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March 18, 2018 | Author: Anonymous QK8bM9Z | Category: Pipeline Transport, Pipe (Fluid Conveyance), Mechanical Engineering, Applied And Interdisciplinary Physics, Engineering
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BIEN DONG PETROLEUM OPERATING COMPANYWorley Parsons BIEN DONG 1 PROJECT WorleyParsons Petro Vietnam Engineering JSC DOC. NO. Page 1 of 67 OFFSHORE FACILITIES BD1-00-L-A-0001 Design Basis SUBSEA PIPELINE DESIGN BASIS ,d/ft· 'rJ1 ;/ RE- APPROVED FOR DESIGN (RE-AFD) VAZA~ JI! D2 20 I 05/10 D1 21 104/10 APPROVED FOR DESIGN (AFD) AZAM MFAM lSI C1 15/01/10 ISSUED FOR APPROVAL (IFA) AZAM MFAM/SI B1 04/09/09 ISSUED FOR REVIEW (IFR) AZAM MFAM/SI BE A 28/08/09 PRELIMINARY IDC AZAM MFAM/SI BE Rev Date Description Prep'd Check'd MFAM/SI ffBE Vi BE WPApp'd BD POCApp'd poe. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited. Location: BD1-00-L-A-0001-D2 Subsea Pipeline Design Basis.doc This document is the property of SO Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 2 of 67 : D2 TABLE OF CONTENTS 1. 2. 3. INTRODUCTION .................................................................................................................................. 5 1.1 General Project Description .................................................................................................... 5 1.2 Objective.................................................................................................................................. 6 1.3 System of Units ....................................................................................................................... 6 1.4 Sources of 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................................................................................................................................... 9 1.10 References ............................................................................................................................ 10 REGULATIONS, CODES AND STANDARDS .................................................................................. 12 2.1 Vietnam Petroleum Regulation Act ....................................................................................... 12 2.2 International Codes and Standards....................................................................................... 12 DESIGN DATA AND CRITERIA ........................................................................................................ 14 3.1 Design Life............................................................................................................................. 14 3.2 Geodetic 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 to reproduce it, in any form, is strictly prohibited. Title: Subsea Pipeline Design Basis 3.13 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 3 of 67 : D2 Site Survey Data.................................................................................................................... 29 3.13.1 WHP-MT1 to WHP-HT1………………………………………………………………….. 29 3.13.2 WHP-HT1 to HT FSO…………………………………………………………………….. 29 3.13.3 WHP-HT1 to NCSP Wye Tie-In………………………………………………………….. 30 3.14 Soil Survey 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................................................................................................................. 33 3.17 Safety Classes....................................................................................................................... 34 3.18 Design Factors ...................................................................................................................... 34 4. PIPELINE / CABLE ROUTE SELECTION ........................................................................................ 35 5. MATERIAL SELECTION AND PROCUREMENT PHILOSOPHY .................................................... 36 6. WALL THICKNESS ........................................................................................................................... 39 7. 8. 9. 6.1 Pressure Containment (Bursting) .......................................................................................... 39 6.2 Local Buckling ....................................................................................................................... 39 6.3 Propagation Buckling............................................................................................................. 40 BUCKLE ARRESTOR DESIGN......................................................................................................... 41 7.1 External Hydrostatic Pressure............................................................................................... 41 7.2 Propagation Pressure............................................................................................................ 41 7.3 Crossover Pressure............................................................................................................... 42 COATING SELECTION ..................................................................................................................... 43 8.1 Pipeline / Riser Corrosion Coating ........................................................................................ 43 8.2 Insulation Coating.................................................................................................................. 43 8.3 Pipeline / Riser Field Joint Coating ....................................................................................... 44 8.4 Pipeline Field Joint Infill ......................................................................................................... 44 8.5 Splash Zone Coating ............................................................................................................. 44 ON BOTTOM STABILITY .................................................................................................................. 45 9.1 Design Criteria (Lateral Stability)........................................................................................... 45 9.2 Hydrodynamic Force Computation........................................................................................ 45 9.3 Method of Analysis ................................................................................................................ 46 This document is the property of BD POC. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited. .. 64 ATTACHMENT ATTACHMENT 1 PLATFORM DISPLACEMENT This document is the property of BD POC. 53 12..... 53 12.......................1 Dynamic Screening Analysis..........................................................................1 Design Criteria.................. 15............ 52 OFFSHORE CROSSING DESIGN..................... ..........2 Vertical Stability……………………………………………………………………………...... PRESERVATION AND PRE-COMMISSIONING OF PIPELINES ................. Any unauthorised attempt to reproduce it............ is strictly prohibited................................................................................................................. 60 15................................................. 55 13.......................... 48 10...................................................................................2 Strain Based Analysis........................2 Anodes Mass Calculation .......... FLEXIBLE PIPELINE AND SUBSEA CABLE INSTALLATION .................................................................................2 Static Analysis (ULS)........................2 Design Cases ....................................... 60 15................................... 12........................................ 49 FREE SPAN ASSESSMENT . 46 9.................................. HYDROTEST..........................................1 Riser Spans Assessment ......................................... 54 CATHODIC PROTECTION ANALYSIS............ 11. 59 PIPELINE....... 62 16.... 57 14............................................................... 13........................ 48 10..............1 Pipeline End Expansion...................................................................................... in any form............................... 63 17..... 58 14.........2 Initial Lateral Buckling Assessment...3................................ 55 13...3 Riser Hanger Flange and Subsea Flange Design...... 60 15...............................1 Lateral Stability……………………………………………………………………………......3..................................................................................1 Current Demand Calculation ..............................................1 Installation Analysis ..................... Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 4 of 67 : D2 9........................................................... 57 14.........2 Riser Stress Analysis........................................................................................................... 53 12............................................................................................................................................................................. PIPELINE PIGGING PHILOSOPHY ......................................................................... 51 11......................................................Title: Subsea Pipeline Design Basis 10....................3 Flexible Pipeline and Subsea Cable Pull Analysis ............................. 56 RISERS AND TIE-IN SPOOL DESIGN ............................3 Analysis Methodology.......................... 51 11................................................................................ 14.............................................................................................................................. 47 PIPELINE EXPANSION ..................................................................................................... in any form. .3 approximately 340km south of the coast of Vietnam. is strictly prohibited. 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. Field locations and existing facilities are indicated in Figure 1. The fields lie approximately 20km apart.Title: Subsea Pipeline Design Basis 1. INTRODUCTION 1.1 : FIELD LAYOUT This document is the property of BD POC.2 and 05.1. FIGURE 1. Any unauthorised attempt to reproduce it.1 General Project Description Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 5 of 67 : D2 The Bien Dong 1 (BD1) Project involves offshore development of the Hai Thach and Moc Tinh gas/condensate Fields in Blocks 05. in any form. all data contained in this document are obtained from references in Section 1. approximate length is 44.3km.7km. 1. 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) This document is the property of BD POC. • 20 inch Gas Export Pipeline (PL-BD2) from WHP-HT1 to Existing NCSP Wye tie-in.0km • Subsea Cable (CAB-BD1) from WHP-HT1 to WHP-MT1. Any unauthorised attempt to reproduce it. approximate length is 2.0km • 3 inch ID Flexible Fuel Gas Pipeline (PL-BD5) from WHP-HT1 to DFR tie-in. the Imperial Units shall be shown on the drawings with Metric equivalent in brackets.3 System of Units The System International of Units (SI units) shall be used in all design.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 19. engineering document and drawings.5 Pipeline System Description The pipeline systems for BD1 include: • 12 inch Well Fluid Pipeline (PL-BD1) from WHP-MT1 to WHP-HT1.2 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 6 of 67 : D2 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. 