1)

(mm)



: BD1-00-L-A-0001 : 26-Mar-10 : 17 of 67 : D1

TABLE 3.3 : PIPELINE DATA FOR OPTIONAL CASES Product

Flange Rating

26 inch (625.0mm ID)

Gas

1500#

1.0

8 inch (199.1mmID)

Condensate

600#

0.0


6 inch (146.3mm ID)

Condensate

600#

6.0


6 inch (149.3mm ID)

Fuel Gas

600#

1.0

(1)

Pipelines

Class

Gas Export Pipeline (PL-BD2) – 26 inch Option

Class 1


Class 2


Class 1


Class 2


Condensate Pipeline (Pl-BD3 / PL-BD4) - Clad Option

Condensate Pipeline (Pl-BD3 / PL-BD4) - CS Option

Class 1

Fuel Gas Pipeline (PL-BD5) CS Option

Class 1

Material Grade

Class 2

Class 2

Size

(1)

CA

(1)

(mm)

Notes: 1. Data is refers to [Ref. 17]. 2. Topside piping material for CRA pipeline shall be DNV OS F101 Grade 22Cr D (SAW).



3.5


Steel Pipeli ne Material Data

Pipeline material properties are presented below. TABLE 3.4 : PIPELINE MATERIAL PROPERTIES Parameters

DNV F101 Grade 450

Density (kg/m3)

AISI 316 L

(1)

Inconel 625

(1)

DNV OS F101 Grade 22Cr D (2)

7850

8027

8440

8027

0.3

0.3

0.3

0.3

11.7 x 10-6

16.5 x 10-6

12.8 x 10-6

12.5 x 10-6

SMYS at 20°C (MPa)

450

170

275

450

SMYS at 100°C (MPa)

420

145

253

360


408

136

246

330

Elastic Modulus at 20°C

2.07 x 105

1.95 x 105

2.10 x 105

2.02 x 105


2.05 x 105

N/A

N/A

1.96 x 105


2.02 x 105

N/A

N/A

1.92 x 105

Poisson Ratio Thermal Expansion Coefficient (/°C) (3)

Note: 1. Data is based

input from JSW.


3.5


Steel Pipeli ne Material Data

Pipeline material properties are presented below. TABLE 3.4 : PIPELINE MATERIAL PROPERTIES Parameters

Density (kg/m3)

DNV F101 Grade 450

AISI 316 L

(1)

Inconel 625

(1)

DNV OS F101 Grade 22Cr D (2)

7850

8027

8440

8027

0.3

0.3

0.3

0.3

11.7 x 10-6

16.5 x 10-6

12.8 x 10-6

12.5 x 10-6

SMYS at 20°C (MPa)

450

170

275

450


420

145

253

360


408

136

246

330


2.07 x 105

1.95 x 105

2.10 x 105

2.02 x 105


2.05 x 105

N/A

N/A

1.96 x 105


2.02 x 105

N/A

N/A

1.92 x 105

Poisson Ratio Thermal Expansion Coefficient (/°C) (3)

Note: 1. Data is based on input from JSW. 2. Data is referred to [Ref. 18]. 3. Derated Thermal Expansion Coefficient can be calculated using equation α = α (at 0°C) + 0.008 x 10-6 θ for carbon steel and α = α (at 0°C) + 0.005 x 10-6 θ for 22 Cr D.

For subsea flanges for the 12 inch Well Fluid Pipeline (PL-BD1), similar to the Class 2 pipeline section and bends, flanges with internally weld overlay of Inconel 625 have been proposed. This is due to the expected prolonged exposure to seawater during installation period.

3.6

Flexible Pipeline, Subsea Cable and Umbili cal Data

Since no detail is available, the Flexible Pipeline, Subsea Cable and Umbilical Material Properties will be updated and presented in detailed design stage based on manufacturer data.



3.7


Pipeline External Coating Data

The pipeline will be protected from external corrosion primarily by means of an externally applied coating supplemented with a Cathodic Protection (CP) System. Properties of insulation coating also included in below table. Due consideration shall be given to a proper coating material based on the operational and environmental aspect. Properties of typical pipeline coating materials and external coating for various pipeline systems are listed in tables below. TABLE 3.5 : TYPICAL PIPELINE COATING PROPERTIES Coating Type

Density 3 (kg/m )

Specific Heat Capacity (J/kgK)

Thermal Conductivity (W/m2K)

50mm Multi Layer Polypropylene (MLPP)

763

2075

0.18

70mm Multi Layer Polypropylene (MLPP)

753

2065

0.18

Asphalt Enamel (AE)

1280

1255

0.69

Fusion Bonded Epoxy (FBE)

1400

1170

0.30

3 Layer Polypropylene (3LPP)

1008

1250

0.25

Syntactic Polyurethane (SPU)

900

2095

0.12

Polyurethane (PU) Foam

160

1700

0.17

Concrete (Dry)

3040

1260

2.10

Marine Mastic

1440

2095

0.24

TABLE 3.5A : PROPOSED EXTERNAL COATING FOR WELL FLUID PIPELINE (PL-BD1) External An ti Corrosion Coating

Section

Insulation Coating

-

5 mm Monel (Metalurgical Bonded)

-

WHP-MT1

Inclusive

50mm MLPP

WHP-HT1

0.4 mm FBE

46mm SPU

KP 0.0 – 6.5

Inclusive

50mm MLPP

KP 6.5 – 19.7

0.4 mm FBE

46mm SPU

Subsea Bend

-

3mm 3LPP

46mm SPU

Field joint coating

-

Heat Shrink Sleeves

46mm Half Shell SPU

Splash Zone Riser Submerged Riser and Tie-In Spool Pipeline

(1)

Note: 1. The final thickness for the insulation coating shall be reconfirmed by the coating contractor based on the required U value.




TABLE 3.5B : PROPOSED EXTERNAL COATING FOR WELL FLUID PIPELINE (PL-BD1) FOR OPTIONAL CASE External An ti Corrosion Coating

Section

Insulation Coating

-

5 mm Monel (Metalurgical Bonded)

-

Submerged Riser and Tie-In Spool

WHP- MT1 & WHP-HT1

Inclusive

70mm MLPP

Pipeline

KP 0.0 – 19.7

Inclusive

70mm MLPP

Subsea Bend

-

3mm 3LPP

-

Field joint coating

-

Heat Shrink Sleeves

PU Foam

Splash Zone Riser

(1)


TABLE 3.5C : PROPOSED EXTERNAL COATING FOR GAS EXPORT PIPELINE (PL-BD2) Section

External An ti Corrosion Coating

In-fill J oint Coating

Splash Zone Riser

-

12.7mm Neoprene

-


-

3mm 3LPP

-

KP 0.0 – 0.5

3mm 3LPP

-

KP 0.5 – 44.3

5mm AE

-

Subsea Bend

-

3mm 3LPP

-

Field joint coating

-

Heat Shrink Sleeves

PU Foam

Pipeline

TABLE 3.5D : PROPOSED EXTERNAL COATING FOR CONDENSATE PIPELINE (PL-BD3 / PLBD4) FOR OPTIONAL CASE External An ti Corrosion Coating

Section

Insulation Coating

Splash Zone Riser

-

12.7mm Neoprene

-


-

0.4mm FBE

56mm SPU

KP 0.0 – 2.0

0.4mm FBE

56mm SPU

Subsea Bend

-

3mm 3LPP

56mm SPU

Field joint coating

-

Heat Shrink Sleeves

56mm Half Shell SPU

Pipeline

(1)





TABLE 3.5E : PROPOSED EXTERNAL COATING FOR FUEL GAS PIPELINE (PL-BD5) FOR OPTIONAL CASE Section

In-fill J oint Coating

Splash Zone Riser

-

12.7mm Neoprene

-


-

3mm 3LPP

-

KP 0.0 – 2.0

3mm 3LPP

-

Subsea Bend

-

3mm 3LPP

-

Field joint coating

-

Heat Shrink Sleeves

PU Foam

Pipeline

3.8

External An ti Corrosion Coating

Pipeline Design Pressures and Temperatures

Tabulated below are the design temperatures and pressures for pipeline systems.

TABLE 3.6 : DESIGN PRESSURES AND TEMPERATURES Design Pressure (Bar)

System Test Pressure (2) (Bar)

Maximum Design Inlet Temperature ( C)

Minimum Design Temperature (°C)

137.0 (1)

158.3

130.0

-5.0


160.0

184.8

70.0

0.0


93.0 (1)

107.4

80.0

0.0

Flexible Fuel Gas Pipeline (PL-BD5)

93.0 (1)

107.4

70.0

0.0

Pipelines


Notes: 1. Design Pressure is based on the maximum pressure for 900# rating for Well Fluid Pipeline and 600# rating for Condensate Pipeline and Fuel Gas Pipeline at the respective design te mperature. 2. With an incidental pressure of 10% above design pressure, the above gives a system test pressure of approximately 1.155 times the local design pressure at the highest point of the pipeline system part tested (DNV OS F101).



3.9


Pipeline Fluid Density

The fluid density is as presented in table below. TABLE 3.7 : FLUID DENSITY Pipelines

3.10

Fluid Density (kg/m3) Minimum

Maximum


37.54

96.75


64.36

181.35


777.4

780.3

Flexible Fuel Gas Pipeline (PL-BD5)

8.74

10.71

Splash Zone

Splash Zone Lower Limit (LSZ) according to DNV OS F101 is determined by: LSZ

= |L1| - |L2| - |L3|

Where, L1

= lowest astronomic tide level (LAT)

L2

= 30% of the Splash zone wave-related height

L3

= upward motion of the riser

Splash Zone Upper Limit (USZ) according to DNV OS F101 is determined by: USZ

= |U1| + |U2| + |U3|

Where, U1

= highest astronomic tide level (HAT)

U2

= 70% of the splash zone wave-related height

U3

= settlement or downward motion of the riser if applicable

Where zone wave related height is 0.46 x significant wave height (Hs) at 100 year return period. Result from above equation or bottom of hanger clamp will be applied for Splash Zone Upper Limit. However, as minimum, a one joint pipe length (12m) will be coated with splash zone coating.

