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Dnv os f101 submarine pipeline systems

Dnv os f101 submarine pipeline systems

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    • OFFSHORE STANDARD DNV-OS-F101SUBMARINE PIPELINE SYSTEMS OCTOBER 2007 Since issued in print (October 2007), this booklet has been amended, latest in October 2008. See the reference to “Amendments and Corrections” on the next page. DET NORSKE VERITAS
    • FOREWORDDET NORSKE VERITAS (DNV) is an autonomous and independent foundation with the objectives of safeguarding life, prop-erty and the environment, at sea and onshore. DNV undertakes classification, certification, and other verification and consultancyservices relating to quality of ships, offshore units and installations, and onshore industries worldwide, and carries out researchin relation to these functions.DNV Offshore Codes consist of a three level hierarchy of documents:— Offshore Service Specifications. Provide principles and procedures of DNV classification, certification, verification and con- sultancy services.— Offshore Standards. Provide technical provisions and acceptance criteria for general use by the offshore industry as well as the technical basis for DNV offshore services.— Recommended Practices. Provide proven technology and sound engineering practice as well as guidance for the higher level Offshore Service Specifications and Offshore Standards.DNV Offshore Codes are offered within the following areas:A) Qualification, Quality and Safety MethodologyB) Materials TechnologyC) StructuresD) SystemsE) Special FacilitiesF) Pipelines and RisersG) Asset OperationH) Marine OperationsJ) Wind TurbinesAmendments and CorrectionsThis document is valid until superseded by a new revision. Minor amendments and corrections will be published in a separatedocument normally updated twice per year (April and October).For a complete listing of the changes, see the “Amendments and Corrections” document located at:http://webshop.dnv.com/global/, under category “Offshore Codes”.The electronic web-versions of the DNV Offshore Codes will be regularly updated to include these amendments and corrections.Comments may be sent by e-mail to rules@dnv.comFor subscription orders or information about subscription terms, please use distribution@dnv.comComprehensive information about DNV services, research and publications can be found at http://www.dnv.com, or can be obtained from DNV,Veritasveien 1, NO-1322 Høvik, Norway; Tel +47 67 57 99 00, Fax +47 67 57 99 11.© Det Norske Veritas. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, includingphotocopying and recording, without the prior written consent of Det Norske Veritas.Computer Typesetting (FM+SGML) by Det Norske Veritas.Printed in Norway.If any person suffers loss or damage which is proved to have been caused by any negligent act or omission of Det Norske Veritas, then Det Norske Veritas shall pay compensation to such personfor his proved direct loss or damage. However, the compensation shall not exceed an amount equal to ten times the fee charged for the service in question, provided that the maximum compen-sation shall never exceed USD 2 million.In this provision "Det Norske Veritas" shall mean the Foundation Det Norske Veritas as well as all its subsidiaries, directors, officers, employees, agents and any other acting on behalf of DetNorske Veritas.
    • GeneralThis document supersedes the January 2000 edition, as amended in October 2005.Main changesIn addition to updating the material related parts, DNV has used this opportunity to update the operation phase requirements,making it more transparent from design until abandonment. This included a re-assessment of the documentation requirementsthat now constitutes Sec.12 moved from Sec.3. This work has also been funded by a JIP from the industry. Minor changes havebeen made to the layout of the design sections. The intention is to make the design more consistent and transparent, in particularwith respect to load combinations. The resulting design is not intended to be changed. Some requirements have been added withrespect to Hydrogen Induced Stress Cracking (HISC).AcknowledgementThe current revision of DNV-OS-F101 has been sponsored by three different Joint Industry Projects. The work has been performedby DNV and discussed in several workshops with individuals from the different companies. They are hereby all acknowledged fortheir valuable and constructive input. In case consensus has not been achievable DNV has sought to provide acceptable compromiseagreement.The two material related JIPs have in total been sponsored by:BP MRM TechnipChevron NSC TenarisCorus PTT V&MEuropipe Saipem VectorFMC Sintef VetcoHydro Statoil WoodsideJFE Subsea7The operation JIP has been sponsored by:ConocoPhillips Gassco ShellDONG Hydro StatoilENIIn addition, individuals from the following companies have been reviewers in the hearing process:Acergy Hydro StatoilAllseas Inoxtech Sumitomo Corp., EuropeButting Intec Tenaris DalmineEuropipe JFE V & M DeutschlandGorgon Nippon SteelDNV is grateful for the valuable co-operations and discussions with the individual personnel in these companies. DET NORSKE VERITAS
    • DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Contents – Page 5 CONTENTSSec. 1 General................................................................. 13 Sec. 4 Design - Loads..................................................... 34A. General.................................................................................. 13 A. General..................................................................................34A 100 Introduction..................................................................... 13 A 100 Objective......................................................................... 34A 200 Objectives ....................................................................... 13 A 200 Application ..................................................................... 34A 300 Scope and application ..................................................... 13 A 300 Load scenarios ................................................................ 34A 400 Alternative methods and procedures............................... 14 A 400 Load categories............................................................... 34A 500 Structure of Standard ...................................................... 14 A 500 Design cases.................................................................... 34A 600 Other codes ..................................................................... 14 A 600 Load effect combination ................................................. 34B. References ............................................................................ 15 B. Functional Loads ..................................................................34B 100 Offshore Service Specifications...................................... 15 B 100 General............................................................................ 34B 200 Offshore Standards ......................................................... 15 B 200 Internal Pressure loads.................................................... 34B 300 Recommended Practices ................................................. 15 B 300 External Pressure loads................................................... 35B 400 Rules ............................................................................... 15B 500 Certification notes and classification notes .................... 15 C. Environmental Loads............................................................35B 600 Other references.............................................................. 15 C 100 General............................................................................ 35 C 200 Wind loads ...................................................................... 35C. Definitions ............................................................................ 18 C 300 Hydrodynamic loads....................................................... 35C 100 Verbal forms ................................................................... 18 C 400 Ice loads .......................................................................... 36C 200 Definitions ...................................................................... 18 C 500 Earthquake ...................................................................... 36C 300 Definitions (continuation)............................................... 21 C 600 Characteristic environmental load effects ...................... 36D. Abbreviations and Symbols.................................................. 22 D. Construction Loads...............................................................38D 100 Abbreviations.................................................................. 22 D 100 General............................................................................ 38D 200 Symbols .......................................................................... 23D 300 Greek characters ............................................................. 24 E. Interference Loads ................................................................38D 400 Subscripts........................................................................ 25 E 100 General............................................................................ 38Sec. 2 Safety Philosophy................................................ 26 F. Accidental Loads ..................................................................38 F 100 General............................................................................ 38A. General.................................................................................. 26A 100 Objective......................................................................... 26 G. Design Load Effects .............................................................39A 200 Application...................................................................... 26 G 100 Design cases.................................................................... 39 G 200 Load combinations.......................................................... 39B. Safety Philosophy Structure ................................................ 26 G 300 Load effect calculations.................................................. 40B 100 General............................................................................ 26B 200 Safety objective............................................................... 26 Sec. 5 Design – Limit State Criteria ........................... 41B 300 Systematic review of risks .............................................. 27B 400 Design criteria principles ................................................ 27 A. General..................................................................................41B 500 Quality assurance............................................................ 27 A 100 Objective......................................................................... 41B 600 Health, safety and environment ...................................... 27 A 200 Application ..................................................................... 41C. Risk Basis for Design ........................................................... 27 B. System Design Principles .....................................................41C 100 General............................................................................ 27 B 100 Submarine pipeline system layout .................................. 41C 200 Categorisation of fluids................................................... 27 B 200 Mill pressure test and system pressure test..................... 42C 300 Location classes .............................................................. 28 B 300 Operating requirements .................................................. 43C 400 Safety classes .................................................................. 28C 500 Reliability analysis.......................................................... 28 C. Design Format ......................................................................43 C 100 General............................................................................ 43Sec. 3 Concept Development and Design Premises .... 29 C 200 Design resistance ............................................................ 43 C 300 Characteristic material properties ................................... 44A. General.................................................................................. 29 C 400 Stress and strain calculations .......................................... 45A 100 Objective......................................................................... 29A 200 Application...................................................................... 29 D. Limit States...........................................................................46A 300 Concept development ..................................................... 29 D 100General............................................................................ 46 D 200Pressure containment (bursting) ..................................... 46B. System Design Principles ..................................................... 29 D 300Local buckling - General ................................................ 46B 100 System integrity .............................................................. 29 D 400Local Buckling – External over pressure onlyB 200 Monitoring/inspection during operation ......................... 29 (System collapse)............................................................ 46B 300 Pressure Protection System............................................. 30 D 500 Propagation buckling ..................................................... 47B 400 Hydraulic analyses and flow assurance .......................... 30 D 600 Local Buckling - Combined Loading Criteria ................ 47 D 700 Global buckling ............................................................. 49C. Pipeline Route....................................................................... 31 D 800 Fatigue ............................................................................ 49C 100 Location .......................................................................... 31 D 900 Ovalisation...................................................................... 50C 200 Route survey ................................................................... 31 D 1000 Accumulated deformation .............................................. 50C 300 Seabed properties............................................................ 32 D 1100 Fracture and supplementary requirement P .................... 50 D 1200 Ultimate limit state – Accidental loads........................... 51D. Environmental Conditions.................................................... 32D 100 General............................................................................ 32 E. Special Considerations .........................................................51D 200 Collection of environmental data.................................... 32 E 100 General............................................................................ 51D 300 Environmental data ......................................................... 32 E 200 Pipe soil interaction ........................................................ 51 E 300 Spanning risers/pipelines ................................................ 52E. External and Internal Pipe Condition ................................... 33 E 400 On bottom stability ......................................................... 52E 100 External operational conditions ...................................... 33 E 500 Trawling interference...................................................... 52E 200 Internal installation conditions........................................ 33 E 600 Third party loads, dropped objects ................................. 53E 300 Internal operational conditions ....................................... 33 E 700 Thermal Insulation.......................................................... 53 DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 6 – Contents see note on front coverE 800 Settings from Plugs .........................................................53 D. Clad or Lined Steel Linepipe................................................77 D 100 General ............................................................................77F. Pipeline Components and Accessories ................................. 53 D 200 Pipe designation ..............................................................77F 100 General ............................................................................53 D 300 Manufacturing Procedure Specification .........................77F 200 Design of bends...............................................................54 D 400 Manufacture ....................................................................78F 300 Design of insulating joints ..............................................54 D 500 Acceptance criteria..........................................................78F 400 Design of pig traps ..........................................................54 D 600 Inspection ........................................................................79F 500 Design of valves..............................................................54F 600 Pipeline fittings ...............................................................55 E. Hydrostatic Testing...............................................................80 E 100 Mill pressure test.............................................................80G. Supporting Structure............................................................. 55G 100 General ............................................................................55 F. Non-destructive Testing........................................................80G 200 Pipe-in-pipe and bundles.................................................55 F 100 Visual inspection.............................................................80G 300 Riser supports..................................................................55 F 200 Non-destructive testing ...................................................80G 400 J-tubes .............................................................................55G 500 Stability of gravel supports and gravel covers ................55 G. Dimensions, Mass and Tolerances ....................................... 81 G 100 General ............................................................................81H. Installation and Repair.......................................................... 56 G 200 Tolerances .......................................................................81H 100 General ............................................................................56 G 300 Inspection ........................................................................82H 200 Pipe straightness..............................................................56H 300 Coating ............................................................................56 H. Marking, Delivery Condition and Documentation ...............84 H 100 Marking...........................................................................84Sec. 6 Design - Materials Engineering......................... 57 H 200 Delivery condition...........................................................84 H 300 Handling and storage .....................................................84A. General.................................................................................. 57 H 400 Documentation, records and certification .......................84A 100 Objective .........................................................................57A 200 Application......................................................................57 I. Supplementary Requirements...............................................84A 300 Documentation ................................................................57 I 100 Supplementary requirement, sour service (S) .................84 I 200 Supplementary requirement,B. Materials Selection for Linepipe fracture arrest properties (F) ...........................................85 and Pipeline Components ..................................................... 57 I 300 Supplementary requirement, linepipe for plasticB 100 General ............................................................................57 deformation (P) ...............................................................86B 200 Sour service.....................................................................57 I 400 Supplementary requirement, dimensions (D) .................87B 300 Corrosion resistant alloys (informative) .........................58 I 500 Supplementary requirement, high utilisation (U) ...........88B 400 Linepipe (informative) ....................................................58B 500 Pipeline components (informative) .................................59 Sec. 8 Construction - Components and Assemblies ... 89B 600 Bolts and nuts..................................................................59B 700 Welding consumables (informative) ...............................59 A. General..................................................................................89 A 100 Objective .........................................................................89C. Materials Specification ......................................................... 59 A 200 Application......................................................................89C 100 General ............................................................................59 A 300 Quality assurance ............................................................89C 200 Linepipe specification .....................................................60C 300 Components specification ..............................................60 B. Component Requirements ....................................................89C 400 Specification of bolts and nuts ........................................60 B 100 General ............................................................................89C 500 Coating specification.......................................................60 B 200 Component specification.................................................89C 600 Galvanic anodes specification.........................................61 B 300 Induction bends – additional andD. Corrosion Control ................................................................. 61 modified requirements to ISO 15590-1 ..........................89D 100 General ............................................................................61 B 400 Fittings, tees and wyes - additional requirements toD 200 Corrosion allowance .......................................................61 ISO 15590-2....................................................................90D 300 Temporary corrosion protection......................................61 B 500 Flanges and flanged connections -D 400 External pipeline coatings (informative).........................62 additional requirements to ISO 15590-3.........................92D 500 Cathodic Protection.........................................................62 B 600 Valves – Additional requirements to ISO 14723 ............92D 600 External corrosion control of risers B 700 Mechanical connectors....................................................93 (informative) ...................................................................63 B 800 CP Insulating joints.........................................................93D 700 Internal corrosion control (informative) .........................64 B 900 Anchor flanges ................................................................94 B 1000 Buckle- and fracture arrestors .........................................94Sec. 7 Construction – Linepipe .................................... 66 B 1100 Pig traps...........................................................................94 B 1200 Repair clamps and repair couplings ................................94A. General.................................................................................. 66A 100 Objective .........................................................................66 C. Materials for Components ....................................................94A 200 Application......................................................................66 C 100 General ............................................................................94A 300 Process of manufacture ...................................................66 C 200 C-Mn and low alloy steel forgings and castings .............94A 400 Supplementary requirements...........................................66 C 300 Duplex stainless steel, forgings and castings ..................95A 500 Linepipe specification ....................................................66 C 400 Pipe and plate material....................................................95A 600 Manufacturing Procedure Specification and C 500 Sour Service ....................................................................95 qualification ....................................................................66 D. Manufacture..........................................................................95B. Carbon Manganese (C-Mn) Steel Linepipe.......................... 67 D 100 Manufacturing procedure specification (MPS) ..............95B 100 General ............................................................................67 D 200 Forging ............................................................................95B 200 Pipe designation .............................................................67 D 300 Casting ............................................................................96B 300 Manufacturing .................................................................67 D 400 Hot forming.....................................................................96B 400 Acceptance criteria..........................................................69 D 500 Heat treatment .................................................................96B 500 Inspection ........................................................................72 D 600 Welding...........................................................................96 D 700 NDT ................................................................................96C. Corrosion Resistant Alloy (CRA) Linepipe ......................... 75C 100 General ............................................................................75 E. Mechanical and Corrosion Testing of Hot Formed,C 200 Pipe designation ..............................................................75 Cast and Forged Components...............................................96C 300 Manufacture ....................................................................75 E 100 General testing requirements ..........................................96C 400 Acceptance criteria..........................................................75 E 200 Acceptance criteria for C-Mn and low alloy steels ........97C 500 Inspection ........................................................................76 E 300 Acceptance criteria for duplex stainless steels................98 DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Contents – Page 7F. Fabrication of Risers, Expansion Loops, Pipe Strings for essential variables and validity ..................................... 108 Reeling and Towing.............................................................. 98 D 400 Operating limit conditions ............................................ 109F 100 General............................................................................ 98 D 500 Installation procedures.................................................. 109F 200 Materials for risers, expansion loops, pipe strings for D 600 Contingency procedures ............................................... 109 reeling and towing .......................................................... 98 D 700 Layvessel arrangement, laying equipment andF 300 Fabrication procedures and planning.............................. 98 instrumentation ............................................................. 109F 400 Material receipt, identification and tracking................... 98 D 800 Requirements for installation........................................ 110F 500 Cutting, forming, assembly, welding and heat treatment.................................................................. 98 E. Additional Requirements for Pipeline Installation MethodsF 600 Hydrostatic testing .......................................................... 98 Introducing Plastic Deformations .......................................111F 700 NDT and visual examination .......................................... 99 E 100 General.......................................................................... 111F 800 Dimensional verification................................................. 99 E 200 Installation manual........................................................ 111F 900 Corrosion protection ....................................................... 99 E 300 Qualification of the installation manual ....................... 111 E 400 Installation procedures.................................................. 111G. Hydrostatic Testing............................................................... 99 E 500 Requirements for installation........................................ 111G 100 Hydrostatic testing .......................................................... 99G 200 Alternative test pressures ................................................ 99 F. Pipeline Installation by Towing..........................................112 F 100 General.......................................................................... 112H. Documentation, Records, Certification F 200 Installation manual........................................................ 112 and Marking ....................................................................... 100 F 300 Qualification of installation manual ............................. 112H 100 General.......................................................................... 100 F 400 Operating limit conditions ............................................ 112 F 500 Installation procedures.................................................. 112Sec. 9 Construction - Corrosion Protection and F 600 Contingency procedures ............................................... 112 Weight Coating .................................................. 101 F 700 Arrangement, equipment and instrumentation ............. 112 F 800 Pipestring tow and installation...................................... 112A. General................................................................................ 101A 100 Objective....................................................................... 101 G. Other Installation Methods .................................................112A 200 Application.................................................................... 101 G 100 General.......................................................................... 112B. External Corrosion Protective Coatings ............................. 101 H. Shore Pull............................................................................113B 100 General.......................................................................... 101 H 100 General.......................................................................... 113B 200 Coating materials, surface preparation, H 200 Installation manual........................................................ 113 coating application and inspection/testing of coating... 101 H 300 Qualification of installation manual ............................. 113 H 400 Operating limit conditions ............................................ 113C. Concrete Weight Coating ................................................... 101 H 500 Installation procedures.................................................. 113C 100 General.......................................................................... 101 H 600 Contingency procedures ............................................... 113C 200 Concrete materials and coating manufacture................ 102 H 700 Arrangement, equipment and instrumentation ............. 113C 300 Inspection and testing ................................................... 102 H 800 Requirements for installation........................................ 113D. Manufacture of Galvanic Anodes....................................... 102 I. Tie-in Operations ................................................................113D 100 Anode manufacture....................................................... 102 I 100 General.......................................................................... 113 I 200 Installation manual........................................................ 113E. Installation of Galvanic Anodes ......................................... 103 I 300 Qualification of installation manual ............................. 113E 100 Anode installation ......................................................... 103 I 400 Operating limit conditions ............................................ 113 I 500 Tie-in procedures .......................................................... 113Sec. 10 Construction - Installation ............................... 104 I 600 Contingency procedures ............................................... 114 I 700 Tie-in operations above water ...................................... 114A. General................................................................................ 104 I 800 Tie-in operations below water ...................................... 114A 100 Objective....................................................................... 104A 200 Application.................................................................... 104 J. As-Laid Survey...................................................................114A 300 Failure Mode Effect Analysis (FMEA) and J 100 General.......................................................................... 114 Hazard and Operability (HAZOP) studies.................... 104 J 200 Specification of as-laid survey...................................... 114A 400 Installation and testing specifications and drawings..... 104 J 300 As-laid survey............................................................... 114A 500 Installation manuals ...................................................... 104 J 400 As-laid survey of corrosion protection systems............ 114A 600 Quality assurance.......................................................... 104A 700 Welding......................................................................... 104 K. Span Rectification and Pipeline Protection ........................114A 800 Non-destructive testing and visual examination........... 105 K 100 General.......................................................................... 114A 900 Production tests............................................................. 105 K 200 Span rectification and protection specification............. 114 K 300 Span rectification .......................................................... 115B. Pipeline Route, Survey and Preparation ............................. 105 K 400 Trenching...................................................................... 115B 100 Pre-installation route survey ......................................... 105 K 500 Post-installation gravel dumping .................................. 115B 200 Seabed preparation........................................................ 106 K 600 Grout bags and concrete mattresses.............................. 115B 300 Pipeline and cable crossings ......................................... 106B 400 Preparations for shore approach ................................... 106 L. Installation of Protective and Anchoring Structures...........116 L 100 General.......................................................................... 116C. Marine Operations .............................................................. 106C 100 General.......................................................................... 106 M. Installation of Risers ...........................................................116C 200 Vessels .......................................................................... 106 M 100 General.......................................................................... 116C 300 Anchoring systems, anchor patterns and anchor M 200 Installation manual........................................................ 116 positioning .................................................................... 106 M 300 Qualification of the installation manual ....................... 116C 400 Positioning systems ...................................................... 107 M 400 Operating limit conditions ............................................ 116C 500 Dynamic positioning..................................................... 107 M 500 Contingency procedures ............................................... 116C 600 Cranes and lifting equipment........................................ 107 M 600 Requirements for installation........................................ 116C 700 Anchor handling and tug management ......................... 107C 800 Contingency procedures ............................................... 107 N. As-Built Survey ..................................................................116 N 100 General.......................................................................... 116D. Pipeline Installation ............................................................ 107 N 200 Specification of as-built survey .................................... 116D 100 General.......................................................................... 107 N 300 As-built survey requirements........................................ 117D 200 Installation manual........................................................ 108 N 400 Inspection of impressed current cathodic corrosionD 300 Review and qualification of the installation manual, protection system .......................................................... 117 DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 8 – Contents see note on front coverO. Final Testing and Preparation for Operation ...................... 117 C 200 Corrosion control system and weight coating ..............128O 100 General ..........................................................................117 C 300 DFI-resumé ...................................................................128O 200 Specification of final testing and preparation for operation........................................................................117 D. Construction - InstallationO 300 Procedures for final testing and preparation for and Pre-Commissioning......................................................128 operation........................................................................117 D 100 General ..........................................................................128O 400 Cleaning and gauging....................................................117 D 200 DFI-Resumé ..................................................................129O 500 System pressure testing .................................................118O 600 De-watering and drying ................................................119 E. Operation - Commissioning................................................ 129O 700 Systems testing..............................................................119 E 100 General ..........................................................................129P. Documentation.................................................................... 119 F. Operation ............................................................................129P 100 General ..........................................................................119 F 100 General ..........................................................................129 F 200 In-Service file................................................................129Sec. 11 Operations and Abandonment ........................ 120 G. Abandonment......................................................................129A. General................................................................................ 120 G 100 General ..........................................................................129A 100 Objective .......................................................................120A 200 Scope and application ...................................................120 H. DFI Resumé ........................................................................129A 300 Responsibilities .............................................................120 H 100 General ..........................................................................129A 400 Authority and company requirements...........................120 H 200 DFI resumé content.......................................................129A 500 Safety philosophy..........................................................120 I. Filing of Documentation.....................................................130B. Commissioning................................................................... 120 I 100 General ..........................................................................130B 100 General ..........................................................................120B 200 Fluid filling ...................................................................120 Sec. 13 Commentary (Informative)............................. 131B 300 Operational verification ................................................120 A. General................................................................................131C. Integrity Management System............................................ 120 A 100 Objective .......................................................................131C 100 General ..........................................................................120C 200 Company policy ............................................................121 B. Cross References ................................................................131C 300 Organisation and personnel...........................................121C 400 Condition evaluation and assessment methods .............121 C. Design Philosophy ..............................................................132C 500 Planning and execution of activities .............................121 C 100 Safety Class discussion .................................................132C 600 Management of change .................................................121 C 200 Structural reliability analyses........................................132C 700 Operational controls and procedures.............................121 C 300 Characteristic values .....................................................133C 800 Contingency plans.........................................................121C 900 Reporting and communication ......................................121 D. Loads...................................................................................133C 1000 Audit and review ...........................................................121 D 100 Conversion of pressures ................................................133C 1100 Information management ..............................................121 E. Design Criteria....................................................................133D. Integrity Management Process ........................................... 122 E 100General ..........................................................................133D 100 General ..........................................................................122 E 200Condition load effect factors.........................................133D 200 Evaluation of threats and condition ..............................122 E 300Calculation of nominal thickness..................................133D 300 External inspection........................................................122 E 400Pressure containment - equivalent format.....................134D 400 In-line inspection...........................................................123 E 500Pressure containment criterion,D 500 Corrosion monitoring....................................................123 incidental pressure less than 10% above the designD 600 Integrity assessment ......................................................124 pressure. ........................................................................134D 700 Mitigation, intervention and repairs..............................124 E 600 HIPPS and similar systems ...........................................134 E 700 Local buckling - Collapse .............................................135E. Re-qualification .................................................................. 125 E 800 Buckle arrestor ..............................................................135E 100 General ..........................................................................125 E 900 Local buckling - Moment..............................................135E 200 Application....................................................................125 E 1000 Local buckling - Girth weld factor................................135E 300 Safety level....................................................................125 E 1100 Ovalisation ....................................................................135E 400 System pressure test ......................................................125E 500 Deterioration .................................................................125 F. API Material Grades ........................................................... 136E 600 Design criteria ...............................................................125 F 100 API material grades.......................................................136F. De-commissioning.............................................................. 126 G. Components and Assemblies..............................................136F 100 General ..........................................................................126 G 100 Riser Supports ...............................................................136 G 200 J-tubes ...........................................................................136G. Abandonment...................................................................... 126G 100 General ..........................................................................126 H. Installation ..........................................................................136 H 100 Safety class definition ...................................................136Sec. 12 Documentation.................................................. 127 H 200 Coating ..........................................................................136 H 300 Simplified laying criteria ..............................................137A. General................................................................................ 127 H 400 Reeling ..........................................................................137A 100 Objective .......................................................................127 I. References...........................................................................139B. Design................................................................................. 127B 100 Structural .......................................................................127 App. A Structural Integrity of Girth Welds inB 200 Linepipe and pipeline components (including welding) .......................................................127 Offshore Pipelines............................................................ 140B 300 Corrosion control systems and weight coating .............127B 400 Installation.....................................................................128 A. General................................................................................140B 500 Operation.......................................................................128 A 100 Objective .......................................................................140B 600 DFI-Resumé ..................................................................128 A 200 Introduction...................................................................140 A 300 Application....................................................................140C. Construction - Manufacturing and Fabrication ................................................................... 128 B. Assessment Categories .......................................................141C 100 Linepipe and pipeline component .................................128 B 100 General ..........................................................................141 DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Contents – Page 9C. Generic ECA for Girth Welds D 500 Welding procedure specification .................................. 169 Subject to Strains Less than 0.4% D 600 Welding procedure specification for repair welding .... 169 Assessed According to ECA Static – Low ......................... 143 D 700 Contents of pWPS......................................................... 169C 100 General.......................................................................... 143 D 800 Essential variables for welding procedures .................. 170D. Generic ECA for Girth Welds Subjected to Strains Equal to E. Qualification of Welding Procedures .................................172 or Larger than 0.4% but Less Than 2.25% Assessed E 100 General.......................................................................... 172 According to ECA Static – High ........................................ 145 E 200 Repair welding procedures ........................................... 173D 100 General.......................................................................... 145 E 300 Qualification of longitudinal and girth butt welds welding procedures ............................ 173E. Girth Welds under Strain-based Loading Assessed According E 400 Qualification of welding procedures for to ECA Static - Full ............................................................ 148 corrosion resistant overlay welding .............................. 175E 100 General.......................................................................... 148 E 500 Qualification of procedures for Pin Brazing andE 200 Assessment methodology ............................................. 149 Aluminothermic welding of anode leads...................... 176 E 600 Qualification of welding proceduresF. Girth Welds Assessed for temporary and permanent attachments According to ECA Fatigue ................................................. 151 and branch welding fittings to linepipe ........................ 176F 100 General.......................................................................... 151 E 700 Qualification of welding procedures for structuralF 200 High-cycle fatigue......................................................... 152 components ................................................................... 177F 300 Low-cycle fatigue ......................................................... 152 E 800 Qualification of welding procedures for hyperbaric dry welding ................................................. 177G. Testing Requirements ......................................................... 152G 100 General.......................................................................... 152 F. Examination and Testing forG 200 Straining and ageing ..................................................... 153 Welding Procedure Qualification .......................................177 F 100 General.......................................................................... 177H. ECA Validation Testing ..................................................... 154 F 200 Visual examination and non-destructive testingH 100 General.......................................................................... 154 requirements ................................................................. 178 F 300 Testing of butt welds .................................................... 178App. B Mechanical Testing and Corrosion Testing ... 156 F 400 Testing of weld overlay ................................................ 179 F 500 Testing of pin brazing and aluminothermic welds ...... 180 F 600 Testing of welds for temporary and permanentA. Mechanical Testing and Chemical Analysis ..................... 156 attachments and branch outlet fittings to linepipe ........ 180A 100 General.......................................................................... 156A 200 General requirements to selection and preparation of G. Welding and PWHT Requirements ....................................180 samples and test pieces ................................................. 156 G 100 General.......................................................................... 180A 300 Chemical analysis ......................................................... 156 G 200 Production welding, general requirements ................... 180A 400 Tensile testing ............................................................... 156 G 300 Repair welding, general requirements .......................... 181A 500 Charpy V-notch impact testing ..................................... 157 G 400 Post weld heat treatment............................................... 182A 600 Bend testing .................................................................. 157 G 500 Welding of pipeline girth welds ................................... 182A 700 Flattening test................................................................ 158 G 600 Welding and PWHT of pipeline components............... 183A 800 Drop weight tear test..................................................... 158A 900 Fracture toughness testing ............................................ 158 H. Material and Process Specific Requirements .....................183A 1000 Specific tests for clad and lined linepipe ...................... 159 H 100 Internally clad/lined carbon steel andA 1100 Metallographic examination and hardness testing........ 159 duplex stainless steel..................................................... 183A 1200 Straining and ageing ..................................................... 160 H 200 13Cr martensitic stainless steel..................................... 184A 1300 Testing of pin brazings and aluminothermic welds ...... 161 H 300 Pin brazing and aluminothermic welding ..................... 185B. Corrosion Testing ............................................................... 161 I. Hyperbaric Dry Welding ....................................................185B 100 General.......................................................................... 161 I 100 General.......................................................................... 185B 200 Pitting corrosion test ..................................................... 161 I 200 Qualification and testing of welding personnel forB 300 Hydrogen Induced Cracking test .................................. 161 hyperbaric dry welding ................................................ 185B 400 Sulphide Stress Cracking test ....................................... 161 I 300 Welding processes for hyperbaric dry welding ............ 186 I 400 Welding consumables for hyperbaric dry welding....... 186App. C Welding.............................................................. 165 I 500 Shielding and backing gases for hyperbaric dry welding ................................................. 186A. Application ......................................................................... 165 I 600 Welding equipment and systems for hyperbaric dryA 100 General.......................................................................... 165 welding ......................................................................... 186A 200 Welding processes ........................................................ 165 I 700 Welding procedures for hyperbaric dry welding .......... 186A 300 Definitions .................................................................... 165 I 800 Qualification welding for hyperbaric dry welding ....... 187A 400 Quality assurance.......................................................... 165 I 900 Qualification of welding procedures for hyperbaric dry welding ................................................. 187B. Welding Equipment, Tools and Personnel ......................... 165 I 1000 Examination and testing ............................................... 187B 100 Welding equipment and tools ....................................... 165 I 1100 Production welding requirements for dry hyperbaricB 200 Personnel....................................................................... 166 welding ......................................................................... 187B 300 Qualification and testing of welding personnel for hyperbaric dry welding ................................................ 166 App. D Non-Destructive Testing (NDT) ...................... 189C. Welding Consumables........................................................ 166 A. General................................................................................189C 100 General.......................................................................... 166 A 100 Objective....................................................................... 189C 200 Chemical composition .................................................. 167 A 200 Applicability of requirements ....................................... 189C 300 Mechanical properties................................................... 167 A 300 Quality assurance.......................................................... 189C 400 Batch testing of welding consumables for A 400 Non-destructive testing methods .................................. 189 pipeline girth welds....................................................... 167 A 500 Personnel qualifications................................................ 189C 500 Shielding, backing and plasma gases............................ 168 A 600 Timing of NDT ............................................................. 190C 600 Handling and storage of welding consumables ............ 168 B. Manual Non-Destructive TestingD. Welding Procedures............................................................ 168 and Visual Examination of Welds ......................................190D 100 General.......................................................................... 168 B 100 General.......................................................................... 190D 200 Previously qualified welding procedures...................... 168 B 200 Radiographic testing of welds ...................................... 190D 300 Preliminary welding procedure specification ............... 169 B 300 Manual ultrasonic testing of welds in C-Mn/low alloy steelD 400 Welding procedure qualification record ....................... 169 with C-Mn/low alloy steel weld deposits ..................... 191 DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 10 – Contents see note on front coverB 400 Manual ultrasonic testing of welds with CRA App. E Automated Ultrasonic Girth Weld Testing ... 223 (duplex, other stainless steels and nickel alloy steel) weld deposits.................................................................194 A. General................................................................................223B 500 Manual magnetic particle testing of welds ...................195 A 100 Scope.............................................................................223B 600 Manual liquid penetrant testing of welds ......................196 A 200 References.....................................................................223B 700 Manual eddy current testing of welds ...........................196B 800 Visual examination of welds.........................................197 B. Basic Requirements ............................................................223B 900 Acceptance criteria for manual non-destructive testing of B 100 General ..........................................................................223 welds with nominal strains < 0.4% and no ECA ..........197 B 200 Documentation ..............................................................224B 1000 ECA based non-destructive testing acceptance criteria for pipeline girth welds .......................................................197 B 300 Qualification..................................................................224B 1100 Repair of welds .............................................................200 B 400 Ultrasonic system equipment and components.............224 B 500 Calibration (reference) blocks.......................................225C. Manual Non-destructive testing and Visual Examination of B 600 Recorder set-up .............................................................226 Plate, Pipe and Weld Overlay............................................. 200 B 700 Circumferential scanning velocity ................................226C 100 General ..........................................................................200 B 800 Power supply.................................................................226C 200 Plate and pipe ................................................................201 B 900 Software ........................................................................226C 300 Weld overlay .................................................................201 B 1000 Reference line, band position and coating cut-back .....226C 400 Visual examination ......................................................202 B 1100 Reference line tools.......................................................226C 500 Residual magnetism ......................................................202 B 1200 Operators.......................................................................226C 600 Acceptance criteria for manual non-destructive testing of B 1300 Spares ............................................................................226 plate, pipe and weld overlay .........................................202 B 1400 Slave monitors...............................................................226D. Non-destructive Testing and Visual Examination of C. Procedure ............................................................................227 Forgings .............................................................................. 203 C 100 General ..........................................................................227D 100 General ..........................................................................203D 200 Ultrasonic and magnetic particle testing of C-Mn and D. Calibration (Sensitivity Setting) .........................................227 low alloy steel forgings .................................................203 D 100 Initial static calibration..................................................227D 300 Ultrasonic and liquid penetrant testing of D 200 Gate settings..................................................................227 duplex stainless steel forgings.......................................204 D 300 Recording Threshold.....................................................228D 400 Visual examination of forgings.....................................205 D 400 Dynamic calibration......................................................228D 500 Acceptance criteria for forgings....................................205 D 500 Recording of set-up data ...............................................228E. Non-destructive Testing and Visual Examination of E. Field Inspection ..................................................................228 Castings .............................................................................. 205 E 100 Inspection requirements ................................................228E 100 General ..........................................................................205 E 200 Operational checks........................................................229E 200 Ultrasonic and magnetic particle testing of C-Mn and E 300 Adjustments of the AUT system...................................230 low alloy steel castings .................................................205E 300 Ultrasonic and liquid penetrant testing of F. Re-examination of Welds ...................................................230 duplex stainless steel castings .......................................206 F 100 General ..........................................................................230E 400 Radiographic testing of castings ...................................207E 500 Visual examination of castings .....................................207 G. Evaluation and Reporting ...................................................230E 600 Acceptance criteria for castings ....................................207 G 100 Evaluation of indications ..............................................230 G 200 Examination reports ......................................................230F. Automated Non-Destructive Testing.................................. 