1. approximate length is 2.Title: Subsea Pipeline Design Basis 1. is strictly prohibited. approximate length is 0. approximate length is 19. . Details of the pipeline system involved in the proposed BD1 development can be found in Section 1. One SSIV will be installed approximate 500m from WHP-HT1 • Umbilical (UMB-BD1) from PQP-HT to SSIV. 1.4 Sources of Data Unless noted otherwise. Where standard equipment is supplied with Imperial Units.10.7km In the beginning of the project.5. Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 7 of 67 : D2 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 This document is the property of BD POC. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited. Title: Subsea Pipeline Design Basis 1.6 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 8 of 67 : D2 Pipeline Battery Limit The battery limit for pipeline scope of work is as follows: • WHP-MT1 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 (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 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 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 This document is the property of BD POC. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited. Title: Subsea Pipeline Design Basis 1.8 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 9 of 67 : D2 Definition 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 This document is the property of BD POC. Any unauthorised attempt to reproduce it, in any form, is strictly prohibited. Pipeline Preliminary Design. 1. HT-NCSP Pipeline Route Survey.1. Condensate Pipeline Flow Assurance 12. 1. Fugro Singapore. 2006 3. Flowline-Pipeline Final Factual Report. Rev.0 Oct. in any form. BD1-00-R-T-0021. 05. 5256-1000-RG-0003. 1. TL Geohydrographics Pte Ltd. 2008 5. is strictly prohibited. In-Service Buckling of Heated Pipelines. Roger E Hobbs 10. 2008 6. Oceanmetrix. 2009 4. A1 Nov. . 5253-1000-RP-1900. 2009 11.10 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 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 10 of 67 : D2 References 1. HT Marine Site Survey. 2009 9. 5256-1000-AG-0001. 2008 8.0 Oct. 5253-1000-RB-0004. Rev. Southern Vietnam. Integrated Statement of Requirement (FEED Phase). TL Geohydrographics Pte Ltd. Any unauthorised attempt to reproduce it. BD1-00-R-T-0024. 5253-1000-RB-1012. 5253-1000-RB-0003.0 Jan. Nam Con Son Blocks 05. Gas Export Pipeline Flow Assurance 13. 2008 7. Rev. Moc Tinh Pipeline Flow Assurance This document is the property of BD POC.3 & 06. Rev.0 Oct. B1 Aug. Rev. 1. MT Marine Site survey. Metocean Criteria.Title: Subsea Pipeline Design Basis 1. Rev. A7 July 2009 2. 5253-1000-RB-0006.0 Oct. Rev. Rev. 5253-1000-RB-0002. HT-MT Pipeline Route Survey. TL Geohydrographics Pte Ltd.2. Rev. Structural Design Basis. BD1-00-S-A-0001. BD1-00-R-T-0022. Bien Dong Petroleum Operating Company. 1. 2 Feb. TL Geohydrographics Pte Ltd. Subsea Pipeline Material Selection Report 18.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 11 of 67 : D2 14. BD1-00-R-T-0025. Topsides Piping. Roark’s Formulas for Stress & Strain 7th Edition. Launcher / Receiver – Design to Pipeline Code & Tech Requisitions Allocation 20. Carl G. Pipeline / Piping Code Break and Intelligent Pig Launcher / Receiver 22. DI-BD1-0012. BR02050/SAFEBUCK/B. Aug. in any form. PL-BD1-L-A-0001.Langner. Flexible Pipelines from WHP-HT1-FSO 21. WHP-HT1 Fuel Gas Pipeline to FSO Flow Assurance 15. “Buckle Arrestors for Deepwater Pipelines” OTC 10711. Safe Design of Pipelines with Lateral Buckling Design Guidelines. Offshore Technology Conference 1999 17. Any unauthorised attempt to reproduce it. 4211281-MOM-PL-006. BD1-00-G-N-L-R-0004. is strictly prohibited. Warren C Young 16. Lateral Buckling Design Basis This document is the property of BD POC. DI-BD1-0003. 2004 19. DI-BD1-0015. . MOM for Scope Demarcation for Pipeline and Topside Piping 23. in any form. In case of any conflict between applicable codes and standards. 2001 DNV RP F110 Global Buckling of Submarine Pipelines. 2009 API 17B / ISO 13628-11 Recommended Practice for Flexible Pipe.Title: Subsea Pipeline Design Basis 2. 2003 DNV RP F107 Risk Assessment of Pipeline Protection. 2003 DNV RP F106 Factory Applied External Pipeline Coatings for Corrosion Control. 2007 DNV OS F201 Offshore Standard for Dynamic Risers. should DNV OS F101 does not cover any specific criterion. 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. 2. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 12 of 67 : D2 REGULATIONS. 2009 API 17J / ISO 13628-2 Specification for Unbonded Flexible Pipe.2 International Codes and Standards Det Norske Veritas (DNV) DNV OS F101 Submarine Pipeline Systems. . 2001 DNV RP F105 Free Spanning Pipelines. Any unauthorised attempt to reproduce it. 2006 DNV RP E305 On-Bottom Stability of Submarine Pipelines. 1988 DNV RP F103 Cathodic Protection of Pipeline Submarine Pipelines By Galvanic Anodes. other applicable design codes may be employed. The applicable codes and standards for the pipeline/riser design are listed below. 2007 American Petroleum Institute API 5LD Specification for CRA Clad or Lined Steel Pipe. 2008 This document is the property of BD POC. the design criteria detailed in this document followed by requirements of client specifications shall govern.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. is strictly prohibited. Valves and Parts for High Pressure Transmission Service. 2001 ISO 15590-2 Petroleum and Natural Gas Industries – Induction Bends. Fittings and Flanges for Pipeline Transportation Systems – Part 1: Fittings. Fittings.1 Rules for Construction of Pressure Vessel. 2000 International Organization for Standardization (ISO) ISO 3183 Petroleum and Natural Gas Industries – Steel Pipe for Pipeline Transportation Systems. 1998 ASME B16. is strictly prohibited. of Pipeline .Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 13 of 67 : D2 American Society of Mechanical Engineers (ASME) ASME B16. 2007 ISO 14723 Petroleum and Natural Gas Industries – Pipeline Transportation Systems – Subsea pipeline valves. 2003 ASME B16. 2004 ISO 13628-5 Subsea Umbilicals ISO 13628-8 Remotely Operated Vehicle (ROV) interfaces on subsea production systems This document is the property of BD POC. or Both ASTM A694 Specification for Carbon and Alloy Steel Forgings for Pipe Flanges. 2002 ISO 15589-2 Petroleum and Natural Gas Industries Cathodic Protection Transportation Systems — Part 2: Offshore pipelines.47 Large Diameter Steel Flanges.5 Pipe Flanges and Flanged Fittings. 2004 ISO 15590-1 Petroleum and Natural Gas Industries – Induction Bends. Fittings and Flanges for Pipeline Transportation Systems – Part 3: Flanges. 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.20 Metallic Gaskets for Pipe Flanges. in any form. Any unauthorised attempt to reproduce it. 2003 ISO 15590-3 Petroleum and Natural Gas Industries – Induction Bends. 2006 ASME VIII Div. Fittings and Flanges for Pipeline Transportation Systems – Part 1: Induction Bends. .00m dZ = -1.000” Scale = 0. Local Datum Geodetic Datum : Spheroid WGS 72 BE DMA WGS 72 Semi-major axis : 6 378 135. Any unauthorised attempt to reproduce it. in any form.814” This document is the property of BD POC.53 meters Inverse flattening (1/f) : 298.90m rX = 0.00 meters Semi-minor axis : 6 356 750.38ppm rY = 0.Title: Subsea Pipeline Design Basis 3.00660431778 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 : 0.1 Design Life The pipeline system and associated facilities shall be designed for a 25 years design life. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 14 of 67 : D2 DESIGN DATA AND CRITERIA The design data is extracted from the Project Statement of Requirement (SOR) [Ref. 3. is strictly prohibited. 3. All positions quoted in reports and charts related to the survey information refer to the WGS72BE DMA spheroid and datum.2 Geodetic Parameters The following geodetic parameters were based on the survey report.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. 1] unless stated otherwise.00m dY = 0.000” rZ = -0.2600 Eccentricity Squared (e2) : 0. 1 New WHP-HT1 271 615 889 619 132. Any unauthorised attempt to reproduce it.4 Existing NCSP Wye Tie-In (POVO PLEM) 230 173 904 364 100.3 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 15 of 67 : D2 Key Location Coordinates The table below presents the key locations coordinates and water depths [Refs.0 Dynamic Flexible Riser Tie-in 269 712 890 388 130. This document is the property of BD POC.7 New FSO-HT Turret 269 473 890 484 130.8 New PQP-HT 271 605 889 756 132. 6 and 7].1 : KEY LOCATION Easting (m) Northing (m) Water Depth (m) (1) New WHP-MT1 256 520 877 038 115.4 SSIV 271 353 890 038 132.8 Description Notes: 1. TABLE 3. . in any form.Title: Subsea Pipeline Design Basis 3. Water Depths are referred to CD/LAT. is strictly prohibited. 0 DNV OS F101 grade 450 (LSAW) 20 inch (1) (479. 3. Any unauthorised attempt to reproduce it. is strictly prohibited.Title: Subsea Pipeline Design Basis 3. TABLE 3. .4mm ID) Gas 1500# 1.4 Document No Date Page Rev : BD1-00-L-A-0001 : 26-Mar-10 : 16 of 67 : D1 Pipeline Data The pipeline design data is as presented in tables below. 2.0 - API 17J (Flexible Pipe) 7 inch ID (2) Condensate 600# - - API 17J (Flexible Pipe) 3 inch ID (2) Fuel Gas 600# - Class Material Grade (1) 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 Flexible Condensate Pipeline (PL-BD3 / PL-BD4) Flexible Fuel Gas Pipeline (PLBD5) Pipelines Well Fluid Pipeline (PL-BD1) Gas Export Pipeline (PL-BD2) Notes: 1. Topside piping material for CRA Clad pipeline shall be DNV OS F101 Grade 22Cr D (SAW). in any form. 19].2 : PIPELINE DATA Size Product Flange Rating CA (1) (mm) 12 inch (1) (297.3mm ID) Well Fluid 900# 0. This document is the property of BD POC. 17]. Data is refers to [Ref. Data is refers to [Ref. This document is the property of BD POC. 2. in any form.0 DNV OS F101 grade 450 (Seamless) 6 inch (149.CS Option Class 1 Fuel Gas Pipeline (PL-BD5) CS Option Class 1 Class 2 Class 2 Notes: 1. Any unauthorised attempt to reproduce it. 17]. .0 Class 2 DNV OS F101 grade 450 + Inconel 625 CRA (LSAW) (2) 8 inch (199.3mm ID) Condensate 600# 6.0 Class 1 DNV OS F101 grade 450 + AISI 316L CRA (LSAW) (2) Condensate 600# 0.3mm ID) Fuel Gas 600# 1.3 : PIPELINE DATA FOR OPTIONAL CASES Pipelines Class Material Grade (1) Size (1) Product Flange Rating CA (1) (mm) Gas Export Pipeline (PL-BD2) – 26 inch Option Class 1 DNV OS F101 grade 450 (HFW) Class 2 DNV OS F101 grade 450 (LSAW) 26 inch (625.0 Condensate Pipeline (Pl-BD3 / PL-BD4) .0mm ID) Gas 1500# 1. Topside piping material for CRA pipeline shall be DNV OS F101 Grade 22Cr D (SAW). is strictly prohibited. Data is refers to [Ref.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 26-Mar-10 : 17 of 67 : D1 TABLE 3.1mmID) DNV OS F101 grade 450 (Seamless) 6 inch (146.Clad Option Condensate Pipeline (Pl-BD3 / PL-BD4) . flanges with internally weld overlay of Inconel 625 have been proposed.3 0.5 x 10-6 12. Subsea Cable and Umbilical Data Since no detail is available.8 x 10-6 12. is strictly prohibited. Data is based on input from JSW.3 0. -6 3.Title: Subsea Pipeline Design Basis 3.6 Flexible Pipeline. 