3.11

Platform Displacement

Platform displacement data for WHP-MT1 and WHP-HT1 are presented in Attachment 1.



3.12


Environ mental Data

The environmental data is extracted from the Metocean Criteria Report [Ref. 3] unless stated otherwise.

3.12.1 Tidal Characteristic The tidal characteristic is presented in table below. TABLE 3.8 : TIDAL CHARACTERISTIC Parameter

Value (m)

Highest Astronomical Tide (HAT)

2.14

Mean Sea Level (MSL)

1.20

Lowest Astronomical Tide (LAT) / Chart Datum (CD)

0.00

Storm Surge (1-Year)

0.04

Storm Surge (100-Year)

0.16

Note: 1. Data is referred from Structural Design Basis [Ref. 10].

3.12.2 Seawater Properties The seawater temperatures with respect to water depth are presented in the table below. TABLE 3.9 : SEAWATER TEMPERATURE WITH DEPTH o

o

Water Depth (m)

Maxim um ( C)

Minimum ( C)

0

32.90

22.35

10

31.50

24.00

20

31.50

23.00

30

31.30

22.17

40

31.10

21.70

50

30.00

20.61

60

29.60

19.39

70

29.12

18.30

80

28.40

18.39

90

28.28

17.00

100

27.95

15.30

120

29.39

16.72

150

26.78

11.60

The seawater density is 1025 kg/m3 and the seawater kinematic density is 1.65 x 10-6 m2/s [Ref. 10].




3.12.3 Wave and Current Data Extreme weather in this region is associated with Tropical Storms (TS), Northeast Monsoon surges (NEM) and Southwest Monsoon surges (SWM). Therefore, the design criteria are presented for the three different types of local extreme weather. The details criteria can be referred to Metocean Criteria Report [Ref. 3].

The waves and currents data at WHP-MT1 is as presented in table below. TABL E 3.10 : WAVE AND CURRENT DATA AT WHP-MT1 LOCATION Tropical Storm 1 yr

North East

South West

10 yr

100 yr

1 yr

10 yr

100 yr

1 yr

10 yr

100 yr

Waves and Associated Current Data

Maximum Wave Height, Hm (m)

7.8

11.5

14.4

9.7

12.7

15.4

5.8

7.2

8.3

Maximum Wave Period, Tm (sec)

10.1

12.6

14.2

10.9

12.5

13.7

8.3

9.3

9.8

Significant Wave Height, H s (m)

3.6

5.8

7.6

4.8

6.4

7.8

2.9

3.5

4.0

Peak Period, Tp (sec)

10.0

12.5

14.1

10.9

12.5

13.7

8.2

9.1

9.7

3 m depth, (m/s)

0.97

1.41

1.76

0.81

0.96

1.09

0.52

0.56

0.58

30 m depth, (m/s)

0.84

1.23

1.53

0.69

0.82

0.93

0.32

0.34

0.36

50 m depth, (m/s)

0.76

1.11

1.38

0.66

0.79

0.89

0.31

0.33

0.35

3 m above seabed, (m/s)

0.59

0.83

1.05

0.54

0.63

0.73

0.30

0.33

0.35

1 m above sea bed, (m/s) (1)

0.50

0.71

0.90

0.46

0.54

0.62

0.26

0.28

0.30

Current and As soc iated Wave Data

3 m depth, (m/s)

1.48

2.12

2.32

1.44

2.12

2.49

0.97

1.41

1.70

30 m depth, (m/s)

1.29

1.84

2.02

1.23

1.81

2.13

0.59

0.86

1.04

50 m depth, (m/s)

1.16

1.66

1.82

1.18

1.73

2.04

0.58

0.85

1.02


0.88

1.27

1.39

0.95

1.40

1.64

0.56

0.83

0.99


0.75

1.09

1.19

0.81

1.20

1.40

0.48

0.71

0.85

Assoc. Sig. Wave Height, Hs (m)

2.7

3.7

4.1

2.5

3.0

3.3

1.3

1.2

1.1

Notes: th 1. Current velocity were calculated by 1/7 Power law at 3m depth. 2. Current calculation for in between depths to be carried out by linear interpolation.




The waves and currents data at WHP-HT1 is as presented in table below. TABLE 3.11 : WA VE AND CURRENT DATA FOR PIPELINE AT WHP-HT1 LOCATION Tropical Storm

North East

South West

10 yr

100 yr

1 yr

10 yr

100 yr

1 yr

10 yr

100 yr

1 yr Waves and Associated Current Data


7.8

11.5

14.4

9.7

12.7

15.4

5.8

7.2

8.3


10.1

12.6

14.2

10.9

12.5

13.7

8.3

9.3

9.8


3.6

5.8

7.6

4.8

6.4

7.8

2.9

3.5

4.0


10.0

12.5

14.1

10.9

12.5

13.7

8.2

9.1

9.7

3 m depth, (m/s)

0.97

1.41

1.76

0.81

0.96

1.09

0.52

0.56

0.58

30 m depth, (m/s)

0.84

1.23

1.53

0.69

0.82

0.93

0.32

0.34

0.36

50 m depth, (m/s)

0.76

1.11

1.38

0.66

0.79

0.89

0.31

0.33

0.35


0.51

0.73

0.92

0.49

0.49

0.66

0.27

0.27

0.32


0.44

0.62

0.79

0.42

0.42

0.56

0.23

0.23

0.27


3 m depth, (m/s)

1.48

2.12

2.32

1.44

2.12

2.49

0.97

1.41

1.70

30 m depth, (m/s)

1.29

1.84

2.02

1.23

1.81

2.13

0.59

0.86

1.04

50 m depth, (m/s)

1.16

1.66

1.82

1.18

1.73

2.04

0.58

0.85

1.02


0.77

1.11

1.22

0.86

1.27

1.49

0.51

0.75

0.90


0.66

0.95

1.04

0.74

1.09

1.27

0.44

0.64

0.77


2.7

3.7

4.1

2.5

3.0

3.3

1.3

1.2

1.1





The waves and currents data at FSO-HT is as presented in table below. TABLE 3.12 : WAVE AND CURRENT DATA FOR PIPELINE AT FSO-HT LOCATION Tropical Storm

North East

South West

10 yr

100 yr

1 yr

10 yr

100 yr

1 yr

10 yr

100 yr



7.8

11.5

14.4

9.7

12.7

15.4

5.8

7.2

8.3


10.1

12.6

14.2

10.9

12.5

13.7

8.3

9.3

9.8


3.6

5.8

7.6

4.8

6.4

7.8

2.9

3.5

4.0


10.0

12.5

14.1

10.9

12.5

13.7

8.2

9.1

9.7

3 m depth, (m/s)

0.97

1.41

1.76

0.81

0.96

1.09

0.52

0.56

0.58

30 m depth, (m/s)

0.84

1.23

1.53

0.69

0.82

0.93

0.32

0.34

0.36

50 m depth, (m/s)

0.76

1.11

1.38

0.66

0.79

0.89

0.31

0.33

0.35


0.52

0.74

0.94

0.50

0.58

0.67

0.27

0.28

0.32


0.44

0.63

0.80

0.43

0.50

0.57

0.23

0.24

0.27


3 m depth, (m/s)

1.48

2.12

2.32

1.44

2.12

2.49

0.97

1.41

1.70

30 m depth, (m/s)

1.29

1.84

2.02

1.23

1.81

2.13

0.59

0.86

1.04

50 m depth, (m/s)

1.16

1.66

1.82

1.18

1.73

2.04

0.58

0.85

1.02


0.79

1.13

1.24

0.87

1.28

1.51

0.52

0.76

0.91


0.68

0.97

1.06

0.74

1.09

1.29

0.44

0.62

0.78


2.7

3.7

4.1

2.5

3.0

3.3

1.3

1.2

1.1





The waves and currents data at NCSP Wye is as presented in table below. TABLE 3.13 : WAVE AND CURRENT DATA FOR PIPELINE AT NCSP WYE LOCATION Tropical Storm

North East

South West

10 yr

100 yr

1 yr

10 yr

100 yr

1 yr

10 yr

100 yr



7.8

11.5

14.4

9.7

12.7

15.4

5.8

7.2

8.3


10.1

12.6

14.2

10.9

12.5

13.7

8.3

9.3

9.8


3.6

5.8

7.6

4.8

6.4

7.8

2.9

3.5

4.0


10.0

12.5

14.1

10.9

12.5

13.7

8.2

9.1

9.7

3 m depth, (m/s)

0.97

1.41

1.76

0.81

0.96

1.09

0.52

0.56

0.58

30 m depth, (m/s)

0.84

1.23

1.53

0.69

0.82

0.93

0.32

0.34

0.36

50 m depth, (m/s)

0.76

1.11

1.38

0.66

0.79

0.89

0.31

0.33

0.35


0.52

0.83

1.03

0.52

0.71

0.73

0.26

0.30

0.32


0.44

0.71

0.88

0.44

0.60

0.62

0.22

0.26

0.27


3 m depth, (m/s)

1.48

2.12

2.32

1.44

2.12

2.49

0.97

1.41

1.70

30 m depth, (m/s)

1.29

1.84

2.02

1.23

1.81

2.13

0.59

0.86

1.04

50 m depth, (m/s)

1.16

1.66

1.82

1.18

1.73

2.04

0.58

0.85

1.02


0.87

1.24

1.36

0.94

1.37

1.62

0.49

0.76

0.91


0.74

1.06

1.16

0.80

1.17

1.38

0.42

0.65

0.78


2.7

3.7

4.1

2.5

3.0

3.3

1.3

1.2

1.1





3.12.4 Hydrodynamics Coefficients The hydrodynamic force coefficients presented below are for use in the calculation of quasi-static forces on pipelines resulting from fluid motion. TABLE 3.14 : HYDRODYNAMIC COEFFICIENTS Coeffic ient

For Pipeline Section

For Riser Secti on

For BTS Secti on

Drag, Cd

0.7 or 1.2 (2)

0.7 (no marine growth) 1.0 (with marine growth)

0.7 or 1.2 (2)

Lift, CL

0.9

0.0

0.9

Inertia, CI

3.29

2.0

3.29

(3)

Notes: 1. Data has been extracted from DNV RP E305. 2. For sub-critical and critical flow regime Re < 3 x 105 and M ≥ 0.8, realistic CD value should be calculated. (Where M = current velocity / wave velocity = Uc / Us). 3. Hydrodynamic Coefficient for pipeline at BTS has been assumed to be the same as pipeline on seabed. The data will be revisited based on the lateral buckling work which will be performed by others.