207 G 300 Inspection records .........................................................230F 100 General ..........................................................................207F 200 Documentation of function and operation ....................208 H. Qualification .......................................................................230F 300 Documentation of performance ....................................208F 400 Qualification..................................................................208 H 100 General ..........................................................................230F 500 Evaluation of performance documentation ...................208 H 200 Scope.............................................................................230 H 300 Requirements ................................................................230G. Non-Destructive Testing at Plate H 400 Variables .......................................................................231 and Coil Mill....................................................................... 208 H 500 Qualification programme ..............................................231G 100 General ..........................................................................208 H 600 Test welds .....................................................................231G 200 Ultrasonic testing of C-Mn steel and CRA plates.........208 H 700 Qualification testing .....................................................231G 300 Ultrasonic testing of CRA clad C-Mn steel plate ........209 H 800 Reference destructive testing ........................................232G 400 Alternative test methods................................................209 H 900 Analysis.........................................................................233G 500 Disposition of plate and coil with H 1000 Reporting.......................................................................233 unacceptable laminations or inclusions.........................209G 600 Visual examination of plate and coil.............................209 I. Validity of Qualification.....................................................233G 700 Acceptance criteria and disposition of surface I 100 Validity..........................................................................233 imperfections.................................................................209 I 200 Essential variables.........................................................233H. Non-Destructive Testing J. Determination of Wave Velocities of Linepipe at Pipe Mills .................................................... 209 in Pipe Steels.......................................................................233H 100 General ..........................................................................209 J 100 General ..........................................................................233H 200 Suspect pipe ..................................................................210 J 200 Equipment .....................................................................233H 300 Repair of suspect pipe ...................................................211 J 300 Specimens .....................................................................234H 400 General requirements for automated NDT systems ......211 J 400 Test method...................................................................234H 500 Visual examination and residual magnetism ................213 J 500 Accuracy .......................................................................234H 600 Non-destructive testing of pipe ends not tested by J 600 Recording ......................................................................234 automated NDT equipment ...........................................214H 700 Non-destructive testing of pipe ends.............................214 App. F Requirements for Shore ApproachH 800 Non-destructive testing of seamless pipe......................215H 900 Non-destructive testing of HFW pipe ...........................215 and Onshore Sections...................................................... 235H 1000 Non-destructive testing of CRA liner pipe ...................216H 1100 Non-destructive testing of lined pipe ............................216 A. Application .........................................................................235H 1200 Non-destructive testing of clad pipe .............................217 A 100 Objective .......................................................................235H 1300 Non-destructive testing of SAWL and SAWH pipe .....218 A 200 Scope and limitation......................................................235H 1400 Manual NDT at pipe mills ............................................220 A 300 Other codes ..................................................................235H 1500 Non-destructive testing of weld repair in pipe .............222 A 400 Definitions.....................................................................235 DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Contents – Page 11B. Safety Philosophy ............................................................... 236 D 300 Design loads.................................................................. 238B 100 General.......................................................................... 236 D 400 Design criteria............................................................... 238B 200 Safety philosophy ......................................................... 236B 300 Quantification of consequence ..................................... 236 E. Construction........................................................................239 E 100 General.......................................................................... 239C. Design Premise ................................................................... 237 E 200 Linepipe ........................................................................ 239C 100 General.......................................................................... 237C 200 Routing ......................................................................... 237 E 300 Components and assemblies ......................................... 239C 300 Environmental data ....................................................... 237 E 400 Corrosion protection & coatings................................... 239C 400 Survey ........................................................................... 237C 500 Marking......................................................................... 238 F. Operation ............................................................................239 F 100 General.......................................................................... 239D. Design................................................................................. 238D 100 General.......................................................................... 238 G. Documentation....................................................................239D 200 System design ............................................................... 238 G 100 General.......................................................................... 239 DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 12 – Contents see note on front cover DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 13 SECTION 1 GENERAL A. General the protection of the environment. — provide an internationally acceptable standard of safetyA 100 Introduction for submarine pipeline systems by defining minimum101 This standard gives criteria and guidance on concept requirements for concept development, design, construc-development, design, construction, operation and abandon- tion, operation and abandonmentment of Submarine Pipeline Systems. — serve as a technical reference document in contractual matters between Purchaser and ContractorA 200 Objectives — serve as a guideline for Designers, Purchaser, and Con-201 The objectives of this standard are to: tractors.— Ensure that the concept development, design, construc- A 300 Scope and application tion, operation and abandonment of pipeline systems are 301 The scope and applicability of this standard is given in safe and conducted with due regard to public safety and Table 1-1.Table 1-1 Scope and application summaryGeneral Systems in the petroleum and natural gas industries are in general described in this table. For submarine pipeline systems that have extraordinary consequences, the quantification of con- sequences by the three safety classes provided in this standard may be insufficient, and higher safety classes may be required.1Phases Concept development, design, construction, operation and abandonmentPipeline Types Dynamic risers and compliant risers are covered by DNV-OS-F201 Dynamic Risers. Rigid metallic pipe Single systems, pipeline bundles of the piggyback type and pipeline bundles within an outer pipe2Extent Pressure and flow Pipeline system in such a way that the fluid transportation and pressure in the submarine pipeline system is well defined and controlled 3 Concept development, design, Submarine pipeline system 4 construction, operation and abandonmentGeometry and configuration Dimensions No limitation (Explicit criteria for local buckling, combined loading are only given for straight pipes with 15 < D/t2 < 45) Water depth No limitation, see Sec.5 A201Loads Pressure No limitation Temperature No limitation Material properties need to be documented for temperatures above 50oC and 20oC for C-Mn steels and CRAs respectively, see Sec.5 C300 Global deformations No limitationLinepipe Material General Sec.7 A201 C-Mn steel linepipe is generally conforming to ISO 3183 Annex J but with modifications and amendments. CRA linepipe with specific requirements to duplex stainless steel and 13Cr martensitic steel Clad and Lined linepipe. Supplementary requirements for sour service, fracture arrest properties, plastic deformation, dimensional tolerances and high utilization.Components Bends, Fittings, Flanges, Valves, Mechanical connectors, CP Insulating joints, Anchor flange, Buckle arrestor, Pig traps, Clamps and Couplings Material and manufacture Sec.8 Design Sec.5 FFluids Categories Table 2-1 Sour service Generally conforming to ISO 15156Installation Sec.10 Method S-lay, J-lay, towing and laying methods introducing plastic deformations Installation requirements for risers as well as protective and anchoring structures are also included.1) Example of extra ordinary consequences may be pristine environment 2) Umbilicals intended for control of subsea installations are not included in and exploration in arctic climate. this standard. Individual pipes, within an umbilical, made of materials DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 14 – Sec.1 see note on front cover applicable to this standard, may be designed according to this standard. — Appendix C contains requirements to welding including3) Different parts of the pipeline system may be designed to different codes. qualification of welding procedures and construction It is important to identify differences between these at an early stage and welding. assess these. Examples of conflicting requirements are; pressure defini- tions and system test pressure requirements. — Appendix D contains requirements to Non-Destructive Testing (NDT) except Automated Ultrasonic Testing4) The owner may apply this standard on sub-sets of the limits of this stand- (AUT) of girth welds. ard. Typical example of excluded items is smaller diameter piping such as kicker lines and designs these to e.g. ISO 15649. — Appendix E contains requirements to AUT of girth welds. — Appendix F contains selected requirements to onshoreA 400 Alternative methods and procedures parts of the submarine pipeline system.401 In case alternative methods and procedures to thosespecified in this Standard are used, it shall be demonstrated 503 Cross references are made as:that the obtained safety level is equivalent to the one specifiedherein, see Sec.2 C500. — nnn within the same sub-section (e.g. 512) — X or Xnnn to another sub-section within the same sectionA 500 Structure of Standard (e.g. C, C500 or C512) — Section m, Section mX or Section mXnnn to section, sub-501 This Standard is based on limit state design. This implies section or paragraph outside the current section (e.g.that the same design criteria apply to both construction/instal- Sec.5, Sec.5 C, Sec.5 C500 or Sec.5 C512).lation and operation. All structural criteria are therefore givenin Sec.5. Where m and nnn denotes numbers and X letter.502 The Standard is organised as follows: 504 Additional requirements or modified requirements com-— Sec.1 contains the objectives and scope of the standard. It pared to ISO 3183 are denoted by AR or MR by the end of the further introduces essential concepts, definitions and paragraph, see Sec.7 B102. abbreviations. A 600 Other codes— Sec.2 contains the fundamental safety philosophy and design principles. It introduces the safety class methodol- 601 In case of conflict between requirements of this code and ogy and normal classification of safety classes. a referenced DNV Offshore Code, the requirements of the— Sec.3 contains requirements to concept development, code with the latest revision date shall prevail. establishment of design premises, with system design Guidance note: principles, pressure protection system, and collection of DNV Offshore code means any DNV Offshore Service Specifi- environmental data. cation, DNV Offshore Standard, DNV Offshore Recommended— Sec.4 defines the design loads to be applied in Sec.5. It Practice, DNV Guideline or DNV Classification Note. includes classification of loads into functional loads Any conflict is intended to be removed in next revision of that (including pressure), environmental loads, interference document. loads and accidental loads. Finally, it defines design cases with associated characteristic values and combinations. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---— Sec.5 contains requirements to pipeline layout, system test and mill test. It contains description of the design (LRFD) 602 Where reference is made to codes other than DNV doc- format and characterisation of material strength for uments, the valid revision shall be taken as the revision which straight pipes and supports. Design criteria for the differ- was current at the date of issue of this standard, unless other- ent limit states for all phases; installation, as-laid, commis- wise noted. sioning and operation, are given. 603 In case of conflict between requirements of this code and— Sec.6 contains materials engineering and includes material code other than a DNV document, the requirements of this selection, material specification (including required sup- code shall prevail. plementary requirement to the linepipe specification), 604 This standard is intended to comply with the ISO stand- welding and corrosion control. ard 13623: Petroleum and natural gas industries - Pipeline— Sec.7 contains requirements to linepipe. The requirements transportation systems, specifying functional requirements for to C-Mn steels are based on ISO 3183. The section also offshore pipelines and risers. includes requirements to CRAs and lined/clad pipe.— Sec.8 contains requirements to materials, manufacture and Guidance note: fabrication of components and assemblies. Structural The following major deviations to the ISO standard are known: requirements to these components are given in Sec.5 F. - This standard allows higher utilisation for fluid category A— Sec.9 contains requirements to corrosion protection and and C pipelines. This standard is here in compliance with weight coating. ISO16708.— Sec.10 contains requirements to installation including pre- - For design life less than 33 years, a more severe environmen- and post-intervention and pre-commissioning. tal load is specified, in agreement with ISO16708.— Sec.11 contains requirements to operation including com- - applying the supplementary requirements U, for increased missioning, integrity management, repair, re-qualifica- utilisation, this standard allows 4% higher pressure contain- tion, de-commissioning and abandonment of the ment utilisation than the ISO standard. submarine pipeline system. - the equivalent stress criterion in the ISO standard sometimes— Sec.12 contains requirements to documentation for the allows higher utilisation than this standard. submarine pipeline system from concept development to - requirements to system pressure test (pressure test). abandonment. - minor differences may appear depending on how the pipeline has been defined in safety classes, the ISO standard does not— Sec.13 is an informative section which discusses several use the concept of safety classes. aspects of the standard.— The appendices are a compulsory part of the standard. This standard requires that the manufacture of line pipe and con-— Appendix A contains the requirements to engineering crit- struction is performed to this standard. ical assessment (ECA). It includes methodology, material ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- characterisation and testing requirements.— Appendix B details the requirements to materials testing 605 The requirements to C-Mn steel linepipe of this standard including mechanical and corrosion testing as well as include amendments and modifications that are additional to chemical analysis. ISO 3183. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 15 B. References B 400 Rules The latest revision of the following documents applies:B 100 Offshore Service SpecificationsThe latest revision of the following documents applies: DNV Rules for Certification of Flexible Risers and PipesDNV-OSS-301 Certification and Verification of Pipelines DNV Rules for Classification of High Speed,DNV-OSS-302 Certification and verification of Dynamic Light Craft and Naval Surface Craft Risers DNV Rules for Planning and Execution of MarineDNV-OSS-401 Technology Qualification Management Operations DNV Rules for Classification of Fixed OffshoreB 200 Offshore Standards InstallationsThe following documents contain provisions which, throughreference in this text, constitute provisions of this Offshore B 500 Certification notes and classification notesStandard. The latest revision of the following document The latest revision of the following documents applies:applies. DNV CN 1.2 Conformity Certification Services, TypeDNV-OS-A101 Safety Principles And Arrangements ApprovalDNV-OS-C101 Design of Offshore Steel Structures, Gen- DNV CN 1.5 Conformity Certification Services, eral (LRFD method) Approval of Manufacturers, Metallic Mate-DNV-OS-C501 Composite Components rialsDNV-OS-E201 Oil And Gas Processing Systems DNV CN 7 Non Destructive TestingDNV-OS-F201 Dynamic Risers DNV CN 30.4 Foundations DNV CN 30.6 Structural Reliability Analysis of MarineB 300 Recommended Practices StructuresThe latest revision of the following documents applies: B 600 Other referencesDNV-RP-A203 Qualification Procedures for New Technol- ogy API RP5L1 Recommended Practice for RailroadDNV-RP-B401 Cathodic Protection Design transportation of Line PipeDNV-RP-C203 Fatigue Strength Analysis of Offshore Steel API5LW Recommended Practice for Transpor- Structures tation of Line Pipe on Barges and Marine VesselsDNV-RP-C205 Environmental Conditions and Environmental Loads API RP 2201 Safe Hot Tapping Practices in the Petroleum & Petrochemical Indus-DNV-RP-F101 Corroded Pipelines tries-Fifth EditionDNV-RP-F102 Pipeline Field Joint Coating & Field Repair ASME/ANSI B16.9 Factory-Made Wrought Buttwelding of Linepipe Coating FittingsDNV-RP-F103 Cathodic Protection of Submarine Pipelines ASME B31.3 2004 Process Piping by Galvanic AnodesDNV-RP-F105 Free Spanning Pipelines ASME B31.4 2006 Pipeline Transportation Systems for Liquid Hydrocarbons and OtherDNV-RP-F106 Factory applied pipeline coatings for corro- Liquids sion control ASME B31.8 2003 Gas Transmission and Distribu-DNV-RP-F107 Risk Assessment of Pipeline Protection tion SystemsDNV-RP-F108 Fracture Control for Pipeline Installation ASME BPVC-V BPBV Section V - Non-destructive Methods Introducing Cyclic Plastic Strain ExaminationDNV-RP-F109 On-bottom Stability Design of Submarine ASME BPVC-VIII-1 BPVC Section VIII - Div. 1 - Rules for Pipelines Construction of Pressure VesselsDNV-RP-F110 Global Buckling of Submarine Pipelines - ASME BPVC-VIII-2 BPVC Section VIII - Div. 2 - Rules for Structural Design due to High Temperature/ Construction of Pressure Vessels - High Pressure Alternative RulesDNV-RP-F111 Interference between Trawl Gear and Pipe- ASNT Central Certification Program lines (ACCP).DNV-RP-F112 Design of Duplex Stainless Steel Subsea ASTM D 695 Standard Test Method for Compres- Equipment Exposed to Cathodic Protection sive Properties of Rigid PlasticsDNV-RP-F113 Pipeline Subsea Repair ASTM A370 Standard Test Methods and Defini-DNV-RP-F204 Riser Fatigue tions for Mechanical Testing of SteelDNV-RP-H101 Risk Management in Marine and Subsea Products Operations ASTM A388 Specification for Ultrasonic Examina-DNV-RP-H102 Marine Operations during Removal of Off- tion of Heavy Steel Forgings shore Installations ASTM A578/578M Standard Specification for Straight-DNV-RP-O501 Erosive Wear in Piping Systems - Summary Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 16 – Sec.1 see note on front coverASTM A577/577M Standard specification for Ultrasonic EN 583-6 Non destructive testing - Ultrasonic Angle-Beam Examination of Steel examination Part 6 - Time-of- flight Plates diffraction as a method for defectASTM A609 Standard Practice for Castings, Low detection and sizing Alloy, and Martensitic Stainless Steel, EN 1418 Welding personnel - Approval testing Ultrasonic Examination Thereof of welding operators for fusion weld-ASTM A 961 Standard Specification for Common ing and resistance weld setters for Requirements for Steel Flanges, fully mechanized and automatic weld- Forged Fittings, Valves, and Parts for ing of metallic materials Piping Applications EN 1591-1 Flanges and their joints - Design rulesASTM E165 Standard Test method for Liquid Pen- for gasketed circular flange connec- etrant Inspection tions - Part 1: Calculation methodASTM E280 Standard Reference Radiographs for EN 1998 Eurocode 8: Design of structures for Heavy-Walled (4 1/2 to 12-in. (114 to earthquake resistance 305-mm)) Steel Castings EN 10204 Metallic products - Types of inspec-ASTM E309 Standard Practice for Eddy-Current tion documents Examination of Steel Tubular prod- EN 12668-1 Non destructive testing - Characterisa- ucts Using Magnetic Saturation tion and verification of ultrasonicASTM E 317-94 Standard Practice for Evaluating Per- examination equipment- Part 1: formance Characteristics of Pulse Instruments Echo Testing Systems Without the EN 12668-2 Non destructive testing - Characterisa- Use of Electronic Measurement tion and verification of ultrasonic Instruments examination equipment- Part 2: Trans-ASTM E426 Standard Practice for Electromagnetic ducers (Eddy Current) of Welded and Seam- EN 12668-3 Non destructive testing - Characterisa- less Tubular Products, Austenitic tion and verification of ultrasonic Stainless Steel and Similar Alloys examination equipment- Part: 3: Com-ASTM E 709 Standard Guide for Magnetic Particle bined equipment Examination EN 13445 Unfired pressure vessels - Part 3:ASTM E797 Standard Practice for Measuring Design Thickness by Manual Ultrasonic EN 26847 Covered electrodes for manual metal Pulse-Echo Contact Method arc welding. Deposition of a weldASTM E 1212 Standard Practice for Quality Manage- metal pad for chemical analysis ment Systems for Non-destructive IMO 23rd Session Testing Agencies 2003 (Res. 936-965)ASTM E 1417 Standard Practice for Liquid Penetrant ISO 3183 Petroleum and natural gas industries - Examination Steel pipe for pipeline transportationASTM E1444 Standard Practice for Magnetic Parti- systems cle Examination ISO 2400 Welds in steel -- Reference block forASTM G 48 Standard Test Methods for Pitting and the calibration of equipment for ultra- Crevice Corrosion Resistance of sonic examination Stainless Steels and Related Alloys by ISO 3690 Welding and allied processes -- Deter- Use of Ferric Chloride Solution mination of hydrogen content in fer-API 6FA Specification for Fire Test for Valves- reted steel arc weld metal Third Edition; Errata 12/18/2006 ISO 4063 Welding and allied processes --API RP 2201 Safe Hot Tapping Practices in the Nomenclature of processes and refer- Petroleum & Petrochemical Indus- ence numbers tries-Fifth Edition ISO 5817 Welding - Fusion-welded joints inAWS C5.3 Recommended Practices for Air Car- steel, nickel, titanium and their alloys bon Arc Gouging and Cutting (beam welding excluded) - Quality levels for imperfectionsBSI BS 7910 Guide to methods for assessing the acceptability of flaws in metallic ISO 6847 Welding consumables -- Deposition of structures a weld metal pad for chemical analysisBSI PD 5500 Specification for Unfired fusion ISO 7005-1 Metallic flanges – Part 1: Steel welded pressure vessels FlangesEN 287-1 Qualification test of welders - Fusion ISO 7963 Non-destructive testing -- Ultrasonic welding - Part 1:Steels testing --- Specification for calibration block No. 2EN 439 Welding consumables - Shielding gases for arc welding and cutting ISO 8501-1 Preparation of steel substrates before application of paints and related prod-EN 473 Non destructive testing - Qualification ucts -- Visual assessment of surface and certification of NDT personnel - cleanliness -- Part 1: Rust grades and General principles preparation grades of uncoated steel substrates and of steel substrates after overall removal of previous coatings DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 17ISO 9000 Quality management systems -- Fun- ISO 12094 Welded steel tubes for pressure pur- damentals and vocabulary poses - Ultrasonic testing for theISO 9001 Quality management systems - detection of laminar imperfections in Requirements strips or plates used in manufacture of welded tubesISO 9001 Quality systems -- Model for quality assurance in production, installation ISO 12095 Seamless and welded steel tubes for and servicing pressure purposes - Liquid penetrant testingISO 9303 Seamless and welded (except sub- merged arc-welded) steel tubes for ISO 12096 Submerged arc-welded steel tubes for pressure purposes - Full peripheral pressure purposes - Radiographic test- ultrasonic testing for the detection of ing of the weld seam for the detection longitudinal imperfections of imperfections.ISO 9304 Seamless and welded (except sub- ISO 12715 Ultrasonic non-destructive testing -- merged arc-welded) steel tubes for Reference blocks and test procedures pressure purposes- Eddy current test- for the characterization of contact ing for the detection of imperfections search unit beam profilesISO 9305 Seamless tubes for pressure purposes - ISO 13623 Petroleum and natural gas industries – Full peripheral ultrasonic testing for Pipeline transportation systems the detection of transverse imperfec- ISO 13663 Welded steel tubes for pressure pur- tions poses - Ultrasonic testing of the areaISO 9402 Seamless and welded (except sub- adjacent to the weld seam body for merged arc welded) steel tubes for detection of laminar imperfections pressure purposes - Full peripheral ISO 13664 Seamless and welded steel tubes for magnetic transducer/ flux leakage test- pressure purposes - Magnetic particle ing of ferromagnetic steel tubes for the inspection of tube ends for the detec- detection of longitudinal imperfec- tion of laminar imperfections tions ISO 13665 Seamless and welded steel tubes forISO 9598 Seamless steel tubes for pressure pur- pressure purposes - Magnetic particle poses - Full peripheral magnetic trans- inspection of tube body for the detec- ducer/flux leakage testing of tion of surface imperfections ferromagnetic steel tubes for the ISO 14723 Petroleum and natural gas industries - detection of transverse imperfections Pipeline transportation systems - Sub-ISO 9606-1 Approval testing of welders -- Fusion sea pipeline valves welding -- Part 1: Steels ISO 14731 Welding coordination -- Tasks andISO 9712 Non-destructive testing -- Qualifica- responsibilities tion and certification of personnel ISO14732 Welding personnel -- Approval testingISO 9764 Electric resistance welded steel tubes of welding operators for fusion weld- for pressure purposes - Ultrasonic test- ing and of resistance weld setters for ing of the weld seam for longitudinal fully mechanized and automatic weld- imperfections ing of metallic materialsISO 9765 Submerged arc-welded steel tubes for ISO 15156-1 Petroleum and natural gas industries - pressure purposes - Ultrasonic testing Materials for use in H2S-containing of the weld seam for the detection of environments in oil and gas produc- longitudinal and/or transverse imper- tion - Part 1: General principles for fections selection of cracking-resistant materi-ISO 10124 Seamless and welded (except sub- als merged arc-welded) steel tubes for ISO 15156-2 Petroleum and natural gas industries - pressure purposes - Ultrasonic testing Materials for use in H2S-containing for the detection of laminar imperfec- environments in oil and gas produc- tions tion - Part 2: Cracking-resistant carbonISO 10375 Non-destructive testing -- Ultrasonic and low alloy steels, and the use of inspection -- Characterization of cast irons search unit and sound field ISO 15156-3 Petroleum and natural gas industries -ISO 10543 Seamless and hot-stretch reduced Materials for use in H2S-containing welded steel tubes for pressure pur- environments in oil and gas produc- poses - Full peripheral ultrasonic tion - Part 3: Cracking-resistant CRAs thickness testing (corrosion-resistant alloys) and other alloysISO 10474 Steel and steel products ISO 15589-2 Petroleum and natural gas industries -ISO 10497 Testing of Valves - Fire Type-Testing Cathodic protection of pipeline trans- Requirements-Second Edition portation systems - Part 2: OffshoreISO 11484 Steel tubes for pressure purposes -- pipelines Qualification and certification of non- ISO 15590-1 Petroleum and natural gas industries - destructive testing (NDT) personnel - Induction bends, fittings and flangesISO 11496 Seamless and welded steel tubes for for pipeline transportation systems -- pressure purposes - Ultrasonic testing Part 1: Induction bends of tube ends for the detection of lami- nar imperfections DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 18 – Sec.1 see note on front coverISO 15590-2 Petroleum and natural gas industries - subject to agreement. The expression may also be used to - Induction bends, fittings and flanges express interface criteria which may be modified subject to for pipeline transportation systems -- agreement. Part 2: Fittings 103 May: Verbal form used to indicate a course of action per-ISO 15590-3 Petroleum and natural gas industries - missible within the limits of the standard. - Induction bends, fittings and flanges 104 Agreement, by agreement: Unless otherwise indicated, for pipeline transportation systems -- this means agreed in writing between Manufacturer/ Contrac- Part 3: Flanges tor and Purchaser.ISO 15614-1 Specification and qualification of welding procedures for metallic mate- C 200 Definitions rials -- Welding procedure test -- Part 201 Abandonment: Abandonment comprises the activities 1: Arc and gas welding of steels and associated with taking a pipeline permanently out of operation. arc welding of nickel and nickel alloys An abandoned pipeline cannot be returned to operation.ISO 15618-2 Qualification testing of welders for Depending on the legislation this may require cover or underwater welding -- Part 2: Diver- removal. welders and welding operators for 202 Accidental loads a load with an annual frequency less hyperbaric dry welding than 10-2, see Sec.5 D1200.ISO 15649 Petroleum and natural gas industries – 203 Accumulated plastic strain: Sum of plastic strain incre- Piping ments, irrespective of sign and direction. Strain incrementsISO 16708 Petroleum and natural gas industries – shall be calculated from after the linepipe manufacturing, see Pipeline transportation systems – Reli- Sec.5 D1100. ability-based limit state methods 204 Additional requirements: Requirements that applies toISO 17636 Non-destructive testing of welds -- this standard, additional to other referred standards. Radiographic testing of fusion-welded joints 205 As-built survey: Survey of the installed and completed pipeline system that is performed to verify that the completedISO 17637 Non-destructive testing of welds -- installation work meets the specified requirements, and to doc- Visual testing of fusion-welded joints ument deviations from the original design, if any.ISO 17638 Non-destructive testing of welds -- Magnetic particle testing 206 As-laid survey: Survey performed either by continuous touchdown point monitoring or by a dedicated vessel duringISO 17640 Non-destructive testing of welds -- installation of the pipeline. Ultrasonic testing of welded joints 207 Atmospheric zone: The part of the pipeline system aboveISO 17643 Non-destructive testing of welds -- the splash zone. Eddy current testing of welds by com- plex-plane analysis 208 Buckling, global: Buckling mode which involves a sub- stantial length of the pipeline, usually several pipe joints andMSSSP-55 Quality standard for steel castings for not gross deformations of the cross section; upheaval buckling valves, flanges, and fittings and other is an example thereof, see Sec.5 D700. piping components (visual method).MSS SP-75 Specification for High Test, Wrought, 209 Buckling, local: Buckling mode confined to a short Butt Welding Fittings length of the pipeline causing gross changes of the cross sec- tion; collapse, localised wall wrinkling and kinking are exam-NORDTEST NT Techn. Report 394 (Guidelines for ples thereof, see Sec.5 D300. NDE Reliability Determination and Description, Approved 1998-04). 210 Characteristic load (LSd): The reference value of a load to be used in the determination of load effects. The character-NORSOK L-005 Compact flanged connections istic load is normally based upon a defined fractile in the upperNS 477 Welding - Rules for qualification of end of the distribution function for load, see Sec.4 G. welding inspectors 211 Characteristic resistance (RRd): The reference value of Guidance note: structural strength to be used in the determination of the design The latest revision of the DNV codes may be found in the publi- strength. The characteristic resistance is normally based upon cation list at the DNV website www.dnv.com. a defined fractile in the lower end of the distribution function for resistance. See Sec.5 C200. Amendments and corrections to the DNV codes are published bi- annually on www.dnv.com. These shall be considered as manda- 212 Clad pipe (C): Pipe with internal (corrosion resistant) tory part of the above codes. liner where the bond between (linepipe) backing steel and cladding material is metallurgical. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 213 Clamp: Circumferential structural element, split into two or more parts. Examples; connecting two hubs in a mechanical connector or two pipe half-shells for repair pur- pose C. Definitions 214 Code: Common denotation on any specification, rule,C 100 Verbal forms standard guideline, recommended practice or similar.101 Shall: Indicates requirements strictly to be followed in 215 Coiled tubing: Continuously-milled tubular productorder to conform to this standard and from which no deviation manufactured in lengths that require spooling onto a take-upis permitted. reel, during the primary milling or manufacturing process.102 Should: Indicates that among several possibilities, one is 216 Commissioning; Activities associated with the initialrecommended as particularly suitable, without mentioning or filling of the pipeline system with the fluid to be transported,excluding others, or that a certain course of action is preferred part of operational phase.but not necessarily required. Other possibilities may be applied 217 Commissioning, De-; Activities associated with taking DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 19the pipeline temporarily out of service. particles or liquid droplets.218 Commissioning, Pre-, Activities after tie-in/connection 236 Fabrication: Activities related to the assembly ofand prior to commissioning including system pressure testing, objects with a defined purpose in a pipeline system.de-watering, cleaning and drying. 237 Fabrication factor (γfab): Factor on the material strength219 Concept development phase: The concept development in order to compensate for material strength reduction fromphase will typically include both business evaluations, collect- cold forming during manufacturing of linepipe, see Table 5-7.ing of data and technical early phase considerations. 238 Fabricator: The party performing the fabrication.220 Condition load effect factor (γC): A load effect factor 239 Failure: An event affecting a component or system andincluded in the design load effect to account for specific load causing one or both of the following effects:conditions, see Sec.4 G200 Table 4-5.221 Connector: Mechanical device used to connect adjacent — loss of component or system function; orcomponents in the pipeline system to create a structural joint — deterioration of functional capability to such an extent thatresisting applied loads and preventing leakage. Examples: the safety of the installation, personnel or environment isThreaded types, including (i) one male fitting (pin), one female significantly reduced.fitting (integral box) and seal ring(s), or (ii) two pins, a cou-pling and seals sea rings(s); Flanged types, including two 240 Fatigue: Cyclic loading causing degradation of theflanges, bolts and gasket/seal ring; Clamped hub types, includ- material.ing hubs, clamps, bolts and seal ring(s); Dog-type connectors. 241 Fittings: Includes: Elbows, caps, tees, single or multiple222 Construction phase: The construction phase will typi- extruded headers, reducers and transition sectionscally include manufacture, fabrication and installation activi- 242 Flange: Collar at the end of a pipe usually provided withties. Manufacture activities will typically include manufacture holes in the pipe axial direction for bolts to permit other objectsof linepipe and corrosion protection and weight coating. Fab- to be attached to it.rication activities will typically include fabrication of pipelinecomponents and assemblies. Installation activities will typical 243 Fluid categorisation: Categorisation of the transportedinclude pre- and post intervention work, transportation, instal- fluid according to hazard potential as defined in Table 2-1.lation, tie-in and pre-commissioning. 244 Fractile: The p-fractile (or percentile) and the corre-223 Contractor: A party contractually appointed by the Pur- sponding fractile value xp is defined as:chaser to fulfil all, or any of, the activities associated with F ( xp ) = pdesign, construction and operation.224 Corrosion allowance (tcorr): Extra wall thickness added F is the distribution function for xpduring design to compensate for any reduction in wall thick- 245 Hub: The parts in a mechanical connector joined by a clamp.ness by corrosion (internally/externally) during operation, seeSec.6 D200. 246 Hydrogen Induced Cracking (HIC): Internal cracking of rolled materials due to a build-up of hydrogen pressure in225 Corrosion control: All relevant measures for corrosion micro-voids (Related terms: stepwise cracking).protection, as well as the inspection and monitoring of corro-sion, see Sec.6 D100. 247 Hydrogen Induced Stress Cracking (HISC): Cracking that results from the presence of hydrogen in a metal while226 Corrosion protection: Use of corrosion resistant materi- subjected to tensile stresses (residual and/or applied). Theals, corrosion allowance and various techniques for "corrosion source of hydrogen may be welding, corrosion, cathodic pro-mitigation", see Sec.6 D100 tection, electroplating or some other electrochemical process.227 Coupling: Mechanical device to connect two bare pipes Crack growth proceeds by a hydrogen embrittlement mecha-to create a structural joint resisting applied loads and prevent- nism at the crack tip, i.e. the bulk material is not necessarilying leakage. embrittled by hydrogen. HISC by corrosion in presence of228 Design: All related engineering to design the pipeline hydrogen sulphide is referred to as Sulphide Stress Crackingincluding both structural as well as material and corrosion. (SSC).229 Design case: Characterisation of different load catego- 248 Hydro-test or Hydrostatic test: See Mill pressure testries, see Sec.4 A500. 249 Inspection: Activities such as measuring, examination,230 Design life: The initially planned time period from ini- weighing testing, gauging one or more characteristics of atial installation or use until permanent decommissioning of the product or service and comparing the results with specifiedequipment or system. The original design life may be extended requirements to determine conformity.after a re-qualification. 250 Installation (activity): The operations related to install-231 Design premises: A set of project specific design data ing the equipment, pipeline or structure, e.g. pipeline laying,and functional requirements which are not specified or which tie-in, piling of structure etc.are left open in the standard to be prepared prior to the design 251 Installation (object): See Offshore installation.phase. 252 Installation Manual (IM): A document prepared by the232 Design phase: The design phase will typically be split Contractor to describe and demonstrate that the installationinto FEED-phase, basic design and detail design. For each method and equipment used by the Contractor will meet thedesign phase, the same design tasks are repeated but in more specified requirements and that the results can be verified.and more specific and detailed level. 253 Integrity: See Pipeline integrity.233 Dynamic riser: A riser which motion will influence the 254 Jointer: Two lengths of pipe welded together by thehydrodynamic load effects or where inertia forces become sig- manufacturer to build up one complete (≈40’) pipe joint.nificant. 255 J-tube: A J-shaped tube installed on a platform, through234 Engineering Critical Assessment (ECA): Fracture which a pipe can be pulled to form a riser. The J-tube extendsmechanics assessment of the acceptability of flaws in metallic from the platform deck to and inclusive of the bottom bend atmaterials. the seabed. The J-tube supports connect the J-tube to the sup-235 Erosion: Material loss due to repeated impact of sand porting structure. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 20 – Sec.1 see note on front cover256 Limit state: A state beyond which the structure no longer 276 Offshore installation (object): General term for mobilesatisfies the requirements. The following limit states catego- and fixed structures, including facilities, which are intendedries are of relevance for pipeline systems: for exploration, drilling, production, processing or storage of hydrocarbons or other related activities/fluids. The term— Serviceability Limit State (SLS): A condition which, if includes installations intended for accommodation of person- exceeded, renders the pipeline unsuitable for normal oper- nel engaged in these activities. Offshore installation covers ations. Exceedance of a serviceability limit state category subsea installations and pipelines. The term does not cover tra- shall be evaluated as an accidental limit state. ditional shuttle tankers, supply boats and other support vessels— Ultimate Limit State (ULS): A condition which, if which are not directly engaged in the activities described exceeded, compromises the integrity of the pipeline. above.— Fatigue Limit State (FLS): An ULS condition accounting 277 Operation, Incidental: Conditions which that are not for accumulated cyclic load effects. part of normal operation of the equipment or system. In rela-— Accidental Limit State (ALS): An ULS due to accidental tion to pipeline systems, incidental conditions may lead to inci- (in-frequent) loads. dental pressures, e.g. pressure surges due to sudden closing of257 Lined pipe (L): Pipe with internal (corrosion resistant) valves, or failure of the pressure control system and activationliner where the bond between (linepipe) backing steel and liner of the pressure safety system.material is mechanical. 278 Operation, Normal: Conditions that arise from the258 Load: Any action causing stress, strain, deformation, intended use and application of equipment or system, includ-displacement, motion, etc. to the equipment or system. ing associated condition and integrity monitoring, mainte- nance, repairs etc. In relation to pipelines, this should include259 Load categories: Functional load, environmental load, steady flow conditions over the full range of flow rates, as wellinterference load or accidental load, see Sec.4 A. as possible packing and shut-in conditions where these occur260 Load effect: Effect of a single load or combination of as part of routine operation.loads on the equipment or system, such as stress, strain, defor- 279 Operation phase: The operation phase starts with themation, displacement, motion, etc. commissioning, filling the pipeline with the intended fluid.261 Load effect combinations: See Sec.4 A. The operation phase will include inspection and maintenance activities. In addition, the operation phase may also include262 Load effect factor (γF, γE, γA): The partial safety factor modifications, re-qualifications and de-commissioning.by which the characteristic load effect is multiplied to obtainthe design load effect, see Sec.4 G200. 280 Operator: The party ultimately responsible for concept development, design, construction and operation of the pipe-263 Load scenarios: Scenarios which shall be evaluated, see line system. The operator may change between phases.Sec.4 A. 281 Out of roundness: The deviation of the linepipe perime-264 Location class: A geographic area of pipeline system, ter from a circle. This can be stated as ovalisation (%), or assee Table 2-2. local out of roundness, e.g. flattening, (mm).265 Lot: Components of the same size and from the same 282 Ovalisation: The deviation of the perimeter from a cir-heat, the same heat treatment batch. cle. This has the form of an elliptic cross section.266 Manufacture: Making of articles or materials, often in 283 Partial safety factor: A factor by which the characteris-large volumes. In relation to pipelines, refers to activities for tic value of a variable is modified to give the design value (i.e.the production of linepipe, anodes and other components and a load effect, condition load effect, material resistance orapplication of coating, performed under contracts from one or safety class resistance factor), see Sec.5 C.more Contractors. 284 Pipe, High Frequency Welded (HFW): Pipe manufac-267 Manufacturer: The party who is contracted to be respon- tured by forming from strip and with one longitudinal seamsible for planning, execution and documentation of manufac- formed by welding without the addition of filler metal. Theturing. longitudinal seam is generated by high frequency current268 Manufacturing Procedure Specification (MPS): A man- applied by induction or conduction.ual prepared by the Manufacturer to demonstrate how the spec- 285 Pipe, Seamless (SMLS): Pipe manufactured in a hotified properties may be achieved and verified through the forming process resulting in a tubular product without aproposed manufacturing route. welded seam. The hot forming may be followed by sizing or269 Material resistance factor (γm): Partial safety factor cold finishing to obtain the required dimensions.transforming a characteristic resistance to a lower fractile 286 Pipe, Submerged Arc-Welded Longitudinal or Helicalresistance, see Sec.5 C200 Table 5-4. (SAWL or SAWH): Pipe manufactured by forming from strip270 Material strength factor (αu ): Factor for determination or plate, and with one longitudinal (SAWL) or helicalof the characteristic material strength reflecting the confidence (SAWH) seam formed by the submerged arc process with atin the yield stress see Sec.5 C300 Table 5-6. least one pass made on the inside and one pass from the outside of the pipe.271 Mill pressure test: The hydrostatic strength test per-formed at the mill, see Sec.5 B200. 287 Pipeline Components: Any items which are integral parts of the pipeline system such as flanges, tees, bends, reduc-272 Nominal outside diameter: The specified outside diame- ers and valves.ter. 288 Pipeline Integrity: Pipeline integrity is the ability of the273 Nominal pipe wall thickness: The specified non-cor- submarine pipeline system to operate safely and withstand theroded pipe wall thickness of a pipe, which is equal to the min- loads imposed during the pipeline lifecycle.imum steel wall thickness plus the manufacturing tolerance. 289 Pipeline Integrity Management: The pipeline integrity274 Nominal strain: The total engineering strain not management process is the combined process of threat identi-accounting for strain concentration factors. fication, risk assessments, planning, monitoring, inspection,275 Nominal plastic strain: The nominal strain minus the lin- maintenance etc. to maintain pipeline integrity.ear strain derived from the stress-strain curve, see Sec.5 290 Pipeline System: pipeline with compressor or pump sta-Figure 3. tions, pressure control stations, flow control stations, metering, DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 21tankage, supervisory control and data acquisition system sient) operation. The maximum allowable incidental pressure(SCADA), safety systems, corrosion protection systems, and is defined as the maximum incidental pressure less the positiveany other equipment, facility or building used in the transpor- tolerance of the pressure safety system, see Figure 1 andtation of fluids. Sec.3 B300.See also Submarine pipeline system. 304 Pressure, Maximum Allowable Operating (MAOP): In291 Pipeline walking: Accumulation of incremental axial relation to pipelines, this is the maximum pressure at which thedisplacement of pipeline due to start-up and shut-down. pipeline system shall be operated during normal operation. The maximum allowable operating pressure is defined as the292 Pressure control system: In relation to pipelines, this is design pressure less the positive tolerance of the pressure pro-the system which, irrespective of the upstream pressure, tection system, see Figure 1 and Sec.3 B300.ensures that the maximum allowable operating pressure is notexceeded, see Figure 1 and Sec.3 B300. 305 Pressure, Mill test (ph): The test pressure applied to pipe joints and pipe components upon completion of manufacture293 Pressure protection system: In relation to pipelines, this and fabrication, see Sec.5 B200.is the system for control of the pressure in pipelines, compris-ing the Pressure Control System, Pressure Safety System and 306 Pressure, Operation (po): The most probable pressureassociated instrument and alarm systems, see Figure 1 and during 1-year operation.Sec.3 B300. 307 Pressure, Propagating (ppr): The lowest pressure294 Pressure safety system: The system which, independent required for a propagating buckle to continue to propagate, seeof the pressure control system, ensures that the allowable inci- Sec.5 D500.dental pressure is not exceeded, see Figure 1 and Sec.3 B300. 308 Pressure, shut-in: The maximum pressure that can be295 Pressure test: See System pressure test attained at the wellhead during closure of valves closest to the wellhead (wellhead isolation). This implies that pressure tran-296 Pressure, Collapse (pc): Characteristic resistance sients due to valve closing shall be included.against external over-pressure, see Sec.5 D400. 309 Pressure, System test (ptest): In relation to pipelines, this297 Pressure, Design (pd): In relation to pipelines, this is the is the internal pressure applied to the pipeline or pipeline sec-maximum internal pressure during normal operation, referred tion during testing on completion of installation work to testto a specified reference elevation, see Figure 1 and Sec.3 B300. the pipeline system for tightness (normally performed as298 Pressure, Hydro- or Hydrostatic test: See Pressure, Mill hydrostatic testing), see Sec.5 B200.test. 310 Pressure, Test: See Pressure, System test.299 Pressure, Incidental (pinc): In relation to pipelines, this 311 Purchaser: The owner or another party acting on hisis the maximum internal pressure the pipeline or pipeline sec- behalf, who is responsible for procuring materials, componentstion is designed to withstand during any incidental operating or services intended for the design, construction or modifica-situation, referred to the same reference elevation as the design tion of a installation or a pipeline.pressure, see Figure 1 and Sec.3 B300. 312 Quality Assurance (QA): Planned and systematic actions necessary to provide adequate confidence that a prod- Internal Pressure uct or service will satisfy given requirements for quality. (The Quality Assurance actions of an organisation is described in a Quality Manual stating the Quality Policy and containing the Accidental necessary procedures and instructions for planning and per- Pressure forming the required actions). Incidental Pressure Maximum Allowable 313 Quality Control (QC): The internal systems and prac- Tolerance of Pressure Safety System Incidental Pressure tices (including direct inspection and materials testing), used (MAIP) Pressure by manufacturers to ensure that their products meet the Pressure System Protection required standards and specifications. Safety System 314 Quality Plan (QP): The document setting out the spe- Design Pressure Maximum Allowable cific quality practices, resources and sequence of activities rel- Tolerance of Operating Pressure evant to a particular product, project or contract. A quality plan Pressure Control System (MAOP) usually makes reference to the part of the quality manual (e.g. Pressure procedures and work instructions) applicable to the specific System Control case. 315 Ratcheting: Accumulated deformation during cyclic loading, especially for diameter increase, see Sec.5 D1000.Figure 1 Does not include so called Pipeline Walking.Pressure definitions 316 Reliability: The probability that a component or system will perform its required function without failure, under statedC 300 Definitions (continuation) conditions of operation and maintenance and during a speci- fied time interval.301 Pressure, Initiation: The external over-pressure requiredto initiate a propagating buckle from an existing local buckle 317 Re-qualification: The re-assessment of a design due toor dent, see Sec.5 D500. modified design premises and/or sustained damage.302 Pressure, Local; Local Design, Local Incidental or 318 Resistance: The capability of a structure, or part of aLocal Test: In relation to pipelines, this is the internal pressure structure, to resist load effects, see Sec.5 C200.at any point in the pipeline system or pipeline section for the 319 Riser: A riser is defined as the connecting piping or flex-corresponding design pressure, incidental pressure or test pres- ible pipe between a submarine pipeline on the seabed andsure adjusted for the column weight, see Sec.4 B200. installations above water. The riser extends to the above sea303 Pressure, Maximum Allowable Incidental (MAIP): In emergency isolation point between the import/export line andrelation to pipelines, this is the maximum pressure at which the the installation facilities, i.e. riser ESD valve.pipeline system shall be operated during incidental (i.e. tran- 320 Riser support/clamp: A structure which is intended to DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 22 – Sec.1 see note on front coverkeep the riser in place. — the first valve, flange or connection above water on plat-321 Riser system: A riser system is considered to comprise form or floaterriser, its supports, all integrated pipelining components, and — the connection point to the subsea installation (i.e. pipingcorrosion protection system. manifolds are not included) — the first valve, flange, connection or insulation joint at a322 Risk: The qualitative or quantitative likelihood of an landfall unless otherwise specified by the on-shore legisla-accidental or unplanned event occurring, considered in con- tion.junction with the potential consequences of such a failure. Inquantitative terms, risk is the quantified probability of a The component above (valve, flange, connection, insulationdefined failure mode times its quantified consequence. joint) includes any pup pieces, i.e. the submarine pipeline sys-323 Safety Class (SC): In relation to pipelines; a concept tem extends to the weld beyond the pup piece.adopted to classify the significance of the pipeline system with 337 Submerged zone: The part of the pipeline system orrespect to the consequences of failure, see Sec.2 C400. installation below the splash zone, including buried parts.324 Safety class resistance factor (γSC): Partial safety factor 338 Supplementary requirements: Requirements for materialwhich transforms the lower fractile resistance to a design properties of linepipe that are extra to the additional require-resistance reflecting the safety class, see Table 5-5. ments to ISO and that are intended to apply to pipe used for325 Single event: Straining in one direction. specific applications.326 Slamming: Impact load on an approximately horizontal 339 System effects: System effects are relevant in casesmember from a rising water surface as a wave passes. The where many pipe sections are subjected to an invariant loadingdirection is mainly vertical. condition, and potential structural failure may occur in connec- tion with the lowest structural resistance among the pipe sec-327 Slapping: Impact load on an approximately vertical sur- tions, see Sec.4 G200.face due to a breaking wave. The direction is mainly horizontal. 340 System pressure test: Final test of the complete pipeline328 Specified Minimum Tensile Strength (SMTS): The mini- system, see Sec.5 B200.mum tensile strength prescribed by the specification or stand-ard under which the material is purchased. 341 Target nominal failure probability: A nominal accepta- ble probability of structural failure. Gross errors are not329 Specified Minimum Yield Stress (SMYS): The minimum included, see Sec.2 C500.yield stress prescribed by the specification or standard underwhich the material is purchased. 342 Temperature, design, maximum: The highest possible temperature profile to which the equipment or system may be330 Splash zone: External surfaces of a structure or pipeline exposed to during installation and operation.that are periodically in and out of the water by the influence ofwaves and tides. 343 Temperature, design, minimum: The lowest possible temperature profile to which the component or system may be331 Splash Zone Height: The vertical distance between exposed to during installation and operation. This may besplash zone upper limit and splash zone lower limit. applied locally, see Sec.4 B107332 Splash Zone Lower Limit (LSZ) is determined by: 344 Test unit: A prescribed quantity of pipe that is made to the specified outer diameter and specified wall thickness, by LSZ = |L1| - |L2| - |L3| the same pipe-manufacturing process, from the same heat, and L1 = lowest astronomic tide level (LAT) under the same pipe-manufacturing conditions. L2 = 30% of the Splash zone wave-related height 345 Threats: An indication of impending danger or harm to defined in 334 the pipeline system. L3 = upward motion of the riser. 