2.02 x 105 N/A N/A 1. For subsea flanges for the 12 inch Well Fluid Pipeline (PL-BD1). similar to the Class 2 pipeline section and bends. the Flexible Pipeline.96 x 105 Elastic Modulus at 150°C 2.10 x 105 2.02 x 105 Elastic Modulus at 100°C 2. Any unauthorised attempt to reproduce it.5 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 18 of 67 : D2 Steel Pipeline Material Data Pipeline material properties are presented below.4 : PIPELINE MATERIAL PROPERTIES DNV F101 Grade 450 AISI 316 L (1) Inconel 625 (1) DNV OS F101 Grade 22Cr D 7850 8027 8440 8027 0.07 x 105 1.95 x 105 2.008 x 10 θ for -6 carbon steel and α = α (at 0°C) + 0. This document is the property of BD POC. This is due to the expected prolonged exposure to seawater during installation period.3 11.5 x 10-6 SMYS at 20°C (MPa) 450 170 275 450 SMYS at 100°C (MPa) 420 145 253 360 SMYS at 130°C (MPa) 408 136 246 330 Elastic Modulus at 20°C 2. in any form. Derated Thermal Expansion Coefficient can be calculated using equation α = α (at 0°C) + 0.92 x 105 Parameters Density (kg/m3) Poisson Ratio Thermal Expansion Coefficient (/°C) (3) (2) Note: 1. 3.3 0. 18].005 x 10 θ for 22 Cr D.05 x 105 N/A N/A 1.7 x 10-6 16. TABLE 3. Subsea Cable and Umbilical Material Properties will be updated and presented in detailed design stage based on manufacturer data. Data is referred to [Ref. . Properties of typical pipeline coating materials and external coating for various pipeline systems are listed in tables below.69 Fusion Bonded Epoxy (FBE) 1400 1170 0.7 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 19 of 67 : D2 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.4 mm FBE 46mm SPU KP 0. Properties of insulation coating also included in below table.25 Syntactic Polyurethane (SPU) 900 2095 0.Title: Subsea Pipeline Design Basis 3. Due consideration shall be given to a proper coating material based on the operational and environmental aspect.5A : PROPOSED EXTERNAL COATING FOR WELL FLUID PIPELINE (PL-BD1) External Anti Corrosion Coating Insulation Coating (1) - 5 mm Monel (Metalurgical Bonded) - WHP-MT1 Inclusive 50mm MLPP WHP-HT1 0.5 Inclusive 50mm MLPP KP 6.0 – 6.30 3 Layer Polypropylene (3LPP) 1008 1250 0.4 mm FBE 46mm SPU Subsea Bend - 3mm 3LPP 46mm SPU Field joint coating - Heat Shrink Sleeves 46mm Half Shell SPU Section Splash Zone Riser Submerged Riser and Tie-In Spool Pipeline Note: 1. TABLE 3.5 – 19.17 Concrete (Dry) 3040 1260 2. The final thickness for the insulation coating shall be reconfirmed by the coating contractor based on the required U value. .7 0.18 Asphalt Enamel (AE) 1280 1255 0.10 Marine Mastic 1440 2095 0.5 : TYPICAL PIPELINE COATING PROPERTIES 763 Specific Heat Capacity (J/kgK) 2075 Thermal Conductivity (W/m2K) 0.24 Coating Type Density (kg/m3) 50mm Multi Layer Polypropylene (MLPP) TABLE 3.12 Polyurethane (PU) Foam 160 1700 0. Any unauthorised attempt to reproduce it. is strictly prohibited. This document is the property of BD POC. in any form.18 70mm Multi Layer Polypropylene (MLPP) 753 2065 0. The final thickness for the insulation coating shall be reconfirmed by the coating contractor based on the required U value.0 – 0. The final thickness for the insulation coating shall be reconfirmed by the coating contractor based on the required U value.7mm Neoprene - Submerged Riser and Tie-In Spool - 0.4mm FBE 56mm SPU KP 0.5 – 44.5D : PROPOSED EXTERNAL COATING FOR CONDENSATE PIPELINE (PL-BD3 / PLBD4) FOR OPTIONAL CASE Section External Anti Corrosion Coating Insulation Coating (1) Splash Zone Riser - 12. TABLE 3.4mm FBE 56mm SPU Subsea Bend - 3mm 3LPP 56mm SPU Field joint coating - Heat Shrink Sleeves 56mm Half Shell SPU Pipeline Note: 1.5B : PROPOSED EXTERNAL COATING FOR WELL FLUID PIPELINE (PL-BD1) FOR OPTIONAL CASE External Anti Corrosion Coating Insulation Coating (1) - 5 mm Monel (Metalurgical Bonded) - Submerged Riser and Tie-In Spool WHP.5 3mm 3LPP - KP 0.0 – 2. . in any form. This document is the property of BD POC.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 20 of 67 : D2 TABLE 3.0 0.7mm Neoprene - Submerged Riser and Tie-In Spool - 3mm 3LPP - KP 0.3 5mm AE - Subsea Bend - 3mm 3LPP - Field joint coating - Heat Shrink Sleeves PU Foam Pipeline TABLE 3. is strictly prohibited. Any unauthorised attempt to reproduce it.7 Inclusive 70mm MLPP Subsea Bend - 3mm 3LPP - Field joint coating - Heat Shrink Sleeves PU Foam Section Splash Zone Riser Note: 1.5C : PROPOSED EXTERNAL COATING FOR GAS EXPORT PIPELINE (PL-BD2) Section External Anti Corrosion Coating In-fill Joint Coating Splash Zone Riser - 12.0 – 19.MT1 & WHP-HT1 Inclusive 70mm MLPP Pipeline KP 0. 0 3mm 3LPP - Subsea Bend - 3mm 3LPP - Field joint coating - Heat Shrink Sleeves PU Foam Pipeline 3.0 0. the above gives a system test pressure of approximately 1.7mm Neoprene - Submerged Riser and Tie-In Spool - 3mm 3LPP - KP 0.8 70.0 Flexible Condensate Pipeline (PL-BD3 / PL-BD4) 93.0 160. 2. .4 70.4 80. in any form. Any unauthorised attempt to reproduce it.0 0.0 0.3 Maximum Design Inlet Temperature (°C) 130.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 21 of 67 : D2 TABLE 3.8 External Anti Corrosion Coating Pipeline Design Pressures and Temperatures Tabulated below are the design temperatures and pressures for pipeline systems.0 – 2. 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 temperature.0 184. is strictly prohibited.0 (1) 107.6 : DESIGN PRESSURES AND TEMPERATURES Minimum Design Temperature (°C) 158.155 times the local design pressure at the highest point of the pipeline system part tested (DNV OS F101).5E : PROPOSED EXTERNAL COATING FOR FUEL GAS PIPELINE (PL-BD5) FOR OPTIONAL CASE Section In-fill Joint Coating Splash Zone Riser - 12.0 Design Pressure (Bar) System Test Pressure (Bar) (2) 137. TABLE 3. With an incidental pressure of 10% above design pressure.0 (1) Gas Export Pipeline (PL-BD2) Pipelines Well Fluid Pipeline (PL-BD1) -5.0 (1) 107. This document is the property of BD POC.0 Notes: 1.0 Flexible Fuel Gas Pipeline (PL-BD5) 93. .|L3| Where.36 181.10 Fluid Density (kg/m3) Minimum Maximum Well Fluid Pipeline (PL-BD1) 37.Title: Subsea Pipeline Design Basis 3.7 : FLUID DENSITY Pipelines 3.46 x significant wave height (Hs) at 100 year return period. TABLE 3. is strictly prohibited.3 Flexible Fuel Gas Pipeline (PL-BD5) 8.4 780.|L2| . 3. However. Result from above equation or bottom of hanger clamp will be applied for Splash Zone Upper Limit. in any form. 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. This document is the property of BD POC. Any unauthorised attempt to reproduce it.9 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 22 of 67 : D2 Pipeline Fluid Density The fluid density is as presented in table below.74 10. 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 0.35 Flexible Condensate Pipeline (PL-BD3 / PL-BD4) 777.71 Splash Zone Splash Zone Lower Limit (LSZ) according to DNV OS F101 is determined by: LSZ = |L1| .11 Platform Displacement Platform displacement data for WHP-MT1 and WHP-HT1 are presented in Attachment 1.54 96. as minimum.75 Gas Export Pipeline (PL-BD2) 64. a one joint pipe length (12m) will be coated with splash zone coating. 39 90 28. Any unauthorised attempt to reproduce it.12. . 3] unless stated otherwise.00 100 27.30 80 28.35 10 31.9 : SEAWATER TEMPERATURE WITH DEPTH Water Depth (m) Maximum (oC) Minimum (oC) 0 32.72 150 26.2 Seawater Properties The seawater temperatures with respect to water depth are presented in the table below.00 30 31. TABLE 3.28 17.17 40 31.8 : TIDAL CHARACTERISTIC Parameter Value (m) Highest Astronomical Tide (HAT) 2.39 16.40 18.60 19.12.50 23.1 Tidal Characteristic The tidal characteristic is presented in table below.61 60 29.04 Storm Surge (100-Year) 0.60 The seawater density is 1025 kg/m3 and the seawater kinematic density is 1. 3.39 70 29.30 120 29. 10]. TABLE 3.70 50 30. This document is the property of BD POC.14 Mean Sea Level (MSL) 1. in any form.78 11.Title: Subsea Pipeline Design Basis 3. 10]. 3.12 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 23 of 67 : D2 Environmental Data The environmental data is extracted from the Metocean Criteria Report [Ref.00 20 31.00 20.90 22.65 x 10-6 m2/s [Ref.95 15.50 24.00 Storm Surge (1-Year) 0.12 18.10 21. Data is referred from Structural Design Basis [Ref.16 Note: 1. is strictly prohibited.20 Lowest Astronomical Tide (LAT) / Chart Datum (CD) 0.30 22. 41 1.18 1.86 1.10 : 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. (m/s) 0.1 12.12 2.64 0.73 2.9 12.3 Wave and Current Data Extreme weather in this region is associated with Tropical Storms (TS).28 0.88 1.59 0.9 3.81 2.3 9.04 0.2 1.4 9.83 1.36 50 m depth.2 8. Therefore.81 0.50 0.84 2.71 0. Hs (m) 2.3 Maximum Wave Period.75 1.1 9.31 0.05 0. Wave Height. in any form.34 0.66 0.69 0. Current velocity were calculated by 1/7 Power law at 3m depth.0 12.48 2.76 0.5 14. (m/s) (1) 0.12 2.5 13. TABLE 3.35 1 m above sea bed.8 7.2 10.82 0.8 2. Current calculation for in between depths to be carried out by linear interpolation.0 Peak Period.7 3 m depth.26 0. 3]. Tm (sec) 10.54 0.32 1.97 1.90 0.1 Notes: th 1.96 1.6 5.23 1.02 3 m above seabed.1 2.59 0.5 14. This document is the property of BD POC.7 8.19 0. (m/s) 0.83 0.09 1. The waves and currents data at WHP-MT1 is as presented in table below.5 4.53 0. .12. (m/s) 1.4 7.95 1.97 1.1 10.9 12.33 0.66 1.73 0.27 1.6 14.02 1.4 5.58 0.3 1.7 3.13 0.58 30 m depth.32 0.5 3.44 2.62 0.56 0.30 Current and Associated Wave Data 3 m depth.84 1.7 4.54 0.6 4. (m/s) 0.52 0.81 1.85 1. (m/s) 1.7 8.09 0.8 11. Northeast Monsoon surges (NEM) and Southwest Monsoon surges (SWM).76 1. Any unauthorised attempt to reproduce it.70 30 m depth.48 0.56 0.33 0.38 0.40 0. is strictly prohibited.5 13.41 1.2 9.8 Significant Wave Height.7 12.99 1 m above sea bed.93 0.8 6.40 1.46 0.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 24 of 67 : D2 3.89 0. (m/s) (1) 0.11 1. 2.3 9.30 0. (m/s) 1.39 0. Hs (m) 3.7 15.3 1.23 1.35 3 m above seabed. (m/s) 0. Tp (sec) 10.63 0. The details criteria can be referred to Metocean Criteria Report [Ref.0 3. (m/s) 0. Hm (m) 7. Sig.71 0.8 7.04 50 m depth.20 1.82 1.79 0.29 1.85 Assoc.49 0.16 1. the design criteria are presented for the three different types of local extreme weather. (m/s) 0.3 1.4 9.27 Current and Associated Wave Data 3 m depth.32 0.49 0.51 0.3 Maximum Wave Period.49 0.02 3 m above seabed.27 0.56 0.42 0.04 0.74 1.11 1.6 5.8 6.69 0.35 3 m above seabed.77 1.42 0. Wave Height.3 9.09 1.85 1.75 0.2 9.5 14.8 Significant Wave Height.64 0. Sig.23 1. TABLE 3.32 1.51 0.2 1.77 Assoc.0 Peak Period.86 1.27 0. (m/s) 0.12 2.89 0.73 2.04 0.2 8.58 30 m depth. (m/s) 1.90 1 m above sea bed.44 0. Hm (m) 7.2 10.7 3 m depth.6 4.12 2.23 0.53 0. 2.1 2.41 1. Hs (m) 2.6 14.9 12.8 7.84 1.66 0.70 30 m depth.8 7.95 1.52 0.58 0.79 0.11 1.7 3.84 2. Current calculation for in between depths to be carried out by linear interpolation.79 0. (m/s) 0.31 0.76 1.8 2.29 1.62 0.1 10.49 0.5 13.34 0. (m/s) (1) 0.81 0.44 2.7 15.13 0. Tp (sec) 10.4 5.97 1. Any unauthorised attempt to reproduce it.27 1.66 1.82 0.76 0.73 0.81 2.02 1.09 0.49 0.5 13.82 1.4 7.1 Notes: th 1.33 0.3 9.9 12.86 1. Current velocity were calculated by 1/7 Power law at 3m depth. Hs (m) 3.66 0. .97 1. (m/s) 0.04 50 m depth.38 0.11 : WAVE AND CURRENT DATA FOR PIPELINE AT WHP-HT1 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. (m/s) 0. (m/s) 1.1 12.16 1.5 4.23 0. is strictly prohibited. (m/s) (1) 0.7 8.8 11.5 14. in any form.7 4.5 3.3 1.41 1.23 1.59 0.7 8.93 0.92 0.18 1.27 0.32 1 m above sea bed.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 25 of 67 : D2 The waves and currents data at WHP-HT1 is as presented in table below.44 0.96 1.48 2. Tm (sec) 10.56 0. (m/s) 1.22 0.0 12.9 3.66 0. This document is the property of BD POC.0 3.1 9.36 50 m depth.7 12. (m/s) 0. Tm (sec) 10.27 3 m above seabed.6 14.96 1.50 0.8 2.66 1.80 0.6 4.52 0.78 2.7 3 m depth.44 0.74 1.50 0.58 0. (m/s) 1.29 1.