3.12.5 Marine Growth The marine growth is presented below. TABLE 3.15 : MARINE GROWTH PROFILE From EL (LAT) (m)

To EL (LAT) (m)

Thick ness (mm)

MSL

-5

50

-5

-30

200

-30

-50

125

-50

-75

50

-75

Mudline

25

Notes: 1. Density of marine growth is 1400 kg/m3. 2. Data is referred to Structural Design Basis [Ref. 10].



3.13


Site Survey Data

Site investigations were carried out following the shallow geophysical surveys in Q2 and Q3 2008. The shallow geophysical surveys were completed in Q3 2008 and comprised analogue surveys and high resolution (HR) and ultra high resolution (UHR) surveys. The four survey reports [Refs. 4 to 7] cover the platform sites and pipeline routes.

3.13.1 WHP-MT1 to WHP-HT1 The length of the pipeline between the WHP-MT1 and WHP-HT1 is approximately 20km. The routing of this pipeline will be based upon the results of the geophysical survey [Ref. 4] which included bathymetry, side scan survey and sub bottom profiling. The water depths along the surveyed Well Fluid route from WHP-MT1 to WHP-HT1 range from 115.3m to 133.4m. The seabed is generally dipping Eastwards with an average seabed gradient that does not exceed 1:800 (0.07º), except for the seabed mound at KP 18.130 to KP 18.640 where the side slope has a maximum gradient of 1:160 (0.4º) with an induced water depth change of 1.6m. Apart from this feature, no bathymetric anomalies are noted along the surveyed pipeline route. The main seabed features noted within the survey area are sonar contacts and a combination of sand ripples and mega ripples. The sand ripples and mega ripples have heights that are less than 1m and are observed over 95% to 98% of the surveyed pipeline route. The closest sonar contact to the surveyed route is noted 101m South-East of KP 12.085. The surveyed route is clear of any features that may impede pipeline installation activities. However, scouring may occur along the surveyed route due to the nature of the mobile sediments, which may lead to occurrences of free span later on. The seabed sediments are expected to comprise of fine to medium sand which is expected to provide fair pipeline settling conditions, and poor to moderate anchor holding capabilities. The sonar contacts should also be considered during anchor planning and handling.

3.13.2 WHP-HT1 to HT FSO The FSO will be located approximate 2.4 km from the Hai Thach wellhead platform. The routing of this pipeline will be based upon the results of the geophysical survey [Refs. 6 and 7] which included bathymetry, side scan survey and sub bottom profiling. The water depths along the surveyed condensate line route from WHP-HT1 to HT FSO range from 129m to 133m. The seabed within the survey area is undulating and generally dipping towards the ESE with a general gradient of 1:540 (0.10°). This undulating seabed is due to the presence of the sand wave/mega ripples that are aligned in a NNE – SSW direction. The crests of these features have an average height of less than 0.5m with varying wave lengths between 6.0m and 9.0m.




3.13.3 WHP-HT1 to NCSP Wye Tie-In The approximate length of the pipeline between Hai Thach and the Wye is 44.5 km. The length and routing of the pipeline is based upon the results of the geophysical survey [Ref. 5] which included bathymetry, side scan survey and sub bottom profiling. Water depths within the survey corridor range from 99.2m to 134.6m. The seabed within the surveyed route is generally clear of bathymetric anomalies with the exception of an elongated depression that crosses the route from KP 42.500 to KP 42.890, which results in a maximum side slope of 1:56 (1.0°). Sand ripples and mega ripples are noted throughout the survey corridor, indicating mobile sediments. This may cause scours around the pipeline that may develop into free spans in later stages. The effects of the bottom currents should also be considered during the final pipeline route design. An elongated sonar contact which could be construction debris crosses the surveyed route at KP 44.202. This will have to be investigated prior to construction. The surface sediments are interpreted to consist of fine sand to sand with some gravel and should provide adequate pipeline settling conditions but poor to moderate anchor holding capabilities. The existing NCS pipeline and the Rong Doi pipeline that joins it should also be considered during anchor planning and handling. The gas export line from Hai Thach will have to cross over the NCS pipeline. At this location the NCS pipeline is laid upon the sea bed (not trenched) and it is coated with 50 mm of concrete coating.

3.14

Soil Survey Data

The geotechnical investigations were completed by Fugro Singapore Pte Ltd. The investigation was a mixture of sampling and piezocone penetration testing (PCPT) at the platform sites, the FSO anchor locations, the HT TAD anchor locations and along the pipeline routes. The detail results of the pipeline route geotechnical investigations are provided in the Fugro reports [Ref. 8].

3.14.1 WHP-MT1 to WHP-HT1 Pipeline Route The fieldwork consisted of five boreholes to maximum depth ranging from 2.7 to 3.3 m along the Moc Tinh Platform to Hai Thach Platform surveyed pipeline route. The soil conditions along this route consist predominantly of granular soils from seafloor to the final penetrations explored. The descriptions are presented in table below.




TABLE 3.16 : WHP-MT1 TO WHP-HT1 BORE HOLE COORDINATES Bore Hole Name

Easting (m)

Northi ng (m)

MT-HT.1 / 1a

259 232.23

879 050.36

MT-HT.2 / 2b

262 236.35

881 703.05

MT-HT.3 / 3a

265 898.01

884 632.98

MT-HT.4 / 4a

267 900.60

886 501.16

MT-HT.5 / 5a

270 233.16

888 418.04

TABLE 3.17 : WHP-MT1 TO WHP-HT1 SOIL DESCRIPTION Bore Hol e Name

Penetration (m)

Soil Sample Description

3

Unit Weight (kN/m ) Sub.

Wet

Angle (deg)

MT-HT.1 / 1a

0.0 – 2.8

Medium dense fine SAND with silt

8.0

18.1

34.0

MT-HT.2 / 2b

0.0 – 2.95


7.8

17.3

-

MT-HT.3 / 3a

0.0 – 1.6


8.0

18.1

-

MT-HT.4 / 4a

0.0 – 2.7


8.4

18.5

34.5

MT-HT.5 / 5a

0.0 – 1.5

Medium dense to dense fine SAND

8.4

18.5

-

3.14.2 WHP-HT1 to FSO Pipeline Route The fieldwork consisted of two boreholes to maximum depth of 2.85 and 3.0m located along the surveyed route. The soil conditions along this route consist predominantly of granular soils from seafloor to the final penetrations explored. The descriptions are presented in table below. TABLE 3.18 : WHP-HT1 TO FSO BORE HOLE COORDINATES Bore Hole Name

Easting (m)

Northi ng (m)

HT.FSO.5 / 5a

270 901.04

889 999.04

HT.FSO.6 / 6a

270 198.46

890 240.02




TABLE 3.19 : WHP-HT1 TO FSO SOIL DESCRIPTION Bore Hol e Name

Penetration (m)


3

Unit Weight (kN/m ) Sub.

Wet

Angl e (deg)

HT.FSO.5 / 5a

0.0 – 2.9

Medium dense fine SAND

8.0

18.1

30.0

HT.FSO.6 / 6a

0.0 – 1.6


8.2

18.4

32.0

3.14.3 WHP-HT1 to NCSP Wye Tie-In Pipeline Route The fieldwork consisted of six boreholes to maximum depth ranging from 2.7 to 3.2m located along the Hai Thach Platform to NCSP Wye Tie-In surveyed pipeline route. The soil condition along this route consists predominantly of granular soils from seafloor to the final penetrations explored. The descriptions are presented in table below. TABLE 3.20 : WHP-HT1 TO NCSP WYE TIE-IN BORE HOLE COORDINATES Bore Hole Name

Easting (m)

Northi ng (m)

HT-NCSP.1b /1a

264 350.62

893 500.41

HT-NCSP.2 / 2a

257 519.93

895 698.96

HT-NCSP.3 / 3a

248 143.75

898 700.76

HT-NCSP.4 / 4a

240 048.54

901 302.01

HT-NCSP.5 / 5a

237 545.13

902 114.45

HT-NCSP.6 / 6a

232 001.01

903 998.60

TABLE 3.21: WHP-HT1 TO NCSP WYE TIE-IN SOIL DESCRIPTION Bore Hol e Name

Penetration (m)

HT-NCSP.1b /1a

0.0 – 2.7

HT-NCSP.2 / 2a

0.0 – 1.95

HT-NCSP.3 / 3a

0.0 – 2.5

HT-NCSP.4 / 4a

0.0 – 1.6

HT-NCSP.5 / 5a

0.0 – 3.1

HT-NCSP.6 / 6a

0.0 – 1.0


Medium dense fine SAND with silt Medium dense fine SAND Medium dense fine SAND with silt Medium dense fine SAND Dense to very dense fine SAND Grey SILT

3

Unit Weight (kN/m ) Sub

Wet

Angl e (deg)

8.8

18.9

33.5

8.4

18.6

-

7.6

17.1

36.0

8.4

18.6

-

8.2

18.4

-

10.0

19.8

-




3.14.4 Soil Friction Coefficient The soil friction coefficients used in on bottom stability analysis are as presented below. TABLE 3.22 : SOIL FRICTION COEFFICIENT Description

Value

Pipeline Lateral Stability (1)

0.7

Pipeline Longitudinal Stability (2)

0.6

Notes: 1. As per DNV RP E305. 2. As per Lateral Buckling Design Basis [Ref. 23].