346 Tide: See Sec.3 D300.333 Splash Zone Upper Limit (USZ) is determined by: 347 Ultimate Tensile Strength (UTS): The measured ulti- mate tensile strength. USZ = |U1| + |U2| + |U3| 348 Verification: An examination to confirm that an activity, U1 = highest astronomic tide level (HAT) a product or a service is in accordance with specified require- ments. U2 = 70% of the splash zone wave-related height defined in 334 349 Weld, strip/plate end: Weld that joins strip or plate joins together. U3 = settlement or downward motion of the riser, if applicable 350 Work: All activities to be performed within relevant con- tract(s) issued by Owner, Operator, Contractor or Manufac-334 Splash zone wave-related height: The wave height with turer.a probability of being exceeded equal to 10-2, as determined 351 Yield Stress (YS): The measured yield tensile stress.from the long term distribution of individual waves. If thisvalue is not available, an approximate value of the splash zoneheight may be taken as: 0.46 Hs100 D. Abbreviations and SymbolsWhere D 100 AbbreviationsHs100 = significant wave height with a 100 year return period335 Submarine Pipeline: A submarine pipeline is defined as ALS Accidental Limit Statethe part of a submarine pipeline system which, except for pipe-line risers is located below the water surface at maximum tide,. AR Additional Requirement (to ISO 3183), seeThe pipeline may, be resting wholly or intermittently on, or Sec.7 B102buried below, the seabed. API American Petroleum Institute336 Submarine Pipeline System: a submarine pipeline sys- ASD Allowable Stress Designtem extends to the first weld beyond: ASME American Society of Mechanical Engineers DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 23ASTM American Society for Testing and Materials MPQT Manufacturing Procedure Qualification TestAUT Automated Ultrasonic Testing MPS Manufacturing Procedure SpecificationBE Best Estimate MR Modified Requirement (to ISO 3183), seeBM Base material Sec.7 B102BS British Standard MSA Manufacturing Survey ArrangementC Clad pipe MT Magnetic Particle TestingC-Mn Carbon Manganese MWP Multiple Welding ProcessCP Cathodic Protection N NormalisedCRA Corrosion Resistant Alloy NACE National Association of Corrosion EngineersCTOD Crack Tip Opening Displacement NDT Non-Destructive TestingCVN Charpy V-Notch OD Outside DiameterDAC Distance Amplitude Correction P ProductionDC Displacement controlled PIM Pipeline Integrity ManagementDFI Design, Fabrication and Installation PRE Pitting Resistance EquivalentDNV Det Norske Veritas PRL Primary Reference LevelDP Dynamic Positioning PT Penetrant TestingDWTT Drop Weight Tear Testing PTFE Poly Tetra Flour EthyleneEBW Electron Beam Welded PWHT Post weld heat treatmentEC Eddy Current Testing pWPS preliminary Welding Procedure SpecificationECA Engineering Critical Assessment Q QualificationEDI Electronic Data Interchange QA Quality AssuranceEMS Electro Magnetic Stirring QC Quality ControlERW Electric Resistance Welding QP Quality PlanESD Emergency Shut Down QRA Quantitative Risk AssessmentFEED Front End Engineering Design QT Quenched and TemperedFLS Fatigue Limit State ROV Remotely Operated VehicleFMEA Failure Mode Effect Analysis RT Radiographic testingG-FCAW Gas-Flux Core Arc Welding SAWH Submerged Arc-welding HelicalGMAW Gas Metal Arc Welding SAWL Submerged Arc-welding LongitudinalHAT Highest Astronomical Tide SC Safety ClassHAZ Heat Affected Zone SCF Stress Concentration FactorHAZOP Hazard and Operability Study SCR Steel Catenary RiserHFW High Frequency Welding SENB Singel Edge Notched Bend fracture mechanics specimenHIPPS High Integrity Pressure Protection System SENT Single Edge Notched Tension fracture mechan-HIC Hydrogen Induced Cracking ics specimenHISC Hydrogen Induced Stress Cracking SLS Serviceability Limit StateID Internal Diameter SMAW Shielded Metal Arc WeldingIM Installation Manual SMLS Seamless PipeISO International Organization for Standardization SMTS Specified Minimum Tensile StrengthJ-R curve Plot of resistance to stable crack growth for SMYS Specified Minimum Yield Stress establishing crack extension SN Stress versus number of cycles to failureKV Charpy value SNCF Strain Concentration FactorKVL Charpy value in pipe longitudinal direction SRA Structural Reliability AnalysisKVT Charpy value in pipe transversal direction SSC Sulphide Stress CrackingL Lined pipe or load effect ST Surface testingLAT Lowest Astronomic Tide TCM Two Curve MethodLB Lower Bound TMCP Thermo-Mechanical Controlled ProcessLC Load controlled TOFD Time of Flight DiffractionLBW Laser Beam Welded TRB Three Roll BendingLBZ Local Brittle Zones UB Upper BoundLRFD Load and Resistance Factor Design ULS Ultimate Limit StateLSZ Splash Zone Lower Limit UO Pipe fabrication process for welded pipesM/A Martensitic/Austenite UOE Pipe fabrication process for welded pipes,MAIP Maximum Allowable Incidental Pressure expandedMAOP Maximum Allowable Operating Pressure USZ Splash Zone Upper LimitMDS Material Data Sheet DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 24 – Sec.1 see note on front coverUT Ultrasonic testing pel Elastic collapse pressure, see Eq. 5.11UTS Ultimate Tensile Strength pf Failure probabilityVT Visual Testing pf,T Target nominal failure probabilityWM Weld Metal ph Mill test pressure, see Sec.7 E100WPQT Welding Procedure Qualification Test pi Characteristic internal pressureWPS Welding Procedure Specification pinc Incidental pressureYS Yield Stress pinit Initiation pressure pld Local design pressureD 200 Symbols pli Local incidental pressure, see Eq. 4.1201 Latin characters plt Local test pressure (system test), see Eq. 4.2a Crack depth pp Plastic collapse pressure, see Eq. 5.12A Cross section area ppr Propagating pressure, see Eq. 5.16Ae π ppr,A Propagating buckle capacity of infinite buckle ⋅ D 2 Pipe external cross section area arrestor 4 pt System test pressure, see Eq. 4.2, 5.1 and 5.2Ai π (D − 2 ⋅ t )2 Pipe internal cross section area px Crossover pressure, see Eq. 5.18 4 R Global bending radius of pipe, Reaction force orAs π ⋅ (D − t )⋅ t Pipe steel cross section area Resistance Rm Tensile strengthB Specimen width Rpx Strength equivalent to a permanent elongation ofD Nominal outside diameter. x% (actual stress)Dfat Miner’s sum Rtx Strength equivalent to a total elongation of x%Di D-2tnom Nominal internal diameter (actual stress)Dmax Greatest measured inside or outside diameter S Effective axial force (Tension is positive)Dmin Smallest measured inside or outside diameter Sm Resistance to failureE Youngs Modulus Sr Ultimate statef0 Dmax _ Dmin Ovality tc Characteristic thickness to be replaced by t1 or t2 as relevant, see Table 5-2 D T Temperaturefcb Minimum of fy and fu/1.15, see Eq. 5.9 t, tnom Nominal wall thickness of pipe (un-corroded)fu Tensile strength to be used in design, see Eq. 5.6 T0 Testing temperaturefu,temp Derating on tensile stress to be used in design, see t1, t2 Pipe wall thickness, see Table 5-2 Eq. 5.6 tcorr Corrosion allowance, see Table 5-2fy Yield stress to be used in design, see Eq. 5.5 Tc/Tc’ Contingency time for operation/ceasing opera-fy,temp Derating on yield stress to be used in design, see tion, see Sec.4 C600 Eq. 5.5 tfab Fabrication thickness tolerance, see Table 7-18g Gravity acceleration tm,min Measured minimum thicknessH Residual lay tension, see Eq. 4.10 and Eq. 4.11 Tmax Maximum design temperature, see Sec.4 B100hl Local height at pressure point, see Eq. 4.1 Tmin Minimum design temperature, see Sec.4 B100Hp Permanent plastic dent depth tmin Minimum thicknesshref Elevation at pressure reference level, see Eq. 4.1 Tpop Planned operational period, see Sec.4 C600Hs Significant wave height TR/TR’ Reference period for operation/ceasing opera-ID Nominal inside diameter tion, see Sec.4 C600k number of stress blocks TSafe Planned time to cease operation, see Sec.4 C600L Characteristic load effect TWF Time between generated weather forecasts.M Moment W Section modulus or Specimen thickness.N Axial force in pipe wall ("true" force) (tension is Wsub Submerged weight positive) or Number of load effect cyclesni Number of stress blocks D 300 Greek charactersNi Number of stress cycles to failure at constant amplitude α Thermal expansion coefficientO Out of roundness, Dmax - Dmin αc Flow stress parameter, see Eq. 5.22OD Outside nominal diameter αfab Fabrication factor, see Table 5-7pb Pressure containment resistance, see Eq. 5.8 αfat Allowable damage ratio for fatigue, see Table 5-9pc Characteristic collapse pressure, see Eq. 5.10 αgw Girth weld factor (strain resistance), see Eq. 5.30pd Design pressurePDi (i’th) Damaging event, see Eq. 5.34pe External pressure DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.1 – Page 25αh Rt 0,5 ρcont Density pipeline content Rm ρt Density pipeline content during system pressure max test Minimum strain hardening σ Standard deviation of a variable (e.g. thickness)αp Pressure factor used in combined loading criteria, σe Equivalent stress, Von Mises, see Eq. 5.38 see Eq. 5.23 σh Hoop stress, see Eq. 5.39αpm Plastic moment reduction factor for point loads, σl Longitudinal/axial stress, see Eq. 5.40 see Eq. 5.26αU Material strength factor, see Table 5-6 τ lh Tangential shear stressβ Factor used in combined loading criteria D 400 Subscriptsε Strainεc Characteristic bending strain resistance, see Eq. A Accidental load 5.30 BA Buckle arrestorεf Accumulated plastic strain resistance c Characteristic resistanceεl.nom Total nominal longitudinal strain d Design valueεp Plastic strain Sd Design load (i.e. including load effect factors)εr Residual strain Rd Design resistance (i.e. including partial resistanceεr,rot Residual strain limit factors)γA Load effect factor for accidental load, see E Environmental load Table 4-4 e ExternalγC Condition load effect factor, see Table 4-5 el ElasticγE Load effect factor for environmental load, see F Functional load Table 4-4 h Circumferential direction (hoop direction)γε Resistance factor, strain resistance, see Table 5-8 H Circumferential direction (hoop direction)γF Load effect factor for functional load, see Table i Internal 4-4 L Axial (longitudinal) directionγinc Incidental to design pressure ratio, see Table 3-1 M Momentγm Material resistance factor, see Table 5-4 p Plasticγrot Safety factor for residual strain R Radial directionγSC Safety class resistance factor, see Table 5-5 s Steelη Usage factor S SLSκ Curvature U ULSν Poisson’s ratio X Crossover (buckle arrestors)μ Friction coefficient DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 26 – Sec.2 see note on front cover SECTION 2 SAFETY PHILOSOPHY A. General and implemented, covering all phases from conceptual devel- opment until abandonment.A 100 Objective Guidance note:101 This section presents the overall safety philosophy that Most companies have a policy regarding human aspects, envi-shall be applied in the concept development, design, construc- ronment and financial issues. These are typically on an overalltion, operation and abandonment of pipelines. level, but may be followed by more detailed objectives and requirements in specific areas. These policies should be used asA 200 Application a basis for defining the Safety Objective for a specific pipeline system. Typical statements may be:201 This section applies to all submarine pipeline systemswhich are to be built and operated in accordance with this - The impact on the environment shall be reduced to as far as reasonably possible.standard. - No releases will be accepted during operation of the pipeline202 The integrity of a submarine pipeline system shall be system.ensured through all phases, from initial concept through to - There shall be no serious accidents or loss of life during thefinal de-commissioning, see Figure 1. This standard defines construction period.two integrity stages: establish integrity in the concept develop- - The pipeline installation shall not, under any circumstances impose any threat to fishing gear.ment, design and construction phases; and maintain integrity in - Diverless installation and maintenance.the operations phase. Statements such as those above may have implications for all or203 This section also provides guidance for extension of this individual phases only. They are typically more relevant for thestandard in terms of new criteria, etc. work execution (i.e. how the Contractor executes his job) and specific design solutions (e.g. burial or no burial). Having defined the Safety Objective, it can be a point of discussion as to whether this is being accomplished in the actual project. It is B. Safety Philosophy Structure therefore recommended that the overall Safety Objective be fol- lowed up by more specific, measurable requirements.B 100 General If no policy is available, or if it is difficult to define the safety101 The integrity of the submarine pipeline system con- objective, one could also start with a risk assessment. The risk assessment could identify all hazards and their consequences,structed to this standard is ensured through a safety philosophy and then enable back-extrapolation to define acceptance criteriaintegrating different parts as illustrated in Figure 2. and areas that need to be followed up more closely.102 The overall safety principles and the arrangement of In this standard, the structural failure probability is reflected insafety systems shall be in accordance with DNV-OS-A101 and the choice of three safety classes (see B400). The choice of safetyDNV-OS-E201. class should also include consideration of the expressed safety objective.B 200 Safety objective ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---201 An overall safety objective shall be established, planned Concept Design Construction Operation Corrosion protection and weight coating Components and assemblies Business development Concept development Integrity management Inspection and repair Pre-commissioning Post-intervention Pre-intervention Re-qualification Commissioning Abandonment Detail design Basic design Installation Linepipe 2* & 3 4, 5 & 6 7 8 9 10 11 Establish Integrity Maintain IntegrityFigure 1 *indicates Section in this Standard.Integrity assurance activities during the pipeline system phases DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.2 – Page 27 gross errors (human errors) shall be controlled by requirements for organisation of the work, competence of persons perform- ing the work, verification of the design, and quality assurance during all relevant phases. 502 For the purpose of this standard, it is assumed that the operator of a pipeline system has established a quality objec- tive. The operator shall, in both internal and external quality related aspects, seek to achieve the quality level of products and services intended in the quality objective. Further, the operator shall provide assurance that intended quality is being, or will be, achieved. 503 Documented quality systems shall be applied by opera- tors and other parties (e.g. design contractors, manufactures, fabricators and installation contractors) to ensure that prod- ucts, processes and services will be in compliance with the requirements of this standard. Effective implementation of quality systems shall be documented. 504 Repeated occurrence of non-conformities reflecting sys- tematic deviations from procedures and/or inadequate work-Figure 2 manship shall initiate:Safety Philosophy structure — investigation into the causes of the non-conformities — reassessment of the quality systemB 300 Systematic review of risks — corrective action to establish possible acceptability of301 A systematic review shall be carried out at all phases to productsidentify and evaluate threats, the consequences of single fail- — preventative action to prevent re-occurrence of similarures and series of failures in the pipeline system, such that nec- non-conformities.essary remedial measures can be taken. The extent of thereview or analysis shall reflect the criticality of the pipeline Guidance note:system, the criticality of a planned operation, and previous ISO 9000 give guidance on the selection and use of quality sys-experience with similar systems or operations. tems. Guidance note: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- A methodology for such a systematic review is quantitative risk analysis (QRA). This may provide an estimation of the overall 505 Quality surveillance in the construction phase shall be risk to human health and safety, environment and assets and performed by the operator or an inspectorate nominated by the comprises: operator. The extent of quality surveillance shall be sufficient - hazard identification to establish that specified requirements are fulfilled and that - assessment of probabilities of failure events the intended quality level is maintained. - accident developments 506 To ensure safety during operations phase, an integrity - consequence and risk assessment. management system in accordance with Sec.11 C shall be The scope of the systematic review should comprise the entire established and maintained. pipeline system, and not just the submarine pipeline system as defined by this standard. B 600 Health, safety and environment It should be noted that legislation in some countries requires risk 601 The concept development, design, construction, opera- analysis to be performed, at least at an overall level to identify tion and abandonment of the pipeline system shall be con- critical scenarios that might jeopardise the safety and reliability of a pipeline system. Other methodologies for identification of ducted in compliance with national legislation and company potential hazards are Failure Mode and Effect Analysis (FMEA) policy with respect to health, safety and environmental and Hazard and Operability studies (HAZOP). aspects. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 602 The selection of materials and processes shall be con- ducted with due regard to the safety of the public and employ-302 Special attention shall be given to sections close to ees and to the protection of the environment.installations or shore approaches where there is frequenthuman activity and thus a greater likelihood and consequenceof damage to the pipeline. This also includes areas where pipe-lines are installed parallel to existing pipelines and pipeline C. Risk Basis for Designcrossings. C 100 GeneralB 400 Design criteria principles 101 The design format within this standard is based upon a401 In this standard, structural safety of the pipeline system limit state and partial safety factor methodology, also calledis ensured by use of a safety class methodology. The pipeline Load and Resistance Factor Design format (LRFD). The loadsystem is classified into one or more safety classes based on and resistance factors depend on the safety class, which char-failure consequences, normally given by the content and loca- acterizes the consequences of failure.tion. For each safety class, a set of partial safety factors isassigned to each limit state. C 200 Categorisation of fluidsB 500 Quality assurance 201 Fluids to be transported by the pipeline system shall be categorised according to their hazard potential as given by501 The safety format within this standard requires that Table 2-1. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 28 – Sec.2 see note on front cover 403 For normal use, the safety classes in Table 2-4 apply:Table 2-1 Classification of fluidsCategory Description Table 2-4 Normal classification of safety classes*A Typical non-flammable water-based fluids. Phase Fluid Category A, C Fluid Category B, D and EB Flammable and/or toxic fluids which are liquids at Location Class Location Class ambient temperature and atmospheric pressure condi- 1 2 1 2 tions. Typical examples are oil and petroleum products. Temporary1,2 Low Low - - Methanol is an example of a flammable and toxic fluid. Operational Low Medium3 Medium HighC Non-flammable fluids which are non-toxic gases at ambient temperature and atmospheric pressure condi- 1) Installation until pre-commissioning (temporary phase) will normally be tions. Typical examples are nitrogen, carbon dioxide, classified as safety class Low. argon and air. 2) For safety classification of temporary phases after commissioning, spe-D Non-toxic, single-phase natural gas. cial consideration shall be made to the consequences of failure, i.e. givingE Flammable and/or toxic fluids which are gases at ambi- a higher safety class than Low. ent temperature and atmospheric pressure conditions 3) Risers during normal operation will normally be classified as safety class and which are conveyed as gases and/or liquids. Typical High. examples would be hydrogen, natural gas (not otherwise covered under category D), ethane, ethylene, liquefied * Other classifications may exist depending on the conditions and critical- petroleum gas (such as propane and butane), natural gas ity of failure the pipeline. For pipelines where some consequences are liquids, ammonia, and chlorine. more severe than normal, i.e. when the table above does not apply, the selection of a higher safety class shall also consider the implication, on202 Gases or liquids not specifically identified in Table 2-1 the total gained safety. If the total safety increase is marginal, the selec-should be classified in the category containing fluids most sim- tion of a higher safety class may not be justified.ilar in hazard potential to those quoted. If the fluid category isnot clear, the most hazardous category shall be assumed. C 500 Reliability analysisC 300 Location classes 501 As an alternative to the LRFD format specified and used in this standard, a recognised structural reliability analysis301 The pipeline system shall be classified into location SRA) based design method may be applied provided that:classes as defined in Table 2-2. — the method complies with DNV Classification Note no.Table 2-2 Classification of location 30.6 "Structural reliability analysis of marine structures"Location Definition — the approach is demonstrated to provide adequate safety1 The area where no frequent human activity is antic- for familiar cases, as indicated by this standard. ipated along the pipeline route.2 The part of the pipeline/riser in the near platform Guidance note: (manned) area or in areas with frequent human activity. The extent of location class 2 should be In particular, this implies that reliability based limit state design based on appropriate risk analyses. If no such anal- shall not be used to replace the pressure containment criterion in yses are performed a minimum distance of 500 m Sec.5 with the exception of accidental loads. shall be adopted. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---C 400 Safety classes 502 Suitably competent and qualified personnel shall perform401 Pipeline design shall be based on potential failure conse- the structural reliability analysis, and extension into new areas ofquence. In this standard, this is implicit by the concept ofsafety class. The safety class may vary for different phases and application shall be supported by technical verification.locations. The safety classes are defined in Table 2-3. 503 As far as possible, nominal target failure probability lev- els shall be calibrated against identical or similar pipelineTable 2-3 Classification of safety classes designs that are known to have adequate safety on the basis ofSafety Definition this standard. If this is not feasible, the nominal target failureclass probability level shall be based on the failure type and safetyLow Where failure implies low risk of human injury and class as given in Table 2-5. minor environmental and economic consequences. This is the usual classification for installation phase. Table 2-5 Nominal failure probabilities vs. safety classesMedium For temporary conditions where failure implies risk of Limit Probability Bases Safety Classes human injury, significant environmental pollution or States very high economic or political consequences. This is Low Medium High Very the usual classification for operation outside the plat- High4) form area. SLS Annual per Pipeline1) 10-2 10-3 10-3 10-4High For operating conditions where failure implies high risk ULS 2) Annual per Pipeline1) of human injury, significant environmental pollution or FLS Annual per Pipeline3) 10-3 10-4 10-5 10-6 very high economic or political consequences. This is the usual classification during operation in location ALS Annual per Pipeline class 2. - Pressure containment 10-4- 10-5-10-6 10-6- 10-7-10-8 10-5 10-7402 The partial safety factors related to the safety class are 1) Or the time period of the temporary phase.given in Sec.5 C100. 2) The failure probability for the bursting (pressure containment) shall be an order of magnitude lower than the general ULS criterion given in the Table, in accordance with industry practice and reflected by the ISO requirements. 3) The failure probability will effectively be governed by the last year in operation or prior to inspection depending on the adopted inspection philosophy. 4) See Appendix F Table F-2. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.3 – Page 29 SECTION 3 CONCEPT DEVELOPMENT AND DESIGN PREMISES A. General — second and third party activities — restricted access for installation or other activities due toA 100 Objective presence of ice.101 This section identifies and provides a basis for definition 304 An execution plan should be developed, including theof relevant field development characteristics. Further, key following topics:issues required for design, construction, operation, and aban-donment of the pipeline system are identified. — general information, including project organisation, scope of work, interfaces and project development phasesA 200 Application — contacts with Purchaser, authorities, third party, engineer-201 This section applies to all pipeline systems which are to ing, verification and construction Contractorsbe built according to this standard. — legal aspects, e.g. insurance, contracts, area planning,202 The design premises outlined in this section should be requirements to vessels.developed during the conceptual phase. 305 The design and planning for the submarine pipeline sys-A 300 Concept development tem should cover all development phases including construc- tion, operation and abandonment.301 When selecting the pipeline system concept all aspectsrelated to design, construction, operation and abandonmentshould be considered. Due account should be given to identifi-cation of potential aspects which can stop the concept from B. System Design Principlesbeing realised:— long lead effects of early stage decisions (e.g. choice of material grade may affect manufacturing aspects of line- B 100 System integrity pipe, choice of diameter may give restrictions to installa- tion methods etc.) 101 The pipeline system shall be designed, constructed and— life cycle evaluations (e.g. maintenance activities etc.) operated in such a manner that:— installation aspects for remote areas (e.g. non-availability — the specified transport capacity is fulfilled and the flow of major installation equipment or services and weather assured issues). — the defined safety objective is fulfilled and the resistance302 Data and description of field development and general against loads during planned operational conditions is suf-arrangement of the pipeline system should be established. ficient — the safety margin against accidental loads or unplanned303 The data and description should include the following, operational conditions is sufficient.as applicable: 102 The possibility of changes in the type or composition of— safety objective fluid to be transported during the lifetime of the pipeline sys-— environmental objective tem shall be assessed at the design phase.— location, inlet and outlet conditions— pipeline system description with general arrangement and 103 Any re-qualification deemed necessary due to changes battery limits in the design conditions shall take place in accordance with— functional requirements including field development provisions set out in Sec.11. restrictions, e.g., safety barriers and subsea valves B 200 Monitoring/inspection during operation— installation, repair and replacement of pipeline elements, valves, actuators and fittings 201 Parameters which could violate the integrity of a pipe-— project plans and schedule, including planned period of line system shall be monitored, inspected and evaluated with a the year for installation frequency which enables remedial actions to be carried out— design life including specification for start of design life, before the system is damaged, see Sec.11. e.g. final commissioning, installation etc. Guidance note:— data of product to be transported including possible As a minimum the monitoring/inspection frequency should be changes during the pipeline systems design life such that the pipeline system will not be endangered due to any— transport capacity and flow assurance realistic degradation/deterioration that may occur between two— pressure protection system requirements including process consecutive inspection intervals. system layout and incidental to design pressure ratio eval- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- uations— pipeline sizing data 202 Special focus shall be on monitoring and inspection— attention to possible code breaks in the pipeline system strategies for “live pipeline systems” i.e. pipeline systems that— geometrical restrictions such as specifications of constant are designed to change the configuration during its design life. internal diameter, requirement for fittings, valves, flanges and the use of flexible pipe or risers Guidance note:— relevant pigging scenarios (inspection and cleaning) Example of such systems may be pipelines that are designed to— pigging fluids to be used and handling of pigging fluids in experience global buckling or possible free-span developments both ends of pipeline including impact on process systems ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---— pigging requirements such as bend radius, pipe ovality and distances between various fittings affecting design for pig- 203 Instrumentation of the pipeline system may be required ging applications when visual inspection or simple measurements are not con-— sand production sidered practical or reliable, and available design methods and DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 30 – Sec.3 see note on front coverprevious experience are not sufficient for a reliable predictionof the performance of the system.204 The need for in-line cleaning and/or inspection, involv-ing the presence of appropriate pig launcher / receiver should Probability Denisty Function Typical maximumbe determined in the design phase. pressure - monotonic decay.B 300 Pressure Protection System301 A pressure protection system shall be used unless thepressure source to the pipeline system cannot deliver a pres-sure in excess of the incidental pressure including possibledynamic effects. The pressure protection system shall preventthe internal pressure at any point in the pipeline system risingto an excessive level. The pressure protection system com-prises the pressure control system, pressure safety system andassociated instrumentation and alarm systems. Guidance note: Pressure An example of situations where a pressure protection system is not required is if full shut-in pressure including dynamic effects, Figure 1 is used as incidental pressure. Typical maximum pressure distribution – monotonic decay ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---302 The purpose of the pressure control system is to main-tain the operating pressure within acceptable limits during nor-mal operation i.e. to ensure that the local design pressure is notexceeded at any point in the pipeline system during normal Typical maximumoperation. The pressure control system should operate auto- Probability Denisty Function pressure distribution formatically. The local design pressure is defined in Sec.4 B200. high integrity pressureDue account shall be given to the tolerances of the pressure protection systemscontrol system and its associated instrumentation, see Figure 1 (HIPPS).in Sec.1. Hence, the maximum allowable operating pressure(MAOP) is equal to the design pressure minus the pressurecontrol system operating tolerance.303 The purpose of the pressure safety system is to protectthe downstream system during incidental operation, i.e. toensure that the local incidental pressure is not exceeded at anypoint in the pipeline system in the event of failure of the pres-sure control system. The pressure safety system shall operateautomatically. Due account shall be given to the tolerances of Pressurethe pressure safety system. Hence, the maximum allowableincidental pressure is equal to the incidental pressure minus the Figure 2pressure safety system operating tolerance. Schematic illustration of maximum pressure distribution for high integrity pressure protection systems (HIPPS)304 The incidental pressure shall have an annual probabilityof exceedance less than 10-2. If the pressure probability densityfunction does not have a monotonic decay beyond 10-2 then 305 For the conditions given in Table 3-1, the given inciden-pressure exceeding the incidental pressure shall be checked as tal to design ratios shall be used. The incidental to design pres-accidental loads in compliance with Sec.5 D1200. Examples of sure ratio shall be selected in order to meet the requirements inpressure probability density distributions are given in Figure 1 302, 303 and 304.and Figure 2. See also Sec.4 B200 for definition of the inciden-tal pressure. Table 3-1 Incidental to design pressure ratios Guidance note: Condition or pipeline system γ inc When the submarine pipeline system is connected to another sys- tem with different pressure definition the pressure values may be Typical pipeline system 1.10 different in order to comply with the requirements of this sub- Minimum, except for below 1.05 section, i.e. the design pressure may be different in two con- When design pressure is equal to full shut-in pressure 1.00 nected systems. The conversion between the two system defini- including dynamic effects tions will often then be based on that the incidental pressures are equal. System pressure test 1.00 ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 306 The pipeline system may be divided into sections with different design pressures provided that the pressure protection system ensures that, for each section, the local design pressure cannot be exceeded during normal operations and that the inci- dental pressure cannot be exceeded during incidental opera- tion. B 400 Hydraulic analyses and flow assurance 401 The hydraulics of the pipeline system should be ana- lysed to demonstrate that the pipeline system can safely trans- port the fluids, and to identify and determine the constraints and requirements for its operation. This analysis should cover steady-state and transient operating conditions. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.3 – Page 31 Guidance note: Landfall Examples of constraints and operational requirements are allow- ances for pressure surges, prevention of blockage such as caused — local constraints by the formation of hydrates and wax deposition, measures to — 3rd party requirements prevent unacceptable pressure losses from higher viscosities at — environmental sensitive areas lower operation temperatures, measures for the control of liquid — vicinity to people slug volumes in multi-phase fluid transport, flow regime for — limited construction period. internal corrosion control erosional velocities and avoidance of slack line operations. It also includes requirements to insulation, 102 Expected future marine operations and anticipated maximum shut-down times, requirements for heating etc. developments in the vicinity of the pipeline shall be considered ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- when selecting the pipeline route. 103 Pipeline components (e.g. valves, tees) in particular402 The hydraulics of the pipeline system shall be analysed should not be located on the curved route sections of the pipe-to demonstrate that the pressure control system and pressure line.safety system meet its requirement during start-up, normaloperation, shut-down (e.g. closing of valves) and all foreseen 104 It is recommended that pipeline ends are designed withnon-intended scenarios. This shall also include determination a reasonable straight length ahead of the target boxes. Curva-of required incidental to design pressure ratio. tures near pipeline ends should be designed with due regard to end terminations, lay method, lay direction and existing/ planned infrastructure.403 The hydraulic analyses shall be used to determine themaximum design temperature profile based on conservative C 200 Route surveyinsulation values reflecting the variation in insulation proper- 201 Surveys shall be carried out along the total length of theties of coatings and surrounding seawater, soil and gravel. planned pipeline route to provide sufficient data for design and404 The hydraulic analyses shall be used to determine the installation related activities.minimum design temperature. Benefit of specifying low tem- 202 The survey corridor shall have sufficient width to defineperatures locally due to e.g. opening of valves is allowed and an installation and pipeline corridor which will ensure safeshall be documented e.g. by hydraulic analyses. installation and operation of the pipeline. 203 The required survey accuracy may vary along the pro- posed route. Obstructions, highly varied seabed topography, or C. Pipeline Route unusually or hazardous sub-surface conditions may dictate more detailed investigations.C 100 Location 204 Investigations to identify possible conflicts with existing101 The pipeline route shall be selected with due regard to and planned installations and possible wrecks and obstructionssafety of the public and personnel, protection of the environ- shall be performed. Examples of such installations includement, and the probability of damage to the pipe or other facil- other submarine pipelines, and power and communicationities. Agreement with relevant parties should be sought as cables.early as possible. Factors to take into consideration shall, at 205 The results of surveys shall be presented on accurateminimum, include the following: route maps and alignments, scale commensurate with requiredEnvironment use. Location of the pipeline, related facilities together with seabed properties, anomalies and all relevant pipeline— archaeological sites attributes shall be shown. Reference seawater elevation shall— exposure to environmental damage be defined.— areas of natural conservation interest including oyster beds 206 Additional route surveys may be required at landfalls to and corral reefs determine:— marine parks— turbidity flows. — seabed geology and topography specific to landfall and costal environmentSeabed characteristics — environmental conditions caused by adjacent coastal fea- tures— uneven seabed — location of the landfall to facilitate installation— unstable seabed — facilitate pre or post installation seabed intervention works— soil properties (hard spots, soft sediment and sediment specific to landfall, such as trenching transport) — location to minimise environmental impact.— subsidence— seismic activity. 207 All topographical features which may influence the sta- bility and installation or influence seabed intervention of theFacilities pipeline shall be covered by the route survey, including but not limited to:— offshore installations— subsea structures and well heads — obstructions in the form of rock outcrops, large boulders,— existing pipelines and cables pock marks, etc., that could necessitate remedial, levelling— obstructions or removal operations to be carried out prior to pipeline— coastal protection works. installation — topographical features that contain potentially unstableThird party activities slopes, sand waves, pock marks or significant depressions, valley or channelling and erosion in the form of scour pat-— ship traffic terns or material deposits.— fishing activity— dumping areas for waste, ammunition, etc. 208 Areas where there is evidence of increased geological— mining activities activity or significant historic events that if re-occurring again— military exercise areas. can impact the pipeline, additional geohazard studies should be DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 32 – Sec.3 see note on front coverperformed. Such studies may include: — problems with respect to pipeline crossing — problems with the settlement of pipeline system and/or the— extended geophysical survey protection structure at the valve/tee locations— mud volcanoes or pockmark activity — possibilities of mud slides or liquefaction as the result of— seismic hazard repeated loading— seismic fault displacements — implications for external corrosion.— possibility of soil slope failure— mudflow characteristics— mudflow impact on pipelines. D. Environmental ConditionsC 300 Seabed properties301 Geotechnical properties necessary for evaluating the D 100 Generaleffects of relevant loading conditions shall be determined for 101 Environmental phenomena that might impair properthe seabed deposits, including possible unstable deposits in the functioning of the system or cause a reduction of the reliabilityvicinity of the pipeline. For guidance on soil investigation for and safety of the system shall be considered, including:pipelines, reference is made to Classification Note No. 30.4"Foundations". — wind — tide302 Geotechnical properties may be obtained from generally — wavesavailable geological information, results from seismic surveys, — internal waves and other effects due to differences in waterseabed topographical surveys, and in-situ and laboratory tests. densitySupplementary information may be obtained from visual sur- — currentveys or special tests, as e.g. pipe penetration tests. — ice — earthquake303 Soil parameters of main importance for the pipeline — soil conditionsresponse are: — temperature — marine growth (fouling).— shear strength parameters (intact and remoulded und- rained shear strength for clay, and angle of friction for 102 The principles and methods described in DNV-RP-C205 sands); and Environmental Conditions and Environmental Loads may be— relevant deformation characteristics. used as a basis for establishing the environmental conditions.These parameters should preferably be determined from ade- D 200 Collection of environmental dataquate laboratory tests or from interpretation of in-situ tests. In 201 The environmental data shall be representative for theaddition, classification and index tests should be considered, geographical areas in which the pipeline system is to besuch as: installed. If sufficient data are not available for the geographi- cal location in question, conservative estimates based on data— unit weight from other relevant locations may be used.— water content— liquid and plastic limit 202 Statistical data shall be utilised to describe environmen- tal parameters of a random nature (e.g. wind, waves). The— grain size distribution parameters shall be derived in a statistically valid manner— carbonate content using recognised methods.— other relevant tests. 203 The effect of statistical uncertainty due to the amount304 It is primarily the characteristics of the upper layer of and accuracy of data shall be assessed and, if significant, shallsoil that determine the response of the pipeline resting on the be included in the evaluation of the characteristic load effect.seabed. The determination of soil parameters for these very 204 For the assessment of environmental conditions alongshallow soils may be relatively more uncertain than for deeper the pipeline route, the pipeline may be divided into a numbersoils. Also the variations of the top soil between soil testing of sections, each of which is characterised by a given waterlocations may add to the uncertainty. Soil parameters used in depth, bottom topography and other factors affecting the envi-the design may therefore need to be defined with upper bound, ronmental conditions.best estimate and lower bound limits. The characteristicvalue(s) of the soil parameter(s) used in the design shall be in 205 The environmental data to be used in the design of pipe-line with the selected design philosophy accounting for these lines and/or risers fixed to an offshore structure are in principleuncertainties. the same as the environmental data used in the design of the offshore structure supporting the pipeline and/or riser. Guidance note: For deep water areas the upper layer may be slurry with a very D 300 Environmental data small strength. In these cases emphasize should also be made to the soil layer underneath. 301 The estimated maximum tide shall include both astro- nomic tide and storm surge. Minimum tide estimates should be ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- based upon the astronomic tide and possible negative storm surge.305 In areas where the seabed material is subject to erosion,special studies of the current and wave conditions near the bot- 302 All relevant sources to current shall be considered. Thistom including boundary layer effects may be required for the may include tidal current, wind induced current, storm surgeon-bottom stability calculations of pipelines and the assess- current, density induced current or other possible phenomena.ment of pipeline spans. For near-shore regions, long-shore current due to wave break- ing shall be considered. Variations in magnitude with respect306 Additional investigation of the seabed material may be to direction and water depth shall be considered when relevant.required to evaluate specific problems, as for example: 303 In areas where ice may develop or where ice bergs may— problems with respect to excavation and burial operations pass or where the soil may freeze sufficient statistics shall be— probability of forming frees-pans caused by scouring dur- established in order to enable calculations of design loads, ing operational phase either environmental or accidental. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.3 – Page 33304 Air and sea temperature statistics shall be provided giv- party activities as mentioned in C101 above should be consid-ing representative design values. ered.305 Marine growth on pipeline systems shall be considered,taking into account both biological and other environmental E 200 Internal installation conditionsphenomena relevant for the location. 201 A description of the internal pipe conditions during stor- age, construction, installation, pressure testing and commis- sioning shall be prepared. The duration of exposure to sea water or humid air, and the need for using inhibitors or other E. External and Internal Pipe Condition measures to control corrosion shall be considered.E 100 External operational conditions E 300 Internal operational conditions101 For the selection and detailed design of external corro- 301 In order to assess the need for internal corrosion control,sion control, the following conditions relating to the environ- including corrosion allowance and provision for inspectionment shall be defined, in addition to those mentioned in D101: and monitoring, the following conditions shall be defined:— exposure conditions, e.g. burial, rock dumping, etc. — maximum and average operating temperature/pressure— sea water and sediment resistivity. profile along the pipeline, and expected variations during102 Other conditions affecting external corrosion which the design lifeshall be defined are: — flow velocity and flow regime — fluid composition (initial and anticipated variations during— maximum and average operating temperature profile the design life) with emphasis on potentially corrosive along the pipeline and through the pipe wall thickness components (e.g. hydrogen sulphide, carbon dioxide,— pipeline fabrication and installation procedures water content and expected content of dissolved salts in— requirements for mechanical protection, submerged produced fluids, residual oxygen and active chlorine in sea weight and thermal insulation during operation water)— design life — chemical additions and provisions for periodic cleaning— selected coating and cathodic protection system. — provision for inspection of corrosion damage and expected capabilities of inspection tools (i.e. detection limits and103 Special attention should be given to the landfall section sizing capabilities for relevant forms of corrosion damage)(if any) and interaction with relevant cathodic protection sys- — the possibility of erosion by any solid particles in the fluidtem for onshore vs. offshore pipeline sections. shall be considered. Reference is made to DNV-RP-O501104 The impact on the external pipe condition of the third Erosive Wear in Piping Systems. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 34 – Sec.4 see note on front cover SECTION 4 DESIGN - LOADS A. General B. Functional LoadsA 100 Objective B 100 General101 This section defines the design loads to be checked by 101 Loads arising from the physical existence of the pipelinethe design criteria in Sec.5. This includes: system and its intended use shall be classified as functional loads.— load scenarios to be considered 102 All functional loads which are essential for ensuring the— categorisation of loads integrity of the pipeline system, during both the construction— design cases and corresponding characteristic loads and the operational phase, shall be considered.— load effect combinations 103 Effects from the following phenomena are the minimum— load effect calculations. to be considered when establishing functional loads:A 200 Application — weight201 This section applies to all parts of the submarine pipeline — external hydrostatic pressuresystem. — internal pressure — temperature of contentsA 300 Load scenarios — pre-stressing301 All loads and forced displacements which may influence — reactions from components (flanges, clamps etc.)the pipeline integrity shall be taken into account. For each — permanent deformation of supporting structurecross section or part of the system to be considered and for — cover (e.g. soil, rock, mattresses, culverts)each possible mode of failure to be analysed, all relevant com- — reaction from seabed (friction and rotational stiffness)binations of loads which may act simultaneously shall be con- — permanent deformations due to subsidence of ground, bothsidered. vertical and horizontal — permanent deformations due to frost heave302 The most unfavourable scenario for all relevant phases — changed axial friction due to freezingand conditions shall be considered. Typical conditions to be — possible loads due to ice interference, e.g. bulb growthcovered in the design are: around buried pipelines near fixed points (in-line valves/ tees, fixed plants etc.), drifting ice etc.— installation — loads induced by frequent pigging operations.— as laid— water filled 104 The weight shall include weight of pipe, buoyancy, con-— system pressure test tents, coating, anodes, marine growth and all attachments to— operation the pipe.— shut-down. 105 End cap forces due to pressure shall be considered, as well as any transient pressure effects during normal operationA 400 Load categories (e.g. due to closure of valves).401 The objective of categorise the different loads into dif- 106 Environmental as well as operational temperatures shallferent load categories is to relate the load effect to the different be considered. The maximum and minimum design tempera-uncertainties and occurrence. ture profiles shall have an annual probability of exceedance402 Unless the load is categorised as accidental it shall be less than of 10-2. Different temperature profiles for differentcategorised as: conditions should be considered (e.g. installation, as-laid, water filled, pressure test, operation and design).— functional load 107 Local minimum temperature profiles, which may be— environmental load caused by e.g. sudden shut-downs, may be applied. This will— interference load. typically be relevant to defined components and sections of the pipeline (e.g. spots around valves).The load categories are described in B, C and E below. Con-struction loads shall be categorised into the above loads and are 108 Fluctuations in temperature shall be taken into accountdescribed in D. Accidental loads are described in F. when checking fatigue strength. 109 For expansion analyses, the temperature difference rela-A 500 Design cases tive to laying shall be considered. The temperature profile shall501 The design cases describe the 100-year load effect. The be applied.100-year load effect is composed of contributions of func- 110 Pre-stressing, such as permanent curvature or a perma-tional, environmental and interference load effects. This will nent elongation introduced during installation, shall be takenbe governed either by the 100-year functional load effect, the into account if the capacity to carry other loads is affected by100-year environmental load effect or the 100-year interfer- the pre-stressing. Pretension forces induced by bolts in flanges,ence load effect, see G100. connectors and riser supports and other permanent attach- ments, shall be classified as functional loads.A 600 Load effect combination 111 The soil pressure acting on buried pipelines shall be601 The load combinations combine the load effect of each taken into account if significant.load category in a design case with different load effect factors,see G200. B 200 Internal Pressure loadsEach load combination constitutes a design load effect to be 201 The following internal pressures shall be defined at a cer-compared with relevant design resistance, see 5 C100. tain defined reference level; System Test Pressure, Operating DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.4 – Page 35Pressure (if relevant), Design pressure (if applicable), and Inci- Sec.1. These pressures are summarised in Table 4-1.dental Pressure, see Sec.3 B300 for definitions and Figure 1 inTable 4-1 Pressure termsPressure Abbreviations Symbol DescriptionMill test - Ph Hydrostatic test pressure at the mill, see Sec.7System test - Pt The pressure to which the complete submarine pipeline system is tested to prior to commissioning, see Sec.5 B200Incidental - Pinc Maximum pressure the submarine pipeline system is designed forMaximum allowable incidental MAIP - The trigger level of pressure safety system. Maximum allowable inciden- tal pressure is equal to the incidental pressure minus the pressure safety system operating toleranceDesign - PD The maximum pressure the pressure protection system requires in order to ensure that incidental pressure is not exceeded with sufficient reliabil- ity, typically 10% below the incidental pressureMaximum allowable operating MAOP - Upper limit of pressure control system. Maximum allowable operating pressure is equal to the design pressure minus the pressure control system operating tolerance Guidance note: C. Environmental Loads The incidental pressure is defined in terms of annual exceedance probability. The ratio between the incidental pressure and the C 100 General design pressure, see Table 3-1, is determined by the accuracy of 101 Environmental loads are defined as those loads on the the pressure protection system. When the pressure source is pipeline system which are caused by the surrounding environ- given (e.g. well head shut-in pressure) this may constitute the ment, and that are not otherwise classified as functional or selection of the incidental pressure. The design pressure can then be established based on the pressure protection system. When accidental loads. transport capacity requirement constitute the design premise this 102 For calculation of characteristic environmental loads, may give the design pressure and the incidental pressure can then reference is made to the principles given in DNV-RP-C205 be established based on the pressure protection system. Environmental Conditions and Environmental Loads. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- C 200 Wind loads202 The local pressure is the internal pressure at a specific 201 Wind loads shall be determined using recognised theo-point based on the reference pressure adjusted for the fluid col- retical principles. Alternatively, direct application of data fromumn weight due to the difference in elevation. It can be adequate tests may be used.expressed as: 202 The possibility of vibrations and instability due to wind induced cyclic loads shall be considered (e.g. vortex shed- (pli = pinc + ρ cont ⋅ g ⋅ href − hl ) (4.1) ding). C 300 Hydrodynamic loadsplt = pt + ρt ⋅ g ⋅ (href − hl ) (4.2) 301 Hydrodynamic loads are defined as flow-induced loads caused by the relative motion between the pipe and the sur-where rounding water.pli is the local incidental pressure 302 All relevant sources for hydrodynamic loads shall bepinc is the incidental reference pressure at the reference ele- considered. This may include waves, current, relative pipe vation motions and indirect forces e.g. caused by vessel motions.ρcont is the density of the relevant content of the pipeline 303 The following hydrodynamic loads shall be considered,g is the gravity but not limited to:href is the elevation of the reference point (positive upwards) — drag and lift forces which are in phase with the absolute orhl is the elevation of the local pressure point (positive relative water particle velocity upwards) — inertia forces which are in phase with the absolute or rela- tive water particle accelerationplt is the local system test pressure — flow-induced cyclic loads due to vortex shedding, gallop-pt is the system test reference pressure at the reference ele- ing and other instability phenomena vation — impact loads due to wave slamming and slapping, andρt is the density of the relevant test medium of the pipeline — buoyancy variations due to wave action.203 The test pressure requirement is given in Sec.5 B200. Guidance note: Recent research into the hydrodynamic coefficients for openB 300 External Pressure loads bundles and piggy-back lines indicates that the equivalent diam-301 In cases where external pressure increases the capacity, eter approach may be unconservative, and a system specific CFD analysis may be required to have a robust design.the external pressure shall not be taken as higher than the waterpressure at the considered location corresponding to low astro- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---nomic tide including possible negative storm surge. 304 The applied wave theory shall be capable of describing302 In cases where the external pressure decreases the the wave kinematics at the particular water depth in questioncapacity, the external pressure shall not be taken as less than including surf zones hydrodynamics where applicable. Thethe water pressure at the considered location corresponding to suitability of the selected theory shall be demonstrated andhigh astronomic tide including storm surge. documented. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 36 – Sec.4 see note on front cover305 The current-induced drag and lift forces on the subma- the normal wave impact zone, may be exposed to wave loadingrine pipeline system shall be determined and combined with due to wave run-up. Loads due to this effect shall be consid-the wave-induced forces using recognised theories for wave- ered if relevant.current interaction. A vector combination of the current andwave-induced water particle velocities may be used. If availa- 316 The increased loads from marine growth shall be consid-ble, however, calculation of the total particle velocities and ered as follows:accelerations based upon more exact theories on wave-current — Increased drag/lift area due to the marine growthinteraction is preferable. — Increased pipe surface roughness and resulting increase in306 Data from model testing or acknowledged industry prac- drag coefficient and reduced lift coefficienttice may be used in the determination of the relevant hydrody- — Any beneficial effect of the weight of the marine growthnamic coefficients. shall be ignored in stability analyses307 Where appropriate, consideration shall be given to wave 317 Tide loads shall be considered when the water depth is adirection, short crested waves, wave refraction and shoaling, significant parameter, e.g. for the establishment of waveshielding and reflecting effects. actions, pipe lay operation particularly near shore approaches/308 For pipelines during installation and for in-place risers, landfalls, etc.the variations in current velocity magnitude and direction as afunction of water depth shall be considered. C 400 Ice loads309 Where parts of the pipeline system are positioned adja- 401 In areas where ice may develop or drift, the possibilitycent to other structural parts, possible effects due to distur- of ice loads on the pipeline system shall be considered. Suchbance of the flow field shall be considered when determining loads may partly be due to ice frozen on the pipeline systemthe wave and/or current actions. Such effects may cause an itself, and partly due to floating ice. For shore approaches andincreased or reduced velocity, or dynamic excitation by vorti- areas of shallow water, the possibility of ice scouring andces being shed from the adjacent structural parts. impacts from drifting ice shall be considered. Increased hydro- dynamic loading due to presence of ice shall be considered.310 If parts of the submarine pipeline system is built up of a The ice load may be classified as environmental or accidentalnumber of closely spaced pipes, then interaction and solidifi- depending on its frequency.cation effects shall be taken into account when determining themass and drag coefficients for each individual pipe or for the 402 In case of ice frozen to parts of the submarine pipelinewhole bundle of pipes. If sufficient data is not available, large- system, (e.g. due to sea spray) the following forces shall bescale model tests may be required. considered:311 For pipelines on or close to a fixed boundary (e.g. pipe- — weight of the iceline spans) or in the free stream (e.g. risers), lift forces perpen- — impact forces due to thaw of the icedicular to the axis of the pipe and perpendicular to the velocity — forces due to expansion of the icevector shall be taken into account (possible vortex inducedvibrations). — increased wind, waves and current forces due to increased exposed area.312 In connection with vortex shedding-induced transversevibrations, the increase in drag coefficient shall be taken into 403 Forces from floating ice shall be calculated according toaccount. recognised theory. Due attention shall be paid to the mechani- cal properties of the ice, contact area, shape of structure, direc-313 Possible increased waves and current loads due to pres- tion of ice movements, etc. The oscillating nature of the iceence of Tee’s, Y’s or other attachments shall be considered. forces (built-up of lateral force and fracture of moving ice)314 The effect of possible wave and current loading on the shall be taken into account in the structural analysis. Whensubmarine pipeline system in the air gap zone shall be forces due to lateral ice motion will govern structural dimen-included. sions, model testing of the ice-structure interaction may be required. Guidance note: Maximum wave load effects may not always be experienced dur- C 500 Earthquake ing the passing of the design wave. The maximum wave loads may be due to waves of a particular length, period or steepness. 501 Load imposed by earth quake, either directly or indi- rectly (e.g. due to failure of pipeline gravel supports), shall be The initial response to impulsive wave slam or slap usually classified into accidental or environmental loads, depending occurs before the exposed part of the submarine pipeline system is significantly immersed. Therefore, other fluid loading on the on the probability of earthquake occurrence in line with acci- system need not normally be applied with the impulsive load. dental loads in F. However, due to structural continuity of the riser, global wave Guidance note: loading on other parts of the system must be considered in addi- tion to the direct wave loading. Earth quake with 475 years return period may be taken from International seismic zonation charts as in Eurocode 8. This can Wave slam occurs when an approximately horizontal member is then be converted by importance factors to 100 years return engulfed by a rising water surface as a wave passes. The highest period. slamming forces occur for members at mean water level and the slam force directions are close to the vertical. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- Wave slap is associated with breaking waves and can affect members at any inclination, but in the plane perpendicular to the C 600 Characteristic environmental load effects wave direction. The highest forces occur on members above mean water level. 601 The characteristic environmental load and the corre- sponding load effect depend on condition: Both slam and slap loads are applied impulsively (over a short instant of time) and the dynamic response of the submarine pipe- — weather restricted condition line system shall be considered. — temporary condition ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — permanent condition.315 Parts of the submarine pipeline system, located above See Figure 1. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.4 – Page 37 Environmental conditions Weather Restricted Operations Non-Weather Restricted Operations Environmental loads based TPOP: Planned TSafe: Time to safely cease on Statistics operation period the operation T ’C: Contingency time to Δstart: Start-up time cease operation TC: Contingency time TWF: Weather forecast intervals TR: Operation T’R=TWF+TSafe+TC reference period TR=Δstart+TPOP+TC No TR’<72 h No TR<72 h No T’POP=TWF+TSAFE TR<6m Establish OPLIM Establish OPLIM 10 yr seasonal 100 yr Calculate start & interrupt Calculate start & interrupt Criterion Co(α(TPOP)) Criterion Co(α(T’POP)) Weather window (TR) Weather window (T’R) End End End EndFigure 1 unfavourable relevant combination, position and direction ofDetermination of characteristic environmental load simultaneously acting environmental loads shall be used in doc- umenting the integrity of the submarine pipeline system.602 An operation can be defined as weather restricted oper- Functional loads (see B), interference loads (see E) and acci-ation if it is anticipated to take less than 72 hours from previous dental loads (see F) shall be combined with the environmentalweather forecast including contingency time, referred to as loads as appropriate, see G103.operation reference period, TR. It may then start-up based on 607 The characteristic environmental load effect for installa-reliable weather forecast less than established operation limit. tion, LE, is defined as the most probable largest load effect forUncertainty in the weather forecast for the operational period a given seastate and appropriate current and wind conditionsshall be considered. given by:603 An operation can be defined as weather restricted oper-ation even if the operation time is longer than 72 hours given 1that it can be ceased and put into safe condition within 72 hours F ( L E ) = 1 – --- - (4.3) Nincluding contingency time and weather forecast intervals,referred to as operational reference period of ceasing opera- where:tion, T’R. The operation can then start-up and continue basedon reliable weather forecast less than established operation F(LE) is the cumulative distribution function of LE, and N is thelimit during this operational reference period for ceasing the number of load effect cycles in a sea-state of a duration not lessoperation. Uncertainty in the weather forecast for this period than 3 hours.shall be considered. 608 The most critical load effect combination for the rele- Guidance note: vant return period shall be used. When the correlations among For weather restricted operations reference is made to DNV-OS- the different environmental load components (i.e. wind, wave, H101. This standard is not yet issued, until issue refer to DNV current or ice) are unknown the characteristic combined envi- Rules for planning of marine operations, Pt. 1, Ch. 2, paragraph ronmental loads in Table 4-2 may be used. 3.1 and DNV-RP-H102, Ch. 2.1, paragraph 2.2. Table 4-2 Combinations of characteristic environmental loads ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- in terms of return period 1)2)604 An operation can be defined as a temporary condition if Wind Waves Current Ice Earth quakethe duration is less than 6 months unless defined as weather Permanent conditionrestricted conditions. The environmental load effect for tempo- 100-year 100-year 10-yearrary conditions shall be taken as the 10-year return period forthe actual season. 