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 26 of 67 : D2 The waves and currents data at FSO-HT is as presented in table below.2 10.6 5.53 0.38 0.1 9. is strictly prohibited.32 0.0 12. Current calculation for in between depths to be carried out by linear interpolation.89 0.18 1.8 7.4 7.76 0.68 0.7 3.51 0.44 2.34 0.23 0.5 14.23 1.2 8.58 0. Hs (m) 3.70 30 m depth.13 0.02 1.7 8.81 2.82 0.57 0.8 Significant Wave Height.5 14. Hs (m) Notes: th 1. Sig.35 0.02 0.87 1.62 0.56 0.7 4.0 Peak Period. This document is the property of BD POC.85 1.24 0.86 1.69 0.5 13.97 1.13 1.52 0. (m/s) (1) Assoc. in any form. 2. TABLE 3. Any unauthorised attempt to reproduce it. (m/s) 1 m above sea bed.31 0.67 0.04 50 m depth.63 0.52 0.1 12.2 9. (m/s) (1) Current and Associated Wave Data 3 m depth.28 0. . Tp (sec) 10.41 1.8 7.3 1.1 2.29 0.8 11.44 0.3 Maximum Wave Period.5 4.81 0.27 0. (m/s) 0. (m/s) 0.79 0. (m/s) 1.4 9.3 9.09 1.48 2.0 3.12 2. Wave Height.1 3 m above seabed.11 1.59 0.93 0. Hm (m) 7.3 1.5 13.82 1.76 1.16 1.7 12.73 2.36 50 m depth.3 9.32 1.12 : WAVE AND CURRENT DATA FOR PIPELINE AT FSO-HT 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.91 0.97 1. Current velocity were calculated by 1/7 Power law at 3m depth.43 0.24 0.2 1. (m/s) 1 m above sea bed.28 1.49 0.76 0.41 1.23 1.5 3.32 0.84 1. (m/s) 1.33 0.9 12.7 15.09 0.9 3.97 1.4 5.04 0.12 2.1 10.8 6.84 2.66 0.06 0.94 0.79 1.74 0.58 30 m depth.7 8.9 12. (m/s) 0.44 2.62 0.5 13.42 0.1 3 m above seabed.4 7. Tm (sec) 10.41 1.16 0.8 7.8 7.3 9. Hs (m) Notes: th 1.8 Significant Wave Height. (m/s) 0. (m/s) (1) Assoc.7 8.94 1.69 0.2 9.2 8.74 1. (m/s) 1.38 0. 2.60 0.58 30 m depth. Tp (sec) 10.1 2.4 5.32 1.52 0.82 1.5 4.70 30 m depth.7 12. TABLE 3.31 0. Sig.13 : WAVE AND CURRENT DATA FOR PIPELINE AT NCSP WYE 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.85 1.4 9.3 1.9 3.27 3 m above seabed.65 0.6 4.97 1. Any unauthorised attempt to reproduce it.8 6.04 0.6 5.71 0.38 0.97 1. (m/s) 1 m above sea bed.48 2. in any form.76 1.7 15.5 13. (m/s) 1.76 0. Hm (m) 7.53 0.3 1.8 11.76 0.73 0. is strictly prohibited.5 14.66 1.83 1.56 0.35 0.17 1.81 2.26 0.29 1.52 0.33 0.87 1.80 1.32 0.32 0.91 0.0 3.49 0.18 1.84 2.22 0.9 12.06 1.9 12.30 0.1 10. (m/s) 0.82 0.96 1. Current calculation for in between depths to be carried out by linear interpolation.93 0.3 9.71 0. (m/s) (1) Current and Associated Wave Data 3 m depth.5 14.7 3 m depth.11 1.59 0.26 0.7 4.78 2.58 0. Wave Height.86 1.02 1. (m/s) 1 m above sea bed.44 0.66 0. Current velocity were calculated by 1/7 Power law at 3m depth.23 1. Hs (m) 3.12 2.1 9.7 3.12 2.02 0.7 8.36 50 m depth.49 0.0 12.03 0.23 1.62 0. (m/s) 1.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 27 of 67 : D2 The waves and currents data at NCSP Wye is as presented in table below.81 0.89 0.2 10.8 2.88 0.52 0.84 1.13 0.44 0.5 3.04 50 m depth.09 0.2 1.1 12.37 1.24 1.3 Maximum Wave Period.6 14.16 1. .73 2.79 0.36 0.34 0.41 1. This document is the property of BD POC.0 Peak Period. CL 0.0 3.9 Inertia.0 0.12. CI 3. Data is referred to Structural Design Basis [Ref.2 (2) 0. Data has been extracted from DNV RP E305. 10]. Cd 0. 3. TABLE 3. TABLE 3.4 Hydrodynamics Coefficients The hydrodynamic force coefficients presented below are for use in the calculation of quasi-static forces on pipelines resulting from fluid motion. The data will be revisited based on the lateral buckling work which will be performed by others.29 2.14 : HYDRODYNAMIC COEFFICIENTS Coefficient For Pipeline Section For Riser Section For BTS Section (3) Drag.8.7 (no marine growth) 1. (Where M = current velocity / wave velocity = Uc / Us). Hydrodynamic Coefficient for pipeline at BTS has been assumed to be the same as pipeline on seabed.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 28 of 67 : D2 3.2 (2) Lift. realistic CD value should be calculated.7 or 1. For sub-critical and critical flow regime Re < 3 x 105 and M ≥ 0. Density of marine growth is 1400 kg/m . in any form.5 Marine Growth The marine growth is presented below.15 : MARINE GROWTH PROFILE From EL (LAT) (m) To EL (LAT) (m) Thickness (mm) MSL -5 50 -5 -30 200 -30 -50 125 -50 -75 50 -75 Mudline 25 Notes: 3 1. This document is the property of BD POC.12.29 Notes: 1. 2. . is strictly prohibited. Any unauthorised attempt to reproduce it.9 0.0 (with marine growth) 0. 3.7 or 1. 2. The routing of this pipeline will be based upon the results of the geophysical survey [Ref. which may lead to occurrences of free span later on.0m. However. The crests of these features have an average height of less than 0. The sonar contacts should also be considered during anchor planning and handling.640 where the side slope has a maximum gradient of 1:160 (0. This document is the property of BD POC. 4] which included bathymetry.5m with varying wave lengths between 6. and poor to moderate anchor holding capabilities. The surveyed route is clear of any features that may impede pipeline installation activities. except for the seabed mound at KP 18.1 WHP-MT1 to WHP-HT1 The length of the pipeline between the WHP-MT1 and WHP-HT1 is approximately 20km.07º). The seabed sediments are expected to comprise of fine to medium sand which is expected to provide fair pipeline settling conditions. The closest sonar contact to the surveyed route is noted 101m South-East of KP 12. scouring may occur along the surveyed route due to the nature of the mobile sediments. This undulating seabed is due to the presence of the sand wave/mega ripples that are aligned in a NNE – SSW direction. The four survey reports [Refs.3m to 133.Title: Subsea Pipeline Design Basis 3.0m and 9. 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. side scan survey and sub bottom profiling. The routing of this pipeline will be based upon the results of the geophysical survey [Refs. in any form. . The seabed is generally dipping Eastwards with an average seabed gradient that does not exceed 1:800 (0. 6 and 7] which included bathymetry.130 to KP 18. 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.6m. The water depths along the surveyed Well Fluid route from WHP-MT1 to WHP-HT1 range from 115. The shallow geophysical surveys were completed in Q3 2008 and comprised analogue surveys and high resolution (HR) and ultra high resolution (UHR) surveys.13 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 29 of 67 : D2 Site Survey Data Site investigations were carried out following the shallow geophysical surveys in Q2 and Q3 2008.085. 3. The water depths along the surveyed condensate line route from WHP-HT1 to HT FSO range from 129m to 133m. 4 to 7] cover the platform sites and pipeline routes.4 km from the Hai Thach wellhead platform. is strictly prohibited. 3. Apart from this feature.4º) with an induced water depth change of 1.4m. side scan survey and sub bottom profiling.13.10°).2 WHP-HT1 to HT FSO The FSO will be located approximate 2. Any unauthorised attempt to reproduce it.13. The seabed within the survey area is undulating and generally dipping towards the ESE with a general gradient of 1:540 (0. The investigation was a mixture of sampling and piezocone penetration testing (PCPT) at the platform sites. At this location the NCS pipeline is laid upon the sea bed (not trenched) and it is coated with 50 mm of concrete coating. which results in a maximum side slope of 1:56 (1. This may cause scours around the pipeline that may develop into free spans in later stages. is strictly prohibited.14. indicating mobile sediments.7 to 3. This document is the property of BD POC. The soil conditions along this route consist predominantly of granular soils from seafloor to the final penetrations explored. The gas export line from Hai Thach will have to cross over the NCS pipeline. An elongated sonar contact which could be construction debris crosses the surveyed route at KP 44.0°).1 WHP-MT1 to WHP-HT1 Pipeline Route The fieldwork consisted of five boreholes to maximum depth ranging from 2. This will have to be investigated prior to construction. The length and routing of the pipeline is based upon the results of the geophysical survey [Ref. the HT TAD anchor locations and along the pipeline routes. 3. 3. Any unauthorised attempt to reproduce it. 8].6m.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 30 of 67 : D2 3.202.14 Soil Survey Data The geotechnical investigations were completed by Fugro Singapore Pte Ltd.3 WHP-HT1 to NCSP Wye Tie-In The approximate length of the pipeline between Hai Thach and the Wye is 44.890. Water depths within the survey corridor range from 99. 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. . The existing NCS pipeline and the Rong Doi pipeline that joins it should also be considered during anchor planning and handling.13.500 to KP 42. side scan survey and sub bottom profiling. Sand ripples and mega ripples are noted throughout the survey corridor.3 m along the Moc Tinh Platform to Hai Thach Platform surveyed pipeline route. The descriptions are presented in table below. 5] which included bathymetry.5 km. 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 FSO anchor locations. The effects of the bottom currents should also be considered during the final pipeline route design.2m to 134. The detail results of the pipeline route geotechnical investigations are provided in the Fugro reports [Ref. in any form. 18 : WHP-HT1 TO FSO BORE HOLE COORDINATES Bore Hole Name Easting (m) Northing (m) HT.5 - 3.6 Medium dense fine SAND with silt 8.04 TABLE 3.FSO.0 18.4 18.8 Medium dense fine SAND with silt 8.04 HT.0 18.1 - MT-HT. TABLE 3.35 881 703.02 This document is the property of BD POC.4 / 4a 267 900.16 888 418.60 886 501.36 MT-HT.98 MT-HT.7 Medium dense fine SAND with silt 8.14.4 18.5 34.0m located along the surveyed route. Any unauthorised attempt to reproduce it.1 / 1a 0.5 / 5a 0.46 890 240.3 - MT-HT.05 MT-HT.5 Medium dense to dense fine SAND 8.1 34.2 / 2b 262 236. in any form.3 / 3a 0.2 WHP-HT1 to FSO Pipeline Route The fieldwork consisted of two boreholes to maximum depth of 2. Wet Angle (deg) MT-HT.0 MT-HT.3 / 3a 265 898.1 / 1a 259 232. The soil conditions along this route consist predominantly of granular soils from seafloor to the final penetrations explored.16 MT-HT.04 889 999.2 / 2b 0.8 17.01 884 632.23 879 050.0 – 1.0 – 2.5 MT-HT.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 31 of 67 : D2 TABLE 3. is strictly prohibited.17 : WHP-MT1 TO WHP-HT1 SOIL DESCRIPTION Bore Hole Name Penetration (m) Soil Sample Description Unit Weight (kN/m3) Sub.FSO.95 Medium dense fine SAND with silt 7.16 : WHP-MT1 TO WHP-HT1 BORE HOLE COORDINATES Bore Hole Name Easting (m) Northing (m) MT-HT.85 and 3.4 / 4a 0.0 – 1. .0 – 2.5 / 5a 270 901.5 / 5a 270 233. The descriptions are presented in table below.0 – 2.6 / 6a 270 198. 0 – 1.13 902 114.1b /1a 264 350.14. The soil condition along this route consists predominantly of granular soils from seafloor to the final penetrations explored.2 18.5 / 5a 0.2 18.0 – 3.2m located along the Hai Thach Platform to NCSP Wye Tie-In surveyed pipeline route.1 HT-NCSP.6 / 6a 0.0 Soil Sample Description 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 Unit Weight (kN/m3) Sub Wet Angle (deg) 8.41 HT-NCSP.45 HT-NCSP.FSO.7 to 3.