The above soil friction will not be applicable for lateral buckling analysis. The soil friction for lateral buckling analysis will be defined as part of the lateral buckling design.

3.15

Corrosion Allowance Philosophy

The corrosion allowance philosophy used in design analysis is summarised in table below. TABLE 3.23 : CORROSION ALLOWANCE PHILOSOPHY Descript ion

3.16

Corrosion Allowance Utilisations (%)

Weight Based Analysis

50

Stress Based Analysis

100

Fluid Classif icatio n

Fluid to be transported shall be categorised according to their hazard potential as per Section 2, C201 of DNV OS F101). For BDPOC pipeline, the fluid category is described in table below. TABLE 3.24 : CLA SSIFICATION OF FLUID Category

Description

E

Flammable and/or toxic fluids which are gases at ambient temperature and atmospheric pressure conditions and which are conveyed as gases and/or liquids. Typical examples would be hydrogen, natural gas (not otherwise covered under category D), ethane, ethylene, liquefied petroleum gas (such as propane and butane), natural gas liquids, ammonia, and chlorine.



3.17


Safety Classes

The safety class for the pipelines and risers is determined as per Section 2, C402 of DNV OS F101 and detailed below. TABLE 3.25 : CLA SSIFICATION OF SAFETY CLASSES Phase

Operational Installation / Hydrotest

3.18

Location Class (Fluid Category E) Class-1

Class-2

Normal

High

Low

Low

Design Facto rs

The allowable stress design factors for Location class -1 and Location class -2 shall be based on Table 5.14 of DNV OS F101 and are defined in respective sections of analysis. TABLE 3.26 : USAGE FACTORS Safety Class

Usage Facto r (

Low

1.00

Normal

0.90

High

0.80


η )


4.


PIPELINE / CABLE ROUTE SELECTION The proposed pipeline, subsea cable and umbilical route shall be selected based on the findings detailed by the survey reports [Refs. 4 to 7]. The pipelines, subsea cable and umbilical are generally route such that the proposed route will give the shortest possible length and the least number of technical constraints, thereby offering the most economically attractive option. The pipeline route shall be selected with due regard to safety of the public and personnel, protection of the environment, and the probability of damage to the pipe or other facilities [Ref. 8]. Agreement with relevant parties should be sought as early as possible. Factors to take into consideration shall, at minimum, include the following:

•

Environment (archaeology, marine parks, turbidity flows)

•

Seabed characteristics (uneven seabed, unstable seabed, soft sediments, seismic activity)

•

Facilities (offshore installations, subsea structure, existing pipelines and cables)

•

Third party activities (ship traffic, fishing activity, dumping area, mining and military exercise, 3rd party requirements)

•

Pipeline components (e.g. valves, tees) in particular should not be located on the curved route sections of the pipeline.

The pipelines, flexible pipelines and cable were therefore routed to avoid unfavourable seabed areas. Pipeline crossing analysis is needed if the pipeline has to cross existing unburied pipeline. Pipeline ends are to be designed with a reasonable straight length ahead of the target boxes. Curvatures near pipeline ends should be designed with due regard to end terminations, lay method, lay direction and existing / planned infrastructure.



5.


MATERIAL SELECTION AND PROCUREMENT PHILOSOPHY The pipeline material selection philosophy is detailed in the Pipeline Material Selection Report [Ref. 17]. Table below summarises the applicable material codes and specifications used for this project. Table 5.1 : SUBSEA PIPELINE material codes and specifications Design Codes / Standards

Company Specifications

Remarks

CS Line Pipes

DNV OS F101 + ISO 3183

BD-00-L-S-0001 BD-00-L-S-0016

Company Procured Long Lead Item

CRA Clad Line Pipes

DNV OS F101 + API 5LD

BD-00-L-S-0002


Induction Bends

DNV OS F101 + ISO 15590-1

BD-00-L-S-0005


-

BD-00-L-S-0006


DNV RP F106

BD-00-L-S-0007 BD-00-L-S-0015 BD-00-L-S-0018 BD-00-L-S-0021


Concrete Coating

-

BD-00-L-S-0008


SPU Half Shells

-

BD-00-L-S-0009


Sacrificial Anode

ISO 15589-2 + DNV RP F103

BD-00-L-S-0008 BD-00-L-S-0010


Subsea Flanges

DNV OS F101 + ISO 15590-3

BD-00-L-S-0004


Subsea Fittings

DNV OS F101 + ISO 15590-2

BD-00-L-S-0025


Subsea Valves

ISO 14723

BD-00-L-S-0003


SSIV Actuator & HPU

-

BD1-00-L-S-0020


SSIV Umbilical

ISO 13628-5

BD1-00-L-S-0021


ISO API 17J + API RP 17B + DNV OS F201

-


ASTM A193 / ASTM A194

-

To be procured by Fabricator / OIC

ASTM A106 / API 5L PSL2 (for 4” and above)

-

To be procured by Fabricator

Material

Insulation Coating

Corrosion Coating

Flexible Pipelines Bolts, Nuts and Gaskets Tie-in Skid Small size piping




Tie-in Skid Small size flanges and fittings

ASTM A105

-


Concrete Mattress and Uraduct

-

-

To be procured by OIC

D2

TABLE 5.2 : TOPSIDE PIPELINE MATERIAL CODES AND SPECIFICATION Material

Design Codes / Standards

Company Specifications

Remarks

CS Line Pipe

DNV OS F101 + ISO 3183/ ASME B31.3Note 1

BD-00-P-S-0001/ BD-00-L-S-0001


CRA Clad Line Pipe

API 5L C + DNV OS F101

BD-00-P-S-0001/ BD-00-L-S-0002


Solid CRA Pipe

API 5L C + DNV OS F101

BD-00-P-S-0001


ISO15590-1 + DNV OS F101/ ASME B31.3Note 1

BD-00-P-S-0001/ BD-00-L-S-0005


Flanges

ASME B31.3 + ASME B16.5

BD-00-P-S-0001


Fittings


BD-00-P-S-0001


Barred/Sphere Tees


BD-00-P-S-0001


Topside Valves

API 6D

BD-00-P-S-0003/ BD-00-I-S-0006


Hot Induction Bends

Scraper Trap Fabrication

Welding as per DNV OS F101/ ASME B31.3Note 1

-Minor Barrel

ISO 3183 + DNV OS F101/ ASME B31.3Note 1

BD-00-P-S-0001/ BD-00-L-S-0001


-Major Barrel

ISO 3183+DNV OS F101/API 5L/ ASME B31.3Note 1

BD-00-P-S-0001/ BD-00-L-S-0001


ASME Section VIII Div. 1

BD-00-M-S-0341


- Flanges


BD-00-P-S-0001


- Fittings


BD-00-P-S-0001


- QOEC


Note: 1.

D2

ASME B31.3 is the design code for topside piping/bend which will be connected to flexible pipeline.


D2



The figure below gives the scope demarcation for material procurement for the pipeline system. Refer to Design Instruction No. DI-BD1-0012 [Ref. 19], DI-BD1-0015 [Ref. 20] and DI-BD1-0003 [Ref. 21] for details. FIGURE 5.1 : PRECUREMENT SCOPE BREAK



6.


WALL THICKNESS The wall thickness analysis for offshore pipeline and topside pipeline up to scrapper trap will be carried out using a proprietary DNV OS F101 spreadsheet developed by DNV. The details of the analysis are described in the following sections. Constant ID based philosophy is implemented on all Bien Dong pipelines.