10-year 10-year 100-year Guidance note: 10-year 10-year 10-year 100-year Conditions exceeding 6 months but no longer than 12 months 100-year may occasionally be defined as temporary conditions. Temporary condition ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 10-year 10-year 1-year 1-year 1-year 10-year605 Conditions not defined as weather restricted conditions 1-year 1-year 1-year 10-yearor temporary conditions shall be defined as permanent condi- 10-yeartions. The environmental load effect for permanent conditionsshall be taken as the 100-year return period. 1) The 100-year return period implies an annual probability of exceedance of 10-2.606 When considering the environmental design load the most 2) This is in conflict with ISO 13623 in case the design life is less than 33 years. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 38 – Sec.4 see note on front cover D. Construction Loads Guidance note: This will typically apply to when dimensional tolerances are added.D 100 General101 Loads which arise as a result of the construction of the ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---pipeline system, comprising installation, pressure testing,commissioning, maintenance and repair, shall be classifiedinto functional and environmental loads.102 All significant loads acting on pipe joints or pipe sec- E. Interference Loadstions during transport, fabrication, installation, maintenance E 100 Generaland repair activities shall be considered. 101 Loads which are imposed on the pipeline system from103 Functional Loads shall consider forces generated due to 3rd party activities shall be classified as interference loads.imposed tension during pipeline installation, maintenance and These loads include but are not limited to trawl interference,repair. anchoring, vessel impacts and dropped objects.104 Environmental loads shall consider forces induced on 102 The requirement for designing the submarine pipeline sys-the pipeline due to wind, waves and current, including deflec- tem for interference loads shall be determined based upon inter-tions and dynamic loads due to vessel movement. ference frequency studies and assessment of the potential damage. If the annual probability of occurrence is less than 10-2105 Accidental loads shall consider inertia forces due to sud- the load shall be classified as accidental load, see F.den water filling, excessive deformation in overbend and sag-bend, and forces due to operation errors or failures in 103 For calculations of trawl interference loads, reference isequipment that could cause or aggravate critical conditions, given to DNV-RP-F111 Interference between Trawl Gear andsee Sec.10 A300. Pipelines.106 Other loads to be considered are: 104 The trawling loads can be divided in accordance with the three crossing phases:— stacking of pipes 1) Trawl impact, i.e. the initial impact from the trawl board— handling of pipe and pipe sections, e.g. lifting of pipe, pipe or beam which may cause local dents on the pipe or dam- joints, pipe strings and pipe spools, and reeling of pipe age to the coating. strings— pull-in at landfalls, tie-ins, trenching etc. 2) Over-trawling, often referred to as pull-over, i.e. the sec- ond phase caused by the wire and trawl board or beam slid-— pressure testing ing over the pipe. This will usually give a more global— commissioning activities, e.g. increase in pressure differ- response of the pipeline. ential due to vacuum drying. 3) Hooking, i.e. the trawl board is stuck under the pipe and in107 Operating limit conditions shall be established relevant extreme cases, forces as large as the breaking strength offor the construction activity under consideration, see C600 and the trawl wire are applied to the pipeline.Sec.10 D400. Hooking is normally categorised as an accidental load.108 Typical construction loads for pre-installed risers, riser 105 The trawl impact energy shall be determined consider-supports/guides and J-tubes on jackets and similar installations ing, as a minimum:are: — the trawl gear mass and velocity— wind-induced forces, in particular wind-induced vortex — the effective added mass and velocity. shedding, on parts which are designed to be submerged after installation of the load-bearing structure The impact energy shall be used for testing of the pipeline— deflections/forces generated during load-out of the load- coatings and possible denting of the pipeline wall thickness. In bearing structure case piggy-back lines these shall also have adequate safety— transportation forces due to barge movements against trawl impacts. Reference is given to DNV-RP-F111.— launch forces due to deflection and hydrodynamic loads 106 Other 3rd party interference loads shall be calculated (drag, slam and slap) on the structure using recognised methods.— deflections/forces generated during installation of load- bearing structure— inertia loads on the riser supports/guides due to pile driv- ing F. Accidental Loads— re-distribution of support forces when possible temporary F 100 General riser supports are removed and the riser turned into the final position 101 Loads which are imposed on a pipeline system under— cold springing of the risers (elastic pre-deformations) abnormal and unplanned conditions and with an annual proba- bility of occurrence less than 10-2 shall be classified as acci-— tie-in forces generated when the riser is connected to the dental loads. tie-in spool/pipeline— dynamic loads from pre-commissioning activities, e.g. 102 Typical accidental loads can be caused by: flooding and de-watering with pigs. — extreme wave and current loads — vessel impact or other drifting items (collision, grounding,109 The load combinations to be considered shall be selected sinking, iceberg)to reflect the most severe load combinations likely to beencountered during the construction phase under considera- — dropped objectstion. — seabed movement and/or mud slides — explosion110 The most severe load effect may be taken as mean ±3 — fire and heat fluxstandard deviations unless otherwise stated. — operational malfunction DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.4 – Page 39— dragging anchors. case of functional, environmental, interference and accidental loads. The 100-year load effect is the load with an annual prob-103 Size and frequency of accidental loads, for a specific ability of 10-2 of exceedance in a period of one year.pipeline system, may be defined through risk analyses. Refer-ence is also made to DNV-RP-F107 Risk Assessment of Pipe- 102 The most critical combination is normally governed byline Protection. extreme functional, environmental, interference or accidental load effect. These have been denoted design cases. Unless spe- cial evaluation of critical 100-year design case is carried out, the design cases defined by combinations of characteristic load G. Design Load Effects effects in Table 4-3 shall be used. 103 In addition to the conditions defined above, fatigue limitG 100 Design cases state and accidental condition shall also be checked. The char-101 Each static limit state, see Sec.5 D, shall be checked for acteristic load definitions for this combination are given inthe load effect induced by the most critical 100-year design Table 4-3.Table 4-3 Combinations of characteristic loads effects for different design casesDesign case Load Functional Environmental Interference Accidental combination5) load load load loadFunctional design case a, b 100-year1) 1-year Associated NAEnvironmental design case a, b Associated2) 100-year3) Associated NAInterference design case b Associated2) Associated UB NAFatigue design4) case c Associated Associated Associated NAAccidental design case d Associated Associated Associated BECharacteristic load definitionn-year: Most probable maximum in n years, UB: Upper Bound, BE: Best estimate1) This will normally be equivalent to an internal pressure equal to the local incidental pressure combined with expected associated values of other functional loads.2) This will normally be equivalent to an internal pressure and temperature not less than the operating pressure and the temperature profiles.3) As defined in C607.4) The fatigue design load shall be cyclic functional loading (start-up and shut-down), random environmental load (e.g. wave and current spectra) and repeated interference loading. The load combinations shall be associated.5) The referred combinations is given in Table 4-4.G 200 Load combinations Guidance note:201 The design load effect can generally be expressed in the The load combinations to the left are referred to explicitly in the design criteria, e.g. Eq. (5.19).following format: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---LSd = LF ⋅ γ F ⋅ γ c + LE ⋅ γ E + LI ⋅ γ F ⋅ γ c + LA ⋅ γ A ⋅ γ c (4.4) 202 The design load effect shall be calculated for eachIn specific forms, this corresponds to: design case, see G100 for all relevant load combinations, Table 4-4. The different ULS design load effects are referred to in the (4.5) different local buckling limit states.M Sd = M F ⋅ γ F ⋅ γ c + M E ⋅ γ E + M I ⋅ γ F ⋅ γ c + M A ⋅ γ A ⋅ γ cε Sd = ε F ⋅ γ F ⋅ γ c + ε E ⋅ γ E + ε I ⋅ γ F ⋅ γ c + ε A ⋅ γ A ⋅ γ c (4.6)S Sd = S F ⋅ γ F ⋅ γ c + S E ⋅ γ E + S I ⋅ γ F ⋅ γ c + S A ⋅ γ A ⋅ γ c (4.7)Table 4-4 Load effect factors and load combinationsLimit State / Load Design load combination Functional loads 1) Environmental load Interference loads Accidental loadscombination γ γE γF γA FULS a System check2) 1.2 0.7 b Local check 1.1 1.3 1.1FLS c 1.0 1.0 1.0ALS d 1.0 1.0 1.0 1.01) If the functional load effect reduces the combined load effects, γF shall be taken as 1/1.1.2) This load combination shall only be checked when system effects are present, i.e. when the major part of the pipeline is exposed to the same functional load. This will typically only apply to pipeline installation. Guidance note: b) for local scenarios and shall always be considered. The partial safety factors in DNV-OS-F101 have been deter- When system effects are present, the pipeline will fail at its weak- mined by structural reliability methods to a pre-defined failure est point. Hence, the likely load shall be combined with the probability. Structural reliability calculations differentiate extreme low resistance. Applied to pipelines system effect can be between single joint failures (local checks) and series system expressed as the weakest link principle (where the chain gets failures (system effects). weaker the longer the chain is). This is characterised by that the whole pipeline is exposed to the same load over time. These two kinds of scenarios are expressed as two different load combinations in DNV-OS-F101: Applied to pipelines, system effects are present for: - pressure containment a) shall only be considered for scenarios where system effects - collapse, in as installed configuration are present - installation. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 40 – Sec.4 see note on front cover The first two are handled with explicitly by the use of thickness quate, model or full-scale tests may be required. t1. This is also why thickness t2 and not t1 is used for the burst capacity in the local buckling for pressurised pipes, since it is a 303 When determining responses to dynamic loads, the local check. dynamic effect shall be taken into account if deemed signifi- Regarding installation, an extreme environmental load is not cant. likely to occur when the weakest pipe section is at the most 304 When non-linear material is required in the analyses the exposed location indicating that system effects not are present. stress-strain curve shall based on specified minimum values However, combined with a more representative environmental accounting for temperature derating (fy and fu) considered load (in the extreme case, “flat sea”), the whole pipeline will undergo the same deformation “over time”, hence, having a sys- being engineering stress values, except for when the mean or tem effect present. upper bound values are explicitly required by the procedure (e.g. for fracture mechanics applications). The use of true ver- In Table 4-3, load combination a has a 10% increase in the func- tional load to cover the system effect combined with a 0.7 factor sus engineering stress strain curve shall be consistent with the on the extreme environmental load giving a more “representa- FE-program applied. tive” environmental load, applicable for the above. Guidance note: Another example of where system effects are present is for reel- The strain at fu is normally considerably less than the fracture ing where the whole pipe also will undergo the same deformation strain and is normally in the order of 6-10%. This should be (neglecting the variation in drum diameter increase). For this determined from tests of similar material. application, a condition factor of 0.82 also applies, giving the total load effect factor of 1.0. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- Hence, load combination b shall always be checked while load 305 Load effect calculation shall be performed applying combination a normally is checked for installation only. nominal cross section values unless otherwise required by the ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- code.203 The condition load effect factor applies to the conditions 306 The effective axial force that determines the globalin Table 4-5. Condition load effect factors are in addition to the response of a pipeline is denoted S. Counting tensile force asload effect factors and are referred to explicitly in Eq. (4.5, 4.6 positive:and 4.7).Table 4-5 Condition load effect factors, γ C π 4 ( S( pi ) = N − pi ⋅ Ai + pe ⋅ Ae = N − ⋅ pi ⋅ (D− 2⋅ t2 ) − pe ⋅ D2 (4.8) 2 )Condition γcPipeline resting on uneven seabed 1.07 307 Split up into functional, environmental and accidental effective force, the following applies:Continuously stiff supported 0.82System pressure testOtherwise 0.93 1.00 S F ( pi ) = N F − pi ⋅ Ai + pe ⋅ Ae = N F − π 4 ( ⋅ pi ⋅ (D − 2 ⋅ t 2 ) − pe ⋅ D 2 2 ) Guidance note: (4.9) An uneven seabed condition is relevant in connection with free- spanning pipelines. If uncertainties in soil conditions and possi- SE = NE ble trawl interference are accounted for, a lower γc is allowed. SA = NA Reference is given to DNV-RP-F110 Global Buckling of Subma- rine Pipelines – Structural Design due to High Temperature/High 308 In the as-laid condition, when the pipe temperature and Pressure. internal pressure are the same as when the pipe was laid, Continuously stiff supported denotes conditions where the main part of the load is also displacement controlled. Examples may be (4.10) reeling on the drum or J-tube pull-in. S=H Several condition factors may be required simultaneously, e.g. Where H is the effective (residual) lay tension. The effective for pressure testing of pipelines on uneven seabed, the resulting residual lay tension may be determined by comparing the as- condition factor will be 1.07 · 0.93 = 1.00. laid survey data to results from FE analysis. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 309 Effective axial force of a totally restrained pipe in the linear elastic stress range is:G 300 Load effect calculations301 The design analyses shall be based on accepted princi- S = H − Δpi ⋅ Ai ⋅ (1 − 2 ⋅ν ) − As ⋅ E ⋅ α ⋅ ΔT (4.11)ples of statics, dynamics, strength of materials and soilmechanics. where:302 Simplified methods or analyses may be used to calculatethe load effects provided that they are conservative. Model H = Effective (residual) lay tensiontests may be used in combination with, or instead of, theoreti- Δ pi = Internal pressure difference relative to as laidcal calculations. In cases where theoretical methods are inade- ΔΤ = Temperature difference relative to as laid. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 41 SECTION 5 DESIGN – LIMIT STATE CRITERIA A. General 104 The routing of risers and J-tubes shall be based on the following considerations:A 100 Objective — platform configuration and topsides layout101 This section provides design and acceptance criteria for — space requirementsthe possible modes of structural failure in pipeline systems. — movements of the Riser or J-tubeA 200 Application — cable/pipeline approach — Riser or J-tube protection201 This standard includes no limitations on water depth. — in-service inspection and maintenanceHowever, when this standard is applied in deep water where — installation considerations.experience is limited, special consideration shall be given to: 105 Crossing pipelines should be kept separated by a mini-— other failure mechanisms than those given in this section mum vertical distance of 0.3 m.— validity of parameter range (environmental/design/opera- tional parameters) 106 The submarine pipeline system shall be protected— dynamic effects. against unacceptable damage caused by e.g. dropped objects, fishing gear, ships, anchoring etc. Protection may be achieved202 This standard does not specify any explicit limitations by one or a combination of the following means:with respect to elastic displacements or vibrations, providedthat the effects of large displacements and dynamic behaviour, — concrete coatingincluding fatigue effect of vibrations, operational constraints — burialand ratcheting, are taken into account in the strength analyses. — cover (e.g. sand, gravel, mattress) — other mechanical protection.203 The local buckling criteria, see D300-D600, are onlyapplicable to pipelines that are straight in stress-free condition 107 Relative settlement between the protective structure andand are not applicable to e.g. bends. the submarine pipeline system shall be properly assessed in the204 For parts of the submarine pipeline system which extend design of protective structures, and shall cover the full designonshore complementary requirements are given in life of the submarine pipeline system. Adequate clearanceAppendix F. between the pipeline components and the members of the pro- tective structure shall be provided to avoid fouling.205 For spiral welded pipes, the following additional limita-tions apply: 108 Structural items should not be welded directly to pres- sure containing parts or linepipe due to the increased local— when supplementary requirement F (fracture arrest prop- stress on the linepipe. External supports, attachments etc. shall erties) is specified, see Sec.7, the possibility for a running be welded to a doubler plate or ring. The doubler plate or ring fracture to continue from a weld in one pipe joint to the shall be designed with sufficient thickness to avoid stresses on weld of the next pipe joint shall be assessed the linepipe. In case structural items are integrated in the pipe-— external pressure resistance should be documented line, e.g. pipe in pipe bulkheads, and are welded directly to the— the design shall be based on the load controlled condition, linepipe, detailed stress analyses are required in order to docu- see D600, unless the feasibility for use of displacement ment sufficiently low stress to ensure resistance against controlled condition can be documented. fatigue, fracture and yielding. Guidance note: 109 Permanent doubler rings and plates shall be made of The limitations to fracture arrest and load controlled condition materials satisfying the requirements for pressure containing are due to limited experience with spiral welded pipes subjected parts. Doubler plates shall be circular. For gas service and liq- to running fracture or large strains. uid service above 137 bar, doubler rings shall be used. For duplex stainless steels and 13Cr martensitic stainless steels no ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- attachments are permitted unless a stress analysis is performed in each case to determine that local stresses will not exceed 0.8 fy. 110 Doubler rings shall be made as fully encircling sleeves B. System Design Principles with the longitudinal welds made with backing strips, andB 100 Submarine pipeline system layout avoiding penetration into the main pipe material. Other welds shall be continuous, and made in a manner minimising the risk101 System lay out, including need for different valves etc., of root cracking and lamellar tearing. The toe of welds attach-shall be designed such that the requirements imposed by the ing anode pads, doubler plates and branch welding fittings,systematic review of the process control are met, see Sec.2 B. when permitted, shall have a toe-to-toe distance from other102 The submarine pipeline system should not be routed welds of minimum 4 · t or 100 mm, whichever is larger.close to other structures, other pipeline systems, wrecks, boul- 111 Girth welds shall not be inaccessible under doublerders, etc. The minimum distance should be determined based rings, clamps, or other parts of supports.upon anticipated deflections, hydrodynamic effects, and uponrisk-based evaluations. The detailed routing shall take the min- 112 Riser and J-tube supports shall be designed to ensure aimum established distance into account. smooth transition of forces between riser/J-tube and support.103 Pipelines, risers and J-tubes should be routed inside the 113 For requirements to transitions, see F110 through F113.structure to avoid vessel impact, and shall be protected against 114 Pipelines in C-Mn steel for potentially corrosive fluidsimpact loads from vessels and other mechanical interaction. of categories B, D and E (see Sec.2 C) should be designed forRisers and J-tubes should not be located inside the loading inspection pigging. In cases where the pipeline design does notzones of platforms. allow inspection pigging, an analysis shall be carried out in DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 42 – Sec.5 see note on front coveraccordance with recognised procedures to document that the — Medium and High Safety Class during normal operation:risk of failure (i.e. the probability of failure multiplied by theconsequences of failure) leading to a leak is acceptable. For plt ≥ 1.05 · pli (5.1)corrosive fluids of other categories the benefit of inspectionpigging on operational reliability shall be evaluated. — Low Safety Class during normal operation:115 For piggable components the internal diameter of thecomponent shall meet the requirements imposed by the pig- plt ≥ 1.03 · pli (5.2)train. Guidance note: Guidance note: With an incidental pressure of 10% above design pressure, the It is recommended that bends radius are designed with a radius above gives a system test pressure of approximately 1.15 times not less than 5 x nominal internal pipe diameter. the local design pressure at the highest point of the pipeline sys- tem part tested, see Figure 1. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---B 200 Mill pressure test and system pressure test Resulting test pressure System test201 The purposes of the mill test are: Internal pressure Local requirement Local incidental 5% above pli design— to constitute a pressure containment proof test pressure pressure, pli— to ensure that all pipe sections have a minimum yield stress. Filled with Filled withTherefore, the mill test pressure is defined in terms of stress water operatingutilisation, see Sec.7 E100, rather than in terms of design pres- 1 contentsure. ρtest⋅g 1 ρcont⋅g Guidance note: “in terms of stress utilisation” implies that the same structural Water depth utilisation will be achieved independent on temperature de-rating or corrosion allowance used in the design. Figure 1 Illustration of local pressures and requirements to system ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- pressure test202 The purpose of the system pressure test is to prove thepressure containment integrity of the submarine pipeline sys- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---tem, i.e. it constitutes a leakage test after completed construc-tion disclosing gross errors. 204 Alternative means to prove the same level of safety as203 The pipeline system shall be system pressure tested after with the system pressure test is allowed by agreement giveninstallation in accordance with Sec.10 O500 unless this is that the mill pressure test requirement of Sec.7 E100 has beenwaived by agreement in accordance with 204 below. The local met and not waived in accordance with Sec.7 E107.test pressure (plt) during the system pressure test shall fulfil the The industries knowledge and track record to date implies thefollowing requirement: limitations in Table 5-1 for waiving the system pressure test.Table 5-1 Requirements to waive system pressure testRequirementOther aspects with respect to system pressure test than pressure con-tainment integrity such as cleaning, contractual, shall be agreed.An inspection and test regime for the entire submarine pipeline system Guidance note:shall be established and demonstrated to provide the same level of The requirement implies that a reporting limit lower than thesafety as the system pressure test with respect to detectable defect acceptance criteria shall be used. This enables tracking of tenden-sizes etc.; Records shall show that the specified requirements have cies such that it can be documented that the criteria has been con-consistently been obtained during manufacture, fabrication and instal- sistently met. It will also indicate systematic errorslation. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---Less than 75% of the pressure containment design resistance shall be Guidance note:utilised The requirement implies that external pressure governs the wall thickness design. The advantage of the system pressure test is normally limited for deep water pipelines, hence, the criteria. The limitation implies that the wall thickness shall be at least 33% larger than required by the pressure containment criterion. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---The linepipe shall be seamless or produced by the SAW method. Guidance note:Repairs by other methods are allowed by agreement. Other welding methods have to date not proved similar degree of quality as SAW. SAW is not required for the girth welds ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 43Table 5-1 Requirements to waive system pressure test (Continued)RequirementAll components and risers shall be hydrostatically pressure tested dur- Guidance note:ing manufacture. Components include flanges, valves, fittings, mechanical con- nectors, induction bends, couplings and repair clamps, pig traps etc. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---Automated Ultrasonic Testing (AUT) shall be performed after instal- Guidance note:lation welding. Alternative NDT methods proven to give the same AUT is normally required in order to ensure that no criticaldetectability and sizing accuracy may be allowed by agreement. defects exist. The acceptance criterion is often based on an ECA linking the fracture toughness, defects and loads. A reporting limit less than this acceptance criteria is required in order to ensure that there is no systematic error on the welding and to prove that the criteria are systematically met. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---The pipeline shall not be exposed to accumulated nominal plasticstrains exceeding 2% after AUT.Installation and intervention work shall be unlikely to have caused Guidance note:damage to the submarine pipeline system. Special attention shall here be given to ploughing, other trenching methods or third party damages e.g. anchor chains of wires. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---205 During system pressure test, all limit states for safety the following format:class low shall be satisfied (see D). Rc ( f c , tc )B 300 Operating requirements RRd = (5.4) γ m ⋅ γ SC301 Operating requirements affecting safety and reliabilityof the pipeline system shall be identified during the design wherephase, and shall be documented in the DFI Resumé and Rc is the characteristic resistancereflected in the PIM system. fc is the characteristic material strength, see Eq. 5.5 and Eq.5.6 tc is the characteristic thickness, see Table 5-2 and Table 5-3 C. Design Format γm, γSC are the partial resistance factors, see Table 5-4 and 5-5C 100 General 202 Two different characterisations of the wall thickness are101 The design format in this standard is based on a Load used; t1 and t2 and are referred to explicitly in the design crite-and Resistance Factor Design (LRFD) format. ria. Thickness t1 is used where failure is likely to occur in con- nection with a low capacity (i.e. system effects are present)102 The fundamental principle of the LRFD format is to ver- while thickness t2 is used where failure is likely to occur inify that design load effects, LSd, do not exceed design resist- connection with an extreme load effect at a location with aver-ances, RRd, for any of the considered failure modes in any age thickness. These are defined in Table 5-2.scenario: Table 5-2 Characteristic wall thickness Prior to operation1) Operation2) ⎛⎛ L ⎞ ⎞ (5.3) f ⎜ ⎜ Sd ⎟ ⎟ ≤1 t1 t-tfab t-tfab-tcorr ⎜ ⎜ RRd ⎟ ⎟ ⎝⎝ ⎠i ⎠ t2 t t-tcorrWhere the fractions i denotes the different loading types that 1) Is intended when there is negligible corrosion (mill pressure test, con-enters the design criterion struction (installation) and system pressure test condition). If corrosion exist, this shall be subtracted similar to as for operation.103 A design load effect is obtained by combining the char- 2) Is intended when there is corrosionacteristic load effects from the different load categories by cer-tain load effect factors, see Sec.4 G. Guidance note: If relevant, the erosion allowance shall be compensated for in the104 A design resistance is obtained by dividing the charac- similar way as the corrosion allowance.teristic resistance by resistance factors that depends on the ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---safety class, reflecting the consequences of failures, see 200. 203 Minimum wall thickness independent on limit stateC 200 Design resistance requirements are given in Table 5-3.201 The design resistance, RRd, can normally be expressed in DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 44 – Sec.5 see note on front coverTable 5-3 Minimum wall thickness requirementsNominal diameter Safety Class Location class Minimum thickness≥ 219 mm (8”) High 2 12 mm unless equivalent protection against accidental loads, other external loads and excessive corrosion is provided by other means Low and All - Medium< 219 mm (8”) High 2 Special evaluation of accidental loads or other external loads and excessive corro- sion shall be included in the determination of minimum required wall thickness Low and All - MediumThe minimum wall thickness requirement is based on failure statistics, which liner on a steel pipe shall not be taken into account in the char-clearly indicate that impact loads and corrosion are the most likely causes of acteristic resistance, unless the strengthening effect is docu-failure and have the decisive effect on thickness design (not D/t2). mented.204 Wall thickness for stability calculations is given inE404. C 300 Characteristic material properties205 The material resistance factor, γm, is dependent on the 301 Characteristic material properties shall be used in thelimit state category and is defined in Table 5-4. resistance calculations. The yield stress and tensile strength in the limit state formulations shall be based on the engineeringTable 5-4 Material resistance factor, γm stress-strain curve.Limit state category1) SLS/ULS/ALS FLS 302 The characteristic material strength fy and fu, values toγm 1.15 1.00 be used in the limit state criteria are:1) The limit states (SLS, ULS, ALS and FLS) are defined in D. ( f y = SMYS − f y ,temp ⋅ α U ) (5.5)206 Based on potential failure consequences the pipeline fu = (SMTS − f )⋅ α (5.6)shall be classified into a safety class see Sec.2 C400. This will u ,temp Ube reflected in the safety level by the Safety Class resistancefactor γSC given in Table 5-5. Where: fy,temp and fu,temp are the de-rating values due to the tempera-The safety class may vary for different phases and different ture of the yield stress and the tensilelocations. strength respectively, see 304. αU is the material strength factor, see Table 5-6.Table 5-5 Safety class resistance factors, γ SC 303 The different mechanical properties refer to room tem- γ SC perature unless otherwise stated.Safety class Low Medium High 304 The material properties shall be selected with due regardPressure containment 2) 1.046 3),4) 1.138 1.308 1) to material type and potential temperature and/or ageingOther 1.04 1.14 1.26 effects and shall include:1) For parts of pipelines in location class 1, resistance safety class medium — yield stress may be applied (1.138). — tensile strength2) The number of significant digits is given in order to comply with the ISO — Youngs modulus usage factors. — temperature expansion coefficient.3) Safety class low will be governed by the system pressure test which is required to be 3% above the incidental pressure. Hence, for operation in For C-Mn steel this shall be considered for temperatures above safety class low, the resistance factor will effectively be 3% higher. 50°C, and for 22Cr and 25Cr for temperatures above 20°C.4) For system pressure test, αU shall be equal to 1.00, which gives an allow- Guidance note: able hoop stress of 96% of SMYS both for materials fulfilling supple- mentary requirement U and those not. Field joint coating application during installation may also impose temperatures in excess of the above and shall be consid-207 Possible beneficial strengthening effect of weight coat- ered.ing on a steel pipe shall not be taken into account in the char- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---acteristic resistance, unless the strengthening effect isdocumented. Coating which adds significant bending stiffness Guidance note:to the pipe may increase the stresses/strains in the pipe at any If no other information of de-rating effects on the yield stressdiscontinuity in the coating (e.g. at field joints). When appro- exist the recommendations for C-Mn steel and Duplex steels Fig-priate, this effect shall be taken into account. ure 2 below may be used. For 13Cr testing is normally required.208 Possible beneficial strengthening effect of cladding or ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 45 308 For material susceptible to HISC, see Sec.6 D500. C 400 Stress and strain calculations 401 Stress Concentration Factors (SCF) shall be included if relevant. Guidance note: Distinction should be made between global and local stress con- centrations. Local stress concentrations (that may be caused by welded attachments, the weld itself, or very local discontinuities) will C-Mn affect the pipe only locally and are typically accounted for in fatigue and fracture evaluations. Global stress concentrations (such as stress amplifications in field joints due to concrete coat- ing, which typically extend one diameter) will affect the pipe glo- bally, and shall be accounted for in the bending buckling evaluations as well as fatigue and fracture evaluations. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 402 Strain Concentration Factors (SNCF) shall be deter- mined and accounted for if plastic strain is experienced. The SNCF shall be adjusted for the non-linear stress-strain rela-Figure 2 tionship for the relevant load level.Proposed de-rating values for yield stress of C-Mnand duplex stainless steels (DSS). Different approaches for calculation of the SNCF for fracture assessment are specified in Appendix A. 403 Strain concentrations shall be accounted for when con- Guidance note: sidering: If no other information on de-rating effect of the ultimate stress exists, the de-rating of the yield stress can be conservatively — uneven deformation caused by variations in actual mate- applied. rial yield stress and strain hardenability between pipe ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- joints and in the weld metal due to scatter in material prop- erties305 Any difference in the de-rating effect of temperature for — variations in cross sectional area (actual diameter or walltension and compression shall be accounted for. thickness) between pipe joints — stiffening effects of coating and variations in coating Guidance note: thickness Difference in de-rating effect for tension and compression has — reduction of yield stress in field joints due to high temper- been experienced on 13Cr steel material. ature imposed by field joint coating application during ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- installation — undermatch/overmatch of actual weld metal yield stress,306 The material factor, αU, depend on Supplementary relative to actual pipe material yield stress.requirement U as shown in Table 5-6. 404 Nominal plastic strain increment shall be calculatedTable 5-6 Material Strength factor, αU from the point where the material stress-strain curve deviatesFactor Normally Supplementary requirement U from a linear relationship, see Figure 3.αU 0.96 1.00 StressNote: For system pressure test, αU shall be equal to 1.00, which gives anallowable hoop stress of 96% of SMYS both for materials fulfilling supple-mentary requirement U and those not. This is equivalent to the mill test utili-sation. SMYS Guidance note: The application of Supplementary requirement U requires docu- mentation after the manufacture and shall be used with care. Plastic Strain Based on production data, it may be used for future upgrade of the pipeline Total Strain ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---307 For manufacturing processes which introduce colddeformations giving different strength in tension and compres- 0.5% Strainsion, a fabrication factor, αfab, shall be determined. If no otherinformation exists, maximum fabrication factors for pipes Figure 3manufactured by the UOE or UO processes are given in Reference for plastic strain calculationTable 5-7.The fabrication factor may be improved through heat treatmentor external cold sizing (compression), if documented. Guidance note: The yield stress is defined as the stress at which the total strain isTable 5-7 Maximum fabrication factor, α fab 0.5%. As an example for a 415 grade C-Mn steel, a unidirectional strain of 0.5% corresponds to an elastic strain of approximatelyPipe Seamless UO & TRB & UOE 0.2% and a plastic strain of 0.3%. ERWα fab 1.00 0.93 0.85 ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 46 – Sec.5 see note on front cover D. Limit States — system collapse (external pressure only) — propagation bucklingD 100 General — combined loading criteria, i.e. interaction between exter-101 All relevant limit states (failure modes) shall be consid- nal or internal pressure, axial force and bending moment.ered in design for all relevant phases and conditions listed inSec.4. These will be given in the following sub-sections. Guidance note: 302 Large accumulated plastic strain may aggravate local As a minimum requirement, the submarine pipeline system shall buckling and shall be considered. be designed against the following potential modes of failure: D 400 Local Buckling – External over pressure only Serviceability Limit State (System collapse) - ovalisation/ ratcheting limit state 401 The characteristic resistance for external pressure (pc) - accumulated plastic strain and strain ageing (collapse) shall be calculated as: - large displacements - damage due to, or loss of, weight coating. Ultimate Limit State ( pc (t ) − pel (t )) ⋅ ( pc (t )2 − p p (t )2 ) = pc (t ) ⋅ pel (t ) ⋅ p p (t ) ⋅ f 0 ⋅ D - bursting limit state t - ovalisation/ratcheting limit state (if causing total failure) (5.10) - local buckling limit state (pipe wall buckling limit state) - global buckling limit state (normally for load-controlled where: condition) - fatigue 3 - unstable fracture and plastic collapse limit state ⎛ t ⎞ - impact. 2⋅ E ⋅⎜ ⎟ (5.11) pel (t ) = ⎝D⎠ ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 1 −ν 2102 In case no specific design criterion is given for a specific 2⋅tlimit state this shall be developed in compliance with the safety p p (t ) = f y ⋅ α fab ⋅ (5.12)philosophy in Sec.2. D D m ax – D minD 200 Pressure containment (bursting) f o = ------------------------------- - D (5.13)201 The following criteria are valid provided that the millpressure test requirement in Sec.7 E100 has been met. If not, a not to be taken < 0.005 (0.5%)corresponding decreased utilisation shall be applied.202 The pressure containment shall fulfil the following cri- αfab is the fabrication factor, see Table 5-7teria: Guidance note: In the above formulas, t shall be replaced by t1 or t2 as given in pb (t1 ) (5.7) the design criteria.plx − p e ≤ γ m ⋅ γ SC ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- Guidance note:Where Ovalisation caused during the construction phase shall beplx = pli during operation, (see Sec.3 B300 and 4 B200) and included in the total ovality to be used in design. Ovalisation dueplx = plt during system test. to external water pressure or bending moment shall not be included.203 The pressure containment resistance pb(t) is given by: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 2⋅t 2 402 The external pressure at any point along the pipelinepb (t ) = ⋅ f cb ⋅ (5.8) D −t 3 shall meet the following criterion (system collapse check):where pc (t1 ) p e − p min ≤ (5.14) ⎡ f ⎤ γ m ⋅ γ SCf cb = Min ⎢ f y ; u ⎥ (5.9) ⎣ 1.15 ⎦ where Guidance note: pmin is the minimum internal pressure that can be sustained. In the above formulae, t shall be replaced by t1 when used in Eq This is normally taken as zero for as-laid pipeline. 5.7 and t2 when used in Eq. 5.19. Guidance note: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- The system collapse will occur at the weakest point in the pipe- line. This will normally be represented by fy and the minimum204 Reduction in pressure containment resistance due to true wall thickness, t1.compressive forces (load controlled), N, shall be considered.Reference is made to DNV-RP-F101 Corroded Pipelines. A seamless produced linepipe’s weakest section may not be well represented by the minimum wall thickness since it is not likely toD 300 Local buckling - General be present around the whole circumference. A larger thickness, between t1 and t2, may be used for such pipes if this can be docu-301 Local buckling (pipe wall buckling) implies gross defor- mented representing the lowest collapse capacity of the pipeline.mation of the cross section. The following criteria shall be ful-filled: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 47D 500 Propagation buckling it is recommended to have a larger confidence and a safety class higher than for the propagating pressure is recommended.501 Propagation buckling cannot be initiated unless localbuckling has occurred. In case the external pressure exceeds ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---the criteria given below, buckle arrestors should be installedand spacing determined based on cost and spare pipe philoso- D 600 Local Buckling - Combined Loading Criteriaphy. The propagating buckle criterion reads: 601 Differentiation is made between: p pr — Load Controlled condition (LC condition)pe < (5.15) — Displacement Controlled condition (DC condition). γ m ⋅ γ SC Different design checks apply to these two conditions.where 602 A load-controlled condition is one in which the struc- tural response is primarily governed by the imposed loads. 2.5 ⎛t ⎞ D/t2 < 45 (5.16) 603 A displacement-controlled condition is one in which thep pr = 35 ⋅ f y ⋅ α fab ⎜ 2 ⎟ ⎝D⎠ structural response is primarily governed by imposed geomet- ric displacements.αfab is the fabrication factor, see Table 5-7 604 A load controlled design criterion can always be applied Guidance note: in place of a displacement controlled design criterion. Collapse pressure, pc, is the pressure required to buckle a pipeline. Guidance note: Initiation pressure, pinit, is the pressure required to start a propa- An example of a purely displacement-controlled condition is a gating buckle from a given buckle. This pressure will depend on pipeline bent into conformity with a continuous curved structure, the size of the initial buckle. such as a J-tube or on a reel. In that case, the curvature of the pipe Propagating pressure, ppr, is the pressure required to continue a axis is imposed but the circumferential bending that leads to propagating buckle. A propagating buckle will stop when the ovalisation is determined by the interaction between the curva- pressure is less than the propagating pressure. ture of the axis and the internal forces induced by the curvature. The relationship between the different pressures are: A less clear-cut example is a pipeline in contact with the rollers of a lay barge stinger. On a large scale, the configuration of the pc > pinit > ppr pipeline has to conform to the rollers, and in that sense is dis- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- placement controlled. On a local scale however, bending of the pipe between the rollers is determined by the interaction between Guidance note: weight and tension and is load-controlled. The stinger tip will, The safety class and amount of metal loss due to corrosion shall however, always be load controlled. be determined based on the probability and possibility of experi- Another intermediate case is an expansion spool in contact with encing a high external over pressure during operation. For liquid the seabed. Pipeline expansion induced by temperature and pres- pipelines, safety class low and non-corroded cross section is nor- sure imposes a displacement at the end of the spool. The struc- mally used while other properties may be used for gas pipelines tural response of the spool itself has little effect on the imposed since they may experience a nearly zero internal pressure in the expansion displacement, and the response is primarily displace- operational phase. ment-controlled. However, the lateral resistance to movement of Note that the possibility of a propagating buckle shall not be the spool across the seabed also plays a significant part and combined with the likelihood of getting an initiating event in the induces a degree of load control. shut-down time span, since a dent caused during the pressurised The answer to the question on if a condition is load controlled or condition, may start propagating as the internal pressure is lost. displacement controlled is impossible since the questions in wrong, the question should be; how can one take partial benefit ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- of that a condition is partially displacement controlled element? On a general basis this needs sensitivity analyses. A load control-502 A buckle arrestor capacity depends on led criterion can, however, always be applied— propagating buckle resistance of adjacent pipe ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---— propagating buckle resistance of an infinite buckle arrestor— length of arrestor. Load controlled condition 605 Pipe members subjected to bending moment, effectiveAn integral buckle arrestor may be designed by: axial force and internal overpressure shall be designed to sat- isfy the following condition at all cross sections: pXpe ≤ (5.17) 2 1.1 ⋅ γ m ⋅ γ SC ⎧ M Sd ⎧ γ ⋅ γ ⋅ S ( p )⎫ ⎫ ⎛ 2 p − pe ⎞ 2 ⎪ ⎪ ⎪ ⎪ ⎨γ m ⋅ γ SC ⋅ + ⎨ m SC Sd i ⎬ ⎬ + ⎜ α p ⋅ i ⎟ ≤1 ⎪ α c ⋅ M p (t 2 ) ⎪ α c ⋅ S p (t 2 ) ⎪ ⎪ ⎜ ⎩ ⎭ ⎭ ⎝ α c ⋅ pb (t 2 ) ⎟ ⎠where the crossover pressure px is ⎩ (5.19a) ⎡ ⎛ t ⋅ L ⎞⎤ (p X = p pr + p pr , BA − p pr ) ⋅ ⎢1 − EXP⎜ − 20 2 2BA ⎟⎥ (5.18) ⎣ ⎝ D ⎠⎦ 2 ⎧ ⎪ M Sd (t2 ) ⎧ γ m ⋅ γ SC ⋅ S Sd ( pi , t2 ) ⎫ ⎫ ⎛ 2 ⎪ p − pe ⎞ 2 ⎨γ m ⋅ γ SC ⋅ +⎨ ⎜α p ⋅ i ⎬ ⎬ +⎜ ⎟ ≤1ppr,BA is the propagating buckle capacity of an infinite arres- ⎪ αc ⎩ αc ⎭ ⎪ ⎝ α c ⋅ pb (t2 ) ⎟ ⎠ tor. This is calculated by Eq. 5.16 with the buckle arre- ⎩ ⎭ stor properties (5.19b)LBA buckle arrestor length Applies for D/t2 ≤ 45, Pi > Pe Guidance note: The propagating buckle criterion, Eq. 5.15, corresponds to a where nominal failure probability that is one order of magnitude higher than the target nominal failure probability. This is because it is MSd is the design moment, see Eq. 4.5 dependent on an initiating even. However, for a buckle arrestor, SSd is the design effective axial force, see Eq. 4.7 DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 48 – Sec.5 see note on front coverpi is the internal pressure, see Table 4-3 the following equation:pe is the external pressure, see Sec.4 B300pb is the burst pressure, Eq. 5.8 ⎧ 2 ⎫ ⎫ 2 2 ⎪ M Sd ⎧ ⎪ γ m ⋅ γ SC ⋅ S Sd ⎪ ⎪ ⎛ pe − pmin ⎞Sp and Mp denote the plastic capacities for a pipe defined by: ⎨γ m ⋅ γ SC ⋅ +⎨ ⎬ ⎬ + ⎜ γ m ⋅ γ SC ⋅ ⎜ ⎟ ≤1 ⎟ ⎪ α c ⋅ M p (t2 ) ⎪ α c ⋅ S p (t 2 ) ⎪ ⎪ ⎝ ⎩ ⎭ ⎭ pc (t2 ) ⎠ ⎩S p (t ) = f y ⋅ π ⋅ (D − t ) ⋅ t (5.20) (5.28a)M p (t ) = f y ⋅ (D − t ) ⋅ t 2 (5.21) 2 ⎧ ⎪ ⎫ M Sd (t2 ) ⎧ γ m ⋅ γ SC ⋅ S Sd (t2 ) ⎫ ⎪ ⎛ 2 pe − pmin ⎞ 2MSd’ = MSd/Mp (normalised moment) ⎨γ m ⋅ γ SC ⋅ +⎨ ⎬ ⎬ + ⎜ γ m ⋅ γ SC ⋅ ⎜ ⎟ ≤1 ⎟ ⎪ αc ⎩ αc ⎭ ⎪ ⎝ pc (t2 ) ⎠SSd’ = SSd/Sp (normalised effective force) ⎩ ⎭ (5.28b) f D/t2 ≤ 45, Pi < Peα c = (1 − β ) + β ⋅ u (5.22) fy where pmin is the minimum internal pressure that can be sustained. ⎧ pi − pe 2 This is normally taken as zero for installation except for ⎪ 1− β < cases where the pipeline is installed water filled. ⎪ pb 3αp = ⎨ (5.23) pc is the characteristic collapse pressure, Eq. 5.10. This ⎛ ⎞ ⎪1 − 3β ⎜1 − pi − pe ⎟ pi − pe 2 ≥ shall be based on thickness t2. ⎪ ⎜ pb ⎟ pb 3 ⎩ ⎝ ⎠ Guidance note: The left hand side of the combined loading criterion is referred to ⎧ 0.5 for D / t 2 < 15 as interaction ratio in order not to mix it with “unity check”. In a ⎪⎛ 60 − D / t 2 ⎞ ⎪ unity check, the loads are normally directly proportional to the uti- β = ⎨⎜ ⎟ for 15 ≤ D / t 2 ≤ 60 (5.24) lisation while the load components are squared in this criterion. ⎪⎝ 90 ⎠ ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- ⎪ ⎩ 0 for D / t 2 > 60 Displacement controlled conditionαc is a flow stress parameter and αp account for effect of D/t2 608 Pipe members subjected to longitudinal compressiveratio. strain (bending moment and axial force) and internal over pres- Guidance note: sure shall be designed to satisfy the following condition at all cross sections: The left hand side of the combined loading criterion is referred to as interaction ratio in order not to mix it with “unity check”. In a unity check, the loads are normally directly proportional to the ε c (t 2 , pmin − pe ) utilisation while the axial load and internal pressure are squared ε Sd ≤ ε Rd = D/t2 ≤ 45, pi ≥ pe (5.29) in this criterion. γε ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- where: Guidance note: εSd = Design compressive strain, Eq. (4.6) In order to improve the engineering understanding, it is recom- mended to use normalised moment, force and pressure as given ⎛ t ⎞ ⎛ p − pe ⎞ in the b equations. ε c (t , p min − p e ) = 0.78 ⋅ ⎜ − 0.01⎟ ⋅ ⎜1 + 5.75 ⋅ min ⎜ ⎟ ⋅ α h −1.5 ⋅ α gw ⎟ ⎝ D ⎠ ⎝ pb (t ) ⎠ ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- (5.30)606 If the pipeline in addition to the axial load, pressure and pmin = Minimum internal pressure that can be continuouslymoment also has a lateral point load, this should be included sustained with the associated strainby a modification of the plastic moment capacity as follows: γε = Strain resistance factor, Table 5-8M p ,point load = M p ⋅ α pm (5.25) ⎛R ⎞ αh = ⎜ ⎜ R ⎟ , Table 7.5 and Table 7.11 t 0,5where ⎟ ⎝ m ⎠ maxαpm = Plastic moment reduction factor accounting for point load αgw = See Sec.13 E1000. D / t2 R 609 Pipe members subjected to longitudinal compressiveα pm = 1 − (5.26) strain (bending moment and axial force) and external over 130 R y pressure shall be designed to satisfy the following condition at all cross sections:R = Reaction force from point load 0.8 ⎛ ⎞R y = 3.9 ⋅ f y ⋅ t 2 2 (5.27) ⎜ ⎟ ⎜ ε Sd ⎟ pe − pmin (5.31) + ≤ 1 D/t2 < 45, pmin < pe ⎜ ε c (t 2 ,0) ⎟ pc (t 2 )607 Pipe members subjected to bending moment, effective ⎜ γ ⎟axial force and external overpressure shall be designed to satisfy ⎝ ε ⎠ γ m ⋅ γ SC DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 49 Guidance note: — exposed on un-even seabed For D/t2 < 23, the utilisation may be increased provided that full — buried pipelines scale testing, observation, or former experience indicate suffi- — reference is made to DNV-RP-F110 Global Buckling of cient safety margin in compliance with this standard. Any Submarine Pipelines – Structural Design due to High increased utilisation shall be supported by analytical design Temperature/High Pressure. methods. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 708 It is not sufficient to design HP/HT pipelines for global buckling based on "worst case condition" axial and lateral soil Guidance note: resistance combined with displacement controlled local buck- System effects are normally not present for local buckling con- ling criteria only. These upper and lower bound soil resistance siderations and, hence, t2 should be used. However, for reeling, a values will typically have a probability of exceedance in the large portion of the pipeline will be exposed to similar curvature order of a couple of per cent and will not alone prove a suffi- and load combination “a” shall be used combined with the con- cient nominal failure probability. A more total evaluation of dition factor of 0.82, yielding unity, and the nominal thickness the failure probability is, hence, required. can be used also for this criteria. The thickness and yield stress variation along the pipe, in particular between two pipe joints D 800 Fatigue should be evaluated in addition to this system effect. 801 Reference is made to the following codes: DNV-RP-C203 Fatigue Strength Analysis of Offshore SteelTable 5-8 Resistance strain factors, γ e StructuresSafety class DNV-RP-C205 Environmental Conditions and Environmen-Low Medium High tal Loads2.0 2.5 3.3 DNV-RP-F105 Free Spanning Pipelines DNV-RP-F204 Riser Fatigue.610 A higher probability of failure corresponding to a serv- 802 The pipeline systems shall have adequate safety againsticeability limit state may be allowed during the installation fatigue failures within the design life of the system.phase provided that: 803 All stress fluctuations imposed on the pipeline system— aids to detect buckle are provided during the entire design life, including the construction phase,— repair of potential damage is feasible and may be per- which have magnitude and corresponding number of cycles formed during laying large enough to cause fatigue effects shall be taken into— buckle arrestors are installed if the external pressure account when determining the long-term distribution of stress exceeds the initiation propagating pressure. ranges. The fatigue check shall include both low-cycle fatigue and high-cycle fatigue. The requirements regarding accumu-Relevant resistance factors may then be calibrated according to lated plastic strain (D1000 below) shall also be satisfied.the SLS requirements in Sec.2. Guidance note:D 700 Global buckling Typical causes of stress fluctuations in a pipeline system are: - direct wave action701 Global buckling implies buckling of the pipe as a bar in - vibrations of the pipeline system, e.g. due to vortex sheddingcompression. The pipeline may buckle globally, either down- (current, waves, wind, towing) or fluid flowwards (in a free span), laterally ("snaking" on the seabed), or - supporting structure movementsvertically (as upheaval buckling of a buried pipeline or on a - fluctuations in operating pressure and temperature.free-span shoulder of an exposed pipeline). Locations to be checked are the girth welds, seam welds and con-702 The effect of internal and external pressures should be struction details. Seam welds will be more vulnerable to fatiguetaken into account using the concept of an effective axial force, for higher steel grades.see Sec.4 G300. The procedure is as for "ordinary" compres- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---sion members in air.703 A negative effective axial force may cause a pipeline or 804 Special consideration shall be given to the fatiguea riser to buckle as a bar in compression. Distinction shall be assessment of construction details likely to cause stress con-made between load-controlled and displacement-controlled centrations, and to the possibility of having low-cycle highbuckling. strain fatigue. The specific design criterion to be used depends upon the analysis method, which may be categorised into:704 The following global buckling initiators shall be consid-ered: — methods based upon fracture mechanics (see 805) — methods based upon fatigue tests (see 806).— trawl board impact, pullover and hooking— out of straightness. 805 Where appropriate, a calculation procedure based upon fracture mechanics may be used. The specific criterion to be705 Load-controlled global buckling may be designed in used shall be determined on a case-by-case basis, and shallaccordance with DNV-OS-C101 Design of Offshore Steel reflect the target safety levels in Sec.2 C500.Structures, General (LRFD). For further guidance on fracture mechanics based fatigue anal-706 Displacement-controlled global buckling may be yses see Appendix A.allowed. This implies that global buckling may be allowedprovided that: 806 When using calculation methods based upon fatigue tests, the following shall be considered:— pipeline integrity is maintained in post-buckling configu- rations (e.g. local buckling, fracture, fatigue etc.) — determination of long-term distribution of stress range, see— displacement of the pipeline is acceptable. 807 — selection of appropriate S-N curve (characteristic resist-707 For design of the following high pressure/high tempera- ance), see 808ture pipelines: — determination of Stress Concentration Factor (SCF) not included in the S-N curve— exposed on even seabed — determination of accumulated damage, see 809. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 50 – Sec.5 see note on front cover807 As most of the loads which contribute to fatigue are of a fabrication of the pipe, is not to exceed 3%, defined as:random nature, statistical consideration is normally required indetermining the long-term distribution of fatigue loading D max – Dm ineffects. Where appropriate, deterministic or spectral analysis f 0 = ------------------------------- ≤ 0.03 - (5.33)may be used. D808 The characteristic resistance is normally given as S-N The requirement may be relaxed if:curves or -N curves, i.e. stress amplitudes (or strain amplitudesfor the case of low-cycle fatigue), versus number of cycles to — a corresponding reduction in moment resistance has beenfailure, N. The S-N curve shall be applicable for the material, includedconstruction detail, NDT acceptance criteria and state of stress — geometrical restrictions are met, such as pigging require-considered, as well as to the surrounding environment. The S- mentsN curve shall be based on the mean curve of log (N) with the — additional cyclic stresses caused by the ovalisation havesubtraction of two standard deviations in log (N). If a fracture been consideredmechanic assessment (ECA) is performed according to — tolerances in the relevant repair system are met.requirements in D1100, the S-N curve shall be validated for theallowable defect sizes determined by the ECA or a fracture 902 Ovalisation shall be checked for point loads at any pointmechanics based fatigue assessment shall be performed as along the pipeline system. Such point loads may arise at free-described in Appendix A. span shoulders, artificial supports and support settlements.809 In the general case where stress fluctuations occur with D 1000 Accumulated deformationvarying amplitude of random order, the linear damage hypoth-esis (Miners Rule) may be used. The application of Miners 1001 Accumulated plastic deformation of pipe caused byRule implies that the long-term distribution of stress range is cyclic loads leading to increased diameter or ovality (ratchet-replaced by a stress histogram, consisting of a number of con- ing) shall be considered. If the ratcheting causes increasedstant amplitude stress or strain range blocks, (σr)i or (εr)i, and ovality, special consideration shall also be made of the effectthe corresponding number of repetitions, ni. Thus, the fatigue on buckling resistance.criterion is given by: 1002 Accumulated longitudinal displacement of the pipeline (pipeline walking) shall be considered. This may occur during k start-up/shut-down for: ni Dfat = ----- ≤ a fat (5.32) — pipeline shorter than two anchor lengths, or Ni i=l — pipeline parts with virtual anchor, and — pipeline laying on seabed slope, orWhere: — pipeline connected to pulling force (e.g. connected to SCR).Dfat = Miners sumk = number of stress blocks D 1100 Fracture and supplementary requirement Pni = number of stress cycles in stress block i 1101 Pipeline systems shall have adequate resistance againstNi = number of cycles to failure at constant stress range of initiation of unstable fracture. magnitude (sr)i or strain range (er)i. 1102 The safety against unstable fracture is considered satis-αfat = allowable damage ratio, see Table 5-9 factory if the requirements in Table 5-10 are met.810 For detailed explanation regarding fatigue calculations/ Table 5-10 Requirements to unstable fracture1)analysis reference is made to DNV-RP-F105 Free Spanning Total nominal AccumulatedPipelines and DNV-RP-F204 Riser Fatigue. In cases where strain plastic strainthis guideline is not applicable, allowable damage ratios aregiven in Table 5-9. ε l,nom ≤ 0.4% Materials, welding, workman- ship and testing are in accord- ance with the requirements ofTable 5-9 Allowable damage ratio for fatigue this standardSafety Class Low Medium High As an alternative girth weldsα fat 1/3 1/5 1/10 allowable defect sizes may be assessed according to Appendix A.811 The split between the different phases of the designfatigue life as described in Table 5-9 shall be agreed in the ini- 0.4% < ε l,nom The integrity of the girth weldstiation phase of the project and be based on the highest safety shall be assessed in accordance with Appendix Aclass during the lifetime. 1.0% < ε l,nom2) Supplementary requirement (P) Guidance note: shall be applied or 2.0% < ε p For a pipeline where e.g. 10% of the design lifetime can be uti- lized during the installation and which is classified as safety class 1) The strain levels refers to after NDT. medium (high) during the operational phase this will correspond 2) Total nominal strain in any direction from a single event. to a damage ratio of 2% (1%) of the operational lifetime. A common split between installation, as laid and operation is 1103 Pipeline systems transporting gas or mixed gas and liq- 10%, 10% and 80% but depend on the need for fatigue capacity uids under high pressure shall have adequate resistance to in the different phases. propagating fracture. This may be achieved by using: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — material with low transition temperature and adequate Charpy V-notch toughnessD 900 Ovalisation — adequate DWTT shear fracture area901 Risers and pipelines shall not be subject to excessive — lowering the stress levelovalisation and this shall be documented. The flattening due to — use of mechanical crack arrestorsbending, together with the out-of-roundness tolerance from — by a combination of these methods. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 51Design solutions shall be validated by calculations based upon Note to table: Standard industry practice assumes safety factors equal to 1.0 forrelevant experience and/or suitable tests. Requirements to frac- an accidental event with a probability of occurrence equal to 10, and survival of the pipeline is merely related to a conservative definition of characteristicture arrest properties need not be applied when the pipeline resistance. In this standard, accidental loads and events are introduced in adesign tensile hoop stress is below 40% of fy. more general context with a link between probability of occurrence and actual failure consequence. For combined loading the simplified design check pro-1104 Material meeting the supplementary requirement for poses a total factor in the range 1.1-1.2, which is consistent with standardfracture arrest properties (F) (Sec.7 I200) is considered to have industry practice interpreted as corresponding to safety class Medium for acci-adequate resistance to running propagating ductile fracture for dental loads with a probability of occurrence equal to 10-4.applications carrying essentially pure methane up to 80%usage factor, 15 MPa internal pressure and 30 mm wall thick-ness. For depths down to 10 metres and onshore, the requiredCharpy V-notch impact energy shall be specially considered. E. Special ConsiderationsD 1200 Ultimate limit state – Accidental loads E 100 General1201 The design against accidental loads may be performed 101 This subsection gives guidance on conditions that shallby direct calculation of the effects imposed by the loads on the be evaluated separately. Both the load effects and acceptancestructure, or indirectly, by design of the structure as tolerable criteria are affected.to accidents. E 200 Pipe soil interaction1202 The acceptance criteria for ALS relate to the overall 201 For limit states influenced by the interaction between theallowable probability of severe consequences. pipeline and the soil, this interaction shall be determined tak-1203 Design with respect to accidental load must ensure that ing due account for all relevant parameters and the uncertain-the overall nominal failure probability complies with the nom- ties related to these.inal failure probability target values in Sec.2. The overall nom- In general pipeline soil interaction depends on the characteris-inal failure probability from accidental loads can be expressed tics of the soil, the pipeline, and the failure mode in question,as the sum of the probability of occurrence of the ith damaging which shall all be properly accounted for in the simulation ofevent, PDi, times the structural failure probability conditioned the pipeline soil interaction.on this event, Pf|Di. The requirement is accordingly expressedas: 202 The main soil characteristics governing the interaction are the shear strength and deformation properties. p f D i ⋅ P D i ≤ p f, T (5.34) 203 Pipeline characteristics of importance are submerged weight, diameter stiffness, roughness of the pipeline surface, and initial embedment from installation which shall all bewhere Pf,T is the relevant target nominal failure probability accounted for as relevant for the limit state in question.according to Sec.2. The number of discretisation levels mustbe large enough to ensure that the resulting probability is eval- 204 All relevant load effects shall be considered. Thisuated with sufficient accuracy. includes:1204 The inherent uncertainty of the frequency and magni- — load duration and history effects (e.g. varying verticaltude of the accidental loads, as well as the approximate nature reactions from installation laying pressures)of the methods for determination of accidental load effects, — variations in the unit weight of the pipe (e.g. empty, watershall be recognised. Sound engineering judgement and prag- filled and operation conditions)matic evaluations are hence required. — cyclic loading effects (both directly from pipe as well as hydrodynamic loads)1205 If non-linear, dynamic finite element analysis isapplied, it shall be ensured that system performance and local 205 Some soils have different resistance values for long termfailure modes (e.g. strain rate, local buckling, joint overloading loading and for short term loading, related to the difference inand joint fracture) are adequately accounted for by the models drained and non-drained behaviour and to creep effects in drainedand procedures applied. and non-drained condition. This shall be taken into account.1206 A simplified design check with respect to accidental 206 For limit states involving or allowing for large displace-load may be performed as shown in Table 5-11 using appropri- ments (e.g. lateral pull-in, pipeline expansion of expansionate partial safety factors. The adequacy of simplified design loops, global buckling or when displacements are allowed forcheck must be assessed on the basis of the summation above in on-bottom condition) the soil will be loaded far beyond failure,order to verify that the overall failure probability complies involving large non-linearities, remoulding of soil, ploughingwith the target values in Sec.2. of soil etc. Such non-linear effects and the uncertainties related to these shall be considered. 207 For pipelines that are buried (trenched and/or covered byTable 5-11 Simplified Design Check versus Accidental loads gravel) and susceptible to global buckling the uplift resistanceProb. of Safety Class Safety Class Safety Class and possible increased axial resistance shall be considered.occurrence 1) Low Medium High The possible effect of backfill material from trenching shall be> 10-2 Accidental loads may be regarded similar to envi- considered. ronmental loads and may be evaluated similar to Guidance note: ULS design check Due to the uncertainties in governing soil parameters, load effects10-2 – 10-3 To be evaluated on a case by case basis etc., it is difficult to define universally valid methods for simulation10-3 – 10-4 γC = 1.0 γC = 1.0 γC = 1.0 of pipe soil interaction effects. The limitations of the methods used, whether theoretically or empirically based, shall be thoroughly10-4 – 10-5 γC = 0.9 γC = 0.9 considered in relation to the problem at hand. Extrapolation beyond10-5 – 10-6 Accidental loads or events may γC = 0.8 documented validity of a method shall be performed with care, as be disregarded shall simplifications from the problem at hand to the calculation< 10-6 model used. When large uncertainties exist, the use of more than one calculation approach shall be considered.1) When failure mode is bursting the probability of occurrence should be 1- 2 order of magnitudes lower, ref Table 2-5. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 52 – Sec.5 see note on front coverE 300 Spanning risers/pipelines special supporting structures or anchoring devices other than weight coating, shall be designed against sinking as described301 Spanning risers and pipelines shall have adequate safety under 405 above. Special considerations shall here be made toagainst local buckling, fatigue, fracture and ovality and these mechanical components such as valves and Tees.shall be documented. 409 It shall be documented that pipelines situated on the sea302 For design of free spanning pipelines, reference is madeto DNV-RP-F105 Free Spanning Pipelines. For fatigue design bottom have adequate safety against being lifted off the bottomof risers, reference is given to DNV-RP-F204 Riser Fatigue. or moved horizontally. For assessment of horizontal (trans- verse) stability of pipelines exposed to wave and current loads,E 400 On bottom stability reference is made to DNV-RP-F109 On-bottom Stability Design of Submarine Pipeline.401 The pipeline shall be supported, anchored in opentrench, or buried in such a way that under extreme functional 410 The most unfavourable combination of simultaneouslyand environmental loading conditions, the pipeline will not acting vertical and horizontal forces on the pipeline shall bemove from its as-installed position. This does not include per- considered. When determining this unfavourable combination,missible lateral or vertical movements, thermal expansion, and the variation in forces along the line, including directionalitya limited amount of settlement after installation. effects of waves and current, shall be addressed. Guidance note: 411 The transverse pipeline stability may be assessed using The acceptance criterion on permissible movements may vary three-dimensional dynamic or two-dimensional static analysis along the pipeline route. Examples of possible limitations to methods. The dynamic analysis methods allow limited pipe pipeline movements include: movements, but require accurate three-dimensional modelling. - local buckling, fatigue and fracture of pipe 412 The coefficient of equivalent friction, µ, may vary - deterioration/wear of coating within a wide range depending on the seabed soil, surface - geometrical limitations of supports roughness, weight and diameter of the pipeline. When the - distance from other pipelines, structures or obstacles. pipeline has some penetration into the soil, the lateral resist- ance includes both friction type resistance and resistance due ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- to mobilising the soil outside the contact surface. In such cases the equivalent friction coefficient may vary with the vertical402 Liquid or gas pipelines in the air- or gas-filled condition load level.shall have a specific gravity which is higher than that of thesurrounding sea water (negative buoyancy). 413 Axial (longitudinal) stability shall be checked. The anode structural connection (when exposed to friction, e.g.,403 When the pipeline is routed in areas that may be influ- pipelines without weight coating) shall be sufficient to sustainenced by unstable slopes, that could lead to slope failure and the anticipated friction force.flow of soil that will impact the pipeline, the probability ofsuch slope failures shall be evaluated. Any relevant slope fail- 414 Pipeline movements due to thermal axial expansion,ure triggering effect, such as wave loading, earthquake loading shall be allowed for near platforms/structures (e.g. at riser tie-or man made activities (e.g. the pipe-laying itself), shall be in point) and where the pipeline changes direction (e.g. at off-considered. Possible flow rates and densities at the pipeline set spools). The expansion calculations shall be based uponshall be evaluated for stability. If stability can not be guaran- conservative values for the axial frictional resistance.teed by sufficient weight of the pipeline, by burial of the pipe-line or by other means, re-routing of the pipeline shall be 415 In shallow water, the repeated loading effects due torequired. wave action may lead to a reduction of the shear strength of the soil. This shall be considered in the analysis, particularly if the404 For weight calculations of the pipe, the nominal wall back fill consists of loose sand which may be susceptible to liq-thickness shall be reduced to compensate for the expected uefaction.average weight reduction due to metal loss. For pipelines withminor corrosion allowance this reduction may be omitted and 416 If the stability of the pipeline depends on the stability ofthe nominal thickness used. the seabed, the latter should be checked.405 Buried pipelines shall have adequate safety against sink- E 500 Trawling interferenceing or flotation. For both liquid and gas pipelines, sinking shallbe considered assuming that the pipeline is water filled, and 501 The pipeline system shall be checked for all three load-flotation shall be considered assuming that the pipeline is gas ing phases due to trawl gear interaction, as outlined in Sec.4 F.or air filled (if relevant). For more detailed description, reference is made to DNV-RP- F111 Interference between Trawl Gear and Pipelines.406 If the specific submerged weight of the water-filled pipeis less than that of the soil, then no further analyses are required 502 The acceptance criteria are dependent on the trawlingto document safety against sinking. If pipelines are installed in frequency (impact) and the safety classification (pull-over andsoils having a low shear strength, then the soil bearing resist- hooking) given in Sec.2 C400.ance shall be documented. If the soil is, or is likely to be, liq- 503 The acceptance criteria for trawl impact refer to anuefied, it shall be documented that the depth of sinking will be acceptable dent size. The maximum accepted ratio of perma-satisfactorily limited (either by the depth of liquefaction or by nent dent depth to the pipe diameter is:the build-up of vertical resistance during sinking) meeting therequirements of D above. HP407 If the specific submerged weight of the gas- or air-filled ≤ 0.05η (5.35) Dpipe is less than that of the soil, it shall be documented that theshear strength of the soil is adequate to prevent flotation. Thus, where:in soils which are or may be liquefied, the specific weight ofthe buried gas- or air-filled pipeline is not to be less than that Hp = permanent plastic dent depthof the soil. η = usage factor given in Table 5-12. Load effect factors408 Pipelines resting directly on the sea bottom without any equal to unity. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 53 requirements for components in Sec.8.Table 5-12 Usage factor (η) for trawl door impact Impact frequency Usage factor Table 5-13 Referenced standards for structural design of (per year per km) η components > 100 0 Component Design Code1) Additional design requirements 1-100 0.3 All Non-linear FE analyses F100 10-4-1 0.7 Components according to; ASME VIII listed below 2) Division 2 / EN 13445 / PD504 When allowing for permanent dents, additional failure 5500modes such as fatigue and collapse shall be taken into account. Induction ISO 15590-1Any beneficial effect of internal over-pressure, i.e. "pop-out" Bends F200shall not normally be included. The beneficial effects of pro- Fittings Bends: F200tective coating may be taken into account. The impact effec- Tees: ASME B31.4, B31.8 F600tiveness of coating shall be documented. Flanges 15590-3/ ISO 7005-1 or NORSOK L005 / EN 1591-1505 Pullover loads shall be checked in combination with Valves ISO 14723 F500other relevant load effects. All relevant failure modes for lat- Mechanical ASME VIII Division 2 / ENeral buckling shall be checked. Accumulation of damage due connectors 13445 / PD 5500to subsequent trawling is not normally allowed. Couplings and DNV-RP-F113 repair clamps, Hot taps: API RP 2201506 Hooking loads shall be checked in combination with other hot tapsrelevant load effects. All relevant failures modes shall be checked. Bolting ASME VIII Division 2 / EN 13445 / PD 5500E 600 Third party loads, dropped objects CP Insulating ASME VIII Division 2 / EN F300601 The pipeline shall be designed for impact forces caused joints 13445 / PD 5500by, e.g. dropped objects, fishing gear or collisions. The design Anchor flanges N.A. see Note 2)may be achieved either by design of pipe, protection or means Buckle and fracture arres-to avoid impacts. tors602 The design criteria shall be based upon the frequency/ Pig traps ASME VIII Division 2 / EN F400likelihood of the impact force and classified as accidental, 13445 / PD 5500environmental or functional correspondingly, see D1200. 1) Other recognised equivalent codes may be used.603 For guidance on impacts, reference is made to DNV-RP- 2) Required in case the code used in the design of a component does not take into account forces other than the internal pressure, see 105.F107 Risk Assessment of Pipeline Protection. 103 All pressure containing components used in the subma-E 700 Thermal Insulation rine pipeline system shall generally represent at least the same safety level as the connecting riser/pipeline section.701 When a submerged pipeline is thermally insulated, itshall be documented that the insulation is resistant to the com- 104 The component shall be designed to accommodate the loading from connected the pipeline section and vice versabination of water, temperature and hydrostatic pressure. with appropriate safety.702 Furthermore, the insulation should be resistant to oil and 105 The design of pipeline components shall be according tooil-based products, if relevant. The insulation shall also have the recognised codes. If the code used in the design of a compo-required mechanical strength to external loads, as applicable. nent does not take into account forces other than the internal pressure, additional evaluations, e.g. non-linear FE analyses703 Degradation of the insulation during construction and according to; ASME VIII Division 2 / EN 13445 / PD 5500,operation should be considered. are required in order to address the maximum forces that can be transferred to the component from the connecting pipelineE 800 Settings from Plugs sections under installation and operation.801 For loads from plugs, reference is given to DNV-RP- The strength shall, as a minimum be:F113 Pipeline Subsea Repair. — equivalent to the connecting pipeline, or — sufficient to accommodate the most probable maximum 100-year load effect that will be transferred to the compo- nent from the connecting pipeline under installation and F. Pipeline Components and Accessories operation, see Sec.4.F 100 General 106 The load scenarios as described in Sec.4 as well as par-101 This Subsection is applicable to pressure containing ticular loads associated with the component shall be analysed. This implies that also external hydrostatic pressure shall becomponents (e.g. bends, flanges and connectors, Tee’s, valves considered in the design with respect to both strength and inter-etc.) used in the submarine pipeline system. Supporting struc- nal leakage when relevant.ture requirements are given in G. 107 For material susceptible to HISC, see Sec.6 D500.102 Design of components may be based on the industry rec- 108 Sealing systems should be designed to allow testingognised codes as listed in Table 5-13 but shall also comply without pressurising the pipeline.with the structural design and functional requirements of this 109 The pigging requirements in B114 and B115 shall besub-section and with the material, manufacturing and test considered for the component. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 54 – Sec.5 see note on front cover110 Transitions in C-Mn and low alloy steels where the nom- η = usage factor as given by Table 5-13inal material thickness or yield stress is unequal shall be in N = pipe wall forceaccordance with ASME B 31.8 Appendix I, Figure 15 orequally recognised codes. Transition in C-Mn linepipe by M = bending moment.means of an external or internal taper shall not be steeper than1 in 4. If transitions to these requirements are not feasible, a Table 5-14 Usage factors for equivalent stress checktransition piece shall be inserted. Safety class111 Transitions in duplex stainless steels and 13Cr marten- Low Medium Highsitic stainless steels shall be such that the local stresses will not η 1.00 0.90 0.80exceed 0.8 SMYS. Guidance note:112 Internal transitions between different wall thicknesses The ovalisation of the bend has typically to be determined byand internal diameters for girth welds in pipes of equal SMYS finite element calculation. The acceptable distortion will typi-may be made in the base material provided radiographic exam- cally governed by the bullet points in D900.ination only is specified. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---113 For welds to be examined by ultrasonic testing, transi-tion tapering in the base material should be avoided. If tapering F 300 Design of insulating jointsis unavoidable the pipe ends shall be machined to provide par-allel external and internal surfaces before the start of the taper. 301 CP insulating joints shall be of the boltless, monolithicThe length of the parallel surfaces shall at least be sufficient to coupling type and shall be provided with a double seal system.allow scanning from the external surface and sufficient for the 302 Insulating joints shall be fitted with pup pieces withrequired reflection off the parallel internal surface. mechanical properties and dimensions identical to that of the114 Specifications for installation and make-up of the com- adjoining pipeline.ponent shall be established. 303 Insulating joints shall be capable of meeting the test115 The pressure testing of components (i.e. Factory Accept- requirements given in Sec.8 B900 and to withstand the effectsance Test) to be in accordance with specified design code. of the environment without loss of performance. 304 To protect insulating joints and CP equipment fromF 200 Design of bends lightning effects, lightning protection shall be installed. Surge201 This Standard does not provide any limit state criteria arrestors should be mounted across insulating joints and outputfor pipeline bends. terminals of D.C. voltage sources. Such measures should take into account the need for potential equalisation between the Guidance note: pipeline, anodes, power supplies, reference electrodes, etc. Bends exposed to bending moments behave differently from during lightning strikes. Alternative devices to the spark gap straight pipes. Ovalisation becomes the first order of deformation type can be used if documented to be reliable. and changes the stress pattern considerably compared to straight pipes. 305 Bolting shall meet the requirements of Sec.6 C400. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 306 All elastomeric materials used shall have a documented performance. The sealing materials shall have documented202 As an alternative to recognised codes the following sim- decompression, creep and temperature properties. O-ring sealsplified Allowable Stress Design (ASD) check may be used shall be resistant to explosive decompression and AED certified.provided that: AED certification is not required for seals other than O-rings, provided they are enclosed in a completely confined space.— The pressure containment criterion in D200 is fulfilled.— The applied moment and axial load can be considered dis- Sealing surfaces exposed to sea water shall be made of materi- placement controlled. als resistant to sea water at ambient temperature.— The bend is exposed to internal over pressure or that the 307 The insulating materials, including dielectric strength, bend has no potential for collapse. This can be considered compressive strength and suitability for use at the design tem- fulfilled if the system collapse design capacity is three peratures shall be documented by testing in accordance with times the external overpressure in question. The external ASTM D 695. pressure differential for the collapse limit state, pe - pmin, shall hence be multiplied by a factor of 3 in Eq 5.14. F 400 Design of pig traps— That the imposed shape distortion (e.g. ovalisation) is 401 The design of closures and items such as nozzle rein- acceptable. forcements, saddle supports, vent- kick and drain branches shall comply with the applied design standard.The ASD criteria read: 402 Closures shall be designed such that the closure cannot be opened while the pig trap is pressurised. An interlockσe ≤ η · fy (5.36) arrangement with the main pipeline valve should be provided.σl ≤ η · fy (5.37) F 500 Design of valves.where 501 The design shall ensure that internal gaskets are able to seal, and shall include a documented safety margin which isσ e ≤ σ h 2 + σ l 2 − σ h ⋅ σ l + 3 ⋅τ hl 2 (5.38) valid during all relevant pipeline operating conditions. Sealing will be sensitive to internal deflections, enlargement of gaps D − t2 and changes in their support conditions. Valve operation willσ h = ( pi − p e ) (5.39) be sensitive to friction and clearances. 2 ⋅ t2 502 Consideration should be given to requirements for dura- bility when exposed to abrasive material (e.g. weld scale, sand N M etc.) or to fire loads.σl = + π ⋅ (D − t2 ) ⋅ t2 π ⋅ (D − (D − 2 ⋅ t2 ) 4 ) 4 (5.40) 503 Valves with requirements for fire durability shall be 32 ⋅ D qualified by applicable fire tests. Reference may be made to DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.5 – Page 55API 6FA and ISO 10497 for test procedures. void for internal pipes. Release of effective axial force by end504 Valve control systems and actuators shall be designed expansions, lateral and/or vertical deformations or bucklingand manufactured in accordance with recognised standards. depends on how the pipes may slide relatively to each other.The valve actuator specification should define torque require- Therefore, analysis of cases where the effective axial force isments for valve operation, with a suitable safety margin to important, such as analysis of expansion, buckling and dynam-accommodate deterioration and friction increase during serv- ics, requires accurate modelling of axial restraints such asice. spacers, bulkheads etc.505 If the code or standard used for design of a component G 300 Riser supportsdoes not take into account the possibility for internal leakage 301 The riser supports should be designed against the possi-due to forces transferred to the component from the connecting ble forms of failure with at least the same degree of safety aspipeline sections, the additional calculations or qualification that of the riser they support. However, if safety considerationstests shall be performed. indicate that the overall safety is increased by a reduction ofF 600 Pipeline fittings the failure load of certain supports, such considerations may govern the support design (weak link principle).601 Tees shall be of the extruded outlet, integral reinforce-ment type. The design shall be according to ASME B31.4, 302 For bolted connections, consideration shall be given toB31.8 or equivalent. friction factors, plate or shell element stresses, relaxation, pipe crushing, stress corrosion cracking, galvanic corrosion,602 Bars of barred tees should not be welded directly to the fatigue, brittle failure, and other factors that may be relevant.high stress areas around the extrusion neck. It is recommendedthat the bars transverse to the flow direction are welded to a 303 For supports with doubler and/or gusset plates consider-pup piece, and that the bars parallel to the flow direction are ation shall be given to lamellar tearing, pull out, elementwelded to the transverse bars only. If this is impracticable, stresses, effective weld length, stress concentrations andalternative designs should be considered in order to avoid peak excessive rotation. See also B108 through B111.stresses at the ends. 304 In clamps utilising elastomeric linings, the long-term603 Y-pieces and tees where the axis of the outlet is not per- performance of the material with regard to creep, sea water andpendicular to the axis of the run (lateral tees) shall not be air or sun light resistance shall be determined.designed to ASME B31.4 or B31.8, as these items require spe-cial consideration, i.e. design by finite element analysis. G 400 J-tubes604 The design of hot taps shall ensure that the use of and the 401 An overall conceptual evaluation shall be made in orderdesign of the component will result in compliance with API RP to define the required:2201, "Procedure for Welding and Hot Tapping on Equipment — safety classin Service". — impact design605 Standard butt welding fittings complying with ANSI — pressure containment resistance.B16.9, MSS SP-75 or equivalent standards may be used pro-vided that: 402 The J-tube shall be designed against the failure modes given in D100.— the actual bursting strength of the fitting is demonstrated Guidance note: to exceed that of the adjoining pipe— the fitting is demonstrated to be able to accommodate the 301 above includes evaluation of whether the j-tube shall be designed for the full design pressure and to which safety class maximum forces that can occur in the pipeline in accord- (i.e. hoop stress usage factors). The J-tube concept may e.g. be ance with A105. based on "burst disc" which will imply that a lower pressure con- tainment resistance shall be governing. Other relevant evalua-606 Branch welding fittings with a size exceeding 2 inches tions may be J-tube pull-in forces, external impact, corrosion etc.or 20% of the pipe circumference shall not be used. Socketwelding fittings are not permitted. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 403 The J-tube spools should be joined by welding. G 500 Stability of gravel supports and gravel covers G. Supporting Structure 501 This applies to all types of gravel supports and covers,G 100 General such as free span supports for installation and operating phases101 Structural items such as support and protective struc- (excessive bending and fatigue), separation and pipeline stabi-tures that are not welded onto pressurized parts are considered lisation at crossings, suppressing of upheaval buckling, axialas structural elements. restraints/locking, stabilisation of pipeline etc.102 Steel structural elements shall be designed according to 502 The design of the gravel supports and covers shall con-DNV-OS-C101 Design of Offshore Steel Structures, General sider the consequence of failure.(LRFD method). 503 The design of the gravel supports and covers shall be performed using recognised methods.G 200 Pipe-in-pipe and bundles 504 The design of the gravel supports and covers shall consider:201 For pipe-in-pipe and bundle configurations, advantagemay be taken of other loading conditions, e.g. pressure con- — weight of gravel supports and/or covers and pipelinetainment for the outer pipe. When determining the safety class, — loads imposed by pipeline (e.g. due expansion)advantage may also be taken on the reduced failure conse- — seabed slope, both longitudinal and horizontalquences compared to those of ordinary pipelines. — uncertainty in soil characteristics202 The combined effective force for a pipe-in-pipe or a — resistance against hydrodynamic loadsbundle may be calculated using the expression in Sec.4 G300 — slope failure (e.g. due to earthquakes)for each component and summing over all components. The — uncertainty in survey dataexternal pressure for each component shall be taken as the — subsea gravel installation tolerances, both horizontal andpressure acting on its external surface, i.e. the pressure in the vertical. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 56 – Sec.5 see note on front cover H. Installation and Repair H 200 Pipe straightness 201 The primary requirement regarding permanent deforma-H 100 General tion during construction, installation and repair is the resulting101 The linepipe transportation should comply with the straightness of the pipeline. This shall be determined and eval-requirements of API5L and API5LW. uated with due considerations of effects on:102 The pipeline strength and stability shall be determined — instabilityaccording to D and E above. — positioning of pipeline components e.g. valves and Tee- Guidance note: joints According to this standard, equivalent limit states are used for all — operation. phases. Hence the design criteria in this section also apply to the installation phase. Installation is usually classified as a lower 202 The possibility of instability due to out of straightness safety class (safety class low) than operation, corresponding to during installation (twisting) and the corresponding conse- lower partial safety factors (higher failure probability). quence shall be determined. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 203 If Tee-joints and other equipment are to be installed as an integrated part of the pipeline assembled at the lay barge, no103 The design analysis for the submarine pipeline system rotation of the pipe due to plastification effects shall be permit-shall include both installation and repair activities, in order to ted. In this case the residual strain from bending at the over-ensure that they can be installed and repaired without suffering bend shall satisfy the following during installation:damage or requiring hazardous installation or repair work.104 The design shall verify adequate strength during all rel-evant installation phases and techniques to be used, including: γ rot ε r ≤ ε r ,rot (5.41)— initiation of pipe laying operation where— normal continuous pipe laying— pipe lay abandonment and pipeline retrieval εr = residual strain from over bend— termination of laying operation γrot = 1.3 safety factor for residual strain— tow out operations (bottom tow, off-bottom tow, control- εr,rot = limit residual strain from over bend. led depth tow and surface tow)— pipeline reeling and unreeling 204 The above equations only consider rotation due to resid-— trenching and back filling ual strain from installation along a straight path. Other effects— riser and spool installation can also give rotation (curved lay route, eccentric weight,— tie-in operations hydrodynamic loads, reduced rotational resistance during pulls— landfalls. due to lateral play/elasticity in tensioners/pads/tracks etc.) and need to be considered.105 The configuration of pipeline sections under installation 205 Instability during operation, due to out of straightnessshall be determined from the laying vessel to the final position caused by the installation method and the corresponding con-on the seabed. The configuration shall be such that the stress/ sequences, shall be determined. Residual stresses affectingstrain levels are acceptable when all relevant effects are taken present and future operations and modifications shall also beinto account. Discontinuities due to weight coating, buckle considered.arrestors, in-line assemblies etc. shall be considered. 206 The requirement for straightness applies to the assumed106 The variation in laying parameters that affect the config- most unfavourable functional and environmental load condi-uration shall be considered. An allowed range of parameter tions during installation and repair. This requirement alsovariation shall be established for the installation operation. applies to sections of a pipeline where the strains are com-107 Critical laying parameters shall be determined for the pletely controlled by the curvature of a rigid ramp (e.g. stingerinstallation limit condition, see Sec.4 C600 and Sec.10 D400. on installation vessel), whether or not environmental loads are acting on the pipe.108 Configuration considerations for risers and pipelinesshall also be made for other installation and repair activities, Guidance note:and the allowed parameter variations and operating limit con- Rotation of the pipe within the tensioner clamps of the pipe dueditions shall be established. to elasticity of the rubber and slack shall be included in the eval- uation of the rotation.109 If the installation and repair analyses for a proposedpipeline system show that the required parameters cannot be ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---obtained with the equipment to be used, the pipeline systemshall be modified accordingly. H 300 Coating110 The flattening due to a permanent bending curvature, 301 Concrete crushing due to excessive compressive forcestogether with the out-of-roundness tolerances from fabrication for static conditions in the concrete during bending at the over-of the pipe shall meet the requirements defined in D900. bend is not acceptable. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.6 – Page 57 SECTION 6 DESIGN - MATERIALS ENGINEERING A. General B. Materials Selection for Linepipe and Pipeline ComponentsA 100 Objective B 100 General101 This section provides requirements and guidelines to theselection of materials for submarine pipeline systems and to 101 Materials for pipeline systems shall be selected with duethe external and internal corrosion control of such systems. consideration of the fluid to be transported, loads, temperatureAlso covered is the specification of linepipe, pipeline compo- and possible failure modes during installation and operation.nents, coatings and cathodic protection. Finally, general con- The selection of materials shall ensure compatibility of allsiderations for fabrication applicable to the design phase are components of the pipeline system. The following materialaddressed. characteristics shall be considered:102 The purpose of performing materials selection is to — mechanical propertiesassess the feasibility of different candidate materials (includ- — hardnessing CRA’s) to meet functional requirements for linepipe and — fracture toughnessfor other components of a pipeline system. It may also include — fatigue resistancea cost comparison between candidate materials, including the — weldabilitycalculated costs for operation and any associated risk cost (see — corrosion resistance.D701). This activity is generally carried out during conceptualdesign of submarine pipeline systems. 102 Materials selection shall include identification of the fol- lowing supplementary requirements for linepipe given inA 200 Application Sec.7 I as required:201 This section is applicable to the conceptual and design — supplementary requirement S, sour service (see B200)phases for submarine pipeline systems. It contains both norma- — supplementary requirement F, fracture arrest propertiestive requirements and information. (Sub-sections containing (see B406)only informative text are indicated ‘Informative’ in heading) — supplementary requirement P, linepipe exposed to plastic deformation exceeding the thresholds specified in Sec.5202 Functional requirements for materials and manufactur- D1102 (see B407-408)ing procedures for linepipe and pipeline components are con- — supplementary requirement D, more stringent dimensionaltained in Sec.7 and 8, respectively. Manufacture and requirements (see B402)installation of systems for external corrosion control is — supplementary requirement U, increased utilisation (seeaddressed in Sec. 9. Sec. 9 also contains functional require- B409).ments to any concrete coating. 103 The mechanical properties, chemical composition,A 300 Documentation weldability and corrosion resistance of materials used in com-301 The selection of materials during conceptual and/or ponents shall be compatible with the part of the pipeline sys- tem where they are located. Low internal temperatures due todetailed design shall be documented, preferably in a “Materials system depressurisation shall be considered during the mate-Selection Report”, referring to the requirements and recom- rial selection.mendations in this section, including use of CRAs, corrosionallowance and provisions for internal corrosion control. In the B 200 Sour servicematerial selection document design premises for materialsselection should be identified, making reference to the design 201 Pipelines to route fluids containing hydrogen sulphidebasis and any other relevant project documents, together with (H2S) shall be evaluated for ‘sour service’ according tothe applicable codes and standards. ISO 15156. For all pipeline components exposed to such inter- nal fluids, materials shall be selected for compliance with this302 Any requirements and conditions on pipeline fabrication standard. For materials specified for sour service inand operational procedures used as the basis for materials ISO 15156, specific hardness requirements always apply.selection shall be duly high-lighted in the document to ensure These are applicable both to manufactured materials as-deliv-that they are adequately transferred into these phases of the ered after manufacture and after fabrication (e.g. welding). Forpipeline. certain materials, restrictions for manufacture (e.g. heat treat- ment) and fabrication (e.g. cold forming) apply). Guidance note: Guidance note: The internal corrosion control of pipelines carrying potentially corrosive fluids based on chemical treatment is much based on ISO 15156-2/3 giving requirements for materials selection were conditions for periodic cleaning, corrosion monitoring and first published in 2004. As per 2006, 4 (four) corrigenda had been published with requirements and guidelines overruling the pub- inspection of the integrity of the pipeline which are not always lished standard and previous corrigenda. The user of this stand- defined in the project design basis and need to be verified by the ard shall ensure that the applicable corrigenda are used. operator of the pipeline. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 202 Any materials to be used which are not covered by303 As a result of design activities, specifications of linepipe ISO 15156 (e.g. type 13Cr steels), shall be qualified accordingmaterial, pipeline components (including bolts and nuts), pipe- to the said standard. The same applies if a material specifiedline coatings (including field joint coating and any concrete for sour service is to be used beyond the conditions specifiedcoating), anode manufacture and installation shall further be (e.g. max. hardness). In accordance with ISO 15156-2/3, theprepared as separate documents. Moreover, the design docu- pipeline owner shall verify and retain the qualification recordsmentation shall include a cathodic protection design report. in case the testing was initiated by a contractor or supplier. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 58 – Sec.6 see note on front cover Guidance note: specified in Subsection I. Additional information, relevant for Purchaser may consider to specify SSC testing of material grades the selection and specification of linepipe is provided below. meeting all requirements for sour service in this standard, as a part of a program for pre-qualification of linepipe manufacturing Dimensional tolerances or pipeline installation procedures. For such testing, the methods 402 When significant plastic straining is required during and acceptance criteria in ISO 15156-2/3 apply. installation or operation Supplementary requirement D is nor- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- mally specified. The most prominent benefit of specifying Supplementary requirement D is the eased fit-up for welding.203 The qualification and selection of materials according to Improved fit-up implies reduced stress concentrations andISO 15156 are applicable to equipment designed and con- improved structural integrity. The tolerances specified instructed using conventional elastic design criteria. When other Sec.7 I400 are considered to be in the uppermost range of whatdesign criteria are applied qualification testing shall be consid- may be achieved by reputable pipe mills. Stricter tolerancesered, unless relevant documentation is provided. and additional requirements such as e.g. pipe eccentricity may204 Supplementary requirements to sour service in this be specified for further improvements, but may be costly asstandard are given in Sec.7 I100 and Sec.8 C500. machining may be required. Corrosion testing of the CRA material of clad or lined linepipeB 300 Corrosion resistant alloys (informative) 403 For alloy 625 clad or lined pipe specified to be seawater301 Type 13Cr martensitic stainless steels (i.e. proprietary resistant, testing according to ASTM G48, Method C, shouldalloys developed for oil/gas pipelines) are generally consid- be considered, with acceptance criteria as for 25Cr duplex, seeered fully resistant to CO2-corrosion, provided welds have Sec.7 C409.adequate PWHT. 22Cr and 25Cr duplex stainless steel andaustenitic CRA’s are also fully resistant and do not require Gripping force of lined linepipePWHT. Duplex and martensitic stainless steels may be less tol- 404 In accordance with Sec.7 D510 the gripping force shallerant than C-Mn steel to well stimulation acids. Corrosion determined with due consideration of the project requirements,inhibitors for such acids and developed for the latter materials especially the level of installation and operational bendingmay not be effective for CRA’s. stresses. If no particular requirements are identified the302 Under conditions when water, oxygen and chloride can requirement should be based on the gripping force obtainedbe present in the fluid, e.g. water injection, stainless steels can during MPQT.be susceptible to localised corrosion. Hence the corrosion Influence of coating application on mechanical propertiesresistance shall be considered for each specific application. Forspecial applications, corrosion testing should be considered to 405 Pipe tensile properties may be affected by high temper-qualify the material for the intended use. ature during coating application. During pipe coating, includ- ing field coating, the pipes might be exposed to temperaturesAlloy 625 (UNS N06625) is generally considered immune to up to approximately 250°C. For TMCP processed pipes andambient temperature seawater. Also type 25Cr duplex (e.g. cold formed pipes not subjected to further heat treatmentUNS S32750/S32760) are generally resistant to ambient tem- mechanical properties may change due to strain aging, causingperature seawater but require more stringent control of micro- e.g. increased yield stress. This may further affect the criticalstructure in base material and weld, consequently corrosion defect size considerably if the pipe is strained above the yieldtesting are often included for the qualification of manufactur- stress.ing and fabrication procedures of these materials. Type 22Crduplex, AISI 316 and Alloy 825 (UNS N08825) are not resist- Fracture arrest propertiesant to corrosion by raw seawater but are applicable for compo- 406 Supplementary requirements to fracture arrest proper-nents exposed to treated seawater (deoxygenated to max. ties are given in Sec.7 I200 and are valid for gas pipelines car-10 ppb and max. 100 ppb as max monthly and daily residual rying essentially pure methane up to 80% usage factor, up to aconcentrations of oxygen). For the latter materials, corrosion pressure of 15 MPa, 30 mm wall thickness and 1120 mm diam-testing is not normally included in specifications for manufac- eter.ture and fabrication. For conditions outside the above limitations the required frac-303 Duplex and martensitic stainless steel linepipe and pipe- ture arrest properties should be based on calculations whichline components require special considerations of the suscepti- reflect the actual conditions or on full-scale tests. The fracturebility of environmentally assisted cracking, primarily (HISC), toughness required to arrest fracture propagation for rich gas,see E502, Guidance note. In particular this applies to material i.e. gas mixtures that enter the two-phase state during decom-subjected to plastic straining during installation and/or opera- pression can be much higher than for essentially pure methane.tion with cathodic protection applied. PWHT is known toreduce the HISC susceptibility of welds for 13Cr martensitic Calculations should be carried out by use of the Battelle Twostainless steel. For duplex stainless steel, HISC design recom- Curve Method (TCM) and the appropriate correction factor formendations are given in DNV-RP-F112. calculated required Charpy values ≥ 95 J. It is strongly recom- mended that the Battelle TCM is calibrated by use of data from304 In addition to resistance to internal corrosion and envi- full-scale test which are as close as possible to the actual pipe-ronmentally assisted cracking, the following major parameters line conditions with regard to gas pressure, pipeline dimen-shall be considered: sions and gas composition. Although the Battelle TCM is based on physical models of the speed of crack propagation— mechanical properties and the speed of decompression, it includes constants that are— ease of fabrication, particularly weldability. based on fitting data and calculations within a limited range of Guidance note: test conditions. Procurement conditions such as availability, lead times and costs Reeling of longitudinally welded pipes and clad pipes should also be considered. 407 Due to the limited field experience, special considera- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- tions should be made for longitudinally welded pipes to ensure that both the longitudinal weld, heat affected zone and baseB 400 Linepipe (informative) material of such pipes are fit for intended use after significant401 Acceptance criteria and inspection requirements for straining.linepipe are given in Sec.7, with supplementary requirements 408 It is recommended that the weld metal strength of the DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.6 – Page 59pipe longitudinal weld overmatches the strength of the base cable as subsea bolting material without cathodic protectionmaterial. It is further recommended to have a limited cap rein- but should only be used in the solution annealed or annealedforcement of the longitudinal weld in order to avoid strain con- condition (ASTM B446) or cold-worked to SMYS 550 MPacentrations. maximum, unless exposure to cathodic protection can beSupplementary requirement U - Qualification in retrospect excluded. Restrictions for sour service according to ISO 15156 shall apply when applicable.409 The Purchaser may in retrospect upgrade a pipe deliveryto be in accordance with Supplementary requirement U. In 604 To restrict damage by HISC for low alloy and carboncase of more than 50 test units it must be demonstrated that the steels, the hardness for any bolts and nuts to receive cathodicactual average yield stress is at least two (2.0) standard devia- protection shall not exceed 350 HV, as specified for the stand-tions above SMYS. If the number of test units are between 10 ard grades in Table 6.1. The same restriction shall apply forand 20 the actual average yield stress shall as a minimum be solution annealed or cold-worked type AISI 316 austenitic2.3 standard deviations above SMYS, and 2.1 if the number of stainless steel and any other cold-worked austenitic alloys.test units are between 21 and 49. Precipitation hardening Fe-or Ni-base alloys, duplex and mar- tensitic stainless steels should not be specified as bolting mate-B 500 Pipeline components (informative) rial if subject to cathodic protection. The hardness of bolts and nuts shall be verified for each lot (i.e. bolts of the same size and501 Materials for components shall be selected to comply material, from each heat of steel and heat treatment batch).with internationally recognised standards meeting the require-ments given in Sec.7 and Sec.8. Modification of the chemical 605 Any coating of bolts shall be selected with due consider-composition given in such standards may be necessary to ations of how such coatings affect tensioning and as-installedobtain a sufficient combination of weldability, hardenability, properties.strength, ductility, toughness and corrosion resistance. Guidance note:502 A component should be forged rather than cast when- Zinc coating, phosphating and epoxy based coatings are applica-ever a favourable grain flow pattern, a maximum degree of ble; however, there have been concerns that hot-dip zinc coating may cause loss of bolt tensioning and that polymeric coatingshomogeneity, and the absence of internal flaws are of impor- may prevent efficient cathodic protection. PTFE coatings havetance. low friction coefficient and the torque has to be applied accord-503 For component material delivered in the quenched and ingly.tempered condition, the tempering temperature shall be suffi- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---ciently high to allow effective post weld heat treatment duringlater manufacture / installation. The minimum tempering tem- B 700 Welding consumables (informative)perature should, if lower than 610°C, be specified by the pur-chaser. 701 Requirements to welding, except for pipe mill manufac- turing welds, are covered in Appendix C. Requirements thatIf welds between the component and other items such as line- are specific for pipeline installation welding are given inpipe are to be post weld heat treated at a later stage, or if any Sec.10. Below is provided guidance regarding the influence ofother heat treatment is intended, a simulated heat treatment of weld metal strength on allowable defect size as determined bythe test piece should, if required, be specified by the purchaser. ECA (if applicable).504 If the chemical composition and the delivery condition 702 The requirement for welds to have strength level equalof components require qualification of a specific welding pro- to or higher than (overmatching properties) the base material iscedure for welding of the joint between the component and the to minimise deformation in the area adjacent to any possibleconnecting linepipe, then the component should be fitted with defects.pup pieces of the linepipe material in order to avoid field weld-ing of these components. 703 For pipes exposed to global yielding, i.e. when girth welds are exposed to strain εl,nom ≥ 0.4%, it is required to per-Alternatively, rings of the component material should be pro- form an ECA according to Appendix A. The ECA generallyvided for welding procedure qualification of the field weld. requires that the weld metal yield stress is matching or over-505 Particular consideration shall be given to the suitability matching the longitudinal yield stress of the pipe. Due to theof elastomers and polymers for use in the specific application scatter in the pipe material yield stress, it is normally requiredand service conditions. that the yield stress of the weld metal is 120-150 MPa higher than SMYS of the base material (depending on the SMYS). AnB 600 Bolts and nuts ECA involving undermatching weld metal will require special601 Carbon and low alloy steel bolts and nuts for pressure considerations, see Appendix A.containing and main structural applications shall be selected in Temperature effectsaccordance with Table 6-1. 704 It must be noted that the reduction in yield stress at ele- vated temperature may be higher for the weld metal than theTable 6-1 Carbon and low alloy steel bolts and nuts for pressure base material. Hence, undermatching may be experienced forbearing or main structural applications high operation temperatures (e.g. snaking scenario). This isTemperature Bolt Nut Size range particularly relevant when welding clad or lined linepipe.range (oC) Whenever such situations occur, it will be required to perform-100 to + 400 ASTM A320, ASTM A194, < 65 mm transverse all weld tensile testing of the weld metal and frac- Grade L7 / L7M Grade 4/S¤ ture toughness testing at the relevant temperature.-46 to + 400 ASTM A193, ASTM A194, All Grade B7/B7M Grade 2H-100 to + 400 ASTM A320, ASTM A194, < 100 mm Grade L43 Grade 7 C. Materials Specification602 When bolts and nuts shall be used at elevated tempera- C 100 Generalture strength de-rating shall be applied, see Sec.5 C300. 101 Requirements to the manufacture of linepipe and pipe-603 Stainless steel according to ASTM A193 grade B8M line components are covered in Sec.7 and Sec.8, respectively.(type AISI 316) is applicable but requires efficient cathodic This includes requirements to all relevant manufacturing stepsprotection for subsea use. UNS N06625 (Alloy 625) is appli- from steel making to dispatch from the pipe mill or component DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 60 – Sec.6 see note on front covermanufacturing facility, but excluding any permanent external/ conforming to supplementary requirement Sinternal coating. — if supplementary requirement P apply, the relevant strain- ing for the installation process, possible corrective actionsC 200 Linepipe specification (e.g. “reel on and reel off twice”) and post installation con-201 A specification reflecting the results of the materials ditions/operations introducing plastic deformation shall beselection according to this section and referring to Sec.7, shall specified.be prepared by the Purchaser. The specification shall state anyoptions, additional requirements to and/or deviations from this C 300 Components specificationstandard pertaining to materials, manufacture, fabrication and 301 A specification reflecting the results of the materialstesting of linepipe. selection according to this section and referring to Sec.8, shall202 The material specification may be a Material Data Sheet be prepared by the Purchaser. The specification shall state anyreferring to this standard. options, additional requirements to and/or deviations from this standard pertaining to materials, manufacture, fabrication and203 The materials specification shall as a minimum include testing of the components.the following (as applicable): 302 The materials specification shall as a minimum include— quantity (e.g., total mass or total length of pipe) the following (as applicable):— manufacturing process (see Sec.7 A300)— type of pipe (see Sec.7 A201) — quantity (i.e the total number of components of each type— SMYS and size)— outside or inside diameter — design standard— wall thickness — required design life— whether data of the wall thickness variation (tmax and tmin) — material type, delivery condition, chemical composition or the standard deviation in wall thickness variation shall and mechanical properties at design temperature be supplied to facilitate girth welds AUT (see Appendix E, — nominal diameters, OD or ID, out of roundness and wall B107) thickness for adjoining pipes including required tolerances— length and type of length (random or approximate) — bend radius, see Sec.8 B413— application of supplementary requirements (S, F, P, D or — type of component, piggable or not piggable U), see B102-B103 — gauging requirements, see Sec.10 O408— delivery condition (see Sec.7, Table 7-1 and H201-H202) — minimum design temperature (local)— minimum design temperature — maximum design temperature (local)— range of sizing ratio for cold-expanded pipe — design pressure (local)— chemical composition for wall thickness > 25 mm (appli- — water depth cable to C-Mn steel pipe with delivery condition N or Q) — pipeline operating conditions including fluid characteris-— chemical composition for wall thickness > 35 mm (appli- tics cable to C-Mn steel pipe with delivery condition M) — details of field environmental conditions— if additional tensile testing in the longitudinal direction — external loads and moments that will be transferred to the with stress strain curves shall be performed component from the connecting pipeline under installation— if additional tensile testing of base material at other than and operation and any environmental loads room temperature is required, define; temperature (e.g. — functional requirements maximum design temperature), acceptance criteria and — material specification including, material type, delivery frequency of tests condition, chemical composition and mechanical proper-— CVN test temperature for wall thickness > 40 mm ties at design temperature— liner/cladding material (UNS number) — required testing— mechanical and corrosion properties of liner/cladding — required weld overlay, corrosion resistant or hardfacing material — if pup pieces of the linepipe material shall be fitted— “type” of seal weld for lined linepipe — coating/painting requirements.— thickness of carrier pipe and liner/cladding material— any project specific requirements to gripping force of lined C 400 Specification of bolts and nuts linepipe 401 Bolts and nuts shall be supplied with certificates to EN— if the ultrasonically lamination checked zone at the pipe 10204 Type 3.1. ends shall be wider than 50 mm— if diameter at pipe ends shall be measured as ID or OD 402 Bolts and nuts for pressure containing and main struc-— if pipes shall be supplied with other than square cut ends tural applications should be specified to have rolled threads. (see Sec.7 B336) 403 Any coating of bolts shall be specified in the purchase— if criteria for reduced hydrostatic test pressure, as given in document for bolting. In order to prevent hydrogen embrittle- Sec.7 E105, is fulfilled, and if it may be applied ment of acid cleaned and/or electrolytically plated bolts and— if the outside weld bead shall be ground flush at least 250 nuts, baking at 200°C for a minimum of 2 hours shall be spec- mm from each pipe end to facilitate girth welds AUT (see ified. Sec.7 B338)— if inside machining of pipe ends is applicable, and the dis- C 500 Coating specification tance from pipe end to tapered portion (see Sec.7 B339, and Appendix E, B108) 501 As a part of detailed design, project specific require-— if pipes shall be supplied with bevel protectors, and in case ments to as-applied coating properties and to quality control of of what type (see Sec.7 H300) the manufacture of coating materials and of coating applica-— if weldability testing is required tion (including risers, see D600) shall be defined in a purchase— if qualification testing shall be conducted after the pipe specification for the applicable coating. DNV-RP-F102 and material has been heated to the expected coating tempera- DNV-RP-F106 give detailed requirements and recommenda- ture when fusion bonded epoxy is used (see B406-B407) tions to manufacture of field joint and linepipe coatings,— application of the alternative weld cap hardness of C-Mn respectively with emphasis of quality control of the application steel pipe according to supplementary requirement S (see procedure. Sec.7 I107) 502 The specification of linepipe coating, field joint coating— if SSC testing shall be performed during MPQT for pipes and any weight coating shall include requirements to the qual- DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.6 – Page 61ification of coating materials, coating application and repair ever, the extra wall thickness will then only delay leakage in pro-procedures, dimensions of the linepipe cut-back (including tol- portion to the increase in wall thickness.erances) and to documentation of inspection and testing. More ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---detailed requirements to the specification of pipeline coatingare contained in Sec. 9. 