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 32 of 67 : D2 TABLE 3.01 903 998.0 – 2.4 - 10. .8 - This document is the property of BD POC.76 HT-NCSP.0 HT.1 30.5 HT-NCSP.6 17.3 / 3a 0.2 / 2a 257 519.5 8.0 – 1.62 893 500. Wet Angle (deg) HT. is strictly prohibited.0 – 1.6 - 7.6 Medium dense fine SAND with silt 8. Any unauthorised attempt to reproduce it.0 8.21: WHP-HT1 TO NCSP WYE TIE-IN SOIL DESCRIPTION Bore Hole Name Penetration (m) HT-NCSP.2 / 2a 0. The descriptions are presented in table below.3 / 3a 248 143.4 / 4a 240 048.1 36.4 18.0 19.9 Medium dense fine SAND 8.8 18.95 HT-NCSP.4 18.01 HT-NCSP.96 HT-NCSP.20 : WHP-HT1 TO NCSP WYE TIE-IN BORE HOLE COORDINATES Bore Hole Name Easting (m) Northing (m) HT-NCSP.6 / 6a 232 001. TABLE 3.0 – 2. in any form.6 / 6a 0.19 : WHP-HT1 TO FSO SOIL DESCRIPTION Bore Hole Name Penetration (m) Soil Sample Description Unit Weight (kN/m3) Sub.3 WHP-HT1 to NCSP Wye Tie-In Pipeline Route The fieldwork consisted of six boreholes to maximum depth ranging from 2.75 898 700.0 3.9 33.7 HT-NCSP.FSO.0 18.1b /1a 0.0 – 2.60 TABLE 3.4 32.6 HT-NCSP.4 / 4a 0.0 – 1.6 - 8.5 / 5a 0.93 895 698.5 / 5a 237 545.54 901 302. and chlorine. the fluid category is described in table below.23 : CORROSION ALLOWANCE PHILOSOPHY Description 3. ethane. ammonia.15 Corrosion Allowance Philosophy The corrosion allowance philosophy used in design analysis is summarised in table below. This document is the property of BD POC. 3. Any unauthorised attempt to reproduce it. is strictly prohibited. ethylene. As per DNV RP E305. 23]. Typical examples would be hydrogen. TABLE 3. in any form. 2.16 Corrosion Allowance Utilisations (%) Weight Based Analysis 50 Stress Based Analysis 100 Fluid Classification Fluid to be transported shall be categorised according to their hazard potential as per Section 2. natural gas (not otherwise covered under category D).14.24 : CLASSIFICATION 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.6 Notes: 1.4 Soil Friction Coefficient The soil friction coefficients used in on bottom stability analysis are as presented below. liquefied petroleum gas (such as propane and butane).7 Pipeline Longitudinal Stability (2) 0. The above soil friction will not be applicable for lateral buckling analysis.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 33 of 67 : D2 3. TABLE 3. natural gas liquids. For BDPOC pipeline. C201 of DNV OS F101). TABLE 3. . The soil friction for lateral buckling analysis will be defined as part of the lateral buckling design.22 : SOIL FRICTION COEFFICIENT Description Value Pipeline Lateral Stability (1) 0. As per Lateral Buckling Design Basis [Ref. TABLE 3. .26 : USAGE FACTORS Safety Class Usage Factor ( η ) Low 1.80 This document is the property of BD POC.90 High 0. TABLE 3.18 Location Class (Fluid Category E) Class-1 Class-2 Normal High Low Low Design Factors The allowable stress design factors for Location class -1 and Location class -2 shall be based on Table 5.25 : CLASSIFICATION OF SAFETY CLASSES Phase Operational Installation / Hydrotest 3.00 Normal 0. is strictly prohibited. Any unauthorised attempt to reproduce it. C402 of DNV OS F101 and detailed below.17 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 34 of 67 : D2 Safety Classes The safety class for the pipelines and risers is determined as per Section 2.Title: Subsea Pipeline Design Basis 3. in any form.14 of DNV OS F101 and are defined in respective sections of analysis. 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. valves. Pipeline crossing analysis is needed if the pipeline has to cross existing unburied pipeline. include the following: • Environment (archaeology. The pipelines. 8]. unstable seabed. existing pipelines and cables) • Third party activities (ship traffic. soft sediments. subsea structure. 4 to 7]. The pipeline route shall be selected with due regard to safety of the public and personnel. marine parks. seismic activity) • Facilities (offshore installations. Pipeline ends are to be designed with a reasonable straight length ahead of the target boxes.Title: Subsea Pipeline Design Basis 4. flexible pipelines and cable were therefore routed to avoid unfavourable seabed areas. subsea cable and umbilical route shall be selected based on the findings detailed by the survey reports [Refs. dumping area. lay method. thereby offering the most economically attractive option. This document is the property of BD POC.g. 3rd party requirements) • Pipeline components (e. Agreement with relevant parties should be sought as early as possible. lay direction and existing / planned infrastructure. Any unauthorised attempt to reproduce it. tees) in particular should not be located on the curved route sections of the pipeline. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 35 of 67 : D2 PIPELINE / CABLE ROUTE SELECTION The proposed pipeline. Curvatures near pipeline ends should be designed with due regard to end terminations. mining and military exercise. in any form. turbidity flows) • Seabed characteristics (uneven seabed. and the probability of damage to the pipe or other facilities [Ref. fishing activity. Factors to take into consideration shall. . protection of the environment. at minimum. The pipelines. is strictly prohibited. 17].Title: Subsea Pipeline Design Basis 5. Any unauthorised attempt to reproduce it. Nuts and Gaskets Tie-in Skid Small size piping This document is the property of BD POC. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 36 of 67 : D2 MATERIAL SELECTION AND PROCUREMENT PHILOSOPHY The pipeline material selection philosophy is detailed in the Pipeline Material Selection Report [Ref. Table below summarises the applicable material codes and specifications used for this project. is strictly prohibited. Material Table 5. .1 : SUBSEA PIPELINE material codes and specifications Company Design Codes / Standards Remarks Specifications 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 Company Procured Long Lead Item Induction Bends DNV OS F101 + ISO 15590-1 BD-00-L-S-0005 Company Procured Long Lead Item - BD-00-L-S-0006 Company Procured Long Lead Item DNV RP F106 BD-00-L-S-0007 BD-00-L-S-0015 BD-00-L-S-0018 BD-00-L-S-0021 Company Procured Long Lead Item Concrete Coating - BD-00-L-S-0008 Company Procured Long Lead Item SPU Half Shells - BD-00-L-S-0009 Company Procured Long Lead Item Sacrificial Anode ISO 15589-2 + DNV RP F103 BD-00-L-S-0008 BD-00-L-S-0010 Company Procured Long Lead Item Subsea Flanges DNV OS F101 + ISO 15590-3 BD-00-L-S-0004 Company Procured Long Lead Item Subsea Fittings DNV OS F101 + ISO 15590-2 BD-00-L-S-0025 Company Procured Long Lead Item Subsea Valves ISO 14723 BD-00-L-S-0003 Company Procured Long Lead Item SSIV Actuator & HPU - BD1-00-L-S-0020 Company Procured Long Lead Item ISO 13628-5 BD1-00-L-S-0021 Company Procured Long Lead Item ISO API 17J + API RP 17B + DNV OS F201 - Company Procured Long Lead Item ASTM A193 / ASTM A194 - To be procured by Fabricator / OIC ASTM A106 / API 5L PSL2 (for 4” and above) - To be procured by Fabricator Insulation Coating Corrosion Coating SSIV Umbilical Flexible Pipelines Bolts. in any form. 9 BD-00-P-S-0001 Company Procured Long Lead Item Topside Valves API 6D BD-00-P-S-0003/ BD-00-I-S-0006 Company Procured Long Lead Item Hot Induction Bends To be procured by Fabricator Scraper Trap Fabrication Welding as per DNV OS F101/ ASME B31.3 + ASME B16.3 + ASME B16.2 : TOPSIDE PIPELINE MATERIAL CODES AND SPECIFICATION Material Design Codes / Standards Company Specifications Remarks CS Line Pipe DNV OS F101 + ISO 3183/ ASME B31.Fittings ASME B31.3Note 1 BD-00-P-S-0001/ BD-00-L-S-0001 Company Procured Long Lead Item -Major Barrel ISO 3183+DNV OS F101/API 5L/ ASME B31.9 BD-00-P-S-0001 To be procured by Fabricator .QOEC Note: 1. in any form.9 BD-00-P-S-0001 Company Procured Long Lead Item Barred/Sphere Tees ASME B31. is strictly prohibited.3Note 1 BD-00-P-S-0001/ BD-00-L-S-0005 Company Procured Long Lead Item Flanges ASME B31.3 is the design code for topside piping/bend which will be connected to flexible pipeline.3 + ASME B16.5 BD-00-P-S-0001 To be procured by Fabricator .3Note 1 BD-00-P-S-0001/ BD-00-L-S-0001 Company Procured Long Lead Item ASME Section VIII Div. D2 ASME B31.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 37 of 67 : D2 Tie-in Skid Small size flanges and fittings ASTM A105 - To be procured by Fabricator Concrete Mattress and Uraduct - - To be procured by OIC D2 TABLE 5.3Note 1 BD-00-P-S-0001/ BD-00-L-S-0001 Company Procured Long Lead Item CRA Clad Line Pipe API 5L C + DNV OS F101 BD-00-P-S-0001/ BD-00-L-S-0002 Company Procured Long Lead Item Solid CRA Pipe API 5L C + DNV OS F101 BD-00-P-S-0001 Company Procured Long Lead Item ISO15590-1 + DNV OS F101/ ASME B31. This document is the property of BD POC.Flanges ASME B31.3 + ASME B16.5 BD-00-P-S-0001 Company Procured Long Lead Item Fittings ASME B31.3 + ASME B16. D2 . Any unauthorised attempt to reproduce it.3Note 1 -Minor Barrel ISO 3183 + DNV OS F101/ ASME B31. 1 BD-00-M-S-0341 Company Procured Long Lead Item . . 20] and DI-BD1-0003 [Ref. is strictly prohibited. DI-BD1-0015 [Ref.1 : PRECUREMENT SCOPE BREAK This document is the property of BD POC. Any unauthorised attempt to reproduce it. FIGURE 5. in any form. Refer to Design Instruction No. 21] for details. DI-BD1-0012 [Ref.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 38 of 67 : D2 The figure below gives the scope demarcation for material procurement for the pipeline system. 19]. or = t – tfab – tcorr (operational condition) 6. The details of the analysis are described in the following sections.2 t = nominal thickness (required thickness) tfab = fabrication thickness tolerance tcorr = corrosion allowance thickness γsc = safety class resistance factor γm = material resistance factor Local Buckling Local buckling implies gross deformation of pipe cross section. Any unauthorised attempt to reproduce it.1 Pressure Containment (Bursting) The pressure containment check shall be performed for operating and hydrotest pressure conditions. or during operating phase when depressurization is required for maintenance or emergency. It could occur during installation phase (new pipe) when the pipeline is empty. . Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 39 of 67 : D2 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. Constant ID based philosophy is implemented on all Bien Dong pipelines. 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 − Pp 2 ) = Pc Pel Pp f o D / t Where. Pc = characteristic collapse pressure Pel = elastic collapse pressure This document is the property of BD POC. in any form. 6.Title: Subsea Pipeline Design Basis 6. is strictly prohibited. It shall fulfill the following criteria as stated in section 5 D200 of DNV OS F101:- Pli − Pe ≤ Pb (t1 ) 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). 5 Utility = Peγ mγ sc ≤ 1. αfab = fabrication factor This document is the property of BD POC. The propagating buckle pressure is taken as :- Ppr = 35 f yα fab (t 2 D ) 2. Any unauthorised attempt to reproduce it. propagating buckle will be started and continue whenever the external pressure is higher than Propagating Pressure. 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.005) Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 40 of 67 : D2 The external pressure at any point along the pipeline shall meet the following criteria:- Utility = Pe (1. If buckle occurs and Pe exceeds Initiation Pressure. 6. Pe is less than the collapse pressure. unless the external pressure is lesser than it.1γ mγ sc ) ≤ 1 (Safe against collapse) Pc Further to this. Pinit which is subject to size of the initial buckle.Title: Subsea Pipeline Design Basis Pp = plastic collapse pressure t2 = pipe wall thickness (installation phase) fo = ovality (>0.0 (Safe against propagating buckling) Ppr Where. . in any form.3 Pmin = minimum internal pressure of pipe (assumed as 0) t = minimum required wall thickness Propagation Buckling 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. is strictly prohibited. Ppr. However.γ SC ⎝ D ⎠ where: fy = 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 . 