6.1

Pressure Containment (Burst ing)

The pressure containment check shall be performed for operating and hydrotest pressure conditions. It shall fulfill the following criteria as stated in section 5 D200 of DNV OS F101:-

Pli

− Pe ≤

Pb (t 1 )

γ sc ⋅ γ m

Where, Pli

=

local incidental pressure

Pe

=

external pressure

Pb

=

pressure containment resistance (yielding limit state & bursting limit state)

t1

=

pipe wall thickness t – tfab (pressure test condition), or = t – tfab – tcorr (operational condition)

6.2

t

=

nominal thickness (required thickness)

tfab

=

fabrication thickness tolerance

tcorr

=

corrosion allowance thickness

γsc

=

safety class resistance factor

γm

=

material resistance factor

Local Bucklin g

Local buckling implies gross deformation of pipe cross section. It could occur during installation phase (new pipe) when the pipeline is empty, or during operating phase when depressurization is required for maintenance or emergency. The pipe wall thickness shall be designed against collapse due to external pressure as required in section 5 D400 of DNV OS F101:-

(Pc − Pel ) Pc 2 − P p 2 = Pc Pel P p f o D / t Where, Pc

=

characteristic collapse pressure

Pel

=

elastic collapse pressure



Pp

=

plastic collapse pressure

t2

=

pipe wall thickness (installation phase)

fo

=

ovality (>0.005)


The external pressure at any point along the pipeline shall meet the following criteria:-

Utility =

Pe (1.1γ mγ sc ) Pc

≤ 1 (Safe against collapse)

Further to this, the minimum required wall thickness of riser section (class 2) for collapse resistance shall be checked against DNV OS F201 section 5 D300 criteria as shown below:-

(Pe − Pmin ) ≤

Pc (t )

γ sc ⋅ γ m

Where,

6.3

Pmin

=

minimum internal pressure of pipe (assumed as 0)

t

=

minimum required wall thickness

Propagation Buckli ng

Section 5 D500 of DNV OS F101 implies that a buckle cannot be initiated within a portion of the pipe where the maximum external pressure, Pe is less than the collapse pressure. If buckle occurs and Pe exceeds Initiation Pressure, Pinit which is subject to size of the initial buckle, propagating buckle will be started and continue whenever the external pressure is higher than Propagating Pressure, P pr , unless the external pressure is lesser than it. The propagating buckle pressure is taken as :-

P pr = 35 f yα fab (t 2 D )

2.5

Utility

=

Peγ mγ sc P pr

≤ 1.0 (Safe against propagating buckling)

Where,

αfab

=

fabrication factor



7.


BUCKLE ARRESTOR DESIGN The buckle arrestor design methodology is in accordance with the recommendations of Langner [Ref. 16]. However, the buckle propagation formula adopted for the buckle arrestor design is as per DNV OS F101 (2007). The pipeline buckle arrestor break points will be determined based on the water depths obtained from wall thickness calculations. The equations used to perform the calculations are summarized below.

7.1

External Hydros tatic Pressure

The external hydrostatic pressure (Pe) is calculated using the formula stated below. P e = hρg

where:

7.2

h

= water depth (m)

ρ

= seawater density (kg/m3)

g

= gravitational acceleration (m/s2)

Propagation Pressure

The buckle propagation pressure, Ppr is defined as :

Ppr

=

f y .α fab ⎛ t 2 ⎞ 2 .5 35 . ⎜ ⎟ γ m .γ SC ⎝ D ⎠

where: f y

= yield strength to be used in the design (MPa)

γm

= material resistance factor (Table 5-4 of DnV 2000)

γSC

= safety class resistance factors (Table 5-5 of DnV 2000)

α fab

= linepipe fabrication factor(Table 5-3 of DnV 2000)

t2

= t - tcorr t

= Nominal wall thickness of pipe

tcorr = Corrosion allowance D

= Nominal Diameter of pipe



7.3


Crosso ver Pressure

The buckle arrestor is designed to the highest pressure at which a propagating collapse failure will be stopped. The propagating collapse failure contained in a given buckle arrestor due to the pressure is called the crossover pressure. The crossover pressure for the integral-ring buckle arrestor (Px) is predicted by using the following formula.

Px - Ppr = (Pa - Ppr ) [1 - exp(-20 tnom L/ Do 2 )]

where: Ppr

=

buckle propagation pressure; minimum external pressure at which the damage of a flattened section of pipe will spread to adjacent undamaged sections (MPa)

Pa

=

buckle propagation pressure of a long buckle arrestor (MPa)

=

f y .α fab ⎛ t b ⎞ ⎜ ⎟ 35 . γ m .γ SC ⎜⎝ D i + 2 t b ⎠⎟

tnom

=

pipeline nominal wall thickness (mm)

Do

=

pipeline outside diameter (mm)

f y

=

yield strength of buckle arrestor material to be used in the design (MPa)

tb

=

wall thickness of buckle arrestor (mm)

Di

=

inside diameter of buckle arrestor (mm)

=

axial length of buckle arrestor (mm )

2.5

Other parameters have previously been described.



8.


COATING SELECTION The primary means of preventing external corrosion for the pipelines and risers will be by the use of anti-corrosion coatings. Anti-corrosion coating materials selected shall suitable for marine environmental conditions and the selection is based on the design temperature of the pipeline. The anti-corrosion coatings for the field joints will consist of a heat shrink sleeve or a self-adhesive tape. The detail recommended pipeline external coatings for individual pipelines are presented in Section 3.8.

8.1

Pipeline / Riser Corros ion Coating

The performance of any particular coating system is directly related to the conditions encountered during the installation and the operational life of the pipeline system. However, the main factors influencing the final coating performance are adhesion, cohesion, flexibility, electrical resistance, moisture absorption, impact resistance, cathodic disbanding resistance, chemical and physical stability, ease of application and weathering resistance. For this project, the following corrosion coatings will be considered for the pipeline corrosion coatings. TABLE 7.1 : MAXIMUM OPERATING TEMPERATURE FOR EXTERNAL COATINGS Coating Material

Maximum Recommended Operating Temperature ( C) ˚

3-Layer Polypropylene (3LPP)

140

Asphalt Enamel (AE)

70

Fusion Bonded Epoxy (FBE) (1)

85

Note: 1. The maximum operating temperature is recommended for stand alone FBE coating. However, maximum temperature recommended for FBE coated together with PE, PP or insulation coating can be higher since the coating is not directly in contact with seawater.

8.2

Insulati on Coating

For the well fluid and condensate lines, insulation coating will be used to keep the fluid temperature above the wax appearance temperature (WAT). The areas of offshore pipelines/risers to be protected can be divided into a few classes as follow:

•

Submarine Pipeline (for unburied or buried pipeline)

•

Riser (for submerged portion)

For this project, the following insulation coatings have been considered:

•

Syntactic Polyurethane (SPU) for temperature up to 115 C

•

Multilayer PP (such as 4LPP) for temperature up to 140 C

˚

˚




Insulation coating type and thickness will be established in consultation with the coating Contractor based on the U value recommended by flow assurance group. Listed below is the U value recommended by flow assurance and the selected insulation coating and thickness for the 12 inch Well Fluid Pipeline. TABLE 8.1 : U VALUE AND INSULATION COATING DATA 2

U Value (W/m K) Note-2

Insulati on Coating

Thickn ess

2.8

Syntactic Polyurethane (SPU)

46mm

4.5

Multi Layer Polypropylene (MLPP)

50mm

3.5

Multi Layer Polypropylene (MLPP)

70mm

(1)

Note: 1. The final insulation thickness shall be determined by the Coating Manufacturer based on U value. 2. U value shall be calculated based on ID of pipeline.

8.3

Pipeline / Riser Field Join t Coating

For field joints, Heat Shrink Sleeve coating will be considered. Selection of suitable grade/type of field joint coating will be based on the pipelines design temperature and the compatibility of the field joint coating material with the corrosion or insulation coating.

8.4

Pipeline Field Joi nt Infil l

Infill material shall be used on joints of pipe that are concrete coated to ensure the outside diameter of the field part is the same as concrete coated. Infill materials should consists of polymer concrete, marine mastic or polyurethane foam. For the insulated pipeline, pre-formed solid half shells of Syntactic Polyurethane or polypropylene foam injection will be used as infill insulating material.

8.5

Splash Zone Coating

For riser splash zone protection, the following guideline will be used in selecting the splash zone coating. 1. Chlorinated Rubber (CR) polychloroprene (also known by the trade name Neoprene)] elastomer coatings for temperature up to 90 C. ˚

2. Ethylene Propylene Diene Monomer (EPDM) elastomer coatings for temperature above 90 C and up to 120 C. ˚

˚

3. Corrosion resistant alloy (CRA) (such as Monel) for temperature above 120 C. ˚



9.


ON BOTTOM STABILITY The static stability analysis is to be performed to determine the adequate concrete weight coating thickness required to provide stability against any lateral movement of the pipeline due to waves and currents as per criteria defined below. The most unfavourable combination of simultaneously acting vertical and horizontal forces on the pipeline shall be considered. Simplified static analysis method as per DNV RP E305 shall be used. Pipeline shall also be checked for vertical stability by determining the pipe sinkage and flotation. Separate stability analysis shall be performed for pipeline on Buckle Trigger Structure (BTS) for the 12 inch Well Fluid Pipeline (PL-BD1). Pipe stability will be achieved by increasing the pipe wall thickness with no concrete weight coating provided to minimise the pipeline stiffness. Pipeline stability analysis on BTS shall be revisit as part of the lateral buckling design performed by others.

9.1

Design Criteria (Lateral Stabilit y)

Pipeline lateral stability analysis was performed for the following load cases:

•

Installation 1: Empty pipe + 1-year significant wave height + 1-year associated current

•

Installation 2: Empty pipe + 1-year current + 1-year associated significant wave height

•

Operation 1: Pipe full of content (minimum density) + 100-year significant wave height + 100year associated current

•

Operation 2: Pipe full of content (minimum density) + 100-year current + 100-year associated significant wave height

Dry concrete density of 3040kg/m3 and wet concrete coating with 5% water absorption, was used for the installation and operation case, respectively. The minimum practical thickness of concrete coating is taken as 40mm.

9.2

Hydrody namic Force Computati on

The current velocity and wave induced particle velocity shall be computed by using one-seventh (1/7) power law and Stokes Fifth order wave theory respectively. The direction of current and wave shall be considered as acting perpendicular to the pipeline.



9.3

Method of Analysi s

9.3.1

Lateral Stability


The calculation is essentially carried out in two parts as follows:

•

Derivation of wave and current velocities and wave-induced acceleration.

•

Relating the velocities and accelerations to the horizontal stability.