202 The needs for, and benefits of, corrosion allowance shall Guidance note: be evaluated, taking into account the following factors as a minimum: Cut-backs shall be defined to accommodate any AUT equipment ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — design life and potential corrosivity of fluid and/or exter- nal environment503 For pipeline components in CRA materials to receive — expected form of corrosion damage (see Guidance noteCP, detailed coating specifications shall be prepared with a pri- above)mary objective to prevent HISC. — expected reliability of planned techniques and procedures for corrosion mitigation (e.g. chemical treatment of fluid,C 600 Galvanic anodes specification external coating, etc.) — expected sensitivity and damage sizing capability of rele-601 As a part of design, specifications for manufacture and vant tools for integrity monitoring, time to first inspectioninstallation of galvanic anodes shall be prepared. These docu- and planned frequency of inspectionments shall define requirements to materials, properties of — consequences of sudden leakage, requirements to safetyanodes (as manufactured and as-installed, respectively) and and reliabilityassociated quality control. Detailed requirements are given in — any extra wall thickness applied during design for installa-Sec.9. tion forces and not needed for control of internal and exter- nal pressure — any potential for down-rating (or up-rating) of operating pressure. D. Corrosion Control 203 An internal corrosion allowance of minimum 3 mm isD 100 General recommended for C-Mn steel pipelines of safety class Medium and High carrying hydrocarbon fluids likely to contain liquid101 All components of a pipeline system shall have adequate water during normal operation. For nominally dry gas and forcorrosion control to avoid failures caused or initiated by corro- other fluids considered as non-corrosive, no corrosion allow-sion, both externally and internally. ance is required. Guidance note: 204 An external corrosion allowance of minimum 3 mm is Any corrosion damage may take the form of a more or less uni- recommended for C-Mn steel risers of safety class Medium form reduction of pipe wall thickness, but scattered pitting and and High in the splash zone. An external corrosion allowance grooving corrosion oriented longitudinally or transversally to the shall further be considered for any landfalls. For risers carrying pipe axis is more typical. Stress corrosion cracking is another hot fluids (> 10oC above normal ambient seawater tempera- form of damage. Uniform corrosion and corrosion grooving may ture), a higher corrosion allowance should be considered, at interact with internal pressure or external operational loads, caus- ing rupture by plastic collapse or brittle fracture. Discrete pitting least for the splash zone (see 602). Any allowance for internal attacks are more likely to cause a pinhole leakage once the full corrosion shall be additional. pipe wall has been penetrated D 300 Temporary corrosion protection ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 301 The need for temporary corrosion protection of external and internal surfaces during storage and transportation shall be102 Pipeline systems may be exposed to a corrosive environ- considered during design/engineering for later inclusion inment both internally and externally. Options for corrosion mit- fabrication and installation specifications. Optional techniquesigation include use of corrosion protective coatings and include end caps or bevel protectors, temporary thin film coat-linings, cathodic protection (externally only), and chemical ing and rust protective oil/wax.treatment or processing (internally only). Guidance note:D 200 Corrosion allowance Outdoor storage of unprotected pipes for a period of up to about a year will not normally cause any significant loss of wall thick-201 For submarine pipeline systems a corrosion allowance ness. However, surface rusting may cause increased surfacemay serve to compensate for internal and/or external corrosion roughness affecting pipeline coating operations. Conditions forand is mostly applied for control of internal or external pres- storage should be such that water will not accumulate internally,sure. For C-Mn steel components, a corrosion allowance may or externally at any supports. End caps may retain water inter-be applied either alone or in addition to some system for cor- nally if damaged or lost at one end, allowing entry of rain waterrosion mitigation. or condensation. Use of temporary coatings may interfere with later external/internal coating. Guidance note: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- A requirement for wall thickness determined by installation forces and exceeding that needed for pressure containment at the 302 The needs for corrosion protection during flooding shall initial design pressure, or wall thickness not needed for pressure be assessed for inclusion in installation specifications. Special containment due to a later down rating of operational pressure precautions are required to avoid corrosion damage to CRA can be utilised for corrosion control but is not referred to in this document as a “corrosion allowance” pipelines during system pressure testing using seawater. Type 13Cr linepipe may suffer superficial corrosion attack during A corrosion allowance is primarily used to compensate for forms outdoor storage. of corrosion attack affecting the pipelines pressure containment resistance, i.e. uniform attack and, to a lesser extent, corrosion Guidance note: damage as grooves or patches. Still, a corrosion allowance may The use of a biocide for treatment of water for flooding is most also enhance the operational reliability and increase the useful essential (even with short duration) as incipient bacterial growth life if corrosion damage occurs as isolated pits; although such established during flooding may proceed during operation and damage is unlikely to affect the pipelines resistance, it will cause cause corrosion damage (pipelines for dry gas are excluded). For a pinhole leak when the full wall thickness is penetrated. How- uncoated C-Mn steel pipelines, an oxygen scavenger may be DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 62 – Sec.6 see note on front cover omitted since oxygen dissolved in seawater will become rapidly addition, sufficient time for application and cooling or curing consumed by uniform corrosion without causing significant loss is crucial during barge laying of pipelines. of wall thickness. Film forming or "passivating" corrosion inhib- itors are not actually required and may even be harmful. Type 407 For pipes with a weight coating or thermally insulated 13Cr steel is highly susceptible to damage by raw seawater or coating, the field joint coating (FJC) is typically made up of an marginally treated seawater even at a short exposure period. Use inner corrosion protective coating and an in-fill. The objective of fresh water should be considered or seawater treated to a pH of the in-fill is to provide a smooth transition to the pipeline of 9 minimum. coating and mechanical protection to the inner coating. For ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- thermally insulated pipelines and risers, requirements for ade- quate insulating properties may also apply. The requirementsD 400 External pipeline coatings (informative) and guidelines to FJC are also applicable to any field repairs of factory coating401 “Linepipe coating” (also referred to as “factory coatingor “parent coating”) refers to factory applied external coating 408 The design and quality control of field joint coatings issystems (mostly multiple-layer, with a total thickness of some essential to the integrity of pipelines in HISC susceptible mate-millimetres) with a corrosion protection function, either alone rials, including ferritic-austenitic (duplex) and martensiticor in combination with a thermal insulation function. Some stainless steel. Compliance with DNV-RP-F102 is recom-coating systems may further include an outer layer for mechan- mended.ical protection, primarily during laying and any rock dumpingor trenching operations. Concrete coating for anti-buoyancy D 500 Cathodic Protection(weight coating, see Sec.9 C) is, however, not covered by the 501 Pipelines and risers in the submerged zone shall be fur-term linepipe coating. nished with a cathodic protection (CP) system to provide ade-402 “Field joint coating” (FJC) refers to single or multiple quate corrosion protection for any defects occurring duringlayers of coating applied to protect girth welds and the associ- coating application (including field joints), and also for subse-ated cut-back of the linepipe coating, irrespective of whether quent damage to the coating during installation and operation.such coating is actually applied in the field or in a factory (e.g. The design of submarine pipeline CP systems shall meet thepipelines for reel laying and prefabricated risers). “Coating minimum requirements in ISO15589-2. DNV-RP-F103 isfield repairs” refers to repairs of factory coating performed in based on this standard, giving amendments and guidelines.the field (typically by the FJC contractor). Guidance note:403 The linepipe (external) coating system should be CP may be achieved using either galvanic ("sacrificial") anodes,selected based on consideration of the following major items: or impressed current from a rectifier. Galvanic anodes are nor- mally preferred.a) general corrosion-protective properties dictated by perme- ability for water, dissolved gases and salts, adhesion, free- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- dom from pores, etc. 502 The CP systems should be capable of suppressing theb) resistance to physical, chemical and biological degrada- pipe-to-seawater (or pipe-to-sediment) electrochemical poten- tion leading to e.g. cracking or disbondment, primarily in tial into the range -0.80 to -1.15 V rel. Ag/AgCl/ seawater. A service but also during storage prior to installation (tem- less negative potential may be specified for pipelines in CRA perature range and design life are decisive parameters) materials.c) requirements for mechanical properties, primarily those Guidance note: related to adhesion and flexibility, during installation (min. temperature) and operation (max. temperature) Potentials more negative than -1.15 V rel. Ag/AgCl/ seawater can be achieved using impressed current. Such potentials mayd) coating system’s compatibility with specific fabrication cause detrimental secondary effects, including coating disbond- and installation procedures, including field joint coating ment and HISC of linepipe materials and welds. Pipeline system and coating field repairs components in high-strength steel, and particularly in martensitic or ferritic-austenitic (‘duplex’) stainless steel, subject to highe) coating systems compatibility with concrete weight coat- local stresses during subsea installation activities (e.g. pre-com- ing (see Sec.9 C), if applicable missioning) or operation can suffer HISC by CP, also within the potential range given above. Such damage is primarily to bef) coating system’s compatibility with CP, and capability of avoided by restricting straining subsea by design measures. In reducing current demand for CP, if applicable addition, special emphasis should be laid on ensuring adequateg) linepipe material’s compatibility with CP considering sus- coating of components that may be subject to localised straining. ceptibility to HISC; see B303 It is essential that the coating systems to be applied (i.e. factory applied coating and field joint coating) for materials that areh) linepipe material’s susceptibility to corrosion in the actual known to be susceptible to HISC have adequate resistance to dis- environment, including stress corrosion cracking in the bonding by mechanical effects during installation as well as atmospheric zone and any onshore buried zone chemical/physical effects during operation. Overlay welding of critical areas with austenitic CRA filler materials may be consid-i) environmental compatibility and health hazards during ered when organic coatings are not applicable. Thermally coating application, fabrication/installation and operation. sprayed aluminium coating has also been applied for this pur- pose. Other measures to reduce or eliminate the risk of HISC404 For thermally insulating coatings, properties related to include control of galvanic anodes by diodes and use of specialflow assurance also apply; e.g. specific heat capacity, thermal anode alloys with less negative closed circuit potential. (Theseconductivity and the degradation of such properties by high techniques require that the pipeline is electrically insulated fromoperating external pressure and internal fluid temperature. conventional CP systems on electrically connected structures). In case conventional bracelet anodes are still to be used, welding of405 Pipeline components should have external coatings pref- anodes to any pressure containing components in these materialserably matching the properties of those to be used for linepipe. should be avoided.If this is not practical, CP design may compensate for inferior ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---properties. However, risks associated with HISC by CP shallbe duly considered (see B303 and 502 Guidance note). 503 Galvanic anode CP systems should be designed to pro-406 For the selection of FJC, the same considerations as for vide corrosion protection throughout the design life of the pro-pipeline and riser coatings as in 403 and 605-606 apply. In tected object. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.6 – Page 63 Guidance note: that do not need to be verified by special considerations and As retrofitting of galvanic anodes is generally costly (if practical testing. DNV-RP-F103 emphasizes the importance of coating at all), the likelihood of the initial pipeline design life being design and quality control of coating application when defin- extended should be duly considered. ing the CP current reducing effects of such coatings. It further ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- contains additional guidance to the CP design. For alternative design procedures, see 505 and 506 above.504 Pipeline systems connected to other offshore installa- 508 The detailed engineering documentation of galvanictions shall have compatible CP systems unless an electrically anode CP systems shall contain the following:insulating joint is to be installed. At any landfall of an offshorepipeline with galvanic anodes and impressed current CP of the — design premises, including design life and reference to rel-onshore section, the needs for an insulating joint shall be eval- evant project specifications, codes and standardsuated. — calculations of average and final current demands for indi- Guidance note: vidual sections of the pipeline Without insulating joints, some interaction with the CP system of — calculations of total anode net mass for the individual sec- electrically connected offshore structures cannot be avoided. As tions, to meet the mean current demand the design parameters for subsea pipelines are typically more — calculation of final current anode output to verify that the conservative than that of other structures, some current drain final current demand can be met for the individual sections from riser and from pipeline anodes adjacent to the pipeline can- of the pipeline (applies to a conventional bracelet anode not be avoided, sometimes leading to premature consumption. concept with max. 300 m anode spacing) When the structure has a correctly designed CP system such cur- — number of bracelet anodes for the individual pipeline sec- rent drain is not critical as the net current drain will decrease with tions, and resulting net anode mass to be installed on each time and ultimately cease; i.e. unless the second structure has insufficient CP. section — outline drawing(s) of bracelet anodes with fastening ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- devices and including tentative tolerances — calculations of pipeline metallic resistance to verify the505 Unless otherwise specified by or agreed with the owner, feasibility of CP by anodes on adjacent structure(s) or apipelines shall be designed with a self-sustaining CP system bracelet anode concept exceeding a spacing of 300 m inbased on bracelet anodes installed with a maximum distance of case any of these options apply (see DNV-RP-F103)300 m (in accordance with ISO 15589-2) and with electrical — documentation of CP capacity on adjacent installation(s)connections to the pipeline by pin brazing or aluminothermic to be utilized for CP of pipeline, if applicable.welding of cable connections to the pipe wall. (see Appendix CE500). Guidance note:For shorter pipelines (up to 30 km approximately), CP may be The above requirements for documentation of CP design is anachieved by anodes installed on structures at the end of the amendment to ISO 15589-2pipeline (e.g. platform sub-structure, subsea template or riser ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---base) electrically connected to the pipeline. This conceptrequires, however, that the design and quality control of fac- 509 For CP design of pipeline system components withtory applied coatings, field joint coatings and coating field major surfaces in structural steel (e.g. riser bases), reference isrepairs are closely defined (e.g. as in DNV-RP-F106 and made to DNV-RP-B401.DNV-RP-F102). A recommended procedure to calculate theprotective length of anodes on an adjacent structure is given in 510 Design of any impressed current CP systems installed atDNV-RP-F103 (ISO 15589-2 gives an alternative procedure land falls shall comply with ISO 15589-1. Requirements tobut, contrary to DNV-RP-F103, does not define the primary electrically insulating joints are given in Sec.8 B800.parameters to be used for calculation of the protective length). Guidance note: Guidance note: Design of impressed current CP systems at landfalls is not cov- ered by this standard. Some general guidance is given in ISO CP by anodes located on adjacent structures significantly reduces 15889. the cost of anode installation in case the pipeline installation con- cept would otherwise require anode installation offshore. More- ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- over, for buried pipelines in general and for hot buried lines in particular, the anode electrochemical efficiency and current out- D 600 External corrosion control of risers put capacity increases since anodes are located boldly exposed to seawater. The condition of such anodes can also be monitored. (informative) The concept of basing pipeline CP on anodes installed on adja- 601 For a specific riser, the division into corrosion protection cent structures further reduces the risk of HISC damage to pipe- zones is dependent on the particular riser or platform design lines in susceptible materials (e.g. martensitic and ferritic- and the prevailing environmental conditions. The upper and austenitic stainless steels). lower limits of the ‘splash zone’ may be determined according ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- to the definitions in Sec.1.506 Bracelet pipeline anodes are to be designed with due 602 Adverse corrosive conditions occur in the zone aboveconsiderations of forces induced during pipeline installation. lowest astronomical tide (LAT) where the riser is intermit-For anodes to be installed on top of the pipeline coating, this tently wetted by waves, tide and sea spray (‘splash zone’).may require use of bolts for tensioning or welding of anode Particularly severe corrosive conditions apply to risers heatedtabs with pressure applied on the bracelet assembly. Connector by an internal fluid. In the splash zone, the riser coating maycables shall be adequately protected; e.g. by locating the cables be exposed to mechanical damage by surface vessels andto the gap between the anode bracelets and filling with a marine operations, whilst there is limited accessibility formoulding compound. inspection and maintenance.507 A calculation procedure for pipeline CP design using 603 The riser section in the ‘atmospheric zone’ (i.e. aboveconventional bracelet anodes and a maximum anode spacing the splash zone) is more shielded from both severe weatheringof 300 m is given in ISO 15589-2 and in DNV-RP-F103. The and mechanical damage. Furthermore, there is better accessi-latter document generally refers to ISO 15589-2 for design bility for inspection and maintenance.parameters and design procedures to be used and recommends 604 In the ‘submerged zone’ and in the splash zone belowsome default values which represent minimum requirements the lowest astronomical tide (LAT), an adequately designed DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 64 – Sec.6 see note on front coverCP system is capable of preventing corrosion at any damaged 702 The selection of a system for internal corrosion protec-areas of the riser coating. In the tidal zone, a CP system will be tion of pipelines and risers has a major effect on detailedmarginally effective. design and must therefore be evaluated during conceptual605 Different coating systems may be applied in the three design. The following options for corrosion control may becorrosion protection zones defined above, provided they are considered:compatible. The considerations according to a), b), c), f), g) a) processing of fluid for removal of liquid water and/or cor-and h) in D403 above apply for all of the three zones. Fastening rosive agents.devices for risers are normally selected to be compatible witha specific riser coating rather than vice versa. b) use of linepipe or internal (metallic) lining/cladding with intrinsic corrosion resistance (see B300).606 The following additional considerations affecting selec-tion of coating system apply in the splash and atmospheric c) use of organic corrosion protective coatings or liningszones: (normally in combination with a) or d)). d) chemical treatment, i.e. addition of chemicals with corro-— resistance to under-rusting at coating defects sion mitigating function.— maintainability— compatibility with inspection procedures for internal and/ In addition, the benefits of a corrosion allowance (see D200) or external corrosion should be duly considered for a) and d).— compatibility with equipment/procedures for removal of 703 Corrosion control by fluid processing may involve biofouling (if applicable) removal of water from gas/oil (dehydration), or of oxygen— fire protection (if required). from seawater for injection (deoxygenation), for example. Consequences of operational upsets on material degradation607 External cladding with certain Cu-base alloys may be should be taken into account. The necessity for corrosionused for combined corrosion protection and anti-fouling, pri- allowance and redundant systems for fluid processing shouldmarily in the transition of the splash zone and the submerged be considered. On-line monitoring of fluid corrosion proper-zone (see D602). However, metallic materials with anti-foul- ties downstream of processing unit is normally required. Foring properties must be electrically insulated from the CP sys- oil export pipelines carrying residual amounts of water, a bio-tem to be effective. Multiple-layer paint coatings and cide treatment should be considered as a back up for preven-thermally sprayed aluminium coatings are applicable to the tion of bacterial corrosion. Periodic pigging for removal ofatmospheric and submerged zones, and in the splash zone if water and deposits counteracts internal corrosion in generalfunctional requirements and local conditions permit. and bacterial corrosion in particular.608 Mechanical and physical coating properties listed in 704 If internal coatings or linings are to be evaluated as anD403 are also relevant for riser coatings, dependent on the par- option for corrosion control, the following main parametersticular corrosion protection zone. The applicable requirements shall be considered:to properties for each coating system and for quality controlshall be defined in a purchase specification. The general — chemical compatibility with all fluids to be conveyed orrequirements and guidelines for quality control in DNV-RP- contacted during installation, commissioning and opera-F106 are applicable. Some of the coating systems with func- tion, including the effects of any additives for control oftional requirements defined in coating data sheets are applica- flow or internal corrosion (see D706)ble also as riser coatings. — resistance to erosion by fluid and mechanical damage by609 In the submerged zone, the considerations for selection pigging operationsof coating in D403 apply. In addition, resistance to biofouling — resistance to rapid decompressionis relevant in surface waters of the submerged zone and the — reliability of quality control during coating applicationlowermost section of the splash zone may have to be consid- — reliability of (internal) field joint coating systems, if appli-ered. cable — consequences of failure and redundant techniques for cor-610 Riser FJC’s shall have properties matching the selected rosion mitigation.pipe coating. In the splash zone, field joint coatings should beavoided unless it can be demonstrated that their corrosion pro- 705 Internal coating of pipelines (e.g. by thin film of epoxy)tection properties are closely equivalent to those of the adja- has primarily been applied for the purpose of friction reductioncent coating. in dry gas pipelines ("flow coatings" or “anti-friction coat- ings”). Any such coatings should have a minimum specifiedD 700 Internal corrosion control (informative) thickness of 40 μm and should comply with the minimum701 Options for internal corrosion control should be evalu- requirements in API RP 5L2. Although such coatings can notated aiming for the most cost-effective solution meeting the be expected to be efficient in preventing corrosion attack ifoverall requirements of safety and environmental regula- corrosive fluids are conveyed, any coating with adequate prop-tions.The selection of the most cost-effective strategy for cor- erties may still be beneficial in reducing forms of attack affect-rosion control requires that all major costs associated with ing membrane stresses and hence, the pressure retainingoperation of the pipeline system, as well as investment costs capacity of the pipeline.for corrosion control, are evaluated ("Life Cycle Cost Analy- 706 Chemical treatment of fluids for corrosion control maysis"). When fluid corrosivity and efficiency of corrosion miti- include:gation cannot be assessed with any high degree of accuracy, a"risk cost" may be added for a specific option being evaluated. — corrosion inhibitors (e.g. "film forming")The risk cost is the product of estimated probability and conse- — pH-buffering chemicalsquences (expressed in monetary units) of a particular failure — biocides (for mitigation of bacterial corrosion)mode (e.g. rupture or pinhole leakage). The probability of such — glycol or methanol (added at high concentrations forfailures should reflect the designers confidence in estimating hydrate inhibition, diluting the water phase)the fluid corrosivity and the efficiency of options for corrosion — dispersants (for emulsification of water in oil)control being evaluated. Depending on the failure mode, con- — scavengers (for removal of corrosive constituents at lowsequences of failure may include costs associated with concentrations).increased maintenance, repairs, lost capacity and secondarydamage to life, environment and other investments. 707 The reliability of chemical treatment should be evalu- DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.6 – Page 65ated in detail during the conceptual design. Important parame- — consequences of failure to achieve adequate protection,ters to be considered are: and redundant techniques.— anticipated corrosion mitigating efficiency for the actual For pipelines carrying untreated well fluid or other fluids with fluid to be treated, including possible effects of scales, high corrosivity and with high requirements to safety and reli- deposits, etc. associated with this fluid— capability of the conveyed fluid to distribute inhibitor in ability, there is a need to verify the efficiency of chemical treat- the pipeline system along its full length and circumference ment by integrity monitoring using a tool allowing wall— compatibility with all pipeline system and downstream thickness measurements along the full length of the pipeline materials, particularly elastomers and organic coatings (see Sec.12). Corrosion probes and monitored spools are pri-— compatibility with any other additives to be injected, marily for detection of changes in fluid corrosivity and are not— health hazards and environmental compatibility applicable for verification of the integrity of the pipeline.— provisions for injection and techniques/procedures for monitoring of inhibitor efficiency DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 66 – Sec.7 see note on front cover SECTION 7 CONSTRUCTION – LINEPIPE A. General Multiple welding processes (MWP) Pipe formed from strip or plate and welded using a combina-A 100 Objective tion of two or more welding processes. If the combination of101 This section specifies the requirements for, manufac- welding processes has not been used previously, pre-qualifica-ture, testing and documentation of linepipe. All mechanical tion testing should be conducted according to Appendix C.properties and dimensional tolerances shall be met after heat 303 The backing steel of lined linepipe shall comply withtreatment, expansion and final shaping. A301.102 Materials selection shall be performed in accordance 304 The liner pipe of lined linepipe shall be manufactured inwith Sec.6. accordance with API 5LC.103 This section does not cover any activities taking part 305 Clad linepipe shall be manufactured from CRA clad C-after the pipes have been dispatched from the pipe mill, e.g. Mn steel plate by application of a single longitudinal weld.girth welding and coating. With respect to the backing steel, the pipe manufacturing shall104 The requirements stated herein for Carbon-Manganese be in general compliance with one of the manufacturing routes(C-Mn) steel linepipe conform in general to ISO 3183 Annex for SAW pipe as given in Table 7-1. The longitudinal weldJ: “PSL 2 pipe ordered for offshore service”, with some addi- shall be MWP (see A302).tional and modified requirements. A 400 Supplementary requirements105 Manufacturers of linepipe shall have an implementedquality assurance system according to ISO 9001. 401 When requested by the Purchaser and stated in the mate- rials specification (as required in A500), linepipe to this stand-A 200 Application ard shall meet supplementary requirements given in201 The requirements are applicable for linepipe made of: Subsection I, for:— C-Mn steel — sour service, suffix S (see I100)— clad or lined steel — fracture arrest properties, suffix F (see I200)— corrosion resistant alloys (CRA) including ferritic - auste- — linepipe for plastic deformation, suffix P (see I300) nitic (duplex) stainless steel, austenitic stainless steels, — enhanced dimensional requirements for linepipe, suffix D martensitic stainless steels (13Cr), other stainless steels (see I400) and nickel based alloys. — high utilisation, suffix U (see I500).202 Materials, manufacturing methods and procedures that A 500 Linepipe specificationcomply with recognised practices or proprietary specifications 501 A linepipe specification reflecting the results of thewill normally be acceptable provided they comply with the materials selection (see Sec.6 C200), referring to this sectionrequirements of this section. (Sec.7) of the offshore standard, shall be prepared by the Pur- chaser. The specification shall state any additional require-A 300 Process of manufacture ments to and/or deviations from this standard pertaining to301 C-Mn linepipe shall be manufactured according to one materials, manufacture, fabrication and testing of linepipe.of the following processes: A 600 Manufacturing Procedure Specification andSeamless (SMLS) qualificationPipe manufactured by a hot forming process without welding. Manufacturing Procedure Specification (MPS)In order to obtain the required dimensions, the hot formingmay be followed by sizing or cold finishing. 601 Before production commences, the Manufacturer shall prepare a Manufacturing Procedure Specification (MPS). TheHigh Frequency Welded (HFW) MPS shall demonstrate how the specified properties may bePipe formed from strip and welded with one longitudinal seam achieved and verified throughout the proposed manufacturingformed by electric-resistance welding applied by induction or route.conduction with a welding current frequency ≥70 kHz, without The MPS shall address all factors that influence the quality andthe use of filler metal. The forming may be followed by cold consistency of the product. All main manufacturing steps fromexpansion or reduction. control of received raw material to shipment of finished pipe,Submerged Arc-Welded (SAW) including all examination and check points, shall be outlined in detail.Pipe manufactured by forming from strip or plate and with onelongitudinal (SAWL) or helical (SAWH) seam formed by the References to the procedures established for the execution ofsubmerged arc process, with at least one pass made on the all the individual production steps shall be included.inside and one pass from the outside of the pipe. The forming 602 The MPS shall as a minimum contain the followingmay be followed by cold expansion or reduction. information (as applicable):302 CRA linepipe may, in addition to SMLS and SAWL, bemanufactured according to one of the following processes: — steel producer — plan(s) and process flow description/diagramElectron Beam Welded (EBW) and Laser Beam Welded (LBW) — project specific quality control planPipe formed from strip and welded with one longitudinal seam, — manufacturing processwith or without the use of filler metal. The forming may be fol- — target chemical compositionlowed by cold expansion or reduction to obtain the required — steel making and casting techniquesdimensional tolerances. These welding processes shall be sub- — ladle treatments (secondary refining), degassing, details ofject to pre-qualification testing according to Appendix C. inclusion shape control, super heat DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 67— method used to ensure that sufficient amount of inter- 609 In addition to the requirements stated above, the follow- mixed zones between different orders are removed ing changes (as applicable) to the manufacturing processes— details and follow-up of limiting macro, as well as micro will require re-qualification of the MPS (essential variables): segregation, e.g. soft reduction and electro magnetic stir- ring (EMS) used during continuous casting — any change in steelmaking practice— manufacturer and manufacturing location of raw material — changes beyond the allowable variation for rolling prac- and/or plate for welded pipes tice, accelerated cooling and/or QT process— billets reheating temperature for seamless — change in nominal wall thickness exceeding + 5% to -10%— allowable variation in slab reheating temperature, and start — change in ladle analysis for C-Mn steels outside ± 0.02% and stop temperatures for finishing mill and accelerated C, ± 0.02 CE and/or ± 0.03 in Pcm cooling — any change in pipe forming process,— methods for controlling the hydrogen level (e.g. stacking — any change in alignment and joint design for welding of slabs or plates) — change in welding heat input ± 15%.— pipe-forming procedure, including preparation of edges and control of alignment and shape (including width of The following additional essential variable applies to HFW, strip for HFW) EBW and LBW pipe:— procedure for handling of welding consumable and flux — any change in nominal thickness— all activities related to production and repair welding, — change in welding heat coefficient including welding procedures and qualification Q = (amps × volts) / (travel speed × thickness) ± 5%— heat treatment procedures (including in-line heat treat- — addition or deletion of an impeder ment of the weld seam) including allowable variation in — change in rollers position and strip width outside agreed process parameters tolerances.— method for cold expansion/reduction/sizing/finishing, tar- get and maximum sizing ratio 610 If one or more tests in the MPQT fail, the MPS shall be— hydrostatic test procedures reviewed and modified accordingly, and a complete re-qualifica-— NDT procedures (also for strip/plate as applicable) tion performed. Re-testing may be allowed subject to agreement.— list of specified mechanical and corrosion testing— dimensional control procedures— pipe number allocation— pipe tracking procedure (traceability procedure) B. Carbon Manganese (C-Mn) Steel Linepipe— marking, coating and protection procedures— handling, loading and shipping procedures. B 100 General 101 C-Mn steel linepipe fabricated according to this standardManufacturing Procedure Qualification Test (MPQT) generally conform to the requirements in ISO 3183 Annex J:603 The MPS shall be qualified for each nominal pipe diam- “PSL 2 pipe ordered for offshore service”. Any additional oreter as part of first day production, unless as allowed in A609. modified requirements to ISO 3183 Annex J are highlighted inFor C-Mn steels with SMYS ≤ 485 MPa that are not intended this subsection (B200-B600) as described in B102 and B103.for sour service, relevant documentation may be agreed in lieu Additional or modified requirementsof qualification testing providing all essential variables inA609 are adhered to. 102 Paragraphs containing additional requirements to ISO 3183 are marked at the end of the relevant paragraph with AR.604 Each MPQT shall include full qualification of one pipefrom two different test units (a total of two pipes). If the entire Paragraphs containing requirements that are modified com-production is limited to one heat the MPQT may be performed pared to ISO 3183 are marked at the end of the relevant para-on a single pipe from that heat. The minimum type and extent graph with MR.of chemical, mechanical, and non-destructive testing are given 103 Additional or modified requirements when given inin this section. This includes all stated production tests plus tables are marked in accordance with B102 with AR and MRadditional tests given in Table 7-8, Table 7-13 and Table 7-15. in the relevant table cells as applicable.605 For C-Mn steels with SMYS > 485 MPa, the qualifica-tion of the MPS shall be completed prior to start of production, B 200 Pipe designationunless otherwise agreed. 201 C-Mn steel linepipe shall be designated with: Guidance note: — DNV Depending on the criticality of the project, it is recommended for — process of manufacture all projects to carefully evaluate if the MPQT should be con- ducted prior to the start of production. — SMYS — supplementary requirement suffix (see Subsection I), as ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- applicable. MR606 If the cold forming of C-Mn steel exceeds 5% strain after Guidance note:heat treatment then ageing tests shall be performed as part of e.g. "DNV SMLS 450 SF" designates a seamless pipe withthe qualification testing. The tests shall be performed on the SMYS 450 MPa, meeting the supplementary requirements foractual pipe without any straightening and additional deforma- sour service and fracture arrest properties.tion, see Appendix B A1201. The absorbed Charpy V-notch ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---impact energy in the aged condition shall meet the require-ments in Table 7-5. B 300 Manufacturing607 Additional MPS qualification testing may be required byPurchaser (e.g. weldability testing, analysis for trace elements Starting material and steel makingfor steel made from scrap, etc.), as part of the qualification of 301 C-Mn steel linepipe shall be manufactured in accord-the MPS (see A603). ance with the processes given in A300 using the starting mate-608 The validity of the MPQT shall be limited to the steel- rials and corresponding forming methods and final heatmaking, rolling, and manufacturing/ fabrication facilities used treatment as given in Table 7-1.during the qualification. 302 All manufacturing including steel making and the raw DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 68 – Sec.7 see note on front covermaterials used shall be in accordance with the qualified MPS, seam welds of SAWL pipes or SAWH pipes.follow the same activity sequence, and stay within the agreed 322 Tack welds shall be made by: manual or semi-automaticallowable variations. submerged-arc welding, electric welding, gas metal-arc weld-303 All steels shall be made by an electric or one of the basic ing, flux-cored arc welding; or shielded metal-arc welding usingoxygen processes. C-Mn steel shall be fully killed and made to a low hydrogen electrode. Tack welds shall be melted and coa-a fine grain practice. lesced into the final weld seam or removed by machining.General requirements to manufacture of seamless pipe 323 Intermittent tack welding of the SAWL groove shall not304 SMLS pipe shall be manufactured from continuously be used unless Purchaser has approved data furnished by Man-(strand) cast or ingot steel. ufacturer to demonstrate that all mechanical properties speci- fied for the pipe are obtainable at both the tack weld and305 If the process of cold finishing is used, this shall be intermediate positions.stated in the inspection document. 324 Unless comparative tests results of diffusible hydrogen306 Pipe ends shall be cut back sufficiently after rolling to versus flux moisture content are provided (meeting theensure freedom from defects. AR requirement in B318), the maximum residual moisture contentGeneral requirements to manufacture of welded pipe of agglomerated flux shall be 0.03%.307 Unless otherwise agreed, strip and plate used for the Repair welding of SAW seam weldsmanufacture of welded pipe shall be rolled from continuously 325 Repair welding of SAW pipe seam welds shall be qual-(strand) cast or pressure cast slabs. Strip or plate shall not con- ified in accordance with ISO3183 Annex D and be performedtain any repair welds. in accordance with ISO3183 Annex C.4. Any repair welding308 The strip width for spiral welded pipes should not be less shall be carried out prior to cold expansion.than 0.8 and not more than 3.0 times the pipe diameter. Strip 326 Acceptance criteria and test requirements for Charpy V-and plate shall be inspected visually after rolling, either of the notch impact properties for qualification of repair welding pro-plate, of the uncoiled strip or of the coil edges. cedures shall be in accordance with B409 through 411. AR309 If agreed, strip and plate shall be inspected ultrasonically HFW pipefor laminar imperfections or mechanical damage, either beforeor after cutting the strip or plate, or the completed pipe shall be 327 The abutting edges of the strip or plate should be milledsubjected to full-body inspection, including ultrasonic inspec- or machined immediately before welding.tion, see Table 7-16. 328 The width of the strip or plate should be continuously310 Plate or strip shall be cut to the required width and the monitored. ARweld bevel prepared by milling or other agreed methods before 329 The weld seam and the HAZ shall be fully normalizedforming. AR subsequent to welding. MR311 Cold forming (i.e. below 250°C) of C-Mn steel shall not Heat treatmentintroduce a plastic deformation exceeding 5%, unless heattreatment is performed or ageing tests show acceptable results 330 Heat treatments of SMLS and welded pipe shall be per-(see A606). AR formed according to documented procedures used during MPQT.312 Normalising forming of materials and weldments shallbe performed as recommended by the Manufacturers of the 331 The documented procedures shall be in accordance withplate/strip and welding consumables. AR any recommendations from the material Manufacturer with regard to heating and cooling rates, soaking time, and soaking313 Welding personnel for execution of all welding opera- temperature. ARtions shall be qualified by in-house training. The in-housetraining program shall available for review on request by Pur- Cold expansion and cold sizingchaser. AR 332 The extent of cold sizing and cold forming expressed as314 Welding procedures for the seam weld shall be qualified the sizing ratio sr, shall be calculated according to the follow-as part of MPQT. AR ing formula:315 The weld metal shall, as a minimum, have strength, duc- sr = |Da - Db| / Dbtility and toughness meeting the requirements of the base mate- whererial. AR316 Welds containing defects may be locally repaired by Da is the outside diameter after sizingwelding. Weld deposit having unacceptable mechanical prop- Db is the outside diameter before sizing.erties shall be completely removed before re-welding. AR 333 The sizing ratio of cold expanded pipe should be within317 Arc stops during welding shall be repaired according to the range 0.003 < sr ≤ 0.015. Expansion shall not introducea qualified welding repair procedure. AR high local deformations.318 Low hydrogen welding consumables shall be used and 334 Pipes may be cold sized to their final dimensions byshall give a diffusible hydrogen content of maximum 5 ml/ expansion or reduction. This shall not produce excessive per-100 g weld metal. AR manent strain. The sizing ratio, sr , shall not exceed 0.015 if no subsequent heat treatment or only heat treatment of the weld319 Welding consumables shall be individually marked and area is performed.supplied with an inspection certificate according to EN 10204.Welding wire shall be supplied with certificate type 3.1. while 335 The sizing ratio, sr , for cold sizing of pipe ends shall notcertificate type 2.2 is sufficient for SAW Flux. AR exceed 0.015 unless the entire pipe ends are subsequently320 Handling of welding consumables and the execution and stress relieved.quality assurance of welding shall meet the requirements of in- Finish of pipe endshouse quality procedures. AR 336 Unless otherwise agreed, pipe ends shall be cut squareSAW pipe and be free from burrs. MR321 Any lubricant and contamination on the weld bevel or 337 The internal weld bead shall be ground to a height of 0the surrounding areas shall be removed before making the to 0.5 mm for a distance of at least 100 mm at both pipe ends. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 69Table 7-1 C-Mn steels, acceptable manufacturing routesType of Starting Material Pipe forming Final heat treatment Deliverypipe condition 1)SMLS Ingot, bloom or billet Normalising forming None N Hot forming Normalising or QT 1) N or Q Hot forming and cold finishing N or QHFW Normalising rolled strip Cold forming Normalising of weld area N Thermo-mechanical rolled strip Heat treating of weld area M Heat treating of weld area and M stress relieving of entire pipe Hot rolled or normalising rolled strip Cold forming Normalising of entire pipe N QT 2) of entire pipe Q Cold forming and hot reduction under None N controlled temperature, resulting in a normalised condition Cold forming followed by thermome- M chanical forming of pipeSAW Normalised or normalising rolled plate or Cold forming None, unless required due to N strip degree of cold forming Thermo-mechanical rolled plate or strip M QT 2) plate or strip Q As-rolled, QT 2), normalised or normalis- Normalising forming None N ing rolled plate or strip Cold forming Normalising N QT 1) QNotes1) The delivery conditions are: “Normalised” denoted N, “Quenched and tempered”, denoted Q, and “Thermomechanical rolled or formed”, denoted M.2) Quenched and Tempered.338 If agreed, the outside weld bead shall be ground to a Re-processingheight of 0 to 0.5 mm for a distance of at least 250 mm at both 344 In case any mechanical tests fail during production ofpipe ends. The transition to the base material/pipe body shall QT or normalised pipe material, it is acceptable to conduct onebe smooth and without a noticeable step. MR re-heat treatment cycle of the entire test unit. All mechanical339 If agreed internal machining or grinding may be carried testing shall be repeated after re-heat treatment. ARout. In case of machining, the following requirements shall be Traceabilityadhered to: 345 A system for traceability of the heat number, heat treat-— if required in the purchase order the internal taper shall be ment batch and test unit number and the records from all located at a defined minimum distance from future bevel required tests to each individual pipe shall be established and to facilitate UT or AUT described in the MPS (see A602). Required repairs and records— the angle of the internal taper, measured from the longitu- of dimensional testing and all other required inspections shall dinal axis shall not exceed 7.0° for welded pipe. For SMLS be included. Care shall be exercised during storage and han- pipe the maximum angle of the internal taper shall be as dling to preserve the identification of materials. MR given in Table 7-2. MR B 400 Acceptance criteriaTable 7-2 Maximum angle of internal taper for SMLS pipe Chemical composition Wall thickness t [mm] Max. angle of taper [°] 401 The chemical compositions given in Table 7-3 are appli- < 10.5 7.0 cable to pipes with delivery condition N or Q (normalised or 10.5 ≤ t < 14.0 9.5 quenched and tempered according to Table 7-1), with nominal 14.0 ≤ t < 17.0 11.0 wall thickness t ≤ 25 mm. ≥ 17.0 14.0 402 The chemical compositions given in Table 7-4 are appli- cable to pipes with delivery condition M (thermo-mechanical formed or rolled according to Table 7-1). The chemical com-Jointers and strip end welds positions given in Table 7-4 are applicable for pipes with t ≤ 35340 Jointers shall not be delivered unless otherwise agreed. mm. MR341 If used, the jointer circumferential weld shall be quali- 403 For pipes with nominal wall thickness larger than thefied according to the requirements for pipeline girth welds limits indicated in B401 and B402, the chemical compositiongiven in Appendix C. Production testing requirements for shall be subject to agreement.jointers shall be in accordance with ISO 3183. Other manufac- 404 For pipe with a carbon content ≤ 0.12% (product analy-turing requirements shall comply with Annex A of ISO 3183. sis), carbon equivalents shall be determined using the Pcm for-342 Apart from linepipe supplied as coiled tubing, strip / mula as given in Table 7-3 and Table 7-4. If the heat analysisplate end welds shall not be permitted unless otherwise agreed. for boron is less than 0.0005%, then it is not necessary for theMR product analysis to include boron, and the boron content may343 If used, see B341, strip / plate end welds shall comply be considered to be zero for the Pcm calculation.with all applicable requirements in ISO 3183. 405 For pipe with a carbon content > 0.12% (product analy- DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 70 – Sec.7 see note on front coversis) carbon equivalents shall be determined using the CE for- 411 From the set of three Charpy V-notch specimens, onlymula as given in Table 7-3. one is allowed to be below the specified average value andTensile properties shall meet the minimum single value requirement. AR Flattening test406 The tensile properties shall be as given in Table 7-5. 412 For HFW pipe with SMYS ≥ 415 MPa with wall407 For transverse weld tensile testing, the fracture shall not thickness ≥ 12.7 mm, there shall be no opening of the weldbe located in the weld metal. The ultimate tensile strength shall before the distance between the plates is less than 66% of thebe at least equal to the SMTS. original outside diameter. For all other combinations of pipeHardness grade and specified wall thickness, there shall be no opening of the weld before the distance between the plates is less than408 The hardness in the Base Material (BM), Weld Metal 50% of the original outside diameter.(WM) and the Heat Affected Zone (HAZ) shall comply withTable 7-5. AR 413 For HFW pipe with a D/t2 > 10, there shall be no cracks or breaks other than in the weld before the distance betweenCVN impact test the plates is less than 33% of the original outside diameter.409 Requirements for Charpy V-notch impact properties for Guidance note:linepipe BM, WM and HAZ are given in Table 7-5. The values The weld extends to a distance, on each side of the weld line, ofin Table 7-5 shall be met when tested at the temperatures given 6.4 mm for D < 60.3 mm, and 13 mm for D ≥ 60.3 mm.in Table 7-6. MR ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---410 Testing of Charpy V-notch impact properties shall, ingeneral, be performed on test specimens 10 × 10 mm. Where Guided-bend testtest pieces of width < 10 mm are used, the measured average 414 The guided-bend test pieces shall not:impact energy (KVm) and the test piece cross-section meas-ured under the notch (A) (mm2) shall be reported. For compar- — fracture completelyison with the values in Table 7-5, the measured energy shall be — reveal any cracks or ruptures in the weld metal longer thanconverted to the impact energy (KV) in Joules using the for- 3.2 mm, regardless of depth, ormula: — reveal any cracks or ruptures in the parent metal, HAZ, or fusion line longer than 3.2 mm or deeper than 12.5% of the 8 × 10 × KV m specified wall thickness. KV = -------------------------------- - (7.1) A However, cracks that occur at the edges of the test piece during testing shall not be cause for rejection, provided that they areAR not longer than 6.4 mm.Table 7-3 Chemical composition for C-Mn steel pipe with delivery condition N or Q, applicable for seamless and welded pipe. Product analysis, maximum. wt.% CarbonSMYS equivalents C1) Si Mn 1) P S V Nb Ti Other 2) CE 3) Pcm 4) Pipe with delivery condition N (normalised according to Table 7-1)245 0.14 0.40 1.35 0.020 0.010 Note 5) Note 5) 0.04 Notes 6,7) 0.36 0.19 8)290 0.14 0.40 1.35 0.020 0.010 0.05 0.05 0.04 Note 7) 0.36 0.19 8)320 0.14 0.40 1.40 0.020 0.010 0.07 0.05 0.04 Notes 6,7) 0.38 0.20 8)360 0.16 0.45 1.65 0.020 0.010 0.10 0.05 0.04 Notes 6) 0.43 0.22 8) Pipe with delivery condition Q (quenched and tempered according to Table 7-1)245 0.14 0.40 1.35 0.020 0.010 0.04 0.04 0.04 Note 7) 0.34 0.19 8)290 0.14 0.40 1.35 0.020 0.010 0.04 0.04 0.04 Note 7) 0.34 0.19 8)320 0.15 0.45 1.40 0.020 0.010 0.05 0.05 0.04 Note 7) 0.36 0.20 8)360 0.16 0.45 1.65 0.020 0.010 0.07 0.05 0.04 Notes 6,9) 0.39 0.20 8)390 0.16 0.45 1.65 0.020 0.010 0.07 0.05 0.04 Notes 6,9) 0.40 0.21 8)415 0.16 0.45 1.65 0.020 0.010 0.08 0.05 0.04 Notes 6,9) 0.41 0.22 8)450 0.16 0.45 1.65 0.020 0.010 0.09 0.05 0.06 Notes 6,9) 0.42 0.22 8)485 0.17 0.45 1.75 0.020 0.010 0.10 0.05 0.06 Notes 6,9) 0.42 0.23 8)555 0.17 0.45 1.85 0.020 0.010 0.10 0.06 0.06 Notes 6,9) As agreedNotes1) For each reduction of 0.01% below the specified maximum for carbon, an increase of 0.05% above the specified maximum for manganese is permissible, up to a maximum increase of 0.20%.2) Al total ≤ 0.060%; N ≤ 0.012%; Al/N ≥ 2:1 (not applicable to titanium-killed steel or titanium-treated steel). Mn (Cr + Mo + V ) ( Ni + Cu )3) CE = C + + + 6 5 154) Si Mn Cu Ni Cr Mo V Pcm = C + + + + + + + + 5B 30 20 20 60 20 15 105) Unless otherwise agreed, the sum of the niobium and vanadium contents shall be ≤ 0.06%.6) The sum of the niobium, vanadium, and titanium contents shall be ≤ 0.15%.7) Cu ≤ 0.35%; Ni ≤ 0.30%; Cr ≤ 0.30%; Mo ≤ 0.10%; B ≤ 0.0005%.8) For SMLS pipe, the listed value is increased by 0.03, up to a maximum of 0.25.9) Cu ≤ 0.50%; Ni ≤ 0.50%; Cr ≤ 0.50%; Mo ≤ 0.50%; B ≤ 0.0005%. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 71Table 7-4 Chemical composition for C-Mn steel pipe with delivery condition M(thermo-mechanical formed or rolled according to Table 7-1). Product analysis, maximum. wt.% Carbon equivalentSMYS C1) Si Mn 1) P S V Nb Ti Other 2) Pcm 3)245 0.12 0.40 1.25 0.020 0.010 0.04 0.04 0.04 Note 4) 0.19290 0.12 0.40 1.35 0.020 0.010 0.04 0.04 0.04 Note 4) 0.19320 0.12 0.45 1.35 0.020 0.010 0.05 0.05 0.04 Note 4) 0.20360 0.12 0.45 1.65 0.020 0.010 0.05 0.05 0.04 Notes 5,6) 0.20390 0.12 0.45 1.65 0.020 0.010 0.06 0.08 0.04 Notes 5,6) 0.21415 0.12 0.45 1.65 0.020 0.010 0.08 0.08 0.06 Notes 5,6) 0.21450 0.12 0.45 1.65 0.020 0.010 0.10 0.08 0.06 Notes 5,6) 0.22485 0.12 0.45 1.75 0.020 0.010 0.10 0.08 0.06 Notes 5,6) 0.22 7)555 0.12 0.45 1.85 0.020 0.010 0.10 0.08 0.06 Notes 5,6) 0.24 7)Notes1) For each reduction of 0.01% below the specified maximum for carbon, an increase of 0.05% above the specified maximum for manganese is permissible, up to a maximum increase of 0.20%.2) Al total ≤ 0.060%; N ≤ 0.012%; Al/N ≥ 2:1 (not applicable to titanium-killed steel or titanium-treated steel). Si Mn Cu Ni Cr Mo V3) Pcm = C + + + + + + + + 5B 30 20 20 60 20 15 104) Cu ≤ 0.35%; Ni ≤ 0.30%; Cr ≤ 0.30%; Mo ≤ 0.10%; B ≤ 0.0005%.5) The sum of the niobium, vanadium, and titanium contents shall be ≤ 0.15%.6) Cu ≤ 0.50%; Ni ≤ 0.50%; Cr ≤ 0.50%; Mo ≤ 0.50%; B ≤ 0.0005%.7) For nominal wall thickness t > 25 mm the carbon equivalent may be increased with 0.01.Table 7-5 C-Mn steel pipe, mechanical properties Yield strength Tensile strength Ratio Elongation in Hardness Charpy V-notch Rt0,5 Rm Rt0,5/Rm 50.8 mm [HV10] energy (KVT) 1) [MPa] [MPa] Af [J] [%] BM, WM HAZSMYS min. max. min.2) max. max. min. max. average min.245 245 450 3) 415 760 0.93 Note 4) 270 300 27 22290 290 495 415 760 270 30 24320 320 520 435 760 270 32 27360 360 525 460 760 270 36 30390 390 540 490 760 270 39 33415 415 565 520 760 270 42 35450 450 570 535 760 270 45 38485 485 605 570 760 300 50 40555 555 675 625 825 300 56 45Notes1) The required KVL (longitudinal direction specimens) values shall be 50% higher than the required KVT values.2) If tested in the longitudinal direction, a minimum tensile strength 5% less than the required value is acceptable.3) For pipe with specified outside diameter < 219.1 mm, the yield strength shall be ≤ 495 MPa.4) The specified minimum elongation Af , in 50.8 mm, expressed in percent, rounded to the nearest percent shall be as determined using 0, 2 AXC the following equation: Af = C 0,9 where: U C is 1940 for calculations using SI units; AXC is the applicable tensile test piece cross-sectional area, as follows: - for round bar test pieces, 130 mm2 for 12.5 mm and 8.9 mm diameter test pieces; and 65 mm2 for 6.4 mm test pieces - for full-section test pieces, the lesser of a) 485 mm2 and b) the cross-sectional area of the test piece, calculated using the specified outside diameter and the specified wall thickness of the pipe, rounded to the nearest 10 mm2 - for rectangular test pieces, the lesser of a) 485 mm2 and b) the cross-sectional area of the test piece, calculated using the specified width of the test piece and the specified wall thickness of the pipe, rounded to the nearest 10 mm2, and U is the specified minimum tensile strength, in MPa. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 72 – Sec.7 see note on front coverTable 7-6 C-Mn steel linepipe, Charpy V-notch impact testing Inspection frequencytemperatures T0 (°C) as a function of Tmin (°C) (Minimum 502 The inspection frequency during production shall be asDesign Temperature) given in Table 7-7 and the extent of testing for MPQT as given in Table 7-8. Reference to the relevant acceptance criteria isNominal wall Thickness (mm) PIPELINES and risers given in these tables. MRt ≤ 20 T0 = Tmin 503 A test unit is a prescribed quantity of pipe that is made20 < t ≤ 40 T0 = Tmin – 10 to the same specified outside diameter and specified wallt > 40 T0 = to be agreed in each case thickness, by the same pipe-manufacturing process, from theFracture toughness of weld seam same heat, and under the same pipe-manufacturing conditions.415 The measured fracture toughness shall as a minimum 504 For coiled tubing, all required mechanical testing inhave a CTOD value of 0.15 mm, when tested at the minimum Table 7-7 shall be performed at each pipe end or for each heat,design temperature. AR whichever gives the highest number of tests. Strip end welds for coiled tubing shall be tested according to ISO 3183Macro examination of weld seam Annex J. AR416 The macro section shall show a sound weld merging 505 Sampling for mechanical and corrosion testing shall besmoothly into the base material without weld defects accord- performed after heat treatment, expansion and final shaping.ing to Appendix D, Table D-4. For SAW pipe complete re- The number and orientation of the samples are given in Tablemelting of tack welds shall be demonstrated. For MPQT welds 7-9. The samples shall not be prepared in a manner that mayshall meet the requirements of ISO 5817 Quality level C. AR influence their mechanical properties.417 The alignment of internal and external seams of SAW 506 In case of large quantities of longitudinally welded largepipes shall be verified on the macro section, unless alternative diameter and heavy wall thickness pipe, where the test unit ismethods with demonstrated capabilities are used. governed by the heat size, it may be agreed that pipes from sev-Metallographic examination of HFW pipe eral heats represents one test unit. The first 30 000 tons shall be tested with a frequency according to normal practice of this418 The metallographic examination shall be documented standard. After exceeding 30 000 tons, the below testing phi-by micrographs at sufficient magnification and resolution to losophy may be applied:demonstrate that no detrimental oxides from the welding proc-ess are present along the weld line. AR — each test unit may consist of pipes from maximum 3 heats419 It shall be verified that the entire HAZ has been appro- — in case of test failure, the test frequency shall revert to thepriately heat treated over the full wall thickness and that no normal rate of testing until again 30 000 tons with satisfac-untempered martensite remains. tory results are documented.Hydrostatic test Re-testing420 The pipe shall withstand the hydrostatic test without 507 In order to accept or reject a particular test unit with anleakage through the weld seam or the pipe body. original test unit release failure, re-testing shall be conducted421 Linepipe that fails the hydrostatic test shall be rejected. in accordance with B508 through B512.AR 508 If a test fails to meet the requirements, two re-tests shall be performed (for the failed test only) on samples taken from422 For pipe classified as coiled tubing, the hydrostatic test two different pipes within the same test unit. Both re-tests shallof the finished coiled tubing shall be performed at a pressure meet the specified requirements. The test unit shall be rejectedcorresponding to 100% of SMYS calculated in accordance if one or both of the re-tests do not meet the specified require-with the Von Mises equation and considering 95% of the nom- ments.inal wall thickness. Test pressure shall be held for not less thantwo hours. AR 509 The reason for the failure of any test shall be established and the appropriate corrective action to prevent re-occurrenceSurface condition, imperfections and defects of the test failures shall be taken accordingly.423 Requirements to visual examination performed at the 510 If a test unit has been rejected, the Manufacturer mayplate mill are given in Appendix D, Subsection G. Require- conduct individual testing of all the remaining pipes in the testments for visual inspection of welds and pipe surfaces are unit. If the total rejection of all the pipes within one test unitgiven in Appendix D H500. MR and AR exceeds 25%, the test unit shall be rejected. In this situation theDimensions, mass and tolerances Manufacturer shall investigate and report the reason for failure424 Requirements to dimensions, mass and tolerances shall and shall change the manufacturing process if required. Re-be as given in Subsection G. qualification of the MPS is required if the agreed allowable variation of any parameter is exceeded (see A609 and A610).Weldability 511 Re-testing of failed pipes shall not be permitted. If a pipe425 If agreed, the Manufacturer shall supply weldability data fails due to low CVN values in the fusion line (HAZ) or weldor perform weldability tests. The details for carrying out the line in HFW pipe, testing of samples from the same pipe maytests and the acceptance criteria shall be as specified in the pur- be performed subject to agreement. Refer to B344 for re-chase order. processing of pipe.426 If requested, the linepipe supplier shall provide informa- 512 If the test results are influenced by improper sampling,tion regarding the maximum Post Weld Heat Treatment machining, preparation, treatment or testing, the test sample(PWHT) temperature for the respective materials. AR shall be replaced by a correctly prepared sample from the same pipe and a new test performed.B 500 Inspection Heat and product analysis501 Compliance with the requirements of the purchase ordershall be checked by specific inspection in accordance with EN 513 Heat and product analysis shall be performed in accord-10204. Records from the qualification of the MPS and other doc- ance with Appendix B. MRumentation shall be in accordance with the requirements in 514 If the value of any elements, or combination of elementsSec.12. fails to meet the requirements, two re-tests shall be performed DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 73on samples taken from two different pipes from the same heat. with Subsection E. MRIf one or both re-tests still fail to meet the requirements, theheat shall be rejected. MR Non-destructive testingMechanical testing 518 NDT, including visual inspection, shall be carried out in accordance with Subsection F. AR and MR515 All mechanical testing shall be performed according toAppendix B. MR Dimensional testingMetallurgical testing 519 Dimensional testing shall be performed according to516 Macro examination and metallographic examination Subsection G. MRshall be performed in accordance with Appendix B. Treatment of surface imperfections and defectsHydrostatic test (mill pressure test) 520 Surface imperfections and defects shall be treated517 Hydrostatic testing shall be performed in accordance according to Appendix D H300. MRTable 7-7 Inspection frequency for C-Mn steel linepipe during production 1 ,2)Applicable Type of test Frequency of testing Acceptance criteriato:All pipe Heat analysis One analysis per heat Table 7-3 or Table 7-4 Product analysis Two analyses per heat (taken from separate product items) Tensile testing of the pipe body Once per test unit of not more than 50/1003) pipes with Table 7-5 the same cold-expansion ratio4) CVN impact testing of the pipe body of Once per test unit of not more than 50/1005) pipes with Table 7-5 and Table 7-6 pipe with specified wall thickness as the same cold-expansion ratio4) given in Table 22 of ISO 3183 Hardness testing Once per test unit of not more than 50/1003) pipes with Table 7-5 the same cold-expansion ratio4) (AR) Hydrostatic testing Each pipe B420 to B422 Pipe dimensional testing See Subsection G See Subsection G NDT including visual inspection See Subsection F (MR and AR) See Subsection F (MR and AR)SAWL, Tensile testing of the seam weld (cross Once per test unit of not more than 50/1006) pipes with B406 and B407SAWH, weld test) the same cold-expansion ratio4) (MR)HFW CVN impact testing of the seam weld Once per test unit of not more than 50/1005) pipes with Table 7-5 and Table 7-6 of pipe with specified wall thickness as the same cold-expansion ratio4) (MR) given in Table 22 of ISO 3183 Hardness testing of hard spots Any hard spot exceeding 50 mm in any direction Appendix D H500 Macrographic testing of seam weld At least once per operating shift7) B416SAWL, Guided-bend testing of the seam weld Once per test unit of not more than 50/1003) pipes with B414SAWH of welded pipe the same cold-expansion ratio4) (MR)HFW Flattening test As shown in Figure 6 of ISO 3183 B412 and B413 Metallographic examination At least once per operating shift7) B418 (MR)Notes1) Sampling of specimens and test execution shall be performed in accordance with Appendix B. For tensile, CVN, hardness, guided-bend and flattening testing Appendix B refers to ISO 3183 without additional requirements.2) The number orientation and location of test pieces per sample for mechanical tests shall be in accordance with Table 7-9.3) Not more than 100 pipes with D ≤ 508 mm and not more than 50 pipes for D > 508 mm.4) The cold-expansion ratio is designated by the Manufacturer, and is derived using the designated before-expansion outside diameter or circumference and the after-expansion outside diameter or circumference. An increase or decrease in the cold-expansion ratio of more than 0.002 requires the creation of a new test unit (for lined pipe this does not apply to the liner expansion process).5) Not more than 100 pipes with 114.3 mm ≤ D ≤ 508 mm and not more than 50 pipes for D > 508 mm.6) Not more than 100 pipes with 219.1 mm ≤ D < 508 mm and not more than 50 pipes for D > 508 mm.7) At least once per operating shift plus whenever any change of pipe size occurs during the operating shift. If qualified alternative methods for detection of misalignments is used, testing is only required at the beginning of the production of each combination of specified outside diameter and specified wall thickness.whereD = Specified outside diameter DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 74 – Sec.7 see note on front coverTable 7-8 Additional testing for Manufacturing Procedure Qualification Test for C-Mn steel pipe 1)Applicable to: Type of test Extent of testing Acceptance criteriaAll pipe All production tests as stated in Table 7-7 One test for each pipe pro- See Table 7-7SMLS pipe 2, 3) with t > CVN testing at ID of quenched and tempered seamless vided for manufacturing4) Table 7-5 and Table 7-625 mm pipe with t > 25 mm AR procedure qualificationWelded pipe (all types) All weld tensile test AR Table 7-5 8) Fracture toughness (CTOD) test of weld metal 5, 6) AR B415 Ageing test 7), see A606 AR Table 7-5Notes1) Sampling of specimens and test execution shall be performed in accordance with Appendix B.2) Only applicable to pipe delivered in the quenched and tempered condition.3) Sampling shall be 2 mm from the internal surface, see Appendix B, A500.4) Two pipes from two different test units shall be selected for the MPQT, see A600.5) CTOD testing is not required for pipes with t < 13 mm.6) For HFW pipe the testing applies to the fusion line (weld centre line).7) Only when cold forming during pipe manufacture exceeds 5% strain.8) Only SMYS, SMTS and elongation applies.wheret = specified nominal wall thicknessTable 7-9 Number, orientation, and location of test specimens per tested pipe 1, 2)Applicable to: Sample location Type of test Wall thickness ≤ 25 mm > 25 mm Specified outside diameter Specified outside diameter < 219.1 mm ≥ 219.1 mm < 219.1 mm ≥ 219.1 mmSMLS, not cold Pipe body Tensile 1L3) 1L 1L3) 1Lexpanded pipe CVN 3T 3T 3T 3T Hardness 1T 1T 1T 1TSMLS, cold expanded Pipe body Tensile 1L3) 1T4) 1L3) 1T4)pipe CVN 3T 3T 3T 3T Hardness 1T 1T 1T 1THFW pipe Pipe body Tensile 1L903) 1T1804) 1L903) 1T1804) CVN 3T90 3T90 3T90 3T90 Seam weld Tensile — 1W — 1W CVN 3W and 3HAZ 5) MR 6W and 6HAZ 5) MR Hardness 1W 1W 1W 1W Pipe body and weld Flattening As shown in Figure 6 of ISO 3183SAWL pipe Pipe body Tensile 1L903) 1T1804) 1L903) 1T1804) CVN 3T90 3T90 3T90 3T90 Seam weld Tensile — 1W — 1W CVN 3W and 6HAZ 6) MR 6W and 12HAZ 6) MR Guided-bend 2W 2W 2W 2W Hardness 1W 1W 1W 1WSAWH pipe Pipe body Tensile 1L3) 1T4) 1L3) 1T4) CVN 3T 3T 3T 3T Seam weld Tensile — 1W — 1W CVN 3W and 6HAZ 6) MR 6W and 12HAZ 6) MR Guided-bend 2W 2W 2W 2W Hardness 1W 1W 1W 1WNotes1) See Figure 5 of ISO 3183 for explanation of symbols used to designate orientation and location.2) All destructive tests may be sampled from pipe ends.3) Full-section longitudinal test pieces may be used at the option of the manufacturer, see Appendix B.4) If agreed, annular test pieces may be used for the determination of transverse yield strength by the hydraulic ring expansion test inaccordance with ASTM A370.5) For the HF weld seam, W means that the notch shall be located in the FL, while HAZ means that the notch shall be located in FL +2 (see Figure 6 in Appen-dix B).6) HAZ means that the notch shall be located in FL and FL +2 (see Figure 5 in Appendix B). DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 75 C. Corrosion Resistant Alloy (CRA) Linepipe Supply conditions 305 Duplex and austenitic stainless steel pipe shall be deliv-C 100 General ered in solution-annealed and water-quenched condition.101 All requirements of this subsection are applicable towelded and seamless linepipe in duplex stainless steel and C 400 Acceptance criteriaseamless martensitic 13Cr stainless steel. Chemical composition102 Austenitic stainless steel and nickel based CRA linepipe 401 The chemical composition of duplex stainless steel andshall be supplied in accordance with a recognised standard that martensitic 13Cr stainless steel parent materials shall bedefines the chemical composition, mechanical properties, according to Table 7-10. Modifications are subject to agree-delivery condition and all the details listed in Sec.6 and as ment. The limits and tolerances for trace elements for marten-specified in the following. If a recognised standard is not avail- sitic 13Cr stainless steels, i.e. elements not listed in Table 7-10,able, a specification shall be prepared that defines these shall be subject to agreement.requirements. Mechanical propertiesC 200 Pipe designation 402 Requirements for tensile, hardness and Charpy V-notch201 CRA linepipe to be used to this standard shall be desig- properties are given in Table 7-11. Weldment shall meet thenated with: requirement for KVT impact properties. 