7. Pe = hρg where: 7.2 h = water depth (m) ρ = seawater density (kg/m3) g = gravitational acceleration (m/s2) Propagation Pressure The buckle propagation pressure. in any form.5 ⎜ ⎟ γ m .tcorr t = Nominal wall thickness of pipe tcorr = Corrosion allowance D = Nominal Diameter of pipe This document is the property of BD POC.Title: Subsea Pipeline Design Basis 7.α fab ⎛ t 2 ⎞ 2 . Ppr is defined as : Ppr = 35 . is strictly prohibited. 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.1 External Hydrostatic Pressure The external hydrostatic pressure (Pe) is calculated using the formula stated below. . Any unauthorised attempt to reproduce it. The equations used to perform the calculations are summarized below. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 41 of 67 : D2 BUCKLE ARRESTOR DESIGN The buckle arrestor design methodology is in accordance with the recommendations of Langner [Ref. 16]. f y . Ppr = (Pa . Any unauthorised attempt to reproduce it. 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) = 35 .3 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 42 of 67 : D2 Crossover Pressure The buckle arrestor is designed to the highest pressure at which a propagating collapse failure will be stopped.γ SC ⎝ D i + 2 t b ⎞ ⎟⎟ ⎠ 2 .5 tnom = pipeline nominal wall thickness (mm) Do = pipeline outside diameter (mm) fy = 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 ) Other parameters have previously been described.Title: Subsea Pipeline Design Basis 7.α fab ⎛ tb ⎜⎜ γ m . in any form.Ppr ) [1 .exp(-20 tnom L/ Do 2 )] where: Ppr = buckle propagation pressure. is strictly prohibited. The propagating collapse failure contained in a given buckle arrestor due to the pressure is called the crossover pressure. . This document is the property of BD POC. The crossover pressure for the integral-ring buckle arrestor (Px) is predicted by using the following formula. f y . Px . 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 This document is the property of BD POC. 8. the main factors influencing the final coating performance are adhesion. For this project.8. flexibility. PP or insulation coating can be higher since the coating is not directly in contact with seawater. . is strictly prohibited. the following corrosion coatings will be considered for the pipeline corrosion coatings. The detail recommended pipeline external coatings for individual pipelines are presented in Section 3.1 : 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. chemical and physical stability. 8. insulation coating will be used to keep the fluid temperature above the wax appearance temperature (WAT). cathodic disbanding resistance. Anti-corrosion coating materials selected shall suitable for marine environmental conditions and the selection is based on the design temperature of the pipeline. ease of application and weathering resistance. cohesion. However. TABLE 7. in any form. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 43 of 67 : D2 COATING SELECTION The primary means of preventing external corrosion for the pipelines and risers will be by the use of anti-corrosion coatings. The maximum operating temperature is recommended for stand alone FBE coating.Title: Subsea Pipeline Design Basis 8. electrical resistance. 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. maximum temperature recommended for FBE coated together with PE. The anti-corrosion coatings for the field joints will consist of a heat shrink sleeve or a self-adhesive tape.2 Insulation Coating For the well fluid and condensate lines. moisture absorption. However.1 Pipeline / Riser Corrosion 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. impact resistance. Any unauthorised attempt to reproduce it. . Heat Shrink Sleeve coating will be considered. 8.3 Pipeline / Riser Field Joint Coating For field joints.5 Multi Layer Polypropylene (MLPP) 50mm 3. 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. Any unauthorised attempt to reproduce it. Infill materials should consists of polymer concrete. 2. 3. is strictly prohibited.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 44 of 67 : D2 Insulation coating type and thickness will be established in consultation with the coating Contractor based on the U value recommended by flow assurance group. Corrosion resistant alloy (CRA) (such as Monel) for temperature above 120˚C.8 Syntactic Polyurethane (SPU) 46mm 4. 1. For the insulated pipeline. the following guideline will be used in selecting the splash zone coating. Chlorinated Rubber (CR) polychloroprene (also known by the trade name Neoprene)] elastomer coatings for temperature up to 90˚C. marine mastic or polyurethane foam. This document is the property of BD POC.5 Multi Layer Polypropylene (MLPP) 70mm Note: 1. 8.4 Pipeline Field Joint Infill 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. 2.1 : U VALUE AND INSULATION COATING DATA U Value (W/m2K) Note-2 Insulation Coating Thickness (1) 2. The final insulation thickness shall be determined by the Coating Manufacturer based on U value. pre-formed solid half shells of Syntactic Polyurethane or polypropylene foam injection will be used as infill insulating material. 8. Listed below is the U value recommended by flow assurance and the selected insulation coating and thickness for the 12 inch Well Fluid Pipeline. Ethylene Propylene Diene Monomer (EPDM) elastomer coatings for temperature above 90˚C and up to 120˚C. U value shall be calculated based on ID of pipeline.5 Splash Zone Coating For riser splash zone protection. TABLE 8. in any form. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 45 of 67 : D2 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.Title: Subsea Pipeline Design Basis 9. 9. Pipeline shall also be checked for vertical stability by determining the pipe sinkage and flotation. Pipeline stability analysis on BTS shall be revisit as part of the lateral buckling design performed by others.2 Hydrodynamic Force Computation 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. Pipe stability will be achieved by increasing the pipe wall thickness with no concrete weight coating provided to minimise the pipeline stiffness. in any form. is strictly prohibited. Any unauthorised attempt to reproduce it. This document is the property of BD POC.1 Design Criteria (Lateral Stability) 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. respectively. The direction of current and wave shall be considered as acting perpendicular to the pipeline. Simplified static analysis method as per DNV RP E305 shall be used. The most unfavourable combination of simultaneously acting vertical and horizontal forces on the pipeline shall be considered. was used for the installation and operation case. . Separate stability analysis shall be performed for pipeline on Buckle Trigger Structure (BTS) for the 12 inch Well Fluid Pipeline (PL-BD1). 9. The minimum practical thickness of concrete coating is taken as 40mm. D. The program finds the worst combination of force against horizontal stability until a minimum value of safety factor is obtained.C L . (U s + U c ).Title: Subsea Pipeline Design Basis 9. in any form. minimum 1. .FL ⎤ Ws = ⎢ D ⎥ μ ⎣ ⎦ Where: Ws = Submerged weight of pipe.3.ρ w .3 Method of Analysis 9.D. As = Significant wave-induced water particle horizontal acceleration perpendicular to pipeline D = Outside diameter of the pipeline (including coatings) 1 2 = . Any unauthorised attempt to reproduce it. As 4 1 = .ρ w . is strictly prohibited.C M .(U s + U c ) 2 This document is the property of BD POC.1 μ = Soil friction factor in lateral direction = 0.π . The required submerged weight of the pipeline is given by: ⎡ ( F + FI ). • Relating the velocities and accelerations to the horizontal stability. FS = Factor of safety. Uc = Current velocity perpendicular to the pipeline integrated over the pipeline overall diameter.ρ w .(U s + U c ) 2 1 .D 2 . The hydrodynamic forces and the safety factor are then calculated.1 Lateral Stability Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 46 of 67 : D2 The calculation is essentially carried out in two parts as follows: • Derivation of wave and current velocities and wave-induced acceleration.Fs + μ.6 FL = Lift Force FI = Inertia Force = FD = Drag Force 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. The wave-induced velocities are derived using the appropriate wave theory.C D . 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.B. the settlement depth ( z ) can be calculated. .5. The pressure exerted by the pipeline on the soil is given by the following equation: σ pipe = Ws B Where: Ws = Submerged Weight of the Pipeline (N/m) B = Contact Area Width between Pipeline and Soil (m) = D z ( 2.z − z 2 ) 1 2 for z < D 2 = Diameter of Pipeline (including coatings) (m) = Settlement Depth (m) The ultimate bearing capacity of the soil is given by the Terzaghi Equation as follows: q f = 0. in any form.1 times the required submerged weight ( Ws ) defined above. N c = Bearing Capacity Factors By equating σpipe and qf .3.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 47 of 67 : D2 For the pipeline to be stable. Any unauthorised attempt to reproduce it. the actual submerged weight of the pipeline must be minimum 1. is strictly prohibited.N c Where: = Undrained Shear Strength of the Soil (N/m2) Su γ = Submerged Density of Soil (N/m3) Nγ .γ . D. This document is the property of BD POC. 9.N γ + Su . 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.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. This document is the property of BD POC. The lateral buckling design shall ensure that the pipeline end expansion will not exceed the specified maximum end expansion. subject to thermal and pressure expansion forces. Any unauthorised attempt to reproduce it. The strain components for the free-fixed or free-free pipeline are εT. εP. The logarithmic has been used in this expansion analysis. The stresses acting in the pipeline wall resulting from the operating loads and friction resistance depend on whether the pipeline is unrestrained. 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. the pipeline end expansion will be limited to the maximum expansion that the riser and expansion spool can accommodate.1 Pipeline End Expansion Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 48 of 67 : D2 CS Pipeline end expansion analysis will be performed to evaluate the magnitude of displacement and virtual anchor length in operating and hydrotest conditions. is strictly prohibited. Requirement for expansion offset will be assessed based on the calculated expansion. partially restrained or fully restrained. The methodology used in estimating the pipeline end expansion is based on the first principle of stress-strain relation. Tx = Tref + (Tmax − Tref )10 − βx 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. .Title: Subsea Pipeline Design Basis 10. LAHOT = Virtual anchor point at hot end LACOLD = Virtual anchor point at cold end However. which presents a more realistic modelling of the temperature distribution. in any form. εS. PIPELINE EXPANSION 10. for Well Fluid Pipeline (PL-BD1). ε TOT = εT + ε P + ε S =0 The longitudinal strain in the pipeline due to temperature gradient εT is given by the following formula:- εT = σ (Ti − Tref ) The thermal strain in the pipeline is calculated based on the difference between the pipeline temperature and the ambient temperature. initiated e. Based on Hobbs. is strictly prohibited. which are given in the formula below: Feff _ axial = k1 ⋅ EI Llat 2 2 5 0.5 ⎧⎪⎡ ⎫⎪ Astc ⋅ E ⋅ μ lat ⋅ Ws ⋅ Llat ⎤ + k 3 ⋅ μ ax ⋅ Ws ⋅ Llat ⎨⎢1 + k 2 ⎥ − 1⎬ μ ax ⋅ ( EI ) 2 ⎥⎦ ⎪⎩⎢⎣ ⎪⎭ This document is the property of BD POC. As the pipeline buckles. and the likelihood of buckling occurring elsewhere in the pipeline is reduced. the relationship between effective axial force and the buckle length depends on several parameters. the compressive load is decreased. 