The wave-induced velocities are derived using the appropriate wave theory. The hydrodynamic forces and the safety factor are then calculated. The program finds the worst combination of force against horizontal stability until a minimum value of safety factor is obtained. The required submerged weight of the pipeline is given by:

W s

⎡ ( F + F ).F + μ .F L ⎤ = ⎢ D I s ⎥ μ ⎣ ⎦

Where:

W s

=

Submerged weight of pipe;

FS

=

Factor of safety, minimum 1.1

μ

=

Soil friction factor in lateral direction = 0.6

FL

=

Lift Force

=

Inertia Force

=

1

=

Drag Force

=

1

ρw

=

Density of Seawater

CL

=

Lift Force Coefficient

CD

=

Drag Force Coefficient

CM

=

Inertia Force Coefficient

Us

=

Significant wave-induced water particle horizontal velocity perpendicular to pipeline.

Uc

=

Current velocity perpendicular to the pipeline integrated over the pipeline overall diameter.

A s

=

Significant wave-induced water particle horizontal acceleration perpendicular to pipeline

D

=

Outside diameter of the pipeline (including coatings)

FI FD

=

1 2

.ρ w D . .C L .(U s

4 2

+ U c )2

.π . D 2 . ρ w .C M . As . ρ w . D.C D . (U s

+ U c ).(U s + U c )




For the pipeline to be stable, the actual submerged weight of the pipeline must be minimum 1.1 times the required submerged weight ( Ws ) defined above.

9.3.2

Vertical Stability Vertical stability of pipeline shall be checked by determining the pipeline sinkage and ensuring that pipe is not buoyant in all conditions. The vertical stability is calculated based on the settlement of each pipeline with respect to the soil conditions which shall be provided after the Pre-Engineering Survey, and is performed using the Terzaghi Equations The pipeline settlement is calculated by assuming that the pipeline will sink into the soil until the contact pressure exerted by the pipeline on the soil is equal to the bearing capacity of the soil. The pressure exerted by the pipeline on the soil is given by the following equation:

σ pipe

=

W s B

Where:

Ws

= Submerged Weight of the Pipeline (N/m)

B

= Contact Area Width between Pipeline and Soil (m) =

(

2. D. z − z

1

2

)

2

for z <

D

2

= Diameter of Pipeline (including coatings) (m)

D z

= Settlement Depth (m)

The ultimate bearing capacity of the soil is given by the Terzaghi Equation as follows:

q f

= 0.5.γ . B. N γ + S u .N c

Where: = Undrained Shear Strength of the Soil (N/m2)

Su

γ

= Submerged Density of Soil (N/m3)

N γ , N c

= Bearing Capacity Factors

By equating

σpipe and qf , the settlement depth ( z ) can be calculated.



10.

PIPELINE EXPANSION

10.1

Pipeline End Expansio n


CS Pipeline end expansion analysis will be performed to evaluate the magnitude of displacement and virtual anchor length in operating and hydrotest conditions, subject to thermal and pressure expansion forces. Requirement for expansion offset will be assessed based on the calculated expansion. The methodology used in estimating the pipeline end expansion is based on the first principle of stress-strain relation. The stresses acting in the pipeline wall resulting from the operating loads and friction resistance depend on whether the pipeline is unrestrained, partially restrained or fully restrained. The strain components for the free-fixed or free-free pipeline are ε T, ε P, ε S. Under the condition of equilibrium between the temperature loads, pressure loads and the soil friction resisting force the following equation must always be true at a location of zero displacement.

ε TOT

= ε T + ε P

+ ε S = 0

The longitudinal strain in the pipeline due to temperature gradient ε T is given by the following formula:-

ε T

= σ (T i − T ref )

The thermal strain in the pipeline is calculated based on the difference between the pipeline temperature and the ambient temperature. The logarithmic has been used in this expansion analysis, which presents a more realistic modelling of the temperature distribution.

T x = T ref

+ (T max − T ref )10

− β x L

The end expansions at the hot and cold ends are calculated by integrating the net longitudinal strain given by:

ΔL

= =

∫

∫

L AHOT

0 L

L ACOLD

ε TOT dL for hot end

ε TOT dL for cold end

Where, L AHOT = Virtual anchor point at hot end L ACOLD = Virtual anchor point at cold end

However, for Well Fluid Pipeline (PL-BD1), the pipeline end expansion will be limited to the maximum expansion that the riser and expansion spool can accommodate. The lateral buckling design shall ensure that the pipeline end expansion will not exceed the specified maximum end expansion.



10.2


Initi al Lateral Buck ling Ass essment

The preliminary assessment to determine the susceptibility of all pipelines to experience lateral buckling is performed based on the guidelines given by Hobbs [Ref. 9]. Based on Hobbs, the pipeline can buckle laterally in several ways as indicated by Figure 9.1.

FIGURE 9.1: LA TERAL BUCKL ING MODE SHAPES

The first mode is the same as a vertical buckle, but in practice it is not likely to occur laterally. It requires concentrated lateral forces at each end of the buckle for equilibrium, which cannot be generated by lateral friction alone. The final "continuous" mode shows the pipeline buckling into a continuous series of half waves. Again, this form of buckling is unlikely to occur. As the pipeline buckles, initiated e.g. by a misalignment in a weld, the compressive load is decreased, and the likelihood of buckling occurring elsewhere in the pipeline is reduced. The remaining modes, Mode 2, Mode 3 and Mode 4 are the possible potential configurations that will form when buckling occurs. Mode 3 is considered to be the critical mode shape as it represents the most realistic shape that can be expected to form in the lateral direction on the seabed. Based on Hobbs, the relationship between effective axial force and the buckle length depends on several parameters, which are given in the formula below:

F eff _ axial

= k 1 ⋅

EI 2

Llat

0.5 2 5 ⎧⎪⎡ ⎫⎪ Astc ⋅ E ⋅ μ lat ⋅ W s ⋅ Llat ⎤ + k 3 ⋅ μ ax ⋅ W s ⋅ Llat ⎨⎢1 + k 2 ⎥ − 1⎬ 2 μ ( ) ⋅ EI ⎥⎦ ax ⎪⎩⎢⎣ ⎪⎭




Where:

k 1, 2,3

Constants for buckling Mode (-)

Llat

Lateral buckling length (m)

EI

Pipe bending stiffness (Nm2)

μ ax

Axial friction coefficient (-)

μ lat

Lateral friction coefficient (-)

W s

Submerged weight of pipe per unit length (N/m)

Astc

Steel pipe cross section (m2)

E

Young’s Modulus of elasticity for steel (N/m2)

The lateral buckling design check will be assessed for all pipelines. If lateral buckling does occur, further assessment which shall be fully in accordance with the requirement of DNV RP F110, Global Buckling of Submarine Pipeline shall be performed. The assessment shall include the followings:

•

Post buckling assessment. This is to determine that the resulting bending moments in the “snaked” configuration must be demonstrated to be acceptable.

•

Mitigation assessment. Mitigation measures should be considered if the buckling results in significant feed-in and high local bending moments/strains exceeding the design criterion. The mitigation may either be to control the development of additional bending so that feed-in to each buckle is within the design criterion or to prevent buckles so there will be no “snaking”. The mitigation measures may include options such as snaked lay configuration, rock berm, or partial burial to laterally restrain the line.

Detailed lateral buckling mitigation analysis methodology is covered in Lateral Buckling Design Basis [Ref. 23].



11.


FREE SPAN ASSESSMENT The maximum allowable free span lengths for pipeline and risers were determined using verified inhouse software based on DNV RP F105. According to the DNV RP F105, pipeline / riser free span should passing both criteria as listed below unless span intervention detailed analysis were done:

11.1

•

Dynamic Screening RP F105 / Fatigue F105

•

Static Check (ULS) RP F105 and OS F101

Dynamic Screening Analys is

As per DNV-RP-F105, the in-line natural frequencies f n , IL must fulfil

f n, IL

γ IL

>

U c ,100 year IL

V R ,onset

⎛ ⎝

* ⎜1 −

L / D ⎞

1

⎟* 250 ⎠ α

Where

γ IL

= Screening factor for in-line, Table 2.1 [Ref. 3].

α

= Current flow ratio =

D

= Outer pipe diameter including coating.

U c,100 year

= 100-year return period value for current velocity at the pipe level.

U w,1 year

= Significant 1-year return period value for the wave induced flow velocity at the pipe

U c ,100 year U w,1 year + U c ,100 year

level corresponding to the annual significant wave height Hs.

V R IL,onset

= In-line onset value for the reduced velocity

The cross flow natural frequencies f n,CF must fulfil

f n,CF

γ CF

>

U c ,100 year + U x ,1 year V RCF , onset * D

Where

γ CF

= Screening factor for cross-flow, Table 2.1 [Ref. 3].

V RCF , onset

= Cross-flow onset value for the reduced velocity.

The maximum allowable dynamic span length will be based on fulfilling the both in-line and crossflow onset criteria above.



11.2


Static Analys is (ULS)

As for the maximum allowable static span length, the static bending moment is estimated based on Section 6.7 of DNV RP F105. The static bending moment is estimated as below.

M static

= C 5

q * L2eff

⎛ S eff ⎞ ⎜⎜1 + ⎟⎟ P cr ⎠ ⎝

Where q

= loadings i.e. the submerged weight of the pipe in the vertical (cross-flow) direction and/or the drag loading in the horizontal (in-line) direction

Leff

= effective span length

S eff

= effective axial force (negative in compression)

Pcr

= Critical buckling load

Effective force is computed based on formulation as per DNV-OS-F101 [Ref. 1] for a totally restrained pipe. The effective axial force is calculated as below.