403 In addition to the requirements in C404 and C405 below,— DNV the following acceptance criteria given for C-Mn steel pipe are— process of manufacture (see A300) also applicable to CRA pipe (as applicable):— grade (see Table 7-10 or C102, as applicable)— supplementary requirement suffix (see A400). — B407 for transverse weld tensile testing — B410 and 411 for Charpy V-notch impact testing Guidance note: — B414 for guided-bend testing e.g. “DNV SMLS 22Cr D” designates a seamless 22Cr duplex — B415 for fracture toughness testing of the seam weld. steel linepipe meeting the supplementary requirements for enhanced dimensional requirements. 404 For the flattening test of pipe with wall thickness ≥ 12.7 ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- mm, there shall be no opening of the weld, including the HAZ, until the distance between the plates is less than 66% of the original outside diameter. For pipe with wall thicknessC 300 Manufacture < 12.7 mm there shall be no opening of the weld, including theStarting material and steel making HAZ, until the distance between the plates is less than 50% of the original outside diameter.301 CRA linepipe shall be manufactured in accordance withthe processes given in A302 using the raw materials stated in 405 For pipe with a D/t2 > 10, there shall be no cracks orthe qualified MPS, follow the same activity sequence, and stay breaks other than in the weld, including the HAZ, until the dis-within the agreed allowable variations. The manufacturing tance between the plates is less than 33% of the original out-practice and instrumentation used to ensure proper control of side diameter.the manufacturing process variables and their tolerances shall Macro examination of weld seambe described in the MPS. 406 The macro examination of weld seam shall meet the302 All steels shall be made by an electric or one of the basic requirements in B416 and B417.oxygen processes. Microstructure of duplex stainless steelRequirements to manufacture of pipe 407 The material shall be essentially free from grain bound-303 In addition to the requirements in C304 and C305 below, ary carbides, nitrides and intermetallic phases after solutionthe following requirements given for C-Mn steel pipe are also heat treatment. Essentially free implies that occasional stringsapplicable for CRA pipes: of detrimental phases along the centreline of the base material is acceptable given that the phase content within one field of— B304-306 for seamless pipe vision (at 400X magnification) is < 1.0% (max. 0.5% interme-— B307-310 and B313-320 for all welded pipes tallic phases).— B321-326 for SAW and MWP pipe— B330-345 for all pipe. 408 The base material ferrite content of duplex stainless steel shall be within the range 35-55%. For weld metal and HAZ,304 Before further processing, the slabs/ingots shall be the ferrite content shall be within the range 35-65%.inspected and fulfil the surface finish requirements specified in Corrosion resistance of duplex stainless steelthe MPS. 409 The maximum allowable weight loss for 25Cr duplex stainless steel is 4.0 g/m2 for solution annealed material tested for 24 hours at 50°C. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 76 – Sec.7 see note on front coverTable 7-10 Duplex- and martensitic stainless steel linepipe, chemical compositionElement 1) Product analysis, wt.% Grade Grade Grade Grade 22Cr duplex 25Cr duplex 13Cr - 2 Mo 13Cr - 2.5 MoC 0.030 max 0.030 max 0.015 max 0.015 maxMn 2.00 max 1.20 max - -Si 1.00 max 1.00 max - -P 0.030 max 0.035 max 0.025 max 0.025 maxS 0.020 max 0.020 max 0.003 max 0.003 maxNi 4.50 - 6.50 6.00 – 8.00 4.50 min 6.00 minCr 21.0 - 23.0 24.0 – 26.0 12.0 min 12.0 minMo 2.50 – 3.50 3.00 – 4.00 2.00 min 2.50 minN 0.14 – 0.20 0.20 – 0.34 - -PRE - min. 40 2) - -Notes1) If other alloying elements than specified in this table are being used, the elements and the maximum content shall be agreed in each case.2) PRE = %Cr+3.3%Mo+16%N.Table 7-11 Duplex- and martensitic 13Cr stainless steel linepipe, mechanical propertiesGrade SMYS SMTS Ratio Maximum Elongation Charpy V-notch energy (KVT) 1) Hardness in 50.8 mm min. J, tested: at T0 = Tmin - 20°C for MPa MPa Rt0.5 / Rm 2) (HV10) Af duplex, and according to Table 7-6 for [%] martensitic 13Cr BM WM Mean Single HAZ22Cr 450 620 0.92 290 350 Note 3) 45 3525Cr 550 750 0.92 330 350 45 3513Cr-2 Mo 550 700 0.92 300 na 60 4513Cr-2.5 Mo 550 700 0.92 300 na 60 45Notes1) The required KVL (longitudinal direction specimens) values shall be 50% higher than the required KVT values.2) The YS/UTS ratio in the longitudinal direction shall not exceed the maximum specified value in the transverse direction by more than 0.020.3) Ref. Note 4) in Table 7-5.C 500 Inspection Retesting501 Compliance with the requirements of the purchase order 508 Requirements for retesting shall be according to B508 toshall be checked by specific inspection in accordance with EN B512.10204. Records from the qualification of the MPS and other Heat and product analysisdocumentation shall be in accordance with the requirements inSec.12. 509 Heat and product analysis shall be performed in accord- ance with Appendix B.Inspection frequency 510 All elements listed in the relevant requirement/ standard502 The inspection frequency during production and MPQT shall be determined and reported. Other elements added forshall be as given in Table 7-12 and Table 7-13, respectively. controlling the material properties may be added, subject toReference to the relevant acceptance criteria is given in the agreement.tables. 511 If the value of any elements, or combination of elements503 A test unit is a prescribed quantity of pipe that is made fails to meet the requirements, two re-tests shall be performedto the same specified outside diameter and specified wall on samples taken from two different pipes from the same heat.thickness, by the same pipe-manufacturing process, from the If one or both re-tests fail to meet the requirements, the heatsame heat, and under the same pipe-manufacturing conditions. shall be rejected.504 Sampling for mechanical and corrosion testing shall be Mechanical testingperformed after heat treatment, expansion and final shaping.The samples shall not be prepared in a manner that may influ- 512 All mechanical testing shall be performed according toence their mechanical properties. Refer to B506 for reduced Appendix B.frequency of testing in case of large quantities of pipe. Metallurgical testing505 The number and orientation of the samples for SMLS 513 Macro examination and metallographic examinationand SAWL/SAWH pipe shall be according to Table 7-9. shall be performed in accordance with Appendix B.506 For EBW and LBW pipe, the number and orientation of Corrosion testing of duplex stainless steelsthe samples shall be as for HFW in Table 7-9. 514 Corrosion testing of 25Cr duplex stainless steels accord-507 For MWP pipe, the number and orientation of the sam- ing to ASTM G48 shall be performed in accordance withples shall be as for SAWL pipe in Table 7-9. Appendix B B200. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 77Hydrostatic test (mill pressure test) Dimensional testing515 Hydrostatic testing shall be performed in accordance 517 Dimensional testing shall be performed according towith Subsection E. Subsection G.Non-destructive testing Treatment of surface imperfections and defects516 NDT, including visual inspection, shall be in accordance 518 Surface imperfections and defects shall be treatedwith Subsection F. according to Appendix D, H300.Table 7-12 Inspection frequency for CRA linepipe 1)Applicable to Type of test Frequency of testing Acceptance criteriaAll pipe All tests in Table 7-7 applicable to “All As given in Table 7-7 Table 7-10 and pipe” Table 7-11SAWL and MWP pipe All tests in Table 7-7 applicable to “SAWL”EBW and LBW pipe 2) Flattening test As shown in Figure 6 of ISO 3183 C404 and C405Duplex stainless steel pipe Metallographic examination Once per test unit of not more than 50/100 3) C407 and C40825Cr duplex stainless steel pipe Pitting corrosion test (ASTM G48) Once per test unit of not more than 50/100 3) C409Notes1) Sampling of specimens and test execution shall be performed in accordance with Appendix B. The number orientation and location of test pieces per sample for mechanical tests shall be according to C505-507.2) For EBW and LBW pipes the testing applies to the fusion line.3) Not more than 100 pipes with 114.3 mm ≤ D ≤ 508 mm and not more than 50 pipes for D > 508 mm.whereD = Specified outside diameterTable 7-13 Additional testing for Manufacturing Procedure Qualification Test of CRA linepipe 1)Applicable to Type of test Frequency of testing Acceptance criteriaAll pipe All production tests as stated above One test for each pipe provided for Subsection CWelded pipe (all types) All weld tensile test manufacturing procedure qualification Table 7-11 3) Fracture toughness (CTOD) test of weld metal 2) B415Notes1) Sampling of specimens and test execution shall be performed in accordance with Appendix B. The number, orientation and location of test pieces per sample for mechanical tests shall be according to C505-507.2) CTOD testing is not required for pipes with t < 13 mm.3) Two pipes shall be provided for MPQT. The two pipes provided shall be from two different test units. D. Clad or Lined Steel Linepipe (see A303 to A305) clad/lined pipes shall be designated with:D 100 General — C, for clad pipe, or — L, for lined pipe101 The requirements below are applicable to linepipe con- — UNS number for the cladding material or liner pipe.sisting of a C-Mn steel backing material with a thinner internalCRA layer. Guidance note:102 Linepipe is denoted "clad" if the bond between the back- e.g. “DNV SAWL 415 D C - UNS XXXXX” designates a longi-ing material and internal CRA layer is metallurgical, and tudinal submerged arc welded pipe, with SMYS 415 MPa, meet-"lined" if the bond is mechanical. ing the supplementary requirements for dimensions, clad with a UNS designated material.103 The backing steel of lined pipe shall fulfil the require-ments in Subsection B. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---104 The manufacturing process for clad or lined linepipe D 300 Manufacturing Procedure Specificationshall be according to A303 to A305. MPS for clad linepipe105 Cladding and liner materials shall be specified accordingto recognised standards. If a recognised standard is not availa- 301 In addition to the applicable information given in A600,ble, a specification shall be prepared that defines chemical the MPS for clad linepipe shall as a minimum contain the fol-composition. If agreed corrosion testing and acceptance crite- lowing information (as applicable):ria shall be specified. — slab reheating temperature and initial rolling practice of106 The cladding/liner material thickness shall not be less cladding alloy and backing material prior to sandwichthan 2.5 mm, unless otherwise agreed. assembly — method used to assemble the sandwich or one-sided-openD 200 Pipe designation package, as applicable, prior to reheating and rolling201 In addition to the designation of the backing material — package (sandwich or one-side-open) reheating tempera- DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 78 – Sec.7 see note on front cover ture, start and stop rolling temperatures, means of temper- Welding of clad linepipe ature and thickness control, start and stop temperatures for 411 In addition to the applicable requirements given in B307 accelerated cooling (if applicable) and inspection to B331, the following requirements shall apply for welding of— final plate heat treatment, e.g. quench and tempering (if clad linepipe: applicable)— method used to cut and separate the metallurgically roll — the corrosion properties of the CRA weld consumable (e.g. bonded plates after rolling (separation of the sandwich root and hot pass) shall be equal or superior to the clad between the CRA layers material— details regarding any CRA clad welding to pipe ends. — the longitudinal weld shall be back purged with welding grade inert gas and be free from high temperature oxidesMPS for lined linepipe — tack welds shall be made using GTAW, GMAW, G-302 In addition to the applicable information given in A600, FCAW or SMAW using low hydrogen electrodesthe MPS for lined linepipe shall as a minimum contain the fol- — weld seam tracking of continuous welding shall be auto-lowing information (as applicable): matically controlled.— details for fabrication of backing pipe and liner General requirements to manufacture of lined linepipe— quality control checks for the lining process 412 The liner pipe shall be manufactured according to— details of data to be recorded (e.g. expansion pressure/ API 5LC. force, strain, deformation) 413 The internal surface of the C-Mn steel backing pipe shall— procedure for cut back prior to seal welding or cladding to be blast cleaned to a surface cleanliness of ISO 8501 Sa2 along attach liner to carrier pipe the complete length of the pipe prior to fabrication of lined— seal welding procedures pipe. The external surface of the liner pipe shall be blast— details regarding any CRA clad welding to pipe ends. cleaned as specified above or pickled. 414 The liner pipe shall be inserted into the backing C-Mn303 The following additional essential variable applies to the steel pipe after both pipes have been carefully cleaned, driedqualification of the MPS for clad linepipe (see A609): and inspected to ensure that the level of humidity and particles— sequence of welding. in the annular space between these two pipes are equal to or less than for the MPQT pipes.D 400 Manufacture 415 The humidity during assembly shall be less than 80%,401 During all stages of manufacturing, contamination of and the carbon steel and CRA surfaces shall be maintained atCRA with carbon steel shall be avoided. Direct contact of the least 5°C above the dewpoint temperature. Temperature andCRA layer with carbon steel handling equipment (e.g. hooks, humidity shall continuously be measured and recorded.belts, rolls, etc.) is prohibited. Direct contact may be allowed 416 After having lined up the two pipes, the liner shall beproviding subsequent pickling is performed. expanded by a suitable method to ensure adequate gripping. The carbon steel pipe shall not under any circumstances402 All work shall be undertaken in clean areas and control- receive a sizing ratio, sr , exceeding 0.015 during the expansionled environment to avoid contamination and condensation. process (See B332).403 In addition to the requirements stated in B300 and C300 Welding of lined linepipe(as applicable), the following shall apply: 417 The liner pipe shall be welded according to API 5LC.Welding consumables 418 Subsequent to expansion, the liner or backing pipe shall404 The welding consumables for seam welds and liner seal be machined at each end and further fixed to the backing pipewelds shall be selected taking into consideration the reduction by a seal weld (clad or fillet weld, respectively) to ensure thatof alloying elements by dilution of iron from the base material. no humidity can enter the annulus during storage, transporta-The corrosion properties of the weld consumable shall be equal tion and preparation for installation.to or superior to the clad or liner material. 419 In addition to the applicable requirements given in B307General requirements to manufacture of clad linepipe to B331, the following requirements shall apply for welding of405 The cladding alloy shall be produced from plate, and lined linepipe:shall be supplied in a solution or soft annealed condition, asapplicable. — the corrosion properties of the CRA weld consumable (e.g. fillet or clad weld) shall be equal or superior to the liner406 The steel backing material and the cladding alloy shall materialbe cleaned, dried and inspected to ensure that the level of — the weld shall be purged with welding grade inert gas andhumidity and particles between the respective plates are equal be free from high temperature oxides.to or less than for the MPQT plates. D 500 Acceptance criteria407 Unless otherwise agreed, the mating plate surfaces shallas a minimum be blast cleaned to a surface cleanliness of ISO Properties of the backing material8501 Sa2. 501 The backing material of the manufactured clad or lined408 A pre-clad rolling assembly procedure shall be part of linepipe shall comply with the requirements for C-Mn steelthe MPS. This procedure shall include details of all surface given in Subsection B. Sour service requirements according topreparation to be performed just prior to the sandwich assem- I100 shall not apply to the backing material unless requiredbly (if applicable). according to I115.409 The sandwich or one-side-open packages, as applicable, 502 The cladding/liner material shall be removed from theshall be hot rolled in order to ensure metallurgical bonding test pieces prior to mechanical testing of the backing material.between the base and the cladding material. Hardness410 The package consisting of sandwich or one-side-open, 503 The hardness of the base material, cladding material,shall be manufactured through a TMCP route, or receive a final HAZ, weld metal and the metallurgical bonded area shall meetheat treatment (e.g. quench and tempering). the relevant requirements of this standard. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 79Bonding strength of clad linepipe ing of the liner pipe shall be according to API 5LC.504 After bend testing in accordance with Appendix B A906 Retesting(see Table 7-14), there shall be no sign of cracking or separa- 605 Requirements for retesting shall be according to B508 totion on the edges of the specimens. B512.505 After longitudinal weld root bend testing in accordance Heat and product analysiswith Appendix B A607 (see Table 7-15), the bend test speci-men shall not show any open defects in any direction exceed- 606 Heat and product analysis shall be performed in accord-ing 3 mm. Minor ductile tears less than 6 mm, originating at the ance with B500 and C500 for the backing steel and the CRAspecimen edge may be disregarded if not associated with obvi- liner or cladding, respectively.ous defects. Mechanical testing506 The minimum shear strength shall be 140 MPa. 607 All mechanical testing of clad pipe and the backing steelProperties of the CRA of clad and lined linepipe of lined pipe shall be performed according to Appendix B. Mechanical testing of the liner pipe shall be according to API507 The CRA material shall meet the requirements of the rel- 5LC.evant reference standard, e.g. API 5LD. 608 Hardness testing of welded linepipe shall be performedChemical composition of welds on a test piece comprising the full cross section of the weld.508 The chemical composition of the longitudinal seam weld Indentations shall be made in the base material, cladding mate-of clad pipes, pipe end clad welds, and the liner seal welds (if rial and the metallurgical bonded area as detailed inexposed to the pipe fluid), shall be analysed during MPQT. Appendix B.Unless otherwise agreed the composition of the deposited weld Corrosion testingmetal as analysed on the exposed surface shall meet therequirements of the base material specification. 609 Unless otherwise agreed, corrosion testing of roll bonded clad pipes or any longitudinal weld seams is notUnless otherwise agreed the calculated PRE (see Table 7-10, required.note no. 2) for alloy 625 weld metal shall not be less than forthe clad pipe base material or liner material. Metallurgical testingMicrostructure 610 Macro examination and metallographic examination shall be performed in accordance with Appendix B.509 The weld metal and the HAZ in the root area of the cladpipe seam welds, any pipe end clad welds and the seal welds of Liner collapse testlined pipe shall be essentially free from grain boundary car- 611 To check for the presence of moisture in the annulusbides, nitrides and intermetallic phases. between the liner and the backing material, one finished pipeGripping force of lined linepipe or a section thereof (minimum length of 6 m) shall be heated to510 Acceptance criteria for gripping force production testing 200°C for 15 minutes and air cooled. This pipe shall be within the first 10 pipes produced.shall be agreed based on project specific requirements (seeSec.6 B400) and/or test results obtained during MPQT. Gripping force testLiner collapse 612 Gripping force of lined pipe shall be measured in511 After the test for presence of moisture in the annulus accordance with API 5LD. Equivalent tests may be appliedbetween the liner and the backing material, the pipe shall be subject to agreement. Inspection frequency for production test-inspected and no ripples or buckles in the liner or carbon steel ing shall be agreed based on test results obtained during thepipe shall be in evidence when viewed with the naked eye. MPQT (see D300). Hydrostatic test (mill pressure test)D 600 Inspection 613 Hydrostatic testing shall be performed in accordance601 Compliance with the requirements of the purchase order with Subsection E.shall be checked by specific inspection in accordance with EN10204. Records from the qualification of the MPS and other docu- Non-destructive testingmentation shall be in accordance with the requirements in Sec.12. 614 NDT, including visual inspection, shall be in accordanceInspection frequency with Subsection F.602 The inspection frequency during production and MPQT Dimensional testingshall be as given in Table 7-14 and Table 7-15, respectively. 615 Dimensional testing shall be performed according to603 For clad pipe, the number and orientation of the samples Subsection G.shall be as for SAWL pipe in Table 7-9 Treatment of surface imperfections and defects604 For lined pipe, the number and orientation of the sam- 616 Surface imperfections and defects shall be treatedples for the backing steel shall be according to Table 7-9. Test- according to Appendix D, H300.Table 7-14 Additional production testing for clad or lined steel linepipeApplicable to Type of test Extent of testing Acceptance criteriaAll pipe All tests in Table 7-7 applicable to “All pipe” See Table 7-7 and D600 D501Clad pipe All tests in Table 7-7 applicable to “SAWL” Bend tests (2 specimens) Once per test unit of not more than 50 pipes D505 Shear strength D507CRA material of According to reference standard (see D508clad pipeLiner pipe According to API 5LC (see D508)Lined pipe Macrographic examination of seal weld Once per test unit of not more than 50 pipes Appendix C, F405 Gripping force test To be agreed, see D612 D511 DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 80 – Sec.7 see note on front coverTable 7-15 Additional testing for Manufacturing Procedure Qualification Test of clad or lined steel linepipe 1)Applicable to Type of test Extent of testing Acceptance criteriaAll pipe All production tests in Table 7-14 One test for each pipe See Table 7-14 Corrosion testing of welds, if agreed, see D609 provided for manufac- To be agreed 2) turing procedure quali-Clad pipe Chemical composition of seam weld and clad weld fication D508 Metallographic examination of the seam weld and clad weld 2) D509 Longitudinal weld root bend test D505Lined pipe Chemical composition of seal or clad welds 2) D508 Metallographic examination of seal welds D509 Liner collapse test D511Notes1) Sampling of specimens and test execution shall be performed in accordance with Appendix B. The number, orientation and location of test pieces per sample for mechanical tests shall be according to D603-604.2) As applicable, according to D508 and D509. E. Hydrostatic Testing than pressure containment, or significant temperature de-rating of the mechanical properties take place, the mill test pressureE 100 Mill pressure test may be significantly higher than the incidental pressure. For101 Each length of linepipe shall be hydrostatically tested, such conditions and where the mill pressure test capacity isunless the alternative approach described in E107 is used. limited, the mill test pressure may be limited to ph= 1.4·pli, (where pli is the local incidental pressure).102 The test pressure (ph) shall, in situations where the sealis made on the inside or the outside of the linepipe surface, be 106 The test configuration shall permit bleeding of trappedconducted at the lowest value obtained by utilising the follow- air prior to pressurisation of the pipe. The pressure test equip-ing formulae: ment shall be equipped with a calibrated recording gauge. The applied pressure and the duration of each hydrostatic test shall 2 ⋅ tmin be recorded together with the identification of the pipe tested.ph = ------------------- ⋅ min [ SMYS ⋅ 0.96 ;SMTS ⋅ 0.84 ] - (7.2) The equipment shall be capable of registering a pressure drop D – t min of minimum 2% of the applied pressure. The holding time at test pressure shall be minimum 10 seconds. Calibration records103 103In situations where the seal is made against the end for the equipment shall be available.face of the linepipe by means of a ram or by welded on endcaps, and the linepipe is exposed to axial stresses, the test pres- 107 Subject to agreement, the hydrostatic testing may besure shall be calculated such that the maximum combined omitted for expanded pipes manufactured by the UOE process.stress equals: It shall in such situations be documented that the expansion process and subsequent pipe inspection will: (7.3)s e = min [ SMYS ⋅ 0.96 ;SMTS ⋅ 0.84 ] — ensure that the pipe material stress-strain curve is linear upbased on the minimum pipe wall thickness tmin. to a stress corresponding to E102 — identify defects with the potential for through-thickness Guidance note: propagation under pressure loading The Von Mises Equivalent stress shall be calculated as: — identify pipes subject to excessive permanent deformation under pressure loading to a degree equivalent to that pro- 2 2 vided by hydrostatic testing. se = s h + s l –s h ⋅ s l Workmanship and inspection shall be at the same level as for where hydrostatically tested pipe. The expansion process parameters and inspection results shall p h ⋅ ( D – t min ) s h = ---------------------------------- - be recorded for each pipe. 2 ⋅ t min N = True pipe wall force which depend on the test set up end restraints. F. Non-destructive Testing F 100 Visual inspection N- s l = ---- As 101 Visual inspection shall be in accordance with Appendix D H500. (tmin is equivalent to t1 in Sec.5) 102 If visual inspection for detection of surface imperfec- tions is substituted with alternative inspection methods then ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- the substitution shall conform to the requirements in Appendix104 For pipes with reduced pressure containment utilisation, D H505 and H506.the test pressure (ph) may be reduced as permitted in F 200 Non-destructive testingSec.5 B200. 201 Requirements for Non-Destructive Testing (NDT) of105 In case significant corrosion allowance has been speci- linepipe are given in Appendix D, Subsection H.fied (as stated by the Purchaser in the material specification),or a large wall thickness is needed for design purposes other 202 Requirements for NDT (laminar imperfections) and vis- ual examination of plate, coil and strip performed at plate mill DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 81are given in Appendix D, Subsection G. the discretion of the Manufacturer.203 Table 7-16 lists the required NDT of linepipe including 204 Alternative test methods may be accepted subject tolamination check for welded linepipe. For welded pipe, lami- agreement according to Appendix D, H401 and H402.nation checks may be performed on linepipe or plate/strip atTable 7-16 Type and extent of non-destructive testing 1)Applicable to Scope of testing Type of test 2) Extent of testing Reference (Appendix D)All Visual inspection - 100% H500 Residual magnetism - 5% 3) H500 Imperfections in un-tested ends UT+ST 100% or cut off H600Pipe ends of all Laminar imperfections pipe ends 4) UT 100% H700pipe Laminar imperfections pipe end face/bevel ST 100%SMLS Laminar imperfections in pipe body UT 100% H800 Longitudinal imperfections in pipe body UT 100% Transverse imperfections in pipe body UT 100/10% 6) Wall thickness testing UT 100% 7) Longitudinal surface imperfections in pipe body 5) ST 100/10% 6)HFW, EBW Laminar imperfections in pipe body UT 100% H900and LBW Laminar imperfections in area adjacent to weld UT 100% Longitudinal imperfections in weld UT 100%SAWL, Laminar imperfections in pipe body UT 100% H1300SAWH and Laminar imperfections in area adjacent to weld UT 100%MWP Imperfections in weld UT 100% Surface imperfections in weld area 5) ST 100%/R 8) Imperfections at weld ends RT 100%Clad pipe Lack of bonding in pipe body and pipe ends 9) UT 100% H1200 Laminar imperfections in pipe body UT 100% Longitudinal and transverse imperfections in weld UT 100% Laminar imperfections in area adjacent to weld UT 100% Surface imperfections in weld area ST 100% Imperfections in welds RT 100%CRA liner pipe Longitudinal and transverse imperfections in weld EC or RT 100% H1000Lined pipe As required for the type of backing material used, see above - 100% - Seal and clad welds ST 100% H1100 Clad welds (bonding imperfections) UT 100%Notes1) The indicated test methods are considered to be industry standard. Alternative methods may be used as required in Appendix D, H400.2) Nomenclature: UT = ultrasonic testing, ST = surface testing, e.g. magnetic particle testing or EMI (flux leakage) for magnetic materials and liquid pene- trant testing for non-magnetic materials, RT = radiographic testing and EC = eddy current testing, see Appendix D.3) 5% = testing of 5% of the pipes produced but minimum 4 pipes per 8-hour shift.4) Laminar inspection is not applicable to pipe with t ≤ 5 mm. Standard width of band to be tested is 50 mm, but a wider band may be tested if specified by the Purchaser.5) Applicable to external surface only.6) 100/10% = 100% testing of the first 20 pipes manufactured and if all pipes are within specification, thereafter random testing (minimum five pipes per 8- hour shift) during the production of 10% of the remaining pipes.7) The wall thickness shall be controlled by continuously operating measuring devices.8) 100%/R = 100% testing of the first 20 pipes manufactured. If all pipes are within specification, thereafter random testing of a minimum of one pipe per 8-hour shift.9) Applies to pipe ends irrespective if clad welds are applied to pipe ends or not. G. Dimensions, Mass and Tolerances defects have been completely removed by grinding, in accord- ance with Appendix D, H300, the minus tolerances for diame-G 100 General ter and out-of-roundness tolerances shall not apply in the101 Linepipe shall be delivered to the dimensions specified in ground area.the material specification, subject to the applicable tolerances. 202 The wall thickness shall be within the tolerances given in Table 7-18.102 The pipe shall be delivered in random lengths or approx-imate length, as specified in the material specification. 203 Geometric deviations, pipe straightness, end squareness and weight shall be within the tolerances given in Table 7-19.G 200 Tolerances 204 Unless otherwise agreed, the minimum average length201 The diameter and out-of-roundness shall be within the of pipe shall be 12.1 m, and the tolerances for length accordingtolerances given in Table 7-17. However, in areas where to Table 7-19. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 82 – Sec.7 see note on front coverTolerances for the weld seam 306 The pipe body out-of-roundness shall be determined as205 Tolerances for the weld seam of welded pipe, i.e.: the difference between the largest and smallest outside diame- ter, as measured in the same cross-sectional plane.— cap reinforcement MR* 307 The wall thickness at any location shall be within the tol-— root penetration MR* erances specified in Table 7-18, except that the weld area shall— cap and root concavity not be limited by the plus tolerance. Wall thickness measure-— radial offset ments shall be made with a mechanical calliper or with a prop-— misalignment of weld beads for double sided welds erly calibrated non-destructive inspection device of— waving bead (dog-leg) appropriate accuracy. In case of dispute, the measurement— undercut determined by use of the mechanical calliper shall govern. The— arc burns mechanical calliper shall be fitted with contact pins having cir-— start/stop craters/poor restart cular cross sections of 6.35 mm in diameter. The end of the pin— surface porosity contacting the inside surface of the pipe shall be rounded to a— cracks maximum radius of 38.1 mm for pipe of size 168.3 mm or— lack of penetration/lack of fusion larger, and up to a radius of d/4 for pipe smaller than size 168.3— systematic imperfections mm with a minimum radius of 3.2 mm. The end of the pin con-— burn through. tacting the outside surface of the pipe shall be either flat or rounded to a radius of not less than 38.1 mm.shall be within the tolerances given in Appendix D, Table D-4. 308 Geometric deviations from the nominal cylindrical con-*) MR indicates that the requirement is modified compared to tour of the pipe, see Table 7-19, resulting from the pipe form-ISO 3183. ing or manufacturing operations (i.e. not including dents), shall be measured using a gauge with the correct curvature accord-206 Requirements for dents are given in Appendix D, H500. ing to the specified internal/external diameter. The length ofG 300 Inspection the gauge shall be 200 mm or 0.25 D, whichever is less.301 The frequency of dimensional testing shall be according Internal measurements shall be taken within 50 mm of eachto Table 7-17 to Table 7-19. pipe end. External measurement shall be taken where indicated by visual302 Suitable methods shall be used for the verification ofconformance with the dimensional and geometrical tolerances. inspection. MR (the requirement is modified compared to ISOUnless particular methods are specified in the purchase order, 3183).the methods to be used shall be at the discretion of the Manu- 309 Straightness shall be measured according to Figure 1facturer. and Figure 2 in ISO 3183.303 All test equipment shall be calibrated. Dimensional test- 310 Out-of squareness at pipe ends shall be measureding by automatic measuring devices is acceptable provided the according to Figure 3 in ISO 3183.accuracy of the measuring devices is documented and found to 311 For pipe with D ≥ 141.3 mm, the lengths of pipe shall bebe within acceptable limits. weighed individually. For pipe with D < 141.3 mm, the lengths304 Unless a specific method is specified in the purchase of pipe shall be weighed either individually or in convenientorder, diameter measurements shall be made with a circumfer- lots selected by the Manufacturer.ential tape, ring gauge, snap gauge, rod gauge, calliper, or opti- 312 The mass per unit length, rl, shall be used for the deter-cal measuring device, at the discretion of the manufacturer. mination of pipe weight and shall be calculated using the fol- Guidance note: lowing equation: For inspection of submerged arc welded pipe, ring gauges can be rl = t(D-t) · C (7.4) slotted or notched to permit passage of the gauge over the weld reinforcement. It is necessary that the pipe permit the passage of where: the ring gauge within (internal) or over (external) each end of the pipe for a minimum distance of 100 mm. rl is the mass per unit length, in kg/m ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- D is the specified outside diameter, expressed in mm t is the specified wall thickness, in mm305 At pipe ends (unless otherwise agreed) inside measure- C is 0.02466.ments shall be used to determine diameter and out-of-round-ness. These measurements shall not be based on 313 All specified tests shall be recorded as acceptable orcircumferential measurements (e.g. tape). Out-of-roundness non-acceptable.shall be determined as the difference between the largest and 314 The minimum and maximum value for wall thicknesssmallest inside diameter, as measured in the same cross-sec- and the diameter of pipe ends and maximum out-of-roundnesstional plane. If agreed, tolerances may be applied to actual at pipe ends, shall be recorded for 10% of the specified tests,internal diameter. MR (the requirement is modified compared unless a higher frequency is agreed. For weight and lengthto ISO 3183). 100% of the actual measurement results shall be recorded. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 83Table 7-17 Tolerances for diameter and out-of-roundnessD [mm] Frequency Diameter Out-of-roundness of Pipe body 1) Pipe end 2, 3) inspection Pipe body 2) Pipe end 3) SMLS Welded SMLS Welded< 60.3 Once per ± 0.5 mm or ± 0.5 mm or ± 0.5 mm Included in the diameter tolerance 4) ± 0.0075 D, ± 0.0075 D,≥ 60.3 ≤ 610 test unit or ± 0.005 D, 0.015 D 0.01 D whichever is whichever is whichever is greater, greater greater, but max. but max. ± 1.6 mm ± 3.2 mm> 610 ≤ 1422 ± 0.01 D ± 0.005 D, but ± 2.0 mm ± 1.6 mm 0.01 D but max.10 mm 0.0075 D but max. 8 mm max. ± 4.0 mm for D/t2 ≤ 75 for D/t2 ≤ 75 By agreement for D/t2 > 75 By agreement for D/t2 > 75> 1422 as agreedwhereD = Specified outside diametert = specified nominal wall thickness.Notes1) Dimensions of pipe body to be measured approximately in the middle of the pipe length.2) For SMLS pipe, the tolerances apply for t ≤ 25.0 mm, and the tolerances for heavier wall pipe shall be as agreed.3) The pipe end includes a length of 100 mm at each of the pipe extremities.4) Once per test unit of not more than 20 lengths of pipe. For D ≤ 168.3 mm; once per test unit of not more than 100 lengths of pipe, but minimum one (1) and maximum 6 pipes per 8-hour shift. MRTable 7-18 Tolerances for wall thicknessType of pipe Wall thickness [mm] Frequency of Tolerances 1) inspection t < 4.0 + 0.6 mm - 0.5 mm 4.0 ≤ t < 10.0 + 0.15 t - 0.125 tSMLS 10.0 ≤ t < 25.0 ± 0.125 t + 0.1 t or + 3.7 mm, whichever is greater t ≥ 25.0 - 0.1 t or - 3.0 mm, whichever is greater t ≤ 6.0 ± 0.4 mmHFW, EBW, LBW and MWP 2) 6.0 < t ≤ 15.0 100% ± 0.7 mm t > 15.0 ± 1.0 mm t ≤ 6.0 ± 0.5 mm 6.0 < t ≤ 10.0 ± 0.7 mmSAW 3) 10.0 < t ≤ 20.0 ± 1.0 mm t > 20.0 + 1.5 mm - 1.0 mmwheret = specified nominal wall thickness.Notes1) If the purchase order specifies a minus tolerance for wall thickness smaller than the applicable value given in this table, the plus tolerance for wall thick- ness shall be increased by an amount sufficient to maintain the applicable tolerance range.2) Subject to agreement a larger plus tolerance for metallurgically clad pipes may be applied.3) The plus tolerance for wall thickness does not apply to the weld area.Table 7-19 Tolerances for pipe geometric properties not covered in Table 7-17 and 7-18Characteristic to be tested Frequency of inspection TolerancesGeometric deviations (peaking and flats) 1) 10% 2) 0.005 D or 2.5 mm, whichever is lessStraightness, max. for full length of pipe 5% 2) ≤ 0.0015 LStraightness, max. deviation for pipe end region 3) 3 mmOut-of squareness at pipe ends ≤ 1.6 mm from true 90°Length 100% min. 11.70 m and max. 12.70 mWeight of each single pipe / pipe bundle -3.5% / +10% of nominal weightTolerances for the pipe weld seam and dents see G205 and G206where L = actual length of pipeNotes1) Applicable to welded pipes only2) Testing of the required percentage of the pipes produced but minimum 4 pipes per 8-hour shift.3) The pipe end region includes a length of 1.0 m at each of the pipe extremities. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 84 – Sec.7 see note on front cover H. Marking, Delivery Condition and strain based design. Any restrictions for maximum allowable strain during operation are beyond the scope of this standard. Documentation ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---H 100 Marking C-Mn steel101 All marking shall be easily identifiable and durable inorder to withstand pipe loading, shipping, and normal installa- 103 C-Mn steel linepipe for sour service shall conform totion activities. Subsection B, and to the modified and additional requirements below, which conform to the requirements in ISO 3183 Annex102 Marking shall include DNV linepipe designation (ref. H: “PSL 2 pipe ordered for sour service”.B200, C200 and D200). Other type of marking shall be subjectto agreement. 104 The chemical compositions given in Table 7-3 and Table 7-4 shall be modified according to Table 7-20 and Table103 Each linepipe shall be marked with a unique number. 7-21, respectively.The marking shall reflect the correlation between the productand the respective inspection document. Table 7-20 Chemical composition for SMLS and welded C-Mn steel pipe with delivery condition N or Q for SupplementaryH 200 Delivery condition requirement, sour service201 The delivery condition of C-Mn steel pipe shall be Product analysis, maximum. weight %according to Table 7-1. SMYS202 The internal surface of CRA pipes shall be pickled in C 1) Mn 1) S 2) V Other 3,4)accordance with the purchase order. If agreed the external sur- Pipe with delivery condition N - according to Table 7-1face of CRA pipes shall be cleaned. 245 - - 0.003 - - 290 - - 0.003 - -H 300 Handling and storage 320 - - 0.003 - -301 On customers request, each linepipe shall be protected 360 - - 0.003 - -until taken into use. Pipe with delivery condition Q - according to Table 7-1302 For temporary storage see Sec.6 D300. 245 - - 0.003 - - 290 - - 0.003 - -H 400 Documentation, records and certification 320 - - 0.003 - -401 Linepipe shall be delivered with Inspection Certificate 3.1 360 - - 0.003 - -according to European Standard EN 10204 (Metallic Products - 390 - - 0.003 - -Types of Inspection Documents) or an accepted equivalent. 415 - - 0.003 - Note 5,6)402 Inspection documents shall be in printed form or in elec- 450 - - 0.003 - Note 5,6)tronic form as an EDI transmission that conforms to any EDI 485 0.16 1.65 0.003 0.09 Notes 5,6,7)agreement between the Purchaser and the manufacturer. Notes403 The Inspection Certificate shall identify the productsrepresented by the certificate, with reference to product 1) For each reduction of 0.01% below the specified maximum for carbon, an increase of 0.05% above the specified maximum for manganese isnumber, heat number and heat treatment batch. The specified permissible, up to a maximum increase of 0.20%.outside diameter, specified wall thickness, pipe designation, 2) If agreed the sulphur content may be increased to ≤ 0.008% for SMLStype of pipe, and the delivery condition shall be stated. and ≤ 0.006% for welded pipe, and in such cases lower Ca/S may be404 The certificate shall include or refer to the results of all agreed.specified inspection, testing and measurements including any 3) Mo ≤ 0.15%. If agreed Cu ≤ 0.10%.supplementary testing specified in the purchase order. For 4) Unless otherwise agreed, for welded pipe where calcium is intention-HFW pipe, the minimum temperature for heat treatment of the ally added, Ca/S ≥ 1.5 if S > 0.0015%. For SMLS and welded pipeweld seam shall be stated. Ca ≤ 0.006%. 5) If agreed Mo ≤ 0.35%.405 Records from the qualification of the MPS and other 6) If agreed Cr ≤ 0.45% and Ni ≤ 0.50%.documentation shall be in accordance with the requirements inSec.12 C100. 7) The maximum allowable Pcm value shall be 0.22 for welded pipe and 0.25 for SMLS pipe. Table 7-21 Chemical composition for welded C-Mn steel pipe with delivery condition M for Supplementary requirement, I. Supplementary Requirements sour serviceI 100 Supplementary requirement, sour service (S) Product analysis, maximum. weight % SMYS C1) Mn 1) S 2) Nb Other 3,4)101 Linepipe for sour service shall conform to the requirementsbelow. Sec.6 B200 provide guidance for material selection. 245 0.10 - 0.002 - - 290 0.10 - 0.002 - -102 All mandatory requirements in ISO 15156-2/3 shall 320 0.10 - 0.002 - -apply, in combination with the additional requirements of thisstandard. 360 0.10 1.45 0.002 0.06 - 390 0.10 1.45 0.002 - - Guidance note: 415 0.10 1.45 0.002 - Note 5) ISO 15156-1/2/3, Sec. 1, states that the standard is only applica- ble “to the qualification and selection of materials for equipment 450 0.10 1.60 0.002 - Notes 5,6) designed and constructed using conventional elastic design crite- 485 0.10 1.60 0.002 - Notes 5,6) ria”. Any detrimental effects of induced strain will only apply if Notes these are imposed during exposure to an H2S-containing envi- ronment; hence, for manufacture and installation of pipelines the 1-5) See Table 7-20. restrictions imposed in the ISO standard are applicable also to 6) If agreed Cr ≤ 0.45%. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 85105 Vacuum degassing or alternative processes to reduce the Clad or lined steel linepipegas content of the steel should be applied. 114 Clad or lined steel or linepipe for sour service shall con-106 The molten steel shall be treated for inclusion shape control. form to Subsection D, and to the modified and additional107 The requirements for mechanical properties in B400 requirements below.shall apply, except for the hardness. 115 Materials selection for cladding/liner, the associated108 During MPQT and production, the hardness in the pipe hardness criteria, and requirements to manufacturing and fab-body, weld and HAZ shall not exceed 250 HV10. rication shall comply with ISO 15156-3. The same applies to welding consumables for weldments exposed to the internalIf agreed, (see ISO 15156-2) and provided the parent pipe wall fluid. For selection of the C-Mn steel base material the consid-thickness is greater than 9 mm and the weld cap is not exposed erations in A13.1 of ISO 15156-3 shall apply.directly to the sour environment, 275 HV10 is acceptable forthe weld cap area. 116 During qualification of welding procedures and produc- tion, hardness measurements shall be performed as outlined in109 Any hard spot larger than 50 mm in any direction, see Appendix B. The hardness in the internal heat-affected zoneTable 7-7, shall be classified as a defect if its hardness, based and in the fused zone of the cladding/lining shall comply withupon individual indentations, exceeds: relevant requirements of ISO 15156-3.— 250 HV10 on the internal surface of the pipe, or Specific inspection— 275 HV10 on the external surface of the pipe. 117 The frequency of inspection for shall be as given in Tables 7-7, 7-8, 7-12, 7-13, 7-14 and 7-15 as relevant, and withPipes that contain such defects shall be treated in accordance additional testing given in Table 7-22.with Appendix D H300. 118 HIC testing during production shall be performed on one110 The acceptance criteria for the HIC test shall be the fol- randomly selected pipe from each of the three (3) first heats, orlowing, with each ratio being the maximum permissible aver- until three consecutive heats have shown acceptable testage for three sections per test specimen when tested in Solution results. After three consecutive heats have shown acceptable(Environment) A (see Table B.3 of ISO 15156-2): test results, the testing frequency for the subsequent production may be reduced to one test per casting sequence of not more— crack sensitivity ratio (CSR) ≤ 2% than ten (10) heats.— crack length ratio (CLR) ≤ 15%, and— crack thickness ratio (CTR) ≤ 5%. 119 If any of the tests during the subsequent testing fail, three pipes from three different heats of the last ten heats,If HIC tests are conducted in alternative media (see selecting the heats with the lowest Ca/S ratio (based on heatAppendix B B302) to simulate specific service conditions, analysis), shall be tested, unless the S level is below 0.0015.alternative acceptance criteria may be agreed. For heat with S level greater than 0.0015 heats shall be selected with the lowest Ca/S ratio. Providing these three tests show111 By examination of the tension surface of the SSC speci- acceptable results, the ten heats are acceptable. However, ifmen under a low power microscope at X10 magnification there any of these three tests fail, then all the ten heats shall be tested.shall be no surface breaking fissures or cracks, unless it can be Further, one pipe from every consecutive heat shall be testeddemonstrated that these are not the result of sulphide stress until the test results from three consecutive heats have beencracking. found acceptable. After three consecutive heats have shownCRA linepipe acceptable test results, the testing frequency may again be112 CRA linepipe for sour service shall conform to Subsection reduced to one test per ten heats.C, and the recommendations given in Sec.6 B200 and D700. SSC test113 Linepipe grades, associated hardness criteria, and 120 If specified in the purchase order SSC testing shall berequirements to manufacturing/fabrication shall comply with performed in accordance with ISO 15156 2/3 as applicable.ISO 15156-3. (see Sec. 6 B409).Table 7-22 Applicable testing for Supplementary requirement S 1)Production testsType of pipe Type of test Extent of testing Acceptance criteriaWelded C-Mn steel pipe HIC test In accordance with I118 and I119 I110Tests for Manufacturing Procedure Qualification TestType of pipe Type of test Extent of testing Acceptance criteriaWelded C-Mn steel pipe HIC test If agreed, one test (3 test pieces) for each pipe provided I110All pipe (only if agreed, see SSC test for manufacturing procedure qualification I111Sec. 6 B202)Notes1) Sampling of specimens and test execution shall be performed in accordance with Appendix B.I 200 Supplementary requirement, fracture arrest 202 A Charpy V-notch transition curve shall be establishedproperties (F) for the linepipe base material. The Charpy V-notch energy201 The requirements to fracture arrest properties are valid value in the transverse direction at Tmin shall, as a minimum,for gas pipelines carrying essentially pure methane up to 80% meet the values given in Table 7-23. Five sets of specimensusage factor, up to a pressure of 15 MPa, 30 mm wall thickness shall be tested at different temperatures, including Tmin, andand 1120 mm diameter. the results documented in the qualification report.Testing shall be according to Table 7-24. Properties of pipe delivered without final heat treatment DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 86 – Sec.7 see note on front cover203 This paragraph does not apply to linepipes delivered formed on welded linepipe with outer diameter > 500 mm, wallwith a final heat treatment (e.g. normalising or quench and thickness > 8 mm and SMYS > 360 MPa. A DWTT transitiontempering). A Charpy V-notch transition curve shall be estab- curve shall be established for the linepipe base material. Mini-lished for the linepipe base material in the aged condition. The mum five sets of specimens shall be tested at different temper-plastic deformation shall be equal to the actual deformation atures, including Tmin. Each set shall consist of two specimensintroduced during manufacturing (no additional straining is taken from the same test coupon. The test shall be performedrequired). The samples shall be aged for 1 hour at 250°C. Five in accordance with Appendix B. The specimens tested at thesets of specimens shall be tested at different temperatures, minimum design temperature shall as a minimum, meet anincluding Tmin. The Charpy V-notch energy value in the trans- average of 85% shear area with one minimum value of 75%.verse direction, at Tmin, shall as a minimum, meet the values 205 If supplementary requirements for sour service as ingiven in Table 7-23 in the aged condition. Values obtained at I100 are specified for linepipe material with SMYS ≥ 450 MPaother test temperatures are for information. the acceptance criteria stated in I204 (average and minimum204 Drop Weight Tear Testing (DWTT) shall only be per- shear area) may be subject to agreement.Table 7-23 Charpy V-notch Impact Test Requirements for Fracture Arrest Properties tested at Tmin(Joules; Transverse Values; Average value of three full size base material specimens) 1, 2)Wall ≤ 30 mm 3)thickness OD (mm) NotesSMYS ≤ 610 ≤ 820 ≤ 1120 1) Minimum individual results to exceed 75% of245 40 40 40 these values, (max 1 specimen per set)290 40 43 52 2) The values obtained in the longitudinal direction,360 50 61 75 when tested, shall be at least 50% higher than the values required in the transverse direction.415 64 77 95 3) Fracture arrest properties for larger wall thick-450 73 89 109 nesses and diameters shall be subject to agreement485 82 100 124 (see Sec. 5 D1100)555 103 126 155Table 7-24 Applicable testing for Supplementary requirement FType of pipe Type of test Extent of testing Acceptance criteriaAll pipe CVN impact testing of the pipe body for establishment of transition curve One test for each Table 7-23 1)Welded pipe DWT testing pipe provided for I204 (see also I205) manufacturing pro-Welded pipe CVN impact testing of the pipe body for establishment of transition curve, cedure qualification Table 7-23 1)except CRA pipe aged condition 2)Notes1) The values obtained in the longitudinal direction, when tested, shall at least be 50% higher than the values required in the transverse direction.2) See I203I 300 Supplementary requirement, linepipe for plastic — the difference between the maximum and minimum meas-deformation (P) ured base material longitudinal yield stress shall not exceed 100 MPa301 Supplementary requirement (P) is applicable to linepipe — the YS/TS ratio shall not exceed 0.90 unless otherwisewhen the total nominal strain in any direction from a single specified. This requirement does not apply to pipe speci-event is exceeding 1.0% or accumulated nominal plastic strain fied as coiled tubing.is exceeding 2.0%. The required testing is outlined in Table 7- — the elongation shall be minimum 20%.25 and detailed below. The requirements are only applicable tosingle event strains below 5%. Guidance note: A higher yield to tensile ratio may be specified in case the local302 For pipes delivered in accordance with supplementary buckling utilisation is not fully utilised given by:requirement (P), tensile testing shall be performed in the lon- ah = 1 - 0.2 · eF · gc ·1.2/ecgitudinal direction using proportional type specimens inaccordance with Appendix B, in order to meet the require- Buckling of the pipeline during on-reeling is primarily caused byments in I303. Tensile testing in the longitudinal direction strain concentrations in the pipeline. These strain concentrations are primarily caused by variation in thickness and yield stressaccording to Table 7-9 is not required. Transverse tensile test- along the pipeline. The strain hardening capability combineding according to Table 7-9 is required. with a tighter tolerance on the yield stress are therefore good measures to mitigate these buckles. The stated criteria alone does303 The finished pipe (for C-Mn steel the requirements are not prevent buckles, evaluations of the loading scenario is alsoapplicable up to X65, otherwise subject to agreement) shall meet necessary.the following requirements to tensile properties in longitudinaldirection (see I302) prior to being tested according to I304: ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.7 – Page 87Table 7-25 Additional testing for Supplementary requirement P 1)Production testsType of pipe Type of test Extent of testing Acceptance criteriaAll pipe Tensile testing of the pipe body, longitudinal spec- Once per test unit of not more than 50/100 3) I303 imen of proportional type 2) pipes with the same cold-expansion ratio 4)Tests for Manufacturing Procedure Qualification Test (all testing on strained and aged samples)Type of pipe Type of test Extent of testing Acceptance criteriaAll pipe Tensile testing of the pipe body, longitudinal spec- One test for one of the pipes provided for I308 imen, strained and aged 2) manufacturing procedure qualification CVN impact testing of the pipe body Hardness testingWelded pipe Tensile testing of weld metal (all weld test) I308 CVN impact testing of the seam weld Hardness testing of the seam weldNotes1) Mechanical and corrosion testing shall be performed in accordance with Appendix B.2) Proportional type specimens according to ISO 6892 shall be tested, see Appendix B A408.3) Not more than 100 pipes with D < 508 mm and not more than 50 pipes for D ≥ 508 mm.4) The cold-expansion ratio is designated by the Manufacturer, and is derived using the designated before-expansion outside diameter or circumference and the after-expansion outside diameter or circumference. An increase or decrease in the cold-expansion ratio of more than 0.002 requires the creation of a new test unit.304 As part of qualification of the pipe material, the finished — weld metal (all weld) tensile testpipe shall be deformed either by full scale or simulated defor- — hardness testing (mid wall thickness)mation (see Appendix B A1202-A1210) as stated by the Pur- — Charpy V-notch test (transverse specimens).chaser in the linepipe specification.After the deformation, specimens for mechanical testing (see 308 The following requirements shall be met after strainingI306 and I307) shall be sampled in areas representative of the and ageing (see I306 and I307):final deformation in tension, (see Appendix A). For full scalestraining the test specimens, which shall represent the strain — SMYS, SMTS and hardness shall be according to Tablehistory ending up in tension, shall be extracted from the sector 7-5 or 7-11, as relevant:5-7 o’clock of the pipe. 12 o’clock position is defined as the — the elongation shall be minimum 15%top of the pipe when reeling on. — Charpy V-notch impact toughness and hardness shall beThe samples shall be artificially aged at 250°C for one hour according to Table 7-5 or 7-11, as applicable.before testing.305 Qualification for Supplementary requirement P may be 309 If the supplementary requirement for sour service (S)based on historical data to be documented by the Manufac- and/or fracture arrest properties (F) is required, the testing forturer. these supplementary requirements shall be performed on sam- ples that are removed, strained and artificially aged in accord-306 The following testing shall be conducted of the base ance with I304. The relevant acceptance criteria shall be met.material after straining and ageing:— longitudinal tensile testing I 400 Supplementary requirement, dimensions (D)— hardness testing in pipe mid wall thickness 401 Supplementary requirements for enhanced dimensional— Charpy V-notch impact toughness testing. Test tempera- requirements for linepipe (D) are given in Table 7-26. ture shall be according to Table 7-6 or Table 7-11 as rele- vant. Requirements for tolerances should be selected by the Pur- chaser considering the influence of dimensions and tolerances307 The following testing shall be performed of the longitu- on the subsequent fabrication/installation activities and thedinal weld seam after straining and ageing: welding facilities to be used. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 88 – Sec.7 see note on front coverTable 7-26 Supplementary requirements D, enhanced tolerances and/or increased frequency of inspection 1)Type of pipe Characteristic to be tested Pipe diameter Frequency of Tolerances inspectionAll Diameter pipe ends - Each pipe end As per Table 7-17 Out-of-roundness, pipe ends, D/t2 ≤ 75 610 < D ≤ 1422 0.0075 D, but max. 5.0 mmSMLS Wall thickness 15.0 mm ≤ t < 25.0 mm - Each pipe +0.125 t – 0.1 t Wall thickness t ≥ 25.0 mm - ± 0.1 t, but max. 3.0 mmSAW pipe Wall thickness t ≤ 6.0 mm - ± 0.5 mm 2) Wall thickness t > 6.0 to ≤ 10.0 mm - ± 0.6 mm 2) Wall thickness t > 10.0 to ≤ 20.0 mm - ± 0.8 mm 2) Wall thickness t ≥ 20.0 mm - ± 1.0 mm 2) Geometric deviations (peaking and flats) - 10% of pipe 0.005 D or 1.5 mm, whichever is less endswhereD = specified nominal outside diametert = specified nominal wall thickness.Notes1) For tolerances not specified in this table, the dimensional tolerances in Table 7-17 to Table 7-19 shall apply.2) Subject to agreement a larger plus tolerance for metallurgically clad pipes may be applied.I 500 Supplementary requirement, high utilisation (U) shall be performed.501 For welded pipes, supplementary requirement U does If the confirmatory tests meet SMYS, the test unit is accepta-only consider the SMYS at ambient temperature in the trans- ble.verse direction. For seamless pipes delivered in the quenchedand tempered condition testing may be conducted in the longi- If one or both of the confirmatory tests fall below SMYS, thetudinal direction. re-test program given in I508 shall apply.502 The test regime given in this sub-section intends to Re-testingensure that the average yield stress is at least two standard 507 If the result from the mandatory testing falls belowdeviations above SMYS. The testing scheme applies to pro- SMYS, four (4) re-tests taken from four (4) different pipes (aduction in excess of 50 test units. Alternative ways of docu- total of 4 tests), within the same test unit, shall be tested. If thementing the same based upon earlier test results in the same four re-tests meet SMYS, the test unit is acceptable. If one ofproduction is allowed. the re-tests fall below SMYS the test unit shall be rejected. Guidance note: 508 If one or both of the confirmatory tests fail to meet The outlined test regime is required to be able to meet Supple- SMYS, two (2) re-tests taken from each of two (2) different mentary requirement U, but as stated above, even if all tested pipes within the same test unit shall be tested (a total of 4 tests). pipes fulfil the requirements for the grade in question the pipes If all re-tests meet SMYS, the test unit is acceptable. If any of do not necessary fulfil the requirements for supplementary the re-tests fall below SMYS, the test unit shall be rejected. requirement U. 509 Re-testing of failed pipes is not permitted. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- 510 If the test results are influenced by improper sampling,Mandatory mechanical testing machining, preparation, treatment or testing, the test sample503 The testing frequency shall comply with Table 7-7 or shall be replaced by a correctly prepared sample from the sameTable 7-12, as applicable. pipe, and a new test performed.504 If the results from the mandatory testing meet the 511 If a test unit has been rejected after re-testing (I507 andrequirement SMYS × 1.03, no further testing is required in I508 above), the Manufacturer may conduct re-heat treatmentorder to accept the test unit. of the test unit or individual testing of all the remaining pipes in the test unit. If the total rejection of all the pipes within one505 If the result from the mandatory testing falls below test unit exceeds 15%, including the pipes failing the manda-SMYS, the re-test program given in I507 shall apply. tory and/or confirmatory tests, the test unit shall be rejected.Confirmatory mechanical testing 512 In this situation, the Manufacturer shall investigate and506 If the mandatory test result falls between SMYS × 1.03 report the reason for failure and shall change the manufactur-and SMYS, then two (2) confirmatory tests taken from two (2) ing process if required. Re-qualification of the MPS is requireddifferent pipes (a total of two tests) within the same test unit if the agreed allowed variation of any parameter is exceeded. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.8 – Page 89 SECTION 8 CONSTRUCTION - COMPONENTS AND ASSEMBLIES A. General used in the submarine pipeline system.A 100 Objective 202 Design of components shall be in accordance with Sec.5 F.101 This section specifies requirements to the constructionof pipeline components, and to the construction of assemblies 203 Materials selection for components shall be in accord-such as risers, expansion loops and pipe strings for reeling and ance with Sec.6.towing. A 300 Quality assuranceA 200 Application 301 Requirements for quality assurance are given in Sec.2201 This Section is applicable to pressure containing compo- B500. Corresponding requirements for the material processingnents (e.g. bends, flanges and connectors, Tee’s, valves etc.) and the manufacture of components shall be specified.Table 8-1 Manufacture and testing of pipeline componentsComponents Requirements for manufacture and testing Reference code and applicable class or designation 1) given in this sectionBends B300 ISO 15590-1, Class C for non-sour and Class CS for sour serviceFittings2) B400 ISO 15590-2, Class C for non-sour and Class CS for sour serviceFlanges B500 ISO 15590-3, Designation (L) for non-sour and desig- nation (LS) for sour serviceValves B600 ISO 14723Mechanical connectors B700 not covered by specific reference codeCP Insulating joints B800Anchor flanges B900Buckle and fracture arrestors B1000Pig traps B1100Repair clamps and repair couplings B1200Notes1) The listed reference codes only cover C-Mn steels, for other materials reference is given to this section.2) Fittings include: Elbows, caps, tees, single or multiple extruded headers, reducers and transition sections. B. Component Requirements B 200 Component specification 201 A component specification reflecting the results of theB 100 General materials selection (see Sec.6 B200), and referring to this sec-101 Reference to requirements for manufacture and testing tion of the offshore standard, shall be prepared by the Pur-of components are listed in Table 8-1. chaser. The specification shall state any additionalComponents covered by ISO standards requirements to and/or deviations from this standard pertaining to materials, manufacture, fabrication and testing of linepipe.102 The following types of components shall be manufac-tured and tested in accordance with the ISO standards listed in B 300 Induction bends – additional and modifiedTable 8-1 and the additional and modified requirements given requirements to ISO 15590-1in B300 - B600: 301 The ISO 15590-1 paragraph number is given in brackets.— induction bends 302 (8.1) The following additional requirements shall be— fittings stated in the MPS:— flanges— valves. — the steel type and grade — the number and location of the pyrometers used (minimumComponents not covered by ISO standards two, located 120-180° apart) and the allowable tempera-103 Pipeline components not covered by any specific ISO ture difference between themstandard (see B201), shall comply with the general require- — the centering tolerances for the coilments given in the following subsections: — the number of water nozzles and flow rate.— materials shall be in accordance with Subsection C 303 (8.2) The chemical composition of C-Mn steel mother— manufacture shall be in accordance with Subsection D pipe, including the backing steel of clad mother pipe, shall be— mechanical and corrosion testing of components covered in agreement with the composition for the linepipe grades in this subsection shall be in accordance with listed in Tables 7-3, 7-4, 7-20 or 7-21 in Sec.7. The maximum Subsection E. carbon equivalent (CE) of quenched and tempered or normal- ised C-Mn steel mother pipe (delivery condition N or Q,in addition to requirements for the different components in respectively) shall be according to Table 8-2. The carbonSubsection B according to Table 8-1. equivalent (Pcm) of thermo-mechanical formed or rolled C-Mn DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 90 – Sec.8 see note on front coversteel mother pipe (delivery condition M) shall be maximum the same number of specimens shall be sampled from the mid-0.02 higher than as required in Table 7-4. wall thickness position in the following locations:Table 8-2 Carbon equivalent values for mother pipe — transition zone base metal (if applicable) SMYS CE 1), max. — bend extrados base metal — bend intrados base metal 245 0.36 — bend weld metal. 290 0.38 320 0.40 310 (9.4.5) The three indicated surface hardness readings 360 0.43 (per circumferential location) shall be located at the bend 390 0.43 extrados, the neutral axis, and the bend intrados. Surface hard- ness testing using portable equipment shall be performed in 415 0.44 accordance with Appendix B. 450 0.45 311 (9.4.6) For metallographic evaluation of CRA or clad 485 0.46 induction bends, the acceptance criteria shall be in accordance 555 0.47 with in Sec.7 C400 and C500.Note 312 (9.5) The following additional NDT testing shall be per-1) According to Table 7-3 formed in accordance with Appendix D (as applicable):304 The chemical composition of mother pipe for CRA mate- — H800, for RT of weldsrials shall meet the applicable requirements for the relevant — H700 or H800, for UT of welds in C-Mn steelmaterial type and grade given in Sec.7. However, the supple- — H200, for UT of welds in duplex stainless steelmentary requirements F, P, D or U are not applicable to bends. — H800, for DP of welds in duplex stainless steel, andMother pipe shall be subjected to NDT as required for linepipe Acceptance criteria for the additional testing shall be accord-in Sec.7. ing Appendix D.Induction bends shall not be produced from CRA lined steel 313 (9.6) Ovality of cross sections shall be kept within thepipe. specified tolerances. The bend radius shall be as specified by Guidance note: the Purchaser, and large enough (e.g. 5x outer diameter) to Hot expanded mother pipe may experience dimensional instabil- allow passage of inspection vehicles when relevant. ity after post bending heat treatment. Dimensional control shall include the following additional or Bends may be made from spare sections of normal linepipe. It modified tests and acceptance criteria: should be noted that linepipe, particularly pipe manufactured from TMCP plate, may not have adequate hardenability to — ID at bend ends (always measure ID) shall be within ± 3 mm achieve the required mechanical properties after induction bend- — out-of-roundness of bend ends shall be maximum 1.5% ing and subsequent post bending heat treatment. and maximum 3% for the body Mother pipe of CRA clad C-Mn steel should preferably be longi- — the included angle between the centrelines of the straight tudinally welded pipe manufactured from roll bonded plate portions of the bend shall be within ±0.75° ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e--- — identification of weld seam location, and — end squareness shall be within ± 0.5°, maximum 3 mm.305 All mother pipe shall be mill pressure tested in accord-ance with Sec.7, Subsection E, where Sec.7 E107 does not 314 (9.7)Gauging shall be performed as specified in theapply. Component specification, see Sec.6 C300.306 (8.3 and Table 2) The following parameters shall be 315 (9.8) If hydrostatic testing of bends is specified, the test-additional to or modification of the essential variables given in ing shall be performed accordance with G100.Table 2: 316 (11) Marking requirements shall be specified to distin-— Heat of steel: This essential variable shall be replaced by: guish between bends manufactured and tested to the require- Change in ladle analysis for C-Mn steels outside ± 0.02% ments above and unmodified ISO 15590-1 bends. C, ± 0.02 CE and/or ± 0.03 in Pcm, or any change in nom- inal chemical composition for CRAs. B 400 Fittings, tees and wyes - additional requirements— Bending radius: Qualified MPS qualifies all larger radii, to ISO 15590-2 but not smaller. 401 The following components shall be defined as fittings:— Forming velocity: ± 2.5 mm/min or ± 10%, whichever is Elbows, caps, tees, single or multiple extruded headers, reduc- the greater. ers and transition sections.— Any change in number and position of pyrometers used 402 The ISO 15590-2 paragraph number is given in brackets. and in the allowable temperature difference between the pyrometers. 403 (6.2) Tees and headers shall be of the integral (non-— Any change in the stated tolerances for coil centring. welded) reinforcement type. Outlets shall normally be— Any change in the number and size of cooling nozzles and extruded but other manufacturing methods may be used, if flow rate or water pressure. agreed. Bars of barred tees and wyes shall not be welded directly to the high stress areas around the extrusion neck. It is307 (8.5) Heat treatment equipment and procedures shall be recommended that the bars transverse to the flow direction arein accordance with D500. welded to a pup piece, and that the bars parallel to the flow308 (9.4.4.2) For C-Mn steel bends intended for sour-serv- direction are welded to the transverse bars only. If this isice, hardness values up to 275 HV10 are acceptable in the out- impractical, alternative designs shall be considered in order toside cap layer. avoid peak stresses at the bar ends.309 (Table 3 and 9.4.3) For bends with wall thickness greater 404 (7) The information required in Sec.6 C302 shall be pro-than 25 mm (intrados - after bending), additional CVN testing vided.shall be performed during MPS qualification testing. In addi- 405 (8) The following additional information shall be pro-tion to the test pieces sampled 2 mm below the outer surface, vided: DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.8 – Page 91The MPS should specify the following items, as applicable: — 25Cr duplex stainless steel fittings shall be corrosion tested as required in Table 8-4, anda) For the starting material — NDT of fitting bodies shall be performed according to B512. — delivery condition — chemical composition, and 411 (Table 3) The extent of testing and examination shall — NDT procedures for examination of starting materials. comprise the following additional requirements:b) For fitting manufacture — the test unit definition shall be amended to: Fitting or test piece of the same designation, starting material wall thick- — NDT procedures ness, heat, manufacturing procedure specification and heat — hydrostatic test procedures treatment batch — dimensional control procedures — surface hardness tests shall be performed on two fittings — coating and protection procedures per test unit — handling, loading and shipping procedures, and — metallography of duplex stainless steel fittings with the — at-site installation recommendations. largest thickness exceeding 25 mm shall be performed as one per test unitFor “one-off” fittings designed and manufactured for a specific — HIC testing shall be performed for qualification of thepurpose, the following additional information shall be pro- MPS for fittings in Class CS manufactured from rolledvided: material, and— plan and process flow description/diagram — 25Cr duplex stainless steel fittings shall be corrosion— order specific quality plan including supply of material tested for qualification of the MPS, in accordance with and subcontracts, and Table 8-4.— manufacturing processes including process- and process 412 (Table 2 and 9.5) NDT of each completed fitting shall be control procedures. performed in accordance with the Table 2, Class C with the fol- lowing additional requirements:406 (8.2) Starting material shall be subject to 100% NDT atan appropriate stage of manufacture according to: — the body of fittings manufactured from plates and pipes shall be subject to 100% magnetic particle testing for C-— C-Mn steel and duplex stainless steel pipe shall be tested Mn steels and 100% dye penetrant/eddy current testing for as required in Sec.7 or Appendix D C200. duplex stainless steel— Appendix D B200, for RT of welds in starting materials — the extrusion area for tees and headers with adjoining pipe other than pipe wall thickness ≥ 12 mm shall be subject to 100% volumet-— Appendix D B300 or B400 as applicable, for UT of welds ric ultrasonic and 100% magnetic particle testing for C- in starting materials other than pipe Mn steels and 100% volumetric ultrasonic and 100% dye— Appendix D D200, for C-Mn steel forgings penetrant/eddy current testing for duplex stainless steel— Appendix D D300, for duplex stainless steel forgings — the extrusion area for tees and headers with adjoining pipe— Appendix D C200, for UT of plate material wall thickness < 12 mm shall be subject to 100% magneticwith acceptance criteria according to the corresponding particle testing for C-Mn steels and 100% dye penetrant/requirements of Appendix D. eddy current testing for duplex stainless steel — overlay welds shall be tested 100%.Subject to agreement, equivalent NDT standards with regard tomethod and acceptance criteria may be applied. 413 NDT shall be performed in accordance with Appendix D (as applicable):407 (8.3.2) Welding and repair welding shall be performedin accordance with qualified procedures meeting the require- — C400, for visual inspectionments in Appendix C. — D200, for C-Mn/low alloy steel forgings408 (8.3.3) Heat treatment equipment and procedures shall — D300, for duplex stainless steel forgingsbe in accordance with D500. — C206 through 213, for UT of a 50 mm wide band inside ends/bevels409 (9.2) Test pieces shall be taken according to E101 and — C221, for MT of ends/bevelsE103. Location of test specimens shall be in accordance with — C222, for PT of ends/bevelsE100. — B200, for RT of welds410 (Table 2) Inspection, testing and acceptance criteria — B300, for UT of welds in C-Mn/low alloy steelshall be in accordance with Class C with the following addi- — B400, for UT of welds in duplex stainless steeltional requirements: — B500, for MT of welds in C-Mn/low alloy steel — B600, for DP of welds in duplex stainless steel— the chemical composition for components shall be modi- — C300, for overlay welds fied according to C200 — D400, for visual inspection of forgings— the chemical composition of duplex stainless steel materi- — B800, for visual inspection of welds, and als shall be according to C300 — C500, for residual magnetism.— Mechanical and hardness testing of weld seams as required by Appendix B Acceptance criteria shall be according to the corresponding— the CVN test temperature shall be 10°C below the mini- requirements of Appendix D. mum design temperature 414 (11) Marking requirements shall be specified to distin-— Surface hardness testing of fittings of Class CS shall be guish between fittings manufactured and tested to the require- performed with acceptance criteria according to 9.4.4.2 ments above and unmodified ISO 15590-2 fittings.— metallographic examination for welds and body of duplex stainless steel fittings shall be performed and in accord- B 500 Flanges and flanged connections - additional ance with Appendix B and with acceptance criteria requirements to ISO 15590-3 according to E300— HIC testing shall be performed on fittings in Class CS man- 501 The ISO 15590-3 paragraph number is given in brackets. ufactured from rolled material as required in Table 8-4 502 (7) The following additional information shall be pro- DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 92 – Sec.8 see note on front covervided: flanges of the same size, heat, manufacturing procedure speci- fication and heat treatment batch shall be 100% tested.— required design life— nominal diameters, OD or ID, out of roundness and wall All flanges shall be subject to 100% visual inspection. thickness for adjoining pipes including required tolerances 513 Magnetic particle testing shall be performed in accord-— dimensional requirements and tolerance if different from ance with Appendix D, D200 or ISO 13664. ISO 7005-1 Liquid penetrant testing shall be performed in accordance with— minimum design temperature (local) Appendix D, D300 or ISO 12095.— maximum design temperature (local)— external loads and moments that will be transferred to the Ultrasonic testing of C-Mn/low alloy steel forgings shall be component from the connecting pipeline under installation performed in accordance with Appendix D, D200. and operation and any environmental loads (e.g. nominal Ultrasonic testing of duplex stainless steel forgings shall be longitudinal strain) performed in accordance with Appendix D, D300.— material type and grade, delivery condition, chemical composition and mechanical properties at design tempera- Testing of overlay welds shall be performed in accordance ture with Appendix D C300.— required testing Visual examination shall be in accordance with Appendix D— corrosion resistant weld overlay. D400.503 (8) Overlay welding shall be performed according to Subject to agreement, equivalent NDT standards with regard toqualified welding procedures meeting the requirements of method and acceptance criteria may be applied.Appendix C. Acceptance criteria for forgings shall be in accordance with the504 (8.1) The MPS shall be in accordance with D100. corresponding requirements of Appendix D, D500 and for overlay welds only, in accordance with Appendix D, C600.505 (8.2 & Table 4) 514 (9.6) For flanges with specified dimensions and toler-— The chemical composition for flanges shall be modified ances different from ISO 7005-1, these specified requirements according to C200. shall be met.— The chemical composition of duplex stainless steel mate- 515 (9.9) Repair welding of flange bodies is not permitted. rials shall be according to C300. 516 (11) Marking requirements shall be specified to distin-506 (8.4) Heat treatment equipment and procedures shall be guish between flanges manufactured and tested to the require-in accordance with D500. ments above and unmodified ISO 15590-3 flanges.507 (Table 3) Mechanical testing shall be performed in Flanged connectionsaccordance with the Table 3 with the following additional 517 Sealing rings shall be compatible with the finish and sur-requirements: face roughness of the flange contact faces.— Tensile, impact and through thickness hardness shall be 518 Sealing rings shall be capable of withstanding the maxi- performed once per test unit with the test unit defined as; mum pressure to which they could be subjected, as well as Flanges of the same size, heat, manufacturing procedure installation forces if flanges are laid in-line with the pipeline. specification and heat treatment batch. Sealing rings for flanges shall be made from metallic materials— Surface hardness testing shall be performed once per test that are resistant to the fluid to be transported in the pipeline unit for flanges in class LS. system. Mechanical properties shall be maintained at the antic-— Mechanical, hardness and corrosion testing of flanges ipated in service pressures and temperatures. shall be performed as required by E100, acceptance crite- 519 Bolts shall meet the requirements given in Sec.6 C400. ria to E200 or E300.— Metallographic examination for duplex stainless steel B 600 Valves – Additional requirements to ISO 14723 flanges shall be performed according to E100, with acceptance criteria according to E300. 601 The ISO 14723 paragraph number is given in brackets. 602 (Annex B) The following additional information shall be508 (Table 5) The impact test temperature for C-Mn steel provided:and low alloy flanges shall be 10°C below the minimum designtemperature for all thicknesses and categories. — design standard509 Hardness indentation locations shall be according to — required design lifeTable 8-4. — minimum design temperature (local) — maximum design temperature (local)510 (9.4.5) Metallographic examination of duplex stainless — design pressure (local)steel shall be performed in accordance with Appendix B, with — water depth, andacceptance criteria according to Sec.7 C400. — weld overlay, corrosion resistant and/or wear resistant.511 (9.4.6 & 9.4.7) Manufacturing procedure specificationCorrosion testing of duplex stainless steel shall be according toTable 8-4. 603 A manufacturing procedure specification in accordance with D100 shall be documented.512 (9.5.4) The extent of NDT shall be100% magnetic parti-cle testing of ferromagnetic materials and 100% liquid pene- 604 (7.1, 7.4 and 7.7) Materials shall be specified to meet thetrant testing of non magnetic materials. A percentage test is not requirements given in subsection C.permitted. 605 (7.5) The impact test temperature shall be 10°C below(9.5.5) 100% ultrasonic testing of the final 50 mm of each end the minimum design temperatureof the flange shall be performed. 100% ultrasonic testing of the 606 (7.6) Bolting shall meet the requirements of Sec.6 C400.first 10 flanges of each type and size ordered. If no defects arefound during the testing of the first 10 flanges of each type and 607 (8) Welding shall be performed according to qualifiedsize ordered the extent of testing may be reduced to 10% of welding procedures meeting the requirements of Appendix C.each size and type. If defects are found in any tested flange, all 608 (9.4) The extent, method and type of NDT of C-Mn/low DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.8 – Page 93alloy steels shall be in accordance with ISO 14723, Annex E, B 800 CP Insulating jointsQL 2 requirements. 801 These requirements apply to manufacture and testing ofThe extent and type of NDT of duplex stainless steels shall be boltless, monolithic coupling type of insulating joints forin accordance with ISO 14723, Annex E, QL 2 requirements. onshore applications.Methods shall be according to Appendix D of this standard. 802 CP Insulating joints shall be manufactured from forg-The extent and type of NDT of weld overlay shall be in accord- ingsance with ISO 14723, Annex E, QL 2 requirements. the 803 Insulating joints shall be protected from electrical highmethod shall be according to Appendix D. current high voltage from welding and lightening etc. in theAcceptance criteria for NDT shall be in accordance with construction period. If high voltage surge protection is not pro-ISO 14723, Annex E with the following amendments: vided in the construction period insulating joints shall be fittedFor UT 2, VT 2 and VT 3 the acceptance criteria shall be in with a temporary short-circuit cable clearly tagged with theaccordance with Appendix D of this standard. instruction “not to be removed until installation of permanent high voltage surge protection.”609 (9.5) Repair welding of forgings is not permitted. 804 For manufactures without previous experience in the610 (10.2) Hydrostatic shell tests shall be performed in design, manufacture and testing of insulating joints, one jointaccordance with ISO 14723, Clause 10, or according to speci- should be manufactured and destructively tested for the pur-fied requirements. pose of qualifying the design and materials of the joint.611 (11) Marking requirements shall be specified to distin- The qualification programme should as a minimum contain theguish between valves manufactured and tested to the require- following elements:ments above and unmodified ISO 14723 valves.612 Valves with requirements for fire durability shall be — bending to maximum design bending momentqualified by applicable fire tests. Refer to API 6FA and BS — Tension to maximum design tension6755 Part 2 for test procedures. — Pressure testing to 1.5 times the design pressure — Pressure cycling from minimum to maximum design pres-B 700 Mechanical connectors sure 10 times at both minimum and maximum design tem- perature.701 These requirements apply to manufacture and testing ofend connections such as hub and clamp connections connect- Before and after testing the resistance and electrical leakageing a pipeline to other installations. tests should show the same and stable values.702 Bolting shall meet the requirements of Sec.6 C400. In addition, after full tests the joint should be cut longitudinally703 End connections shall be forged. into sections to confirm the integrity of the insulation and fill materials and the condition of the O-ring seals.NDT 805 Insulation joint shall be forged close to the final shape (if704 The extent of NDT shall be: applicable). Machining of up to 10% of the local wall thickness— 100% magnetic particle testing of ferromagnetic materials at the outside of the component is allowed. and 100% liquid penetrant testing of non magnetic materi- 806 The extent of NDT shall be: als.— 100% ultrasonic testing of forgings and castings — 100% magnetic particle testing of ferromagnetic materials— 100% RT of critical areas of castings and 100% liquid penetrant testing of non magnetic materials— 100% ultrasonic or radiographic testing of welds — 100% ultrasonic testing of forgings— 100% magnetic particle testing / liquid penetrant testing of — 100% ultrasonic or radiographic testing of welds welds — 100% magnetic particle testing / liquid penetrant testing of— 100% visual inspection welds — 100% visual inspection.NDT shall be performed in accordance with Appendix D (asapplicable): NDT shall be performed in accordance with Appendix D (as applicable):— C400, for visual inspection— D200, for C-Mn/low alloy steel forgings — C400, for visual inspection— D300, for duplex stainless steel forgings — D200, for C-Mn/low alloy steel forgings— E200, for C-Mn/low alloy steel castings — D300, for duplex stainless steel forgings— E300, for duplex stainless steel castings — C220, for MT of ends/bevels— E400, for RT of castings — C221, for DP of ends/bevels— C221, for MT of ends/bevels — B200, for RT of welds— C222, for DP of ends/bevels — B300, for UT of welds in C-Mn/low alloy steel— B200, for RT of welds — B400, for UT of welds in duplex stainless steel— B300, for UT of welds in C-Mn/low alloy steel — B500, for MT of welds in C-Mn/low alloy steel— B400, for UT of welds in duplex stainless steel — B600, for DP of welds in duplex stainless steel— B500, for MT of welds in C-Mn/low alloy steel — C300, for overlay welds— B600, for DP of welds in duplex stainless steel — D400, for visual inspection of forgings— C300, for overlay welds — B800, for visual inspection of welds, and— D400, for visual inspection of forgings — C500, for residual magnetism.— E500, for visual examination of castings Acceptance criteria shall be according to the corresponding— B800, for visual inspection of welds requirements of Appendix D.— C500, for residual magnetism. 807 Prior to hydrostatic testing, hydraulic fatigue test and theAcceptance criteria shall be according to the corresponding combined pressure-bending test / electrical leakage tests shallrequirements of Appendix D. be performed and the results recorded.705 If hydrostatic testing is specified, the test shall be per- 808 Hydrostatic strength test of each insulating joint shall beformed according to G100. performed with a test pressure 1.5 times the design pressure, DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 94 – Sec.8 see note on front coverunless otherwise specified, and to the specified holding time in — B200, for RT of weldsgeneral accordance with G100. — B300, for UT of welds in C-Mn/low alloy steel809 Hydraulic fatigue of each insulating joint shall be per- — B400, for UT of welds in duplex stainless steelformed. The test shall consist of 40 consecutive cycles with the — B500, for MT of welds in C-Mn/low alloy steelpressure changed from 10 barg to 85 percent of the hydrostatic — B600, for DP of welds in duplex stainless steeltest pressure. At the completion of the test cycles the pressure — D400, for visual inspection of forgingsshall be increased to the hydrostatic test pressure and main- — B800, for visual inspection of welds, andtained for 30 minutes. There shall be no leakage or pressure — C500, for residual magnetism.loss during the test. Acceptance criteria shall be according to the corresponding810 One insulating joint per size/design pressure shall also requirements of Appendix D.be tested to meet the specified bending moment requirements.The joint shall be pressurised to the specified hydrostatic test B 1000 Buckle- and fracture arrestorspressure and simultaneously be subjected to an external 4 point 1001 The material for buckle and fracture arrestors and man-bending load sufficient to induce a total (bending plus axial ufacture, inspection and testing shall be in accordance withpressure effect) longitudinal stress of 90% of SMYS in the Subsec.E or Sec.7.adjoining pup pieces. The test duration shall be 2 hours. Theacceptance criteria are no water leakage or permanent distor- B 1100 Pig trapstion. 1101 Materials shall comply with the requirements of the811 After hydrostatic testing, all isolating joints shall be leak design code or with the requirements of this section, if moretested with air or nitrogen. The joints shall be leak tested at 10 stringent.barg for 10 minutes. The tightness shall be checked by immersionor with a frothing agent. The acceptance criterion is: no leakage. 1102 Testing and acceptance criteria for qualification of welding procedures shall comply with the requirements of the812 The FAT shall be performed according to the accepted design code or with the requirements of Appendix C, if moreFAT programme. The FAT shall consist of: stringent.— dielectric testing Essential variables for welding procedures shall comply with— electrical resistance testing the requirements of the design code— electrical leakage tests. Production welding shall comply with the requirements in813 Prior to testing insulating joints shall be stored for 48 Appendix C.hours at an ambient temperature between 20 and 25°C and a 1103 The extent, methods and acceptance criteria for NDTrelative humidity of 93%. shall comply with the requirements of the design code. In addi-814 Dielectric testing shall be performed by applying an AC tion the requirements of Appendix D, subsection A and B100sinusoidal current with a frequency of 50 - 60 Hz to the joint. shall apply.The current shall be applied gradually, starting from an initial 1104 Hydrostatic testing shall comply with the requirementsvalue not exceeding 1.2kV increasing to 5.0kV in a time not of the design codelonger than 10 seconds and shall be maintained at peak valuefor 60 seconds. The test is acceptable if no breakdown of the B 1200 Repair clamps and repair couplingsinsulation or surface arcing occurs during the test and a maxi- Repair clamps and repair couplings to be installed according tomum leakage of current across the insulation of 1 mA. RP-F113 shall be manufactured and tested in general accord-815 Electrical resistance testing shall be carried out at 1000 ance with this section and based on materials selection accord-V DC. The test is acceptable if the electrical resistance is min- ing to Sec.6.imum 25 MOhm.816 Electrical leakage tests shall be performed to assess anychanges which may take place within a joint after hydrostatic C. Materials for Componentstesting, hydraulic fatigue test and the combined pressure-bend-ing test. No significant changes in electrical leakage shall be C 100 Generalaccepted. 101 The materials used shall comply with internationallyB 900 Anchor flanges recognised standards, provided that such standards have acceptable equivalence to the requirements given in Sec.7 and901 Anchor flanges shall be forged. this section. Modification of the chemical composition given902 The extent of NDT shall be: in such standards may be necessary to obtain a sufficient com- bination of weldability, hardenability, strength, ductility,— 100% magnetic particle testing of ferromagnetic materials toughness, and corrosion resistance. and 100% liquid penetrant testing of non magnetic materi- als 102 Sampling for mechanical and corrosion testing shall be— 100% ultrasonic testing of forgings performed after final heat treatment, i.e. in the final condition.— 100% ultrasonic or radiographic testing of welds The testing shall be performed in accordance with Appendix B— 100% magnetic particle testing / liquid penetrant testing of and E100. welds C 200 C-Mn and low alloy steel forgings and castings— 100% visual inspection 201 These requirements are applicable to C-Mn and lowNDT shall be performed in accordance with Appendix D (as alloy steel forgings and castings with SMYS ≤ 555 MPa. Useapplicable): of higher strength materials shall be subject to agreement.— C400, for visual inspection 202 All steels shall be made by an electric or one of the basic— D200, for C-Mn/low alloy steel forgings oxygen processes. C-Mn steel shall be fully killed and made to— D300, for duplex stainless steel forgings a fine grain practice.— C220, for MT of ends/bevels 203 The chemical composition for hot-formed, cast and— C221, for DP of ends/bevels forged components shall be in accordance with recognised DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.8 – Page 95international standards. The chemical composition shall be 102 Components shall be manufactured in accordance with aselected to ensure an acceptable balance between sufficient documented and approved MPS.hardenability and weldability. 103 The MPS shall demonstrate how the fabrication will be204 For materials to be quenched and tempered, a hardena- performed and verified through the proposed fabrication steps.bility assessment shall be performed to ensure that the required The MPS shall address all factors which influence the qualitymechanical properties are met. and reliability of production. All main fabrication steps from205 For C-Mn steels the maximum Carbon Equivalent (CE) control of received material to shipment of the finished prod-shall not exceed 0.50, when calculated in accordance with: uct(s), including all examination and check points, shall be covered in detail. References to the procedures and acceptance criteria established for the execution of all steps shall be included.CE = C + Mn + Cr + Mo + V + Cu + Ni ------- -------------------------------- ------------------- - - - 6 5 15 104 The MPS should be project specific and specify the fol- lowing items as applicable:206 Acceptance criteria for tensile, hardness and Charpy V-notch impact properties are given in E200. — starting materials207 Forgings shall be delivered in normalised or quenched — manufacturerand tempered condition. Minimum tempering temperature — steel making processshall be 610°C when PWHT will be applied, unless otherwise — steel gradespecified. — product form, delivery condition208 Castings shall be delivered in homogenised, normalised — chemical compositionand stress relieved or homogenised, quenched and tempered — welding procedure specification (WPS)condition. — NDT procedures.209 For C-Mn and low alloy materials delivered in the — Manufacturingquenched and tempered condition, the tempering temperatureshall be sufficiently high to allow effective post weld heat — supply of material and subcontractstreatment during later manufacture / installation (if applica- — manufacturing processes including process- and proc-ble). ess control procedures — welding proceduresC 300 Duplex stainless steel, forgings and castings — heat treatment procedures301 All requirements with regard to chemical composition — NDT proceduresfor 22Cr and 25Cr duplex stainless steel shall be in accordance — list of specified mechanical and corrosion testingwith Sec.7 C400. — hydrostatic test procedures302 Acceptance criteria for tensile, hardness, Charpy V- — functional test proceduresnotch impact properties and corrosion tests are given in E300. — dimensional control procedures — FAT procedures303 Duplex stainless steel castings and forgings shall be — marking, coating and protection proceduresdelivered in the solution annealed and water quenched condi- — handling, loading and shipping procedurestion. — at-site installation recommendations.C 400 Pipe and plate material For “one-off” components and other components designed and401 Pipe and plate material shall meet the requirements in manufactured for a specific purpose, the following additionalSec.7. information shall be provided:402 For welded pipe it shall be assured that the mechanical — Plan and process flow description/diagramproperties of the material and longitudinal welds will not be — Order specific quality plan including supply of materialaffected by any heat treatment performed during manufacture and subcontractsof components. — Manufacturing processes including process- and process403 In case post weld heat treatment is required, the mechan- control procedures.ical testing should be conducted after simulated heat treatment. D 200 ForgingC 500 Sour Service 201 Forging shall be performed in compliance with the501 For components in pipeline systems to be used for fluids accepted MPS. Each forged product shall be hot worked as farcontaining hydrogen sulphide and defined as “sour service” as practicable, to the final size with a minimum reduction ratioaccording to ISO 15156, all requirements to chemical compo- of 4:1.sition, maximum hardness, and manufacturing and fabrication 202 The work piece shall be heated in a furnace to theprocedures given in the above standard shall apply. required working temperature.502 The sulphur content of C-Mn and low alloy steel forg- 203 The working temperature shall be monitored during theings and castings shall not exceed 0.010%. forging process.503 Pipe and plate material used for fabrication of compo- 204 If the temperature falls below the working temperaturenents shall meet the requirements given in Sec.7 I100. the work piece shall be returned to the furnace and re-heated before resuming forging. 205 The identity and traceability of each work piece shall be D. Manufacture maintained during the forging process. 206 Weld repair of forgings is not permitted.D 100 Manufacturing procedure specification (MPS)101 The requirements of this subsection are not applicable to D 300 Castinginduction bends and fittings that shall be manufactured in 301 Casting shall be performed in general compliance withaccordance with B300 and B400 ASTM A352. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 96 – Sec.8 see note on front cover302 A casting shall be made from a single heat and as a sin- nace volume shall be within ± 10°C.gle unit. 504 Whenever practical thermocouple(s) should be attached303 Castings may be repaired by grinding to a depth of max- to one of the components during the heat treatment cycle.imum 10% of the actual wall thickness, provided that the wall 505 Components should be rough machined to near finalthickness in no place is below the minimum designed wall dimensions prior to heat treatment. This is particularly impor-thickness. The ground areas shall merge smoothly with the sur- tant for large thickness components.rounding material. Guidance note:304 Defects deeper than those allowed by D303 may be The extent and amount of machining of forgings and castingsrepaired by welding. The maximum extent of repair welding prior to heat treatment should take into account the requirementsshould not exceed 20% of the total surface area. Excavations for machining to flat or cylindrical shapes for ultrasonic exami-for welding shall be ground smooth and uniform and shall be nation. See also Appendix D.suitably shaped to allow good access for welding. ---e-n-d---of---G-u-i-d-a-n-c-e---n-o-t-e---305 All repair welding shall be performed by qualified weld-ers and according to qualified welding procedures. 506 For components that shall be water quenched, the time from the components are leaving the furnace until beingD 400 Hot forming immersed in the quenchant shall not exceed 90 seconds for low401 Hot forming shall be performed to according to an alloy steel, and 60 seconds for duplex stainless steels.agreed procedure containing: 507 The volume of quenchant shall be sufficient and shall be heavily agitated, preferably by cross flow to ensure adequate— sequence of operations cooling rate. The maximum temperature of the quenchant shall— heating equipment never exceed 40°C. Temperature measurements of the quen-— material designation chant shall be performed— pipe diameter, wall thickness and bend radius— heating/cooling rates 508 The hardness of the accessible surfaces of the compo-— max/min. temperature during forming operation nent shall be tested. The hardness for C-Mn or low alloy steels— temperature maintenance/control and duplex stainless steels shall be in accordance with E200— recording equipment and E300, respectively.— position of the longitudinal seam— methods for avoiding local thinning D 600 Welding— post bending heat treatment (duplex stainless steel: full Welding and repair welding shall be performed in accordance solution annealing and water quenching) with qualified procedures meeting the requirements of Appen-— hydrostatic testing procedure dix C.— NDT procedures— dimensional control procedures. D 700 NDT NDT shall be performed in accordance with Appendix D.402 Hot forming of C-Mn and low alloy steel, includingextrusion of branches, shall be performed below 1050°C. Thetemperature shall be monitored. The component shall beallowed to cool in still air. E. Mechanical and Corrosion Testing of Hot403 For duplex stainless steel material, the hot forming shall Formed, Cast and Forged Componentsbe conducted between 1000 and 1150°C. E 100 General testing requirementsD 500 Heat treatment 101 Testing of mechanical properties after hot forming, cast-501 Heat treatment procedures for furnace heat treatment ing or forging shall be performed on material taken from oneshall as a minimum contain the following information: prolongation or component from each test unit (i.e. compo- nents of the same size and material, from each heat and heat— heating facilities treatment batch) shall be tested as given in Table 8-4, as appli-— furnace cable:— insulation (if applicable)— measuring and recording equipment, both for furnace con- 102 All mechanical testing shall be conducted after final heat trol and recording of component temperature treatment.— calibration intervals for furnace temperature stability and 103 If agreed, separate test coupons may be allowed provid- uniformity and all thermocouples ing they are heat treated simultaneously with the material they— fixtures and loading conditions represent, and the material thickness, forging reduction, and— heating and cooling rates mass are representative of the actual component.— temperature gradients— soaking temperature range and time 104 A simulated heat treatment of the test piece shall be per-— maximum time required for moving the component from formed if welds between the component and other items such the furnace to the quench tank (if applicable) as linepipe are to be PWHT at a later stage or if any other heat— cooling rates (conditions) treatment is intended.— type of quenchant (if applicable) 105 The CVN test temperature shall be 10°C below the min-— start and end maximum temperature of the quenchant (if imum design temperature. applicable). 106 Sampling for mechanical and corrosion testing shall be502 If PWHT in an enclosed furnace is not practical, local performed after final heat treatment, i.e. in the final condition.PWHT shall be performed according to Appendix C, G400. The testing shall be performed in accordance with Appendix B.503 The heat treatment equipment shall be calibrated at leastonce a year in order to ensure acceptable temperature stability 107 A sketch indicating the final shape of the component andand uniformity. The uniformity test shall be conducted in the location of all specimens for mechanical testing shall beaccordance with a recognised standard (e.g. ASTM A991). issued and accepted prior to start of production.The temperature stability and uniformity throughout the fur- 108 For 25Cr duplex stainless steels corrosion testing DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.8 – Page 97according to ASTM G48 shall be performed in order to con- shall meet the requirements for linepipe with equal SMYS asfirm that the applied manufacturing procedure ensures accept- given in Sec.7 B400.able microstructure. Testing shall be performed in accordance 202 The hardness for components intended for non-sourwith Appendix B, at 50°C. The test period shall be 24 hours. service shall not exceed 300 HV10. For components intendedE 200 Acceptance criteria for C-Mn and low alloy steels for sour service the hardness shall according to Sec.7 I100.201 Tensile, hardness and Charpy V-notch impact propertiesTable 8-4 Number, orientation, and location of test specimens per tested componentType of test No. of tests 1) Test location, e.g. as shown in Figure 1 2,3)Tensile test 3 One specimen in tangential direction from the thickest section 1/4T below the internal surface One mid thickness specimen in both tangential and axial direction from the area with highest utilisation (after final machining), e.g. the weld neck area 4)CVN impact testing, axial and tan- 6 One set in each direction (axial and tangential) taken from the same locations as thegential specimens 5) two tensile specimens described above for the relevant wall thicknesses4) (thick sec- tion and high utilisation section, a total of 2 sets)CVN impact testing of the thickest 3 One set in the tangential direction 2 mm below the internal surfacesection of the component for sectionthickness ≥ 25 mm 5,6)Metallographic sample 3 As for the CVN impact testing setsHardness testing 7) 3 As for the CVN impact testing setsHIC and SSC test 8) 1 In accordance with ISO 15156ASTM G48 9) 1 See E108Notes1) For CVN impact testing one test equals one set which consist of three specimens.2) For test pieces (components) having maximum section thickness, T ≤ 50 mm, the test specimens shall be taken at mid-thickness and the mid-length shall be at least 50 mm from any second surface. For test pieces (components) having maximum section thickness, T > 50 mm, the test specimens shall be taken at least 1/4 T from the nearest surface and at least T or 100 mm, whichever is less, from any second surface. For welded components, the testing shall also include testing of the welds in accordance with Appendix C.3) Internal and external surface refers to the surfaces of the finished component.4) For Tees and Wyes both main run and branch weld necks shall be tested.5) The notch shall be perpendicular to the components surface.6) Only applicable to C-Mn and low alloy steel. The section thickness is in the radial direction in the as-heat treated condition.7) A minimum of 3 hardness measurements shall be taken on each sample.8) Only applicable for rolled C-Mn steels not meeting the requirements in C500.9) Only applicable for 25Cr duplex steels.Figure 1Location of tensile and CVN specimens, component with section thickness ≥ 25 mm203 Specimens for hardness testing shall be examined, prior to testing, at a magnification of not less than x100. Grain-size DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 98 – Sec.8 see note on front covermeasurement shall be performed in accordance with ASTM required for adequate inspection and testing as fabrication pro-E112. The type of microstructure and actual grain size shall be ceeds.recorded on the materials testing report. 306 Due consideration during fabrication shall be given toE 300 Acceptance criteria for duplex stainless steels the control of weight and buoyancy distribution of pipe strings for towing.301 Tensile, hardness and Charpy V-notch impact propertiesshall meet the requirements for linepipe as given in Sec.7, C400. 307 The procedures prepared by the fabricator shall be sub- mitted for acceptance prior to start of fabrication.302 The metallographic samples shall comply with therequirements of Sec.7 C400. F 400 Material receipt, identification and tracking303 For ASTM G48 testing the acceptance criteria is: maxi- 401 All material shall be inspected for damage upon arrival.mum allowable weight loss 4.0 g/m2. Quantities and identification of the material shall be verified. Damaged items shall be clearly marked, segregated and dis- posed of properly. 402 Pipes shall be inspected for loose material, debris, andF. Fabrication of Risers, Expansion Loops, Pipe other contamination, and shall be cleaned internally before Strings for Reeling and Towing being added to the assembly. The cleaning method shall not cause damage to any internal coating.F 100 General 403 A system for ensuring correct installation of materials101 The following requirements are applicable for the fabri- and their traceability to the material certificates shall be estab-cation of risers, expansion loops, pipe strings etc. lished. The identification of material shall be preserved during102 The fabrication shall be performed according to a speci- handling, storage and all fabrication activities.fication giving the requirements for fabrication methods, pro- 404 A pipe tracking system shall be used to maintain recordscedures, extent of testing, acceptance criteria and required of weld numbers, NDT, pipe numbers, pipe lengths, bends,documentation. The specification shall be subject to agreement cumulative length, anode installation, in-line assemblies andprior to start of production. repair numbers. The system shall be capable of detectingF 200 Materials for risers, expansion loops, pipe strings duplicate records.for reeling and towing 405 The individual pipes of pipe strings shall be marked in201 Linepipe shall comply with the requirements, including accordance with the established pipe tracking system using asupplementary requirements (as applicable) given in Sec.7. suitable marine paint. The location, size and colour of the marking shall be suitable for reading by ROV during installa-202 Forged and cast material shall as a minimum meet the tion. It may be required to mark a band on top of the pipe stringrequirements given in this section. to verify if any rotation has occurred during installation.F 300 Fabrication procedures and planning 406 If damaged pipes or other items are replaced, the sequential marking shall be maintained.301 Before production commences, the fabricator shall pre-pare an MPS. F 500 Cutting, forming, assembly, welding and heat302 The MPS shall demonstrate how the fabrication will be treatmentperformed and verified through the proposed fabrication steps. 501 The Contractor shall be capable of producing weldedThe MPS shall address all factors which influence the quality joints of the required quality. This may include welding ofand reliability of production. All main fabrication steps from girth welds, other welds, overlay welding and post weld heatcontrol of received material to shipment of the finished prod- treatment. Relevant documentation of the Contractors capabil-uct(s), including all examination and check points, shall be ities shall be available if requested by the Purchaser.covered in detail. References to the procedures and acceptancecriteria established for the execution of all steps shall be 502 Attention shall be paid to local effects on material prop-included. erties and carbon contamination by thermal cutting. Preheating of the area to be cut may be required. Carbon contamination303 The MPS shall, as a minimum, contain the following shall be removed by grinding off the affected material.information: 503 Forming of material shall be according to agreed proce-— plan(s) and process flow description/diagram dures specifying the successive steps.— project specific quality plan including supply of material 504 The fabrication and welding sequence shall be such that and subcontracts the amount of shrinkage, distortion and residual stress is mini-— fabrication processes used mised.— supply of material, i.e. manufacturer and manufacturing location of material 505 Members to be welded shall be brought into correct— fabrication processes alignment and held in position by clamps, other suitable devices, or tack welds, until welding has progressed to a stage— fabrication process procedures where the holding devices or tack welds can be removed with-— fabrication process control procedures out danger of distortion, shrinkage or cracking. Suitable allow-— welding procedures ances shall be made for distortion and shrinkage where— heat treatment procedures appropriate.— NDT procedures— pressure test procedures 506 Welding shall meet the requirements given in— list of specified mechanical and corrosion testing Appendix C.— dimensional control procedures— marking, coating and protection procedures and F 600 Hydrostatic testing— handling, loading and shipping procedures. 601 Hydrostatic testing shall be performed to established procedures meeting the requirements of G100.304 The MPS shall be submitted for acceptance prior to startof fabrication F 700 NDT and visual examination305 Due consideration shall be given to the access and time 701 All welds shall be subject to 100% visual inspection. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.8 – Page 99702 Welds where the acceptance criteria are based on the specified test pressure, with an accuracy better than ± 0.1acceptance criteria in Appendix D shall be subject to 100% bar and a sensitivity better than 0.05 bar.radiographic or ultrasonic testing based on the requirements to — Temperature-measuring instruments and recorders shallapplicable and preferred NDT methods is given in have an accuracy better than ± 1.0°C, andAppendix D. — Pressure and temperature recorders are to be used to pro-703 For welds where allowable defect sizes are based on an vide a graphical record of the pressure test for the totalECA, ultrasonic testing shall supplement radiographic testing, duration of the test.unless automated ultrasonic testing is performed 109 Where the test acceptance is to be based on observation704 Requirements to automated ultrasonic testing systems of pressure variations calculations showing the effect of tem-are given in Appendix E. perature changes on the test pressure shall be developed prior705 All NDT shall be performed after completion of all cold to starting the test. Temperature measuring devices, if used,forming and heat treatment. shall be positioned close to the test object and the distance between the devices shall be based on temperature gradients706 Requirements for personnel, methods, equipment, proce- along the test object.dures, and acceptance criteria for NDT are given in Appendix D. 110 The test medium should be fresh water or adequatelyF 800 Dimensional verification treated sea water, as applicable. Filling procedure shall ensure minimum air pockets.801 Dimensional verification should be performed in orderto establish conformance with the required dimensions and tol- 111 Pressurisation shall be performed as a controlled opera-erances. tion with consideration for maximum allowable velocities in the inlet piping up to 95% of the test pressure. The final 5% up802 Dimensional verification of pipe strings for towing shall to the test pressure shall be raised at a reduced rate to ensureinclude weight, and the distribution of weight and buoyancy. that the test pressure is not exceeded. Time shall be allowed forF 900 Corrosion protection confirmation of temperature and pressure stabilisation before the test hold period begins.901 Application of coatings and installation of anodes shallmeet the requirements of Sec.9. 112 The test pressure shall be according to the specified requirement. 113 Where the test acceptance is to be based on 100% visual inspection the holding time at test pressure shall be until 100% G. Hydrostatic Testing visual inspection is complete or 2 hours, whichever is longer. Where the test acceptance is to be based on pressure observationG 100 Hydrostatic testing the holding time at test pressure shall be not less than 2 hours.101 Prior to the performance of the pressure test the test 114 During testing, all welds, flanges, mechanical connec-object shall be cleaned and gauged. tors etc. under pressure shall be visually inspected for leaks.102 The extent of the section to be tested shall be shown on 115 The pressure test shall be acceptable if:drawings or sketches. The limits of the test, temporary blindflanges, end closures and the location and elevation of test instru- — During a 100% visual inspection there are no observedments and equipment shall be shown. The elevation of the test leaks and the pressure has at no time during the hold periodinstruments shall serve as a reference for the test pressure. fallen below 99% of the test pressure. 100% visual inspec-103 End closures and other temporary testing equipment tion shall only be acceptable where there is no risk that ashall be designed, fabricated, and tested to withstand the max- leak may go undetected due to prevailing environmentalimum test pressure, and in accordance with a recognised code. conditions, or — The test pressure profile over the test hold period is con-104 Testing should not be performed against in-line valves, sistent with the predicted pressure profile taking intounless possible leakage and damage to the valve is considered, account variations in temperatures and other environmen-and the valve is designed and tested for the pressure test con- tal changes.dition. Blocking off or removal of small-bore branches andinstrument tappings should be considered in order to avoid 116 Documentation produced in connection with the pres-possible contamination. sure testing shall, where relevant, include:Considerations shall be given to pre-filling valve body cavitieswith an inert liquid unless the valves have provisions for pres- — Test drawings or sketchessure equalisation across the valve seats. — pressure and temperature recorder charts — log of pressure and temperatures105 Welds shall not be coated, painted or covered. Thin — calibration certificates for instruments and test equipmentprimer coatings may be used where agreed. — calculation of pressure and temperature relationship and106 Instruments and test equipment used for measurement of justification for acceptance.pressure, volume, and temperature shall be calibrated for accu-racy, repeatability, and sensitivity. All instruments and test G 200 Alternative test pressuresequipment shall possess valid calibration certificates with 201 For components fitted with pup pieces of material iden-traceability to reference standards within the 6 months preced- tical to the adjoining pipeline, the test pressure can be reduceding the test. If the instruments and test equipment have been in to a pressure that produce an equivalent stress of 96% offrequent use, they should be calibrated specifically for the test. SMYS in the pup piece.107 Gauges and recorders shall be checked for correct func- 202 If the alternative test pressure in G201 can not be usedtion immediately before each test. All test equipment shall be and the strength of the pup piece is not sufficient:located in a safe position outside the test boundary area.108 The following requirements apply for instruments and — Testing shall be performed prior to welding of pup pieces.test equipment: The weld between component and pup piece is regarded a pipeline weld and will be tested during pipeline system— Testers shall have a range of minimum 1.25 times the testing. DET NORSKE VERITAS
    • Offshore Standard DNV-OS-F101, October 2007 Amended October 2008Page 100 – Sec.8 see note on front cover H. Documentation, Records, Certification 102 Records from the qualification of the MPS and other and Marking documentation shall be in accordance with Sec.12.H 100 General 103 Each equipment or component item shall be adequately and uniquely marked for identification. The marking shall, as101 All base material, fittings and, flanges, etc. shall bedelivered with Inspection Certificate 3.1 according to Euro- a minimum, provide correlation of the product with the relatedpean Standard EN 10204 or accepted equivalent. inspection documentation.The inspection certificate shall include: 104 The marking shall be such that it easily will be identi- fied, and retained during the subsequent activities.— identification the products covered by the certificate with reference to heat number, heat treatment batch etc. 105 Other markings required for identification may be— dimensions and weights of products required.— the results (or reference to the results) of all specified inspections and tests 106 Equipment and components shall be adequately pro-— the supply condition and the temperature of the final heat tected from harmful deterioration from the time of manufac- treatment. ture until taken into use. DET NORSKE VERITAS
    • Amended October 2008 Offshore Standard DNV-OS-F101, October 2007see note on front cover Sec.9 – Page 101 SECTION 9 CONSTRUCTION - CORROSION PROTECTION AND WEIGHT COATING A. General — marking, traceability and handling of non-conformities — handling and storage of coated pipes (for linepipe coating)A 100 Objective — documentation.101 This section gives requirements and guidelines on: Material data sheets for coating, blasting and any other surface— manufacture (application) of external pipeline coatings preparation materials may either be included in the MPS or in including field joint coatings a separ