9]. in any form.2 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 49 of 67 : D2 Initial Lateral Buckling Assessment The preliminary assessment to determine the susceptibility of all pipelines to experience lateral buckling is performed based on the guidelines given by Hobbs [Ref. but in practice it is not likely to occur laterally. this form of buckling is unlikely to occur. Mode 3 and Mode 4 are the possible potential configurations that will form when buckling occurs. . The remaining modes. FIGURE 9.1: LATERAL BUCKLING MODE SHAPES The first mode is the same as a vertical buckle. Based on Hobbs. Again. It requires concentrated lateral forces at each end of the buckle for equilibrium. Any unauthorised attempt to reproduce it.1. the pipeline can buckle laterally in several ways as indicated by Figure 9. by a misalignment in a weld. The final "continuous" mode shows the pipeline buckling into a continuous series of half waves.Title: Subsea Pipeline Design Basis 10. 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.g. which cannot be generated by lateral friction alone. Mode 2. • Mitigation assessment. The assessment shall include the followings: • Post buckling assessment. 23]. in any form.3 Constants for buckling Mode (-) Llat Lateral buckling length (m) EI Pipe bending stiffness (Nm2) μ ax Axial friction coefficient (-) μlat Lateral friction coefficient (-) Ws 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. Mitigation measures should be considered if the buckling results in significant feed-in and high local bending moments/strains exceeding the design criterion. is strictly prohibited. .Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 50 of 67 : D2 Where: k1. The mitigation measures may include options such as snaked lay configuration. Any unauthorised attempt to reproduce it. rock berm. further assessment which shall be fully in accordance with the requirement of DNV RP F110. This document is the property of BD POC. If lateral buckling does occur. This is to determine that the resulting bending moments in the “snaked” configuration must be demonstrated to be acceptable. or partial burial to laterally restrain the line. 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”. Global Buckling of Submarine Pipeline shall be performed. 2. Detailed lateral buckling mitigation analysis methodology is covered in Lateral Buckling Design Basis [Ref. 1 [Ref. U c . Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 51 of 67 : D2 FREE SPAN ASSESSMENT The maximum allowable free span lengths for pipeline and risers were determined using verified inhouse software based on DNV RP F105.1 year = Significant 1-year return period value for the wave induced flow velocity at the pipe U c .CF γ CF > f n . VRCF .1 [Ref.onset = In-line onset value for the reduced velocity The cross flow natural frequencies f n . U w.onset = Cross-flow onset value for the reduced velocity. the in-line natural frequencies f n . in any form. 3]. is strictly prohibited.Title: Subsea Pipeline Design Basis 11. pipeline / riser free span should passing both criteria as listed below unless span intervention detailed analysis were done: 11. The maximum allowable dynamic span length will be based on fulfilling the both in-line and crossflow onset criteria above. IL must fulfil f n . Table 2. α = Current flow ratio = D = Outer pipe diameter including coating.onset * D Where γ CF = Screening factor for cross-flow.1 year VRCF .100 year + U x .1 • Dynamic Screening RP F105 / Fatigue F105 • Static Check (ULS) RP F105 and OS F101 Dynamic Screening Analysis As per DNV-RP-F105. 3].100 year = 100-year return period value for current velocity at the pipe level.100 year ⎛ L / D ⎞ 1 * ⎜1 − ⎟* 250 ⎠ α VRIL. Any unauthorised attempt to reproduce it. . Table 2. IL γ IL > U c .onset ⎝ Where γ IL = Screening factor for in-line. VRIL. This document is the property of BD POC.1 year + U c .100 year U w.100 year level corresponding to the annual significant wave height Hs.CF must fulfil U c . According to the DNV RP F105. . the static bending moment is estimated based on Section 6.Title: Subsea Pipeline Design Basis 11. M static = C5 q * L2eff ⎛ S eff ⎜⎜1 + Pcr ⎝ ⎞ ⎟⎟ ⎠ Where q = loadings i. 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 Seff = 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. 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 As = Pipe steel cross section area Ai = 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.e. This document is the property of BD POC. The static bending moment is estimated as below. is strictly prohibited. Any unauthorised attempt to reproduce it. in any form.2 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 52 of 67 : D2 Static Analysis (ULS) As for the maximum allowable static span length. The effective axial force is calculated as below.7 of DNV RP F105. Pipeline expansion has to be considered at crossing location. Any unauthorised attempt to reproduce it. This document is the property of BD POC. 12. Pipeline expansion has to be considered at crossing location. In the crossing analysis. Concrete sleepers. 12. The proposed pipeline should generally cross the existing pipelines at 90° angle and wherever possible the crossing angle shall not be reduced below 30°. . Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 53 of 67 : D2 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. 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. 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. 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.Title: Subsea Pipeline Design Basis 12. 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.1 Design Criteria The vertical clearance between the existing and the new pipeline shall be 300mm minimum. 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.2 Design Cases The finite element program AutoPIPE. is strictly prohibited. in any form. Pipeline configuration shall satisfy the design criteria detailed below. Horizontal clearance between the outermost edge of installed grout bag / steel structure / concrete mattress supports and existing pipeline shall be minimum 500mm. The pipeline crossing stress analysis is performed for a sufficient length of pipeline on either side of the crossing centerline. Any unauthorised attempt to reproduce it. a) Check the pipeline spans for allowable spans at the crossing location. 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.Title: Subsea Pipeline Design Basis 12. If necessary. operational and hydrotest conditions. 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.2 above. in any form. The order of analysis is broadly outlined below. This document is the property of BD POC.3 Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 54 of 67 : D2 Analysis Methodology The pipeline crossing configurations shall be checked against stress criteria described in 12. is strictly prohibited. For pipeline bracelet anodes that are mounted flush with a concrete coating. 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. an inner liner temperature resistant material is needed. However. The anode dimensions shall be sufficient to meet the required current demand at the end of the design life. the mean current demand (Icm) and the final current demand (Icf) shall be calculated separately from equation below:- I c = πOD p × L p × f c × ic Where Ic = Current demand for a specific pipeline section (A) ic = Current density (A/m2) fc = Coating breakdown factor. Maximum operating temperature for anode material is 80˚C. Anode spacing shall be 10 joints (120m) maximum. the thickness of the concrete coating layer shall be taken into account when determining the overall dimensions of the anode.5 × b × DesignLife] Final coating breakdown factor. This document is the property of BD POC.Title: Subsea Pipeline Design Basis 13. . anode will be installed on the insulation coating for the 12 inch Well Fluid Pipeline (PL-BD1). Therefore. The spacing between anodes shall be determined once the number of anodes has been calculated.1 Current Demand Calculation From the pipeline dimensions and the coating selected. For anodes facing with temperature above 80˚C.1. Fm = a + [0. the need for neoprene is not anticipated. Any unauthorised attempt to reproduce it. for this project. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 55 of 67 : D2 CATHODIC PROTECTION ANALYSIS Cathodic protection shall be provided by sacrificial anodes (bracelet half-shell type) designed in accordance with ISO 15589-2 and DNV RP F103. Mean coating breakdown factor. the use of 10mm neoprene coating liner is recommended. 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. For this. is strictly prohibited. F f = a + [b × DesignLife] The mean coating breakdown factor. 13. The anode spacing shall be close enough to maintain an adequate protection in the event of mechanical or electrical loss of a single anode. in any form. in any form. If.002 0. The final dimensions and net mass of the individual anodes can be calculated using the formulae given below:- M = n Ma Where.002 0. the number of anodes.0005 Multilayer PE / PP + Concrete 0.2 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:- I cm × t dl × 8760 μ ×ε M = 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. 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.002 0.1: RECOMMENDATION FOR COTING BREAKDOWN FACTOR Pipeline and Field Joint Coating a b Asphalt / Coal Tar Enamel + Concrete 0.0001 Thermal Insulation System 0. As per ISO 15589-2 for pipeline and as per Design Basis for field joint. their dimensions and net mass shall be determined in order to meet the estimated mean and final current requirements for protection of the pipeline. .01 0. Any unauthorised attempt to reproduce it.0001 Note: 1.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 56 of 67 : D2 TABLE 13. is strictly prohibited. 13.0001 Field Joint Coating 0. shall be calculated from following equation:- If = I cf n This document is the property of BD POC. sufficient anodes shall be installed at the last few pipeline joints to protect the riser. • Effects on flow velocity due to adjacent jacket legs are ignored. In case vortex-induced resonant oscillation in in-line direction occurs.1 Riser Spans Assessment 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. Tie-in of expansion loop/ dog leg to riser and subsea pipeline shall be via subsea flange tie-in. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 57 of 67 : D2 RISERS AND TIE-IN SPOOL DESIGN The riser will be preinstalled within the jackets. Any unauthorised attempt to reproduce it. The intermediate guide clamps positioned along the platform in consideration of vortex shedding effect shall be located to allow the riser to move longitudinally. 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 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.Title: Subsea Pipeline Design Basis 14. This document is the property of BD POC. No insulation joint will be provided between the riser and topside piping system. All risers shall be protected by pipeline’s cathodic protection system. 30. 14. Therefore. is strictly prohibited. . 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. • The bottom span is considered as the span from the bottom guide clamp to the mudline (seabed). it shall be checked for fatigue. in any form.5. 