S eff

= H − ΔPi * Ai * (1 − 2ν ) − A s * E * α * ΔT

Where H

= Effective (residual) lay tension

ΔPi

= Internal pressure difference relative to as laid

ΔT

= Temperature difference relative to as laid

α

= Thermal expansion coefficient

E

= Young’s Modulus

A s

= Pipe steel cross section area

A i

= Pipe internal cross section area

ν

= Poisson’s ratio

The allowable static span lengths will be determined based on local buckling check (load control) for the functional and environmental loads.



12.


OFFSHORE CROSSING DESIGN The design of the offshore crossing shall fulfil the requirements that are in accordance with the standard practice within offshore Vietnam. The pipeline span shall be supported by supports at selected elevation and position near the crossing location. Concrete sleepers, grout bag and concrete mattress or a combination of either two or three of those support types may be used as crossing supports The spacing between supports shall be selected such that pipeline free spans are within the allowable span and pipeline shall have adequate safety against yielding. Pipeline configuration shall satisfy the design criteria detailed below. In the crossing analysis, it is to be assumed that existing pipeline is not settled into seabed. The pipeline crossing analysis is to be performed for a sufficient length of pipeline on either side of the crossing centerline.

12.1

Design Criteria

The vertical clearance between the existing and the new pipeline shall be 300mm minimum. Horizontal clearance between the outermost edge of installed grout bag / steel structure / concrete mattress supports and existing pipeline shall be minimum 500mm. The proposed pipeline should generally cross the existing pipelines at 90° angle and wherever possible the crossing angle shall not be reduced below 30°.

12.2

Design Cases

The finite element program AutoPIPE, shall be used to calculate the pipeline stresses for the design cases defined as per below: a) Installation condition: Analysis shall be performed for un-corroded empty pipeline under the maximum wave and current for 1-year return period. b) Hydrotest condition: Analysis shall be performed for the hydrotest condition considering the uncorroded pipeline filled with seawater using the maximum wave and current for 1-year return period. Pipeline expansion has to be considered at crossing location. c) Functional and environmental conditions: the pipe stresses are calculated for the corroded pipeline under the design operational conditions with maximum wave and current for 100-year return period. Pipeline expansion has to be considered at crossing location.



12.3


Analysi s Method olog y

The pipeline crossing configurations shall be checked against stress criteria described in 12.2 above. The order of analysis is broadly outlined below. a) Check the pipeline spans for allowable spans at the crossing location. If necessary, relocate and add or delete bag supports so as to achieve a pipeline-crossing configuration that satisfies the allowable span criteria. b) Perform a structural analysis of pipeline crossing for the design installation, operational and hydrotest conditions. If necessary, relocate the supports and the height in order to reduce the stresses to permissible levels and to maintain the required vertical clearance between the existing and new pipeline.

The pipeline crossing stress analysis is performed for a sufficient length of pipeline on either side of the crossing centerline.



13.


CATHODIC PROTECTION ANA LYSIS Cathodic protection shall be provided by sacrificial anodes (bracelet half-shell type) designed in accordance with ISO 15589-2 and DNV RP F103. For pipeline bracelet anodes that are mounted flush with a concrete coating, the thickness of the concrete coating layer shall be taken into account when determining the overall dimensions of the anode. The anode dimensions shall be sufficient to meet the required current demand at the end of the design life. The spacing between anodes shall be determined once the number of anodes has been calculated. The anode spacing shall be close enough to maintain an adequate protection in the event of mechanical or electrical loss of a single anode. Anode spacing shall be 10 joints (120m) maximum. Maximum operating temperature for anode material is 80 C. For anodes facing with temperature above 80 C, an inner liner temperature resistant material is needed. For this, the use of 10mm neoprene coating liner is recommended. However, for this project, anode will be installed on the insulation coating for the 12 inch Well Fluid Pipeline (PL-BD1). Therefore, the need for neoprene is not anticipated. ˚

˚

13.1

Current Demand Calculation

From the pipeline dimensions and the coating selected, the mean current demand (Icm) and the final current demand (Icf ) shall be calculated separately from equation below:-

I c

= π OD p × L p × f c × ic

Where Ic

= Current demand for a specific pipeline section (A)

ic

= Current density (A/m2)

f c

= Coating breakdown factor, calculated for mean or final conditions

ODp

= Outer diameter of steel pipe (m)

Lp

= Total length of pipeline section requiring protection (m)

The coating breakdown factor for each external coating is accordance with ISO 15589-2. Mean coating breakdown factor,

F m

= a + [0.5 × b × DesignLife]

Final coating breakdown factor,

F f

= a + [b × DesignLife]

The mean coating breakdown factor,

F = F (linepipe ) + r × F ( fieldjnt )

where r is the ratio of the lengths of the cutbacks and the line pipe coating for the specific pipeline or pipeline section and a and b value is as presented in Table 13.1.




TABLE 13.1: RECOMMENDATION FOR COTING BREAKDOWN FACTOR Pipeline and Field Joi nt Coating

a

b

0.01

0.0005

Multilayer PE / PP + Concrete

0.002

0.0001

Thermal Insulation System

0.002

0.0001

Field Joint Coating

0.002

0.0001

Asphalt / Coal Tar Enamel + Concrete

Note: 1. As per ISO 15589-2 for pipeline and as per Design Basis for field joint.

13.2

Anodes Mass Calculation

The total net anode mass required to maintain CP throughout the design life shall be calculated for each section of pipeline in accordance with following equation:-

M =

I cm

× t dl × 8760 μ × ε

Where, M

= Total net anode mass for the specific pipeline section (kg)

Icm

= Mean current demand (A)

tdl

= Design life (years)

µ

= Utilization factor

ε

= Electrochemical capacity of the anode material (A)

For the anode type selected, the number of anodes, their dimensions and net mass shall be determined in order to meet the estimated mean and final current requirements for protection of the pipeline. The final dimensions and net mass of the individual anodes can be calculated using the formulae given below:-

M =

n M a

Where, M

= Total net anode mass for the specific pipeline section (kg)

n

= Number of anodes

Ma

= Individual anode mass (kg)

The required end-of-life individual anode current output, If , shall be calculated from following equation:-

I f

=

I cf n This document is the property of BD POC. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited.


14.


RISERS AND TIE-IN SPOOL DESIGN The riser will be preinstalled within the jackets. A hanger flange shall be integrated in the riser body and supported by an upper support hanger clamp designed for extreme riser weight load which is located at the top level of the platform's jacket. The intermediate guide clamps positioned along the platform in consideration of vortex shedding effect shall be located to allow the riser to move longitudinally. Expansion loop / dog leg shall be part of the riser and therefore shall be designed with the same design factor as that of the vertical riser section. Tie-in of expansion loop/ dog leg to riser and subsea pipeline shall be via subsea flange tie-in. All risers shall be protected by pipeline’s cathodic protection system. Therefore, sufficient anodes shall be installed at the last few pipeline joints to protect the riser. No insulation joint will be provided between the riser and topside piping system.

14.1

Riser Spans Assess ment

Vortex shedding analysis will be performed to determine the maximum allowable span length between riser guide clamps in accordance with the requirements stipulated in DNV RP F105 and limitation as per DNV Classification Notes No. 30.5. The load case considered for the riser is as follows:-

•

100 year return period current + corroded (50% of corrosion allowance) + marine growth + minimum product content (operating case)

The criterion to be used in the analysis is that vortex-induced resonant oscillation of the riser span shall not occur in in-line direction or cross-flow direction under the design current conditions. In case vortex-induced resonant oscillation in in-line direction occurs, it shall be checked for fatigue. The following assumptions have been made in the VIV span analysis:-

•

The end fixity for the all the spans are based on pinned-fixed condition.

•

Effects on flow velocity due to adjacent jacket legs are ignored.

•

The bottom span is considered as the span from the bottom guide clamp to the mudline (seabed).




The relevant partial safety factors applied to riser spans are presented in table below. TABL E 14.1 : SAFETY FACTORS - RISER SPAN DYNAMIC ANA LYSIS Safety Facto r

Riser Safety Factor

Safety Factor on Natural Frequency - γF

1.15

Safety Factor on Stability - γK

1.30

Safety Factor on Stress - γS

1.30

Fatigue Analysis Usage Factor

0.25

(1)

Note: 1. All risers shall be classified as high safety class.

Structural damping of 2% (based on API RP 2A) shall be considered for dynamic analysis. Increased flow velocities observed due to flow around the riser shall be considered where appropriate. Interaction and solidification effects shall be addressed where appropriate.