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. TABLE 14. The structural integrity of each riser/spool shall be verified for the critical combination of functional and environmental load and hydrotest conditions.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 58 of 67 : D2 The relevant partial safety factors applied to riser spans are presented in table below. in any form. is strictly prohibited. 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.15 Safety Factor on Stability . Any unauthorised attempt to reproduce it.1 : SAFETY FACTORS . All risers shall be classified as high safety class. 14. 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 This document is the property of BD POC. Increased flow velocities observed due to flow around the riser shall be considered where appropriate.γF 1.2 Riser Stress Analysis All risers and spool pieces including the tie-in spools at subsea tie-in end shall be designed to DNV Location class-2. Interaction and solidification effects shall be addressed where appropriate.30 Safety Factor on Stress . .γS 1.30 Fatigue Analysis Usage Factor 0.25 Note: 1. These include:• Dead load (weight of pipe. Structural damping of 2% (based on API RP 2A) shall be considered for dynamic analysis.γK 1. AutoPIPE Software.RISER SPAN DYNAMIC ANALYSIS Safety Factor Riser Safety Factor (1) Safety Factor on Natural Frequency . is strictly prohibited.5. in any form. 0.8 for high) fy = characteristic yield strength Subsequently. f y σ l ≤ η.2 : ALLOWABLE STRESS CRITERIA Allowable Stress (% fy) Load Combinations Class 1 Load Conditions A B C D E F G Operating Case X X X X X X X Hydrotest Case X X X X X Abbreviations:A: Gravity B: Design Temperature C: Design Pressure D: Platform Movement Long. Any unauthorised attempt to reproduce it. 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. f y Where. 1 and Roark’s Formula for Stress & Strain requirements [Ref. 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. Subsea flange stress analysis is carried out in accordance with ASME VIII Div. . This document is the property of BD POC. Stress Von Mises Stress 90 90 80 80 100 100 100 100 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. The allowable stress criteria are summarized in table below. TABLE 14. Waves and currents are assumed to be collinear and uni-directional.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 59 of 67 : D2 For the operating condition. 1 code and flange size is per ASME B16.3 H X Class 2 Long. Wind loading is negligible compared to the wave loads. 0. Stress Von Mises Stress Long.: Longitudinal 14. σe = equivalent stress σl = Longitudinal stress η = usage factor (1 for safety class low. These additional design checks which are not covered by AutoPIPE will be performed using INTECSEA’s in house calculation sheet. 15]. Allowable Stress Design simplified criteria as given in section 5 F202 of DNV OS F101 shall be used:- σ e ≤ η.9 for normal. PIPELINE. Any unauthorised attempt to reproduce it. 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. Abandonment and Recovery Analysis was performed based on the maximum water depth along the pipeline / subsea cable route. Pipeline Start-up 2. The analysis will be carried out for the following cases: 1. .A.2 Strain Based Analysis To provide non linear strain analysis. This is to confirm the installability of all the pipelines. Basis for maximum water depth calculation for the installation analysis shall be maximum water depth along the pipeline route + H.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 60 of 67 : D2 15. Pipeline weight shall be based on air filled condition (empty). in any form. The Ramberq-Osgood Equation is of the form : ⎛ M K M = + A×⎜ ⎜M Ky My ⎝ y ⎞ ⎟ ⎟ ⎠ B Where. is strictly prohibited. Local buckling checks shall also be performed as per DNV OS F101 3.1 Installation Analysis The preliminary pipelay analysis was carried out by utilizing the commercially available finite element program OFFPIPE. Pipeline Normal Lay. A&B = Ramberg-Osgood coefficient factor K = 1 / R (R =stinger radius) Ky = Pipe Curvature at Nominal Yield Stress 2σ y ⎞ ⎛ ⎜⎜ K y = ⎟⎟ ED ⎝ ⎠ This document is the property of BD POC.T + Storm Surge. 15. FLEXIBLE PIPELINE AND SUBSEA CABLE INSTALLATION 15. Any unauthorised attempt to reproduce it. .1 : OFFPIPE DEFAULT NON LINEAR MOMENT CURVATURE RELATIONSHIP This document is the property of BD POC. The yield strength ratio is usually in the range of (1. Ry is assumed as 1. To generate this relationship. is strictly prohibited.2 in this analysis. OFFPIPE has its’ built in default moment curvature relation ship by specifying the yield stress ratio (Ry) of the pipe. in any form.Title: Subsea Pipeline Design Basis My Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 61 of 67 : D2 = Pipe Bending Moment at Nominal Yield Stress 2σ y I ⎞ ⎛ ⎜⎜ M y = ⎟ 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. FIGURE 4.3). Therefore.0 < Ry < 1. For conservative. in any form. Initial entry 2. peak pull-in load occurs during one of the following stages of the pull-in: 1. H200 which states that: γcc emean ≤ ecc Where : 15. pull in analysis through J tube has not been carried during FEED. This document is the property of BD POC. the allowable for sagbend area is assumed as 72% of fy as commonly engineering practice (equal to 0. In a typical umbilical pull-in. H300 which states that: • The maximum pipe total strain in the over bend region shall not exceed 0.3 γcc = 1.25% for X65 (equivalent to DNV OS F101 grade 450) material. . Due to the presence of concrete weight coating. End of pull-in Due to unavailability of subsea cable and flexible pipe data. • The maximum equivalent stress at the sag bend region and pipeline stress at the stinger tip shall be less than 87% of fy for a combination of both static and dynamic loads.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 Analysis 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. Primary bending 3. Any unauthorised attempt to reproduce it. the analysis also performed in accordance with the limit states criteria for concrete crushing of DNV OS F101 Section 13.156% strain).Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 62 of 67 : D2 The analysis is performed in accordance with the simplified lay criteria of DNV OS F101 Section 13. is strictly prohibited. The analysis shall be performed during detailed design. e. 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. • Dual diameter (20 and 26 inch) Intelligent Pig (IP) requirement for Gas Export Pipeline (PLBD2). is strictly prohibited. Table 16. • All bends within the pipeline system (i..Title: Subsea Pipeline Design Basis 16. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 63 of 67 : D2 PIPELINE PIGGING PHILOSOPHY All pipelines shall be designed to be suitable for the passage of either operational or intelligent pigs or both.e. taper of 1:4). machining should be carried out at pipes end and the transition angle should not exceed 14 degrees. TABLE 16. in any form.1 : PIPELINE PIGGING PHILOSOPHY DETAIL Description 12 inch 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 Pipeline (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. • Bidirectional operational pigging requirement for Condensate Pipelines (PL-BD3 / PL-BD4). The following design considerations shall be applied when designing the Bien Dong pipelines: • Constant ID philosophy will be applied for all pipelines. from launcher to receiver) shall be of 5D if layout allows. This document is the property of BD POC. D2 .1 summarizes the key pigging philosophy for all pipelines. 3D may be considered if layout constraint is encountered. For topside bends. measured from the axis of the pipe (i. • Where sections of different external diameter are connected together. Any unauthorised attempt to reproduce it. During detailed design. The hydrostatic test pressures for all pipelines and risers are given in Table 3. Metallic pipelines after hydrotested shall be dewatered. Any unauthorised attempt to reproduce it.Title: Subsea Pipeline Design Basis 17. In case the pipeline sections are tested separately from the risers. oxygen scavenger and biocides shall be defined by the pre-commissioning contractor based on fresh water properties.6. vacuum dried. fresh water shall be used for pipeline cleaning and hydrotesting. Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 64 of 67 : D2 HYDROTEST. Chloride level in fresh water shall be as per hydrotest specification. a hydrotest (comprising riser. swabbed. Requirements for corrosion inhibitor. For the CRA clad and flexible pipelines. 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. This document is the property of BD POC. requirements for corrosions inhibitor. oxygen scavenger and biocides shall be defined by the pre-commissioning contractor based on the seawater properties. For carbon steel pipelines. purged with nitrogen and preserved with nitrogen packing with positive pressure. The minimum pipeline hydrotest. . expansion spool and subsea pipeline) shall be performed. the pipeline sections may be tested upon completion of pipeline installation while the risers may be hydrostatically tested onshore as part of jacket fabrication. preservation and pre-commissioning requirements will be covered in project specifications. Upon completion of full pipeline system tie-in offshore. is strictly prohibited. in any form. a detailed base case of pre-commissioning plan shall be developed for all pipeline systems. Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 65 of 67 : D2 ATTACHMENT 1 PLATFORM DISPLACEMENT (2 Pages) This document is the property of BD POC. in any form. is strictly prohibited. . Any unauthorised attempt to reproduce it. 64 104.78 178.83 137.22 126.65 Storm 62. Deflection (Z) (mm) (mm) (mm) Operating 19.60 373.25 Storm 252.57 125.13 108. Deflection (Y) Max.06 107.80 96.TROPICAL STORM DESIGN WAVE AND ASSOCIATED CURRENT Plan Bracing Level Condition Max.65 43.7 Storm 182.51 181.55 113.63 59. .04 110.07 100.58 Storm 105.34 139.0 (-) 10.34 Operating 147.05 154.41 Operating 57.0 (+) 7.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 66 of 67 : D2 MAXIMUM HAI THACH JACKET DEFLECTION .6 (+) 18.6 (-) 104.0 (-) 118.71 66.87 173.81 24.67 Storm 364.64 110.87 141.47 340.64 Storm 97. Any unauthorised attempt to reproduce it.0 (-) 32.15 Storm 309.34 430.28 133.62 412. in any form.67 161.86 Operating 83. Deflection (X) Max.88 280.0 This document is the property of BD POC.21 Operating 34.72 84.91 76.47 162.35 32.81 (-) 131.76 197.26 101.0 (+) 29.12 Operating 38.35 Operating 112.84 Operating 162.0 (-) 63.27 Operating 97.09 117. is strictly prohibited.82 Storm 276.99 Storm 390.80 96. 10 153.93 109.90 109.48 46.48 232.18 108.82 133.71 184. Deflection (Z) (mm) (mm) (mm) Operating 18.0 This document is the property of BD POC.0 (-) 32.27 Storm 246.4 (-) 102. is strictly prohibited.6 (+) 18.17 192.17 172.47 Storm 137.51 (-) 113.0 (-) 10.54 111.48 Operating 91.91 Storm 316.19 102.33 126.51 77. Deflection (X) Max. Any unauthorised attempt to reproduce it.47 320.71 290.39 Operating 129.64 101.82 104.15 Storm 62.Title: Subsea Pipeline Design Basis Document No Date Page Rev : BD1-00-L-A-0001 : 20-May-10 : 67 of 67 : D2 MAXIMUM MOC TINH JACKET DEFLECTION .06 168.41 Operating 64.52 Storm 199.28 354.20 Operating 40.47 Storm 218.12 384.74 Operating 22.TROPICAL STORM DESIGN WAVE AND ASSOCIATED CURRENT Plan Bracing Level Condition Max.01 Storm 88.5 (-) 63.47 Operating 77. in any form.91 93.70 120.0 (+) 29.38 87.0 (+) 7. Deflection (Y) Max.44 Storm 302.16 176.41 24.65 98.53 Operating 137.48 124. .42 35.81 135.73 136.71 98.
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