14.2

Riser Stress Analys is

All risers and spool pieces including the tie-in spools at subsea tie-in end shall be designed to DNV Location class-2. The structural integrity of each riser/spool shall be verified for the critical combination of functional and environmental load and hydrotest conditions. AutoPIPE Software, a 3dimensional finite element software will be used for this analysis. Stresses develop in a riser as a result of various operational functional and environmental loads acting on the riser. These include:-

•

Dead load (weight of pipe, coating)

•

Live load (weight of product)

•

Upward buoyancy force

•

Internal & external pressure

•

Hydrodynamic loads acting on a riser

•

Wave loading

•

Thermal expansion effect

•

Expansion of the pipeline on the seabed due to the thermal and pressure effects

•

Platform deflection

The structural integrity of riser is verified for the critical combination of:-

•

Operating functional + 100 years environmental load

•

Hydrotest functional + 1 year environmental load




For the operating condition, it is assumed conservatively that the riser pipe is filled with homogeneous maximum product density. The temperature of pipe content during system test pressure is assumed to be the same as the maximum ambient seawater temperature. Waves and currents are assumed to be collinear and uni-directional. Wind loading is negligible compared to the wave loads. Allowable Stress Design simplified criteria as given in section 5 F202 of DNV OS F101 shall be used:-

σ e

≤ η . f y

σ l

≤ η . f y

Where,

σe

=

equivalent stress

σl

=

Longitudinal stress

η

=

usage factor (1 for safety class low; 0.9 for normal; 0.8 for high)

f y

=

characteristic yield strength

Subsequently, the location (node) with the highest stress value will be verified against combined loading buckling criteria in according with section 5 D600 of DNV OS F101. These additional design checks which are not covered by AutoPIPE will be performed using INTECSEA’s in house calculation sheet. The allowable stress criteria are summarized in table below. TABL E 14.2 : A LLOWAB LE STRESS CRITERIA Al lowable Str ess (% fy)

Load Combinations Load Conditions

Class 1

A

B

C

D

E

F

G

Operating Case

X

X

X

X

X

X

X

Hydrotest Case

X

X

X

X

X

H

X

Class 2

Long. Stress

Von Mises Stress

Long. Stress

Von Mises Stress

90

90

80

80

100

100

100

100

Ab brev iat io ns: -

A: Gravity B: Design Temperature C: Design Pressure D: Platform Movement Long.: Longitudinal

14.3

E: Environment F: Seawater Temperature Fluctuation Effects G: Marine Growth H: Hydrostatic Test Pressure fy: Characteristic Yield Strength

Riser Hanger Flange and Subsea Flange Design

Riser hanger flange shall be design is in compliance with ASME VIII Div. 1 and Roark’s Formula for Stress & Strain requirements [Ref. 15]. Subsea flange stress analysis is carried out in accordance with ASME VIII Div. 1 code and flange size is per ASME B16.5.




15.

PIPELINE, FLEXIBLE PIPELINE AND SUBSEA CABL E INSTALLA TION

15.1

Installati on Analys is

The preliminary pipelay analysis was carried out by utilizing the commercially available finite element program OFFPIPE. This is to confirm the installability of all the pipelines. The analysis will be carried out for the following cases: 1. Pipeline Start-up 2. Pipeline Normal Lay. Local buckling checks shall also be performed as per DNV OS F101 3. Abandonment and Recovery

Analysis was performed based on the maximum water depth along the pipeline / subsea cable route. Basis for maximum water depth calculation for the installation analysis shall be maximum water depth along the pipeline route + H.A.T + Storm Surge. Pipeline weight shall be based on air filled condition (empty). 15.2

Strain Based Analys is

To provide non linear strain analysis, a moment curvature relationship has to be built for pipe material. This moment curvature relationship is assumed to be given by a Ramberq-Osgood Equation. The Ramberq-Osgood Equation is of the form : B

K K y

=

M M y

⎛ M ⎞ ⎟ + A × ⎜⎜ ⎟ ⎝ M y ⎠

Where, A & B

= Ramberg-Osgood coefficient factor

K

= 1 / R (R =stinger radius)

Ky

= Pipe Curvature at Nominal Yield Stress

2σ ⎞ ⎛ ⎜⎜ K y = y ⎟⎟ ED ⎠ ⎝



My


= Pipe Bending Moment at Nominal Yield Stress

⎛ ⎜⎜ M y = ⎝

2σ y I ⎞ D

⎟⎟ ⎠

E

= Steel Modulus of Elasticity

D

= Steel Outside Diameter

I

= Steel Moment of Inertia

σy

= Steel Nominal Yield Stress

The above nonlinear moment curvature relationship is primarily used to model the nonlinear of the pipe when the yield strength of the pipe has been exceeded. To generate this relationship, OFFPIPE has its’ built in default moment curvature relation ship by specifying the yield stress ratio (Ry) of the pipe. The yield strength ratio is usually in the range of (1.0 < Ry < 1.3). Therefore, Ry is assumed as 1.2 in this analysis.

FIGURE 4.1 : OFFPIPE DEFAULT NON LINEAR MOMENT CURVATURE RELATIONSHIP




The analysis is performed in accordance with the simplified lay criteria of DNV OS F101 Section 13, H300 which states that:

•

The maximum pipe total strain in the over bend region shall not exceed 0.25% for X65 (equivalent to DNV OS F101 grade 450) material.

•

The maximum equivalent stress at the sag bend region and pipeline stress at the stinger tip shall be less than 87% of f y for a combination of both static and dynamic loads. For conservative, the allowable for sagbend area is assumed as 72% of f y as commonly engineering practice (equal to 0.156% strain).

Due to the presence of concrete weight coating, the analysis also performed in accordance with the limit states criteria for concrete crushing of DNV OS F101 Section 13, H200 which states that:

γ cc emean ≤ ecc

Where :

15.3

γ cc

= 1.05 (safety factor for concrete crushing)

emean

= calculated mean over bend strain

ecc

= limit mean strain giving crushing of the concrete

Flexible Pipeline and Subsea Cable Pull Analys is

The flexible pipeline / cable pull in through J tube analysis will be performed to provide the pulling reaction load on J tube to structural discipline. In a typical umbilical pull-in, peak pull-in load occurs during one of the following stages of the pull-in: 1. Initial entry 2. Primary bending 3. End of pull-in

Due to unavailability of subsea cable and flexible pipe data, pull in analysis through J tube has not been carried during FEED. The analysis shall be performed during detailed design.



16.


PIPELINE PIGGING PHILOSOPHY All pipelines shall be designed to be suitable for the passage of either operational or intelligent pigs or both. The following design considerations shall be applied when designing the Bien Dong pipelines:

•

Constant ID philosophy will be applied for all pipelines.

•

Where sections of different external diameter are connected together, machining should be carried out at pipes end and the transition angle should not exceed 14 degrees, measured from the axis of the pipe (i.e., taper of 1:4).

•

All bends within the pipeline system (i.e. from launcher to receiver) shall be of 5D if layout allows. For topside bends, 3D may be considered if layout constraint is encountered.

•

Dual diameter (20 and 26 inch) Intelligent Pig (IP) requirement for Gas Export Pipeline (PLBD2).

•

Bidirectional operational pigging requirement for Condensate Pipelines (PL-BD3 / PL-BD4).

Table 16.1 summarizes the key pigging philosophy for all pipelines. A detailed pigging philosophy report will be produced as part of FEED scope to cover other aspects of pigging such as pigging frequency and type of pigging. TABLE 16.1 : PIPELINE PIGGING PHILOSOPHY DETAIL

Description

12 inc h Well Fluid Pipeline (PL-BD1)

20 inch Gas Export Pipeline (PL-BD2)

7inch ID Flexible Condensate Pipeline (PL-BD3/4)

3 inch ID Flexible Fuel Gas Pip eline (PL-BD5)

Intelligent Pigging (IP)

X

√

X

X

Routine Operational Pigging (RP)

√

X

√

√

Permanent Launcher Location

WHP-MT1

WHP-HT1

WHP-HT1

WHP-HT1

Permanent Receiver Location

WHP-HT1

Subsea skid at NCSP Wye(Note1)

WHP-HT1

FSO-HT

Note1: Subsea receiver will be temporary.


D2


17.


HYDROTEST, PRESERVATION AND PRE-COMMISSIONING OF PIPELINES The pipelines will be hydrostatic tested in accordance with the requirements of DNV OS F101 and project specific specifications. The hydrostatic test pressures for all pipelines and risers are given in Table 3.6. In case the pipeline sections are tested separately from the risers, the pipeline sections may be tested upon completion of pipeline installation while the risers may be hydrostatically tested onshore as part of jacket fabrication. Upon completion of full pipeline system tie-in offshore, a hydrotest (comprising riser, expansion spool and subsea pipeline) shall be performed. For carbon steel pipelines, requirements for corrosions inhibitor, oxygen scavenger and biocides shall be defined by the pre-commissioning contractor based on the seawater properties. For the CRA clad and flexible pipelines, fresh water shall be used for pipeline cleaning and hydrotesting. Requirements for corrosion inhibitor, oxygen scavenger and biocides shall be defined by the pre-commissioning contractor based on fresh water properties. Chloride level in fresh water shall be as per hydrotest specification. Metallic pipelines after hydrotested shall be dewatered, swabbed, vacuum dried, purged with nitrogen and preserved with nitrogen packing with positive pressure. During detailed design, a detailed base case of pre-commissioning plan shall be developed for all pipeline systems. The minimum pipeline hydrotest, preservation and pre-commissioning requirements will be covered in project specifications.




ATTACHMENT 1 PLATFORM DISPLACEMENT (2 Pages)




MAXIMUM HAI THACH JACKET DEFLECTION - TROPICAL STORM DESIGN WAVE AND ASSOCIATED CURRENT

Plan Bracing Level

(-) 131.0

(-) 118.6

(-) 104.0

(-) 63.0

(-) 32.0

(-) 10.0

(+) 7.6

Condition

Max. Deflecti on (X) Max. Deflect ion (Y) Max. Deflect ion (Z) (mm) (mm) (mm)

Operating

19.81

24.64

110.65

Storm

62.91

76.87

141.12

Operating

38.35

32.63

59.64

Storm

97.26

101.72

84.21

Operating

34.65

43.13

108.58

Storm

105.83

137.28

133.41

Operating

57.71

66.64

104.7

Storm

182.76

197.57

125.86

Operating

83.80

96.07

100.25

Storm

252.88

280.09

117.27

Operating

97.22

126.80

96.82

Storm

276.47

340.04

110.35

Operating

112.34

139.06

107.15

Storm

309.60

373.55

113.34

Operating

147.05

154.67

161.67

Storm

364.62

412.78

178.84

Operating

162.87

173.47

162.99

Storm

390.34

430.51

181.81

(+) 18.0

(+) 29.0


dafa

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